Systems and methods for cutting coiled tubing strings at a wellsite

Abstract

A coiled tubing (CT) cutting system (150) for a surface assembly of a well system includes an upper blow-out preventer (BOP)(102), a lower BOP (120), a spacer (145) coupled between the upper BOP and the lower BOP, a CT string extending through the upper BOP and the lower BOP and into a wellbore penetrating a subsurface region, and a connector (160) coupled between the spacer and the lower BOP, wherein the connector is configured to connect the upper BOP from the lower BOP.

Description

3314-69702SYSTEMS AND METHODS FOR CUTTING COILED TUBING STRINGS AT A WELLSITECROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit of U.S. provisional patent application Serial No.63 / 776,818 filed March 24, 2025, and entitled "Systems and Methods for Cutting Coiled Tubing Strings at a Wellsite," 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] 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.BRIEF SUMMARY OF THE DISCLOSURE

[0004] A CT cutting system for a surface assembly of a well system comprises an upper blow-out preventer (BOP), a lower BOP, a spacer coupled between the upper BOP and the lower BOP, a CT string extending through the upper BOP and the lower BOP and into a wellbore penetrating a subsurface region, and a connector coupled between the spacer and the lower BOP, wherein the connector is configured to connect the upper BOP from the lower BOP. In some embodiments, the connector3314-69702comprises a releasable connector comprising one or more test ports configured to facilitate pressure testing of the surface assembly. In certain embodiments, the releasable connector comprises one or more actuators for transitioning the releasable connector between a locked configuration locking a lower end of the spacer to an upper end of the lower BOP whereby relative movement therebetween is restricted, and an unlocked configuration unlocking the lower end of the spacer to the upper end of the lower BOP whereby relative movement there between is permitted. In certain embodiments, the connector comprises a flanged connector. In some embodiments, the upper BOP is positioned vertically above the lower BOP along a longitudinal axis of the CT cutting system. In some embodiments, the upper BOP comprises a cutting device configured to sever a portion of the CT string. In certain embodiments, the lower BOP comprises a slip ram.

[0005] An embodiment of a method for cutting a CT string of a well system comprises (a) assembling a toolstring onto a CT string, (b) running the CT string through a lubricator and into a wellbore penetrating a subsurface region, (c) positioning the CT string at a desired depth in the wellbore and closing a lower blow-out preventer (BOP) around the CT string, (d) reducing pressure from the lubricator and the CT string, and (e) activating an upper BOP to sever the CT string, wherein the upper BOP is positioned vertically above the lower BOP along a longitudinal axis of the CT cutting system, and wherein the upper BOP comprises a cutting device. In certain embodiments, (e) comprises activating the cutting device to sever the CT string. In some embodiments, the method comprises (f) pressure testing the well system, and (g) disconnecting the lubricator from the lower BOP. In some embodiments, (g) comprises utilizing one or more test ports located on a releasable connector coupled between the upper BOP and the lower BOP. In certain embodiments, a spacer is coupled between the upper BOP and the releasable connector. In certain embodiments, the releasable connector comprises one or more actuators for transitioning the releasable connector between a locked configuration locking a lower end of the spacer to an upper end of the lower BOP whereby relative movement therebetween is restricted, and an unlocked configuration unlocking the lower end of the spacer to the upper end of the lower BOP whereby relative movement therebetween is permitted. In some embodiments, the lower BOP comprises a slip ram.3314-69702

[0006] An embodiment of a method for cutting a CT string of a well system comprises (a) detecting a position of a toolstring in a lubricator coupled to a wellbore penetrating a subsurface region, wherein the toolstring is coupled to a CT string, (b) lifting the toolstring above an upper blow-out (BOP) coupled to a wellhead of the wellbore, (c) closing a lower BOP around the CT string to secure the wellbore, (d) reducing pressure from the lubricator and the CT string, and (e) activating the upper BOP to sever the CT string by a cutting device of the upper BOP, wherein the upper BOP is positioned vertically above the lower BOP along a longitudinal axis of the CT cutting system. In some embodiments, the method comprises (f) pressure testing the well system, and (g) disconnecting the lubricator from the lower BOP. In certain embodiments, (g) comprises utilizing one or more test ports located on a releasable connector coupled between the upper BOP and the lower BOP. In certain embodiments, a spacer is coupled between the upper BOP and the releasable connector. In some embodiments, the releasable connector comprises one or more actuators for transitioning the releasable connector between a locked configuration locking a lower end of the spacer to an upper end of the lower BOP whereby relative movement therebetween is restricted, and an unlocked configuration unlocking the lower end of the spacer to the upper end of the lower BOP whereby relative movement therebetween is permitted. In some embodiments, the lower BOP comprises a slip ram.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 well system in accordance with principles disclosed herein;

[0009] 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;

[0010] FIG. 3 is a zoomed-in view of the surface assembly of FIG. 2 in accordance with principles disclosed herein;

[0011] FIGS. 4-8 are schematic views illustrating a method for cutting a CT string using a CT cutting system in accordance with principles disclosed herein; and

[0012] FIG. 9 is a schematic view of another embodiment of a CT cutting system in accordance with principles disclosed herein.3314-69702DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

[0013] 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.

[0014] Certain terms are used throughout the following description and claims to refer to 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.

[0015] 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,3314-69702regardless 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.

[0016] 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 the 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.

[0017] 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 bottomhole 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 toolstrings including one or more downhole tools. In some embodiments, the toolstrings disclosed herein may include tools in common with, or perform similar functions as BHAs. 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.

[0018] Conventionally, cutting a coiled tubing is a manual process, however some operations use hydraulic cutters. When it is determined that a coiled tubing string needs to be severed, the tubing string is raised to access the section of the coiled string that needs to be cut, a cutting tool may be inserted within the coiled tubing, positioned for cutting at a desired location, and activated to make the cut. These cutters are typically outfitted with a blade or other cutting member for severing the coiled tubing. However, the risk to avoid is the uncontrolled swinging of the injector head and the lubricator, the potential impact of their movement on the coiled tubing3314-69702during the cutting process, maintaining pressure integrity and consequently the safety of rig personnel.

[0019] Accordingly, embodiments disclosed herein includes methods and systems for cutting coiled tubing strings at a wellsite to improve rig up and rig down time and prevent uncontrolled movement of the CT string while providing wellhead pressure containment functions and safety for rig personnel at the wellsite. Embodiments disclosed herein includes a CT cutting system of a surface assembly comprising an upper BOP, a lower BOP, a spacer coupled between the upper BOP and the lower BOP, a downhole CT string, and a releasable connector coupled between the spacer and the lower BOP and configured to connect and / or disconnect the upper BOP from the lower BOP. Particularly, embodiments disclosed herein comprises a releasable connector having a plurality of test ports configured to allow pressure testing of the surface assembly, and a one or more actuators for transitioning the releasable connector between a locked configuration locking a lower end of the spacer to an upper end of the lower BOP whereby relative movement therebetween is restricted, and an unlocked configuration unlocking the lower end of the spacer to the upper end of the lower BOP whereby relative movement therebetween is permitted.

[0020] 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 fordrilling 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 terranean3314-69702surface 3, and a drilling assembly including a drill bit for cutting into the subterranean earthen formation 2.

[0021] 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.

[0022] Additionally, in this exemplary embodiment, CT system 10 includes a one or more toolstring 12 coupled to CT string 20. Particularly, CT system 10 is shown in FIG. 1 as including a first toolstring 12 coupled to the downhole end 21 of downhole CT string 20, and a second toolstring 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 toolstrings 12 in this exemplary embodiment, in other embodiments, CT system 10 may include one, or any number / combinations of toolstring 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.

[0023] 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 toolstrings 12 such that fluid may be pumped from the surface assembly 50 into and through uphole CT string 30, the second toolstring 12, the downhole CT string 20, and into the first toolstring 12 connected to the downhole end 21 of the downhole CT string 20. The toolstrings 12 of CT system 10 may include any combination of tools or equipment for performing specific tasks associated with wellbore 4. For example, toolstring 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.

[0024] 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 from3314-69702wellbore 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.

[0025] 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 toolstrings 12, and for communicating signals (e.g., electrical signals, optical signals) and / or applying axial loads to CT strings 20, 30 and toolstrings 12 as needed to facilitate their downhole operation.

[0026] In this exemplary embodiment, surface assembly 50 generally includes a CT truck or transporter 92 that may include an accumulator or other equipment such as hydraulic units and safety devices, a CT reel 94 rotatable by a CT motor 96 (each positioned on the CT transporter 92), a CT control center or unit 98 (also positionable on the CT transporter 92) 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 90 for aligning downhole CT string 20 as it is deployed or retrieved, and a crane 87 (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.

[0027] 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 CT3314-69702reel 94 in response to the operation of CT motor 96. The unwinding from, and winding onto, CT reel 94 of downhole CT string 20 may be performed or assisted by a tubing tensioner (not shown) of CT transporter 92 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 90 extending from injector head 85. The injector head 85 is suspended from a crane 87 such that the crane 87 may be used to control the positioning of injector head 85 relative to wellbore 4. In this manner, crane 87 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 87 may selectably vertically lift the injector head 85 and lubricator 80 from BOP 60 (i.e., when the lubricator 80 is decoupled from BOP 60) as desired to expose a segment of the downhole CT string 20 located vertically above BOP 60.

[0028] 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 cutting 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 cutting ram configured to cut the downhole CT string 20 when present therein. In some embodiments, BOP 60 may not include BOP ram 62 and may instead only include BOP rams 64 and 66. 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.

[0029] 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 92 may include or support the CT control unit 983314-69702for 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 toolstring 12 shown in FIG. 1. Additionally, fluids may be pumped between CT transporter 92 and tools attached to the terminal end of downhole CT string 20 via the central passage extending through downhole CT string 20.

[0030] 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 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 87) the injector head 85 and lubricator 80 vertically upwards away from the BOP 60.

[0031] 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 toolstring (e.g., toolstring 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 pull tests and pressure 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 toolstring is run into wellbore 4. As previously described, different lengths of CT string may be placed between toolstring(s), depending on the 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 downhole toolstring 12 and an uphole toolstring 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 string3314-6970230) via a CT connector 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.

[0032] Referring to FIG. 4, an exemplary CT cutting system 100 for cutting a CT string at a wellsite is shown. CT cutting system 100 may be incorporated into a surface assembly of a well system. For instance, in some embodiments, CT cutting system 100 is incorporated into the surface assembly 50 of the well system shown in FIGS. 1-3 described above; however, the configuration of the surface assembly or well system into which CT cutting system 100 is incorporated may vary than that shown in FIGS.1-3 in other embodiments In this exemplary embodiment, CT cutting system 100 is generally configured to cut CT strings (e.g., downhole CT string 20 shown in FIG. 1) while the CT string is being run in hole (RIH) whereby the CT string is lowered into a wellbore (e.g., wellbore 4 shown in FIGS. 1 and 2) and / or being pulled out of hole (POOH) whereby the CT string is being retracted from the wellbore. Particularly, CT cutting system 100 may minimize the time required for cutting the CT string by facilitating the quick connection and / or disconnection from wellhead 52 while providing wellhead pressure containment functions and safety for rig personnel 72 at the wellsite.

[0033] In this manner, CT cutting system 100 allows for the rapid cutting of a CT string without necessarily exposing rig personnel 72 to risks that may manifest when rig personnel 72 is required to manually cut an exposed segment of the CT string in proximity therewith. For instance, immediately following cutting, the separated uphole length of CT string may flex or swing rapidly and violently because of residual stresses retained in the CT string and which are permitted to release following cutting. Conversely, CT cutting system 100 permits the remote cutting of the CT string with rig personnel 72 located at a safe distance from the CT string during the cutting thereof. Moreover, CT cutting system 100 utilizes preexisting equipment of the surface assembly such as BOPs of the surface assembly to physically support and cut the CT string, thereby minimizing the amount of additional equipment required to provide CT cutting system 100 at a wellsite.

[0034] In this exemplary embodiment, CT cutting system 100 has a longitudinal or central axis 105 and generally includes a first or upper BOP 102, a second or lower BOP 120 and an elongate, tubular BOP spacer 140, and a tubular releasable connector 160 connected between the lower BOP 120 and BOP spacer 140. In some3314-69702embodiments, CT cutting system 100 further includes a tandem stripper head (not shown); In other embodiments, the configuration of CT cutting system 100 may vary from that shown in FIG. 4. For instance, in other embodiments, CT cutting system 100 may comprise more or fewer BOPs and / or different ram configuration, for example, CT cutting system 100 may comprise a triple BOP ram with a blind ram, a quad BOP, a quint BOP, and so on. In another embodiment, CT cutting system 100 may further include a tandem stripper head. Additionally, in this exemplary embodiment, CT cutting system 100 is shown incorporated into a surface assembly in which CT cutting system 100 is coupled or mounted between lubricator 80 and BOP ram 62 which have been described further above. However, the equipment of the surface assembly between which CT cutting system 100 is coupled may vary from that shown in FIG. 4. Additionally, in some embodiments, the lower BOP 120 of CT cutting system 100 may directly incorporate an additional BOP to define a combination BOP.

[0035] The upper BOP 102 of CT cutting system 100 comprises a BOP body 104 defining a central passage 107 extending therethrough. Additionally, BOP body 104 defines a first or upper end 106 and an opposing second or lower end 108. In this exemplary embodiment, one or more cutting rams 110 are coupled to lateral sides of the BOP body 104, each cutting ram 110 comprising a ram actuator 112 and a cutting device 114 coupled to a terminal end of the ram actuator 112. In this exemplary embodiment, cutting device 114 comprises one or more shear ram blocks; however, the configuration of cutting device 114 may vary in other embodiments. The actuator of each cutting ram 110 is configured to selectably (e.g., as controlled by an operator of CT cutting system 100) displace the cutting device 114 laterally (orthogonally relative central axis 105) into and from the central passage 107 of the upper BOP 102. In this exemplary embodiment, the cutting devices 114 of upper BOP 102 are each comprise cutting surfaces configured to cut through or sever the downhole CT string 20 and / or other tubular member extending through central passage 107, and sealing elements for sealing the central passage 107 whereby fluid communication is restricted between the upper end 106 and lower end 108 of BOP body 104.

[0036] The lower BOP 120 of CT cutting system 100 similarly comprises a BOP body 122 defining a central passage 125 extending therethrough. Additionally, BOP body 122 defines a first or upper end 124 and an opposing second or lower end 126. In this exemplary embodiment, a pair of slip rams 130 are coupled to lateral sides of the BOP body 122, each slip ram 130 comprising a ram actuator 132 and a gripping element or3314-69702slip ram block 134 coupled to a terminal end of the ram actuator 132. The ram actuator 132 of each slip ram 130 is configured to selectably (e.g., as controlled by an operator of CT cutting system 100) displace the slip ram block 134 laterally (orthogonally relative central axis 105) into and from the central passage 125 of the lower BOP 120. The slip ram block 134 of each slip ram 130 comprises one or more engagement members or teeth 135 for gripping a portion of the downhole CT string 20 and / or other tubular members received in central passage 125 to both restrict relative movement between the gripped portion of the downhole CT string 20 and the slip ram block 134. For instance, the teeth 135 of slip ram blocks 134 may bite into the outer surface of the downhole CT string 20 to affix the downhole CT string 20 to the slip ram blocks 134 whereby relative movement is restricted therebetween.

[0037] In some embodiments, slip ram blocks 134 may comprise sealing elements or members configured to, in addition to gripping downhole CT string 20, seal against the outer surface of downhole CT string 20 whereby fluid flow is restricted along the annular interface formed between slip ram blocks 134 and the outer surface of downhole CT string 20. For instance, in some embodiments, slip ram blocks 134 may comprise pipe-slip ram blocks and the like. Thus, in at least some embodiments, the slip ram block 134 of each slip ram 130 is configured to provide a seal and / or grip around the downhole CT string 20 thereby creating a pressure-tight seal / barrier to prevent any fluids from flowing up the wellbore 4 when lower BOP 120 is closed. In other embodiments, a separate BOP may instead seal against the downhole CT string 20 other than lower BOP 120.

[0038] BOPs 102 and 120 are both actuatable between an open state or configuration in which the ram blocks 114 and 134, respectively, are retracted from their corresponding central passages 107 and 125, respectively, and a closed state or configuration in which ram blocks 114 and 134 are extended into their corresponding central passages 107 and 125. Particularly, upper BOP 102 is actuatable between its open and closed configurations by ram actuators 112 while lower BOP 120 is actuatable between its open and closed configurations by ram actuators 132. In this exemplary embodiment, BOPs 102 and 120 are remotely actuatable between their open and closed configurations by an operator of CT cutting system 100. For example, CT cutting system 100 may comprise a hydraulic pump or actuator fluidically connected to the ram actuators 112 and 132 of BOPs 102 and 120 for hydraulically actuating BOPs 102 and 120 between their open and closed configurations.3314-69702Alternatively, BOPs 102 and 120 may be electrically, pneumatically, and / or mechanically (e.g., manually) actuated between their open and closed configurations.

[0039] BOP spacer 140 extends along central axis 105 of CT cutting system 100 and includes a first or upper end 142 coupled to the lower end 108 of upper BOP 102, a longitudinally opposed second or lower end 144 coupled to an upper end of the releasable connector 160, and a central passage 145 extending between the ends 142 and 144 thereof. In some embodiments, BOP spacer 140 comprises a 3-to-4-foot (ft) pup joint coupled between upper BOP 102 and releasable connector 160. However, the dimensions and other features of BOP spacer 140 may vary in other embodiments.

[0040] Releasable connector 160 facilitates a convenient and rapid connection and disconnection of the lower end 144 of BOP spacer 140 with the upper end 124 of the lower BOP 120 to minimize the time required for performing the connection or disconnection. Releasable connector 160 includes one or more actuators 162 for transitioning the releasable connector 160 between a locked state or configuration locking the lower end 144 of BOP spacer 140 to the upper end 124 of lower BOP 120 whereby relative movement therebetween is restricted, and an unlocked state or configuration unlocking the lower end 144 of BOP spacer 140 to the upper end 124 of lower BOP 120 whereby relative movement therebetween is permitted. In other words, in the unlocked configuration of releasable connector 160, the BOP spacer 140 (along with the upper BOP 102) may be vertically lifted from the lower BOP 120 as will be discussed further herein. In some embodiments, actuators 162 comprise powered actuators such as hydraulically, pneumatically, and / or electromechanically actuators which may be operated remotely by a user of CT cutting system 100.

[0041] In other embodiments, actuators 162 may comprise mechanical fasteners that may be operated manually by rig personnel 72. However, even when actuators 162 comprise mechanical fasteners, releasable connector 160 may still define a so called “quick connect” that may be more quickly and easily connected and disconnected relative to a standard flanged connection such as by having mechanical fasteners than would otherwise be present on a standard flanged connection having, for example, eleven separate circumferentially spaced mechanical fasteners. In other embodiments, the lower end 144 of BOP spacer 140 may be connected to the upper end 124 of lower BOP 120 via such a standard flanged connection such as in applications when releasable connector 160 is unavailable for use.3314-69702

[0042] In this exemplary embodiment, the releasable connector 160 includes a tool change joint hydraulic bottom connection instead of a manual bolted or hand union connection, a tapered seal bore configured to facilitate stabbing of the downhole CT string 20, and a dual O-ring sealing area through which rig personnel 72 can easily pressure test the connection via a hydraulic pump and one or more test ports 164.

[0043] Referring to FIGS. 4-8, to illustrate operational features of CT cutting system 100, an exemplary cutting operation of the downhole CT string 20 is shown. Particularly, FIG. 4 illustrates downhole CT string 20 being unwound from CT reel 94 of the surface assembly 50 shown in FIGS. 2 and 3 in response to the operation of CT motor 96. The unwinding from CT reel 94 of downhole CT string 20 may be performed or assisted by a tubing tensioner of CT transporter 92 that is powered by a hydraulic unit, tubing guide 90 extending from injector head 85, and crane 87 such that the crane 87 may align injector head 85 with wellhead 52 and BOP 102 to ensure smooth feeding of downhole CT string 20 into wellbore 4, and selectably vertically lift the injector head 85 and lubricator 80 from upper BOP 102 as desired to expose a segment of the downhole CT string 20 located vertically above upper BOP 102, as will be discussed further herein. Additionally, as downhole CT string 20 is being RIH, both the upper and lower BOPs 102 and 120, respectively, are in their open configurations along with, in this exemplary embodiment, BOP ram 62.

[0044] Prior to downhole CT string 20 being RIH as shown in FIG. 4, the lubricator 80 is assembled, filled with appropriate fluid to equalize the pressure between the lubricator 80 and wellbore 4 (e.g. wellbore fluid to maintain pressure balance between wellbore 4 and lubricator 80) and ensure safe entry into wellbore 4. In some embodiments, a milling toolstring or cutting device is assembled onto the downhole end 21 of downhole CT string 20 (defining a “CT stinger” in this example). Oftentimes, a surface test is performed to check tool functionality prior to RIH. For instance, the lower BOP 120 may be closed around the downhole CT string 20, and the pressure in lubricator 80 and the downhole CT string 20 above pipe ram 130 is bled off. Particularly, a pressure test is performed to ensure pressure integrity in the CT cutting system 100 via the releasable connector 160 without the need to undo bolts or fasteners as in a conventional flanged connection, thereby improving rig up and rig down, while providing wellhead pressure containment functions and safety for rig personnel 72 at the wellsite. In some embodiments, a pressure test is performed by first closing BOP 120 to isolate the section above. Once the rams of the BOP 120 are3314-69702closed, the pressure that has built up above the closed downhole CT string 20 is bled off to check or detect any leaks or inflow through a potential leak path. Alternatively, pressure in the system may be bled down and then built back up to detect any leak in the system. The lubricator 80 may include a kill line and associated valves that allow pressure to be safety bled off above the BOPs, or if needed, to inject fluids to control the wellbore 4. More importantly, the BOP includes the cutting ram for cutting the CT string 20 if necessary, and the slip rams for securely clamping the CT string 20 and sealing the annular space around it.

[0045] When a desired length of the downhole CT string 20 has been RIH, it may be desired to cut the downhole CT string 20 to define the uphole end 23 thereof which may be subsequently coupled to a downhole tool (e.g., a toolstring 12) or directly to another, separate CT string (e.g., uphole CT string 30). As shown particularly in FIG.5, to initiate the process of cutting the downhole CT string 20 (or another tubular member extending centrally through CT cutting system 100), the lower BOP 120 is actuated from its open configuration to its closed configuration whereby the teeth 135 of the slip ram blocks 134 thereof clamp against the outer surface of the downhole CT string 20. With lower BOP 120 in the closed configuration, the downhole CT string 20 is secured to or supported by the slip ram blocks 134 of the lower BOP 120. Additionally, in certain embodiments, slip ram blocks 134 may seal the annulus formed between the downhole CT string 20 and an inner surface of the central passage 125 of lower BOP 120. Further, releasable connector 160 is in its locked configuration in the configuration shown in FIGS. 4 and 5.

[0046] As shown in FIG. 6, with downhole CT string 20 physically supported or clamped against the slip ram blocks 134 of lower BOP 120, the upper BOP 102 may be actuated from its open configuration to its closed configuration whereby the cutting devices 114 thereof cut or sever the downhole CT string 20 at a desired location therealong. In some embodiments, upper BOP 102 is activated through hydraulic activation using a series of valves and accumulators configured to deliver the pressure necessary to activate upper BOP 102. However, in other embodiments, mechanical and / or electronic / remote actuators may be used.

[0047] As shown particularly in FIG. 7, an upper end 23 of the downhole CT string 20 is severed from a lower end 24 of the downhole CT string 20 by the cutting devices 114 of the upper BOP 102 as indicated by arrow A of FIG. 7. In this manner, the uphole end 23 of severed downhole CT string 20 is separated from a remaining3314-69702segment 22 of the downhole CT string 20 which may be retracted through the lubricator 80 and to the CT reel 94 of surface assembly 50 such that only the downhole CT string 20 terminating at uphole end 23 remains within the CT cutting system 100. During the cutting of downhole CT string 20, the closed lower BOP 120 may limit movement of the downhole CT string 20 to facilitate the cutting thereof.

[0048] As shown particularly in FIG. 8, following the retraction of remaining segment 22 to the CT reel 94 of surface assembly 50, the releasable connector 160 is actuated from its locked configuration to its unlocked configuration to thereby disconnect lubricator 80 from the lower combi BOP 104. In some instances, releasable connector 160 is hydraulically actuated to pressure test and quickly connect / disconnect lubricator 80 and the upper BOP 102 from the lower BOP 120. In other instances, releasable connector 160 may be mechanically or electrically actuated. In some embodiments, lubricator 80 is raised and moved away from wellbore 4 using crane 87, allowing redress of the portion of the downhole CT string 20 above lower BOP 120 for subsequent operation.

[0049] The steps described above may also be performed during a POOH operation. For example, when a toolstring enters lubricator 80 during a POOH operation, the toolstring is raised above the upper BOP 102 (e.g., 5 ft above the upper BOP 102) with both the upper BOP 102 and the lower BOP 120 in the closed configuration. The pressure in the downhole CT string 20 and lubricator 80 is then bled off. Once pressure integrity is confirmed, upper BOP 102 is actuated from its open configuration to the closed configuration to cut the downhole CT string 20. The releasable connector 160 is activated to disconnect lubricator 80 and the upper BOP 102 from the lower BOP 120. Subsequently, lubricator 80 is moved away from above wellhead 52 and the toolstring contained in lubricator 80 is removed. The portion of the downhole CT string 20 above the toolstring may be manually cut without induced stress in the downhole CT string 20 at the location of the cut.

[0050] Referring to FIG. 9, another exemplary CT cutting system 150 for cutting a CT string at a wellsite is shown. CT cutting system 150 may be incorporated into a surface assembly of a well system. For instance, in some embodiments, CT cutting system 150 is incorporated into the surface assembly 50 of the well system shown in FIGS. 1-3 described above; however, the configuration of the surface assembly or well system into which CT cutting system 150 is incorporated may vary than that shown in FIGS.1-3 in other embodiments.3314-69702

[0051] In this exemplary embodiment, CT cutting system 150 is generally configured to cut CT strings (e.g., downhole CT string 20 shown in FIG. 1) while the CT string is being RIH. CT cutting system 150 includes features in common with CT cutting system 100 disclosed in FIGS. 4-8 above, and like components are labelled similarly. Particularly, in this exemplary embodiment, CT cutting system 150 includes a standard flanged connector 900 coupled between the lower BOP 120 and BOP spacer 140 instead of the tubular releasable connector 160 of CT cutting system 100. The flanged connector 900 may be manually bolted or connected between the lower BOP 120 and BOP spacer 140 via a hand union.

[0052] In this exemplary embodiment, when a desired length of tubing (e.g., CT string 20) has been RIH as shown in FIG. 9, to initiate the process of cutting the downhole CT string 20 (or another tubular member extending centrally through CT cutting system 150), the lower BOP 120 is actuated from its open configuration to its closed configuration whereby the teeth 135 of the slip ram blocks 134 thereof clamp against the outer surface of the downhole CT string 20. With lower BOP 120 in the closed configuration, the downhole CT string 20 is secured to or supported by the slip ram blocks 134 of the lower BOP 120.

[0053] Additionally, in some embodiments, slip ram blocks 134 may seal the annulus formed between the downhole CT string 20 and an inner surface of the central passage 125 of lower BOP 120. Alternatively, another sealing device (e.g., a different BOP) may seal the annulus surrounding downhole CT string 20. With the flanged connector 900 securely locked or clamped against the lower BOP 120, the upper BOP 102 may be actuated from its open configuration to its closed configuration whereby the cutting 114 thereof cut or sever the downhole CT string 20 at a desired location therealong. Following cutting of the CT string 20 and subsequent retraction of remaining segment 22 to the CT reel 94 of surface assembly 50, the flanged connector is then unlocked to thereby disconnect lubricator 80 from the lower combi BOP 104.

[0054] As previously described, the steps described above may also be performed during a POOH operation. For example, when a toolstring enters lubricator 80 during a POOH operation, the toolstring is raised above the upper BOP 102 (e.g., 5 ft above the upper BOP 102) with both the upper BOP 102 and the lower BOP 120 in the closed configuration. The pressure in the downhole CT string 20 and lubricator 80 is then bled off. Once pressure integrity is confirmed, upper BOP 102 is actuated from its3314-69702open configuration to the closed configuration to cut the downhole CT string 20. The flanged connector 900 is then disconnected to release the lubricator 80 and the upper BOP 102 from the lower BOP 120. Subsequently, lubricator 80 is moved away from above wellhead 52 and the toolstring contained in lubricator 80 is removed.

[0055] 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

3314-69702CLAIMSWhat is claimed is:

1. A coiled tubing (CT) cutting system for a surface assembly of a well system, the CT cutting system comprising:an upper blow-out preventer (BOP);a lower BOP;a spacer coupled between the upper BOP and the lower BOP;a CT string extending through the upper BOP and the lower BOP and into a wellbore penetrating a subsurface region; anda connector coupled between the spacer and the lower BOP, wherein the connector is configured to connect the upper BOP from the lower BOP.

2. The CT cutting system of claim 1, wherein the connector comprises a releasable connector comprising one or more test ports configured to facilitate pressure testing of the surface assembly.

3. The CT cutting system of claim 2, wherein the releasable connector comprises one or more actuators for transitioning the releasable connector between a locked configuration locking a lower end of the spacer to an upper end of the lower BOP whereby relative movement therebetween is restricted, and an unlocked configuration unlocking the lower end of the spacer to the upper end of the lower BOP whereby relative movement there between is permitted.

4. The CT cutting system of claim 1, wherein the connector comprises a flanged connector.

5. The CT cutting system of claim 1, wherein the upper BOP is positioned vertically above the lower BOP along a longitudinal axis of the CT cutting system.

6. The CT cutting system of claim 1, wherein the upper BOP comprises a cutting device configured to sever a portion of the CT string.3314-697027. The CT cutting system of claim 1 , wherein the lower BOP comprises a slip ram.

8. A method for cutting a coiled tubing (CT) string of a well system, the method comprising:(a) assembling a toolstring onto a CT string;(b) running the CT string through a lubricator and into a wellbore penetrating a subsurface region;(c) positioning the CT string at a desired depth in the wellbore and closing a lower blow-out preventer (BOP) around the CT string;(d) reducing pressure from the lubricator and the CT string; and(e) activating an upper BOP to sever the CT string, wherein the upper BOP is positioned vertically above the lower BOP along a longitudinal axis of the CT cutting system, and wherein the upper BOP comprises a cutting device.

9. The method of claim 8, wherein (e) comprises activating the cutting device to sever the CT string.

10. The method of claim 8, further comprising:(f) pressure testing the well system; and(g) disconnecting the lubricator from the lower BOP.

11. The method of claim 10, wherein (g) comprises utilizing one or more test ports located on a releasable connector coupled between the upper BOP and the lower BOP.

12. The method of claim 11, wherein a spacer is coupled between the upper BOP and the releasable connector.

13. The method of claim 12, wherein the releasable connector comprises one or more actuators for transitioning the releasable connector between a locked configuration locking a lower end of the spacer to an upper end of the lower BOP whereby relative movement therebetween is restricted, and an unlocked configuration unlocking the lower end of the spacer to the upper end of the lower BOP whereby relative movement therebetween is permitted.3314-6970214. The method of claim 8, wherein the lower BOP comprises a slip ram.

15. A method for cutting a coiled tubing (CT) string of a well system, the method comprising:(a) detecting a position of a toolstring in a lubricator coupled to a wellbore penetrating a subsurface region, wherein the toolstring is coupled to a CT string;(b) lifting the toolstring above an upper blow-out (BOP) coupled to a wellhead of the wellbore;(c) closing a lower BOP around the CT string to secure the wellbore;(d) reducing pressure from the lubricator and the CT string; and(e) activating the upper BOP to sever the CT string by a cutting device of the upper BOP, wherein the upper BOP is positioned vertically above the lower BOP along a longitudinal axis of the CT cutting system.

16. The method of claim 15, further comprising:(f) pressure testing the well system; and(g) disconnecting the lubricator from the lower BOP.

17. The method of claim 16, wherein (g) comprises utilizing one or more test ports located on a releasable connector coupled between the upper BOP and the lower BOP.

18. The method of claim 17, wherein a spacer is coupled between the upper BOP and the releasable connector.

19. The method of claim 18, wherein the releasable connector comprises one or more actuators for transitioning the releasable connector between a locked configuration locking a lower end of the spacer to an upper end of the lower BOP whereby relative movement therebetween is restricted, and an unlocked configuration unlocking the lower end of the spacer to the upper end of the lower BOP whereby relative movement therebetween is permitted.

20. The method of claim 15, wherein the lower BOP comprises a slip ram.

Images