Abstract:
A coiled tubing connection system is used in a well. A connector having an engagement end is used to couple a wellbore device to the end of a coiled tubing. The connector is spoolable, and the engagement end comprises engagement features that facilitate formation of a connection that is dependable and less susceptible to separation.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
       [0001]    This application claims priority to and is a Continuation in Part of U.S. patent application Ser. No. 11/466,335, filed on Aug. 22, 2006, which is incorporated herein by reference. 
     
    
     BACKGROUND 
       [0002]    In many wellbore applications, connections are formed between coiled tubing and wellbore tools or other components such as subsequent sections of coiled tubing. Often, the coiled tubing connector must form a pressure tight seal with the coiled tubing. The connector end often is threaded for connecting the wellbore tool to the coiled tubing. Coiled tubing connectors can be designed to attach and seal to either the inside or the outside of the coiled tubing. 
         [0003]    Examples of internal connectors include roll-on connectors, grapple connectors and dimple connectors. Roll-on connectors align circumferential depressions in the coiled tubing with preformed circumferential grooves in the connector to secure the connector to the coiled tubing in an axial direction. Grapple connectors utilize internal slips that engage the inside of the coiled tubing to retain the coiled tubing in an axial direction. Dimple connectors rely on a dimpling device to form dimples in the coiled tubing. The dimples are aligned with preformed pockets in the connector to secure the connector to the coiled tubing both axially and torsionally. Elastomeric seals can be used to provide pressure integrity between the connector and the coiled tubing. However, internal connectors constrict the flow area through the connector which can limit downhole tool operations. 
         [0004]    Examples of external connectors include dimple connectors, grapple connectors and threaded connectors. This type of dimple connector relies on a dimpling device to create dimples in the coiled tubing. The dimple connector comprises set screws that are aligned with the dimples in the coiled tubing and threaded into the dimples. The set screws provide both an axial and a torsional connectivity between the connector and the coiled tubing. External grapple connectors use external slips to engage the outside of the coiled tubing for providing axial connectivity to the tubing. External threaded connectors rely on a standard pipe thread which engages a corresponding standard external pipe thread on the end of the coiled tubing. The threaded connection provides axial connectivity, but the technique has had limited success due to the normal oval shape of the coiled tubing which limits the capability of forming a good seal between the connector and the coiled tubing. External connectors, in general, are problematic in many applications because such connectors cannot pass through a coiled tubing injector or stripper. This limitation requires that external connectors be attached to the coiled tubing after the tubing is installed in the injector. 
       SUMMARY 
       [0005]    The present invention comprises a system and method for forming coiled tubing connections, such as connections between coiled tubing and downhole tools. A connector is used to couple the coiled tubing and a downhole tool by forming a secure connection with an end of the coiled tubing. The connector comprises a unique engagement end having engagement features that enable a secure, rigorous connection without limiting the ability of the connector to pass through a coiled tubing injector. The connector design also enables maximization of the flow area through the connector. In some embodiments, additional retention mechanisms can be used to prevent inadvertent separation. Some embodiments of the present invention also include a wired coiled tubing assembly including a cable termination head for receiving electrical and/or fiber optic terminations that is configured in a manner to allow the entire assembly to pass through a coiled tubing injector. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS  
         [0006]    Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and: 
           [0007]      FIG. 1  is a front elevation view of a coiled tubing connection system deployed in a wellbore, according to one embodiment of the present invention; 
           [0008]      FIG. 2  is an orthogonal view of a bayonet style connector that can be used in the system illustrated in  FIG. 1 , according to an embodiment of the present invention; 
           [0009]      FIG. 3  is another view of the connector illustrated in  FIG. 2 , according to an embodiment of the present invention; 
           [0010]      FIG. 4  is an orthogonal view of the connector coupled to an end of coiled tubing that has been formed with protrusions to engage the connector, according to an embodiment of the present invention; 
           [0011]      FIG. 5  is an alternate embodiment of the connector illustrated in  FIG. 2 , according to another embodiment of the present invention; 
           [0012]      FIG. 6  is a cross-sectional view of an alternate embodiment of the connector threadably coupled with a coiled tubing end, according to an embodiment of the present invention; 
           [0013]      FIG. 7  is a cross-sectional view of a coiled tubing end that has been expanded and then threaded internally for engagement with the connector, according to an embodiment of the present invention; 
           [0014]      FIG. 8  is a view similar to that of  FIG. 7  but showing a connector engaged with the coiled tubing end, according to an embodiment of the present invention; 
           [0015]      FIG. 9  is a cross-sectional view of a coiled tubing end that has been swaged radially inward and threaded for engagement with the connector, according to an embodiment of the present invention; 
           [0016]      FIG. 10  is a view similar to that of  FIG. 9  but showing a connector engaged with the coiled tubing end, according to an embodiment of the present invention; 
           [0017]      FIG. 11  is a cross-sectional view of a coiled tubing end that has been swaged radially and threaded externally for engagement with the connector, according to an embodiment of the present invention; 
           [0018]      FIG. 12  is a view similar to that of  FIG. 11  but showing the connector engaged with the coiled tubing end, according to an embodiment of the present invention; 
           [0019]      FIG. 13  is a flow chart illustrating a methodology for engaging a threaded connector with coiled tubing at a well site, according to an embodiment of the present invention; 
           [0020]      FIG. 14  is a flow chart illustrating a more detailed methodology for engaging a threaded connector with coiled tubing at a well site, according to an embodiment of the present invention; 
           [0021]      FIG. 15  is an orthogonal view of a retention system for rotationally retaining a connector with respect to coiled tubing, according to an embodiment of the present invention; 
           [0022]      FIG. 16  is another embodiment of a retention system for rotationally retaining a connector with respect to coiled tubing, according to an embodiment of the present invention; 
           [0023]      FIG. 17  is another embodiment of a retention system for rotationally retaining a connector with respect to coiled tubing, according to an embodiment of the present invention; 
           [0024]      FIG. 18  is a view similar to that of  FIG. 17  but showing the retention mechanism in a locked position, according to an embodiment of the present invention; 
           [0025]      FIG. 19  is another embodiment of a retention system for rotationally retaining a connector with respect to coiled tubing, according to an embodiment of the present invention; 
           [0026]      FIG. 20  is a view similar to that of  FIG. 19  but showing the retention mechanism in a locked position, according to an embodiment of the present invention; 
           [0027]      FIG. 21  is another embodiment of a retention device for rotationally retaining a connector with respect to coiled tubing, according to an embodiment of the present invention; 
           [0028]      FIG. 22  illustrates the retention device of  FIG. 21  incorporated into a retention system between a coiled tubing end and a wellbore component, according to an embodiment of the present invention; 
           [0029]      FIG. 23  illustrates another embodiment of a retention device, according to an embodiment of the present invention; 
           [0030]      FIG. 24  illustrates a fixture used to form depressions in the coiled tubing for engagement with devices, such as those illustrated in  FIGS. 2 and 5 , according to an embodiment of the present invention; 
           [0031]      FIG. 25  illustrates an assembly for conveying a well tool into a wellbore; 
           [0032]      FIG. 26  illustrates a wired coiled tubing assembly according to one embodiment of the present invention; and 
           [0033]      FIG. 27  illustrates a method of conveying a wired coiled tubing assembly into a wellbore according to one embodiment of the present invention. 
       
    
    
     DETAILED DESCRIPTION  
       [0034]    In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those of ordinary skill in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. 
         [0035]    The present invention relates to a system and methodology for forming coiled tubing connections. The coiled tubing connections typically are formed between coiled tubing and a well tool for use downhole, however the coiled tubing connections can be formed between coiled tubing and other components, such as subsequent sections of coiled tubing. The coiled tubing connections are formed with a connector that is of similar outside diameter to the coiled tubing and uniquely designed to provide a secure, rigorous connection without limiting the ability of the connector to pass through a coiled tubing injector. Additionally, some coiled tubing connection embodiments utilize a retention mechanism to further guard against inadvertent separation of the coiled tubing connection. 
         [0036]    Referring generally to  FIG. 1 , a well system  30  is illustrated according to one embodiment of the present invention. The well system  30  comprises, for example, a well intervention system  32  deployed for use in a well  34  having a wellbore  36  drilled into a reservoir  38  containing desirable fluids, such as hydrocarbon based fluids. In many applications, wellbore  36  is lined with a wellbore casing  40  having perforations  42  through which fluids can flow between wellbore  36  and the reservoir  38 . Well intervention system  32  can be formed in a variety of configurations with a variety of components depending on the specific well intervention application for which it is used. By way of example, well intervention system  32  comprises a well tool  44  located downhole and coupled to a coiled tubing  46  by a connector  48 . Connector  48  is securely attached to coiled tubing  46 . The connection is sized to pass through a coiled tubing injector when rigging up to the well. The tool  44  is securely attached to the connector  48  after the connector is installed through the injector and well intervention system  32  is run downhole. 
         [0037]    One embodiment of connector  48  is illustrated in  FIGS. 2 and 3 . In this embodiment, connector  48  comprises a midsection  50 , a first engagement end or region  52  extending axially from the midsection  50 , and a second engagement end or region  54  extending from midsection  50  in a direction generally opposite first engagement region  52 . First engagement region  52  is designed for engagement with coiled tubing  46 , and second engagement region  54  is designed for engagement with a component, such as well tool  44 . As illustrated, midsection  50  may be radially expanded, i.e. comprise a greater diameter, relative to engagement regions  52  and  54 . 
         [0038]    The first engagement region  52  is sized for insertion into coiled tubing  46  and comprises one or more bayonet slots  56  recessed radially inwardly into engagement region  52 . This form of engagement region can be referred to as a breech lock engagement region. Each bayonet slot comprises a generally longitudinal slot portion  58  intersected by one or more generally transverse slot portions  60 . Transverse slot portions  60  may be substantially linear, curved, J-shaped, helical, or formed in other suitable shapes. Additionally, one or more seals  62 , such as elastomeric seals, may be mounted on engagement region  52  in a location placing the seals  62  between the engagement region  52  and coiled tubing  46  when engagement region  52  is inserted into coiled tubing  46 . Seals  62  may comprise  0 -rings, poly-pak seals or other seals able to form a sealed region between the coiled tubing  46  and connector  48 . Connector  48  further comprises a hollow interior  64  that maximizes flow area for conducting well fluids therethrough, as best illustrated in  FIG. 3 . 
         [0039]    The second engagement region  54  may have a variety of shapes and configurations depending on the specific type of well tool  44  or other component to be connected to coiled tubing  46  via connector  48 . By way of example, engagement region  54  is a tubular threaded end sized for insertion into and threaded engagement with a corresponding receptacle of the component, e.g. well tool  44 . One or more seals  66 , such as O-rings, poly-pak seals or other suitable seals can be mounted around the engagement region  54 , as illustrated, to form a fluid seal with well tool  44 . 
         [0040]    The coiled tubing  46  is formed with one or more protrusions  68  that are sized and spaced to engage bayonet slots  56 , as further illustrated in  FIG. 4 . Protrusions  68  extend radially inward into the interior of coiled tubing  46  and may be formed with pins, bolts, weldments, externally formed depressions or other suitable elements that protrude inwardly. In the embodiment illustrated, protrusions  68  are formed by applying localized pressure at selected locations along the exterior of coiled tubing  46  to create depressions that extended inwardly into the interior of coiled tubing  46 . By way of example, the depressions can be formed in coiled tubing  46  with a screw type forming tool (see  FIG. 24 ). Additionally, a depression forming mandrel can be placed inside the coiled tubing while the depressions are formed to accurately control the final shape of the protrusions  68  extending into the interior of the coiled tubing  46 . In other applications, however, the depressions can be formed in the tubing without an inner mandrel or they can be formed while the coiled tubing is positioned directly on the connector  48 . Regardless of the method of formation, the protrusions  68  are located such that longitudinal slot portions  58  of bayonet slots  56  can be aligned with the protrusions. The protrusions  68  are then moved along longitudinal slot portions  58  as engagement region  52  moves into the interior of coiled tubing  46 . Once connector  48  is axially inserted, the connector  48  and coiled tubing  46  are rotationally twisted relative to each other to move the plurality of protrusions into the generally transverse slot portions  60 . 
         [0041]    After the coiled tubing  46  and connector  48  are joined through the relative axial and rotational movement, a retention mechanism  70  may be used to rotationally secure the coiled tubing protrusions  68  within their corresponding bayonet slots  56 . One example of retention mechanism  70  comprises an interference mechanism, e.g. simple detents  72  (see  FIG. 2 ), that hold protrusions  68  in transverse slot portions  60  once protrusions  68  are inserted longitudinally along longitudinal slot portions  58  and rotated into transverse slot portion  60 . Another example of retention mechanism  70  (see  FIG. 4 ) comprises a snap ring, e.g. a C-ring, member  74  that may be positioned within a corresponding slot  76  located, for example, circumferentially along midsection  50  of connector  48 . C-ring member  74  further comprises a transverse pin  78  that is positioned in corresponding recesses  80 ,  82  of connector  48  and coiled tubing  46 , respectively, when C-ring member  74  is pressed into slot  76 . A variety of other retention mechanisms  70  also can be used, some of which are discussed in greater detail below. 
         [0042]    In the embodiment illustrated in  FIGS. 2-4 , each bayonet slot  56  is illustrated as having two transverse slot portions  60  for receiving corresponding pairs of protrusions  68 . However, the bayonet slots  56  can be designed in other configurations with different numbers of longitudinal slot portions  58  and a different numbers of transverse slot portions  60  associated with each longitudinal slot portion. As illustrated in  FIG. 5 , for example, each longitudinal slot portion  58  is intersected by four transverse slot portions  60 . Additionally, each transverse slot portion  60  has a generally J-shape as opposed to the linear shape illustrated best in  FIG. 2 . The embodiment illustrated in  FIG. 5  provides one example of other potential bayonet slot configurations that can be used in coupling connector  48  with coiled tubing  46 . 
         [0043]    As shown in  FIG. 4 , when engagement end  52  of connector  48  is engaged with coiled tubing  46 , an outer diameter  51  of the coiled tubing  46  is substantially continuous with an outer diameter  53  of the connector  48 . That is, the outer diameters  51 , 53  of the coiled tubing  46  and the connector  46  are substantially equal or flush at the interface of the coiled tubing  46  and the connector  46 . 
         [0044]    In another embodiment, engagement region  52  of connector  48  comprises a threaded portion  84  having threads  86  for engaging a corresponding coiled tubing threaded portion  88  having threads  90 , as illustrated in  FIG. 6 . In the embodiment illustrated, threads  86  are formed externally on engagement region  52  of connector  48 , and the corresponding threads  90  are formed on the interior end of coiled tubing  46 . The threads  86  and  90  are designed to absorb substantial axial loading. In some embodiments, an additional seal  92 , such as an elastomeric seal, also may be deployed between engagement region  52  of connector  48  and the surrounding coiled tubing  46 . Examples of seals  92  include O-ring seals, poly-pak seals or other seals able to form a seal between the coiled tubing  46  and connector  48 . The seal area on either side of the elastomeric seal  92  is designed to form a metal to metal seal. In addition, threads that form a metal to metal seal can be used. Regardless, the threads also are selected such that they may be formed at the well site as opposed to being pre-manufactured in a factory environment. Examples of suitable threads include locking tapered threads, such as the Hydril 511 thread, the Tapered Stub Acme thread, the Tapered Buttress thread, and certain straight threads. The interference of the threads also can be designed such that the threads are sacrificial threads. In other words, once connector  48  and coiled tubing  46  are threaded together, the threads are plastically deformed and typically unusable for any subsequent connections, i.e. sacrificed, and the connector cannot be released from the coiled tubing. 
         [0045]    The connectors illustrated herein enable preparation of the coiled tubing and formation of rigorous, secure connections while at the well site. Whether the connector utilizes bayonet slots or threads, the connection with coiled tubing  46  can be improved by preparing the coiled tubing end for connection. For example, the strength of the connection and the ability to form a seal at the connection can be improved by rounding the connection end of the coiled tubing through, for example, a swaging process performed at the well site. As illustrated in  FIGS. 7-12 , the coiled tubing  46  can be prepared with an internal swage or an external swage. 
         [0046]    Referring first to  FIGS. 7 and 8 , an end  94  of coiled tubing  46  is illustrated after being subjected to an internal swage that creates a swage area  96 . Swage area  96  results from expanding the coiled tubing  46  at end  94  to a desired, e.g. maximum, outside diameter condition. The coiled tubing end  94  is caused to yield during swaging such that end  94  is near round and the outside diameter is formed to the desired, predetermined diameter. The interior of end  94  can then be threaded with threads  90  for engagement with connector  48 , as illustrated in  FIG. 8 . In addition to rounding and preparing end  94  for a secure and sealing engagement with connector  48 , the internal swaging can be used to maximize the flow path through connector  48 . Furthermore, the swaging enables a single size connector  48  to be joined with coiled tubing sections having a given outside diameter but different tubing thicknesses. An external rounding fixture also can be used to round the coiled tubing for threading. 
         [0047]    Alternatively, the coiled tubing end  94  can be prepared via external swaging in which, for example, an external swage is used to yield the coiled tubing in a radially inward direction. In this embodiment, the coiled tubing  46  can be yielded back to nominal outside diameter dimensions. As illustrated in  FIGS. 9 and 10 , the external swaging creates a swage area  98  that is yielded inwardly and rounded for engagement with connector  48 . As with the previous embodiment, threads  90  can be formed along the interior of swaged end  94  for a rigorous and sealing engagement with connector  48 , as best illustrated in  FIG. 10 . In another alternative, swage area  98  can be created, and threads  90  can be formed on the rounded exterior end of coiled tubing  46 , as illustrated in  FIGS. 11 and 12 . In this embodiment, threads  86  of connector  48  are formed on an interior of engagement region  52 , as best illustrated in  FIG. 12 . 
         [0048]    The methodology involved in rounding and otherwise preparing the coiled tubing for attachment to connector  48  enables field preparation of the coiled tubing at the well site. An example of one methodology for forming connections at a well site can be described with reference to the flowchart of  FIG. 13 . As illustrated in block  100  of the flowchart, the coiled tubing  46  and connectors  48  initially are transported to a well site having at least one well  34 . Once at the well site, the end  94  of the coiled tubing  46  is swaged, as illustrated by a block  102 . The swaging can utilize either an internal swage or an external swage, depending on the application and/or the configuration of connector  48 . The swaging process properly rounds the coiled tubing for a secure, sealing engagement with the connector. In some applications, the swaging portion of the process requires that the coiled tubing seam be removed. When using an internal swage, for example, the coiled tubing seam formed during manufacture of the coiled tubing can be removed with an appropriate grinding tool. 
         [0049]    If connector  48  comprises a threaded portion  84  along its engagement region  52 , the threads  86  are cut into coiled tubing end  94 , as illustrated by block  104 . The threads can be cut at the well site with a tap having an appropriate thread configuration to form the desired thread profile along either the interior or the exterior of coiled tubing end  94 . It should be noted that if connector  48  comprises an engagement region having bayonet slots  56 , the swaging process can still be used to properly round the coiled tubing end  94  and to create the desired tubing diameter for a secure, sealing fit with the breech lock style connector. Once the end  94  is prepared, engagement region  52  of connector  48  is engaged with the coiled tubing. When using a threaded engagement region, the connector  48  is to theadably engaged with the coiled tubing  46 , as illustrated by block  106 . The connector  48  and coiled tubing  46  are then continually threaded together until an interfering threaded connection is formed, as illustrated by block  108 . The interfering threaded connection forms a metal-to-metal seal and a rigorous connection able to withstand the potential axial loads incurred in a downhole application. Of course, the well tool  44  or other appropriate component can be coupled to engagement region  54  according to the specific coupling mechanism of the well tool prior to running the well tool and coiled tubing downhole. 
         [0050]      FIG. 14  illustrates a slightly more detailed methodology of forming connections at a well site. In this embodiment, the coiled tubing  46  and connectors  48  are initially transported to the well site, as illustrated by block  110 . The connection end of the coiled tubing  46  is then swaged, as described above and as illustrated by block  112 . In this particular embodiment, an internal interference thread is cut into the interior of the rounded connection end  94  with a tap having an appropriate thread configuration, as illustrated by block  114 . The cut interference threads are then finished with a second tap, as illustrated by block  116 . A supplemental seal, such as elastomeric seal  92 , is located between the connector  48  and the coiled tubing  46 , as illustrated by block  118 . The connector  48  and the coiled tubing  46  are then threadably engaged, as illustrated by block  120 . In this example, the connector  48  and the coiled tubing  46  are threaded together until a sacrificial threaded connection is formed, as illustrated by block  122 . The embodiments described with reference to  FIGS. 13 and 14  are examples of methodologies that can be used to form stable, rigorous, sealed connections at a well site. However, alternate or additional procedures can be used including additional preparation of the coiled tubing end, e.g. chamfering or otherwise forming the end for a desired connection. Additionally, the connector  48  can be torsionally, i.e. rotationally, locked with respect to the coiled tubing  46  and/or the well device  44  via a variety of locking mechanisms, as described more fully below. 
         [0051]    Depending on the type of engagement regions  52  and  54  used to engage the coiled tubing  46  and well tool  44 , respectively, the use of retention mechanism  70  may be desired to lock the components together and prevent inadvertent separation. In addition to the examples of retention mechanism  70  illustrated in  FIGS. 2 and 4 , another embodiment of retention mechanism  70  is illustrated in  FIG. 15 . In this embodiment, a snap ring member  124 , such as a C-ring, is designed to snap into a corresponding groove  126  formed, for example, in connector  48 . However, groove  126  also can be formed in coiled tubing  46  or well tool  44 . The snap ring member  124  further comprises a transverse pin  128 , such as a shear pin. When snap ring member  124  is properly placed into groove  126 , pin  128  extends through corresponding recesses or castellations  130 ,  132  formed in connector  48  and the adjacent component, e.g. coiled tubing  46 , respectively. In the embodiment illustrated in  FIG. 15 , connector  48  comprises a plurality of castellations  130  circumferentially spaced, and coiled tubing  46  comprises a plurality of corresponding castellations  132  also circumferentially spaced. In one specific example example, 15 castellations  130  are machined between groove  126  and the end of midsection  50  adjacent coiled tubing  46 . In this same example, 12 corresponding castellations are machined into the corresponding end  94  of coiled tubing  46 . This particular pattern of castellations provides matching notches within plus or minus one degree around the circumference of the connector. When pin  128  is disposed within corresponding castellations, the connected components are prevented from rotating with respect each other and are thus retained in a connected position, regardless of whether the connection is formed with bayonet slots  56  or threads  86 . This method can be used for all tool joint connections within the downhole tool. 
         [0052]    Another retention mechanism  70  is illustrated in  FIG. 16 . In this embodiment, one or more split ring locking mechanisms  134  can be used to connect sequentially adjacent components, such as coiled tubing  46 , connector  48  and well tool  44 . Each split ring locking mechanism  134  comprises a separate ring sections  136  that can be coupled together around the connection region between adjacent components. The split ring locking mechanism  134  comprises, for example, an internal thread that can be used to pull the adjacent components together when torque is applied to the split ring locking mechanism. Corresponding castellations  138  may be machined into each split ring locking mechanism  134  and an adjacent component to prevent unintended separation of the components, as discussed above. For example, a plurality of castellations can be machined into both the split ring locking mechanism  134  and the adjacent component. A snap ring member  124  can be positioned to prevent the split ring  134  from loosening, thereby securing the adjacent components. By way of specific example, each split ring locking mechanism  134  may comprise a pair of castellations, and each of adjacent component may comprise  12  castellations to facilitate alignment of the corresponding castellations for placement of the snap ring member  124 . In this type of embodiment, the adjacent components, e.g. connector  48  and well tool  44 , can be designed with connector ends having corresponding splines that mate with each other when the adjacent components are initially engaged. The one or more split ring locking mechanisms  134  are used to retain the adjacent components in this engaged position. 
         [0053]    Another embodiment of the split ring locking mechanism  134  is illustrated in  FIGS. 17 and 18 . In this embodiment, the split ring locking mechanism  134  comprises a split ring portion  140  and a wedge ring portion  142 . The wedge ring portion  142  has a mechanical stop  144  and one or more inclined or ramp regions  146  that cooperate with corresponding inclined or ramp regions  148  of split ring portion  140 . With this type of split ring, the adjacent components are assembled as described above with reference to  FIG. 16 , and the split ring  134  is threaded onto an adjacent component until contacting a component shoulder and “shouldering out” on the inside of the connection. The ramp regions  146 ,  148  of the wedge ring portion  142  and the split ring portion  140  interfere with each other such that the wedge ring portion  142  rotates with the split ring portion  140 . When the connection is tight, the split ring portion  140  is held in position and the wedge ring portion  142  is turned in the tightening direction. The ramp regions  146  force wedge ring portion  142  away from split ring portion  140  (see  FIG. 18 ) and into a shoulder of the adjacent component. Friction holds the wedge ring portion  142  in place. If an external force acts on the split ring locking mechanism  134  in a manner that would tend to loosen the connection, ramp regions  146  are further engaged, thereby tightening the wedge and preventing the split ring mechanism from loosening. 
         [0054]    In another alternate embodiment, retention mechanism  70  may comprise a belleville washer or wave spring  150  positioned to prevent inadvertent loosening of adjacent components, such as connector  48  and coiled tubing  46 . As illustrated in  FIGS. 19 and 20 , belleville washer  150  may be positioned between a shoulder  152  of a first component, e.g. connector  48 , and the mating end of the adjacent component, e.g. coiled tubing  46 . When the connection is tightened, such as by threading connector  48  into coiled tubing  46  as described above, the belleville washer  150  is transitioned from a relaxed state, as illustrated in  FIG. 19 , to a flattened or energized state, as illustrated in  FIG. 20 . The belleville washer  150  may be designed so the washer is fully flattened when the desired torque is applied to the connection. In the event a large axial load is applied to the connection, loosening of the connection is prevented by the washer due to the highly elastic nature of the belleville washer  150  relative to the elasticity of the connected components. 
         [0055]    Another embodiment of retention mechanism  70  is illustrated in  FIGS. 21 and 22 . In this embodiment, a key  154  is used in combination with a split ring locking mechanism  134  that may be similar to the design described above with reference to  FIG. 16 . Prior to installation, key  154  is slid into a corresponding slot  156  formed in the split ring locking mechanism  134 . The corresponding slot  156  may have one or more undercut regions  158  with which side extensions  160  of key  154  are engaged as key  154  is moved into slot  156 . The side extensions  160  allow the key to move back and forth in slot  156  but prevent the key  154  from falling out of slot  156  once the split ring locking mechanism  134  is engaged with adjacent components. 
         [0056]    The key  154  retains adjacent components in a rotationally locked position by preventing rotation of split ring locking mechanism  134  in the same manner as pin  128  of the snap ring member  124  described above with reference to  FIGS. 15 and 16 . In operation, the split ring locking mechanism  134  is rotated until sufficiently tight and until the key  154  can be moved into an aligned castellation  138  of an adjacent component, as best illustrated in  FIG. 22 . The key  154  is then slid into the aligned castellation until it engages both the split ring locking mechanism  134  and the adjacent component. In this position, key  154  prevents relative rotation between the split ring locking mechanism and the adjacent component. The key  154  may be prevented from sliding back into slot  156  by an appropriate blocking member  162 , such as a set screw positioned behind the key after the key is moved into its locking position. The set screw  162  prevents the key  154  from moving fully back into slot  156  until removal of the set screw. It should be noted that many of these retention mechanisms also can be used in combination. For example, interlocking castellations  130 ,  132  can be combined with belville washers  150 , keys  154 , wedge ring portions  142 , or other locking devices in these and other combinations. 
         [0057]    Another embodiment of retention mechanism  70  is illustrated in  FIG. 23 . In this embodiment, a jam nut  164  prevents inadvertent separation of adjacent components, such as separation of coiled tubing  46  from an adjacent component. The jam nut  164  can be used to force coiled tubing  46  and specifically protrusions  68  into more secure engagement with slots  56 , e.g. against the wall surfaces forming slots  56 . In one embodiment, jam nut  164  is used to securely move protrusions  68  into a J-slot portion of each slot  56 . A split ring  134  may be used with the connector  48  to prevent loosening of jam nut  164 , thereby ensuring a secure connection. It should be further noted that additional retention mechanisms can be used for other types of connections, such as threaded connections. For example, threaded connections can be secured with a thread locking compound, such as a Baker™-lock and loctite™ thread locking compound. 
         [0058]    As briefly referenced above, a forming tool  166  can be used to form depressions in the exterior of coiled tubing  46  that result in inwardly directed protrusions  68 , as illustrated in  FIG. 24 . The forming tool  166  comprises a tool body  168  with an interior, longitudinal opening  170  sized to receive an end of the coiled tubing  46  therein. A mandrel  172  can be inserted into the interior of coiled tubing  46  to support the coiled tubing during formation of protrusions  68 . Additionally, a plurality of tubing deformation members  174  are mounted radially through tool body  168 . The tubing deformation members  174  are threadably engaged with tool body  168  such that rotation of the tubing deformation members drives them into the coiled tubing to form inwardly directed protrusions  68 . Mandrel  172  can be designed with appropriate recesses to receive the newly formed protrusions  68 , as illustrated. 
         [0059]    The connectors described herein can be used to connect coiled tubing to a variety of components used in well applications. Additionally, the unique design of the connector enables maximization of flow area while maintaining the ability to pass the connector through a coiled tubing injector. The connector and the methodology of using the connector also enable preparation of coiled tubing connections while at a well site. Additionally, a variety of locking mechanisms can be combined with the connector, if necessary, to prevent inadvertent disconnection of the connector from an adjacent component. The techniques discussed above can be used for all tool joints in a downhole tool string. 
         [0060]    As shown in  FIG. 1 , a well tool  44  may be connected to coiled tubing  46  by any one of the connectors  48  described above. The coiled tubing  46  may then be used to convey the well tool  44  to a desired depth of the wellbore  36  where a well operation is to be performed.  FIG. 25  shows in more detail an assembly for conveying the well tool  44  into a wellbore  36  via coiled tubing  46 . 
         [0061]    As shown,  FIG. 25  shows a coiled tubing  46 , which is a continuous strand of metal tubing that is stored and transported to a well site  200  on a reel  202 . Once at the well site  200 , the coiled tubing  46  may be guided from the reel  202  to a coiled tubing injector  206  by an optionally included gooseneck assembly  204 . Once in the injector  206 , the coiled tubing  46  is driven downwardly toward the wellbore  36 . 
         [0062]      FIG. 25  also shows a typical coiled tubing injector  206 . As shown, the coiled tubing injector  206  includes two opposed roller assemblies  212  that are spaced apart to receive the outer diameter of a coiled tubing  46 . Each roller assembly  212  includes a chain  214  looped around one or more sprockets  216 , which are driven by a motor to rotate the chain  214  as shown by arrows  218 . As the chains  214  rotate, they engage the coiled tubing  46  and force it downwardly into the wellbore  36 . In addition, by reversing the motion of the roller assemblies  212 , the coiled tubing  46  may be pulled away from the well. 
         [0063]    However, it is important to note that the injector roller assemblies  212  are spaced apart to receive a specific coiled tubing  46  outer diameter, and cannot “tolerate” diameters outside a specific range. As such, if the coiled tubing  46  is connected to a device having an outer diameter that varies from the outer diameter of the coiled tubing  46  by an amount outside the tolerance of the injector  206 , then the device cannot be “run” through the injector. That is, if the outer diameter of the device is too large, then it will not fit between the roller assemblies  212  of the injector  206 , and if the outer diameter of the device is too small, then the roller assemblies  212  will not be able to engage the device. 
         [0064]    In such situations, the coiled tubing  46  is inserted into the injector  206  and moved thereby to enable a lower end of the coiled tubing  46  to be moved to a position below a lower end of the injector  206 . At this position (below the injector), the coiled tubing  46  can be assembled with the differently sized device. Once assembled, the injector  206  can then be operated to drive the coiled tubing  46 , with the differently sized device assembled thereto, into the wellbore  36 . However, assembling the device to the coiled tubing  46  in this manner is a time consuming process. It would be preferable to perform as much of this assembling as possible prior to injecting the coiled tubing  46  into the injector  206 . However, in order to do so, the device and the coiled tubing  46  must have similar enough outer diameters to be tolerated by the injector. Therefore, as described above, in embodiments of the coiled tubing connector  48 , described above, the outer diameter of the connector  48  is substantially equal to the outer diameter of the coiled tubing  46 . As such, both the coiled tubing  46  and the connector  48  can be run through the injector  206 , thus saving assembly time at the well site  200 . 
         [0065]      FIG. 26  shows another assembly  220  designed to save assembly time at the well site  200 . As shown, the assembly  220  includes a coiled tubing  46  connected to a coiled tubing connector  48 . In this example, the coiled tubing  46  is connected to a connector  46  that is similar to the one shown in  FIG. 2 . However, any of the above described connectors may be used in this assembly  220 . The assembly  220  also includes a cable  222 . Some well tools  44  require such a cable  222  for power and/or data transmission. As such, the assembly  220  includes a cable  222  that runs through both the coiled tubing  46  and the coiled tubing connector  48 , and then terminates in a cable termination head  224  as described further below. The cable  222  itself may include any appropriate wireline cable having one or more electrically conductive lines therein. For example, the cable  222  may be a monocable (a cable having one electrically conductive line therein) or a heptacable (a cable having seven electrically conductive lines therein). However, in other embodiments the cable  222  may include any appropriate number of electrically conductive lines therein. 
         [0066]    As mentioned above and shown in  FIG. 26 , the assembly  220  also includes a cable termination head  224 , within which the cable  222  is “terminated.” That is, each electrically conductive line  226  is separated from a cover of the cable  222  and electrically connected to a pin connector  228  to form a stable electrical connection. A well tool  44 , for connection to the cable termination head  224 , similarly contains corresponding electrically conductive lines  232  that are terminated or electrically connected to a socket type connector  230 . The pin(s)  228  from the cable termination head  224  can then be “plugged into” or engaged with corresponding openings in the socket connector  230  to form electrical connections between the cable  222  and the well tool  44 , such an electrical connection may be referred to as a “plug in connection.” Such a connection also forms a mechanical connection between the cable termination head  224  and the well tool  44 . 
         [0067]    As such, power can be transmitted from surface equipment  221  at the well site  200  to the well tool  44  through one or more of the electrically conductive lines  226  in the cable  222 . Similarly, signals can be transmitted between the surface equipment  221  and the well tool  44  via the electrically conductive line(s)  226  in the cable  222 . These signals can be control signals for varying the operational parameters of the well tool  44  or data from measurements of the well tool  44  or its environment. Such data can be monitored and/or analyzed during and the wellbore operation. Based on this monitoring or analysis, the wellbore operation can be altered to achieve desired results in the operation. 
         [0068]    In one embodiment, the cable  222  may be replaced by one or more fiber optic lines, which may be used for transmitting data between the well tool  44  and the surface equipment  221 . In such an embodiment, a similar pin and socket arrangement as that described above with respect to the electrical embodiment may be used to create an optical pathway between the cable termination head  224  and the well tool  44 . It is important to note that in both the optical embodiment and the electrical embodiment, the pin(s)  228  may be disposed in the cable termination head  224  and the socket  230  may be disposed in the well tool  44 , or the pin(s)  228  may be disposed in the well tool  44  and the socket  230  may be disposed in the cable termination head  224 . 
         [0069]    With the cable  222  terminated in the cable termination head  224 , and the coiled tubing  46  connected to the cable termination head  224  through the coiled tubing connector  48 , such as by threadably engaging the second end  54  of the connector  48  with a threaded end of the cable termination head  224 , the coiled tubing  46 , the coiled tubing connecter  48 , the cable termination head  224  and the cable  222  running therethrough combine to form a wired coiled tubing assembly  220 . As can be seen from  FIGS. 1 and 26 , when connected, the exposed outer diameters  51 ,  53 ,  55  of the coiled tubing  46 , the coiled tubing connecter  48 , the cable termination head  224  combine to form a wired coiled tubing assembly  220  having a substantially continuous outer diameter. That is, the outer diameters  51 ,  53 ,  55  of the coiled tubing  46 , the coiled tubing connecter  48 , the cable termination head  224  are all substantially equal or at least close enough to each other to be tolerated by the coiled tubing injector  206 . Thus, the entire wired coiled tubing assembly  220  may be inserted into and run through the injector  206 . 
         [0070]    Were it not possible to run the cable termination head  224  through the injector  206 , the act of terminating the cable  222  to the cable termination head  224  would have to be performed at the job site with the coiled tubing  46  extending below the injector  206 . Thus, amounting to a tremendous expenditure of time, which is avoid by the cable termination head  224  of the present invention. It should also be noted that although the above description focuses on the wired coiled tubing assembly  220  having one of the coiled tubing connectors  48  described herein, any coiled tubing connectors that is capable of being run through an injector may be used to form a wired coiled tubing assembly  220  according to the present invention. In addition, although a specific coiled tubing injector  206  has been depicted and described above, any appropriate coiled tubing injector  206  may be used in alternative embodiments of the present invention. 
         [0071]      FIG. 27  shows a method according to one embodiment according to the present invention. As shown in step  300  of the method, a coiled tubing  46  is connected to a coiled tubing connector  48  and a cable  222  is run through the coiled tubing  46  and the connector  48 . At step  302  the cable  222  is terminated in a cable termination head and the cable termination head  224  is connected to the connector  48  to form a wired coiled tubing assembly  220 . At step  304 , the wired coiled tubing assembly  220  is run through an injector  206 . At step  306 , the injector  206  is stopped once an end of the wired coiled tubing assembly  220  has exited the lower end of the injector  206 . At step  308 , a well tool  44  is electrically and/or optically connected to the cable  222 , such as by a plug in operation between the cable termination head  224  and the well tool  44 . At step  310  the injector  206  is operated until the wired coiled tubing assembly  220 , with the well tool  44  attached thereto, has been lowered to a desired depth in the wellbore  36 . At step  312 , the well tool  44  is operated to perform a wellbore operation. 
         [0072]    In this manner, the coiled tubing  46  may be used to forcibly drive the well tool  44  to a depth in the wellbore  36  where it is desired to perform a wellbore operation. This forceful driving of the coiled tubing  46  into the wellbore  36  allows the well tool  44  to access not only vertical sections  208  of the wellbore  36 , but also more difficult to access horizontal or deviated sections  210  as well. 
         [0073]    It is also noted that after a wellbore operation has been performed, the wired coiled tubing assembly  220  may be reversed up through the injector  206  as a single unit. In addition, it is noted that the wired coiled tubing assembly  220  is reusable. That is, the cable termination head  224  of the wired coiled tubing assembly  220  may be “plugged into” a first well tool to form power and or data transmission pathways with the first tool during a first wellbore operation; then unplugged from the first well tool  44  and plugged into a second well tool to form power and or data transmission pathways with the second tool during a second wellbore operation. 
         [0074]    Accordingly, although only a few embodiments of the present invention have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this invention. Such modifications are intended to be included within the scope of this invention as defined in the claims.