Gas lift manual gabor takacs free download - Issuu Gas lift valves with a high degree of tubing-pressure sensitivity may require a minimum production pressure at valve depth to open the valve with the available injection-gas pressure. This problem occurs more frequently with the top one or two gas lift. A proper gas lift installation design, therefore, assures trouble-free operation for the entire productive life of a well. 1, 2 The usual gas lift installation types are classified in two broad categories: tubing flow and casing flow installations. In a tubing flow installation, lift gas is injected in the casing-tubing annulus,. LIFT-O-MAT gas springs are non-locking gas springs. They are used whenever components, such as doors, aps, and lids, must be brought into a dened position. LIFT-O-MAT controls the extension force and damping action depending on the function, thereby ensuring user-friendly motion sequences. Parts, service and operations manuals for Genie articulated boom lifts, telescopic boom lifts, scissor lifts, aerial work platform, material handing and telehandler products.
You must log in to edit PetroWiki. Help with editing
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information
Ideally, an artificial-lift system should be chosen and designed during the initial planning phase of an oil field. However, in the haste to get a field on production, artificial lift may not be considered until after other production facilities are designed and installed. It is difficult to choose and install the optimum artificial-lift system after the surface production facilities have been installed. This is especially true in the case of gas lift.
- 2Factors having an effect on the design of a gas lift system
Fundamentals of gas for gas lift design
Only the gas fundamentals essential to the design and analysis of gas lift installations and operations are discussed in this section. The more important gas calculations related to gas lift wells and systems can be divided into these topics:
Factors having an effect on the design of a gas lift system
Most production equipment affects the design of a gas lift system, so it is best to design the gas lift system concurrently with the design of surface facilities. The entire purpose of a gas lift system is to reduce the bottomhole flowing pressure of the well. Anything that restricts or prevents this from occurring will have an impact on the system and must be considered in the design.
Field layout and well design
Consideration of gas lift operations should be a prime factor in sizing the hole for the desired oilwell tubulars. This is particularly true in offshore wells where all of the downhole gas lift equipment, except the valves, is installed during the initial completion. In on-shore fields, gas lift affects the size and location of gathering lines and production stations. Artificial lift should be considered before a casing program is designed. Casing programs should allow the maximum production rate expected from the well without restrictions. Skimping on casing size can ultimately cost lost production that is many times greater than any savings from smaller pipe and hole size. The same is true in flowline size and length. Production stations should be relatively near the producing wells. In most cases, increasing the size of the flowline does not compensate for the backpressure generated by the added pipe length. Any item of production equipment that increases backpressure at the wellhead, whether it be wellhead chokes, small flowlines, undersized gathering manifolds and separators, or high compressor suction pressure, seriously impacts the operation of a gas lift system. Fig. 1 illustrates the effect of backpressure on injection-gas requirement and fluid production in a 6,900-ft gas lift well.[1]
- Fig. 1-Effect of wellhead backpressure on daily production rates and injection-gas requirements.[2]
Injection-gas pressure
Choosing a proper injection-gas pressure is critical in a gas lift system design. [2] Several factors may affect the choice of an injection-gas pressure. However, one primary factor stands out above all others. To obtain the maximum benefit from the injected gas, it must be injected as near the producing interval as possible. The injection-gas pressure at depth must be greater than the flowing producing pressure at the same depth. Any compromise with this principle will result in less pressure drawdown and a less efficient operation. High volumes of gas injected in the upper part of the fluid column will not have the same effect as a much smaller volume of gas injected near the producing formation depth because the fluid density is reduced only above the point of gas injection.
The equilibrium curve[1] illustrates the effect of injection-gas depth on a particular well. The equilibrium curve is established by determining the intersection of the formation-fluid pressure gradient below the depth of gas injection with the produced gas lift gradient above the depth of gas injection for various producing liquid rates (See Fig. 2). In Fig. 2, the intersections of the flowing formation-fluid pressure-gradient traverses for a 400-B/D rate and a 600-B/D rate with the flowing total (formation plus injection gas) -pressure-gradient traverses above the point of gas injection to the surface for both rates are shown. If intersections are established for a large number of rates, as are shown in Fig. 3, the points can be connected and will form what is referred to as an equilibrium curve. When injection-gas pressure traverses are drawn from the surface, it is possible to determine the maximum gas lift rate from the well for various surface injection-gas pressures. Referring again to Fig. 3, a 1,200-psig surface injection-gas pressure would gas lift this well at a rate slightly above 600 B/D.
- Fig. 2-Construction of an equilibrium curve.
- Fig. 3-Complete equilibrium curve for specific well conditions.
Less downhole equipment may be required when higher injection-gas pressures are used (see Fig. 4). The higher injection-gas pressure provides a greater pressure differential between the injected-gas pressure and the flowing tubing pressure; thereby, allowing a greater spacing between valves. Thus, fewer mandrels and valves are required to reach the maximum injection-gas depth. Note that in Fig. 4, the 800-psig design reaches only the depth of 4,817 ft and requires seven gas lift valves. In comparison, the 1,400-psig design uses only four gas lift valves to reach the full depth of the well at 8,000 ft. The maximum pressure drawdown at the formation with the 800-psig injection gas is only 210 psi (2,200 to 1,990) compared to 1,010 psi (2,200 to 1,190) when 1,400-psig injection gas is used.
- Fig. 4-A graphical design for a continuous-flow gas lift installation based on 800-psig injection-gas pressure (light lines) overlaying a design for 1,400-psig injection-gas pressure.
Major factors that have an effect on choosing the most economical injection-gas pressure
Only the basic conditions that must be met to ensure the most efficient injection-gas pressure to maintain operating pressure for a given well have been discussed. A variety of other factors can affect the selection of the most efficient surface injection-gas pressure. These may include:
- Pressure/volume/temperature (PVT) properties of the crude
- Water cut of the producing stream
- Density of the injected gas
- Wellhead backpressure
- Pressure rating of the equipment
- Design of the well facility
Calculating the effect of injection-gas pressures on surface production facilities
The selection and design of compression equipment and related facilities must be closely considered in gas lift systems because of the high initial cost of compressor horsepower and the fact that this cost usually represents a major portion of the entire project cost. In most instances, the injection-gas pressure required at the wellhead determines the discharge pressure of the compressor. Higher injection-gas pressures increase the discharge pressure requirement of the compressor, which is translated into a related increase in the compressor horsepower required for a given volume of gas. However, if the gas lift system is designed properly, the related decrease in gas volume requirements will result in an improvement in overall operating efficiency.
Gas volume
The total injection gas required for a continuous-flow gas lift well may be determined by well-performance prediction techniques. Well-performance calculations are discussed later in this chapter, but they are typically obtained by simultaneously solving the well inflow and well outflow equations. Well inflow, or fluid flow from the reservoir, can be simulated by either the straight line pressure drawdown (PI) or the inflow performance relationship (IPR) methods. [3] Likewise, well outflow, or fluid flow from the reservoir to the surface, is typically predicted by empirical correlations such as those presented by Poettmann and Carpenter, [4] Orkiszewski, [5] Duns and Ros, [6] Hagedorn and Brown, [7] Beggs and Brill, [8] and others. Once typical gas volume requirements for individual wells are determined, totals for the entire field can be calculated.
Dynamic gas lift valve performance
The importance of gas lift valve performance in the design of a gas lift installation is primarily dependent upon the maximum required injection-gas rates through the gas lift valves to unload and gas lift a well. Dynamic testing of gas lift valves indicated a noticeable difference in the performance of the 1-in.- and 1.5-in.-OD gas lift valves. Although both OD of these gas lift valves had the same port size, the 1.5-in.-OD valve with the larger bellows had a much higher injection-gas throughput rate for the same increase in the injection-gas pressure above the initial valve opening pressure. For this reason, the larger-OD gas lift valve with a 0.77-in.2 bellows area is recommended for gas lifting high-rate wells with large tubing.
In recent years, there has been considerable interest in the actual injection-gas throughput rates of gas lift valves. API RP 11V2[9] presents the recommended methods for testing gas lift valves. A single-element unbalanced gas lift valve has two fundamental characteristics that are determined from a probe test. The procedure for performing the probe test is outlined in RP 11V2. These characteristics are the bellows-assembly load rate or spring rate and the approximate effective linear travel of the valve stem. The required valve-stem travel to ensure a fully open port increases with the valve port size, as shown in Fig. 5, for gas lift valves with square, sharp-edged seats. If the maximum linear stem travel is less than required for a fully open port area, the injection-gas throughput will be less than the gas rate through an orifice with an area equal to the port area.
- Fig. 5-Equivalent area of a gas lift valve port vs. stem travel based on the lateral surface area of the frustum of a right circular cone.
Gas lift design and operation can be divided into two categories on the basis of the primary opening force. If a valve is opened primarily by an increase in the injection-gas pressure in the casing, the valve is called an injection-pressure-operated gas lift valve. A production-pressure-operated valve is opened primarily by an increase in the flowing-production pressure in the tubing at valve depth.
The typical standardized bellows sizes are 0.31 in.2 for 1-in.-OD gas lift valves and 0.77 in.2 for the 1.5-in.-OD valve. There are other sizes of bellows and smaller-OD gas lift valves for special clearance applications that will not be included in this section. The OD of a gas lift valve does not ensure the bellows size. The 1.5-in.-OD gas lift valve may have a smaller bellows. The published specifications for a valve indicate the bellows size.
A gas lift valve should be tested in the exact same manner as it is operated in a well. Typical port sizes for 1-in.-OD gas lift valves are 1/8-, 3/16-, 1/4-, 5/16-, and 3/8-in. ID. Port sizes of 3/16-, 1/4-, 5/16-, 3/8-, 7/16-, and 1/2-in. ID are available for 1.5-in.-OD gas lift valves (See Table 1.). These injection-pressure-operated valves are opened by an increase in the injection-gas pressure being applied over a major portion of the effective bellows area. It is impractical to attempt to open these valves by increasing the flowing-production pressure that acts on a much smaller area. Theoretically, a several hundred or thousand psi increase is required to fully stroke these valves by only increasing the flowing-production pressure.
- Table 1
Operators should recognize the possibility of limited injection-gas passage of gas lift valves for gas lifting high-rate wells through large tubing or casing annulus. An injection-gas throughput rate based on a fully open port size should not be assumed for the larger port sizes in many unbalanced, single-element gas lift valves. For the maximum actual range in the injection-gas pressure during typical gas lift unloading operations, the equivalent port area open for the injection-gas flow is less than an area based on the reported port size for gas lift valves with a large port area relative to the effective bellows area. Assuming that a 1-in. OD gas lift valve with a large port has the valve stem travel to fully open, the necessary increases in the injection-gas pressure to stroke the valve stem for this required travel may approach, or exceed, 200 psi for a constant flowing-production pressure. Maximum valve-stem travel may also be limited by manufacturing tolerances running in the same direction, a mechanical stop, or by the bellows stacking before a fully open port is achieved.
References
- ↑ 1.01.1Blann, J.R. and Williams, J.D. 1984. Determining the Most Profitable Gas Injection Pressure for a Gas Lift Installation (includes associated papers 13539 and 13546 ). J Pet Technol36 (8): 1305-1311. SPE-12202-PA. http://dx.doi.org/10.2118/12202-PA.
- ↑ 2.02.1Gas Lift, Book 6 of Vocational Training Series, third edition. 1994. Dallas, Texas: API, E&P Dept.
- ↑Vogel, J.V. 1968. Inflow Performance Relationships for Solution-Gas Drive Wells. J Pet Technol20 (1): 83–92. SPE 1476-PA. http://dx.doi.org/10.2118/1476-PA.
- ↑Poettmann, F.H. and Carpenter, P.G. 1952. The Multiphase Flow of Gas, Oil and Water Through Vertical Flow Strings. Drilling & Prod. Prac., 257.
- ↑Orkiszewski, J. 1967. Predicting Two-Phase Pressure Drops in Vertical Pipe. J Pet Technol 19 (6): 829–838. SPE-1546-PA. http://dx.doi.org/10.2118/1546-PA.
- ↑Duns, H. Jr. and Ros, N.C.J. 1963. Vertical Flow of Gas and Liquid Mixtures from Boreholes. Proc., Sixth World Petroleum Congress, Frankfurt, Germany, Sec. II, Paper 22-PG.
- ↑Hagedorn, A.R. and Brown, K.E. 1964. The Effect of Liquid Viscosity in Two-Phase Vertical Flow. J Pet Technol 16 (2): 203-210. SPE-733-PA. http://dx.doi.org/10.2118/733-PA.
- ↑Beggs, D.H. and Brill, J.P. 1973. A Study of Two-Phase Flow in Inclined Pipes. J Pet Technol25 (5): 607-617. SPE-4007-PA. http://dx.doi.org/10.2118/4007-PA.
- ↑ API RP 11V2, Recommended Practice for Gas Lift Valve Performance Testing, first edition. 1995. Washington, DC: API.
Noteworthy books
Brown, K. E. (1967): GAS LIFT THEORY AND PRACTICE. Petroleum Publishing Co., Tulsa, Oklahoma.
Hernandez, A. (2016): FUNDAMENTALS OF GAS LIFT ENGINEERING. ISBN 978-0-12-804133-8 Gulf Professional Publishing, Cambridge, MA, 966p
Takács G. (2005): GAS LIFT MANUAL. ISBN 0-87814-805-1 PennWell Books, Tulsa Oklahoma, 478p.
Noteworthy papers in OnePetro
Camco Gas Lift Manual
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
External links
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
See also
Retrieved from 'https://petrowiki.spe.org/index.php?title=Gas_lift_system_design&oldid=54092'
You must log in to edit PetroWiki. Help with editing
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information
A recommended practice for operation, maintenance, and troubleshooting gas lift installations is given in API RP 11V5.[1]
- 1Unloading procedures and proper adjustment of injection-gas rate
Unloading procedures and proper adjustment of injection-gas rate
The importance of properly unloading a gas lift installation cannot be overemphasized in terms of possible damage to gas lift valves and for attaining the optimum depth of lift. Cyberoam vpn setup. If a permanent meter tube is not installed in the injection-gas line to the well, provisions should be made for the installation of a portable meter tube before unloading and adjustment of the injection-gas rate to the well. Preferably, the meter tube and the orifice meter or flow computer should be located near the well’s injection-gas control device so that the effect of changes in the adjustment of the injection-gas volume can be observed.
Gas Lift Design Manual
A two-pen pressure recorder should be installed before unloading all gas lift installations. The ranges of the pressure elements in the recorder should be checked before hookup. A typical recorder will have a 0- to 500- or 0- to 1,000-psig range element for the flowing wellhead production pressure and a 0- to 1,000- or 0- to 2,000-psig range element for the injection-gas pressure, depending on the kick-off and available operating injection-gas pressure at the wellsite. These pressure elements should be calibrated periodically with a dead eight tester to ensure accurate recordings.
Recommended practices before unloading
If the injection-gas line is new, it should be blown clean of scale, welding slag, and the like, before being connected to a well. This precaution prevents damage and plugging of the surface control equipment and entry of debris with the injection gas into the casing annulus. Debris may cause serious operational problems to gas lift valves.
The surface facilities for a gas lift installation should be checked before the well is unloaded. This includes all valves between the wellhead and the battery, the separator gas capacity, and the stock-tank room. It is important to check the pop-off safety release valve for the gas gathering facilities if this is the first gas lift installation in the system.
Recommended procedure for unloading gas lift installations
Preventing excessive pressure differentials across the gas lift valves during initial U-tubing operations minimizes the chance for equipment failure because of fluid and sand cutting. The following procedure avoids excessive pressure differential across the valves during the unloading operation. The permissible rate of increase in the injection-gas pressure downstream of the control device can be greater for an open installation without a packer than for an installation with a packer. Most of the load fluid from the casing annulus will be U-tubed through the lower end of the tubing in an open installation; whereas all the load fluid in the annulus must pass through the small ports of the gas lift valves in an installation with a packer. The initial U-tubing is the most critical operation during the unloading procedure. There is no reason to hurry the U-tubing of the load fluid to uncover the top gas lift valve. Because the tubing remains full of load fluid during the U-tubing operation, there is no drawdown in flowing bottomhole pressure. Gas lifting does not begin until the initial U-tubing is completed and injection gas enters the tubing through the top valve. The load-fluid production rate is controlled by the rate of increase in the injection-gas pressure, which in turn, depends on the injection-gas rate. Because most gas lift installations include a packer, the load fluid enters the tubing through the gas lift valves. If the load fluid contains sand and debris and full line injection-gas pressure is applied to the casing by opening a large valve on the injection-gas line, the gas lift valves may leak after the well is unloaded. An instantaneous pressure differential that is approximately equal to the full line injection-gas pressure occurs across every gas lift valve because the casing and tubing are full of load fluid. If sand or debris is in the load fluid, the resulting high fluid velocity through the small valve ports might fluid cut the seats. The following procedure is recommended for monitoring and controlling the unloading operations for all gas lift installations to prevent damage to the gas lift valves and surface facilities.
- Install a two-pen pressure recorder that is accurate and in good working condition. The injection-gas pressure downstream of the gas-control device and the wellhead tubing pressure should always be recorded during the entire unloading operation.
- If the well has been shut in and the tubing pressure exceeds the separator pressure, bleed down the tubing through a small flowline choke. Do not inject lift gas before or while the tubing is being bled down.
- Remove all wellhead and flowline restrictions including a fixed or adjustable choke if the well does not flow after all load fluid has been produced. If the gas lift installation is in a new well, or a recompletion that could flow, a 24∕64- to 32∕64-in. flowline choke is recommended until the well has cleaned up and does not flow naturally. The selected range of the element for the flowing-wellhead-pressure pen in the two-pen recorder should be able to handle the maximum flowing wellhead pressure with a choke in the flowline.
- Inject lift gas into the casing at a rate that does not allow more than a 50-psi increase in casing pressure per 10-minute interval. Continue until the casing pressure has reached at least 300 psig. Most companies use a standard choke size in the injection-gas line for U-tubing and initial unloading operations. A typical injection-gas choke size ranges from 6∕64 to 8∕64 in. for the U-tubing operation.
- After the casing pressure has reached 300 to 500 psig, the injection-gas rate can be adjusted to allow a 100-psi increase per 10-minute interval until gas begins to circulate through the top gas lift valve (top valve is uncovered). After the top gas lift valve is uncovered and gas has been injected through this valve, a high pressure differential cannot occur across the lower gas lift valves. Any time the casing injection-gas pressure is increased above the opening pressure of the top valve, the valve will open and prevent a further increase in the injection-gas pressure. Gas lifting begins with injection gas entering the top valve.
- If the gas lift installation does not unload to the bottom valve or the design operating gas lift valve depth, adjustment of the injection-gas rate to the well is required. An excessive or inadequate injection-gas rate can prevent unloading. This is particularly true for intermittent gas lift on time-cycle control where the maximum number of injection-gas cycles per day decreases with depth of lift. It may be necessary to decrease the number of injection-gas cycles per day and to increase the duration of gas injection as the point of gas injection transfers from an upper to a lower valve. Proper adjustment of the injection-gas volume to a well is not permanent for most installations. The injection-gas requirements change with well conditions; therefore, continuous monitoring of the injection-gas rate and the wellhead and injection-gas pressure is recommended to maintain efficient gas lift operations.
Depressing the fluid level ('rocking' a well)
If the top gas lift valve cannot be uncovered with the available injection-gas pressure, the fluid level can be depressed when there is no standing valve in the tubing. The injection-gas pressure is applied simultaneously to the tubing and casing. Several hours may be required to depress the fluid level sufficiently in a 'tight' low-permeability well. The tubing pressure is released rapidly, and the source of the major portion of the fluid entering the tubing is load fluid from the annulus. This procedure may be required several times to lower the fluid level in the casing annulus below the depth of the top gas lift valve.
High-production-pressure-factor valves in an intermittent gas lift installation or an installation with production-pressure-operated valves may cease to unload after the top valve has been uncovered. Gas lift valves with a high degree of tubing-pressure sensitivity may require a minimum production pressure at valve depth to open the valve with the available injection-gas pressure. This problem occurs more frequently with the top one or two gas lift valves and may be referred to as a 'stymie' condition. The stymie condition can be corrected by applying an artificial increase in production pressure at valve depth by 'rocking' the well. The valve cannot detect the difference between a liquid column and a pressure increase from partially equalizing the tubing and casing pressure with injection gas. If a well should stymie, the proper procedure for 'rocking' the well follows:
- First, with the wing valve on the flowline closed, inject lift gas into the tubing until the casing and tubing pressures indicate that the gas lift valve has opened. A small copper tubing or flexible high-pressure line can be used for this purpose. When a valve opens, the casing pressure begins to decrease and to equalize with the tubing pressure. The tubing pressure also should begin to increase at a faster rate with injection gas entering the tubing through the valve and surface connection.
Gas Lift Manual Free Download
- Next, stop gas injection into the tubing and immediately open the wing valve to lift the liquid slug above the gas lift valve into the flowline as rapidly as possible. A flowline choke may be required to prevent venting injection gas through the separator relief valve. Some surface facilities are overloaded easily, and bleeding off the tubing must be controlled carefully.
- Last, the rocking process may be required several times until a lower gas lift valve has been uncovered. As the depth of lift increases, the possibility of stymie decreases because of a higher minimum production pressure at the greater depth and the decrease in the distance between valves.
Controlling the daily production rate from continuous-flow installations
The daily production rate from a continuous-flow gas lift installation should be controlled by the injection-gas volumetric flow rate to the well. A flowline choke should not be used for this purpose. Excessive surface flowline backpressure increases the injection-gas requirement. Production-pressure-operated gas lift valves and injection-pressure-operated valves with a large production-pressure factor are particularly sensitive to high wellhead flowing pressure. Inefficient multipoint gas injection can result and prevent unloading an installation to the maximum depth of lift for the available operating injection-gas pressure when the flowing wellhead backpressure is excessive.
Adjustment of a time-cycle-operated controller for intermittent-flow operations
When initially unloading an intermittent-flow gas lift installation, an excessive injection-gas-cycle frequency may prevent 'working down' (unloading the gas lift installation beyond a certain depth). As the depth of lift increases, the maximum possible number of injection-gas cycles per day decreases and the volume of injection gas required per cycle increases. If the number of injection cycles per day becomes excessive and there is insufficient time between gas injections for the casing pressure to decrease to the closing pressure of an upper unloading gas lift valve, the unloading process will discontinue until the number of injection-gas cycles is reduced. Many installations require several adjustments of the time-cycle controller before the operating valve depth is reached.
The following procedure is recommended for final adjustment of a time-cycle-operated controller to minimize the injection-gas requirement when lifting from the operating gas lift valve:
- Adjust the controller for a duration of gas injection that ensures an excessive volume of injection gas used per cycle (approximately 500 ft3 /bbl/1,000 ft of lift). For most systems 30 sec/1,000 ft of lift results in more gas being injected into the casing annulus than is actually needed.
- Reduce the number of injection-gas cycles per day until the well will not lift from the final operating valve depth and/or the producing rate declines below the desired or maximum daily production rate.
- Reset the controller for the number of injection-gas cycles per day immediately before the previous setting in Step 2. This establishes the proper injection-gas-cycle frequency.
- Reduce the duration of gas injection per cycle until the producing rate decreases and then return to the previous setting and increase the duration of gas injection by 5 to 10 seconds for fluctuations in injection-gas-line pressure.
A time-cycle-operated controller on the injection-gas line can be adjusted as previously outlined, provided the line pressure remains relatively constant. If the line pressure varies significantly, the controller is adjusted to inject ample gas volume with minimum line pressure. When the line pressure is above the minimum pressure, excessive injection gas is used each cycle. One solution to this problem is a controller that opens on time and closes on a set increase in casing pressure. Several electronic timers are designed to operate in conjunction with pressure control.
References
- ↑API RP 11V5, Recommended Practice for Operation, Maintenance and Troubleshooting of Gas Lift Installations, first edition. 1995. Washington, DC: API.
Noteworthy books
Brown, K. E. (1967): GAS LIFT THEORY AND PRACTICE. Petroleum Publishing Co., Tulsa, Oklahoma.
Takács G. (2005): GAS LIFT MANUAL. ISBN 0-87814-805-1 PennWell Books, Tulsa Oklahoma, 478p.
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
![Design Design](/uploads/1/1/8/9/118943716/329128965.jpg)
External links
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
See also
Category
Retrieved from 'https://petrowiki.spe.org/index.php?title=Gas_lift_operations&oldid=48357'