Coiled tubing (CT) drilling has its roots in Canada. In 1997, Fleet Coil Technologies, a division of Plains Energy Services, brought a prototype rig into Canada from the United States. That rig drilled over 200 wells during its first year of operation.

By 2000, CT drilling was fully commercial for Canadian shallow hydrocarbon drilling. Since then, Canada has moved from drilling a few hundred wells to drilling thousands of wells a year with coil technology.

In shallower, unconsolidated formations, penetration rates of 1,300 ft/hr (396 m) can be achieved compared to 300 to 400 ft/hr (91 to 121 m) using a conventional rig drilling to the same depths. New generation coil drilling rigs are capable of drilling two 2,000 ft (609 m) wells in one day using preset casing. Other advantages are:
• Rig-up and rig-out is faster and often completed within an hour;
• Continuous circulation provides better overall well control;
• Less pipe handling can improve rig safety and requires a smaller crew;
• Crews work in a comfortable, climate-controlled cab; and
• Costs are lower. The drilling component can be reduced 15 to 50%.

Rapid technological improvements and the combination of coil technology with top drive technology is leading to further improvement in depth capability. New wells drilled achieve up to 7,000 ft (2,134 m) total depth. Exploration and production companies have rapidly embraced the technology, creating demand for even deeper drilling capability with coil rigs.

Larger tubing and injector sizes

At the inception of CT drilling, coil size was 23¼8 in. and 27¼8 in. In bigger holes, the original smaller tubing sizes experienced friction loss, resulting in very high pressures and slowed drilling rates as the bit went deeper. Now, coil up to 31¼2 in. is built to handle hook loads greater than 200,000 lb.

Figure 1. COTD is shown in the injector mode. (Photos courtesy of Xtreme Coil Drilling)
Using 31¼2 in. coil to drill deeper 83¼4-in., 77¼8-in. or 61¼2-in. holes reduces friction loss and wear on coil and surface equipment. Now, pressures range between 1,500 to 2,000 psi, compared to 2,000 to 3,000 psi with smaller tubing.

Initially, injectors handled 60,000 to 80,000 lb hook loads, and they worked well with 23¼8-in. to 27¼8-in. CT. The next generation of injectors handled hook loads of up to 120,000 lb. Some injectors built for specific work in the Middle East were rated to 200,000 lb. These were mostly limited to use in re-entry drilling, usually with 27¼8-in. or smaller coil.
CT drillers are adapting large injectors to deploy larger diameter tubing in open hole. As a result, the 10,000-ft (3,048-m) well (which comprises much of US drilling) is now achievable.

Transport redesign

Originally, the coil unit component of a coil over top drive (COTD) rig was transported in a single load. Adding a top drive and injector along with the coil string made the loads exceedingly heavy. To reduce rig-up and rig-out time, we are now configuring deeper coil drilling rigs with half as many loads as conventional drilling rigs. We are also breaking up the coil components into various modular loads that rig-up and rig-out quickly. In Canada, where loads can use different axle configurations, highway jurisdictions more readily allow transport of heavier coil rigs. This is not the case in the United States.

To address both drilling and transport challenges, our company has more than 15 patents pending mostly related to integrating CT and top drive processes and to moving the load economically. Numerous patents pending relate to transportation methods for large coil drilling units. Existing trailer units cannot handle loads of this nature nor can they reel on 10,000 ft of 31¼2-in. coil. New trailer designs meet the standards required to move on US highways.

Improved BHA handling

Previous handling of bottomhole assemblies (BHA) was slow and awkward with small coil drilling rigs. Because of the time that can be saved, efficient switchover from top drive to coil is critical. This led to combining top drive systems with coil. Injector systems are adapted to cross over and stab into the BHA using a dimple connector attached to the coil tubing. The multi-functional top drive makes up the BHA and can also run casing, conventional drill pipe or drill collars.

Transitioning from coil to jointed pipe

The latest COTD drilling rigs can now drill as efficiently — with variable frequency drive systems, high horsepower mud pumps and automated pipe handling systems — and as fast as or faster than most conventional rigs in top drive mode. These rigs can drill the fast hole
Figure 2. COTD is shown in top drive mode.
with coil and switch over to conventional pipe when required, or they can drill the entire depth with either coil or conventional pipe. Many COTD rigs are using Range 3 drill pipe. Thus, even when using conventional pipe, these rigs drill with fewer time-consuming connections.

In late 2006, the largest COTD rigs ever built will be deployed in the field. They will have a jointed-pipe depth rating of 14,000 ft and 400,000-lb hook loads. With coiled tubing, they will have a depth rating of 10,000 ft and 200,000-lb hook loads.

Challenges remain

Coiled tubing. Currently, there are only two coiled tubing suppliers in the world and transport of the pipe adds to the cost. In addition, coil life is a concern although this is somewhat mitigated by the amount of time saved (4 to 5 days on a 15 day hole drilled conventionally). Time is money. For wells to 2,100 ft (640 m), drilling time reduces to 12 hours with coil from 20 hours with conventional pipe.
Mud programs. Because of rapid deployment of coil technology and
the unprecedented penetration rates, operators unfamiliar with the technology can run into problems at mud-up points when they are planned for the intervals that have been historically used for conventional drilling. This can lead to the hole not being properly conditioned at total depth, resulting in difficulty getting logs to the bottom. New designs in mud programs must address the penetration rates achieved with coil technology.
Logging problems. Caliper logs indicate that coil tends to drill a more-gauge hole. In certain situations, when the hole gauge is that accurate, running logs can be more difficult. Again, careful planning of the mud program and system is required. In instances where difficulty with logging occurs, operators can use coil to run a shuttle log to bottom to push through areas where wireline cannot normally run.
S-curve drilling. The major hurdle for coiled tubing drilling to overcome, particularly in the United States market, relates to S-curve drilling. A number of companies are working on rotary steerable tools but much of the equipment has been developed for use in conventional drilling. Coil requires different applications because, in the slide sections, coil cannot rotate. This is a rapidly developing market that should capture the attention of directional drillers.

In many situations, directional drilling tools cause a “tacking” situation when drilling a straight hole after drilling a tangent using a mechanical orienter. On directional wells, operators might have to set up with ratchet-type orienters, which drop into the target in a manner resembling a curved hockey stick blade, starting to one side and dropping into the target area in one motion to prevent the tacking mode.

Conclusion
The use of COTD drilling technology has come very far in a very short time. COTD rigs can drill to 14,000 ft as effectively as the best conventional drilling rigs. Further technological advances may lead to use of 4-in. coil. Coil drillers looking toward the future see unlimited opportunities right now. COTD technology is creating a paradigm shift in drilling throughout North America. Hybrid rigs operate with speed, safety, flexibility and costs savings. Coil is next-generation drilling.

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