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Gas 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. The principle of gas lift is that gas injected into the tubing reduces the density of the fluids in the tubing, and the bubbles have a “scrubbing” action on the liquids. Both factors act to lower the flowing bottom-hole pressure (BHP) at the bottom of the tubing. There are two basic types of gas lift in use today—continuous and intermittent flow.
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.
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 bywire line 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.
Continuous-flow gas lift
The vast majority of gas lift wells are produced by continuous flow, which is very similar to natural flow. Fig. 1 shows a schematic of a gas-lift system. 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 bottom-hole pressure below the static bottom-hole pressure thereby creating a pressure differential that allows the fluid to flow into the wellbore. Fig. 2 illustrates this principal.
Gas lift has the following advantages:
Gas lift is the best artificial lift method for handling sand or solid materials. Many wells produce some sand even if sand control is installed. The produced sand causes few mechanical problems in the gas-lift system; whereas, only a little sand plays havoc with other pumping methods, except the progressive cavity pump (PCP).
Deviated or crooked holes can be lifted easily with gas lift. This is especially important for offshore platform wells that are usually drilled directionally.
Gas lift permits the concurrent use of wireline equipment, and such down-hole equipment is easily and economically serviced. This feature allows for routine repairs through the tubing.
The normal gas-lift design leaves the tubing fully open. This permits the use of BHP surveys, sand sounding and bailing, production logging, cutting, paraffin, etc.
High-formation GORs are very helpful for gas-lift systems but hinder other artificial lift systems. Produced gas means less injection gas is required; whereas, in all other pumping methods, pumped gas reduces volumetric pumping efficiency drastically.
Gas lift is flexible. A wide range of volumes and lift depths can be achieved with essentially the same well equipment. In some cases, switching to annular flow also can be easily accomplished to handle exceedingly high volumes.
A central gas-lift system easily can be used to service many wells or operate an entire field. Centralization usually lowers total capital cost and permits easier well control and testing.
A gas-lift system is not obtrusive; it has a low profile. The surface well equipment is the same as for flowing wells except for injection-gas metering. The low profile is usually an advantage in urban environments.
Well subsurface equipment is relatively inexpensive. Repair and maintenance expenses of subsurface equipment normally are low. The equipment is easily pulled and repaired or replaced. Also, major well workovers occur infrequently.
Installation of gas lift is compatible with subsurface safety valves and other surface equipment. The use of a surface-controlled subsurface safety valve with a 1/4-in. control line allows easy shut in of the well.
Gas lift can still perform fairly well even when only poor data are available when the design is made. This is fortunate because the spacing design usually must be made before the well is completed and tested.
Gas lift has the following disadvantages:
Relatively high backpressure may seriously restrict production in continuous gas lift. This problem becomes more significant with increasing depths and declining static BHPs. Thus, a 10,000-ft well with a static BHP of 1,000 psi and a PI of 1.0 bpd/psi would be difficult to lift with the standard continuous-flow gas-lift system. However, there are special schemes available for such wells.
Gas lift is relatively inefficient, often resulting in large capital investments and high energy-operating costs. Compressors are relatively expensive and often require long delivery times. The compressor takes up space and weight when used on offshore platforms. Also, the cost of the distribution systems onshore may be significant. Increased gas use also may increase the size of necessary flowline and separators.
Adequate gas supply is needed throughout life of project. If the field runs out of gas, or if gas becomes too expensive, it may be necessary to switch to another artificial lift method. In addition, there must be enough gas for easy startups.
Operation and maintenance of compressors can be expensive. Skilled operators and good compressor mechanics are required for reliable operation. Compressor downtime should be minimal (< 3%).
There is increased difficulty when lifting low gravity (less than 15°API) crude because of greater friction, gas fingering, and liquid fallback. The cooling effect of gas expansion may further aggravate this problem. Also, the cooling effect will compound any paraffin problem.
Good data are required to make a good design. If not available, operations may have to continue with an inefficient design that does not produce the well to capacity.
Potential gas-lift operational problems that must be resolved include:
Freezing and hydrate problems in injection gas lines
Corrosive injection gas
Severe paraffin problems
Fluctuating suction and discharge pressures
Other problems that must be resolved are:
Changing well conditions
Especially declines in BHP and productivity index (PI)
Deep high-volume lift
Valve interference (multi-pointing)
Additionally, dual gas lift is difficult to operate and frequently results in poor lift efficiency. Emulsions forming in the tubing, which may be accelerated when gas enters opposing the tubing flow, also must be resolved.
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.
Open and Closed Gas Lift Installations
Most tubing flow gas lift installations will include a packer to stabilize the fluid level in the casing annulus after a well has unloaded. A packer is installed in a low flowing bottom-hole pressure well to prevent injection gas from blowing around the lower end of the tubing.
A closed gas lift installation implies that there is a packer and a standing valve in the well. An installation without a standing valve is referred to as semi-closed, which is widely used for continuous flow operations. An installation without a packer or standing valve is an open installation. An open installation is seldom recommended unless the well has a flowing bottom-hole pressure that significantly exceeds the injection gas pressure and packer removal may be difficult or impossible because of sand, scale, etc. Casing flow gas lift requires an open installation since the production conduit is the casing annulus. A packer is required for gas
lifting low bottom-hole pressure wells to isolate the injection gas in the casing annulus and allow surface control of the injection gas volumetric rate to the well. Most intermittent gas lift installations will include a packer and possibly a standing valve. Although illustrations of nearly all-intermittent gas lift installations show a standing valve, many actual installations do not include this valve. If the permeability of the well is very low, a standing valve may not be needed.
The advantages of a packer are particularly important for gas lift installations where the injection gas line pressure varies or the injection gas supply is periodically interrupted. If the installation does not include a packer, most wells must be unloaded or partially unloaded after each extended shutdown. More damage to gas lift valves can occur during unloading operations than any time in the life of a gas lift installation. If the injection gas line pressure varies, the working fluid level changes in an open installation. The result is a liquid washing action through all of the valves below the working fluid level. This continuing fluid transfer can eventually fluid-cut the seat assemblies of these lower gas lift valves. A packer stabilizes the working fluid level, thus eliminating the need for unloading after a shutdown and the fluid washing action from a varying injection gas line pressure.
Gas lift valves
A gas lift valve is designed to stay closed until certain conditions of pressure in the annulus and tubing are met. When the valve opens, it permits gas or fluid to pass from the casing annulus into the tubing. Gas lift valves can also be arranged to permit flow from the tubing to the annulus. Figure 1.9, shown on the following page, illustrates the basic operating principles involved. Mechanisms used to apply force to keep the valve closed are: (1) a metal bellows charged with gas under pressure, usually nitrogen; and/or (2) an evacuated metal bellows and a spring in compression. In both cases above, the operating pressure of the valve is adjusted at the surface before the valve is run into the well. The bellows dome may be charged to any desired pressure up to the pressure rating of a particular valve. The compression of the spring can be adjusted. All gas lift valves when installed are intended for one way flow, i.e. check valves should always be included in series with the valve.
The forces that cause gas lift valves to open are (1) gas pressure in the annulus and (2) pressure of the gas and fluid in the tubing. As the discharge of gas and liquid from the tubing continues and well conditions change, the valve will close and shutoff gas flow from the annulus. In the case of a continuous flow system, the one valve at the point of gas injection will remain open, thus, the injection of gas continuous.
Gas lift system design
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.
Fundamentals of gas for gas lift design
Only the gas fundamentals essential to the design and analysis of gas lift installations and operations are discussed in this section. The more important gas calculations related to gas lift wells and systems can be divided into these topics:
Gas pressure at depth
Temperature effect on the confined nitrogen-charged bellows pressure
An alternative solution for calculating nitrogen-charged bellows pressure at 60oF
Volumetric gas throughput of a choke or gas lift valve port
Gas volume stored within a conduit
Factors having an effect on the design of a gas lift system
Most production equipment affects the design of a gas lift system, so it is best to design the gas lift system concurrently with the design of surface facilities. The entire purpose of a gas lift system is to reduce the bottom-hole 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 down-hole 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
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. 2). In Fig. 2, the intersections of the flowing formation-fluid pressure-gradient traverses for a 400-B/D rate and a 600-B/D rate with the flowing total (formation plus injection gas) -pressure-gradient traverses above the point of gas injection to the surface for both rates are shown. If intersections are established for a large number of rates, as are shown in Fig. 3, the points can be connected and will form what is referred to as an equilibrium curve. When injection-gas pressure traverses are drawn from the surface, it is possible to determine the maximum gas lift rate from the well for various surface injection-gas pressures. Referring again to Fig. 3, a 1,200-psig surface injection-gas pressure would gas lift this well at a rate slightly above 600 B/D.
Major factors that have an effect on choosing the most economical injection-gas pressure
Only the basic conditions that must be met to ensure the most efficient injection-gas pressure to maintain operating pressure for a given well have been discussed. A variety of other factors can affect the selection of the most efficient surface injection-gas pressure. These may include:
Pressure/volume/temperature (PVT) properties of the crude
Water cut of the producing stream
Density of the injected gas
Pressure rating of the equipment
Design of the well facility
Calculating the effect of injection-gas pressures on surface production facilities
The selection and design of compression equipment and related facilities must be closely considered in gas lift systems because of the high initial cost of compressor horsepower and the fact that this cost usually represents a major portion of the entire project cost. In most instances, the injection-gas pressure required at the wellhead determines the discharge pressure of the compressor. Higher injection-gas pressures increase the discharge pressure requirement of the compressor, which is translated into a related increase in the compressor horsepower required for a given volume of gas. However, if the gas lift system is designed properly, the related decrease in gas volume requirements will result in an improvement in overall operating efficiency.
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.
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 lifts 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.
1. 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.
2. 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.
3. 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.
4. 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.
5. 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.
6. 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.
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.