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Gas lift

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Gas lift is a method of artificial lift that uses an external source of high-pressure gas for supplementing formation gas to lift the well fluids. 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 bottomhole pressure (BHP) at the bottom of the tubing. There are two basic types of gas lift in use today—continuous and intermittent flow. This page briefly describes each method and its advantages and disadvantages.

Continuous-flow gas lift

The vast majority of gas lift wells are produced by continuous flow, which is very similar to natural flow. Fig. 1 shows a schematic of a gas-lift system. In continuous-flow gas lift, the formation gas is supplemented with additional high-pressure gas from an outside source. Gas is injected continuously into the production conduit at a maximum depth that depends upon the injection-gas pressure and well depth. The injection gas mixes with the produced well fluid and decreases the density and, subsequently, the flowing pressure gradient of the mixture from the point of gas injection to the surface. The decreased flowing pressure gradient reduces the flowing bottomhole pressure below the static bottomhole pressure thereby creating a pressure differential that allows the fluid to flow into the wellbore. Fig. 2 illustrates this principal.

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.

Numerical models enable the performance prediction of a well under continuous-flow gas lift. The applicability of these models depend on their class (mechanistic vs. empirical) and their underlying assumptions.


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 progressive cavity pump (PCP).
  • 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 1/4-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 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
  • Wireline problems

Other problems that must be resolved are:

  • Changing well conditions
  • Especially declines in BHP and productivity index (PI)
  • Deep high-volume lift
  • Valve interference (multipointing)

Additionally, dual gas lift is difficult to operate and frequently results in poor lift efficiency. Emulsions forming in the tubing, which may be accelerated when gas enters opposing the tubing flow, also must be resolved.

Intermittent-flow gas lift

As the name implies, intermittent flow is the periodic displacement of liquid from the tubing by the injection of high-pressure gas. The action is similar to that observed when a bullet is fired from a gun. (See Fig. 2.) The liquid slug that has accumulated in the tubing represents the bullet. When the trigger is pulled (gas lift valve opens), high-pressure injection gas enters the chamber (tubing) and rapidly expands. This action forces the liquid slug (shaded in Fig. 2) from the tubing in the same way that expanding gas forces the bullet from the gun. The disadvantage of intermittent-flow gas lift is the "on/off" need for high-pressure gas, which presents a gas-handling problem at the surface and causes surging in the flowing bottomhole pressure that cannot be tolerated in many wells producing sand. Because of the intermittent production of the well, intermittent-flow gas lift is not capable of producing at as high a rate as continuous-flow gas lift. Intermittent flow should not be considered unless the flowing bottomhole pressure is low, and the well is gas lifting from the bottom valve.

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 productivity index (PI) and low bottomhole pressure (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 gas/oil ratios (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 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 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 is particularly applicable for lifting fluids in wells that have a significant amount of gas produced with the crude. Gas compressors are nearly always installed to gather the produced gas and, with only minor changes, can be designed to supply the high injection-gas pressure for the gas lift system. The injected gas only supplements the formation gas and may amount to only a small percentage of the total produced-gas volume. Most continuous-flow wells can be depleted by gas lift because reservoir-pressure maintenance programs are implemented in most major oil fields and many reservoirs have waterdrives.

The flexibility of gas lift, in terms of production rates and depth of lift, can seldom be matched by other methods of artificial lift if adequate injection-gas pressure and volume are available. Gas lift is one of the most forgiving forms of artificial lift because a poorly designed installation will normally gas lift some fluid. The mandrel depths for many gas lift installations with retrievable-valve mandrels are calculated with minimal well information.

Highly deviated wells that produce sand and have high formation-gas/liquid ratios are excellent candidates for gas lift when artificial lift is needed. Many gas lift installations are designed to increase the daily production from flowing wells. No other method is as ideally suited for through-flowline ocean-floor completions as a gas lift system. Wireline-retrievable gas lift valves can be replaced without killing a well or pulling the tubing.

The gas lift valve is a simple device with few moving parts, and sand-laden well fluids do not have to pass through the valve to be lifted. The individual-well downhole equipment is relatively inexpensive. The surface equipment for injection-gas control is simple and requires little maintenance and practically no space for installation. Typically, the reported high overall reliability and lower operating costs for a gas lift system are superior to other methods of lift.

Limitations of gas lift

The primary limitation for gas lift operations is the lack of formation gas or an injection-gas source. Wide well spacing and lack of space for compressors on offshore platforms may also limit the application of gas lift. Poor compressor maintenance can increase compressor downtime and add to the cost of gas lift gas, especially with small field units. Compressors are expensive and must be properly maintained. Generally, gas lift is not as suitable as some other systems for single-well installations and widely spaced wells. The use of wet gas without dehydration reduces the reliability of gas lift operations.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

Yadua, A.U., Lawal, K.A., Eyitayo, S.I. et al. Performance of a gas-lifted oil production well at steady state. J Petrol Explor Prod Technol (2021).

See also

Gas lift system design

Gas lift equipment and facilities

Gas lift valve mechanics

Gas lift installation design

Gas lift installation design methods

Intermittent-flow gas lift

Intermittent-flow gas lift installation design

Chamber lift

Intermittent gas lift plunger application

Gas lift operations

Gas lift for unusual environments