U.S. patent application number 14/495845 was filed with the patent office on 2016-03-24 for back-reaming rotary steering.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Junichi Sugiura.
Application Number | 20160084007 14/495845 |
Document ID | / |
Family ID | 55525276 |
Filed Date | 2016-03-24 |
United States Patent
Application |
20160084007 |
Kind Code |
A1 |
Sugiura; Junichi |
March 24, 2016 |
Back-Reaming Rotary Steering
Abstract
A rotary steerable system (RSS) having multiple steering pads, a
valve to sequentially actuate the plurality of steering pads, and a
back-reaming bit formed by multiple cutting elements carried by
each of the steering pads. While rotating the drill string, the
RSS, and the drill bit, the valve and/or the controller are
operated to sequentially actuate the steering pads to operatively
urge the RSS and the drill bit away from a longitudinal axis of the
wellbore, thus steering the wellbore drilling direction.
Thereafter, while rotating the drill string, the RSS, and the drill
bit, the valve and/or the controller are operated to simultaneously
actuate each of the steering pads to operatively urge at least one
of the cutting elements on each of the steering pads into contact
with a sidewall of the wellbore, thus back-reaming the
wellbore.
Inventors: |
Sugiura; Junichi; (Bristol,
GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
55525276 |
Appl. No.: |
14/495845 |
Filed: |
September 24, 2014 |
Current U.S.
Class: |
175/61 ;
175/76 |
Current CPC
Class: |
E21B 17/1092 20130101;
E21B 10/322 20130101; E21B 7/06 20130101; E21B 17/1014
20130101 |
International
Class: |
E21B 7/06 20060101
E21B007/06; E21B 10/46 20060101 E21B010/46; E21B 10/32 20060101
E21B010/32; E21B 3/00 20060101 E21B003/00; E21B 34/06 20060101
E21B034/06 |
Claims
1. A system for drilling a wellbore, comprising: a rotary steerable
system (RSS) at least indirectly coupled between a drill string
collar and a drill bit, wherein the RSS comprises: a housing; a
plurality of steering pads circumferentially spaced around the
housing, wherein each of the plurality of steering pads is
actuatable to radially extend away from the housing independent of
the other ones of the plurality of steering pads, and wherein at
least one of the plurality of steering pads comprises a
back-reaming bit; a valve; and a controller, wherein the valve and
the controller are collectively operable to: sequentially actuate
ones of the plurality of steering pads to substantially
decentralize the RSS relative to the wellbore; and simultaneously
actuate each of the plurality of steering pads to substantially
centralize the RSS relative to the wellbore, thus urging the
back-reaming bit into contact with a sidewall of the wellbore.
2. The system of claim 1 wherein each of the plurality of steering
pads is actuatable to radially extend away from the housing by
rotating about an axis that is substantially parallel to a
longitudinal axis of the housing.
3. The system of claim 1 wherein the valve and the controller are
collectively operable to simultaneously actuate each of the
plurality of steering pads by disengaging the valve.
4. The system of claim 1 wherein the back-reaming bit comprises a
plurality of cutting elements.
5. The system of claim 4 wherein each of the plurality of cutting
elements comprises: a substrate coupled to the corresponding
steering pad; and a cutting layer coupled to the substrate.
6. The system of claim 4 wherein each of the plurality of steering
pads comprises at least one of the plurality of cutting
elements.
7. The system of claim 6 wherein simultaneously actuating each of
the plurality of steering pads to substantially centralize the RSS
relative to the wellbore urges at least one of the plurality of
cutting elements on each of the plurality of steering pads into
contact with the sidewall of the wellbore.
8. The system of claim 1 wherein each of the plurality of steering
pads is actuatable to radially extend away from a retracted
position toward an extended position.
9. The system of claim 8 wherein each of the plurality of steering
pads is lockable in the extended position.
10. The system of claim 1 wherein the cutting elements are disposed
in an uphole portion of each of the plurality of steering pads and
not in a downhole portion of each of the plurality of steering
pads.
11. An apparatus, comprising: a drill string disposed within a
wellbore that extends from a wellsite surface to a subterranean
formation; a drill bit; and a rotary steerable system (RSS) coupled
between the drill string and the drill bit, wherein the RSS
comprises: a plurality of steering pads spaced circumferentially
apart around a perimeter of the RSS; a valve operable to
sequentially actuate the plurality of steering pads; and a
back-reaming bit comprising a plurality of cutting elements,
wherein each of the plurality of steering pads comprises at least
one of the plurality of cutting elements.
12. The apparatus of claim 11 wherein each of the plurality of
cutting elements comprises: a substrate coupled to a corresponding
one of the plurality of steering pads; and a cutting layer coupled
to the substrate.
13. The apparatus of claim 12 wherein: the substrate substantially
comprises tungsten carbide; and the cutting layer substantially
comprises polycrystalline diamond.
14. The apparatus of claim 11 further comprising a controller,
wherein the valve and the controller are collectively operable to
sequentially actuate the plurality of steering pads to operatively
urge the RSS away from a longitudinal axis of the wellbore.
15. The apparatus of claim 14 wherein the valve and the controller
are collectively further operable to simultaneously actuate each of
the plurality of steering pads to operatively urge at least one of
the plurality of cutting elements on each of the plurality of
steering pads into contact with a sidewall of the wellbore.
16. The apparatus of claim 11 not comprising a reaming tool,
component, or feature disposed between the drill string and the
RSS.
17. The apparatus of claim 11 not comprising a reaming tool,
component, or feature disposed between the drill string and the
drill bit, other than the back-reaming bit formed by the plurality
of cutting elements comprised by corresponding ones of the
plurality of steering pads.
18. A method, comprising: conveying apparatus within a wellbore
that extends from a wellsite surface to a subterranean formation,
wherein the apparatus comprises a drill string, a drill bit, and at
a rotary steerable system (RSS) coupled between the drill string
and the drill bit, and wherein the RSS comprises: a plurality of
steering pads spaced circumferentially apart around a perimeter of
the RSS, wherein each of the plurality of steering pads carries at
least one of a plurality of cutting elements; a valve operable for
sequentially actuating the steering pads; and a controller;
rotating the drill string, thereby rotating the RSS and the drill
bit, while operating at least one of the valve and the controller
to sequentially actuate the plurality of steering pads to
operatively urge the RSS and the drill bit away from a longitudinal
axis of the wellbore; and rotating the drill string, thereby
rotating the RSS and the drill bit, while operating at least one of
the valve and the controller to simultaneously actuate each of the
plurality of steering pads to operatively urge at least one of the
plurality of the cutting elements on each of the plurality of
steering pads into contact with a sidewall of the wellbore.
19. The method of claim 18 wherein: rotating the drill string while
operating at least one of the valve and the controller to
sequentially actuate the plurality of steering pads to operatively
urge the RSS and the drill bit away from a longitudinal axis of the
wellbore comprises: rotating the drill string while operating at
least one of the valve and the controller to sequentially actuate
the plurality of steering pads to operatively urge the RSS and the
drill bit in a first azimuthal direction away from the longitudinal
axis of the wellbore; and the method further comprises: rotating
the drill string while operating at least one of the valve and the
controller to sequentially actuate the plurality of steering pads
to operatively urge the RSS and the drill bit in a second azimuthal
direction away from the longitudinal axis of the wellbore, wherein
the first and second azimuthal directions differ by at least about
twenty degrees.
20. The method of claim 19 wherein: rotating the drill string while
operating at least one of the valve and the controller to
sequentially actuate the plurality of steering pads to operatively
urge the RSS and the drill bit in the first azimuthal direction
away from the longitudinal axis of the wellbore creates a first
wellbore section extending in a first wellbore direction; rotating
the drill string while operating at least one of the valve and the
controller to sequentially actuate the plurality of steering pads
to operatively urge the RSS and the drill bit in the second
azimuthal direction away from the longitudinal axis of the wellbore
creates a second wellbore section extending in a second wellbore
direction; and rotating the drill string while operating at least
one of the valve and the controller to simultaneously actuate each
of the plurality of steering pads to operatively urge at least one
of the plurality of the cutting elements on each of the plurality
of steering pads into contact with the sidewall of the wellbore
includes back-reaming the first and second wellbore sections.
Description
BACKGROUND OF THE DISCLOSURE
[0001] Oil and gas wellbore drilling applications may utilize a
rotary steerable system to control the direction of drilling during
formation of the wellbore. A rotary steerable system may utilize a
drill bit that is coupled with a drill collar and rotated to drill
through the subterranean formation. One or more valves and control
systems may control steering pads selectively actuated for radial
deflection to control the direction of drilling. The valve(s) may
be held at angular orientations with respect to the rotating drill
collar to control the flow of fluid to the steering pads.
[0002] Such rotary steerable systems may be utilized in conjunction
with a concentric reamer as part of a bottom-hole assembly (BHA).
However, due at least in part to operational demands of other BHA
components, the concentric reamer is located a considerable
distance away from the drill bit. For example, once target depth
(TD) is reached, the portion of the wellbore that has not been
reamed by the concentric reamer--also known as the "rathole"
portion of the wellbore located between the concentric reamer and
the drill bit--may far exceed 100-200 feet (or 30-60 meters).
Consequently, to open the rathole to an adequate size, the drill
string, BHA, and drill bit are removed so that another tool/tool
string can be run in-hole to ream the rathole. Of course, this
procedure is time-intensive and expensive.
SUMMARY OF THE DISCLOSURE
[0003] The present disclosure introduces a system for drilling a
wellbore. The system includes a rotary steerable system (RSS)
coupled between a drill string collar and a drill bit. The RSS
includes a housing, multiple steering pads, a valve, and a
controller. The steering pads are circumferentially spaced around
the housing, and are each actuatable to radially extend away from
the housing independent of the other steering pads. At least one of
the steering pads comprises a back-reaming bit. The valve and the
controller are collectively operable to sequentially actuate the
steering pads to substantially decentralize the RSS relative to the
wellbore, and simultaneously actuate each steering pad to
substantially centralize the RSS relative to the wellbore, thus
urging the back-reaming bit into contact with a sidewall of the
wellbore.
[0004] The present disclosure also introduces an apparatus that
includes a drill string disposed within a wellbore that extends
from a wellsite surface to a subterranean formation. The apparatus
also includes a drill bit and a rotary steerable system (RSS)
coupled between the drill string and the drill bit. The RSS
includes multiple steering pads spaced circumferentially apart
around a perimeter of the RSS, a valve operable to sequentially
actuate the steering pads, and a back-reaming bit that includes
multiple cutting elements. Each of the steering pads includes at
least one of the cutting elements.
[0005] The present disclosure also introduces a method in which an
apparatus is conveyed within a wellbore that extends from a
wellsite surface to a subterranean formation. The apparatus
includes a drill string, a drill bit, and at a rotary steerable
system (RSS) coupled between the drill string and the drill bit.
The RSS includes multiple steering pads spaced circumferentially
apart around a perimeter of the RSS. Each of the steering pads
carries at least one of a set of cutting elements. The RSS also
includes a valve operable for sequentially actuating the steering
pads, as well as a controller. The method also includes rotating
the drill string, thereby rotating the RSS and the drill bit, while
operating at least one of the valve and the controller to
sequentially actuate the steering pads to operatively urge the RSS
and the drill bit away from a longitudinal axis of the wellbore.
The method also includes rotating the drill string, thereby
rotating the RSS and the drill bit, while operating at least one of
the valve and the controller to simultaneously actuate the steering
pads to operatively urge at least one of the cutting elements on
each of the steering pads into contact with a sidewall of the
wellbore.
[0006] These and additional aspects of the present disclosure are
set forth in the description that follows, and/or may be learned by
a person having ordinary skill in the art by reading the materials
herein and/or practicing the principles described herein. At least
some aspects of the present disclosure may be achieved via means
recited in the attached claims
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] The present disclosure is understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
[0008] FIG. 1 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure.
[0009] FIG. 2 is a sectional view of a portion of the apparatus
shown in FIG. 1.
[0010] FIG. 3 is a perspective view of a portion of the apparatus
shown in FIG. 2.
[0011] FIG. 4 is a sectional view of a portion of the apparatus
shown in FIG. 2.
[0012] FIG. 5 is a side view of a portion of the apparatus shown in
FIG. 2.
[0013] FIG. 6 is a schematic view of at least a portion of a bit
profile according to one or more aspects of the present
disclosure.
[0014] FIG. 7 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure.
[0015] FIG. 8 is a schematic view of at least the apparatus shown
in FIG. 7 in a subsequent stage of operation according to one or
more aspects of the present disclosure.
[0016] FIG. 9 is a schematic view of at least the apparatus shown
in FIG. 8 in a subsequent stage of operation according to one or
more aspects of the present disclosure.
[0017] FIG. 10 is a flow-chart diagram of at least a portion of a
method according to one or more aspects of the present
disclosure.
[0018] FIG. 11 is a flow-chart diagram of at least a portion of a
method according to one or more aspects of the present
disclosure.
[0019] FIG. 12 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure.
DETAILED DESCRIPTION
[0020] It is to be understood that the following disclosure
provides many different embodiments, or examples, for implementing
different features of various embodiments. Specific examples of
components and arrangements are described below to simplify the
present disclosure. These are, of course, merely examples and are
not intended to be limiting. In addition, the present disclosure
may repeat reference numerals and/or letters in the various
examples. This repetition is for simplicity and clarity, and does
not in itself dictate a relationship between the various
embodiments and/or configurations discussed. Moreover, the
formation of a first feature over or on a second feature in the
description that follows may include embodiments in which the first
and second features are formed in direct contact, and may also
include embodiments in which additional features may be formed
interposing the first and second features, such that the first and
second features may not be in direct contact.
[0021] FIG. 1 is a schematic view of at least a portion of a
drilling system 20 according to one or more aspects of the present
disclosure. The drilling system 20 may comprise a BHA 22, which may
be coupled to and/or otherwise form a portion of a drill string 24,
such as may be utilized to form a wellbore 26 via directional
drilling. The drilling system 20 comprises a rotary steerable
system (RSS) 28 comprising at least three radially actuated
steering pads 30 (two of which being shown in FIG. 2). The steering
pads 30 may be at substantially the same axial positions within the
RSS 28, as shown in FIG. 1, or one or more of the steering pads 30
may be axially offset in a direction substantially parallel to a
longitudinal axis 60 of the wellbore 26, the RSS 28, and/or the BHA
22. The steering pads 30 may be controlled by and/or in conjunction
with a corresponding valve system 32. Each steering pad 30 is
operable and/or otherwise actuated to act against a sidewall of the
wellbore 26, thereby providing directional control. The valve
system 32 may be positioned with the steering pads 30 within a
drill collar and/or other housing 34 of the RSS 28. The housing 34
is directly or indirectly coupled with a drill bit 36, which is
rotated to cut through a surrounding rock formation 38 that may be
in or proximate a hydrocarbon bearing reservoir 40.
[0022] Depending on the environment and the operational parameters
of the drilling operation, the drilling system 20 may comprise a
variety of other features. For example, the drill string 24 may
comprise additional drill collars 42 incorporating various drilling
modules, such as logging-while-drilling (LWD) and/or
measurement-while-drilling (MWD) modules 44, among others. The
additional drill collars 42 may also or instead comprise one or
more conventional reaming devices, such as a concentric
under-reamer device 15 that may be located proximate an uphole end
of the BHA 22.
[0023] Various surface systems also may form a part of or otherwise
be utilized in conjunction with the drilling system 20. For
example, a drilling rig 46 positioned above the wellbore 26 may be
utilized in conjunction with a drilling fluid system 48 also
positioned at the wellsite. The drilling fluid system 48 is
operable to deliver drilling fluid (e.g., "mud") 50 from a drilling
fluid tank 52, through tubing 54, and into the drill string 24. The
drilling fluid 50 returns to the wellsite surface 10 through an
annulus 56 between the drill string 24 and the sidewall of the
wellbore 26. The return flow may be utilized to remove drill
cuttings resulting from operation of drill bit 36. The drilling
fluid 50 may also be utilized in conjunction with control of the
RSS 28, such as in conjunction with control of the valve system 32
and/or the steering pads 30. For example, in addition to being
conducted by an internal passage of the drill string 24 to the
drill bit 36, the drilling fluid 50 may also be directed to or
otherwise utilized to actuate the valve system 32 and/or the
steering pads 30. Actuation of the steering pads 30 may be
controlled by and/or in conjunction with the valve system 32,
thereby controlling the drilling direction.
[0024] The drilling system 20 may also comprise or otherwise be
utilized in conjunction with a surface control system 58. The
surface control system 58 may be utilized to control communication
with the RSS 28 and/or other components of the BHA 22. For example,
the surface control system 58 may receive data from downhole sensor
systems and communicate commands to the RSS 28 to control actuation
of the valve system 32, thereby controlling the drilling direction.
Such control electronics and/or other control apparatus may also or
instead be located downhole, perhaps integral to the RSS 28 and/or
other component of the BHA 22, such as may operate in conjunction
with one or more orientation sensors to control the drilling
direction. The downhole control electronics may be operable to
communicate with the surface control system 58, such as to receive
directional commands and/or to relay information related to
drilling and/or the formation 38 to the surface control system
58.
[0025] The RSS 28 may be conveyed and operated within the wellbore
26 via the drill string 24, as described above. However, the RSS 28
may also or instead be utilized in conjunction with a mud motor
and/or turbine, such as described below and/or otherwise within the
scope of the present disclosure. Other means of conveyance and/or
fluid delivery, however, may also be utilized in implementations
within the scope of the present disclosure, such as coiled tubing,
casing, and/or other tubular means.
[0026] In at least one implementation within the scope of the
present disclosure, the drilling system 20 does not comprise a
reaming component and/or feature other than that which may be
incorporated with the steering pads 30. That is, while conventional
BHAs, drilling systems, and/or other apparatus utilized for
directional drilling may include a concentric reamer and/or other
type of reaming component and/or feature disposed at or near an
uphole end of the BHA, the drilling system 20, the BHA 22, and the
RSS 28 of the present disclosure may include no such reaming
component and/or feature because, for example, the steering pads 30
may instead include reaming features and capabilities.
Consequently, the drilling system 20, the BHA 22, and the RSS 28 of
the present disclosure may be shorter, lighter, less expensive,
and/or less complex (whether mechanically, operationally, or
otherwise) relative to a conventional drilling system, BHA, and/or
RSS.
[0027] FIG. 2 is a schematic view of a portion of the RSS 28 shown
in FIG. 1. Referring to FIGS. 1 and 2, collectively, the housing 34
comprises and/or is coupled between the drill bit 36 and an MWD or
LWD component 44 and/or other component 42 of the BHA 22. For
example, the housing 34 may comprise upper and lower interfaces 35
and 37, respectively, which may couple the RSS 28 between the drill
bit 36 an adjacent drill collar and/or other component of the drill
string 24. The interfaces 35 and 37 may be or comprise
industry-standard fittings (such as box-pin connections), threads,
and/or other coupling means. Such coupling may be in conjunction
with one or more flexible and/or other intervening components.
[0028] A variety of RSS components are carried within internal
passages 62 of the housing 34, such as may be operable for
actuation of the steering pads 30. In the example implementation(s)
described below, each steering pad 30 may be moved radially outward
from the housing 34 by a corresponding piston 64, which may be
hydraulically actuated via drilling fluid 50 metered by the valve
system 32. However, hydraulic oil and/or other fluids carried
internally with the RSS 28 and/or another component of the BHA 22
or drill string 24 may also or instead be utilized to activate the
steering pads 30.
[0029] The valve system 32 may comprise a rotational, spider,
barrel, digital, and/or other type of valve 66. The valve 66 may be
selectively rotated, digitally actuated, and/or otherwise actuated
to direct a portion of the drilling fluid 50 from the corresponding
internal passage 62 to selected ones of the steering pads 30. For
example, one or more hydraulic lines 68 may communicate drilling
fluid 50 from the valve 66 to act against the pistons 64
corresponding to the steering pads 30. The housing 34 and the drill
bit 36 rotate during drilling of the wellbore 26, during which time
the valve 66 may undergo a controlled, relative rotation to
selectively deliver the drilling fluid 50 through the corresponding
hydraulic line(s) 68 to the corresponding steering pads 30.
[0030] The valve 66 may be coupled to or otherwise driven by a
shaft 70, which may be rotated by a corresponding electric and/or
other type of motor 72. One or more encoders and/or other sensors
74 may be operatively engaged with the shaft 70 to monitor the
angular orientation of the valve 66 relative to the housing 34. The
valve system 32, and/or another component of the RSS 28, may also
comprise one or more control devices 75, such as may comprise
and/or operate in conjunction with a microprocessor and/or other
controller 76. The control devices 75 and/or controllers 76 may
each receive data from the sensors 74 and utilize such data and/or
other data to control the motor 72. The motor 72 may thus be
operable in controlling the angular positioning of the valve 66.
One or more of the control devices 75 and/or controllers 76 may
also communicate with the surface control system 58, such as to
receive commands and/or relay data. One or more of the control
devices 75 and/or controllers 76 may also comprise and/or operate
in conjunction with one or more additional components, such as a
direction and inclination package containing magnetometers and
accelerometers (not shown).
[0031] Operational power may be provided to each control device 75,
controller 76, motor 72, and/or other components of the RSS 28 via
one or more power sources 78, such as may be or comprise batteries
(not shown) and/or a turbine 80. Each turbine 80 may comprise
and/or operate in conjunction with an alternator 82 driven by
rotation of the turbine blades 84, such rotation being in response
to the pressurized flow of the drilling fluid 50 through the
internal passages 62.
[0032] One or more components of the valve system 32 and/or other
component of the RSS 28 may be mounted within a pressure housing
86, such as may provide a level of protection against the
relatively high pressure of the drilling fluid 50 and/or the rigors
of the downhole environment. For example, the motor 72, sensors 74,
control device(s) 75, controller(s) 76, and alternator 82 may be
disposed within one or more pressure housings 86. Such pressure
housing(s) 86 may be rigidly attached to the housing 34 via one or
more centralizers and/or other members 88 disposed within the
housing 34. Thus, the pressure housing(s) 86 may rotate with the
housing 34.
[0033] Each steering pad 30 may be activated by differential
pressure, such as between the inside and outside of the housing 34.
When a steering pad 30 is activated, it pivots and/or otherwise
moves away from the RSS 28, ultimately pushing against the sidewall
of the wellbore 26, thus deflecting the corresponding RSS 28 in the
opposite direction, and thereby providing the RSS 28 with steering
capability. As the housing 34 rotates, the valve 66 selectively
operates to cause the extension and retraction of the corresponding
steering pads 30 by alternatingly permitting and restricting the
flow of drilling fluid 50 through the corresponding hydraulic line
68 to the corresponding piston 64 behind the steering pad 30. The
steering pads 30 may thus rotate substantially simultaneously with
the rotation/speed of the bit 36. However, in other implementations
within the scope of the present disclosure, substantially
non-rotating pads may also or instead be utilized.
[0034] FIG. 3 is an exploded view of an example implementation of
at least a portion of the valve 66, depicting the valve 66 as being
disengaged from the openings 92 leading to the hydraulic lines 68.
Referring to FIGS. 1-3, collectively, the valve 66 comprises a
valve opening 90 that is rotated via the shaft 70 in response to
operation of the motor 72. The valve opening 90 may be selectively
aligned with selected ports 92 that are part of and/or rotate with
the housing 34. The ports 92 deliver drilling fluid 50 into
hydraulic lines 68 for subsequent communication to the
corresponding steering pads 30. In the example implementation
depicted in FIGS. 1-3, the housing 34 comprises three ports 92
connected to three steering pads 30 via three hydraulic lines 68.
However, other implementations within the scope of the present
disclosure may include ports 92, steering pads 30, and/or hydraulic
lines 68 in other numbers.
[0035] The valve opening 90 may be selectively aligned with
individual ports 92 or combinations of adjacent ports 92. Each
valve 66 is selectively rotated via the shaft 70 and the motor 72
to bring the valve opening 90 into alignment or out of alignment
with a selected one or two ports 92.
[0036] FIG. 4 is a sectional view of the steering pads 30 carried
by the housing 34, the valve 66, and related components. To
facilitate an understanding of the angular relationship of the
valve opening 90 with respect to the ports 92, the ports 92 have
been labeled as a first port 92(1), a second port 92(2), and a
third port 92(3), corresponding with a first steering pad 30(1), a
second steering pad 30(2), and a third steering pad 30(3). The
ports 92(1-3) and steering pads 30(1-3) are illustrated as
positioned substantially at 0.degree., 120.degree., and
240.degree., respectively, around the housing 34. If the valve 66
and the housing 34 are both positioned at 0.degree., then the first
port 92(1) is activated by the pressure of drilling fluid 50, but
the second port 92(2) and third port 92(3) are not activated. If
the angle of the housing 34 is substantially 0.degree. while the
angle of the valve 66 is substantially 60.degree., then the first
port 92(1) and second port 92(2) are both activated.
[0037] The size of the valve opening 90 and each of the ports
92(1-3) may vary according to a variety of design parameters. For
example, the valve opening 90 may have an angular width of about
90.degree. and each of the ports 92(1-3) may have an angular width
of about 80.degree.. However, the angular widths and/or other
dimensions of the valve opening 90 and the ports 92(1-3) may vary
within the scope of the present disclosure. The number of openings
90, ports 92, and hydraulic lines 68 may also vary within the scope
of the present disclosure, such as in accord with the number of
steering pads 30 of the RSS 28 (which may also vary within the
scope of the present disclosure).
[0038] Referring to FIGS. 1-4, collectively, and as described
above, the valve system 32 may be operated to sequentially actuate
the steering pads 30 of the RSS 28 to urge the RSS 28 and, hence,
the drill bit 36 away from a longitudinal axis 60 of the wellbore
26. Thus, after creating a substantially straight section 53 of the
wellbore 26, the steering pads 30 of the RSS 28 may be operated to
create a curved section 29 of the wellbore 26.
[0039] That is, a first steering pad 30 of the RSS 28 may be
actuated to pivot about a pivot axis, such as may be defined by
pivot pins 47, or otherwise extend away from the housing 34 of the
RSS 28 and, thus, push against an azimuthal location 49 of the
sidewall of the wellbore 26, thereby urging the RSS 28 in the
opposite azimuthal direction (toward the right-hand side of the
page in FIG. 1). The pivot pins 47 and/or the pivot axis may extend
substantially parallel to the longitudinal axis 60 of the housing
34. At substantially the same time, the other steering pads are not
actuated, but instead remain substantially retracted against the
housing 34, thereby permitting the RSS 28 to be urged away from the
longitudinal axis 60 of the wellbore 26. As the RSS 28 continues to
rotate in the wellbore 26 (in response to rotation of the BHA 22
and drill string 24), the first actuated steering pad 30 rotates
away from the azimuthal location 49 and retracts back toward the
housing 34. Consequently, a second steering pad 30 is actuated to
extend away from the housing 34 and, thus, push against the
azimuthal location 49 of the sidewall of the wellbore 26, thereby
continuing to urge the RSS 28 in the opposite azimuthal direction
(toward the right-hand side of the page in FIG. 1). At
substantially the same time, the other steering pads are not
actuated, but instead remain substantially retracted against the
housing 34, thereby permitting the RSS 28 to continue to be urged
away from the longitudinal axis 60 of the wellbore 26. This process
is repeated, with the steering pads 30 being sequentially actuated
to push against the azimuthal location 49 of the sidewall of the
wellbore 26 until the goal inclination 27 is achieved.
[0040] Thereafter, each of the steering pads 30 may be retracted to
drill another, perhaps substantially straight section 51 of the
wellbore 26. However, other control schemes by which the steering
pads 30 may be controlled to achieve the substantially straight
section 51 are also within the scope of the present disclosure,
including implementations in which the steering pads 30 are
intermittently actuated to account for minor fluctuations in
direction, as well as implementations in which the steering pads 30
are actuated to maintain the wellbore 26 on a trajectory that is
dependent upon a boundary and/or other feature of the subterranean
formation 38 and/or reservoir 40 (e.g., geosteering).
[0041] FIG. 4 also depicts optional locking mechanisms 67 that may
each be operable to lock and/or otherwise maintain a corresponding
steering pad 30 in the extended position. For example, each locking
mechanism 67 may comprise a locking member 69 movable between a
locking position, as shown in FIG. 4 with respect to the extended
steering pad 30(1), and a retracted position, as shown with respect
to the non-extended steering pads 30(2) and 30(3). Each locking
mechanism 67 may also comprise one or more solenoids, transducers,
and/or other actuators 71 operable to move the corresponding
locking member 69 between the locking and retracted positions. Each
locking mechanism 67 may be secured within a corresponding recess
73 of the housing 34, whether via threaded engagement, adhesive,
press/interference fit, and/or other means. Furthermore, means for
locking the steering pads 30 in positions extended away from the
housing 34 other than the example locking mechanisms 67 depicted in
FIG. 4 are also within the scope of the present disclosure. Such
implementations may comprise one or more ramps and/or other
features that may be temporarily inserted between the steering pads
30 and the housing 34 to temporarily prevent radially-inward motion
of the steering pads 30, and/or one or more features that may be
temporarily positioned underneath the piston 64 to temporarily
prevent radially-inward motion of the piston 64, among other
examples.
[0042] FIG. 5 is a side view of the steering pad 30 shown in FIG.
2. The steering pad 30 shown in FIGS. 2 and 5 (and others)
comprises a plurality of cutting elements 31 that, when considered
collectively, constructively form a back-reaming bit. Each steering
pad 30 of the RSS 28 may carry one or more of the cutting elements
31. In implementations in which more than one of the steering pads
30 each carries more than one of the cutting elements 31, the
effective back-reaming bit may be formed by each of the cutting
elements 31 carried by each of the steering pads 30,
collectively.
[0043] Referring to FIGS. 2 and 5, collectively, each cutting
element 31 may be mounted in a corresponding pocket, groove, and/or
other recess 33 formed in the corresponding steering pad 30,
although other means for assembling the cutting elements 31 to the
steering pads 30 are also within the scope of the present
disclosure. The recesses 33 may fix the cutting elements 31 in a
particular location and orientation. However, one or more of the
cutting elements 31 may instead be movable within a recess 33, such
as in implementations in which the recess 33 may comprise a bearing
and/or other similar element (not shown), such that the cutting
element 31 may be coupled to or within the bearing element in a
manner permitting the cutting element 31 to rotate relative to the
steering pad 30.
[0044] The cutting elements 31 may be arranged, for example, in a
regular or irregular grid pattern along or proximate an uphole end
or portion 39 of a corresponding one of the steering pads 30.
However, other arrangements are also within the scope of the
present disclosure. Arranging the cutting elements 31 proximate the
uphole end 39 of the corresponding steering pad 30 may reduce or
prevent contact between the cutting elements 31 and the sidewall of
the wellbore when the steering pad 30 is actuated for steering
during directional drilling.
[0045] For example, referring to FIGS. 1-5, collectively, the
back-reaming bit formed by the cutting elements 31 may be operable
for back-reaming the wellbore 26 by simultaneously extending each
of the steering pads 30 away from the housing 34 such that the
cutting elements 31 contact the sidewall of the wellbore 26 while
the RSS 28 is rotated and the drill string 24 is retracted from the
wellbore 26. For example, in implementations in which the valve 66
is a rotary valve, the valve 66 may be disengaged by axial motion
away from the openings of the hydraulic lines 68 leading to the
steering pads 130 (such as in the disengaged arrangement shown in
FIG. 3), and/or otherwise allowing drilling or other working fluid
to simultaneously actuate each steering pad 30 substantially
simultaneously. For example, one or more solenoids and/or other
linear actuators of the RSS 28 may be operable for such
disengagement of the valve 66. Similarly, in implementations in
which the valve 66 is instead a digital valve, it may be digitally
operated to simultaneously actuate each steering pad 30.
[0046] Moreover, by consolidating the cutting elements 31 in or
near the uphole ends or portions 39 of the steering pads 30,
inadvertent contact between the cutting elements 31 and the
sidewall of the wellbore 26 may be reduced or even eliminated
during directional drilling. That is, during directional drilling,
the steering pads 30 may not be simultaneously deployed, but are
instead sequentially deployed in a manner causing bending of the
RSS 28 relative to the wellbore 26. Such bending of the RSS 28
relative to the wellbore 26 induces contact between the downhole
ends or portions 41 of the steering pads 30, but not the uphole
ends or portions 39 of the steering pads 30, such that excessive
material is not inadvertently removed from the sidewall of the
wellbore 26 during the directional drilling.
[0047] The cutting elements 31 may each comprise a material having
sufficient hardness to cut through the desired formation, cement,
scale, and/or other material. For example, the cutting elements 31
may include a substantially cylindrical substrate 43 comprising
tungsten carbide and/or other materials, and a cutting layer 45
comprising polycrystalline diamond, polycrystalline cubic boron
nitride, other materials, or some combination of the foregoing. The
cutting elements 31 may have a diameter ranging between about five
millimeters and about 25 millimeters. However, other dimensions are
also within the scope of the present disclosure. The cutting
elements 31 may have the same or different dimensions relative to
each other, including dimensions which may correspond to
industry-standard sizes and/or otherwise.
[0048] FIG. 6 is a schematic view of the back-reaming bit as it
would appear with the cutting elements 31 rotated into an
aggregated profile view, depicting the positions of each cutting
element 31 from each steering pad 30 as if each steering pad 30 was
positioned at the same azimuth at the same time. Such view also
depicts a cutting profile 45 (depicted in FIG. 6 by a heavy dark
line) collectively formed by outermost edges of each cutting
element 31. As described above, the cutting elements 31 may be
located at or near the uphole end or portion 39 of the steering
pads 30 and not at or near the downhole end or portion 41 of the
steering pads 30. Consequently, when bending of the RSS 28 relative
to the wellbore 26 during directional drilling induces contact
between the downhole ends or portions 41 of the steering pads 30,
but not the uphole ends or portions 39 of the steering pads 30,
excessive material is not inadvertently removed from the sidewall
of the wellbore 26.
[0049] For example, the uphole end or portion 39 of each steering
pad 30 that comprises the cutting elements 31 may be the upper
third (33%) of the axial length 65 of the steering pad 30, such
that the lower two-thirds (67%) of each steering pad 30 does not
comprise cutting elements 31. However, other dimensional ranges are
also within the scope of the present disclosure.
[0050] The uphole end or portion 39 of each steering pad 30 that
comprises the cutting elements 31 may also be limited to an upper,
non-linear portion thereof. For example, as depicted in the example
implementation shown in FIG. 6, the uphole end of portion 39 of
each steering pad 30 may be curved, arcuate, slanted, tilted,
beveled, and/or otherwise non-linear relative to a middle portion
61 of the steering pad 30. As also shown in FIG. 6, the downhole
end or portion 41 of each steering pad 30 may also be curved,
arcuate, slanted, tilted, beveled, and/or otherwise non-linear
relative to the middle portion 61 of the steering pad 30.
[0051] The uphole end or portion 39 of each steering pad 30 that
comprises the cutting elements 31 may also be that portion of the
steering pad 30 that falls within a maximum radius 63 of the
steering pad 30 when actuated. For example, the middle portion 61
of the steering pad 30 may have the greatest radius 63 (with
respect to other features of the steering pad 30) relative to the
longitudinal axis 60 of the RSS 28, and the cutting elements 31 may
not extend beyond that radius 63. That is, the cutting elements 31
may be flush with or recessed below a gauge surface 57 of the
steering pad 30. In other implementations, however, the cutting
elements 31 may extend slightly beyond the radius of the middle
portion 61, such as to provide clearance for the middle portion 61
during back-reaming, and/or to account for wear of the cutting
elements 31 after prolonged use. For example, the outermost edges
of the cutting elements 31 may extend beyond the radius 63 of the
middle portion 61 by less than about five millimeters.
[0052] Although not shown in the figures, the RSS 28 may comprise
mechanical stops and/or other means limiting the maximum extent to
which each steering pad 30 may be extended away from the housing
34. Such means may be adjustable and/or otherwise designed to match
the effective back-reaming diameter of the back-reaming bit
constructively formed by the collective cutting elements 31 with
the reaming diameter of another reaming component of the BHA 22,
such as the concentric under-reamer 15 shown in FIG. 1.
[0053] FIG. 7 is a simplified view of the RSS 28 shown in FIGS.
1-6, in which the valve system 32 and hydraulic lines 68 are
simplified for clarity of the following description. As described
above, the RSS 28 is at least indirectly coupled between the drill
bit 36 and an MWD or LWD component 44 and/or other component 42 of
the BHA 22, and comprises at least three steering pads 30 operable
to sequentially actuate to "steer" the drill bit 36 during
directional drilling. In the example implementation depicted in
FIG. 7, the RSS 28 comprises four circumferentially spaced steering
pads 30, comprising two sets each of two diametrically opposed
steering pads 30 (although one set is hidden from view in FIG. 7).
However, other implementations within the scope of the present
disclosure may not comprise diametrically opposed steering pads 30,
and may comprise more or less than four steering pads 30.
[0054] The example RSS 28 depicted in FIG. 7 also comprises a
controller 130 operable to control the valve system 32 and/or other
components of the RSS 28 and/or BHA 22. The controller 130 may
comprise one or more instances of the control devices 75 and/or
controllers 76 shown in FIG. 2. The controller 130 may be a single,
discrete controller operable to control the valve system 32, such
as via control/data lines 132 that may extend between the
controller 130 and the valve system 32. Other implementations
within the scope of the present disclosure, however, may utilize
multiple controllers 130 each operable to control the valve system
32 and/or other components of the RSS 28 and/or BHA 22. Where
multiple controllers are utilized, two or more (or each) of the
controllers may be operably connected to a common communication
bus. The common or "main" controller may be located somewhere else
in the BHA 22, such as in an MWD, LWD, and/or other component 42/44
of the BHA 22. One or more of the controllers may also be operable
to communicate with other tools of the BHA 22, such as the
formation testing tools of MWD and/or LWD modules 44, via a common
communication bus. For example, for closed-loop geosteering, the
steering pad controller 130 may be operable in conjunction with
formation data obtained by an LWD and/or MWD module 44 of the BHA
22, such as to reference a boundary and/or other feature of the
formation 38 and/or reservoir 40 (FIG. 1) that may be utilized to
guide steering and, thus, the trajectory of the wellbore 26. Thus,
among other possible implementations, the LWD and/or MWD module 44
may be utilized to obtain formation/reservoir image and/or other
data that may then be utilized with the steering pad controller 130
to maintain the drilling path within a subterranean pay-zone of the
formation 38 and/or reservoir 40 while elongating the wellbore
26.
[0055] The steering pad controller and/or other downhole
controllers 130 of the RSS 28 and/or other portions of the BHA 22
may also communicate with surface equipment (e.g., the surface
control system 58 in FIG. 1) in substantially real-time manner. For
example, such communication may be via wired drill pipe,
electromagnetic (EM) telemetry, and/or others. However, mud pulse
telemetry is also contemplated.
[0056] FIG. 8 is a schematic exterior view of the apparatus shown
in FIG. 7 after the controller 130 has operably controlled the
valve system 32 to actuate the steering pads 30 of the RSS 28 to
operatively urge at least one of the cutting elements 31 on at
least one of the steering pads 30 into contact with the sidewall of
the wellbore 26, while the drill string 24, BHA 22, RSS 28 and
drill bit 36 continue to rotate. For example, such actuation of the
steering pads 30 may include actuating each of the steering pads 30
simultaneously such that at least one of the cutting elements 31 on
each of the steering pads 30 contacts the sidewall of the wellbore
26.
[0057] Thereafter, the drill string 24 may be retracted from the
wellbore 26 while the drill string 24, BHA 22, RSS 28 and drill bit
36 continue to rotate, as shown in FIG. 9. During such rotating
retraction, the controller 130 may operably control the valve
system 32 to actuate the steering pads 30 to operatively maintain
at least one of the cutting elements 31 on at least one of the
steering pads 30 in contact with the sidewall of the wellbore 26.
For example, such actuation of the steering pads 30 may include
actuating each of the steering pads 30 simultaneously such that at
least one of the cutting elements 31 on each of the steering pads
30 contacts the sidewall of the wellbore 26. Consequently, the
cutting elements 31 contacting the sidewall of the wellbore 26 may
be utilized for a back-reaming operation, whereby undulations,
bumps, ridges, protrusions, and/or other irregularities of the
surface of the wellbore 26 may be reduced, smoothed, and/or
partially or substantially removed. Consequently, the length of the
remaining rathole section 55 of the wellbore 26 may be
substantially limited to axial separation between the end of the
drill bit 36 and the cutting elements 31. For example, the rathole
section 55 of the wellbore 26 may range between about one meter and
about five meters, although other values are also within the scope
of the present disclosure.
[0058] The dimensions of various features described above may vary
across the myriad implementations within the scope of the present
disclosure. One such dimension regards the outer diameter of the
effective back-reaming bit constructively formed by the cutting
elements 31 collectively carried by one or more of the steering
pads 30 relative to the outer diameter of the BHA 22, the RSS 28,
and/or the drill bit 36. For example, if the outer diameter of the
BHA 22, the RSS 28, and/or the drill bit 36 is about 8.3 inches (or
about 21.1 centimeters), then the outer diameter of the
back-reaming bit may be about 9.3 inches (or about 23.6
centimeters). If the outer diameter of the BHA 22, the RSS 28,
and/or the drill bit 36 is about 6.8 inches (or about 17.3
centimeters), then the outer diameter of the back-reaming bit may
be about 7.7 inches (or about 19.6 centimeters). If the outer
diameter of the BHA 22, the RSS 28, and/or the drill bit 36 is
about 4.8 inches (or about 12.2 centimeters), then the outer
diameter of the back-reaming bit may be about 5.6 inches (or about
14.2 centimeters). The outer diameter of the back-reaming bit may
be greater than the outer diameter of the BHA 22, the RSS 28,
and/or the drill bit 36 by an amount ranging between about 0.5
inches (or about 1.3 centimeters) and about 1.5 inches (or about
3.8 centimeters). Of course, the dimensions described above are
examples, and other dimensions are also within the scope of the
present disclosure.
[0059] FIG. 10 is a flow-chart diagram of at least a portion of a
method (800) according to one or more aspects of the present
disclosure. The method (800) may be executed utilizing at least a
portion of the apparatus shown in one or more of FIGS. 1-9, among
other apparatus within the scope of the present disclosure. For
example, the method (800) may comprise conveying such apparatus
within a wellbore that extends from a wellsite surface to a
subterranean formation, wherein the wellbore may be substantially
similar to the wellbore 26 shown in one or more of FIGS. 1, 7, 8,
and 9. Such apparatus may comprise or be utilized in conjunction
with a drill string, a drill bit, and an RSS collectively coupled
in series between the drill string and the drill bit, such as the
drill string 24, the drill bit 36, and the RSS 28 shown in one or
more of FIGS. 1-9. The method (800) may comprise coupling (810) the
RSS, and perhaps other portions of a BHA (such as the BHA 22 shown
in one or more of FIGS. 1-9), between the drill string and the
drill bit.
[0060] As described above, the RSS may comprise at least three
steering pads spaced circumferentially apart around a perimeter of
the RSS, a valve operable to sequentially actuate the steering
pads, a controller operable to control the valve, and a plurality
of cutting elements carried by one or more of the steering pads.
The steering pads may be substantially similar to those shown in
one or more of FIGS. 1, 2, and 4-8. The rotational valve may be
substantially similar to at least a portion of the valve systems 32
shown in one or more of FIGS. 1-9. The controller may be
substantially similar to the surface control system 58 shown in
FIG. 1, the controller 75 and/or the processor 76 shown in FIG. 2,
and/or the controller 130 shown in FIG. 7. The cutting elements may
be substantially similar to those shown in one or more of FIGS. 2
and 5-9.
[0061] The method (800) comprises operating (820) the drill string,
the RSS, and the drill bit to create a first wellbore section
having a first trajectory. For example, such operation (820) may
comprise rotating the drill string, and thereby rotating the RSS
and the drill bit, while operating at least one of the valve and
the controller to sequentially and/or otherwise actuate the
steering pads to operatively urge the RSS and drill bit relative to
a longitudinal axis of the wellbore to achieve the intended
trajectory of the first wellbore section. The first wellbore
section may be substantially similar to the wellbore section 53 or
the wellbore section 29 shown in FIG. 1.
[0062] The method (800) also comprises operating (830) the drill
string, the RSS, and the drill bit to create a second wellbore
section having a second trajectory. For example, such operation
(830) may comprise rotating the drill string, and thereby rotating
the RSS and the drill bit, while operating at least one of the
valve and the controller to sequentially and/or otherwise actuate
the steering pads to operatively urge the RSS and drill bit
relative to a longitudinal axis of the wellbore to achieve the
intended trajectory of the second wellbore section. The second
wellbore section may be substantially similar to the wellbore
section 29 or the wellbore section 51 shown in FIG. 1. For example,
if the first operation (820) resulted in the substantially straight
wellbore section 53 shown in FIG. 1, then the second operation
(830) may result in the curved wellbore section 29 shown in FIG. 1.
Similarly, if the first operation (820) resulted in the curved
wellbore section 29 shown in FIG. 1, then the second operation
(830) may result in the substantially straight wellbore section 51
shown in FIG. 1. However, as described above, either or both of the
first and second wellbore sections may have trajectories other than
as shown in FIG. 1, including trajectories following, paralleling,
and/or otherwise corresponding to a boundary and/or other feature
of a subterranean formation or reservoir (e.g., geosteering), among
other examples within the scope of the present disclosure.
[0063] Rotating the drill string while operating at least one of
the valve and the controller to sequentially actuate the steering
pads to operatively urge the RSS and the drill bit relative to the
longitudinal axis of the wellbore may comprise rotating the drill
string while operating at least one of the valve and the controller
to sequentially actuate the steering pads to operatively urge the
RSS and the drill bit in a first azimuthal direction away from the
longitudinal axis of the wellbore. In such implementations, among
others, the method (800) may also comprise rotating the drill
string while operating at least one of the valve and the controller
to sequentially actuate the steering pads to operatively urge the
RSS and the drill bit in a second azimuthal direction away from the
longitudinal axis of the wellbore. For example, the first and
second azimuthal directions may differ by at least about twenty
degrees. The first and second azimuthal directions may be
substantially opposite each other, such as in implementations in
which the first and second azimuthal directions differ by an amount
ranging between about 170 degrees and about 190 degrees.
[0064] The method (800) also comprises operating (840) the drill
string and the RSS to back-ream the second wellbore section. For
example, such operation (840) may comprise rotating the drill
string, and thereby rotating the RSS and the drill bit, while
operating at least one of the valve and the controller to
simultaneously actuate each of the steering pads to operatively
urge at least one of the cutting elements on at least one of the
steering pads into contact with the sidewall of the wellbore. The
operation (840) may comprise operating at least one of the valve
and the controller to simultaneously actuate each of the steering
pads to operatively urge at least one of the cutting elements on
each of the steering pads into substantially simultaneous contact
with the sidewall of the wellbore. The operation (840) may also
comprise locking one or more of the steering pads in the extended
position, such as via operation of the locking mechanisms 67 shown
in FIG. 4 and/or other locking means, and may also comprise
immediately or otherwise thereafter unlocking the steering pads to
permit the steering pads to again retract towards the RSS housing.
The resulting, back-reamed wellbore may resemble that shown in FIG.
9, in which the rathole section of the wellbore is limited to the
distance by which the drill bit and the cutting elements are
axially separated.
[0065] The method (800) also comprises operating (850) the drill
string and the RSS to back-ream the first wellbore section. For
example, such operation (850) may comprise rotating the drill
string, and thereby rotating the RSS and the drill bit, while
operating at least one of the valve and the controller to
simultaneously actuate each of the steering pads to operatively
urge at least one of the cutting elements on each of the steering
pads into contact with the sidewall of the wellbore. The operation
(850) may also comprise locking one or more of the steering pads in
the extended position, such as via operation of the locking
mechanisms 67 shown in FIG. 4 and/or other locking means, and may
also comprise immediately or otherwise thereafter unlocking the
steering pads to permit the steering pads to again retract towards
the RSS housing.
[0066] FIG. 11 is a flow-chart diagram of at least a portion of a
method (900) according to one or more aspects of the present
disclosure. The method (900) may be executed utilizing at least a
portion of the apparatus shown in one or more of FIGS. 1-9, among
other apparatus within the scope of the present disclosure. For
example, the method (900) may comprise conveying such apparatus
within a wellbore that extends from a wellsite surface to a
subterranean formation, wherein the wellbore may be substantially
similar to the wellbore 26 shown in one or more of FIGS. 1, 7, 8,
and 9. Such apparatus may comprise or be utilized in conjunction
with a drill string, a drill bit, and an RSS collectively coupled
in series between the drill string and the drill bit, such as the
drill string 24, the drill bit 36, and the RSS 28 shown in one or
more of FIGS. 1-9. The method (900) may comprise coupling (910) the
RSS, and perhaps other portions of a BHA (such as the BHA shown in
one or more of FIGS. 1-9), between the drill string and the drill
bit.
[0067] As described above, the RSS may comprise at least three
steering pads spaced circumferentially apart around a perimeter of
the RSS, a valve operable to sequentially actuate the steering
pads, a controller operable to control the valve, and a plurality
of cutting elements carried by one or more of the steering pads.
The steering pads may be substantially similar to those shown in
one or more of FIGS. 1, 2, and 4-9. The rotational valve may be
substantially similar to at least a portion of the valve systems 32
shown in one or more of FIGS. 1-9. The controller may be
substantially similar to the surface control system 58 shown in
FIG. 1, the controller 75 and/or the processor 76 shown in FIG. 2,
and/or the controller 130 shown in FIG. 7. The cutting elements may
be substantially similar to those shown in one or more of FIGS. 2
and 5-9.
[0068] The method (900) comprises operating (920) the drill string,
the RSS, and the drill bit to create a first wellbore section
having a first trajectory. For example, such operation (920) may
comprise rotating the drill string, and thereby rotating the RSS
and the drill bit, while operating at least one of the valve and
the controller to sequentially and/or otherwise actuate the
steering pads to operatively urge the RSS and drill bit relative to
a longitudinal axis of the wellbore to achieve the intended
trajectory of the first wellbore section. The first wellbore
section may be substantially similar to the wellbore section 53 or
the wellbore section 29 shown in FIG. 1.
[0069] The method (900) also comprises operating (930) the drill
string and the RSS to back-ream the first wellbore section. For
example, such operation (930) may comprise rotating the drill
string, and thereby rotating the RSS and the drill bit, while
operating at least one of the valve and the controller to
simultaneously actuate each of the steering pads to operatively
urge at least one of the cutting elements on at least one of the
steering pads into contact with the sidewall of the wellbore. The
operation (930) may comprise operating at least one of the valve
and the controller to simultaneously actuate each of the steering
pads to operatively urge at least one of the cutting elements on
each of the steering pads into substantially simultaneous contact
with the sidewall of the wellbore. The operation (930) may also
comprise locking one or more of the steering pads in the extended
position, such as via operation of the locking mechanisms 67 shown
in FIG. 4 and/or other locking means, and may also comprise
immediately or otherwise thereafter unlocking the steering pads to
permit the steering pads to again retract towards the RSS
housing.
[0070] The method (900) may also comprise installing (940) a casing
in the first wellbore section after the back-reaming operation
(930). For example, the operation (920) performed to create the
first wellbore section may result in the wellbore section 53 shown
in FIG. 1, and the installed (940) casing may be substantially
similar to the casing 59 shown in FIG. 1. Installing (940) the
casing may comprise positioning casing in the back-reamed first
wellbore section, and then securing the positioned casing in place
by cement and/or coupling the casing to previously installed
casing, among other installation methods within the scope of the
present disclosure. Installing (940) the casing in the back-reamed
first wellbore section may be performed with or without removing
the drill string from the wellbore.
[0071] The method (900) also comprises operating (950) the drill
string, the RSS, and the drill bit to create a second wellbore
section having a second trajectory. For example, such operation
(950) may comprise rotating the drill string, and thereby rotating
the RSS and the drill bit, while operating at least one of the
valve and the controller to sequentially and/or otherwise actuate
the steering pads to operatively urge the RSS and drill bit
relative to a longitudinal axis of the wellbore to achieve the
intended trajectory of the second wellbore section. The second
wellbore section may be substantially similar to the wellbore
section 29 or the wellbore section 51 shown in FIG. 1. For example,
if the first operation (920) resulted in the substantially straight
wellbore section 53 shown in FIG. 1, then the second operation
(950) may result in the curved wellbore section 29 shown in FIG. 1.
Similarly, if the first operation (920) resulted in the curved
wellbore section 29 shown in FIG. 1, then the second operation
(950) may result in the substantially straight wellbore section 51
shown in FIG. 1. However, as described above, either or both of the
first and second wellbore sections may have trajectories other than
as shown in FIG. 1, including trajectories following, paralleling,
and/or otherwise corresponding to a boundary and/or other feature
of a subterranean formation or reservoir (e.g., geosteering), among
other examples within the scope of the present disclosure.
[0072] The method (900) also comprises operating (960) the drill
string and the RSS to back-ream the second wellbore section. For
example, such operation (960) may comprise rotating the drill
string, and thereby rotating the RSS and the drill bit, while
operating at least one of the valve and the controller to
simultaneously actuate each of the steering pads to operatively
urge at least one of the cutting elements on at least one of the
steering pads into contact with the sidewall of the wellbore. The
operation (960) may comprise operating at least one of the valve
and the controller to simultaneously actuate each of the steering
pads to operatively urge at least one of the cutting elements on
each of the steering pads into substantially simultaneous contact
with the sidewall of the wellbore. The operation (960) may also
comprise locking one or more of the steering pads in the extended
position, such as via operation of the locking mechanisms 67 shown
in FIG. 4 and/or other locking means, and may also comprise
immediately or otherwise thereafter unlocking the steering pads to
permit the steering pads to again retract towards the RSS housing.
The resulting, back-reamed wellbore may resemble that shown in FIG.
9, in which the rathole section of the wellbore is limited to the
distance by which the drill bit and the cutting elements are
axially separated.
[0073] The method (900) may also comprise installing (970) a casing
in the second wellbore section after the back-reaming operation
(960). Installing (970) the casing may comprise positioning casing
in the back-reamed second wellbore section, and then securing the
positioned casing in place by cement and/or coupling the casing to
previously installed (940) casing, among other installation methods
within the scope of the present disclosure. Installing (970) the
casing in the back-reamed second wellbore section may be performed
with or without removing the drill string from the wellbore.
[0074] Methods within the scope of the present disclosure may also
comprise conventional back-reaming that is performed in addition to
the back-reaming described above. For example, such conventional
back-reaming may utilize the drill bit to clean the borehole,
including implementations in which the conventional back-reaming
does not substantially enlarge the borehole diameter. Such
implementations may entail maintaining each of the steering pads
retracted against the housing of the RSS via corresponding
actuation (or lack thereof) of the digital or rotary valves.
[0075] FIG. 12 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure. The apparatus is or comprises a processing system 1300
that may execute example machine-readable instructions to implement
at least a portion of one or more of the methods and/or processes
described herein, and/or to implement a portion of one or more of
the example RSS and/or other downhole tools described herein. The
processing system 1300 may be or comprise, for example, one or more
processors, controllers, special-purpose computing devices,
servers, personal computers, personal digital assistant ("PDA")
devices, smartphones, internet appliances, and/or other types of
computing devices. Moreover, while it is possible that the entirety
of the processing system 1300 shown in FIG. 12 is implemented
within downhole apparatus, perhaps as at least a portion of the
control devices 75, controllers 76, controller 130, other downhole
apparatus shown in one or more of FIGS. 1-9, and/or other downhole
apparatus, it is also contemplated that one or more components or
functions of the processing system 1300 may be implemented in
wellsite surface equipment, perhaps including the surface control
system 58 depicted in FIG. 1 and/or other surface equipment.
[0076] The processing system 1300 may comprise a processor 1312
such as, for example, a general-purpose programmable processor. The
processor 1312 may comprise a local memory 1314, and may execute
coded instructions 1332 present in the local memory 1314 and/or
another memory device. The processor 1312 may execute, among other
things, machine-readable instructions or programs to implement the
methods and/or processes described herein. The programs stored in
the local memory 1314 may include program instructions or computer
program code that, when executed by an associated processor, enable
surface equipment and/or downhole controller and/or control system
to perform tasks as described herein. The processor 1312 may be,
comprise, or be implemented by one or a plurality of processors of
various types suitable to the local application environment, and
may include one or more of general-purpose computers,
special-purpose computers, microprocessors, digital signal
processors ("DSPs"), field-programmable gate arrays ("FPGAs"),
application-specific integrated circuits ("ASICs"), and processors
based on a multi-core processor architecture, as non-limiting
examples. Of course, other processors from other families are also
appropriate.
[0077] The processor 1312 may be in communication with a main
memory, such as may include a volatile memory 1318 and a
non-volatile memory 1320, perhaps via a bus 1322 and/or other
communication means. The volatile memory 1318 may be, comprise, or
be implemented by random access memory (RAM), static random access
memory (SRAM), synchronous dynamic random access memory (SDRAM),
dynamic random access memory (DRAM), RAMBUS dynamic random access
memory (RDRAM) and/or other types of random access memory devices.
The non-volatile memory 1320 may be, comprise, or be implemented by
read-only memory, flash memory and/or other types of memory
devices. One or more memory controllers (not shown) may control
access to the volatile memory 1318 and/or the non-volatile memory
1320.
[0078] The processing system 1300 may also comprise an interface
circuit 1324. The interface circuit 1324 may be, comprise, or be
implemented by various types of standard interfaces, such as an
Ethernet interface, a universal serial bus (USB), a third
generation input/output (3GIO) interface, a wireless interface,
and/or a cellular interface, among others. The interface circuit
1324 may also comprise a graphics driver card. The interface
circuit 1324 may also comprise a communication device such as a
modem or network interface card to facilitate exchange of data with
external computing devices via a network (e.g., Ethernet
connection, digital subscriber line ("DSL"), telephone line,
coaxial cable, cellular telephone system, satellite, etc.).
[0079] One or more input devices 1326 may be connected to the
interface circuit 1324. The input device(s) 1326 may permit a user
to enter data and commands into the processor 1312. The input
device(s) 1326 may be, comprise, or be implemented by, for example,
a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an
isopoint, and/or a voice recognition system, among others.
[0080] One or more output devices 1328 may also be connected to the
interface circuit 1324. The output devices 1328 may be, comprise,
or be implemented by, for example, display devices (e.g., a liquid
crystal display or cathode ray tube display (CRT), among others),
printers, and/or speakers, among others.
[0081] The processing system 1300 may also comprise one or more
mass storage devices 1330 for storing machine-readable instructions
and data. Examples of such mass storage devices 1330 include floppy
disk drives, hard drive disks, compact disk (CD) drives, and
digital versatile disk (DVD) drives, among others. The coded
instructions 1332 may be stored in the mass storage device 1330,
the volatile memory 1318, the non-volatile memory 1320, the local
memory 1314, and/or on a removable storage medium 1334, such as a
CD or DVD. Thus, the modules and/or other components of the
processing system 1300 may be implemented in accordance with
hardware (embodied in one or more chips including an integrated
circuit such as an application specific integrated circuit), or may
be implemented as software or firmware for execution by a
processor. In particular, in the case of firmware or software, the
embodiment can be provided as a computer program product including
a computer readable medium or storage structure embodying computer
program code (i.e., software or firmware) thereon for execution by
the processor.
[0082] In view of the entirety of the present disclosure, including
the figures and the claims that follow, a person having ordinary
skill in the art will readily recognize that the present disclosure
introduces a system for drilling a wellbore, wherein the system
comprises: a rotary steerable system (RSS) at least indirectly
coupled between a drill string collar and a drill bit, wherein the
RSS comprises: a housing; a plurality of steering pads
circumferentially spaced around the housing, wherein each of the
plurality of steering pads is actuatable to radially extend away
from the housing independent of the other ones of the plurality of
steering pads, and wherein at least one of the plurality of
steering pads comprises a back-reaming bit; a valve; and a
controller, wherein the valve and the controller are collectively
operable to: sequentially actuate ones of the plurality of steering
pads to substantially decentralize the RSS relative to the
wellbore; and simultaneously actuate each of the plurality of
steering pads to substantially centralize the RSS relative to the
wellbore, thus urging the back-reaming bit into contact with a
sidewall of the wellbore.
[0083] Each of the plurality of steering pads may be actuatable to
radially extend away from the housing by rotating about an axis
that is substantially parallel to a longitudinal axis of the
housing.
[0084] The valve may be a digital valve.
[0085] The valve may be a rotational valve. The valve and the
controller may be collectively operable to simultaneously actuate
each of the plurality of steering pads by disengaging the
valve.
[0086] The back-reaming bit may comprise a plurality of cutting
elements. Each of the plurality of cutting elements may comprise: a
substrate coupled to the corresponding steering pad; and a cutting
layer coupled to the substrate. The substrate may substantially
comprise tungsten carbide. The cutting layer may substantially
comprise polycrystalline diamond. Each of the plurality of steering
pads may comprise at least one of the plurality of cutting
elements. Simultaneously actuating each of the plurality of
steering pads to substantially centralize the RSS relative to the
wellbore may urge at least one of the plurality of cutting elements
on each of the plurality of steering pads into contact with the
sidewall of the wellbore.
[0087] Each of the plurality of steering pads may be actuatable to
radially extend away from a retracted position toward an extended
position. Each of the plurality of steering pads may be lockable in
the extended position.
[0088] The cutting elements may be disposed in an uphole portion of
each of the plurality of steering pads and not in a downhole
portion of each of the plurality of steering pads.
[0089] The present disclosure also introduces an apparatus
comprising: a drill string disposed within a wellbore that extends
from a wellsite surface to a subterranean formation; a drill bit;
and a rotary steerable system (RSS) coupled between the drill
string and the drill bit, wherein the RSS comprises: a plurality of
steering pads spaced circumferentially apart around a perimeter of
the RSS; a valve operable to sequentially actuate the plurality of
steering pads; and a back-reaming bit comprising a plurality of
cutting elements, wherein each of the plurality of steering pads
comprises at least one of the plurality of cutting elements.
[0090] Each of the plurality of cutting elements may comprise: a
substrate coupled to a corresponding one of the plurality of
steering pads; and a cutting layer coupled to the substrate. The
substrate may substantially comprise tungsten carbide. The cutting
layer may substantially comprise polycrystalline diamond.
[0091] The apparatus may further comprise a controller, wherein the
valve and the controller may be collectively operable to
sequentially actuate the plurality of steering pads to operatively
urge the RSS away from a longitudinal axis of the wellbore. The
valve and the controller may be collectively further operable to
simultaneously actuate each of the plurality of steering pads to
operatively urge at least one of the plurality of cutting elements
on each of the plurality of steering pads into contact with a
sidewall of the wellbore.
[0092] The apparatus may not comprise a reaming tool, component, or
feature disposed between the drill string and the RSS.
[0093] The apparatus may not comprise a reaming tool, component, or
feature disposed between the drill string and the drill bit, other
than the back-reaming bit formed by the plurality of cutting
elements comprised by corresponding ones of the plurality of
steering pads.
[0094] The present disclosure also introduces a method comprising:
conveying apparatus within a wellbore that extends from a wellsite
surface to a subterranean formation, wherein the apparatus
comprises a drill string, a drill bit, and at a rotary steerable
system (RSS) coupled between the drill string and the drill bit,
and wherein the RSS comprises: a plurality of steering pads spaced
circumferentially apart around a perimeter of the RSS, wherein each
of the plurality of steering pads carries at least one of a
plurality of cutting elements; a valve operable for sequentially
actuating the steering pads; and a controller; rotating the drill
string, thereby rotating the RSS and the drill bit, while operating
at least one of the valve and the controller to sequentially
actuate the plurality of steering pads to operatively urge the RSS
and the drill bit away from a longitudinal axis of the wellbore;
and rotating the drill string, thereby rotating the RSS and the
drill bit, while operating at least one of the valve and the
controller to simultaneously actuate each of the plurality of
steering pads to operatively urge at least one of the plurality of
the cutting elements on each of the plurality of steering pads into
contact with a sidewall of the wellbore.
[0095] The method may further comprise, prior to conveying at least
a portion of the apparatus within the wellbore, coupling the RSS
between the drill string and the drill bit.
[0096] Rotating the drill string while operating at least one of
the valve and the controller to sequentially actuate the plurality
of steering pads to operatively urge the RSS and the drill bit away
from a longitudinal axis of the wellbore may comprise rotating the
drill string while operating at least one of the valve and the
controller to sequentially actuate the plurality of steering pads
to operatively urge the RSS and the drill bit in a first azimuthal
direction away from the longitudinal axis of the wellbore. In such
implementations, the method may further comprise: rotating the
drill string while operating at least one of the valve and the
controller to sequentially actuate the plurality of steering pads
to operatively urge the RSS and the drill bit in a second azimuthal
direction away from the longitudinal axis of the wellbore. The
first and second azimuthal directions may differ by at least about
twenty degrees. The first and second azimuthal directions may be
substantially opposite each other. The first and second azimuthal
directions may differ by an amount ranging between about 170
degrees and about 190 degrees. Rotating the drill string while
operating at least one of the valve and the controller to
sequentially actuate the plurality of steering pads to operatively
urge the RSS and the drill bit in the first azimuthal direction
away from the longitudinal axis of the wellbore may create a first
wellbore section extending in a first wellbore direction. Rotating
the drill string while operating at least one of the valve and the
controller to sequentially actuate the plurality of steering pads
to operatively urge the RSS and the drill bit in the second
azimuthal direction away from the longitudinal axis of the wellbore
may create a second wellbore section extending in a second wellbore
direction. Rotating the drill string while operating at least one
of the valve and the controller to simultaneously actuate each of
the plurality of steering pads to operatively urge at least one of
the plurality of the cutting elements on each of the plurality of
steering pads into contact with the sidewall of the wellbore may
include back-reaming the first and second wellbore sections. The
second wellbore section may be created after the first wellbore
section is created. The second wellbore section may be back-reamed
before the first wellbore section is back-reamed.
[0097] The foregoing outlines features of several embodiments so
that a person having ordinary skill in the art may better
understand the aspects of the present disclosure. A person having
ordinary skill in the art should appreciate that they may readily
use the present disclosure as a basis for designing or modifying
other processes and structures for carrying out the same goals
and/or achieving the same aspects of the implementations introduced
herein. A person having ordinary skill in the art should also
realize that such equivalent constructions do not depart from the
scope of the present disclosure, and that they may make various
changes, substitutions and alterations herein without departing
from the spirit and scope of the present disclosure.
[0098] The Abstract at the end of this disclosure is provided to
comply with 37 C.F.R. .sctn.1.72(b) to allow the reader to quickly
ascertain the nature of the technical disclosure. It is submitted
with the understanding that it will not be used to interpret or
limit the scope or meaning of the claims.
* * * * *