Optimum Performance in Dual Gas-Lift Wells

ASME/API/ISO Spring 2004 Gas-Lift Workshop February 10-11, 2004

Dual gas-lift design

• Design goals - lift as deep as possible

Single point injection through the bottom valve

Or inject through two of the bracketing valves

Multi-point injection must be at stable injection rates and at the deepest possible locations.

Unloading a dual

• Follow the API unloading procedure.

• Be patient. There are no shortcuts to the unloading procedure that will safely speed up the unloading process.

Unloading a dual Build the casing pressure no

faster than 50 psi per 10 minutes

Surveillance• SCADA

• 2-pen charts

• Well tests

• Flowing pressure surveys

• Static pressure surveys

• Acoustic sounding device

Typical dual gas-lift problems

• Higher backpressure than the original designed conditions.

• Lower injection pressure than the original designed conditions.

• Higher injection pressure than the original designed conditions.

• One string will not take injection gas or takes less than the designed rate.

• One string has pressure depleted and is shut-in.

• One string taking more injection gas than its designed rate.

• Producing Emulsions

• Tubing-casing communication

Proving tubing-casing communicationCommunication Above Tubing Fluid Level

As the casing is bled down, the tubing with the communication

problem will loose pressure and

gradually equalize with the casing

pressure.

Proving tubing-casing communicationCommunication Below Tubing Fluid Level

As the casing pressure is bled down, the

casing fluid level will rise as tubing fluid enters the casing.

A formation with high feed-in ability will

maintain a constant tubing fluid level as it fills

the casing during the bleed-down. No change in tubing pressure will be

observed.

Monitor the casing fluid level during bleeding operations

Locating the communication point

Slickline log – Temperature, spinner, pressure, CCLDependable only if steady flow can be achievedCan sometimes find multiple leaks or holes.

Holefinder – Use if steady flow cannot be achieved. Good for locating the top hole.Not good for multiple holes.

Caliper survey – Can find multiple holes. Will not locate leaking gaslift mandrels.

Ponytail – You must have a good flow rate across the hole to locate it.Not as dependable as other methods.

Dual gas-lift troubleshooting

• Compare the initial design parameters with the actual operating parameters.

• Obtain individual well tests with the other string shut-in.

• Conduct tubing integrity tests while monitoring the casing fluid level.

• Design and run a flowing gradient survey with a build-up.

• If a gas-lift valve revision is necessary, use as many dummy valves as possible.

High productivity wells with relatively high formation GLR’s will sometimes unload and transfer to a shallower point of injection as the production rates increase.

Wireline procedures for dual gas-lift

Running valves

• Keep both sides of the dual shut-in when a gas-lift mandrel has a vacant pocket.

• Pulling a gas-lift valve in a dual will give the reservoir a flow path to the casing and through the gas-lift valves of the other string.

Dummy valves in the other string

• The wireline procedure is the same as running valves in a single completion.

Live valves in the other string

• Take precautions to prevent the well from flowing into the other string during the valve revision

Wireline procedures for dual gas-lift

• Installing valves in the string with the lowest pressure

Use the same wireline procedure as for single completions

• Installing valves in the string with the highest pressure

Prevent the high pressured zone from flowing into the low pressure zone during the valve installation

• Tubing Integrity test

Monitor the casing fluid level during the tubing integrity test.

Pulling valves in a dual

The casing and tubing pressures are equalized

with gas-lift pressure

Pulling the bottom valves in the long string

will result in the long string filling the casing with fluid. The fluid will then pass through the gaslift valves on the

short string.

Pulling valves in a dual

A standing valve is set in the lowest pressure side of the dual and the tubing is

filled with water. This prevents cross-flow from

occurring

Avoiding wireline problems• Always have a detailed wireline procedure completed before

pulling valves

• Minimize wireline time but don’t take short-cuts

• Utilize dummy valves in valve re-designs when possible

• Be aware of the size of the tool deflector in the sidepocket mandrel.

• When running valves, use two brass pins in the running tool

• Prevent the higher pressured zone from flowing into the low pressured zone

• Catcher subs on kickover tools

• Perform tubing integrity tests monitoring the casing fluid level after every valve revision

Dual flowing surveys

0

500

1000

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0

TIME (HOURS)

PRES

SURE

(PSI)

0

50

100

150

200

TEMPE

RATU

RE (D

EG F)

Long String

0

500

1000

1500

2000

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0

TIME (HOURS)

PRES

SURE

(PSI

)

0.0

50.0

100.0

150.0

200.0

TEMPE

RATU

RE (D

EG F)

Short String

Dual flowing surveys

2991

4095

4804

5809

6296

6820

7300

7809

8189

5322

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

100000 500 1000 1500 2000 2500 3000

PRESSURE (PSI)

DEP

TH (F

T)

0 500 1000 2000 2500 30001500

FLOWING TEMP (DEG F)50 140 23020017011080

Long String

03000

03000

03000

03000

03000

865129713781450151015101510

5877

2962

4065

4773

5779

6267

6796

7277

7791

00

8059

5291

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

100000 500 1000 1500 2000 2500 3000

PRESSURE (PSI)

0 500 1000 2000 2500 3000

SBHP @ PERFS =1569 PSI

1500

FLOWING TEMP (DEG F)

50 140 23020017011080

Short String

Flowing surveys in heading wells

03000

03000

03000

03000

0

1890

2664

3189

3998

4398

4787

5198

000

55285547

3593

0

1000

2000

3000

4000

5000

60000 500 1000 1500 2000 2500 3000

PRESSURE (PSI)

DEP

TH (F

T)

0 500 1000 2000 2500 30001500

FLOWING TEMP (DEG F)

50 140 23020017011080

84 BOPD177 BWPD

261 Total fluid

03000

03000

03000

03000

0

1890

2664

3189

3998

4398

4787

5198

000

5528

3593

0

1000

2000

3000

4000

5000

60000 500 1000 1500 2000 2500 3000

PRESSURE (PSI)

DEP

TH (F

T)

0 500 1000 2000 2500 30001500

FLOWING TEMP (DEG F)

50 140 23020017011080

SBHP = 2040 psi

x

Maximum pressure reading Minimum pressure reading

Flowing surveys in heading wellsShort String

03000

03000

1610162316351640164616461646

2994

4699

5893

7296

7659

00000

7722

6650

8026

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

100000 500 1000 1500 2000 2500 3000

PRESSURE (PSI)

DEP

TH (F

T)

SBHP @ DATUM = 1790 PSI

0 500 1000 2000 2500 30001500

FLOWING TEMP (DEG F)

50 140 23020017011080

03000

03000

03000

03000

1670168016801801193620742074

2889

4306

5207

6314

6807

7315

7678

000

5810

8188

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

100000 500 1000 1500 2000 2500 3000

PRESSURE (PSI)

DEP

TH (F

T)

0 500 1000 2000 2500 3000

SBHP @ PERFS =2239 PSI

1500

FLOWING TEMP (DEG F)

50 140 23020017011080

Slickline log – Temperature, Pressure, CCL

Slickline log – Temperature, Spinner, CCL