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Gas lift equipment
Downhole gas lift equipment consists mainly of the gas lift valves and the mandrels in which the valves are placed. The American Petroleum Inst. (API) Spec. 11V1 covers the manufacture of gas lift valves and mandrels. 
- 1 Compressor horsepower
- 2 Tubing- and wireline-retrievable equipment
- 3 Open and closed installations
- 4 Considerations for selecting the proper installation and equipment
- 5 Bellows
- 6 Purposes of gas lift valves and reverse checks
- 7 References
- 8 Noteworthy papers in OnePetro
- 9 External links
- 10 See also
- 11 Category
The compressor horsepower requirements are considered in analyzing the gas lift system design. Please look at the page of gas lift equipment and facilities for more details.
Tubing- and wireline-retrievable equipment
The early gas lift valves were the conventional tubing-retrievable type, in which the tubing mandrel that held the gas lift valve and reverse check valve was part of the tubing string. It was necessary to pull the tubing to replace a conventional gas lift valve. The first selectively wireline-retrievable gas lift valve and mandrel were introduced around 1950. The wireline-retrievable-valve mandrel was designed with a pocket receiver within the mandrel. A gas lift valve could be removed or installed by wireline operations without pulling the tubing. The primary wireline device for locating the mandrel pocket and selectively removing or installing a gas lift valve is a kickover tool. The mandrel is called a sidepocket mandrel because the pocket is offset from the centerline of the tubing. Most sidepocket-type retrievable-valve mandrels have a full-bore inside diameter (ID) equal to the tubing ID. These mandrels permit normal wireline operations, such as pressure surveys. This wireline-retrievable system for gas lift valves revolutionized the application of gas lift for inaccessible wells. The newer generation of retrievable-valve mandrels uses orienting devices to ensure successful wireline operation in highly deviated wells. A description of such equipment can be found in API Spec. 11V1. 
The operating principles for a given type of tubing-retrievable or wireline-retrievable gas lift valve are the same. Although the performance characteristics may vary between the same type of tubing- and wireline-retrievable valve, the installation design calculations outlined in this chapter do not change. The choice between tubing- and wireline-retrievable equipment depends primarily on the costs associated with pulling the tubing and whether a workover fluid may damage the deliverability of a well.
With the increased cost of pulling the tubing in today’s field operations, wireline-retrievable equipment is now used in most new wells and particularly in offshore and inaccessible wells. A wireline-retrievable gas lift valve and mandrel are illustrated in Fig. 1, while a tubing-retrievable valve and mandrel are shown in Fig. 2. 
Fig. 1-Wireline-retrievable gas lift valve and mandrel (after API Spec. 11 V1).
Fig. 2-Tubing-retrievable gas lift valve and mandrel (after API Spec. 11 V1).
Open and closed installations
Most tubing flow gas lift installations include a packer to stabilize the fluid level in the casing annulus and prevent injection gas from blowing around the lower end of the tubing in wells with a low flowing bottomhole pressure. A closed gas lift installation implies that the installation includes a packer and a standing valve. An installation without a standing valve may be referred to as semiclosed, and this is widely used for continuous-flow operations. An installation without a packer or standing valve is called an open installation. An open installation is seldom recommended.
A packer is required for gas lifting low-bottomhole-pressure wells to isolate the injection gas in the casing annulus and to control the gas volume per cycle for intermittent-lift operations. Intermittent gas lift operations require a packer and possibly a standing valve. Although most illustrations of an intermittent gas lift installation show a standing valve, many actual installations do not include this valve. If the permeability of the well is very low, the need for a standing valve is optional. The advantages of a packer are particularly important for gas lift installations in an area where the injection-gas-line pressure varies or the injection-gas supply is interrupted periodically. If the installation does not include a packer, the well must be unloaded after each shutdown. More damage to gas lift valves can occur during unloading operations than during any other time in the life of a gas lift installation. If the injection-gas-line pressure varies, the working fluid level changes. The result is a liquid washing action through all valves below the working fluid level, and this continuing fluid transfer can eventually fluid-cut the seat assemblies of some gas lift valves. A packer stabilizes the working fluid level and eliminates the need for unloading fluids in the annulus after a shutdown.
Considerations for selecting the proper installation and equipment
If a well can be gas lifted by continuous flow, this form of gas lift should be used to ensure a constant injection-gas circulation rate within the closed rotative gas lift system. Continuous flow reduces pressure surges in the bottomhole flowing pressure, flowline, and the low- and high-pressure surface facilities that are associated with intermittent gas lift operations. Overdesign rather than underdesign of a gas lift installation is recommended when the well data are questionable. The gas lift equipment in the wells is the least expensive portion of a closed rotative gas lift system. The larger-outside-diameter (OD) gas lift valve should be selected for lifting most wells if casing size permits. The superior injection-gas volumetric throughput performance for the l.5-in.-OD gas lift valve, as compared to the l-in.-OD valve, is an important consideration for gas lift installations with a high injection-gas requirement. The smaller diameter 1-in.-OD valve is designed to be used in small-casing-diameter wells. Structurally, the 1-in.-OD valve is not as strong as the 1.5-in.-OD valve. Its bellows size is much smaller, which results in an increase in the ratio of port area to bellows area. This increase in port-to-bellows area ratio and higher bellows-assembly load rate can increase the number of gas lift valves and the injection-gas pressure required to lift deep wells.
The gas lift design techniques presented in Gas lift system design include several factors to compensate for errors in well information and provide for an injection-gas pressure increase to stroke the gas lift valves. If an installation is properly designed, all gas lift valves above an operating valve should be closed, and all valves below should be open. The installation methods presented here are based on this premise. Gas lift valve operation is discussed in detail because it is difficult to design or analyze a gas lift installation properly without understanding the mechanical operation of a gas lift valve.
A large-bore seating nipple, which is designed to receive a lock, is recommended for most gas lift installations. This seating nipple should be installed at the lower end of the tubing and, if feasible, below the packer. Applications for a seating nipple include installation of a standing valve for testing the tubing or for intermittent gas lift operation and a means to secure and to pack off a bottomhole-pressure gauge for conducting pressure-transient tests. The lock should have an equalizing valve if the tubing is to be blanked off. The pressure across the lock can be equalized before the lock is disengaged from the nipple to prevent the wireline tool string from being blown up the hole.
The advent of the unbalanced, single-element, bellows-charged gas lift valve (as illustrated in Fig. 3) revolutionized gas lift application and installation design methods. Before the bellows-charged gas lift valve, there were differential valves and numerous types of unique devices used for gas lifting wells. These devices, or valves, were operated by rotating or vertically moving the tubing and by means of a sinker bar on a wireline.
Single-element implies that the gas lift valve consists of a bellows and dome assembly, a stem with a tip that generally is a carbide ball, and a metal seat housed in a valve body that is attached to a mandrel in the tubing string. This is illustrated in Fig. 3. The original patent for this type of gas lift valve was filed in 1940 by W.R. King. Currently, the unbalanced, single-element nitrogen-charged, bellows valve remains the most widely used type of gas lift valve for gas lifting wells. The original King valve had most of the protective design features of the present gas lift valves. The bellows was protected from high hydrostatic fluid pressure by a gasket that sealed the bellows chamber from well fluids after full stem travel. A small orifice was drilled in a bellows guide tube. The orifice was designed to be an anti-chatter mechanism, and the bellows guide provided bellows support.
Purposes of gas lift valves and reverse checks
The gas lift valve is the heart of most gas lift installations and the predictable performance of this valve is essential for successful gas lift design and operations. The gas lift valve performs several functions in a typical gas lift installation.
The primary function of a string of gas lift valves is to unload a well with the available injection-gas pressure to a maximum depth of lift that fully uses the energy of expansion of the injection gas for the available injection-gas pressure. Gas lift valves provide the flexibility for a varying depth of gas injection as a result of a changing flowing bottomhole pressure, water cut, daily production rate, and well deliverability.
Gas lift valves provide the means to control the injection-gas volume per cycle in an intermittent gas lift operation. The operating gas lift valve in an intermittent gas lift installation prevents an excessive injection-gas pressure bleed down following an injection-gas cycle.
When wet gas must be used for gas lifting with an orifice-check operating valve, freezing may occur across the surface control valve because of a low flowing bottomhole pressure. This condition can sometimes be eliminated by replacing the orifice-check valve with an injection-pressure-operated gas lift valve. This allows the pressure drop to be taken across the operating gas lift valve at depth where freezing will not occur.
The reverse check in a gas lift valve is especially important if any valves are located below the working fluid level. The check prevents backflow from the tubing into the casing, which is particularly important if the well produces sand and has a packer.
- API Spec. 11V1, Specification for Gas Lift Equipment, first edition. 1995. Washington, DC: API.
Noteworthy papers in OnePetro
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