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Intermittent-flow gas lift installation design
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.
The following article describes intermittent-flow gas lift design.
- 1 Design methods
- 2 Gas lift valves
- 3 Intermittent pressure-gradient spacing factor
- 4 Selection of surface closing pressure
- 5 Selection of valve port size
- 6 Valves with a large port, constant surface closing pressure, and an intermittent-spacing-factor pressure gradient with depth
- 7 Determination of the gas lift valve depths
- 8 Calculation of the test-rack set opening pressures
- 9 Noteworthy papers in OnePetro
- 10 External links
- 11 Nomenclature
- 12 See also
- 13 Category
There are many published methods and variations in these methods for designing intermittent-flow gas lift installations. These methods can be divided into:
- Production rate based design
- Percentage-load design
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
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 factor
The 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:
- Liquid fallback from injection-gas penetration of the displaced liquid slug while the slug is in the tubing.
- Fluid transfer from the casing annulus to the tubing during unloading operations.
- Fluid production after flowing-bottomhole-pressure drawdown occurs.
- 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. 1, 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. 1 at a later date. One of several important parameters missing from this correlation is depth. The only two correlating parameters in Fig. 1 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
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.
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:
- No decrease in operating injection-gas pressure with depth of lift is required (particularly important in deep wells with low available injection-gas pressure)
- 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 straight line pressure drawdown (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. 2. 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. 3 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. 1.
4. Calculate a surface closing pressure for the gas lift valves, Pvc, with Eq. 2, and calculate the valve closing pressure, Pvcd, at Dd, with Eq. 3. 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. 4.
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. 5 , 6 , or 7.
|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.|
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
A tabulation form for these calculations is illustrated in Table 1. The bellows-charged pressure at the valve unloading temperature, PbvD, is calculated.
For Eq. 10 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. 10 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. 5. The test-rack opening pressure is calculated with Eq. 11 for a tester setting temperature of 60°F using CT(n) from Table 2.
The design given in Example 1 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 1: Determination of valve depths
Using the following information, calculate what is required for installing intermittent gas lift for this well.
- 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. 3.
1. gpfa = Fs = 0.074 psi/ft from Fig. 2 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.
4. Pvc = 0.85 (800) = 680 psig at surface, and PvcD = 783 psig at 6,000 ft. (Eq. 3).
First Gas Lift Valve Depth Calculations
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
8. (PpfD2)min = 299 psig, PvcD2 = 726 psig, and TvuD2 = 120°F at 2,693 ft.
Third Gas Lift Valve Depth Calculations
8. (PpfD3)min = 372 psig, PvcD3 = 743 psig, and TvuD3 = 135°F at 3,680 ft.
Fourth Gas Lift Valve Depth Calculations
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
A tabulation form for these calculations is given in Table 1. The bellows-charged pressure at the valve unloading temperature, PbvD at TvuD, is calculated with Eq. 14. The temperature correction factor, CT, is calculated with Eq. 13 rather than read from Table 2.
- For the first valve at Dv1 using Eq. 13: PbvD1 = PvcD1 = 707 psig at 103°F.
- Calculated CT(1) = 0.914 with Eq. 14.
- With Eq. 15, 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 1 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.
Noteworthy papers in OnePetro
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