Patent Description:
Directional drilling operations involve controlling the direction of a wellbore as it is being drilled. Generally, the goal of directional drilling is to reach a target subterranean destination with a drill string, and often the drill string will need to be turned through a tight radius to reach the target destination. Generally, a rotary steerable system, which forms a portion of a bottom hole assembly ("BHA"), is used to steer the bottom hole assembly to create a curved section of the wellbore. Each BHA has a maximum dogleg capability. There are instances when the maximum dogleg capability of a BHA is not sufficient. For example, the BHA, even when operated at its maximum dogleg capability may produce a dogleg less than a desired dogleg. This may be due to the type of formation being drilled; a tool problem; drill bit walk tendencies; when the geology of interest is not at the depth expected and a quick response is desired; or when sudden changes in geology are encountered, such as faults. Directional drilling can also result in a reduction of weight transfer to the drill bit due friction forces being generated when the drill string contacts a wall of a curved section of the wellbore. International Patent Publication <CIT> discloses a steerable drilling apparatus including a control system inside a cylindrical housing connected to a drill bit having radially-extendable pistons, and a method for drilling a borehole with a drill bit having a cutting structure. Other documents relating to this subject-matter are <CIT>, <CIT> and <CIT>.

Various embodiments of the present disclosure will be understood more fully from the detailed description given below and from the accompanying drawings of various embodiments of the disclosure. In the drawings, like reference numbers may indicate identical or functionally similar elements.

The scope of the invention is defined by independent method claim <NUM> and independent apparatus claim <NUM>. Other aspects of the invention are defined by the dependent claims.

Illustrative embodiments and related methods of the present disclosure are described below as they might be employed using a push-the-bit type assembly with reamer. In the interest of clarity, not all features of an actual implementation or method are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further aspects and advantages of the various embodiments and related methods of the disclosure will become apparent from consideration of the following description and drawings.

Referring to <FIG> and <FIG>, a push-the-bit type assembly with reamer that is extending a wellbore from an offshore oil or gas platform that is schematically illustrated and generally designated <NUM>. A semi-submersible platform <NUM> is positioned over a submerged oil and gas formation <NUM> located below a sea floor <NUM>. A subsea conduit <NUM> extends from a deck <NUM> of the platform <NUM> to a subsea wellhead installation <NUM>, including blowout preventers <NUM>. The platform <NUM> has a hoisting apparatus <NUM>, a derrick <NUM>, a travel block <NUM>, a hook <NUM>, and a swivel <NUM> for raising and lowering pipe strings, such as a substantially tubular, axially extending drill string <NUM>. A wellbore <NUM> extends through the various earth strata including the formation <NUM>, with some portions of the <NUM> having a casing string <NUM> cemented therein. However, in some embodiments the entirety of the wellbore <NUM> may be an open hole wellbore.

The wellbore <NUM> includes any one or more of a vertical section 75a, a curved section 75b, a tangent section 75c, and a horizontal section 75d. The wellbore <NUM> may be an uphill wellbore and/or include multilateral wellbores. Accordingly, it should be understood by those skilled in the art that the use of directional terms such as "above," "below," "upper," "lower," "upward," "downward," "uphole," "downhole", "up", "down", "left", "right" and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well, the downhole direction being toward the toe of the well. "Up" and "down" apply on a plane at the downhole end of a drill bit perpendicular to the longitudinal axis of the wellbore; "up" being in line with but oriented against the gravity vector projected on this plane; "down" being in line with and oriented with the gravity vector projected on this plane. "Left" and "right" apply on the same plane but in directions perpendicular to the projected gravity vector as viewed looking downhole. Also, even though <FIG> and <FIG> depict an offshore operation, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in onshore operations.

A push-the-bit type assembly with reamer, or BHA <NUM>, is coupled to the lower or distal end of the drill string <NUM>. <FIG> illustrates the BHA <NUM> coupled to a distal end of the drill string <NUM>. The BHA <NUM> may include a rotary steerable tool <NUM> and a drill bit <NUM> that may be rotationally fixed relative to the drill string <NUM>, such that the rotary steerable tool <NUM> and the drill bit <NUM> rotate with the same speed and direction as the drill string <NUM>. In other instances, the rotary steerable tool <NUM> maintains a geo-stationary position with respect to the wellbore <NUM> as the drill string <NUM> and drill bit <NUM> rotate at the same speed. In some instances, a straight mud motor <NUM> may be placed in the BHA <NUM> directly above the rotary steerable tool <NUM>, or at the top of the BHA <NUM>, or anywhere in between to provide extra torque and rotational speed to the drill bit <NUM>. With mud motor <NUM> above rotary steerable tool <NUM>, the rotary steerable tool <NUM> and drill bit <NUM> may rotate at a speed faster than the drill string <NUM>. In other instances, the rotary steerable tool <NUM> may maintain a geo-stationary position with respect to the wellbore <NUM>, but the drill bit <NUM> will still rotate faster than the drill string <NUM>. In certain embodiments, the BHA <NUM> includes additional tools, such as a measurement-while-drilling (MWD) apparatus.

In certain embodiments, the BHA <NUM> includes the drill bit <NUM> coupled to the rotary steerable tool <NUM> directly or via one or more tools. The rotary steerable tool <NUM> imparts rotation from the drill string <NUM> to the drill bit <NUM>. As the drill string <NUM> rotates, the downhole end of the rotary steerable tool <NUM> and the drill bit <NUM> may rotate at the same speed and direction as the drill string <NUM>. The downhole end of the rotary steerable tool <NUM> and the drill bit <NUM> may rotate about a longitudinal axis <NUM> of the drill bit <NUM> that may be different than a longitudinal axis <NUM> of the wellbore <NUM> at the downhole end. In the embodiment shown, a drilling direction of the drill bit <NUM>, or toolface, may have two components on a plane perpendicular to a longitudinal axis <NUM> of the wellbore <NUM> at the downhole end of the wellbore <NUM>: an up or down component of side force reacted at the drill bit <NUM> cutting structure; and a left or right component of side force reacted at the drill bit <NUM> cutting structure.

According to aspects of the present disclosure, the rotary steerable tool <NUM> may include at least one actuator. The invention discloses a plurality of actuators <NUM> coupled to the rotary steerable tool <NUM>. As will be described below, the actuators <NUM> are selectively and independently triggered as the rotary steerable tool <NUM> rotates to cause the drill bit <NUM> side force (e.g., one of up/down and one of left/right) to correspond to a desired drilling direction. For example, the actuators <NUM> may alter or maintain the drill bit side force components in the up/down and left/right directions and/or may maintain the drill bit <NUM> in a relatively straight forward path with respect to the wellbore <NUM> as the drill string <NUM> rotates. The actuators <NUM> may take a variety of configurations-including electromagnetic actuators, piezoelectric actuators, hydraulic actuators, etc.-and be powered through a variety of mechanisms. The actuators 115a 115b, and 115c (115c shown in <FIG>), which in some embodiments are circumferentially spaced by about <NUM> degrees, may include pads or blades <NUM> that contact a wall of the wellbore <NUM> when triggered. A pad may include a blade or other tool that contacts the wall of the wellbore <NUM>. That is, the actuators <NUM> and thus the pads <NUM> are configured to extend radially in a direction perpendicular to a longitudinal axis <NUM> of the rotary steerable tool <NUM>. By contacting the wall of the wellbore <NUM>, the pad <NUM> may apply a force <NUM> to the side of the rotary steerable tool <NUM> that is reacted as a side force <NUM> at the drill bit <NUM> cutting structure. As drilling progresses, the side force <NUM> reacted by the drill bit <NUM> is substantially relieved as a deviated wellbore <NUM> is drilled in the desired direction. The pad force is subsequently reacted at other contact locations with the wellbore <NUM>, such as at stabilizer or wear pad locations, or creates bending moments in BHA <NUM> that has to traverse a deviated wellbore <NUM>. The force <NUM> from pad <NUM> and reaction force <NUM> at the drill bit <NUM> may create an offset angle <NUM> between the longitudinal axis <NUM> of the wellbore and the longitudinal axis <NUM> of the drill bit. The size of the offset angle <NUM> may be a function of the amount of lateral deflection of the rotary steerable tool <NUM> relative to the wellbore <NUM> caused by the actuators 115a, 115b, and 115c and pads <NUM> acting on wellbore <NUM>. The offset angle <NUM> is shown as a negative tilt angle of the longitudinal axis <NUM> of drill bit <NUM> relative to the longitudinal axis <NUM> of wellbore <NUM>, meaning the drill bit is pointing outside the curvature of the deviated wellbore <NUM>. As drilling progresses, weight-on-bit acting with the negative tilt angle <NUM> of the drill bit <NUM> will tend to straighten the curvature of deviated wellbore <NUM>. The side force <NUM> reacted by the drill bit <NUM> acts with the side cutting capability of the drill bit <NUM> to compensate and create additional curvature of deviated wellbore <NUM> up to the maximum dogleg capability of the BHA <NUM>. Accordingly, the actuators 115a, 115b, and 115c may be triggered to control the up and down direction components of the drill bit <NUM>. Likewise, the left or right orientation of the actuators 115a, 115b, and 115c when they are triggered may control the left or right direction components of the drill bit <NUM>.

The BHA <NUM> also includes a reamer <NUM> that is positioned between the drill bit <NUM> and the rotary steerable tool <NUM>. This positioning "between" includes the reamer <NUM> being built into or forming a portion of the drill bit <NUM>, and thus positioned below the rotary steerable tool <NUM>; the reamer <NUM> being built into or forming another tool that is positioned between the drill bit <NUM> and the rotary steerable tool <NUM>; and the reamer <NUM> being built into a lower end of the rotary steerable tool <NUM>. Generally, the reamer <NUM> is positioned below, or downhole from, the pads <NUM> of the rotary steerable tool <NUM>. The reamer <NUM> may be any wellbore diameter enlargement device and may be a single actuation reamer or a multi-actuation reamer such that the reamer <NUM> can be activated and deactivated multiple times. <FIG> is an illustration of the BHA <NUM> and the drill string <NUM> extending in the wellbore <NUM>. As shown in <FIG>, the reamer <NUM> is in a first configuration such that reamer cutting structures 125a and 125b, which are capable of extending radially in a direction perpendicular to a longitudinal axis of the reamer <NUM>, are in a retracted position. While only two reamer cutting structures 125a and 125b are shown in <FIG>, <FIG>, and <FIG>, the reamer <NUM> may include any number of reamer cutting structures spaced circumferentially and/or longitudinally along the reamer <NUM>. When in the first configuration (e.g., not activated), the reamer cutting structures 125a and 125b are retracted and spaced from the wall of the wellbore <NUM> such that the reamer <NUM> does not enlarge the diameter of the wellbore <NUM>.

The BHA <NUM> may also include a flexible collar <NUM> or include a flexible section that is coupled uphole from the rotary steerable tool <NUM>. Generally, the flexible collar <NUM> is positioned along the BHA <NUM> such that the rotary steerable tool <NUM> is coupled between the drill bit <NUM> and the flexible collar <NUM>. The flexible collar <NUM> generally has a lower bending stiffness than the rotary steerable tool <NUM> and other BHA components. In some embodiments, the flexible collar <NUM> includes a structural connector, threads, latches, etc. at leading or downhole end thereof for selectively coupling to a trailing or uphole end of the rotary steerable tool <NUM>. A control section and a flow control section of the BHA <NUM> along with the steering section (i.e., the rotary steerable tool <NUM>) is packaged in a single housing with a greater bending stiffness than the flexible collar <NUM> in some instances. The flexible collar <NUM> may include a drill string coupler 140a and wear band at an uphole end thereof for coupling to an uphole portion of the BHA <NUM> and another coupler 140b on an opposing end to couple to the downhole portion of the BHA <NUM>. Between the couplers 140a and 140b, a flex section 140c extends that is capable of buckling or bending. As such, the BHA <NUM> exhibits greater flexibility than the rotary steerable tool <NUM> alone. In some embodiments, the flexible collar <NUM> is more flexible (i.e., has a lower Modulus of Elasticity (E), or a smaller outer diameter) than other portions of the BHA <NUM> such that bending moment within the BHA <NUM> is reduced when the flexible collar <NUM> bends or buckles. That is, the flexible collar <NUM> has a lower bending stiffness than the rotary steerable tool <NUM>. The flexible collar is sized and is composed of materials to increase or maximize the dogleg capability when desired, e.g., to drill a high DLS build, curve, drop or turn section of a wellbore. In some instances, the flexible collar <NUM> is a generally cylindrical tubular member, a traditional necked down collar section, or a fully articulated universal joint.

In some embodiments, the BHA <NUM> also includes a modular control and sensor section, or instrument collar, <NUM> with a control stabilizer. While the instrument collar <NUM>, the flexible collar <NUM>, and the rotary steerable tool <NUM> are illustrated in <FIG> and <FIG> as separate elements, the rotary steerable tool <NUM> includes the instrument collar <NUM> and the flexible section <NUM>. In some embodiments, the instrument collar <NUM> may be positioned downhole from the flexible section <NUM> or anywhere along the BHA <NUM>.

<FIG> illustrates the reamer <NUM> in a second configuration. When activated or when in a second configuration, the reamer cutting structures 125a and 125b extend radially to contact the wall of the wellbore <NUM> and enlarge the diameter of the wellbore <NUM>. Thus, when activated, the reamer <NUM> has an outermost diameter <NUM>. In an exemplary embodiment, the outermost diameter <NUM> is greater than an outer diameter <NUM> of the drill bit <NUM>.

In an exemplary embodiment, as illustrated in <FIG> with continuing reference to <FIG>, <FIG>, <FIG>, and <FIG> a method <NUM> of extending the wellbore <NUM> includes creating a first curved section of the wellbore <NUM> using the BHA <NUM> while the BHA <NUM> is in the first configuration while steering the BHA <NUM> at step <NUM>; creating a second curved section of the wellbore <NUM> having a greater dogleg than the first curved section using the BHA <NUM> while the BHA <NUM> is in the second configuration while steering the BHA <NUM> at step <NUM>; and creating a straight section (e.g., vertical, tangent, horizontal, lateral section) of the wellbore <NUM> using the BHA <NUM> while the BHA <NUM> is in the first configuration at step <NUM>.

The step <NUM> includes the sub steps of creating, using the drill bit <NUM>, the wellbore <NUM> having an original diameter illustrated by the dimension having the reference numeral 75e in <FIG> at step 205a and applying the force <NUM> to the side of the rotary steerable tool <NUM> that is reacted as the side force <NUM> at the drill bit <NUM> cutting structure, using the pad <NUM>, in the original diameter 75e wellbore at step 205b. Referring back to <FIG> illustrates the BHA <NUM> in the first configuration and drilling a curved section of the wellbore <NUM> while steering of the BHA <NUM> or at least the drill bit <NUM>. To create the first curved section of the wellbore <NUM>, the drill bit <NUM> creates a portion of the wellbore <NUM> having the original diameter 75e that generally corresponds to the diameter <NUM> of the drill bit <NUM>. In some embodiments, the original diameter 75e is not equal to the diameter <NUM> of the drill bit <NUM>, but at least a function of the diameter <NUM>. As the reamer <NUM> of the BHA <NUM> is placed or remains in the first configuration, the reamer cutting structures 125a and 125b are retracted such that the reamer cutting structures 125a and 125b do not enlarge the original diameter 75e of the wellbore <NUM>. At the step 205b, the actuators <NUM> trigger the pads <NUM> to contact the original diameter 75e of wellbore <NUM> and apply a side force <NUM> to rotary steerable tool <NUM> that creates the reaction side force <NUM> on the cutting structure of the drill bit <NUM>. The flex section 140c buckles (i.e., bends or otherwise articulates) to make contact with wellbore 75e at coupler 140a, allowing a certain amount of offset angle <NUM> between the longitudinal axis <NUM> of the downhole end of wellbore 75e and the longitudinal axis <NUM> of the drill bit <NUM>. The offset angle <NUM> is typically a negative tilt angle, meaning the drill bit <NUM> is pointing outside the curvature of the wellbore <NUM>. That is, the drill bit <NUM> is pointed towards a trajectory having a radius of curvature greater than the curvature of the wellbore <NUM>. A positive tilt angle is created when the drill bit <NUM> is pointing inside the curvature of the wellbore <NUM>, or when the drill bit <NUM> is pointed towards a trajectory having a radius of curvature smaller than the curvature of the wellbore <NUM>. As drilling progresses forward, the drill bit <NUM> creates a deviated wellbore <NUM> that is generally at the maximum dogleg capability associated with BHA <NUM> in the original diameter 75e of wellbore <NUM>. Generally, the steps of 205a and 205b occur simultaneously.

When it is desired to increase the dogleg capability of the BHA <NUM>, the reamer cutting structures 125a and 125b are deployed or activated such that the reamer <NUM> is in the second configuration to enlarge the original wellbore 75e to an enlarged diameter illustrated by the dimension having numeral 75f in <FIG> and <FIG>, with the enlarged diameter 75f being greater than the original diameter 75e. As the amount of increased dogleg capability is related to the amount of wellbore "overage" or difference between the enlarged diameter 75f and the original diameter 75e, the outermost diameter <NUM> of the reamer <NUM> while in the second configuration is sized to create the desired increase. In some embodiments, the reamer cutting structures 125a and 125b are capable of extending to one of a plurality of radial distances from the reamer <NUM> such that the reamer <NUM> is capable of enlarging the diameter of the wellbore to different diameters.

The step <NUM> includes the sub steps of the step 205a, enlarging the diameter of the wellbore <NUM> to the enlarged diameter 75f at step 210a, and applying the force <NUM> to the side of the rotary steerable tool <NUM> at step 210b that is reacted as the side force <NUM> at the drill bit <NUM> cutting structure. Generally, the steps of 205a, 210a, and 210b occur simultaneously. <FIG> illustrates the BHA <NUM> in the second configuration and drilling a curved section of the wellbore <NUM> while steering the BHA <NUM>. The drill bit <NUM> creates a portion of the wellbore <NUM> having the original diameter 75e that generally corresponds to the diameter <NUM> of the drill bit <NUM> at the step 205a. At the step 210a, the reamer cutting structures 125a and 125b enlarge the diameter of the wellbore <NUM> from the original diameter 75e to the enlarged diameter 75f. At the step 210b, as drilling progresses forward and the wellbore is enlarged the actuators <NUM> trigger pads <NUM> to contact the enlarged diameter 75f of wellbore <NUM>, causing the reactive side force <NUM> on the cutting structure of drill bit <NUM> to steer the drill bit <NUM> in the desired direction or drilling direction. The upper end of the flex section 140c of rotary steerable tool <NUM> may buckle or articulate to make contact with enlarged wellbore 75f at the coupler 140a. The maximum lateral displacement at the upper end of the flex section <NUM>, or at the coupler 140a, is greater in the enlarged wellbore 75f than in original wellbore 75e. This extra displacement, allows offset angle <NUM> between the longitudinal axis <NUM> of the downhole end of wellbore 75e and the longitudinal axis <NUM> of the drill bit <NUM> to be less negative than the offset angle <NUM> in the original diameter wellbore 75e. That is, the negative tilt angle <NUM> is reduced and in some instances reduced such that the offset angle <NUM> becomes a positive tilt angle. Weight-on-bit acting with a less negative, or positive, offset angle <NUM> helps the side force <NUM> reacted by the drill bit <NUM> to act with the side cutting capability of the drill bit <NUM> to create additional curvature of wellbore 75f. The drill bit <NUM> generally creates a deviated wellbore with a larger dogleg capability due to the enlarged wellbore 75f than is possible in the original diameter wellbore 75e. Deliberately enlarging the diameter of the wellbore <NUM> provides more displacement of the pads <NUM>. That is, the pads <NUM> can extend further away from the tool <NUM> when the tool <NUM> passes through the enlarged diameter wellbore 75f than when the tool <NUM> passes through the original diameter wellbore <NUM>. This is acceptable up to the physical limit of extension of pads <NUM>.

In an exemplary embodiment, when the enlarged diameter 75f is approximately <NUM> (<NUM> inches) larger than the original diameter 75e, the actual dogleg capability is approximately <NUM> deg/<NUM> or <NUM> ft. greater than the maximum dogleg capability of the BHA <NUM> in the original wellbore diameter 75e. Thus, during the step <NUM>, the BHA <NUM> creates a second curved section having a radius of curvature that is less than the radius of curvature associated with the first curved section. That is, the second curved section has a greater dogleg than the first curved section.

In order to drill a relatively straight wellbore, the step <NUM> includes the sub steps of the steps 205a, and sweeping the pad or pads <NUM> that see the force <NUM> from actuator or actuators <NUM> around the wellbore in the original diameter wellbore 75e at step 215a such that the pad force <NUM> is never stationary in one orientation. <FIG> and <FIG> illustrate the BHA <NUM> while in the first configuration while drilling a generally straight section of the wellbore <NUM>. As previously noted, the drill bit <NUM> creates a portion of the wellbore <NUM> having the original diameter 75e that corresponds to the diameter <NUM> of the drill bit <NUM> at the step 205a. When drilling a straight section of the wellbore, the original diameter 75e of the wellbore <NUM> not only corresponds to the diameter <NUM> of the drill bit <NUM>, but may be dependent upon other factors as well such as for example distance between the drill bit <NUM> and the rotary steerable tool <NUM>, etc. The reamer cutting structures 125a and 125b are retracted during the step 205a. At the step 215a, the orientation of the force <NUM> on pads <NUM> is swept around the wellbore <NUM> as the drill string <NUM> and the BHA <NUM> (including rotary steerable tool <NUM> and the drill bit <NUM>) rotate. In one embodiment, the rotary steerable tool <NUM> does not rotate but the drill bit <NUM> does. In another embodiment, the mud motor <NUM> is placed in the BHA <NUM> above the rotary steerable tool <NUM> such that the rotary steerable tool <NUM> and the drill bit <NUM> rotate faster than the drill string <NUM>. In another embodiment with the mud motor <NUM> placed in the BHA <NUM> above the rotary steerable tool <NUM>, the rotary steerable tool <NUM> does not rotate, but the drill bit <NUM> rotates faster than the drill string <NUM>. The orientation of the force <NUM> on pads <NUM> can be swept around the wellbore <NUM> at the same speed as the drill bit <NUM>, slower than drill bit <NUM>, faster than drill bit <NUM>, and even in the opposite rotary direction. Additionally, the orientation of the force <NUM> on pads <NUM> can be swept back and forth in an arc to achieve a relatively straight wellbore or to reduce effective dogleg capacity. Generally, the steps of 205a and 215a occur simultaneously during rotational drilling to create a straight section (i.e., tangent, horizontal, vertical, or lateral) section of the wellbore <NUM>. At the steps <NUM> and <NUM>, and when the increased dogleg capability associated with an enlarged diameter 75f is not needed, such as drilling straight or steering with a reduced dogleg, the reamer <NUM> is in the first configuration, reducing dogleg capability. Reduced dogleg capability leads to improved steering control, less wellbore tortuosity and less wellbore curvature. These features reduce forces and stress on the drill bit <NUM>, the rotary steerable tool <NUM>, and other tools within the BHA <NUM> such as stabilizers, pads, etc. Weight transfer to the drill bit <NUM> is also improved due to the reduction in friction from the reduced contact forces, which enables longer horizontal/lateral sections of the wellbore <NUM>.

Use of the BHA <NUM> and/or the method <NUM> allows for increased dogleg capability when necessary, but otherwise reduces friction from the reduced contact forces between a wall of the wellbore and the BHA <NUM> and/or the drill string <NUM>, which improves the weight transfer to the drill bit <NUM> and enables longer horizontal/lateral sections of the wellbore <NUM>. Wellbore tortuosity is also decreased with the lower dogleg capability (i.e., when the reamer <NUM> is in the first configuration), which better enables the casing and completion equipment to be run downhole.

The BHA <NUM> and/or the method <NUM> results in the ability to have a high dogleg capability for the curved section 75b of the wellbore <NUM> and a reduced dogleg capability for straighter sections of the wellbore <NUM> thereby creating a multi-dogleg-capability BHA <NUM>. The multi-dogleg-capability BHA <NUM> reduces equipment failures, non-productive time, and potentially the loss of a well. The multi-dogleg-capability BHA <NUM> reduces frictional drag, which improves weight transfer to the drill bit <NUM>, which in turn supports drilling ahead, drilling long tangent or horizontal/lateral sections beyond the curve, and running casing and completions equipment. Generally, wellbore tortuosity creates higher contact forces with the BHA <NUM> and drill string <NUM>, increases frictional drag, and inhibits weight transfer to the drill bit <NUM>. This, in turn, can impede drilling ahead, drilling long tangent or horizontal/lateral sections beyond the curve, and running casing and completions equipment. Use of the BHA <NUM> and/or the method <NUM> reduces the wellbore tortuosity.

Deliberately enlarging the wellbore <NUM> at or near the drill bit <NUM> to increase dogleg capability when needed is useful in many situations. Higher dogleg capability is typically needed to drill the curved section 75b of a wellbore <NUM> compared to other sections of the well bore such as vertical, tangent, and horizontal. Using the BHA <NUM> to deliberately enlarge the diameter of the wellbore <NUM> at or near the drill bit <NUM> allows the curved section 75b of the wellbore <NUM> to be drilled at the desired, higher dogleg. This is in part because the flexible collar <NUM> reduces the bending moment exerted or applied to each of the rotary steerable tool <NUM> and the drill bit <NUM>, thereby allowing the side force <NUM> to more effectively steer the drill bit <NUM> instead of trying to overcome the forces pushing the drill bit <NUM> in a trajectory that is outside the curvature of the desired wellbore curvature. Other sections of the wellbore <NUM> that require lower dogleg capability (i.e., sections 75a, 75c, 75d, etc.) would be drilled without deliberately enlarging the diameter of the wellbore <NUM>. The lower dogleg capability (e.g., when the reamer <NUM> is in the first configuration) reduces forces and stress on the drill bit <NUM>, rotary steerable tool <NUM>, mud motor, stabilizers, pads, etc. for the majority of the wellbore.

Other situations where increased dogleg capability on demand may be needed are: when the rotary steerable tool <NUM> is not generating the dogleg expected, perhaps due to the formation being drilled, or a tool problem or to counter drill bit walk tendencies; or if the geology of interest is not at the depth expected and a quick response is desired; or sudden changes in geology are encountered, such as faults.

In some embodiments, the BHA <NUM> and/or the method <NUM> reduces the number of bitruns for each well, as the BHA <NUM> is capable of creating a variety of segments of the well (e.g., the vertical section 75a, the curved section 75b, the tangent section 75c, the horizontal section 75d) while reducing stresses on the BHA <NUM> and reducing wellbore tortuosity.

Any variety of wellbore diameter enlarging tools can be used in place of the reamer <NUM>. In some cases, a single activation of the reamer <NUM> may be acceptable. For example, the reamer may remain deactivated at the beginning of a bitrun to drill a straight (vertical, tangent, horizontal) section or a lower dogleg curve section, then activated to allow reamer cutting structures 125a and 125b to move outward for a higher dogleg curve section. Examples of single, irreversible activation of the reamer <NUM> include the use of shear pins based on high differential pressure and ball drops. In other cases, a single deactivation of the reamer <NUM> may be acceptable. For example, once the curved section 75b is drilled while the reamer <NUM> is in the second configuration, the reamer <NUM> may be irreversibly deactivated to the first configuration, such that the reamer cutting structures 125a and 125b are moved inward to prevent enlargement of the wellbore <NUM> for the remainder of the bitrun in order to drill with lower dogleg capability. Examples of single, irreversible deactivation of the reamer <NUM> include the use of ball drops.

Returning to <FIG>, in some embodiments, a control unit <NUM> is provided to control the BHA <NUM>, under conditions to be described below. In one exemplary embodiment, the control unit <NUM> is connected to, and/or disposed within, the rotary steerable tool <NUM>, although it may be located anywhere along the BHA <NUM>. In one exemplary embodiment, the control unit <NUM> includes one or more measurement-while-drilling (MWD) systems, one or more logging-while-drilling (LWD) systems, and/or any combination thereof. In one exemplary embodiment, the control unit <NUM> includes one or more processors 270a, a memory or computer readable medium 270b operably coupled to the one or more processors 270a, and a plurality of instructions stored in the computer readable medium 270b and executable by the one or more processors 270a. A surface control unit or system <NUM> is in two-way communication with the control unit <NUM>. In one exemplary embodiment, the surface control system <NUM> includes one or more processors 275a, a memory or computer readable medium 275b operably coupled to the one or more processors 275a, and a plurality of instructions stored in the computer readable medium 275b and executable by the one or more processors 275a. During operation, the control unit <NUM> positioned in the wellbore <NUM> communicates with the surface control system <NUM>, sending directional survey information to the surface control system <NUM> using a telemetry system. The telemetry system may utilize mud-pulse telemetry or the like. In any event, the control unit <NUM> may transmit to the surface control system <NUM> information about the direction, inclination and orientation of the BHA <NUM>. In one exemplary embodiment, the surface control system <NUM> controls the BHA <NUM> via the control unit <NUM>. During operation and when the reamer <NUM> is operably coupled to the control unit <NUM> such that the control unit <NUM> controls the actuation of the reamer cutting structures 125a and 125b, the control unit <NUM> actuates the reamer cutting structures 125a and 125b to place the reamer <NUM> in the first configuration, the second configuration, third configuration that is different from both the first and second configuration and that also enlarges the diameter of the wellbore <NUM>, back to the first configuration, and back to the second configuration, or any combination thereof. That is, the reamer <NUM> may have a variety of configurations that correspond with a variety of wellbore diameters. In one exemplary embodiment, one or both of the control unit <NUM> and the surface control system <NUM> are part of a downlink system that allows for automatic steering along a fixed or preprogrammed trajectory towards the desired target location in the formation <NUM>. In one exemplary embodiment, to control the BHA <NUM> using the surface control system <NUM> and/or the control unit <NUM>, the one or more processors 270a and/or the one or more processors 275a execute the plurality of instructions stored in the computer readable medium 270b and/or the plurality of instructions stored in the computer readable medium 275b.

In an exemplary embodiment, creating a straight section or a generally straight section of the wellbore includes creating a section of the wellbore that is intended to be straight but includes some deviations.

In an exemplary embodiment, the steps <NUM>, <NUM>, and <NUM> may occur in any order.

In several exemplary embodiments, the method <NUM> may be implemented in whole or in part by a computer. The plurality of instructions stored on the computer readable medium 270b, the plurality of instructions stored on the computer readable medium 275b, a plurality of instructions stored on another computer readable medium, and/or any combination thereof, may be executed by a processor to cause the processor to carry out or implement in whole or in part the method <NUM>, and/or to carry out in whole or in part the above-described operation of the BHA <NUM>. In several exemplary embodiments, such a processor may include the one or more processors 270a, the one or more processors 275a, one or more additional processors, and/or any combination thereof.

Thus, a method has been described. Embodiments of the method may generally include drilling a wellbore along a trajectory using a bit; reaming the diameter of a portion of the drilled wellbore to enlarge the portion of the wellbore; and altering the trajectory of the bit by applying a lateral force to the enlarged diameter wellbore. For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
Reducing a negative tilt angle that is defined between a longitudinal axis of the bit and a longitudinal axis of the wellbore.

Reducing the negative tilt angle includes bending a longitudinally extending flexible collar that is coupled between a rotary steerable system and a drill string, wherein the flexible collar has a lower bending stiffness than the rotary steerable system.

Bending the longitudinally extending flexible collar reduces a bending moment exerted on the rotary steerable system.

Reducing the negative tilt angle increases a dogleg of the wellbore.

Simultaneously drilling the wellbore using the bit such that the wellbore has an original diameter; applying the lateral force to the original diameter wellbore; and displacing a portion of a longitudinally extending flexible collar when the flexible collar is positioned in the original diameter wellbore, to create a first curved section of the wellbore having a first radius of curvature.

Simultaneously drilling the wellbore, reaming the diameter of the portion of the drilled wellbore to enlarge the portion of the wellbore, applying the lateral force to the enlarged diameter wellbore, and displacing the portion of the longitudinally extending flexible collar when the flexible collar is positioned in the enlarged diameter wellbore, to create a second curved section of the wellbore that has a second radius of curvature that is less than the first radius of curvature.

Drilling the wellbore along the trajectory using the bit, reaming the diameter of the portion of the drilled wellbore to enlarge the portion of the wellbore, and altering the trajectory of the bit by applying the lateral force to the enlarged diameter wellbore occur simultaneously to steer the bit.

Creating a positive tilt angle that is defined between the longitudinal axis of the bit and the longitudinal axis of the wellbore.

Thus, a method has been described. Embodiments of the method may generally include extending a drilled wellbore while simultaneously reaming a portion of the drilled wellbore; and continuing to extend the wellbore while simultaneously applying a lateral force to the reamed portion of the drilled wellbore. For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
Bending, within the reamed portion of the wellbore, a longitudinally extending flexible collar that is coupled between a rotary steerable system and a drill string, wherein the flexible collar has a lower bending stiffness than the rotary steerable system.

Reducing a bending moment exerted on at least a portion of a bottom hole assembly that extends within the reamed portion of the drilled wellbore.

Extending a drilled wellbore such that the wellbore has an original diameter while simultaneously applying a lateral force to the original diameter wellbore via a rotary steerable system.

Applying the lateral force to the original diameter wellbore via the rotary steerable system results in a first negative tilt angle defined by a longitudinal axis of the bit and a longitudinal axis of the wellbore.

Applying the lateral force to the enlarged diameter wellbore results in a second negative tilt angle defined by the longitudinal axis of the bit and the longitudinal axis of the wellbore; and wherein the second negative tilt angle is less than the first negative tilt angle.

Reaming a portion of the drilled wellbore includes radially extending a cutting structure in a direction perpendicular to a longitudinal axis of a reamer from a retracted position such that an outermost diameter of the reamer is greater than an outer dimension of the bit.

A rotary steerable system is coupled to a drill string that extends within the wellbore; wherein the method further includes allowing lateral displacement of a portion of the rotary steerable system within the reamed portion of the drilled wellbore to reduce a negative tilt angle of the bit; and wherein the negative tilt angle is defined by a longitudinal axis of the bit and a longitudinal axis of the wellbore.

The bit and the rotary steerable system form a portion of a push-the-bit bottom hole assembly and wherein enlarging the diameter of the wellbore increases a dogleg capability associated with the push-the-bit bottom hole assembly.

Thus, a push-the-bit bottom hole assembly has been described. Embodiments of the push-the-bit bottom hole assembly may generally include a bit; a rotary steerable system coupled to the bit, wherein the rotary steerable system includes an actuator that extends radially in a direction perpendicular to a longitudinal axis of the rotary steerable system to exert a lateral force on the bit; and a reamer positioned between a portion of the bit and a portion of the rotary steerable system. For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
A longitudinally extending flexible collar, wherein the rotary steerable system is positioned between the longitudinally extending flexible collar and the bit, and wherein the flexible collar has a lower bending stiffness than the rotary steerable system.

The reamer is movable between a first configuration and a second configuration; wherein, when in the first configuration, a cutting structure that is capable of extending radially in a direction perpendicular to a longitudinal axis of the reamer is retracted; wherein, when in the second configuration, the cutting structure is radially extended to form an outermost diameter of the reamer; and wherein, when in the second configuration, the outermost diameter of the reamer is greater than an outer diameter of the bit.

When in the first configuration, the push-the-bit bottom hole assembly has a first maximum dogleg capability.

When in the second configuration, the push-the-bit bottom hole assembly has a second maximum dogleg capability that is greater than the first maximum dogleg capability.

Thus, a method has been described. Embodiments of the method may generally include extending a wellbore using a drill bit; enlarging a diameter of the wellbore using a tool; and applying a lateral force to a rotary steerable tool when the rotary steerable tool is positioned in the enlarged diameter wellbore using a pad that extends radially from the rotary steerable tool; wherein the tool, the rotary steerable tool, and the drill bit are coupled together such that the tool is positioned between a portion of the drill bit and a portion of the rotary steerable tool. For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
Reducing a negative tilt angle that is defined between a longitudinal axis of the drill bit and a longitudinal axis of the wellbore.

Reducing the negative tilt angle comprises bending a longitudinally extending flexible collar that is coupled between the rotary steerable tool and a drill string, wherein the flexible collar has a lower bending stiffness than the rotary steerable tool.

Bending the longitudinally extending flexible collar reduces a bending moment exerted on the rotary steerable tool.

Simultaneously extending the wellbore using the drill bit such that the wellbore has an original diameter; applying the lateral force to the rotary steerable tool when the rotary steerable tool is positioned in the original diameter wellbore; and displacing a portion of a longitudinally extending flexible collar, when the flexible collar is positioned in the original diameter wellbore, to create a first curved section of the wellbore having a first radius of curvature; and simultaneously extending the wellbore using the drill bit, applying the lateral force to the rotary steerable tool when the rotary steerable tool is positioned in the enlarged diameter wellbore, and displacing the portion of the longitudinally extending flexible collar, when the flexible collar is positioned in the enlarged diameter wellbore, to create a second curved section of the wellbore that has a second radius of curvature that is less than the first radius of curvature; wherein the flexible collar is coupled between the drill bit and a drill string.

Extending the wellbore using the drill bit, enlarging the diameter of the wellbore, and applying the lateral force to the rotary steerable tool when the rotary steerable tool is positioned in the enlarged diameter wellbore occur simultaneously to steer the drill bit.

The tool is a reamer and enlarging the diameter of the wellbore comprises activating the reamer.

Creating a positive tilt angle that is defined between a longitudinal axis of the drill bit and a longitudinal axis of the wellbore.

Thus, a method has been described. Embodiments of the method may generally include extending a wellbore, using a drill bit and a rotary steerable tool comprising a pad that extends in a radial direction, while simultaneously enlarging a diameter of the wellbore using a reamer positioned between a portion of the drill bit and a portion of the rotary steerable tool. For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
Applying a lateral force to the rotary steerable tool when the rotary steerable tool is positioned in the enlarged diameter wellbore using the pad.

Bending, within the enlarged diameter wellbore, a longitudinally extending flexible collar that is coupled between the rotary steerable tool and a drill string, wherein the flexible collar has a lower bending stiffness than the rotary steerable tool.

Bending, within the enlarged diameter wellbore, the longitudinally extending flexible collar reduces a bending moment exerted on the rotary steerable tool.

Extending the wellbore, using the drill bit and the rotary steerable tool, such that the wellbore has an original diameter while simultaneously applying a lateral force to the rotary steerable tool when the rotary steerable tool is positioned in the original diameter wellbore.

Applying the lateral force to the rotary steerable tool when the rotary steerable tool is positioned in the original diameter wellbore results in a first negative tilt angle defined by a longitudinal axis of the drill bit and a longitudinal axis of the wellbore.

Applying the lateral force to the rotary steerable tool when the rotary steerable tool is positioned in the enlarged diameter wellbore results in a second negative tilt angle defined by the longitudinal axis of the drill bit and the longitudinal axis of the wellbore.

The second negative tilt angle is less than the first negative tilt angle.

The reamer is movable between a first configuration and a second configuration.

When in the first configuration, a cutting structure that is capable of extending radially in a direction perpendicular to a longitudinal axis of the reamer is retracted.

When in the second configuration, the cutting structure is radially extended to form an outermost diameter of the reamer.

When in the second configuration, the outermost diameter of the reamer is greater than an outer dimension of the drill bit.

The rotary steerable tool is coupled to a drill string that extends within the wellbore.

Allowing a lateral displacement of a portion of the rotary steerable tool within the enlarged diameter wellbore to reduce a negative tilt angle of the drill bit in a drilling direction.

The negative tilt angle is defined by a longitudinal axis of the drill bit and a longitudinal axis of the wellbore.

The drill bit and the rotary steerable tool form a portion of a push-the-bit bottom hole assembly and wherein enlarging the diameter of the wellbore increases a dogleg capability associated with the push-the-bit bottom hole assembly.

Thus, a push-the-bit bottom hole assembly has been described. Embodiments of the push-the-bit bottom hole assembly may generally include a drill bit; a rotary steerable tool coupled to the drill bit, wherein the rotary steerable tool comprises a pad that extends radially in a direction perpendicular to a longitudinal axis of the rotary steerable tool to exert a lateral force on the drill bit; and a reamer positioned between a portion of the drill bit and a portion of the rotary steerable tool. For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
The reamer is a multi-actuation reamer.

The reamer is movable between a first configuration and a second configuration; wherein, when in the first configuration, a cutting structure that is capable of extending radially in a direction perpendicular to a longitudinal axis of the reamer is retracted; wherein, when in the second configuration, the cutting structure is radially extended to form an outermost diameter of the reamer; and wherein, when in the second configuration, the outermost diameter of the reamer is greater than an outer diameter of the drill bit.

A longitudinally extending flexible collar, wherein the rotary steerable tool is positioned between the longitudinally extending flexible collar and the drill bit, and wherein the flexible collar has a lower bending stiffness than the rotary steerable tool.

The foregoing description and figures are not drawn to scale, but rather are illustrated to describe various embodiments of the present disclosure in simplistic form. Although various embodiments and methods have been shown and described, the disclosure is not limited to such embodiments and methods and will be understood to include all modifications and variations as would be apparent to one skilled in the art. Therefore, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Accordingly, the intention is to cover all modifications, equivalents and alternatives falling within the scope of the disclosure as defined by the appended claims.

In several exemplary embodiments, while different steps, processes, and procedures are described as appearing as distinct acts, one or more of the steps, one or more of the processes, and/or one or more of the procedures could also be performed in different orders, simultaneously and/or sequentially. In several exemplary embodiments, the steps, processes and/or procedures could be merged into one or more steps, processes and/or procedures.

It is understood that variations may be made in the foregoing without departing from the scope of the disclosure. Furthermore, the elements and teachings of the various illustrative exemplary embodiments may be combined in whole or in part in some or all of the illustrative exemplary embodiments. In addition, one or more of the elements and teachings of the various illustrative exemplary embodiments may be omitted, at least in part, and/or combined, at least in part, with one or more of the other elements and teachings of the various illustrative embodiments.

In several exemplary embodiments, one or more of the operational steps in each embodiment may be omitted. Moreover, in some instances, some features of the present disclosure may be employed without a corresponding use of the other features. Moreover, one or more of the above-described embodiments and/or variations may be combined in whole or in part with any one or more of the other above-described embodiments and/or variations.

Claim 1:
A method for constructing a wellbore (<NUM>), comprising:
drilling a wellbore (<NUM>) along a trajectory using a bit (<NUM>);
reaming the diameter of a portion of the drilled wellbore (<NUM>) to enlarge the portion of the wellbore (<NUM>); and
using a rotary steerable tool (<NUM>) coupled to the bit (<NUM>), wherein a plurality of actuators (<NUM>) are coupled to the rotary steerable tool (<NUM>) and configured to independently and selectively extend radially in a direction perpendicular to a longitudinal axis of the rotary steerable tool (<NUM>),
altering the trajectory of the bit (<NUM>) by applying a lateral force to the enlarged diameter wellbore (<NUM>), and further comprising reducing a negative tilt angle (<NUM>) that is defined between a longitudinal axis of the bit and a longitudinal axis of the wellbore,
wherein reducing the negative tilt angle (<NUM>) increases a dogleg of the wellbore.