Advantages and Disadvantages of ESP Systems

Advantages & Disadvantages of Electrical Submersible Pumping Systems

From Tables 10-5(a) – 10-5(j), 10-6(a) – 10-6(i), 10-7(a) – 10-7(l)

Artificial Lift Selection, SPE Handbook

Artificial Lift – Design Considerations and Overall Comparisons (Clegg, et al., 12/1993)


Consideration for ESP’s

Capital cost ·    Relatively low capital cost if electric power available. 

·    Costs increase as horsepower increases.

Downhole equipment ·    Requires proper cable in addition to motor, pumps, seals, etc. 

·    Good design plus good operating practices are essential.


Operating efficiency

(Hydraulic HP/Input HP)

·     Good for high rate wells but decreases significantly for < 1000 BFPD. 

·     Typically total system efficiency is about 50% for high rate wells but for < 1000 BPD, efficiency typically <40%. 

·     Can be as high as 60% for large ID equipment.

Flexibility ·     Poor for fixed speed. 

·     Requires careful design. 

·     VSD provides better flexibility.

Miscellaneous problems ·     Requires a highly reliable electric power system. 

·     System very sensitive to changes downhole or in fluid properties.

Operating costs ·     Varies. 

·     If high HP, high energy costs. 

·     High pulling costs result from short run life especially in offshore operation. 

·     Repair costs often high.

System reliability ·     Varies. 

·     Excellent for ideal lift cases.

·     Poor for problem areas (very sensitive to operating temperatures and electrical malfunctions).

Salvage value ·     Fair. 

·     Some trade in value. 

·     Poor open market values.

System (Total) ·     Fairly simple to design but requires good rate data. 

·     System not forgiving. 

·     Requires excellent operating practices. 

·     Follow API RP’s in design, testing, and operation. 

·     Each well is an individual producer using a common electric system.

Usage/outlook ·     An excellent high rate artificial lift system. 

·     Best suited for <200 0F and >1000 BFPD rates. 

·     Most often used on high water cut wells. 

·     Used on about 5% of US lifted wells.

Casing size limits

(Restricts tubing size)

·     Casing size will limit use of large motors and pumps. 

·     Avoid 4.5” casing and smaller. 

·     Reduced performance inside 5.5” casing depending on depth and rate.

Depth limits ·     Usually limited to motor HP or temperature. 

·     Practical depth about 10,000 feet.

·     1000’ – 10000’ TVD is typical, Max is 15,000 ‘ TVD.

Intake capabilities

(Ability to pump with low pressures at pump intake)

·     Fair if little free gas (i.e. >250 PSI pump intake pressure). 

·     Poor if F = 666*(Qg/Ql)/Pip > 1.0

Where: Pip: intake psi; Qg: gas vol; Ql: liquid vol @ intake conditions.

·     5% gas at low pressures can cause problems.

Noise level ·     Excellent. 

·     Very low noise. 

·     Often preferred in urban areas if production rate high.

Obtrusiveness ·     Good. 

·     Low profile but requires transformer bank.

Prime mover flexibility ·     Fair. 

·     Requires a good power source without spikes or interruptions. 

·     Higher voltages can reduce losses.

Surveillance ·     Fair. 

·     Electrical checks but special equipment needed otherwise.

Relative ease of well testing ·     Good. 

·     Simple with few problems. 

·     High water cut and high rate wells may require a free water knock out (three-phase separator).

Time cycle and pump off controllers application ·     Poor. 

·     Soft start and improved seal/ protectors recommended.

Corrosion/scale handling ability ·     Fair. 

·     Batch treating inhibitor only to intake unless shroud is used.

Crooked/deviated holes ·     Good.

·     Few problems.

·     Limited experience in horizontal wells.

·     Requires long radius wellbore bends to get through.

10° typical,

0 – 90° < 10° / 100 build angle maximum.

·     However must set in section 0 – 2° max deviation.

Duals application ·     No known installations.

·     Larger casing required.

·     Possible run & pull problems.

Gas handling ability ·     Poor for free gas (i.e. >5% through pump).

·     Poor if F = 666 * (Qg/Ql)/Pip > 1.0

Where: Pip: intake psi; Qg: gas vol; Ql: liquid vol, @ intake conditions.

·     Rotary gas separators helpful if solids not produced.

Offshore application ·     Good.

·     Must provide electrical power and service pulling unit.

Paraffin handling capability ·     Fair.

·     Hot water/oil treatments, mechanical cutting, batch inhibition possible.

Slim hole completions

(2 7/8″ tubing, casing)

·     No known installations.
Solids/sand handling ability ·     Poor.

·     Requires <100 – 200 PPM solids for standard construction.

·     200 – 2000 ppm possible with special bushings, stage materials, coatings, and thrust supporting bearings or fixed pumps employed.

·     A maximum of about 5000 ppm might be possible depending on pump and sharpness and angularity of sand.

Temperature limitation ·     Limited to <2500F for standard & <4000F for special motors & cable.

·     100 – 275°F typical.

High viscosity fluid handling capability ·     Fair.

·     Limited to as high as 1000 cp.

·     Depends on economics.   (~>7-9°API)

·     Increases HP and reduces head.

·     Potential solution is to use “core flow” with 20% water.

High volume lift capabilities ·     Excellent.

·     Limited by needed HP and can be restricted by casing size.

·     In 5.5” casing can produce 4000 BFPD from 4000 feet W/240 HP.

·     Tandem motors increase HP & operating costs.

200 – 20,000 bpd typical, ~30,000 bpd max.

52,000 bpd, shallow, 10.25” equip has been done.

Low volume lift capabilities ·      Generally poor.

·      Lower efficiencies and high operating costs <400 BFPD.