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Plunger lift design and models

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Plunger lift systems can be evaluated using rules of thumb in conjunction with historic well production, or with a mathematical plunger model. Because plunger lift systems typically are inexpensive and easy to install and test, most are evaluated by rules of thumb.

GLR and buildup pressure requirements

The two minimum requirements for plunger lift operation are:

  • Minimum gas-liquid ratio (GLR)
  • Well buildup pressure

Plunger lift operation requires available gas to provide the lifting force, in sufficient quantity per barrel of liquid for a given well depth. The minimum GLR requirement is approximately 400 scf/bbl per 1,000 ft of well depth and is based on the energy stored in a compressed volume of 400 scf of gas expanding under the hydrostatic head of 1 bbl of liquid.[1] One drawback to this rule of thumb is that it does not consider line pressures. Excessively high line pressures relative to buildup pressure might increase the requirement. The rule of thumb also assumes that the gas expansion can be applied from a large open annulus without restriction, but slimhole wells and wells with packers that require gas to travel through the reservoir or through small perforations in the tubing will cause a greater restriction and energy loss, which increase the minimum GLR requirement to as much as 800 to 1,200 scf/bbl per 1,000 ft.

Well buildup pressure is the bottomhole pressure just before the plunger begins its ascent (equivalent to surface casing pressure in a well with an open annulus). In practice, the minimum shut-in pressure requirement for plunger lift is equivalent to one and a half times the maximum sales-line pressure, although the actual requirement might be higher. This rule of thumb works well in intermediate-depth wells (2,000 to 8,000 ft) with slug sizes of 0.1 to 0.5 bbl/cycle. It does not apply reliably, however, to higher liquid volumes, deeper wells (because of increasing friction), and excessive pressure restrictions at the surface or in the wellbore.

An improved rule of thumb for minimum pressure is that a well can lift a slug of liquid when the slug hydrostatic pressure (phs) equals 50 to 60% of the difference between shut-in casing pressure (pcs) and maximum sales-line pressure:

  ........................(1a)

or

  ........................(1b)

This rule of thumb accounts for liquid production, can be used for wells with higher liquid production that require slug sizes of more than 1 to 2 bbl/cycle, and is regarded as a conservative estimate of minimum pressure requirements. To use Eqs. 1a and 1b, first estimate the total liquid production on plunger lift and number of cycles possible per day. Then, determine the amount of liquid that can be lifted per cycle. Use the well tubing size to convert that volume of liquid per cycle into the slug hydrostatic pressure, and use the equations to estimate required casing pressure to operate the system (see example below).

A well that does not meet minimum GLR and pressure requirements still could be plunger lifted with the addition of an external gas source. At this point, design becomes more a matter of the economics of providing the added gas to the well at desired pressures. Several papers in the literature discuss adding makeup gas to a plunger installation through existing gas lift operations, installing a field gas supply system, or using wellhead compression. [2][3][4][5][6][7][8][9]

Estimating production rates

The simplest and sometimes most accurate method of determining production increases from plunger lift is decline-curve analysis[1] (Fig. 1). Gas and oil reservoirs typically have predictable declines, either exponential or hyperbolic. Initial production rates usually are high enough to produce the well above critical rates (unloaded) and establish a decline curve. When liquid loading occurs, a marked decrease and deviation from normal decline can be seen. Unloading the well with plunger lift can re-establish a normal decline. Production increases from plunger lift will be somewhere between the rates of the well when it started loading and the rate of an extended decline curve to the present time. Ideally, decline curves would be used with critical-velocity curves to predetermine when plunger lift should be installed. This would enable plunger lift to maintain production on a steady decline and to never allow the well to begin loading.

  • Fig. 1—Effects of plunger lift on a typical gas-well production decline. (Modified from Ferguson and Beauregard.)[1]

Another method for estimating production is to build an inflow performance (IP) curve on the basis of the backpressure equation (Fig. 2).[10][11][12][13] This is especially helpful if the well has an open annulus and is flowing up the tubing, and if the casing pressure is known. The casing pressure closely approximates bottomhole pressure. Build the IP curve on the basis of:

  • Estimated reservoir pressure
  • Casing pressure
  • Current flow rate

  • Fig. 2—Inflow-performance-relationship analysis for estimating plunger-lift performance. Chart shows production increase resulting from reducing liquid hydrostatic pressure with a plunger-lift system. (After Vogel[12] and Mishra and Caudle[13].)

Because the job of the plunger lift is to lower the bottomhole pressure by removing liquids, estimate the bottomhole pressure with no liquids. Use this new pressure to estimate a production rate with lower bottomhole pressures.

Models

Plunger lift models are based on the sum of forces acting on the plunger while it lifts a liquid slug up the tubing (Fig. 3). These forces at any given point in the tubing are:

  • Fig. 3—Plunger force balance. (Based on Lea.)[14]

Stored casing pressure freely acting on the cross section of the plunger.

Stored reservoir pressure acting on the cross section of the plunger, based on inflow performance.

  • Weight of the fluid.
  • Weight of the plunger.
  • Friction of the fluid with the tubing.
  • Friction of the plunger with the tubing.
  • Gas friction in the tubing.
  • Gas slippage upward past the plunger.
  • Liquid slippage downward past the plunger.
  • Surface pressure (line pressure and restrictions) acting against the plunger travel.

Several publications have dealt with this approach. Beeson et al.Cite error: Invalid <ref> tag; name cannot be a simple integer. Use a descriptive title [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16] [17] </references>

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Plunger lift

Plunger lift applications

Plunger design considerations and selection

Plunger lift installation and maintenance

PEH:Plunger Lift

  1. ↑ 1.0 1.1 1.2 Cite error: Invalid <ref> tag; no text was provided for refs named r1
  2. ↑ 2.0 2.1 Christian, J., Lea, J.F., and Bishop, R. 1995. Plunger Lift Comes of Age. World Oil (November): 43.
  3. ↑ 3.0 3.1 Beeson, C.M., Knox, D.G., and Stoddard, J.H. 1955. Plunger Lift Correlation Equations And Nomographs. Presented at the Fall Meeting of the Petroleum Branch of AIME, New Orleans, Louisiana, 2-5 October. http://dx.doi.org/10.2118/501-g.
  4. ↑ 4.0 4.1 Foss, D.L. and Gaul, R.B. 1965. Plunger Lift Performance Criteria with Operating Experience—Ventura Avenue Field. Drilling and Production Practices, 124-140. Dallas, Texas: API.
  5. ↑ 5.0 5.1 Abercrombie, B. 1980. Plunger Lift. In The Technology of Artificial Lift Methods, ed. K.E. Brown, Vol. 2b, 483-518. Tulsa, Oklahoma: PennWell Publishing Co.
  6. ↑ 6.0 6.1 Hall, J.C. and Bell, B. 2001. Plunger Lift By Side String Injection. Proc., Forty-Eighth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 17–18..
  7. ↑ 7.0 7.1 Morrow, S.J. Jr. and Aversante, O.L. 1995. Plunger Lift: Gas Assisted. Proc., Forty-Second Annual Southwestern Petroleum Short Course, Lubbock, Texas, 195–201.
  8. ↑ 8.0 8.1 White, G.W. 1982. Combine Gas Lift, Plungers to Increase Production Rate. World Oil (November): 69.
  9. ↑ 9.0 9.1 Phillips, D.H. and Listiak, S.D. 1996. Plunger Lift With Wellhead Compression Boosts Gas Well Production. World Oil (October) 96.
  10. ↑ 10.0 10.1 Lea Jr., J.F. and Tighe, R.E. 1983. Gas Well Operation With Liquid Production. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 27 February-1 March 1983. SPE-11583-MS. http://dx.doi.org/10.2118/11583-MS.
  11. ↑ 11.0 11.1 Phillips, D.H. and Listiak, S.D. 1998. How to Optimize Production from Plunger Lift Systems. World Oil (May): 110.
  12. ↑ 12.0 12.1 12.2 Vogel, J.V. 1968. Inflow Performance Relationships for Solution-Gas Drive Wells. J Pet Technol 20 (1): 83-92. http://dx.doi.org/10.2118/1476-PA.
  13. ↑ 13.0 13.1 13.2 Mishra, S. and Caudle, B.H. 1984. A Simplified Procedure for Gas Deliverability Calculations Using Dimensionless IPR Curves. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 16-19 September 1984. SPE-13231-MS. http://dx.doi.org/10.2118/13231-MS.
  14. ↑ 14.0 14.1 Lea, J.F. 1982. Dynamic Analysis of Plunger Lift Operations. J Pet Technol 34 (11): 2617-2629. SPE-10253-PA. http://dx.doi.org/10.2118/10253-PA.
  15. ↑ Mower, L.N., Lea, J.F., E., B. et al. 1985. Defining the Characteristics and Performance of Gas-Lift Plungers. Presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22-26 September 1985. SPE-14344-MS. http://dx.doi.org/10.2118/14344-MS.
  16. ↑ Rosina, L. 1983. A Study of Plunger Lift Dynamics. MS Thesis, University of Tulsa, Tulsa.
  17. ↑ Lea, J.F. 1999. Plunger Lift vs. Velocity Strings. Paper presented at the 1999 Energy Sources Technology Conference & Exhibition, Houston, 1–2 February.
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