U.S. patent application number 14/777078 was filed with the patent office on 2016-02-04 for tool for measuring wellbore geometry.
This patent application is currently assigned to SMITH INTERNATIONAL, INC.. The applicant listed for this patent is SMITH INTERNATIONAL, INC.. Invention is credited to Sudarsanam Chellappa, Rui Gao, Jianbing Hu, James Layne Larsen, Jennifer L. Pereira, Tommy G. Ray, Vishal Saheta, Zhenbi Su, Dwayne P. Terracina, Robert Utter, Weixiong Wang, Siqi Xu, Baozhong Yang, Ming Zhang.
Application Number | 20160032710 14/777078 |
Document ID | / |
Family ID | 51625276 |
Filed Date | 2016-02-04 |
United States Patent
Application |
20160032710 |
Kind Code |
A1 |
Hu; Jianbing ; et
al. |
February 4, 2016 |
TOOL FOR MEASURING WELLBORE GEOMETRY
Abstract
A downhole tool is disclosed for measuring wellbore geometry.
The downhole tool may include a body with a bore extending at least
partially therethrough. The body may include a radial recess. An
arm may be movably coupled to the body at a first end portion of
the arm. The arm may be within the radial recess in a retracted
position and be pivotable in a radially-outward direction relative
to the body to an expanded position. A measurement device coupled
to the body may measure the pivoting motion of the arm. A piston
coupled to the body may be movably coupled to a second end portion
of the arm, and the piston may respond to changes in hydraulic
pressure to pivot the arm between the retracted position and the
expanded position.
Inventors: |
Hu; Jianbing; (Houston,
TX) ; Larsen; James Layne; (Spring, TX) ; Ray;
Tommy G.; (Houston, TX) ; Terracina; Dwayne P.;
(Spring, TX) ; Gao; Rui; (Spring, TX) ;
Pereira; Jennifer L.; (The Woodlands, TX) ; Wang;
Weixiong; (Houston, TX) ; Zhang; Ming;
(Spring, TX) ; Su; Zhenbi; (Spring, TX) ;
Yang; Baozhong; (Pearland, TX) ; Xu; Siqi;
(Houston, TX) ; Chellappa; Sudarsanam; (Houston,
TX) ; Saheta; Vishal; (Houston, TX) ; Utter;
Robert; (Sugar Land, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SMITH INTERNATIONAL, INC. |
Houston |
TX |
US |
|
|
Assignee: |
SMITH INTERNATIONAL, INC.
Houston
TX
|
Family ID: |
51625276 |
Appl. No.: |
14/777078 |
Filed: |
March 13, 2014 |
PCT Filed: |
March 13, 2014 |
PCT NO: |
PCT/US2014/025351 |
371 Date: |
September 15, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61784711 |
Mar 14, 2013 |
|
|
|
Current U.S.
Class: |
33/544.2 |
Current CPC
Class: |
E21B 47/08 20130101 |
International
Class: |
E21B 47/08 20060101
E21B047/08 |
Claims
1. A downhole tool for measuring wellbore geometry, comprising: a
body having a bore extending at least partially therethrough, the
body also having an aperture formed radially therein; an arm having
a first end portion movably coupled to the body, the arm being
pivotable between a retracted position in which the arm is within
the aperture and an expanded position in which the arm is at least
partially radially-outward relative to the body; a measurement
device coupled to the body and configured to measure a pivoting
motion of the arm; and a piston disposed in the bore of the body
and movably coupled to a second end portion of the arm, the piston
responsive to hydraulic pressure to cause the arm to pivot between
the retracted position and the expanded position.
2. The downhole tool of claim 1, the arm being configured to pivot
through an angle between 1.degree. and 20.degree..
3. The downhole tool of claim 1, the arm being configured to
contact a wall of a wellbore when in the expanded position.
4. The downhole tool of claim 3, further comprising: a roller
coupled to the arm, the roller being configured to contact the wall
of the wellbore when the arm is in the expanded position.
5. The downhole tool of claim 1, the measurement device including a
magnet configured to move axially within the measurement
device.
6. The downhole tool of claim 5, further comprising: an electronic
device coupled to the body, the electronic device including a
magnetometer.
7. The downhole tool of claim 6, the magnetometer being configured
to measure a distance that the magnet moves.
8. The downhole tool of claim 5, the magnet being configured to
move axially a distance proportional to a pivoting rotation of the
arm.
9. The downhole tool of claim 8, the measurement device being
configured to use the pivoting rotation of the arm to determine the
diameter of a wellbore.
10. The downhole tool of claim 1, the arm being biased toward the
configured to be positioned radially-inward from an outer surface
of the body when in the retracted position in the aperture and at
least partially radially-outward relative to the outer surface of
the body when in the expanded position.
11. A tool for measuring geometry, comprising: a body having an
axial bore extending at least partially therethrough; a piston
coupled to the body and configured to move axially within the body
from a first position to a second position when hydraulic pressure
of a fluid in the bore is increased; a spring gear assembly coupled
to the piston and configured to rotate when the piston moves
between the first position and the second position; an arm coupled
to the body and the spring gear assembly and configured to move
radially relative to the body when the spring gear assembly
rotates; and a measuring device coupled to the arm and configured
to measure the movement of the arm.
12. The tool of claim 11, the piston including a shaft having
plurality of teeth coupled thereto and axially spaced along the
shaft, the spring gear assembly including a gear having a plurality
of teeth coupled thereto and circumferentially spaced around at
least a portion of the gear, the plurality of teeth of the gear
being configured to engage the plurality of teeth of the shaft.
13. The tool of claim 12, the piston being configured to use
engagement of the plurality of teeth of the shaft with the
plurality of teeth of the gear to convert the axial movement of the
piston to rotational movement of the gear when the piston moves
between the first position and the second position.
14. The tool of claim 13, further comprising: a connector coupled
to and disposed between the arm and the spring gear assembly, the
connector configured to pivot the arm radially when the piston
moves between the first position and the second position.
15. The tool of claim 11, the measuring device being configured to
use the measured movement of the arm to determine a diameter of a
wellbore.
16. A method for measuring a diameter of a wellbore while
performing a downhole drilling or remedial operation, comprising:
increasing a pressure of a fluid in a bore that extends through a
body of a downhole tool within a wellbore; moving a piston axially
within the body from a first position to a second position in
response to the increased pressure in the bore; pivoting an arm
movably coupled to the body radially-outward in response to the
piston moving from the first position to the second position;
sensing the pivoting of the arm with a measuring device coupled to
the arm while drilling or performing a remedial operation; and
determining a diameter of the wellbore based upon the pivoting of
the arm.
17. The method of claim 16, wherein pivoting the arm comprises:
rotating a gear to the body in response to the piston moving from
the first position to the second position; and pivoting the arm
radially-outward in response to the rotation of the gear.
18. The method of claim 16, wherein determining the diameter of the
wellbore comprises: moving a magnet axially a distance proportional
to an amount by which the arm pivots; and determining the diameter
of the wellbore based upon the axial distance the magnet moves.
19. The method of claim 16, further comprising: contacting a wall
of the wellbore with a roller coupled to the arm when the arm is
positioned radially-outward from the body.
20. The method of claim 19, further comprising: rotating the
downhole tool while the arm is positioned radially-outward from the
body such that the roller rolls along the wall of the wellbore.
Description
FIELD OF THE INVENTION
[0001] Embodiments described herein generally relate to downhole
tools. More particularly, embodiments of the present disclosure
relate to downhole tools for measuring a diameter or other geometry
of a wellbore while performing drilling or remedial operations
within a wellbore.
BACKGROUND INFORMATION
[0002] Wellbores drilled in subterranean formations, such as
oilfields, often have irregular shapes. In particular, walls of the
wellbore are not perfectly smooth, and the magnitude of such
irregularities may be particularly great where the borehole
traverses weak, highly stressed, or fractured rock. Wellbore shape
and geometry can provide an indication of the mechanical stability
of the wellbore, and knowing the wellbore shape and geometry can be
useful in downhole operations such as drilling, reaming, producing,
casing, and plugging.
[0003] The diameter of the wellbore is oftentimes measured by an
ultrasonic measurement tool, which measures the diameter of the
wellbore using acoustic pulses and echoes. On wireline tools with
limited drilling or remedial tools, local diameter measurements may
also be made with mechanical arms. By combining measurements at
different angular orientations and depths, wellbore geometry may be
mapped out in two-dimensional or three-dimensional space.
SUMMARY
[0004] Embodiments of the present disclosure may relate to a
downhole tool for measuring wellbore geometry. An illustrative
downhole tool may include a body with a bore extending fully or
partially therethrough. An aperture may also extend radially
through a portion of the body. An arm with opposing ends may have
one end movably coupled to the body. The arm may pivot to move
between retracted and expanded positions. In the retracted
position, the arm may be within the aperture, and in the expanded
position the arm may be at least partially radially outward
relative to the body and aperture. A piston in the bore of the body
may be coupled to the second end of the arm and may respond to
hydraulic pressure to cause the arm to pivot and move between the
retracted position and the expanded position.
[0005] In accordance with another embodiment, a tool for measuring
geometry includes a body with a bore therein. A piston coupled to
the body may move axially within the body when hydraulic pressure
of fluid in the bore is increased. A spring gear assembly coupled
to the piston may rotate when the piston moves between two
positions. An arm coupled to the body and the spring gear assembly
may move radially relative to the body upon rotation of the spring
gear assembly, and a measuring device coupled to the arm may
measure rotational or other movement of the arm.
[0006] An example embodiment for measuring a diameter of a wellbore
while performing a downhole drilling or remedial operation may
include increasing a pressure of a fluid within a bore of a body of
a downhole tool in the wellbore. A piston may move axially in
response to the increased pressure, and an arm movably coupled to
the body may be pivoted radially-outward in response to axial
movement of the piston. A measuring device coupled to the arm may
sense the pivoting motion of the arm while drilling or while
performing a remedial operation, and the pivotal movement of the
arm may be used to determine a diameter of the wellbore.
[0007] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] So that features of claimed and described embodiments may be
understood in detail, a more particular description may be had by
reference to one or more embodiments, some of which are illustrated
in the appended drawings. It is to be noted, however, that the
appended drawings represent illustrative embodiments, and are,
therefore, not to be considered limiting of the scope of the
present disclosure. Moreover, while the drawings generally
illustrate certain embodiments at a scale useful for some
applications, the drawings should not be interpreted as being to
scale for each embodiment which may be described or claimed
herein.
[0009] FIG. 1 is a side view of an illustrative downhole tool for
measuring a diameter of a wellbore, according to one or more
embodiments of the present disclosure.
[0010] FIG. 2 is a cross-sectional side view of the downhole tool
shown in FIG. 1, according to one or more embodiments of the
present disclosure.
[0011] FIG. 3 is a partial perspective view of the downhole tool
shown in FIG. 1, with the body of the tool removed for clarity and
to illustrate example internal components, according to one or more
embodiments of the present disclosure.
[0012] FIG. 4 is a side view of an arm shown in FIG. 3, the arm
including an illustrative stop latch, according to one or more
embodiments of the present disclosure.
[0013] FIG. 5 is a cross-sectional perspective view of an arm,
roller, and slot connector of the downhole tool shown in FIG. 3,
according to one or more embodiments of the present disclosure.
[0014] FIG. 6 is a perspective view of a piston of the downhole
tool shown in FIG. 3, according to one or more embodiments of the
present disclosure.
[0015] FIG. 7 is a cross-sectional view of a spring gear assembly
coupled to a shaft of a piston of a downhole tool for measuring
wellbore geometry, according to one or more embodiments of the
present disclosure.
[0016] FIG. 8 is an exploded perspective view of a spring gear
assembly of a downhole tool for measuring wellbore geometry,
according to one or more embodiments of the present disclosure.
[0017] FIG. 9 is a cross-sectional view of a spring gear assembly
of the downhole tool shown in FIG. 2, according to one or more
embodiments of the present disclosure.
[0018] FIG. 10 is a cross-sectional side view of a downhole tool
showing an illustrative measurement device, according to one or
more embodiments of the present disclosure.
[0019] FIG. 11 is a partial perspective view of the measurement
device of FIG. 10, according to one or more embodiments of the
present disclosure.
[0020] FIG. 12 is a partial top view of the measurement device
shown in FIG. 11, according to one or more embodiments of the
present disclosure.
[0021] FIG. 13 is a partial perspective view of a measurement
device that may be used in the downhole tool shown in FIG. 10,
according to one or more embodiments of the present disclosure.
[0022] FIG. 14 is cross-sectional view of a measurement device in a
downhole tool, according to one or more embodiments of the present
disclosure.
[0023] FIG. 15 is a partial perspective view of the measurement
device shown in FIG. 14, according to one or more embodiments of
the present disclosure.
[0024] FIG. 16 is a cross-sectional view of the downhole tool shown
in FIG. 14, according to one or more embodiments of the present
disclosure.
[0025] FIG. 17 is a schematic view of three magnets, each
associated with a different measurement device, according to one or
more embodiments of the present disclosure.
[0026] FIG. 18-1 is a cross-sectional view of a downhole tool in an
inactive state with an arm assembly folded into a body of the
downhole tool, according to one or more embodiments of the present
disclosure.
[0027] FIG. 18-2 is a cross-sectional view of the downhole tool of
FIG. 18-1 in an active state with the arm assembly folded into the
body of the downhole tool due to contact with a wall of a wellbore,
according to one or more embodiments of the present disclosure.
[0028] FIG. 18-3 is a cross-sectional view of the downhole tool of
FIG. 18-3 in the active state with the arm assembly expanded
radially-outward and into contact with the wall of the wellbore,
according to one or more embodiments of the present disclosure.
[0029] FIG. 19-1 is a cross-sectional view of the downhole tool of
FIG. 18-1 in the inactive state with arm assemblies folded into the
body of the tool, according to one or more embodiments of the
present disclosure.
[0030] FIG. 19-2 is a cross-sectional view of the downhole tool of
FIG. 18-2 and FIG. 18-3 in the active state with two arm assemblies
expanded radially-outward and into contact with a round wall of a
wellbore, according to one or more embodiments of the present
disclosure.
[0031] FIG. 19-3 is a cross-sectional view of the downhole tool of
FIG. 18-2 and FIG. 18-3 in the active state with two arm assemblies
expanded radially-outward and into contact with a non-round wall of
a wellbore, according to one or more embodiments of the present
disclosure.
[0032] FIG. 20 is a partial perspective view of a downhole tool
prior to a measurement device being inserted into an aperture in a
body of the downhole tool, according to one or more embodiments of
the present disclosure.
[0033] FIG. 21 is a cross-sectional view of the downhole tool shown
in FIG. 20, according to one or more embodiments of the present
disclosure.
[0034] FIG. 22 is a cross-sectional view of the downhole tool shown
in FIG. 20, with the measurement device being inserted into the
aperture, according to one or more embodiments of the present
disclosure.
[0035] FIG. 23 is a cross-sectional view of the downhole tool shown
in FIG. 20, with the measurement device disposed within the
aperture, according to one or more embodiments of the present
disclosure.
[0036] FIG. 24 is a cross-sectional view of the downhole tool shown
in FIG. 20, with the measurement device coupled to the body and
within the aperture between the body and the mandrel, according to
one or more embodiments of the present disclosure.
[0037] FIG. 25 shows a cross-section of a partial perspective view
of the downhole tool shown in FIG. 24, according to one or more
embodiments of the present disclosure.
DETAILED DESCRIPTION
[0038] Some embodiments described herein generally relate to
downhole tools. More particularly, some embodiments of the present
disclosure relate to downhole tools for measuring a diameter or
other geometry of a wellbore while performing drilling or remedial
operations within the wellbore.
[0039] FIG. 1 shows a side view of an illustrative downhole tool
100 within a wellbore 102. The illustrated downhole tool 100 may be
used for measuring wellbore geometry, according to one or more
embodiments of the present disclosure. More particularly, the
downhole tool 100 may include a drilling caliper assembly that is
configured to measure the diameter of the wellbore in real-time. As
shown in FIG. 1, the downhole tool 100 may include a housing or
body 110 having a first or upper end portion 114, and a second or
lower end portion 116. The upper end portion 114 may be coupled to
a drill string, bottomhole assembly (BHA) component, or other
drilling tubular 120. For instance, the upper end portion 114 may
include a threaded box or pin connector to be threadingly engaged
with a corresponding pin or box connector of a drill string
extending upward toward a surface of a wellbore. In the same or
other embodiments, the lower end portion 116 may be coupled to a
drill string, BHA component, or other drilling tubular 120. The
lower end portion 116 may include a threaded connector (e.g., box
or pin connector) for being connected to a corresponding component
of a lower drill string, BHA components, or the like. In other
embodiments, the upper and/or lower end portions 114, 116 may have
other types of connectors.
[0040] In accordance with some embodiments, the body 110 may have
one or more openings, radial recesses, or apertures (three
apertures 122 are shown in FIG. 1) formed therein that are
circumferentially-offset from one another. The apertures 122 may be
defined as openings in the body 110, which may be generally
tubular. The apertures 122 may extend through a thickness of the
body 110 and therefore may extend radially from the outer surface
118 of the body 110 to an interior bore or chamber of the body 110.
The apertures 122 may also extend axially along a suitable length
of the body 110.
[0041] In some embodiments, a caliper system 136 may be at least
partially positioned within each aperture 122. In this particular
embodiment, the caliper system 136 may include an arm assembly 140,
a spring gear assembly 160, and a pin slot connector 180. The arm
assembly 140 may include an arm 142 having a roller 144 coupled
thereto. The pin slot connector 180 may be coupled to the arm 142
and the spring gear assembly 160 may be coupled to the pin slot
connector 180. Although three (3) apertures 122 and caliper systems
136 are shown in FIG. 1, it should be appreciated by those having
ordinary skill in the art, having the benefit of this disclosure,
that there may be more or fewer than three (3) apertures 122 and/or
caliper systems 136. For instance, there may be one (1), two (2),
or four (4) or more apertures 122 and/or caliper systems 136. In a
more particular embodiment, the number of apertures 122 and caliper
systems 136 may range up to six (6), eight (8), ten (10), twelve
(12), or more. Moreover, while the illustrated embodiment shows the
apertures 122 and caliper systems 136 as being circumferentially
offset at a common axial position, other embodiments also
contemplate apertures 122 and caliper systems 136 that are axially
offset. For instance, a first set of one or more apertures 122 and
caliper systems 136 may be located at a first axial position, and a
second set of one or more apertures 122 and caliper systems 136 may
be located at a second axial position. Such positioning may allow
real-time evaluation of wellbore geometry at multiple axial
positions. Optionally, the apertures 122 and caliper systems 136 at
different axial positions may be circumferentially aligned or
offset relative to each other.
[0042] FIG. 2 shows a cross-sectional side view of the downhole
tool 100 of FIG. 1, and FIG. 3 shows a partial perspective view of
the downhole tool 100 of FIG. 1, with the body 110 removed to more
clearly illustrate the caliper system 136, according to one or more
embodiments of the present disclosure. As shown in FIGS. 2 and 3, a
mandrel 156 may be disposed within the body 110. The mandrel 156
may have an axial bore 112 that extends partially or completely
therethrough. In the illustrated embodiment, a first or upper cap
108 may be disposed in an annular region between the mandrel 156
and the body 110. The upper cap 108 may also be an annular cap and,
as seen in FIG. 2, for instance, the upper cap 108 may be
positioned proximate or within the upper end portion 114 of the
body 110. In the same or other embodiments, a second or lower cap
106 may be disposed in the annular region between the mandrel 146
and the body 110, may have an annular shape, and may be proximate
or within the lower end portion 116 of the body 110.
[0043] In the illustrated embodiment, a piston 150 may be disposed
within the body 110 and configured to move axially within the body
110. The piston 150 may include a head 152 having a shaft 154
coupled thereto and extending axially therefrom. The head 152 may
abut the lower cap 106, and the shaft 154 may extend axially toward
the caliper system 136 and/or the upper end portion 114. In some
embodiments, the shaft 154 may be coupled to the mandrel 156 (e.g.,
a lower end of the mandrel). In the particular embodiment shown in
FIG. 2, the shaft 154 is coupled around an exterior surface of the
mandrel 156; however, in other embodiments, the mandrel 156 may be
coupled to an exterior surface of the shaft 154, the shaft 154 and
mandrel 156 may be coupled end-to-end, the shaft 154 and mandrel
156 may be coupled by one or more intermediate components, or the
shaft 154 and the mandrel 156 may be disconnected.
[0044] In FIGS. 2 and 3, a spring 190 is shown as being disposed
around the shaft 154 of the piston 150. The spring 190 may act as a
biasing member to bias the piston 150 toward the lower end portion
116 of the body 110. The spring 190 may be a compression spring
that compresses in an axial direction (e.g., toward the upper end
portion 114 of the body 110) when exposed to an axial force. A stop
ring 192 may be disposed around the shaft 154 of the piston 150.
The stop ring 192 may restrict axial movement of the spring 190.
For instance, the stop ring 192 may restrict, if not prevent, an
upper axial end portion of the spring 190 from moving or sliding
axially (e.g., toward the upper end portion 114 of the body 110)
past the stop ring 192 when the spring 190 is compressed. In some
embodiments, the spring 190 may be compressed between the stop ring
192 and the head 152. A maximum distance between the head 152 and
stop ring 192 may allow the spring 190 to be fully expanded;
however, in other embodiments the maximum distance between the head
152 and the stop ring 192 may maintain the spring 190 under some
compression. In some embodiments, the stop ring 192 may be fixed
relative to the body 110 while the head 152 and shaft 154 may be
movable relative to the body 110. Accordingly, the distance between
the stop ring 192 and the head 152 may change as the piston 150 is
activated. In other embodiments, however, the stop ring 192 may be
axially movable relative to the body 110, and the head 152 may be
axially fixed relative to the body 110.
[0045] Each spring gear assembly 160 may be coupled to the body 110
and/or to the shaft 154 of the piston 150. For example, each spring
gear assembly 160 may be coupled to the body 110 via a support bar
188 as shown in FIG. 3. The support bar 188 may be fixed at an
axial position along the body 110, and the spring gear assembly 160
coupled to the support bar 188 may be maintained axially stationary
with respect to the body 110. In some embodiments, the support bar
188 may rotate within the body 110 and/or the spring gear assembly
160 may include components that rotate or pivot around the support
bar 188.
[0046] According to some embodiments, the shaft 154 of the piston
150 may be configured to move axially with respect to the spring
gear assemblies 160 and the body 110. The spring gear assemblies
160 may each include a spring 162. The spring 162 may act as a
biasing member to bias at least a portion of the spring gear
assemblies 160. For instance, the spring 162 may be a torsion
spring configured to rotate about the support bar 188 and/or to
bias a portion of the spring gear assembly 160 towards rotation in
a particular direction around the support bar 188.
[0047] Each spring gear assembly 160 may be coupled to a
corresponding arm assembly 140. In some embodiments, the spring
gear assemblies 160 are coupled to corresponding arm assemblies 140
via a pin slot connector 180. More particularly, a pin connector
170 of the pin slot connector 180 may be coupled to each spring
gear assembly 160, and a slot connector 182 of the pin slot
connector 180 may be coupled to each arm assembly 140. The pin
connector 170 may include a pin 172 extending therefrom. The pin
172 may be positioned within a slot 184 formed in the corresponding
slot connector 182. In some embodiments, the slot 184 may have an
elongate shape. In such an embodiment, the pin 172 may be axially
movable along the elongate length of the slot 184. Although not
specifically shown, in another embodiment, the pin connectors 170
may be coupled to a corresponding arm assembly 140, and the slot
connectors 182 may be coupled to a corresponding spring gear
assembly 160.
[0048] The arm 142 of each arm assembly 140 may be coupled to a
measurement device 124. In this embodiment, the measurement device
124 may be positioned around the mandrel 156, and in the annular
region between the mandrel 156 and the body 110. The measurement
device 124 may be configured to sense or measure movement of the
arm 142. For example, the arm 142 may be pivotally connected to the
measurement device 124. The measurement device 124 may sense or
measure the rotational or pivoting movement of the arm 142 with a
mechanical device, electronic device (e.g., an electromagnet and/or
radio transmitter), a potential meter, a rotary encoder, or the
like. As discussed in greater detail herein, in one embodiment, the
measurement device 124 may include a magnet or other position
indicator. Such a position indicator may move axially within the
measurement device 124. In at least some embodiments, the distance
that the position indicator moves axially may correspond to the
rotational/pivoting movement of the arm 142 and/or the radial
movement of the arm assembly 140.
[0049] The measurement device 124 may be in communication with a
probe or other electronic device that is optionally disposed within
the bore 112 of the mandrel 156. The electronic device 134 may
include a magnetometer. For example, a magnetometer in the
electronic device 134 may be configured to detect the position of
the magnet in the measurement device 124, which position may
correspond to the position of the arm 142. The electronic device
134 may also include a transmitter configured to transmit the
measurement to another downhole tool (e.g., a
measurement-while-drilling (MWD) tool, a logging-while-drilling
(LWD), a mud-pulse telemetry transmitter, etc.) or to the surface.
Such transmission may occur in real-time or near real-time.
Real-time or near real-time transmission may allow
monitoring/recording (e.g., at an uphole or surface location) of
the diameter or other geometry of the wellbore 102 (FIG. 1) as
measured by the downhole tool 100, during drilling or remedial
operations within the wellbore 102. Remedial operations may
include, for instance, cementing operations, milling operations,
fishing operations, plugging operations, and the like.
[0050] FIG. 4 is a side view of the arm 142 of FIG. 3, and
illustrates an example stop latch 148. The stop latch 148 may be
configured to limit the rotational/pivoting movement of the arm 142
in one direction or in both directions. As shown, the illustrative
stop latch 148 may be configured to limit the rotational/pivoting
movement of the arm 142 in a clockwise direction when the arm 142,
which direction may also be a radially-inward direction.
[0051] FIG. 5 is a cross-sectional perspective view of the arm 142,
the roller 144, and the slot connector 182 shown in FIG. 3,
according to one or more embodiments of the present disclosure. The
roller 144 may be disposed around the arm 142. One or more bushings
or bearings 146 may be disposed between the arm 142 and the roller
144. The bearings 146 may reduce the friction between the arm 142
and the roller 144 to allow the roller 144 to rotate around the arm
142. This may allow the roller 144 to "roll" along the wall of the
wellbore when the downhole tool rotates about its longitudinal axis
within the wellbore.
[0052] FIG. 6 is a perspective view of a portion of the piston 150
shown in FIG. 3, and FIG. 7 is a cross-sectional view of the spring
gear assembly 160 coupled to the shaft 154 of the piston 150 of
FIG. 3, according to one or more embodiments of the present
disclosure. The shaft 154 of the piston 150 may include a plurality
of clogs or teeth 166 formed on the outer surface thereof. The
teeth 166 on the shaft 154 may be axially offset from one another
along the shaft 154. In some embodiments, the teeth 166 may form an
axial rack of teeth 166.
[0053] The spring gear assembly 160 may include a gear 168 that has
a plurality of clogs or teeth 164 formed on the outer surface
thereof. The teeth 164 on the gear 168 may be circumferentially
offset from one another, with each configured to fit within or
engage the teeth 166 on the shaft 154. In the illustrated
embodiment, the teeth 164 may extend circumferentially around a
portion of the gear 168. For instance, the teeth 164 may extend
around between 90.degree. and 270.degree. of the gear 168;
although, in other embodiments the teeth 164 may extend around less
than 90.degree. or greater than 270.degree. of the gear 168. In
more particular example embodiments, the teeth 164 may extend
around between 130.degree. and 150.degree., between 140.degree. and
160.degree., between 150.degree. and 170.degree., between
160.degree. and 180.degree., between 170.degree. and 190.degree.,
between 180.degree. and 200.degree., or between 190.degree. and
210.degree., between 200.degree. and 220.degree., or between
210.degree. and 230.degree.. In some embodiments, the teeth 164 may
extend around a full circumference of the gear 168.
[0054] The circumferentially offset of the teeth 164 may correspond
to the axial distance between the teeth 166. Consequently, when the
shaft 154 of the piston 150 moves axially with respect to the
spring gear assembly 160 of the illustrated embodiment, the
engagement of the teeth 164, 166 may cause the gear 168 to rotate
and move axially along the rack of teeth 166. In such an
arrangement, the gear 168 may operate as a pinion cooperating with
the rack of teeth 166.
[0055] FIG. 8 is an exploded perspective view of the spring gear
assembly 160 of FIGS. 3 and 7, according to one or more embodiments
of the present disclosure. The spring gear assembly 160 may include
a spring 162, a gear 168, a frame 178, and a support sleeve 186. In
some embodiments, a lateral portion 161 of the spring 162 may be
configured to fit within a corresponding slot 169 in the gear 168.
In the same or other embodiments, one or more end portions 163 (two
are shown in FIG. 8) of the spring 162 may be configured to fit
within corresponding first slots 179 in the frame 178. The
illustrated spring 162 is a torsional spring. By virtue of the
lateral portion 161 remaining in the slot 169 and the end portions
163 remaining in the first slots 179 while the gear 168 rotates
relative to the frame 178 (or vice versa), the bias of the spring
162 may be overcome and the spring 162 can be partially
uncoiled.
[0056] The support sleeve 186 may be positioned inside the spring
162 and/or the frame 178. In at least some embodiments, the support
sleeve 186 may be used to center or otherwise maintain a desired
positioning of the spring 162 within the frame 178 while the spring
162 winds and unwinds. In some embodiments, the frame 178 may
include a second slot 174 configured to have a tab 176 of the pin
connector 170 positioned therein. In the illustrated embodiment,
the tab 176 and the slot 174 may have elongated shape. Optionally,
such a shape may be used to limit if not prevent relative rotation
between the pin connector 170 and the frame 178. In the same or
other embodiments, the tab 176 may be sized to be about the same
size as the slot 174 to further restrict or even prevent relative
axial movement between the pin connector 170 and the frame 178. In
other embodiments, however, the slot 174 and/or tab 176 may have
other shapes or configurations. For instance, the tab 176 may have
a circular shape to allow rotation within the slot 174. The slot
174 may also be circular or have another shape or
configuration.
[0057] FIG. 8 depicts an example embodiment in which the frame 178
is separable into two halves, and in which each have a
corresponding slot 174 (one for each end portion 163 of the spring
162). The pin connector 170 is also shown as having two tabs 176,
one on each lateral side thereof so as to couple to each half of
the frame 178. Similarly, the support sleeve 186 is shown as having
two individual portions. It should be appreciated in view of the
disclosure herein that in other embodiments the frame 178 may be
formed of a single, unitary component and/or the sleeve support 186
may be formed as a single, unitary component. In the same or other
embodiments, the spring 162--which is shown as having two (2) coils
connected by the lateral portion 161--have more than two (2) coils
or may have a single coil.
[0058] FIG. 9 is a cross-sectional view of the downhole tool of
FIG. 2 taken along the line 9-9, and particularly shows a spring
gear assembly 160 according to one or more embodiments. Three (3)
apertures 122 are shown formed into the body 110 and
circumferentially-offset from one another. The apertures 122 are
shown as extending radially through the body 110, and between the
mandrel 156 and the outer surface 118 of the body 110. Each
aperture 122 may have a spring gear assembly 160 disposed at least
partially therein. In the illustrated embodiment, each spring gear
assembly 160 may be coupled to the body 110 with a support bar 188.
The support bar 188 may allow the spring gear assembly 160 to
rotate thereabout, while limiting, and potentially preventing,
axial movement of the spring gear assembly 160 with respect to the
body 110.
[0059] FIG. 10 is a cross-sectional side view of an example
downhole tool 100 showing an illustrative measurement device 124,
FIG. 11 is a partial perspective view of the measurement device 124
shown in FIG. 10, and FIG. 12 is a partial top view of the
measurement device 124 shown in FIG. 11, according to one or more
embodiments of the present disclosure. The measurement device 124
may include a gear shaft 126, one or more gears (one is shown 128),
one or more pulleys (two are shown 130-1, 130-2), and a magnet 132.
In at least some embodiments, the measurement body 124 may define
or include a body, casing, or other housing for one or more of the
gear shaft 126, gears 128, pulleys 130-1, 130-2, or magnet 132.
According to at least some embodiments, the housing may be a
pressure compensated casing or other housing. For instance, a
pressure compensation piston 129 may be fully or partially disposed
within the measurement device 124.
[0060] The arm 142 of the arm assembly 140 may be coupled to the
gear shaft 126 such that the rotational movement of the arm 142 is
transferred to the gear shaft 126. The gear shaft 126 may be
coupled to the gear 128 such that the rotational movement of the
gear shaft 126 may be transferred to the gear 128. Although a
single gear 128 is shown in FIG. 11, it should be appreciated in
view of the disclosure herein that two or more gears 128 may be
used in moving the magnet 132 and/or that any desired gear ratio
may be used. For instance, a gear ratio may be used to amplify the
rotational movement of the gear shaft 126 and the arm 142. A
desired gear or other transmission ratio may be achieved by
increasing or decreasing the number of gears 128 and/or the size or
number of teeth on each gear 128. As shown in FIG. 12, for
instance, two gears 128-1, 128-2 may be coupled to the gear shaft
126. The width of the first gear 128-1 and corresponding pinion may
be less than the width of the second gear 128-2 and corresponding
pinion. In the illustrated embodiment, the diameter of the gear
128-1 may be larger than the diameter of the gear 128-2.
Consequently, for each rotation of the gear 128-1, the gear 128-2
may rotate multiple times. The difference in width and/or the
difference in gear diameter/size may account for a loading ratio
effect.
[0061] The first and/or second gear 128-1, 128-2 may be coupled to
a first pulley 130-1 by direct engagement or through indirect
engagement of one or more other gears. In the illustrated
embodiment, the rotational movement of the gear 128-2 may cause the
first pulley 130-1 to rotate. More particularly, the gear shaft 126
may rotate. The gear 128-1 may be co-axial with the gear shaft 126
and may therefore rotate as the gear shaft 126 rotates. By virtue
of engagement between the gear 128-2 and the gear 128-1, the gear
128-1 may also be caused to rotate. As shown in FIG. 12, the
illustrated embodiment may include a pinion 131-1 coupled to, and
optionally co-axial with, the first pulley 130-1. The pinion 131-1
may include teeth that engage with teeth of the gear 128-1. When
the gear shaft 126 rotates, the first pulley 130-1 may therefore be
rotated through the interconnection of the gears 128-1, 128-2 and
the pinion 131-1.
[0062] When the first pulley 130-1 rotates, the rotation may cause
a line or cable 123 disposed at least partially thereabout to move
the magnet 132 in a linear or axial direction within the
measurement device 124. The second pulley 130-2 may serve to reduce
or prevent slack in the cable 123. In some embodiments, the cable
123 may be tensioned. For instance, the cable 123 may be tensioned
by a preloaded torsion spring 125 or other biasing or tensioning
member.
[0063] The movement of the magnet 132 may correspond to the
rotational/pivoting movement of the arm 142 (see FIG. 10). In
particular, the rotational/pivoting movement of the arm 142 may
cause the gear shaft 126 to rotate, and such rotation may be
translated into axial movement of the magnet 132. Optionally, the
movement of the magnet may be proportionally related to the
rotational/pivoting movement of the arm 142.
[0064] A probe or other electronic device 134 (see FIG. 2) may
include one or more sensors that are configured to sense or measure
the axial movement or position of the magnet 132. The magnet 132
may therefore be one example of a device that may be used to
determine the position of the arm 142. In other embodiments, the
magnet 132 may be replaced by other components (e.g., ferrous
metals, electronic components, etc.) that may be used in
determining the position of the arm 142. The electronic device 134
may transmit the measured or determined position of the magnet 132
to a MWD, pulse transmitter, or other downhole tool, or to the
surface. In another embodiment, the electronic device 134 may
operate in a memory mode in which the information is stored for use
after a run by a drilling or remedial tool string. In some
embodiments, the electronic device 134 may use the obtained
measurements in real-time or near real-time to determine the
rotational/pivoting movement of the arm 142. As discussed in
greater detail herein, the rotational/pivoting movement of the arm
142 may be used to determine the diameter or other geometry of the
wellbore.
[0065] FIG. 13 is a partial perspective view of another example of
a measurement device 224 that may be used in downhole tools such as
those disclosed herein (e.g., downhole tool 100 of FIGS. 1 and 2).
Rather than, or in addition to, having a set of one or more gears
and/or one or more pulleys, the measurement device 224 may have a
piston 227 disposed therein. The piston 227 may be coupled to a
gear shaft 226 via a connection bar 229. The gear shaft 226 may be
coupled to an arm assembly or other component as discussed herein.
The piston 227 may be disposed within a first chamber 233 in the
measurement device 224, and a magnet 232 or other positioning
device may be disposed within a second chamber 235 that is
optionally in fluid communication with the first chamber 233. When
the gear shaft 226 rotates, the gear shaft 226 may cause the
connection bar 229 to rotate and/or translate, thereby causing the
piston 227 to move within the first chamber 233. Movement of the
piston toward the second chamber 235 may compress or move a fluid
within the first chamber 233, which may cause the magnet 232 to
move axially within the second chamber 235. The first chamber 233
may have a greater cross-sectional size (e.g., diameter) than the
second chamber 235, which may amplify movement of the magnet 232
with respect to the piston 227. In other words, the magnet 232 may
move a larger axial distance than the piston 227. In other
embodiments, the relationship may be reversed or the magnet 232 and
piston 227 may move about the same distance. In still other
embodiments, the magnet 232 may be positioned on or in the piston
227, or the piston 227 may be used as a measurement device.
[0066] FIG. 14 is cross-sectional view of a downhole tool 300
incorporating another embodiment of a measurement device 324, and
FIG. 15 is a partial perspective view of the measurement device 324
of FIG. 14. In this particular embodiment, the measurement device
324 may include a magnet 332 coupled to a shaft 336. In this same
embodiment, a gear shaft 326 may be coupled to a gear amplifier 337
of the measurement device 324. The gear amplifier 337 may include
teeth for engaging the gear shaft 326, and an extension arm
extending from a gear or teeth portion. The extension arm may
engage a shaft 336. As the gear shaft 326 rotates, the gear shaft
326 may therefore cause the gear amplifier 337 to rotate, and the
gear amplifier 337 may cause the shaft 336 to move. In this
particular embodiment, the shaft 336 may be moved in a linear
direction; however, other embodiments are contemplated in which a
shaft is rotated and/or moved in a curved fashion. The shaft 336
may have the magnet 332 or other positioning device coupled
thereto. Optionally, one or more support bearings 338 may be
configured to guide the linear or other movement of the shaft 336.
In at least one embodiment, the support bearings 338 may be
stationary with respect to the shaft 336, and the shaft 336 may
slide or otherwise move.
[0067] FIG. 16 is a cross-sectional view of the downhole tool 300
shown in FIG. 14, according to one or more embodiments of the
present disclosure. As shown, the downhole tool 300 may include
three measurement devices 324 that are circumferentially offset
from one another. Thus, three magnets 332-1, 332-2, and 332-3 may
be circumferentially offset from one another within the body 310.
As will be appreciated by one having ordinary skill in the art in
view of the disclosure herein, the magnets 332-1, 332-2, 332-3 may
be movable independently of each other based on the relative
position of a corresponding arm or other device for measuring
wellbore geometry.
[0068] In some embodiments, a mandrel 356 may be shaped and sized
to form one or more flow channels (three are shown 339-1, 339-2,
339-3) between the mandrel 356 and an electronic device 334 (see
FIG. 14). The flow channels 339-1, 339-2, 339-3 may be
circumferentially offset from one another. Optionally, the flow
channels 339-1, 339-2, 339-3 are circumferentially offset by an
amount corresponding to a circumferential offset of the magnets
332-1, 332-2, 332-3. In some embodiments, each flow channel 339-1,
339-2, 339-3 may be positioned between two circumferentially
adjacent magnets 332-1, 332-2, 332-3. The total cross-sectional
area of the flow channels 339-1, 339-2, 339-3 may vary, and in some
embodiments may range between 3 cm.sup.2 and 100 cm.sup.2. For
instance, the cross-sectional area may be between 5 cm.sup.2 and 10
cm.sup.2, between 10 cm.sup.2 and 20 cm.sup.2, between 20 cm.sup.2
and 40 cm.sup.2, or between 40 cm.sup.2 and 60 cm.sup.2. In other
embodiment, the cross-sectional area may be less than 5 cm.sup.2 or
greater than 100 cm.sup.2.
[0069] An electronic device (e.g., 334 of FIG. 14) or other
measurement tool may be used to measure/determine the position of
the magnets 332-1, 332-2, 332-3. In one embodiment, the electronic
or other measurement tool may be disposed within the mandrel 356.
For instance, the measurement device may be or include a tube
having one or more sensors 341-1, 341-2, 341-3 disposed therein.
For example, the electronic device 334 may include three (3)
sensors 341-1, 341-2, 341-3 that are circumferentially offset from
one another. In other embodiments, more or fewer than three (3)
sensors may be used. According to some aspects of the present
disclosure, each sensor 341-1, 341-2, 341-3 may be aligned or
otherwise associated with a corresponding magnet 332-1, 332-2,
332-3.
[0070] FIG. 17 shows a schematic view of three magnets 432-1,
432-2, 432-3, each disposed within or otherwise aligned with a
different measurement device, according to one or more embodiments
of the present disclosure. In at least one embodiment, two or more
sensors (three are shown 441-1, 441-2, 441-3) may be coupled to the
body of a downhole tool. For instance, the sensors 441-1, 441-2,
441-3 may be disposed within a tube and/or circumferentially offset
from one another (see, e.g., sensors 341-1, 341-2, 341-3 of FIG.
16). For example, the three (3) sensors 441-1, 441-2, 441-3 may be
disposed about 120.degree. apart around the circumference of the
body of a downhole tool. In other embodiments, the circumferential
offset between circumferentially adjacent sensors may be less than
or greater than 120.degree.. For instance, if more than three (3)
sensors are used, there may be a reduced circumferential offset. If
two (2) sensors are used, there may be a larger circumferential
offset. In other embodiments, there may be different
circumferential offsets between adjacent sensors.
[0071] Each sensor 441-1, 441-2, 441-3 may sense the location
and/or movement of a corresponding magnet 432-1, 432-2, 432-3 or
other positioning device. Each magnet 432-1, 432-2, 432-3 may be
configured to move linearly within a single one of the zones 443-1,
443-2, 443-3. In one embodiment, the zones 443-1, 443-2, 443-3 may
be axially offset from one another so that the magnets 432-1,
432-2, 432-3 have reduced or even no "cross-talk" with one another.
In some embodiments, the zones 443-1, 443-2, 443-3 may be axially
offset to have no overlap. In other embodiments, one or more of the
magnets 432-1, 432-2, 432-3 may be configured to move within
multiple zones 443-1, 443-2, 443-3. As discussed herein, the
position of a magnet 432-1, 432-2, 432-3 may be related to the
position of an arm assembly used to measure or otherwise determine
wellbore geometry.
[0072] FIG. 18-1 is a partial cross-sectional view of a downhole
tool 500 in an inactive or retracted state, in accordance with some
embodiments of the present disclosure. The downhole tool 500 of
FIG. 18-1 may operate in a manner similar to the downhole tool 100
of FIGS. 1 and 2 and the downhole tool 300 of FIG. 14. Accordingly,
the discussion of the downhole tool 500 may be equally applicable
to the downhole tool 100 and/or downhole tool 300, and vice
versa.
[0073] In this particular embodiment, an arm assembly 540 may be
folded or otherwise retracted into a body 510 of the downhole tool
500. When the downhole tool 500 is in the inactive state, a piston
550 may be positioned proximate a lower end portion 516 of the body
510. The spring 590 may also be generally uncompressed in such an
embodiment. In addition, the arm 542 and the roller 544 (or other
device for engaging a wall of a wellbore) may be folded or
otherwise retracted into an aperture 522 of the body 510, and the
outer surface of the arm 542 and/or a roller 544 may be aligned
with, or positioned radially-inward from, the outer surface 518 of
the body 510.
[0074] FIG. 18-2 is a cross-sectional view of the downhole tool 500
in an active state with the arm assembly 540 folded or otherwise
retracted into the body 510 of the downhole tool 500 due to contact
with the wall of a wellbore, and FIG. 18-3 is a cross-sectional
view of the downhole tool 500 in the active or expanded state with
the arm assembly 540 expanded radially-outward for engaging or
otherwise contacting the wall of a wellbore, according to one or
more embodiments of the present disclosure. When the downhole tool
500 is actuated into the active state, the piston 550 may slide or
otherwise move toward the upper end portion 514 of the body 510,
thereby compressing the spring 590. As the piston 550 moves, the
engagement of the teeth on the shaft 554 of the piston 550 with
teeth on the gear 568 of the spring gear assembly 560 may cause the
gear 568 to rotate. The rotation of the gear 568 may exert a force
on the arm assembly 540 (e.g., through the pin slot connector 580)
in a direction that is radially-outward relative to the body 510.
When the arm assembly 540 is unobstructed, as shown in FIG. 18-3,
the force exerted by the spring gear assembly 560 may cause the arm
assembly 540 to pivot or rotate radially-outward from the body 510.
For example, the arm assembly 540 may pivot or rotate
radially-outward until the roller 544 or other engagement device
contacts the wall of the wellbore.
[0075] When the arm assembly 540 is obstructed, as shown in FIG.
18-2, the force exerted by the spring gear assembly 560 may be less
than an opposing force exerted on the roller 544 in a direction
that is radially-inward relative to the body 510. For example, when
a side of the body 510 abuts the wall of the wellbore, the wall of
the wellbore may limit or even prevent the arm assembly 540
proximate that side of the body 510 from expanding
radially-outward. The pin slot connector 580 may enable the arm
assembly 540 to remain folded into the aperture 522 of the body 510
when the downhole tool 500 is in the active state. More
particularly, the pin 572 may be configured to slide or otherwise
move within a slot (see slot 184 of FIG. 3) to allow the arm
assembly 540 to remain folded into the aperture 522 of the body 510
when the force exerted by the spring gear assembly 560 is less than
the opposing force exerted by the wall of the wellbore.
[0076] FIG. 19-1 is a cross-sectional view of the downhole tool 500
of FIG. 18-1 in the inactive state with the arm assemblies 540
retracted into the body of the downhole tool 500, according to one
or more embodiments of the present disclosure. As discussed herein,
when the downhole tool 500 is in an inactive state, the arms 542
and the rollers 544 may be folded or otherwise retracted into the
apertures 522 of the body 510, such that the outer surfaces of the
arms 542 and/or the rollers 544 may be radially aligned with, or
positioned radially-inward from, the outer surface 518 of the body
510.
[0077] FIG. 19-2 is a cross-sectional view of the downhole tool 500
in the active state with the arm assemblies 540-1, 540-2, 540-3
expanded radially-outward and into contact with a round wall 504 of
the wellbore 502, according to one or more embodiments of the
present disclosure. When the downhole tool 500 is in the active
state, the arms 542 and the rollers 544 may expand radially-outward
from the body 510 to cause the rollers 544 to contact the wall 504
of the wellbore 502. As shown in FIG. 19-2, the longitudinal axis
of the downhole tool 500 may be misaligned relative to the
longitudinal axis of the wellbore 502. As such, two of the arm
assemblies 540-1, 540-2 may be expanded radially-outward from the
body 510, while the third arm assembly 540-3 may be restricted or
even prevented from expanding radially-outward because the wall 504
of the wellbore 502 is contacting the outer surface 518 of the body
510 proximate the third arm assembly 540-3. In accordance with at
least some embodiments, the weight of the downhole tool 500 and/or
the fluid within the wellbore 502 may limit the ability of the
third arm assembly 540-3 to push against the wall 504 of the
wellbore 504 to align the longitudinal axis of the downhole tool
500 with the longitudinal axis of the wellbore 502. In other
embodiments, however, the force exerted by the third arm assembly
540-3 may be sufficient to push the downhole tool 500 off the wall
504 to align the downhole tool 500 with the longitudinal axis of
the wellbore 502 and/or to cause the three arm assemblies 540-1,
540-2, 540-3 to each move radially-outward about a same
distance.
[0078] FIG. 19-3 is a cross-sectional view of the downhole tool 500
in the active state with the arm assemblies 540-1, 540-2, 540-3
expanded radially-outward and into contact with a non-round wall
505 of the wellbore 502, according to one or more embodiments. The
arm assemblies 540-1, 540-2, 540-3 may be configured to each expand
radially-outward a different distance to contact the wall 505 of
the wellbore 502. For example, as shown in FIG. 19-3, a first arm
assembly 540-1 may be expanded out a first distance, a second arm
assembly 540-2 may be expanded out a second distance, and a third
arm assembly 540-3 may be restricted or prevented from expanding
because the wall 504 of the wellbore 502 is contacting the outer
surface 518 of the body 510 proximate the third arm assembly 540-3.
The third arm assembly 540-3 could also be expanded out a third
distance. In some embodiments, each of the three distances is
different. In other embodiments, two of the three distances may be
about the same.
[0079] FIGS. 20-25 generally illustrate a manner of assembling a
downhole tool 600 that includes arm assemblies 640 and measurement
devices 624, according to some embodiments of the present
disclosure. The downhole tool 600 may be the same or similar to
other downhole tools disclosed herein (e.g., downhole tool 100 of
FIG. 1, downhole tool 300 of FIG. 14, or downhole tool 500 of FIG.
18-1 to FIG. 18-3). The measurement devices 624 may also include
various types of measurement devices (e.g., measurement device 124
of FIG. 11, measurement device 224 of FIG. 13, measurement device
324 of FIG. 15, or measurement device 524 of FIG. 18-1 to FIG.
18-3). Accordingly, the discussion of FIGS. 20, 21, 22, 23, 24, and
25 may be equally applied to the other embodiments disclosed
herein, and vice versa.
[0080] More particularly, FIG. 20 is a perspective view of the
downhole tool 600 prior to the measurement devices 624 being
inserted into apertures 622 in the body 610. FIG. 21 is a
cross-sectional view of the downhole tool 600 shown in FIG. 20.
Prior to inserting the measurement devices 624 into the apertures
622, a mandrel 656 inside the body 610 may be placed in a first
axial position within the body 610. With the mandrel 656 in the
first position, a gap 658 between a radial surface 611 of the body
610 and a shoulder 657 extending radially-outward from the mandrel
656 may be large enough to allow the measurement devices 624 to
fully or partially pass therethrough.
[0081] FIG. 22 is cross-sectional view of the downhole tool 600 of
FIGS. 20 and 21 with one of the measurement devices 624 being
inserted into the aperture 622, according to one or more
embodiments of the present disclosure. When the mandrel 656 is in
the first position, the measurement device 624 may pass through the
gap 658 and at least partially into the aperture 622. At least a
portion of the measurement device 624 may be disposed radially
between the body 610 and the mandrel 656.
[0082] FIG. 23 is a cross-sectional view of the downhole tool 600
of FIGS. 20 and 21 with the measurement device 624 disposed within
the aperture 622, according to one or more embodiments of the
present disclosure. Relative to the embodiment shown in FIG. 22,
the measurement device 624 is shown as being moved axially along
the body 610 toward the upper cap 608. In particular, once in the
aperture 622, the measurement device 624 may be moved axially
toward the upper end portion 614 of the body 610 until a shoulder
625 extending radially-outward from the measurement device 624
contacts or abuts the radial surface 611 of the body 610. In some
embodiments, moving the measurement device 624 may also include
moving the measurement device 624 radially. Optionally, the pin
slot connector 680 may then be coupled to the spring gear assembly
660; however, as may be appreciated, this coupling may occur before
or after the measurement device 624 is disposed within the aperture
622. Similarly, the arm assembly 640 may be coupled to the
measurement device 624 before or after insertion of the measurement
device into the aperture 622.
[0083] FIG. 24 shows a partial cross-sectional view of the downhole
tool 600 with the measurement device 624 coupled to the body 610
and within the aperture 622 between the body 610 and the mandrel
656, according to one or more embodiments of the present
disclosure. The upper cap 608 may have a plurality of threads
formed on an inner surface thereof, and the mandrel 656 may have a
plurality of threads formed on the outer surface thereof, which
threads may be configured to engage the inner threads of the upper
cap 608. The inner cap 608 may be rotated with respect to the body
610 and the mandrel 656, thereby causing the mandrel 656 to move
axially within the body 610 toward the upper end portion 614 of the
body 610. The mandrel 656 may move toward the upper end portion 614
of the body 610 until the outer shoulder 657 of the mandrel 656
contacts or abuts the measurement device 624 (which may abut the
radial surface 611). Thus, the measurement device 624 may be
coupled to the body 610 and secured in place between the body 610
and the mandrel 656.
[0084] The outer shoulder 657 of the mandrel 656 and/or the radial
surface 611 of the body 610 may be straight, tapered, curved, or
otherwise contoured. When the outer shoulder 657 is straight, it
may be substantially perpendicular to a longitudinal axis extending
through the mandrel 656 and/or the body 610. The straight outer
shoulder 657 may not affect the centralization of the mandrel 656
because may not push the measuring devices 624 radially outward.
Thus, there may not be a reaction force applied radially on the
mandrel 656 to shift the mandrel 656 from its central location.
When the outer shoulder 657 is tapered, the taper may be oriented
at an angle between 2.degree. and 130.degree.. For instance, the
angle may range from a low of 5.degree., 10.degree., 20.degree., or
30.degree. to a high of 45.degree., 60.degree., 75.degree., or more
with respect to the longitudinal axis extending through the mandrel
656 and/or body 610 (where 90.degree. is perpendicular to the
longitudinal axis). When the outer shoulder 657 is tapered, the
outer shoulder 657 may apply a force to the measuring device 624 in
the axial and radial directions, and this may tend to push the
mandrel 656 off-center.
[0085] FIG. 25 shows a cross-section of a perspective view of the
downhole tool 600 shown in FIG. 24, according to one or more
embodiments of the present disclosure. In at least one embodiment,
one or more grooves or slots (three grooves 659 are shown in FIG.
25) may be formed in the outer surface of the mandrel 656. The
measuring devices 624 may each include a radial protrusion 627 or
tab configured to fit within a corresponding slot 659 in the
mandrel 656. The engagement of the radial protrusion 627 within the
slot 659 may restrict or even prevent relative rotation of the
mandrel 656 relative to the measuring devices 624. In some
embodiments, engagement of the radial protrusion 627 with the slot
659 may restrict or even prevent rotation of the mandrel 656 and
measuring devices 624 about the longitudinal axis extending through
the mandrel 656 when the upper cap 608 (see FIG. 24) rotates. Thus,
the mandrel 656 and the measuring devices 624 may move axially in
response to the rotation of the upper cap 608, but may not rotate
along with the upper cap 608. Although a slot 659 and a
corresponding radial protrusion 627 are shown, it will appreciated
in view of the disclosure herein that any engagement (e.g., an
edge, a pin, etc.) may be used to restrict rotation of the mandrel
656 and/or the measuring devices 624. As will also be appreciated
in view of the present disclosure, the illustrated mechanism for
coupling the measuring device 624 to the mandrel 656 and/or the
body 610 of the downhole tool 600 is not limited to measuring
devices 624. For example, the same or a similar design may be used
to couple any component to a downhole tool, or to insert any
component at least partially within another tool, such as a
downhole tool.
[0086] Once the downhole tool 600 is assembled, the downhole tool
600 may be run into a wellbore (e.g., wellbore 102 of FIG. 1) on a
drill string or other drilling tubular. The downhole tool 600 may
be in the inactive state as it is run into the wellbore. More
particularly, the arm assemblies 640 may be folded or otherwise
retracted through the apertures 622 and into the body 610, such
that the outer surface of each arm 642 and/or the roller 644 may be
aligned with, or positioned radially-inward from, the outer surface
618 of the body 618. The downhole tool 600 may then be actuated
into the active state when the downhole tool 600 reaches the
desired position/depth within the wellbore (e.g., a downhole
position/location at which it is desired to measure the diameter or
other geometry of the wellbore). In one or more embodiments, the
downhole tool 600 may be actuated into or already in the active
state while drilling (e.g., a drill bit coupled to the downhole
tool 600 may be rotating to further drill the wellbore) or
conducting other drilling operations. In one or more other
embodiments, the downhole tool 600 may be actuated into or already
in the active state while performing remedial operations within a
wellbore (e.g., a mill may be coupled to the downhole tool and
rotating to mill casing above or below the downhole tool 600, an
underreamer may be increasing the diameter of the wellbore, a
cementing apparatus may be cementing a rock-to-rock section of the
wellbore, a stuck tool may be fished out of the wellbore, etc.).
The diameter of a drilled wellbore may therefore be determined as
the wellbore is drilled, as drilling operations are conducted, or
as remedial operations are conducted. In drilling or remedial
operations using drilling fluid or other hydraulic fluid, fluid may
flow through the drill string and to the drilling or remedial tool.
Where such tool is below the tool 600, the fluid may flow through
the mandrel 656 of the downhole tool 600 in some embodiments.
[0087] To actuate the downhole tool 600 into the active state, the
hydrostatic pressure of the fluid in a bore (e.g., bore 112 of FIG.
2) within the mandrel 656 of the downhole tool 600 may be
increased. For example, a pump disposed at the surface may increase
the flow rate through a drilling tubular and to the bore in the
downhole tool 600, which may thereby increase the pressure in the
bore. A portion of the fluid may flow from the bore, through a
nozzle, bore, port, or other opening (e.g., opening 196 of FIG. 2)
formed radially through the body 610, and to an annulus formed
between the outer surface of the body 610 and the wall of the
wellbore. The difference pressure in the annulus between the
downhole tool 600 and the wellbore and the pressure within the bore
may result in activation of the downhole tool 600. More
particularly, as the pressure of the fluid in the bore increases
relative to the pressure in the annulus, the fluid may exert an
axial force on a piston (e.g., piston 150 of FIG. 2). For instance,
fluid pressure may build between a lower cap and a head of the
piston. The lower cap may be relatively fixed at an axial position,
and the building pressure may push against the head in a direction
toward the upper end portion 614 of the downhole tool 600. The
force exerted by the increased pressure of the fluid may become
greater than the opposing force exerted by a spring or other
biasing element. When this occurs, the piston may slide or
otherwise move axially toward the upper end portion 614 of the
downhole tool 600.
[0088] As the piston moves toward the upper end portion 614 of the
downhole tool 600, a shaft (e.g., shaft 154 of FIG. 2) of the
piston may also move, and engagement between the teeth (e.g., teeth
166 of FIG. 7) on the shaft of the piston and the teeth (e.g.,
teeth 164 of FIG. 7) on the gears of a gear assemblies (e.g.,
spring gear assembly 160 of FIG. 2) may cause the gears to rotate
(e.g., clockwise). The rotational movement of each gear may be
transferred through the pin slot connector 680 to the arm assembly
640, which may cause the arm assembly 640 to pivot or rotate
radially-outward from the body 610, and therefore into an active
state.
[0089] More particularly, and as described in more detail with
respect to the spring gear assembly 160 of FIG. 8, a gear 168 may
be coupled to a spring 162, and rotational movement of the gear 168
may cause the spring 162 to rotate. The spring 162 may be coupled
to a frame 178, and the rotational movement of the spring 162 may
cause the frame 178 to rotate. The frame 178 may be coupled to the
pin connector 170, and the rotational movement of the frame 178 may
cause the pin connector 170 to rotate. The pin connector 170 may in
turn be coupled to the arm 142 of the arm assembly 140 via the slot
connector 182 (or to the arm assembly 640 of FIGS. 20, 21, 22, 23,
24, and 25), and the rotational movement of the pin connector 170
may cause the arm assembly 140 to pivot or rotate
radially-outward.
[0090] With continued reference to the illustrative embodiment
shown in FIGS. 20, 21, 22, 23, 24, and 25, the arm assemblies 640
may pivot or rotate radially-outward until rollers or other
wellbore engagement elements contact the wall of the wellbore. As
discussed herein, the movement of the arm assemblies 640 may be
measured and translated into a measurement of the diameter or other
geometry of a wellbore wall. When the arm assemblies 640 are
rotated and the rollers or other wellbore engagement elements are
in contact with the wellbore wall, a biasing member (e.g., spring
162 of FIG. 8) may be loaded and may hold the wellbore engagement
elements against the formation while also allowing the arm
assemblies 640 to move with changes in diameter of the
wellbore.
[0091] The downhole tool 600 may rotate about a longitudinal axis
extending therethrough, and the wellbore engagement elements may be
configured to roll or slide along the wall of the wellbore. In at
least one embodiment, one or more of the wellbore engagement
elements may not expand radially-outward (or may expand
radially-outward a lesser amount relative to other wellbore
engagement elements) because the wall of the wellbore may be
contacting or near the outer surface of the body 610 proximate the
corresponding arm assembly 640 (see FIGS. 19-2 and 19-3). In some
embodiments, as the downhole tool 600 rotates the arm assemblies
640 may cyclically expand and retract.
[0092] Each measurement device 624 may sense or measure the angle
that the corresponding arm assembly 640 rotates through as it
transitions from the inactive, retracted state to the active,
expanded state. More particularly, the measurement device 624 may
sense or measure the angle that the arm assembly 640 rotates
through as it rotates radially-outward until the wellbore
engagement element contacts with the wall of the wellbore. The
angle through which the arm assembly 640 rotates may range from
0.degree. to 720.degree. in some embodiments. In some embodiments,
for instance, the angle may be less than a full revolution. For
instance, the angle may range from a low of 0.degree., 1.degree.,
2.degree., 4.degree., 6.degree., or 8.degree. to a high of
10.degree., 15.degree., 20.degree., 30.degree., 40.degree., or
more. For example, the angle may be between 1.degree. and
20.degree., between 2.degree. and 15.degree., or between 2.degree.
and 10.degree..
[0093] Each measurement device 624 may convert the rotary movement
of the corresponding arm assembly 640 into linear or axial movement
of a magnet or other positioning element (see FIGS. 10-17), and an
electronic device, probe, or the like may sense the axial distance
that the positioning element moves. In at least one embodiment, a
probe or electric device may transmit the sensed distance to a MWD,
LWD, or other downhole tool, or to the surface. In another
embodiment, the probe or other electric device may use the sensed
distance to determine the diameter or other geometry of the
wellbore to transmit the diameter of the wellbore to a MWD, LWD,
other downhole tool, or to the surface. In still other embodiments,
the probe or other electronic device may store the information.
[0094] After the measurements are taken and/or the diameter or
other geometry of the wellbore is determined, the downhole tool 600
may be actuated back into the inactive state. To actuate the
downhole tool 600 into the inactive state, hydrostatic pressure of
the fluid in the bore of the downhole tool 600 may be decreased
(e.g., to return the pressure near the pressure within the
annulus). For example, a surface fluid pump may be turned off. The
pressure may decrease until the force exerted by the fluid on the
piston toward the first end portion 614 of the body 610 is less
than the opposing force exerted by a spring or other biasing member
toward a second end portion of the body 610. When the force exerted
by the spring or other biasing member becomes greater than the
force exerted by the fluid, the piston may move axially toward the
lower end portion of the body 610.
[0095] As the piston moves toward the lower end portion of the
downhole tool 600, the engagement between the teeth (see teeth 166
of FIG. 7) on the shaft of the piston and the teeth (see teeth 164
of FIG. 7) on the gears of a spring gear assemblies 660 may cause
the gears (e.g., gears 168 of FIG. 7) to rotate (e.g.,
counterclockwise). The rotational movement of each gear may be
transferred through the pin slot connector 680 to the corresponding
arm assembly 640, which may cause the arm assembly 640 to pivot or
rotate radially-inward into the aperture 622 of the body 610 (i.e.,
into the inactive state).
[0096] In a more particular example shown in FIG. 8, a gear 168 may
be coupled to a spring 162, and the rotational movement of the gear
168 may cause the spring 162 to partially unwind. The spring 162
may be coupled to the frame 178, and the rotational movement of the
spring 162 may cause the frame 178 to rotate. The frame 178 may in
turn be coupled to the pin connector 170, and the rotational
movement of the frame 178 may causes the pin connector 170 to
rotate. The pin connector 170, which may be coupled to the arm 142
of the arm assembly 140 (e.g., via the slot connector 182), may
rotate and cause the arm assembly 140 to pivot or rotate
radially-inward.
[0097] Embodiments of the present disclosure may therefore relate
to a system for measuring a diameter or other geometry of a
wellbore. In accordance with some embodiments of the present
disclosure, wellbore diameter may be obtained by using rollers or
other wellbore engagement elements pushed against a wellbore wall
through use of a spring or other biasing member. Arms connected to
the wellbore engagement elements may rotate as the wellbore
engagement elements are pushed radially-outward, and the wellbore
diameter, wellbore eccentricity, or other wellbore geometry may be
calculated from the rotational position of the arms. A measurement
device may sense the rotation (e.g., by converting the rotational
movement to axial movement of a magnet or other device), and may
communicate the information with one or more sensors within an
electronic or other sensing tube or device. The sensing device save
the data, or may communicate with a MWD, LWD, or other downhole
tool to save data for later use, to send delayed or real-time data
to other devices, or to send delayed or real-time data to the
surface. The data that is saved or sent may be raw measurement data
or may be the calculated wellbore diameter or other geometry.
Moreover, such a downhole tool may be utilized with other downhole
drilling or remedial tools, and while such drilling or remedial
tools are actively operating within the wellbore. In still other
embodiments, components of some embodiments of the present
disclosure (e.g., spring gear assemblies, measurement devices, pin
slot connectors, mandrel couplings, etc.) may be used in other
devices or systems other than in connection with a device for
measuring wellbore geometry.
[0098] A method is disclosed for coupling components together and
may include inserting a component into an aperture formed between a
body and a mandrel within the body. The component may be moved
axially in one direction within the aperture until a shoulder
extending radially outward from the component contacts a radial
surface of the body. The mandrel may also be moved axially in the
first direction until a shoulder extending radially outward from
the mandrel contacts the component.
[0099] According to some embodiments, the component coupled to the
mandrel includes a device configured to measure wellbore
geometry.
[0100] According to some embodiments, moving the mandrel axially in
the first direction includes rotating a cap within the body.
[0101] According to some embodiments, the cap and mandrel are
configured to be threadably engaged together.
[0102] According to some embodiments, inserting the component into
the aperture includes engaging a protrusion of the component with
an axial slot formed in an outer surface of the mandrel.
[0103] According to some embodiments, the shoulder extending
radially-outward from the mandrel is substantially perpendicular
with respect to a longitudinal axis extending through the mandrel.
In other embodiments, the shoulder extending radially-outward from
the mandrel is tapered at an angle from 5.degree. to 75.degree.
with respect to a longitudinal axis.
[0104] Additional embodiments relate to a device for measuring
wellbore geometry and include an arm that can rotate about an axis
extending through a pivot of the arm. A gear shaft may be coupled
to the pivot of the arm and can rotate in response to rotation of
the arm about the axis. A position indicator may be coupled to the
gear shaft in a way allowing the position indicator to move axially
in response to rotation of the gear shaft.
[0105] According to some embodiments, the device for measuring
wellbore geometry may further include a housing in which the gear
shaft and position indicator are located.
[0106] According to some embodiments, the device for measuring
wellbore geometry may include a piston coupled to the gear shaft
within the housing. The piston may be movable in an axial direction
in response to rotation of the gear shaft.
[0107] According to some embodiments, the device for measuring
wellbore geometry may use a magnet as the position indicator, and
the magnet may move in response to axial movement of the
piston.
[0108] According to some embodiments, the piston may be disposed
with a fluid in the housing, and the piston may cause fluid to move
or be compressed so as to exert a force on the magnet, thereby
causing the magnet to move in the axial direction within the
housing.
[0109] According to some embodiments, a gear may be coupled to the
gear shaft and configured to rotate in response to rotation of the
gear shaft.
[0110] According to some embodiments, a pulley may be coupled to
the gear and the position indicator. The pulley may be configured
to rotate in response to rotation of the gear.
[0111] According to some embodiments, a cable may be coupled to the
pulley and the position indicator, and the cable may be configured
to move the position indicator axially in response to rotation of
the pulley.
[0112] Devices for measuring wellbore geometry may also include a
downhole tool for measuring wellbore geometry while performing
drilling or remedial operations. A body may define a bore passing
through a full or partial portion of the body, and a mandrel may be
positioned in the bore. A measurement device may be located between
the body and the mandrel, and may include a housing, a gear shaft
in the housing, and a position indicator within the housing and
which moves linearly in response to rotation of the gear shaft. An
arm may also be coupled to an end portion of the gear shaft to
rotate about an axis and cause the gear shaft to rotate.
[0113] According to some embodiments, an arm may be configured to
rotate radially outward from the body and into contact with a wall
of a wellbore, and linear movement of the position indicator may be
proportional or otherwise related to extent of the radially outward
movement of the arm and/or to the wellbore geometry.
[0114] According to some embodiments, a gear is coupled to the gear
shaft and rotates in response to rotation of the gear shaft, while
a pulley is coupled to the gear and rotates in response to rotation
of the gear.
[0115] According to some embodiments, a cable is coupled to the
pulley and position indicator and moves the position indicator
linearly as the pulley rotates.
[0116] According to some embodiments, there may be multiple
measurement devices and the downhole tool may include two
measurement devices circumferentially offset from each other about
the mandrel. A position indicator of one measurement device may be
in a first zone while a position indicator of a second measurement
device may be in a second zone that is axially offset from the
first zone.
[0117] In the description herein, various relational terms are
provided to facilitate an understanding of various aspects of some
embodiments of the present disclosure. Relational terms such as
"bottom," "below," "top," "above," "back," "front," "left",
"right", "rear", "forward", "up", "down", "horizontal", "vertical",
"clockwise", "counterclockwise," "upper", "lower", and the like,
may be used to describe various components, including their
operation and/or illustrated position relative to one or more other
components. Relational terms do not indicate a particular
orientation for each embodiment within the scope of the description
or claims. For example, a component of a BHA that is "below"
another component may be more downhole while within a vertical
wellbore, but may have a different orientation during assembly,
when removed from the wellbore, or in a deviated borehole.
Accordingly, relational descriptions are intended solely for
convenience in facilitating reference to various components, but
such relational aspects may be reversed, flipped, rotated, moved in
space, placed in a diagonal orientation or position, placed
horizontally or vertically, or similarly modified. Relational terms
may also be used to differentiate between similar components;
however, descriptions may also refer to certain components or
elements using designations such as "first," "second," "third," and
the like. Such language is also provided merely for differentiation
purposes, and is not intended limit a component to a singular
designation. As such, a component referenced in the specification
as the "first" component may for some but not all embodiments be
the same component that referenced in the claims as a "first"
component.
[0118] Furthermore, to the extent the description or claims refer
to "an additional" or "other" element, feature, aspect, component,
or the like, it does not preclude there being a single element, or
more than one, of the additional element. Where the claims or
description refer to "a" or "an" element, such reference is not be
construed that there is just one of that element, but is instead to
be inclusive of other components and understood as "one or more" of
the element. It is to be understood that where the specification
states that a component, feature, structure, function, or
characteristic "may," "might," "can," or "could" be included, that
particular component, feature, structure, or characteristic is
provided in some embodiments, but is optional for other embodiments
of the present disclosure. The terms "couple," "coupled,"
"connect," "connection," "connected," "in connection with," and
"connecting" refer to "in direct connection with," "integral with,"
or "in connection with via one or more intermediate elements or
members."
[0119] Although various example embodiments have been described in
detail herein, those skilled in the art will readily appreciate in
view of the present disclosure that many modifications are possible
in the example embodiments without materially departing from the
present disclosure. Accordingly, any such modifications are
intended to be included in the scope of this disclosure. Likewise,
while the disclosure herein contains many specifics, these
specifics should not be construed as limiting the scope of the
disclosure or of any of the appended claims, but merely as
providing information pertinent to one or more specific embodiments
that may fall within the scope of the disclosure and the appended
claims. Any described features from the various embodiments
disclosed may be employed in combination. In addition, other
embodiments may also be devised which lie within the scopes of the
disclosure and the appended claims. Each addition, deletion, and
modification to the embodiments that falls within the meaning and
scope of the claims is to be embraced by the claims.
[0120] While embodiments disclosed herein may be used in an oil,
gas, or other hydrocarbon exploration or production environment,
this environment merely illustrates one environment in which
embodiments of the present disclosure may be used. Systems, tools,
assemblies, methods, and other components discussed herein, or
which would be appreciated in view of the disclosure herein, may be
used in other applications and environments, including in
automotive, aquatic, aerospace, hydroelectric, or even other
downhole environments. The terms "wellbore," "borehole," and the
like are therefore also not intended to limit embodiments of the
present disclosure to a particular industry or environment. A
wellbore or borehole may, for instance, be used for oil and gas
production and exploration, water production and exploration,
mining, utility line placement, or myriad other applications.
[0121] Certain embodiments and features may have been described
using a set of numerical upper limits and a set of numerical lower
limits. It should be appreciated that ranges including the
combination of any two values, e.g., the combination of any lower
value with any upper value, the combination of any two lower
values, and/or the combination of any two upper values are
contemplated unless otherwise indicated. Certain lower limits,
upper limits and ranges may appear in the description and/or one or
more claims. Any numerical value is "about" or "approximately" the
indicated value, and takes into account experimental error and
variations that would be expected by a person having ordinary skill
in the art.
* * * * *