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Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume III – Facilities and Construction Engineering
Kenneth E. Arnold, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 12 – Electrical Systems
The electrical system of a typical oil field consists of power generation, power distribution, electric motors, system protection, and electrical grounding. The power is either generated on site or purchased from a local utility company. To ensure continuous production from an oil field, it is of utmost importance that the associated electrical systems be designed adequately. This chapter covers essential topics in the design and operation of the electrical system and discusses the construction and specification of electric motors.
Electrical Codes and Standards
Various organizations in the U.S. and other countries have developed many electrical codes and standards that are accepted by industry and governmental bodies throughout the world. These codes and standards provide guidelines or rules for design and installation of electrical systems. Table 12.1 lists some of the major local and international codes and standards used in the oil field. Refer to other electrical codes and standards, as well, as appropriate to your needs.
Also, U.S. regulatory agencies have established some requirements for the design, installation, and operation of offshore production platforms. Table 12.2 lists some of these governmental codes and regulatory documents. Other state and/or municipal regulations also may apply.
The required power for the oil field is either generated on site by engine- or turbine-driven generator sets or purchased from a local utility company. The engines or turbines may use diesel or natural gas as a fuel. Some units are dual-fueled, using natural gas and diesel. Natural-gas-fueled prime movers are most practical for normal power generation for most applications. Diesel is used where natural gas is unavailable and for units that provide black-start and emergency power.
Some remote oil fields lack access to utility power lines and require on-site power generation. In such cases, in addition to normal generators, a standby generator might be needed to provide emergency power and black-start capability. Sometimes, a standby generator is designed to handle the total facility electrical load, but usually it is designed only for essential loads.
When commercial power is purchased from a utility company, an electrical substation generally is installed near the oilfield facility. Most local utility companies bring their power into their main substation(s) through high-voltage overhead transmission lines from a large generating plant in a remote area. From the main substation(s), the utility company distributes power to end users through medium-voltage overhead lines. The power from the distribution line voltage is converted to facility distribution voltage by step-down transformers in the facility’s electrical substation or on the utility poles. Large facilities generally have an on-site electrical substation and an overhead or underground power distribution network, whereas a small facility might be furnished power from a pole-mounted transformer through underground distribution.
The power from the on-site generating plant or the utility transformer is connected to facility switchgear and then to motor-control centers that further distribute power to electrical loads in the facility.
Sizing and Selection of the Power Supply
The first step in sizing the power supply requirements is to develop a detailed load summary for the entire facility. Table 12.3 shows an example of a load summary. The load summary contains every facility electrical load and its duty, efficiency, load factor, and power factor. The total of these loads is the total connected load of the facility. The generating system rarely is sized on the basis of the connected load, however, because doing so can lead to the generating system being oversized. The actual running load can be significantly lower than the connected load. An oversized generating system is less efficient and might require excessive maintenance because of operation of prime movers at light loads for a long period of time. Diesel engines are especially susceptible to this.
Table 12.3 further categorizes loads as continuous, intermittent, and spare on the basis of their duty cycle. Continuous loads are energized in normal production operation and generally include all process motors; facility lighting; living accommodations; heating, ventilating, and air conditioning (HVAC) loads, etc. Intermittent loads are cyclical and operate only part of the time (e.g., sump pumps, pre-/post-lube pumps, and air compressors). Spare loads are standby loads and operate only when the main unit fails. Spare loads are not considered when sizing the power requirements.
The maximum power demand normally is calculated as 100% of the continuous loads, plus 40 to 60% of the intermittent loads. In determining minimum generator capacity, a 20% allowance for future growth generally is added to the maximum power demand. Additionally, a voltage-dip analysis during motor starting is recommended if the facility load has a large motor or a group of motors that start simultaneously. A motor-starting voltage dip of > 15% generally is considered high and should prompt an evaluation of ways to reduce it. A large voltage dip will cause lights to flicker and might even cause some motor contactors to drop out because of insufficient coil-holding voltage. Reducing the voltage dip might involve increasing the generator size; however, reduced-voltage starting methods such as auto-transformer starters, electronic soft starters, and variable frequency drives also might be used to reduce the required capacity of generators.
Generators are rated in kilowatts (kW) and are designed to carry loads of up to their kW rating continuously, as long as the kilovolt ampere (kVA) rating is not exceeded. Most generators are designed for a 0.8 power factor at sea level and 40°C ambient temperature. The kVA capacity of a generator is determined by dividing the kW by the power factor of the generator. (See the Power Factor and Use of Capacitors section later in this chapter for a discussion of power factor.)
To eliminate the possibility of arcing, the generators that are used in the oil field generally are the revolving-field, brushless exciter type. On larger units, select a shaft-mounted permanent-magnet-generator (PMG) option to provide constant voltage to the generator-voltage regulator. On smaller units, a residual-magnetism exciter generally is used. Generators normally are provided with static-voltage regulators to maintain 1% voltage regulation from no load to full load.
The generator windings should be vacuum-pressure-impregnated (VPI) for high-humidity environments. The winding design temperature rise normally is limited to NEMA Class B (80°C over 40°C ambient), but NEMA-Class-F insulation normally is specified for a longer insulation life.
Generator voltage must be selected on the basis of the size of the loads and the total power requirement of the facility. Facilities with motors of 250 hp and higher should use a medium voltage (4.16 kV and higher) generator. For facilities with motors smaller than 250 hp, 480-V generation generally is sufficient. The most commonly used voltages for power generation are 480; 600; 2,400; 4,160; and 13,800 V.
In the case of purchased power from the utility, calculate the maximum load demand of the facility in kVA and select a proper kVA rated utility transformer to provide power to the facility. The transformer winding should be made of copper, and the desired transformer impedance should be 5.75% or less. Generally, oil-filled types of transformer are used for the power transformers. Dry, air-cooled types of transformer generally are used only for transformers in lighting and small-power applications. Even when the power is purchased from a utility, a standby generator generally is needed for emergency power in case utility power is lost. The standby generator normally powers the critical loads for shutdown, life saving, and personnel protection.
The electrical-distribution system furnishes electrical power and partial protection of the electrified oil field and consists of a primary system and a secondary system. It is important to the economics and longevity of the overall system that distribution be designed adequately before installation.
Primary Distribution System and Voltages
To reduce power losses, electricity distributed to an oil field is brought to the field at higher voltages of between 4,000 and 15,000 V. This higher-voltage distribution system is called a primary system. Higher voltages allow the use of smaller conductors, but require more expensive transformers. Even so, when the primary system must deliver electrical power over a long distance, a higher voltage generally is favored because the lower cost of the smaller cable over the longer distances offsets the higher costs of the transformers and protective equipment.
An electrified oil field has a high degree of exposure to electrical storms. Electrical storms cause high static voltages and, sometimes, high transient voltages, the latter being caused by lightning. Static lines and lightning arresters are used to reduce the damage to electrical equipment by the static voltages and lightning strikes.
During electrical storms, the formation of rain clouds creates a difference in potential between the cloud and the earth. Above-ground primary electrical systems in a storm’s vicinity might inherit a high static-voltage level that, if not reduced by properly sized and grounded lightning arresters, can cause motor-winding-insulation damage.
When the potential difference between the cloud and the earth becomes large enough, there will be an electrical discharge, or lightning strike. If lightning strikes the primary system, it will create high transient voltages. These voltages must be arrested by lightning arresters; otherwise, the insulation of the motors will fail, as will other electrical equipment in the system, including transformers and reclosures.
Secondary Electrical SystemThe secondary electrical system includes devices that operate at the same voltage as the motors, including the transformer at the end of the primary system, the cables, the disconnect switches, and the controls. In general, the voltage of all the devices within the secondary system should not be greater than 600 V.
A special case of the secondary system is the installation of a 796-V system. This voltage is obtained by Y-connecting three transformers, each with a secondary voltage of 460 V, yielding a line-to-line voltage of 796 V at the motor. (The Y connection is discussed below.) The 796-V system is used to reduce line drop to the motor; however, many operators who installed 796-V systems years ago have since converted to 460-V operation because, although operating at 796 V requires less current than operating at 460 V, this benefit is more than offset by the 796-V system overstressing the insulation of motors and control components.
The secondary system consists of one or more transformers that convert the primary-system voltage to the motor-operating voltage. Voltage from the transformer is provided to the motor starters through a fused disconnect switch or a circuit breaker. The motor starter provides for control and protection of the motor itself.
Wherever the secondary system uses overhead cables, it is exposed to electrical storms. As discussed earlier, because static and lightning strikes can damage the insulation of the electrical equipment, it is desirable to install lightning arresters at the transformer.
All the devices in the secondary part of the system should be sized to allow full loading of the motors without thermal damage to the equipment. Sizing of this equipment also should consider the protection of the electrical devices. Select fuses, circuit breakers, transformers, and wire sizes on the basis of the full-load rating of the motors.
Distribution Transformers.Distribution transformers reduce the primary high voltage to a lower voltage used by the motors. The distribution transformers are rated from 3 to 500 kVA. Transformers larger than 500 kVA are classified as power transformers.
To obtain full-load capability of the transformers and the motors, it is desirable to use three single-phase transformers in place of a single three-phase transformer. One advantage of using three single-phase transformers is the convenience of replacing one, should it fail.
Distribution transformers can be connected in several different configurations to deliver three-phase power: wye-delta, delta-delta, delta-wye, wye-wye, and open-delta (Figs. 12.1 through 12.3). All these configurations are used in the oil field, although some have distinct advantages.
Fig. 12.2—Three transformers, delta-delta connected.
Fig. 12.3—Two transformers, open delta connected.
Wye-Delta. The most desirable transformer connection is the wye-delta. The transformer primary is wye-connected, and the secondary is delta-connected. Though it is done in many cases, the primary winding of the transformer, known as the Y point, should not be grounded at the wellsite because if one of the primary wires were to go to ground at some point in the primary system, the ground wire at the wellsite might be at primary voltage to ground potential, creating a danger of electrical shock for personnel. The transformer "ground" should not be connected to the grounding system at the pumping unit because the latter includes the enclosures for the electrical equipment.
The wye-delta connection has the advantage of allowing harmonic voltages in the system to have a self-canceling effect in the delta-connected secondary. It is not necessary for three single-phase units connected wye-delta in a three-phase bank to have equal impedances; however, it is important for the primary to have balanced voltage because unbalanced primary voltages can cause circulating currents in the delta secondary.
Delta-Delta. In a delta-delta connection, the primary and secondary windings both are delta-connected. Delta-delta is an acceptable transformer connection, although not as desirable as wye-delta. The delta-delta connection requires all units in a three-phase bank to have impedances with less than a 10% differential. If a delta-delta connection is used, none of the endpoints or midpoints of the primary or secondary winding should be tied to the ground system at the wellsite. If any is, and if the ground is not satisfactory, the ground wire could be at a potential anywhere from zero to the line-to-ground voltage available at the transformer.
Delta-Wye. The delta-wye connection is undesirable because it allows a harmonic voltage in the distribution system to be applied to the motor and its control system. Harmonic voltages can cause erratic behavior of control components, as well as excess motor heat. If a delta-wye system is used, neither the primary nor the secondary windings of the transformer should be connected to the ground system at the motor. If grounds are attached to any part of this winding, they might be subject to the same voltage discussed under delta-delta. It is not necessary for the impedance of each unit in the three-phase transformer bank to be the same.
Wye-Wye. The wye-wye connection is the least desirable because harmonic voltages in the system are unable to circulate in the transformer winding. If harmonic voltages exist, they will be transmitted to the motor and its control system. If a wye-wye connection is used, no part of the transformer winding should be connected to the ground system at the wellsite. If a primary circuit has a phase-to-ground fault, a grounded wye will carry ground-fault current. This connection does not require transformers to have equal impedance. Using a delta secondary will eliminate harmonic voltage in the motor and its control system. It is not necessary for transformers to have equal impedances.
Open-Delta. The open-delta is an incomplete delta-delta and is possible when three single-phase transformers are connected in delta-delta fashion to provide the three-phase power. If one of the three transformers on the delta-delta connection is removed, the connection is an open-delta circuit. This type of connection provides unsatisfactory performance of induction motors. The open-delta connection will have unbalanced voltages, which prevents utilization of full-load rating of the transformer and motor.
At no-load and with balanced voltages supplied to this transformer, the output will be a balanced three-phase voltage. While this two-transformer system is loaded, the impedance changes, providing an unbalanced voltage to the motor. Using the two-transformer open-delta connection does not allow full use of transformer kVA and the output rating of the motor.
Figs. 12.2 and 12.3 compare a three-transformer delta connection and an open-delta transformer connection.
In the open-delta connection, the total kVA is only 57% of the original 100 kVA. The two 33.3-kVA transformers remaining in the circuit would have a total of 66.6 kVA. With one unit removed, the remaining units with 66.6 kVA provide only 57.7 kVA, or only 86.6% of the rating. This example shows that the transformers used in open-delta connections must be derated to obtain the desired kVA rating of an open-delta connection system.
While the open-delta-connected transformers are loaded, the voltage shifts from a balanced voltage at low load to a seriously unbalanced voltage at rated load. Unbalanced voltages will contain a negative sequence component of voltage. When applied to a three-phase induction motor, this causes excessive heating in the rotor, as well as some lost torque in the motor. Unbalanced voltages cause unbalanced currents.
Unbalanced voltage causes a 3 to 5 times greater current imbalance. This means, for example, that for a 3% voltage imbalance, a current imbalance of 9 to 15% can be expected. Such unbalanced conditions require that the motor be derated. Fig 12.4 can be used to determine the derating factor for percent voltage imbalance at the motor terminals. It shows, for example, that for a 5% voltage imbalance, the motor will operate at 75% of capacity.
Fig. 12.4—Effects of unbalanced voltages on performance of three-phase induction motors. (Reprinted from Motors and Generators, MG-1-1978, by permission of the Natl. Electrical Manufacturers Assn., © 1978; all rights, including translation into other languages, reserved under the Universal Copyright Convention, the Berne Convention for the Protection of Library and Artistic Works, and the International and Pan American Copyright Conventions.)
Many older oilfield installations use open-delta transformer connections. The only way the open-delta transformer will operate successfully is if both the transformers and the motors are oversized to handle the load. An open-delta transformer connection should be used only briefly and in an emergency situation in which one transformer has failed. For this emergency condition, the transformer and motor must be derated.
Sizing of the distribution transformer is a very important part of satisfactory operation of rod-pumping motors. The industry rule of thumb for sizing transformers is 1 kVA per connected hp. Because of the cyclic nature of oilwell pumping loads, some operators use 0.9 kVA/hp. Ultrahigh-slip motors do not have horsepower ratings; therefore, to determine the required kVA, use a factor of 0.75 times the full-load current of the motor in the high-torque mode.
Electrical grounding can be classified one of two types: system grounding and equipment grounding. System grounding includes grounding of the power supply neutral so that the circuit protective devices will remove a faulty circuit from the system quickly and effectively. Requirements for system grounding are covered in detail in the Natl. Electrical Code (NEC), * Chap. 2, Article 250. Equipment grounding includes grounding of the noncurrent-carrying conductive part of electrical equipment and of enclosures that contain electrical equipment for personnel safety.
Equipment grounding is a very important aspect of the electrical system. Grounding of electrical equipment has two purposes: to ensure that persons in the area are not exposed to dangerous, electric-shock voltage, and to provide current-carrying capability that can accept ground-fault current without creating a fire or explosive hazard.
To protect personnel from electric shock, all enclosures that house electrical devices that might become energized because of unintentional contact with energized electrical conductors should be effectively grounded. If the enclosure is grounded adequately, stray voltage will be reduced to safe levels. If the enclosures are not grounded properly, unsafe voltages could exist, which could be fatal to the operating personnel.
The lightning arresters installed in electrical systems cannot operate satisfactorily unless they are grounded well. Under elevated static voltage or lightning strikes, lightning arresters will short-circuit the above-normal voltages to ground. If the lightning arresters are not grounded properly, elevated voltage will enter the windings of transformers, control, and/or motors, causing component failures.
Obtaining a satisfactory ground can present some difficulties. Wellheads normally can be considered an excellent grounding source through the well casing. Ground rods can vary from acceptable in moderately wet soils to very inadequate in dry soils. Whenever possible, use the wellhead for grounding of the secondary electrical system. If a wellhead is not available, ground rods can be used.
In designing an electrical grounding system, follow these directions:
- For personnel safety, ground to the wellhead or to properly installed ground rods all the secondary-electrical-system devices. This includes the transformer tank, disconnect switch enclosure, motor control, and motor frame.
- Ground to the wellhead or to properly installed ground rods all secondary lightning arresters. Use different conductors to ground the secondary enclosures and lightning arresters. The wire that grounds the lightning arresters should be a continuous, unbroken cable that is no smaller than No. 6 wire.
- Primary lightning arresters also should be grounded at a utility primary ground, and not to the secondary ground or the wellhead.
- Do not attach utility static wires or grounding of transformer connections to the wellhead. If connected to the wellhead, this can adversely affect the cathodic protection of well casing and production tubing. This part of the electrical system might include many miles of line exposure and many grounds that could influence the corrosion of the production equipment. Grounds for this part of the system should be grounding rods or ground pads located at the bottoms of the utility poles. Other satisfactory grounds are wells drilled or ground mats constructed for this purpose at the electrical substation.
- If possible, install ground rods at each location for each of the separate grounding wires run to the wellhead. During the servicing of the wells, the wellhead grounds may be removed. When service work is completed, reconnect these wellhead grounds.
- Do not connect grounds of telephone systems to the grounds of motors. Induction motors can generate harmonic voltages that can cause noise on telephones when they share common grounds.
Natl. Electrical Code and NEC are registered trademarks of the Natl. Fire Protection Assn. Inc., Quincy, Massachusetts 02269.
Voltage Drop in Electrical Systems
The electrical system of an oil field should be economically designed, yet capable of delivering the required current at adequate voltage to all motors for starting and running. When the load current flows through copper or aluminum wire, voltage drop occurs in the wire because of resistance of the wire, as indicated by Ohm’s law:
where E = voltage, V; I = current, A; and R = resistance, Ω.
Voltage loss in the wire reduces the available voltage at the load terminals for motors and other loads. Most electrical loads operate at designed efficiency at their rated voltage. Reducing voltage supplied to electrical equipment reduces its efficiency or output and might even reduce its ability to start under full-load condition. For example, a 5% reduction in applied voltage at its terminals reduces the power output of an electric motor by 10%.
The voltage drop in the conductor depends on the amount of current flowing through the conductor and the conductor resistance, or impedance. The conductor resistance is directly proportional to the length of the wire and inversely proportional to the size of the wire. For the same-sized wire, the voltage drop increases with the increase in conductor length:
where R = resistance, Ω; ρ = conductor resistivity, Ω-circular mil/ ft; L = conductor length, ft; and A = cross-sectional area of conductor, circular mil. (A circular mil is the area of a circle with 1 mil diameter, and a mil = 0.001 in.)
The NEC gives the maximum allowable voltage drop in branch or feeder circuit conductors as 3%. The total maximum allowable voltage drop on both feeders and branch circuits to the farthest outlet is 5%.
In addition to the voltage drop caused by load current, a voltage drop during the starting of a large induction motor also must be calculated. Large induction motors and industrial synchronous motors (see the section on Motors in this Handbook ) draw several times full-load current from their power supply under full voltage across the line starting. The starting power factor ranges from 0.15 to 0.50 lagging, which causes an inrush current as high as 6 to 7 times the full-load current of the motor. This large current flowing through motor impedance, cable impedance, and all other impedances between the supply and the motor causes a significant voltage drop. Undesirable effects of this voltage drop include dimming lights or lamp flicker, control relay or contactor dropout (de-energizing), and inability to start motor.
Motor-Starting Voltage Drop (Off a Transformer)
Determining the percent voltage drop (ΔE) on a motor fed by a transformer bank, which is fed by an infinite utility bus, requires knowing the transformer impedance (Z), the three-phase impedance of the cable between the transformer and the motor (Zc), and the motor-starting impedance (Zm). The approximate formula to determine the percent voltage drop is:
where Zt = total impedance, in Ω, given as:
where Ztr = transformer impedance, %; Pt = transformer-rated kVA; and Et = transformer voltage, kV. For Eq. 12.4, the cable impedence is calculated as:
where R = cable resistance, Ω; X = cable three-phase reactance, Ω; θ = the power factor angle; and cos θ = power factor. (See the Power Factor and Use of Capacitors section later in this chapter for a discussion of power factor.)
For Eq. 12.4, the motor-starting impedance is calculated as:
where Em = motor voltage, kV, and Pm = motor-starting kVA.
Motor-Starting Voltage Drop (Off a Generator)
The voltage drop while starting a motor off a limited-capacity generator is an important factor in sizing the generator and determining the starting method for the motor. The generator cannot supply the large motor inrush current without a momentary voltage falloff while the voltage regulator works to increase excitation and to re-establish the voltage level.
The magnitude and duration of voltage drop depends on the size of the motor and its inrush current, the kVA capacity of the generator, the performance characteristics of the voltage regulator, and the amount of initial load on the generator before starting the motor. Most new installations use fast-response solid-state voltage regulators, which considerably reduce the amount and duration of voltage drop.
Along with large voltage drop, another problem encountered during motor starting is possible excessive kilowatt loading of the generator prime mover. The motor input horsepower during its acceleration period creates a large load, which reflects to the prime mover of the generator. If large enough, this load will stall the prime mover in the worst case, or cause it to shut down because of overload and/or temperature rise.
In determining the voltage drop when starting a motor off a generator that has limited capacity, the motor-feeder-cable impedance generally is disregarded because its impact on the calculation is negligible. Also, the resistance component of the generator impedance and motor impedance is neglected because reactance values are far greater than the resistance values. The voltage drop therefore is a simple ratio of the reactances in the circuit.
The approximated formula to determine the percent voltage drop when starting a generator is:
where Xm =motor reactance during starting, Ω, and Xg = generator reactance, Ω. In Eq. 12.8', Xmis calculated as:
InEq. 12.8,Xgis calculated as:
where X’d= the transient reactance of the generator, %; Pg= generator kVA; and Eg= generator voltage, V.
The presence of initial load on the generator before starting a motor could have substantial effect on the voltage drop, depending on the amount and nature of the load. A constant impedance load (e.g., resistors or lights) might increase the voltage drop only slightly, but might cause a longer time to recover voltage to normal value. Many generator manufacturers provide graphs, personal computer (PC)-based programs, and data to determine voltage drop during motor starting on their generators, with and without an initial load.
Power Factor and Use of Capacitors
The electrical power required to drive a motor has three components: reactive power (Pr, kVAR), active power (Pa, kW), and apparent power (Pap, kVA). The active power is the actual amount of work done by the motor and measured for billing purposes. The reactive power is the power required to magnetize the motor winding or to create magnetic flux, and is not recordable. The apparent power is the vector sum of kilowatts and kilovars and is the total amount of energy furnished by the utility company. The power triangles shown in Fig. 12.5 illustrate the relationships between these terms.
The power factor (Fp) is the ratio of active power to apparent power:
The power factor is "leading" in loads that are more capacitive and "lagging" in loads that are more inductive (e.g., motor or transformer windings). In a purely resistive load, Fops = 1 (unity), such that Pa = Pap (kW = kVA) and no reactive power is present. When Fp < unity, reactive power is present and more power is required to produce work, as seen in the following equation:
The reactive power of a motor is approximately the same from no load to full load. When a motor is operating at full load, the active/reactive power ratio is high, and thus the power factor of the motor is high. A lightly loaded motor has a low active/reactive power ratio, which causes the power factor to be low. At low power factors, more power will be required from the utility company than actually is needed by the load. This translates into higher energy cost and the need for larger generation units and transformers. Some utility companies charge a substantial penalty to their customers for low power factors (generally < 0.95). Also, low power factors might cause more voltage drop in the system, which causes the motors to operate sluggishly and the lights to dim.
It is essential that the power factor of the system be maintained as high as possible (close to unity). Removing the reactive power from the system can make this possible. Power-factor-correction capacitors are used for this purpose. A motor requires inductive or lagging reactive power for magnetizing. Capacitors provide capacitive or leading reactive power that cancels out the lagging reactive power when used for power-factor improvement. The power triangles in Fig. 12.6 show how capacitors can improve the power factor for a motor. The improved power factor changes the current required from the utility company, but not the one required by the motor.
Fig. 12.6—Power triangle showing power factor correction.
Capacitors should not be selected as a means of correcting poor power factors that are the result of oversized motors or unbalanced pumping units. Choosing a capacitor for this purpose might cause overcorrection, which can result in a leading power factor. A leading power factor, in turn, might cause overvoltages that would cause control-component failure or power-cable failure. This potential problem generally is avoided by connecting the capacitors downstream of the motor contactors and switching them on and off, along with the motor contactors.
Power factor correction capacitors could be applied to each individual motor to correct the power factor of that motor, or could be a single unit connected to the main bus of the switchgear. In the latter case, the unit should have power-factor-sensing circuits that automatically determine the amount of capacitance required for maintaining a preset power factor. The required amount of capacitors are automatically added to or removed from the switchgear bus to maintain the required power factor.
The cyclic kW load on a pumping-unit motor can cause the power factor to vary from 1.0 to near zero if excessive adverse pumping conditions exist.
Production facilities contain, or may contain, flammable gases and vapors in normal operations. In the right concentration with air, these can form an explosive environment that is ignitable by hot surfaces, electrical arcs, and sparks. To prevent this from happening, facilities must be classified properly, so that all electrical equipment and systems are properly selected and installed.
North American Standards
In the U.S., facilities are classified according to NEC,  and a nationally recognized testing laboratory must approve all arcing electrical equipment installed in the classified areas.
The four steps involved in hazardous area classification are:
- Determine the type of hazard or "class" that might be present—combustible gas (Class I), combustible dust (Class II), or fibers (Class III).
- Identify the specific "group" for the hazardous substance (Group A through Group G).
- Determine the degree of the classification (Division 1 or Division 2).
- Determine the extent of the classified locations.
Groups A through G are acetylene, hydrogen, ethylene, propane/methane, metal dust, coat dust, and grains/fibers, respectively. Almost all classifications in oil and gas facilities are Class I, Group D. Class I locations are those in which flammable gases or vapors are or might be present in the air in the quantities sufficient to produce explosive or ignitable mixtures.
Class I locations are either Division 1 or Division 2, or are unclassified: 
Class I, Division 1. Locations (1) in which ignitable concentrations of flammable gases or vapors can exist under normal operating conditions, (2) in which ignitable concentrations of such gases or vapors may exist frequently because of repair or maintenance operations or because of leakages, or (3) in which breakdown or faulty operation of equipment or processes might release ignitable concentrations of flammable gases or vapors and might also cause simultaneous failure of electrical equipment in such a way as to directly cause electrical equipment to become a source of ignition.
Class I, Division 2.Locations (1) in which volatile, flammable liquids or flammable gases are handled, processed, or used, but in which the liquids, vapors, or gases normally will be confined within the closed containers or closed system from which they can escape only in case of accidental rupture or breakdown of such containers or systems, or in case of abnormal operation of equipment; (2) in which ignitable concentrations of gases or vapors normally are prevented by positive ventilation, and which might become hazardous through failure or abnormal operation of the ventilation equipment; or (3) which are adjacent to a Class I, Division 1 location, and to which ignitable concentrations of gases or vapors might occasionally be communicated unless such communication is prevented by adequate positive-pressure ventilation from a source of clean air, and effective safeguards against ventilation failure are provided.
Unclassified.All areas in a facility that are not Division 1 or Division 2 are considered unclassified. Arcing electrical equipment in the unclassified areas need not be explosion-proof. General-purpose enclosures are accepted in these areas.
API RP 500 shows typical examples of classifications of equipment in oil and gas production facilities, including the extent of the classified areas around such equipment. Figs. 12.7 through 12.11 provide examples of classified locations in a typical oil-and-gas-production facility.
Fig. 12.7—Nonenclosed, adequately ventilated well on which work is being performed.
Fig. 12.8—Nonenclosed beam-pumping well in an adequately ventilated area with an inadequately ventilated cellar.
Fig. 12.9—Nonenclosed beam-pumping well in an adequately ventilated area without a cellar.
Fig. 12.10—Electrical submersible pumping well in a nonenclosed, adequately ventilated area without a cellar.
Fig. 12.11—Electrical submersible pumping well in a nonenclosed, adequately ventilated area with an inadequately ventilated cellar.
Refer to API RP 500 and the NEC for further details regarding hazardous-area classification.
International Electrotechnical Commission (IEC) Standards
Whereas the classification based on the NEC and API standards is used in the U.S. and a few other countries in the world, an IEC-created zone classification system is widely accepted elsewhere.
The IEC zone classifications basically are:
Class I, Zone 0.Locations (1) in which ignitable concentrations of flammable gases or vapors are present continuously or (2) in which ignitable concentrations of flammable gases or vapors are present for long periods of time.
Class I, Zone 1.Locations (1) in which explosive or ignitable concentrations of flammable gases or vapors are likely to exist under normal operating conditions; (2) in which ignitable concentrations of flammable gases or vapors may exist frequently because of repair or maintenance operations or because of leakages; (3) in which equipment is operated or processes are carried on, of such a nature that equipment breakdown or faulty operations could result in the release of ignitable concentrations of flammable gases or vapors and cause simultaneous failure of electrical equipment in a mode to cause the electrical equipment to become a source of ignition; or (4) that is adjacent to a Class I, Zone 0 location, from which ignitable concentrations of gases or vapors could be communicated, unless such communication is prevented by adequate positive-pressure ventilation from a source of clean air, and effective safeguards against ventilation failure are provided.
Class I, Zone 2.Locations (1) in which ignitable concentrations of flammable gases or vapors are not likely to occur in normal operation and if they do occur will exist only for a short period; (2) in which volatile, flammable liquids, flammable gases, or flammable vapors are handled, processed, or used, but in which the liquids, gases, or vapors are confined within closed containers or a closed system from which they can escape only in case of accidental rupture or breakdown of such containers or system, or as a result of the abnormal operation of equipment with which the liquids or gases are handled, processed, or used; (3) in which ignitable concentrations of flammable gases or vapors normally are prevented by positive mechanical ventilation, but which may become hazardous because of failure or abnormal operation of the ventilation equipment; or (4) which are adjacent to a Class I, Zone 1 location from which ignitable concentrations of flammable gases or vapors could be communicated unless such communication is prevented by adequate positive-pressure ventilation from a source of clean air, and effective safeguards against ventilation failure are provided.
Unclassified.All areas in the facility that are not Zone 0, Zone 1, or Zone 2 are considered unclassified. Arcing electrical equipment in unclassified areas need not be explosion-proof. General-purpose enclosures are acceptable in these areas.
The IEC zone classification also differs from North American standards in its grouping of the hazardous gases or vapors as either Group I or Group II. Group I is for use in describing atmospheres that contain firedamp (a mixture of gases, composed mostly of methane, found underground, usually in mines). Group II covers all other flammable gases. Group II is subdivided into IIC, IIB, and IIA, according to the nature of the gas or vapor:
- Group IIC is equivalent to a combination of Class I, Group A and Class I, Group B in the NEC system.
- Group IIB is equivalent to Class I, Group C in the NEC system.
- Group IIA is equivalent to Class I, Group D in the NEC system.
See NEC, Chap. 5, Article 505 for further details of the IEC zone classifications.
Alternating-Current (AC) Motors
AC motors are used worldwide in many residential, commercial, industrial, and utility applications. Motors transform electrical energy into mechanical energy. An AC motor may be part of a pump, fan, or other form of mechanical equipment. AC motors are found in a variety of applications, from those that require a single motor to special applications that require several motors working in concert.
All AC motors are made up of a magnetic circuit formed by a stationary member called a stator and a rotating member known as rotor. The stator and rotor are separated by an air gap. The stator has primary windings that are connected to the power source and develop a rotating magnetic field. The rotor has secondary windings that rotate in the magnetic field created by the stator windings. This causes currents to flow in the secondary windings and causes development of a secondary magnetic field. How the rotors are designed and how the currents are made to flow determines the type of motor and its performance characteristics. Two types of AC motors are widely used in the oil and gas industry: induction and synchronous.
The National Electrical Manufacturers Association (NEMA) sets the standards for a wide range of electrical products, including motors. NEMA is associated primarily with motors used in North America. NEMA’s standards (see NEMA Standard Publication No. MG 1) represent general industry practices and are supported by manufacturers of electrical equipment. The NEMA standards might not apply to some large AC motors that are built to meet the requirements of a specific application. Such motors are referred to as "above-NEMA." The American Petroleum Institute (API) and the Institute of Electrical and Electronic Engineers (IEEE) also have standards for NEMA-sized and above-NEMA motors.
Induction MotorsAC induction motors are widely used in the oil and gas industry because of their simplicity, reliability, and low cost. Induction motors are either single-phase or three-phase. This discussion will center on the three-phase, 460-VAC (volts-alternating-current) induction motors. In an induction motor, the actual rotor speed always is less than that of the rotating magnetic field. Fig. 12.12 shows a typical induction motor and labels its three basic parts: stator, rotor, and enclosure.
Stator Construction. The stator and the rotor are electrical circuits that perform as electromagnets. The stator is the stationary electrical part of the motor. The stator core of a NEMA motor is made up of several hundred thin laminations that are stacked together to form a hollow cylinder. Coils of insulated wire are inserted into slots of the stator core.
Each group of coils and the steel core it surrounds form an electromagnet. Electromagnetism is the principle behind motor operation. The stator windings are connected directly to the power source.
Rotor Construction.The rotor is the rotating part of the electromagnetic circuit. The most common type of rotor is the "squirrel cage" rotor, so called because it is reminiscent of one of the exercise wheels found in the cages of pet rodents. Other types of rotor construction are mentioned later in the chapter.
The squirrel-cage rotor consists of a stack of steel laminations that has evenly spaced conductor bars around its circumference. The stacked laminations form the rotor core. Aluminum is die-cast in the slots of the rotor core to form the series of conductors around the rotor’s perimeter. Current flow through the conductors forms the electromagnet. The conductor bars are mechanically and electrically connected with end rings. The rotor core mounts on a steel shaft to form a rotor assembly.
The wound rotor is another type of induction-motor-rotor construction. A major difference between the wound rotor motor and the squirrel-cage rotor is that the conductors of the wound rotor consist of wound coils instead of bars. These coils are connected through slip rings and brushes to external variable resistors, as shown in Fig. 12.13. The rotating magnetic field induces a voltage in the rotor windings that increases the resistance of the rotor windings. This increase in resistance allows less current flow in the rotor windings, which decreases motor speed. Conversely, decreasing the resistance allows more current flow, and so increases motor speed.
Wound-rotor induction motors are used in applications of certain types of pump, in mine hoists, mills, and applications where speed reduction is required in the drive application.
Stator-Coil Arrangement.The schematic in Fig. 12.14 illustrates the relationship between the stator coils. The coils operate in pairs. This example uses six coils, a pair for each of the three phases. The coils are wrapped around the soft iron core material of the stator. These coils are referred to as motor windings. Each motor winding becomes a separate electromagnet. The coils are wound in such a way that when current flows in them, one coil in a pair is a north pole and the other a south pole. For example, if A1 were a north pole, then A2 would be a south pole. When the current reverses, so does the polarity of the poles.
Rotor RotationPrinciple of Rotation.To see how a rotor works, use a magnet mounted on a shaft in place of the squirrel cage rotor, as shown in the upper image in Fig. 12.15. Energizing the stator windings establishes a rotating magnetic field. The magnet has its own magnetic field that interacts with the rotating magnetic field of the stator. The north pole of the rotating magnetic field attracts the south pole of the magnet, and vice versa. As the rotating magnetic field rotates, it pulls the magnet along, causing it to rotate. Motors that use this design are known as permanent-magnet synchronous motors.
The squirrel-cage rotor acts essentially the same as the magnet. When power is applied to the stator, current flows through the winding, causing an expanding electromagnetic field (emf) that cuts across the rotor bars.
When a conductor, such as a rotor bar, passes through a magnetic field, it induces a voltage (an emf) in the conductor. The induced voltage causes a current flow in the conductor. The current flows through the rotor bars and around the end ring, producing magnetic fields around each rotor bar. In an AC circuit, the current continuously changes direction and amplitude. The resultant magnetic field of the stator and rotor continuously change. The squirrel-cage rotor becomes an electromagnet with alternating north and south poles.
The lower image in Fig. 12.15 illustrates one instant in time during which current flow through winding A1 produces a north pole. The expanding field cuts across an adjacent rotor bar, inducing a voltage. The resultant magnetic field in the rotor tooth produces a south pole. As the stator magnetic field rotates, the rotor follows.
Synchronous Speed.The speed of the rotating magnetic field is referred to as the synchronous speed (Ns). Synchronous speed is equal to 120 times the frequency (f), divided by the number of poles (P):
If the frequency of the applied power supply for the two-pole stator is 60 Hz, then the synchronous speed is 3,600 rev/min:
Synchronous speed decreases as the number of poles increases. Table 12.4 shows the synchronous speed at 60 Hz for different numbers of poles.
The relative difference in speed between the rotor (N) and the rotating magnetic field (Ns) is called slip. There must be some slip because if the rotor and the rotating magnetic field were turning at the same speed, no relative motion would exist between the two, such that no lines of flux would be cut and no voltage would be induced in the rotor. Slip is necessary to produce torque and depends on load—an increase in load will cause the rotor to slow down, ergo increase the slip. Conversely, a decrease in load will cause the rotor to speed up, and so will decrease slip. Slip (S) is expressed as a percentage and can be determined by:
where N = rotor speed, rev/min. For example, a four-pole motor operated at 60 Hz has a synchronous speed of 1,800 rev/min. If the rotor speed at full load is 1,765 rev/min, then slip is 1.9%:
Synchronous MotorThe synchronous motor is another type of AC motor. Like an induction motor, it has a stator and a rotor. Its stator winding closely resembles that of an induction motor, and it, too, receives AC power from the power source to drive the connected load.
Synchronous motors are available with various rotor designs to fit different applications. In one type, for example, the rotor is constructed somewhat like a squirrel-cage rotor. In addition to rotor bars, it has coil windings for providing direct-current (DC) excitation, as shown in Fig. 12.16. The coil windings are connected to an external DC power supply by slip rings and brushes. Like a squirrel-cage motor, a synchronous motor is started by applying AC power to the stator; however, DC power then is applied to the rotor coils after the motor reaches maximum speed. This produces a strong, constant magnetic field in the rotor, which locks in step with the rotating magnetic field of the stator. Because the rotor turns at the same speed as synchronous speed (speed of the rotating magnetic field), there is no slip. The speed of rotation of the motor is constant in a synchronous motor, and does not vary with load, as in an induction motor.
Synchronous motors are designed to operate at unity (1.0) power factor or 0.8 leading power factor. By varying the DC excitation of the motor, the power factor of the motor can be varied widely. Overexcited synchronous motors operate at leading power factor and provide reactive kVAR-like capacitors. This yields an improved power factor for the power-supply system. Because most utility companies bill their industrial customers on the basis of their kVAR use, rather than kW, an improved power factor provides large savings for the customer.
Synchronous motors initially were used as a way to raise the power factor of systems that have larger induction-motor loads; now, however, they are used because they can maintain the terminal voltage on a weak power system, are lower cost, and are more efficient than equivalently sized induction motors.
A motor’s nameplate provides important information relevant to its selection and application. Fig. 12.17 is the nameplate from a 30-hp AC motor. It gives specifications for the load and operating conditions, as well as for motor protection and efficiency.
Voltage and Amps
AC motors are designed to operate at standard voltages and frequencies. This sample motor is designed for continuous-duty operation in a 460-VAC, three-phase system. At full-load, this motor would draw a 34.9-A current.
Horsepower and Kilowatts
U.S.-manufactured AC motors generally are hp-rated, whereas European-manufactured equipment generally is kW-rated.
In kW, the power formula for a single-phase motor is:
The power formula for three-phase motor is:
The motor manufacturer provides the voltage, current, and power factor of the motors.
Base speed is the nameplate speed—given in rev/min—at which the motor develops the rated horsepower at the rated voltage and frequency. It indicates how fast the output shaft will turn the connected equipment when fully loaded and supplied with the proper voltage and frequency. The base speed of the motor in Fig. 12.17 is 1,765 rev/min at 60 Hz.
The service factor is a multiplier that may be applied to the rated power to allow a motor to be operated at higher than its rated hp. A motor designed to operate at its nameplate hp rating with a service factor of 1.0 would operate continuously at 100% of its rated hp without exceeding its operating temperature. Some applications might require a motor to exceed its rated hp. In such cases, a motor with a service factor of 1.15 can be specified, allowing the motor be operated 15% higher than its nameplate hp. For example, with a 1.15 service factor, the 30-hp motor in Fig. 12.17 can be operated at 34.5 hp. Note, however, that any motor operating continuously at a service factor > 1.0 will have a reduced life expectancy compared to one operating it at its rated hp. This is because of high winding temperature, which causes motor-winding insulation to age thermally at approximately twice the rate that occurs for a motor with a 1.0 service factor.
Insulation ClassesNEMA has established motor-winding-insulation classes to meet motor-temperature requirements found in different operating environments. The four insulation classes are A, B, F, and H, as illustrated in Fig. 12.18. Class-F insulation is most commonly used. Class-A insulation seldom is used. Before a motor is started, its windings are at ambient temperature (the temperature of the surrounding air). NEMA has standardized on an ambient temperature of 40°C within a defined altitude range for all motor classes.
Temperature will rise in the motor as soon as the motor is started. Each insulation class has a specific allowable temperature increase. The combination of ambient temperature and allowed temperature increase equals the maximum winding temperature in the motor. For example, a motor with Class-F insulation has a maximum temperature increase of 105°C when operated at a 1.0 service factor. The maximum winding temperature is 145°C (40°C ambient plus 105°C rise). A margin is allowed to provide for the motor’s "hot spot," a point at the center of the motor’s windings where the temperature is higher.
The operating temperature of a motor is important to efficient operation and long life. Operating a motor above the limits of the insulation class reduces its life expectancy. For example, a 10°C increase in the operating temperature can decrease the motor’s insulation life expectancy as much as 50%.
The motor in Fig. 12.17 has Class-F insulation and is rated for continuous duty at 40°C ambient.
NEMA has established standards for motor construction and performance. Standard NEMA designs are NEMA A, NEMA B, NEMA C, and NEMA D. NEMA B motors are the most commonly used. (See the NEMA Motor Design section below for more details of the NEMA designs.) Additionally, NEMA has assigned frame sizes for all three-phase induction motors built to NEMA standards. This includes motors from 0.5 to 250 hp. Each frame size has a specific frame design, set of dimensions, full-load amperage, efficiency, and power factor. See NEMA MG 1 for the details of frame sizes.
The motor in Fig. 12.17 is a NEMA B design and has a NEMA 286T frame designation.
Locked Rotor-Code LettersNEMA has assigned code letters A through V to designate the locked-rotor kVA per horsepower. This is an amount of power drawn by the motor when it is started. Table 12.5 gives the designations of each code letter.
The motor in Fig. 12.17 is code letter G and has 5.6 to 6.29 locked-rotor kVA/hp.
AC motor efficiency is expressed as a percentage. It is an indication of how much of the input electrical energy is converted to output mechanical energy. The nominal efficiency of the motor in Fig. 12.17 is 93.6%. The higher the percentage, the more efficiently the motor converts the incoming electrical power to mechanical horsepower. A 30-hp motor with a 93.6% efficiency would consume less energy than a 30-hp motor with an efficiency rating of 83.0%. This can mean a significant saving in energy cost. In addition to lower energy costs, lower operating temperature, longer life, and lower noise levels are typical benefits of high-efficiency motors.
NEMA Motor Characteristics
Standard Motor Designs
Motors are designed with certain speed-torque characteristics to match speed-torque requirements of various loads. A motor must be able to develop enough torque to start, accelerate, and operate a load at rated speed. The relationship between horsepower (H), torque (T, lbf-ft), and motor speed (Nm , rev/min) is given by:
NEMA has established class designations for motors on the basis of motors’ starting-torque and accelerating loads. The four standard NEMA designs are NEMA A, NEMA B, NEMA C, and NEMA D. NEMA A motors usually are used for applications that require extremely high efficiency and extremely high full-load speed. NEMA A-design motors are special and are not used very often. NEMA B-design motors are considered to be normal-torque motors. They are used for low-starting-torque loads, such as with centrifugal pumps and fans. NEMA C and NEMA D motors are used for applications that require high starting torque (e.g., positive-displacement pumps and compressors).
Speed/Torque CurveThe graph in Fig. 12.19 shows a typical speed/torque curve for a NEMA-B motor. Such curves show the relationship between motor speed and torque produced by a motor from the moment it is started until the time it reaches full-load torque at the rated speed.
Starting torque (Fig. 12.19, A) is also known as locked-rotor torque. It is developed when the rotor is held at rest with the rated voltage and frequency applied, a condition that occurs whenever a motor is started. When the rated voltage and frequency are applied to the stator, there is a brief time before the rotor turns. During this time, a NEMA B motor develops approximately 150% of its full-load torque.
Accelerating Torque and Breakdown Torque
As a motor accelerates, torque decreases slightly (Fig. 12.19, A to B) before beginning to increase. As speed continues to increase, torque increases until it reaches a maximum at approximately 200% (Fig. 12.19, B to C). This torque is referred to as accelerating (or pull-up) torque. If this maximum is beyond the motor’s torque capability, the motor will then stall or abruptly slow down. Point C on the graph in Fig. 12.19 is referred to as the breakdown (or pull-out) torque.
Full-load torque is the torque that develops when the motor is operating with the rated voltage, frequency, and load. The speed at which full-load torque is produced is the slip speed or the rated speed of the motor (Fig. 12.19, D)
Starting Current and Full-Load CurrentStarting current also is referred to as locked-rotor current and is measured from the supply line at the rated voltage and frequency with the rotor at rest. Full-load current is the current measured from the supply line at the rated voltage, frequency, and load, with the rotor up to speed. Starting current typically is 600 to 650% of full-load current on a NEMA B motor. As the rotor comes up to speed, the starting current decreases to the rated full-load current (Fig. 12.20).
Special Design Motors
Multispeed motors and motors used in variable-speed applications are special motors that are uniquely designed or selected to fulfill specific load requirements. NEMA design classifications are not applicable to these specialized motors.
Methods of Motor Starting
Various methods are used for starting the electric motors. The most common method is full-voltage starting; motor torque and current from standstill to full speed are highest when the full-voltage starting method is used. The other starting methods (e.g., autotransformer, wye-delta, part-winding, and soft) provide reduction of both motor current and torque during the starting period.
In full-voltage starting (also called across-the-line starting), the motor is connected directly to the power source through the motor starter. When used to start an induction motor, the starting current for this method can be as high as 5 to 7 times the full-load current. This might cause excessive undesirable voltage drop in the system. In the case of a large induction motor starting at full voltage on a limited-capacity power-supply system, the voltage drop during motor starting must be calculated [see the Motor-Starting Voltage Drop (Off a Transformer) and Motor-Starting Voltage Drop (Off a Generator) sections earlier in this chapter]. Consider reduced-voltage starting methods if the voltage drop during starting is > 15% of the rated voltage.
Autotransformer StartingAutotransformer starting is a reduced-voltage starting method, commonly referred to as an RVAT (reduced-voltage autotransformer). During starting, the applied voltage can be reduced below the line voltage, and the motor is switched to full-line voltage upon reaching full speed. Both the motor-starting current and the torque will be reduced to below the values of an across-the-line starter. The most desirable starting current and starting torque can be selected by reconnecting the motor leads to the 50, 65, or 80% output taps on the autotransformer. The starting characteristics of the motor load and allowable accelerating times determine the best tap connection for each application.
Table 12.6 gives the starting torque and starting current as the percentage of full-voltage starting for the three tap settings of the autotransformer. In Table 12.6, %LRT (locked-rotor torque) is the starting torque expressed as a percentage of the values of an across-the-line start, and %LRA (locked-rotor ampere) is the starting current drawn from the power lines, expressed as a percentage of the values of an across-the-line start.
In the wye-delta starting method, the motor windings are wye-connected (star-connected) during the starting and acceleration period. Once the motor approaches full-load speed, the windings are delta-connected for normal running operation. The transition from wye to delta may be an open or a closed transition type. Because the starting torque for this method is one-third of full-load torque, it is used when low starting torque is acceptable.
Part-winding starting sometimes is used for lower-horsepower, higher-speed types of induction motors. In this method, a full voltage is applied to only part of the suitably designed stator winding during starting. After accelerating on the part-winding for a short time, the remainder of the stator winding is connected and the motor continues to accelerate to full speed. The starting torque for this method is approximately 50% of full-voltage starting, and the starting current is approximately 60 to 70% of full-voltage starting.
Soft starting is a reduced-voltage starting method that uses solid-state, programmable starters. The starters provide smooth, stepless acceleration of the induction motors from zero to full speed over an adjustable time period. The starting torque of the motor varies as the square of the applied voltage. As the voltage is reduced, the torque is reduced to the level required to accelerate the motor and load to full speed. The acceleration time is set through "ramp" control to bring the motor to full speed over a desired length of time.
Factors such as voltage and frequency variation, altitude, and temperature can affect the operation and performance of an AC motor enough to lower its rated capability, and should be considered when selecting a motor.
Voltage VariationAC motors are designed to operate on standardized voltages and frequencies. A small variation in supply voltage can affect motor performance significantly. Fig. 12.21 shows that when the supply voltage is 10% below the rated voltage of the motor, the motor has 20% less starting torque. This reduced voltage might prevent the motor from getting its load started or keep it from running at its rated speed. A 10% increase in supply voltage, on the other hand, increases the starting torque by 20%, which might cause damage during startup (e.g., a conveyor might lurch forward at startup). Voltage variation causes similar changes in a motor’s starting amperage, full-load amperage, and temperature rise.
FrequencyVariation in the frequency at which a motor operates causes changes mainly in its speed and torque. For example, a 5% increase in frequency causes a 5% increase in full-load speed and a 10% decrease in torque (Table 12.7). AC motors should operate successfully at their rated load with a combined variation in voltage and frequency of up to 10% above or below the rated voltage and the rated frequency, provided that the frequency variation does not exceed 5%; however, performance within this combined variation range might not be the same as the standards established for operation at the rated voltage and frequency.
Altitude and TemperatureThe NEMA standards for allowable temperature increase for motor winding insulation discussed in the Insulation Classes section of this chapter is based on motor operation at or below an altitude of 3,300 ft and at a maximum ambient temperature of 40°C. For operation at altitudes of > 3,300 ft (at 40°C ambient), most motors must be derated because of temperature increase in the windings, as shown in Table 12.8. Some motors (Class A or B insulated) can be operated successfully at altitudes of > 3,300 ft in locations where a decrease in ambient temperature compensates for the increase in temperature rise. Also, motors with a service factor of 1.15 or higher will operate satisfactorily at a 1.0 service factor at a 40°C ambient temperature at altitudes of between 3,300 and 9,000 ft.
AC Motor Drives
Many applications require variable-speed motors. The easiest way to vary the speed of an AC induction motor is to use an AC drive to vary the applied frequency. AC drives commonly are known as variable frequency drives (VFDs). VFDs are microprocessor-based controllers that incorporate an electronic control section, an electromagnetic and semiconductor power section, and typical components that are used with standard motor controllers. VFDs can provide voltage to motors at frequencies of from < 1 Hz to approximately 120 Hz. Currently, they are available for motors ranging from 0.33 hp to thousands of horsepower. Operating a motor at other than the rated frequency and voltage affects motor current and torque. The following sections provide further discussion on this subject.
Volts per Hertz Ratio
The output torque for a motor is determined on the basis of the ratio of the motor’s applied voltage and applied frequency, known as the volts per hertz (V/Hz) ratio. A typical AC motor manufactured for use in the U.S. is rated for 460 VAC and 60Hz, and thus has a 7.67 V/Hz ratio. Failure to maintain the proper V/Hz ratio will affect motor torque, temperature, speed, noise, and current draw.
For example, increasing the frequency without increasing the voltage will cause an increase in speed and a decrease in air-gap flux density. The air-gap flux density decrease causes motor torque to decrease because torque is directly proportional to the magnetic flux density in the motor’s air gap.
Thus, for a motor to produce its rated torque at variable speeds, it also is necessary to control the voltage and frequency supplied to the motor. A VFD maintains a preset V/Hz ratio in supplying power to a motor at the variable speeds.
Constant Torque LoadAC motors running on an AC line operate with a constant flux because voltage and frequency are constant. Motors operated with constant flux are said to have constant torque. An AC drive can operate a motor with a constant flux of from zero to the motor’s rated nameplate frequency (typically 60 Hz), which is the constant-torque range. As long as a constant V/Hz ratio is maintained, the motor will generate constant torque. AC drives change the frequency to vary the speed of the motor and change voltage proportionately to maintain constant flux. The V/Hz ratio can be kept constant for any speed up to 60 Hz. See Fig. 12.22.
Some examples of constant torque loads are conveyors, positive-displacement pumps, extruders, hydraulic pumps, and packaging machinery.
Constant Horsepower LoadSome applications require a motor to be operated at above base speed. Such applications need less torque at higher speeds, yet require voltage to be no higher than the rated nameplate voltage because the motor insulation deteriorates exponentially at higher-than-rated voltage. VFDs are designed to maintain a constant V/Hz ratio and torque up to 60 Hz. As Table 12.9 shows, the V/Hz ratio decreases at above 60 Hz because VFDs are designed to maintain constant voltage above 60 Hz. When the V/Hz ratio decreases, the air-gap flux decreases, causing a decrease in the torque. Because the motor horsepower is directly proportional to the torque and speed of the motor, it remains constant while torque decreases in proportion to the increase in frequency. As such, a motor that is operated above its rated frequency is operating in a region known as constant horsepower (see Fig. 12.22).
Reduced Voltage and Frequency StartingA NEMA B motor that is started by connecting it to the power supply at full voltage and full frequency will develop approximately 150% starting torque and 600% starting current (Fig. 12.19). The same motor started with a VFD at reduced voltage and frequency develops approximately 150% torque and current. Fig. 12.23 shows that the torque/speed curve shifts to the right as frequency and voltage are increased. The dotted lines on the torque/speed curve represent the portion of the curve not used by the drive. The drive starts and accelerates the motor smoothly as frequency and voltage are gradually increased to the desired speed. A VFD drive that is properly sized to a motor is capable of delivering 150% torque at any speed up to the speed that corresponds to the incoming line voltage.
Some applications require a starting torque > 150%. A conveyor, for example, might require a 200% rated torque for starting. If a motor is capable of 200% torque at 200% current, and the drive is capable of 200% current, then 200% motor torque is possible. Typically, drives are capable of producing 150% of the drive nameplate rated current for 1 minute. A load that needs more starting torque than a drive can deliver requires a drive with a higher current rating. It is appropriate to supply a drive with a higher continuous horsepower rating than the motor when high peak torque is required.
Selecting a Motor
AC drives often have more capability than the motor. Drives can run at higher frequencies than might be suitable for an application. At frequencies above 60 Hz, for example, the V/Hz ratio decreases and the motor cannot develop 100% torque. Drives also can run at lower speeds than might be suitable. For example, a self-cooled motor might not develop enough air flow for cooling at reduced speeds and full load. Each motor must be evaluated according to its own capability before selecting it for use on an AC drive.
Harmonics, voltage spikes, and voltage rise times of AC drives are not identical. Some AC drives have more sophisticated filters and other components that are designed to minimize undesirable heating and insulation damage to the motor. This must be considered when selecting an AC drive/motor combination. Motor manufacturers generally will classify certain recommended motor selections on the basis of experience, required speed range, type of load torque, and temperature limits.
Distance Between Drive and Motor
The distance between the drive and the motor must also be considered. All motor cables have line-to-line and line-to-ground capacitance. The longer the cable, the greater the capacitance. Some types of cables (e.g., shielded cable or cables in metal conduit) have greater capacitance. The charging current in the cable capacitance causes spikes in the output of AC drives; higher voltage and higher capacitance cause higher current spikes. Voltage spikes caused by long cable lengths can shorten the life of the AC drive and motor. When considering an application in which distance might be a problem, contact the VFD manufacturer for its recommendations.
Service Factor on AC Drives
A high-efficiency motor with a 1.15 service factor is recommended when used on an AC drive. The 1.15 service factor is reduced to 1.0 because of heat associated with harmonics of an AC drive.
Matching AC Motors to Load
One way to evaluate whether the torque capabilities of a motor meet the torque requirements of the load is to compare the motor’s speed/torque curve with the speed/torque requirements of the load.
Load-Characteristics TablesUse a load-characteristics table to find the torque characteristics of various types of loads. Table 12.10 is an example of such a table, although it contains only a partial list of load types. NEMA MG 1 is one—and a complete—source of typical torque characteristics.
Calculating Load Torque
The most accurate way to obtain torque characteristics of a given load is to obtain them from the equipment manufacturer.
Centrifugal PumpWhen a motor accelerates a load from zero to full-load speed, the amount of torque it can produce changes. Throughout acceleration, the motor must produce more torque than required by the load. Fig. 12.24 graphs speed/torque curves for a NEMA B motor with a centrifugal-pump load. The pump load curve shows that the centrifugal pump only requires approximately 20% of full-load torque to start. The torque dips slightly after the pump is started, then increases. This typically is defined as a variable torque load. The pump will operate at the speed where the torque required by the pump equals that furnished by the motor.
Screw-Down ActuatorFig. 12.25 graphs speed/torque curves for a NEMA-B motor with a screw-down actuator load. The actuator-load curve shows that the starting torque of a screw-down actuator is approximately 200% of full-load torque. Comparing the load’s requirement with the NEMA B-design motor of equivalent horsepower shows that the load’s starting torque requirement is greater than the motor’s capability. The motor therefore will not start and accelerate the load.
One solution would be to use a higher-horsepower NEMA B motor. A less-expensive solution might be to use a NEMA D motor of the same horsepower requirements as the load. A NEMA D motor would start and accelerate the load easily, as shown in Fig. 12.26.
The motor selected to drive the load must have sufficient torque to start, accelerate, and run the load. If ever the motor cannot produce the required torque, it will stall or run in an overloaded condition. This will cause it to generate excess heat and typically to exceed current limits, causing protective devices to disconnect the motor from the power source. If the overload condition is not corrected, or the proper motor not installed, the existing motor eventually will fail.
An enclosure protects a motor from contaminants in the environment in which it is operating. In addition, the type of enclosure affects the cooling of the motor. Enclosures are categorized as either open or totally enclosed, and there are different types of enclosures within each category.
Open Drip-Proof (ODP)
Open enclosures permit cooling air to flow through the motor. The rotor has fan blades that help move the air through the motor. One type of open enclosure is the ODP enclosure. In an ODP enclosure, the vent openings prevent liquids and solids that fall from above at angles up to 15° from vertical from entering the interior of the motor and damaging the operating components. When the motor is not in the horizontal position, such as when it is mounted on a wall, a special cover might be necessary to protect it. An ODP enclosure can be specified when the environment is free from contaminants and where wind-driven rain is not a consideration.
Totally Enclosed Nonventilated (TENV)
Sometimes, the air surrounding the motor contains corrosive elements, dust, sand, and other debris that can damage the internal parts of a motor, or the motor is exposed to wind-driven rain or seawater spray. A totally enclosed motor enclosure is not airtight, but it restricts the free exchange of air between the inside of the motor and the outside. A seal where the shaft passes through the housing keeps out water, dust, and other foreign matter that could enter the motor along the shaft. The absence of ventilating openings means that all heat dissipates through the enclosure through conduction.
Most TENV motors are fractional horsepower in size. TENV motors can be used indoors and outdoors.
Totally Enclosed, Fan-Cooled (TEFC)
Totally enclosed, fan-cooled enclosures are similar to TENV enclosures, except that an external fan is mounted opposite the drive end of the motor. The fan provides additional cooling by blowing air over the exterior of the motor to dissipate heat more quickly. A shroud covers the fan to prevent anyone from touching it. With this arrangement no outside air enters the interior of the motor. TEFC motors can be used in dirty, moist, or mildly corrosive operating conditions, or where wind-driven rain is anticipated.
Explosion-proof motor enclosures are similar in appearance to TEFC motors, but are designed to contain an inside explosion and to prevent ignition of specified gases or vapors surrounding the motors.
NEMA has standardized frame-size motor dimensions, including bolt-hole sizes, mounting-base dimensions, shaft height, shaft diameter, and shaft length. Existing motors can be replaced without reworking the mounting arrangement. New installations are easier to design because the dimensions are known. Letters are used to indicate where a dimension is taken. For example, the letter "C" indicates the overall length of the motor, and "E" represents the distance from the center of the shaft to the center of the mounting holes in the feet. Motor manufacturers provide tables in the motor-data sheet that reference the letter to find the desired dimension.
NEMA categorizes standard frame sizes as either fractional or integral. Fractional frame sizes are designated as 45 and 56, and mainly include horsepower ratings of < 1.0. Integral (or medium) horsepower motors are designated by frame sizes that range from 143T to 445T. A "T" in the motor frame size designation of integral horsepower motors indicates that the motor is built to current NEMA frame standards. Motors built before 1966 have a "U" in the motor frame size designation, indicating that they were built to previous NEMA standards.
The frame-size designation is a code to help identify key dimensions. For example, the first two digits are used to determine the shaft height. The shaft height is the distance from the center of the shaft to the mounting surface, given in inches. To calculate the shaft height, divide the first two digits of the frame size by four. For example, a 143T frame size motor has a shaft height of 3.5 in. (14 ÷ 4).
The third digit in the integral "T" frame-size number is the NEMA code for the distance between the center lines of the mounting bolt-holes. The dimension is determined by matching the third digit in the frame number with a table in NEMA MG-1. 
Motors that are larger than the NEMA frame sizes are referred to as above-NEMA motors. These motors typically range in size from 200 to 10,000 hp.
There are no standardized frame sizes or dimensions for above-NEMA motors because above-NEMA motors typically are constructed to meet the specific requirements of an application.
The customer typically supplies specifications for starting torque, breakdown torque, and full-load torque on the basis of speed-torque curves obtained from the driven-equipment manufacturer; however, there are some minimum torques that all large AC motors must be able to develop. These are specified by NEMA MG-1:
- Locked-rotor torque ≥ 60% of full-load torque.
- Pull-up torque ≥ 60% of full-load torque.
- Maximum torque ≥ 175% of full-load torque.
Altitude and Ambient Temperature
Above-NEMA motors require the same adjustment for altitude and ambient temperatures as do integral frame-size motors. When the motor is operated at an altitude of above 3,300 ft, a higher class of insulation should be used or the motor should be derated. Above-NEMA motors with Class-B insulation can be modified easily for operation in ambient temperatures between 40° and 50°C. Operation at ambient temperatures of > 50°C requires special modification at the factory.
Enclosures for Above-NEMA Motors
Environmental factors also affect large AC motors. Enclosures used on above-NEMA motors are different from those on integral frame-size motors.
ODP.The ODP enclosure for an above-NEMA motor provides the same amount of protection as the one for the integral frame-size open motor. As with the integral frame-size ODP, the above-NEMA ODP provides the least amount of protection for the motor’s electrical components and typically is used in contaminant-free environments.
Horizontal Drip-Proof Weather-Protected Type I.The horizontal drip-proof weather-protected type I enclosure is an open enclosure with ventilating passages that are designed to minimize the entrance of rain, snow, and airborne particles that could come into contact with the electrical and rotating parts of the motor. All air inlets and exhaust vents are covered with screens. It is used on indoor applications in low-humidity environments.
Horizontal Drip-Proof Weather-Protected Type II.Horizontal drip-proof weather-protected type II enclosures are open enclosures with vents that are constructed so that high-velocity air and airborne particles blown into the motor are discharged without entering the internal ventilating passages that lead to the electrical parts of the motor. The intake and discharge vents are designed to have at least three 90° turns and to maintain the air velocity at < 600 ft/min. It is used outdoors on motors that are not protected by other structures.
TEFC for Above-NEMA Motors.A TEFC enclosure for an above-NEMA motor functions the same way as the TEFC enclosure for integral frame-size motors. It is designed for indoor and outdoor applications in which internal parts must be protected from adverse ambient conditions. Above-NEMA TEFC enclosures are available for motors up to 900 hp on 580 frames and up to 2,250 hp on 708 to 880 frames.
Totally Enclosed, Air-to-Air Cooled.Motors using the totally enclosed, air-to-air cooled enclosure use the air-to-tube type of heat exchangers for cooling.
Totally Enclosed, Water-to-Air Cooled.In some situations, the motor frame cannot adequately dissipate heat, even with the help of a fan. The totally enclosed, water-to-air cooled enclosure cools the motor using a water-to-air heat exchanger and thus requires a steady supply of water.
Totally Enclosed, Fan-Cooled, Explosion-Proof. Large AC motors also are used in hazardous environments. The totally enclosed, fan-cooled, explosion-proof enclosure meets or exceeds all applicable Underwriter’s Laboratories (UL) Standard 1203 requirements for hazardous (Division 1) environmental operation. 
|A||=||cross-sectional area of conductor, circular mil|
|Eg||=||generator voltage, V|
|Em||=||transformer voltage, kV|
|Et||=||motor voltage, kV|
|Fp||=||power factor, cos θ|
|H||=||horsepower [Eq. 12.17]|
|L||=||length of conductor, ft|
|N||=||rotor speed, rev/min|
|Nm||=||motor speed, rev/min|
|Ns||=||synchronous speed, rev/min|
|P||=||number of poles|
|Pa||=||active power, kW|
|Pap||=||apparent power, kVA|
|Pr||=||reactive power, kVAR|
|X||=||cable three-phase reactance, Ω|
|Xg||=||generator reactance, Ω|
|Xm||=||motor reactance during starting, Ω|
|X′d||=||transient reactance of the generator, %|
|Z||=||transformer impedance, Ω|
|Zc||=||the three-phase impedance of the cable between the transformer and the motor, Ω|
|Zm||=||motor-starting impedance, Ω|
|Zt||=||total impedance, Ω|
|Ztr||=||transformer impedance, %|
|ΔE||=||voltage drop, V|
|θ||=||power factor angle|
|ρ||=||resistivity of conductor, Ω-circular mil/ft|
- API RP4F, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1 and Division 2 Locations, fourth edition. 1999. Washington, DC: API.
- API RP505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, first edition. 1998. Washington, DC: API.
- API RP540, Recommended Practice for Electrical Installation in Petroleum Processing Plants, fourth edition. 1999. Washington, DC: API.
- API RP540, Recommended Practice for Electrical Installation in Petroleum Processing Plants, fourth edition. 1999. Washington, DC: API. Cite error: Invalid
<ref>tag; name "r5" defined multiple times with different content
- ANSI C37.12, For AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis—Specification Guide—1991. 1991. New York City: American Natl. Standards Inst.
- ANSI/IEEE C37.20.1-2002, Standard for Metal-Enclosed Low Voltage Power Circuit Breaker Switchgear,[revision of ANSI/IEEE C37.20.1-1993 (R1998)]. 1998. New York City: American Natl. Standards Inst.
- ANSI C37.20.2, Standard for Metal-Clad and Station-Type Cubicle Switchgear. 1999. New York City: American Natl. Standards Inst.
- ANSI C37.12.70, Terminal Markings and Connections for Distribution and Power Transformers. 2000. New York City: American Natl. Standards Inst.
- ANSI C84.1, Voltage Rating for Electrical Wiring and Equipment (60Hz). 1989. New York City: Natl. Standards Inst.
- CSA C22.1, Canadian Electrical Code, Part I, 19th edition. 2002. Rexdale, Ontario, Canada: Canadian Standards Assn.
- IEC 60050-426 (1990-10), International Electrotechnical Vocabulary, Chapter 426: Electrical Apparatus for Explosive Atmospheres, ed. 1.0 bilingual. 1990. Geneva: Intl. Electrotechnical Commission (IEC).
- IEC 331, Fire-Resisting Characteristics of Electrical Cables. 1999. Geneva: IEC.
- IEC 529, Degrees of Protection Provided by Enclosures (IP Code). 2001. Geneva: IEC.
- IEEE Std. 100, Standard Dictionary of Electrical and Electronics Terms, sixth edition. 1996. New York City: IEEE.
- IEEE Std. 141, Electrical Power Distribution for Industrial Plants. 1993. New York City: IEEE.
- IEEE Std. 142, Grounding of Industrial and Commercial Power Systems. 1991. New York City: IEEE.
- IEEE Std. 242, Protection and Coordination of Industrial and Commercial Power Systems. 2001. New York City: IEEE.
- IEEE Std. 315, Graphic Symbols for Electrical and Electronics Diagrams (R1993). 1975. New York City: IEEE.
- IEEE Std. 446, Emergency and Standby Power Systems for Industrial and Commercial Applications. 1995. New York City: IEEE.
- IEEE Std. 485, Sizing Large Lead Storage Batteries for Generating Stations and Substations (R2003). 1997. New York City: IEEE.
- TIESNA RP1 American Natl. Standard Practice for Office Lighting. 2004. New York City: The Illuminating Engineering Soc. of North America.
- TIESNA RP7 American Natl. Standard Practice for Industrial Lighting. 2001. New York City: The Illuminating Engineering Soc. of North America.
- ISA-5.1, Instrumentation Symbols and Identification (R1992). 1984. Research Triangle Park, North Carolina: ISA.
- ANSI/ISA-12.00.01, Electrical Apparatus for Use in Class I, Zones 0, 1, and 2, Hazardous (Classified) Locations: General Requirements. 2002. Research Triangle Park, North Carolina: ISA.
- ISA-RP 12.1 Recommended Practice for Electrical Instruments in Hazardous Atmospheres. 1999. Research Triangle Park, North Carolina: ISA.
- NEMA MG 2 Safety Standard for Construction and Guide for Selection, Installation, and Use of Electrical Motors and Generators. 2001. Rosslyn, Virginia: NEMA.
- NEMA MG 10 Energy Management Guide for Selection and Use of Polyphase Motors. 2001. Rosslyn, Virginia: NEMA.
- NFPA 30, Flammable and Combustible Liquids Code. 2003. Quincy, Massachusetts: Natl. Fire Protection Assn.
- NFPA 78, Lightning Protection Code. 1989. Quincy, Massachusetts: NFPA.
- NFPA 496, Standard for Purged and Pressurized Enclosures for Electrical Equipment. 2003. Quincy, Massachusetts: NFPA.
- NFPA 497, Recommended Practices for the Classification of Flammable Liquids, Gases, or Vapors and of Hazardous (Classified) Locations for Electrical Installations in Chemical Process Area. 2004. Quincy, Massachusetts: NFPA.
- US DOI 30 CFR Part 250, Oil and Gas and Sulfur Operation in the Outer Continental Shelf. 2004. Washington, DC: US Dept. of the Interior.
- API RP500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, second edition. 1998. Washington, DC: API.
- NEMA MG 1 Motors and Generators. 2003. Rosslyn, Virginia: NEMA.
- NFPA 70, Natl. Electrical Code (NEC). 2005. Quincy, Massachusetts: NFPA.
- US DOT 49 CFR Part 190, Pipeline Safety Programs and Rulemaking Procedures. 2004. Washington, DC: US Dept. of Transportation.
- US DOT 49 CFR Part 191, Transportation of Natural and Other Gas by Pipeline; annual reports, incident reports, and safety-related condition reports. 2004. Washington, DC: US Dept. of Transportation.
- US DOT 49 CFR Part 192, Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards. 2004. Washington, DC: US Dept. of Transportation.
- US DOT 49 CFR Part 195, Transportation of Hazardous Liquids by Pipeline. 2004. Washington, DC: US Dept. of Transportation.
- OSHA 29 CFR Part 1910, Subpart H, Hazardous Materials. 2004. Washington, DC: Occupational Safety and Health Administration (OSHA).
- OSHA 29 CFR Part 1910, Subpart S Electrical. 2004. Washington, DC: OSHA.
- OSHA 29 CFR Part 1926, Subpart K Electrical Construction. 2004. Washington, DC: OSHA.
- USCG 33 CFR Part 67, Subchapter C Aids to Navigation. 2004. Washington, DC: US Coast Guard.
- USCG 46 CFR Part 110-113, Shipping Subchapter J Electrical Engineering. 2004. Washington, DC: US Coast Guard.
- Bradley, H.B. ed. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.
- UL Standard 1203, Explosion-Proof and Dust-Ignition-Proof Electrical Equipment for Use in Hazardous (Classified) Locations. 2000. Northbrook, Illinois: Underwriters Laboratories Inc.fckLR
SI Metric Conversion Factors
|A||×||1.0*||E + 00||=||A|
|circular mil||×||5.067 075||E – 10||=||m2|
|cycles/s||×||1.0*||E + 00||=||Hz|
|°F||(°F – 32)/1.8||=||°C|
|ft||×||3.048*||E – 01||=||m|
|hp||×||7.460 43||E – 01||=||kW|
|in.||×||2.54*||E + 00||=||cm|
|in.2||×||6.451 6*||E + 00||=||cm2|
|lbf-ft||×||1.355 818||E + 00||=||N•m|
|mile||×||1.609 344*||E + 00||=||km|
|rev/min||×||1.666 667||E – 02||=||rev/s|
|V||×||1.0*||E + 00||=||V|
Conversion factor is exact.
API RP4F, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1 and Division 2 Locations, fourth edition. 1999. Washington, DC: API.
API RP505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, first edition. 1998. Washington, DC: API.
API RP540, Recommended Practice for Electrical Installation in Petroleum Processing Plants, fourth edition. 1999. Washington, DC: API.
API RP2003, Recommended Practice for Protection Against Ignitions Arising Out of Static, Lightning, and Stray Currents, sixth edition. 1998. Washington, DC: API.
ANSI C37.12, For AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis—Specification Guide—1991. 1991. New York City: American Natl. Standards Inst.
ANSI/IEEE C37.20.1-2002, Standard for Metal-Enclosed Low Voltage Power Circuit Breaker Switchgear,[revision of ANSI/IEEE C37.20.1-1993 (R1998)]. 1998. New York City: American Natl. Standards Inst.
ANSI C37.20.2, Standard for Metal-Clad and Station-Type Cubicle Switchgear. 1999. New York City: American Natl. Standards Inst.
ANSI C37.12.70, Terminal Markings and Connections for Distribution and Power Transformers. 2000. New York City: American Natl. Standards Inst.
ANSI C84.1, Voltage Rating for Electrical Wiring and Equipment (60Hz). 1989. New York City: Natl. Standards Inst.
CSA C22.1, Canadian Electrical Code, Part I, 19th edition. 2002. Rexdale, Ontario, Canada: Canadian Standards Assn.
IEC 60050-426 (1990-10), International Electrotechnical Vocabulary, Chapter 426: Electrical Apparatus for Explosive Atmospheres, ed. 1.0 bilingual. 1990. Geneva: Intl. Electrotechnical Commission (IEC).
IEC 331, Fire-Resisting Characteristics of Electrical Cables. 1999. Geneva: IEC.
IEC 529, Degrees of Protection Provided by Enclosures (IP Code). 2001. Geneva: IEC.
IEEE Std. 100, Standard Dictionary of Electrical and Electronics Terms, sixth edition. 1996. New York City: IEEE.
IEEE Std. 141, Electrical Power Distribution for Industrial Plants. 1993. New York City: IEEE.
IEEE Std. 142, Grounding of Industrial and Commercial Power Systems. 1991. New York City: IEEE.
IEEE Std. 242, Protection and Coordination of Industrial and Commercial Power Systems. 2001. New York City: IEEE.
IEEE Std. 315, Graphic Symbols for Electrical and Electronics Diagrams (R1993). 1975. New York City: IEEE.
IEEE Std. 446, Emergency and Standby Power Systems for Industrial and Commercial Applications. 1995. New York City: IEEE.
IEEE Std. 485, Sizing Large Lead Storage Batteries for Generating Stations and Substations (R2003). 1997. New York City: IEEE.
TIESNA RP1 American Natl. Standard Practice for Office Lighting. 2004. New York City: The Illuminating Engineering Soc. of North America.
TIESNA RP7 American Natl. Standard Practice for Industrial Lighting. 2001. New York City: The Illuminating Engineering Soc. of North America.
ISA-5.1, Instrumentation Symbols and Identification (R1992). 1984. Research Triangle Park, North Carolina: ISA.
ANSI/ISA-12.00.01, Electrical Apparatus for Use in Class I, Zones 0, 1, and 2, Hazardous (Classified) Locations: General Requirements. 2002. Research Triangle Park, North Carolina: ISA.
ISA-RP 12.1 Recommended Practice for Electrical Instruments in Hazardous Atmospheres. 1999. Research Triangle Park, North Carolina: ISA.
NEMA MG 2 Safety Standard for Construction and Guide for Selection, Installation, and Use of Electrical Motors and Generators. 2001. Rosslyn, Virginia: NEMA.
NEMA MG 10 Energy Management Guide for Selection and Use of Polyphase Motors. 2001. Rosslyn, Virginia: NEMA.
NFPA 30, Flammable and Combustible Liquids Code. 2003. Quincy, Massachusetts: Natl. Fire Protection Assn.
NFPA 70, Natl. Electrical Code (NEC). 2005. Quincy, Massachusetts: NFPA.
NFPA 78, Lightning Protection Code. 1989. Quincy, Massachusetts: NFPA.
NFPA 496, Standard for Purged and Pressurized Enclosures for Electrical Equipment. 2003. Quincy, Massachusetts: NFPA.
NFPA 497, Recommended Practices for the Classification of Flammable Liquids, Gases, or Vapors and of Hazardous (Classified) Locations for Electrical Installations in Chemical Process Area. 2004. Quincy, Massachusetts: NFPA.
US DOI 30 CFR Part 250, Oil and Gas and Sulfur Operation in the Outer Continental Shelf. 2004. Washington, DC: US Dept. of the Interior.
US DOT 49 CFR Part 190, Pipeline Safety Programs and Rulemaking Procedures. 2004. Washington, DC: US Dept. of Transportation.
US DOT 49 CFR Part 191, Transportation of Natural and Other Gas by Pipeline; annual reports, incident reports, and safety-related condition reports. 2004. Washington, DC: US Dept. of Transportation.
US DOT 49 CFR Part 192, Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards. 2004. Washington, DC: US Dept. of Transportation.
US DOT 49 CFR Part 195, Transportation of Hazardous Liquids by Pipeline. 2004. Washington, DC: US Dept. of Transportation.
OSHA 29 CFR Part 1910, Subpart H, Hazardous Materials. 2004. Washington, DC: Occupational Safety and Health Administration (OSHA).
OSHA 29 CFR Part 1910, Subpart S Electrical. 2004. Washington, DC: OSHA.
OSHA 29 CFR Part 1926, Subpart K Electrical Construction. 2004. Washington, DC: OSHA.
USCG 33 CFR Part 67, Subchapter C Aids to Navigation. 2004. Washington, DC: US Coast Guard.
USCG 46 CFR Part 110-113, Shipping Subchapter J Electrical Engineering. 2004. Washington, DC: US Coast Guard.Bradley, H.B. ed. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.