Gas Lift TS-A4 Troubleshooting Weather Ford)

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Contents

© 2007 Weatherford. All rights reserved.

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Inlet 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Tagging 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


Where to Install a Two-Pen Recorder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Connect Casing Pen Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Connect Tubing Pen Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Interpretation of Two-Pen Recorder Charts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Continuous-Flow Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9


Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

High-Pressure Gas-Lift Surface Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Low-Pressure Gas-Lift Surface Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Gas-Lift Troubleshooting Checklist . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15



Sep.

ProductionHeader

Flowlinechoke

Wing andMaster Valve

Inlet Outlet

D o w n

h o

l e

Gas Header

ValveCasingChoke

Casing

Packer

Gas-Lift Valve

Perforations

C o m p

.

1© 2007 Weatherford. All rights reserved.

Introduction

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

Examples of inlet problems may be the input choke sized toolarge or too small, uctuating linepressure, plugged choke, etc.

Outlet problems could behigh backpressure because of a owline choke, a closed or partially closed wing or master valve, or a plugged owline.

Downhole problems couldinclude a cutout valve, restrictionsin the tubing string, or sand-covered perforations.

Further examples of eachproblem area are included in thishandbook. Often the problemcan be found on the surface. If nothing is found on the surface,

a check can then be made todetermine whether the downholeproblems are wellbore problemsor equipment problems.

Fig. 1: The Gas-Lift System

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



2 © 2007 Weatherford. All rights reserved.

Introduction

Fig. 2: Typical Continuous-FlowGas-Lift Operation

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 ProblemsChoke sized too large. Check for casing pressure at or above designoperating pressure. This can cause reopening of upper-pressure valvesand/or excessive gas usage. Approximate gas usages for various owrates are included in Fig. 2 .

Choke sized too small. Check for reduced uid production as a resultof insuf cient gas injection. This condition can sometimes prevent thewell from unloading fully. The design gas:liquid ratio can often give anindication of the choke size to use as a starting point.

Low casing pressure. This condition can occur because the choke issized 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 checkof injected-gas volume will separate this case from low casing pressurebased on a hole in the tubing or cutout valve. Verify the gauge readings tobe sure the problem is real.

High casing pressure. This condition can occur because the choke istoo large. Check for excessive gas usage from the reopening of upper pressure valves. If high casing pressure is accompanied by low injection-gas volumes, the operating valve may be partially plugged or high tubingpressure may be reducing the differential between the tubing and casing.If this is the case, remove the owline choke or restriction. High casingpressure accompanying low injection-gas volumes may also be causedby higher-than-anticipated temperatures raising the set pressures of

pressure operated valves.Inaccurate gauges. Inaccurate gauges can cause false indications of high or low casing pressures. Always verify the wellhead casing andtubing pressures with a calibrated gauge.

Low gas volume. Check to ensure that the gas-lift line valve is fully openand that the casing choke is not too small, frozen, or plugged. Check tosee if the available operating pressure is in the range required to openthe 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 resultinghigher temperature will cause the valve set pressure to increase, therebyrestricting the gas input.

Excessive gas volume. This condition can be caused by the casingchoke sized too large or excessive casing pressure. Check to see if thecasing pressure is above the design pressure, causing upper pressurevalves to be opened. A tubing leak or cutout valve can also cause thissymptom, but they will generally also cause a low casing pressure.

Intermitter problems. Intermitter cycle time should be set to obtainthe maximum uid volume with a minimum number of cycles. Injectionduration should then be adjusted to minimize tail gas. Avoid choking anintermitter unless absolutely necessary. For small gas-lift systems inwhich opening the intermitter drastically reduces the system pressure, itmay be possible to reduce pressure uctuation by placing a small choke

in parallel dead wells as volume chambers. Check to make sure thatthe intermitter has not stopped, whether it is a manual-wind or battery-operated model. Wells intermitting more than 200 BFPD should be




Introduction

evaluated for constant ow application. Less than one barrel per cycle is probably an indication that the well isbeing cycled too rapidly.

Outlet ProblemsValve restrictions. Check to ensure that all valves at the tree and header are fully open or that an undersizedvalve is not in the line (1-in. valve in a 2-in. owline). Other restrictions may result from a smashed or crimped

owline. 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 thewellbore and reducing production. Check to ensure that no choke is in the owline. Even with no choke bean ina choke body, it is usually restricted to less than full ID. Remove the choke body if possible. Excessive 90° turnscan cause high backpressure and should be removed when feasible.

High backpressure can also result from paraf n or scale buildup in the owline. Hot-oiling the line will usuallyremove paraf n; however, removal of scale may or may not be possible, depending on the type. Where highbackpressure is caused by long owlines, it may be possible to reduce the pressure by looping the owline withan inactive line. The same would apply to cases in which the owline ID is smaller than the tubing ID. Sometimesa partially opened check valve in the owline can cause excessive backpressure. Common owlines cancause excessive backpressure and should be avoided if possible. Check all possibilities, and remove as manyrestrictions from the system as possible.

Separator operating pressure. The separator pressure should be maintained as low as possible for gas-liftwells. Often a well may be owing to a high or intermediate pressure system when it dies and is placed on gaslift. Make sure the well is switched to the lowest-pressure system available. Sometimes an undersized ori ceplate in the meter, at the separator, will cause high backpressure.

Downhole ProblemsHole in the tubing. Indicators of a hole in the tubing include abnormally low casing pressure and excess gasusage. A hole in the tubing can be con rmed as follows:

Equalize the tubing pressure and casing pressure by closing the wing valve with the lift gas on.1.

After the pressures are equalized, shut off the gas input valve and rapidly bleed-off the casing pressure.2.

If the tubing pressure bleeds as the casing pressure drops, then a hole is evident.3.

The tubing pressure will hold; if not, then a hole is present since both the check valves and gas-lift valves4.will be in the closed position as the casing pressure bleeds to zero.

A packer leak may also cause symptoms similar to a hole in the tubing.5.

Operating pressure valve by surface closing-pressure method. A pressure-operated valve will pass gasuntil the casing pressure drops to the closing pressure of the valve. As a result, the operating valve can often beestimated by shutting off the input gas and observing the pressure at which the casing will hold. This pressureis the surface closing pressure of the operating valve, or the closing-pressure analysis. The opening-pressureanalysis assumes the tubing pressure to be the same as the design value and at single-point injection. Theseassumptions limit the accuracy of this method because the tubing pressure at each valve is always varying, andmultipoint injection may be occurring. This method can be useful when used in combination with other data tobracket the operating valve.

Well blowing dry gas. For pressure valves, check to ensure that the casing pressure is not in excess of thedesign operating pressure, which causes operation from the upper valves. Using the procedure mentionedabove, make sure that there are no holes in the tubing. If the upper valves are not being held open by excesscasing pressure and no hole exists, then operation is probably from the bottom valve.




Introduction

Additional veri cation can be obtained by checking the surface closing pressure as indicated above. When thewell is equipped with uid valves and a pressure valve on the bottom, blowing dry gas is a positive indicationof operation from the bottom valve after the possibility of a hole in the tubing has been eliminated. Operationfrom the bottom valve usually indicates a lack of feed-in. Often it is advisable to tag bottom with wireline toolsto determine whether the perforations have been covered by sand. When the well is equipped with a standingvalve, 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 valveby measuring the pressures upstream and downstream of the choke. Also, check for closed valves on the outletside. If uid valves were run without a pressure valve on bottom, this condition is probably an indication that allthe uid 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 uid rate because thehigher rate may have caused the temperature to increase suf ciently 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 makesure that the valve set pressures are not too high for the available casing pressure.

Well fowing in heads. Several causes can be responsible for this condition. With pressure valves, one causeis port sizes that are too large. This would be the case if a well initially designed for intermittent lift were placedon constant ow because of higher-than-anticipated uid volumes. In this case, large tubing effects are involvedand the well will lift until the uid gradient is reduced below a value that will keep the valve open. This case canalso occur because of temperature interference.

For example, if the well started producing at a higher-than-anticipated uid rate, the temperature could increase,causing the valve set pressures to increase and locking them out. When the temperature cools suf ciently, thevalves will open again, thus creating a condition in which the well would ow by heads. With tubing pressurehaving a high tubing effect on uid-operated valves, heading can occur as a result of limited feed-in. The valveswill not open until the proper uid load has been obtained, thus creating a condition in which the well will intermititself whenever adequate feed-in is achieved. Because an injection gas rate that is too high or too low can oftencause a well to head, try tuning in the well.

Gas-lift operation stalls and will not unload. This typically occurs when the uid column is heavier than theavailable lift pressure. Applying injection-gas pressure to the top of the uid column, usually with a jumper line,will often drive some of the uid column back into the formation. This reduces the height of the uid columnbeing lifted and allows unloading with the available lift pressure. This procedure is called “rocking the well.” Thecheck valves prevent this uid from being displaced back into the casing. For uid-operated valves, rocking thewell in this fashion will often open an upper valve and permit the unloading operation to continue. Sometimesa well can be swabbed to allow unloading to a deeper valve. Ensure that the wellhead backpressure is notexcessive or that the uid used to kill the well for workover was not excessively heavy for the design.

Valve hung open. This case can be identi ed 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. Tryshutting the wing valve and allow the casing pressure to build up as high as possible, and then rapidly open thewing valve. This action will create high differential pressure across the valve seat, removing any trash that maybe holding it open. Repeat the process several times if required. In some cases valves can be held open by saltdeposition. Pumping several barrels of fresh water into the casing will solve the problem. If the above actions donot help, a at 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 tolower valves. If a high-pressure gas well is nearby, using the pressure from it may allow unloading. If the problemis severe, the only solution may be to replace the current valve spacing, install a packoff gas-lift valve, or shootan ori ce into the tubing to achieve a new point of operation.




Tuning in the Well

Continuous-Flow WellsUnloading a well typically requires more gas volume than producing awell. As a result the input gas volume can be reduced once the point of operation has been reached. Excess gas usage can be expensive interms of compression costs; therefore, it is advantageous, in continuous-

ow installations, to achieve maximum uid production with a minimumamount of input gas. This can be accomplished by starting the well on arelatively small input choke size, at 1/64 increments, until the maximum

uid rate is achieved.

Allow the well to stabilize for 24 hours after each change before makinganother adjustment. If for some reason a owline choke is being used,increase the size of that choke until maximum uid is produced beforeincreasing 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 isbeing used.

Intermittent-Flow WellsIn intermittent lift, the cycle frequency is typically controlled by anintermitter. The intermitter opens periodically to lift an accumulated uidslug to the surface by displacing the tubing with gas. The same amountof gas is required to displace a small slug of uid to the surface as isrequired to displace a large slug of uid ( Fig 3. ). As a result, optimalperformance is obtained when the well produces the greatest amount of

uid with the least number of cycles.The cyclic operation of the injection gas causes the surface casingpressure to uctuate between an opening casing pressure (high) anda closing casing pressure (low). The difference in the surface openingand closing pressures during a single cycle is referred to as “spread.”Injection-gas volume per cycle increases as spread value increases.

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 toset 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 uid is obtained with the least number of cycles, and then decrease the injection time until the optimal amount of

uid 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-liftvalve. This will be indicated by a sharp drop in casing pressure. Whena two-pen recorder is used, it will give a saw-tooth shape to the casingpressure line (Fig. 4) .

Fig. 3: Typical Intermittent-FlowGas Well Operation

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

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4

6

8

P r e s s u r e

( × 1 0 0 p s

i g )

10Casing

Tubing




Troubleshooting: Diagnostic Tools

CalculationsOne 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 valveopening 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 owing pressuresurvey because of inaccuracies in the data used, it can still be a valuable tool in highgrading the well selectionfor more expensive diagnostic methods. Weatherford’s VALCAL gas-lift design software is available for this typeof diagnostics.

Well-Sounding DevicesThe uid 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 determinethe depth of the uid level in the annulus. Acoustic devices are fairly economical compared to owing-pressuresurveys. 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 uid level in the annulus willbe below the actual point of operation.

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

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

Flowing Pressure SurveyIn this type of survey, an electronic pressure gauge or bomb is run in the well under owing conditions. Theserecording instruments can also measure temperature, and both ambient and “quick-response” models areavailable.Under owing conditions, a no-blow tool is run with the tools, which prevents the tools from beingblown up the hole. The no-blow tool is equipped with dogs, or slips, that are activated by sudden movements upthe 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 owing bottomholepressure (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 theprocess in detail.




Procedure for Running a Flowing BHP Test When the Well IsEquipped with Gas-Lift Valves

Continuous-Flow WellsInstall a crown valve on the well, if necessary, and ow the well to the test separator for 24 hours so that a1.stabilized production rate is known. Test facilities should duplicate normal production facilities as nearly aspossible.

Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. A gas and uid2.test, two-pen recorder chart, and separator chart should be sent in with the pressure traverse.

A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a small-diameter bomb.3.

Install a lubricator and pressure-recording bomb. Make the rst stop in the lubricator to record wellhead4.pressure. Run the bomb, making stops 15 ft below each gas-lift valve for 3 minutes. Do not shut in the wellwhile rigging up or recording owing pressures in tubing.

Leave the bomb on bottom for at least 30 minutes, preferably at the same depth that the last static BHP5. was taken.

The casing pressure should be taken with a deadweight tester or “master test” gauge, or a recently6.calibrated two-pen recorder.

Intermittent-Flow WellsInstall a crown valve on the well if necessary, and ow the well to the test separator for 24 hours so that a1.stabilized production rate is known. Test facilities should duplicate, as nearly as possible, normal productionfacilities.

Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. Test2.information, two-pen recorder charts, and separator chart should be sent in with the pressure traverse.

A pressure bomb must be equipped with one, or preferably two, no-blow tools. Use a small-diameter bomb.3.Install a lubricator and pressure recording bomb. Let the well cycle one time with the bomb, just below the4.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 eachgas-lift valve. Do not shut in the well while rigging up or recording owing pressures in the tubing.

Leave the bomb on bottom for at least two complete intermitting cycles.5.

High and low tubing and casing pressures should be checked with a deadweight tester or “master test”6.gauge, or a recently calibrated two-pen recorder.




Where to Install a Two-Pen Recorder

Connect Casing Pen LineAt 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 LineAt 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 Installedon Wellhead



2

4

6

8

10

Casing

Tubing P r e s s u r e

( × 1 0 0 p s

i g )

2

4

6

8

10

Casing


( × 1 0 0 p s

i g )

ChokeFreezing

ChokeThawed

2

4

6

8

10Casing


( × 1 0 0 p s

i g )

Design Casing Pressureof Operating Valves

Separator Pressure

2

4

6

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10Casing


( × 1 0 0 p s

i g ) Top

Valve

2 Valvend3 Valverd

4 Valveth


Interpretation of Two-Pen Recorder Charts

The two most signi cant forces acting on any gas-lift valve are thetubing pressure and the casing pressure. The downhole values can becalculated and compared to the operating characteristics of the type of gas-lift valves in service. From this information it is possible to estimatethe point of operation. Observing the surface pressures can also givevaluable information on the ef ciency of the system. The following owcharts illustrate the type of information gained with the use of two-penrecorders.

Continuous-Flow Wells

TroubleFluctuating gas-lift line pressure (Fig. 6). This can be caused byintermittent wells in the same system as continuous- ow wells.

RemedyPut the continuous- ow wells in a separate gas supply system, apartfrom the intermittent wells, increasing the system gas pressure, loweringthe set pressures of the gas-lift valves in the continuous ow well, or increasing the storage capacity of the supply system to dampen outpressure uctuations.

Trouble

Injection gas choke freezing (Fig. 7) .

RemedySometimes 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.

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

Remedy

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

TroubleNone (Fig. 9). Well unloading.

RemedyAllow well to unload and get stabilized well test. Make adjustments basedon test.

Fig. 6

Fig. 7

Fig. 8

Fig. 9



2

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10

Casing


( × 1 0 0 p s

i g )

2

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10Casing

Tubing

P r e s s u r e

( × 1 0 0 p s

i g )

2

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10Casing

Tubing

P r e s s u r e

( × 1 0 0 p s

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2

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( × 1 0 0 p s

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TroubleNone (Fig. 10) . Note the uniform tubing, casing pressures, and relativelylow backpressure. Available horizontal ow curves will indicate whether backpressure is above normal.

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

TroubleExcessive backpressure (Fig. 11).

RemedyRemove choke, excessive 90° turns, paraf n, scale, or other restrictionsto ow from the owline. Looping or replacing the existing line with alarger line may be indicated in severe cases.

TroubleValve throttling (Fig. 12).

RemedyThe wavy tubing pressure line indicates valve throttling. This condition iscaused 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.

TroubleHoles and/or parted tubing (Fig. 13). Well produces continuously untilhole or parted tubing is uncovered, causing the casing pressure to bedropped rapidly. Production is stopped until the casing pressure builds up.

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

Fig. 10

Fig. 11

Fig. 12

Fig. 13



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10 Casing

Tubing

P r e s s u r e

( × 1 0 0 p s

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10 Casing


( × 1 0 0 p s

i g )

2

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10 Casing


( × 1 0 0 p s

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10 Casing

Tubing

P r e s s u r e

( × 1 0 0 p s

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Intermittent-Flow Wells

TroubleNone (Fig. 14) . Good operation. Rapid buildup and drawdown of casingpressure with a constant pressure between cycles indicates good valveoperation. Thin, sharp kicks on the tubing-pressure pen indicate goodslug recovery.

RemedyGood operation. Adjust the number of cycles and test well to con rmoptimum production.

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

RemedyTrash may be preventing valve closure. Attempt to clear trash from valveseat, using the procedure described in the “Downhole Problems” sectionof this booklet. If that fails, it will be necessary to pull the valves when theproblem causes signi cant loss of production or excess gas usage.

TroubleA leak in the tubing string, indicated by a relatively at tubing line andexcessive gas (Fig. 16). Lack of tubing kicks indicates no valve action atall.

RemedyPull and replace defective tubing.

TroubleClosed valve throttling, indicated by a slow casing-pressure drawdown(Fig. 17). Broad tubing-pressure kicks usually indicate excessive gasusage and reduced uid recovery.

RemedyThis condition is usually caused by running valves with low domevolumes or heavy strings. Try to select valves, such as the Weatherfordpilot-operated RPV series, that allow rapid opening and closing.

Fig. 14

Fig. 15

Fig. 16

Fig. 17



2

4

6

8

10 Casing

Tubing

P r e s s u r e

( × 1 0 0 p s

i g )

2

4

6

8

10

Casing

Tubing

P r e s s u r e

( × 1 0 0 p s

i g )

2

4

6

8

10

Casing

Tubing

P r e s s u r e

( × 1 0 0 p s

i g )

2

4

6

8

10

Casing

Tubing

P r e s s u r e

( × 1 0 0 p s

i g )



TroubleImproper intermitter setting (Fig. 18). The injection gas shuts off beforethe valve opening pressure is reached. As a result, two intermitter cyclesare required to open the valve. Tubing kicks show good uid recovery.

RemedyAdjust intermitter cycle and duration of injection until maximum uid withminimum cycles is achieved.

TroubleLeaking intermitter, indicated by casing pressure build-up between cycles

(Fig. 19). Tubing kicks show good uid recovery.

RemedyReplace seat in intermitter.

TroubleNone (Fig. 20). Well intermitting with casing choke.

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

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

RemedyUse faster injection cycle.

Fig. 18

Fig. 19

Fig. 20

Fig. 21



Wingvalve

Wellhead150 psi

Casinggatevalve

Checkvalve

AdjustablechokeInjection

meter

Bull plug

Recycle valveset at 55 psi

Union Ballvalve

Valvemaster

Fluid to heater

130-psi separator

130-psibackpressurevalve

Flow line

Non-adjustable

choke

Bypassvalve

Suction line

High-pressuregas line

Pressure recovery valvehold 75 psi on compressor

Regulator set to hold 60 psion compressor

Backpressurevalve

Backpressure valveset to hold 1,000 psi Backpressure valve

140 psi

To flare pit

Compressor package

Discharge

line

PI

T o

g a s

l i n e

Salesmeter

Purchasemeter

PI

PI

Definition: High-pressure system = Sales line connected to dischargeside of compressor rather than to suction side of compressor. Note: Client is responsible for final layout.


Appendix

High-Pressure Gas-Lift Surface Schematic



Definition: Low-pressure system = Sales line connected to suction sideof compressor rather than to discharge side of compressor. Note: Client is responsible for final layout.

Wingvalve

Wellhead150 psi

Casinggatevalve

Checkvalve

AdjustablechokeInject meter

run

Bull plug

Union Ballvalve

Valvemaster

Fluid to heater

130-psi separator

Backpressurevalve

Flow line

Non-adjustablechoke

Bypassvalve

Suction line

Gas line100 psi

Pressure recovery valvehold 70 psi on compressor

Backpressure valveset to hold 70 psion compressor

Backpressure valveset to hold 75 psi

Backpressure valve140 psi

To flare pit

Compressor package

Discharge

line

PI

T o

g a s

l i n e

Salesmeter

Purchasemeter

PI

PI


Appendix

Low-Pressure Gas-Lift Surface Schematic



Well: ________________________________________________________________________________________________ Field: ________________________________________________________________________________________________ Date: ________________________________________________________________________________________________

I. Inlet A. Problem

1. Choke sized too large Popping upper valves Excessive gas usage2. Choke size too small Cannot unload Insufficient gas3. Choke plugged Choke frozen up4. Bad pressure gauges: causing insufficient or excessive casing pressure5. Intermitter stopped Intermitter cycle or injection time incorrect6. Intermitter on constant-flow well7. 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 closed2. High backpressure as a result of:

Flowline choke Flowline choke body Excessive 90° turnsLong flowline Flowline plugged or partially pluggedExcessive canal crossings Flowline ID smaller than tubing string

3. Valve shut at header Restricted ID valve4. Check valve at header leaking causing backpressure5. Separator operating pressure too high6. Separator orifice plate sized too small

III. Downhole A. Problem

1. No feed-in; fluid standing at or below bottom valve2. Perfs covered3. Fluids too light to load valves4. Restrictions in tubing string5. Spacing too wide to allow unloading6. On bottom valve: not valved deep enough

7. Cutout valve or tubing leak8. Flat valve Valve plugged9. Valve pressures set: too low too high10. Salt deposits or trash in valves11. Leaking packoff gas-lift valve12. Excessive backpressure popping valves up the hole13. Working as deep as possible, but:

Backpressure preventing higher rateLow casing pressure preventing higher rate

14. Dual gas lift:One side robbing gasTemperature affecting other string

7. Other problems/remarks: ______________________________________________________________________ ____________________________________________________________________________________________


7. Other problems/remarks: ______________________________________________________________________ ____________________________________________________________________________________________


Gas-Lift Troubleshooting Checklist








515 Post Oak Blvd., Suite 600Houston, Texas 77027 USA

l 3 693 000

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. Speci cations are subject to change without notice.Weatherford sells its products and services in accordance with the terms and conditions set forth in the applicable contractbetween Weatherford and the client.

Documents

Gas Lift TS-A4 Troubleshooting Weather Ford)