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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.

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 1 lists some of the major local and international codes and standards used in the oil field.

Also, U.S. regulatory agencies have established some requirements for the design, installation, and operation of offshore production platforms. Table 2 lists some of these governmental codes and regulatory documents. Other state and/or municipal regulations also may apply.

Power sources

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 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 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 Power factor and capacitors 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.

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:

Vol3 page 471 eq 001.PNG(Eq. 1)

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:

Vol3 page 471 eq 002.PNG(Eq. 2)

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%.[31]

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 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:

Vol3 page 472 eq 001.PNG(Eq. 3)

where Zt = total impedance, in Ω, given as:

Vol3 page 472 eq 002.PNG(Eq. 4)

for which

Vol3 page 472 eq 003.PNG(Eq. 5)

where Ztr = transformer impedance, %; Pt = transformer-rated kVA; and Et = transformer voltage, kV. For Eq. 4, the cable impedence is calculated as:

Vol3 page 472 eq 004.PNG(Eq. 6)

where R = cable resistance, Ω; X = cable three-phase reactance, Ω; θ = the power factor angle; and cos θ = power factor. (See [[Power factor and use of capacitors for a discussion of power factor.)

For Eq. 4, the motor-starting impedance is calculated as:

Vol3 page 472 eq 005.PNG(Eq. 7)

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:

Vol3 page 473 eq 001.PNG(Eq. 8)

where Xm =motor reactance during starting, Ω, and Xg = generator reactance, Ω. In Eq. 8, Xm is calculated as:

Vol3 page 473 eq 002.PNG(Eq. 9)

In Eq. 8, Xg is calculated as:

Vol3 page 473 eq 003.PNG(Eq. 10)

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.

Nomenclature

A = cross-sectional area of conductor, circular mil
E = voltage, V
Eg = generator voltage, V
Em = transformer voltage, kV
Et = motor voltage, kV
f = frequency, Hz
Fp = power factor, cos θ
I = current, A
L = length of conductor, ft
N = rotor speed, rev/min
Nm = motor speed, rev/min
Ns = synchronous speed, rev/min
P = number of poles
Pg = generator kVA
Pm = motor-starting kVA
Pr = reactive power, kVAR
Pt = transformer-rated kVA
R = resistance, Ω
S = slip, %
T = torque, lbf-ft
X = cable three-phase reactance, Ω
Xg = generator reactance, Ω
Xm = motor reactance during starting, Ω
Xd = 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

References

  1. 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.
  2. 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.
  3. 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.
  4. API RP540, Recommended Practice for Electrical Installation in Petroleum Processing Plants, fourth edition. 1999. Washington, DC: API.
  5. API RP2003, Recommended Practice for Protection Against Ignitions Arising Out of Static, Lightning, and Stray Currents, sixth edition. 1998. Washington, DC: API.
  6. 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.
  7. 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.
  8. ANSI C37.20.2, Standard for Metal-Clad and Station-Type Cubicle Switchgear. 1999. New York City: American Natl. Standards Inst.
  9. ANSI C37.12.70, Terminal Markings and Connections for Distribution and Power Transformers. 2000. New York City: American Natl. Standards Inst.
  10. ANSI C84.1, Voltage Rating for Electrical Wiring and Equipment (60Hz). 1989. New York City: American Natl. Standards Inst.
  11. CSA C22.1, Canadian Electrical Code, Part I, 19th edition. 2002. Rexdale, Ontario, Canada: Canadian Standards Assn.
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  15. IEEE Std. 100, Standard Dictionary of Electrical and Electronics Terms, sixth edition. 1996. New York City: IEEE.
  16. IEEE Std. 141, Electrical Power Distribution for Industrial Plants. 1993. New York City: IEEE.
  17. IEEE Std. 142, Grounding of Industrial and Commercial Power Systems. 1991. New York City: IEEE.
  18. IEEE Std. 242, Protection and Coordination of Industrial and Commercial Power Systems. 2001. New York City: IEEE.
  19. IEEE Std. 315, Graphic Symbols for Electrical and Electronics Diagrams (R1993). 1975. New York City: IEEE.
  20. IEEE Std. 446, Emergency and Standby Power Systems for Industrial and Commercial Applications. 1995. New York City: IEEE.
  21. IEEE Std. 485, Sizing Large Lead Storage Batteries for Generating Stations and Substations (R2003). 1997. New York City: IEEE.
  22. TIESNA RP1 American Natl. Standard Practice for Office Lighting. 2004. New York City: The Illuminating Engineering Soc. of North America.
  23. TIESNA RP7 American Natl. Standard Practice for Industrial Lighting. 2001. New York City: The Illuminating Engineering Soc. of North America.
  24. ISA-5.1, Instrumentation Symbols and Identification (R1992). 1984. Research Triangle Park, North Carolina: ISA.
  25. 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.
  26. ISA-RP 12.1 Recommended Practice for Electrical Instruments in Hazardous Atmospheres. 1999. Research Triangle Park, North Carolina: ISA.
  27. NEMA MG 1 Motors and Generators (revised 2004). 2003. Rosslyn, Virginia: NEMA.
  28. NEMA MG 2 Safety Standard for Construction and Guide for Selection, Installation, and Use of Electrical Motors and Generators. 2001. Rosslyn, Virginia: NEMA.
  29. NEMA MG 10 Energy Management Guide for Selection and Use of Polyphase Motors. 2001. Rosslyn, Virginia: NEMA.
  30. NFPA 30, Flammable and Combustible Liquids Code. 2003. Quincy, Massachusetts: Natl. Fire Protection Assn. (NFPA).
  31. 31.0 31.1 NFPA 70, Natl. Electrical Code (NEC). 2005. Quincy, Massachusetts: NFPA.
  32. NFPA 78, Lightning Protection Code. 1989. Quincy, Massachusetts: NEFPA.
  33. NFPA 496, Standard for Purged and Pressurized Enclosures for Electrical Equipment. 2003. Quincy, Massachusetts: NFPA.
  34. 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.
  35. 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.
  36. US DOT 49 CFR Part 190, Pipeline Safety Programs and Rulemaking Procedures. 2004. Washington, DC: US Dept. of Transportation.
  37. 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.
  38. 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.
  39. US DOT 49 CFR Part 195, Transportation of Hazardous Liquids by Pipeline. 2004. Washington, DC: US Dept. of Transportation.
  40. OSHA 29 CFR Part 1910, Subpart H, Hazardous Materials. 2004. Washington, DC: Occupational Safety and Health Administration (OSHA).
  41. OSHA 29 CFR Part 1910, Subpart S Electrical. 2004. Washington, DC: OSHA.
  42. OSHA 29 CFR Part 1926, Subpart K Electrical Construction. 2004. Washington, DC: OSHA.
  43. USCG 33 CFR Part 67, Subchapter C Aids to Navigation. 2004. Washington, DC: US Coast Guard.
  44. USCG 46 CFR Part 110-113, Shipping Subchapter J Electrical Engineering. 2004. Washington, DC: US Coast Guard.


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See also

Electrical grounding

Electrical distribution systems

Power factor and capacitors

Hazardous area classification for electrical systems

Alternating current motors

Induction motors

Synchronous motor

Motor specifications

NEMA motor characteristics

Alternating current motor drives

Motor enclosures

PEH:Electrical Systems