Coiled tubing commonly has a diameter of 1 to 2 in. and may range in length from 2,000 to more than 20,000 ft [610 to 6,100 m], depending on spool size. Continuous lengths of tubing obviate connecting one joint of pipe to the next while tripping into the well. With no need to make or break connections between joints, CT permits continuous circulation while running in or out of the hole. Continuously circulating during well treatment enhances flow control, and this capability is a primary reason for using CT in live-well interventions.
Completion or remedial operations increas - ingly employ CT to improve well performance through perforating, stimulation treatments or removal of pipe scale and debris. The CT string sometimes serves as a production string in shallow gas wells and has even been utilized in certain drilling and cementing operations. Its strength and rigidity, combined with the capability to circulate treatment fluids, offer distinct advantages over wireline tools during workover operations.1
Coiled tubing jobs can be grouped into three broad categories: conveyance or placement of tools, conveyance or placement of fluids, and completion operations. Tool conveyance—Its strength and rigidity enable CT to push or pull equipment and tools through highly deviated or horizontal wellbores and restrictions, or even push obstructions beyond the zone of interest. Coiled tubing has proved capable of conveying tools downhole in a wide range of assignments.
In zonal isolation applications, the operator must set plugs or packers to mechanically isolate a particular interval within a wellbore. Operators frequently employ coiled tubing to convey and place bridge plugs and mechanical, hydraulic or inflatable packers.
Cleanout operations require a means of removing scale buildup or fill material that can threaten production by restricting flow through tubing or casing.2
One approach is to run CT into
the well with a removal tool to wash away the material (above right). One example, the Blaster tool, is a rotating high-pressure jetting assembly that forcefully sprays solvents, acids or abrasive
1. For more on CT applications: Boumali A, Brady ME, Ferdiansyah E, Kumar S, van Gisbergen S, Kavanagh T, Ortiz AZ, Ortiz RA, Pandey A, Pipchuk D and Wilson S: “Coiled Tubing: Innovative Rigless Interventions,” Oilfield Review17, no. 4 (Winter 2005/2006): 29–41.
2. Ali A, Blount CG, Hill S, Pokhriyal J, Weng X, Loveland MJ, Mokhtar S, Pedota J, Rødsjø M, Rolovic R and Zhou W: “Integrated Wellbore Cleanout Systems: Improving Efficiency and Reducing Risk,” Oilfield Review17, no. 2 (Summer 2005): 4–13.
Coiled tubing Jetting nozzle Fill
> Sand removal. Pressure from a surface pump forces fluid through a specially designed jetting nozzle to blast away sand, scale or other fill material.
fluids to remove scale or clean downhole screens and perforations.
Coiled tubing technology also extends to well perforating operations. Shooting holes through tubing and casing to produce a well is generally achieved by downhole explosives deployed in special perforation guns. In many cases, perforating guns are run into a well on wireline. However, because wireline tools are dependent on gravity to reach the target zone, this approach may not be possible in horizontal or highly deviated wells. And formation pressure can work against wireline tools in underbalanced wells, pushing the guns uphole and kinking the cable or even sticking the guns.
For these wells, the guns can be conveyed downhole at the end of conventional jointed tubing or coiled tubing. Either of these is stronger and more rigid than wireline, providing greater load capacity for the tubing, which translates into substantially longer gun strings and higher-angle deployments. Compared with jointed tubing, the CT option may offer advantages in speed when it comes to tripping in and out of the hole. Fluid conveyance—The capacity for circulating or injecting fluids makes CT especially suited for production kickoff, cleanout, cement - ing and stimulation applications.
Coiled tubing can play an important role in initiating production in a well. When drilling or workover fluids exert hydrostatic pressures that exceed formation pressure, reservoir fluids are prevented from entering the wellbore. Pumping nitrogen through the CT string and into the fluid column is a common method for kicking off
production by lowering hydrostatic pressure within the wellbore (below).
After the CT string is run to depth, nitrogen gas is pumped through the string and into the fluid column in the well. Nitrogen reduces the density of the hydrostatic column. Once the hydrostatic pressure of the fluid column drops below reservoir pressure, the well can begin to flow. In some cases, the same effect can be gained by circulating a light liquid, such as diesel, instead of nitrogen gas.
Nitrogen gas
Reservoir pressure
> Nitrogen kickoff. Some wells need help to get started. Injecting nitrogen into the well reduces pressure imposed by completion or kill fluids, thus permitting reservoir fluids to flow into the wellbore.
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Hydrostatic pressure
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