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Relative advantages and disadvantages of artificial lift systems

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The discussion of each major artificial lift system includes advantages and disadvantages, more detailed listings are available from various sources.

Advantages

Rod Pumping

  • Relatively simple system design.
  • Units easily changed to other wells with minimum cost.
  • Efficient, simple, and easy for field people to operate.
  • Applicable to slimholes and multiple completions.
  • Can pump a well down to very low pressure (depth and rate dependent).
  • System usually is naturally vented for gas separation and fluid level soundings.
  • Flexible-can match displacement rate to well capability as well declines.
  • Analyzable.
  • Can lift high-temperature and viscous oils.
  • Can use gas or electricity as power source.
  • Corrosion and scale treatments easy to perform.
  • Applicable to pumpoff control if electrified.
  • Availability of different sizes.
  • Hollow sucker rods are available for slimhole completions and ease of inhibitor treatment.
  • Has pumps with double valving that pump on both upstroke and downstroke

Hydraulic piston pumping

  • Can lift from as deep as 18,000 feet (5486 m)
  • Can produce 500 B/D (79.49 m3/d) from 15,000 feet (4572 m)
  • Crooked holes present minimal problems depending on the model of pump being used.
  • Unobtrusive in urban locations.
  • Power source can be remotely located.
  • Installations can be analyzed.
  • Flexible. Normally able to match output to delivery of well.
  • Can use diesel, natural gas or electricity as power source.
  • Downhole pumps can be installed /retrieved using the power fluid.
  • Capable of producing a well to low formation pressures (pumped off).
  • Can be used on offshore platforms.
  • Can use any liquid for power fluid. Typically a liquid being produced from the well is used (water or oil)
  • Easy to pump in cycles depending on the model of pump being used.
  • Power fluid can be heated to reduce viscosity of produced fluid. Additional liquids can be mixed with the power fluid (such as diesel) for this purpose also.
  • Inhibitors can be mixed with the power fluid for the purposes of controlling corrosion, scale, emulsions, etc.

Electric submersible pumping

  • Can lift a wide range of volumes fromlow volumes 750 B/D, to extremely high volumes; 20,000 B/D (19 078 m3/d) in shallow wells with large casing.
  • Currently lifting± 120,000 B/D (19 068 m3/d) from water supply wells in Middle East with 600 hp (448 kW) units; 720 hp (537 kW) available; 1,000 hp (746 kW) under development.
  • Unobtrusive in urban locations.
  • Simple to operate.
  • Easy to install downhole­ pressure sensor for telemetering pressure to surface by cable.
  • Crooked holes present no problem.
  • Applicable offshore.
  • Corrosion and scale treatment easy to perform.
  • Availability of different sizes.
  • Lifting cost for high volumes generally very low.

Gas Lift

  • Can handle large volume of solids with minor problems.
  • Handles large volume in high-PI wells (continuous lift}; 50,000 B/D (7949.37 m /d).
  • Fairly flexible-convertible from continuous to intermittent to chamber or plunger lift as well declines.
  • Unobtrusive in urban locations.
  • Power source can be remotely located.
  • Easy to obtain downhole pressures and gradients.
  • Lifting gassy wells is no problem.
  • Sometimes serviceable with wireline unit.
  • Crooked holes present no problem.
  • Corrosion is not usually as adverse.
  • Applicable offshore.

Hydraulic jet pump

  • Can lift from as deep as 20,000 feet (5486 m)
  • Can produce 25,000 B/D (3975 m3/d) from 5,000 feet ( 1520 m)
  • Crooked holes present no problems.
  • Unobtrusive in urban locations.
  • Power source can be remotely located.
  • Installations can be analyzed.
  • Flexible. Normally able to match output to delivery of well.
  • Can use diesel, natural gas or electricity as power source.
  • Downhole pumps can be installed /retrieved using the power fluid.
  • No record of plugging due to producing sand.
  • Can be used on offshore platforms.
  • Can use any liquid for power fluid. Typically a liquid being produced from the well is used (water or oil)
  • Easy to pump in cycles by qualified personnel.
  • Power fluid can be heated to reduce viscosity of produced fluid. Additional liquids can be mixed with the power fluid (such as diesel) for this purpose also.
  • Inhibitors can be mixed with the power fluid for the purposes of controlling corrosion, scale, emulsions from reservoir, etc.
  • No record that a jet pump has ever created an emulsion

Plunger lift

  • Retrievable without pulling tubing.
  • Very inexpensive installation.
  • Automatically keeps tubing clean of paraffin and scale.
  • Applicable for high GOR wells.
  • Can be used with intermittent gas lift.
  • Can be used to unload liquid from gas wells.

Progressive cavity pumps

  • Some types are retrievable with rods.
  • Moderate cost.
  • Low profile.
  • Can use downhole electric motors that handle sand and viscous fluid well.
  • High electrical efficiency.

Continuous belt transportation

  • Very low cost of operation.
  • Low cost of installation.
  • Oleophilic belt collects only heavy oil.
  • Optimal application for high GOR, high viscosity, high sand and paraffin wells.
  • Increased production of stripper, marginal, and orphaned wells.
  • Lower environmental impact, no disposal of radiactive rods or hazardous fluids.
  • Can use downhole electric motors that handle sand and viscous fluid well.
  • Minimal water reclamation.
  • Unobtrusive in urban locations.

Disadvantages

Rod Pumping

  • Crooked holes present a friction problem.
  • High solids production is troublesome.
  • Gassy wells usually lower volumetric efficiency.
  • Is depth limited, primarily because of rod capability.
  • Obtrusive in urban locations.
  • Heavy and bulky in offshore operations.
  • Susceptible to paraffin problems.
  • Tubing cannot be internally coated for corrosion.
  • H2S limits depth at which a large-volume pump can be set.
  • Limitation of downhole pump design in small diameter casing.

Hydraulic piston pumping

  • Power oil systems are possible fire issue.
  • Maintaining an oil inventory required for power oil system, and cannot be sold.
  • Production end has same problems with sand as does a rod pump.
  • Production end has same problems with gas as does a rod pump.
  • Can install a vented system so gas can by-pass pump but such systems are more expensive.
  • Qualified personnel needed for trouble shooting in field, as with other A/L systems.
  • Qualified personnel needed to obtain valid well tests, as with other A/L systems.
  • Surfactant needed for lubrication of engine end when using water for power fluid.
  • Any leaks when using power oil pose an environmental issue. The issues of a leak when using a power water system are much less.

Electric submersible pumping

  • Not applicable to multiple completions.
  • Only applicable with electric power.
  • High voltages (1,000 V) are necessary.
  • Impractical in shallow, low volume wells.
  • Expensive to change equipment to match declining well capability.
  • Cable causes problems in handling tubulars.
  • Cables deteriorate in high temperatures.
  • System is depth limited, 10,000 ft (3048.0 m), because of cable cost and inability to install enough power downhole (depends on casing size).
  • Gas and solids production are troublesome.
  • Not easily analyzable unless good engineering know-how.
  • Lack of production rate flexibility.
  • Casing size limitation.
  • Cannot be set below fluid entry without a shroud to route fluid by the motor. Shroud also allows corrosion inhibitor to protect outside of motor.
  • More downtime when problems are encountered because of the entire unit being downhole.

Gas Lift

  • Lift gas is not always available.
  • Not efficient in lifting small fields or one-well leases.
  • Difficult to lift emulsions and viscous crudes.
  • Gas freezing and hydrate problems.
  • Problems with dirty surface lines.
  • Some difficulty in analyzing properly without engineering supervision.
  • Cannot effectively produce deep wells to abandonment.
  • Requires makeup gas in rotative systems.
  • Casing must withstand lift pressure.
  • Safety problem with high pressure gas.

Hydraulic jet pump

  • Uses momentum transfer as method for operation. A very inefficient form of energy transfer. Total system efficiency approximately 10-30%.
  • Requires approximately 10% submergence to prevent cavitation damage at low production rates.
  • Pump will cavitate if more production than planned is forced through the pump.
  • As with other A/L systems, the less the back pressure the better.
  • Producing more free gas for a given nozzle/throat combination than intended will reduce the amount of produced liquids and may cause cavitation damage. Pump must be retrieved and a larger throat installed.
  • Power oil systems are a possible fire issue.
  • High surface power fluid lines are required.
  • Any leaks when using power oil pose an environmental issue. The issues of a leak when using a power water system are much less.
  • Maintaining an oil inventory required for power oil system, and cannot be sold.
  • Can install a vented system so gas can by-pass pump but such systems are more expensive.
  • Qualified personnel needed for trouble shooting in field, as with other A/L systems.
  • Qualified personnel needed to obtain valid well tests, as with other A/L systems.

Plunger lift

  • May not take well to depletion; therefore, eventually requires another lift method.
  • Good for low-rate, normally less than 200 B/D (31.8 m/d) wells only.
  • Requires more engineering supervision to adjust properly.
  • Danger exists in plunger reaching too high a velocity and causing surface damage.
  • Communication between tubing and casing required for good operation unless used in conjunction with gas lift.

Progressive cavity pumps

  • Elastomers in stator swell in some well fluids.
  • Pump off control is difficult. Lose efficiency with depth.
  • Rotating rods wear tubing.
  • Rod windup and afterspin of rods increase with depth.
  • Sand and solids quickly wear chrome off of rotor.

Continuous belt transportation

  • Limited to 500B/D (79.2 m3/d) from 12123 feet (4000 m).
  • Not suitable for high volume production wells.
  • Cannot be used on offshore platforms.
  • Optimal only for medium, heavy and very heavy oil.
  • Limited to wells deviated less than 5 deg. depending on well bore configuration.

References

Noteworthy papers in OnePetro

Brown, K.E. 1982. Overview of Artificial Lift Systems. J Pet Technol 34 (10): 2384–2396. SPE-9979-PA. http://dx.doi.org/10.2118/9979-PA.

Clegg, J.D., Bucaram, S.M., and Hein, N.W.J. 1993. Recommendations and Comparisons for Selecting Artificial-Lift Methods. J Pet Technol 45 (12): 1128–1167. SPE-24834-PA. http://dx.doi.org/10.2118/24834-PA.

Neely, B., Gipson, F., Clegg, J. et al. 1981. Selection of Artificial Lift Method. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4-7 October 1981. SPE-10337-MS. http://dx.doi.org/10.2118/10337-MS.

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Artificial lift

PEH:Artificial_Lift_Systems

Category