Coil Pipe Assemblies

Coil Pipe Assemblies

Coil Pipe Assemblies

A coil pipe is a long metal pipe, normally from 1 to 3.25 in (25 to 83 mm) in diameter, supplied spooled on a reel. It is typically used in interventions in oil and gas wells.

Coiled tubing can be used for pumping chemicals, or deliquification of hydrostatic heads in depleted gas wells that inhibit formation fluid flow. It also is useful in circulation operations, which lift liquids to the surface.

Coiled Tubing

Coiled tubing is a pipe used for downhole operations in the oil and gas industry. This specialized type of tubing has several advantages over conventional wireline methods, including strength and rigidity, which allows it to be pushed and pulled into a well and circulate treatment fluids. It also can be used to push or pull tools down a well to fish for lost equipment or clear a wax plug.

While coiled tubing can be used for other downhole operations, it is commonly used for drilling and completion operations. Unlike wireline, which has the disadvantage of requiring a heavy toolstring to be lowered into a well, coiled tubing can be pushed or pulled down a well by gravity alone. This can be a significant advantage on highly deviated or horizontal wells, where gravity is not enough to pull the toolstring down.

In addition to its use for drilling and completion operations, coiled tubing is also used in workover operations on producing wells. It can be pushed down the well to unload the bottomhole pressure, and then it can be run back up again to replace broken equipment or clean out the well.

For these operations, coiled tubing must be pumped with a large amount of fluid. This is often water, but it can also contain chemicals that are pumped into the coiled tubing to help with the operation.

A coiled tubing unit typically contains a control cab, a reel trailer and sometimes a chemical trailer. The control cab is where the operator and supervisor sit and controls the operation with hydraulic or electronic controls. Most coiled tubing units also have satellite dishes and touchscreen controls so they can send real-time job data to the surface.

Depending on the application, coiled tubing can be pumped with nitrogen or other chemicals to help it run smoothly and safely. Many units also have heating systems to prevent the chemicals from freezing during cold weather.

A coiled tubing intervention can be deployed through a production tube or casing to unload a well in a time frame that is comparable to a wireline job. This is an important benefit, since it allows operations to be carried out while production is ongoing. It also minimizes the risk of destroying formation pressure and damaging formation rock.

Injector Head

During the drilling and production of oil and gas wells, coiled tubing may be fed into or withdrawn Coil Pipe Assemblies from the well using a coiled tubing injector head. Injector heads vary from manufacturer to manufacturer, but most of them are comprised of a pair of opposing endless chains loops that carry a plurality of gripper blocks that are pressed against and grab generally opposed sides of the coiled tubing when it is inserted therebetween.

The coiled tubing injector head can then be moved within a wellbore to perform a wide variety of tasks including placing chemical treatments or operating tools to rectify or enhance the well bore. However, as the tubing diameter changes throughout the course of a wellbore’s lifecycle, the means of gripping the tubing must change to accommodate a new diameter, causing the injector head to become heavy and difficult to manipulate.

As a result, a method of automatically adjusting the tension of a chain in an injector head used in coiled tubing systems includes applying a force to a floating bottom sprocket to maintain a chain loop at a desired chain tension and preventing the floating bottom sprocket from moving toward the first end of the chain loop using a mechanical stop. Automatically adjusting the tension of the chain loop prevents the floating bottom sprocket from allowing the chain to bind and/or wear, and also prevents the coiled tubing from being deformed on passing through the injector head.

Further, the multifunctional links of the chain loops obviate the need to provide the conventional pair of roller chains with a gripper block mounted therebetween that is required to handle a different tubing diameter. This increases the life and efficiency of the coiled tubing, reducing the chance of tubing failure as it passes through the injector head, and allows for a narrower chain loop in an injector head that uses three or four driven chains.

The coiled tubing injector head of the present invention is comprised of a plurality of halves 202, 204 containing an endless chain 22, a plurality of gripper block assemblies 40, a drive sprocket 28, a plurality of idler sprockets 27, a tensioning cylinder 37, a plurality of traction cylinders 21, a bearing skate 34 and a drive motor (not shown). As is known to one skilled in the art, the selection and sizing of these components is entirely within the scope of the present invention.

Bottom Hole Assembly

The Bottom Hole Assembly (BHA) is a key component of the drill string, providing force for the bit to break the rock, survive a hostile mechanical environment and provide directional control. This assembly is typically composed of a down hole motor, a rotary steerable system (RSS), measurement and logging while drilling tools as well as other specialized devices.

A BHA is designed to function in a variety of different formations; ranging from simple vertical wells where there is little or no LWD requirements to complex directional wells that require multi-combo LWD suites. The specific application and the wellbore are important factors in deciding which components will be placed within the BHA.

Stabilizers are a key element in most BHA designs as they allow for the driller to build angle and control side force while still maintaining the ability to slide or rotate. Most stabilizers are placed within the first 120 feet of the drillstring; stabilizer diameter and placement are based on the desired build, drop or hold angle.

Packers are also an important aspect of most BHA designs as they provide the necessary axial set-down force to seal against the casing. These sealing elements are generally more difficult to set with coiled tubing as they require large forces to axially compress and then seal the casing.

Active centralization is an important feature of many BHA designs as it helps ensure that the packer and anchor assemblies are concentrically aligned within the casing when they are set. This can improve the effectiveness of the sealing elements and prevent deformation of the soft rubber element 212 due to pressure increases.

In one illustrative embodiment, the anchor assembly 300 is moved between a set position and an unset position by an increase in hydraulic pressure within the BHA to a predetermined amount. The mandrel assembly 300 is then slid axially within the anchor housing to engage a plurality of anchor slips extendable from the anchor housing. The release assembly may selectively retain the anchor slips 310 in the unset position until a valve 501 is closed and the mandrel assembly is moved back to the set position.


The BOP (Blowout Preventer) assembly is installed to prevent an accident during coiled tubing operations. It consists of several different components which are connected by a series of hoses. The piping in the BOP system is designed to withstand well bore pressure. The pressure in the piping will vary based on the size of the coil and the operating conditions.

Typically, the BOP stack consists of four rams: blind rams to close in a well, shear rams to shear pipe, slip rams to hold pipe in place, and Coil Pipe Assemblies a pipe ram to seal the pipe around. These rams are usually made from a pliable elastomer. They are actuated by a four-way valve that is usually located some distance away from the wellbore.

In older quad BOPs, a ram is needed for each function (blind, shear, slip, and pipe). Newer dual BOPs combine some of these functions into one ram (shear-blind, pipe-slip). The shear rams in a dual BOP can be made to cut coiled tubing with high pressure, while the other rams in the BOP can shear the drill pipe with a low pressure.

When a coiled tubing operation is completed, the operator should shut down all of the rams in the stack and remove any shearing tools that are attached to them. This will ensure that the pipe does not shear and cause an explosion while the tubing is still in the well.

After the rams are closed, the pliable elastomer packings will seal off the well. This will prevent oil, gas, or water from entering the well and the rig floor.

On some jobs, a secondary accumulator system is used to provide the needed accumulated pressure for the operation. These systems have their own pumps and power supply plus a large number of accumulator bottles that are connected through hoses or hard piping to the BOPs.

The accumulator system is typically placed some distance away from the wellbore so that it can be easily reached in an emergency event. The accumulator system is controlled by a separate four-way valve that is normally mounted on a skid.