Multistage Gas-Lift Valve Unloading A string with multistage gas-lift valves is designed in accordance with the requirements of unloading. The type of gas-lift valve should be selected, and the setting depths of the valves of stages should be calculated. Refer to the calculation method of gas-lift production design. FSV on the gas-lift supply pipeline. PSHL on the gas-lift supply. API Spec 6A and API Spec 6AV1 manual isolation valve. (1) Subsea pipelines, pipeline risers, or manifolds via an external gas lift pipeline or umbilical: Meet all of the requirements for the BSDV described in §§ 250.835 and 250.
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A recommended practice for operation, maintenance, and troubleshooting gas lift installations is given in API RP 11V5.[1]
- 1Unloading procedures and proper adjustment of injection-gas rate
Unloading procedures and proper adjustment of injection-gas rate
The importance of properly unloading a gas lift installation cannot be overemphasized in terms of possible damage to gas lift valves and for attaining the optimum depth of lift. 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:
Gas Lift Manual
- 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 Manual Gabor Takacs Free Download
References
- ↑API RP 11V5, Recommended Practice for Operation, Maintenance and Troubleshooting of Gas Lift Installations, first edition. 1995. Washington, DC: API.
Noteworthy books
Brown, K. E. (1967): GAS LIFT THEORY AND PRACTICE. Petroleum Publishing Co., Tulsa, Oklahoma.
Takács G. (2005): GAS LIFT MANUAL. ISBN 0-87814-805-1 PennWell Books, Tulsa Oklahoma, 478p.
Noteworthy papers in OnePetro
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See also
Category
Gas lift or bubble pumps use the artificial lift technique of raising a fluid such as water or oil by introducing bubbles of compressed air, water vapor or other vaporous bubbles into the outlet tube. This has the effect of reducing the hydrostatic pressure in the outlet tube vs. the hydrostatic pressure at the inlet side of the tube.
Devices using this type of lift mechanism:
- Coffee percolators and electric drip coffeemakers use vaporized water to lift hot water
- Airlift pumps uses compressed air to lift water
- Pulser pumps use a subterranean chamber of air for an airlift pump
- Suction dredges use an airlift pump to vacuum mud, sand and debris
- Mist lift pumps uses vaporized water to lift seawater in Ocean thermal energy conversion
Petroleum industry uses[edit]
In the United States, gas lift is used in 10% of the oil wells that have insufficient reservoir pressure to produce the well. In the petroleum industry, the process involves injecting gas through the tubing-casing annulus. Injected gas aerates the fluid to reduce its density; the formation pressure is then able to lift the oil column and forces the fluid out of the wellbore. Gas may be injected continuously or intermittently, depending on the producing characteristics of the well and the arrangement of the gas-lift equipment.[1]
The amount of gas to be injected to maximize oil production varies based on well conditions and geometries. Too much or too little injected gas will result in less than maximum production. Generally, the optimal amount of injected gas is determined by well tests, where the rate of injection is varied and liquid production (oil and perhaps water) is measured.
Although the gas is recovered from the oil at a later separation stage, the process requires energy to drive a compressor to raise the pressure of the gas to a level where it can be re-injected.
The gas-lift mandrel is a device installed in the tubing string of a gas-lift well onto which or into which a gas-lift valve is fitted. There are two common types of mandrels. In a conventional gas-lift mandrel, a gas-lift valve is installed as the tubing is placed in the well. Thus, to replace or repair the valve, the tubing string must be pulled. In the side-pocket mandrel, however, the valve is installed and removed by wireline while the mandrel is still in the well, eliminating the need to pull the tubing to repair or replace the valve.
A gas-lift valve is a device installed on (or in) a gas-lift mandrel, which in turn is put on the production tubing of a gas-lift well. Tubing and casing pressures cause the valve to open and close, thus allowing gas to be injected into the fluid in the tubing to cause the fluid to rise to the surface. In the lexicon of the industry, gas-lift mandrels are said to be 'tubing retrievable' wherein they are deployed and retrieved attached to the production tubing. See gas-lift mandrel.
Gas lift operation can be optimized in different ways. The newest way is using risk-optimization which considers all aspects for gas lift allocation.
History[edit]
Air lift uses compressed air to lift water in operations such as dredging and underwater archeology. It is also found in aquariums to keep water circulating. These forms of lift were used as far back as 1797 in mines to lift water from mine shafts. These systems used single point injection of air into the liquid stream, normally through a foot valve at the bottom of the string. Gas lift was used as early as 1864 in Pennsylvania to lift oil wells, also using compressed air, via an air pipe bringing the air to the bottom of the well. Air was used in Texas for large-scale artificial lift. In 1920 natural gas replaced air, lowering the risk of explosion. From 1929 until 1945 about 25000 patents were issued on different types of gas lift valves that could be used for unloading in stages.[2] Some of these systems involved moving the tubing, or using wireline sinker bars to change the lift point. Others were spring operated valves. Ultimately, in 1944 W.R. King patented the pressurized bellows valve that is used today. In 1951 the sidepocket mandrel was developed for selectively positioning and retrieving gas lift valves with wireline.
See also[edit]
- Airlift pump – A pump using density difference due to injected air in the liquid
- Submersible pump – Pump designed to work submerged in fluid
References[edit]
Gas Lift Manual Download
- ^How Does Artificial Lift Work?, Rigzone, retrieved May 29, 2012
- ^Gas lift, retrieved 2015-10-14