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PEH:Artificial Lift Systems

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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume IV - Production Operations Engineering

Joe Dunn Clegg, Editor

Chapter 10 – Artificial Lift Selection

James F. Lea, U. of Oklahoma

Pgs. 411-455

ISBN 978-1-55563-118-5
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Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the formation to obtain a higher production rate from the well. This can be done with a positive-displacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake. It also can be done with a downhole centrifugal pump, which could be a part of an electrical submersible pump (ESP) system. A lower bottomhole flowing pressure and higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is lowered and expanding gas helps to lift the fluids. Artificial lift can be used to generate flow from a well in which no flow is occurring or used to increase the flow from a well to produce at a higher rate. Most oil wells require artificial lift at some point in the life of the field, and many gas wells benefit from artificial lift to take liquids off the formation so gas can flow at a higher rate.

To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected. The methods historically used to select the lift method for a particular field vary broadly across the industry. The methods include operator experience; what methods are available for installations in certain areas of the world; what is working in adjoining or similar fields; determining what methods will lift at the desired rates and from the required depths; evaluating lists of advantages and disadvantages; "expert" systems to both eliminate and select systems; and evaluation of initial costs, operating costs, production capabilities, etc. with the use of economics as a tool of selection, usually on a present-value basis.

These methods consider geographic location, capital cost, operating cost, production flexibility, reliability, and "mean time between failures." This chapter discusses some of the most commonly used methods. In most cases, what has worked best or which lift method performs best in similar fields serve as selection criteria. Also, the equipment and services available from vendors can easily determine which lift method will be applied. However, when significant costs for well servicing and high production rates are a part of the scenario, it becomes prudent for the operator to consider most, if not all, of the available evaluation and selection methods. If the "best" lift method is not selected, such factors as long-term servicing costs, deferred production during workovers, and excessive energy costs (poor efficiency) can reduce drastically the net present value (NPV) of the project. Typically, the reserves need to be produced in a timely manner with reasonably low operating costs. Conventional wisdom considers the best artificial lift method to be the system that provides the highest present value for the life of the project. Good data are required for a complete present-value analysis, and these data are not always broadly available.

In some situations, the type of lift already has been determined and the task is to best apply that system to the particular well. The more basic question, however, is how to determine the proper type of artificial lift to apply in a given field for maximum present value profit (PVP). This chapter briefly reviews each of the major types of artificial lift before examining some of the selection techniques. Some less familiar methods of lift also are mentioned. Preliminary factors related to the reservoir and well conditions that should be considered are introduced.

Environmental and geographical considerations may be overriding issues. For example, sucker-rod pumping is, by far, the most widely used artificial lift method in onshore United States operations. However, in a densely populated city or on an offshore platform with 40 wells in a very small deck area, sucker-rod pumping might be a poor choice. Also, deep wells producing several thousands of barrels per day cannot be lifted by beam lift; therefore, other methods must be considered. Such geographic, environmental, and production considerations can limit the choices to only one method of lift; however, determining the best overall choice is more difficult when it is possible to apply several of the available lift methods.

Reservoir Pressure and Well Productivity

Among the most important factors to consider when selecting an artificial lift system are current and future reservoir pressure and well productivity. If producing oil or liquid rate is plotted (X axis) against producing BHP (Y axis), one of two inflow performance relationships (IPR) usually is seen. Above the bubblepoint pressure, the liquid rate vs. pressure drop below the reservoir pressure (drawdown) is linear. Below the bubblepoint pressure, a relationship similar to that described by Vogel[1] occurs. Fig. 10.1 illustrates production vs. drawdown relationships as a single IPR with a bubblepoint of 750 psig and an average reservoir pressure of 2,000 psig. If the necessary data are available, a single-phase IPR expression for either gas or liquid flow is available from radial-flow equations. Gas-deliverability curves show a nonlinear dependence of gas rate similar to the liquid rate vs. pressure on a Vogel curve.[1] Liquid-rate IPR curves can have a gas-to-liquid ratio associated with the liquid rate, and gas-deliverability curves can have a liquid production (e.g., bbl/MMscf/D) associated with the gas rates. This chapter focuses on IPRs with liquid production as a function of the flowing BHP.

Some types of artificial lift can reduce the producing sandface pressure to a lower level than other artificial lift methods. For pumping wells, achieving a rate that occurs below the bubblepoint pressure requires measures to combat possible gas interference because gas bubbles (free gas) will be present at the intake of the downhole artificial lift installation. In addition to setting the pump below the perforations, such measures include the use of a variety of other possible gas-separation schemes and the use of special pumps to compress gas or reduce effects of "fluid pound" in beam systems. However, the artificial lift method of gas lift is assisted by the production of gas (with liquids) from the reservoir.

The reward for achieving a lower producing pressure will depend on the IPR. With the IPR data available, a production goal may be set. For low-rate wells, the operator would want to produce the maximum rate from the well. For high-rate wells, the production goal can be set by the capacity or horsepower limit of a particular artificial lift method.

In addition to radial flow and IPR expressions for vertical wells, there are several IPR models[2] for horizontal wells. Horizontal wells typically produce several multiples of what a vertical well would produce in the same formation. Artificial lift usually is installed in the near vertical portion of a horizontal well, rarely into the horizontal portion, to reduce slugging and to achieve maximum drawdown.

IPRs can be generated to represent the expected well conditions as the shut-in pressure depletes. When correlated to a reservoir model or a tank material balance, time can be associated with future IPRs. Fig. 10.2 shows future IPR curves as the reservoir pressure drops as a result of depletion. This particular model shows the productivity index (PI) remaining constant above the bubblepoint as the reservoir depletes. The bubblepoint would not necessarily remain constant with time as modeled here. Reservoir models may be used to predict expected inflow conditions of the wells for the life of the project. Usually this is done only for larger projects. IPR expressions can be modified to show damage or stimulation effects. A test rate or absolute open flow for an IPR increase due to skin removal can be found by multiplying by approximately (7+s)/7 in which s is the nonrate dependent initial "skin" of the well and the final skin is zero. This approximate ratio is determined by dividing a radial-flow rate equation with no skin by a radial-flow equation with skin. The "7" is approximately the log of 0.472 times the drainage radius over the wellbore radius. More complex relationships show the effects of rate-dependent skin or turbulence. For more discussion, see the chapter on formation damage in this volume of the Handbook.

Reservoir Fluids

The characteristics of the reservoir fluid also must be considered. paraffin buildup can be attacked mechanically when sucker-rod pumping is used but may require a thermal or chemical method when other artificial lift methods are used. Sand- or solids-laden production, which can rule out the use of plunger lift, also can cause wear with sucker-rod pumps, reciprocating hydraulic pumps, and jet pumps. Gas lift and PCPs produce moderate volumes of solids with only minor problems. The producing gas/liquid ratio is very important to the lift designer. If the percentage of free gas at intake conditions is high, gas interference is a potential detriment to all methods of lift, but it is a benefit to gas lift. High-fluid viscosity hinders most major forms of lift, but the PCP may produce low temperature, shallow, viscous fluids with little difficulty.

Long-Term Reservoir Performance and Facility Constraints

Two approaches frequently are taken to account for long-term reservoir performance: design on the basis of anticipated performance and design on the basis of current conditions.

If future reservoir performance can be predicted, artificial lift equipment can be installed that can produce up to the largest rate anticipated over the life of the well. This philosophy leads to the installation of oversized equipment, perhaps in anticipation of ultimately producing large quantities of water. Because most artificial lift methods operate at poor efficiency when underloaded, oversized equipment installed because of anticipated high short-term production rates can lead to high energy or operational costs over a significant fraction of the life of the field.

Another extreme is to design only for current conditions without anticipating future production profiles. This can lead to multiple required changes in the size or type of installed lift equipment. Operating efficiently during the short term may be possible, but large amounts of capital for changing equipment may be required later. For example, changing reservoir conditions with time, as shown in Fig. 10.2, would have to be considered carefully in sizing artificial lift equipment for current conditions and for some future date. Bennett[3] addresses some of the concerns of timing related to artificial lift methods.

The operator should consider both long-term and short-term aspects of an artificial lift plan. The goal is to maximize the PVP of the operation over the life of the field. Frequently, the lift method that produces the most oil is the method that provides maximum PVP. However, if operational costs are significantly high for a particular method, a method that can only produce a lower rate but produces more reliably may be more economical. Changes in a lift method usually are not considered worthwhile, but if conditions change drastically, other lift methods may need to be implemented.

Types of Artificial Lift

The major forms of artificial lift are sucker-rod (beam) pumping, ESP, gas lift, and reciprocating and jet hydraulic pumping systems. Also, plunger lift and PCP are becoming more common. There are other methods, which are mentioned as appropriate, such as the electrical submersible progressive cavity pump (ESPCP) for pumping solids and viscous oils, in deviated wells. This system has a PCP with the motor and some other components similar to an ESP. Other methods include modifications of beam pump systems, various intermittent gas-lift methods, and various combination systems.

Artificial lift method selection should be a part of the overall well design. Once the method is selected, the wellbore size required to obtain the desired production rate must be considered. Many times, a casing program has been designed to minimize well-completion costs, but it is later found that the desired production could not be obtained because of the size limitation on the artificial lift equipment. This can lead to an ultimate loss of total reserves. Even if target production rates can be achieved, smaller casing sizes can lead to higher long-term well-servicing problems. If oil prices are low, it is tempting to select a small casing size to help with current economics. Obviously, wells should be drilled and completed with future production and lift methods in mind, but this is often not the case.

Secs. 10.5.1 through 10.5.6 introduce the major methods of artificial lift. The advantages and disadvantages of each method of lift are presented. This information is a tool for any artificial lift selection process.

Sucker-Rod Pumping

Sucker-rod pumping systems are the oldest and most widely used type of artificial lift for oil wells. Fig. 10.3 shows a schematic of a rod pumping system. System details are found in the chapter on sucker-rod pumping in this section of the Handbook.

There are approximately 2 million oil wells in operation worldwide. More than 1 million wells use some type of artificial lift. More than 750,000 of the lifted wells use sucker-rod pumps. In the U.S., sucker-rod pumps lift approximately 350,000 wells. Approximately 80% of all U.S. oil wells are stripper wells making less than 10 B/D with some water cut. The vast majority of these stripper wells are lifted with sucker-rod pumps. Of the nonstripper "higher" volume wells, 27% are rod pumped, 52% are gas lifted, and the remainder are lifted with ESPs, hydraulic pumps, and other methods of lift. These statistics 4 indicate the dominance of rod pumping for onshore operations. For offshore and higher-rate wells around the world, the use of ESPs and gas lift is much higher.

Major Considerations for Sucker-Rod Pumping Systems. Sucker-rod pumping systems should be considered for new, lower volume stripper wells because they have proved to be cost effective over time. In addition, operating personnel usually are familiar with these mechanically simple systems and can operate them efficiently. Inexperienced personnel also can operate rod pumps more effectively than other types of artificial lift. Sucker-rod pumping systems can operate efficiently over a wide range of production rates and depths. Most of these systems have a high salvage value.

Sucker-rod systems should be considered for lifting moderate volumes from shallow depths and small volumes from intermediate depths. It is possible to lift up to 1,000 B/D from approximately 7,000 ft and 200 bbl from approximately 14,000 ft. Special rods may be required, and lower rates may result depending on conditions.

Most of the sucker-rod pumping system parts are manufactured to meet existing standards, which have been established by the American Petroleum Institute (API). Numerous manufacturers can supply each part, and all interconnecting parts are compatible. Many components are manufactured and used that are not API certified, such as large-diameter downhole pumps extending to more than 6 in. in diameter.

The sucker-rod string is the length of the rods from the surface to the downhole pump, and it continuously is subjected to cyclic load fatigue typical of sucker-rod pump systems. The system must be protected against corrosion, as much as any other artificial lift system, because corrosion introduces stress concentrations that can lead to early failures. Frequent rod failures must be avoided for an economical system operation.

Sucker-rod pumping systems often are most incompatible with deviated (doglegged) wells, even with the use of rod protectors and rod and/or tubing rotators. However, deviated wells with smooth profiles and low dogleg severity may allow satisfactory sucker-rod pumping, even if the angle at the bottom of the well is large (approximately 30 to 40°, up to 80°). Some high-angle hole systems use advanced methods of protecting the tubing and rod string with rod protectors and "roller-rod protectors," while other installations with high oil cuts, smooth profiles, and lower angles of deviation use only a few of these devices. Plastic-lined tubing has proven to be effective in reducing rod/tubing wear.

The ability of sucker-rod pumping systems to produce sand-laden fluids is limited, although there are several special filters and sand-exclusion devices available. Some pumps are designed either to exclude the sand or continue to operate as the sand travels through the barrel-plunger clearance. Special metallurgies are used for sand wear.

Paraffin and scale can interfere with the efficient operation of sucker-rod pumping systems. Special wiper systems on the rods and hot water/oil treatments are used to combat paraffin. Hard scales can cause early failures.

Free gas entering the downhole pump reduces hydrocarbon production and causes other problems. This problem and various recommended solutions are detailed in the chapter on sucker-rod pumping in this section of the Handbook.

One of the disadvantages of a beam-pumping system is that the polished-rod stuffing box, in which a polished rod with the rods hung below enters the well at the surface through a rubber packing element, can leak. This can be minimized with special pollution-free stuffing boxes that collect any leakage. Good operations, with such practices as "don’t over tighten" and "ensure unit alignment with standard boxes," with standard boxes are also important.

Continuous production with the system attempting to produce more than the reservoir will produce leads to incomplete pump filling of the pump, fluid pound, mechanical damage, and low energy efficiency. Many systems are designed to produce 120 to 150% more than the reservoir will produce, but when the well is pumped down, a pumpoff controller will stop pumping temporarily to allow fluid entry into the casing-tubing annulus over the pump.

In general, sucker-rod pumping is the method of artificial lift that should be used if the system can be designed without overloading the prime mover, gearbox, unit structure, and the calculated fatigue loading limits of the rods. This system should be considered very carefully in the selection process and, in many cases, should be the artificial lift system of choice.

Electrical Submersible Pumping

As an example area in which ESPs are applied extensively, THUMS Long Beach Co. was formed in April 1965 to drill, develop, and produce the 6,479-acre Long Beach unit in Wilmington field, Long Beach, California. It was necessary to choose the best method to lift fluids from the approximately 1,100 deviated wells over a 35-year contract period from four man-made offshore islands and one onshore site. ESPs have been the primary system in this environment for the contract period.

Fig. 10.4 shows a schematic of a typical ESP system. The chapter on ESP in this section of the handbook contains more complete details of this mechanical-electrical-hydraulic system.

Major ESP Advantages. ESPs provide a number of advantages.
  • Adaptable to highly deviated wells; up to horizontal, but must be set in straight section.
  • Adaptable to required subsurface wellheads 6 ft apart for maximum surface-location density.
  • Permit use of minimum space for subsurface controls and associated production facilities.
  • Quiet, safe, and sanitary for acceptable operations in an offshore and environmentally conscious area.
  • Generally considered a high-volume pump.
  • Provides for increased volumes and water cuts brought on by pressure maintenance and secondary recovery operations.
  • Permits placing wells on production even while drilling and working over wells in immediate vicinity.

Major ESP Disadvantages. ESPs have some disadvantages that must be considered.

  • Will tolerate only minimal percentages of solids (sand) production, although special pumps with hardened surfaces and bearings exist to minimize wear and increase run life.
  • Costly pulling operations and lost production occur when correcting downhole failures, especially in an offshore environment.
  • Below approximately 400 B/D, power efficiency drops sharply; ESPs are not particularly adaptable to rates below 150 B/D.
  • Need relatively large (greater than 4½-in. outside diameter) casing size for the moderate- to high-production-rate equipment.

Long life of ESP equipment is required to keep production economical. Improvements and recommendations based on experience are in the chapter on ESP in this section of the Handbook and in "ABB Automation Technology Products Presentation."[4]

The PCP and the Electrical Submersible Progressive Cavity Pump

Fig. 10.5 shows a schematic of a PCP with a rotating metal rotor and a flexible rubber-molded stator. The stator forms a cavity that moves up as the rotor turns. The pump is well suited for handling solids and viscous fluids because the solids that move through the pump may deflect the rubber stator but do not abrade, wear, or chemically deteriorate the stator or rotor to any appreciable degree. Most PCPs are powered by rotating rods driven from the surface with a hydraulic or electric motor. The system shown in Fig. 10.5 has a pump small enough that the entire pump can be inserted with rods.

Introduced in 1936, the PCP is of simple design and rugged construction. Its low (300 to 600 rev/min) operating speeds enable the pump to maintain long periods of downhole operation if not subjected to chemical attack or excessive wear or it is not installed at depths greater than approximately 4,000 to 6,000 ft. The pump has only one moving part downhole with no valves to stick, clog, or wear out. The pump will not gas lock, can easily handle sandy and abrasive formation fluids, and is not normally plugged by paraffin, gypsum, or scale.

With this system, the rotating rods wear and also wear the tubulars. The rotating rods "wind" up on start and "unwind" on the shutdown. Rotating rods must be sealed at the surface, and many installations have oil leaks at the surface. These problems must be addressed during system design.

To alleviate problems inherent with the conventional rotating-rod PCP systems, the ESPCP system is available. While the number installed is still small, this is not a new system. It has been run in Russia for a number of years and also was available from an ESP vendor a number of years ago. The newer ESPCP system (Fig. 10.6) has some advantages over the rotating sucker-rod systems.

There is a problem of rotating the eccentric rotor with the motor shaft because of possible vibration; therefore, a flexible connection is used. There is a seal section, as in an ESP assembly, to protect the underlying motor from wellbore fluids and to accommodate an internal thrust bearing. Because the PCP usually rotates at approximately 300 to 600 rev/min, and the ESP motor rotates at approximately 3,500 rev/min under load, there must be a way of reducing speed before the shaft connects to the PCP. Methods available from various manufacturers include the use of a gearbox to reduce the motor to acceptable speeds (less than approximately 500 rev/min). Another method is to use higher pole motors with lower synchronous speeds to allow the PCP to turn at operational speeds in combination with a gearbox, but this system produces less output-starting torque.

Major PCP Advantages. PCPs have the following major advantages.
  • The pumping system can be run into deviated and horizontal wells.
  • The pump handles solids well, but the coating of the rotor will erode over time.
  • The pump handles highly viscous fluids in a production well with a looser rotor/stator fit.
  • Several of the components are off-the-shelf ESP components for the ESPCP.
  • The production rates can be varied with the use of a variable-speed controller with an inexpensive downhole-pressure sensor.
  • For appropriate conditions, the PCP can operate with a power efficiency exceeding other artificial lift methods.
  • The PCP can be set in a straight section of a deviated well.
  • Use of an ESPCP eliminates the rotating rods and eliminates problems with rods rotating in a deviated well.

Major PCP Disadvantages. PCPs have the following disadvantages.

  • The stator material will have an upper temperature limit and may be subject to H 2 S and other chemical deterioration.
  • Frequent stops and starts of the PCP pumps often can cause several operating problems.
  • Although it will not gas lock, best efficiency occurs when gas is separated.
  • If the unit pumps off the well or gas flows continuously though the pump for a short period, the stator will likely be permanently damaged from overheating caused by gas compression.
  • The gearbox in an ESPCP is another source of failure if wellbore fluids or solids leak inside it or if excessive wear occurs.

Progressive Cavity Pump Summary. For a low-pressure well with solids and/or heavy oil at a depth of less than approximately 6,000 ft and if the well temperature is not high (75 to 150°F typical, approximately 250°F or higher maximum), a PCP should be evaluated. Even if problems do not exist, a PCP might be a good choice to take advantage of its good power efficiency. If the application is offshore, or if pulling the well is very expensive and the well is most likely deviated, ESPCP should be considered so that rod/tubing wear is not excessive. There is an ESPCP option that allows wire lining out a failed pump from the well while leaving the seal section, gearbox, motor, and cable installed for continued use.

Hydraulic Pumping

There are two primary kinds of hydraulic pumps: jet pumps and reciprocating positive-displacement pumps. Fig. 10.7 shows a jet pump arrangement. For jet pumps, high-pressure power fluid is directed down the tubing to the nozzle where the pressure energy is converted to velocity head (kinetic energy). The high-velocity, low-pressure power fluid entrains the production fluid in the throat of the pump. A diffuser then reduces the velocity and increases the pressure to allow the commingled fluids to flow to the surface.

The positive-displacement pump consists of a reciprocating hydraulic engine directly coupled to a pump piston or pump plunger. Fig. 10.8 shows a reciprocating hydraulically powered pump. Power fluid (oil or water) is directed down the tubing string to operate the engine. The pump piston or plunger draws fluid from the wellbore through a standing valve. Exhausted power fluid and production can be returned up a separate tubing string or up the casing.

When the power fluid and the production are combined, the system is an open power-fluid system. For a vented open power-fluid system, the production and power fluid typically are returned separately in a parallel tubing string with gas normally vented through the casing annulus to the surface. A nonvented casing installation requires a pump to handle the gas and production. The power fluid plus all reservoir fluids are produced up the annulus. Both completion types are used with positive-displacement pumps and with jet pumps. In fact, many bottomhole assemblies (BHAs) can accommodate jet or positive-displacement pumps interchangeably.

In a closed power-fluid arrangement, the power fluid is returned to the surface separately from produced fluids, requiring a separate tubing string. The use of a closed power fluid system is limited as a result of the added initial costs and clearance problems in small casing. Because the jet pump must commingle the power fluid and production, it cannot operate as a closed power-fluid pump.

The most outstanding feature of hydraulic pumps is the "free pump" system. Fig. 10.9 shows a schematic of a free hydraulic pump. Fig. 10.9a shows a standing valve at the bottom of the tubing, and the tubing is filled with fluid. In Fig. 10.9b, a pump has been inserted in the tubing and power fluid is being circulated to the bottom. In Fig. 10.9c, the pump is on bottom and pumping. When the pump is in need of repair, fluid is circulated to the surface as shown in Fig. 10.9d. The positive-displacement pump, the jet pump, and the closed power-fluid system previously shown are all free pumps.

Surface facilities require a power-fluid storage and cleaning system and a pump. The most common cleaning systems are settling tanks located at the tank battery. Cyclone desanders sometimes are used in addition to settling tanks. In the last 40 years, wellsite power plants, which are separators located at the well with cyclone desanders to remove solids from the power fluid, have become popular.

Surface pumps are most commonly triplex plunger pumps. Other types are quintiplex plunger pumps, multistage centrifugal pumps, and "canned" ESPs. The surface pressure required is usually in the 1,500 to 4,000 psi range. It is important to specify 100% continuous duty for the power-fluid pump at the required rate and pressure. Low volume (< 10,000 B/D), high-pressure installations (> 2,500 psi) typically use plunger-type pumps.

Table 10.1 shows approximate maximum capacities and lift capabilities for positive-displacement pumps. In some cases, two pumps have been installed in one tubing string. Seal collars in the BHA hydraulically connect the pumps in parallel; thus, maximum displacement values are doubled.

A relationship between capacity and lift is not practical for jet pumps because of the many variables and the complex relationships among them. To keep fluid velocities below 50 ft/sec in suction and discharge passages, the maximum production rates vs. tubing size for jet-free pumps are approximated in Table 10.2.

Fixed-type jet pumps (those too large to fit inside the tubing) have been made with capacities of 17,000 B/D, and even larger pumps are possible. Maximum lifting depth for jet pumps is approximately 8,000 to 9,000 ft if surface power-fluid pressure is limited to approximately 3,500 psi for water power fluid and approximately 4,000 psi with oil power fluid, considering the operating life of a triplex pump. The maximum capacities can be obtained only to approximately 5,000 to 6,000 ft. These jet pump figures are only guidelines. The maximum capacities listed are for high-volume jet pumps that require BHAs that are incapable of accommodating piston pumps.

Hydraulic Pumping Advantages. Hydraulic pumping has the following advantages.
  • Being able to circulate the pump in and out of the well is the most obvious and significant feature of hydraulic pumps. It is especially attractive on offshore platforms, remote locations, and populated and agricultural areas.
  • Positive-displacement pumps are capable of pumping depths to 17,000 ft and deeper. Working fluid levels for jet pumps are limited to approximately 9,000 ft.
  • By changing the power-fluid rate to the pumps, production can be varied from 10 to 100% of pump capacity. The optimum speed range is 20 to 85% of rated speed. Operating life will be significantly reduced if the pump is operated above the maximum-rated speed.
  • Deviated wells typically present few problems to hydraulic free pumps. Jet pumps can even be used in through flowline installations.
  • Jet pumps, with hardened nozzle throats, can produce sand and other solids.
  • There are methods in which positive-displacement pumps can handle viscous oils very well. The power fluid can be heated, or it can have diluents added to further aid lifting the oil to the surface.
  • Corrosion inhibitors can be injected into the power fluid for corrosion control. Added fresh water can solve salt-buildup problems.

Hydraulic Pumping Disadvantages. Hydraulic pumping has the following disadvantages.

  • Removing solids from the power fluid is very important for positive-displacement pumps. Solids in the power fluid also affect surface-plunger pumps. Jet pumps, on the other hand, are very tolerant of poor power-fluid quality.
  • Positive-displacement pumps, on average, have a shorter time between repairs than jet, sucker rod, and ESPs. Mostly, this is a function of the quality of power fluid but, on average, the positive-displacement pumps are operating from greater depths and at higher strokes per minute than for a beam pump system. Jet pumps, on the other hand, have a very long pump life between repairs without solids or if not subjected to cavitation. Jet pumps typically have lower efficiency and higher energy costs.
  • Positive-displacement pumps can pump from a low BHP (< 100 psi) in the absence of gas interference and other problems. Jet pumps cannot pump from such low intake pressures, especially when less than the cavitation pressure. Jet pumps require approximately 1,000 psi BHP when set at 10,000 ft and approximately 500 psi when set at 5,000 ft.
  • Positive-displacement pumps generally require more maintenance than jet pumps and other types of artificial lift because pump speed must be monitored daily and not allowed to become excessive. Power-fluid-cleaning systems require frequent checking to keep them operating at their optimum effectiveness. Also, well testing is more difficult.

When should a jet be used, and when should a positive-displacement hydraulic pump be used? One possible answer is to use jet pumps if the flowing (pumping) BHP is large enough because the pressure drawdown capability for the jet system is inferior to that of the reciprocating pump. Other factors enter in as well as those mentioned previously. Jet pumps typically have low pump-repair costs but have high energy-consumption expenses because of low pump efficiencies, usually less than 35%. However, for both systems, a higher pump-failure rate can be very acceptable if a free system is present and the pumps can be retrieved quickly (less than 30 minutes typically) without pulling the tubing.

Gas Lift

Gas lift is used extensively around the world and dominates production in the U.S. Gulf Coast. Most of these wells are on continuous-flow gas lift. This section addresses the following issues: Why choose gas lift?; Where should continuous flow be used?; and When should intermittent lift be selected?

The principle of gas lift is that gas injected into the tubing reduces the density of the fluids in the tubing, and the bubbles have a "scrubbing" action on the liquids. Both factors act to lower the flowing BHP at the bottom of the tubing. Care must be exercised not to inject excess gas, or friction will begin to negate the desirable effects of injecting gas into the tubing.

Continuous-Flow Gas Lift. Fig. 10.10 shows a schematic of a gas-lift system. Continuous-flow gas lift is recommended for high-volume and high-static BHP wells in which major pumping problems could occur with other artificial lift methods. It is an excellent application for offshore formations that have a strong waterdrive, or in waterflood reservoirs with good PIs and high gas/oil ratios (GORs). When high-pressure gas is available without compression or when gas cost is low, gas lift is especially attractive. Continuous-flow gas lift supplements the produced gas with additional gas injection to lower the intake pressure to the tubing, resulting in lower formation pressure as well.

A reliable, adequate supply of good quality high-pressure lift gas is mandatory. This supply is necessary throughout the producing life of the well if gas lift is to be maintained effectively. In many fields, the produced gas declines as water cut increases, requiring some outside source of gas. The gas-lift pressure typically is fixed during the initial phase of the facility design. Ideally, the system should be designed to lift from just above the producing zone. Wells may produce erratically or not at all when the lift supply stops or pressure fluctuates radically. Poor gas quality will impair or even stop production if it contains corrosives or excessive liquids that can cut valves or fill low spots in delivery lines. The basic requirement for gas must be met, or gas lift is not a viable lift method.

Continuous-flow gas lift imposes a relatively high backpressure on the reservoir compared with pumping methods; therefore, production rates are reduced. Also, power efficiency is not good compared with some artificial lift methods, and the poor efficiency significantly increases both initial capital cost for compression and operating energy costs.

Gas Lift Advantages. Gas lift has the following advantages.
  • Gas lift is the best artificial lift method for handling sand or solid materials. Many wells produce some sand even if sand control is installed. The produced sand causes few mechanical problem in the gas-lift system; whereas, only a little sand plays havoc with other pumping methods, except the PCP type of pump.
  • Deviated or crooked holes can be lifted easily with gas lift. This is especially important for offshore platform wells that are usually drilled directionally.
  • Gas lift permits the concurrent use of wireline equipment, and such downhole equipment is easily and economically serviced. This feature allows for routine repairs through the tubing.
  • The normal gas-lift design leaves the tubing fully open. This permits the use of BHP surveys, sand sounding and bailing, production logging, cutting, paraffin, etc.
  • High-formation GORs are very helpful for gas-lift systems but hinder other artificial lift systems. Produced gas means less injection gas is required; whereas, in all other pumping methods, pumped gas reduces volumetric pumping efficiency drastically.
  • Gas lift is flexible. A wide range of volumes and lift depths can be achieved with essentially the same well equipment. In some cases, switching to annular flow also can be easily accomplished to handle exceedingly high volumes.
  • A central gas-lift system easily can be used to service many wells or operate an entire field. Centralization usually lowers total capital cost and permits easier well control and testing.
  • A gas-lift system is not obtrusive; it has a low profile. The surface well equipment is the same as for flowing wells except for injection-gas metering. The low profile is usually an advantage in urban environments.
  • Well subsurface equipment is relatively inexpensive. Repair and maintenance expenses of subsurface equipment normally are low. The equipment is easily pulled and repaired or replaced. Also, major well workovers occur infrequently.
  • Installation of gas lift is compatible with subsurface safety valves and other surface equipment. The use of a surface-controlled subsurface safety valve with a ¼-in. control line allows easy shut in of the well.
  • Gas lift can still perform fairly well even when only poor data are available when the design is made. This is fortunate because the spacing design usually must be made before the well is completed and tested.

Gas Lift Disadvantages. Gas lift has the following disadvantages.

  • Relatively high backpressure may seriously restrict production in continuous gas lift. This problem becomes more significant with increasing depths and declining static BHPs. Thus, a 10,000-ft well with a static BHP of 1,000 psi and a PI of 1.0 bpd/psi would be difficult to lift with the standard continuous-flow gas-lift system. However, there are special schemes available for such wells.
  • Gas lift is relatively inefficient, often resulting in large capital investments and high energy-operating costs. Compressors are relatively expensive and often require long delivery times. The compressor takes up space and weight when used on offshore platforms. Also, the cost of the distribution systems onshore may be significant. Increased gas use also may increase the size of necessary flowline and separators.
  • Adequate gas supply is needed throughout life of project. If the field runs out of gas, or if gas becomes too expensive, it may be necessary to switch to another artificial lift method. In addition, there must be enough gas for easy startups.
  • Operation and maintenance of compressors can be expensive. Skilled operators and good compressor mechanics are required for reliable operation. Compressor downtime should be minimal (< 3%).
  • There is increased difficulty when lifting low gravity (less than 15°API) crude because of greater friction, gas fingering, and liquid fallback. The cooling effect of gas expansion may further aggravate this problem. Also, the cooling effect will compound any paraffin problem.
  • Good data are required to make a good design. If not available, operations may have to continue with an inefficient design that does not produce the well to capacity.

Potential gas-lift operational problems that must be resolved include freezing and hydrate problems in injection gas lines, corrosive injection gas, severe paraffin problems, fluctuating suction and discharge pressures, and wireline problems. Other problems that must be resolved are changing well conditions, especially declines in BHP and PI; deep high-volume lift; and valve interference (multipointing). Additionally, dual gas lift is difficult to operate and frequently results in poor lift efficiency. Finally, emulsions forming in the tubing, which may be accelerated when gas enters opposing the tubing flow, also must be resolved.

Intermittent Gas Lift

The intermittent gas-lift method typically is used on wells that produce low volumes of fluid (approximately < 150 to 200 B/D), although some systems produce up to 500 B/D. Wells in which intermittent lift is recommended normally have the characteristics of high PI and low BHP or low PI with high BHP. Intermittent gas lift can be used to replace continuous gas lift on wells that have depleted to low rates or used when gas wells have depleted to low rates and are hindered by liquid loading.

If an adequate, good quality, low-cost gas supply is available for lifting fluids from a relatively shallow, high GOR, low PI, or low BHP well with a bad dogleg that produces some sand, then intermittent gas lift would be an excellent choice. Intermittent gas lift has many of the same advantages/disadvantages as continuous-flow gas lift, and the major factors to be considered are similar. Only the differences are highlighted in the following discussion. If plunger lift can be used instead of only intermittent lift, the efficiency will be higher. This difference could determine the success or failure of the system.

Intermittent Gas Lift Advantages. Intermittent gas lift has the following advantages.

  • Intermittent gas lift typically has a significantly lower producing BHP than continuous gas-lift methods.
  • It has the ability to handle low volumes of fluid with relatively low production BHPs.

Intermittent Gas Lift Disadvantages. Intermittent gas lift has the following disadvantages.

  • Intermittent gas lift is limited to low volume wells. For example, an 8,000-ft well with 2-in. nominal tubing can seldom be produced at rates of more than 200 B/D with an average producing pressure much below 250 psig.
  • The average producing pressure of a conventional intermittent lift system is still relatively high when compared with rod pumping; however, the producing BHP can be reduced by use of chambers. Chambers are particularly suited to high PI, low BHP wells.
  • The power efficiency is low. Typically, more gas is used per barrel of produced fluid than with constant flow gas lift. Also, the fallback of a fraction of liquid slugs being lifted by gas flow increases with depth and water cut, making the lift system even more inefficient. However, liquid fallback can be reduced by the use of plungers, where applicable.
  • Fluctuations in rate and BHP can be detrimental to wells with sand control. The produced sand may plug the tubing or standing valve. Also, pressure fluctuations in surface facilities cause gas- and fluid-handling problems.
  • Intermittent gas lift typically requires frequent adjustments. The lease operator must alter the injection rate and time period routinely to increase the production and keep the lift gas requirement relatively low.

Gas lift has numerous strengths that can make it the best choice of artificial lift; however, there are limitations and potential problems. One has a choice of the use of either continuous flow for high volume wells or intermittent for low volume wells; there is little difficulty in switching from one to the other. In addition, gas lift can be used to kick off wells, unload water from gas wells, or backflow injection wells. Gas lift deserves serious consideration as a means of artificial lift; however, it is not energy efficient and continuous gas lift does not achieve a low BHP at the formation, compared with well operating pumping systems.

Other Lift Methods

Plunger lift commonly is used to remove liquids from gas wells or produce relatively low volume, high GOR oil wells. Plunger lift is important and, in its most efficient form, will operate with only the energy from the well. Fig. 10.11 shows a schematic of a plunger lift installation. A free-traveling plunger and produced-liquid slug is cyclically brought to the surface of the well from stored gas pressure in the casing-tubing annulus and from the formation. In the off cycle, the plunger falls and pressure builds again in the well. A new two-piece plunger (cylinder with ball underneath) can lift fluids when the components are together, but both components are designed to fall when separate. Use of this plunger allows a shut-in portion of the operational cycle that is only a few seconds long, resulting in more production for many wells.

There is a chamber pump that relies on gas pressure to periodically empty the chamber and force the fluids to the surface, which is essentially a gas-powered pump. There are variations of gas lift and intermittent lift, such as chamber lift. Not all possible variations of artificial lift can be discussed; however, the principles presented apply to the selection of all methods that might be considered.

Selection Methods

Selection by Consideration of Depth/Rate System Capabilities

This section discusses various selection techniques. Some of the following discussion is after material from a pair of sources.[5][6]

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.[7] Figs. 10.12 and 10.13 are slightly altered versions of information from "5 Steps to Artificial Lift Optimization,"[8] and are probably more accurate because they are more recent. Minimums for method applications are not shown in the charts from the same source.[8] 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. 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 introducing the artificial lift methods, the depth-rate charts are tools for artificial lift selection or quick elimination of possibilities.

Selection by Advantages and Disadvantages

Although previous sections detailed the major artificial lift systems, more detailed listings of advantages and disadvantages are available from various sources. Neely et al.[9] contains a brief summary of advantages, disadvantages, and selection criteria for various artificial lift systems presented by experts in a forum discussion. Tables 10.3 and 10.4[10] provide a useful summary of the advantages and disadvantages of the various artificial lift systems. Some were discussed previously when introducing each system.

Clegg, Bucaram, and Hein[11] 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 the same source[11] is a very useful tool for artificial lift selection.

Tables 10.5 through 10.7 present the information in the selection tables from Clegg, Bucaram, and Hein.[11] Some of the details in the tables have been updated, but the majority of the work is from the original authors. These tables are 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[7][8] and this extensive set of tables of artificial lift capabilities.[11] Very severe conditions and special conditions can require further study. Also, a quantitative economic assessment is not possible with the charts and tables.

Selection by 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. A few sources[12][13][14] deal with expert systems for the selection of artificial lift systems.

Espin, Gasbarri, and Chacin[12] describes an expert system with selection criteria on sucker rod, hydraulic pump, ESP, progressive pump, continuous gas lift, intermittent gas lift, intermittent gas lift with plunger, constant slug injection gas lift, chamber gas lift, and conventional plunger lift. 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, Gasbarri, and Chacin[12] 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, Gasbarri, and Chacin[12] also gives other details for knowledge representation and technical and economic evaluation.

Heinze, Thonberry, and Wit[13] 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. Problems—such as sand, paraffin, crooked hole, corrosion, small casing, flexibility, and scale—are used with the stored knowledge base and user input to allow the program to rank the most appropriate artificial lift method for the particular conditions.

Valentin and Hoffman[14] describes another encompassing expert system. It describes the optimum pumping-unit search program, which consists of a knowledge base containing the complete set of specific information on the domain of expertise, an inference engine with the data and heuristics of the knowledge base to solve the problem, and interactive modules enabling very simple use of the expert system. Another interesting feature[14] is the presentation of economical 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 the failure rates of the system components, fuel costs, maintenance costs, inflation rates, anticipated revenue from produced oil and gas, and other factors that may vary from system to system. A few sources[15][16][17] are example studies that follow economically guided selection techniques. Several sources[18][19][20][21][22][23][24][25][26] 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. The methods considered are ESP, gas lift, hydraulic pump, and rod pump. An enhanced method of analysis similar to the NPV comparison method is available from Kol and Lea.[17]

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 10.1

Consider a vertical well with the characteristics given in Table 10.8. 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 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 10.9 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. 10.14 plots the summary of the cumulative 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. 10.14, and the results are tabulated in Table 10.10.

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 10.1 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. 10.15 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. 10.16 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. 10.15. 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. 10.17 shows ESP run lives for various fields. These data were collected and presented in Kol and Lea[17] 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. 10.17.

Lea and Patterson[5] and Lea and Nickens[6] 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[17] contains additional information on the conditions in these fields. Fig. 10.17 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, Table 10.11[6] shows downhole hydraulic pump lives for a collection of fields. Lea and Nickens[6] presents the conditions for these fields. The average life of the 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.


This chapter presents information on the various methods available for the selection of the best artificial lift system for given field conditions. The discussion presents selection methods covering depth-rate feasibility maps; tables of advantages and disadvantages; expert system programs containing feasibility, technical, and economic programs; and economic analysis methods such as present-value analysis.

Because the present-value method requires designs to meet target rates, the user is somewhat forced to evaluate harsh conditions, etc., during the course of the design. The user must then add gas separators, sand control, or whatever is necessary to meet target rates before the NPV analysis is performed. By necessity, various feasibility criteria must be considered; therefore, even if all data required for a complete economic analysis are not available, going through the analysis forces the user to consider or make best estimates of critical parameters, pointing to a better selection process.

Although some fairly complete expert systems for selection exist, their use is not widespread at this time. This may be a result of the constant updating required or because other types of selection processes that use experienced personnel may work as well or better. The lack of use also may be a result of the general lack of experience with these tools and a lack of understanding about the results that may be obtained from their use.


RTENOTITLE = average reservoir pressure, m/Lt2, psi
pb = bubblepoint pressure, m/Lt2, psi
pp = pump intake pressure, m/Lt2, psi
Vg = gas volume, L3, ft3
Vl = liquid volume at intake conditions, L3, ft3
s = skin (not rate dependent), dimensionless
Φ = dimensionless term to indicate gas problems at ESP intake


  1. 1.0 1.1 _
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  3. _
  4. _
  5. 5.0 5.1 _
  6. 6.0 6.1 6.2 6.3 _
  7. 7.0 7.1 _
  8. 8.0 8.1 8.2 8.3 8.4 _
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  10. _
  11. 11.0 11.1 11.2 11.3 _
  12. 12.0 12.1 12.2 12.3 _
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  14. 14.0 14.1 14.2 _
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  17. 17.0 17.1 17.2 17.3 _
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  26. 26.0 26.1 _

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SI Metric Conversion Factors

acre × 4.046 856 E + 03 = m2
°API 141.5/(131.5 + °API) = g/cm3
bbl × 1.589 873 E – 01 = m3
ft × 3.048* E – 01 = m
ft3 × 2.831 685 E – 01 = m3
°F (°F – 32)/1.8 = °C
hp × 7.460 43 E – 01 = kW
in. × 2.54* E + 00 = cm
psi × 6.894 757 E + 00 = kPa


Conversion factor is exact.