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Summary Coiled-tubing (CT) services are frequently used to conduct kill operations concentric to existing production tubulars. Kill operations are typically performed to effect a temporary hydrostatic balance of formation pressure at the exposed completion. Because CT well-control operations are conducted concentric to existing production tubulars, special attention to job design and implementation is critical to ensure proper placement of kill fluids within the wellbore to achieve the desired pressure balance and to minimize the potential of formation damage. In those cases in which wellbore operations subsequent to the kill program are not intended to return the existing completion to active status, formation damage induced by the kill practice is typically of little consequence. However, when return of the existing completion to active status is desired, the well-control operation must be conducted with a complete understanding of the pressure balance and effect of kill fluid circulation on the completion. Many practices used in performing concentric-tubing well-control services lead to varying degrees of formation damage and impair completion flow performance. This paper discusses typical damage mechanisms resulting from completed wellbore kill programs, along with the related formation damage consequences for these types of operations, alternative well-control kill processes with CT, and the potential for reducing formation damage with CT well-control processes. In addition, recommendations for planning and implementing CT-conveyed well-control programs within existing production tubulars are provided to guide the user in conducting well-control operations with minimal induced formation damage. Introduction During the life cycle of a conventional completion, operations within the wellbore may be necessary that require the formation pressure to be hydrostatically balanced to achieve zero well pressure at the surface. For these types of operations, well-control practices described as "kill programs" are employed to replace the existing wellbore fluids with a column of liquid that has a sufficient density to create a hydrostatic balance with the formation pressure. This well-control operation can be performed in several ways with various fluid rheology types and densities, depending on the operation to be conducted subsequent to the kill program. In general, conventional well completions are constructed with concentric tubulars assembled to achieve a desired function within the wellbore. During installation of the completion, the tubing provides a flow path for the circulation of pumped fluids from the surface. However, once the completion tubing is pressure-isolated downhole, by packers or other flow-control devices, the circulation pathway to the completion may not be available, depending upon the confines of the tubing design. If circulation of the wellbore fluids is not possible, a well kill-pumping technique described as "bullheading" may be used. This well-control operation is performed by pumping the killweight density liquids through the surface wellhead at a rate sufficient to displace the fluids from the wellbore tubulars back into the open completion. Bullheading operations offer minimal control of fluids placement within the wellbore and have a high potential for inducing extraneous formation damage. If the operations conducted after the well-control program do not require continued service from the completion interval, formation damage mitigation is not a major concern, and the bullhead kill method is a viable option. When the well-control operation is intended as a temporary pressure-balance condition, the design of the well-kill program should focus on performing the kill with a minimum of induced formation damage. In this situation, concentric-tube well-intervention services have been used successfully to establish the fluids circulation flow path from the surface to the completion. With this type of service, the kill operation can be performed by circulating out existing wellbore fluids and replacing the wellbore volume with a kill-weight liquid having the desired rheology and density for the prescribed service. In conjunction with selection of the proper kill-weight fluid type, the kill-fluid circulation method has the highest potential for reducing induced formation damage through proper placement of the kill fluid and tailoring the pump circulation rate for minimal frictional pressure losses within the wellbore annuli. However, the effectiveness of the fluid-circulation program is also dependent on the type of concentric-tube well-intervention system selected. A comparison of the two types of concentric-tube well-intervention systems is offered in the following sections. Concentric-Tube Well-Intervention Services In general, well completions are designed with considerations for performing either wireline or tubing-conveyed through-tubing intervention services over the planned life cycle of the wellbore. Tubing-conveyed, through-tubing well-intervention services, such as hydraulic workover (HWO) and CT, provide a means for pumping and circulating fluids within existing wellbore tubulars, and both services can be performed with surface well pressure present. Although both the HWO and CT systems are capable of performing fluid-pumping operations within existing completion tubulars, a comparison of these two systems in well-control operations reveals that CT services provide additional benefits when compared to HWO services. By design, CT services use a continuous-length tubing string that can be deployed and retrieved throughout the prescribed operation without interrupting pumping services. The continuous-pumping capability of CT provides for a high degree of fluid placement control within the wellbore, allowing the kill program to be designed in the manner best suited to achieve the desired hydrostatic pressure balance. In contrast, the HWO system uses jointed tubing and must interrupt pumping services when making and breaking connections. By eliminating the need to make and break connections, the CT string can be deployed and retrieved rapidly in comparison to HWO systems, reducing the time needed to perform the desired intervention service. In addition, with the introduction of higher yield-strength CT grades, the upper pressure limits for safely performing CT services have increased dramatically.
The CT injector is the equipment component used to grip the continuous-length tubing and provide the forces needed for deployment and retrieval of the tube into and out of the wellbore. Figure 1.5--CT injector and typical well-control stack rig-up (courtesy of SAS Industries Inc.). The tubing guide arch assembly may incorporate a series of rollers along the arch to support the tubing or may be equipped with a fluoropolymer-type slide pad run along the length of the arch. The tubing guide arch should also include a series of secondary rollers mounted above the CT to center the tubing as it travels over the guide arch. The number, size, material, and spacing of the rollers can vary significantly with different tubing guide arch designs. For CT used repeatedly in well intervention and drilling applications, the radius of the tubing guide arch should be at least 30 times the specified OD of the CT in service. This factor may be less for CT that will be bend-cycled only a few times, such ...
Kang, B. I. (Korea National Oil) | Murugappan, B. S. (Korea National Oil) | Kwon, O. K. (Korea National Oil) | Sinn, G. J. (Korea National Oil) | Foster, I.. (Weatherford) | Robinson, L.. (Weatherford) | Elliott, J. B. (Halliburton) | Hampson, R.. (Halliburton) | McKinnon, B. L. (Halliburton)
Abstract This case study examines the techniques required to recover a coiled-tubing (CT) fish from a live condensate well (using CT) without actually killing the well. These procedures were recently implemented offshore Vietnam, where an extremely fluid-sensitive formation prevented killing the well because the formation would not likely have recovered. Using the techniques described in this paper, a 1.50-in. (38.1-mm) CT fish 9,177 ft (2797 m) long was successfully recovered from a well while keeping the well on production throughout the operation. This was achieved using temperature-setting gel as an isolation barrier against wellbore pressure in the fish, which saved the customer the approximately USD 20 million in costs associated with the alternative solution of drilling a new well. This paper outlines the equipment required and factors to consider while designing the job, as well as describing the surface handling procedures once the fish is brought to surface. Particular problems with operating in a live condensate well are also highlighted. Finally, safety methods will be discussed throughout the paper to maintain a dual barrier against wellbore pressure during all phases of the job, including the use of gel as an isolation barrier.
The coiled tubing (CT) injector is the equipment component used to grip the continuous-length tubing and provide the forces needed for deployment and retrieval of the tube into and out of the wellbore. Figure 1 illustrates a typical rig-up of a CT injector and well-control stack on a wellhead. There are several types of counter-rotating, chaindrive injectors working within the industry, and the manner in which the gripper blocks are loaded onto the tubing varies depending on design. These types of injectors manipulate the continuous tubing string using two opposed sprocketdrive traction chains, which are powered by counter-rotating hydraulic motors. Figure 1--CT injector and typical well-control stack rig-up (courtesy of SAS Industries Inc.).
The service reel serves as the coiled tubing(CT) storage apparatus during transport, and as the spooling device during CT well-intervention and drilling operations. The inboard end of the CT may be connected either to the hollow segment of the reel shaft (spoke and axle design), or to a high-pressure piping segment (concave flange plates), both of which are then connected to a high-pressure rotating swivel. This high-pressure fluid swivel is secured to a stationary piping manifold, which provides connection to the treatment-fluid pumping system. As a result, continuous pumping and circulation can be maintained throughout the job. A high-pressure shutoff valve should be installed between the CT and reel shaft swivel for emergency use in isolating the tubing from the surface pump lines.