SYSTEMS AND METHODS FOR ALIGNING COILED TUBING STRINGS AT A WELLSITE

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefit of U.S. provisional Ser. No. 63/729,165 filed Dec. 6, 2024, and entitled “Systems and Methods for Aligning 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

Not applicable.

BACKGROUND

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

BRIEF SUMMARY OF THE DISCLOSURE

An embodiment of a coiled tubing (CT) aligner for aligning a first CT string and a second CT string of a well system comprises a first clamp having a central passage and positionable about the second CT string to apply a clamping force to the second CT string for locking the first clamp to the second CT string, a centralizer comprising a central passage in which the first CT string is slidably receivable, a rigid support arm connected between the first clamp and the centralizer, and a second clamp having a central passage and positionable about the first CT string to apply a clamping force to the first CT string for locking the first clamp to the first CT string. In some embodiments, the CT aligner further comprising a CT tensioner that comprises a flexible CT linkage connectable between the first clamp and the second clamp, and an actuator configured to selectably adjust a longitudinal length of the CT linkage to adjust tension applied to the CT linkage. In certain embodiments, the CT linkage comprises a chain and the actuator comprises a chain tensioner for adjusting the longitudinal length of the chain. In other embodiments, the first clamp comprises a cylindrical body defined by a pair of C-rings defining the central passage of the first clamp, and a plurality of clamping actuators configured to selectably adjust an inner diameter of the central passage of the first clamp. In some embodiments, the first clamp further comprises a set of C-ring adapters each of which are configured to releasably couple to the pair of C-rings to adjust a minimum inner diameter of the first clamp. In certain embodiments, the CT aligner further comprises a rigid leverage arm connectable to the first clamp and the second clamp for applying a lateral force to the second clamp. In other embodiments, the leverage arm extends between a proximal end and a longitudinally opposed distal end that is pointed and receivable in a connector of the second clamp. In some embodiments, the centralizer comprises a cylindrical body and a plurality of circumferentially spaced alignment members each extending radially through the cylindrical body to project radially from an inner surface of the central passage of the centralizer. In certain embodiments, the centralizer comprises a frustoconical central passage.

An embodiment of a CT aligner for aligning a first CT string and a second CT string of a well system comprises a first clamp having a central passage and positionable about the second CT string to apply a clamping force to the second CT string for locking the first clamp to the second CT string, a second clamp having a central passage and positionable about the first CT string to apply a clamping force to the first CT string for locking the second clamp to the first CT string, a rigid support arm connected between the first clamp and the second clamp, and a CT tensioner comprising a flexible CT linkage connectable between the first clamp and the second clamp, and an actuator configured to selectably adjust a longitudinal length of the CT linkage to adjust tension applied to the CT linkage. In some embodiments, the CT linkage comprises a chain and the actuator comprises a chain tensioner for adjusting the longitudinal length of the chain. In certain embodiments, the first clamp comprises a cylindrical body defined by a pair of C-rings defining the central passage of the first clamp, and a plurality of clamping actuators configured to selectably adjust an inner diameter of the central passage of the first clamp. In other embodiments, the first clamp further comprises a set of C-ring adapters each of which are configured to releasably couple to the pair of C-rings to adjust a minimum inner diameter of the first clamp. In some embodiments, the CT aligner further comprises a rigid leverage arm connectable to the first clamp and the second clamp for applying a lateral force to the second clamp. In certain embodiments, the leverage arm extends between a proximal end and a longitudinally opposed distal end that is pointed and receivable in a connector of the second clamp. In other embodiments, the centralizer comprises a cylindrical body and a plurality of circumferentially spaced alignment members each extending radially through the cylindrical body to project radially from an inner surface of the central passage of the centralizer.

An embodiment of a method for aligning a CT string of a well system using a CT aligner comprises clamping a first clamp of the CT aligner to the CT string; slidably positioning a centralizer of the CT aligner around the CT string whereby the CT string is slidably received in a central passage of the centralizer; and clamping a second clamp of the CT aligner to the CT string whereby the centralizer is positioned between the first clamp and the second clamp along the CT string. In some embodiments, the method further comprises cutting the CT string at a location between the first clamp and the centralizer to separate the CT string into a first segment and a second segment and whereby residual stresses in the CT string are transferred between the first segment and the second segment through a rigid support arm of the CT aligner coupled between the first clamp and the centralizer. In certain embodiments, the method further comprises lifting the first segment of the CT string from the second segment of the CT string whereby the first segment gradually angularly misaligns from the second segment of the CT string as a terminal end of the second segment slides along an inclined inner surface of the central passage of the centralizer. In other embodiment, the first clamp and the second clamp comprise a cylindrical body defined by a pair of C-rings defining the central passage of the first clamp and the second clamp, and a plurality of clamping actuators configured to selectably adjust an inner diameter of the central passage of the first clamp and the second clamp. In some embodiments, the first clamp and the second clamp further comprise a set of C-ring adapters each of which are configured to releasably couple to the pair of C-rings to adjust a minimum inner diameter of the first clamp and the second clamp.

An embodiment of a method for coupling a first CT string and a second CT string of a well system using a CT aligner comprises clamping a first clamp of the CT aligner to the second CT string, the first clamp comprising a first tensioner connector; clamping a second clamp of the CT aligner to the first CT string, the second clamp comprising a second tensioner connector; connecting a CT tensioner between the first tensioner connector and the second tensioner connector, the CT tensioner comprising a tensioner linkage and an actuator; and operating the actuator to gradually reduce a longitudinal length of the tensioner linkage to align a lower end of the second CT string with an upper end of the first CT string. In some embodiments, the method further comprises lowering the upper end of the first CT string into a central passage of an intermediate centralizer of the CT aligner, whereby the intermediate centralizer is initially positioned between the lower end of the second CT string and the upper end of the first CT string. In certain embodiments, the method further comprises adjusting the CT tensioner to align the first CT string with the second CT string.

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

BRIEF DESCRIPTION OF THE DRAWINGS

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

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

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

FIGS. 3-5 are zoomed-in, additional views of the surface assembly of FIG. 2 in accordance with principles disclosed herein;

FIG. 6 is a schematic perspective view of an embodiment of a CT aligner in accordance with principles disclosed herein;

FIG. 7 is a schematic cross-sectional view of an embodiment of an upper clamp of the CT aligner of FIG. 6 in accordance with principles disclosed herein;

FIG. 8 is a schematic perspective view of an embodiment of an intermediate centralizer of the CT aligner of FIG. 6 in accordance with principles disclosed herein;

FIG. 9 is a schematic cross-sectional view of an embodiment of a lower clamp of the CT aligner of FIG. 6 in accordance with principles disclosed herein;

FIG. 10 is a schematic side view of an embodiment of a rigid support arm of the CT aligner of FIG. 6 in accordance with principles disclosed herein;

FIG. 11 is a schematic perspective view of an embodiment of a CT tensioner of the CT aligner of FIG. 6 in accordance with principles disclosed herein;

FIG. 12 is an embodiment of an adjustable support arm of a CT aligner in accordance with principles disclosed herein;

FIGS. 13-17 are zoomed-in, additional views of the surface assembly of FIG. 2 in accordance with principles disclosed herein;

FIG. 18 is a schematic perspective view of another embodiment of a CT aligner in accordance with principles disclosed herein;

FIG. 19 is a schematic perspective view of another embodiment of a CT aligner in accordance with principles disclosed herein; and

FIG. 20 is a schematic perspective view of yet another embodiment of a CT aligner in accordance with principles disclosed herein.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

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

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

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

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

During operation of a CT system, circumstances may arise where it becomes necessary to cut the coiled tubing in order to for example, facilitate fishing operations, connect two or more 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 bottomhole assemblies (BHA). In this instance, when the desired length of CT stinger has been deployed into the wellbore, the coiled tubing will need to be cut, and a longer coiled tubing string attached to the CT stinger to continue the operation.

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, as well as the potential impact of their movement on the coiled tubing during the cutting process, and consequently the safety of rig personnel.

Accordingly, embodiments disclosed herein includes methods and systems for aligning coiled tubing strings at a wellsite to prevent uncontrolled movement of the CT string. Embodiments disclosed herein includes a CT aligner comprising an elongate support arm, an upper clamp, an intermediate centralizer, a lower clamp, and a CT tensioner configured to secure and align the CT string. In some embodiments, the CT aligner may include only an upper clamp clampable to an uphole CT string and a lower clamp clampable to a downhole CT string, the upper and lower clamps being connected together by rigid support arm and/or a CT tensioner. In this manner, loads may be transferred between the uphole and downhole CT strings by the CT aligner during the process of either cutting an initial single CT string into separate uphole and downhole CT strings or in the process of connecting together initially separate uphole and downhole CT strings to form a continuous tubular assembly through which fluid and/or axial forces may be communicated downhole.

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

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

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

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

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

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

In this exemplary embodiment, surface assembly 50 generally includes a CT truck or transporter 100 that may include an accumulator or other equipment such as hydraulic units and safety devices, a CT reel 110 rotatable by a CT motor 112 (each positioned on the CT transporter 100), a CT control center or unit 120 (also positionable on the CT transporter 100) 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 95 for aligning downhole CT string 20 as it is deployed or retrieved, and a crane 90 (shown only partially in FIG. 2); however, in other embodiments, the configuration of surface assembly 50 may vary in other embodiments from that shown in FIG. 2.

To illustrate operational features of CT system 10, surface assembly 50 is shown in FIG. 2 deploying downhole CT string 20 into the wellbore 4. Particularly, during operation of CT system 10, downhole CT string 20 may be unwound from CT reel 110 in response to the operation of CT motor 112. The unwinding from, and winding onto, CT reel 110 of downhole CT string 20 may be performed or assisted by a tubing tensioner (not shown) of CT transporter 100 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 95 extending from injector head 85. The injector head 85 is suspended from a crane 90 such that the crane 90 may be used to control the positioning of injector head 85 relative to wellbore 4. In this manner, crane 90 may align injector head 85 with wellhead 52 and BOP 60 to ensure smooth feeding of downhole CT string 20 into and out of wellbore 4. Additionally, crane 90 may selectably vertically lift the injector head 85 and lubricator 80 from the BOP 60 (i.e., when the lubricator 80 is decoupled from the BOP 60) as desired to expose a segment of the downhole CT string 20 located vertically above BOP 60.

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

A variety of tools may be coupled to the terminal end of downhole CT string 20 for performing various operations in wellbore 4 as previously disclosed. For example, a mill tool may be coupled to the terminal end of downhole CT string 20 for selectably drilling or milling out downhole plugs (e.g., bridge plugs) previously installed in wellbore 4 to permit fluid communication between the toe 5 of wellbore 4 and the terranean surface 3. CT transporter 100 may include or support the CT control unit 120 for transmitting signals to and receiving signals from (e.g., electronic signals and/or data) downhole tools or equipment attached to the terminal end of downhole CT string 20 such as the first downhole CT tool 12 shown in FIG. 1. Additionally, fluids may be pumped between CT transporter 100 and tools attached to the terminal end of downhole CT string 20 via the central passage extending through downhole CT string 20.

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

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

Referring to FIG. 4, another view of the surface assembly 50 of CT system 10 is shown. Particularly, FIG. 4 illustrates lifting of injector head 85 and lubricator 80 vertically upwards away from BOP 60 to access a desired segment of the downhole CT string 20. Particularly, in the configuration of surface assembly 50 shown in FIG. 4, a portion of the downhole CT string 20 extends between a lower end 81 of the lubricator 80 and an upper end 61 of the BOP 60 such that the exposed portion of downhole CT string 20 is directly accessible by rig personnel 72. The segment of the downhole CT string 20 to be accessed may include, for example, a segment of the downhole CT string 20 that needs to be cut after attaching to a BHA, a segment of the downhole CT string 20 that needs to be coupled to another CT string (e.g., uphole CT string 30 shown in FIG. 1), tool (e.g., a BHA 12), or assembly, and a segment of the downhole CT string 20 that needs to be anchored or secured during a jarring/fishing operation. In some embodiments, safety checks are performed to ensure adequate well control and proper functioning of all tools, and associated equipment prior to decoupling the lower end 81 of lubricator 80 from the upper end 61 of BOP 60 and lifting injector head 85 and lubricator 80 therefrom. For example, an inflow test may be performed, whereby the downhole CT string 20 is opened to the atmosphere and observed to ensure there is no fluid flow through the downhole CT string 20. Subsequently, in some embodiments, BOP 60 is closed whereby one or more of BOP rams 62, 64, and 66 are closed around the downhole CT string 20, and a negative or inflow test is again performed to ensure all equipment are functioning as desired.

Referring now to FIG. 5, yet another view of the surface assembly 50 of CT system 10 is shown. Particularly, FIG. 5 illustrates the surface assembly 50 just prior to cutting of the exposed portion of downhole CT string 20 by the rig personnel 72 such as by a handheld saw or other cutting element operated by rig personnel 72. Particularly, in the configuration of surface assembly 50 shown in FIG. 5, an exemplary CT aligner 200 is secured to the desired segment of the downhole CT string 20 to facilitate cutting, aligning, and/or coupling of the downhole CT string 20 to an uphole CT string (e.g., uphole CT string 30), tool (e.g., BHA 12), or assembly as will be disclosed further herein. For instance, once safety tests have been satisfactorily completed, rig personnel 72 may signal the injector head 85 be moved to disengage lubricator 80 from the BOP 60 (e.g., via the operation of crane 90) providing access to the area around the desired segment of the downhole CT string 20 for installing CT aligner 200. With CT aligner 200 secured to the downhole CT string 20, a controlled cut can be made to the downhole CT string 20 while ensuring that the downhole CT string 20, lubricator 80, and injector head 85 are unable to swing uncontrollably as will be disclosed further herein.

As previously described, an alignment tool (e.g., CT aligner 200) may be used to physically support and maintain axial alignment of the downhole CT string 20 and facilitate specific tasks associated with wellbore 4, such as, cutting, aligning, and/or coupling of the downhole CT string 20 to other components of CT system 10. Referring to FIGS. 6 to 11, an exemplary embodiment of a CT aligner 200 for a CT system (e.g., CT system 10 shown in FIG. 1) is shown. CT aligner 200 generally includes an upper clamp 230, a lower clamp 290, an intermediate centralizer 260, a rigid support arm 202, and a CT tensioner 320. Particularly, FIG. 6 is a schematic view of an exemplary CT aligner 200; FIGS. 7 and 9 are cross-sectional views of the upper clamp 230 and the lower clamp 290 respectively; FIG. 8 is a schematic view of the intermediate centralizer 260; FIG. 10 is schematic view illustrating support arm 202; and FIG. 11 is a schematic view of an exemplary CT tensioner 320.

As shown particularly in FIG. 6, CT aligner 200 defines a first or upper longitudinal or central axis 235, a second or lower longitudinal or central axis 295. Upper clamp 230 and intermediate centralizer 260 are both positioned along the upper central axis 235 while lower clamp 290 is positioned along the lower central axis 295 which may be laterally offset and/or disposed at a non-zero angle from the upper central axis 235. The intermediate centralizer 260 positioned between upper clamp 230 and lower clamp 290, and rigid support arm 202 is coupled to both the upper clamp 230 and the intermediate centralizer 260. Additionally, the CT tensioner 320 separately or independently connects between the upper clamp 230 and lower clamp 290 for applying a counteracting tension or force to ensure alignment of the downhole CT string 20; however, in other embodiments, the configuration of CT aligner 200 may vary from that shown in FIG. 6.

The support arm 202 is generally defined by an elongate body and extends from an upper end 204 to a longitudinally opposed lower end 206. In this embodiment, support arm 202 is coupled to upper clamp 230 at the upper end 204 thereof via an upper clamp connector 212 that also couples to a generally U-shaped upper tensioner connector 208. Additionally, support arm 202 couples to the intermediate centralizer 260 at the lower end 206 thereof via an intermediate centralizer connector 214 that also couples to a generally U-shaped intermediate tensioner connector 210. In some embodiments, support arm 202 may comprise a single rigid member formed to a desired longitudinal (e.g., extending along upper central axis 235) length as shown in FIG. 10 depending on the requirements of the given application. In other embodiments, support arm 202 may comprise a plurality of separate rigid members or pieces coupled together by welding, fasteners, or other suitable means.

As an example, and referring briefly to FIG. 12, illustrates an exemplary adjustable support arm 400. In this exemplary embodiment, adjustable support arm 400 includes a locking member 402, a first or outer arm 404 and a second arm that is slidably coupled to the outer arm 404 such that a longitudinal length 405 of the support arm 400 may be adjusted. Particularly, in this exemplary embodiment, arms 404 and 406 are coupled together telescopically whereby outer arm 404 defines a hollow section that forms the exterior structure of adjustable support arm 400, and an inner arm 406 that is configured to telescopically and slidably engage with an interior of the outer arm 404. In this manner, the longitudinal length of adjustable support arm 400 is adjustable to permit a user to adjust the spacing between, for example, upper clamp 230 and intermediate centralizer 260 along a length of the adjustable support arm 400.

Additionally, the locking member 402 (e.g., a detent, pin, or other translatable member) is translatable between an unlocked position permitting relative movement between arms 404 and 406 along a longitudinal axis of the adjustable support arm 400, and a locked position restricting relative movement between arms 404 and 406 along the longitudinal axis of adjustable support arm 400. In this manner, the longitudinal length of adjustable support arm 400 may be adjusted with locking member 402 in the unlocked position. The arms 404 and 406 may subsequently be locked rigidly together by translating locking member 402 from the unlocked position to the locked position to lock the longitudinal length of adjustable support arm 400.

Referring again to FIGS. 6-11, as described above, support arm 202 is coupled to upper clamp 230 at the upper end 204 thereof. The upper clamp 230 includes a generally cylindrical body 231 extending from an upper end 232 of the upper clamp 230 to a lower end 234 of the upper clamp 230 and a central passage 236 extending along upper central axis 235 of CT aligner 200 between ends 232 and 234 and configured to receive a first or upper segment of the downhole CT string 20. Additionally, upper clamp 230 comprises an additional pair of upper clamp connectors 238 coupled between body 231 and support arm 202. Upper clamp connectors 212 and 238 are each spaced along the longitudinal length of body 231 with upper clamp connector 212 located proximal the upper end 232 thereof and one of the upper clamp connectors 238 located proximal to the lower end 234 thereof. Upper clamp connectors 212 and 238 cooperate to restrict upper clamp 230 from pivoting or rotating (e.g., about a lateral axis extending out of the page in FIG. 6) relative to the support arm 202 during operation of CT aligner 200 and instead maintain upper central axis 235 parallel a longitudinal axis of the support arm 202.

In some embodiments, inner diameter of the inner surface of body 231 defining the central passage of upper clamp 230 is adjustable to allow upper clamp 230 to impart a radially inwards directed clamping force (that is generally equal in magnitude extending around the circumference of the central passage 236) to a CT string or other cylindrical member extending through central passage 236. As shown particularly in FIG. 7, the body 231 of upper clamp 230 is defined by a pair of C-rings 233 and a plurality of clamping actuators 237 coupled between the C-rings 233. Clamping actuators 237 may be decoupled from one of or both of the C-rings 233 to permit the pair of C-rings 233 to be entirely separated, providing access and flexibility in securing and/or disengaging upper clamp 230 from the downhole CT string 20 and/or associated BHA.

Upon being positioned around the downhole CT string 20 (or another cylindrical member extending through central passage 236), clamping actuators 237 may be operated to gradually reduce the inner diameter of central passage 236 until a desired clamping force is applied by upper clamp 230 to the downhole CT string 20 thereby locking upper clamp 230 to downhole CT string 20. In this exemplary embodiment, clamping actuators 237 comprise threaded fasteners that may be manually operated to adjust the inner diameter of central passage 236; alternatively, the configuration of clamping actuators 237 may vary in other embodiments. In some embodiments, upper clamp 230 is manufactured from lightweight material (e.g., aluminum). In this manner, when the upper clamp 230 is installed, it secures the downhole CT string 20 firmly without inducing a dent/mark or damage to the downhole CT string 20.

In some embodiments, a minimum inner diameter of the upper clamp 230 is further adjustable to accommodate CT strings or other cylindrical members having outer diameters that vary in magnitude. For example, and referring briefly to FIG. 13, another embodiment of a clamp 420 for a CT aligner is shown. For instance, clamp 420 may replace the upper clamp 230 and/or lower clamp 290 of CT aligner 200. Clamp 420 comprises a generally cylindrical body 421 defining a central passage 422. Additionally, the body 421 of clamp 420 is defined by or formed from a pair of opposing C-rings 423 connectable together by a pair of clamping actuators 237 coupled therebetween.

In this exemplary embodiment, clamp 420 also includes a pair of C-ring adapters 426 releasably connectable to inner surfaces of C-rings 423 thereof. Particularly, C-ring adapters 426 have a minimum inner diameter that is less than the minimum inner diameter of C-rings 423 to permit clamp 420 to clamp against cylindrical members having relatively smaller outer diameters. For example, a CT aligner comprising clamp 420 may include a plurality or set of C-ring adapters 426 having different minimum diameters. The C-ring adapters 426 of the set having a minimum inner diameter suitable for clamping against a CT string or cylindrical member of the given application may be selected and coupled to C-rings 423 of clamp 420. Further, by employing clamps 420, a CT aligner may grip or clamp against CT strings or cylindrical members having different outer diameters. For instance, an upper clamp 420 may include a first pair of C-ring adapters 426 defining a first minimum inner diameter while a lower clamp 420 of the CT aligner may include a second pair of C-ring adapters 426 defining a second minimum inner diameter that is different from (e.g., greater or less than) the first minimum inner diameter.

Referring back to FIGS. 6-11, the intermediate centralizer 260 of CT aligner 200 is coupled to support arm 202 at the lower end 206 thereof. The intermediate centralizer 260 includes a generally cylindrical body 261 extending from an upper end 262 of intermediate centralizer 260 to a lower end 264 of intermediate centralizer 260, and a central passage 266 extending along the upper central axis 235 of CT aligner 200 and configured to receive a second or intermediate segment of the downhole CT string 20. Additionally, intermediate centralizer 260 comprises an additional pair of intermediate centralizer connectors 240 coupled between body 261 and support arm 202. Connectors 214 and 240 are each spaced along the longitudinal length of body 261 to restrict intermediate centralizer 260 from pivoting or rotating (e.g., about a lateral axis extending out of the page in FIG. 6) relative to the support arm 202 during operation of CT aligner 200.

In some embodiments, central passage 266 of intermediate centralizer 260 is defined by a generally frustoconical or tapered inner diameter 270. In this instance, inner diameter 270 increases gradually from a minimum inner diameter 270 at the upper end 262 of body 261 to a maximum inner diameter 270 at the lower end 264 of body 261. The minimum inner diameter 270 of central passage 266 may be slightly greater than the outer diameter of the downhole CT string 20 to permit downhole CT string 20 to slide axially through central passage 266 during operation of CT aligner 200. Thus, unlike upper clamp 230 described above, intermediate centralizer 260 may not be configured to apply a radially inwards directed clamping force to downhole CT string 20. It should be noted that central passage 266 may also comprise other shapes and/or dimensions as would be appreciated by one of ordinary knowledge and skill in the arts. For instance, in some embodiments, central passage 266 may be generally cylindrical rather than frustoconical in shape.

In some embodiments, the body 261 of intermediate centralizer 260 is defined or formed by a pair of opposing C-rings that may be decoupled to facilitate positioning intermediate centralizer 260 around downhole CT string 20. Additionally, and as shown particularly in FIG. 8, intermediate centralizer 260 further comprises alignment members 268 for aligning a central axis of downhole CT string 20 (or other cylindrical member received in central passage 266) with a central axis of central passage 266 (e.g., upper central axis 235). Alignment members 268 may be translated radially (e.g., via rotating alignment members 268 through internally threaded receptacles of the body 261) relative to body 261 for securing and/or disengaging the intermediate centralizer 260 from the downhole CT string 20 and/or associated BHA. Alignment members 268 are circumferentially spaced (e.g., spaced ninety degrees) about central passage 266 whereby alignment members 268 may be translated in concert to adjust the position of a central axis of downhole CT string 20 relative to the central axis of central passage 266. In this manner, upper clamp 230 together with intermediate centralizer 260 secure the downhole CT string 20 to facilitate cutting of the downhole CT string 20.

The lower clamp 290 of CT aligner 200 comprises a generally cylindrical body 291 extending from an upper end 292 of lower clamp 290 to a lower end 294 of lower clamp 290, and a central passage 296 extending along lower central axis 295 of lower clamp 290 that may be offset or located at an angle from the upper central axis 235 of CT aligner 200. The central passage 296 of lower clamp 290 is defined by an inner diameter that is adjustable to allow lower clamp 290 to impart a radially inwards directed clamping force (that is generally equal in magnitude extending around the circumference of the central passage 296) to a CT string or other cylindrical member (e.g., BHA components) extending through central passage 296. Clamping the lower clamp 290 to the downhole CT string 20, for example, facilitate aligning of BHA components and/or the downhole CT string 20 with another CT string (e.g., uphole CT string 30), tool (e.g., a BHA 12), or assembly that is clamped to the upper clamp 230 of CT aligner 200. Additionally, lower clamp 290 includes a lower clamp connector 302 that is attached to a lower clamp mount 298, which extends from lower clamp 290 to a generally U-shaped lower tensioner connector 300.

As shown particularly in FIG. 9, the body 291 of lower clamp 290 is defined by a pair of opposing C-rings 293. Additionally, lower clamp 290 further comprises a plurality of clamping actuators 297 coupled between the pair of C-rings 293 for securing and/or disengaging lower clamp 290 from the downhole CT string 20 and/or associated BHA. In certain embodiments, clamping actuators 297 are similar in configuration and similarly operable as the clamping actuators 237 described above. In some embodiments, lower clamp 290 is manufactured from lightweight material. In this manner, when the lower clamp 290 is installed, it secures the downhole CT string 20 firmly without inducing a dent/mark or damage on the downhole CT string 20.

As shown particularly in FIG. 11, CT tensioner 320 includes a flexible tensioner linkage 322 (e.g., a chain or other flexible member) extending and coupled between a pair of generally C-shaped hooks or connectors 332, 334 configured to engage with the upper tensioner connector 208 and lower tensioner connector 300, respectively, and an actuator 336 for adjusting (e.g., increasing or decreasing) the longitudinal length of tensioner linkage 322 extending between connectors 332 and 334. While CT tensioner 320 comprises a mechanical actuator 336 in this exemplary embodiment, CT tensioner 320 may also comprise hydraulic, pneumatic, electric and other types of actuators. In this embodiment, CT tensioner 320 together with lower clamp 290 facilitate aligning of the downhole CT string 20 and uphole CT string 30/BHA 12 for coupling as will be disclosed further herein. For instance, by operating (e.g., manually operating) mechanical actuator 336 to reduce the longitudinal length of tensioner linkage 322, the central axes 235 and 295 of CT aligner 200 may be brought towards or into alignment with one another.

As previously described, once a desired length of CT stinger has been run into wellbore 4, downhole CT string 20 may be cut whereby the uphole end of downhole CT string 20 may be attached to the longer CT string (e.g., uphole CT string 30). Referring to FIGS. 14 and 15, during installation of the CT aligner 200, upper clamp 230 and intermediate centralizer 260 are secured to the downhole CT string 20 across an area surrounding the desired segment of the downhole CT string 20 to be cut, whereby a first or upper segment 510 of the downhole CT string 20 is received within central passage 236 of upper clamp 230 through upper split 704 and a second or lower segment 520 of the downhole CT string 20 is received within central passage 266 of intermediate centralizer 260. In some instances, the location of the upper segment 510 and lower segment 520 may be predetermined based on the desired location of the cut.

With upper clamp 230 clamped to upper segment 510 and intermediate centralizer 260 slidably receiving lower segment 520 in the central passage 266 thereof, a controlled cut (indicated by arrow S in FIG. 14) is made to the segment of downhole CT string 20 located between segments 510 and 520 using for example, a shearing, milling, or other cutting tool operated by rig personnel 72. In this manner, residual lateral stresses within segments 510 and 520 of downhole CT string 20 (indicated by arrows A and B in FIG. 12) may be physically resisted by reactive forces communicated along the support arm 202 of CT aligner 200. In this manner, even though residual stresses A and B may urge segments 510 and 520 to pivot relative each other, this motion is resisted by CT aligner 200 such that the central axes of segments 510 and 520 remain roughly aligned with one another.

As shown particularly in FIG. 15, after the cut of downhole CT string 20 is completed, the injector head 85 may be lifted to lift the upper segment 510 of downhole CT string 20 vertically upwards and away from the lower segment 520 thereof until the lower end 264 of intermediate centralizer 260 clears a terminal end (e.g., uphole end 23) of the lower segment 520 of downhole CT string 20 vertically clears the upper end 262 of intermediate centralizer 260. The inner diameter 270 of the central passage 266 of intermediate centralizer 260 is tapered in such a manner that a central axis 515 of upper segment 510 gradually angularly misaligns from a central axis 525 of lower segment 520 as the upper segment 510 is gradually lifted from the lower segment 520. In this manner, once the orientation of the downhole CT string 20 is established, rig personnel 72 can move away from the swing path or be removed completely from service platform 70 so as to not come into contact with the upper segment 520. In other words, given that angular misalignment between segments 510 and 520 occurs only gradually prior to the release of CT aligner from lower segment 520, rig personnel 72 may anticipate the direction which upper segment 520 will travel or swing once the lower end 264 of intermediate centralizer 260 clears the terminal end of the lower segment 520.

Following cutting of the downhole CT string 20, CT aligner may again be utilized for coupling the downhole CT string 20 (or another cylindrical member connected therewith such as a BHA 12) to a second CT string such as uphole CT string 30 in an example. For instance, and referring now to FIGS. 16-18, an example illustrating aligning of the downhole CT string 20 with uphole CT string 30 is shown. As shown particularly in FIG. 16, during aligning of the uphole CT string 30 with the downhole CT string 20, upper clamp 230 of CT aligner 200 is initially clamped to a lower segment 610 of the uphole CT string 30 while the lower clamp 290 of CT aligner 200 is clamped to the lower segment 520 of the downhole CT string 20. In this configuration, intermediate centralizer 260 is clear of and disengaged from the downhole CT string 20 such that intermediate centralizer 260 is positioned between the uphole end 23 of downhole CT string 20 and the downhole end 31 of uphole CT string 30.

Additionally, a portion of tensioner linkage 322 of the CT tensioner 320 of CT aligner 200 is received in intermediate tensioner connector 210, while the upper connector 332 and lower connector 334 are received in upper tensioner connector 208 and lower tensioner connector 300, respectively. With CT tensioner 320 connected between upper clamp 230 and lower clamp 290, mechanical actuator 336 may be operated (e.g., by rig personnel 72) to gradually reduce the longitudinal length of tensioner linkage 322 whereby the CT aligner gradually forces the uphole CT string 30 towards or into alignment with the downhole CT string 20, as shown particularly in FIG. 17.

As shown particularly in FIG. 18, when the uphole CT string 30 is within a few inches of the downhole CT string 20, the lower end of the downhole CT string 20 is lowered into central passage 266 of intermediate centralizer 260 using CT tensioner 320 to bring CT strings 20 and 30 into general alignment. Particularly, operating mechanical actuator 336 of CT tensioner 320 to increase the tension applied to tensioner linkage 322 allows the lower end of the uphole CT string 30 to enter the central passage 266 of intermediate centralizer 260. Once the downhole end 31 of uphole CT string 30 is received within central passage 266, and the intermediate centralizer 260 is fully engaged, the uphole CT string 30 may be coupled to the downhole CT string 20 using couplers, fasteners, or other suitable means whereby uphole CT string 30 may be deployed into a wellbore in conjunction with downhole CT string 20. Thus, while CT tensioner 320 may generally align CT strings 20 and 30, intermediate centralizer 260 may more precisely align CT strings 20 and 30. For instance, the alignment members 268 of intermediate centralizer 260 may be operated to precisely align CT strings 20 and 30 whereby a secure connection may be formed between CT strings 20 and 30.

In some instances, it may be desirable to apply additional force to CT strings 20 and 30 to bring CT strings 20 and 30 into general alignment whereby the downhole end 31 of uphole CT string 30 may be successfully stabbed or slid into and through the central passage 266 of the intermediate centralizer 260 of CT aligner 200. For instance, in some instances, a substantial amount of tension may need be applied to the tensioner linkage 322 of CT tensioner 320 to bring CT strings 20 and 30 into general alignment, which require the application of significant force to mechanical actuator 336 of CT tensioner 320.

Referring to FIG. 19, another embodiment of a CT aligner 500 is shown. CT aligner 500 includes features in common with CT aligner 200 shown in FIGS. 5-18, and shared features are labeled similarly. Particularly, CT aligner 500 is similar to CT aligner 200 except that CT aligner 500 further includes a leverage arm 502 for applying additional lateral force between clamps 230 and 290 to facilitate the general alignment of CT strings 20 and 30 or other cylindrical members to which clamps 230 and 290 are attached. Leverage arm 502 extends longitudinally between a first or proximal end 504 and a second or distal end 506. In this exemplary embodiment, distal end 506 of leverage arm 502 is pointed to assist in inserting distal end 506 into and through lower connector 334. For example, rig personnel 72 may grasp the proximal end 504 of leverage arm 502 to apply torque thereto with the leverage arm 502 forming a fulcrum at the distal end 506 thereof which applies a lateral force to the lower clamp 290.

The substantial length of the leverage arm 502 and concomitant length of the fulcrum defined thereby permits rig personnel 72 to apply additional lateral force as needed to CT strings 20 and 30 to bring CT strings 20 and 30 into general alignment whereby the distal end 506 of leverage arm 502 may be stabbed or inserted through the lower connector 334. Additionally, with the distal end 506 of leverage arm 502 inserted through lower connector 334, leverage arm 502 serves to lock CT strings 20 and 30 into general alignment such that rig personnel 72 is free to operate alignment members 268 of intermediate centralizer 260 to more precisely align CT strings 20 and 30 to permit the connection thereof.

In some embodiments, CT aligners disclosed herein may not include an intermediate centralizer and instead may only include upper and lower clamps connected together by a rigid support arm and/or a CT tensioner. As an example, and referring to FIG. 20, another embodiment of a CT aligner 600 is shown. CT aligner 600 includes features in common with CT aligner 200/500 shown in FIGS. 5-19, and shared features are labeled similarly. Particularly, CT aligner 600 is similar to CT aligner 200/500 except that CT aligner 600 does not carry intermediate centralizer 260, and instead, upper clamp 230 and lower clamp 290 are connected directly together by rigid support arm 202.

In this exemplary embodiment, CT aligner includes the CT tensioner 320 for applying lateral force between clamps 230 and 290 to facilitate the general alignment of CT strings 20 and 30 or other cylindrical members to which clamps 230 and 290 are attached. For example, during an alignment operation, the upper connector 332 and lower connector 334 are received in upper tensioner connector 208 and lower tensioner connector 300, respectively. With CT tensioner 320 connected between upper clamp 230 and lower clamp 290, mechanical actuator 336 may be operated (e.g., by rig personnel 72) to gradually reduce the longitudinal length of tensioner linkage 322 whereby the CT aligner gradually forces the uphole CT string 30 towards or into alignment with the downhole CT string 20, as shown particularly in FIG. 20.

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.