T Distinguished

Author Series

Recommendations and Comparisons for Selecting Artificial-Lift Methods

J.D. Clegg, SPE, consultant S.M. Bucaram, SPE, Arco E&P Technology

N.W. Heln Jr., SPE, Conoco Inc.

Summary Selecting the proper artificial-lift method is critical to the long-tenn profitability of most producing oil and gas wells. This paper compares the main selection attributes for the current eight major artificial-lift methods and provides practical guidelines, based on practical and proven technology, on the per­fonnance and operating capabilities of the methods. This paper covers beam pumping, progressing cavity pumping, electric sub­mersible pumping, hydraulic reciprocating pumping, hydraulic jet systems, continuous gas-lift systems, intennittent gas-lift sys­tems, and plunger lift.

Introduction Correct selection of an artificial-lift method is important to the long-tenn profitability of most producing oil wells. Proper artificial­lift method selection also is very important for gas wells that load up with liquid and for coalbed methane wells that must be dewatered. A poor choice can reduce pro­duction and increase operating costs substan­tially. Once a decision has been made on the type of lift to install on a well, it rarely is reviewed to detennine that the method selected was and still is the best choice for existing conditions. In addition, changing the type of lift costs money and implies that the wrong system was selected initially. Although prudent production engineering re­quires continuous review of the perfonnance of the lift method to modify operating pa­rameters or even to evaluate changing the method, once a method is chosen, it usually stays in place.

A starting point in any selection process is to review current practices. Fig. 1 shows a review of about 500,000 U.S. oil wells on artificial lift . This database consists of a wide variety of conditions and a large number of operators. Various types of sucker-rod pumps are used on about 85 % of the wells. Gas lift, mostly continuous flow, comes in a distant second with less than 10% usage. Electric submersible pumps (ESP's) are used

Copyright 1993 Society of Petroleum Engineers

1128

Joe D. Clegg retired from Shell in Houston in 1991. He was involved in a program to protect wells with "low" collapse casing in the Cedar Creek Anticline field and has worked with subsurface safety valves and fire-resistant wellheads. He has written many computer programs and technical papers on gas-lift

Clegg Bucaram design and sucker-rod pumping systems. Clegg was a Distinguished Lecturer during 1984-85, served on the Reprint Series Committee during 1986-87, and is a member of the Editorial Review Committee. A member of the Well Completions Technical Committee for the 1986 Annual Technical Conference and Exhibition, he chaired it for the 1987 meeting. S. Mike Bucaram, senior staff production engineer at Arco E&P Technology in Plano, TX, has experience in production problems and equipment failure control. He previously worked at Batelle Memorial Inst., Sinclair Research, Arco Oil & Gas Research Center, and Arco Production Center. Bucaram, a member of the Editorial Review Committee, holds an MS degree in physics from Texas A&M U. Photo and biographical sketch of N.W. Heln Jr. are unavailable.

on only 4% of the wells. All other lift meth­ods (hydraulic reciprocating pumps, progressing cavity pumps, and plunger lift) represent less than 5 % total usage.

Remember that about 400,000 of these wells are classified as stripper wells that produce < 10 BOPD. When the stripper wells are excluded, the 100,000 or so re­maining U.S. oil wells are relatively high­rate artificially lifted wells. Most of these wells (53%) are gas lifted. About 27% are on rod pumping, 10% are on ESP's, and < 10% are on hydraulic pumps and jets. All other methods total less than 1 %. By far, the majority of offshore gas-lift wells are on continuous gas lift.

Proper selection of the best lift method usually is based on strong opinions. Oper­ating personnel nonnally select the lift method with which they are most familiar. Equipment suppliers or even in-house ex­perts on a specific method usually recom­mend that their favorite method can be made to fit the requirements.

This "force-fit" selection usually results in the extension of the capabilities or oper­ating experience of the selected lift method.

We typically find that improvements made solve a new problem encountered as a result of a poor original choice. Thus, we must es­tablish the nonnal and, more importantly, the practical operating capabilities of the major lift methods.

This paper compares eight major arti­ficial-lift methods (Figs. 2 through 7). Hy­draulic reciprocating and jet pumps are combined in Fig. 5 because their surface re­quirements are comparable; however, they have different downhole designs, applica­tions, and capabilities. Similarly, continuous and intennittent gas lift are combined in Fig. 6.

This work extends the comparisons by Brown et al. 1 The basis of this paper was formulated during discussions at the July 1991 SPE Forum on New Advances in Ar­tificial Lift. Four new lift methods were added: progressing cavity pumping, hydrau­lic jet systems, intermittent gas-lift systems, and plunger lift. This paper significantly ex­pands the number of lift method selection attributes Brown et al. listed: 31 different design and operational attributes are given for new comparisons between all eight tech-

December 1993 • JPf

C-GL 10±% PLNG <1%

PC <1%

ROD 85±%

Fig. 1-Usage in U.S. of different types of artificial· lift methods. (C·Gl = continuous gas liftj PlNG = plunger liftj HP = hydraulic reciprocating pumpsj PC = progressing cavity pumps.)

niques. Each attribute nonnally affects oper­ating costs or production rate, which then affects profitability (see Tables 1 through 3 for details.

We should emphasize that the perform­ance or capability attributes in this paper are based on practical and proven technology, not on manufacturers' claims or limited lab­oratory or field test results. New advances may improve performance of an individual method. Until the advances are proved prac­tical and cost-effective over the long term, they should be viewed as remedies to a par-

ticular problem. Thus, these current attrib­utes can be used to compare and select the "best" lift method for a new installation. Furthennore, we can compare the attributes to determine whether the lift method selected for a well may have been chosen incorrectly.

Discussion Selection of the most appropriate artificial­lift method has to start when the reservoir, drilling, and completion designs and deci­sions are being made. This requires open communication between people in all these

PUMPIN\ UNIT

SHEAVES AND BELTS

PRIME MOVER" \

PRODUCING ZONE

;< m

Fig. 2-Typical sucker·rod/beam pumping system.

JPT • December 1993

CLAMP AND CARRIER BAR o POLISHED ROD

/' ./ STUFFING BOX ./ . FLOW LINE

r'lfL---I-==

TUBING

SUCKER RODS

TUBING ANCHOR

SINKER BARS

PUMP

GAS ANCHOR

"Correct selection of an artificial-lift method is important to the long­term profitability of most producing oil wells."

disciplines. Coupled to this are the produc­tion requirements and limitations in contract deliverables that must be met. Thus, obtain­ing good drill stem test and production rate data is the first step of method selection. The drilling and completion scenarios then have a major impact on determining not only the best lift method but also overall well capa­bility.

The attribute tables were developed to aid in comparisons of all the different produc­tion parameters. These tables were divided into three main areas. The practical capa­bilities should be compared to select the best method for the life of the project.

Table 1 presents the 10 different attributes for design considerations and overall capa­bility comparisons, Table 2 presents the nine different parameters grouped under normal operating considerations, and Table 3 pre­sents the 12 lift method parameters that can present special problems. When selecting the best lift method, all 31 parameters must be considered. However, some items over­ride the obvious choice. For example, lo­cation is a key factor in method selection. Offshore, arctic, and remote areas may justi­fy or require a different method than the combination of all other attributes.

The cost of energy is very important in some locations. In today's restricted U.S. production, overall efficiency and total oper­ating costs are driving a re-examination of the "best" method. Fig. 8 compares the to­tal hydraulic efficiencies of various artificial-lift methods. Only the efficiencies of sucker-rod and progressing cavity pumps typically exceed 50 %. Continuous-flow gas lift has a large range of efficiency depend­ing significantly on gas-injection quantities and depth.

Service and repair of the artificial-lift equipment vary significantly. Such service may be very costly in some locations. For example, repair costs for continuous gas lifts normally are low; however, the system ef­ficiency also nonnally is low. This can re-

1129

TRANSFORMERS

'ol'l:i"---Stuffing Box "c:::::L==D PRODUCTION

PRIMARY CABLE CASING

DRAIN VALVE (OPTIONAL)

CHECK VALVE (OPTIONAL)

TUBING --;'UC:Ker Rods MOTOR FLAT SPLICE

MOTOR FLAT CABLE

Rotor

Il~'-'--"--- Stator

POTHEAD --u,---"

MOTOR -----r.cdIl

PUMP

PUMP INTAKE

SEAL

Fig. 3-Typical progressing cavity pumping system. Fig. 4-Typical ESP system.

"Selection of the most appropriate artificial-lift method has to start when the reservoir, drilling, and completion designs and decisions are being made."

Fig. 5-Typical hydraulic and jet pumping

suIt in high energy and operating costs, which limit the return on investment for this technique. These factors and those discussed in Tables 1 through 3 must be considered to determine the final lift method. Thus, the selection of any method needs a "full-cycle" economic analysis where total costs for the expected life of the installation are con­sidered.

An economic analysis can be relatively straightforward but requires various produc­tion and cost data and several assumptions. The capital cost of the initial artificial-lift installation can be determined quickly and accurately, but it is only one of the many factors needed. Prediction of production rate over the life of the well for the specific lift method also is required. Normally, a flat life

(A) CONTINUOUS GAS LIFT PERFORMANCE

followed by an exponential decline is ade­quate. An estimate of future oil and gas prices also is essential; however, making these predictions is very difficult.

The most difficult part of the analysis is obtaining good operating cost data on the lift method over the life of the well. Data from similar wells should be used if possible. With those data, plus predictions on salvage value, inflation, taxes, etc., the present value profit of the specific artificial-lift method can be found. Fig. 9 is a graph of production rate vs. time for a typical land installation. The chart shows revenue received vs. capi­tal and operating expenses. As Fig. 9 shows, revenue and operating expenses far exceed the initial installation capital cost. The figure also shows that it might be better to spend

(8) INTERMITTENT GAS LIFT PERFORMANCE

system configuration. Fig. 6-Comparison of continuous vs. intermittent gas·lift system.

1130 December 1993 • JPf

BUMP1:R SPRING

CONTROL GAS

CHOKE

CONTROLLER --CJ

8 ~D0

- GAS L==========-+..J SUPPLY

.......... CASING PRESSURE TO SEPARATOR

PLUNGER

I~-r-- FOOTPIECE SPRING

STANDING VALVE

Fig. 7-Typical pressure·controlled plunger·lift system.

extra money to select the best equipment from the start, especially if doing so results in increased revenue and decreased operat­ing costs over the life of the installation.

Review and Conclusions 1. Each artificial-lift method has different

attributes that must be evaluated for the spe­cific installation over the fulllifecycle. The

most important attribute is the ability to produce the well at the desired capacity or rate over the required time. The next most important attribute is relatively low operat­ing costs over the life of the well.

2. The attributes of artificial-lift methods are relative to each otht;r and can be specific only for a particular production installation. For a specific installation, the economic con-

sequences of each applicable attribute need to be estimated and compared to select the most appropriate lift method.

3. Location has an overwhelming effect on capital and operating costs and on pro­duction rates. The alternatives may change significantly, depending on location. Remote locations call for simple operation, long run time, and ease of service and repair. Arctic locations also require simplicity and methods heating equipment even during shutdown. Offshore locations require long operating life and minimum pulling costs.

4. Sucker-rod (beam) pumping should be the standard consideration if operations are on land. If the location is offshore, then gas lift should be the standard. Experience has shown that such choices normally result in optimum production and minimum costs. Thus, these choices should be the standard for comparison with other lift methods. The other methods should be selected only where there are definite installation and operational advantages.

5. Once a method is selected, there still needs to be refinement and proper engineer­ing to design and select all the equipment necessary to make this method work for the application. Improper design and operation of the "best" selected method will always "prove" that the selection was not the best in the first place.

Thus, once the method is selected, oper­ations personnel should be given the neces­sary information and training to' make the installation economically successful.

6. The limits and relative comparisons listed in Tables 1 through 3 are based on our experience and are considered conventional wisdom. Most of these attributes are sub­ject to change with improVed technology. In addition, others' experience may alter some of the limits. Thus, we request that new data be published that may alter these attributes or that will improve our knowl­edge of artificial-lift selection.

Acknowledgments We thank our management for allowing this work to be done and the comparisons pub-

(To Page 1163)

80 TYPICAL GOOD MAJOR CONTRIBUTING

70

I 60

I 'i ~50 -

I >- ' U ffi40-

I U ii:30

I I u.. w

20

10 • 0 ROD PC ESP HP JET C-GL I-GL

Fig. a-Hydraulic horsepower efficiency comparisons for the major artificial-lift methods (excluding plunger lift).

JPI' • December 1993

LAND WELL FACTORS TO PVP 200 , + WATER

is a. 100

~ 9 w l-e a:

5 10 15 20 TIME ·(YEARS)

PVP > $2 MILLION

Fig. 9-Artlflclal-lift full-life-cycle economic evaluation (PVP = present value profit).

1131

Recommendations and .. , (From Page 1131)

TABLE 1-ARTIFICIAL-LiFT DESIGN CONSIDERATIONS AND OVERALL COMPARISONS

Hydraulic Gas Lift

Sucker Rod Progressing Reciprocating Hydraulic Continuous Pumping Cavity Pumping ESP's Pumping Jet Systems Flow Intermittent

Capital cost Low to moderate: Low: increases Relatively low Varies but often Competitive with Well equipment Same as increases with with depth and capital cost if competitive with sucker-rod costs low but continuous flow depth and larger rates. commercial rod pumps. pump. Cost lines and gas lift. larger units. electric power Multiple well, increases compression

available. Costs central systems with higher costs may be increase as reduce cost per horsepower. high. Central horsepower well but is more compression increases. complicated. system reduces

cost per well. Downhole Reasonably good Good design Requires proper Proper pump Requires Good valve Unload to bottom equipment rod design and and operating cable in addition sizing and computer design design and with gas lift

operating practices to motor, pumps, operating programs for spacing essential. valves; consider practices needed. May seals, etc. Good practices sizing. Tolerant Moderate cost for chamber for high needed. Data have problems design plus good essential. of moderate well equipment PI and low BHP bank of rod and with selection operating Requires power- solids in power (valves and wells. pump failures of appropriate practices fluid conductor. fluid. No moving mandrels). Choice beneficial. Good stator elastomer. essential. Free pump and parts in pump; of wireline-selection, closed power- long service life; retrievable or operating, and fluid option. simple repair conventional repair practices procedures. valves. needed for rods and pumps.

Efficiency (output Excellent total Excellent: may Good for high Fair to good: not Fair to poor. Fair: increases for Poor: normally hydraulic system exceed rod rate wells but as good as rod Maximum wells that require requires a high horsepower efficiency. Full- pumps for ideal decreases pumping owing efficiency only small injection injection gas divided by input pump fillage cases. Reported significantly for to G LR, friction, 30%. Heavily GLR's. Low for volume/barrel hydraulic efficiency system efficiency < 1 ,000 BFPD. and pump wear. influenced by wells requiring fluid. Typical lift horsepower). typically about 50% to 70%. Typically total Efficiencies power fluid plus high GLR's. efficiency is 5%

50 to 60%- More operating system efficiency range from 30% production Typical to 10%; feasible if well is data needed. is about 50% for to 40% with gradient. Typical efficiencies of improved with not overpumped. high rate well, GLR>100; may operating 20% but range plungers.

but for < 1,000 be higher with efficiencies of from 5% to 30%. B/D, efficiency lower GLR. 10% to 20%. typicaly is < 40%.

Flexibility Excellent: can Fair: can alter Poor: pumps Good/excellent: Good to excellent: Excellent: gas Good: must adjust alter stroke speed. Hydraulic usually run at a Can vary power power fluid rate injection rate injection time speed and unit provides fixed speed. fluid rate and and pressure varied to change and cycles length, plunger additional Requires careful speed of adjusts the rates. Tubing frequently. size, and .run flexibility but at sizing. VSD downhole pump. production rate needs to be time to control added cost. provides more Numerous pump and lift capacity. sized correctly. production rate. flexibility but sizes and Selection of

added costs. pump/engine throat and Time cycling ratios adapt to nozzle sizes normally avoided. production and extend range of Must size pump depth needs. volume and properly. capacity.

Miscellaneous Stuffing box May have limited Requires a highly Power fluid solids More tolerant of A highly reliable Labor-intensive to problems leakage may be service in some reliable electric control essential. power fluid compressor with keep fine tuned;

messy and a areas. Because power system. Need 15 ppm of solids; 200 ppm 95 + % run time otherwise, poor potential hazard. this is a newer Method sensitive 15-/Lm particle of 25-/Lm required. Gas performance. (Antipollution method, field to rate changes. size maximum to particles must be Maintaining stuffing boxes knowledge and avoid excessive acceptable. dehydrated steady gas flow are available.) experience are engine wear. Diluents may properly to avoid often causes

limited. Must add be added if gas freezing. injection gas surfactant to a required. Power measurement water power fluid water (fresh, and operating for lubricity. produced, or problems. Triplex plunger seawater) leakage control acceptable. required.

Operating costs Very low for Potentially low, Varies: if Often higher than Higher power Well costs low. Same as shallow to but short run life horsepower is rod P)J mps even cost owing to Compression continuous-flow medium depth on stator or rotor high, energy for free systems. horsepower costs vary gas lift. ( < 7500 ft) land frequently costs are high. Short run life requirement. depending on locations with reported. High pulling increases total Low pump fuel cost and low production costs result from operating costs. maintenance compressor «400 BFPD). short run life. cost typical with maintenance.

Often repair properly sized Key is to inject costs are high. throat and as deeply as

nozzle. possible with optimum GLR.

Reliability Excellent: run Good: normally Varies: excellent Good with a Good with proper Excellent if Excellent if there time efficiency overpumping and for ideal lift correctly designed throat and compression is an adequate >95% if good lack of experience cases; poor for and operated nozzle sizing for system properly supply of operating practiCes decreases run problem areas. system. Problems the operating designed and injection gas and are followed and time. Very sensitive to or changing well conditions. Must maintained. an adequate low-if corrosion, wax, operating conditions reduce avoid operating pressure storage asphaltenes, temperatures downhole pump in cavitation volume for solids, deviations, and electrical reliability. range of jet injection gas. etc., are malfunctions. Frequent pump throat; System must be controlled. downtime results related to pump designed for the

from operational intake pressure. unsteady gas problems. More problems if flow rates.

pressures > 4,000 psig.

Salvage value Excellent: easily Fair/poor: easily Fair: some trade Fair market for Good: easily Fair: some market Same as moved and good moved and some in value. Poor triplex pumps; moved. Some for good used continuous-flow market for used current market open market good value for trade in value. compressors and gas lift. equipment. for used values. wellsite system Fair market for some trade in

equipment. that can be triplex pump. value for mandrels moved easily. arid valves.

JPT • December 1993

Plunger Lift

Very low; only low-cost well equipment if no compressor required.

Operating practices have to be tailored to each well for optimization. Some problem with sticking plungers.

Excellent for flowing wells. No input energy required because it uses the energy of the well. Good even when small supplementary gas is added.

Good for low-volume wells. Can adjust injection time and frequency.

Plunger hangup or sticking may be a major problem.

Usually very low.

Good if well production is stable.

Fair: some trade in value. Poor open market value.

1163

TABLE 1-ARTIFICIAL-LiFT DESIGN CONSIDERATIONS AND OVERALL COMPARISONS (continued)

System (total)

Usage/outlook

Sucker Rod Pumping

Straightforward and basic procedures to design, install, and operate' following API specifications and recommended practices. Each well is an individual system.

Excellent: used on about 85% of U.S. artificial·lift wells. The normal standard artificial·lift method.

Progressing Ca~ity Pumping

Simple to install and operate. Limited proven design, installation, and operating speCifications and procedures. Each well is an individual system.

Limited to relatively shallow wells with low rates. Used on less than 0.5% of U.S. lifted wells. Used primarily on gas· well dewatering.

lished. We also thank the individuals who contributed to the practical comments related to this paper.

Reference I. Brown, K.E.: The Technology of Artifidal Lift,

Petroleum Publishing Co., Tulsa (1980).

General Overview

Brown, K.E.: "Overview of Artificial Lift Sys­tem," JPT (Oct. 1982) 2384.

Bucaram, S.M. and Yearly, B.J.: "A Data­Gathering System To Optimize Producing Op­erations: A 14-Year Review," JPT(AprilI987) 457; Trans., AIME, 287.

Clegg, J.D.: "High-Rate Artificial Lift," JPT (March 1988) 277.

Neely, A.B. et al.: "Selection of Artificial Lift Method," paper SPE 10337 presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 26-29.

Beam Rod Pumping

Clegg, J.D.: "Another Look at Gas Anchors," Proc., 36th Annual Meeting of the South­western Petroleum Short Course, Lubbock (April 1989).

Clegg, J.D.: "Rod Pumping Selection and De­sign," Proc., 38th Annual Meeting of the Southwestern Petroleum Short Course, Lub­bock (April 1991) 274.

Foley, W.L. and Savinos, J.G.: "Expert Adviser Program for Rod Pumping," JPT (April 1989) 394.

Gault, R.H.: "Designing a Sucker-Rod Pumping System for Maximum Efficiency," JPT (Nov. , 1987) 284.

Gibbs, S.G.: "A General Method for Predicting Rod Pumping System Performance," paper SPE 6850 presented at the 1977 SPE Annual Technical Conference and Exhibition, Denver, Oct. 9-12.

1164

ESP's

Fairly simple to design but requires good rate data. System not forgiving. Requires excellent operating practices. Follow API recommended practices in design, testing, and operation. Typically each well is an individual producer using a common electric system.

An excellent high rate artificial lift system. Best suited for < 200°F and >1,000 BFPD rates. Most often used on high water cut wells. Used on about 4% of U.S. lifted wells.

Hydraulic ReCiprocating

Pumping

Simple manual or computer design typically used. Free pump easily retrieved for servicing. Individual well unit very flexible but extra cost. Requires attention. Central plant more complex; usually results in test and treatment problems.

Often used as a default artificial·lift well system. Flexible operation; wide rate range; suitable for relatively deep, high·volume, high·temperature, deviated oil wells. Used on < 2% of U.S. lifted wells.

Hydraulic Jet Systems

Computer design program typically used for design. Basic operating procedures needed for downhole pump and wellsite unit. Free pump easily retrieved for on site repair or replacement. Down hole jet often requires trial and error to arrive at besVoptimum jet.

Good for higher· volume wells requiring flexible operation. System will tolerate wide depth ranges, high temperatures, corrosive fluids, high GOR, and significant sand production. Used on < IDA> of U.S. lifted wells. Sometimes used to test wells that will not flow offshore.

Gibbs, S.G.: "Predicting the Behavior of Sucker­Rod Pumping Systems," JPT (July 1963) 769; Trans., AIME, 228.

Gibbs, S.G.: "A Review of Methods for Design & Analysis of Rod Pumping Installations, " JPT (Dec. 1982) 2931.

Gipson, F.W. and Swaim, H.W.: "The Beam Pumping Design Chain," Proc., 31st Annual Meeting of Southwestern Petroleum Short Course," (April 1984) 296.

Kramer, M.J.C., Martin, J.D., and Neely, A.B.: "On-Site Analysis of Sucker-Rod Pumping Sys­tems Wells," paper SPE 11037 presented at the 1982 SPE Annual Technical Conference and Exhibitions, New Orleans, Sept. 26-29.

Lea, J.F. and Brown, J.F.: "Dynamic Measure­ment of Beam Pump Parameters," SPEPE (Feb. 1992) 113; Trans., AIME, 293.

NACE Standard MR-OI-76, Material Require­ments: Metallic Materials for Sucker Rod Pwnps for Hydrogen Sulfide Environments: Selection of Optimum Type Pump, Appendix B, NACE, Houston.

Neely, A.B. and Tolbert, H.O.: "Experience With Pump-Off Control in the Permian Basin," JPT (May 1988) 645.

Schmidt, Z. and Doty, D.R.: "System Analysis for Sucker-Rod Pumping," SPEPE (May 1989) 125.

Swaim, H.W. and Hein, N.W.: "Surface Dyna­mometer Card Interpretation: A Beam Pump­ing Problem Solving Tool," Southwestern Petroleum Short Course, Lubbock (April 22-23, 1987).

Progressing Cavity Pumps Gaymard, B. et al.: "The Progressing Cavity

Pump in Europe: Results and New Develop­ments, " Proc., Offshore South East Asia Con­ference, Singapore (Feb. 2-5, 1988) 444.

Saveth, KJ. and Klein, S. T.: "The Progressing Cavity Pump: Principle and Capabilities," paper SPE 18873 presented at the 1989 SPE Production Operations Symposium, Oklahoma City, March 13-14.

Gas Lift

Continuous Flow

An adequate volume, high· pressure, dry, noncorrosive and clean gas supply source is needed throughout the entire life. System approach needed. Low backpressure beneficial. Good data needed for valve design and spacing. API specifications and deSign/operating recommended practices should be followed.

Good, flexible, high-rate artificial·lift system for wells with high bottomhole pressures. Most like a flowing well. Used on about 10% of U.S. lifted wells, mostly offshore.

Gas Lift

Intermittent

Same as continuous·flow gas lift.

Often used as a default artificial lift method in lieu of sucker rod pumps. Also a default for low bottom hole pressure wells on continuous gas lift. Used on <1% of U.S. wells

Gas Lift Manual, API, Dallas.

Plunger Lift

Individual well or system. Simple to deSign, install, and operate. Requires adjusting and plunger maintenance.

Essentially a low· liquid·rate, high· GLR lift method. Can be used for extending flow life or improving efficiency. Ample gas volume and/or pressure needed for successful operation. Used on <1% of U.S. wells.

Blann, J.R. and Williams, J.D.: "Determining the Most Profitable Gas Injection Pressure for Gas Lift Installations," JPT(Aug. 1984) 1305.

DeMoss, E.E. and Tiemann, W.D.: "Gas Lift Increases High-Volume Production From Clay­more Field," JPT (April 1982) 696.

Kanu, E.P., Mach, J., and Brown, K.E.: "Eco­nomic Approach to Oil Production and Gas Al­location in Continuous Gas Lift, " JPT (Oct. 1981) 1887.

Reddin, J.D., Sherman, T.A.G., and Blann, J.R.: "Optimizing Gas-Lift Systems," paper SPE 5150 presented at the 1974 SPE Annual Meet­ing, Houston, Oct. 6-9.

Simmons, W.E.: "Optimizing Continuous Flow Gas Lift Wells," Pet. Eng. (Aug. 1972) 46; (Sept. 1972) 68.

Winkler, H.W. and Smith, S.S.: Camco Gas Lift Manual, Camco Inc., Houston.

Intermittent Gas Lift Neely, A.B., Montgomery, J.W., and Vogel,

J.V.: "A Field Test and Analytical Study of Intermittent Gas Lift," JPT (Oct. 1974) 502; Trans., AIME, 257.

White, G. et al.: "An Analytical Concept of the Static and Dynamic Parameters oflntermittent Gas Lift," JPT (March 1963) 301; Trans., AIME,228.

Plunger Lift Beauregard, E. and Ferguson, P.L.: "Introduc­

tion to Plunger Lift: Applications, Advantages and Limitations," Southwestern Petroleum Short Course, Lubbock (April 23-25, 1981).

Beauregard, E. and Morrow, S.: "New and Un­usual Application for Plunger Lift System," paper SPE 18868 presented at the 1989 SPE Production Operation Symposium, Oklahoma City, March 13-14.

December 1993 • JPI'

TABLE 2-NORMAL OPERATING CONSIDERATIONS

Hydraulic Gas Lift

Sucker Rod Progressing Reciprocating Hydraulic Continuous Pumping Cavity Pumping ESP's Pumping Jet Systems Flow Intermittent Plunger Lift

Casing size limits Problems only in Normally no Casing size will Larger casing Small casing size The use of 4,5- Small casing (4.5 Small caSing (restricts tubing high-rate wells problem for limit use of large required for often limits and 5.5-in. and 5.5 in.) suitable for this size) requiring large 4.5-in. casing motors and parallel free or producing rate casing with 2-in. normally is not a low-volume lift.

plunger pumps. and larger, but pumps. Avoid closed systems. owing to high nominal tubing problem for this Annulus must Small casing gas separation 4.5-in. casing Small caSing (unacceptable) normally limits relatively low- have adequate sizes (4.5- and may be limited. and smaller. (4.5- and 5.5-in.) friction losses. rates to < 1 ,000 volume lift. gas storage 5.5-in.) may limit Reduced may result in Larger casing BID. For rates volume. free-gas performance excessive friction may be required >5,000 B/D, separation. inside 5.5-in. losses and limits if dual strings use >7-in.

casing, producing rate. run. caSing and depending on > 3.5-in. tubing depth and rate. needed.

Depth limits Good: rods or Poor: limited Usually limited Excellent: limited Excellent: Similar Controlled by Usually limited Typically structure may limit to relatively to motor by power-fluid limits as system injection by fallback; <10,000 ft. rate at depth. shallow depths, horsepower or pressure reciprocating pressure and few wells Effectively, about possibly 5,000 ft. temperature. (5,000 psi) or pump. Practical fluid rates. > 10,000 ft. 500 B/D at 7,500 ft Practical depth horsepower. depth of Typically, for and 150 B/D at about 10,000 ft. Low-volume/ 20,000 ft. 1,000 BID with 15,000 ft. high-lift head 2.5-in. nominal

pumps operating tubing, 1,440-psi at depths to lift system, and 17,000 ft. 1,000 GLR, has

an injection depth of about 10,000 ft.

Intake capabilities Excellent: < 25 Good: < 100 psi Fair: if little free Fair: not as good as Poor to fair; Poor: restricted by Fair when used Good: bottomhole psig feasible provided gas (i.e. rod pumping. >350 psig to the gradient of without chambers. pressures < 150 provided adequate > 250-psi pump Intake pressure 5,000 ft with low the gas-lifted PIP>250 psi for psi at 10,000 ft adequate displacement intake pressure). < 100 psig GLR. Typical fluid. Typically 10,000 ft well. for low-rate, displacement and gas venting. Poor if pump usually results in design target moderate rate is Good when used high-GLR wells. and gas venting. must handle frequent pump is 25% limited to about with chamber. PIP Typically about > 5% free gas. repairs. Free gas submergence. 100 psi/1,000 ft of <250 psi 50 to 100 psig. reduces efficiency injected depth. feasible at

and service life. Thus, the 10,000 ft. backpressure on 10,000 ft well may be > 1 ,000 psig.

Noise level Fair: moderately Good: surface Excellent: low Good: well noise Same as Low at well Same as Low. high for urban prime mover noise. Often low. Wellsite hydrauliC but noisy continuous flow. areas, provides the preferred in power-fluid units reCiprocating compressor.

only noise. urban areas can be sound- pump. if production proofed. rate high.

Obtrusiveness Size and Good: low-profile Good: low profile Fair to good: Same as Good low profile: Same as Good. operation are surface but requires wellhead hydraulic but must provide continuous flow. drawbacks in equipment. transformer bank. equipment has reciprocating for compressor. populated and Transformer may low profile. pump. Safety farming areas. cause problems in Requires surface precautions must Special low- urban areas. treating and high be taken for profile units are pressure pumping high-pressure available. eqUipment. gas lines.

Prime mover Good: both Good: both Fair: requires a Excellent: prime Same as Good: engines, Same as None normally flexibility engines or engines or good power mover can be hydraulic turbines, or continuous flow. required.

motors can be motors can be source without electric motor, reciprocating motors can be used easily used. spikes or gas, or diesel-fired pump. used for (motors more interruptions. engines or compression. reliable and Higher voltages motors. flexible). can reduce 12R

losses. Surveillance Excellent: can be Fair: analysis Fair: electrical Goodlfair: Same as Good/excellent: Fair: complicated Good: depends

easily analyzed based on checks but downhole pump hydraulic can be analyzed by standing on good well based on well production and special performance can reciprocating easily. valve and tests and well test, fluid levels, fluid levels only. equipment be analyzed from pump. Bottomhole fallback. pressure chart. etc. Analysis Dynamometers needed surface power- pressure and improved by use and pump-off otherwise. fluid rate and production log of dynamometers cards not pressure, speed, surveys easily and computers. possible to use. and producing obtained.

rate. Bottomhole Optimization and pressure obtained computer control with free pumps. being attempted.

Testing Good: well testing Good: well testing Good: simple with Fair: well testing Same as Fair: well testing Poor: well testing Well testing is simple with simple with few few problems. with standard hydraulic complicated by complicated by simple with few few problems problems. High-water-cut individual well reciprocating injection gas injection gas problems. using standard and high-rate units presents few pump. Three- volume/rate. volume/rate. available wells may problems. Well stage production Formation GLR Measurement of equipment and require a free- testing with a test can be obtained by both input and procedures. water knock-out. central system conducted by subtracting total outflow gas

more complex; adjusting produced gas a problem. requires accurate production step from injected I ntermittent flow power fluid rates, pressured gas. Gas can cause measurement. recorder in place measurement operating

to monitor intake errors common. problems with pressure. separators.

Time cycle and Excellent if well Poor: avoid Poor: soft start Poor: possible but Poor: does not Not applicable. Poor: cycle must Not applicable. pump-off can be pumped shutdown in high and improved not normally used. appear applicable be periodically controllers off. viscosity/sand seals/protectors Usually controlled owing to intake adjusted. Labor-application. producers. recommended. only by pressure intensive.

displacement requirement checks; pump-off higher than control not pump-off. developed.

JPl' • December 1993 1165

TABLE 3-ARTIFICIAL-LiFT CONSIDERATIONS

Hydraulic Gas Lift

Sucker Rod Progressing Reciprocating Hydraulic Continuous Pumping Cavity Pumping ESP's Pumping 'Jet Systems Flow Intermittent Plunger Lift

Corrosion/scale- Good to excellent: Good: batch Fair: batch Good/excellent: Good/excellent: Good: inhibitor in Same as Fair: normal handling ability batch treating treating inhibitor treating inhibitor batch or inhibitor with the injection gas continuous flow. prod uction cycle

inhibitor down down annulus only to intake continuous power fluid and/or batch must be annulus used feasible. unless shroud is treating inhibition mixes with inhibiting down interrupted to frequently for used. can be circulated produced fluid at tubing feasible. batch treat the both corrosion with power fluid entry of jet pump Steps must be well. and scale for effective throat. Batch taken to avoid control. control. treat down corrosion in

annulus feasible. injection gas lines.

Crooked/deviated Fair: increased Poor to fair: Good: few Excellent. If Excellent: short Excellent: few Same as Excellent. holes load and wear increased load problems. tubing can be jet pump can wireline continuous flow.

problems. High- and wear Limited run in the well, pass through problems up to angle deviated problems. experience in pump normally doglegs up to 70° deviation for holes (> 70°) Currently, very horizontal wells. will pass through 24°/100 ft. in wireline-and horizontal few known Requires long- the tubing. Free 2-in. nominal retrievable wells are being installations. radius well bore pump retrieved tubing. Same valves. produced. Some bends to get without pu IIi ng conditions as success in through. tubing. Feasible hydraulic pumping Isol100 operation in reCiprocating ft using rod horizontal wells. pump. guides.

Duals application Fair: parallel No known No known Fair: three-string Same as Fair: dual gas lift Same as No known 2 x 2-in. low-rate installations. installations. nonvented hydraulic common but continuous flow. installations. duals feasible Larger casing applications have reciprocating good operating inside 7-in. would be been made with pump except can of dual lift casing. Duals needed. Possible complete possibly handle complicated and inside S.S-in. run and pull isolation of higher GLR's but inefficient casing currently problems. production and at reduced resulting in not in favor. Gas power fluid from efficiency. reduced rates. is a problem each zone. Parallel 2 x 2-in. from lower zone. Limited to low nominal tubing Increased GLR's and inside 7-in. mechanical moderate rates. casing and problems. 3 x 3-in. tubing

inside 9*-in. casing feasible.

Gas-handling Good if can vent Poor if must Poor for free gas Good/fair: Similar to Excellent: Same as Excellent. ability and use natural pump any free (i.e., >S% concentric fixed hydraulic produced gas continuous flow.

gas anchor with gas. through pump). pump or parallel reciprocating reduces need for properly Rotary gas free permits gas pump. Free gas injection gas. designed pump. separators venting with reduces Poor if must helpful if solids suitable efficiency but pump >SO% not produced. downhole gas helps lift. Vent free gas. separator below free gas if

pump intake. possible. Use a Casing free gas anchor. pump limited to low GLR's.

Offshore Poor: must design Poor: may have Good: must Fair: feasible Good: produced Excellent: most Poor in wells Excellent for application for unit size, some special provide electrical operation in water or common method needing sand correct

weight, and application power and highly deviated seawater may be if adequate control. Use of application. pulling unit offshore. service pulling wells. Requires used as power injection gas standing valve space. Most However, pulling unit. deck space for fluid with well available. risky. Heading wells are unit needed. treating tanks site type system causes operating deviated and and pumps. or power fluid problems. typicaUy produce Water power separation sand. fluid can be before

used. Power oil production a fire/safety treating system. problem.

Paraffin-handling Fair/good: hot Fair: tubing may Fair: hot water/oil Good/excellent: Same as Good: mechanical Same as Excellent: cuts capability water/oil treating need treatment. treatments, circulate heat to hydraulic cutting continuous flow. paraffin and

and/or use of Rod scrapers not mechanical downhole pump reciprocating sometimes removes small scrapers used. Possible to cutting, batch to minimize pump. required. deposits. pOSSible, but unseat pump inhibition buildup. Injection gas they increase and circulate hot possible. Mechanical may aggravate operating fluids. cutting and an existing problems and inhibition problem. costs. possible. Soluble

plugs available. "Free" pumps can be surfaced on a schedule.

Slim-hole Feasible for low Feasible if low No known Possible but may Same as Feasible but can Same as Good: similar to completions rates « 100 rates, low installations. have high friction hydraulic be troublesome continuous flow. casing lift but (2J\-in. B/D) and low GOR's, and losses or gas reciprocating and inefficient. must have production GOR «2S0). shallow depths problems. pump. adequate caSing string) Typically are but no known Suitable for low formation gas.

used with I.S-in. installations. rates and low nominal tubing. GLR's.

Solids/sand- Poor/Fair: for low- Excellent: up to Poor: requires Poor: requires Fair/good: jet Excellent: limit is Fair: standing Sand can stick handling ability viSCOSity « 1 0 SO% sand with <200 ppm < 10-ppm solids pumps are inflow and valve may cause plunger;

cp) production. high-viscosity solids. Improved power fluids for operating with surface problems. however, plunger Improved (>200 cp) wear-resistant good' run life. 3% sand in problems. wipes tubing performance for crude. materials Also produced produced fluid. Typical limit is clean. high-viscosity Decreases to available at fluids must have Power fluid to jet 0.1% sand for (>200 cp) < 10% sand for premium cost. low solids pump can inflow and cases. May be water producers. «200 ppm of tolerate 200 ppm outflow able to handle IS-~m particles) of 2S~m particle problems. up to 0.10/0 sand for reasonable size. Fresh water with special life. Use fresh treatment for salt pumps. water injection buildup possible.

for salt buildup problems.

1166 December 1993 • JPf

TABLE 3-ARTIFICIAL-LiFT CONSIDERATIONS (continued)

Sucker Rod Progressing Pumping Cavity Pumping

Temperature Excellent: Fair: limited to limitation currently used in stator elastomer.

thermal At present operations normally below (550°F). 250°F.

High·viscosity Good for < 200· Excellent for high fluid·handling cp fluids and low viscosity fluids capability rates (400 B/D). with no

Rod fall problem stator/rotator for high rates. problems. Higher rates may require diluent to lower viscosity.

High·volume lift Fair: restricted to Poor: restricted to capabilities shallow depths relatively small

using large rates. Possibly plungers. 2,000 BFPD from Maximum rate 2,000 ft and 200 about 4,000 BFPD from BFPD from 1,000 5,000 ft. ft and 1,000 BFPD from 5,000 ft.

Low·volume lift Excellent: most Excellent for capabilities commonly used <100·BFPD

method for wells shallow wells producing < 100 that do not pump BFPD. off.

Foss, D.L. and Gaul, R,B,: "Plunger Lift Per­formance Criteria With Operating Experience­Ventura Ave. Field," Drill. & Prod. Prac., API (1965) 124,

Lee, J.P.: "Dynamic Analysis of Plunger Lift 0p­erations," paper SPE 10253 presented at the 1981 SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 4-7.

McCoy, C,D, and Ross, K.: "Plunger Lift, and Economic Alternative to Sucker Rod Pumps," Southwestern Petroleum Short Course, Lub­bock (April 22-23, 1992) 337.

Mower, L. N. et aL: "Defining the Characteris­tics and Performance of Gas-Lift Plungers," paper SPE 14344 presented at the 1985 SPE Annual Technical Conference and Exhibition, Las Vegas, Sept. 22-25.

ESP's

Allis, D.H, and Capps, W.M.: "Submersible Pumping-Long Beach Unit of East Wilming­ton Field: A 17-Year Review," JPT (Aug, 1984) 1321.

Divine, D,L.: "A Variable Speed Submersible Pumping System," paper SPE 822.61 presented at the 1979 SPE Annual Technical Conference and Exhibition, Las Vegas. Sept 23-26.

Lea, J ,F. and Bearden, J.L.: "Effects of Gase­ous Fluids on Submersible Pump Perform­ance," JPT (Dec. 1982) 2922.

Lea, J.F. and Bearden, J ,L.: "Gas Separator Per­formance for Submersible Pump Operations," JPT (June 1982) 1327,

,JPT • December 1993

Hydraulic Reciprocating Hydraulic

ESP's Pumping Jet Systems

Limited to Excellent: Excellent: <250°F for standard possible to standard and materials to operate to <325°F with 300+ 0 F and to 500+ o F with special motors 500 + ° F feasible special and cable. with special materials.

materials.

Fair: limited to Good: > 8°API Good/excellent: about 200 cpo production with production with Increases <500 cp up to 800 cp horsepower and possible. Power possible. Power reduces head. fluids can be oil of >24°API Potential solution used to dilute and <50 cp or is to use "core low·gravity water power fluid flow" with 20% production. reduces friction water. losses,

Excellent: limited Good: limited by Excellent: up to by needed tubular and 15,000 BFPD horsepower and horsepower. with adequate can be restricted Typically 3,000 flowing by casing size. BFPD from bottomhole In 5.5·in. casing, 4,000 ft and pressure, tubular can produce 1,000 BFPD size, and 4,000 BFPD from 10,000 ft horsepower. from 4,000 ft with 3,SOO'psi with 240 system. horsepower. Tandem motors can be used but will increase costs.

Generally poor: Fair: not as good Fair: > 200 BFPD lower efficiencies as rod pumping. from 4,000 ft. and high Typically 100 to operating costs 300 BFPD from for <400 BFPD. 4,000 to 10,000

ft; >75 BFPD from 12,000 ft possible.

Lea, J.F. and Wilson, B.L.: "The Role of Power Cost in Selection of an Artificial Lift System, " Proc., SPE Electrical Submersible Pumping Workshop, Houston (April 1990).

Stewart, R.E.: "The Effects of Power Supply In­tegrity on Electrical Submergible Pumping Sys­tems," paper SPE 9038 presented at the 1980 SPE Rocky Mountain Regional Meeting, Casper, May 14-16.

Hydraulic Pumping

Coberly, CJ.: Theory and Application of Hydrau­lic Pumping Installations, Kobe Inc., Hunting­ton Park, CA (1961).

Hollis, R.G.: "Deep Hydraulic Pumping-Reno Field," JPT (Nov. 1966) 1395.

Nolen, K,B, and Gibbs, S.G.: "Subsurface Hy­draulic Pumping Diagnostic Techniques," paper SPE 4540 presented at the 1973 SPE An­nual Meeting, Las Vegas, Sept. 30-0ct. 3.

Wilson, P,M.: Introduction to Hydraulic Pump­ing, Kobe Inc., Huntington Park, CA (1976).

Hydraulic Jet Pumping

Christ, F.C and Petrie, H.L.: "Obtaining Low Bottomhole Pressures in Deep Wells With Hy­draulic Jet Pumps," SPEPE (Aug. 1989) 290.

Corteville, J.C. et al.: "Research on Jet Pumps for Single and Multiphase Pumping of Crudes," paper SPE 16923 presented at the 1987 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 27-30,

Gas Lift

Continuous Flow Intermittent Plunger Lift

Excellent: typical Same as Excellent. maximum of continuous flow. about 350°F. Need to know temperatures to design bellows charged valves.

Fair: few Same as Normally not problems for continuous flow. applicable. > 16°API or below 20 cp viscosity. Excellent for high water cut lift even with high viscosity oil.

Excellent: Poor: limited by Poor: limited by restricted by cycle volume number of tubing size and and number of cycles. Possibly injection gas rate possible injection 200 BFPD from and depth. cycles. Typically 10,000 ft, Depending on about 200 BFPD reservoir from 10,000 ft pressure and PI, wtth < 2S0'psi with 4 in. pump intake nominal tubing, pressure. rates of 5,000 B/D from 10,000 ft feasible with 1,440 psi injection gas and GLR of 1,000.

Fair: limited by Good: limited by Excellent: for low heading and efficiency and flow rates of 1 to slippage. Avoid economic limit. 2 BFPD with unstable flow Typically V, to 4 high GLR's. range. Typically bbllcycle with up lower limit is 200 . to 48 cycles/D. BFPD for 2·in. tubing without heading; 400 B/D for 2.5·in. and 700 B/D for 3·in. tubing.

Grupping, A.W. et aL: "Fundamentals of Oil­well Jet Pumping," SPEPE (Feb. 1988) 9.

Jiao, B., Schmidt, Z., and Blais, R,N.: "Effi­ciency and Pressure Recovery in Hydraulic Jet Pumping of Two-Phase, Gas/Liquid Mix­tures," SPEPE (Nov. 1990) 361.

Petrie, H.L. et al.: "Jet Pumping Oil Wells­Part I," World Oil (Nov. 1983) 51; (Dec. 1983) 109; (Jan. 1984) 101.

Tjondrodiputro, B. et aL: "Hydraulic Jet Pump­ing in a Remote Location," World Oil (Dec, 1986) 35.

SI Metric Conversion Factors °API 141.5/(131.5+ ° API) glcm'

bbI x 1.589873 E-OI m' ep x 1.0* E+oo mPa's ft x 3.048* E-OI m

OF (OF - 32)/1.8 °C in. X 2.54* E+oo em psi x 6.894757 E+oo kPa

'Conversion factor is exact.

This paper is SPE 24834. Distinguished Author Series ar· ticles are general, descriptive representations that summar· ize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: To inform the general readership of recent advances in various areas of petrole· um engineering. A softbound anthology, SPE Distinguished Author Series: Dec. 1981-Dec. 1983, is available from SPE's Book Order Dept.

1167

Discussion of Recommendations and Comparisons for Selecting

Artificial-Lift Methods Denis J. O'Donoghue, SPE, Denver Petroleum Consulting SRL

We read with extreme interest the valuable contribution made by J.D. Clegg et al. ("Recommendations and Comparisons for Select­ing Artificial-Lift Methods," Dec. 1993 JPT, Page 1128). The sub­ject is of great value in this period of depressed oil values and in­creasing energy and other operating costs.

We fully concur with the authors that "correct selection of an arti­ficial-lift method is important to the long-term profitability of most producing oil wells." Therefore, it is most important that the meth­ods used to select the artificial-lift method are beyond reproach. I suggest that the method of presentation used is biased toward the older lift methods and that some revisions should be made to the method proposed by the authors.

The authors present a pie chart (Fig. 1) that gives a very mislead­ing impression as an aid for selecting an artificial-lift system be­cause it is heavily weighted toward rod pumps (85%). I believe that the only valuable graph would be one on a time basis with the per­centage of new installations of each type plotted vs. years, possibly with the addition of information on the number of installations changed over from, say, beam pumps in each year.

It is interesting to review the references to see the date for the first paper in each category and the number of papers listed for each cate­gory. This date is an indication of how long that type of installation has been in use and what type of weighting factor might be used in

.JPl' • July 1994

evaluating the growth rate of the market share. Of even greater value would be a series of graphs of this type

plotted vs. a depth range/production rate range. This would have been a monumental task a few years ago, but it could be achieved without an overwhelming effort in this age of computers and large databases.

In the Conclusions, the authors state categorically that "sucker­rod (beam) pumping should be the standard consideration if opera­tions are on land." This conclusion would be better omitted as this point is amply covered by Conclusions 1 and 2 and by Fig. 8, which shows the relative hydraulic horsepower efficiencies. It is unfortu­nate that Fig. 2 does not show the hydraulic horsepower efficiency for plunger lift, which requires no external energy. The conclusion would seem to be better phrased as "sucker-rod (beam) pumping should be considered only if no other, more energy efficient system is viable."

In Table 2, Clegg et at. state that it is "not applicable." Apparent­ly, they are unaware of the major developments in this field by W &H Development's plunger lift controller, the OP/uS 1. The computer­ized controlling of the plunger operation has resulted in incredible (up to 300%) increases in production.

(SPE 28645) JPT

621

Authors' Reply to Discussion of Recommendations and Comparisons for

Selecting Artificial-Lift Methods Joe Dunn Clegg, SPE, consultant; Norman W. Hein Jr., SPE, Conoco Inc.;

and S. Mike Bucaram, SPE, Arco E&P Technology

We welcome and appreciate any constructive criticism that will im­prove our paper. As we stated, we want new data to be published that may alter the attributes given in our tables or that will improve our knowledge of artificial-lift selection. O'Donoghue makes some in­teresting observations directed mostly at rod pumping and plunger lift.

We admit that we may be biased toward the older lift methods (i.e., those methods where ample data have been gathered to define the advantages and limitations of the various 31 attributes listed). Each attribute was a consensus of what we define as "conventional wisdom." New methods, recent design changes, or improvements in operating techniques must stand the test of time. A good selection is critically important in today's production atmosphere because we are often faced with meeting operating-cost benchmarks and estab­lished earnings goals. We tried to be objective and found that manufacturers' claims often had to be modified.

Good statistical data on artificial-lift use are difficult to obtain. We believe that Fig. I is representative of the total artificial-lift use in the U.S. The paper states that, if the U.S. stripper wells (<10 BOPD) are removed, the percent of rod pumping for the higher-rate U.S. oil wells declines to 27%. A larger number of the 500,000 to 600,000 U.S. oil wells on artificial lift certainly have been installed for more than 10 or 20 years. Some operators (Shell, Conoco, Arco, Amoco, and Exxon) indicate that the current total use shown in Fig. 1 has not significantly changed. However, rod pumping seems to have declined during the past 10 years from 85%, and use of electri­cal submersible pumping, progressing cavity pumping, and even plunger lift have increased slightly.

We carefully selected only what we considered worthwhile refer­ence papers. Naturally, many more papers on rod pumping are avail­able than papers on progressing cavity pumping (a new lift method). The publication dates had nothing to do with selection of references.

A series of graphs for the various lift methods showing rate vs. depth is certainly feasible. To develop such graphs usually requires a large number of assumptions; otherwise, a series of graphs must be developed for each influencing variable. This results in a thick

622

design book that is of little help in artificial-lift selection. A better approach might be a series of PC programs that would quickly gen­erate data for given conditions.

As we stated, sucker-rod (beam) pumping should be the "stan­dard" consideration if operations are on land. That does not mean that rod pumping is automatically installed but that other lift meth­ods should be compared to rod pumping. If significant improve­ments in rates or reductions in operating costs occur that affect pres­ent-value profit, then the other lift methods should be selected. Energy cost is only one of the many variables that must be consid­ered.

It was debated at the 1992 SPE Forum Series on New Develop­ments in Artificial Lift whether plunger lift is actually artificial lift or an improved flow method. If supplemental gas is supplied (which is sometimes necessary), it does become artificial lift just as contin­uous-flow gas lift is. Plunger lift is not a new lift method. Shell suc­cessfully used plunger lift in the Ventura field in California in the 1950's; others undoubtedly used plunger lift even before then. The best applications for plunger lift are for relatively low liquid rates and high GLR's for both oil and gas wells. The limits for a specific field can be found with a little effort.

By their very nature, plunger-lift installations are "time cycled." Control of the number of cycles is the key to good, efficient opera­tion. This control has been obtained with various types of pressure and time control systems. Use of a computer chip or new develop­ments in control systems should allow more flexibility and promote better control. We suggest changing "not applicable" to "necessary for efficient operation" in Table 2 (for the attribute time cycle) for plunger lift. Use of pump-off controllers remains "not applicable."

O'Donoghue should consider writing a paper about the merits of plunger lift and present his data there.

81 Metric Conversion Factor

bbl X 1.589 873 E-01 =m3

(SPE 29092) JPT

July 1994 • JPT