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.
Injection assembly | Oil & Gas Engineering Books
Th injector assembly is designed to perform three basic functions:
- Provide the thrust required to snub the tubing into the well against surface pressure and/or to overcome wellbore friction forces.
- Control the rate of lowering the tubing into the well under various well conditions.
- Support the full weight of the tubing and accelerate it to operating speed when extracting it from the well.
Fig. 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.
Fig. 1—CT injector and typical well-control stack rig-up (courtesy of SAS Industries Inc.).
The fundamental operating concept of the counter-rotating, opposed-chain injector is one that utilizes drive chains fabricated with interlocking gripper blocks mounted between the chain links (Fig. 2). These types of gripper blocks are designed to minimize damage to the CT and may be machined to fit the circumference of the CT string or formed in a “V” shape to accommodate variable outer diameter (OD) sizes of CT (Fig. 3). The chaindrive assembly operates on the principle of frictional restraint, in that the CT is loaded by the opposing gripper blocks with sufficient magnitude of applied normal force that the resulting tangential friction forces are greater than the axial tubing loads (tension or compression).
Fig. 2—Typical CT injector-drive-chain system (courtesy of SAS Industries Inc.).
Fig. 3—Typical CT gripper-block configurations (courtesy of SAS Industries Inc.).
In all traction-loading systems, hydraulic cylinders are used to supply the traction pressure and subsequent normal force applied to the CT (Fig. 4). The primary means of applying hydraulic pressure to this circuit may be through pumps on the prime mover, air-over-hydraulic pumps, or manual hand pumps. In addition, chain-loading systems require an emergency pressure source to maintain traction in case of a loss of hydraulic pressure supply. Typically, this system consists of an accumulator and a manual hydraulic pump or air-over-hydraulic pump located in the control cabin.
Fig. 4—Cutaway view of injector-drive assembly (courtesy of SAS Industries Inc.).
It is critical that the injector be equipped with a weight indicator that measures the tensile load in the CT (above the stripper), with the weight measurement displayed to the equipment operator during well intervention or drilling services. There should also be a weight indicator that measures the compressive force in the tubing below the injector when CT is being thrust into the well (often referred to as negative weight). Some weight indicators are capable of measuring a limited amount of negative weight—typically equal to the weight of the chaindrive assembly mounted in the injector frame. If this type of weight indicator is being used, the thrust force applied during the CT operation should not exceed the weight of the chaindrive assembly.
Tubing guide arch
The counter-rotating, opposed-chaindrive injectors used in well intervention and drilling operations utilize a tubing guide arch, located directly above the injector. The tubing guide arch supports the tubing through the 90°+ bending radius and guides the CT from the service reel into the injector chains. 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 as in permanent installations. The continuous-length tubing should enter and exit the tubing guide arch tangent to the curve formed by the guide arch. Any abrupt bending angle over which the CT passes causes increased bending strains, dramatically increasing the fatigue damage applied to the tubing. During normal CT operations, the reel tension applies a bending moment to the base of the tubing guide arch. Therefore, the tubing guide arch must be designed to be strong enough to withstand the bending caused by the required reel back tension for the applicable tubing size.
The injector should be stabilized when rigged up to minimize the potential for applying damaging bending loads to the well-control stack and surface wellhead during the well-intervention program. The injector may be stabilized above the wellhead using:
- Telescoping legs
- An elevating frame
- A mast or rig-type structure
The injector support is the means provided to the injector to prevent a bending moment (such as reel back tension) from being applied to the wellhead of such magnitude as to cause damage to the wellhead or well-control stack under normal planned operating conditions. Precautions should be taken to minimize the transfer of loads resulting from:
- The weight of the injector
- Well-control equipment
- The hanging weight of the CT into the tree along the axis of the wellhead
Telescoping legs are generally used in rig-ups where the height of the injector or wellhead does not permit the use of an elevating frame. When telescoping legs are used, the top sections are inserted into the four cylinders located on the corners of the injector frame and then secured with pins at the required height.
Footpads are placed beneath each telescoping leg to distribute the weight of the injector to the surface grade. Further stiffness of the legs is achieved by tightening the turnbuckles mounted beneath the leg sections. When telescoping legs are used, the weight and operating forces of the injector and well-control stack assembly are transferred directly to the wellhead, requiring that the rig-up load be supported with a crane or traveling block to minimize the load applied onto the wellhead.
In rig-up scenarios where an unobstructed surface is available (e.g., offshore platforms), it is recommended to support the injector using a hydraulically or mechanically controlled elevating frame structure. Once the desired height of the stand is achieved, the four legs on the perimeter of the stand are pinned and secured in place. The base of the elevating frame distributes the weight of the injector evenly around the perimeter of the frame. The benefits of using an elevating frame over the telescoping legs include greater stability, latitude in releasing the overhead crane support in noncritical service, and safety.
Requirements when using a mast
In rig-up scenarios in which a mast or derrick is required, precautions must be taken to minimize the axial load placed on the wellhead by the injector and well-control stack. In addition, the injector should be secured in some fashion within the mast or derrick to minimize the pitch and yaw motion of the injector during service.