SPE 24834 Clegg 1993 Recommendations and Comparisons for Selecting Artificial-Lift Methods(Includes Associated Papers 28645 and 29092 )

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

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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 $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 Sucker Rod Pumping Capital cost

Low to moderate: increases with depth and larger units.

Progressing Cavity Pumping

Low: increases with depth and larger rates.

ESP's Relatively low capital cost if commercial electric power available. Costs increase as

horsepower increases. Downhole equipment

Efficiency (output hydraulic horsepower divided by input hydraulic horsepower).

Flexibility

Miscellaneous problems

Reasonably good Good design Requires proper rod design and and operating cable in addition operating practices to motor, pumps, practices seals, etc. Good needed. May design plus good needed. Data have problems bank of rod and with selection operating pump failures of appropriate practices beneficial. Good stator elastomer. essential. selection, operating, and repair practices needed for rods and pumps. Good for high Excellent total Excellent: may rate wells but system exceed rod efficiency. Fullpumps for ideal decreases cases. Reported significantly for pump fillage system efficiency < 1,000 BFPD. efficiency 50% to 70%. typically about Typically total 50 to 60%More operating system efficiency feasible if well is data needed. is about 50% for not overpumped. high rate well, but for < 1,000 B/D, efficiency typicaly is < 40%. Excellent: can Fair: can alter Poor: pumps alter stroke speed. Hydraulic usually run at a speed and unit provides fixed speed. length, plunger additional Requires careful size, and .run flexibility but at sizing. VSD time to control added cost. provides more production rate. flexibility but added costs. Time cycling normally avoided. Must size pump properly. Stuffing box May have limited Requires a highly leakage may be service in some reliable electric messy and a areas. Because power system. potential hazard. this is a newer Method sensitive (Antipollution method, field to rate changes. knowledge and stuffing boxes are available.) experience are limited.

Operating costs

Very low for shallow to medium depth (< 7500 ft) land locations with low production «400 BFPD).

Reliability

Excellent: run Good: normally time efficiency overpumping and >95% if good lack of experience operating practiCes decreases run are followed and time. if corrosion, wax, asphaltenes, solids, deviations, etc., are controlled.

Salvage value

Excellent: easily Fair/poor: easily moved and good moved and some market for used current market equipment. for used equipment.

JPT • December 1993

Potentially low, but short run life on stator or rotor frequently reported.

Hydraulic Reciprocating Pumping Varies but often competitive with rod pumps. Multiple well, central systems reduce cost per well but is more complicated. Proper pump sizing and operating practices essential. Requires powerfluid conductor. Free pump and closed powerfluid option.

Fair to good: not as good as rod pumping owing to G LR, friction, and pump wear. Efficiencies range from 30% to 40% with GLR>100; may be higher with lower GLR.

Gas Lift Hydraulic Jet Systems

Continuous Flow

Intermittent

Plunger Lift

Competitive with sucker-rod pump. Cost

Very low; only Well equipment Same as continuous flow costs low but low-cost well lines and gas lift. equipment if no increases compression compressor with higher costs may be required. horsepower. high. Central compression system reduces cost per well. Requires Good valve Unload to bottom Operating computer design design and with gas lift practices have programs for spacing essential. valves; consider to be tailored to sizing. Tolerant Moderate cost for chamber for high each well for of moderate well equipment PI and low BHP optimization. solids in power (valves and wells. Some problem fluid. No moving mandrels). Choice with sticking parts in pump; of wirelineplungers. long service life; retrievable or simple repair conventional valves. procedures.

Fair to poor. Maximum efficiency only 30%. Heavily influenced by power fluid plus production gradient. Typical operating efficiencies of 10% to 20%.

Fair: increases for Poor: normally wells that require requires a high small injection injection gas GLR's. Low for volume/barrel wells requiring fluid. Typical lift high GLR's. efficiency is 5% Typical to 10%; efficiencies of improved with plungers. 20% but range from 5% to 30%.

Good/excellent: Good to excellent: Excellent: gas Can vary power power fluid rate injection rate fluid rate and and pressure varied to change speed of adjusts the rates. Tubing downhole pump. production rate needs to be Numerous pump and lift capacity. sized correctly. sizes and Selection of pump/engine throat and ratios adapt to nozzle sizes production and extend range of depth needs. volume and capacity. Power fluid solids More tolerant of A highly reliable control essential. power fluid compressor with solids; 200 ppm Need 15 ppm of 95 + % run time 15-/Lm particle required. Gas of 25-/Lm size maximum to particles must be avoid excessive acceptable. dehydrated engine wear. Diluents may properly to avoid Must add be added if gas freezing. surfactant to a required. Power water power fluid water (fresh, produced, or for lubricity. seawater) Triplex plunger leakage control acceptable. required. Varies: if Often higher than Higher power Well costs low. horsepower is rod P)J mps even cost owing to Compression high, energy for free systems. horsepower costs vary costs are high. Short run life requirement. depending on High pulling increases total Low pump fuel cost and costs result from operating costs. maintenance compressor 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. Varies: excellent Good with a Good with proper Excellent if for ideal lift correctly designed throat and compression cases; poor for and operated nozzle sizing for system properly problem areas. system. Problems the operating designed and Very sensitive to or changing well conditions. Must maintained. operating conditions reduce avoid operating temperatures downhole pump in cavitation and electrical reliability. range of jet malfunctions. Frequent pump throat; downtime results related to pump from operational intake pressure. problems. More problems if pressures > 4,000 psig. Fair: some trade Fair market for Good: easily Fair: some market in value. Poor triplex pumps; moved. Some for good used open market good value for trade in value. compressors and values. wellsite system Fair market for some trade in that can be triplex pump. value for mandrels moved easily. arid valves.

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: must adjust Good for lowvolume wells. injection time Can adjust and cycles frequently. injection time and frequency.

Labor-intensive to Plunger hangup or sticking may keep fine tuned; be a major otherwise, poor performance. problem. Maintaining steady gas flow often causes injection gas measurement and operating problems.

Same as continuous-flow gas lift.

Usually very low.

Excellent if there Good if well is an adequate production is supply of stable. injection gas and an adequate lowpressure storage volume for injection gas. System must be designed for the unsteady gas flow rates.

Same as continuous-flow gas lift.

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

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

Progressing Ca~ity Pumping

ESP's

Hydraulic ReCiprocating Pumping

Gas Lift Hydraulic Jet Systems

Continuous Flow

Intermittent

Plunger Lift

System (total)

Simple to install Simple manual or Computer design An adequate Fairly simple to Straightforward Same as continuous·flow and operate. design but requires computer design program typically volume, high· and basic pressure, dry, gas lift. Limited proven good rate data. typically used. used for design. procedures to System not noncorrosive and design, Free pump easily Basic operating design, install, retrieved for forgiving. installation, and procedures and operate' clean gas supply servicing. source is needed Requires operating needed for following API specifications speCifications Individual well downhole pump throughout the excellent unit very flexible and wellsite unit. entire life. System operating and recommended and procedures. Each well is an Free pump easily approach needed. practices. Follow but extra cost. practices. Each individual system. API recommended Requires retrieved for well is an Low backpressure practices in individual system. beneficial. Good attention. Central on site repair or design, testing, plant more replacement. data needed for and operation. complex; usually Down hole jet valve design and often requires Typically each spacing. API results in test trial and error well is an specifications and and treatment to arrive at individual problems. deSign/operating besVoptimum jet. recommended producer using a common electric practices should system. be followed.

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

Usage/outlook

Good for higher· Excellent: used An excellent high Often used as Limited to Good, flexible, high-rate volume wells on about 85% of relatively shallow rate artificial lift a default wells with low system. Best requiring flexible U.S. artificial·lift artificial·lift artificial·lift well rates. Used on operation. System system for wells suited for wells. The system. Flexible less than 0.5% operation; wide will tolerate wide with high < 200°F and normal standard rate range; depth ranges, artificial·lift of U.S. lifted >1,000 BFPD bottomhole high temperatures, pressures. Most rates. Most often suitable for wells. Used method. corrosive fluids, primarily on gas· used on high relatively deep, like a flowing high GOR, and well dewatering. water cut wells. high·volume, well. Used on Used on about high·temperature, significant sand about 10% of 4% of U.S. lifted deviated oil wells. production. Used U.S. lifted wells, wells. Used on < 2% of on < IDA> of U.S. mostly offshore. U.S. lifted wells. lifted wells. Sometimes used to test wells that will not flow offshore.

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