Latch Collet Including Unique Collet Prop Buttons

This application is a continuation of U.S. application Ser. No. 18/481,536, filed on Oct. 5, 2023, entitled “LATCH COLLET INCLUDING UNIQUE COLLET PROP BUTTONS,” which claims the benefit of U.S. Provisional Application Ser. No. 63/414,272, filed on Oct. 7, 2022, entitled “ADAPTIVE ORIENTING LATCH,” commonly assigned with this application and incorporated herein by reference in their entirety.

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.

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 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 in 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.

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

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 levelmultilateral junction could be completed in 1 trip devoted exclusively to the multilateral technology (MIT), or in certain instances even less than 1 trip as further discussed below.

One example idea is to run the mainbore completion (e.g., lower main bore screens) with a whipstock, anchor them in the mainbore and establish an annular seal (e.g., if required). Then, one may release the running tool, turn it into a milling bottom hole assembly (BHA), 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.

The new system proposed here also features a new latch collet design that incorporates a packer assembly to achieve an annular seal between the anchor and the casing of the main bore. To prevent premature compression of the packer elements, the new latch collet incorporates one or more (e.g., three) independent anti-preset features.

Also present is a new running tool that automatically releases once the latch collet has engaged with the correct latch coupling without any action required to be taken on the surface. Together, with the anti-preset features of the latch collet, this ensure that the running tool will only release when the BHA has reached the correct depth and orientation in the well.

Since, in at least one embodiment, the running tool is a solid piece with no moving parts, it is possible to realize further trip savings by employing a two part milling/running tool, such that the simple running tool becomes the milling assembly for milling the window from the main bore.

Once the lateral wellbore has been drilled, and lateral bore completion dropped off, the upper part of the bottom hole assembly (BHA) (e.g., the whipstock) may be retrieved, leaving behind the anchor part of the system which incorporates a set of seals. 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.

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.

is a schematic view of a well systemdesigned, manufactured and/or operated according to one or more embodiments disclosed herein. The well systemincludes a platformpositioned over a subterranean formationlocated below the earth's surface. The platform, in at least one embodiment, has a hoisting apparatusand a derrickfor raising and lowering one or more downhole tools including pipe strings, such as a drill string. Although a land-based oil and gas platformis illustrated in, 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 wellborehas been drilled through the various earth strata, including the subterranean formation. 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 wellboredoes not necessarily need to extend directly to the earth's surface, but could instead be a branch of yet another lateral wellbore. A casing stringmay be at least partially cemented within the main wellbore. 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 assemblyaccording to one or more embodiments of the present disclosure may be positioned at a location in the main wellbore. Specifically, the whipstock assemblycould be placed at a location in the main wellborewhere it is desirable for a lateral wellboreto exit. Accordingly, the whipstock assemblymay be used to support a drilling/milling tool used to penetrate a window in the main wellbore. In at least one embodiment, once the window has been milled and a lateral wellboreformed, the whipstock assemblymay be retrieved and returned uphole by a retrieval tool, in some embodiments in only a single trip.

In some embodiments, an anchor assemblymay be placed downhole in the wellboreto support and anchor downhole tools, such as the whipstock assembly, for maintaining the whipstock assemblyin place while drilling the lateral wellbore. The anchor assembly, in accordance with the disclosure, may be employed in a cased section of the main wellbore, such as shown, or may be located in an open-hole section of the main wellbore. As such, the anchor assemblyin 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 assemblymay 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 assemblymay be configured to resist at least 1814 kg (e.g., about 4,000 lb) of axial force. In yet another embodiment, the anchor assemblymay be configured to resist at least 4536 kg (e.g., about 10,000 lb) of axial force, and in yet another embodiment the anchor assemblymay be configured to resist at least 6804 kg (e.g., about 15,000 lb) of axial force.

In the illustrated embodiment, the anchor assemblyis 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, and any other features hanging there below (e.g., main wellbore completion, screens, valves, etc.) in the wellbore. Once the ancho assemblyreaches a desired location in the main wellbore, the reciprocal profile in the downhole tool (e.g., whipstock assembly) may be activated to engage with the profile in the casing string, thereby setting the anchor assembly. One aspect of the present disclosure provides a new latch coupling. The well systemmay be manufactured using any one or more of the devices and/or methods disclosed below.

One embodiment of a well system (e.g., the well systemof) may incorporate several new features that all contribute to eliminating trips. Beginning with a down-hole end of the BHA, there is a latch collet. (See,). New, in this embodiment, is the addition of a set of packer elements at the up-hole end of the latch collet that when compressed will form an annular seal between the BHA and the main wellbore. (See,). New profiles between the collet fingers are there to allow torque to be transmitted between the latch collet and the inner mandrel.

To ensure that the packer elements are not prematurely energized, the latch mechanism incorporates several features that when taken together will ensure that the latch mechanism only actuates when in the correct latch coupling. Below the external profile on the collet fingers is a set of internal profiles (e.g., collet prop buttons) that match groves on the OD of the mandrel. (See,) When the latch collet is inside of the system casing size, the collet fingers are compressed and the internal profiles (e.g., collet prop buttons) engage the OD groves on the mandrel, preventing relative axial movement between the latch collet and the mandrel. Once the latch collet latches into a latch coupling, the collet fingers snap out into the pockets in the latch coupling, and the internal profiles (e.g., collet prop buttons) retract from the groves in the mandrel thereby allowing movement between the mandrel and latch collet.

To prevent movement between the latch collet and the mandrel if the latch mechanism is in larger casing when the latch collet fingers are not compressed, the upper part of the latch mechanism incorporates a bore sensor. (See,). This bore sensor locks the latch collet and mandrel together when not in system size casing (see,), and unlocks when in the correct casing (see,). Placing the bore sensor above the latch collet ensures that the mandrel and latch collet are always locked together, until the latch coupling is reached. For example, when entering a liner, the latch collet fingers will lock onto the mandrel, before the bore sensor unlocks.

Moreover, a set of shear screws may also be used, which can be varied in quantity (or omitted entirely), to require a certain amount of weight to be set down before the latch mechanism will actuate. (See,).

Once all three features have been triggered, the packer elements are compressed, and the annular seal is established by setting down weight. At the end of the stroke, a locking snap ring may be used to ensure that the mechanism does not release again. This snap ring may also be designed to shear at a certain load such that the latch collet may be released, if necessary. Similarly (e.g., simultaneously), the profiles on the ID of the latch collet (e.g., collet prop buttons) may move out of their corresponding grooves in the mandrel. When dimensioned correctly this will serve to prop open the latch collet preventing it from releasing from the latch coupling as long as it is prevented from moving axially relative to the mandrel (e.g., the above-mentioned snap ring).

It is possible to combine the above-described latch mechanism with a new style running tool that automatically releases once the latch mechanism has locked into the latch coupling. A running tool collet inside the mandrel may be used to connect the running tool to the latch mechanism. Prior to setting the latch mechanism, profiles in the OD of the running tool collet engage with dogs that protrude through the body of the mandrel. In this state the dogs may lock the collet in tension, though they may also be used for compression and torque. Before the latch mechanism has actuated, the dogs are held in place by the body of the latch collet. Once the latch collet moves into the final position the dogs are free to move radially outward thereby also unlocking the running tool collet. (See,).

Once the latch mechanism has locked into the latch coupling, simply applying tension to the tool string will free the running tool with no further action required on the surface. As the running tool is pulled up, the running tool collet pushes the unsupported dogs radially outward and at the end of the travel and the collet fingers are free to expand over the body of the running tool. Continuing to pull on the running tool will retract the milling features into the outer mill body thereby creating a combined milling assembly.

The running tool may be used to install two separate assemblies in the well. The anchor, of which the latch mechanism is a part, and the whipstock assembly. The anchor features a set of seals for a multilateral junction, and above that a Muleshoe profile as well as groves and slots for transmitting tension, compression, and torque. This part may be used to allow for a straight pull to shear some shear screws and release the whipstock.

A lower portion of the whipstock assembly may be connected to the running tool collet in such a way to allow the two to move relative to each other, such that the running tool collet can release the running tool and be retrieved with the whipstock when it is retrieved. A connecting piece engages with the completion seals in the anchor assembly thereby providing pressure integrity between the whipstock and the anchor. Depending on the application it may or may not be necessary to have this temporary seal.

A second set of seals may be present in the whipstock assembly, the second set of seals sealing on the OD of the running tool thereby completing the pressure barrier. With a fully sealed system, as described, it would be possible to use the system to apply pressure to components below the anchor or to circulate.

As presented in one embodiment, the whipstock assembly incorporates a fluid loss device (e.g., including a flapper valve) that is held open by the running tool and automatically closes once the running tool is pulled back. (See,). This serves as a fluid loss device while drilling the lateral, thereby protecting the main wellbore from drilling pressures, and also prevents milling/drilling debris from entering further. Since the flapper valve is part of the retrievable whipstock assembly, once it is retrieved after the lateral has been drilled, the main wellbore will once again be in communication to the rest of the well. The milling/drilling debris may also be retrieved with the whipstock, leaving behind a clean seal assembly in the anchor assembly. Depending on the well and/or field, this may or may not be acceptable and the isolation may need to be maintained until a later time, perhaps until after the junction has been installed. In such instances, the fluid loss device may instead be installed in a different part of the system, or it may be omitted entirely. Likewise, while a flapper valve style fluid loss device is shown, many other types of flow/pressure isolating devices may be used.

The whipstock assembly may include a set of holes through the body. These are for a hydraulic retrieving tool to engage with and retrieve the whipstock assembly. Nevertheless, this is not the only way that a whipstock assembly can be retrieved. In the interest of brevity, whipstock retrieval options will not be discussed as part of this disclosure, but it is understood that any whipstock retrieval option may be used, and a typical whipstock is designed for several contingencies.

Returning to the two-part drilling assembly, once the smaller assembly, inner mill, is pulled back it will engage with the larger bit assembly. (See,). At this point locking the two mills together is important for the successful milling of the window exit. A no-go shoulder is there to provide a hard stop once the smaller assembly is pulled into position. A one-way mechanism is used to then prevent the smaller assembly from coming back out of the larger bit assembly. (See,). A spring pushes a segmented cone downward into a narrowing space inside the larger bit assembly, such that it is squeezed onto the OD of the body of the smaller assembly. Downward movement of the smaller assembly will be prevented by the geometry of the cone and ID of the larger bit assembly, the more downward force is applied the harder the smaller assembly will be squeezed.

In addition to preventing axial movement between the two mills, it is important to ensure that torque applied to the smaller assembly by the drill string is transmitted to the larger bit assembly. With sufficient axial force applied as described above, this is not a problem, as this is the operating principle of collet chucks that are used in many different applications. As an additional feature to aid with torque transfer, profiles may be added to the two mills and match the shape of the segmented cone fingers. (See,). Friction enhancing surface treatments, or geometries may be added to the various components to enhance grip and make for a better connection.

The operational sequence for this system would, in one embodiment, start off by having a latch coupling already installed in the well. Then the main wellbore screens and whipstock/anchor assembly may be latched into the latch coupling. Weight may then be set down to energize the packer elements, and in the same sequence the running tool is released. Pulling up retracts the running tool from the whipstock assembly bore, and the flapper valve closes creating a fluid loss barrier. The smaller assembly of the two-part drilling and running tool may then be further pulled uphole until the larger bit assembly is tagged, and then may shear off. At this point, normal window milling and lateral drilling operations can commence. The lateral screens may then be dropped off, and a whipstock retrieving tool that is connected to the liner running tool may be used to retrieve the whipstock. The junction may then be installed, landing (e.g., simultaneously landing) in the seals in the main wellbore anchor, and then tying back the already dropped off lateral liner and/or screens. Since, in this embodiment, there is no completion deflector, the lateral leg of the junction may need to employ a deflector less solution to exit out into the lateral. Again, such an operational sequence can save 4-5 trips when constructing one or more multilateral junctions of a trilateral well, and 2+ trips when constructing a multilateral junction of a single bilateral well.

Since the upper part of the system (e.g., the whipstock assembly) is retrieved, the lower anchor can have a larger ID. This means that it is possible to install a junction that is compatible with the intelligent completions such as the FlexRite® MIC family of junctions.

As can be appreciated, with a large system there are several changes that can be made to tailor the system for other applications. One possible variation is in the selection of anchoring in the main bore. While the latch collet and latch coupling have been discussed in detail above, the ideas have more universal applications. For example, in place of a latch coupling an XtremeGrip® MLT anchor may be used with the compatible latch mechanism. As discussed above, the XtremeGrip® compatible latches feature a mandrel and an external housing that slides relative to the mandrel. Incorporating the automatic release features and anti-preset features into a different latch mechanism is quite feasible. Selecting this alternative has the benefit of allowing the system to be used for existing well that may not have a latch coupling already present.

It would also be possible to incorporate more components from a traditional packer into the system. The axial movement could also be used to set slips into the casing, thereby achieving the required mechanical anchoring. This variation could have a far simpler profile in the well than a latch coupling, perhaps just a recessed no-go.

A major change that could be made to the system is to remove the whipstock assembly disconnect features and instead have the whipstock be installed permanently with the latch collet in the well. In this embodiment, the whipstock assembly would incorporate completion seals to ensure pressure integrity for the life of the well. These seals may be the same seals in the same location as the seals previously discussed that seal on the body of the running tool, below the flapper valve. With this variation, once the lateral is drilled the lateral screens could be run on the junction and installed at the same time. A flapper valve may be present in the same location to protect the main wellbore from drilling pressures as well as milling/drilling debris. This flapper valve could then be broken while landing the junction with the main wellbore seal stinger, or a different kind of valve could be shifted open. If implemented as described, this embodiment would be a “zero trip” system that does not require any trips that are solely devoted to the construction of a multilateral junction. One likely required sacrifice of this option is the change to a junction that may not be compatible with intelligent completions since the bore in the whipstock is not large enough to accommodate all the necessary equipment.

This system is also stackable, as in multiple junctions can be installed in the same well. The upper whipstock/anchor assembly would have the lower junction connected to it instead of the main bore screens as described earlier.

Furthermore, a latch system different from that described above could also be used. A challenge is to latch in and set various orientation-critical well equipment in a matching well bore latch profile, such as a whipstock and/or a deflector device for a multilateral installation, without the need for latch profile pre-orientation, and/or an additional verification run to confirm latch profile orientation in the wellbore casing upon installation at depth.

An adaptive orienting latch according to the present disclosure could be used. The adaptive orienting latch (e.g., a latch-in device, for locking in various well equipment at depth and within a specific required orientation range), in one embodiment, consists of a latch collet, as the anchor of the orientational critic well equipment, and a latch coupling with an internal mating profile, run and installed in a well bore as a part of the casing liner run. The latch coupling, when placed within the wellbore, does not require any orientational alignment to the wellbore casing. The latch collet, run in as part of the well equipment, also does not require any orientational alignment to its connected well equipment. Upon reaching the planned depth of the latch coupling with the latch collet, the latch collet will be oriented, by the help of an orientation device in the running string. The latch collet may have one or more selector profiles (e.g., having multiple shoulders), and multiple torque buttons set up in a pattern to match the latch coupling torsional slots in any orientation, such that the latch collet will lock in independent of its orientation. The latch coupling is set up with multiple sets of matching torque slots, axially through the collet, where the latch collet torque buttons engage to hold in torsional loading. The number of matching profiles determines the accuracy of latch in orientation. For example, if:

The latch collet has multiple sets of torque buttons. In the illustrated embodiment, the multiple sets of torque buttons may each be separated into multiple linearly aligned and spaced apart torque button portions (e.g., three torque button portions in the illustrated embodiment). In one or more embodiments, the torque buttons (and/or torque button portions) may be set up in an alternating pattern to increase debris tolerance and engagement into the latch coupling.

The latch collet, in the illustrated embodiment, may also have one or more coupling selector buttons. In one or more embodiments, the latch collet includes an uphole coupling selector button and a downhole coupling selector button. In accordance with one embodiment, the one or more coupling selector button include one or more transaxial compressive shoulders (e.g., a set of three transaxial compressive shoulders) and one or more transaxial tensile shoulders (e.g., a set of three transaxial tensile shoulders), locking the latch collet at depth into the latch coupling upon latching in. The latch collet may also be propped and locked into position, as discussed in the paragraphs above employing the mandrel, for increased latch rating or permanent anchoring by an internal mandrel.

The coupling selector buttons, in at least one embodiment, may be used to selectively engage with one latch coupling while passing upon another latch coupling. For example, a size and/or shape of the coupling selector buttons may change based upon the latch collet selector profiles in the latch coupling that a particular coupling selector button is intended to engage with. For example, if the latch couplings were installed within the wellbore, each having sequentially smaller latch collet selector profiles (e.g., from heal to toe), then larger coupling selector buttons would pass the smaller latch collet selector profiles until such time as the coupling selector buttons matched with the latch collet selector profiles in the latch collet.

One novelty of this new adaptive orienting latch lies in how the latch collet can latch in and lock into the latch coupling at any desired orientation without any required pre-alignment of latch collet or orientation (or verification) of the casing latch coupling upon casing liner installation in wellbore. The latch collet torque buttons, in combination with its transaxial shoulders, has a novel method of locking into the latch couplings profile, at depth and at desired orientation, even though the latch couplings orientation is an unknown.

With the adaptive orienting latch, an operator will be able to run and install casing liner to depth without need to rotate or orient. This means less risk, and potentially longer sections with increased well exposure. Also, if the adaptive orienting latch is being run in multiple sections of liner, alignment in between is no longer critical and can be disregarded. This leads to reduced time spent on alignment and reduced potential risk of misalignment. The adaptive latch coupling does not require any alignment to the connected well equipment and may be installed in any orientation with respect to the whipstock taper. This will then reduce and/or eliminate the risk of any misalignment upon the assembly process.

One embodiment of the adaptive orienting latch is shown in. As shown, the adaptive orienting latch has two main components, the latch coupling, with the inner plurality of axial alignment slots, and the mating latch collet. The latch coupling will be made up to the casing sting and run in hole. The latch collet will be made up as a subcomponent to the planned well equipment, such as a whipstock and or a deflector. Depending on operational requirements, an inner mandrel may also be installed to allow for the latch collet to become propped and thereby fully locked into the latch coupling.

As shown in, the latch collet has multiple torque buttons in combination with the transaxially shoulders. All of these torque buttons hold torsional loading applied after latching in at depth. Again, while the embodiment ofillustrate each torque button having a set of torque button portions, other embodiments exist wherein each torque button is a single longitudinal torque button. As the latch collet is run into the latch coupling, the transaxial shoulders will engage and the torque buttons will engage into closest aligned position of the latch couplings axially alignment slots by applying any torsional loading.