Most oil wells cannot flow to surface on their own reservoir energy for long - and many never can. Artificial lift is the collective term for the technologies that add energy to a well to bring fluids to surface once natural flow is insufficient. This guide explains what artificial lift is, the major methods, and the factors that drive method selection.
Artificial Lift in one line: Artificial lift is any method of adding energy to a producing well - by pumping, gas injection, or plunger action - to lift fluids to the surface when the reservoir's natural pressure is no longer enough to flow the well at the desired rate.
A well flows naturally as long as reservoir pressure can overcome the weight of the fluid column and the friction in the tubing. As a reservoir depletes, or as water cut rises and the column gets heavier, that natural drive weakens and production falls off or stops. Artificial lift restores or increases the rate by supplying the missing energy - either by physically pumping the fluid or by lightening the fluid column.
The great majority of the world's oil wells are on some form of artificial lift. In unconventional plays, wells often go on lift very early in life because they decline steeply, and the lift method may change several times as rates and conditions evolve.
Rod pumping (sucker rod / beam pumping) uses a surface pumping unit to reciprocate a downhole plunger pump - the classic pumpjack, dominant in lower-rate onshore wells. Electric submersible pumps (ESPs) are multistage centrifugal pumps run downhole on a power cable, suited to high volumes. Gas lift injects compressed gas into the tubing to lighten the fluid column, and works well with high gas-to-liquid wells and deviated wellbores.
Progressing cavity pumps (PCPs) use a rotor-and-stator screw pump, favored for viscous or sandy fluids. Plunger lift uses the well's own gas energy and a free-traveling plunger to sweep liquids off the bottom, common in gas wells that load up with liquid. Each has a distinct sweet spot in rate, depth, fluid, and cost.
Method selection weighs production rate, depth, deviation, gas and water content, solids, temperature, power availability, and capital versus operating cost. A high-volume offshore well leans ESP; a stripper well onshore leans rod pump; a gassy well may suit gas lift or plunger lift. Optimizing lift over the well's life is a continuous engineering task.
Every lift method depends on data: pump intake pressure and motor load for ESPs, dynamometer cards for rod pumps, injection rate for gas lift, cycle counts for plunger lift. SCADA collects these signals from field controllers, and a cloud platform such as Merobix can read them over Modbus so lift performance is tracked and alarmed across the whole field.
It is any way of adding energy to an oil or gas well to push fluids to the surface when the reservoir can no longer flow the well on its own - by pumping the fluid, injecting gas to lighten it, or using a plunger driven by the well's gas.
Rod (beam) pumping, electric submersible pumps (ESP), gas lift, progressing cavity pumps (PCP), and plunger lift are the primary methods. Each fits a different range of flow rate, depth, fluid type, and cost.
When reservoir pressure can no longer overcome the weight of the fluid column and tubing friction to deliver the target rate. This happens as the reservoir depletes or as water cut rises and the column gets heavier. Many wells go on lift early in their life.
This page references the protocol specifications published by the organizations below. Editions, product capabilities, and documentation change over time - confirm current requirements and specifications directly with the source.
Last reviewed: July 27, 2026. Merobix is not affiliated with, endorsed by, or sponsored by these organizations; their names are used only to identify the standards and products discussed.
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