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 tool or a mud motor that forms a portion of the bottom hole assembly ("BHA") is used to steer the BHA to create a curved section of the wellbore. Often, the rotary steerable tool and mud motor are fixed, when run downhole, at a given bend angle or displacement that embodies the maximum dogleg capability of the bottom hole assembly. There are instances when the maximum dogleg capability is not needed, such as when the drill string is creating a generally straight section of the wellbore and/or when the radius of a required turn is not as tight as the radius associated with the maximum dogleg capability. In these instances and when a point-the-bit bottom hole assembly with a fixed maximum dogleg capability is used, large lateral forces are exerted on the drill bit, bearings, stabilizers, pads, etc., resulting in very high stresses on housings, shafts, mandrels, internal connections, external connections, etc. of the rotary steerable tool or mud motor. These high forces and stresses can lead to equipment failures, non-productive time, and potentially the loss of a well. In addition, transitions from steering to straight drilling and vice-versa impart significant tortuosity to the wellbore.

<CIT> discloses drilling with casing. <CIT> discloses a near-bit borehole opener tool and a method of reaming. <CIT> discloses a flexible directional drilling apparatus and a method. <CIT> discloses directional casing-while-drilling. <CIT> discloses an automated steerable hole enlargement drilling device and methods. <CIT> discloses an intelligent reamer for rotary/sliding drilling system and a method.

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.

Illustrative embodiments and related methods of the present disclosure are described below as they might be employed using a point-the-bit bottom hole 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 point-the-bit bottom hole assembly having a reamer that is extending, or forming, a wellbore from an offshore oil or gas platform, 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" 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. Also, even though <FIG> and <FIG> depicts 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 point-the-bit bottom hole assembly <NUM>, or the BHA <NUM>, is coupled to the lower or distal end of the drill string <NUM> and includes a drill bit <NUM> that is operably coupled to a steering tool <NUM>, such as a mud motor or a rotary steerable system, suitable for selectively changing a direction of drilling by the BHA <NUM>. A reamer <NUM> also forms a portion of the BHA <NUM> and is coupled to, and positioned between, the drill bit <NUM> and the steering 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 steering tool <NUM>; the reamer <NUM> being built into or forming another tool that is positioned between the drill bit <NUM> and the steering tool <NUM>; and the reamer <NUM> being built into a lower end of the steering tool <NUM>. Generally, the reamer <NUM> is positioned downhole from the "bend" in the steering 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. Generally, the reamer <NUM> includes reamer cutting structures 100a and 100b that, when activated, extend radially in a direction perpendicular to a longitudinal axis of the reamer <NUM> to contact a wall of the wellbore <NUM> and enlarge the diameter of the wellbore <NUM>. While only two reamer cutting structures are shown in <FIG> and <FIG>-<NUM>, the reamer <NUM> may include any number of reamer cutting structures spaced circumferentially and/or longitudinally along the reamer <NUM>. The BHA <NUM> is a point-the-bit system in that a central axis 95a of the steering tool <NUM> (shown in <FIG>) creates a bend angle <NUM> relative to a central axis 90a of the drill bit <NUM>. That is, the bend angle <NUM> is defined between the central axis 90a and the central axis 95a. In some instances, the bend angle <NUM>, among other factors such as a bit-to-bend distance, placement of the steering tool <NUM> relative to other tools that form the BHA <NUM> etc., defines a dogleg capability of the BHA <NUM>. The dogleg achieved by a particular steering tool <NUM> will depend at least in part on the bend angle <NUM>, and may also depend on a bit-to-bend distance, placement of the steering tool <NUM> relative to other tools that form the BHA <NUM> etc. The dogleg capability associated with the BHA <NUM> is the measure of the amount of change in the inclination, and/or azimuth of a wellbore, usually expressed in degrees per <NUM> feet of course length that the BHA <NUM> is capable of creating during steering of the BHA <NUM>. Hence, the dogleg capability of a particular steering tool <NUM> depends at least in part on a maximum bend angle, and may further depend on the bit-to-bend distance, placement of the steering tool <NUM> relative to other tools that form the BHA <NUM> etc..

Often, the wellbore <NUM> will have a planned trajectory such that the curved section 75b is associated with a dogleg, such as for example <NUM> degrees per <NUM> ft. In these instances, and when the bend angle <NUM> of the steering tool <NUM> is fixed prior to being run downhole, the bend angle <NUM> (along with the other factors that determine dogleg capability) is often set to be in excess of what is needed to accomplish the <NUM> degrees per <NUM> ft. Thus, the bend angle <NUM> is often capable of producing a dogleg capability of, for example, <NUM> or <NUM> degrees per <NUM> ft. Having excess dogleg capability provides the capacity to catch up to the planned wellbore path or trajectory if the drilled wellbore gets behind the plan for any reason, but also can result in the multiple transitions from steering to drilling straight sections in order to create a curved section that has a dogleg that is less than the fixed dogleg capability that is associated with the BHA <NUM>. Activating the reamer <NUM> to enlarge a diameter of the wellbore decreases the fixed dogleg capability associated with the BHA <NUM> to reduce the number of transitions from steering to drilling straight when creating a curved section and to reduce the stresses exerted on the BHA <NUM> during such transitions and when drilling straight sections.

In some embodiments and generally when the steering tool <NUM> is a mud motor, the drilling string <NUM> is not rotated during steering of the BHA <NUM> such that the orientation of the steering tool <NUM> in the wellbore <NUM> is stationary. However, in other embodiments and generally when the steering tool <NUM> is a rotary steerable system, the drilling string <NUM> is rotated while steering of the BHA <NUM>, but the orientation of the steering tool <NUM> in the wellbore <NUM> is stationary. Generally, when drilling a straight section of the wellbore <NUM>, the drilling string <NUM> and the BHA <NUM> rotate together or at least the orientation of the BHA <NUM> in the wellbore <NUM> is not stationary.

In an exemplary embodiment, as illustrated in <FIG> with continuing reference to <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 a first configuration while steering the BHA <NUM> at step <NUM>; creating a second curved section of the wellbore <NUM> using the BHA <NUM> while the BHA <NUM> is in a second configuration while steering the BHA <NUM> at step <NUM>; and creating a straight or a generally straight section (e.g., vertical, tangent, horizontal, lateral) of the wellbore <NUM> using the BHA <NUM> while the BHA <NUM> is in the second 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 110a and laterally offsetting the steering tool <NUM> in the original diameter 75e wellbore at step 110b. <FIG> illustrates the BHA <NUM> in the first configuration while drilling a curved section of the wellbore <NUM>. When in the first configuration, the reamer cutting structures 100a and 100b are in a retracted position such that the reamer cutting structures 100a and 100b do not enlarge the diameter of the wellbore <NUM>. To create a curved section of the wellbore <NUM> the drill bit <NUM> creates a portion of the wellbore <NUM> having the original diameter 75e that corresponds to a diameter of the drill bit <NUM>. In some embodiments, the original diameter 75e is not equal to the diameter of the drill bit <NUM>, but at least a function of the diameter of the drill bit <NUM>. As the reamer <NUM> of the BHA <NUM> is placed or remains in the first configuration, the reamer cutting structures 100a and 100b do not enlarge the original diameter 75e of the wellbore <NUM>. Placing, or allowing, the reamer <NUM> to stay in the first configuration restores, or otherwise results in the BHA <NUM> creating a first dogleg or portion of the wellbore that has a first radius of curvature. This first radius of curvature often corresponds to the fixed dogleg capability of the BHA <NUM>, which can include the excess dogleg capability. The central axis 95a of the steering tool <NUM> is laterally offset from a center of the wellbore <NUM> by a distance <NUM>, with the center of the wellbore <NUM> illustrated as the line having a reference numeral <NUM> in <FIG> ("center <NUM>"). Thus, a contact point 95b of the steering tool <NUM> is also offset from the center <NUM> and results in a side-cutting force or leverage applied to the drill bit <NUM> to enable laterally drilling while also drilling axially. Generally, the steps of 110a and 110b occur simultaneously.

When it is desired to create a portion of the wellbore that has a radius of curvature that is greater than the first radius of curvature, the reamer cutting structures 100a and 100b 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>. The enlarged diameter 75f is greater than the original diameter 75e. Generally, the reduction of dogleg, or the increase in the radius of curvature is a function of the amount of wellbore "overage", or difference between the enlarged diameter 75f and the original diameter 75e. Thus, an outermost diameter of the reamer <NUM> when the reamer <NUM> is in the second configuration is sized to create the desired reduction of dogleg, or increase in the radius of curvature. In some embodiments, the reamer cutting structures 100a and 100b 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 <NUM>10a, enlarging the diameter of the wellbore <NUM> to the enlarged diameter 75f at step 115a, and laterally offsetting the steering tool <NUM> in the enlarged diameter 75f of the wellbore <NUM> at step 115b. <FIG> illustrates the BHA <NUM> in the second configuration and drilling a curved section of the wellbore <NUM>. To create the second curved section of the wellbore <NUM> that has a radius of curvature that is greater than the first radius of curvature, the drill bit <NUM> creates a portion of the wellbore <NUM> having the original diameter 75e that corresponds to a diameter of the drill bit <NUM> at the step <NUM>10a. During the step <NUM>, the reamer <NUM> is placed in or is maintained in the second configuration. Thus, at step 115b, the reamer cutting structures 100a and 100b enlarges the diameter of the wellbore <NUM> from the original diameter 75e to the enlarged diameter 75f. At the step 115c, the steering tool <NUM> is laterally offset from the center <NUM> of the enlarged diameter 75f wellbore by a distance <NUM> from the center <NUM>. That is, the contact point 95b of the steering tool <NUM> is offset from the center <NUM> by the distance <NUM>, which is greater than the distance <NUM>. This generally results in a reduction of the side-cutting force or leverage applied to the drill bit <NUM> when laterally and axially drilling. Reducing the side-cutting force or leverage applied to the drill bit <NUM> increases the radius of curvature of the curved section being drilled and, effectively, reduces the dogleg capability of the BHA <NUM>. Generally, the steps of <NUM>10a, 115a, and 115b occur simultaneously.

The step <NUM> includes the sub steps of the steps 110a, 115a, and 115b, and is similar to the step <NUM> except that the step <NUM> occurs during steering of the BHA <NUM> and the step <NUM> occurs when the BHA <NUM> rotates to drill a straight section. Thus, the step <NUM> results in a generally straight section of the wellbore <NUM>. <FIG> illustrates the BHA <NUM> while in the second configuration and drilling a generally straight section of the wellbore <NUM> during rotational drilling, or when the BHA <NUM> is rotating. As previously noted, the drill bit <NUM> creates a portion of the wellbore <NUM> having the original diameter 75e that corresponds to a diameter of the drill bit <NUM> at the step 110a. During drilling of a straight section, the original diameter 75e of the wellbore <NUM> not only corresponds to the diameter of the drill bit <NUM>, but on other factors such as the bend angle <NUM>, distance between the drill bit <NUM> and the steering tool <NUM>, etc. The reamer <NUM> is placed in or is maintained in the second configuration during the step <NUM>, thus the reamer cutting structures 100a and 100b are extended. At step 115a, the reamer cutting structures 100a and 100b enlarge the diameter of the wellbore <NUM> from the original diameter 75e to the enlarged diameter 75f. At the step 115b, one central axis <NUM> of the BHA <NUM> has a maximum lateral offset from the center <NUM> of the enlarged diameter 75f wellbore <NUM> by a distance <NUM>. The distance <NUM> is greater when the BHA <NUM> is offset in the enlarged diameter 75f than the distance <NUM> when the BHA <NUM> is offset in the original diameter 75e. This enlargement of the wellbore diameter reduces the forces exerted on, and the stresses imposed on, the BHA <NUM> due to the bend angle <NUM> of the steering tool <NUM>. Generally, the steps of 110a, 115a, and 115b occur simultaneously during drilling of a tangent, vertical, or lateral section of the wellbore <NUM>.

Any variety of wellbore diameter enlarging tools can be used in place of the reamer <NUM>. In some cases, a single actuation of the reamer <NUM> may be acceptable. Once the curved section 75b is drilled using the first dogleg capability (i.e., the reamer <NUM> in the first configuration), the reamer <NUM> can be irreversibly activated such that the reamer cutting structures 100a and 100b are moved outward to enlarge the wellbore for the remainder of the bitrun in order to drill with a dogleg capability that is less than the first dogleg capability associated with the BHA <NUM> while in the first configuration. Single, irreversible activation of the reamer <NUM> includes the use of shear pins based on high differential pressure and ball drops.

In some embodiments, a control unit <NUM> as illustrated in <FIG> 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 steering 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 150a, a memory or computer readable medium 150b operably coupled to the one or more processors 150a, and a plurality of instructions stored in the computer readable medium 150b and executable by the one or more processors 150a. 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 155a, a memory or computer readable medium 155b operably coupled to the one or more processors 155a, and a plurality of instructions stored in the computer readable medium 155b and executable by the one or more processors 155a. 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 structure 100a, the control unit <NUM> actuates the reamer cutting structure 100a 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, 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 150a and/or the one or more processors 155a execute the plurality of instructions stored in the computer readable medium 150b and/or the plurality of instructions stored in the computer readable medium 155b.

While the bend angle <NUM> of the steering tool <NUM> described by way of example as being fixed when downhole, a tool may alternately include an adjustable bend angle, in which case, one or more embodiments of the steering tool <NUM> may have at least a straight mode with zero or near zero bend angle or displacement that can alternate between deflected and straight modes downhole. Optionally, the bend angle may be selectively adjustable to any of a range of values. Use of the steering tool <NUM>, when the steering tool <NUM> has the ability to alternate between deflected and straight modes downhole, in the method <NUM> results in the creation of intermediate dogleg capabilities when the diameter of the wellbore <NUM> is enlarged.

Moreover, another embodiment of the steering tool <NUM> has self-adjusting dogleg capabilities. Use of the steering tool <NUM>, when the steering tool <NUM> has self-adjusting dogleg capabilities, in the method <NUM> results in the reduction of the dogleg capability when the diameter of the wellbore <NUM> is enlarged.

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

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 150b, the plurality of instructions stored on the computer readable medium 155b, 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 150a, the one or more processors 155a, one or more additional processors, and/or any combination thereof.

As noted above, having excess dogleg capability provides the capacity to catch up to the planned wellbore path or trajectory if the drilled wellbore gets behind the plan for any reason. Use of the BHA <NUM> and/or the method <NUM> allows for the use of the excess bend angle when necessary, but otherwise reduces the effects of the excess bend angle when the excess bend angle is not required. Thus, when creating the curved section 75b, the BHA <NUM> creates a curved section having a radius of curvature that is greater than the radius of curvature associated the excess bend angle. This reduces the need for approximating the desired curve by creating alternate segments of the wellbore <NUM> when steering to create a curvature is too tight and drilling straighter segments. Thus, the BHA <NUM> and/or the method <NUM> reduces the number of transitions from steering drilling to straight drilling. Transitions from steering to straight drilling involves "back-bending", or forcing the bend angle <NUM> against the curvature created during steering as the bend angle <NUM> is rotated. Large lateral forces on the drill bit <NUM>, bearings, stabilizers, etc. are exerted during "back-bending" and result in very high stresses on housings, shafts mandrels, internal connections, external connections, etc. of the steering tool <NUM> (e.g., rotary steerable tool or mud motor). These high forces and stresses can lead to equipment failures, non-productive time, and potentially the loss of a well. In addition, transitions from steering to straight drilling and vice-versa can impart significant tortuosity to the wellbore <NUM>. Wellbore tortuosity creates higher contact forces with the BHA <NUM> and/or the drill string <NUM>, increasing frictional drag which inhibits weight transfer to the drill bit <NUM>, which impedes drilling ahead, drilling long tangent or horizontal/lateral sections beyond the curve, and running casing and completions equipment. Thus, as the BHA <NUM> and/or the method <NUM> reduces the number of transitions from steering to straight drilling, the BHA <NUM> and/or the method <NUM> reduces lateral forces on the BHA <NUM>, such as on the drill bit <NUM>, bearings, stabilizers, etc. and reduces the associated stresses on the BHA <NUM>, such as on housings, shafts, mandrels, internal connections, external connections, etc. Moreover, use of the BHA <NUM> and/or the method <NUM> reduces wellbore tortuosity. Moreover, when the drill string <NUM> extends within or through the enlarged diameter wellbore 75f, friction forces acting on the drill string <NUM> due to the contact with a wall of the wellbore <NUM> are generally less than friction forces acting on the drill string <NUM> when the drill string <NUM> extends through the original diameter wellbore 75e.

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 making corrections in other portions of the wellbore <NUM> thereby creating a multi-dogleg-capability BHA <NUM>. The multi-dogleg-capability <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 supports drilling ahead, drilling long tangent or horizontal/lateral sections beyond the curve, and running casing and completions equipment.

In some embodiments and if the diameter of the wellbore <NUM> is enlarged sufficiently, the effect of the bend angle <NUM> on dogleg capability can be completely overcome. Enlarging the diameter of the wellbore <NUM> provides room for the contact points, such as 95b of the steering tool <NUM> or other contact points of the BHA <NUM>, to shift laterally, which reduces the effect of the bend angle <NUM> on the side-cutting force or leverage applied to the drill bit <NUM> and thereby results in a lower dogleg capability.

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.

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.

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, the method comprising:
extending a wellbore (<NUM>) using a drill bit (<NUM>) and a mud motor (<NUM>) having a bend angle, while simultaneously enlarging a diameter of the wellbore (<NUM>) using a reamer (<NUM>) positioned between at least a portion of the drill bit (<NUM>) and at least a portion of the mud motor (<NUM>);
laterally offsetting the mud motor (<NUM>) in the enlarged diameter wellbore (<NUM>); and
using the drill bit (<NUM>) and the mud motor (<NUM>) to extend the wellbore (<NUM>), such that the wellbore has an original diameter (75e), while simultaneously laterally offsetting the mud motor (<NUM>) in the original diameter wellbore (<NUM>).