New, larger bore CT drilling beyond 7,000 ft

June 25, 2007
New coiled-tubing rigs are drilling to record depths, with larger diameter strings and top drives capable of holding 200,000-lb hook loads.

New coiled-tubing rigs are drilling to record depths, with larger diameter strings and top drives capable of holding 200,000-lb hook loads.

Tenaris Coiled Tubes and Xtreme Coil Drilling Corp. are working together on a project that is extending the limits of coiled-tubing drilling technology. Tenaris explains this pioneer effort to use deep coil drilling in the US Rocky Mountains (Figs. 1, 2).

Calgary-based Xtreme is a specialized coiled-tubing services company with a new coil-over top-drive (COTD) rig design (OGJ Sept 18, 2006, p. 48). The company has been using its new rigs to drill shallow wells in the aging, marginally economic, shallow oil fields of Colorado’s Denver-Julesburg basin (OGJ, Dec. 18, 2006, p. 37).

Xtreme’s CT Rig 2, model 200ST, was drilling near Rock Springs, Wyo., in late 2006 for Shell Unconventional Resources (Fig. 1; photo from Tenaris Coiled Tubes and Xtreme Coil Drilling Corp.).
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Xtreme is pioneering the use of coiled tubing (CT) in downhole drilling applications to 10,000 ft, a depth that is 3,000 ft beyond coiled tubing’s 7,000-ft historical technical drilling limit. As part of that project, Xtreme asked Tenaris Coiled Tubes, a manufacturer of coiled tubing, to produce the first strings of CT to support the project. Ultimately, that request required Tenaris to develop new 3½-in. OD tubing capable of drilling a 10,000 ft well.

Rough beginning

As an oil and gas technology, coiled tubing seems too good to be true. It is surprisingly simple and straightforward in its application on oil and gas wells, can be used for a wide range of tasks and, due to its operational efficiency, reduces overall well costs.

Yet, despite all of its advantages, CT was not always so highly regarded. For years, operators would only consent to using it for specialty jobs such as washing out sand, retrieving subsurface safety valves, and lifting fluids from wells using nitrogen. This was due to the fact that during its early period of development it was plagued by safety and reliability issues because of its inability to withstand the repeated bending cycles and high tensile loads encountered during jobs.

Low yield-strength steels and the butt welds necessary to make the continuous tubing strings often failed, sometimes with catastrophic consequences. Equipment failures and lost tubing that required expensive fishing expeditions tarnished CT’s reputation. Over time, operators simply lost confidence in the technology.

Xtreme’s CT Rig 4, model 200DT, was drilling in the Denver-Julesburg basin near Greeley, Colo., in January 2007 for Anadarko Petroleum (Fig. 2; photo from Tenaris and Xtreme Coil Drilling).
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In the late 1970s and early 1980s, improved manufacturing techniques allowed the tubing to be formed from much longer sheets of steel. This effectively reduced the quantity of required welds by at least half, according to Tenaris. Later, new developments in welding methods allowed butt welds to be entirely eliminated. Improvements in the quality of the steels used to make the tubing were also introduced, and a better understanding of CT fatigue enabled significant advancements in reliability and performance.1

The early 1990s brought a renaissance in CT technology and soon it was being applied to an expanding list of tasks that included acid and fracturing treatments, tool conveyance, drilling, artificial lift, well completions, and logging.

Xtreme said that continuing technology challenges include the slightly higher cost of coil rigs, shorter life cycle of coil tubing over conventional drill pipe, difficulty in fishing CT, and directional drilling with CT.

Xtreme began a joint venture with Shell Technology Ventures BV in December 2006-Coil-X Drilling Systems Corp. Coil-X is a private company (51% Xtreme, 49% Shell), which will address existing technology challenges of coiled tubing and expand the use of Xtreme’s COTD design for conventional and unconventional resource exploration, according to Xtreme’s April 2007 corporate update.

CT moves offshore

It was during the late 1990s that the CT technology movement turned toward offshore. The issues facing coiled-tubing technology offshore were much greater, however, and more complicated than those encountered on land. Among the numerous issues that offshore coiled-tubing operations had to overcome was an aging fleet of offshore platforms, extremely heavy CT equipment, platform space issues, on site CT welds on platforms, and the vertical or lateral movement of the platform rig when the CT is deployed from a floating facility.

A loaded reel is by far the heaviest single component of a coiled-tubing system. Existing platforms and cranes, whose lifting limits had been downgraded over time due to their ages, posed an obstacle for moving CT offshore because the coiled-tubing reels were too heavy and the power pack and control cabin footprints were too large for them.

Even in deep water, where very large floating platforms and cranes are rated to lift more weight than that of the largest coiled-tubing systems, limited available space remained a formidable obstacle for operators interested in using CT.

Also, using CT offshore often required welding operations due to weight restrictions. The preferred approach at the time was to take the coil offshore in two or three pieces and weld them together on the platform. This was expensive and time consuming.

Welding specialists were required to set up the operation. In most jurisdictions, a special work permit was required, and a discrete area on the rig used. In many instances, the wells had to be shut in for the duration of the welding job. Then the welds had to be x-rayed by yet another set of specialists with more equipment. As the tubing was used, the discrepancies between wall thicknesses and ovality became more significant and the welding process became harder to control.2

Finally, CT rigs used on floating platforms were subject to vertical and lateral movement. To compensate for these movements, they relied on heave compensators attached to the platform rig. However, the platform rig had to sit over the same well as the coiled-tubing unit. Before CT could become a truly useful tool offshore, this problem had to be solved.

Eventually, engineering innovations offered solutions to these problems.

Canadian endorsement

Globally, and particularly in Canada, CT drilling has become increasingly prevalent due to several technical improvements developed over the past 2 decades. Canadian oil and gas operators routinely use CT to drill shallow wells because they can drill them quickly and efficiently (Fig. 3). In shallower, unconsolidated formations, CT drilling rigs achieve penetration rates of 1,300 fph, compared to 300-400 fph accomplished with conventional rigs.

Xtreme’s CT Rig 3, model 200ST, was drilling in injector mode near Wabasca, northern Alta., in January 2007 (Fig. 3; photo from Tenaris and Xtreme Coil Drilling).
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And the new generation of coil-tubing drilling rigs can drill two, 2,000-ft wells in a single day using preset casing. They can also rig up and rig down faster and their continuous circulation provides superior overall well control. They exhibit improved safety because less pipe is handled and crews are smaller, and they reduce costs by 15-50%.

Despite the increased presence of CT drilling in Canada, the use of CT technology in the US hasn’t been as freely employed to drill anything other than shallow or moderately deep wells.

Hook-load increase

Xtreme’s project represented an advance for CT drilling.

For example, the project needed larger injectors to handle the increased hook loads, which can weigh up to 120,000 lb. While some injectors rated to 200,000 lb have been built for other specialized field service work, their use in CT drilling has typically been limited to reentry operations using mostly smaller sizes of coiled tubing.

More recently, engineers have adapted the large coiled-tubing injectors so they can utilize larger diameter tubing sizes in open holes. As a result, the 10,000-ft well, which is very common in US drilling projects using conventional pipe, has become achievable with CT drilling.

Transporting the equipment required by these projects presented problems. Adding a top drive and injector along with the CT string made loads too heavy for existing US roadways. Therefore, it became necessary to redesign the transport logistics to break up the CT rig components into various modules that can be transported legally yet rigged up and down quickly.

Bigger rigs were also needed. Fortunately, technology has kept pace in this area. Late in 2006, coil over top drive (COTD) rigs with 200,000-lb hook loads, which were capable of drilling to 10,000 ft with coiled tubing or to 14,000 ft with jointed pipe, were introduced (OGJ, Sept. 18, 2006, p. 48).

The biggest obstacle for the project was the coiled tubing itself. At the inception of CT drilling, tubing in 2 3/8-in. and 2 7/8-in. sizes sufficed. In drilling larger holes, however, the smaller tubing sizes experienced friction loss that resulted in high pressures and slower drilling rates as the bit went deeper. Engineers found that if 3½-in. CT was used to drill deeper 8¾-in, 7 7/8-in. or 6½-in. holes, the friction loss and wear on the CT and surface equipment could be reduced.

Thus, pump pressures ranging from 1,500-2,000 psi could be achieved compared to the 2,000-3,000 psi required for circulating through the smaller sizes. Tenaris Coiled Tubes said its experience producing larger diameter coiled tubing in 3½-in., 4½-in., and 5-in. OD primarily for subsea pipelines and its handling equipment, capable of moving reels with up to 120,000 lb of pipe, were useful when developing CT for the project.

Thicker, lighter CT

The coiled-tubing strings that Xtreme required to drill 10,000-ft wells had to be light enough to transport on trailers, yet thick enough to withstand the abrasions of drilling horizontally. Staff at Tenaris Coiled Tubes worked with Xtreme’s engineers to develop pipe that could withstand the load, operating and external pressures, and fatigue that punishes the CT in the course of drilling deep wells.

Bruce Reichert, Tenaris Coiled Tubes technical and R&D manager, said, “We examined different diameters, wall thicknesses, and grades in order to the produce pipe that would best fit their needs. The final product is the result of a team effort by both companies.”

Tenaris recommended 0.204-in. gauge pipe with a 3.50-in. OD that would result in a string weight of almost 100,000 lb. In August 2006, Tenaris produced the first strings for the project at its Houston facility and became the only US mill that could, and still does, produce CT strings in this size.

To date, Tenaris has produced 12 strings of the new coiled tubing for Xtreme to use on the project and it anticipates that demand for 10,000-ft well strings will increase as more experience is gained drilling the deeper wells. “Xtreme’s innovation in using CT drilling for deep gas wells could very well result in an overall increase in the amount of CT drilling in the US,” said Reichert.

According to Tom Wood, chairman of Xtreme, further technological advancements may lead to the use of 4-in. OD CT. Xtreme will be drilling in deep gas fields such as Pinedale and Jonah in Colorado’s Green River basin for EnCana Oil & Gas (USA) Inc. (OGJ, Dec. 18, 2006, p. 37).

Xtreme plans to have 18 CT drilling rigs operating in the US Rocky Mountains and Canada by early 2008. Xtreme also continues to market coiled tubing drilling services to major independents and other large operators who can apply CT technology to projects in the Piceance, Powder River, and DJ basins and in southwest Wyoming as well as other similar oil shale projects throughout the U.S. Rockies.”

References

  1. “A History of Coiled Tubing,” Schlumberger Oilfield Review, spring 2004, p. 42.
  2. “The Reel Deal,” Offshore Engineer, October 2004.