You must log in to edit PetroWiki. Help with editing
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information
Intermittent-flow gas lift
The following topic describes the intermittent-flow gas lifts and the factors which affect its design and performance.
Overview
Intermittent-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. 1. 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.
Fig. 1-Intermittent-flow gas lift cycle of operation.
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:
- The total liquid production reaching the surface per cycle
- 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.-outside diameter (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.
Intermittent-flow gas lift design
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.
Two basic factors control the maximum production from a high-rate intermittent-flow gas lift installation:
- The total liquid production reaching the surface per cycle
- The maximum number of injection-gas cycles per day
Factors affecting intermittent-flow gas lift
Streamlining wellheads
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.
Maintaining injection gas casing pressure
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.
Length of flowline
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.-outside diameter (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.
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 gas/liquid ratio (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.
Comparison of time-cycle to choke control gas lifts
The 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. 2, illustrate time-cycle and choke-control operations. Fig. 2 is time-cycle control where:
- Time-cycle controller opens
- Time-cycle controller closes
- Gas lift valve closes
Fig. 2b is choke control of the injection gas where:
- Gas lift valve opens
- 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.
Fig. 2-Two-pen pressure-recording charts from intermittent gas lift installations with time-cycle and choke control of the injection gas.
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.
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
External links
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
See also
Intermittent-flow gas lift installation design
Intermittent gas lift plunger application