Coiled Tubing Assembly

Abstract

A coiled tubing assembly includes coiled tubing conveyable into a wellbore, a rotational device operatively coupled to the coiled tubing, a rotatable tubing segment operatively coupled to the rotational device, and a bottom hole tool arranged at an end of the rotatable tubing segment opposite the rotational device. The rotational device rotates the rotatable tubing segment relative to the coiled tubing as the coiled tubing, the rotatable tubing segment, and the bottom hole tool are axially displaced along the wellbore.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority of U.S. Provisional Application Ser. No. 62/690,673, filed Jun. 27, 2018 and U.S. Provisional Application Ser. No. 62/657,308, filed Apr. 13, 2018, the disclosures of which are incorporated herein by reference in their entireties.

BACKGROUND

In the oil and gas industry, coiled tubing (alternately referred to as “coil tubing,” “endless tubing,” or “reeled tubing”) can be used to conduct various downhole operations and applications. Unlike drill pipe, which requires introducing relatively heavy and diameter-varying sections of jointed pipe into a wellbore, coiled tubing comprises a continuous length of flexible or semi-flexible pipe having a relatively consistent diameter along its full length that is unwound from an adjacent reel (spool) and progressively introduced into the wellbore.

One limiting factor in coiled tubing applications, particularly in “non-vertical” wells, such as horizontal or deviated wells, is the depth to which coiled tubing can advance before it buckles. More particularly, coiled tubing is traditionally “pushed” from a surface location into the wellbore. Upon entering a non-vertical section of the wellbore, gravitational forces urge the coiled tubing against the inner wall of the wellbore, which results in the generation of frictional resistance as the coiled tubing rubs against the wellbore wall. Advancing the coiled tubing further into the non-vertical section increases the frictional forces, which may eventually surpass the compressive limits of the coiled tubing and cause the coiled tubing to buckle. Advancing the coiled tubing even further after buckling could end up locking the coiled tubing within the wellbore.

One way to increase the reach of coiled tubing is to increase the diameter and/or wall thickness of the tubing. However, this leads to heavier tubing and imposes limitations on the length of the coil due to size restrictions of the reel. Consequently, it is often required to use jointed pipe (e.g., drill pipe, etc.) to reach non-vertical portions of some wellbores. Jointed pipe, however, must be snubbed under pressure to enter the wellbore, which creates significant risks for rig personnel and the surrounding environment. Coil tubing is easier to snub in and out of a well due to consistent outside diameter. However, due to reduced wall thickness and weight as compared to conventional jointed pipe, coiled tubing has limits with regard to distance it can be advanced through a horizontal section of the wellbore. Friction in the horizontal section of the wellbore, between the tubing and wellbore wall, limits additional advancement and is often a key factor determining the maximum length for constructing the horizontal wellbore section. What is needed, therefore, is a way to advance coiled tubing further into non-vertical portions of a wellbore while mitigating the risk of buckling or lock-out.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure.

FIG. 1 is a schematic diagram of an example well system that may employ one or more principles of the present disclosure.

FIG. 2 is an enlarged schematic view of the coiled tubing assembly of FIG. 1, according to one or more embodiments.

FIG. 3 is another enlarged schematic view of the coiled tubing assembly of FIG. 1, according to one or more additional embodiments.

FIG. 4 is another enlarged schematic view of the coiled tubing assembly of FIG. 1, according to one or more additional embodiments.

DETAILED DESCRIPTION

The present disclosure is related to coiled tubing intervention operations and, more particularly, to coiled tubing that incorporates one or more rotational devices that help reduce friction against wellbore walls and thereby mitigate buckling of the coiled tubing in non-vertical sections of a wellbore.

Embodiments discussed herein describe a coiled tubing assembly that combines the operational safety of coiled tubing with the extended reach capabilities of jointed pipe. More specifically, the coiled tubing assembly may include coiled tubing conveyable into a wellbore, and a rotational device operatively coupled to the coiled tubing. A rotatable tubing segment may be operatively coupled to the rotational device, and a bottom hole tool may be arranged at an end of the rotatable tubing segment opposite the rotational device. In operation, the rotational device may rotate the rotatable tubing segment relative to the coiled tubing as the coiled tubing, the rotatable tubing segment, and the bottom hole tool are axially displaced along the wellbore. In some applications, this may reduce the friction generated by the coiled tubing rubbing against the wall of the wellbore and may allow the bottom hole tool to be advanced deeper into the wellbore with a reduced risk of buckling the coiled tubing.

FIG. 1 is a schematic diagram of an example well system 100 that may employ one or more principles of the present disclosure, according to one or more embodiments. As illustrated, the well system 100 may include a wellbore 102 that extends from a surface location 104 and penetrates one or more subterranean formations 106. The wellbore 102 may be drilled into the subterranean formation 106 using any suitable drilling technique and may extend in a substantially vertical direction away from the earth's surface 104 over a vertical wellbore portion 108. At some point in the wellbore 102, the vertical wellbore portion 108 may deviate from vertical relative to the Earth's surface 104 and transition into a substantially non-vertical portion, such as a horizontal wellbore portion 110. As used herein, “non-vertical” refers to a it) section of the wellbore 102 that may be horizontal, slanted, deviated, or extending at any angle offset from vertical relative to the surface location 104. While not depicted in FIG. 1, in some embodiments, the horizontal wellbore portion 110 may comprise a lateral wellbore that extends from a parent wellbore (i.e., the vertical wellbore portion 108).

In some embodiments, the wellbore 102 may be completed by cementing a string of casing 112 (or another type of wellbore liner) within the wellbore 102 along all or a portion thereof. In other embodiments, however, the casing 112 may be omitted from all or a portion of the wellbore 102 and the principles of the present disclosure may equally apply in an “open-hole” environment.

The well system 100 may also include a surface assembly 114, which may help facilitate one or more wellbore intervention operations or applications. In the illustrated embodiment, the surface assembly 114 comprises a coiled tubing deployment assembly operable to introduce coiled tubing 116 into the wellbore 102 for a variety of purposes and applications. As illustrated, the surface assembly 114 includes a truck 118 with a control cab 120 mounted thereto. The control cab 120 is the operational center used to operate the surface assembly 114 and may include a power pack, one or more hydraulic pumps, one or more air compressors, etc. A reel 122 (also referred to as a “spool”) may also be mounted to the truck 118 and the coiled tubing 116 may be wound onto the reel 122 for storage or deployment. In some embodiments, the reel 122 may include various fixtures, plumbing, conduits, valves, etc. that enable the coiled tubing 116 to convey a variety of fluids downhole and into the wellbore 102 for various purposes.

The coiled tubing 116 may enter the wellbore 102 by passing through an injector 124. More particularly, the coiled tubing 116 may be unwound from the reel 122 and conveyed over a gooseneck guide 126, which guides the coiled tubing 116 into the injector 124. The injector 124 may include hydraulic motors and counter-rotating chains designed to grip the exterior of the coiled tubing 116 and pull the coiled tubing 116 into the injector 124 and toward the wellbore 102. In some embodiments, the injector 124 may be configured to “push” the coiled tubing 116 into the wellbore 102 from the surface location 104.

A stripper 128 may be used to pack off between the coiled tubing 116 and the wellbore 102, and the injector 124 may further include or otherwise be coupled to a blowout preventer (BOP) 130 and a Christmas tree 132, which may regulate fluid pressure to safely inject the coiled tubing 116 downhole. In some applications, a crane truck 134 may provide lifting means for working at the surface location 104.

While the surface assembly 114 is depicted in FIG. 1 as a coiled tubing deployment assembly, the surface assembly 114 may alternatively comprise any type of installation or rig system capable of running the coiled tubing 116 into the wellbore 102. In other embodiments, for instance, the surface assembly 114 may comprise a drilling rig, a completion rig, a workover rig, or the like. In some embodiments, the surface assembly 114 may be omitted and replaced with a standard surface wellhead completion or installation, without departing from the scope of the disclosure. Moreover, in at least one embodiment, the coiled tubing 116 may comprise another type of tubing conveyable into the wellbore 102, such as jointed pipe (e.g., drill pipe, etc.). Furthermore, while the well system 100 is depicted as a land-based operation, it will be appreciated that the principles of the present disclosure are equally applicable to any offshore, sea-based, or sub-sea application where the surface assembly 114 may form part of a floating platform, a semi-submersible platform, or a sub-surface wellhead installation as generally known in the art.

The coiled tubing 116 may form part of a coiled tubing assembly 136 conveyed into the wellbore 102 to undertake various downhole operations. As illustrated, the coiled tubing assembly 136 may also include a bottom hole tool 138 (alternately referred to as a “bottom hole assembly”) arranged at or near the end of the coiled tubing 116. The bottom hole tool 138 may include, for example, one or more downhole tools or devices configured to carry out one or more downhole operations. Example downhole tools or devices that may be included in the bottom hole tool 138 include, but are not limited to, a cutting tool (e.g., a mill, a drill bit, etc.), a jetting tool (e.g., a nozzle assembly), a jarring device, one or more well screens, a wellbore isolation device (e.g., a wellbore packer), one or more wellbore sensors or gauges, a fishing tool, or any combination thereof.

In at least one embodiment, the bottom hole tool 138 may comprise a mill or milling assembly. In such embodiments, the milling assembly may be used to mill (drill) out one or more plugs positioned within the wellbore 102 as part of a multi-stage hydraulic fracturing operation. Milling the plug(s) enables the well to start producing hydrocarbons. In the process, the milling assembly may also inject a fluid into the wellbore 102 to clean out debris, proppant, and sand accumulation in preparation for hydrocarbon production. In other embodiments, the bottom hole tool 138 may comprise a drill bit used to extend the length (depth) of the wellbore 102.

As the coiled tubing assembly 136 advances into the horizontal portion 110 of the wellbore 102, gravitational forces will urge the coiled tubing 116 to engage and slide (rub) against the inner wall of the wellbore 102, which creates friction at the interface. When the friction overcomes the forces advancing (pushing) the coiled tubing assembly 136 into the wellbore 102, the coiled tubing 116 may start to buckle at one or more points. At first, the coiled tubing 116 may deform into a sinusoidal wave within the wellbore 102. As the buckling progresses, however, the coiled tubing 116 may subsequently take on a more helical shape as the coiled tubing 116 assumes a “corkscrew” effect represented as three-dimensional buckling. Helical buckling can eventually lead to total lock-up as the coiled tubing 116 contacts the inner wall of the wellbore 102 at several angular points and thereby greatly increases the generated friction. When total lock-up is reached, the coiled tubing assembly 136 can no longer be pushed further into the wellbore 102. In some embodiments, one or more sensors may be included in the coiled tubing assembly 136 to detect when buckling occurs.

According to embodiments of the present disclosure, the coiled tubing assembly 136 may further include one or more rotational devices 140 (one shown) operatively coupled to the coiled tubing 116, either directly or indirectly, at a location uphole from the bottom hole tool 138. More specifically, the rotational device 140 may interpose an uphole segment 142 of the coiled tubing 116 and a rotatable tubing segment 144, and the rotatable tubing segment 144 may extend from the rotational device 140 and otherwise be positioned at a location between the rotational device 140 and the bottom hole tool 138. In some embodiments, the rotational device 140 may be arranged in line with the coiled tubing 116 such that the uphole segment 142 and the rotatable tubing segment 144 may each comprise uphole and rotatable tubing segments (sections, portions, etc.), respectively, of the coiled tubing 116. In other embodiments, however, at least the rotatable tubing segment 144 may comprise another type of downhole tubing, such as jointed pipe, without departing from the scope of the disclosure.

As described herein, the rotational device 140 may be operable to impart torque to and rotate the rotatable tubing segment 144 relative to the uphole segment 142. Rotating the rotatable tubing segment 144 may help reduce friction generated by the rotatable tubing segment 144 against the inner wall of the wellbore 102, which may allow the coiled tubing 116 to be advanced further downhole without buckling.

The rotational device 140 can comprise any device or mechanism capable of rotating the rotatable tubing segment 144. In one embodiment, for example, the rotational device 140 may comprise a fluid powered motor (e.g., a mud motor) operable by circulating a fluid through the coiled tubing 116 and the rotational device 140. The fluid acts on a rotor and stator combination within the fluid powered motor to impart torque to the rotatable tubing segment 144 of the coiled tubing 116 extending therefrom. Example fluids that may be circulated to operate the fluid powered motor include, but are not limited to, a drilling fluid it) (mud), water, a gas, or any combination thereof.

In other embodiments, however, the rotational device 140 can include, but is not limited to, a hydraulic motor, a pneumatic motor, an electric motor, an electromechanical motor, or any combination thereof. In such embodiments, means for operating or powering the rotational device 140 may be conveyed downhole with the coiled tubing 116 or may otherwise form part of the rotational device 140. For example, one or more control lines 146 (one shown) may be communicably coupled to the rotational device 140 and extend to the surface location 104. The control line 146 may provide power and/or communication to the rotational device 140 in the form of electricity, hydraulic fluid, pneumatic fluid, or any combination thereof. In yet other embodiments, or in addition thereto, the rotational device 140 may include an on-board power supply 148, such as a battery pack, one or more fuel cells, or a downhole power generator that may be used to power the rotational device 140.

In some embodiments, the rotational device 140 may be designed to provide high torque at low rotations per minute. In one or more embodiments, for example, the rotational device 140 may be configured to output about 20 rpm to about 100 rpm. Depending on the application, the specific rotations per minute may be chosen to optimize reduction in axial friction.

While only one rotational device 140 is depicted in FIG. 1, it is contemplated herein to employ a plurality of rotational devices 140 in the coiled tubing assembly 136. In such embodiments, the coiled tubing 116 may be divided into multiple portions or segments with individual rotational devices 140 installed between each segment. Each rotational device 140 may be designed to rotate a corresponding rotatable tubing segment of the coiled tubing 116, and the length of each rotatable tubing segment may be such that the torque provided by the particular rotational device 140 may be sufficient to rotate the corresponding rotatable tubing segment.

FIG. 2 is an enlarged schematic view of the coiled tubing assembly 136, according to one or more embodiments of the disclosure. More specifically, FIG. 2 depicts one example of the coiled tubing assembly 136 conveyed into a non-vertical portion 202 of the wellbore 102 with the coiled tubing 116. In some embodiments, the non-vertical portion 202 may be the horizontal portion 110 (FIG. 1) of the wellbore 102, but could alternatively be any portion of the wellbore 102 that is offset from vertical.

In one or more embodiments, the rotational device 140 may be operatively coupled to (engaged with) the coiled tubing 116 with a connector 204. The connector 204 may comprise any type of tubing connector capable of coupling the rotational device 140 to the coiled tubing 116. In at least one embodiment, for example, the connector 204 may comprise a spoolable coiled tubing connector, such as the DURALINK™ coiled tubing connector available from Baker Hughes, a GE Company, of Houston, Tex., USA.

As illustrated, the rotatable tubing segment 144 is located downhole from the rotational device 140 and generally interposes the bottom hole tool 138 and the rotational device 140. The rotational device 140 may be operable to impart torque to the rotatable tubing segment 144 and thereby rotate the rotatable tubing segment 144 in a first angular direction, as shown by the arrow A. In some embodiments, the uphole segment 142 of the coiled tubing 116 located uphole from the rotational device 140 may remain stationary as the rotatable tubing segment 144 rotates. As the rotatable tubing segment 144 rotates, friction generated by the rotatable tubing segment 144 engaging the inner wall of the wellbore 102 may be reduced, which may allow the coiled tubing 116 to be advanced further downhole with a reduced risk of buckling.

As illustrated, the bottom hole tool 138 may be arranged at or otherwise operatively coupled to (e.g., engaged with either directly or indirectly) an end 206 of the rotatable tubing segment 144 and opposite the rotational device 140. In the illustrated embodiment, the bottom hole tool 138 includes a cutting tool 208, which may include, but is not limited to, a mill, a drill bit, or any other downhole cutting or milling tool. In preparation for well production operations, the cutting tool 208 may be conveyed downhole to mill/drill out a wellbore isolation device 210 located within the wellbore 102. The wellbore isolation device 210 may comprise, for example, a plug (e.g., a bridge plug, a wiper plug, etc.), a ball, a packer, a ball seat, or any combination thereof.

In some embodiments, the cutting tool 208 may include a motor 212 operable to rotate the cutting tool 208 and thereby enable milling/drilling of the wellbore isolation device 210 or extending the length (depth) of the wellbore 102. In such embodiments, rotation of the motor 212 and the rotatable tubing segment 144 may be combined to cooperatively rotate the cutting tool 208. In other embodiments, however, the motor 212 may be omitted and the cutting tool 208 may be rotated solely through operation of the rotational device 140.

In some embodiments, the motor 212 may comprise a fluid powered motor (e.g., a mud motor) operable by circulating a fluid through the coiled tubing 116, the rotatable tubing segment 144, and the motor 212. Example fluids that may be circulated to operate the motor 212 include, but are not limited to, a drilling fluid (mud), water, a gas, or any combination thereof. In other embodiments, however, the motor 212 can include, but is not limited to, a hydraulic motor, a pneumatic motor, an electric motor, an electromechanical motor, or any to combination thereof. In yet other embodiments, or in addition thereto, the motor 212 may include an on-board power supply, such as a battery pack, one or more fuel cells, or a downhole power generator that may be used to power the motor 212.

In some embodiments, a swivel 214 may be included in the coiled tubing 116 at a location between the bottom hole tool 138 and the rotational device 140. In the illustrated embodiment, the swivel 214 is located uphole from and adjacent the bottom hole tool 138. In other embodiments, however, the swivel 214 may be located at any location between the bottom hole tool 138 and the rotatable tubing segment 144. The swivel 214 may be configured to rotationally isolate the bottom hole tool 138 from the rotational device 140 and, more particularly, from the rotatable tubing segment 144. Consequently, the swivel 214 may allow the rotatable tubing segment 144 to rotate relative to the bottom hole tool 138, which may remain stationary as the rotatable tubing segment 144 rotates in the first angular direction A.

In some embodiments, however, the swivel 214 may comprise a one-way swivel that allows rotation in one direction (e.g., the first angular direction A), but prevents rotation in the opposite direction. In such embodiments, operation of the motor 212 may impart torque to the cutting tool 208 and thereby rotate the cutting tool 208 in a second angular direction, as shown by the arrow B, where the second angular direction B is opposite the first angular direction A. The swivel 214 may prevent the motor 212 from back rotating in the second angular direction B, which allows all the generated torque to be assumed at the cutting tool 208.

In some embodiments, a clutch mechanism 216 may be positioned between the rotational device 140 and the rotatable tubing segment 144. In the illustrated embodiment, the clutch mechanism 216 is located adjacent the rotational device 140, but could alternatively be offset from the rotational device 140. The clutch mechanism 216 may be configured to disengage the rotational device 140 from driving the rotatable tubing segment 144 when a predetermined torque limit is reached at the rotational device 140. In some embodiments, the predetermined torque limit may comprise a torsional strain value that does not exceed the torque limit for the coiled tubing 116. Consequently, the clutch mechanism 216 may prove advantageous in preventing the coiled tubing 116 from failing in torsion caused by operation of the coiled tubing assembly 136.

In one or more embodiments, the cutting tool 208 may become lodged or stuck in the wellbore 102. In other embodiments, or in addition thereto, the rotatable tubing segment 144 may become rotationally stuck in the wellbore 102. In such embodiments, the torque generated by the motor 212 and/or the rotational device 140 may continue to build until reaching the predetermined torque limit, at which point the clutch mechanism 216 may release. Releasing the clutch mechanism 216 may correspondingly release the torsional strain on the coiled tubing 116, and thereby prevent the coiled tubing 116 from failing in torsion.

FIG. 3 is another enlarged schematic view of another example embodiment of the coiled tubing assembly 136 of FIG. 1, according to one or more additional embodiments. The coiled tubing assembly 136 is again located in the non-vertical portion 202 of the wellbore 102 and conveyed downhole as part of the coiled tubing 116. In operation, the rotational device 140 may impart torque to the rotatable tubing segment 144 in the first angular direction A, and thereby reduce friction generated by the coiled tubing 116 engaging the inner wall of the wellbore 102.

In the illustrated embodiment, the bottom hole tool 138 comprises a jetting tool 302 that includes one or more nozzles 304 (two shown). A fluid 306 may be conveyed to the jetting tool 302 via the coiled tubing 116 and ejected from the nozzles 304 for a variety of downhole applications. In some embodiments, for example, the jetting tool 302 may be used to cut one or more holes in the walls of the wellbore 102 or in a wellbore liner that lines the wellbore 102 (e.g., the casing 112 of FIG. 1). In other embodiments, however, the jetting tool 302 may be used to clear an obstruction 308 from the wellbore 102. The obstruction 308 may comprise, for example, a sand dune that has accumulated within the wellbore 102 over time. Ejecting the fluid 306 from the jetting tool 302 may also help flush the wellbore 102 of debris, proppant, and sand in preparation for hydrocarbon production.

In some embodiments, the swivel 214 may be included in the coiled tubing 116 at a location between the bottom hole tool 138 and the rotational device 140. In the illustrated embodiment, the swivel 214 is offset from the bottom hole tool 138 a short distance, but could otherwise be arranged adjacent the jetting tool 302, without departing from the scope of the disclosure. The swivel 214 may allow the rotatable tubing segment 144 to rotate without causing corresponding rotation of the bottom hole tool 138. In other embodiments, however, the swivel 214 may be omitted and the bottom hole tool 138 may correspondingly rotate in the first angular direction A along with the rotatable tubing segment 144.

In one or more embodiments, the connector 204 and the clutch mechanism 216 may also be included in the coiled tubing assembly 136 of FIG. 3. Operation of the connector 204 and the clutch mechanism 216 may be the same as provided above, and therefore will not be discussed again.

FIG. 4 is another enlarged schematic view of another example embodiment of the coiled tubing assembly 136 of FIG. 1, according to one or more additional embodiments. The coiled tubing assembly 136 is again located in the non-vertical portion 202 of the wellbore 102 and conveyed downhole as part of the coiled tubing 116. The bottom hole tool 138 may comprise any of the downhole tools or devices mentioned herein. In the illustrated embodiment, however, the coiled tubing assembly 136 may include multiple rotational devices, shown as a first rotational device 140a and a second rotational device 140b.

The rotational devices 140a,b may each be conveyed into the non-vertical portion 202 of the wellbore 102 on the coiled tubing 116. In some embodiments, each tubing rotation device 140a,b may be coupled to the coiled tubing 116 with corresponding connectors 204. The rotational devices 140a,b may be longitudinally offset from each other such that a first rotatable tubing segment 144a interposes the first and second rotational devices 140a,b, and a second rotatable tubing segment 144b interposes the second rotational device 140b and the bottom hole tool 138. In some embodiments, the distance between the rotational devices 140a,b may be spaced from each other between about 500 ft and about 2000 feet, but it will be appreciated that the spacing may be less than 500 ft or more than 2000 ft, without departing from the scope of the disclosure.

In at least one embodiment, a first swivel 214a may be arranged in the coiled tubing 116 and otherwise interpose the first and second rotational devices 140a,b. The first swivel 214a may prove advantageous in allowing the first rotational device 140a to operate without correspondingly rotating the second rotational device 140b. Accordingly, in such embodiments, the first rotatable tubing segment 144a may be rotated relative to the second rotational device and/or the second rotatable tubing segment 144b. In other embodiments, however, the first swivel 214a may be omitted and the torque and rotation generated by each rotational device 140a,b may be combined along the coiled tubing 116 and assumed at the bottom hole tool 138.

In some embodiments, a second swivel 214b may be included in the coiled tubing 116 and otherwise at a location between the bottom hole tool 138 and the second rotational device 140b. In the illustrated embodiment, the second swivel 214b is located uphole from and adjacent the bottom hole tool 138. In other embodiments, however, the second swivel 214b may be located at any location between the bottom hole tool 138 and the second rotatable tubing segment 144b. The second swivel 214b may be configured to rotationally isolate the bottom hole tool 138 from the rotational devices 140a,b and, more particularly, from the second rotatable tubing segment 144b. Consequently, the second swivel 214b may allow the second rotatable tubing segment 144b to rotate relative to the bottom hole tool 138.

In other embodiments, however, the second swivel 214b may comprise a one-way swivel that allows rotation in one direction, but prevents rotation in the opposite direction. In such embodiments, rotation of the second rotatable tubing segment 144b may not correspondingly rotate the bottom hole tool 138 in the same direction. Instead, in some embodiments, the bottom hole tool 138 may be able to rotate in an opposite angular direction.

In one or more embodiments, the coiled tubing assembly 136 may further include one or more clutch mechanisms 216 (two shown) used to prevent the coiled tubing 116 from failing in torsion caused by operation of the coiled tubing assembly 136. More specifically, a first clutch mechanism 216a may be positioned between the first rotational device 140a and the first rotatable tubing segment 144a, and a second clutch mechanism 216b may be positioned between the second rotational device 140b and the second rotatable tubing segment 144b. The clutch mechanisms 216a,b may be configured to disengage the corresponding rotational devices 140a,b from driving the associated rotatable tubing segments 144a,b, respectively, when a predetermined torque limit is reached at the rotational device 140a,b.

Embodiments disclosed herein include:

A. A coiled tubing assembly that includes coiled tubing conveyable into a wellbore, a rotational device operatively coupled to the coiled tubing, a rotatable tubing segment operatively coupled to the rotational device, and a bottom hole tool arranged at an end of the rotatable tubing segment opposite the rotational device, wherein the rotational device rotates the rotatable tubing segment relative to the coiled tubing as the coiled tubing, the rotational tubing segment, and the bottom hole tool are axially displaced along the wellbore.

B. A method of performing a coiled tubing operation in a wellbore including introducing a coiled tubing assembly into the wellbore, the coiled tubing assembly comprising coiled tubing, a rotational device operatively coupled to the coiled tubing, a rotatable tubing segment operatively coupled to the rotational device, and a bottom hole tool arranged at an end of the rotatable tubing segment opposite the rotational device. The method further including powering the rotational device to rotate the rotatable tubing segment, and simultaneously conveying the coiled tubing assembly axially along the wellbore while rotating the rotatable tubing segment.

Each of embodiments A and B may have one or more of the following additional elements in any combination: Element 1: wherein the bottom hole tool comprises a downhole tool or device selected from the group consisting of a cutting tool, a jetting tool, a jarring device, one or more well screens, a wellbore isolation device, one or more wellbore sensors or gauges, a fishing tool, and any combination thereof. Element 2: wherein the bottom hole tool is located in a non-vertical portion of the wellbore. Element 3: wherein the rotational device is a mechanism selected from the group consisting of a fluid powered motor, a hydraulic motor, a pneumatic motor, an electric motor, an electromechanical motor, and any combination thereof. Element 4: wherein the rotational device comprises a fluid powered motor that operates in response to a fluid circulated through the coiled tubing and the rotational device. Element 5: further comprising one or more control lines extending from a surface location to the rotational device to provide at least one of power and communication to the rotational device. Element 6: further comprising a swivel coupled to the rotatable tubing segment at a location between the bottom hole tool and the rotational device, wherein the swivel allows the rotatable tubing segment to rotate relative to the bottom hole tool. Element 7: wherein the swivel is a one-way swivel that allows rotation of the rotatable tubing segment relative to the bottom hole tool in a first angular direction, but prevents rotation of the rotatable tubing segment relative to the bottom hole tool in a second angular direction opposite the first angular direction. Element 8: further comprising a clutch mechanism positioned between the rotational device and the rotatable tubing segment. Element 9: wherein the rotational device comprises a first rotational device and the rotatable tubing segment comprises a first rotatable tubing segment, the coiled tubing assembly further comprising a second rotational device coupled to the coiled tubing downhole from the first rotatable tubing segment, and a second rotatable tubing segment interposing the second rotational device and the bottom hole tool. Element 10: further comprising a swivel coupled to the second rotatable tubing segment uphole from the second rotational device, wherein the swivel allows the first rotatable tubing segment to rotate relative to the second rotational device. Element 11: wherein the swivel is a first swivel and the coiled tubing assembly further comprises a second swivel coupled to the second rotatable tubing segment at a location between the bottom hole tool and the second rotatable tubing segment, wherein the second swivel allows the second rotatable tubing segment to rotate relative to the bottom hole tool. Element 12: wherein the second swivel is a one-way swivel that allows rotation of the second rotatable tubing segment relative to the bottom hole tool in a first angular direction, but prevents rotation of the second rotatable tubing segment relative to the bottom hole tool in a second angular direction opposite the first angular direction.

Element 13: wherein the rotational device comprises a fluid powered motor and the method further comprises circulating a fluid through the coiled tubing to the fluid powered motor, and operating the fluid powered motor with the fluid circulating through the fluid powered motor. Element 14: wherein the fluid comprises a drilling mud and the bottom hole tool comprises a drill bit, the method further comprising circulating the drilling mud to the drill bit, and rotating the drill bit and thereby extending a length of the wellbore. Element 15: further comprising allowing the rotatable tubing segment to rotate relative to the bottom hole tool with a swivel coupled to the rotatable tubing segment at a location between the bottom hole tool and the rotational device. Element 16: wherein the swivel is a one-way swivel that allows rotation of the rotatable tubing segment relative to the bottom hole tool in a first angular direction, but prevents rotation of the rotatable tubing segment relative to the bottom hole tool in a second angular direction opposite the first angular direction. Element 17: wherein the coiled tubing assembly further includes a clutch mechanism positioned between the rotational device and the rotatable tubing segment, the method further comprising disengaging the rotational device from rotating the rotatable tubing segment with the clutch mechanism when a predetermined torque limit is reached. Element 18: wherein the rotational device comprises a first rotational device and the rotatable tubing segment comprises a first rotatable tubing segment, the method further comprising rotating a second rotatable tubing segment with a second rotational device coupled to the coiled tubing downhole from the first rotatable tubing segment, and reducing friction caused by the second rotatable tubing segment engaging the wall of the wellbore as the second rotatable tubing segment rotates. Element 19: further comprising combining rotation of the first and second rotatable tubing segments to rotate the bottom hole tool.

By way of non-limiting example, exemplary combinations applicable to A and B include: Element 1 with Element 2; Element 1 with Element 3; Element 3 with Element 4; Element 3 with Element 5; Element 6 with Element 7; Element 8 with Element 9; Element 9 with Element 10; Element 10 with Element 11; Element 11 with Element 12; Element 13 with Element 14; Element 15 with Element 16; and Element 18 with Element 19.

Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.

The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.

Claims

1. A coiled tubing assembly, comprising:

coiled tubing conveyable into a wellbore;

a rotational device operatively coupled to the coiled tubing;

a rotatable tubing segment operatively coupled to the rotational device; and

a bottom hole tool arranged at an end of the rotatable tubing segment opposite the rotational device,

wherein the rotational device rotates the rotatable tubing segment relative to the coiled tubing as the coiled tubing, the rotational tubing segment, and the bottom hole tool are axially displaced along the wellbore.

2. The coiled tubing assembly of claim 1, wherein the bottom hole tool comprises a downhole tool or device selected from the group consisting of a cutting tool, a jetting tool, a jarring device, one or more well screens, a wellbore isolation device, one or more wellbore sensors or gauges, a fishing tool, and any combination thereof.

3. The coiled tubing assembly of claim 1, wherein the bottom hole tool is located in a non-vertical portion of the wellbore.

4. The coiled tubing assembly of claim 1, wherein the rotational device is a mechanism selected from the group consisting of a fluid powered motor, a hydraulic motor, a pneumatic motor, an electric motor, an electromechanical motor, and any combination thereof.

5. The coiled tubing assembly of claim 1, wherein the rotational device comprises a fluid powered motor that operates in response to a fluid circulated through the coiled tubing and the rotational device.

6. The coiled tubing assembly of claim 1, further comprising one or more control lines extending from a surface location to the rotational device to provide at least one of power and communication to the rotational device.

7. The coiled tubing assembly of claim 1, further comprising a swivel coupled to the rotatable tubing segment at a location between the bottom hole tool and the rotational device, wherein the swivel allows the rotatable tubing segment to rotate relative to the bottom hole tool.

8. The coiled tubing assembly of claim 7, wherein the swivel is a one-way swivel that allows rotation of the rotatable tubing segment relative to the bottom hole tool in a first angular direction, but prevents rotation of the rotatable tubing segment relative to the bottom hole tool in a second angular direction opposite the first angular direction.

9. The coiled tubing assembly of claim 1, further comprising a clutch mechanism positioned between the rotational device and the rotatable tubing segment.

10. The coiled tubing assembly of claim 1, wherein the rotational device comprises a first rotational device and the rotatable tubing segment comprises a first rotatable tubing segment, the coiled tubing assembly further comprising:

a second rotational device coupled to the coiled tubing downhole from the first rotatable tubing segment; and

a second rotatable tubing segment interposing the second rotational device and the bottom hole tool.

11. The coiled tubing assembly of claim 10, further comprising a swivel coupled to the second rotatable tubing segment uphole from the second rotational device, wherein the swivel allows the first rotatable tubing segment to rotate relative to the second rotational device.

12. The coiled tubing assembly of claim 11, wherein the swivel is a first swivel and the coiled tubing assembly further comprises a second swivel coupled to the second rotatable tubing segment at a location between the bottom hole tool and the second rotatable tubing segment, wherein the second swivel allows the second rotatable tubing segment to rotate relative to the bottom hole tool.

13. The coiled tubing assembly of claim 12, wherein the second swivel is a one-way swivel that allows rotation of the second rotatable tubing segment relative to the bottom hole tool in a first angular direction, but prevents rotation of the second rotatable tubing segment relative to the bottom hole tool in a second angular direction opposite the first angular direction.

14. A method of performing a coiled tubing operation in a wellbore, comprising:

introducing a coiled tubing assembly into the wellbore, the coiled tubing assembly comprising; coiled tubing; a rotational device operatively coupled to the coiled tubing; a rotatable tubing segment operatively coupled to the rotational device; and a bottom hole tool arranged at an end of the rotatable tubing segment opposite the rotational device;

powering the rotational device to rotate the rotatable tubing segment; and

simultaneously conveying the coiled tubing assembly axially along the wellbore while rotating the rotatable tubing segment.

15. The method of claim 14, wherein the rotational device comprises a fluid powered motor and the method further comprises:

circulating a fluid through the coiled tubing to the fluid powered motor; and

operating the fluid powered motor with the fluid circulating through the fluid powered motor.

16. The method of claim 15, wherein the fluid comprises a drilling mud and the bottom hole tool comprises a drill bit, the method further comprising:

circulating the drilling mud to the drill bit; and

rotating the drill bit and thereby extending a length of the wellbore.

17. The method of claim 14, further comprising allowing the rotatable tubing segment to rotate relative to the bottom hole tool with a swivel coupled to the rotatable tubing segment at a location between the bottom hole tool and the rotational device.

18. The method of claim 17, wherein the swivel is a one-way swivel that allows rotation of the rotatable tubing segment relative to the bottom hole tool in a first angular direction, but prevents rotation of the rotatable tubing segment relative to the bottom hole tool in a second angular direction opposite the first angular direction.

19. The method of claim 14, wherein the coiled tubing assembly further includes a clutch mechanism positioned between the rotational device and the rotatable tubing segment, the method further comprising disengaging the rotational device from rotating the rotatable tubing segment with the clutch mechanism when a predetermined torque limit is reached.

20. The method of claim 14, wherein the rotational device comprises a first rotational device and the rotatable tubing segment comprises a first rotatable tubing segment, the method further comprising:

rotating a second rotatable tubing segment with a second rotational device coupled to the coiled tubing downhole from the first rotatable tubing segment; and

reducing friction caused by the second rotatable tubing segment engaging the wall of the wellbore as the second rotatable tubing segment rotates.

21. The method of claim 20, further comprising combining rotation of the first and second rotatable tubing segments to rotate the bottom hole tool.