Optimum Performance in Dual Gas-Lift Wells ASME/API/ISO Spring 2004 Gas-Lift Workshop February 10-11, 2004
Feb 09, 2016
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