SYSTEMS AND METHODS FOR CONNECTING SEPARATE COILED TUBING STRINGS AT A WELLSITE

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefit of U.S. provisional patent application No. 63/733,330 filed Dec. 12, 2024, and entitled “Systems and Methods for Connecting Separate Coiled Tubing Strings at a Wellsite,” and U.S. provisional patent application No. 63/784,452 filed Apr. 7, 2025, and entitled “Systems and Methods for Connecting Separate Coiled Tubing Strings at a Wellsite,” each of which is hereby incorporated herein by reference in its entirety for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

Coiled tubing (CT) systems are used to run continuous pipe into and out of wellbores. Continuous pipe may be referred to as CT because it is stored and transported on a coiled tubing reel. Coiled tubing can be used for drilling operations, and is likewise well-suited for servicing and/or producing hydrocarbons from existing wells. CT can be inserted into and removed from a wellbore extending through a subterranean earthen formation without having to first erect a complex drilling rig or other structure at a well site at which the wellbore is located. Instead, the CT may be conveniently unreeled from its associated storage reel and run into the wellbore with the assistance of additional surface equipment. Similarly, the CT may be conveniently reeled back onto the storage reel at the conclusion of the CT operation rather than needing to be broken down at the surface into a plurality of separate pipe joints or stands as with well operations that utilize drill pipe instead of CT. Further, during operation, CT may be subjected to bending and associated bending strains at varying bending radii.

BRIEF SUMMARY OF THE DISCLOSURE

An embodiment of a coiled tubing (CT) connector assembly for connecting separate CT strings at a wellsite comprises a first sub extending between an uphole end and a downhole end and comprising a first connector located at the uphole end thereof and a second connector located at the downhole end thereof, a second sub extending between an uphole end and a downhole end and comprising a third connector located at the uphole end thereof and connected to the second connector of the first sub, a slip connected between the first sub and the second sub and comprising one or more engagement members formed on an inner surface thereof for biting into an outer surface of a CT string, a first annular seal and a second annular seal each positioned along an inner surface of at least one of the first sub and the second sub, and a radial port formed in at least one of the first sub and the second sub and located longitudinally between the first annular seal and the second annular seal for pressurizing an internal region of the CT connector assembly extending longitudinally between the first annular seal and the second annular seal. In some embodiments, the first annular seal comprises a first pair of annular seals and the second annular seal comprises a second pair of annular seals longitudinally spaced from the first pair of annular seals. In certain embodiments, the CT connector assembly further comprises a plug releasably and sealingly receivable in the radial port to selectably restrict fluid communication across the radial port. In other embodiments, the second sub comprises an inner frustoconical surface configured to apply a radially inwards directed clamping force against an outer surface of the slip in response to relative axial movement between the first sub and the second sub. In some embodiments, the CT connector assembly further comprises a piston slidably received in a central passage of the first sub and extending between an uphole end and a downhole end, the piston having a central passage extending between the uphole end and the downhole end of the piston. In certain embodiments, the piston comprises an uphole piston, and the CT connector assembly further comprises a separate downhole piston slidably received in the central passage of the first sub and extending between an uphole end and a downhole end, the downhole piston having a central passage extending between the uphole end and the downhole end of the downhole piston. In other embodiments, the downhole piston comprises a downhole seat and one or more circumferentially spaced radial openings formed therein for permitting fluid communication around the downhole seat of the downhole piston.

An embodiment of a CT connector for connecting separate CT strings at a wellsite comprises a first sub extending between an uphole end and a downhole end and comprising a first connector located at the uphole end thereof and a second connector located at the downhole end thereof, a second sub extending between an uphole end and a downhole end and comprising a third connector located at the uphole end thereof and connected to the second connector of the first sub, a slip connected between the first sub and the second sub and comprising one or more engagement members formed on an inner surface thereof for biting into an outer surface of a CT string, and a piston slidably received in a central passage of the first sub and extending between an uphole end and a downhole end, the piston having a central passage extending between the uphole end and the downhole end of the piston, wherein the piston defines a seat for receiving an obturating member to restrict fluid flow through the central passage of the piston from the uphole end to the downhole end of the piston. In some embodiments, the second sub comprises an inner frustoconical surface configured to apply a radially inwards directed clamping force against an outer surface of the slip in response to relative axial movement between the first sub and the second sub. In certain embodiments, the slip is trapped longitudinally between the downhole end of the first sub and an annular inner shoulder of the second sub. In other embodiments, the CT connector assembly further comprises an annular seal positioned radially between an outer surface of the piston and an inner surface of the first sub to restrict fluid communication therebetween. In some embodiments, the CT connector assembly further comprises a radial passage formed in the first sub for selectably retrieving the obturating member from the central passage of the first sub. In certain embodiments, the CT connector assembly further comprises a plug releasably and sealingly receivable in the radial passage for selectably restricting fluid communication across the radial passage. In other embodiments, the CT connector assembly further comprises a first annular seal and a second annular seal each positioned along an inner surface of at least one of the first sub and the second sub. In some embodiments, the CT connector assembly further comprises a radial port formed in at least one of the first sub and the second sub and located longitudinally between the first annular seal and the second annular seal for pressurizing an internal region of the CT connector assembly extending longitudinally between the first annular seal and the second annular seal. In certain embodiments, the piston comprises an uphole piston, and the CT connector assembly further comprises a separate downhole piston slidably received in the central passage of the first sub and extending between an uphole end and a downhole end, the downhole piston having a central passage extending between the uphole end and the downhole end of the downhole piston. In other embodiments, the downhole piston comprises a downhole seat and one or more circumferentially spaced radial openings formed therein for permitting fluid communication around the downhole seat of the downhole piston. In some embodiments, the CT connector assembly further comprises the obturating member which is receivable in the central passage of the piston. In certain embodiments, the obturating member is configured to deform and pass through a seat of the piston in response to applying an actuation pressure to the uphole end of the piston. In other embodiments, the piston comprises an outer piston body and an inner piston body frangibly coupled to the outer piston body by one or more frangible members. In some embodiments, a downhole end of the outer piston body defines a stationary seat against which the inner piston body is landable, and an uphole end of the inner piston body defines a moveable seat against which the obturating member is landable.

An embodiment of a method for connecting separate coiled tubing (CT) strings at a wellsite comprises (a) locking a CT connector assembly to a terminal end of a first CT string, (b) pressurizing a central passage of the CT connector assembly to apply fluid pressure to an annular seal located in the central passage of the CT connector assembly, or (c) applying a tensile load to the CT connector assembly by applying fluid pressure to a central passage of the CT connector assembly. In some embodiments, (b) comprises pressurizing the central passage of the CT connector assembly via a radial port of the CT connector assembly. In certain embodiments, the radial port is located longitudinally between a first annular seal and a second annular seal of the CT connector assembly each in sealing engagement with the first CT string whereby a segment of the central passage of the CT connector assembly extending longitudinally between the first annular seal and the second annular seal is pressurized at (b). In other embodiments, (b) comprises connecting the radial port of the CT connector assembly to an external fluid pump. In some embodiments, (c) comprises applying the tensile load to the CT connector assembly by applying the fluid pressure to the central passage of the CT connector assembly. In certain embodiments, the method further comprises (d) landing an obturating member against an end of a piston received in the central passage of the CT connector assembly whereby fluid flow is restricted across a central passage of the piston. In other embodiments, the method further comprises (e) removing the obturating member from the central passage of the CT connector assembly via a radial passage of the CT connector assembly. In some embodiments, the method comprises (e) passing the obturating member through the central passage of the piston whereby the obturating member lands against a downhole seat of the piston. In certain embodiments, (e) comprises deforming the obturating member to pass the obturating member through the central passage of the piston to land the obturating member against the downhole seat of the piston. In other embodiments, (e) comprises shearing or deforming one or more frangible members to disconnect an inner piston body from an outer piston body of the piston whereby the inner piston body and the obturating member travel in concert through the central passage of the piston. In some embodiments, the method further comprises (f) flowing fluid through one or more circumferentially spaced openings formed in the piston and around the obturating member landed against the downhole seat.

Embodiments described herein comprise a combination of features and characteristics intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical characteristics of the disclosed embodiments in order that the detailed description that follows may be better understood. The various characteristics and features described above, as well as others, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes as the disclosed embodiments. It should also be realized that such equivalent constructions do not depart from the spirit and scope of the principles disclosed herein.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of exemplary embodiments of the disclosure, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic view of an embodiment of a well system in accordance with principles disclosed herein;

FIG. 2 is a schematic view of an embodiment of a surface assembly of the CT system of FIG. 1 in accordance with principles disclosed herein;

FIGS. 3 and 4 are zoomed-in, additional views of the surface assembly of FIG. 2 in accordance with principles disclosed herein;

FIG. 5 is a side cross-sectional view of an embodiment of a CT connector assembly in accordance with principles disclosed herein;

FIG. 6 is a side cross-sectional view of another embodiment of a CT connector assembly in accordance with principles disclosed herein;

FIGS. 7-9 are schematic views of an exemplary method for connecting a CT connector assembly with a CT string in accordance with principles disclosed herein;

FIG. 10 is a schematic view of an exemplary method for testing a CT connector assembly in accordance with principles disclosed herein;

FIG. 11 is a schematic view of another exemplary method for testing a CT connector assembly in accordance with principles disclosed herein;

FIG. 12 is a side cross-sectional view of another embodiment of a CT connector assembly in accordance with principles disclosed herein;

FIG. 13 is a side cross-sectional view of another embodiment of a CT connector assembly in accordance with principles disclosed herein;

FIGS. 14 and 15 are a side cross-sectional views of another embodiment of a CT connector assembly in accordance with principles disclosed herein;

FIG. 16 is a cross-sectional view of another embodiment of a CT connector assembly in accordance with principles disclosed herein; and

FIG. 17 is a cross-sectional view an embodiment of a CT connector kit in accordance with principles disclosed herein.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. 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 in interest of clarity and conciseness. Unless the context dictates the contrary, all ranges set forth herein should be interpreted as being inclusive of their endpoints, and open-ended ranges should be interpreted to include only commercially practical values. Similarly, all lists of values should be considered as inclusive of intermediate values unless the context indicates the contrary.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to...” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct engagement between the two devices, or through an indirect connection that is established via other devices, components, nodes, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a particular axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to a particular axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. Any reference to up or down in the description and the claims is made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation. As used herein, the terms “approximately,” “about,” “substantially,” and the like mean within 10% (i.e., plus or minus 10%) of the recited value. Thus, for example, a recited angle of “about 80 degrees” refers to an angle ranging from 72 degrees to 88 degrees.

As previously described, coiled tubing (CT) systems may include a reel assembly and a coiled tubing which may be spooled or stored on a core of the reel assembly. The coiled tubing is a single length of continuous, unjointed tubing, typically unwound from the reel assembly and deployed into a wellbore using a specialized injector head, which controls the speed and tension of the coiled tubing as it is fed into the wellbore. Once a desired depth is reached, various tools and equipment can be run through the coiled tubing to perform tasks or services associated with the wellbore. Circulating, pumping, coiled tubing drilling, production, logging, completion, and perforating may utilize CT systems.

During operation of a CT system, circumstances may arise where it becomes necessary to cut the coiled tubing in order to for example, facilitate fishing operations, connect two or more bottom hole assemblies (BHAs), and to couple a lower downhole CT string to an upper downhole CT string. Under such circumstances, the coiled tubing that extends into the wellbore is cut away from the coiled tubing reel at the surface. For example, depending on the application, different lengths of coiled tubing referred to as a “CT stinger” may be placed between bottomhole assemblies (BHA). In this instance, when the desired length of CT stinger has been deployed into the wellbore, the coiled tubing will need to be cut, and a longer coiled tubing string attached to the CT stinger to continue the operation.

The cut CT stringer or downhole CT string may be connected to a second or uphole CT string either directly via one or a pair of CT connector assemblies connected directly together, or across one or more downhole tools connected between the pair of CT strings. Conventionally, the connection between a downhole end of the uphole CT string and a CT connector assembly coupled therewith may be mechanically tensile tested and/or fluidically pressure or seal tested to test the mechanical strength and/or seal quality formed between the CT connector assembly and the uphole CT string. For example, a test plate or flange may be coupled to the downhole end of the CT connector assembly to facilitate the testing of the connection formed between the CT connector assembly and the uphole CT string. However, the downhole end of the downhole CT string is not accessible at the surface, and thus a similar testing procedure may not be utilized for testing the connection formed between the uphole end of the downhole CT string and a corresponding CT connector assembly connected therewith. Conventionally, no such similar testing may be performed on this second connection, increasing the odds that a failure of this connection may occur downhole that may jeopardize the future productivity of the well system.

Accordingly, embodiments of CT connector assemblies and methods of operating such are disclosed herein which permit the tensile and/or seal testing of the connection formed between an uphole end of a tubular member (e.g., a downhole CT string) and a CT connector assembly coupled or locked thereto. Particularly, embodiments of CT connector assemblies disclosed herein include a radial port for providing direct access to a central passage of the CT connector assembly between one or more annular seals thereof for testing the integrity of the seal formed between the annular seal and a tubular member received in the central passage of the CT connector assembly. Additionally, embodiments of CT connector assemblies disclosed herein include a piston slidably received in a central passage of the CT connector assembly and which receives an obturating member (e.g., a ball or dart) for selectably blocking fluid flow through a central passage of the piston whereby an axially directed pressure force may be applied to the piston. This axially directed pressure force may be transferred to the tubular member coupled to the CT connector assembly as a tensile load for testing the mechanical strength (e.g., tensile strength) formed between the tubular member and the CT connector assembly.

Referring initially to FIG. 1, an embodiment of a well system 1 including a wellbore 4 extending into an earthen subterranean formation 2 to a terminal end or “toe” 5 from a terranean surface 3 is shown. In the embodiment of FIG. 1, well system 1 comprises a system for servicing or completing the wellbore 4; however, in other embodiments, well system 1 may comprise a system for drilling wellbore 4 or a system for producing hydrocarbons from wellbore 4. Initially, it should be appreciated that the terranean surface 3 may be a land surface, a sub-sea surface (e.g., a seabed), or other underwater surface. Additionally, subterranean earthen formation 2 may comprise a plurality of discrete subterranean layers within the subterranean earthen formation 2. While wellbore 4 is shown in FIG. 1 as initially substantially vertical and then deviating at a substantially 90 degrees angle, it should be appreciated that in other embodiments, wellbore 4 may be deviated, horizontal, and extended at an incline relative to the direction of gravity along one or more sections of the deviated or horizontal wellbore. The wellbore 4 may be formed with various dimensions (diameter) and depths using a drilling system not shown in FIG. 1, which may include, among other things, a support structure (e.g., a derrick, a mast) located at the terranean surface 3, and a drilling assembly including a drill bit for cutting into the subterranean earthen formation 2.

In general, well system 1 includes a CT system 10 comprising a surface assembly 50 and one or more CT strings deployable into and from the wellbore 4 using the surface assembly 50. Particularly, CT system 10 includes a first downhole CT string 20 extending between a downhole end 21 and an uphole end 23, and a second or uphole CT string 30 coupled to the downhole CT string 20 and extending from a downhole end 31 to the terranean surface 3.

Additionally, in this exemplary embodiment, CT system 10 includes a one or more downhole CT tools 12 coupled to CT string 20. Particularly, CT system 10 is shown in FIG. 1 as including a first downhole CT tool 12 coupled to the downhole end 21 of downhole CT string 20, and a second downhole CT tool 12 coupled between the uphole end 23 of downhole CT string 20 and the downhole end 31 of uphole CT string 30. It should be noted that while CT system 10 includes a pair of downhole CT tools 12 in this exemplary embodiment, in other embodiments, CT system 10 may include one, or any number/combinations of downhole CT tool 12 depending on the particular application. Additionally, while in this exemplary embodiment CT system 10 includes an uphole CT string 30 and a downhole CT string 20, CT system 10 may include more than two separate CT strings depending on the application.

The CT strings 20 and 30 each comprise a continuous length of spoolable tubing defining an internal throughbore or central passage through which fluid may flow between the respective uphole and downhole ends thereof. In some embodiments, downhole CT string 20 and uphole CT string 30 may be in fluid communication with downhole CT tools 12 such that fluid may be pumped from the surface assembly 50 into and through uphole CT string 30, the second downhole CT tool 12, the downhole CT string 20, and into the first downhole CT tool 12 connected to the downhole end 21 of the downhole CT string 20. The downhole CT tools 12 of CT system 10 may include any combination of tools or equipment for performing specific tasks associated with wellbore 4. For example, downhole CT tool 12 may include any combination of fishing tools, packers/bridge plugs, perforating guns, well cleanup tools, cutting tools, drills, mills, and stimulation tools depending on the needs of the given application.

In this exemplary embodiment, surface assembly 50 of CT system 10 is configured to deploy and/or retrieve continuous lengths of tubing (e.g., downhole CT string 20 and uphole CT string 30), which are spooled onto a reel, into and/or from wellbore 4 while performing specific tasks associated with wellbore 4 as will be disclosed further herein. Unlike wireline and slickline units that use a winch drum and cable that lacks a central passage for communicating fluid flow and/or pressure, surface assembly 50 includes a coiled tubing reel which stores and feeds the continuous tubing into wellbore 4, an injector head that grips and pushes the coiled tubing downhole under controlled pressure and tension, pressure control equipment, and fluid handling systems, allowing the continuous coil of tubing to be run in and out of wellbore 4 while maintaining well control. The surface assembly 50 may be powered by hydraulic systems, electrical systems, or a combination thereof depending on the application.

Referring to FIG. 2, an embodiment of the surface assembly 50 of CT system 10 is shown. In this embodiment, surface assembly 50 is generally configured to inject or stab coiled tubing (e.g., downhole CT string 20 shown in FIG. 1) into wellbore 4 and/or pull or retract downhole CT string 20 from wellbore 4. Additionally, surface assembly 50 may be used to provide fluid flow and/or pressure to CT strings 20, 30 and downhole CT tools 12, and for communicating signals (e.g., electrical signals, optical signals) and/or applying axial loads to CT strings 20, 30 and downhole CT tools 12 as needed to facilitate their downhole operation.

In this exemplary embodiment, surface assembly 50 generally includes a CT truck or transporter 94 that may include an accumulator or other equipment such as hydraulic units and safety devices, a CT reel 95 rotatable by a CT motor 96 (each positioned on the CT transporter 94), a CT control center or unit 98 (also positionable on the CT transporter 94) for transmitting signals from the surface to/from equipment deployed in wellbore 4, a wellhead 52, a Christmas tree 56, a blowout preventer (BOP) 60 installed above the wellhead 52 and comprising separate BOP rams 62, 64, and 66 for providing well control, a service platform 70 for supporting rig personnel involved in performing various tasks associated with wellbore 4, a lubricator 80, an injector head 85, a tubing guide 92 for aligning downhole CT string 20 as it is deployed or retrieved, and a crane 90 (shown only partially in FIG. 2); however, in other embodiments, the configuration of surface assembly 50 may vary in other embodiments from that shown in FIG. 2.

To illustrate operational features of CT system 10, surface assembly 50 is shown in FIG. 2 deploying downhole CT string 20 into the wellbore 4. Particularly, during operation of CT system 10, downhole CT string 20 may be unwound from CT reel 95 in response to the operation of CT motor 96. The unwinding from, and winding onto, CT reel 95 of downhole CT string 20 may be performed or assisted by a tubing tensioner (not shown) of CT transporter 94 that is powered by a hydraulic unit. The deployment of downhole CT string 20 into and out of wellbore 4 may also be facilitated by the tubing guide 92 extending from injector head 85. The injector head 85 is suspended from a crane 90 such that the crane 90 may be used to control the positioning of injector head 85 relative to wellbore 4. In this manner, crane 90 may align injector head 85 with wellhead 52 and BOP 60 to ensure smooth feeding of downhole CT string 20 into and out of wellbore 4. Additionally, crane 90 may selectably vertically lift the injector head 85 and lubricator 80 from the BOP 60 (i.e., when the lubricator 80 is decoupled from the BOP 60) as desired to expose a segment of the downhole CT string 20 located vertically above BOP 60.

Wellhead 52 is positioned at the terranean surface 3 of wellbore 4 and physically supports christmas tree 56 and BOP 60, which is mounted or otherwise coupled to Christmas tree 56. Christmas tree 56 comprises a system of valves and fittings for controlling the flow of fluids from wellbore 4. Along with christmas tree 56, BOP 60 may be used to control the circulation of fluids from wellbore 4 and the surrounding environment at the terranean surface 3 so as to prevent blowouts during drilling and/or intervention operations. BOP rams 62, 64, and 66 (e.g., pipe rams, blind rams, and shear rams) of BOP 60 are configured to selectably isolate fluid communication across BOP 60. For example, BOP rams 62 and 64 may comprise blind and pipe rams respectively while BOP ram 66 may comprise a shear ram configured to cut the downhole CT string 20 when present therein. In this exemplary embodiment, lubricator 80 of surface assembly 50 extends from BOP 60 to injector head 85, where lubricator 80 provides pressure control and mechanical guidance for downhole CT string 20 as downhole CT string 20 is extended into or retracted from wellbore 4.

A variety of tools may be coupled to the terminal end of downhole CT string 20 for performing various operations in wellbore 4 as previously disclosed. For example, a mill tool may be coupled to the terminal end of downhole CT string 20 for selectably drilling or milling out downhole plugs (e.g., bridge plugs) previously installed in wellbore 4 to permit fluid communication between the toe 5 of wellbore 4 and the terranean surface 3. CT transporter 94 may include or support the CT control unit 98 for transmitting signals to and receiving signals from (e.g., electronic signals and/or data) downhole tools or equipment attached to the terminal end of downhole CT string 20 such as the first downhole CT tool 12 shown in FIG. 1. Additionally, fluids may be pumped between CT transporter 94 and tools attached to the terminal end of downhole CT string 20 via the central passage extending through downhole CT string 20.

Referring to FIG. 3, another view of the surface assembly 50 of CT system 10 is shown. Particularly, FIG. 3 illustrates the use of the service platform 70 of surface assembly 50, which is located near a vertical upper end of the BOP 60 of surface assembly 50. Service platform 70 provides access to rig personnel 72 of CT system 10 to the area vertically above the BOP 60 as shown in FIG. 3. For instance, service platform 70 includes a deck 74 (e.g., a human-accessible deck 74) located vertically above the terranean surface 3 and over the wellhead 52 and Christmas tree 56. The deck 74 of service platform 70 may be accessed by rig personnel 72 via a ladder, lift or other mechanism. As will be discussed further herein, rig personnel 72 may access a desired segment of the downhole CT string 20 (or other CT strings) at a location between the injector head 85 and the BOP 60 by lifting (e.g., via crane 90) the injector head 85 and lubricator 80 vertically upwards away from the BOP 60.

In this exemplary embodiment, surface assembly 50 is shown with downhole CT string 20 being deployed into wellbore 4 with at least a portion of Downhole CT string 20 suspended above BOP 60 in lubricator 80. In some embodiments, prior to running the downhole end 21 of downhole CT string 20 into wellbore 4, a BHA (e.g., BHA 12 shown in FIG. 1) is coupled to the downhole end 21 of Downhole CT string 20 and deployed BOP 60 and into wellbore 4. Additionally, various mechanical tensile or “pull” tests and pressure or “seal” tests may be carried out on downhole CT string 20 prior to deploying Downhole CT string 20 into wellbore 4. For example, the lubricator connection at the wellhead 52 may be tested, then the wellbore 4 is opened and a BHA is run into wellbore 4. As previously described, different lengths of CT string may be placed between BHA(s), depending on the particular application. For example, in some embodiments, downhole CT string 20 comprises a relatively short length of CT referred to as a CT stinger placed between a lower BHA 12 and an upper BHA 12, such that, once the desired length of CT stinger has been run into wellbore 4, the CT stinger is cut and another CT string (e.g., uphole CT string 30 shown in FIG. 1) is attached to the CT stinger. In other embodiments, the downhole CT string 20 may be directly connected to another CT string (e.g., uphole CT string 30) via a CT connector assembly coupled directly therebetween. In still other embodiments, other members, strings, and/or tools may be coupled between downhole CT string 20 and an uphole CT string such as uphole CT string 30.

Referring to FIG. 4, another view of the surface assembly 50 of CT system 10 is shown. Particularly, FIG. 4 illustrates surface assembly 50 following the cutting of downhole CT string 20 to form the uphole end 23 of downhole CT string 20 whereby downhole CT string 20 is separated from a remainder 20′ that extends from a terminal end 25, through lubricator 80, injector head 85, and tubing guide 92 to the CT reel 95 of surface assembly 50. The remainder 20′ may be retracted via CT motor 96 such that the terminal end 25 of remainder 20′ passes successively through the lubricator 80, injector head 85, and tubing guide 92 whereby the remainder 20′ may be fully retracted and spooled about CT reel 95.

Following the completion of the spooling of remainder 20′ onto CT reel 95, another CT transporter 94 may be positioned adjacent the wellhead 52 having a CT reel 95 about which a separate CT string (e.g., uphole CT string 30) is reeled about. In an example, the downhole end 31 of uphole CT string 30 is unreeled from the CT reel 95 of the separate CT transporter 94 and threaded successively through the tubing guide 92, injector head 85, and lubricator 80 such that the downhole end 31 of uphole CT string 30 is located vertically above the uphole end 23 of the downhole CT string 20. The downhole end 31 of uphole CT string 30 may then be connected to the uphole end 23 of the downhole CT string 20 using one or more CT connector assemblies. For instance, the downhole end 31 of uphole CT string 30 can be directly coupled to the uphole end 23 of downhole CT string 20 via a single CT connector assembly. As another example, a BHA (e.g., BHA 12) and/or other tools may be connected between the downhole end 31 of uphole CT string 30 and the uphole end 23 of the downhole CT string 20 via at least a pair of CT connector assemblies coupled between uphole and downhole ends of the BHA and the CT strings 30 and 20, respectively.

Additionally, the mechanical strength and the strength of the fluidic seal formed by each CT connector assembly with its corresponding CT string may be separately tested to ensure the mechanical and hydraulic robustness of the connection. For instance, a predefined axial load may be applied to the CT connector assembly to test the mechanical strength of the connection and a predefined internal fluid pressure may be applied to the CT connector assembly to test the quality of the seal formed between the CT connector assembly and the CT string connected therewith. Such tests may be performed to ensure that the connection formed between the selected CT connector assembly and its associated CT string will not fail when located downhole within the wellbore 4 which could result in at least a portion of the CT string becoming stuck in the wellbore 4 and/or other catastrophic operational issues that may impact the viability of the wellbore 4 for producing hydrocarbons therefrom following completion.

Referring to FIG. 5, an embodiment of a CT connector assembly 100 for connecting a CT string with another tubular member (e.g., another CT string, a downhole tool such as a BHA and the like) at a wellsite is shown. In this exemplary embodiment, CT connector assembly 100 has a central or longitudinal axis 105 and generally includes a tubular first or uphole sub 102, a tubular second or downhole sub 140 coupled to the uphole sub 102, an annular slip 180, and a friction ring 190. In this exemplary embodiment, the downhole sub 140 is slidably positioned over a terminal end of a CT string (e.g., over the uphole end 23 of downhole CT string 20); however, the downhole sub 140 may be stabbable within a CT string in other embodiments.

The uphole sub 102 of CT connector assembly 100 extends longitudinally between a first or uphole end 104 and an opposing second or downhole end 106. Additionally, the uphole sub 102 comprises a central throughbore or passage 108 defined by a generally cylindrical inner surface 110 extending between ends 104 and 106, and a generally cylindrical outer surface 112 also extending between ends 104 and 106. In this exemplary embodiment, the uphole end 104 of uphole sub 102 defines a first or uphole externally threaded connector 114 formed along the outer surface 112 thereof. Alternatively, the uphole end 104 of uphole sub 102 may instead define an internally threaded connector formed along the inner surface 110 thereof in other embodiments. In this exemplary embodiment, uphole sub 102 additionally defines another or downhole externally threaded connector 116 formed along the outer surface 112 thereof and located at the downhole end 106 thereof. As will be described further herein, uphole sub 102 may threadably connect to the downhole sub 140 of CT connector assembly 100 via the downhole externally threaded connector 116 thereof. Further, the inner surface 110 of uphole sub 102 defines an annular internal stop shoulder 117 located axially between the upper pair of annular seals 118 and the uphole end 104 of uphole sub 102.

Uphole sub 102 additionally includes a first or uphole pair of annular seals 118 positioned along the inner surface 110 thereof and located axially between the uphole externally threaded connector 114 and downhole end 106 of uphole sub 102. Additionally, in this exemplary embodiment, uphole sub 102 includes a second or downhole pair of annular seals 120 also positioned along the inner surface 110 thereof and located axially between the upper pair of annular seals 118 and the downhole end 106 of uphole sub 102. As will be described further herein, the pairs of annular seals 118 and 120 are each configured to fluidically seal the connection formed between CT connector assembly 100 and the terminal end of a CT string received in the central passage 108 of uphole sub 102. Additionally, the pairs of annular seals 118 and 120 comprise elastomeric seals (e.g., O-rings and the like); however, the configuration of the pairs of annular seals 118 and 120 may vary in other embodiments.

In this exemplary embodiment, uphole sub 102 comprises a radial port 122 extending entirely between the inner surface 110 and outer surface 112 thereof and located axially between the uphole pair of annular seals 118 and the downhole pair of annular seals 120. Radial port 122 receives a plug 124 releasably and sealably coupled (e.g., threadably coupled) to the radial port 122 to control fluid communication through the radial port 122. Particularly, when plug 124 is removed or released from radial port 122, fluid may be communicated between the external environment (e.g., an external fluid pump) and the axially extending segment 109 of central passage 108 located between the uphole pair of annular seals 118 and the downhole pair of annular seals 120. Conversely, when plug 124 is received in or coupled to radial port 122, fluid communication through radial port 122 between the external environment and central passage 108 of uphole sub 102 is restricted.

The downhole sub 140 of CT connector assembly 100 extends longitudinally between a first or uphole end 142 and an opposing second or downhole end 144. Additionally, the downhole sub 140 comprises a central throughbore or passage 146 defined by a generally cylindrical inner surface 148 extending between ends 142 and 144. In this exemplary embodiment, downhole sub 140 additionally defines an uphole internally threaded connector 150 formed along the inner surface 148 thereof and located at the uphole end 142 thereof. In this configuration, the downhole externally threaded connector 116 of uphole sub 102 may threadably connect to the uphole internally threaded connector 150 of downhole sub 140 to threadably connect the uphole sub 102 with the downhole sub 140.

Additionally, in this exemplary embodiment, the inner surface 148 of downhole sub 140 includes or defines an annular inner frustoconical surface 152 that terminates at an annular internal or stop shoulder 154 formed along the inner surface 148 of downhole sub 140 and which is located axially between the inner frustoconical surface 152 and the downhole end 144 of downhole sub 140. Particularly, an inner diameter of the inner frustoconical surface 152 gradually declines gradually from a first or uphole end of inner frustoconical surface 152 opposite stop shoulder 154 to an opposing second or downhole end of inner frustoconical surface 152 adjacent stop shoulder 154.

In this exemplary embodiment, both the slip 180 and the friction ring 190 are received in the central passage 146 of downhole sub 140. Particularly, slip 180 extends longitudinally between a first or uphole end 182 and an opposing second or downhole end 184. Additionally, slip 180 includes a plurality of engagement members or teeth 186 (e.g., annular or helical teeth) formed along an inner surface of the slip 180 extending between ends 182 and 184 thereof.

As will be discussed further herein, teeth 186 are configured to mechanically engage or bite into (e.g., plastically deform) a tubular member (e.g., a CT string) received within a central passage 185 of the slip 180 extending between ends 182 and 184 thereof. Specifically, an inner diameter of slip 180 may radially contract in response to engagement between an outer surface 188 of slip 180 and the inner surface 148 of downhole sub 140 with the radial contraction of slip 180 serving to engage or bite the teeth 186 of slip 180 into an outer surface of the tubular member received in central passage 185 thereby mechanically coupling or locking the slip 180 to the tubular member. In some embodiments, slip 180 includes circumferentially spaced cutouts or similar features to facilitate a circumferentially uniform radial contraction of slip 180 during the transitioning of CT connector assembly 100 from a first or unlocked state or configuration to a second or locked state or configuration as will be discussed further herein.

In this exemplary embodiment, friction ring 190 is positioned adjacent the uphole end 182 of slip 180 and serves to provide a circumferentially uniform axially compressive force against the uphole end 182 of slip 180 whereby slip 180 is forced axially towards the stop shoulder 154 of downhole sub 140. Particularly, friction ring 190 is axially positioned or sandwiched between the downhole end 106 of uphole sub 102 (received in the central passage 146 of downhole sub 140) and the uphole end 182 of slip 180 such that threading of the downhole externally threaded connector 116 of uphole sub 102 with the corresponding uphole internally threaded connector 150 of downhole sub 140 applies an axially directed, compressive force by the downhole end 106 of uphole sub 102 to the friction ring 190 which is transferred by the friction ring 190 to the uphole end 182 of slip 180. In turn, the axially compressive force applied by friction ring 190 to the uphole end 182 of slip 180 drives the slip 180 axially towards stop shoulder 154 which results in the radial contraction of slip 180 via sliding engagement between the outer surface 188 of slip 180 and the inner frustoconical surface 152 of downhole sub 140.

Referring to FIG. 6, another embodiment of a CT connector assembly 200 for connecting a CT string with another tubular member (e.g., another CT string, a downhole tool such as a BHA and the like) at a wellsite is shown. CT connector assembly 200 includes features in common with the CT connector assembly 100 shown in FIG. 5, and shared features are labeled similarly. In this exemplary embodiment, CT connector assembly 200 has a central or longitudinal axis 205 and includes a first or uphole sub 202, downhole sub 140, slip 180, and friction ring 190.

The uphole sub 202 of CT connector assembly 200 extends longitudinally between a first or uphole end 204 and an opposing second or downhole end 206. Additionally, the uphole sub 202 comprises a central throughbore or passage 208 defined by a generally cylindrical inner surface 210 extending between ends 204 and 206, and a generally cylindrical outer surface 212 also extending between ends 204 and 206. In this exemplary embodiment, the uphole end 204 of uphole sub 202 defines a first or uphole internally threaded connector 214 formed along the inner surface 210 thereof. Alternatively, the uphole end 204 of uphole sub 202 may instead define an externally threaded connector formed along the outer surface 212 thereof in other embodiments. Additionally, uphole sub 202 defines downhole externally threaded connector 116 formed along the outer surface 212 thereof and located at the downhole end 206 thereof. Further, the inner surface 210 of uphole sub 202 defines an annular internal stop shoulder 117 located axially between the upper pair of annular seals 118 and the uphole end 204 of uphole sub 202.

In this exemplary embodiment, uphole sub 102 comprises a radial opening or passage 218 extending entirely between the inner surface 210 and outer surface 212 thereof and located axially between the uphole end 204 and the shoulder 117 of uphole sub 202. Radial passage 218 receives a plug 219 releasably and sealably coupled (e.g., threadably coupled) to the radial passage 218 to control fluid communication through the radial passage 218. Particularly, when plug 219 is received in or coupled to radial passage 218, external access to the radial passage 218 is restricted such that plug 219 seals the radial passage 218 from the surrounding environment. Conversely, when plug 219 is removed or released from radial passage 218, external access is provided to the central passage 208 via the radial passage 218 of uphole sub 202.

In this exemplary embodiment, CT connector assembly 200 additionally includes a piston 220 slidably disposed in the central passage 208 of uphole sub 202 along with an obturating member or ball 230 receivable in the central passage 208 of uphole sub 202. Particularly, piston 220 extends longitudinally between a first or uphole end 222 and an opposing second or downhole end 224. Additionally, piston 220 has a central passage extending between ends 222 and 224. Further, piston 220 has an outer surface defining an annular shoulder 228 located between the uphole end 222 and downhole end 224 thereof. The uphole end 222 of piston 220 defines an annular seat 229 for the ball 230.

Particularly, when ball 230 is landed or seated against annular seat 229 of piston 220, fluid flow through central passage 226 from the uphole end 222 to the downhole end 224 thereof. However, while ball 230 may restrict fluid flow from the uphole end 222 to the downhole end 224 of piston 220, ball 230 does not restrict fluid flow through central passage 226 in the opposing direction from downhole end 224 to the uphole end 222 of piston 220. As will be discussed further herein, ball 230 may be removed from the central passage 208 of uphole sub 202 as desired via the radial passage 218 thereof.

Additionally, an annular seal 225 is positioned along the inner surface 110 of uphole sub 102 for sealing against an outer surface of piston 220 for restricting fluid communication across the annular interface formed between the outer surface of piston 220 and the inner surface 110 of uphole sub 102.

Referring to FIGS. 7-9, an exemplary method for mechanically connecting the CT connector assembly 100 to the uphole end 23 of downhole CT string 20. The method illustrated in FIGS. 7-10 may be similarly employed to mechanically connect the CT connector assembly 200 with the downhole CT string 20 and/or connect CT connector assemblies 100 and/or 200 various types of tubular members other than downhole CT string 20. As shown particularly in FIG. 7, in this exemplary embodiment, the downhole sub 140 of CT connector assembly 100 is initially slid or slipped over the uphole end 23 of downhole CT string 20 followed by slip 180, friction ring 190, and finally by the uphole sub 102 thereof which is only partially slipped over or slid onto the uphole end 23 of downhole CT string 20.

As shown particularly in FIG. 8, uphole sub 102 may continue to be slipped over (e.g., manually by rig personnel 72) until the uphole end 23 of downhole CT string 20 contacts or is positioned adjacent the internal stop shoulder 117 of uphole sub 102. In this position of uphole sub 102, the downhole end 106 of uphole sub 102 may be located adjacent friction ring 190 which in-turn may be located adjacent the uphole end 182 of slip 180.

With uphole sub 102 fully slipped over the uphole end 23 of downhole CT string 20, the downhole sub 140 of CT connector assembly 100 may be slid upward towards the downhole end 106 of uphole sub 102. Additionally, as the uphole end 142 of downhole sub 140 comes into contact with the downhole end 106 of uphole sub 102, downhole sub 140 may be rotated relative to uphole sub 102 (e.g., manually by rig personnel 72) whereby the uphole internally threaded connector 150 of downhole sub 140 threadably engages and connects with the downhole externally threaded connector 116 of uphole sub 102 as shown particularly in FIG. 9. As downhole sub 140 threadably connects with uphole sub 102, slip 180 is radially compressed with teeth 186 forced into contact with the outer surface of downhole CT string 20 as the slip 180 is forced towards the stop shoulder 154 of downhole sub 140 with inner frustoconical surface 152 thereof clamping against the outer surface 188 of slip 180. Downhole sub 140 is threaded onto the uphole sub 102 until the downhole end 184 of slip 180 engages or is located adjacent the stop shoulder 154 of downhole sub 140 whereby CT connector assembly 100 is placed in a locked configuration sealingly locked to the uphole end 23 of downhole CT string 20. In the locked configuration of CT connector assembly 100, one or more fasteners (e.g., set screws) may be connected to the CT connector assembly 100 to rotationally lock the CT connector assembly 100 to the uphole end 23 of downhole CT string 20.

Following the locking of CT connector assembly 100 to the uphole end 23 of downhole CT string 20, one or more tests may be performed to ensure the mechanical and sealing integrity of the connection formed between CT connector assembly 100 and the uphole end 23 of downhole CT string 20. The performance of such tests may identify mechanical and/or sealing issues between the CT connector assembly 100 and downhole CT string 20 prior to the running of CT connector assembly 100 into the wellbore where such issues may jeopardize the continued operation of the wellbore and associated well system.

Referring to FIG. 10, an example of a seal test applied to the connection formed between CT connector assembly 100 and the uphole end 23 of downhole CT string 20 is shown. CT connector assembly 100 is shown in the locked configuration in FIG. 10 mechanically locked to the uphole end 23 of downhole CT string 20 such that the uphole end 23 of downhole CT string 20 is located adjacent or in engagement with the stop shoulder 117 of uphole sub 102. With CT connector assembly 100 in the locked configuration, plug 124 may be released from radial port 122 and a pressurized fluid 107 may be applied to radial port 122 to thereby pressurize segment 109 of the central passage 108 of uphole sub 102 to test the annular seal formed between the downhole CT string 20 and both of the pairs of annular seals 118 and 120 of CT connector assembly 100.

For example, pressurized fluid 107 may be applied by a hand pump or other pumping device by rig personnel 72. Pressurized fluid 107 may be applied to segment 109 of central passage 108 for a predefined time period to determine if segment 109 may successfully hold or maintain fluid pressure therein for the predefined time period. The pair of annular seals 118 and 120 being able to maintain a threshold fluid pressure within segment 109 associated with the pressurized fluid 107 over the predefined time period may indicate a positive or successful seal integrity formed between the pairs of annular seals 118 and 120 and the downhole CT string 20.

Referring to FIG. 11, an example of a seal test applied to the connection formed a mechanical or tensile test applied to the connection formed between CT connector assembly 200 and the uphole end 23 of downhole CT string 20 is shown. In this exemplary embodiment, with CT connector assembly 200 in the locked configuration a pressurized fluid 111 may be applied to central passage 108 of uphole sub 102 at the uphole end 104 thereof. Pressurized fluid 111 may be applied by a pumping device or system of the CT transporter 94 of surface assembly 50. Pressurized fluid 111 applies an axially directed force against the piston 220 with ball 230 sealing fluid flow through the central passage 226 thereof.

The axially directed force applied by pressurized fluid 111 to piston 220 is applied to the uphole end 23 of downhole CT string 20. In turn, the axially directed force applied to the uphole end 23 of downhole CT string 20 is transferred to the downhole sub 140 of CT connector assembly 200 through slip 180. In this manner, the robustness or strength of the mechanical connection formed between slip 180 and downhole CT string 20 is tested via the axially directed force applied to downhole CT string 20 through pressurized fluid 111. For instance, pressurized fluid 111 may be applied for a predefined time period whereby a successful test corresponds to a lack or restriction of relative axial movement between downhole CT string 20 and CT connector assembly 200 over the course of the predefined time period. In this manner, fluid pressure may be used to generate the tensile axial force (applied to the downhole sub 140 to thus apply a tensile load to the uphole sub 102) required to test the mechanical strength (e.g., axial strength) of the connection formed between downhole CT string 20 and the CT connector assembly 100. Such a technique may be conveniently utilized in applications in which the downhole end of the tubular member received within CT connector assembly 100 (downhole CT string 20 in this example) is inaccessible.

Prior to or following the performance of the seal and tensile tests to CT connector assembly 100 and/or 200, the uphole end of the CT connector assembly 100/200 may be connected to another tubular member such as another CT string or to a downhole tool such as a BHA (e.g., BHA 12 shown in FIG. 1). For instance, the uphole internally threaded connector 214 of the uphole sub 202 of CT connector assembly 200 may be threadably connected to a corresponding downhole externally threaded connector of the downhole tool. In another example, uphole internally threaded connector 214 may be threadably connected to the uphole externally threaded connector 114 of CT connector assembly 100 (being vertically inverted in this example) which is in-turn connected to the downhole end of another CT string (e.g., to the downhole end 31 of uphole CT string 30 shown in FIG. 1). In this second example, the tensile test applied to CT connector assembly 200 would also serve to similarly test the mechanical strength of the connection formed between CT connector assembly 100 and uphole CT string 30 given that the tensile load applied to the downhole sub 140 of CT connector assembly 200 would be transferred through CT connector assembly 200 to the CT connector assembly 100 connected uphole therefrom.

Referring to FIG. 12, another embodiment of a CT connector assembly 300 for connecting a CT string with another tubular member (e.g., another CT string, a downhole tool such as a BHA and the like) at a wellsite is shown. CT connector assembly 300 includes features in common with the CT connector assemblies 100 and 200 shown in FIGS. 5 and 6, respectively, and shared features are labeled similarly. In this exemplary embodiment, CT connector assembly 300 has a central or longitudinal axis 305 and includes a first or uphole sub 302, downhole sub 340, the slip 180, and the friction ring 190.

The uphole sub 302 of CT connector assembly 300 extends longitudinally between a first or uphole end 304 and an opposing second or downhole end 306. Additionally, the uphole sub 302 comprises a central throughbore or passage 308 defined by a generally cylindrical inner surface 310 extending between ends 304 and 306, and a generally cylindrical outer surface 312 also extending between ends 304 and 306. Uphole sub 202 includes the uphole internally threaded connector 214 and the downhole externally threaded connector 116. Further, the inner surface 210 of uphole sub 202 includes a radial passage 314, a radial port 316 located downhole from the radial passage 314 and axially between the uphole pair of annular seals 118 and the downhole pair of annular seals 120, and an annular internal stop shoulder 318 located axially between the radial passage 314 and the radial port 316. Each of radial passage 314 and radial port 316 may releasably and sealingly receive a separate corresponding plug for selectably restricting fluid communication across the radial passage 314 and radial port 316, respectively.

The downhole sub 340 of CT connector assembly 300 extends longitudinally between a first or uphole end 342 and an opposing second or downhole end 344. Additionally, the downhole sub 340 comprises a central throughbore or passage defined by a generally cylindrical inner surface 346 extending between ends 342 and 344. Downhole sub 340 additionally includes the uphole internally threaded connector 150 located at the uphole end 342 thereof. The downhole externally threaded connector 116 of uphole sub 302 may threadably connect to the uphole internally threaded connector 150 of downhole sub 340 to threadably connect the uphole sub 302 with the downhole sub 340. Slip 180 and friction ring 190 are each receivable within the central passage of downhole sub 340 whereby a radially inwards clamping force may be applied by the inner frustoconical surface 152 of downhole sub 340 to the outer surface 188 of slip 180 to force the teeth 186 of slip 180 into contact with a tubular member (e.g., downhole CT string 20 in this example) received in the central passage of downhole sub 340 to mechanically lock the CT connector assembly 300 to the uphole end 23 of downhole CT string 20.

In this exemplary embodiment, CT connector assembly 300 additionally includes a first or uphole piston 360 and a second or downhole piston 380 each slidably disposed in the central passage 308 of uphole sub 302. Particularly, uphole piston 360 extends longitudinally between a first or uphole end 362 and an opposing second or downhole end 364. Additionally, uphole piston 360 has a central passage 366 extending between ends 362 and 364. The uphole end 362 of uphole piston 360 defines an annular seat 369 against which a first or uphole obturating member or ball 370 of CT connector assembly 300 may be received to selectably restrict fluid communication through central passage 366 from the uphole end 362 to the downhole end 364 thereof. Further, the annular interface formed between an outer surface of uphole piston 360 and the inner surface 310 of uphole sub 302 is sealed by an annular seal 320 positioned radially between the uphole piston 360 and the uphole sub 302.

Similarly, downhole piston 380 extends longitudinally between a first or uphole end 382 and an opposing second or downhole end 384. Additionally, downhole piston 380 has a central passage 386 extending between ends 382 and 384. The uphole end 382 of downhole piston 380 defines an annular seat 389 against which a second or downhole obturating member or ball 398 of CT connector assembly 300 may be received to selectably restrict fluid communication through central passage 386 from the uphole end 382 to the downhole end 384 thereof. In this exemplary embodiment, at least a portion of the downhole piston 380 is received within a central passage 27 of the downhole CT string 20 whereby the downhole end 384 of downhole piston 380 is stabbed into the central passage 27 of downhole CT string 20 from the uphole end 23 thereof. The annular interface formed between an outer surface of downhole piston 380 and the inner surface of the downhole CT string 20 is sealed by an annular seal 388 positioned radially between the outer surface of downhole piston 380 and the inner surface of the downhole CT string 20.

In this exemplary embodiment, the downhole end 384 of downhole piston 380 defines an annular downhole seat 390 for receiving one or more obturating members or balls pumped through the central passage 386 of downhole piston 380. Additionally, downhole piston 380 comprises one or more circumferentially spaced radial openings or slots 391 extending therethrough for permitting fluid communication from the central passage 386 of downhole piston 380, around the downhole seat 390 via slots 391, and through the central passage 27 of the downhole CT string 20. For instance, fluid may flow through the slots 391 and into an annulus formed between the outer surface of downhole piston 380 and the downhole CT string 20.

Following the mechanical locking of CT connector assembly 300 to the uphole end 23 of downhole CT string 20, one or more tests may be performed on CT connector assembly 300 to ensure the mechanical and sealing integrity of the connection formed between CT connector assembly 300 and downhole CT string 20. In this exemplary embodiment, CT connector assembly 300 facilitates the performance of multiple separate seal tests on CT connector assembly 300 depending on the needs of the given application. Particularly, a first or primary seal test may be performed on CT connector assembly 300 by pumping downhole ball 398 (e.g., via applying fluid pressure to the uphole end 304 of uphole sub 302 of CT connector assembly 300) against the uphole seat 389 of downhole piston 380 (with uphole ball 370 not received in central passage 308 of uphole sub 302) to restrict fluid communication through the central passage 386 of downhole piston 380 from the uphole end 382 to the downhole end 384 thereof. In this configuration, fluid pressure applied to the uphole end 382 of downhole piston 380 is exerted against the uphole pair of annular seals 118 via an annulus formed between the outer surface of downhole piston 380 and the inner surface 310 of uphole sub 302.

In some embodiments, downhole ball 398 comprises a flexible ball configured to pass through the uphole seat 389 of downhole sub 340 in response to the application of a threshold pressure differential across downhole ball 398 that exceeds the differential pressure required for performing the seal test. In this manner, a first threshold pressure may be applied to the downhole ball 398 to seal test annular seals 118 and 120 followed by the application of a second threshold pressure (greater than the first threshold pressure) to the downhole ball 398 to force the downhole ball 398 through the uphole seat 389 following which the downhole ball 398 may be caught and seat against the downhole seat 390 of downhole piston 380 where the downhole ball 398 may remain during the operation of downhole CT string 20.

Alternatively, downhole ball 398 could be retrieved from the CT connector assembly 300 using various means rather than forcing the downhole ball 398 through the uphole seat 389 of downhole piston 380. Additionally, a secondary seal test may be performed on CT connector assembly 300 by applying fluid pressure to the segment of central passage 308 extending between annular seals 118 and 120 via the radial port 316 formed in uphole sub 302 in a manner similar to that described above for CT connector assemblies 100 and 200 shown in FIGS. 5 and 6, respectively. Further, a tensile test may be performed on CT connector assembly 300 to test the mechanical strength of the connection formed between CT connector assembly 300 and downhole CT string 20 by introducing (via radial passage 314) the uphole ball 370 into central passage 308 of uphole sub 302 and applying fluid pressure to the uphole end 304 of uphole sub 302. In this manner, a threshold fluid pressure may be applied to the uphole end 362 of uphole piston 360 which is translated into an axially directed or tensile force applied to the downhole CT string 20 via the connection formed between downhole CT string 20 and the slip 180 of CT connector assembly 300. Uphole ball 370 may be subsequently retrieved (again via radial passage 314) from the central passage 308 of uphole sub 302 prior to running CT connector assembly 300 and the uphole end 23 of downhole CT string 20 into a wellbore.

Referring to FIG. 13, another embodiment of a CT connector assembly 400 for connecting a CT string with another tubular member (e.g., another CT string, a downhole tool such as a BHA and the like) at a wellsite is shown. CT connector assembly 400 includes features in common with the CT connector assemblies 100, 200, and 300 shown in FIGS. 5, 6, and 12, respectively, and shared features are labeled similarly. Particularly, CT connector assembly 400 is similar in configuration to CT connector assembly 300 except that CT connector assembly 400 does not include downhole piston 380 and instead of uphole internally threaded connector 214, CT connector assembly 400 includes the uphole externally threaded connector 114 of CT connector assembly 100 shown in FIG. 5.

Referring to FIG. 14, another embodiment of a CT connector assembly 500 for connecting a CT string with another tubular member (e.g., another CT string, a downhole tool such as a BHA and the like) at a wellsite is shown. CT connector assembly 500 includes features in common with the CT connector assemblies 100, 200, 300, and 400 shown in FIGS. 5, 6, 12, and 13, respectively, and shared features are labeled similarly. Particularly, CT connector assembly 500 is similar in configuration to CT connector assembly 300 except that CT connector assembly 500 includes an annular downhole piston 502 instead of the downhole piston 380 included in CT connector assembly 300.

Particularly, in this exemplary embodiment, downhole piston 502 includes both a radially outer piston body 504 and a radially inner piston body 520 that may frangibly couple to the outer piston body 504 by one or more frangible and/or deformable members or bodies 530 extending and coupled between outer piston body 504 and inner piston body 520. Outer piston body 502 extends between a first or uphole end 506 and a longitudinally opposed second or downhole end 508 and comprises a central passage 510 extending between ends 506 and 508 and in which the inner piston body 520 is slidably received. The downhole end 508 of outer piston body 504 defines an annular stationary seat 512 for receiving the inner piston body 520 as will be discussed further herein. Additionally, outer piston body 504 includes the slots 391 positioned between the uphole end 506 and downhole end 508 thereof.

The inner piston body 520 of downhole piston 502 is initially connected or axially locked to the outer piston body 504 at the uphole end 506 thereof when downhole piston 502 is in a first or test configuration. Particularly, inner piston body 520 is frangibly connected to the uphole end 506 of outer piston body 504 via frangible member 530 which extends radially between the outer piston body 504 and the inner piston body 520 to frangibly couple the inner piston body 520 to the outer piston body 504 when downhole piston 502 is in the test configuration. In this exemplary embodiment, frangible member 530 comprises a shear pin. Alternatively, the shape or configuration of frangible member 530 may vary from that shown in FIG. 14 in other embodiments. For instance, in other embodiments, frangible member 530 comprises a shear ring, a deformable member, and the like. Additionally, in this exemplary embodiment, inner piston body 520 defines an annular transportable or moveable piston seat 522 for receiving an obturating member or ball 540 of CT connector assembly 500 as will be discussed further herein. Further, an annular seal 524 is positioned along a generally cylindrical outer surface of inner piston body 520 for sealing the annular interface formed between outer piston body 504 and inner piston body 520.

FIG. 14 shows downhole piston 502 in the test configuration in which ball 540 has been pumped through the central passage 308 of uphole sub 302 and sealingly landed against the moveable piston seat 522 of inner piston body 520. In this configuration, the sealing integrity of the upper pair of annular seals 118 may be tested by increasing pressure within the portion of central passage 308 extending uphole from moveable piston seat 522 (uphole ball 370 may be removed from central passage 308 in this scenario to permit the communication of fluid pressure to moveable piston seat 522) to a predefined test pressure. This test pressure is communicated to the annulus formed between the uphole end 506 of outer piston body 502 and the inner surface 310 of uphole sub 302 such that the test pressure may be applied against at least one of the upper pair of annular seals 118. For instance, the test pressure may be applied by a rig pump of surface assembly 50 connected to an uphole end of the CT string connected, in-turn, to the uphole end 304 of uphole sub 302. Thus, the test pressure need not be communicated via a radial port such as the radial port 316 of uphole sub 302.

Referring to FIGS. 14 and 15, FIG. 15 illustrates the downhole piston 502 in a second or set configuration. Particularly, following the performance of the pressure test, fluid pressure within the uphole portion of central passage 308 may be increased from the test pressure to a second or actuation pressure sufficient to shear or otherwise break the frangible member 530 and thereby disconnect the inner piston body 520 from the outer piston body 504. As shown particularly in FIG. 15, the actuation pressure acting against the uphole end of inner piston body 520 drives the inner piston body 520 (along with the ball 540 seated thereagainst) downhole through the central passage 510 of outer piston body 504 until the inner piston body 520 lands against the stationary seat 512 of outer piston body 504, arresting the downhole travel of inner piston body 520 relative to outer piston body 504. In this configuration, fluid is permitted to flow into the central passage 27 of downhole CT string 20 from the central passage 510 of outer piston body 504 via the slots 391 thereof. In this manner, fluid flow through central passage 510 of outer piston body 504 may be reestablished without needing to deform ball 540 in order to pass it through the moveable piston seat 522 where such deformation risks the ball 540 becoming stuck within the moveable piston seat 522 or other undesirable operational risks.

Referring to FIG. 16, another embodiment of a CT connector assembly 600 for connecting a CT string with another tubular member (e.g., another CT string, a downhole tool such as a BHA and the like) at a wellsite is shown. FIG. 16 illustrates CT connector assembly 600 before and after setting. CT connector assembly 600 includes features in common with the CT connector assemblies 100, 200, 300, 400 and 500 shown in FIGS. 5, 6, 12, 13, and 14 respectively. Particularly, CT connector assembly 600 includes an obturating member or dart 602, a single piston 604 configured for setting and pressure testing the system, and a test port 606. In some embodiments, test port 606 may be omitted.

Referring to FIG. 17, an embodiment of a mechanical setting or installation tool 650 is shown for mechanically setting or installing CT connector assemblies. In this example, mechanical setting tool 650 is shown in conjunction with CT connector assembly 200. However, mechanical setting tools such as mechanical setting tool 650 may be used to set or install various kinds of CT connector assemblies consistent with principles disclosed herein. Particularly, mechanical setting tool 650 permits the mechanical setting of CT connector assembly 200 without needing to rely on the application of hydraulic pressure for driving the piston 220 against, for instance, the uphole end 23 of downhole CT string 20 as shown in FIG. 16. Additionally, the combination of a CT connector assembly (e.g., CT connector assembly 200 as shown in FIG. 17) and mechanical setting tool 650 forms or defines a CT connector kit 680. The mechanical setting tool 650 need not be coupled or inserted into the CT connector assembly 200 as shown in FIG. 17 in order to form the CT connector kit 680. Instead, the arrangement shown in FIG. 17 may correspond to an assembled configuration of the CT connector kit 680 with CT connector kit 680 including a disassembled configuration in which the mechanical setting tool 650 may not contact or otherwise engage the CT connector assembly 200.

In this exemplary embodiment, mechanical setting tool 650 generally includes an outer housing or body 652 and a mandrel 670 that extends through the body 652. Body 652 extends longitudinally between a first or uphole end 654 and an opposing second or downhole end 656. Additionally, body 652 comprises a central bore or passage 658 extending between ends 654 and 656 and which is at least partially defined by a threaded inner surface 660. Further, in this exemplary embodiment, body 652 includes an externally threaded or pin connector 662 located at the downhole end 656 thereof which may releasably or threadably connect to the internally threaded connector 214 of CT connector assembly 200, as will be discussed further herein.

The mandrel 670 of mechanical setting tool 650 extends longitudinally between a first or uphole end 672 and an opposing second or downhole end 674. Additionally, mandrel 670 includes a threaded outer surface or connector 676 extending at least partially between uphole end 672 and downhole end 674. Further, mandrel 670 includes a head or tool connector 678 located at the uphole end 672 thereof for connecting with a tool (e.g., a wrench and the like) for imparting rotational torque to the mandrel 670, as will be discussed further herein.

Initially, to set CT connector assembly 200 whereby the CT connector assembly 200 is fully secured or affixed to the uphole end 23 of downhole CT string 20, the externally threaded connector 662 of body 652 is threadably connected to the internally threaded connector 214 of CT connector assembly 200. With body 652 secured to CT connector assembly 200, mandrel 670 may be displaced through the central passage 658 of body 652 to drive the downhole end 674 of mandrel 670 against the uphole end 222 of piston 220. Particularly, a tool (e.g., a wrench and the like) may be coupled to the head 678 of mandrel 670 and rotated to thereby displace the mandrel 670 axially downhole towards the piston 220 of CT connector assembly 200. Particularly, threaded engagement between the internally threaded connector 676 of mandrel 670 and the externally threaded connector 662 of body 652 translates the rotation of mandrel 670 relative to body 652 into axial or longitudinal motion of mandrel 670 relative to body 652.

The axial motion of mandrel 670 relative to body 652 (which is secured to CT connector assembly 200) mechanically applies an axially directed compressive force (indicated by arrow 651 in FIG. 17) against the uphole end 222 of piston 220 from the downhole end 674 of mandrel 670. The axially directed force is applied as a compressive force by the downhole end 224 of piston 220 to the uphole end 23 of downhole CT string 20. Additionally, slip 180 react against the axially directed force 451 applied to the uphole end 23 of downhole CT string 20, causing slip 180 to further bite into the downhole CT string 20 to thereby set or complete the installation of CT connector assembly 200 with downhole CT string 20. Further, the axially directed force 451 may be predefined or selected as part of performing a tensile test of the connection formed between CT connector assembly 200 and downhole CT string 20. Moreover, a pressure test of the connection formed between CT connector assembly 200 and downhole CT string 20 may be performed using radial port 122 of CT connector assembly 200. Thus, mechanical setting tool 650 provides a means by which CT connector assembly 200 (and other embodiments of CT connector assemblies described herein) may be mechanically set and tensile tested without needing to rely on fluid pressure for doing so.

While exemplary embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.