Coiled tubing drilling. Many oilfield folks think coiled tubing is used only for well servicing work. However, Coiled Tubing Drilling (CTD) has been around for some time, and it is gaining daily in popularity, especially in certain critical applications.
The first US patent for CTD was issued in 1951 to G. D. Priestman, et al. The device included many of the features one finds today, including a drive system with opposing wheels that grip the pipe (motorized pipe benders and pipe straighteners), a reel with an electric motor driver, and a bottomhole assembly with a downhole motor above the bit.
In the 1960s, R. H. Cullen Research perfected armored, wire-wrapped flexible pipe that could be spooled with minimal effort. It was used to drill several wells up to 4,500 ft by 1969 before the project was suspended.
In the early 1970s, small-diameter coiled tubing was used for specialized remediation work in West Texas. The first units involved welded 3⁄4-in-OD pipe on spools much like enlarged wireline. The injectors were primitive, and several strings of this pipe were left in the hole. Sadly, once it dropped, the pipe “bird-nested” in the bottom of the well and was hard to fish. For many company men, using coiled tubing was a last resort.
In 1976, Canadian inventor Ben Gray finally developed the first true rigid-pipe CTD unit using 3,000 ft of 23⁄8-in-OD, welded X-42 line pipe. This larger diameter pipe was apparently capable of withstanding the forces from being alternately spooled and straightened as it entered the hole (also known as cycling). The unit drilled 20 shallow gas wells in Canada. CTD was highlighted in this magazine in March 1977 in an article titled “New rig concept.”
Since that time, CTD has become even more popular for a variety of reasons. One involves well control. There are no couplings or connections on this drill pipe, so kicks that plague “stick pipe” drilling rigs are not nearly as problematic. The packoff and quad-BOP arrangement makes controlling a kick a rather simple process—weight-up the mud a little and keep drilling.
Secondly, there are few problems with surge—sucking fluids from the formation while pulling pipe out of the hole. One can pump through the drillstring while pulling. As long as the pump rate meets or exceeds the void rate, the hole stays full with constant bottomhole pressure. This, of course, makes tripping ever so much faster with coiled pipe than with conventional drillpipe. However, one must be concerned about surge pressures while tripping back in the hole.
Pipe handling is much safer and it requires fewer people, an average of two less vs. a conventional drilling rig. The pipe has no connections, so there is no time expended breaking-out and making-up connections. Also, there is no need for a derrick to rack thribbles or fourbles. Clearly, there is less rig personnel exposure, so there are fewer injuries. While the pipe can be spooled, the BHAs must be handled conventionally. There are no coiled drill collars (yet), and wrapping a motor or an MWD/LWD tool around a reel would probably reduce its operating life dramatically.
Snubbing or stripping pipe into or out of a pressured well is simple and safe using coiled tubing. The injector head can perform both jobs, and the packoff can hold moderate surface pressures. Again, this is fine until the BHA reaches the surface.
CTD has some obvious drawbacks. The most serious is that the pipe cannot turn, so all downhole rotary motion must be provided by motors or turbines. This also means that all directional work must be performed by slide drilling using some device that can change the tool face without turning the pipe, such as an indexing tool. This tool uses pump pressure impulses to turn the directional tools a fraction of a rotation. Once the tool face is properly oriented, the tool locks until subsequent course corrections are needed.
Another drawback is drillpipe life. Each time the pipe is rolled off the spool, over the gooseneck, into the hole and back out again, the pipe is bent and straightened several times. Flexible pipe can only withstand so much of this “cold” work before it becomes fatigued and unusable for heavy service. Thus, every section of each string must be monitored continuously for the number of cycles it has undergone.
So what happens when the drillstring gets stuck and the company man wants to “work” the pipe? One small section of the total pipe length can become fatigued, requiring its removal if the rest of the string is still usable. Unfortunately, this usually leaves a shortened string or a weld in the middle of the string that derates the pipe string from that point down.
Yet another problem involves a hole in the drillstring. If a hole develops in a conventional joint of drill pipe, the joint is identified and simply laid down to be replaced by another joint. With coiled tubing, the problem is considerably more difficult to solve. It usually results in a field weld, since nobody has figured out a way to patch the hole yet (or to deal with the stress raiser resulting from the defect in the string).
Various concepts to combat these major problems have been hatched over the years. One idea, which evolved into a few rigs, is to rotate the entire reel while drilling to permit the coiled tubing to be turned in the hole. Unfortunately, when one puts a heavy weight such as an entire spool of coiled tubing on a track and starts rolling it around a central axis, very high inertial forces are generated.
Another concept is to weld a connector onto each end of a length of coiled tubing that could be disconnected after the pipe was run in the hole. The pipe hanging in the well could then be made up to a “kelly,” allowing the string to rotate since it would no longer be connected to the reel. Additional “joints” could be added as drilling continued. Once at depth, the pipe could be reconnected to the reel and spooled in and out of the hole for trips. This would marry the strengths of coiled pipe and “stick” pipe, while diminishing the flaws in each.
Despite drawbacks, coiled tubing is predicted to become even more popular over time. With improved directional steering tools and telemetry, and recognizing the high cost of large conventional drilling rigs, CTD is bound to flourish.
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