U.S. patent application number 13/792532 was filed with the patent office on 2014-09-11 for rotating drilling stabilizer.
This patent application is currently assigned to BP Corporation North America Inc.. The applicant listed for this patent is James McKay. Invention is credited to James McKay.
Application Number | 20140251692 13/792532 |
Document ID | / |
Family ID | 51486443 |
Filed Date | 2014-09-11 |
United States Patent
Application |
20140251692 |
Kind Code |
A1 |
McKay; James |
September 11, 2014 |
ROTATING DRILLING STABILIZER
Abstract
A stabilizer and method for use in a wellbore are disclosed. The
apparatus can include a rotary body disposed about a tubular and
configured to rotate and axially-translate with respect to the
tubular. The apparatus can also include a first anti-rotation
device disposed axially adjacent the rotary body and configured to
resist rotation and axial translation with respect to the tubular.
The rotary body can be configured to engage the first anti-rotation
device and rotationally lock therewith. The apparatus can also
include a biasing member configured to bias apart the rotary body
and the first anti-rotation device.
Inventors: |
McKay; James; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
McKay; James |
Houston |
TX |
US |
|
|
Assignee: |
BP Corporation North America
Inc.
Houston
TX
|
Family ID: |
51486443 |
Appl. No.: |
13/792532 |
Filed: |
March 11, 2013 |
Current U.S.
Class: |
175/57 ; 175/315;
175/325.3; 175/325.5 |
Current CPC
Class: |
E21B 17/1078
20130101 |
Class at
Publication: |
175/57 ;
175/325.3; 175/325.5; 175/315 |
International
Class: |
E21B 17/10 20060101
E21B017/10; E21B 7/28 20060101 E21B007/28; E21B 10/26 20060101
E21B010/26 |
Claims
1. A stabilizer apparatus for use in a wellbore, comprising: a
rotary body disposed about a tubular; a first anti-rotation device
disposed axially adjacent the rotary body and configured to resist
rotation and axial translation with respect to the tubular, wherein
the rotary body is configured to slide axially to engage the first
anti-rotation device and rotationally lock therewith; and a biasing
member configured to bias apart the rotary body and the first
anti-rotation device.
2. The apparatus of claim 1, further comprising a first stationary
body comprising the first anti-rotation device, the first
stationary body being positionally fixed to the tubular.
3. The apparatus of claim 2, wherein the first stationary body
provides an axial stop for the rotary body.
4. The apparatus of claim 2, wherein the biasing member extends
between the first stationary body and the rotary body.
5. The apparatus of claim 2, wherein the first stationary body
comprises a stop collar fixed to the tubular, a portion integrally
formed with the tubular, or both.
6. The apparatus of claim 1, wherein the rotary body further
comprises an axial face defining a cutting surface, the cutting
surface being configured to remove a partial obstruction of the
wellbore when the rotary body engages the first anti-rotation
device.
7. The apparatus of claim 1, further comprising a second
anti-rotation device disposed axially adjacent the rotary body such
that the rotary body is positioned axially intermediate the first
and second anti-rotation devices, wherein the rotary body is
configured to axially translate to engage the second anti-rotation
device and rotationally lock therewith.
8. The apparatus of claim 7, further comprising a second stationary
body comprising the second anti-rotation device, the second
stationary body being positionally fixed with respect to the
tubular.
9. The apparatus of claim 8, wherein the biasing member extends
between the second stationary body and the rotary body.
10. The apparatus of claim 8, further comprising a second biasing
member configured to bias apart the second anti-rotation device and
the rotary body.
11. The apparatus of claim 1, further comprising a secondary
anti-rotation device coupled to the tubular and configured to
expand and engage the rotary body such that the rotary body resists
axial translation and rotation with respect to the tubular.
12. The apparatus of claim 11, wherein the secondary anti-rotation
device comprises: an inner profile extending into the tubular and
configured to receive a shifting device; and a gripping member
coupled to the inner profile and configured to expand radially
outwards to engage the rotary body, wherein the inner profile is
configured to shift by receiving the shifting device and expand the
gripping member.
13. The apparatus of claim 11, wherein the secondary anti-rotation
device comprises: an actuator configured to receive signals from a
controller; and a gripping member coupled to the tubular, wherein
the actuator is configured to cause the gripping member to engage
the rotary body when the controller signals the actuator to
actuate.
14. The apparatus of claim 13, wherein the actuator hydraulically
expands the gripping member.
15. A method of stabilizing a drill string, comprising: biasing the
rotary body disposed on a tubular axially apart from a first
stationary body disposed axially adjacent the rotary body; radially
engaging a wellbore wall with an outer diameter of the rotary body
so as to centralize the drill string; sliding the rotary body
toward the first stationary body in response to an axial force; and
rotationally locking the rotary body and the first stationary
body.
16. The method of claim 15, wherein biasing the rotary body
includes providing a restoring force to restore an axial offset
between the rotary body and the first stationary body.
17. The method of claim 15, further comprising rotating the rotary
body relative the tubular when the rotary body and the first
stationary body are not rotationally locked.
18. The method of claim 15, wherein rotationally locking the rotary
body and the first stationary body includes engaging the rotary
body with an anti-rotation device of the first stationary body.
19. The method of claim 15, further comprising actuating a
secondary anti-rotation device to rotationally lock the rotary body
and the tubular.
20. The method of claim 19, wherein actuating the secondary
anti-rotation device comprises deploying a shifting device into the
wellbore to engage and shift the secondary anti-rotation
device.
21. The method of claim 19, wherein actuating the secondary
anti-rotation device comprises signaling an actuator disposed in
the wellbore with a controller.
22. The method of claim 15, further comprising: biasing the rotary
body from a second stationary body disposed axially adjacent the
rotary body, such that the rotary body is disposed axially
intermediate the first and second stationary bodies; and sliding
the rotary body toward the second stationary body in response to a
second axial force; and rotationally locking the rotary body and
the second stationary body.
23. The method of claim 15, further comprising removing a ledge
with the rotary body rotationally locked with the first stationary
body.
24. A stabilizer for a drill string, comprising: a rotary body
disposed about a tubular of the drill string and comprising first
and second axial ends, and an outer diameter configured to engage a
wellbore; a first stationary body disposed axially adjacent the
first axial end of the rotary body and comprising a first
anti-rotation device configured to rotationally lock with the
rotary body, the first stationary body being configured to resist
axial translation and rotation with respect to the tubular; a
second stationary body disposed axially adjacent the second axial
end of the rotary body and comprising a second anti-rotation device
configured to rotationally lock with the rotary body, the second
stationary body being configured to resist axial translation and
rotation with respect to the tubular; and one or more biasing
members configured to bias the rotary body to a position
intermediate and axially offset from both the first and second
stationary bodies, wherein the rotary body is free to rotate with
respect to the tubular unless rotationally locked with the first
stationary body or the second stationary body.
25. The stabilizer of claim 24, wherein at least one of the first
and second anti-rotation devices is configured to slide between an
inner diameter of the rotary body and the tubular and engage the
inner diameter of the rotary body.
26. The stabilizer of claim 24, wherein the rotary body comprises a
cutting surface on at least one of the first and second axial ends,
the cutting surface being configured to at least partially remove a
ledge of the wellbore when the rotary body is rotationally locked
with at least one of the first and second stationary bodies.
27. The stabilizer of claim 24, wherein the rotary body is free
from bearings disposed on the outer diameter.
28. The stabilizer of claim 24, wherein at least one of the first
and second stationary bodies comprises a stop collar fixed to the
tubular.
29. The stabilizer of claim 24, wherein at least a portion of at
least one of the first and second stationary bodies is integrally
formed with the tubular.
30. The stabilizer of claim 24, wherein the one or more biasing
members include: a first biasing member extending axially between
the rotary body and the first stationary body; and a second biasing
members extending axially between the rotary body and the second
stationary body.
31. The stabilizer of claim 24, further comprising a secondary
anti-rotation device coupled to the tubular and configured to
expand and engage the rotary body such that the rotary body resists
axial translation and rotation with respect to the tubular.
32. The stabilizer of claim 31, wherein the secondary anti-rotation
device comprises: an inner profile extending into the tubular and
configured to receive a shifting tool; and a gripping member
coupled to the inner profile and configured to expand radially
outwards to engage the rotary body, wherein the inner profile is
configured to shift by receiving the shifting tool and expand the
gripping member.
33. The stabilizer of claim 31, wherein the secondary anti-rotation
device comprises: an actuator configured to receive signals from a
controller; and a gripping member coupled to the tubular, wherein
the actuator is configured to cause the gripping member to engage
the rotary body when the controller signals the actuator to
actuate.
Description
BACKGROUND
[0001] A bottom hole assembly ("BHA") is a drilling tool or
combination of drilling tools typically configured for use at the
distal or downhole end of a drill string. More particularly, the
BHA is generally the portion of the drill string extending from a
distal end of the drill pipe. The BHA can include one or more subs
made up together, with each sub providing a specific tool or
structure. For example, a conventional BHA can include one or more
drill bits, stabilizers, reamers, shocks, hole openers, drill
collars, combinations thereof, and the like. Further, BHAs can
include mud motors and can be steerable, for example, to assist in
changing a direction of the wellbore in directional drilling
applications.
[0002] BHAs can be "slick," i.e., can generally have no stabilizing
devices; however, this can lead to undesired vibration.
Accordingly, stabilizers are commonly employed as part of BHAs to
avoid such vibration and can also assist in directional control.
Such directional control can enable the driller to maintain or
avoid pendulum forces and/or can be used in packed hole assemblies.
To this end, stabilizers can be employed in vertical drilling, to
maintain a constant direction, and in deviated or directional
drilling, to provide control of directional changes in the
wellbore. Various BHAs and stabilizers are suitable for use in
either or both applications and are commonly employed.
[0003] The use of stabilizers to aid in directional control,
however, presents several challenges. Stabilizers often slide
against the wellbore wall, resulting in wear on the stabilizer and
increasing drag on the advancing of the drill string. Further, such
increased drag can even result in the stabilizer being hung-up on
ledges or other partial wellbore obstructions. Overcoming the drag
forces can, at least temporarily, reduce the weight on the drill
bit (WOB) and slow the drilling process. Further, the stabilizers
can increase torsional vibration ("stick slip"), especially in
"non-rotational" stabilizers (i.e., stabilizers rotationally fixed
to the drill string so as to rotate therewith with respect to the
wellbore). Such vibration can be damaging to the BHA.
[0004] Roller reamers have been employed in an attempt to overcome
some of these challenges. Roller reamers generally include a
stabilizer with roller bearings or wheels on the outside diameter,
so as to reduce friction resulting from the stabilizer engaging the
wellbore. Such roller reamers can reduce drag and torsional
vibration, but can also be sensitive to drill string vibration or
other upsets and can lose bearings downhole. Such losses (often
referred to as "junk" or "fish") can lead to the roller reamers
becoming less effective and can cost rig time as the lost
structures can necessitate fishing operations to remove the
structures from the wellbore.
[0005] What is needed are improved apparatus and methods for
stabilizing a bottom hole assembly.
BRIEF SUMMARY
[0006] In various aspects, the disclosure can provide a stabilizer
having a rotary body and one or more, for example, two stationary
bodies. The rotary body can be configured to rotate about a
tubular, whether the tubular is stationary or rotating with respect
to a stationary reference plane. For example, while the tubular
rotates with respect to a stationary reference plane, the rotary
body can remain generally rotationally stationary with respect to
the wellbore, although it can be free to rotate as needed. The
rotary body can be centralized between the two stationary bodies by
one or more biasing members. The stationary bodies can be
stationary with respect to the tubular, i.e., can move along with
the tubular. If the rotary body encounters a ledge or other partial
wellbore obstruction, the obstruction can apply an axial force on
the rotary body that can overcome the centralizing force applied by
the biasing member and can cause the rotary body to slide, in some
cases, into engagement with one of the stationary bodies.
[0007] The stationary bodies can each include an anti-rotation
device, which can rotationally lock with the rotary body, such that
the rotary body and the stationary body can resist rotation
relative one another. Accordingly, turning of the tubular and/or
application of axial force on the drill string can cause the rotary
body to cut, grind, or otherwise remove the wellbore obstruction,
freeing the stabilizer to pass by. With the wellbore obstruction
removed, the biasing member can urge the rotary body to slide out
of engagement with the stationary body, allowing the rotary body to
recommence generally free rotation with respect to the tubular.
[0008] Embodiments of the disclosure can provide a stabilizer
apparatus for use in a wellbore. The apparatus can include a rotary
body disposed about a tubular. The apparatus can also include a
first anti-rotation device disposed axially adjacent the rotary
body and configured to resist rotation and axial translation with
respect to the tubular. The rotary body can be configured to slide
axially to engage the first anti-rotation device and rotationally
lock therewith. The apparatus can also include a biasing member
configured to bias apart the rotary body and the first
anti-rotation device.
[0009] Embodiments of the disclosure can also provide a method for
stabilizing a drill string. The method can include biasing the
rotary body disposed on a tubular axially apart from a first
stationary body disposed axially adjacent the rotary body. The
method can also include radially engaging a wellbore wall with an
outer diameter of the rotary body so as to centralize the drill
string. The method can further include sliding the rotary body
toward the first stationary body in response to an axial force, and
rotationally locking the rotary body and the first stationary
body.
[0010] Embodiments of the disclosure can also provide a stabilizer
for a drill string. The stabilizer can include a rotary body
disposed about a tubular of the drill string and having first and
second axial ends, and an outer diameter configured to engage a
wellbore. The stabilizer can also include a first stationary body
disposed axially adjacent the first axial end of the rotary body
and including a first anti-rotation device configured to
rotationally lock with the rotary body. The first stationary body
can be configured to resist axial translation and rotation with
respect to the tubular. The stabilizer can also include a second
stationary body disposed axially adjacent the second axial end of
the rotary bod and including a second anti-rotation device
configured to rotationally lock with the rotary body. The second
stationary body can be configured to resist axial translation and
rotation with respect to the tubular. The stabilizer can further
include one or more biasing members configured to bias the rotary
body to a position intermediate and axially offset from both the
first and second stationary bodies. The rotary body can be free to
rotate with respect to the tubular unless rotationally locked with
the first stationary body or the second stationary body.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] Various features of the embodiments can be more fully
appreciated, as the same become better understood with reference to
the following detailed description of the embodiments when
considered in connection with the accompanying figures, in
which:
[0012] FIG. 1 illustrates a schematic, side view of a stabilizer,
according to an embodiment.
[0013] FIGS. 2-4 illustrate simplified, schematic, side views of
the stabilizer, depicting one example of operation of the
stabilizer being deployed into a wellbore, according to an
embodiment.
[0014] FIGS. 5A and 5B illustrate quarter-sectional views of the
stabilizer including a secondary anti-rotation device, according to
an embodiment.
[0015] FIG. 6 illustrates a quarter-sectional view of the
stabilizer, with another embodiment of the secondary anti-rotation
device.
[0016] FIG. 7 illustrates a flowchart of a method for stabilizing a
drill string in a wellbore, according to an embodiment.
DETAILED DESCRIPTION
[0017] While the present disclosure has been described according to
its preferred embodiments, it is of course contemplated that
modifications of, and alternatives to, these embodiments, such
modifications and alternatives obtaining the advantages and
benefits of this disclosure, will be apparent to those of ordinary
skill in the art having reference to this specification and its
drawings. It is contemplated that such modifications and
alternatives are within the scope of this disclosure as
subsequently claimed herein.
[0018] FIG. 1 illustrates a schematic, side view of a stabilizer
100, according to an embodiment. The stabilizer 100 can be disposed
about a tubular 102, which can form part of or be connected to a
drill string and can be configured to be disposed in a wellbore. It
will be appreciated that the tubular 102 can include one or more
pipes, mandrels, segments, subs, or bodies and can be cylindrical
or can have a non-circular cross-section (e.g., elliptical).
Furthermore, the stabilizer 100 can include a rotary body 104 and
one or more stationary bodies (for example, two are shown: 106,
108). As the terms are used herein, "rotating," "rotatable,"
"rotary," and "stationary" are generally considered to be taken
with the tubular 102 as the point of reference, and it will be
appreciated that the tubular 102 itself can be rotating with
respect to a stationary reference plane and can be advancing
axially in the wellbore. The "rotary" body 104 can free to rotate
with respect to the tubular 102, unless, for example, the rotary
body 104 is rotationally locked, as will be described in greater
detail below.
[0019] The rotary body 104 can have axial ends 110, 112 and an
outer diameter 113. The rotary body 104 can be disposed axially
between or "intermediate" the stationary bodies 106, 108, such that
the axial ends 110, 112 can face the stationary bodies 106, 108,
respectively, while the outer diameter 113 faces radially outwards.
In some embodiments, a single stationary body 106 or 108 can be
employed, while omitting the other stationary body 106 or 108.
Furthermore, in other embodiments, additional stationary bodies can
be employed for a variety of purposes, as will be readily
understood by one with skill in the art. Additionally, the outer
diameter 113 of the rotary body 104 can be larger than an outer
diameter of the stationary bodies 106, 108, as shown.
[0020] The rotary body 104 can also include cutting surfaces 110A,
112A, for example, on or adjacent to the axial ends 110, 112 or
elsewhere on the rotary body 104. The cutting surfaces 110A, 112A
can be a high-friction coating, such as a tungsten carbide coating.
In other embodiments, buttons of high-strength cutting material can
be embedded in the axial ends 110, 112 to provide the cutting
surfaces 110A, 112A. In yet other embodiments, the cutting surfaces
110A, 112A can be an edge between one or both of the axial ends
110, 112 and the outer diameter 113. One skilled in the art will
realize that the cutting surface 110A, 112A can be formed of any
material and formed in any configuration that facilitates removal
of material from the wellbore.
[0021] The juncture between the axial ends 110, 112 and the outer
diameter 113 can form one example of the cutting surface 110A,
112A, which can define an attack angle a. The attack angle a can be
defined as the angle between a line parallel to the cutting surface
110A, 112A and a line parallel to the outer diameter 113. A range
of cutting angles a can be employed, for example, between about
120.degree. and about 0.degree.. However, in some embodiments,
cutting efficiency of the rotary body 104 can be maximized with
reduced cutting angles, for example, less than about
20.degree..
[0022] The rotary body 104 can further include an inner diameter
that can be larger than the outer diameter of the tubular 102,
e.g., to enable relative rotation between the rotary body 104 and
the tubular 102. Friction-reducing members, such as bearings, can
be disposed between the rotary body 104 and the tubular 102, to
facilitate such relative rotation. The inner diameter can be
cylindrical or can have one or more non-circular cross-sectional
shapes.
[0023] The stationary bodies 106, 108 can each include an
anti-rotation device 114, 115, respectively, and a base 116, 117,
respectively. The anti-rotation devices 114, 115 can extend axially
from the bases 116, 117 and toward the rotary body 104, as shown.
In at least one embodiment, the bases 116, 117 can be stop collars
fixed to the tubular 102 in any suitable manner, for example, by
resistance fit, welding, brazing, set screws, pins, or other
fasteners, adhesives, teeth, combinations thereof, or the like. In
another embodiment, one or more of the bases 116, 117 can be a pipe
joint or can otherwise be integrally formed with the tubular 102.
The anti-rotation devices 114, 115 can be coupled to the bases 116,
117, respectively, such that the anti-rotation devices 114, 115 can
be constrained from rotating with respect to the tubular 102.
Accordingly, the stationary bodies 106, 108 can be positionally
fixed to the tubular 102, such that, in general, the stationary
bodies 106, 108 can resist relative axial translation and rotation
with respect to the tubular 102. In some embodiments, however, a
range of axial motion of the anti-rotation devices 114, 115 can be
provided, while the stationary bodies 106, 108 can still be
considered positionally fixed with respect to the tubular 102, as
the term is used herein.
[0024] The stabilizer 100 can also include one or more biasing
members (two are shown: 118, 120), which can extend between the
axial ends 110, 112 of the rotary body 104 and the stationary
bodies 106, 108, respectively. The biasing members 118, 120 can
apply centralizing forces on the rotary body 104, such that the
rotary body 104 can be, at a default, maintained between and
axially offset from both of the stationary bodies 106, 108. The
biasing members 118, 120 can thus prevent the rotary body 104 from
engaging either anti-rotation devices 114, 115 until an externally
applied force overcomes the biasing force applied by the biasing
members 118, 120.
[0025] The biasing members 118, 120 can be or include one or more
tension springs, one or more compression springs, leaf springs,
resilient elastomeric members, magnets, combinations and/or arrays
thereof, or any other structure capable of applying an axial
centralizing force on the rotary body 104. Accordingly, in various
embodiments, the biasing member 118 can bias the second stationary
body 108 from the rotary body 104, while the biasing member 120 can
bias the first stationary body 106 from the rotary body 104. In
other embodiments, the biasing member 118 can bias the first
stationary body 106 from the rotary body 104, while the biasing
member 120 can bias the second stationary body 108 from the rotary
body 104. Furthermore, in some embodiments, the biasing members
118, 120 can cooperate to provide a centralizing force on the
rotary body 104, such that both can serve to bias the rotary body
104 from the stationary bodies 106, 108. In still other
embodiments, a single biasing member can be employed to apply the
centralizing force. Further, although a single biasing member 118,
120 is shown on each side of the rotary body 104, it will be
appreciated that each biasing member 118, 120 can include multiple
biasing members.
[0026] In various embodiments, the biasing force applied by one or
more of the biasing members 118, 120 can range from about 1,000 lbs
to about 2,000 lbs. In some embodiments, the biasing force can be
determined at least according to how many stabilizers 100 are
deployed in a drill string. Further, the biasing force can be
controlled and/or selected according to how many and what type of
biasing members 118, 120 are utilized with the rotary body 104. For
example, a lower biasing force can be suitable when more
stabilizers 100 are used. Without being limited to theory, the
biasing force can also act generally according to Hooke's law, such
that the force varies according to the position of the rotary body
104.
[0027] The rotary body 104 can also include engaging members which
can be configured to engage the anti-rotation devices 114, 115 so
as to resist relative rotation between the rotary body 104 and the
stationary bodies 106, 108. In one embodiment, the engaging members
of the rotary body 104 can extend radially, either toward or away
from the tubular 102. Such radially-oriented engaging members can
include teeth, forming, for example, a gear. In such an embodiment,
the anti-rotation devices 114, 115 can also include teeth, for
example, so as to form a spline gear. Accordingly, the rotary body
104 can be configured to slide at least partially over the
anti-rotation devices 114, 115, such that the engaging members
rotationally lock, enmesh, or otherwise engage the anti-rotation
devices 114, 115 so as to resist rotation relative thereto. In
another radial embodiment, the engaging members can be a
high-friction surface disposed on the inside diameter of the rotary
body 104. In at least one such embodiment, the anti-rotation
devices 114, 115 can also include a high-friction surface, such
that an engagement between one of the engaging members and one of
the anti-rotation devices 114, 115 forms a brake. Indeed, it will
be appreciated that the anti-rotation devices 114, 115 may be or
include any suitable device configured to reduce, slow, eliminate,
or otherwise resist relative motion of the rotary body 104 with
respect to the tubular 102, when the rotary body 104 and at least
one of the anti-rotation devices 114, 115 are engaged together.
[0028] In another embodiment, the engaging members can extend
axially from the axial ends 110, 112, either outward, toward the
stationary bodies 106, 108, respectively, or inward, away
therefrom. Such axially-extending engaging members can form half of
a dog clutch or another type of clutch with the anti-rotation
devices 114, 115 forming the other half of the clutch. In another
embodiment, the engaging members and the anti-rotation devices 114,
115 can be axial high-friction surfaces disposed on the axial ends
110, 112, so as to engage axial high-friction surfaces of the
anti-rotation devices 114, 115.
[0029] In yet another embodiment, either axial or radial, or both,
the engaging members can be a magnetic target (e.g., laminated
ferrous regions) and the anti-rotation devices 114, 115 can be
electromagnets, or vice versa, such that, when engaged, relative
rotation of the rotary body 104 and the stationary bodies 106, 108
can induce eddy currents resistive of such rotation. In yet another
embodiment, the engaging members can be protrusions and/or slots,
and the anti-rotation devices 114, 115 can include a complementary
configuration of slots and/or protrusions.
[0030] As will be appreciated from the foregoing description of
several exemplary embodiments for the engaging members of the
rotary body 104 and the anti-rotation devices 114, 115, a wide
variety of embodiments thereof are contemplated for use consistent
with the present disclosure. Further, it will be appreciated that
the anti-rotation devices 114, 115 need not have the same
construction and can include different configurations adapted to
provide rotational locking, as will be described in greater detail
below. Additionally, the anti-rotation devices 114, 115 are
illustrated as having a smaller outer diameter than the bases 116,
117; however, in other embodiments, the anti-rotation devices 114,
115 can be equal or larger in radius than the bases 116, 117.
[0031] With continuing reference to FIG. 1, FIGS. 2-4 illustrate
schematic, side views of the stabilizer 100, showing exemplary
operation thereof, according to an embodiment. For ease of
illustration, the stabilizer 100 is shown with a single stationary
body 108; however, it will be appreciated that the stabilizer 100
can include two stationary bodies 106, 108, or more, as described
above. Further, the functioning of the two stationary bodies 106,
108 can be substantially similar, such that a description of the
functioning of the stationary body 106 can be substantially
duplicative of the functioning of the stationary body 108.
[0032] As depicted in FIG. 2, the stabilizer 100 can be deployed
into a wellbore 200. The wellbore 200 can be formed, for example,
by drilling and/or reaming operations. Additionally, the wellbore
200 can be vertical, horizontal, or deviated. Further, the wellbore
200 can include areas where it departs from cylindrical. An example
of such an area can be a ledge 202, as shown. Especially in open
holes, ledges can form for a variety of reasons and can extend
partially into the annulus defined between the drill string or
tubular 102 and the wellbore 200, so as to partially obstruct the
wellbore 200.
[0033] The outer diameter 113 of the rotary body 104 of the
stabilizer 100 can be configured to engage the wellbore 200, as
needed, to centralize the tubular 102 in the wellbore 200. Further,
the tubular 102 can be rotating relative to the wellbore 200, and
the rotary body 104 can rotate with respect to the tubular 102, for
example, so as to be generally non-rotating with respect to the
wellbore 200, or, for example, non-rotating with respect to the
tubular 102 unless acted upon by an outside torsional force (e.g.,
engagement with the wellbore 200). Accordingly, torsional friction
forces, slip/stick conditions, and/or axially oriented drag forces
induced by the stabilizer 100 engaging the wellbore 200 can be
minimized. At other times, the tubular 102 can be non-rotating,
while the rotary body 104 can remain free to rotate with respect
thereto.
[0034] When the rotary body 104 encounters the ledge 202, as the
tubular 102 is advanced into (or out of) the wellbore 200 in
direction D.sub.T, the ledge 202 can apply an axially-directed
force F.sub.L on the rotary body 104, resisting progression of the
rotary body 104 along with the tubular 102. When the
axially-directed force overcomes a biasing force F.sub.S applied by
the biasing member 120 (and/or by the biasing member 118, FIG. 1)
the rotary body 104 can axially translate with respect to the
tubular 102 in direction D.sub.R, toward the stationary body
108.
[0035] FIG. 3 illustrates a side, schematic view of the stabilizer
100, with the rotary body 104 after sliding into engagement with
the stationary body 108, according to an embodiment. By engagement
with the stationary body 108, the rotary body 104 can be prevented
from rotation and/or axial translation with respect to the tubular
102. For example, the axial end 112 of the rotary body 104 can bear
against the base 117 of the stationary body 108, such that the base
117 provides an axial stop for the rotary body 104. Further, the
engaging member of the rotary body 104 can engage the anti-rotation
device 115, resulting in rotational locking of the anti-rotation
device 115 and the rotary body 104. Since the anti-rotation device
115 can be coupled to the base 117 so as to resist rotation
relative thereto, and the base 117 can be coupled to the tubular
102 so as to resist rotation relative thereto, such rotational
locking of the rotary body 104 to the anti-rotation device 115 can
result in the rotary body 104 being rotationally locked with the
tubular 102. As the term is used herein, "rotational lock," and
grammatical variants thereof, is generally defined to mean that
relative rotation between two members is resisted and/or avoided
unless and until excessive force is applied that results in failure
of one or more of the components.
[0036] With the rotary body 104 rotationally locked with and
prevented from further axial translation with respect to the
tubular 102, rotation and/or axial advancement of the tubular 102
can be transmitted to the rotary body 104. Accordingly, the rotary
body 104 can apply a cutting force F.sub.C, which can be at least
partially axial and/or at least partially torsional, on the ledge
202. The rotary body 104, for example, the axial end 110 thereof,
can include the cutting surface 110A, as described above. The
cutting surface 110A can cut into, grind, or otherwise remove the
ledge 202 by application of the cutting force F.sub.C, until the
ledge 202 breaks away, grinds apart, or otherwise yields to allow
passage of the rotary body 104. It will be appreciated that the
axial end 112 can also include a cutting surface, as noted above,
and can function similarly to the axial end 110 when the axial end
112 encounters a ledge.
[0037] Referring now to FIG. 4, there is illustrated the stabilizer
100 after the ledge 202 has been removed, according to an
embodiment. With the ledge 202 removed, the axially-directed force
F.sub.L that was applied by the ledge 202 on the rotary body 104 to
overcome the biasing force F.sub.S can be removed. Accordingly, the
biasing force F.sub.S can act as a restoring force, pushing,
pulling, or otherwise urging the rotary body 104 away from the
stationary body 108, to return the rotary body 104 to its default
position, offset from the anti-rotation device 115. As such, the
rotary body 104 can once again be free to rotate about the tubular
102 and to translate axially, for example, between the stationary
bodies 106, 108 (FIG. 1).
[0038] In some cases, it may be desirable to resist the rotation of
the rotary body 104 with respect to the tubular 102, without the
engagement of the rotary body 104 with the anti-rotation devices
114, 115 providing the resistance to rotation. For example, in some
cases, the engagement between the rotary body 104 and the
anti-rotation devices 114, 115 may fail. In other cases, a
restriction of the rotation of the rotary body 104 about the
tubular 102 may be desired without requiring axial force to be
supplied thereto. Accordingly, FIGS. 5A and 5B illustrate
quarter-sectional views of the stabilizer 100 including a secondary
anti-rotation device, according to an embodiment.
[0039] The secondary anti-rotation device can include an inner
profile 500 and a gripping member 502. The inner profile 500 can
extend radially inward in the tubular 102 and can be configured to
shift axially, for example, from the position shown in FIG. 5A to
the position shown in FIG. 5B (i.e., toward the stationary body
106) and/or in reverse. Shifting the inner profile 500 can also
cause the inner diameter of the inner profile 500 to expand. The
gripping member 502 can be or include a set of slips, as shown,
whether marking or non-marking, and/or can be or include one or
more pins, screws, protrusions, brake pads, or the like. The
gripping member 502 can be pivotally coupled to the tubular 102, or
otherwise configured to move between a retracted position (e.g.,
FIG. 5A) and an expanded position (e.g., FIG. 5B).
[0040] In an embodiment, when the gripping member 502 is retracted,
as shown in FIG. 5A, the inner diameter of the rotary body 104 can
slide past the gripping member 502. When expanded, as shown in FIG.
5B, the gripping member 502 can engage the rotary body 104, either
at the inner diameter or at one or both of the axial ends 110, 112.
Further, the gripping member 502 can be coupled to the inner
profile 500, such that shifting of the inner profile 500 causes the
gripping member 502 to expand or retract.
[0041] In exemplary operation, the inner profile 500 can be
configured to receive a shifting device, which can be a ball 504,
as shown, a dart, a valve shifting tool, or any other suitable
device deployed into the tubular 102 or otherwise moved into
proximity of the inner profile 500. In the depicted embodiment, the
ball 504 can have a diameter that exceeds the inner diameter of the
inner profile 500, but can be less than the inner diameter of the
tubular 102. Accordingly, the ball 504 can travel through the
tubular 102, for example, motivated by hydraulic force and catch on
the inner profile 500. Continued hydraulic force can be transmitted
through the ball 504 to the inner profile 500, causing the inner
profile 500 to shift and thus expand the gripping member 502. The
shifting of the inner profile 500 can include increasing the inner
diameter thereof, and, as such, the ball 504 can continue through
the tubular 102 after shifting the inner profile 500, for example,
to engage the inner profile of a subjacent stabilizer.
[0042] Accordingly, the secondary anti-rotation device can be
engaged to rotationally lock the rotary body 104 at the discretion
of a wellbore operator, without requiring a ledge or other wellbore
obstruction. Additionally, the secondary anti-rotation device can
be employed when it is determined or at least suspected that one or
both of the anti-rotation devices 114, 115 has failed or the
stabilizer 100 otherwise requires additional rotational locking
force. A variety of other embodiments suitable for use in a
mechanically-actuated, secondary anti-rotation device will be
readily apparent and are contemplated for use according to the
present disclosure.
[0043] FIG. 6 illustrates a quarter-sectional view of the
stabilizer 100, with another embodiment of the secondary
anti-rotation device. The secondary anti-rotation device can
include an actuator 600, a battery 601, and a gripping member 602.
In at least one embodiment, the secondary anti-rotation device can
also include a valve 603 coupled to the actuator 600, such that the
actuator 600 can control the position of the valve 603.
[0044] The gripping member 602 can be or include one or more slips,
whether marking or non-marking, pins, teeth, screws, cylinders,
protrusions, or the like. The gripping member 602 can also be one
or more brake pads. The gripping member 602 can radially retract to
allow the rotary body 104 to pass by, rotationally and/or axially,
and can expand so as to rotationally lock and/or axially restrain
the rotary body 104.
[0045] The actuator 600 can be any suitable electromechanical or
mechanical actuator, such as a solenoid, servo-motor, mud motor, or
the like, and can be coupled to the battery 601 so as to receive
power therefrom. The battery 601 can be any suitable type of power
storage and/or generating device configured to provide power to the
actuator 600 for hours, days, months, or longer. The actuator 600
can be directly, mechanically linked to the griping member 602, or
can be coupled thereto hydraulically via the valve 603, for
example. In such a hydraulic embodiment, actuation of the actuator
600 can cause the valve 603 position to modulate, thereby applying
a relatively large hydraulic force on the gripping member 602 by
application of a relatively small amount of force by the actuator
600.
[0046] Further, the actuator 600 can receive signals from a
controller 604. The controller 604 can be located remotely from the
actuator 600, e.g., at the surface of the wellbore, or at a
position between the actuator 600 and the surface. In other
embodiments, the controller 604 or can be located proximal the
actuator 600, for example, located in the tubular 102 near the
actuator 600. In an embodiment, the controller 604 can send such
signals via wired tubing, or via a wireless connection. Further, in
some embodiments, power can be transmitted to the actuator 600, for
example, by running power cables parallel with the tubular 102,
which can allow the battery 601 to be omitted. In other
embodiments, external power may not be required, as the actuator
600 can be powered by movement of fluid in the wellbore.
[0047] When singled by the controller 604, the actuator 600 can
actuate to expand the gripping member 602, thereby rotationally
locking and/or axially restraining the rotary body 104 with respect
to the tubular 102. Here again, the secondary anti-rotation device
can thus be engaged to rotationally lock and/or axially restrain
the rotary body 104, for example, at the discretion of a wellbore
operator, without requiring a ledge or other wellbore obstruction
to force the rotary body 104 to engage one of the stationary bodies
106, 108 and/or in a situation where the engagement between the
rotary body 104 and one of the stationary bodies 106, 108 fails or
is otherwise insufficient.
[0048] FIG. 7 illustrates a flowchart of a method 700 for
stabilizing a drill string in a wellbore, according to an
embodiment. The method 700 can proceed by operation of one or more
embodiments of the stabilizer 100 and can thus be best understood
with reference thereto. The method 700 can include biasing a rotary
body disposed on a tubular axially apart from a stationary body
disposed axially adjacent the rotary body, as at 702. Such biasing
at 702 can include providing a restoring force to restore an axial
offset between the rotary body and the stationary body, for
example. The method 700 can also include radially engaging a
wellbore wall with an outer diameter of the rotary body so as to
centralize the drill string, as at 704. The method 700 can further
include sliding the rotary body toward the stationary body in
response to an axial force, as at 706.
[0049] Additionally, the method 700 can include rotationally
locking the rotary body and the stationary body, as at 708.
Rotationally locking at 708 can include engaging the rotary body
with an anti-rotation device of the stationary body. The
anti-rotation device can be or include one or more of a variety of
devices configured to engage the rotary body and generally resist
relative rotation between the rotary body and the stationary body.
The method 700 can also include removing a ledge with the rotary
body, as at 709, for example, when the rotary body is rotationally
locked with the stationary body.
[0050] In an embodiment, the method 700 can also include rotating
the rotary body relative the tubular when the rotary body and the
stationary body are not rotationally locked. This can allow the
stabilizer to have a reduced torsional and/or axial drag when
engaging the wellbore wall, as compared to stabilizers that are not
configured to rotate with respect to the drill string.
[0051] In an embodiment, the method 700 can further include
actuating a secondary anti-rotation device to rotationally lock the
rotary body and the tubular, as at 710. Actuating the secondary
anti-rotation device at 710 can include dropping a drop ball, dart,
or both in the wellbore. Additionally or alternatively, actuating
the secondary anti-rotation device at 710 can include signaling an
actuator disposed in the wellbore with a controller. Actuating the
secondary anti-rotation device at 710 can enable the rotary body to
be rotationally locked at the option of an operator and/or if one
or more of the first and second anti-rotation devices fails and/or
slips.
[0052] The method 700 can also include biasing the rotary body from
a second stationary body disposed axially adjacent the rotary body,
such that the rotary body can be disposed axially intermediate the
first and second stationary bodies. The method 700 can further
include sliding the rotary body toward the second stationary body
in response to a second axial force, and rotationally locking the
rotary body and the second stationary body.
[0053] While the teachings have been described with reference to
the exemplary embodiments thereof, those skilled in the art will be
able to make various modifications to the described embodiments
without departing from the true spirit and scope. The terms and
descriptions used herein are set forth by way of illustration only
and are not meant as limitations. In particular, although the
method has been described by examples, the steps of the method can
be performed in a different order than illustrated or
simultaneously. Furthermore, to the extent that the terms
"including", "includes", "having", "has", "with", or variants
thereof are used in either the detailed description and the claims,
such terms are intended to be inclusive in a manner similar to the
term "comprising." As used herein, the terms "one or more of and
"at least one of with respect to a listing of items such as, for
example, A and B, means A alone, B alone, or A and B. Those skilled
in the art will recognize that these and other variations are
possible within the spirit and scope as defined in the following
claims and their equivalents.
* * * * *