Coiled tubing systems and methods including separate coiled tubing strings

Abstract

A system deployable into a wellbore penetrating a subsurface region includes a bottomhole assembly (BHA) including one or more downhole tools, a first CT string extending between a downhole end coupled to the BHA and an opposing uphole end, a second CT string extending between a downhole end and an opposing uphole end, and an intermediate agitator assembly including an agitator, an uphole swivel connector coupled between the intermediate agitator assembly and the downhole end of the second CT string, and a downhole swivel connector coupled between the intermediate agitator assembly and the uphole end of the first CT string, wherein at least one of the uphole swivel connector or the downhole swivel connector permits rotation of the agitator about a longitudinal axis of the system relative to at least one of the second CT string or the first CT string.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit of U.S. provisional patent application Serial No. 63 / 762,804 filed February 25, 2025, and entitled "Coiled Tubing Systems and Methods Including Separate Coiled Tubing Strings," which is hereby incorporated herein by reference in its entirety for all purposes.STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable.BACKGROUND

[0003] Conventional well systems commonly rely on rigid pipe joints that require time-consuming, threaded connections and disconnections when running a drill string comprising a plurality of the separately connected drill pipe joints into the wellbore. Coiled tubing (CT) systems address these inefficiencies by providing a singular, continuous string of tubing woundable about a CT reel that can be more rapidly deployed and retrieved. These systems are capable of delivering fluids, tools, and instrumentation into the wellbore under controlled conditions, making them advantageous for a wide range of drilling, completion, cleanout, and remedial activities.BRIEF SUMMARY OF THE DISCLOSURE

[0004] An embodiment of a CT system deployable into a wellbore penetrating a subsurface region comprises a bottomhole assembly (BHA) comprising one or more downhole tools, a first CT string extending between a downhole end coupled to the BHA and an opposing uphole end, wherein the downhole end of the first CT string is coupled to the BHA, a second CT string extending between a downhole end and an opposing uphole end, wherein the second CT string is separate from the first CT string, and an intermediate agitator assembly comprising an agitator, an uphole swivel connector coupled between the intermediate agitator assembly and the downhole end of the second CT string, and a downhole swivel connector coupled between the intermediate agitator assembly and the uphole end of the first CT string, wherein at least one of the uphole swivel connector or the downhole swivel connector permits rotation of the agitator about a longitudinal axis of the CT system relative to at least one of the second CT string or the first CT string. In some embodiments, rotation is permitted about the longitudinal axis of the CT system between the intermediate agitator assembly and both the first CT string and the second CT string. In some embodiments, at least one of the uphole swivel connector is welded to the second CT string, or the downhole swivel connector is welded to the first CT string. In certain embodiments, at least one of the uphole swivel connector or the second CT string comprises a heat-treated material. In certain embodiments, at least one of the downhole swivel connector or the first CT string comprises a heat-treated material. In certain embodiments, at least one of the uphole swivel connector comprises an uphole slip member locked to the second CT string, or the downhole swivel connector comprises a downhole slip member locked to the first CT string. In some embodiments, the uphole slip member and the downhole slip member both comprise one or more teeth located on an inner surface of the uphole slip member and the downhole slip member. In some embodiments, the agitator comprises a housing, a stator coupled to the housing, a rotor rotatably positioned in the stator, and a valve positioned in the housing, wherein the housing comprises a first releasable connector coupled to the uphole swivel connector and a second releasable connector longitudinally opposed to the first releasable connector of the housing and coupled to the downhole swivel connector.

[0005] An embodiment of an agitator assembly for a CT system deployable into a wellbore penetrating a subsurface region comprises a first swivel connector comprising a coil connector configured to connect to a first CT string, a releasable connector, and a swivel joint located between the coil connector and the releasable connector that permits relative rotation about a longitudinal axis of the agitator assembly between the coil connector and the releasable connector, an agitator comprising a housing, a stator coupled to the housing, a rotor rotatably positioned in the stator, and a valve positioned in the housing, wherein the housing comprises a first releasable connector coupled to the releasable connector of the first swivel connector and a second releasable connector longitudinally opposed to the first releasable connector of the housing, and a second swivel connector comprising a coil connector for connecting to a second CT string that is different from the first CT string, a releasable connector connected to the second releasable connector of the housing of the agitator, and a swivel joint located between the coil connector and the releasable connector of the second swivel connector that permits relative rotation about the longitudinal axis of the agitator assembly between the coil connector and the releasable connector of the second swivel connector. In certain embodiments, at least one of the first swivel connector comprises a first slip member configured to lock onto to the first CT string, or the second swivel connector comprises a second slip member configured to lock onto to the second CT string. In certain embodiments, the first slip member and the second slip member both comprise one or more teeth located on an inner surface of the first slip member and the second slip member. In some embodiments, relative rotation about the longitudinal axis of the agitator assembly is permitted between the agitator and both the first swivel connector and the second swivel connector.

[0006] An embodiment of a method for deploying a CT system into a wellbore penetrating a subsurface region comprises (a) deploying a first CT string of the CT system into the wellbore, (b) cutting the first CT string at a surface assembly of the CT system to form an uphole end of the first CT string that is located opposite to a downhole end of the CT string located in the wellbore, (c) coupling a downhole swivel connector to the uphole end of the first CT string, (d) coupling an uphole swivel connector to a downhole end of a second CT string of the CT system that is different from the first CT string, and (e) coupling an agitator assembly of the CT system between the downhole swivel connector and the uphole swivel connector whereby rotation about a longitudinal axis of the CT system is permitted between the agitator assembly and at least one of the first CT string or the second CT string about a longitudinal axis of the CT system. In some embodiments, (c) comprises permitting rotation about the longitudinal axis of the CT system between the agitator assembly and both the first CT string and the second CT string. In certain embodiments, at least one of (c) comprises welding the downhole swivel connector to the uphole end of the first CT string, or (d) comprises welding the uphole swivel connector to the downhole end of the second CT string. In certain embodiments, at least one of (c) comprises heating the downhole swivel connector and / or the first CT string to a predefined heat treatment temperature, or (d) comprises heating the uphole swivel connector and / or the second CT string to the predefined heat treatment temperature. In some embodiments, the predefined heat treatment temperature is equal to or greater than 400 degrees Fahrenheit. In some embodiments, the predefined heat treatment temperature is equal to or greater than 450 degrees Fahrenheit. In certain embodiments, the predefined heat treatment temperature is equal to or greater than 500 degrees Fahrenheit. In certain embodiments, at least one of (c) comprises slipping the downhole swivel connector onto the uphole end of the first CT string and locking the downhole swivel connector to the first CT string with a slip of the downhole swivel connector, or (d) comprises slipping the uphole swivel connector onto the downhole end of the second CT string and locking the uphole swivel connector to the second CT string with a slip of the uphole swivel connector.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] For a detailed description of exemplary embodiments of the disclosure, reference will now be made to the accompanying drawings in which:

[0008] FIG. 1 is a schematic view of an embodiment of a CT system in accordance with principles disclosed herein;

[0009] FIG. 2 is a schematic view of an embodiment of a CT system in accordance with principles disclosed herein;

[0010] FIG. 3 is a side cross-sectional view of an embodiment of a coil connector in accordance with principles disclosed herein;

[0011] FIG. 4 is a side cross-sectional view of another embodiment of a coil connector in accordance with principles disclosed herein;

[0012] FIG. 5 is a side cross-sectional view of an embodiment of an agitator in accordance with principles disclosed herein; and

[0013] FIGS. 6-12 are schematic views of an embodiment of a surface assembly of the CT system of FIG. 1 in accordance with principles disclosed herein.DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

[0014] 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.

[0015] 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.

[0016] 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.

[0017] As previously described, CT systems are versatile and widely used in the oil and gas industry for various well intervention, completion, and drilling operations. These systems consist of a continuous length of small-diameter steel tubing wound on a CT reel or spool, which is injected into and retrieved from the wellbore using a specialized injector head. The tubing is typically made of high-strength alloy steel, allowing it to withstand high pressures and mechanical stresses. In the context of CT drilling systems, such CT systems are typically equipped with a range of downhole tools, including motors, sensors, and drilling assemblies packaged in a BHA coupled to a downhole end of the CT string. The BHA of the CT system enables operations such as drilling, logging, perforating, and well cleanouts. The primary advantage of CT is its ability to perform these operations without the need to trip the drill string, significantly reducing operational time and costs.

[0018] In the context of CT drilling systems, coiled tubing is used to drill new sections of a wellbore or to re-enter and sidetrack existing wellbores. The continuous nature of CT allows for real-time data acquisition and precise control of downhole tools, enhancing drilling accuracy and safety. Additionally, CT drilling systems are well-suited for drilling in highly deviated or horizontal wellbores, where traditional jointed pipe drilling can be challenging. However, CT systems have notable limitations, particularly in extended reach wells (ERWs). ERWs are characterized by their long horizontal sections, often exceeding 10,000 feet, and high measured depths. One of the primary limitations of CT drilling in ERWs is the reduced reach capability due to frictional forces between an outer surface of the CT and a sidewall of the wellbore. Particularly, as the CT is pushed further into the wellbore, the cumulative friction increases, limiting the depth to which the CT can be effectively deployed. This issue is exacerbated in highly deviated or horizontal sections, where the CT is in continuous contact with the wellbore wall. Additionally, the relatively small diameter of coiled tubing restricts the flow rate and hydraulic horsepower available for drilling, which can hinder the efficiency of the drilling process, especially in deeper or more complex wells.

[0019] Another limitation is the mechanical strength of CT. While high-strength alloys are used, the CT is still susceptible to fatigue and mechanical failure, particularly when subjected to repeated bending and straightening cycles during spooling and deployment. This fatigue can limit the operational lifespan of the tubing and increase the risk of downhole failures. Furthermore, the limited weight-on-bit (WOB) that can be applied with coiled tubing can reduce drilling performance in harder formations, where higher WOB is required for effective penetration.

[0020] Accordingly, embodiments of CT systems and associated methods are described herein which overcome at least some of the aforementioned limitations of conventional CT systems. Particularly, embodiments of CT systems are provided which include an intermediate agitator positioned along the CT system and spaced from a BHA thereof for inducing vibratory and / or reciprocating motion in the CT system. By maintaining relative motion along the entire length of the CT system and the sidewall of the wellbore via the operation of the intermediate agitator, friction between the CT system and the sidewall of the wellbore may be minimized. Additionally, embodiments of CT systems disclosed herein include one or more swivel connectors coupled between the intermediate agitator and the separate CT strings of the CT system. The swivel connectors may permit the separate CT strings to rotate relative one another to relieve torsional stresses therebetween. Additionally, the swivel connectors may permit rotation of the agitator relative to one or both of the CT strings to ease assembly of the CT system at a wellsite of the well system.

[0021] Referring initially to FIG. 1, an embodiment of a well system 1 including a wellbore 4 extending into a subsurface region 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 drilling the (partially drilled in FIG. 1) wellbore 4; however, in other embodiments, well system 1 may comprise a system for servicing, intervening, and / or completing wellbore 4. Additionally, while wellbore 4 is shown as extending generally vertically in FIG. 1, in other embodiments, wellbore 4 may include a deviated or horizontal section extending laterally through the subsurface region 2. Generally, well system 1 includes a CT system 10 comprising a surface assembly 60 and one or more CT strings deployable into and from the wellbore 4 using the surface assembly 60.

[0022] Particularly, CT system 10 extends along a central or longitudinal axis 15 and generally includes a first or downhole CT string 30 extending between a downhole end 32 and an uphole end 34, and a second or uphole CT string 50 coupled to the downhole CT string 30 and extending from a downhole end 52 to the terranean surface 3. CT system 10 is shown in FIG. 1 in the process of running or deploying the uphole CT string 50 into the wellbore 4. CT system 10 further includes a first or lower tool string comprising a BHA 12 that is coupled to the downhole end 32 of downhole CT string 30 and a second or intermediate agitator assembly 40 that is coupled between the uphole end 34 of downhole CT string 30 and the downhole end 52 of uphole CT string 50. As will be discussed further herein, intermediate agitator assembly 40 reduces friction (e.g., stiction and the like) between the outer surfaces of CT strings 30 and 50 and a sidewall 6 of the wellbore 4 to maximize the distance which CT system 10 may extend into the subsurface region 2 and hence the measured depth of wellbore 4.

[0023] The CT strings 30 and 50 of CT system 10 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. Additionally, CT strings 30 and 50 are in fluid communication with both BHA 12 and intermediate agitator assembly 40 whereby drilling fluid may be pumped from the surface assembly 60 into and through uphole CT string 50, intermediate agitator assembly 40, downhole CT string 30, and into the BHA 12.

[0024] In this exemplary embodiment, BHA 12 of CT system 10 generally includes a downhole coil connector 14, a valving sub 16, a downhole agitator 18, a downhole motor 20, and a drill bit 22. Alternatively, the BHA 12 may include additional components not shown in FIG. 1 in other embodiments. Additionally, in other embodiments, BHA 12 may not include each of the components shown in FIG. 1.

[0025] The downhole coil connector 14 of BHA 12 connects the downhole end 32 of downhole CT string 30 to the uphole end of BHA 12. Particularly, an uphole end of downhole coil connector 14 is coupled to the downhole end 32 of downhole CT string 30 via different coupling mechanisms such as, for example, welding and / or via one or more sets of connector teeth of the downhole coil connector 14 that mechanically bite into the downhole CT string 30 to lock the downhole CT string 30 to the downhole coil connector 14. In this manner, the uphole end of downhole coil connector 14 may be permanently coupled to the downhole end 32 of downhole CT string 30 when it is connected therewith at the surface assembly 60 when BHA 12 is initially run into the wellbore 4. Conversely, the downhole end of downhole coil connector 14 may comprise a releasable connector such as a threaded connector and the like for releasably connecting to the valving sub 16 of BHA 12. For instance, the different components of BHA 12 may be releasably (e.g., threadably) connected together at the surface assembly 60 prior to or as the BHA 12 is lowered into the wellbore 4.

[0026] The valving sub 16 of BHA 12 includes one or more valves for directing fluid flow through the BHA 12 before it is delivered to the drill bit 22 located at the downhole end of BHA 12. Particularly, during operation of CT system 10, drilling fluid is pumped from surface assembly 60 through a central passage of CT system 10 (e.g., central passages of CT strings 30 and 50 and intermediate agitator assembly 40) whereby the drilling fluid is delivered at a desired pressure to the BHA 12 for operating various components thereof including, for example, mud motor 20 and drill bit 22. For instance, valving sub 16 may include a backpressure valve for controlling backpressure within CT system 10 and / or an annulus valve whereby a controlled amount of the drilling fluid may be injected directly from valving sub 16 into an annulus 8 formed between an outer surface of the CT system 10 and the sidewall 6 of wellbore 4. This injection of drilling fluid into the annulus 8 may assist with recirculating fluid in the annulus 8 (e.g., drilling fluid ejected from drill bit 22 carrying suspended drill cuttings from the subsurface region 2) to the terranean surface 3. In some embodiments, valving sub 16 may also include a disconnect such as a hydraulically activated disconnect and the like to permit disconnecting the BHA 12 from the downhole CT string 30 within the wellbore 4 in the event that, for instance, BHA 12 becomes stuck within and irretrievable from the wellbore 4.

[0027] The downhole agitator 18 of BHA 12 receives the flow of drilling fluid from the surface assembly 60 and converts some of the energy present in the flow of drilling fluid into vibratory or reciprocating (e.g., along central axis 15) motion of downhole agitator 18 that is imparted to the rest of the BHA 12 and the downhole CT string 30. The motion induced in downhole agitator 18 minimizes friction between the outer surfaces of BHA 12 / downhole CT string 30 and the sidewall 6 of wellbore 4 by preventing or limiting stiction therebetween. For example, downhole agitator 18 may comprise a valve that intermittently disrupts the flow of drilling fluid therethrough to repeatedly spike fluid pressure within the downhole agitator 18. This spiked fluid pressure within downhole agitator 18 may be applied to a biasing member thereof for converting the spiked fluid pressure into axially directed, reciprocating motion of the downhole agitator 18 within the wellbore 4.

[0028] The mud motor 20 of BHA 12 receives the flow of drilling fluid from surface assembly 60 and converts this flow of drilling fluid into rotational motion of the drill bit 22 about the central axis 15 of CT system 10 permit drill bit 22 to cut into the subsurface region 2 to thereby extend the wellbore 4 formed therein. For example, mud motor 20 may comprise an outer stator and an inner rotor rotatably positioned in the stator thereof. The rotor may be connected to the drill bit 22 whereby rotation of the rotor about central axis 15 is transferrable to the drill bit 22. Particularly, drilling fluid supplied to the mud motor 20 may through annular spaces formed between the stator and rotor of mud motor 20 to forcibly drive the rotation of the rotor relative to the stator thereof about central axis 15. In this manner, fluid pressure of the drilling fluid supplied to mud motor 20 is used to drive the rotation of the rotor of mud motor 20 and hence the rotation of drill bit 22.

[0029] Finally, the drill bit 22 of BHA 12 defines a downhole end of CT system 10 and is rotatable relative the other components of CT system 10 (e.g., CT strings 30 and 50) about the central axis 15 thereof. In some embodiments, drill bit 22 comprises one or more cutting elements configured to mechanically cut into the subsurface region 2 in response to the application of pressure against the rotating drill bit 22 against the toe 5 of wellbore 4. In this manner, material from subsurface region 2 is released therefrom as drill cuttings which are recirculated through the annulus 8 to the surface assembly 60.

[0030] As described above, while the downhole agitator 18 of BHA 12 does impart some reciprocating and / or vibratory motion to the downhole CT string 30, the magnitude of such motion may decline with increasing distance from the BHA 12. Thus, in applications in which it is desired to extend wellbore 4 great distances through the subsurface region 2, the efficacy of downhole agitator 18 in reducing friction between CT system 10 and the sidewall 6 of wellbore 4 (particularly towards the uphole end of the CT string connected therewith) may decline substantially whereby the cumulative friction may overwhelm the capacity of surface assembly 60 for injecting or running the CT string into the wellbore 4.

[0031] To counteract these issues to permit the formation of wellbores 4 extending substantial distances through subsurface region 2, CT system 10 is provided with the intermediate agitator assembly 40 which is spaced along the central axis 15 thereof from the BHA 12. In this manner, intermediate agitator assembly 40 may be operated to ensure that sufficient vibratory and / or reciprocating motion is applied along the entire longitudinal length of CT system 10 to maintain friction between CT system 10 and the sidewall 6 of wellbore 4 at acceptably low magnitudes.

[0032] In this exemplary embodiment, intermediate agitator assembly 40 generally includes (moving in FIG. 1 from an uphole end to a downhole end thereof) a first or uphole swivel connector 42, an intermediate agitator 44, and a second or downhole swivel connector 46.

[0033] The uphole swivel connector 42 of intermediate agitator assembly 40 connects the downhole end 52 of uphole CT string 50 to the uphole end of intermediate agitator assembly 40. Particularly, an uphole end of uphole swivel connector 42 is coupled to the downhole end 52 of uphole CT string 50 via different coupling mechanisms such as, for example, welding and / or via one or more sets of connector teeth of the uphole swivel connector 42 that mechanically bite into the uphole CT string 50. In this manner, the uphole end of uphole swivel connector 42 may be permanently coupled to the downhole end 52 of uphole CT string 50. Conversely, the downhole end of uphole swivel connector 42 may comprise a releasable connector such as a threaded connector and the like for releasably connecting to an uphole end of the intermediate agitator 44 of intermediate agitator assembly 40. For instance, the different components of intermediate agitator assembly 40 may be releasably (e.g., threadably) connected together at the surface assembly 60 prior to or as the intermediate agitator assembly 40 is lowered into the wellbore 4.

[0034] Similarly, the downhole swivel connector 46 of intermediate agitator assembly 40 connects the uphole end 34 of downhole CT string 30 to the downhole end of intermediate agitator assembly 40. Particularly, a downhole end of downhole swivel connector 46 is coupled to the uphole end 34 of downhole CT string 30 via different coupling mechanisms such as, for example, welding and / or via one or more sets of connector teeth that mechanically bite into the downhole CT string 30. Conversely, the uphole end of downhole swivel connector 46 may comprise a releasable connector such as a threaded connector and the like for releasably connecting to a downhole end of the intermediate agitator 44.

[0035] In this exemplary embodiment, uphole swivel connector 42 comprises an uphole rotatable or swivel joint 43 and the downhole swivel connector 46 similarly comprises a downhole rotatable or swivel joint 47. In some embodiments, swivel joints 43 and 47 comprise rotatable sleeves or mandrels. However, the configuration of swivel joints 43 and 47 may vary in other embodiments. Uphole swivel joint 43 of uphole swivel connector 42 permits uphole CT string 50 to rotate about central axis 15 of CT system 10 relative to intermediate agitator assembly 40 as indicated by arrow 45 in FIG. 1. Similarly, downhole swivel joint 47 of downhole swivel connector 45 permits downhole CT string 30 to rotate about central axis 15 of CT system 10 relative to intermediate agitator assembly 40 as indicated by arrow 49 in FIG. 1. In this arrangement, uphole CT string 50 is free to rotate about central axis 15 relative to downhole CT string 30 as the CT system 10 is being run into or retrieved from the wellbore 4. By permitting relative rotation between CT strings 30 and 50 along central axis 15, swivel connectors 42 and 46 may reduce rotational or torsional binding of the CT system 10 as it is run into the wellbore 4 which may increase friction between CT string 10 and the sidewall 6 of wellbore 4 along with other undesirable operational issues that may limit the length of wellbore 4. For instance, without permitting relative rotation between CT strings 30 and 50, torsional stress may be communicated along the combined CT strings 30 and 50 whereby the CT strings 30 and 50 may buckle helically within the wellbore 4 such that increased pressure is applied by the portions of the outer surfaces of CT strings 30 and 50 contacting the sidewall 6 of wellbore 4 which may, in turn, undesirably increase friction between CT strings 30 and 50 and the sidewall 6 of wellbore 4. By permitting free relative rotation between CT strings 30 and 50, such torsional stress along CT system 10 may be minimized to, in turn, minimize friction between CT system 10 and the sidewall 6 of wellbore 4. However, in other embodiments where such issues are not as paramount, one or both of swivel connectors 42 and 46 may comprise a non-rotatable connector that does not permit relative rotation thereacross about central axis 15.

[0036] Referring to FIG. 2, another embodiment of a well system 75 and another embodiment of a CT system 80 are shown. Well system 75 and CT system 80 include features in common with well system 1 and CT system 10 shown in FIG. 1, and shared features are labeled similarly. Particularly, in this exemplary embodiment, CT system 80 includes a plurality of intermediate agitator assemblies 40 (shown as intermediate agitator assemblies 40-1, 40-2, and 40-3 in FIG. 2) spaced therealong. Additionally, in this exemplary embodiment, CT string 50 comprises an intermediate CT string 50 with CT system 80 additionally including a further intermediate CT string 82 and an uphole CT string 90.

[0037] Intermediate CT string 82 extends between a downhole end 84 and an opposing uphole end 86 while uphole CT string 90 extends from a downhole end 92 to the surface assembly 60. A first intermediate agitator assembly 40-1 is coupled between the downhole CT string 30 and the intermediate CT string 50. Additionally, a second intermediate agitator assembly 40-2 is coupled between the intermediate CT string 50 and the intermediate CT string 82. Finally, a third intermediate agitator assembly 40-3 is coupled between intermediate CT string 82 and the uphole CT string 90. The distances between intermediate agitator assemblies 40-1, 40-2, and 40-3 may vary depending on the application, such as the geometry of wellbore 8. Further, while CT system 80 is shown as including three intermediate agitator assemblies 40-1, 40-2, and 40-3 along with four separate CT strings 30, 50, 82, and 90, in other embodiments, the number of intermediate agitator assemblies 40 and CT strings may vary.

[0038] As discussed above, different mechanisms may be used for coupling swivel connectors 42 and 46 to CT strings 50 and 30, respectively. Referring to FIG. 3, an embodiment of a coil connector 100 is shown connected to an exemplary CT string 120. In some embodiments, coil connector 100 may comprise a component of a swivel connector such as swivel connectors 42 and 46 shown in FIG. 1. For example, coil connector 100 may be coupled to a swivel joint (e.g., swivel joints 43 or 45 shown in FIG. 1) to form a swivel connector.

[0039] Coil connector 100 includes a connector body 102 having a central or longitudinal axis 105 and extends longitudinally between a first end 103 and an opposing second end 107. Additionally, in this exemplary embodiment, the connector body 102 of coil connector 100 has a central passage 104 extending between ends 103 and 107, and a generally cylindrical outer surface 106 also extending between ends 103 and 107. The outer surface 106 of connector body 102 defines a generally cylindrical connector surface 108 located at the first end 103 thereof and that terminates at an annular shoulder 110 of the outer surface 106. Additionally, outer surface 106 of connector body 102 defines a releasable connector 112 located at the second end 107 thereof. In this exemplary embodiment, releasable connector 112 comprises an externally threaded or pin connector and thus may also be referred to herein as pin connector 112. In other embodiments, releasable connector 112 may comprise other kinds of releasable connectors besides a pin connector. For instance, in some embodiments, releasable connector 112 may instead comprise a box connector formed along an inner surface of connector body 102. Releasable connector 112 may releasably connect to a mating releasable connector of another component of an intermediate agitator assembly (e.g., intermediate agitator assembly 40 shown in FIG. 1). In certain embodiments, releasable connector 112 connects to a mating connector of a swivel joint whereby relative rotation is permitted about central axis 105 between connector body 102 and the swivel joint connected therewith.

[0040] The CT string 120 shown in FIG. 3 has a central passage 122 and terminates at a terminal end 124 that is connected to the first end 103 of connector body 102. Particularly, in this exemplary embodiment, the terminal end 124 of CT string 120 connects to the connector surface 108 of connector body 102 via an annular weld or weld material 114 that is fused (e.g., via a welding process) to both the CT string 120 and the connector body 102 to restrict relative movement therebetween while fluidically sealing the connection formed between CT string 120 and connector body 102. Particularly, in this exemplary embodiment, weld 114 is applied to the terminal end 124 of CT string 120 and the shoulder 110 and / or connector surface 108 of connector body 102 to thereby fuse the weld material forming weld 114 with the materials forming both the CT string 120 and the connector body 102. Alternatively, weld 114 may be located at other positions along the connector body 102. For instance, in other embodiments, the terminal end 124 of CT string 120 may instead be insertable into the central passage 104 connector body 102 whereby an outer surface of CT string 120 may be welded to the first end and / or an inner surface of connector body 102.

[0041] Referring to FIG. 4, another embodiment of a coil connector 150 is shown. In some embodiments, coil connector 150 may comprise a component of a swivel connector such as swivel connectors 42 and 46 shown in FIG. 1. For example, coil connector 150 may be coupled to a swivel joint (e.g., swivel joints 43 or 45 shown in FIG. 1) to form a swivel connector. In this exemplary embodiment, coil connector 150 has a central or longitudinal axis 155 and generally includes a connector body or housing 152, a connector collar 170, an annular slip member or simply “slip”180, and a compression ring 190.

[0042] The connector body 152 of coil connector 150 extends longitudinally between a first end 153 and an opposing second end 157. Additionally, connector body 152 has a central passage 154 defined by a generally cylindrical inner surface 156 extending between ends 153 and 157, and a generally cylindrical outer surface 158 also extending between ends 153 and 157. The outer surface 158 of connector body 152 defines a first releasable connector 160 located at the first end 153 thereof and a second releasable connector 162 located at the second end 157 thereof. Additionally, a pair of annular seals 164 are positioned along the inner surface 156 of connector body 152. Seals 164 are configured to seal against an outer surface of a CT string (e.g., CT string 120 shown in FIG. 3) that is inserted into the central passage 154 of connector body 152 to thereby seal the connection formed between the CT string and coil connector 150. For instance, a terminal end of the CT string may be inserted into central passage 154 of connector body 152 from first end 153 until the terminal end of the CT string sealingly contacts the seals 164.

[0043] In this exemplary embodiment, releasable connectors 160 and 162 of connector body 152 each comprise externally threaded or pin connectors and thus may also be referred to herein as pin connectors 160 and 162. In other embodiments, releasable connectors 160 and 162 may comprise other kinds of releasable connectors besides a pin connector. For instance, in some embodiments, second releasable connector 162 may instead comprise a box connector formed along the inner surface 156 of connector body 152. First releasable connector 160 releasably connects with the connector collar 170, as will be discussed further herein. Second releasable connector 162 may releasably connect to a mating releasable connector of another component of an intermediate agitator assembly (e.g., intermediate agitator assembly 40 shown in FIG. 1). In certain embodiments, second releasable connector 162 connects to a mating connector of a swivel joint whereby relative rotation is permitted about central axis 155 between coil connector 150 and the swivel joint connected therewith.

[0044] The connector collar 170 of coil connector 150 extends between a first end 171 and a longitudinally opposed second end 173 and includes a central passage 172 defined by a generally cylindrical inner surface 174 extending between ends 171 and 173. In this exemplary embodiment, the inner surface 174 of connector collar 170 defines a frustoconical surface 176 located between ends 171 and 173, and a releasable connector 178 located at the second end 173 thereof. The frustoconical surface 176 has an inner diameter that increases in size moving along central axis 155 towards the second end 173 of connector collar 170. Releasable connectors 178 of connector collar 170 comprises an internally threaded or box connector configured to matingly or threadably connect to the first releasable connector 160 of connector body 152. In other embodiments, releasable connector 178 may comprise other kinds of releasable connectors besides a box connector.

[0045] Both slip 180 and compression ring 190 are receivable in the central passage 172 of connector collar 170. Particularly, slip 180 comprises one or more engagement members or teeth 182 formed along a generally cylindrical inner surface thereof whereas a generally cylindrical outer surface (e.g., a frustoconical outer surface) of slip 180 slidably engages the frustoconical surface 176 of connector collar 170. In addition, compression ring 190 is positioned in central passage 172 of connector collar 170 axially between the slip 180 and the first end 153 of connector body 152 whereby axially directed forces may be transmitted across compression ring 190 between connector body 152 and slip 180.

[0046] During operation, an inner diameter of slip 180 may be radially contracted with a terminal end of a CT string inserted into the central passage 154 of connector body 152 whereby the teeth182 of slip 180 may bite into the outer surface of the CT string to couple or lock the terminal end of the CT string to the coil connector 150. Particularly, with the terminal end of the CT string inserted into the central passage 154 of connector body 152, connector collar 170 may be rotated relative to connector body 152. Rotation of connector collar 170 results, via the threaded coupling formed between releasable connectors 160 and 178 of connector body 152 and connector collar 170, results in connector collar 170 travelling axially towards the second end 157 of connector body 152. The axial travel of connector collar 170 forces the slip 180 to travel axially relative to connector collar 170 towards the first end 171 of connector collar 170. This relative axial travel of slip 180 results in the radial contraction thereof as the inner diameter of the portion of frustoconical surface 176 engaged by slip 180 continually declines, causing the teeth 182 of slip 180 to bite into the CT string extending therethrough.

[0047] Referring to FIG. 5, an embodiment of an agitator 200 is shown. In some embodiments, the downhole agitator 18 of BHA 12 and / or the intermediate agitator 44 of intermediate agitator assembly 40 may comprise or be configured similarly as the agitator 200 shown in FIG. 5. Alternatively, agitators 18 and / or 44 may vary in configuration from the agitator 200 of FIG. 5. In this exemplary embodiment, agitator 200 has a central or longitudinal axis 205 and generally includes an outer housing 202, a rotor 220, and a valve 240. Housing 202 extends between a first end 203 and a longitudinally opposed second end 207. Additionally, housing 202 has a central passage 204 in which a stator 206 of the agitator 200 is received and coupled with the housing 202.

[0048] Rotor 220 of agitator 200 is rotatably received in the central passage 204 of housing 202 within the stator 206 whereby a plurality of annular openings are formed between the stator 206 and rotor 220. Rotor 220 is rotatable relative to stator 206 in response to the flow of drilling fluid through the agitator 200. Additionally, rotor 220 includes a central passage 222 through which some of the drilling fluid flowing through agitator 200 is permitted to flow.

[0049] Valve 240 of agitator 200 is also received in the central passage 204 of housing 202 and comprises a first valve member 242 coupled to a downhole end of rotor 220 and a second valve member 244 coupled to the housing 202 external the stator 206. Particularly, first valve member 242 rotates in concert with rotor 220 while second valve member 244 remains fixed to housing 202 such that first valve member 242 rotates relative to second valve member 244 in response to rotation of the rotor 220 within stator 206. Additionally, each valve member 242 and 244 includes one or more fluid ports for conveying the flow of drilling fluid from central passage 222 of rotor 220.

[0050] Particularly, valve 240 has a first or open configuration permitting fluid within central passage 222 of rotor 220 to pass through valve 240 and a second configuration restricting fluid within central passage 222 from passing through valve 240. The open and closed configurations of valve 240 correspond to different relative angular positions of valve members 242 and 244 whereby fluid ports of valve members 242 and 244 align and are placed in fluid communication when in the open configuration while the fluid ports of valve members 242 and 244 misalign and are out of fluid communication with each other when valve 240 is in the closed configuration. In this arrangement, valve 240 cyclically opens and closes as the rotor 220 rotates within stator 206, thereby cyclically choking the flow of drilling fluid through agitator 200. This cyclical restricting of flow through agitator 200 results in the creation of a pressure spike or pulse that is transmitted to a piston located downhole from housing 202 (e.g., coupled with housing 202). The piston may be engaged by a biasing member also located within the same sub therewith whereby the cyclical pressure forces applied to the piston are translated into reciprocating motion of the piston within the housing, this reciprocating motion being transmittable to a CT string coupled to agitator 200 for inducing reciprocating motion therein.

[0051] Surface assembly 60 is generally configured to deploy and / or retrieve continuous lengths of tubing (e.g., downhole CT string 30 and uphole CT string 50), which are spooled onto a reel, into and / or from wellbore 4 while performing specific tasks associated with wellbore 4. 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 60 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 60 may be powered by hydraulic systems, electrical systems, or a combination thereof depending on the application.

[0052] Referring to FIG. 6, a more detailed view of the surface assembly 60 of the CT system 10 of FIG. 1 is shown. In this exemplary embodiment, surface assembly 60 generally includes a wellhead 61, a christmas tree 62, a blowout preventer (BOP) 63 installed above the wellhead 61 and comprising one or more separate BOP rams for providing well control, a lubricator 64, an injector head 66, a tubing guide 67 for aligning downhole CT string 30 as it is deployed or retrieved, and a crane 68 (shown only partially in FIG. 6); however, in other embodiments, the configuration of surface assembly 60 may vary in other embodiments from that shown in FIG. 6. Additionally, surface assembly 60 may include additional equipment not shown in FIG. 6 such as, for example, a CT truck or transporter, a CT reel around which the CT string is wound, a surface controller, and / or a surface fluid pump for pumping fluid (e.g., drilling fluid, completion fluid, and the like) through the CT string and into the wellbore 4.

[0053] Particularly, surface assembly 60 is shown in FIG. 6 deploying downhole CT string 30 into the wellbore 4. Particularly, during operation of CT system 10, downhole CT string 30 may be unwound from CT reel in response to the operation of a motor thereof. The deployment of downhole CT string 30 into and out of wellbore 4 may also be facilitated by the tubing guide 67 extending from injector head 66. The injector head 66 is suspended from a crane 68 such that the crane 68 may be used to control the vertical location of injector head 66 relative to the BOP 63. In this manner, crane 68 may align injector head 66 with wellhead 61 and BOP 63 to ensure smooth feeding of downhole CT string 30 into and out of wellbore 4. Additionally, crane 68 may selectably vertically lift the injector head 66 and lubricator 64 from the BOP 63 (i.e., when the lubricator 64 is decoupled from the BOP 63) as desired to expose a segment of the downhole CT string 30 located vertically above BOP 63.

[0054] Wellhead 61 is positioned at the terranean surface 3 of wellbore 4 and physically supports christmas tree 62 and the BOP 63 which is mounted or otherwise coupled to Christmas tree 62. Christmas tree 62 comprises a system of valves and fittings for controlling the flow of fluids from wellbore 4. Along with christmas tree 62, BOP 63 may be used to control the circulation of fluids from wellbore 4 and the surrounding environment at the terranean surface 3 to prevent blowouts during drilling and / or intervention operations. In this exemplary embodiment, lubricator 64 of surface assembly 60 extends from BOP 63 to injector head 66, where lubricator 64 provides pressure control and mechanical guidance for downhole CT string 30 as downhole CT string 30 is extended into or retracted from wellbore 4.

[0055] Referring to FIGS. 6-12, additional views of surface assembly 60 are provided to illustrate an exemplary process for running the CT system 10 into the wellbore 4. As described above, CT system 10 is shown in FIG. 6 during the running of downhole CT string 30 into the wellbore 4 with the downhole end 32 thereof and BHA 12 already positioned in the wellbore 4. Once a desired length of downhole CT string 30 has been run into the wellbore 4, the rotation of the CT reel supporting downhole CT string 30 may be stopped and a lower end 65 of the lubricator 64 may be disconnected from the BOP 63 and the lubricator 64 along with injector had 80 may be vertically raised from the BOP 63 by crane 68 as indicated by arrow 69 in FIG. 7.

[0056] With the portion of the downhole CT string 30 extending between BOP 63 and the lower end 65 of lubricator 64 exposed to the surrounding environment, a cutting tool or element 70 may be applied to the exposed portion of downhole CT string 30 as indicated in FIG. 8. The cutting tool 70 cuts the downhole CT string 30 thereby forming the uphole end 34 of downhole CT string 30 along with a remainder or cut CT string 30’ which extends from a cut downhole end 32’, through the lubricator 64 and injector head 66, to the CT reel of surface assembly 60. The cut CT string 30’ may be retracted via the CT reel to permit passage of the downhole end 52 of uphole CT string 50 through the vacated injector head 66 and lubricator 64. Alternatively, each CT string 30 and 50 may use a unique lubricator 64 and / or injector head 66 such that the injector head 66 carrying cut CT string 30 may simply be pivoted out of the way of BOP 63 by the crane 68 and a second injector head 66 (e.g., connected to a second CT reel) may be pivoted over the BOP 63, the second injector head 66 supporting the uphole CT string 50.

[0057] As shown particularly in FIG. 9, the downhole end 52 of uphole CT string 50 may be positioned vertically above (extending or projecting from the lower end 65 of lubricator 64) the uphole end 34 of downhole CT string 30 and the uphole swivel connector 42 may be coupled to the downhole end 52 of uphole string 50 while the downhole swivel connector 46 is coupled to the uphole end 34 of downhole CT string 30. In some embodiments, one or both of swivel connectors 42 and 46 may be welded to their corresponding CT strings 50 and 30 using a welding tool 71 as shown in FIG. 9. For instance, in some embodiments, swivel connectors 42 and / or 46 may comprise coil connector 100 shown in FIG. 3.

[0058] In certain embodiments, a heat treatment is applied to the weld (e.g., weld 114 of coil connector 100) following welding by welding tool 71 to prevent the weld from cracking or otherwise failing (e.g., due to residual stresses present therein) during the future operation of CT system 10. The heat treatment reduces the brittleness of the resulting weld to minimize the potential for failure of the weld in the downhole environment. For example, a heating element 72 may be applied to swivel connectors 42 and 46 and / or the ends 34 and 52 of CT strings 30 and 50 to heat the swivel connectors 42 and 46 and / or CT strings 30 and 50 to a predefined heat treatment temperature for a predefined period of time in order to maximize the strength and resilience of the connections formed between CT strings 30 and 50 and swivel connectors 46 and 42, respectively. In some embodiments, heating element 72 comprises a gas torch. However, the configuration of heating element 72 may vary. Additionally, a temperature sensor 73 may be used to ensure the heated portions of swivel connectors 42 and 46 and / or CT strings 30 and 50 have been successfully heated to the heat treatment temperature. For instance, the temperature sensor 73 may comprise a temperature stick that is applied to the heated portions of swivel connectors 42 and 46 and / or CT strings 30 and 50 and which is configured to melt upon reaching the heat treatment temperature to provide an indication that the heated portions of swivel connectors 42 and 46 and / or CT strings 30 and 50 have also achieved the heat treatment temperature.

[0059] In some embodiments, the heat treatment temperature is equal to or greater than 400 degrees Fahrenheit (°F). In certain embodiments, the heat treatment temperature is equal to or greater than 450°F. In certain embodiments, the heat treatment temperature is equal to or greater than 500°F. In some embodiments, the heat treatment temperature is between approximately 400°F and 600°F. The heat treatment may be applied for a predefined time period such as 30 minutes, 45 minutes, or other durations. Additionally, a predefined cool down period may occur following heat treatment but prior to welding such as a 30 minute cool down period, a 45 minute cool down period, or other durations. The heat treatment temperature and heat treatment time period may vary depending on the materials and / or thicknesses of the heated portions of swivel connectors 42 and 46 and / or CT strings 30 and 50. Thus, in at least some embodiments, CT strings 30 and 50 and / or swivel connectors 42 and 46 may comprise heat-treated materials. As used herein, the term “heat-treated materials” refers to materials that have been exposed to a predefined heat treatment temperature of at least 400°F. Alternatively, one or both of swivel connectors 42 and 46 may be attached via a mechanical connector such as a slip for fastener. For instance, in some embodiments, swivel connectors 42 and / or 46 may comprise coil connector 150 shown in FIG. 4.

[0060] Once swivel connectors 42 and 46 have been connected (e.g., welded, slipped on, and the like) to CT strings 50 and 30, respectively, the remainder of the intermediate agitator assembly 40 may be assembled onto the uphole CT string 50 as shown particularly in FIG. 10. Particularly, an uphole end of the agitator 44 may be coupled to a downhole end of the uphole swivel connector 42 and the uphole CT string 50. Uphole CT string 50 may be retracted and vertically raised through lubricator 64 during this process, as shown particularly in FIG. 10, to provide sufficient space for attaching agitator 44 to uphole swivel connector 42.

[0061] As shown particularly in FIG. 11, uphole CT string 50 may then be lowered through lubricator 64 to position the downhole end of agitator 44 proximal the downhole swivel connector 46 whereby the two may be coupled together. For example, the downhole end of agitator 44 may be threadably coupled to the downhole swivel connector 46 where the free rotation about central axis 15 provided by swivel connectors 42 and 46 permits the rotation of agitator 44 relative to downhole swivel connector 46 without needing to rotate the uphole CT string 50 already connected therewith. In other words, agitator 44 may be threaded onto or into downhole swivel connector 46 without needing to rotate the downhole end 52 of uphole CT string 50 in concert with the agitator 44. Finally, with agitator 44 coupled to downhole swivel connector 46 to complete the assembly of intermediate agitator assembly 40 above the BOP 63, lubricator 64 and injector head 66 may be vertically lowered by crane 68 as indicated by arrow 74 in FIG. 12 and the lower end 65 may again be secured or coupled to BOP 63. Following the attachment of lubricator 64 to BOP 63, uphole CT string 50 may be run into the wellbore 4 to facilitate the drilling thereof.

[0062] 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.

Claims

1. A coiled tubing (CT) system deployable into a wellbore penetrating a subsurface region, the CT system comprising:a bottomhole assembly (BHA) comprising one or more downhole tools;a first CT string extending between a downhole end coupled to the BHA and an opposing uphole end, wherein the downhole end of the first CT string is coupled to the BHA;a second CT string extending between a downhole end and an opposing uphole end, wherein the second CT string is separate from the first CT string; andan intermediate agitator assembly comprising an agitator, an uphole swivel connector coupled between the intermediate agitator assembly and the downhole end of the second CT string, and a downhole swivel connector coupled between the intermediate agitator assembly and the uphole end of the first CT string, wherein at least one of the uphole swivel connector or the downhole swivel connector permits rotation of the agitator about a longitudinal axis of the CT system relative to at least one of the second CT string or the first CT string.

2. The CT system of claim 1, wherein rotation is permitted about the longitudinal axis of the CT system between the intermediate agitator assembly and both the first CT string and the second CT string.

3. The CT system of claim 1, wherein at least one of the uphole swivel connector is welded to the second CT string, or the downhole swivel connector is welded to the first CT string.

4. The CT system of claim 1, wherein at least one of the uphole swivel connector or the second CT string comprises a heat-treated material.

5. The CT system of claim 1, wherein at least one of the downhole swivel connector or the first CT string comprises a heat-treated material.

6. The CT system of claim 1, wherein at least one of the uphole swivel connector comprises an uphole slip member locked to the second CT string, or the downhole swivel connector comprises a downhole slip member locked to the first CT string.

7. The CT system of claim 6, wherein the uphole slip member and the downhole slip member both comprise one or more teeth located on an inner surface of the uphole slip member and the downhole slip member.

8. The CT system of claim 1, wherein the agitator comprises a housing, a stator coupled to the housing, a rotor rotatably positioned in the stator, and a valve positioned in the housing, wherein the housing comprises a first releasable connector coupled to the uphole swivel connector and a second releasable connector longitudinally opposed to the first releasable connector of the housing and coupled to the downhole swivel connector.

9. An agitator assembly for a coiled tubing (CT) system deployable into a wellbore penetrating a subsurface region, the agitator assembly comprising:a first swivel connector comprising a coil connector configured to connect to a first CT string, a releasable connector, and a swivel joint located between the coil connector and the releasable connector that permits relative rotation about a longitudinal axis of the agitator assembly between the coil connector and the releasable connector;an agitator comprising a housing, a stator coupled to the housing, a rotor rotatably positioned in the stator, and a valve positioned in the housing, wherein the housing comprises a first releasable connector coupled to the releasable connector of the first swivel connector and a second releasable connector longitudinally opposed to the first releasable connector of the housing; anda second swivel connector comprising a coil connector for connecting to a second CT string that is different from the first CT string, a releasable connector connected to the second releasable connector of the housing of the agitator, and a swivel joint located between the coil connector and the releasable connector of the second swivel connector that permits relative rotation about the longitudinal axis of the agitator assembly between the coil connector and the releasable connector of the second swivel connector.

10. The agitator assembly of claim 9, wherein at least one of the first swivel connector comprises a first slip member configured to lock onto to the first CT string, or the second swivel connector comprises a second slip member configured to lock onto to the second CT string.

11. The agitator assembly of claim 10, wherein the first slip member and the second slip member both comprise one or more teeth located on an inner surface of the first slip member and the second slip member.

12. The agitator assembly of claim 11, wherein relative rotation about the longitudinal axis of the agitator assembly is permitted between the agitator and both the first swivel connector and the second swivel connector.

13. A method for deploying a coiled tubing (CT) system into a wellbore penetrating a subsurface region, the method comprising:(a) deploying a first CT string of the CT system into the wellbore;(b) cutting the first CT string at a surface assembly of the CT system to form an uphole end of the first CT string that is located opposite to a downhole end of the CT string located in the wellbore;(c) coupling a downhole swivel connector to the uphole end of the first CT string;(d) coupling an uphole swivel connector to a downhole end of a second CT string of the CT system that is different from the first CT string; and(e) coupling an agitator assembly of the CT system between the downhole swivel connector and the uphole swivel connector whereby rotation about a longitudinal axis of the CT system is permitted between the agitator assembly and at least one of the first CT string or the second CT string about a longitudinal axis of the CT system.

14. The method of claim 13, wherein (c) comprises permitting rotation about the longitudinal axis of the CT system between the agitator assembly and both the first CT string and the second CT string.

15. The method of claim 13, wherein at least one of:(c) comprises welding the downhole swivel connector to the uphole end of the first CT string; or(d) comprises welding the uphole swivel connector to the downhole end of the second CT string.

16. The method of claim 15, wherein at least one of:(c) comprises heating the downhole swivel connector and / or the first CT string to a predefined heat treatment temperature; or(d) comprises heating the uphole swivel connector and / or the second CT string to the predefined heat treatment temperature.

17. The method of claim 16, wherein the predefined heat treatment temperature is equal to or greater than 400 degrees Fahrenheit.

18. The method of claim 16, wherein the predefined heat treatment temperature is equal to or greater than 450 degrees Fahrenheit.

19. The method of claim 16, wherein the predefined heat treatment temperature is equal to or greater than 500 degrees Fahrenheit.

20. The method of claim 13, wherein at least one of:(c) comprises slipping the downhole swivel connector onto the uphole end of the first CT string and locking the downhole swivel connector to the first CT string with a slip of the downhole swivel connector; or(d) comprises slipping the uphole swivel connector onto the downhole end of the second CT string and locking the uphole swivel connector to the second CT string with a slip of the uphole swivel connector.

Images