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Gas lift equipment and facilities

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The following topic describes Gas distribution and control, Gas compression and dehydration and Gas surface facilities.


Figs. 1 and 2 show the amount of injection gas and compression brake horsepower per well, respectively, required to obtain identical producing rates using several different surface injection-gas pressures. As expected, compression horsepower decreases as injection-gas pressure increases for a given daily liquid rate, until the injection-gas pressure reaches maximum injection depth. An injection-gas pressure greater than that required to inject at maximum depth requires additional compression without additional production.

In the example shown in Figs. 1 and 2, a significant decrease in horsepower requirements is possible by employing an injection-gas pressure of 2,000 psig (ANSI Class 900 pipe) rather than one of 1,440 psig (ANSI Class 600 pipe) or lower. For these conditions, the compression horsepower requirements represent the minimum for each producing rate when an injection-gas pressure of approximately 2,000 psig is used. Unlike an injection-gas pressure of 2,500 psig, 2,000-psig pressure allows the use of ANSI Class 900 piping (2,160-psig working pressure) in the distribution system.

Most high-pressure gas lift systems are designed to recirculate the lift gas. The low-pressure gas from the production separator is compressed and reinjected into the well to lift the fluids from the well. This closed loop, as illustrated in Fig. 3 is referred to as a closed rotative gas lift system. Continuous-flow gas lift operations are preferable with a closed rotative system. Intermittent gas lift operations are particularly difficult to regulate and operate efficiently in small closed systems having limited gas-storage capacities.

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.

Gas distribution and control

The control and distribution of injection gas to a gas lift well is as important as the control and distribution of electric power is to a pumping well. The distribution system must be large enough so that very little pressure is lost between the compressor and the wellhead. This is usually best accomplished with a main distribution line that circles a producing area and is connected to distribution manifolds located at each production station. Manifolds of this type were first used in the vast gas lift systems of Lake Maracaibo. They proved so successful for centralizing the control of injection gas that their use spread to many areas of the world. The distribution manifold consists of a control valve, gas meter, and distribution line to each well. Such a system is illustrated in Fig. 4.[1] [2]

Gas compression and dehydration

In the early days of gas lift, most injection gas for the gas lift wells came from large gas-processing facilities. This ensured a good constant source of dry gas to lift the wells. However, as more gas was gathered and processed, the processing plants became larger and were located further from the oil-production facilities. This resulted in the widespread use of field compressors to compress gas gathered in the field before it was sent to the processing facilities. The field compressors tended to be smaller, high-speed, skid mounted, reciprocal units that could be moved and quickly installed wherever required.

The use of the field compressors made gas lift easily accessible in any field where sufficient gas was available from a local source. This brought about many closed-cycle gas lift systems where gas was separated from the produced crude, gathered and sent to compressors, and then after compression, returned to the wells for reinjection as gas lift gas or sold.

Both the centrifugal and reciprocating compressors are used in production facilities. However, because of their flexibility under changing conditions and applicability to small volumes, reciprocating compressors are used far more often than centrifugal compressors in gas lift operations.

Gas dehydration

Because most injection gas for gas lift is now compressed in the field, dehydration of the gas has become an important part of a successful gas lift operation. Natural gas may contain substantial amounts of water vapor because of the presence of connate water in the reservoir. The ability of a gas to hold water in the vapor phase is dependent upon the pressure and temperature of the gas. As a gas is cooled, its ability to hold water in the vapor phase is reduced. The water dewpoint of a gas is defined as the temperature under a given pressure at which water initially begins to condense from an all-vapor system. Water vapor should be removed from lift gas to prevent the formation of liquids in the distribution system. Liquids can cause the formation of hydrates, which are solid compounds resembling dirty ice that is caused by the reaction of natural gas with water. Hydrates consist of approximately 10% hydrocarbons and 90% water. These hydrates may pack solidly in gas distribution systems causing blocked valves, lines, and orifices. In distribution systems that contain acid gas fractions (CO2 and H2S), liquids can also greatly accelerate the corrosion of the gas-handling facilities, as well as the well casing and tubing.

Gas dehydration removes the source of the problem and is preferred over methanol injection or line heaters. Dehydration can be accomplished by either absorption or adsorption processes. The absorption process involves the passing of the gas stream through a liquid desiccant that has a strong affinity for water. In the adsorption process, gas flows through a bed of granular solids called solid desiccants. The most widely used dehydration system in oilfield and gas lift operations is the absorption-type process. The desiccant used in these systems is usually a solution of one of the glycols; generally, diethylene glycol (DEG) or triethylene glycol (TEG) is used. The method of operation is the same for both systems.

Surface production facilities

The location of surface production facilities can greatly impact the efficiency of a gas lift operation. Production stations that provide liquid and gas separation along with other gathering facilities should be located as near the wells as practical. Every effort should be made to minimize the length of multiphase flowlines. In some cases, substations with a minimum of facilities can be employed to shorten the length of the multiphase flowlines.


  1. 1.0 1.1 Poettmann, F.H. and Carpenter, P.G. 1952. The Multiphase Flow of Gas, Oil and Water Through Vertical Flow Strings. Drilling & Prod. Prac. 257.
  2. Blann, J.R. 2001. Gas Lift Optimization. Houston, Texas:J&L Publishing.

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See also

Gas lift

Gas lift valve mechanics

Gas lift operations