U.S. patent application number 16/278279 was filed with the patent office on 2019-10-17 for coiled tubing assembly.
The applicant listed for this patent is Pavlin B. Entchev, David A. Howell. Invention is credited to Pavlin B. Entchev, David A. Howell.
Application Number | 20190316444 16/278279 |
Document ID | / |
Family ID | 65685999 |
Filed Date | 2019-10-17 |
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United States Patent
Application |
20190316444 |
Kind Code |
A1 |
Entchev; Pavlin B. ; et
al. |
October 17, 2019 |
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.
Inventors: |
Entchev; Pavlin B.; (Spring,
TX) ; Howell; David A.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Entchev; Pavlin B.
Howell; David A. |
Spring
Houston |
TX
TX |
US
US |
|
|
Family ID: |
65685999 |
Appl. No.: |
16/278279 |
Filed: |
February 18, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62690673 |
Jun 27, 2018 |
|
|
|
62657308 |
Apr 13, 2018 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 7/068 20130101;
E21B 7/046 20130101; E21B 31/00 20130101; E21B 41/00 20130101; E21B
4/16 20130101; E21B 17/05 20130101; E21B 4/02 20130101; E21B 17/20
20130101 |
International
Class: |
E21B 41/00 20060101
E21B041/00; E21B 4/02 20060101 E21B004/02; E21B 17/05 20060101
E21B017/05; E21B 31/00 20060101 E21B031/00 |
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.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] 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
[0002] 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.
[0003] 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.
[0004] 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
[0005] 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.
[0006] FIG. 1 is a schematic diagram of an example well system that
may employ one or more principles of the present disclosure.
[0007] FIG. 2 is an enlarged schematic view of the coiled tubing
assembly of FIG. 1, according to one or more embodiments.
[0008] FIG. 3 is another enlarged schematic view of the coiled
tubing assembly of FIG. 1, according to one or more additional
embodiments.
[0009] FIG. 4 is another enlarged schematic view of the coiled
tubing assembly of FIG. 1, according to one or more additional
embodiments.
DETAILED DESCRIPTION
[0010] 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.
[0011] 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.
[0012] 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).
[0013] 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.
[0014] 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.
[0015] 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.
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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.
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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.
[0025] 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.
[0026] 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.
[0027] 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.
[0028] 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.TM. coiled tubing connector available from
Baker Hughes, a GE Company, of Houston, Tex., USA.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] 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.
[0033] 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.
[0034] 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.
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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.
[0045] 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.
[0046] 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.
[0047] Embodiments disclosed herein include:
[0048] 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.
[0049] 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.
[0050] 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.
[0051] 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.
[0052] 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.
[0053] 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.
[0054] 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.
[0055] 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.
* * * * *