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Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume IV - Production Operations Engineering
Joe Dunn Clegg, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 12 – Gas Lift
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Description of Gas LiftGas 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. There are two basic types of gas lift in use today—continuous and intermittent flow.
Continuous-Flow Gas Lift. The vast majority of gas lift wells are produced by continuous flow, which is very similar to natural flow. 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. 12.1 illustrates this principal.
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. 12.2.) 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. 12.2) 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.
Applications. 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.
Advantages of Gas Lift. 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.
Designing a Gas Lift System
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.
Factors Having an Effect on the Design of a Gas Lift SystemMost 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. 12.3 illustrates the effect of backpressure on injection-gas requirement and fluid production in a 6,900-ft gas lift well.
Fig. 12.3-Effect of wellhead backpressure on daily production rates and injection-gas requirements.
Injection-Gas Pressure. Choosing a proper injection-gas pressure is critical in a gas lift system design.  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 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. 12.4). In Fig. 12.4, 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. 12.5, 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. 12.5, a 1,200-psig surface injection-gas pressure would gas lift this well at a rate slightly above 600 B/D.
Less downhole equipment may be required when higher injection-gas pressures are used (see Fig. 12.6). 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. 12.6, 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.
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 such things as the 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, and 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.  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,  Orkiszewski,  Duns and Ros,  Hagedorn and Brown,  Beggs and Brill,  and others. Once typical gas volume requirements for individual wells are determined, totals for the entire field can be calculated.
Gas Lift SystemsFigs. 12.7 and 12.8 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. 12.7 and 12.8, 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. 12.9 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 Distribution and ControlThe 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. 12.10. 
Fig. 12.10-Injection-gas manifold for controlling and measuring gas to individual wells.
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.
Gas Lift EquipmentDownhole 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. 
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. 12.11, while a tubing-retrievable valve and mandrel are shown in Fig. 12.12. 
Fig. 12.11-Wireline-retrievable gas lift valve and mandrel (after API Spec. 11 V1).
Fig. 12.12-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 this chapter 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.
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: (1) gas pressure at depth, (2) temperature effect on the confined nitrogen-charged bellows pressure, (3) volumetric gas throughput of a choke or gas lift valve port, and (4) gas volume stored within a conduit.
The fundamental gas equations are based on pressure in pounds per square inch absolute (psia), temperature in degrees Rankine (°R), and volume or capacity in cubic feet (ft3). An exception is pressure difference in pounds per square inch (psi), which may be a difference in gauge or absolute units because the calculated pressure difference is the same. Generally, field measurements of pressure are in gauge readings; therefore, the volumetric gas throughput and gas-pressure-at-depth charts are in units of psig. The gas lift valve equations and calculations for bellows-charge and operating pressures in this chapter use gauge pressure.
Gas Pressure at Depth
Prediction of injection-gas pressure at depth is essential for proper gas lift installation design and for analyzing or troubleshooting gas lift operations. Most gas-pressure-at-depth calculations are based on a static gas column. Pressure loss, because of friction from the flow of injection gas through a typical casing/tubing annulus, is negligible. The gas velocity in the annulus is considered negligible because the cross-sectional area of the annulus is so much larger than the port area of a gas lift valve. The maximum gas flow rate is limited by the valve port size. Only in annular flow, where the flow areas are reversed and large volumes of gas may be injected down a small tubing string, does pressure loss because of velocity become a concern. Eq. 12.1 is used for predicting the static bottomhole injection-gas pressures.
The depth used in the equation is the true vertical depth of the gas column. Because the gas compressibility factor is a function of the average pressure and temperature, the solution to this equation requires several iterations. Generally, the average pressure and temperature are assumed to be the arithmetic mean of the wellhead and bottomhole values. This assumption is reasonable because the increase in well temperature with depth tends to result in a relatively constant gas density with depth. A straight-line traverse will approximate an actual static injection-gas pressure-at-depth traverse and is used for the design of most gas lift installations.
Temperature Effect on the Confined Nitrogen-Charged Bellows Pressure
There are many more bellows-charged than spring-loaded gas lift valves in service. Most of the bellows-charged valves have nitrogen gas in the dome and bellows. Because it is impractical to set each gas lift valve at its operating well temperature, the test-rack opening or closing pressure is set at a standard base temperature. Most manufacturers set their bellows-charged gas lift valves with the nitrogen-gas charge in the bellows at 60°F. Nitrogen was selected as the charge gas because: (1) the compressibility factors for nitrogen at various pressures and temperatures are known, (2) nitrogen is noncorrosive and safe to handle, (3) nitrogen is readily available throughout the world, and (4) nitrogen is inexpensive. The temperature correction factors for nitrogen can be obtained from tables such as the one shown in Table 12.1.  Table 12.1 is calculated for a specific condition of temperature and pressure (nitrogen-charged bellows pressure of 1,000 psig at 60°F) and is based on the work of Winkler and Eads.  An equation for calculating the temperature correction factor, CT, at other conditions of temperature and pressure is shown at the bottom of the table. However, for most gas lift designs, unless pressures are considerably higher than 1,000 psig, Table 12.1 gives sufficient accuracy. CT is used to calculate the nitrogen-charged bellows pressure at 60°F for a given valve operating or unloading temperature at valve depth in a well.
|CT||=||temperature correction factor for nitrogen from PbvD at TvuD to Pb at 60°F, dimensionless,|
|Pb||=||nitrogen-charged bellows pressure at 60°F, psig|
|PbvD||=||nitrogen-charged bellows pressure at valve temperature, psig.|
If a more accurate calculation of CT is required, the alternative solution shown in Example Problem 1b may be used.
An Alternative Solution for Calculating Nitrogen-Charged Bellows Pressure at 60oF. If the CT from Table 12.1 is used to calculate the nitrogen-charged bellows pressure at the test-rack valve setting temperature for gas lift valves in a high-injection-gas-pressure system, the possible error in the test-rack opening pressures may prevent successful gas lift operations. If the operating injection-gas-line pressure exceeds a range of 1,200 to 1,500 psig, the following correlation, based on the work of Winkler and Eads, is recommended for calculating the gas lift valve nitrogen-charged bellows pressure in psig at the setting test-rack opening temperature of 60°F.
|P||=||Pb + Patm and T = TvD - 60|
If Pb is less than 1,250 psia:
|A||=||3.054E – 07 ( T ), B = 1 + 0.001934(T) and C = – 0.00226 (T – P).|
If Pb is greater than 1,250 psia:
|A||=||1.84E – 07 (T), B = 1 + 0.002298 (T) and C = –0.267 (T – P).|
When Eq. 12.3 is used to calculate Pb, Eq. 12.4 is used to calculate CT:
Example Problem 1a A 1.5-in.-OD gas lift valve with a 1/4-in.-ID port (Ap/Ab = 0.064 from Table 12.2), nitrogen-charged bellows pressure at well temperature PbvD = 800 psig at 142°F. Calculate Pvo using Table 12.1 and Eqs. 12.2 and 12.15:
- Determine CT from Table 12.1: CT = 0.845 for TvD = 142°F.
- Using Eq. 12.2, solve for Pb: Pb = 0.845(800) = 676 psig at 60°F.
- Using Eq. 12.15, calculate the test-rack opening pressure, Pvo:
When Eq. 12.3 is used to calculate Pb: P = 814.7, T = 82, A = 2.50428E – 05, B = 1.158588, C = –814.8853, and Pb = 678.3 psig at 60°F. Using Eq. 12.15 to calculate Pvo and Eq. 12.4 to calculate CT:
The difference between using Eq. 12.3 or Table 12.1 for calculating Pvo is only 3 psi.
Example Problem 1b A 1.5-in.-OD gas lift valve with a 1/4-in. ID port ( Ap / Ab = 0.064 from Table 12.2 ), nitrogen-charged bellows pressure at well temperature PbvD = 2,228 psig at 200°F. Calculate Pvo using Table 12.1 and Eqs. 12.2 and 12.15 :
- Determine CT from Table 12.1 for TvD = 200°F: CT = 0.761.
- Using Eq. 12.3 , solve for Pb : Pb = 0.761(2,228) = 1,695.5 psig at 60°F.
- Using Eq. 12.15 , calculate the test-rack opening pressure, Pvo :
Using Eq. 12.3 to calculate PbvD : P = 2,242.7 and T = 140.
A = 2.576E – 05, B = 1.32172, C = –2,280.1, and Pb = 1,656 psig at 60°F.
Using Eq. 12.15 to calculate Pvo and Eq. 12.4 to calculate CT :
For the high-injection-gas-pressure system, note that the calculated test-rack opening pressure is higher using the CT from Table 12.1 to correct the nitrogen-charged bellows pressure from valve temperature in the well to the setting temperature of 60°F. The above data represent an actual 1,800-psig injection-gas system for gas lifting deep wells in Alaska. The operator had difficulty unloading and gas lifting these wells because the set test-rack opening pressures of the gas lift valves were too high.
Volumetric Gas Throughput of an Orifice or Choke
The volumetric gas throughput of an orifice or choke is calculated on the basis of an equation for flow through a converging nozzle. This equation is complex and lengthy for noncritical flow. For this reason, gas passage charts are widely used for estimating the volumetric gas flow rate. A widely used equation for calculating the gas flow rate through an orifice, choke, or full-open valve port was published by Thornhill-Craver. 
|qgsc||=||gas-flow rate at standard conditions (14.7 psia and 60°F), Mscf/D,|
|Cd||=||discharge coefficient (determined experimentally), dimensionless,|
|A||=||area of orifice or choke open to gas flow, in.2,|
|P1||=||gas pressure upstream of an orifice or choke, psia,|
|P2||=||gas pressure downstream of an orifice or choke, psia,|
|g||=||acceleration because of gravity, ft/sec2,|
|k||=||ratio of specific heats (Cp/Cv), dimensionless,|
|T1||=||upstream gas temperature, °R,|
|Fdu||=||pressure ratio, P2/P1, consistent absolute units,|
If Fdu ≤ Fcf, then Fdu = Fcf (critical flow). The gas-compressibility factor is not included in Eq. 12.5; therefore, most published gas passage charts do not include a gas-compressibility factor correction. Since the compressibility factor would enter the equation as a square root term in the denominator, the chart values will be lower than actual values for most injection-gas gravities and pressures. One type of choke capacity chart is illustrated in Figs. 12.13 and 12.14. The advantages of this type of display are the number of orifice sizes on a single chart for a full range of upstream and downstream pressures and that an orifice size can be determined for a given gas rate throughput and the given upstream and downstream pressures. The gas throughput capacity of the different orifice sizes is based standard conditions of 14.65 psia and 60°F for a gas gravity of 0.65 and an orifice discharge coefficient of 0.865.
Because gas flow in a gas lift installation occurs at the gas temperature at valve depth, a correction for temperature improves the prediction for the volumetric gas rate. If the actual gravity differs from 0.65, a second correction should be applied. An approximate correction for gas passage can be calculated using Eq.12.6.
|CgT||=||approximate gas gravity and temperature correction factor for choke charts, dimensionless,|
|TgD||=||gas temperature at valve depth, °R,|
|qga||=||actual volumetric gas rate, Mscf/D, and|
|qgc||=||chart volumetric gas rate, Mscf/D.|
Although many gas lift manuals will include gas capacity charts for most typical orifice and choke sizes, numerous charts are unnecessary. The gas capacity for an orifice or choke size can be calculated from a known gas capacity for a given choke size because the calculated volumetric gas throughput rate is directly proportional to the area open to flow for the same gas properties and discharge coefficient.
|qg1||=||known volumetric gas rate, Mscf/D,|
|d1||=||orifice or choke ID for known volumetric gas rate, in.,|
|qg2||=||unknown volumetric gas rate, Mscf/D, and|
|d2||=||orifice or choke ID for unknown volumetric gas rate, in.|
If d1 and d2 are fractions, then the denominator of both terms must be the same.
Example Problem 2 Given:
- Injection-gas specific gravity (air = 1.0), γg = 0.7
- Orifice check valve choke size = 1/4-in. ID.
- Injection-gas pressure at valve depth (upstream pressure, P1), PioD = 1,100 psig.
- Flowing-production pressure at valve depth (downstream pressure, P2), PpfD = 900 psig.
- Injection-gas temperature at valve depth (T1), TgD = 140°F.
- Determine the actual volumetric gas throughput of the orifice-check valve:
Calculate volumetric gas throughput of a 1/2-in.-ID orifice on the basis of the capacity of a 1/4-in.-ID orifice and compare the calculated and chart values (1,200 Mscf/D from Fig. 12.13 for 1/4-in.-ID orifice),
qgc = 4,800 Mscf/D for 1/2-in.-ID orifice from Fig. 12.14. There have been misleading references in the literature to the validity of the Thornhill-Craver equation related to gas lift installation design and operation. It is not the equation that is in error. The assumption that a gas lift valve is fully open for all injection-gas throughput calculations is incorrect in most instances. An unloading or operating gas lift valve is seldom fully open. The Thornhill-Craver equation would yield a reasonably accurate injection-gas rate through an operating valve if the actual equivalent port area open to injection-gas flow and the correct discharge coefficient were used in the equation.
Gas Volume Stored Within a Conduit
Typical applications for gas volume calculations are given next.
- The volume of injection gas required to fill the production conduit and to displace a liquid slug to the surface for intermittent gas lift operations.
- The volume of injection gas available, or removed, from a casing annulus on the basis of a change in the casing pressure during an intermittent injection-gas cycle (particularly important for design calculations using choke control of the injection gas).
- The capacity calculations for storage, or retention, of the injection gas in the low- and high-pressure systems in a closed, rotative gas lift system.
The gas capacity and volume calculations are based on an equation of state for real gases.
|V||=||volume or capacity, ft3,|
|z||=||compressibility factor based on P and T, dimensionless,|
|n||=||number of pound-moles, lbm mol,|
|R||=||universal gas constant = , and|
|T||=||gas temperature, °R.|
The volume of gas required to fill a conduit can be calculated with Eq. 12.10.
Also, the volume of gas can be calculated by solving for the number of pound-moles in Eq. 12.9 and by converting the pound-moles to standard cubic feet using Avogadro’s principle which states that 1 lbm-mole of any gas occupies approximately 379 scf at 14.7 psia and 60°F. Average values for pressure and temperature based on surface and bottomhole values and the corresponding compressibility factor must be used in the equation for inclined conduits.
A gas volume equation for pressure difference can be written as
where subscripts 1 and 2 refer to the high and the low average pressure and the corresponding compressibility factor, respectively, and the average gas temperature does not change. If the conduit is horizontal, average pressures and temperature are the surface values in Eqs. 12.10 and 12.11. The average temperature of a gas column in the casing is assumed to be the same at the instant a gas lift valve opens or closes. Eq. 12.11 may be simplified by using one compressibility factor for an average of the average pressures. This assumption is particularly applicable for very little change at high pressure.
Approximate estimations and questionable field data do not warrant detailed calculations. The approximate volume of gas required for a given change in pressure within a conduit can be calculated with Eq. 12.12.
Vgx is the approximate gas volume at standard conditions, scf.
The ratio of the standard to the average temperature, which is less than unity in most cases, tends to offset the reciprocal of the compressibility factor that is greater than unity. This compensation decreases the error from not including several variables in the approximate equation.
Gas Lift Equipment
IntroductionThe advent of the unbalanced, single-element, bellows-charged gas lift valve (as illustrated in Fig. 12.15) 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. 12.15. 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.
Gas Lift Valve Mechanics
Unbalanced, Single-Element Gas Lift ValvesThe unbalanced, single-element gas lift valve is essentially an unbalanced pressure regulator. The analogy between these two devices is apparent in Fig. 12.16, where (a) injection-pressure-operated gas lift valve and backpressure regulator responds to injection-gas pressure and upstream pressure, respectively, and (b) production-pressure-(fluid)-operated gas lift valve and downstream-pressure regulator respond to flowing production pressure and downstream pressure, respectively. The closing force for a gas lift valve can be a gas pressure charge in the bellows exerted over the effective bellows area or a spring force, or a combination of both. The closing force for the regulator or gas lift valve can be adjusted to maintain a desired backpressure for injection-pressure operation. The regulator or valve remains closed until this set closing force is exceeded.
Generally, the major initial opening force for a gas lift valve is the pressure exerted over the effective bellows area minus the port area, and the lesser opening force is the pressure acting over the port area. In like manner, the major opening pressure for a pressure regulator is applied over an area equal to the diaphragm area minus the port area. The effect of the unbalanced opening force is far less for most unbalanced backpressure and pressure-reducing regulators than for gas lift valves. The reason is that the ratio of the port area to the total effective bellows area of a gas lift valve is much greater than the ratio of the port area to the total diaphragm area for most regulators. The operating principle remains identical for the gas lift valve and regulator, but the pressure applied over the port area has greater effect on the initial opening pressure of most gas lift valves.
Pilot-Operated Gas Lift ValvesThere are numerous special application gas lift valves available. The operation of many of these unique valves can be analyzed using the static force-balance equations for the unbalanced, single-element, gas lift valve. The many different types of gas lift valves and the variation in calculations are not discussed in this section because of their limited application. However, one special-purpose valve of particular importance is the pilot-operated gas lift valve.
The pilot-operated gas lift valve in Fig. 12.17 has operating characteristics that are ideally suited for chamber installations and deep intermittent gas lift operations with low injection-gas operating pressure and small tubing in large casing. The pilot valve offers a very large main port with controlled spread and a predictable constant closing pressure. Spread is defined as the difference between the initial valve opening and closing pressures. This type of valve functions properly on time cycle or choke control of the injection gas. The pilot section operates in the same manner as a single-element gas lift valve with a small choke located downstream of the valve seat. The production pressure at valve depth is exerted over the ball/seat contact area of the pilot section as an initial opening force. When the pilot section begins to open, an increase in pressure occurs between the pilot valve seat and the main valve piston. This increase in pressure above the piston results in compression of the spring under the piston, and the main valve snaps open. An exceedingly high, instantaneous, injection-gas rate enters the tubing through the large main valve port. As the injection-gas pressure in the casing decreases from gas passage through the large main port, the pilot section begins to close. The pressure downstream of the pilot port remains approximately equal to the injection-gas pressure until the pilot port area open to injection-gas flow becomes less than the bleed-hole area in the main valve piston. When the pressure across the piston approaches equalization, the spring returns the main valve to its seat.
The closing pressure of a pilot valve is considered predictable because it is approximately equal to the theoretical closing pressure of an unbalanced, single-element gas lift valve. The pressure upstream and downstream of the pilot port is approximately equal at the instant the pilot section closes. Selecting the proper pilot port size controls the spread of a pilot valve. The high injection-gas throughput capacity of the large main valve port is unaffected by the pilot port size.
Valve Specifications Including Full-Open Stem TravelManufacturers publish gas lift valve specifications for their valves. Some manufacturers assume a sharp-edged seat for the ball/seat contact, and others arbitrarily add a small increase to the port ID to account for a slight bevel for the ball-seat contact. Because most manufacturers use the same sources for their supply of bellows, the effective bellows areas are considered the same. The generic gas lift valve specifications in Table 12.2 are representative of many actual unbalanced, single-element, gas lift valves. The theoretical fully open stem travel is not included in the valve specifications published by most manufacturers.
The stem travel required to fully open an unbalanced, single-element gas lift valve increases with port size, as illustrated in Fig. 12.18. The curves were calculated for gas lift valves with a square, sharp-edged seat and a ball on the stem that is 1/16-in. larger in OD than the bore diameter of the port. The calculated equivalent port area, before a valve is fully open, is based on the lateral surface area of the frustum of a right circular cone. The major area of the frustum is the ball/seat contact area, which remains constant. The minor area decreases with an increase in stem travel as the ball moves away from its seat.
Actual gas lift valve injection-gas rate throughput performance is seldom mentioned in published gas lift installation design literature. Gas lift valves with the larger ports may, or may not, fully open and have the predicted injection-gas capacity for gas lifting high-rate wells through large tubing or the casing annulus.
Gas Lift Valve Port ConfigurationsThe port geometry and the maximum valve-stem travel affect the volumetric injection-gas throughput rate of a gas lift valve. Most gas lift valves have a polished carbide ball that is silver soldered to the valve stem. The valve seat can have a sharp-edged port or a taper. The chamfer may be very slight for breaking the seat line or may be of sufficient depth to assure that the ball remains in the taper for full-stem travel. A sharp-edged and a tapered seat with a 45° chamfer are illustrated in Fig. 12.19. Note that in (a) the sharp-edged seat has an effective Ap equal to the bore area through the seat and in (b) the tapered seat has a 45° chamber measured from the horizontal (90° included angle). The effective Ap in the Ap/Ab ratio is the ball/seat contact area and not the bore area through the seat. The example calculations in this section are based on the sharp-edged seat because the majority of gas lift valves in service have a sharp-edged seat or a very shallow chamfer for breaking the seat line. The calculations are basically the same for a sharp-edged seat and a seat with a shallow taper. The calculations for an equivalent area open to the injection-gas flow differ for a seat with a deep chamfer. There has been no standard angle adopted for the taper of a gas lift valve seat. Certain manufacturers use the same tapered seat for different stem-ball sizes, and the bore area through the seat may be the same. The area of the port used in the port-to-bellows area ratio must be redefined for a tapered seat when the ball/seat contact area is larger than the bore area through the seat, as shown in Fig. 12.19b. The Ap/Ab ratio is the ball/seat contact area, not necessarily the bore area through the seat, divided by the effective bellows area.
The specifications for the gas lift valve depend upon the ball size and the angle of the chamfer for valves with a port configuration similar to Fig. 12.19b. The selection of an angle for the taper, ball size, and the bore area through the seat can result in a ball/seat contact at the base of the taper. For this geometry, the bore area of the port would be used in the Ap/Ab term. The maximum stem travel in many gas lift valves with a deep taper is restricted to prevent the ball from pulling out of the taper, and the valve always remains in the throttling mode. A throttling mode implies that the generated area open to flow for the injection gas is less than the bore area through the valve seat. Certain types of gas lift valves with a deep tapered seat are designed to operate only in the throttling mode for continuous-flow application.
Crossover SeatsSeveral types of gas lift valves have a crossover seat for a particular application. The crossover seat is designed to direct the downstream pressure into the valve body where the pressure is exerted over the effective bellows area less the ball/seat contact area. The upstream pressure is applied to the ball/seat contact area. The crossover seat in Fig. 12.20 is a schematic illustrating the principle of a crossover seat. A choke upstream of the port controls the maximum injection-gas rate and aids in keeping downstream pressure applied over the bellows area after the valve opens. An actual crossover seat has a group of bypass openings or a milled area around the main port. The total bypass area must significantly exceed the port area to ensure that a valve with a crossover seat will close.
An example of the need for a crossover seat is a production-pressure-operated gas lift valve installed in an injection-pressure-operated gas lift valve mandrel. Another application is a casing (annulus) -flow gas lift valve in a tubing-flow mandrel. In both examples, the gas lift valve is modified, rather than the mandrel. An example is a wireline-retrievable gas lift valve mandrel with pockets designed for injection-pressure-operated gas lift valves and tubing flow that has been installed in a well. The operator desires production-pressure operation. The solution is production-pressure-operated gas lift valves with a crossover seat.
Gas lift valves with a crossover seat are not recommended if the proper mandrels can be installed to eliminate the need for a crossover seat. The maximum port size is limited for valves with a crossover seat. This limitation can be very serious in wells requiring high injection-gas rates. Another problem with a crossover seat is the possibility of partial plugging of the crossover bypass area. The physical bypass area should be at least 100% greater than the valve port area because the bypass openings usually are smaller and more likely to plug than a valve port that can be opened and closed. The production-pressure-operated gas lift valve does not close at the design closing pressure when the crossover area results in a significant pressure loss. The pressure exerted over the bellows area is between the flowing-production and injection-gas pressures rather than at the lower flowing-production pressure.
Many production-pressure-operated gas lift valves with crossover seats can be choked upstream of the ball/seat contact area. The same port size may be used in all valves, and the volumetric injection-gas throughput, for the upper unloading gas lift valves, is limited by a choke size that is smaller than the port area. The small inlet chokes tend to reduce the valve closing-pressure problem associated with production-pressure operation.
All reputable manufacturers of gas lift valves have provided bellows protection in the design of their valves. A bellows should be protected from a high pressure differential between the bellows-charge and the wellbore pressures and from the possibility of a resonance condition that can result in high-frequency valve stem chatter. The bellows-charge pressure is atmospheric pressure for most spring-loaded valves. The maximum pressure differential across the valve bellows occurs in most installations during initial unloading operations when the lower gas lift valves are subjected to exceedingly high hydrostatic-load-fluid pressures in deep wells.
Gas lift valve bellows are protected from high hydrostatic pressures by several methods: (1) hydraulically preformed bellows by a high pressure differential, with or without, support rings within the bellows convolutions, (2) a confined liquid seal in the bellows with full stem travel, and (3) isolation of bellows from outside pressure with full stem travel. The primary purpose of these methods for protecting the bellows is to prevent a permanent change in the radii of the convolutions after installation in a well, which in turn, can change the operating pressure of a gas lift valve.
The possibility of a valve-stem chatter condition is not predictable. The evidence of valve-stem chatter is a bellows failure and a dished-out seat if the valve seat is not manufactured from an extremely hard material. Many gas lift valves have some form of dampening mechanism, and the majority of these devices operate hydraulically. The bellows are partially filled with a liquid, generally a high-viscosity silicone fluid. A restricted liquid-flow rate within the bellows or a fluid-shear dampening mechanism prevents valve-stem chatter.
Stabilization of Test-Rack Opening Pressures
One of the most important procedures for preparing gas lift valves for installation in a gas lift well is the stabilization of the operating pressure. The test-rack set opening or closing pressure of an unbalanced, single-element, nitrogen-charged or spring-loaded bellows gas lift valve should be stabilized before installation in a well. Many operators and manufacturers call the process "aging." The purpose of this procedure is to prevent the set operating pressure of a valve from changing after being run in a well. Another term for valve operating pressure changes is valve set pressure "scrambling," which may prevent a gas lift well from unloading, cause inefficient multipoint gas injection, or may cause an unpredictable variation in operating valve depth.
After setting the test-rack opening or closing pressure, the gas lift valve is placed in a high-pressure vessel filled with water. The valve is fully stroked several times by alternately increasing and decreasing the pressure of the water confined in the vessel. The exact procedure varies among manufacturers. Typically, the maximum pressure ranges between 3,000 and 5,000 psig, and the minimum number of cycles is between 5 and 10. The valve is removed from the high-pressure vessel, and the test-rack opening pressure is rechecked at the base setting temperature. If the opening pressure varies more than a specified few psi, the valve must be reset and the procedure repeated until the test-rack opening or closing pressure stabilizes. Also, the process identifies valve bellows and bellows weld failures.
Bellows-Assembly Load RateBellows-assembly load rate is defined as: the psi increase exerted over the bellows area per linear unit travel of the valve stem. The controlled pressure is applied over the entire effective bellows area, and the valve-stem travel is measured by means of a depth micrometer. A typical gas lift valve probe tester is shown in Fig. 12.21.  The bellows-assembly load rate is the slope of the pressure vs. stem travel best-fit straight line in the linear portion of the curve in Fig. 12.22. 
Fig. 12.21-Typical gas lift valve probe-test fixture.
Fig. 12.22-Determination of bellows-assembly load rate and maximum linear valve-stem travel (after API Spec. 11 V1).
The best-fit straight line represents an average between the stem travel measured for increasing and decreasing probe-tester pressures. The increase in nitrogen-charged dome pressure with stem travel is negligible, as compared with the load rate of a bellows-assembly in most bellows-charged gas lift valves. The load rate of a bellows assembly, which is analogous to the load rate of a helical spring, is far greater than the effect of the increase in dome pressure resulting from the decrease in dome capacity for the stem travel required to open a typical gas lift valve.
The measured bellows-assembly load rate is not identical for all gas lift valves with the same size bellows. The typical three-ply, seamless Monel bellows that is used in many 1.5-in.-OD gas lift valves has a reported effective bellows area of 0.77 in.2. The typical bellows-assembly load rate for a valve with a nitrogen-charged bellows ranges from 400 to 600 psi/in. in the linear portion of the curve for a valve with a test-rack opening pressure between 600 and 1,200 psig. The three-ply, seamless Monel bellows in the 1-in.-OD valve has a reported effective area of 0.31 in.2 and a bellows-assembly load-rate range of 1,200 to 2,200 psi/in. for a valve with a nitrogen-charged bellows and a test-rack opening pressure between 600 and 1,200 psig. The bellows-assembly load rate for a spring-loaded 1-in.-OD valve can range from near 2,000 to more than 3,500 psi/in. It is similar to the load rate of a spring. The load rate of a spring depends on the wire size, material, and number of free coils. The purpose in noting the magnitude of the bellows-assembly load rate for typical gas lift valves is to emphasize the fact that an unbalanced, single-element, gas lift valve will not "snap" open. An increase in injection-gas pressure, or in flowing-production pressure, or a combination of an increase in both pressures, is necessary to stroke the valve stem. The larger-OD gas lift valves should be selected for installations requiring high injection-gas rates because the smaller valves do not have the same gas throughput rate performance as the larger-OD valve with the same port size. Valves with the smaller bellows assembly are not recommended for low-pressure injection-gas systems that may be used to gas lift shallow wells. The low closing force and bellows stiffness can result in leaking valve seats because of poor ball/seat seating characteristics at low injection-gas valve opening pressures.
Static Force-Balance Equations for Unbalanced, Single-Element, Bellows-Charged Gas Lift ValvesMost gas lift equipment manufacturers test-rack set valve opening pressures are based on 60°F for nitrogen-charged gas lift valves. The valve is submerged in a 60°F water bath to ensure a constant nitrogen temperature in the bellows of each valve during the test-rack setting procedure. The initial test-rack opening pressure is measured with the tester pressure applied over the effective bellows area less the ball/seat contact area while atmospheric pressure (0 psig) is exerted over the ball/seat contact area. The valve actually is closed and begins to open from an opening force that is slightly greater than the closing force. The tester gas rate through the valve seat is very low. Although most gas lift valves are set with an initial opening pressure, certain types of valves with high production-pressure factors and valves with unique construction may be set at test-rack closing pressures.
The test-rack closing pressure is obtained by bleeding the tester gas from the downstream side of a gas lift valve. This theoretical closing pressure is noted when the downstream pressure continues to decrease and the upstream pressures remain constant. The upstream and downstream pressures are equal momentarily at the instant a gas lift valve closes. An accurate closing pressure is more difficult to observe than an initial opening pressure and can be affected by the rate of decrease in the tester pressure during bleedoff of the tester gas. An encapsulating tester with gas capacity rather than a ring-type tester is recommended so that any small leaks in the tester piping will not prevent observation of the true gas lift valve closing pressure. The pressure should be bled off of the downstream side of the valve through a very small orifice.
The equations for initial valve opening pressure in a tester and in a well, and a tester closing pressure, are based on static force-balance equations. These equations also apply to spring-loaded gas lift valves. The spring-load effect replaces the bellows-charge pressure of the valve as the closing force. Several manufacturers with spring-loaded gas lift valves report a test-rack closing pressure. The spring is adjusted until the force exerted by the spring is equal to the desired test-rack closing pressure. A base-temperature correction does not apply to the opening- or closing-pressure calculations of spring-loaded gas lift valves. If the total closing force for a gas lift valve is a combination of a bellows-charge pressure and a spring load, the spring-load effect must be subtracted from the total closing force to obtain the bellows-charged-pressure portion of this closing force before calculating the bellows charge pressure from well to tester base temperature.
The following equations for the initial gas lift valve opening pressures in a tester and in a well are derived for a bellows-charged injection-pressure-operated gas lift valve because most gas lift installations are gas lifted with this type of valve In Fig. 12.23, (a) shows the determination of the test-rack opening pressure, Pvo, by flowing supply gas at a low rate into a ring type tester with atmospheric pressure applied to the port area and in (b) the test-rack closing pressure, Pvct, is obtained by opening the gas lift valve, closing the supply valve, and slowly bleeding off the encapsulating tester pressure downstream of the port. In (c), the initial valve opening pressure in a well, PoD, is based on the injection-gas and flowing-production pressures at valve depth. The injection-gas and flowing-production pressures are interchanged for production-pressure-operated (fluid-operated) gas lift valves.
Initial Valve Opening Pressure in a Tester at 60oF (Fig. 12.23a).Closing force = opening force.
Valve Closing Pressure in a Tester at 60oF (Fig. 12.23b).Closing force = opening forces.
Initial Opening Pressure in a Well (Fig 12.23c).Closing force = opening forces.
Solving for the Injection-Gas Initial Valve Opening Pressure in a Well.
Additional Related Valve Mechanics Equations.
|Ab||=||total effective bellows area, in.2,|
|Ap||=||valve port area (ball/seat line contact area for sharp-edged seat), in.2,|
|CT||=||temperature correction factor for nitrogen from PbvD at TvuD to Pb at 60°F, dimensionless,|
|Fp||=||production-pressure factor, dimensionless,|
|n||=||valve location designation (n = 1 for top valve),|
|Pb||=||nitrogen-charged bellows pressure at 60°F, psig,|
|PbvD||=||nitrogen-charged bellows pressure at valve temperature, psig,|
|Po||=||surface initial valve opening pressure, psig,|
|PoD||=||initial gas lift valve opening pressure at valve depth, psig,|
|Pot||=||tester pressure upstream of gas lift valve port, psig,|
|Ppe||=||production-pressure effect, psi,|
|PpfD||=||flowing-production pressure at valve depth, psig,|
|Ppft||=||tester pressure downstream of gas lift valve port, psig,|
|Pvct||=||test-rack valve closing pressure at 60°F if Ppft = Pot at instant valve closes, psig,|
|PvoD||=||initial gas lift valve opening pressure at valve depth if PpfD = 0, psig,|
|ΔPpe||=||variation in production-pressure effect, psi.|
Initial Opening and Closing Pressures of an Unbalanced, Single-Element Gas Lift ValveAn understanding of the relationship between the initial opening and closing pressures of an unbalanced, single-element gas lift valve is important for calculating gas lift installation designs and analyzing gas lift operations. An unbalanced, single-element, gas lift valve does not have a constant closing pressure as noted in many publications, and the valve does not "snap" fully open at the initial injection-gas opening pressure. This type of gas lift valve initially opens and closes at the same injection-gas pressure if the flowing-production pressure and valve temperature remain constant. In like manner, an unbalanced backpressure regulator opens and closes at the same upstream pressure if the downstream pressure remains constant.
Fig. 12.24 shows a plot of the initial injection-gas opening pressure vs. the flowing-production pressure curves for both a 1/4-in.- and 1/2-in.-ID sharp-edged port in a 1.5-in.-OD gas lift valve having an effective bellows area of 0.77 in.2. Most manufacturers use this bellows size in the 1.5-in.-OD gas lift valve.
The closing force for an unbalanced, single-element gas lift valve is assumed to remain constant for this analysis. The gas lift valve is actually closed on the line that represents a balance between the opening and closing forces in Fig. 12.24. The valve begins to open above the line and is closed below the line. The valve can be opened by increasing the injection-gas pressure with a constant flowing-production pressure, increasing both the injection-gas and flowing-production pressures simultaneously, and increasing the flowing-production pressure with a constant injection-gas pressure.
Production-Pressure Factor and Valve Spread
The production-pressure factor, Fp, is a relationship based on the effective bellows and ball/seat-contact areas for an unbalanced gas lift valve. Unbalanced implies that the flowing-production pressure is exerted over the entire ball/seat contact area as a portion of the initial opening force for a valve. In terms of gas lift valve operation, the production-pressure factor is the ratio of the incremental difference in the initial injection-gas opening pressures to a difference in the corresponding flowing-production pressures. If the flowing-production pressure increases, the initial injection-gas opening pressure decreases, and vice versa. The production-pressure factor can be obtained from the slope of the force-balance lines in Fig. 12.24 or can be calculated from the specifications for the valve.
Valve spread is defined as the difference between the initial injection-gas opening and the injection-gas closing pressures of a gas lift valve. The valve spread is zero for a constant flowing-production pressure because a valve initially opens and closes at the same injection-gas pressure. The valve spread observed in intermittent gas lift operations results from a large port and the change in the flowing-production pressure at the depth of the operating gas lift valve during an injection-gas cycle. The production pressure at valve depth approaches the injection-gas pressure beneath a liquid slug during gas injection, thus decreasing the valve closing pressure, which results in a spread between the initial opening and closing pressures of the operating valve. This can be a very important consideration for a chamber-lift installation where the initial opening pressure of the operating gas lift valve is high because of low tubing pressure. The operating gas lift valve is located above the chamber, and the tubing pressure, at valve depth exerted over the ball/seat contact area when the valve initially opens, is very low. The tubing pressure may approach the injection-gas pressure at the time the valve closes, thus resulting in a low closing pressure.
Injection-Gas Volumetric Throughput Rates for a Fixed Choke Compared to Unbalanced, Single-Element Gas Lift ValvesThe difference in the injection-gas rate throughput performance of unbalanced, single-element, injection-pressure-operated gas lift valves and a fixed-size choke is illustrated in Fig. 12.25. The flowing-production pressure is a constant 500 psig. The gas lift valves have an injection-gas initial opening pressure of 1,000 psig. As soon as the injection-gas pressure exceeds 500 psig, injection gas enters the production conduit through the 1/4-in.-ID choke. The injection-pressure-operated gas lift valves are backpressure regulators and metering devices because of the bellows-assembly load rate. These valves prevent injection-gas entry into production conduit until the injection-gas pressure exceeds the 1,000-psig set pressure. The difference in the injection-gas throughput performance of these two gas lift valves with the same 1/4-in.-ID sharp-edged port is from the bellow-assembly load rates. A greater injection-gas pressure increase is required to stroke the valve stem of the valve with the higher load rate.
The effective area of the bellows, the bellows-assembly load rate, the stem/seat configuration, and the linear valve-stem travel control the injection-gas throughput performance of a gas lift valve. The 1-in.-OD valve with a 0.31-in.2 bellows area has the higher load rate of 1,800 psi/in., and the 1.5-in.-OD valve with a 0.77-in.2 bellows area has the lower load rate of 400 psi/in.
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 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. 12.18, 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.
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 12.2.). 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.
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.
Design of Gas Lift Installations
Continuous FlowContinuous-flow gas lift is analogous to natural flow, but there are generally two distinct flowing-pressure traverses. The traverse below the point of gas injection includes only formation gas; whereas, the traverse above the point of gas injection includes both the formation and injection gases. These two distinct flowing-pressure traverses and their corresponding gas/liquid ratios (GLR) are illustrated in Fig. 12.1.
There are numerous gas lift installation design methods offered in the literature. Several installation designs require unique valve construction or gas lift-valve injection-gas throughput performance. Only two design techniques are illustrated in this section: (1) a design based on a constant decrease in the operating injection-gas pressure for each succeeding lower valve (this design is essentially the same as the API gas lift design technique in RP 11V6), and (2) an alternative design for wells requiring high injection-gas rates. The API design can be used on the majority of wells in the United States. However, when high-volume lift and high injection-gas rates are required, gas lift valve performance should be considered in the design. Both of these techniques use the simple single-element-type, unbalanced, gas lift valve with a nitrogen-charged bellows. This type of valve is the most widely used in the industry and is available from all major gas lift equipment manufacturers.
Gas lift installation design calculations are divided into two parts. The first part is the determination of the gas lift valve depths, and the second part is the calculation of the test-rack opening pressures of the gas lift valves. The opening pressures are calculated after the valve depths because the operating injection-gas and flowing-production pressures and temperatures during unloading are based on these valve depths.
The primary objective of this section is to outline in detail installation design methods for calculating the valve depths and the test-rack opening pressures of the gas lift valves that will unload a well to a maximum depth of lift for the available injection-gas volume and pressure. The unloading operations, as illustrated by the two-pen pressure recorder chart in Fig. 12.26, should be automatic. The static-load-fluid level was near the surface in the casing and tubing before initial unloading began. The wellhead pressure remains relatively constant during U-tubing operations before injection gas enters the tubing for the first time through the top gas lift valve. A surge in wellhead tubing pressure and a decrease in the injection-gas casing pressure occur as the depth of gas injection transfers to each lower gas lift valve. As each lower gas lift valve is uncovered, the valve immediately above closes, and the point of gas injection transfers from the upper to the lower valve. All gas lift valves above an operating valve should be closed and the valves below should be open in a properly designed gas lift installation.
Description of Unloading Operations for Continuous-Flow Gas LiftThe depths of the unloading gas lift valves are calculated to unload the kill (load) fluid to the design depth of the operating valve with the injection-gas pressure and gas volume available at the wellsite. As the injection gas is initially injected into the casing annulus, the injection-gas pressure downstream of the control device on the injection-gas line increases as the load-fluid level in the casing annulus is lowered during U-tubing of the load fluid. The load fluid is transferred into the tubing through the open gas lift valves in a well with a packer, or through the open gas lift valves and lower end of the tubing in a well without a packer. Initial gas lift operations begin after the first gas lift valve is uncovered and injection gas enters the tubing at this top-valve depth.
The pressures in the casing and tubing are essentially equal at the instant a gas lift valve is uncovered. Immediately after injection gas begins to enter the tubing through the next lower gas lift valve, the injection-gas pressure in the casing begins to decrease because the newly uncovered gas lift valve is set to remain open at a lower injection-gas pressure than the unloading valve above. Less and less injection gas enters the tubing through the upper unloading valve. The injection-gas rate through the newly uncovered valve increases until the injection-gas pressure in the casing decreases to the closing pressure of the upper unloading valve. The depth of gas-injection transfer is complete when all injection gas is entering the tubing through the lower valve and all upper gas lift valves are closed. The principles of continuous-flow operation are illustrated by a pressure/depth diagram shown in Fig. 12.27.
As injection gas enters the tubing through a newly uncovered valve, the flowing-production pressure decreases. The injection-gas pressure in the casing begins to increase from a decreasing opening force from a lower flowing-production pressure at the valve depth and the need for stroking the valve stem to increase the injection-gas rate into the tubing for uncovering the next lower valve. The increase in the injection-gas pressure above the initial valve opening pressure at valve depth for passing the injection-gas rate to establish the flowing-production transfer pressure must be determined. This maximum injection-gas pressure required to stroke the valve stem sufficiently to pass the injection-gas rate necessary to transfer the depth of gas injection to the next lower valve depends on the gas lift valve performance. The valve port ID, bellow-assembly load rate, and linear stem travel control the gas lift valve performance. The design maximum injection-gas pressure for establishing the flowing-production transfer pressure from a lower valve during unloading should not result in reopening any of the upper gas lift valves. In Fig. 12.27, the injection gas is entering the production conduit through the fourth gas lift valve and the three upper unloading gas lift valves are closed. Although the bottom gas lift valve is open, no injection gas can enter this valve at depth D5 because the flowing-production pressure exceeds the injection-gas pressure at this depth. The flowing-pressure-at-depth traverse gradient, gpfa, above the operating gas lift valve depth, Dov , includes the injection- plus the formation-gas production, and the flowing-pressure-at-depth traverse gradient, gpfb, below Dov contains only formation-gas production.
Initial Installation Design Considerations
Continuous-flow installation designs vary depending on whether complete and precise well data are known. Reliable inflow well performance and an accurate multiphase-flow correlation are required to establish the approximate point of gas injection in deep wells. When the well data are limited or questionable, the exact point of gas injection cannot be calculated accurately in many wells. If there is insufficient injection-gas pressure to reach the bottom of the well, a desired depth of gas injection may not be possible. If there is no change in injection-gas pressure or well conditions, the point of gas injection should remain at the maximum depth for the life of the gas lift installation.
Retrievable gas lift valve mandrels are installed (usually with dummy valves in place) in many wells before little, if any, well-production information is available. The engineer must locate these mandrels in wells before gas lift is required. The design considerations are similar for wells with a changing point of gas injection. In general, many gas lift installations are in this category, in which accurate well data are unknown or limited and the point of gas injection is unknown and/or changing as the reservoir is depleted.
Installation Design Methods
The two installation design methods given in this chapter can be classified as: (1) the decreasing injection-gas pressure design in API, and (2) a variation of the decreasing injection-gas pressure design that considers valve performance at each station.  Valves with small production-pressure factors, Fp, are recommended for the decreasing injection-gas pressure installation design method. Valves with a small Fp (under 0.2) are sensitive primarily to a change in the injection-gas pressure. A decrease in the surface operating injection-gas pressure for each lower gas lift valve is essential to ensure the closure of upper unloading valves after gas injection has been established through a lower operating valve. This design is particularly applicable when the available injection-gas pressure is high relative to the required depth of lift and an additional incremental decrease in injection-gas pressure can be added between valves.
If gas lift valves with large ports are required to pass sufficient gas rates for unloading and lifting a well, the design that incorporates valve performance should be used. Generally, if the operating valve is not near the packer, the calculated point of gas injection will be bracketed by installing at least one valve below the calculated operating valve depth in the event there is a slight error in the well information or a change in well conditions.
Assumptions and Safety Factors in the Simplified Continuous-Flow Installation Design Methods Without Consideration of Gas Lift Valve Performance
Safety factors are used for continuous-flow gas lift installation design with unbalanced, single-element, gas lift valves when the load rate and the gas throughput performance of the valve are not considered in the calculations. The initial gas lift valve opening pressures are based on the static force-balance equations. Safety factors allow the injection-gas and/or the flowing-production pressure to increase at valve depth, which is needed to properly stroke the valve stem and provide the equivalent port area required to pass the injection-gas rate necessary for unloading and gas lifting most wells. The following safety factors compensate for the fact that most operators set the gas lift valves to the nearest tubing joint. The actual depth of the gas lift valve is usually within 15 ft of the calculated depth.
- The operating injection-gas pressure used for the installation design calculations should be the average and not the maximum injection-gas pressure available at the wellsite for most wells. In special cases, a kick-off pressure can be used.
- The unloading daily production rate is assumed equal to the design daily production rate. Generally, the actual unloading daily production rate may be less than the design production rate and can be controlled at the surface by the injection-gas rate.
- No formation gas is produced during the unloading operations. The total gas/liquid ratio is based on the daily injection-gas rate available for unloading the well.
- The flowing-pressure-at-depth traverses above the unloading gas lift valves are assumed to be straight lines for the design calculations.
- The unloading flowing-temperature-at-depth traverse is assumed to be a straight rather than a curved line between an assigned unloading flowing wellhead temperature, Twhu, and the bottomhole temperature, Twsd.
The design surface unloading flowing temperature generally is assumed to be lower than the final, operating temperature. A final flowing temperature that is slightly higher than the design temperature increases the initial opening pressure of a bellows-charged gas lift valve and aids in keeping the upper valves closed while lifting from a lower gas lift valve.
- An assigned valve-spacing pressure differential, ΔPsD, of 20 to 60 psi across a valve for unloading is used by many gas lift design engineers. As a result, the actual minimum flowing-production pressure required to uncover the next lower unloading gas lift valve is greater by the assigned ΔPsD.
- The flowing-pressure traverse below the point of gas injection for locating the valve depths is normally assumed to be the static-load-fluid gradient. Once formation production occurs, the actual flowing pressure gradient decreases in most wells.
An Orifice-Check Valve for the Operating Gas Lift Valve in Continuous-Flow InstallationsAn orifice being used for gas lifting a well should include a reverse-flow check valve. The check disk, or dart, should be closed by gravity or spring loaded. In a well with a packer, the check portion should remain closed to prevent debris from accumulating on top of the packer when this valve is below the working fluid level and is not the operating valve. An inlet screen is recommended for orifice-check valves with a small choke to prevent possible plugging. The individual openings in the inlet screen should be smaller than the choke in the orifice-check valve.
A properly designed continuous-flow gas lift installation with an orifice-check valve does not have a higher injection-gas requirement than the same well with an injection-pressure-operated gas lift valve. The injection-gas rate for lifting a well is controlled by the metering device on the injection-gas line at the surface. An orifice-check valve rather than a more expensive and complicated pressure-operated gas lift valve should be considered for the bottom valve in most continuous-flow installations.
Advantages of an Orifice-Check Valve. The orifice-check valve is the simplest of all types of operating valves and has a very low possibility of malfunction. It can be used as a "flag" because of the change in the surface injection-gas pressure downstream of the control valve when the orifice-check valve is uncovered and becomes the point of gas injection. Fig. 12.28 illustrates an unloading operation using an orifice-check valve on bottom. The heading flowing wellhead tubing pressure is the result of the opening and closing of the unloading gas lift valves because of a 24/64-in. choke in the flowline and a frictional drag mechanism in the valve to prevent stem shatter. After the orifice-check valve is uncovered at approximately 3:00 a.m., there is no heading. The operating injection-gas pressure decrease is the result of low reservoir deliverability and not the gas lift system. A properly sized orifice-check valve can prevent severe heading or surging in a continuous-flow gas lift installation by ensuring a constant orifice size. No injection-gas pressure increase is required to stroke an orifice-check valve, and the orifice size is always known because it is equal to the choke size in the valve. The orifice-check valve is always open and passes gas as long as injection-gas pressure at valve depth exceeds the flowing-production pressure at the same depth. A properly sized orifice is required to control the injection-gas volume for gas lifting some wells. One application is gas lifting one zone of a dual gas lift installation with a common injection-gas source in the casing annulus. A design pressure differential of at least 100 to 200 psi across the orifice is necessary to ensure a reasonably accurate gas-passage prediction.
Disadvantage of the Orifice-Check Valve. If the injection-gas-line pressure is high, relative to the flowing-production pressure at the orifice-check valve depth, freezing can occur at the surface if wet gas is used. The weak wells with an orifice-check operating valve will continue to consume injection gas at lower injection-gas-line pressure than stronger wells with higher flowing-production pressures at the depth of the operating orifice-check valve.
A hole in the tubing or a leaking packer is indistinguishable from an orifice-check valve during a normal, uninterrupted, continuous-flow gas lift operation. An orifice-check valve generally is not recommended for a small closed rotative gas lift system when costly makeup gas is required to charge the system after a shutdown. A properly set injection-pressure-operated gas lift valve closes after a slight decrease in the injection-gas pressure and prevents the unnecessary loss of injection gas from the casing annulus and the small high-pressure system.
Depth of the Top Gas Lift Valve
The top gas lift valve should be located at the maximum depth that permits U-tubing the load fluid from this depth with the available injection-gas pressure. If the well is loaded to the surface with a kill fluid, the depth of the top valve can be calculated with one of the following equations.
|Dv1||=||depth of top valve, ft,|
|Pko||=||surface kick-off or average field injection-gas pressure (optional), psig,|
|Pwhu||=||surface wellhead U-tubing (unloading) pressure, psig,|
|ΔPsD||=||assigned spacing pressure differential at valve depth, psi,|
|gls||=||static load (kill)-fluid pressure gradient, psi/ft,|
|ggio||=||injection-gas pressure-at-depth gradient, psi/ft.|
Eq. 12.29 does not include the increase in the injection-gas pressure to the valve depth, Dv1. This equation is widely used because of a safety factor from neglecting this increase in gas pressure with depth. Eq. 12.30 yields the same depth as a graphical solution without any pressure drop across the top gas lift valve at the instant this valve is uncovered. In other words, the top valve is not uncovered if the actual kick-off injection-gas pressure is less than the design value or if the U-tubing wellhead pressure is higher than assumed. Eq. 12.31 includes injection-gas column weight and an assigned pressure differential at the instant the top valve is uncovered.
The surface U-tubing wellhead pressure is less than the flowing wellhead pressure for most installations. The difference between these two pressures increases for longer flowlines and higher production rates. The wellhead U-tubing pressure is approximately equal to the separator or production-header pressure because the rate of load fluid transfer is very low during the U-tubing operation and no injection gas can enter the flowline until the top gas lift valve is uncovered. Gas lift operations do not begin until injection gas enters the production conduit through the top valve. Flowing wellhead pressure should be used to locate the depths of the remaining gas lift valves.
A load-fluid traverse based on g ls can be drawn from the wellhead U-tubing pressure to the intersection of the kick-off injection-gas pressure-at-depth curve (PkoD traverse) on a pressure/depth plot. The top valve may be located at this intersection, which is the same depth as calculated with Eq. 12.30. An arbitrary pressure drop across the top gas lift valve can be assumed in conjunction with the graphical method, and this technique is the same as Eq. 12.31. If no gas pressure increase with depth is assumed, this method becomes similar to the calculation of Dv1 with Eq. 12.29. For simplicity, Eq. 12.28 is often used for top-valve spacing calculations.
Multiphase-Flow Correlations and Flowing-Pressure-at-Depth Gradient CurvesAccurate flowing-pressure-at-depth predictions are essential for good continuous-flow gas lift installation design and analysis. When computer programs for gas lift installation design and analysis are unavailable for daily routine calculations, the gas lift designers must rely on published gradient curves to determine flowing pressures at depth. Many oil-producing companies have their own multiphase-flow correlations and publish in-house gradient curves. Gradient curves are available from the gas lift manufacturers and are published in books that can be purchased. Where possible, use field data to verify the accuracy of the computer program calculations and gradient curves. It is not the purpose of this chapter to compare the various multiphase-flow correlations or published gradient curves.
The widely accepted multiphase-flow correlations and mechanistic models are based on pseudo-steady state flow without serious heading through a clean production conduit with an unrestricted cross-sectional area. Accurate pressures cannot be obtained from gradient curves based on these correlations if the conduit is partially plugged with paraffin or scale. Emulsions also can prevent the application of these correlations and gradient curves. The applicability of a particular correlation or set of gradient curves for a given well can be established only by comparing a measured flowing pressure to a pressure at depth determined from the correlation or gradient curves. The measured production data must be accurate and repeatable before discounting the multiphase-flow correlations or gradient curves.
A set of typical gradient curves is given in Fig. 12.29. These gradient curves are used in the example installation design calculations in Example Problem 4. GLR and not gas/oil ratio (GOR) is used for these installation design calculations.
Most gradient curves display GLR rather than GOR. For this reason, the first step in the application of gradient curves is to convert GOR to GLR, if only GOR is reported and the well produces water. The GLR can be calculated for a given GOR and water cut with Eq. 12.32.
|Rglf||=||formation gas/liquid ratio, scf/STB,|
|fo||=||oil cut (l – fw), fraction,|
|Rgo||=||gas/oil ratio, scf/STB.|
Example Problem 3 Given:
- Rgo = 500 scf/STB
- Water cut fw = 0.60 (60%)
Calculate the formation GLR: Rglf = (1 – 0.6) 500 = 200 scf/STB.
When gradient curves are used, the depth is a relative depth and may be shifted, whereas pressure is never shifted. If a flowing-pressure-at-depth traverse is being traced, the pressures on the pressure/depth plot must always overlie the same pressures on the gradient curves. For deviated wells where friction is small, use true vertical depths rather than measured depths in a graphical design.
Flowing Temperature at DepthThe accurate prediction of the flowing-production fluid temperature at valve depth is important in the design and analysis of many gas lift installations with nitrogen-charged gas lift valves. The temperature of a wireline-retrievable valve is assumed to be the same as the temperature of the flowing fluids at the valve depth. A retrievable gas lift valve is located in a mandrel pocket inside the tubing and is in contact with the production from the well. The temperature of a conventional valve is between the flowing fluid temperature and the geothermal temperature for the well but is normally closer to the flowing fluid temperature because steel has higher thermal conductivity than gas.
Kirkpatrick published one of the most widely used flowing-temperature-gradient correlations in 1959. The family of flowing-temperature-gradient curves in Fig. 12.30 is based on data from high-water-cut wells being produced by gas lift through 2 7/8-in.-OD tubing over a wide range of production rates. Although the correlation does not include several important parameters, such as GLR and fluid properties, the estimated surface temperature and temperatures at depth have proved to be reasonably accurate for many gas lift operations. Sagar et al. published another flowing-temperature correlation. This empirical method for calculating flowing-temperature profiles is far more rigorous and is based on well data from several areas. The calculation procedure can be programmed easily for predicting surface flowing temperatures in vertical and inclined wells. However, the best approach, when possible, is to measure the temperature-at-depth traverse in the actual gas lift well.
Continuous-Flow Installation Design Based on a Constant Decrease in the Operating Injection-Gas Pressure for Each Succeeding Lower Gas Lift Valve (API Design Technique)
This installation design method is based on all gas lift valves having the same port size and a constant decrease in the operating injection-gas pressure for each succeeding lower gas lift valve. The gas lift valve selection must be based on a port size that allows the injection-gas throughput required for unloading and gas lifting the well. This installation design method is recommended for gas lift valves with a small production-pressure factor. When the ratio of the port area to the bellows area is low, the decrease in the injection-gas pressure between gas lift valves, based on the additional tubing-effect pressure for the top valve, is not excessive. The effect of bellows-assembly load rate on the performance of the gas lift valves is not considered in the installation design calculations. Safety factors included in these design calculations should allow sufficient increase in the operating injection-gas pressure, which is necessary to provide the valve-stem travel for adequate injection-gas passage through each successively lower unloading gas lift valve without excessive interference from upper valves.
Selection of a constant injection-gas pressure decrease, or drop, in the surface operating-injection-gas pressure for each succeeding lower gas lift valve should not be arbitrary, as proposed in some design methods. The pressure decrease should be based on the gas lift valve specifications to minimize the possibility of upper valves remaining open while lifting from a lower valve. The additional tubing-effect pressure for the top gas lift valve is a logical choice for this decrease in the operating injection-gas pressure between valves. Closing or reopening of an injection-pressure-operated gas lift valve is partially controlled by the production-pressure effect, which is equal to the production-pressure factor for the valve multiplied by the difference flowing-production pressure at the top valve depth.
The flowing-production pressure at an unloading-valve depth changes from the transfer pressure, (PpfD)min, to a higher flowing-production pressure after the next lower valve becomes the operating valve. The additional tubing-effect pressure is the difference between (PpfD)min and the maximum flowing-production pressure, at the unloading valve depth, (PpfD)max, after the point of gas injection has transferred to this next lower valve. As the unloading gas lift valve depths increase, the distance between valves and the difference between (PpfD)min and (PpfD)max decrease. Although the additional tubing-effect pressure decreases for lower valves, the injection-gas requirement for unloading increases with depth. An increased stem travel, or stroke, is usually needed for the lower valves to generate the larger equivalent port area necessary for the higher injection-gas requirements with the lower pressure differentials that occur across these deeper valves. A constant decrease in the operating injection-gas pressure equal to the additional tubing-effect pressure for the top valve allows a greater increase in the injection gas above initial opening pressure for lower gas lift valves.
Another application for this simplified design method depends on the relationship between the available injection-gas pressure and the flowing-production pressure at the maximum depth of lift. When the injection-gas pressure significantly exceeds this flowing-production pressure, an arbitrary decrease in the injection-gas pressure, ΔPio, can be added to the additional production-pressure effect for the top valve for calculating the spacing and the initial opening pressures of the unloading gas lift valves. The total decrease in the injection-gas pressure is distributed equally between each successively lower unloading gas lift valve rather than having a sizable injection-pressure drop across the operating gas lift or orifice-check valve. This procedure reduces the possibility of multipoint gas injection through upper unloading gas lift valves by ensuring that these valves remain closed after the point of gas injection has transferred to the next lower gas lift valve.
Determination of Valve Depths. Because this final injection-gas pressure is unknown until the installation is designed, a pressure difference of at least 100 to 200 psi between the unloading PioD and PpfD traverses is assumed for locating the deepest-valve depth. This assumption of (PioD – PpfD = 100 to 200 psi) should ensure calculation of the operating valve depth. The static bottomhole pressure, Pwsd, and temperature, Twsd, generally are referenced to the same depth, which is the lower end of the production conduit, Dd. The steps for establishing the gas lift valve depths follow.
1. Calculate the maximum unloading GLR based on the maximum injection-gas rate available for unloading and the maximum daily design total fluid rate.
|qgiu||=||maximum unloading injection-gas rate, Mscf/D,|
|qlt||=||total liquid (oil + water) daily production rate, B/D,|
|Rgl||=||maximum unloading GLR, scf/STB,|
|Rglu||=||maximum unloading GLR, scf/STB.|
2. Calculate with a multiphase-flow computer program or determine from an appropriate gradient curve the unloading flowing-production pressure at the lower end of the production conduit, Ppfd at Dd, based on the installation design Rgl and qlt. 3. Calculate the unloading flowing-pressure-at-depth gradient above the point of gas injection, gpf, by subtracting the wellhead U-tubing (unloading) wellhead pressure, Pwhu, from the flowing-production pressure, Ppfd at Dd, and dividing by the reference datum depth, Dd.
The traverse above the point of gas injection will actually be a curved line representing a fluid density that typically becomes increasingly less dense as it travels toward the surface. An exception to this is the case of high GLRs at low pressures where the pressure traverse may reverse slope near the surface. However, a straight line is used because it will be easier to calculate the flowing-production pressure at valve depth, PpfD, than with an actual curved flowing-pressure-at-depth traverse. This assumption normally will give a slightly more conservative design.
4. Calculate the static injection-gas pressure at the lower end of the production conduit, Piod at Dd, using Eq. 12.1 and the static injection-gas pressure-at-depth gradient, ggio, by subtracting the surface injection-gas pressure, Pio, from Piod at Dd and dividing by the reference datum depth, Dd.
5. Calculate the unloading gas lift valve temperature-at-depth gradient, gTvu, by assuming a straight line and subtracting the surface unloading flowing wellhead temperature, Twhu, from the bottomhole temperature, Twsd at Dd, and dividing by the reference datum depth, Dd.
6. Calculate the depth of the top gas lift valve, Dv1, on the basis of the surface kick-off or average field injection-gas pressure, Pko, static-load fluid gradient, gls, and the wellhead U-tubing unloading pressure, Pwhu, with either Eqs. 12.29, 12.30, or 12.31. Eq. 12.31 is used in this example. The flowing wellhead pressure, Pwhf, and the wellhead unloading U-tubing pressure, Pwhu, are considered equal in the API Design. 7. Calculate the minimum flowing-production pressure, (PpfD1)min, the injection-gas pressure, PioD1, and the unloading gas lift valve temperature, TvuD1, at the top valve depth by multiplying the appropriate gradient by the valve depth, Dv1, and adding to the appropriate surface values (where n = 1 for top valve):
8. Calculate the depth of the second gas lift valve, Dv2, where n = 2, on the basis of the assigned minimum decrease in surface injection-gas pressure, Δpio, for spacing the gas lift valves and the PioD traverse. A valve-spacing differential of approximately 20 to 30 psi will usually be sufficient for most 1.5-in.-OD gas lift valves. However, 1-in.-OD valves with large ports may require a higher Δpio. This can be checked by calculating the additional production-pressure effect, ΔPpe1, using Eq. 12.49 after the valve depths are calculated for the assigned Δpio. The distance between valves and valve depth are calculated as follows:
Solve for Dbv.
Repeat calculations in Step 7 at second valve depth by calculating (PpfD2)min, PioD2, and TvuD2 with Eqs. 12.37, 12.38, and 12.39.
Repeat calculations in Step 8 for Dbv and Dv3 with Eqs. 12.41 and 12.42.
Repeat Steps 7 and 8 until the maximum desired valve depth, Dv(max), is attained. When the calculated distance between gas lift valves, Dbv, is less than an assigned minimum distance between valves, Dbv(min), use Dbv(min).
Gas Lift Valve Port Sizing and Test-Rack Opening Pressure Calculations
The port size selection is based on the maximum depth of lift and the final operating injection-gas pressure for spacing the deepest valve. The port size and the test-rack setting pressures of the gas lift valves are calculated as follows:
1. Determine the port size for the type of gas lift valves to be installed in the installation on the basis of the unloading and operating injection-gas requirements. Correct the injection-gas rate for the actual gas gravity and temperature at each valve depth with Eq. 12.6. Determine from Fig. 12.13 the port ID needed to pass the required injection-gas rate with the pressure differential available at the operating valve. When an orifice-check valve is selected for the bottom valve, the upstream injection-gas pressure, P1, should be equal to or less than the injection-gas initial valve opening pressure of the last unloading valve, corrected to the depth of the orifice-check valve. The pressure differential across the orifice-check valve is the difference between P1 and the downstream flowing-production pressure, P2, at the valve depth.
2. Record the gas lift valve specifications, which include the effective bellows area, Ab, port area, Ap, (Ap /Ab), (1 – Ap /Ab), and the production-pressure factor, Fp.
3. Calculate the injection-gas initial opening pressure at depth of the top gas lift valve,
|PioD1||=||injection-gas pressure at valve depth, psig, and|
|PoD1||=||injection-gas initial gas lift valve opening pressure at valve depth, psig.|
4. Calculate the test-rack set opening pressure of the first valve (n = 1), Pvo1, with Eqs. 12.44 and 12.45 or 12.46.
|CT||=||temperature correction factor for nitrogen from PbvD to Pb at 60°F, dimensionless,|
|PbvD||=||nitrogen-charged bellows pressure at valve temperature, psig,|
|(PpfD) min||=||minimum flowing-production pressure at valve depth, psig,|
|Pvo||=||test-rack valve opening pressure at 60°F, psig.|
Some designers prefer Eq. 12.46, which does not require calculation of PbvD and gives the same result.5. Calculate the injection-gas initial opening pressure of the second gas lift valve at depth (n = 2) with Eq. 12.47.
6. Calculate the maximum flowing-production pressure opposite the top unloading valve immediately after the point of gas injection has transferred to the second (lower) valve, (PpfD1)max. (PpfD1)max is shown graphically in Fig. 12.31 and can be calculated with Eq. 12.48.
7. Determine if the assumed decrease in surface injection-gas pressure, ΔPio, is sufficient for the required gas lift valve port size by calculating the additional production-pressure effect, ΔPpe1, at the top valve:
If ΔPpe1 is less than or equal to the assumed ΔPio, proceed with the design. If ΔPpe1 is greater than the assumed ΔPio, then set ΔPio = ΔPpe1 and recalculate the spacing design. This is a conservative approach, and many operators use actual operating experience to determine which ΔPio to use.
Repeat Steps 3 and 4 calculations for the second gas lift valve. Repeat Steps 3, 4, and 5 calculations for remaining gas lift valves. If the operating valve is an orifice-check valve, determine the orifice ID for lifting the well on the basis of the calculated upstream and downstream pressures, P1 and P2.
Example Problem 4
Well information for continuous-flow installation design (API Design Technique).
- Tubing size = 2 7/8-in. OD.
- Tubing length, Dd = 6,000 ft.
- Maximum valve depth, Dv(max) = 5,970 ft.
- Static bottomhole pressure at Dd, Pwsd = 1,800 psig at 6,000 ft.
- Daily production rate = 800 STB/D.
- Water cut = 50% (fw = 0.50).
- Formation GOR = 500 scf/STB.
- Oil gravity = 35°API.
- Gas gravity, γg = 0.65.
- Produced-water specific gravity, γw = 1.08.
- Bottomhole temperature, Twsd = 170°F at 6,000 ft.
- Design unloading wellhead temperature, Twhf = 100°F.
- Load-fluid pressure gradient, gls = 0.46 psi/ft.
- U-tubing wellhead pressure, Pwhu = 100 psig.
- Flowing wellhead pressure, Pwhf = 100 psig.
- Static fluid level = 0 ft (well loaded with kill fluid).
- Surface kick-off injection-gas pressure, Pko = 1,000 psig.
- Surface operating injection-gas pressure, Pio = 1,000 psig.
- Maximum unloading injection-gas rate, qgiu = 800 Mscf/D.
- Operating daily injection-gas rate, qgi = 500 Mscf/D.
- Wellhead injection-gas temperature, Tgio = 100°F.
- Assigned valve-spacing pressure differential at valve depth, ΔPsD = 50 psi.
- Test-rack valve setting temperature, Tvo = 60°F.
- Assigned minimum decrease in surface operating injection-gas pressure between valves, ΔPio = 20 psi.
- Minimum distance between valves, Dbv(min) = 150 ft.
- Gas lift valves: 1.5-in.-OD nitrogen-charged with A b = 0.77 in. 2 and sharp-edged seat.
Solution—Calculation of Valve Depths
The pressure traverses used to establish the gas lift valve depths are drawn on pressure/depth worksheets in Figs. 12.31 and 12.32. 1. Calculate maximum injection GLR with Eq. 12.33.
2. Determine the flowing-production pressure Ppfd at Dd from the appropriate gradient curves in Fig. 12.29 for 800 B/D and 1,000 scf/STB:
|Actual Depth, ft||Chart Depth, ft||Pressure, psig|
Ppfd = 900 psig at 6,000 ft, where Ppfd is the flowing-production pressure at the lower end of the production conduit, Dd.
3. Calculate gpfa with Eq. 12.34.
4. Calculate the operating injection-gas pressure at the lower end of the production conduit using Eq. 12.1 and ggio with Eq. 12.35. Piod = 1,154 psig at 6,000 ft (calculated).
Because the difference between Ppfd and Piod, (Piod – Ppfd = 1,154 – 900 = 254 psi), exceeds 200 psi, the maximum valve depth of 5,970 ft can be attained.
5. Calculate the unloading gas lift valve temperature at depth gradient with Eq. 12.36.
6. Calculate the depth of the top gas lift valve with Eq. 12.31.
7. Calculate the minimum flowing-production pressure, (PpfD1)min, injection-gas pressure, PioD1, and the unloading flowing temperature, TvuD1 at Dv1 of 1,957 ft with Eqs. 12.37 through 12.39.
(PpfD1)min = 100 + 0.1333 (1,957) = 361 psig. PioD1 = 1,000 + 0.0257 (1,957) = 1,050 psig. TvuD1 = 100 + 0.0117 (1,957) = 123°F.
8. Calculate Dbv for depth of second valve, Dv2, where ΔPioD2 = 20 psi, using Eqs. 12.41 and 12.42:
Repeat Step 7: Calculate (PpfD2)min, PioD2, and TvuD2 at valve depth Dv2 = 3,429 ft. (PpfD2) min = 557 psig, PioD2 = 1,088 psig, and TvuD2 = 140°F.
Repeat Step 8: Calculate depth of third valve, Dv3 , where ΔPioD3 = 40 psi. Dbv = 1,061 ft and Dv3 = 4,490 ft.
Repeat Step 7: Calculate (PpfD3)min, PioD3, and TvuD3 at valve depth Dv3 = 4,490 ft. (PpfD3) min = 699 psig, PioD3 = 1,115 psig, and TvuD3 = 152°F.
Repeat Step 8: Calculate depth of fourth valve, Dv4, where ΔPioD4 = 60 psi. Dbv = 752 ft and Dv4 = 5,242 ft.
Repeat Step 7: Calculate (PpfD4)min, PioD4, and TvuD4 at valve depth Dv4 = 5,242 ft. (PpfD4) min = 799 psig, PioD4 = 1,135 psig, TvuD4 = 161°F.
Repeat Step 8: Calculate depth of fifth valve, Dv5, where ΔPioD3 = 80 psi. Dbv = 520 ft and Dv5 = 5,762 ft.
Repeat Step 7: Calculate (PpfD5)min, PioD5, and TvuD5 at valve depth Dv5 = 5,762 ft. (PpfD5)min = 868 psig, PioD5 = 1,148 psig, and TvuD5 = 167°F.The calculated valve spacing for the sixth valve, Dv6, would exceed the maximum valve depth, Dv(max), of 5,970 ft. Because an orifice-check valve will be placed in the bottom wireline-retrievable valve mandrel, no test-rack valve setting information is required. This completes the valve spacing calculations. A graphical representation of the valve installation design is shown in Fig. 12.32.
Solution—Determination of Gas Lift Valve Port Size and Calculation of Test-Rack Opening Pressures The gas lift valves port ID and test-rack opening pressure calculations are given next.
1. Determine the port size required for the gas lift unloading valves and the operating orifice-check valve orifice ID. The upstream injection-gas pressure, P1 , is based on PoD5 of the last unloading valve using Eq. 12.47 corrected to the orifice-check valve depth of 5,970 ft.
P1 = 1,068 + 0.0257 (5,970 – 5,762) = 1,073 psig at 5,970 ft.
The downstream flowing-production pressure, P2, is equal to the minimum flowing-production pressure at 5,970 ft with Eq. 12.37.
P2 = 100 + 0.1333 (5,970) = 896 psig at 5,970 ft. ΔPov = 1,073 – 896 = 177 psi across the orifice-check valve.
From Fig. 12.13, the required equivalent orifice size is near ∕6414 in.; therefore, the next largest gas lift valve port ID is 1/4 in. This size is sufficient for all of the upper unloading valves because they have a higher injection-gas operating pressure and a greater differential pressure between PioD and (PpfD)min. An equivalent orifice size of 12/64 in. to 13/64 in. is required to pass the operating injection-gas rate of 500 Mscf/D.
2. Record the valve specifications for a l.5-in.-OD gas lift valve having a 1/4-in.-ID port with a sharp-edged seat where A b = 0.77 in. 2 from Table 12.2.
(Ap/Ab) = 0.064, (1 – Ap/ Ab) = 0.936, and Fp = 0.068.
3. Calculate PoD1 with Eq. 12.43 : PoD1 = 1,050 psig at 1,957 ft.
4. Calculate PbvD1 with Eq. 12.44 for CT1 = 0.876 (Calculated with Eq. 12.3 for TvuD1 = 123°F).
5. Calculate Pvo1 with Eq. 12.45: Pvo1 = = 942 psig at 60°F.
6. Calculate PoD2 with Eq. 12.47: PoD2 = 1,088 – 20 = 1,068 psig at 3,429 ft.
7. Calculate (PpfD1)max with Eq. 12.48:
8. Calculate ΔPpe1 with Eq. 12.49: ΔPpe1 = 0.068 (652 – 361) = 20 psi.
Because the ΔPpe1 of 20 psi is the same as the assumed ΔPio of 20 psi for spacing, a pressure differential of 20 psi can be used for setting the valves. Note that if 1-in.-OD valves had been used in this design, Fp = 0.188 for a 1/4-in.-ID port and ΔPpe1 would be 55 psi. Repeat Steps 6, 4, and 5 for remaining gas lift valves:
PoD2 = 1,035 psig at 3,429 ft, PbvD2 = 1,035 psig, CT2 = 0.847 for TvuD2 = 140°F, and Pvo2 = 937 psig.
PoD3 = 1,075 psig at 4,490 ft, PbvD3 = 1,051 psig, CT3 = 0.828 for TvuD3 = 152°F, and Pvo3 = 929 psig.
PoD4 = 1,075 psig at 5,242 ft, PbvD4 = 1,057 psig, CT4 = 0.815 for TvuD4 = 161°F, and Pvo4 = 919 psig.
PoD5 = 1,068 psig at 5,762 ft, PbvD5 = 1,055 psig, CT5 = 0.805 for TvuD5 = 167°F, and Pvo5 = 907 psig.An orifice-check valve is recommended for the sixth valve at 5,962 ft. The orifice ID should be 1/4 in. to pass sufficient gas to gas lift the well. A tabulation form for these calculations is given in Table 12.3.
Continuous-Flow Installation Design When Injection-Gas Pressure is High, Relative to Depth of Lift
An additional incremental decrease in the injection-gas pressure can be added to the calculated decrease to ensure unloading a gas lift installation when the injection-gas pressure is high, relative to the required depth of lift. The flowing-production pressure at the depth of lift limits the maximum injection-gas pressure that can be used in terms of contributing to the lift process. The higher available injection-gas pressure cannot be utilized in this installation. An excessive injection-gas pressure drop across the operating valve represents an inefficient energy loss. Distributing the decrease in the injection-gas pressure between each successively lower unloading gas lift valve prevents multipoint gas injection through upper gas lift valves after the point of gas injection transfers to a lower valve. In other words, the gas lift installation can be unloaded without valve interference, and the unloading process is apparent from the injection-gas pressure recording at the surface. A high available injection-gas pressure, relative to the depth of lift, may exist in areas where both shallow and deep wells are being gas lifted with injection gas from the same system. The flowing-production pressure in the shallow wells limits the injection-gas pressure that can be used to gas lift these wells.
High Rate Continuous-Flow Installation DesignThe application of the injection-gas rate throughput performance for injection-pressure-operated gas lift valves is illustrated in the high daily liquid rate continuous-flow installation design. The importance of valve performance data for high daily injection-gas rates is shown, and their unimportance for low-injection-gas-rate installation designs is illustrated. Valve performance data is of no value in selection of the top two unloading gas lift valves in this installation. For these two upper valves, an assumed reasonable decrease in the surface injection-gas pressure of 20 psi for each valve ensures unloading the well and these upper valves remaining closed while lifting from a lower valve. When the required daily injection-gas rate increases for lifting from the third and fourth gas lift valves, valve performance information becomes very important. A pressure-vs.-depth plot for this continuous-flow installation is shown in Fig. 12.33.
Although the flowing-production transfer-pressure-traverse method for locating the depths of the valves may require an additional valve, or valves, in some installations, this design method has several advantages in wells requiring a high daily injection-gas rate for unloading. Because the injection-gas requirement to uncover the next lower valve is reduced, smaller valve ports can be used and the increase in the injection-gas pressure to stroke the valve stem is less. The unloading operations are faster because of the lesser difference in injection-gas requirement between unloading valves. This fact is of more importance after an injection-gas supply interruption when several wells must be unloaded and the total-system available daily injection-gas volume is limited. The chance of heading and surging with a smaller port is reduced because a change in flowing-production pressure has a lesser affect on the valve-stem position. Bubble-tight seats are easier to achieve with small ports.
The surface origin and final downhole termination pressures for the flowing-production transfer-pressure traverse are arbitrary. The 20% in this example for locating the surface transfer-pressure traverse is widely used. The unloading injection-gas requirements for uncovering each lower valve increase as that percentage decreases and decrease as that percentages increases. The flowing-production transfer pressure at datum depth should be at least 100 to 200 psi less than the available design operating injection-gas pressure at the same depth. This flowing-production transfer pressure at datum depth should also be less than the flowing-production pressure at the same depth based on the design daily production rate and maximum total GLR.
The multiphase-fluid-flow correlation selected for these calculations can significantly affect the results. Several assumptions for calculating the depths of the unloading valves are very conservative in this example (e.g., assuming a load-fluid pressure gradient below an unloading valve after significant bottomhole-pressure drawdown and the assigned valve spacing pressure differential of 50 psi at the next lower valve depth). These design calculations provide a comprehensive understanding of the overall well unloading process and operations. The installation designer can modify the assumptions on the basis of the availability and accuracy of the known well information.
A lower-than-the-design daily liquid-production rate is assigned for spacing the unloading valves until the flowing-bottomhole-pressure drawdown results in a calculated daily production rate that exceeds the assigned rate. Typical assigned unloading daily liquid rates would be 200 to 400 B/D for 2 3/8-in.-OD tubing and 400 to 600 B/D for 2 7/8-in.-OD tubing. When the calculated flowing-bottomhole-pressure drawdown results in a higher than the assigned unloading daily liquid production rate for the flowing-production transfer pressure at the depth of the operating unloading valve, this higher rate is used for spacing the next lower unloading valve. A 1,000-B/D unloading rate is assigned for unloading valves before a higher liquid rate occurs from a flowing-bottomhole-pressure drawdown in this high-productivity well with large tubing. The assigned design flowing-wellhead temperature of 120°F is between the ambient surface temperature and the flowing-well fluids temperature at the design daily production rate from the well.
Simplified Mathematical Gas Lift Valve Performance Model. Because performance equations for specific gas lift valves are not available from gas lift valve manufacturers, a simplified gas lift valve performance computer model was used to illustrate the calculations in this paper. The model is based on static force-balance equations and several simplifying assumptions. This computer model describes qualitatively the injection-gas rate throughput of unbalanced, single-element gas lift valves using the Thornhill-Craver equation (Eq. 12.5).
For this computer model, the gas lift valve has a square sharp-edged seat and the stem tip is a carbide ball with a 1/16-in. larger OD than the bore ID of the valve seat. The equivalent port area for a partially open valve is defined by the lateral surface area of the frustum of a right circular cone. The frustum area is generated between the surface of the ball and the valve seat-line as the valve stem moves away from its seat. The bellows-assembly load rate is assumed to be linear for the stem travel required to attain a given equivalent port area, and there is no increase in nitrogen-charged bellows pressure during this stem travel. The flow restriction and the pressure loss, resulting from a check-valve assembly, are not included in the gas lift valve model calculations. The same gas gravity, ratio of specific heats, and discharge coefficient are used for all calculations.
There are many unknown dynamic quantities in terms of actual areas and pressures acting on these areas as the gas-flow rate through a valve changes with valve-stem travel. For the valve performance calculations with a partially open port, the injection-gas pressure is assumed to act over the effective bellows area minus the port ball/seat contact area. Regardless of the valve-stem position, the flowing-production pressure is applied over the entire port ball/seat contact area. These assumptions should result in the calculated injection-gas rate being less than the actual rate. As the ball on the valve stem moves away from its seat during an increase in injection-gas pressure, the two areas over which the opening pressures are applied will change. The bellows area exposed to the injection-gas pressure increases and the flowing-production pressure approaches the injection-gas pressure downstream of the port as the equivalent port area increases in the variable-orifice throttling mode. This pressure is difficult to define accurately because of the varying pressure loss as the equivalent port area changes with valve-stem travel.
Although several of the assumptions for the mathematical valve model are known to be approximate, the predicted performance illustrates, with reasonable accuracy, the manner in which an unbalanced, injection-pressure-operated, single-element gas lift valve operates in a well. The valve performance curves, in the continuous-flow installation design, were calculated using the computer model in Appendix A. The coefficient for Eq. A-9 in Appendix A is based on the Thornhill-Craver coefficient of 155.5, a gas gravity of 0.65, ratio of specific heats of 1.26, discharge coefficient of 0.865, and acceleration caused by gravity of 32.174.
Determination of Valve Depths. The procedure for referencing the static bottomhole pressure, Pwsd, and temperature, Twsd, to the lower end of the production conduit, Dd, is the same as for the previous lower-injection-gas-rate continuous-flow installation design in Example Problem 4.
1. Determine the static operating injection-gas pressure at the lower end of the production conduit, Piod, with Eq. 12.1 and calculate the static operating injection-gas pressure at depth gradient, ggio, with Eq. 12.35. The same operating injection-gas pressure at depth gradient, ggio, is used for all calculations regardless of the surface injection-gas pressure. This is not a recommended procedure; particularly, for high injection-gas pressures in deep wells. The injection-gas pressures at depth should be calculated on the basis of the actual surface pressures, gas properties, and temperature. The constant ggio was used in the following installation design to simplify the calculations.
2. Calculate the gas lift valve unloading temperature-at-depth gradient, gTvu, with Eq. 12.36 on the basis of the assigned unloading flowing-wellhead temperature, Twhu, and the static bottomhole temperature, Twsd, in the well. The assigned unloading flowing-wellhead temperature should be between the ambient surface temperature and the flowing-well fluids temperature at the design maximum daily production rate from the well.
3. Calculate the surface flowing-production transfer pressure, Ppt, on the basis of the assigned flowing-production transfer-pressure valve-spacing factor at the surface, fpt. The assigned fpt will generally range between 0.15 and 0.25 (15 to 25%).
4. Calculate the flowing-production transfer pressure at the lower end of the production conduit, Pptd, and the flowing-production transfer pressure at depth gradient, gpt. The recommended minimum pressure difference, ΔPptd, between the flowing-production transfer pressure at the lower end of the production conduit, Pptd, and the operating injection-gas pressure at the same depth, Piod, should be at least 100 to 200 psi or greater and can be based on operating experience in the area.
5. Determine from the appropriate set of gradient curves, or calculate using a reliable multiphase-flow computer program, the flowing-production pressure at the lower end of the production conduit, Ppfd at Dd, on the basis of the maximum operating total GLR, Rglt (operating daily injection-gas plus formation-produced gas rates), and the installation design total daily liquid rate (oil + water), qlt.
The Ppfd calculation (or determination from gradient curves) determines if the tubing size restricts the maximum design daily production rate and whether a higher injection-gas pressure is recommended. If Ppfd is less than Pptd, the tubing size does not appear to restrict the design production rate, and the available injection-gas-line pressure appears to be adequate. The final maximum daily production rate will be controlled by the productivity of the well. If Ppfd is greater than Pptd, a higher operating injection-gas pressure is necessary to achieve the assigned maximum depth of lift for this design method.
6. Determine the depth of the top gas lift valve, Dv1. The top unloading valve depth is calculated using Eqs. 12.29, 12.30, or 12.31 on the basis of the terms defined for the equation or can be located graphically.
7. Calculate the flowing-production transfer pressure, PptD(n) , the operating injection-gas pressure, PioD(n), and the unloading valve temperature, TvuD(n), at the gas lift valve depth, Dv(n).
8. Calculate the flowing bottomhole pressure, Pwfd(n), while lifting from the gas lift valve at depth, Dv(n), based on the flowing-production transfer pressure, PptD(n), and the static load (kill) fluid pressure gradient, gls, to determine whether the calculated daily liquid rate, qlc(n), based on Productivity Index, PI, exceeds the assigned unloading daily liquid rate, qlu(n).
If Pwfd(n) < Pwsd, calculate qlc(n).
The static load (kill)-fluid pressure at depth gradient is recommended for calculating the valve depths after flowing-bottomhole-pressure drawdown. The time required to recover all load (kill) fluid that entered the reservoir during workover is unknown. It may require days, or weeks, before normal formation-fluids production returns. When reservoir fluids begin to re-enter the wellbore, the flowing-pressure-at-depth gradient below an operating unloading valve will normally decrease and formation free-gas production will reduce the injection-gas requirement.
9. Calculate the daily injection-gas rates, qgi(n), on the basis of the assigned unloading or calculated daily producing liquid rate in Step 8 if qlc(n) > qlu(n). Assume injection-gas/liquid ratios, Rgli(n), that result in flowing-production pressures, PpfD(n), at the valve depth, Dv(n), that bracket the flowing-production transfer pressure, PptD(n). Values of PpfD(n) for varying Rdlt can be calculated or determined from gradient curves. Then calculate the qgi(n) for the PptD(n) after the assumed Rdlt equals the calculated Rdlt.
10. Calculate the increase in the injection-gas pressure, ΔPioc(n), above injection-gas initial valve opening pressure, PoD(n), for the valve to pass the required daily injection-gas rate, qgi(n), to establish the PptD(n) in Step 9 on the basis of the valve port ID, bellows-assembly spring rate, Bsr = Blr (Ab) in Appendix A, the PoD(n) and the PptD(n). The injection-gas rate through a gas lift valve for an assumed PioD(n) greater than PoD(n) is calculated with the equations in Appendix A. Similar to Step 9, the increase in the injection-gas pressure, PioD(n), above PoD(n) to attain the qgi(n) in Step 7 can be determined graphically or calculated using a curve-fitting routine. The calculated increase in the injection-gas pressure, ΔPioc(n), is equal to the difference between the PioD(n) that results in the required qgi(n) and the PoD(n) of the valve.
11. Compare the assigned minimum surface injection-gas pressure decrease between valves, ΔPioa, (represents the assigned minimum surface design injection-gas pressure increase above PoD(n) for stroking a valve) to the calculated injection-gas pressure increase in Step 10. If the calculated surface injection-gas pressure increase in Step 10, ΔPioc(n), is less than ΔPioa, use this assigned injection-gas pressure decrease, ΔPioa (ΔPio(n) = ΔPioa). Then calculate the sum of the ΔPio(n) values, ΣΔPio(n), required for calculation of the injection-gas initial gas lift valve opening pressure at depth of the next lower valve, PoD(n). The ΣΔPio(n) equals zero for the top gas lift valve in Eq. 12.58.
12. Calculate the depth of the next lower valve, Dv(n+1), below the operating unloading valve with a load (kill)-fluid gls traverse (no formation production fluids) below the valve. The top and the second valve depths, Dv1 and Dv2, respectively, are based on the assigned surface operating injection-gas pressure, Pio. The following equation is used for calculating the depths of the second and lower valves until the assigned maximum valve depth or minimum distance between valves is reached.
If Dv(n+1) exceeds Dv(max), Dv(n+1) = Dv(max), and PptD(n) is calculated with Eqs. 12.60 and 12.61.
Orifice-Check Valve Calculations. The deepest (bottom) operating valve of choice in many continuous-flow installations is an orifice-check valve. Because an orifice-check valve is always fully open, there are no dynamic valve performance calculations required. The published orifice or choke equations or charts are used to select the proper orifice or gas lift valve seat ID and determine the injection-gas rate throughput. Orifice-check valve calculations for the bottom valve are outlined in detail in the following high-rate continuous-flow installation design in Example Problem 5.
Example Problem 5: High-Rate Continuous-Flow Installation Design Calculations
Well data for installation design using unbalanced, nitrogen-charged, injection-pressure-operated gas lift valves for unloading.
- Tubing size = 4 1/2 -in. OD (ID = 3.958 in.), and length = 6,000 ft.
- Casing size = 8 5/8-in. OD, 44 lbm/ft (ID = 7.725 in.).
- Datum depth for bottomhole pressures and temperature, Dd = 6,000 ft.
- Bottomhole temperature at Dd, Twsd = 170°F.
- Shut-in (static) bottomhole pressure at Dd, Pwsd = 2,000 psig.
- Maximum depth for bottom valve, Dv(max) = 5,900 ft.
- Productivity index (gross liquid), PI = 6.3 B/D/psi.
- Oil gravity = 35°API (γo = 0.850).
- Gas specific gravity (air = 1.0), and γg = 0.65.
- Water specific gravity, γw = 1.08.
- Water fraction, fw = 0.50 (50%).
- Formation GOR, Rgo = 400 scf/STB.
- Formation GLR, Rglf = 200 scf/STB.
- Assigned minimum daily unloading production rate, qlu = 1,000 B/D
- Design total (oil + water) daily production rate, qlt = 5,000 B/D.
- Wellhead U-tubing unloading pressure, Pwhu = 100 psig.
- Surface flowing wellhead pressure, Pwhf = 100 psig.
- Static load (kill)-fluid pressure gradient, gls = 0.468 psi/ft.
- Unloading wellhead temperature, Twhu = 120°F (basis for calculation of Pvo).
- Wellhead injection-gas temperature, Tgio = 120°F.
- Surface kick-off injection-gas pressure, Pko = 1,400 psig (at wellsite).
- Surface operating injection-gas pressure, Pio = 1,400 psig (at wellsite).
- Assigned daily injection-gas rate, qgi = 2,000 Mscf/D.
- Minimum assigned surface injection-gas pressure decrease between valves, ΔPio = 20 psi. (Represents minimum surface injection-gas pressure increase for stroking gas lift valve).
- Valve spacing design line percent factor at surface = 20% (fpt = 0.20).
- Minimum transfer-production-pressure difference (Piod – Pptd) at Dd, ΔPptd = 200 psi.
- Valve-spacing pressure differential at valve depth, ΔPsD = 50 psi.
- Minimum distance between valves Dbv(min) = 400 ft.
- Gas lift valve test-rack setting temperature, Tvo = 60°F.
- Gas lift valves: 1.5-in.-OD wireline-retrievable, unbalanced, single-element, nitrogen-charged bellows with Ab = 0.77 in.2, Blr = 600 psi/in., and square sharp-edged seat.
Solution—Calculation of Valve Depths
1. Piod = 1,617 psig at 6,000 ft (Eq. 12.1), and ggio = = 0.03617 psi/ft.
3. Ppt = 100 + 0.20 (1,400 – 100) = 360 psig at wellhead.
4. Pptd = 1,617 – 200 = 1,417 psig at 6,000 ft, and gpt = = 0.1762 psi/ft.
5. Rglf = = 400 scf/STB, and Rglt = 200 + 400 = 600 scf/STB.
Ppfd = 1,227 psig at 6,000 ft for 5,000 B/D, and Rglt = 600 scf/STB (Rgli + Rglf) using the Ros multiphase-flow correlation. Because Ppfd is less than Pptd by 390 psi (1,617 – 1,227), the tubing size does not appear to restrict the design production rate and the available injection-gas-line pressure seems adequate. The final maximum daily production rate will be controlled by the reservoir productivity of this well.
Top Valve Depth Calculations
6. Dv1 = = 2,778 ft (Eq. 12.29)
7. PptD1 = 360 + 0.1762 (2,778) = 849 psig at 2,778 ft. PioD1 = 1,400 + 0.03617 (2,778) = 1,500 psig at 2,778 ft. TvuD1 = 120 + 0.008333 (2,778) = 143°F at 2,778 ft.
8. Pwfd1 = 849 + 0.468 (6,000 – 2,778) = 2,357 psig at 6,000 ft for gls traverse below Dv1. Because Pwfd1 > Pwsd, there is no flowing-bottomhole-pressure drawdown.9. Refer to Table 12.4 with values of PpfD1 and qgi1 for assumed varying total-injection GLRs, Rglt = Rgli, and to the intersection of PptD1 = 849 psig with the tubing performance curve in Fig. 12.34, where qgi1 = 104 Mscf/D.
10. Refer to Table 12.4 with values of PioD1 vs. qgi1 based on equations in Appendix A and the intersection of the gas lift valve performance curve in Fig. 12.34 with qgi1 = 104 Mscf/D, where PioD1 = 1,484 psig.
11. Because PoD1 = 1,480 psig, ΔPioc1 = 1,484 – 1,480 = 4 psi, which is less than the 20-psi minimum assigned surface pressure increase required to stroke the valve.
ΔPioc1 < ΔPioa, ΔPio1 = ΔPioa = 20 psi and ΣΔPio1 = 20 psi for calculation of PoD1.
Second Valve Depth Calculations
12. Dbv = = 1,392 ft and Dv2 = 2,778 + 1,392 = 4,170 ft.
7. For Dv2 = 4,170 ft: PptD2 = 1,095 psig, PioD2 = 1,551 psig, and TvuD2 = 155°F.
8. PwfD2 = 1,951 psig at 6,000 ft and qlc = 309 BPD. Because qlc < qlu, use qlu = 1,000 BPD.9. Refer to Table 12.5 with values of PpfD2 and qgi2 for assumed varying total-injection GLRs, Rglt. The PptD2 of 1,095 psig intersects the tubing performance curve in Fig. 12.35 at qgi2 = 168 Mscf/D.
10. Refer to Table 12.5 with values of PioD2 and qgi2 based on equations in Appendix A and the intersection of the gas lift valve performance curve in Figure 12.35 with qgi2 = 168 Mscf/D where PioD2 = 1,518 psig.
11. Because PoD2 = 1,511 psig, ΔPioc2 = 1,518 – 1,511 = 7 psi: ΔPioc2 < ΔPioa, ΔPio2 = ΔPioa = 20 psi and ΣΔPio2 = 40 psi for calculation of PoD2.
Third Valve Depth Calculations
12. Dbv = = 894 ft, and Dv3 = 4,170 +894 = 5,064 ft.
7. For Dv3 = 5,064 ft: PptD3 = 1,252 psig, PioD3 = 1,583 psig, and TvuD3 = 162°F.
8. Pwfd3 = 1,252 + 0.468 (6,000 – 5,064) = 1,690 psig at 6,000 ft and qlc = 6.3 (2,000 – 1,690) = 1,953 B/D.9. Refer to Table 12.6 with values of PpfD3 and qgi3 for varying assumed total-injection GLRs, Rglt. The PptD3 of 1,252 psig intersects the tubing performance curve in Fig. 12.36 at qgi3 = 430 Mscf/D.
10. Refer to Table 12.6 with values of PioD3 and qgi3 based on equations in Appendix A and the intersection of the gas lift valve performance curve in Fig. 12.36, with qgi3 = 430 Mscf/D where PioD3 = 1,538 psig.
11. Because PoD3 = 1,523 psig, ΔPioc3 = 1,538 – 1,523 = 15 psi: ΔPioc3 < ΔPioa, ΔPio3 = ΔPioa = 20 psi and ΣΔPio3 = 60 psi for calculation of PoD3.
Fourth Valve Depth Calculations.
12. Dbv = = 558 ft and Dv4 = 5,064 +558 = 5,622 ft.
7. For Dv4 = 5,622 ft: The calculated Dbv for the fifth valve results in Dv5 exceeding the maximum valve depth of 5,900 ft. Refer to the fifth valve depth calculations in Step 12 where the Dbv = 278 ft (5,900 – 5,622). The transfer PptD4 is based on the actual Dbv of 278 ft and calculated with the following equation.
8. Pwfd4 = 1,373 + 0.468 (6,000 – 5,622) = 1,550 psig at 6,000 ft. qlc4 = 6.3 (2,000 – 1,550) = 2,835 B/D for gls-traverse below Dv4.
10. Refer to Table 12.7 with values of PioD4 and qgi4 based on equations in Appendix A and the intersection of the gas lift valve performance curve in Fig. 12.37 with qgi4 = 730 Mscf/D where PioD4 = 1,543 psig.
11. Because PoD4 = 1,513 psig, ΔPioc4 = 1,543 – 1,513 = 30 psi ΔPioc4 > ΔPio, ΔPio4 = ΔPioc4 = 30 psi and ΣΔPio4 = 90 psi for calculation of PoD4.
Fifth Valve Depth Calculations
12. Dbv = = 308 ft, and Dv5 = 5,622 + 308 = 5,930 ft exceeds given maximum valve depth of 5,900 ft; therefore, Dv5 = Dv(max) = 5,900 ft and Dbv = 278 ft (5,900 – 5,622).7. TvuD5 = 120 + 0.008333 (5,900) = 169°F at 5,900 ft for injection-gas rate calculations. An orifice-check valve with a 5∕16-in.-ID port is installed in the bottom wireline-retrievable gas lift valve mandrel at 5,900 ft. An orifice-check valve is fully open at all times. The three-parameter graphical solution in Fig. 12.38 includes two curves that are a function of PpfD5.
The daily liquid production rates curve is based on the well PI, Pwfd, and Pwsd(Pwfd = PpfD5 + 34 psi for the approximate increase in pressure between 5,900 and 6,000 ft). An increase in the qgi (higher Rglt) decreases the PpfD5 and increases the calculated qlc for the given PI and Pwsd. For a constant assigned qgia, different values of ql are assumed and the Rglt and corresponding PpfD5 are calculated (or PpfD5 is determined from gradient curves) for each ql. The assumed ql is compared to the calculated qlc based on the PI and Pwsd. This procedure is repeated until the calculated qlc is equal to the assumed ql for the total assigned qgia. Refer to Table 12.8.
In the above calculations, a PpfD5 is calculated for each assumed qgia that is less than and a qgia equal to the assigned maximum of 2,000 Mscf/D. The injection-gas requirements curve is a plot of the assumed qgia vs. the calculated PpfD5.
The maximum assigned qgia of 2,000 Mscf/D intersects the injection-gas requirements curve at PpfD5 = 1,190 psig. The calculated PioD5 is 1,393 psig at 5,900 ft (upstream pressure) for the maximum assigned qgia of 2,000 Mscf/D through a 5 ∕16-in.-ID orifice with a PpfD5 of 1,190 psig downstream pressure and an upstream TgD5 of 169°F. The Pio5 at the surface is 1,180 psig for a PioD5 of 1,393 psig at 5,900 ft. The upstream surface injection-gas pressure for 2,000 Mscf/D should not exceed a surface injection-gas pressure that would reopen any of the upper unloading valves. The calculated minimum Pio to reopen the deepest unloading valve is 1,310 psig at the surface (injection-gas available line pressure, Pio – ΣΔPio = 1,400 – 90) and is 1,523 psig at 5,900 ft. Because the calculated upstream choke pressure of 1,393 psig is considerably less than 1,523 psig, there will be no unloading valve interference when the orifice-check valve becomes the operating valve, and the change in surface injection-gas pressure will be readily apparent after the depth of gas injection has transferred to the orifice-check valve.
Calculation of Test-Rack Opening Pressures of the Gas Lift Valves. The following calculations apply to injection-pressure-operated, unbalanced, single-element, nitrogen-charged bellows gas lift valves with a square, sharp-edged seat.
1. Calculate the injection-gas initial valve opening pressure at valve depth, PoD(n), on the basis of the available installation design injection-gas pressure at depth, PioD(n).
2. The nitrogen-charged bellows pressure is calculated at the unloading valve temperature at depth, TvuD, in the well using Eq. 12.63.
3. Calculate the temperature correction factor for nitrogen, CT, using Eq. 12.3 or determine CT from Table 12.1.
4. Calculate the nitrogen-charged bellows pressure at a test-rack setting temperature of 60°F.
5. Calculate the test-rack opening pressure at 60°F using Eq. 12.45 or Eq. 12.65.
Solution – Calculation of Test-Rack Opening Pressures
Second Valve Calculations (1/4-in.-ID Port) 1. PoD2 = 1,551 – 40 = 1,511 psig at 4,170 ft. 2. and 3. PbvD2 = (0.936) 1,511 + (0.064) 1,095 = 1,484 psig at 155°F, and CT2 = 0.8184 (calculated). 4. and 5. Pb2 = (0.8184) 1,484 = 1,215 psig at 60°F, and
Third Valve Calculations (3/8-in.-ID Port) 1. PoD3 = 1,583 – 60 = 1,523 psig at 5,064 ft. 2. and 3. PbvD3 = 0.857 (1,523) + 0.143 (1,252) = 1,484 psig at 162°F, and CT3 = 0.8079 (calculated). 4. and 5. Pb3 = 0.8079 (1,484) = 1,199 psig at 60°F, and
Fourth Valve Calculations (1/2-in.-ID Port) 1. PoD4 = 1,603 – 90 = 1,513 psig at 5,622 ft. 2. and 3. PbvD4 = 0.745 (1,513) + 0.255 (1,373) = 1,477 psig at 167°F, and CT4 = 0.8007 (calculated). 4. and 5. Pb4 = 0.8007 (1,477) = 1,183 psig at 60°F, and
A summary of the installation design calculations is shown in Table 12.9. The significant increase in Pvo(n) with depth is the result of the larger-ID port sizes required for the unloading gas lift valve Numbers 3 and 4.
Casing-Annulus-Flow Installation DesignThe design calculations for an annular-flow installation are similar to those for a continuous-flow installation through the tubing. Intermittent gas lift is not recommended for annular flow. Because the gross liquid production is generally thousands of barrels per day, selecting valve port ID sizes for adequate gas passage is very important for annular-flow installations. Actual gas lift valve performance, based on port ID, maximum linear stem travel, and bellows-assembly load rate, is an important factor in the design calculations for annular-flow installations because of the high injection-gas requirements. The increase in the injection-gas pressure to overcome the bellows-assembly load rate and to attain the needed equivalent port area for a required injection-gas throughput should be considered.
Selection of the proper size of gas-injection tubing string that will deliver the required daily injection-gas requirement for unloading and operating is absolutely essential. An initial assumption can be an injection-gas tubing size that will deliver the maximum daily injection-gas requirement with no pressure loss (i.e., the increase in the injection-gas pressure with depth, as a result of gas-column density, is offset by the flowing frictional pressure loss). This should be the smallest nominal tubing size considered for the injection-gas string. Charts for static injection-gas pressure at depth cannot be used for the valve spacing calculations.
The Cullender and Smith correlation is recommended for calculating the pressure loss in the injection-gas tubing string. This method for calculating the flowing injection-gas pressure at depth was derived for a producing gas well and not for gas injection. The only difference in the calculations is the friction term for gas being injected rather than being produced. The sign for the friction term changes (i.e., the friction term becomes negative in the Cullender and Smith equation for gas injection).
Wireline-retrievable gas lift valve mandrels that accommodate standard injection-pressure-operated valves for annular flow are available (Fig. 12.39). When these mandrels are used, the valves are run and set in the pocket in exactly the same manner as for tubular flow. However, the mandrel configuration is such that the injection gas enters the side of the pocket from inside the tubing. This allows injection gas to pass through the valve and exit the pocket into the casing annulus rather than into the tubing. Annular-flow mandrels should be used for annular flow wherever possible because they allow full gas passage through the valve without the restriction imposed by cross-over seats. Also, gas is injected from the bottom rather than the side of the mandrel. This provides a much safer installation from an erosion standpoint than the installation using valves with crossover seats in which gas is injected from the side of the pocket into the wall of the casing.
Where mandrels for tubing flow are already installed and are not feasible to replace, valves with crossover seats must be installed. In such installations, the check disk in the reverse-flow checks valve seats in the opposite direction for casing flow as compared to a tubing flow installation and allows gas passage from the injection-gas tubing to the casing annulus. In the wireline-retrievable valve tubing flow series mandrel, the valve for casing flow is similar to a production-pressure-operated valve, except the integral check valve is reversed for injection-gas flow from tubing to casing.
Because nitrogen-charged bellows gas lift valves have a lower bellows-assembly load rate than a spring-loaded valve, bellows-charged valves are recommended for high injection-gas volumetric throughput, as required for most annular-flow installations. Fortunately, the valve temperature at depth is not difficult to predict accurately in high-volume wells. The flowing surface temperature is near the bottomhole flowing temperature; therefore, the operating temperature of all valves in a high-volume, annular-flow gas lift installation is approximately the same. An important caution is to never use the surface injection-gas temperature to estimate the valve temperature at depth. The injection gas will begin to approach the flowing-fluid temperature within a few hundred feet of the surface. The flowing wellhead temperature of the fluid production should be used to establish the unloading valve temperatures at depth. This same consideration is applicable to the Cullender and Smith injection-gas pressure-at-depth calculations.
Intermittent-Flow Gas Lift
IntroductionIntermittent-flow gas lift is applicable to low-productivity wells and to low- and high-productivity wells with low reservoir pressure. Chamber installations may be beneficial to gas lift the low-flowing-bottomhole-pressure wells, particularly those wells with a high productivity index.
As the name implies, the reservoir fluid is produced intermittently by displacing liquid slugs with high-pressure injection gas, as illustrated in Fig. 12.40. Either an electronic or clock-driven time-cycle controller, or an adjustable or fixed choke, controls the flow of injection gas. Not all gas lift valves operate on choke control. The number of intermittent-flow gas lift installations on time-cycle control far exceeds the number of choke-controlled installations.
Disadvantages of Intermittent-Flow Gas Lift
Intermittent-flow gas lift has several disadvantages compared to continuous-flow operations. If the desired production can be gas lifted by continuous flow, this method is preferable. It is difficult to handle the high instantaneous gas volumes properly in the low- and high-pressure sides of a closed rotative gas lift system. Choke control of the injection gas into a well eliminates the removal of injection-gas volume at high instantaneous rates from the high-pressure system. However, it does not solve the problem of the large gas volume beneath the slug that enters the low-pressure system following displacement of the liquid slug to the surface. Gas volume storage requires pressure difference and physical capacity. The difference between the compressor discharge pressure and the operating injection-gas casing pressures normally exceeds the difference between the separator and compressor suction pressures. For this reason, retaining the needed injection-gas volume in the low-pressure side of a small, closed rotative gas lift system can be difficult unless the injection-gas cycles are staggered properly. Staggering of the injection-gas cycles is less precise on choke control than with a time-cycle controller. The electronic timers have improved the accuracy of controlled gas injection, whereby the injection cycles can be scheduled to prevent more than one well receiving injection gas at the same time. Therefore, total injection plus formation gas can be scheduled to enter the low-pressure system at a more constant rate with accurate time cycle than with choke control of the injection gas.
Severe surging in the flowing bottomhole pressure can present a serious production problem in unconsolidated-sand wells where sand production cannot be controlled. Sand bridging can plug off production and result in sand cleanout costs. Pressure surges in a chamber installation may be far more severe than in a regular intermittent-flow installation. A wireline release type of lock with an equalizing valve is recommended for the standing valve in a chamber to prevent the standing valve from being blown out of its seating nipple following blowdown after an injection-gas cycle. Some companies have resorted to increasing the operating injection-gas pressures to lift near total depth by continuous flow rather than intermittent flow wells that produce sand.
The total energy in the formation and injection gas is not fully used with intermittent-flow gas lift. The high-pressure gas under the slug is spent in the flowline and does not contribute to the lift process. This is one reason for using continuous-flow operations for a high-GLR well if possible. Plunger lift may be the best method for lifting certain high-GLR wells.
The injection-gas requirements are usually higher for intermittent-flow than for continuous-flow gas lift operations. The tubing capacity beneath the slug must be filled with injection gas to displace the liquid slug to the surface. The tubing under the liquid slug cannot be one-half or two-thirds filled with high-pressure gas. For this reason, the gas requirements for intermittent lift of low-GLR wells that do not partially flow can be estimated with reasonable accuracy. Unfortunately, articles have been published that imply that a well, or group of wells, is being intermittent lifted with a certain type of gas lift valve that results in an injection-gas requirement of only a fraction of the gas volume needed to fill the tubing beneath the liquid slug. Although gas orifice meter charts are published to illustrate these claims, the truth is, these wells are partially flowing. Only minimal agitation and displacement of the liquid slug is required to lift these wells. Most of the energy needed to lift the well is being furnished by the formation and not the gas lift system. Intermittent-flow gas lift is much more labor intensive than continuous flow. In intermittent-flow gas lift, the operator should frequently adjust the injection time and cycle frequency to maintain an efficient operation.
The injection-gas requirements for intermittent-flow and continuous-flow gas lift should be compared before eliminating continuous-flow operations. With the advent of several reliable multiphase-flow correlations, the predictable range of continuous flow has been extended to much lower daily production rates. A careful investigation of the proper production conduit size for lifting a well by continuous flow may permit this type of gas lift in place of intermittent-flow gas lift.
Types of Intermittent-Flow Gas Lift Installations
Intermittent-flow gas lift should be used only for tubing flow. Most installations have a packer and may include a standing valve in the tubing. If a well produces sand, a standing valve is recommended only if it is essential. A seating nipple should be installed at the lower end of the tubing string in intermittent-flow installations where a standing valve may be needed.
The working fluid level in a well should result in a minimum starting slug length that provides a production pressure at the depth of the operating gas lift valve equal to 50 to 60% of the operating injection-gas pressure at the same depth. If this is not possible, a chamber or plunger installation should be considered. In a chamber installation, the calculated depths of the unloading gas lift valves are the same as for a regular intermittent-lift installation. The chamber design converts a few feet of fluid, standing above the formation, into many feet of fluid in the tubing above the chamber. This entire liquid column is transferred into the tubing above the standing valve before injection gas enters the production conduit. The standing valve is required for efficient chamber operation to ensure U-tubing all fluid from the chamber into the tubing rather than allowing fluid to be pushed into the formation.
If a chamber installation is not installed in a low-bottomhole-pressure well, a plunger downhole stop and bumper spring can be set by wireline immediately above the operating gas lift valve. The plunger reduces the injection-gas slippage through the small liquid slug and decreases the liquid fallback. Smaller starting liquid slugs can be gas lifted more efficiently with the plunger acting as a sealing interface between the liquid slug and injection gas.
Prediction of Daily Production Rates
Two basic factors control the maximum production from a high-rate intermittent-flow gas lift installation: (1) the total liquid production reaching the surface per cycle and (2) the maximum number of injection-gas cycles per day. An intermittent gas lift installation should be designed to maximize the liquid recovery per cycle on low- and high-capacity wells. All restrictions in and near the wellhead should be eliminated. For this reason, streamlined wellheads are recommended. If the wellhead cannot be streamlined, all unnecessary ells and tees should be removed to reduce the number of bends between the tubing and flowline. If the velocity of the liquid slug is reduced before the entire column of liquid can be displaced into the horizontal flowline, additional injection-gas breakthrough, or gas slippage, will occur and decrease the liquid recovery per cycle. Performance of the operating gas lift valve, or valves, is important for efficient liquid-slug displacement. The operating gas lift valve should have a large port that opens quickly to ensure ample injection-gas volumetric throughput for efficiently displacing the liquid slug. Even though a large port is used, the valve spread (the difference between initial valve opening and closing pressure) should be kept relatively low to prevent excessive gas usage. This is especially true where large volumes of gas are stored in wells with small tubing and large casing.
The gas lift valve should not open slowly and meter a small injection-gas rate into the production conduit, which tends to aerate and percolate through the liquid slug rather than displace the slug. Rapid increase in the injection-gas casing pressure, after a time-cycle controller opens, improves the gas lift valve performance and ensures a more efficient displacement of a liquid slug in a time-cycle-operated intermittent-lift installation. Ample injection-gas volume must be available at the wellsite from the high-pressure injection-gas system. If the line pressure in the high-pressure system decreases to the casing pressure immediately after the time-cycle controller opens, poor valve action is the fault of the high-pressure system and not the gas lift installation in the well.
The size and length of the flowline can significantly affect the maximum cycle frequency. A flowline should always be at least equal to, or one size larger than, the tubing. The maximum number of injection-gas cycles per day is controlled by the time required for the wellhead pressure to return to the separator or production-header pressure after a slug surfaces. Reducing the separator pressure increases the starting slug length for the same flowing bottomhole pressure but does not solve the problem of decrease in wellhead pressure after the slug surfaces. When comparing or predicting the maximum production from two relatively high-capacity wells on intermittent gas lift, the size and length of the flowlines must be considered. If one installation requires 45 minutes and another 10 minutes for the wellhead pressure to approach the production-header pressure after a slug surfaces, the difference in maximum production (assuming that both wells have the same deliverability) is not the result of the gas lift installation in the well but of the surface facilities.
One definition of liquid fallback is the difference between the starting-liquid-slug volume, or length, and the produced slug volume, or length. The purpose of a properly designed intermittent gas lift installation is to recover a large portion of the starting slug. An important parameter that can be observed is the average slug velocity. The operating gas lift valve normally opens in less than 30 seconds after the time-cycle controller opens in most intermittent-lift installations. An approximate slug velocity can be estimated by assuming the valve opens 15 seconds after the controller opens and recording the time elapsed from this instance until the slug surfaces. In most installations, the depth of the operating gas lift valve is known or can be estimated from an acoustical fluid-level survey. If the average liquid-slug velocity is not near or exceeding 1,000 ft/min, the liquid fallback may be excessive. A slug velocity less than 800 ft/min can result in excessive fallback.
The maximum number of injection-gas cycles per day can be estimated for many wells by assuming 2 to 3 min/1,000 ft of lift for typical wells. The actual time can be less for installations on a production platform without flowlines and much longer for intermittent installations with small-ID and/or long flowlines, such as a well with 2 7/8-in.-OD tubing and a 2-in. flowline that is 2 miles in length. Also, emulsions and other unique well problems can decrease the maximum number of injection cycles per day and the recoverable liquid production per cycle.
Injection-Gas Requirement for Intermittent Lift
Multiphase-flow correlations are not applicable for the prediction of the gas requirement to lift a well by intermittent gas lift. Intermittent lift is the displacement of a liquid slug by high-pressure gas. The injection-gas requirement is not based on reducing the density of the fluid column. It is based instead upon the volume of gas needed to fill the tubing between the bottom of the slug when it reaches the surface and the depth of the deepest gas lift valve that opens during an injection-gas cycle. The injection-gas pressure and volume following the liquid slug at the instant this slug surfaces are spent in the flowline.
In intermittent lift, the energy in the formation gas does little to assist in lifting most wells. One method for calculating the injection-gas requirement is to assume the produced slug to be a continuous liquid column without any after-flow production in the tail gas. The theoretical pressure under this liquid slug at the instant the slug surfaced is approximately the wellhead production pressure plus the length of the produced slug multiplied by the liquid gradient. The actual average pressure in the tubing under a liquid slug is more than this pressure based on the solid slug length and a dry-gas gradient. This results from the injection-gas penetration of the slug during the lift process and the frictional losses that occur. An average injection-gas pressure in the tubing equal to the theoretical pressure under the produced liquid slug plus the surface closing pressure of the operating gas lift valve divided by two is a realistic assumption on the basis of numerous bottomhole-pressure measurements in intermittent-flow gas lift installations.
The total volume of injection gas per cycle depends on the average pressure in the tubing under the slug and the physical capacity of the tubing. When the depth of lift is several thousand feet, compared to an equivalent produced slug length of only a few hundred feet, the length of the slug may be subtracted from the tubing length above the operating valve for calculating the capacity of tubing filled with injection gas each cycle. This assumption implies that the rate of decrease in the pressure of the expanding injection-gas volume beneath the liquid slug is less than the rate of decrease in the pressure exerted by the slug length remaining in the tubing as the upper portion of the slug enters the flowline.
Comparison of Time-Cycle to Choke Control of the Injection GasThe advantage of choke-controlled injection-gas volume for an intermittent-flow gas lift installation is the fact that a low volumetric injection-gas rate is required from the high-pressure system into the well. Several conditions must be met before choke control of the injection gas can be used successfully. The gas lift valve must be suited for choke-control operation, and the casing annulus must provide adequate storage capacity for the injection-gas volume needed to displace the slug. Clean, dry gas is extremely important in choke control, and low-capacity wells are more difficult to choke control because of the small surface injection-gas choke size required for the low daily injection-gas rate needed to lift the well. A pressure-reducing regulator to maintain a constant maximum valve opening casing pressure between valve operating cycles may be necessary to permit the use of a larger-sized choke in the injection-gas line. Other limitations of choke control of the injection gas include a reduction in the maximum liquid slug size that can be lifted each cycle and the maximum number of injection-gas cycles per day. Time-cycle control of the injection gas should be considered for high-rate intermittent-lift operations. Two-pen pressure recorder charts, shown in Fig. 12.41, illustrate time-cycle and choke-control operations. Fig. 12.41a is time-cycle control where: (1) time-cycle controller opens, (2) time-cycle controller closes, and (3) gas lift valve closes. Fig. 12.41b is choke control of the injection gas where (1) gas lift valve opens and (2) gas lift valve closes. The difference in the maximum recorder tubing pressure for the time-cycle and choke-controlled installations results from different bourdon-tube ranges in the two pressure recorders. The pressure range for tubing pressure for time-cycle control is 0 to 1,000 psig, and it is 0 to 500 psig for the choke-control chart.
Most intermittent-flow gas lift installations use time-cycle-operated controllers on the injection-gas line because of the many advantages of time-cycle over choke control of the injection gas. Rugged unbalanced, single-element, nitrogen-charged bellows gas lift valves with large ports can be used. Much larger liquid slugs can be lifted with time-cycle control because injection gas in the annulus can be supplemented with gas from the high-pressure injection-gas system during each injection-gas cycle.
Intermittent-Flow Gas Lift Installation Design Methods
There are many published methods and variations in these methods for designing intermittent-flow gas lift installations. These methods can be divided into one type of design that is based on a production rate and another design that can be described as a percentage-load technique. Intermittent pressure gradient spacing factors are used for installation designs based on an assumed daily production rate. Production rate is not a consideration for a percent-load design method. The procedures for calculating a percent-load installation vary between gas lift manufacturers and between operators who have introduced slight variations in these calculations. The gas lift valve depths in most designs can be calculated or determined graphically. Regardless of the method used, the design should ensure unloading and operation from the deepest gas lift valve.
Gas Lift Valves for Intermittent Lift
Most operating valves used for intermittent lift are the unbalanced, single-element, bellows-charged valve with a large port. The majority of intermittent-lift designs require an operating gas lift valve with a large production-pressure factor. Single-element, spring-loaded gas lift valves are not recommended for intermittent lift because of the higher bellows-assembly load rate from the additional load rate of the spring. The operating gas lift valve should tend to "snap" open and provide a large port size for injection-gas throughput so that the liquid slug can be displaced efficiently with minimal injection-gas slippage and liquid fallback. Time-cycle control of the injection gas is recommended for intermittent-lift installations using unbalanced, single-element gas lift valves. These valves may or may not operate on choke control of the injection gas.
There are gas lift valves that have been designed for choke-controlled intermittent gas lift operation. These valves have a large port for gas passage and may be designed to operate on either time-cycle or choke control of the injection gas. Several types of gas lift valves are designed for only choke-control operation. A properly selected pilot-operated gas lift valve as the operating valve, functions in most wells on time cycle or choke control. It is extremely important to select the proper pilot port size based on the relationship between the capacity of the casing annulus and tubing if choke control of the injection gas is required. Choke control may be mandatory because of limited gas storage capacity in the high-pressure surface facilities.
Intermittent Pressure-Gradient Spacing FactorThe intermittent pressure-gradient spacing factor is similar to a flowing-pressure gradient above the point of gas injection in a continuous-flow installation. This factor increases with daily production rate for a given size of tubing. These intermittent spacing factors account for the following conditions: (1) liquid fallback from injection-gas penetration of the displaced liquid slug while the slug is in the tubing, (2) fluid transfer from the casing annulus to the tubing during unloading operations, (3) fluid production after flowing-bottomhole-pressure drawdown occurs, and (4) increase in tubing pressure with depth in deep wells with a high surface wellhead tubing pressure.
The fluid level in the tubing immediately after an injection-gas cycle is not at the operating valve depth. There is always an accumulation of liquid fallback because of gas slippage through the liquid slug during displacement. Consequently, the minimum flowing-production pressure between injection-gas cycles is greater than a gas pressure at operating valve depth based on the surface wellhead tubing pressure.
The intermittent pressure-gradient spacing factors, Fs, given in Fig. 12.42, were published many years before flowing-pressure-gradient curves were available for continuous-flow installation designs. The same unloading pressure gradients were used for intermittent-lift and continuous-flow installation design. These data were compiled from a limited number of flowing-pressure surveys from low GLR, high-water-cut wells with 2 3/8-in.- and 2 7/8-in.-OD tubing. Other tubing sizes were added to Fig. 12.42 at a later date. One of several important parameters missing from this correlation is depth. The only two correlating parameters in Fig. 12.42 are the production rate and conduit size. The rate of injection-gas penetration velocity into the slug is reported to be relatively constant for a given fluid. Therefore, the liquid fallback increases with the depth of lift because the liquid slug requires more time to reach the surface in deeper wells. These published intermittent spacing factors may be too low for deep intermittent lift and too high for shallow lift.
Selection of Surface Closing Pressure of Gas Lift Valves
The surface closing pressure of an operating gas lift valve is the minimum surface injection-gas pressure between gas injections if there are no leaks in the producing string, which includes wellhead, tubing, and gas lift valves. The maximum surface injection-gas pressure occurs at the instant the time-cycle controller closes in time-cycle control, or when the operating gas lift valve opens on choke control. The available operating injection-gas-line pressure at the wellsite must exceed the maximum surface casing pressure during an injection-gas cycle. For this reason, an assumed gas lift valve surface closing pressure of 15% less than the available injection-gas-line pressure at the wellsite is recommended for line pressures between 700 and 1,000 psig. This is the same as assuming a surface closing pressure equal to 85% of the available injection-gas-line pressure. A minimum 100-psi difference between the injection-gas line and the gas lift valve surface closing pressure is suggested for lower injection-gas pressures and a maximum of 200 psi for higher pressures. The maximum surface casing pressure during an injection-gas cycle for intermittent-lift operations is usually 8 to 10% higher than the surface closing pressure of the operating gas lift valve. This assumption can be used for approximate injection-gas requirement calculations in typical tubing/casing combinations such as 2 3/8-in.-OD tubing in 5 1/2-in.-OD casing and 2 7/8-in.-OD tubing in 7-in.-OD casing.
When a time-cycle controller on the injection-gas line opens, pressure upstream of the controller decreases. To have an injection-gas volume stored in the high-pressure injection-gas lines, there must be a pressure difference in addition to the capacity of the high-pressure system. If the difference between the injection-gas-line pressure and the surface closing pressure of the operating gas lift valve is insufficient, the casing pressure will not increase at a rate necessary to ensure rapid opening of an unbalanced, single-element, gas lift valve after the controller opens. A near instant increase in casing pressure after the controller opens improves the gas throughput performance of a single-element valve and decreases the liquid fallback. To ensure fast opening of the operating gas lift valve, it is better to design an intermittent installation with a pressure difference between the injection-gas line and valve closing pressure that is slightly excessive rather than insufficient.
Selection of Valve Port Size
Many gas lift designers disagree on port sizing for intermittent-flow unloading valves. One school of thought maintains that because most intermittent-flow installations are a natural progression from continuous flow, the same mandrel spacing for continuous flow can be used for intermittent flow. In such instances, small ports can be used in the unloading valves and a large-ported valve placed on bottom for the operating valve. This would also hold true for the spacing factor method of locating the unloading valves. On the other hand, another school of thought maintains that the constant surface closing and percent-load intermittent gas lift installation designs require unbalanced, single-element, gas lift valves with large ports relative to the effective bellows area. The design principle is based on the production-pressure effect. This is the tubing-production pressure from the liquid column above the valve at depth immediately before valve opening multiplied by the production-pressure factor for the valve. The valve with the highest tubing-production pressure that is less than the injection-gas pressure at valve depth is the deepest operating gas lift valve in the installation. There is no reason to decrease the surface closing pressure for each successively lower unloading gas lift valve for valves with high-production-pressure factors. The point of gas injection transfers automatically from an upper to the next lower valve after the production pressure at the lower-valve depth becomes less than the injection-gas pressure at the same depth. This same design technique can be used for pilot-operated gas lift valves used on bottom for the operating valve. The calculations for pilot valves apply to the pilot section of the valve.
When the design technique employing large ported valves for unloading is used, there may be variations in the port size or surface closing pressure of the bottom gas lift valve. If the casing size is large relative to the tubing size, such as with 2 3/8-in.-OD tubing in 7-in.-OD casing, a smaller-ported gas lift valve may be used for the bottom valve. The l.5-in.-OD unloading gas lift valves may have a 7∕16- or 1/2-in.-ID port and the bottom valve a 3/8-in.-ID port to reduce the valve spread (i.e., the difference between the initial opening and closing pressures of the operating valve). This consideration is important for installations in wells with an anticipated low flowing bottomhole pressure. The design surface closing pressure can be the same as the assumed closing pressure for the unloading gas lift valves with larger ports. Another variation in the installation design is to decrease the surface closing pressure of the bottom gas lift valve. The purpose of decreasing the closing pressure of the bottom valve is to provide a visible change in operating injection-gas pressure when the well is unloaded to this valve depth. This procedure is referred to as "flagging" the bottom valve, and a typical decrease in surface closing pressure is 20 to 30 psi.
Intermittent Gas Lift Installation Design Based on Valves With a Large Port, Constant Surface Closing Pressure, and an Intermittent-Spacing-Factor Pressure Gradient With Depth
There are two advantages to a properly designed constant-surface-closing-pressure installation design: (1) no decrease in operating injection-gas pressure with depth of lift is required (particularly important in deep wells with low available injection-gas pressure) and (2) the depth of lift is always the deepest valve depth where the maximum production pressure in the tubing is less than the injection-gas pressure at the same depth.
Because intermittent-flow gas lift is normally used only when lifting from near total depth of a well, it is important to know which valve is the operating valve at any given time. One disadvantage of the constant-surface-closing-pressure design method is the difficulty of establishing the depth of the operating valve from the surface operating injection-gas pressure because the operating pressure does not decrease with each successively lower valve. Determining the fluid level acoustically or recording the time for a liquid slug to surface are two methods for establishing the approximate depth of lift. A liquid-slug velocity of approximately 1,000 ft/min can be assumed for most installations. Decreasing the surface closing pressure of the bottom valve is another method used by some operators to indicate that a well has unloaded to and is operating from the deepest valve. A decrease in the surface-closing pressure of the operating gas lift valve should be considered if a plunger is being installed in an intermittent-lift installation. Intermittent installations with a low PI should operate from the maximum possible depth of lift. This design technique uses an intermittent-spacing-factor pressure gradient based on the tubing size and design gas lift production rate from the well. This pressure gradient is used for locating all unloading valves in the well.
Determination of the Gas Lift Valve Depths
The bottomhole pressures, Pwsd and Pwfd, and bottomhole temperature, Twsd, are generally referenced to the same datum depth, Dd, which is usually the lower end of the production conduit. The steps for establishing the gas lift valve depths on a pressure/depth plot are the same as used in a continuous-flow design, except that the intermittent spacing factor represents the unloading flowing-pressure gradient above the depth of gas injection. The steps for establishing the gas lift valve depths are discussed next.
1. Determine the intermittent spacing factor, Fs, for the design daily production rate and tubing size from Fig. 12.42. Using the intermittent spacing factor as the unloading pressure gradient above the depth of gas injection, gpfa, calculate the unloading flowing-production pressure at the lower end of the production conduit, Ppfd.2. Plot the minimum wellhead pressure between gas injections, Pwh, and the Ppfd on the pressure/depth graph in Fig. 12.43 and connect these two pressures with a straight line. This represents the minimum unloading flowing-tubing-pressure-at-depth (PpfD) min traverse above the depth of gas injection.
3. Add a temperature scale to the pressure/depth graph and plot the surface unloading-wellhead temperature, Twhu, and the bottomhole temperature, Twsd, at D d . Draw the unloading gas lift valve temperature at depth (TvuD) traverse by assuming a straight-line traverse between Twhu and Twsd. Calculate the unloading gas lift valve temperature at depth gradient, gTvu, using Eq. 12.36.
4. Calculate a surface closing pressure for the gas lift valves, Pvc, with Eq. 12.66, and calculate the valve closing pressure, Pvcd, at Dd, with Eq. 12.1. Draw a straight line between Pvc at the surface and, Pvcd, at Dd, which represents the valve closing pressure at depth, PvcD-traverse, and calculate the valve closing gas pressure at depth gradient, ggvc, with Eq. 12.67.
5. Calculate the depth of the top gas lift valve, Dv1, on the basis of the available injection-gas-line pressure, Pio, load-fluid pressure gradient, gls, and the wellhead U-tubing pressure, Pwhu, with either Eq. 12.29 , 12.30 , or 12.31.
6. Draw a horizontal line on the pressure/depth plot at depth Dv1 between the (PpfD)min and TvuD traverses, which includes PvcD1, and record (PpfD1)min, PvcD1, and TvD1, or calculate these pressures and temperature using the appropriate gradients and depth Dv1.
7. Locate the second gas lift valve depth graphically by drawing the static-load-fluid traverse, gls, below the depth of the top gas lift valve with the traverse originating at the minimum unloading flowing tubing pressure, (PpfD1)min, and extend this traverse to the valve closing pressure at depth (PvcD) traverse The spacing between valves may be solved mathematically.
Solving for Dbv,
8. Repeat Step 6 at depth Dv2.
9. Locate the depth of the third gas lift valve, Dv3, graphically or mathematically, and record the pressures and valve temperature at Dv3 as outlined in Steps 7 and 8. Repeat Steps 7 and 8 until the maximum desired gas lift valve depth is attained or the calculated distance between valves is less than the assigned minimum distance between valves. The minimum distance is used for calculating the remaining valve depths until the maximum valve depth is reached.
Calculation of the Test-Rack Set Opening Pressures of the Gas Lift ValvesA tabulation form for these calculations is illustrated in Table 12.10. The bellows-charged pressure at the valve unloading temperature, PbvD, is calculated.
For Eq. 12.70 to be valid, the flowing-production pressure at valve depth is assumed equal to the injection-gas pressure at the same depth when the valve closes. This assumption is reasonable for the deeper gas lift valves with large ports. The pressure in the tubing approaches the injection-gas pressure at valve depth immediately before the valve closes. Eq. 12.70 does not accurately describe the closing pressure for the upper one or two valves as the point of gas injection transfers to the next lower valve. The pressure downstream of the valve port can be significantly less than the injection-gas pressure at the instant the upper one or two valves close. These upper valves will have a higher closing pressure.
The unloading valve temperature at the depth of the valve can be estimated from a TvuD traverse on the pressure/depth plot or calculated with Eq. 12.39. The test-rack opening pressure is calculated with Eq. 12.45 for a tester setting temperature of 60°F using CT(n) from Table 1 or calculated with Eq. 3.
The design given in Example Problem 6 is based on valves with a constant surface closing pressure and uses large-ported unloading valves. The design uses a single intermittent spacing-factor gradient for the spacing calculations. Unloading valves are spaced from the surface because of the possibility that the fluid level may be high after a workover. As discussed earlier, this is only one of many design techniques. Many designers prefer to use small-port valves for an unloading design similar to continuous flow.
Example Problem 6 Intermittent gas lift well data for installation design calculations:
- Tubing size = 2 7/8-in. OD.
- Tubing length, Dd = 6,000 ft.
- Maximum valve depth, Dv(max) = 5,950 ft.
- Static bottomhole well pressure at depth Dd, Pwsd = 1,600 psig at 6,000 ft.
- Bottomhole well temperature at Dd, Twsd = 170°F at 6,000 ft.
- Design daily production rate, qlt = 300 B/D.
- Design unloading wellhead temperature, TvuD = 80°F.
- Static-load-fluid pressure gradient, gls = 0.45 psi/ft.
- U-tubing wellhead pressure, Pwhu = 100 psig.
- Minimum wellhead pressure between injection-gas cycles, Pwh = 100 psig.
- Specific gravity of injection gas, γg = 0.65.
- Injection-gas wellhead temperature, Tgio = 80°F.
- Surface injection-gas-line pressure, Pio = 800 psig.
- Minimum distance between gas lift valves, Dbv(min) = 350 ft.
- Test-rack valve setting temperature, Tvo = 60°F.
- Gas lift valves: 1.5-in.-OD with nitrogen-charged bellows Ab = 0.77 in. 2 and 1/2-in.-ID port with sharp-edged seat.
Determination of Valve Depths. The traverses for the pressures and temperatures used for calculating the gas lift installation design are drawn on a pressure/depth plot in Fig. 12.43.
1. gpfa = Fs = 0.074 psi/ft from Fig. 12.42 for a rate of 300 B/D through 2 7/8-in.tubing, and Ppfd = 100 + 0.074 (6,000) = 100 + 444 = 544 psig at 6,000 ft.
2. Draw the (PpfD) min traverse.
3. Draw the TvuD traverse and gTvu = = 0.015°F/ft.
4. Pvc = 0.85 (800) = 680 psig at surface, and PvcD = 783 psig at 6,000 ft. (Eq. 12.1).
5. ggvc = = 0.0172 psi/ft, and draw the PvcD traverse.
First Gas Lift Valve Depth Calculations.
5. Dv1 = = 1,556 ft. (Eq. 12.29 is the conservative approach).
6. (PpfD1)min = 100 + 0.074 (1,556) = 215 psig at 1,556 ft. PvcD1 = 680 + 0.0172 (1,556) = 707 psig, and TvuD1 = 80 + 0.015 (1,556) = 103°F at 1,556 ft.
Second Gas Lift Valve Depth Calculations.
7. Dbv = = 1,137 ft, and Dv2 = 1,556 + 1,137 = 2,693 ft.
8. (PpfD2)min = 299 psig, PvcD2 = 726 psig, and TvuD2 = 120°F at 2,693 ft.
Third Gas Lift Valve Depth Calculations.
7. Dbv = = 987 ft, and Dv3 = 2,693 +987 = 3,680 ft.
8. (PpfD3)min = 372 psig, PvcD3 = 743 psig, and TvuD3 = 135°F at 3,680 ft.
Fourth Gas Lift Valve Depth Calculations.
7. Dbv = = 857 ft, and Dv4 = 3,680 + 857 = 4,537 ft.
8. (PpfD4)min = 436 psig, PvcD4 = 758 psig, and TvuD4 = 148°F at 4,537 ft.
Repeat Steps 7 and 8 until the maximum desired gas lift valve depth is attained or the calculated distance between gas lift valves is less than an assigned minimum distance between valves. If the desired maximum valve depth had not been reached, assume the minimum distance between valves until the maximum valve depth is reached. The minimum distance between valves of 350 ft was not used in the design of this installation because the maximum calculated valve depth of 5,928 ft was reached before the calculated distance between valves was less than 350 ft.
Calculation of the Test-Rack Set Opening Pressures of the Gas Lift Valves
A tabulation form for these calculations is given in Table 12.10. The bellows-charged pressure at the valve unloading temperature, PbvD at TvuD, is calculated with Eq. 12.60. The temperature correction factor, CT, is calculated with Eq. 12.3 rather than read from Table 12.1.
- For the first valve at Dv1 using Eq. 12.70: PbvD1 = PvcD1 = 707 psig at 103°F.
- Calculated CT(1) = 0.914 with Eq. 12.3.
- With Eq. 12.45, calculate the test-rack opening pressure, Pvo1, of the valve at Dv1:
Repeat Steps 1 to 3 for the remaining valves. An additional pressure drop of 20 psi in PvcD may be taken at the last (bottom) valve to flag it and ensure that the upper valves do not reopen.
The calculated test-rack opening pressure of Valve 6 in Table 12.10 is based on a 1/2-in. ID port. A valve with the same surface closing pressure and a 3/8-in ID port can be run as the bottom valve to reduce the spread for a lower than predicted flowing bottomhole pressure. The test-rack opening pressure for a valve with a 3/8-in. ID port (1 – Ap/Ab = 0.857) would be 754 psig.
Gas Lift Chambers
Chamber lift is a form of intermittent-flow gas lift. The chamber installation design determines the success of this type of gas lift operation. There are three primary reasons for selecting a chamber lift to gas lift a well:
- To lower the depth of gas injection in a low-flowing-bottomhole-pressure well with a long perforated interval or open hole.
- To fully use an available injection-gas pressure that significantly exceeds the flowing bottomhole pressure in terms of the pressure resulting from the starting slug length.
- To attain the lowest possible average flowing bottomhole pressure by reducing the fluid-head backpressure against the formation for a given liquid feed-in volume.
Although there are numerous variations in the physical design of a chamber, the two fundamental types are the two-packer and the insert bottle type for collecting the well fluids. Both types are shown in Fig. 12.44. The two-packer chamber utilizes the casing annulus for accumulation of the well fluids. The insert type of chamber is usually fabricated from the largest pipe that can be safely run inside of the casing or open hole. Chamber location and size relative to the working fluid level, the injection- and formation-gas venting, the injection-gas rate through the chamber-operating gas lift valve for lifting the slug, and properly using the chamber-lift principle can be the difference between efficient and inefficient chamber-lift operations.
Chamber-Lift Principle. The chamber-lift principle implies that the injection gas initially contacts the top of the liquid column in the chamber and displaces this liquid into the tubing above the chamber before injection gas enters the lower end of the dip tube. The dip tube is assumed to be filled with liquid at the beginning of an injection-gas cycle; that is, the top of the chamber is located at the working fluid level. The accumulated liquid in the chamber annulus is U-tubed into the tubing above the chamber before injection gas entry into the lower end of the dip tube. Chamber-lift operation prevents water accumulation in the production conduit because the water is U-tubed first from the chamber, followed by the oil, and then by the injection gas.
Design Considerations and Chamber Length. The chamber length should be calculated on the basis of an injection-gas pressure that is 60 to 75% of the initial opening pressure of the chamber-operating gas lift valve to ensure adequate pressure differential across the liquid column at the instant the injection gas enters the lower end of the dip tube. Actual operations have shown higher chamber-lift efficiency when the chamber length is based on an injection-gas pressure that is at least 60 to75% of the opening pressure of the chamber-operating gas lift valve. An adequate pressure differential across the liquid slug is necessary to ensure maximum liquid recovery with a minimum of injection-gas breakthrough during displacement to the surface.
|PioDc||=||injection-gas pressure at depth for calculating chamber length, psig,|
|PoDov||=||injection-gas initial opening pressure of the chamber-operating gas lift valve at depth, psig,|
|Lc||=||chamber length, ft,|
|PtDc||=||tubing pressure at chamber depth based on Pwh when chamber-operating gas lift valve opens, psig,|
|glc||=||average pressure gradient for liquid production in chamber, psi/ft,|
|Fat||=||ratio of physical capacities per foot of chamber annulus/tubing above chamber, dimensionless,|
|Vca||=||capacity per foot of casing or chamber annulus, ft3/ft,|
|Vt||=||capacity per foot of tubing above chamber, ft3/ft.|
The actual chamber length is the distance from the top of the chamber to the lower end of the dip tube. The chamber-length equation is based on three assumptions: (1) the top of the chamber is located at the working fluid level between injection-gas cycles, (2) the dip tube is full when the chamber-operating gas lift valve opens, and (3) the physical size of the chamber and dip tube do not change over the entire chamber length. The chamber-length equation must be modified for other geometries and assumptions.
Example Problem 7: Two-Packer Chamber-Length Calculations
The following data are given for a two-packer chamber at 6,000 ft (top packer):
- Casing size = 7-in. OD, 26 lbm/ft.
- Tubing and dip tube size = 2 7/8-in. OD.
- PoDov = 800 psig at 6,000 ft.
- glc = 0.40 psi/ft.
- PtDc = 100 psig at 6,000 ft.
- Vca = 0.1697 ft3/ft.
- Vt = 0.0325 ft3/ft.
Calculate the approximate chamber length using Eqs. 12.71 through 12.73.
Unloading Valve Depths. The unloading valve spacing calculations for a chamber installation are the same as the valve depth calculations for an intermittent installation with the exception of the bottom unloading valve. The bottom unloading gas lift valve should be within a few joints of the chamber-operating valve because the depth of gas-injection for the chamber-operating valve is the lower end of the dip tube rather than the actual valve depth, and the fluid-slug length above the valve is based on the chamber annular capacity plus the dip-tube length. The initial opening pressure of a chamber-operating gas lift valve should be at least 50 psi lower than the initial opening pressure of the bottom unloading valve in most installations to ensure lifting from the chamber-operating valve. The tubing pressure at the top of a properly designed chamber that is located at the working fluid level will be near wellhead tubing pressure. The operating-chamber valve must have proper spread characteristics (difference between the operating valve initial opening and closing pressures in the well) to prevent excessive injection-gas usage per cycle. Pilot-operated gas lift valves are widely used as the chamber-operating valve because a large port is available with controlled spread characteristics.
There can be a significant pressure differential across the standing valve immediately after the liquid slug surfaces and blowdown occurs. A mechanical-locking-type standing valve is recommended to prevent the standing valve from being blown out of its seating nipple from this pressure differential.
Importance of Chamber-Bleed Valve. An important consideration is the design and operation of the chamber-bleed valve for venting free gas in the upper section of the chamber after an injection-gas cycle. Most of the free gas is injection gas trapped above the increasing fluid level in the chamber during fill-up. A liquid seal at the lower end of the dip tube occurs soon after a liquid slug surfaces and the injection-gas velocity in the tubing begins to decrease. The liquid seal results from liquid fallback accumulating in the lower end of the dip tube and chamber. Injection-gas from the previous chamber U-tubing cycle is trapped in the chamber annulus above the lower end of the dip tube. The trapped injection gas from the previous injection-gas cycle must be vented from the chamber annulus before the chamber can fill with liquid. If the injection gas is not vented, the trapped injection gas will reduce the liquid production entering the chamber. Without venting the trapped injection gas, a portion of the production entering the chamber increases the length of the liquid column in the tubing. If a significant volume of the reservoir-liquid production fills the tubing above the chamber, the major benefit of an accumulation chamber is nullified in terms of lowering the liquid-column backpressure against the formation. Differential valves have been used as chamber-bleed valves. The differential valve must be properly set with choke sizes that ensure closure immediately after the chamber-operating gas lift valve opens.
Description of Chamber-Lift Injection-Gas Cycle. A complete injection-gas cycle of operation for chamber lift is described for stabilized operation after unloading. Stabilized production infers that the well has unloaded the kill fluid, all production is from the reservoir, and the production per injection-gas cycle remains approximately the same.
When the chamber-operating valve opens, the standing valve closes. The liquid column in the chamber annulus is U-tubed into the dip tube and tubing above the chamber to form the starting-liquid-slug length. A portion of the starting liquid slug is displaced to the surface by the injection gas. Not all of a starting liquid slug reaches the surface because of injection-gas breakthrough and resulting liquid fallback during displacement.
While the standing valve is closed and the liquid slug is surfacing, the reservoir fluid feed-in continues to enter the wellbore. Formation production enters the casing annulus between the chamber OD and casing ID of an insert chamber or below the bottom packer of a two-packer chamber installation. Reservoir production cannot enter the chamber while the standing valve is closed. All free gas, including the formation and trapped injection gas, is vented into the tubing through the chamber bleed valve in a properly designed two-packer installation. The formation-gas production in the annular area between the insert chamber OD and casing ID beneath the packer should be vented into the tubing above the chamber to prevent a significant decrease in the maximum daily production from a high-PI, low-flowing-bottomhole-pressure well.
Free-Gas Problems With Insert Chambers. Gas separation occurs beneath the packer in the annulus between the insert chamber OD and casing ID. The formation free gas accumulates above the liquid level in this annulus. This trapped formation free gas is compressed by the new production entering the wellbore. The additional formation free-gas production is added to the trapped free gas beneath the packer as the formation free gas separates from the liquid production. This trapped free gas under the packer restricts the total volume of produced-liquid accumulation in the casing-ID/insert-chamber-OD annulus below the packer.
After a liquid slug surfaces, the injection gas in the tubing exhausts into the flowline, and the flowing bottomhole pressure in the chamber decreases. The standing valve opens when the pressure in the chamber is less than the reservoir pressure beneath the standing valve. The liquid in the casing/chamber annulus below the gas/liquid level flows into the chamber first. Liquid is followed by the trapped formation free gas from the casing/chamber annulus until the annulus and chamber pressures are equal at the depth of the standing valve. The casing/chamber annulus between the packer and standing valve depth is totally filled with formation free gas and no liquid at the equalized minimum flowing bottomhole pressure between injection-gas cycles.
The injection-gas cycle frequency depends on the well deliverability. When maximum cycle frequency is required, the next injection-gas cycle begins as soon as the tubing wellhead pressure approaches the production-header (separator) pressure. Time-cycle control of the injection-gas cycle is required to ensure maximum cycle frequency. A very short time after beginning the surface injection-gas cycle, the chamber-operating valve opens and the standing valve closes. Because of the high injection-gas cycle frequency, most of the well production enters the wellbore while the standing valve is closed and the liquid slug is surfacing. As a result, nearly all of the liquid entering the chamber is the liquid accumulation in the casing/chamber annulus before the standing valve opens. Very little production enters the chamber directly from the reservoir because the standing valve is open for a much shorter length of time than it is closed at maximum injection-gas cycle frequency. The solution to this problem is to vent the free gas in the casing/chamber annulus beneath the packer into the tubing above the chamber. The separated formation gas would not be trapped in this annular space. The casing opposite the insert chamber annulus could fill with liquid if the free gas was vented into the tubing above the chamber. When the standing valve opens after a slug surfaces and the pressure in the chamber decreases, mostly liquid rather than free gas enters the chamber when free gas is vented from below the packer.
If a well is producing less than 10 to 20 B/D and is requiring less than 6 or 12 injection-gas cycles per 24 hours, the free gas in the casing annulus is not a serious a problem. Most of the reservoir-fluid production enters the wellbore while the standing valve is open during the long time interval between injection-gas cycles. The free-gas volume above the liquid level in the chamber annulus has sufficient time to flow into the dip tube through a small orifice or bleed valve. One reason that inefficient insert chamber operations in a high-injection-gas-cycle frequency, gassy well is not addressed in the literature is the fact that most low-cost insert-chamber installations use a hookwall packer and hanger nipple, as illustrated in Fig. 12.44a . This is the type of insert chamber that is run in low-rate, "stripper-type" wells.
There may be little benefit from an insert-chamber installation in a gassy well with a high-frequency injection-gas cycle if the design does not provide a means to vent the trapped free gas below the packer as shown in Fig. 12.45. Improved chamber-lift operations can be expected by installing a gravity-closed or spring-loaded gas lift valve check below the packer. A tubing-retrievable conventional gas lift mandrel and check valve is run upside down between the packer and top of the insert chamber in Fig. 12.46. Wireline- instead of tubing-retrievable equipment can be used. Adding a screen to the check-valve inlet is recommended to prevent trash in the well fluids from entering and preventing the check dart from closing. The check valve adds very little cost to this type of chamber installation. Because liquid, rather than trapped formation gas, is in contact with the formation in the casing annulus, better reservoir-liquid feed-in between injection-gas cycles should occur. Only the trapped formation free and injection gas in the chamber must vent through the chamber-bleed valve.
Plunger Application for Intermittent Gas LiftAn important consideration related to intermittent gas lift operations is the injection-gas breakthrough and resulting loss of the liquid production per cycle from the injection gas penetrating the liquid slug during the time required to displace this slug to the surface. The produced-liquid slug can be a small fraction of the starting slug size because of injection-gas breakthrough. The losses are greater when the injection-gas pressure is low and the required depth of lift is near total depth in a deep well. For example, a 12,000-ft well with a bottomhole flowing pressure of 300 psig and an available injection-gas pressure of only 450 psig can be gas lifted intermittently with the proper plunger. The well could not be gas lifted successfully from this depth without a plunger.
A typical plunger installation for intermittent gas lift operation is shown in Fig. 12.47. A plunger can be expected to decrease the injection-gas requirement for an intermittent gas lift installation from 30 to 70% depending on plunger construction, the depth of lift, injection-gas pressure, and adjustment of the injection-gas volume to the well before the plunger is installed.
There is little if any liquid-slug recovery by intermittent gas lift from very deep wells with low injection-gas pressure unless a plunger is installed. The plunger provides a solid interface between the starting liquid slug and the displacing injection gas. The plunger practically eliminates liquid fallback as a result of gas penetrating the liquid slug. The increase in liquid recovery and the decrease in the injection-gas requirement per cycle from installing a plunger are minimal in an intermittent gas lift installation with small liquid slugs being lifted at an exceedingly high slug velocity in shallow wells. Another advantage of a plunger is that it reduces paraffin in a well with a paraffin problem. Plungers are installed in some wells for the sole purpose of keeping the tubing free of paraffin deposition.
A plunger can be installed in an existing tubing-retrievable conventional gas lift valve installation by wireline without pulling the tubing if there are no tight spots in the tubing. A standing valve and a bottomhole collar lock or a stop with a bumper spring can be installed with wireline tools. A standing valve normally is recommended but not required in wells with a low permeability. The bottomhole bumper spring is located immediately above the operating gas lift valve, and a standing valve is stationed below the valve. The remaining equipment is on the surface and includes a lubricator with a bumper spring and a plunger catcher mechanism. A plunger-arrival detector to shut in the tubing is not needed for an intermittent gas lift installation because the tubing is not shut in between injection-gas cycles.
A plunger ascent velocity of 800 to 1,000 ft/min is recommended for the most efficient lift. A plunger may stall or tend to stop and start at plunger velocities less than 350 to 400 ft/min. Plunger velocities in excess of 1,200 to 1,500 ft/min are not recommended because of possible damage to the plunger on arrival at the surface and an apparent tendency to bypass a thicker than normal liquid boundary on the tubing wall. Noting the times when a time-cycle controller opens and when the plunger arrives at the surface can approximate an average plunger velocity.
The addition of a plunger to an intermittent gas lift installation should be considered when (1) the available injection-gas pressure is low relative to the required depth of lift in a low-flowing-bottomhole-pressure well; (2) there is an excessive increase in wellhead tubing pressure as the liquid slug enters the flowline because of such factors as a small-ID flowline, excessive number of bends at the wellhead, and flowline choke; and (3) a paraffin-deposition problem exists. A plunger should increase the efficiency required of most intermittent gas lift installations. Because a plunger adds several moving parts, it can also increase the operating problems.
Well conditions that prohibit the use of a plunger are a bore opening through surface wellhead and tree valves that differs from the tubing ID; excessive well deviation, which prevents a plunger from descending to its bottomhole bumper spring; tight spots in the tubing; appreciable sand production; and high-rate intermittent gas lift operations. The fall time required for a plunger to descend to the bottom bumper spring could reduce the maximum production from a high-cycle-frequency intermittent gas lift installation.
Specially designed plungers are available for wells with side-pocket mandrels. Plungers have worked in wells with a deviation near 50°, but the maximum deviation for a plunger operation depends on the construction of the plunger. The manufacturers should be able to provide the information related to their plunger operation in a deviated well.
There are numerous types of plunger sealing elements, bypass valves, plunger weights and lengths, and other features that may have been developed for unique applications. Some plungers are particularly applicable for gas lift and other types are not. Select the proper plunger to match the well conditions and application for trouble-free service and efficient operation. Please refer to the chapter on Plunger Lift in this volume of the Handbook.
Operation of Gas Lift Installations
A recommended practice for operation, maintenance, and troubleshooting gas lift installations is given in API RP 11V5. 
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. 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.
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.
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.
Gas Lift for Unusual Environments
Gas lift is especially suited for application in unusual environments. This section discusses a few of these environments and how gas lift is used in the particular application.
Gas lift is a widely used artificial-lift system in offshore installations and has performed exceptionally well. Most downhole gas lift equipment has few if any moving parts and requires little maintenance. What little maintenance that is required can normally be done with wireline equipment. For this reason, downhole gas lift equipment is much less costly to replace than other forms of downhole artificial-lift equipment. The required space, or "footprint," and weight of gas lift surface controls are minimal. Because produced gas from the offshore wells generally must be conserved, it can be compressed and provide a ready source of high-pressure gas for gas lift.
The process of gas lift from offshore platforms is slightly different from gas lift onshore. In many cases, the surface installations on offshore platforms are better designed than onshore installations. If designed properly, there will be very little pressure loss caused by restrictions or flowlines. The compressors for gas lift are located nearby, so the distribution of gas should be no problem. Because of the importance to the overall installation, gas compression and dehydration equipment is normally operated and maintained by people who are provided for this specific purpose.
Safety Devices. There are many more safety devices on offshore platforms than on onshore installations. High-/low-pressure shutoff devices are installed at the wellhead on both the injection-gas line and the flowline to automatically close in the well at the surface, should there be a radical change in either line’s operating pressure.
Surface or downhole safety devices are a necessary part of any offshore well. With so much property and human life at stake on the platforms, it is an absolute necessity to prevent downhole or surface catastrophic failure. Safety valves are included on the production string of a gas lift well and may cause some restriction to flow. In the North Sea, governmental agencies also require a safety valve on the gas-injection side of gas lift wells. The reason is the possibility of the check valve on the gas lift valve failing, which would allow well fluids to flow into the casing. Restrictions from subsurface safety equipment may enter into the design of a gas lift installation.
Gas Lift Installations Drilled From Offshore Platforms
Wells drilled from offshore platforms have varying degrees of deviation that must be accounted for in predicting vertical multiphase flow. Most gas lift design programs can take this varying deviation into account. Wireline operators report little problems in setting valves in mandrels at deviations up to 60°. Motors have been developed to move tools downhole at high deviations and have been used in some instances. The gas lift retrievable-valve mandrels with orientation sleeves are designed to insure that the valve enters the pocket regardless of pocket orientation relative to the vertical.
Subsea Gas Lift Installations
Subsea installations increased dramatically in the last few years with the addition of producing areas in greater and greater water depths. Today, it is not unusual to find production from water depths over 6,000 ft with gas lift being the preferred production method in most of these completions. With extreme water depths, some form of artificial lift is usually required just to kick off the well and move the production from the seafloor to the surface.
Devices and equipment for carrying gas lift equipment into subsea wells were perfected at the onset of subsea technology. These include devices for carrying the valves and engines for driving the valve downhole through flowlines and other systems.  Although such tools are available, these operational techniques are not widely used. Most subsea gas lift today is done with high-pressure gas and a single orifice placed as deep as the pressure will permit. By using this approach, there is no gas lift equipment in the well that could fail or need replacing. In many deepwater installations, where the water depth itself adds considerable head that must be overcome to produce the well, gas injection is often through a single point at the wellhead or near the mudline. 
Gas lift has been used to produce high-viscosity oil in many parts of the world. Heavy oil is being produced by gas lift in Venezuela. Diluent injection has been found to be very beneficial in producing all types of artificial-lift wells in eastern Venezuela. Diesel fuel is usually used as the diluent, and the injection of approximately 10% by volume lowers the specific gravity and increases the API gravity of the oil. 
Water can be used as a diluent as well as diesel fuel and has been proven effective to reduce backpressure in large pipelines. In most cases, water acts to reduce backpressure by adding a water ring around the viscous crude that reduces friction between the crude and the pipe wall. When this occurs, water becomes the wetting phase and the resulting friction is similar to that of water. However, unlike the diesel fluid which increases the value of the produced oil by lowering its viscosity, water adds another phase that must eventually be removed.
Gas Lift With Air, Nitrogen, and Carbon Dioxide
Typically, gas lift designs are based on natural gas as the injection gas. However, gas lift with natural gas did not begin in a big way until the 1920s. Early gas lift operations were conducted using air as the injection gas. Many of the early great oil fields such as Spindletop and Goose Creek were produced with air lift. Air has its disadvantages when used for gas lift because oxygen in the air causes serious corrosion, scale, and the possibility of combustion when it is mixed with well fluids. Air is still used in gas lift installations today but on a very limited scale.
Nitrogen and carbon dioxide offer good alternatives to natural gas for gas lift. Nitrogen can be used for gas lift because it is inert, relatively inexpensive, and noncorrosive. Quite often, nitrogen is available at high pressure near the producing facilities, where it is being used for various enhanced-oil-recovery and pressure-maintenance projects. 
Carbon dioxide is also readily available from miscible displacement projects and can be used for gas lift purposes. Natural gas containing 75% carbon dioxide was used for gas lift in two large fields in Argentina without noticeable problems.  In heavy-oil reservoirs, carbon dioxide is also very useful in decreasing the viscosity of the oil. Both nitrogen and carbon dioxide can be purchased at a price competitive with natural gas in many locations. The use of small nitrogen plants for gas lift of remote offshore and onshore locations has proved feasible under certain conditions.
|a||=||actual, annulus, assigned, or assumed|
|b||=||bellows, below, or between|
|c||=||capacity, critical, closing, calculated, or chamber|
|d||=||reference datum depth|
|f||=||flow, flowing, or formation|
|o||=||oil, opening, or operating|
|p||=||production, pressure, or port|
|s||=||static, shut-in, set, or spacing|
|t||=||tubing, total, tester, or transfer|
|u||=||unloading or U-tubing|
|w||=||well or water|
Blann, J.R., Brown, J.S., and DuFresne, L.P. 1980. Improving Gas-Lift Performance in a Large North African Oil Field. J Pet Technol 32 (9): 1486-1492. SPE-8408-PA. http://dx.doi.org/10.2118/8408-PA.
Brown, K.E. et al 1980. The Technology of Artificial Lift Methods, Vol. 2a, 224-229. Tulsa, Oklahoma: The Petroleum Publishing Co.
Mower, L.N., Lea, J.F., E., B. et al. 1985. Defining the Characteristics and Performance of Gas-Lift Plungers. Presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22-26 September 1985. SPE-14344-MS. http://dx.doi.org/10.2118/14344-MS.
Ros, N.C.J. and Gray, H.E. 1964. Shell Two-Phase Vertical Flow Computer Program MK 1X-H. Proprietary paper, Shell Development Co. E&P Research Div., a Division of Shell Oil Co., Houston, Texas.
API RP 11V7, Recommended Practice for Repair, Testing and Setting Gas Lift Valves, first edition. 1995. Washington, DC: API.
Winkler, H.W. and Smith, S.S. 1962. Camco Gas Lift Manual, A2-001. Houston, Texas: Camco Inc.
Appendix A-Simplified Mathematical Gas Lift Valve Performance Model
A.2 Calculation of Equivalent Port Area Open to Gas Flow
If A Ape > Ap , then Ape = Ap (fixed-ID orifice flow).
A.3 Calculation of Gas Rate Through '''Ape
If Rdu < = 0.553, then Rdu = 0.553 (critical flow).
|Ab||=||effective area of bellows, in.2|
|Ap||=||valve port area (ball/seat-line contact area for sharp-edged seat), in.2|
|Ape||=||valve port equivalent area open to gas flow, in.2|
|Blr||=||bellows-assembly load rate, psi/in.|
|Bsr||=||bellows-assembly spring rate, lbf/in.|
|CT||=||temperature correction factor for nitrogen from PbvD at TvuD to Pb at 60°F, dimensionless|
|Mvs||=||movement of the gas lift valve stem, in.|
|Patm||=||atmospheric pressure, psia|
|PbvD||=||nitrogen-charged bellows pressure at valve temperature, psig|
|PioD||=||injection-gas pressure at valve depth, psig|
|PptD||=||flowing-production transfer pressure at valve depth, psig|
|Pvo||=||test-rack valve opening pressure at 60°F, psig|
|qgi||=||daily injection-gas rate through gas lift valve, Mscf/D|
|rb||=||radius of ball on gas lift valve stem, in.|
|rp||=||radius of valve port (ball/seat-line contact for sharp-edged seat), in.|
|rtf||=||top radius of frustum of right circular cone, in.|
|Rdu||=||ratio of downstream pressure/upstream pressure, psia|
|s||=||slant height of frustum of right circular cone, in.|
|TgiD||=||injection-gas temperature at valve depth, °F|