Gas Lift Troubleshooting

7/21/2019 Gas Lift Troubleshooting

http://slidepdf.com/reader/full/gas-lift-troubleshooting 1/20

The Lift ExpertsSM

Troubleshoot your well

before you call a rig.

Gas-LiftTroubleshooting



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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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


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


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 too

large or too small, uctuating line

pressure, plugged choke, etc.

Outlet problems could be high

backpressure because of a owline

choke, a closed or partially closed

wing or master valve, or a plugged

owline.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.

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.




Introduction

Fig. 2: Typical Continuous-Flow

Gas-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 design

operating pressure. This can cause reopening of upper-pressure valves

and/or excessive gas usage. Approximate gas usages for various ow rates

are included in Fig. 2.

Choke sized too small. Check for reduced uid production as a result of

insufcient 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 basedon 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 injection-

gas 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 owline 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.

Inaccurate gauges. Inaccurate gauges can cause false indications ofhigh 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 casingpressure 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 uid 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 uctuation by placing a small choke in parallel dead




Introduction

wells as volume chambers. Check to make sure that the intermitter has not stopped, whether it is a manual-wind orbattery-operated model. Wells intermitting more than 200 BFPD should be evaluated for constant ow application.

Less than one barrel per cycle is probably an indication that the well is being cycled too rapidly.

Outlet ProblemsValve 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. 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 the

wellbore and reducing production. Check to ensure that no choke is in the owline. 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 parafn or scale buildup in the owline. Hot-oiling the line will usually removeparafn; however, removal of scale may or may not be possible, depending on the type. Where high backpressure

is caused by long owlines, it may be possible to reduce the pressure by looping the owline with an inactive

line. The same would apply to cases in which the owline ID is smaller than the tubing ID. Sometimes a partially

opened check valve in the owline can cause excessive backpressure. Common owlines 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 owing 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 orice plate 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 gas usage.

A hole in the tubing can be conrmed 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 valves will4.

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 gas until the

casing pressure drops to the closing pressure of the valve. As a result, the operating valve can often be estimatedby 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.




Introduction

Additional verication can be obtained by checking the surface closing pressure as indicated above. When the wellis equipped with uid 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 uid valves were run without a pressure valve on bottom, this condition is probably an indication that all the 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 the higher rate may

have caused the temperature to increase sufciently 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 fowing 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 ow because of higher-than-anticipated uid volumes. In this case, large tubing effects are involved and

the well will lift until the uid 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 uid rate, the temperature could increase,

causing the valve set pressures to increase and locking them out. When the temperature cools sufciently, the

valves will open again, thus creating a condition in which the well would ow by heads. With tubing pressure having

a high tubing effect on uid-operated valves, heading can occur as a result of limited feed-in. The valves will not

open until the proper uid 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 uid column is heavier than the

available 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 column being lifted

and allows unloading with the available lift pressure. This procedure is called “rocking the well.” The check valves

prevent this uid from being displaced back into the casing. For uid-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 uid used to

kill the well for workover was not excessively heavy for the design.

Valve hung open. This case can be identied 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 holdingit 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 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 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

orice 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 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-ow

installations, to achieve maximum uid 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 uid rate is

achieved.

Allow the well to stabilize for 24 hours after each change before making

another adjustment. If for some reason a owline choke is being used,

increase the size of that choke until maximum uid is produced before

increasing the gas-input choke. If the total gas:liquid ratio (TGLR) exceedsthe values shown in Fig. 2, it is possible that too much gas is being used.

Intermittent-Flow WellsIn intermittent lift, the cycle frequency is typically controlled by an intermitter.

The intermitter opens periodically to lift an accumulated uid slug to the

surface by displacing the tubing with gas. The same amount of gas is

required to displace a small slug of uid to the surface as is required to

displace a large slug of uid (Fig 3.). As a result, optimal performance 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 casing pressure

to uctuate between an opening casing pressure (high) and a closing casingpressure (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.

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 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-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).

Fig. 3: Typical Intermittent-Flow

Gas Well Operation

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

2

4

6

8

P r e s s u r e

( ×

1 0 0

p s

i g )

10 Casing

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 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 owing 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 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 determine the

depth of the uid level in the annulus. Acoustic devices are fairly economical compared to owing-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 whileunloading, then return to operation at a valve up the hole. The resulting uid level in the annulus will be 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 valve subject

to several limitations. Fluid feed-in will often raise the uid level before the wireline tools can be deployed down the

hole. In addition, uid fallback will always occur after the lift gas has been shut off. Both of these factors will cause

the observed uid 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 uid back down the hole and 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-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 SurveyIn this type of survey, an electronic pressure gauge or bomb is run in the well under owing conditions. These

recording instruments can also measure temperature, and both ambient and “quick-response” models are available.

Under owing 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, theexact point of operation can be determined, as well as the actual owing 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.




Procedure for Running a Flowing BHP Test When the Well Is

Equipped 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 as

possible.

Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. A gas and uid test,2.

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 well

while 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 BHP was5.

taken.The casing pressure should be taken with a deadweight tester or “master test” gauge, or a recently calibrated6.

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 production

facilities.

Put the well on test before running the BHP. The test is to be run for a minimum of 6 hours. Test information,2.

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 each

gas-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” gauge,6.

or a recently calibrated two-pen recorder.




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



2

4

6

8

10

Casing

Tubing r e s s u r e

×

p s g

2

4

6

8

10

Casing

Tubing P r e s s u r e

( ×

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

8

10

Casing


( ×

1 0 0

p s

i g ) Top

Valve

2 Valvend

3 Valverd

4 Valveth


Interpretation of Two-Pen Recorder Charts

The two most signicant 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 efciency of the system. The following ow charts

illustrate the type of information gained with the use of two-pen recorders.

Continuous-Flow Wells

Trouble

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

RemedyPut the continuous-ow 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 ow well, or increasing the

storage capacity of the supply system to dampen out pressure uctuations.

TroubleInjection 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).

RemedyCorrect wellbore problems that are restricting feed-in, or redesign gas-lift

string for lower producing rate.

TroubleNone (Fig. 9). Well unloading.

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

on test.

Fig. 6

Fig. 7

Fig. 8

Fig. 9



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 )



TroubleNone (Fig. 10). Note the uniform tubing, casing pressures, and relatively

low 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, parafn, scale, or other restrictions toow from the owline. Looping or replacing the existing line with a larger line

may be indicated in severe cases.

TroubleValve throttling (Fig. 12).

RemedyThe 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 oversizedports in the gas-lift valve.

TroubleHoles 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.

RemedyPull well, and replace faulty tubing. It may be possible to locate the hole and

isolate it by installing a pack-off.

Fig. 10

Fig. 11

Fig. 12

Fig. 13



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 )



Intermittent-Flow Wells

TroubleNone (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.

RemedyGood operation. Adjust the number of cycles and test well to conrm

optimum production.

Trouble A leaking valve, indicated by casing pressure drawdown between cycles

(Fig. 15).

RemedyTrash 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 signicant loss of production or excess gas usage.

Trouble

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

RemedyPull and replace defective tubing.

TroubleClosed valve throttling, indicated by a slow casing-pressure drawdown

(Fig. 17). Broad tubing-pressure kicks usually indicate excessive gas usage

and reduced uid recovery.

RemedyThis condition is usually caused by running valves with low dome volumesor heavy strings. Try to select valves, such as the Weatherford pilot-

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 before the

valve opening pressure is reached. As a result, two intermitter cycles are

required to open the valve. Tubing kicks show good uid recovery.

Remedy Adjust intermitter cycle and duration of injection until maximum uid with

minimum 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-tubing kicks

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

Adjustablechoke

Injectionmeter

Bull plug

Recycle valveset at 55 psi

Union Ballvalve

Valvemaster

Fluid to heater

130-psi separator

130-psibackpressurevalve

Flow line

Non-adjustablechoke

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 gas

3. 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. Problem1. 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 enough7. 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 hole

13. 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 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. Specications 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.

Gas Lift Troubleshooting

Documents

Transcript of Gas Lift Troubleshooting