U.S. patent application number 14/803654 was filed with the patent office on 2015-11-12 for hydraulically locked tool.
The applicant listed for this patent is Smith International, Inc.. Invention is credited to Timothy A. Burdett, Nathan E. Fuller.
Application Number | 20150322725 14/803654 |
Document ID | / |
Family ID | 55218190 |
Filed Date | 2015-11-12 |
United States Patent
Application |
20150322725 |
Kind Code |
A1 |
Fuller; Nathan E. ; et
al. |
November 12, 2015 |
HYDRAULICALLY LOCKED TOOL
Abstract
A tool with a hydraulic lock mechanism may include a body
defining a flow tube and a chamber. An expandable member may be
coupled to the body. A first valve may be located between the
chamber and the flow tube to control the flow of fluid into the
chamber from the flow tube. A second valve may located between the
chamber and an external environment to control the flow of fluid
from the chamber into the external environment. The first and
second valves may trap fluid within the chamber to maintain the
tool in an active position. A piston may be connected to the
expandable member and may move in response to pressurization of the
chamber. At one position, the piston may cause the expandable
member to extend to a radially outward position. At another
position, the piston may cause the expandable member to retract to
a radially inward position.
Inventors: |
Fuller; Nathan E.; (Spring,
TX) ; Burdett; Timothy A.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Smith International, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
55218190 |
Appl. No.: |
14/803654 |
Filed: |
July 20, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61031665 |
Feb 26, 2008 |
|
|
|
Current U.S.
Class: |
166/373 ;
166/381; 175/267; 175/269 |
Current CPC
Class: |
E21B 7/28 20130101; E21B
23/00 20130101; E21B 10/322 20130101; E21B 34/06 20130101; E21B
34/066 20130101 |
International
Class: |
E21B 10/32 20060101
E21B010/32; E21B 34/06 20060101 E21B034/06; E21B 7/28 20060101
E21B007/28 |
Claims
1. A downhole tool for reaming a wellbore, comprising: a body
having an inner surface that defines a bore, the body further
having a chamber defined therein; an expandable member movably
coupled to the body; a moveable element movably coupled to the body
and configured to move to cause the expandable member to move
between a retracted position and a deployed position; and at least
one valve providing fluid communication between the bore and the
chamber, the at least one valve being configured to facilitate
pressurizing the chamber to move the expandable member toward the
deployed position and to facilitate releasing pressure in the
chamber to allow the expandable member to move toward the retracted
position.
2. The downhole tool of claim 1, the at least one valve including a
check valve configured to facilitate fluid flow: from the bore to
the chamber and to restrict flow from the chamber to the bore; or
from the chamber to an external environment and to restrict flow
from the external environment to the chamber.
3. The downhole tool of claim 1, further comprising: a bias element
configured to apply a force to the expandable member to move the
expandable member toward the retracted position.
4. The downhole tool of claim 1, the moveable element being located
at least partially within the chamber and configured to apply a
force to the expandable member to move the expandable member toward
the deployed position.
5. The downhole tool of claim 1, the at least one valve including a
first valve configured to open to allow fluid to enter the chamber
from the bore when a differential pressure across the first valve
is greater than an opening pressure setpoint of the first
valve.
6. The downhole tool of claim 1, further comprising: a controller
coupled to the at least one valve and configured to: open the at
least one valve; close the at least one valve; adjust an opening
pressure setpoint of the at least one valve; or adjust a closing
pressure setpoint of the at least one valve.
7. A tool comprising: a body having a flow tube and chamber
therein; a cutter block coupled to the body; a first valve
selectively connecting the chamber and the flow tube in fluid
communication; a second valve selectively connect the chamber and
an external environment in fluid communication; and a piston
coupled to the cutter block, the piston being movable between first
and second positions in response to pressurization of the chamber,
the first position corresponding to a position in which the cutter
block is extended in a radially outward position and a the second
position corresponding to a position in which the cutter block is
retracted in a radially inward position.
8. The tool of claim 7, further comprising: a bias element that
biases the piston toward the second position.
9. The tool of claim 7, further comprising: a controller coupled to
the first and second valves, the controller being configured to
receive downlink signals and control the first and second valves in
response to the downlink signals.
10. The tool of claim 7, the chamber having a radially outward
boundary defined at least in part by the body and a radially inward
boundary defined at least in part by the flow tube.
11. A method of operating a downhole tool, the method comprising:
tripping a drill string into a wellbore, the drill string being
coupled to a downhole tool; providing a supply fluid to the
downhole tool; transitioning the downhole tool into an active state
while off a bottom of the wellbore and in response to the supply
fluid being at a first pressure; reducing a pressure of the supply
fluid to a second pressure that is below the first pressure; and
maintaining the downhole tool in the active state while reducing
the pressure of the supply fluid to the second pressure by
maintaining a quantity of fluid in the downhole tool at or above
the first pressure.
12. The method of claim 11, wherein reducing the pressure of the
supply fluid to the second pressure includes providing less than 10
L/m of the supply fluid into the wellbore while maintaining the
downhole tool in the active state.
13. The method of claim 11, wherein maintaining the downhole tool
in the active state includes hydraulically locking the downhole
tool in the active state.
14. The method of claim 11, wherein transitioning the downhole tool
into the active state includes actuating a first valve, and wherein
reducing the pressure of the supply fluid to the second pressure
includes closing the first valve to maintain the quantity of fluid
at or above the first pressure.
15. The method of claim 11, further comprising: transitioning the
downhole tool into an inactive state by at least one of: increasing
a pressure of the quantity of fluid to a third pressure that is
above the first pressure; decreasing a pressure of fluid external
to the downhole tool; or using a controller responsive to downlink
signals from a surface of the wellbore.
16. The method of claim 15, the downhole tool being configured to
release the quantity of fluid when at the third pressure, and
wherein increasing the pressure of the quantity of fluid includes
applying a mechanical force to the drill string, the mechanical
force causing an expandable member to exert a force on the quantity
of fluid and increase the pressure to the third pressure.
17. The method of claim 19, wherein decreasing the pressure of
fluid external to the downhole tool includes: increasing a pressure
differential across a valve to cause the valve to open; and
releasing fluid from a chamber through the valve to an external
environment to cause a piston to move such that an expandable
member retracts to a radially inward position.
18. The method of claim 20, wherein using the controller includes:
downlinking a signal to the controller in the downhole tool to
cause a valve to open or to change a pressure setpoint of the
valve; releasing fluid from a chamber through the valve; and
causing a piston to move such that an expandable member retracts to
a radially inward position.
19. The method of claim 14, wherein transitioning the downhole tool
into the active state includes: increasing a pressure differential
across a first valve; and pressurizing a chamber with the supply
fluid by flowing the supply fluid through the first valve to move a
piston, the piston acting to extend an expandable member to a
radially outward position.
20. The method of claim 14, wherein transitioning the downhole tool
into the active state includes: downlinking a signal to a
controller in the downhole tool, the downlinking signal being
configured to: cause the first valve to open; change an opening
pressure setpoint of the first valve; or change a closing pressure
setpoint of the first valve; and pressurizing a chamber with the
supply fluid by flowing the supply fluid through the first valve to
move a piston, the piston acting to extend an expandable member to
a radially outward position.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of, and priority to,
U.S. Patent Application Ser. No. 62/031,665, titled "Tool with
Hydraulic Lock Mechanism," and filed on Jul. 31, 2014, which
application is expressly incorporated herein by this reference in
its entirety.
BACKGROUND
[0002] In the drilling of oil and gas wells, concentric casing
strings are installed and cemented in the wellbore as drilling
progresses to increasing depths. Each new casing string is
supported within the previously installed casing string, thereby
limiting the annular area available outside the uppermost casing
strings for the cementing operation. As successively smaller
diameter casing strings are suspended, the flow area for the
production of oil and gas inside the casing strings decreases as
the distance from the surface increases.
[0003] The diameter of the wellbore below the lower end portion of
the previous casing string or other locations in a wellbore may be
enlarged for various reasons. For example, the diameter of the
wellbore may be enlarged to provide clearance for running casing,
to obtain adequate annular space in the hole for cementing, to
enlarge zones for gravel pack completion or cementing, and for
other purposes.
[0004] Reamers are used for enlarging the diameter of the wellbore.
A reamer generally has two states. In an inactive or retracted
state, the cutter blocks of the reamer are in a radially inward,
retracted position and the reamer maintains a diameter small enough
to pass through the existing casing strings. In an active,
expanded, or deployed state, the cutter blocks are in an outward,
radially extended position where the cutter blocks can be used to
enlarge the diameter of the wellbore.
[0005] Changing the state of a reamer or actuating other downhole
tools in a wellbore is often accomplished by dropping a ball down a
bore of a drill string to break shear pins using back pressure
caused by the drilling mud building up pressure behind the ball as
the ball obstructs the path of the drilling mud. After the shear
pins break, a valve may be free to open or actuate a downhole tool,
such as a reamer. Once the valve is open, the drilling mud may be
used to move the cutter blocks to the active state.
[0006] A drilling system may continually pump drilling fluid or mud
down through the drilling system to the downhole tools, then out
into the wellbore annulus and back up to the surface. The drilling
mud may cool the downhole drilling system, flush cuttings back up
to the surface, and provide pressure to hold the downhole tools in
a position that facilitates operation of the tool, such as holding
the cutter blocks of a reamer in an active position with enough
force to ream and enlarge the wellbore. Once the drilling tool has
completed an operation, such as when a wellbore has been enlarged
by a reamer, the downhole tool and the drill string may be removed
from the wellbore.
SUMMARY
[0007] In one non-limiting embodiment, a downhole tool for reaming
a wellbore is disclosed. The downhole tool may include a body that
defines a bore and a chamber. An expandable member may be coupled
to the body and movable by a movable element that also moves
relative to the body. The movable element may move the expandable
member between retracted and deployed positions. Valves may also be
used to move the expandable member. The valves may provide fluid
communication between the bore and the chamber and may be used to
pressurize the chamber to move the expandable member toward the
deployed position. The valves may also facilitate releasing
pressure in the chamber to move the expandable member toward the
retracted position.
[0008] In another non-limiting embodiment, a tool is disclosed. The
too may include a body with a flow tube and a chamber. A cutter
block may be coupled to the body and a valve may selectively allow
the chamber and the flow tube to be in communication. Another valve
may selectively allow the chamber and an external environment to be
in fluid communication. A piston may be coupled to the cutter block
and may move in response to pressurization of the chamber. The
piston may move from one position in which the cutter block is
extended in a radially outward position to another position in
which the cutter block is retracted in a radially inward
position.
[0009] In a further non-limiting embodiment, a method of operating
a downhole tool is disclosed. The method may include tripping a
drill string into a wellbore. The drill string may be coupled to a
downhole tool. A supply fluid may be provided to the downhole tool
and the downhole tool may transition into an active state while
off-bottom in the wellbore. The transition to the active state may
be in response to the supply fluid being at a first pressure. A
pressure of the supply fluid may be reduced to a lower, second
pressure while the downhole tool is maintained in the active state.
Maintaining the downhole tool in the active state may include
maintaining a quantity of fluid in the downhole tool at or above
the first pressure.
[0010] 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
[0011] FIG. 1 is a perspective view of a downhole tool according to
one or more embodiments disclosed herein;
[0012] FIG. 2 is a cross-sectional view of a downhole tool with
valves in an inactive state according to one or more embodiments
disclosed herein;
[0013] FIG. 3 is a detailed cross-sectional view of a downhole tool
with valves in an inactive state according to one or more
embodiments disclosed herein;
[0014] FIG. 4 is a cross-sectional view of a downhole tool with
valves in an active state according to one or more embodiments
disclosed herein;
[0015] FIG. 5 is a cross-sectional view of a downhole tool with
valves in an active state and which includes a casing shoe
according to one or more embodiments disclosed herein;
[0016] FIG. 6 is a detailed cross-sectional view of a downhole tool
with control valves in an inactive state according to one or more
embodiments disclosed herein;
[0017] FIG. 7 is a detailed cross-sectional view of a downhole tool
with control valves in an active state according to one or more
embodiments disclosed herein;
[0018] FIG. 8 depicts an illustrative method of operating a
downhole tool according to one or more embodiments disclosed
herein;
[0019] FIG. 9 depicts an illustrative method of activating a
downhole tool according to one or more embodiments disclosed
herein;
[0020] FIG. 10 depicts an illustrative method of deactivating a
downhole tool according to one or more embodiments disclosed
herein;
[0021] FIG. 11 depicts another illustrative method of activating a
downhole tool according to one or more embodiments disclosed
herein; and
[0022] FIG. 12 depicts another illustrative method of deactivating
a downhole tool according to one or more embodiments disclosed
herein.
DETAILED DESCRIPTION
[0023] Some embodiments of the present disclosure relate to
expandable tools. Some embodiments described herein generally
relate to downhole tools. Some embodiments described herein
generally relate to reamers. More particularly, some embodiments
herein relate to reamers for increasing the diameter of a
wellbore.
[0024] FIGS. 1 through 5 illustrate an embodiment of a downhole
tool 100, the illustrated embodiment of downhole tool 100 including
an expandable tool such as a reamer. Other examples of expandable
tools may include, but are not limited to, stabilizers, section
mills, expandable anchors, bridge plugs, and the like. With
reference to FIG. 1, downhole tool 100 may include a body 102 with
one or more expandable members. The expandable members in FIG. 1
may include cutter blocks 104 for use in a reaming operation. In
other embodiments, such as where the downhole tool 100 includes
other expandable tools, the expandable members may include, but are
not limited to, stabilizers blades, section mill blades, anchor
slips, sealing members, and the like. FIG. 1 depicts the cutter
blocks 104 in a retracted or deactivated position, and the downhole
tool 100 in a deactivated or inactive state.
[0025] FIGS. 2 and 3 depict cross-sectional views of the downhole
tool 100 according to one or more embodiments disclosed herein. The
body 102 of the downhole tool 100 may be substantially tubular or
cylindrical and may include an axial bore 110 extending at least
partially therethrough. The body 102 may be a single component, or
the body 102 may be two or more components coupled together.
[0026] The cutter blocks 104 may be movably coupled to the body 102
to move between a retracted position, as shown in FIGS. 1 and 2,
and an expanded or deployed position, as shown in FIGS. 4 and 5.
The number of cutter blocks 104 may vary between embodiments. For
instance, there may be between 1 and 20 cutter blocks 104. In at
least some embodiments, the number of cutter blocks 104 may be
within a range having lower and/or upper limits that include any of
1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 12, 15, 20, or values therebetween.
For example, there may be between 2 and 5 cutter blocks 104 or
between 3 and 8 cutter blocks 104. In a more particular embodiment,
the body 102 may have 3 cutter blocks 104. In some embodiments the
cutter blocks 104 may be evenly spaced around a longitudinal axis
of the downhole tool 100. For example, the cutter blocks 104 may be
120.degree. apart around the longitudinal axis. In other
embodiments, the cutter blocks 104 may be spaced more or less than
120.degree.. The cutter blocks 104 may be evenly or unevenly spaced
around the longitudinal axis.
[0027] The downhole tool 100 may be configured to actuate from a
first or inactive state (for example, as shown in FIGS. 1, 2, and
3) to a second or active state (as shown in FIGS. 4 and 5). When
the downhole tool 100 is in the inactive state, the cutter blocks
104 may be retracted. In some embodiments, when the cutter blocks
104 are in an inactive or retracted position, the outer surfaces
116 of the cutter blocks 104 may be aligned with, or positioned
radially inward from, the outer surface 112 of the body 102. The
external surface of the body 102 may have an overall shape of an
undergauge stabilizer and the cutter blocks 104 may be contained in
the blades of the undergauge stabilizer. In some embodiments, the
external surface of the body 102 may be slick, straight, tapered,
fluted, or have other configurations, or have portions with
different configurations.
[0028] When the downhole tool 100 is in the inactive state, the
outer surface 116 of each of the cutter blocks 104 may be retracted
radially inward of the outer surface of a stabilizer blade. Such
state of the downhole tool 100, similar to an undergauge
stabilizer, may permit sufficient annular flow passage along the
downhole tool 100.
[0029] In some embodiments, when the downhole tool 100 is in the
inactive state, the outer surface 116 of the cutter blocks 104 may
be positioned radially outward from the outer surface 112 of the
body 102. When the cutter blocks 104 are positioned radially
outward from the body 102 in the retracted position, the cutter
blocks 104 may stabilize the body 102 in a wellbore. In at least
some embodiments, when the downhole tool 100 is in the inactive
state, the cutter blocks 104 may operate as an undergauge
stabilizer.
[0030] In some embodiments, the cutter blocks 104 may have a
plurality of splines, rails, or other features (collectively
splines 114) formed on their surfaces. For instance, the splines
114 may be formed on one or more side or lateral surfaces of the
cutter blocks 104. The splines 114 may be or include, for example,
offset ridges or protrusions that engage corresponding grooves,
depressions, or channels (collectively grooves 115) in the body
102. The splines 114 on the cutter blocks 104 and the corresponding
grooves 115 on the body 102 may be oriented at an angle with
respect to a longitudinal axis through the body 102, for example,
longitudinal axis A. In other embodiments, the cutter blocks 104
may include pivoting elements that facilitate transition between
active and inactive states. Such pivoting elements may be used in
addition to, or instead of, the splines 114 or other features that
facilitate translational movement of the cutter blocks 104.
[0031] When the downhole tool 100 transitions from the inactive
state to the active state, the engagement of the splines 114 on the
cutter blocks 104 and the grooves 115 in the body 102 may cause the
cutter blocks 104 to move radially outward as the cutter blocks 104
are urged axially along the longitudinal axis A of the body 102.
These radially outward and axial movements of the cutter blocks 104
reflect a transition of the downhole tool 100 from an inactive
state, in which the cutter blocks 104 are in a retracted position,
into an active state, in which the cutter blocks 104 are in a
deployed or expanded position. When the downhole tool 100 is in an
active state, the outer surfaces 116 of the cutter blocks 104 may
be positioned radially outward from the outer surface 112 of the
body 102, or further radially outward as compared to the position
of the outer surfaces 116 when the cutter blocks 104 are in the
retracted position.
[0032] The cutter blocks 104 may each have cutting elements 106
coupled thereto. In some embodiments, the cutting elements 106 may
be coupled to, and extend outwardly from, the outer surface 116 of
the cutter blocks 104. In the same or other embodiments, the
cutting elements 106 may be coupled to, and extend outwardly from,
lateral or side surfaces of the cutter blocks 104. In at least some
embodiments, the cutter blocks 104 may include pockets or recesses
in which cutting elements 106 may be positioned and then brazed,
welded, or otherwise secured therein. In other embodiments, the
cutting elements 106 may be coupled to the cutter block 104 in
other manners. For instance, the cutting elements 106 may be
applied as hardfacing or crushed carbide, impregnated within the
body of the cutter blocks 104, or in other manners. The cutting
elements 106 on the cutter blocks 104 may be configured to cut,
grind, shear, crush, or otherwise deform or remove a portion of the
wall of the wellbore to increase the diameter of the wellbore when
the downhole tool 100 is in the active state.
[0033] In some embodiments, the cutter blocks 104 may also include
a plurality of stabilizer pads 105 and/or gauge protection elements
107 (see FIG. 1) coupled thereto. The stabilizer pads 105 and gauge
protection elements 107 may be located on, or coupled to, the outer
surface 116 of the cutter blocks 104. In some embodiments, the
gauge protection elements 107 may be located within the stabilizer
pads 105. For instance, the gauge protection elements 107 may be
located in pockets formed in the stabilizer pad 105. In other
embodiments, the gauge protection elements 107 may be positioned
outside of the stabilizer pads 105, applied as hardfacing or
crushed carbide, or excluded. When the cutter blocks 104 include
cutting elements 106, stabilizer pads 105, gauge protection
elements 107, other structures, or any combination of the
foregoing, the downhole tool 100 may function as a cleanout
stabilizer. When the cutter blocks 104 include stabilizer pads 105
and/or gauge protection elements 107, but no cutting elements 106,
the downhole tool 100 may function as an expandable stabilizer. In
some embodiments, an expandable stabilizer may be run in
conjunction with a reamer (e.g., in a bottomhole assembly that also
includes a reamer). While the illustrated stabilizer pads 105 are
shown in FIG. 1 as being located at an intermediate location along
the axial length of the cutter blocks 104, in the same or other
embodiments, the stabilizer pads 105 may be located at one or more
axial ends of the cutter blocks 104.
[0034] When the downhole tool 100 is in an inactive state, the
cutter blocks 104 may remain retracted and potentially recessed
within the body 102, and the outer surface 116 of the cutter blocks
104 may remain radially inward of, or aligned with, the outer
surface 112 of the body 102. For example, the cutter blocks 104 may
be held in the retracted position by a piston 118 and/or the
biasing force of a spring 128 or other bias element. The spring 128
or other bias element may also hold the piston 118 in a particular
position (e.g., a position corresponding to the inactive position
of the cutter blocks 104).
[0035] The downhole tool 100 may be in an inactive state while
tripping into a wellbore. While the downhole tool 100 is in the
inactive state, an equalization valve 124 may facilitate equalizing
of the pressure within a chamber 134 and the pressure of the
environment outside the body 102. One example of an environment
that is outside or external the body 102 is the annulus of a
wellbore. The pressure inside the chamber 134 may therefore be
substantially equal to the pressure in the annulus, and in some
embodiments there may be no force within the chamber to counteract
the force of the spring 128. The equalization valve 124 may be
located within a port, opening, or channel (e.g., port 123). The
port 123 may, in some embodiments, connect two volumes, such as an
annulus and a pressure chamber, in fluid communication.
[0036] In some embodiments, the equalization valve 124 may be a
check valve. In such embodiments, the equalization valve 124 may be
set to have opening and closing pressure setpoints that are low
relative to other pressure setpoints within the downhole tool 100,
or low relative to other pressure setpoints the equalization valve
124 may use when the equalization valve 124 is adjustable. For
example, the equalization valve 124 may be set to open and/or close
at a pressure between 5 psi and 100 psi (0.03 MPa and 0.69 MPa). In
a more particular embodiment, the equalization valve 124 may be set
to open and/or close at a pressure within a range having lower
and/or upper limits including any of 5 psi, 10 psi, 15 psi, 20 psi,
30 psi, 45 psi, 60 psi, 80 psi, 100 psi (0.03 MPa, 0.07 MPa, 0.10
MPa, 0.14 MPa, 0.21 MPa, 0.31 MPa, 0.41 MPa, 0.55 MPa, or 0.69
MPa), any value therebetween, or any other pressure that
facilitates operation of the downhole tool 100. In other
embodiments, the opening and/or closing pressure setpoints may be
less than 5 psi or greater than 100 psi (0.03 MPa and 0.69 MPa). In
some embodiments, low pressure setpoints allow the equalization
valve 124 change or actuate to an open position and facilitate flow
from the annulus into the chamber 134, but, when the pressure
across the valve from the annulus to the chamber 134 becomes lower
than the low pressure setpoint, the equalization valve 124 may
change to or actuate to a closed position, thereby restricting flow
from the chamber 134 into the annulus.
[0037] In addition to the equalization valve 124, and as shown in
FIG. 3, the downhole tool 100 may also include a mandrel valve 126
and/or a body valve 122. In some embodiments, the mandrel valve 126
may be located within a port, opening or channel (e.g. port 125)
and the body valve 122 may also be located within a port, opening,
or channel (e.g., port 121). The port 125 associated with the
mandrel valve 126 may, in some embodiments, be formed in a mandrel
108 of the downhole tool 100. In at least some embodiments, the
port 125 may extend through a portion of the mandrel 108. For
instance, the port 125 may extend radially through the mandrel 108,
and between a flow tube 136 or interior bore of the mandrel 108 and
the chamber 134 along an outer surface of the mandrel 108. The port
121 associated with the body valve 122 may, in some embodiments, be
formed in the body 102 of the downhole tool 100. In at least some
embodiments, the port 122 may extend through the body 102. For
instance, the port 122 may extend radially through the body 102,
and between the chamber 134 along an interior surface of the body
102 and an annulus of a wellbore. In some embodiments, the mandrel
valve 126 may be a mechanical check valve. The mandrel valve 126
may allow flow from the flow tube 136 into the chamber 134, but not
allow flow from the chamber 134 into the flow tube 136. Thus, when
the mandrel valve 126 is open, the flow tube 136 may be in fluid
communication with the chamber 134 though the port 122 in the
mandrel 108.
[0038] In some embodiments, a valve, such as a check valve or the
mandrel valve 126, may fluidly couple a supply chamber (e.g., flow
tube 136) with a pressure chamber (e.g. chamber 124). In some
embodiments, pressurized fluid may flow from the supply chamber,
through an open valve (e.g., mandrel valve 126), and into the
pressure chamber. In some embodiments, the pressurized fluid within
the pressure chamber may act on a piston (e.g., piston 118) or
other moveable element.
[0039] During drilling operations, drilling fluid or drilling mud
may be pumped through the flow tube 136 for any of various uses.
For example, the drilling fluid or mud may flow through the flow
tube 136 to operate downhole tools, cool cutting elements, clear
cuttings away from the face of a cutting tool, carry cuttings up a
wellbore, perform other operations, or perform any combination of
the foregoing. For such operations, a pressure of the drilling
fluid or drilling mud may be less than a pressure at which the
mandrel valve 126 is configured to open. For instance, in order to
use pressurized mud during drilling operations without opening the
mandrel valve 126 and forcing drilling mud into the chamber 134,
the mandrel valve 126 may open at or above a mud pressure setpoint
higher than a relatively lower pressure of the drilling mud during
drilling operations, or higher than a pressure setpoint of the
equalization valve 124. An example pressure setpoint at which the
mandrel valve 126 opens may, in some embodiments, be an
intermediate pressure setpoint between the pressure setpoints of
various valves in the downhole tool 100, or between pressures used
to perform different functions in the downhole tool 100. For
instance, the intermediate pressure setpoint of the mandrel valve
126 may be between 150 psi and 1000 psi (1.0 MPa and 6.9 MPa). More
particularly, in some embodiments, the intermediate pressure at
which the mandrel valve 126 opens may be within a range having
lower and/or upper limits that include any of 150 psi, 300 psi, 400
psi, 500 psi, 600 psi, 800 psi, 1000 psi (1.0 MPa, 2.1 MPa, 2.8
MPa, 3.4 MPa, 4.1 MPa, 5.5 MPa, and 6.9 MPa), or any values
therebetween. In other embodiments, the intermediate pressure may
be less than 150 psi or greater than 1000 psi (1.0 MPa and 6.9
MPa). In some embodiments, the pressure at which the mandrel valve
126 opens may be lower than the high pressure discussed herein
(e.g., a pressure used to open the body valve 122). In other
embodiments, the pressure at which the mandrel valve 126 opens may
be lower than the pressure used to open a second valve, such as the
body valve 122 or the equalization valve 124.
[0040] According to at least some embodiments, the body valve 122
may open at a pressure setpoint that is higher relative to the
pressure at which the mandrel valve 126 opens. The pressure used to
open the body valve 122 may be referred to as a high pressure as it
may be higher than the pressure used to open the equalization valve
124 and/or the mandrel valve 126. The high pressure corresponding
to the pressure setpoint of the body valve 122 may further be
greater than the pressure within the chamber 134 that would
counteract the force of the spring 128 and/or which would activate
the downhole tool 100. For example, high pressure setpoints of the
body valve 122 may, in some embodiments, be between 1000 psi and
3000 psi (6.9 MPa and 20.7 MPa). More particularly, a high pressure
used to open the body valve 122 may be within a range that includes
lower and/or upper limits including any of 1000 psi, 1250 psi, 1500
psi, 1750 psi, 2000 psi, 2500 psi, 3000 psi (6.9 MPa, 8.6 MPa, 10.3
MPa, 12.1 MPa, 14 MPa, 13.8 MPa, 17.2 MPa, and 20.7 MPa), or any
values therebetween. In other embodiments, however, the pressure
used to open the body valve 122 may be less than 1000 psi (6.9 MPa)
or greater than 3000 psi (20.7 MPa).
[0041] FIG. 4 shows the illustrative downhole tool 100 in an active
state. In the active state, a moveable element, such as the piston
118, may be moved axially along the longitudinal axis A of the
downhole tool 100 toward an upper end portion 130 of the downhole
tool 100. When the piston 118 translates or otherwise moves axially
along the downhole tool 100, the piston 118 may push a drive ring
120 in the direction of the upper end portion 130 of the downhole
tool 100. This drive ring 120, in turn, may push the cutter blocks
104 at least partially in the same direction. For instance, by
moving the drive ring 120 axially toward the upper end portion 130
of the downhole tool 100, the cutter blocks 104 may move axially
toward the upper end portion 130 of the downhole tool 100. Axial
movement of the cutter blocks 104 may also cause the cutter blocks
104 to move radially outward relative to the body 102 of the
downhole tool 100. The piston 118 may be coupled indirectly to the
cutter block 104 via the drive ring 120. In some embodiments, a
piston may be directly coupled to a cutter block or other
expandable member without the drive ring 120, or the drive ring 120
may be integral with the piston 118.
[0042] In some embodiments, a moveable element may include a
flexible or deformable portion, and one portion of the movable
element may remain in substantially the same location while another
portion of the moveable element moves. For example, a spring-like
movable element may include an end that is pinned or fixed in place
and remains stationary while another portion moves. A pivoting
movable element may include an end that is pinned or rotationally
coupled to a part of the downhole tool, while a free end rotates in
an arc about the pinned end. Combinations of different types of
movable elements may also be used.
[0043] As the cutter blocks 104 translate or otherwise move toward
the upper end portion 130, the splines 114 of the cutter blocks 104
may cooperate with the grooves 115 in the body 102 to cause the
cutter blocks 104 to move radially outward. In an outward or
expanded position of the cutter blocks 104, such as that shown in
FIG. 4, the outer surface 116 of the cutter blocks 104 and/or the
cutting elements 106 may extend beyond the outer surface 112 of the
body 102 of the downhole tool 100.
[0044] In some embodiments, the piston 118 may translate or move
axially along the longitudinal axis A of the downhole tool 100 when
the pressure of the fluid within the chamber 134 acts on a surface
of the piston 118 facing the interior of the chamber 134 with
enough force to overcome the force of the spring 128. The pressure
inside the chamber 134 may be increased by allowing drilling fluid
or drilling mud into the chamber 134.
[0045] As discussed herein, pressurized fluid may enter the chamber
134 from the flow tube 136. In some embodiments, the mandrel valve
126 may open and allow fluid flow into the chamber 134 when the
fluid pressure within the flow tube 136 exceeds the opening
pressure setpoint of the mandrel valve 126. In some embodiments,
the opening pressure setpoint of the mandrel valve 126 may be above
the relatively lower opening pressure setpoint of the equalization
valve 124. When an operator wishes to activate the downhole tool
100 and extend the cutter blocks 104, the operator may increase the
fluid pressure inside the flow tube 136 above the opening pressure
setpoint of the mandrel valve 126, but the operator may keep the
fluid pressure below the relatively higher opening pressure
setpoint of the body valve 122. This may cause drilling fluid or
mud to enter the chamber 134. As a result of the fluid pressure
remaining below the opening pressure setpoint of the body valve
122, the pressure within the chamber 134 may increase, but the body
valve 122 may remain closed and resist flow from the chamber 134
into the annulus.
[0046] The characteristics of the spring 128, such as the spring
constant and any preloading, may be selected such that the spring
128 holds the cutter blocks 104 in a retracted position and the
downhole tool 100 in an inactive state when the fluid pressure
within the chamber 134 is below an intermediate pressure, but
allows the cutter blocks 104 to transition to an active or expanded
position and the downhole tool 100 to transition to an active state
when the fluid pressure within the chamber 134 meets or exceeds an
intermediate pressure or other pressure setpoint of the mandrel
valve 126. When the pressure inside the chamber 134 overcomes the
force exerted by the bias spring 128, the piston 118 may begin to
translate axially along the longitudinal axis A of the downhole
tool 100. Eventually, the pressure within the chamber 134 and the
flow tube 136 may begin to equalize. As the pressure in the chamber
134 and the pressure in the flow tube 136 begin to equalize, the
differential pressure across the mandrel valve 126 may drop and, in
an embodiment where the mandrel valve 126 is a check valve, the
mandrel valve 126 may close. When the mandrel valve 126 closes, the
pressure within the chamber 124 may hold the piston 118 and cutter
blocks 104 in active or expanded positions, thereby maintaining the
downhole tool 100 in the active or deployed state. The downhole
tool 100 may remain in this state as fluid flows within the flow
tube 136 or even if the pressure of the fluid in the flow tube 136
drops or if flow stops entirely.
[0047] When the mandrel valve 126 closes, the downhole tool 100 may
be in a state where the three valves--namely the mandrel valve 126,
the equalization valve 124, and the body valve 122--are closed. The
mandrel valve 126 may be closed due to the differential pressure
between the flow tube 136 and the inside of the chamber 134 not
being great enough to open the mandrel valve 126. The body valve
122 may be closed due to the differential pressure between the
chamber 134 and the annulus not being great enough to open the body
valve 122. The equalization valve 124, which may be a check valve,
may be closed due to the pressure inside the chamber 134 being
greater than the pressure in the annulus.
[0048] In some embodiments, the process of activating the downhole
tool 100 may occur even in the absence of weight-on-bit. An
operator may, therefore, activate the downhole tool 100 at an
intermediate depth within the wellbore or when the downhole tool
100 is not on the bottom of the wellbore (i.e., is off-bottom).
Additionally, in this configuration, the downhole tool 100 may be
hydraulically locked in the active or deployed state as the
pressurized fluid may be contained in the chamber 134. The
pressurized fluid held within the chamber 134 may restrict movement
of the cutter blocks 104 or other applicable expandable member or
tool, and may maintain the downhole tool 100 in the active state.
In the active state, the operator may use the tool to ream the
wellbore or stabilize the downhole tool 100 independently of any
weight-on-bit or continued drilling fluid flow. In this
configuration, the operator may, in some embodiments, therefore
lower the pressure of the drilling fluid within the flow tube 136
(e.g., back down to normal operating pressures), stop the flow
completely, or switch to using an aerated or other type of drilling
fluid. The operator may then continue to operate the downhole tool
100 under these conditions while the downhole tool 100 remains in
the active state.
[0049] If the mandrel valve 126 were absent or disabled, the port
125 could be open to allow free flow between the flow tube 136 and
the chamber 134. Similarly, if the body valve 122 were absent or
disabled, the port 121 could allow fluid to flow from the chamber
134 to the annulus. In such configurations, pressure within the
chamber 134 could be maintained. For instance, the pressure in the
chamber 134 could be maintained where the mandrel valve 126 is
removed or disabled by having the operator maintain the pressure
within the flow tube 136 at a level high enough to counteract the
force of the spring 128. The pressure in the chamber 134 could also
be maintained when the body valve 122 is removed or disabled where
the combination of the drilling fluid pressure in the annulus and
the pressure drop across the body port 121 is high enough that the
pressure within the chamber 134 is maintained at a level that
overcomes the biasing force of the spring 128.
[0050] The pressure in the annulus may be maintained by the head
pressure of the fluid in the annulus. In some embodiments, the head
pressure in the annulus may be affected by the porosity of the
geologic formations through which the downhole tool 100 passes. If
the formations are porous, drilling fluid may easily enter the
formations and the head pressure in the annulus may be low. When
the head pressure in the annulus is low, the fluid that is pumped
into the chamber 134 may escape through the body port 121, and
pressure within the chamber 134 may not be maintained. These porous
locations within a wellbore are called loss zones, or total loss
zones. In embodiments in which the downhole tool 100 may remain in
the active state even when the flow of drilling fluid is reduced or
even stopped (e.g., when a quantity of fluid is contained within
the chamber 134 and the downhole tool 100 is hydraulically locked
with the cutter blocks 104 in an expanded position), the downhole
tool 100 may continue to effectively be operated without the loss
of large quantities of drilling fluid to loss zones, or total loss
zones.
[0051] An operator may wish to return the downhole tool 100 to an
inactive state in order to trip the downhole tool 100 out of the
wellbore, or to begin reaming in another zone within the wellbore.
To return the downhole tool 100 to an inactive state, the biasing
force of the spring 128 and any other retraction forces applied
directly or indirectly to the cutter blocks 104 should exceed the
force applied to the cutter blocks 104 by the piston 134. One
method of changing the balance in these forces is to reduce the
pressure in the chamber 134. By opening the body valve 122,
pressurized fluid within the chamber 134 may flow into the annulus,
thereby reducing the pressure within the chamber 134, thereby
reducing the force applied by the piston 134.
[0052] The body valve 122 may open when the pressure differential
across the body valve 122 increases (e.g., exceeds the high opening
pressure setpoint as discussed herein). To increase the
differential pressure across the body valve 122, the annulus
pressure may decrease, the pressure in the chamber 134 may
increase, or a combination of the foregoing may occur.
[0053] One way to decrease the pressure in the annulus may be to
pull the downhole tool 100 up the wellbore. The pressure in the
annulus near the downhole tool 100 may be a function of the depth
of the downhole tool 100 and may increase with increasing depth and
may decrease with decreasing depth. Moving the downhole tool up the
wellbore may therefore cause the pressure on the annulus side of
the body valve 122 to decrease and, because the valves to the
chamber 134 may be closed, the pressure within the chamber 134 may
remain constant. The differential pressure across the body valve
122 may therefore increase as the downhole tool 100 is moved toward
the surface of the wellbore.
[0054] When the differential pressure across the body valve 122
exceeds the opening pressure, the body valve 122 may open and the
fluid within the chamber 134 may flow out of the chamber 134
through body valve 122 and into the annulus. When the pressure
within the chamber 134 decreases to a point where the force on the
piston 134 no longer counteracts the biasing force of the spring
128 on the cutter blocks 104, the spring 128 may cause the cutter
blocks 104 to translate axially along the longitudinal axis A of
the downhole tool 100 toward the lower end portion 132.
[0055] In another embodiment, pressure within the chamber 134 may
be increased by increasing the pressure within the flow tube 136.
By increasing the pressure of the fluid within the flow tube 136 to
a high pressure, the mandrel valve 126 may open, which may cause
fluid to enter and pressurize the chamber 134 to a high pressure.
Pressurizing the chamber 134 may also cause the body valve 122 to
open. At this point, the pressure in the flow tube 136 may be
reduced and, if the body valve 122 has a low closing pressure
setpoint, the body valve 122 may remain open while fluid drains
from the chamber 134 into the annulus. The pressure within the
chamber 134 may decrease, allowing the downhole tool 100 to
transition to an inactive state. In another embodiment, an ignitor
and an explosive material may be used to increase pressure within
the chamber 134. The ignitor may be triggered by an electrical
signal, in some embodiments. Such signal may be generated or
provided by a controller, surface signal, battery, other component,
or any combination of the foregoing.
[0056] When the downhole tool 100 transitions from an active state
to an inactive state, the engagement of the splines 114 on the
cutter blocks 104 and the grooves 115 in the body 102 may cause the
cutter blocks 104 to move radially inward. This movement of the
cutter blocks 104 reflects a transition of the downhole tool 100
from an active state, in which the cutter blocks 104 are in an
expanded or deployed position, into an inactive state, in which the
cutter blocks 104 are in a retracted or inactive position.
[0057] In some embodiments, additional or other mechanisms other
than increasing flow in the flow tube 136 or changing the head
pressure may be used to transition the downhole tool 100 to an
inactive state. For instance, despite the reduction in head
pressure by pulling the downhole tool 100 up the wellbore, the
differential pressure across the body valve 122, between the
chamber 134 and the annulus, may not increase to a level great
enough to open the body valve 122. If the operator does not want to
increase the pressure in the flow tube 136 to open the body valve
122, the operator may use other methods for transitioning the
downhole tool 100 to an inactive state. For example, an operator
may apply an additional mechanical force to transition the downhole
tool 100 into an inactive state.
[0058] An additional mechanical force may act in parallel with, and
potentially in a same direction as, the biasing force of the spring
128. In some embodiments, when retrieving the downhole tool 100
from the wellbore, an operator may pull the downhole tool 100 up to
engage an un-reamed portion of the formation, a portion of casing,
or another object. In FIG. 5, for example, the downhole tool 100
may be pulled up to engage a casing shoe 504. When pulling the
downhole tool 100 up against the casing shoe 504, the casing shoe
504 may press down against the cutter blocks 104. The force between
the casing shoe 504 and the cutter blocks 104, along with the force
applied to the cutter blocks 104 by the spring 128, may push
against the piston 118 and toward the lower end portion 132 of the
body 102. Such forces may increase the fluid pressure within the
chamber 134.
[0059] When the pressure within the chamber 134 increases to a
level that causes the body valve 122 to open, the fluid within
chamber 134 may flow through the body valve 122 and into the
annulus, and the cutter blocks 104 and the piston 118 may translate
axially along the longitudinal axis A of the body 102 toward the
lower end portion 132. As the cutter blocks 104 translate toward
the lower end portion 132, the engagement between the splines 114
on the cutter blocks 104 and the grooves 115 in the body 102 may
cause the cutter blocks 104 to move radially inward and into an
inactive state.
[0060] When a mechanical force is applied, the mechanical force may
be applied while the downhole tool 100 is rotating or not rotating.
For instance, during a reaming operation, the downhole tool 100 may
rotate and move axially within the wellbore. To retract the cutter
blocks 104, the rotation may slow or stop and the downhole tool 100
may be pulled up to apply an axially force that increases the fluid
pressure within the chamber 134. In other embodiments, the downhole
tool 100 may continue to rotate while being pulled up to increase
the fluid pressure within the chamber 134.
[0061] Although the present disclosure discuses tools in the
context of illustrative reamer embodiments, this disclosure is also
applicable to embodiments that include other types of reamers or
other tools, including no-flow locked reamers as discussed herein.
Embodiments of the present disclosure, including activation
systems, may be used in other tools, such as, for example,
expandable anchors, bridge plugs, expandable stabilizers, section
mills, casing jacks, inflatable packers, casing cutters, and pipe
cutters.
[0062] In some embodiments, a tool (e.g., downhole tool 100 of
FIGS. 1 through 5) may include control valves to facilitate
actuating the tool and/or transitioning between active and inactive
states. For example, in the embodiment shown in FIGS. 6 and 7, a
tool may be a downhole tool 600 and may include a body valve 622
located within a port 621, and a mandrel valve 626 located within a
port 625. The body valve 622 and the port 621 may connect a chamber
634 with an annulus or other chamber or area outside a body 602,
and the mandrel valve 626 and the port 625 may connect a flow tube
636 with the chamber 634 through a mandrel 608. The body valve 622
and the mandrel valve 626 may be on/off flow valves that facilitate
the actuation of the downhole tool 600 between an active and an
inactive state. In some embodiments one or more of the body valve
622 or the mandrel valve 626 may be adjustable check valves.
[0063] In simple terms, a control valve is a type of valve that
changes between open and closed positions in response to a signal
or signals. A signal may include electromagnetic, electrical,
mechanical, or any other type of signal. For example, an
electrically actuated control valve might open and close based on
the polarity of the electric voltage applied to the valve's
electric actuator. Another type of control valve may be an
adjustable check valve, which may be opened in any of various
different ways. In some embodiments a controller may adjust the
opening pressure setpoint of an adjustable check valve. In some
embodiments signals may be sent from the surface down to the
adjustable check valve to adjust the opening pressure setpoint or
the adjustable check valve may be adjusted at the surface prior to
being tripped into the wellbore. An adjustable check valve may open
when a controller applies electric current to the adjustable check
valve's solenoid. In some embodiments, even when electric current
is not applied to the valve's solenoid, the adjustable check valve
may open when the differential pressure across the adjustable check
valve is greater than the opening set pressure of the adjustable
check valve, thus causing the adjustable check valve to act like a
mechanical check valve.
[0064] A transition between active and inactive states of the
downhole tool 600 will now be described with reference to FIGS. 6
and 7. On the trip into the wellbore, the downhole tool 600 may be
in an inactive state with the cutter blocks 604 retracted such that
the cutting elements 606 and the outer surface 616 are radially
inward of, or flush with, the outer surface 612 of the body 602.
During the trip into the wellbore, the body valve 622 may be open
and the mandrel valve 626 may be closed and set to an intermediate
opening pressure, for example, 400 psi (2.8 MPa). In this
configuration, the pressure within the piston chamber 634 may be
balanced or equalized with the pressure in the annulus by reverse
free flow of fluid between the annulus and the chamber 634 through
the open body valve 622.
[0065] Downhole operations (e.g., drilling the pilot hole, milling
casing, etc.), may proceed with the cutter blocks 604 in the
retraced position. The downhole tool 600 may thus be used for
downhole operations without activating the downhole tool 600. In
some embodiments, the downhole operations may occur while the
drilling fluid pressure within the flow tube 636 does not exceed
the mandrel valve opening pressure setpoint.
[0066] To transition to an active state, an operator may send a
signal or signals from the surface down to a controller or
controllers contained within the downhole tool 600 or otherwise
located in the wellbore. This process is sometimes referred to as
downlinking. For example, the downhole tool 600 may include a
controller 642. An operator may downlink with a downhole tool 600
using any of a number of methods, including, for example, rotation,
shock, pressure pulses, wired drill pipe, and fluid flow. In a more
particular example, the operator may vary the rotation of the drill
string, send shocks down the drill string, create pulses pressure
pulses transmitted through the annulus of the wellbore or through
the drill string, change the drilling fluid flow rate to send
instructions to a downhole controller, send electronic
communications through wired drill pipe, or the like. The downhole
controller may include sensors for measuring or detecting these
changes, as well as instructions for interpreting and acting on the
signals, for example, by changing the state of a control valve.
[0067] A power supply, such as a battery 638, may provide power for
operating the controller 642 and/or various valves 622, 626. In
some embodiments, the battery 638 may connect to the controller 642
through power conductors 640. The controller 642 may be
electrically connected to the valves 622, 626 through conductors
624, 626.
[0068] In some embodiments, for example the embodiment of FIGS. 6
and 7, an operator may downlink a command to the downhole
controller 640 that causes the controller 640 to set the body valve
622 to a closed position and/or to set the body valve 622 to have a
high opening pressure setpoint, for example 1,500 psi (10.3 MPa).
The same or a similar command may be used to cause the mandrel
valve 626 to change to an open position or to set the mandrel valve
626 to an intermediate opening pressure setpoint. In this
configuration, drilling fluid may flow from the flow tube 636,
located within the bore 610 of the body 602, through the mandrel
valve 626, and into the chamber 634. The fluid may be held within
the chamber by the closed body valve 622. As the chamber 634 fills
with fluid and becomes pressurized, the force on the piston 618 may
increase. When the force exerted by the fluid in the chamber 634 on
the piston 618 overcomes the biasing force of spring 628, the
piston 618 may translate axially along the longitudinal axis B of
the downhole tool 600 in the direction of the upper end portion 630
of the downhole tool 600. The translation of the piston 618 may
cause the cutter blocks 604 to also translate toward the upper end
portion 630 of the downhole tool 600. As the cutter blocks 604
translate, splines, rails or other features (see splines 114 of
FIG. 1) of the cutter blocks 604 and grooves or channels (see
grooves 115 of FIG. 1) in the body 602 may cause the cutter blocks
604 to move to a radially outward position, such as that shown in
FIG. 7. In a radially outward position, the outer surface 616 of
the cutter blocks 604 and the cutting elements 606 may extend
further radially outward than when in a retracted position as shown
in FIG. 6, which may also be radially outward beyond the outer
surface 612 of the body 602 of the downhole tool 600.
[0069] When the chamber 634 is pressurized and the downhole tool
600 is in an active state, a signal or signals sent from the
controller 642 (e.g., in response to downlinking commands from the
surface) may cause the mandrel valve 626 to close and/or may set
the opening pressure setpoint of the mandrel valve 626 to a high
level, for example, 1500 psi (10.3 MPa), which may be above the
pressure of the fluid within the mandrel 608. In this
configuration, the mandrel valve 626 may be closed while a quantity
of fluid is contained in the chamber 634 and at a pressure
sufficient to maintain the downhole tool 600 in the active state.
As the quantity of fluid in the chamber 634 remains pressurized,
the downhole tool 600 may be hydraulically locked in an active or
deployed state and the cutter blocks 604 may remain extended
without the need for additional drilling fluid flow into or through
the chamber 634 or the mandrel 608. Indeed, the downhole tool 600
may remain in an active state even when the flow tube 636 and the
annulus lose pressure.
[0070] In some embodiments, the operator may return the downhole
tool 600 to an inactive state, for example, to trip the downhole
tool 600 out of the wellbore, or to move the downhole tool 600
within the wellbore. To return the downhole tool 600 to an inactive
state, the controller 642 may send a send a signal or signals to
the body valve 622 to cause the body valve 622 to open and/or to
change the opening pressure setpoint of the body valve 622.
[0071] Opening the body valve 622 may break the seal on the chamber
634 and allow fluid to flow out of the chamber 634 and into the
annulus of the wellbore. When the seal on the chamber 634 is broken
or otherwise released, the biasing force of the spring 628 may push
against the cutter blocks 604 and the piston 618 in an axial
direction toward the lower end portion 632 of the body 602. This
may push the drilling fluid held within the chamber 634 out through
the body valve 622 and into the annulus. The biasing force of the
spring 628 may also cause the cutter blocks 604 and the piston 618
to translate axially toward the lower end portion 632 of the body
602.
[0072] The axial translation of the cutter blocks 604 combined with
the engagement of the splines, rails, or other features on the
cutter blocks 604 with the grooves or channels in the body 602, may
cause the cutter blocks 604 to move radially inward and the
downhole tool 600 to transition into an inactive state where the
cutting elements 606 and the outer surface 616 of the cutter blocks
604 retract such that they are in a position radially inward of, or
flush with, the outer surface 612 of the body 602. In some
embodiments, an operator may leave the body valve 622 open during
additional drilling operations or while the downhole tool 600 makes
the trip out of the wellbore.
[0073] In the embodiment shown in FIGS. 1 through 7, the operator
may transition a downhole tool 100, 600 between active and inactive
states by operating the downhole tool 100, 600 and its valves as
described herein. Such operation may save time because the state of
the downhole tool may transition between active and inactive states
multiple times without tripping the downhole tool out of the
wellbore. Such operation may also save drilling fluid because the
downhole tool can be maintained, or locked (e.g., hydraulically
locked), in an active state without constant drilling fluid flow
and pressure, also called a "no-flow" condition. This may
potentially be used when the downhole tool 100, 600 is operating in
a loss zone or a total loss zone. The downhole tool 100, 600 may
also be operated without weight-on-bit or with the bit off-bottom;
therefore, an operator may activate and deactivate the downhole
tool 100, 600 while at any position within the wellbore, and use
the downhole tool to underream and back ream within a wellbore.
[0074] Although the embodiments shown in the figures depict two or
three valves for managing the flow into and out of a chamber, in
some embodiments, more or fewer valves may be used to manage the
flow into and out of a chamber. In some embodiments, for instance,
a downhole tool may include a single valve to facilitate
transitioning the downhole tool between active and inactive states.
For example, a downhole tool may include a single mandrel valve
that allows fluid into a chamber from a flow tube to activate the
downhole tool and allows fluid from the chamber to the flow tube to
deactivate the valve. In other embodiments, multiple mandrel valves
may be used to control fluid flow into an annular chamber.
[0075] FIG. 8 depicts an illustrative method 800 of operating a
downhole tool according to one or more embodiments disclosed
herein. At block 802 the method 800 includes tripping a drill
string into a wellbore. A drill string may include drill pipe, a
bottomhole assembly, or any other tools used in a wellbore drilling
or other downhole process. The bottomhole assembly may include a
downhole tool, for example, a downhole tool 100 (FIG. 1) or 600
(FIG. 6). In some embodiments, the trip-in process may include
inserting the drill string into the wellbore and through the
existing casing and/or openhole portions of the wellbore toward the
bottom of an existing wellbore.
[0076] At block 804 the wellbore is drilled. For example, once the
drill string reaches the bottom of the wellbore or the end of a
lateral or deviated borehole, the operator may begin drilling and
extending the wellbore's depth or length. In some embodiments, for
example when a wellbore has collapsed, the operator may begin
drilling the wellbore before reaching the bottom of the
wellbore.
[0077] At block 806 the downhole tool is activated and at block 808
the downhole tool is operated. In some embodiments, the operator
may activate and operate the downhole tool (e.g., to enlarge the
wellbore) while drilling. This process is called hole enlargement
while drilling. In order to enlarge the wellbore while drilling,
the operator may activate the downhole tool, as shown by block 806
and operate the downhole tool, as indicated by block 808. Other
operations may include, but are not limited to, underreaming, back
reaming, section milling, sealing the wellbore, pulling casing,
cutting casing, fishing operations, and the like. In other
embodiments, the downhole tool may be activated and/or operated for
operations performed independently of drilling operations.
[0078] The downhole tool may also be deactivated, as shown by block
810. For example, in some embodiments, the operator may put a
downhole tool into an inactive state in order to pull the drill
string up through an openhole or cased section of the wellbore, and
through a smaller internal diameter than the downhole tool will fit
through when the downhole tool is in an active state. In some
embodiments, after deactivating the downhole tool, the operator may
continue to drill the wellbore, as shown by block 812.
[0079] In some embodiments, the downhole tool may be activated,
operated, and deactivated multiple times during a single trip in
the wellbore. The operator may also conduct multiple drilling
operations during a single trip. Therefore, the method 800 may be
carried out in an order other than the order shown in FIG. 8, and
one or more actions may occur multiple times during a single trip.
In the same or other embodiments, less than each action shown in
method 800 may be carried out during a trip.
[0080] At block 814 the method 800 includes tripping the drill
string out of the wellbore. In some embodiments, the entire drill
string may be removed from the wellbore during the trip out. In
other embodiments, however, portions of the drill string that were
carried into the wellbore during the trip in may be left in the
wellbore during the trip out.
[0081] The process of drilling a wellbore may include using method
800 (or portions thereof) multiple times. For example, if a
downhole tool breaks or fails during one trip, the operator may
pull the drill string out of the wellbore to replace or fix the
downhole tool, or to fish for the downhole tool. In some
embodiments, the operator may reconfigure the downhole tool to
complete different sections of the wellbore, for example, the
shallow or upper portions of the wellbore may have a larger
diameter than the lower or deeper portions of the wellbore. In such
embodiments, the operator may use a set of reamers and drill bits
sized for drilling and reaming one portion of the wellbore and
another set of reamers and drill bits sized for drilling and
reaming another portion of the wellbore.
[0082] FIG. 9 depicts an embodiment of a method 900 of activating a
tool, and may include a method of activating a downhole tool. At
block 902 the pressure of a supply fluid is increased. In some
embodiments, a flow tube may contain or transport the supply fluid,
for example, flow tube 136, as shown in FIG. 2. In some
embodiments, the operator may increase the pressure in the flow
tube by pumping drilling fluid into the wellbore at a greater flow
rate or otherwise causing a drilling system to increase the
pressure of the drilling fluid.
[0083] At block 904 pressure is increased across a first valve. In
some embodiments, increasing the pressure of a supply fluid may
cause an increase in pressure across a first valve. In some
embodiments, the first valve may be a check valve, and more
particularly, a check valve located in a mandrel or other flow tube
and configured such that when the valve is open, the valve connects
the flow tube in fluid communication with a chamber.
[0084] At block 906 the first valve is opened (e.g., in response to
an increase in pressure of the supply fluid) and at block 908 a
chamber fills with pressurized fluid. In some embodiments, opening
the first valve may put the flow tube in fluid communication with
the chamber and cause the chamber to fill with pressurized fluid.
The pressurized fluid may include drilling fluid, hydraulic fluid,
or other fluid that facilitates the opening of the first valve
and/or filling the chamber with pressurized fluid.
[0085] At block 910 a piston or other movable element or drive
mechanism may be moved. In some embodiments, a spring may apply a
biasing force directly or indirectly onto the piston to bias the
piston toward an inactive position. When the chamber is
unpressurized or contains fluid at a low pressure, the spring may
maintain the piston in the inactive position, but when the force of
the pressurized fluid on the piston exceeds the biasing force of
the spring, the piston may move.
[0086] In some embodiments, the piston may move by, for instance,
translating axially along the longitudinal axis of the downhole
tool. In some embodiments, in addition to translating
longitudinally, the piston may also rotate. The piston may also
translate or otherwise move in other directions that facilitate the
transition of a downhole tool between an inactive state and an
active state, and vice versa.
[0087] At block 912, the method 900 of activating a tool may
include transitioning the tool into an active position. In some
embodiments, two opposing forces may act on the tool. For example,
as shown in FIGS. 1 through 4, a spring 128 may act on one end of
the cutter blocks 104 and push the cutter blocks 104 toward the
lower end of the body 102 of the downhole tool 100, while the
piston 118 may act on another end of the cutter blocks 104 and push
the cutter blocks 104 toward the upper end of the body 102. In the
inactive position (see FIG. 2), the biasing force of the spring 128
on the cutter blocks 104 may exceed the force of the piston 118 on
the cutter block 104. In the active position (see FIG. 4), the
force of the piston 118 on the cutter blocks 104 may exceed the
biasing force of the spring 128 on the cutter blocks 104. At block
912, some embodiments may include transitioning a downhole tool
into an active state in response to the force of the fluid pressure
on the piston exceeding the force applied to the downhole tool,
such as to the cutter blocks by, for example, a spring.
[0088] Transitioning the tool into an active state at block 912 may
also include causing cutter blocks or other expandable members to
extend from a retracted, radially inward, or inactive position, to
an expanded, radially outward, or active position. In the radially
outward position the outer surface and/or the cutting elements of
the cutter blocks may extend radially beyond the outer surface of
the body of the downhole tool.
[0089] At block 914 the first valve may close. In some embodiments,
the first valve may close after transitioning the downhole tool
into an active state at block 912. In some embodiments, as the
chamber fills with pressurized fluid (block 908) the pressure
within the chamber may increase. As the pressure within the chamber
increases, the differential pressure across the first valve chamber
may decrease. In an embodiment wherein the first valve is a check
valve, the decrease in the differential pressure across the first
valve may reduce to a point below the closing pressure of the check
valve. When this occurs, the first valve may close and the chamber
may be sealed. The sealed chamber may remain pressurized, holding
the downhole in an active state. Block 914 may also include, for
example, reducing the flow rate of fluid into the tool, below a
threshold flow rate, or stopping the flow of fluid into the tool.
In some embodiments, such as where the tool is a downhole tool,
block 914 may include reducing the flow rate of drilling fluid into
a wellbore or the downhole tool below a threshold flow rate. In
some embodiments, the threshold flow rate may be less than 1 L/min,
5 L/min, 10 L/min, 15 L/min, 20 L/min, 30 L/min, 60 L/min, 100
L/min, or any value therebetween. In still other embodiments, the
threshold flow rate may be greater than 100 L/min. The tool (e.g.,
a downhole tool) may remain in an active position until a valve,
for example, a second valve, opens and releases the pressurized
fluid contained within the chamber.
[0090] FIG. 10 shows an embodiment of a method 1000 for
deactivating a tool (e.g., a downhole tool). Deactivating a tool
may include transitioning a downhole tool from an active state to
an inactive state. The method 1000 for deactivating a tool may
include increasing the pressure of a supply fluid, as shown by
block 1002. In some embodiments, a flow tube may contain or
transport the supply fluid; for example, flow tube 136, as shown in
FIG. 2.
[0091] At block 1004 pressure may be increased across a first
valve. In some embodiments, increasing the pressure of a supply
fluid may cause an increasing pressure across a first valve. In
some embodiments, the first valve may be a check valve, or more
particularly, a check valve located in a mandrel or other flow tube
and configured such that when the valve is open, the first valve
connects the flow tube in fluid communication with a chamber.
[0092] The method 1000 of deactivating a tool may include causing
the first valve to open, as depicted by block 1006. Opening the
first valve may put a flow tube of a downhole tool in fluid
communication with a chamber, thereby pressurizing the chamber with
supply fluid. In some embodiments, the first valve may have an
intermediate opening pressure setpoint. The first valve may
therefore open when the differential pressure across the first
valve exceeds the intermediate opening pressure setpoint.
[0093] In some embodiments, the second valve may have an opening
pressure setpoint higher than the intermediate opening pressure
setpoint, and may therefore be referred to as having a high opening
pressure setpoint. In such embodiments, the fluid in the chamber
may reach a pressure such that the differential pressure across the
second valve, for example, between a chamber and an annulus,
exceeds the high opening pressure setpoint of the second valve.
Thus, at block 1008 the chamber may be pressurized with a supply
fluid, and at block 1010 the pressure across the second valve may
be increased. Increasing the pressure across the second valve in
block 1010 may be performed by, for instance, by pumping drilling
fluid into a wellbore and, in particular, into a flow tube of a
downhole tool, which may cause the pressure within the flow tube to
increase. Increasing the pressure in the flow tube may cause the
first valve to open and the fluid to enter and increase the
pressure within the chamber. A relatively high pressure in the
chamber may cause the differential pressure across the second valve
to increase until the differential pressure exceeds the opening
pressure setpoint of the second valve, causing the second valve to
open. As another example, the pressure across the second valve in
block 1010 may be increased by moving a downhole tool toward the
surface of a wellbore. The pressure within the annulus may decrease
with decreasing depth in the wellbore; therefore, moving the
downhole tool toward the surface may decrease the pressure on the
outside of the second valve and increase the differential pressure
across the second valve. In still another example, increasing
pressure across a second valve at block 1010 may include applying a
mechanical force. For instance, a mechanical force may be applied
to a cutter block or expandable member of a downhole tool. The
mechanical force may oppose a force applied by a piston or other
movable member, which may increase pressure in the chamber and
increase the differential pressure across the second valve.
[0094] At block 1012 the second valve opens and at block 1014
pressurized fluid is released from the chamber. In some
embodiments, when the second valve opens it connects the chamber in
fluid communication with an external environment. For a downhole
tool, the external environment may be an annulus within a wellbore.
When the chamber and the external environment are in fluid
communication with each other, the fluid within the chamber may
flow out into the external environment, thereby causing the
pressure within the chamber to decrease.
[0095] In some embodiments, after the second valve opens, the
pressure of the supply fluid in the downhole tool may be reduced.
Reducing the pressure of the supply fluid may cause the
differential pressure across the first valve to drop below the
closing pressure setpoint and the first valve to close. In other
embodiments, the pressure of the supply fluid in the downhole tool
may be reduced prior to opening the second valve.
[0096] In some embodiments, one or more of the valves of a tool may
have a delayed closing setpoint. Delayed closing means that the
valve closes at a lower pressure than the pressure which opens the
valve. For example, the second valve may open with a high pressure
differential or opening setpoint, for example, 1,500 psi (10.3
MPa), but may not close until a lower pressure differential or
closing setpoint exists, for example, 10 or 20 psi (0.07 MPA or
0.14 MPa). The lower closing pressure setpoint may allow the second
valve to remain open while the supply fluid drains from the chamber
into the external environment and the piston moves to an inactive
position.
[0097] Using a valve with a high opening pressure setpoint and a
low closing pressure setpoint allows the valve to remain closed
during an initial activation period, for example, as described
above with reference to FIG. 8, but then open to facilitate
depressurization and transition to an inactive state. For example,
at block 1016 of FIG. 10, the piston moves, and at block 1018 a
tool, such as an expandable downhole tool, may move into an
inactive state. In some embodiments, the expandable downhole tool
may be a reamer, and transitioning the reamer into an inactive
state may include retracting cutter blocks.
[0098] Moving the piston may include translating the piston axially
along the longitudinal axis of a tool. In some embodiments, as the
pressure within the chamber decreases, the biasing force of the
spring of a downhole tool may overcome the force of the fluid on
the piston. When this occurs, the biasing force of the spring may
cause the downhole tool to transition from an active state to an
inactive state. For example, moving the piston may cause cutter
blocks to retract from a radially outward, active position to a
radially inward, inactive position. In the radially inward
position, the outer surface and the cutting elements of the cutter
blocks may be retracted to a position that is radially inward of,
or about flush with, the radially outer surface of the body of the
downhole tool.
[0099] At block 1020 the second valve may be closed. The second
valve may close when a pressure differential across the second
valve decreases, when an actuation signal is received, or in any
other suitable manner. The second valve may also close for a number
of reasons, including to restrict or even prevent fluid from
flowing into the chamber from an external environment such as an
annulus of a wellbore.
[0100] FIG. 11 depicts an embodiment of a method 1100 of activating
a tool according to one or more embodiments disclosed herein. The
tool activated in the method 1100 may include a downhole tool or
any other suitable tool. At block 1102 a first valve is opened. In
some embodiments, the first valve is a mandrel valve that, when
opened, connects a flow tube in fluid communication with a
chamber.
[0101] In some embodiments, the first valve may be an electrically
actuated valve or another type of control valve. Block 1102 may
include sending a signal to a controller, and in the case of a
downhole tool, the signal may be sent from the surface down the
wellbore. The controller may receive one or more signals or
instructions that can be processed to cause the first valve to
open. The controller may direct the first valve to open by applying
voltage to the valve such that a solenoid of the valve is activated
and the valve is opened. In some embodiments, the voltage applied
to the valve by the controller may cause a motor to turn and open
the valve. In some embodiments, opening the first valve at block
1102 may include the controller adjusting the first valve to set a
configurable opening pressure setpoint. The first valve may then
open when the pressure differential across the valve, or a pressure
within the tool, reaches or exceeds the opening pressure
setpoint.
[0102] At block 1104 a chamber may fill with pressurized fluid. The
chamber may fill with pressurized fluid that flows through the
first valve opened in block 1102. Block 1104 may include
pressurizing a supply fluid, for example, by pumping fluid into a
tool (e.g., pumping drilling fluid into a downhole tool in a
wellbore) at a high flow rate. The high flow rate may be above the
opening pressure setpoint of the first valve. A tool may also be
operated in other manners to cause a chamber to fill with
pressurized fluid. In some embodiments, filling the chamber with
pressurized fluid at block 1104 may causes a piston to move, as
shown in block 1106.
[0103] In some embodiments, a spring may hold the piston in an
inactive position when the chamber is unpressurized or contains
fluid at a low pressure. The piston may move when the pressure
within the chamber acts on the piston with enough force to overcome
the biasing force of the spring.
[0104] In some embodiments, the piston may translate axially along
the longitudinal axis of the tool, or otherwise move within the
tool. In some embodiments, in addition to, or instead of,
translating longitudinally, the piston may rotate. The piston may
also translate or otherwise move in other directions that
facilitate the transition of a tool between an inactive state and
active state.
[0105] At block 1108 the downhole tool may transition to an active
state. Moving the piston may include transitioning a tool to an
active state. Moving the piston may include applying a force to an
expandable member, such as the cutter blocks of a reamer or other
downhole tool, which may cause the cutter blocks to move from an
inactive position to an active position. For example, moving the
piston may cause the cutter blocks to extend from a radially
inward, inactive position to a radially outward, active position.
In the radially outward, active position, the outer surface and the
cutting elements of the cutter blocks may extend beyond the
radially outer surface of the body of the tool.
[0106] At block 1110 the first valve may be closed. In some
embodiments, after moving a tool into an active position the first
valve may close. Closing the first valve may include reducing a
pressure of the supply fluid and/or sending a signal to the first
valve (e.g., from the surface of a wellbore and down the wellbore
to a controller). The controller may receive one or more signals
and close the first valve (e.g., by issuing a close command or
instruction). The controller may close the first valve by removing
a voltage to the valve such that the valve's solenoid is
deactivated and the valve is closed. In some embodiments, the
controller may apply a voltage to the valve which may cause a motor
to turn and close the valve. When the first valve closes, the
chamber may be sealed. A sealed chamber may remain pressurized,
holding the tool in an active state even in the absence of
continued fluid flow. In other embodiments, the first valve may
have a configurable opening or closing pressure setpoint. In such
an embodiment, the controller may adjust the opening or closing
pressure setpoint of the first valve. By increasing the closing
pressure setpoint to be above the pressure of the supply fluid, the
first valve may then also close as the pressure of the supply fluid
will be below the minimum pressure at which the first valve remains
open (i.e., the closing pressure setpoint). In some embodiments, by
increasing the opening pressure setpoint of the first valve to be
above the pressure of the supply fluid, the first valve may further
be closed as the pressure of the supply fluid may be below the
minimum pressure at which the first valve will open (i.e., the
opening pressure setpoint).
[0107] According to some embodiments, closing the first valve may
not include sending an additional signal (e.g., from the surface to
a controller of a downhole tool). For example, the signal sent as
described with respect to block 1102 may include instructions or
commands that tell a controller the conditions under which to open
and the conditions under which to close the first valve. The first
valve may, therefore, be closed without receiving additional
signals from an external or other source, or the tool may be
configured to close the valve when a certain pressure is reached
within the chamber or after a certain period of time. The tool may
remain in an active state until a valve, for example, a second
valve, opens and releases the pressurized fluid contained within
the chamber.
[0108] FIG. 12 depicts an embodiment of a method 1200 of
deactivating a tool. The tool deactivated in the method 1200 may be
a downhole tool or other tool. At block 1202 a second valve is
opened. Opening the second valve at block 1202 may connect a
chamber in fluid communication with an external environment, such
as an annulus of a wellbore when the tool is a downhole tool. In
some embodiments, the second valve may be an electrically actuated
valve or other type of control valve. Opening the second valve may
include sending a signal to a controller (e.g., from the surface
down the wellbore). The signal may be a pressure signal, rotational
signal, electrical signal, an RFID or tracer signal, or the like,
and the controller may receive one or more signals and open the
second valve. The controller may open the second valve by applying
voltage to the valve (or causing the voltage to be applied) such
that the second valve's solenoid is activated and the second valve
is opened. In some embodiments, the voltage applied to the second
valve by the controller may cause a motor to turn and open the
second valve. In other embodiments, the second valve may have a
configurable opening or closing pressure setpoint that may be set
by the controller in response to a sent signal.
[0109] In still other embodiments, opening the second valve at
block 1202 may include using a mechanical force to increase the
pressure in the chamber above an opening pressure setpoint of the
second valve. For instance, a downhole tool may include a piston
that moves in response to forces applied by pressurized fluid in a
chamber. A mechanical force may be applied to oppose the opening
force of the piston (e.g., by applying a force to a cutter block or
other expandable member of a downhole tool), which may increase the
pressure within the chamber. The increased pressure may exceed the
opening pressure setpoint of the second valve and cause the second
valve to open at block 1202.
[0110] At block 1204 the chamber may release pressurized fluid. The
pressurized fluid may be released to any location. In some
embodiments, when the chamber is in fluid communication with a
wellbore annulus or some other external environment, the fluid
within the chamber may flow out into the external environment,
causing the pressure within the chamber to decrease.
[0111] At block 1208 the tool may transition into an inactive
state. Block 1208 may include translating a piston axially along a
longitudinal axis of the tool. In some embodiments, as the pressure
within the chamber decreases, the biasing force of a spring may
overcome the force of the fluid on the piston. When this occurs,
the biasing force of the spring may cause expandable members, such
as the cutter blocks of a reamer, to move from an active position
to an inactive position. For example, moving the piston as shown by
block 1206 may cause cutter blocks to retract from a radially
outward, active position to a radially inward, inactive position.
In the radially inward position the outer surface and the cutting
elements of the cutter blocks may retract to a position that is
radially inward of, or about flush with, the radially outer surface
of the body of the downhole tool.
[0112] In some embodiments, at block 1210 the second valve may
close. The second valve may close in response to any number of
stimuli and for a number of reasons. The second valve may close to
restrict or even prevent fluid from flowing into the chamber from
an external environment. The second valve may close in response to
a signal sent to a controller within or coupled to the tool, or in
response to a decrease in differential pressure across the second
valve.
[0113] In some embodiments, a method of deactivating a tool may
include opening a first valve. For example, if opening the first
valve connects a chamber in fluid communication with a flow tube or
other supply chamber, then, if the pressure within the flow tube is
lower than the pressure within the chamber, pressurized fluid
within the chamber may flow into the flow tube. This may cause the
pressure in the chamber to decrease and the downhole tool to
transition into an inactive state.
[0114] A few example embodiments have been described in detail
herein; however, 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 scope of the present disclosure or the appended claims.
Accordingly, such modifications are intended to be included within
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 of the present disclosure may also be
devised which lie within the scopes of the disclosure and the
appended claims. Additions, deletions and modifications to the
embodiments that fall within the meaning and scopes of the claims
are to be embraced by the claims.
[0115] 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," "uphole,"
"downhole," 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
bottomhole assembly or downhole tool that is described as "below"
another component may be further from the surface 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. Certain
descriptions or designations of components as "first," "second,"
"third," and the like may also be used to differentiate between
identical components or between components which are similar in
use, structure, or operation. Such language is not intended to
limit a component to a singular designation. As such, a component
referenced in the specification as the "first" component may be the
same or different than a component that is referenced in the claims
as a "first" component.
[0116] Furthermore, while the description or claims may 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 or other 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 "at least
one" 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," or
"in connection with via one or more intermediate elements or
members." Components that are "integral" or "integrally" formed
include components made from the same piece of material, or sets of
materials, such as by being commonly molded or cast from the same
material, or machined from the same one or more pieces of material
stock. Components that are "integral" should also be understood to
be "coupled" together.
[0117] A person having ordinary skill in the art should realize in
view of the present disclosure that equivalent constructions do not
depart from the spirit and scope of the present disclosure, and
that various changes, substitutions, and alterations may be made to
embodiments disclosed herein without departing from the spirit and
scope of the present disclosure. Equivalent constructions,
including functional "means-plus-function" clauses are intended to
cover the structures described herein as performing the recited
function, including both structural equivalents that operate in the
same manner, and equivalent structures that provide the same
function. It is the express intention of the applicant not to
invoke means-plus-function or other functional claiming for any
claim except for those in which the words `means for` appear
together with an associated function.
[0118] While embodiments disclosed herein may be used in oil, gas,
or other hydrocarbon exploration or production environments, such
environments are merely illustrative. Systems, tools, assemblies,
methods, reamers, downhole tools, actuation systems, valves, and
other components of the present disclosure, or which would be
appreciated in view of the disclosure herein, may be used in other
applications and environments. In other embodiments, systems,
tools, and methods of the present disclosure or which would be
appreciated in view of the disclosure herein, may be used outside
of a downhole environment, including within automotive, aquatic,
aerospace, hydroelectric, manufacturing, other environments, or
even in other downhole environments. The terms "well," "wellbore,"
"borehole," "downhole", 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.
[0119] Certain embodiments and features may have been described
using a set of numerical values that may provide lower and/or upper
limits It should be appreciated that ranges including the
combination of any two values are contemplated unless otherwise
indicated (e.g., between 200 psi and 500 psi), as are ranges
including a single value (e.g., up to 500 psi, or at least 200
psi), or that any particular value may be used. Numbers,
percentages, ratios, measurements, or other values stated herein
are intended to include the stated value as well as other values
that are about or approximately the stated value, as would be
appreciated by one of ordinary skill in the art encompassed by
embodiments of the present disclosure. A stated value should
therefore be interpreted broadly enough to encompass values that
are at least close enough to the stated value to perform a desired
function or achieve a desired result. The stated values include at
least experimental error and variations that would be expected by a
person having ordinary skill in the art, as well as the variation
to be expected in a suitable manufacturing or production process. A
value that is about or approximately the stated value and is
therefore encompassed by the stated value may further include
values that are within 10%, within 5%, within 1%, within 0.1%, or
within 0.01% of a stated value.
[0120] The Abstract included with this disclosure is provided to
allow the reader to quickly ascertain the general nature of some
embodiments of the present disclosure. The Abstract is submitted
with the understanding that it will not be used to interpret or
limit the scope or meaning of the claims.
* * * * *