DOWNHOLE TOOL INCLUDING A TWO PART DRILLING AND RUNNING TOOL THAT COUPLES ITS SMALLER ASSEMBLY TO A CONVEYANCE

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application Ser. No. 63/738,275, filed on Dec. 23, 2024, entitled “TWO PART MILL WITH RETRACTABLE RUNNING AND ACTIVATION TOOL FOR WHIPSTOCK/DEFLECTOR,” commonly assigned with this application and incorporated herein by reference in its entirety.

BACKGROUND

The unconventional market is extremely competitive. The market is trending towards longer horizontal wells to increase reservoir contact. Multilateral wells offer an alternative approach to maximize reservoir contact. Multilateral wells include one or more lateral wellbores (e.g., secondary wellbores) extending from a main wellbore (e.g., primary wellbore). A lateral wellbore is a wellbore that is diverted from the main wellbore or another lateral wellbore.

Lateral wellbores are typically formed by positioning one or more deflector assemblies (e.g., whipstock assemblies) at desired locations in the main wellbore (e.g., an open hole section or cased hole section) with a running tool. The deflector assemblies are often laterally and rotationally fixed within the primary wellbore using a wellbore anchor.

BRIEF DESCRIPTION

Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

FIG. 1 is a schematic view of a well system designed, manufactured and operated according to one or more embodiments disclosed herein;

FIGS. 2A through 3B illustrate perspective views a downhole tool designed manufactured and/or operated according to one or more embodiments of the disclosure, at various different states of operation;

FIGS. 3C and 3D illustrate an external top view and a cross-sectional view of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure;

FIGS. 4A through 5H illustrate external side views and cross-sectional views of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure; and

FIGS. 6A through 13E illustrate cross-sectional views of a downhole tool designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure at different operational states.

DETAILED DESCRIPTION

In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawn figures are not necessarily, but may be, to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of certain elements may not be shown for the interest of clarity and conciseness. The present disclosure may be implemented in embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results. Moreover, all statements herein reciting principles and aspects of the disclosure, as well as specific examples thereof, are intended to encompass equivalents thereof. Additionally, the term “or,” as used herein, refers to a non-exclusive or, unless otherwise indicated.

Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” “fixed,” or any other like term describing an interaction between elements, is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.

Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or other like terms shall be construed as generally away from the bottom, terminal end of a well, regardless of the wellbore orientation; likewise, use of the terms “down,” “lower,” “downward,” “downhole,” “downstream,” or other like terms shall be construed as generally toward the bottom, terminal end of a well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical or horizontal axis. Unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water, such as ocean or fresh water.

Various values and/or ranges may be explicitly disclosed in certain embodiments herein. However, values/ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited. Similarly, values/ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited. In the same way, values/ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from a to b,” or, equivalently, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values, even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit, combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited. Similarly, any individual value disclosed herein may be combined with another individual value or range disclosed herein to form another range.

One challenge with constructing oil and gas wells in general, and multilateral wells in particular, is the costly rig time it takes to drill and complete a well. Reducing the number of trips required to construct a multilateral junction is a great way to reduce that time. Presented here is a new multilateral system that combines several new features to achieve a significant reduction in the number of trips needed to build a multilateral junction. If all new features are implemented, a level 5 multilateral junction could be completed in 1 trip devoted exclusively to the multilateral technology (MLT), or in certain instances even less than 1 trip.

One example idea is to run the mainbore completion (e.g., lower main bore screens) with a whipstock downhole on a two part drilling and running tool, and then anchor the whipstock and mainbore completion and establish an annular seal (e.g., if required). Then, one may release the two part drilling and running tool (e.g., such that the simple running tool becomes the milling assembly for milling the window from the main bore), mill the window exit, and drill a short rat hole and lateral wellbore. Once the lateral wellbore has been drilled, the lateral bore completion (e.g., lateral bore screens) may be dropped off, and on the same trip the upper part of the system (e.g., the whipstock) may be retrieved, exposing a set of seals for the junction to land in. At this point, the junction may be installed into the well, for example by using a deflector-less system to direct the lateral leg out the window exit.

The present disclosure also addresses the challenge of running a whipstock on the two part drilling and running tool. Certain designs for shear bolting a whipstock to a mill leave the shear bolt vulnerable to combined loading which can cause unreliable shear values. Also, certain shear bolts are less suitable for deploying the whipstock in very deep wells, for example because of the low shear ratings. In addition, the present disclosure allows for certain tools to be activated with pressure or flow, further improving efficiencies in the construction of a multilateral junction.

Trip savings have been one of the most important drivers of new technology development when it comes to multilateral technology. This system eliminates 4-5 trips that are currently required when constructing multilateral junctions of a trilateral well, which is an unprecedented leap forward in terms of operational efficiency over the current state of the art. This system also eliminates 2+ trips when constructing a multilateral junction of a single bilateral well, the benefits of which cannot be overstated.

FIG. 1 is a schematic view of a well system 100 designed, manufactured and/or operated according to one or more embodiments disclosed herein. The well system 100 includes a platform 120 (e.g., oil and gas platform) positioned over a subterranean formation 110 located below the earth's surface 115. The platform 120, in at least one embodiment, has a hoisting apparatus 125 and a derrick 130 for raising and lowering one or more downhole tools including pipe strings, such as a drill string 140. Although a land-based platform 120 is illustrated in FIG. 1, the scope of this disclosure is not thereby limited, and thus could potentially apply to offshore applications. The teachings of this disclosure may also be applied to other land-based well systems different from that illustrated.

As shown, a main wellbore 150 extends through the various earth strata, including the subterranean formation 110. The term “main” wellbore is used herein to designate a primary wellbore from which another secondary wellbore is drilled. It is to be noted, however, that a main wellbore 150 does not necessarily need to extend directly to the earth's surface, but could instead be a branch of yet another lateral wellbore. A casing string 160 may be positioned within the main wellbore 150, for example fixed within the main wellbore 150 using cement 165. The term “casing” is used herein to designate a tubular string used to line a wellbore. Casing may actually be of the type known to those skilled in the art as a “liner” and may be made of any material, such as steel or composite material and may be segmented or continuous, such as coiled tubing. The term “lateral” wellbore is used herein to designate a wellbore that is drilled outwardly from its intersection with another wellbore, such as a main wellbore. Moreover, a lateral wellbore may have another lateral wellbore drilled outwardly therefrom.

A whipstock assembly 190 according to one or more embodiments of the present disclosure may be positioned at a location in the main wellbore 150. Specifically, the whipstock assembly 190 could be placed at a location in the main wellbore 150 where it is desirable for a lateral wellbore 180 to exit. Accordingly, the whipstock assembly 190 may be used to support a downhole tool (e.g., not shown) that includes a two part drilling and running tool, which may be used to penetrate a window in the main wellbore 150. In at least one embodiment, once the window has been milled and a lateral wellbore 180 formed using the downhole tool including the two part drilling and running tool. Thereafter, the whipstock assembly 190 may be retrieved and returned uphole by a retrieval tool, in some embodiments in only a single trip.

In some embodiments, an anchor assembly 194 may be placed downhole in the main wellbore 150. The anchor assembly 194, in one or more embodiments, such as that shown, supports and axially anchors various different downhole tools within the main wellbore 150, including the whipstock assembly 190. In at least one other embodiment, the anchor assembly 194 additionally rotationally anchors the whipstock assembly 190 within the main wellbore 150, as may be important while drilling the lateral wellbore 180. The anchor assembly 194, in accordance with the disclosure, may be employed in a cased section of the main wellbore 150, such as shown, or may be located in an open-hole section of the main wellbore 150. As such, the anchor assembly 194 in at least one embodiment may be configured to resist at least 6,750 newton meters (Nm) (e.g., about 5,000 lb-ft) of torque. In yet another embodiment, the anchor assembly 194 may be configured to resist at least 13,500 newton meters (Nm) (e.g., about 10,000 lb-ft) of torque, and in yet another embodiment configured to resist at least 20,250 newton meters (Nm) (e.g., about 15,000 lb-ft) of torque. Similarly, the anchor assembly 194 may be configured to resist at least 1814 kg (e.g., about 4,000 lb) of axial force. In yet another embodiment, the anchor assembly 194 may be configured to resist at least 4536 kg (e.g., about 10,000 lb) of axial force, and in yet another embodiment the anchor assembly 194 may be configured to resist at least 6804 kg (e.g., about 15,000 lb) of axial force.

In one or more embodiments, the anchor assembly 194 is a latch coupling. In this embodiment, the latch coupling (e.g., a profile in the casing engages with a reciprocal profile in another downhole tool) anchors the whipstock assembly 190, and any other features hanging there below (e.g., main wellbore completion, screens, valves, etc.) in the main wellbore 150. Once the anchor assembly 194 reaches a desired location in the main wellbore 150, the reciprocal profile in the downhole tool (e.g., whipstock assembly 190) may be activated to engage with the profile in the casing string 160, thereby setting the anchor assembly 194.

Turning now to FIGS. 2A through 3B, presented are perspective views a downhole tool 200A designed manufactured and/or operated according to one or more embodiments of the disclosure, at various different states of operation. FIGS. 2A and 2B illustrate different views of the downhole tool 200A at its run-in-hole state, whereas FIGS. 3A and 3B illustrate different views of the downhole tool 200A in its milling and/or drilling state. In the embodiment of FIGS. 2A through 3B, the downhole tool 200A includes a conveyance 210. In at least this one embodiment, the conveyance 210 has a first conveyance end 212a and a second opposing conveyance end 212b. In one embodiment, the second opposing conveyance end 212b includes a conveyance coupling 214, for example having an outer width (W_C). The conveyance 210, in one or more embodiments, further includes a length (L_C). In at least one embodiment, the conveyance 210 forms at least a portion of a drill string, as might be used to drill one or more wellbores.

In the illustrated embodiment of FIGS. 2A through 3B, the downhole tool 200A additionally includes a two part drilling and running tool 220 coupled to the conveyance 210, for example via the conveyance coupling 214. The two part drilling and running tool 220 may have a variety of different configuration and remain within the scope of the disclosure. Nevertheless, in the illustrated embodiment of FIGS. 2A through 3B, the two part drilling and running tool 220 includes a larger bit assembly 230 and a smaller assembly 240. In at least this one embodiment, the larger bit assembly 230 has a first larger bit assembly end 232a, a second opposing larger bit assembly end 232b, a length (L_LB), and an outer width (W_LB). The larger bit assembly 230, in at least one embodiment, may additionally include a larger bit assembly coupling 233 configured to engage with and axially fix to the conveyance coupling 214 of the conveyance 210. The larger bit assembly, in one or more embodiments, may further include one or more cutting/milling features 234, for example as might be used to mill an opening in a casing and/or to drill a wellbore in a subterranean formation. Further to this one embodiment, the smaller assembly 240 has a first smaller assembly end 242a, a second opposing smaller assembly end 242b, a length (L_SA), and an outer width (W_SA). The smaller assembly 240, in at least one embodiment, may be a smaller bit assembly including one or more cutting features 244 along a nose thereof, for example as might be used to mill the opening in the casing and/or to drill the wellbore in the subterranean formation.

In accordance with one embodiment of the disclosure, the smaller assembly 240 is at least partially positioned within the larger bit assembly 230, the smaller assembly 240 configured to retract within the larger bit assembly 230 to form a combined bit assembly 280. In one or more embodiments, the smaller assembly 240 is configured to retract within the larger bit assembly 230 to form the combined bit assembly 280 while the two part drilling and running tool 220 is axially fixed to the conveyance 210. In even yet another embodiment, the smaller assembly 240 is configured to retract within the larger bit assembly 230 to form the combined bit assembly 280 while the larger bit assembly 230 of the two part drilling and running tool 220 is axially fixed to the conveyance 210. In yet another embodiment, the smaller assembly 240 is configured to retract within the larger bit assembly 230 and at least a portion of the conveyance 210 to form the combined bit assembly 280 while the two part drilling and running tool 220 is axially fixed to the conveyance 210. In further yet another embodiment, the smaller assembly 240 is configured to be able to rotate relative to the larger bit assembly 230 and the conveyance 210 as the smaller assembly 240 is retracting within the larger bit assembly 230. In even further yet another embodiment, the smaller assembly 240 is configured to retract within the larger bit assembly 230 to form the combined bit assembly 280 while the smaller assembly 240 of the two part drilling and running tool 220 is axially fixed to the conveyance 210.

The above scenarios that couple the larger bit assembly 230 to the conveyance 210 or couple the smaller assembly 240 to the conveyance 210, respectively, each have their advantages. For example, the scenario that couples the smaller assembly 240 to the conveyance 210 favors the run-in-hole part of the trip at the expense of the milling operation, because the larger bit assembly 230 and the smaller assembly 240 can become disconnected during the milling operation. Also, for the scenario that couples the smaller assembly 240 to the conveyance 210, the requirement for the smaller assembly 240 to fit inside the bore of the whipstock assembly means that the conveyance coupling of the conveyance 210 that couples to the larger bit assembly 230 is of significantly smaller diameter than the majority of the conveyance 210 (e.g., drill string). Thus, for the scenario that couples the smaller assembly 240 to the conveyance 210, this in turn makes the two part drilling and running tool 220 very flexible compared to a conventional drill string, and can result in poor window geometry due to early exit and/or excessive roll off.

In contrast, the scenario that couples the larger bit assembly 230 to the conveyance 210 favors the milling portion of the trip. For example, to accomplish this in the scenario that couples the larger bit assembly 230 to the conveyance 210, the larger bit assembly 230 is connected (e.g., directly) to the conveyance 210 (e.g., drill string) and the smaller assembly 240 may be on a retractable mandrel. One of the advantages of this scenario that couples the larger bit assembly 230 to the conveyance 210 is that the conveyance coupling of the conveyance 210, and thus the larger bit assembly 230, is not of significantly smaller diameter than the majority of the conveyance 210 (e.g., drill string). This, in turn, means that the excessive flexibility of the other scenario is not an issue. Furthermore, while the scenario that couples the larger bit assembly 230 to the conveyance 210 may also employ a retractable mandrel locking feature, weight on bit (e.g., itself) may also prevent the larger bit assembly 230 and smaller assembly 240 from disconnecting during milling. Notwithstanding the foregoing, the present disclosure envisions many different configurations for the downhole tool 200A, each having their own inherent previously unknown benefits over existing similar tools.

Further to the embodiment of FIGS. 2A through 3B, in at least one embodiment, the outer width (W_C) is at least 70 percent of the outer width (W_LB). In yet another embodiment, the outer width (W_C) is at least 80 percent of the outer width (W_LB). In even yet another embodiment, the outer width (W_C) is at least 90 percent of the outer width (W_LB), if not at least 98 percent of the outer width (W_LB). In further yet another embodiment, the outer width (W_C) ranges from 95 percent to 105 percent of the outer width (W_LB). The aforementioned relative values for the outer width (W_C) and the outer width (W_LB) are important to give the second opposing conveyance end 212b of the conveyance 210 the necessary rigidity to mill the opening in the casing (e.g., while having a sufficient inner diameter to flow a necessary amount of fluid therethrough).

Further to the embodiment of FIGS. 2A through 3B, the downhole tool 200A additionally includes a whipstock assembly 290a. In the illustrated embodiment, the whipstock assembly 290a is coupled with the two part drilling and running tool 220. In at least one embodiment, the whipstock assembly is coupled with the smaller assembly 240 of the two part drilling and running tool 220, and otherwise is not coupled with the larger bit assembly 230 of the two part drilling and running tool 220. For example, certain current designs for shear bolting a whipstock assembly to a mill leave the shear bolt vulnerable to combined loading, which can cause unreliable shear values. Also, current shear bolts are less suitable for deploying the whipstock assembly in very deep wells, for example because of the low shear ratings. Nevertheless, in yet another embodiment, the whipstock assembly 290a is coupled with the larger bit assembly 230 of the two part drilling and running tool 220, and otherwise is not coupled with the smaller assembly 240 of the two part drilling and running tool 220. In even yet another embodiment, the whipstock assembly 290a is coupled to both the smaller assembly 240 and the larger bit assembly 230 of the two part drilling and running tool 220. In at least one embodiment, the whipstock assembly 290a is a hybrid whipstock assembly, and thus may include certain features of a deflector assembly, such as seals.

The concept described in the above disclosure ensures reliable deployment of a whipstock assembly. Also, it greatly increases the mechanical ratings that can be achieved while running-in-hole, thereby allowing the whipstock assembly to be deployed into deeper or highly deviated wells. It would also be feasible to connect more components to the whipstock assembly without risking premature shear of the shear bolt. For a re-entry well where an anchor needs to be set first, the ability to apply pressure down the tool string would save a further trip by combining the anchor setting and first pass milling operations into one trip. Furthermore, an additional trip may be saved by being able to land the junction into the hybrid whipstock/deflector.

Given the foregoing, one embodiment of this disclosure is to have a two part drilling and running tool coupled to an end of the drill string. This two part drilling and running tool, in one embodiment, includes hollow mills at the end connected to the drill string with an enlarged bore to allow for internal components to fit. The dimensions may be such that large inside diameter (ID) drill string may be used without modification. In this embodiment, protruding from the two part drilling and running tool described above is a smaller assembly, for example that may also have one or more cutting features along a nose thereof. This smaller assembly, in at least one embodiment, extends into a bore of the whipstock assembly, where it is connected to the whipstock assembly to transmit axial loads as well as torque. Also, there may be sealing elements to allow for communication from the two part drilling and running tool into the whipstock assembly, and below.

In one or more embodiments, a portion of the conveyance and/or drill string proximate the two part drilling and running tool contains an inner sleeve that extends to a three-way crossover 215 connecting the different parts of the conveyance and/or drill string together. At the upper end of the inner sleeve, there may be a sealing member seat (e.g., ball seat) to allow for the flow/pressure to be directed into a first annular space between the conveyance and the inner sleeve. In at least one embodiment, the lower end of the inner sleeve, above the three-way crossover 215, has one or more pressure ports extending through a sidewall thickness thereof that allow for pressure to enter a second annular space between the smaller assembly and the inner sleeve (e.g., forming a piston chamber inside the inner sleeve). When fluid flow is blocked from entering the inner sleeve at the upper end, for example by dropping a sealing member (e.g., ball, dart, etc.) against the sealing member seat (e.g., ball seat, dart seat, etc.), the fluid flow is diverted through the first annular space, the one or more pressure ports, and into the second annular space (e.g., piston chamber). In one or more embodiments, an uphole end of the smaller assembly (e.g., piston) includes a circumferential sealing member that seals against the ID of the inner sleeve. In one or more embodiments, the smaller assembly further includes an axial retention mechanism (e.g., collet axial retention mechanism). The axial retention mechanism, in one or more embodiments, includes a naturally locked state (e.g., its collet is naturally propped via a prop feature and internal spring when the axial retention mechanism is a collet axial retention mechanism). This axial retention mechanism, when engaged, transmits compressive loads from the drill string to the smaller assembly. In at least one embodiment, a no-go below the axial retention mechanism passes tensile loads between the smaller assembly and larger bit assembly. It should be noted that the three-way crossover 215 is illustrated as being part of the conveyance 210, but it could equally be at a junction between the conveyance 210 and the two part drilling and running tool 220.

Once a greater fluid pressure is applied against the circumferential sealing member, the axial retention mechanism disengages (e.g., the greater fluid pressure overcomes the spring force of the internal spring and allows the prop feature to slide, thereby unpropping the collet feature). This process axially frees the smaller assembly from the larger bit assembly and conveyance (e.g., drill string), such that when additional fluid flow is provided, the smaller assembly retracts within the larger bit assembly to form a combined bit assembly while the two part drilling and running tool (e.g., larger bit assembly) is axially fixed to the conveyance.

It should be noted that, in one or more embodiments, before the smaller assembly can be retracted, as described above, the smaller assembly needs to be released from the whipstock assembly. In at least one embodiment, the second opposing smaller assembly end of the smaller assembly includes a set of smaller assembly profiles (e.g., keys or grooves), which are configured to engage with related whipstock assembly profiles (e.g., grooves or keys) located in the bore of the whipstock assembly. The smaller assembly profiles and whipstock assembly profiles hold the smaller assembly to the whipstock assembly. The smaller assembly profiles and whipstock assembly profiles, in at least one embodiment, transmit the mechanical loads that allow the downhole tool described in this disclosure to function as a running tool.

In at least one embodiment, nozzles at the end of the smaller assembly allow for flow and pressure to pass down into the whipstock assembly and below, which can be used to circulate while running in hole and activate different tools. There may also be radial holes on the side of the two part drilling and running tool (e.g., smaller assembly, larger bit assembly, etc.) that serve as activation ports, for example for a release mechanism inside the whipstock assembly. Alternatively, these radial holes may be used for indicating the status of the downhole tool, by changing the total flow area through the downhole tool, such that back pressure changes during circulation which can then be correlated to downhole tool status.

In one or more embodiments, in order to transmit torque between the smaller assembly and the larger bit assembly, a rotational retention mechanism may be used. For example, the rotational retention mechanism would rotationally fix the smaller assembly relative to the larger bit assembly after the smaller assembly has retracted within the larger bit assembly and formed the combined bit assembly. In at least one embodiment, the rotational retention mechanism is one or more collapsable torque keys (e.g., spring loaded keys), the one or more collapsable torque keys configured to collapse to allow the smaller assembly to be able to rotate relative to the larger bit assembly as the smaller assembly is retracting within the larger bit assembly, but expand to rotationally fix the smaller assembly relative to the larger bit assembly after the smaller assembly has retracted within the larger bit assembly and formed the combined bit assembly. In at least one embodiment, the rotational retention mechanism may also rotationally fix the smaller assembly to the larger bit assembly when the two part running and drilling tool is in its run-in-hole state.

In one or more embodiments, as the smaller assembly moves to the end of travel, several things happen to transform the smaller assembly and larger bit assembly into the combined bit assembly. For example, the axial retention mechanism that disengaged before may be allowed to engage once again. For example, once the greater pressure required to disengage the axial retention mechanism is reduced back to the lesser pressure, the axial retention mechanism may engage with a combined bit assembly lock profile (e.g., once pressure is removed the spring feature pushes the prop feature back down to prop the collet back in its nature state, such that the smaller assembly is axial fixed relative to the larger bit assembly). Likewise, the rotational retention mechanism may enter a second set of torque profiles inside the conveyance. As the rotational retention mechanism are spring loaded in one embodiment, it is not necessary to have the smaller assembly and larger bit assembly initially rotationally aligned. If not rotationally aligned, any relative rotation will allow the spring loaded rotational retention mechanisms to pop out into the profiles as the smaller assembly and larger bit assembly initially begin to rotate relative to one another.

Finally, a further increase in pressure may shear the sealing member seat and allow for flow to bypass the sealing member allowing for circulation through the smaller assembly again. At this point, the combined bit assembly, externally looks like a standard drilling/milling assembly.

Turning now to FIGS. 3C and 3D, illustrated are an external top view and a cross-sectional view of a downhole tool 200B designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. The downhole tool 200B of FIGS. 3C and 3D is similar in many respects to the downhole tool 200A of FIGS. 2A through 3B. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The downhole tool 200B differs, for the most part, from the downhole tool 200A, in that the downhole tool 200B employs a different whipstock assembly 290b coupled with a downhole end of the two part drilling and running tool 220. For example, in the embodiment of FIGS. 3C and 3D, the different whipstock assembly 290b is coupled with the downhole end of the two part drilling and running tool 220 using a shear feature 292 (e.g., coupled between the larger bit assembly 230 and the different whipstock assembly 290b), among other coupling mechanisms (e.g., the second opposing end of the smaller assembly 240 may additionally axially and/or rotationally couple within a bore of the different whipstock assembly 290b). The downhole tool 200B further differs from the downhole tool 200A in that it additionally includes an anchor assembly 294 (e.g., including a muleshoe 296 and latch coupling 298) coupled to a downhole end of the different whipstock assembly 290b.

As those skilled in the art appreciate, the downhole tool 200B may be: 1) run-in-hole in a single pass; 2) the anchor assembly 294 set (e.g., with the different whipstock assembly 290b properly oriented, and for example with the latch coupling 298 engaging with a related profile in the casing string); 3) the smaller assembly 240 may be retracted within the larger bit assembly 230 to form the combined bit assembly (e.g., as set forth above); 4) the shear feature 292 could then be sheared; and 5) the two part drilling and running tool 220 used to mill a window in the casing and/or drill a lateral wellbore in the subterranean formation.

Turning now to FIGS. 4A through 5H, illustrated are external side views and cross-sectional views of a downhole tool 400 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure. In the illustrated embodiment, FIGS. 4A through 4C illustrate various external side views of the downhole tool 400 at a run-in-hole state, whereas FIGS. 5A through 5H illustrate various cross-sectional views of the downhole tool 400 at the run-in-hole state. The downhole tool 400, in the illustrated embodiments, includes a conveyance 410. As indicated above, the conveyance 410 may have a first conveyance end 412a (e.g., uphole end), a second opposing conveyance end 412b (e.g., downhole end) with a conveyance coupling 414 having an outer width (W_C), and a length (L_C). In at least one embodiment, the conveyance 410 forms at least a portion of a drill string, whether that be a rigid drill string or a flexible drill string, such as coiled tubing.

The downhole tool 400, in the illustrated embodiments, further includes a two part drilling and running tool 420 coupled to the conveyance coupling 414 of the conveyance 410. In the illustrated embodiment, the two part drilling and running tool 420 includes a larger bit assembly 430 having a first larger bit assembly end 432a (e.g., uphole end), a second opposing larger bit assembly end 432b (e.g., downhole end), a length (L_LB), and an outer width (W_LB). Further to this embodiment, the two part drilling and running tool 420 additionally includes a smaller assembly 440 having a first smaller assembly end 442a (e.g., uphole end), a second opposing smaller assembly end 442b (e.g., downhole end), a length (L_SA), and an outer width (W_SA). In accordance with one or more embodiments of the disclosure, the smaller assembly 440 is at least partially positioned within the larger bit assembly 430 (e.g., and at least partially positioned within the conveyance coupling 414 of the conveyance 410 in one embodiment), and the smaller assembly 440 is configured to retract within the larger bit assembly 430 to form a combined bit assembly (e.g., not shown in this run-in-hole state) while the two part drilling and running tool 420 is axially fixed to the conveyance 410. Further to the embodiment of FIGS. 4A through 5H, the smaller assembly 440 is configured to retract within the larger bit assembly 430 to form the combined bit assembly while the larger bit assembly 430 of the two part drilling and running tool 420 is axially fixed (e.g., directly coupled to) to the conveyance 410 (e.g., with second opposing conveyance end 412b, and more particularly the conveyance coupling 414, coupling with a larger bit assembly coupling 433 of the first larger bit assembly end 432a).

In one or more embodiments, such as that shown, the outer width (W_C) is at least 70 percent of the outer width (W_LB). In one or more alternative embodiments, the outer width (W_C) is at least 80 percent of the outer width (W_LB). In yet one or more alternative embodiments, the outer width (W_C) is at least 90 percent of the outer width (W_LB), if not at least 98 percent of the outer width (W_LB). In even yet one or more alternative embodiments, the outer width (W_C) ranges from 85 percent to 115 percent of the outer width (W_LB), if not from 90 percent to 110 percent of the outer width (W_LB), if not from 95 percent to 105 percent of the outer width (W_LB), if not from 98 percent to 102 percent of the outer width (W_LB), if not from 99 percent to 101 percent of the outer width (W_LB).

In one or more other embodiments, the smaller assembly 440 is configured to be able to rotate relative to the larger bit assembly 430 and the conveyance 410 as the smaller assembly is retracting within the larger bit assembly 430. For example, in at least one embodiment, the smaller assembly 440 is not rotationally fixed relative to the larger bit assembly 430 or the conveyance 410 from the moment that the smaller assembly 440 rotationally disconnects from the whipstock assembly (e.g., not shown in these views, but shown in FIGS. 2A through 3B) and until the smaller assembly 440 and the larger bit assembly 430 come together to form the combined bit assembly. In fact, in one or more embodiments, only the whipstock assembly rotationally fixes the smaller assembly 440 to the larger bit assembly 430 and the conveyance 410 while the smaller assembly 440 is coupled with the whipstock assembly.

In the illustrated embodiment, the smaller assembly 440 is a smaller bit assembly. For example, the smaller bit assembly, when used, could include one or more cutting features (e.g., teeth 444, blades 446, etc.) along a nose (e.g., second opposing smaller assembly end 442b) thereof. The second opposing smaller assembly end 442b, in one or more other embodiments, may additionally include one or more smaller assembly profiles 448 (e.g., keys or grooves), which are configured to engage with related whipstock assembly profiles (e.g., grooves or keys) located in the bore of the whipstock assembly. The smaller assembly profiles 448 and whipstock assembly profiles rotationally fix the smaller assembly profiles 448 to the whipstock assembly. Similar to the smaller assembly 440, the larger bit assembly 430 may include one or more cutting features (e.g., teeth 434, blades 436, etc.) located on a radial exterior surface thereof.

In at least one embodiment, the downhole tool 400 includes a circumferential seal 450 positioned between the smaller assembly 440 and the larger bit assembly 430. In at least one embodiment, the circumferential seal 450 is a dynamic circumferential seal that maintains its seal integrity as the smaller assembly 440 retracts within the larger bit assembly 430. In at least one embodiment, the circumferential seal 450 is a circumferential seal stack positioned on the ID of the larger bit assembly 430, and the outside diameter (OD) of the smaller assembly 440 seals against the circumferential seal stack. In yet another embodiment, the circumferential seal 450 is a circumferential seal stack positioned on the OD of the smaller assembly 440, and the ID of the larger bit assembly 430 acts as a seal bore that seals against the circumferential seal stack.

In at least one other embodiment, the downhole tool 400 additionally includes an inner sleeve 452 located within the larger bit assembly 430 or the conveyance 410. In the embodiment illustrated in FIGS. 4A through 5H the inner sleeve 452 is primarily (e.g., if not entirely) located within the conveyance 410, however, in other embodiments the inner sleeve 452 might be located primarily (e.g., if not entirely) within the larger bit assembly 430. As shown, in at least one embodiment, the inner sleeve 452 is positioned at least partially about the first smaller assembly end 442a of the smaller assembly 440. Moreover, in at least one embodiment, a first annular space 454 remains between the inner sleeve 452 and the larger bit assembly 430 or the conveyance 410. Again, in the illustrated embodiment, the first annular space 454 is located between the inner sleeve 452 and the conveyance 410.

The downhole tool 400, in one or more embodiments, further includes a second annular space 456 located between the smaller assembly 440 and the inner sleeve 452. Further to this embodiment, the downhole tool 400 may include a circumferential sealing member 458 rigidly coupled (e.g., axially coupled) to the smaller assembly 440 and sealing the second annular space 456. In at least one embodiment, the circumferential sealing member 458 includes one or more swab cups configured to seal against the ID of the inner sleeve 452, and thus may function as a dynamic circumferential sealing member. Nevertheless, the present disclosure could use any type of circumferential sealing member 458 and remain within the broad scope therein.

The downhole tool 400, in at least one embodiment, further includes one or more pressure ports 460 extending through a sidewall thickness of the inner sleeve 452. In at least this one embodiment, the one or more pressure ports 460 connect the first annular space 454 and the second annular space 456 at an axial location between the circumferential sealing member 458 and the circumferential seal 450. In one embodiment, the one or more pressure ports 460 are configured to allow fluid flow from the first annular space 454 to access the second annular space 456 and provide a fluid pressure against the circumferential sealing member 458, for example to urge the circumferential sealing member 458 away from the second opposing larger bit assembly end 432b to retract the smaller assembly 440 within the larger bit assembly 430.

In the illustrated embodiment of FIGS. 4A through 5H, the downhole tool additionally includes a first axial retention mechanism 470 positioned between the smaller assembly 440 and the larger bit assembly 430 or the conveyance 410. The first axial retention mechanism 470, in this embodiment, is configured to axially fix the smaller assembly 440 relative to the larger bit assembly 430 when the fluid flow provides a lesser fluid pressure against the circumferential sealing member 458 (e.g., when the downhole tool is in a run-in-hole state), but is configured to axially release the smaller assembly 440 relative to the larger bit assembly 430 when the fluid flow provides a greater fluid pressure against the circumferential sealing member 458 (e.g., when it is desired to retract the smaller assembly 440 within the larger bit assembly 430 to form the combined bit assembly, as discussed above). The first axial retention mechanism 470, in at least one embodiment, is a first collet axial retention mechanism. In this embodiment, the first collet axial retention mechanism includes a first collet feature 472, a prop feature 474 configured to urge the first collet feature 472 radially outward, and an internal spring member 476 configured to urge the prop feature 474 under the first collet feature 472, and thus into a naturally locked state. When the first axial retention mechanism 470 is in the locked state, the first collet feature 472 is held radially outward into engagement with a first profile 478 in the larger bit assembly 430 or conveyance 410, thereby axially fixing the smaller assembly 440 relative to the larger bit assembly 430.

In at least one other embodiment, the downhole tool 400 additionally includes a sealing member seat 480. In the illustrated embodiment, the sealing member seat 480 is located within the inner sleeve 452, and for example positioned such that the circumferential sealing member 458 is axially positioned between the one or more pressure ports 460 and the sealing member seat 480. Further to this embodiment, the sealing member seat 480 is configured to receive a dropped sealing member (e.g., not shown in this run-in-hole state) to prevent the fluid flow from passing through the smaller assembly 440 and force the fluid flow into the first annular space 454, through the one or more pressure ports 460 into the second annular space 456, and against the circumferential sealing member 458. In at least one embodiment, the sealing member seat 480 is a drop ball seat or drop dart seat, among others. In at least one other embodiment, the sealing member seat 480 is a shearable sealing member seat that includes a shearable feature 482 that shearling couples the shearable sealing member seat to the inner sleeve 452. In at least this one embodiment, the shearable sealing member seat is configured to shear (e.g., the shearable feature 482 is configured to shear) after the smaller assembly 440 has retracted within the larger bit assembly 430 and formed the combined bit assembly to allow the fluid flow to again pass through the smaller assembly 440. In at least one embodiment, the shearable sealing member seat includes one or more fluid passageways 484 that allows the fluid to bypass the dropped sealing member and allow the fluid flow to again pass through the smaller assembly 440.

The downhole tool 400 of FIGS. 4A through 5H, in at least one embodiment, further includes a second axial retention mechanism 486 positioned between the smaller assembly 440 and the larger bit assembly 430 or the conveyance 410, the second axial retention mechanism 486 configured to axially fix the smaller assembly 440 relative to the larger bit assembly 430 after the smaller assembly 440 has retracted within the larger bit assembly 430 and formed the combined bit assembly. In at least one embodiment, the second axial retention mechanism 486 is a second collet axial retention mechanism that is configured to engage with a second profile 490 to axially fix the smaller assembly 440 relative to the larger bit assembly 430 after the smaller assembly 440 has retracted within the larger bit assembly 430 and formed the combined bit assembly. For example, the downhole device could include a second collet feature 488 positioned radially about the smaller assembly 440, the second collet feature 488 configured to engage with the second profile 490 of the smaller assembly 440 to axially fix the smaller assembly 440 relative to the larger bit assembly 430 after the smaller assembly 440 has retracted within the larger bit assembly 430 and formed the combined bit assembly. While one specific design for the second axial retention mechanism 486 has been discussed and illustrated, other embodiments are within the scope of the disclosure.

The downhole tool 400 of FIGS. 4A through 5H, in at least one embodiment, further includes a rotational retention mechanism 492. In this embodiment, the rotational retention mechanism 492 is configured to rotationally fix the smaller assembly 440 relative to the larger bit assembly 430 after the smaller assembly 440 has retracted within the larger bit assembly 430 and formed the combined bit assembly. In at least one embodiment, such as that shown, the rotational retention mechanism 492 includes one or more collapsable torque keys 494 (e.g., one or more spring loaded collapsable torque keys). In at least this one embodiment, the one or more collapsable torque keys 494 are configured to collapse to allow the smaller assembly 440 to be able to rotate relative to the larger bit assembly 430 as the smaller assembly 440 is retracting within the larger bit assembly 430, but expand to rotationally fix the smaller assembly 440 relative to the larger bit assembly 430 after the smaller assembly 440 has retracted within the larger bit assembly 430 and formed the combined bit assembly. In at least one embodiment, the one or more collapsable torque keys 494 are configured to engage with a third profile in the larger bit assembly 430 or the conveyance 410 to rotationally fix the smaller assembly 440 relative to the larger bit assembly 430 after the smaller assembly 440 has retracted within the larger bit assembly 430 and formed the combined bit assembly. In at least one other embodiment, the one or more collapsable torque keys 494 are configured to engage with a fourth profile 498 in the larger bit assembly 430 or the conveyance 410 to rotationally fix the smaller assembly 440 relative to the larger bit assembly 430 when the downhole tool 400 is in the run-in-hole state. Accordingly, in at least this one embodiment, the rotational retention mechanism 492 functions to rotationally fix the smaller assembly 440 relative to the larger bit assembly 430 in the run-in-hole state and when the combined bit assembly has been formed, but allows the two to rotate relative to one another in the transitional states therebetween.

Turning now to FIGS. 6A through 13E, illustrated are cross-sectional views of a downhole tool 600 designed, manufactured and/or operated according to one or more alternative embodiments of the disclosure at different operational states. The downhole tool 600 of FIGS. 6A through 13E is similar in many respects to the downhole tool 400 of FIGS. 4A through 5H. Accordingly, like reference numbers have been used to indicate similar, if not identical features.

Turning initially to FIGS. 6A through 6H, illustrated is the downhole tool 600 in the run-in-hole state. Accordingly, the downhole tool 600 would be in a similar state, and function similarly to the downhole tool 400 of FIGS. 4A through 5H. While not shown, the downhole tool 600 could be coupled with a whipstock assembly, as well as having one or more lower completion devices, hanging from a downhole end thereof.

Turning now to FIGS. 7A through 7E, illustrated is the downhole tool 600 of FIGS. 6A through 6H after a dropped sealing member 710 has been dropped within the downhole tool 600, but prior to pressuring down on the dropped sealing member 710. At this stage, the first axial retention mechanism 470 is still axially fixing the smaller assembly 440 relative to the larger bit assembly 430. For example, the prop feature 474 is still propping the first collet feature 472 radially outward, and thus into engagement with the first profile 478. Similarly, the rotational retention mechanism 492 is still rotationally fixing the smaller assembly 440 and the larger bit assembly 430 relative to one another. Again, typically the two part drilling and running tool 420 would remain coupled to the whipstock assembly (e.g., not shown) at this stage of operation

Turning now to FIGS. 8A through 8E, illustrated is the downhole tool 600 of FIGS. 7A through 7E after pressuring down on the dropped sealing member 710 using a fluid flow 810 with a lesser pressure. The fluid flow 810 with the lesser pressure extends into the first annular space 454, through the one or more pressure ports 460, and into the second annular space 456, wherein is pressures up against the circumferential sealing member 458, and ultimately against the first axial retention mechanism 470. At this stage, the fluid flow 810 with the lesser pressure is insufficient to disengage the first axial retention mechanism 470, and thus the first axial retention mechanism 470 is still axially fixing the smaller assembly 440 relative to the larger bit assembly 430. For example, the fluid flow 810 with the lesser pressure is insufficient to slide the circumferential sealing member 458 uphole, and thus the prop feature 474 is still propping the first collet feature 472 radially outward, and thus into engagement with the first profile 478. Similarly, the rotational retention mechanism 492 is still rotationally fixing the smaller assembly 440 and the larger bit assembly 430 relative to one another.

Turning now to FIGS. 9A through 9E, illustrated is the downhole tool 600 of FIGS. 8A through 8E after pressuring down on the dropped sealing member 710 using a fluid flow 910 with a greater pressure. The fluid flow 910 with the greater pressure extends into the first annular space 454, through the one or more pressure ports 460, and into the second annular space 456, wherein is pressures up against the circumferential sealing member 458, and ultimately against the first axial retention mechanism 470. At this stage, the fluid flow 910 with the greater pressure is sufficient to disengage the first axial retention mechanism 470. For example, the fluid flow 910 with the greater pressure is sufficient to move the circumferential sealing member 458 uphole relative to the first axial retention mechanism 470, thereby sliding the prop feature 474 uphole. As the prop feature 474 is no longer positioned radially inside of the first collet feature 472, the first collet feature 472 is now able to collapse and thus axially release the smaller assembly 440 relative to the larger bit assembly 430. At this stage, the rotational retention mechanism 492 is still rotationally fixing the smaller assembly 440 and the larger bit assembly 430 relative to one another.

Turning now to FIGS. 10A through 10G, illustrated is the downhole tool 600 of FIGS. 9A through 9E after continuing to provide a fluid flow 1010 against the circumferential sealing member 458, and thus against the first axial retention mechanism 470. The fluid flow 1010 may be the fluid flow 910 with the greater pressure, or may be the fluid flow 810 with the lesser pressure or a different fluid flow with a different pressure, so long as the fluid flow 1010 is enough to continue moving the smaller assembly 440 uphole relative to the larger bit assembly 430). Reducing the fluid flow pressure is workable, as there is no first profile 478 for the first axial retention mechanism 470 to engage with, and thus it cannot axially restrict movement at this stage of operation. Accordingly, the fluid flow 1010 continues to pass through the first annular space 454, through the one or more pressure ports 460, and into the second annular space 456 against the circumferential sealing member 458. Accordingly, in this embodiment, the smaller assembly 440 has been retracted about 25% of what is needed to form the combined bit assembly. Furthermore, while the smaller assembly 440 and the larger bit assembly 430 are no longer axially fixed relative to one another, the smaller assembly 440 is able to rotate relative to the larger bit assembly 430, as the rotational retention mechanism 492 is no longer engaged with the fourth profile 498.

Turning now to FIGS. 11A through 11G, illustrated is the downhole tool 600 of FIGS. 10A through 10G after continuing to provide the fluid flow 1010 against the circumferential sealing member 458. Accordingly, the fluid flow 1010 continues to pass through the first annular space 454, through the one or more pressure ports 460, and into the second annular space 456 against the circumferential sealing member 458. Accordingly, in this embodiment, the smaller assembly 440 has been retracted about 50% of what is needed to form the combined bit assembly. Furthermore, the smaller assembly 440 is still able to rotate relative to the larger bit assembly 430.

Turning now to FIGS. 12A through 12G illustrated is the downhole tool 600 of FIGS. 11A through 11G after continuing to provide the fluid flow 1010 against the circumferential sealing member 458. Accordingly, the fluid flow 1010 continues to pass through the first annular space 454, through the one or more pressure ports 460, and into the second annular space 456 against the circumferential sealing member 458. Accordingly, in this embodiment, the smaller assembly 440 has been retracted about 75% of what is needed to form the combined bit assembly. Furthermore, the smaller assembly 440 is still able to rotate relative to the larger bit assembly 430.

Turning now to FIGS. 13A through 13E illustrated is the downhole tool 600 of FIGS. 12A through 12G after continuing to provide the fluid flow 1010 against the circumferential sealing member 458. Accordingly, the fluid flow 1010 continues to pass through the first annular space 454, through the one or more pressure ports 460, and into the second annular space 456 against the circumferential sealing member 458. Accordingly, in this embodiment, the smaller assembly 440 has been retracted about 100% of what is needed, and thus now forms the combined bit assembly 1380. At this stage, a second axial retention mechanism 486, and more specifically the second collet feature 488, may engage with the second profile 490 to again axially fix the smaller assembly 440 relative to the larger bit assembly 430, and thus fix the larger bit assembly 430 and the smaller assembly 440 as the combined bit assembly 1380. In at least one other embodiment, the fluid flow 1010 may be reduced back to the fluid flow 810 with the lesser pressure, or there below, which would allow the first axial retention mechanism 470 to engage with a fifth profile 1372, and thus also axially fix the smaller assembly 440 relative to the larger bit assembly 430. In even yet another embodiment, the rotational retention mechanism 492, and specifically the one or more collapsable torque keys 494 thereof, are axially aligned with the third profile 496. If the rotational retention mechanism 492, and specifically the one or more collapsable torque keys 494 thereof, are rotationally aligned with the third profile 496, it will snap into place and rotationally fix the smaller assembly 440 relative to the larger bit assembly 430. However, if the rotational retention mechanism 492, and specifically the one or more collapsable torque keys 494 thereof, are rotationally misaligned with the third profile 496 (e.g., but axially aligned), the rotational retention mechanism 492 will snap into place and rotationally fix the smaller assembly 440 relative to the larger bit assembly 430 with just a slight rotation of the larger bit assembly 430 and conveyance 410. Again, at this stage, the downhole tool 600 including the combined bit assembly 1380 is ready to mill the casing and/or drill a lateral wellbore.

Aspects disclosed herein include:

• • A. A downhole tool, the downhole including: 1) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB), the first larger bit assembly end having a larger bit assembly coupling configured to engage with and axially fix to a conveyance coupling of a conveyance; and 2) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, wherein the smaller assembly and the larger bit assembly form at least a part of a two part drilling and running tool, the smaller assembly configured to retract within the larger bit assembly to form a combined bit assembly while the larger bit assembly is axially fixed to the conveyance
  • B. A method, the method including: 1) providing a downhole tool, the downhole tool including: a) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB), the first larger bit assembly end having a larger bit assembly coupling configured to engage with and axially fix to a conveyance coupling of a conveyance; and b) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, wherein the smaller assembly and the larger bit assembly form at least a part of a two part drilling and running tool; and 2) retracting the smaller assembly within the larger bit assembly to form a combined bit assembly while the larger bit assembly is axially fixed to the conveyance.
  • C. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool positioned within the wellbore, the downhole tool including: a) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB), the first larger bit assembly end having a larger bit assembly coupling configured to engage with and axially fix to a conveyance coupling of a conveyance; and b) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, wherein the smaller assembly and the larger bit assembly form at least a part of a two part drilling and running tool, the smaller assembly configured to retract within the larger bit assembly to form a combined bit assembly while the larger bit assembly is axially fixed to the conveyance.
  • D. A downhole tool, the downhole including: 1) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and 2) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: a) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and b) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, the smaller assembly configured to retract within the larger bit assembly to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance, wherein the outer width (W_C) is at least 70 percent of the outer width (W_LB).
  • E. A method, the method including: 1) providing a downhole tool, the downhole tool including: a) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and b) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: i) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and ii) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, wherein the outer width (W_C) is at least 70 percent of the outer width (W_LB); and 2) retracting the smaller assembly within the larger bit assembly to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance.
  • F. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool positioned within the wellbore, the downhole tool including: a) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and b) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: i) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and ii) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, the smaller assembly configured to retract within the larger bit assembly to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance, wherein the outer width (W_C) is at least 70 percent of the outer width (W_LB).
  • G. A downhole tool, the downhole including: 1) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and 2) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: a) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and b) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, the smaller assembly configured to retract within the larger bit assembly and at least a portion of the conveyance to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance.
  • H. A method, the method including: 1) providing a downhole tool, the downhole tool including: a) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and b) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: i) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and ii) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly; and 2) retracting the smaller assembly within the larger bit assembly and at least a portion of the conveyance to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance.
  • I. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool positioned within the wellbore, the downhole tool including: a) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and b) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: i) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and ii) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, the smaller assembly configured to retract within the larger bit assembly and at least a portion of the conveyance to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance.
  • J. A downhole tool, the downhole including: 1) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and 2) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: a) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and b) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, the smaller assembly configured to retract within the larger bit assembly to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance, and further wherein the smaller assembly is configured to be able to rotate relative to the larger bit assembly and the conveyance as the smaller assembly is retracting within the larger bit assembly.
  • K. A method, the method including: 1) providing a downhole tool, the downhole tool including: a) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and b) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: a) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and b) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, and further wherein the smaller assembly is configured to be able to rotate relative to the larger bit assembly and the conveyance as the smaller assembly is retracting within the larger bit assembly; and 2) retracting the smaller assembly within the larger bit assembly to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance.
  • L. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a downhole tool positioned within the wellbore, the downhole tool including: a) a conveyance having a first conveyance end, a second opposing conveyance end with a conveyance coupling having an outer width (W_C), and a length (L_C); and b) a two part drilling and running tool coupled to the conveyance coupling of the conveyance, the two part drilling and running tool including: i) a larger bit assembly having a first larger bit assembly end, a second opposing larger bit assembly end, a length (L_LB), and an outer width (W_LB); and ii) a smaller assembly having a first smaller assembly end, a second opposing smaller assembly end, a length (L_SA), and an outer width (W_SA), the smaller assembly at least partially positioned within the larger bit assembly, the smaller assembly configured to retract within the larger bit assembly to form a combined bit assembly while the two part drilling and running tool is axially fixed to the conveyance, and further wherein the smaller assembly is configured to be able to rotate relative to the larger bit assembly and the conveyance as the smaller assembly is retracting within the larger bit assembly.

Aspects A through L may have one or more of the following additional elements in combination: Element 1: further including a circumferential seal positioned between the smaller assembly and the larger bit assembly. Element 2: wherein the circumferential seal is a dynamic circumferential seal. Element 3: further including an inner sleeve located within the larger bit assembly or the conveyance the larger bit assembly is configured to engage with, the inner sleeve positioned at least partially about the first smaller assembly end of the smaller assembly, and further wherein an annular space remains between the inner sleeve and the larger bit assembly or the conveyance the larger bit assembly is configured to engage with. Element 4: wherein the annular space is a first annular space, and further including a second annular space located between the smaller assembly and the inner sleeve, a circumferential sealing member rigidly coupled to the smaller assembly and sealing the second annular space. Element 5: wherein the circumferential sealing member is a dynamic circumferential sealing member. Element 6: further including one or more pressure ports extending through a sidewall thickness of the inner sleeve, the one or more pressure ports connecting the first annular space and the second annular space at an axial location between the circumferential sealing member and the circumferential seal, the one or more pressure ports configured to allow fluid flow from the first annular space to access the second annular space and provide a fluid pressure against the circumferential sealing member to urge the circumferential sealing member away from the second opposing larger bit assembly end to retract the smaller assembly within the larger bit assembly. Element 7: further including an axial retention mechanism positioned between the smaller assembly and the larger bit assembly or the conveyance the larger bit assembly is configured to engage with, the axial retention mechanism configured to axially fix the smaller assembly relative to the larger bit assembly when the fluid flow provides a lesser fluid pressure against the circumferential sealing member, but configured to axially release the smaller assembly relative to the larger bit assembly when the fluid flow provides a greater fluid pressure against the circumferential sealing member. Element 8: wherein the axial retention mechanism is a collet axial retention mechanism. Element 9: further including a sealing member seat located within the inner sleeve, the circumferential sealing member axially positioned between the one or more pressure ports and the sealing member seat, the sealing member seat configured to receive a dropped sealing member to prevent the fluid flow from passing through the smaller assembly and force the fluid flow into the first annular space, through the one or more pressure ports into the second annular space, and against the circumferential sealing member. Element 10: wherein the sealing member seat is a shearable sealing member seat, the shearable sealing member seat configured to shear after the smaller assembly has retracted within the larger bit assembly and formed the combined bit assembly to allow the fluid flow to again pass through the smaller assembly. Element 11: wherein the axial retention mechanism is a first axial retention mechanism, and further including a second axial retention mechanism positioned between the smaller assembly and the larger bit assembly or the conveyance, the second axial retention mechanism configured to axially fix the smaller assembly relative to the larger bit assembly after the smaller assembly has retracted within the larger bit assembly and formed the combined bit assembly. Element 12: further including a rotational retention mechanism, the rotational retention mechanism configured to rotationally fix the smaller assembly relative to the larger bit assembly after the smaller assembly has retracted within the larger bit assembly and formed the combined bit assembly. Element 13: wherein the rotational retention mechanism is one or more collapsable torque keys, the one or more collapsable torque keys configured to collapse to allow the smaller assembly to be able to rotate relative to the larger bit assembly as the smaller assembly is retracting within the larger bit assembly, but expand to rotationally fix the smaller assembly relative to the larger bit assembly after the smaller assembly has retracted within the larger bit assembly and formed the combined bit assembly. Element 14: wherein the larger bit assembly coupling is engaged with and axially fixed to the conveyance at the conveyance coupling, the conveyance having a first conveyance end, a second opposing conveyance end with the conveyance coupling having an outer width (W_C), and a length (L_C), wherein the outer width (W_C) is at least 70 percent of the outer width (W_LB). Element 15: wherein the outer width (W_C) is at least 80 percent of the outer width (W_LB). Element 16: wherein the outer width (W_C) is at least 90 percent of the outer width (W_LB). Element 17: wherein the outer width (W_C) is at least 98 percent of the outer width (W_LB). Element 18: wherein the outer width (W_C) ranges from 95 percent to 105 percent of the outer width (W_LB). Element 19: wherein the smaller assembly is a smaller bit assembly. Element 20: wherein the smaller bit assembly includes one or more cutting features along a nose thereof.

Those skilled in the art to which this application relates will appreciate that other and further additions, deletions, substitutions and modifications may be made to the described embodiments.