High-rate gas wells can be drilled by deliberately seeking out large fractures and can minimize formation damage by using managed pressure drilling with a downhole deployment valve.
Nyoman Dharma, ConocoPhillips Indonesia, and Julmar Shaun S. Toralde, Weatherford
To enable the drilling of big-bore, high-rate gas wells in the ConocoPhillips-operated Suban Field in South Sumatra, Indonesia, Managed Pressure Drilling (MPD), particularly the Pressurized Mud Cap Drilling (PMCD) variant, was used. This operation also included Weatherford’s proprietary Downhole Deployment Valve (DDV). The combination of MPD with a DDV system was applied during drilling operations and resulted in wells capable of producing 300 MMcfd, while improving the safety and efficiency of drilling and completion operations. The combined MPD/DDV system allowed drilling to continue even with total loss of circulation. The combined system increased the safety margin of operations, reduced the amount of mud and Lost Circulation Materials (LCM) required, minimized formation damage and made running and installing the completion assembly possible without killing the well.
SUBAN GAS FIELD DEVELOPMENT
To reduce costs, ConocoPhillips with partners Talisman and Pertamina determined that by increasing individual well productivity, fewer wells would be required during Phase II of the development. In line with these higher capacity wells, Suban-10 and Suban-11 were completed with a tapered big bore Corrosion Resistant Alloy (CRA) completion (9 5/8-in. × 7 5/8-in.), and a blank uncemented tapered liner (7-in. × 5½-in.) in the openhole.
The Suban-10 and 11 well trajectories were planned to intersect a fault that was encountered on the adjacent DM-2 well, where total losses occured and where production logging tools indicated that more than 90% of DM-2 production originated. Additionally, the well paths designed for Suban-10 and 11 dictated that additional major faults were to be crossed, increasing the likelihood that circulation losses would be severe, if not total. ConocoPhillips had previously encountered total losses on wells in adjacent fields where more than 200,000 bbl of mud had been lost per individual well.
An alternative drilling method had to be developed that would enable drilling through these formations while reducing the amount of high-density mud and LCM. Tripping and running the completion without killing the well was also required. The solution that addressed all these problems in the Suban Field was a system integrating and synergizing MPD and DDV technologies.
MANAGED PRESSURE DRILLING
During PMCD operations, the formation pressure is kept in balance by low back pressure held by a Rotating Control Device (RCD) at surface. With the annulus sealed by the RCD and the choke completely closed, the back-pressure can be monitored to record any changes in the reservoir pressure or to detect the migration of gas upward through the annulus fluid. Whenever annular pressure increases to a certain level due to gas migration, low-density mud is pumped down the annulus to bullhead the reservoir gas back into the formation. The pressure returning to its original value gives a clear indication that the pressure rise was due to gas migration and that it has been pushed back into the formation.
A weakness of the PMCD technique is that the well still has to be killed prior to pulling out of the hole for any reason, including at well total depth. Performing a well kill can be costly in time and mud materials and will lead to reservoir damage. Large volumes of high-density mud may need to be pumped into the hole before the well is killed and stabilized. Since PMCD was employed to prevent reservoir damage in the first place, the system had to be improved and augmented to allow for pulling out of the hole and running the completion without the need to kill the well. A downhole isolation system, specifically the DDV, was therefore considered to achieve this goal.
DOWNHOLE DEPLOYMENT VALVE
The DDV is a full-bore, flapper-type valve installed within the casing string which can be closed to isolate productive formation while tripping and to avoid pipe-light conditions due to annulus pressure, Fig. 1. It eliminates the need for snubbing operations, as well as the need to kill the well in order to trip the drillstring and install completion assemblies during underbalanced and near-balanced operations.
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Fig. 1. The DDV flapper-type valve is installed within the casing string (bottom view).
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Its design allows passage of the drill bit when in the open position. When tripping out of the hole, the string is tripped out until the bit is above the valve, which is then closed and the casing annulus pressure above the DDV bled off. The drillstring can then be tripped out of the well without the use of a snubbing unit and at conventional tripping speeds, thus reducing rig-time requirements and providing improved personnel safety.
The valve can also be used to trip in the hole. The drillstring is tripped back into the well until the bit is just above the DDV, the annulus pressure is equalized, the valve opened and the drillstring run in to continue drilling operations.
The DDV can either be run and cemented in place with the casing, or it can be run in a retrievable mode within a tie-back assembly. Once installed, the valve is operated by pressure, applied via an armored control line that runs from the valve to the surface control panel. It comes in two sizes, 7-in. and 9 5/8-in., and in varying weights and pressure rating options. The DDV has a good reliability record with 100 separate installations globally by the time the Suban project was underway.
On the Suban project, 9 5/8-in., 47-lb/ft DDVs were used. This type has a maximum OD of 12 in. (305 mm) and a minimum ID of 8.535 in. (217 mm). It can withstand a maximum differential pressure of 5,000 psi (345 bar) and a maximum temperature of 300°F (149°C). The Suban DDVs were installed in retrievable mode using a tie-back assembly, marking the first time that a 9 5/8-in., 47-lb/ft DDV was installed this way. The retrievable mode had been done multiple times with the 7-in. DDV.
SUBAN SYSTEM
The equipment and materials used during Suban drilling operations are as follows:
- Drilling tieback-A 9 5/8-in. drilling tieback with communication at the base was installed to provide an additional annulus.
- DDV was installed in the drilling tieback at the bottom just above the bullet seal assembly stung into the liner hanger polished-bore receptacle. This allows the productive formation to be isolated when tripping, eliminating the need to kill the well during tripping operations, and to overcome pipe-light situations.
- Injection Collar-A 9 5/8-in. pup joint, with twenty ½-in. holes drilled in a vertical line along one side, was used as an injection collar. This allows viscous fresh water to be injected into the drill pipe annulus to lighten the hydrostatic pressure when required. The injection collar was installed in the drilling tieback just above the DDV. The injection holes were lined up vertically to minimize the exit of gas from the inner to the outer annulus.
Suban operations used Weatherford’s model 7100 high-pressure RCD to exert backpressure on the annulus during PMCD operations, Fig. 2. The equipment is capable of withstanding 2,500 psi in dynamic mode and can increase to 5,000 psi in static mode. This model was chosen because the maximum surface pressure, with gas all the way to the surface, was in the range of 3,400-3,500 psi.
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Fig. 2. The Suban pressurized mudcap drilling (PMCD) system exerted back pressure on the annulus.
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The PMCD system for the Suban-10 and 11 wells was set up in stages. The RCD, valves and pipework required were installed before the 12¼-in.-hole section was drilled, and was used to divert returns while drilling this section. Next, prior to drilling the 8½-in. production interval and after a 9 5/8-in. production liner was run and cemented, the 9 5/8-in. drilling tieback was installed, together with the DDV and injection collar.
SUBAN-10 COMPLETION AND RESULTS
Both wells were successful, but the process differed somewhat. MPD operations for Suban-10 began as planned with the installation of the RCD and the PMCD components before the 12¼-in. section was drilled, Fig. 3. The DDV was installed along with the rest of the drilling tieback after the 9 5/8-in. casing was cemented in place. The DDV was installed at 1,428 m at a deviation angle of 12.24°.
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Fig. 3. Rotating control device was installed on the blowout preventer.
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Partial circulation losses were encountered during the early phase of the 8½-in. section while drilling through faults at 2,107 m and 2,176 m. These were cured with LCM. Total losses were encountered at 2,237 m when a major fracture was hit, and gas was then bullheaded back down in preparation for PMCD operations. The volume of drilling mud lost to the formation was about 2,500 bbl before the shift to PMCD was made. Using PMCD, the interval from 2,238 m to 2,289 m (51 m) was subsequently drilled in MPD mode.
Another major fracture was encountered at 2,276 m. Drilling continued to 2,286 m with increasing torque and erraticly increasing annulus pressures. A bit change resulted in the bit being stripped to above the DDV, which was set to the closed position. However, with gas present above and below the DDV, the differential pressure required to seal the flapper effectively was not present. An attempt was made to bleed off gas from the surface to establish that the DDV was closed. This was immediately halted when the crew realized that there was too much gas above the DDV. Surface pressure, therefore, continued to rise and reached 3,400 psi, which is within the RCD’s capability.
Once sufficient fluid volume was available, the gas was bullheaded using Viscous Sacrificial Drilling Fluid (VSDF); the DDV was closed and pressure was bled off. The DDV sealed effectively and gas was kept out of the wellbore. Circulation down the outer annulus and up the inner annulus, and the reverse, was performed to circulate out any remaining gas in the upper section of the hole. When the inner and outer annuli pressures were zero, the bit was conventionally tripped out of the hole.
After discussions with partners and the government regulator (BPMIGAS), approval was obtained to complete the well, since four major fractures had been encountered. Preparations were immediately made for running the completion. Instead of killing the well before completion, the DDV was used to hold the formation pressure until the completion assembly was positioned above it. Since the DDV is not designed to open with a pressure differential across the flapper, pressure equalization was performed. The gas below the DDV was bullheaded down the well and back into the formation at a high rate through the outer annulus, and at a low rate down the inner annulus past the completion packer element. Bullheading continued down the inner annulus at a low rate while the completion assembly was run into the hole through the RCD. Finally, the packer was set, effectively isolating reservoir gas from the wellbore. The presence of the outer annulus allowed much larger volumes to be bullheaded at higher rates without the concern of pumping past the packer elements on the completion packer assembly.
Once the lower completion assembly was in place, the drilling tieback was pulled along with the DDV and injection collar. A subsequent cleanout trip was made to displace the drilling mud to 12-ppg weighted brine prior to running the upper 95/8-in. × 75/8-in. completion assembly.
Mud and water losses, when the Suban-10 reached TD, were 5,450 bbl and 11,950 bbl, respectively. Of that amount, about 2,950 bbl of mud was lost in MPD mode. Total mud and water losses, up to the time the lower completion was run and the well was sealed, were 7,040 bbl and 12,975 bbl, respectively.
Subsequent testing operations in Suban-10 have proven the value of using MPD and DDV technologies during drilling and completion operations. Results have shown that the well is capable of delivering at a high rate of more than 300 MMcfd to the Suban Gas Plant facilities.
Suban-11. The DDV for Suban-11 was set at 1,395 m with a deviation angle of 6.8°. It was set at a shallower depth than previously to allow for the re-use of the DDV control line from Suban-10. However, the DDV was not used on Suban-11 because losses were minimal. Due to the lack of losses, MPD was also not used in Suban-11. Losses encountered were minimal and were easily cured with applications of LCM or by the reduction of the pump flow rate.
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Fig. 4. The Suban-10 well has produced at rates exceeding 300 MMcfd. Higher rates are limited by the pipeline.
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CONCLUSION
The Suban-10 experience has proven that MPD and DDV technologies can be successfully integrated and applied during drilling and completion operations to produce high-rate gas wells, Fig. 4. The combination of the two technologies opens the door to the construction of gas wells designed for increased productivity and output, by deliberately seeking out large fractures while concurrently minimizing formation damage. The synergized use of MPD and the DDV will allow the drilling of fewer but larger output wells, greatly improving the economics of gas-field development. 
ACKNOWLEDGEMENT
We thank our partners, Pertamia, Talisman and BP Migas, who supported the Suban big bore development. Special acknowledgement goes to Brett Borland, John Tregilgas and Peter Edwards at ConocoPhillips, and to Ken Muir, Weatherford, who played major roles in the evolution and implementation of this success.
BIBLIOGRAPHY
Beltran, J. C., Gabaldon, O., Puerto, G., Alvarado, P. and V. Varon, “Case studies-Proactive managed pressure drilling and underbalanced drilling application in San Joaquin wells, Venezuela,” SPE paper 100927-PP presented at the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 24-27, 2006.
Colbert, J. W. and G. Medley, “Light annular mudcap drilling-A well control technique for naturally fractured formations,” SPE paper 77352 presented at the SPE Technical Conference and Exhibition, San Antonio, Texas, September 29-October 2, 2002.
Hannegan, D. and K. Fisher, “Managed pressure drilling in marine environments,” paper IPTC-10173-PP presented at International Petroleum Technology Conference 2005 held in Doha, Qatar, November 21-23, 2005.
Sweep, M. N., Bailey, J. M. and C. R. Stone, “Closed hole circulation drilling: Case study of drilling a high-pressure fractured reservoir-Tengiz Field, Tengiz, Republic of Kazakhstan,” SPE/IADC paper 79850 presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, February 19-21, 2003.
Timms, A, Muir, K. and C. Wuest, “Downhole deployment valve-case history,” SPE paper 93874 presented at the Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, April 5-7, 2005.
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THE AUTHORS
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Nyoman Dharma is Senior Drilling Engineer, ConocoPhillips in Stavanger. He graduated with a BS degree in Petroleum Engineering in 1980. After working for 10 years with a major drilling fluid company in Indonesia, he subsequently worked for Marathon, Clyde and Gulf. He joined ConocoPhillips in 1990 with responsibilities as drilling engineer, drilling supervisor, drilling superintendent and drilling engineering coordinator.
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Julmar Shaun S. Toralde joined Weatherford in 2005 as a Control Pressure Drilling Engineer specializing in Managed Pressure Drilling. He graduated with a BS degree in geothermal engineering in 1999, and is working on an MSc degree in mathematics.
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