U.S. patent application number 14/552187 was filed with the patent office on 2015-05-28 for hydraulically actuated tool with electrical throughbore.
The applicant listed for this patent is SMITH INTERNATIONAL, INC.. Invention is credited to John Michael Aubin, Mahavir Nagaraj, Bhushan Pendse, Renato Pereira, Francesco Vaghi.
Application Number | 20150144401 14/552187 |
Document ID | / |
Family ID | 53181680 |
Filed Date | 2015-05-28 |
United States Patent
Application |
20150144401 |
Kind Code |
A1 |
Nagaraj; Mahavir ; et
al. |
May 28, 2015 |
HYDRAULICALLY ACTUATED TOOL WITH ELECTRICAL THROUGHBORE
Abstract
A bottom hole assembly includes a drill string, a bit coupled to
an end of the drill string, a rotary steerable system coupled to
the drill string above the bit, a hydraulically actuated tool
assembly coupled to the drill string above the rotary steerable
system, and an electrically controlled tool coupled to the drill
string above the hydraulically actuated tool assembly and
electrically coupled to the rotary steerable system. A method
includes running a bottom hole assembly downhole, the bottom hole
assembly including a drill bit, a rotary steerable system, an
electrically controlled tool, and a hydraulically actuated tool
assembly disposed between the rotary steerable system and the
electrically controlled tool. The method includes cutting a
formation with the drill bit, actuating the hydraulically actuated
tool assembly, and maintaining an electrical connection between the
rotary steerable system and the electrically controlled tool during
the running, the cutting, and the actuating.
Inventors: |
Nagaraj; Mahavir; (Spring,
TX) ; Aubin; John Michael; (Cypress, TX) ;
Pereira; Renato; (Layfayette, LA) ; Pendse;
Bhushan; (League City, TX) ; Vaghi; Francesco;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SMITH INTERNATIONAL, INC. |
HOUSTON |
TX |
US |
|
|
Family ID: |
53181680 |
Appl. No.: |
14/552187 |
Filed: |
November 24, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61909456 |
Nov 27, 2013 |
|
|
|
Current U.S.
Class: |
175/45 ; 175/263;
175/320; 175/325.5; 175/61; 175/74 |
Current CPC
Class: |
E21B 17/028 20130101;
E21B 17/1078 20130101; E21B 47/00 20130101; E21B 7/28 20130101;
E21B 10/32 20130101; E21B 7/04 20130101 |
Class at
Publication: |
175/45 ; 175/320;
175/325.5; 175/263; 175/74; 175/61 |
International
Class: |
E21B 7/04 20060101
E21B007/04; E21B 17/10 20060101 E21B017/10; E21B 47/00 20060101
E21B047/00; E21B 17/02 20060101 E21B017/02; E21B 10/32 20060101
E21B010/32; E21B 7/28 20060101 E21B007/28 |
Claims
1. A tool assembly comprising: a tool body configured to connect
with a drill string; a mandrel disposed in the tool body; a piston
assembly disposed in the mandrel, the piston assembly having a
throughbore and including a valve piston and a cam piston
configured to reciprocate axially in the mandrel; a spring member
disposed in the tool body and configured to bias the piston
assembly towards a first axial position; and a tubular disposed in
the tool body and the throughbore of the piston assembly, the
tubular having a throughbore configured to carry an electrical
wire.
2. The tool assembly of claim 1, further comprising a first locking
apparatus disposed at an upper end and a second locking apparatus
disposed at a lower end, the first and second locking apparatus
configured to secure the tubular within the tool assembly.
3. The tool assembly of claim 2, wherein the first locking
apparatus and the second locking apparatus each include a locking
sleeve.
4. The tool assembly of claim 2, wherein the first locking
apparatus and the second locking apparatus each include a jam
nut.
5. The tool assembly of claim 1, wherein the tubular comprises a
centralizer coupled to an outer surface of the tubular and
extending radially therefrom.
6. The tool assembly of claim 5, wherein a portion of the tubular
radially adjacent the piston assembly is free of the
centralizer.
7. The tool assembly of claim 1, further comprising at least one
reamer blade coupled to the tool body and configured to extend
radially therefrom.
8. A bottom hole assembly comprising: a drill string; a bit coupled
to an end of the drill string; a rotary steerable system coupled to
the drill string axially above the bit; a hydraulically actuated
tool assembly coupled to the drill string axially above the rotary
steerable system; and an electrically controlled tool coupled to
the drill string axially above the hydraulically actuated tool
assembly, the electrically controlled tool electrically coupled to
the rotary steerable system.
9. The bottom hole assembly of claim 8, wherein the electrically
controlled tool is a
measurement-while-drilling/logging-while-drilling (MWD/LWD)
tool.
10. The bottom hole assembly of claim 8, further comprising a
reamer coupled to the drill string axially above the electrically
controlled tool.
11. The bottom hole assembly of claim 8, wherein the hydraulically
actuated tool assembly comprises a tubular disposed in a central
throughbore of the hydraulically actuated tool assembly and
extending from proximate a first end of the hydraulically actuated
tool assembly to proximate a second end of the hydraulically
actuated tool assembly.
12. The bottom hole assembly of claim 11, further comprising an
electrical wire coupled at a first end to the rotary steerable
system, extending through the tubular, and coupled at a second end
to the electrically controlled tool.
13. The bottom hole assembly of claim 8, wherein the hydraulically
actuated tool assembly is a reamer.
14. The bottom hole assembly of claim 8, wherein the hydraulically
actuated tool assembly is a caliper measurement tool.
15. The bottom hole assembly of claim 8, wherein the hydraulically
actuated tool assembly is a stabilizer when in a deactuated mode
and a reamer when in an actuated mode.
16. A method comprising: running a bottom hole assembly downhole,
the bottom hole assembly including a drill bit, a rotary steerable
system, an electrically controlled tool, and a hydraulically
actuated tool assembly disposed between the rotary steerable system
and the electrically controlled tool; cutting a formation with the
drill bit; actuating the hydraulically actuated tool assembly; and
maintaining an electrical connection between the rotary steerable
system and the electrically controlled tool during the running, the
cutting, and the actuating.
17. The method of claim 15, wherein the maintaining the electrical
connection between the rotary steerable system and the electrically
controlled tool comprises running an electrical wire through a
tubular disposed within the hydraulically actuated tool assembly
and coupling the electrical wire to the rotary steerable system and
the electrically controlled tool.
18. The method of claim 16, further comprising stabilizing the
tubular within the hydraulically actuated tool assembly with at
least one centralizer.
19. The method of claim 15, wherein the bottom hole assembly
further includes a reamer disposed above the electrically
controlled tool and wherein the hydraulically actuated tool
assembly includes at least one radially actuated reamer blade, the
method further comprising: dropping an activation ball into the
bottom hole assembly and actuating the reamer; cutting the
formation with the reamer, the cutting the formation with the drill
bit and the cutting the formation with the reamer forming a rathole
between drill bit and the reamer; deactuating the reamer and
pulling the BHA upward to position the hydraulically actuated tool
assembly proximate the top of the rathole; activating the tool
assembly; and cutting the rathole with the at least one radially
actuated reamer blade of the hydraulically actuated tool assembly,
wherein the electrical connection is maintained during the
dropping, the cutting the formation with the reamer, the
deactuating, the activating, and the cutting the rathole.
20. A method comprising: running a bottom hole assembly downhole,
the bottom hole assembly including a drill bit, a rotary steerable
system, a hydraulically actuated reamer tool assembly, a
measurement-while-drilling/logging-while-drilling (MWD/LWD) tool,
and a reamer; dropping an activation ball into the bottom hole
assembly and actuating the reamer; cutting a formation with the
drill bit and the reamer, the cutting the formation forming a
rathole between the drill bit and the reamer; deactuating the
reamer and pulling the BHA upward to position the reamer tool
assembly proximate the top of the rathole; activating the reamer
tool assembly; and cutting the rathole with the reamer tool
assembly, the running, dropping, cutting the formation,
deactuating, actuating, and cutting the rathole being performed
while maintaining electrical connection between the rotary
steerable system and the MWD/LWD tool.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims priority to U.S. Provisional
Application 61/909,456, filed Nov. 27, 2013, the entirety of which
is incorporated by reference.
FIELD OF THE INVENTION
[0002] Aspects relate to downhole drilling operations. More
specifically, aspects relate to a hydraulically actuated tool with
electrical throughbore.
BACKGROUND
[0003] Downhole drilling operations commonly require a downhole
tool to be actuated after the tool has been deployed in the
borehole. For example, underreamers are commonly tripped into the
borehole in a collapsed state (i.e., with the cutting structures
retracted into the underreamer tool body). At some predetermined
depth, the underreamer is actuated such that the cutting structures
expand radially outward from the tool body. Hydraulic actuation
mechanisms are used in oilfield services operations and are
commonly employed in such operations.
[0004] For example, one hydraulic actuation methodology involves
wireline retrieval of a plug (or "dart") through the interior of
the drill string to enable differential hydraulic pressure to
actuate an underreamer. Upon completion of the reaming operation,
the underreamer may be deactuated by redeploying the dart. While
commercially serviceable, such wireline actuation and deactuation
is both expensive and time-consuming in that it requires concurrent
use of wireline or slickline assemblies.
[0005] Another commonly used hydraulic actuation methodology makes
use of shear pins configured to shear at a specific differential
pressure (or in a predetermined range of pressures). Ball drop
mechanisms are also known in the art, in which a ball is dropped
down through the drill string to a ball seat. Engagement of the
ball with the seat typically causes an increase in differential
pressure which in turn actuates the downhole tool. The tool may be
deactuated by increasing the pressure beyond a predetermined
threshold such that the ball and ball seat are released (e.g., via
the breaking of shear pins). While such sheer pin and ball drop
mechanisms are also commercially serviceable, they are generally
one-time or one-cycle mechanisms and do not allow for repeated
actuation and deactuation of a downhole tool.
[0006] Various other hydraulic actuation mechanisms make use of
measurement while drilling (MWD), logging while drilling (LWD)
and/or other electronically controllable systems including, for
example, computer controllable solenoid valves and the like.
Electronic actuation advantageously enables a wide range of
actuation and deactuation instructions to be executed and may
further enable two-way communication with the surface (e.g., via
conventional telemetry techniques). However, these actuation
systems tend to be highly complex and expensive and can be limited
by the reliability and accuracy of MWD, telemetry, and other
electronically controllable systems deployed in the borehole.
SUMMARY
[0007] In one aspect, embodiments disclosed herein relate to a tool
assembly that includes a tool body configured to connect with a
drill string, a mandrel disposed in the tool body, a piston
assembly disposed in the mandrel, and a spring member disposed in
the tool body and configured to bias the piston assembly towards a
first axial position. The piston assembly has a throughbore and
includes a valve piston and a cam piston configured to reciprocate
axially in the mandrel. The tool assembly further includes a
tubular disposed in the tool body and the throughbore of the piston
assembly. The tubular is configured to carry an electrical
wire.
[0008] In another aspect, embodiments disclosed herein relate to a
bottom hole assembly that includes a drill string, a bit coupled to
an end of the drill string, a rotary steerable system coupled to
the drill string axially above the bit, a hydraulically actuated
tool assembly coupled to the drill string axially above the rotary
steerable system, and an electrically controlled tool coupled to
the drill string axially above the hydraulically actuated tool
assembly. The electrically controlled tool is electrically coupled
to the rotary steerable system.
[0009] In another aspect, embodiments disclosed herein relate to a
method including running a bottom hole assembly downhole, the
bottom hole assembly including a drill bit, a rotary steerable
system, an electrically controlled tool, and a hydraulically
actuated tool assembly disposed between the rotary steerable system
and the electrically controlled tool. The method further includes
cutting a formation with the drill bit, actuating the hydraulically
actuated tool assembly, and maintaining an electrical connection
between the rotary steerable system and the electrically controlled
tool during the running, the cutting, and the actuating.
[0010] In another aspect, embodiments disclosed herein relate to a
method including running a bottom hole assembly downhole, the
bottom hole assembly including a drill bit, a rotary steerable
system a hydraulically actuated reamer tool assembly, a
measurement-while drilling/logging-while-drilling (MWD/LWD) tool,
and a reamer. The method further includes dropping an activation
ball into the bottom hole assembly and actuating the reamer,
cutting a formation with the drill bit and the reamer, the cutting
the formation forming a rathole between the drill bit and the
reamer, and deactuating the reamer and pulling the BHA upward to
position the reamer tool assembly proximate the top of the rathole.
The method further includes activating the reamer tool assembly and
cutting the rathole with the reamer tool assembly, the running,
dropping, cutting the formation, deactuating, actuating, and the
cutting the rathole being performed while maintaining electrical
connection between the rotary steerable system and the MWD/LWD.
[0011] 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 DRAWINGS
[0012] FIG. 1 shows a conventional drilling rig and bottom hole
assembly.
[0013] FIG. 2 is a schematic of a bottom hole assembly in
accordance with embodiments disclosed herein.
[0014] FIG. 3 is partial cross-sectional view of an underreamer in
a retracted configuration in accordance with embodiments disclosed
herein.
[0015] FIG. 4 is a partial cross-sectional view of the underreamer
of FIG. 3 in an extended configuration in accordance with
embodiments disclosed herein.
[0016] FIG. 5 is a cross-sectional view of a hydraulically actuated
tool assembly in accordance with embodiments disclosed herein.
[0017] FIG. 6 is a partial cross-sectional view of a portion of the
tool assembly shown in FIG. 5 in a first configuration in
accordance with embodiments disclosed herein.
[0018] FIG. 7 is a partial cross-sectional view of a portion of the
tool assembly shown in FIG. 5 in a second configuration in
accordance with embodiments disclosed herein.
[0019] FIG. 8 is a side view of a tubular configured to carry an
electrical wire or cable through a tool assembly in accordance with
embodiments disclosed herein.
[0020] FIG. 9 is a cross-sectional view of a tool assembly having a
tubular configured to carry an electrical wire or cable in
accordance with embodiments disclosed herein.
[0021] FIG. 10 is a schematic of a bottom hole assembly in
accordance with embodiments disclosed herein.
[0022] FIG. 11 is a perspective view of a reamer block for a tool
assembly in accordance with embodiments disclosed herein.
[0023] FIG. 12 is a perspective view of a cutter block for a tool
assembly in accordance with embodiments disclosed herein.
DETAILED DESCRIPTION
[0024] Embodiments disclosed herein generally relate to a bottom
hole assembly (BHA). More specifically, embodiments disclosed
herein relate to a bottom hole assembly including a power drive and
a reamer. A bottom hole assembly in accordance with embodiments
described herein may include a reamer that allows electrical
communication through a central throughbore of the reamer, for
example, from a power drive to an electrically controlled or
actuated tool, such as a measurement-while-drilling (MWD) and/or
logging-while-drilling (LWD) tool, or a caliper tool.
[0025] FIG. 1 depicts an offshore drilling assembly, generally
denoted 50, suitable for use with a downhole tool in accordance
with embodiments disclosed herein. In FIG. 1 a semisubmersible
drilling platform 52 is positioned over an oil or gas formation
(not shown) disposed below the sea floor 56. A subsea conduit 58
extends from deck 60 of platform 52 to a wellhead installation 62.
The platform may include a derrick and a hoisting apparatus for
raising and lowering the drill string 70, which, as shown, extends
into borehole 80 and includes drill bit 72 and a hydraulically
actuated tool assembly 100 disposed. The drill string 70 may
optionally further include substantially any number of other
downhole tools (collectively referred to as the BHA 33) including,
for example, MWD/LWD tools, stabilizers, a drilling jar, a rotary
steerable tool, and a downhole drilling motor. The hydraulically
actuated tool assembly 100 may be disposed in substantially any
location along the string, for example, just above the bit 72 or
further uphole above various MWD/LWD tools. The invention is
explicitly not limited in these regards.
[0026] As used herein, a MWD/LWD tool(s) refers to a MWD tool
and/or a LWD tool. The MWD/LWD tool may include one or more
individual tools. The MWD/LWD tool may evaluate physical properties
including, for example, pressure, temperature, and wellbore
trajectory, and formation parameters, such as resistivity,
porosity, and sonic velocity, as the tool is run downhole. This
information may be stored and/or transmitted to the surface by any
method known in the art, for example, by wireline.
[0027] During a drilling operation, drilling fluid (commonly
referred to as "mud" in the art) is pumped downward through the
drill string 70 and the bottom hole assembly (BHA) where it emerges
at or near the drill bit 72 at the bottom of the borehole. The mud
serves several purposes, for example, including cooling and
lubricating the drill bit, clearing cuttings away from the drill
bit and transporting them to the surface, and stabilizing and
sealing the formation(s) through which the borehole traverses. The
discharged mud, along with the borehole cuttings and sometimes
other borehole fluids, then flow upwards through the annulus 82
(the space between the drill string 70 and the borehole wall) to
the surface. In some embodiments of the present disclosure, the
tool assembly 100 makes use of the differential pressure between an
internal flow channel and the annulus to selectively actuate and
deactuate certain tool functionality (e.g., the radial extension of
a cutting structure outward from a tool body).
[0028] It will be understood by those of ordinary skill in the art
that the configuration illustrated in FIG. 1 is an example of a
drilling assembly in which a bottom hole assembly in accordance
with the present disclosure may be used. It will be further
understood that embodiments in accordance with the present
disclosure are not limited to use with a semisubmersible platform
52 as illustrated in FIG. 1. Embodiments of the present disclosure
may also be used with any kind of subterranean drilling operation,
either offshore or onshore.
[0029] Referring now to FIG. 2, in accordance with embodiments of
the present disclosure, the BHA 33 may include drill bit 72, tool
assembly 100, one or more MWD/LWD tool 39, and a rotary steerable
system 34. One of ordinary skill in the art will understand that
the rotary steerable system 34 is a power driven tool used for
directional drilling. The rotary steerable system 34 allows
continuous rotation of the drill string while steering the bit.
Rotary steerable system 34 may be any rotary steerable system known
in the art, including push-the-bit systems and point-the-bit
systems. The rotary steerable system 34 includes a bias unit (not
shown) and a control unit (not shown). The bias unit applies a
force to the bit 72 in a controlled direction. The control unit may
include self-powered electronics, sensors, and a control mechanism.
The MWD/LWD tool 39 may be electrically coupled to the rotary
steerable system 34. The electrical connection between the rotary
steerable system 34 and the MWD/LWD tool 39 may provide power to
the MWD/LWD tool for operating the various components of the
MWD/LWD tool, such as sensors, transducers, and transmitters.
[0030] As shown in FIG. 2, the BHA 33 includes a tool assembly 100
disposed axially (i.e., along the length or longitudinal axis of
the drill string 70) above the rotary steerable system 34 and
axially below the MWD/LWD tool 39. In other words, the tool
assembly 100 is disposed on the drill string between the MWD/LWD
tool 39 and the rotary steerable system 34.
[0031] In one embodiment of the present disclosure, tool assembly
100 may include an underreamer configured for selective hydraulic
actuation and deactuation. By actuate and deactuate (or activate
and deactivate) it is meant that the reamer cutting structures 105
(referred to herein as blades or blocks) may be extended radially
outward from the tool body 110 and retracted radially inward
towards (or into) the tool body 110. FIGS. 3 and 4 depict one
embodiment of an underreamer in retracted (i.e., deactivated as
shown on FIG. 3) and extended (activated as shown on FIG. 4)
configurations. In certain tool configurations, the blades may be
fully extended when the hydraulic pressure exceeds a predetermined
threshold. The blades may be spring biased inwards and retract upon
removal of the pressure. These reamers may therefore be thought of
as having two operational configurations: (i) a low flow (low
pressure) configuration in which the blades are retracted and (ii)
a high flow (high pressure) configuration in which the blades are
extended. Additional configurations, for example, including a high
flow (high pressure) configuration in which the blades are
retracted and a mechanism for selecting among the various
configurations during a drilling/reaming operation may also be
provided. For example, a reamer may be configured to provide an
actuation/deactuation system that enables the reamer to be actuated
and deactuated substantially any number of times without breaking
the tool string or tripping it out of the borehole. For example, a
drilling tool assembly, including a reamer disposed axial above a
drill bit, may be configured to drill a portion of the wellbore
with the reamer deactivated (with the reamer blades 105 retracted
as depicted on FIG. 3). At some specific (or predetermined)
location, the reamer may be activated (with the reamer blades 105
extended as depicted on FIG. 4) so as to form a wellbore having an
increased diameter. The reamer may then be deactivated at
substantially any other suitable location and the drill bit alone
may be used to drill another length of the wellbore. Substantially
any number of such activation/deactivation cycles may be performed
in drilling the wellbore.
[0032] It will be understood that tool assembly embodiments in
accordance with the present disclosure are not limited to
underreamers such as depicted on FIGS. 3 and 4. Various embodiments
of tool assemblies disclosed herein may be used to actuate
substantially any downhole tool for which hydraulic actuation and
deactuation may be advantageous. Such tools may include
hydraulically actuated stabilizers, milling tools, packers, impact
tools, and the like.
[0033] One example of a tool assembly that may be used in
accordance with embodiments disclosed herein is shown and disclosed
in U.S. application Ser. No. 13/112,326 (U.S. Publication No.
2011/0284233), which is incorporated herein by reference in its
entirety.
[0034] FIG. 5 depicts one embodiment of a hydraulically actuated
tool assembly 100 in longitudinal cross section in accordance with
the present disclosure. In the embodiment shown, the tool assembly
100 includes an underreamer tool body 110 connected to a sub body
120. While the embodiments described herein are specific to
reamers, it will be understood that embodiments of the present
disclosure may be used to activate/deactivate various downhole
tools as described above. A piston assembly 200 is disposed
substantially co-axially in the tool and sub bodies 110 and 120 and
is configured to reciprocate axially therein. Piston assembly 200
includes a valve piston 210 connected to a cam piston 240 (e.g.,
via locking nut 238). A helical compression spring 252 is disposed
axially between a lower face of the cam piston 240 and a mandrel
cap 222 disposed in the sub body 120. In the embodiment shown, the
cam piston 240 and the spring 252 are disposed about a cam mandrel
265, with an outer surface of the mandrel 265 being sealingly
engaged with an inner surface 241 of the cam piston 240.
Compression spring 252 is configured to bias the cam piston 240
(and therefore piston assembly 200) in the uphole direction
(towards the underreamer tool body 110).
[0035] The piston assembly 200 is configured to reciprocate between
a first low flow position and second and third high (or full) flow
positions. In the low flow position, the spring force urges
(biases) the assembly 200 in the uphole direction such that an
uphole engagement face 245 engages internal shoulder 224 of sub
body 120 (as shown in FIGS. 5 and 6). In the second high flow
position, fluid force exceeds the spring force and urges the
assembly 200 in a downhole direction such that at least one
shoulder portion 282 of the cam piston engages at least one stop
block 229. In the third high flow position, fluid force again
exceeds the spring force and urges the assembly 200 in a downhole
direction such that the stop block 229 slides past the shoulder
portion 282 of the cam and engages a cam slot 484 (as shown in FIG.
6). In the embodiment shown, the stop blocks 229 are disposed in
corresponding recesses formed in the sub body and extend radially
into the central bore 221 of the sub body 120 where they may engage
the cam piston 240 as described above.
[0036] FIG. 6 depicts a partial cross section of tool assembly 100
in the low flow configuration. In the embodiment shown, valve
piston 210 is disposed substantially co-axially in and sealingly
engaged with mandrel sleeve 370 and mandrel 380. Valve piston 210
includes first and second axially spaced sets of circumferentially
spaced ports 416 and 418. In the low flow configuration depicted on
FIGS. 5 and 6, ports 416 are sealingly engaged with an inner
surface 371 of mandrel sleeve 370 (i.e., such that they are axially
misaligned with mandrel ports 385) and ports 418 are sealingly
engaged with an inner surface 381 of the mandrel 380. Moreover, as
depicted the mandrel ports 385 formed in the mandrel 380 are
sealingly engaged with outer surface 411 of valve piston 210 such
that there is no fluid communication between ports 385 and the
through bore 375. As described in more detail below, tool actuation
requires that the valve piston be translated axially such that the
first set of ports 416 (the uphole ports) become axially aligned
with mandrel ports 385. Such alignment provides fluid communication
between the internal bore 375 and the downhole tool via the lower
mandrel ports 385.
[0037] With continued reference to FIG. 6, cam piston 240 is
disposed in and sealingly engaged with sub body 120. The cam piston
240 shown includes first, second, and third axial portions 450,
460, and 480 having distinct outer diameters. The first portion 450
of the cam piston 240 includes a plurality of circumferentially
spaced apertures 452 configured to provide fluid communication
between the internal bore of the cam and an annular area 318 formed
internal to the tool and sub bodies 110 and 120. A second portion
460 of the cam piston 240 includes a plurality of cam grooves 465
formed in an outer surface thereof. The cam grooves 465 are
configured to engage one or more guide pins 327 that extend
radially inward from the sub body 120. In the embodiment shown,
four guide pins 327 are circumferentially spaced at 90 degree
intervals about the sub body (although the present disclosure is
not limited in this regard). The guide pins 327 are configured to
travel within the cam grooves 465 and rotate the cam piston 240 and
the valve piston 210 as the piston assembly 200 reciprocates
axially. A third portion 480 of the cam piston 24, having an
enlarged diameter and a plurality of lower cam slots 484, is
configured to engage at least one stop block 229. In the embodiment
shown, four stop blocks 229 are circumferentially spaced at 90
degree intervals about the sub body (although the present
disclosure is again not limited in this regard). The guide pin/cam
groove and stop block/cam slot interactions are discussed in more
detail below with respect to the activation and deactivation
mechanisms.
[0038] Referring back to FIG. 5, the tool assembly 100 further
includes a conduit or tubular 290 extending through a central bore
of the tool assembly 100, i.e. through central bores of the tool
body 110 and the sub body 120. The tubular 290 may be formed from
any material known in the art, for example, steel, alloys, and
composites. Tubular 290 may be rigid or flexible. As shown, the
tubular 290 extends from an upper end of the tool body 110 through
a central bore of the valve piston 210 and a central bore of the
cam piston 240 to a lower end of the sub body 120. A locking
apparatus 137 may be used to secure each end of the tubular 290 to
the tool assembly 100. As shown in FIG. 5, the tool assembly 100
may further include a bottom sub 119 coupled to the lower end of
the sub body 120. In the embodiment shown, a locking apparatus 137
is disposed in a bottom sub 119 and in an upper end of the tool
body 110 to secure the tubular 290 within the tool assembly. In one
embodiment, the locking apparatus may include a locking sleeve
coupled to the inner surface of the tool body 110, the sub body
120, and/or the bottom sub 119. The tubular 290 may extend through
the locking sleeve and may be threadedly coupled to the locking
sleeve.
[0039] In other embodiments, as shown in FIG. 5, the tubular 290
may extend through a first locking sleeve 104 disposed at one end
of the tubular 290 and coupled to the upper end of the tool body
110 and through a second locking sleeve 106 disposed at an opposite
end of the tubular 290 and coupled to the bottom sub 119. A locking
element 103, 107 may be disposed around the tubular 290 and
configured to secure the tubular 290 between the two locking
sleeves 104, 106, respectively. For example, the locking elements
103, 107 may be threadedly engaged with the ends of the tubular and
tightened against the locking sleeves 104, 106. In some
embodiments, locking elements may include jam nuts. One of ordinary
skill in the art will appreciate that other apparatus and
mechanisms may be used to secure the ends of the tubular 290 within
the tool assembly 100 without departing from the scope of the
present disclosure. The locking sleeves 104, 106 and locking
elements 103, 107 may also provide tension to the tubular 290 to
provide stabilization and centralization of the tubular 290 within
the tool assembly. One of ordinary skill in the art will appreciate
that various locking apparatus may be used to secure the tubular
290 within the tool assembly without departing from the scope of
the present disclosure.
[0040] Tubular 290 includes a throughbore 273 configured to carry
or house an electrical wire or cable extending from one end of the
tool assembly 100 to an opposite end of the tool assembly 100. The
electrical wire or cable may connect electrical components disposed
on the drill string at opposite ends of the tool assembly 100. For
example, referring back to FIG. 2, tubular 290 is configured to
carry an electrical wire or cable through the tool assembly 100
that electrically connects the rotary steerable system 34 to the
MWD/LWD tool 39. Thus, a hydraulically actuated tool in accordance
with embodiments disclosed herein may be disposed between a power
source (e.g., a rotary steerable system) and a tool electrically
connected to the power source.
[0041] Referring now to FIGS. 8 and 9, tubular 290 may include a
single tubular component or multiple tubular components coupled to
one another at each end (e.g., by threaded engagement, press fit,
welded, or the like). Tubular 290 may also include one or more
centralizers 255 coupled to an outer surface of the tubular 290.
The centralizer 255 is configured to centralize and/or stabilize
the tubular within the tool assembly, thereby stably securing the
electrical wire or cable within the tool assembly 100. A
centralizer 255 may include a block formed to fit against the outer
curved surface of the tubular 290 and extend radially outward from
the tubular 290 a predetermined distance, i.e., an extension
height. The extension height of the centralizer may be determined
based on the inside diameters of the components of the tool
assembly 100 (FIG. 5). For example, the extension height of the
centralizer may be determined based the outer diameter of the
tubular 290 and the inside diameter of one or more of the tool body
110, the sub body 120, the valve piston 210, and the cam piston
240. The outer surface 278 of the centralizer 255 is configured to
contact the inside diameter of at least one component of the tool
assembly 100. The centralizer 255 block may be formed from any
material known in the art, for example, a polymer, a metal, a
composite material. The centralizer 255 may be coupled to the
tubular 290 by any method known in the art, for example, by
mechanical fasteners 277, such a screws or bolts, adhesives, or
welding.
[0042] As shown in FIG. 8, the tubular 290 may include multiple
sets of centralizers 255 disposed along the length of the tubular
290. Each set of centralizers may include two or three or more
centralizer 255 blocks disposed azimuthally around the tubular 290.
For example, three centralizers 255 may be disposed at a same axial
position along the tubular 290 and positioned 120 degrees from each
other, as shown near the upper end of the tubular 290 in FIG. 8. In
other embodiments, four centralizers 255 may be disposed at a same
axial position along tubular 290 and positioned 90 degrees from
each other, as shown near the lower end of the tubular 290 in FIG.
8. One of ordinary skill in the art will appreciate that various
numbers of centralizers at various azimuthal angles and various
numbers of sets of centralizers may be used with the tubulars 290
in accordance with the present disclosure. Further, a second set of
centralizers 255 adjacent a first set of centralizers 255 may be
positioned rotationally offset from the first set of centralizers
255, as shown in FIG. 8.
[0043] With reference to FIG. 5, in certain embodiments, the
tubular 290 may include one or more centralizers 255 disposed
proximate an upper end of the tubular 290 and one or more
centralizers 255 disposed proximate the lower end of the tubular
290, while a central portion 274 of the tubular 290 is free of
centralizers 255. When the tubular 290 is disposed inside the tool
assembly 100, central portion 274 of tubular 290 may be positioned
radially inward of the piston assembly 200. The tubular 290 is free
of centralizers 255 in the central portion 274 to allow movement of
the valve piston 210 and the cam piston 240 within the tool
assembly 100. Thus, the piston assembly 200 may be used to actuate
and deactuate the tool assembly 100 downhole while the tubular 290
allows for electrical communication through the tool assembly 100
from a first downhole component (e.g., a rotary steerable system)
to a second downhole component (e.g., a MWD/LWD tool).
[0044] Downhole tool actuation and deactuation is described in
detail in U.S. application Ser. No. 13/112,326 (U.S. Publication
No. 2011/0284233). In general, a hydraulically actuated tool
assembly as described herein may be selectively switched between
the three aforementioned modes of operation. In one embodiment,
changing the drilling fluid flow rate to a low flow state and then
back to a high (or full) flow state changes actuation modes (from
deactivated to activated or from activated to deactivated). This
may be accomplished, for example, via cycling the mud pumps off and
then back on. In other embodiments, such cycling of the mud pumps
may be insufficient to activate or deactivate the downhole tool,
and therefore the mud pumps may be cycled substantially any number
of times without changing the tool mode (i.e., without activating
or deactivating the downhole tool). As described in more detail
below, actuation (or deactuation) of the tool assembly may include
a fourth mode, referred to herein as an indexing mode that makes
use of a corresponding index (indexing) flow.
[0045] In FIG. 7, tool assembly 100 is depicted in a second mode,
in which high (or full) full flow is provided while the downhole
tool remains inactive. To switch the assembly 100 from the first
mode (low flow) to the second mode, high (or full) flow is turned
on at the wellbore surface. Increasing the pressure beyond a
predetermined threshold overcomes the spring bias and urges the cam
piston 240 in the downhole direction. The increased flow (pressure)
acts, for example, on uphole face 454 of cam piston 240 thereby
urging valve piston 210 and cam piston 240 in the downhole
direction such that shoulders 282 engage stop blocks 229.
Engagement of the guide pins 327 with cam groove 465 rotates the
cam piston 240 (due to the profile of the groove). In the
embodiment shown, valve piston 210 and cam piston 240 are connected
to one another (e.g., via locking nut 238) and therefore rotate
together, although the present disclosure is not limited in this
regard.
[0046] Despite valve piston 210 being urged downhole with cam
piston 240, ports 416 remain sealingly engaged with the inner
surface 371 of mandrel sleeve 370 (i.e., such that they are axially
misaligned with ports 385). Ports 418 also remain sealingly engaged
with the inner surface 381 of mandrel 380. Moreover, as also
depicted the mandrel ports 385 remain sealingly engaged with the
outer surface 411 of valve piston 210. Therefore, the downhole tool
remains inactive (in the deactuated state) while substantially full
flow is provided through the bore, for example, to a drill bit for
a drilling operation.
[0047] As described above, cycling the mud pumps between high and
low flow is insufficient to activate and deactivate the downhole
tool. The mud pumps may be cycled substantially any number of times
such that the tool cycles between the first and second operational
modes depicted on FIGS. 6 and 7 without activating the downhole
tool. The cam piston 240 shown includes a groove pattern having a
plurality of upper and lower axial end portions 462 and 464. In the
embodiment depicted, half of the axial end portions 462a and 464a
are circumferentially aligned with corresponding cam shoulders 282
and the other half 462b and 464b are circumferentially aligned with
corresponding cam slots 484 (and therefore misaligned with the cam
shoulders 282). The axial portions 462a and 464a that are aligned
with the cam shoulders 282 alternate with the axial portions 462b
and 464b that are aligned with the cam slots 484.
[0048] The guide pins 327 are initially located in a lower axial
end portion 464b of the cam groove that is circumferentially
aligned with a cam slot 484. Increased flow urges the cam piston
240 downward causing the guide pins 327 to travel along the groove
465 to upper axial end portion 462a. Movement of the cam piston 240
past the guide pins 327 rotates the cam through an angle of 45
degrees in the embodiment shown such that the guide pin(s) 327
align with cam shoulders 482 (see FIG. 6). In this mode, the tool
assembly remains deactivated (FIG. 7) while high flow is provided.
Decreasing fluid flow allows the cam piston 240 to move upwards via
spring bias causing the guide pins 327 to travel along groove 465
to lower axial end portion 464b. Movement of the cam piston 240
past the guide pins 327 further rotates the cam piston 240 by an
additional 45 degrees such that it is again aligned with an
adjacent cam slot 484. Irrespective of the number of high-low mud
pump cycles, the guide pin(s) returns to the same alignment after
each cycle (i.e., circumferentially aligned with a slot or a
shoulder). In this way, repeated cycling is insufficient to
activate and/or deactivate the downhole tool (i.e., is insufficient
to change the operational mode of the tool).
[0049] In the embodiment shown, actuation of the downhole tool may
be effected by indexing the cam such that the guide pins 327 move
from one axial end portion of the cam groove to an adjacent axial
end portion (from end portion 462a to end portion 462b or from end
portion 462b to end portion 462a). This may be accomplished by (i)
decreasing the flow rate from high flow to low flow thereby
returning the tool to the first mode as depicted on FIG. 6, (ii)
increasing the flow rate from low flow to an intermediate
`indexing` flow rate, (iii) decreasing the flow rate from the
indexing flow to the low flow, and (iv) increasing the flow rate
from low flow back to high flow.
[0050] As discussed above, a tool assembly in accordance with
embodiments of the present disclosure provides hydraulic actuation
of the tool assembly while simultaneously providing electrical
communication through the throughbore of the tool assembly.
Therefore, a tool assembly in accordance with embodiments disclosed
herein may allow for various configurations of a BHA that may
provide an improved rate of penetration, reduced drilling costs,
and faster drill times.
[0051] FIG. 10 is a schematic of a BHA 333 in accordance with
embodiments of the present disclosure. BHA 333 includes a bit 372,
a rotary steerable system 334, a tool assembly 300, a MWD/LWD tool
339, and a reamer 383. Tool assembly 300 is a tool assembly similar
to that described above with respect to tool assembly 100 in FIGS.
2-7. Specifically, tool assembly 300 is a hydraulically actuated
tool assembly as described above and includes a tubular extending
through the central throughbore of the tool assembly 300 configured
to carry or house an electrical wire or cable. As shown in FIG. 10,
the tool assembly 300 is disposed between a rotary steerable system
334 and a MWD/LWD tool 339. Thus, tool assembly 100 may be
hydraulically actuated from the surface, while the MWD/LWD tool 339
is powered by the rotary steerable system 334. While a MWD/LWD tool
339 is described here, one of ordinary skill in the art will
appreciate that any electrically controlled or actuated tool may be
disposed above the tool assembly 300 and be powered by the rotary
steerable system 334 by an electrical wire or cable extending from
the rotary steerable system 334, through a tubular of the tool
assembly 300, as described above with reference to tool assembly
100 in FIG. 5, and coupled to an electrically controlled or
actuated tool. By providing electrical communication through the
tool assembly 300, the tool assembly 300 may be positioned closer
to the drill bit 372 than in conventional BHAs.
[0052] For example, in one embodiment, the tool assembly 300 of
FIG. 10 may be a hydraulically actuated reamer. Because the tool
assembly 300 provides for electrical communication through the tool
assembly 300, the tool assembly 300 may provide for reaming of the
wellbore at an axial location above the drill bit 372 and below the
MWD/LWD tool 339 (or other electrically controlled and/or actuated
tool).
[0053] In one embodiment, BHA 333 of FIG. 10 may be used for hole
enlargement while drilling (HEWD) applications. HEWD applications
may use concentric expandable underreamers housed in a conventional
BHA configuration with a rotary steerable system and an underreamer
placed above the MWD/LWD tool. HEWD applications using a BHA with
an underreamer above the rotary steerable system and the MWD/LWD
tool results in the creation of a long, un-enlarged section of the
borehole, known as a "rathole," between the drill bit and the
underreamer at a total depth. The rathole can range between, for
example, 100 feet and 200 feet in length. Setting an appropriate
casing depth and landing a liner hanger package may be complicated
with a lengthy rathole. If a liner is run after a drilling
operation, the length of the rathole is a factor in determining the
distance between a liner shoe and a liner hanger setting depth. A
rathole may also complicate cementing operations because the
equivalent circulating density (ECD) during cementing while
circulating around the casing shoe may increase in the rathole due
to a reduced annular clearance between the casing and the borehole.
Zones with a tight window between ECD and fracture gradients may be
impacted further when cement needs to be circulated up the rathole
using a heave mud. To alleviate such complications in a HEWD
application, a second BHA may be run to cleanout or open the hole,
thereby removing the removing or reducing the rathole.
[0054] BHA 333 of FIG. 10 may be used for such a HEWD application
such that the rathole may be removed or reduced in a single trip of
BHA 333. In such a HEWD application, the tool assembly 300 is a
hydraulically actuated reamer and is positioned between the rotary
steerable system 334 and the MWD/LWD tool 339, as shown. The
hydraulic actuation of the tool assembly 300, as discussed above,
activates or deactivates cutting blocks of the reamer tool assembly
300. Open and closed modes of the reamer tool assembly (i.e.,
extended cutter blocks or collapsed cutter blocks) may be
accomplished by using a predetermined sequence of indexing flow
rates. Operators may monitor flow rates between the modes by
observing parameters such as standpipe pressure, surface torque,
hookload and downhole data that measure flow rate changes through
the MWD/LWD tool 339. Because the reamer tool assembly 300 allows
electrical communication through the throughbore of the reamer tool
assembly 300, the reamer tool assembly may be disposed closer to
the drill bit 372 in the BHA 333, which reduces the length of the
rathole.
[0055] In the embodiment shown in FIG. 10, reamer 383 may be a
standard ball-drop actuated underreamer disposed above the MWD/LWD
tool 339. In this embodiment, the BHA 333 may be run down hole.
After drilling out a casing shoe and obtaining an acceptable
formation integrity test, the reamer 383 may be actuated by
dropping an activation ball from the surface. While the drill bit
372 and the reamer 383 cut the formation, the reamer tool assembly
300 may remain in the deactivated mode. After reaching total depth,
reamer 383 may be deactivated by increasing a pressure above the
dropped activation ball or dropping a deactivation ball and the BHA
333 may be pulled back. The reamer tool assembly 300 may then be
positioned proximate the top of the rathole and activated. The BHA
is then lowered again to total depth with the reamer tool assembly
300 cutting the formation to enlarge the rathole. This dual reamer
system (BHA 333 with reamer 383 and reamer tool assembly 300) may
provide a BHA that may reduce or remove long ratholes without a
second or dedicated cleanout run and without impacting the
functionality of MWD/LWD tools during the drilling operation.
[0056] One of ordinary skill in the art will appreciate that a
hydraulically actuated tool assembly including a tubular extending
through a central bore of the tool assembly and configured to carry
or house an electrical wire or cable in accordance with embodiments
disclosed herein may be disposed at various locations in a BHA. For
example, in some embodiments, the hydraulically actuated tool
assembly may be disposed above a MWD/LWD tool. A hydraulically
actuated tool assembly as described herein may include a caliper
measurement tool, a reamer, a stabilizer, or any downhole tool
having actuatable (extendable) arms.
[0057] One of ordinary skill in the art will appreciate that other
hydraulically actuated tools similar to that described with respect
to FIG. 5 may be modified to include a tubular or conduit as
discussed above without departing from the scope of embodiments
disclosed herein. For example, other tool assemblies, for example,
those shown in U.S. application Ser. No. 13/112,326 (U.S.
Publication No. 2011/0284233), may be modified to include a tubular
configured to carry or house an electrical wire or cable extending
from one end to an opposite end of the tool assembly. The tool
assemblies disclosed in U.S. application Ser. No. 13/112,326 (U.S.
Publication No. 2011/0284233) may be modified, for example, by
enlarging the central bores of the valve piston, the cam piston,
and/or the tool and sub bodies to accommodate the outer diameter of
the tubular. Additionally, retaining mechanisms for securing the
tubular within the tool assembly body may be coupled to one or both
ends of the tool assembly body, as discussed above.
[0058] With reference to FIG. 10, the BHA 333 may also include a
stabilizer (not shown) disposed between the rotary steerable system
334 and the tool assembly 300. The stabilizer may act as a fulcrum
for a deflection assembly (i.e., the lower end of the BHA including
the rotary steerable assembly and the bit). In other embodiments,
the reamer tool assembly 300 may act as a stabilizer when the tool
assembly 300 is in the deactivated mode. Thus, when the reamer tool
assembly 300 is in the deactivated mode (i.e., the blades are
retracted), the reamer tool assembly 300 may provide a fulcrum for
the rotary steerable system 334 and drill bit 372. Then, the blades
of the reamer tool assembly 300 may be moved into the activated
mode (i.e., the blades are extended) to cut the formation (e.g.,
reduce the rathole). Use of the reamer tool assembly 300 as a
reamer during activated mode and a stabilizer during deactivated
mode may allow for the reamer tool assembly 300 to be positioned
closer to the rotary steerable system, and therefore reduce the
rathole length before reaming.
[0059] The reamer tool assembly 300 may include one or more reamer
blocks 597 having two reamer blades 594 disposed, as shown in FIG.
11. Each blade 594 includes a plurality of cutting elements 593
disposed on a lower end of the blade 594 and a plurality of cutting
elements 593 disposed on an upper end of the blade 594, such that
the reamer blocks 597 provide an overall active gauge cutting
structure. In other embodiments, the reamer tool assembly 300 may
include cutter blocks 599, as shown in FIG. 12. Cutter blocks 599
may be, for example, cement removal cutter blocks. Each cutter
block 599 may include two reamer blades disposed on a lower end of
the cutter block 599 having a plurality of cutting elements 593
disposed thereon. An upper end of each cutter block 599 may include
a stabilizer pad 595 with a plurality of stabilizer elements
disposed thereon, such that the cutter block 599 provides an
overall passive gauge cutting structure. In other words, the number
of cutting elements on the gauge surface of the cutter block 599
may be small and provide passive gauge interaction with the
formation when the cutter block 599 is retracted. Thus, the cutter
block 599 may be used with the tool assembly 300 and act as a
stabilizer for the rotary steerable system when the tool assembly
300 is in the deactivated mode.
[0060] Embodiments disclosed herein may provide a hydraulically
actuated tool assembly that allows electrical communication through
a throughbore of the tool assembly. Thus, embodiments disclosed
herein may provide a tool assembly that may be positioned between
electrically connected components of a bottom hole assembly.
Further, embodiments disclosed herein may provide a reamer tool
assembly that may provide for a reduced rathole during drilling
operations.
[0061] Although only a few example embodiments have been described
in detail above, those skilled in the art will readily appreciate
that many modifications are possible in the example embodiments
without materially departing from scope of the present disclosure.
Accordingly, all such modifications are intended to be included
within the scope of this disclosure and the following claims. In
the claims, means-plus-function clauses are intended to cover the
structures described herein as performing the recited function and
not only structural equivalents, but also equivalent structures.
Thus, although a nail and a screw may not be structural equivalents
in that a nail employs a cylindrical surface to secure wooden parts
together, whereas a screw employs a helical surface, in the
environment of fastening wooden parts, a nail and a screw may be
equivalent structures.
* * * * *