121753182 Offshore Electrical Guidelines

50Using This Manual Abstract This section summarizes the contents and explains the organization of the Electrical Manual. This manual is divided into two volumes. Volume 1 contains the engineering guidelines with accompanying appendices. Volume 2 contains specifications, 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 Scope and Application The 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. Organization The colored tabs in the manual will help you find information quickly. • • • • White tabs are for table of contents, introduction, appendices, PC disks, index, and general purpose topics. Blue tabs denote engineering guidelines. Gray tabs are for model specifications, industry standards, and standard drawings. Red tab marks a place to keep documents developed at your facility. Engineering Guidelines The Electrical Manual covers a range of topics relating to electrical systems and equipment: system design; system studies and protection; hazardous (classified) areas; motor control centers; switchgear, protective devices, switches, and transformers; grounding systems; installation of electrical facilities; wire and cable and lighting; 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 Design This section contains guidelines for the design of an electrical distribution system, to be used when designing a new distribution system or making significant additions to an existing system. The section gives an overview of the electrical design October 2000 50-2 Chevron Corporation Electrical Manual 50 Using This Manual 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 Specification ELC-MS-1675, Installation of Electrical Facilities, and data sheet and data guide for ELC-DS-597, Instructions for 480 V Motor Control Rack Specification and Arrangement. Section 200, System Studies and Protection This section gives an introduction to electrical power system studies for the design of new systems or the modification of existing systems. These studies, which serve as a framework for analyzing critical factors in power system design, include: a short-circuit study, a motor-starting study, and a load flow analysis. Also included is a brief discussion of studies for transient stability and harmonic analysis. A list of references is provided along with a technical paper for performing a short-circuit study (Appendix C). Section 300, Hazardous (Classified) Areas This section discusses the classification of locations for electrical installations. It gives guidance for the selection of electrical equipment for hazardous (classified) areas. Topics discussed include: definitions of hazardous (classified) areas; maximum operating temperature and equipment enclosures; hermetically sealed devices and intrinsically safe systems; and nonincendive equipment and purged enclosures. A list of references is included along with the engineering form ELCEF-652, Conduit Stub-up Arrangement. Section 400, Motor Control Centers This section provides information for selecting 600 volt, 2400 volt, and 5 kV motor control centers (MCCs). It discusses the relationship of motors and starters, control methods, ratings, enclosures, selection, and customizing. Also included is a discussion of motor protection, overvoltages, and surge arrestors, and descriptions of NEMA ratings. The section refers to Company model specifications, data sheets and data guides, and engineering forms that relate to motor control centers and starters. Model specifications included in this manual with data sheets and data guides are: ELC-MS3977, Medium Voltage Current-limiting Fused Motor Starters, and ELC-MS-4371, Chevron Corporation 50-3 October 2000 50 Using This Manual Electrical Manual Adjustable Frequency Drives. Other relevant data sheets and guides included are: ELC-DS-366, Motor Control Center Specification and Arrangement, and ELC-DS597, Motor Control Rack Specification and Arrangement. Engineering form ELCEF-592, Wiring Diagram for Motor and Contractor Installation, is also provided. Section 500, Switchgear This section discusses switchgear assemblies and their application in an industrial facility. Specific steps in the design process are identified, including the use of standard forms and major selection factors. The section also aids in selecting switchgear 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 Switchgear, 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 Devices This section addresses the two major electrical system hazards, overload and short circuit, and the risk posed by each. It discusses system protective devices, particularly circuit breakers and fuses, and the operation of the principal components of any protective scheme. The section also discusses indirect protective control, specifically 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, Switches This 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 Interrupter Switches, are included. The standard drawing relating to this section is GFP99972, 480 Volt Stand-by Power System One-Line Diagram. Section 800, Transformers This 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, pressure vacuum gage, pressure relief diagram in cover, sampling device, pressure regu- October 2000 50-4 Chevron Corporation Electrical Manual 50 Using This Manual 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 transformers), 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 Systems This section contains guidelines and procedures for selecting grounding methods for generation and distribution systems. The advantages and disadvantages of each method are discussed and specific recommendations are made. Included are: procedures 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; and how to protect against the effects of lightning. This section also includes the mandatory and recommended practices for grounding and the design parameters for grounding systems for onshore and offshore applications. Two model specifications pertaining to this guideline are: ICM-MS-3651, Installation Requirements for Digital Instruments and Process Computers, and ELC-MS1675, Installation of Electrical Facilities. Standard drawings relating to this section are: 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 Facilities This section discusses general design and installation practice for electrical facilities, with reference to specification ELC-MS-1675, Installation of Electrical Facilities, included in the manual. Specific guidance is given for the design and installation of conduit systems, cable tray systems, and direct burial cable. Also included 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. Also provided with this guideline are the following: “Installation Practices for Cable Raceway Systems” (Appendix E); API RP 540, Recommended Practice for Electrical Installations in Petroleum Processing Plants; and API RP 14F, Design and Installation of Electrical Systems for Offshore Production Platforms. Chevron Corporation 50-5 October 2000 50 Using This Manual Electrical Manual Section 1100, Wire and Cable This section gives guidance in the selection of wire and cable for power, lighting, control, instrumentation, and communication circuits. The details of the construction 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-MS3552, 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 Installation of Electrical Systems for Offshore Production Platforms, and API RP 540, Electrical Installations in Petroleum Processing Plants. Section 1200, Lighting This 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 engineering 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 Systems This 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 equipment discussed includes: power synthesizers, motor-generators, uninterruptible October 2000 50-6 Chevron Corporation Electrical Manual 50 Using This Manual 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 ELCMS-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 Maintenance This 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, transformer fault-gas analysis, functional and operational testing, and factory testing. Standard references are cited as well as the following specifications and engineering 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 Electrical Generators; and ELC-EF-645, High Potential Test Record Sheet. Section 1500, Adjustable Speed Drives This 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, commissioning and maintaining drives is covered. Section 1600, Design of Electrical Systems for ESP Installations Guideline This section contains a guideline that 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 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, pressure, fluid characteristics, liquid flow rates, and well injection fluids or gases) this guideline focuses on above ground design issues. Chevron Corporation 50-7 October 2000 50 Using This Manual Electrical Manual 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 Manuals The text sometimes refers to documents in other Company manuals. These documents carry the prefix of that manual. The prefixes and their referents are: Prefix CIV CMP COM CPM DRI ELC EXH FFM FPM HTR ICM IRM MAC NCM PIM PMP PPL PVM TAM UTL WEM Company Manual Civil and Structural Compressor Coatings Corrosion Prevention and Metallurgy Driver Electrical Heat Exchanger and Cooling Tower Fluid Flow Fire Protection Manual Fired Heater and Waste Heat Recovery Instrumentation and Control Insulation and Refractory General Machinery Noise Control Piping Pump Pipeline Pressure Vessel Tank Utilities Welding October 2000 50-8 Chevron Corporation 100 System Design Abstract This section provides engineering guidelines for the design of an electrical distribution 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 110 111 112 113 120 121 122 123 124 125 126 127 128 130 131 System Design Introduction Design Procedure Basic Design Considerations Conceptual Design Load Summary Type of System Power Source Auxiliary Power Systems Bus Arrangement System Voltages One-Line Diagram Area Classification Detailed Design System Studies 100-26 100-6 Page 100-3 Chevron Corporation 100-1 May 1996 100 System Design Electrical Manual 132 133 134 135 136 137 140 141 142 143 144 145 Equipment Sizing Enclosure Selection Feeder and Branch Circuit Systems Grounding Lighting System Protection References Model Specifications (MS) Standard Drawings Data Sheets (DS), Data Guides (DG), and Engineering Forms (EF) Appendices Other References 100-60 May 1996 100-2 Chevron Corporation Electrical Manual 100 System Design 110 System Design 111 Introduction This 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 identifies other sections of this manual that contain more detail about specific subjects and guidelines for selecting equipment. 112 Design Procedure This 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 identifies 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. 2. 3. 4. Gathering process and load data. Choosing the most suitable system configuration and bus arrangements for the particular application. Selecting a power source. Determining system voltages. Detailed design involves: 1. 2. 3. 4. 5. Developing the one-line diagram. Performing system studies. Sizing equipment and feeder systems. Designing grounding and lighting systems. Designing system protection. 113 Basic Design Considerations The following basic design considerations must be included in the design of all electrical systems. Chevron Corporation 100-3 May 1996 100 System Design Electrical Manual Fig. 100-1 System Design Guide May 1996 100-4 Chevron Corporation Electrical Manual 100 System Design Fig. 100-2 General One-Line Diagram for Electrical Distribution System 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 Chevron Corporation 100-5 May 1996 Load Data To develop a load summary. It is important that the system electrical designer acquire knowledge of the facility processes. space for additional equipment. It is used to determine the power requirements of a system—in order to properly size power sources. See Section 1400. Poor voltage regulation is detrimental to the life and operation of electric equipment. distribution equipment. Operation should be as simple as possible to meet system requirements. At the initial stages of design. Safety. the lifetime cost also should be considered.100 System Design Electrical Manual should be designed to allow maintenance without major interruptions to the process. and potential for expansion should be considered in designing electrical systems and selecting equipment. Loads must be estimated until the design is finalized. design operating loads should be included. The list should include nameplate ratings of motors. brake-horsepower of electric motor-driven equipment. Operating and maintenance personnel should be consulted for preferred system configurations and existing maintenance procedures. for more details about maintenance. It is important to consider accessibility and availability (for inspection and repair) when selecting and locating equipment. accurate load data may be limited. maintenance. and kVA and kW ratings of all other process equipment. and capacity for increased load should be considered. Flexibility of the electrical system determines the adaptability to meet varied requirements during the life of the facility. The load summary also aids in determining system voltages. This knowledge will assist in estimating loads and selecting the proper system and components. Simplicity of Operation. Simplicity of operation is a necessary factor in achieving safe and reliable systems. Voltage Regulation. 120 Conceptual Design 121 Load Summary A load summary is a detailed listing of all loads to be served by the electrical distribution system. Flexibility. Utilization voltage must be maintained within equipment tolerance limits under all load conditions. Cost reductions achieved by using inferior apparatus should never be made at the expense of safety and performance. equipment ratings. Generally. and feeder systems. Cost. reliability. If available. voltage regulation. data on all loads to be served and information about the facility processes should be collected first. A list of loads must be obtained from the process and equipment designers. industrial facility loads are a function of the process equipment. May 1996 100-6 Chevron Corporation . While initial costs are important. It is better to estimate loads on the “high side” to avoid undersized equipment. Voltage levels. transformers. To provide a basis for a cost estimate. The procedures described in Sections 122 through 126 of the conceptual design phase must be performed before starting the one-line diagram and detailed load summary. Areas containing high load densities should be identified as possibly requiring load centers. circuit breakers. The load summary is developed for three main reasons: 1.000 volts) switchgear. To determine power requirements for the entire system—permitting power sources to be sized. Typically. and feeders). See Section 400. 3. Loads located on the plan give a geographical view of the load density. and an overload relay. 2. Load center breakers typically feed large motors. a draw-out air or vacuum contactor. which can be used to assist in devising a logical power distribution scheme. If available. or other load centers. lighting and heating) are served by thermal magnetic circuit breakers in the motor control center. Starters typically employ a current limiting fuse. and the loads assigned to individual busses. starters. and ambient compensated overload relays. buses.g. motor control centers. 460 volt motors rated 200 hp or less are fed from MCCs and started with combination motor starters. a load layout should be created using the plot plan to show major load components. Once the basic system has been selected. individual horsepower ratings should be obtained.Electrical Manual 100 System Design Load Layout For large facilities. A combination motor starter consists of a circuit breaker. Loads should be assigned to busses before beginning the load summary so that individual summaries can be made for each bus. A low voltage motor control center (MCC) is a group of motor starters and thermal magnetic circuit breakers rated up to 600 volts. A load center is defined as an assembly (lineup) of low-voltage (0-1000 volts) or medium voltage (1001-100.g.. a load layout made. Chevron Corporation 100-7 May 1996 . To determine the power requirements for each load center and motor control center—permitting the designer to select distribution voltages and size distribution equipment (e. Detailed Load Summary A detailed load summary can be developed once the load data has been gathered. Larger 460 volt motors commonly are started with circuit breakers if they draw too much current for combination motor starters. Other loads (e..” A medium voltage MCC is a lineup of motor starters rated up to 7200 volts. a contactor. “Motor Control Centers. Section 122 discusses selection of the various types of distribution systems. The load layout should then be used to assist in selecting the power distribution scheme. the load layout is used to assign loads to individual load centers and motor control centers (MCCs). Familiarity with existing facilities is also helpful. a basic distribution system chosen. making it easier to size system components. Fig. lighting transformers. including planned future loads. should be listed on the summary by equipment type and number. 100-3 One-Line Diagram for Load Summary Example All significant loads in the electrical system. Each new summary in the upstream direction will include load data from previous downstream summaries for use in sizing upstream equipment.g. Figure 100-4 is a load summary for this system.. Horsepower ratings should be listed for electric motors and kVA ratings for other loads (e. Brake horsepower should be listed for electric motor-driven equipment. power receptacles. Summarizing in the upstream direction should continue until the source is reached. It is best to begin summarizing at the furthermost downstream bus (often a motor control center). the totals from these summaries should be combined to determine power requirements for the entire system. separate load summaries should be developed for each load center and motor control center. Next.100 System Design Electrical Manual First. Figure 100-3 shows an example of a one-line diagram for an electrical distribution system during the conceptual design phase. and heat tracing). May 1996 100-8 Chevron Corporation . individual loads must be identified as either continuous. motor control centers. Running load is the actual electrical load of the facility during operation.Electrical Manual 100 System Design 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. Intermittent loads are included on a percentage basis. including planned future loads. Chevron Corporation 100-9 May 1996 . 100-4 Equip. No. To determine running load. MCC #300 WO-1 HTR-1 LP-7 MP-304 MP-304A MP-305 MP-305A LP-8 MP-308 Welding Outlet Heater Lighting Panel Pump Pump (Spare) Pump (Future) Pump (Future Spare) Lighting panel (Stand-by) Firepump (Stand-by) 30 43 43 20 20 50 50 25 25 20 40 100 50 50 25 25 50 30 50 30 50 30 50 30 25 25 20 40 100 50 20 40 100 50 Load Summary for System Shown in Figure 100-3 Rated hp Connected Load(1) (kVA) Intermittent Load (kVA) Running Load (kVA) Peak Load (kVA) Stand-by Load (kVA) Description BHP ___ Total Load Center #100 MP-101 MP-102 MP-103 MP-104 MCC#300 Pump Compressor Pump Compressor MCC #300 200 250 200 250 200 250 200 250 390 ____ Total 1290 390 __ 20 ___ 295 ___ 315 __ 80 200 250 200 250 20 __ 20 295 ____ 1195 200 250 200 250 315 ____ 1215 80 __ 80 (1) For motors where power factor and efficiency are not known. feeders. generators. intermittent. spare loads are not included in running load calculation. and uninterruptible power supplies. Running load is used to size utility service. Running load is the sum of all continuous loads. Fig. including planned future continuous loads. transformers. assume 1 hp load requires 1kVA. or spare. circuit breakers. is obtained when the facility is operating at full capacity and the maximum instantaneous intermittent load is energized. As actual power factors and efficiencies become available. computers and certain electronic instrumentation) should also be identified on the load summary. and UPS power systems. in cases where many large intermittent motors are connected to a bus.g. expressed as a decimal equivalent. consider 1 hp of load to require 1 kVA of power. Intermittent loads are loads that operate continuously for periods of less than 3 hours.g. May 1996 100-10 Chevron Corporation . load estimates should be updated constantly. Stand-by loads should be identified on the load summary to enable the electrical system designer to design the stand-by power system. Run factor is the percentage of hours operating per day. Typically. Two factors used to calculate the running load of motors for the sizing of transformers are demand factor and run factor.g. loads required for black start-up of a generator (e. emergency. to estimate peak load the process must be evaluated to determine when the maximum intermittent load will be energized. A load with a low power factor (e. However. Power factor and efficiency must be known to calculate the running load. Refer to Sections 124 and 1300 for more information on stand-by. As the design evolves. Spare loads are operated only when other loads are not operating.. All intermittent loads on a system normally will not be energized at the same time. It is important to coordinate with other design disciplines to ensure that up-to-date data are used. the load summary should be updated. Initially. the maximum instantaneous load drawn by a system during a stated period of time. selected plant lighting and HVAC loads. only estimated horsepower ratings may be available. Typically. jacket water heaters and pumps). Demand factor is the ratio of actual operating load to nameplate rating.. and power factor and efficiency must be estimated.. These factors generally are not used in the load summary. Therefore.. Peak load is the sum of the running load and the maximum instantaneous intermittent load. and sewage pumps.g. When power factor and efficiency are not known. 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. stand-by loads include critical loads that cause damage to the process or product if power is interrupted. particularly for large motors. Power factor is defined as the ratio of real power (kW) to apparent power (kVA).100 System Design Electrical Manual A continuous load is defined as a load that is expected to operate continuously for 3 hours or more. run factors and demand factors should be included in the running load calculations for economic reasons. Emergency loads deemed essential for personnel safety (e. Peak load. emergency loads are powered from unit equipment separate from the stand-by system because of the more stringent requirements of emergency systems. building egress lighting) and UPS loads that require clean uninterrupted power (e. Figure 100-5 is an example of a radial system. Fig. A disadvantage of the radial system is that a loss of the source or primary feeder will shut down all loads connected to that load center. one primary service feeder supplies power from a distribution transformer to the loads (at utilization voltage) from a load center. Ch. The radial system is satisfactory only for installations where the process allows sufficient down-time for adequate maintenance. and expansion is accomplished easily. Each unit substation is connected to two separate primary Chevron Corporation 100-11 May 1996 . Also. 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.Electrical Manual 100 System Design 122 Type of System Once the load layout has been developed and areas of high load concentrations have been identified. a power distribution scheme can be selected. This system is simple in operation. Used with permission Primary Selective System Protection against the loss of a primary supply can be gained through the use of a primary selective system. 100-5 Example Depicting Radial System From IEEE Standard 142. loads must be shut down for system maintenance and servicing. 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 System In the radial system. 1993. 2. If both sources can be paralleled during switching. a section may be energized from two directions. Figure 100-7 is an example of a primary loop system. 2. Used with permission Primary Loop System The primary loop system offers the same basic protection against loss of primary supply as the primary selective system. some maintenance of the primary cables (and. The disadvantage of this system is that locating a cable fault in the loop is more difficult. the distribution transformer is switched to the alternate source.100 System Design Electrical Manual feeders through switching equipment to provide a normal source and an alternate source. 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. Cost is higher than for a radial system because of duplication of the primary cable and switchgear. A primary cable fault can be isolated by sectionalizing—allowing restoration of service. For these reasons. 1993. If the normal source fails. May 1996 100-12 Chevron Corporation . Ch. In addition. the primary loop system is not recommended for new facilities. but there will be an interruption of power until the load is transferred to the alternate source. The cost of this system may be slightly less than the primary selective system. switching equipment) may be performed without interruption of service. in certain configurations. Fig. Switching can be either manual or automatic. Figure 100-6 is an example of a primary selective system. 100-6 Example Depicting Primary Selective System From IEEE Standard 142. Size the transformers so that either one can carry the total load (with fans). the result is a secondary selective system. Chevron Corporation 100-13 May 1996 . Provide forced-air cooling to the transformer(s) designated for emergency service. 1993. the total substation load can be supplied by one transformer. With the loss of a primary circuit or transformer. 100-7 Example Depicting Primary Loop System From IEEE Standard 142. If the primary feeder or a transformer fails. Designate nonessential loads that can be shed during emergency periods. Ch. 2. Use the temporary overload capacity of the transformers (and accept the loss of transformer life). A variation of the secondary selective system. 2. a distributed secondary selective system. Complete station maintenance will require a shut down. 1. The cost of the additional tie circuit breaker and the tie cable should be compared to the cost advantage of locating the unit stations nearer the load center. Maintenance of primary feeders. Used with permission Secondary Selective System If two unit substations are connected through a normally open secondary tie circuit breaker.Electrical Manual 100 System Design Fig. Operation may be manual or automatic. To allow for this condition. 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). 3. one or a combination of the following features should be considered. transformers. 4. the main secondary circuit breaker on the affected transformer is opened and the tie circuit breaker closed. has two substations in different locations—connected by a tie cable with a normally open circuit breaker provided in each substation. or other fuels are available at the facility to operate a generating unit. putting the two load centers in parallel. the availability and cost of fuel should be determined. 1993. 100-8 Secondary Selective System From IEEE Standard 142. Used with permission 123 Power Source The power supply usually affects system reliability more than any other component. as well as increase the risk of injury to personnel. and at a competitive cost. Ch. Voltage dips can also be particularly troublesome when computers or high intensity discharge (HID) lighting (e. Fig. Many economic factors must be considered when deciding whether to produce power or to buy it from a local utility. the degree of reliability required can be determined. the quality and reliability of the generated power must be considered. this method is allowed only if the available short circuit does not exceed the ratings of the secondary buses and breakers. mercury vapor and high pressure sodium) are in use. If a facility elects to generate power. When considering a utility as the source of power. notably refinery operations. as well as economics. Electrical failures can cause costly production down-time and equipment damage. require dual sources of power. waste heat. The utility must be able to provide service to the double-ended substations that are common in refineries. Figure 100-8 is an example of a secondary selective system. Whether power is obtained from a utility company or is generated. it is important to investigate the outage history and the quality of the power from the utility.100 System Design Electrical Manual In locations where interruptions cannot be tolerated. if not.g. The feasibility (primarily from an economic standpoint) for a facility to generate its own electricity should be evaluated. However. Perhaps waste gases. 2. It is important to remember that many operations. By assigning a dollar value to lost process time due to power interruptions.. Should May 1996 100-14 Chevron Corporation . a variation of the secondary selective system is to provide a normally closed tie breaker. it must be reliable. Other loads connected to emergency power systems are ventilation systems essential to maintain life. and metering requirements. These systems often are legally required and are classed as emergency systems by authorities having jurisdiction. The cost of the utility providing stepdown transformers should be compared to the cost of the Company providing them. normally increasing with the distance transmitted. Wiring is not permitted to utilize the same raceways. and industrial processes where power loss would cause safety and health hazards. lists typical loads. Obviously. Typical loads include communication systems. There are two types of auxiliary power systems: emergency and stand-by. Wiring of emergency circuits must be completely independent of all other wiring. ventilation and smoke removal systems. and reliable utility power source is available. cables.” for equipment details. It takes time to complete the engineering. and the delivery time for large equipment can be quite long. Typical emergency loads include exit signs and lights required for the safety of personnel. rescue operations. See Section 1300. “Auxiliary Power Systems. Emergency systems are intended to automatically supply illumination and power to designated systems essential for personnel safety during power interruptions. sewage disposal. 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. This section describes each system. and control of health hazards. and discusses criteria used in the selection and sizing of power sources. economic. elevators. requirements for protection and coordination with the utility protection system. 124 Auxiliary Power Systems An auxiliary power system is designed to supply and distribute power to equipment when the normal electrical supply is interrupted. if stopped. or cabinets as normal wiring. obtain rights-of-way. the cost of stepping down the voltage to the desired level must be investigated. the utility rates for power should be compared to costs of Company generation. It is important to compare the time required to design and construct a facility generating unit to the time required for a utility to install or expand a substation or transmission line. fire and gas detection and alarm systems. See NEC Article 700 for complete requirements. Also to be considered are available space.Electrical Manual 100 System Design facility generation be total or partial? Should steam or hydrocarbon-fueled drivers be used? The cost of utility power varies from region to region. Stand-by systems are used to provide electric power to aid in fire fighting. If an adequate. Chevron Corporation 100-15 May 1996 . fire pumps. and file permit applications. certain lighting and HVAC systems. and industrial processes that. could create hazards or hamper rescue or fire fighting operations. prepare environmental statements. The National Electrical Code (NEC) requires that emergency power must be transferred automatically to emergency loads within 10 seconds after loss of normal power. boxes. a battery-charging system. Equipment required to minimize re-start time or to initiate black start-up are often supported by the stand-by system.g. This power supply may be used to provide both emergency and stand-by power.. storage batteries. A storage battery supply consists of batteries and a batterycharging system. Four types of power sources available for emergency and stand-by systems are: engine driven generator set. Auxiliary Power Source Once standby and emergency loads are identified. However. and wiring for stand-by systems. Because of requirements on wiring and transfer time for emergency loads. UPS is used to supply emergency and stand-by loads that require a high quality of conditioned power with no interruptions. 1. Individual unit equipment consists of a rechargeable battery. it is usually more economical to connect them to unit equipment and connect stand-by loads to a generator set. lamps) upon failure of the normal supply. Engine Driven Generator Set. Design Criteria General. uninterruptible power supply (UPS) systems. What are the power requirements? Is high reliable and quality power (such as that serving process controls or computers) required. This power source is used primarily for emergency illumination. This is the most common power source for emergency and stand-by loads. 3. Unit Equipment. the number and type of power sources required can be determined. Uninterruptible Power Supply (UPS). or would commercial quality power be acceptable? What are the motor starting requirements? What future loads are anticipated? 2. Storage Batteries. and unit equipment. Means must be provided for automatic starting of the engine and automatic transfer of loads to the auxiliary source. and a relaying device to automatically energize the equipment (e. The following questions should be addressed when designing emergency and stand-by power systems. May 1996 100-16 Chevron Corporation . Emergency and stand-by loads may be fed from the same source or from separate sources. or discomfort to personnel if power were interrupted. serious interruption to the process. See NEC Articles 701 and 702 for requirements for transfer time. emergency and stand-by loads are sometimes connected to one source. 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.100 System Design Electrical Manual Stand-by systems also provide power to critical loads that could cause damage to processes or products. type of transfer. A UPS is not normally designed to supply the necessary short circuit current to clear a fault. 7. To clear a fault.Electrical Manual 100 System Design 4. what frequency of occurrence is acceptable? Can more than one facility be supplied from a single source? Can the utility improve the reliability of its service to an acceptable level? If so. or computers.g. or must power be provided until commercial power is restored (e. atmospheric and noise pollution. 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. Normally.008 seconds).10 cycles.. and potential value of waste heat. resulting in the loss of critical loads. fast clearing of faults has not been considered when selecting branch circuit protection and when sizing the maintenance bypass circuit. During the fault time period of between 0.03 to 0. The economic and technical considerations involve: fuel costs and long term availability. solenoid valves. J. is there a possibility of cogeneration with the utility? 5.2 seconds. or are momentary outages acceptable? If so.. the inverter-output circuit breaker opens and fault current is supplied by the bypass. the complete UPS system must be able to clear a 120-volt branch circuit fault in less than 1/2 cycle (0. Since most short circuits are ground faults and most UPS branch circuits are protected by circuit breakers. the UPS automatically transfers to the bypass. e. motor contactors. the short circuit condition persists for about 2 . notably a low-voltage condition. all UPS branch circuits are subject to the effects of the fault. and the branch circuits.. supplying fault current. If any UPS loads are sensitive to voltage fluctuation. After 6 cycles. with 1950 technology branch circuit components. the UPS inverter output and the bypass are in parallel. the transformer. for an orderly shutdown). to prevent hazards to equipment or personnel or financial losses)? Must power be available under “no-break” conditions. For large on-site generation facilities where prime mover energy is in excess of facility needs. UPS System Design. 8. the SCR’s in the static transfer switch begin conducting in about 1/2 cycle. a power interruption may occur.g. To sustain a tolerable voltage level. what sources of prime mover energy are available? Steam and gaseous or liquid hydrocarbon fuels are the usual choices. 9. Class CC fuses are preferred because Chevron Corporation 100-17 May 1996 . at what cost? 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. maintenance costs and personnel requirements. Upon sensing a fault. What are the stand-by power requirements? Is power required for only a short length of time (e. Often. or must old facilities carry a greater burden? For on-site generation.g. Frequently a short circuit develops on a branch circuit. the resulting system does not meet the expectations of an uninterruptible power system. control system relays. 6. Conventional Uninterruptible Power Supply (UPS) system designs use state-of-the-art UPS technology. causing the entire system voltage to drop. For a period of 2½ to 6 cycles. Underwriter’s Laboratory (UL) Class CC. See Section 1300. A stand-by system does not have this requirement. Unit equipment. Consultation with the UPS manufacturer is recommended. See Section 132 for information on sizing auxiliary generators. it will blow in less than 1/2 cycle. On smaller systems. Smaller wire increases the branch circuit impedance and lowers the available fault current. The size of batteries depends not only on the size and duration of each load. The calculations to size a UPS require a complete system load analysis. refer to ANSI/IEEE Std 485. it does not afford an advantage over a circuit breaker. for the required time period. When sizing the branch circuit conductor. To properly size batteries and chargers. the smallest rated fuse should be selected. but on the sequence in which the loads occur. It is recommended that power sources supplying stand-by loads be sized according to peak load. #12 copper should be the smallest size specified. When sizing branch circuit protection. For example. See Section 1300.” Unit Equipment. Otherwise.100 System Design Electrical Manual they are in-rush tolerant. and (3) peak load currents. Class J and T fuses in ratings from 1A to 30A are available in the same fuse clip size. The batteries and charger are sized by the manufacturer of the equipment. Procedures for sizing power sources for emergency and stand-by systems are described below. May 1996 100-18 Chevron Corporation . The best clearing time is about three cycles and system voltage can fall well below 50%. The smaller the fuse rating. a 20 ampere class J fuse begins current limiting at 200 amperes. Class CC fuses require a different fuse clip. a detailed load profile should be developed. an allowance for spare capacity of 10 to 20% is recommended.” for additional information. Battery Sizing. As long as the fuse is in its CL range. Once the load is determined. The UPS is selected to provide the needed quantity and quality of power to specific loads. (2) load demand. “Auxiliary Power Systems.” for equipment details. “Auxiliary Power Systems. The maximum peak inrush current is usually insignificant on large systems. Generator Sets. Sizing the Auxiliary Power Source The National Electrical Code (NEC) requires that the power source for an emergency system be designed with adequate capacity and rating to carry safely the entire connected load. typically used only for emergency lighting. the equipment inrush may be very important for determining the required rating. The short circuit current available however must be high enough to be in the CL range of the fuse. 120-volt circuit breakers are unable to respond as quickly and are therefore unsatisfactory for providing system voltage preservation during a fault. For details on sizing battery systems. but a 10 ampere class J fuse begins current limiting at about 100 amperes. “IEEE Recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations. including (1) connected loads (watts and power factor). Uninterruptible Power Supply (UPS) Sizing. is selected based on the amount of illumination required. the lower its current limit. transformers. In general. the circuit breaker protecting the affected transformer is opened. Double-Ended Bus Arrangement A double-ended bus arrangement. Operation may be manual or automatic. Some processes are minimally affected by interruption. optimum reliability and safety of operations require routine maintenance. utilizes a single primary service and distribution transformer to supply all feeders. Although the reliability of electric power distribution equipment is high. or transformer will cut off service. Other processes may sustain long-term damage by even brief interruptions. also known as a radial system. loss of a cable. in these cases. Where the industrial process allows enough down-time for maintenance and is minimally affected by interruptions. If the primary feeder or a transformer fails. Equipment must be shut down to perform routine maintenance and servicing. System investment is the lowest of all circuit arrangements since there is no duplication of equipment. A combination of bus arrangements should be used to achieve the required reliability and selectivity. system costs increase with system reliability if component quality is equal. Single-Ended Bus Arrangement A single-ended bus arrangement. 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. A more complex system. This type of bus arrangement is commonly used in industrial installations where high reliability is required. may be justified in these cases. Circuit redundancy may be required in continuous-process systems to allow equipment maintenance. If quality components are used. utilizes two unit substations connected through a normally open secondary tie circuit breaker. Maintenance of primary feeders. Figure 100-9 shows the single-ended bus arrangement. reliability is high. also known as a secondary selective system. primary supply. Operation and expansion are simple. and main secondary circuit breakers is possible with only a momentary power interruption (or Chevron Corporation 100-19 May 1996 . A system that cannot be maintained because of improper bus arrangements is improperly designed. the simple radial system or the single-ended bus arrangement is recommended. with an alternate power source for critical loads. and the tie circuit breaker is closed. a simple singleended bus arrangement may be satisfactory.Electrical Manual 100 System Design 125 Bus Arrangement The 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. However. while Source 2 feeds the loads. Ch.100 System Design Electrical Manual Fig. 1993. 55°C rating. If this arrangement is ever operated with the tie breaker closed. To allow for this condition. 2. With the loss of one primary circuit or transformer. Complete station maintenance requires shut down. the available short circuit current must not exceed the short circuit rating of the bus and interrupting rating of the breakers. A fault anywhere in the system results in two breakers operating May 1996 100-20 Chevron Corporation . Each transformer should be sized to carry 75% of the total running load on both buses at its self-cooled. Ring Bus Arrangement A ring bus arrangement is used primarily when two utility sources supply the facility. If a fault occurs in Source 1. The ring bus arrangement offers the advantage of automatically isolating a fault and restoring service if a fault occurs in one of the sources. total substation load may be supplied by one transformer. Figure 100-10 shows the double-ended bus arrangement. Where a process cannot be shut down for maintenance and interruption of power cannot be tolerated. This provision ensures that when one transformer 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. one or a combination of the four features outlined in Section 122 for a secondary selective system must be implemented. a double-ended bus arrangement or secondary selective system is recommended. 100-9 Single-Ended Bus Arrangement From IEEE Standard 142. Breakers A and D operate to isolate the fault. The transformers should be dual rated with provisions for future fans. This design feature can be used for the main power source or for substations within a facility. Normally all breakers of a ring bus arrangement are closed (Figure 100-11). with forced air cooling). Used with permission no interruption if the stations can be operated in parallel with the tie breaker closed during switching). Breaker-and-a-Half Scheme A 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. providing power to one of the load transformers. 100-11 Ring Bus Arrangement From IEEE Standard 142. 2. 2. but more expensive than single. 1993. Ch. This system is less expensive than the breaker-and-a-half scheme described below. As its name implies. 1993. 100-10 Double-Ended Bus Arrangement From IEEE Standard 142. if a fault develops on source 1. Source 1 remains in service. Configuring the system with source connections and load connections diagonally opposite affords breaker-failure relaying and a continuous source of power to the load. For example. 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. Used with permission 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. Used with permission Fig. Normally all the breakers are closed. Fig. If breaker C fails to open. breakers D and C will normally clear the fault. even if a breaker fails to operate and the adjacent breaker must clear the fault. Ch. This arrangement offers a high degree of security since a faulted area will in no way affect other operating sections. this arrangement requires one-and-a-half breakers for each source (three breakers for every two sources) in the scheme.and double-ended bus arrangements. breaker B clears the fault. Chevron Corporation 100-21 May 1996 .Electrical Manual 100 System Design to isolate the fault. equipment and cable May 1996 100-22 Chevron Corporation . Used with permission 126 System Voltages To select distribution and utilization voltages. Losses due to higher current (at lower voltages). 6. Overall system flexibility (i. the capability for future expansion). 2. Specific loads served (size and voltage level). Existing voltage levels in the facility. the following factors should be considered: 1. 2. 100-12 Breaker-and-a-half Scheme From IEEE Standard 142. Voltage level supplied by the utility or on-site generation. Ch. The advantage of a higher voltage system is that less current is required for the same power than for lower voltage systems. 4. 5.. A major consideration when choosing voltage levels is the cost of equipment and cable. 1993. 3. In some cases.100 System Design Electrical Manual Fig.e. Cost of electrical equipment and cable at different voltage levels and current ratings. 000 kVA. Chevron Corporation 100-23 May 1996 . An economic study should be made to determine the primary distribution voltage (based on load). but the selection depends on the total facility load and distance that the primary distribution voltage must be transmitted.000 volts. If the utility supplies a voltage in the range of 12. Depending on the size of motors at the facility. but less than 100. The same 5 kV class of switchgear and motor controllers is used for both 2400 volt and 4160 volt systems. Other voltages.800 volts. 4160 volts. Standard nominal system voltages for the United States are listed in Table 1 of ANSI/IEEE Standard 141.000 volts.000 volts. and 2400 volts.000 kVA or larger. The medium voltage class contains nominal system voltages equal to or greater than 1000 volts.000 volts. The high voltage class contains nominal system voltages equal to or greater than 100. A higher voltage system is also more efficient because of lower power losses.800 volts for primary distribution. There are three system voltage classes.000 to 20. Typical primary distribution voltages are 13. In most large facilities where facility load is less than 10. lower current-rated breakers and controllers are required for the 4160 volt system. 4160 volts or 2400 volts is the most economical primary distribution voltage. The cost of 4160 volt motors is typically 5 to 10% more than for 2400 volt motors.800 volts. it is often economical to use this voltage as the primary distribution voltage for the facility because step down transformers are not required. the first voltage level to consider should be the incoming utility (or generator) voltage. dictated by the standard utility voltage levels in the area. future expansion.800 volts and 4160 volts. 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. it is most economical to use 13.000 kVA. the preferred primary distribution voltages are 13. If the utility supply is over 15. For facilities where the load is 20. transformation to a lower voltage is typically required. Cable costs are also usually less on the 4160 volt systems (since smaller conductors can be used). however. For large plant facilities.000 volts to 15. Distribution Voltage In most facilities it is necessary to distribute power at a voltage higher than or equal to the utilization voltages. The low voltage class contains all nominal system voltages below 1000 volts. When choosing a distribution voltage. and distances between load centers. Primary distribution voltages above 15 kV are seldom recommended in Company facilities because of significantly higher costs for equipment rated above 15 kV. a 4160 volt system may be less expensive than a 2400 volt system. may be encountered in some systems.Electrical Manual 100 System Design rated at higher voltage levels may be more economical because of the reduced current rating required. For facilities where the load is 10. and rating of the electrical equipment is also included. 120 volt-single phase. then it becomes an economic choice of which voltage level to use after considering the cost of the motor. for motors up to 250 hp. However. For example. and single lines are used to show the interconnection of the components.000 1000-12. The best utilization voltage depends on what voltages are available. starter. in May 1996 100-24 Chevron Corporation . For motors between 100 and 200 hp. a 5000 hp motor could be added to a 13.800 volt system. Motor Horsepower (hp) 3500-25. The preferred utilization voltages are 480 volt.800 volts. some existing facilities have 2400 volt systems. and 240 volt single phase for convenience outlets. based on the size of individual motors installed at the facility (Reference: API Standard 541). and 13. A complete one-line diagram. lighting. Similarly.100 System Design Electrical Manual Utilization Voltage Selection of utilization voltage is primarily dependent on the equipment to be served. Information on size. If 480 volt capacity is not available but 2400 volt or 4160 volt capacity is. and 4160 volts. or a 4160 volt system. may be best served at 480 volts. Standard symbols are used to represent electrical equipment. and the availability and cost of installing motors at the various voltages (including the cost of the motor). The preferred utilization voltage for small loads (such as integral horsepower motors below 100 hp) is three-phase 480 volts. Listed below are utilization voltages and motor voltages available. the latter voltage may be more economical.800 6900 4160 2400 480 Motor Rated Voltage (V) 13. Small dry-type transformers rated 480-208/120 volt or 480-240/120 volt are used to provide 208 volt three-phase. one should consider the available system voltages and bus capacity at each voltage to select the best utilization voltage for the motor. If bus capacity is available at 13. or other outdoor lights where voltage drop is a problem. and other small loads. typically the most cost effective utilization voltage is 480 volts. 6900 volts. type.200 6600 4000 2300 460 The above list demonstrates a large overlap in motor horsepowers and utilization voltages. 4160 volt. Some floodlights.000 400-7000 250-4000 Up to 600 Utilization Voltage (V) 13. these situations may make it more economical to choose one of these levels. 127 One-Line Diagram A one-line diagram is a schematic drawing that uses graphical symbols and standard nomenclature to illustrate the overall configuration of an electrical system. the capacity of the bus at those voltages. and feeder. a 6900 volt system.800 volt. and some utilities provide 6900 volt service. parking lot lights. and trip setting of molded case circuit breakers. See: Exhibit I of API RP 14F for symbols for offshore applications. and grounding methods of separately derived sources. available short-circuit current. Medium Voltage Motor Starters.. Size and type. Feeders. should provide enough data to plan and evaluate an electrical system. I. 6. Standard form ELC-EF-541 should be used for standard electrical symbols. One-line diagrams should also show known future additions. The actual drawing should be as simple as possible. Restrictions are placed on the type of equipment used. See Section 300 for a detailed discussion of classified areas and selecting electrical equipment for these areas. 128 Area Classification Locations are classified according to the presence of flammable gases or vapors. See Standard Drawing GF-P99988 for information found on a typical one-line diagram and for practices used in system design. current rating. Buses and Bus Duct. and short circuit bracing. Low Voltage Switchgear.Electrical Manual 100 System Design conjunction with a physical plan of the installation. combustible dusts. Meter types. 2. Hazardous (classified) locations must be identified in order to select proper electrical equipment for these areas. LT. voltages. the effect of such additions should be part of the original system planning.g. impedance. Power Sources. Capacity. number of conductors. Loads. trip setting. Current rating and MVA rating. and on its operation and maintenance. and NEMA sizes of starters. it need not show geographical relationship. or easily ignitible fibers or flyings. frame size. The following items should be shown on a one-line diagram: 1. Size and description. Since it is a schematic diagram. and options (e. relay types. 5. Current rating. and conduit size. 3. Metering and Relaying. transformers. 10. frame size. connection. and grounding method. 11. 8. Medium Voltage Switchgear. Transformers. 7. Current rating. Current rating. Low Voltage Motor Control Centers. Fuses. Size. voltages. ST.). 9. Voltage. CT and PT ratios. 4. Chevron Corporation 100-25 May 1996 . Generators. These harmonics may cause problems elsewhere in the system (e. and voltage vs. It models the electrical system and examines the effects on motors and generators of system transients. acceleration time calculations. such as faults. soft starting using solid state controllers. and wye-delta starting). transformer tap settings. and a harmonic study may also be required. switching. reduced voltage starting. It also determines if the system may become unstable. It is useful for determining voltage drops.. Voltage drop should never exceed 20%. particularly when installing large motors on systems with limited short circuit capacity. capacitor failure. Section 200. malfunctioning computers. “System Studies and Protection. Facilities with this equipment may be susceptible to harmonics generated by the equipment. Alternate methods to across-the-line starting are often required (e. torque relationships (to determine if there is sufficient accelerating torque to start motors). a transient stability study. A load flow study. A harmonic study analyzes system harmonics and problems in the design. or overheated equipment).” discusses various system studies and May 1996 100-26 Chevron Corporation . and power factor.g.g.. blown fuses. and a study must be made to ensure that the power system has sufficient capacity to start the motors. Sometimes it is difficult to limit voltage drop to 15 to 20%. and relay action. When adding large motors to a facility. which determines the maximum short circuit current that could flow at all points in the system. The motorstarting voltage drop on the system must be limited to avoid problems with contactors and relays dropping out and high intensity discharge (HID) lighting fixtures extinguishing. which could result in a shut down. A load flow study determines the real and reactive power in the system under normal and special operating conditions. A motor-starting study typically includes voltage drop calculations. A voltage drop study may be necessary if motors comprise the majority of the loads. It is recommended that the system be designed to limit the initial motor-starting voltage drop at the main bus to less than 15%.100 System Design Electrical Manual 130 Detailed Design 131 System Studies Several studies are conducted in the design phase of a project. 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). different methods for starting motors. Probably the most important of these studies is the short circuit study. A transient stability study is applicable only to facilities with synchronous motors and generators. consideration must be given to the voltage drop that occurs when these motors are started. This study determines if the synchronous motors and generators will fall out of synchronism during transients and checks if they are capable of returning to synchronism shortly after transients dampen. This information is used when specifying the current interrupting ratings and bracing for electrical equipment. Determine the generator voltage drop during starting of the largest motor. “Protective Devices. This design reduces the stress on the insulation and increases generator life. Section 600. Pg (in kilowatts). Step 3. A stand-by generator supplies power to stand-by loads only. Chevron Corporation 100-27 May 1996 . if the generator rating (in kW) is at least five times the numerical value of the horsepower of the largest motor. The generator will also be able to operate in overload conditions for short periods of time and still remain below the allowable temperature ratings. it is considered an emergency generator and must be designed according to NEC requirements for emergency systems. Select a standard generator rating (PG) equal to or greater than Pg. The designer should refer to the generator manufacturer’s motor starting applications data. 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.” explains how to conduct a relay coordination study. Determine the generator power requirements. It is recommended that the generator rating be based on a NEMA Class B temperature rise. See Driver Manual for guidance in determining horsepower requirements for the prime mover. Step 1. A primary power generator supplies electrical power for normal operations. Step 2. refer to other sections of this manual for guidelines for specifying equipment. (2) standby.Electrical Manual 100 System Design explains their use and requirements. the voltage drop will not be greater than 15% with the generator already loaded to 50 to 75%. Usually a 15 to 20% voltage drop is acceptable if the motor is not started often. and (3) emergency. it is recommended that Pg equal total connected load plus known future connected load plus 10 to 20% spare capacity. As a rule of thumb. Following are guidelines for sizing generators. If emergency loads are connected to a generator. Generators Three types of generators are discussed in this section: (1) primary power. The generator should be specified with NEMA Class F (or Class H) insulation so that it will operate below its insulation temperature rating during normal operating conditions. 132 Equipment Sizing This section provides guidelines for sizing: • • • • • Generators Transformers Switchgear Motor control centers Switches Once the equipment has been sized. It is recommended that each transformer have dual ratings (55°C/65°C). the remaining transformer will be able to supply 112% of its rated kVA. or may be. 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. at 65°C. 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. Each transformer should be sized to carry 75% of this total running load at self-cooled. 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.tween 400 and 600 volts should not exceed a rating of 750 kVA.75 x 940 = 705 kVA. at 55°C rise. as used here. Engineering judgment and load considerations should be used to decide if fan cooling should be provided for the transformers upon installation. 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. Total running load on both buses is 940 kVA. except that capacity should be provided for starting the largest spare motor with all normal motor drivers running. operated under normal conditions (i. calculate the running load on both buses. When sizing transformers for double-ended substations. Transformer capacity. In general. or 84% of the total running load. and other equipment that will be. other than power outage). loads should be balanced between the buses. If it is not desirable to drop loads while one transformer is out of service. “Transformers. thus giving some leeway for adding load in the future. 55°C/65°C rated transformers with fan cooling or larger sized transformers may be used. The minimum size transformer required is 0. 55/65°C.e. is the self-cooled rating without fans. For example. Assume 1 hp equals 1 kVA for induction motors.. May 1996 100-28 Chevron Corporation . A single transformer at 2400 volts or more should not have an initial running load exceeding 90% of its self-cooled 55°C rating. Size transformers serving a double-ended substation. Individual transformers with secondaries of less than 400 volts should not exceed a rating of 125 kVA. when one transformer is out of service. and transformers with secondaries be. a 2500 kVA. without a detailed investigation of the effects of high short circuit currents on secondary equipment. 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. if ambient conditions allow overloading without exceeding its 65°C rise rating. Therefore.100 System Design Electrical Manual Transformers Transformer sizing should be based upon running loads (determined from nameplate ratings) for motors. See Section 800. 55°C rating.” for a detailed explanation of transformer temperature rise and fan cooling ratings. Spare motor drivers should not be considered part of the running load for the purpose of sizing transformers. lighting transformers. power transformers (500 kVA and above) should be supplied with 55°C/65°C temperature rise ratings and provisions for future forced air cooling. Example. 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. one transformer will be able to supply 1.000 37.500 16. 55°C/65°C transformer is selected. See Section 200. one transformer will be able to carry the entire running load with 28 kVA to spare. two 1000 kVA transformers without fan cooling could be selected. The additional impedance of the transformer in series with the motor reduces inrush current.000 25. Transformers should be sized so that the voltage drop on the secondary of the transformer 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).5 150 225 75 100 167 250 333 500 833 300 500 750 1000 1500 2000 2500 1250 1667 2500 3333 5000 6667 8333 3750 5000 7500 10.000 12.12 x 750 = 840 kVA of running load at its 65°C rise.Electrical Manual 100 System Design Consulting the table below. A transformer serving a single motor is called a captive transformer or unit transformer.000 25.000 60. Thus. a 750 kVA. In general. Without fan cooling.000 20.000 15.667 20.000 30. and not a uniquely designed transformer. As an alternate. However.000 33.500 50.29 x 750 = 968 kVA.” for details. of course. A captive transformer is a special application of a standard transformer.5 50 15 30 45 75 112. If the transformers are equipped with fans.000 10. Using a captive transformer may also be econom- Chevron Corporation 100-29 May 1996 .000 12.333 Three-Phase Motor-starting requirements must be considered in sizing power transformers. 100 kVA of load will need to be dropped in order to stay within the transformer operating limits. “System Studies and Protection. one transformer can supply 1.000 100. Standard Transformer Ratings (kVA) Single-Phase 3 5 10 15 25 37. which lists standard transformer kVA sizes. the voltage drop at the terminals of the motor during starting must also be considered to ensure that there is no starting problem. Captive transformers are used primarily to reduce system voltage drop during motor starting. In this case.000 75. wye-delta. delta-delta. transformers with manufacturer’s standard impedance are satisfactory. Consult the transformer manufacturer when sizing captive transformers. Pulsating loads and frequent motor starting may place unusual duty on the transformer. See Appendix B for information on the advantages and disadvantages of using captive transformers. For other applications. then the conventional ruleof-thumb (1 horsepower = 1 kVA) can be used to size the transformer. The wye-connected secondary windings can be used as a three-wire or four-wire system. otherwise potentially destructive circulating currents may flow. Under starting conditions. the load is not considered pulsating.00). voltage drops increase with higher impedance and should be checked. and wye-wye. If a motor is operated continuously with infrequent starting (less than once every 4 hours). For applications outside of acceptable limits. Each winding connection has advantages and disadvantages that make it suitable or unsuitable for particular applications. Higher impedance is sometimes needed to reduce the short circuit current (to match secondary equipment rating). the transformer kVA rating closely approximates that of the motor kVA requirement. and the installation is considered a “usual service condition” (per ANSI/IEEE C57. this requirement imposes a sizeable thermal and impact load on the transformer. but increases the available short circuit current. There are four fundamental three-phase transformer connections: delta-wye. depending on the application. a larger transformer may be required. In general. lower impedance lowers the voltage drop. 1. In the motor/captive transformer combination. however. Captive transformers must be sized so the voltage at the motor terminals is sufficient to ensure adequate starting torque for the load. When paralleling with an existing system. Transformer Impedance. the same connection scheme must be used to provide identical phase shifting. or the manufacturer should be consulted. a larger transformer should be specified.100 System Design Electrical Manual ical because of reduced motor cost. The connection recommended for most applications is delta-wye (delta winding on the primary and wye winding on the secondary). Impedances higher or lower than standard values increase transformer costs. Figure B-6 of Appendix B shows a transformer application curve for pulsating or short-time loads. Connection of Transformer Windings. a fourth wire connected to the wye neutral can be used to support single-phase loads (such as lighting). Delta-Wye Advantages – Effective control of phase to neutral over-voltages May 1996 100-30 Chevron Corporation . An important consideration for sizing captive transformers is the impact loading on the transformer during starting. The transformer application curve should be checked to ensure that acceptable operating limits are not exceeded. Refer to Table 72 in ANSI-IEEE Std 141 for standard impedance values of three-phase transformers.12. It usually is used as a three-wire system with the neutral grounded. However. Conversely. although loadcarrying 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. Not recommended for new installations. Not recommended for new installations. 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.) Interruption of critical processes due to disconnection of equipment upon detection of a ground fault. 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 Chevron Corporation 100-31 May 1996 . except where required to parallel with an existing system. however. Wye-Delta.”) Entire system rendered inoperable by failure of one winding – – 2. Delta-Delta.) 3. (See high-resistance grounding in Section 900. methods of creating high resistance grounding schemes. that allow ground faults to be found quickly without interrupting operations. “Grounding Systems.” for recommendations. (There are. (See high-resistance grounding in Section 900. “Grounding Systems. except where required to parallel with an existing system. thus not affecting ground relaying on the high voltage side Disadvantages – Possibility of large phase-to-ground fault current. similar to wye winding with high value neutral resistor. leading to possible sustained arcing.Electrical Manual 100 System Design – – Easy detection of phase-to-ground faults Isolation of ground-fault current from the high voltage (delta) side. The standard main bus ratings for medium voltage switchgear are 1200.25 times the full load current of the largest running motor. 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. Advantages – Advantages on the secondary side similar to those of delta-wye connection. Not recommended except when required by utilities. Higher cost due to insulation degradation and requirement of tertiary delta windings Third harmonic voltages impressed upon line-to-line voltages.100 System Design Electrical Manual Disadvantages – – – – – 4.. plus the full load current of May 1996 100-32 Chevron Corporation . 3200 and 4000 amperes. (Third harmonics can be significantly reduced by using three-phase core-type transformers. The current capacity of a bus is determined by its material (e. 2000. 2000. For low voltage switchgear. Neutral-to-ground over-voltages are uncontrolled and can lead to equipment 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 Wye-Wye. 1600. both available from General Electric Company. and 3000 amperes. Switchgear Switchgear 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. resulting in additional voltage stress on equipment. This problem can be solved with tertiary deltaconnected windings.g. consult System Grounding for Low-voltage Power Systems and Transformer Connections. The continuous current rating of the main bus should be a minimum of: 1.) Interference in communications circuits from third harmonic ground currents – – – For more information about transformer connections. the standard bus ratings are 800. copper) and its physical size. the two are rated the same.732 ) = 1943 Amperes (Eq. The continuous current rating of circuit breakers is determined by the ampacity of the conductors they protect (NEC Article 240-3). 100-1) Therefore. plus the full load current for future motor load for future space provided.= 1146 Amperes I = -----------------------------------------( 4. Full load current of the 10.12 ) ( 1.. Example. a 2000 ampere bus should be selected (to provide for future expansion) rather than the 1200 ampere bus indicated by the running load calculations. Feeder breakers that serve a bus are typically rated the same as the bus. a double-ended substation).25 (1000) + 1000 + 2 (500) + 5000 = 8250 kVA 8250 kVA . Two . assume 1 kVA per hp and calculate the load using the method described above.500 hp motors (future) 5000 kVA of connected transformer load For motors. The continuous current rating of a main circuit breaker must not exceed the ampacity of the main bus it is feeding. Determine the main bus rating for 4160-volt switchgear with the following load summary. Chevron Corporation 100-33 May 1996 . the main bus should be sized to carry the maximum full load current of the transformer with fans at 65°C rise. Conductor ampacity requirements are based on the load and can be determined by using NEC Article 220 (see Section 134 below for sizing conductors).25 ) I = -----------------------------------------------------------------4.000 kVA ) ( 1.e. kVA = 1. If the switchgear is served from a transformer.000 kVA dual-rated transformer. the main bus should be sized to carry the rated full load current of the transformer (with fans). Typically. the recommended minimum standard bus rating is 1200 amperes.16 kV ( 1. Continuous Current Rating of Breakers. If the switchgear is fed from a 10. each bus should be sized to carry the rated full load current of its transformer (with fans) only. 100-2) Since the maximum full load capability of the transformer is 1943 amperes.Electrical Manual 100 System Design remaining running motors.000 kVA transformer with fans at 65°C is: ( 10. When sizing two buses connected through a tie-breaker (i.16 kV ) ( 1.732 ) (Eq. plus the primary rated current of transformer loads.1000 hp motors (running) Two . e. the K factor was introduced into the ANSI standards for medium voltage circuit breakers. Therefore. See Section 200.” Industry standard continuous current ratings for low voltage power breakers are 800. These trip devices are available with long time delay. Ratings for low and medium voltage circuit breakers are given in Figures 100-13 and 100-14. 100-13 Maximum Short Circuit Interrupting Ratings for Low Voltage Power Circuit Breakers with Instantaneous Direct-Acting Trip Elements Maximum 3φ Symmetrical Short Circuit Interrupting Ratings Nominal Voltage (volts) 600 600 600 600 600 480 480 480 480 480 Rated Max Voltage (volts) 635 635 635 635 635 508 508 508 508 508 Frame Size (amperes) 800 1600 2000 3200 4000 800 1600 2000 3200 4000 Standard Rating (kA) 22 42 42 65 85 30 50 50 65 85 High Rating (kA) 42 65 65 85 85 42 65 65 85 85 Medium Voltage Breakers. 2000. For details see Section 200. See Section 200. instantaneous and ground fault options. The K factor is a dimensionless number May 1996 100-34 Chevron Corporation . current sensors and rating plugs). 2000. These breakers are tripped by protective relays. “System Studies and Protection. A low voltage circuit breaker operates in the first half cycle of a fault. A medium voltage circuit breaker begins to interrupt fault current during the third cycle. and 3000 amperes. so the interrupting rating must be greater than the short circuit current calculated at one-half cycle.” for details on calculating fault currents and determining the necessary interrupting ratings for switchgear. the short circuit current must be calculated at three cycles. “System Studies and Protection. short delay. Fig.” for information on trip settings. These breakers are available with various sizes of solid state overcurrent trip devices (i.100 System Design Electrical Manual Industry standard continuous current ratings (frame sizes) for medium voltage breakers are 1200. Interrupting Rating of Breakers. Correct selection depends on the load (see Specification ELCMS-3987 for more details). To take advantage of this capability.. The interrupting rating of a protective device is the fault current that the device can interrupt safely. 3000 and 4000 amperes. The physics of arc interruption are such that oil-blast and air-magnetic circuit breakers can interrupt a higher current at a lower voltage. 1600. set for the load being fed by the breakers. “System Studies and Protection. 2000 ampere circuit breaker with a rated short circuit of 29 kA. 100-14 Short Circuit Ratings for Medium Voltage Circuit Breakers Rated Maximum Voltage (kV.24) of 3. Determine the adjusted interrupting rating of the circuit breaker when applied at: (A) 2. Solution 1.4 kV and at (B) 4.3 By applying the K factor adjustment.76 . 2000 1200. 3000 Rated Short Circuit Current @ Rated Max Voltage (kA. 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}.16 kV is in the constant MVA interrupting rating of the circuit breaker.19 1. 4. rms) 29 41 18 28 37 Maximum Symmetrical Interrupting Capability (kA.24 1. 2000 1200. 2000 1200.24. 100-3) Example Given a 4. at voltages below VRated Max/K. 2000. therefore. the interrupting capability is given by Equation 100-3.Electrical Manual 100 System Design which defines the range of voltage over which the rated short circuit current increases. Chevron Corporation 100-35 May 1996 .84 kV the circuit breaker is in its constant current interrupting capability of K times rated short circuit current. Fig. and a constant current interrupting rating. 3000 1200.= 33kA .4 kV is below the V/K ratio (4. The operating voltage of 4. equal to K times rated short circuit current.3 1.16 (Eq. rms) 4. and a K factor of 1. Since the operating voltage of 2. (Eq.3 1.16 kV. 100-4) 2.76 4. rms) 1200.24 x 29 kA = 35 kA. a maximum symmetrical interrupting capability of 36 kA.76 kV. Breakers using this technology have a constant MVA interrupting rating between VRated Max and VRated Max/K.76 15 15 15 Rated Continuous Current (amperes. 2000. Crest) 97 132 62 97 130 Rated Voltage Range K Factor 1.76/1. rms Sym) 36 49 23 36 48 Close and latch Short Circuit Current (kA. Symmetrical current interrupting capability = 29 × --------4. Symmetrical current interrupting capability = 1. The actual MVA rating of a vacuum circuit breaker applied at 13.3) for 15 kV class equipment. however.9 49 18 19.8 kV is 1147 MVA. kA 29 33. a K factor of 1.76 4. K factor ratings other than 1.4 4.2 kA  37 × -------- 13. rms 29 System Operating Voltage kV.5 Actual MVA @ Operating Voltage 239 239 150 338 338 204 468 468 468 727 727 727 961 961 961 Nominal MVA 250 Circuit breakers using vacuum and SF6 puffer interrupters are essentially constant current interrupters up to a limiting maximum voltage. For example.16 2.4 15 18 500 15 13.2 36 41 46.76 41 350 4. 100-15 Adjusted Interrupting Current Values and Actual MVA Ratings for Medium Voltage Circuit Breakers Operating at the Various Voltage Levels Rated Maximum Voltage kV.8 12. 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 = 15/1.100 System Design Electrical Manual 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.47 15 37 1000 15 13.8 12.16 2.76 Rated Short Circuit Current kA. This corresponds to an actual MVA rating of 961 at 11. For this type of technology.76 4.0 is appropriate.4 33.47 15 28 750 15 13.8 12. however.6 21.7 37 40.2 44.or 961 MVA 40.7 28 30.5 kV.8 May 1996 100-36 Chevron Corporation . to meet existing ANSI standards for metal clad switchgear. rms 4. This results in vacuum and SF6 breakers of higher interrupting capability at higher applied voltages. 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.47 Interrupting Current @ Operating Voltage. Fig. rms 4. ANSI Standards specify the capability to be rated at an interrupting short circuit current of: 15  .0 are given. Nevertheless. This rating is determined from the one-half cycle calculation of short circuit current. Optional vertical bus ratings of 450 amperes and 600 amperes are available. 800. a 450 ampere or 600 ampere bus may be specified. The recommended minimum current rating of the main (horizontal) bus should be 1. except only the loads in a specific vertical section should be used. The momentary rating of a protective device is the maximum fault current that the device can physically withstand without failure. plus the full load current of future motor load for future space provided. plus the full load current of remaining running motors.” 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. “System Studies and Protection. “System Studies and Protection.Electrical Manual 100 System Design In order to apply the circuit breaker at 1147 MVA. 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. Short Circuit Rating of Bus. The manufacturer will size the vertical buses. or the load should be rearranged in such a way Chevron Corporation 100-37 May 1996 . its interrupting rating is equal to the momentary rating. This commonly is referred to as the “close-and-latch” rating. 1200. and 2000 amperes. The industry standard for the continuous current rating of the vertical bus is 300 amperes. however. 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. plus 10 to 20% for future load capacity. Momentary Current Rating of Breakers. 1000. To determine the available short circuit current at the bus see Section 200. If the load in any vertical section exceeds 300 amperes. See Section 200. before the circuit breaker can be nameplated with the higher interrupting rating. an additional safety margin exists when applying vacuum and SF6 circuit breakers.25 times the full load current of the largest running motor. If the motor control center is fed from a transformer. 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. particular attention should be given to vertical sections where continuous current rating may exceed 300 amperes. 1600. the equipment manufacturer must test the breaker at this fault level per ANSI standards. plus the primary rated current of transformer loads. Since a low voltage circuit breaker interrupts during the first half cycle.” for details about calculating fault currents and determining momentary ratings for switchgear. 732 ) (Eq.200 hp Motors Three . If the motor control center (or panelboard) is three-phase 4-wire. Example.000 amperes. For example.100 System Design Electrical Manual that the continuous current rating in that vertical section does not exceed 300 amperes.25 × 200 + 200 + (3 × 75) + 40) = 858 kVA 858 kVA . Examine the single phase loads.000.75 hp Motors 40 kVA Miscellaneous Load Assume 1 kVA per hp. the neutral bus should have a rating of 300 amperes. It is recommended that the total short circuit current of motor control centers be limited to 22. 65. the neutral bus should be rated for one-half the capacity of the main horizontal bus continuous current rating. both from the source and from the connected motors. however. The main bus must have a short circuit rating equal to or greater than the maximum available symmetrical short circuit current. to determine if the neutral capacity could be exceeded. Optional short circuit bus ratings of 42. Short Circuit Rating of Main Bus. It is good practice to provide 10 to 20% extra capacity on the main bus for future load growth. 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- May 1996 100-38 Chevron Corporation . a 1200 ampere rating is selected. Most of the load on the motor control center is balanced three-phase. To determine the short circuit current at the motor control center. therefore. Determine the main bus rating for a 480 volt MCC with the following running loads: Two .2 (1. if the main bus is rated 600 amperes.000 amperes so that standard starter units and buses can be used.” The industry standard short circuit rating for motor control center bus is 22. experience indicates that the load on the motor control center typically increases throughout design (and even after the facility is in operation). the unbalanced current flowing in the neutral bus is not expected to exceed half the capacity of the main horizontal bus. It should be noted that the standard 1000 ampere bus would have been adequate for the present load on the motor control center.000 and 100. The recommended minimum bus capacity (including 20% spare capacity) is: kVA = 1.= 1032 Amperes I = -----------------------------------( 480V ) ( 1. however. “System Studies and Protection. 100-5) Therefore. see Section 200.000 rms symmetrical amperes are available. A combination 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. low voltage power circuit breakers must be used for sizes over 1200 amperes.Electrical Manual 100 System Design ability.0 service factor motor. The trip setting of the MCP is set at 10 to 13 times the full load current of the motor. The maximum continuous rating of low voltage molded case circuit breakers is 1200 amperes. However. the maximum overload relay setting is 115% of full load Chevron Corporation 100-39 May 1996 . Molded case circuit breakers can also be used for manual switching. shall have an ampacity of not less than 125% of the continuous load current. These reactors can be sized to limit the short circuit current to the MCC to the accepted industry standard level (usually 22. After the feeder conductors are sized. The overload relay in each phase of the starter is selected on the basis of the full load current of the motor. Therefore. 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. according to NEC. Main circuit breakers may be deleted. Continuous Current Rating of Breakers and Contactors. the disadvantage of this method is that reactors increase voltage drop. If the standard trip setting of the circuit breaker does not correspond to the ampacity of the conductors. In this case. Combination starters are recommended to feed motors 200 hp or less. A short delay trip feature should be included on the main breaker to allow coordination with upstream breakers. 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. MCPs are rated corresponding to NEMA starter sizes. The continuous current rating of the main breaker must not exceed the continuous current rating of the main bus. the trip setting of the feeder breaker should be set to match the conductors’ ampacity. Feeder breakers in MCCs provide both overload and short circuit protection for the insulated conductors feeding the load. The maximum continuous current rating of circuit breakers is determined from the ampacity of the conductors they feed (NEC Article 240-3). Feeder conductors. Conductor ampacity requirements are based on the load and are determined by using NEC Article 220. An alternative design is to omit the main breaker and provide remote trip capability to the upstream breaker. 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. For a 1. The continuous ratings of MCPs are also listed in the table in ELC-DS-597. then the next higher rating is allowed by NEC. NEMA starter sizes and maximum horsepower are listed in a table on the data sheet ELCDS-597.000 amperes). however. the MCC bus should have a voltmeter and an ammeter. only where permitted by NEC. . inductive.100 System Design Electrical Manual current.000 symmetrical amperes or more.e. Enclosures are specified by NEMA type according to location (i. the maximum setting is 125% of the full load current. dust. Load Interrupter Switches. Switches Disconnect Switches. as well as for individual circuit breakers.g. indoor or outdoor). switches. such as motor control centers and switchgear. Their continuous current rating is sized the same as for disconnect switches. for a 1. Load interrupter switches are available in 600 amperes and 1200 amperes continuous ratings and 40. The short circuit momentary rating must be greater than the maximum available fault current. The load should not exceed the current rating of the switch at the voltage involved (NEC Article 380-14). corrosive conditions. and may be fused or unfused. Load interrupter switches can interrupt load current. Automatic transfer switches should be sized according to procedures described in Appendix A. Interrupting Rating of Breakers and Combination Starters. protect equipment from environmental conditions. The continuous current rating of a disconnect switch must be greater than the continuous load current of the load.000 amperes asymmetrical momentary current ratings. “Sizing of Automatic Transfer Switches” (Automatic Switch Co. 133 Enclosure Selection Equipment enclosures are used to isolate live parts. wind. May 1996 100-40 Chevron Corporation . environmental conditions (e. with short circuit momentary ratings of 10. rain. and ice). Safety switches are sized the same as disconnect switches except when used to switch: • • Motor loads.). Resistive. and area classification. Low Voltage Safety Switches.000 symmetrical amperes can be obtained by combining them with current limiting fuses. Standard short circuit ratings up to 200. Voltage levels typically are 600 volts and higher. The load should not exceed 80% of the current rating of the switch at its rated voltage (NEC Article 380-14). and satisfy area classification requirements. Low voltage safety switches are rated at 600 volts. Disconnect switches are not designed to interrupt load current. Automatic Transfer Switches. Breakers and starters should have the same current interrupting rating as the short circuit rating of the main motor control center horizontal bus. Low voltage safety switches are available in various sizes—from 30 amperes to 1200 amperes.15 service factor motor. and motor starters. or tungsten-filament lamp loads.. They are provided on large groups of equipment. hazardous (classified) locations. and hosedirected water is required. space considerations. Non-walk-in enclosures do not have room in the enclosure to work. NEMA Type 4 enclosures are recommended for indoor or outdoor locations where protection against windblown dust and rain. are not dust-tight or watertight. NEMA Type 1A (Type 1 with neoprene gaskets) enclosures are recommended for the same basic applications as NEMA Type 1. NEMA Type 7 enclosures are suitable for Class I. this type of enclosure is watertight and dust-tight. splashing water. If available. In addition to being corrosion-resistant. and corrosion. there is enough room inside the enclosure to work on the equipment in front of the gear. indoor locations where the equipment and enclosures are not exposed to unusual service conditions. NEMA Type 3R enclosures are recommended for many outdoor locations— primarily to provide a degree of protection against falling rain. The decision to install equipment indoors or outdoors is dependent on cost. • • • • • • Walk-in and Non-walk-in Enclosures. NEMA Standards 250 and ICS 6 describe the types of electrical equipment enclosures and their applications. NEMA 3R enclosures have solid bottoms and tops. hazardous (classified) locations. Below is a brief description of enclosure types recommended for typical applications: • NEMA Type 1 enclosures are recommended for general-purpose use in unclassified. Enclosed heat generating devices must not cause external surfaces to reach ignition temperatures of the surrounding atmosphere. If possible. Walk-in and non-walk-in enclosures are used to house motor control centers and switchgear in outdoor locations. Walk-in enclosures are recommended only for onshore facilities because the Chevron Corporation 100-41 May 1996 . NEMA Type 9 enclosures are suitable for Class II. but where some protection against dust and falling dirt and limited protection against light and indirect splashing are required. UL-listed NEMA Type 7 (or 9) enclosures with NEMA 4 features are recommended for outdoor classified area applications. sleet. NEMA Type 4X enclosures are recommended for use in most indoor or outdoor locations where corrosion protection is required. If outdoor enclosures are used. The enclosures. weathering. equipment should be installed outside of and away from hazardous (classified) locations to minimize the likelihood of fire and explosion and to reduce the cost of installation. The primary purpose of these enclosures is to prevent accidental contact by personnel with the enclosed energized equipment. greater care must be taken to ensure that the equipment is protected from water. In a walkin enclosure. and external ice formation. Often. proximity of the utilization equipment to the switchgear or motor control center. and the number of units to be supplied. outdoor enclosures are provided with space heaters to prevent moisture condensation.Electrical Manual 100 System Design Indoor enclosures are less expensive than outdoor enclosures. however. When it is necessary to install local starters in the field for a small group of motors located in a certain area. It may contain medium or low voltage switchgear. “Installation of Electrical Facilities. Power Houses. switchrack mounted starters may be desirable. See Section 1000. 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). motor control centers. installation and check-out time. A branch circuit is defined as the circuit conductors between the final overcurrent device and the load.” and Specification ELC-MS1675 for specific guidelines on routing and installing wire and conduits and cable systems. control stations. Outdoor Switchracks. NEMA Type 7 enclosures are required in Class I locations and NEMA Type 9 in Class II locations. salt air offshore can create potentially dangerous conditions for personnel to work inside the limited-space enclosures. custom-designed electrical distribution system in a prefabricated building. refer to Section 1100. and circuit breakers. starters. A power house is a complete. Space for routing feeders and branch circuits should be reserved as early as possible in the layout and design. a transformer) and the final branch circuit overcurrent device. 134 Feeder and Branch Circuit Systems Feeders and branch circuits are used to distribute electrical power throughout facilities. lighting panels.” for their selection.. NEMA Type 4 enclosures are usually recommended (NEMA 4X in corrosive atmosphere). “Wire and Cable. Power houses should be considered when there is significant interconnecting wiring since all internal wiring is done in the factory. relay panels and control panels. for example. Switch racks may contain other equipment. Power houses should be selected on the basis of cost. This section describes how to size conductors and raceways. Conductors Conductors must be sized to meet five different criteria: • • • • • Current carrying capacity (ampacity) Voltage drop Terminations Short circuit duty Mechanical strength May 1996 100-42 Chevron Corporation . The routing of conduit and cable is extremely important. Once conductors have been sized. Completely wired and tested units reduce field installation time (over conventional methods). and local preference. lighting transformers. A feeder is defined as all circuit conductors between the service equipment or source of the separately derived system (e. For use in outdoor unclassified areas.100 System Design Electrical Manual moist.g. Copper is required by the MMS in offshore OCS areas. The ampacity ratings of conductors are dependent on conductor material. and fires. Even though aluminum conductors are light weight and inexpensive. and Tables 310-69 through 310-84 contain rated ampacities for conductors over 2000 volts. temperature derating is determined by the following formula: TC – TA 2 – ∆ TD I 2 = I 1 × -----------------------------------------TC – TA 1 – ∆ TD (Eq. Ambient temperature derating factors for conductors rated 2000 volts or less are included in NEC ampacity Tables 310-16 through 310-19. Branch circuit conductors supplying a single motor must have an ampacity equal to or greater than 125% of the motor fullload current rating (NEC Article 430-22). aluminum is very ductile. TA1 I2 = ampacity at actual ambient temperature.Electrical Manual 100 System Design Current Carrying Capacity. For conductors over 2000 volts. heat. 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. Copper is the preferred conductor material because of its high conductivity and resiliency. type of insulation. 100-6) where: I1 = ampacity from NEC tables at ambient.) NEC Tables 310-16 through 310-19 contain rated ampacities for conductors rated 02000 volts. and the number of conductors in the raceway. Branch circuit conductors must have an ampacity not less than the maximum load to be served (NEC Article 210-19 and 220-10). 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-46426) NEC Appendix B contains tables for better approximation of 0-2000 volt cable temperatures for specific installations (these ratings are also based on Chevron Corporation 100-43 May 1996 . 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). more than three conductors in a raceway. resulting in high resistance. installation in underground electrical ducts. Requirements for sizing feeder and branch circuit conductors are provided by NEC. which causes terminations to loosen. and direct burial cable. The ampacity of conductors must be derated for the following conditions: high ambient temperatures. type of raceway. Note that the conductors should be installed so each conduit contains all three-phases (A. type of raceway. B. Faults must be cleared on 133% insulation level cable within 1 hour. Selection depends on: voltage rating. For cable tray installations. Single conductors below 1/0 cannot be used. “Wire and Cable. These factors are all described in detail in Section 1100. operating conditions.000 volts. which may be less expensive than large wire in one conduit over 4 inches.e. telemetering.” they may and should be used for more accurate ampacity estimates. Paralleling conductors allows the use of two conduits. In general. Standard size conductors used for paralleling are usually more readily available and easier to install than conductors larger than 500 MCM. 133% insulation level cable is recommended for medium voltage installations because of increased cable life and decreased likelihood of faults. 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 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.. 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). and C) to mini- May 1996 100-44 Chevron Corporation . Derating factors do not apply to conductors in conduits 24 inches long or shorter. the cable type must be listed specifically for use in cable trays. Although the code says “these are not part of the code but included for information only. the ampacities given in NEC tables must be derated by the derating factors following the tables. size of load. Descriptions of operating conditions and temperature ratings for low voltage insulations may be found in NEC Table 310-13. NEC Table 310-64 provides insulation thickness requirements for shielded conductors rated 2001 to 35. Computer programs for derating are available. and thermocouple cables. length of circuit. paralleling conductors should be considered. 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.” which contains recommendations for selecting power. NEC Article 318 contains requirements for cables installed in tray. If the required conductor size is larger then 500 MCM. When there are more than three conductors in a raceway or cable. and cost. instrumentation. Shielding is recommended on conductors rated 5 kV and higher. type of voltage (i. control. shielding. The type of insulation used depends on a number of factors which must be considered before making a final selection. 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. NEC Table 310-63 provides insulation thickness requirements for nonshielded conductors rated 2001 to 8000 volts. AC or DC).100 System Design Electrical Manual Equation 100-6). NEC Article 310-4 contains requirements for paralleling conductors.e. in feet R = line resistance for one conductor. For balanced three-phase AC circuits the approximate voltage drop formula is: VD = 1.e.. distance from overcurrent device to end device). and reactance in AC circuits.732 IL (Rcosφ + Xsinφ) (Eq. in amperes L = length of one conductor (i. distance from overcurrent device to end device).Electrical Manual 100 System Design mize induction heating. in ohms per foot X = line reactance for one conductor. 100-8) where: VD = voltage drop in circuit. For motor circuits. in feet R = line resistance for one conductor. Because of the phaser relationships between voltage. It also recommends that the total voltage drop on all conductors between the service-entrance equipment and connected loads be limited to 5%. line to neutral.. not only the steady state voltage drop but also the starting voltage drop must be considered. Fortunately. in volts I = current flowing in the 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. most voltage drop calculations are based on assumed limiting conditions. and. for long runs (particularly at low voltage) and conductors feeding critical circuits. the voltage drop should be calculated to ensure satisfactory operation. In most circuits. However. line to line. Voltage Drop. The NEC recommends (for efficiency of operation) that voltage drop should not exceed 3% on any feeder or branch circuit. the voltage drop is not significant. approximate formulas are adequate. in ohms per foot Chevron Corporation 100-45 May 1996 . 100-7) where: VD = voltage drop in circuit. therefore. current. Voltage drop should be considered when sizing conductors. in amperes L = length of one conductor (i. voltage drop calculations require a working knowledge of trigonometry for making exact computations. resistance. in volts I = current flowing in the conductor. A voltage drop table has been developed to easily determine voltage drop for most lighting circuits. This table also lists values of effective impedance (defined as Rcosφ + Xsinφ) calculated at 0. distance from overcurrent device to end device). Termination. R depends on the size of the conductor. it might be more economical to move the power center (substation) closer to the load. in ohms per foot If the calculated voltage drop is excessive. The reactance X depends on the size and material of the conductor. the type of conductor (copper or aluminum). If voltage drop is a problem with several loads. Conductors should be sized to limit conductor operating temperatures to those designated for the termination devices involved. in ohms per foot φ = angle whose cosine is the power factor of the load In using these formulas. however. unless marked with higher temperature limits. or steel conduit. so an average value is required. in feet R = DC resistance of conductor. For UL listed devices.e. it may vary with single conductor cables. in amperes L = length of one conductor (i. and on the spacing between the conductors of the circuit. aluminum. 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. the temperature of the conductor (normally 75°C for average loading and 90°C for maximum loading). a larger conductor size should be selected. and whether the conductor is installed in magnetic (steel) or nonmagnetic (aluminum or nonmetallic) raceway.. Voltage drop tables are sufficiently accurate to determine the approximate voltage drop for most problems. in volts I = current flowing in the conductor.100 System Design Electrical Manual X = line reactance for one conductor. The spacing is fixed for multi-conductor cable. the line current is generally considered to be the maximum or assumed load current carrying capacity of the conductor. 100-9) where: VD = voltage drop. The angle φ between the load voltage and load current is determined from the power factor of the circuit: φ = arccos (power factor). whether the raceway is magnetic or nonmagnetic. The resistance R is the AC resistance of the particular conductor used and of the particular type of raceway in which it is installed. See Section 136 for details. the terminals of devices May 1996 100-46 Chevron Corporation . For single phase DC circuits the voltage drop formula is: VD = 2ILR (Eq.85 power factor. should be considered when determining conductor operating temperature. conductor impedance. switchboard and motor control center construction.20. “Wire and Cable. where power cables may terminate on the terminals of molded-case circuit breakers or starters.5.5 of each of these standards limits the temperature of the air surrounding insulated power cables to 65°C. Mechanical Strength. In metal-enclosed switchgear.2 for metal-enclosed interrupter switchgear. “System Studies and Protection. Voltage of Conductor (volts) Up to 2000 Minimum Conductor Size (AWG) 12 Chevron Corporation 100-47 May 1996 . The minimum recommended conductor sizes for power and lighting circuits are given below. ANSI/IEEE C37. Short circuit duty requires a minimum conductor size according to ICEA requirements for transient temperature limits to avoid damaging thermal and mechanical stresses. Paragraph 4. 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. Selection of cable size for short circuit duty should be based on anticipated actual short circuit current (including the effect of breaker impedance.20. the designer shall assure that the actual conductor temperature does not exceed the temperature rating of the terminal device. Devices rated in excess of 100A are typically limited to 75°C. In selecting circuit conductors.” for details. or a total temperature of 85°C.1 for low-voltage switchgear.” for information on calculating short circuit currents. not directly on the terminals of the main switching device. Table 4 of each standard limits the temperature rise of silver-or tin-surfaced connections to insulated cables to 45°C. All three of these standards require the same temperature for these features. when the switchgear assembly is equipped with devices having the maximum current rating for which the assembly is designed. Short Circuit Duty. power cables usually terminate on buswork. which limit the actual current allowed in circuit wiring.Electrical Manual 100 System Design rated 100A or less are typically limited to operating temperatures of 60°C. For control wiring. the minimum recommended single conductor size is 14 AWG. This is in contrast to panelboard. is carrying rated continuous current. and ANSI/IEEE C37. The minimum conductor size recommended for instrumentation and thermocouple cables is 18 AWG for single pairs and 20 AWG for multiple pairs. The tests to demonstrate conformance with these limiting temperature rises require including appropriate sizes and lengths of power cables in the continuous current path. Conductor size should be checked to avoid severe permanent insulation damage from short circuit currents during intervals of fault-current flow. The minimum conductor sizes for various insulations are shown in Table 79 of IEEE Std 141 or in ICEA P-32-382. and is in an ambient temperature of 40°C. The allowable 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. See Section 1100. The derating required for motor circuits and continuous loads on devices such as circuit breakers. See Section 200. arcing fault impedance and breaker trip time). “Minimum Conductor Sizes for Fault Current and Clearing Times” NEC Table 310-16. This example illustrates how to size conductors to feed a 100 hp motor. b. f.Three-Phase Alternating Current Motors” NEC Table 9.000 8 6 2 1 Example Calculation for Sizing Conductors. h.5 amperes. c.000 amperes symmetrical Power factor of motor: 0. above ground Conductors: three copper. Since the maximum ampacity of the conductor is greater than 155 amperes.000 Above 15. b. c. e. • Design Parameters a.94) = 164. g. 2/0 AWG conductors should be selected. Therefore. the load current for a 100 hp motor is 124 amperes. with an alarm for manual fault clearing Tables Used a. rated 75°C Circuit Length: 400 feet from overcurrent device to motor Voltage drop allowed: 3% (cable drop only) Ambient temperature: 35°C (105°F) maximum Short circuit current available: 15.25 x 124 amperes = 155 amperes. • Voltage and frequency of utilization: 480 VAC. Minimum size for mechanical strength: 12 AWG (based on circuit voltage) Minimum size for load current: From NEC Article 430-150. d. and the derating factor for 35°C ambient is 0.85 Ground: high resistance. i. “Full-Load Current . “Allowable Ampacities” NEC Table 430-150.94. 75°C rated conductor temperature has an ampacity of 175. “AC Resistance and Reactance for 600 V Cables” • Conductor Sizing a. THW. NEC Article 430-22 requires that the branch circuit conductors be sized to carry 125% of motor full load current: 1. 60 Hz Raceway: steel conduit.100 System Design Electrical Manual 2001 to 5000 5001 to 8000 8001 to 15. Table 79. May 1996 100-48 Chevron Corporation . From NEC Table 310-16. type THW single conductors. b. d. IEEE Std 141. 2/0 AWG. 600 volt. the maximum ampacity is 175 (0. “Installation of Electrical Facilities.) Maximum of 3% voltage drop in feeder at load current VD = 1. IEEE Std 141.000 amperes fault at 1/2 cycle and 2/0 AWG for 15.g.732 (124) (400) (0.Electrical Manual 100 System Design c. Aboveground conduit systems are generally used where there are overhead pipeways or structures to provide support for the conduits. VD = 1.732 IL (Rcosφ + Xsinφ) I = 124 amperes L = 400 ft d.” Raceway Systems Four types of raceway systems are commonly used to distribute electrical power in industrial systems. Overhead conduits should be either schedule 40 rigid. when no means for adequately supporting conduit is available). Figure 100-16 shows some of the advantages and disadvantages of the different conduit systems. hot dipped galvanized steel or schedule 40 copper-free aluminum conduit. It is recommended that underground conduits be enclosed in a red concrete bank for protection from damage and for ease of recognition during excavation. as dictated by overall economics and facility site requirements.× 100 = 2. schedule 40 PVC conduit. (See Table 79. “System Studies and Protection. From Table 9 of NEC. see Section 200. Minimum size for short circuits: 6 AWG for 15.85 power factor for 2/0 AWG is 0.00011) = 9. PVC coated galvanized steel conduit.00011 ohms per foot.45 volts 9. 100-10) For motor starting voltage drop calculation procedures.45 . rigid galvanized steel conduit.0% %VD = --------480 (Eq.000 amperes fault at 10 cycle clearing time for PVC insulation. See Section 1000. • • • • Conduit systems Cable trays Direct burial cables Submarine cables Conduit Systems.” for details about selecting and installing 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. Chevron Corporation 100-49 May 1996 . and PVC coated aluminum conduit may be used. In an underground conduit system. the effective “Z” (defined as Rcosφ + Xsinφ) at 0.. In general. and 3C may be used to determine the number of conductors if only one type of conductor is installed in the conduit.9834 + 0. easy accessibility for repair or addition of cables. armored cables are used instead of TC cables.g. and channel. See Section 1000. the percentage of fill must be calculated using Tables 4 through 8. TC Type Cables). 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. 18. trough. 40% fill is allowed for four conductors in conduit. Area of one 4 AWG THWN conductor is 0. which lists approximate diameter and cross-sectional area of various conductors: Total area of three 4/0 THWN wires is 3 x 0.9834 in2. the actual dimensions should be used. for more than two conductors at 40% fill. A cable tray system offers low installed cost.0679 in2. For aboveground systems. 12. Total area of the conductors is 0. Tables 1 through 8 in Chapter 9 of NEC are used to determine conduit fill and the maximum number of conductors allowed.0845 in2. such as compact or multi-conductor cables. 60% of the total cross-sectional area may be filled. 3B.. For conductors not included in Chapter 9. From Table 5 of NEC. In most process facility cable tray installations. From Table 4 of NEC. 30. If a combination of conductor types is needed. When a conduit or nipple installed between junction boxes. cabinets. 24.” Cable Tray Systems. The normal sizes (widths) of cable trays are 6. and is space saving when compared to conduits where there are large numbers of circuits with a common routing. “Installation of Electrical Facilities. and similar enclosures does not exceed 24 inches in length. the minimum recommended size of conduit used in underground systems is 1 inch. Cables used in cable tray systems must be approved specifically for cable tray installations (e. Tables 3A. May 1996 100-50 Chevron Corporation . The four different types of cable trays are ladder.3278 = 0. Conductor jamming in the conduit must be considered when sizing conduits.0845 = 1. From Table 1 of NEC. solid bottom. and 36 inches. system flexibility.100 System Design Electrical Manual Sizing of conduit is based on the percentage of cross-sectional area of conduit filled by the conductors or cables. the minimum recommended size is 3/4 inches for galvanized steel and 1 inch for aluminum. the minimum trade size of conduit allowed is 2 inches. Easy conventional installation. Inexpensive. No ground continuity. It permits liberal air flow. Requires intermediate supports. Solid bottom cable tray affords maximum protection against damage. Corrosion-resistant in most atmospheres. and mechanical damage. it provides no ventilation. Solid Chevron Corporation 100-51 May 1996 . repair. because it has a solid bottom. Not approved for Class I areas. easy accessibility for repair or addition of cable. Same as for rigid conduit. explosion. Aluminum cable tray with multiconductor cable wiring. corrosion. Labor intensive. Subject to deterioration by U/V.General Galvanized steel cable tray with multi-conductor cable wiring. Ladder cable tray is used primarily with power cables and other heat-producing cable. 100-16 Comparison of Raceway Systems Method of Distribution Underground conduit General Aboveground conduit General Rigid conduit and single conductor wiring. Expensive. High maintenance cost. Low installed cost. Provides high degree of mechanical protection. but more resistant to corrosion. Not recommended for Company installations. Most expensive. Fiberglass cable tray with multiconductor cable wiring. Electricians familiar with installations. Disadvantages Not accessible for maintenance. Additions and modifications simply made. Very low cost. Has history of installation problems. Least susceptible to corrosion. Same as for rigid conduit. Light weight. high exposure to corrosion. More accessible for maintenance. and mechanical damage. Highest resistance to corrosion. IMC conduit with single conductor wiring. Usually available only in 12-foot lengths. Solid bottom cable tray is not commonly used because its cost is about 30 to 50% more than the ladder type. structural supports always required. repair and additions. PVC coated conduit (coated on outside only) with single conductor wiring. PVC coated cable tray with multiconductor cable wiring. Additional supports required. High cost. Greater exposure to fire. More corrosion-resistant than galvanized steel. but. PVC coated conduit (also coated on the inside) with single conductor wiring. Most readily available materials. Advantages Best protection against mechanical and fire damage. Greater exposure to fire. Susceptible to corrosion in some atmospheres. and additions. Expensive fittings. Rigid PVC conduit with single conductor wiring. Cable tray .Electrical Manual 100 System Design Fig. More resistant to corrosion than conduit coated just on outside. Subject to corrosion pockets despite PVC coating. Friction factor for pulling wire is greater than for conduit with no inside coating. but does not offer total protection against damage from external sources. explosion. corrosion. Not allowed by MMS in classified areas offshore. Very expensive. refer to Articles 318-9 through 318-11.1 × Sd) = 1. Column 2.34 in2.0 4.83 in2. 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. It represents a compromise between the primary features of ladder and solid bottom tray. Trough cable tray permits average ventilation and average protection against cable damage.951 = 4. In addition. and communication cables that do not develop heat.1 × 3.4026 in2. This cable tray is used when there is not space for larger tray or when large tray is uneconomical.4026 = 4. Chapter 9) = 1.66 in2. the maximum allowable fill area is 6. a 6 inch cable tray is not large enough. When sizing cable trays.66 in2. the cable weight should be checked to ensure that it does not exceed the manufacturer’s recommendations for maximum deflection.951 inches (1. By the formula in NEC Table 318-10. The conductors are type THWN rated 600 volts. Trays are available in different strengths for minimizing sagging. May 1996 100-52 Chevron Corporation .34 = 2.16 in2. see Section 1000. Area of one 250 MCM conductor (NEC Table 5. type of conductors or cables. For more details on cable tray installation. Sd = 3 × 1. From Table 318-10 for 12 inch cable tray.34 = 8. From Table 318-10 for 6 inch cable tray. control. a cable tray 12 inches wide and 6 inches deep should be selected to conform to NEC.16 in2. “Installation of Electrical Facilities.5 4. the maximum allowable fill area is 13.83 in2) is larger than 2. Diameter of one 1000 MCM conductor (NEC Table 5.” 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 conductors. and sizes of conductors or cables in the cable trays. Area of twelve 250 MCM conductors = 12 × 0. Since the area of the 250 MCM conductors (4. consideration must be given to loading and support systems. For cables and conductors rated over 2000 volts nominal refer to Articles 318-12 and 318-13. Since the area of the 250 MCM conductors is smaller than 8. 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.100 System Design Electrical Manual bottom cable tray should be used only for instrumentation. Chapter 9) = 0.317 = 3. The sizing of cable trays depends upon the rated voltage level.317 inches Sd = Sum of the diameter of three 1/C 1000 MCM THWN wires. the area of all cables smaller than 1000 MCM should not exceed the maximum allowable fill area resulting from the computation. prolonging insulation life (by limiting overvoltage). A high resistance grounded system is grounded through an impedance. The cables used must be suitable for direct burial and identified for such use (NEC Article 310-7). primarily resistive. The system limits ground fault currents to a value that will minimize damage to equipment.” 135 Grounding Grounding is essential for personnel safety. “Installation of Electrical Facilities. 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.” Submarine Cables. and Inland Locations. refer to Section 900.) The metallic shield.g. but values of ground fault current can be large. For direct burial cable installation details. see Section 1000. primarily resistive. A completely ungrounded system can be hazardous to personnel and is subject to excessive overvoltage. For a detailed discussion on grounding. where the ground fault current is limited between 25 amperes and several hundred amperes. Refer to Tables 300-5 and 710-3(b) of NEC for minimum depth requirements. compliance with various codes. where the ground fault current is limited to less than 10 amperes. There are three methods of system grounding: solid. Direct Burial Cables.” System Grounding. transformers and generators). yet allow sufficient ground current for selective relay performance. Direct burial cables rated over 2000 volts nominal must be shielded (NEC Article 310-7. and high resistance. System grounding involves grounding the neutral point of separately derived sources (e.. For more information see “Chevron Eastern Region-ELEP. Low resistance grounded systems are not subject to excessive overvoltage due to arcing faults. Electrical Construction Guidelines for Offshore.Electrical Manual 100 System Design See Figure 100-16 for a comparison of the advantages and disadvantages of wire and conduit systems and cable tray systems. A low resistance grounded system is grounded through an impedance. Solidly grounded systems are not subject to excessive over-voltages during ground fault. low resistance. Direct burial cables are recommended only when the need for future maintenance along the cable run is not anticipated. and for fast selective isolation of ground faults (thereby improving equipment protection). Submarine cables are used primarily to provide power to offshore platforms from shore and from one platform to other. A solidly grounded system is connected directly to ground through an adequate ground connection where no impedance has been inserted intentionally. Various types of grounding are described below. They are used on 2 kV through 15 kV systems. “Grounding Systems. sheath or armor must be grounded per NEC Article 310-7 (for personnel safety in the event of accidental dig-in). The Chevron Corporation 100-53 May 1996 . Marshland. They are used on low voltage systems (0-1000 volts) and systems over 15 kV when immediate tripping is desired. Submarine cables are generally medium voltage to high voltage cables. 100 System Design Electrical Manual 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 enclosures, 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, structures, 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 Lighting The 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 emergency lighting requirements. May 1996 100-54 Chevron Corporation Electrical Manual 100 System Design Voltage Level The 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 Sizing A 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 fourwire 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 (overcurrent 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. Standard 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 recommended 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 Calculations NEC 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 Chevron Corporation 100-55 May 1996 100 System Design Electrical Manual 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. 2. 3. The conductors are copper, installed in rigid steel conduit. The circuit is single-phase two wire—ungrounded (hot) and grounded (neutral) conductors. 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. Conductor temperature is 75°C or less. 4. 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 manufacture’s literature). For two 8 AWG conductors: Ampere feet = (2.7A + 2.7A) (500ft) = 2700 A-ft VD = 3.78V (from Figure 100-17) 3.78 - × 100 = 3.2% %VD = --------120 (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) May 1996 100-56 Chevron Corporation Electrical Manual 100 System Design Fig. 100-17 Voltage Drop Table Chevron Corporation 100-57 May 1996 100 System Design Electrical Manual Fig. 100-18 Voltage Drop Calculation, Example 1 2.5 - × 100 = 2.1% %VD = -------120 (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. 100-19 Voltage Drop Calculation, Example 2 May 1996 100-58 Chevron Corporation Electrical Manual 100 System Design The rated operating current for each 250 watt HPS fixture is 2.7A (from manufacturer’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: 2.57 - × 100 = 2.14% %VD3 = --------120 (Eq. 100-13) Therefore, 8 AWG wire is large enough for this application. 137 System Protection Power 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 coordination study. Section 600, “Protective Devices,” describes how to select relays, current transformers and potential transformers, and how to plot relay curves on the timecurrent coordination sheet. It also discusses the major relays used for protection of components in an industrial electrical system. Chevron Corporation 100-59 May 1996 100 System Design Electrical Manual 140 References The 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 Standard Manual Transfer Panel for Double-Ended Substations 480-V Stand-by Power System, One-Line Diagram Typical One-line Diagram Data Sheet for Instructions for 480 V Motor Control Rack Specifications and Arrangement Data Guide for Instructions for 480 V Motor Control Rack Specifications and Arrangement Schedule of Motors and Starters Lighting Schedules Electrical Symbols and Index of Reference Drawings Equipment Schedule and Reference Drawings 142 Standard Drawings GF-P99968 GF-P99972 GF-P99988 *ELC-DS-597 *ELC-DG-597 *ELC-EF-204 *ELC-EF-484 *ELC-EF-541 *ELC-EF-759 143 Data Sheets (DS), Data Guides (DG), and Engineering Forms (EF) 144 Appendices Automatic 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 References American Petroleum Institute (API) *RP 14F *RP 540 Design and Installation of Electrical Systems for Offshore Production Platforms Recommended Practice for Electrical Installations in Petroleum Processing Plants IEEE Recommended Practice for Electric Installations on Shipboard. Distribution, Power and Regulating Transformers. IEEE Recommended Practice for Electric Power Distribution for Industrial Plants. Institute of Electrical and Electronics Engineers (IEEE) ANSI/IEEE Std 45 IEEE Std C57 ANSI/IEEE Std 141 May 1996 100-60 Chevron Corporation Electrical Manual 100 System Design ANSI/IEEE Std 446 ANSI/IEEE Std 485 Vol. IA-9 No. 3 IEEE Recommended Practice for Emergency & Standby Power Systems for Industrial and Commercial Applications. IEEE Recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations. “Features of a Power System Incorporating Large AC Motors/Captive Transformers,” IEEE Transactions on Industry Applications, May/June 1973. National Electrical Code (NEC). System Grounding for Low-Voltage Power Systems. Transformer Connections, Dec. 1967. Short Circuit Characteristics of Insulated Cable Enclosures for Electrical Equipment (1000 Volts Maximum) Enclosures for Industrial Controls and Systems. National Fire Protection Association (NFPA) ANSI/NFPA 70 GET-3548 GET-2H ICEA P-32-382 NEMA 250 ANSI/NEMA ICS6 General Electric Company (GE) Insulated Cable Engineers Association (ICEA) National Electrical Manufacturers Association (NEMA) Other Publications Beeman, Donald. Industrial Power Systems Handbook. New York: McGraw-Hill Book Co., Inc., 1955. Chevron Corporation 100-61 May 1996 200 System Studies and Protection Abstract This 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 210 211 220 221 222 223 224 225 226 227 228 230 231 232 233 234 235 236 Introduction System Studies Summary Short-Circuit Studies Scope Reasons for a Short-Circuit Study When to Conduct a Short-Circuit Study Short-Circuit Study Methods Short-Circuit Analysis: Example Using the Per-Unit Method Comments on the Short-Circuit Calculation Example Computer Methods for Calculating Short-Circuit Current Electrical Systems Analysis Computer Programs Motor-Starting Studies Scope Reasons for a Motor-Starting Study When To Conduct a Motor-Starting Study Voltage-Drop Calculations Data for a Voltage-Drop Calculation Voltage-Drop Calculation: Example 200-32 200-4 Page 200-3 Chevron Corporation 200-1 May 1996 200 System Studies and Protection Electrical Manual 237 238 239 240 241 242 243 244 250 260 270 271 272 273 274 Correcting for Unacceptable Voltage Drop Motor Acceleration Time Calculation Computer Programs That Simulate Motor-Starting Load-Flow Studies Reasons for a Load-Flow Study When To Conduct a Load-Flow Study Data for a Load-Flow Study Interpreting Computer Load-Flow Data Transient-Stability Studies Harmonic Analysis Studies References Model Specifications (MS) Standard Drawings Data Sheets (DS), Data Guides (DG) and Engineering Forms (EF) Other References 200-55 200-57 200-58 200-54 May 1996 200-2 Chevron Corporation Electrical Manual 200 System Studies and Protection 210 Introduction This 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 Summary A 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 shortcircuit 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 determine 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 intensity 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 shortcircuit 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 Chevron Corporation 200-3 May 1996 200 System Studies and Protection Electrical Manual 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 shortcircuit 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 Scope A 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 potential 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 references, but rather to recommend that they should be consulted when performing critical 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. May 1996 200-4 Chevron Corporation Electrical Manual 200 System Studies and Protection 222 Reasons for a Short-Circuit Study In any system subject to a fault current there is a short period of time before protective devices operate when the system components are exposed to high-fault currents. A short-circuit study helps ensure that system components are appropriately 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 Study A 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 electrical 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 Methods There 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”) Chevron Corporation 200-5 May 1996 It is not discussed in this section. or for quick checks of calculations done by computer or by the per-unit method. as it incorporates the detailed methods currently accepted by IEEE. 200-1) The system is modeled as a single phase line-to-neutral circuit with a single phase line-to-neutral driving voltage (E L-N). generators. and the fault current is calculated by the equation: IFault = EL-N/Z (Eq. The Per-Unit method is utilized in most computer programs for the solution of short-circuit studies. May 1996 200-6 Chevron Corporation . The IEEE Per-Unit method is the most commonly used. transformers. It also is useful as a preliminary study to determine if a computer study is necessary. This is the method which should be used to determine the required equipment ratings on large electrical projects. 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. as shown in Figure 200-1. The IEEE Red Book (Per-Unit) Method The 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. A description and example of the Per-Unit method is presented below.) associated with the motors.200 System Studies and Protection Electrical Manual • • Ohmic method IEEE Per-Unit method The MVA method is probably the easiest to use. Yuen explaining the MVA method is included as Appendix C. Line-to-Neutral Model. and utility. a computer study may not be necessary. The object of modeling is to reduce the entire system to an equivalent circuit. An article by M. The ohmic method is seldom used since it requires extensive calculations to reflect impedances across transformers. 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. The modeled impedances are real and reactive circuit impedances (Zequiv. and is recommended to those unfamiliar with this method. If there is sufficient margin between the equipment capabilities and the maximum fault current indicated by the MVA method. The Red Book should be consulted when performing a large or critical study. Ohm’s law can then be applied. cables. This article presents the material in an easy to understand manner. and because the ratings of the equipment in the ANSI standards are based on this method. The MVA Method The primary application of the MVA method is for quick calculations in the field. Figure 200-3(a) shows a three-phase faulted system consisting of a generator or utility and motor load. IF. shown in Figure 200-3(d) represents the line to neutral model of Figure 200-3(c). Maximum Fault. A very small amount of load current may still flow to the non-motor load. There are now two voltage sources in the line-to-neutral model in Figure 200-3(b). represents the line-to-neutral model of Figure 200-2(c). Since the per-unit voltage of both sources is near unity at the instant of fault. the generator is represented by a single phase driving voltage. the maximum fault is a three-phase bolted fault. the three-phase representation (Figure 200-2(a)) has been replaced by an equivalent line-to-neutral model. Most of the fault current. The impedance diagram. Thevenin’s law allows them to be combined into one voltage source. as shown in Figure 200-3(c). and the motor slows down. In Figure 200-2(b). shown in Figure 200-2(d). and its resistance is represented by Rs. In most systems. resulting in the refined line-to-neutral model of Figure 200-2(c). A three-phase bolted fault is a short circuit where all three phases are connected at the fault location by a zero impedance path. the voltage at the fault drops to almost zero. Since the voltage is almost zero with respect to neutral at the fault location. When a fault occurs. it acts as an induction generator and contributes additional fault current IM to the fault. The non-motor load is simply a resistance and reactance added to the feeder circuit resistance RL and reactance XL. The commonly seen impedance diagram. IL is usually neglected. While it is slowing down.Electrical Manual 200 System Studies and Protection Fig. flows through Xs and Rs to the fault and back to the neutral side of the generator. Its inductive reactance is represented by Xs. In Figure 200-2(b). 200-1 Equivalent Circuit of Fault Network 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. Chevron Corporation 200-7 May 1996 . 200-2 Derivation of Line-to-Neutral Models with Non-Motor Loads for Short-Circuit Studies May 1996 200-8 Chevron Corporation .200 System Studies and Protection Electrical Manual Fig. Electrical Manual 200 System Studies and Protection Fig. 200-3 Derivation of Line-to-Neutral Models with Motor Loads for Short-Circuit Studies Chevron Corporation 200-9 May 1996 . The size of the initial asymmetrical peak depends on the point on the voltage waveform May 1996 200-10 Chevron Corporation . 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. This fault is usually less than the threephase bolted fault.200 System Studies and Protection Electrical Manual Another type of fault is a line-to-line fault. the subtransient reactance of the motor. This value can be obtained from the motor manufacturer (usually shown on the motor data sheet). the ground fault current is limited to a known quantity by high or low resistance grounding. The subtransient reactance may be approximated by: (Eq. This fault occurs when two of the phase conductors are connected with zero impedance. and the current wave changes to the symmetrical form. Usually at the instant a system fault is initiated. Asymmetrical and Symmetrical Fault Values. For standard fault calculations. The time required for the DC component to decay depends on how much resistance is in the circuit. An approximation of the ground fault current is necessary for coordination of ground fault relays. 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. 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. Representing Motors as an Impedance. 200-3) It then follows that the initial slope of the current curve must be E/L. decay over a few cycles. Therefore. 200-2) The subtransient reactance is given in per-unit with respect to the kVA base of the motor. however. X"d. The magnitude of this fault is usually 87% of the three-phase bolted fault. The DC component of the current waveform does. the short-circuit current wave is not completely symmetrical as shown in Figure 200-4. In some refineries and industrial plants. it will also withstand a line-to-line fault. motors are represented by a per-unit reactance quantity. therefore a ground fault study is usually unnecessary. inducing a voltage equal to: (Eq. The current cannot change instantaneously to coincide with the symmetrical steady state waveform. the current behaves in accordance with the properties of an inductor. A third kind of fault is the ground fault. so if the system is designed to withstand a three-phase bolted fault. it is standard practice to first solve for the symmetrical rms short-circuit current and then apply a multiplying factor to the result. Circuit breakers and fuses must have the capability to interrupt the asymmetrical current. A 1. smaller multipliers (indicated in the Red Book) may be used. 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. Momentary Ratings and Interrupting Ratings. If the IEEE Red Book method is used. at which the short-circuit is initiated. Chevron Corporation 200-11 May 1996 . 1993. 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. To account for the asymmetry of the current wave. 200-4 Asymmetrical and Symmetrical Fault Current Wave Shapes From IEEE Standard 142. Ch. 2.Electrical Manual 200 System Studies and Protection Fig. A short-circuit initiated at a voltage zero crossing causes the maximum asymmetrical peak of current. possibly resulting in lower calculated fault current values. The electrical equipment must be able to withstand the electrical and mechanical stresses associated with this increased current. Used with permission. It is not the value of the current which the circuit breaker interrupts.6 multiplying factor may conservatively be applied to faults at all voltage levels. 5. It is less than or equal to the momentary rating. or 8 cycle) and the proximity of the fault to generator and utility sources. or 8 cycle point. As a result. The first cycle network is used for calculating the short-circuit current for comparison with the interrupting ratings of fuses (low and high voltage) and low voltage circuit breakers. Most manual calculations use the first cycle network. Within two to eight cycles after the initiation of the short circuit. The per-unit (PU) system is a mathematical tool using per-unit values to simplify short-circuit calculations. Multipliers are applied to the motor subtransient reactances to represent them as smaller contributors to the fault current. For additional information. the motor contribution has decreased. 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. Short-Circuit Impedance Networks. depending on the speed of the circuit breaker (2. This network ignores the motors in the network. 3. Per-Unit Values. since it is the most severe case. only considering generators and passive elements. 5. depending on the design of the circuit breaker. Different impedance diagram networks are used depending on the purpose of the short-circuit study. (Eq. the calculated rms symmetrical short-circuit current is smaller than that of the first cycle network. Multipliers are also applied to the calculated fault duties. These devices interrupt the short-circuit current sometime within the first cycle. such as transformers and cables. 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.200 System Studies and Protection Electrical Manual 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. 3. 200-4) May 1996 200-12 Chevron Corporation . The calculated short-circuit current for this network is smaller than either the first cycle network or the interrupting case network. The interrupting case network applies to medium and high voltage circuit breakers which interrupt the short-circuit current at the 2. A per-unit value is a ratio of a number to a base number. see the IEEE Red Book. Subtransient reactances are used to represent rotating machines in this network. express all parts of the electrical system in per-unit terms as follows: (Eq. Base Value Relations. For example. and kVA for a given electrical system. Using the selected base values.06 per-unit.076 per-unit on a base of 225. the per-unit value of 17 is 17/225 = 0. 200-7) (Eq. the base quantities can be determined from the following basic equations: Chevron Corporation 200-13 May 1996 . ohms. 200-5) To change percent values to per-unit values. The per-unit value of 225 on a base of 225 is 225/225 = 1 per-unit. Impedance of electric equipment is usually given in percent. Percent values are obtained by multiplying the per-unit value by 100. Percent Values. 200-6) (Eq. first select base values of voltage. if the base number is 225. a transformer which has an impedance of 6% has an impedance of 0. To use the per-unit system. These bases provide a reference to which resultant per-unit values can be compared.Electrical Manual 200 System Studies and Protection For example. (Eq. 200-8) In a similar manner. divide the percent value by 100. It is convenient to convert these figures immediately to per-unit by dividing by 100 (to avoid confusion). current. 200-12) Note Base kVA is the three-phase kVA. 200-10) Note Single-phase voltages are given in line-to-neutral values.= Ohms b Base Ohms = -------------------------Base Amps (Eq. All per-unit formulas are summarized in Figure 200-5. Fig. 200-5 Per-Unit Calculation Summary Sheet for Three-Phase Systems (1 of 2) Actual Quantity Per-Unit Quantity = -----------------------------------Base Quantity Base kVA = Base kV × Base Amperes × 3 Base kVA kVA ( 1000 ) Base Current (Amperes) = Base -------------------------------------.= ---------------------------------------3 ( Base kV ) 3 ( Base Volts ) May 1996 200-14 Chevron Corporation . Three-Phase System Equations (Eq. Base Ohms is ohms per phase. 200-9) Base Volts .200 System Studies and Protection Electrical Manual Single-Phase System Equations Base kVA Base Amps = -----------------------.= -----------------------------3 ( Base kV ) 3 ( Base Volts ) Base MVA ( 1000 ) Base MVA ( 10 6 ) = -------------------------------------. and base voltage is line-to-line voltage. 200-11) (Eq.= I b Base kV (Eq. C.= -------------------------------------Base kVA ( 1000 ) 3 ( Base Amperes ) ( Base kV ) 2 ( Base kV ) 2 ( 1000 ) = -----------------------------------------. 3 Selecting Base Values. Ohms on a Different MVA Base: Desired MVA Base P. In the example one-line diagram.Electrical Manual 200 System Studies and Protection Fig. The Chevron Corporation 200-15 May 1996 . Ohms on Given MVA Base given MVA Base 3. MVA 2.U.U.U. Zutil = -----------------------------------Utility S. Ohms on kVA New Base = ----------------------------------kVA Old Base Changing Base Volts ( Old Base Volts ) 2 P.× P.U. Given Utility Short Circuit MVA: P. where motor kVA = F.. Ohms on Old Base Volts × --------------------------------------------( New Base Volts ) 2 Utility Impedance MVA Base 1.× P. it is necessary to select a single base kVA or MVA and base voltages for every voltage level in the system. This base MVA applies to all voltage levels in the entire system. Ohms = x"d × ---------------------------------Generator kVA Note All voltages are Line-to-Line. All kVA’s are three-phase.U. Amps × Motor kV × P.U.U.U. Ohms = -----------------------------------------------------------------------------------------------3 ( S. Ohms on New Base Volts = P. Amperes ) ( kV Rating of System ) Transformer Impedance %Z Tx Base kVA . the base MVA is chosen to be 100 MVA.U.L.U.U.U.× ------------------------------------------------------------------------------P. Ohms = ------------100 kVA ( Self-Cooled ) of Transformer Cable Impedance Base MVA P. 200-5 Per-Unit Calculation Summary Sheet for Three-Phase Systems (2 of 2) Base Volts ( Base Volts ) 2 Base Impedence (Ohms) = ---------------------------------------------.U. Figure 200-6. Ohms = Actual Impedance in Ohms × -------------------------( Base kV ) 2 Motors Base kVA . Given Utility P.= -------------------------Base MVA Base kVA Changing Base kVA kVA New Base . Given Utility Short Circuit Amperes (RMS symmetrical): Base kVA P.C. Ohms on Desired MVA Base = -------------------------------------------. Ohms on kVA Old Base P. At the beginning of a short-circuit study. Ohms = x"d × -----------------------Motor kVA Generators Base kVA P. as follows: ( kV old ) 2 kVA new . C3. they must be converted to the new kVA base. Changing kVA Bases of Circuit Elements. For further detailed information on the use and application of the per-unit system.). M3. The chosen base voltages are 115 kV... the following formula is used: ( kV old ) 2 . they must be converted to the new kV base.16 kV.. 2.). G2. see References 1. To be used as per-unit impedances on the chosen system base. Use a system one-line diagram to collect the necessary data. 4. 200-13) Ohms pu new Changing Voltage Bases of Circuit Elements. 13. although typical values are 10 MVA or 100 MVA.8 kV. and 5. motors (M1. C2.200 System Studies and Protection Electrical Manual choice is arbitrary and any value will work. and 480 volts. The step-bystep procedure for short-circuit calculations is as follows: 1. Identify all buses on the one-line diagram with unique numbers. General Step-by-Step Procedure for Short-Circuit Calculations.). May 1996 200-16 Chevron Corporation . Impedances may be changed to a new kVA base and a new kV base by combining the equations above. It is helpful to identify all circuit components such as generators (G1. transformers (T1.) and cables (C1. To do this. To be used as per-unit impedances on the chosen system base. T3.× -------------------= Ohms pu × ----------------------old ( kV ) 2 kVA new old Ohms pu new (Eq.. M2. 200-15) These equations for changes of bases are demonstrated in the example in Section 225 below. usually the nominal voltage of the system.. T2.. use the following formula: kVA new .. 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. G3.× Ohms pu = -------------------old kVA old (Eq. Notice that each bus has its own base voltage. Sometimes a machine rated at one voltage may be used in a circuit at a different voltage. as shown in Figure 200-6. 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.. To do this. 200-14) Ohms pu new Changing Both kVA and Voltage Bases.× Ohms pu = ----------------------old ( kV new ) 2 (Eq. Include all significant system components and impedances. Electrical Manual 200 System Studies and Protection Fig. 200-6 Example One-Line Diagram Chevron Corporation 200-17 May 1996 . The diagram should show the per-unit impedance of every component in the system. The base kVA or MVA applies to all voltage levels in the system.17 Xd" = . 50 HP and above Lumped motors. 4. below 50 HP Synchronous Motors 1200 RPM and greater 514 RPM through 900 RPM 450 RPM and less Note Xd"= .17 Xd" = . it is useful to make a table showing base volts. 5.20 Xd" = . These must be converted if a different kVA base is being used in the system study.28 Xd" = . In this step. See Figure 200-8(b). only the available fault current at that location in the system is of interest. and ohms for each voltage level in the system. Prepare an impedance diagram. Data that needs to be gathered include the following: – – – Fig. 2. 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 2.0 PF Induction Motors Above 1000 HP at 1800 RPM or less Above 250 HP at 3600 RPM All others. use a computer to determine the fault value of every bus in the system.8 PF Synchronous Motor.28 All per-unit values have the kVA rating of the motor as the base kVA. If doing a large study for a new plant. transformer. Collect and convert impedance data.8 kVA Induction Motor Synchronous Motor. At this point. a base voltage for the system.200 System Studies and Protection Electrical Manual Figure 200-6 shows a one-line diagram with the information needed to perform a short-circuit study. .15 Xd" = . See Figure 200-8(a). Determine the fault location for which solutions are desired. Choose a base kVA or MVA. A “bus” is wherever a circuit-interrupting device or switch is connected.20 Xd" = . May 1996 200-18 Chevron Corporation . and a base voltage for every bus throughout the system . reactor. 1. If purchasing a new MCC. amps. 200-7 Utility short-circuit MVA (and X/R ratio if calculating per Red Book) Cable lengths and impedances Motor (see Figure 200-7). and generator impedances Typical kVA to HP Ratios and Subtransient Reactances for Motors 1 HP = 1 kVA 1 HP = 1 kVA 1 HP = . 3. Electrical Manual 200 System Studies and Protection 6. 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. Chevron Corporation 200-19 May 1996 . See Figures 200-9 through 200-13. 200-16) Then. 7. Combine impedances until there is a single resultant impedance between the infinite bus and the fault. Calculate the short-circuit current using: E pu I scpu = -------Z pu (Eq. 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 May 1996 200-20 Chevron Corporation .200 System Studies and Protection Electrical Manual 8. Apply the appropriate multiplying factors to obtain the asymmetrical or total current value of the short circuit. TX4. Also shown are the cables of significant length (to introduce additional reactance into the calculation). 13. and 480 volts. resulting in a very conservative solution. refer to Tables 24 and 25 of IEEE 14. For interrupting case fault calculations subtransient reactances. subtransient reactances. Decide on the Fault Location In this example. The reactances associated with the motors are subtransient reactances with no multipliers. and motors are given a unique identifier (such as B1.16 kV. 4. a new transformer. This calculation is made to determine the required interrupting rating of the transformer’s secondary main breaker and the low voltage circuit breakers in the motor control center. the impedance diagram is drawn (Figure 200-8(b)) showing the base volts. C1 and M1). and base ohms for each voltage level in the system. To determine the asymmetrical value of the fault current. all induction and synchronous motor sizes. and 480-volt motor control center are to be added to an existing system. It contains all transformer sizes (based on self-cooled ratings) and percent impedances. 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. At this point.6 is applied to the rms symmetrical fault current. cables. Step 1. and power factors for the synchronous motors. Prepare a System One-Line Diagram The example one-line diagram is shown in Figure 200-6. The example also estimates the asymmetrical or total fault current for comparison with devices rated in total or asymmetrical current values. a multiplier of 1. base amperes. resulting in a conservative first cycle rms symmetrical fault calculation. The base voltages are chosen to be consistent with the nominal voltages of the system: 115 kV. This kind of diagram is useful to change back and forth between base values in per-unit. Figure 200-6 is the one-line diagram for this example.Electrical Manual 200 System Studies and Protection 225 Short-Circuit Analysis: Example Using the Per-Unit Method The following example presents a short-circuit calculation to determine the threephase bolted fault current at the location in the electrical system where a new 480volt transformer and substation are to be added.8 kV. Step 2. such as ohms and amperes. and the fault withstand capability of the Chevron Corporation 200-21 May 1996 . and actual values. Choose the Base MVA and Base Voltages 100 MVA is chosen for the base. TX1. The maximum available fault (MVA) from the utility is given. Notice that all buses. Notice that the 100 MVA base applies to all levels of voltage in the system. The method used to calculate the base values for the 115 kV level in the diagram is shown in Figure 200-8(a). This example illustrates the basic mechanics of the per-unit method of calculating faults. transformers. Resistances are ignored. Step 3. 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. Figure 200-6. Step 4. The formulas used to convert the data are summarized in Figure 200-5. The fault location is designated F1 in Figure 200-6 and is indicated in each of the impedance diagrams that follow. The per-unit reactance calculated is approximately equal to the complex impedance in magnitude because resistance is usually small compared to the reactance in medium voltage systems. Figure 200-5. which results in a higher calculated fault value than if both resistance and reactance are considered. 200-17) Transformer Impedances (Eq. 200-19) (Eq. Convert and Collect Impedance Data The impedance data are shown on the example one-line diagram. Common practice in medium voltage systems is to consider reactance only. Utility Impedance (Eq. ZTX ≈XTX indicates that resistance is not being considered. The data are converted to per-unit values of reactance on a 100 MVA base. The per-unit values of all electrical components on the one-line diagram are calculated by applying the formulas from the calculation summary sheet. 200-20) May 1996 200-22 Chevron Corporation . 200-18) (Eq.200 System Studies and Protection Electrical Manual 480-volt MCC bus and mechanical components. the resistances and reactances of cables are used (See Tables N1. However.8 kV. For this example. so divide the value by two to obtain: ZC1 ≈ XC1 = 0. see Reference 2. For 1500 feet of cable the impedance is: (Eq. but there are two per phase. To convert this per-unit value to a 100 MVA base use the change of base kVA formula given in Figure 200-5: Chevron Corporation 200-23 May 1996 .Electrical Manual 200 System Studies and Protection Cable Impedance The cable used is 500 MCM copper cable with two cables per phase in magnetic conduits.17 per unit on its own kVA base. and that the subtransient reactance of this size of motor is 0. its own kVA base would be 3000 kVA. use that value to calculate the per-unit impedance. divide by 100. Each cable is 1500 feet long and the voltage level is 13. Next. convert the per-unit value from a 1000 kVA base to a 100 MVA base. 200-22) M1 and M2 are both 3000 hp induction motors. These must be converted to perunit by dividing by base ohms.3 and N1. To obtain the impedance. This is calculated by using the change of base kVA formula in Figure 200-5. Because this motor is 3000 hp.0003 per-unit on a 1000 kVA base.7 in Reference 1). 1 hp = 1 kVA. if it is not available the data in Figure 200-7 show that for induction motors.03% to a per-unit value. The result is 0. Commonly.015pu Motor Impedances The basic formula used for motor impedance is: kVA b Z Motor ≈ X Motor = xd ″ × --------------------------Motor kVA (Eq. 200-21) To change 0. If the actual subtransient reactance is available from the manufacturer. (Note: 1000 kVA = 1 MVA) This is the per-unit impedance of one of the cables. the reactance is 0.02% per 1000 feet on a 1000 kVA base. 200-24) (Eq. Using the 0.8 pf.200 System Studies and Protection Electrical Manual (Eq. The total hp of the lumped motors is 450 hp. The data in Figure 200-7 show that. 200-26) Step 5. This is accomplished by combining reactance values following the same rules as combining resistors in series and parallel. Combine Impedances in the Impedance Diagram The next task is to simplify the impedance network until a single resultant impedance remains between the infinite bus and the chosen fault location. May 1996 200-24 Chevron Corporation . M7. The data in Figure 200-7 indicates that 1 hp = 1 kVA. 200-23) M3 and M4 are synchronous motors with 0. 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.25 per unit on its own kVA base. The motors are acting as induction generators and contribute to the short circuit as discussed in Section 224. the motors would be individually represented with the reactances listed in Figure 200-7. M8. all motors on the bus have been lumped as one large motor with a subtransient reactance of 0. The change-of-base calculations for M3 and M4 are similar to those for M1: (Eq.25 per-unit figure on the 450 kVA base and converting it to the 100 MVA base: (Eq. and M9) in this example.8 power factor (pf). for synchronous motors with 0. and that the typical subtransient reactance is 0. Step 6. 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).20 per unit on the motor’s kVA base. Normally. so the total kVA is 450. 1 hp = 1 kVA. M6. 200-25) To handle the motors on the 480-volt motor control center bus (M5. 200-10 Impedance Diagram Reduction (Step 2) Chevron Corporation 200-25 May 1996 . 200-9 Impedance Diagram Reduction (Step 1) Fig. Fig. 200-27) The various intermediate impedance diagrams between the initial and the final are shown in Figures 200-9 through 200-13.Electrical Manual 200 System Studies and Protection (Eq. 200 System Studies and Protection Electrical Manual Fig. 200-12 Impedance Diagram Reduction (Step 4) Fig. 200-13 Impedance Diagram Reduction (Step 5) May 1996 200-26 Chevron Corporation . 200-11 Impedance Diagram Reduction (Step 3) Fig. 6 applied to the rms symmetrical short-circuit current to determine the asymmetrical shortcircuit current. 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. (Eq. per-unit.303 per unit on a 100 MVA base. driving voltage in the line-to-neutral model. To calculate the actual short-circuit current. it is 1. depending on the available asym- Chevron Corporation 200-27 May 1996 . In this example.281 = 16.478 amperes. Calculate the Fault Current Calculate the available fault current using: (Eq. To convert the 0. To arrive at the symmetrical per-unit fault current. solve the following equation. 200-30) This value can now be compared directly to the interrupting rating of the proposed secondary main circuit breaker of TX4.478 amperes (Eq. it is 7. This table shows that the base amperes at the level of the fault location is 120.281 amperes. 200-29) The 1 in the numerator is the one. it is conservative to use a multiplying factor of 1. It is common practice to specify breakers with interrupting ratings which exceed the calculated maximum fault by 15-to-20% or more. Since the prefault voltage is the base voltage at the fault location. 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.Electrical Manual 200 System Studies and Protection Step 7. 200-28) The final resultant per-unit impedance between the infinite bus and the fault location is the value to use for Z.0 in per unit volts. This current is sometimes referred to as total current.137 x 120.137 per unit amperes to actual amperes. refer to Figure 200-8(a). 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. to allow for future system short-circuit growth. Step 8. multiply the per-unit amperes by the base amperes as follows: SCA (rms symmetrical) = 0. The driving voltage represents the prefault voltage. depending on how the short-circuit calculations will be applied. The ratings of circuit breakers are based on the Red Book method. basic method for determining the short-circuit current typical of medium voltage systems when resistance is not a significant factor. For more detailed calculations. and the bus numbers appear in the input and output summaries of the computer program. Although low voltage circuit breakers must withstand the asymmetrical current also. 227 Computer Methods for Calculating Short-Circuit Current An example of a computer calculation of a more complex system than the example above is shown in Figure 200-14. and another for time-delayed relay devices. an X/R ratio is established at the point of fault and used to select tabulated multiplying factors which are applied to E/X values to establish total rms current interrupting duties. an X network and an R network. the Red Book prescribes additional multipliers to be applied to the subtransient reactances based on motor type. The net effect of the differences between the method employed in this example and the method of the Red Book. resistance has an increasing effect on reducing the short-circuit currents. Depending on the network being calculated. 3. The Red Book refers to the appropriate ANSI standard for the multiplier to obtain the asymmetrical. 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. May 1996 200-28 Chevron Corporation . see the IEEE Red Book for calculation methods. 2. The nodal diagram used with this program is shown in Figure 200-15.200 System Studies and Protection Electrical Manual metrical fault current. For a more detailed consideration of this topic see ANSI C37. The program employed is the GE computer program SHCKT$ used for calculating three-phase short-circuit currents. 226 Comments on the Short-Circuit Calculation Example The preceding example demonstrates a conservative. another for low voltage circuit breakers and fuses. It has one method for high voltage circuit breakers.13. The Red Book calculates three different solutions based on three different networks. or total. which is recommended for detailed calculations. If resistance is ignored in those situations. All buses are numbered. When the two networks are solved. is that the Red Book method gives (yields) a lower calculated fault current. they are rated in symmetrical rms current interrupting values which have already considered the asymmetrical components up to certain limits. In lower voltage systems with long cable runs. 4. an overly conservative solution may be reached. rms current. The Red Book uses the same basic method demonstrated here with the following refinements: 1. 11484 7.49907 3.U.U.53145 1.04349 . .67092 10.46528 .92082 10.90148 X P.19204 1.44251 1.41311 16.54013 1.10471 2.40807 16.03245 2. Three-Phase Short-Circuit Program (1 of 2) (Courtesy of the General Electric Company) CASE: 1-FCY Page.86118 5.13-1981 05/29/85 100 MVA BASE 60 HERTZ 10700 LINE WITH C-A TIE CLOSED.35177 8.97831 1.30714 10.22288 16.38804 7.22288 7.47226 5.38265 7.C-2 OPEN CASE: 1-FCY NORMAL PLUS C-A CLOSED AND C-2 OPEN C-1 OPEN A-1 CLOSED INPUT DATA BUS 0 1 2 3 4 6 7 8 8A 15A 15B 16A 20 21 17 18 10 26 22 12 9 27 28 5 13 19 C3 C4 C11 TO BUS SWG1070 1L 2L 3L 4L 6L 7L 8L 8AL 15AL 15BL 16AL 20L 21L 17L 18L 10L 26L 22L 12L 9L 27L 28L 5L 13L 19L C4 C5 27 R P.86152 8.79914 2.64238 .03075 .53145 2.14243 .22288 9.59992 1.58087 1. .91850 1. FOR BREAKER DUTIES PER ANSI C37.01215 .48910 8.91756 10.11129 .50204 5. 200-14 G.Electrical Manual 200 System Studies and Protection Fig.44082 2.40807 14.22288 6.17398 COD 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 EPSCAC Chevron Corporation 200-29 May 1996 .66296 2.46832 3.1 GENERAL ELECTRIC CO.50204 4.03141 6.44082 5.37090 1.E.41311 9.01718 . — INDUSTRIAL POWER SYSTEMS THREE PHASE SHORT CIRCUIT PROGRAM FIRST CYCLE CALC.52379 2.49526 3.60060 6.53214 .99679 16.53145 1.53145 5. 168 ANG 74.01281 .004 ANG 76.200 System Studies and Protection Electrical Manual Fig.19 1.000 5TOT 8.506 ANG 84.425678 IASYM BASED ON X/R= 10.196 KA (226/17MVA) AT’74. 14.19 1.111536 +j .01679 .19 1.44MVA) AT77.03087 .02769 .119557 +j 14.642 Fig.844 BUS A1 TO BUS 3 MAG 9.649 .01618 0 0 0 0 0 0 = 9.02074 .721 79.483743 5SYM 8. 200-15 Nodal Diagram for Short Circuit Study (Courtesy of the General Electric Company) May 1996 200-30 Chevron Corporation ..200 KV .03901 .303 8.02269 .000 3SYM 8..34.X/R= 4.E.SYM 8.31DEG.01641 .000 ANG 75.200 KV . 200-14 G.028 E/Ze= Ze= CIRCUIT BREAKER TYPE MAX DUTY LEVEL MULT.513 BUS A2 TO BUS A1 MAG .000 8TOT.56.59196 .65 1.02DEG. FACTOR CONTRIBUTIONS IN KA BUS TO SWG1070 3 BUS A1 A1 MAG 7.6*ISYM = CONTRIBUTIONS IN KA BUS TO 3L *BUS A1 BUS 3 MAG .X/R= 3.11424 .01697 . Three-Phase Short-Circuit Program (2 of 2) (Courtesy of the General Electric Company) C11 SWG1070 A1 A2 SWG1070 B1 *BUS 3 19 A1 A2 A3 B1 B2 E/Ze Ze = .19 1. 14.71 .190 KA( 201. 71 kA. First cycle (momentary). The multiplier is determined by internal tables and relates to the X/R ratio. Suite 102 Chevron Corporation 200-31 May 1996 . The second case calculated the interrupting rating requirements for medium voltage circuit breakers. An advantage of the computer solution over the manual solution is that it gives the currents in the branches feeding the fault bus.6 multiplier is 14. 5.190 kA.31 degrees. not just the total fault current. ETAP is available from: Operation Technology. Next to Bus A1. The current at the faulted bus lags the infinite bus voltage by 74. This value. 17870 Skypark Circle. Two different cases were run for each location. and interrupting duty for fuses and low voltage circuit breakers. The first cycle case shows the input data. The multiplier times the symmetrical fault current gives the maximum duty level.56.56 to determine the asymmetrical multiplier from tables within the computer produces a total asymmetrical current of 10. Following that are the fault levels to be compared to medium and high voltage circuit breakers with 8. depending on whether or not they are rated in total current or symmetrical current. E/Ze (the symmetrical fault current) is 8. Following the fault current summary. short-circuit currents are used to compare equipment mechanical strength requirements.65 kA by this method.2 kV. or 3 cycle interrupting times. Also shown for the first-cycle cases. The same information discussed in the first cycle case is also provided. 10. The base voltage of Bus 3 is 14. is considerably less than the value obtained by using 1. 1. The first case is the first cycle case.11957 + j0. The X/R ratio of the fault location is 3. consisting of the resistance and reactance in per-unit values on a 100 MVA base for every branch between nodes. Only part of the input and output for the program is presented. closing and latching requirements for medium and high voltage circuit breakers. Also calculated is the interrupting case. Inc. For Bus 3.65 kA.196 kA. are examples of the output produced by the computer. 228 Electrical Systems Analysis Computer Programs The following programs have been used successfully by the Company and are recommended for analysis of electrical systems.Electrical Manual 200 System Studies and Protection The model used in the computer run of Figure 200-14 simulated faults at over 70 different locations shown in the nodal diagram. the rms symmetrical fault current E/Z is 9. Using the actual X/R ratio of 3. The equivalent impedance from the infinite bus to the fault point is 0. The total asymmetrical current using the 1. similar to the example presented above. the study shows fault current contributions from other buses. Electrical Transient Analyzer Program (ETAP) is the most usuable set of PCbased programs to analyze electrical systems.425678 per-unit.6 as a standard multiplier (as in the example). The output has current values in phase and symmetrical component format. Westinghouse has a group of programs known as Westcat. Archer Drive Oregon City.200 System Studies and Protection Electrical Manual Irvine. Another IBM PC-based program is the ESAPP Program available from: Electrical Systems Analysis. load-flow. available on a timeshare basis. dynamic stability. and a data-reduction program (in addition to the short-circuit program). 3. short circuit. 16545 S. May 1996 200-32 Chevron Corporation . CA 92714 (714) 476-8814 This set of programs includes loadflow. Inc. The General Electric computer program SHCKT$ used in the short-circuit example presented above is available on disk from: General Electric Company Industrial Power Systems Engineering 1 River Road. They are available on a time share basis from: Westinghouse Electric Corporation Advanced Systems Technology 777 Penn Center Boulevard Pittsburgh. Westinghouse also has harmonic-analysis. and cable pulling programs. cable ampacity derating. and impedance calculations. Building 6. 2. 230 Motor-Starting Studies 231 Scope A complete motor-starting study consists of two parts: a voltage-drop calculation and an acceleration-time calculation. simple dynamic stability. NY 12345 (518) 385-4500 This program. Third Floor Schenectady. data-reduction. also contains a motor-starting program. and device-analysis programs. 4. a load-flow program. motor starting. The cost of this set of programs is approximately $7. Pennsylvania 15235 (412) 824-9100 The Westcat program can perform short-circuit analysis. OR 97045 (503) 655-3615 The ESAPP program performs short-circuit analysis.500. The long cable length feeding the motor further decreases the voltage at the motor terminals. a 200-hp motor that will drive a reciprocating pump or a compressor is being added. enough information should be available to determine if the motor will meet the system requirements. the torque vs. The reason that a study is required is that the transformer kVA is not much larger than the motor kVA.Electrical Manual 200 System Studies and Protection 232 Reasons for a Motor-Starting Study Motor-starting studies should be done in preliminary form as early as possible in a project. 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. 233 When To Conduct a Motor-Starting Study A motor-starting study is not always necessary. 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 the voltage dips to 80% of normal. causing low voltage at the motor terminals. Chevron Corporation 200-33 May 1996 . When the bids are received.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. the motor will deliver only 64% of its normal starting torque. 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. speed characteristics and starting current values of motors similar to the one to be purchased. for example. 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. If the system has 500 hp or larger medium voltage motors. speed and starting current limitations on the motor can be calculated. Early studies make use of typical torque vs. If. so there may be excessive voltage drop through the transformer. Motor-starting torque is proportional to the square of the voltage. 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. it will be necessary to conduct a motor-starting voltage drop study (and possibly an accelerating time study). If the calculations are completed before the motor is specified. 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. a motor-starting calculation is almost always recommended. which may not be enough to drive the pump. e. Motor nameplate information a. 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. and should be designed to be less than 15%. Voltage Full-load current Horsepower rpm at full load Locked-rotor current or locked-rotor kVA Starting power factor (or an approximation) System impedance data (including the utility) Running load on system at time of starting (and approximate power factor if more accuracy is desired). As this current flows to the motor terminals from the power source through power lines. 20% or more may be allowable. It will just hum. dim.200 System Studies and Protection Electrical Manual 234 Voltage-Drop Calculations When a motor is first started. 4. control relays may drop out causing shutdowns or erratic operation of systems and computers. various voltage drops occur. d. the voltage at the motor terminals can be significantly less than 100% of the bus voltage feeding the motor. The largest voltage drop occurs at the motor terminals. If the voltage drop is too large at any of these points. May 1996 200-34 Chevron Corporation . 2. Some utilities require less than a 2% drop on their lines. the voltage drop during starting maybe so severe that the motor will not start at all. When all these voltage drops are accounted for. In extreme cases where weak power systems are involved. If the voltage drop exceeds 15 to 20%. b. This voltage reduction during motor starting occurs to some extent at every point in the electrical system. or even extinguish momentarily during motor starting. transformers. 3. 1. and other impedances in the system. drawing locked rotor current at the reduced voltage until its breaker or starter trips on overload. In some instances. Lights may flicker. it can cause problems throughout the system. Many utilities limit the size and current inrush of motors to prevent voltage drops of more than 5% at the utility. 235 Data for a Voltage-Drop Calculation The following data are needed to perform a complete motor voltage-drop calculation. c. to be conservative. it is necessary to use the minimum available short-circuit MVA available from the utility. Smaller motors will have a locked-rotor code on their nameplate as (described in NEC 430-7). so its impedance is in series with the utility. as does the short-circuit study. To model the starting motor as an impedance. 200-31) It is important to use the motor nameplate voltage for Vmotor. shown in Figure 200-18.3 kV. For more information on the perunit method. As shown in Figure 200-18. divide by 1000. To calculate the locked-rotor MVA in this case. In the motor-starting example. use the following formula: (Eq. Figure 200-17 shows the line-toneutral model used for a short-circuit calculation at point A. ILR.Electrical Manual 200 System Studies and Protection 236 Voltage-Drop Calculation: Example Circuit Model. For example. 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. The motor-starting voltage-drop calculation normally utilizes the per-unit method. the terminal voltage at the motor can be calculated as a ratio of the motor-starting impedance to the total impedance of the circuit. For a motor-starting voltage-drop study. although the bus voltage is 2. the nameplate voltage of the motor in Figure 200-16 is 2. transformer. Use the maximum kVA per horsepower in the range for the particular locked-rotor code. How to Represent the Starting Motor as an Impedance. To change the locked-rotor kVA to MVA. “Short-Circuit Studies. and cable impedances.” and References 2 and 5. Suppliers of larger motors will give the maximum locked-rotor current. the motor is not a source of current as in the short-circuit example. 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 short-circuit case. as this will produce the most severe voltage drop calculation (the conservative case). Figure 200-16 presents an example of a oneline diagram for a sample voltage-drop calculation.4 kV. Use the per-unit system to calculate the voltage drop. at the rated motor voltage. find the starting kVA of the motor. 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. see Section 220. Similarly. Chevron Corporation 200-35 May 1996 . 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. 200 System Studies and Protection Electrical Manual Fig. 200-16 Example of a One-Line Diagram for Motor Starting May 1996 200-36 Chevron Corporation . Electrical Manual 200 System Studies and Protection Fig. 200-18 Circuit Model for Motor Starting Voltage Drop at Point A Chevron Corporation 200-37 May 1996 . 200-17 Short Circuit Model for Fault Current at Point A Fig. 200 System Studies and Protection Electrical Manual Once the locked-rotor kVA is calculated. Cable impedance is also ignored in this example. May 1996 200-38 Chevron Corporation . Make an impedance diagram. After assembling the required data and one-line diagram. This is calculated by the following formula: (Eq. 2. Calculate component impedances on a common MVA base. Calculate voltage drop. Choose the base voltage of the system. system resistance was ignored since it is a medium voltage system and the reactive component of impedance has the largest effect. 4. Approximate motor-starting studies can be done using the MVA method. however.8 kV and 2. 3. For approximate calculations in medium voltage systems. An impedance diagram was drawn (Figure 200-19). using the per-unit method described in Section 220. it should be included in low voltage motorstarting cases and medium voltage cases with long cable runs. In this case the impedance is assumed equal to the reactance. 4. as shown in the example in Figure 200-19. ignoring resistance. 2. Although this method is simpler. In this example. The MVA method is described in Appendix C. 3. 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). 13. Impedances were calculated on a 100 MVA base. it is not as versatile. it must be changed to a per-unit impedance value at the same base voltage as that of the system impedance diagram. impedance can be considered to be all reactance (X). 200-32) This equation calculates the impedance (Z) of the motor. complete the following tasks: 1.4 kV were chosen as base voltages. The voltage drop was calculated as 73% full voltage at the motor terminals upon starting. For the example. the following steps were completed in accordance: 1. Example of Motor-Starting Voltage-Drop Calculation Using the Per-Unit Method Calculate the utility voltage drop during starting and the terminal voltage of the motor as shown in Figure 200-16. Electrical Manual 200 System Studies and Protection Fig. 200-19 Motor Starting Voltage Drop Impedance Diagram Chevron Corporation 200-39 May 1996 . Computer programs that calculate motor-starting voltages can easily calculate the actual effects of running load.3 kV). this could be modeled as 500 kVA.8 kV utility bus was found to be 1. a few percentage points higher than if it were not considered.200 System Studies and Protection Electrical Manual In this example. causing the relays to dropout. 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 voltage at the instant the motor starts is 73% of the 2. This 500 kVA can be represented conservatively by an impedance using the following formula: (Eq. The torque vs. In medium voltage motor-starting calculations. It may be allowable if further investigation shows there is enough torque to start the load.4 kV bus voltage.4 kV (due to the running load voltage drop). For this reason if the initial calculation without considering running load indicates a marginal voltage drop.6 kV as the motor accelerated. the speed curve. When the motor reaches rated speed. For example. voltage relationship is discussed below in Section 238. This is equal to 76% of the motor nameplate voltage (2.5%. the voltage would drop to 13. the current drops to the normal loaded value. Effect of Running Load The 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. 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. knowing the effect of resis- May 1996 200-40 Chevron Corporation .4 kV bus (Figure 200-16). the voltage prior to starting the 1500 hp motor would be something less than 2. Including Resistance in the Motor-Starting Circuit Model The resistive component of impedance becomes important in low voltage motorstarting calculations where a significant portion of the voltage drop is due to resistance. and at the motor terminals. and if it will not cause control problems at the motor bus (or elsewhere in the system). and the voltage drops throughout the system return to normal.8 kV. if there is a 500 hp combined load already running on the 2. This means that if the utility voltage at the time the motor was started was 13. for example. The effect of running load can sometimes make the voltage drops throughout the electrical system. then the effect of running load should be calculated. For example. The voltage drop on the 13. if there were a large running load on the 2. 200-33) The impedance representing the running load is located in the impedance diagram as shown in Figure 200-20.4 kV bus in Figure 200-16. 200-20 Running Load Impedance tance produces a slightly more accurate solution. A further refinement of the motor-starting impedance diagram includes the resistive component of the utility.Electrical Manual 200 System Studies and Protection Fig. cable. The utility is resolved into a complex per-unit impedance. 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. R + Chevron Corporation 200-41 May 1996 . this makes manual calculations more time consuming. however. running load. and starting motor impedances. use a computer program such as the one described in Section 239. transformer. • Utility Including the resistance of the utility in the impedance diagram is illustrated in Figure 200-21. References 5 and 7 give examples of this application. it will also reduce the available starting torque by the square of the ratio of the reduced voltage to the motor voltage. If it is not available. Such a power source has less impedance and will allow larger starting currents to flow without as great a voltage drop on the utility.200 System Studies and Protection Electrical Manual jX. to know the short-circuit MVA and the X/R ratio of the utility source. 3. Specify a motor with a smaller starting current to limit the voltage drop. “Starting Methods for Motors. However. Reducing the voltage at the time of starting will reduce the motor-starting current and associated utility or plant voltage drop. it can be assumed that starting power factor is 0. 4. which should be verified before specifying reduced voltage starting. See Section 440. Use a reduced voltage starter to start the motor. This arrangement will reduce the starting current and the associated voltage drop. then its impedance can be resolved into R and X components as shown in Figure 200-21.” for specific methods of reduced voltage starting.462 perunit ohms) has a starting power factor of 0. allowing a larger starting voltage at the motor. These data may also be obtained from transformer test data. This alternative will cause the voltage drop across the transformer to be smaller. This method can be used only when there is net accelerating torque to sacrifice. It is necessary. however. • Motor Impedance The motor impedance (from Equation 200-2) may be resolved into R and X components if the starting power factor is known. See Section 200 of the Driver Manual for further discussion. On large motors. 237 Correcting for Unacceptable Voltage Drop If the starting voltage drop calculation predicts that a motor will produce too large a voltage drop for the system.2. several options for correcting the problem are available. • 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. a reasonable approximation. May 1996 200-42 Chevron Corporation . 2. If the 1500 hp motor depicted in Figure 200-16 (with an impedance of 12. Find a power supply source with a larger available short-circuit MVA to start the motor. 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.2. 5. 1. Consider feeding the motor from a larger transformer. the manufacturer can provide the starting power factor. 200-21 Resistance in the Motor Starting Model Chevron Corporation 200-43 May 1996 .Electrical Manual 200 System Studies and Protection Fig. 200-34) where: Torque = tangential effort in ft-lb hp = horsepower developed rpm = revolutions per minute The full load torque of the 1500 hp. 238 Motor Acceleration Time Calculation The following information is necessary to make a time calculation for net starting torque and acceleration. horsepower. and speed (rpm) are related by the following formula: (Eq. by the counter-torque developed by the driven equipment. by the moment of inertia (WK2) of the motor and driven equipment. speed curve of the motor for 100% of motor nameplate voltage. and by the operating speed. speed curve for the motor at full voltage Power factor 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. however. Torque. Most of this information is available from the manufacturer. • • • WK2 (moment of inertia) of the motor rotor WK2 of the driven equipment. and another curve for the percent of rated motor terminal voltage predicted in the starting voltage drop calculation Torque vs. 1780 rpm motor depicted in Figure 200-16 is: May 1996 200-44 Chevron Corporation . this is a very expensive alternative if the adjustable speed feature is not needed. referenced to the same rpm as the motor rotor Torque vs.200 System Studies and Protection Electrical Manual 6. and speed of the driven equipment if it is gearbox-connected to the motor Current vs. 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. speed curve for the motor • • • • • Basic Mechanical Relationships The acceleration time of a motor is governed by the torque developed by the motor. then rapidly increases until it peaks at 95% speed. speed curve for the motor and the driven load is needed (usually available from the manufacturer). use the worst case scenario. This information was supplied by the motor vendor. who obtained the torque vs. speed data for the pump from the pump manufacturer. less torque is required at a given rpm. The motor rated speed of 1800 rpm is not reached. when the pump is to be started and use the appropriate curve. Motor torque then drops rapidly until the operating speed is reached (in this case 1780 rpm).Electrical Manual 200 System Studies and Protection (Eq. even at no load condition. For centrifugal pump. As the motor accelerates the load. Check the position of the discharge valve. 200-35) The term “full load torque” is defined as the torque associated with the horsepower rating of the motor at operating speed. T = Net accelerating torque. When the discharge valve is closed. the motor produces 84% of its full-load torque on starting (Point A). in seconds WK2 = Total moment of inertia of motor and driven equipment. open or closed. 1800 rpm induction motor and the pump it drives. in ft-lb To use this equation to predict the acceleration time. in rpm. As indicated on the motor torque vs. To be safe. speed-torque curves. the motor torque at first slowly increases. be aware of the difference between the curves with the discharge valve open and those with the valve closed. Speed Curve of Motor and Driven Load Figure 200-22 is an example of a combination torque vs. a torque vs. because motor torque is not developed at synchronous speed. At 1800 rpm. Torque vs. Chevron Corporation 200-45 May 1996 . speed curve in Figure 200-22. 200-36) where: t = Time. Discharge Valve on Centrifugal Pump. in lb-ft2 rpm Change = Increment of speed change. Figure 200-23 shows the difference between the two cases. 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. speed curve for a 3500 hp. This value is known as starting torque or locked-rotor torque. The acceleration time of the motor and driven load are governed by the following relationship: (Eq. The net accelerating torque at 50% of synchronous speed (as shown in Figure 200-22) is about 70% of motor full-load torque (0. Fig. 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).” 1780 rpm. The bold arrow shows where the measurement is May 1996 200-46 Chevron Corporation . 200-22 Induction Motor Starting Characteristics (Calculated) at 100% Line Voltage Net Accelerating Torque. 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. If a motor is to accelerate to operating speed.200 System Studies and Protection Electrical Manual Motor Operating Speed. In Figure 200-22. 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. the intersection is at point “C.70 x 10323 ft-lbs = 7226 ft-lbs). speed curve. If only the curve at 100% of rated motor voltage is available and an adjusted curve based on the motor- Chevron Corporation 200-47 May 1996 . 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.Electrical Manual 200 System Studies and Protection taken at 50% speed. Fig. the motor torque for all speeds is shifted down to 72%. By comparing motor torques at similar speeds for the two curves. Figure 200-24 presents the same information except at 85% of rated motor voltage during starting. At other points on the curve.14% = 70%. it can be seen that if the voltage drops to 85% during starting. the net accelerating torque changes with speed can be determined.85) 2 or 72% of the starting torque at full voltage. the torque available on starting will be only (0. The net accelerating torque on starting is 84% . 200-23 Compared Effects of Open and Closed Pump Discharge Torque Effect of Reduced Voltage. Figure 200-22 is the speed torque curve for a 3500 hp motor at 100% of rated voltage during starting. If the voltage drops to 85% of rated voltage when the motor starts. As the starting current decreases while the motor is turning. it is conservative to shift the 100% motor torque vs. therefore. the voltage drop becomes less severe. the square relationship between terminal voltage and torque can be used as a good approximation to shift the motor torque curve. 200-24 Induction Motor Starting Characteristics (Calculated) at 85% Line Voltage starting voltage drop is required. 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. speed curve by May 1996 200-48 Chevron Corporation . then it decreases rapidly. Current vs. For this reason.200 System Studies and Protection Electrical Manual Fig. Speed Curve for a Starting Motor Figure 200-24 demonstrates that the starting current of the motor decreases slowly until about 85% speed is reached. there is higher motor terminal voltage as speed increases. gearbox.92 at running speed. 4. The gear box has a WK2 of 300 lb-ft2 at 1780 rpm. One way to reduce these large starting currents is to add correction capacitors that switch into the circuit during motor starting. 2. the gearbox. Example of a Motor Acceleration Time Calculation For this example. speed curves). Steps to calculate total acceleration time are: 1. Verify that there is a net positive accelerating torque at all times (from the motor and pump torque vs. as described above. the capacitors usually can be switched out of the circuit since most motors have reasonable power factors at running speed. at all speeds.Electrical Manual 200 System Studies and Protection the square of the voltage. Notice that the pump WK2 is not at the same rpm as the rotor and gear box. the same voltage drop will not be present at all speeds. This motor has a full load torque of 4424 ft-lbs at 100% terminal voltage of 2300 volts. Then all values for moment of inertia (WK2) are added to obtain the total moment of inertia. The slope of the curve then increases rapidly with speed and reaches a final value of about 0. Power Factor vs. Speed Curve for a Starting Motor Figure 200-22 also shows the power factor vs. 3. The fact that motors start with a low power factor contributes to large starting currents. first calculate the combined WK2 of the motor. Calculate the time for the motor to accelerate through each increment. To calculate the acceleration time. 5. Step 1. the motor rotor has a WK2 of 1900 lb-ft2 at 1780 rpm. the motor shown in Figure 200-16 will be used. Notice that the first value for the curve is about 0. Divide the motor and pump torque vs. speed curve for a starting motor.21 and the slope does not rise appreciably until the motor attains about 80% of speed. The sum is the total time to accelerate the motor and load to full speed. Add the acceleration times calculated for each interval. Once the motor reaches operating speed. and the pump. and the pump rotor has a WK2 of 10 lb-ft2 at 7000 rpm. and pump. From the information in Figure 200-16. Calculate WK2 (moment of inertia) of motor. This arrangement improves the starting power factor of motors and results in greatly decreased starting currents. The pump WK2 must be referred to the motor rated speed by multiplying it by the ratio of the squares of the two speeds. In reality. speed curves into an equal number of increments. shown below: Chevron Corporation 200-49 May 1996 . calculate the time required to accelerate through each 10% increment of total speed (178 rpm).28 per-unit. the net percent accelerating torque is 0. The curve has been divided into 10 equal increments (each 10% of rated speed). Figure 200-25 shows that the minimum net accelerating torque in any speed interval is 0.200 System Studies and Protection Electrical Manual (Eq. so the net accelerating torque is: May 1996 200-50 Chevron Corporation . there is sufficient net accelerating torque. 200-37) The value to use for Step 2. Therefore. speed curves are shown in Figure 200-25. speed curve of the motor and the load to determine if there is net accelerating torque at all points.22 per-unit or 22% of motor full load torque. The full load motor torque is 4424 ft-lb. use the motor torque vs. Step 4. based on the midpoint net acceleration torque shown in each interval. The motor and pump torque vs. The curve can be divided into smaller increments for greater accuracy. WK2 in the accelerating time equation is 2355 lb-ft2. and it is necessary to look closely at the torque vs. even though only 76% voltage (24% drop) is expected on starting. Because the voltage drop calculation predicts a drop in motor terminal voltage to 76% of the rated 2300 volts. and the perunit net accelerating torque has been measured and drawn at the center of each of these sections. speed curve for 76% voltage. Step 3. 200-38) For example. These curves must be obtained from the manufacturer of the motor. Ten percent is a good guideline for the minimum acceptable net accelerating torque at all points from startup to operating speed. in the first interval. (Eq. Seventy-six percent is a rather severe voltage drop. Using the accelerating time equation. 780. 200-25 Speed vs.28 x 4424 T = 1. or 178 rpm. Thus. the total time to accelerate to 1780 rpm. Torque for the Example Motor and Load Acceleration Calculations T = Tpu x T total T = 0.72 ft-lb WK2 is 2355 lb-ft2 and the speed change is 10% of 1. 200-39) Acceleration times for all the intervals are listed in Figure 200-26.Electrical Manual 200 System Studies and Protection Fig. Chevron Corporation 200-51 May 1996 . the accelerating time for the first interval is: (Eq. 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.238. 100% P.81 11.28 973. MOTST$.90 1. 239 Computer Programs That Simulate Motor-Starting Several computer programs can simplify calculating motor-starting voltage drop and acceleration time. 3.U. Correcting for Unacceptable Acceleration Time If the acceleration time study indicates that it will take too long to accelerate the motor.28 1681. Specify a motor with a higher torque characteristic.12 Total Acceleration Time Time 1.10% 10 . current curve on the same time current coordination sheet as the motor thermal limit curve. consider the following options: 1. This will increase the net accelerating torque.25 0.40% 40 . Motor manufacturers can vary the torque vs. install an interlock or stipulate an operational requirement so that the motor can only be started if the driven equipment is unloaded. but does so at the expense of motor efficiency.30% 30 .28 1.00 1061.90% 90 . 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.20% 20 .20 1106.68 1504.28 0. One of these is the General Electric timeshare program.30 0.72 1415. If starting the motor loaded is the problem.40 0. Torque 1238.14 This accelerating time information may now be used to plot the motor-starting current vs. 2. 200-26 1500 HP Motor Accelerating Time Calculation Speed Interval 0 .16 1327. May 1996 200-52 Chevron Corporation . time curve on the motor time overcurrent relay protection sheet.23 1.60% 60 .80% 80 .40 1.34 0.03 1.38 Net Acc. Torque 0.30 0.03 1. speed characteristics of motors by changing the design of the rotor bars.20 1327.70% 70 .24 0. Net Acc.22 0.22 0. Use a larger size motor if additional voltage drop during starting is available.50% 50 .32 0.200 System Studies and Protection Electrical Manual Fig.10 0.76 973.96 0. 88 17.0+ 1.002 LOAD BUS 1 2 CONSTANT MVA MW .42 CONSTANT I MW .00 .00 MVAR .0197 0. speed curve points.70 6.332 1 1 TAP P.462 %M-TRQ . The output is shown in Figure 200-27. impact load.002 .00 CONSTANT Z MW .003 0.90 %PWR FACTOR 13.00 .00 3.70 SOURCE MVAR 3. It allows the user to change cases very easily. motor and load torque vs.00 2. FINAL MOTOR SPEED IS 99.61 12.10 %AMPS . speed curve points.Electrical Manual 200 System Studies and Protection The information required for the GE program is similar to that used in the manual calculation previously discussed. RPM 360 %LD TRQ 10 0.3 %FL AMPS 395 390 385 M-KVOLT 6.00 .8 % IN 52.42 BUS1 1. speed curve points.1 0.0 180. INITIAL VOLTAGE 1.04/02/80 BUS SOURCE 1 2 2 3 BUS R 0.00 APPROX. Motor Starting Program (Courtesy of the General Electric Company) GENERAL ELECTRIC MOTOR STARTING PROGRAM LINE IMPEDANCES ON 10 MVA BASE ABC STEEL SCHDY.3 %SPEED .00 5.E.2 START CAP(KVA) . The computer program input requires WK2 values. or constant current. to more accurately model the behavior of the on-line loads as voltage changes during the starting of the motor.000 .00 12.88 VOLTS . and tapped transformers.60 BUS KVOLT 6. power factor vs.0 TIME (SEC) 0.00 MVAR . 200-27 G.005 0.972 VOLTAGE BUS2 .0053 X 0.00. however.442 .00 .462 . this program also includes running load. and impedance diagram information.U.39 MOTOR %LD-TRQ .0 %MOT TRQ 59 58 56 SYN.23 SEC Chevron Corporation 200-53 May 1996 . The program can model the running load as constant impedance.00 STARTING MOTOR DATA HP 8000. NY START 8000 HP MOTOR CASE 1A . Fig.3 180.3 13.52 MVAR . current vs.929 .000 .929 BUS3 .442 MW 5.972 .00 .022 0.00 10.3 15 WK-2 526000.52 17. constant kVA.0 % SPEED 0 2 10 KVA 7796.55 6.00 .992 . adding new transmission lines. 2. Base voltages of all buses.200 System Studies and Protection Electrical Manual 240 Load-Flow Studies 241 Reasons for a Load-Flow Study A load-flow study models an electrical power system for normal. 7. Transformer tap settings. It determines the magnitude and phase angle of the voltage at each bus. The system is presented in one-line form similar to that shown for the short-circuit study (Section 220). 3. Buses designated as: swing bus. 5. adding capacitor banks or synchronous condensers. abnormal. Total watts and vars of all loads. adding motors. but with a few additions. The following information is required: 1. 242 When To Conduct a Load-Flow Study A 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 Study The data needed to perform a load-flow study are the same as that required for the short-circuit study. adding or shifting generation. or making other changes in the system. Vars produced by capacitors. 6. Resistances and reactances of all lines connecting buses. taking transformers out of service. or a bus with fixed real and reactive power. or special case operating configurations. and the real and reactive power flowing in each line. The study examines the effects of changing lineups. It illustrates the effects on the overall system of any of these changes prior to actually implementing the change. 4. a regulated bus (where voltage magnitude is held constant by generation of reactive power). The study consists of the examination of a series of load-flow solutions for different cases. Initial per-unit voltage at buses. changing taps on transformers. May 1996 200-54 Chevron Corporation . 2500 -. At Bus 10.Electrical Manual 200 System Studies and Protection 244 Interpreting Computer Load-Flow Data Figure 200-28 is an example of a computer printout for a load-flow study for the one-line diagram shown in Figure 200-29. a large synchronous motor powered by a large AC generator). Stability applies only to electrical systems with two or more synchronous machines tied together electrically (e. and the voltage is 1.89. and inexpensive way to simulate transient performance of an electrical system. the computer derives a solution by several iterations of calculations that converge towards a solution. see the IEEE Brown Book (IEEE Std. In the printout in Figure 200-28.0044 .1540 1.974 -1. 200-28 Example of a Computer Load-Flow Study P-MW * Bus 1 To Bus 2 Generate * Bus 10 * Const Load To Bus 4 . 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 voltage at Bus 10 lags the voltage at the swing bus by 1.0044 .2500 . the voltage drop becomes greater. The current I flowing from Bus 1 is given in per-unit amperes..3500 -. 250 Transient-Stability Studies Computerized transient-stability studies provide a fast. the real and reactive power are generated by Bus 1.0939 . When the program is run. It can be seen that further from the swing bus.394 * (Swing) 2.0 per-unit volts. Another example would be several generation units and several large hydrogen compressors driven by synchronous motors. and Q is the reactive power in Mvar.0939 1. about a 3% drop during normal running load operation. V-P.974 per unit.1540 2. the bus voltage is 0.U. A system which is stable under normal Chevron Corporation 200-55 May 1996 .394 degrees. Fig.0242 Q-MVAR I-P. the solution is output. the swing bus.0242 . The current flowing in each line is compared to the ampacities of the lines to make sure there is no overloading. they are in step with each other. For more detail about load-flow studies. which may have some effect on the utility billing. The power factor is 0. simple.000 ANGLE-DEG .3499 . 399). P is the real power in MW.g. When the specified degree of accuracy is reached.U.000 Computer data also include the power flow (in real and reactive power). The swing bus phase angle is zero since it is the reference bus. and the current flowing from each bus to adjacent buses. that is. Stability exists if all of the AC synchronous motors and generators are in synchronism. 1. A transient-stability study is a good way to simulate the response of the power system to predictable transients. such as a switching operation. a transient may cause a permanent loss of synchronism among the machines. The study should be made when large synchronous machines are added to a power system. If the system is unstable. the machines may oscillate with respect to each other momentarily. such as loss of generators. faults. but will regain synchronism within a very short period of time. a fault. or utility outages. May 1996 200-56 Chevron Corporation . If the system has transient stability. or a relay action. Transient-stability studies should be included in the design phase of cogeneration projects. Distance relays may interpret the large surges in real and reactive power flow as fault currents and also cause system shutdown related to instability. Most synchronous machines are equipped with pullout protection that shuts down the machines when they pull out of step. a separation from the utility.200 System Studies and Protection Electrical Manual Fig. Frequent outages are another problem related to instability. This asynchronous operation can cause high transient mechanical torques and currents with associated mechanical and thermal damage. 200-29 One-Line Diagram for the Example Computer Load-Flow Study steady-state operating conditions may not be stable when it undergoes a transient. torques. Harmonics are voltages or currents with a frequency which is some multiple of the fundamental frequency (60 Hz). The study is usually done with a computer and allows solutions to problems to be simulated and tested before they are physically installed. 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. the larger the magnitude of the harmonics generated. PCbased programs are also available. rotating machine data (such as moments of inertia of the rotors of the electrical and driven mechanical machines). These plots make it easy to determine if the swing curves come back into step after the initial disturbance.Electrical Manual 200 System Studies and Protection 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. Fourier analysis shows that any periodic waveform can be represented as the sum of an infinite series of sine and cosine waveforms harmonically related. Chevron Corporation 200-57 May 1996 . Swing curves are plots of the rotor angles of synchronous machines vs. 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. 260 Harmonic Analysis Studies Harmonic analyses evaluate the potential effects of harmonics (usually produced by solid state power conversion equipment) on electrical systems. Harmonic voltage and currents are produced primarily by solid state power conversion equipment using rectifiers and thyristors. relay study. The Westinghouse Westcat program is a commonly used transient-stability computer program available on timeshare. load data (as used in the load-flow study). or if they diverge. It includes system data (as used in the short-circuit study). and disturbance data. The output of the computer programs can include the following information: • • • • • Rotor angles. time. 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. and the load-flow study. Those marked with an asterisk (*) are included in this manual or are available in other manuals. since it no longer is a pure sine wave. 4. When applying large capacitor banks for power factor correction. the sine wave becomes distorted. and eleventh (660 Hz). The dominant harmonics are typically the fifth (300 Hz). When installing large. A harmonic analysis program examines the effects of the particular harmonic frequencies that are expected to be produced by the solid state conversion equipment and checks to see if they will coincide with any resonance points in the power system. only a fundamental component at 60 Hz—the wave itself. 271 Model Specifications (MS) There are no specifications related to this guideline. May 1996 200-58 Chevron Corporation . Some examples of problems that can occur are: excessive capacitor fuse operation (due to resonance at harmonic frequencies). seventh (420 Hz). The periodic distorted wave contains harmonics. These harmonics can cause problems in the plant electrical system. When installing solid-state AC-to-DC power conversion equipment. 3. 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. A harmonic analysis of the electrical system should be considered in the following situations: 1. 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. such as rectifiers and motor drives. Harmonic analyses are best done by a specialist. 270 References The following references are readily available. communication interference (due to mutual coupling at harmonic frequencies). In the design stage of an installation using large solid-state power conversion equipment with capacitor banks. solid-state power conversion equipment at a plant where the utility has restrictive requirements on harmonics put into the utility line. 2. Solid state power conversion equipment. As a result. 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. When there is a history of harmonic-related problems (such as blowing fuses in capacitor banks). computer problems. 5.200 System Studies and Protection Electrical Manual A pure 60 Hz sine wave has no harmonics. and excessive heating of equipment. 1983). PCI-68-43. 8.A.. PCI-81-5. Advances in Capacitor Starting (Paper No. R. PCI-77-41.. Stevenson. 11. Fourth Edition. C. G. Donald. 9. Nichols.” Paper No. presented at the 1982 IEEE PCIC Conference. PCI-73-7. High Inertia Load — Induction Motor Design Considerations (Paper No. Harder. presented at the 1968 IEEE PCIC Conference). Oscarson. PCI-82-1. 7.. EM Synchronizer . 1954). Woodbury.. Pierre. (General Electric Company Industrial Power Systems Engineering Operation. Co. Use It Anywhere. 3.The ABC of Synchronous Motors (Electric Machinery Mfg. and F. (See also Paper No.D. Jr. 273 Data Sheets (DS).E.E.. Industrial Power Systems Handbook (McGraw-Hill. G. presented at the 1977 IEEE PCIC Conference).L. Beeman. ANSI/IEEE Standard 141 IEEE Recommended Practice for Electric Power Distribution for Industrial Plants.L. 10. 274 Other References 1.. and B.S. 2.. R. Lewis.W. J. and J. Brozek. 4. Short Circuit ABC — “Learn It in an Hour.D. 12. Elements of Power System Analysis (McGraw-Hill.. W. 1982). 5. R.R. IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems. Nailen. Data Guides (DG) and Engineering Forms (EF) There are no engineering forms related to this engineering guideline. presented at the 1981 IEEE PCIC Conference). Valentine. 1955). PCI-81-31. ANSI/IEEE Standard 242. Large Motor Starting Problems in the Petroleum Industry (Paper No. presented at the 1981 IEEE PCIC Conference). IEEE Recommended Practice for Power System Analysis. for a paper which describes using this method with a handheld calculator.W.) Included as Appendix C. Chevron Corporation 200-59 May 1996 . and Mirabile. St. Thode. ANSI/IEEE Standard 399.. 6. Timeshare Computer Manual for LFLOWS. W. Moon H. presented at the 1973 IEEE PCIC Conference. H. Bried. Large Motors on Limited Capacity Transmission Lines (Paper No. *Yuen. Memorize No Formula.Electrical Manual 200 System Studies and Protection 272 Standard Drawings There are no standard drawings related to this engineering guideline. H. Area classification should be effected in conformance with these guidelines as they are applicable. Section 1500 of the Fire Protection Manual provides additional information. It provides guidance in the selection of electrical equipment for hazardous (classified) locations. Contents 310 320 330 331 332 333 334 335 336 340 350 351 352 353 354 355 356 Introduction Classification of Locations for Electrical Installations Types of Equipment for Class I Hazardous (Classified) Locations Maximum Operating Temperatures Equipment Enclosures Hermetically Sealed Devices Intrinsically Safe Systems Nonincendive Equipment Purged Enclosures Electrical Equipment Requirements and Recommendations for Class I Hazardous (Classified) Locations 300-10 Types of Equipment for Class II Hazardous (Classified) Locations Maximum Operating Temperatures Equipment Enclosures Hermetically Sealed Devices Intrinsically Safe Systems Nonincendive Equipment Pressurized Enclosures 300-16 Page 300-3 300-3 300-6 Chevron Corporation 300-1 May 1996 . Foreign projects should conform to applicable foreign codes and standards as conditions dictate.300 Hazardous (Classified) Areas Abstract This section discusses the classification of locations for electrical installations. 300 Hazardous (Classified) Areas Electrical Manual 360 370 380 381 382 383 384 Electrical Equipment Requirements and Recommendations for Class II Hazardous (Classified) Locations 300-18 Area Classification Based on the IEC “Zone” System for Flammable Gases or Vapors 300-23 References Model Specifications (MS) Standard Drawings Data Sheets (DS). and Engineering Forms (EF) Other References 300-24 May 1996 300-2 Chevron Corporation . Data Guides (DG). Other devices. and other low-temperature devices without make-or-break contacts can become ignition sources through insulation failure. has been introduced in the 1996 NEC (NFPA 70) as Article 505 and is described in Section 370 of this manual.Electrical Manual 300 Hazardous (Classified) Areas 310 Introduction This section provides guidelines for classifying domestic locations for electrical installations. Switches. Designate the specific “Group” of the hazardous substance. motor starters. or fiber. Chevron Corporation 300-3 May 1996 . Designate the type (Class) of hazard which may be present—gas.” The classification process is three-fold: 1. Many parts of an electrical system. can produce enough heat to ignite flammable mixtures or combustible dusts. It also discusses the necessary requirements and provides recommendations for electrical equipment installed in these areas. An alternative system of classifying areas. solenoids. single phase and DC motors. or easily ignitable fibers or flyings. A flowchart directing the designer to specific NFPA. combustible dusts or easily ignitable fibers which may be present and the likelihood that a flammable or combustible concentration will be present. Necessary procedures and requirements are included in the referenced documents. It is necessary to identify hazardous (classified) locations in order to select the proper electrical equipment for these areas. A loose lamp can combine arcing with heat. and receptacles can produce arcs or sparks capable of ignition in normal operation. transformers. combustible dust. API. pushbutton stations. 2. such as lighting fixtures. circuit breakers. or may contain. referred to as the International Electrotechnical Commission (IEC) “Zone” system. the location must first be “classified. 320 Classification of Locations for Electrical Installations In order to properly select and install electrical equipment in a location which contains. fuses. Proper equipment must be chosen to ensure safety. Reference Section 1500 of the Fire Protection Manual for additional information. and ISA documents containing procedures for determining area classification and selecting electrical equipment is provided in Figure 300-1. Determine the probability that the hazardous substance will be present (Division). plugs. liquids. flammable gases or vapors. 3. Location classification is based on the properties of flammable vapors. such as wiring (particularly splices in the wiring). Restrictions are placed on the types of equipment used and their operation and maintenance. gases. 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 electrical enclosures and conduits. dust. Group and Properties of Flammable Vapors.1 Fire Protection Manual STEP 1 Determining Class. and it is designated Class III if easily ignitable fibers or flyings may be present. Liquids. 300-1 Area Classification Flowchart for Hazardous (Classified) Locations GENERAL REQUIREMENTS AND DEFINITIONS OF TERMS NFPA 70 (NEC) Article 500 or 505 API RP 14F API RP 500 ISA S12. Grain elevators. Designating the “Group” of a specific material is easily accomplished by referencing either the National Electrical Code or the National Fire Protection Associa- May 1996 300-4 Chevron Corporation . Article 515 (Bulk Storage Plants) STEP 3 Selecting 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. 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. 58A. Examples of Class I locations are oil refineries and natural gas compressor stations. and coal mines are examples of Class II locations. Designating the type of hazard is the first and easiest of the steps. It is called a Class II area if the hazardous material is combustible dust. Article 514 and NFPA 30A (Gasoline Dispensing Stations) NFPA 70. AND 58B Fire Protection Manual STEP 2 Determining Division and Extent of Classified Area Fire Protection Manual API RP 500 (Petroleum Facilities) NFPA 497A (Chemical Plants) NFPA 70. The area is called Class I if the hazardous material is flammable gas or vapor.6 (Intrinsically Safe Systems. Cotton gins and textile mills are examples of Class III locations. Gases and Combustible Dusts NFPA 497M NFPA 30 NFPA 325M NFPA 321 UL 58.300 Hazardous (Classified) Areas Electrical Manual Fig. portions of some chemical and oil shale plants. drawings showing Division 1. F. or unclassified (for areas of extremely low probability). and Division 2 if they are stored or handled in a non-manufacturing environment. and unclassified area boundaries within a specific facility. 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 Chevron Corporation 300-5 May 1996 . Hydrogen is in Group B. Acetylene is the only gas in Group A. Class III areas are specified Division 1 if easily ignitable materials are handled. Article 514. 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. Most hydrocarbons are included in Group D. Division 2 (for areas of lower probability). Additionally. Combustible dusts are included in Groups E. While some individual judgment is required. the American Petroleum Institute (API) has developed Recommended Practice 500 for refining facilities. There are no groups for Class III materials. most people following these guidelines would arrive at very similar area classification drawings—that is. producing and drilling facilities. Group D (because most hydrocarbons are included in Group D). Division 2. and either Division 1 (for areas of high probability of exposure to flammable concentrations of gas). to help facilitate the selection of the electrical equipment for installation in the hazardous location. and G according to their electrical properties. as opposed to dust or fibers). To promote uniformity within the industry in area classification for oil and gas facilities. Class I and II areas are referred to as Division 1 areas when hazardous material is anticipated during normal operations on a continuous or intermittent basis. Typical areas at oil and gas facilities are classified Class I (due to gas or vapor. Group F is comprised primarily of carbon dusts. In a similar manner. Area classification drawings should include information about the gas or vapor involved. Areas are referred to as Division 2 when hazardous material is anticipated only during abnormal operations. To promote uniformity in area classification within Chevron. Group E includes metal dusts. 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. refer to the Fire Protection Manual. Section 1500. and Group G primarily of plastic and agricultural dusts. NFPA 70. manufactured or used. and hydrogen sulfide is in Group C.Electrical Manual 300 Hazardous (Classified) Areas tion’s documents numbered 325M and 497M. Determining the probability that the hazardous substance will be present is the most difficult of the three steps in classifying an area. and pipeline facilities. Class II areas are also considered Division 1 if the hazardous dust involved is metallic or is a Group E or F dust with a resistivity less than 105 ohm-centimeters. provides specific guidance for the classification of gasoline dispensing and service stations. in Classes I and II. process plant area. 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. This section defines the various types of electrical equipment suitable for use in Class I hazardous (classified) locations.. Division 2 versus Division 1). If one is classifying an area for the actual design and installation of electrical equipment. with proper area classification drawings. and the methods by which the equipment must be installed. Therefore. Each individual area (whether room. Sections 330 and 340 of this guideline cover Class I locations. if provided. 330 Types of Equipment for Class I Hazardous (Classified) Locations Electrical equipment installed in hazardous (classified) locations must be suitable for the area classification — Class. or outdoors) of the facility must be considered separately in determining the area classification. When practical. Section 370 covers the IEC Zone classification system. process engineers. In some applications. building. This section is intended to give inexperienced personnel a basic understanding of area classification. it may be more practical or economical to utilize purging and pressurization techniques. Electrical installations in hazardous locations are more costly and require special and additional precautions during maintenance operations. the National Electrical Code and other applicable documents should be consulted for additional details. safe electrical installations can be made in areas which may be exposed to flammable concentrations of gases and vapors. and safety engineers may be needed to establish area classifications. and Group. Division. or easily ignitable fibers or flyings. combustible dust. Sections 350 and 360 cover Class II locations. its maximum temperature must not exceed 80% of the ignition temperature of the gas or vapor involved (expressed in degrees Centigrade). This temperature identification number is often referred to as the T-rating. Unless equipment is T-rated. group. By applying this process. indoors. The temperature range. the area classification drawing is created. Consultation with project engineers. referenced to a 40°C (104°F) ambient. Equipment identified with a T-rating (by a nationally recog- May 1996 300-6 Chevron Corporation . is indicated by identification numbers in accordance with NEC Table 500-3(d). 331 Maximum Operating Temperatures The NEC requires that the exposed surfaces of all approved equipment used in hazardous locations operate below the ignition temperature of the specific flammable gas or vapor which may be present.300 Hazardous (Classified) Areas Electrical Manual the various classified areas. Class III will not be discussed because there are no known Company Class III locations.e. Heat producing equipment must be marked to show the class. major electrical equipment should be installed either outside hazardous (classified) locations or in less hazardous locations (i. and operating temperature or temperature range. may accumulate both moisture. 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. These gases must be cooled before they reach the surrounding atmosphere. Since they prevent (versus contain) explosions. a safety factor of 4 is used (i.e. explosionproof enclosures containing equipment and built as a complete Chevron Corporation 300-7 May 1996 . unless the equipment has been T-rated by a recognized testing laboratory. even if NEMA designations are used. In addition. unless T-rated by a nationally recognized testing laboratory (NRTL). NEMA Type 8 enclosures are not “explosionproof. Since there is no consistent relationship between the ignition temperature and the other explosive properties of a substance. Explosionproof enclosures suitable for use in Class I (Division 1 and 2) locations are designated NEMA (National Electrical Manufactures Association) Type 7. If an internal explosion occurs. Identifying only the group to which the flammable substance belongs is not sufficient to establish maximum surface operating temperatures of equipment. In most designs for Class I. Divisions 1 and 2.Electrical Manual 300 Hazardous (Classified) Areas nized testing laboratory) can be applied up to the auto ignition temperature (AIT) of the gas or vapor involved equal to the T-rating. the enclosure must withstand a very rapid buildup of pressure which is relieved by the escape of the expanding gases. Explosionproof enclosures breathe when the ambient temperature changes and. 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. 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. See NEC Article 500-3 and NFPA 497M for additional information.” 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. In order to comply with NEC Article 500-3(b). 332 Equipment Enclosures Explosionproof enclosures are capable of withstanding an internal explosion and preventing its propagation to the external atmosphere. the enclosure must withstand a hydrostatic test four times the maximum pressure normally produced by an explosion within the enclosure). and hazardous gases within. Arcing is confined under the oil so that it will not ignite an explosive mixture of the specified gases in internal spaces above the oil or in the atmosphere surrounding the enclosure. equipment selection must be based on Class and Group as well as on operating temperature.. therefore. it may be employed with various end devices to form an intrinsically safe system. 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 equipment (as well as the inherent environmental protection for the hermetically sealed contacts. mechanically strong. Abnormal equipment conditions include accidental damage to or failure of any part of the equipment. Enclosures whose seals are formed by O-rings. Refer also to API RP 14F and API RP 540 for guidelines on the application of enclosures in offshore and refinery locations. Intrinsically safe systems are suitable for use in any hazardous (classified) location for which they are approved. However. respectively. The materials used to accomplish hermetic sealing must be resistant to mechanical abuse and durable enough to withstand normal aging. Where equipment has been rated intrinsically safe by a recognized testing laboratory. or silicone compounds are not necessarily considered hermetically sealed. motor starters) must be labeled with the appropriate Class and Group designations and either the operating temperature or the temperature range. and exposure to overvoltage. and the effects of severe weather. These devices are suitable for use in Division 2 and unclassified areas. 333 Hermetically Sealed Devices Hermetically sealed devices are designed to prevent flammable gases from coming in contact with sources of ignition.) This feature is particularly desirable in corrosive atmospheres or outdoor installations. such as controllers. Normal conditions include periods of adjustment and maintenance.. In Division 2 applications. No May 1996 300-8 Chevron Corporation .g. or other components. 334 Intrinsically Safe Systems Intrinsically 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 concentration. wiring. refer to NEMA Standards Publication 250. be located in an unclassified area. insulation. such as arcing contacts or high-temperature components.300 Hazardous (Classified) Areas Electrical Manual assembly (e. For a complete description of NEMA enclosures and their requirements. Particular attention must be paid to the Group(s) listed. NEC Articles 500 through 517 do not require intrinsically safe systems. Hermetically sealed enclosures must be sealed through glass-to-metal or metal-to-metal fusion at all joints and terminals. significant savings can be realized by using hermetically sealed devices since non-explosionproof enclosures are then allowed. The most common applications are in instrumentation and communication systems. nor is the potting of components necessarily considered hermetic sealing. such systems may require that specific equipment items. The bond between the different materials employed must be permanent. epoxy. Article 504 of the NEC governs the requirements for the installation of intrinsically safe systems. molded elastomer. and capable of withstanding the surrounding environment. exposure to chemicals and hydrocarbons. bulky. extreme care should be exercised. Such equipment is suitable for use only in Division 2 and unclassified locations. Proper design of an intrinsically safe system requires adherence to strict rules. However. This disadvantage can be minimized by using hermetically sealed contacts or devices with wiping contacts. and in most cases. wiring methods must conform to area classification requirements. Intrinsically safe equipment does not require explosionproof enclosures. Two disadvantages of intrinsically safe systems are: 1. and NEC Article 504 should be followed closely when designing and installing intrinsically safe systems. laboratory testing. 335 Nonincendive Equipment Nonincendive equipment is not capable of igniting a flammable mixture under normal circumstances. Economy and Convenience. Chevron Corporation 300-9 May 1996 .Electrical Manual 300 Hazardous (Classified) Areas end device is of itself intrinsically safe. Nonincendive equipment normally is limited to instrumentation and communication systems. Portions of a nonincendive system may operate at energy levels potentially capable of causing ignition. depending on the wiring methods used. detailed mathematical analysis. Therefore.6. Maintenance and calibration operations can be performed in classified areas without de-energizing the equipment or shutting down process equipment. Thus. or hermetically sealed. This could increase the installed system cost. oil immersed. sliding or makeand-break contacts need not be explosionproof. Intrinsically safe apparatus and wiring may be installed using any of the wiring methods suitable for unclassified locations. and corroded conduit systems will not impair the safety of the systems. Low power signals are more easily affected by high contact resistance. of the Instrumentation and Control Manual. Circuit Separation. The low voltages and currents involved may reduce the hazard of electrical shock. Standards UL 913 and ISA RP 12. The two most important advantages of intrinsically safe equipment are: 1. Safety. When employing nonincendive systems. with maintenance personnel specifically trained with that proper maintenance in view. High Contact Resistance. Wiring for intrinsically safe systems need only meet the requirements of Article 504 of NEC. Nonincendive equipment is similar in design to other equipment suitable for Division 2 locations. 2. enclosures open during maintenance and testing operations. but is intrinsically safe only when employed in a properly designed intrinsically safe system. explosion-proof enclosures are not required. missing bolts and covers. Wiring for intrinsically safe systems must be installed separately from higher power circuits. Intrinsically safe equipment must always be maintained as an intrinsically safe system. but ignition is not necessarily prevented under abnormal circumstances. See Section 1400. in nonincendive equipment. Thus. expensive. 2. May 1996 300-10 Chevron Corporation . If they do not contain flammable liquids. Also. power equipment enclosures. the use of humid salt air for purging will cause corrosion damage to equipment. The word “approved” as used in this section is defined as “acceptable to the authority having jurisdiction. Transformers In Division 1 areas. (Totally enclosed.” Most authorities will require equipment to be tested and approved by a nationally recognized testing laboratory (NRTL).) Liquid-filled transformers usually require external metering and protective devices which must be suitable for the area. Manufacturers’ literature. not just built to appropriate standards. transformers containing flammable liquids must be installed in vaults. environmental and corrosive considerations are outside the scope of this section. Any source of air for purging must be from an unclassified location. On an offshore platform. and large volume enclosures (such as control rooms). liquid-filled units may require costly curbing and drains in environmentally sensitive areas. API RP 14F provides requirements and recommendations for wiring and equipment located on fixed offshore production platforms. they must either be installed in vaults or be approved for Division 1 locations. 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. NEC Article 501 provides requirements for wiring and equipment in Class I locations. Generally. non-ventilated transformers are recommended for harsh outside environments. dry-type transformers are normally more economical for 600 volts or less and for 150 kVA or smaller sizes. use of inert gas or dehydrated clean air must be considered. thus. 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. 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. In Division 2 locations.300 Hazardous (Classified) Areas Electrical Manual 336 Purged Enclosures Purging (frequently referred to as pressurizing) is a method of installing electrical equipment in a Class I area without using explosionproof enclosures. In Class I. are limited to a maximum of 480 volts. Division 1 locations must be installed in explosionproof enclosures. In Class I. In Class I. light switches and start-stop stations. certain types of fuses can be installed in general purpose enclosures: • • • silver-sand. 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. are commonly available for level switches and other sensing devices. Solid state switches. double-throw. single phase and DC motors. relays. 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 available) that satisfy the requirements of NEC Article 501-5(f)(3) when sensing ignitable fluids. they must be sealed where cable (other than type MI) is used. for example.Electrical Manual 300 Hazardous (Classified) Areas See NEC Article 501-2 for Class I locations. grounding resistors. and lamps should be considered high temperature devices unless they are T-rated by an NRTL. immersed in oil. Refer to NEC Article 450 for additional transformer requirements. Division 2 locations must be installed in explosionproof enclosures. Also. are suitable for general purpose enclosures for Division 2 locations. motor starters. in offshore areas where certain cables are allowed in Division 1 areas. and circuit breakers are typical arcing devices. High temperature devices in Class I. suitable for Division 2 locations. Arcing and High Temperature Devices Switches. arcing contacts must be installed in explosionproof enclosures. arcing and high temperature devices must be installed in enclosures which are either approved explosionproof or purged in accordance with NFPA 496. without contacts. Division 2 areas. Factory-sealed units are suitable for Division 1 and Division 2 areas without external sealing fittings. single-throw. Division 2 locations. or be nonincendive. hermetically sealed mercury switches are suitable for Division 2 locations and can be obtained as single-pole. hermetically sealed. Typically they are singlepole. Division 1 areas. fuses. Division 2 locations must be installed in explosionproof enclosures. particularly concerning vaults. if the surface temperature of the mechanism does not exceed 80% of the AIT (in °C) of the gas or vapor involved. However. and are limited to 100 VA. Chevron Corporation 300-11 May 1996 . Utility switches. Hermetically sealed reed switches. Fuses in Class I. Space heaters. 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. hand-off-automatic. it is desirable (for environmental protection) to install hermetically sealed control stations (e. 4. 2. See API RP 14F. MI. 5. separate grounding conductors. 1. See NEC Articles 501-16(b). 5. 6. Division 1 locations: 1. an overall jacket of suitable polymeric. except rigid nonmetallic conduit. Enclosed gasketed busways Enclosed gasketed wireways Type PLTC (power-limited tray cable) cable in accordance with NEC Article 725 Type MC.. TC. and other provisions of Article 5014(a).300 Hazardous (Classified) Areas Electrical Manual Frequently. and start-stop devices) in NEMA 4X or 3R enclosures. May 1996 300-12 Chevron Corporation . These installations are suitable for Division 2 areas.g. Additional wiring methods allowed in Division 2 locations include the following: 1. 2. Exception No. installed below grade. 4. Division 2 locations. of the 1996 NEC IMC and Type MI cable are not recommended for offshore installations. the NEC allows all of the wiring methods for Division 1 locations. Lengths should be kept as short as possible and cannot exceed 6 feet unless an approved internal bonding system is provided. Threaded rigid metal conduit Intermediate metal conduit Type MI (mineral-insulated metal-sheath) cable Explosionproof flexible connections Rigid nonmetallic conduit. with approved fittings Type ITC (instrumentation tray cable) cable in accordance with NEC Article 727 Flexible cord rated for extra hard service with an equipment grounding conductor.4 for additional application guidelines. Division 1 locations with a gas/vaportight continuously corrugated aluminum sheath. Exception No. Section 4. and encased in concrete per the requirements of Article 501-4(a). listed for use in Class I. 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 applications requiring flexibility. 3. Refer to NEC Article 501-3 and API 14F (for offshore platforms) for additional details. 3. and other specific cables. 2. 250-91(b) and 250-79(c) and (f) for additional requirements relative to flexible connections. of the 1996 NEC Type MC cable. In Class I. Wiring Methods The following wiring methods are allowed in Class I. motors. must also be approved for the location in which it is installed.Electrical Manual 300 Hazardous (Classified) Areas Type TC (Tray Cable) and Type MC (Metal Clad) cables are suitable for use in Class I. generators. supplied with positive-pressure ventilation. (2) totally enclosed. the splice should be made with a heat shrink tubing to maintain the integrity of the unbroken sheath. NEC Article 501-5 contains the requirements for sealing cables and conduits in Division 1 and 2 areas.) is considered to be a gas/vapor tight continuous sheath. In Division 2 areas. it may be more economical to select totally enclosed units supplied with positive pressure ventilation as described in NEC Article 501-8(a). Cables installed in trays per the cable manufacturer’s recommendation should not suffer jacket damage due to installation. Division 1 are preferred. Division 1. must be approved Chevron Corporation 300-13 May 1996 . etc. and other rotating electrical machinery that employs sliding contacts. and other rotating electric machinery used in Class I locations. explosionproof machines approved for Class I. See API 14F Section 4. Motors and generators should be selected to provide optimum protection from the environment and satisfy the area classification. such as space heaters. CSPE. Auxiliary equipment. It is recommended that underground conduits. The NEC does qualify this “no seal requirement” at the Division 2 and unclassified boundary by stating that the sheath must be unbroken. If installation in Division 1 locations is unavoidable. The extruded polymeric cable jacket (PVC. in soil that may be hydrocarbon laden. totally enclosed fan cooled (TEFC). Four types of rotating electric machinery are suitable for Class I. For large motors and generators. and totally enclosed water/air cooled (TEWAC). Division 2 location. 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 Generators The proper selection of motors and generators is imperative to ensure safety and minimize initial and subsequent maintenance costs. If the jacket is damaged or if an in-line splice is made in a Class I.8(a) for a description of the purposes for sealing. (3) totally enclosed. inert gas filled. be sealed where they enter and/or exit the ground.8(b). generators. This generally applies to three-phase induction motors and brushless generators. CPE. weather protected I (WPI) and II (WPII). Some enclosures typically specified are: open drip proof (ODP). totally enclosed pipe ventilated (TEPV). Division 2 locations. and the cable is permitted to pass from a Division 2 location to an unclassified location without a seal. For sealing requirements on offshore installations see API 14F Section 4. non-explosionproof motors and generators having no arcing or high temperature devices are permitted. and (4) liquid submerged. switching devices or resistance devices. In Division 2 areas. Refer to NEC Article 501-8 for complete requirements on motors. Division 1 areas: (1) explosionproof approved for Class I. generators.300 Hazardous (Classified) Areas Electrical Manual for Class I. Maximum surface temperature shall be permanently marked on a visible nameplate mounted on the motor. The requirements above for Division 1 fixtures concerning stems also apply. Stems over 12 inches in length must be laterally braced within 12 inches of the fixture. These devices may be installed in machines with enclosures of TEPV design with the source of air and vent in nonhazardous locations. This equipment must provide for connection of a flexible cord. and corrosion considerations. Refer to NEC Article 501-9 for further details on Class I locations. arcing or high temperature devices.The exposed surface temperature of motors. Ignition Systems Low tension (voltage) systems must be utilized on all offshore locations and at onshore locations classified Class I. it may be more economical to use purged enclosures for these devices in accordance with NFPA 496. Because all equipment must meet the area classification requirements (Class. selection of a specific type of motor or generator is dependent on economical. Motor surge arresters of the gapless non-arcing types such as sealed type. and Group). Receptacles and Attachment Plugs Receptacles and attachment plugs must be approved for Class I locations. facilitating maintenance and extending ballast life if the ballasts would otherwise be mounted in a high temperature area. 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 May 1996 300-14 Chevron Corporation . Division. environmental. Division 1 locations. Lighting Fixtures In Division 1 areas. Division 1 or 2. In Division 2 areas. metal oxide varistor (MOV) and surge capacitors may be installed in general purpose enclosures for these devices in Division 2 locations. Pendant fixtures must be suspended by conduit stems and provided with set screws or other effective means to prevent loosening. as described in NEC Article 501-17. Other fixtures must be either explosionproof or labeled as suitable for Division 2 and for the particular Group involved. unless those devices are enclosed in Class I enclosures. other rotating equipment. For motor auxiliary. Division 1 locations. Surge arresters of types other than described above shall be installed in enclosures approved for Class 1. Remote mounted ballasts may be mounted at a lower level. portable lamps must be explosionproof. See the Driver Manual for additional information on motors and generators. grounding conductor. 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. lighting fixtures must be explosionproof and marked to indicate the maximum wattage of allowed lamps. They must be protected from physical damage by a suitable guard or by location. Section 1230 of this manual contains a detailed procedure for choosing suitable lighting fixtures. They must be protected against physical damage by suitable guard or by location. even these ordinary flashlights can ignite flammable gases and vapors. under “ideal” conditions. “Electrical Flashlights and Lanterns for Hazardous Locations. Solid-state ignition systems should be provided as original equipment and as replacements when economically justified. Unless cameras have been properly evaluated. Telephone equipment (including outside ringers) installed in Class I areas must be explosionproof or otherwise suitable for the area. If there are any questions concerning a particular model. All wiring should be kept as short as possible. 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. making it susceptible to arcing. All locations should be reviewed for Class I areas which are other than Group D (e. Flashlights Ordinary commercial two. 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. The use of shielded ignition wire is allowed but not required.” for additional information. In Class I locations. video. clean. This modification does not eliminate internal combustion engines as a possible ignition source but substantially reduces the possibility of an ignition occurring. Group B for hydrogen). Cameras Most modern cameras (still. and clear of hot or rubbing objects. Groups C and D.Electrical Manual 300 Hazardous (Classified) Areas section on internal combustion engines in the Fire Protection Manual. utilizing intrinsically safe circuits). the conductor is easily broken by bending the wire. Communication Equipment Stationary 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.and three-cell flashlights present a minimal risk of igniting natural gas and most petroleum vapors.) Therefore. 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. consult the Telecommunications Division of Chevron Information Technology Company. Resistance wire with a carbon impregnated linen core should not be used. Many portable hand-held radios used throughout the Company are listed (usually by Factory Mutual) as intrinsically safe or nonincendive.. it must be assumed that they are a source of ignition (particularly those with flashes or motor drives).g. However. and movie) utilize batteries for light sensors and may utilize batteries for artificial illumination (flash or continuous) and automatic film advance. Chevron Corporation 300-15 May 1996 . Class I. it is recommended that all flashlights be approved by a recognized testing laboratory as suitable for Class I. the flashlights used should be suitable for the appropriate classification (group). (See UL783. and if such areas exist. When installed and protected in accordance with the NEC they will not permit arcs.300 Hazardous (Classified) Areas Electrical Manual 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. Division 1 areas. This section defines the various types of electrical equipment suitable for use in Class II hazardous (classified) locations. Class I and Class II areas are covered by the same basic maximum temperature requirements. and similar devices. Division. Miscellaneous Equipment Air conditioning units used in unclassified areas often have equipment exposed to external Class I. without first taking the precautions outlined above. sparks or heat within the enclosure to cause ignition of a specified dust on or in the vicinity of the enclosure. vents should be sealed closed and sealant should be placed around the perimeter of the wall penetration. In such installations. 352 Equipment Enclosures “Dust-ignitionproof” enclosures are capable of excluding ignitible quantities of dusts or amounts that might affect performance or rating. 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. May 1996 300-16 Chevron Corporation . 351 Maximum Operating Temperatures Refer to Section 331 for a general discussion of maximum operating temperatures. all openings between the internal and external environments must be sealed. or flammable chemical or gas handling equipment. Specifically. the latter method generally requires the utilization of a portable combustible gas detector by a qualified operator. Cameras must not be used in enclosed areas such as buildings which contain producing or drilling equipment. 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. and Group). 350 Types of Equipment for Class II Hazardous (Classified) Locations Electrical equipment installed in hazardous (classified) locations must be suitable for the area classification (Class. Dust-ignitionproof enclosures suitable for use in Class II (Division 1 and 2) locations are designated NEMA (National Manufacturers Association) Type 9. Storage batteries in Class I. Refer to Section 330 for additional comments. As a practical procedure. Class II temperature limits are given in NEC Article 500-3(f). The former method generally requires testing by a recognized testing laboratory. Division 2 areas. These may be used after ascertaining from the person-in-charge that no unusual operations (such as venting) are in progress or anticipated. Storage batteries should not be installed in Class I. This feature is particularly desirable in corrosive atmospheres or outdoor installations.g. even if NEMA designations are used. exposure to chemicals and dusts.. and the effects of severe weather. For a complete description of NEMA enclosures and their requirements. 12P. 6P. 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 equipment (as well as the inherent environmental protection for the hermetically sealed contacts). unless the equipment has been T-rated by a nationally recognized testing laboratory (NRTL). They cannot be used in Class II. The surface temperature of the enclosure must not be higher than 80% of the ignition temperature (in degrees C) of the dust involved. 12. Dust tight enclosures are suitable for Class II. such as arcing contacts or high-temperature components. Division 1 locations. dust-ignitionproof and dust tight enclosures containing equipment and built as a complete assembly (e.Electrical Manual 300 Hazardous (Classified) Areas Explosionproof enclosures are not required and are not acceptable for Class II areas unless they are additionally approved for such areas. 3S. 354 Intrinsically Safe Systems Intrinsically safe systems are described in Section 334. Dust tight enclosures are made with gaskets or other means to exclude dust. refer to NEMA Standards Publication 250. and 13 enclosures can be made dust tight. motor starters) must be labeled with the appropriate Class and Group designations and either the operating temperature or the temperature range. They are suitable for use in any hazardous (classified) location for which they are approved. 6. 4X. The door or cover must be dust tight — obtained with either a securely fastened gasket or closeness of fit of the mating flanges. These devices are suitable for use in Division 1. Division 2 locations. 4. bonded conduit hub. They have no openings or knockouts. Threaded-hub fittings must be dust tight through welding or gasketing. The materials used to accomplish hermetic sealing must be resistant to mechanical abuse and durable enough to withstand normal aging. significant savings can be realized by using hermetically sealed devices since non-dust-ignitionproof enclosures are then allowed. Conduit entries into dust tight enclosures must be through tapped threads with a minimum of three threads engaged or by a gasketed. In Class II applications. Chevron Corporation 300-17 May 1996 . 353 Hermetically Sealed Devices Hermetically sealed devices are designed to prevent combustible dusts from coming in contact with sources of ignition. The door or cover must be captive to the enclosure. NEMA 3. Particular attention must be paid to the Groups(s) listed. Division 2 and unclassified 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). In order to comply with NEC Article 500-3(b). 356 Pressurized Enclosures Pressurizing is a method of installing electrical equipment in a Class II area without using dust-ignitionproof or dust tight enclosures. in nonincendive equipment. NFPA 496 discusses the different requirements for the pressurizing of small enclosures. Any source of air for pressurizing must be from an unclassified location. they must either be installed in vaults or be approved as a complete assembly for Class II locations. 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. However. environmental and corrosive considerations are outside the scope of this section. Nonincendive equipment normally is limited to instrumentation and communication systems. power equipment enclosures. not just built to appropriate standards. The word “approved” as used in this section is defined as “acceptable to the authority having jurisdiction. When employing nonincendive systems. Nonincendive equipment is similar in design to other equipment suitable for Division 2 locations. No transformer shall be installed in a location where metal dust may be present.” Most authorities will require equipment to be tested and approved by a nationally recognized testing laboratory (NRTL). Such equipment is suitable for use only in Division 2 and unclassified locations. Generally. Portions of a nonincendive system may operate at energy levels potentially capable of causing ignition. wiring methods must conform to area classification requirements. but ignition is not necessarily prevented under abnormal circumstances. 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. sliding or make-and-break contacts need not be dust-ignitionproof. transformers containing flammable liquids must be installed in vaults. and large volume enclosures (such as control rooms). If they do not contain flammable liquids. dust tight. May 1996 300-18 Chevron Corporation . Transformers In Division 1 areas. or hermetically sealed.300 Hazardous (Classified) Areas Electrical Manual 355 Nonincendive Equipment Nonincendive 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. Therefore. extreme care should be exercised. NEC Article 502 provides requirements for wiring and equipment in Class II locations. single phase and DC motors. relays. Threaded rigid metal conduit Intermediate metal conduit Type MI (mineral-insulated metal-sheath) cable Chevron Corporation 300-19 May 1996 . Refer to NEC Article 450 for additional transformer requirements. 2. Refer to NEC Article 502-6 for additional details. it is desirable (for environmental protection) to install hermetically sealed control stations (e.. be able to absorb gasses generated by arcing. Division 1 areas. Transformers containing askarel and rated above 25 kVA shall be provided with pressurerelief vents. grounding resistors. Transformers containing flammable liquids must be installed in vaults. particularly concerning vaults. and circuit breakers are typical arcing devices. liquid-filled units may require costly curbing and drains in environmentally sensitive areas. Division 1 areas must be installed in dust-ignitionproof enclosures and approved as a complete assembly for Class II locations. Frequently. they must be installed in dust tight or dust-ignitionproof enclosures. hand-off-automatic and start-stop devices) in NEMA 4X or 3R enclosures. In Class II. High temperature devices in Division 2 locations must be installed in dust-ignitionproof enclosures. arcing contacts must be installed in dust tight or dustignitionproof enclosures. and have an air space not less than 6 inches between the case and combustible material. 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. 3. Wiring Methods The following wiring methods are allowed in Class II. 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. In Class II. dry type transformers shall be installed in a vault or have their windings and terminal connections totally enclosed and not operate over 600 volts.g. Division 1 locations: 1.Electrical Manual 300 Hazardous (Classified) Areas In Division 2 locations. Division 2 locations. See NEC Article 502-2 for Class II locations. Fuses in Class II. arcing and high temperature devices must be installed in enclosures specifically approved for Class II. Arcing and High Temperature Devices Switches. Division locations. Space heaters. and lamps should be considered high temperature devices unless they are T-rated by an NRTL. In Class II. motor starters. 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. Division 2 areas. fuses. Division 1 areas where metal dusts may be present. Also. an overall jacket of suitable polymeric. and (2) totally enclosed. NEC Article 502-5 contains the requirements for sealing cables and conduits in Division 1 and 2 locations. 2. 5. such as space heaters. Lengths should be kept as short as possible and cannot exceed 6 feet unless an approved internal bonding system is provided. 1. 3. and electrical sealing putty is an acceptable method of sealing. the NEC allows the Division 1 wiring methods. 250-91(b) and 250-79(c) and (f) for additional requirements relative to flexible connections. generators. Division 1 areas: (1) dust-ignitionproof approved for Class II. and other rotating electric machinery used in Class II locations. See NEC Articles 50216(b). Dust tight flexible connections Type MC cable. Auxiliary equipment. separate grounding conductors.300 Hazardous (Classified) Areas Electrical Manual 4. must also be approved for the location in which it is installed. If installation in Division 1 locations is unavoidable. it May 1996 300-20 Chevron Corporation . Exception No. and other provisions of Article 502-4(a). with a gas/vapor-tight continuously corrugated aluminum sheath. Motors and generators should be selected to provide optimum protection from the environment and satisfy the area classification. Seal fittings shall not be required to be explosionproof. dust-ignitionproof machines approved for Class II. listed for use in Division 1 locations. plus the following: 1. For large motors and generators. Division 1 are preferred. Refer to NEC Article 502-8 for complete requirements on motors. with approved fittings 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. Motors and Generators The proper selection of motors and generators is imperative to ensure safety and minimize initial and subsequent maintenance costs. Division 1. Dust tight wireways Type PLTC (power-limited tray cable) cable in accordance with NEC Article 725 Type MC and TC cable. Two types of rotating electric machinery are suitable for Class II. All threaded connections (including enclosures and conduits) should be lubricated with an electrically conductive and enthuses compound which will survive in the environment. of the 1996 NEC In Division 2 areas. 4. pipe ventilated. Lighting Fixtures In Division 1 areas. motors and generators shall be totally enclosed fan cooled (TEFC). the ventilating piping must comply with NEC Article 502-9. The requirements above for Division 1 fixtures concerning stems also apply. Chevron Corporation 300-21 May 1996 . This modification does not eliminate internal combustion engines as a possible ignition source. They must be protected against physical damage by a suitable guard or by location. “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. In Division 2 areas. facilitating maintenance and extending ballast life if the ballasts would otherwise be mounted in a high temperature area.Electrical Manual 300 Hazardous (Classified) Areas may be more economical to select totally enclosed pipe ventilated units as described in NEC Article 502-8(a). This equipment must provide for connection of a flexible cord. totally enclosed pipe ventilated (TEPV). portable lamps must be dust-ignitionproof. They must be protected from physical damage by a suitable guard or by location. Ignition Systems 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. If totally enclosed pipe ventilated units are installed in Class II locations. or dust-ignitionproof. protective boots or covers should be provided for all high voltage (tension) connections. 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. Section 1230 of this manual contains a detailed procedure for choosing suitable lighting fixtures. Rigid stems over 12 inches in length must be laterally braced within 12 inches of the fixture. In Class II locations. Solid-state ignition systems should be provided as original equipment and as replacements when economically justified. lighting fixtures must be dust-ignitionproof and marked to indicate the maximum wattage of allowed lamps. Receptacles and Attachment Plugs Receptacles and attachment plugs must be approved for Class II locations. grounding conductor. Remote mounted ballasts may be mounted at a lower level. lighting fixtures must be approved for the specific location. In areas where metal dusts may be present. but substantially reduces the possibility of an ignition occurring. totally enclosed non-ventilated (TENV). In Division 2 areas. Refer to NEC Article 502-11 for further details on lighting fixtures in Class II locations. Other fixtures must be either dust-ignitionproof or labeled as suitable for Division 2 and for the particular Group involved. As a practical procedure. utilizing intrinsically safe circuits). the latter method generally requires visible inspection by a qualified operator. 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. consult the Telecommunications Division of Chevron Information Technology Company. The use of shielded ignition wire is allowed but not required. and clear of hot or rubbing objects. May 1996 300-22 Chevron Corporation . Unless cameras have been properly evaluated. Cameras Most modern cameras (still. Storage batteries should not be installed in Class II locations unless provided with suitable enclosures. Division 2 areas. 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. Communication Equipment Stationary 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. Telephone equipment (including outside ringers) installed in Class II areas must be dust-ignitionproof or otherwise suitable for the area. Miscellaneous Equipment Air conditioning units used in unclassified areas often have equipment exposed to external Class II. and movie) utilize batteries for light sensors and may utilize batteries for artificial illumination (flash or continuous) and automatic film advance. making it susceptible to arcing. all openings between the internal and external environments must be sealed. If there are any questions concerning a particular model. In such installations. Many portable hand-held radios used throughout the Company are listed (usually by Factory Mutual) as intrinsically safe or nonincendive. cameras without either a flash (strobe or flash bulb) or a motor drive may be utilized in open.300 Hazardous (Classified) Areas Electrical Manual Resistance wire with a carbon impregnated linen core should not be used. clean. Cameras must not be used in enclosed areas such as buildings which contain dust handling equipment. the conductor is easily broken by bending the wire. video. without first taking the precautions outlined above. vents should be sealed closed and sealant should be placed around the perimeter of the wall penetration. it must be assumed that they are a source of ignition (particularly those with flashes or motor drives). The former method generally requires testing by a recognized testing laboratory. All wiring should be kept as short as possible. Specifically. These may be used after ascertaining from the person-incharge that no unusual operations are in progress or anticipated. well ventilated areas which are at least 10 feet from dust processing equipment. are approximately equivalent to Division 1. 1 and 2 locations. Zone 1 listed equipment cannot be installed in Division 1 locations (which also includes Zone 0). Chevron Corporation 300-23 May 1996 . motors. Figure 300-2 describes the Zone classification system. Figure 300-3 gives a cross reference between the NEC and IEC area classification systems. Equipment listed for Division 1 locations can be installed in Zone 1 locations and equipment listed for Division 2 in Zone 2 locations. similar to RP500. for the Zone classification system. 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 explosionproof apparatus. That is. Equipment such as lighting. Zones 0 and 1 combined. It is not a replacement for the “Division” classification system. nor can Zone 2 listed equipment be installed in Division 2 locations unless the equipment is NRTL-listed for the specific application. Zone 2 is approximately equivalent to Division 2. An IEC concept not yet available for application with an NEC equivalent is the IEC “increased safety” (EX “e”) category. Generally. and permits all wiring methods allowed in Division 2 to be used in Zone 2 locations. the American Petroleum Industry (API) is in the process of developing a recommended practice. This system has been applied outside of the US for decades. after suitable NRTL test standards are complete. but these test standards should be fully available by the time that the 1999 NEC is issued. Only intrinsically safe systems are allowed in a Zone 0 locations. but may be used as an alternative under the supervision of a qualified Registered Professional Engineer. and requires specifically approved and secure terminations. The practical application of the Zone system cannot be used until Nationally Recognized Testing Laboratories (NRTL) have standards to approve equipment for use in Zone 0. Also.Electrical Manual 300 Hazardous (Classified) Areas 370 Area Classification Based on the IEC “Zone” System for Flammable Gases or Vapors Article 505 of the 1996 NEC has introduced the International Electrotechnical Commission (IEC) classification system in the United States. but not vice versa. Full applicability of the Zone system awaits the publication of suitable test standards. Increased safety equipment essentially limits surface temperatures and provides protection against sparking within apparatus. These standards are currently under development by a number of ISA committees. the NEC permits all wiring methods allowed in Division 1 to be used in Zone 1 locations. in which ignitible concentrations of flammable gases or vapors are present for long periods of time. that is adjacent to a Class I. Class I. or 4. or 3. but which may become hazardous as the result of failure or abnormal operation of the ventilation equipment. 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. but in which the liquids. or 2. or used. unless communication is prevented by adequate positive-pressure ventilation from a source of clean air and effective safeguards against ventilation failure are provided. unless communication is prevented by adequate positive-pressure ventilation from a source of clean air. or as the result of the abnormal operation of the equipment with which the liquids or gases are handled. processed. 300-2 Zone Classification System Zone Description A location: 1. gases. in which ignitible concentrations of flammable gases or vapors are likely to existunder normal operating conditions. Zone 2 A location in which: 1. or used. or 2. or 3. or 2. in which ignitible concentrations of flammable gases or vapors normally are prevented by positive mechanical ventilation. 380 References The following references are readily available. Zone 1 A location: 1. Zone 0 location from which ignitible concentrations of vapors could be communicated. flammable gases. processed. equipment is operated or processes are carried on. Zone 0 Class I. in which volatile flammable liquids. 381 Model Specifications (MS) There are no model specifications in this guideline. 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 4. and effective safeguards against ventilation failure are provided. Class I. or flammable vapors are handled. in which ignitible concentrations of flammable gases or vapors are present continuously. that is adjacent to a Class I. of such a nature that equipment breakdown or faulty operations could result in the release of ignitible concentrations 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 ignition. May 1996 300-24 Chevron Corporation . from which ignitible concentrations of flammable gases or vapors could be communicated. in which ignitible concentrations of flammable gases or vapors may exist frequently because of repair or maintenance operations or because of leakage. Those marked with an asterisk (*) are included in this manual or are available in other manuals.300 Hazardous (Classified) Areas Electrical Manual Fig. Zone 1 location. 2 Ex Type ib. and Engineering Forms (EF) ELC-EF-652 Conduit Stub-up Arrangement 384 Other References Various organizations have developed numerous codes. 383 Data Sheets (DS).R.2 Pressurization Ex Type p.T. Codes. 1. guides and standards useful in classification of locations for electrical installations and selecting equipment for these locations are listed below as references only. Zone 1 Ex Type n. 2 Hermetically sealed Division 2 Nonincendive Division 2 Identification Number (NEC) T1 450°C T2 300°C T3 200°C T4 135°C T5 100°C T6 85°C T1 450°C T2 300°C T3 200°C T4 135°C T5 100°C T6 85°C 382 Standard Drawings GF-P99987 Typical Area Classification for Selection of Electrical Equipment—Process Plant. guides and standards that are widely accepted by industry and governmental bodies. Data Guides (DG).2 Ex Type h. Zone 2 Flameproof Ex Type d Zone 1. Zone 1. Tank Field and T. Zone 2 Locations Divisions (Zones) Type of Protection Explosionproof NEMA Type 7 Division 1.2 Purged Division 1. Zone 0.Electrical Manual 300 Hazardous (Classified) Areas Fig. 300-3 Cross Reference Between NEC and IEC for Classified Locations of Gases and Vapors Classification Topic NEC Class I Group A Group B Group C Group D Division 1 Division 2 Intrinsically Safe Division 1 and Division 2 IEC Group II ≈ IIC ≈ IIB plus Hydrogen ≈ IIB ≈ IIA Zone 0 & Zone 1 Zone 2 Intrinsically Safe Ex Type ia.L. These are not Chevron Corporation 300-25 May 1996 . 300 Hazardous (Classified) Areas Electrical Manual 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. and Dusts for Electrical Equipment in Hazardous (Classified) Locations NFPA Fire Protection Handbook May 1996 300-26 Chevron Corporation .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. Design. Gases & Volatile 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. 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 Standards The International Electrotechnical Commission (IEC) Publication 79-7 and Complete Series The European Committee for Electrotechnical Standardization (CENELEC) Publication CEN 110. Vapors. B. C and D. Schram and Mark W. 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. 58A. and Class III. Peter J. and III.6 Installation of Intrinsically Safe Systems for Class I Hazardous (Classified) Locations Chevron Corporation 300-27 May 1996 . An Investigation of Additional Flammable Gases or Vapors With Respect to Explosionproof Electrical Equipment UL 58B Bulletin of Research No. 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 Shipboard ANSI/IEEE 303 IEEE Recommended Practice for Auxiliary Devices for Motors in Class I. Hazardous Locations UL 1604 Electrical Equipment for Use in Hazardous Locations. 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) Locations ANSI/UL 913 Intrinsically Safe Apparatus and Associated Apparatus for Use in Class I. 3611 Electrical Equipment for Use in Class I. Groups C and D. (UL) UL 58 Bulletin of Research No. Inc. 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. Classes I and II. Divisions 1 and 2 Factory Mutual Research Corporation (FM) Approval Standard Class No. 58. Class II. Groups A. and Class III. Class I. Division 2. 58B. Division 1. II. Division 2. Division 2. Class II.1 Electrical Instruments in Hazardous Atmospheres ANSI/ISA RP 12. Groups E. An Investigation of Fifteen Flammable Gases or Vapors With Respect to Explosionproof Electrical Equipment UL 58A Bulletin of Research No.Electrical Manual 300 Hazardous (Classified) Areas NFPA Electrical Installations in Hazardous Locations. Easley Underwriters’ Laboratories. Installation. Bulletin 627 American Bureau of Shipping. Part 250. Shipping. Oil and Gas and Sulphur Operations in the Outer Continental Shelf (Minerals Management Service) Code of Federation Regulations. and Regulations Code of Federal Regulations. Rules. Marshland. OSHA Standards. Subpart S. and Maintenance of Combustible Gas Detection Instruments Chevron Corporation Practices and Standards Chevron U. Subchapter J. Eastern Region—Exploration. Subpart 111. Department of Transportation. Labor. Part II. Rules for Building and Classing Mobile Offshore Drilling Units Miscellaneous References Appleton NEC Code Review (Appleton Electric Company) Code Digest (Crouse Hinds Company) May 1996 300-28 Chevron Corporation . Part I.10 Area Classification in Hazardous (Classified) Dust Locations ISA S 12. Title 46. Performance Requirements. Chapter XVII. Coast Guard. Chapter I. OSHA Standard Subpart H. OSHA. Electrical Construction Guidelines for Offshore. Inc. Operation.A.300 Hazardous (Classified) Areas Electrical Manual ISA S 12.S. Hazardous Materials.13. & Inland Locations Fire Protection Manual Government Codes.. Part 1910. Flammable Characteristics of Combustible Gases and Vapors.106 Code of Federal Regulations.12 Electrical Equipment for Use in Class I. Division 2 Hazardous (Classified) Locations ISA S 12. Chapter XVII.105 Hazardous Locations United States Department of Interior. Paragraph 1910.13. Electrical Code of Federal Regulation. Title 29. Title 29. OSHA. Combustible Gas Detectors ANSI/ISA RP 12. Labor. Title 30. Bureau of Mines. Land & Production. Part 1910. ratings. control methods. It also discusses the relationship of motors and starters.400 Motor Control Centers Abstract This section assists the engineer with selecting 600 volt. enclosures. selection and customizing. 2400 volt. and 5 kV motor control centers (MCCs). Contents 410 411 412 420 421 422 423 424 430 431 432 433 440 441 442 443 444 445 450 451 452 Introduction Motor Starters—Basics Motor Control Centers—An Overview Motor Starters (Controllers) Combination Starter (Low Voltage) Manual Starter Motor Starter (Medium Voltage) Adjustable Speed Controllers Control Circuit Contactors Control Wiring Methods Control Power Sources Starting Methods for Motors Full-Voltage Starting Reduced-Voltage Starting Reduced-Inrush Starting Adjustable Speed Drives Capacitor Starting Motor Protection Low Voltage Motor Protection Medium Voltage Motor Protection 400-15 400-10 400-6 400-4 Page 400-3 Chevron Corporation 400-1 May 1996 . Data Guides (DG).400 Motor Control Centers Electrical Manual 453 454 460 461 462 463 464 470 480 481 482 490 491 492 493 494 Overvoltages Surge Arrestors NEMA Ratings Starter Ratings Low Voltage MCC NEMA Classes and Types Bus Bracing Medium Voltage MCC Enclosure Types Selecting Equipment Types and Characteristics Design Specifics Checklist References Model Specifications (MS) Standard Drawings Data Sheets (DS). and Engineering Forms (EF) Other References 400-22 400-20 400-21 400-18 May 1996 400-2 Chevron Corporation . circuit breakers.Electrical Manual 400 Motor Control Centers 410 Introduction This section is a guide for the selection of motor control centers (MCCs). however. fuses. Data Sheet ELC-DS-3977 and Data Sheet Guide Adjustable frequency drives: use Specification ELC-MS-4371. Electrically operated circuit breakers may also be used to control 460-volt motors 200 hp and larger. Data Sheet ELC-DS-597 and Data Sheet Guide MCCs for 2300 volt and 4000 volt motors: use Specification ELC-MS-3977. switches. The other type is rated for 7200 volts. “Switchgear. Low voltage MCCs are available for systems up to 600 volts and are primarily used to control 460-volt motors. 411 Motor Starters—Basics A 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. fuses or a combination 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 Overview A motor control center (MCC) groups multiple motor controllers into one enclosure and combines motor control equipment with electrical power feeders. Two types of medium voltage MCCs are available.” for information about switchgear used as motor starters. The control equipment includes starters. switches. relays. One type is rated for 4800 volts and is used to control 2300-volt and 4000-volt motors. See Section 500. To specify motor controllers. Data Sheet ELC-DS-4371 and Data Sheet Guide Chevron Corporation 400-3 May 1996 . Common types of controllers are discussed. See Figures 400-1 and 400-2. 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. contactors. metering and auxiliary devices. it is more common to use electrically operated circuit breakers to control motors above 4800 volts. Medium voltage MCCs are available for systems up to 7200 volts. and protection. The standard low voltage combination motor starter includes the following devices: May 1996 400-4 Chevron Corporation . Four types of motor starters are discussed below. and provides greater safety through mechanical interlocks.400 Motor Control Centers Electrical Manual Fig. 421 Combination Starter (Low Voltage) Combination starters are the most common starters used in low voltage MCCs. speed variation. braking. It requires less space. It can be used for speed reduction. A combination starter combines a contactor. It has several advantages over separately mounted starters and disconnects. reversing. 400-1 Low Voltage Motor Control Center Three Vertical Sections 420 Motor Starters (Controllers) A motor starter (controller) is an electric device that provides the basic functions of starting and stopping a motor. short circuit protection. less time to install and connect. and a disconnect in one enclosure. however. but can be used with motors up to approximately 10 hp. 400-2 Medium Voltage Motor Control Center • • • • 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 Starter Manual starters normally are not used. it is an on-off switch with an inherent (direct-acting) overloadprotection device. Standard manual starters cannot provide under-voltage protection. Basically. It is applied directly across full-line voltage. A manual starter has a contact mechanism (hand operated) and overload protection.Electrical Manual 400 Motor Control Centers Fig. That is. they are most commonly used with fractional-horsepower equipment. if power fails the contacts Chevron Corporation 400-5 May 1996 . solid state components produce a variable frequency AC output to provide speed variations. Stacking two-high is recommended to provide lower cost MCCs while maintaining ease of maintenance. Motor protection is discussed in Section 452.400 Motor Control Centers Electrical Manual remain closed. with solids handling systems. or with fluid flow control applications. (b) a stationary or draw-out type air or vacuum contactor. Specification ELC-MS-4371 and Data Sheet ELC-DS-4371 can be used to specify these controllers. It is the component in a controller that actually closes and opens the circuit between the energy source and the motor. and (c) overload devices. Electrical power contacts large enough to handle motor current are mounted on the armature. automatic restarting can be hazardous to personnel and/or to equipment. This method of control is used with equipment which has large turndowns between startup and final operating conditions. 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. This can be an advantage when the equipment is required to restart after power outage. 424 Adjustable Speed Controllers Adjustable frequency drives are used to provide speed control for AC motors and may be used for soft starts to minimize voltage drop. when power returns. The contactor is controlled by a relatively small flow of current through the coil of an electromagnet. the power May 1996 400-6 Chevron Corporation . In adjustable speed controllers. For some applications. A contactor combined with a thermal overload unit is called a magnetic starter. DC motors with adjustable speed controllers are used for high starting torque applications. This application should also be referred to an experienced electrical engineer or the Materials and Equipment Engineering Unit of CRTC for assistance. When proper voltage is applied to the coil. No Specification or Data Sheets are provided. Medium voltage starters are available in one. the motor will immediately restart. 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. 430 Control Circuit 431 Contactors The magnetic contactor is the primary device in all motor starters. Stacking three-high is not recommended because it makes maintenance difficult. two. or three-high enclosures (see Figure 400-2). These applications should be referred to an experienced electrical engineer or to the Materials and Equipment Engineering Unit of CRTC for assistance. Fig. and carrying high inrush currents without undergoing undue degradation from either the currents or the applied voltage.5 15 30 50 100 200 300 450 800 460/575 Volts 2 5 10 25 50 100 200 400 600 900 1. 400-3 NEMA ICS Standard Continuous Ratings for Low Voltage Starters ©NEMA. They should be specified when the starter is ordered. NEMA standards establish maximum operating conditions of six-times full load motor current (FLA) for AC motors.5 3 7. four times for DC motor reduced voltage starters. A 9 18 27 45 90 135 270 540 810 1. provide power to the motor.250 110 Volts 0. 3-PHASE HORSEPOWER AT VOLTAGE LISTED BELOW Size of Controller 00 0 1 2 3 4 5 6 7 8 9 Continuouscurrent Rating.400 2. the power contacts open. “b” contacts open when the power contacts close. and interlocking purposes. and 10 times for DC across-the-line full voltage starters. The Company does not recommend using sizes smaller than NEMA size 1. Chevron Corporation 400-7 May 1996 . display. Used with permission.600 Service-limit Current Rating. A size 1 will control small motors for a small increase in equipment cost and reduce the amount of spare parts required. These NEMA sizes correspond to motor horsepower. and 1 through 9) of low voltage (600 volt maximum) contactors for use in across-the-line full voltage controllers (see Figure 400-3). wired in series with the power circuit. NEMA standard ICS 2 lists eleven sizes (00. alarms. 0. A contactor must be capable of closing on.590 Auxiliary Contacts Starters 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. When voltage is removed from the coil. The contacts. Instead vacuum contactors or air breakers should be used. Auxiliary “a” contacts close when the power contacts close. A 11 21 32 52 104 156 311 621 932 1.215 2.75 2 3 208/230 Volts 1.Electrical Manual 400 Motor Control Centers contacts close. These auxiliary contacts are used for control. Contactors larger than NEMA size 5 are not recommended. interrupting current to the motor. relay contacts. Inc. the starter will drop out and remain de-energized until the “Start” button is depressed. 432 Control Wiring Methods Several control methods are shown on Engineering Form ELC-EF-592. 400-4 Three-Wire Control With Control-Power Transformer (CPT) (From Switchgear and Control Handbook by R. 1987. Fig. level switches. Used by permission from McGraw Hill. As the term implies. Operation of the thermal units causes the overload contacts in the control circuit to open. pushbuttons. the equipment will restart following a power outage. is called the control circuit. The “Start” button is connected parallel with the seal-in contact.e.. level switches or selector switches. It opens when excessive (overload) current is sensed by the thermal units in the power circuit. This arrangement is generally referred to as “maintained contact” (i. The device is connected in series with the contactor coil of the starter. This in turn causes the power contacts to open. these devices require the use of two wires between the control unit and the starter. Control Circuit Devices Control-circuit devices (e. pressure switches. See Figure 400-4..400 Motor Control Centers Electrical Manual Thermal Overload The portion of the wiring that includes the coil of the starter (or contactor) and overload contacts. limit switches. The basic methods of motor control are discussed below. Smeaton. Three-Wire Control (Start-Stop Station) “Start-Stop” pushbutton stations require the use of three wires between the control station and the starter.g. and PLC contacts) can be wired into the control circuit. removing voltage from the coil.) Two-Wire Control Two-wire control is generally used for pilot devices such as thermostats.) May 1996 400-8 Chevron Corporation . In the event of a power failure. This type of control is used for critical pumps. Two-wire control is not recommended for applications where automatic restarting (after a power outage) of equipment can be hazardous to personnel and/or detrimental to equipment. 400-5 Common Control (Not Recommended) (From Switchgear and Control Handbook by R. Fig. but it is not recommended above 120 volts. which can be safely restarted to maintain system integrity. The disadvantage of this method is that space heaters powered from the CPT will not be energized when the starter breaker is opened. See Figure 400-5. Common Control When the control and power circuits are powered from a single common source. Inc. 1987. 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). See Figure 400-4. Smeaton. This method may be used up to 480 volts. Run-Off-Auto or Hand-Off-Auto switches are modified versions of the two-wire control. only the affected motor shuts down when there is a CPT failure since each motor has its own CPT. refrigeration compressors or cooling fans. Also.) Chevron Corporation 400-9 May 1996 . it is called common control. The CPT should be fused to protect the control circuit and the starter against damage from short circuits in the control devices. Used by permission from McGraw Hill.Electrical Manual 400 Motor Control Centers The opening or closing of two wire pilot devices directly de-energizes or energizes the starter. Examples of applications where automatic restart could be considered undesirable are drill presses and conveyors. 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. The control voltage is the same as the power voltage. 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.” for a discussion of voltage drop during motor starting and how it affects motor torque. The source of power usually is not disconnected when the starter breaker is opened unless a circuit breaker auxiliary contact (normally open) is used. 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. Fig. This can affect other equipment supplied by the same utilization system. 441 Full-Voltage Starting Most AC motors are started by connecting them directly across the supply lines. “System Studies and Protection. it is. In a closed-circuit transition.400 Motor Control Centers Electrical Manual Separate Control A method of avoiding high voltages in the control circuit is to power the control circuit from a remote low voltage source. is not recommended for safety reasons. 400-6 Separate Control (From Switchgear and Control Handbook by R. See Figure 400-6. See Section 200. In an open-circuit transition. 442 Reduced-Voltage Starting Occasionally. Inc.) 440 Starting Methods for Motors A comparison of starting currents and torques produced by various types of reduced voltage starters is shown in Figures 400-7 and 400-8. Smeaton. This method. power to the motor is not interrupted during the starting sequence. though less expensive than the integral control power transformer scheme. Reduced voltage starting or “soft-starting” is used to start motors without causing unacceptable voltage drop. This is referred to as “full voltage” or “across the line starting. See Figures 400-7 and 400-8 for the effect on motor torque.” However. Closed-circuit transition mini- May 1996 400-10 Chevron Corporation . 1987. Used by permission from McGraw Hill. parallel stator windings to the line in two or more steps. Ratio of starting torque to starting kVA is highest with this type of starting. Actual values will vary with the motor design and application. Torque per kVA is lower than with auto-transformer starting. Addition of switches in the autotransformer interconnection provides closed transition in transfer to full voltage. When wye connected. (2) torque increments are required in starting. Provides closed transition by use of a small resistor inserted during transfer. Synchronizer) Starting Characteristics In Percent Of Rated Starting Values Motor Terminal Voltage Motor Current 100 Line Current 100 Torque Per kVA 100 Chevron Corporation 400-11 May 1996 Electrical Manual Torque 100 1 FULL VOLTAGE STARTING Full voltage starting gives the highest starting torque efficiency . closed transition.that is. more than two resistance steps may be used. 400-7 Types of Motor Starting (Courtesy Electric Machinery. Full voltage starting should always be used unless (1) power system disturbance makes reduced current inrush necessary. Reduced inrush. resultant starting torque and reduced inrush possibilities may meet the requirement of the load and system at least possible expense. If the motor can be designed for part-winding starting. For increment starting. 100 2 PART-WINDING STARTING 100 100 70 50(1) HIGH SPEED 70 LOW SPEED 55 50(1) 50 72 90 3 REACTOR OR RESISTOR STARTING 80 65 50 80 65 50 100 80 65 50 80 65 50 33 80 65 50 64 42 25 33 64 42 25 64 42 25 33 80 65 50 100 100 100 100 4 AUTO-TRANSFORMER STARTING (Closed transition) 400 Motor Control Centers 5 WYE-DELTA STARTING (Closed transition) (1) These values are for 2-step part-winding starting and are approximate. Reduced inrush by using an auto-transformer to reduce voltage to the motor. winding voltage is 58% rated. .Fig. the highest torque per starting kVA. starting by inserting impedance (reactor) or resistance (resistors) in the circuit during motor starting. Reduced inrush. closed transition starting by connecting the sectionalized. This type of starting requires no auxiliary current reducing device and uses simple switching. Reduced inrush by switching the windings on a motor designed for wye-delta connection. 400 Motor Control Centers Electrical Manual Fig. 400-8 Starting Methods (1 of 2) (Courtesy Electric Machinery. Synchronizer) May 1996 400-12 Chevron Corporation . 400-8 Starting Methods (2 of 2) (Courtesy Electric Machinery.Electrical Manual 400 Motor Control Centers Fig. Synchronizer) Chevron Corporation 400-13 May 1996 . With an auto-transformer. Thus a high value of torque is produced per unit of starting current. Inrush current is limited by the resistors. Primary Reactor The primary reactor method of reduced-voltage motor starting is similar to resistor starting. except transformer losses. is transmitted to the motor. 50%.g. Resistance value is reduced in one or more steps until full voltage is applied to the terminals. 65%. but separate reactors are necessary for each step since a portion of a reactor cannot be short-circuited as with a resistor. 443 Reduced-Inrush Starting There are two principal methods of minimizing the initial inrush of starting current to a motor without reducing voltage. if the initial voltage is reduced to 50%. • Wye-Delta May 1996 400-14 Chevron Corporation . and it is generally the least expensive of the techniques for reducing starting currents. Motor current is reduced in direct proportion to the voltage applied at the motor terminals. and therefore is not suitable for motors which drive equipment demanding high torques during acceleration. therefore. A disadvantage is that they are generally the most expensive reduced-voltage starting method. The line current is reduced in proportion to the square of the motor-terminal voltage because of the auto-transformer action.. Starting torque is a function of the square of the applied voltage. It uses only part of the motor winding on starting. adjustments of torque and inrush current can easily be made in the field by selecting a different voltage tap (e. These methods require special motor configurations as well as special starters. • Part-Winding The part-winding method is attractive due to its simplicity. Methods of Reduced-Voltage Starting Auto-Transformer The auto-transformer starter is usually provided with two or more taps. the starting torque of the motor will be 25% of its full-voltage starting torque.400 Motor Control Centers Electrical Manual mizes inrush voltage disturbances and is recommended for all applications of reduced-voltage starting. Starting characteristics can be adjusted by tap selection. All power taken from the line. A compromise must be made between the required starting torque and the inrush current. Auto-transformer starters are the most widely used reduced-voltage starters because of their high efficiency and flexibility. Primary Resistor The primary resistor method of reduced-voltage motor starting provides series resistors in each phase of the motor primary circuit. or 80%). The following methods and devices for motor protection are recommended. As the motor speed (frequency) increases. used for motor starters for many years.Electrical Manual 400 Motor Control Centers In general. thereby reducing inrush currents and also torques. The delta wound motor is started with the windings connected in a wye and then switched to run with the windings connected in a delta. They provide reactive (magnetizing) current to the motor during starting. These solid state motor controllers increase voltage to induction motors during starting. However. 444 Adjustable Speed Drives Adjustable frequency drives produce a soft start. the voltage level is increased. 451 Low Voltage Motor Protection Disconnect Rating The minimum required rating of the breaker or fused disconnect is determined by the MCC short-circuit rating. as well as speed control by starting the motor at low speed and increasing until full running speed is reached. wye-delta starters cost less than auto-transformers or primary-resistor starters. They typically control the volts/hertz ratio. thereby reducing the voltage drop on the power system. Short Circuit Protection Short circuit protection and a means to disconnect the motor from its source are provided by a circuit breaker or a fused disconnect switch. 445 Capacitor Starting Motor starting shunt capacitors are switched on with the motor. “Protective Devices” for more details of motor protection. they are more expensive for some ratings. 450 Motor Protection See Section 600. Starting torque is only one-third of that at rated voltage. The capacitor is switched off when the motor is up to speed. Molded-Case Circuit Breakers Molded-case circuit breakers with thermal magnetic trip elements. Chevron Corporation 400-15 May 1996 . The short-circuit rating can usually be found on the one-line diagram or in the system study. are gradually being replaced by motor circuit protectors (see below). such as blocked filters on WPII motors and water shutoff on TEWAC motors. relays or other protection devices listed below should also be used in both methods. Overload Protection Motor overload protection is provided by thermal overloads which interrupt the control circuit and cause the contactor to open. provided fault current is less than contactor interrupting capacity. 452 Medium Voltage Motor Protection Two methods are used to control medium voltage motors: current-limiting starters and switchgear-type circuit breakers. Relays Recommended for 500 HP and Above (suggested breakpoint): Thermal Overload Relay. Bimetallic Instantaneous Ground Fault Relays (50G). Solid state relay devices for medium voltage motors are available and may be used instead of the individual devices listed below. Fused Disconnect Switch A fused disconnect switch provides short circuit protection and a means of disconnect.000 amperes. This feature allows for faster tripping and offers better protection than molded-case circuit breakers. See Figure 400-4. It is used as an inexpensive method for providing short circuit protection. Bearing RTDs should be applied to critical motors consistent with the driven equipment protection. Under 500 HP (suggested breakpoint): Thermal Overloads Ambient Compensated. A current-limiting attachment (attached to the load side of the MCP) can be used to provide an interrupting rating up to 100. The current-limiter is coordinated with the MCP so that short circuits will be cleared by the MCP. Replica Type (49) May 1996 400-16 Chevron Corporation . Although current-limiting fuses provide short circuit protection for current-limiting starters. These should be used only on low resistance grounded systems. The type of service and whether or not the motor is spared should be considered when evaluating relay application. but has the disadvantage of not being resettable (damaged fuses must be replaced).400 Motor Control Centers Electrical Manual Motor Circuit Protectors Motor Circuit Protectors (MCPs) are magnetic trip-only circuit breakers available in size graduations that match starter and motor sizes. The extent of motor protection should be consistent with the protection philosophy of the driven equipment. They provide protection against fault currents and feature an adjustment for setting the minimum trip value. Only high fault currents will cause the current limiter to function. Winding RTDs should be installed in critical motors and motors subject to “threatening” situations. and the rest is passed through to the motor winding. see Chapter 4 of IEEE Standard 141 (Red Book. Bearing RTD relay (38) Winding RTD relay (49) Additional Relays Recommended for 1500 HP and Above (suggested breakpoint): Differential Current Relay (87) Additional Relays Recommended for Synchronous Motors: Incomplete Sequence (48) Power Factor (55) for Pullout Protection 453 Overvoltages For a detailed discussion of overvoltages.Electrical Manual 400 Motor Control Centers Time Overcurrent (Locked Rotor) (51) Phase-Balance and Single-Phase (46) Lockout. For surge protection. Leads to the motor should be kept as short as possible. with external reset (86) Instantaneous Ground Fault Relays (50G). 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. 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. A portion of the surge is reflected along the incoming conductor back toward the source. These should only be used on low resistance grounded systems provided fault current is less than contactor interrupting capacity. This effect is most severe when the motor surge impedance is much larger than that of the incoming conductor. surge capacitors (connected from each phase to ground at the incoming motor cable terminals) are recommended. This refracted voltage can approach twice the incoming voltage level (already very high in the surge) for motors with high surge impedance.) A number of disturbances can occur in the distribution system supplying power to an MCC and its motors. Chevron Corporation 400-17 May 1996 . 454 Surge Arrestors Machines connected to circuits which are exposed to lightning require surge arrestors to limit the peak of the voltage surge. NEMA Classes Class I: Class I MCCs consist of a mechanical grouping of combination motor starters. speed. Specifics regarding performance of MOSAs are given in Table 19 of IEEE 141 (Red Book). arranged in an assembly with only power connections furnished. These data are available from the nameplate of the motor or from certified drawings provided by the manufacturer. Until recently. Recommended values are as follows: • • • 1. Diagrams of only the individual units are supplied. Details on NEMA classes are presented below. Type B is recommended for most applications. Final selection of a motor starter should be based on specific motor data. These classes pertain to factory-provided interwiring or interlocking and define where field terminations are made on the MCC. Station arrestors designed for rotating machines are available in ratings of 3 to 27 kV. only the current necessary to limit the overvoltage is conducted. They do not include interwiring or interlocking between units and remotely mounted devices. unless they are supplied by uninsulated overhead lines. there is positive clearing after the surge has passed.25 microfarad for motors above 6. Class I is generally May 1996 400-18 Chevron Corporation . It provides typical full-load current based on horsepower. surge arrestors were constructed with nonlinear resistors made of bonded silicon carbide. However.9 kV motors 0. 460 NEMA Ratings 461 Starter Ratings Figure 400-3 lists NEMA ICS standard continuous ratings for low voltage starters and can be used for preliminary size selection of a motor starter. Therefore.5 microfarad for 2. and voltage. Class II. The MOSA draws only a few milliamperes of line current at normal system voltage.400 Motor Control Centers Electrical Manual Surge capacitors of the proper value will reduce the rate of rise of an incoming wave to a tolerable value.0 microfarad for low voltage motors (600 volts and below) 0. feeders. 462 Low Voltage MCC NEMA Classes and Types There are two MCC NEMA classes: Class I and Class II. Nor do they include control-system engineering.9 kV Surge capacitors generally are not used on motors of 460 volts and below.3-6. During a surge. and/or other units. a new type of arrestor has become the industry standard: the metal-oxide surge arrestor (MOSA). feeders. field terminations are made directly to the unit components. Buses rated 65 kA and 100 kA symmetrical are also available. unit-mounted control terminal blocks are supplied. They include the necessary electrical interlocking and interwiring between units and interlocking provisions for remotely mounted devices. in addition to the power connections. 464 Medium Voltage MCC Medium voltage starters are labeled NEMA Class EI if the contacts are used for interrupting short circuit current. ICS 2. or H5. NEMA Types Type A: Applicable to Class I only. and 42 kA rms symmetrical. For more detail refer to NEMA Publication No. 463 Bus Bracing Buses must be braced to withstand the maximum of short-circuit currents available. H3. 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. interlocking. Load terminals are not supplied for feeder units. No terminal blocks are supplied on the units for load or control connections. corresponding to specific continuous current ratings and interrupting ratings. Wiring between combination controllers. 14 kA. and are labeled NEMA Class EII if fuses are used for interrupting short circuit currents. and the master terminal boards is provided. Type B: Applicable to both Class I and II. Unit load terminal blocks are provided for size 3 and smaller starters. or interconnecting. NEMA standards for bracing are based on ratings of 10 kA. or control assemblies. Chevron Corporation 400-19 May 1996 . 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. Type C: Applicable to both Class I and II. H4. Class II: Class II MCCs consist of a grouping of combination motor controllers.Electrical Manual 400 Motor Control Centers specified for independently operated motors requiring no interlocking or other interconnection between units. Type C MCCs are similar to Type B MCCs with the addition of the master-section terminal boards. Type B is recommended for most applications. The size of the contactor has a NEMA designation of H2. 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. and/or other units designed to form a complete control system and are recommended for most applications. 30 kA. • 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.” for more information. The two types of explosionproof enclosures are screwed-cover and ground joint bolted-cover. If weather protection is needed in a classified area. is useful for specifying explosionproof starters. They provide some protection against dust and falling dirt. “Hazardous (Classified) Areas.400 Motor Control Centers Electrical Manual 470 Enclosure Types NEMA Standards 250-295 and ICS 6-1983 describe enclosures according to their environmental capabilities. starters housed in explosionproof enclosures suitable for the specific area must be used (Type 7 for Class I and Type 9 for Class II).” In such instances.” ELC-DS-597. and sleet. The recommended enclosure for outdoor use is Type 3R. May 1996 400-20 Chevron Corporation . as well as against external ice formation. • Type 7 and 9 If it is necessary to locate motor starters in classified areas. a NEMA 7 or 9 UL listed enclosure with NEMA 4 features should be specified. They also offer limited protection against light splashing and indirect splashing. For most indoor applications. “Hazardous (Classified) Areas. “Hazardous (Classified) Areas. NEMA Type 4 enclosures can be used either in indoor or outdoor locations. See Section 300. Type 1A (with neoprene gasketing) is recommended. plus operation of external mechanisms when ice laden. • 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. Their primary purpose is to prevent accidental contact with the enclosed equipment by personnel. Motor Control Rack Specification and Arrangement. See Section 300. but. • Type 4 and 4X (Indoor and Outdoor) Type 4 and 4X enclosures provide protection against dripping or splashing water and are dust-tight. rain. Type 4X and Type 7 are used for certain applications. NEMA Type 4X enclosures are corrosion resistant. refer to Section 300. but are not dust-tight. Explosionproof equipment is listed by the Class and Group appropriate for the location in which the ignitable material may be present. – Type 3S (Outdoor) Type 3S enclosures provide the protection of Type 3 and 3R enclosures. 482 Checklist The following checklist should be reviewed before completing the MCC design and issuing the one-line diagram. 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? Chevron Corporation 400-21 May 1996 . 4. frame and trip rating. 3. and 4000-volt motors will be supplied at 4160 volts. • • • Is each load supplied by the correct voltage? 460-volt motors will be supplied at 480 volts. 2. 5. Specify whether available space requires front-only or back-to-back arrangement. and short-circuit current rating MCC Layout The equipment arrangement for an MCC layout is often left for the vendor. or fused-switch rating and fuse size Voltage. 6. number of wires. number of phases. frequency. Locate units in specific vertical sections. bus continuous-current rating.Electrical Manual 400 Motor Control Centers 480 Selecting Equipment Types and Characteristics 481 Design Specifics The designer should first develop an MCC one-line diagram using standard symbols and presentation according to Section 100. Specify the location and size of the incoming line compartment. but the designer should do the following: 1.” The one-line diagram should include the following data: • • • • • Motor horsepower Starter type Starter size Circuit-breaker type. Locate units controlling similar or associated process functions adjacent to one another if possible. Specify the wireway location after determining whether most circuits enter or leave via the top or bottom. “System Design. Specify that larger units be installed at the bottom of vertical sections (for ease of handling). stopped.400 Motor Control Centers Electrical Manual • Can each motor be started. elevation above sea level. and otherwise controlled as required? (If a reactor has been used to limit short-circuit currents.) 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. Data Guides (DG). 493 Data Sheets (DS). motor starting calculations will have to be reviewed. indoor or outdoor location. and Engineering Forms (EF) * ELC-DS-366 * ELC-DG-366 * ELC-DS-597 * ELC-DG-597 * ELC-DS-3977 Motor Control Center Specification and Arrangement Data Sheet Guide for Motor Control Center Specification and Arrangement Motor Control Rack Specification and Arrangement Data Sheet Guide for Motor Control Rack Medium Voltage Current-limiting Fused Motor Starters Data Sheet May 1996 400-22 Chevron Corporation . corrosive substances. Those with an asterisk (*) are included in this manual or are available in other manuals. relative humidity. such as ambient temperature range. 491 Model Specifications (MS) * ELC-MS-3977 * ELC-MS-4371 ELC-MS-5008 Medium Voltage Current-limiting Fused Motor Starters Adjustable Frequency Drives Medium Voltage Adjustable Speed Drives 492 Standard Drawings This guideline has no Standard Drawings. relays and control power transformers been specified according to the control diagrams? • • • • • • • 490 References The following references are readily available. and area classification Have the control devices. ANSI/IEEE Standard 100. ANSI/NFPA. ANSI/NEMA ICS2. ANSI/IEEE C37. IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems. ANSI/NEMA ICS2. Relay-Instrument Division. Enclosures for Electrical Equipment (1000 Volts Maximum). Electrical Power System Device Function Numbers. National Electrical Code 70. Chevron Corporation 400-23 May 1996 .2. ANSI/UL 347. Westinghouse Electric Corporation. NEMA Standard 250. API RP 14F. ANSI/NEMA ICS6. Design and Installation of Electrical Systems for Offshore Production Platforms. Controllers and Assemblies. Part 2-322. Part 2-324. IEEE Recommended Practice for Electric Power Distribution for Industrial Plants. 50 Hz and 60 Hz. ANSI/IEEE Standard 242. IEEE Standard Dictionary of Electrical and Electronics Terms. High Voltage Industrial Control Equipment.Electrical Manual 400 Motor Control Centers * ELC-DG-3977 * ELC-DS-4371 * ELC-DG-4371 * ELC-EF-592 Data Sheet Guide for Medium Voltage Current Limiting Fused Motor Starter Data Sheets Adjustable Frequency Drive Data Sheet Data Sheet Guide for Adjustable Frequency Drive Data Sheet Wiring Diagram for Motor and Contactor Installation 494 Other References ANSI/IEEE Standard 141. Standards for Industrial Control Devices. Applied Protective Relaying. AC General-Purpose Medium-Voltage Contactors and Class E Controllers. Enclosures for Industrial Controls and Systems. 500 Switchgear Abstract This section discusses switchgear assemblies and their application in an industrial facility. “Protective Devices. fuses. Outdoor Ratings Control Power Accessory Equipment and Space Heaters Type of Assembly Materials Application Steps Incoming and Outgoing Cables Labels.” Contents 510 511 512 520 521 522 523 524 525 526 527 530 531 540 550 560 561 570 571 572 Introduction Scope Switchgear—An Overview Application Procedure General Considerations Indoor vs. Markings and Listings Materials to be Supplied Glossary of Terms Acronyms References Model Specifications (MS) Standard Drawings 500-12 500-10 500-11 500-11 500-9 500-4 Page 500-3 Chevron Corporation 500-1 May 1996 . Specific steps in the design process are identified. This section also aids in selecting switchgear for distribution and application of power up to 15 kV nominal. Circuit breakers. and relays are discussed in Section 600. including the use of standard forms and major selection factors. 500 Switchgear Electrical Manual 573 574 Data Sheets (DS). Data Guides (DG). and Engineering Forms (EF) Other References May 1996 500-2 Chevron Corporation . industrial-type with withdrawable power circuit breakers.” Switchgear is used throughout the electric power system of an industrial facility for incoming line service. which are the principal devices used in opening and closing (“switching”) power circuits. When used in conjunction with the documents listed below. and for distributing power to load centers. and ordering of switchgear. A comprehensive description and discussion of circuit breakers can be found in Section 600. Specifications ELC-MS-3908 ELC-MS-3987 Medium Voltage Metal-Clad Switchgear Low Voltage Draw-out Circuit Breaker Switchgear Data Sheets ELC-DS-3908 and ELC-DS-3987 Data Sheet Guides ELC-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. accessories. motors. Switchgear assemblies consist of one or more pieces of equipment in addition to main bus conductors. protective and regulating equipment. Chevron Corporation 500-3 May 1996 . and other secondary distribution equipment.Electrical Manual 500 Switchgear 510 Introduction 511 Scope This section of the Electrical Manual presents an overview of switchgear assemblies. Lighter duty “molded-case” or “insulatedcase” circuit breakers are not included. The switchgear described in this section are the heavy-duty. and enclosures. metering. “Protective Devices. specification. Switchgear may be used either alone or in combination with control. motor control centers. the word “switchgear” applies to both the items of which a switchgear assembly consists and the assembly itself. instrumentation. interconnecting wiring. transformers. and are typically not recommended for industrial applications. this section will assist in the selection. panelboards. and includes a variety of switching and interrupting devices. supporting structures. Major switchgear assemblies for Company facilities are generally located indoors. Outdoor switchgear assemblies can be either walk-in (with an enclosed maintenance aisle) or non-walk-in (aisle-less). The primary switching components are generally circuit breakers. In actual usage. May 1996 500-4 Chevron Corporation . Where considerable interwiring is necessary.500 Switchgear Electrical Manual 520 Application Procedure 521 General Considerations By using an Application Table such as Figure 500-1.083 sec) after a fault occurs. Outdoor Indoor locations are preferred for easier maintenance and protection from weather related problems. Recommended paint is ANSI 70 light gray enamel or lacquer. lighting transformers. (See Figure 500-2. Light-colored nonmetallic paints will minimize the effect of solar energy loading and avoid derating the equipment in outdoor locations.( rated short circuit current ) = --------. its three phase and line-to-line fault rating would be: E 15.6 kiloamperes is its current interrupting rating at a time of 5 cycles (0. and other panels. Technical application is not the only criterion. moisture.8 kiloamperes symmetrical (Eq.8 = 19. Cost must be considered as well as the need for compatibility between existing and new components and equipment.” 1/2 cycle (0.0 -------. 522 Indoor vs. the applications or design engineer can select switchgear of adequate rating for the operating requirements. and/or MCCs.( 18 ) KV 13.) These are prefabricated units containing switchgear. For some plant layouts it may be necessary to use an outdoor enclosed switchgear assembly. the applications or design engineer then selects the most appropriate standardized switchgear cubicle layouts. wind.8 kV. After determining the functional needs as well as physical layout and environmental conditions.0083 second). For example. Outdoor enclosures should be specified to have front aisles (as a minimum) for ease of maintenance and protection from weather. “power houses” are often used. In outdoor applications. Plant layout logistics should be considered to optimize feeder and bus duct lengths. The manufacturer provides the units either completely assembled or in modules. or 37 kiloamperes asymmetrical. Ancillary equipment such as space heaters are also included. ANSI/IEEE C37. and local ambient temperatures should be considered in determining the suitability and capacity of the switchgear. both are ready for external connections. if 500 MVA Class switchgear is selected (Figure 500-1) for an application at 13. The circuit breaker and switchgear assembly rating for “momentary. area classification. 500-1) 19. current is given in the last column of Figure 500-1. Tables are also available for selection of current potential and control-power transformers.24-197 is the primary reference for solar loading in switchgear. factors such as sun. 500-1 Typical Application Table for Circuit Breakers (Courtesy of Cutler-Hammer) Chevron Corporation 500-5 May 1996 .Electrical Manual 500 Switchgear Fig. 500 Switchgear Electrical Manual Fig. 500-2 Power House May 1996 500-6 Chevron Corporation . The two primary uses of control power in switchgear are to provide tripping power and closing power.20. (However. Batteries (DC) can be a source of both tripping power and closing power. The requirements for power to close are less rigid.Electrical Manual 500 Switchgear 523 Ratings Switchgear has two current ratings. There are voltage ratings and other current ratings associated with switchgear assemblies and current breakers. short-circuit and continuous.2. the source of control power to trip the breaker must always be available. and C37. to optimize battery capacity.05-0. C37. Because an essential function of switchgear is to provide instantaneous and unfailing protection in emergencies. Since low voltage switchgear circuit breakers operate to interrupt a circuit very quickly. Commonly. the circuit breakers and switchgear assemblies have interrupting ratings and mechanical bus-bracing ratings that correspond with the one-cycle short-circuit current.20. We use electrically-operated (a solenoid is used to operate the springoperated 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.) Battery ampere-hour and inrush requirements have been reduced by the use of stored-energy spring-mechanism closing of power circuit breakers through Chevron Corporation 500-7 May 1996 . These are described in ANSI C37. The continuous current rating of switchgear assemblies and circuit breakers corresponds to the highest current which can be carried without exceeding temperatures that can be harmful to insulating materials and/or equipment. This is the mechanical withstand rating of the switchgear assembly. medium voltage circuit breakers are electrically operated for both closing and tripping. usually during the first cycle (0. 524 Control Power Successful operation of switchgear is dependent on a reliable source of control power. the circuit breaker will not be subject to full short-circuit contributions from the motor and/or generator. an AC source for closing power is recommended.08 seconds) after the interaction of a fault and is the magnitude of current which the circuit breaker contacts must successfully interrupt. Subsequently.3 for switchgear assemblies. Medium voltage switchgear has a short-circuit rating called its interrupting rating. ANSI C37.1. usually in the order of 3 to 5 cycles (0.08 seconds).016 second). In contrast.16 for medium and high voltage current breakers. This is the magnitude of current existing three to five cycles (0.20.016 second) of a short circuit. Medium voltage circuit breakers and switchgear assemblies have a “close-and-latch” or “momentary” rating corresponding to the highest current the equipment will experience during the first cycle (0. The short-circuit current ratings depend on whether the switchgear is low voltage (600 volts or less) or medium voltage (greater than 600 volts). The short-circuit current contributions from motors decay during this interval.05 to 0.06 for low voltage current breakers. and ANSI C37. medium voltage switchgear circuit breakers are larger and take longer to interrupt a circuit. In most installations.500 Switchgear Electrical Manual 34. 525 Accessory Equipment and Space Heaters Accessory equipment such as instrument transformers. AC general distribution systems cannot be relied upon for tripping power. because outages are possible. the space heaters should be on all of the time (manual operation). it is better to have thermostatically controlled space heaters.5 kV. a switch must be provided to turn off the heater when work is being performed inside the cubicle. to charge a set of batteries.) DC tripping power is recommended. Space heaters can be manually or thermostatically controlled. They are also recommended on indoor switchgear to keep the temperature above the dew point inside the enclosure during shutdown conditions. If the space heater is thermostatically controlled. voltmeters. it is recommended that the tripping power be obtained by rectifying the output from a control-power transformer. May 1996 500-8 Chevron Corporation . Outages could potentially occur during those times when the switchgear is required to perform its protective functions. 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. Alarming for abnormal operating conditions of the tripping source is recommended. The most elaborate protective relaying system is useless if tripping power is not available to open the circuit breaker when required. An ammeter should be installed in each main heater circuit so the operator can determine if the space heaters are operating properly. If the climate is always humid or damp. particularly where the ambient temperature becomes warm in the summer. ammeters. watthour meters can be located in almost any compartment of metal-clad or metalenclosed switchgear. Space heaters should be placed in each breaker or auxiliary compartment as well as in each cable area. a bypass switch is required for manual operation and an operating temperature must also be specified. (This application is not recommended. Furthermore. If the heater is manually operated. The importance of periodic maintenance and testing of the tripping power source cannot be overemphasized. Space heaters are supplied as a standard feature in outdoor metal-enclosed switchgear to eliminate condensation on surfaces and insulation. which provide the primary source of tripping power. Metal-clad switchgear is available for voltages from 2. • • • • • All buses should be copper. and hinges should be of corrosion-resistant material.g. and special features of switchgear devices to distribute power to points of application. affording optimum structural integrity and considerable personnel protection. synchronizing. styles. and required operating procedures. 527 Materials In the manufacturing of certain parts for switchgear assemblies. initial cost. as radial. This can be accomplished by either specifying a low-watt density heater. sectionalized. or sizing the heater to operate at half normal voltage. “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. Most bus arrangements. Exposed handles. In the process it is necessary to: Chevron Corporation 500-9 May 1996 . screws. In both instances. Recommendations are as follows. For heaters operating at half voltage.. ratings. Bus bars for 5 kV bus systems should be insulated with thermoplastic sleevings and held in place by high-strength molded polyester glass insulators. and ring) are available to achieve the desired system reliability and flexibility. several different materials and finishes can be used.” and Section 200. (e. Bolted bus connections (plated connections are recommended) should be of silver or tin plate. assembly elements are completely enclosed by sheet metal. circuit breaker and a half. installation cost. double.Electrical Manual 500 Switchgear To help ensure longevity. “System Design. space heaters should be sized for low surface temperatures. 15 kV bus insulation should be high-alumina (high strength) porcelain. 526 Type of Assembly Low voltage.4 kV through 15 kV. metal-enclosed switchgear is available for applications at 600 volts and below. 530 Application Steps Engineering the system according to Section 100. those rated at four-times the watts actually required in the compartment must be installed. transfer. main. Selections should be based on total electrical system requirements. and listings to identify equipment that complies with applicable standards. however. 531 Incoming and Outgoing Cables All cables. 540 Labels. However. is an May 1996 500-10 Chevron Corporation . Factory Mutual (FM) and Canadian Standards Association (CSA) are usually accepted to most as inspection organizations. Medium voltage switchgear. These items should not be used unless approval is obtained from the local electrical inspector. marked. ELC-DG-3908 and ELC-DG3987. Markings and Listings Local inspectors rely heavily on labels. ELC-DS-3908 and ELC-DS-3987 should be completed using their respective Data Sheet Guides. it is easy to obtain a UL label for switchgear rated at or below 600 volts. or labeled because the manufacturers have chosen not to spend the time and money required to obtain UL approval of these items. 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. relaying. markings. (incoming and outgoing) usually enter/exit at the bottom of switchgear. Items of control apparatus are manufactured to specific standards but may not be listed. Special terminations are used for shielded conductors and sufficient space must be provided to make these terminations (stress cores). The standard specifications in this section should be used to specify switchgear. (UL). specific design considerations may make it advantageous to enter from the top. Inc. The most common label is from Underwriters’ Laboratories. and control power transformer ratings Select closing and tripping voltage and power Consider special requirements The appropriate Data Sheets.500 Switchgear Electrical Manual • • • • • • • • 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. and locations Select metering. connections (wye or open-delta). However. Switchgear and certain items of control apparatus should have an attached label indicating UL recognition. Equipment recognized by UL carries either a UL mark or is listed in a UL publication as a recognized component. In general. Manufacturers 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. metering. protective. Switchgear: Switching and interrupting devices alone or in combination with associated control. accessories. to be supplied by the manufacturer. all housed within a grounded metal enclosure. type. supporting structures. Ventilating openings and inspection windows may be present. circuit breakers Relay and power-fuse time-current curves and application information Complete spare parts lists. Power Switchgear Assembly: One or more of the devices mentioned in the definition of switchgear. 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. 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. interconnections. and any enclosures. Metal-Enclosed Switchgear Assembly: Switchgear enclosed on the top and all sides by sheet metal on a supporting structure. rating. Metal-Enclosed Bus: An assembly of rigid electrical buses with associated connections. joints. Chevron Corporation 500-11 May 1996 . and insulating supports. Lists of priced spare parts that the manufacturer recommends be available for startup and the first year’s operation. including conductors.3. 550 Materials to be Supplied Specification ELC-EG-3908 requires all engineering data for equipment.Electrical Manual 500 Switchgear engineered item with very few standard configurations and is difficult to have ULlabeled unless done by a third-party examination service. as specified and ordered. and regulating equipment. 560 Glossary of Terms Metal-Clad Switchgear: Metal-enclosed switchgear that has specific features enumerated in Section 9. and manufacturer’s catalog number of all equipment in each unit Catalog data for relays. switches.4 of ANSI/IEEE Standard 141. 20. Inc. 570 References The following references are readily available.3. Metal-Enclosed Interrupter Switchgear (Above 1000 V). 573 Data Sheets (DS).20. and Engineering Forms (EF) * ELC-DS-3908 * ELC-DG-3908 * ELC-DS-3987 * ELC-DG-3987 Medium Voltage Switchgear Data Sheet Data Sheet Guide for Medium Voltage Switchgear Data Sheet Low Voltage Switchgear Data Sheet Data Sheet Guide for Low Voltage Switchgear Data Sheet 574 Other References ANSI/IEEE Standard 141.2.1. Metal-Enclosed Low-Voltage Power Circuit Breakers. May 1996 500-12 Chevron Corporation . ANSI/IEEE C37. The ones which are marked with an asterisk (*) are included in this manual or are available in other manuals. Low Voltage (600 V maximum) Drawout Circuit Breaker Switchgear 572 Standard Drawings There are no standard drawings in this guideline. IEEE Standard Dictionary of Electrical and Electronics Terms. ANSI/IEEE C37.500 Switchgear Electrical Manual 561 Acronyms CSA NEMA NFPA UL Canadian Standards Association National Electrical Manufacturers Association National Fire Protection Association Underwriters’ Laboratories. Metal-Clad and Station-Type Cubicle Switchgear (Above 1000 V). ANSI/IEEE Standard 100. ANSI/IEEE C37. 571 Model Specifications (MS) * ELC-MS-3908 * ELC-MS-3987 Medium Voltage 5 kV and 15 kV Metal-clad Switchgear. IEEE Recommended Practice for Electric Power Distribution for Industrial Plants.20. Data Guides (DG). Metal-Enclosed Bus and Guide for Calculating Losses in Isolated Phase Bus. NY: McGraw-Hill. NY: McGraw-Hill. Standard Handbook for Electrical Engineers. ANSI/IEEE C37.23. Chevron Corporation 500-13 May 1996 . Beeman.Electrical Manual 500 Switchgear ANSI/IEEE C37.24. Fink and Carroll. 1968. 1955. Industrial Power Systems Handbook. Guide for Evaluating the Effect of Solar Radiation on Outdoor Metal-Clad Switchgear. overload and short circuit. Circuit breakers and fuses are described with typical numerical values. specifically relays for large motors. It discusses system protective devices (most importantly circuit breakers and fuses) and the operation of the principal components of any protective scheme. Contents 610 611 612 620 621 622 623 630 631 632 633 634 635 636 640 641 642 643 644 Introduction Protective Devices—An Overview Characteristics of Protective Devices Circuit Breakers Power Circuit Breaker Molded-Case Circuit Breakers Current Limiting Circuit Breakers Relays and Protective Device Coordination Zones of Protection Instrument Transformers Basic Considerations for Overcurrent Relaying and Coordination Ground Fault Relaying and Coordination Other Common Types of Relay Protection Electrical Component Protection and NEC Requirements Fuses Advantages and Disadvantages of Fuses Design Features Time-Current Curves Miscellaneous Considerations 600-57 600-8 600-5 Page 600-3 Chevron Corporation 600-1 November 1991 . The section also discusses indirect protective control. and the risk posed by each.600 Protective Devices Abstract This section addresses the two major electrical system hazards. 600 Protective Devices Electrical Manual 645 650 651 652 653 654 Current-Limiting Fuses References Model Specifications (MS) Standard Drawings Data Sheets (DS). Data Guides (DG) and Engineering Forms (EF) Other References 600-62 November 1991 600-2 Chevron Corporation . Protecting the components of an electrical system when either of these problems occurs is the function of protective devices. One example is a leakage current through failing insulation between phase windings in a motor. This type of fault occurs when a high impedance current path exists between phases or between phase and ground. are defined as abnormal connections or arcs between two points of different potential. the most common type of fault. High impedance faults are characterized by low fault current magnitudes. Short Circuits Short circuits. It causes power sources to deliver their maximum short circuit capacity. arcing faults. fuses. as well as a discussion of current and potential transformers. An arcing fault can be extremely destructive if not quickly extinguished by a protective device. Arcing. Bolted Fault. Relays sense the electrical parameters and control the circuit breakers and contactors. Protective devices designed to protect against short circuit damage are primarily current sensitive. Fortunately. Circuit breakers and fuses physically perform the circuit interruption. These abnormal connections can be caused by insulation failure. Protective devices must be applied only within their ratings. and a line-to-ground or line-to-line arcing fault remains. Overloads Heat caused by overloads damages components of electrical systems. 611 Protective Devices—An Overview Two problems can disrupt an electrical system: overloads and short circuits. is caused by a variety of events. and high impedance faults.Electrical Manual 600 Protective Devices 610 Introduction This section gives an overview of the devices and methods for protecting electrical systems and electrical system components. Each has its relative merits and weaknesses for system protection. High Impedance Fault. Three types of protective devices are discussed: circuit breakers. 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. also called faults. Protective devices designed to prevent overloads are therefore primarily heat sensitive. Basic guidance on using and setting relays is given. these faults are extremely rare. or mechanical failure. Three basic types of faults occur in electrical systems: bolted faults. Arcing Fault. accidental short circuiting caused by misplacement of tools and wiring. which make their detection by protective devices difficult. and relays. The wire or tool melts. that is. they monitor current and time which translates into heat. Chevron Corporation 600-3 November 1991 . This fault is so named because it is as solid as if an electrical conductor had been bolted to the points of short circuit. such as insulation failure or careless placement of wire or tools. “Instantaneous tipping of breakers.” usually occurs within one cycle (16. Electromechanical relays.7 milliseconds for 60 Hz current). Breakers and controlling relays should be adjusted to ensure their fastest possible operation to clear a fault or other abnormal condition without nuisance interruptions for minor transients. melt. In circuits of lower voltage. Common Characteristics of Protective Devices Protective devices have several common characteristics: • They all have an inverse time-current characteristic. the higher the current. No protective device is perfect. such as a thermal-magnetic molded-case circuit breaker or an air circuit breaker. Fuses provide both sensing and interrupting functions. This process takes at least a quarter cycle (4 milliseconds for 60 Hz current). 2. Even a fast-acting fuse takes a finite time to heat up to its melting point. and separate enough to cause current flow to cease. None operates in zero time or prevents unwanted current from flowing. including fuses. that is. both functions can be combined in one device. the detecting devices commonly used are relays. November 1991 600-4 Chevron Corporation .600 Protective Devices Electrical Manual 612 Characteristics of Protective Devices Circuit 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. Fuses. • 1. If maintained in accordance with manufacturers’ specifications. these are as follows: Solid-state trip units. 3. Magnetic direct-acting trip devices. The speed of this operating response is limited by the mechanical and arc-quenching capacity of the device. In circuits above 1000 volts. They all have a minimum value of current necessary for operation called the “pickup” current. Protective devices must be capable of successfully interrupting the maximum fault current that flows. the faster the device acts to interrupt it. the fault current could weld together the contacts of the breaker and continue to flow until the breaker explodes. protective devices will perform in the same manner in repeated operations. In order of decreasing accuracy. 4. The accuracy (or repeatability) of operation varies among devices. and the protective devices are power circuit breakers. Where an improperly applied circuit breaker is subjected to higher than rated fault currents. if they are replaced with exactly the same parts. a circuit breaker is a device designed to open a circuit automatically on a predetermined overcurrent without damage to itself. from the source(s) to the fault point. it is important to know whether the first device can withstand full fault current momentarily and function satisfactorily afterwards. 600-1 Typical Low Voltage Air Circuit Breaker with Magnetic Air Chutes. for low voltage applications. to withstand the thermal and mechanical effects until the fault is cleared. for medium and low voltage applications. The two types of circuit breakers are: power circuit breakers. Before the second device opens. During this time. full fault current flows through the first one. therefore. In a fault condition a protective device may never open because the faulted circuit may be removed from the system by another protective device. Fig. are subjected to the fault current and its effects of heat and mechanical stress. 620 Circuit Breakers When properly applied within its rating. all system components in series. Breaker Shown in the Open Position Chevron Corporation 600-5 November 1991 .Electrical Manual 600 Protective Devices Through-Fault Withstand Capacity All protective devices require a finite time to clear a fault. The components must be able. See Figure 600-1. Therefore. and molded-case circuit breakers. Its contacts are enclosed in a vacuum container which allows rapid arc extinguishment and short contact travel. November 1991 600-6 Chevron Corporation . but more slowly than fuses. longer contact travel. Parts are designed for easy access for maintenance. Because of their larger size. these breakers are capable of clearing a fault more rapidly than power circuit breakers. and other characteristics. See Figure 600-1. and replacement. they make possible fast interruption and very short clearing time—generally in one cycle or less after the contacts part. Air interrupter types are the most common. 622 Molded-Case Circuit Breakers A 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 insulating material. 600-2 Details of 15 kV Horizontal-drawout Vacuum Circuit Breaker (Courtesy of ABB) Low voltage (600 volts and below) power circuit breakers are open construction assemblies on several standard sizes of metal frames. Air circuit breakers are the most common type of low voltage power breakers. repair. These breakers are intended for service in switchgear compartments or other enclosures of deadfront construction. See Figure 600-2. Fig. which must be protected from rough treatment. In general. Tripping units are field adjustable and are usually interchangeable within the frame sizes. they are slower acting than molded-case circuit breakers. The vacuum circuit breaker is another type of power circuit breaker.600 Protective Devices Electrical Manual 621 Power Circuit Breaker Medium voltage (601 volts to 15 kV) power circuit breakers are rugged devices built on several standard sizes of metal frames. Together. A drawback of the vacuum breaker is the fragile nature of the vacuum container. . The other component is the magnetic pickup described above. The frame size of a family of circuit breakers determines the breakers current limitation. CL circuit breakers do not provide the same current limitation as similarly sized and rated CL fuses. Branch circuits supplying critical loads fed from an uninterruptible power supply (UPS) system are protected best by CL fuses. Molded-case breakers. A 100 ampere. A pickup setting is adjustable to select the magnitude of fault current that will trip the breaker. UPS System Design) If very high levels of fault current are available on feeders. i.Electrical Manual 600 Protective Devices These breakers generally are not designed to be maintained in the field like low voltage power circuit breakers. 623 Current Limiting Circuit Breakers Current limiting (CL) circuit breakers (UL 489) provide high interrupting capabilities. can only be used in combination motor starters. another protective device is needed to protect equipment against heating caused by overload current. 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. 40. For example. Many are sealed to prevent tampering — precluding inspection of the contacts. a cost-effective approach is to apply series-connected molded-case circuit breakers. Westinghouse Quicklag or GE Q-Line). For example.000 amperes. a 100-ampere frame CL circuit breaker will have one currentlimiting characteristic for all ratings (20. 70.g. Chevron Corporation 600-7 November 1991 . two molded-case CB electrically in series sharing fault-interrupting duties. 30. replacement parts generally are not available since manufacturers recommend total replacement if a defect appears or the unit begins to overheat. particularly the larger sizes. the breaker opens. called motor circuit protectors (MCPs). These molded-case circuit breakers.000 amperes.e. less than 1/2 cycle) are desired for branch circuits. If an overload persists long enough to raise the temperature of a heat sensitive element to a predetermined temperature. 100) in that frame. 600 V circuit breaker is 25. are not suitable for repetitive fault clearing (more than 1000 to 5000 operations). One is a thermal-trip unit. If current-limiting characteristics (lowerpeak short-circuit levels and fast-acting operation. therefore. Moreover. CL fuses are the only available protective device. (See Section 124. Thermal-magnetic breakers have two major components. The two modes of operation for molded-case breakers are: magnetic (only) trip and thermal-magnetic trip. the instantaneous peak let-through current of 100ampere. 600 V CL fuse will limit the peak let-through to 10. Seriesconnected CB must meet the appropriate sections of UL-489 to be listed with Underwriters Laboratory for series connection. CL circuit breakers are not available in the single-pole 120-V branch-type (e. Magnetic (only) trip breakers have trip units sensitive to the magnetic field caused by the current. Only fault currents are interrupted by this type of breaker. Instrument and potential transformers are also discussed. The actual settings are determined later in the design phase after the short circuit calculations have been made. the protective relays will cause breakers 2. It is common practice to have the zones overlap. then breaker 1 (the backup protection) will trip and clear the fault. and dependable for protecting electric circuits and devices. The zones may be protected by various types of relays. A variety of relays is available to protect against electrical abnormalities. a transformer. Relays are precise. For example. in Figure 600-4. and the different types of relays and their uses are presented. Each zone is protected by a primary protection scheme and a backup protection scheme which will function only if the primary protection fails. phase overcurrent relaying. and the basic tools and mechanics for completing a coordination study using time current curves on log-log paper are presented. an incoming line. November 1991 600-8 Chevron Corporation . Figure 600-4 shows a typical one-line diagram divided into several zones. Section 635 below gives a description by number of standard electrical power system devices. and motors.600 Protective Devices Electrical Manual 630 Relays and Protective Device Coordination This section provides essential information for selecting the appropriate protective devices during design stages of a project (prior to purchasing the equipment). and ground overcurrent relaying. If these primary circuit breakers fail to operate. This information is then applied to protection schemes for individual components. the usual procedure is to divide the one-line diagram into zones to be protected. breaker 2 fails to trip. The method for setting these devices so they will operate together in a safe and effective manner is explained. a feeder. pilot wire relaying. See Figure 600-3. 631 Zones of Protection When designing relay protection for industrial plants. for example. 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. if there is a fault on Bus A in Zone 2. 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. and 4 to trip (as necessary) to clear the fault. such as buses. they are sensing devices only and must be used in conjunction with a contactor or circuit breaker to actually protect a circuit. then the backup circuit breakers will operate—isolating the fault. as shown in Zones 1 and 2. versatile. Each zone contains a component to be protected—such as a bus. Each zone is protected by circuit breakers or fuses which will open if there is a fault within the zone. transformers. such as differential relaying. 3. However. If. feeders. or a motor. flows through the CT primary. and transform them to proportional currents of smaller magnitudes which can be sensed directly by relays. A primary current. In most cases. The particular type is normally selected by the manufacturer of the electrical gear with which it is associated. 141-1986. ©1986 IEEE. 600-3 One-line Diagram of Current-limiting Fuse and Motor Controller with a Thermal Device. The four main types of CTs are: • • • • Wound Bar Window Bushing Three types of current transformers are illustrated in Figure 600-5. 12ed/ 1987.) Fig. by D.Electrical Manual 600 Protective Devices Fig. 600-4 Diagram Depicting Zones of Protection. Fink & W. (From Standard Handbook for Electrical Engineers. Inc. this primary current is the one flowing in the circuit to be protected. Used by Permission from McGraw Hill. CT Operation In electrical drawings.) 632 Instrument Transformers Current Transformers Current transformers (CTs) are used in protective relay circuits to detect currents in the protected circuits. CTs are represented by the symbol shown in Figure 600-6. The cable or bus carrying this current usually passes through the center of a window-type CT and does not Chevron Corporation 600-9 November 1991 . Current transformers also isolate the relay from the primary circuit voltage. IP. (Reprinted with permission from IEEE Std. Beatty. All rights reserved. This configuration is used in ground fault protection schemes. These squares or polarity symbols November 1991 600-10 Chevron Corporation . CT Symbology The two small squares in Figure 600-6 are the standard polarity symbols for current transformers. Figure 600-9 illustrates this scheme. Figure 600-8 shows the symbol for three conductors passing through a windowtype CT. See Figure 600-7 which provides a pictorial representation of the schematic of Figure 600-6. 600-5 Current Transformers contact the wiring of the CT itself.600 Protective Devices Electrical Manual Fig. Ground fault protection often uses window-type (zero sequence) current transformers enclosing all the conductors of a three-phase circuit and the neutral. 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). Electrical Manual 600 Protective Devices Fig. 600-8 Standard Zero Sequence CT Symbology Fig. 600-9 Core Balance Ground Fault Scheme with Zero Sequence CT are marked in a similar manner on the actual current transformer. the protection system will not function properly. Chevron Corporation 600-11 November 1991 . 600-6 Standard CT Symbology Fig. 600-7 Current Transformer Ratio Fig. If the polarities are not correct. The polarities are very important when several current transformers are connected together in a protection scheme such as differential relaying. it causes the CT to saturate during fault conditions—producing errors in relay operation. the currents in the primary and secondary are no longer related by the CT ratio and large errors are introduced.13. Some of the other ratings associated with CTs are: voltage. and equiva- November 1991 600-12 Chevron Corporation . In actuality. CT Saturation Thus far. During faults. a current transformer is a nonlinear device. These ratings and the verifying tests are discussed in detail in ANSI C37. industry standards. it is recommended that the maximum anticipated ampere loading not be greater than two-thirds of the CT primary current rating. the CT may saturate. and mechanical and thermal capability. A CT ratio must be selected so that at maximum continuous current in the primary circuit. the switchgear manufacturer chooses the proper ratings appropriate for the equipment after the desired ratio is specified. When selecting a CT ratio. a smaller ratio might be chosen. For a more in-depth explanation of the use of the excitation curve. frequency. CTs are available in standard ratios as shown below: Standard Ratios for Current Transformers 10:5 15:5 25:5 40:5 50:5 75:5 100:5 200:5 300:5 400:5 600:5 800:5 1200:5 1500:5 2000:5 3000:5 4000:5 5000:5 6000:5 12000:5 Current transformers are also available with taps to allow multiple ratios on one CT. only ideal current transformers have been discussed.600 Protective Devices Electrical Manual CT Ratios CTs transform higher currents to lower currents in accordance with their CT ratio. the secondary current will be less than or equal to 5 amperes. basic impulse insulation level (BIL). subject to saturation of the magnetic core. The value should be given in the relay literature. In Figure 600-6. By U. At saturation. For example. the ratio is 1200:5. If the feeder breaker supplies loads well under 1200 amperes. insulation class. accuracy class. The relay burden is the electrical impedance of the relay. the CT rated secondary current normally is 5 amperes. a 1200 ampere-feeder breaker might be supplied with a CT having a 1200:5 ratio. burdens. When the burden of the relay is too high for the CT.S. CTs have ratings other than the CT ratio that must also be considered for proper selection. Usually. Fig.Electrical Manual 600 Protective Devices lent circuit. sometimes called voltage transformers. Florida.8 kV.13. and X2 are marked on the transformer. H2.16 kV. PTs also provide isolation between the primary and secondary circuits. Different accuracy classes of CTs are required for different applications. 1982). is 120 volts. The shorting bars must be removed in the field. For this reason. the secondary voltage of potential transformers in the U. many CTs are fitted with shorting bars or shorting contacts. see Applied Protective Relaying. The polarity symbols H1. 13..g. Safety Precautions For safety reasons. this can cause overheating of the CTs or possibly become a personnel hazard. Blackburn (Westinghouse Electric Corporation. PT Ratings In general. edited by J. and 480 volts). X1.S. or the relays will not work. Accuracy classes are discussed in the IEEE Buff Book and ANSI C57. Most primary voltages are available (e. 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. L. Potential Transformers Potential transformers (PTs). Coral Springs. 4. High voltages can be induced in the secondary. CTs should never be left open circuited. 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. are used to convert the high voltages of primary circuits to proportionally lower voltages suitable as relay and metering input voltages. 600-10 Open Delta PT Connection Chevron Corporation 600-13 November 1991 . Potential transformers are connected in an open delta configuration as shown in Figure 600-10 or in a wye-wye configuration. the relay is designated as a 50/51 device. These ratings are described in detail in ANSI C57. Potential transformers also have maximum thermal burdens expressed in volt-amperes. The targets must be reset manually. primary and secondary voltage. Overcurrent Relay Types There are two types of overcurrent relaying: instantaneous overcurrent relaying and time overcurrent relaying. frequency. and accuracy.600 Protective Devices Electrical Manual Like current transformers. Overcurrent relays incorporate targets that indicate when they are tripped. If these burdens are exceeded. basic impulse level. The 50 is the instantaneous overcurrent relay and the 51 is the time overcurrent relay. Potential transformers are similar to power transformers in most respects and can be open-circuited without high voltage being induced in their secondaries. When the two functions are combined. 600-11 Construction of a Typical Induction Disk Overcurrent Relay (Courtesy of the General Electric Company) November 1991 600-14 Chevron Corporation . usage. potential transformers should have their primaries fused to protect the power system from faults in the potential transformer windings. Fig. Sometimes they are provided with secondary fuses to protect them against short circuits on their secondaries. which is used for both phase fault protection and ground fault protection. Unlike current transformers. potential transformers have several ratings associated with them. 633 Basic Considerations for Overcurrent Relaying and Coordination The most common type of relaying is overcurrent relaying. ratio. thermal loading.2 percent. These ratings include: insulation class. the lives of the transformers will be reduced.13. Accuracy classes range from 0.3 to 1. Both are usually combined into one relay as shown in Figure 600-11. Chevron Corporation 600-15 November 1991 .Electrical Manual 600 Protective Devices Instantaneous relays. or 51N. if there is one. The time overcurrent operating coil operates in series with the instantaneous overcurrent unit operating coil. See Figure 600-9 for one type of installation method. When there are no faults in the system. When shielded cable is used. Fig. It is set to pick up at a lower current than the other three overcurrent relays. The three phase conductors and the current carrying neutral. 600-12 Typical Connection of Overcurrent Relays and CTs Zero-sequence Connection Another 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 shield wiring must not go through the CT in one direction only. Current transformers are normally used to match overcurrent relays to the current levels of the electrical system. of the hinged armature-type (solenoid-type). and each is set to cover its own portion of the tripping range. overcurrent relay.5 to 2 cycles to operate plus circuit breaker operating time. if both are used. The current sensed is the ground fault current if one of the primary phases goes to ground. trip the associated circuit breaker immediately when the current reaches a preset value. Residually Connected Relays The typical method of connecting overcurrent relays into a circuit with the current transformers is shown in Figure 600-12. are passed through the window of the CT. It usually takes the relay 0. the relay normally does not sense current. The relay in the single return leg is known as a residually connected. The shield wiring must return through the CT (to ground) to prevent cancelling out ground fault currents. The CT detects any ground fault current which occurs if one of the phases shorts to ground. The curves will not be prone to cross each other. Time-overcurrent relays have two adjustments: taps and a time dial as shown in Figure 600-11. and a set of contacts. the larger the current. Overcurrent relays can be obtained with different time versus current characteristics: inverse. The delay time varies depending on the magnitude of the current. The very inverse characteristic is usually chosen as a starting point for overcurrent protection. Fig. Time overcurrent relays trip after a time delay when the current magnitude is within their preset tripping range. It is much easier to coordinate relays in series if they have the same type of characteristic curve shape. Overcurrent Relay Pickup. the extremely inverse characteristic usually is chosen to coordinate with fuses because it is closer in shape to the fuse characteristic. long time inverse.e. Figure 600-11 shows an induction disk relay. Taps. medium time inverse. The differences in these characteristics are shown in Figure 600-13.600 Protective Devices Electrical Manual Basic Relay Operation The basic operating unit of an overcurrent relay consists of a magnetic core operating coil.. a damping magnet. an induction disk. very inverse. For example. and Time Dials Taps. All of these combine to produce a time versus current operating characteristic. extremely inverse. Time overcurrent relays have an inverse time characteristic (i. 600-13 Time Characteristics Available for Overcurrent Relays The characteristics chosen depend on the piece of equipment being protected and the devices being coordinated. and short time inverse. the shorter the time it takes to trip). Taps are used to determine the level of current at which the relay November 1991 600-16 Chevron Corporation . 10 would represent 1500 amperes. if the 2.g. which equals 2. then it will take 150 amperes in the primary of the CT to produce 2. the longer it takes the relay to trip for any given current.5 amperes tap on an overcurrent relay is selected. 10 times the pickup current.5 to 10. For example. The time dial setting determines the distance the induction disk must turn to close the relay contacts.5 to 2 amperes.5 amperes in the secondary. The taps are adjustable in steps over a fixed range of current values (e. but a time dial setting of 10 Curve C has the same time-dial setting as Curve A. Notice that both vertical and horizontal scales are logarithmic. at 1500 amperes. The tripping range is any current larger than the pickup current. this would be represented as 1 on the horizontal axis. it takes an infinite amount of time to trip at the pickup current.3 seconds to trip if the time dial is set to 1. it will take this particular relay 0. Taps are changed by inserting a special screw in the appropriate hole in the face of the relay corresponding to the desired relay pickup current. If the pickup current is 150 amperes as calculated in the previous example.5 to 6 amperes. For example. multiply the tap times the CT ratio: Pickup Current = Tap Value × CT Ratio For the example above. 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. The pickup current is the minimum current which will start the induction disk moving (and ultimately close its contacts).5 seconds to trip if the time dial setting is 6.5 Curve B has the same tap setting as Curve A. The time to trip can be determined from the time-current curve. 0..5 times 300 divided by 5.Electrical Manual 600 Protective Devices will begin to actuate. as illustrated in Figure 600-15. which is what is sent to the relay coil. pickup current equals 150 amperes. Time-current Curves The time-current characteristic curve for a typical time-overcurrent relay is shown in Figure 600-14. The relay curves do not extend all the way to the pickup current because. The time required for an overcurrent relay to operate can be determined from its time-current characteristic curve. and 1. If the relay is connected to a 300:5 current transformer. To determine the actual current in the primary which will cause the relay to pick up. The time required for a relay to operate at any particular current value is determined by the time dial setting. Current scaling on the x-axis is more convenient because it is not necessary to refer elsewhere for the pickup current. • • • • Curve A has a time-dial setting of 0. or 4 to 16 amperes). the characteristic curve can be moved vertically and horizontally on a time-current relay coordination curve. 2. By varying the settings of the taps and time dials of an overcurrent relay. Chevron Corporation 600-17 November 1991 .5 amperes is the current which will start to move the induction disk towards contact closure. The horizontal axis is the current axis. 1. Time Dial. Time dial settings usually have an adjustable range from 0. theoretically. The larger the time dial setting. The vertical axis indicates the time to trip (in seconds). Current is expressed in multiples of relay pickup current. not in multiples of pickup current. 600-14 Typical Time Current Characteristic Curve November 1991 600-18 Chevron Corporation .600 Protective Devices Electrical Manual Fig. Current Characteristic Curve of a Relay can be Shifted by Varying the Tap and Time Dial Settings The inset diagram in the lower right half of Figure 600-14 is the characteristic of the instantaneous unit. from the utility source to the utilization device. This value neglects effects due to CT saturation. if the instantaneous relay adjustment is set at 100 amperes and the CT ratio is 300:5. Time dials do not affect the setting of the instantaneous unit. Once the settings of the taps and time dials are made. it trips very quickly (within approximately 8 milliseconds) upon reaching the pickup current. Typically. There is no intentional time delay in an instantaneous unit. It also has a setting which is separate from the overcurrent unit tap setting. For example. The instantaneous setting is calculated in the same way as the overcurrent setting. instantaneous pickup ranges are adjustable between 40 to 160 amperes. 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 coordinate. relays should be checked (using special testing equipment) in the field to ensure that they are working and properly calibrated. 10 to 40 amperes. 20 to 80 amperes. Coordination means that the relay or device nearest the fault has sufficient Chevron Corporation 600-19 November 1991 .Electrical Manual 600 Protective Devices Fig. 4 to 16 amperes. Information Needed to Perform an Overcurrent Relay Coordination Study An overcurrent relay coordination study is a time-versus-current study of all devices in series. or 2 to 8 amperes. 600-15 Diagram Showing How Time vs. 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. The tap setting multiplied by the CT ratio yields the primary pickup current. then the relay will trip at 100 x 300/5 = 6000 amperes. and inrush current. the starting current. and the acceleration time. 2. 6. For motors. Values of three phase bolted fault current and ground fault current. their tap ranges. For transformers in the system. the full load current. the factory relay curves. For molded-case circuit breakers. 7. the transformer short time capability curve. and instruction manuals for all relays. These curves may include the time-versus-current withstand limit curves for the machines during running overloads or stalled conditions. 8. The actual settings of the protective devices are determined in the course of the coordination study. For solid state trip units. the full load current. With proper coordination. Values of short circuit current through the devices considered in the study. trip setting. 13. Existing settings of all relays in the system to be studied. and time-current curves.600 Protective Devices Electrical Manual time to act in order to clear the fault before the devices closer to the source. November 1991 600-20 Chevron Corporation . unnecessary shutdowns are eliminated. 10. For cables in the system. Manufacturer model and fuse size of all fuses in the system and their timecurrent curves for melting and clearing. and instantaneous settings. 9. the ratio of the CTs to which they are connected. The short time capability curve is available from ANSI C57. The following information is needed to perform a coordination study. Values of load currents. the current withstand limit curves. model. the manufacturer. the manufacturer’s curves and instructions on how to set the long time. 1. 5. 11. eliminating a single unnecessary shutdown can more than pay for the time required to complete a relay study. short time. A system one-line diagram (and a meter and relaying drawing if separate from the one-line diagram). In large electrical systems.109 or the IEEE Buff Book. 3. the overcurrent device nearest the fault will clear the fault. For large motors and generators. delay bands. 4. which also see the fault current. shutting down the smallest possible part of the total system. have time to initiate a trip. With proper coordination. The manufacturer and model of all relays in the system to be studied. This is known as selective tripping. the short circuit withstand curve (the insulation damage curve)—based on the particular type of insulation and the current ampacity. 12. 1 A 100 × --------13. This is done on log-log transparent paper (e. See Figure 600-16. there may be relays on the primary and secondary side of a three-phase transformer.8 (Eq.Electrical Manual 600 Protective Devices When to Conduct a Coordination Study Conditions requiring a coordination study are as follows: 1. During the design phase of a new facility.16 kV on the secondary. When significant new loads are added to an existing system or when existing equipment is replaced with equipment of a different rating. When the available short circuit current from the source is increased. “Current in Amperes x 1000.16 .8 kV primary voltage can be shown as either 100 amperes at the 4.g. All curves must be shown with equivalent current at one chosen voltage level. The Time-Current Coordination Curve After the information listed above is gathered. A voltage level within the system must be chosen and all currents referenced to that voltage level..8 kV on the primary and 4. See (1) in Figure 600-17. For example.” if the scaling factor is 1000. 3.8 kV.g. K&E type 42-5258. Following a major electrical plant modification. The x-axis is expressed in amperes of current at the reference voltage. It is common to show relays at two or three voltage levels on the same sheet. If so.1 amperes at 13. 2. A secondary current of 100 amperes will cause a primary current to flow. Often the current axis at the bottom of the curve is scaled.) First the voltage and current level for the horizontal scale must be selected.= 30. 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). all referenced to the common voltage level on the coordination curve. 4. it must be transferred to the TimeCurrent Coordination Sheet. 600-1) On the time-current curve the 13. 5. with 13. 4.) Chevron Corporation 600-21 November 1991 .16 kV secondary voltage level or 30. Usually.. the title should indicate the scaling factor (e. it is best to select the lowest voltage level of the relays being studied. 600-16 Case 1 Relay Coordination Example (Courtesy of the General Electric Company) November 1991 600-22 Chevron Corporation .600 Protective Devices Electrical Manual Fig. Electrical Manual 600 Protective Devices Fig. 600-17 Case 2 Relay Coordination Example (Courtesy of the General Electric Company) Chevron Corporation 600-23 November 1991 . See (5) in Figure 600-17. 6. transformer full load amperes. the relay that will operate first cannot be predicted. The value of this current can be approximated by multiplying the calculated symmetrical first cycle short circuit current by 1. See (3) in Figure 600-17. direct acting trip units associated with low voltage circuit breakers. 2. transformers or generators. motors. Any thermal damage or withstand limit curves for cables. after it is reduced in magnitude. Maximum fault current level the protective devices can be subjected to. Transformer inrush points. Coordination Time Intervals Relay curves are extended only to the value of the maximum fault current that affects them. determines if selective coordination exists.6. If the curves have too little vertical separation at the fault current level. See (7) in Figure 600-17.600 Protective Devices Electrical Manual Other information displayed on the time current curve is as follows: 1. Fuses. although this multiple varies with the impedanceto-resistance ratio (X/R). tap. To determine which relay will operate at a given point in time. 3. and instantaneous relays respond to asymmetrical short circuit current. 4. If the relays characteristics are of the same general shape. the vertical time separation between curves of relays in series (which see the same current). Fault Levels and the Coordination Curve Both symmetrical and asymmetrical currents are of interest in relay applications since different relays respond to different fault currents. of this manual. time dial. See (2) in Figure 600-17. 7. to insure coordination. For an explanation of first cycle short circuit current. the relays will also coordinate at lower values of current. Induction disk overcurrent relays respond to the symmetrical fault current a few cycles later. generator and motor full load amperes. 5. Cable ampacities. see Section 220. Motor acceleration time-current curves. fuses and molded-case circuit breakers relating to the system being coordinated. and selective tripping cannot be guaranteed. and if these intervals are applied at the maximum fault level. November 1991 600-24 Chevron Corporation . The one-line diagram of the system to be coordinated. This current value is approximated by the interrupting current calculated in the short circuit study at 3 to 5 cycles. The characteristic curves of protective devices are normally not drawn beyond the maximum fault current level. Figure 600-18 shows the suggested minimum values of time intervals between overcurrent protective devices in series. the value of fault current to which each relay responds must be known. Their CT ratios. See (4) in Figure 600-17. The time-current characteristics of all relays. and instantaneous setting values. At the fault current value. See (6) in Figure 600-17. January.Electrical Manual 600 Protective Devices Fig. Courtesy of Square D. 600-18 Time Margins for Use with Induction Disc Overcurrent Relays (1 of 2) (From Procedure for an Overcurrent Protective Device. Company) Chevron Corporation 600-25 November 1991 . 1979. 1979.600 Protective Devices Electrical Manual Fig. January. Company) November 1991 600-26 Chevron Corporation . 600-18 Time Margins for Use with Induction Disc Overcurrent Relays (2 of 2) (From Procedure for an Overcurrent Protective Device. Courtesy of Square D. cables. 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.38 seconds must be used. and motors. The size of the cable is also shown. One-line Diagram The one-line diagram of the system being studied is shown to the side of the relay curves. Fault Current Values The fault currents at the locations of interest in the one-line diagram are shown at the top of the figure. Graph Scales The current scale is identified as currents at 13. All voltage levels are also shown on the one-line diagram. For more information on protective relaying see the reference section (Section 650). 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.16 kV side of the transformer must be multiplied by the factor 4. but serve to make some important points. they cannot overlap.16/13.16 kV secondary. and show how to interpret them. If the relays are not calibrated in the field. Example Showing How to Interpret Relay Coordination Curves Figure 600-16 and Figure 600-17 provide two examples of typical information shown on time coordination curves including transformers. This is the “6 X Trans FL” point at the top Chevron Corporation 600-27 November 1991 . It is recommended that this be done before startup. 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.25 seconds at the maximum fault level if the relays are set and calibrated at specific critical operating points in the field.8 kV. and winding type. as well as the transformer kVA. It shows all of the relays whose curves are on the coordination drawing and all CT ratios.38 seconds to 0.Electrical Manual 600 Protective Devices In addition to the information in Figure 600-18.8 kV primary and a 4.25 second intervals are used. These examples are not exhaustive. however. Any currents on the 4. induction disk relay-to-relay coordination time intervals can be reduced from 0. Case 1—Transformer Protection (Figure 600-16) Figure 600-16 shows the overcurrent relaying of a 5000 kVA delta-delta transformer with a 13. 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.8 before they can be displayed on the curve. the coordination criterion is that there be no overlap. In some of the examples. sometimes they are marked at the bottom for convenience. 0. 0. No space is required between the boundaries of the time bands of the two devices. based on field calibration being performed. impedance. Cables have different CHL curves. The primary pickup current for this relay is the CT ratio multiplied by the tap setting (300/5 x 10 = 600 amperes). These curves are available from sources listed in the references of Section 200. An example of a CHL curve is shown in Figure 600-19. the breaker must be set to trip below six times the ampacity of the cable (NEC Article 240-100). Relay Settings Figure 600-16 shows that there is a time overcurrent relay and an instantaneous relay associated with the primary circuit breaker. 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.600 Protective Devices Electrical Manual of the diagram. depending on the type of insulation and the wire size. This curve is found in ANSI C57. Transformer full load current is 209 amperes. and limits the maximum allowable pickup setting of the primary 50/51 relay. Table 450-3. 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. Therefore. Curves can be applied directly at the values shown in the ANSI curve for transformers with delta-delta or wye-wye windings. 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. for cables at voltages greater than 600 volts. This point is usually shown at 12 times the transformer full load current at 0. the short-time-loading-limit curve current values must be reduced to 58% of the values shown. the relay must protect the cable according to its ampacity. For low voltage cables. The time overcurrent is set with a tap setting of 10 amperes and a time dial setting of 3. The transformer inrush point must also be indicated on the coordination drawing. The cable heating limit (CHL) curve is in the lower right area of the time current coordination curve.1 second for load center type units. and at eight times full load current at 0. “System Studies and Protection” (see also the Buff Book). For delta-wye transformers.1 seconds for primary substation and pad type units. the primary overcurrent relay will provide short-circuit protection for secondary short-circuit currents. November 1991 600-28 Chevron Corporation . Transformer Protection The ANSI transformer short-time-loading-limit curve is plotted on the time-current sheet. The 600 amperes pickup is less than six times the transformer full load current (1254). Cable Protection The cable also must be protected in accordance with requirements of NEC. the maximum allowed by NEC. The transformer and cable overload protection are the lower constraints on the relay protection.109-1985 and also in the Buff Book. Electrical Manual 600 Protective Devices Fig. 600-19 Typical Insulated Cable Short Circuit Heating Limits (Time-Current Curves). (Courtesy of General Electric Company) Chevron Corporation 600-29 November 1991 . from the short circuit study.6 x IFCY).25 second coordination interval is required if the relays are field calibrated. Only a 0. This feature ensures selectivity with the secondary overcurrent relay. The one-line diagram is in the upper right corner of the coordination drawing.1 seconds)—this is the motor starting amperes (MSA). showing the CT ratio (200/5). therefore.6 times the locked rotor amps. It is also 0. 0. usually less than 10 times the full load amps of the motor. It is set just above the asymmetrical value of the first cycle short circuit current (1. The cable ampacity. When induction motors are first started.38 to 0. an instantaneous relay was used on the primary. is indicated at the top right of the figure since the instantaneous device responds to this current. is plotted at the top of the figure. If the relays are not field calibrated. consisting of three parts. Transformer Secondary-side Protection The secondary time overcurrent device. but not for a secondary side fault. IINT. 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. the cable size. which should trip first on a secondary fault. The instantaneous relay is set below the cable heating limit curve. is also plotted. The secondary 51 device curve is below and to the left of the transformer shorttime-loading curve at the maximum three phase secondary fault through breaker B1. so the transformer is protected against faults. Case 2— Motor Protection (Figure 600-17) Figure 600-17 demonstrates relay coordination for a 3000 hp motor.25 seconds below the primary overcurrent relay curve to provide coordination at the maximum secondary fault. labelled 51 in Figure 600-16. they have a magnetic inrush. Motor Acceleration Curve The motor accelerating current curve. This is the current impressed on the primary side if there is a fault on the secondary side of the transformer. The asymmetrical fault current at the motor. The cable short circuit heating limit curve is plotted for the 1/0 feeder conductors. similar to that of a transformer (which lasts less than 0. The November 1991 600-30 Chevron Corporation . and the relay device numbers. a secondary fault will not trip the primary instantaneous relay. The value of this starting current is approximately 1. 195 amperes.600 Protective Devices Electrical Manual Transformer Primary-side Protection As added protection. The instantaneous device is set below the maximum asymmetrical fault current so that it will respond to the fault current. It also must have a pickup below three times the full load current of the transformer as required by NEC Article 4503. but above the full load current of the transformer.40 seconds are required. protected by a circuit breaker with an overcurrent relay and an instantaneous relay. but above the transformer inrush point (called magnetizing current and labelled MAG). has a pickup below six times the cable ampacity needed to comply with NEC requirements. Motor Thermal Limit Curve Next. passes below and to the left of the motor thermal limit curve. If the relay curve intersects the motor acceleration time-current curve. where motor starting is discussed. but protecting it against locked rotor conditions. The time dial is set at 2. which exceeds the motor starting amps. the relay provides the required protection for the motor and the feeder. The curve of the 51 relay lies between the motor acceleration curve and the motor thermal limit curve. Since the cable ampacity is 200 amperes. so the pickup setting allows the motor to run. the motor thermal limit curve is drawn on the time current sheet. This value is usually in the range of four to six times the full load current of the motor. NEC requires that the cable be protected within six times its ampacity. The curve for the motor overload protection. therefore. The value can be obtained from the manufacturer or. the cable is adequately protected against overloading. 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. the current levels off to approximately the full load amps of the motor—110 amperes in this case. For large motors this curve is obtained from the manufacturer. Both conditions are illustrated in Figure 600-17. establishing a pickup current of 200/5 x 4 = 160 amperes. The majority of all electrical faults involve ground faults. The second part of the motor accelerating curve is the locked rotor amperes (LRA)—640 amperes in this case. for low voltage motors. allowing the motor to start and run. The instantaneous setting at 110% of the motor starting amps. Setting the Relay The motor full load amps is 110 amperes. When the motor reaches operating speed. supplied by the 51 device in this case. but it is important to consider ground fault relaying in electrical systems at all voltage levels. yet will still trip for fault currents above this value. 634 Ground Fault Relaying and Coordination Another form of overcurrent relaying is ground fault relaying. The tap setting of the 51 relay is set at 4. Chevron Corporation 600-31 November 1991 . the arcing may continue until a fire or serious damage results. The actual acceleration time can be estimated or calculated as demonstrated in Section 400. provides an extra degree of protection against faults and also gives additional cable fault protection.Electrical Manual 600 Protective Devices instantaneous device is set approximately 10% above this value to ensure it will not trip when the motor starts. 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. Sometimes the thermal limits are given in terms of maximum stall times from a hot or cold starting condition. If these faults are not cleared. The acceleration time-current curve serves as a lower restraint for the 51 relay timecurrent curve. after about 5 seconds. which gives the starting kVA per horsepower. the motor will be shut down before it reaches operating speed. can be calculated from the locked rotor code. This circumstance is particularly applicable to low voltage systems. Since the residual relay does not actuate for normal load currents. if one of the conductors becomes grounded. but high enough to eliminate spurious tripping and allow coordination with any other downstream ground fault relaying which sees the same fault. However. Residually Connected Ground Fault Relaying (Device 51N) A residually connected ground fault relaying scheme is shown in Figure 600-12. During balanced normal load current flow. They are seen only on the faulted side. it can be set to pick up at much lower currents than the phase overcurrent relays fed by the same set of CTs. producing no secondary current in the CT. The core balance ground fault relaying device can be used with shielded or non-shielded cables. usually closer to the lower end of the range for modern sensitive ground fault relays. so the relays on both sides of the transformer do not have to be time delayed to allow mutual coordination. if one of the phases becomes grounded. Usually the currents in phases A. the flow of the external ground fault current causes an unbalance in the CT currents. This scheme normally is used on medium voltage systems. Types of Ground Fault Protection 1. It is used widely on medium voltage systems since ground fault currents usually are higher.600 Protective Devices Electrical Manual Typical ground fault protection schemes are not sensitive to load currents. resulting in a flux unbalance within the window CT. Typical pickup settings for ground fault relaying range from 10% to 100% of the phase overcurrent relay settings. The residual scheme is not as sensitive as the core balance or zero sequence (window CT) scheme. Ground fault relays usually do not require as severe coordination time restraints as phase overcurrent relays. 2. Ground faults are not seen by the relays on both sides of delta-wye and wye-delta transformers. However. and is not often used on low voltage systems. the core balance method is insensitive to normal load currents. therefore. the ground fault relay pickups can be set much lower than the phase overcurrent relays protecting the same feeder or electrical device. the magnetic fields of the three phases passing through the window CT vectorially add to zero. Core Balance Ground Fault Relaying (Device 50/51G) Figure 600-9 shows a typical core balance or zero sequence current transformer ground fault relay scheme. Like the residually connected ground fault scheme. and C vectorially add to zero—resulting in little or no current through the ground residual relay. It should be set low enough to provide sensitive ground fault tripping. it is important to route November 1991 600-32 Chevron Corporation . and a current proportional to the ground fault current flows through the residual relay—causing it to trip the circuit breaker. This produces a secondary current of sufficient magnitude to trip the ground fault relay. This method is very sensitive and is widely used on low voltage systems. B. a large external current flows outside the window CT. If it is used with shielded cables. These circulating currents can cause sensitive core balance relays to trip. Instead of a CT. This current will produce a voltage approaching line-to-neutral. However.Electrical Manual 600 Protective Devices the shield drain wires back through the window CT as shown in Figure 600-9. a meter relay monitors the voltage across the grounding resistor. this CT would not see load current. there will be a ground return current through the resistor. The meter relay will detect this voltage and alarm. if one of the phases goes to ground. As in the other schemes. Under normal conditions. This arrangement prevents magnetic flux due to ground fault currents (which return through the shield) from cancelling and therefore remaining undetected. there is little or no voltage across the resistor. it could be set with a much lower pickup. Ground Return Figure 600-20 shows a medium voltage delta-wye transformer with a low resistance grounded wye secondary. Figure 600-21 shows a similar arrangement commonly used in high resistance grounded 480 volt systems. 600-21 Meter Relay Used for High Resistance Grounding Scheme on a Transformer Chevron Corporation 600-33 November 1991 . 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. 600-20 Ground Return Relay for a Low Resistance Grounding Scheme on a Transformer Fig. 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. therefore. Fig. There are two ways to solve this problem: (1) the ground loop can be eliminated 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. the transformer primary breaker. The ground fault relays protecting the transformer and feeder. short time. a feeder. 51G1 and 51G2. The settings on both relays are well below the expected load currents of the transformer and motors.25 seconds above the instantaneous motor ground fault relay to provide coordination. Two relays are used to provide backup protection. 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. ground fault relaying should be applied from source to load. A typical time-current curve for such a device is shown in Figure 600-22. It is recommended that the pickup level be set as low as possible without causing spurious shutdowns due to inrush currents. The 51G1 relay trips the secondary breaker.600 Protective Devices Electrical Manual 4.25 second interval rather than the standard 0. but the time dials are set differently to provide coordination. 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. Ground Fault Relaying Example Figure 600-23 shows a typical ground fault protection scheme for a transformer. 51G1 is set 0. The ground fault relays which protect load devices (such as motors) can also be obtained with an instantaneous setting. 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. They are both set with the same tap setting (to pick up at about 20 amperes). 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). and motor branch circuits. The time delays for coordination between series ground fault devices which sense the same faults follow the same rules as the overcurrent device coordination intervals. 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. Note that these relays must be field calibrated to use the 0. and instantaneous functions).38 second interval. then the 51G2 relay trips A7. November 1991 600-34 Chevron Corporation . If this fails. Selection of Settings for Ground Fault Relaying For best protection against ground faults. 1979.Electrical Manual 600 Protective Devices Fig. by Curd & Curtis. Company) Chevron Corporation 600-35 November 1991 . 600-22 Typical Time-Current Characteristics of Low-Voltage Breakers (From Procedure for an Overcurrent Protective Device. Courtesy of Square D. January. 600-23 Example of Ground Fault Relay Coordination (Courtesy of the General Electric Company) November 1991 600-36 Chevron Corporation .600 Protective Devices Electrical Manual Fig. A heating element melts the eutectic metal if the overload persists long enough. Since this same alloy is used for specialty soldering. It will also respond to heat resulting from jogging or frequent starting. the ratchet turns on its shaft because of the spring. The most common situation is that in which the ambient of the starter is controlled. This temperature is between 80°C and 150°C (176°F to 272°F). 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. When the coil circuit is opened. A resistive heater element in series with the motor current is wound around the strip. and the motor is de-energized. If the strip is heated sufficiently. 4. it moves over a certain distance and opens. the ratchet is kept from turning by the solidified eutectic metal. which in turn opens a normally closed contact in the coil circuit of the motor. Only bimetallic relays are available with ambient-compensated features. A lever opens a normally closed relay contact. Chevron Corporation 600-37 November 1991 . 3. 1. usually in the form of a strip—occasionally a disc. it melts at an extremely low temperature for metals. the main contacts of the starter open. When the metal alloy melts. it may be necessary to use an ambient-compensated thermal relay to achieve proper overload protection. The relay can be reset. and to overcurrents resulting from unbalanced voltage conditions. During normal operations a small ratchet is kept under torsional force by a spring. Ambient-compensated If a motor and its starter are exposed to different ambient temperatures. This removes power from the motor. but that of the motor is not.Electrical Manual 600 Protective Devices 635 Other Common Types of Relay Protection Thermal Overload Protection Thermal overload relays are used for motor thermal overload protection. However. 2. by snap action. this type of overload relay is sometimes called a solder-pot relay. Heaters are chosen from manufacturer’s tables. Melting-alloy This type of thermal overload protection employs a metal alloy that is called eutectic. to the high inrush currents that flow during the starting period. Bimetallic Two metals with different coefficients of expansion are bonded together. based on the normal load current of the motor. a normally closed contact in the coil circuit of the starter for the motor. the other can move freely. One end is fixed. jogging. but 120 ohms are recommended as 120 ohm RTDs are more accurate. and other abnormal conditions. It is recommended for motors rated 1500 hp and larger. It is recommended for motors rated 1500 hp and larger. rotor/stator thermal time limit. It is also November 1991 600-38 Chevron Corporation . A temperture-actuated overload relay is sensitive to motor heating due to continuous overloads. loss or restriction of ventilation. A combination thermal overload relay may be used in lieu of either a current-actuated or a temperature-actuated overload relay. When a fused magnetic-contactor starter is used. An instantaneous overcurrent relay is recommended for all motors above 600 volts. this relay is not required since the fuse will provide short-circuit protection. The value to be used should be established and included in the motor specifications. 6.600 Protective Devices Electrical Manual The relay may or may not be ambient-compensated. or both. and a current-actuated input that is responsive to the rate of temperature rise of the rotor during the starting period. unbalanced voltage conditions. provide continuous overload protection. high atmospheric temperatures. 2. locked-rotor current. 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. The 50 relay can be integrally mounted in the same case as the current-actuated thermal relay (49) or timed-overcurrent-relay (51). The RTDs may have a 10 ohm value. motor-winding temperature rise. RTD ohms. Combination Thermal Overload Relay (Device 49/49T) A combination thermal overload relay is a solid state relay. Complete motor information (such as full-load current. This relay is recommended for all motors above 600-volts. 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. It uses an RTD input to sense motor temperature. 5. or provided in a separate case. 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. Differential Relay (Device 87) A differential relay provides sensitive high-speed protection against internal motor faults. and CT ratio) must be furnished for proper selection and calibration of the relay. The relay is mounted in the controller. frequent starting. Fault Protection 1. 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. Ambient compensation is used to offset the differences in temperature between the motor ambient and the interior of the controller enclosure. Because of faster operation. fixed-percentage. better sensitivity. 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. However. The relay typically used is either a standard-speed. The latter costs slightly more. 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.g. This scheme provides protection against phase-to-phase internal winding faults. a. and ground faults. the self-balancing scheme is usually preferred over the conventional scheme. The conventional scheme utilizes a total of six current transformers and three differential relays.) Self-balancing differential scheme. Downtime costs are also a factor to be considered. Conventional scheme. b. Two basic schemes are used to provide this protection for large motors: conventional and self-balancing. (See Figure 600-24a. and the other set is located in the motor terminal box (on the neutral side of the motor winding).. This scheme consists of three differential relays energized from three flux-balance current transformers mounted at the motor terminals. 600-24 Differential Schemes (a) Conventional Differential Protection Scheme. One set of current transformers is located in the motor controller. induction-disk relay or a highspeed variable-percentage relay. (See Figure 600-24b. and lower cost. 50:5) are recommended to obtain higher sensitivity to lower primary currents.) Fig. One Phase Shown (b) Self-Balancing Differential Scheme Chevron Corporation 600-39 November 1991 . faults in the primary cable. Small-ratio current transformers (e.Electrical Manual 600 Protective Devices recommended for critical motors. Device 46 is recommended for 1500 hp and larger motors. since voltage variations normally affect all phases. The function of the undervoltage relay is to trip the buses on complete loss of voltage or sustained voltages 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.600 Protective Devices Electrical Manual Undervoltage or Loss of Voltage Protection 1. The rate of heating in the rotor due to negative-sequence currents is considerably higher than that for positive-sequence currents. Standard current-operated overload relays (even one per phase) cannot be depended upon for reliable protection against unbalanced conditions. it is recommended that this device be combined with current balance (46) and phase sequence voltage (47) relays. Current-Balance Relay (Device 46) In a fused motor starter. These currents can cause rotor damage before the overload relay operates. The undervoltage relaying scheme is designed to trip each motor controller (through an auxiliary relay) rather than trip the incoming line breaker. Undervoltage relay protection is not required for low voltage motor starters (less than 60 volts) since the contactor opens on low voltage. The resulting unbalanced currents in each of the unopened phases will produce serious heating in the motor. an open fuse will allow the motor to operate singlephased. The undervoltage relay has an inverse time characteristic with adjustable operating settings for both time and voltage. Another use of this relay is to monitor fuses of potential transformers and other relays connected to the potential transformers. However. Current and Voltage Unbalance Protection 1. 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. A current-balance relay on each motor feeder will properly sense this unbalanced condition and trip the motor. For most installations. Undervoltage Relay (Device 27) An undervoltage relay should be provided on each bus supplying motors controlled by switchgear or latched contactors. A single relay sensing phase-to-phase voltage is adequate. The current in the two unopened phases has a large component of negative-sequence currents. undervoltage relays may be used to open the contactor if low voltage is of short duration. Although the overload may eventually initiate tripping. 2. This relay is a three-phase device that will operate when there is a fixed percentage of unbalance between any two phases. approximately equal to the positive-sequence currents. Undervoltage relays are recommended for all medium voltage motors (600 volts and above). the motor can be substantially damaged before it can be removed from the bus. thus preventing unnecessary trip- November 1991 600-40 Chevron Corporation . Special Protection Schemes 1. A time delay relay is used to sense a failure of equipment to reach normal running conditions within a specified starting time. 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. Blown-Fuse Trip The blown fuse trip is not recommended for motors greater than 1500 hp. wound-rotor motor starting schemes. thus sending a signal to the contactor to open the other two phases.g. In this case. An auxiliary contact on the motor starter is used to engage the timer. A time-delay relay may be used to block successive restarts until a preset time interval has elapsed. A reversephase sequence causes a motor to run in the opposite direction.2 kV) synchronous motors. The blown-fuse trip consists of a trip bar that will trip and close a switch contact in the event of a blown fuse. a situation which would occur for a fault Chevron Corporation 600-41 November 1991 . A phase sequence voltage relay may be used on a bus to protect a group of motors. The lower cost of the blown-fuse trip device is its only advantage over the current-balance relay. It is used in reduced-inrush starting schemes. it is not reliable. 3. Alarms to indicate blown fuses can also be provided. This scheme is recommended for medium voltage (2300 volts to 13. three per hour). This protection will ensure that the maximum allowable number of starts in a given period is not exceeded. the relay would only detect power flowing from the plant to the source. The relay can protect against starting a motor with a reverse-phase sequence. The tripping contact of the timer is blocked by an auxiliary contact that operates last to complete the starting sequence. Phase Sequence Voltage Relay (Device 47) A phase sequence relay is used to detect a reversed phase rotation. Repetitive-Start Protection All large motors have a limitation on the number of starts allowed within a given time period (e. Phase Sequence Protection 1. 2. The timer is preset to have a slightly longer time interval than is required for normal starting.. This feature can be purchased as an option on medium voltage fused starters. and unloaded-start synchronous motor starting schemes.Electrical Manual 600 Protective Devices ping in the event of a blown fuse. 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. which can cause equipment damage. A typical use of this relay is on incoming power from a source. These contacts are usually wired to send a trip signal to the transformer’s primary circuit breaker. 7. Directional Power Relay (Device 32) This device is sensitive to power flow in one direction and ignores power flow in the other. Another common use of this relay is in ground fault protection circuits. relay contacts are wired to the trip circuit of a lockout relay. 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. Another use of the directional power relay is as an anti-motoring device for generators. This relay is used in conjunction with other protective relays in switchgear and motor control centers.600 Protective Devices Electrical Manual located near the source. it could be set lower than a normal bi-directional overcurrent relay. The lockout relay is often connected so that it can be tripped by multiple relays. 8. it monitors November 1991 600-42 Chevron Corporation . When the relay contacts close. thus tripping the circuit breaker or starter. indicating a paralleling problem or a loss of the prime mover. In a typical application. If there is an internal fault in the transformer. Lockout Relay (Device 86) A lockout relay sends a signal to trip the breaker it is associated with. It should be set to detect power entering the generator terminals from other parallel generators. 4. 6. In the simpler cases for small motors. 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. 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. the directional power relay can be set to alarm or trip on power flow from the plant generators to the utility. Loss of Excitation Relay (Device 40) This relay is used to protect against loss of field for both synchronous motors and synchronous generators. It would not detect load current flowing to the load. Overvoltage Relay (Device 59) This relay is adjustable to trip on increasing voltage at a specified value. therefore. A typical application is used for utility lines serving a plant which also has local generating capability. 5. If it is needed only to import power from the utility. 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. The lockout relay must be manually reset before the circuit breaker or starter can be reclosed. It is used for protection of sensitive components against sustained overvoltage. the lockout relay trips. so a fault on one side of the bus will isolate only that side. Bus differential relays are not sensi- Chevron Corporation 600-43 November 1991 . a trip signal is initiated. it monitors the relative angle between voltage and current. or initiates the breaker closure automatically. If the fault is within the specified distance zone of the relay. This scheme works well with sectionalized buses connected by tie breakers. It also provides a trip signal when the angle indicates a loss of field.Electrical Manual 600 Protective Devices field current and provides a trip signal on loss of this current. thus connecting the generator to the bus. 10. frequency. When these differences are within the specified range. differential protection is often used to provide instantaneous bus fault protection (see Differential Relay. Device 87). They provide a trip signal if the fault is within a specified distance from the relay location. Synchronizing Relays (Device 25) Synchronizing relays are used to control breaker closure when connecting two power sources which must be synchronized. this upsets the balance and all the breakers on the bus are immediately tripped to clear the fault. A typical application of this type of relay would be to supervise or initiate the breaker closure of generators connected to the same bus. These units can provide both overcurrent protection and ground fault protection. 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. On medium voltage buses. Both sections of the bus can be protected by individual bus differential relays. the distance to the fault can be determined. From this relationship. A synchronizing relay monitors the difference between the terminal voltage. If a fault occurs on the bus. On larger motors and generators. On low voltage buses this function usually is handled by the multi-function solid-state direct-acting trips on the incoming and outgoing circuits. 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. the relay supplies a contact closure which serves as a permissive for manual breaker closure. This distance is altered by adjusting the values allowed for R and X for which the relay will trip. Distance Relay (Device 21) Distance relays are fault detection devices that are mainly used on transmission lines. they need protection that will rapidly clear ground faults or phase faults on the bus. and phase angle of the oncoming generator and the bus to which it is to be connected. 9. The distance relay monitors the phase relationship between the current and voltage on the transmission line. 636 Electrical Component Protection and NEC Requirements Bus Protection Since switchgear buses are vital parts of the electrical system. allowing continuity of load on the other side. Other less common schemes are pilot wire differential relaying and directional overcurrent relaying. November 1991 600-44 Chevron Corporation . Fig. A suitable short-time delay trip feature should be used instead of an instantaneous trip feature on the feeder to an MCC. Low Voltage Feeders In general. Low voltage feeders are usually protected by fuses or circuit breakers which give this protection. 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. 600-25 Typical Bus Differential Relay Scheme Buses protected by bus differential schemes have backup protection provided by overcurrent relays on the incoming line to the bus. Additionally. Feeder Protection The most commonly applied protection of feeders is time overcurrent relaying. 1. The instantaneous overcurrent trip on the feeder breaker will not coordinate 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.600 Protective Devices Electrical Manual tive to faults outside the bus zone. 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. separate ground fault protection may be provided. Figure 600-25 shows a typical bus differential scheme. This situation might occur on an incoming line where current only should be flowing to the plant. This time period must be compared to the short circuit heating limit curve for the cable. A residually connected 50/51N relay is often used in lieu of the 50/51 GS. 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. If the feeder is protected by a time delay relay. The curves depend on the wire size and the insulation of the cable. 3. A directional overcurrent scheme is applied when it is desirable to have relays detect overcurrent conditions in one direction only.Electrical Manual 600 Protective Devices 2. Fig. When plotted on the same time-current coordination curve. Also shown on this figure is a ground fault relay 50/51 GS. it will allow the short circuit current to persist for a short time. or by a circuit breaker set at a maximum of six times the ampacity of the feeder. The instantaneous Device 50 should not be used if there are downstream devices requiring coordination at the same voltage level. Figure 600-19 (located at the end of this section) shows typical short circuit heating limit curves. the short circuit heating limit of the cable must be considered for protecting feeders. 600-26 Typical Feeder Protection Scheme In addition to overcurrent protection. Typical Overcurrent Schemes Figure 600-26 shows a typical overcurrent scheme suitable for low voltage feeders. A reverse in current direction would indicate a fault or abnormal condition. the overcurrent relay curve should lie below and to the left of the short circuit heating limit curve. Chevron Corporation 600-45 November 1991 . This point is usually shown on the time-current coordination curve. For more information. it is necessary that their settings be high enough to allow the transformer inrush current that occurs on energizing the transformer. “Transformers. as illustrated in Figure 600-27.” NEC Article 450-3 prescribes the required minimum overcurrent protection requirements for transformers both above and below 600 volts. for delta-wye transformers. see Section 800. the effect of external secondary faults on delta-delta and delta-wye transformers must be considered. Transformer Inrush When protecting a transformer with overcurrent protection devices. external faults.109. As a result. which minimize the possibility of feeder damage due to overheating during a fault. Transformers connected to overhead lines should also be protected by surge arresters to prevent insulation failure due to lightning overvoltage impulses. Short Time Withstand Capability Transformers must also be protected according to their short time withstand capability. Phase-to-neutral and phase-tophase faults on the secondary side of a delta-wye transformer will not have the same per-unit current value on the primary side. Pilot Wire Relays Pilot wire relays use a form of differential relaying that provides high speed fault protection for feeders. 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. This difference is due to the deltawye connection. and in ANSI C57. 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. See Figure 600-16 for an example showing transformer magnetic inrush on a timecurrent coordination curve. Primary/Secondary Devices If a transformer is protected by both primary and secondary overcurrent protective devices. Transformer Protection Transformers should be protected against internal faults. When applying the transformer short time withstand curves for the purpose of relay coordination. and overload conditions. The system compares line currents at both ends of the line and trips if there is a significant difference.600 Protective Devices Electrical Manual 4. This inrush current is usually considered to be eight to 12 times the transformer full load current for 0. These withstand curves are found in the IEEE Red Book. and may prevent the primary relay from responding quickly enough to prevent transformer damage. particularly if the primary device is a November 1991 600-46 Chevron Corporation .1 second duration. The inrush point should fall below and to the left of the curve of the transformer primary protective device. The advantages of pilot wire relaying are high speed and sensitivity. Buff Book. it is desirable that they coordinate. 600-27 Effect of External Secondary Faults on Transformer Protection and Coordination Requirements (From Procedure for an Overcurrent Protective Device. by Curd & Curtis. Company. January 1979.Electrical Manual 600 Protective Devices Fig.) Chevron Corporation 600-47 November 1991 . Courtesy of Square D. The relay action is instantaneous. if the primary instantaneous relay is set above the maximum secondary asymmetrical fault value but below the primary maximum asymmetrical fault value. Overload Protection Transformer overload protection is usually provided by an overcurrent device in the secondary main breaker or by a secondary fuse of the transformer. mounted on the transformer. the CTs on the primary and secondary of the transformer have different ratios to match the transformer turns ratio. it is quickly detected and cleared. Figure 600-29 shows typical protection for a transformer with medium voltage windings. If a fault occurs on a bus fed by the secondary of a transformer. The transformer differential relaying compares the primary transformer current with the equivalent secondary current. Figure 600-30 is a coordination curve showing the primary and secondary protec- November 1991 600-48 Chevron Corporation . If the fuses blow. Internal Faults There are several means of protecting against internal transformer faults. On large transformers. To accomplish this. it may provide some degree of external fault protection. Upstream primary overcurrent and ground fault protective relays will also provide a degree of protection against internal transformer faults. Device 63 is usually specified on large oil-filled transformers (1000 kVA). When using transformer differential relaying on transformers of 2 MVA or larger at 15 kV and above. it is preferable for the secondary breaker to trip rather than for the primary fuse to blow. detects a sudden pressure increase inside the transformer due to an internal fault and trips the primary circuit breaker. An instantaneous overcurrent relay may be used in combination with a time overcurrent relay on the transformer primary protection and still provide coordination with the transformer secondary overcurrent device. but may be too slow for some low-level internal faults. Depending on the extent of the zone covered by the differential relaying. an embedded winding thermocouple or oil temperature thermometer (Device 49) can be used to alarm or shut down when insulation temperature limits are exceeded. This system includes the transformer and a surrounding zone which may also include some of the transformer feeder cable. One of the best methods of protecting large transformers against internal faults is to use transformer differential relaying (Device 87T). 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. A fault pressure relay (Device 63). thereby minimizing damage to the transformer and reducing costly repairs. If there is an internal fault.600 Protective Devices Electrical Manual fuse. Examples Figure 600-28 shows the typical protection for a small transformer. 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. This is demonstrated in the Case 1 example of relay coordination illustrated in Figure 600-16. It does not have to be coordinated with other relays. Notice too that the transformer inrush point is plotted and lies below and to the left of the primary overcurrent relay. Motor Protection NEC Article 430 provides extensive. motors should be protected against the following hazards: 1. It is set high enough not to respond to secondary faults. a 16% current margin has been left between primary and secondary relay curves (to insure selectivity). Unshifted curves can be obtained from the IEEE Red Book. detailed information about the requirements for motor protection and installation. Medium and Low-Voltage Windings Fig.86 per unit results in a primary current of 1.Electrical Manual 600 Protective Devices tion of a transformer. Fig. The pickups of the two relays are set to meet the requirements of NEC Article 450-3.0 per unit. Electrical – Faults in windings and associated circuits Chevron Corporation 600-49 November 1991 . 600-29 Recommended Minimum Protection for Transformers 750 kVA and Above. Since a secondary line-to-line fault of 0. MediumVoltage Windings Since the transformer is a delta-wye. 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. 600-28 Recommended Minimum Protection for Transformers 2500 kVA and Below. the short time withstand curve has been shifted to the left to 58% of its unshifted value to protect against line-to-neutral faults. 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. In general. 600-30 Example of Transformer Protection Coordination Curve – – – – – – – – – 2. or even desirable. the cost of motor repair or replacement. and the cost of motor downtime. 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). 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 Mechanical – – – Bearing and lubrication failures Loss of ventilation Excessive vibration It is not always possible. The cost of motor protection must be weighed against the probability of a failure occurring. 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 November 1991 600-50 Chevron Corporation .600 Protective Devices Electrical Manual Fig. Starter manufacturers have standard tables to help select appropriate overload heaters and circuit breakers or motor circuit protectors supplied with the starters. accelerometers. Vibration Instrumentation On motors of 1000 hp and larger. Many of these functions may be combined in solid-state multi-function relays which are specifically applicable to motor protection. as might be the case with a multi-function relay failure. Figure 600-31 is a guideline for desirable protection functions for motors based on size and voltage.15 Motors with temperature rise 40°C All other motors Maximum Trip Current 125% 125% 115% 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. When the temperature of the heaters rises due to excessive motor current. See ELC-DS-597. The instrumentation (consisting of either bearing-housing mounted velocity probes. NEC Article 430-32 requires that the overload relays be set to trip at. this causes a bimetallic switch in the overload relay to change state. Sometimes melting-alloy overload relays are used instead of the bimetallic type (see Section 635 above). for the sizes of motor circuit protectors or manufacturers’ literature. Motor starters for motors above 1500 hp usually use circuit breakers rather than fuses. vibration instrumentation is normally required. Motor Control Center Specification Data Sheet. Their sizing is based on the full load current of the motor. 2. The motor circuit protector provides fault protection for the motor (less than 250 hp) 1. Motor Category Motors with Service Factor 1. These multi-function relays are available for use for motors in conjunction with fused medium voltage starters. Chevron Corporation 600-51 November 1991 . A motor circuit protector is a circuit breaker with an adjustable instantaneous magnetic trip. With discrete relays. These relays are extremely versatile and may have 15 or more functions to protect the motor. If one of the discrete relays fails. tripping the motor. or less than. Solid State Multi-function Relay Large motors and motors at voltages exceeding 600 volts require more extensive protection. 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. or non-contacting shaft vibration probes) monitors motor vibration and provides a signal to shut down the motor if the vibration exceeds specified limits. all protection is not lost. other discrete relays provide backup protection. Above 1500 hp it is recommended that discrete relays be used for each function (instead of a single multi-function relay). These relays have heaters in series with the motor conductors. the following multiples of full load current.Electrical Manual 600 Protective Devices starter. ) November 1991 600-52 Chevron Corporation . 3-7-74.600 Protective Devices Electrical Manual Fig. 600-31 Application Table for Motor Protective Devices (Used with permission from “Plant Engineering Magazine”. Electrical Manual 600 Protective Devices Figures 600-32 through 600-35 show typical relaying schemes for protecting motors of different sizes and voltages. Fig. 600-33 Recommended Minimum Protection for Induction Motors 1500 hp and Above Chevron Corporation 600-53 November 1991 . These figures include recommendations for specific considerations for motor protection. 600-32 Recommended Minimum Protection for Induction Motors below 1500 hp Fig. 600-34 Recommended Minimum Protection for Brushless Synchronous Motors. below 1500 hp Fig. Medium-Voltage. 600-35 Recommended Minimum Protection for Brushless Synchronous Motors 1500 hp and Above November 1991 600-54 Chevron Corporation .600 Protective Devices Electrical Manual Fig. On larger motors. A synchronous motor starts as an induction motor using an auxiliary squirrel cage known as the Amortisseur winding. On small low voltage motors (less than 250 hp) fault protection (Device 50/51) is usually provided by motor circuit protectors or fuses. the RTDs are backed up by a special time overcurrent relay which is set so that its characteristic is below and to the left of the motor thermal limit curve supplied by the manufacturer. 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. only on low resistance grounded systems. The Amortisseur winding will be damaged. on large motors. When a motor starts. 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). As the motor accelerates. When the motor is up to speed. Closely related to thermal protection. The characteristic curves for these relays lie below and to the left of the thermal limit curve. it will continue to draw locked rotor current with a high probability of sustaining damage unless it is tripped off the line. These fused starters usually have CTs connected to a ground sensor circuit which trips the starter on a ground fault.Electrical Manual 600 Protective Devices The following sections briefly discuss some of the protective devices and schemes for motors. Locked Rotor Protection. On larger motors (up to about 1500 hp) fault protection may be provided by fused medium voltage starters. If the motor binds mechanically and does not accelerate. Synchronous motors and generators require loss of field protection. resistance temperature detectors (RTDs) embedded in the stator windings provide a more direct indication of insulation temperature. the rotor field is energized and the rotor is pulled into synchronism. this device warns of high temperature. In larger motors. If the field is lost while under load. Thermal protection (Device 49) is one of the most important protective functions for a motor. Thermal Protection. the fault protection (Device 50/51) is usually provided by individual phase overcurrent relays and instantaneous overcurrent relays which control circuit breakers. See Figure 600-17 for an example. Special time overcurrent relays provide locked rotor protection for large motors. the current deceases to normal. 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. This current significantly increases the temperature of the motor winding. Overload relays provide locked rotor protection on small motors. since the Amortisseur Chevron Corporation 600-55 November 1991 . The Amortisseur winding is no longer used once the motor reaches synchronous speed. the thermal overload relay provides this function. The temperature of the insulation of a motor determines the life of the motor. locked rotor protection is often provided by the same relays as overload protection. In many cases. unless tripped off the line by a protective device. On larger motors. but induction motors do not. yet allow the motor time to accelerate and run without being tripped off the line. it draws locked rotor current. In small motors. Loss of Field Protection. the motor slows down and again tries to run on the Amortisseur winding. Normally it is recommended that a 50G ground sensor relay be provided on large motors for ground fault protection. The fuses provide the phase fault protection. Fault Protection. Incomplete Sequence Protection. Generator protection is beyond the scope of this discussion. The relay is usually blocked during motor acceleration and enabled after the motor has reached synchronous speed. Overvoltage Protection. This condition usually is detected by a power factor relay (Device 55). If the motor does not accelerate to speed and the starter does not complete its sequence within the normal amount of time. The power factor relay detects this drop and trips the motor. Undervoltage can cause high currents to flow in motors. Motors served by magnetic starters normally will drop off the line on loss of voltage. On loss of field. Surge arrestors should be used on motors subject to the effects of lightning on overhead lines or switching surges. 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. When running normally. the synchronous motor has a high power factor (usually 0. If they are different. it trips the motor off the line. sometimes as low as 0. November 1991 600-56 Chevron Corporation . This relay also detects loss of phase voltage (due to a blown fuse or an opened winding). Current Balance Protection. Figure 600-17 depicts a typical time overcurrent curve showing motor fault protection and overload protection. this relay (Device 87) compares the current entering each winding of the motor with the current leaving the other end of the winding. Generator Protection. This protection is very rapid and is effective at detecting internal faults and ground faults. The undervoltage relay (Device 27) serves to disconnect the motor from the power source on low voltage or loss of voltage. the incomplete sequence relay (Device 48) shuts the motor down. It sends a trip signal to the circuit breaker.5 to 0. Motors with reduced voltage starting and synchronous motors have multi-step starting sequences which should be completed within a certain amount of time. Motor Differential Protection. Switching surges and lightning can cause voltage surges which may endanger motor insulation. Like the other forms of differential protection.6 lagging. Another method of detecting loss of field is to monitor field current and trip on loss of field current. the power factor drops.8 leading to 1. See ANSI/IEEE 242 and “Applied Protective Relaying” for more information on generator protection. Undervoltage Protection. The power factor relay is the preferred method. Unbalanced currents in motors can cause severe overheating for small amounts of voltage unbalance.600 Protective Devices Electrical Manual winding is not built for continuous full load operation.0). Device 46 compares the three phase currents and trips the motor off the line if the difference reaches a specified setpoint. Unless special provisions have been made. Some fuses respond to fault currents more rapidly than the fastest-acting circuit breakers. (The tendency with a breaker is simply to reclose it in the hope that the problem has “gone away. a three-phase motor could run single-phased long enough to overheat and be damaged. they are maintenance-free and do not require periodic checking. A single one may blow. 641 Advantages and Disadvantages of Fuses The advantages and disadvantages of fuses over circuit breakers are discussed below. • • • • • Chevron Corporation 600-57 November 1991 . Fuses combine sensing and interrupting elements in one unit. Good design practice sometimes dictates a mix of circuit breakers and fuses. Fuses must be replaced after they have blown. This problem is avoided with circuit breakers. The IEEE Buff Book is a good source of information. with no moving parts. Blown fuses generally must be replaced by an electrician. Replacing fuses is more hazardous to personnel than resetting a circuit breaker. Thus. 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. Initially fuses are less expensive. A blown fuse provides more incentive for an electrician to correct the cause of a failure than does a tripped circuit breaker. removing power in an unbalanced manner. Stocks of replacement fuses must be maintained. Fuses generally require less space than circuit breakers. Advantages • • • • • • Fuses are mechanically simple.”) Disadvantages • Fuses are single-phase devices. 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.Electrical Manual 600 Protective Devices 640 Fuses There are two major types of fuses: current-limiting and noncurrent-limiting. Maximum peak let-through current. L. i. See Figure 600-36. K.e. The value of current that can flow through the fuse indefinitely.. Frequency rating.600 Protective Devices Electrical Manual 642 Design Features Low voltage (600 volt) fuses are designated by classes: G. J. UL standards specify the following design features and definitions. The instantaneous peak value of current through the fuse during the time that it is opening a circuit. These are curves with time plotted on the y-axis and current on the x-axis. Interrupting rating. There are two curves for each fuse—one for minimum melting time and one for total clearing time. giving the appearance of a band. For each classification. This correction is necessary because the dielectric strength of air decreases with increases in elevation. The maximum value of current that the fuse is capable of safely interrupting. The amount of thermal energy developed throughout the entire short-circuit path during the total clearing time. the designated voltage of a circuit in which the fuse can be used safely. Voltage rating. both their continuous-current ratings and their interrupting ratings must be reduced by a correction factor obtainable from Table 1 in ANSI/IEEE C37. TCCs are required to coordinate circuit protective devices. Manufacturers provide curves necessary to modify the TCCs to account for thermal preloading and high ambient locations of fuses. Another consideration when coordinating fuses is that the minimum-melting curves are determined by the manufacturer under the conditions of no initial load current. comprised of melting and arcing times. and others. 644 Miscellaneous Considerations When fuses are used in equipment at elevations above 3000 feet. The designated frequency of the operating voltage of a circuit in which the fuse can be used. November 1991 600-58 Chevron Corporation . and forming the clearing characteristic of the fuse. The area between the curves is usually cross-hatched. Current rating. H. Maximum clearing thermal energy. 643 Time-Current Curves Manufacturers produce time-current curves (TCCs) for fuses. The voltage at which the fuse is intended to be used.40. by D. The sand cools and absorbs the vaporized silver when the fuse blows. Heat produced by long-duration overloads damages fuses which are not selfprotecting. of all circuit elements is high enough to withstand this arc-voltage surge (which might be twice the system voltage). 12 ed/1987.008 seconds) if the SCC is in the CL range of the fuse. or impulse withstand rating. 600-36 Typical Current-Limiting Fuse Characteristics. Fink & W. by definition. Beatty. 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 most common type of current-limiting fuse is the silver/sand fuse. See Figure 600-37. which has a silver element in a sand medium (see Figure 600-38).Electrical Manual 600 Protective Devices Fig. The silver element is currentresponsive. The engineer designing a system must ensure that the basic impulse insulation level (BIL). open and clear (total clearing) the flow of short-circuit current (SCC) in less than 1/2 cycle (0.) 645 Current-Limiting Fuses Current-limiting (CL) fuses. Used by Permission of McGraw Hill. The interrupted current is considerably less than that which would flow if the fuse were replaced by a non-CL device. Two Different Types Shown (From Standard Handbook for Electrical Engineers. 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 Chevron Corporation 600-59 November 1991 . Inc. Fink & W. Chance Company) (Courtesy of A. B. self-protective).. 12 ed/1987. Chance Co. Some manufacturers use patented techniques to manufacture fuses that they claim to be “fatigue-proof” (i.600 Protective Devices Electrical Manual Fig. by D.) and unreliable as a system protective device. 600-37 The Current Limiting Action of Current-limiting Fuses (From Standard Handbook for Electrical Engineers. 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. More- November 1991 600-60 Chevron Corporation . 600-38 Typical Current-limiting (Silver-Sand) Fuse (Copyright by.) Fig. and not to the first portion of current that actually does flow (let through by the fuse). Inc.e. Used by permission of McGraw Hill. It is prudent however to replace all three fuses in a threephase system if one fuse blows. and reprinted with permission of A. Beatty. 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. B. A self-protecting fuse is not damaged by moderate overloading. 600 V and Less Underwriters Laboratory (UL) recognizes and permits the labeling of only class G. 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). By the nature of their fast action. This fuse is designed to interrupt faults reliably at 200% to 264% of the fuse’s continuous current rating. J. when a fault persists for 2-4 cycles. For UPS-fed 120-V branch circuits. UL Class T (300 V and 600 V) and Class J (600 V) fuses are recommended. is the general-purpose E-rated CL fuse. CC. the system voltage collapses. total arc clearing time. Medium Voltage CL Fuses Because of the highly specialized action of CL fuse’s. The first type is the original “pure” fuse. Chevron Corporation 600-61 November 1991 . Interrupting extremely high levels of fault current is the real forte of CL fuses. Normally they are not assigned actual current ratings. At 200 amperes. can ride through a shorted branch circuit without jeopardizing the entire system. however. A particular UL classification does not indicate unique performance or time-current characteristic. The minimum fault current these fuses can respond to is the continuous current rating. 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. current-limiting fuses are not capable of protecting against low levels of fault current. 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. the R rating multiplied by 100 approximates the ampere level that will cause the fuse to melt in about 20 seconds. Generally. and CL characteristics. or a “backup” fuse because it offers backup protection against large faults. Low Voltage CL Fuses . dimensional characteristics are unique for a particular class of fuse.46). A second type. This fast clearing of faulted branch circuits is especially important for critical loads served by Uninterruptible Power Supply (UPS) systems. but information is provided about typical melting time. R. now called an R-rated fuse (ANSI C37. two variations of the “pure” CL fuse has been developed for medium voltage circuits. Normally.Electrical Manual 600 Protective Devices over. developed to handle low-level and high-level fault currents. L. 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 deteriorating. Less important faults are handled by other protective devices in series with the backup fuse. Lesser currents must be interrupted by some other overload protection device. CL fuses are capable of not only limiting the damage normally resulting from a short circuit but also maintaining system voltage to voltage-sensitive equipment. and T fuses as current limiting. Systems designed properly with sufficient fault duty to operate the CL fuse in its current-limiting range. (See Section 124 System Design). . 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. ed. Those with an asterisk (*) are included in this manual or are available in other manuals. November 1991 600-62 Chevron Corporation . ed. Fink. 651 Model Specifications (MS) There are no specifications related to this guideline. 652 Standard Drawings There are no standard drawings related to this engineering guideline. 1987).L. Data Guides (DG) and Engineering Forms (EF) There are no engineering forms related to this engineering guideline. IEEE Recommended Practice for Protection and Coordination of Industrial Power Systems *API RP 14F. Electrical Power System Device Function Numbers ANSI/IEEE Standard 141.2. Industrial Power Systems Handbook (McGraw-Hill: NY. 1982). Donald G. Distribution Enclosed Single-Pole Air Switches. 1977). and Wayne Beaty. Westinghouse Electric Corporation (Coral Springs.. Fla. 650 References The following references are readily available. IEEE Standard Dictionary of Electrical and Electronics Terms Beeman. Applied Protective Relaying. and Accessories ANSI/IEEE C37. 654 Other References ANSI/IEEE C37. Design and Installation of Electrical Systems for Offshore Production Platforms ANSI/IEEE Standard 100... Donald. J.600 Protective Devices Electrical Manual Smaller rated fuses become current limiting at progressively lower fault levels. Service Conditions and Definitions for High Voltage Fuses. Fuse Disconnecting Switches. Blackburn. eds. Standard Handbook for Electrical Engineers (McGraw-Hill: NY... IEEE Recommended Practice for Electric Power Distribution for Industrial Plants ANSI/IEEE Standard 242. 653 Data Sheets (DS).40. Switchgear and Control Handbook (McGraw-Hill: NY.Electrical Manual 600 Protective Devices Smeaton. Chevron Corporation 600-63 November 1991 . Robert W.. 1977). ed.. 700 Switches Abstract This section describes and compares five types of switches used in power circuits: disconnect switches. The switches are compared on the basis of their interrupting capabilities. Data Guides (DG) and Engineering Forms (EF) Other References 700-9 700-11 700-13 700-13 700-4 700-4 Page 700-2 Chevron Corporation 700-1 September 1990 . Contents 710 711 712 720 730 731 732 733 734 735 736 740 750 760 770 771 772 773 774 Introduction Scope Switches—An Overview Disconnect Switch Load Interrupter Switch Air Load Interrupter Switches Metal-Enclosed Load Interrupter Switches Oil Interrupter Switch Air Interrupter Switch vs. load interrupter switches. Oil Interrupter Switch Interrupting Power to Transformers Fused Load Interrupter Switch Low Voltage Safety Switches Automatic Transfer Switches Oil Fused Cutouts References Model Specification (MS) Standard Drawings Data Sheets (DS). and oil fused cutouts. safety switches. Fusing is discussed for all of the above except for the disconnect switch. automatic transfer switches. These are qualifying terms indicating the number of open and closed positions of a switching device. A quick-make. The most common function of load interrupter switches is to provide isolation of the unit substation from its incoming feeder. Switches are often referred to as single-pole or multi-pole devices. September 1990 700-2 Chevron Corporation . A single throw device has one open and one closed position only. quick-break. Disconnect switches usually are operated when circuits are de-energized or when the interrupted currents are low. Not all switches discussed in this section are quick-make. it will conduct electricity and when it is opened. Load interrupter switches (see Figure 700-2) are three-pole devices associated with unit substations supplied from the primary distribution feeder. “Multi-pole” usually means two or three poles. When a switch is closed. A disconnect switch (see Figure 700-1) is often used to isolate a circuit or equipment from a source of power. Switches are often referred to as “single throw” or “double throw” devices.700 Switches Electrical Manual 710 Introduction 711 Scope This 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 Overview A switch is a device which opens and closes a circuit. A multi-pole device is often referred to as a gang or group-operated device. it will not conduct electricity. the poles are coupled in such a manner that they mechanically operate together. A double throw device can change the circuit connections by utilizing either one of its two closed positions. The switch has springs that cause the contacts to move very quickly once operation of the switch is initiated. In a multi-pole device. A pole is that portion of a switch associated with a separate conducting path. quick-break switch is one in which the operating speed of the switch mechanism is independent of the speed of the handle movement. The switches discussed below are used primarily on distribution feeder circuits. Electrical Manual 700 Switches Fig. 700-2 Load Interrupter Switch (Courtesy of S & C Electric Company) Chevron Corporation 700-3 September 1990 . 700-1 Disconnect Switches (Courtesy of S & C Electric Company) Fig. If a disconnect switch is opened under load. The main blade opens first. Load interrupter switches can be air or oil-immersed and are usually manually operated. Air load interrupter switches have primary (blade) and arcing (secondary) contacts. They have close and latch current ratings which specify the maximum fault current into which they can close. Its function is simply to disconnect equipment after all loads have been disconnected by other means. an arc could be drawn between the blade and the stationary contact. 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. The close and latch current is the current September 1990 700-4 Chevron Corporation .700 Switches Electrical Manual 720 Disconnect Switch Disconnect switches are used to isolate equipment or a section of line from a feeder. The hot arc produced could damage the switch and injure personnel. In oil-immersed load interrupter switches. This electrical isolation makes the area safe for repairs. A disconnect switch must not be opened under load. quick-break. a no-load disconnect switch is implied. Interlocking is generally provided to prevent operation when the switch is carrying load current. inspections or modification after the circuit has been grounded. In other load interrupter switches. when reference is made to a disconnect switch. it is recommended that manufacturers’ standards be utilized. It is not designed to interrupt load current. A number of disconnect switch types are available. there are only main blades and arc chutes. disconnecting the circuit. They are available in ratings up to 4000 amperes interrupting capacity at 600 volts and 1200 amperes at 5 kV and 15 kV. Air interrupter switches are equipped with arcing horns (pieces of material in which the arc forms when a circuit carrying current is opened). the load must be disconnected by some other means such as a circuit breaker. 730 Load Interrupter Switch The 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 disconnecting the circuit. A disconnect switch is designed to carry normal load current continuously and abnormal or short circuit current for a specified short interval. A no-load disconnect switch is an air-break. Each is designed to perform its circuit isolation function in a specific fashion. The secondary contact of the interrupter switch then lengthens and cools the arc until it extinguishes. a feeder from a substation. or a substation from a transmission line. Load interrupter switches are quick-make. This switch is sometimes designed to interrupt the small capacitive charging current of cables or transmission lines and the magnetizing current of transformers. tests. quick-break. or even between the blade and other conductors or ground. Generally. These switches have blades and stationary contacts. It is not designed to interrupt current. hand-operated switch. Disconnect switches typically are not quick-make. To purchase disconnect switches. One type of disconnect switch is shown in Figure 700-1. The two switches can be key-interlocked to prevent being closed at the same time. single-throw. There are three basic types of air interrupter switches: the single air interrupter switch. A stored-energy-operated device uses springs to open or close the switch. A duplex selector switch consists of two three-pole. the spring is charged as the handle is moved to the open position. 731 Air Load Interrupter Switches An air load interrupter switch is designed to open and close one or more poles with contacts that separate in air. 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). See Figure 700-4. and the selector switch. lines 1 and 2. 700-3 Fused Load Interrupter Switch (Courtesy of S & C Electric Company) flowing when a switch successfully latches.Electrical Manual 700 Switches Fig. or open). The interrupter has a stored-energy (spring) device and can be equipped to operate manually or electrically. air interrupter switches. There is also a window on the front panel for visual inspection of the switch blades. These switches also have short-time current ratings for both momentary (one cycle) and 3-second conditions. the duplex selector switch. Both switches can be designed for manual or electrical operation and are stored- Chevron Corporation 700-5 September 1990 . A switch with a stored-energy mechanism must be properly adjusted so that when the switch is closed it will have complete contact. With a stored-energy device. The two switches may permit four different positions (line 1. The single air interrupter switch has open and closed positions and is usually three-phase. making the speed of opening and closing independent of the speed of the operating handle. line 2. 700-4 Typical One-Line of a Three-Pole Duplex Selector Switch energy-open and stored-energy-closed. two-position (open and closed) air interrupter switch and one three-pole (line 1. Fig. open. A window permits inspection of the switch blades. The interrupter switch is stored-energy open and stored-energy closed and can be electrically or manually operated.700 Switches Electrical Manual Fig. 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. The duplex selector switch is frequently used when two separate power sources feed one load. See Figure 700-5. line 2 and open) to show the position of the switch blades. 700-5 Typical One-Line of a Three-Pole Selector Switch September 1990 700-6 Chevron Corporation . single-throw. line 2) disconnect switch. The disconnecting switch handle has indicating targets (line 1. The interrupter switch is connected in series with the disconnecting switch. A selector switch consists of one three-pole. both of which are mounted in a single enclosure. Indicating targets show whether the switch blades are open or closed. contact an electrical engineer who is familiar with their application (i.. and Model Specification ELC-MS-3944 be used. Fig. 700-6 Metal-enclosed Load Interrupter Switch To ensure proper performance. To purchase 5 kV and 15 kV switches. of manually or automatically closing on faults up to the interrupting rating of the associated fuses Chevron Corporation 700-7 September 1990 .e. Metal-enclosed load interrupter switches typically are installed ahead of a transformer as a primary disconnect means. Data Sheet ELC-DS-3944.Electrical Manual 700 Switches 732 Metal-Enclosed Load Interrupter Switches If metal-enclosed load interrupter switches are being considered. it is recommended that Data Sheet Guide ELCDG-3944. transformer magnetizing currents. The selection requires critical review to ensure that a reliable design is being purchased. and line and cable charging currents Interruption of currents without external arc or flame Visible isolating air gap after interruption Capability. where required. This switch is completely enclosed with sheet metal except for ventilating openings and inspection windows.5 kV. The Electrical Group in Engineering Technology Department) for a list of suitable manufacturers.4 through 34. Metal-enclosed load interrupter switches are available with interrupting ratings of 600 or 1200 amperes for system voltage ratings of 2. metal-enclosed interrupter switches should provide the following features: • • • • • Minimal periodic maintenance requirements Adequate interrupting capability for load currents. See Figure 700-6. 733 Oil Interrupter Switch Oil interrupter switch specifications are not provided in this manual. the oil should be replaced or filtered to remove carbon products formed by arcing. The switch should have an indicating device to show the position (open or closed). 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. the insulating medium. 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. Oil interrupter switches have contacts which open and close under oil. oil could leak out of the enclosure of an oil interrupter switch Air switch contacts are easily accessible for testing (e. 734 Air Interrupter Switch vs. Division 1 or 2 hazardous (classified) areas unless enclosed in NEMA 7 enclosures September 1990 700-8 Chevron Corporation . The switch contacts are immersed in oil and the entire apparatus is enclosed in a steel container. Most handles are provided with holes for padlocking in either the open or closed position. 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. Any barrier must also be interlocked 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. This also prevents energizing while the door is opened (unless there is a protective barrier).700 Switches Electrical Manual • • • Controlled sequence. quick-break mechanism. After several hundred operations. The oil insulates the poles and helps extinguish the arc formed when the switch contacts are opened. Oil Interrupter Switch The 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..g. does not require maintenance. such as temporary or prolonged overload.or oil-filled load interrupter switches. These switches have quick-make. Fig. quick-break features. Fused load interrupter switches consist of an interrupter switch and fuses mounted on a common base. It is recommended that all loads be removed before primary load interrupter switches are opened. Although generally less expensive than circuit breakers. The safety switch is operated with an outside handle. 700-7 Typical Fused Load Interrupter Switch (Courtesy of S & C Electric Company) 740 Low Voltage Safety Switches Safety switches (see Figure 700-8) are used for voltages up to 600 volts and are always enclosed. The configuration shown in Figure 700-7 shows a typical fused load interrupter switch. motor-starting.” These switches are used to both disconnect and protect circuits. and can be fused or unfused. This requires the operator to lock the transformer secondary breaker open before the switch can be operated. Keyinterlocking prevents operation of the switch unless the transformer secondary breaker is opened. or faults in the system.Electrical Manual 700 Switches 735 Interrupting Power to Transformers In many cases the primary switching devices on transformers are air. Short term currents in excess of the continuous current rating of the switch may be caused by events. usually in a metal enclosure. These interrupter switches must not carry full-load currents more than the continuous rating of the switch. Circuit breakers are usually recommended. The handle Chevron Corporation 700-9 September 1990 . 736 Fused Load Interrupter Switch Load interrupter switches are often fused and are referred to as “fused load interrupter switches” or “fused load-break switches. they have protection and system application limitations. that can subject the switch to currents in excess of its interrupting rating. Some safety switches use current-limiting fuses. 700-8 Typical Safety Switch If a motor is protected with a safety switch. Two different types of bolted-pressure September 1990 700-10 Chevron Corporation . The continuous current rating of the safety switch must be at least 115% of the fullload current rating of the motor. the safety switch should be capable of interrupting the maximum starting current of the motor (the locked rotor current). 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.700 Switches Electrical Manual is interlocked so that the enclosure cannot be opened unless the switch is in the open position (or the defeater is operated.) Fig.” Bolted-pressure safety switches have a toggle mechanism for applying bolted pressure to both the hinge and the jaw contacts. The bolted-pressure switch can be applied to 100% of its rating. this switch can be used on some circuits with available symmetrical fault currents of 200. 750 Automatic Transfer Switches Automatic transfer switches are typically used to connect an alternate power source or standby power generation system to the distribution system. 700-9 Typical Sequence for Automatic Switching on a Two Feeder System Chevron Corporation 700-11 September 1990 . When the power fails. These switches can be used with ground fault protection equipment and have contact interrupting ratings of 12 times the continuous current rating. the transfer mechanism automatically transfers the load to the alternate source or system. These switches are most commonly used in commercial buildings.Electrical Manual 700 Switches switches are available.000 amperes. See Figure 700-9 for a typical sequence. 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 quickbreak operations. When used with current-limiting fuses. 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. Fig. The stationary contacts have “arcing contacts” which cause the arc to be extinguished rapidly. the manually operated bolted pressure switch and the electric-trip bolted pressure switch. Both types of bolted pressure switches consist of movable blades and stationary contacts. These two switches differ in that the make-before-break transfer switch transfers from one circuit to another without interrupting the current. 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. If the sources are in phase. and indicating lights.700 Switches Electrical Manual The automatic transfer switch can be programmed to automatically reconnect the load to the preferred feeder when it has been restored. see Section 4. a number of manufacturers provide standard September 1990 700-12 Chevron Corporation . If the contacts of the automatic transfer switch should open during a fault.heating Withstand available short-circuit currents without contact separation for at least 0. and selective-preferential. It is important to coordinate the automatic transfer switch and the overcurrent protection. fails. The three types of automatic transfer switches are non-preferential. Many automatic transfer schemes can be used. 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. The non-preferential type automatically re-transfers the load to the original source only when the alternate source. For more information on specifying an automatic transfer switch with proper ratings. These electromagnetic forces help circuit breakers to open quickly and minimize clearing time of faults. To accommodate the variety of transfer control schemes required.2 seconds Properly interrupt circuits without flashover between the two power sources Some automatic transfer switches include in-phase monitors for transfer between sources. such as timers. These switches are available in ratings of 30 to 4000 amperes. controls. accessories and features. Automatic transfer switches usually are double-throw without overcurrent protection.3 of the IEEE Orange Book (IEEE Standard 446). fixed-preferential. 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. electromagnetic forces are created in the contacts of circuit breakers. designed to withstand high fault currents. Automatic transfer switches. The switch will re-transfer the load to the preferred source upon reenergization. test switches. Automatic transfer switches must satisfy the following requirements: • • • • Close against inrush currents without contact welding Carry full rated current continuously without over. When high fault currents occur. the high fault current could cause arcing and welding of the contacts. This switch is furnished with relays. and critical operating components. Switches rated over 100 amperes are mechanically held and are electrically operated from the power source to which the load is to be transferred. utilize the electromagnetic forces in the reverse manner— keeping the transfer switch contacts closed until the fault has been cleared. while the break-before-make transfer switch interrupts the current flow before transferring to the other source. to which it has been connected. there will be no flashover. This switch will re-transfer the load to the preferred source when it is reenergized after a loss of voltage. consult manufacturer directly. 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. 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). The switch is used for circuits rated up to 15 kV. For applications. 760 Oil Fused Cutouts Oil fused cutouts can be used to disconnect and protect circuits. The fuse in the fused oil cutout usually is of the non-current-limiting type. Oil fused cutouts must not be used to energize circuits because they are not rated to close into a fault. See: Eastern Region Exploration. 771 Model Specification (MS) *ELC-MS-3944 Load Interrupter Switches Chevron Corporation 700-13 September 1990 . Electrical Construction Guidelines for Offshore. They have low short circuit ratings and no “close-and-latch” rating. Oil-fused cutouts differ from the other switches discussed in this section. The interrupter (which is the “cutout”) and the fuses are immersed in oil. an upstream circuit breaker must be used to energize the circuit. Those marked with an asterisk (*) are included in this manual or are available in other manuals. Marshland and Inland Locations for an example of special packaging for 5 kV oil-fused cutouts suitable for corrosive environments. creating an arc below the oil level. 770 References The following references are readily available.Electrical Manual 700 Switches automatic control devices for integration with metal-enclosed load interrupter switches. Land and Production. Instead. when manually operated the speed of the switch is dependent on the speed with which the operator moves the handle. refer to Standard Drawing GF-P99972. A fused oil cutout switch is a combination of a load interrupter switch and fuses. the excessive current melts the fuse. When an overcurrent occurs. Manufacturing Specifications. Kurtz and Shoemaker. C37. The Lineman’s and Cableman’s Handbook (McGraw-Hill. 1986). C37. and Accessories ANSI/IEEE. R.Rated Control Voltages and Their Ranges for High-Voltage Air Switches ANSI/IEEE.Test Code for High-Voltage Air Switches IEEE.71 . and Bus Supports IEEE C37. 100 . Switchgear and Control (McGraw-Hill. C37. and Switch Accessories ANSI.30 .37 .IEEE Recommended Practice for Emergency and Standby Power System for Industrial and Commercial Applications ANSI/IEEE. Industrial Power System Handbook (McGraw-Hill.Loading Guide for AC High-Voltage Air Switches (In Excess of 1000 Volts) ANSI/IEEE.33 . 1987). Bus Supports. Operation and Maintenance of High-Voltage Air Disconnecting and Load Interrupter Switches ANSI/IEEE. W.Standard for Three-Phase. Installation. Donald. and Maintenance of Distribution Cutouts and Fuse Links.32 . Operation. Smeaton. Secondary Fuses.Guide for the Application.34 . C37. Fuse Disconnecting Switches. Data Guides (DG) and Engineering Forms (EF) *ELC-DS-3944 *ELC-DG-3944 Load Interrupter Switch Data Sheet Data Sheet Guide for Load Interrupter Switch Data Sheet 774 Other References ANSI/IEEE. and Application Guide for High-Voltage Air Switches. 1955).Schedules of Preferred Ratings.IEEE Recommended Practice for Electric Power Distribution for Industrial Plants ANSI/IEEE C37. Insulators.Guide for Application.700 Switches Electrical Manual 772 Standard Drawings *GF-P99972 480 Volt Stand-by Power System One-Line Diagram 773 Data Sheets (DS).IEEE Standard Dictionary of Electrical and Electronic Terms Beeman. Manually Operated Subsurface Load Interrupting Switches for Alternating Current Systems ANSI/IEEE. Standard 446 . C37. Standard 141 . Power Fuses. September 1990 700-14 Chevron Corporation .48 . Distribution Enclosed Single-Pole Air Switches. C37.35 .Definitions and Requirements for High-Voltage Air Switches. ” Transformers for relaying (current transformers. The transformer size must first be determined using the guidelines in Section 100. power. design characteristics for specific job applications. It also describes rating considerations (including operating conditions). Contents 810 811 812 813 814 820 821 822 830 831 832 840 841 842 843 844 Introduction Scope Overview Standards and Codes Transformer Types Insulation for Transformers Liquid Insulation Dry Insulation Classes of Self-Cooled Transformers Auxiliary Cooling Typical Cooling Ratings Ratings kVA Ratings Primary and Secondary Voltage Ratings Temperature Rise Altitude 800-9 800-8 800-6 Page 800-4 Chevron Corporation 800-1 September 1990 . “Protective Devices. and control transformers.” 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. “System Design. and quality assurance tests. potential transformers) are covered in Section 600.800 Transformers Abstract This section provides technical and practical guidance for specifying distribution. accessories needed for safe operation. lighting. Dial Type Pressure Vacuum Gage Pressure Relief Diaphragm in Cover Sampling Device Pressure Regulator Provisions for Future Cooling Fans Sudden Pressure Relays Neutral Current Transformer Grounding Resistors and Bushing Current Transformers Grounding Resistors Bushing Current Transformers Surge Capacitors/Lightning Arrestors Shop Testing Economics—Evaluation Factor References Model Specifications (MS) Standard Drawings 800-22 800-21 800-15 800-14 September 1990 800-2 Chevron Corporation .800 Transformers Electrical Manual 845 846 847 850 851 852 860 861 862 863 864 865 866 870 871 872 873 874 875 876 877 878 879 880 881 882 883 884 885 890 891 892 Basic Impulse Level (BIL) Impedance Secondary Circuit Voltage Winding Connections 800-13 Angular Displacement (Nominal) between Voltages of Windings for ThreePhase Transformers Series Multiple Windings Design Characteristics and Their Application (Construction) Voltage Taps Paralleling Transformers Location Painting Termination Tertiary Windings Accessories Liquid Level Gage Fluid Thermometer. Data Guides (DG). and Engineering Forms (EF) Appendices Other References Chevron Corporation 800-3 September 1990 .Electrical Manual 800 Transformers 893 894 895 Data Sheets (DS). 800 Transformers Electrical Manual 810 Introduction 811 Scope This section focuses on the basic information required for selecting. 812 Overview Transformers are primarily used to reduce (or increase) voltage to a level where it can be used to power equipment. 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. “Protective Devices. They are either liquid-immersed or dry. Inc. and IEEE standards. 814 Transformer Types Six types of transformers are described below: distribution. regulating. This ratio also equals the ratio of secondary current to primary current. Transformers are also used to isolate loads from power sources and to accomplish a variety of special functions. “System Design. Dry-type distribution transformers through 1000 kVA three-phase. specifying. power transformers that supply power to a single motor load. control power. Transformers should be labeled by a recognized testing laboratory (usually Underwriters’ Laboratories. Inc.” Grounding transformers are discussed in Section 900. They can be mounted on a pole. 891. auto-transformer. They September 1990 800-4 Chevron Corporation . pad. It should be used along with the Data Sheet Guide when completing the Transformer Data Sheet. 600 volts and below. Foreign-made transformers are built to specific national or IEC standards. and ordering transformers. and networking. (reference documents UL-506. wall. and constant voltage. 813 Standards and Codes Transformers are designed. are discussed fully in Section 100.” Distribution Distribution transformers cover power ranges of 3 to 500 kVA. and tested in accordance with ANSI. API RP 14F. power. and through 167 kVA single-phase. or floor.) in the United States. are designed in accordance with Underwriters’ Laboratories. buck-and-boost. fabricated. and 1561.) NFPA-70 (National Electrical Code). Instrument transformers are discussed in Section 600. ELC-DS-401. NEMA. and applicable governmental regulations should be reviewed prior to selecting transformers.” Captive transformers. These functions include phase shifting. “Grounding Systems. Because the primary and secondary circuits share part of a coil.Electrical Manual 800 Transformers can be installed aboveground or underground (in a transformer vault) and can be installed indoors or outdoors. 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. They are designed for small voltage increments and only for low voltage systems (600 volts and below). they are sometimes used for cubicle and motor space heating and for substation lighting. and startup and shutdown circuits.47 kV bus. greater efficiency. the auto-transformer does have certain advantages over a two-winding transformer: lower cost. Buck-and-boost transformers are connected as auto-transformers and can be used for single and three-phase circuits. Power Power transformers cover power ranges above 500 kVA. and a smaller exciting current. the transformer does not provide electrical isolation between the load circuits and the primary circuits. They are only suitable for compensating for high or low voltage when the available line voltage is constant. The remainder flows directly from the primary to the secondary by means of the shared coil with no electrical isolation. For example. non-ventilated system. For example. however. Auto-Transformer Auto-transformers can be either distribution or power transformers.8 kV bus to a 12. Buck-and-boost transformers are not suitable for solving a fluctuating voltage problem. an auto-transformer requires only a fraction of the power to flow across the electrical isolation by means of an electric field. Buck-and-boost transformers provide a convenient and cost-effective way to match the line voltage to the equipment nameplate rating. The auto-transformer’s primary and secondary circuits share a single coil (two coils connected in series). However. they can be used to reduce a 13. Buck-and-Boost Transformer Buck-and-boost transformers are power transformers that can decrease or increase the voltage level. better regulation. voltage at motor terminals can be corrected by using a buck-and-boost transformer instead of resizing the line. smaller physical size and weight. Chevron Corporation 800-5 September 1990 . Some electrical equipment requires that line voltage be at or near its nameplate rating for efficient operation. They usually are rated up to 15 kVA and are of encapsulated core and cell construction—providing a totally enclosed. They typically are used to step voltage up or down slightly ( ±5%). They can be installed indoors or outdoors. They can be dry-type but more often are liquid-immersed (oil-filled). Oil-filled transformers are recommended for most outdoor installations. relays. Control Power Control power transformers generally supply power to instruments. Oil Insulated The oil-insulated unit is the least expensive of liquid-insulated transformers and is suitable for mounting outdoors or. 821 Liquid Insulation Liquid-immersed transformers include 1) oil insulated. 820 Insulation for Transformers Transformers are insulated by either a liquid or a dry media. and 3) low-flammable liquid insulated. This transformer is frequently called a voltage regulator. durability and high flash point. when enclosed in a vault. indoors. 2) non-flammable liquid insulated (Inerteen or PCB laden Askarel).800 Transformers Electrical Manual See Figure 800-1 for a better understanding of the principle and function of autotransformers. spikes. Mineral oil is recommended for most oil-insulated transformers because of its high dielectric strength. These voltage variations can have damaging effects on sensitive equipment over the long term due to stresses on the power supply components. Fig. 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. 800-1 Auto-Transformer Connection Constant Voltage Transformer Sensitive electronic equipment may be subjected to line transients. surges. and sustained low voltage. September 1990 800-6 Chevron Corporation . A constant voltage transformer can be used to minimize these voltage fluctuations. Low-Flammable Liquid Insulated For indoor installations. For this reason. An alternative to circulating outside air freely through the dry-type transformer is to provide a sealed enclosure in which an insulating gas or vapor is contained. be aware that PCB-filled transformers are still in use at many Company facilities. In general.Electrical Manual 800 Transformers Non-Flammable Liquid Insulated The manufacture of non-flammable (PCB) liquid-insulated transformers in the United States ceased in 1977 as a result of laws and regulations concerning the environmental and health effects of PCBs. 822 Dry Insulation Dry-insulated transformers do not employ a liquid as a cooling or insulating medium. This disadvantage may be compensated for. When replacing or repairing existing transformers. The shell is constructed of a 10-gage. For many offshore applications. Also see EPA regulation TSCA. non-ventilated dry-type transformers are specified. it is recommended that Company facilities replace or detoxify PCBcontaminated transformers. as specified. list less flammable liquids for transformers. The benefit is that repair to the core of the transformer can be performed if necessary without further inspection for PCB purposes. Factory Mutual Research Corp. if necessary. 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). polyalphaolefins. All PCB transformers must be labeled. type 316 stainless steel enclosure rated Chevron Corporation 800-7 September 1990 . Detoxification allows treatment of the unit as a non-PCB transformer. inspected. The law does not allow the repair (removal of the core) of a transformer with greater than 500 PPM concentration of PCB. These include silicones. that is free to circulate from the outside to the inside of the transformer enclosure. and to lower PCB exposure. these less flammable insulation materials are more expensive than mineral oil. handled and disposed of in accordance with strict safety and environmental regulations. and Underwriters’ Laboratories Inc. In either case. and high molecular weight hydrocarbons that have a flash point of at least 300°C.. the surrounding medium acts both as a heat transfer medium and as a medium suitable for either indoor or outdoor installation. by installing surge capacitors and lightning arrestors. “Electric Rule” of 1982 and “Fires Rule” of 1985. Processes are available to chemically treat a transformer in order to reduce the level of PCBs. The dry-type transformer is designed to have the core and coils surrounded by an atmosphere (which may be air). Most 30 kVA and larger dry-type distribution transformers manufactured today are designed with a NEMA Class 220°C insulation system. The primary disadvantage of the dry-type transformer is that the basic insulation level (BIL) is lower than for liquid-immersed transformers. Two agencies.102 for further information on handling PCBs. See ANSI/IEEE C57. self-cooled/forced-air-cooled: Class AFA. Liquid-immersed. Liquid-immersed. self-cooled/forced-air-cooled/forced-air-cooled: Class OA/FA/FA. The most commonly used transformers with auxiliary cooling and their classifications follow: • Liquid-immersed. Liquid-immersed. self-cooled: Class OA. Dry-type. A liquid-type transformer in which the insulating oil circulates by natural convection within a tank having smooth sides.800 Transformers Electrical Manual NEMA 4X. in accordance with NEMA and ANSI test standards (See Appendix D. 830 Classes of Self-Cooled Transformers ANSI standard C57. The insulation system is a vacuum impregnated. integral tubular sides. Class H rated silicone varnish. The FOA rating is intended for use only when both the oil pumps and fans are operating. or detachable radiators. The transformer may be purchased with fans installed or with the option of adding fans later (OA/FFA). Dry-type Self-cooled: Class AA. fans are thermostatically controlled. FA. A dry-type transformer which is cooled by the natural circulation of air. An increased level of fan cooling is provided for increased air flow. • 831 Auxiliary Cooling One way to protect a transformer from overloads is to increase the transformer’s capacity with the use of auxiliary cooling. self-cooled/forced-air-cooled/forced-liquid-cooled: Class OA/FA/FOA. • • • • September 1990 800-8 Chevron Corporation . self-cooled/forced-air-cooled: Class OA/FA.12 lists two classes of self-cooled transformers: • Liquid-immersed. self-cooled/forced-air-forced-liquid cooled/forced-airforced liquid cooled: Class OA/FOA/FOA. A forced-aircooled transformer. corrugated sides. An OA/FA unit is provided with a second stage of cooling by means of an oil pump. is basically an OA unit with fans and requires approximately twice the space needed by an OA transformer. The temperature rise of the completed transformer is specified not to exceed 80°C. The transformer requires from 24 to 36 inches of clearance on all sides for adequate air circulation. A dry-type transformer which has both a self-cooled rating with cooling obtained by the natural circulation of air and a forced-air-cooled rating with cooling obtained by the forced circulation of air. “Minimum Requirements for Dry-Type Transformers”). Typically. In this class there are two stages of fan/pump combinations to enhance cooling. This standard also discusses how to increase the life expectancy of a transformer. Chevron Corporation 800-9 September 1990 . 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. The duration of the overload may be shorter than the time it takes the oil to heat past its rated temperature rise. 800-2 Cooling Ratings for Forced Air/Forced Liquid Percent Rating Increase with Auxiliary Cooling (Over Self-Cooled Rating) 3-Phase(1) 501-2499 2500-11999 12000 & above 12000 & above 12000 & above 12000 & above 501 & above 1st Stage 15% 25% 33 1/3% 33 1/3% 33 1/3% 33 1/3% 33 1/3% 2nd Stage – – – 66 2/3% 66 2/3% 66 2/3% – Self-Cooled 55°C Rating (kVA) Class OA/FA OA/FA OA/FA OA/FA/FA OA/FA/FOA OA/FOA/FOA AA/FA 1-Phase(1) 501-2499 2500-9999 10000 & above 10000 & above 10000 & above 10000 & above 501 & above (1) Add 12% to all self-cooled ratings for 55°/65°C rated transformers 840 Ratings There are various rating categories for transformers. The following ratings allow the transformer to perform efficiently and safely under specified conditions. For instance. A transformer can be overloaded intermittently within limits without physically damaging the transformer or significantly reducing its life expectancy. See ANSI C57. 841 kVA Ratings See Section 100.91 for information on how to calculate the amount and the duration of overload that a transformer can withstand without experiencing a loss of life expectancy. If the transformer is also rated 55°C/65°C. for information on temperature rise. there is an additional 12% increase.” for standard transformer ratings and transformer sizing information. the FA rating for the 2500 kVA transformer is 125% of 112% (140%) of 2500 kVA which equals 3500 kVA. Fig. For example. That is. liquid-filled transformers can withstand overloads of short duration because of the thermal properties of oil.Electrical Manual 800 Transformers 832 Typical Cooling Ratings Typical rating increases for forced-air and forced-liquid transformers are listed in Figure 800-2. “System Design. See Section 843 below. One can specify a high insulation class temperature rating and a low temperature rise to obtain extra life for a transformer. asbestos. Aging (deterioration) of insulation is a function of both time and temperature. Liquid-filled transformers may be specified with a 55°C/65°C rise to permit 100% loading with a 55°C rise. For the purpose of transformer selection. Standard dry-type transformers are divided into three groups for temperature rise specification purposes. glass fiber. Class 185°C limiting temperature insulation system (for temperature rises by resistance through 115°C) with component insulating materials including mica. and other materials with thermal life at 185 °C. and similar inorganic material. or average more than 30°C during a 24-hour period. 3. The temperature rise rating indicates 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 dual rating transformer is recommended for most applications because a 5% increase in transformer cost provides an additional 12% in loading capacity. The temperature rise for dry-type transformers does not necessarily have to be the same rating as the insulation class temperature. 1. 843 Temperature Rise A transformer should achieve a normal life at rated kVA if the specified temperature rise is not exceeded and the ambient temperature does not peak above 40°C. Class 220°C limiting temperature insulation system (for temperature rises by resistance through 150°C) with component insulating materials including silicone elastomer. components operating at the highest temperatures will experience the greatest deterioration. and other materials with thermal life at 220°C. and 112% loading at the 65°C rise. 2. “System Design” for standard voltage ratings. Therefore. asbestos. 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.800 Transformers Electrical Manual 842 Primary and Secondary Voltage Ratings Standard nominal and maximum system voltages are included in manufacturers’ literature in compliance with ANSI C84. Class 150°C limiting temperature insulation system (for temperature rise by resistance through 80°C) with component insulating materials including mica. September 1990 800-10 Chevron Corporation . See Section 100. Since temperature distribution is not uniform. the hot spot temperature is very important for determining transformer aging. 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. glass fiber. asbestos glass fiber. mica. the primary and secondary voltages are set by the system design.1. 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 transient condition. and because the air becomes less dense at higher altitudes. For quick approximation. 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 C57. The BIL is dependent on voltage class.Electrical Manual 800 Transformers Ambient temperature influences the normal life expectancy of transformers. 844 Altitude Effects of Insulation and Temperature at High Altitude Insulation and temperature rise ratings of transformers are valid up to an altitude of 3300 feet. OA/FA/FA) and forcedliquid-cooled (FOA. However. The rated load of the forced-oil-cooled transformer can be increased by 0. Chevron Corporation 800-11 September 1990 . The percent increase or decrease for the sealed. Higher than standard BIL ratings are available but are more expensive. ANSI recommends that a 5°C margin be added to the actual average ambient temperature before derating or increase rating factors are applied. self-cooled transformer can be increased or decreased by 0. A transformer primary will have a different BIL rating than the secondary unless both voltages are in the same voltage class.12 and provide a derated transformer that meets the kVA requirements. ventilated. See ANSI C57. self-cooled transformer is 0. the rated load of an oil-insulated self-cooled (OA) transformer should be reduced by 1.75% per degree C if it operates below the average ambient temperature of 30°C. The rated load for forced-air-cooled (OA/FA. 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. the manufacturer will derate the transformer per ANSI C57. Transformers depend upon air for dissipation of heat losses.6% for each degree C it operates above or below 30°C. 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.12 for more information on temperature rise.4% per degree C. Conversely. 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. For a specified kVA rating and altitude.92 is the guide for loading mineral-oil-immersed power transformers. Dry-type transformers usually have lower BIL ratings than liquid-filled transformers. The rated load for a dry-type. respectively.96 covers loading of dry-type distribution transformers. transformers installed at 3300 feet and higher must be derated. ANSI C57.5% for each degree C it operates above the average ambient temperature of 30°C. Standard BIL values for various nominal system voltages are listed in Figure 800-3. .20 12.9 26.0 Power 45 60 75 75 95 95 110 110 110 110 110 150 150 200 200 250 250 350 350 350 450 550 650 750 Distribution 30 45 60 60 75 75 95 95 95 95 95 150 150 200 200 250 250 350 350 350 Dry Type 10 20 30 30 30 30 60 60 60 60 95 95 110 125 150 846 Impedance Impedance is usually expressed as a percentage value and is determined by the internal characteristics of the transformer (i. 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) 0.60 2.8 46.800 Transformers Electrical Manual Fig.4.0 138.12 — 0. Because of cost.0 66.80 14. core loss.0 230.40 4. 43.40 16.16 4.90 7.0 115.0 67.4 34.e. it may be desirable to install transformers with greater than standard September 1990 800-12 Chevron Corporation .0 161. However.20 13.00 12.0 69.80 6. resistance.5 22. the usual practice is to accept manufacturers’ standards.47 13. and reactance of windings). wye-delta. “System Design. “System Design. The larger the impedance value of the transformer. 852 Series Multiple Windings Series multiple windings consist of two similar (multiple) coils in each winding that can be connected in series or parallel. Refer to Section 100. If the transformer is connected delta-wye.” for typical manufacturers’ impedance values. delta-delta. could impair the performance of. “Paralleling Transformers.” for a comprehensive discussion about the selection of different connections. The impedance of the transformer causes secondary voltage to decrease as the load increases. “System Studies and Protection. there is no angular displacement.” for an explanation of differential relaying). and delta-wye. Attention should be given to equipment voltage requirements when heavily loading a transformer. see Section 200. and reduce the production from the utilization equipment. 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.” Angular displacement is also important when selecting current transformer connections for differential relaying on transformers (See Section 200. such as primary Chevron Corporation 800-13 September 1990 . or to select a transformer with lower than standard impedance to aid motor starting by reducing the voltage drop. 847 Secondary Circuit Voltage The secondary voltage is determined by load characteristics.” To understand the effects of impedance on short-circuit duty. “System Studies and Protection. equipment availability and plant preference. Transformers with series-multiple windings are designated with an “X” or “/” between the voltage ratings. 850 Winding Connections The typical winding connections for three-phase transformers are the wye-wye. For information on voltage drop see Section 134. “Feeder and Branch Circuit Systems. combined with the drop due to cable resistance. the current transformers for differential relaying must be connected wye-delta (primary CTs connected wye and secondary CTs connected delta). Angular displacement is of concern when connecting transformers in parallel. Consult Section 100. For the delta-delta and wye-wye transformers. This arrangement provides the differential relay with in-phase current from the primary and secondary sides and prevents nuisance tripping on external faults. the delta-wye or wye-delta transformer has a 30 degree angular displacement.Electrical Manual 800 Transformers impedance to limit the short-circuit duty on secondary switchgear.” and the appendix on the MVA method. This voltage drop. the greater the voltage drop during heavy loading. See Section 862. However. ” If the series multiple winding is designated by an “X. 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. or 240 with a 120-volt midpoint. The automatic load tap changer automatically provides additional voltage adjustment in incremental steps with continuous monitoring of the secondary voltage. manually adjustable no-load voltage taps are adequate. If tap changing under load is required.. and 4) the percent impedance of the transformers should be within 10% of each other (i. if the secondary voltage is 2-1/2% low. With double-ended substations (a lineup of switchgear fed from two transformers). within 0. 3) the phase-to-neutral voltages must have the same ratios. 2-1/2% steps below. the use of the first 2-1/2% below tap will maintain the rated secondary voltage. 240 (series). 860 Design Characteristics and Their Application (Construction) 861 Voltage Taps Voltage taps on a transformer provide adjustment of the number of turns in the windings. but a 120/240 winding can be connected for 120 (parallel). September 1990 800-14 Chevron Corporation .” the winding can only be connected in series or parallel (not both). an automatic load tap changer should be specified. It is recommended to specify two. it is usually acceptable to remove a transformer from service long enough to change the manually adjustable no-load voltage taps. 862 Paralleling Transformers The four requirements for paralleling transformers are as follows: 1) the phase relationships between the high voltage and the low voltage must be the same. This type of tap changer should be specified only for unusual applications when voltage control is critical and must be corrected often. a mid-point is available in addition to the series or parallel connection. For most applications. If required. 2-1/2% steps above and two. The purpose of the fourth requirement is to minimize circulating current and to ensure that the load is shared equally by each transformer.e. Automatic tap changers are significantly more expensive than manually adjustable no-load tap changers.8% for an 8% impedance transformer).800 Transformers Electrical Manual voltage of “240 X 480” or “120/240. No-load tap changers are used very infrequently where an over or under voltage must be corrected. Voltage taps are either of the manually adjustable no-load type or the automatically adjustable under-load type. For example. a 120 X 240 winding can be connected for either 120 (parallel) or 240 (series). These taps can be changed only while the transformer is de-energized. 2) the line-to-line voltage variation must not exceed ±10%. tap settings that allow up to 10-to15% voltage correction in one direction (above or below) are available. These taps are typically provided on the high voltage side of the transformer. As an example. With the “/” designation. If a transformer must be installed in a Class I area. static capacitors (synchronous condensers) for purposes of power factor correction or voltage regulation. 870 Accessories The 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. As an example. 865 Termination It is recommended that the transformer manufacturer supply the connectors and termination (e. Chevron Corporation 800-15 September 1990 . 864 Painting Manufacturer’s standard paint should be allowed unless there are unusual conditions (primarily environmental) or a local preference. 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. 866 Tertiary Windings Three-phase transformers may have tertiary (third) windings to provide voltage for auxiliary power purposes.g. “Hazardous (Classified) Areas. This assures that the transformers will be properly connected with the appropriate hardware.Electrical Manual 800 Transformers 863 Location It is recommended that transformers and associated equipment be installed in unclassified (nonhazardous) locations whenever possible.) The liquid level gage can be specified with contacts to alarm on a low liquid level. 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. An excessively low level of liquid could lead to internal overheating and flashovers. Use of non-standard paint adds to the cost. The tertiary windings are sometimes connected in delta configuration to provide a circuit for the third harmonics of the exciting current.. cable lugs) to match their terminals to the electrical system. may be connected to the tertiary windings. See Section 300.” for specific information on installing transformers in hazardous (classified) locations. 871 Liquid Level Gage The 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. 800-4 Liquid Level Gage (Courtesy of Qualitrol) 872 Fluid Thermometer. Furthermore. depending upon the rate of change of the load and the ambient conditions. This device also indicates the peak liquid temperature with a resettable pointer. The thermal time constant of the liquid is much longer than that of the windings and hence the liquid temperature is more sluggish in its response to changes in loading losses than the windings. common to most liquid-filled transformers. the temperature reading will vary between being too conservative and too pessimistic. measures the temperature of the insulating liquid at the top of the transformer tank. Thus. Dial Type A dial-type fluid thermometer (see Figure 800-5). Fig.800 Transformers Electrical Manual Fig. The thermometer is only partially effective as a protective device because the thermal coefficient of the liquid is quite different from that of the windings. the thermometer reading is related to transformer loading only as long as the loading affects the temperature rise above ambient. 800-5 Dial Type Thermometer (Courtesy of Qualitrol) September 1990 800-16 Chevron Corporation . That is. the fans are turned on at approximately 90% load. Fig. the device resumes its former seating to assure a weather-tight seal. 800-6 Pressure Vacuum Gage (Courtesy of ABB) 874 Pressure Relief Diaphragm in Cover This cover-mounted pressure relief device (see Figure 800-7). These approximate figures vary with design and the actual ambient temperature. The need for pressure limit alarms is less critical when the transformer is equipped with a pressure relief device. This device requires minimal maintenance. When applied to a 65°C rated transformer. 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. but its operation indicator must be manually reset. 873 Pressure Vacuum Gage This gage (see Figure 800-6) indicates the pressure of the gas inside the tank space. and 3) arc-producing faults. It can be equipped with alarm contacts in conjunction with a self- Chevron Corporation 800-17 September 1990 . operates to relieve dangerous pressure buildups from 1) high peak load. 2) long-time overloads. The percent loadings will be somewhat lower at temperatures above ambient. For example. This device can be equipped with alarms to detect excessive vacuum or positive pressure that could deform or rupture the tank. and higher at ambient temperatures below 30°C. After the pressure has been released. fans are usually turned on if the liquid temperature reaches 60°C. The pressure vacuum gage typically has a scale range of ±10 psi and provides a means of continually monitoring the sealed system. It is primarily used to protect the tank that houses the liquid. the switch will operate at loading values of approximately 75% and 115%. not to be confused with the sudden pressure relay described below. a contact is actuated to alarm or to disconnect the transformer. whereas the alarm is given at about 130% rated load.Electrical Manual 800 Transformers Thermometers are usually specified with alarm contacts for providing remote warnings 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. When the temperature reaches 90°C. winding temperature indicators with alarm contacts should be equipped with one to three adjustable contacts that operate at preset temperatures. It is used on transformers with sealed tanks. 876 Pressure Regulator This accessory (see Figure 800-8) automatically maintains a positive-pressure nitrogen atmosphere above the oil. 877 Provisions for Future Cooling Fans Transformers normally are not specified with fans at initial installation. but often should be specified with provisions for future forced air cooling. A pressure relief device is recommended for transformers rated 500 kVA and above.800 Transformers Electrical Manual sealing relay and can be connected so that a remote warning device can be activated. 800-7 Pressure Relief Diaphragm Courtesy of ABB: Transmission and Distribution 875 Sampling Device Sampling devices should be specified for oil insulated transformers. Fig. Sampling devices are usually located on the side of the tank or as a part of the drain valve. moisture. Manufacturers can September 1990 800-18 Chevron Corporation . These devices allow access to the oil so that the oil can be checked for dielectric strength. supplied in cylinders. Nitrogen. and sludge buildup. advising the operator of excessive pressure. 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. Any operation of this relief device that was not preceded by overloading will indicate possible trouble in the windings. Since the operation of this device is closely related to actual faults in the winding. This device is mounted with its main pressuresensing element in direct contact with the gas cushion in the tank of a liquid-filled transformer. 800-8 Pressure Regulation w/N2 Blanketing increase in pressure that actuates the contacts.Electrical Manual 800 Transformers 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. When a fault occurs. The relay then trips the transformer off-line. Chevron Corporation 800-19 September 1990 . Sudden pressure relays are generally recommended for transformer sizes of 5000 kVA and above. faults to ground. and winding-to-winding faults. The relay is designed to be insensitive to gradual changes in pressure due to changing load and ambient conditions. This device detects internal shorted turns. a sudden increase in gas produces an abrupt Fig. one should consider all risks involved in re-energizing a transformer that has been tripped off-line by a sudden pressure relay. and energizes the relay. 878 Sudden Pressure Relays A 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. 800-10 Bushing Current Transformer Courtesy of ABB: Transmission and Distribution September 1990 800-20 Chevron Corporation . 800-9 Sudden Pressure Relay Courtesy of ABB: Transmission and Distribution 879 Neutral Current Transformer A bushing current transformer (see Figure 800-10) installed on the neutral bushing is required on a grounded transformer that has a ground fault relay.800 Transformers Electrical Manual Fig. This feature provides the required signal to operate the protective relay. Fig. 5 MA. Lightning arrestors limit the overvoltage by providing a conducting path of relatively low impedance to ground. Arrestors have a single gap. 882 Bushing Current Transformers Bushing current transformers (see Figure 800-10) installed on low-voltage and/or high-voltage bushings. Typically.” for further information). they should be protected by surge arrestors. or several gaps in series. This low impedance to ground must not exist before the overvoltage appears. the surge arrestor should be mounted directly on. It is recommended that surge arrestors be installed on the primary of all substation transformers fed by uninsulated overhead lines. whereas surge capacitors alter the shape of the steep incoming wavefront. and quality of manufacture. The three classes of arrestors are: station. intermediate. and distribution class arrestors are applied to small dry-type and oil-filled distribution transformers. current transformers supplying signals to metering or protective relays on the load side of the transformer are supplied with the switchgear. protection. and it must disappear immediately after the voltage has returned to normal. the size and importance of the transformer. Lightning is considered to be the most severe source of surge voltages. Station class arrestors are applied to both large (7. Intermediate class arrestors are applied to transformers between 225 kVA and 7. are required if signals are needed for metering or operating protective relays.5 MVA and larger) and critical transformers. and the type and cost of the arrestors.Electrical Manual 800 Transformers 880 Grounding Resistors and Bushing Current Transformers 881 Grounding Resistors Grounding resistors are used to limit the amount of fault current on the load circuit (See Section 900. and distribution which are listed in order of decreasing cost. It may be desirable for the switchgear manufacturer to provide the resistor since the ground fault detection system. The appropriate degree of surge protection depends on the degree of exposure to lightning. which will withstand the normal operating voltage but flash-over and become conductive at higher voltages. Surge arrestors intercept the surge and divert it to the ground. 883 Surge Capacitors/Lightning Arrestors Lightning protection is achieved by the process of intercepting lightning-produced surges and diverting them to ground or altering their associated waveshapes. “Grounding Systems. Ordinarily. to the transformer terminals. If transformers are connected to bare overhead lines. surge arrestors are not needed. is usually located in the switchgear. To provide the best protection for the transformer. or as close as possible. Chevron Corporation 800-21 September 1990 . if specified. if a liquid-insulated transformer is supplied by enclosed conductors from the secondaries of transformers with adequate primary protection. high frequency current interruption. Those marked with an asterisk (*) are included in this manual or are available in other manuals.” 885 Economics—Evaluation Factor When economically evaluating transformers. restriking. thyristor-switching. Data Guides (DG). 891 Model Specifications (MS) There are no model specifications in this guideline. and Engineering Forms (EF) *ELC-DS-401 *ELC-DG-401 Transformer Data Sheet Transformer Data Sheet Guide September 1990 800-22 Chevron Corporation . If a choice must be made among several transformers that all meet the technical requirements. and Maintenance. or ferroresonance). or as close as possible.. Commissioning. The sum of these two costs is the lifecycle cost.) 890 References The following references are readily available. Surge capacitors.800 Transformers Electrical Manual Surge capacitors provide additional protection against overvoltages (surges). 892 Standard Drawings There are no Standard Drawings in this guideline. prestriking. Surge capacitor protection is also effective against voltage transients generated from circuit conditions (e. “Electrical Checkout. (See ELC-DS-401 for formulas. Tests required for installation and commissioning of transformers are covered in Section 1400. The capacitors “bend” the front of the surge so that the initial force from the surge is distributed over more turns.g. both the initial cost of the equipment and the cost of energy losses over the lifespan of the transformer must be considered. current limiting fuse operations. like surge arrestors. 884 Shop Testing Tests required for verification of quality control before shipping transformers are covered in the Data Sheet Guide for Data Sheet ELC-DS-401. 893 Data Sheets (DS). the one with the lowest life cycle cost should be selected. Transformer windings can experience a very non-uniform distribution of a fast-front surge in the transformer. to the transformer terminals. should be connected on. Electrical Manual 800 Transformers 894 Appendices *Appendix D “Minimum Requirements for Dry-Type Transformers” (Eastern Region) 895 Other References IEEE C57. Chevron Corporation 800-23 September 1990 . ANSI/NEMA ST-20 Dry-Type Transformers for General Applications. *API RP 14F Design and Installation of Electrical Systems for Offshore Production Platforms. Distribution. Power and Regulating Transformers. 800 Transformers Electrical Manual September 1990 800-24 Chevron Corporation . Advantages and disadvantages of each method are discussed and specific recommendations are provided. Methods of preventing static charge buildup and protection against the effects of lightning are covered. Engineering and physical principles. Contents 910 911 912 913 914 920 921 922 923 924 925 926 930 931 Introduction Grounding—An Overview Design Parameters Checklist Selecting the System Grounding Point System Grounding Background Solidly Grounded Neutral Low-Resistance Grounded Neutral High-Resistance Grounded Neutral Low-Reactance Grounded Neutral Grounding Transformers System Grounding Recommendations Equipment Grounding Methods Onshore Equipment Grounding 900-14 900-5 Page 900-3 Chevron Corporation 900-1 May 1996 . How and where to ground electrical systems and what equipment to use are discussed. Design parameters for the various grounding systems for onshore and offshore applications are provided as well as a list of references. Procedures for system.900 Grounding Systems Abstract This section provides guidelines and procedures for selecting grounding methods for generation and distribution systems. and static grounding at Company installations in the United States are included. equipment. lightning. Standard drawings of grounding details for equipment and instrumentation are included. and mandatory and recommended practices are included also. National Fire Protection Association. Standard for the Installation of Lightning Protection Systems. Data Guides (DG) and Engineering Forms (EF) Other References 900-26 900-23 900-23 900-20 Note All figures reprinted from NFPA are reprinted with permission from NFPA 780. 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. Mass. Quincy. Chapter 6.900 Grounding Systems Electrical Manual 932 933 934 935 936 940 941 942 950 960 961 962 970 971 972 973 974 Offshore Equipment Grounding Common Equipment Grounding Applications Control Room Instrument and Computer Equipment Grounding Shipboard Equipment Grounding Installations Ground Resistance Measurement Lightning Protection Grounding Structures Electrical Equipment Static Electricity Grounding Sizing Components Low-Resistance Grounding High-Resistance Grounding References Model Specifications (MS) Standard Drawings Data Sheets (DS). Copyright © 1995. May 1996 900-2 Chevron Corporation . 02269. lines. are grounded.g. equipment grounding.Electrical Manual 900 Grounding Systems 910 Introduction This section provides guidelines for selecting and designing grounding systems. in which the neutral of a “Y” connected transformer or generator is grounded. Lightning protection grounding. This section also provides a source for applicable standards and references. etc. where appropriate. Static electricity grounding. and static electricity grounding are also discussed. 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. 2. 912 Design Parameters The following design parameters must be established before a grounding system can be designed: • • • Voltages: utility supply or generation. the model specifications and standard drawings. System grounding.. 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). System grounding. Equipment grounding. Those experienced in the design of grounding systems will find the checklist useful. area classification. 3. Issues discussed include the rationale for different system grounding methods as well as specific recommendations for both on. and surge arresters are used to protect equipment. on truck and tank car loading stations) are grounded. and piping (e. 4. in which tanks. The term “grounding” covers four separate functions: 1.. distribution. structures. and utilization Environmental or site conditions: corrosive conditions. IEEE Standard 142 (the Green Book) is also a good reference. and soil resistivity Mean annual number of days with thunderstorms for the specific job site (available from Isoceraunic Maps in NFPA 780 or IEEE Std 142) Chevron Corporation 900-3 May 1996 . • • 911 Grounding—An Overview Items are grounded to protect personnel and equipment. in which all metallic non-current carrying parts (which could become energized) are grounded.and offshore applications. in which tall vessels. lightning protection grounding. . vessels. electrical enclosures.g.900 Grounding Systems Electrical Manual Grounding design may be started after the following design items have been established: • • • 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. such as motors rated 2300 volts and above. installed with at least two equipment grounding conductors? Are all noncurrent-carrying metal raceways. area and room layouts. MCCs. and power transformers. 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? • • May 1996 900-4 Chevron Corporation . cabinets. conduits. generators. plot plans) Mechanical and electrical equipment details Structural plans 913 Checklist The 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. junction boxes. switchgear. cable armors. Transformers or generator neutrals must be grounded at each voltage level to achieve the advantages of neutral grounding. This must be considered when selecting the pickup values for Chevron Corporation 900-5 May 1996 . motor windings. and economic system is the responsibility of the design engineer. The selection of the most efficient. high-resistance.g. Fault Current Magnitude When a low-impedance ground fault (commonly called a “bolted” fault) occurs on a solidly grounded system. The fault. However. these are: 1. and low reactance. once established. at the transformer or generator. These situations are avoided when systems are grounded properly. the current magnitude is significantly less than the maximum bolted ground fault level since the arc resistance is relatively high. This is illustrated in Figure 900-1. 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. The voltage required to sustain an arc is approximately 140 volts. low-resistance. and other electrical equipment. See IEEE 142 for detailed information. As a result. is maintained as an arc through the ionized gases between the phase conductor and ground. Sometimes a specially designed grounding transformer is used to establish a system neutral. safe. 2. 921 Solidly Grounded Neutral The power system is solidly grounded when the neutral of the source is connected directly to ground without intentionally inserting any impedance in the path. There are four recommended system grounding methods: solid. the current magnitude of an arcing ground fault is approximately 40% of the bolted fault value on 480 volt systems. Ground at the source of each voltage transformation level. a single motor fed by three single-phase distribution transformers). When arcing line-to-ground faults occur on 480 volt solidly grounded systems. it may be appropriate to install an ungrounded system (e. that is. 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)..Electrical Manual 900 Grounding Systems 914 Selecting the System Grounding Point Two basic rules dictate the selection of the system neutral grounding points in an electrical distribution system. Overvoltage Overvoltage conditions can cause deterioration of the insulation on electrical cables. 920 System Grounding Background The following discussion is not intended to be a comprehensive description of system grounding. Never ground a system neutral at the load. very high ground fault currents will flow. Briefly. ” for recommended settings. A window-type (“donut type”) current transformer is used to monitor all current-carrying conductors. See Section 600. The choice of a particular method will depend on the sensitivity required and the circuit-interrupting devices selected. Zero sequence method (core balance). May 1996 900-6 Chevron Corporation . These devices may be applied in several different ways as illustrated in Figure 900-2: • • • • Ground return path. Fault Detection To detect ground fault currents. An overcurrent relay is located in common return conductor of the phase current transformer secondaries. “Protective Devices. Residual ground method. Their operating current level for ground faults can be as low as a few amperes to detect a low level arcing ground fault.” for additional information.900 Grounding Systems Electrical Manual Fig. “Protective Devices. 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. See Section 600. 900-1 Solidly Grounded Neutral ground fault protective relays. These devices only operate on ground-fault currents and are insensitive to normal load or phase-fault currents. sensitive ground fault protective devices must be used. Ground sensor integral with circuit breakers. an arcing ground fault is self-extinguishing on 208Y/120 volt systems (the line-to-ground voltage is 120 volts). An overcurrent relay is located in the transformer or generator neutral connection to ground. Since the voltage to sustain an arc is approximately 140 volts. Evaluation of downtime costs must consider the effects of suddenly disconnecting a Chevron Corporation 900-7 May 1996 . this feature also adds to the cost. as illustrated in Figure 900-1. See IEEE Std 142. Cost Factors The initial cost of solidly grounding the neutral is minimal on “wye” connected transformers. Resistance grounded systems require higher lineto-line voltage-rated arresters. four wire systems. Cost is higher for delta-connected transformers because a grounding transformer is required to establish a neutral point (see Section 925 below).Electrical Manual 900 Grounding Systems Fig. Thus. is the only system to which line-to-neutral loads can be connected since the neutral is always at ground potential. Overvoltage Solidly grounded systems offer the opportunity for using lower voltage-rated (lineto-neutral voltage) surge arresters. 900-2 Ground Fault Protective Devices Line-to-neutral Loads The solidly grounded neutral system. for additional details. If sensitive ground-fault protection is required. Chapter 1. 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. Fig. as illustrated in Figure 900-3. It is evident that damage is minimized if both current and time duration are kept to a minimum during a line-to-ground fault. shown in Figure 900-2. These costs may be high for continuous processes or critical services. A ground-fault current not exceeding 400 amperes is recommended. the ground-fault current magnitude is limited by the resistor to between 50 and 1000 amperes. 900-3 Low-Resistance Grounded Neutral System Fault Current Magnitude Ground resistors are sized to limit the current magnitude during a line-to-ground fault. resulting in a total ground fault current of (4 x 200) 800 amperes at the fault.900 Grounding Systems Electrical Manual portion of the electrical system when a ground fault occurs. I2t. current may be increased or decreased to meet the requirements of a specific application. are recommended on feeder circuits. 922 Low-Resistance Grounded Neutral A 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. where I is the fault current in amperes and t is time in seconds. sensitive ground fault relays are required since the phase relays normally will not detect a ground fault. For this reason. Fault Detection With the ground fault current limited by resistance. Typically. a system with four parallel sources may suggest a limit of 200 amperes each. However. Burning damage is proportional to the energy. medium voltage systems with large motors are commonly grounded in this manner. For example. 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. Sensitive zero-sequence relays. May 1996 900-8 Chevron Corporation . to repair a motor insulation failure may require only a coil replacement.Electrical Manual 900 Grounding Systems The ground return path method (Figure 900-2) may be used for transformers or generators. but where immediate interruption of power on occurrence of the first ground fault would cause significant economic loss. Surge arresters must be rated for line-to-line voltage (versus line-to-ground). 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 Factors The initial cost to provide low-resistance grounding of the system neutral includes the grounding resistor. the maximum line-to-ground voltages (including transients) during a line-to-ground fault are held to a minimum. 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 disconnect 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. Residual ground relays may be used where they provide adequate sensitivity—typically 10% of the maximum ground-fault current. Overvoltage With the values of resistance normally used. downtime costs must be evaluated on the same basis as solidly grounded systems. For example. whereas a similar failure on a solidly grounded system may require extensive repairs. and fault-locating equipment. 923 High-Resistance Grounded Neutral The 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-toground faults. The ground resistor on a low-resistance grounded system is normally rated for 10 second duty. and the ground-fault relaying equipment. High-resistance grounded neutral systems are applied in process industries and in other situations where control of transient overvoltages is desired. The resistance device must be rated to carry continuously the maximum current which can flow (line-to-ground voltage divided by the resistance). Cost Factors The initial cost to provide a high-resistance grounded system includes the grounding equipment. Costs to repair the faulted equipment may be much lower. Chevron Corporation 900-9 May 1996 . or even a complete motor replacement. Fault Current Magnitude The magnitude of the line-to-ground fault current at any point in a system is determined by the value of the grounding resistor and the system charging current. Since the faulted equipment is disconnected suddenly. the grounding transformer (if no wye-connection is available). 900 Grounding Systems Electrical Manual Fig. 900-4 High-Resistance Grounded Neutral System 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-toneutral 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 Detection The first ground fault will not automatically trip a faulted circuit. A second line-toground 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 May 1996 900-10 Chevron Corporation Electrical Manual 900 Grounding Systems 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. Fig. 900-5 Fault Detection by Means of a Contactor 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 HighResistance Grounding Equipment, is one such unit available. Overvoltage The 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 Neutral Low-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. Chevron Corporation 900-11 May 1996 900 Grounding Systems Electrical Manual 925 Grounding Transformers Sometimes 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 established 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 Recommendations The 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 requirements. Solidly Grounded Neutral Appropriate 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 Neutral Appropriate system voltage ratings for high-resistance grounded neutrals are 480 volt three-phase, three-wire, and 2400 volt through 4160 volt three-phase, threewire. High-resistance grounded neutrals are recommended when: May 1996 900-12 Chevron Corporation Electrical Manual 900 Grounding Systems • 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 shutdown. • • 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-resistance 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 groundfault currents to approximately 5 amperes (10 amperes maximum). It is recommended also as a means of detecting and alarming ground faults. Low-Resistance Grounded Neutral Appropriate 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 insulation 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. Chevron Corporation 900-13 May 1996 900 Grounding Systems Electrical Manual 930 Equipment Grounding Methods Equipment Ground Background Equipment 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 structures 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 equipment 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 25094. 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. Courtesy of the National Fire Protection Association. Minimum Size Grounding Electrode Conductor (AWG) 6 4 2 1/0 2/0 3/0 Service (Feeder) Conductor Size (AWG) 1/0 or smaller 2/0 — 3/0 Over 3/0 — 350 MCM Over 350 MCM — 600 MCM Over 600 MCM — 1100 MCM Over 1100 MCM May 1996 900-14 Chevron Corporation Electrical Manual 900 Grounding Systems Fig. 900-7 Minimum Sizes for Copper Equipment Grounding Conductors Reprinted with permission from NFPA 70-1999, National Electric Code®, copyright 1998. Courtesy of the National Fire Protection Association. Rating or Setting of Automatic Overcurrent Device in Circuit Ahead of Equipment, Conduit, etc., Not exceeding (Amperes) 15 20 30 40 60 100 200 300 400 500 600 800 1000 1200 1600 2000 2500 3000 4000 5000 6000 Minimum Size (AWG) 14 12 10 10 10 8 6 4 3 2 1 0 2/0 3/0 4/0 250 MCM 350 MCM 400 MCM 500 MCM 700 MCM 800 MCM 931 Onshore Equipment Grounding The grounding system for a large or complex plant may involve an extensive multiloop 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 requirements 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. Chevron Corporation 900-15 May 1996 900 Grounding Systems Electrical Manual 932 Offshore Equipment Grounding One 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 singlephase 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 equipment 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 Applications The 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 lowresistance 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 • • May 1996 900-16 Chevron Corporation Electrical Manual 900 Grounding Systems 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 equipment 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 noncurrentcarrying enclosures of electrical devices be grounded. These include conduit, wireways and other similar wiring raceways. Where the continuity of the enclosure 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 terminate all grounding conductors. This ground bus must be bonded to the enclosure 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 arrangement 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 subpanel. 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 • • • • Chevron Corporation 900-17 May 1996 900 Grounding Systems Electrical Manual 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 GFP99735 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 resistance 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 Grounding Grounding 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 May 1996 900-18 Chevron Corporation Electrical Manual 900 Grounding Systems • 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 connection point to the plant grounding grid. See ANSI/IEEE Std 142 for more information. “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 Installations U.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 distribution 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 Measurement For 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 complicated 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 determined only by test. Several methods of testing have been devised, varying in degree of accuracy. It is important that the measurement of grounding connection resistance 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 necessary. 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 resistance 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 Chevron Corporation 900-19 May 1996 900 Grounding Systems Electrical Manual 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 Structures The 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 terminals (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 lightningproduced 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 structures. However, it is necessary to ground the taller structures adequately to prevent possible damage to reinforced concrete foundations and to provide a zone of protection 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 Lightning Protection Systems,” NFPA No. 780. As a minimum, all structures 100 feet tall May 1996 900-20 Chevron Corporation Electrical Manual 900 Grounding Systems 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) 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 sidewalls 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 Equipment To 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 Chevron Corporation 900-21 May 1996 900 Grounding Systems Electrical Manual 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 essentially 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 application 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 information. 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 equipment 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. May 1996 900-22 Chevron Corporation selective performance of the system protective relaying scheme Limiting ground-fault current to a value that causes minimal damage to equipment at the point of a fault Sizing of Resistor The 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).4 kV. tank cars. 900-1) where: RN = Resistance of the neutral grounding resistor. Bonding and grounding conductors should be copper (usually bare copper is recommended for both economy and ease of identification).4 through 14. in ohms EL-N = Line-to-neutral voltage of source. the determination of the ohmic value of the grounding resistor. 960 Sizing Components 961 Low-Resistance Grounding For a low-resistance grounded system of 2. etc. When charges do accumulate.Electrical Manual 900 Grounding Systems 950 Static Electricity Grounding Static electricity is caused by the accumulation of electrical charges on materials and objects. potential differences of thousands of volts may be produced. The flow of electricity during static electricity generation and accumulation is small—in the range of microamperes. EL – N R N = -------------IL – G (Eq. container filling apparatus.. The size of the bonding conductor can be based only on mechanical strength as current flow is in microamperes. Usually static charges do not accumulate if the total resistance to ground is one megohm or less. should be in accordance with API RP 2003 and NFPA 77. Bonding and grounding of tank trucks. Of particular concern is the static charge resulting from contact and separation that occurs when flammable fluids flow. in volts IL-G = Line-to-ground current. in amperes Chevron Corporation 900-23 May 1996 . Static grounds are connected directly to the grounding system. A primary manifestation of static electricity is the discharge or sparking of accumulated charges. and hence the magnitude of ground fault current. This is usually the case for the ground fault currents limited by the resistor to several hundred amperes. is based on the following: • • Providing sufficient current for fast. Fig.4 4. 962 High-Resistance Grounding Sizing of Resistor The 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. ufd.0 0. see Figure 900-10 For 3 Ico (motors and generators). 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). the current rating of the resistor (usually 5 amperes) and the time rating.5 0. 900-9 Line-to-Ground Fault Charging Currents (3 Ico) for Surge Capacitors Voltage. kV 0. due to system capacitance can be defined as follows: IR = 3 Ico where: I co = System charging current of one phase Thus. ma 313 784 1357 2253 2253 May 1996 900-24 Chevron Corporation . The resistor current. 1. the minimum size of the grounding resistor is determined from the sum of capacitive charging currents of all equipment components in the system.5 0. IR. see Figure 900-11 Note Transformer capacitive charging currents are not included as they normally are negligible.8 C.5 0. usually “continuous rating” should be specified.25 3 Ico.16 6. If the grounding resistor is purchased with a motor control center.900 Grounding Systems Electrical Manual If the grounding resistor is purchased concurrently with the transformer or switchgear. see Figure 900-9 For 3 Ico (cables).9 13. The 10 second rating permits the ground-fault relay and the circuit-switching device time to operate before the resistor is damaged. only the current rating of the resistor (usually 400 amperes maximum) and the time rating (usually 10 seconds) need to be specified.48 2. and provide an adjustable (tapped) resistor that allows several settings either side of the estimated value for field adjustment. Systems of higher voltage should be limited to 10 amperes. Motor and cable manufacturers normally will be able to supply accurate values of capacitance-to-ground per phase. in microfarads (10-6 farads) • Surge Capacitor Charging Current The charging current for surge capacitors is significant for the values of capacitance normally used. maximum of approximately 5 amperes. Chevron Corporation 900-25 May 1996 . more refined calculations for motor and cable charging currents should be made. in amperes VLL = System line-to-line voltage. in hertz Co = Per-phase capacitance-to-ground. size. an approximation of the total system charging current can be made and the size of the ground resistor can be selected. Since measurement is not possible during the design phase. From the data in Figures 900-9. Typically. in amperes Ico = System charging current of each phase during normal system conditions (no ground fault) [I co]. The surge capacitors may easily be the largest single contributor to the total capacitive charging current. normal practice is to estimate the charging current. 900-10. Capacitive charging current can be calculated from the per-phase capacitance-toground value using the following equations: 3V LL I c = 3 I co = ----------------X co (Eq. 900-2) 10 6 X co = --------------2 π fC o (Eq. 900-3) where: IC = System charging current during a ground fault. charging currents for 480 volt systems are less than 1 ampere.Electrical Manual 900 Grounding Systems Capacitive Charging Current The only accurate method of determining charging current for a given system is by direct measurement. When the detailed design of a system is in progress. as shown in Figure 900-9. as above. and voltage rating). and 900-11. in volts Xco = Per-phase capacitive reactance. in ohms [Xco] f = Frequency. 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. 000 volt cables. 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. length. Determination of charging current is based on cable size.and high-voltage windings are concentrically placed around a rectangular cross section core. XLPE or Butyl for 600 through 15. Thus the ground fault charging current usually is negligible in systems rated 15 kV and below. 971 Model Specifications (MS) *ICM-MS-3651 *ELC-MS-1675 Installation Requirements for Digital Instruments and Process Computers Installation of Electrical Facilities May 1996 900-26 Chevron Corporation . Multiplying factors are also provided to calculate the charging current of cables with dielectric constants different from those listed.900 Grounding Systems Electrical Manual • Cable Charging Current Insulated power cables can contribute a significant percentage of the total system charging current. This design results in a very small value of distributed capacitance between the windings and ground. The minimum charging current value is typical of high-speed machines (1800 rpm). that is. second only to surge capacitors. and the maximum value is typical of lower speed machines (600 rpm) for the range of ratings normally selected at each voltage level. Those marked with an asterisk (*) are included in this manual or are available in other manuals. 970 References The following references are readily available. • Transformer Charging Current The transformers most commonly used in industrial systems are of core and coil construction. • Motor and Generator Charging Current Typical charging currents for motors and generators are as shown in Figure 900-11. the low. and thickness. insulation material. 3.16 kV 171 198 231 253 274 299 323 356 380 435 505 600 679 3 Ico.2 for paper-insulated cable. 2. ma/1000 ft 6. multiply the above by the actual dielectric constant and then divide by 3. Chevron Corporation 900-27 May 1996 .4 kV 4. 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 Cable Size (AWG) 6 4 2 1 1/0 2/0 3/0 4/0 250 MCM 350 MCM 500 MCM 750 MCM 1000 MCM 2.16 kV 13 ma/1000 ft 63 ma/1000 ft 109 ma/1000 ft Unshielded cable in metallic cable tray (typical): 480 V 2.9 kV 284 329 383 419 455 496 536 590 631 721 838 996 1126 13.4 kV 99 114 133 146 158 172 186 205 219 251 291 346 392 4.Electrical Manual 900 Grounding Systems Fig.16 kV Notes: 9 ma/1000 ft 47 ma/1000 ft 81 ma/1000 ft 1. The charging currents given above are for cables with a dielectric constant of 3. current is negligible for lengths normally used in industrial distribution systems.4 kV 4. 3.8 kV — — 577 631 676 739 793 865 919 1045 1207 1424 1604 Unshielded cable in metallic conduit (typical): 480 V 2. Multiply charging current by 1. For other dielectric constants. open-wire lines. Neglect charging current for bare.3. IEEE Guide for Measuring Earth Resistivity. 2. IEEE Recommended Practice for Electric Power Distribution for Industrial Plants ANSI/IEEE Standard 142. and Test Procedure for Neutral Grounding Devices ANSI/IEEE Standard 45. 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. Data Guides (DG) and Engineering Forms (EF) There are no data sheets.8 Notes: Generators. IEEE Recommended Practice for Grounding of Industrial & Commercial Power Systems May 1996 900-28 Chevron Corporation . kV Motors. 0.4 4. Terminology.900 Grounding Systems Electrical Manual Fig.48 2. 10 40 70 115 230 5 20 35 60 115 1. IEEE Standard Requirements. data guides or engineering forms for this guideline. IEEE Guide For Safety in Substation Grounding ANSI/IEEE Standard 81. 20 16 25 35 50 Max. Ground Impedance. ma/1000 hp Min.9 13.16 6. IEEE Recommended Practice for Electric Installations on Shipboard ANSI/IEEE Standard 80. 972 Standard Drawings *GD-P99734 *GF-P99735 *GF-J1236 Grounding Details — Grounding Electrodes Grounding Details — Equipment Connections Typical Ground System for Digital Instruments and Process Computers 973 Data Sheets (DS). 10 12 18 25 36 Max. 900-11 Line-to-Ground Fault Charging Currents (3 Ico) for Motors and Generators Voltage. ma/MVA Min. Charging current values for generators rated 2. 974 Other References ANSI/IEEE Standards ANSI/IEEE Standard 32.400 volts and above are for 1800 rpm air cooled machines in the range of 10-60 MVA. and Earth Surface Potentials of a Ground System ANSI/IEEE Standard 141. Chapter 6: Neutral Grounding.. 6: Machine Characteristics. and pages 426 through 433: Shock Hazards Electrical Transmission & Distribution Reference Book . Standard for Electrical Safety Requirements for Employee Workplaces ANSI/NFPA 77. 1964. Standard for the Installation of Lightning Protection Systems NFPA Fire Protection Handbook ANSI C2 National Electrical Safety Code American Petroleum Institute Practices (API) RP 14F RP 540 RP 2003 Design and Installation of Electrical Systems for Offshore Production Platforms Recommended Practice for Electrical Installations in Petroleum Processing Plants Protection Against Ignitions Arising Out of Static. 7: Equipment Grounding. National Electrical Code ANSI/NFPA 70E. Title 29. Westinghouse Electric Corp. Office of the Federal Register ANSI/NFPA Standards and Codes ANSI/NFPA 70. Title 46. IEEE Recommended Practice for Emergency and Standby Power Systems for Industrial and Commerical Applications ANSI/IEEE Standard 1100. Static Electricity ANSI/NFPA 780. Shipping.Electrical Manual 900 Grounding Systems ANSI/IEEE Standard 242. Chapter 2: Symmetrical Components. IEEE Recommended Practice for Powering and Grounding Sensitive Electronic Equipment Government Regulations Occupational Safety & Health Administration (OSHA) Code of Federal Regulations. McGraw-Hill. 1st Edition 1955. Donald. 1910 Code of Federal Regulations. and 19: Neutral Grounding Chevron Corporation 900-29 May 1996 . IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems ANSI/IEEE Standard 446. Subpart S. Beeman. 16: Lightning Phenomena. Lightning and Stray Currents Miscellaneous References Industrial Power Systems Handbook. and direct burial cable.” as the general specification. “Installation of Electrical Facilities. uninterruptible power supplies.1000 Installation of Electrical Facilities Abstract Section 1000 covers general design and installation practices for electrical facilities. Guidance is given on the installation of switchgear. motor control centers. with reference to ELC-MS-1675. transformers. The section also provides specific guidance for the design and installation of conduit systems. cable tray systems. and battery systems. Contents 1010 Introduction 1020 Conduit System Design and Installation 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 1040 Installation of Cable Tray Systems 1041 Determination of the Cable Tray Route 1042 Cable Tray Arrangement 1043 Grounding and Bonding of Metallic Tray 1044 Supports for Cable Tray 1000-9 1000-9 Page 1000-3 1000-3 Chevron Corporation 1000-1 November 1991 . An appendix is included in this manual which provides extensive information on the calculation of pulling tensions and installing and terminating cables. and Engineering Forms (EF) 1084 Appendices 1085 Other References 1000-20 1000-15 1000-15 1000-13 November 1991 1000-2 Chevron Corporation . Data Guides (DG).1000 Installation of Electrical Facilities Electrical Manual 1045 Installation of Cable in Cable Tray Systems 1050 Conductor Terminations 1051 Purpose 1052 Control of Electrical Stress With Terminations 1053 Terminator Requirements 1060 Direct Buried Cables 1070 Installation of Electrical Equipment 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 1080 References 1081 Model Specifications (MS) 1082 Standard Drawings 1083 Data Sheets (DS). This specification should accompany drawings which specify electrical items by referring to the P-item number (rather than a detailed material list). the best course of action is to use listed (usually UL) components in the equipment. ELC-MS-4377. It is becoming increasingly important that all electrical components be listed by UL. It also serves as a wire pulling schedule. In OCS areas offshore. Section 100. Foreign regulations are often based on publications written by the International Electrotechnical Commission (IEC). therefore. For ships. “Installation of Electrical Facilities. such as the American Bureau of Shipping and the United States Coast Guard.” should be consulted before choosing the type of conduit system and before sizing conduit systems.” is used for listing each conduit in an electrical installation and the number. In addition. Standard specifications. 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.Electrical Manual 1000 Installation of Electrical Facilities 1010 Introduction This section provides useful information pertinent to the design and installation of electrical facilities in addition to the information in ELC-MS-1675.” ELC-MS-1675 is usually given to electrical contractors as the general electrical specification. Problems sometimes arise when installing custom-designed equipment not covered by a specific standard (which. For those areas which do not have a list. In this case. type and destination of wire pulled in each conduit. the recently revised version is included and can be modified to meet local preferences. Chevron Corporation 1000-3 November 1991 . installation. FM. can’t be listed). It should be modified to accompany the specific contract documents for construction. drawings. 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. is a standard electrical item list (P-item list) which describes bulk electrical materials by manufacturer and model. Underwriters’ Laboratories (UL) and Factory Mutual (FM) have requirements for listed equipment which must be adhered to when the equipment is installed. “Conduit and Wire Schedule. One of these specifications. and forms related to this section are listed in Section 1080. “System Design. Check with local inspectors in advance of purchase to determine their applicable requirements. It is created during the design phase of a project and used during the construction phase when installing wire. Conduit bank design. and layouts of both aboveground and underground systems are discussed. Some locations have their own standard electrical material list. ELC-EF-70. 1020 Conduit System Design and Installation This section discusses the most common types of conduit systems in use. or another nationally recognized testing laboratory (NRTL) in order to be accepted by the inspectors of the agency having jurisdiction. installation is governed by classification societies and national authorities. API RP 14F is applicable and deviates from the NEC in a few places. the types of supports. In facilities with poor documentation.1000 Installation of Electrical Facilities Electrical Manual On large projects. it may be desirable to generate these schedules with a computer. ability to be manually bent into wide-radius sweeping turns (rather than small radius bends). PVC-coated galvanized steel. 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.g. it is sometimes worthwhile to do exploratory excavation along the proposed routes prior to excavating for the installation of new underground conduits. 1023 Conduit Route In general. 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. the best route to use is the most direct route which avoids high fire risk areas.. The minerals Management Service does not allow the use of IMC in hazardous (classified) areas offshore. Also. November 1991 1000-4 Chevron Corporation . and aluminum (usually copper free). 1022 PVC Conduit Systems The use of PVC conduit systems in underground concrete encased duct banks is increasing. ease of installation. The advantages of PVC for underground applications are. 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). piping and hidden underground structures). The most common conduits are galvanized steel. the most frequently used system for providing power from the source to the load is wire in rigid metal conduit. The form is included as a model for developing computer forms or for direct use. low coefficient of friction (for pulling). and corrosion resistance. The following sections cover several important features of both above and belowground conduit installations. PVC does not have the same strength as rigid steel. This will minimize unknown interference problems and reduce installation costs. 1021 Rigid Metal Conduit Systems For refinery and chemical plants. PVC-coated galvanized steel and aluminum conduit have superior corrosion resistance and are appropriate for more corrosive environments. they are more expensive than standard galvanized conduit. however. but strength is added by the concrete reinforcement which protects the conduit. low initial cost. In both above.and belowground systems. PVC conduit cannot be used in classified areas. careful consideration should be given to avoiding interferences (e. Intermediate metal conduit (IMC) is not recommended for hazardous (classified) areas or areas not environmentally controlled. For both underground and abovegrade installations. Their phone number is (713) 9737032. On a large project it is common practice to wait until the project is electrically complete before pouring the seals. If there are multiple power circuits in a duct bank. 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. a computer program which calculates cable ampacities in duct banks. 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. When installing conduit in this manner. High temperatures can cause cables inside conduits to fail prematurely. or a duct bank belowground. 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. computer programs are available which take into account load factor. steam lines and heat exchangers. AMPCALC. However. Refer to Section 300 for additional seal requirements. soil thermal resistivity. position the conduit to minimize any interference during subsequent pipe removal or installation. The National Electrical Code provides some guidance in computing the derating factors. install conduits away from sources of heat such as furnaces. Steam line crossings should be made at right angles whenever possible. is available from Calcware in Houston. Texas. and the configuration of the adjacent conduits in order to determine safe ampacities. Conduit spacing has an effect on the heating of conductors within duct banks. but no fitting is allowed between the seal and the point at which the conduit leaves the Division 1 or Division 2 boundary. All seals are then poured at one time. 1024 Conduit Arrangement and Spacing When multiple conduits are organized into a group aboveground. Chevron Corporation 1000-5 November 1991 . there are specific conduit spacing requirements which are based on the voltage and current of the enclosed conductors. Once seals are poured. Underground conduit should never be routed close to parallel steam lines.Electrical Manual 1000 Installation of Electrical Facilities Abovegrade conduit routes often parallel piping in trenches or on overhead pipe racks. ambient temperature. a derating factor must be applied to the ampacity of the insulated conductors in the conduits in the bank. Sufficient space should be left around conduit seals to allow access for pouring. 1025 Use of Seals and Drains Conduit seals are required in conduits when an area classification change occurs. The seals can be placed on either side of the area classification change. it is recommended that they be painted red or otherwise marked to indicate that the sealing compound has been poured. If there are several conduits in a concrete duct bank. clampon beam clamps should be used judiciously since they tend to loosen with vibration. When supporting conduit from structural members in high vibration areas. This usually is accomplished with plastic spacers or by tying the conduit to the surrounding reinforcing bar (rebar) cage with wire ties. based on conduit size. For outdoor. For larger banks (particularly those with non-metallic conduit). It is important to observe the metallurgy of the supports and the conduit to avoid galvanic corrosion. It is preferable to design systems so that conduits enter enclosures from the side or bottom to avoid water entry.g.. a rebar cage is required to provide strength for the duct bank (particularly if there will be heavy vehicular traffic over the bank). this can not take the place of structural support.1000 Installation of Electrical Facilities Electrical Manual Seals in vertical conduit runs should be provided with drains. Conduit support should be checked carefully during the construction phase. A civil engineer should be consulted for the design of large banks to November 1991 1000-6 Chevron Corporation . gives the maximum spacing between supports. drain seals should be installed where conduits enter enclosures from the top. corrosion will result if aluminum conduit is secured directly to steel. Conduits must not be supported from process piping. the spacing and position of the conduits must be maintained during the pouring of the concrete. Careful consideration must be given to the number and size of the underground conduits since it is difficult (and very costly) to modify or expand the system once the concrete is poured. This prevents water from entering enclosures through conduit. aboveground installations. For example. however. Conduit should be supported from structural members at proper intervals. NEC Article 346. It is permissible to support them from pipe support structures if proper clearances are observed. Special isolation pads are available to eliminate this problem. 1026 Aboveground Conduit Support Aboveground conduit usually is supported by steel channel (e. Unistrut). 1027 Underground Conduit Banks Routing of underground conduit banks must be decided early in the project since underground banks usually are installed before abovegrade plant construction is done. Drains must also be installed in the low points of conduit runs where water might accumulate. Conduit should not be able to be moved easily with hand pressure. Conduit in overhead conduit systems should be checked carefully to ensure conduits are secured to the supports. Supporting conduits from adjacent conduits is not allowed in most cases (Reference NEC 300-11). Often additional rigidity of a conduit group can be obtained if adjacent conduits are tied together at intermediate points. Figure 1000-1 illustrates a typical underground conduit bank. Fig. is specified in ELC-MS-1675. the drainage will flow into a pull box equipped with a drywell which allows the water to percolate into the soil. 1000-1 Typical Underground Conduit System An often overlooked consideration in underground conduit systems is drainage. repairing systems damaged by excavators can be very expensive (in addition to down-time and personnel safety factors). A civil engineer should be consulted concerning the necessity and details of any required pile support systems. This provides a warning for future excavators that they are digging up an electrical installation.Electrical Manual 1000 Installation of Electrical Facilities ensure the proper sizing and arrangement of the rebar and the proper compressive strength of the concrete. It is recommended that permanent. Figure 1000-1 shows pile supports under a concrete-encased conduit bank. Conduits should be sloped toward a low point so that water will drain from the conduit. or belowground. Although the initial cost is greater. Figure 1000-2 summarizes Chevron Corporation 1000-7 November 1991 . either aboveground. are equipped with sump pumps. Piles are often required in poor soil areas where the conduit may settle or sink. 1028 Conduit Bends and Pull Boxes The recommended maximum number of bends in a conduit run. It is good practice to mark the top few inches of concrete-encased duct banks with red iron oxide mixed with concrete. underground duct bank markers be visibly embedded at grade level along the path of the duct bank. Often. Sometimes large pull boxes or basements into which water from conduits will drain. 90 Deg. as well as the allowable bending radii for different types of conductors. 180 Deg. 180 Deg. the distance between the exit and entrance points must be at least four-times the minimum bending radii of the cable. Where cable is pulled out of and back into an enclosure. 6 x OD 30 in. 180 Deg. 90 Deg. LB. Fig. 315 Deg. 180 Deg. November 1991 1000-8 Chevron Corporation . 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. To change directions in a medium voltage conduit run and to meet the bending radius requirement of the medium voltage cable. 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. pull boxes are used. 15 kV 400 ft. 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. 5 kV Shielded 400 ft. 180 Deg.and C-type fittings usually do not meet this requirement (and would constitute an NEC violation if 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. 5 kV Unshielded 400 ft. 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. To limit the number of bends in underground conduit. 8 x OD 30 in. 180 Deg.1000 Installation of Electrical Facilities Electrical Manual these requirements. 90 Deg. usually a conduit bend of the proper radius or a large pull box which allows the proper bending radius is required. Degrees of Bend and Minimum Bending Radius for Specific Conductor Types in Conduit Conductor Type Maximum Pulling Distance Maximum Degrees of Bend for Runs 300 Foot or Less Maximum Degrees of Bend for 400 Foot Run Minimum Bending Radius Maximum Single Bend 600V 300 ft. 1000-2 Maximum Pulling Distances. 90 Deg. 180 Deg. “System Design. aluminum. The installation requirements for cable tray systems are found in the NEC Article 318. Cable tray is used extensively on offshore platforms. Cable tray is available in different materials.Electrical Manual 1000 Installation of Electrical Facilities 1030 Installing Electrical Conductors in Conduit Systems Introduction Most land-based electrical installations use insulated conductors pulled in rigid metal conduit although the use of cables in cable tray is increasing. Cables can be added to the tray easily and economically. 1041 Determination of the Cable Tray Route The 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. stainless steel. During the installation of conductors in conduit. The choice of material should be based on the degree of strength and corrosion resistance which is required. and fiberglass. These materials include: galvanized steel. The use of cable tray and cables is often a less expensive alternative to conduit systems. a cable tray system can often be installed for less than wire and conduit. This is of particular importance when installing medium voltage insulated 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.” 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. as well as information on the proper equipment to use and precautions to take. A major disadvantage of a cable tray system compared to an underground conduit. Chevron Corporation 1000-9 November 1991 . 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. When circuits are routed from one area to another as a group. it is important that proper procedures for pulling are followed and that maximum pulling tension and jam ratios are not exceeded. Cable tray routing should be determined at the same time as the piping routing. 1040 Installation of Cable Tray Systems Section 100. Figure 1000-3 illustrates a typical “ladder”-type cable tray system. Also. supports can be dual purpose— supporting pipe and cable tray (which minimizes overall costs). is that cable in tray is more susceptible to fire and mechanical damage. Large. are usually installed in a single layer. NEC Article 318 requires that single conductors be larger than 1/0 if used in tray. “Installation of Electrical Facilities. Multi-conductor cables with conductors smaller than 4/0 may be layered if the maximum cross sectional area fill is not exceeded. Most wire which is normally installed in conduit is not suitable for use in tray. Smaller conductors may be used if they are in a suitable multi-conductor cable. For example. 1000-3 Typical Aboveground Cable Tray System 1042 Cable Tray Arrangement Trays may be either stacked or placed side by side. It is important to avoid mixing low-level signals (such as thermocouple leads) and high-level power cables in the same tray. above 1/0. November 1991 1000-10 Chevron Corporation . Specific rules concerning layering cables in the same tray are given in NEC Article 318. multiconductor cables which are 4/0 or larger must be in a single layer (with no other cables on top of them). and they must be of a type suitable for use in tray. individual conductors of AWG 12 THW are not suitable for use in tray. single conductors. Generally.1000 Installation of Electrical Facilities Electrical Manual Fig. NEC Article 318-3 lists the cables suitable for installation in tray.” Cables installed in cable tray must be suitable for use in cable tray systems. cable tray systems are stacked with different voltage levels. Information regarding separation requirements between signal levels can be found in ELC-MS1675. Cable cannot be stacked indiscriminately in cable tray. Violations of Article 318 can result in the overheating of circuits. signal levels and intrinsically safe circuits separated (in different trays). For example. . refer to the cable tray manufacturer’s literature for recommended weight loading of the tray.g. 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 generator ground). often by threaded rods supporting horizontal members on which the tray is fastened.. Tray supports must be installed at close enough intervals to prevent exceeding specified maximum deflections (both vertical and horizontal). suspension below a horizontal surface (e. 1000-4 Cable Tray Supported on Pipe Racks To prevent exceeding the maximum allowable deflection. pipe supports. Typical support methods are shown in Figures 1000-4 and 1000-5. beam or deck). 1044 Supports for Cable Tray The most common methods of supporting cable tray include the following: direct mounting on fixed objects (e. and building walls).Electrical Manual 1000 Installation of Electrical Facilities 1043 Grounding and Bonding of Metallic Tray Metallic tray must form a complete system that is electrically and mechanically continuous and grounded as required by Section 318-7(a) of the NEC. ceiling. 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. Fig. pipe racks). and supporting the tray by welded steel channel or angle supports which are welded or bolted to other rigid structures (such as decks.g. Chevron Corporation 1000-11 November 1991 . 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. trays of the same power level. 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. 1000-5 Typical Cable Tray Anchoring 1045 Installation of Cable in Cable Tray Systems Care should be taken when installing cables in cable tray to prevent nicking or scraping the cables. protect cables from damage during construction. November 1991 1000-12 Chevron Corporation . Maintain the separations between signal levels listed in ELC-MS-1675 to prevent signal interference.1000 Installation of Electrical Facilities Electrical Manual Fig.) 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. or supported by cable tray. 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. non-shielded and shielded power conductors.Electrical Manual 1000 Installation of Electrical Facilities 1050 Conductor Terminations 1051 Purpose Figure 1000-6 illustrates the preferred compression-type of two-hole lug conductor termination for large (1/0 AWG and larger). overall jacket and armor Effective control of electrical stresses for medium voltage applications (by position of both internal and external insulation) Grounding of shields Fig. Terminations 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. the combination of longitudinal and radial electrical stresses would focus at the shield end and eventually would cause Chevron Corporation 1000-13 November 1991 . If a termination at these higher voltages did not provide electrical stress relief. 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 applications since they do not loosen over time like some bolted connections. The additional insulation level and shape serves as a means of electrical stress relief. 1000-6 Two-hole Lug Cable Termination 1052 Control of Electrical Stress With Terminations Figure 1000-7 illustrates various types of medium voltage shielded cable terminations used for indoor and outdoor terminations. shielding. The shield is then carried up the cone surface and terminated behind the largest part of the cone. Heat-shrinkable stress relief termination kits (such as Raychem) are recommended for both indoor and outdoor medium voltage installations. The size of the terminator should be considered when sizing junction boxes of medium voltage motors and termination compartments in switchgear. Discharge corona can form ozone which can cause the insulation to fail. reducing the potential for electrical discharge. Most terminators should be of the two-hole lug-type as shown in Figure 1000-6. Care should be taken not to overheat shrinkable termination kits during application.1000 Installation of Electrical Facilities Electrical Manual insulation failure. 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). and must provide the required insulation level. Cable faults can result from overheating heat-shrink products. The most common method for reducing the electrical stress is to gradually increase the insulation to form a cone. Also. Fig. 1000-7 Typical Medium Voltage Terminations 1053 Terminator Requirements Cable terminators must provide adequate current carrying capacity. Skirts are added to outdoor terminators November 1991 1000-14 Chevron Corporation . Exposed lugs may be taped. they must be of the same material as the conductor or be approved specifically for the combination of materials. This type of terminator provides good resistance to loosening when subjected to vibration. The energy stored between the shield and the conductor is dissipated over an increasing volume of insulation (the cone). the phases must be connected to the corresponding buses. Once buried. Therefore. Once the phases are identified at the power source. These requirements include minimum coverage. transformer. and other electrical equipment. and blue tape at the switchgear and at all termination points. The three phases feeding the facility must be identified. This is very important when tying systems together. When using direct burial cable. splices and taps. MCC. when parallelling systems. the Chevron Corporation 1000-15 November 1991 . This identification is usually accomplished by color. It is recommend that outgoing feeder cables be taped with black. NEC Article 300-5. a route should be selected that offers the least potential for future damage. protection from damage. it is necessary to determine which conductor is phase A. One recommended method for labeling the cable location is to use metallic tape (such as that used for labeling buried plastic lines). Proper spacing between cables is important for separation of signal levels and for heat dissipation. Some prefer the use of porcelain terminators (which are more expensive and physically larger than the heat shrinkable variety). and C at every bus in the system. phase B with red. Cables should be buried with a sand backfill immediately surrounding them. When connecting the conductors from the utility or generator to the first switchgear bus. and the C phase. The three phases are commonly referred to as the A phase. provided the cable is a type approved for direct burial applications. left to right. and backfill. 1060 Direct Buried Cables Cables can be buried directly when the potential for cable damage is minimal. and C from top to bottom. the B phase. The cable can then be found by using a metal detector. or front to back when facing the front of the switchgear.Electrical Manual 1000 Installation of Electrical Facilities to increase tracking resistance. B. red. cables are difficult to repair. the convention for connection of the three phases to the bus is to connect phase A. and when predicting motor rotation. Phase A is identified by the color black. depths of up to five feet are recommended. 1070 Installation of Electrical Equipment 1071 Phasing and Phase Rotation In electrical system installations it is important to maintain the identity of the three phases throughout the system. but. The proper phase is connected to the designated bus for that phase (according to the convention) at each downstream switchgear. from source to load.. provides specific requirements for the direct burial of cables.S. The locations of direct burial cables should be clearly labeled so that construction equipment does not damage the cable. The minimum depth for direct burial of cables is 24 inches. Cables should be located to minimize crossing process pipes and other obstructions. and phase C with blue. for safety and reliability. B. Direct burial cables rated over 2000 volts nominal should be shielded and provided with an external ground path. grounding. In the U. The phase sequence determines which phase-to-neutral voltage peaks first. 1072 Installation of Switchgear and Motor Control Centers Switchgear and motor control centers usually arrive in two or more vertical sections. If the phase sequence is not known. November 1991 1000-16 Chevron Corporation . After switchgear has been interconnected. Sometimes manufacturers supply boots which can be applied in the field. different anchoring designs are required to allow flexing of the anchor (instead of breaking) during earthquakes. it is very difficult and expensive to move. When a bolt has been properly torqued. the distances to nearby equipment should be checked and compared to the requirements of NEC Articles 110-16 and 110-34. obtaining correct motor rotation of three phase motors is not a serious problem. It may be possible to adjust the position of the equipment to meet NEC requirements if it does not meet them as initially positioned. it should be marked to indicate that it has been checked. C. If conduits stub up below the switchgear or MCC. The most common phase sequence is A. second. The switchgear may be bolted or welded to this channel or bolted directly to the concrete (normally using expansion-type anchors). early checks should confirm that conduits stub up below the vertical section in which the cable is to be terminated. and third. they should be moved inside and the space heaters energized to prevent condensation. must be connected together. Before finalizing the location of (and securing) switchgear or MCC units. For insulated bus systems. The buses between adjacent sections. it is necessary to tape or otherwise insulate all fieldconnected bus splits. Ascertain that all bus bolts are torqued to the values specified by the manufacturer. The foundation for switchgear and MCC units must be level. If these sections are to be stored. wooden blocks or styrofoam packing (found inside relays) must be removed. See Section 1400 for a bolt torque checklist. This can eliminate problems with motor rotation and the operation of other electrical equipment. including ground buses. It is necessary to know the phase sequence of the power source to predict the direction of motor rotation. The most common design for onshore installations uses steel sills embedded in concrete. When all sections are set in place. In some cases. the shipping splits must be fastened together in accordance with the manufacturer’s instructions. In order to change the rotation of the motor. These articles specify the required working space around electrical equipment based on voltage to ground.1000 Installation of Electrical Facilities Electrical Manual phasing is indicated throughout the system. The proper torquing of bus bolts is extremely important to eliminate high resistance connections which could result in overheating and eventual failure. B. it is important to know the phase sequence of the system. all that is necessary is to interchange any two of the power lead termination points. Often. In severe earthquake zones. and to parallel systems. to allow proper connection of semiconductor power convertors (such as UPS systems and variable speed drives). If the oil must be installed on site. There is an illustration of this method in Section 600. The manufacturer’s mounting instructions should be followed. oil-filled transformers arrive on site filled with oil and ready to install. spreader bars should be used to prevent damage to the lifting lugs. the entire system should be tested. The point-to-point connections between the shipping splits shown in the vendors drawings must be followed. which are the most delicate part. The pressure should be monitored on a monthly basis to detect leaks. Often. Transformers should be installed where there is adequate ventilation. It is usually desirable to have a manufacturer’s representative test the operation of relays and switchgear breakers. The use of termination kits for stress relief of medium voltage cable is discussed in this section. If oil-filled power transformers are to be stored for considerable lengths of time prior to energization.g. it is important to bring the ground shield back through the CT before terminating it. megohmmeter testing of the bus and cable). the control wiring must be connected using switchgear-grade wire. or bolt the transformer base to the channel. After all terminations have been made. They generate heat and should not be installed where heat can build and cause failure of electrical Chevron Corporation 1000-17 November 1991 . Care should be exercised to prevent damage to the cooling fins. Section 1400 discusses the tests which should be performed prior to commissioning switchgear and MCCs. it is important to have flexibility in the anchoring system as discussed in Section 1072. In most cases. It is desirable to maintain positive internal pressure to prevent the entrance of moisture. the internal pressure should be monitored. One common method of anchoring transformers to pads is to embed steel channel in concrete and either weld. Others can perform the basic electrical testing (e. Onshore transformers are often mounted on concrete pads. vendors install shorting bars on the current transformer terminal strips which require 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. If transformers are moved to the site by a crane or cherry picker. The next step after the interconnection of control wiring is to terminate the power wiring. A pressure-regulated nitrogen cylinder may be used to increase the internal pressure to 2-3 psi above atmospheric pressure. 1073 Installation of Transformers Dry-type transformers should be stored in an environmentally protected location if not installed and energized soon after delivery. In medium voltage systems using shielded cable which passes through window CTs. This must be performed carefully with special equipment to avoid the possibility of moisture entering the transformer. These shorting bars are installed to prevent CT secondary overvoltages from occurring if the switchgear is energized without making the field interconnection wiring.Electrical Manual 1000 Installation of Electrical Facilities Once adjacent bus sections have been connected. It is important that the pads are level. it is best to have a manufacturer’s representative perform the filling operation. In earthquake-prone areas. Once transformers are mounted. A final check should be made with a megohmmeter on all transformers prior to initial energization. They should be installed where this noise will not be an annoyance. These fans draw air from the outside of the enclosure and pass it through the enclosure. Most UPS systems produce noise when they are energized. Prior to energizing an oil transformer. When installing UPS systems. This can be performed with a field test instrument. ensure that all bolts are installed to prevent the entrance of water. porcelain insulators). Case grounding is important for personnel safety. it is recommended that the conductor connected to the neutral be connected to the enclosure as well as ground (ground rod. or grounding electrode system). It is recommended that sufficient cable lengths be left on each of the three conductors inside the junction box to facilitate phase swapping. When closing junction boxes. Most UPS systems have internal ventilation fans which may run continuously or periodically (controlled by a thermostat). Careful attention should be paid to the function of all ventilation systems associated with heat removal. See Section 1400 for further details on testing and commissioning transformers.1000 Installation of Electrical Facilities Electrical Manual components. On large transformers. but usually is best handled by a specialized laboratory. The correct voltage taps should be selected on any tap changers prior to initial energization. They should be mounted on a level surface with sufficient space around the enclosure for adequate ventilation.g. breakers which have been turned on (or off). November 1991 1000-18 Chevron Corporation . the connecting cables can be quite heavy. It may be necessary to mount large UPS systems in air conditioned rooms to aid in heat dissipation. This can be avoided by installing cable strain relief clamps or ties when primary and secondary junction boxes are used. and ground connections should be ensured. a dielectric breakdown test should be performed on the transformer oil to ensure that it has the proper insulation quality. metal deck. 1074 Installation of UPS Systems UPS systems usually are provided with sheet metal cabinets similar to those used for switchgear and MCCs. Dissipation of heat in UPS systems is of prime importance for long life of solid state components. Debris should not be placed on operating transformers since it can interfere with heat removal and possibly become a fire hazard. primary and secondary connections must be terminated.. Tap changers should be padlocked after the correct settings are verified. The weight of cables should not be borne by the transformer terminals (e. spare fuses. It is important that filters be installed prior to energizing the equipment to prevent dust buildup on hot internal surfaces. Transformer enclosures should be grounded. wiring harnesses which have been disconnected. and instructions from the manufacturer. the cabinets should be checked carefully for packing notes. The primary and secondary terminal lugs should be torqued to the proper values when the cables are connected. If the secondary neutral is grounded. Even small control wire terminations should be checked for proper tightness prior to energization. Each of these systems/components has its own grounding requirements which must be followed explicitly. the battery bus. Careful attention should be given to UPS system grounding requirements. Filling batteries with electrolyte (sulfuric acid for lead calcium batteries and potassium hydroxide for NiCd batteries) can be dangerous unless proper safety precautions are taken. The cabinets should be kept closed after energization. When the UPS is initially energized. consult the manufacturer’s manual for maximum storage time and other conditions. the cabinet. These voltages prevent excessive gassing and maintain full charge. This is important for proper battery operation. Suitable goggles. Battery charging. gloves. The battery cables are then connected to the charger. The manufacturer’s operating manual should be read carefully before attempting to start up a UPS system. Chevron Corporation 1000-19 November 1991 . It is important to set the float and equalize voltages to the manufacturer’s recommended values. and the batteries are placed on charge after they are filled. UPS functions should be tested in accordance with the manufacturer’s recommendations. eyewash water and neutralization substances should be available during the filling operation. float and equalize voltage settings of the battery charger should be carefully set to the manufacturer’s specifications. Heat sinks are often at line voltage (not grounded). it is important to fill the batteries with electrolyte and place them on charge fairly quickly. 1075 Installation of UPS Batteries Batteries may arrive either dry or filled with electrolyte. and indications on the UPS panel should be checked for proper operation.” discusses battery commissioning in detail. The battery rack should be assembled prior to filling the batteries. After energization. time in storage. If the batteries need to be stored for a month or more. and specified torques should be ensured on all terminations. boots and aprons should be worn. static switching to the bypass source.Electrical Manual 1000 Installation of Electrical Facilities Sometimes the UPS system cannot be energized until the associated battery has been commissioned. This is an important safety consideration when working inside energized cabinets. the DC output. It often is desirable to have a manufacturer’s representative on site for startup. “Electrical System Checkout and Commissioning. synchronization detection between the UPS output and the bypass source. Specification ELC-MS-4744. The time of receipt. Wiring inside UPS systems often carries high currents. Consult a safety engineer for further information regarding detailed procedures which should be followed. the incoming line. The batteries are then placed in the racks and the cells interconnected. and time of initial charge should be recorded. and the AC output. If they arrive dry. The ones which are marked with an asterisk (*) are included in this manual or are available in other manuals. 1080 References The following references are readily available. and Engineering Forms (EF) ELC-EF-70 Conduit and Wire Schedule 1084 Appendices * Appendix E Installation Practices for Cable Raceway Systems November 1991 1000-20 Chevron Corporation . Division 1 and Division 2 Areas Standard Grounding Details. 1081 Model Specifications (MS) * ELC-MS-1675 * ELC-MS-4377 Installation of Electrical Facilities Standard Electrical Items (P-Items) 1082 Standard Drawings * GD-P87601 * GF-P99544 * GB-P99711 * GD-P99716 Standard Signs and Markers for Underground Cables Standard Mountings for Outdoor Welding Outlets with Circuit Breakers Standard Name Plate Bracket for XP Push Button Station Standard Conduit Connections at Motors Overhead and Underground Conduit Construction for Installing in Class I. This will allow a comparison of the values to determine if there are problems with any of the cells. Data Guides (DG). 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. Grounding Electrodes Standard Grounding Details. Equipment Connections Standard Steel Support Details for RG5 and Aluminum Conduit * GD-P99734 * GF-P99735 * GF-P99935 1083 Data Sheets (DS).1000 Installation of Electrical Facilities Electrical Manual See Section 1300 for additional information on batteries (and particularly the effects of temperature extremes). J. Design and Installation of Electrical Systems for Offshore Production Platforms. 1987 Appleton NEC 1987 Code Review. Illinois 1987 Chevron Corporation 1000-21 November 1991 . F.Electrical Manual 1000 Installation of Electrical Facilities 1085 Other References * API RP 540 * API RP 14F ANSI/IEEE 45 McPartland. New York: McGraw Hill. Appleton Recommended Practice for Electrical Installations in Petroleum Processing Plants. National Electric Code Handbook (19th Edition). IEEE Recommended Practice for Electric Installations on Shipboard. Chicago. and armor for the various wire and cable types are described.1100 Wire and Cable Abstract This section provides guidance in the selection of wire and cable for power. safe. and communication circuits. instrumentation. Areas of concern in wire and cable system design are discussed and typical cables commonly specified are described and illustrated. Flame Retardant Cable and Fire Cable 1135 Thermocouple Extension Cable 1136 Computer Cable 1100-32 1100-21 Page 1100-3 Chevron Corporation 1100-1 March 2001 . and economical service. jackets.” Contents 1110 Introduction 1111 Checklist 1112 Components of Wire and Cable 1113 Areas of Concern in Specifying Wire and Cable 1120 Construction of Wire and Cable 1121 Conductors 1122 Insulation 1123 Outer Jackets 1124 Armors 1125 Shielding 1130 Special Wire and Cable 1131 Instrument and Telemetering Cables 1132 Power and Control Tray Cable (Type TC) 1133 Power Limited Tray Cable (Type PLTC) 1134 High Temperature Cable. insulation. The construction details of the conductors. shielding. lighting. “System Design. The determination of cable ampacities and voltage drop is discussed in Section 100. along with Section 100. This section. control. “System Design” provides guidance in the selection of wire and cable to provide reliable. Control. and Alarm Cable 1145 Thermocouple Extension Cable 1146 Flame Retardant Cable 1147 High Temperature Cable 1148 Fire Hazard Area Cable 1150 Glossary 1151 Definitions 1152 Abbreviations and Acronyms 1160 References 1161 Model Specifications (MS) 1162 Standard Drawings 1163 Data Sheets (DS). Data Guides (DG) and Engineering Forms (EF) 1164 Other References 1100-44 1100-41 1100-39 March 2001 1100-2 Chevron Corporation .1100 Wire and Cable Electrical Manual 1137 Fiber Optic Cable 1138 Shipboard Cables. and Submersible Pump Cables 1140 Typical Wire and Cable Specified 1141 Medium Voltage Power Conductors 1142 Low Voltage Power and Lighting Conductors 1143 Low Voltage Control Cable 1144 Instrumentation. Submarine Cables. Electrical Manual 1100 Wire and Cable 1110 Introduction This section of the Electrical Manual provides guidelines for the selection of wire and cable. “System Design. 4. The issues discussed in this section include. it is recommended that the entire section be reviewed.” and Section 200. the checklist may be useful This section of the manual also provides a source for applicable standards and references • • • 1111 Checklist The following checklist should be reviewed before completing the selection of wire and cable: 1. important selection considerations. review the section on “Special Wire and Cable” and the appropriate Company specification. When using this section. particularly for ambient temperature). The guidelines apply to installations in the United States. depending upon the reader’s familiarity with the topic: • If the reader has minimum experience selecting wire and cable. 3. the applicable foreign codes and standards must be consulted. voltage drop due to load current. special wire and cable. and wire and cable typically specified by the Company. as well as Section 100. and voltage drop due to inrush current? Chevron Corporation 1100-3 March 2001 . 5. “System Studies and Protection” If a review is needed on the selection of wire and cable for a special application. as applicable If the reader is experienced in the selection of wire and cable. For foreign projects. short-circuit conditions. 2. the following alternate approaches are suggested. 7. wire and cable construction details. Is the cable construction suitable for the intended service? Is the voltage rating adequate? Is the number of conductors in accordance with design requirements? Does the NEC (API RP 14F for offshore locations) allow the cable type to be used in the proposed installation method? Is the insulation level suitable for the grounding system and ground fault clearing time? Is the insulation type suitable for the intended service and consistent with Company recommendations? Is the conductor adequately sized for mechanical strength. 6. load current (including any derating. Concentric Stranding. system grounding method. 0 AWG for aerial line applications. Stranded Conductor. Like concentric stranded conductors. and below No. and cost. Insulation The insulation provides isolation of the conductor from other conductors and from ground. XLPE (cross-linked polyethylene). AA. Rope-Lay Stranding. J. and M. Figure 1100-1. Due to the lack of flexibility solid conductors are more common in sizes below No.1100 Wire and Cable Electrical Manual 1112 Components of Wire and Cable Conductor The conductor. and may be referred to as having a reverse lay progression. H. shows an assortment of ropelay strand configurations. March 2001 1100-4 Chevron Corporation . PVC (polyvinyl chloride) and PE (polyethylene). chemical and flame resistance. bunched conductors are available in a variety of ASTM Classes: I. Each sub-strand may in-turn be configured in a concentric or bunched manner. The thickness of the insulation (usually specified in mils) is determined by the voltage rating of the cable. Depending upon the application and need for conductor flexibility concentric stranded conductors are available in a variety of ASTM Classes: A. Stranded conductors are usually arranged in concentric layers around a central core. flexibility (soft or annealed and stranding) and cost. Important considerations for determining the type of insulation include. flexibility. shows different concentric stranded conductors with a progressively larger number of wires. P and Q. Solid conductors come in a wide range of sizes. provides a low impedance path for the flow of electric current. A solid conductor is a single conductor of solid circular construction. detail A. A bunched conductor consists of a group of wires all twisted together in the same direction without regard to physical location. Rope-lay stranded conductors are available in a variety of ASTM Classes: G. A stranded conductor is composed of a multiple wires grouped together to form a single conductor. type of installation. I. detail B. L. A rope-lay stranded conductor is a concentric stranded conductor where the strands (sub-strands) that makeup the various layers are themselves stranded. B. Commonly used insulating materials are EPR (ethylene propylene rubber). Stranded conductors are typically used where improved flexibility is desired for handling and installation. to form a single conductor. Bunched Stranding. K. K. Figure 1100-1. usually copper. O. 8 AWG in insulated conductor applications. Typically each concentric layer is spun in opposite directions. Solid Conductor. M. Some important considerations are size (current carrying capacity). C and D. Figures 1100-1 and 1100-2 illustrate various conductor configurations. In addition. water and chemicals. In particular. bacteria. insects. They may also provide resistance to ozone. polychloroprene (PCP. they may distribute electrical stresses and charges and increase electrical safety. provide hard service protection. polyethylene. Chevron Corporation 1100-5 March 2001 . and afford resistance to fire. they may provide mechanical protection during installation. Materials such as polyvinylchloride (PVC). 1100-1 Conductor Stranding Courtesy of Okonite Wire and Cable Jacket. Outer Armor Jacket and armor serve as protection for the electrical insulation components and the conductors during installation and while in service. and the effects of weather. “Neoprene”) or nylon jackets may be applied over individual conductors or as an overall jacket on a multi-conductor cable. over the overall jacket. act as a barrier to oil. The armor may consist of interlocked steel. braided wire or lead sheath. and rodents. “Hypalon”). Individual. sometimes. Armor is often applied over the cable assembly core and. corrugated metal sheath. chlorosulfonated polyethylene (CSP. sunlight. Overall. An overall extruded jacket (PVC or CSP) may be applied over the armor where corrosion and moisture are of concern.Electrical Manual 1100 Wire and Cable Fig. fungus. 1100 Wire and Cable Electrical Manual Fig. 1100-2 Cable Conductors Courtesy of ABB Transmission and Distribution (a) Standard concentric stranded (c) Non-compact sector (e) Annular stranded (rope core) (g) Rope stranded (b) Compact round (d) Compact sector (f) Segmental (h) Hollow core March 2001 1100-6 Chevron Corporation . 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 Chevron Corporation 1100-7 March 2001 .Electrical Manual 1100 Wire and Cable Figure 1100-3. 1100-6. 1100-5. 1100-4. 1100-4 Typical Instrument Cable Construction Courtesy of Houston Wire and Cable March 2001 1100-8 Chevron Corporation .1100 Wire and Cable Electrical Manual Fig. Electrical Manual 1100 Wire and Cable Fig. 1100-5 Typical PLTC Cable Construction Courtesy of Houston Wire and Cable Chevron Corporation 1100-9 March 2001 . 1100-6 Typical Telemetering Cable Construction Courtesy of Houston Wire and Cable March 2001 1100-10 Chevron Corporation .1100 Wire and Cable Electrical Manual Fig. 1100-7 Typical Thermocouple Cable Construction Courtesy of Houston Wire and Cable Chevron Corporation 1100-11 March 2001 .Electrical Manual 1100 Wire and Cable Fig. can be reduced by providing an overall shield (over all the conductors) if the shield is effectively grounded. Voids or stress concentrations at the conductor could result in corona and. usually copper Concentric wires. caused by external electric fields radiated by a voltage source. A nonmetallic strand shield is normally used on all conductors which are rated over 2000 volts. in time. dielectric failure. Installing these cables in steel conduit will provide additional shielding. 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. caused by external magnetic fields radiated by power circuits. particularly radio frequency interference (RFI). March 2001 1100-12 Chevron Corporation . The strand shield may be a semiconducting tape or an extruded semiconducting material applied over the conductor (extruded is preferred). usually copper A combination of tapes and wires Section 1125. The insulation shield is made up of a nonmetallic extruded semiconducting layer and a nonmagnetic metallic layer. Metallic shields take one of the following forms: • • • Nonmagnetic tapes. EMI. which eliminates voltage stress concentration at the individual conductor strands. The strand shield material must be compatible with both the conductor and the insulation material. “Shielding” discusses metallic shields for power cable in detail. This semiconducting tape or extruded semiconducting layer (extruded is preferred). Its purposes are to eliminate air spaces between the conductor and the insulation and to provide a uniform circular surface. Shield (Control and Instrument Cable) When an installation is prone to electromagnetic interference (EMI). particularly at the edges of the metallic shielding tape. and cross-talk from either internal or external sources. is designed to eliminate voltage stress concentrations between the insulation and the metallic shield. some form of cable shielding will be required.1100 Wire and Cable Electrical Manual Shield (Power Cable) Shielding of electric power cable confines the potential field of the cable to the insulation of the conductor. can be reduced by twisting the wires of each circuit. RFI. It is accomplished by means of a nonmetallic conductor shield and a combination nonmetallic and metallic insulation shield. Bare copper wire is to be softdrawn in accordance with ASTM B3. Company practice is to use copper conductors. cable trays and enclosures. All insulated copper wire is to be annealed in accordance with ASTM B3 and have Class B stranding in accordance with ASTM B8. with Class B stranding in accordance with ASTM B8. caused by the superimposing of signals carried on one wire pair to another wire pair.switchgear. size available) 8 AWG (Min.1/C shielded power cable 15 kV . 12 AWG 14 AWG 16 AWG 18 AWG 8 AWG (Min. transformers. Overhead bare copper wire may be medium-hard-drawn for added rigidity. 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. Cable from ground loop to large motors. thermocouple extension wire. The individual shields must be effectively grounded. can be reduced by providing individual shields on each wire pair and twisting each wire pair.1/C shielded power cable Ground loop cable Cable from ground loop to MCC. tall stacks/vessels. however. Conductors should be stranded to provide flexibility (except AWG 12 and 14 conductors used for power and lighting. 1113 Areas of Concern in Specifying Wire and Cable Conductor Material and Minimum Size Conductor material can be copper or aluminum. size available) 2 AWG (Min. 1100-5. substation fence and pipeway columns.1/C nonshielded power cable 5 kV .Electrical Manual 1100 Wire and Cable Cross-talk. and communication wire). and 1100-7 illustrate individual and overall shields. Medium voltage cable conductors can be either concentric-stranded in accordance with ASTM B8 or compact-round-stranded in accordance with ASTM B496. Copper conductors are required by the Minerals Management Service (MMS) in offshore outer continental shelf (OCS) areas. 1100-6. The Company recommended minimum conductor size for mechanical strength is as follows: Power and lighting (600 V max) Single conductor control (120 V) Single pair or triad for instrument Multi-conductor cable for instrument/control 5 kV . Figures 1100-4. size available) 2/0 AWG 2/0 AWG 4 AWG Chevron Corporation 1100-13 March 2001 . Refer to Section 100. the terminals of devices rated 100 amperes or less are limited to operating temperatures of 60°C. Vendor curves based on ICEA are also available for checking cable fault duty. due to thermal characteristics of the insulation. “System Design” for wire and cable sizing. unless otherwise marked. Then. maximum overload. The ICEA initial and final conductor temperatures (see ICEA P-32. the temperature of the conductor rises rapidly. the cable insulation or sheath may be expanded to produce voids. Ampacity Conductor current-carrying capacity (ampacity) is defined as the current a conductor can safely carry continuously without damage to the conductor. to install larger cables. Likewise. it cools slowly after the short-circuit condition is removed. Maximum Emergency Overload Temperature Normal loading limits of insulated wire and cable are based on many years of practical experience and represent a rate of deterioration that results in the most economical and useful life of cable systems. will give the emergency or overload current rating for the particular insulation type. Minimum conductor sizes for various short-circuit currents and clearing times are shown in Table 79 of IEEE Std 141.382) are shown for the various insulations. Table 76 of IEEE Std 141 gives conductor temperatures (maximum operating. This is especially serious in 5 kV and higher voltage cables. Table 78 of IEEE Std 141 provides uprating factors for short-time overloads for various types of insulated cables. when multiplied by the nominal current rating for the cable in a particular installation. “System Design” for wire and cable sizing. it is generally not cost effective to use a cable above its rated ampacity for extended periods. 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. As a practical guide. Operation at these emergency overload temperatures should not exceed 100 hours per year. It is generally more economical. 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. devices rated in excess of 100 amperes are limited to 75°C. insulation. Note. March 2001 1100-14 Chevron Corporation . The disintegrating insulation may give off smoke and combustible vapors. sheath and surrounding materials. however. and coverings. and such 100-hour overload periods should not exceed 5 during the life of the cable. leading to subsequent failure. Additionally. that unless marked with higher temperature limits. The rate of deterioration is expected to result in a useful life of 20 to 30 years. and maximum short-circuit current) for various insulated cables. Refer to Section 100. when losses are considered. ICEA has established maximum emergency overload temperatures for various types of insulation. owing to its increased resistance since losses increase in proportion to the square of the current. Also. The uprating factor. These vapors may ignite if sufficiently heated.1100 Wire and Cable Electrical Manual Minimum Conductor Size for Short-Circuit Duty Under short-circuit conditions. the greater the currentcarrying capacity. ICEA S-61-402/NEMA WC5-1986. conduit.000 volts. which replaces the old ICEA P-46-426 (1962) two-volume edition. (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. ICEA S-66-524/NEMA WC7-1986 and ICEA S-68-516/NEMA WC81986. Temperature Derating Factor. under the jurisdiction of the NEC. Other ICEA publications describing methods of calculation and tabulation of ampacities are ICEA S-1981/NEMA WC3-1986. 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. cable tray and air. These tables are derived from IEEE S-135. 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. Heat transfer from the cable or conduit is much lower in concrete and soil than in air. The larger the cross-sectional area. cable sheaths. Heat dissipation is lessened as the number of individually insulated conductors (bundled together or installed in conduit) is increased. soil temperature and proximity of other conduits and cables must be considered. NEC Tables 310-16 through 310-19 give ampacities based on ambient temperatures of 30°C and 40°C. The ampacities of wire and cable for different installation conditions. Soil type. trays or other raceways lessens the currentcarrying capacity. Many cable vendors publish ampacities of various types of cable using methods of calculation generally conforming to ICEA P-54-440/NEMA WC511979. The maximum temperature rating of the insulation material should never be exceeded on a continuous basis. The derating factor multi- Chevron Corporation 1100-15 March 2001 . is the major factor affecting conductor current-carrying capacity. and introduced by above-normal ambient temperature. duct. 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). and can be used to determine ampacities of cable installations not covered by the NEC. ICEA Power Cable Ampacities. Underground installation. consult the International Association of Drilling Contractors (IADC) Interim Guidelines for Industrial System DC Cable for Mobile Offshore Drilling Units (IADC-DCCS-1). The higher the ambient temperature. Ambient temperature. Heat generated by the current through the conductor. Number of conductors. direct burial. the less current is required to reach the maximum temperature rating of the insulation. an ampacity correction (derating) factor must be used. Other factors limiting the amount of current a conductor can safely handle are as follows: • • • • • Conductor size. Restricting the heat dissipation by installing the conductors in conduit. ICEA S-65-375/NEMA WC4-1983. are tabulated in NFPA-70. retained by confining the conductors in a raceway.Electrical Manual 1100 Wire and Cable Installation Conditions. At ambient temperatures above or below these. Insulation. Most insulations are classified as organic. anti-oxidants. 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). handling. 1100-8 Properties of Commonly Used Insulating Materials Common Name Thermosetting Crosslinked polyethylene EPR Butyl SBR Oil base Polyethylene Ethylene propylene rubber (copolymer and terpolymer) Isobutylene isoprene Styrene butadiene rubber Complex rubber-like compound Excellent Excellent Excellent Excellent Excellent Excellent Excellent Good Good Good Chemical Composition Electrical Physical March 2001 1100-16 Chevron Corporation . solid dielectric cable ampacities given in NEC Tables 310-69 through 310-76 are based on ambient temperatures of 40°C. The following insulations are in common use: • • Thermosetting compounds. To determine the proper wire size for a particular load refer to Section 100 of this manual. and end use. smaller amounts of materials (in the form of fillers. For temperatures other than these ambients. accelerators. Generally. laminated tapes Mineral insulation. Mineral-insulated (MI) cable employs the one generally available inorganic insulation (MgO). solid dielectric Thermoplastic compounds. Insulation Basic insulating materials are either organic or inorganic. 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 manufacturing. solid dielectric Less common insulations include: • • • Paper-laminated tapes Varnished cloth. and anti-oxidants in varying proportions. Tables 310-77 through 310-84 are based on ambient earth temperatures of 20°C for underground use. Fig. The thermosetting (rubber-like) materials are mixed with curing agents. If more than three conductors are installed in a raceway or cable. fillers.1100 Wire and Cable Electrical Manual plied by the ampacity of a particular conductor at ambient results in a reduced conductor ampacity. cross-linked polyethylene (XLPE) is included in this class. the ampacities must be reduced in accordance with Note 8 following Table 310-19 of the NEC. stabilizers. plasticizers. Medium voltage. and pigments) are added to the thermoplastics. Chevron Corporation 1100-17 March 2001 . Elongation of an insulation (or jacket) when subjected to aging in a circulating air oven is an acceptable measure of heat resistance.Electrical Manual 1100 Wire and Cable Fig. Aging factors (namely heat. Relative Heat Resistance. but provides a relatively quick method of grading materials for possible use at high conductor temperatures or in hot-spot areas. Hypalon Chemical Composition Methyl chlorosilane Tetrafluoroethylene Isoprene Chloroprene Chlorosulfonated polyethylene Electrical Good Excellent Excellent Fair Good Physical Good Good Good Good Good Polyethylene Polyvinyl chloride Polyamide Excellent Good Fair Good Good Excellent Insulation Comparison. Of particular interest is the rapid change in the hardness of polyethylene and cross-linked polyethylene insulations above 100°C. 1100-8 Properties of Commonly Used Insulating Materials Common Name Silicone TFE(1) Natural rubber Neoprene Class CP rubber(2) Thermoplastic Polyethylene Polyvinyl chloride Nylon (1) For example. The following comparisons can be made to gage the properties of different insulations: 1. Temperature ratings of common insulations are shown in Table 76 of IEEE Std 141 and in tables of NEC Article 310-13. moisture. and ozone) are among the most destructive to organic-based insulations. The air oven test at 121°C called for in some specifications is severe. Fig. Heat Aging. Teflon or Halon (2) For example. 1100-9 Typical Values for Hardness vs. 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 2. Figure 1100-9 indicates the effect of temperature on the hardness of insulating materials. flame. and power factor Thermal. crushing. air oven tests followed by exposure to ozone and exposure to ozone at higher temperatures. acids. Solid dielectrics of both plastic and thermosetting types are in common use. in a properly designed and manufactured cable. high density polyethylene. and moisture Chemical. specific inductive capacitance (dielectric constant). The electrical stability of these insulations in water (as measured by capacitance and power factor) is very good. These materials are essentially inert in the presence of ozone (but not of corona discharge). NEC Table 310-13 lists various types of insulated wire according to their type. Moisture Resistance. Insulations in General Use. In one such test. Ozone and Corona Resistance.03% ozone for 3 hours at room temperature. sunlight. Insulations exhibiting superior ozone resistance under accelerated conditions are silicone. Corona discharge produces destructive thermal effects and forms ozone and other ionized gases. cables usually require evidence of approval March 2001 1100-18 Chevron Corporation . and EPR exhibit excellent resistance to moisture (as measured by standard industry tests of ICEA). aids in measuring a material’s ultimate ozone resistance. such as high concentrations of ozone. XLPE. thermal expansion. This phenomenon occurs in solid dielectric PE and is more prevalent in PE and XLPE than in EPR. maximum operating temperature. application and insulation thickness. Insulations in general use for 2 kV and above. Cable Design The selection of power cable for specific applications is based on the following properties: • • • • Electrical. and thermal resistance Mechanical. and alkalies To conform with the NEC. it will be accelerated by contact with water. and PVC. standardized by the Insulated Cable Engineers Association. resistance to impact. Although corona resistance is a property associated with cables over 600 volts. are shown in Table 76 of IEEE Std 141. ozone.1100 Wire and Cable Electrical Manual 3. 5. Insulations such as XLPE. if the degradation phenomenon known as treeing is present. Stability of materials when exposed to oils. However. type and thickness of insulation. 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. resistance. Exposure to accelerated conditions. state and local codes which are under the jurisdiction of a local electrical inspection authority. Compatibility with ambient and overload temperatures. EPR. Toughness and flexibility of jacketing or armoring. polyethylene. 4. damaging corona is expected to be absent at operating voltage. butyl is exposed to 0. abrasion. Conductor size. Other tests for ozone include. Ethylene propylene rubber (EPR) exhibits less susceptibility to such discharge activity than PE and XLPE. Single conductors and multiple conductor cables are available with nominal voltage ratings of 5. without jacket: Type XHHW. neoprene. Low voltage power cables are rated at 600 volts. The combination of crosslinking the polyethylene molecules through vulcanization plus fillers produces superior mechanical properties. extruded semiconducting insulation shield. where additional physical protection is required. • Polyvinyl chloride-insulated.Electrical Manual 1100 Wire and Cable for the intended service by a nationally recognized testing laboratory such as Underwriters Laboratories Inc. with or without jacket: Type RHW for 75°C maximum operating temperature in wet or dry locations and Type RHH for 90°C maximum in dry and damp locations • • • Medium Voltage Cables. extruded semiconducting strand shield. and are used on system voltages of 120. However. and 600 volts. For mechanical protection. The selection of 600 volt power cable is usually based less on electrical requirements than on physical requirements such as resistance to external forces (e. metallic shield and an overall jacket. 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. 25. Medium voltage. However. rubberlike insulations such as EPR are often provided with outer jackets. Vulcanization eliminates polyethylene’s main weakness: a relatively low 105°C melting point.g. 277. 600 volt XLPE compounds are usually filled (carbon black or mineral) to further enhance the toughness of conventional polyethylene. 240. or CSP rubber (such as Hypalon). usually of polyvinyl chloride. extruded insulation. 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.000 volts. Good electrical properties are required for wet locations. 15. 8. (This cable is usually dual-rated THWN/THHN) XLPE-insulated. a jacket may be included over the insulation. Low Voltage Cables. 208. and abrasion). Some cable types are discussed in the following paragraphs. Type MV power cables have solid extruded dielectric insulation and are rated from 2001 volts to 35. 480. crush. and 35 kV. Low voltage cable generally consists of conductors with a single extrusion of insulation of a specified thickness.. the newer EPR insulations have improved physical properties and do not require an outer jacket for mechanical protection. (UL). 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. Chevron Corporation 1100-19 March 2001 . without jacket: Type THW. in some applications. A list of the more commonly used 600 volt cables follows. Medium voltage cables generally consist of the conductor. impact. 85°C for butyl rubber. Fortunately. refer to IEEE Std 141. for details of voltage drop calculations. 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. The maximum operating temperatures are 90°C for EPR and XLPE.1100 Wire and Cable Electrical Manual EPR and XLPE are the most commonly used insulating compounds for Type MV cables. voltage drop calculations require a working knowledge of trigonometry to make exact computations. direct burial. exposure to sunlight. They must be specifically approved for cable tray installation. splicing devices. and messenger-supported cable. Refer to Section 100.” For additional guidance on installation. Wire and Cable in Classified Areas For selection of wire and cable and installation methods to be used in hazardous (classified) areas. cable connectors. Due to the phasor relationships between voltage and current. “Installation of Electrical Facilities. Voltage Drop A working knowledge of voltage drop calculations is required not only to meet NEC requirements. Chapter 11. and approximate formulas are adequate. but also to ensure that the voltage applied to utilization equipment is maintained within proper limits.” Wire and Cable Grounding For proper grounding of cable shields and metallic sheaths/armor refer to Section 900. polyethylene and butyl rubber are also used. in cable trays or by direct burial. most voltage drop calculations are based on assumed limiting conditions. March 2001 1100-20 Chevron Corporation . for offshore installations. and 75°C for polyethylene. Wire and Cable Costs Economics are an important factor in the selection of wire and cable. terminations.” Installation For a discussion on wire and cable installation refer to Section 1000. however. Section 4. Figure 1100-10 illustrates the relative cost comparison for various types of cable. and techniques. “Grounding Systems. “Hazardous (Classified) Areas. “System Design”. See API RP 14F. as well as resistance and reactance. refer to Section 300. Type MV cables may be installed in raceways in wet or dry locations. Actual prices will vary according to market conditions. medium-hard wire is the intermediate between these two. affording adequate strength and the necessary flexibility. thus permitting the desired Chevron Corporation 1100-21 March 2001 . polyvinyl chloride. to temperatures up to 600°F. Insulated conductors sized 10 AWG and larger are stranded (unless otherwise specified). Copper wires and cables are usually manufactured in one of three tempers: hard-drawn. or soft-annealed. is applied over the copper to prevent the sulphur in the rubber from attacking the copper. Aluminum has a lower conductivity than copper and requires a larger conductor. medium-hard. is usually stranded. except for thermocouple extension wire. Copper has the highest electrical conductivity of all commercial metals except silver. shape. Flexibility Flexibility is achieved by annealing and stranding conductors. Otherwise. Coatings If a copper conductor is to be rubber-insulated. lighter in weight. Untinned or bare copper conductors are generally used with such insulations as varnished cambric. size. Several varieties of stranding are achieved by varying the number. or an alloy of tin and lead. It is manufactured in a wide range of tensile strengths. however. a protective coating of pure tin. or vacuum. Copper is used in almost all wire and cable because of its high conductivity.Electrical Manual 1100 Wire and Cable 1120 Construction of Wire and Cable 1121 Conductors Insulated conductors for electrical power transmission are composed of either copper or aluminum. a separator of paper or cotton serving must be used. resulting in lower weight loading for given ampacity. It is. and cost. size. Copper is required for all conductors installed in offshore OCS areas. There is little difference in the conductivity of wires of different tensile strengths. and arrangement of the individual wires comprising the conductor. Some prime considerations in the selection of conductors are flexibility. Annealing is a process in which copper wire is exposed in an inert atmosphere. sizes 12 AWG and smaller (with the exception of flexible cords and fixture wire) are usually solid. Hard-drawn wire has the highest tensile strength and the lowest elongation. therefore. smaller conductor diameters are possible. polyethylene. and asbestos. Instrument wire. Stranding Stranding provides added flexibility. Annealing increases the ultimate elongation of the wire by about 2500% and its electrical conductivity by about 3%. soft-annealed provides the greatest elongation and the lowest tensile strength. 1100 Wire and Cable Electrical Manual Fig. 1100-10 Relative Costs of Cable March 2001 1100-22 Chevron Corporation . 2. however. TW.O P.Q For sizes 7 AWG . Fig. RR.Electrical Manual 1100 Wire and Cable degree of flexibility.20 AWG Chevron Corporation 1100-23 March 2001 .) Special (Some RR. ASTM Classes of Stranding Only ASTM solid and class B stranding are normally used in Company practice. Conductor Construction Different types of conductor construction are illustrated in Figure 1100-2.M. 4.20 AWG For sizes 9 AWG . of the four constructions shown. ASTM class letters set guidelines for cable flexibility.K L. only annular strand is normally used in Company practice. Solid Concentric-stranded Bunched-stranded Rope-lay-stranded Figure 1100-11 provides stranding and application information for ASTM conductors. VC. 3. SO) Welding Cable Bunch Stranded I.20 AWG For sizes 16 AWG . The various forms of conductor construction in order of increasing flexibility are as follows: 1. etc. Machine Tool Wire) Very Special—high flexibility Rope-Lay with Concentric Members G H Portable cables Portable cables on take-up reels Types (W & G) Rope-Lay with Bunched Members I K M Apparatus Cable and Motor Leads Portable Cables (SJO. 1100-11 Application of ASTM Stranding Classes Construction Concentric Lay Class AA A B C D Use Bare Overhead Flexible bare: Slow burning and/or weather resistant (WP) cables Insulated conductors (Types RHW.J. 10 to 7) doubles the crosssectional area and weight. The AWG is retrogressive. 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. from No. For sizes larger than 4/0. and price. that is. operating conditions.g. consequently. and (for standard annealed copper at 20°C) a resistance of approximately 1. 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. 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. a larger number denotes a smaller wire.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. No wire or cable will operate for its expected life at voltages higher than those for which it was designed. and.. 10 to 4) doubles the diameter An increase of 10 gage numbers (e. Instead many types are used.g. from No. The weights and dimensions are given for solid conductor copper wire. The type of insulation used for electrical wire must be carefully considered in selecting cable for a specific application. with each best suited to the service for which it is designed. halves the DC resistance An increase of 6 gage numbers (e. Space limitation is sometimes an additional factor influencing the choice of insulation.89 grams per cubic centimeter.g.. March 2001 1100-24 Chevron Corporation . from No.000 CM. Weights are based on a copper density of 8. load. Solid wire weights should be increased by two percent to obtain the weights for stranded wire • • 1122 Insulation No single type of insulation has been developed to meet all requirements.10 inch. All insulations are designed and constructed to withstand a stated voltage without damage under given conditions. The following approximations can be made using American Wire Gage measurements: • • • • An increase of 3 gage numbers (e.1100 Wire and Cable Electrical Manual Wire Gages The American Wire Gage (AWG) is used almost exclusively in the United States for electric wire sizes 4/0 and smaller. Selection depends upon voltage rating.. Voltage limitation is the prime consideration in selecting the appropriate insulation. the wires are designated by MCM (thousand circular mils). a cross-sectional area of approximately 10. plastic insulations are mechanically stronger than rubber insulations at normal temperatures. relatively low weight. Rubber insulations are more elastic than plastic insulations. and good mechanical properties. plastic materials are usually not cross-linked. and varnished cambric. plastic compounds. 1100-12 Comparison of Wire Gages The various types of insulation presently used may be divided into three major classes: rubber compounds. Most rubber materials are cross-linked. However. 1100-13. Figures 1100-8. 1100-9. Except for polyethylene. and 1100-14 provide information on the properties and uses of various insulating materials. Rubber and plastic materials have good electrical properties. Chevron Corporation 1100-25 March 2001 .Electrical Manual 1100 Wire and Cable Fig. It is flexible and will March 2001 1100-26 Chevron Corporation .001-28.000 15.000 Cross-linked Polyethylene.000 0-2000 2001-5000 5001-8000 8001-15. When thermoplastic materials are heated. conductor size range.1100 Wire and Cable Electrical Manual Cross-linked rubber and plastic materials do not melt when heated and are called thermosetting materials.001-35.000 0-2000 2001-5000 5001-8000 8001-15. 1100-13 Size Range and Corresponding Voltages ICEA Size Rubber 18 & over 14 & over 8 & over 6 & over 2 & over 1 & over 14-1000 8-1000 6-1000 2-1000 1-1000 0-1000 4-1000 8-1000 6-1000 2-1000 1-1000 0-1000 18 & over 14-1000 8-1000 6-1000 2-1000 1-1000 0-1000 Voltage 0-600 601-2000 2001-5000 5001-8000 8001-15. EPR. application.000 0-600 0-2000 2001-5000 5001-8000 8001-15. insulation type.000 15. (XPLE) Ethylene Propylene Rubber. The compounds are rated for 90 °C dry locations (RHH) and 75°C wet and dry locations (RHW).000 28. lists various types of insulations according to their trade name.000 15.000 15. they soften and eventually melt. (EPR) Polyvinyl Chloride (PVC) Polyethylene (PE) Rubber Compounds Ethylene Propylene Rubber (EPR). is a synthetic rubber material. mechanical properties of thermoplastic materials are more dependent on temperature than are thermosetting materials. type letter.001-35.000-28. Rubber and plastic materials that are not cross-linked are called thermoplastic materials. if the temperature is sufficiently low. Brief descriptions of several types of insulation follow. maximum operating temperature. Therefore.001-35. referred to by the NEC as type RHH/RHW. become brittle. Fig. At low temperatures thermoplastic materials stiffen and.000 28. and outer covering. NEC-1987 Table 310-13.001-28.001-28.000 28. insulation thickness. Electrical Manual 1100 Wire and Cable Fig. 1100-14 Typical Values of Properties of Insulation Materials Chevron Corporation 1100-27 March 2001 . control. and other chemicals. ozone. most chemicals. PE insulation is used on instrument and control cables (300 volt or 600 volt maximum). THWN.1100 Wire and Cable Electrical Manual retain its flexibility at low temperatures. PE insulation is thinner and can eliminate the need for an outer covering. 5 kV and 15 kV power wiring systems. API RP 14F recommends EPR. It is no longer available at the 5 kV and 15 kV levels. sunlight. and moisture and possesses excellent electrical properties. when held in place by an outer braid. and flame. thus saving space. Polyethylene is a heat-and light-stabilized thermoplastic. Superior dielectric characteristics make low density (high molecular weight) polyethylene a much better insulating material than high density polyethylene. high density polyethylene makes an excellent. lighting. EPR differs from many other rubber materials because it is resistant to ozone. acids. when it burns it forms a nonconducting ash which. tough jacket material. Silicone Rubber. but not to mineral oils. However. XLPE is made by crosslinking polyethylene. but it is not suitable for DC applications above 40 volts in wet locations. and THHN applications. PVC insulation is resistant to oils. 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. PVC thermoplastic is available in several compounds to meet specific temperature conditions of THW. Cross-linked Polyethylene (XLPE-NEC type XHHW). 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. Its weather resistance is also good. Plastic Compounds Polyvinyl chloride (PVC). 90°C for dry locations (THHN) and 75°C for wet and 90°C for dry locations (THHW). but March 2001 1100-28 Chevron Corporation . Polyethylene (PE). However. It has low dielectric loss characteristics and is highly resistant to moisture. continues to serve as an insulator. ozone. and control wiring (600 volt maximum). XLPE or thermosetting insulation for DC services above 40 volts DC in wet locations to reduce the possibility of electro-osmosis or electrical endosmosis. and remains stable in wet or moist locations. It is designed for long life and continuous operation at temperatures ranging from -60°C to 150°C without losing its high flexibility. THHW. This type of insulation is used for power (600 volt maximum). It is recommended up to a maximum operating temperature of 75°C. oil. and instrument circuits in critical fire hazard areas. It is used on power. which deteriorate the insulation. bases. This insulation is available for 600 volt. EPR has excellent electrical properties and can be used for 600 volt. Silicone rubber is a synthetic rubber compound with excellent temperature resistance properties. minimizes moisture absorption. It has a high dielectric strength. It is also ozone and corona resistant. The compounds are rated for 75°C for wet and dry locations (THW and THWN). EPR is also resistant to most acids. having been replaced by EPR and XLPE. Although it is flame-retardant. flame. it will burn. rot fungus. which demand a highly resistant and protective jacket. and corona. since black resists deterioration by ultraviolet rays. and abrasion. and 15 kV power cables and instrument cables where additional abrasion resistance. oil. gasoline and solvent. Neoprene jackets are used on power cables in mining applications. street lighting. with a suitable compound applied between the layers. acids. ozone. oil. It is highly resistant to heat. and is highly flexible. It is applied in thin films to improve the primary insulation’s resistance to abrasion. bases. sunlight.000 volts for grounded neutral systems. PVC is not recommended for jackets on cables to be used in underwater service. Polychloroprene sheaths are tough and resistant to abrasion. and direct burial cables. It is springy. It is widely used for jackets of power. CSP (trade name. and several chemicals but should not be used in contact with mineral oils. has high dielectric strength and low loss. but heat resistant grades with ratings up to 90°C are available. It is relatively low in cost. the thinner walls of varnished cambric insulation afford a cable of smaller outer diameter. Chlorosulfonated Polyethylene (CSP). depending on the particular compound chosen. Polychloroprene (PCP). fire. or chemical resistance is desired. heat. alkalies. bacteria. oil. Where space is limited. operating at temperatures up to 85 °C. It has been replaced by EPR. The normal useful operating temperature range is 75°C to -40°C.Electrical Manual 1100 Wire and Cable it will not stiffen further at temperatures as low as 0°C. weather. signal. Varnished cambric (NEC Type VC) VC insulation consists of a cotton or linen tape treated with varnish or resin and linseed oil and applied helically around the conductors. Varnished cambric. XLPE is resistant to acids. weather. It is also widely used in shipboard cables. 5 kV. aerial. fire retardation. and on welding cable. This type of jacket is used on 600 volt. Plastic Jackets Polyvinyl chloride (PVC). and grease resistant. Nylon.or XLPE-insulated wire. This improves weather resistance. This type of insulation wire is no longer used by the Company. but a thick application causes loss of flexibility. Maximum operating voltage is 28. PVC compounds should be black for outdoor use. It is moisture. Chevron Corporation 1100-29 March 2001 . 1123 Outer Jackets Outer jackets used on electrical cables and wires may be divided into two categories: • • Rubber Jackets Plastic Jackets Rubber Jackets Neoprene. Nylon is used as an extruded covering to protect individual insulations. on portable cable. Polyvinyl chloride thermoplastic is a synthetic resin which provides resistance to oils. Hypalon) is a synthetic rubber material with properties similar to chloroprene rubber. control. The temperature range is approximately -50°C to 105°C. Fig. March 2001 1100-30 Chevron Corporation . Nylon coverings are used primarily for cables in gasoline stations. lead sheaths are rarely used today. The question should be referred to the cable manufacturer. 1100-15 Properties of Cable Jacket Materials Material Neoprene Class CP rubber(1) Polyethylene low density high density cross linked Polyvinyl chloride Polyurethane Nylon Note Abrasion Resistance Good Good Flexibility Good Good Low Temperature Good Fair Heat Resistance Good Excellent Fire Resistance Good Good Fair Excellent Good Fair Excellent Excellent Poor Poor Poor Good Good Fair Poor Poor Poor Fair Good Good Fair Good Excellent Good Good Good Poor Poor Poor Fair Poor Fair Chemical resistance and barrier properties depend on the particular chemicals involved. embedment in concrete. (1) For example. Longitudinally welded and continuously extruded corrugated sheaths (usually aluminum) offer mechanical protection superior to and at a lower weight than interlocked armor. 1124 Armors Corrugated Metal Sheath. 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.1100 Wire and Cable Electrical Manual Its temperature range is -20°C to 105°C. or in areas with environments that are corrosive to the metal sheath. shipboard control cables. Hypalon Lead Sheath. An overall extruded nonmetallic jacket must be used over the metal sheath for direct burial. and on THHN and THWN wire. Corrugated sheaths are recommended for pliability and increased radial strength. For properties of various types of outer jacket materials refer to Figure 1100-15. 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. This sheath offers maximum protection from moisture and liquid or gaseous contaminants. 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 . A lead sheath is used in cables for underground installation to protect a varnished cambric or rubber insulation from moisture. and cross the cable surface at many different potentials. aluminum. The metallic shield must be effectively grounded as described in Section 900. A jacket can be added over the armor for moisture and corrosion resistance.Electrical Manual 1100 Wire and Cable Braided Wire Armor. or aluminum rounded and interlocked tapes protect cables from damage (during and after installation) and are applied directly over the outer jacket. Interlocked armor is not recommended for Company installations. or bronze. A shielded electric power cable uses conducting or semiconducting layers. the stress control layers at the inner and outer insulation surfaces present a smooth surface to reduce the stress concentrations and minimize void formation. For unshielded cable operating on 4160-volt systems. to confine the electric field of the cable to the insulation surrounding the conductor. Bronze. The equipotential surfaces for the unshielded system are cylindrical. the equipotential surfaces are concentric cylinders between the conductor and the shield. the outer shield confines the electric field to the space between the conductor and the shield. The voltage distribution follows a simple logarithmic variation. eventually to the point of failure. The inner (strand shield) stress relief layer is at or near the conductor potential. Braided. Interlocked Armor. “Grounding Systems. eliminating any tangential or longitudinal stresses within the insulation or on its surface. the tangential creepage stress to Chevron Corporation 1100-31 March 2001 . The outer (insulation) shield is designed to carry the charging currents. It is being replaced by the corrugated metal sheath. basket weave metal armor is constructed of fine metal wires of galvanized steel.” By their close bonding to the insulation surface. 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. In other words. This type of armor is used extensively on shipboard cables to provide lightweight mechanical protection in accordance with IEEE Std 45. minimizing surface discharges Protects cable from induced potentials Limits electromagnetic interference (EMI/RFI) In a shielded cable. Ionization of the air in such voids can progressively damage certain insulating materials. but not concentric with the conductor. The conductivity of the shield is determined by its cross-sectional area and its resistivity (in conjunction with the semiconducting layer). closely fitted or bonded to the inner and outer surfaces of the insulation. 1125 Shielding Power Cable Shielding Refer to Figure 1100-3 for a typical shielded MV cable. The lines of force and stress are uniform and radial and cross the equipotential surfaces at right angles. galvanized steel. and the electrostatic field is confined entirely within the insulation. Interlocked armor provides mechanical protection against compression and impact. however. This type of shield provides 100% coverage and can be applied in the same manner as a helical tape on a power cable. If the surges. 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. for transmitting March 2001 1100-32 Chevron Corporation . 1131 Instrument and Telemetering Cables Instrument Cable Although similar to other cables used to interconnect electronic devices. properly designed nonshielded cables (as described in the NEC) limit the surface energies. Surface tracking. caused by changes in the operating state of these high voltage conductors. and destructive discharges to ground could occur. induced potential To limit electromagnetic interference (EMI). including the following: • • • • To reduce shock hazard To protect the cable from extraneous. 1130 Special Wire and Cable It is recommended that all cables be listed by a nationally recognized testing laboratory (NRTL) such as Underwriters’ Laboratories (UL). particularly radio interference (RFI) To confine the electric field generated by the conductors For control and instrument cable shielding. instrumentation cables are specifically designed for ease of installation. This conducting material can be nonmetallic or metallic. Control and Instrument Cable Shielding Control and instrument cable shielding usually consists of a layer of conducting material completely covering the core of cable conductors. If nonmetallic. control errors (and even severe damage to apparatus supplied by the cable) may result. A drain wire in intimate contact with the shield throughout the length of the cable (used for grounding the shield) should be provided. or an overall shield. A cable shield over an individual pair. The most common shielding method for control and instrument cables consists of an Aluminum-Mylar tape applied helically over the cable core. it should be supplemented by a metallic conductor of sufficient conductivity to provide effective shielding. induced potentials and EMI (particularly RFI) are of particular interest because cables are frequently operated in areas of high disturbance by high voltage power conductors. burning. has several functions.1100 Wire and Cable Electrical Manual ground at points along the cable may be several times that recommended for creepage distance at terminations in dry locations. are permitted to induce a voltage on the control cable conductors. cutting. and shielding are all selected to resist damage from water absorption. Cables used for communications. Figure 1100-6 shows various types of telemetering cable construction. abrasion. single triad. remote control. bending. control. refer to Section 1133. shielding techniques. a staggered lay is employed to reduce cross talk. and communication circuits where superior electrical characteristics (shielding from electromagnetic and electrostatic interference) are required. Electrical interference is minimized by twisting conductors in a tight lay configuration to counter the effects of electromagnetic interference (EMI). Jacketing. These cables are available with either PVC or PE outer jackets. an Aluminum-Mylar tape shield over each pair is the recommended remedy. particularly radio frequencyinterference (RFI). refer to Section 1125. Instrument cables are designed to minimize mechanical failures. noise. pulling. In multi-pair cables. or as aerial cable supported by a messenger wire. and insulation material to meet the technical requirements of different types of equipment and installations. for maximum durability. “Power Limited Tray Cable (Type PLTC). For instrument cables installed in cable tray. See Section 1125 for further details. in metallic or nonmetallic conduit (above or belowground). and cross talk. Instrument cable can be installed in cable tray. pilot relay operations. The PVC-jacketed cables are more flexible and are flame-retardant. Where critical signal inputs could be affected by EMI. however. This type of cable is particularly suited for applications where the cable will normally transmit low level DC or communication signals. Cable used for fire protective signaling systems must comply with NEC Article 760. Most of these cables are designed to protect a desired signal—reducing hum. Multi-conductor instrumentation cables are manufactured in a wide range of sizes. ELC-MS-3551. multi-pair or multi-triad cable construction and must comply with NEC Article 725. For shielding techniques. and data transmission are all included in this category. and temperature extremes. instrumentation.Electrical Manual 1100 Wire and Cable signals and energy with minimal interference. but where there is also a need for emergency transmission of 110 volt AC signals as well. chemical and oil contamination. and to comply with recognized industry standards. conductors. Effective shielding designs and insulating techniques maintain signal integrity over a wide diversity of conditions and environment. The cables are shielded to protect against electrical interference from external sources. insulation. the PE-jacketed cables have superior resistance to cracking when flexed at low temperatures. Reference Specification.” Telemetering Cable This cable is used in telemetry. Instrument cable is available in single pair. Chevron Corporation 1100-33 March 2001 . crushing. Figure 1100-4 shows typical instrument cable construction. Use of Type TC tray cable is permitted (1) for power. and 502 of the NEC. unless identified for such use. 501. or both. A metallic sheath is not permitted either under or over the nonmetallic sheath. When installed in wet locations. The outer jacket material is nonmetallic and flame-retardant. and resistant to oil. (2) in cable trays. The insulated conductors are available in sizes 22 AWG through 16 AWG. sunlight. unless identified as sunlight-resistant. in raceways.1100 Wire and Cable Electrical Manual 1132 Power and Control Tray Cable (Type TC) Power and control tray cable (Type TC) is a factory assembly of two or more insulated conductors (with or without associated bare or covered grounding conductors) under a nonmetallic sheath. 501. Type TC tray cable must not be installed (1) where exposed to physical damage. (2) one or more group assemblies of twisted or parallel conductors. The outer sheath is a nonmetallic material that is flame-retardant and resistant to oil. sunlight (if specified) and moisture. control. and moisture. and 502 of the NEC. (3) where directly exposed to rays of the sun. A metallic shield or a metallized foil shield with drain wire(s) is permitted either over the cable core. and communication circuits. March 2001 1100-34 Chevron Corporation . Figure 1100-5 illustrates the construction details of typical power limited tray cables. Type TC cable must be resistant to moisture and corrosive agents. approved for installation in cable trays and raceways or where supported by a messenger wire. The cable can also be installed in cable trays in hazardous (classified) locations under specific conditions specified by Articles 318. lighting. or supported by a messenger wire. 1133 Power Limited Tray Cable (Type PLTC) Type PLTC nonmetallic-sheathed. or (3) a combination thereof. process control and computer cable transmitting low level signals. or (4) by direct burial. power-limited tray cable is a factory assembly of two or more insulated conductors under a nonmetallic jacket. The conductor material is copper (solid or stranded). Insulation on the conductors is suitable for 300 volts. signal. or directly buried (if the cable is listed for this use). Type PLTC cable is designed for use in Class 2 or 3 circuits (in accordance with NEC Article 725) as instrumentation. supported by messenger wires. 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. (2) as open cable on brackets or cleats. The cable is marked TYPE PLTC and can be installed in cable trays or raceways. The allowable ampacity of the conductors is defined in NEC Articles 400-5 and 318-11. The cable core is either (1) two or more parallel conductors. over groups of conductors. The cables are marked TYPE TC. (3) in cable trays in hazardous (classified) locations under specific conditions outlined in Articles 318. For general processing plant use. for 300 volt power-limited tray cable Type TC. Type MC. • • • Type PLTC. Flame Retardant Cable and Fire Cable High Temperature Cable Asbestos insulations (NEC Type A or AA) are used for high temperature applications. Flame Retardant Cable Insulated conductors and cables that will be installed in a cable tray and all cables used offshore must pass a flammability test. Teflon-insulated (as well as silicone rubber insulated) wire is recommended where high heat and contact with oil. Type MC cables with a nonmetallic outer covering are tested and will carry the above legend if the jacket is flame retardant. to be approved for cable tray use. Silicon rubber has good chemical-. Fire Cable SI fire cable is designed for use with critical motors (mainly MOVs) and controls that must be operable during a fire. fiberglass. up to 200°C. For higher temperatures.4d(5) for flammability tests required for cables used in OCS areas offshore. The cable is constructed with nickel conductors. All single conductors and multi-conductor cables must pass the UL vertical tray flame test. Teflon-insulated (FEP) wire can be used for conductor temperatures up to 200°C. Teflon. The flame test is used to ensure that in the event of a fire in or around the cable. Section 4. or combinations thereof are recommended. water. Chevron Corporation 1100-35 March 2001 . which are imprinted on the outer surface of a single conductor or on the jacket of a cable. silicon dioxide insulation. which is identical to IEEE 383. and oil-resistant properties. or chemicals are expected. Type MV cables. PVC insulation with a PVC jacket is recommended for applications below 105°F. the conductors or cables will not transmit the fire to another area. 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. silicone. mica. Consult API RP 14F.Electrical Manual 1100 Wire and Cable 1134 High Temperature Cable. Pyrometer wiring is available with many types of insulation. Insulated conductors and cables that pass this flame test are identified by the following legends. It is best known for its resistance to heat and can be used for conductor temperatures as high as 125°C. These cables can operate at over 2000°F without failing. Both FEP and silicone-rubber-insulated wires are more expensive than ordinary insulations. moisture-. particularly in dry locations. for single conductors. for 600 volt power and control tray cable For CT Use or For Use in Cable Trays. Various types of insulation are used: PVC. Figure 1100-7 shows a typical construction. Various types of jackets (PVC. impedance as required. Same as coaxial cable except with two twisted conductors • March 2001 1100-36 Chevron Corporation . foam polyethylene insulation.7b(1) for requirements of cables used for fire pumps in OCS areas offshore. One 22 AWG copper conductor. as in computer and other data processing systems.1100 Wire and Cable Electrical Manual and an outer stainless steel sheath. an Aluminum-Mylar tape shield can be used to provide 100% coverage for excellent shielding effectiveness. Reference ELC-MS-3552 for further information. Consult API RP 14F. CSP or PE).1. 105° PVC for fire hazard areas. Thermocouple extension cable conductors must match the specific type of thermocouple (see ANSI/MC 96. are used over individual pair and over multi-pair cable. one chromel and one alumel conductor for higher temperature ANSI/ISA type K thermocouple probes. 300-volt rated cable. shielded. overall PVC jacket. Teflon should be used in fire hazard areas. silicone rubber mica tapes. solid conductor. Where individual or overall shielding is required. thereby avoiding electrical reflection that can distort signal strength and decrease quality Vendor catalogs should contain data on the preceding parameters. glass braid. bare or tinned copper braid shield. or Hypalon for PLTC-type cable. The jacket required depends on the installation—for example. rated for 30 volts and 60°C Twin axial cable. 1135 Thermocouple Extension Cable Thermocouple extension cable consists of single-pair or multi-pair twisted. and Teflon tapes. The basic construction features of a few computer cables are as follows: • Coaxial cable. the interconnecting cable must have the following specific characteristics: • • • • 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. either solid or stranded. 90°C PVC for normal use. Temperature Measurement Thermocouples): one iron and one constantine conductor for use with ANSI/ISA type J thermocouple probe. Section 9. 1136 Computer Cable Where high-speed transmission is required. thereby maintaining peak voltage and signal shape Proper characteristic impedance to prevent mismatch with that of the system receiver. bare or tinned. Other conductor materials are available for very high temperature applications. A copper drain wire in intimate contact with the shield throughout the length of the cable is provided for grounding the shield. For low-loss transmission. in general. and high-density signal channels. cable tray. Section 4. PVC insulation. 90. This cable is not recognized by the NEC for onshore installations. The four major fiber parameters used in selecting the proper cable for an application are bandwidth. and Submersible Pump Cables Shipboard Cable Commercial shipboard cable as specified in IEEE Std 45 is permitted by API RP 14F. and core diameter. It offers numerous advantages for the transmission of signals and data with complete freedom from EMI. individual and overall Aluminum-Mylar tape shields. A basket weave armor of bronze or aluminum is applied over the outer 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. foam polyethylene insulation.4. These parameters should be defined in vendors’ catalogs. rated for 30 volts and 60°C IEEE 488 interface cable. Six twisted pairs and 11 single 26 AWG conductors. overall PVC jacket. and is required for offshore classified area applications. Chevron Corporation 1100-37 March 2001 . the core region has a varying or graded refractive index.overall tinned copper braid. Section 18 for additional construction details. The individual optical fiber is the signal transmission medium and is very similar in function to an individual optical wave guide. They can be installed in conduit. 1138 Shipboard Cables. PVC. respectively. tinned copper. The fiber has an all-dielectric structure consisting of a central circular transparent core that propagates the optical radiation and an outer cladding layer that completes the guiding structure. numerical aperture (NA). The cables are rugged enough for many applications and installation conditions. XLPE or silicone rubber insulation with maximum temperatures of 75. EPR. An overall PVC or CSP jacket can be added. by direct burial or as aerial cable with messenger wire support. 90. and process control. To achieve high signal bandwidth. Refer to IEEE Std 45. and 100°C. to be installed in classified locations on offshore platforms. They provide wide bandwidth. 1137 Fiber Optic Cable Fiber optic cable has been developed to replace the usual copper wire cable in many communication and instrument cable applications. light weight. underground duct. Submarine Cables. overall PVC jacket. conductor shielding as required. consists of copper stranded conductors. instrumentation.Electrical Manual 1100 Wire and Cable • Synchronous EIA interface cable. Fiber optic cables can be used for a variety of applications—including communications. data transmission. Fourteen conductors. the fiber is typically polymer-clad silica (PCS) with a core of silica glass and cladding of glass or polymer material. and PVC or CSP jacket. Fiber optic cables offer long distance transmission without the use of repeaters. attenuation. Cable construction. application of commercial shipboard cable is as follows: • • • • 600 volt maximum power and lighting: PVC. cabled together with jute or polypropylene fillers. center strand filled. shielded as required 600 volt control cable: PVC. EPR insulation. polyester-coated instrument conductor. This cable consists of flat. extruded semiconducting insulation screen. higher voltage systems are occasionally used. construction must be highly resistant to undersea environments. 133% EPR or XLPE insulation. normally. or XLPE insulation Instrument cable: PVC insulation Refer to Section 19 of IEEE Std 45 and Section 4. a solid copper. an asphalt-impregnated jute or PE bedding layer.” Submersible Pump Cable Submersible 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 pressures up to 5000 psig. “Installation of Electrical Facilities. Voltage levels of 5 kV and 15 kV are common.. The basic construction of some types of submersible pump cables is as follows: • Flat Oil Well Cable (5 kV). EPR. • March 2001 1100-38 Chevron Corporation . and galvanized steel interlocked armor.4 of API RP 14F for more application details. Round Armored Downhole Cable (3 kV).A. a layer of EPR insulation. Cable voltage ratings from 2 kV to 5 kV are typical. IEEE Standard 1018 and 1019 may be used as guides.1100 Wire and Cable Electrical Manual In general.” Submarine Cable Submarine cables are used to supply power from shore to offshore platforms and from offshore platform to offshore platform. Obviously. Eastern Region-EL&P’s “Electrical Construction Guidelines for Offshore Marshland and Inland Locations. Sample specifications for 5 kV and 15 kV submarine cable are included in Chevron U. EPR. a moisture-resistant rubber compound overall jacket. and two layers of galvanized steel armor. an equal number of groups of communications pairs). This cable consists of three coated and stranded copper conductors. and Section 1000. when required. Typical construction is as follows: three-stranded copper conductors (and.S. and copper tape shield over individual conductors. extruded semiconducting strand screen. It is for use at temperatures up to 240°F (116°C) and is manufactured in Sizes 6 AWG to 1 AWG. layers of fused Kapton (a Dupont film). parallel construction of three solid copper conductors. It is for use where the ambient temperature is up to 350°F (177°C) and is manufactured in Sizes 6 AWG to 2 AWG. For more details and application information refer to the vendors’ catalogs or contact vendors. Section 4 of API RP 14F. or XLPE insulation 2 kV and 5 kV power: EPR or XLPE insulation. moisture-resistant rubber compound jacket. galvanized steel wire armor. and an overall jacket which is resistant to underwater environments. For cable installation details refer to Section 20 of IEEE Std 45. single conductor. Type THHN/THWN with nylon jacket. It is installed in aboveground or underground conduit and as messenger-supported aerial cable. 600 volt. PVC-insulated for dry and wet locations. as follows: • • • • Type THW: 75°C. single conductor cable of sizes 250 MCM and larger can be installed in cable tray. UL-83. To be used on special applications where superior electrical characteristics and/or flexibility at low temperatures is required. 600 volt. 1141 Medium Voltage Power Conductors Typical practice is to use UL-listed single conductor. 600 volt. XLPE-insulated for wet locations.4 kV and in certain non-critical 5 kV services provided that they meet the requirements of NEC Articles 310-6 and 7. 90°C (UL) for dry locations. Type RHH/RHW with or without jacket. type MV-90. copper. If flame retardant. UL-83.Electrical Manual 1100 Wire and Cable • Round Armored Downhole Cable (3 kV). 600 volt rated wire. It is purchased without a Company specification. 1142 Low Voltage Power and Lighting Conductors Typical practice is to use UL-listed. Nonshielded cable may be used in systems operating at 2. shielded. These wires can be installed in aboveground and underground conduit. This cable has the same construction as round armored downhole cable except that the insulation is a polypropylene-based compound suitable for temperatures up to 190°F (88°C). refer to vendors’ catalogs or contact the vendor. When installed in cable tray or in direct burial systems. UL-44. UL-listed multi-conductor armored cable type MC-MV90 is used with a corrugated welded or extruded aluminum sheath. PVC-insulated for dry and wet locations at 75°C (UL) and for dry locations at 90°C (UL). 600 volt. 1140 Typical Wire and Cable Specified The following descriptions apply to typical wire and cable used in Company onshore facilities. It is manufactured in Sizes 6 AWG to 1 AWG. copper. A jacket over the armor may be required for moisture and corrosion resistance and direct burial. Type XHHW: 75°C. For more details and application information on downhole cable. For description of cables typically used offshore refer to API RP 14F. 133% EPR insulated cable in accordance with ELC-MS-2447. 5 kV or 15 kV. Chevron Corporation 1100-39 March 2001 . UL-44. EPR-insulated for dry and wet locations at 75°C (UL) and for dry locations at 90°C (UL). When installed in cable tray. Multi-conductor cable may be used as aerial cable when messenger-supported. and 300 volt rated. For temperatures above 200°C. shielded. single triad. A minimum of 18 AWG is recommended for mechanical strength. 16 AWG for single pair in conduit and 18 AWG for multi-pair in conduit or in cable tray.e. Multi-conductor cable can be run in conduit or in cable tray (if labeled TC). or “for TC use”). March 2001 1100-40 Chevron Corporation . Type MC 600 volt armored cable with a corrugated welded or extruded aluminum sheath is recommended for exposed cable tray or direct burial installation. Control. oil. It is run in aboveground or underground conduit. sunlight and moisture on all cables installed in cable tray. This is discussed in Section 1146. the outer jacket must be flame retardant. Single pair or triad is run in conduit. “Type PLTC”. and Alarm Cable Typical practice is to use single pair. 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. The minimum conductor size is 14 AWG for 120 volt AC motor control. The minimum sizes are. 1143 Low Voltage Control Cable Typical practice is to use UL-listed single conductor. “Type TC”. Cables should pass the UL 383 vertical tray flame test and be identified as to usage (i. 600 volt rated wire of the types indicated in Section 1142. copper.1100 Wire and Cable Electrical Manual Multi-conductor cables containing Types XHHW or THHN/THWN conductors may also be provided with a flame retardant jacket for use in cable tray. 1145 Thermocouple Extension Cable Typical practice is to use single pair or multi-pair twisted. It is recommended that cables meet the requirements of ELC-MS-3552. the minimum recommended wire sizes are 20 AWG. multi-pair or multi-triad cable in accordance with ELC-MS-3551. 1147 High Temperature Cable The typical practice for high temperature areas is to use silicon rubber or teflon insulations. 1144 Instrumentation. 1146 Flame Retardant Cable The typical practice is to use PVC or CSP (Hypalon) outer jackets that are resistant to flame.. glass reinforced mica tapes are recommended. in which the higher numbers represent the smaller conductor diameters. a number of fine wires are twisted together in a common direction. B & S: (Brown and Sharpe Gage). stranded conductor. A wire diameter standard that is the same as the AWG system. Specifically. 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. which is detrimental to the dielectric material and outer coverings of cables. Bunch Stranding: A method of twisting individual wires to form a finished.Electrical Manual 1100 Wire and Cable 1148 Fire Hazard Area Cable The typical practice in fire hazard areas is to use insulation of mica tapes and glass braid impregnated with a silicone finish on instrument. thus forming a rounded core. This measure is also known as the cross-sectional area of a wire. In determining wire sizes. (See definition of Cross-Sectional Area. permits only a small or negligible current to flow through it. Circular Mil Area: The area of a conductor equal to the square of the diameter in mils (0. AWG: (American Wire Gage). Cross-Sectional Area: The sum of the cross-sectional areas of the component wires. Chevron Corporation 1100-41 March 2001 . thermocouple and control circuits in accordance with ELC-MS-3551. 3552. all wires are of the same size and the central core is a single wire. 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. and 3553. when placed between conductors at different potentials. without regard to exact position. the circular mil area of one of the strands is determined and multiplied by the total number of strands in the conductor. Cable Filler: The material used in multi-conductor cables to occupy the interstices of the insulated conductors.001 inches).) 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. Dielectric: A medium or material which. Corona: An electrostatic discharge at high voltage resulting from ionization. 1150 Glossary 1151 Definitions Ampacity: Current carrying capacity of electric conductors. and with a uniform pitch (twist per unit of length). A system for classifying sizes of cable conductors. expressed in amperes. Usually. Higher values indicate higher losses. yarn. Jacket: A covering. March 2001 1100-42 Chevron Corporation . Ozone: A form of oxygen produced by the passage of electrical discharges or sparks through air. and (sometimes) the armor of a cable. applied over the insulation. metallic sheath. Drain Wire: A bare conductor. 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. This value is an indication of losses in the cable during operation. used to connect the shield to ground.A. usually in a metallic shielded instrument cable. Serving: Wrapping applied over the core of a cable to hold it in a cylindrical configuration before it is jacketed or armored. sometimes fabric reinforced). used in the U. Extrusion: A process consisting of flowing plastic insulation material through forming dies. and surrounded by one or more helically-laid groups of wire. It is usually expressed in volts rms. which can be considered the applied dielectric. It is detrimental to cable insulations and outer coverings.S. This type of stranding offers the highest degree of flexibility. which are also stranded in the manner of the center core. or from ground. 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. The commonly used materials are filaments. Insulation: A nonconducting material used to prevent leakage of current from a conductor and to isolate a conductor from other conductors. Dielectric Strength: The ability of an insulating material to resist rupture by electrical potential. and subsequently cooling the insulation material in a homogeneous solid cylinder around the wire. conducting parts. core. fibers. The maximum voltage which a dielectric can withstand for a short time without breakdown or rupture. It is expressed as right. Dielectric Constant: That property of a dielectric which determines the electrostatic energy stored per unit volume for unit potential gradient. This type of stranding differs from concentric stranding only in that the main strands are themselves stranded.or left-hand lay. Flex Life: The resistance of a conductor to fatigue failure when bent repeatedly. (usually thermoplastic or thermosetting material. and tape. Mil: One-thousandth of an inch.1100 Wire and Cable Electrical Manual The term dielectric is almost synonymous with electrical insulation. to measure wire or cable diameter. The serving is for mechanical protection and not for insulating purposes. Usually a numerical value given relative to a vacuum. Usually expressed as volts per mil. Operating Voltage: The voltage at which a cable is actually used. a metallic tube. This shield can be braided or served wires. Voltage rating is given as phase-tophase voltage. foil backed tape.Electrical Manual 1100 Wire and Cable Sheath: An outside covering that protects a cable from mechanical injury or from the harmful effects of water. Treeing: Treeing is a gradual deterioration of insulation developed under voltage stress. This type of construction usually is employed for instrumentation and communication cables. Temperature Rating: The maximum temperature at which the insulating material may be used in continuous operation without degradation of its basic properties. Voltage Rating: The highest voltage that may be continuously applied to a wire or cable in conformance with ICEA Standards. oils. foil wrap. made firm by filler material and finished with a common protective covering. usually expressed in percentage. the shielding effectiveness is in direct proportion to the amount of coverage. 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. Stranded Conductor: A conductor composed of a group of bare wires twisted together. acids. 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 identification. and chemicals. 1152 Abbreviations and Acronyms A AC ANSI API AWG B&S CM CSP DC EMI EPR Ampere Alternating Current American National Standards Institute American Petroleum Institute American Society for Testing and Materials American Wire Gage Brown and Sharpe (Gage) Circular Mil Chlorosulfonated Polyethylene (Hypalon) Direct Current Electromagnetic Interference Ethylene Propylene Rubber ASTM - Chevron Corporation 1100-43 March 2001 . or conductive vinyl or rubber. The name “treeing” is derived from the branched appearance of the deterioration channels on the affected insulation. When a metallic braid of tinned or bare copper is applied over the insulated conductors. Those marked with an asterisk (*) are included in this manual or are available in other manuals. 1161 Model Specifications (MS) *ELC-MS-2447 *ELC-MS-3551 *ELC-MS-3552 *ELC-MS-3553 5 kV and 15 kV Insulated Power Cable Instrument and Control Cable Single and Multi-pair (or Multitriad) Construction Twisted and Shielded Thermocouple Extension Cable Single and Multi-pair Construction 600 Volt Multi-conductor Control Cable 1162 Standard Drawings There are no standard drawings in this section.1100 Wire and Cable Electrical Manual ICEA IEEE ISA MC MCM MI MV NEC NFPA NRTL PCP PE PLTC PVC RFI RMS TC UL XLPE - Insulated Cable Engineers Association Institute of Electrical and Electronics Engineers Instrument Society of America Metal Clad Thousands of Circular Mils (or kcmil) Mineral Insulated Medium Voltage National Electrical Code National Electrical Manufacturers Association National Fire Protection Association Nationally Recognized Testing Laboratory Occupational Safety and Health Administration Polychloroprene (Neoprene) Polyethylene Power Limited Tray Cable Polyvinyl Chloride Radio Frequency Interference Root Mean Square Tray Cable Underwriters Laboratories Cross-Linked Polyethylene NEMA - OSHA - 1160 References The following references are readily available. March 2001 1100-44 Chevron Corporation . AEIC CS6. IEEE Recommended Practice for Electric Power Distribution for Industrial Plants. Specification for Lead-Coated and Lead-Alloy-Coated Soft Copper Wire for Electrical Purposes ASTM B496. Hard. Specification for Concentric-Lay-Stranded Copper Conductors.Electrical Manual 1100 Wire and Cable 1163 Data Sheets (DS). 1164 Other References American Petroleum Institute Practices (API) API RP 14F. Medium-Hard. Specifications for Ethylene Propylene Rubber Insulated Shielded Power Cables Rated 5 Through 69 kV. for Electrical Conductors ASTM B174. Specification for Soft or Annealed Copper Wire ASTM B8. Specification for Hard-Drawn Copper Wire ASTM B2. Specification for Bunch-Stranded Copper Conductors for Electrical Conductors ASTM B189. data guides or engineering forms with this section. or Soft ASTM B33. for Electrical Conductors ASTM B173. Specification for Medium-Hard-Drawn Copper Wire ASTM B3. Standard 141. Specification for Tinned Soft or Annealed Copper Wire for Electrical Purposes ASTM B172. Data Guides (DG) and Engineering Forms (EF) There are no data sheets. Specifications for Thermoplastic and Cross-linked Polyethylene Insulated Shielded Power Cables Rated 5 Through 46 kV. Specification for Rope-Lay-Stranded Copper Conductors Having Concentric-Strand Members. Chevron Corporation 1100-45 March 2001 . Specification for Rope-Lay-Stranded Copper Conductors Having Bunch-Strand Members. Recommended Practice for Electrical Installations in Petroleum Processing Plants American Society for Testing and Materials (ASTM) ASTM B1. Design and Installation of Electrical Systems for Offshore Production Platforms API RP 540. Institute of Electrical and Electronic Engineers (IEEE) ANSI/IEEE. Specification for Compact-Round-Concentric-Lay-Stranded Copper Conductors Association of Edison Illuminating Companies (AEIC) AEIC CS5. Short-Circuit Characteristics of Insulated Cable. IEEE Recommended Practice for Specifying Electric Submersible Pump Cable. ANSI/IEEE Standard 383. IEEE Standard 1018. Ampacities-Cables in Open-Top Cable Trays. ICEA S-65-375. ICEA P-45-482. IEEE Recommended Practice for Specifying Electric Submersible Pump Cable. ICEA S-61-402.1. IEEE Standard for Type Test of Class IE Electric Cables. (UL) ANSI/UL 44. Inc. Varnished-Cloth-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy. Field Splices. IEEE Power Cable Ampacities ANSI/IEEE Standard 45. Flexible Cord and Fixture Wire. National Electrical Code Underwriters Laboratories. Temperature Measurement Thermocouples Insulated Cable Engineers Association (ICEA) ICEA P-32-382. IEEE Recommended Practice for Electric Installations on Shipboard. Ethylene-Propylene Rubber Insulation. ANSI/UL 62. ICEA S-66-524.1100 Wire and Cable Electrical Manual IEEE. Standard 135. and Connections for Nuclear Power Generating Stations. Instrument Society of America (ISA) ASI/ISA RP 12. Cross-Linked-Thermosetting-Polyethylene-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy. Rubber-Insulated Wires and Cables. March 2001 1100-46 Chevron Corporation . Ethylene-Propylene-Rubber-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy. ICEA S-19-81. Polypropylene Insulation. ICEA P-54-440. National Fire Protection Association (NFPA) ANSI/NFPA 70. Thermoplastic-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy. IEEE Standard 1019. ICEA S-82-552. Rubber-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy. Instrumentation Cables and Thermocouple Wire. ICEA S-68-516. Installation of Intrinsically Safe Systems for Hazardous (Classified) Locations ANSI MC 96. Short-Circuit Performance of Metallic Shields and Sheaths of Insulated Cable.6. ANSI/UL 1569. Cables. ANSI/UL 1581. Outline of Proposed Investigation of Power-Limited Circuit Cable. ANSI/UL 1277. UL 13. Electrical Power and Control Tray Cables with Optional OpticalFiber Members. ANSI/UL 1072. Medium-Voltage Power Cables. IADC-DCCS-1 Interim Guidelines for Industrial System DC Cable for Offshore Drilling Units. Thermoplastic-Insulated Wires and Cables.” New York: McGraw-Hill.Electrical Manual 1100 Wire and Cable ANSI/UL 83. “Calculation of Voltage Drop. Reference Standard for Electrical Wires. Industrial Power Systems Handbook. July 1978. 1955. Chevron Corporation 1100-47 March 2001 . Metal-Clad Cables. Miscellaneous: Beeman. and Flexible Cords. and the design. Design considerations including acceptable lighting levels for specific areas. economic factors. It defines and describes lighting.1200 Lighting Abstract This section provides technical and practical guidance for the design and selection of lighting systems. and maintenance of lighting systems. different types of light sources. factors to consider when selecting lamps and fixtures. Contents 1210 Introduction 1211 Section Guide 1220 Light Sources (Lamps) 1221 Incandescent Lamps 1222 Fluorescent Lamps 1223 High Intensity Discharge Lamps 1224 Lamp Designations 1230 Fixture Selection 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 1200-8 1200-3 Page 1200-3 Chevron Corporation 1200-1 September 1990 . safety issues. layout. and different methods for determining the number and layout (location) of fixtures are also discussed. Data Guides (DG). and Engineering Forms (EF) 1284 Other References 1200-44 1200-45 1200-46 1200-25 September 1990 1200-2 Chevron Corporation .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 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 1270 Glossary of Terms 1280 References 1281 Model Specifications (MS) 1282 Standard Drawings 1283 Data Sheets (DS). cleaning fixtures. Company experience is also outlined for many applications.” discusses relamping. Section 1260. “Electrical Installations in Petroleum Refineries. or luminous efficacy. This section contains information that provides guidance for selecting appropriate lighting systems. This section is not intended to be used for the selection of lighting fixtures.” reviews the many considerations involved in lighting design. cost. Section 1230. fluorescent. “Fixture Selection. Topics discussed are: area lighting. color rendition. and three computational methods. lumen maintenance factor (LMF). If unfamiliar with different types of lamps. and cleaning lighted surfaces. fixture materials. Three other factors should be considered when specifying fixtures: ballast. luminous efficacy and lumen depreciation. “Design and Installation of Electrical Systems for Offshore Production Platforms. and voltage level. temperature. Section 1240.” should be used as a guide in selecting the type of fixture.” should be used to determine the necessary footcandle levels.” and API RP 14F. and emergency lighting systems. Many OPCOs have standardized particular fixtures. and different high intensity discharge (HID) lamps. Section 1250. Section 1220. “Lighting System Design.” can be used to determine the number of fixtures and their layout. the recommended illumination levels listed in API RP 540. “Maintenance Considerations. metal halide. HID lamp types include mercury vapor. “Light Sources (Lamps)” should be reviewed. “Lighting Calculations and Fixture Layout. with two examples using the iso-footcandle method. and lamp starting and restarting time. These considerations include the type of light distribution. It also provides guidance for analyzing the efficiency of existing systems and for analyzing systems maintenance. Chevron Corporation 1200-3 September 1990 . lighting methods. Factors discussed that influence fixture selection are: area classification. General information is provided about incandescent. All decisions involving lighting system design and selection must take into consideration these two factors. Section 6. 1211 Section Guide The following guide directs the user to the appropriate sections. and high pressure sodium.Electrical Manual 1200 Lighting 1210 Introduction Good lighting systems provide two primary benefits in a facility: personnel safety and efficiency of operations. 1220 Light Sources (Lamps) The primary purpose of an electrical light source is the conversion of electrical energy into visible light. illumination levels. For these applications. The effectiveness with which a lamp accomplishes this is expressed in terms of lumens emitted per watt of power consumed. This results in more light output. All filament lamps emit a large quantity of heat with generally less than 5% light energy emitted. 120-volt lamps. consider that a 150-watt. 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. the shorter the life. the larger the diameter of the filament wire. As a general rule. the hotter the lamp can operate. September 1990 1200-4 Chevron Corporation . the fluorescent lamp has a ten-times longer life than the incandescent lamp. However. Some lamps can only be mounted in a vertical position. Undervoltage. 120-volt lamp produces approximately 34% more light than three 50-watt. Maintaining the proper voltage is an important factor in obtaining good performance from lamps and lighting installations.1200 Lighting Electrical Manual For an idea of the relative luminous effectiveness of common light sources. and light output. only in a horizontal position. which generates energy in the form of light and heat. others for the base to be down. Incandescent lamps have a rated average life of about 1000 hours and radiate about 14 to 20 lumens per watt. Type Incandescent Fluorescent Mercury Vapor Metal Halide High Pressure Sodium (HPS) Group Filament Fluorescent High Intensity Discharge High Intensity Discharge High Intensity Discharge 1221 Incandescent Lamps The filament lamp produces light by heating a wire filament to incandescence. Incandescent lamps are available with virtually unbreakable shells and filaments where high vibration or rugged duty is required. with a savings in wattage of only 8%. In addition. This is roughly six times the lumens per watt of the incandescent lamp. Some have a requirement for the base to be up. To obtain the predicted long life of any lamp. The most common filament material is tungsten. Since the lamp cost is almost always small compared with the cost of the power to operate the lamp. others. and higher light output. the increased lamp life which accompanies reduced voltage does not compensate for the loss in light output. To illustrate this. causes a reduction in wattage. while increasing lamp life. Overvoltage operation produces higher wattage. A voltage as little as 5% below normal results in a loss of light of more than 16%. which in turn means higher efficacy. but results in a shorter life. higher efficacy. efficacy. it must be mounted according to the manufacturer’s instructions. incandescent lamps should be operated at rated voltage. The higher the temperature for a given lamp. Vibration and shock should be eliminated as they can greatly reduce lamp life. The most common types of light sources and their associated groups are shown below. Both the life and light output of an incandescent lamp are determined by the filament temperature. A rule-of-thumb is that each lamp start reduces the average lamp life by 3 hours. The lamps radiate about 74 to 84 lumens per watt. However. the light should be turned off to save energy because approximately 80% of the life-cycle cost of a fluorescent lamp is for electrical energy. 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. the line voltage can drop to the values illustrated in the table below before the lamps will extinguish: Type Preheat Rapid-start series-sequence Instant-start lead-lag Instant-start series-sequence Percent of Normal Voltage 75 80 60 50 Chevron Corporation 1200-5 September 1990 . The discharge generates ultraviolet radiation which excites the fluorescent powders on the inner wall of the lamp. an “arc” discharge is produced by current flowing through the mercury vapor. is not appreciably affected by the number of starts. Like most gas discharge lamps. T-12 lamps. as well as high voltage.000 hours when operated for a minimum of 3 hours per start. which in turn emit light. Low voltage. For 40-watt. All burned-out lamps should be removed promptly to prevent the auxiliary equipment from overheating. 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. This is in contrast with filament lamps. The ballast produces the required voltage to start and operate the lamp and the required current to produce the desired light output. The reaction to a voltage dip depends on the lamp type and ballast characteristics. Fluorescent lamps have a rated average life of about 20. a dense deposit develops at the end of the lamp where the electrode is deactivated. When voltage is applied. This effect is especially marked if the lamp is allowed to flash on and off before it is replaced. reduces efficiency and shortens fluorescent lamp life.Electrical Manual 1200 Lighting 1222 Fluorescent Lamps The fluorescent lamp contains mercury vapor at low pressure with a small amount of inert gas for starting. The life of F40 and F30 lamps. where low voltage reduces efficiency but prolongs life. A large voltage dip or reduction in line voltage affects the stability of the arc. operating on rapid start ballasts when burned 3 or more hours per start. The average lamp life for fluorescent lamps is affected by the number of on-off operations. In the last hours of lamp life. fluorescent lamps must be operated in series with a ballast. Low voltage and low ambient temperatures may also cause starting difficulties with fluorescent luminaires. metal halide. 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. Through the use of phosphor coatings on the inside surface of the outer envelope.” are accelerated to tremendous speeds. The applied voltage ionizes the gas and permits current to flow between two electrodes located at opposite ends of the lamp. Mercury Vapor Lamps Most mercury vapor (MV) lamps are constructed with two envelopes. The electrons which comprise the current stream. Light is produced by the passage of an electric current through a vapor or gas rather than through a tungsten wire. or “arc discharge. Most metal halide lamps require a higher open-circuit voltage to start than corresponding wattage mercury lamps.1200 Lighting Electrical Manual 1223 High Intensity Discharge Lamps High intensity discharge (HID) lamps that are commonly used include mercury vapor. Metal halide lamps are also available with phosphors applied to the outer envelopes to further modify the color. nonenclosed fixtures should be specified with self-extinguishing lamps that will automatically extinguish if the outer envelope is broken or punctured. 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. Low pressure sodium lamps are not recommended because of very poor color rendition and high operating costs. and an outer envelope which: (a) shields the arc tube from outside drafts and resulting changes in temperature. and high pressure sodium. they require specifically designed ballasts. September 1990 1200-6 Chevron Corporation . For this reason. A significant part of the energy radiated by the mercury arc is in the ultraviolet region. (c) provides an inner surface for a coating of phosphors. some of this ultraviolet energy is converted to visible light by the same mechanism employed in fluorescent lamps. The light producing element of these lamps is a stabilized arc discharge contained within an arc tube. an inner envelope (arc tube) which contains the arc. and light is produced from the energy generated as the atoms return to their normal state. Metal Halide Lamps Metal halide (MH) lamps are very similar in construction to mercury lamps. Therefore. and (d) acts as a filter to remove certain wavelengths of arc radiation. When they collide with the atoms of the gas or vapor. Self-extinguishing lamps cost about twice as much as standard lamps. they temporarily alter the atomic structure. The major difference is that the metal halide arc tube contains various metal halides in addition to mercury and argon. (b) usually contains an inert gas which prevents oxidation of internal parts. After the number. This letter designation is followed by an ANSI assigned number which identifies the electrical characteristics of the lamp and. The arc tube may unexpectedly rupture due to internal causes or external factors. Allowing lamps to operate beyond their design life increases the possibility of arc tube rupture. the ballast. Additional precautions to use to reduce the likelihood of arc tube rupture are: 1. the glass envelope surrounding the arc tube can break. High Pressure Sodium Lamps In a high pressure sodium (HPS) lamp. and finish. These arc tubes operate under high pressure (6 to 7 atmospheres) at a very high temperature (up to 900°C). Turn continuously operating lamps off once a month for at least 15 minutes. HPS lamps do not incorporate a starting electrode or heater coil as do mercury vapor and metal halide lamps. two arbitrary letters identify the bulb size. but do not Chevron Corporation 1200-7 September 1990 . self-extinguishing lamps that automatically extinguish when the outer envelope is broken or punctured should be specified. Special ballasts are required which incorporate starting voltages in the range of 2250 to 4000 volts to strike the arc. If the arc tube ruptures. Shortwave radiation is also not a concern with high pressure sodium lamps. The arc tube contains xenon as a starting gas. but most commonly ruptures when the lamp is operated beyond its rated life. 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. Like mercury vapor lamps. All designations begin with a letter that identifies the type of HID lamp: “H” for mercury. and “S” for high pressure sodium. 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. “M” for metal halide. light is produced by electric current passing through sodium vapor. 2. shape. use metal halide lamp manufacturers with proven lamps. These high strike voltages can result in high temperatures which could possibly create problems in classified areas. To reduce the potential hazard of ruptured arc tubes. This procedure will reduce the chance of arc tube rupture caused by continuously operating lamps burning beyond the end of rated life. Lights which are close to the end of their design life likely will not restart. consequently. When using open-type fixtures.Electrical Manual 1200 Lighting Metal halide lamps are constructed of a glass envelope with an internal arc tube made of quartz. 1224 Lamp Designations Lamp designations follow a system authorized by the American National Standards Institute (ANSI). 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. Relamp fixtures at or before the end of their rated life. Arc tube rupture is not a problem with high pressure sodium lamps since the arc tube is made of ceramic material. 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. Fig. 1230 Fixture Selection A thorough understanding of the purpose for a lighting system must be established before the various selection factors can be evaluated.1200 Lighting Electrical Manual identify the color. 1200-1 Light Fixture Selection (1 of 2) Light Fixture Type Application Outdoor: Entrance Illumination Wall Illumination Ladder Illumination Emergency Lights Area Floodlighting Walkways Roadways Corridors Canopy Lighting Heliports Indoor: Small Store Rooms Exit Lights Stairways Bulkheads Emergency Lights Offices Control Rooms Living Areas 2 1 1 2 1 2 1 1 1 1 1 2 2 2 4 3 1 1 4 2 4 3 3 3 3 2 2 4 2 3 2 2 1 1 1 1 (with instant restrike) 1 1 1 1 Incandescent Fluorescent MV MH HPS September 1990 1200-8 Chevron Corporation . mercury vapor fixtures are often preferred. a review of the features of each one can be made to complete the selection process. 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. Additional letters are used by individual manufacturers for special designations. On offshore platforms where power is generated and the physical layout prevents full use of light output. “Fixture Selection. See Section 1230. on offshore platforms). 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.g. By comparison. the light output of a mercury vapor lamp at the end of rated life will only be about 50% of its original light output.Electrical Manual 1200 Lighting Fig. 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. Number indicates order of preference. 1200-1 Light Fixture Selection (2 of 2) Light Fixture Type Application Corridors Switchgear Buildings High Bay Area Lighting Warehouses Notes: Incandescent 2 Fluorescent 1 1 3 3 MV MH HPS 2 2 1 1 1. 1232 Luminous Efficacy and Lumen Depreciation One of the two primary factors used in fixture selection is the luminous efficacy (lumens per watt) of the light source. Luminous Efficacy and Lumen Depreciation Summary Figure 1200-3 and Figure 1200-4 summarize the luminous efficacy and lumen depreciation for different light sources. usually will govern the selection process.” for discussion of limited-light applications and low-cost power usage. Refer to the area classification drawing of the facility in which the lighting fixture is to be installed to identify the proper area classification.. It is an important factor during the design and fixture layout process. See Figure 1200-2 for temperature identification numbers and T-Ratings for typical fixtures. 1 being the most preferred. For example. Chevron Corporation 1200-9 September 1990 . The fixture temperature must not exceed the ignition temperature of flammable gases or vapors present. For fixtures that have a long life. which relates directly to the operating cost of the lamp. 1231 Area Classification Area classification must be determined before selecting lighting fixtures. The other primary factor is the initial cost of the fixture. Lumen depreciation is a reduction in normal light output that is unique to each type of lamp. Refer to Section 300 of this manual for guidance in determining area classification and Section 340 for specific lighting fixture considerations. 2. the luminous efficacy. There are different “white” and color spectrum September 1990 1200-10 Chevron Corporation .1200 Lighting Electrical Manual Fig. for reading. but the visual attractiveness obtained by using metal halide lamps outweighs their added operating cost. when time is lost locating the correct lamps. Mixing high pressure sodium with metal halide or mercury vapor is not recommended because of the contrasting colors. Metal halide lamps use more energy per lumen output and have a shorter life than high pressure sodium lamps. Fluorescent Lamps The color produced by a fluorescent lamp depends upon the blend of phosphors used to coat the wall of the tube. Mixing luminaires becomes a problem when color rendition is important—for example. Mixing luminaires also presents a maintenance problem during relamping. metal halide fixtures are typically used in the canopy area of service stations because of the pleasing visual effect of the light. task-oriented activities. and when performing precision. For example. for distinguishing colors. 1200-2 Technical Data: Temperature Identification Numbers of Typical Fixtures (Courtesy of Appleton Electric Company) 1233 Color In some applications. with good color rendition. Incandescent Filament Lamps Incandescent light closely resembles natural sunlight. color rendition is the dominant factor in fixture selection. The color spectrum of high pressure sodium lamps consists of white light with a yellow-orange tone. The color spectrum of “clear” mercury lamps is deficient in red and has a preponderance of blue and green. 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. “White” lamps have good color rendering properties.Electrical Manual 1200 Lighting Fig. HPS lamps are best used for Chevron Corporation 1200-11 September 1990 . but better color rendition than HPS lamps. Courtesy of IESNA) fluorescent lamps available with their own particular coloration. 1200-3 Efficacies for Various Light Sources (from The IESNA Lighting Handbook Reference and Application. MV lamps have poorer color rendition than MH lamps. Ninth Edition. 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. Mercury Vapor (MV) Lamps. The color spectrum of “clear” metal halide lamps is equal to or superior to phosphor-coated mercury vapor lamps. High Pressure Sodium (HPS). industrial. High Intensity Discharge (HID) Lamps A discussion of the color aspects of HID lamps follows. and makes mercury vapor lamps undesirable when the appearance of colors is important. Phosphor coatings can be added for better color. MV lamps are best used for general lighting (street. MH lamps are best used where color rendering is important and in general lighting where only a few fixtures are required. This results in marked distortion of object colors. Courtesy of the Philips Lighting Company. 1200-4 Lumen Depreciation Factor (LDF) (from “Philips Lighting Guide to High Intensity Discharge Lamps" Printed 8/91. and 16.) September 1990 1200-12 Chevron Corporation . pages 7. 12.1200 Lighting Electrical Manual Fig. publication # P-2685. 000. and lamp stanchions are required for the MV lamp option. For different costs of power and labor. with an energy cost of $0. At locations where power is purchased or generated at low cost and physical layout prevents full use of light output. more conduit. An economic evaluation should be performed. or MH fixture provides a maintained minimum illumination of 5 footcandles. Fluorescent lamps are often the preferred choice for enclosed areas. Incandescent lamps should be used sparingly.Electrical Manual 1200 Lighting general lighting of large areas where good color rendition is a secondary consideration.g. This cost does not consider the added cost of source equipment (transformers and panelboards) for the MV lamp option (with a connected load of 82 KW versus 30 KW for the HPS option).000.000 square foot area to an illumination level of 5 footcandles. In this example.. and warehouse lighting. Fluorescent Lamps Figure 1200-5 shows a cost analysis for energy-saving versus standard efficiency fluorescent lamps. the Chevron Corporation 1200-13 September 1990 . metal halide or mercury vapor fixtures may be more cost effective.00 annual operating cost). In fact. The analysis is based on using Class I. Division 2 (UL-844) fixtures. Mercury vapor fixtures should not be used in new installations due to poor luminous efficacy and high lumen depreciation (which results in high operating costs) except for specific locations as discussed below. wire. office buildings.864. By comparison. The undiscounted life cycle cost (LCC) of using HPS lamps in this example is approximately $300. Metal halide is the second most cost effective choice for outdoor lighting. the undiscounted LCC of MV lamps is more than $720. Such areas include: floodlighting. The metal halide option is also a better choice economically than mercury vapor. ratio actual costs to the costs used in this example (e. road way lighting. $0. and laboratories with low ceiling clearance. This analysis indicates that energy-saving lamps should be specified even when the time value of money is as high as 20%. especially for control rooms. High Intensity Discharge Lamps Figure 1200-6 shows a cost analysis to light a 50. MV.. High pressure sodium lamps are often preferred for warehouses and indoor process areas. and only for specialty applications (e.g. 1234 Cost High pressure sodium lamps are usually the best economic choice for lighting large areas. general area lighting.04/KWH/$0. primarily because of their low operating cost and long life. emergency lighting) or where lighting is used infrequently and the initial fixture cost is low compared to alternative lighting fixtures. Figure 1200-7 illustrates another example in which one HPS. it may be cost effective to retrofit existing mercury vapor installations with high pressure sodium lamps.08/KWH=$4. 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. In addition. and 4000 burning hours per year. followed by fluorescent.08/KWH. 24 40. An initial investment of approximately $96. Standard Lamps F40CW Standard Number of Luminaires Required Initial Lumens Per Lamp Estimated Lamp Life (Hrs) Average Lamp Replacements/yr Lamp Net Cost After Discount ($/lamp) Lamp Input (watts/lamp) Total Connect Load (W) Relamp Labor/lamp @$50/hr Annual Operating Cost ($) Relamp Cost: Lamps Relamp Cost: Labor Energy Cost Total Annual Operating Cost 20 Year Operating Cost ($) Relamp Cost: Lamps Relamp Cost: Labor Energy Cost Total 20 Year Operating Cost 20 Year Life Cycle Cost ($–discounted) 8% Discount Rate 10% Discount Rate 12% Discount Rate 20% Discount Rate 110.19 1.05/KWH. it is not cost effective to change out the MV lights.1200 Lighting Electrical Manual Fig.15 1.30 54.00 3.000 0.00 30 10.60 11.00 MV option has the lowest initial cost and the lowest LCC even when the time value of money is over 20%.16 9.00 192.000 to retrofit to MH.15 1.44 74.00 40 10. 1200-5 Cost Analysis: Comparison of Fluorescent Lamps—Energy Savers vs.000 will be required to retrofit to HPS or $104.00 2.08 84.96 97.00 163. An economic analysis should be performed for each possible situation. Retrofitting with MH is not a cost effective option.08 48.775.38 84. the option to retrofit with HPS yields a savings even when the time value of money is as high as 12%. Based on a 10-year LCC. However.36 0.150.20 198. when the cost of energy is below $0.000 0.26 1. Figure 1200-8 demonstrates a retrofit example in which MV lamps are presently in use.72 30.72 34.72 5. September 1990 1200-14 Chevron Corporation .50 9.00 F40 Energy Saver 1.29 0. This also is true when using a 20-year LCC.92 1.00 20.16 30.81 96.00 225.30 3.00 20.50 8. 728 10.822 2.000 24.800 446.382 329.40 350 150 10 175 W MV 357 8600 0.155 195. Illuminated to 5 fc 4.000 0.525 542.840 56.444 720.000 24.720 17.11 310 150 10 175 W MH 200 14.800 729 270 9.338 437.000 Sq Ft Area.000 90.198 143.000 27 27 190 30.540 19.580 5.615 202.50 1.08/Kwh Area Class: Class I.540 294. 1200-6 Cost Analysis: High Intensity Discharge Fixtures High Intensity Discharge Fixtures Basis: 50.173 332.896 185. Group D 150 W HPS Number of Luminaires Required Initial Lumens Per Lamp Lumen Maintenance Factor Total Lumens Estimated Lamp Life (hrs) Avgerage Lamp Replacements/yr Lamp Net Cost ($) Luminaire Input (watts/fixture) Total Connected Load (kw) Fixture Cost ($) Installation Labor/Fixture @ $50/hr Relamp Labor/Lamp @ $50/hr Initial Installation Cost ($) Fixture Cost Labor Cost Total Initial Cost Annual Operating Cost ($) Relamp Cost: Lamps Relamp Cost: Labor Energy Cost Total Annual Operating Cost 20 Year Operating Cost ($) Relamp Cost: Lamps Relamp Cost: Labor Energy Cost Total 20 Year Operating Cost 20 Year Life Cycle Cost ($–undiscounted) 20 Year Life Cycle Cost ($–discounted) 8% Discount Rate 10% Discount Rate 12% Discount Rate 20% Discount Rate 225.Electrical Manual 1200 Lighting Fig.332 483.729 952 595 26. Division 2.320 800 14.540.55 1.000 30.000 Burning Hrs Per Yr.451 294.400 16.220 60.00 300 150 10 Chevron Corporation 1200-15 September 1990 .536.000 160 16.60 1.550 164.000 60 16 230 82.000 80.900 525.040 11.000 10.000 80 29 230 46.000 110.623 265.400 194.770 14.000 0.664 46.670 53.275 27.400 356.000 294. Energy Cost = $0.000 24.535.560 214.504 556. 473 1. Area Class: Class I.000 0.80 1.1200 Lighting Electrical Manual Fig.000 0.60 39. Illumination Minimum to 5 fc.70 32.000 0.472 1.23 300 150 10 September 1990 1200-16 Chevron Corporation .760 10.306 232 80 1.784 2. 4.08/kwh.480 24.55 7.60 89.00 73.13 215 150 10 175 W MH 1 14.000 0.325 978 97 33 652 782 1.10 325 150 10 100 W MV 1 4200 0.20 1.004 904 827 644 1.257 63 33 844 941 1.006 923 859 707 1.40 29 230 0.70 42. 1200-7 Cost Analysis: High Intensity Discharge Fixtures High Intensity Discharge Fixtures Basis: Equal Number of Fixtures.662 1.10 3.100 24.20 47.60 4.17 19 132 0.234 4. Energy Cost = $0.50 2.20 325 150 475 215 150 365 300 150 450 1 5800 0. Group D 70 W HPS Number of Luminaires Required Initial Lumens Per Lamp Lumen Maintenance Factor Total Lumens Estimated Lamp Life (hours) Avgerage Lamp Replacements/yr Lamp Net Cost ($) Luminaire Input (watts/fixture) Total Connected Load (kw) Fixture Cost ($) Installation Labor/Fixture @ $50/hr Relamp Labor/Lamp @ $50/hr Initial Installation Cost ($) Fixture Cost Labor Cost Total Initial Cost Annual Operating Cost ($) Relamp Cost: Lamps Relamp Cost: Labor Energy Cost Total Annual Operating Cost 20 Year Operating Cost ($) Relamp Cost: Lamps Relamp Cost: Labor Energy Cost Total 20 Year Operating Cost 20 Year Life Cycle Cost ($–undiscounted) 20 Year Life Cycle Cost ($–discounted) 8% Discount Rate 10% Discount Rate 12% Discount Rate 20% Discount Rate 1.10 11.17 29 102 0.000 Burning Hrs Per Yr.60 3. Division 2. 000 0.55 1.201 273.280 107. Group D Number of Luminaires Required Initial Lumens Per Lamp Lumen Maintenance Factor Total Lumens Estimated Lamp Life Avgerage Lamp Replacements/yr Lamp Net Cost ($) Luminaire Input (watts/fixture) Total Connected Load (kw) Fixture Cost ($) Installation Labor/Fixture @ $50/hr Relamp Labor/Lamp @ $50/hr Initial Installation Cost ($) Fixture Cost Engineering Installation Labor Cost Remove MV Fixtures ($50/fixture) Total Initial Cost Annual Operating Cost ($) Relamp Cost: Lamps Relamp Cost: Labor Energy Cost Total Annual Operating Cost 10 Year Operating Cost ($) Relamp Cost: Lamps Relamp Cost: Labor Energy Cost Total 10 Year Operating Cost 10 Year Life Cycle Cost ($–undiscounted) 10 Year Life Cycle Cost ($–discounted) 8% Discount Rate 10% Discount Rate 12% Discount Rate 20 Year Life Cycle Cost ($–discounted) 8% Discount Rate 10% Discount Rate 12% Discount Rate 14% Discount Rate 150 W HPS 160 16.840 23.720 17.390 201.955 157.540.000 Sq Ft Area.814 175 W MV 357 8.222 186.000 10.649 279.000 80 29 230 46.000 6.000 24.005 255.000 30.850 95.50 1.60 1.950 262.11 0 0 10 0 0 0 0 0 952 595 26.000 9.290 2.08/kwh Area Class: Class I.00 300 150 10 60.850 729 270 9.557 213.728 10.746 161.000 24.700 97.850 2.727 7.006 Chevron Corporation 1200-17 September 1990 .275 27.270 203.400 282. 1200-8 Fixture Retrofit Cost Analysis Replace Existing Mercury Vapor (MV) Fixtures Basis: 50. Illuminated to 5 fc 4.104 222.250 223.752 278.686 156.000 147.689 170.200 178.320 800 14.520 5.000 Burning Hrs Per Yr.120 167.Electrical Manual 1200 Lighting Fig. Division 2.731 237.000 60 16 230 82.070 175.000 0.866 207.40 350 150 10 56.536.000 6.162 236.000 7.000 27 27 190 30.535.048 187.200 8.822 9.222 278.270 175 W MH 200 14. Energy Cost = $0.000 24.469 204.600 0.850 103.882 166.816 184. but can become a significant problem outdoors. Care should be taken to ensure that the correct wattage lamps are installed in fixtures. turning the lamp off and on unpredictably. When using lamps in cold weather without a surrounding enclosure. therefore. Overvoltage conditions or the use of lamps of higher wattage than the manufacturer’s rating can cause slight or severe damage. For outdoor applications. Enclosing the lamps shifts the peak output to a lower ambient temperature. and fixture. the fixture and adjacent wiring can be damaged. Self-generated heat in excess of that which is designed to be dissipated by the fixture can damage the ballast. the lamps must be enclosed. For maximum efficiency. Light output decreases about 1 percent for each 1-degree drop in bulb temperature below 100 °F. Fixtures must be mounted according to manufacturers recommendations to correctly dissipate heat. In order to maintain high output in cold climates. This normally is not a problem with indoor applications. Incandescent Filament Lamps Operation of lamps under conditions which cause excessive bulb and base temperatures may result in softening of the base cement and loosening of the base. it may be more cost effective to use fixtures with remote-mounted ballasts. September 1990 1200-18 Chevron Corporation . Ballast life is very sensitive to high ambient temperatures. Most fixtures are designed to dissipate a specific quantity of heat generated by the lamps. or a fixture installed in a high ambient temperature area. The use of incorrect wattage lamps may also affect light distribution by fixtures since the focal point will not be correct for reflectors. light output is significantly affected by the temperature and movement of the surrounding air. even though the initial costs for fixtures with integral ballasts may be lower. In extreme cases. lamp. Low temperatures may also cause starting difficulty. base. best results will be obtained from T10J lamps specifically designed for use in low air temperatures.1200 Lighting Electrical Manual 1235 Temperature Temperature can affect the installation and operation of light sources in many ways. and decreases a like amount for each 2-degree rise between 120° to 200°F. Fluorescent Lamps Temperature is an important factor in the performance of fluorescent lamps. For high ambient temperature areas. to insure immediate starting at low temperatures. However. The temperature of the bulb wall has a substantial effect on the amount of ultraviolet light generated by the arc. fixtures must be able to dissipate the heat which is generated. Ambient temperatures can affect the lumen output of some fixtures. bulb wall temperatures should be within a range of 100° to 120°F. can cause the ballast protection to cut in and out. High Intensity Discharge Lamps The lumen output of the enclosed arc-tube type lamp is not significantly affected by ambient temperature. When fluorescent lamps with “P” ballasts are installed. fluorescent lamps designed for outdoor use are recommended because of their high lumen output. Insulation around the fixture. The epoxy protects the ballast from possible contaminants. Fluorescent Lamps Fluorescent lamps should be equipped with rapid-start ballasts which provide immediate starting and restarting characteristics. socket. or lead-in wires. 1236 Lamp Starting and Restarting Lamp starting and restarting can be an important consideration if there is a significant time delay before light output can be achieved. Chevron Corporation 1200-19 September 1990 . metal halide lamps take the longest time to restart and reach full power output after a power failure. operating temperatures are particularly important. softening of the basing cement or solder. unsatisfactory performance due to softening of the glass. Because HID lamps have a long life. The effect of heat is partly a function of time. Excessive bulb and base temperatures may cause the following conditions: lamp failure. Battery-powered emergency lighting systems may be required for outages which are longer than momentary outages. 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. or in an industrial setting where an unsafe condition may exist after a power dip if light is not restored immediately. High Intensity Discharge (HID) Lamps All HID lamps need time to reach full output and stable color.Electrical Manual 1200 Lighting 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. Ballasts equipped with restart circuits provide full light output immediately upon restoration of power. and the longer the life of the lamp. Of all luminaires. Epoxy encapsulated ballasts should be considered for high humidity areas and corrosive environments. If the arc is extinguished after this warm-up. Some ballasts can be equipped with a restart circuit that will provide sufficient starting voltage to overcome the higher vapor pressure of the gases. damage to the arc tube from moisture being driven out of the outer envelope. Incandescent Lamps Incandescent lamps achieve immediate light output upon starting and restarting. or corrosion of the base. Mercury Vapor (MV) Lamps The 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. The use of any reflecting equipment that might concentrate heat and light rays on either the inner arc tube or the outer envelope should be avoided. the greater the possibility of damage from high temperature. This factor can be important in remote locations. ” Ballasts should also be listed by September 1990 1200-20 Chevron Corporation . Ninety percent of full light output is reached in 3 to 4 minutes. the time to cool and lower the vapor pressure of the metal halide lamp is longer. and a potting compound (such as asphalt) containing a filler (such as silica). The incandescent quartz lamp lights immediately when the circuit is restored.5 and 1 minute. varying between 10 and 20 minutes. When the MV lamp attains 75% of its rated output. Because the operating pressure of a high pressure sodium lamp is lower than that of a mercury lamp. With this feature. Fig. The average ballast life at a 50% duty cycle and proper operating temperature is about 12 years. 1200-9 Lamp Start and Restrike Time (in Minutes) Type of Lamp MV Start Time Restrike Time 5-7 3-6 MH 2-5 10-20 HPS 3-4 0.1200 Lighting Electrical Manual Mercury vapor lights with an auxiliary quartz lamp are available. the restrike time is shorter. varying between 2 and 5 minutes. Lamp Start and Restrike Summary Figure 1200-9 summarizes the lamp starting and restrike times for the various HID light sources. between 0. Since MH arc tubes operate at higher temperatures than MV lamps. some light is available immediately. Quartz lamps operate at temperatures which are above those allowed for Class I.5-1(1) Incandescent immediate immediate Fluorescent immediate immediate (1) Also available with instant restrike. The thermally protected Underwriters’ Laboratory approved ballast is marked or labeled as “Class P. thermal protective device. it is mandatory that all fluorescent lamp ballasts be thermally protected internally. High Pressure Sodium (HPS) Lamps The lamp warm-up time for HPS lamps is between 3 and 4 minutes. 1237 Ballasts Fluorescent Lamps The components of a typical rapid start ballast consist of a transformer-type core and coil. power capacitor. Division 1 or 2 areas. Light output reaches 30% of full output after 1/2 minute. Full light output is achieved in about 3 minutes. In the United States and Canada. 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. and full light output is reached in approximately 10 minutes. a current sensing relay turns the quartz lamp off. Metal Halide (MH) Lamps The warm-up time for MH lamps is slightly less than that of MV lamps. The CWA features allow maximum loading on branch circuits and provide more cost-effective HID lighting systems. It consists of a high reactance autotransformer with a capacitor in series with the lamp. These variables include: (1) lighting for detailed work. or 480 volts. The design of any lighting installation involves the consideration of many variables. and reduced inventories of fixtures and ballasts. 1238 Fixture Materials Fixture material may be an important consideration in the selection of lighting fixtures. (3) task-oriented lighting. “System Design. the following project design tasks must be completed: facility layout. maintenance factor and luminaire depreciation factor). Other advantages of the CWA ballast are a high power factor. Many locations prefer 120 volts for all fixtures for safety considerations. easier phase balancing. and environmental suitability (e. Fixtures with ballasts other than CWA will require approximately 60% more starting current than operating current. HID fixtures can be supplied at 120. fixture selection. outdoors. 277. the following design parameters must be determined: area classification. The lighting system should also be designed to provide the desired quantity of light at the particular location and in the proper visual plane. 1239 Voltage Levels The voltage level of the electrical supply is discussed in Section 100. and emergency escape routes. In addition. and (4) emergency lighting. The capacitor allows the lamp to operate with better wattage stability if branch circuit voltage fluctuates. mechanical equipment plans. structural plans. 240. CBM publishes sound ratings for ballasts. indoors. Outdoor fixtures for use on shipboard or offshore platforms should be UL-595 listed. and hazardous locations) should all be considered during the design phase. All CBM listed ballasts are also UL listed. 208. Chevron Corporation 1200-21 September 1990 .e. 1240 Lighting System Design Before the system design process can begin. and voltage level. Many locations have standardized a particular voltage level..Electrical Manual 1200 Lighting the Certified Ballast Manufacturers Association (CBM). 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. the ease of installation and maintenance. especially in marine environments. The amount of glare produced. High Intensity Discharge The Constant Wattage Autotransformer “CWA” lead circuit ballast is the preferred choice for most HID installations.” Incandescent and fluorescent fixtures normally are supplied with 120 volts. Underwriters’ Laboratories Standard UL-595 covers marine-type electric light fixtures. This practice should be investigated before selecting fixtures. low-line extinguishing voltage. (2) flood lighting.g.. and lower line starting currents. An example of this is in the bunk areas of living quarters. they have the lowest utilization of the five classes and often are difficult to maintain. This system emits very little brightness in the direct-glare zone. and while it often is most efficient. Where vertical surfaces are adjacent to sources of high luminance. This type of lighting system is used when reflected glare from room surfaces must be minimized. Supplementary luminaires are used to provide higher levels of illumination in small or restricted areas. Indirect lighting is preferred for control rooms with CRT monitors. • • 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. • General lighting should provide overall.1200 Lighting Electrical Manual 1241 Distribution of Light The distribution of light is divided into five classes: direct. with a general decrease in glare and increase in seeing comfort. three types of lighting are used. Localized general lighting is used in areas where higher illumination levels are required. 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. However. The lighting level at the wall should be comparable to that at the center of the room. and indirect. semi-indirect. to prevent reflected glare. September 1990 1200-22 Chevron Corporation . semi-direct. General-diffuse (direct-indirect) lighting systems provide approximately equal components of up-light and down-light. it usually results in glare. The efficiency of the system depends largely on the reflectances of all the room surfaces. Semi-indirect lighting provides 60 to 90% up-light and depends on light being reflected from the ceiling and walls. generaldiffuse (or direct-indirect). uniform lighting with special attention focused on the areas along walls. Indirect lighting systems provide 90 to 100% up-light and produce the most comfortable light. Semi-direct lighting provides 60 to 90% of its light downward. This often can be obtained by increasing the output of the general lighting system in the particular area. This system is widely used in laboratories and offices. • • • Direct lighting provides 90 to 100% of its light downward. • • 1242 Lighting Methods To provide the necessary quantity and quality of light for lighting system applications. A ballast will continue to draw current after all lamps are removed (except for fixtures with circuit-interrupting lampholders). energy is still consumed by the ballasts. Certain considerations and precautions must be made when removing fluorescent lamps: 1. Lighting level reductions often are made by removing fluorescent lamps from fixtures. the lamps should be selected and placed so that minimum glare is introduced. technical assistance should be obtained before lamps are removed. Levels listed for office areas are based on the 1974 guidelines of the Federal Energy Administration. All maintenance personnel who are likely to be working on or cleaning these fixtures should be made aware of this potentially dangerous condition. Rapid-Start fixture show that each ballast uses 10 2. resulting in wasted energy and possible overheating of the ballast. Most four-lamp fixtures operate from two ballasts. lighting levels which exceed the standard recommendation should be reduced.” and API RP 14F. With the exception of Slim-Line (Instant-Start) lamps. As a general rule. For example. 1244 Lighting Level Reduction In the interest of energy conservation. 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. UL rating and manufacturer’s warranties are normally invalidated if the above steps are not followed. When lamps are removed from a fixture. Either all four lamps should be removed or two lamps operating from the same ballast should be removed. 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. a potential voltage remains at the sockets which could be dangerous. with two lamps on each ballast. Persons with uncorrectable visual difficulties and those performing difficult visual tasks may require supplemental lighting. Section 6. 4. the power factor in a given installation will not drop below 90% provided that no more than one-half of the lamps are removed. When supplemental lighting is provided in the form of desk or floor lamps. Chevron Corporation 1200-23 September 1990 . “Design and Installation of Electrical Systems for Offshore Production Platforms.Electrical Manual 1200 Lighting 1243 Illumination Level Company experience has shown that the lighting levels listed in API RP 540. Even if all lamps are removed from a fluorescent fixture. 3. measurements taken on a fourlamp. A suitable protective cap should be used or the sockets should be taped with high temperature tape. resulting in higher currents and possible utility charges for excessive use of reactive power. 40 watts-per-lamp. If maintenance personnel are uncertain about the lampholder type. “Electrical Installations in Petroleum Refineries. Removing only one or three lamps from this type of fixture is not a safe practice.” are adequate and are recommended for Company installations. Disconnecting additional lamps lowers the power factor further. 1245 Emergency Lighting Systems Emergency lighting is used during power failures and provides illumination by silhouetting objects. if practical. and especially if the reduction in lighting level is to be permanent. state. Service Station Lighting Metal halide lighting is almost exclusively used for outdoor lighting at Chevron service stations. If the same power source is used for both normal and emergency lighting. high pressure lighting is used for tank truck loading racks and warehouse lighting. light should automatically be provided in areas where the loss of light might cause personnel hazard. and to maintain a level of illumination adequate for safety and security. and federal codes may require emergency lighting for special areas where personnel work. It should be provided in control rooms. and batteries. 1246 Company Experience with Lighting Systems Industrial Lighting High pressure sodium lamps are preferred for most outdoor onshore lighting applications because of their lower initial capital investment and operating costs. Normally. Therefore. There are some applications where only a few fixtures are required or where color rendering is of primary importance. Applicable codes should be reviewed carefully. The power source for emergency lighting systems should be separate from the normal electrical source. in large electrical substations. Offshore Platforms Mercury vapor and metal halide (and occasionally high pressure sodium) lamps are used for area lighting and lighting the interiors of large buildings. Local. in mechanics shops. UPS. to provide light to shut down controls and equipment. It may also be required to illuminate equipment for plant startup following a power outage. If normal power is lost. Emergency lighting power sources include engine generator sets. Roadway and Parking Lot High pressure sodium lighting normally is preferred for roadways and parking lots. the ballast should be disconnected from the power source. city. at critical instrument locations. a power outage would render the emergency lighting useless.1200 Lighting Electrical Manual watts of power with all lamps removed. In these situations. and in laboratories. metal halide or color-corrected mercury vapor fixtures may be preferred. Emergency systems are used to evacuate personnel. 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). Fluorescent September 1990 1200-24 Chevron Corporation . The better color rendering properties of metal halide help to maintain the Company image and improve sales. the point-to-point method. and the iso-footcandle method. particularly where low profile fixtures are needed because of low ceiling heights. Designs should produce uniform and efficient lighting levels and facilitate cost-effective maintenance. Incandescent fixtures equipped with long-life lamps are used for landing lights. All surfaces in control rooms should be nonreflective. 1251 Area Lighting Area lighting for a particular operating company location should be standardized as much as possible. The watts-per-square foot method is used for estimating purposes very early in a project or during the conceptual phase of a project. Wall-mounted or suspended indirect fluorescent fixtures with adjustable light level controls are preferred. the greater the area illuminated. either method may be used for indoor or outdoor locations. The IES Handbook and the Westinghouse Lighting Handbook contain detailed. Fluorescent fixtures may be required for low profile applications. Aviation Lighting Metal halide or color-corrected mercury vapor systems are preferred for most heliport lighting applications on offshore platforms because of their superior quality of light. light output directly beneath the fixture will be lower. Fluorescent lighting with parabolic louvers (to reduce glare) can also be used for general lighting. This section explains two lighting-calculation methods: the watts-per-square foot method for conceptual design. The point-to-point method is commonly used in calculations for outside applications where reflected light is not a factor. Generally. Incandescent spot lighting can be used for task lighting. Floodlighting The difference between floodlighting and area lighting is the aiming angle. 1250 Lighting Calculations and Fixture Layout The 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. however. and the isofootcandle method for general outdoor applications. Most lighting design done by the Company is for exterior (outdoor) lighting. An effort should be made to prevent light penetration from other work spaces. Since the objective of floodlighting is to Chevron Corporation 1200-25 September 1990 . step-by-step processes for using these two methods. primarily for area lighting and floodlighting. Control Room Lighting Control rooms or other rooms equipped with CRTs should be designed with indirect lighting to reduce glare. The greater the aiming angle. the lumen method is used in calculations where fixtures are installed in an enclosed space (like a room).Electrical Manual 1200 Lighting lighting is used indoors (and at times outdoors) for area lighting. However. 2.29 29 . Figures 1200-10 and 1200-11 are iso-footcandle tables for fixtures with and without reflectors. Fixture Reflector. Angled Reflector. Angled reflectors serve the same purpose as angled mounts. Since the objective of area lighting is to provide light at grade level.18 18 . 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 illuminated.1200 Lighting Electrical Manual maintain only 1 to 2 footcandles at grade. This is particularly useful when the light must be directed to a specific area where an individual lighting fixture cannot be installed. and that relatively low mounting heights facilitate maintenance. it should be kept in mind that the objective of area lights is to achieve a fairly high illumination level directly below fixtures. A good application for an angled reflector is for fixtures mounted adjacent to buildings. the brighter the area directly below the fixture. angled mounts work well. 3. Figure 1200-12 provides a conversion table for lamps other than high pressure sodium lamps. When selecting mounting height. as much light as possible should be directed to the area needing illumination.100 100. However. the amount of peripheral light decreases. Standard floodlight beam widths are specified by NEMA as follows: NEMA TYPE 1 2 3 4 5 6 7 BEAM SPREAD (degrees) 10 . Angled Mounting. as opposed to out. 4. Mounting Height.70 70 . Since minimal light is needed on the side of the building. reflectors should be used in most applications. 1. The purpose for the reflector is to direct light down.46 46 . It is more efficient to mount a fixture directly above an area. as the fixture height is lowered.130 130 and up Variables in Area Lighting By understanding and properly addressing the variables discussed below. The area illuminated by floodlights can be varied by using different beam widths. the best method is usually to angle fixtures at 60 degrees from horizontal and install them at heights of about 25 feet. September 1990 1200-26 Chevron Corporation . but if this is not possible. Both Figures 1200-10 and 1200-11 demonstrate that the lower a fixture is mounted. an effective lighting design can be achieved. Standard Reflector. 1200-10 Footcandle Table—Typical HPS Fixture. No Guard (See Figure 1200-12 to convert HPS footcandle values to MV or MH) Courtesy of EGS Electrical Group (formerly Appleton Electric) Chevron Corporation 1200-27 September 1990 Electrical Manual 1200 Lighting .Fig. 1200-11 Footcandle Table—Typical HPS Fixture. No Reflector.Fig. No Guard (See Figure 1200-12 to convert HPS footcandle values to MV or MH) Courtesy of EGS Electrical Group (formerly Appleton Electric) September 1990 1200-28 Chevron Corporation 1200 Lighting Electrical Manual . lumen output deteriorates (lumen depreciation).55 0.60 0.60 0. Figure 1200-13 provides the recommended lumen maintenance factors to apply to various types of fixtures. and reflector.55 0.50 0. Dirt depreciation is the lamp depreciation associated with dirt on the lamp.40 0. 1200-12 Conversion Table for HPS to MV or MH Courtesy of EGS Electrical Group (formerly Appleton Electric) 1252 Lumen Maintenance Factor (LMF) As lamps age. Together.70 Lumen Maintenance Factor Chevron Corporation 1200-29 September 1990 . lens. Fig. 1200-13 Lumen Maintenance Factors (1 of 2) Type of Fixture Incandescent -Indoor -Outdoor Fluorescent -Indoor -Outdoor Mercury Vapor -Indoor -Outdoor High Pressure Sodium -Indoor 0. lamp depreciation and dirt depreciation constitute the lumen maintenance factor (LMF).Electrical Manual 1200 Lighting Fig. To use this method.6 for HPS fixtures. Determine the watts per square foot from Figure 1200-14. By applying the LMF of 0. 1200-13 Lumen Maintenance Factors (2 of 2) Type of Fixture -Outdoor Metal Halide -Indoor -Outdoor 0. will provide 10 footcandles of initial illumination in a 5-foot radius. the illumination level design basis is 6 footcandles (10 x 0. Step 2. and are representative of the lamp’s actual output. Iso-footcandle charts show lines of equal footcandles that will be produced by a specific fixture at a given height. but is not well suited for indoor applications. Iso-footcandle charts (IFCs) September 1990 1200-30 Chevron Corporation . Obtain the total wattage required by multiplying the watts per square foot (from Step 4) by the area to be illuminated (from Step 2).6) near the end of rated life. a 70-watt HPS fixture with a standard reflector and no guard.55 Lumen Maintenance Factor 0. a six-step process is outlined below: Step 1. Step 3. Step 5. 1253 Watts-Per-Square Foot Method The 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. Determine the type of lighting fixture to use from Figure 1200-1. If the minimum recommended illumination level is 12 footcandles. Iso-footcandle charts are useful as they can be superimposed on the design plot plan and relocated until satisfactory light levels are achieved. 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).1200 Lighting Electrical Manual Fig. Step 6. Step 4. Determine the illumination level for the area(s) in question.60 For example. Light Fixture Selection. Figure 1200-15 shows an iso-footcandle chart for a 70-watt HPS fixture with a standard dome reflector mounted at an elevation of 8 feet.45 0. These curves are created from photometric test data. two 70-watt HPS fixtures spaced 5-feet apart would provide the required illumination. 1254 Iso-Footcandle Method The iso-footcandle lighting-calculation method works well for outdoor locations. Determine the total square footage of the area to be illuminated from the preliminary plot plan. mounted 8-feet high. Chevron Corporation 1200-31 September 1990 . isofootcandle 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.Electrical Manual 1200 Lighting Fig. Using this data. which is readily available from most fixture manufacturers. An alternative to the iso-footcandle chart is the iso-footcandle table. 1200-14 Chart for Determining Watts per Square Foot may be hard to obtain for a specific fixture and often have to be scaled to match the plot plan. 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. walkways. The first step for fixture layout is to determine the proper illumination levels for the various areas. Another fixture should be located to one side of the MCC. placing a luminaire on an 8-foot stanchion near each stairway would light both the platform and the stairs. an elevated valve manifold platform. The location in Figure 1200-21 was chosen for two reasons: first. A better choice. The values are for initial footcandle levels. The first decision is whether to use floodlights or area lights. 15 feet from the valve platform. 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. Walkway The walkway requires a minimum of 1 footcandle. and one more fixture is located to provide the three fixtures called for in the lumen method. three 70-watt HPS lamps will provide adequate light for the pump pad and elevated platform. 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. Using the lumen method. An iso-footcandle chart (IFC) is superimposed on the plot plan to locate the fixtures along the walkway. The 8-foot height also provides ease of relamping. and a parking lot. The facility consists of a pump pad. The next step is to use the detailed iso-footcandle method.6. Pump Pad and Elevated Valve Platform The iso-footcandle chart (drawn to the scale of the plot plan) is now located at the top of each stairway. A lumen maintenance factor of 0. In particular. however. Logical locations for the area lights would be the perimeters of the pump pad and the valve platform.6 for HPS lamps (from Figure 1200-13) will reduce the radiated light shown on the chart by a factor of 0. including area classification. to September 1990 1200-32 Chevron Corporation . Figure 1200-20 shows the results. the result is one fixture. The lighting levels listed in Figure 1200-17 were chosen from API RP 540. and two more at 25-foot intervals at the loading dock area. an MCC. is to use three or four area lights because a uniform light level over the entire area (including the two stairways) can be achieved. Using 70watt HPS fixtures mounted at 8 feet. High pressure sodium fixtures have been selected since they have the highest lumen efficacy and adequate color rendering. Figure 1200-19 shows the iso-footcandle lighting level of the three fixtures.1200 Lighting Electrical Manual 1255 Fixture Layout Using Iso-Footcandle Charts Figure 1200-16 shows a plot plan of a tank truck loading dock. MCC Note that the walkway fixtures do not provide adequate light at the MCC where a minimum of 5 footcandles is required. The pump pad and valve platform could be adequately lit with two floodlights. Section 6. 1200-15 Iso-Footcandle Chart for Stanchion Mount Fixture Courtesy of EGS Electrical Group (formerly Appleton Electric) Chevron Corporation 1200-33 September 1990 .Electrical Manual 1200 Lighting Fig. September 1990 1200-34 Chevron Corporation .1200 Lighting Electrical Manual 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 Pump Pad Elevated Valve Platform Stairs Area of Loading Dock Paved Walkways Instruments and Gages Parking Area Lighting Level (footcandles) 5 5 5 10 1 5 1 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. 1200-18 Diagram of Iso-Footcandle Chart for 70 Watt HPS Plot-Plan Scale Loading Dock The illumination level on the loading dock needs to be much higher than other areas. superimposed on the plot plan. Parking Lot The final area to be illuminated is the parking lot.Electrical Manual 1200 Lighting Fig. The area of the overhang normally will be occupied by a tanker truck and will only receive partial lighting. plus the fixture length of 1 foot. the fixture height is 10 feet above grade. Two fixtures are located to provide the desired 10 footcandles in the loading area. the canopy above the loading rack is 15 feet above grade. 150-watt HPS floodlight. 1256 Fixture Layout Using Iso-Footcandle Tables Iso-footcandle tables can also be used to determine fixture locations. the 70-watt HPS will not provide adequate lumen output per fixture. 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. Chevron Corporation 1200-35 September 1990 . A single. By inspection. Figure 1200-10 is an iso-footcandle table for a 70-watt HPS fixture with a reflector. By choosing a 100-watt HPS pendant-mounted fixture with a 4-foot pendant. Figure 1200-22 shows the IFC drawn to scale for this fixture. The table indicates the amount of light at grade level from a light source mounted at a given height. In addition. Floodlights should be used for this application since the area is larger and light levels need not be uniform or high. 1200-19 Pump-Pad Platform Lighting Level September 1990 1200-36 Chevron Corporation .1200 Lighting Electrical Manual Fig. 1200-20 Walkway Lighting Levels Chevron Corporation 1200-37 September 1990 .Electrical Manual 1200 Lighting Fig. 1200-21 MCC Lighting Levels Chevron Corporation 1200-38 September 1990 .Electrical Manual 1200 Lighting Fig. Because of the lumen maintenance factor. illuminates an oval shaped area 70 feet by 50 feet to approximately 1 footcandle. assume it is necessary to light a circle of 5-foot radius to 5 footcandles. High pressure sodium fixtures are used for this application since they have the lowest life-cycle cost and adequate color rendering for the application. will light a 5-foot radius circle to 6 footcandles (after a 60% maintenance factor is applied). HPS widebeam floodlight. Two 70-watt HPS fixtures. refer to API 540. To determine the lighting levels in Figure 1200-25. For example. Group D area. the sum of the contributions at the center of the 10-foot by 20-foot area is approximately 6 footcandles. A lighting survey has shown that the existing illumination where the new facilities are to be installed is essentially zero. Lighting design pamphlets available from major lighting manufacturers can be used as guides. When two fixtures are adjacent. construction. Figure 1200-25 shows a plot plan where two gasoline pumps are to be installed in an area adjacent to a pipeway. about 1 footcandle can be maintained (including the lumen maintenance factor) for a horizontal distance of Chevron Corporation 1200-39 September 1990 . 70-watt HPS fixtures mounted at a height of 8 feet will be used throughout the facility. Division 2. From Figure 1200-10. To design the lighting system. and (d) the pump manifold. Section 6. See Figure 1200-24 (bottom). To illustrate the iso-footcandle table method. mounted at 8 feet. For instance. will do the job. mounted at a height of 25 feet and aimed at 60 degrees. Two new walkways and a small parking lot are to be added. Parking Lot A 250-watt. the resulting footcandle level is the sum of the contributions from each fixture. the best method to overlap light output from different sources must be determined in order to achieve desired light outputs. The fixtures are aimed at 60 degrees to the opposite corners of the parking lot. With most multiple floodlight designs. but most of the lot will be adequately illuminated. The only existing lights in the area are the streetlights on the road and the floodlights by the existing pump station.2). divide the new area into four sections: (a) the parking lot. and maintenance of the facility. See Figure 1200-24 (top). 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. There may be shadow areas that may not achieve 1 footcandle. 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. one fixture will fulfill the requirement. (b) the walkways.6 = 1. Assume the area to illuminate is 10 feet by 20 feet. One 70-watt HPS fixture with a reflector. (c) the pumps.Electrical Manual 1200 Lighting When using iso-footcandle tables. it is virtually impossible to avoid shadow areas and still achieve a cost-effective design. Standardization simplifies the design. spaced 15 feet apart. Walkways For standardization purposes. The area classification is shown by hashed marks representing a Class I. Therefore. Electrical Manual 1200 Lighting Fig. 1200-22 Loading Dock Lighting Levels Chevron Corporation 1200-40 September 1990 . Electrical Manual 1200 Lighting Fig. 1200-23 Parking Lot Lighting Levels Chevron Corporation 1200-41 September 1990 . Fixtures will be separated by 25 feet. Pumps Seventy-watt HPS fixtures spaced 12.1200 Lighting Electrical Manual Fig. 25 feet apart. Area (bottom) 12. by 20 ft.5 feet from the intersection of the two new walkways and eight more are installed along the walkway towards the pump station. Circle (top) and Lighting Level at Center of 10 ft.5 feet. Four more are installed along the walkway toward the new pumps. 25 feet apart. September 1990 1200-42 Chevron Corporation .5 feet apart (one per pump) will provide the required 5 footcandles of illumination. One fixture is installed on the paved walkway.5 feet from the parking lot. 12. 1200-24 Lighting Level at a Radius of 5 ft. a fixture is installed 12. Along the 225 foot walkway towards the pump station. 1200-25 Iso-Footcandle Plot-Plan: Example Showing Iso-Footcandle Table Method Chevron Corporation 1200-43 September 1990 Electrical Manual 1200 Lighting .Fig. 1200-26 Desired Lighting Levels for Iso-Footcandle Areas in Figure 1200-25 Area Pump Pad Pump Manifold/General Area Walkways Parking Lot Lighting Level (footcandles) 5 1 1 1 Manifold Area The general area to be illuminated around the pump is approximately 50 feet by 50 feet. The labor portion of the relamping program typically dominates the total cost. The first approach. When the labor cost is not the largest portion of relamping cost. dust and other foreign material on lighting equipment can reduce the lighting level by 30% in only a few months.) A group replacement scheme can be developed for a given installation by considering the cost of labor and lamps. (2) cleaning fixtures. If fixture cleaning is coordinated with group lamp replacement. Replacing Lamps (Relamping) Two different approaches may be taken in relamping programs: (1) replace lamps as they extinguish. 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. This approach cannot be used if fixtures provide light for specific locations. Cleaning Fixtures In some instances. The time between replacements may vary somewhat because of variations in system voltage and operating schedules. on offshore platforms.g. individual lamp replacement. is usually the least cost-effective method. The type of ventilation and cleanliness of the surrounding area determine the required cleaning intervals. 1260 Maintenance Considerations If a regularly scheduled maintenance program is not followed. A good maintenance program involves: (1) replacing lamps. maintenance costs usually can be kept to a minimum. Proper maintenance is usually more economical than allowing the system to operate at low efficiency. September 1990 1200-44 Chevron Corporation . or (2) replace all lamps at one time (group replacement). A commonly used criterion for group replacement is: When 20% of the original lamps have failed.. and the effect of work interruptions. Overvoltage or undervoltage should be suspected if the replacement interval is several months shorter than normal. the entire installation is relamped.1200 Lighting Electrical Manual Fig. and (3) cleaning lighted surfaces. It is important to clean fixtures regularly. the first approach is the more economical (e. lamp life. the effectiveness of a lighting system can be substantially reduced. Ballast: An electromagnetic device used to control starting and operating conditions of electric discharge lamps. Discomfort: Glare that produces discomfort. Disability: Glare which reduces visibility and causes discomfort. but does not necessarily reduce visibility. Candela: Unit of luminous intensity (preferred over the term candle). However. Brightness: See luminance. Fixture: A full assembly of lamp. Direct: Glare resulting from high brightness in the field of vision. diffuser. 1270 Glossary of Terms Average Luminance: The average brightness of a luminary at a given angle. lens and guard. it is the unit of light output that lamp manufacturers identify on their specification sheets. Candle: Unit of luminous intensity (candela is preferred). holder. the lighted surfaces may need painting or cleaning. Illumination: The quantity of light (lumens) falling on a given surface area. Glare. Candlepower: Luminous intensity expressed in candelas. showing the effect of age on the output of a lamp. Glare.076 dekalux. socket. In practice. Lumen maintenance: Data. Brightness Ratio: See luminance ratio. Footlambert: The unit of luminance (brightness). It is equal to the illumination of a surface area of 1 square foot on which there is a uniformly distributed flux of 1 lumen. expressed in candles per square inch or footlamberts. The amount of light flux radiated into a solid angle by a uniform light source. The term luminaire is used interchangeably with fixture.929 footcandles. a check should be made first to insure that low voltage is not the problem. usually given in graph form. One footcandle equals 10. Dekalux: 10 lux (0. Chevron Corporation 1200-45 September 1990 .Electrical Manual 1200 Lighting Cleaning Lighted Surfaces Cleaning interior lighted surfaces usually is an important maintenance factor. Footcandle: The unit of illumination used in the United States. Lumen: The unit of luminous flux.) Electric discharge lamp: A lamp in which light is produced by passing an arc current through a vapor or gas. ballast (if necessary).76 lux or 1. Glare. If an illumination survey indicates less than the design level illumination after lamp replacement and fixture cleaning. 1282 Standard Drawings There are no standard drawings in this guideline. Lux: The International System Unit (SIU) of illumination. Luminous flux: The time rate of flow of light. and Engineering Forms (EF) *ELC-EF-484 Lighting Schedule *ELC-EF-599 Lighting Standards. equal to the illumination on a surface area of 1 square meter on which there is a uniformly distributed flux of 1 lumen. Flood Ltg. 1280 References The following references are readily available. the luminous intensity of a surface in a given direction. One lux equals 0. expressed in total output of a light source in lumens. 1283 Data Sheets (DS). Luminance: Brightness. expressed in lumens per watt. Those marked with an asterisk (*) are included in this manual or are available in other manuals. Reflectance: The fraction of the total luminous flux incident on a surface that is reflected. 1281 Model Specifications (MS) There are no specifications for this section. 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. Work plane: The plane where the task under consideration is located and where the recommended illumination is required. the parts to protect and position the lamps. Fixtures & Mtg. and the parts to connect the lamps to the power supply.1200 Lighting Electrical Manual Luminaire: A complete lighting unit which consists of a lamp with components to distribute light. Details *ELC-EF-600 Standard Lighting Poles. Fixtures. Data Guides (DG).0929 footcandles. and Receptacle Mountings September 1990 1200-46 Chevron Corporation . per unit of projected area of the surface. Mounting height: The distance from the work plane to the center of the lamp. DC Westinghouse Lighting Handbook. 1978 (No longer published) Chevron Corporation 1200-47 September 1990 . Deck Lighting. 1987.Regulations for Marine Oil Transfer Facilities. ANSI/NFPA No. 1984 Reference Volume and 1987 Application Volume IES RP 12. “Recommended Practice for Marine Lighting” National Electric Code. Coast Guard Regulations. “Recommended Practice for Electrical Installations in Petroleum Processing Plants” Code for Safety to Life from Fire in Buildings and Structures. revised August 1988. ANSI/NFPA 70 U. Revised May.570. “Design and Installation of Electrical Systems for Offshore Production Platforms” *American Petroleum Institute RP 540. 101 Electrical Construction Guidelines for Offshore.79. CUSA Eastern Region Production Department ANSI/IEEE Std 45. “IEEE Recommended Practice for Electric Installations on Shipboard” IES Lighting Handbook. Lighting. and Inland Locations.Electrical Manual 1200 Lighting 1284 Other References American 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. Washington.” Paragraph 154. Marshland. and Paragraph 155. July 1. “Pollution Prevention . Federal Register Title 33.S. and methods for managing them. their effects. Contents 1310 Introduction 1311 Scope 1320 Types of Disturbances and Outages 1321 Power System Disturbances 1322 Power System Outages 1330 Solving Power Problems 1331 Disturbance Problems 1332 Outage Problems—Emergency and Standby Systems 1340 Equipment Used for Auxiliary Power Systems 1341 Common Equipment 1350 Power Conditioning Equipment 1351 Power Synthesizer 1352 Motor-Generators 1353 Uninterruptible Power Supply (UPS) 1354 Dual Feeds 1355 Summary 1360 References 1361 Model Specifications 1362 Standard Drawings 1363 Data Sheets (DS).1300 Auxiliary Power Systems Abstract This section describes auxiliary power systems in industrial plants and provides guidelines for specifying the most commonly used equipment for auxiliary power systems. and Engineering Forms (EF) 1300-18 1300-16 1300-6 1300-5 1300-3 Page 1300-3 Chevron Corporation 1300-1 May 1996 . Data Guides (DG). It also lists and describes various disturbances and outages in power systems. 1300 Auxiliary Power Systems Electrical Manual 1364 Other References May 1996 1300-2 Chevron Corporation . and is caused by electromagnetic or electrostatic induction from the surroundings. program upsets. facilities. The effects of transient and oscillatory over-voltages are generally limited to systems which include computers (e. notably offshore.. The damage can result in errors. Conventional power.Electrical Manual 1300 Auxiliary Power Systems 1310 Introduction Generally.2 to 5 kHz and higher. and downtime.5 to 200 microseconds.g. This section also provides descriptions and general guidelines for specifying and sizing equipment that is commonly used for auxiliary power systems. on-site motor loads. a brief discussion of the various alternatives is presented.7 milliseconds at frequencies of 0. Normal-mode noise is a change in voltage appearing differentially between conductors. Electric common-mode noise is an in-phase change in voltage that appears equally on each conductor to ground. Voltage spikes are caused by lightning. A full engineering analysis of all types of power conditioning equipment and emergency and standby power systems is beyond the scope of this section. and operation of large. with durations of 0. 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. 1321 Power System Disturbances Transient and Oscillatory Overvoltage Voltage spikes may exceed 200 to 400% of rated rms voltage. the most convenient and economical source of electric power is a local electric utility (commercial power). omissions. Certain types of equipment. power network switching. Some locations. However. in most cases. control. 1311 Scope This 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 operations. plants.) Oscillatory transients can cause damage to both hardware and software. They may be oscillatory up to 16. Chevron Corporation 1300-3 May 1996 . The quality and reliability of the power is. are not served by local utilities. In these situations the most cost effective method of supplying power (at the required standards) must be determined. microprocessors and process controls. or installing an emergency or standby power system. It is caused by unequal electromagnetic or electrostatic induction between the conductors and their surroundings. This may require adding power conditioning equipment. 1320 Types of Disturbances and Outages This section provides a brief description of possible power system disturbances and outages. adequate and acceptable. requesting the electric utility to install additional or parallel facilities. and processes require high quality electric power and reliability that cannot be met by commercial power. respectively. Automatic transfer can occur in a time as short as four milliseconds (1/4 cycle) if a static transfer switch is used. If the reclosure is too fast.5 to 60 seconds. Generally. because of inherent inertia.. For instance. mercury vapor and high-pressure sodium).g. (2) an electrical system equipment failure. or product rejection.and over-voltage conditions are either below 80 to 85% or above 110% of rated rms voltage. momentary outage problems can range from a minor annoyance to a serious hazard and financial loss. “Lighting. protective systems may initiate shutdowns. Permanent Outage A permanent outage is a complete. They are caused by power system faults. motors will continue to run (ride through). As the duration of the disturbance increases. with only a slight increase in slip (induction) or torque angle (synchronous). and power system equipment malfunctions. will extinguish if the voltage drops below certain levels. large load changes (possibly seasonal).or over-voltage depend upon the length and severity of the voltage disturbances. relays and contactors may drop out. motors may stop because their starter contacts open due to low voltage. At the lower end of the 4 to 60-cycle range.” for additional details.or Over-voltage Under. The first reclosure usually occurs in less than 10 seconds. See Section 1200. Some circuit protective devices are set for three or four automatic reclosures before lockout. depending on the type of power system and on-site distribution.) Personnel safety should also be considered if HID lighting is involved (due to the restrike time). Depending upon the severity of the under-voltage. The effects would be similar to those that occur in transient and oscillatory disturbances except that hardware damage seldom occurs. May 1996 1300-4 Chevron Corporation . more conventional types of power equipment are affected. sustained power failure due to a protective device opening as a result of (1) a fault. many transient conditions will not clear. computer systems and some types of sensitive high speed instrumentation and control systems will be affected. High-Intensity Discharge (HID) lighting (e. and control system readouts may go off scale. Automatic reclosure of utility system protective devices or automatic transfer to an alternate source is seldom fast enough to prevent shutdown of the supplied equipment when momentary outages occur. The timing of reclosure can range from 0. However. 1322 Power System Outages Momentary Outage A 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 automatic reclosure of the protective device or automatic transfer to an alternate source.1300 Auxiliary Power Systems Electrical Manual Momentary Under. They have durations of 4 to 60 cycles. loss of production. and a second momentary outage or a lockout will result. The effects of under. power utilization equipment is not affected by short duration disturbances. Depending on the facility. (Certain facilities may require planned orderly shutdowns to prevent equipment damage. ) Knowing the source of the disturbance is important to ensure that power conditioning equipment is installed at the most effective locations. Outage time can range from a few minutes to days. 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. Emergency systems may be supplemented by standby power systems to increase the supply time. An analysis of the power source operating records is needed to develop a complete power profile of the system. First. 1332 Outage Problems—Emergency and Standby Systems The effects of an outage may range from tolerable to completely unacceptable regardless of whether the outage is momentary or permanent. the necessity for continuous equipment operation. the cause of the system disturbances should be determined. The study should begin with the installation of power disturbance recording equipment. Personnel safety could also become a problem with a total blackout. a study should be conducted to identify the extent and nature of the power problems. The various methods of power conditioning and their effectiveness are examined below. continuous equipment operation. process control. 1330 Solving Power Problems 1331 Disturbance Problems Solving power system disturbance problems is accomplished by evaluating the degree of power conditioning required. The effects of permanent outages are much the same as momentary outages except that production losses may become more significant. Normal system instrumentation is generally not capable of recording high speed transients and oscillations. power system operating personnel must respond before power can be restored. A careful study should be made to determine if an emergency or standby power system is necessary for personnel safety. Startups can be difficult and lengthy after a long shutdown.Electrical Manual 1300 Auxiliary Power Systems or (3) incorrect operation of power system protective equipment. (Keep in mind that the source of the disturbance could be at the power source or the facility’s distribution system. In all cases. Chevron Corporation 1300-5 May 1996 . The imperfections in available power. and the “clean” power requirements of the equipment define the extent of the power conditioning required to solve power disturbance problems. when the power profile of the system is complete. 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. “System Design.” for details regarding whether an emergency and/or a standby system is required. Starting and regulating controls (for on-site standby generation). Controls (manual or automatic) that transfer loads from the normal to standby or alternate source. 1340 Equipment Used for Auxiliary Power Systems Once it has been established that an emergency or standby power system is required.1300 Auxiliary Power Systems Electrical Manual Standby power systems should have the following features: 1. “System Design” for further information. What are the power requirements? Is highly reliable and/or high quality power required for process controls or computers. 6. 3. Customers may also be charged amortization and/or standby costs for additional equipment. The following questions should be answered before a decision is made. 2. or must old plants carry a greater burden? 2. An alternate source of electric power (separate from the normal power source). 1. or is commercial quality power acceptable? 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? Must power be available under “no-break” conditions or are momentary outages acceptable? What frequency of outages are acceptable? Can several facilities be supplied from a single alternate source? Can the provider of normal power (the utility) improve the reliability of its service? If so. Generators Storage Battery Systems May 1996 1300-6 Chevron Corporation . 4. 3. 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. The four most common systems used in industrial plants as auxiliary power are: 1. 2. 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). an auxiliary power system independent of the utility power source is needed to provide uninterrupted emergency or standby power. 1341 Common Equipment In most industrial plants. a study should be conducted to determine the proper system and hardware needs. See Section 100. See Section 100. 5. “System Design.” Generators Engine-Generators. Inc. automatic transfer of the load to the generator and fuel storage.Electrical Manual 1300 Auxiliary Power Systems 3. Provisions must be made for automatic starting of the engine. 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. “Recommended Practice for Emergency and Standby Systems for Industrial and Commercial Applications. Diesel engine-generators (as shown in Figure 1300-1) are commonly used in industrial plants to provide emergency or standby power. see IEEE Std 446. 4. For standby service. 1300-1 Typical Diesel Engine-Driven Generator Permission granted by Caterpiller.” Fig. Caution! The generator normal operating load should not be less than 50% of the diesel engine nameplate Chevron Corporation 1300-7 May 1996 . The fuel cost is relatively low and fire and explosion hazards are less for a diesel engine-generator than for a gasoline engine-generator. the diesel engine-generator should be specified to conform to the following conditions. Properly designed engine-generators can start and accept full load in less than 10 seconds. see Section 100. Uninterruptible Power Supplies Unit Equipment (primarily for emergency lighting systems) For more information. Diesel generators are available in sizes up to several MW. For sizing generators. Removable. Operation at less than 50% will cause carbon buildup in the engine and decrease reliability. thermostatically controlled. 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. Storage Battery Systems A storage battery system is the most dependable system for providing DC power for emergency or standby power for loads (e. Steam turbine drivers are an alternative to engine-driven generators where steam is available. Both of these problems can become more serious in cold climates. electric immersiontype crankcase oil and water jacket heaters should be specified for use in cold weather climates.1300 Auxiliary Power Systems Electrical Manual rating.g. Lead-acid flooded cell batteries (lead-calcium and lead-antimony) Sealed. A storage battery system consists of rechargeable batteries and a battery charger. causing the turbine to overspeed and trip on startup. communication equipment. fire and gas detection systems. Naturally aspirated engines are preferred over turbocharged engines. The three types of batteries most commonly used are: 1. valve regulated lead acid (VRLA) batteries Nickel-cadmium batteries May 1996 1300-8 Chevron Corporation . ELC-MS-4802 and DC Power Storage Battery System Data Sheet. “System Design. For details of natural gas engines. Governors can be a source of trouble.” Batteries and battery chargers for DC power supplies should be specified in accordance with the attached Specification. refer to the Driver Manual. Natural gas-fueled engines are used where natural gas or LP gas is readily available (such as on offshore platforms). ELC-DS-4802.. Fuel will also need to be heated in cold climates. They have a long life and are quick starting after extended shutdown periods. 3. Damage to turbines may occur because of wet steam if the steam trapping is not adequate. See the Driver Manual for information on selecting a steam turbine. For sizing batteries and battery chargers see Section 100. and switchgear control power). Many refineries utilize steam turbine-driven standby generators. The decision to use a steam turbine should be carefully considered. 2. Some problems can be expected if these are used. Gasoline engine-generators may be appropriate for installations up to 100 kW but are not recommended for offshore and metropolitan applications. emergency lighting systems. Detailed comparisons are shown in Figures 1300-2 and 1300-3. when discharged 2. Lead-acid flooded (or wet) cell batteries use sulfuric acid and water as electrolyte and include lead-antimony and lead-calcium alloy plate designs.-1 yr. Does gas on high rate No Yes -50-115°F without freeze hazard or loss of life Only at -50°F or below 1.0 Low end of leadcalcium Good Quarterly 140-200% Does not gas on float.2 20 WH/Lb Better than leadcalcium Quarterly 160-300% Nickel-cadmium Corrosive Fumes Spillage Hazard Temperature Range Freezing Problems Volts/Cell. Sealed VRLA and Nickel-cadmium Batteries (1 of 2) Lead-Acid Lead-calcium Gassing Gases on float/equalize Yes Yes 32-85°F without freeze hazard or loss of life Yes. when discharged 2. Nominal Energy Density Mechanical Ruggedness Maintenance Requirements Relative Cost Based on 20-Year Battery Shelf Life When Filled and Not on Charge 6 mo. Lead-antimony. when discharged 2.0 Slightly less than lead-calcium Good Quarterly 105% Sealed VRLA Gases recombine inside battery No No 32-80°F without freeze hazard or loss of life Yes. Fig. 6 mo. very long Chevron Corporation 1300-9 May 1996 .Electrical Manual 1300 Auxiliary Power Systems Lead-Acid Flooded Cell Batteries. Indefinite.-1 yr.0 10-25 WH/Lb Good Quarterly 100% Lead-antimony Gases on float/equalize Yes Yes 32-85°F without freeze hazard or loss of life Yes. 6 mo. 1300-3 Comparative Features of Lead-calcium.-1 yr. 1300-2 Recommended Battery Type Location Controlled Temperature Environment Uncontrolled Temperature Environment Inside Office Area <100 Discharges (To Final End Voltage) Lead-calcium Nickel-cadmium Sealed Lead-calcium >100 Discharges (To Final End Voltage) Lead-antimony Nickel-cadmium Lead-antimony in Adjacent Battery Room Fig. severely reduces life Stays constant. normally Use is low. therefore. from which they cannot be recharged economically. valve-regulated lead acid (VRLA). therefore. Lead-acid batteries require low voltage disconnects to prevent full discharge.1300 Auxiliary Power Systems Electrical Manual Fig. Lead-antimony. gases on high rate Yes. Sealed. normally Widely used Normal battery disposal 40+ years 15-20 years Required. gases on float/equalize Yes. 1300-3 Comparative Features of Lead-calcium. However. Gas is not emitted under normal usage.S. lead-calcium batteries cannot tolerate discharge cycling as frequently as lead-antimony batteries. 500 cycles to end of voltage Poor. water normally does not need to be replaced. Lead-acid type batteries do not tolerate elevated temperatures and. Lead-calcium batteries may be used for many applications. The life of a lead-acid battery is reduced by 50% for each 15°F above 77°F. does not indicate charge state Very good. May 1996 1300-10 Chevron Corporation . They have a longer shelf life and are less expensive than lead-antimony batteries. Sealed VRLA and Nickel-cadmium Batteries (2 of 2) Lead-Acid Lead-calcium Specific Gravity Changes to indicate state of charge Average 100 cycles to end of voltage Poor. mainly due to high cost Hazardous waste disposal 40+ years 20+ years Nickel-cadmium Cycling Capability Ability to Withstand Complete Discharge Ventilation Requirements Special Room Required? Frequency of Use Disposal Years in Field Application Life to 80% Capacity with Minimum Cycling Note Required. severely reduces life Sealed VRLA Changes (cannot monitor) Average 100 cycles to end of voltage Poor. leadcalcium batteries have a minimum amount of electrolyte which is absorbed in the absorbtive glass mat (AGM) separator material or contained in a gel. are recommended only for use in temperature-controlled environments. Lead-Acid Sealed Batteries. Lead-calcium batteries require fewer equalizing charges and charge more efficiently than lead-antimony batteries. gases on float/equalize Yes. Both of these are less expensive than sealed VRLA and nickel-cadmium batteries. severely reduces life Lead-antimony Changes to indicate state of charge Good. no damage on complete discharge Required. 2000 or more in lifetime Very good. 5-15 years (Depending upon design) Additional comparative battery data is available in API RP-14F. normally About 10-20% Normal battery disposal 75+ years 15-20 years Not required under normal conditions Temperature controlled About 30-50% Normal battery disposal 8 years in U. In this system. per year. Their initial cost is more than lead-acid batteries. may be less. 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 battery does not supply load current unless the charger is overloaded or Chevron Corporation 1300-11 May 1996 . More cells are required for a nickel-cadmium battery than for a lead-acid battery of the same voltage. Nickel-cadmium batteries have a longer life. if a nickel-cadmium battery is not discharged with an external load. They can be charged after a full discharge (common during platform evacuations). Sintered plate cells are subject to thermal runaway. are more ruggedly constructed. and are more tolerant of elevated temperatures.2 volts. Nickel-cadmium batteries can operate more efficiently at much lower temperatures than lead-acid batteries.Electrical Manual 1300 Auxiliary Power Systems 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. A battery charger converts AC voltage into a regulated DC voltage. nickel-cadmium batteries are recommended for most applications (except for engine cranking service where lead-acid batteries are used). it will remain charged for a longer time than a lead-acid battery. Pocket plate. The life of a nickel-cadmium battery is minimally affected by temperatures up to 115°F. The charger keeps the battery fully charged at all times so that the battery will be available during failures of normal power.0 volts for lead-acid batteries. but their cost per amphour. and they require less maintenance. nickel-cadmium batteries are not frequently used in on-shore plant applications. Battery Chargers. Nickel-cadmium batteries are made with nickelcadmium plates in an electrolyte solution of potassium hydroxide and pure water. they can withstand ten times as many discharge cycles. Except for standby switchgear control power applications. The nominal nickel-cadmium cell voltage is 1. compared to 2. Nickel-cadmium batteries can tolerate much harsher temperatures than lead-acid batteries. as opposed to sintered plate. In offshore platform operations. The nickel-cadmium cell also has a much lower self-discharge. As a result. 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. cells should be specified. If power is not restored. Float Trickle Equalizing Float charging. The special features that distinguish a battery charger from a conventional rectifier are: 1.1300 Auxiliary Power Systems Electrical Manual shut down. 2. (Clean and stable is defined as having minimal harmonic distortion and being free of transients and voltage swings. Uninterruptible Power Supplies For AC Power The primary function of an uninterruptible power supply (UPS) is to provide critical loads with uninterrupted clean. and 135 in “System Design”. 134. 2. Trickle charging. not all cells in a multi-cell battery display identical current efficiencies in charge and discharge. Therefore. The UPS may provide power for critical May 1996 1300-12 Chevron Corporation . The choice of method depends primarily on the service intended for the battery system. Because of minor differences among individual cells in leadacid batteries. Charging methods. The most common charging methods are: 1. and delivers energy on demand. constant current charging at a low rate. 4. the state of charge of the cells becomes unbalanced when charged by constant potential methods. Float charging is a condition where the battery is permanently connected to a constant potential charging device from which the battery receives its charge. Several charging methods are available. Close output voltage regulation over the full range of rated-output current and input voltage Current-limiting capacity (including discharged batteries) Automatic switching from a voltage-regulating mode to a current-regulating mode at preselected values of output current Stable output when connected to a fully charged or discharged battery SCR type battery chargers are most commonly used. at a rate which is several times the rate of self-discharge.) For sizing UPS systems see Sections 124. and stable AC power. 3. 3. This method is used for uninterruptible power supply (UPS) systems. Trickle charging. UPS systems utilize standby storage batteries to provide clean AC power for a limited time during power outages. Equalizing charging. As a result. 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). is used primarily for emergency and standby systems. the UPS will shut down when the batteries are nearly discharged. Trickle charging is continuous. be of better quality than the normal AC power source. It is recommended that the isolated redundant system with two sets Chevron Corporation 1300-13 May 1996 .Electrical Manual 1300 Auxiliary Power Systems systems to allow orderly shutdowns and to provide for personnel safety. After 6 cycles. the AC output of the inverter can. If the UPS fails or is overloaded. supplying fault current. ELC-DS-2643. Since most short circuits are ground faults and most UPS branch circuits are protected by circuit breakers. contains a battery charger. the UPS inverter output and the bypass will be in parallel. The typical UPS system is solid state. The UPS may consist of single (see Figure 1300-4) or multiple modules (see Figure 1300-5). The magnitude and location of the fault will determine the voltage drop on the system.05 to 0. Voltage dip is minimized by the fast action of the CL fuse. A manual external bypass switch is recommended to allow switching the load to the AC line. If branch circuits are protected by current limiting (CL) fuses and if the fault current is within the current limit range.2 seconds. UPS systems should be specified in accordance with Specification ELC-MS-2643. the short circuit condition will persist for about 3 . If a transfer has been made and the system has stabilized. The duration of the voltage drop depends upon the time the protective device takes to clear the fault. notably a low voltage condition. The transfer is necessary as the inverter is normally incapable of supplying the energy necessary to clear a fault. the inverter-output circuit breaker opens and fault current is supplied by the bypass. Under normal operation. The inverter supplies power to the AC load through a transformer. the output will be transferred from the inverter to an AC bypass through a static transfer switch. If a fault occurs on a downstream branch circuit that exceeds the inverter’s capability (normally about 150% of rated current). The battery is sized to provide the system standby time requirements (typically 15 minutes to 4 hours). With this system. All manufacturers provide the automatic retransfer feature. a static inverter. Because this is the normal mode of operation. if required. any power disturbance that may occur in the incoming AC line will not be transmitted to the AC load. which isolates the inverter and static switch for maintenance. it will be bypassed automatically through a static transfer switch to the internal bypass circuit. For a period of 2-1/2 to 6 cycles.” and Data Sheet. all UPS branch circuits will be subject to the effects of the fault. a faulted branch will clear in less than one-half cycle. “Solid State AC Uninterruptible Power Supply. therefore. During the fault time period of between 0. an automatic retransfer to the inverter is advised. the SCR’s in the static transfer switch will begin conducting in 1/2 cycle. The manual bypass switch should have make-before-break contacts to permit bypass of the load without any interruption.10 cycles. the time necessary for a CL fuse to clear a fault and not transfer to the bypass. (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 AC power supplies the rectifier and the battery charger which provides DC input power to the static inverter and charges the battery. and a static transfer switch. storage batteries. Upon sensing a fault. ) May 1996 1300-14 Chevron Corporation . (See Figures 1300-4 and 1300-5. and may be justified for critical processes where the instrumentation requires continuous higher quality power than that which is available from normal power.1300 Auxiliary Power Systems Electrical Manual of batteries be used for most systems where the process is critical and instrumentation cannot operate properly on utility power. Fig. the isolated redundant system is more reliable for providing power to instrumentation. 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. 1300-4 Non-Redundant UPS Configuration with External Maintenance Bypass Although more expensive than a single system. 1300-5 Isolated Redundant with Individual Batteries and External Maintenance Bypass Chevron Corporation 1300-15 May 1996 .Electrical Manual 1300 Auxiliary Power Systems Fig. An electrostatically shielded isolation transformer is very effective in reducing common-mode noise. isolating. Isolation transformers can prevent power system noise from disturbing sensitive equipment. 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. When utility power is restored. Completely self-contained individual emergency lighting units are also available. AC inverter units are used primarily for providing emergency lighting power when there are no standby generators for emergency power or when standby high intensity discharge lamps are used in the emergency lighting system. systems) which do not require high quality power. High intensity discharge lamps that have been illuminated will extinguish with power interruptions. filtering. the UPS system should be connected to the standby bus to reduce the required capacity of the batteries. an inverter. or reduce distortion. In AC emergency lighting inverter units. increasing. These units usually contain the following: a trickle charger. and will not relight for 10 minutes or more (if not provided with instant restrike).1300 Auxiliary Power Systems Electrical Manual If a standby generator is provided. and a test switch. The transformer should have the capability to sufficiently attenuate electrical noise.” 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.A. See Section 1200. They typically supply emergency light for up to 1-1/2 hours. utility power is fed directly to the lighting load via a transformer and a static switch. a high speed circuit detects the failure and simultaneously turns on the inverter (battery powered) and disconnects the utility input with the static switch. It does not provide protection from normal-mode transients. an indicator lamp. a solid state switch. regulate line voltages. The isolation transformer will reduce common-mode noise and electromagnetic interference (EMI). the static switch simultaneously turns off the inverter and transfers the lighting load back to the utility source without interruption of power to the load. Unit Equipment Two types of unit equipment are available for emergency lighting: AC emergency lighting inverter units and self-contained individual emergency lighting units. or decreasing the voltage before delivering power to the equipment. May 1996 1300-16 Chevron Corporation . They can be used for emergency lighting and other loads (such as P. “Lighting. When utility power fails. 1350 Power Conditioning Equipment The following methods should be considered to modify and improve incoming power waveforms by clipping. They should be installed as close to the protected equipment as possible. The inverter is normally off and the batteries charged. Transformer taps allow higher or lower output voltage levels to be set. a battery (normally nickel-cadmium). These are often used where 400 Hz power is required. 1351 Power Synthesizer An AC magnetic power synthesizer uses pulse transformers. 1352 Motor-Generators Motor-generators are one of the oldest methods for providing high quality power. shielded flexible conduit with appropriate wiring and receptacles for the equipment to be serviced. long-term high voltage. The system is virtually maintenance free and will maintain power during a loss of input power for one cycle. an alternative is to install a line-voltage regulator. or voltage spikes that do not exceed the clamping limits. Chevron Corporation 1300-17 May 1996 . as well as possible variations in frequency. (3) a circuit breaker panel. Surge suppressors clip high voltage spikes and transients. For an existing system. They contain the following isolation and distribution equipment: (1) an isolation transformer with an electrostatic shield and voltage adjustment taps. They do not provide protection from noise. pre-engineered power systems should be considered.Electrical Manual 1300 Auxiliary Power Systems For protecting computer-controlled data processing systems. A linevoltage regulator maintains steady state voltage within desired operating limits and permits reduction of transient voltage disturbances of short duration. and (4) an insulated. and capacitors to create the desired AC output waveform. completely isolated power output waveform. and provides power that is almost free of spikes and transient disturbances. The system is portable. inductors. feeders should be designed with the impedance as low as possible to minimize voltage drops. A motor draws power from the utility line to drive an alternator. To ensure better voltage regulation. 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. The inherent limitations of a typical regulator allow short-term variations to be transmitted to the load and offer no protection from waveform distortion. voltage sags. which in turn supplies power to the equipment. (2) a main circuit breaker with a shunt trip feature. and voltage fluctuations by creating a new. The following power conditioning methods offer the most dependable means of delivering power without spikes. noise. and can be placed close to the system being protected. 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. and the electrical loads should be balanced on the phases. 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. See Section 1341 for more details. considerable space (dependent to a large extent on battery back-up time). 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. 1360 References The following references are readily available.1300 Auxiliary Power Systems Electrical Manual 1353 Uninterruptible Power Supply (UPS) The UPS is the most expensive power conditioning system. 1361 Model Specifications * ELC-MS-2643 * ELC-MS-4802 Solid State AC Uninterruptible Power Supply DC Power Battery Storage System 1362 Standard Drawings * GF-P-99972 One Line Diagram 480V Emergency Power System 1363 Data Sheets (DS). (See Figure 1300-6. and maintenance costs can be high. It requires a large initial investment. Many variations and options are available within the various categories. 1354 Dual Feeds A third alternative for protection from momentary under or over voltage disturbances is dual feeders with a magnetic synthesizer. and Engineering Forms (EF) * ELC-DS-2643 Solid State AC Uninterruptible Power Supply Data Sheets May 1996 1300-18 Chevron Corporation . The following table summarizes and compares the effectiveness of the more common methods of reducing power system disturbance problems. Reliability is dependent on the available power sources. Data Guides (DG). Those with an asterisk (*) are included in this manual or are available in other manuals. 1355 Summary The alternatives for power conditioning range from circuit modifications to total isolation of sensitive equipment from the power system.) The above information is intended only as a brief summary of the various methods of power conditioning. Design and Installation of Electrical Systems for Offshore Production Platforms API RP 540. Many variations and options are available within the various categories. depending on regulator response time Eliminates most. depends on capability to maintain generated power during voltage fluctuation Eliminates all under. Refer to the text for details.Electrical Manual 1300 Auxiliary Power Systems * ELC-DG-2643 * ELC-DS-4802 * ELC-DG-4802 Instructions for Solid State AC Uninterruptible Power Supply Data Sheet DC Power Storage Battery System Data Sheet Instructions for DC Power Storage Battery System Data Sheet Fig. Recommended Practice for Electrical Installations in Petroleum Processing Plants ANSI/IEEE Standard 446. Chevron Corporation 1300-19 May 1996 .and over-voltages. depends on capability to maintain generated power during voltage fluctuation Eliminates most.and overvoltage Magnetic synthesizer Motor-generator Eliminates all voltage spikes Uninterruptible power supply Dual feeders Note Eliminates all voltage spikes No effect The above information is intended only as a brief summary of the various methods of power conditioning. filters. IEEE Recommended Practice for Emergency and Standby Power Systems for Industrial and Commercial Applications. does not eliminate load generated spikes Eliminates all voltage spikes Momentary Under-voltage or Overvoltage Some improvement(1) No effect No effect Line-voltage regulator Some. does not eliminate loadgenerated spikes Eliminates some source voltage spikes. and spikes Eliminates most under. (1) These improvements do not suppress disturbances but can make the load less sensitive to voltage disturbances. and lightning arrestors combined Shielded isolation transformer Transient and Oscillatory Overvoltage Some improvement(1) Suppresses most voltage spikes Eliminates most source voltage spikes. 1300-6 Comparison of Power Conditioning Methods Condition Method Balanced load on three-phase supply with improved grounding Surge suppressor. 1364 Other References API RP 14F. 1300 Auxiliary Power Systems Electrical Manual ANSI/IEEE Standard 484. IEEE Recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations. 1984. ANSI/UL924.. N. Transactions Industrial Applications ANSI/NFPA 70. IEEE. McGraw-Hill.Y. Code for Safety to Life from Fire in Buildings and Structures. May 1996 1300-20 Chevron Corporation . National Electric Code ANSI/NFPA 101. Emergency Lighting and Power Equipment Linden. Diagnosing Power Quality Related Computer Problems. Handbook of Batteries and Fuel Cells. IEEE Recommended Practice for Installation Design and Installation of Large Lead Storage Batteries for Generating Stations and Substations. ANSI/IEEE Standard 485. It discusses preventive maintenance of electrical systems and equipment. Commissioning.1400 Electrical Checkout. Inspection and Testing checklists are provided. Contents 1410 General 1411 Scope 1412 Safety 1413 Documentation 1420 Testing Methods 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 1440 System Check-Out and Commissioning 1400-9 1400-9 1400-4 Page 1400-3 Chevron Corporation 1400-1 September 1990 . Company equipment specifications and data sheets for factory check-out and testing of most equipment are also in this section. and Maintenance Abstract This section establishes requirements for the checkout and commissioning of newly installed or upgraded electrical systems. and Maintenance Electrical Manual 1450 Maintenance 1460 References 1461 Model Specifications (MS) 1462 Standard Drawings 1463 Data Sheet (DS). September 1990 1400-2 Chevron Corporation . Electrical Equipment Maintenance. Data Guide (DG) and Engineering Forms (EF) 1464 Other References 1400-10 1400-10 Note All figures reprinted from NFPA are reprinted with permission from NFPA 70B. Mass. Quincy. 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.1400 Electrical Checkout. 02269. Commissioning. National Fire Protection Association. Copyright © 1987. inspection and testing. Electrical systems should then be checked and commissioned as part of the construction and start-up phases of a project. use of Specification ELC-MS-4744. as well as ensure that damage to equipment and plant shutdowns do not occur. It is comprehensive and may be tailored to the user’s specific requirements. “Electrical Systems Check-out and Commissioning. Finally. factory acceptance tests should be conducted to ensure that equipment conforms with specifications and industry standards. For guidance in developing an Electrical Preventive Maintenance (EPM) program. For check out and commissioning of a complete electrical facility. comparison of test data throughout the life of equipment may be used to track deterioration and predict failures. Only qualified personnel should be permitted to participate in any test program and only proper test equipment should be used. During facility construction. 1412 Safety Many tests performed on electrical equipment involve the use of imposed high voltages and special test equipment.” This may be used in conjunction with facility operating experience for developing an EPM program.” is recommended. Detailed references are also provided. Also. 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. Commissioning. Initially. 1413 Documentation Proper documentation of all inspections. 1411 Scope This guideline discusses recommended methods for checking and testing electrical equipment and systems. Chevron Corporation 1400-3 September 1990 . Company specifications covering factory tests for different types of electrical equipment are referenced.Electrical Manual 1400 Electrical Checkout. Safety procedures must be designed to prevent injury to both test and non-test personnel. tests. operating facilities require ongoing maintenance. and maintenance performed is very important. “Recommended Practice for Electrical Equipment Maintenance. refer to NFPA 70B. and Maintenance 1410 General Electrical equipment and systems are inspected and tested during the various phases of a facility’s life. Test data must be recorded so that personnel may evaluate any problem areas that are detected at the time of the test or later. This specification covers the inspection and testing requirements for newly installed or upgraded electrical systems. A comprehensive safety program should be in operation before testing electrical equipment or systems. it is the preferred method to gage insulation deterioration. Insulation is tested by placing a test potential across the insulation and comparing the readings to a reference standard. Test equipment for DC voltage testing is smaller and more readily available than AC voltage testing equipment.” 1421 Visual Inspection Visual inspection is critical. It may be applied as either a dielectric absorption test or a step-voltage test. The temperature correction is made according to the equation R = K (1 + KV) as defined in ELC-MS-4744. environmental factors. Detailed information on these testing methods can be found in Chapter 18 of NFPA 70B. a DC high potential test set with kilovolt and micro-amp meters is used. The DC high potential test is performed by applying voltage across an insulation at or above the DC equivalent of the AC peak voltage. voltage stresses. Since temperature and humidity can affect the megohmeter readings. In either case. Visual inspections should be performed during factory tests. It is less stressful to the insulation than AC voltage testing. with a minimum of 1 megohm. An ohmmeter which reads directly in megohms is used as the potential source. Insulation resistance or megohmeter testing is performed by applying 500 to 5. Clean dry insulations will normally test higher than this value. September 1990 1400-4 Chevron Corporation . Insulation may deteriorate due to aging.1400 Electrical Checkout. Insulation resistance values are affected by temperature and should be corrected to a base value for proper comparison. therefore. “Recommended Practice for Electrical Equipment Maintenance. and plant maintenance. Test data obtained from DC testing may be used to track insulation resistance over time. Megohmeter testing is easy to perform and is used extensively during all phases of equipment testing. inspecting for foreign objects and contaminants. One rule of thumb is that insulation resistance should be at least one megohm per 1. facility check-out and commissioning. the changes in readings must be carefully analyzed before deciding the insulation has deteriorated. DC Voltage (Potential) Testing DC voltage testing is the most commonly used method for testing insulation.000 V of insulation rating. Since DC insulation testing is easy to perform. Megohmeter readings may be charted and used to detect deterioration in insulation systems.000 V DC across the insulation. It includes comparing equipment and systems with design drawings. 1422 Insulation Testing Insulation failure is the most common cause of failure of electrical equipment. facilities commissioning and plant maintenance. less potential for damage exists. and checking for changes in appearance over time. Commissioning. or mechanical and thermal damage. and Maintenance Electrical Manual 1420 Testing Methods The following discusses the basic inspections and tests which are performed on most electrical facilities. “DC High Potential Testing of Medium Voltage Cable and Electrical Equipment. A rule of thumb is to perform commissioning tests at 75% of factory test voltage and maintenance tests at 65% of factory test voltage. Insulation may be evaluated from the absolute insulation resistance at each voltage step. and whether or not a sharp increase in leakage current occurs at higher test voltages. Whenever high potential testing is performed. Evaluation of test results is based on the comparison to previous tests. A leakage current reading is taken at each interval. Step-voltage field tests are typically performed on medium voltage cables and equipment. Chevron Corporation 1400-5 September 1990 . high-pot testing is recommended for medium voltage systems (except for transformers) during maintenance turnarounds to uncover insulation weaknesses while they can be repaired. The polarization index is the ratio of the insulation resistance after 10 minutes to the value after 1 minute of potential application. with each voltage applied until the leakage current stabilizes. is not commonly performed in the field. This test. and leakage current readings are taken each minute.” for more information. An increasing power factor is a sign of insulation deterioration. and a voltage versus leakage current plot is developed. When applied as a step-voltage (hi-pot) test. care should be taken to ensure that insulation is not overstressed. The insulation is evaluated on a “pass or fail” basis. transformers and cable. for 5 minutes thereafter. AC Potential Testing AC high potential tests are performed by subjecting insulation to high AC voltages for a brief period (approximately 1 minute). the change in insulation resistance with voltage. and Maintenance When applied as a dielectric absorption test. Comparison of polarization index values over time can help identify deteriorating insulation and prevent failures. is another AC voltage test which may be performed on all types of insulating materials. AC high potential field testing is not recommended since AC voltage testing is sometimes a destructive test. the maximum voltage is applied gradually over a period of about 1 minute. however. If a sharp increase in leakage current occurs. See Specification ELC-MS-2469. A low value indicates that the insulation is probably moist or dirty. Actual failure or excessive leakage current is considered a “fail” evaluation. the test should be discontinued.Electrical Manual 1400 Electrical Checkout. test voltage is increased in a number of equal increments until maximum test voltage is reached. Care should be taken in comparing previous plots and data. Sometimes it is useful to calculate the polarization index for rotating electric machinery. Insulation power factor testing. The insulation resistance may be calculated from the applied voltage and the resulting leakage current. which is used to determine the power loss through insulation. Some facilities do not perform high voltage field testing on transformer or rotating electric machinery windings due to concerns of overstressing the insulation. However. The value usually should be above 2 (resistance at 10 minutes divided by resistance at 1 minute). Commissioning. as results are subject to variations in temperature and humidity. Visual. See note on page 1400-1. Therefore. the corresponding ASTM test method. (Oil) 25 kV Min. (Askarel) 0.0 Max.2–. dirty. Recommended Practice for Electrical Equipment Maintenance.014 Max. 0.0 Max. ASTM Dielectric Breakdown Voltage ASTM Test Method D1534-64 or D1902-64 D1500-64 (1968) D877-67 (Disk Electrodes) or D1816-67 (VDE Electrodes) D1524-69 (Petroleum Oils) or D1702-65 (Askarels) D971-50 (1968) (Ring Method) or D2285-68 (Drop Weight) D974-54 (1968) or D664-58 D924-65 (1969) Minimum Test Criteria Typical New Liquid Values Same as Neutralization Number Below 4. (Askarel) 22 kV Min. and the typical acceptance criteria. Min. Maintenance tests usually should include dielectric breakdown and neutralization number tests as well as a visual examination. (25°C) (Askarel) Equipment normally is received from manufacturers already filled with oil and sealed. (25°C) (Oil) . Should the insulating liquid not pass the breakdown test or exhibit marginal qualities. it may be practical to have a series of tests run. or have visible water or contaminants 18 Dynes/Cm.5% Max.0% Max. If samples are sent to a laboratory for testing. (Oil) 0.0 Max. Min.014 Max.40 Max. 1400-1 Insulating Liquid Tests and Acceptance Criteria Courtesy of NFPA 70B. including a test for PCBs. and Maintenance Electrical Manual 1423 Insulating Liquid Testing Electrical equipment insulating liquids should be tested on a regular basis by performing a series of tests on liquid samples. Commissioning.1% Max. (Oil) 0. (Askarel) 1.04 Max. (Oil) 2. additional tests may be required to determine the reason. Test Acidity Color. only a dielectric breakdown test is usually required during commissioning activities. Clear Interfacial Tension (Oil Only) Neutralization Number Power Factor 35 Dynes/Cm. (Oil) 2. (Oil and Askarel) 26 kV (Oil) 30 kV (Askarel) Examination. (Askarel) 0. (Askarel) 1.1400 Electrical Checkout. 1424 Protective Device Testing Protective devices should be tested for both acceptance and maintenance purposes. they should be either reconditioned or replaced. Fig. Figure 1400-1 lists the tests most commonly performed. The extent and frequency of testing required is dependent on the type of device and September 1990 1400-6 Chevron Corporation . Field Should not be cloudy.8% Max. When tests indicate that insulating liquids have deteriorated. Sometimes. 1425 Impedance and Resistance Measurements Contact Resistance Testing The 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. Contact resistance testing normally should be performed on large. Trip circuits should be disabled if the relay is left in its case to prevent operation of other trip circuit devices. Circuit breaker time-travel analyses should be performed to ensure that the operating mechanisms of medium voltage breakers function properly.volt test voltage source. Grounding electrode to earth resistance usually is measured with a ground resistance test set. Otherwise. 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. Protective relays should be calibrated and tested during equipment commissioning and every two to three years thereafter. the contacts should be replaced. equipment commissioning and equipment maintenance. Protective relays normally are tested by injection of secondary currents and voltages. If contact resistance is greater than 250 microhms. This test must be performed by personnel familiar with the appropriate equipment. the total impedance to earth from any point which is intentionally grounded. In addition. Instruments are available which measure the impedance of the complete equipment ground current loop or just the grounding path. should be less than one ohm. Overloads in motor starters should be checked for correct sizing during commissioning. Commissioning. Ground System Impedance Testing Installation and maintenance for a low impedance equipment ground system is very important. lowvoltage and medium-voltage breakers and switches. The manufacturer’s recommendations should be followed (as a minimum). a large current source and/or high voltage source must be applied on the primary side of the transformers.Electrical Manual 1400 Electrical Checkout. which makes the testing considerably more difficult. it is desirable to test relays with their corresponding instrument transformers. and Maintenance the installation. Ground system impedance testing should be performed during facility commissioning and maintenance testing. Maintaining a low resistance from grounding electrodes to earth is also important. Generally. Ground fault and differential relays installed with zero sequence current transformers normally should be tested using primary injection to ensure predictable performance of the relay/CT combination. visual inspection of the ground system should be an ongoing Chevron Corporation 1400-7 September 1990 . This test is applicable to equipment field testing. a DC current may be passed through the contacts and the resultant millivolt drop measured. In this case. protective devices should be thoroughly inspected and tested following their interruption of fault level currents. Fuses generally are not tested (except for continuity). A test set with a direct readout in microhms may be used. or the readings can be incorrect. Circuit breaker and switch testing should also be performed. In addition to acceptance and routine testing. Prepare to investigate cause by internal inspection. this amount can increase by a factor of 20 to 30. Commissioning. 2. but it is normally more cost effective to have it done by outside contractors. a contractor will perform a more thorough inspection. Adequate results will be achieved if the equipment being tested is carrying at least 40% of the rated current.0 Over 5.0 September 1990 1400-8 Chevron Corporation . Make tests at regularly scheduled intervals. Remove transformer from service and conduct internal inspection. and Maintenance Electrical Manual activity to ensure that connections are tight and grounding conductors are undamaged.0 Evaluation No Reason for concern. 1427 Transformer Fault-Gas Analysis The analysis which determines the percentage of combustible gases present in the nitrogen cap of sealed and pressurized oil-filled transformers can provide information regarding the likelihood of an impending fault. Begin more frequent readings immediately. If a problem develops. Combustible gases are produced by arcing or excessive heating below the transformer oil level. Infrared inspections should be performed whenever hot spots are suspected. Various types of infrared “guns” are available for performing this type of inspection. Recommended Practice for Electrical Equipment Maintenance. Make more frequent readings and watch trend. A special test set (with a readout in percent of combustible gas) should be used to analyze a sample of the transformer’s nitrogen. 1426 Infrared Inspection Infrared inspections are performed on operating electrical equipment to detect elevated temperatures or hot spots.0 1. Figure 1400-2 provides an evaluation of fault-gas analysis test results. Normally.0 to 1. Percentage of Combustible Gas 0.5% combustible gases.1400 Electrical Checkout. Fig. See note on page 1400-1. The work may be performed in-house. Hot spots can be caused by both bad connections or overloaded equipment. 1400-2 Fault-Gas Analysis Evaluation Courtesy of NFPA 70B. Typically.0 to 5. Early detection of these hot spots can help prevent equipment deterioration which could result in failure or plant shutdown. Indication of contamination or slight incipient fault.0 to 2. the nitrogen will contain less than 0. Voltage levels. minimize damage to equipment and property. and Maintenance 1428 Functional Testing Prior to placing any equipment or system in service. NEMA. 1440 System Check-Out and Commissioning It is critical that a facility be completely checked and tested prior to energization. The functional test should closely simulate actual operating conditions. Chevron Corporation 1400-9 September 1990 . and minimize the possibility of injury to personnel. and operational testing should be conducted at the manufacturer’s plant. In general. Commissioning. motors and generators should be performance tested at the manufacturer’s plant and during field start-up. Generally. Usually. testing requirements should be based on industry standards (such as those published by IEEE. 1430 Factory Testing A comprehensive check-out and testing program at the manufacturer’s plant of any new or refurbished electrical equipment is critical. and automatic transfer schemes. acceptance testing following plant commissioning. except the power busses should not be energized. Functional testing should be performed during factory tests and when commissioning new or reconditioned electrical facilities. protective device testing. visual inspection. All maintenance programs should include tracking of equipment operating conditions. resistance measurements. This will also minimize unexpected shutdowns and increase run time. Functional testing should include verifying the proper operation of all protective devices. Operational testing is applicable to all phases of a facility’s life. it should be given a complete functional test. Specification ELC-MS-4744. a series of operational tests should be conducted. and other operating conditions must be verified for the entire power distribution system. Inspection and testing checklists are included with this specification.Electrical Manual 1400 Electrical Checkout. this involves comparing the performance of the equipment or system against design criteria. functional testing. The commented version identifies how the document can be tailored to meet particular needs. Company specifications in Section 2000 provide recommended factory tests for various equipment. control circuits. and monitoring operating conditions as part of the maintenance program. “Electrical Systems Check-out and Commissioning” is a comprehensive inspection and testing program. Mechanical and electrical performance data are compared against design tolerances. Factory testing requirements should be included with the purchase order documents. ANSI. 1429 Operational Testing After the start-up of new equipment or systems. and API). For example. This will allow for a smooth start-up. real and reactive power flows. insulation testing. Operational testing includes factory testing of equipment. interlocks. 1461 Model Specifications (MS) *ELC-MS-2469 *ELC-MS-4744 *DRI-EG-3547 DC High Potential Testing Medium Voltage Cable and Electrical Equipment Electrical Systems Checkout and Commissioning Inspection and Testing of Large Motors and Electrical Generators 1462 Standard Drawings There are no Standard Drawings in this section. and ensuring that manufacturers’ storage requirements are met. NFPA 70B. Commissioning. If not. The benefits of an EPM program include measurable results (such as reduced repair costs and shutdown time. “Recommended Practice for Electrical Equipment Maintenance. September 1990 1400-10 Chevron Corporation . Those marked with an asterisk(*) are included in this manual or are available in other manuals. Typical activities to include in this program are: protecting equipment from the environment. A suitable comprehensive Electrical Preventive Maintenance (EPM) program needs to be established during the construction phase. The resulting designs should reflect maintenance and operating requirements. major equipment must be maintained in accordance with manufacturers’ guidelines. and Maintenance Electrical Manual 1450 Maintenance Maintenance of an electrical facility and the required spare parts should be considered during the design phase of a project. the preventive maintenance program should be expanded. Another reference source is Westinghouse’s four-volume set “Electrical Maintenance Hints. As soon as a facility is placed in service.” 1460 References The following references are readily available. During the construction phase of a project. A preventive maintenance program for storing equipment should be in place prior to the receipt of any items. rotating the shafts of motors and generators.” provides a comprehensive guide for establishing an effective EPM program. the warranty may be nullified. Plant operating personnel should be consulted for preferred system configurations and existing maintenance procedures. Included in this reference are sample record sheets which may be used to record inspections.1400 Electrical Checkout. checking the charge on activated storage batteries.) Another less tangible benefit is improved productivity resulting from a safer workplace. and maintenance actions taken. ensuring that space heaters are energized. test data. National Electrical Safety Code ANSI/IEEE C57. Chapter XIV—Electrical Systems API RP 14F Design and Installation of Electrical Systems for Offshore Production Platforms ASTM D-877. Guide for Field Testing of Relaying Current Transformers API Guide for Inspection.Direct-Voltage Tests on Power Cable Systems in Field ANSI/NFPA 70. IEEE Guide for Measuring Earth Resistivity. Data Guide (DG) and Engineering Forms (EF) *ELC-EF-645 High Potential Test Record Sheet 1464 Other References ANSI C2. IEEE Standard Test Code for Resistance Measurement IEEE Standard 120.1. Test Method for Dielectric Breakdown Voltage of Insulating Oils From Petroleum Origin Using VDE Electrodes ANSI/IEEE Standard 4. Commissioning. and Earth Surface Potentials of a Ground System IEEE Standard 118. (Electrical Equipment Testing and Maintenance) Westinghouse (Electrical Maintenance Hints) Chevron Corporation 1400-11 September 1990 . and Maintenance 1463 Data Sheet (DS). Guide for Making High. Electrical Equipment Maintenance Gill. IEEE Guide for Acceptance and Maintenance of Insulating Oil in Equipment ANSI/IEEE Standard 81.S.13.Electrical Manual 1400 Electrical Checkout. Ground Impedance. Techniques for High Voltage Testing IEEE Standard 51. Master Test Code for Electrical Measurements in Power Circuits ANSI/IEEE Standard 400. Test Method for Dielectric Breakdown Voltage of Insulating Liquids Using Disk Electrodes ASTM D-1816. IEEE Guide for Field Testing Power Apparatus Insulation IEEE Standard 64. IEEE Guiding Principles for Dielectric Tests IEEE Standard 62. National Electrical Code ANSI/NFPA 70B. A. It covers basic theory of drives. Contents 1510 Background & Selecting Drive Applications 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 1521 Systems Integration 1522 Front-End Engineering 1523 Specifying Equipment 1530 Applying Low Voltage Drives 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 1500-24 1500-17 Page 1500-3 Chevron Corporation 1500-1 May 1996 . commissioning and maintaining drives is covered. Also discussed are the steps involved with selecting and installing drives. Specific studies. Finally.1500 Adjustable Speed Drives Abstract This section discusses the application of low voltage (LV) and medium voltage (MV) adjustable speed drives. like rotor dynamic and harmonic analysis are also briefly described. when to apply an adjustable speed drive and the economic benefits of drives. testing. 1500 Adjustable Speed Drives Electrical Manual 1537 Reliability 1538 Motor Considerations 1539 Drive Retrofit Applications 1540 Applying Medium Voltage Drives 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 1551 Effects on the Drive 1552 Effects on Other Equipment 1553 Harmonic Analysis 1560 Rotordynamic Studies 1561 Lateral Critical Speed Analysis 1562 Torsional Analysis 1563 Pulsation and Structural Resonance Analysis 1570 Miscellaneous Information 1571 System Testing 1572 Commissioning and Startup 1573 Training 1574 Maintenance and Spare Parts 1500-66 1500-59 1500-54 1500-38 May 1996 1500-2 Chevron Corporation . To maintain the desired V/Hz ratio. The relationship between motor speed. applied on the DC section. the speed can be adjusted by changing the power frequency.e. Figure 1500-1 shows a block diagram of a typical ASD. Then filtering (either an inductor or capacitor). the inverter output voltage is normally adjusted proportionally with frequency. Since speed is directly proportional to the frequency. Fig. thereby keeping the motor magnetic field within design limits and providing the required performance characteristics.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. i. the number of magnetic poles. First. power frequency. Inverter output filters may also be used. an ASD rectifier (or line converter) converts the 60 Hz AC power to DC power. or provide reactive power necessary for operation of the drive.. RPM = 120f/P (Eq. smoothes the DC ripple and helps decouple the rectifier and inverter sections. to reduce the harmonic distortion of the output voltage to levels acceptable for the motor. The inverter (or machine converter) changes the DC power back to AC at the frequency needed to obtain the desired motor speed. 1500-1 Basic ASD Block Diagram ‘ Chevron Corporation 1500-3 May 1996 . 1500-1) where: f = frequency in Hertz P = number of magnetic poles For example. This speed is established by the frequency of the power source connected to the stator and the design of the motor. and number of poles is given by Equation 1500-1. This is accomplished using power electronics by supplying the motor from a frequency converter known as an adjustable speed drive (ASD). from Equation 1500-1 the speed of a two-pole motor on a 60 Hz power system is 3600 RPM. because they can not be used to control the voltage amplitude or frequency in a power converter output. such as diodes. are shown in Figure 1500-2. For a rectifier SCR. Once forward biased. Each device is described below. 1500-2 Commonly Used Solid State Switching Devices for Power Converters. 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. Diodes Diodes are the simplest and most reliable switching devices which are commonly used in the rectifier section of an ASD. The sequential switching of these devices is known as commutation. However. i. load commutation. only a momentary trigger signal to the gate is required to turn the device on and cause it to conduct.e. However. this device must wait for the next current zero to naturally turn off after the gating signal is removed. and symbols for commonly used devices. or thyristors. These devices switch in a programmed sequence and time to fabricate the required voltage and current waveforms. 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). that the device is turned on is selected by the control system to provide the voltage or frequency output desired. transistors. on the waveform.. Courtesy of Toshiba International. There is May 1996 1500-4 Chevron Corporation .1500 Adjustable Speed Drives Electrical Manual 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. these devices are uncontrolled in that they can not be switched on or off at any desired point with respect to the voltage waveform. 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. Fig. The time. Thus. their use is limited. 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. and pulse width modulated (PWM) inverter as shown by Figures 1500-4. smaller overall drive physical size. Chevron Corporation 1500-5 May 1996 . 1512 Low Voltage Induction Motor ASDs Low voltage (LV) drives are typically used with motors up to approximately 1000 HP. or a turn-off signal is applied to the gate. and improved drive output characteristics. making them suitable for pulse width modulated control (discussed later). For now (1996). 1500-5. Transistors Transistors have the advantage of being switched on or off very rapidly and are commonly used in low voltage (460V or 575V) ASDs. Twelve-pulse and higher bridge configurations are common for larger horsepower drives. Conduction will continue until current falls to zero. IGBTs provide faster switching frequencies (2 . bridge cells can be connected in series to provide the necessary output voltage (See Section 1513. a GTO gate signal need only be triggered momentarily to turn the device on. Three basic types of low voltage induction motor ASDs are in use today. Harmonics will be discussed in more detail in Section 1550.Electrical Manual 1500 Adjustable Speed Drives no other way to turn it off. but today are commonly used in large medium-voltage induction and synchronous motor drives. Alternatively. However. insulated gate bipolar transistors (IGBTs) have evolved and become the device of choice. 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. Compared to BJTs (1 . Like an SCR. These devices are normally used in the machine converter of large medium voltage induction-motor drives as an alternative to load commutation using conventional thyristors mentioned above. Harmony® Power Cell drive).2 kHz switching frequencies).20 kHz). Since the late 1960s bipolar junction transistors (BJTs) have been used for low voltage induction motor ASDs. A GTO can be switched on and off at high frequencies. and 1500-6. The six thyristors in the rectifier or in the inverter each complete one switching sequence for each cycle of power frequency. GTO Thyristors The gate turn-off (GTO) thyristor has the added feature of a controlled (or forced) turn-off. current source inverter (CSI). These devices can be used in all sizes of ASDs. However. in the past couple of years. The higher pulse number offers the advantage of lower harmonic distortion to minimize effects on the electrical system and the motor. the voltage ratings available are not high enough for medium voltage ASD applications unless transformers are used to provide acceptable (output) voltage levels. lower gating power requirements. some manufacturers are building LV drives up to 2500 HP. These types are variable voltage inverter (VVI). Above about 500 HP an output transformer and a medium-voltage motor are normally used with the LV drive. which can be more economic than a medium-voltage drive. giving a total of six pulses every cycle and hence the designation as a six-pulse drive. VVI and CSI-type drives have virtually disappeared from the marketplace for new drive applications below 600VAC input. 1500-5 Current Source Inverter Drive.1500 Adjustable Speed Drives Electrical Manual respectively. 1500-4 Variable Voltage Inverter Drive. Courtesy of Toshiba International. Fig. May 1996 1500-6 Chevron Corporation . Fig. 1500-3 Typical Six-Pulse ASD Configuration Fig. Courtesy of Toshiba International. High speed (super synchronous) drives have been applied up to 11.000 HP and high speed drives up to 3. the HP size that can be applied decreases.000 rpm. Notice in Figure 1500-6 the output voltage is a square wave formed by individual pulses. and the stored capacitive charge helps maintain a stable DC voltage. In this case. 1500-6 Pulse Width Modulated Drive. 1513 Medium Voltage Induction Motor ASDs Medium voltage induction motor drives range in sizes from 400 HP to 15. which also helps maintain a stable voltage.000 rpm. The VVI drive uses a thyristor-controlled (phase-delayed) rectifier to convert AC to a variable DC voltage. Courtesy of Toshiba International. also an inductor). The Company has applied conventional speed (up to 3600 rpm) induction-motor drives up to 10.Electrical Manual 1500 Adjustable Speed Drives Fig. The DC is filtered by a capacitor. 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. Also. The pulse width is varied to produce the required voltage magnitude. IGBTs are used. A transistorcontrolled inverter changes the DC voltage to AC.500 HP and 11. The DC current is converted to an AC current at the required frequency by a thyristorcontrolled inverter. due to rotor fabrication limits.000 HP. The DC ripple is smoothed by an inductor. and the stored energy from the inductor helps maintain a stable DC current. As with the VVI drive. The CSI drive also uses a thyristor-controlled rectifier to convert the AC voltage to a variable DC voltage (and current). the DC voltage is filtered with a capacitor (and with some manufacturers. As the speed of the drive increases. A thyristor controlled inverter converts the DC voltage to an AC voltage at the required frequency. notice the current is nearly sinusoidal compared to the VVI and CSI drives in Figures 1500-4 and 1500-5. Chevron Corporation 1500-7 May 1996 . which reduces harmonic distortion. and 8 cells for 6600V. Each cell is a static PWM power converter. In this case. The inverter output filter capacitor. The input transformer is a multi-winding transformer. 5 cells for 4160V. DC bus capacitors. 3 cells for 2300V. The load commutated inverter induction motor (LCI IM) drive is shown in Figure 1500-7. a large capacitor is not necessary for load commutation because the GTO thyristors can be completely controlled and switched on and off as required. The Harmony® Power Cell drive topology is shown in Figure 1500-9. Courtesy of Ansaldo Ross Hill. so the output converter never has to block against output voltage. i. This is a current-source drive. similar to the low voltage drive described above. 50/60Hz and delivering that power to a single-phase output. and uses a thyristor controlled rectifier and inverter. This ASD normally functions as a PWM-type drive. The GTO induction motor drive can use several configurations. except the output is single phase instead of 3 phase. with the appropriate phase shift to May 1996 1500-8 Chevron Corporation . and the Harmony® Power Cell drive. the GTO drive. and a single-phase inverter using IGBT switching devices. 3 phase. 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. capable of receiving input power at 480VAC. 1500-7 Load Commutated Inverter Induction Motor Drive. but at a lower switching frequency. A typical power cell is shown in Figure 1500-10. Each cell consists of a 6-pulse diode rectifier.. (The Power Cell is identical to a 480V PWM-type ASD. A large capacitor is installed on the inverter output to provide the leading power factor necessary for load commutation. either as a voltagesource or a current-source drive.e. is much smaller than the one required for the LCI induction motor drive. Fig.1500 Adjustable Speed Drives Electrical Manual Three basic types of medium-voltage ASDs are in common use today: the LCI IM drive. The DC link reactors smooth the DC ripple.) All inverters of each cell are continuously conducting. The output of the power cells are connected in series to provide the necessary output voltage. A forced commutation scheme (rectifier commutated 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. Used with permission from IEEE 95-CH 35840-b/95/0000-0231. Used with permission from IEEE Paper No. 1500-8 GTO Induction Motor Drive. ©1987 IEEE. ©1995 IEEE. Fig.Electrical Manual 1500 Adjustable Speed Drives Fig. Chevron Corporation 1500-9 May 1996 . PCIC-87-45. 1500-9 Harmony® Power Cell Drive Topology. A forced commutation scheme. 6. so that the primary currents are nearly sinusoidal. similar to the LCI IM drive. which is different from the conventional 6. The rectifier and inverter are thyristor controlled.or 12-Pulse PWM controllers. The synchronous-motor drive in common use today is the LCI type (Figure 1500-11).000 HP and 5. The net effect is the 3-cell.000 rpm. typically 10.000 HP and up to 50. 4160V drive is equivalent to a 30pulse drive and the 8-cell. 2300V drive is equivalent to an 18-pulse drive.000 HP and 6.000+ HP. is used to start the drive and bring it up to a minimum speed where sufficient motor voltage is developed for load commutation. The Company has applied synchronousmotor LCI drives up to 15. the 5-cell. cancel most of the harmonic currents drawn by the power cells. The May 1996 1500-10 Chevron Corporation .600V drive is equivalent to a 48-pulse drive. 1514 Synchronous Motor ASD Synchronous-motor drives are normally used for very large motors. 1500-10 Schematic of a Power Cell. Diodes are used on the line converter and IGBTs on the output single-phase bridge. The PWM control of each cell per phase is synchronized with the other cells to provide synchronized 3-phase conduction. The power cells all receive commands from one central controller.000 rpm. Courtesy of Robicon. High speed synchronous-motor drives have been applied up to 50. The motor field excitation is supplied from a thyristor-controlled exciter to provide a leading power factor which is required for load commutation.1500 Adjustable Speed Drives Electrical Manual Fig. Electrical Manual 1500 Adjustable Speed Drives exciter control is turned on at start to provide field excitation even at zero speed. It works very well for most applications within the Company such as pumps. This more complex drive-control scheme allows independent control of the motor Volts/Hertz and torque producing Chevron Corporation 1500-11 May 1996 . and fans which require fast (but not instantaneous) response times for speed changes. which means rated torque is available at any speed. Fig. This technique has been used for many years in both synchronous and induction motor drives. at nameplate value: 460V/60Hz = 7. 1500-12 Typical Volts/Hertz Control Block Diagram. 1500-11 Synchronous Motor Drive. A relatively new control method for induction motors now gaining wide use is the Flux-vector Control Scheme (Figure 1500-13). so the motor is always synchronized with the machine converter. In this scheme both the frequency and strength of the motor magnetic field are established with a single speed input command. for a 460V motor. Courtesy of Ansaldo Ross Hill. 1515 Control Methods A common control strategy for ASDs uses a Volts/Hertz scheme to control speed and torque (see Figure 1500-12). Maintaining a constant V/Hz ratio (for example. Speed regulation (for most drives) is better than 1 percent for the full operating speed range.66 V/Hz) produces a constant value of magnetic field strength in the motor. Courtesy of Reliance Electric. compressors. even during startup. Fig. always improves the speed regulation (0. making the installation less complex. valve pockets. Flux-vector control provides very accurate speed regulation. Control of key process variables. recycle control with control valves and recycle coolers. soft start. Flux-vector control technology is a good option for those applications requiring very accurate speed control. Adjusting the speed of a pump.01 percent). with open-loop control. or other equipment is a more efficient way of controlling flow compared to control valves. with rotor position feedback. or flow rate. starting torque. etc.1500 Adjustable Speed Drives Electrical Manual current. Open-loop control is also preferred for retrofit applications. reduced maintenance costs. such as inlet pressure. or other forms of volume control such as cylinder unloaders. since no tachometer feedback signal is required. This is normally the predominant reason for applying an ASD. low-speed high torque output. dampers. and improved process control and enhancements (described below). Courtesy of Reliance Electric. Speed regulation. Both open-loop and closed-loop (requiring tachometer or rotor position reference feedback) schemes are available. The openloop flux-vector control scheme is preferred for applications where incremental improvement in speed regulation. fast response and constant or high torque loads. and zerospeed (starting) torque relative to open-loop (encoderless) drive control. 1516 When To Apply An ASD ASDs can offer several benefits over fixed speed motors: reduced power consumption. fan. 1500-13 Flux Vector Control Scheme Block Diagram. becomes a viable alternative to discharge flow throttling. Closed-loop control. Fig. and excellent torque control. torque-response damping. etc. compressor. and dynamic response is preferred over the traditional V/Hz.1 percent. high dynamic response. Maintenance costs are typically lower for an ASD than for May 1996 1500-12 Chevron Corporation . is 0. especially at lower speeds. ASDs can be an option to gas or steam turbines where emissions are a concern or steam is in short supply. centrifugal pumps. Also. recycle centrifugal compressors. CCR uses a rule-of-thumb that 50 percent of their processes have the potential for ASDs. Styrene plants offer many constant torque ASD applications for reactor feed pumps. 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). vapor recovery rotary compressors. reflux pumps and cooling tower fans. Process enhancements. pulsation dampening systems may be necessary to accommodate the range of pressure pulsation frequencies. condenser fans. For constant torque applications. See Section 1560 for more details on pulsation analysis. Each application must be reviewed individually to determine if an ASD makes sense. agitators and compressors. because the motor current is near rated. a motor designed for the application is required. This may include an externally mounted fan to provide motor cooling at low speeds. Some typical applications which should be considered are feed pumps. if the required flow varies. positive displacement pumps. There are some constant torque applications such as conveyors. the more cost effective an ASD will be. and agitators. pelleters. if very slow speeds are required. Use of ASD with Electric Motor It is difficult to generalize when an ASD with an electric motor should be used. where frequently started fixed speed motors are applied. Most ASD applications within the Company are centrifugal loads such as pumps. Reciprocating compressors are also becoming candidates for ASDs. but the cooling air flow from the shaft mounted fans is reduced in proportion to speed. Chevron Corporation 1500-13 May 1996 . The ASD can also provide fast and accurate responses to changes in flow requirements giving optimum process control. 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. due to ASD control flexibility have far exceeded power savings. and oil pumping jack units). and fans. Most motor manufacturers have retrofit kits for installing externally mounted fans. Company Experience Chevron 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. reciprocating compressors. special precautions for motor cooling must be taken when operating at low speeds. compressors. However. Process enhancements have included turndown as well as supersynchronous speed capability as the various processes have required more throughput.Electrical Manual 1500 Adjustable Speed Drives mechanical flow control devices. For drives applied to reciprocating-type driven equipment. an ASD should be considered. The greater the variation in flow requirements and the longer the duration of reduced flow. In these applications. refrigeration compressors. The affinity laws given in Figure 1500-16 describe the behavior of centrifugal loads. However. 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. which limits. External blowers may be necessary to stay within stator winding and bearing temperature limits. or cooling tower fans. Figure 1500-15 shows a typical pump system with flow controlled by an ASD. or in extreme cases prohibits. Constant torque loads. A simple example will demonstrate how the use of an ASD rather than mechanical means to control flow will save energy costs. and other mechanical handling equipment. which are becoming more common in process applications. However. May 1996 1500-14 Chevron Corporation . In practice. Notice the flow varies directly with speed and head (pressure) as the square of the speed. Positive Displacement Machinery. including reciprocating and screw pumps and compressors.1500 Adjustable Speed Drives Electrical Manual Most Common Uses for ASDs The following is a general guide for the most common ASD applications: Centrifugal Machinery. feed pumps and compressors usually operate in systems with a high static head component. but it is an emerging technology. the ASD is an ideal match. For applications where the system resistance is mainly dynamic (or frictional). such as recycle pumps and compressors. Axial compressors. which can provide substantial energy savings. This may result in portions of the speed range becoming unavailable for steady state operation due to potentially damaging resonances. motor torque may be limited by available cooling if the cooling fan is output shaft driven. variable speed control. Mechanical Handling. except that blade vibration analysis must take into account torque harmonics. at lower speeds. Positive displacement machinery. The advice and counsel of a specialist is recommended for these applications. Centrifugal pumps and compressors are ideal applications. 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. such as conveyors. Reducing the speed to 60 percent reduces the flow to 60 percent and the power input to 21. Figure 1500-14 shows a simplified fixed speed pump system with flow adjusted by control valves. are similar to centrifugals in their general characteristics. However. They are also not familiar with applying the affinity laws for centrifugal equipment as applied with ASDs.6 percent of normal. while the power varies as the cube of the speed. controlled by ASDs may offer some attractive control advantages. 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. 1517 Economics In general. these engineers are often not familiar with benefits or the practical aspects of adjustable speed drives. 1500-14 Simplified Fixed Speed Pump System Using Control Valves Fig.Electrical Manual 1500 Adjustable Speed Drives Fig. 1500-15 Typical ASD Controlled Pump System Chevron Corporation 1500-15 May 1996 . The output reduces to 22. the better the payout.1500 Adjustable Speed Drives Electrical Manual However. 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. As the flow requirements decrease.5 HP when the flow is reduced to 70 percent of rated by adjusting the control valve. an ASD will save sufficient energy to have an adequate payout period.127 per year if the pump operates full time at 70 percent flow. 1500-16 Affinity Laws for Centrifugal Equipment 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 relatively low static head. At seven cents per KWH this saves $3. the savings with an ASD increase.7 HP for a net reduction of 6. Fig. If the pump runs near 100 percent of rated flow most of the time. May 1996 1500-16 Chevron Corporation . but continue to be substantial at reduced flow in either case. If the pump runs at reduced flow a majority of the time.1 KW over the control valve case. The motor output is 25 HP with the pump at normal flow. The higher the HP application. an ASD is probably not justified. since the drive cost per HP decreases as the size increases. The payout time is roughly three years for this example. If the flow is reduced to 70 percent by adjusting the speed with an ASD. The energy savings with an ASD are less if the system has a relatively high static head. The estimated installed cost for the ASD is $9000.8 HP or 5. the motor output is 15. 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. . the HP size.Electrical Manual 1500 Adjustable Speed Drives Fig.g. which can substantially reduce the payout time. and associated equipment (if required). transient overvoltage or voltage sags that can result in nuisance trips of the drive. 1500-17 Power Consumption of a Pump with Flow Regulated by a Control Valve versus an ASD The actual payout for a potential ASD application can vary significantly. The payout for this example is longer than many applications. Consideration must be given to conditions that the electrical system imposes on the drive. the local electric utility may offer rebates for installing energy efficient equipment. because the relatively high static head increases the energy requirements as previously discussed. 1520 Applying (Specifying and Installing) Drives The 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. and integrating the drive and motor into the existing electrical distribution system. e. 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. depending on the system parameters. motor. and the cost of power. A properly integrated system is imperative for successful and reliable operation of the drive and electrical system. Applications with payouts of one to two years or less are reported by some users. the load profile (percent of normal flow versus time). Finally. The drive generates harmonics which can affect reliable operation of other electrical equipment on Chevron Corporation 1500-17 May 1996 . Engineering firms will usually copy the previous. Unfortunately.1500 Adjustable Speed Drives Electrical Manual 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. few engineering firms have the necessary experience in applying drives. Careful review of their design and prompting the engineer to consider new ideas. May 1996 1500-18 Chevron Corporation . usually from conception through startup and commissioning. features and improvements is often necessary to get the full benefit of the drive. successful design even though conditions may be different or real improvements and optimizations could enhance the new application. Systems integration is best done by a consultant specializing in the ASD business. A systems integrator needs to be experienced 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. Fig. 1500-18 Example Pump Performance with Flow Reduced by a Control Valve 1521 Systems Integration Systems integration is the function of coordinating the project. Most engineering. qualified engineers who perform this function. Many installations use a hybrid approach to systems integration. some of the steps described in Figure 1500-20 are not appropriate. there may be preventable incidents. equipment failures or process upsets during the first year (or more) of operation. Chevron Corporation 1500-19 May 1996 . The steps in systems integration are shown in Figure 1500-20. If the job is done well. Depending upon the size of the ASD application. No matter how it is accomplished. The harmonic and rotordynamic studies require particular expertise and should only be performed by qualified engineering firms that specialize in these fields. systems integration will occur. Figure 1500-21 takes the system integration steps and provides guidance in using the steps for low voltage and medium voltage applications. 1500-19 Example Pump Performance with Flow Reduced by an ASD Some facilities that have applied many drives have built up their own expertise and have their own engineers that do the systems integration.Electrical Manual 1500 Adjustable Speed Drives Fig. The level of effort for each step will depend on the size of the drive and the critical nature or complexity of the application. the ASD system will be nicely integrated. procurement and construction (EPC) contractors have few. If not. in which multiple people perform parts of the process. if any. 1500 Adjustable Speed Drives Electrical Manual Fig. 1500-20 Systems Integration Steps (1 of 2) 1 1a. 1b. 2 3 4 Define operation parameters of the driven equipment (study hydraulic parameters of system and pump to determine HP size and speed range). Determine the economic benefits for applying the ASD. Develop a process control strategy for controlling the speed of the driven equipment and integrate process or equipment safeguards into the drive control logic. Determine (by field verification) baseline harmonic distortion levels (both voltage and current) on the electrical system and establish acceptance criteria for the drive application. Develop a conceptual electrical system design by using a one line diagram to determine compatibility with the existing electrical system and for further economic evaluation. The one line diagram should include: • • • • drive configuration equipment sizes cable lengths wireway method 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 • 5b. other harmonic generators such as other drives and UPSs 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. 5 5a. 6 7 Prepare equipment specifications and data sheets for the drive, motors, and all associated equipment (transformers, filters, circuit breakers, contactors, etc.) 7a. 7b. Analyze lateral and torsional rotordynamics of the rotating system assembly (motor, driven equipment, coupling, and gear box), discussed in Section 1560. 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. May 1996 1500-20 Chevron Corporation Electrical Manual 1500 Adjustable Speed Drives Fig. 1500-20 Systems Integration Steps (2 of 2) 9 Perform detail engineering of the complete system including: • • • • 10 11 12 13 drive electrical system driven equipment process control 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). Witness factory testing of the drive and motor. Provide for training of the plant operating, maintenance, and technical personnel. 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. Determine torsional effects by metering the coupling of the installed system during system commissioning. 15 Fig. 1500-21 Systems Integration Steps for LV and MV Applications (1 of 2) Activity 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 Develop an impedance diagram and perform a harmonic analysis LV Application    MV Application    ≥ 250 hp For applications, where harmonicproducing loads are ≥ 1/5 the size of the substation or on systems with pf correction capacitors  (This step can be streamlined through a supplier alliance) ≥ 500 hp For critical applications  Prepare equipment specification and data sheets Perform a lateral and torsional rotordynamic analysis Perform a reliability review study  ≥ 500 hp For critical applications Chevron Corporation 1500-21 May 1996 1500 Adjustable Speed Drives Electrical Manual Fig. 1500-21 Systems Integration Steps for LV and MV Applications (2 of 2) Activity Perform detail engineering LV Application  (This step can be streamlined through a supplier alliance)  (Spare parts inventory can be reduced through a supplier alliance) For critical applications and ≥ 500 hp (considered by some as the most important implementation step  (critical to the success of using drives in the plant)  For applications, where harmonicproducing loads are ≥ 1/5 the size of the substation or on systems with pf correction capacitors Not applicable MV Application  Develop a spare parts list  Witness factory testing of the drive and motor Provide for training of plant operating, maintenance and technical personnel Prepare a startup, commissioning and system testing plan Measure harmonics (field measurements) of the system after the drive is in service Determine torsional effects by metering the coupling during commissioning  = Activity applies to this application.    If the factory tests indicate a potential resonance problem 1522 Front-End Engineering Regardless of the size of the drive application, a certain amount of preliminary engineering 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 computersimulated harmonic analysis is necessary to estimate the voltage harmonic distortion on the system, produced by the drive. For simple or small horsepower applications, 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 onefifth 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. May 1996 1500-22 Chevron Corporation Electrical Manual 1500 Adjustable Speed Drives 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 manufacturer. Rotordynamic studies are discussed in more detail in Section 1560. 1523 Specifying Equipment Specifications 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 applications, 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 modifications 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. Chevron Corporation 1500-23 May 1996 1500 Adjustable Speed Drives Electrical Manual Fig. 1500-22 Typical Drive Voltage and HP Ratings Drive Voltage 460 and 575 460 and 575 with Input & Output Transformers 2,400 4,160 6,900 13,800 HP Range up to 650 600 - 2,500 650 - 5,000 650 - 20,000 10,000 - 30,000 25,000 - 50,000+ 1530 Applying Low Voltage Drives Most 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 manufacturers 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 Drives LV 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 squarefunction 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 algorithm, 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 May 1996 1500-24 Chevron Corporation Electrical Manual 1500 Adjustable Speed Drives 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 Specification ELC-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 specification 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 manufacturer, 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 components (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 (inverterduty motor, winding insulation voltage rating, temperature rise, insulated bearings, 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), • • • • • • Chevron Corporation 1500-25 May 1996 1500 Adjustable Speed Drives Electrical Manual • • Driven equipment requirements: speed/torque requirements (constant or variable), 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 Considerations Drive 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 Section LV 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 Protection All 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 ÷ 2 = 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- May 1996 1500-26 Chevron Corporation Electrical Manual 1500 Adjustable Speed Drives 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-Through Other considerations for the input (rectifier section) are undervoltage (UV) ridethrough 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 ridethrough 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 drivestartup provision is a standard drive feature, and can allow for a programmed DCS or PLC staggered startup of multiple machines if desired. Harmonic Reduction A computer-simulated harmonic analysis is necessary to estimate the voltage harmonic distortion on the system, produced by the drive. For simple or small horsepower 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 evaluating the need for harmonic mitigation (filter), if necessary to meet the acceptance criteria. Protection from Input Line Transients Metal 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, Chevron Corporation 1500-27 May 1996 1500 Adjustable Speed Drives Electrical Manual 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 Rating The 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 modulation 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 carefully selected and completely verified during system commissioning. Undervoltage ride-through should be carefully set up. The limitations of the undervoltage ridethrough of the logic control should also be understood and carefully applied and tested. 1536 Inverter and Output Section LV 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 semiconductor switching devices. Carrier frequencies of IGBT can exceed 20 kHz. The May 1996 1500-28 Chevron Corporation Electrical Manual 1500 Adjustable Speed Drives 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 rectifier 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 2 x 480Vac = 680Vdc. The drive provides motor branch circuit and motor overload and short circuit protection. 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 protection 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 microsecond 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 manufacturer. 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 magnitude 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- Chevron Corporation 1500-29 May 1996 1500 Adjustable Speed Drives Electrical Manual 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 autoignition 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 thickness 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 Reliability Many 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. May 1996 1500-30 Chevron Corporation Electrical Manual 1500 Adjustable Speed Drives Fig. 1500-23 Recommended Drive Ratings and Features for 460V Class Drives SECTION Component or Feature Diode or SCR Power Switching Devices Recommended Rating or Setting 1600VPEAK Comments 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 significantly increased by using the recommended voltage rating for the switching devices. All drives have this feature, however improper settings often defeat or disable its effectiveness. Ensure the settings are properly programmed and test the ride-through during commissioning. 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 temperature and current margins and can cause motor shaft currents and bearing failures. For drives supplied from a high resistance ground source. Cable characteristic impedance and dv/dt characteristic of IGBTs can cause high magnitude output voltages at motor terminals and result in winding failure. Dual input option, or UPS for critical systems Test undervoltage ride-through Redundant fans or sufficient temperaturecooling margins should exist to allow for continuous drive operation with one fan failure. A fan failure should initiate an alarm. Components should be selected that are applied at no more than 75% of the component rating. RECTIFIER Undervoltage Ride-Through Zero Volts for 0.5 Sec. and 50% Voltage for 1 Sec IGBT Switching Devices 1200VPEAK 2 kHz Switching Freq. INVERTER Ground-fault alarm 2 Ampere (depending upon capacitive charging current) Depends on Motor Cable Length (see Mfg. Installation Instructions) Not Applicable Not Applicable Not Applicable Output Filter CONTROL COOLING Power Supply Undervoltage Ride-Through Fans DC BUS Power Components Applied to 75% or less of device rating 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 considerations are motor stator insulation voltage rating and motor (stator, rotor, bearings, Chevron Corporation 1500-31 May 1996 1500 Adjustable Speed Drives Electrical Manual and lubrication) thermal rating. These considerations and cause and effects are summarized in Figure 1500-24. Fig. 1500-24 Motor Considerations for LV Drive Applications Motor Considerations Stator Winding-Insulation Voltage Rating Cause & Effects High-voltage wavefronts at motor terminals due to fast-switching IGBTs and (motor feeder) cable characteristic impedance. Recommendations 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. 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 HPsize 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 standard-rated motor. These are generally constant torque applications with a speed range greater than 6:1. 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 inefficiencies in air cooling. This increase in motor temperature (initially for constant torque and gradually for variable torque applications) can affect stator winding insulation, rotor, bearings, and bearing lubrication integrity. Harmonic currents also result in higher stator and rotor heating. Higher motor surface temperatures will be experienced on drive-controlled motor versus motors on sine-wave power. Class I Division 2 Area Classifications TEFC motors are recommended for all Class I Division 2 applications, however the motor surface temperature 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. Keep PWM switching frequencies below 4 kHz. Alternatively, 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-tobearing housing voltages. Other considerations are to ground the inverter output (motor side) to shift the common mode voltage to the rectifier (input side). 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. Motor Sizing and Selection Motors 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 May 1996 1500-32 Chevron Corporation Electrical Manual 1500 Adjustable Speed Drives operating time). An auxiliary fan. (2) Premium Efficiency (PE) Motors meet the energy Policy Act of 1992 (NEMA MG-1-1993 refers to PE motors as “energy efficient”).15 SF Premium Efficiency TEFC Motor W/ 1.0 SF Premium Efficiency TEFC Motor W/ 1.15 SF Premium Efficiency TEFC Motor W/ 1. built to the latest IEEE Std 841 and DRIMS-1824 are recommended for drive applications. Figure 1500-26 shows the relationship between voltage. 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). 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. In addition. the motor and drive manufacturers should always be consulted to verify that the ASD application is suitable for their equipment.15 SF. Bearing temperature rise of 45°C (above a 40°C ambient) at worst operating condition. horsepower. NEC T-Code for the area classification 3.60 Hz (1) Motor standard rating is based on 60 Hz sine-wave power. Motors.15 SF. IEEE Std 841 motors offer many of the design features that are suitable for drive applications. two sizes above standard motor Speed Range 2:1 30 . torque. 2. can be evaluated for applications with a wide speed range. 1500-25 Typical Motor Sizes for ASD Applications Motor Size(1) Variable Torque Applications (Centrifugal Loads) Premium Efficiency (2) TEFC Motor W/ 1. Both the drive manufacturer and driven equipment manufacturer should confirm the motor size. one size above standard motor Motor Size(1) Constant Torque Applications Premium Efficiency TEFC Motor W/ 1.60 Hz 10:1 6 . applications. 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.15 SF. and current versus speed for constant torque. one size above standard motor Premium Efficiency TEFC Motor W/ 1. Fig.15 SF Premium Efficiency TEFC Motor W/ 1.60 Hz 6:1 10 . Chevron Corporation 1500-33 May 1996 . one size above standard motor Premium Efficiency TEFC Motor W/ 1. This option is usually not economical unless the motor HP size is increased two sizes above the standard-rated motor.60 Hz 3:1 20 .15 SF.0 SF Premium Efficiency TEFC Motor W/ 1. versus increasing the size of the standard motor. retrofitted to the motor frame. one size above standard motor Premium Efficiency TEFC Motor W/ 1. Two inverter-duty design features that are not included in an IEEE 841 motor are 1600VPEAK rated winding insulation and insulated bearings. Constant torque applications are the most severe for motor service.60 Hz 4:1 15 .15 SF. and six pole. 1800 rpm. May 1996 1500-34 Chevron Corporation . Motor Sizing Examples For variable torque applications. should be used to determine the HP rating of the motor. The maximum speed varies greatly between frame sizes and models. The motor sizing criteria. Two-pole. below. Size a motor for a pelleter application with a 6:1 speed range and the speed torque conditions given in Figure 1500-27. NEMA-frame motors are likely to be closer to their first lateral critical speed. Motor manufacturers should be consulted for actual maximum operating speed. Used with permission from IEEE 95-CH35840-b/95/0000-0231. Figure 1500-25 can also be used to determine the need for increasing the motor HP rating above the standard HP rating. Example 1 . Four pole. described above. For constant torque applications. motors up to 2400 rpm.1500 Adjustable Speed Drives Electrical Manual Fig. the worst operating condition is at the highest operating speed. 1500-26 Constant Torque Characteristics for Induction Motors. the worst operating condition is at the lowest operating speed. High speed applications (above synchronous speed) for low voltage motors are common. motors can typically be operated to 2700 rpm. ©1995 IEEE. especially with two-pole motors. Most motors can operate above normal nameplate speed.Variable Torque Application. The following two examples will show how to size motors for variable torque and constant torque applications. 1200 rpm. This is a variable torque application with a maximum speed operating condition above synchronous speed for a six pole motor. 3600 rpm. size the motor HP rating based on the highest operating speed. The motor should meet the requirements of DRI-MS-1824 and IEEE Std. and a load torque of 600 lb-ft. 1500-27 Speed vs. minimum speed. On an equivalent 60 Hz (900 rpm) basis. at the lowest operating speed. Torque Requirements for Motor-Sizing—Example 1 Operating Condition Maximum Speed Normal Highest Speed Medium Speed Minimum Speed Speed (rpm) 1500 1200 800 200 Torque (lb-ft) 158 131 98 26 For this variable torque application. this is an acceptable margin. 841-1994. 841.= 45 HP 5250 Select a 50 HP motor to accommodate the maximum speed condition (and HP requirement of 45 HP). and per IEEE Std. Torque Requirements for Motor-Sizing—Example 2 Operating Condition Normal Maximum Speed Normal Minimum Speed Safe Off (Worst Case Minimum Speed Speed Speed (rpm) 855 425 150 Torque (lb-ft) 300 570 600 Operating Hrs/Year 6000 2200 75 For this 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.Electrical Manual 1500 Adjustable Speed Drives Fig. size the motor HP rating based on two methods described below and compare the pros and cons of each: 1. By meeting the requirements of DRI-MS-1824. However. the bearing temperature rise must not exceed 45°C. Chevron Corporation 1500-35 May 1996 . Fig. since the motor operates only 75 hours per year (less than 1 percent of the time) at this condition. Using a Class F rise provides no design margin at the worst case. 1500-28 Speed vs. The HP rating is given by the following formula: Torque × Speed HP = ------------------------------------5250 158 × 1500 HP = -------------------------. the winding temperature rise at the service rating must not exceed 90°C. below.Constant Horsepower. High Torque Application. Example 2 . which is 1500 rpm and 158 lb-ft of torque. The HP rating should also be based on operating the motor at Class F temperature rise. however. if the winding temperature rise at SF load does not exceed 90°C (Class B. 1. Class F. 1. however the inverter output voltage at this speed (based on a constant V/Hz output) is 460/6 = 77 volts. Torque Requirements for Motor-Sizing—Example 2. the 1. with an external blower. Method 2 (Example 2): The HP requirements for the three operating cases are calculated and shown in Figure 1500-29. service-factor temperature rise). For the unusual. The amount of load current for 17 HP at a motor terminal voltage of 77 volts is approximately 125 amperes. Section 5. and additional heating due to harmonics. with the following characteristics: 900 rpm. safe-off condition. TEFC. premium efficiency.0 SF motors are preferred. 1500-29 Speed vs. For the normal operating speed range (425 .15 SF motor. Method 1 (Example 2): 600 × 900 HP = ----------------------.855 rpm) the HP load is constant. See DRI-MS1824. a 150 HP motor is chosen.15 SF allows for a small margin for machines that are sized right at the stan- May 1996 1500-36 Chevron Corporation .1500 Adjustable Speed Drives Electrical Manual 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. When appropriate. A spare blower should also be ordered. for a discussion of service factor temperature rise. Discussion For Example 2.15 SF.= 103 HP 5250 Based on the motor manufacturer’s allowances for limited cooling at 150 rpm. In this case. 1. Fig. premium efficiency.15 service factor (SF) as a standard for drive applications. Choose a 100 HP. to improve the mean time to repair. high output torque is required. 1. If there is concern about the reliability of the external blower. equivalent to the full load current of a 100 HP motor. the motor and drive should be specified to operate with the external blower on all of the time and alarm if it fails. 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 2 Operating Condition Normal Max Speed Normal Min Speed Safe Off (Worst Case Min Speed) Speed (RPM) 855 425 150 Torque (lb-ft) 300 570 600 HP 49 46 17 The HP required for the lowest speed is 17 HP. Many drive and motor manufacturers offer motors with a 1.15 SF machines are acceptable. TEFC.4. Torsional analysis should also be considered for motors above 500 HP. a motor rated for inverter operation should be specified. or other components with lubricated. the service factor temperature rise of 90°C should be clearly stated on the motor data sheet. plotting acceptable torque versus speed for retrofit applications. and damage could occur due to overheating. Note that for a safety margin. Most 3600 rpm (and lower) motors up to 900 HP operate below their first lateral critical (synchronous) speed. the curve shows no more than 90 percent motor rated torque be applied for the ASD application. Fig. In situations where the load requires high torque at slow speeds.Electrical Manual 1500 Adjustable Speed Drives dard motor rating. If torque requirements at slow speeds continuously exceed the values shown in the curve. oil filled gear boxes. At slower speeds. or other machinery with journal or sleeve bearings. A lateral critical rotor dynamic analysis is therefore not required for these motors. the minimum speed might not provide adequate cooling. Courtesy of Toshiba International. Fixed speed machinery (motor and driven equipment) may not run properly over the variable speed range. Speed for Retrofit Applications. nominally sliding bearing or force transmitting surfaces. This should be checked and verified by the driven equipment manufacture. When 1. Special considerations must be taken when applying an inverter to an existing motor. However. the driven equipment may have a lateral natural frequency in the operating speed range. cooling is not as effective due to reduced fan speed. Operating above or below 60 Hz may damage bearings or rotating parts. The Chevron Corporation 1500-37 May 1996 . Slow speeds may not provide sufficient lubrication for bearings. speed reducers.15 SF motors are specified. 1539 Drive Retrofit Applications Rotating machinery considerations and branch circuit cable type are two of the most important issues for retrofit applications. Figure 1500-30 shows a curve. Refer to Section 1560 for guidance on when to perform rotor dynamic studies. 1500-30 Torque vs. in which case the next higher HP motor may be necessary. Electrostatic shielded cable may be necessary if sensitive equipment or analog instrumentation and control circuits are located near the drive-output cable route. since they have many inverter-duty features. Figure 1500-31 can assist in determining if the existing motor is adequate. Premium efficiency motors should be selected for all ASD applications. one size above Standard Motor Premium Efficiency TEFC Motor W/ 1. There are three common induction-motor drive types.60 Hz Motor Size(1) Variable Torque Application TEFC Motor W/ 1. The second type is one May 1996 1500-38 Chevron Corporation . Operating on or near a critical speed can cause high vibration and can damage bearings and rotating equipment.15 SF. (3) Premium Efficiency Motors meet the Energy Policy Act of 1992 (NEMA MG-1-1993 refers to PE motors as "energy efficient").60 Hz 4:1 15 .15 SF. See Section 1560 for more discussion on rotordynamic studies.60 Hz 3:1 20 .60 Hz 6:1 10 . See Section 1550 for a detailed discussion of electrical distribution system considerations.15 SF.0 SF High Efficiency TEFC Motor W/ 1.0 SF High Efficiency TEFC Motor W/ 1. IEEE Std 841-1994 are preferred motors. See Section 1536 for more details on the inverter output. if necessary.15 SF High Efficiency TEFC Motor W/ 1.1500 Adjustable Speed Drives Electrical Manual first or second lateral critical natural frequency may also be within the operating speed range. One uses a silicon controlled rectifier (SCR) inverter bridge with a large output capacitor (for commutation). Fig. All existing THHN cable should be replaced with UL-44 listed cable. 1540 Applying Medium Voltage Drives Medium voltage drives consist of both induction and synchronous types. 1500-31 Minimum Motor Sizes for LV ASD/Retrofit Applications Speed Range 2:1 30 . since they traditionally run cooler than less efficient machines. one size above Standard Motor High Efficiency TEFC Motor W/ 1.15 SF.60 Hz 10:1 6 . A computer simulated harmonic analysis is also required to identify any possible effects that the drive-created harmonics may have on the electrical distribution system. one size above Standard Motor High Efficiency TEFC Motor W/ 1. Often.15 SF. two sizes above Standard Motor (1) Motor standard rating is based on 60 Hz sine-wave power.0 SF Premium Efficiency (3) TEFC Motor W/ 1. called a load commutated inverter (LCI) induction motor (IM) drive. Computer simulated lateral and torsional analyses are required to identify natural frequencies and corrective actions. The drive may also produce harmonic currents that excite a torsional critical natural frequency. one size above Standard Motor Motor Size(1) Constant Torque Application TEFC Motor W/ 1.0 SF High Efficiency (2) TEFC Motor W/ 1. or assist in sizing the new motor. (2) High Efficiency Motors exceed the standard efficiency motors supplied by the manufacturer. If a new motor must be substituted for an existing machine. a motor on a fixed speed application can be directly applied to an ASD. Electrical Manual 1500 Adjustable Speed Drives using gate turn-off (GTO) thyristors in the inverter bridge. The third type is a drive that uses a low-voltage power cell. connected in series. Figure 1500-32 provides an HP versus speed application envelope of MV induction and synchronous-motor drives that have been applied in industry. using SCR converter bridges. High-speed (super synchronous) drives have also been applied up to 12. The field on the synchronous machine is controlled by the ASD control system.000 HP and high speed drives up to 3.000 rpm. called a GTO drive. to vary the motor terminal voltage in order to commutate the machine-converter thyristors. 1500-32 Induction and Synchronous Motor Drive HP vs Speed Application Envelope 1541 Induction-Motor Drive Types The GTO and LCI IM drives both use the same line and machine converters. The Harmony® Power Cell drive uses a low voltage power section with a diode line converter and an Chevron Corporation 1500-39 May 1996 .000 rpm. the HP size that can be applied. decreases due to rotor fabrication limitations. with thyristors. MV induction-motor drives range in sizes from 400 HP to 15. Fig. See Section 1510 for a basic description of the synchronous-motor LCI drives. See Section 1513 for a basic description of medium voltage induction-motor drives. Synchronous-motor drives are load commutated inverter (LCI) types.000 HP. to provide the desired voltage output. The Company has applied conventional speed (up to 3600 rpm) induction-motor drives up to 10. As the speed of the drive increases.500 HP and 11. called a Harmony® Power Cell drive. normally either 6-pulse or 12-pulse bridges. motor thermal heating. Several amperes is all that is required to turn on a GTO. This makes the GTO type drive particularly well suited for retrofit applications. Most drive manufacturers use PWM technology to switch the GTO thyristors. Normally two dc link inductors are used. lateral and torsional rotor dynamics. Each leg of the rectifier bridge consists of a sufficient number of SCRs in series to reliably block the input voltage.dc bus. This is done at the expense of an increase in some higher order harmonics. dry type. The inductors are air or iron core. Rate-of-rise voltage (dv/dt) is controlled by R-C snubber circuits in parallel with each thyristor.1500 Adjustable Speed Drives Electrical Manual IGBT output (single-phase) converter.900 volts. applied for several micro seconds. May 1996 1500-40 Chevron Corporation . stator winding voltage stresses. Each leg of the inverter bridge consists of a sufficient number of GTO devices in series to reliably block the DC bus voltage. The GTO converter can handle power flow in either direction. GTO Type Induction-Motor Drive The GTO drive has power ratings up to 15. All drive-types use either air or liquid for cooling the power section. one to turn the device on and the other to turn the device off (or force commutate). The inverter utilizes a current source controlled bridge to provide a variable frequency and variable voltage source to an induction motor. The GTO inverter uses a pulse width modulated (PWM) control mode. The GTO device has two gate inputs. Voltage dividing resistors and unidirectional R-C snubber circuits.or 12-pulse line converter. which can selectively reduce the electrical harmonics to the motor.000 HP and 6. The maximum speed for the GTO drive is 9. however. are connected in parallel with each GTO. particular harmonics can be eliminated in the inverter output wave. A relatively small size 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. GTO drives can be either current-source or voltage source inverters. as high as a thousand amperes. The standard GTO drive uses a 6. The power cells are connected in series to develop the necessary output medium voltage. which can be filtered out. and source and load harmonics all need to be evaluated for retrofit applications. However.000 rpm (and increasing) as the GTO thyristor technology continues to grow. DC link reactors are used to smooth the current ripple on the DC bus. The recommended design margin is a working voltage equal to one half the repetitive reverse blocking voltage. and air cooled reactors. for dv/dt control. Equal (dc) voltage sharing among the rectifier devices is accomplished with voltage dividing resistors in parallel with each thyristor. By the correct selection of switching points. is necessary to turn off a GTO. one on the + dc bus and one on the . 500 HP 4000V motor.414 x 4160V = 5. or three devices in series. A graphical symbol for a GTO is shown in Figure 1500-2. such as 4500V . the working voltage of a GTO is one-half of its peak reverse voltage.000 rpm. Typically there may be three of these devices in series per leg of an inverter for a 1.5A 1200Kg 34mm 8µSec 17µSec 900V/µSec 200 A/µSec 4500A GTOs are primarily classified by their repetitive peak reverse voltage and gate turnoff current rating. The LCI IM drive uses a current-source drive technology. LCI Type Induction-Motor Drive The LCI induction motor (IM) drive has power ratings up to 12.000 HP and 6.900VPEAK.4. and therefore the current. GTO working voltage is: 4. The minimum desired number of devices is: 5. Peak applied voltage is: 1. 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. to provide the torque necessary to satisfy the motor shaft load.500VPEAK ÷ 2 = 2500VPEAK.500VPEAK = 2. Chevron Corporation 1500-41 May 1996 . A typical rating and its characteristics are shown below: • • • • • • • • • • • • Repetitive Peak Off-State and Reverse Voltage RMS On-State Current Turn-Off Gate Current Peak Gate Turn-Off Current Gate Turn-On Current Mounting Force Junction Diameter Gate Turn-On Time Gate Turn-Off Time Critical dv/dt Minimum di/dt Peak One Cycle Surge On-State Current 4500V 300A 260A 800A 2. The line converter controls the DC bus voltage.900VPEAK ÷ 2.Electrical Manual 1500 Adjustable Speed Drives GTO thyristors come in a variety of voltage and current ratings.900 volts.800A GTO. The maximum speed for the LCI IM drive is currently (1996) approximately 12. Selecting the number of devices in series can be determined as follows. For improved reliability. Voltage dividing resistors and R-C snubber circuits. Typically. SCRs come in a variety of voltage and current ratings. The SCR is turned off by reverse biasing the device and removing the gate signal. are connected in parallel with each SCR. Several amperes is all that is required to be applied to the gate to turn on an SCR. A typical rating and its characteristics are shown below: • • • • • • • • • • Repetitive Peak Off-State and Reverse Voltage Average Forward On-State Current Junction Diameter Mounting Force DC Gate Trigger Current Gate Turn-On Time Circuit Commutated Turn-Off Time Critical dv/dt Critical di/dt Peak One Cycle Surge On-State Current 3200V 1000A 43 mm 5.000-6. The SCR device has a single gate input. Selecting the number of devices in series for an N+1 configuration can be determined as follows.1000A SCR.900VPEAK. Each leg of the inverter bridge consists of a sufficient number of SCR devices in series to reliably block the DC bus voltage.000 HP. to turn the device on.000 lb 200mA 10µSec 125µSec 1000V/µSec 100A/µSec 15.414 x 4160V = 5. for a 7. Peak applied voltage is: 1. 4000V motor there may be five of these devices (in an N+1 configuration) in series per leg. The reverse bias voltage comes from the load. 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. The device turns off when the current goes to zero. such as 3. for dv/dt control.1500 Adjustable Speed Drives Electrical Manual The rectifier bridge for the LCI IM drive is configured the same as for the GTO (see above). the working voltage of an SCR is one-half of its peak reverse voltage. For improved reliability. May 1996 1500-42 Chevron Corporation .000A SCRs are primarily classified by their repetitive peak off-state and reverse voltage and average forward on-state current rating.300V . a capacitor is installed on the output of the inverter to provide a steady and adequate biasing voltage for commutation. and since an induction motor’s terminal voltage does not provide adequate biasing voltage. the singlephase outputs in each phase are synchronized such that total output is a 3-phase. in which only two phases conduct simultaneously. With this configuration. The lowest harmonic for the 2400V drive is the 17th harmonic. Harmony® Power Cell Drive The Harmony® Power Cell (HPC) drive has power ratings up to 10.600V ASD uses 48-pulse converter. phase shifted so as to form a 30-pulse input.01 percent of rated torque. This differs from all other 6. Each 6-pulse line-converter bridge feeds an inverter bridge which has a singlephase output. To illustrate the HPC drive. and the 6600V drive is the 47th harmonic. The motor current duplicates the current which flows in a three-phase motor fed from a 60 Hz source.600 volts.Electrical Manual 1500 Adjustable Speed Drives The minimum desired number of devices is: 5. The advantage of the HPC drive technology is that output torque pulsations are very low.400V ASD uses an 18-pulse line converter and equivalent machine converter.or 12-pulse converters. nor is extra motor stator winding insulation. Chevron Corporation 1500-43 May 1996 . furnished to date (May 1996). At any frequency. The magnitude is dependent upon the number of power cells used to develop the output voltage. The harmonic current and voltage distortion will be even less at other locations on the electrical distribution system. The total harmonic voltage distortion. A 1. shown in Figure 1500-9. Two more power cells are used per phase for the 4. The input line converters are each supplied with a 480V. sine-wave voltage whose frequency is controlled to get the desired motor speed. and the 6. with a peak magnitude less than 0. throughout the speed range. Five devices are used in an N+1 leg configuration. the input line current has considerably less than 5 percent total harmonic current distortion (as measured on the input terminals of the drive).7 or four devices in series.900VPEAK ÷ 1.600VPEAK = 3. sine-wave voltage output. is considerably below 3 percent. except the frequency varies. The existing drive technology can accommodate higher output frequencies. The maximum drive output frequency. 3-phase voltage from individual windings in the isolating transformer. The 2. The HPC drive uses a non-conventional PWM technology. well below IEEE limits. is 120 hertz.160V ASD uses 30-pulse converter. However.000 HP and 6. The supply voltage can be any voltage up to 13.1 percent of rated torque and an average of 0. The isolating transformer is mounted inside the ASD cubicle and is furnished as part of the drive. The inverters are connected in series on each phase to form a threephase. in that the singlephase output of each cell is controlled using PWM technology. In addition. total harmonic current distortion on the input and output is very low. even for a source impedance as high as 10 percent on the ASD’s own KVA base. Any motor. as measured at the input of the drive. even an existing motor.8kV. a sine-wave current is flowing in all 3 phases to the motor. the 4. for the 4160V drive is the 29th harmonic. The topology of the 4160V HPC drive is similar to the 2300V ASD.15 SF is not required. can be used with the HPC drive. consider a 4160V ASD consisting of five sets (or cells) of 6-pulse converters.160V drive. Figure 1500-34 shows a 6-pulse/6-pulse GTO drive configuration for controlling multiple motors. Thyristors are used in both the line and machine converters.g. Drive cooling is either air or liquid (glycol) with liquid cooling the preferred method for applications above 15. Design margins for applying the power section components are the same as for the induction-motor drive. which reduces the capital costs of the installation. If the set point is not met with the capacity of pump #1. 480V) source. Each drive controls two (or more motors). with two 6-pulse bridges combined in series. which allows the two inverters to produce a 12-pulse output. The field control system normally uses a 3-phase low voltage (e. 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. These are the basic building blocks for more complex or sophisticated configurations. Synchronous-motor drives are current-source. to a voltage controller. The significant difference between the induction and synchronous-motor LCI is the field control on the synchronous-motor ASD. Figure 1500-33 shows a 12-pulse/12-pulse LCI synchronous-motor drive. due to the high magnitude of harmonic currents associated with the large HP drives.000 HP. May 1996 1500-44 Chevron Corporation .. This configuration can be used for water injection applications or pipeline applications. As an example. load commutated inverter (LCI) type and uses a line and machine converter that is the same as the LCI induction drive (see Section 1541). elimination of noise contamination on the gate signal and voltage isolation between the medium voltage bridge and the control system. Motors can be put into service or taken out of service sequentially. then M1 is switched to the fixed-speed bus and M2 is started by the common ASD. Some additional complexity is necessary for the drive and pump controls. in which the system pressure is controlled by multiple pumps. A 12-pulse machine converter is also desirable to limit the harmonic currents and motor stator and rotor heating. Drive controls should be fully digital with fiber optics for the thyristor gating signals. The motor has two three-phase windings displaced by 30 electrical degrees from each other. 1543 MV Drive Configurations Several drive configurations are shown below for medium voltage drives. M1 is started and brought up to speed to satisfy the pressure controller set point. 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.000 HP. The input transformer (not shown) provides a 30-degree phase shift between the two rectifiers. It is common to use a 12-pulse converter on the line converter.1500 Adjustable Speed Drives Electrical Manual 1542 LCI Synchronous-Motor Drive It is usually not economic to consider using synchronous-motor drives until the application reaches about 10. Fiber optics provide two benefits. which then produce a total of 12 pulses for each cycle of line power frequency. Electrical Manual 1500 Adjustable Speed Drives Fig. a model specification. a Company specification and data sheets do not exist for medium voltage drives. There are many similar specification requirements for both induction and synchronous medium voltage drives. Courtesy of Ansaldo Ross Hill. ELC-MS- Chevron Corporation 1500-45 May 1996 . This makes it suitable for a single model specification to be used as the basis for a purchase specification for either induction or synchronous applications. 1500-34 6 Pulse/6 Pulse GTO Drive Configuration for Multiple Motors 1544 MV Drive Specification An MV drive specification and data sheets should always be used to purchase an ASD. 1500-33 12 Pulse/12 Pulse Configuration. At this time. Fig. However. The diagram should also include all downstream distribution equipment. beginning with the utility source. should be completed and accompany the drive specification. In order to accurately specify drive equipment. Parameters to Determine for Drive Equipment Drive equipment includes: input or output transformers. drive and motor. input or output filters. Unique features and requirements can be added to the model specification to make it specific for the application. you must complete sufficient 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 Sheets Once you have determined these parameters. can be found in Volume 2 of the Electrical Manual. data sheets. motor and driven equipment data sheets should include: • • • • • HP voltage ampere power factor rpm May 1996 1500-46 Chevron Corporation . Completed data sheets should accompany the specification to identify specific drive. For the purchase of new motors and driven equipment. 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 accompany the data sheets and include the entire electrical distribution system. For new or retrofit applications. motor and driven equipment application features. based on the applicable industry standard (API-541 or 546).1500 Adjustable Speed Drives Electrical Manual 5008. complete the appropriate data sheets. compressor. to verify that the design is correct. analyzers. unlike LV drives. drive. anti-surge protection is applied on the compressor. etc. surge controller) and all of the application engineers (control systems. if on a compressor application. If the drive were installed in a lab. An engineer. are customized-engineered systems. drive. All of the steps identified in Figure 1500-21 should be done.Electrical Manual 1500 Adjustable Speed Drives • • • • • 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. Chevron Corporation 1500-47 May 1996 . the manufacturer could independently apply the product successfully without much outside involvement.) 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 Applications Medium voltage drive applications. process controllers) supplied from the same power source as the drive. By success is meant a drive that meets the requirements of the intended service with trip-free operation. the degree of customization increases. without adversely affecting other equipment on the system. the flaws and other unanticipated effects can be corrected. and Company personnel (familiar with the facility) is required. For example. especially if there is sensitive electronic equipment (computers. Finally. process). 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. A highly integrated application effort by the drive and driven equipment manufacturers. Each of these steps often has intra-disciplinary overlaps that must be thoroughly evaluated. Harmonics can be especially troublesome to the power system supplying large MV drives. However. Experience has shown that a high degree of Company involvement is necessary to successfully apply drive systems. conditions are not ideal in an operating facility. mechanical. pump. under controlled conditions. Through testing. the ASD application engineer. As the HP size gets larger. a commissioning field test must be done to prove that the designed system works. Commissioning always uncovers unanticipated effects or flaws in the design. Undervoltage ride-through is the most important reliability feature of MV drives. Control Section. In most applications this is sufficient to get through disturbances that traditionally cause most of the drive trips. The impedance should be chosen to limit the voltage notch depth. should be consulted on all large ASD applications. General Application Considerations There are many common application considerations for all types of MV drives. Three-winding transformers with a 12-pulse rectifier are recommended. both of which are desirable effects. The control section should be completely digital with alarm and diagnostic functions to warn of May 1996 1500-48 Chevron Corporation . To improve the reliability of the system. In order to accommodate voltage transients. Some form of harmonic filtering should always be applied. at the input transformer primary. It should also meet the specified voltage harmonic distortion limits (See Section 1550). The transformer can be either a two or three winding transformer depending upon harmonic considerations and should be equipped with an electrostatic shield.1500 Adjustable Speed Drives Electrical Manual specializing in harmonic analysis. The higher the transformer impedance. an uninterruptible power supply (UPS) should be used to provide power to the control section. 519. The adverse effects of a high impedance are less commutation margin and higher harmonic voltage distortion on the transformer secondary. switching transients and brown-out conditions. the drive should be tested during commissioning by simulating a voltage interruption while the motor and drive are in operation. To verify that the setup is proper. the short circuit requirements and the drive design margins must be met. Selection of the transformer impedance is an important consideration. Unique application considerations for the three types of induction-motor drives and the synchronous-motor LCI drive are discussed after this section. especially if the input source from the utility is affected by lightning strikes. MV drives should always be applied with a rectifier-duty input transformer. since it will affect the following design requirements: commutation impedance of the line converter. In addition. The drive designer must resolve these competing requirements and a compromise must be made to satisfy the overall system requirements. current and thermal margins for the components used in the line and machine converters should be applied at no more than 50 percent of their ratings. the short circuit duty applied to the line converter. Power Converter Section. These considerations are discussed below. both the drive power and the control sections should be set up to ridethrough a power interruption of zero volts for a minimum of 0. The voltage. and the harmonic voltage distortion. Input filters are often utilized to meet the harmonic distortion design criteria. to a maximum of 20 percent as defined in IEEE Std. if there is a doubt about the harmonic effects. Drive Input. This is discussed in more detail in Section 1550.5 seconds and a voltage sag of 50 percent of rated voltage for a minimum of two seconds. the voltage notch depth of the input source. 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. A drive trip and switchover is normally required to transfer to the backup. Self diagnostics monitor the health of the system. For critical applications. The FMEA is best done with the drive manufacturer. lowest losses. A separate and comprehensive drive monitoring. Another potential scaling factor problem is alarm and trip settings that have been specially modified and programmed for factory testing. The motor will coast down. Rotor cage design modifications are often necessary to accommodate harmonic currents. Constantvoltage transformers (CVTs) should be used to provide control power to the power supplies and other drive equipment. and fault tracing system should also be considered for troubleshooting and preventing unplanned shutdowns of the ASD system. the harmonics originating from the drive will have a considerable effect on the electrical distribution system. Sine-wave motor voltage and current produces the best torque. a failure modes and effects analysis or a reliability centered maintenance analysis should be considered for large HP MV drives. Factory Testing. Drives that produce sine-wave output do not require any motor modifications. Rotordynamics. consider using dual control modules to increase reliability of the drive. See Section 1560. but after the switchover a flying restart can be performed. When setting up control section software parameters. Factory testing should be witnessed for all MV drives. especially large HP applications. 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. Two days should be devoted to this review. CVTs provide some immunity to voltage transients on the load side of the UPS. Early in the design of the drive system. For drives manufactured overseas primarily for the 50 Hz market. Either or both of these studies will reduce failure modes and improve reliability. Electrical Distribution System. a transfer to the backup module is initiated. If a control system failure is detected. FMEA or RCM Analysis. diagnostic. Harmonic effects are discussed in more detail in Section 1550. this option should be considered.Electrical Manual 1500 Adjustable Speed Drives impending trouble and provide self monitoring of the drive condition. Drive Output. and lowest audible noise in the motor. If the process can tolerate a 3 second slowdown. the scaling factors must be adjusted for 60 Hz supply systems. Motor. special attention must be paid to the scaling factors. For MV drives. except for low speed constant torque applications. and can take several seconds to complete. Drive Diagnostics. The UPS provides effective conditioning of power due to voltage transients on the line side of the UPS. All MV drives larger than 500 HP or with high inertia loads should be analyzed for rotordynamics. The same consideration applies for drives manufactured in 60 Hz markets and applied in 50 Hz locations. Section 1570 provides guidance for factory testing. 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. The FMEA is really an abbreviated study that has been done on Chevron Corporation 1500-49 May 1996 . The scaling factors need to be reset and field tested as part of the final commissioning plan. The degree of harmonic elimination is limited by the output frequency and the maximum switching rate for the device. and switching losses. If several drives are being installed with a staggered startup schedule. A 12-pulse output inverter bridge can significantly reduce the 5th. The first is a parallel resonance between the output capacitor and the stator and rotor series inductances. Additional benefits are improved spare parts selection and a reduced MTTR. Certain lower order harmonics can also be selectively eliminated by operating the inverter bridge in PWM mode at the correct switching frequency. Considerations for specific applications are given next.1500 Adjustable Speed Drives Electrical Manual some applications. and other higher order harmonics. the review discovered over a dozen single-point failure components or systems that were corrected. The second resonance condition is that between the capacitor and the motor magnetizing inductance. This is expected to greatly improve the MTBF of the system. RCM assists in the training of plant personnel. one harmonic. which can be filtered out. ASDs are unable to handle the rapid power swings associated with the compressor surge. these harmonics can be reduced by 80-90 percent. Motor and Capacitor Resonance. 7th. usually the 5th can be eliminated. reliability margins in the switching rate. In practice. The RCM is best done with the facility engineers. This condition can be avoided by putting the drive output contactor downstream of the capacitors and opening the contactor on an input trip. 19th. This is done at the expense of an increase in some higher order harmonics. Unplanned shutdowns as well as thyristor failures can occur. due to two possible resonance conditions. Considerations for GTO Drive Applications Harmonic Reduction Technique. Often. 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. This also greatly reduces the 6th and 18th harmonic torsional excitation frequencies (See Section 1560). With three pulses per half cycle. using the drive manufacturer as a resource. Care must be taken in the selection of the component values. Driven Equipment Surge Protection. In one case. resulting in excessive self-excitation during an input power trip. 17th. In addition to improving the MTBF of the system. to answer specific questions. May 1996 1500-50 Chevron Corporation . 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. These have included a “safe fire circuit” to turn-on a thyristor if the blocking voltage exceeds a maximum value. Elimination of additional harmonics requires two extra pulses for each harmonic eliminated. Protective features can be incorporated in the drive controls and in the thyristor firing circuit to prevent compressor surges from damaging the drive. 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. The maximum switching frequency is further determined by device characteristics. 160V ASD can drive a cubic load (blower. a 4. One method to limit self-excitation voltage is by circulating current in the drive during periods when input voltage is too low. the HPC drive has an optional feature called a “cell by-pass”. and no limitations on using an existing motor. unlikely. Since the output waveform is a sine-wave current. no electrically-induced torque pulsations. harmonic baseline data should be collected prior to installing the drive and again after startup to confirm acceptable harmonic distortion levels. the applied voltage to the motor is gradually lowered and during a trip. The high speed motor is designed with low magnetic flux levels to keep iron core losses low at high operating frequencies. This makes the first resonance condition. there is no extra heating in the motor due to harmonics. fan. and no harmonic losses in transformers or motors on the power-source distribution system. A faulty cell can be removed and a new one installed in less than 30 minutes. if an existing bus has other harmonic sources. However. The capacitor on the output of the LCI IM drive is quite large. no HV standing wave at the motor terminals (normally associated with PWM IGBT drives). described above. etc. there are no harmonic considerations. For additional reliability. no derating of the input transformer. centrifugal pump. The HPC drive can be powered from any bus even if that bus also supplies harmonic sensitive loads. no harmonic filters. This causes the motor to self-excite to a greater percentage of rated voltage as compared to a normal 60 Hz motor. without an outage. Self diagnostics and bypass can be accomplished on the run. Also. However. the HPC drive will contribute such low additional harmonics to the system. the output isolating device is opened to eliminate any overexcitation condition. when the output contactor is kept closed. No harmonic analysis is required. Output. the self-excitation condition is possible. Maintenance. Since the input waveform is a sine-wave current. High Speed Motor Application. a saturable reactor can be used to limit the self-excitation voltage. no common-mode voltages requiring higher ground-wall stator insulation. With this option. This same self-excitation condition can occur on a drive pause. with a KVAR rating equal in size to the HP rating of the motor. To avoid this problem. if the drive does not have to overcome a system with a high back pressure or high differential head. The power cells are mounted on rollers. but can be avoided by putting the drive output contactor downstream of the capacitors and opening the contactor on an input trip. prior to installing the HPC drive.) at any speed up to 90 percent of full speed with one cell bypassed due to failure. During a normal drive shutdown. Considerations for Harmony® Power Cell Drive Applications Input. Chevron Corporation 1500-51 May 1996 . 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. Reliability. that it is unlikely that the harmonic distortion problem will be worse.Electrical Manual 1500 Adjustable Speed Drives Considerations for LCI Induction-Motor Drive Applications Motor And Capacitor Resonance. Alternatively. The motor exciter voltage rating should be compatible with the supply voltage for the field controller. 1546 Motor Considerations Motor considerations for applications with large ASDs include: • • • • Rotor and stator heating due to inverter output harmonic currents. The output voltage of the drive field supply will have voltage spikes created by the back-to-back thyristors. 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 May 1996 1500-52 Chevron Corporation . LCI synchronous-motor drives are simpler and less costly than induction-motor drives. The standard voltage rating of the exciter stator windings is normally 1000VPEAK and may not be adequately rated for the transient voltage spikes. Synchronous machines require a power source for the field. due to the higher cost differential of the synchronous motor versus the induction motor. One area to evaluate during the design is the insulation voltage rating of the stator windings of the motor exciter. One example of incompatibility is with a European manufactured drive and motor that uses a 150V exciter. Considerations for Synchronous-Motor Drive Applications For high HP applications (above about 10. A failure of a leg thyristor on the field controller. Another feature to evaluate is the rating of the varistors on the output of the field supply.1500 Adjustable Speed Drives Electrical Manual 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. This inattention to detail has resulted in several incidents and plant shutdowns. and the size of the snubber circuits across the thyristors.000 HP). the synchronous drive and motor system is more expensive.000HP. Redundant power supplies for the field controller have been applied on drives. The field supply system for ASD applications is often not given the careful consideration that the rest of the drive system is given. will apply 480V to the 150V rated exciter. since auxiliary systems tend to have relatively higher failure rates than the main drive system. During factory testing of the motor and drive. This can greatly improve the MTBF of the system. installed in a US plant with a 480V supply to the field controller. Undersized varistors may fail in service and result in a drive trip. Below 10. the voltage waveform of the exciter supply should be inspected and a hard copy of the waveform provided as part of the test documentation. Field Supply. The retaining ring is a nonmagnetic steel material for near elimination of induced currents and to facilitate current flow from the wedges. during lower speed. Constant voltage converter operation improves power factor and reduces harmonic currents induced into the utility supply. 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. Below this speed the converter operating characteristic must be in a V/Hz mode. and the number and size of strands of wire in each turn. 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.Electrical Manual 1500 Adjustable Speed Drives Synchronous Motor Design For LCI Drives Rotor Design. Fig. The cylindrical rotor configuration for ASD applications is as an amortisseur winding. number of separate turns in the coils. which will also be the number of stator coils. but requires increasing levels of magnetic flux in the rotor and stator of the motor. Once you know the number of stator slots. then you can determine the length of the stator and rotor. A rotor isometric is shown in Figure 1500-35. dimensions of the slots. Completing the electrical and magnetic design involves selection of the number of stator slots. using either a continuous wedge or a segmented wedge design with wedge-to-wedge interconnects to provide for the electrical continuity. Stator Design. Since the motor supply voltage and frequency are determined by the machine converter. Synchronous motor manufacturers usually have a limited series of design selections to choose from when beginning a machine design. with its reduced resistivity. Chevron Corporation 1500-53 May 1996 . Courtesy of Electric Machinery. The design will be based on the outer diameter of the stator magnetic core and/or the outer diameter of the rotor. 1500-35 Rotor Isometric for Synchronous Motor. Constant voltage operation is not normally feasible below two-third of rated speed. The second is the effect the drive will have on the electrical system and other equipment on the system. 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. 1550 Considerations for Electrical Distribution System There are two main considerations for the electrical distribution system. 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. connected to ground potential. Construction techniques 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. the machine-stator-ventilation plan may also need to be modified. In most applications this is sufficient to get through disturbances that traditionally cause most of the drive trips. The design of the motor for ASD application can result in a larger machine than is normally expected for the horsepower application. 1551 Effects on the Drive The electrical system can adversely affect the drive operation for most systemimposed conditions. However. or “electrical stiffness”. Ventilation of the machine is also of great concern since the volume and effectiveness of cooling air will be reduced as the speed is reduced. This transfers the highest voltages to ground to the transformer side of the circuit. the drive should be tested during commissioning by simulating a voltage interruption while the motor and drive are in operation. which is suitably insulated to handle the additional voltage stress. in effect. at any instant in time (excluding the commutation overlap). A design or application modification can mitigate these effects. Selection of various materials mitigates some of the effects of the harmonic currents. ASD reliability is most affected by short duration power interruptions (voltage goes to zero) and voltage sags. Also. during inverter SCR switching. The first is the effect the electrical distribution system will have on the drive and the reliability of the drive operation. To verify that the setup is proper.1500 Adjustable Speed Drives Electrical Manual To accommodate the higher voltages to ground (common-mode voltages) experienced with LCI drives. two of the motor stator terminals are. and establishes the levels of rotor field current. can adversely affect the line converter of the drive. The drive can be configured to ride-through these disturbances. Line transients and surges.5 seconds and a voltage sag of 50 percent of rated voltage for a minimum of one to two seconds. the inverter section is generally high-resistance grounded. Drives should be equipped with metal oxide varistors (MOV) on the input that protect the power semiconductor devices from the line surges. The stator terminals of the open-circuit phases of each winding will be raised to a voltage greater than the normal line voltage levels. from lightning strikes or capacitor switching. In some cases the varistors are not adequately rated for the energy of the transients. An MOV may protect the semiconductor devices May 1996 1500-54 Chevron Corporation . Harmonic analysis should be performed up to the 97th harmonic. the 7th harmonic is 1/7 of the fundamental. It also provides a good tutorial on the drivegenerated harmonics and how the electrical system responds to these harmonics. 25th. 19th. the canceled harmonics are not completely eliminated but continue to exist at low magnitudes. 23rd. This can be avoided by selecting the proper size varistor for the line condition. In practice. 519 (for Low voltage Systems) should apply to medium voltage as well as low voltage systems. In several drive applications. For example.. notably the 5th and 7th. The notch depth should not exceed 20 percent as shown in Figure 1500-36. Considerations Regarding IEEE Std. 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. whereas the characteristic harmonic currents for a 12-pulse converter are 11th.Electrical Manual 1500 Adjustable Speed Drives but fail during the process and result in a drive trip. should not exceed 5 percent. 2. usually a lightning surge and the cumulative effect of multiple. It also provides harmonic and voltage quality limits for the drive manufacturer. 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. etc. The maximum individual frequency voltage harmonic should not exceed 3 percent. To use IEEE Std. 11th. 17th. not at the utility delivery point. Using this relationship. Where excessive harmonic distortion (see IEEE Std. Voltage notching limits. 519 for industrial and commercial applications. several clarifications and adjustments should be made. Consideration should be given to the energy of a single transient. The total harmonic voltage distortion at this point. corrective actions must be taken to avoid potential equipment damage and associated reduction in system reliability. etc.2 of IEEE Std. 25th. 1552 Effects on Other Equipment Drives produce harmonics and other conditions that can adversely affect the electrical distribution system and electrical equipment in the system. the utility company and the utility customer. 519 IEEE Std. to properly apply the varistor. 13th. Harmonic orders considered for limits and evaluation in IEEE Std. 519) occurs. 519 should go through the 97th order and not be limited to the 35th order. 23rd. Elimination of harmonics. the 5th harmonic is 1/5 of the fundamental. given in Table 10. 519 is a good resource for helping to identify potential problems. Capturing waveform disturbances can assist in sizing varistors. 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. The theoretical magnitude of each harmonic is inversely proportional to the order of the harmonic. Chevron Corporation 1500-55 May 1996 . 3. etc. in order to predict the system resonance frequencies. successive transient spikes. with the 12-pulse converter significantly reduces the harmonic distortion imposed on the electrical system. characteristic harmonic currents for a 6-pulse converter are 5th. 7th. 1. 13th. including the contribution from all existing harmonic generators. When a harmonic filter is not part of the design. 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. current. May 1996 1500-56 Chevron Corporation .1500 Adjustable Speed Drives Electrical Manual Fig. and surge or filter capacitors. 1500-36 Voltage Notch Depth. installed at the input of the drive can solve harmonic problems. Used with permission from IEEE Std. a much more detailed analysis is required in order to understand the effect. Harmonic heating in motors and generators and energy losses in transformers. Harmonic problems that have the biggest effect on the electrical distribution system are: 1. In most cases a properly designed harmonic filter. Resonance conditions with power factor correction capacitors. S19-1992. ©1993 IEEE. where the HP size is equal to or greater than 20 percent of the capacity of the substation. and to design the drive line converter and input transformer to prevent harmonic problems. Resonance conditions with capacitors can result in premature failure and rupture of the capacitor. Harmonics Considerations Harmonics tend to be a potentially bigger problem with medium voltage drives (due to their HP size) and large LV drives. 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. IEEE Std 18 gives limitations on voltage. 2. cable capacitance. and Voltage notching and spikes related to commutation switching of the SCRs on the line converter. 3. e. a simplified impedance diagram). 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. 6. especially in transformers. Commutation notching can also excite a resonance condition that normally will not be predicted by harmonic analysis. 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. 7. power supplies.Electrical Manual 1500 Adjustable Speed Drives H NATURAL = KVA sc -------------------KVA cap (Eq. “Harmonic Analysis. 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. The voltage notch depth can be calculated by Equation 1500-3 (refer to Figure 1500-37. 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.) for a particular capacitor size. Analyzer and instrumentation errors are classical problems that can be caused by drive harmonics. etc. 5. The natural frequency of this system is near the 7th order multiple of the fundamental frequency. and electronic equipment.× 100% % Notch Depth = -----------------Xs + Xt (Eq. by either exceeding the voltage rating or energy rating of the varistor. KVAsc = short circuit duty in KVA KVAcap = capacitor rating in KVAR As an example. The only way to predict harmonic resonance problems and quantify harmonic heating and energy losses is to perform a computer simulated harmonic analysis of the entire electrical distribution system. With transformers. 1500-2) where: HNATURAL = the system natural harmonic order (i.” Voltage Notching and Spikes Voltage spikes due to SCR commutation can cause overloading and failure of MOVs on the input of UPSs. Harmonic analysis is discussed in Section 1553. 1500-3) Chevron Corporation 1500-57 May 1996 . Xs . High order harmonics can result in significant energy losses. 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. The voltage notch depth should be limited to a maximum of 20 percent. Voltage notching and spikes caused by SCR commutation can be controlled by proper selection of the impedance of the input transformer and/or by appropriate snubber circuit design of the line converter. keep in mind the installation of future drives. complicated systems that include PF correction capacitors. All harmonic generators (like drives and UPS). significant shielded cable and a large drive. The first thing to do.1500 Adjustable Speed Drives Electrical Manual Fig. From the impedance diagram and the plant loading history. for simple systems with a single small HP drive. Cable capacitance should be included in the impedance diagram and in the harmonic model. transformers. the computer model can be developed. generators. short circuit and coordination studies. the drive manufacturer can perform the study. 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. The computer model should be developed and various cases evaluated. If the predicted results are higher than the criteria established. The results should be verified by comparing computer results with field data. The plant load history and future load plans should also be identified. The distortion limits should not be set so high that filters must be installed in the next drive to clean up past installations. In some cases. For extensive. in preparation for a harmonic study. May 1996 1500-58 Chevron Corporation . PF correction capacitors. These include load flow. Harmonic acceptance criteria should be established for the input source to the drive. current limiting reactors. 1500-37 Impedance Diagram 1553 Harmonic Analysis The advice of a specialist familiar with harmonic analysis is recommended for all ASD applications. including cases with maximum and minimum source impedance. The diagram should include the utility source and all electrical equipment data for the system. and cable and line impedance should be included. In addition to the traditional studies. When establishing the limits. the computer model can also be used to design a harmonic filter. a computer-simulated harmonic analysis should be performed for all drive applications. a specialist should be hired to perform the study. is to prepare an impedance diagram. and various drive loading conditions. The natural frequency increases as the stiffness increases. the need for this analysis should be considered for any ASD system rated 500 HP and above. Chevron Corporation 1500-59 May 1996 . The oil film usually has the dominating effect on support stiffness. CH-3451-2/94/0000-0261. Consult a mechanical equipment specialist for guidance. and decreases as the mass increases. bearing shells. The rotor system has several natural frequencies which are referred to as the first critical. The rotor can be represented as a mass supported at each end by equivalent support springs.Electrical Manual 1500 Adjustable Speed Drives 1560 Rotordynamic Studies Rotordynamic studies should be considered for all drive systems above 500 HP and for high inertia load applications. third critical. These studies traditionally consist of lateral critical speed analysis and torsional analysis of the rotating equipment train. etc. In general. especially for offshore platform applications. 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. when excited. This concept is shown by the rotor diagram in Figure 1500-38. second critical. and pulsation studies for all positive displacement applications. 1500-38 Lateral Resonance of Two Bearing Rotor and Support System. sliding vane. Positive displacement applications include rotary pumps and compressors (screw. In most applications the first (bouncing mode) and second (rocking mode) critical speeds are of principal concern. bearing pedestals. Additional studies to consider include structural dynamic studies (foundations and support structures). and oil film. eccentric rotor and gear type) and reciprocating pumps and compressors (piston and plunger type). since the higher order criticals are usually well above the maximum operating speed. Used with permission from IEEE PCIC 94. causes a periodic oscillation perpendicular to the shaft. mounting skid. 1561 Lateral Critical Speed Analysis A 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 critical speed or within 20 percent of any critical speed. Fig. A lateral critical speed is the natural resonant frequency of the rotor and support system which. ©1994 IEEE. The support system includes the foundation. The natural frequency is determined by the mass of the rotor and the stiffness of the shaft and support system. 0 x 106 lbs. the frequencies of the first three modes are identified. the rotor must also have some residual unbalance to excite a critical frequency. ©1994 IEEE. Fig. the overhung mass has the most significant effect on the second and higher modes./in. At a support stiffness of 2. the first critical is predicted at 2256 r/min. However. CH-3451-2/94/0000-0261. May 1996 1500-60 Chevron Corporation . just as a mass supported by a spring does not oscillate until it is excited by an impact. Used with permission from IEEE PCIC 94. The normal speed range is 3100 to 5922 rpm.1500 Adjustable Speed Drives Electrical Manual If the motor should be operated at or near one of its critical speeds. The plot represents lateral displacement of the rotor versus position along the rotor when the particular mode is excited. two for the main rotor and one for the exciter. Whether or not vibration associated with operation near a critical is excessive depends on the degree of damping in the system and the amount of unbalance exciting force. 1500-39 Undamped Critical Speed Map. the mass-moment of the coupling half must be included in the lateral analysis model.000 HP synchronous motor ASD at the Pascagoula Aromax Plant. In addition to the rotor mass. In this case. 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. the rotor is supported by three bearings. Figure 1500-39 shows an example undamped critical speed map. the second at 5431 r/min. From this figure. The results of a lateral analysis will be illustrated by example. the consequences are usually excessive vibration levels. This example is the 15. For this motor.. ©1994 IEEE. The highest amplitude responses are above 7500 r/min. CH-3451-2/94/0000-0261. Used with permission from IEEE PCIC 94. the predicted response at the intermediate bearing (opposite drive end) can exceed the allowed 2. API 546 requires each critical speed to be separated from an operating speed by 15 percent. unless the response is well damped. which can be tolerated because it is much Chevron Corporation 1500-61 May 1996 . “Well damped” means the vibration amplitude cannot exceed 1. The rotor response is calculated using unbalance weights defined in the applicable specifications (API 546. For our example.2 mils. and on the coupling. the peak response is 2. In this case. At this location. to excite the rotor system resonances. in this example). well outside the maximum operating speed of 5922 r/min.5(12000/N)1/2 in mils peak-to-peak displacement (one mil = 0. This figure shows the predicted vibration amplitude in displacement versus speed at each of the three bearings and the coupling. 180 degrees out-of-phase at each end of the main rotor.001 inches) where N is the maximum operating speed in r/min. 1500-40 Lateral Critical Speed Analysis with Mode Shapes.2 mils.9 mils at 6900 r/min. the amplitude limit is 2. For this example. with the rotor unbalances as follows: applied in-phase at each end of the main rotor. The damped rotor responses are calculated. However. the worst case is with the unbalances applied 180 degrees out-of-phase and is shown by Figure 1500-41.Electrical Manual 1500 Adjustable Speed Drives Fig. familiar with torsional analysis. Figure 1500-42 depicts the motor.1500 Adjustable Speed Drives Electrical Manual Fig. it is essential that torsional analysis be performed for large systems. of the rotating system components. this rotor lateral response is acceptable. Consult a mechanical equipment specialist. compressor. Damaging torques can occur if the system is excited at one of its natural frequencies. Torsional excitations which must be considered include: harmonic torques caused by the ASD. pump. coupling. CH3451-2/94/0000-0261. consider performing a torsional analysis for any system rated 500 HP and above. in the form of twisting torques. Torsional vibration is the periodic oscillation.0 mils). On this basis. and transient torques from electrical short circuits. i. ©1994 IEEE. a similar-type analysis must also be performed for the driven equipment to avoid operating at a rotor system resonance producing unacceptably high vibration. These excitations must be examined for both startup and normal operating conditions.e. gear. and compressor rotating mass system. 1500-41 Calculated Rotor Response with Unbalance Weights Applied 180° Out-of-Phase at Each End of Rotor. carefully including all sources of excitation. Because of the many potential torsional excitations in an ASD system. less than the minimum bearing clearance (7. Although this example focused on the motor. Used with permission from IEEE PCIC 94. dynamic torques from the motor. May 1996 1500-62 Chevron Corporation . The definition of “large” depends on the nature of the driven equipment. fan. In general. for guidance on all large systems. 1562 Torsional Analysis A torsional analysis is required for all large ASD systems. etc. Harmonic torques produced by the ASD during normal operation are multiples of the converter 12-pulse output. It also identified speeds to be avoided as noted above. 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. For evaluation of torsional excitation caused by short circuits.. 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 harmonic torques would be 6X. This analysis found that torsional natural frequency separation margins and component stress levels associated with torsional excitation were within acceptable limits for the normal operating speed range. the Pascagoula Aromax ASD will be used again. 1500-42 Simplified Model for Torsional Analysis. CH-3451-2/94/0000-0261. coupling. the 2x being caused by the unbalanced nature of the fault. Also. The interference diagram shown in Figure 1500-43 identifies where the excitation frequencies intersect with the torsional natural frequencies. (For a 6-pulse converter. ©1994 IEEE. and 48X electrical output frequency. The ASD can be set to block out the required speeds and accelerate quickly through them during startup. Used with permission from IEEE PCIC 94.) Excitation at the fundamental mechanical frequency and one and two the times electrical frequency must also be considered. 36X. 12X. The separation margin from these speeds must be maintained at plus or minus 10 percent per API 546. so this speed must be avoided. The torque shown is sufficient to cause coupling failure. 24X. 24X. note the intersection of the fundamental mechanical and electrical frequency (1X) with the first torsional natural frequency at 964 r/min (16.07 Hz). etc. This is an operating speed to avoid. As a partial example of the torsional analysis. Chevron Corporation 1500-63 May 1996 . 12X. 18X.e.Electrical Manual 1500 Adjustable Speed Drives Fig. The excitation frequencies are 1X and 2X electrical frequency. i. a phase-to-phase fault normally represents the worst case due to the combined fundamental and second order frequency components. A computer simulated torsional analysis of the entire rotating system (motor. and compressor and gear. For example. when appropriate) is used to predict the torsional 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. because multiple excitation frequencies may excite multiple system natural frequencies. This equipment needs special dynamic consideration. ©1994 IEEE. 1563 Pulsation and Structural Resonance Analysis The advice of a specialist.1500 Adjustable Speed Drives Electrical Manual Fig. 1500-43 Torsional Resonance Interference Diagram. Positive displacement pumps and compressors include reciprocating and rotarytype machinery. Used with permission from IEEE PCIC 94. is recommended for all positive displacement ASD applications. familiar with pulsation and structural resonance analysis. CH-3451-2/94/0000-0261. Use of ASDs in positive displace- May 1996 1500-64 Chevron Corporation . Used with permission from IEEE PCIC 94. is commonly done as part of the platform design. associated with the design of offshore platforms. The following is a summary of the precautionary studies likely to be needed. but it is an emerging technology. ASDs have been applied to some reciprocating compressor applications at 900 rpm. Chevron Corporation 1500-65 May 1996 . 1500-44 Typical Coupling Torsional Response Resulting from Phase-to-Phase Short Circuit with Motor Operating at First Torsional Natural Frequency. 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. ©1994 IEEE. • • • 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 (particularly important for offshore applications) As a result of these studies. Structural resonance analysis. ment applications is relatively rare. and each study is an order of magnitude more extensive than a fixed speed analysis.Electrical Manual 1500 Adjustable Speed Drives Fig. None of these items is a trivial undertaking. Consideration should be given for structural resonance analysis when applying ASDs on offshore platforms. CH-3451-2/94/0000-0261. Thorough testing can help assure a reliable installation with minimum commissioning time. One ASD and motor is operated in the normal mode as a motor. installation and startup. An example is a heat run at rated frequency and a sound test conducted on a saturable reactor for a high speed LCI IM drive application. being proven equipment. Control logic tests are often conducted using the factory test facility motor. protective features and alarms. Although it is costly in both time and dollars to conduct a system test. ASD Production Tests Production tests of the ASD. The other ASD and motor is operated as a generator to provide the necessary load and to generate most of the power requirements of the test. If multiple drive systems are built. The test facility generator provides only the system KW losses as well as substantial reac- May 1996 1500-66 Chevron Corporation . Back-to-Back Testing BTB testing is normally performed at the motor manufacturing facility. these tests are limited to the rating of the test facility motor. normally a unit test cannot be done in the factory. Thorough testing of the entire system is essential when applying ASDs in critical services. should include verification of control logic. The objective is to avoid problems after startup. The ASD should first be tested without the motor. and insulation high potential tests. at the drive manufacturer’s factory. Additional tests should be considered for special auxiliary equipment that may be unique to the application. This is an adequate testing method. However. should be given routine electrical tests required by applicable ANSI standards. the protection and alarm scaling factors must be changed to perform the verification tests. performed at the ASD factory. Tests for Transformers and Reactors The transformers and reactors. If the test facility motor is rated less than the drive.1500 Adjustable Speed Drives Electrical Manual 1570 Miscellaneous Information 1571 System Testing Past problems encountered with ASD applications illustrate the importance of system testing. 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. Final system tests should be conducted during commissioning at the plant site. back-to-back (BTB) testing at the motor manufacturer’s plant should be considered. heat run. it is always worth the cost if in-service problems can be avoided. The motors are arranged in a back-to-back configuration as shown by Figure 1500-45 for load testing the ASD system. Unanticipated problems found and corrected at the factory before shipment to the plant avoid significant delays during commissioning. 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). after the drive and motor have had separate production tests. If a single unit is purchased. 1500-45 Back-to-Back Test Configuration  Caution It should be noted that the back-to-back arrangement is an abnormal configuration for operating the drives. 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. Also. in that one drive is operating in the regenerative mode. In this manner. both the ASD and motor can be operated at rated speed and power for testing purposes. and load versus speed characteristics Verify drive stability and control under all load conditions Perform rated power and speed heat run and determine efficiency Chevron Corporation 1500-67 May 1996 . current balance. a condition which will never exist in service. Fig. The losses can be directly measured for determining the efficiency of the ASD and the motor. it is necessary to avoid tests which cause sudden load changes while operating in the back-to-back configuration.Electrical Manual 1500 Adjustable Speed Drives tive power. the drives are being supplied by the test facility generator which has limited capacity. 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. Thus. resulting from local or remote faults. motor starting. rated current. the full complement of factory performance tests required by API Standard 541 or 546 should be performed in accordance with IEEE and NEMA requirements. up to the 60th harmonic order Verify system voltage disturbance ride through For Induction-motor drives. and slip No load and rated temperature mechanical running tests Rotor unbalance response test to verify critical speeds Sound test Insulation high potential. etc. Voltage disturbances always occur on an electrical system. the rotor is driven to approximately 120 percent of rated speed and allowed to coast down to stop. Reliability problems associated with many previous drive installations have included frequent trips due to system voltage disturbances. With the weights applied. The vibration amplitude and phase angle versus speed from May 1996 1500-68 Chevron Corporation . and polarization index tests Bearing inspection and insulation resistance check Rotor Unbalance Response Test A 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 requires the drive to ridethrough complete voltage interruptions of 0. capacitor switching. Motor Tests For motors. The tests should also require a ride through of a voltage sag to 75 percent of rated voltage and immediately recover. 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. resistance. 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 Disturbance One of the most important tests for the ASD is to test its ability to ride through a voltage disturbance. This test involves intentionally unbalancing the rotor with prescribed weights to excite the rotor critical speeds. power factor.1500 Adjustable Speed Drives Electrical Manual • • Record input and output voltage and current waveforms and quantify harmonic current values on the line and machine converter.5 seconds and a 50 percent sag of rated voltage for two seconds. Electrical Manual 1500 Adjustable Speed Drives each shaft proximity probe is recorded. These procedures. 1572 Commissioning and Startup Comprehensive commissioning and startup procedures should be developed and performed before the equipment is placed in service. The benefits of training those who apply drives will be in the form of reliable short term and long term drive operation. the less complex it appears and the more successful the plant or facility will be at applying the technology. In drive technology. this system should also be verified. either as in-house courses or informal manufacturer-sponsored short courses. The response will clearly indicate the actual location of the critical speed as well as the rotor response to a modest level of unbalance. surge controls (if applied). it operates trouble free without the need for any troubleshooting or repair and requires only annual preventative maintenance. especially for electricians that are less familiar with solid state power Chevron Corporation 1500-69 May 1996 . In any ASD application. Refresher courses should be attended. If the drive is configured with a surge-protection feature. Often. both theory and equipment assembly is quite involved and generally requires continuing education. and troubleshooting drives is necessary for long-term reliable drive operation. The more you know. This should not result in a neglect of training. after the ASD has been installed. servicing. they should be thoroughly tested. 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. if anti-surge controls are included to avoid surge. Training also helps to bridge the gap between new technology and the acceptance to change. 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. motor. and the process control system (PCS). it is essential to consider both normal and unusual operating conditions which may be experienced. All manufacturers of drives provide training for both applying drives and maintaining and troubleshooting. 1573 Training Training of technical and maintenance people involved with applying. driven equipment. For compressor applications. which are essential to minimize future reliability problems during operation. maintaining. 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. Maintenance and troubleshooting training will result in achieving the promoted mean-time-to-repair (MTTR) and mean-time-between failure (MTBF) figures. Training will provide an electrician with the background knowledge necessary to troubleshoot a failed drive. 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. Establishing a good stock of spare parts and maintaining the inventory will determine the repair time. and not maintained as specified by the manufacturer.000 Operations 100 Operations 6 Months 1 Year 5 Years May 1996 1500-70 Chevron Corporation . and deionizers. two x10 and one x100 calibrated probes. even though the equipment may still be functioning with no apparent problems. with one megohm minimum input impedance. This will surely affect reliability.1500 Adjustable Speed Drives Electrical Manual semiconductors. water filters. Coaching from a factory representative can often provide the necessary guidance to identify the failed equipment and initiate the replacement. and checking the drive diagnostic status on a periodic basis. MTTR will always be a function of the spare parts on hand. it is likely that the drive equipment will be “orphaned”. SCRs or transistors). Many drives provide direct diagnostic displays through LCD screens. All digital drives employ extensive diagnostics to aid in correcting many malfunctions that occur in the drive system. If training is not provided to the electricians that generally service and troubleshoot motor controls. Repair will usually be limited to replacing of printed circuit boards (PCBs) or power switching devices (diodes. 1500-46 Service Life of Replaceable Parts Part Air Filters Cooling Fan Large Capacity Electrolytic Capacitors Connect Relays Connectors Deionizer and Filters (Water-Cooled Systems) Resistivity Probes (Water-Cooled System) Rubber Hoses (Water-Cooled Systems) Service Life 1 Year 3 Years 5 Years 500. a clamp-on ammeter with current capability of 2x rated current. a maintenance handbook will be necessary to provide a description of the fault code. Fig. Often. 1574 Maintenance and Spare Parts Maintaining drives is usually limited to changing air filters. 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. Other troubleshooting aids include a true-rms digital multifunction meter capable of 1000 VDC ÷ 750VAC. These parts include the equipment listed in Figure 1500-46. and a dual trace oscilloscope with differential capability. although the MTBF is normally quite high for both PCB and power switching devices. digital storage. liquid flow rates. If application issues related to the electrical system are not sufficiently considered. they can contribute significantly to problems and unreliability of the ESP system. temperature.1600 Design of Electrical Systems for ESP Installations Guideline Abstract This guideline is intended to provide guidance unique to the design of electrical systems for oil-field Electrical Submersible Pump (ESP) installations. depth. and well injection fluids or gases) this guideline focuses on above ground design issues.. Contents 1610 Overview 1620 Power Delivery System 1621 Transmission Lines 1622 Service Voltage 1623 Offshore Systems 1630 Surface Design Considerations 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 1641 ESP Cables 1600-22 1600-5 Page 1600-3 1600-4 Chevron Corporation 1600-1 October 2000 . Downhole operating conditions are harsh and ESPs can have relatively short run lives.g. pressure. Due to the large variation in downhole conditions (e. fluid characteristics. 1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual 1642 ESP Motor 1650 Reliability Considerations 1651 Maintenance Programs 1660 Other Considerations 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 1670 References 1600-30 1600-26 1600-24 October 2000 1600-2 Chevron Corporation . Chevron Corporation 1600-3 October 2000 . 2nd edition. cable support strapping. cable terminators. 1999. 1600-1 Typical Onshore ESP Installation From API RP11S3. Courtesy of the American Petroleum Institute. Power is supplied to the site by an overhead transmission line. cable splices. The major subsurface components consist of power cable.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline 1610 Overview Figure 1600-1 shows a simplified representation of a typical onshore ESP installation. March. interconnecting power cables. a motor controller (either constant speed or variable speed). perhaps a step-up transformer. the down-hole power cable and the wellhead cable penetration. power cable junction box. The major surface components of the installation include a power transformer. Fig. the ESP motor and instrumentation. local utility substation) routing and right-of-way for constructing a transmission line service to the site designing and constructing the transmission line. and October 2000 1600-4 Chevron Corporation . 1622 Service Voltage ESP motors may range in horsepower from 20hp to 1000hp. and power supply delivery voltages have wide range too. If owned by the utility. The engineer is encouraged to familiarize himself with local requirements governing overhead line construction. some consideration must be given to transmission line design. Refer to the Section 1670 References for more information. providing detailed design requirements here for overhead line construction is beyond the scope of this guideline. it is common to provide power to the well site via overhead transmission lines.The power system voltage levels range from 4. The Rural Electric Administration [2] provides a good reference book showing transmission line construction details. Whether the transmission lines are owned by the local utility or by Chevron.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual 1620 Power Delivery System 1621 Transmission Lines Because oil fields are usually located in remote locations with the wells spread out over a large geographical area. Issues such as line capacity and routing to the site will be handled by the utility.16 kV to 34. they will provide service to the well site or field. 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. 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. Because requirements for overhead line construction vary greatly from region to region. Design considerations 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.5 kV. If Chevron owns the overhead electrical transmission system. Power supply voltages range from 480 V to 4. Design optimization must meet the above goals. keep the system voltage low. local power generation is common practice. 5. Chevron Corporation 1600-5 October 2000 . and fluid characteristics that affect reliability. [4. sand or entrained gas.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline • still provides power enough to start a large ESP motor without affecting other equipment on the system (often referred to as stiffness). the need for compactness (low weight and space) of the power supply and drive system equipment. Chevron has begun installing ESPs offshore. Offshore installations differ from onshore installations by: • • • • the need for environmental protection from the offshore marine atmosphere. 1630 Surface Design Considerations Some 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. For more information on these factors. 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. drive controllers are usually concentrated into a small area or room. 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. and keep the cost of building the transmission line reasonable. There are other design considerations that are not discussed in this section.16 KV. They include: • • • ESP pump and motor sizing the suitability of materials of construction for the downhole conditions. refer to API RP 11S series.g. The ESPs would be connected by subsea cables and installed through subsea wellheads. These factors are discussed further in this section. 1623 Offshore Systems Recently. 6. The power system usually consists of a group of generators and the main power supply switchgear. e. Power Quality. Or. short circuit and motor starting conditions. On Chevron owned systems. overvoltage. 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. These can significantly affect power quality (both for the power system and your installation). of the ESP installation will never be any better than the underlying electrical supply. it is important to know the reliability of the power supply system — the ability of the utility to supply uninterrupted power over time. Power Surges and Interruptions Variable Speed Drives. at least within ± 5% of the nominal service voltage or better. Reliability of Power Supply When planning an ESP installation. Utilities monitor and record these conditions and are able to report the number of problems that occur during a year and their duration. short duration loss of power and long duration loss of power. outages are normally recorded and investigated. Also. Lack of this information may indicate the need to install monitoring and recording equipment for a period of time to gather this data. the new adjustable speed drive installation October 2000 1600-6 Chevron Corporation . it is important to computer model the supply system for load flow. other utility equipment such as switches or capacitors may interact with the ESP installation to cause interruptions at the ESP installation. Significant voltage drop during starting conditions may result in some secondary problems such as causing lights to flicker or magnetic starters to drop out. These are caused by lightning strikes. or runtime. 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.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual The ESP manufacturers have computer programs for matching the appropriate type of downhole and surface equipment to the well characteristics. Recent new electric submersible pump installations are almost exclusively variable speed drive. however. undervoltages. Utilities experience overvoltages. Regardless of whether the supply is a utility or Chevron owned system. Results of the modeling studies are used for conductor sizing and equipment rating selection later in the design phases. however. The reliability. switching operations and equipment failures. On occasion. Ability of Electrical Supply to Power the Load Along with reliable service. This is difficult to anticipate or predict unless other installations have experienced these problems. undervoltage and short duration loss conditions may not be. So. an adequate power system is often necessary in successful field operations. must be carefully incorporated into the power system design because they are a source of harmonics and voltage disturbances both to the supply system and to the ESP motor. Use of an adjustable speed drive. the electrical supply at the installation must be within reasonable voltage parameters. Harmonics already on the supply system (from nearby facilities or loads) may interact with detriment to the ESP installation. ESP motors or pumps will often lock up due to downhole conditions and the controller will be used to try to “unlock” it. lightning strikes are so frequent as to require certain minimum equipment at service points. A good reference for learning more about adjustable speed drives is the “Adjustable Speed Drive Guideline for Upstream. An example of such a standard might be. special grounding techniques are needed. 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. consistent. reliable installations. Oil-field Application. These standards are designed to overcome anomalies in the area and to result in safe. “Grounding Design.” Chevron Corporation 1600-7 October 2000 . More information about harmonics associated with variable speed drives can be found in Section 1550. Installation of lightning and surge arrestors is normal for most installations. 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. Just as important as anticipating power system disturbances and harmonics is installing equipment to control these conditions and protect the ESP equipment.” Installing Equipment to Control Power Disturbances. Adherence to Local Requirements and Accepted Standards In the interest of safety. This may be dictated by the local utility or by analysis of isokaronic conditions for the area.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline may cause problems with nearby equipment if the harmonics are not sufficiently controlled. How transient voltage surge suppressors and harmonic filters work is discussed later in this section. These issues will be discussed in more detail later in these guidelines. Or. This topic is very important and is discussed in more detail in Section 1637. it is very important to adhere to local requirements and standards of the utility or Chevron standards developed for the location. because soil conditions in the area may be unusual. Grounding the Installation Grounding 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 includes complete loss of voltage for up to ½ cycle. Harmonics’ amplitudes may be measured using a frequency analyzer. very short duration. lasting less than ½ cycle. caused by capacitor bank switching. 1100. caused by loss of large load or transformer tap changing. very short duration.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual 1631 Power System Disturbances and Surge Protection Types of Disturbances There is a wide and confusing array of power system disturbances that might occur. at normal power frequency. surges — caused by lightning strikes (direct or induced). switching of remote electrical equipment. the following disturbances will become more well known and more important: • notch — a disturbance of the normal voltage wave form. duration from ½ cycle to a few seconds. duration greater than a few seconds. or faults or failures. on the order of 10-100 microseconds. distortion indicates the presence of harmonics. 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. “Emerald Book” [9] has an exhaustive list of different types of disturbances and provides definitions for them. swells — an increase in the system voltage level. 7th. overvoltage — an increase in the system voltage. rms voltage may drop to as low as 15%. Often converter equipment or variable speed controllers are described by their characteristic harmonics so that the Fourier series expansion terms are known. initially of opposite polarity than the wave form and is thus subtractive from the peak value of the wave form. at normal power frequency. voltage distortion — any deviation from the nominal sine waveform of the line voltage. • • October 2000 1600-8 Chevron Corporation . 11th. or operation of circuit breakers and other switching devices in the power system. IEEE Std. Disturbances most often found in the oil fields are as follows: • • voltage sags — caused by faults often at remote locations. harmonics — the deviation from the sinusoidal waveform expressed in terms of the order and magnitude of the Fourier series terms describing the waveform. outage — a complete loss of voltage for a period of time. the order is expressed in multiples of the operating frequency. • • • As variable speed drive controllers are applied more often in the oil field. 13th. etc. the magnitude is expressed as a percent of the fundamental. The failure may be the result of a one-time significant overvoltage or the aggregate sum total of lesser overvoltages. IEEE Red Book. A much more in-depth discussion of insulation system ratings and protections is contained in ANSI/IEEE Std 141. Insulation systems and equipment are tested and certified to the voltage levels specified in the standards. where equipment is subjected to a voltage pulse that increases from zero to peak value in 1. 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. 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 capability is BIL or Basic Impulse Level.2 micro-seconds and declines to one-half peak value in 50 micro-seconds (shorthand for this is 1. take extreme care when selecting the voltage test levels and doing the testing. 1.2 x 50 micro-second voltage impulse is considered a typical impulse associated with indirect or induced lightning strikes.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline Controlling Disturbances In general. The 60.e. the system must: • • • • conduct lightning stroke current to ground safely through shield grounding wires. The voltage stress that appears across a single-turn in a multi-turn coil (i. to control power system disturbances and reduce damage to equipment. The physical arrangement of an insulation system also reduces an insulation system’s ability to withstand over voltages. 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. “Surge Voltage Protection. 4 x 10 micro-second current pulse is considered a typical impulse associated with a direct lightning strike. The 10. and protect equipment from surges and transients with protective devices. They are mentioned here to illustrate the amplitude and the very short duration times of typical voltage transients.” [3] There are several standard test impulses that are used to approximate transient conditions. motor) when a high-rate-of-rise voltage surge occurs is much higher than the single-turn operating voltage.2 x 50). Chapter 4. a large portion of insulation’s ability to withstand applied voltage can be destroyed in the process of testing. 8 x 20 Chevron Corporation 1600-9 October 2000 . Insulation The failures associated with power system disturbances and surges are always insulation integrity breakdowns somewhere in the system. BIL is defined as the crest voltage for a fullwave impulse test. The 1500 amp. 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.000 amp. In all cases. So.000 volt. 1632 Typical ESP System Layout The typical layout of surface located equipment for an ESP installation is shown in Figure 1600-1 and Figure 1600-3.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual micro-second current impulse is considered a typical impulse associated with a system switching operation. Figure 1600-1 shows an installation where the ESP has a constant speed drive.25 x √2 x (2 X Nameplate Voltage + 1000) (2) There are no established. October 2000 1600-10 Chevron Corporation . Figure 1600-3 shows an installation where the ESP has a variable speed drive. protective devices such as lightning arrestors and surge suppressors are added strategically to the system to be the designated point of failure and protect the motor.) Copyright ©1999 by IEEE Basic Impulse Level --. Fig. Figure 1600-4 shows the plan view of a well site and the clearances that must be maintained between wellhead. Red Book Tables 15-18. surface equipment and overhead power lines.BIL Nominal Voltage Rating AC Motors (1) (2) Oil Filled Transformers Enclosed Switchgear Distribution Line 480 V 2300 V 4000 V 12000 V 13800 V 3.9 KV 45 KV 60 KV 75 KV 110 KV 110 KV 30 KV 60 KV 60 KV 95 KV 95 KV 400 KV (1) Motor impulse strength can be obtained from the formula: 1. 1600-2 Comparative BIL Values (Data from ANSI/IEEE 141. 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). the motors on the system are the weakest point. The main difference between the two is the step-up transformer associated with the variable speed drive installation. Therefore. standardized BILs for motors.9 KV 15. This is more often referred to as Impulse Strength and is based on the crest value of the standard high-potential test voltages. Just by glancing at this table you can see that without adequate protection from overvoltage or surge.5 KV 9. Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline Fig. 1600-3 Typical Surface Located Equipment Layout Chevron Corporation 1600-11 October 2000 . 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).1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual Fig. Distribution transformers sizes typically range through 500 kVA (for example three 167 KVA transformers). or high voltage (distribution voltage) as would be the case with a transformer mounted on the ground. or a power type transformer that is mounted on the ground (pad mounted). October 2000 1600-12 Chevron Corporation . as would be the case with distribution transformer. 1600-4 Well Site Plan View 1633 Main Power Transformers Depending upon the size of the ESP. The difference is whether the drop from the pole is low voltage. while power transformers cover ranges above 500 kVA. Transformers are supplied with variable taps in the high voltage winding that allow you to adjust the secondary voltage ± 5%. such as ± 10%. Liquid Filled Transformers Liquid filled transformers are recommended for a couple of reasons: • • they are generally more suited to be mounted outdoors. This type of transformer connection continues to be used in the oil field despite other ways of achieving its main advantage. The delta-delta connection historically gives longer run life than a solidly grounded bank of transformers in this way. The main advantage of delta-delta transformer windings connections is if one phase of the circuit (say the downhole motor cable) becomes faulted. 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. Some voltage drop is expected on the distribution system between the source point (say a substation bus) and the service or load. which can be from 4. is available for slightly higher cost. A wider tap adjustment range.8 KV) are becoming available as ESP controllers but have generally only been applied in special installations. 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. and the BIL of a liquid filled transformer is higher than for dry-type. to 480 volts.5 KV. The main power transformer(s) step the voltage down from distribution voltage. Liquid filled transformers may be filled with several types of liquid insulating fluids. Taps are used to adjust the secondary voltage of the transformers up or down to within the nominal voltage range required by the load. Delta-delta Transformer Windings The usual transformer windings connection for the main power transformer used with ESPs is delta-delta.16 KV to 34.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline In oil fields that are equipped for overhead line work.” and under the single phase fault to ground conditions. the system will continue to operate until another phase becomes faulted. the two remaining phase’s voltage can rise to 173% of normal line-to-line voltage. Refer to Section 800 for more information about transformers. The disadvantages of delta-delta transformer windings are: • • the system is ungrounded so that personnel may be exposed to “touch potentials. the distribution type transformer bank will be more economical. Medium voltage drives (2300 volts to 13. mineral oil based insulating oil is recommended for most applications. Chevron Corporation 1600-13 October 2000 . Input voltage to most constant speed and most variable speed drive controllers is 480 volts. If equipment sensitive to harmonics (for example. Consider main power transformers with a K-factor rating where harmonics are expected and perhaps modeled as part of the system design. and/or designing multiple-secondary windings that are phase shifted for zero sequence harmonic current cancellation.17. such as open deltas and tee connections. Transformers Feeding Variable Speed Drives For 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%. single phase transformers may be connected in various combinations of size and impedance.75%. Banked single phase transformers saturate and overheat when harmonic currents are present on their neutral paths. This will help ensure good voltage regulation on the transformer secondary.6) as the better selection for a variable speed drive system. • Pad mount transformers where the transformer’s windings are on a single core are recommended by IEEE Std 1100 (9. because they also saturate and overheat when harmonic currents are present on their neutral paths. October 2000 1600-14 Chevron Corporation . • • • K-factor Rated Transformers Transformers 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. there will be less contribution to sine wave distortion if harmonics are present. transformers with K ratings should be considered. insulated secondary conductors wired in parallel and transposed to reduce the heating from the skin effect and associated AC resistance. If distribution transformers are used. Pad mount transformers generally have a standard impedance of 5. This should be monitored and avoided if possible. Also. Avoid unconventional connection of transformer banks. a control system power supply) is connected to the main transformer bank along with a variable speed drive.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual Specifications and data sheets for purchasing power transformers are available in Volume 2 of the Electrical Manual. A solution is available for this problem but it is not yet proven. with a high resistance grounded secondary. very close to the distribution transformer bank. Implementing a high resistance ground system involves installing a high resistance ground module either next to the service pole. In particular. please contact the CRTC Mechanical and Electrical Equipment Group. Standard K-factor ratings are 4. Alternative Grounding Method As mentioned earlier. the normal winding connections for the main power transformers are delta-delta. 20. 30. variable speed drive controllers or other nearby equipment such as capacitors can amplify the surges or cause resonance at the high surge frequencies. Also. 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. 1634 Lightning and Surge Protection As shown in Figure 1600-2. The more practical way Chevron Corporation 1600-15 October 2000 . If you are willing to consider or are considering using a high resistance grounded system to feed an ESP. The best way to protect ESPs is to eliminate exposing the ESP and surface equipment to transients and surges. 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. 9. 40 and 50. 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. The K-rating required can be calculated from formulas in IEEE Std 1100. An alternative winding connection for the transformers that should be considered is delta primary. a transformer should have a K rating of no more than 9. Practically. The module could be installed next to a pad mount transformer. downhole cables. 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. the BIL for motors is very low as compared to other equipment on the system. those downhole instrumentation packages that have “non-dedicated conductors” (they use the power conductors to carry the instrumentation signals to the surface). This is a long standing oil field practice but is not in step with good electrical system design practice. 13.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline 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. A high resistance grounded system could be installed with a variable speed control system but there are additional issues related to harmonics control to be considered. the long length. or next to the controller (on a constant speed system). This is not feasible since some of these conditions are inherent with the equipment that is used in power systems. One inherent problem with a grounded (solid or high resistance) system is it may “ground out” certain downhole instrumentation packages. 2 2. for Metal Oxide arrestors)(1) System Type Nominal System Voltage Voltage Line to Line Voltage Line to Ground Ungrounded or Resistance Grounded Rating MCOV(2) Solidly Grounded Rating MCOV 2. (See Figure 1600-5. 1600-5 Voltage Ratings of Arrestors Usually Selected for Three-Phase Systems (From Table 21.4 4.2 3.9 (1) All numbers in KV (2) MCOV = maximum continuous operating voltage Surge Suppressors A Surge Protection Device (SPD) should be installed on the secondary side of the transformer bank (API Recommended Practice 11S3 Second Edition.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual is to direct the surge energy to protective devices and dissipate the energy to ground. This protects the transformers and connected equipment from high energy lightning strikes. If a pad mounted transformer is used.9 19. 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.0 9. TVSSs are also designed to reduce the lower energy surges that make it through the lightning arrestors. 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.38 2. The majority of transients are usually due to remote switching and contactor operation. SPDs are often referred to as Transient Voltage Surge Suppressors (TVSS). controllers and ESP cable/motors.) Fig. March 1999) [6].16.7 3. October 2000 1600-16 Chevron Corporation .5 13.8 34.7 4.0 10 27 2. TVSSs operate much like lightning arrestors in that they absorb and divert energy from surges that exceed their voltage threshold. Lightning Arrestors Lightning arrestors should be installed on the primary side of distribution transformer banks.7 10. transformers.3 2. This reduces overall maintenance on VFDs. 15 15 36 2.9 2.5 12. and switching within the field.62 8. mount the lightning arrestors on the last pole (often called the service pole) before the circuit goes into the conduit feeding the transformer.54 7.7 12. 12.4 7.47 21. The ANSI/IEEE Std 141.2 7. The two most commonly used devices are lightning arrestors and surge suppressors. Surge suppressors are used for ESPs and are designed to handle high-energy surges such as direct lightning strikes.7 29.5 1.16 12. and the vented junction box through the wellhead penetrator downhole to the ESP motor. Different types of cables are used in these interconnections. Local conditions would normally dictate the capacity required for the TVSS. the TVSS should be electrochemically encapsulated and must not deteriorate with surge activity. 3 wire plus ground.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline In general. The cable is usually installed in conduit down the pole to the controller. The cable has an overall PVC outer jacket. Typical cables used for 600 volt service may be used. etc. single conductor cables or the three-conductor type MC cables each need Chevron Corporation 1600-17 October 2000 . the line to ground surge values will be greater than the line to line surge values. When comparing and applying TVSS. Connections to the TVSS should be as short and straight as possible. 1635 Surface Power Cabling Power cable is used to conduct the power from the main transformer bank to the various equipment in the ESP system. Note that this is the nominal system voltage RMS. TVSSs are installed between each phase conductor and ground and between each phase conductor and phase. but measurements of the actual level may not be available. specification properties should be considered: let through voltage. As a result. The clamping voltage of the TVSS should be in the range of 110%-125% of the nominal system voltage. Voltages vary depending on switchboard/motor or VFD/motor. The sheath is usually helically wound. or. Also. Most TVSSs should be fused to ensure they are removed from service if leakage current gets too high. A registered laboratory should provide performance testing for higher voltages. voltage ratings. The three. TVSSs must be tested and rated according to UL-1449 second edition [13]. These ratings should be as tested values in accordance with UL 1449 second edition or authorized laboratory. Common types are three. no neutral. frequency. TVSSs with capacities of 100KA to 240KA should be used. lightning induced surges produce surges of the same polarity on all three-phase conductors. or an armored cable such as type MC cable. Line impedance can affect performance of the SPD. each individually insulated and enclosed in a metallic sheath or armor. Type MC cable is three single-conductor cables that are assembled together. the controller to vented junction box. single conductor cables. TVSSs installed with ESPs should have a very high surge current capacity. Joule energy. On an ESP. which is applicable up to 600 volts. Main Transformer to Controller The power cable used to connect the main transformer bank to the controller usually operates at 480 volts. TVSS must also protect line to line in order to limit associated switching voltages. To protect line to line and line to ground. interlocking aluminum. such as 1000 volts to 4160 volts. all systems are 3 phase.41 [14]. the TVSS should be suitable for a Category C environment per IEEE C62. Cable connects the main transformer bank to the controller. peak surge current capabilities. Normally this section of cable should be round. The operating voltage of this cable is the same as the operating voltage of the ESP motor.” However. Optimally. If the main transformer is pad mounted. or a continuing portion of the downhole cable that passes intact through the wellhead — like through a gland. If medium voltage cables are used. the power cable from the overhead line to the transformer will need to be selected for the voltage of the overhead power line. often dictates that downhole cable be used. The operating voltage of the cable is usually the same as the operating voltage for the ESP. such as by being placed in a trench. The medium voltage cables may be shielded or non-shielded. or covered as though it were a permanent installation. Vented Junction Box Through/To Wellhead Penetrator This section of cable may be a short section of cable that terminates at the wellhead penetrator. 25 KV or 35 KV class. excess lengths of downhole cable are just coiled above ground. Excess cable should be cut off and removed.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual to be installed in conduit (for support) down the pole to the controller. Too often. Downhole cable is not approved for this “service. cables having a 133% insulation level should be used. By code. flat cable is often seen when this section is an extension of the downhole cable. Controller to Vented Junction Box The cable connecting between the controller and the vented junction box is usually a short section of round cable or single conductor cables in conduit. practicality (usually the desire not to have a splice at the wellhead). the lower the current flow for the same horsepower ESP. However. this section of cable should not be downhole cable. this cable section should be buried from the vented junction box to the edge of the wellhead cellar. If local practice is not to do this. medium voltage type MC-type cable rated to 5 KV. the cable most often used is non-shielded. Give particular attention to bonding equipment together properly and to the minimum bending radius of the cable whichever type of cable is used. and just left on the top of the ground. the cable should at least be physically protected. The higher the voltage. Both the MC-type cable and conduit should be direct buried. October 2000 1600-18 Chevron Corporation . These would typically be medium voltage cables of 15 KV. Cables normally used for this interconnection are: low voltage MC-type cable rated to 600 volts. Code issues relating to this cable would generally center on providing adequate physical protection for the cable. so the cables very often are medium voltage cables. and. The conduit may be rigid steel or plastic. either low voltage or medium voltage single conductor cables installed 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. especially if drill rigs or other heavy equipment might need to travel over it. Three single conductor cables of the appropriate voltage class would be installed in conduit and connect the overhead line to the pad mount transformer. 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 six pulse drives are noted for their very high harmonics content and very low power factors. Care must be taken however.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline 1636 Drive Choices Fixed Speed or Constant Speed Motor Controllers By far the most utilized ESP motor starter used within Chevron is the across-theline pump panel or controller. However. a new technology drive using Pulse Width Modulation (PWM). The pump panel or constant speed motor controller consists of a fused disconnect. This switching causes notches in the voltage waveform. Variable speed drives improve system efficiency when well productivity data is unreliable or uncertain and the ability to vary speed makes operation more flexible to adapt to changing well productivity conditions. The sophisticated controllers are electronic and monitor motor conditions. when applied in power systems. such as overload. The rectifier bridges were normally silicone controlled rectifiers (SCRs) and each one is switched on/off during each cycle. The contactor within the controller gives the operator the ability to start and stop the ESP. such as overvoltage. underload and current unbalance. There are a number of application issues that need to be considered when variable speed drives are used. there is more to be concerned about in the power waveform going to the ESP. Voltage levels for pump panels range from 480 volts to 3300 volts. if groups of six pulses drives may be used. 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. began to be used with ESPs. Since line frequency (60 hertz) from the power source is directly supplied to the pump. But. The Centrilift Electrostart Pump Panel is an example of this type of controller. The PWM uses very fast switching techniques on the drive output using Insulated Gate Bipolar Transis- Chevron Corporation 1600-19 October 2000 . The controller may range from basic — monitoring overload conditions and shutting down — to sophisticated. Variable Speed Drives In most recent ESP applications. These early drives are so-called “six pulse” drives. the pump will run at a constant speed. They are characterized by a three-phase rectifier bridge as shown in Figure 1600-6. “IEEE Recommended Practices and Requirements for Harmonics Control in Electrical Power Systems” [10] as standalone units. Variable speed drives have been available for ESP use since the late 1970’s. their harmonics (as seen by the power system) are much less and in fact meet IEEE-519 as standalone drive units. The “brains” of the pump panel reside in the controller. sometimes the effects of their high harmonics can be controlled. controls and monitoring devices and an overall outdoor type enclosure. which in turn causes harmonics. This technology improved on the harmonics issue compared with six pulse drives. In the mid-1990’s. a contactor. “Pulse” refers to the number of pulses (or peaks) in the DC output voltage in one cycle of the supply voltage. and incoming power conditions. the petroleum engineers recommend that variable speed drives be used. undervoltage. Six pulse drives do not meet the requirements of IEEE-519. voltage unbalance and reverse phase rotation. When using PWM drives with ESPs.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual Fig. The amplitude of the harmonics is reduced but they occur (or are a concern) at higher frequencies (harmonic orders). one connected delta-delta and the other connected deltawye. the downhole cable and the ESP motor. Two input transformers or two windings from one transformer (Figure 1600-6) are used. This causes some self-canceling of the harmonics and reduces the amplitude of October 2000 1600-20 Chevron Corporation . The newer PWM drives have a means of tuning (raising or lowering the carrier frequency) to avoid system resonances. These fast switching transistors also cause notches in the waveforms which result in harmonics. always check the cable length with the ESP supplier to see if harmful resonances may occur. 1600-6 Three-Phase Rectifier Bridges tors (IGBTs). Twelve pulse drives are very common. These higher frequency harmonics can often excite resonance between the drive. 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. Chevron practices and IEEE Emerald Book. Surge arrestor and TVSS recommended practice is for all leads to be short and avoid sharp bends in the conductors. Buried grounding conductor should be #4/0 AWG. A good grounding system will also provide personnel protection in the event of line to ground faults. Minimum ground conductor size (not buried) should be #6 AWG. Ground wires to lightning arrestors should be as large diameter as feasible. PWM drives have better torque control at lower speeds and may have better success in starting and running in problematic wells. Chevron’s practice is to ground conduit and equipment directly to the well casing as well as to a ground rod. bolted or compression connections may be necessary. Any time grouping of ESPs is considered. • • • • • • Chevron Corporation 1600-21 October 2000 . use chemical treatment around the ground rods to achieve ground resistance as low as possible. If the plan is to have only one drive on a system. Preferably closer to 1 ohm. perhaps “grouped. 1637 Grounding Design Grounding at an ESP installation is very important. A typical grounding system for an ESP installation is shown in Figure 1600-7. Avoid sharp bends. Exothermic grounding connections are preferred. The ESP supplier may recommend a PWM drive be used because of downhole conditions. do harmonic modeling to try to predict any harmful effects from the harmonics. Ground current should be checked periodically with a ground resistance tester. If more than one ESP is planned.” A few guidelines for good grounding practice are as follows: • • Resistance to ground must be 5 ohms or less. The figure is based on NEC requirements. A low resistance ground is most important to allow the lighting and surge arrestors to adequately protect the installation from external lightning and surges. Periodically inspect bolted or compressed connections to be sure connection integrity is maintained. The recommended drive to use will depend on a number of factors. However. If one ground rod does not achieve 5 ohms or less. Or.” twelve pulse drives should be used. the six pulse drive can be used. “IEEE Recommended Practice for Powering and Grounding Sensitive Electronic Equipment.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline the harmonic orders. Drives are now available with much higher pulses (over 30) to reduce harmonics to negligible amounts. use a triangular arrangement for ground rods in accordance with standard drawings to try to achieve low resistance. refer to Centrilift’s “9 Steps.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual Fig. For more information on sizing and selecting an ESP for your application. refer to the IEEE Emerald Book. 1640 Sub-Surface Design Considerations It is not within the scope of this guideline to discuss sub-surface design issues in detail. For particularly sensitive installations. 1600-7 Typical Grounding System • Be careful of conduit and ground conductors near piping if the piping has insulating flanges. Contacting the pipe with the conduit or ground conductors may short out the effects of the insulating flanges. All the manufacturers have computer programs that may be used for sizing ESPs.” [15] a brochure which takes you through Centrilift’s nine-step process for sizing and selecting ESPs. refer to API-11S4. October 2000 1600-22 Chevron Corporation .” Also. ESPs are normally selected jointly by the petroleum engineer and the manufacturer based on well flow and field conditions. having the manufacturer review the design and select an ESP using the computer is recommended. “Recommended Practice for Sizing and Selection of Submersible Pump Installations. 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. In fact. a barrier or tape shield (optional). In round cable construction. Well conditions will dictate the appropriate material selection. a jacket (over all three conductors in a round cable. “IEEE Recommended Practice for Specifying Electric Submersible Cable-Ethylene-Propylene Rubber Insulation.” and API RP1156: “Recommended Practice for Testing of Electrical Submersible Pump Cable Systems. mil Average 3 KV 5 KV 75 90 Minimum 68 81 The maximum conductor operating temperatures for the cables are as follows: Maximum Conductor Operating Temperature(1) Thermoplastic (Polypropylene) Thermoset (EPDM) 205°F 284°F (1) Note that this table shows the maximum conductor operating temperatures as noted in the IEEE standards. All of the materials must be selected in order to be compatible with environmental conditions downhole. Manufacturers make cables that can operate at temperatures above these maximums. The armor provides mechanical protection during installation and removal from the well. over the individual conductors in a flat cable) and an overall jacket. The first choice cable should be round cable. 1018. some are noted to be suitable up to 450°F. This cable may be either round or flat.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline 1641 ESP Cables The ESP cable is the cable which runs from the surface mounted controller or drive to the ESP motor downhole. Armor is available in most any type of material from galvanized steel to Monel. depending on the room left in the annulus between the tubing string and the well casing. Cable insulation thickness for cable insulated with either type of insulation is as follows: Wall Thickness. The cable consists of a copper conductor.” Armor selection is just as important to a cable’s integrity as insulation selection. gas attack and corrosion are paramount in selecting the cable. since the supply voltage will remain balanced to the motor terminals. Refer to IEEE Std.” IEEE Std 1019. Where long lengths of flat cable are installed. armor provides mechanical strength to confine swelling of the cable Chevron Corporation 1600-23 October 2000 . Cable insulation is available in two types: thermoplastic (polypropylene being most common) and thermoset (ethylene-propylene diene monomer [EPDM] being most common). “IEEE Recommended Practice for Specifying Electric Submersible Pump CablePolypropylene Insulation. Resistance to organic chemical attack. the phases of the cable should be transposed along the length so as to keep the motor terminal voltage balanced. insulating material. which prevents entry of well fluids into the motor at the drive end. The armor helps prevent the cable from being crushed under the bands. some ESP motor windings are epoxy filled in the slots and end turns. Some of these motors can be 30 feet in length. To connect the motor to the power supply. More importantly. there is a special motor lead cable. ESPs average 2-4 year runs. Where surface equipment can be expected to run 8-10 years. equalizes pressure inside the motor with the well bore pressure. which extends from the connection at the motor winding to above the end of the pump. electrically insulate the motor and conduct heat from within the motor. 1650 Reliability Considerations Downhole electric submersible pump systems normally have shorter run lives than their surface counterparts due to the hostile environments they are exposed to. The motor lead cable and the downhole power cable are spliced together above the pump where there is more room. Each motor is filled with a light mineral oil in order to seal it.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual during decompression as the cable is pulled. Guards are usually placed over the motor lead cable to protect it from damage when the pump is raised or lowered into the well. the motors must have turn-to-turn insulation to give it better protection against voltage transients. The tubing may be used for chemical injection or well monitoring purposes. This provides more insulation and support (rigidity) for the winding. Cables are also available which have capillary tubing incorporated into the armor. The motor has a seal section. The seal section also contains the thrust bearing for the pump and is the main connection point between the motor and the pump. and compensates for the expansion and contraction of motor oil due to heating and cooling when the motor is running or shutdown. lubricate the bearings. Chevron experiences on average 2-2. 1642 ESP Motor An ESP motor is unlike a motor you would see for use on the surface. Yet these motors can supply 400 HP and more. Banding of the cable to the production pipe or tubing supports the cable. Older motors or perhaps rebuilt motors may only have varnish coated windings and they may not have turn-to-turn insulation. Like many surface motors. It must be very small in diameter in order to fit into the well casing. 1651 Maintenance Programs The most effective maintenance programs combine three efforts: October 2000 1600-24 Chevron Corporation .5 years run lives in most fields. Intervention 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. This cable is normally flat and may have a special profile different from a flat downhole cable. The well fluids passing the outside of the motor during operation provide cooling. Provide adequate power system disturbance protection for the ESP system as discussed in the sections above.” 5. Monitor re-installs of ESP systems. “Recommended Practice for Electrical Submersible Pump Teardown Report. The teardown report is one way to approach root cause failure analysis. tubing failures.” This reporting system or something similar is widely used within Chevron. Often new equipment is not tested or run before equipment is shipped. Formal reporting and documenting of power problems needs to be done. Chevron Corporation 1600-25 October 2000 . The mechanical failures and some of the electrical failures lend themselves to being solved using modern maintenance monitoring and predictive maintenance techniques. A few testing standards exist such as API Recommended Practice 11S2. 40% are electrical and 20% are a host of things including design or application problems. Monitor the materials used and replaced during an ESP rebuild. Monitor the cable splicing and reduce or eliminate splices from the run downhole. Use supports over the cable if required. 3. Install the correct number of bands. Do not tighten the bands so tight as to crush the cable. Root cause failure analysis is critical to the basic understanding of why the system is failing and provides information for solving the failure problem. Properly handling of the cable and tubing reels must be done in order to avoid damage and assure integrity. 2. Using the right equipment is necessary also to avoid damage and to safely increase speed of the work. etc. changed fluid characteristics. and operating information and failure outage information. A few recommendations follow: 1. Before accepting new ESP equipment or rebuilt ESP equipment. “Recommended Practice for Testing of Electric Submersible Pump Cable Systems. test them for proper operation. Electrical failures in the ESP are often the result of other power system problems. “Recommended Practice for Electric Submersible Pump Testing” and API Recommended Practice 11S6. Tracking materials. A teardown reporting system is described in API Recommended Practice 11S1. usually computerized. About 40% of ESP failures are mechanical. and knowing what materials have failed in the past are critical to solving mechanical problems.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline • • • the pump teardown and teardown reporting a maintenance management system. scaling. 4. knowing what material is on-hand. Monitor electrical failures in the same way along with correlating failures with system disturbances at the surface. Combining teardown reporting with a maintenance management system can resolve very difficult ESP problems. 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. This is particularly true if the ESP population is large or expanding. Electrical noise from the motor historically has interfered with analog data transmission. refer to Chevron Technical Memorandum 99-16. CPTC 1999 Portfolio Deliverable (WP-11B Deliverable 3): “Evaluate Downhole Monitoring Systems” revised October 11. With the DC power cable signal. the motor may not fail immediately but failure is imminent. Flowmeters downhole are being installed in some offshore applications. 1660 Other Considerations 1661 Downhole Monitoring Systems ESP systems often include downhole monitoring devices to provide information on pump or reservoir conditions. These filters or traps are located within the drive unit or stepup transformer cable termination compartment.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual 6. Electrically test the cable to see if it could be reused. The measurements most often taken with monitors (or gauges) are: downhole pressure. it is starting to be recognized that near real time monitoring of the pumps and equipment is necessary to maintain production levels near optimum. Data about ESP October 2000 1600-26 Chevron Corporation . motor operating temperature can easily be one of the downhole measurements that are taken. and electrical noise from any of the ESP equipment interferes with wireless data transmission. With a dedicated data line. the dielectric strength drops. If water or well fluids enter the motor. An additional type of sensor being used monitors the dielectric strength of the oil in the motor. a separate wire pair is run along the outside similar to the power cable. [20] 1662 Supervisory Control and Data Acquisition (SCADA) With ESP systems. The preferred method of data transmission from these devices is in digital format. The two methods used for downhole monitoring devices are DC power cable signal and dedicated data line. With a dedicated data line system. Do not cut downhole cable as it is removed and expect to reuse that cable with a lot of new splices. Cable and other equipment may be reused but it should be reconditioned and stored properly between uses. One of the benefits of this system is that monitoring devices are isolated from the ESP motor and electrical system. Filters or traps at the surface pick up the sensing device signal and provide a reading. When fluid intrusion is sensed. 1999. downhole temperature and motor operating temperature. With the DC power cable type system. the sensing device information is impressed on the star point of the electric power cables at the motor. the motor can be meggered with this type of system. For a more complete discussion and evaluation of downhole monitoring systems. since the monitors are separate from the ESP system. If pump problems develop or anomalies in the data are detected. Not all information controlled and monitored by the ESP drive controller is gathered by the SCADA system. The ESP may be only monitored (send information only) or the ESP may be monitored and controlled (send and receive information) by the master station. The typical way for data to be transmitted is by radio over a field-wide monitoring system.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline operation is gathered by the SCADA system and then saved or displayed for engineering and management use. As mentioned earlier. 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. failures of equipment such as transformers. monitoring 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. 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. eventually all the data gathered and evaluated by the controller will be able to be communicated back to the master station. Chevron Corporation 1600-27 October 2000 . 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. Other methods for data gathering could be fiber optic network or twisted pair network. Some of the parameters most often gathered and used in a SCADA system are as follows: Voltage A Phase Voltage B Phase Voltage C Phase Current A Phase Current B Phase Current C Phase Running Frequency Number of Starts High Pressure Switch Status Casing Pressure Tubing Pressure Fluid Temperature Pump Status (On/Off) Flow As controllers continue to improve and SCADA system capacities continue to increase. 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. it is very important to be aware of harmonics and the need to control them. operators usually go to the ESP location and review all the data within the controller historian. Once the data is gathered it can be used in any number of ways to improve operations. If not anticipated. the typical six-pulse drive does not meet the harmonic level requirements of IEEE 519 for a source without other mitigating considerations. a delta-wye transformer has 30 ° phase shift and special transformers with 15° phase shift may be needed. 3. In particular. consider doing the following: 1. However. Do not install power factor correcting capacitors without careful consideration. the capacitors may set up a resonance with the drives and both will fail. some additional filters may need to be installed on the power source to further reduce the harmonic levels. Under practical conditions this is probably not very often. Connecting drives to look like twelve pulse drives needs to be done with caution since harmonic content from a drive will vary with load. Have a harmonic power system model done to model the proposed system. In some cases. in remote locations. A delta-delta transformer has no phase shift. or. However. installing power factor correction capacitors may be needed to improve the ability to match the generator size with the load. If the drives have significantly different loads (or transformer sizes vary) the harmonic problem may not be solved. Even though harmonics levels from the drives may be low. For information on power system analysis and harmonic analysis. Worst case scenarios can be investigated and mitigation plans can be evaluated. The amount of VARs that a generator must supply to the ESPs then becomes the main sizing criteria. Even with twelve pulse drives. may be appropriate since they inherently operate at higher power factor and lower harmonics. When ESPs with variable speed controllers are a significant portion of the load on a generator. do this with caution and after some system modeling has been done to avoid problems with resonance. Use at least twelve pulse drives or connect the drives in such a way that the drive group looks like twelve pulse drives. like a twelve pulse drive or a PWM drive. a single generator may feed an ESP at the well site. refer to Section 200 or Section 1553 1664 Generator Power Supply to ESPs Often ESP installations will be powered by an isolated power system supplied from generators (offshore platform). it then becomes important to know how often the ESP operates at its best design point. Selecting another type of drive. Six-pulse variable speed controllers operate at a particularly low power factor — 65% down to 40% — depending on load. 2. October 2000 1600-28 Chevron Corporation . At the optimum design point for the load the power factor will be the best. Connecting drives to look like twelve pulse drives involves installing isolation transformers that are phase shifting (this way some harmonics will cancel out). 4. a system model for harmonics should be done. there are two concerns: power factor of the variable speed controller and harmonics generated by the variable speed controller.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual When installing groups of ESPs. Use caution and investigate further into the ratings of generators when the variable speed controller load is 25% or more of the generator capacity. the voltage regulator will fail or not operate properly due to the notching and spikes from the harmonics. 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. 6. Generator rotors should be supplied with copper amortisseur bars.5% and 17. It is not uncommon to see generators sized 150% to 200% of full load current to compensate for the factors above. For sizes smaller than 150 KW. 2. the sub-transient reactance should be between 12. In general. They should be oversized to mitigate the effects of skin effect heating and harmonic current heating. the generator sub-transient reactance should be between 15% and 20%. 4. The voltage regulator should contain filtering to protect against system noise or higher order harmonics. Use larger copper bars to counteract torsionals from the 5th and 7th harmonics. 3. Generators are no different. 9. Also. For generator 150 KW and larger. line reactors may be required to limit notching effects. “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. Often a harmonic filter may be required to further remove harmonic content and allow the generator to be a more standard design. The generator exciter should be brushless. 8.5%. Some recommended generator design features to consider when drives are supplied by generators are as follows: 1. the insulation system design should comply with API Standard 546. 5. excessive rotor heating will occur and insulation failures will occur. with a permanent magnet unit and have three phase voltage sensing.Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline As with all electrical equipment discussed so far. Chevron Corporation 1600-29 October 2000 . 10. The stator should have form wound coils and be vacuum pressure impregnated (VPI) during fabrication. harmonics can be harmful if they are not anticipated and the equipment is not made to handle them. the harmonics must be filtered to provide less than the equivalent of 30% negative sequence current. 7. Also. Inter-turn taping must be included. For six pulse drives. If harmonics are too high on a generator. ” IEEE Transactions on Industry Applications. March/April 1987. and Kelly Packard. Steve M. Contact CRTC specialists for more information. Massey.” 1998 ESP Workshop. Centrilift Publication. Section Edition.1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual 1670 References Note Many overhead power system designs are available from past Chevron projects. IEEE Std 519. March 1999. “Transient Voltage Protection for Induction Motors Including Electrical Submersible Pumps. IEEE Recommended Practice for Powering and Grounding Sensitive Electronic Equipment (IEEE Emerald Book) 10. Article 28. 2. 5. 16. 17. 7. “Design and Implementation of a Reliable and Flexible ESP System for the Tohatamba Development. No. 13. Westinghouse T&D Book Rural Electrification Construction Guidelines ANSI/IEEE Std 141. Alfred Comeau.” Power Quality Assurance Magazine.41 15. October 2000 1600-30 Chevron Corporation . 3. Keith Fangmeier and David Shipp. Vol. UL-1449 14. “Brushless Synchronous Machines — 500 KVA and Larger” IEEE Std 1100. IEEE C62. “Power System Design Considerations When Applying Variable Frequency Drives. “Recommended Practice for Electric Submersible Pump Testing” API Recommended Practice 11S3.” 1996 ESP Roundtable. Dillard and Thomas D. “Recommended Practice for Electrical Submersible Pump Teardown Report” API Recommended Practice 11S2. IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems 11. “Recommended Practice for Testing of Electric Submersible Pump Cable Systems” API Standard 546. IA-23. Gregory W. 12. “9 Steps” (Nine step procedure for designing appropriate submersible pumping systems). “Design Solutions for Harmonic Load Current Effects on Electrical Power Distribution Systems. 4. 1. Greiner. “Recommended Practice for Electrical Submersible Pump Installations” API Recommended Practice 11S6. 6. SPE Gulf Coast Section. Lance Grainger. 9. IEEE Recommended Practice for Electric Power Distribution for Industrial Plants (IEEE Red Book) API Recommended Practice 11S1. 8. 2. Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline 18. 20. Lewis and Frederic P. John P. Warren H. “Adjustable Speed Drive Guideline for Upstream.” EC&M Magazine. 19.” 1997. Chevron Technical Memorandum 99-16. McSharry. “Quality Grounding and Power Quality.” 1995 ESP Workshop. CPTC 1999 Portfolio Deliverable (WP-11B Deliverable 3): “Evaluate Downhole Monitoring Systems” 21. Hartwell. Oil-field Application. “Benefits of Properly Installed and Maintained Electrical Surface Equipment. Chevron Corporation 1600-31 October 2000 . Chevron document. February 1996. Kenneth Lacey. Florham Park. 2.. Automatic Switch Co. Asco Facts.) Chevron Corporation A-1 September 1990 . New Jersey (Courtesy of the Automatic Switch Co. Sizing of Automatic Transfer Switches Part I and Part II.Appendix A. 12 (Part I) and Vol. 2. 13 (Part II). No. Vol. No. Appendix A Electrical Manual September 1990 A-2 Chevron Corporation . Electrical Manual Appendix A Chevron Corporation A-3 September 1990 . Appendix A Electrical Manual September 1990 A-4 Chevron Corporation . Electrical Manual Appendix A Chevron Corporation A-5 September 1990 . Pa. P.0 B6.0 Introduction General Description of the Electrical System Power System Considerations Why AC Motor/Captive Transformer Combination? Matching Motor/Captive Transformers with Load System Experience References Page B-2 B-2 B-3 B-4 B-9 B-10 B-11 Paper TOD-72-134. Philadelphia. S. Morton is with the Industrial Sales Division. No. R. Leinberger. Axe is with Atlantic Richfield Company. relaying and grounding systems possibilities. Philadelphia. Denver.0 B3. 1972. Schnectady. pumps.0 B7. Morton Note ©1973 IEEE. September 10-13. power system considerations. Axe. F. Contents B1. General Electric Company. 19145.Appendix B. N. General Electric Company. Chevron Corporation B-1 September 1990 . 1972. and operating experience with installed drives in Atlantic Richfield’s Philadelphia Refinery are covered. Abstract Both synchronous and induction motors driving fans. pp.8-kV motor. approved by the Petroleum and Chemical Industry Committee of the IEEE Industry Applications Society for presentation at the Petroleum and Chemical Industry Technical Conference. A.0 B2. 12345. The economic factors. Vol. Pa. Features of a Power System Incorporating Large AC Motors/Captive Transformers Samuel P.0 B5. and William R. 262-267 (May/June 1973). and compressors (variable 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 13.0 B4. 3. IA-9. A.Y. F. Leinberger is with the Industrial Sales Division. Colo. W. matching motor capabilities to load requirements. Adapted and reprinted with permission from IEEE Transactions on Industry Applications.. Manuscript released for publication December 15. 19102. operate in parallel to deliver power to a continuous operating load of 40 MW.750 hp. For a system of this magnitude.8-kV metal-clad switchgear to the following loads: 1. The ability to produce is dependent to a large degree on the adequacy and continuity of the electrical service.400-V metal-clad switchgear to 16 motors ranging in size from 250 to 1. September 1990 B-2 Chevron Corporation . it was deemed necessary to perform many studies such as voltage drop. relay. Three lines. or is removed from service for maintenance reasons.Appendix B Electrical Manual B1. it is of prime importance that the electrical system be designed to serve continuously. a standard electrical distribution system is not universally applicable. This paper briefly describes a highly reliable electrical system serving a complex of five processing units at Atlantic Richfield’s Philadelphia Refinery.400-V level distributed through a double-ended lineup of 2. Five large motors and their associated captive transformers: 1 1 2 1 2. 13.000 8.500 4. and hopefully unnoticed. reliably.500 hp two-speed induction motor hp induction motor hp brushless synchronous motors hp brushless synchronous motor 21. 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. 7. This cost may exceed the cost of the physical damage to the electric equipment that caused the interruption. short circuit. 1. Electric power is purchased from the utility company at 13. If one line fails.000 kVA of transformer capacity at a 2. Therefore.8 kV. the cost of service interruptions can be evaluated directly in terms of lost production. and stability to determine the feasibility of the conceptual design. it is the intention of the authors to highlight the use of captive transformers1 with large AC motors on this type of system. the remaining two lines are designed to deliver the full load on a short-time basis.000 5.0 General Description of the Electrical System The electrical single-line diagram for the complex is shown in Figure B-1. In many cases. In this paper. A Captive transformer is one that is connected to and supplies only one large motor.0 Introduction The primary objective of any industrial plant is to produce—consistently and economically. B2. Therefore. Since no two plants have identical requirements. This power is distributed through a lineup of 13.000 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 3. The operating demand for this complex is 40 MW. each consisting of single-conductor 2000 kcmil cables. Careful consideration was given to the following to determine the adequacy of the system under steady-state.0 Power System Considerations Atlantic Richfield’s Philadelphia Refinery is historically committed.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. 2) voltage drop limitations. Small capacity transformers located throughout the complex for lighting and instrumentation power are also supplied from these racks. To reduce the voltage drop on the high-voltage 13. and 6) system grounding. The first three of these considerations are interrelated. through its growth pattern over the years. These racks supply power to 200 motors ranging in size from 1/2 to 200 hp. 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.Electrical Manual Appendix B Fig. motor starting. 4) system stability. 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. B-1 Single-line Diagram racks. B3. In this case. and fault conditions: 1) short-circuit capacity. This is shown by the following formula: Chevron Corporation B-3 September 1990 . 3) motor speed-torque requirements. 4) system protective relaying. to the purchase of electric power. 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. 3.3-kV motors. The transformer cost curves in Figure B-2 show dollars per kVA for a 13. The motor cost curves of Figure B-2 show the added dollars per horsepower for 13.000 hp.8-kV system is solidly grounded by the utility company at the source. interphase barriers were installed in the cable terminating compartments and single-conductor metal-clad cables were specified. B4.8-kV ground fault current.Appendix B Electrical Manual % of system voltage drop inrush kVA × 100 = -----------------------------------------------------------------------system S/CkVA + inrush kVA (Eq.6-kV motors.6 percent of the system three-phase S/CkVA. Recognizing this limitation. for a desired maximum voltage drop of 15 percent. Together these two changes resulted in an acceptable voltage drop on the 13. 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. On this system. the design of some system components was modified. magnitude of impedances connecting various rotating devices to the source and to each other. it was possible to reduce the inrush kVA.0 Why AC Motor/Captive Transformer Combination? As previously mentioned.8-kV system is that of economics. Also.or 4. WK2 of the rotating devices. To prevent a phase-to-ground failure escalating to a phase-to-phase fault. This resulted in a considerable increase in the 13. A stability study was performed on this system utilizing a digital computer. the electric utility removed some of the reactors in their incoming lines. B-1) For example. the relaying system was designed to remove ground faults within the critical switching time. relaying time.500 hp. the inrush kVA through the system cannot exceed 17. For motors above 10. the curves apply for 2. Thus it was necessary to carefully consider the ampacity of the ground return paths and the ground fault clearing times. The 13. One of the first questions to be answered about the use of this combination on a 13.0-kV motors. 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. and mechanical loads on the rotating devices.8-kV motors over 2. by utilizing the captive transformer approach. Assuming 1 kVA/hp and September 1990 B-4 Chevron Corporation . the curves apply up to a 6. In addition. System stability is dependent upon several factors: system three-phase short-circuit magnitude. To meet the previously mentioned requirement of increasing the three-phase shortcircuit kVA. the electric utility had the capability for increasing the system threephase S/CkVA from their initially proposed 150 MVA to 328 MVA. it is the authors’ intention to highlight the use of the large AC motor/captive transformer combination in this system.8-kV system.8-kV stepdown transformer to obtain the selected motor voltage. For motors above 2. The curves do show. These advantages.60/hp.20 for a saving of $0. as listed next. the combination inherently has many other major advantages. 1. should be considered and evaluated even where the cost of the combination is equal or slightly higher. This results in a longer acceleration time for a given load speed-torque requirement.20/kVA.40/hp by using the motor/captive transformer combination or a total saving of $18. In addition to the probable economic benefit. a cost comparison can be quickly obtained from the upper set of curves.000. the comparable costs would be $3.40/hp or a total saving of $3. that for the majority of cases there is a potential dollar saving in using the motor/captive transformer combination.500-hp 1200-r/min induction motor drive. Reducing the inrush current also reduces the speed-torque capabilities of the motor.60 and $3. The added cost for a 13. whereas the cost for a step-down transformer is approximately $3.Electrical Manual Appendix B Fig. This reduces the mechanical forces on the motor windings and mechanical parts since these forces vary as the square of the inrush current. This results in a saving of $2. Inrush Limiting: The use of the captive transformer introduces added impedance 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. 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. however.000.8-kV induction motor is approximately $5. B-2 Savings Using Captive Transformers considering a 7. As shown in Figure B-4. there is a greater margin in time between Chevron Corporation B-5 September 1990 . If a similarly rated synchronous motor was being considered. B-3 Speed-torque and Speed-current Curves Fig. and centrif- September 1990 B-6 Chevron Corporation . B-4 Acceleration and Thermal Limit Curves the acceleration time and the motor thermal limits when the captive transformer is used. The standard motor at this reduced voltage will usually produce adequate accelerating torque for variable torque type loads such as fans.Appendix B Electrical Manual Fig. pumps. decrease the possibilities of line-to-ground faults escalating into threephase faults. b. Less System Voltage Drop During Starting: Since the system inrush current is reduced by the transformer/motor combination. It should be noted that other steps may need to be taken in limiting inrush current where more severe restrictions are encountered. With this magnitude of ground fault current it is not imperative to trip immediately on the first ground fault. The higher copper to insulation ratio also results in a firmer coil. a ground fault in each subsystem. Chevron Corporation B-7 September 1990 . approximately 1-2 A. of course. with a high degree of sensitivity. Thus. prevent widespread burning and subsequent replacement of stator laminations. Grounding: Statistically. This makes it possible to “tailor” the grounding system of each subsystem (captive transformer secondary. 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. This relay can either initiate an alarm or trip. This consideration was of prime importance in this installation. This provides a greater structural rigidity of the coils and end turns. 3. must be checked. there is less voltage drop on the 13. before going ahead with the application. c.Electrical Manual Appendix B ugal compressors starting unloaded. bus duct. 2. a lower than normal motor voltage can be selected during starting and acceleration and then rated voltage can be established when the drive is at full speed. as will be described later. With LTC. an unscheduled outage may be prevented. One alternative would be to specify higher than normal impedance in the transformer. The captive transformer isolates the primary and secondary ground systems. If one options to alarm. Increased Motor Winding Strength: The lower voltage motor inherently requires a greater copper cross-section. 4. and associated motor) independent of the primary system grounding considerations. This. Adding LTC would affect the economics discussed earlier more than added impedance. in many cases. eliminate the need for immediate tripping on the first ground fault with the resulting unscheduled outages of the process. Another would be to use a step-down transformer with load tap changing (LTC). A voltage relay across the grounding resistor can detect. The total ground fault current is the vector sum of these two and is also quite small. it is advantageous to severely limit ground fault current so as to: a. The capacitance-to-ground of this subsystem is quite small. the predominant initial mode of electrical failure in a motor is line-to-ground. but both may be economically feasible.8-kV system. b. consideration should be given to the following: a. consideration should be given to using a self-balancing differential relaying system to protect against phase-to-phase faults in the motor. e) ground faults. d) stalled rotor. September 1990 B-8 Chevron Corporation . If the no-trip option on the first subsystem ground fault is exercised. the determination of which complement of relays to utilize should be appraised with the possibility of equivalent or better protection for less cost. f) single phase. 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. In making this appraisal. c) undervoltage and reverse phase sequence. Relaying: Motor relaying is designed to protect against some or all of the following abnormal conditions: a) overload (thermal). consideration should be given to the elimination of motor differential protection. Figure B-5 shows the relaying selected for the Atlantic Richfield installation. To protect against internal transformer faults. B-5 With the motor/captive transformer combination. b) short circuit. c.Appendix B Electrical Manual 5. g) current unbalance. and h) underfrequency. Motor Protective Circuit Fig. consideration may be given to the use of a sudden pressure relay in lieu of a transformer differential protection. The ground and ground relay alternative previously mentioned results in sensitive ground fault protection for the subsystem. either a more precise check should be made by the transformer designer or a larger transformer specified. If single-phase protection is deemed necessary. it is the consensus of the authors that a less expensive relay system could have been used with comparable results. The motor speedtorque 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. 6. the transformer kVA rating closely approximates that of the motor kVA requirement. This reduces the impact stresses applied to the motor. When the system voltage is returned to normal. the starting limitation is 2 times an hour but in actual practice starts are made only several times per year. switching surges. without single-pole opening devices. at all speeds.) thus reducing abnormal stresses on the motor insulation system. the starting current of any one motor does not represent as much of an overload on the transformer. the computer program facilitates reshaping the torque curves. In the event that the initial motor design does not provide adequate torque margin over the entire speed range. These and many other points should be considered before investing in a protective system. In the motor/captive transformer combination. no switching surges are present directly at the motor terminals. the voltage on the system might be severely reduced or completely lost. Under starting conditions this imposes a sizeable thermal and impact load on the transformer. In Figure B-3 the Chevron Corporation B-9 September 1990 . This curve delineates the acceptable application limits. the magnitude of the inrush current to the motor is reduced due to the added impedance of the captive transformer. 7. The relaying shown in Figure B-5 was selected after careful consideration of the preceding options. In a system of this nature. After several years of trouble-free operation. Consideration must always be given to the starting torque requirements of the mechanical load. For applications outside these limits. Where one transformer serves many motors. B5. With the motor starting contacts on the transformer primary. Reduced Transient Impact Stresses: During abnormal system conditions. be capable of delivering accelerating torque in excess of that required by the load. While this is an advantage. Typical curves for a compressor and the drive motor are shown in Figure B-3. the motor/captive transformer combination acts as a reduced voltage starter.Electrical Manual Appendix B d. etc. Reduced Transient Voltage Stresses: The captive transformer acts as a buffer to any system voltage disturbance (lightning surges. Another important consideration is that of impact loading on the transformer during starting. It is fundamental that the motor must. Figure B-6 shows a transformer application curve for pulsating or short-time loads. consideration should be given to the use of the less expensive negative sequence voltage relay. For applications in this plant. it may also prove to be a problem. the need for a current balance relay should be questioned. The effect of the added transformer impedance can also be noted on these curves.0 Matching Motor/Captive Transformers with Load As mentioned earlier. These were rapidly isolated without undue disturbance to the system. However. The application limits shown apply for pulsating or starting duty even though transformers are designed to withstand bolted short circuits on their secondary which exceed 4 per unit current. The few 13.0 System Experience Five years of very favorable experience with this system indicates that our original design concepts and ideas were correct. it is not expected that they will be repetitive. in the case of short circuits. The voltage drop considerations under actual starting conditions were as predicted. The operation of the motor/captive transformer combination has been trouble free. In retrospect a very workable and nearly trouble-free system was achieved. B-6 Transformer Application Curve B6.8-kV faults that have occurred were in the cables and in the cable terminations. Fig.75 times transformer fullload current and hence is in the approved operating area for a standard transformer.Appendix B Electrical Manual starting motor current is shown as being approximately 3. September 1990 B-10 Chevron Corporation . The interphase barriers proved effective during these fault conditions. “Problems of impact loading on unit transformers supplying chipper motors.” presented at the 16th Annu.0 References F. Pulp and Paper Conf. June 1970.Electrical Manual Appendix B B7. Chevron Corporation B-11 September 1990 . Ristow. J. J.. McCann and R. Memorize No Formula Moon H. Yuen IEEE Conference Catalogue No. 73 CH0769-01A. PCI-73-7 (From Short Circuit ABC by Moon H. E. Yuen. Courtesy of YEI Engineers.) Chevron Corporation C-1 September 1990 . Used by permission of the Yuen Family. Short Circuit ABC: Learn It In an Hour. P. Inc.Appendix C. Paper No. Use It Anywhere. Appendix C Electrical Manual September 1990 C-2 Chevron Corporation . Electrical Manual Appendix C Chevron Corporation C-3 September 1990 . Appendix C Electrical Manual September 1990 C-4 Chevron Corporation . Electrical Manual Appendix C Chevron Corporation C-5 September 1990 . Appendix C Electrical Manual September 1990 C-6 Chevron Corporation . Electrical Manual Appendix C Chevron Corporation C-7 September 1990 . Appendix C Electrical Manual September 1990 C-8 Chevron Corporation Electrical Manual Appendix C Chevron Corporation C-9 September 1990 Appendix C Electrical Manual September 1990 C-10 Chevron Corporation Electrical Manual Appendix C Chevron Corporation C-11 September 1990 Appendix C Electrical Manual September 1990 C-12 Chevron Corporation Electrical Manual Appendix C Chevron Corporation C-13 September 1990 Appendix C Electrical Manual September 1990 C-14 Chevron Corporation Electrical Manual Appendix C Chevron Corporation C-15 September 1990 Appendix C Electrical Manual September 1990 C-16 Chevron Corporation Electrical Manual Appendix C Chevron Corporation C-17 September 1990 Appendix C Electrical Manual September 1990 C-18 Chevron Corporation Electrical Manual Appendix C Chevron Corporation C-19 September 1990 Appendix C Electrical Manual September 1990 C-20 Chevron Corporation Electrical Manual Appendix C Chevron Corporation C-21 September 1990 . Appendix C Electrical Manual September 1990 C-22 Chevron Corporation . Electrical Manual Appendix C Chevron Corporation C-23 September 1990 . Appendix C Electrical Manual September 1990 C-24 Chevron Corporation . Electrical Manual Appendix C Chevron Corporation C-25 September 1990 . Appendix C Electrical Manual September 1990 C-26 Chevron Corporation . Electrical Manual Appendix C Chevron Corporation C-27 September 1990 . Appendix C Electrical Manual September 1990 C-28 Chevron Corporation . Electrical Manual Appendix C Chevron Corporation C-29 September 1990 . Appendix C Electrical Manual September 1990 C-30 Chevron Corporation . Electrical Manual Appendix C Chevron Corporation C-31 September 1990 . 8. 6. permanently attached with 316 stainless-steel hardware to the transformer exterior. The transformer shall be provided with a nameplate of non-corrosive material. 2. polarity. NEMA 4 enclosure (TENV). Terminal boards for the terminal leads and taps are not acceptable. information on voltage taps. D2. These brackets shall be welded in place. The transformer shall operate at 60 Hz. 4.0 General 1. Both the primary and the secondary lead wires shall have a minimum working length of 12 inches and shall be of the flexible. and the temperatures rise for the insulation system. 9.Appendix D. Properly-sized grounding lugs shall be provided both inside and outside the case. or equivalent. Chevron Corporation D-1 September 1990 . 10 gage. 316 stainless-steel. 5. The enclosure shall have lifting eyes with closed holes to allow for either a onepoint or a two-point lift. serial number. 11. 10. The transformer shall be capable of supplying a continuous load of ________kVA without exceeding an 80°C temperature rise above 40°C ambient temperature. class of insulation. Gaskets shall be secured with 316 stainless-steel hardware. The wiring compartment shall be at the bottom of the enclosure and shall contain ample space for field connections. phases. 3. These lifting eyes shall be welded in place. Minimum Requirements for Dry-Type Transformers D1. The name plate will state the manufacturer. Epoxy-encapsulated units are not acceptable. The enclosure shall be provided with mounting brackets to allow (rack or floor) _________ mounting with a minimum of four bolts. The wiring compartment (not the cover) will be utilized by the Company for the installation of hubs. rated kilovolt-amperes.0 Ratings 1. Front panels shall be separate for the wiring compartment and for the core and coil compartment. frequency. percent internal impedance. model number. The coils and the lead wires shall be made of copper. 3. primary and secondary voltage. Primary (high) voltage shall be ________. multi-strand type. The transformer shall be totally enclosed in a non-ventilated. 7. 2. Audible sound levels shall be in accordance with NEMA guidelines. Connection type (wye/delta.Appendix D Electrical Manual 4. 4. 6. etc. Full Capacity taps for 90%. 9. A wiring diagram. Each transformer shall be shipped in an individual wooden crate durable enough to withstand normal shipping methods. 7. 95%. The lead wires shall have a 115°C silicone rubber insulation.0 Shipment 1. 8. dimension print and approximate weight shall be approved by a Company Representative prior to manufacturing the transformer. Secondary (low) voltage shall be ________. 100%.) ______. 5. The insulation shall be resistive to the effects of salt water and alkaline mud or a combination of these two agents.0 Insulation 1. 105% and 110% rated voltage on the primary. 3. 2. 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 manufacturer. D3. The transformer shall be subtractive polarity. Number of phases ________. D4. Powdered mica held in a suspension of a silicone varnish will not be acceptable as an insulation material. September 1990 D-2 Chevron Corporation . 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. 2. Installation Practices for Cable Raceway Systems The Okonite Company. 1988 (Courtesy of the Okonite Wire and Cable Company) Chevron Corporation E-1 September 1990 .Appendix E. Appendix E Electrical Manual September 1990 E-2 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-3 September 1990 . Appendix E Electrical Manual September 1990 E-4 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-5 September 1990 . Appendix E Electrical Manual September 1990 E-6 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-7 September 1990 . Appendix E Electrical Manual September 1990 E-8 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-9 September 1990 . Appendix E Electrical Manual September 1990 E-10 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-11 September 1990 . Appendix E Electrical Manual September 1990 E-12 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-13 September 1990 . Appendix E Electrical Manual September 1990 E-14 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-15 September 1990 . Appendix E Electrical Manual September 1990 E-16 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-17 September 1990 . Appendix E Electrical Manual September 1990 E-18 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-19 September 1990 . Appendix E Electrical Manual September 1990 E-20 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-21 September 1990 . Appendix E Electrical Manual September 1990 E-22 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-23 September 1990 . Appendix E Electrical Manual September 1990 E-24 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-25 September 1990 . Appendix E Electrical Manual September 1990 E-26 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-27 September 1990 . Appendix E Electrical Manual September 1990 E-28 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-29 September 1990 . Appendix E Electrical Manual September 1990 E-30 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-31 September 1990 . Appendix E Electrical Manual September 1990 E-32 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-33 September 1990 . Appendix E Electrical Manual September 1990 E-34 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-35 September 1990 . Appendix E Electrical Manual September 1990 E-36 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-37 September 1990 . Appendix E Electrical Manual September 1990 E-38 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-39 September 1990 . Appendix E Electrical Manual September 1990 E-40 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-41 September 1990 . Appendix E Electrical Manual September 1990 E-42 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-43 September 1990 . Appendix E Electrical Manual September 1990 E-44 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-45 September 1990 . Appendix E Electrical Manual September 1990 E-46 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-47 September 1990 . Appendix E Electrical Manual September 1990 E-48 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-49 September 1990 . Appendix E Electrical Manual September 1990 E-50 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-51 September 1990 . Appendix E Electrical Manual September 1990 E-52 Chevron Corporation . Electrical Manual Appendix E Chevron Corporation E-53 September 1990 .