Category Archives: Equipment & Technology

Centrifugal Pump ( ESP Pump)

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Pump Theory:

The term “centrifugal pump” has been used to describe a wide variety of pumping applications and designs throughout the years. A Centrifugal Pump is a machine that moves fluid by spinning it with a rotating impeller in a diffuser that has a central inlet and a tangential outlet.  The path of the fluid is an increasing spiral from the inlet at the center to the outlet tangent to the diffuser. The fluid rotational motion is the result of the concept of centrifugal forces.

The pressure (head) develops against the inside wall of the diffuser because of the curved wall forces fluid to move in a circular path.

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Submersible Pump System Overview

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The submersible pump system consists of both downhole and surface components. The main surface components are transformers, motor controllers, junction box and wellhead. The main downhole components are the motor, seal, pump and cable. Additional downhole components may be included to the system: data acquisition instrumentation, motor lead extension, cable bands and protectors, gas separator, check and drain valves.

The following video gives a quick equipment overview of the ESP submersible pumping system:

 

The following figure shows schematic diagram of a submersible pump installation:

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Advantages and Disadvantages of ESP Systems

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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)

Category

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.

 

Pump Performance Curves – part 02

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In the previous article “Pump Performance Curves – part 01“, we have discussed how pump performance curves are obtained? How there are plotted? What are the downthrust and the upthrust? and what is the recommended operating range of the pump? In this article, pump performance curve is further detailed and we will answer the following two questions :

  • How the shape of the pump performance curve is related to changes in well performance?
  • What are the tolerance limits of performance data?

Shape of the pump performance curve:

The  ability  of  a  pump  to  adapt  to  changes  in  well  performance  depends  on  the characteristic  shape of  the pump performance  curve.

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Pump Performance Curve – part 01

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The pump performance curves characterize the performance of ESP pumps. This article will detail the technical aspects related to these curves and will answers the following questions: How pump performance curve is obtained? How to plot it? What are the downthrust and the upthrust? What is the recommended operating range of the pump?

Pump Curve:

The published pump performance curve describes the performance of particular pump (or stage). It shows the discharge head developed by the pump, brake horsepower (power consumption curve), and efficiency of the pump as a function of flow rate. It is an experimental curve given by the manufacturer and obtained with freshwater at 60 °F (S.G. = 1) under controlled conditions detailed in API RP11 S2. These curves are commonly available for both 50 Hz and 60 Hz operation and must represent the operation of one or more stages of each pump curve (the number of pump stages must be clearly indicated on the pump chart).

Typical Pump Curve

  • The left vertical axis is scaled in feet and meters of head (or lift).
  • The bottom horizontal axis is scaled in bbl/d and m3/d.
  • The curve labeled Head-Capacity defines the lift (or head) the impeller can produce at all of the available flow rates.
  • The first vertical axis on the right is scaled in horsepower. It is based on pumping water with a specific gravity of 1.00.

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