Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
TOOL FOR MEASURING WELLBORE GEOMETRY
FIELD OF THE INVENTION
[1] 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
[2] Wel!bores 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.
[3] 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
[4] 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.
1
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
[5] 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.
[6] 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.
[7] 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
[8] 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.
[9] 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.
2
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
[10] 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.
[11] 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.
[12] 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.
[13] 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.
[14] 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.
[15] 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.
[16] 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.
[17] 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.
[18] 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.
[19] FIG. 11 is a partial perspective view of the measurement device of
FIG. 10,
according to one or more embodiments of the present disclosure.
[20] 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.
[21] 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.
[22] FIG. 14 is cross-sectional view of a measurement device in a downhole
tool,
according to one or more embodiments of the present disclosure.
3
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
[23] 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.
[24] 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.
[25] 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.
[26] 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.
[27] 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.
[28] 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.
[29] 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.
[30] 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.
[31] 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.
[32] 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.
[33] 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.
4
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
[34] 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.
[35] 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.
[36] 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.
[37] 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
[38] 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.
[39] 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
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
other embodiments, the upper and/or lower end portions 114, 116 may have other
types of connectors.
[40] 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.
[41] 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.
[42] 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
6
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[43] 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.
[44] 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
7
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[45] 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.
[46] 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.
[47] 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,
8
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[48] 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.
[49] 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.
[50] 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
9
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[51] 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.
[52] 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.
[53] 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 and 270 of the gear
168;
although, in other embodiments the teeth 164 may extend around less than 90
or
greater than 270 of the gear 168. In more particular example embodiments, the
teeth 164 may extend around between 130 and 150 , between 140 and 160 ,
between 150 and 170 , between 160 and 180 , between 170 and 190 , between
180 and 200 , or between 190 and 210 , between 200 and 220 , or between 210
and 230 . In some embodiments, the teeth 164 may extend around a full
circumference of the gear 168.
[54] 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
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[55] 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.
[56] 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.
[57] 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
11
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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¨may have more than two (2) coils or may have a single
coil.
[58] 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.
[59] 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.
[60] 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
12
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[61] 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.
[62] 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.
[63] 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
13
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
movement of the magnet may be proportionally related to the
rotational/pivoting
movement of the arm 142.
[64] 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.
[65] 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
14
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[66] 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.
[67] 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.
[68] 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,
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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 cm2 and 100 cm2. For instance, the cross-
sectional area may be between 5 cm2 and 10 cm2, between 10 cm2 and 20 cm2,
between 20 cm2 and 40 cm2, or between 40 cm2 and 60 cm2. In other embodiment,
the cross-sectional area may be less than 5 cm2 or greater than 100 cm2.
[69] 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.
[70] 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 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 . 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.
16
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
[71] 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.
[72] 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.
[73] 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.
[74] 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
17
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[75] 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.
[76] 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.
[77] 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
18
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[78] 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.
[79] 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-
19
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[80] 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.
[81] 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.
[82] 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
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
to the measurement device 624 before or after insertion of the measurement
device
into the aperture 622.
[83] 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.
[84] 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 and 1300. For instance, the angle may range from a low of 50,
10 ,
20 , or 30 to a high of 450, 60 , 750, or more with respect to the
longitudinal axis
extending through the mandrel 656 and/or body 610 (where 90 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.
[85] 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.
21
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[86] 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
22
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[87] 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.
[88] 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
23
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[89] 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.
[90] 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.
[91] 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.
[92] 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
24
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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 to 720 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 , 1 , 2 , 4 , 6 , or 8 to a
high of 10 ,
15 , 20 , 30 , 40 , or more. For example, the angle may be between 1 and 20 ,
between 2 and 15 , or between 2 and 10 .
[93] 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.
[94] 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.
[95] 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
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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).
[96] 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.
[97] 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.
26
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
[98] 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.
[99] According to some embodiments, the component coupled to the mandrel
includes a device configured to measure wellbore geometry.
[100] According to some embodiments, moving the mandrel axially in the first
direction includes rotating a cap within the body.
[101] According to some embodiments, the cap and mandrel are configured to be
threadably engaged together.
[102] 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.
[103] 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 to 75 with
respect
to a longitudinal axis.
[104] 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.
[105] 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.
[106] 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.
27
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
[107] 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.
[108] 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.
[109] 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.
[110] 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.
[111] 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.
[112] 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.
[113] 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.
[114] 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.
[115] According to some embodiments, a cable is coupled to the pulley and
position indicator and moves the position indicator linearly as the pulley
rotates.
[116] According to some embodiments, there may be multiple measurement
devices and the downhole tool may include two measurement devices
28
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
[117] 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.
[118] 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
29
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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."
[119] 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.
[120] 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.
[121] 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
CA 02906559 2015-09-14
WO 2014/159861
PCT/US2014/025351
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.
31
