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Slotted liner drilling

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20140238748 patent thumbnailZoom

Slotted liner drilling


Drilling assemblies, systems and methods enable a wellbore to be drilled and lined with a slotted liner. A drilling system includes a liner assembly with a drill string in a bore thereof. The drill string and the liner assembly can be selectively coupled together to restrict relative motion between the liner assembly and the drill string. The liner assembly includes a slotted liner portion through which fluid may flow. As the drilling system is used to drill a wellbore, the liner assembly is simultaneously positioned within the wellbore. Once the wellbore is drilled to a desired depth, the drill string can be disengaged from the liner assembly and retrieved from the well. Production fluids such as oil and gas may then be transferred uphole through the liner assembly.
Related Terms: Elective Drilling System

Browse recent Smith International, Inc. patents - Houston, TX, US
USPTO Applicaton #: #20140238748 - Class: 175 57 (USPTO) -
Boring Or Penetrating The Earth > Processes



Inventors: Bill B. Dubose, Henry Foy, Matthew D. Flach, Joshua A. Blankenship, Austin C. Groover, Russell A. Wagstaff

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The Patent Description & Claims data below is from USPTO Patent Application 20140238748, Slotted liner drilling.

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CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to, and the benefit of, U.S. Patent Application Ser. No. 61/768,890, filed on Feb. 25, 2013, and entitled “SLOTTED LINER DRILLING”, which is expressly incorporated herein by this reference in its entirety.

BACKGROUND

A well may be formed to extract natural resources such as oil, gas, water, minerals, and the like. Such wells may be formed by drilling using drill pipe up to a certain depth, after which the drill pipe is removed and casino, is run and cemented in the well. The operator may then drill the well to a greater depth with drill pipe, and cement another string of casing in place. In this type of system, each string of casing may extend to a wellhead assembly at the surface of the well.

In some well completions, an operator may install a liner rather than another string of casing. The liner is made up of joints of pipe in the same manner as casing, and the liner is also cemented into the well. The liner, however, does not extend back to the wellhead assembly at the surface. Instead, the liner is attached to a liner hanger coupled to the last string of casing just above the lower end of the casing. The operator may later install a tieback string of casing that extends from the wellhead downward into engagement with the liner hanger assembly.

When installing a liner, the operator may dull the well to the desired depth, retrieve the doll string, then assemble and lower the liner into the well. A liner top packer may also be incorporated with the liner hanger. A cement shoe with a check valve may be attached to the lower end of the liner as the liner is made up. When the desired length of liner is reached, the operator may attach a liner hanger to the upper end of the liner, and attach a running tool to the liner hanger. The operator may then run the liner into the well on a string of drill pipe that is attached to the running, tool. Thereafter, the operator may set the liner hanger and pinup cement through the drill pipe, down the liner, and back up an annulus surrounding the liner. The cement shoe limits or prevents the flow of cement back into the liner. The running tool may dispense as wiper plug following the cement to wipe cement from the interior of the liner at the conclusion of the cement pumping. When a liner top pack is used, the operator may then set the liner top packer, release the running tool from the liner hanger, and retrieve the drill pipe.

SUMMARY

According to an embodiment of the present disclosure, a drilling system may include a litter assembly that has a central bore formed therethrough. The liner assembly may include a slotted liner portion having a plurality of slots formed therethrough. The drilling system may also include a drill string disposed at least partially within the central bore of the liner assembly, such that an annulus may be formed between the liner assembly and the drill string. The drill string may be selectively engageable with the liner assembly.

In another embodiment of the present disclosure, a method of drilling may include drilling a wellbore to a pre-determined depth using a slotted liner drilling assembly. The slotted liner drilling assembly may include a drill string engaged with a liner assembly. The method may further include disengaging the drill string from the liner assembly and removing the drill string from the wellbore.

A method of drilling according to another embodiment of the present disclosure may include engaging a liner assembly with a drill string. An annulus may be formed between the liner assembly and the drill string. The method of drilling may also include drilling a wellbore with the drill string engaged with the liner assembly, circulating drilling fluid downhole through the drill string, and circulating the drilling fluid uphole through the annulus.

This summary is provided to introduce some features and concepts that are further developed in the detailed description. Other features and aspects of the present disclosure will become apparent to those persons having ordinary skill in the art through consideration of the ensuing description, the accompanying drawings, and the appended claims. This summary is therefore not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a side view of a liner assembly in accordance with one or more embodiments of the present disclosure.

FIG. 2 is a side view of a drill string in accordance with one or more embodiments of the present disclosure.

FIG. 3 is a partial cross-sectional view of the liner assembly of FIG. 1 engaged with the drill string of FIG. 2, according to one or more embodiments of the present disclosure.

FIG. 4 is a cross-sectional schematic view of the liner assembly of FIG. 1 engaged with the drill string of FIG. 2, according to one or more embodiments of the present disclosure.

FIG. 5 is a flow chart of a method of drilling according to one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

One or more embodiments of the present disclosure are directed to drilling apparatuses, methods, and systems for drilling a wellbore, while simultaneously installing a slotted liner in the wellbore. More particularly, some embodiments of the present disclosure are directed to drilling apparatuses, methods, and systems to allow a wellbore to be drilled with a slotted liner, such that the slotted liner may not be installed in a separate process following drilling of the wellbore.

One or more embodiments of the present disclosure may further be directed to a slotted liner drilling assembly. A slotted liner drilling assembly may be used to drill a wellbore while also positioning a slotted liner at a predetermined depth within the wellbore. In one or more embodiments, the slotted liner drilling assembly may include a slotted liner and a drill string. For example, drill string may be run into the wellbore, and may even drill the wellbore, while a slotted liner is simultaneously run into the wellbore. The drill string may be positioned within the slotted liner. In some embodiments, the slotted liner is disposed around the drill string in a manner that allows torque, axial force, weight, and other forces encountered during the drilling process to be borne primarily by the drill string and not the slotted liner. Because the torque, axial force, weight, and other forces encountered during drilling are borne primarily by the drill string, the slotted liner may be positioned in the wellbore during the drilling process, which may reduce the time for drilling the wellbore and commencing production.

For example, a slotted liner drilling assembly according to embodiments of the present disclosure may reduce the time for drilling the wellbore and beginning production by removing a process of separately running a slotted liner into the wellbore after the wellbore has been drilled and the drill string has been removed from the wellbore. In one or more embodiments, once the production section of the wellbore is drilled, the drill string may be disengaged from the slotted, liner, and the slotted liner may remain in the wellbore after a single drilling run. Having the slotted liner and/or casing downhole may also be useful during swelling or sloughing of the formation to facilitate maintaining the wellbore shape, integrity, or quality.

Referring to FIG. 1, a liner assembly 100 is shown in accordance with an embodiment of the present disclosure, in such an embodiment, the liner assembly 100 may include one or more casing sections and one or more slotted liner portions, as will be discussed in greater detail herein. The liner assembly 100 may have a bore 123 (see FIG. 3) formed therethrough. In at least some embodiments, the bore 123 may be a central bore aligned with a central or longitudinal axis of the liner assembly 100, although in other embodiments the bore 123 may be offset from, or angled relative to, the central or longitudinal axis of the liner assembly 100. According to some embodiments, the bore 123 may render the liner assembly 100 or a component thereof) substantially hollow. In one or more embodiments, the liner assembly 100 may be configured to receive a drill string 110 at least partially through or within the bore 123.

In one or more embodiments, the liner assembly 100 may include one or more segments of casing 101. The segments of casing 101 may be tubular structures that are generally cylindrical in shape. In the illustrated embodiment, a segment of casing 101 is illustrated at the upper portion of the liner assembly 100. In other embodiments, a liner assembly 100 may include one or more segments of casing 101 at an intermediate or lower portion of the liner assembly 100. Similarly, in some embodiments, a liner assembly 100 may include one or more segments of casing 101 at both the upper portion and the lower portion of the liner assembly 100, at multiple intermediate portions, or at one or more intermediate portions and one or more of the upper or lower portions of the liner assembly 100. In one or more embodiments, the segments of casing 101 may extend from the surface. For instance, the segments of casing, 101 may extend to a casing profile nipple discussed in greater detail herein.

The one or more segments leasing 101 may be used (e.g., by an operator at the surface of the wellbore) to apply torque or axial force to the liner assembly 100. Further, in one or more embodiments, the one or more segments of casing 101 may be used to line and case the wellbore to increase structural rigidity and integrity, or isolate portions of the wellbore, after the wellbore has been drilled. In one or more embodiments, the one or more segments of casing 101 may be coupled together or engaged by way of couplings (e.g., threaded connectors). The one or more segments of casing 101 may be formed from carbon steel, stainless steel, aluminum titanium, fiberglass, composite materials, other materials, or a some combination of the foregoing. In one or more embodiments, the one or more segments of casing 101 may replace or supplement drill pipe that may be used for a drilling operation.

According to some embodiments of the present disclosure, the liner assembly 100 may include a casing profile nipple 102. The casing profile nipple 102 may be used to couple a segment of casing 101 to a perforated liner portion 103. For instance, a first end of the casing profile nipple 102 may be coupled to a segment of casing 101 and a second end of the casing profile nipple 102 may be coupled to the perforated liner portion 103. The connections between the segment of casing 101 and the casing profile nipple 102 and between the casing profile nipple 102 and the perforated liner portion 103 may take a variety of forms. For instance, the connections may be made by threaded interfaces, mating interfaces, welding, interference or friction fits, any other suitable mechanism, or some combination of the foregoing.

The casing profile nipple 102 may be configured for selective and secure engagement with a drill lock assembly of a drill string 110 (e.g., drill lock assembly 111 of FIG. 2), as discussed in greater detail herein. The casing profile nipple 102 may include one or more slots, grooves, tabs, or other features on an interior surface such that engagement with a drill string 110 may allow torque, axial force, or weight applied, to the liner assembly 100 to be transferred to the drill string 110. For example, in one or more embodiments, the casing profile nipple 102 may include one or more slots or grooves formed on an inner surface of the casing profile nipple 102, and the drill string 110 may include one or more tabs or splines for engaging the slots or grooves.

In one or more embodiments, an inner diameter of the casing profile nipple 102 may cooperate with an outer diameter of a portion of the drill string 100 (e.g., a drill lock component or assembly). For instance, the inner diameter of the casing profile nipple 102 may be substantially identical, slightly larger than, or otherwise correspond to the outer diameter of a drill lock assembly or other portion of the drill string 110. The corresponding diameters may allow for selective engagement between the casing profile nipple 102 and at least a portion of the drill string 110, and may result in secure engagement between the casing profile nipple 102 (and thus the liner assembly 100) and at least a portion of the drill string 110. The secure engagement between the casing profile nipple 102 and the drill string 110 may link together the motions of the casing profile nipple 102 (and thus the liner assembly 100) and the drill string 110. For instance, axial movement of the casing profile nipple 102 may result in or be associated with axial movement of the drill string 110, and vice versa. Similarly, rotational movement of the casing profile nipple 102 may result in or be associated with axial movement of the drill string 110, and vice versa. Thus, coupling the casing profile nipple 102 to the drill string 110 may restrict and potentially prevent relative axial and/or rotational motion between the liner assembly 100 and a drill string 110 located therein.

As noted above and as shown in FIG. 1, a liner assembly 100 of embodiments of the present disclosure may include a perforated liner portion 103. The perforated liner portion 103 of FIG. 1 includes a plurality of slots 104 formed therethrough. More particularly, the plurality of slots 104 may be a plurality of perforations, openings, gaps, or spaces formed through one or more walls of the perforated liner portion 103, and may provide for fluid communication between the bore 123 (see FIG. 3) and an outer annulus around the exterior of the liner assembly 100. Thus, fluid may pass from an outer surface of the liner assembly 100 through the slots 104 of the liner assembly 100 and to an inner surface of the liner assembly 100, and/or vice versa. In one or more embodiments, the plurality of slots 104 in the perforated liner portion 103 may be used to filter a formation fluid during production. In the same or other embodiments, the plurality of slots 104 may limit and control an amount of sand that may pass through the liner assembly 100 with a formation fluid.

The perforated liner portion 103 may include a single perforated liner segment, or, as illustrated, the perforated liner portion may include multiple perforated liner segments 105 coupled together. The one or more perforated liner segments 105 may be coupled together in a variety of ways. For instance, the one or more perforated liner segments 105 may be coupled together by way of threaded interfaces, mating interfaces, welding, or any other suitable mechanism. In some embodiments, the one or more perforated liner segments 105 may be coupled together by one or more intermediate coupling components. As illustrated in FIG. 1, for example, the one or more perforated liner segments 105 may be coupled together by way of casing couplings 106. Similar to the other connections described herein, the connections between the one or more perforated liner segments 105 and the casing couplings 106 may take any suitable form (e.g., threaded interfaces, mating interfaces, welding).

In some embodiments, the casing couplings 106 may act as, or be replaced by, one or more stabilizer or centralizer components. The one or more stabilizer/centralizer components may have an outer diameter that is larger than an outer diameter of the perforated liner portion 103. Optionally, such components may engage the interior wall of the wellbore or a casing within a wellbore to stabilize and center the liner assembly 100 within the wellbore.

As shown in FIG. 1, one or more embodiments of the liner assembly 100 may further include a casing shoe guide 107. According to some embodiments, the casing profile nipple 102 may be separated from the casing shoe guide 107 by one or more segments of perforated liner portions 103. Thus, in one or more embodiments, there may be up to several hundred feet of separation between the casing profile nipple 102 and the casing shoe guide 107. The casing shoe guide 107 may be configured to selectively and securely engage with a portion of the drill string 110 (e.g., a casing shoe), as discussed in greater detail herein.

In one or more embodiments, an inner diameter of the casing shoe guide 107 may be substantially identical or correspond to (or be slightly larger than) an outer diameter of a portion of the drill string, 110 (e.g., the casing shoe). The corresponding diameters and/or the selective engagement between the casing shoe guide 107 (and thus the liner assembly 100) and at least a portion of the drill string 110 may result in secure engagement between the casing shoe guide 107 and at least a portion of the drill string 110. The secure engagement between the casing shoe guide 107 and the casing shoe or other portion of the drill string 110 may link together the motions of the casing shoe guide 107 (and thus the liner assembly 100) and the drill string 110, thereby restricting or potentially preventing relative motion between the liner assembly 100 and the drill string 110. For instance, axial movement of the casing shoe guide 107 may result in or be associated with axial movement of the drill string 110, and vice versa. Similarly, rotational movement of the casing shoe guide 107 may result in or be associated with axial movement of the drill string 110, and vice versa.

In some embodiments, both the casing profile nipple 102 and the casing shoe guide 107 may be selectively and securely engaged with the drill string 110. Securing the perforated liner portion 103 to the drill string 110 at two locations (e.g., at ends of the perforated liner portion 103 via the casing profile nipple 102 and the casing shoe guide 107) may reduce the potential for structural damage to the perforated liner portion 103. By way of example, coupling the perforated liner portion 103 to the drill string 110 at axially offset locations may allow the structure of the drill string 110 to provide axial rigidity to the perforated, liner portion 103. Similarly, coupling the perforated, liner portion 103 to the drill string 110 at two locations and/or at one or more ends of the perforated liner portion 103 may allow the structure of the drill string 110 to provide rotational rigidity to the perforated liner portion 103. That is, coupling the perforated liner portion 103 to the drill string 110 at two locations may limit or even prevent opposing ends of the perforated liner portion 103 from rotating relative to one another, which could cause the perforated liner portion 103 to become twisted or damaged.

Referring now to FIG. 2, a drill string 110 in accordance with embodiments disclosed herein is shown in additional detail. In one or more embodiments, the drill string 110 may be a retrievable drill string that may be used to drill and/or underream a wellbore. As described above, the drill string. 110 may include a drill lock assembly 111 for selectively coupling the drill string 110 to the liner assembly 100. For instance, the drill lock assembly 111 may include one or more locking mechanisms that may selectively and securely engage the drill lock assembly 111 with the casing profile nipple 102 of the liner assembly 100 shown in FIG. 1. For example, in one or more embodiments, the drill lock assembly 111 may include vertical and/or horizontal locking dogs, slips, splines, or other features that may be actuated to engage with one or more slots or grooves formed in the casing profile nipple 102. The grooves formed in the casing profile nipple 102 may therefore be longitudinal or annular grooves. Multiple grooves may also be longitudinally and/or circumferentially offset.

In one or more embodiments, actuation of the drill lock assembly 111 of the drill string 110 may occur by way of any means known in the art (e.g., using a retrievable actuation tool, ball drop, dart, electrical signal, etc.), which may cause the one or more locking mechanisms to engage the casing profile nipple 102. For instance, in embodiments where the one or more locking mechanisms include one or more locking dogs, the drill lock assembly 111 may be actuated to cause the one or more locking dogs to extend or displace radially outwardly from the drill lock assembly 111. Radially displacing one or more locking dogs of the drill lock assembly 111 may cause one or more of the locking dogs to engage with a portion of the liner assembly 100 (e.g., with one or more slots or grooves formed in the casing profile nipple 102). Similarly, deactivation of the drill lock assembly 111 may be performed by using any means known in the art. An example deactivation of the drill lock assembly 111 may include causing one or more lock dogs to retract or displace radially inward and disengage from the liner assembly 100 (e.g., disengage from one or more slots or grooves formed in the interior surface of the casing profile nipple 102). Thus, in one or more embodiments, the drill lock assembly 111 may be actuated and de-actuated from the surface (e.g., an operator or other controller at the surface) to at least partially control engagement of the drill string 110 with the liner assembly 100.

In one or more embodiments, the drill string 110 may include one or more internal tandem segments 112. The internal tandem segments 112 may be formed from steel, titanium, metal alloys, composite materials, any other suitable material, or some combination of the foregoing. In one or more embodiments, the internal tandem segments 112 may be used to limit undesired vibration of the drill string 110 during drilling operations, and may act as a stabilizer for the drill string 110 downhole. The internal tandem segments 112 may have an outer diameter that is larger than an outer diameter of at least a portion of the drill string 110 may act as centralizers to keep the drill string 110 centered within the liner assembly 100 when disposed in the bore 123 (see FIG. 3). In the illustrated embodiments, the drill string 110 is shown as including two internal tandem segments 112—one coupled to a lower end of the drill lock assembly 111 and one coupled above a bottom hole assembly and a circulating sub 115. Other embodiments of drill strings may include, however, a single internal tandem segment 112 or more than two internal tandem segments 112.

Further, as shown, the drill string 110 may include one or more cross-over segments 113 coupled between the internal tandem segments 112 and an inner casing string 114. The connections between the internal tandem segments 112, the cross-over segments 113, and the inner casing string 114 may be any suitable connection type (e.g., threaded interfaces, mating interfaces, welding). As shown, the internal tandem segments 112 may be positioned both above and below the inner casing string 114, with the cross-over segments 113 coupling each internal tandem segment 112 to the inner casing string 114. In one or more embodiments, the inner casing string 114 (or a coupling between sections of the inner casing string 114) may have an outer diameter that is substantially identical to, or slightly less than, an inner diameter of the perforated liner portion 103 of the liner assembly 100.

In one or more embodiments, such as shown in FIG. 2, the drill string 110 may include a circulating sub 115 below the lower internal tandem segment 112. The circulating sub 115 may help guide the inner casing string 114 of the drill string 110 downhole. In one or more embodiments, the circulating sub 115 may be configured to engage with the casing shoe guide 107 of the liner assembly 100 shown in FIG. 1. By way of example, the circulating sub 115 may have one or more outer surfaces sized, shaped, with surface features, or otherwise configured to generally correspond to one or more inner surfaces of the casing shoe guide 107. In some embodiments, the circulating sub 115 may include one or more selectively actuatable locking mechanisms (e.g., vertical, axial, or annular locking dogs and/or slips) that selectively and securely engage the circulating sub 115 with the casing shoe guide 107. In some embodiments, such as that shown in NG 2, the circulating sub 115 may include one or more casing shoes 119 that are configured to engage the casing shoe guide 107. The one or more casing shoes 119 may be considered locking mechanisms that couple the circulating sub 115 to the casing shoe guide 107.

In one or more embodiments, the one or more casing shoes 119 may include one or more sealing elements or sealing mechanisms that may restrict or even prevent fluid communication through the engagement between the circulating sub 115 and the casing shoe guide 107. Specifically, the one or more casing shoes 119 may include one or more annular sealing elements or sealing mechanisms that may restrict or prevent fluid flowing from beneath the one or more casing shoe 119 upwardly toward the surface in an annular region between the circulating sub 115 and the casing shoe guide 107. Similarly, the one or more casing shoes 119 may include one or more sealing elements or sealing mechanisms that may restrict or even prevent fluid flowing from above the one or more casing shoes 119 downwardly toward the bottom of the wellbore in the annular region between the circulating sub 115 and the casing, shoe guide 107.

For example, the one or more sealing elements or mechanisms of the one or more casing shoes 119 may include rubber seals, chevron seals, or any other suitable seal. In one or more embodiments, the circulating sub 115 may be activated to seal the one or more casing shoes 119 against the casing shoe guide 107 to restrict or prevent cuttings from getting inside of the liner assembly 100 through an inner annulus formed between the circulating sub 115 and the casing shoe guide 107. In some embodiments, the circulating sub 115 may be activated/deactivated independent of the activation/deactivation of the drill lock assembly 111. In other embodiments, the activation/deactivation of the circulating sub 115 and the drill lock assembly 111 may be linked together or dependent on one another. In still other embodiments, the activation or deactivation of the circulating sub 115 may be linked to either the activation or deactivation of the drill lock assembly 111, while the other is not so linked. For instance, the activations of the drill lock assembly 111 and the circulating sub 115 may be linked together, while the deactivations thereof may be independent of one another.

In one or more embodiments, the circulating sub 115 may be activated by an obstruction such as a ball or dart, and may be used to seal the one or more casing shoes 119 against the casing shoe guide 107 to restrict or even prevent, cuttings and fluid from getting inside of the liner assembly 100 through the inner annulus formed between the circulating sub 115 and the casing shoe guide 107. In one or more embodiments, the circulating sub 115 ma be activated upon retrieval of the drill string 110 to clean debris that may have accumulated in one or more of the plurality of slots (i.e., slots 104) formed in the liner assembly 100. In order to clean out the plurality of slots 104, the circulating sub 115 may include one or more ports 120 positioned above and/or below the one or more casing shoes 119. Once the circulating sub 115 is activated, the ports 120 positioned above and/or below the one or more casing shoes 119 may open and allow fluid pumped through the drill string 110 to exit the drill string 110 through the one or more ports 120. Fluid exiting through the one or more ports 120 may act as a fluid jet to clear the plurality of slots 104 formed in the liner assembly 100 of debris. Further, allowing fluid to exit the one or more ports 120 of the circulating sub 115 may limit or even avoid or prevent swabbing of the formation during retrieval.

According to some embodiments, the drill string 110 may include an underreamer 116. The underreamer 116 may be a drilling-type underreamer configured to run in conjunction with a drill bit (e.g., drill bit 118), or it may be an underreamer for use without a drill bit. The underreamer 116 may include radially retractable arms, which may be used for cutting. In one or more embodiments, the radially retractable arms of the underreamer 116 may be selectively extended and held in position by hydraulic pressure (e.g., selective fluid flow through the drill string 110) and may be repositioned downhole for selective underreaming operations or retrieval from the wellbore. In one or more embodiments, the underreamer 116 may be used to increase the size of the wellbore drilled by the drill string 110. In one or more embodiments, when the underreamer 116 is actuated and engaged with a wall of the wellbore, an outer annulus between the wall of the wellbore and the exterior liner assembly 100 may be formed, which may allow passage of the liner assembly 100 during drilling.

Further, in one or more embodiments, the drill string 110 may include one or more logging-while-drilling (LWD) or measurement-while-drilling (MWD) tool(s) 117. In the illustrated embodiment, the drill string 110 includes a tool 117 below the underreamer 116. It will be appreciated that the drill string 110 may include any of a variety of LWD or MWD tools, and that such tools may be positioned at any suitable location along the drill string 110.

Furthermore, in one or more embodiments, the drill string 110 may include a drill bit 118 positioned below the LWD/MWD tool(s) 117. In one or more embodiments, the drill bit 118 may be a fixed cutter drill bit. Fixed cutters made of polycrystalline diamond (PCD), tungsten carbide (WC), cubic boron nitride (CBN), or other materials may be coupled to a b body of the drill bit 118. In other embodiments, however, the drill bit 118 may be a roller cone bit, a percussion hammer bit, or any other suitable type of drill bit. In one or more embodiments, the underreamer 116, the LWD/MWD tool(s) 117, and the drill bit 118 may be considered to be part of a bottomhole assembly (BHA) 121.

Referring now to FIG. 3, an engaged slotted liner drilling assembly 122 is shown in accordance with embodiments of the present disclosure. In one or more embodiments, the slotted liner drilling assembly 122 may be a drilling assembly. As shown, the engaged slotted liner drilling assembly 122 may include a drill string 110 disposed within and engaged with a liner assembly 100. The drill string 110 may be disposed within the central bore 123 formed through the liner assembly 100. In one or more embodiments of the engaged slotted liner drilling assembly 122, the drill string 110 may be concentric with the liner assembly 100, although the drill string 110 may be otherwise positioned in other embodiments. Further, an annulus may be formed between the liner assembly 100 and the drill string 110 of the engaged slotted liner drilling assembly 122. In one or more embodiments, a portion of the drill string (e.g., one or more of the underreamer 116, the LWD/MWD tool(s) 117, or the drill bit 118) may extend below the liner assembly 100.

As discussed herein, the liner assembly 100 may include a casing profile nipple 102, and the drill string 110 may include a corresponding drill lock assembly 111 configured to engage with the casing profile nipple 102 of the liner assembly 100. In one or more embodiments, the drill lock assembly 111 of the drill string 110 may be actuated by suitable means or mechanism (e.g., using a retrievable actuation tool, ball drop, dart, electric signal, etc.), which may cause one or more locking dogs, slips, or other components to extend or displace radially outwardly from an outer surface of the drill lock assembly 111. Radially displacing one or more vertical, axial, annular, or other locking dogs or slips of the drill lock assembly 111 may cause one or more of the locking dogs to engage with a portion of the liner assembly 100. For instance, one or more slips may engage directly against the inner surface of the casing profile nipple 102, or one or more engagement features 124 (e.g., locking dogs or slips) may engage the casing profile nipple 102. Slips may, for instance, expand to engage the inner surface of the casing profile nipple 102, whereas locking dogs or other similar components may enter one or more slots or grooves 125 formed in the casing profile nipple 102. Similarly, any suitable means or mechanism may be used to de-actuate the drill lock assembly 111, which may cause one or more slips, locking dogs, or other engagement features 124 to retract or otherwise displace radially inward and disengage from the liner assembly 100 (e.g., disengage from one or more slots or grooves 125 formed in the casing profile nipple 102, or from an interior surface of the casing profile nipple 102). Thus, in one or more embodiments, the drill lock assembly 111 may be actuated and de-actuated from the surface (e.g., an operator or controller at the surface) to control engagement of the drill string 110 with the liner assembly 100. Once the drill lock assembly 111 and/or the casing shoes 119 are de-actuated, the drill string 110 may no longer be engaged with the liner assembly 100, and the drill string 110 may be retrieved from the wellbore, thereby leaving the liner assembly 100 in the wellbore.

As discussed elsewhere herein, when the drill string 110 is disposed within and selectively coupled to the liner assembly 100, the drill string 110 may provide structural reinforcement for the liner assembly 100. Disposing and securing the drill string 110 at least partially within the liner assembly 100 may allow a substantial portion of any torque, axial force, weight, or other forces applied to or encountered the liner assembly 100 (e.g., torque, axial force, or weight applied to the casing segments 101), and potentially the entirety of such forces, to be transferred to the drill string 110. The structural reinforcement provided to the liner assembly 100 by the drill string 110 may allow the liner assembly 100 to be positioned in the wellbore during drilling operations. As such, the perforated liner portion 103 of the liner assembly 100 may not experience torque, axial force, weight, or other forces that may otherwise cause the plurality of slots 104 to collapse, plug, or buckle during drilling operations.

In one or more embodiments, the torque, axial force, weight, or other forces applied to or encountered by the liner assembly 100 may be transferred to the drill string 110 via the engagement between the drill lock assembly 111 and the casing profile nipple 102 and/or between the engagement between the casing shoe guide 107 and the one or more casing shoes 119. As such, in one or more embodiments, torque, axial force, weight, or other forces may be applied to the casing 101 of the liner assembly 100 from the surface, which may be transferred to the drill string 110 and to the drill bit 118.

In one or more embodiments, the BHA 121 may include a bit release tool positioned above the drill bit 118. In embodiments where the drill bit 118 is a non-retrievable bit, the bit release tool may be used to decouple the bit 118 from the drill string 110. For instance, once the wellbore has been drilled to a desired depth, the bit release tool may be activated to decouple the drill bit 118 from the drill string 110. The bit release tool may be activated using one or more of hydraulic, mechanical, or electrical mechanisms (e.g., retrievable actuation tool, ball drop, dart, etc.). Once the drill bit 118 has been released, the rest of the drill string 110—including the remaining portions of the BHA 121—may be retrieved. In particular, the drill lock assembly 111 and/or the casing shoes 119 may be de-actuated to disengage the drill string 110 from the liner assembly 100. The drill string 110 may then be withdrawn from the wellbore and the liner assembly 100, leaving the liner assembly 100 in place in the wellbore. This may also allow the liner assembly 100 to be positioned in the wellbore at a predetermined depth (e.g., total depth, a production location, etc.), without transferring damaging loads to the liner assembly 100 and without having to make separate drilling and liner placement runs.

Further, as shown, the circulating sub 115 of the drill string 110 may be disposed within and engaged with the casing shoe guide 107 of the liner assembly 100. As noted, in one or more embodiments, the circulating sub 115 may include one or more casing shoes 119 that restrict or even prevent fluid flow through an inner annulus formed between the circulating sub 115 and the casing shoe guide 107 of the liner assembly 100.

In some embodiments, at least one of the one or more ports 120 may be positioned above the one or more shoe seals 119 so as to be positioned within the liner assembly 100. Fluid pumped through the drill string 110 and out of the upper port(s) 120 may flow uphole between the liner assembly 100 and the drill string 110. In some embodiments, at least some of the fluid pumped out of the upper port(s) 120 may pass through the plurality of slots 104 out of the liner assembly 100, such as to clean out the slots 104.

Similarly, in some embodiments, at least one of the one or more ports 120 may be positioned below the one or more shoe seals 119. Fluid pumped through the drill string 110 and out of the lower port(s) 120 may flow uphole between the liner assembly 100 and the wellbore. In some embodiments, at least some of the fluid pumped out of the lower port(s) 120 may pass through the plurality of slots 104 into the liner assembly 100, such as to clean out the slots 104. The drill bit 118 may also include one or more ports or nozzles through which fluid may be pumped.

For example, referring to FIG. 4, as drilling fluid is circulated downhole through the drill string 110 (indicated by dashed arrows) and out of the port(s) 120 or nozzles of the drill bit 118 (indicated by solid arrows), the casing shoes 119 may restrict or prevent the drilling fluid from passing between in the inner annulus between the circulating sub 115 and the casing shoe guide 107. In other words, the casing shoes 119 may divert fluid exiting the lower port(s) 120 toward an outer annulus formed between the wellbore 109 and the liner assembly 100. As shown, the slotted liner portion 103 may be positioned below the casing profile nipple 102 and below the at least one casing segment 101. Because the uphole-directed drilling fluid flow may initially be diverted toward the outer annulus formed between the wellbore 109 and the liner assembly 100 (e.g., by way of the casing seals 119), the drilling fluid may be restricted or prevented from flowing uphole through the inner annulus at a location formed between the liner assembly 100 and the drill string 110 until the drilling fluid passes radially through the slotted liner portion 103 of the liner assembly 100. As discussed herein, the slotted liner portion 103 may include a plurality of slots 104 formed therethrough, which may allow the drilling fluid flowing uphole to pass radially from the outer annulus formed between the wellbore 109 and the liner assembly 100 into the inner annulus formed between the liner assembly 100 and the drill string 110. Where the casing profile nipple 102 and the at least one casing segment 101 are positioned above the slotted liner portion 103, the drilling fluid may be circulated uphole through the inner annulus formed between the liner assembly 100 and the drill string 110, through the casing profile nipple 102, and through the at least one casing segment 101 to the surface.

In some embodiments the casing shoes 119 may direct the fluid exiting the upper port(s) 120 uphole through an inner annulus formed between the liner assembly 100 and the drill string 110. In some embodiments, the fluid flowing out of the upper port(s) 120 may pass through the slots 104 and into the outer annulus formed between the liner assembly 100 and the wellbore 109. In one or more embodiments, the drilling fluid may be filtered through the slotted liner portion 103 (e.g., through the plurality of slots 104) of the liner assembly 100 when the drilling fluid is circulated uphole.

According to another aspect of the present disclosure, there is provided a method of drilling and completing a well. As illustrated in FIG. 5, for instance, a method 150 may be used for drilling and completing a well, and may include disposing a drill string in a slotted liner assembly 151. For instance, at least a portion of a drill string (e.g., drill string 110 of FIG. 2) may be inserted or passed through a bore formed in a slotted liner assembly (e.g., slotted liner assembly 100 of FIG. 1). In some embodiments, when the drill string is disposed in the slotted liner assembly, at least a portion of the drill string, such as a drill bit, underreamer, bottomhole assembly, etc. may extend out of a lower end of the slotted liner assembly.

The method 150 may also include coupling the slotted liner assembly to the drill string 152. Coupling the slotted liner assembly to the drill string may be accomplished in various ways. For instance, the slotted liner assembly and the drill string may have corresponding, mating, or engageable surfaces. In some embodiments, selectively actuatable locking mechanisms (e.g., drill lock assemblies, locking dogs, expandable/retractable slips, etc.) may be used to couple the slotted liner assembly to the drill string. Coupling the slotted liner assembly to the drill string may also include forming one or more seals between components of the slotted liner assembly and the drill string. For instance, a seal may be formed between a portion of the slotted liner assembly (e.g., casing shoe guide 107) and a portion of the drill string (e.g., circulating sub 115). The one or more seals may be formed using various sealing mechanisms (e.g., casing shoe 119), whether selectively actuatable or not.

As illustrated in FIG. 5, in one or more embodiments, the method 150 may also include drilling a wellbore 153. For instance, a slotted liner drilling assembly (e.g., slotted liner drilling assembly 122) that includes a drill string engaged with a slotted liner assembly may be used for drilling a wellbore. Drilling a wellbore 153 may be accomplished by engaging a drill bit (e.g., drill bit 118) with the earth and applying torque, axial force, weight, or some other force to the slotted liner assembly (e.g., via drill string 110 or casing 101). In some embodiments, the torque, axial force, weight, or other force applied to the slotted liner assembly may be transferred from the slotted liner assembly to the drill string. The torque, axial force, weight, or other force may be transferred from the slotted liner assembly to the drill string by way of the engagement between the slotted liner assembly and the drill string. For instance, the torque, axial force, weight, or other force may be transferred from the slotted liner assembly to the drill string by way of locking and/or sealing mechanisms that couple together and/or form seals between the slotted liner assembly and the drill string.

In some embodiments, a substantial portion of the torque, axial force, weight, or other force is transferred from the slotted liner assembly to the drill string at a location above a slotted liner portion (e.g., slotted liner portion 103) of the slotted liner assembly. As discussed herein, transferring the torque, axial force, weight, or other force from the slotted liner assembly to the drill string at a location above a slotted liner portion can limit or even prevent the slotted liner portion or slots (e.g., slots 104) formed therein from collapsing, plugging, buckling, or otherwise being damaged. Thus, in one or more embodiments, a slotted liner assembly may be used simultaneously and in combination with a drill string to drill a wellbore to a predetermined depth.

A method 150 of drilling and completing a well may also include circulating fluid 154. As discussed above, fluid may circulated through a slotted liner drilling assembly by pumping fluid down through the drill string and out of the drill string through one or more ports (e.g., ports 120). The ports may remain open or may be selectively opened. In one or more embodiments, prior to circulating the fluid, seals may be activated to limit or prevent the flow of the fluid between certain components of the slotted liner drilling assembly. For instance, a circulating sub (e.g., circulating sub 115) may be activated to actuate seals (e.g., casing shoes 119) to seal off an annulus formed between the circulating sub and a casing shoe guide or other component of a slotted liner assembly. As a result, cuttings and fluid outside of the slotted liner assembly may not be able to enter the slotted liner assembly through the annulus between the circulating sub and the casing shoe guide.

As discussed herein, fluid may be pumped out of the drill string through one or more ports. In some embodiments, one or more of the ports may be disposed inside the slotted liner assembly (e.g., upper ports above a sealing mechanism). The fluid that flows out of these port(s) may flow uphole through an inner annulus formed between the slotted liner assembly and the drill string. In some embodiments, the fluid may flow from the inner annulus between the slotted liner assembly and the drill string, through slots in the slotted liner assembly, and uphole through an outer annulus formed between the wellbore and the slotted liner assembly.

In some embodiments, one or more of the ports may be disposed outside of the slotted liner assembly (e.g., lower ports below a sealing mechanism). The fluid flowing out of lower port(s) may flow uphole through an outer annulus formed between the slotted liner assembly and the wellbore. In some embodiments, the fluid may flow from the outer annulus between the slotted liner assembly and the wellbore, through the slots in the slotted liner assembly, and uphole through an inner annulus formed between the drill string and the slotted liner assembly.

Circulating fluid through the slotted liner drilling assembly may assist with cleaning debris or cuttings from the slots in the slotted liner assembly. For instance, as fluid flows between the inner annulus formed between the drill string and the slotted liner assembly and the outer annulus formed between the slotted liner assembly and the wellbore, the debris and cuttings may be flushed out of the slots.

The method 150 shown in FIG. 5 may also include disengaging the drill string from the slotted liner assembly 155. Disengaging the drill string from the slotted liner assembly 155 may be accomplished by de-actuating a drill lock assembly and/or a sealing mechanism. De-actuating a drill lock assembly may cause one or more locking mechanisms (e.g., locking dogs, slips, etc.) to disengage from a slotted liner assembly. Disengaging the drill string from the slotted liner assembly may also include de-actuating or otherwise disengaging one or more seals (e.g., casing shoes sealed against a casing shoe guide). In some embodiments, disengaging the drill string from the slotted liner assembly may also include releasing the drill bit from the drill string.

According to some embodiments, a method 150 may also include removing a drill string 156. For instance, the drill string 156 may be removed from a slotted liner assembly and from a wellbore following drilling of the wellbore, and optionally running the casing into the wellbore simultaneously with the drill string during drilling. Once the drill string is disengaged from the slotted liner assembly, the drill string can be retrieved from the wellbore, leaving the slotted liner assembly in place in the wellbore. The method 150 may further include securing the slotted liner assembly in the wellbore 157. The slotted liner assembly may be secured in place in any suitable manner. For instance, cement may be pumped downhole so that it fills at least a portion of the outer annulus formed between the slotted liner assembly and the wellbore. The portion of the outer annulus between the slotted liner portion and the wellbore may be kept free of cement so that oil, gas, water, or other production materials may flow through the slots in the slotted liner portion, into the wellbore, and uphole through the slotted liner assembly.

The method of drilling 150 may also include producing a production fluid 158. In some embodiments, the production fluid may be produced while filtering the production fluid through a slotted liner. For instance, as the formation fluid flows from the wellbore through the slots in the slotted liner portion, the slots may filter debris, cuttings, or sand out of the formation fluid, resulting in cleaner production fluid entering the wellbore. Production fluid that is relatively clean and free of debris and cuttings may thereafter be pumped uphole through the slotted liner assembly.

In some embodiments, producing a production fluid may include positioning or deploying one or more packers between the slotted liner assembly and the wellbore above and/or below the slotted liner portion. The packer(s) may limit or prevent formation fluid from flowing uphole or downhole through the outer annulus formed between the slotted liner assembly and the wellbore. Rather, the production fluids flow into the slotted liner assembly through the slots in the slotted liner portion.

While slotted liner assemblies, drill strings, and methods of drilling and completing a well may be described herein with primary reference to downhole tools for oil and gas production, such embodiments are provided solely to illustrate one environment in which aspects of the present disclosure may be used. In other embodiments, devices, systems, assemblies, and methods of the present disclosure, or which would be appreciated in view of the disclosure herein, may be used in other applications, including in automotive, aquatic, aerospace, hydroelectric, or other industries. Further, the figures are not to scale for each embodiment within the scope of the present disclosure. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown or described in interest of clarity and conciseness.

In the description herein, various relational terms are provided to facilitate an understanding of various aspects of some embodiments of the present disclosure. Relational terms such as “bottom,” “below,” “lower, “top,” “above,” “upper”, “back,” “front,” “left”, “right”, “rear”, “forward”, “up”, “down”, “horizontal”, “vertical”, “clockwise”, “counterclockwise,” “inner”, “outer”, and the like, may be used to describe various components, including their operation and/or illustrated position relative to one or more other components. Relational terms do not indicate a particular orientation for each embodiment within the scope of the description or claims. For example, a component of a BHA that is “below” another component may be more downhole while within a primary or vertical wellbore, but may have a different orientation during assembly, when removed from the wellbore, or in a deviated borehole. Accordingly, relational descriptions are intended solely for convenience in facilitating reference to various components, but such relational aspects may be reversed, flipped, rotated, moved in space, or similarly modified. Relational terms may also be used to differentiate between similar components. Certain descriptions or designations of components as “first,” “second,” “third,” and the like may also be used to differentiate between similar components. Such language is not intended to limit a component to a singular designation. As such, a component referenced in the specification as the “first” component may be the same or different than a component that is referenced in the claims as a “first” component.

Furthermore, to the extent the description or claims refer to “an additional” or “other” element, feature, aspect, component, or the like, it does not preclude there being a single element, or more than one, of the additional element. Where the claims or description refer to “a” or “an” element, such reference is not be construed that there is just one of that element, but is instead to be inclusive of other components and understood as “one or more” of the element. It is to be understood that where the specification states that a component, feature, structure, function, or characteristic “may,” “might,” “can,” or “could” be included, that particular component, feature, structure, or characteristic is provided in some embodiments, but is optional for other embodiments of the present disclosure. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with,” “integral with,” or “in connection with via one or more intermediate elements or members.”

Although various example embodiments have been described in detail herein, those skilled in the art will readily appreciate in view of the present disclosure that many modifications are possible in the example embodiment without materially departing from the present disclosure. Accordingly, any such modifications are intended to be included in the scope of this disclosure. Likewise, while the disclosure herein contains many specifics, these specifics should not be construed as limiting the scope of the disclosure or of any of the appended claims, but merely as providing information pertinent to one or more specific embodiments that may fall within the scope of the disclosure and the appended claims. Any described features from the various embodiments disclosed may be employed in combination. In addition, other embodiments of the present disclosure may also be devised which lie within the scopes of the disclosure and the appended claims. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents and equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to couple wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Certain embodiments and features may have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, and/or the combination of any two upper values are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges may appear in one or more claims below. Any numerical value is “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.



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stats Patent Info
Application #
US 20140238748 A1
Publish Date
08/28/2014
Document #
14188209
File Date
02/24/2014
USPTO Class
175 57
Other USPTO Classes
166208
International Class
21B7/20
Drawings
4


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