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.
(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.
(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.
· Low profile but requires transformer bank.
|Prime mover flexibility||· Fair.
· Requires a good power source without spikes or interruptions.
· Higher voltages can reduce losses.
· 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.
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.