Gas Lift Troubleshooting Guide

Gas-Lift Troubleshooting Troubleshoot your well before you call a rig.

The Lift Experts

SM

Contents Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Inlet Problems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Outlet Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Downhole Problems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Tuning in the Well. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Continuous-Flow Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Intermittent-Flow Wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Troubleshooting: Diagnostic Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Well-Sounding Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Tagging Fluid Level. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Two-Pen Recorder Charts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Flowing Pressure Survey. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Procedure for Running a Flowing BHP Test When the Well Is Equipped with Gas-Lift Valves . . . . . . . . . . . . . . . . 7 Continuous-Flow Wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Intermittent-Flow Wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Where to Install a Two-Pen Recorder. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Connect Casing Pen Line. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Connect Tubing Pen Line. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Interpretation of Two-Pen Recorder Charts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Continuous-Flow Wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Intermittent-Flow Wells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Appendix. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 High-Pressure Gas-Lift Surface Schematic. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Low-Pressure Gas-Lift Surface Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Gas-Lift Troubleshooting Checklist. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

© 2007 Weatherford. All rights reserved.

Introduction Gas-lift problems are usually associated with three areas: inlet, outlet, and downhole (Fig. 1).

Outlet problems could be high backpressure because of a flowline choke, a closed or partially closed wing or master valve, or a plugged flowline. Downhole problems could include a cutout valve, restrictions in the tubing string, or sand-covered perforations. Further examples of each problem area are included in this handbook. Often the problem can be found on the surface. If nothing is found on the surface, a check can then be made to determine whether the downhole problems are wellbore problems or equipment problems.

Outlet

Comp.

Wing and Master Valve Gas Header Valve

Casing

Downhole

Examples of inlet problems may be the input choke sized too large or too small, fluctuating line pressure, plugged choke, etc.

Inlet

Flowline choke

Casing Choke

Sep.

Production Header

Gas-Lift Valve

Packer

Perforations

Fig. 1: The Gas-Lift System

Troubleshoot your well before you call a rig. For your convenience, a gas-lift troubleshooting checklist is included in the appendix of this handbook.


1

Introduction Rate (BPD)

GLR

Rate (BPD)

GLR

100

4,000/1

800

600/1

200

2,000/1

1,000

400/1

400

1,000/1

1,200

300/1

600

800/1

1,500

200/1

Inlet Problems Choke sized too large. Check for casing pressure at or above design operating pressure. This can cause reopening of upper-pressure valves and/or excessive gas usage. Approximate gas usages for various flow rates are included in Fig. 2. Choke sized too small. Check for reduced fluid production as a result of insufficient gas injection. This condition can sometimes prevent the well from unloading fully. The design gas:liquid ratio can often give an indication of the choke size to use as a starting point. Low casing pressure. This condition can occur because the choke is sized too small, it is plugged, or it is frozen up. Choke freezing can often be eliminated by continuous injection of methanol in the lift gas. A check of injected-gas volume will separate this case from low casing pressure based on a hole in the tubing or cutout valve. Verify the gauge readings to be sure the problem is real. High casing pressure. This condition can occur because the choke is too large. Check for excessive gas usage from the reopening of upper pressure valves. If high casing pressure is accompanied by low injectiongas volumes, the operating valve may be partially plugged or high tubing pressure may be reducing the differential between the tubing and casing. If this is the case, remove the flowline choke or restriction. High casing pressure accompanying low injection-gas volumes may also be caused by higher-than-anticipated temperatures raising the set pressures of pressure operated valves.

Fig. 2: Typical Continuous-Flow Gas-Lift Operation

Inaccurate gauges. Inaccurate gauges can cause false indications of high or low casing pressures. Always verify the wellhead casing and tubing pressures with a calibrated gauge. Low gas volume. Check to ensure that the gas-lift line valve is fully open and that the casing choke is not too small, frozen, or plugged. Check to see if the available operating pressure is in the range required to open the valves. Be sure that the gas volume is being delivered to the well. Nearby wells, especially intermittent wells, may be robbing the system. Sometimes a higher-than-anticipated producing rate and the resulting higher temperature will cause the valve set pressure to increase, thereby restricting the gas input. Excessive gas volume. This condition can be caused by the casing choke sized too large or excessive casing pressure. Check to see if the casing pressure is above the design pressure, causing upper pressure valves to be opened. A tubing leak or cutout valve can also cause this symptom, but they will generally also cause a low casing pressure. Intermitter problems. Intermitter cycle time should be set to obtain the maximum fluid volume with a minimum number of cycles. Injection duration should then be adjusted to minimize tail gas. Avoid choking an intermitter unless absolutely necessary. For small gas-lift systems in which opening the intermitter drastically reduces the system pressure, it may be possible to reduce pressure fluctuation by placing a small choke in parallel dead

2


Introduction wells as volume chambers. Check to make sure that the intermitter has not stopped, whether it is a manual-wind or battery-operated model. Wells intermitting more than 200 BFPD should be evaluated for constant flow application. Less than one barrel per cycle is probably an indication that the well is being cycled too rapidly.

Outlet Problems Valve restrictions. Check to ensure that all valves at the tree and header are fully open or that an undersized valve is not in the line (1-in. valve in a 2-in. flowline). Other restrictions may result from a smashed or crimped flowline. Check locations where the line crosses a road, which is where this situation is likely to occur. High backpressure. Wellhead pressure is transmitted to the bottom of the hole, reducing the differential into the wellbore and reducing production. Check to ensure that no choke is in the flowline. Even with no choke bean in a choke body, it is usually restricted to less than full ID. Remove the choke body if possible. Excessive 90° turns can cause high backpressure and should be removed when feasible. High backpressure can also result from paraffin or scale buildup in the flowline. Hot-oiling the line will usually remove paraffin; however, removal of scale may or may not be possible, depending on the type. Where high backpressure is caused by long flowlines, it may be possible to reduce the pressure by looping the flowline with an inactive line. The same would apply to cases in which the flowline ID is smaller than the tubing ID. Sometimes a partially opened check valve in the flowline can cause excessive backpressure. Common flowlines can cause excessive backpressure and should be avoided if possible. Check all possibilities, and remove as many restrictions from the system as possible. Separator operating pressure. The separator pressure should be maintained as low as possible for gas-lift wells. Often a well may be flowing to a high or intermediate pressure system when it dies and is placed on gas lift. Make sure the well is switched to the lowest-pressure system available. Sometimes an undersized orifice plate in the meter, at the separator, will cause high backpressure.

Downhole Problems Hole in the tubing. Indicators of a hole in the tubing include abnormally low casing pressure and excess gas usage. A hole in the tubing can be confirmed as follows: 1. Equalize the tubing pressure and casing pressure by closing the wing valve with the lift gas on. 2. After the pressures are equalized, shut off the gas input valve and rapidly bleed-off the casing pressure. 3. If the tubing pressure bleeds as the casing pressure drops, then a hole is evident. 4. The tubing pressure will hold; if not, then a hole is present since both the check valves and gas-lift valves will be in the closed position as the casing pressure bleeds to zero. 5. A packer leak may also cause symptoms similar to a hole in the tubing. Operating pressure valve by surface closing-pressure method. A pressure-operated valve will pass gas until the casing pressure drops to the closing pressure of the valve. As a result, the operating valve can often be estimated by shutting off the input gas and observing the pressure at which the casing will hold. This pressure is the surface closing pressure of the operating valve, or the closing-pressure analysis. The opening-pressure analysis assumes the tubing pressure to be the same as the design value and at single-point injection. These assumptions limit the accuracy of this method because the tubing pressure at each valve is always varying, and multipoint injection may be occurring. This method can be useful when used in combination with other data to bracket the operating valve. Well blowing dry gas. For pressure valves, check to ensure that the casing pressure is not in excess of the design operating pressure, which causes operation from the upper valves. Using the procedure mentioned above, make sure that there are no holes in the tubing. If the upper valves are not being held open by excess casing pressure and no hole exists, then operation is probably from the bottom valve.


3

Introduction Additional verification can be obtained by checking the surface closing pressure as indicated above. When the well is equipped with fluid valves and a pressure valve on the bottom, blowing dry gas is a positive indication of operation from the bottom valve after the possibility of a hole in the tubing has been eliminated. Operation from the bottom valve usually indicates a lack of feed-in. Often it is advisable to tag bottom with wireline tools to determine whether the perforations have been covered by sand. When the well is equipped with a standing valve, check to ensure the standing valve is not stuck in the closed position. Well will not take any input gas. Eliminate the possibility of a frozen input choke or a closed input gas valve by measuring the pressures upstream and downstream of the choke. Also, check for closed valves on the outlet side. If fluid valves were run without a pressure valve on bottom, this condition is probably an indication that all the fluid has been lifted from the tubing and not enough remains to open the valves. Check for feed-in problems. If pressure valves were run, check to see if the well started producing above the design fluid rate because the higher rate may have caused the temperature to increase sufficiently to lock out the valves. If the temperature is the problem, the well will probably produce periodically and then stop. If this is not the problem, check to make sure that the valve set pressures are not too high for the available casing pressure. Well flowing in heads. Several causes can be responsible for this condition. With pressure valves, one cause is port sizes that are too large. This would be the case if a well initially designed for intermittent lift were placed on constant flow because of higher-than-anticipated fluid volumes. In this case, large tubing effects are involved and the well will lift until the fluid gradient is reduced below a value that will keep the valve open. This case can also occur because of temperature interference. For example, if the well started producing at a higher-than-anticipated fluid rate, the temperature could increase, causing the valve set pressures to increase and locking them out. When the temperature cools sufficiently, the valves will open again, thus creating a condition in which the well would flow by heads. With tubing pressure having a high tubing effect on fluid-operated valves, heading can occur as a result of limited feed-in. The valves will not open until the proper fluid load has been obtained, thus creating a condition in which the well will intermit itself whenever adequate feed-in is achieved. Because an injection gas rate that is too high or too low can often cause a well to head, try tuning in the well. Gas-lift operation stalls and will not unload. This typically occurs when the fluid column is heavier than the available lift pressure. Applying injection-gas pressure to the top of the fluid column, usually with a jumper line, will often drive some of the fluid column back into the formation. This reduces the height of the fluid column being lifted and allows unloading with the available lift pressure. This procedure is called “rocking the well.” The check valves prevent this fluid from being displaced back into the casing. For fluid-operated valves, rocking the well in this fashion will often open an upper valve and permit the unloading operation to continue. Sometimes a well can be swabbed to allow unloading to a deeper valve. Ensure that the wellhead backpressure is not excessive or that the fluid used to kill the well for workover was not excessively heavy for the design. Valve hung open. This case can be identified when the casing pressure will bleed below the surface closing pressure of any valve in the hole yet tests to determine the existence of a hole show that one is not present. Try shutting the wing valve and allow the casing pressure to build up as high as possible, and then rapidly open the wing valve. This action will create high differential pressure across the valve seat, removing any trash that may be holding it open. Repeat the process several times if required. In some cases valves can be held open by salt deposition. Pumping several barrels of fresh water into the casing will solve the problem. If the above actions do not help, a flat valve cutout may be the cause. Valve spacing too wide. Try rocking the well when it will not unload. This will sometimes allow working down to lower valves. If a high-pressure gas well is nearby, using the pressure from it may allow unloading. If the problem is severe, the only solution may be to replace the current valve spacing, install a packoff gas-lift valve, or shoot an orifice into the tubing to achieve a new point of operation.

4


Tuning in the Well Continuous-Flow Wells Unloading a well typically requires more gas volume than producing a well. As a result the input gas volume can be reduced once the point of operation has been reached. Excess gas usage can be expensive in terms of compression costs; therefore, it is advantageous, in continuous-flow installations, to achieve maximum fluid production with a minimum amount of input gas. This can be accomplished by starting the well on a relatively small input choke size, at 1/64 increments, until the maximum fluid rate is achieved. Allow the well to stabilize for 24 hours after each change before making another adjustment. If for some reason a flowline choke is being used, increase the size of that choke until maximum fluid is produced before increasing the gas-input choke. If the total gas:liquid ratio (TGLR) exceeds the values shown in Fig. 2, it is possible that too much gas is being used.

Intermittent-Flow Wells In intermittent lift, the cycle frequency is typically controlled by an intermitter. The intermitter opens periodically to lift an accumulated fluid slug to the surface by displacing the tubing with gas. The same amount of gas is required to displace a small slug of fluid to the surface as is required to displace a large slug of fluid (Fig 3.). As a result, optimal performance is obtained when the well produces the greatest amount of fluid with the least number of cycles.

To accomplish this, the initial injection-gas volume and the number of injection cycles must be more than required. A good rule of thumb is to set the cycle based on 2 minutes per 1,000 ft of lift, with the duration of gas injection based on 1/2 minute per 1,000 ft of lift. Reduce the number of cycles per day until the most fluid is obtained with the least number of cycles, and then decrease the injection time until the optimal amount of fluid production is maintained with the least injection time. If one barrel or less is produced per cycle, the cycle time should probably be increased. Be sure the intermitter stays open long enough to fully open the gas-lift valve. This will be indicated by a sharp drop in casing pressure. When a two-pen recorder is used, it will give a saw-tooth shape to the casing pressure line (Fig. 4).

10

Pressure (× 100 psig)

The cyclic operation of the injection gas causes the surface casing pressure to fluctuate between an opening casing pressure (high) and a closing casing pressure (low). The difference in the surface opening and closing pressures during a single cycle is referred to as “spread.” Injection-gas volume per cycle increases as spread value increases.

Fig. 3: Typical Intermittent-Flow Gas Well Operation

Casing

8 6 4

Tubing

2

Fig. 4: Intermittent Gas Lift: Saw-Tooth Shape to Surface Casing Pressure


5

Troubleshooting: Diagnostic Tools Calculations One method of checking gas-lift performance is by calculating the “tubing load required” (TLR) pressures for each valve. This can be accomplished by calculating surface closing pressures or by comparing the valve opening pressures with the opening forces that exist at each valve downhole based on the operating tubing, and casing pressures, temperatures, etc. Although this method may not be as accurate as a flowing pressure survey because of inaccuracies in the data used, it can still be a valuable tool in highgrading the well selection for more expensive diagnostic methods. Weatherford’s VALCAL gas-lift design software is available for this type of diagnostics.

Well-Sounding Devices The fluid level in the annulus of a gas-lift well will sometimes give an indication of the depth of lift. This method involves imploding or exploding a gas charge at the surface and uses the principle of sound waves to determine the depth of the fluid level in the annulus. Acoustic devices are fairly economical compared to flowing-pressure surveys. It should be noted that for wells with packers, it is possible for the well to have lifted down to a deeper valve while unloading, then return to operation at a valve up the hole. The resulting fluid level in the annulus will be below the actual point of operation.

Tagging Fluid Level Tagging the fluid level in a well with wireline tools can sometimes give an estimation of the operating valve subject to several limitations. Fluid feed-in will often raise the fluid level before the wireline tools can be deployed down the hole. In addition, fluid fallback will always occur after the lift gas has been shut off. Both of these factors will cause the observed fluid level to be above the operating valve. Care should be taken to ensure that the input gas valve was closed before closing the wing valve, or the gas pressure will drive the fluid back down the hole and below the point of operation. This is certainly a questionable method.

Two-Pen Recorder Charts To calculate the operating valve, it is necessary to have accurate tubing and casing pressure data. Two-pen recorder charts give a continuous recording of these pressures and can be quite useful if accompanied by an accurate well test. The two-pen recorder charts can be used to optimize surface controls, locate surface problems, and identify downhole problems.

Flowing Pressure Survey In this type of survey, an electronic pressure gauge or bomb is run in the well under flowing conditions. These recording instruments can also measure temperature, and both ambient and “quick-response” models are available. Under flowing conditions, a no-blow tool is run with the tools, which prevents the tools from being blown up the hole. The no-blow tool is equipped with dogs, or slips, that are activated by sudden movements up the hole. The bomb is stopped at each gas-lift valve for a period of time, recording the pressures at each valve. From this information, the exact point of operation can be determined, as well as the actual flowing bottomhole pressure (BHP). This type of survey is the most accurate way to determine the performance of a gas-lift well, provided that an accurate well test is run in conjunction with the survey. The following procedure explains the process in detail.

6


Procedure for Running a Flowing BHP Test When the Well Is Equipped with Gas-Lift Valves Continuous-Flow Wells 1. Install a crown valve on the well, if necessary, and flow the well to the test separator for 24 hours so that a stabilized production rate is known. Test facilities should duplicate normal production facilities as nearly as possible. 2. Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. A gas and fluid test, two-pen recorder chart, and separator chart should be sent in with the pressure traverse. 3. A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a small-diameter bomb. 4. Install a lubricator and pressure-recording bomb. Make the first stop in the lubricator to record wellhead pressure. Run the bomb, making stops 15 ft below each gas-lift valve for 3 minutes. Do not shut in the well while rigging up or recording flowing pressures in tubing. 5. Leave the bomb on bottom for at least 30 minutes, preferably at the same depth that the last static BHP was taken. 6. The casing pressure should be taken with a deadweight tester or “master test” gauge, or a recently calibrated two-pen recorder.

Intermittent-Flow Wells 1. Install a crown valve on the well if necessary, and flow the well to the test separator for 24 hours so that a stabilized production rate is known. Test facilities should duplicate, as nearly as possible, normal production facilities. 2. Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. Test information, two-pen recorder charts, and separator chart should be sent in with the pressure traverse. 3. A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a small-diameter bomb. 4. Install a lubricator and pressure recording bomb. Let the well cycle one time with the bomb, just below the lubricator, to record the wellhead pressure and to ensure that the no-blow tools are working. Rub the bomb, making stops 15 ft below each gas-lift valve. Be sure to record a maximum and minimum pressure at each gas-lift valve. Do not shut in the well while rigging up or recording flowing pressures in the tubing. 5. Leave the bomb on bottom for at least two complete intermitting cycles. 6. High and low tubing and casing pressures should be checked with a deadweight tester or “master test” gauge, or a recently calibrated two-pen recorder.


7

Where to Install a Two-Pen Recorder Connect Casing Pen Line • At the well, not at compressor or gas distribution header. • Downstream of input choke so that the true surface casing pressure is recorded.

Connect Tubing Pen Line • At the well, not the battery, separator, or production header. • Upstream of choke body or other restrictions. Even with no choke bean, a less-than-full opening is found in most chokes.

Fig. 5: Two-Pen Recorder Installed on Wellhead

8


Interpretation of Two-Pen Recorder Charts 10


The two most significant forces acting on any gas-lift valve are the tubing pressure and the casing pressure. The downhole values can be calculated and compared to the operating characteristics of the type of gas-lift valves in service. From this information it is possible to estimate the point of operation. Observing the surface pressures can also give valuable information on the efficiency of the system. The following flow charts illustrate the type of information gained with the use of two-pen recorders.

Continuous-Flow Wells

Casing

8 6 4

Tubing

2

Fig. 6

Trouble

Remedy

Put the continuous-flow wells in a separate gas supply system, apart from the intermittent wells, increasing the system gas pressure, lowering the set pressures of the gas-lift valves in the continuous flow well, or increasing the storage capacity of the supply system to dampen out pressure fluctuations.

10


Fluctuating gas-lift line pressure (Fig. 6). This can be caused by intermittent wells in the same system as continuous-flow wells.

Casing 8 6 4 Tubing

2

Trouble

Fig. 7

Injection gas choke freezing (Fig. 7). Sometimes installing a slightly larger input choke will reduce freezing. Dehydrating the lift gas, injecting methanol upstream of the choke, or using heat exchanges may prove necessary in severe cases.

Trouble

Valve opening periodically on tubing pressure effect (Fig. 8).

10


Remedy

Casing

8 Design Casing Pressure of Operating Valves

6 4

Separator Pressure Tubing

2

Remedy

Trouble

None (Fig. 9). Well unloading.

Remedy

Allow well to unload and get stabilized well test. Make adjustments based on test.

Fig. 8 10


Correct wellbore problems that are restricting feed-in, or redesign gas-lift string for lower producing rate.

Choke Thawed

Choke Freezing

8

Top Valve

Casing

rd

nd

6

2 Valve

3 Valve th

4 Valve

4 2

Tubing

Fig. 9


9

Interpretation of Two-Pen Recorder Charts


10

Trouble Casing

8 6

Remedy

Leave well alone as long as production and gas:liquid ratios are optimal.

4 2

Tubing

Fig. 10


10

Casing

8 6


Casing

6


The wavy tubing pressure line indicates valve throttling. This condition is caused by the casing pressure being too near the valve closing pressure. A slightly larger gas-input choke would eliminate the problem. If a larger input choke causes excessive gas usage, it is probably an indication of oversized ports in the gas-lift valve.

Trouble

4

Tubing

Fig. 12

Casing

8 6 Tubing

2

Fig. 13

10

Remove choke, excessive 90° turns, paraffin, scale, or other restrictions to flow from the flowline. Looping or replacing the existing line with a larger line may be indicated in severe cases.

Remedy

8

4

Remedy

Valve throttling (Fig. 12).

Fig. 11

10

Excessive backpressure (Fig. 11).

Trouble

2

2

Trouble

Tubing

4

10

None (Fig. 10). Note the uniform tubing, casing pressures, and relatively low backpressure. Available horizontal flow curves will indicate whether backpressure is above normal.


Holes and/or parted tubing (Fig. 13). Well produces continuously until hole or parted tubing is uncovered, causing the casing pressure to be dropped rapidly. Production is stopped until the casing pressure builds up.

Remedy

Pull well, and replace faulty tubing. It may be possible to locate the hole and isolate it by installing a pack-off.


Trouble

None (Fig. 14). Good operation. Rapid buildup and drawdown of casing pressure with a constant pressure between cycles indicates good valve operation. Thin, sharp kicks on the tubing-pressure pen indicate good slug recovery.

Remedy

10


Intermittent-Flow Wells

8 6 4

Remedy

Trash may be preventing valve closure. Attempt to clear trash from valve seat, using the procedure described in the “Downhole Problems” section of this booklet. If that fails, it will be necessary to pull the valves when the problem causes significant loss of production or excess gas usage.

Fig. 14 10


A leaking valve, indicated by casing pressure drawdown between cycles (Fig. 15).

Tubing

2

Good operation. Adjust the number of cycles and test well to confirm optimum production.

Trouble

Casing

Casing

8 6 4 2

Tubing

Fig. 15

A leak in the tubing string, indicated by a relatively flat tubing line and excessive gas (Fig. 16). Lack of tubing kicks indicates no valve action at all.

Remedy

Pull and replace defective tubing.

Trouble

10


Trouble

8 6 4 2

Closed valve throttling, indicated by a slow casing-pressure drawdown (Fig. 17). Broad tubing-pressure kicks usually indicate excessive gas usage and reduced fluid recovery. This condition is usually caused by running valves with low dome volumes or heavy strings. Try to select valves, such as the Weatherford pilotoperated RPV series, that allow rapid opening and closing.

Tubing

Fig. 16 10


Remedy

Casing

Casing

8 6 4

Tubing

2

Fig. 17


11



10

Casing

8 6 4

Tubing

2

Fig. 18 10


Casing 8

Trouble

Improper intermitter setting (Fig. 18). The injection gas shuts off before the valve opening pressure is reached. As a result, two intermitter cycles are required to open the valve. Tubing kicks show good fluid recovery.

Remedy

Adjust intermitter cycle and duration of injection until maximum fluid with minimum cycles is achieved.

Trouble

Leaking intermitter, indicated by casing pressure build-up between cycles (Fig. 19). Tubing kicks show good fluid recovery.

Remedy

Replace seat in intermitter.

6 4

Tubing

Trouble

None (Fig. 20). Well intermitting with casing choke.

2

Remedy Fig. 19


10

Casing

6 Tubing

2

Fig. 20


10

Casing

8 6 4

Tubing

2

Fig. 21

12

Trouble

Intermitter cycle not fast enough; well loading up (Fig. 21). Dual-tubing kicks and casing pressure drops indicate two valves at work.

8

4

Leave the well alone if production and gas usage are optimal.


Remedy

Use faster injection cycle.

Appendix High-Pressure Gas-Lift Surface Schematic Backpressure valve

Sales meter

Backpressure valve 140 psi To flare pit

Purchase meter

Regulator set to hold 60 psi on compressor

PI

130-psi backpressure valve

To gas line

High-pressure gas line

Backpressure valve set to hold 1,000 psi

Flow line

Pressure recovery valve hold 75 psi on compressor

130-psi separator

Suction line

Nonadjustable choke

Fluid to heater Recycle valve set at 55 psi

PI

Bypass valve Bull plug Discharge line Compressor package

Definition: High-pressure system = Sales line connected to discharge side of compressor rather than to suction side of compressor.

Union

PI

Wing valve

Adjustable choke

Injection meter Ball valve

Check valve

Valve master

Casing gate valve

Wellhead 150 psi

Note: Client is responsible for final layout.


13

Appendix Low-Pressure Gas-Lift Surface Schematic To flare pit Backpressure valve set to hold 70 psi on compressor

Purchase meter

PI

Backpressure valve

To gas line

Gas line 100 psi

Backpressure valve 140 psi

Backpressure valve set to hold 75 psi

Sales meter

Flow line

Pressure recovery valve hold 70 psi on compressor

130-psi separator

Suction line

Nonadjustable choke

Fluid to heater

PI

Bypass valve Bull plug Discharge line Compressor package

Definition: Low-pressure system = Sales line connected to suction side of compressor rather than to discharge side of compressor.

14


Union

PI

Wing valve

Adjustable choke

Inject meter run Ball valve

Check valve

Valve master

Casing gate valve

Wellhead 150 psi

Note: Client is responsible for final layout.

Gas-Lift Troubleshooting Checklist Well: Field: Date: I.

________________________________________________________________________________________________ ________________________________________________________________________________________________ ________________________________________________________________________________________________

Inlet A. Problem  Popping upper valves  Excessive gas usage 1.  Choke sized too large  Cannot unload  Insufficient gas 2.  Choke size too small  Choke frozen up 3.  Choke plugged 4.  Bad pressure gauges: causing insufficient or excessive casing pressure  Intermitter cycle or injection time incorrect 5.  Intermitter stopped 6.  Intermitter on constant-flow well 7.  Intermitter malfunction, other 8.  Gas-lift supply gas shut off 9.  Line pressure down. Why? _____________________________________________________________________ 10.  Fluctuating line pressure. Why? _________________________________________________________________ 11.  Other problems/remarks: ______________________________________________________________________ ____________________________________________________________________________________________ B. Corrective action: __________________________________________________________________________________ ________________________________________________________________________________________________ ________________________________________________________________________________________________

II.

Outlet A. Problem 1. Master valve or wing valve closed 2. High backpressure as a result of:  Flowline choke  Flowline choke body  Excessive 90° turns  Long flowline  Flowline plugged or partially plugged  Excessive canal crossings  Flowline ID smaller than tubing string  Restricted ID valve 3.  Valve shut at header 4.  Check valve at header leaking causing backpressure 5.  Separator operating pressure too high 6.  Separator orifice plate sized too small 7.  Other problems/remarks: ______________________________________________________________________ ____________________________________________________________________________________________ B. Corrective action: __________________________________________________________________________________ ________________________________________________________________________________________________ ________________________________________________________________________________________________

III. Downhole A. Problem 1.  No feed-in; fluid standing at or below bottom valve 2.  Perfs covered 3.  Fluids too light to load valves 4.  Restrictions in tubing string 5.  Spacing too wide to allow unloading 6.  On bottom valve: not valved deep enough 7.  Cutout valve or tubing leak  Valve plugged 8.  Flat valve  too low  too high 9.  Valve pressures set: 10.  Salt deposits or trash in valves 11.  Leaking packoff gas-lift valve 12.  Excessive backpressure popping valves up the hole 13.  Working as deep as possible, but:  Backpressure preventing higher rate  Low casing pressure preventing higher rate 14.  Dual gas lift:  One side robbing gas  Temperature affecting other string 7.  Other problems/remarks: ______________________________________________________________________ ____________________________________________________________________________________________ B. Corrective action: __________________________________________________________________________________ ________________________________________________________________________________________________ ________________________________________________________________________________________________


15

515 Post Oak Blvd., Suite 600 Houston, Texas 77027 USA Tel: 713-693-4000 www.weatherford.com

Weatherford products and services are subject to the Company’s standard terms and conditions, available on request or at www.weatherford.com. For more information contact an authorized Weatherford representative. Unless noted otherwise, trademarks and service marks herein are the property of Weatherford. Specifications are subject to change without notice. Weatherford sells its products and services in accordance with the terms and conditions set forth in the applicable contract between Weatherford and the client. © 2007 Weatherford. All rights reserved.

Handbook 4615.00

Gas Lift Troubleshooting Guide

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