Introduction to Coiled Tubing
Coiled tubing drilling (CTD) has been utilized on a commercial basis for many years, and can provide significant economic benefits when applied in the proper field setting. In addition to potential cost advantages, CTD can provide the following additional benefits:
- Safe and efficient pressure control
- Faster tripping time (150+ ft/min)
- Smaller footprint and weight
- Faster rigup/rigdown
- Reduced environment impact
- Less personnel
- High speed telemetry (optional)
In general, CTD can be divided into two main categories consisting of directional and non-directional wells. Non-directional wells use a fairly conventional drilling assembly in conjunction with a downhole motor. Directional drilling requires the use of an orienting device to steer the well trajectory, per the well plan. CTD can then be further segmented into over-balance and under-balanced drilling applications.
Bit design and selection for CTD follows the same theory as is used in conventional rotary drilling. However, CTD generally uses higher bit speeds at lower weight on bit as a result of the structural differences in CT versus jointed pipe.
Non-directional wells represent the largest CTD application, and these are defined as a well that lacks downhole tools to control direction, inclination and/or azimuth. Much of the CTD work performed to date involved shallow gas well development in Canada, but it has also been used for shallow water injection wells and for "finishing" operations. A primary advantage that CTD provides in this application is the speed of the rig up/down operation, and the continuous rate of penetration (no delays to add stands of jointed pipe).
The majority of this CTD work has been performed with hole sizes less than 7 in., but hole sizes up to 13 3/4 in. have been successfully drilled. Much the same as in conventional drilling, drill collars can be used in low angle wells to control inclination build-up and apply weight on bit for CTD applications.
This type of CTD application utilizes an orienting device in the bottomhole assembly (BHA) to control the wellbore trajectory as desired. CTD for this application can include new wells, extensions, side-tracks through existing completions, horizontal drainholes, or side-tracks where the completions are pulled. However, the primary use of CTD for directional wells is to directionally drill into new reservoir targets from existing wellbores.
Directional drilling with CT has some fundamental differences compared to conventional rotary drilling techniques. One of the basic differences is the need for an orienting device to control the well trajectory, since CT cannot rotate. Orienting devices control hole direction by rotating a bent housing to a particular orientation (toolface) or controls the side loading at the bit to push the assembly in a particular direction. This control over the BHA provides directional control for CTD applications.
A steering tool is used to measure inclination, azimuth, and tool face orientation. Two basic types of steering tools are used for directional drilling with CT. Electric steering tools are used in conjunction with a cable inside the CT to transmit data to surface. Mud pulse tools comprise the second type of steering device for CTD applications. Mud pulse steering tools transmit data to the surface by generating pressure pulses in the mud.
In addition to orientation and steering devices, some BHAs utilized for CTD are equipped with additional measurement tools, including gamma ray, casing collar locator, accelerometers (shock load measurements), pressure (internal and annulus) and weight on bit.
Wellbore Hydraulics and Wellbore Fluids
There are some key fluid design parameters to keep in mind for CTD applications versus traditional rotary drilling. For example, all CTD operations require the fluid to travel through the entire tubing string regardless of the current drilling depth. In addition, the frictional pressure loss for CT on the reel is considerably larger than for straight tubing. Thus, for optimum hydraulic performance, the drilling fluid must behave as a low viscosity fluid while inside the CT, and as a high viscosity fluid in the annulus (for efficient cuttings removal).
Another key difference associated with CTD is the absence of tubing rotation while drilling. Jointed pipe is rotated during conventional drilling operations, and this movement helps keep the drill cuttings suspended in the drilling fluid, so they can be lifted to surface. Since the tube doesn't rotate in CTD applications, hole cleaning can be more challenging in heavily deviated/horizontal applications. This effect is partially offset by the smaller cuttings produced with CTD (higher RPM, lower weight on bit). In addition, special visco-elastic fluids have been developed for CTD, that change their rheology according to the local shear rate, i.e., become more viscous in the annulus (lower shear rate) to improve cutting suspension.
As with conventional well drilling operations, the drilling fluid is used for controlling subsurface pressure and the CTD drilling fluid systems are typically smaller versions of conventional systems. Conventional well control principles apply except that the CT string limits the fluid flow rate and the frictional pressure loss varies with the ratio of tubing on/off the reel.
To date, most underbalanced CTD activity has been for re-entry operations, but new wells could also benefit from this approach. CTD is ideal for this underbalanced applications because of it's inherent well control system. In addition, underbalanced "finishing" is a variation of underbalanced drilling used extensively in Canada and gaining acceptance in other areas. For finishing operations, a conventional rig is used to drill to the top of the reservoir and casing is run. From this point, CTD is utilized to drill into the reservoir with underbalanced drilling techniques. This technique attempts to leverage the respective strengths of both drilling approaches. Conventional drilling can be faster (less expensive) in the large diameter, unproductive uphole drilling intervals, while underbalanced CTD is faster (less expensive) in the producing interval. CTD is also better suited to deal with the pressure/produced hydrocarbons from the productive interval.