Section 13 — Electrical

Power System Design Practice

IPE Engineering Practice IPE-EP-13-1-1

Document number: IPE-EP-13-1-1 · Section: 13 — Electrical

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SCOPE

This Practice provides design preferences of the Owner in the Electrical Power Engineering design for plants and associated facilities.

This Practice, as normally used, will generate and display information required for development of detailed one line diagrams, overall plot plans, and engineered equipment specifications for the power distribution system.

This Practice will be applicable to both new facilities and the modernization of existing facilities.

All Owner Practices are to be used in conjunction with this Practice to provide the complete detail design requirements.

Any deviation from this Practice must be approved by the procedure described in EP 1-1-3. A revision bar indicates all changes made to this Revision.

REFERENCES

The latest published edition of the following Standards and Codes shall be used with this Practice:

STANDARDS AND PUBLICATIONS

STANDARDS AND PUBLICATIONS (Cont.)

2.1 Trade Standards

The Owner is in general agreement with the published standards of API, CMA, and etc. when equipment or system design can be supplied with increased reliability at a minimal cost above Manufacturer's standard. Where increased reliability per dollar spent is questionable based on the Contractor's experience, the Contractor may propose to the Owner for approval of the deletion of the trade standard or parts thereof.

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Owner Practices

IPE Engineering Practices are to be referenced where necessary on the Manufacturer's and/ or Contractor's drawings and specifications, but are not to be retyped or redrawn.

Where IPE Engineering Practices are not available for a particular situation or piece of equipment, the Contractor is to submit his standard or specification to the Owner for approval. Owner approval for material and/or equipment specifications is required before it is issued for procurement.

DEFINITIONS

Coincident Demand (C.D.) - The sum of two or more demands which occur in the same demand interval.

Contractor - Company or business that agrees to furnish materials or perform specified services at a specified price and/or rate to the Owner.

Demand (D) - The electric load at the receiving terminals averaged over a specified interval of time. Demand is expressed in kilowatts, kilovoltamperes or amperes. The interval of time is generally 15 minutes, 30 minutes or one hour.

Demand Factor (D.F.) - The ratio of the maximum demand of a system to the total connected load of the system.

Diversity Factor (DI.F) - The ratio of the maximum demand of two or more loads to their coincident maximum demand for the same time period.

Firm Load - Data is obtained from actual equipment performance characteristics and duty cycles.

Inspector - A Inflection Point Engineering, LLC appointed engineer or inspector.

Load Factor - The ratio of the average load over a designated period of time to the peak load occurring in that same period.

Manufacturer - The recipient of a direct or indirect purchase order for materials and/or equipment. In this context, a direct order is one issued to a Manufacturer by a Contractor or the Owner. An indirect order is one issued to a Manufacturer by a vendor (recipient of a direct order) for materials, fabricated components, or subassemblies.

Maximum Demand (M.D.) - The largest of all demands which have occurred during a specified period of time.

Owner - Inflection Point Engineering, LLC.

Owner's Engineer - A Inflection Point Engineering, LLC appointed engineer.

Peak Load (P.L.) - The maximum load consumed by a unit or group of units in a stated period of time. It may be the maximum instantaneous load or the maximum averaged load over a designated period of time.

Purchaser - The party placing a direct purchase order. The Purchaser is the Owner's designated representative.

BASIC PHILOSOPHY

• General
• Design of the electrical power system is to be done by qualified electrical engineer(s) in the electrical power distribution and generation field and is not to be subcontracted to a Manufacturer of electrical distribution and/or generation equipment.
• Design of the electrical power system shall be contingent on the proper selection of equipment to meet the electrical area classification for hazardous material where applicable. In general for Class I and II classified areas, the Owner follows the recommended practice of API RP 500. For classified areas, the Contractor is to follow standard industry practice for classifying areas and submit these to the Owner for approval.
• Design of the electrical power system must be approved by the Owner and shall be based on the following items in order of decreasing importance:
• Personnel Safety: All electrical clearances and equipment shall be in compliance with OSHA, the National Electrical Code, and the National Electric Safety Code, and the American National Standards Institute.
• Economics: Electrical designs should stand the scrutiny of being evaluated from an economic point of view. Pre-investment in future electrical facilities must be realistic.
• Future pre-investments in facilities shall meet the requirements as defined in the scope document.
• The Contractor is encouraged to propose to the Owner for approval, pre-investments in future facilities not outlined in the scope documents. Items that should be considered are those where sizeable future costs could be avoided, increases in system reliability can be realized or reductions in maintenance of equipment are possible. Clear and detailed support documentation is a necessity in order to obtain approval from the Owner.
• The most economical grade of electrical equipment shall be used for the application. For example, heavy duty industrial grade equipment for plant process units and commercial grade equipment for buildings.
• In all cases where "equivalent," "approved equivalent," "equal," or "approved equal," equipment is considered, the Owner shall approve the substitution.
• Reliability: Reliability criteria must be defined on a per case basis. In general a two source single failure (N-1 = 1, N=sources) system shall be used in critical applications as defined by the Owner (e.g., Double Ended Secondary Selective Substation). Simple radial systems (N-1 = 0) where a single failure results in power loss may be applicable to less critical applications, as specified by the Owner.
• Maintainability: Electric design shall make maintenance as simple and fail-safe as possible. Assumptions should be made that maintenance capabilities are stronger for low voltage systems than for medium and high voltage systems.
• Simplicity of Operation: Switching of feeders shall be simple and straight forward. Switching arrangements involving the use of key interlocks should be avoided.
• Flexibility and Expandability: Electric designs should accommodate future increases in load by incorporating flexibility and expandability design concepts. Pre-investment should be kept to a minimum to obtain this flexibility.
• Technically Suitable: The electrical equipment and design shall be technically suitable based on short circuit studies, transient stability studies, load flow studies, coordination studies, and existing plant constraints (if any).

• General Design Basis
• Electric Power Sources
• Purchased Electric Utilities: The Owner is responsible for negotiating or obtaining from the utility (with possible technical assistance from the Contractor) such items as voltage levels and regulation, short circuit ratings, multiple incoming feeders (reliability of the utility, capacity or ratings of the incoming feeders), parallel operation of the incoming feeders, automatic transfer (when parallel operation of the incoming feeders is not permitted by the utility), protective relay schemes, rate structures, interconnection of Owner's generation, etc.
• In-Plant Service (Utilization of Spare Capacity): The Owner will be responsible for supplying electrical system data similar to that gathered for the previous paragraph titled "Purchased Electric Utilities". This data will be used by the Contractor as a basis for his design.
• In-Plant Generation (Cogeneration with the Utility): The Owner will be responsible for obtaining utility data and negotiations with the utility. Technical assistance may be needed from the Contractor.
• Standby Generator
• Standby generation is to be supplied if specified in the project scope documents.
• The standby power source will normally be a diesel generator set mounted inside a concrete block or engineered prefabricated building.
• In general, the loads that should be powered from a standby generator are as follows:
• Emergency Lighting
• Instrument Power Supply and/or UPS System
• Communication System
• Control Room Ventilation
• Basic System Types
• Simple Radial System: Load supplied from only one feeder.
• Loop Primary Radial System: Multiple loads tapped from a single feeder. Switches on the primary of the system will allow isolation of trouble on the primary feeder.
• Primary Selective Radial System: Load supplied from two or more feeders; one actively supplying power and the other a spare. Switches are provided for the selection of the feeders.
• Secondary Selective System: System has two buses with each bus being supplied by a different source through a normally closed incoming line circuit breaker. The two buses are connected together by a normally open bus tie breaker with the loads divided between the two buses. Failure of one of the sources will cause isolation of the bus from the source by opening the incoming line circuit breaker. The de-energized bus is then connected to the remaining energized bus by closing the tie breaker. The transfer of the loads from one source to the other can be done automatically or manually.
• Spot Network: System parallels all transformer secondaries.
• System and Equipment Voltages
• Motors: In general, motor system voltage requirements are as noted in Table 1.
• Lighting: In general, lighting system voltage requirements are as noted in Table 2.
• Receptacles: In general, receptacle system voltage requirements are as noted in Table 3.

• Power System Grounding
• Wye Connected Secondary Systems
• Power systems rated 2.4KV and above shall be low resistance grounded with a 400 ampere maximum ground fault current. A possible exception to this would be where an existing plant has an established grounding system of another type and must be used for the new system to make both systems compatible. Ground faults on these systems shall be detected and removed from the electrical system.
• In general, power systems rated below 2.4KV shall be high resistance grounded with a 5 ampere maximum continuous ground fault current. A possible exception to this would be where an existing plant has an established grounding system of another type and must be used for the new system to make both systems compatible. Ground faults on these systems shall be detected and alarmed only. Removal of faults shall be at the discretion of the plant.
• Delta Connected Systems: Delta connected systems are ungrounded. Ground fault detection system for these systems are required only to provide visual indication and a contact alarm circuit for detection of single phase to ground faults. Delta, or other ungrounded systems, shall not be installed without the approval of the Owner.
• Power System Studies
• The following paragraphs describe the basic study requirements for the design of electrical power systems. Unless directed otherwise by the Owner, the Contractor shall perform short circuit, load flow and stability studies. The Contractor is responsible for problem formulation and proper data submittal. The Owner shall perform the required studies and provide printouts to the Contractor.
• With approval of the Owner, the Contractor may utilize his own computer programs, or use hand calculations to perform electrical systems studies. If hand calculations are used, copies of all calculations shall be furnished with the data to the Owner. Note: Computer programs are preferred. The Contractor shall be responsible for updating the Owner's existing system study computer program.
• In each case where the Owner approves the requirement for a study, the Contractor is to formally issue results, calculations and supporting data to the Owner.
• Items "1" through "4" below shall follow the concepts developed in ANSI/IEEE Std 399 and Std 141.
• Short Circuit: This study shall be done twice. The first study will be done prior to the issue of major electrical equipment bills of material to determine equipment withstand and short circuit fault duties. The first study shall be based on nominal transformer impedance values, preliminary motor sizes, and preliminary cable sizes and lengths. The second or final study shall be done using the actual transformer certified impedances, final motor sizes, and final cable sizes and lengths. The short circuit study shall include data for the maximum and minimum symmetrical and asymmetrical short circuit currents at each bus and line used in establishing settings for the protective relays and devices.

• Voltage Drop: This study shall be done twice. The first study shall be done prior to the issue of major electrical bills of material to determine transformer impedances, the need of load tap changers (LTC), feeder conductor size, and etc. In general, the study shall be limited to bulk power distribution feeders above 600 volts and shall be based on the initial issue of power system single line diagram. Voltage drop calculations for the remaining feeders and branch circuits shall be done during detail design per EP 13-2-1. The final study shall be done when the loads are final and the power system single line diagram(s) has been finalized.
• The Voltage Profile Data shall include:
• Voltage variations at buses and motor terminals during normal operation.
• Voltage variations at buses and motor terminals during motor starting and reacceleration.
• Loadings of bus supply lines in amperes during motor reacceleration.
• Motor reacceleration schedule showing motors assigned to each step.
• Tap settings for all power transformers.
• Load Flow Study: The load study shall be done twice. The first study will be based on preliminary load data using 85 percent of nameplate horsepower for the brake horsepower (BHP) value at the operating point. The final load tabulation shall be based on the driven equipment BHP value from the mechanical vendor and the actual electrical characteristics of the motor. The load tabulations will be used to determine the following loads.
• Feeders must be sized to carry the maximum demand which equals the connected load multiplied by the demand factor.
• The panelboard, switchgear bus, or etc. and the circuit supplying it must carry the maximum demand which equals the individual maximum demand on the panelboard, switchgear bus, etc., divided by the diversity factor.
• Transformer maximum demand is equal to the sum of the individual maximum demands of the switchgear bus, panelboards, etc., connected to it divided by the diversity factor.
• Primary feeder maximum demand is equal to the sum of the maximum demands on all transformers divided by the diversity factor of the transformer load.
• Motor Reacceleration Studies: Systems having motors with required reacceleration schemes shall be modeled to determine the ability of the system to reaccelerate the motors and overall impact on system performance.
• Relay Coordination Study: Relay coordination curves shall be made on two occasions. The first issue of the relay coordination curves shall be made prior to the issue of major electrical bills of material where relay types and ranges, current transformer ratios and etc., are specified to the equipment Manufacturer. This may be difficult at this time for proper motor protection due to the lack of information. However, provisions should be made to allow sufficient flexibility with the Manufacturer supplying the motor protection relays to allow for changes when motor information becomes available. The second or final issue shall be based on the final power system configuration. The final study shall include copies of all certified data for the system electrical equipment as requested by the individual equipment test / data requirements, e.g. motor thermal limit and starting curves. The electrical system shall be designed to provide a properly coordinated system of protective devices based on industrial protective coordination criteria such as the IEEE Buff Book (IEEE STD 242), ANSI C37, and the following criteria.

• A properly coordinated system shall have all protective devices selective with each other. In those isolated cases where complete selectivity cannot be obtained, selectivity may be sacrificed in the long time (for faults longer than 2 seconds) in order to obtain selectivity for faults that will clear in less than 2 seconds.
• Coordination studies shall provide/contain the following as a minimum:
• All criteria for calculations and settings shall be established by the Contractor and approved by the Owner prior to starting the study.
• Provide all calculations for complex relays.
• Include the protective relay Manufacturer's instruction books and protective device curves for each type of relay/device in the study.
• Provide the protected equipment (e.g., motor, transformer, power cable) data sheets, test data (as required by the device specific EP or data on hand for existing equipment) that supports the coordination study settings (e.g., provide transformer ANSI point, motor thermal limits, etc.).
• Provide complete settings for each device in a manner that will allow a qualified relay test technician to set/check each device/relay. Relays with inverse time/current curves shall have at least three test points provided to verify the curve characteristic.
• For 480 volt motors, provide a motor load summary that includes, but is not limited to, motor full load and inrush current, specific overload (heater) supplied, current range if adjustable, and performance data as specified in EP 13-3-1.
• Relay coordination curves shall include, as a minimum, the following items:
• A brief, one-line diagram for the subject devices.
• All pertinent fault bus numbers and the fault currents plotted on the coordination curves.
• Provide all pertinent protected equipment limits such as motor thermal limit curves, transformer ANSI points, cable thermal limit/current curves, etc.
• Unique protective device identification on the curves that is identical to that on the relay setting listings.
• Show all pertinent faults to be cleared by each protective device, e.g., transformer fault clearing for two-phase low side faults.
• All non-fault device settings, e.g., motor RTDs, excitation equipment, etc., shall be supplied with the coordination study with all back-up equipment limits, information and calculations.
• Fast fault clearing should be one criteria to be achieved by proper relay coordination. Selective use of differential relays is to be considered to achieve this requirement.
• Transformers rated 10 MVA and larger shall have differential current protection specified. Protection zone shall extend from the line side of the transformer primary breaker to the load side of transformer secondary breaker.
• Motors 1500 HP and larger shall be supplied with self-balancing current differential protection, and surge protection. In the case of motors 1500 HP and larger, sourced by E-2 (fused) controllers, differential protection shall be omitted due to the reduced duty of E-2 controllers.
• Substation bus differential on 4.16 KV systems and higher shall be supplied on all substation buses where a normally closed tie breaker is used to connect them. All 13.8KV switchgear buses shall be protected with dedicated bus differential relays ABB Type KAB (or equal).

• All outdoor substations (open buswork) rated 12.5 KV and higher shall have bus differential protection with GE type PVD (or equal). Overlapping protection from transformer differential and/or line relaying may also provide suitable protection.
• For secondary selective substations, the method of blocking transfer for a fault on one of the substation buses shall be specified.
• For proper selectivity and maximum protection on 480 volt switchgear systems the basis for design shall be:
• 480 volt switchgear main breakers, tie breakers, and feeders to load centers (e.g., MCC's, Switchracks, Panelboards) shall be equipped with solid state trip units having long time and short time.
• 480 volt switchgear breakers used to source individual motors, or transformers shall be equipped with solid state trip units having long time, short time, and instantaneous.
• Power Factor Study: Power factor studies shall be performed on two occasions. This first group of studies shall be based on preliminary load information and the initial issue of the power system single line diagram(s). The power factor should only be corrected to what is economically justified. The bus connection point(s) of the power factor capacitor bank(s) shall be determined on the basis of economics and with a recognition of technical issues such as voltage transient implications. The second or final issue of the power factor studies shall be done using final load data and the final issue of the power system single line diagram.
• Insulation Coordination Study: A complete overvoltage study for coordination of insulation BIL levels shall be performed whenever the system includes synchronous motors, overhead transmission lines exposed to lightning strikes, reclosers on the utility lines, application of vacuum switchgear, etc. Individual cases of overvoltage protection shall be done as required. Cases in point would be the application of lighting arrestors and surge capacitors installed at medium voltage motors and voltage impact of operating synchronous motors overexcited.
• Grounding Study: A grounding study shall be done whenever a main outdoor substation yard is in the scope of work. Calculations showing the touch and step potentials in the outdoor substation shall be submitted to the Owner. All design and calculations shall be based on ANSI/IEEE 80.
• Power System Distribution

The following sections describe the general requirements and preferences for the distribution system. In some cases, special design parameters will alter these general requirements as well as require economic and technical evaluation before the final design is approved by the Owner.

• Main Substation
• Main substation is defined as the substation where the tie-in is made with Power Houses and Bulk Power Center (BPC) .
• In general, there will be normally two or more feeders from the utility being terminated at the substation.
• A field fabricated concrete block building, engineered steel building or prefabricated electrical equipment shelter (see EP 13-16-1) shall be supplied to house D.C. power system, switchgear, utility company protective relays, etc. The building shall be heated, air conditioned and, where required, purged to classify the interior as general purpose when located in a classified area.

• A solid-state annunciator, or addition to the existing plant alarm system shall be provided to annunciate the substation alarms. A "Common Trouble" alarm is required for remote alarm indication of trouble at the substation. The annunciator system shall be powered from the substation's D.C. power system.
• For main substations where the incoming utility voltage is transmission or subtransmission (i.e., 34.5KV and above), the following criteria shall apply.
• Outdoor substation shall be of the low profile design.
• Outdoor bus shall be made of electrical grade aluminum.
• Outdoor disconnect switches shall be of the hook stick type. Gang operated three phase air break disconnect switches should only be applied where needed for safety and for operation and/or maintenance constraints on subtransmission voltages, but are always used on transmission voltages.
• Oil-immersed power transformers shall be used.
• Oil-immersed or SF6 circuit breakers shall be used. Availability and economics shall determine which type of breaker shall be used.
• Outdoor metering transformers and line carrier equipment (if applicable) shall meet the utility company's requirements.
• For main substations where the incoming utility voltage is the same as the highest in plant distribution voltage (i.e., 34.5KV and below), the following shall govern.
• For incoming utility voltages less than 15KV, the utility sources will terminate directly at the indoor metal-clad switchgear. Entry shall generally be underground into the switchgear; however, individual cases may require other means of entry.
• For incoming voltages above 15KV, the utility sources will terminate directly at the outdoor circuit breakers. Requirements will be the same as the paragraph 4.3.1.5 except that no oil-immersed transformers are required.
• A switchboard-type relay panel shall be required whenever there is a need to mount the following:
• Utility company and the Owner's protective relays.
• Control switches including circuit breaker status lights. A mimic bus is required with the control switches and shall meet the following:
• The mimic bus shall be colored plastic strips fastened directly to the front of the panel with screws or plastic rivets.
• Phenolic nameplates with a white background and 1/4 inch minimum high black letters shall identify all components (Both front and back panels).
• Physical orientation of controls on the panel shall be the same as the equipment layout in the substation. In addition, the orientation/location of the panel shall be such that it matches the equipment layout. The purpose of this is to avoid point of reference problems when operating equipment from the panel (e.g., OCB control switch).
• Metering General

The choice of meters, metering system and meter information/data gathering system shall be specified by the Owner. The metering methods described below are for general planning. The specific metering types or systems to be used at a particular facility must be approved by the Owner to insure the sufficiency of the metering and compatibility to existing systems. As a minimum, solid-state metering shall have digital displays and the capability to communicate via IEEE RS 232/485 ports.

• Metering Electro-Mechanical
• When electro-mechanical meters are provided, all ammeters and voltmeters, as a minimum, shall be switchboard class instruments, ± 1% accuracy, 250 degree movement, 4-1/4 inch face. Watt-hour meters shall be supplied in drawout test cases.
• Voltmeter with 3-phase selector switch along with associated potential transformers shall be supplied to meter the utility company's incoming circuits at the first accessible point into the substation.
• Voltmeter with 3-phase selector switch along with the associated potential transformer shall be supplied on the line side of all incoming breakers located on the secondary side of the main transformers.
• On all bus main breakers, a kilowatt-hour meter with demand register shall be supplied. The kilowatt-hour meter may also be used for check metering purposes. The kilowatt hour meter shall be capable of accepting a synchronizing pulse from the utility company metering system and match the utility system's demand interval.
• A voltmeter with 3-phase selector switch and associated potential transformers shall be supplied to each bus.
• An ammeter with a 3-phase selector switch and associated meter class current transformers shall be located on each bus main breaker.
• An ammeter with 3-phase selector switch and a kilowatt-hour meter with a demand register, shall be supplied on all outgoing feeder breakers.
• In facilities using special meters and/or transducers as part of power monitoring systems these devices shall also be provided (matched) in addition to or in place of the above items as necessary.
• Metering Solid-State

When solid state meters are supplied, as a minimum, they shall provide the same metering values and functionality as electro-mechanical/analog meters.

• Substation Alarms
• All breakers shall separately alarm if tripped open by a protective device or manual operation. Slip contacts shall be used on all control switches to segregate alarms when the breaker is manually opened, or tripped by protective functions.
• Circuit breakers with hydraulic or air operating mechanisms shall have an alarm for low operating pressure.
• D.C. Power System shall have the following alarms:
• D.C. ground fault
• Charger D.C. output failure
• Charger A.C. input failure
• Low D.C. voltage alarm
• High D.C. voltage alarm
• Additional Substation Alarms
• Smoke & Fire Alarm
• High Room Temperature
• Loss of Air Purge (if Purged)
• Station Entry Alarm
• Sump High Level Alarm (if Applicable)
• Loss of Station Service Alarm
• Transfer of Station Service Source

• For specific equipment alarms, e.g., power transformer, see the applicable equipment EP and the applicable section in the EP.
• Grounding

Substation Grounding design shall comply with ANSI/IEEE STD 80 and NFPA 70.

• Plant Distribution
• Power Circuits
• Power circuits between the main substation and a critical unit substation generally will be underground in red dyed concrete enclosed conduit duct bank(s). However, on an individual case basis, other alternatives may be proposed to the Owner for approval. Possible acceptable alternate raceways would include cable tray, overhead conduit, aerial cable, or bus duct. The choice of alternate raceway shall be based on economics, but consideration must be given to the area classification, plant layout, and reliability.
• Power circuits between the main substation and a semi-critical or non-critical unit substation may be above or below ground. The method of routing shall be based on economics, but consideration must be given to the area classification, plant layout and reliability.
• Critical Bulk Power and Load Substations
• For critical substations where N-1 reliability is required (see Paragraph 4.1.3.3 of this Practice), there shall be two separate feeders originating from two separate supply buses. These feeders shall terminate at the transformer primaries and be configured in a secondary selective or spot network. Other substation configurations may be proposed to the Owner for approval where cost savings can be demonstrated with very little loss or no loss in reliability.
• Normally, prefabricated electrical equipment shelters (i.e., "Power Houses"), field fabricated concrete block buildings, or engineered steel building shall be used for the substation building. Power houses (where electrical equipment is in place and is pre-wired inside the building) are preferred.
• All substations shall have heating and air conditioning. The need for air filtering, sulfur scrubbing and purging shall be a function of the location of the substation in the plant.
• Semi-Critical Bulk Power and Load Substations

The requirements are similar to critical substations except the system configuration preference is primary selective or looped primary.

• Non-Critical Load Substations
• For non-critical substations where N-1 = 0 (no redundance source) reliability is required, only a simple radial system shall be supplied.
• Weather protected type switchgear or unit substations mounted on a concrete slab is the preferred substation equipment.
• Lighting Systems
• Lighting systems shall be designed to provide the lighting levels listed in API RP 540.
• All lighting fixtures, lighting transformers, and controls shall meet the area classification.

• Grounding

Plant distribution grounding design shall comply with ANSI/IEEE Std 80 and Std 142 as well as NFPA 70.

POWER SYSTEM ARRANGEMENT

• Substation Bus Arrangement
• For a Radial, Spot Network, Looped Primary, and Primary Selective Substations, a single bus shall supply all branch circuit loads. Except for Radial Systems, the substations shall have an alternate source at the transformer primary.

For Secondary Selective and Primary Selective Substations, there shall be two separate buses with each bus supplying half of the total branch circuit loads, and each bus capable of supplying power to both buses. The Contractor shall be responsible for obtaining specific design requirements for all Secondary Selective and Primary Selective schemes. This shall include but not be limited to such items as automatic transfer schemes, type of switching devices, etc.

Every effort shall be made to duplicate automatic transfer schemes at a facility to reduce confusion for operators (such as written procedures).

• Power Supply to Spare and Multiple Service Motors

Where motors are designated for a given service as: 1) normal and spare; 2) 3-50% rated machines (i.e., two out of three motors normally running or equivalent); or 3) If two or more motors can operate independently for partial service (such as air-cooled heat exchanger fans and parallel cooling water circulation pumps), the following shall apply:

• When motors are fed directly from secondary selective type buses, the motors of each service shall be divided between (or among) the buses.
• When motors are fed from radially supplied buses (which may be supplied radially from Secondary Selective or spot network substation buses), it is preferred that the supply to the motors of each service be divided between independent radially supplied buses. Although not preferred, it is acceptable if they are supplied from a common bus.
• Unspared Critical Motors
• For buses that must be maintained while the plant is in operation, all unspared critical motors shall be designed for an alternate feed from another bus. A manual or automatic transfer switch would meet this requirement.
• For buses that must be extendable while the plant is in operation, one of the following (listed in declining preference) shall be supplied to meet this requirement:
• Supply spare starters and spaces or circuit breakers on each bus.
• Supply an alternate feed to motors per paragraph 5.3.1 of this Practice.
• Supply a sectionalizing means at the end of each bus that would permit the addition of equipment at the end of the bus.
• Power circuits to unspared critical motors shall be designed with multiple conductors per phase. Conductor sizing shall allow one set of conductors to be removed from service and the motor be fully operable on the remaining conductors.

• Bus Sectionalizing
• In secondary selective substations, the bus sectionalizing shall be performed by the normally open tie circuit breaker.
• In spot network substations, the bus sectionalizing shall be done by a circuit breaker or isolating disconnect switch.
• Emergency Bus Deenergization

Emergency bus deenergization shall be provided by one of the following means:

• Primary or main incoming breaker if it is located in the same room as the bus.
• Transformer primary load break if it is located in the same room as the bus.
• Initiation of an "86" lockout relay or operation of a local breaker control switch if the incoming circuit breaker is mounted remote from the bus.
• Incoming Breakers
• Incoming line circuit breakers are required at spot and secondary selective substations.
• Incoming line circuit breakers are generally required for radial substations, but may be deleted if the substation is fed directly at bus voltage and any one of the following conditions are met:
• There is an incoming line load break switch in the same room.
• The source circuit breaker is in the same room.
• Manual transfer tripping of the remote source circuit breaker is provided.
• Transformer Feeders
• Two or more transformers may be fed from a single feeder circuit breaker, if parallel terminations for incoming and outgoing cable are provided at the transformer primary, and each transformer is provided with individual protection/isolation with a load break fused switch.
• A method of disconnecting each transformer primary shall be provided when a feeder serves two or more transformers. Type of disconnection shall be as follows:
• If a feeder serves only secondary selective or spot network substations or both, removable air links or non-load break isolating switches shall be used.
• Radial substations on tapped feeders shall use primary load break switches.
• When a feeder serves a secondary selective or spot network substation, or both, and also feeds one or more radial substations, a primary load break switch shall be provided for each transformer of a secondary selective, spot network or radial substation.
• Unit substation metal enclosed switches shall be of the load break design, non-load break switches shall not be used.
• Motor Control
• In general, all motors shall only be started locally (at the motor) via a local momentary push button start-stop station. Starter location (remote) operation control is generally limited to stop (off) only. Further detail on this matter is provided in the individual equipment practices.
• Each plant location shall be consulted in this matter because control decisions are generally determined on local preferences and the type and location of the project.

ELECTRICAL EQUIPMENT REQUIREMENTS

• General
• All engineered electrical equipment items shall comply with IPE Engineering Practices (see EP 1-1-1) and shall be purchased only from Manufacturers on the Owner's approved vendor list. Changes required to apply IPE Engineering Practices to a specific application shall only be modified as directed in EP 1-1-3.
• All non-engineered items, as a minimum, shall meet the requirements (if any) of EP 13-2-1 and other applicable IPE Engineering Practices.
• Manufacturers' and vendors' quotations are to be fully evaluated and documented by the Contractor. Technical bid evaluations are to be submitted to the Owner for approval before any engineered electrical equipment is placed on order. Technical bid evaluations shall include such items as identification and clarification of all exceptions, spare parts cost, maintenance cost differentials and energy cost for operation in the case of transformers and motors in addition to evaluation of specific itemized costs. Contractors shall either accept or reject Manufacturer's exceptions to Practices and provide detailed technical analysis to support the recommendation. In all cases the Owner must approve acceptance and/or rejection of an exception to a IPE Engineering Practice or project specification.
• Liquid-Immersed Transformers
• For detailed requirements see EP 13-4-1.

• All substation class transformers shall be liquid-immersed type rated with a 55/65C rise.
• Primary switches shall be either fused or non-fused, load break, interrupting switches, with the minimum requirements are as follows:
• Air Break
• Switch shall be gang operated.
• Minimum continuous rating shall be 600 amperes.
• BIL ratings shall be as shown in Table 4.
• Liquid-immersed
• Switch shall be gang operated.
• Minimum switch rating shall be 200 amperes.
• BIL ratings shall be as shown in Table 5.
• Forced Cooling
• Forced cooling is mandatory on any transformers that feed secondary selective or spot network substations.
• Forced cooling shall consist of the maximum number of stages available with one stage of cooling being available on transformers less than 12 MVA and two stages of cooling being available on transformers 12 MVA and larger.
• Transformers feeding substations other than secondary selective or spot network shall have provisions for the future addition of forced cooling equipment.
• Liquid Preservation System
• In general, all transformers rated below 10 MVA shall be of the sealed tank type.
• Transformers rated 10 MVA and larger shall use a pressurized nitrogen system.

• Other types of liquid preservation systems may be used if an economic evaluation will support this selection. These alternates shall be provided to the Owner for approval.
• Transformer Sizing Criteria
• Non Secondary Selective Systems (Single Bus): The transformer shall be sized to carry maximum normal load without reaching 90 percent of its 65°C "OA" rating. Sizing upward beyond this for future use shall be a function of job specific preinvestment criteria.
• Secondary Selective Systems: The transformer shall be sized to carry the normal load for the case of one source out, tie closed within the transformer's 55°C "FA" rating. This will mean normal, tie open, operation will be at approximately 40% of the transformers capability and should be considered in any transformer loss evaluation. Sizing upward beyond this for future use shall be a function of job specific pre-investment criteria.
• Unit substation transformers (480V secondary): The maximum size transformer for this application shall be 2500 KVA 55/65°C OA). Loading shall not exceed that defined in 1. and 2. above
• Protective Requirements
• Fuses: High side protection of transformers 500 KVA and larger with current limiting fuses shall be avoided. An exception to this are transformers with E-2 latched controllers as the high side disconnect device. For this case the E-2 controller current limiting fuse, with anti single phasing (blown fuse "trigger" pin) trip device shall be acceptable.
• Fault pressure relay "63": Transformers rated 5000 KVA and larger, with high side and low side automatic breaker disconnect devices, shall be supplied with a fault pressure relay, associated controls and a separate "86FP" lockout relay. Locate the 86FP relay on the transformer relay panel.
• Differential Protection "87": Transformers 10 MVA and larger shall be protected with harmonic restraint differential relays designed for this application. The low side zone shall normally extend to the load side of the load side main breaker. The high side zone shall be a function of the design, e.g., include only the transformer, extend to the transformer breaker, could include the high side substation bus.
• Overcurrent Relays "50/51" and "50G": The preferred method of providing overload and phase fault protection is by means of three phase overcurrent relays. Ground fault protection shall be provided via a zero sequence ground fault relay and 50G window CT for resistance grounded power systems. For high fault, solidly grounded systems, source the relay in the residual of the phase relay CT's. The ground relay shall be a "50" plunger type GE PJC or equivalent. These relays, under normal conditions, should be connected to current transformers in the bus side of the transformer high side feeder (source) breaker.
• Neutral Backup Ground Relay "51G": Ground fault relaying shall be applied to low resistance grounded systems (and solidly grounded systems). The ground relay shall be connected to a current transformer in the power transformer neutral.
• Lockout Relays "86T" and "86BUG" (BUG - Back Up Ground) and Trip Schemes: Protective relay tripping shall be segregated to provide separation of trip paths as well as a means to provide for backup relay segregation. 86T shall be operated by "87" and "63" relays and shall trip and lockout the primary (source) and secondary (load) breakers. "50/51" relays shall trip the primary source breaker. The "51 G" shall operate a separate "86BUG" relay that trips and locks out the primary and secondary breakers.
• Lockout relay "86FP": For transformers equipped with a fault pressure relay "63" and associated "86FP" lockout relay the 86FP shall trip and lock out the primary (source) and secondary (load) breakers.

• All lockout relays shall be alarmed via the substation annunciator.
• Transformers equipped with "FA" (Forced Air) and/or "FO" (Forced Oil) equipment and "86" lockout trip relays, shall have all transformer "86" lockout devices wired into the "FA" and "FO" control circuit to shut this equipment off for faults. This is a fire safety precaution that must be incorporated into the design.
• Transformer Alarms

Alarm contacts shall be provided for the following functions.

• Oil temperature
• Low oil level
• Sudden pressure relay (if supplied)
• Mechanical pressure relief valve (also provide a visual operation flag)
• Winding temperature hot spot CT (if specified)
• For transformers with nitrogen pressurization system:
• Low tank pressure
• High tank pressure
• Low bottle pressure
• Medium Voltage Switchgear
• For detailed requirements see EP 13-5-2.
• Circuit breakers shall be vacuum break. Air break shall only be used for replacement purposes.
• Circuit breaker control voltage shall generally be 125 VDC.
• Both incoming line breakers and the tie breaker shall each have their own separately fused DC control bus on secondary selective substations.
• Feeder breakers on the same power bus shall have the same DC control bus.
• Protective Relay Requirements: NOTE: Relays shall be ABB (Westinghouse) or General Electric draw out electro-mechanical types or solid state types for motor protection. If Solid State relays are specified for motor protection, they must be supplied in draw out test cases or provided with external test switches. For motors below 1500 HP, acceptable solid state relays are Multilin 369 or the latest model as approved by the Owner. For motors1500 HP and larger, acceptable relays are the Multilin 369, Multilin 469 or the latest model as approved by the Owner.
• Minimum Protection for Induction Motors 300 HP to less than1500 HP
• One "51" locked rotor protection.
• Three phase "50" fault protection.
• Three phase "49" thermal running overload protection. Alternate to this is to provide running protection via motor stator RTD's, (See Section 6.3.6.2.3 of this Practice).
• Three phase undervoltage "47/27" protection (use bus PT's and trip all motor starters on a bus.)
• Zero sequence ground fault relay and window 50/5 CT for resistance grounded power systems. For solidly grounded systems recommend using the residual circuit of the phase CT's unless calculations demonstrate the recommended relay and window CT will operate for the fault current available (no saturation/burden problems). Electro-mechanical relay, when provided, shall be a "50" plunger type GE PJC or equivalent.

• Minimum protection for Induction Motors 1500 HP and above
• Two "51" locked rotor protection
• Three phase "50" fault protection
• Provide running overload "49" protection via motor stator RTD's (two per phase) and an RTD monitor. The monitor shall have two set points - high alarm and high-high trip. Motor RTD's shall be 100 OHM or 120 OHM Edison TR-7 or equal 3-wire devices.
• Three phase "46" current balance.
• Self-balancing type motor differential "87" scheme using CT's at the motor and a three phase "50" relay PJC or ITH for sensing/tripping via an 86M lockout relay. Motors 1500 HP and above sourced via E-2 controllers must take into account the fault interrupting capacity of the controller. If the fault current available is higher than the rating of the controller contacts, motor differential schemes shall not be provided.
• Three phase undervoltage "47/27" protection.
• For ground fault protection see 6.3.6.1.5 above.
• Bearing RTD alarm and trip.
• Synchronous Motors: Same relaying as specified for induction motors 1500 HP and above and in addition the following:
• "55" power factor relay (Basler PRP 320 with an auxiliary target relay).
• DC field loss relay.
• Load Center Feeder
• Three "50/51" overcurrent load/fault protection relays.
• For ground fault protection see 6.3.6.1.5 above.
• Metering: When analog type meters are provided they shall be switchboard class instruments,

+1% accuracy, 250 degree movement, 4-1/4 inch face. Solid state metering with digital displays may be provided instead of analog metering. The solid state meters must provide, as a minimum, the same functions as analog meters and comply with paragraph 4.3.1.10 of this Practice.

• Load Center Feeders and Induction Motor Feeders (motors below 1500 HP): An ammeter with a 3-phase selector switch and associated meter class current transformers shall be provided on each feeder. The same current transformer used for protective relaying can be used for metering.
• Induction Motor Feeders (Motors 1500 HP and above): Same metering as above except a current transformer separate from that used for relaying shall be used for metering.
• Synchronous Motors
• The location of the metering for synchronous motors shall be a function of the specific installation, however, all metering identified below shall be provided as a minimum.
• For all installations, potential transformers shall be provided at the motor terminals and these shall be used for relay and metering purposes. Current transformers used for relay and metering shall be those at the same voltage level as the motor, i.e., not those on the high voltage side of an associated captive transformer. Dedicated metering current transformers shall be used for all synchronous motor applications.
• The minimum Metering Required (either analog or solid state) shall be as follows:
• An ammeter with a 3-phase selector switch.

• A voltmeter with a 3-phase selector switch. Note; Since the potential transformer (PT) is located at the motor, the PT leads shall be sized to minimize voltage drop to less than one percent. Higher voltage drops must be approved by the Owner.
• Power Factor Meter
• Field Voltmeter
• Watt Hour Demand Meter
• RTD Monitor with a minimum of eight inputs and ability to select readings for all inputs (either switched or electronic). The monitor shall have two set points - High Alarm and High-High Trip Alarm. Motor RTD's shall be 100 OHM Platinum or 120 OHM (3 wire devices) or equal, three per phase (one spare per phase) and two per bearing.
• Low Voltage Switchgear
• For detailed requirements see EP 13-5-1.
• All feeder breakers shall be manually operated except those used as motor starters which will be electrically operated.
• Incoming line breakers and tie breakers shall normally be manually operated except those circuit breakers used in auto-transfer schemes which shall be electrically operated.
• For electrically operated circuit breakers, the control voltage shall be as specified on the Data Sheets.
• Each electrically operated incoming line breaker and tie breaker used in an autotransfer scheme shall each have its own control bus.
• Electrically operated feeder breakers on the same power bus shall be on the same control bus.
• 480 volt switchgear shall use solid state protective schemes. 480 volt switchgear having autotransfer schemes may require drawout electro-mechanical relays to obtain required auxiliary relay contacts and lockout functions required in transfer schemes. For proper selectivity and maximum protection on 480 volt switchgear, the basis for design shall be:
• See 4.2.5.4.6.7 of this Practice.
• TRMS (True Root Mean Square) solid state trip (Protective) devices may be required for applications on adjustable frequency drive feeders, UPS feeders, diesel generator breakers.
• A switchboard class ammeter with a 3-phase selector switch or solid state metering (as specified) and three associated meter class current transformers shall be provided on each main breaker.
• A switchboard class voltmeter with a 3-phase selector switch or solid state metering (as specified) and two associated meter class potential transformers shall be provided for each main bus, and each incoming circuit.
• 5000 Volts and Above Power Cable
• For detailed requirements see EP 13-8-2.
• Cable insulation shall be vulcanized Ethylene Propylene Rubber (EPR).
• Cable conductor shall be stranded copper. Stranded aluminum conductor will only be considered where environmentally required and must be approved for use by the Owner.
• Minimum cable size shall be #6 AWG.

• 600 Volts Power and Control Cable
• For detailed requirements see EP 13-8-1.
• Power Cable
• Cable insulation shall be XHHW, XHHW-2, RHH(XLP), RHW(XLP), or RHW (EPR) for all conductors, as specified by the Owner.
• Cable conductor shall be stranded copper.
• Minimum size conductor shall be #12 AWG.
• Control Wire and Cable
• Conductors shall be stranded copper.
• For single conductor cable the insulation shall be XHHW, XHHW-2, RHH(XLP) or RHW(XLP). For multi-conductor cable the conductor insulation shall be THHN/THWN, XHHW, or XHHW-2 with the overall jacket PVC, or jacket as specified otherwise.
• In general, the minimum size conductor for single conductor cables shall be #12 AWG and for multiple conductor cable the minimum size shall be #14 AWG, Equipment wire sizes shall be sized as directed in the applicable IPE EP.
• Medium Voltage Motor Control Centers
• For detailed requirements see EP 13-6-1.
• In general, induction motor starters shall be E-2 vacuum controllers of the full voltage non- reversing (FVNR) type. Where excessive voltage drops have been calculated for the starting of large motor drives, reduced voltage motor starters such as closed transition auto transformer or primary reactor type (in order of preference) can be proposed to the Owner for approval, if this would solve the voltage drop problem.
• A standard 3-wire control circuit utilizing momentary start and stop pushbuttons are to be utilized unless specified otherwise in the project scope documents.
• When specified, Owner defeatable adjustable time delay under voltage re-acceleration control circuits shall be provided on a starter. When a large number of motors are being re-accelerated after a brief voltage loss, it may be necessary to reaccelerate the motors in groups to keep the motor terminal and motor bus voltage within the prescribed voltage limits. The stepped re- acceleration scheme will generally require an additional timer beyond those used in the time delay undervoltage scheme. It is also required that the undervoltage relay/control scheme and CPT bus connections shall be staggered.
• All controllers main contactor control circuit shall be designed to insure that the main contacts remain closed for 10 cycles during a voltage dip (to zero volts on main bus).
• Starters for synchronous motors shall follow the same general philosophy as the induction motor starters. The only additional requirement shall be that the DC motor field shall be source as specified on the data sheet. If the power source consists of batteries and DC battery charger then they should be separate from those used for switchgear control. Undervoltage re- acceleration shall not be provided.
• When medium voltage controllers are used as primary feeder devices for transformers, they shall be of the latching type. Transformer and fault protection shall be provided by the controller current limiting fuses, and a 50G relay/sensor for ground faults.

• Whenever protective devices are supplied with E-2 controllers care shall be taken to insure that protective relay initiated tripping doesn't result in the main contacts being overdutied.
• Metering requirements are as follows:
• Induction motors and transformer feeders: All starters and transformer feeders are to be supplied with solid state metering or an ammeter and three phase ammeter selector switch (as specified).
• Synchronous Motors: Synchronous motor starters shall contain all metering as specified for the induction motor starters and in addition shall have the following:
• DC Field Ammeter
• DC Field Voltmeter
• Power Factor Meter
• KWH Meter
• Protective relaying requirements: Relays shall be either electro-mechanical draw out type manufactured by General Electric or Westinghouse (ABB) or Solid State Motor Protection Relay. Solid State Motor Protection relays shall be Multilin 369.
• The minimum protection for Induction Motors 300 HP to less than1500 HP
• One Locked Rotor "51 LR" Protection Relay.
• "49" protection via RTD's and an RTD monitor/trip relay for "high" alarm, and "high-high" trip. Protection shall be for all three phases.
• Zero sequence ground fault "50" relay for resistance grounded power systems. Acceptable electro-mechanical type relay, if provided, is a plunger type GE PJC.
• Induction Motors1500 HP and Above
• Two Locked Rotor "51 LR" Protection Relays.
• "49" protection via RTD's and a RTD monitor/trip relay for "High" alarm, and "High-High" trip. Protection shall be for all three phases.
• Three phase "46" current balance relay.
• Zero sequence ground fault "50" relay for resistance grounded power systems. Acceptable electro-mechanical type relay, if provided, is a plunger type GE PJC.
• Bearing RTD alarm and trip.
• Synchronous Motors: All starters shall contain the same relaying as specified for the induction motors with the addition of the following relays:
• Power Factor Relay
• DC Field Loss Relay
• 600 Volt Class Motor Control Centers
• For detailed requirements see EP 13-6-2.
• In general, induction motor starters shall be full voltage non-reversing (FVNR) type. Where excessive voltage drops have been calculated for the starting of large motor drives, reduced voltage motor starters such as a closed transition auto transformer type or solid state soft start can be proposed to the Owner, if this would solve the voltage drop problem.
• A standard 3-wire control circuit utilizing momentary start and stop pushbuttons is to be utilized, unless specified otherwise in the project scope documents.

• Only when specified in the project scope documents, time delay undervoltage re-acceleration control circuits shall be required on starters. When a large number of motors are being re- accelerated after a brief voltage loss, it may be necessary to reaccelerate the motors in groups to keep the motor terminal voltage and motor control center bus voltage within the prescribed voltage limits. The stepped re-acceleration scheme will generally require an additional timer beyond those used in the standard time delay undervoltage scheme.
• Metering requirements are as follows:
• An ammeter with a 3-phase selector switch and three CT's for each main circuit.
• A voltmeter with a 3-phase selector switch and associated PT's for each main bus.
• For starters up through size 4, no metering is generally required.
• For size 5 starters, a single phase ammeter shall be supplied.
• NOTE: Items 1 and 2 above shall be provided only when similar metering is not provided at the motor control center source device.
• Protective requirements are as follows:
• All starters shall be supplied with 3-pole ambient compensated bimetallic, eutectic alloy or solid state trip overload relays, as specified on the Data Sheet.
• Combination starters input disconnect device shall be via specified molded case breaker (MCB) or fused disconnect.
• Size 4 and 5 starters

These starters shall be supplied with main contact vacuum interrupters, not elecro-mechanical air interrupter contactors.

• Motors
• 500 HP and Below Induction Motors
• For detailed requirements see EP 13-3-1.
• Process Applications
• All motors shall be energy efficient NEMA rated totally enclosed fan-cooled severe duty (TEFC).
• For indoor or outdoor applications, explosion-proof motors shall be used in Class I Division 1 classified areas. They shall be totally-enclosed fan-cooled severe duty (TEFC) motors and UL listed for use in Class I Division 1.
• Above 500 HP Induction Motors
• For detailed requirements see EP 13-3-2.
• For indoor or outdoor applications, motors shall use WPII enclosures in non-classified areas or Class I Division 2 classified areas.
• For indoor or outdoor locations where the motor is very large and is a critical application or is located in a highly corrosive environment, the motor enclosure shall be either totally- enclosed water-air-cooled (TEWAC) or totally-enclosed pipe ventilated (EPV).
• Above 200 HP Synchronous Motors
• For detailed requirements see EP 13-3-3.
• Same requirements as 6.9.2.2 and 6.9.2.3 of this Practice.
• All synchronous motors shall have brushless excitation.
• DC Power System
• For detailed requirements see EP 13-9-1.

• DC power systems for exciter field excitation shall be separate from those required for control power on metal-clad switchgear.
• On switchgear power applications, batteries shall be sized to provide 8 hour backup with the battery charger off. The battery charger shall be a battery eliminator type sized to recharge the battery bank after an 8 hour discharge in 12 hours.

On brushless synchronous exciter field supplies, the battery bank shall be sized to provide 4 hours of backup with the battery charger off. The battery charger shall be a battery eliminator type. Each battery charger shall be sized to recharge the battery bank after a 4-hour discharge in 8 hours, while simultaneously supplying maximum field current.

• If no other DC battery system is at the same location as the excitation DC system, provide two redundant parallel operating battery eliminator/chargers.
• If a station DC battery system is in the same location as the excitation DC system, provide a circuit breaker switched tie between the two systems. Only one battery eliminator/charger shall be supplied with the excitation DC system.
• Lead-Calcium wet cells are the preferred battery. Nickel-Cadmium cells are acceptable, but only with approval of the Owner.
• Standby Power Source
• Diesel generator set size shall be based on the standby rating.
• Location of the diesel generator, in a block building, outdoor metal building/shelter, or provided with its own outdoor unit enclosure shall be a function of location, existing facilities, and unit size.
• An automatic transfer switch with an isolation/bypass switch (switchgear may be used as the transfer device) shall be used to perform the transfer of the load from the normal source to the generator set. The bypass switch shall be capable of bypassing the load to either the normal source or the generator.
• Transfer shall be specified as open or closed transition. For closed transition systems, automatic synchronizing circuitry shall be provided.
• The automatic transfer switch shall use three phase voltage sensing for the initiation of the automatic transfer of the load from the normal source to the alternate source. The retransfer of the load back to the normal source shall be done manually, unless approved otherwise by the Owner.
• No automatic exerciser is to be supplied for the diesel engine.
• An above grade fuel tank is to be utilized unless the plant has standards that prohibit such an installation.
• Communication System
• In existing installations, unless directed otherwise by the Owner, the new equipment shall be the same as that currently installed.
• A communication system using local amplifiers is preferred over a system that utilizes one large central amplifier.
• Local stations in the process area shall meet the area classification.

• Two-way radio or pager only type communication systems shall be supplied only when specified in the scope documents. In existing plant facilities, the new equipment must be of the manufacture as currently being used by the plant.
• Power for radio systems should be from sources with battery or diesel backup to insure communications availability during power outages.

6.13 Testing

Electrical equipment shall be given the type of test as indicated in Table 6 and shall require a witness of the test as indicated. All tests shall be witnessed by the Owner unless directed otherwise by the Owner. The required specific test items and methods are detailed in the associated equipment's IPE Engineering Practice and Plant Standard Operating Procedure SOP# 10-0201001 (Section-B Commissioning & Energizing New Electrical Equipment).Table 6

DOCUMENTATION

• General
• Vendor drawings from mechanical and electrical equipment vendors shall be utilized whenever possible. Redrawing of vendor drawings is not permitted.
• Drawings when supplied by the Contractor shall be drawn on mylar using the following sizes:
• 8-1/2 x 11
• 11 x 17
• 24 x 36
• 18 x 24
• All lettering shall be a minimum of 1/8 inch high letters.
• All drawings shall be produced on a CAD system and shall be supplied to the Owner on magnetic media in a format compatible with the system in use at the facility.
• Documents for Approval
• Comment copies of all studies, documents and drawings are to be submitted in a timely manner to allow adequate time for the Owner to comment.
• The following classes of drawings and/or documents shall be issued to the Owner for approval:
• Electrical single lines and three lines
• Electrical specifications
• Electrical plot plans
• Electrical area classification
• Major electrical equipment inquiry packages prior to inquiry (technical portion only)
• Major electrical equipment bills of material and vendor drawings (prior to placement of order and fabrication)
• Shutdown system schematics
• Interconnection drawings
• Electrical equipment schematics/elementary diagrams
• Electrical grounding drawings
• Protective device manuals, schematics and coordination curves
• Power metering device manuals and schematics

• Documents for Construction
• The following classes of documents shall be issued for construction. All documents issued shall be marked "ISSUED FOR CONSTRUCTION".
• All electrical drawings and all electrical bills of material.
• All electrical equipment manufacturer drawings.
• Quantities of the documents to be transmitted shall be as specified in the project scope documents.
• Documents for Record
• The following original tracings are to be supplied to the Owner at the termination of the contract:
• All electrical drawings
• All electrical bills of material
• Electrical equipment vendor drawings
• Quantities as specified in the project scope documents shall be supplied to the Owner of the following:
• Instruction and maintenance manuals.
• Spare parts lists.
• Equipment factory test reports.
• As-Built Documents
• All electrical drawings and bills of material shall be revised to reflect "as-built" conditions of the project. These documents shall include engineering changes as well as field modifications.
• The following "as-built" drawings shall be supplied within 90 days of field mark-ups:
• Electrical single lines and three lines.
• All electrical equipment schematics (elementary diagrams) and wiring diagrams.
• Connection diagrams for all junction boxes, and electrical equipment.
• Area classification drawings for all electrical equipment affected by the scope of this project.
• Conduit and/or cable tray routings/locations including elevations.
• Complete manhole and duct bank details.
• Erection details.
• All calculations and data, including but not limited to the following:
• Short Circuit and Load Flow Study
• Voltage Drop Calculation
• Coordination Study and Curves

8.0 TABLES

TABLE 1

NOMINAL SYSTEM VOLTAGES FOR MOTORS

TABLE 2

NOMINAL SYSTEM VOLTAGES FOR LIGHTING

NOTES:

(1) The majority of the Owner's 480 Volt systems are high resistance grounded limiting phase-to-ground current to 5 ampere.

TABLE 3

NOMINAL SYSTEM VOLTAGES FOR RECEPTACLES

TABLE 4

BIL RATINGS FOR MEDIUM VOLTAGE AIR BRAKE SWITCHES (para. 6.2.3.1)

TABLE 5

BIL RATINGS FOR MEDIUM VOLTAGE LIQUID IMMERSED SWITCHES (para. 6.2.3.2)

TABLE 6

ELECTRICAL EQUIPMENT TESTING AND WITNESS REQUIREMENTS

NOTES:

• Required if a loss guarantee is specified.
• Only by direction/approval of the Owner.
• The electrical equipment in the shelter shall be tested per its EP after Installation in the shelter.

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