Oil Country Tubular Goods

Monodiameter wells continue to expand possibilities

Although not yet a commercial reality, tests to date, as well as foreseen benefits, argue that these wells will eventually become common.

Perry A. Fischer, Editor

Uptake of expandable tubulars, in general, has been relatively good. There are now dozens of new uses in drilling and completion, and several hundreds of jobs completed. It has been used in wells more than 28,000-ft deep, and in wells with bottomhole temperatures of 400°F. Of all the expandable applications to date, the monodiameter well has the most potential to change the industry.

The present path to full commercial use of a monodiameter well is anticipated to take at least another five years.¹ However, various tests and experiments in the field, as well as modeling and bench work, are taking place continuously to achieve that goal. An intermediate goal is to achieve monodiameter liners.

BACKGROUND

Expandable tubulars must be manufactured and handled much differently than ordinary pipe. Besides metallurgy, the drift ID and all defects must be tightly controlled. Galling and defects, both internal and external, can act as seed spots for ruptures when the metal is expanded.² These problems can be largely overcome, in part, through careful handling similar to Chrome 13 pipe.

Challenges. Post-expansion properties of the pipe, particularly collapse resistance after expansion, need to be closer to the standard pipe that it might replace. Thus, the focus is now the intermediate goal of monodiameter drilling liners or production liners in low-pressure, non-gas applications. Where pressure differentials could become a problem, expandable liners could still be helpful for preserving hole size during well construction, followed by conventional liner pipe for strength. Research continues into stronger, more robust and cheaper expandable tubulars, with gas-tight connections and improved burst and collapse ratings.

For a true monodiameter well, two expansions are needed. One expansion is a bell-shaped (or flared) upper pipe into which a lower, subsequent pipe is expanded. The ID of the bell is only slightly larger than the OD of the lower, subsequent pipe which it receives. Elastomeric compound is squeezed between the two pipes and acts as a hanger and seal. Ideally, both the lower pipe and the upper pipe, with its flared, “over-expanded” bell, need to be expanded in a single trip.

The overlap area, or bell, is the limiting factor for pipe size. Thus far, the practical limit of plastic deformation without risking pipe fracture is an expansion ratio of 30%. Expanding 9-5/8 x 11-3/4-in. pipe results in a 10.4-in. ID. This yields a basic expansion rate of 17%. If there is to be a bell, as needed for monodiameter sections, the bell must expand 24%, which is well within the feasible expansion ratio. This makes 9-5/8 x 11-3/4-in. pipe a practical monodiameter size.

Applying the expansion process to 5-1/2 x 7-in. pipe yields a 6.1-in. ID, and a 25% expansion, while the corresponding bell must expand 42%, which exceeds the practical expansion limit. The smallest practical diameter that can be expanded into a bell for monodiameter applications is 7-5/8 x 9-5/8-in. pipe, which yields an 8-in. ID with a 19% expansion, while the bell expands 29%.³ Smaller sizes are a challenge – likely to become viable as the technology is further developed.

For cementing purposes, the bell poses another problem: The borehole must be a minimum 1 – 1.5 in. larger than the OD of the bell for cement to travel. Underreamers and bicentered bits can usually achieve this, but special arrangements might have to be made. For example, a 9-5/8 x 11-3/4-in. monodiameter drilling liner creates a 10.4 in.-ID and a bell OD of 11.8 in. A cement clearance of 1.5 in. requires a hole of 13.4 in. This means a bit would have to increase from 10.4 in. to 13.4 in., which is a 127% increase.

Benefits. At first, solid expandable tubulars were used as contingencies, including when needed for an intermediate casing string, such as drilling through a depleted zone, preventing lost circulation, preserving hole size. Gradually these have been enhanced to include remediation of old wellbores and water control.¹ Achieving a true monodiameter well would multiply these benefits.

Time is an obvious benefit from single diameter wells. This is similar to what is expected from reduced casing clearance programs, since every inch of wellbore larger than what is needed to accommodate production at the producing zone is, in some sense, wasted. These benefits are:

• Fewer cuttings
• Reduced fluids/ cement
• Smaller surface string(s)
• Preservation of hole size at TD
• Higher ROP from smaller holes
• Potentially, smaller rigs.

Cost savings can derive from all the above. Smaller boreholes could save as much as 59% for cuttings disposal, 38% for casing weight, 42% less cement and 44% less drilling fluid volume. A simulation study of a 29,000-ft well drilled in 5,000-ft deep water showed savings of $12 to $31 million.¹ 

Improving operational efficiency. Techniques for the installation of expandables is undergoing rapid improvement. A major advancement under development by Enventure Global Technology is a one-trip system that replaces several trips into the hole for monodiameter well construction. It was tested in a live well in late 2004 and is still in development.⁴

The one-trip system:

1. Locks the expandable one-trip BHA/ toolstring to the ID of the pipe for run-in hole to TD.
2. Over-expands the bottom of the pipe, creating a bell section for subsequent monodiameter strings
3. Sets a cement packer, which can be used to hydraulically expand above/ against.
4. Expands the remaining pipe to the monodiameter ID. This presently requires a separate trip.
5. As a contingency, since the expanded pipe shortens as it expands and, over long sections, the degree of shortening cannot be accurately predicted, a cut-off mill, incorporated into the toolstring, removes any excess pipe that might extend beyond the upper bell. At present, this requires a separate trip.

APPLICATION FOCUS: EXTREME ERD

A monodiameter system for extended lateral reach would be used for the same reasons as conventional Extended Reach Drilling (ERD). One reason is avoidance of operational problems, such as those found offshore in the weather-vicious Straits of Magellan, where Total elected to access its Tierra del Fuego fields from the shore. Those ERD wells were 36,693-ft MD.

Similarly, BP is planning to use ERD wells from Alaska’s North Slope to reach its Liberty prospect in the icy Beaufort Sea, some 8 mi offshore. And of course there’s the environmental gem of Wytch Farm, the epitome for ERD wells, with its record 37,001-ft MD well. Of course, it’s not just for mitigating the environmental concerns, since the long horizontal sections contact much more reservoir, which can lead to increased production per well, fewer wells drilled and less infrastructure.

In addition, by combining ERD and monodiameter technologies, two other benefits are derived: one of these is the benefits of a slim well, as mentioned earlier; the other is the substantial increase in reach, which contacts even more reservoir than conventional ERD, with predictable benefit to production. These can further reduce field wells and infrastructure, resulting in improved field development economics.

A well design feasibility study was conducted for a major North Sea operator, as part of the front-end engineering and design. It covered an existing oil field and a near-term planned deepwater subsea gas development project. It assessed conventional drilling vs. expandable casing technology regarding ERD for field development.

The study showed potential lateral reach increases of 25% to 100%, with reduced drilling problems in both fields. Other drilling performance and cost studies in the same two North Sea fields indicated that well costs and times can be reduced by at least $40 million, or 30% to 50% of the current drilling cost and time, by applying solid expandable tubulars and/or single-diameter technology.⁵

The initial model showed that if conventional technology was used, the existing oil field could achieve 5 mi (8.5 km) lateral wells with significant drilling risk. The operator had an ERD drilling record that was established with significant trouble, which helped validate the model.

The model then considered the effect of incorporating two solid expandable tubular liners into the well design, which showed a potential 50% increase in lateral reach. Up to about 7.5 mi (12.7 km) reach can be achieved by installing two successive, solid expandable, tubular liners. By varying the number and size of various monodiameter liner lengths and installation depths, the model indicated that about 9.5 mi (15 km) of lateral reach was achievable, using 9 to 11 successive monodiameter liners, each ranging between about 1,000 and 3,000 ft near TD. The drilling profile for such a well is shown in Table 1.

TABLE 1. An ERD 15km well profile.5

Achieving reach beyond about 7.5 mi (12.7 km) requires monodiameter liners to ensure it is mechanically feasible with a tapered (5-1/2-in. X 6-5/8-in.) S-grade drillstring and high-torque tool joints with increased makeup torque. Hydraulic analysis indicates that increased pump capacity beyond the 5,500-psi that’s now available will be required to efficiently drill and complete the longer reach wells and may require capacity beyond conventional triplex pumps.⁵

Because expandable pipe cannot be handled the same as ordinary pipe, for the type of extreme ERD proposed, some consideration must be given to handling these softer steels, and to the fact that the drill pipe and all subsequent runs will lie on only one side of the liner.

Mitigating some of these effects, including reducing drag risk during setdown, is achieved by using some of the same technology as currently exists for extreme ERD (e.g., friction-reducing fluids, rollers, Teflon), to reduce wear while extending the range of ERD. For the extreme 9.5 mi reach, additional friction-reduction techniques may have to be designed, tested and deployed in the well. Monitoring the drag risk during operations is crucial to manage the risk. Analysis indicates that maximum expected casing wear in the upper-most monodiameter liner is an acceptable 5 – 6%.

CONCLUSION

Achieving 9.5-mi with ERD is impressive, but very challenging. The study’s authors recommended a more practical target of about 8.5 mi (13.5 km) for now, which is still 50% more than what is possible with conventional drilling technology.

Sometime in mid-2006, further testing will occur with the one- (or two- or three-) trip BHA, together with well angles, mud properties, liner length and other considerations necessary to simulate the planned North Sea installation. With a little luck, well construction could begin as early as year-end.

As a contingency, expandable technology is well-proven today. But, it is the application of monodiameter wells that will ultimately have the most impact on tomorrow’s oil fields. 

Click here for a complete list of World Oil’s annual expandable technology reports.

LITERATURE CITED

  ¹ Waddell, K., “Advances in single-diameter well technology: The next step to cost-effective optimization,” SPE 90818, ATCE, Houston, Sept. 26 – 29, 2005.
  ² Jabs, M., “Using expandable metal technology to create a monobore well,” OTC 16670, Offshore Technology Conference, May 3 – 6, 2004.
  ³ Dean, B., L. Cook and D. Brisco, “Monodiameter drilling liner - from concept to reality,” SPE/ IADC 79790, SPE/ IADC Drilling Conference, Amsterdam, Netherlands, February 19 – 21, 2003.
  ⁴ Flippov, A., et al., “Continued evolution of the one-trip expansion, single-diameter wellbore,” Paper OTC 17437, presented at the 2005 Offshore Technology Conference, Houston, May 2 – 5, 2005.
  ⁵ Bell, R., R. McKee, E. Zwald, D. Lewis and P. V. Suryanarayana, “Single-diameter technology capable of increasing extended-reach drilling by 50%,” Paper OTC 17828-PP, Offshore Technology Conference, Houston, May 1 – 4, 2006.