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ExxonMobil Proprietary ELECTRIC POWER FACILITIES

POWER DISTRIBUTION DESIGN PRACTICES

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CONTENTS Section

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SCOPE ............................................................................................................................................................ 3 REFERENCES ................................................................................................................................................ 3 BACKGROUND .............................................................................................................................................. 4 DEFINITIONS .................................................................................................................................................. 4 EQUIPMENT TYPES AND APPLICATION..................................................................................................... 5 POWER TRANSFORMERS.................................................................................................................... 5 SWITCHGEAR........................................................................................................................................ 5 MOTOR CONTROL CENTERS & TURNAROUND POWER CENTERS (MCCS & TPCS) .................... 6 CABLES AND BUS DUCT ...................................................................................................................... 6 SQUIRREL CAGE INDUCTION MOTORS ............................................................................................. 7 BASIC DESIGN CONSIDERATIONS ............................................................................................................. 7 NUMBER OF SUBSTATIONS & THEIR LOCATION .............................................................................. 7 TYPES OF SUBSTATIONS .................................................................................................................... 8 SPOT-NETWORK VERSUS SECONDARY-SELECTIVE SUBSTATIONS ............................................ 8 SPOT NETWORK SUBSTATIONS......................................................................................................... 9 SECONDARY-SELECTIVE SUBSTATIONS .......................................................................................... 9 FEEDING ARRANGEMENTS FOR SUBSTATIONS ............................................................................ 10 SERIES VERSUS PARALLEL TRANSFORMATION............................................................................ 10 VOLTAGE LEVELS............................................................................................................................... 11 NOMINAL VOLTAGE............................................................................................................................ 11 VOLTAGE REGULATION ..................................................................................................................... 11 SYSTEM NEUTRAL GROUNDING (EARTHING)................................................................................. 12 WIRING METHOD ................................................................................................................................ 12 SYSTEM RELIABILITY ......................................................................................................................... 13 LOAD SHEDDING ................................................................................................................................ 13 REACCELERATION ............................................................................................................................. 14 DESIGN PROCEDURE ................................................................................................................................. 14 DESIGN BASIS..................................................................................................................................... 14 COMPUTER PROGRAMS ............................................................................................................................ 15 SYMBOLS..................................................................................................................................................... 16 APPENDIX - USEFUL MOTOR FORMULAS ............................................................................................... 28

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CONTENTS (Cont) Section TABLES Table 1 Table 2 Table 3 Table 4 FIGURES Figure 1 Figure 2 Figure 3 Figure 4 Figure 5 Figure 6 Figure 7 Figure 8 Figure 9 Figure 10 Figure 11 Figure 12 Figure 13

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Typical Efficiency and Power Factors of Squirrel Cage Induction Motors......................... 17 Typical Equipment Voltage Ratings for Motor Circuits...................................................... 18 ANSI C84-1 Voltage Ranges ............................................................................................ 18 Typical Ratings in kW of Squirrel Cage Induction Motors Relative to I.E.C. Frame Sizes...................................................................................................................... 19

Spot-Network .................................................................................................................... 20 Secondary-Selective......................................................................................................... 20 Series Transformation ...................................................................................................... 20 Parallel Transformation..................................................................................................... 20 Loop Fed Substation......................................................................................................... 20 Radial Substation.............................................................................................................. 20 Tapped Feeders ............................................................................................................... 21 Typical One Line Diagram For A Small Plant With Main Substation 10 To 25 Kv............. 22 Typical One Line Diagram For A Small Plant With Main Substation 3 To 6 Kv................. 23 Motor Voltages For Various Operating Conditions............................................................ 24 Voltage Ranges At Motor Terminals And Busbars That Supply Motors............................ 25 Motor Voltages Versus Outputs ........................................................................................ 26 Guideline For The Application Of Induction And Synchronous Motors ............................. 27

Revision Memo 12/00

REFERENCES - Updated C84.1. Deleted date from standards. Changed Exxon to ExxonMobil throughout document.

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SCOPE This section applies to the distribution of electric power from the main source(s) of power, either main substations where purchased power is received or generator switchgear, to the plant unit substations and from there to the loads. Instrument/computer power supplies and emergency power supplies required for safety in the event of a loss of the main power source are not included.

REFERENCES DESIGN PRACTICES Section XV Section XXIX-I

Safety in Plant Design Civil Work, Blast-Resistant Structures

INTERNATIONAL PRACTICES IP 2-1-1 IP 4-3-1 IP 4-3-2 IP 10-11-1 IP 15-7-1 IP 16-1-1 IP 16-1-2 IP 16-3-1 IP 16-4-1 IP 16-5-1 IP 16-5-2 IP 16-6-1 IP 16-7-1 IP 16-8-1 IP 16-9-1 IP 16-9-2 IP 16-9-3 IP 16-10-1 IP 16-11-1 IP 16-12-1 IP 16-12-2 IP 16-13-1 ➧

Plant Noise Design Criteria Plant Buildings for Operation and Storage Blast-Resistant Buildings Sizing of Drivers and Transmissions for Compressors, Fans and Pumps Electrical Power Branch Circuit Design for Instrumentation Area Classification and Related Electrical Design for Flammable Liquids, Gases or Vapors Area Classification and Related Electrical Design for Combustible Dust Wiring Methods and Material Selection Grounding and Overvoltage Protection Lighting Security Lighting of Plants Substation Layout Motor Application Instrument and Essential Services Power Supplies Low Voltage A-C Motors Up to 200 HP (150 kW) A-C Motors: Medium Voltage and Low Voltage Over 200 HP (150 kW) Synchronous Generators Power Transformers Neutral Grounding Resistors Switchgear, Control Centers and Bus Duct Control of Secondary Selective Substations with Automatic Transfer Field Installation and Testing of Electrical Equipment

OTHER REFERENCES ANSI/IEEE (Institute of Electrical and Electronics Engineers) Standard 141, IEEE Recommended Practice for Electrical Power Distribution for Industrial Plants (IEEE Red Book) NEMA MG1, Motors & Generators NEMA C84.1, Electric Power Systems & Equipment - Voltage Ratings

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BACKGROUND The electric power distribution system is part of the overall plant utility system and provides electric power to onsite, offsite and utilities areas. The power distribution system may be supplied by purchased power, in-plant generated power, or by a combination of the two sources operating in synchronism or as separate sources (see Section XXX-A, Power Sources). Emergency power sources are normally provided to supply critical services during total power failures for plants which are supplied solely by purchased electric power. Voltage ranges typically used in ExxonMobil plant distribution systems are 400 to 660 volts for low-voltage systems; 2.4 to 36 kV for medium voltage systems, and 69 kV where high voltage distribution systems are used. Plant loads are almost exclusively motors driving rotating equipment (pumps, compressors, fans and blowers) required in the process, offsites and utilities facilities. In chemicals and synthetic fuel plants, there will also be solids handling equipment loads. In addition to the loads mentioned, the electric power distribution system will also serve instrument power and computer power supply equipment and plant lighting. For various reasons, such as safety, economics and maintenance, the usual design embodies substations of convenient sizes located near the loads. These “plant” substations are generally in buildings of masonry construction and in the case of refineries, there is generally one for each major process unit. Areas of lower load density, such as offsites, may be served by smaller substations in masonry buildings or metal enclosures. The smaller groups of loads may be supplied from switchracks installed outdoors. Distribution switchgear is controlled locally (at the breaker) and may also have remote control from a utilities or main control room. Motor control stations are always located adjacent to the motor and do not have facilities for starting the motors from their switching devices (starters) in the substation. In some cases a motor may, in addition to the control station at the motor, have an emergency stop switch in the control room and/or automatic starting by means of a process pressure switch or other device.

DEFINITIONS (Refer to Section XXX-A and the following.) Plant All the facilities at one geographic location. These may consist of one or many individual process units. The following are plants: Refinery, Mine, Chemical Complex, Pipeline Pumping Terminal, etc. Plant Main Substation The substation which provides power to the whole plant. Unit Substation A substation that is the last in line providing power to an individual unit within a plant. It is generally located on the same block as its associated unit or could supply power to more than one unit. In refineries and chemical plants, the unit substations that supply process units are called process unit substations. Offsite unit substations are identified by the unit they serve, such as cooling water pumphouse substation. Source The point(s) of power supply to a plant. Examples are generators and incoming power circuits from a utility company. Switchrack A group of switches and/or motor starters mounted together on a rack. They are usually located outdoors and may be protected by a roof but without any side walls.

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EQUIPMENT TYPES AND APPLICATION POWER TRANSFORMERS Oil immersed transformers with natural cooling (Type OA), i.e., natural oil circulation and natural air circulation, are generally used and in most cases have the capability to increase their rating by adding fans to force circulate the air (Type FA). The OA and FA ratings should be specified even when the fans are not fitted. By the insertion of an oil pump in the return cold oil pipe to the tank from the radiator, it is possible to increase the dissipation from the radiator surface as compared with natural oil circulation. This increased rating is designated as Type FO. When both fans and oil pumps are added, the rating is designated as Type FOA for one stage and Type FOA/FOA for two stages. The percentage increase in transformer rating for the various cooling methods depends on the transformer OA rating and is given in IP 16-10-1 and industry standards. The oil system may utilize a sealed main oil tank or have an auxiliary oil tank called a conservator. Generally, units 20 MVA and larger are equipped with conservators. For smaller units, the conditions of operation and local practice, i.e., sealed units in the Americas and conservator units in European locations and regions following European practices, determine the type of oil tank. With conservator units, a Buchholz relay is used for transformer protection. On sealed units, a sudden pressure relay is provided (see Section XXX-E). Other than on main source transformers or generator transformers, it is rare to provide automatically operated load tap changers. Manually operated tap changers for de-energized operation are fitted on unit substation transformers. Four taps are provided at ± 2.5% and ± 5%, which is an industry standard. Reactance or impedance of the transformer is generally the manufacturer’s standard unless the design requires a special value, which may be the case for a captive transformer which powers a motor or to decrease short-circuit current to permit the use of lower interrupting capacity switchgear. It should be quite clear as to whether the value of reactance or impedance, generally expressed as a percentage, refers to the OA or FA rating. Generally for in-plant distribution transformers, the OA rating is the base, but for larger units with integral fans and oil pumps, the FA rating may be the base. Manufacturers will provide any voltage winding, the only limitation being that, to have a very high, high voltage winding and very low, low voltage winding on the same transformer would increase the cost. Transformers with a ratio 15/0.4 kV are readily available. Difficulty may be encountered in increasing the ratio beyond this, hence, it should be checked with manufacturers. As a rule, the transformers installed in ExxonMobil plants are manufacturer’s standard except that the switches on the thermometer and Buchholz (or fault pressure relay) are hermetically sealed. Transformers are installed outdoors. Indoor location of transformers is limited to applications where an outdoor location cannot be used for such reasons as appearance, noise level, architectural considerations, etc. Transformers located indoors should be either dry type or filled with a non-flammable liquid. All energized parts should be enclosed. This does not present any problem for transformers located at the plant substations.

SWITCHGEAR For plant substations, switchgear is usually indoor, metal-clad type with the breaker cubicles bolted together to form a switchgear lineup. Breakers are withdrawable for isolation and maintenance purposes. They may be air break, air blast, bulk oil, minimum oil, SF6, or vacuum type. Voltage and current transformers are located in or on the switch cubicles where required. The choice of breakers will depend on cost, space and maintenance. ExxonMobil plants have all the above types in use. All the circuit breakers in a switchgear lineup must be rated for the maximum fault level, but their continuous current rating may vary. For the higher fault levels, breakers are not made in the lower current ratings, therefore, some breakers may have a much higher continuous current rating than would otherwise be required. A 125 volt d-c battery is usually required for control of the switchgear. Other control systems such as a-c close and d-c trip (with a 48 volt tripping battery) or a-c close and capacitor trip, are sometimes used to suit special conditions. Where a d-c battery is required, this is located in the same room as the switchgear, except where local codes require a separate battery room. This was necessary when the battery cells consisted of open-top glass jars with the electrodes suspended in them, generally without any spacers between the plates. With this type of construction, droplets of acid would be given off at highcharge rates, which are harmful both to equipment and personnel, hence, the need for a separate room and exhaust fan. Currently, all cells, both in acid and alkali batteries, have covers and are fitted with breathers and filler plugs to prevent any acid getting into the atmosphere.

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EQUIPMENT TYPES AND APPLICATION (Cont) The battery can be considered the heart of the electrical system, as without it, all the electrical protective devices are useless. It is, therefore, very important to have a good battery and charger. Despite the very high reliability required, it is not normal to provide duplicate batteries or chargers as both, when well designed and maintained, are extremely reliable. However, when separate switchboards are used to increase reliability, or break up a network for other reasons (examples are stub busses on a synchronizing bus network, and generators connected to different switchboards), separate battery/chargers should be considered for each switchgear lineup. A process substation with several switchgear lineups at various voltage levels would normally only have one battery/charger to serve all the lineups. The size of the battery will depend very much on the type of switchgear closing mechanism. Solenoid closing requires a much larger battery than motor wound spring type. However, this should not deter the use of solenoid closing where available as it is generally less expensive, simpler, and permits faster reclosure. The selection of the closing method should be based on total cost, reliability, etc. Solenoid closing is no longer available in the U.S.A. Switchgear, in addition to being used to control the transmission and distribution network, may also be used to control medium voltage motors and the larger low voltage motors. This can be an arduous duty for circuit breakers, especially for drives, such as loading pumps, which are switched frequently. Before using a circuit breaker as a motor starter, it should be checked with the manufacturer.

MOTOR CONTROL CENTERS & TURNAROUND POWER CENTERS (MCCS & TPCS) MCCs and TPCs consist of multi-tier starters housed in steel cubicles with horizontal and vertical busbars that permit cubicles to be joined together. Supply to the MCC is obtained either by connecting the horizontal busbars directly, by bus duct, or by a cable fed from a circuit breaker on the main low voltage switchgear. MCCs may be at medium voltage or low voltage, whereas TPCs are always at low voltage. The MCC provides control for process motors, whereas the TPC feeds the circuits required during a turnaround, i.e., lighting, welding outlets, convenience outlets, substation auxiliaries, etc. The philosophy being that the MCC can be isolated during a turnaround. This cannot always be achieved, nevertheless, with this approach it should be easier to shutdown an MCC for extensions and maintenance. The reliability of the MCC should be at least equal to the TPC. A short interruption of power to the TPC may not cause any plant upset, whereas for an MCC it would be serious. Control room and computer power supplies may be obtained from either the MCC or from the LV switchgear. As there will always be at least two circuits to control rooms and computer power supplies, it is possible to obtain the power from two MCCs or either side of the LV switchgear (see IP 16-8-1). Control power for the MCCs/TPCs is nearly always obtained from each starter power circuit; hence no external d-c is required. The fault level capability of the MCC/TPC can limit the size of the main transformers supplying the power. This can have a considerable cost impact, thus the maximum size of low voltage transformers that can be used should be confirmed at the Planning or Class V estimate stage.

CABLES AND BUS DUCT Cables are required to supply power from the plant main substation to the process unit substations and offsite substations, and from the process unit substations and offsite substations to the loads (see Figure 8). The connection between the transformer secondaries and the switchgear may be cable or bus duct. Cabling methods vary from country to country and from refinery to refinery. However, the following may be used as a rough guide: In the Americas, the onsite cabling method usually consists of single or multicore unarmored cables installed in conduits. An exception is the connection between the transformer secondary and the switchgear, which is bus duct. In the rest of the world, direct buried multicore (3 or 4 core) armored cable is usually used, either directly buried or pulled into conduits at roadways and congested areas. These conduits may be made of plastic, concrete, or some other composite material. The conduits or duct bank are not necessarily sealed at the ends other than to keep out sand and soil, as the cable is suitable for direct burial. With this type of installation, the cable is suitable for installation in the area classification where it is terminated so it does not require any additional protection above grade. Offsite cable runs throughout the world are generally directly buried armored cables. Outside the Americas, bus duct is not readily available except for larger generator connections, therefore, the connection between the transformer secondary and the switchgear is often made with either single core or multicore cables.

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EQUIPMENT TYPES AND APPLICATION (Cont) SQUIRREL CAGE INDUCTION MOTORS Most of the motors used in ExxonMobil plants (over 98%) are squirrel cage induction type. These motors offer the following advantages: •

Low cost

•

High reliability

•

Robust design

•

Non-incendiary sparking in normal operation (Conventional squirrel cage induction motors are currently acceptable in many countries as being suitable for a Class I, Division 2 area classification. They are also available in explosion-proof designs for use in a Class I, Division 1 areas with little cost premium.) Typical sizes and performance data of squirrel cage induction motors made in the U.S.A. are given in Table 1. In Europe it is more usual to designate motors by frame size (the height in millimeters from the underside of the motor feet to the centerline of the shaft) and then state the kW outputs depending on voltage, class of insulation, speed, type of cooling, etc. (see Table 4). There is a rough relationship between output and voltage of motors as illustrated in Figure 12. It is possible to have machines specially constructed outside these limits, but the cost could be high. The motor-rated voltage, especially at low voltage (660 volts or less) is nearly always below the system-nominal voltage to allow for the voltage drop in the motor feeder and in some cases, the transformer. This is explained in more detail in the Basic Design Considerations below. Typical values of system-nominal voltage versus motor-rated voltages are given in Table 2.

BASIC DESIGN CONSIDERATIONS NUMBER OF SUBSTATIONS & THEIR LOCATION Each onsite process unit will require its own substation unless the load is very low, say less than 1 MVA. Some of the process units with large electrical loads may require several substations. The deciding factors are the maximum transformer capacity that can be used and the distance of the loads from the substation. Ideally the substations should have the largest transformers possible to reduce the cost, on the other hand, the outgoing cables to the motors should be as short as possible, particularly in the case of the larger low-voltage motors. Transformer size will be limited by either the continuous current rating of the incoming circuit breakers or the short circuit rating of the downstream switchgear/MCC/TPC. A good rule of thumb is to limit low voltage cable runs to 600 ft (180 m) maximum with a target of 300 ft (90 m) or less, if possible. Whenever possible, all cables from the substation to motors should be of one continuous length without any splices (joints). Flexibility is required to isolate and maintain the equipment. This generally entails limiting a substation to supply only one main process unit and its associated processes, thus, permitting major maintenance and switchgear extensions to be carried out during that plant’s turnaround. If one switchgear supplies motors on two large independent process units, it may be very difficult to shutdown even one half of the switchgear for maintenance or extension if the process units do not have the same turnaround dates. Several switchgear lineups and MCCs/TPCs may be located in one substation building, but two important factors must be considered: •

Space is required for the outgoing cables. The more cables there are leaving a substation the more difficult it is to find a route for them from the substation to the loads. Also, the more cables in a group the greater the ampacity derating factor.

•

If a substation supplies two or more facilities and one or more of the facilities is critical and independent, the minimum spacing between the substation and process equipment is required to be three times greater than if the substation only supplied one facility (see IP 16-6-1).

Substations must be located at the edge of process units at a distance of 50 to 150 ft (15 to 45 m) from process equipment with any outdoor transformers located on the side of the substation farthest from the process unit (see Design Practice XV-G, Table 1, Item H, and IP 16-6-1).

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BASIC DESIGN CONSIDERATIONS (Cont) TYPES OF SUBSTATIONS The types of substations most commonly used in ExxonMobil plants are: •

Secondary Selective - Figure 2 (also see IP 16-12-2)

•

Spot Network - Figure 1

•

Loop Fed - Figure 5

•

Radial - Figure 6

In some cases, especially expansions, other types may be used but the above four types will suit most purposes. It is very rare for a Design Specification to include any other type. The vast majority of the substations will require a very reliable supply plus provision for maintenance. This usually means that most, if not all, substations will be secondary selective with automatic transfer. A few offsite substations could be radial or loop fed, but this is becoming more unusual as the importance of the offsite facilities is increasing. Examples of loads that could be supplied by loop fed or radial substations are: •

Administration Building

•

Product Loading Facilities

• Waste Water Treating However, with the absolute dependence on electrical power; to operate computers, typewriters, copying machines, and heating ventilation and air conditioning (HVAC) in offices; the high demurrage charges resulting from loss of product loading pumps and increased use of product pipelines; the severe restrictions imposed by national and local authorities on pollution; it is unlikely that other than a secondary-selective substation with automatic transfer (or spot-network substation) will provide adequate reliability and flexibility for these offsite loads. There may be special cases where a secondary selective substation with manual transfer should be used, such as locations where the load is small and there is no plant maintenance force, or an interruption to supply is not serious provided that it is restored within an hour.

SPOT-NETWORK VERSUS SECONDARY-SELECTIVE SUBSTATIONS The vast majority of substations, certainly all those supplying continuous process units, should be provided with two separate supplies for reliability and maintenance purposes, as discussed above. The substation types for such a design are generally limited to spot-network substations (refer to Figure 1) or secondary-selective substations with automatic transfer (refer to Figure 2). An advantage of spot-network substations is that during normal operation, with two infeeds, the voltage drop is less when starting large motors. However, due to the higher-fault level associated with the two infeeds being in parallel, it is not usually practical to install spot network substations at low voltage because of the high short-circuit level resulting from having two transformers in parallel. This limits spot network substations at low voltage to incoming transformers about 750 kVA or less. As a result, the spot-network substations in ExxonMobil plants are generally only at medium voltage. Secondary selective substations are designed with a momentary rating based on only one incomer infeed (IP 16-2-1) as it is not possible to operate with the two supplies in parallel. An automatic transfer isolates one incomer before closing the tie breaker and a manual transfer automatically trips the incomer or tie breaker that has been pre-selected whenever all three breakers are closed. Thus, the two incoming supplies can only be paralleled for a fraction of a second during a manual transfer. Since the secondary-selective substation is designed for the short-circuit rating of only one incomer, there is a smaller variation between maximum and minimum short-circuit level, as compared with the spot network which will range from the maximum level with two transformers, to the minimum level with one transformer. These large variations in short circuit level can cause problems in the protective relaying. As the system should be stable at minimum short-circuit level, which may be taken as a reference point because it is generally a limiting condition, it follows that the spot network must be designed to operate at a much higher maximum short-circuit level than a secondary-selective substation. This often involves extra cost to purchase switchgear with a higher short-circuit rating. Most substations at ExxonMobil plants are secondary selective. This is the standard design for process unit substations, unless there are very good reasons to do otherwise. There are many other considerations in selecting the type of design. A summary of some of the advantages and disadvantages is given below.

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BASIC DESIGN CONSIDERATIONS (Cont) SPOT NETWORK SUBSTATIONS •

Advantages a. Generally during normal operation, with both incomers in service, starting large motors causes less of a voltage drop and therefore results in faster starts. b. Due to the higher short-circuit level, some faults will be cleared quicker resulting in less of a disturbance. c. The loss of one of the incoming feeders, either due to a fault, false trip, or switching error, does not interrupt supply to the bus. In the case of an incoming or outgoing feeder fault, the whole bus would suffer a voltage drop until the fault is cleared, but this is much shorter than an automatic transfer on a secondary-selective substation which would leave half the bus without supply for up to three to five seconds. This may avoid a step/stage reacceleration of motors for such an incident. d. Complex automatic transfer relaying is not required and the risk of an automatic transfer not functioning correctly is avoided.

•

Disadvantages a. The ratio of maximum to minimum short-circuit level is much higher than with a secondary selective-substation. The minimum short-circuit level with only one incomer may make reacceleration much more difficult. b. The upstream (utility) infeeds must be in synchronism at all times. c. d.

f. g.

Circulating currents between sources are possible. For any fault on an incoming or outgoing feeder, the whole bus “sees” the fault and motors must reaccelerate. Depending on relay settings, this may or may not be a stepped reacceleration. Current transformers are required on the busbars for the tie breaker’s protection. In addition to reducing reliability, the busbar current transformers are more difficult to isolate when working on incomer or outgoing feeder current transformers. If the tie breaker fails to operate for a bus fault, or uncleared feeder fault, the whole substation is shutdown. Protective relaying is more complex (see Section XXX-E).

h.

Relaying required on tie breaker. Directional relays required. Relay coordination is more complex due to current flow being possible in two directions. Extra step of time graded protection added by the tie breaker relaying. Often higher cost due to the more expensive switchgear required for the higher short-circuit level.

e.

SECONDARY-SELECTIVE SUBSTATIONS •

Advantages a. Variation in short-circuit level from maximum to minimum is much less than for spot-network substations. Therefore, a secondary-selective substation having the same maximum short-circuit level as a spot-network substation will generally have better stability than the spot-network substation when operating on one source. b. If stability is not a problem with a secondary-selective substation, it may be possible to use switchgear with a lower short-circuit rating than would be required for a spot-network substation while maintaining the same minimum operating short-circuit level and thus achieve a cost saving. c. For a disastrous failure, such as a loss of the d-c control power or a stuck breaker(s) during a fault condition, only half the substation will be lost. d. No current transformers on the busbars, which improves reliability. e. No directional overcurrent relays are used. These are often wired incorrectly and are much more difficult to test than non-directional overcurrent relays.

•

Disadvantages a. Auto transfer relaying is complex, and half the substation would be lost if the transfer does not operate properly; but the circuit in IP 16-12-2 is fully proven. b.

During normal operation, the short-circuit level for motor starting may be lower than in a spot network substation with both infeeds, thus resulting in longer run-up times.

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BASIC DESIGN CONSIDERATIONS (Cont) FEEDING ARRANGEMENTS FOR SUBSTATIONS Power supplies to the process unit substations and offsite substations should be arranged to comply with the following requirements: •

The two incoming feeders to a secondary selective (or spot network) substation should be supplied either from different substations or different sides of a tie breaker (section switch) of a switchgear lineup.

•

The continuous current rating of feeder breakers should be utilized as fully as practical. This generally entails tapped feeders (see Figure 7) to several substations, especially if the voltage is in the 15 to 25 kV range.

•

Flexibility should be maintained. A fault on the feeder cable to one process unit substation should not have a serious impact on another process unit. The ideal power supply arrangement would be for each transformer to have its own primary circuit breaker. This is generally not economically practical because it would result in using expensive circuit breakers carrying only a fraction of their rated current, hence the use of tapped feeders. However, great care must be taken in feeding several substations from one circuit breaker. Some guidelines to consider are: •

Utility substations that power the air compressors, boilers, cooling towers, power plant auxiliaries, etc., should not be supplied from the same circuit breaker as a process unit substation. An exception to this is when the plant is very large and designed on the unit concept where the utilities in question are only associated with a particular process unit, then they may be supplied from the same feeder breaker as that process unit.

•

Transformers that provide power to the same process unit, for example, the medium-voltage and low-voltage transformers in a process unit substation, are ideal candidates for sharing the same feeder breaker.

•

Where possible, transformers that share a feeder breaker should be fairly close to each other, say no more than a block or two away, to avoid the loss of power to one half of a substation for a fault in a cable feeding another substation that is far away. Increasing the number of transformers on a tapped feeder: Lowers the reliability Makes the system more difficult to maintain Increases the impact of a cable or transformer fault on the electrical network.

•

Design for tapped feeders must be in accordance with IP 16-2-1, which requires isolators or links and interlocks.

Also, it should be possible to isolate a transformer in a process unit substation without creating a major maintenance problem. This means that very careful consideration should be given as to how many and which substations are fed from a single breaker in the main substation by means of tapped feeders.

SERIES VERSUS PARALLEL TRANSFORMATION The low voltage transformers may be fed either at the medium voltage motor supply voltage (Series transformation, refer to Figure 3) or at the distribution voltage (Parallel transformation, refer to Figure 4). The series transformation arrangement was used in some of the older ExxonMobil designs, but most new installations use parallel transformation. As a general rule, parallel transformation should be used unless there is a very good reason for doing otherwise. Parallel transformation is generally more economical than series transformation and reduces voltage drops during motor starting and reacceleration. All the ExxonMobil designs prior to the early 1950’s were series transformation in line with the accepted electrical network design customs of transforming down from one voltage level to another. In those days very few, if any, LV motors reaccelerated and the average LV transformer size was 500 kVA or less. With the introduction of higher loads and the requirement for most motors to reaccelerate, the impedance of series transformation became a serious impediment, therefore, parallel transformation was adopted and is now the standard design. Instances where series transformation may be used as an exception are: small low voltage transformers, say less than 500 kVA, and for the power supply to a radial substation where a long primary feeder cable may be avoided. This reduces the downtime of the feeder cable, which would have to be switched off to isolate any of the other transformers supplied from the same primary breaker.

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BASIC DESIGN CONSIDERATIONS (Cont) VOLTAGE LEVELS Any plant of 10 MW or more will have several voltage levels, as the incoming supply from the power utility company will probably be 10 kV or higher and utilization voltages for motors, which constitute most of the load, will be in the range of 3 to 6 kV for the medium voltage motors and 660 volts or below for the low voltage motors. This is illustrated in Figure 12. There will always be a low voltage and there may be one or two medium voltage levels in addition. If two medium voltage levels are required for motors, they should be near the extreme ends of the medium voltage range and not be close to each other. For example, 3.3 kV and 6.6 kV usually would not be used on the same plant. Sometimes there are exceptions for very good reasons, one example being a plant which has 2.4, 4.16, and 6.6 kV. However, this should be avoided wherever possible. It is desirable to limit the number of voltage levels at any one plant to the minimum for standardization, thereby reducing the number of different voltage classes of cables, transformers, switchgear, and motors. Typical voltage levels in a plant in the U.S.A. would be 13.8 kV, 4.16 kV, and 480 volts, whereas in Europe, they may be 10 or 15 kV, 3.3 kV and 400 volts. There is an increased use of 660 volts as the standard for low voltage systems. This reduces voltage drop and copper losses on the present range of low voltage motors, plus extends the low voltage motor range to higher kW ratings. When used, lighting transformers are required to obtain the lower voltages, but it is generally justified in ExxonMobil plant applications where most of the load consists of motors.

NOMINAL VOLTAGE In all parts of the electrical system, the voltage will vary depending on the load and the source supply regulation; therefore a measured voltage may not be the design or nominal voltage. To avoid confusion, the following procedure should be adopted: •

All system voltages, unless specified otherwise, shall be taken as NOMINAL.

•

Switchgear busbars should be rated at nominal voltage.

•

Transformer secondary rated voltages will generally be the same as the nominal voltage.

•

Equipment voltages shall be nameplate values, which will usually differ from the system nominal voltage to which they are connected.

•

Motors, and in some cases transformer primary windings, will have voltage ratings that are generally lower than the nominal voltage of the system to which they are connected (see Table 2).

VOLTAGE REGULATION Voltages will vary as stated above due to changes in load on the system and regulation at the source. This is undesirable for squirrel cage induction motors, which will only perform in accordance with specification, when supplied at rated voltage and frequency. Tolerances accepted in the U.S.A. by NEMA MG-1 for induction motors are: •

Plus or minus 10% of rated voltage with rated frequency.

•

Plus or minus 5% of rated frequency with rated voltage.

•

A combined variation in voltage and frequency of plus or minus 10% (sum of absolute values) of the rated values, provided the frequency variation does not exceed plus or minus 5% of rated frequency. But MG-1 also states: “Performance within these voltage and frequency variations will not necessarily be in accordance with the standards established for operation at rated voltage and frequency.” IP 16-9-1 requires that all motors shall operate successfully at rated load: •

And at rated frequency with a voltage variation of 5% or less above or below rated voltage.

•

And at rated voltage with a frequency variation of 5% or less above or below rated frequency.

• With a combined variation in the voltage and frequency of 5% or less above or below rated voltage and rated frequency. To keep within these limits without having load tap changers in every process substation requires that: •

The process substation primary voltage is closely regulated and that

•

The motor rated voltage is carefully selected relative to the transformer secondary rated voltage.

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BASIC DESIGN CONSIDERATIONS (Cont) These requirements are met by having load tap changers on the plant (refinery) incoming transformers (see Section XXX-A) and by specifying motor rated (nameplate) voltages approximately 5% below the nominal system voltage (see Table 2). The expected spread of voltages for various operating conditions is shown in Figure 10 which assumes a 5% voltage drop in the motor feeder cable at full load. This is the maximum voltage drop permitted by IP 16-2-1, which is often the actual value for low voltage motors. The 10% voltage drop in the motor feeder during reacceleration is also a maximum permitted by IP 16-2-1. The values obtained from Figure 10 have been presented in graphical form in Figure 11 where it can be seen that motors should, at all times, other than when starting or reaccelerating, operate at a terminal voltage that varies plus and minus 2% of motor rated voltage. This is provided the motor nameplate voltage is 5% below the transformer secondary rated voltage (nominal voltage) and the transformer has a tap setting to increase the voltage 2 1/2% if there is rated primary voltage. All the above calculations assume constant voltage at the transformer primary. The voltage ranges specified in NEMA C84-1 are presented in tabular form in Table 3. Comparing these ranges with Figure 11, it will be seen that we expect to operate well within the NEMA Range, which is the more onerous range.

SYSTEM NEUTRAL GROUNDING (EARTHING) This is covered in Section XXX-D, and Section XXX-B for generators; however, it may be summarized as follows: •

High voltage systems (above 36 kV) operated by utility companies are usually solidly grounded (earthed) at the neutral point because: a. There are no rotating machines connected directly to the system. b. The cost of insulation is reduced. c. The very high ground fault currents permit fast, reliable clearance of ground faults. d. Permits use of lower cost lightning arresters with lower voltage ratings, which provide better protection against overvoltages.

•

Medium voltage systems (1001 to 36,000 volts) have the neutral grounded through a low resistance that is sized to limit the ground fault current to as low a value as possible, while permitting enough current to flow to operate the ground relaying reliably. IP 16-2-1 defines the current required for reliable operation of the ground relaying as 15 times the lowest reliable operating current of the least sensitive outgoing feeder ground relaying and five times the lowest reliable operating current of bus ground relaying. The reason for using low resistance grounding on medium voltage systems, is that in the event of a ground fault in a motor, the damage is limited to such an extent that it should be possible to repair the machine without changing any of the stator laminations.

•

Low voltage systems (up to 1000 volts) have the neutral solidly grounded to permit fast, reliable clearance of ground faults and avoid overvoltages and sensitive ground fault relaying equipment. Alternatives to the above are given in Section XXX-D. One worthy of mention is high resistance neutral grounding, which is sometimes used on low voltage systems and MV systems up to 4160 V.

WIRING METHOD A Design Specification should state the wiring method for onsite and offsite locations. It is not usual to specify the lighting and instrument wiring method, with the exception of communications and control cables. Underground wiring is the preferred wiring method that should be used wherever possible, because the cables are protected from damage by fire or mechanical means and less interference is caused with above-ground piping, etc. One exception is lighting. In offsite areas, the preferred underground wiring method is multicore, armored cable directly buried in the ground in one layer. For various reasons, such as congestion, better protection, ease of replacement or additions, the onsite (within block limits) wiring method may be either single core or multicore cables drawn into duct banks. Often there is a strong owner preference on the wiring method and this will determine the method used (see also Cables and Bus Duct above).

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BASIC DESIGN CONSIDERATIONS (Cont) SYSTEM RELIABILITY After designing a system in accordance with Section XXX-A and the preceding portion of this section, the reliability should inherently be adequate. However, some special attention may be required to certain aspects of the design, such as automatic load shedding, special protective relaying, or computer studies to ensure system stability is maintained during abnormal conditions. Additionally, computer studies may be required to confirm that the system has adequate steady state and transient stability. Whatever studies, re-design, or modifications are required to ensure that the system designed will be reliable should be carried out, before the Design Specification is issued and later confirmed by the contractor’s studies. If from experience it can be assured that the Design Specification offers a reliable design, studies by the contractor only may be acceptable. An important aspect of system reliability is system stability. Loss of stability can be divided into two main parts: •

Loss of synchronism by synchronous machines.

• Collapse of voltage that prevents motors from reaccelerating. The former is covered in Section XXX-B, which can be applied to plants, which are supplied by in-plant generation only or inplant generation and purchased power. For systems, which are supplied by purchased power only, the main stability aspect is whether synchronous motors lose synchronism and induction motors stall either during a system disturbance such as a fault or in the recovery after the disturbance. For the synchronous motor, in most cases, either the synchronous motor field is removed by protective relaying or the motor is shutdown. When only the field is removed, the motor operates as an induction motor and the considerations mentioned below apply. For the induction motor and the synchronous motor appearing as an induction motor, the voltage at the motor bus after the system disturbance is cleared must be restored to the level, which will permit the motor to reaccelerate the driven equipment to normal speed. The design considerations for this condition are covered in Section XXX-B under Motor Starting and Reacceleration.

LOAD SHEDDING A load shedding system, to cope with system disturbances, is required normally for the following: •

A plant, supplied by purchased power operating in synchronism with in-plant generation, which does not have sufficient capacity to supply the plant load when the purchased power supply fails.

•

Plants having in-plant generation only. Load shedding is the economical way to provide process and electrical system protection against double and higher contingency losses of capacity for which additional reserve in generation cannot be justified. Load shedding is usually not needed for plant systems supplied by purchased power only. In unique situations where a purchased power supply may have limited capacity or maximum capacity level established by protective relaying during single source operation, it may be necessary to provide a load shedding logic system. A similar situation might arise in an existing inplant substation, which becomes unacceptably overloaded during single-ended operation. Section XXX-B covers load shedding system design considerations in detail including design criteria and calculation procedures. Some additional design considerations for the plant having in-plant generation operating in synchronism with a purchased power supply are: •

The protective system should operate in the following steps: a. Detection of the disturbances in the public utility system. These can be either voltage interruptions due to shortcircuits, or frequency decay caused by generation capacity loss. b. Operation of protective relays to separate the busses supplied by in-plant generation from the purchased power supply. c. Load shedding by logic if in-plant generation capacity, which normally should be in operation, is not in service. d. Load shedding by frequency relays detecting frequency decay caused by load in excess of available generation capacity. This load shedding usually occurs in steps until generation capacity is sufficiently in excess of load to halt the frequency decay and the prime mover has sufficient torque to increase frequency to acceptable, continuous operation levels.

•

Usually this step sequence operates so quickly that often no turbine governor action is assumed. Also, frequency decay automatically causes load decay at rates of approximately 2% load decay per 1% frequency decay. Unless the load shedding step components are known quite accurately, it is advisable to try to provide an adequate system without using this margin.

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BASIC DESIGN CONSIDERATIONS (Cont) REACCELERATION The need for reacceleration following a voltage dip or short interruption to the power supply is determined by process and utility designers and is indicated in the Process Design Specification. Automatic reacceleration control details are specified in the Electrical Design Specifications and International Practices. Standard squirrel cage induction motors normally have adequate torque capability to permit automatic reacceleration of centrifugal pumps and compressors even when fully loaded. Automatic reacceleration of synchronous motors and motors driving positive displacement compressors (reciprocating and screw type) require close coordination between machinery and electrical specialists. Automatic unloading devices are required on positive displacement compressors, which are to be reaccelerated. The need for automatic reacceleration is classified as follows:

CLASSIFICATION

NEED FOR AUTOMATIC REACCELERATION

A

Necessary

Motor driven equipment required to keep the unit operating without equipment damage and without safety valves blowing, but not necessarily on product specifications.

B

Desirable

Additional motor driven equipment required to keep unit products on specification.

C

Unnecessary

Manual restart is sufficient without adverse effect on unit or product specifications.

BASIS

Motor driven pumps with steam turbine driven standbys specified for automatic start will be included in Classification A as protection against the contingency that either the standby pump, its turbine driver, or the automatic start-up facilities may be undergoing maintenance at the time of a voltage dip. IP 16-2-1, Power System Design, specifies how the reacceleration classifications are to be implemented in detailed system design. Relative priorities must be specified among the pumping services, and between the pumping services and the other motor driven equipment in the plant (air-cooled heat exchangers, compressors, etc.) to implement the sequencing of reacceleration. The “memory” time (the maximum time a loss of voltage can occur before the reacceleration relays abort) may be specified in the Design Specification. This time generally varies from 5 to 20 seconds. Factors that determine the “memory” time are: •

The maximum acceptable time the process can accept an outage and restart safely. This time can be very short for furnaces.

•

The capabilities of the electrical system.

•

The electrical protective relay settings.

•

The “memory” time of other associated process units, i.e., it may be undesirable to have part of a refinery reaccelerating while the other part is shutdown.

DESIGN PROCEDURE DESIGN BASIS During the planning and early design stages, the design basis must be established so that the design specification includes all requirements needed to conform to the basis. Setting the design basis requires close collaboration with the process and offsite facilities designers, the power generation system designer (when applicable) and with the Owner. Expansion or revamp projects, which require integration with an existing system, place more constraints on the designer’s alternatives than grassroots’ projects. These constraints must be identified in the early planning stage, if possible.

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DESIGN PROCEDURE (Cont) The designer must: 1. Obtain load data for all new process units and offsite facilities and also for existing process and offsite facilities in the case of expansion of revamp projects. 2. Identify all planned normal and abnormal operating conditions for process and offsite facilities, which affect the electrical system design. 3. Develop the basic distribution system design alternatives and determine operational and capacity limitations of specific alternatives. 4. Select the optimum design with respect to reliability, operability, and cost. 5. Make design provisions for special equipment applications, such as motors above 1,100 kW. 6. Obtain Owner’s acceptance of the selected design and its limitations or modifications required to provide the capability, which the Owner considers necessary. Following are the specific items of the design basis and the point in design engineering at which they are established: •

Design Basis Engineering (DBM) Stage Purchased power or in-plant generation or combination. Basis determined by driver study. Voltage level, location, and basic details of purchased power supply circuits, in-plant switching station (if required), and split of responsibility between public utility and plant. Configuration of main substation stepdown transformers and main distribution switchgear (secondary selective, spot network, etc.). Approximate location, number and size of unit substations and load assignments at medium and low voltage levels. Approximate number of distribution circuits from main substation to unit substations. Identification of motor service above 1,100 kW or other applications requiring special attention. Identification of any motor service above 15,000 kW and tentative selection of motor type and starting method to assure technical acceptability of selection, and adequacy of cost information. Wiring method for distribution circuits (for cost purpose only). System neutral grounding. Instrument power supply design basis. Emergency power system design basis.

•

Design Specification Stage Finalize the design to a degree that will permit a contractor to construct a plant that will meet the design basis by using the Design Specification and International Practices. (The contractor does not have a copy of these Design Practices and must not be given one.)

•

Design Considerations State the reasons why the Design Specification was so written. Detail alternatives considered and reasons for those rejected. (This is a very useful document that should be prepared concurrently or immediately after the Design Specification. It is used by the Owner and Project Management Team. As a general rule the contractor is not given a copy.) Section XXX-A includes an Electrical Design Specification Guide, a Design Specification Checklist of International Practice Asterisk Items, and a sample Design Specification No. 94-1.

COMPUTER PROGRAMS Refer to Section XXX-A, for information on applicable computer programs.

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SYMBOLS

Circuit Breaker or Fused Switch - Closed During Normal Operation.

Circuit Breaker or Fused Switch - Open During Normal Operation.

Isolator - Closed During Normal Operation.

Isolator - Open During Normal Operation.

Two Winding Transformer.

Reactor.

Alternator.

M

Motor.

ExxonMobil Secondary-Selective Substation with Automatic Transfer as Per IP 16-12-2.

DP30CF0

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TABLE 1 TYPICAL EFFICIENCY AND POWER FACTORS OF SQUIRREL CAGE INDUCTION MOTORS(1)

MOTOR RATING HP

Load(2) kW

0.75

1

1.12

1-1/2

1.50

kW

MOTOR EFFICIENCY (%)(3) AT FULL LOAD CAPACITY

MOTOR CONNECTED

POWER FACTOR (%)(4) AT % OF FULL LOAD CAPACITY

2 Pole

4 Pole

6 Pole

50

75

100

0.98

—

80.5

75.5

53.5

65.5

75.4

1.42

78.5

81.5

82.5

54.0

73.5

80.5

2

1.86

81.5

82.5

82.5

54.5

68.0

77.0

2.25

3

2.76

82.5

84.0

84.0

55.5

68.0

75.5

3.7

5

4.39

85.5

85.5

85.5

60.0

71.0

78.0

5.6

7-1/2

6.65

85.5

87.5

87.5

58.0

70.0

77.0

7.5

10

8.78

87.5

87.5

87.5

65.5

75.5

80.5

11.2

15

13.00

87.5

88.5

89.5

76.0

84.0

87.0

15

20

17.05

88.5

90.2

89.5

79.0

84.5

87.0

18.7

25

21.00

89.5

91.0

90.2

79.0

84.5

87.0

22.5

30

25.10

89.5

91.0

91.0

80.0

85.0

88.0

30

40

33.5

90.2

91.7

91.7

81.0

86.0

88.5

37

50

41.7

90.2

92.4

91.7

82.0

87.0

89.0

45

60

49.7

91.7

93.0

91.7

82.0

87.0

89.0

56

75

62.1

92.4

93.0

93.0

82.0

87.0

89.0

75

100

82.0

93.0

93.6

93.0

85.0

89.0

91.0

93

125

102.0

93.0

93.6

93.0

85.0

90.0

92.0

112

150

123.0

93.0

94.1

94.1

85.0

90.0

92.0

150

200

161.0

94.1

94.5

94.1

87.5

91.0

92.0

187

250

201.0

95.7

95.4

95.2

84.0

87.7

90.5

225

300

241.0

95.7

95.7

95.1

84.4

88.2

90.9

260

350

281.0

95.8

95.7

95.2

84.8

88.5

91.1

300

400

320

95.8

95.7

95.3

85.0

89.0

91.3

336

450

360

95.8

95.7

95.4

85.1

89.0

91.6

375

500

399

96.0

95.6

95.3

85.3

89.2

91.6

450

600

478

96.0

95.8

95.1

85.5

89.5

91.8

525

700

557

96.1

95.9

95.4

85.7

89.7

91.9

600

800

636

96.0

95.7

95.5

85.8

89.8

92.0

675

900

715

95.8

95.9

95.5

85.9

89.9

92.0

750

1000

793

96.0

96.0

95.7

85.9

89.9

92.1

933

1250

988

96.5

96.1

95.9

86.0

90.0

92.2

1125

1500

1185

96.8

96.3

96.0

86.1

90.1

92.3

1312

1750

1380

96.9

96.4

96.1

86.2

90.2

92.4

1500

2000

1575

96.9

96.5

96.1

86.3

90.4

92.5

Notes: (1) Applies to energy efficient, enclosed motors rated 3-phase, 60 Hertz. For motors up to 200 HP, the data are from NEMA Std. MG -1. Above 200 HP, the data are based on typical vendor data. These data may also be used for 50 Hertz motors for early planning studies where vendor data are not available. kW

(2)

Connected Load =

(3)

Efficiency and losses are determined in accordance with IEEE Std. 112, Standard Test Procedures for Polyphase Induction Motors and Generators. The efficiency is determined at rated output, voltage and frequency. Power factor values are based on typical vendor data. Above 1500 kW, use the 1500 kW values until specific vendor estimates are obtained.

(4) (5)

Efficiency @ Full - Load

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TABLE 2 TYPICAL EQUIPMENT VOLTAGE RATINGS FOR MOTOR CIRCUITS SYSTEM NOMINAL VOLTAGE AND VOLTAGE OF TRANSFORMER SECONDARY AND BUSBAR RATING

MOTOR NAMEPLATE VOLTS

400

380

440

415

480

460

690

660

2,400

2,300

3,300

3,150

4,160

4,000

6,600

6,300

6,900

6,600

13,800

13,200

Notes: (1)

The transformers with a secondary winding of low voltage will generally have their primary winding tap changer set at minus 2-1/2% to give a 2-1/2% increase in secondary voltage over the rated ratio.

(2)

Medium voltage systems may operate with the transformer tap changer at nominal, as the voltage drop for motor feeders may be negligible.

(3)

Rated voltage is assumed at transformer primary.

TABLE 3 NEMA C84-1 VOLTAGE RANGES PERCENT OF BUSBAR NOMINAL VOLTAGE SYSTEM NOMINAL VOLTAGE

TYPE (1)

Above Systems up to 600 V Systems above 600V

RANGE B (2)

RANGE A Below

Above

Below

Busbar volts

5

5

5.8

8.3

Utilization voltage

4

10(3)

5.8

13.3(4)

Busbar volts

5

2.5

5.8

5

Utilization voltage

5

10

5.8

13.3

Notes: (1)

The utilization voltage is measured at the motor terminals or lighting fixture, etc.

(2)

Care should be taken before applying Range B in ExxonMobil plants as it will be noted that above 600 volts the utilization range is 20%!

(3)

For lighting minimum is 8.3% below bus nominal.

(4)

For lighting minimum is 11.7% below bus nominal.

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TABLE 4 TYPICAL RATINGS IN KW OF SQUIRREL CAGE INDUCTION MOTORS RELATIVE TO I.E.C. FRAME SIZES

380 VOLTS FRAME SIZE

2 POLE

4 POLE

63

0.25

71

0.55

0.18

80

0.75

1.1

0.55

0.75

90

1.5

2.2

1.1

1.5

100

3.0

2.2

3.0

112

4.0

4.0

0.37

132

5.5

7.5

160

11.0

15.0

180

22.5

200

30

225

45

250

55

18.5

5.0

7.5

11.0

15.0

18.5

22.0

37

30 37

45

75

55

75

280

90

110

90

315

132

to

190

132

355

225

to

560

180

110 to

190 530

661 TO 4160 VOLTS FRAME SIZE 355

2 POLE 225

to

680

4 POLE 210

to

500

400

930

to

1120

650

to

800

450

1250

to

1600

950

to

1250

4161 TO 6600 VOLTS FRAME SIZE

2 POLE

4 POLE

355

250

to

375

260

to

400

530

to

650

460

to

335 560

450

900

to

1200

700

to

1000

Notes: (1)

The frame size is the distance in millimeters from the underside of the motor feet to the centerline of the shaft.

(2)

The ratings given in kW are typical values and should only be used as a rough guide. Actual values will depend on the class of insulation, etc., and may, in addition, vary from manufacturer to manufacturer.

(3)

The purpose of this table is to highlight the fact that there is no I.E.C. standard HP or kW list of ratings. There is instead this list of standard frame sizes. Outputs for a particular frame size can vary considerably for various reasons. One example being a motor with Class H insulation will have a much higher output for the same frame size than a motor with Class B insulation. However, for our applications where the insulation is generally Class B or F, and cooling is generally by air, the above table gives a good guide as to the output rating that can be expected for a particular frame size.

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FIGURE 1 SPOT-NETWORK

FIGURE 2 SECONDARY-SELECTIVE

DP30CF01

DP30CF02

FIGURE 3 SERIES TRANSFORMATION

FIGURE 4 PARALLEL TRANSFORMATION

MEDIUM VOLTAGE

DP30CF03

LOW VOLTAGE

FIGURE 5 LOOP FED SUBSTATION

DP30CF04

FIGURE 6 RADIAL SUBSTATION

DP30CF06 DP30CF05

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Section XXX-C

Page 21 of 29

December, 2000

FIGURE 7 TAPPED FEEDERS (SEE IP 16-2-1, TAPPED FEEDERS)

Link DP30CF07

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ELECTRIC POWER FACILITIES

Page 22 of 29

POWER DISTRIBUTION DESIGN PRACTICES

December, 2000

FIGURE 8 TYPICAL ONE LINE DIAGRAM FOR A SMALL PLANT WITH MAIN SUBSTATION 10 TO 25 KV

Utility Co. Substation

HV or MV - 10 To 25 kV Main Substation

M Motor 6 MW

MV or LV Offsite Substation

MV

LV Processing Unit S/S

MV Offsite S/S

LV

LV Offsite S/S

LV Offsite S/S

ExxonMobil Research and Engineering Company – Fairfax, VA

DP30CF08

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Section XXX-C

POWER DISTRIBUTION DESIGN PRACTICES

23 of 29

December, 2000

FIGURE 9 TYPICAL ONE LINE DIAGRAM FOR A SMALL PLANT WITH MAIN SUBSTATION 3 TO 6 KV

Utility Co. Substation

MV

LV

LV

Page

LV

LV

LV DP30CF09

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ELECTRIC POWER FACILITIES

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POWER DISTRIBUTION DESIGN PRACTICES

December, 2000

FIGURE 10 MOTOR VOLTAGES FOR VARIOUS OPERATING CONDITIONS

Ratio X/105V Tap 2 1/2%

Ratio X/105V Tap 2 1/2%

Ratio X/105V Tap 2 1/2%

Ratio X/105V Tap 2 1/2%

2% Drop

Zero Volt-Drop

4% Drop

5% Drop

105 V Measured

107 V Measured

103 V Measured

102 V Measured

5% Drop

5% Drop

100 V Measured M

5% Drop

102 V Measured

10% Drop

98 V Measured

92 V Measured

M

M

M

NORMAL OPERATION

TURNAROUND

SINGLE ENDED

STEP RE-ACCELERATION

Transformer 50% Loaded

Transformer On Very Light Load

Transformer Fully Loaded

Single Ended. Last Step Of Re-Acceleration

• Sketches are for a secondary-selective substation with each transformer loaded to approximately 50% during normal operation. • Motor NAMEPLATE voltage is 100 volts. • Transformer RATED secondary voltage is 105 volts. (e.g., 10 kV/105 V) with tap changer set to increase low voltage 2-1/2% (2% shown in sketch). • Transformer reactance in 5% range with assumed volt drop of 2% at half load and 4% at full load based on power-factor between 0.8 and 0.9 lagging. • NOMINAL voltage of above busbar is 105 volts, i.e., Transformer secondary rate voltage. DP30CF10

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Section

Page

XXX-C

POWER DISTRIBUTION DESIGN PRACTICES

25 of 29

December, 2000

FIGURE 11 VOLTAGE RANGES AT MOTOR TERMINALS AND BUSBARS THAT SUPPLY MOTORS

108

104

103

100

99

Normal Operating Motor Voltage Range

101

Busbar Nominal Volts

Motor Rated Volts

98

97

96

95

94

Re-Acceleration

Percent of Motor Rated Volts

102

Volt Drop

Transformer Lightly Loaded and No Motor Feeder Volt Drop

105

Busbar Voltage range

106

Motor Feeder Volt Drop

107

Transformer

Transformer Tap 2 1/2%

93

92

DP30CF11

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ELECTRIC POWER FACILITIES

Page

XXX-C

26 of 29

POWER DISTRIBUTION DESIGN PRACTICES

December, 2000

FIGURE 12 MOTOR VOLTAGES VERSUS OUTPUTS

Motor Rating kW

100,000

Ma nu fac tur ers

Motor Rating kW

Up pe rL im

it

10,000

M

an uf ac t

ur er s

Lo w

er Li m

1,000

it

Typical ExxonMobil Range

100

Motor Nameplate Voltage KV 10

2

4

6

8

10

Motor Nameplate Voltage, kV

ExxonMobil Research and Engineering Company – Fairfax, VA

12

14 DP30CF12

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POWER DISTRIBUTION DESIGN PRACTICES

27 of 29

December, 2000

FIGURE 13 GUIDELINE FOR THE APPLICATION OF INDUCTION AND SYNCHRONOUS MOTORS 6,000

4,500

Synchronous 3,000

1,500

Kilowatts

750

600

450

Induction or Synchronous 300

150

Induction 0

Page

3600

1800

1200

900

720

600

514

450

400

360

Synchronous Speed of Induction and Synchronous Motors

ExxonMobil Research and Engineering Company – Fairfax, VA

327

300 DP30CF13

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POWER DISTRIBUTION DESIGN PRACTICES

December, 2000

APPENDIX USEFUL MOTOR FORMULAS 5,252 HP , lb-ft rpm

9,549 kW , N-m rpm

1.

Torque =

2.

The inertia value, WK2, of a driven machine judged to be “normal” by NEMA Standards is:

or

    0.95  (HP)  2 − 0.0685 WK (Load) = A  2.4    rpm     1000     where: A

or

I(Load)

=

where: A

3.

=

=

    1.5  (HP)  , lb-ft2  1.8  rpm        1000    

24 for 300 to 1,800 rpm motors and A = 27 for 3,600 rpm motors     0.95  (HP)  − 0.0685  2.4  rpm        1000    

    1.5  (HP)  , kg-m2  1.8  rpm        1000    

1.33 for 300 to 1,800 rpm motors and A = 1.50 for 3,600 rpm motors

This value provides a frame of reference only. Each rotor has a specific value dependent upon its particular geometry and weight. Driven equipment that has an intertia equal to or less than that calculated by this formula, should be able to be started by a standard motor with direct-on-line starting. For a particular machine, the time to accelerate from one speed to another is: t =

I (Nf − Ni ) 9.6 Ta

where: t = Nf = Ni = Ta = I = WK2 = GD2 = Tai = Tam =

or

t =

WK 2 (Nf − Ni ) 308 Tai

or

t =

GD2 (Nf − Ni ) 375 Tam

Accelerating time, seconds Final speed, rpm Initial speed, rpm Average accelerating torque available from driver in N-m (lb-ft) Inertia value in kg-m2 (slug-ft2) Inertia value in lb-ft2 using radius of gyration Inertia value in kg-m2 using diameter of gyration Accelerating torque value in lb-ft Accelerating torque value in kg-m

Inertia (I) is the MASS of the rotating parts times the RADIUS of gyration squared and has the dimensions ML2, whereas manufacturers generally quote a “pseudo” inertia which they may call any of the following: wr2, WR2, Wr2, WK2, Wk2 This is force times radius of gyration squared and has the dimensions ML3T-2. This value has to be divided by the gravitational acceleration “g” to obtain inertia. The gravitational acceleration is 9.807 m/sec2 (32.17 ft/sec2). Therefore: the number of Newtons = the number of kilograms times 9.807 m/sec2 or the number of pounds = the number of slugs times 32.17 ft/sec2. The other expression used in continental Europe for inertia is GD2. This is correct as far as units are concerned (MASS times length squared), but for some unknown reason the DIAMETER of gyration is used which can be confusing.

ExxonMobil Research and Engineering Company – Fairfax, VA

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POWER DISTRIBUTION DESIGN PRACTICES

For transfer of inertia through a gear, N  I1 = I2  2   N1  where: I1

5.

29 of 29

December, 2000

APPENDIX (Cont) USEFUL MOTOR FORMULAS 4.

Page

2

=

Inertia at new speed N1 and I2 = Inertia at original speed N2.

Example of calculation for sizing a pump motor: ∆P = 700 kPa,

Q = 50 dm3/s, Driver power required kW =

Pump Eo = 72%

(Q)( ∆P) (50)(700) = = 49 kW (1715)(E o ) (1000)(0.72)

where: Q = ∆P = Eo =

Flow rate in dm3/s Differential pressure (pressure rise) in kPa Pump efficiency including hydraulic and mechanical losses

or

1,000,

Q

=

Driver power required BHP = where: Q = ∆P = Eo =

∆P = 100,

Pump Eo = 72%

(Q)( ∆P) (1000 )(100) = = 72 HP (1715 )(Eo ) (1715 )(0.72)

Flow rate in US gpm Differential pressure (pressure rise) in psi Pump efficiency including hydraulic and mechanical losses

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