Multiphase correlations References

Multiphase correlations References:

Correlation Description Reference
1 Anand, et al Predicting Thermal Conductivities of Formations from Other Known Properties. JPT (Oct. 1980).
2 Ashford, F.E, & Pierce, P.E. The Determination of Multiphase Pressure Drops and Flow Capacities in Downhole Safety Valves (Storm Chokes). SPE 5161 1974 SPE Annual Fall Meeting, Houston Oct. 6-9.
3 Beggs, H.D. & Brill, J.P. A Study of Two Phase Flow in Inclined Pipe. JPT (May 1973), 606-617.
4 Churchill-Chu Correlating Equations for Laminar and Turbulent Free Convection from a Horizontal Cylinder. International Journal Heat Mass Transfer (1975) 18, 1049-1053.
5 Fancher, & Brown, G.G. Prediction of Pressure Gradients for Multiphase Flow in Tubing. SPE Journal (Mar. 1963), 59-64.
6 Fortunati Two Phase Flow Through Well-head Chokes. SPE 3742 1972 SPE European Spring Meeting, Amsterdam, May 17-18.
7 Hagedorn, A.R. & Brown, K.E. Experimental Study of Pressure Gradients Occurring During Continuous Two-Phase Flow in Small-Diameter Vertical Conduits. JPT (Apr. 1965), 475-484.
8 Mandhane et al A Flow Pattern Map for Gas-liquid Flow in Horizontal Pipes. International Journal Multiphase Flow, 1, 537-541.
9 Moody Friction Factor for Pipe Flow. Trans., AIME (1944), 66, 671-675.
10 Mukherjee, H. & Brill, J.P. Liquid Holdup Correlations for Inclined Two-Phase Flow. JPT (May 1983), 1003-1008.
11 Oranje Condensate Behaviour in Gas Pipeline is Predictable. Oil and Gas Journal (July 1973), 39-43.
12 Orkiszewski Predicting Two Phase Pressure Drop in Vertical Pipes. JPT (June 1967), 829-833.
13 Duns, H. Jr & Ros, N.C.J. Vertical Flow of Gas and Liquid Mixtures in Wells. Proc., Sixth World Petroleum Congress, Frankfurt (1963) 451.
14 Tansev, E. Startzman, R. & Cooper, A. Predicting Pressure Loss and Heat Transfer in Geothermal Wellbores. SPE 5584 1975 SPE Annual Fall Meeting, Dallas, Sept. 28-Oct. 1.
15 Gould, T.L, Tek, M.R. & Katz, D.L. Two-Phase Flow Through Vertical, Inclined, or Curved Pipe. JPT, August, 1974, 915-925.

Reference: PROSPER Use’s Guide.

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Multiphase flow correlations

The primary purpose of a multiphase flow correlations is to predict the liquid holdup (and hence the flowing mixture density) and the frictional pressure gradient.  This article details the most widely used correlations for the prediction of the Vertical Lift Performance.

The oil and water are lumped together as one equivalent fluid. Thus flow correlations in common use consider liquid/gas interactions.  They are therefore more correctly termed two-phase flow correlations.  Depending on the particular correlation, flow regimes are identified and specialized holdup and friction gradient calculations are applied for each flow regime.

There is no universal rule for selecting the best flow correlation for a given application. When an outflow performance simulator is used, it is recommended that a Correlation Comparison always be carried out. By inspecting the predicted flow regimes and pressure results, the User can select the correlation that best models the physical situation.

Multiphase flow correlations:

Fancher & Brown:

  • Fancher and Brown is a no-slip correlation, with no flow regime map. Therefore, this correlation cannot be recommended for general use and it is provided for use as a quality control (should not be used for quantitative work).
  • It gives the lowest possible value of Vertical lift Performance (VLP). Therefore, Measured data falling to the left of Fancher Brown on the correlation comparison plot indicates a problem with fluid density (i.e PVT) or field pressure data.
  • According to Brown, it is only suitable for 2-3/8 – 2-7/8 inch tubing.
  • It is for GLR less than 5000 scf/bbl and flow rates less than 400 bpd.
  • It has its own friction factor model, which is independent of pipe roughness.

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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.