Relative advantages and disadvantages of artificial lift systems

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.

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

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See also

Artificial lift

PEH:Artificial_Lift_Systems