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Overview of Artificial Lift Systems Kermit E. Brown, SPE, U. ofTulsa Summary This paper gives guidelines to assist in the selection of One serious limitation to artificial lift installations has artificial lift methods. The most important guideline is been the installation of small casing sizes, whi...

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Overview of Artificial Lift Systems Kermit E. Brown, SPE, U. ofTulsa

Summary This paper gives guidelines to assist in the selection of artificial lift methods. The most important guideline is determination of the flow rates possible by each method. This requires preparation of pressurelflow rate diagrams combining well-inflow performance relationships with tubing intake curves. The tubing intake curve includes pressure loss in the complete piping system and/or pressure gains by the pumping method. Many other factors other than rate, such as location, retrievability by wireline, corrosion, paraffin, scale deposition, cost, operating life, and others, influence the final selection of lift equipment.

Introduction This paper provides an overview of artificial lift systems and gives guidelines indicating when one system is better to use than another. Advantages and disadvantages are given with examples in the selection oflift methods. This list represents the relative standing of lift systems based on the number of installations throughout the world: (1) sucker rod pumping (beam pumping), (2) gas lift, (3) electric submersible pumping, (4) hydraulic piston pumping, (5) hydraulic jet pumping, (6) plunger (free-piston) lift, and (7) other methods. This differs according to field, state, and country. New lift systems are being developed and tested continually. The lifting of heavy viscous crude oils requires special attention, and methods designed specifically for this purpose are being tested. Wells located offshore and in deep water present specific problems, and surfacespace limitations become important. The artificial lift method should be considered before the well is drilled. Obviously this cannot be done on wildcat wells, but it must be done on all subsequent development wells. The drilling program must be set out to ensure hole sizes that permit adequate casing and tubing sizes. 0149-213618210010-9979$00.25 Copyright 1982 Society of Petroleum Engineers of AIME

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One serious limitation to artificial lift installations has been the installation of small casing sizes, which limits the installation to specific tubing sizes to obtain the objective flow rate and, in particular, limits the size of retrievable gas lift equipment and/or pumping equipment. The installation of gas-lift mandrels that accept only I-in. (2.5-cm) OD gas-lift valves is common in the U.S., and serious limitations on gas passage volumes are imposed on the system with this small valve. Also, the better performance characteristics of the IIh-in. (3.8I-cm) OD valve are lost. For the pumping systems, the smaller capacity pumps must be used in the smaller casing sizes, and sometimes the advantage of retrievable pumps is lost. Surface-space limitations become an important factor. For example, if large compressors for gas lift or large generators for electrical pumping are anticipated for offshore platforms, provisions must be made in the original design to allow for both weight and space on the platforms. Some engineers are invariably optimistic about natural flow in the planning stage, and in many instances they still maintain that artificial lift will not be required during the life of a field. This leads to very poor planning, especially on offshore facilities. In the design of artificial lift systems for a well, it is recommended that it initially be treated as if it were a flowing well-i.e., a production systems graph should be prepared to see if the well is capable of flowing and, if it is, at what rate. The artificial lift analysis can be placed on the same plot. Numerous flowing wells will show increased flow rates when placed on artificial lift. The purpose of any artificial lift system is to create a predetermined tubing intake pressure such that the reservoir may respond and produce the objective flow rate. The design and analysis of any lifting system can be divided into two main components. The first is the reservoir component (inflow performance relationship), which represents the well's ability to produce fluids. The JOURNAL OF PETROLEUM TECHNOLOGY

TABLE 1-RELATIVE ADVANTAGES OF ARTIFICIAL LIFT SYSTEMS· Electric Submersible Pumping Not so depth limited- Can lift extremely can lift large volumes high volumes, 20,000 BID from great depths, 500 BID (79.49 m 3 /d), (19078 m 3 /d), in Units easily changed shallow wells with to other wells with from 15,000 ft (4572 m). Have been large casing. Currently minimum cost. lifting ± 120,000 BID installed to 18,000 ft (19068 m 3 /d) from Efficient, simple (5486.4 m). water supply wells in and easy for field people to operate. Crooked holes present Middle East with 600-hp (448-kW) units; minimal problems. 720-hp (537-kW) Applicable to slim Unobtrusive in urban available, 1,OOO-hp holes and multiple (746-kW) under locations. completions. development. Can pump a well down Power source can be Unobtrusive in urban remotely located. to very low pressure locations. (depth and rate Analyzable. dependent). Simple to operate. System usually is Flexible-can usually Easy to install naturally vented for match displacement downhole pressure to well's capability gas separation and sensor for telemetering fluid level soundings. as well declines. pressure to surface via cable. Flexible-can match Can use gas or displacement rate to electricity as Crooked holes present well capability as well power source. no problem. declines. Downhole pumps can be circulated out in Applicable offshore. Analyzable. free systems. Corrosion and scale Can lift hightreatment easy to Can pump a well temperature and perform. viscous oils. down to fairly low pressure. Availability in Can use gas or different size. electricity as power Applicable to multiple completions. source. Lifting cost for high volumes generally Corrosion and $cale Applicable offshore. very low. treatments easy to Closed system will perform. combat corrosion. Applicable to pump Easy to pump in off control if cycles by time clock. electrified.

Rod Pumping Relatively simple system design.

Availability of different sizes. Hollow sucker rods are available for slim hole completions and ease of inhibitor treatment.

Hydraulic Piston Pumping

Gas Lift Can handle large volume of solids with minor problems.

Hydraulic Jet Pump Retrievable without pulling tubing. Has no moving parts.

Handles large volume in high-PI wells (continuous lift), 50,000 BID (7949.37 m 3 /d). Fairly flexibleconvertible from continuous to intermittent to chamber or plunger lift as well declines. Unobtrusive in urban locations. Power source can be remotely located. Easy to obtain downhole pressures and gradients. Lifting gassy wells is no problem.

No problems in deviated or crooked holes. Unobtrusive in urban locations.

Plunger Lift Retrievable without pulling tubing. Very inexpensive installation. Automatically keeps tubing clean of paraffin, scale. Applicable for high gas oil ratio wells.

Applicable offshore. Can use water as a power source. Power fluid does not have to be so clean as for hydraulic piston pumping.

Can be used in conjunction with intermittent gas lift. Can be used to unload liquid from gas wells.

Corrosion scale emulsion treatment easy to perform. Power source can be remotely located and can handle high volumes to 30,000 BID (4769.62 m 3 /d).

Sometimes serviceable with wireline unit. Crooked holes present no problem. Corrosion is not usually as adverse. Applicable offshore.

Adjustable gear box for Triplex offers more flexibility. Mixing power fluid with waxy or viscous crudes can reduce viscosity.

Have pumps with double valving that pump on both upstroke and downstroke. *Reprinted with permission from S. Gibbs. Nabla Corp., Midland, TX, with modifications by K. Brown. 1

second component represents the entire piping and artificial lift system. This includes separator, flowline, flowline restrictions such as chokes, tubing string, tubing string restrictions such as safety valves, and the artificial lift mechanism itself. Tubing intake pressures then can be determined for varying flow rates, and when this intake curve is placed on the same plot as the IPR curve, the rate for a particular lift method can be determined. These factors should be considered in the selection of artificial lift equipment: producing characteristics, fluid properties, hole characteristics, long-range recovery OCTOBER 1982

plan, surface facilities, location, available power sources, operating problems, completion type, automation, operating personnel, service availability, and economics. Tables I and 2 I summarize the advantages and the disadvantages of the principal methods that are commonly used.

Factors To Consider in Design Liquid Productive Capacity of the Well The desired rate from a particular well is the most significant factor in selecting the lift method. It is impor2385

TABLE 2-RELATIVE DISADVANTAGES OF ARTIFICIAL LIFT SYSTEMS' Electric Submersible Gas Lift Pumping Hydraulic Pumping Rod Pumping Lift gas is not Crooked holes present Power oil systems are Not applicable to multiple completions. always available. a fire hazard. a friction problem. High solids production is troublesome. Gassy wells usually lower volumetric efficiency. Is depth limited, primarily due to rod capability. Obtrusive in urban locations. Heavy and bulky in offshore operations.

Only applicable with Large oil inventory electric power. required in power oil system which detracts High voltages from profitability. (1,000 V) are necessary. High solids production is Impractical in troublesome. shallow, low-volume wells. Operating costs are sometimes higher. Expensive to change Usually susceptible equipment to match to gas interference- declining well capability. usually not vented.

Suseptible to paraffin problems.

Vented installations are more expensive because of extra tubing required.

Tubing cannot be internally coated for corrosion.

Treating for scale below packer is difficult.

H 2 S limits depth at which a large volume pump can be set.

Not easy for field personnel to troubleshoot.

Limitation of Difficult to obtain downhole pump design valid well tests in low volume wells. in small diameter casing. Requires two strings of tubing for some installations. Problems in treating power water where used.

Cable causes problems in handling tubulars. Cables deteriorate in high temperatures. System is depth limited, 10,000 ft (3048.0 m). due to cable cost and inability to install enough power downhole (depends on casing size). Gas and solids production are troublesome.

Not efficient in lifting small fields or one well leases. Difficult to lift emulsions and viscous crudes. Not efficient for small fields or one-well leases if compression eqUipment is required. Gas freezing and hydrate problems. Problems with dirty surface lines. Some difficulty in analyzing properly without engineering supervision. Cannot effectively produce deep wells to abandonment.

Hydraulic Jet Pumping Relatively inefficient lift method.

Plunger Lift

May not take well to depletion; hence, eventually requiring Requires at least 20o,-t, another lift method. submergence to Good for low-rate approach best lift efficiency. wells only normally less than 200 BID Design of system is (31.8 mid). more complex. Requires more Pump may cavitate engineering under certain supervision to adjust properly. conditions. Very sensitive to any change in backpressure.

Danger exists in plunger reaching too high a velocity and causing surface damage.

The producing of free gas through the pump causes reduction in Communication ability to handle between tubing liquids. and casing required for good operation unless used in Power oil systems are fire hazard. conjunction with gas lift. High surface power fluid pressures are required.

Requires makeup gas in rotative systems. Casing must withstand lift pressure.

Not easily analyzable Safety problem with high pressure gas. unless good engineering knowhow.

Safety problem for high surface pressure Lack of production rate flexibility. power oil. Loss of power oil in surface equipment failure.

Casing size limitation. Cannot be set below fluid entry without a shroud to route fluid by the motor. Shroud also allows corrosion inhibitor to protect outside of motor. More downtime when problems are encountered due to entire unitbeing downhole .

• Reprinted with permission from S. Gibbs, Nabla Corp., Midland, TXt with modifications by K. Brown. 1

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JOURNAL OF PETROLEUM TECHNOLOGY

tant to have sufficient data to construct pressurelflow rate diagrams, such as inflow performance curves shown in Fig. 1. This determination also is critical, depending on whether the objective flow rate is less that the maximum. An economic limit is reached when profits derived from increased oil production are offset by additional costs. To compare rates of different lift methods properly, it is necessary to establish tubing intake curves for each lift system (Fig. 2). The solution position for rate determination in Fig. 2 is taken at the bottom of the well, opposite the completion interval. The intersection of each intake curve with the well inflow performance (IPR) curve shows the flow rate for a particular lift method. The rates possible by each method will change depending on well conditions. Each well must be evaluated separately, and many factors control the flow rate. For example, the rate by gas lift may exceed all other methods if relatively high volumes of free gas must be handled by the pumping mechanism, whereas electrical pumping may show higher rates for high productivity water wells and low GOR oil wells. The procedures for preparation of these intake curves has been presented by Agena. 2 A short summary of the method of preparation is presented here. It is suggested that the first intake curve for any well will be prepared assuming that the well will flow naturally. Fig. 3 shows that this well does flow naturally. If the tubing intake curve falls above the IPR curve as noted in Fig. 3, the well is dead. Procedure for Preparation of Tubing Intake Curves. The tubing intake curve is prepared independently of the IPR curve (see Figs. 4a, 4b, and 4c). To prepare these curves, all pressure losses must be accounted for starting from the separator and summing up all losses and gains (in case of pumps) to the bottom of the well. All restrictions such as surface chokes, safety valves, and downhole restrictions must be accounted for. A brief description of the preparation of these curves is given in the following discussions and starts with the flowing well. The Flowing Well. Fig. 5 shows the various losses in pressures and corresponding pressure traverses for a flowing well. For clarification, this is divided into surface and downhole segments. For the simple system, the various restrictions such as surface chokes, etc. may be eliminated. Note that all losses are additive, beginning with the separator (constant pressure vs. rate for most applications). To construct tubing intake curves for a pressure vs. flow rate diagram, it is necessary to assume flow rates and to determine the corresponding tubing intake pressures. Typical results are shown in Fig. 4. The solution node or position can be taken anywhere in the system. Often it is taken at the wellhead or the separator to emphasize the effect of certain segments of the system. Fig. 6 shows a wellhead pressure solution, which isolates the effect of the flowline. Fig. 7 shows the solution taken at the separator to emphasize the effect of separator pressure. The separator pressure becomes increasingly important in rotative compressor gas-lift installations because OCTOBER 1982

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NATURAL FLOW (NF) BEAM PUMP (BP) HYDRAULIC PISTON - PUMPING (HP) JET PUMPING (JP) GAS LIFT (GL) __ｾＭｅｌｃｔｒｉａ＠ PUMPING (EP)

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2387

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ｒａｔｅｾ＠ e Fig. 4-(a) dead well, (b) dead well, (c) dead or severe heading well, (d) well flowing at Position 2, (3) stable flow.

the separator pressure controls the suction pressure to the compressor and, hence, controls horsepower requirements. Gas-Lift Well. The preparation of tubing intake curves is more complex for gas-lift wells. This is because the injection gas/liquid ratio becomes an additional unknown quantity. Figs. 8 and 9 show typical continuous flow gas-lift system plots, including a horizontal flowline. For gas-lift wells, the solution point to determine rate usually is taken at one of two nodes, at the bottom of the well or at the top of the well. Figs. 8 and 9 show the solution to the same problem taken at both nodes. If the solution point is taken at the bottom of the well, the well capability can be isolated. For IPR's at different average reservoir pressures, the node at the bottom of the well is 2388

a logical solution point. The tubing intake pressure curve represents the entire piping system, including separator pressure, flowline, any restrictions, and the tubing. By taking the solution at the surface (Fig. 9), the piping system has been separated. One curve represents the separator pressure and flowline; the other curve incorporates the tubing string and IPR of the well. Both solutions may be advisable. A final gas-lift well performance curve of oil flow rate vs. gas injection rate can be obtained from either plot. This final plot is essential for optimization (Fig. 10). For optimal allocation of gas to one well of a group, this type of curve is necessary. Pumping Systems. The preparation of tubing intake curves for pumping systems can be relatively simple, for JOURNAL OF PETROLEUM TECHNOLOGY

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