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Artificial lift selection methods

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With a wide range of artificial lift systems available, it is important to choose the best method for the well, considering its location, depth, estimated production, reservoir properties, and other factors. This page reviews some of the methods available for selecting the appropriate artificial lift method for the situation. Often a combination of these methods may be used -- one to screen candidate systems, then one for selection. Some of the following discussion is after material from Lea and Patterson[1] and Lea and Nickens[2].

Consideration of depth/rate system capabilities

One simple selection or elimination method is the use of charts that show the range of depth and rate in which particular lift types can function. One example is a chart from Blais[3]. Figs. 1 and 2 are slightly altered versions of information from a presentation by Weatherford Artificial Lift Systems[4] and are probably more accurate because they are more recent. Minimums for method applications are not shown in the charts from this presentation[4]. The charts are approximate for initial selection possibilities, as any simplified charts such as these would be. Particular well conditions, such as high viscosity or sand production, may lead to the selection of a lift method that is not initially indicated by the charts. Specific designs are recommended for specific well conditions to more accurately determine the rates possible from given depths.

The depth-rate charts show how hydraulic systems can pump from the greatest depths, because of the U-tube balancing of produced fluid pressures with the hydraulic fluid pressure. Gas lift is somewhat depth limited, primarily from compressor pressures required, but has a wide range of production capacity. Beam pump produces more from shallower depths and less from deeper depths because of increasing rod weight and stretch as depth increases. Electric submersible pumps (ESPs) are depth limited because of burst limitations on housings and energy considerations for long cables, but can produce large production rates. Plunger lift is for low liquid rates, although some wells can produce more than 300 B/D. Plunger lift is not particularly depth limited because of the increased energy storage in the casing annulus as depth increases. Along with advantage/disadvantage lists, the depth-rate charts are tools for artificial lift selection or quick elimination of possibilities. NOTE: The depth-rate curves are only a relative comparison of the different lift forms and not absolutes. For example, a jet pump has been used to produce 25,000 bpd from 5000 feet.

Screening by advantages and disadvantages

The discussion of each major artificial lift system includes advantages and disadvantages, more detailed listings are available from various sources. Neely[5] contains a brief summary of advantages, disadvantages, and selection criteria for various artificial lift systems presented by experts in a forum discussion.

Clegg, et al.[6] provides the most extensive and useful listing of the various advantages and disadvantages of lift systems under a broad range of categories. Some of the information is open to interpretation, but, in general, it is the best list of artificial lift advantages and disadvantages available at this time. The information in the tables from Clegg, et al.[6] is a very useful tool for artificial lift selection.

Design considerations and overall comparisons of artificial lift list was originally developed using the information in the PEH selection tables from Clegg, et al.[6] Some of the details within this page have been updated, but the majority of the work is from the original authors. This information is used for a preliminary look at some operation details and capabilities for artificial lift. Much of the selection process can be accomplished with depth-rate charts[3][4] and this extensive set of artificial lift capabilities.[6] Very severe conditions and special conditions can require further study. Also, a quantitative economic assessment is not possible with the charts and tables.

Use of expert programs

“Expert” programs, or computerized artificial lift selection programs, are more advanced than a simple list of advantages and disadvantages and depth-rate charts. These programs include rules and logic that branch to select the best artificial lift system as a function of user input of well and operating conditions. Several authors[7][8][9] deal with expert systems for the selection of artificial lift systems. NOTE: These programs are based on the assumptions that the user inputs and operational evaluations of the different forms of lift are up-to-date and valid. As this is frequently not the case, the user is cautioned in the use of the results until the inputs and evaluations can be verified.

Espin, et al.[7] describes an expert system covering a variety of artificial lift methods. The program contains three modules:

  • Module 1 is an expert module that includes a knowledge base structured from human expertise, theoretical written knowledge, and rule-of-thumb calculations. It ranks the methods and also issues warnings, some of which may rule out high-ranked methods.
  • Module 2 incorporates simulation design and facility-component specification programs for all artificial lift methods considered. It contains a suite of design methods with advice to follow from Module 1.
  • Module 3 is an economics evaluation module that includes a cost database and cost-analysis programs to calculate lift profitability. It uses the designs and expected production rate to calculate profitability with evaluation parameters such as NPV and rate of return. Module 3 also includes investment costs and repair and maintenance costs.

The rules in Espin, et al.[7] take the form of “if (condition), then (type of process).” For each artificial lift method, a suitability coefficient (SC) from –1 to +1 is defined for the given condition, where SC = –1 eliminates the process from further consideration, and SC = +1 indicates a process well suited to the given condition. For example, “if (Pump Temperature > 275°F), then (ESP) –1” defines a rule that eliminates ESPs if the pump temperature exceeds 275°F. Rules such as this require constant updating because equipment capabilities change with time.

Intermediate values can be used to refine the system, and methods are presented for combining the coefficients into a single coefficient. The program can combine the suitability coefficients into one value for overall evaluation. Espin, et al.[7] also gives other details for knowledge representation and technical and economic evaluation.

Heinze, et al.[8] describes an artificial lift program that decides, from the user’s input, which system among gas lift, hydraulic, sucker rod, or ESP pumping systems is best for the particular conditions. The stored knowledge base and user input allow the program to rank the most appropriate artificial lift method for the particular conditions, such as:

  • Sand
  • Paraffin
  • Crooked hole
  • Corrosion
  • Small casing
  • Flexibility
  • Scale

Valentin and Hoffman[9] describes another encompassing expert system. It describes the optimum pumping-unit search program, which consists of:

  • Knowledge base containing the complete set of specific information on the domain of expertise
  • Inference engine with the data and heuristics of the knowledge base to solve the problem
  • Interactive modules enabling very simple use of the expert system

Another interesting feature[9] is the presentation of economic data for annual costs to be incurred by various artificial lift systems. The costs are presented in bar graphs that show how the component costs would occur above the wellhead or subsurface. For instance, much of the possible recurring costs for ESPs can be from the subsurface; whereas, for gas lift, other than wireline work, larger repair and servicing costs associated with compressors would be taken care of on the surface.

Selection by net-present-value comparison

A more thorough selection technique depends on the lifetime economics of the available artificial lift methods. The economics, in turn, depend on:

  • Failure rates of the system components
  • Fuel costs
  • Maintenance costs
  • Inflation rates
  • Anticipated revenue from produced oil and gas
  • Other factors that may vary from system to system

There are several studies[10][11][12] that follow economically guided selection techniques. Many authors[13][14][15][16][17][18][19][20][21] discuss artificial lift in general, the efficiency of lift methods, selection techniques, and limitations on various artificial lift systems.

Economic analysis of artificial lift selection

An enhanced method of analysis similar to the NPV comparison method is available from Kol and Lea[12].

To use the NPV comparison method, the user must have a good idea of the associated costs for each system. This requires that the user evaluate each system carefully for the particular well and be aware of the advantages and disadvantages of each method and any additional equipment (i.e., additional costs) that may be required. Because energy costs are part of the NPV analysis, a design for each feasible method must be determined before running the economic analysis to better determine the efficiency of a particular installation. These factors force the consideration of all the applicable artificial lift methods to generate the necessary information for the NPV analysis.

Example 1

Consider a vertical well with the characteristics given in Table 6. To calculate the expected life of the well, reasonable reservoir production estimates must be supplied. For this example, assume that all artificial lift methods (ESP, gas lift, beam pump, and hydraulics) will be considered and initially will produce at the rate of 1,000 B/D with 50% water cut and 400 gas/oil ratio (GOR). After a 1-year constant rate period, oil production is assumed to decline by 20% per year. The overall rate (oil+water+gas) will remain constant. The water cut will increase after the first year. The rate of 10 BOPD is selected as the end of the evaluation period, but the economic limit will be reached long before this rate occurs.

Table 7 contains the values needed for the NPV analysis that are specific to each lift method. The sources of all these values are typical of each of the methods. The direct operating expenses could be manpower to visit and monitor wells, site maintenance, overhead charged to field, etc. The direct operating expenses per barrel could be water disposal charges, injection of corrosion inhibitor or scale treatments, etc. The average pulling and repair charges are average charges for pulling because of failed or worn equipment. An analog field, if available, can be a source of such data.

The actual initial production rate may differ for each method, but for comparison and to illustrate concepts, an initial total rate of 1,000 B/D for each method is assumed. In this case, it is possible to accomplish this rate with all the methods considered. Different rates possibly would require different production facilities and different initial costs. Thus, each method should be optimized and the associated required costs included in the economic analysis.

Solution. Fig. 3 plots the summary of the cumulative present value profit (PVP) income. The maximum in each curve occurs at the time the project should be ended, because beyond that, the project would be operating at a loss. The maximum PVP for each lift method examined is indicated in Fig. 3, and the results are tabulated in Table 8.

Again, the results depend on the particular cost-related data for each method. For this case, however, the rod pump or ESP would be the most economical method. Because rod pump and ESP are approximately the same economically, the decision then would fall on vendor availability, service expected, where equipment can be warehoused, and other factors. Gas lift and jet hydraulic pump would not be recommended for this case according to the results obtained. Different field conditions could easily change the lift system selected.

Sample run-life information

As Example 1 shows, one of the factors to consider in artificial lift selection is the failure rates for the various artificial lift systems or the individual components of the systems. Fig. 4 shows failure rates from a group of 532 beam-pumped wells over several years. The costs for downhole lift replacement and servicing are shown.

Fig. 5 shows a breakdown of the major causes for failure of the beam pump systems that went into the accumulation of the failure-rate data in Fig. 4. If a lift selection study is needed, field data from a field of similar conditions would be very helpful in evaluating beam pumping as a candidate and in comparing beam pump with other artificial lift methods. A breakdown of failing components for any lift method is a good evaluation tool.

Fig. 6 shows ESP run lives for various fields. These data were collected and presented in Kol and Lea[12] for a study of artificial lift feasibility and methods to use in a Siberian location. Targets and downside potentials were established for this study as shown in Fig. 6.

Lea and Patterson[1] and Lea and Nickens[2] include various run-life information and selection criteria. Swan Hills (Alberta), Milne Point (Alaska), the Amoco Congo field, the THUMS East Wilmington field, the Amoco North Sea field, and the Montrose field were used to help predict run lives for the Priobskoye field in Siberia. Kol and Lea[12] contains additional information on the conditions in these fields. Fig. 6 shows the “learning curve” aspect of these field developments. The initial learning curve is very costly, showing the time required to come from low run lives before failures up to reasonable operational lives for the ESP installations. This learning curve can be eliminated with careful planning, reference to previous projects, and implementation of early good practices in the development.

From Lea and Nickens[2], Table 9 shows downhole hydraulic pump lives for a collection of fields. Lea and Nickens2 presents the conditions for these fields. The average life of the (piston) pumps is approximately 114 days. Target, downside, and industry data is summarized for the downhole hydraulic pumps. No data are presented for gas-lift-system costs and failures expected. Initial compressor costs are high, but after installation, most of the expense is wireline work unless a major compressor fix or addition is needed. Cost examples for other systems are not shown here.

The data shown are for particular fields and may or may not be indicative of what might be undertaken in the future. Again, the run lives to failure data cases for the various artificial lift systems presented are example cases and are not intended for general use.


  1. 1.0 1.1 Lea, J.F. and Patterson, J. 1997. Selection Considerations for Artificial Lift. Presented at the 1997 Artificial Lift Equipment Forum, Dubai.
  2. 2.0 2.1 2.2 Lea, J.F. and Nickens, H.V. 1999. Selection of Artificial Lift. Presented at the SPE Mid-Continent Operations Symposium, Oklahoma City, Oklahoma, 28-31 March 1999. SPE-52157-MS.
  3. 3.0 3.1 Blais, R. 1986. Artificial Lift Methods. Tulsa, Oklahoma: PennWell Publishing Co.
  4. 4.0 4.1 4.2 4.3 4.4 5 Steps to Artificial Lift Optimization. Commercial presentation, Weatherford Artificial Lift Systems, Houston, May.
  5. Neely, B., Gipson, F., Clegg, J. et al. 1981. Selection of Artificial Lift Method. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4-7 October 1981. SPE-10337-MS.
  6. 6.0 6.1 6.2 6.3 Clegg, J.D., Bucaram, S.M., and Hein, N.W.J. 1993. Recommendations and Comparisons for Selecting Artificial-Lift Methods. J Pet Technol 45 (12): 1128–1167. SPE-24834-PA.
  7. 7.0 7.1 7.2 7.3 Espin, D.A., Gasbarri, S., and Chacin, J.E. 1994. Expert System for Selection of Optimum Artificial Lift Method. Presented at the SPE Latin America/Caribbean Petroleum Engineering Conference, Buenos Aires, Argentina, 27-29 April 1994. SPE-26967-MS.
  8. 8.0 8.1 Heinze, L.R., Thornsberry, K., and Witt, L.D. 1989. AL: An Expert System for Selecting the Optimal Pumping Method. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 13-14 March 1989. SPE-18872-MS.
  9. 9.0 9.1 9.2 Valentin, E.P. and Hoffmann, F.C. 1988. OPUS: An Expert Advisor for Artificial Lift. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 2-5 October 1988. SPE-18184-MS.
  10. Etherton, J.H. and Thornton, P. 1988. A Case Study of the Selection Procedure for Artificial Lift in a High Capacity Reservoir. Presented at the 1988 Annual Meeting of the Southwestern Petroleum Short Course, Lubbock, Texas, 20–21 April.
  11. Smith, G.L. 1977. Lease Operational Study - Gas Lift Vs. Submersible Pump Lift = G.H. Arledge "c" Lease, Scurry, County, Texas. Presented at the SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, 9-12 October 1977. SPE-6852-MS.
  12. 12.0 12.1 12.2 12.3 12.4 Kol, H. and Lea, J.F. 1992. Selection of the Most Effective Artificial Lift System for the Priobskoye Field. 1992 SPE ESP Workshop, Houston, Texas, 26–28 April.
  13. Clegg, J.D. 1991. Artificial Lift Efficiency Depends on Design. American Oil & Gas Reporter (June).
  14. Lea, J.F. 1994-95. Artificial Lift—Operating at Lower Cost. SPE Distinguished Lecturer Presentation.
  15. Clegg, J.D. 1992-93. Artificial Lift: Producing at High Rates. SPE Distinguished Lecturer Presentation.
  16. Johnson, L.D. 1968. Selection of Artificial Lift for a Permian Basin Waterflood. Presented at the 1968 Annual Meeting of the Southwestern Petroleum Short Course, Lubbock, Texas.
  17. Clegg, J.D. 1988. Improved Sucker Rod Pumping Design Calculations. Presented at the 1988 Annual Meeting of the Southwestern Petroleum Short Course, Lubbock, Texas, 20–21 April.
  18. Clegg, J.D. 1989. Another Look at Gas Anchors. Presented at the 1989 Annual Meeting of the Southwestern Petroleum Short Course, Lubbock, Texas, 19–20 April.
  19. Clegg, J.D. 1991. Rod Pumping Selection and Design. Presented at the 1991 Annual Meeting of the Southwestern Petroleum Short Course, Lubbock, Texas, 17–18 April.
  20. Duke, S.E. 1981. Artificial Lift—Which Method Best Fits Your Needs. Presented at the 1981 Annual Meeting of the Southwestern Petroleum Short Course, Lubbock, Texas, 23–24 April.
  21. Bucaram, S.M. and Yeary, B.J. 1987. A Data-Gathering System To Optimize Production Operations: A 14-Year Overview. J Pet Technol 39 (4): 457-462. SPE-13248-PA.

Noteworthy papers in OnePetro

Brown, K.E. 1982. Overview of Artificial Lift Systems. J Pet Technol 34 (10): 2384–2396. SPE-9979-PA.

Meng, H.Z. "Method of Determining Optimum Cost-Effective Free Flowing or Gas Lift Well Production." US Patent 4,442,710 (April 1984).

Hirschfeldt, M. - Martinez, P.- Distel, F. "Artificial-Lift Systems Overview and Evaluation in a Mature Basin: Case Study of Golfo San Jorge." Paper SPE 108054 presented at the SPE LAtin American and Caribbean Petroleum Engineering Conference held in Buenos Aires, April 15-18, 2007.

Takacs, G., Hadi, B. “Latest Technological Advances in Rod Pumping Allow Achieving Efficiencies Higher than with ESP Systems.” J. Canadian Petroleum Technology. April 2011, 53-58.

Brown, K. E., Lea, J. F. “Nodal Systems Analysis of Oil and Gas Wells.” JPT October 1985, 1751-1765.

External links

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See also

Artificial lift


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