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Field guide

Artificial Lift Methods: Which Lift for Which Well

Short answer: artificial lift adds energy to a well that can no longer flow on its own, or flow fast enough. The five main methods are rod lift (a beam pumping unit and a plunger pump), the electric submersible pump (ESP), the progressing cavity pump (PCP), gas lift, and plunger lift. Rate, gas, solids, depth and deviation, and the energy available on location decide which fits. On mature, declining oil wells, rod lift carries most of the load. ¹²⁸

By SRABS Engineering · October 18, 2026

Article / What is artificial lift?

What is artificial lift?

Artificial lift is any system that adds energy to the fluid column in a well, so the reservoir can produce, or produce more, after its own pressure is no longer enough to push fluid to surface. An industry estimate quoted in the Journal of Petroleum Technology puts 90% to 95% of the world's producing wells on some form of artificial lift. ¹

Every method works one of two ways:

Pumps (rod lift, ESP, PCP) sit below the fluid level and push liquid up the tubing. That lowers the flowing pressure at the bottom of the well, so more fluid flows in from the reservoir.
Gas (gas lift, plunger lift) lightens or carries the liquid instead. Gas lift injects gas to make the column lighter; plunger lift uses the well's own gas to push a slug of liquid up behind a free piston.

The rest of this guide takes each method in turn, then compares them side by side.

Article / The five main artificial lift methods

The five main artificial lift methods

schematic · five artificial lift methods by category

1. Rod lift (beam pumping)

A beam pumping unit at surface rocks a walking beam, which strokes a string of sucker rods up and down. At the bottom of the tubing, the rods work a plunger pump: on each upstroke the plunger lifts the fluid above it, and the pump barrel refills from the well below. The sucker rod pump guide walks through every component.

Rod lift is the most widely used method: a Southwestern Petroleum Short Course paper puts nearly two thirds of the world's producing oil wells on it. ² SPE's rod-lift webinar gives a typical range of 5 to 1,500 barrels of liquid a day from depths of 100 to 11,000 feet, with a total system efficiency of 45% to 60%. ³

Where it fits: land wells, lifting from low-pressure reservoirs, medium and light oil, and wells whose rates change a lot. It also fits locations that already have rod-lift infrastructure and experience, and locations with limited skilled service resources. ³
Where it struggles: gas and solids handling are rated only fair to good, the typical range for well deviation is 0 to 20 degrees, and offshore use is limited. ³ Rods also fail in ways the other methods don't: they buckle in compression, part from fatigue and corrosion, and take a beating from fluid pound.

2. Electric submersible pump (ESP)

An ESP hangs on the tubing near the bottom of the well: an electric motor at the bottom drives a stack of centrifugal pump stages above it, with a seal section between them and power sent down a cable from surface. Because the stages spin rather than stroke, an ESP moves large volumes from a small footprint.

That's why operators use ESPs to maximise production in a well's early, high-rate years. ⁸ Two things limit them on older, gassier wells:

Free gas. A centrifugal pump can't handle significant quantities of gas. Two-phase fluid, with phases that differ in density by orders of magnitude, has always been hard to pump. ⁷ Large gas slugs can make a pump overheat. ⁸
Sand. Abrasive sand chews up downhole pumps, and produced gas and sand together shorten pump life. ⁸

When an ESP fails, a rig has to pull the tubing to replace it.

3. Progressing cavity pump (PCP)

A PCP is a positive-displacement pump: a helical steel rotor turns inside a stator made of elastomer bonded to a steel tube, forming sealed cavities that move fluid steadily up the pump. In the usual setup, a drive head at surface turns the rod string, and the rods turn the rotor. ⁴ Flow doesn't pulse, because as one cavity closes the next one opens. ⁴

SPE's PCP webinar gives a typical range of 5 to 2,500 barrels a day from 2,000 to 6,000 feet, rates solids handling as excellent and gas handling as good, and puts total efficiency at 50% to 75%. ⁴ Most PCPs are deployed producing heavy, viscous oil with high sand content. ⁹

Where it fits: heavy oil and sandy wells on land. See the heavy oil guide for how the same wells treat a rod pump.
Where it struggles: the elastomer. The typical temperature range is 75 to 150°F, and the webinar lists the fit as oil "with low CO2, H2S, BTX": aromatic light crudes and sour service attack the stator. Offshore use is limited. ⁴

4. Gas lift

Gas lift injects gas, usually down the casing annulus, into the production tubing through gas-lift valves set at depth. The gas lightens the fluid column, so the reservoir's own pressure can push the liquid to surface. It runs continuously on most wells; intermittent gas lift suits lower-rate wells.

SPE's gas-lift webinar gives a typical range of 100 to 10,000 barrels a day, from 5,000 to 10,000 feet, in wells deviated up to 50 degrees. It rates gas handling excellent and solids handling good, and calls it excellent offshore. ⁵ In the Permian, operators found that gas lift is not affected by sand and that "gas lift likes gas." ⁸

Where it fits: high-volume and gassy wells, deviated and horizontal wells, sand, offshore, and wells with limited data. ⁵
Where it struggles: it needs a supply of injection gas and compression. ⁵⁸ Its typical system efficiency, 10% to 30%, is well below rod lift's 45% to 60% and the PCP's 50% to 75%, ³⁴⁵ and matching injection to changing wells takes skills in short supply. ⁸

5. Plunger lift

Plunger lift drops a free piston, the plunger, down the tubing while the well is shut in. When a controller opens the well, gas pressure that has built up below the plunger pushes it, and the slug of liquid above it, back to surface, where a lubricator catches it. No outside energy is needed in most cases: the well's own gas does the work. ¹⁰

SPE's plunger-lift webinar gives a typical range of 5 to 200 barrels a day, from 2,000 to 12,000 feet, with excellent gas handling and fair to good solids handling. ⁶ Typical applications are removing liquids from gas wells, high gas-to-oil ratio oil wells, paraffin and hydrate control, and improving intermittent gas lift. Low initial cost and very little maintenance are its advantages. ¹⁰

Where it fits: gas wells loading up with liquid, and oil wells with plenty of gas and low liquid rates.
Where it struggles: it can only lift what the well's own gas can carry, so liquid-rich wells without enough gas need another method. ¹⁰

Article / Artificial lift methods compared

Artificial lift methods compared

No method wins on every count. Each one trades rate against gas handling, solids, efficiency and the energy it needs on location.

Method	Typical liquid rate	Gas handling	Solids handling	Energy at the well
Rod lift	5–1,500 bbl/d ³	Fair to good ³	Fair to good ³	Electric motor or gas engine ³
ESP	High; the usual choice for high early rates ⁸	Poor with free gas ⁷	Sand shortens pump life ⁸	Downhole electric motor, cable from surface
PCP	5–2,500 bbl/d ⁴	Good ⁴	Excellent ⁴	Electric motor or gas engine ⁴
Gas lift	100–10,000 bbl/d ⁵	Excellent ⁵	Good ⁵	Compressed injection gas ⁵
Plunger lift	5–200 bbl/d ⁶	Excellent ⁶	Fair to good ⁶	The well's own gas ⁶

Typical ranges for rod lift, PCP, gas lift and plunger lift come from one SPE webinar series, so they compare like for like. Each deck lists higher maximums that need special analysis. ³⁴⁵⁶

Article / How to choose artificial lift for a mature well

How to choose artificial lift for a mature well

Start with what the well makes today and how fast it is declining, then rule out methods on gas, solids, fluid and wellbore, and choose among the rest on what a failure costs. The classic SPE comparison of lift methods frames selection the same way: screen each method against the well's conditions. ¹²

Rate and decline. A method sized for today's rate may be oversized in two years. Plunger lift and rod lift cover the lowest rates; ESPs and gas lift the highest. ³⁵⁶⁸
Gas. High gas-to-liquid ratios favour gas lift and plunger lift. Pumps need the gas separated before it reaches the intake; on a rod pump, too much free gas shows up as gas interference or gas lock. ⁵⁶⁷
Solids and fluid. Sand and heavy, viscous oil point to PCPs, if temperature and fluid chemistry suit the elastomer. ⁴⁹
Wellbore. Deviated and horizontal wells favour gas lift, though rod lift has been used to produce highly deviated and horizontal wells with the right equipment. ⁵¹¹
Energy and people. Gas lift needs gas and compression. ⁵ Rod lift suits locations with rod-lift infrastructure and experience, and with limited skilled service resources. ³
Lifecycle cost. On a low-rate well, the biggest cost is usually the failure: every pull is a rig, parts and lost production. See workover cost and stripper well economics.

Article / How lift changes as a well declines

How lift changes as a well declines

Most wells change lift method at least once. A common pattern is to start on a high-rate method and move to rod lift as the rate falls.

The Permian shows the pattern. JPT reported that the standard routine was to use ESPs first, to maximise production in a well's early years while the rate was high enough to lift efficiently with an ESP. As production dropped below that, wells were switched to a lower-cost rod pump: "Late in the life of wells, rod pumps remain the standard." More operators have since moved the early, high-rate stage from ESPs to gas lift. ⁸

At the very end of a well's life, plunger lift or intermittent gas lift can keep low-rate, gassy wells producing at very low cost. ¹⁰

Article / Where rod lift struggles, and the fixes

Where rod lift struggles, and the fixes

Because rod lift ends up running most mature wells, its failure modes decide most of the economics of a mature field. Each one has a guide of its own:

Rod buckling on the downstroke wears tubing and parts rods: sucker rod buckling and sinker bars and rod guides.
Fluid pound when the pump outruns inflow: fluid pound and pump-off controllers vs. AI well control.
Gas at the pump intake: gas-locked rod pump.
Not knowing the fluid level until something breaks: how to shoot a fluid level.
Reading what the pump is doing: the dynamometer card atlas.

For any term in this guide, see the glossary.

Article / Where SRABS fits

Where SRABS fits

SRABS is built for the rod-pumped well. In the system page's words, SRABS is "an anti-buckling rod pump, a real fluid-level listener, and an AI brain coordinating both on mature wells." The SRABS Pump is "a mechanically re-engineered sucker rod pump that keeps the rod string in tension where it would otherwise buckle." See the system, solutions and how it works.

To estimate what fewer failures would mean for your fleet, run the ROI calculator. Its default 100-well scenario is modelled, not a field result.

Article / The bottom line

The bottom line

Lift selection is not a one-time decision. High-rate methods earn their keep early in a well's life; on the long, low-rate tail, the question becomes which method fails least and costs least to fix. For most mature oil wells, that is rod lift, so the biggest gains come from making rod lift fail less.

See how that plays out on a real well.

Loan us a well →

Article / FAQ

FAQ

What are the main types of artificial lift?

The five main methods are rod lift (a beam pumping unit and a downhole plunger pump), the electric submersible pump (ESP), the progressing cavity pump (PCP), gas lift and plunger lift. The first three are pumps that push liquid up the tubing; gas lift and plunger lift use gas to lighten or carry the liquid instead.

Which artificial lift method is most common?

Rod lift. A Southwestern Petroleum Short Course paper puts nearly two thirds of the world's producing oil wells on sucker rod lift. More broadly, an industry estimate in the Journal of Petroleum Technology says 90% to 95% of the world's producing wells use some form of artificial lift.

What is the difference between an ESP and a rod pump?

An ESP is a downhole centrifugal pump driven by an electric motor at the bottom of the well, suited to high rates but sensitive to free gas and sand. A rod pump is a plunger pump stroked by sucker rods from a beam unit at surface, suited to the low and declining rates of most mature wells.

When should a well switch from ESP to rod pump?

When the rate has fallen far enough that a rod pump can make it at lower cost. In the Permian, the standard routine was to run ESPs in a well's early high-rate years and switch to a lower-cost rod pump once the rate dropped below what an ESP lifts efficiently. Late in a well's life, rod pumps remain the standard.

Which artificial lift method is best for low-rate stripper wells?

Usually rod lift, or plunger lift where the well has enough gas. Rod lift covers low liquid rates from almost any depth on land and suits locations with limited skilled service resources. Plunger lift needs no outside energy, but only lifts what the well's own gas can carry.

Article / Sources

Sources

Beckwith, R., "Legends of Artificial Lift—Part 1," Journal of Petroleum Technology, September 30, 2014. https://jpt.spe.org/legends-artificial-lift-part-1
Green, J., "Basic Methods for Improving Rod Pump Operations," Southwestern Petroleum Short Course. https://www.swpshortcourse.org/paper/basic-methods-improving-rod-pump-operations
Chokshi, R., Lane, B., "Reciprocating Rod Lift (RRL)," SPE Artificial Lift webinar series, webinar 2, September 23, 2014. https://file.streaming.spe.org/wp-content/uploads/2024/02/22131640/Reciprocating-Rod-Lift-RRL-.pdf
Lane, B., "Progressing Cavity Pumps," SPE Artificial Lift webinar series, webinar 4, November 19, 2014. https://file.streaming.spe.org/wp-content/uploads/2024/02/22131547/Progressing-Cavity-Pumping-PCP-.pdf
Chokshi, R., Lane, B., "Gas-Lift," SPE Artificial Lift webinar series, webinar 3, October 21, 2014. https://file.streaming.spe.org/wp-content/uploads/2024/02/22132153/Gas-Lift-.pdf
Albers, D., "Plunger Lift and Capillary Deliquification," SPE Artificial Lift webinar series, webinar 7, February 10, 2015. https://file.streaming.spe.org/wp-content/uploads/2024/02/22131617/Plunger-Lift-and-Capillary-Deliquification-.pdf
Wilson, B. L., "Problems and Solutions for ESPs in Gassy Environments," Southwestern Petroleum Short Course. https://www.swpshortcourse.org/paper/problems-and-solutions-esps-gassy-environments
Rassenfoss, S., "Gas Lift Use Grows in Permian," Journal of Petroleum Technology, November 8, 2016. https://jpt.spe.org/gas-lift-use-grows-permian
Adair, R. L., Kramer, T., "New Technologies for PC Pumps," Southwestern Petroleum Short Course. https://www.swpshortcourse.org/paper/new-technologies-pc-pumps
Beauregard, E., Ferguson, P., "Introduction to Plunger Lift Applications, Advantages, Limitations," Southwestern Petroleum Short Course. https://www.swpshortcourse.org/paper/introduction-plunger-lift-applications-advantages-limitations
Hein, N. W., Jr., DaCunha, J., Long, S., Mahoney, M., Stephens, R., "Sucker Rod Lifting Horizontal and Highly Deviated Wells," Southwestern Petroleum Short Course. https://www.swpshortcourse.org/paper/sucker-rod-lifting-horizontal-and-highly-deviated-wells
Clegg, J. D., Bucaram, S. M., Hein, N. W., Jr., "Recommendations and Comparisons for Selecting Artificial-Lift Methods," Journal of Petroleum Technology 45(12), 1993, pp. 1128–1167. https://doi.org/10.2118/24834-PA