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.

Description

BACKGROUND

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.

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.

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.

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.

What is needed are improved apparatus and methods for stabilizing a bottom hole assembly.

BRIEF SUMMARY

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.

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.

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.

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.

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

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:

FIG. 1 illustrates a schematic, side view of a stabilizer, according to an embodiment.

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.

FIGS. 5A and 5B illustrate quarter-sectional views of the stabilizer including a secondary anti-rotation device, according to an embodiment.

FIG. 6 illustrates a quarter-sectional view of the stabilizer, with another embodiment of the secondary anti-rotation device.

FIG. 7 illustrates a flowchart of a method for stabilizing a drill string in a wellbore, according to an embodiment.

DETAILED DESCRIPTION

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.

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.

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.

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.

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° and about 0°. However, in some embodiments, cutting efficiency of the rotary body 104 can be maximized with reduced cutting angles, for example, less than about 20°.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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_T, the ledge 202 can apply an axially-directed force F_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_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_R, toward the stationary body 108.

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.

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_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_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.

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_L that was applied by the ledge 202 on the rotary body 104 to overcome the biasing force F_S can be removed. Accordingly, the biasing force F_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).

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.

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).

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.