Artificial Lift: Rod Pumps, ESPs and Gas Lift, and What Each Sends to the Workshop

When a well stops flowing on its own, artificial lift keeps it producing. This page explains the five common methods, how each is installed on or inside the tubing string, and what arrives at a pipe yard or service shop when the lift system fails and the workover rig pulls it.

Artificial lift is any method of adding energy to a well that no longer flows to surface on reservoir pressure alone: sucker rod pumps, electric submersible pumps, gas lift, progressive cavity pumps and plunger lift. Each is installed on or inside the production tubing, and when it fails the tubing and its threaded accessories come back to a yard or service shop, which is where lift meets the bucking unit.

At a glance

Why lift is needed	Reservoir pressure declines and water cut rises; at some point the column of fluid in the tubing is heavier than the reservoir can push. Lift lowers the pressure the reservoir sees or moves the fluid mechanically
The five common methods	Sucker rod pumping, electric submersible pumps, gas lift, progressive cavity pumps and plunger lift; hydraulic and jet pumps in fewer wells
How each is installed	Rod pumps and PCPs on a rod string inside the tubing; ESPs on the bottom of the tubing with a power cable; gas-lift valves in mandrels threaded into the tubing; plungers free inside the tubing
What a failure pulls	Rods and a pump for rod lift; the whole tubing string for an ESP or a tubing-retrievable gas-lift valve; nothing but the plunger for plunger lift. Pulled tubing goes to a yard, pumps and mandrels to a shop
Decision this page supports	Predicting a field’s reconditioning workload from its lift methods, and specifying the bench and the break-out capacity behind it

What artificial lift is

A new well usually flows on its own. The reservoir pressure lifts oil and gas up the tubing and out of the tree. As the field produces, pressure falls, water enters the stream and the fluid column grows heavier, until one day the reservoir can no longer push it to surface. Almost every oil well reaches that day, and many gas wells reach a version of it when liquids load the tubing. Artificial lift is the family of methods that keep such wells producing, and the equipment-training literature lists the same handful of them: rod pumping, electric submersible pumps, gas lift, progressive cavity pumps and plunger lift (Kimray, 5 Common Methods of Artificial Lift), with hydraulic and jet pumps as less common alternatives (iFluids, Artificial Lift in Oil and Gas).

The lift method is a production engineering decision, made from the well’s rate, depth, gas fraction, sand, temperature and the field’s infrastructure. This page does not make that decision. It follows what the decision does to the tubing string, because every method changes what is threaded into the string, and therefore what comes back to a workshop when the method fails.

The five methods, and how each lives in the tubing

Method	How it is installed	What a failure pulls, and where it goes
Sucker rod pump	A beam unit at surface reciprocates a string of steel rods inside the tubing; a downhole pump, seated in the tubing near the bottom, lifts fluid on each stroke	The rods and the pump, by the rod string; the tubing stays unless it is holed or the pump seat has failed. Pump to a pump shop, rods to a rod yard
Electric submersible pump	A multistage centrifugal pump and its motor are made up to the bottom of the tubing and run in with a power cable strapped to the string; a tubing-deployed ESP needs a rig to change, and even a change of setting depth means pulling the tubing (PETEX, Artificial Lift Methods)	The whole tubing string, with the pump, motor and cable. Tubing to the pipe yard, ESP to its supplier’s shop, cable to scrap or test
Gas lift	Gas is injected down the annulus and enters the tubing through valves seated in mandrels that are threaded into the tubing string at design depths; wireline-retrievable valves can be changed through the tree, tubing-retrievable ones cannot	For a wireline-retrievable valve, only the valve, by wireline. For a tubing-retrievable valve or a mandrel problem, the whole string, tubing to the yard and mandrels to the completion shop
Progressive cavity pump	A rotor on a rod string turns inside a stator made up into the tubing; a surface drive rotates the rods. Suited to viscous, sandy fluid	The rotor with the rods; the stator only with the tubing. Stator and rotor to the pump shop, tubing to the yard if it is pulled
Plunger lift	A free plunger travels up and down the tubing, lifting liquid slugs on the well’s own gas; a bumper spring at the bottom and a lubricator at the top	The plunger and the bumper spring, through the tree. Nothing threaded is pulled, and the yard sees nothing

Two rows in that table drive workshop volume. An ESP failure or a tubing-retrievable gas-lift change pulls every joint of tubing in the well, and in a field with many such wells that is a steady stream of used pipe. The other methods pull rods and pumps, which go to their own specialist shops, and leave the tubing in the well most of the time.

What each method sends to the workshop

Pulled tubing from an ESP or gas-lift well arrives at a pipe yard as a full string, still made up, with the lift accessories threaded into it: the ESP discharge head and check valve at the bottom, or the gas-lift mandrels spaced along the string. The yard’s sequence is the one described in workover rig operations: break out every coupling and accessory on a horizontal hydraulic bucking unit, clean and inspect the joints, gauge the threads, drift the bore, scrap what fails, re-couple what passes, and record the make-up torque on every new coupling. The drift step, and what it does and does not prove, is in casing and tubing drift.

The lift accessories take their own path. Gas-lift mandrels are broken out from their pup joints, inspected, and made up onto fresh pups for the next installation, with the valve pockets protected; that is completion-shop work, and the shop is described in completion tool service shops and the make/break cell. ESP components go back to the pump supplier. Sucker rod pumps and PCP stators go to a pump shop, where they are stripped, re-fitted and bench tested. The rod string goes to a rod yard for inspection and re-threading; rod connections are made up with rod tongs to a displacement rule, which is a different trade from tubular make-up and is not bucking unit work.

The break-out load is the number that sizes the yard’s bench. Lift tubing has usually been in the well for years, carrying produced fluid inside and packer or annulus fluid outside, and its couplings and accessory connections do not release at the torque that made them up. The reasons are set out in what is breakout force, and a yard that reconditions ESP and gas-lift strings specifies its machine from that load first. Where the volume of pulled pipe is high, a dedicated breakout unit beside the make-up bench keeps the two jobs from competing for one machine.

The string that goes back in

A lift change is also a new installation, and the new string is prepared before the rig arrives. Reconditioned or new tubing comes from the yard with couplings made up and recorded. Gas-lift mandrels, with their valves or dummy valves, are made up onto pup joints in the completion shop at the spacing the design calls for, pressure tested and tagged in running order. The ESP is assembled at the wellsite by the supplier’s technicians, but the tubing above it, with its check valve, drain sub and cable protectors, is made up joint by joint on the rig with the workover crew’s tongs. As with any completion, the rig floor makes up the joint-to-joint connections, and the shop made up everything with a function; the pattern is set out in well completion explained.

That division has a record attached to it. The connection owner’s make-up torque applies on the bench and on the rig alike, and a field that changes lift systems often accumulates a long file of coupling traces and accessory traces per well. The value of that file shows on the next pull, when a joint that will not break out can be traced back to how it was made up.

Where artificial lift sits in the well’s life

Lift is production-phase equipment in the upstream sector, installed after completion and changed through the well’s life by workovers; the phase view is in upstream oil and gas. A mature field on rod pumps generates pump-shop and rod-yard work; a field on ESPs or gas lift generates pipe-yard work every time a well is pulled. Reading a region’s lift mix is therefore one of the better ways of predicting how much tubing reconditioning it will need, and how many benches that takes.

When another page is the better start

A production engineer choosing a lift method is making a well decision from rate, depth, gas, sand and infrastructure, and this site offers no guidance on it; the lift suppliers’ engineering data and the training literature cited above are the place to start. A pipe yard that already knows its tubing range and break-out loads should go to the bucking unit product page and the acceptance checklist, and should ask about jaws for corroded couplings and mandrels. A pump shop or rod yard is a different trade with different equipment, and this page has told it so. And a reader who wants to know what a whole workover does, beyond the lift change, should read the workover page first.

The usual limit applies. Make-up torques for tubing and accessories belong to the connection owners, and lift equipment specifications belong to the lift suppliers. This page describes what the lift method does to the string and where that string goes; it does not set any of the numbers.

Frequently asked questions

What is artificial lift?

Any method of adding energy to a well that no longer flows to surface on reservoir pressure alone, so that it keeps producing: sucker rod pumps, electric submersible pumps, gas lift, progressive cavity pumps and plunger lift are the common ones, with hydraulic and jet pumps in fewer wells. Most oil wells need some form of it during their life.

How does gas lift work?

Gas is injected down the casing-tubing annulus and enters the tubing through gas-lift valves seated in mandrels threaded into the string at design depths. The injected gas lightens the fluid column so the reservoir can push it to surface. Wireline-retrievable valves can be changed through the tree; tubing-retrievable ones require the string to be pulled.

What is an electric submersible pump?

A multistage centrifugal pump driven by a downhole electric motor, made up to the bottom of the production tubing and run in with a power cable strapped to the string. It suits high-rate wells. Because it is tubing-deployed, a failure or a change of setting depth means pulling the whole tubing string with a workover rig.

Which lift methods send tubing to a pipe yard?

Electric submersible pumps and tubing-retrievable gas lift, because any failure or change pulls the whole tubing string with the accessories threaded into it. Rod pumps and progressive cavity pumps usually pull only the rods and the pump, leaving the tubing in the well; plunger lift pulls nothing threaded. The lift mix of a field predicts its reconditioning workload.

Are sucker rod connections made up on a bucking unit?

No. Sucker rod couplings are made up with rod tongs to a circumferential displacement rule set by the rod manufacturer, and rods are inspected and re-threaded in rod yards with their own equipment. A bucking unit handles the tubing and the accessories threaded into it, mandrels, pump seating nipples and ESP subs, which are tubular connections.

Why is break-out torque the number that sizes a lift yard’s bench?

Because lift tubing has spent years in a producing well carrying produced fluid, and its couplings and accessory connections need more torque to release than the torque that made them up. A bench sized from the make-up table alone stalls on pulled strings. Yards with high volumes of pulled lift tubing often add a dedicated breakout unit beside the make-up bench.

Send the lift mix with the enquiry

A yard serving lift changes is quoted from the tubing it will see. The useful set for a bucking unit quotation is: the lift methods in the field and the share of wells on each, the tubing sizes and connection types, the accessories threaded into the strings (mandrels, ESP subs, pump seating nipples) with their dimensions, the highest break-out torque seen on pulled couplings, the condition of the pipe and the jaw protection needed, the monthly volume of joints, the record required per re-coupled joint, the site power supply and a sketch of the bay. The Galip team quotes from that list and will say whether the volume justifies a separate breakout unit.

The artificial lift checklist

• Record the lift method on every well the yard or shop serves; the method decides what a failure pulls.
• Expect ESP and tubing-retrievable gas-lift wells to send whole tubing strings; expect rod and PCP wells to send rods and pumps to other shops.
• Size the yard bench from the break-out torque on pulled lift tubing, with jaws for corroded couplings and mandrels.
• Route mandrels to a completion shop for inspection and re-make onto fresh pups; route ESPs, pumps and rods to their own specialists.
• Drift, gauge and inspect every reconditioned joint before it is re-coupled, and record the make-up torque on the new coupling.
• Prepare the next string in the shop: mandrels spaced and tested, couplings recorded, so the rig floor only makes up joint to joint.
• Keep the trace file per well across lift changes; it explains the next stubborn break-out.
• Decide whether a separate breakout unit is justified by the monthly volume of pulled lift tubing.