Patent Publication Number: US-6668930-B2

Title: Method for installing an expandable coiled tubing patch

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to oil and gas wellbore completion. More particularly, the invention relates to a system of completing a wellbore through the expansion of tubulars. More particularly still, the invention relates to methods for expanding a section of coiled tubing into a surrounding tubular so as to form a patch. 
     2. Description of the Related Art 
     In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling a predetermined depth, the drill string and bit are removed and a section of casing is lowered into the wellbore. An annular area is thus formed between the string of casing and the formation. The casing is temporarily hung from the surface of the well. A cementing operation is then conducted in order to fill the annular area with cement. Using apparatus known in the art, the casing is cemented into the wellbore by circulating cement into the annular area defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons. 
     It is common to employ more than one string of casing in a wellbore. In this respect, a first string of casing is set in the wellbore when the well is drilled to a first designated depth. The first string of casing is hung from the surface, and then cement is circulated into the annulus behind the casing. The well is then drilled to a second designated depth, and a second string of casing, or liner, is run into the well. The second string is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The second liner string is then fixed, or “hung” off of the existing casing by the use of slips which utilize slip members and cones to wedgingly fix the new string of liner in the wellbore. The second casing string is then cemented. This process is typically repeated with additional casing strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing of an ever-decreasing diameter. 
     In many instances, the casing is perforated, typically at a lower region of the casing string. Alternatively, the last string of casing extending into the wellbore may be pre-slotted to receive and carry hydrocarbons through the wellbore towards the surface. In this instance, the hydrocarbons are filtered through a screened portion of tubular. In either instance, the hydrocarbons flow from the formation, into the wellbore, and then to the surface through a string of tubulars known as production tubing. Because the annulus between the casing and the production tubing is sealed with packers, the hydrocarbons flow into the production tubing en route to the surface. 
     Over the life of a well, circumstances may occur that change the properties of particular formations. For example, the pressure in a formation may fall, or a formation may begin to produce an unacceptably high volume of water. In these situations, it is known to run straddles into the well to patch the perforations adjacent the troubled formation. Straddles are sections of hard pipe with sealing arrangements at either end. Typically, the straddle is located downhole at the depth of the perforations. The seals are actuated into contact with the surrounding casing to isolate the perforations between the seals. 
     Additionally, there are varied other uses for a patch or straddle within a live well. For example, a straddle may be used to patch over corroded sections of tubulars within the wellbore, such as production tubing or casing. Straddles may also be used to patch over eroded sections of tubulars or to cover screens in gravel packs. Straddles may further be used to create a restricted flow area thereby increasing the velocity of a fluid during production of the well. 
     Conventional straddles tend to be complex in operation. A conventional straddle consists of a length of tubular having a mechanical packer at either end. The mechanical packers have moving parts that are expensive to fabricate and install. Conventional straddles require a source of hydraulic and/or mechanical force to actuate the seals. Further, conventional straddles of hard pipe result in a significant loss in bore cross section which chokes off the well, thereby reducing production capacity. 
     Another problem associated with existing straddles is the time and cost associated with locating and setting a straddle of hard pipe in a live well. Conventional straddles are run into a live well on a string of tubulars. Lowering a string of tubular into a live well requires the use of at least two pressure devices to safely maintain the well while running the tubular string. Such an operation also requires the placement of a large working unit for handling joints of working string. Removal of the string requires the same amount of time and energy. 
     There is a need, therefore, for an easier and less expensive system for patching or repairing a tubular. There is a further need for an improved assembly for patching or repairing a tubular in a live well. There is further a need for an apparatus and methods by which a section of tubular, such as casing or a sand screen, can be either straddled or patched by expanding a replacement section therein. 
     SUMMARY OF THE INVENTION 
     The present invention provides methods for expandably installing a section of coiled tubing in situ within a wellbore, including a live wellbore. The installed section of coiled tubing is used to form a patch within a surrounding tubular body. For purposes of the present inventions, the term “patch” includes any installation of a section of coiled tubing into a surrounding tubular body. Such patches include, but are not limited to: (1) the expansion of a section of coiled tubing along a desired length in order to seal perforations; (2) the expansion of coiled tubing above and below perforations in order to form a “straddle;” and (3) the expansion of a section of coiled tubing at a point above perforations in order to form a “velocity tube” and to isolate an upper portion of surrounding casing. The patch may also serve to support a corroded or weakened section of tubular. In any method of the present invention, the surrounding tubular body may comprise a string of production tubing, a string of casing, a sand screen, or any other tubular body disposed within a wellbore. 
     In the methods of the present invention, an assembly is run into the wellbore on a working string. The assembly in one aspect comprises a slip, a motor, a cutting tool, and an expander tool. In operation, the assembly is lowered into the wellbore on a string of coiled tubing. A section of coiled tubing to be expanded is located in the wellbore at the desired depth. The expander tool is then actuated, preferably through the use of hydraulic pressure, so as to expand the section of coiled tubing into a surrounding tubular. Thereafter, the coiled tubing is cut above the expanded region, thereby leaving a patch within the wellbore. The patch remains in the wellbore through frictional engagement with the surrounding tubular. The expansion assembly is then removed from the wellbore, along with the unexpanded portion of coiled tubing above the severance point. 
     In an alternate aspect of the invention, a method is provided which installs a patch into a wellbore as outlined above. Then, a new expansion assembly is run into the wellbore. The second expansion assembly is disposed within a working string, and is run into the wellbore adjacent the patch. The second expansion assembly in one aspect comprises a slip, a motor, a telescoping member, and rotating expander tool. The expander tool is actuated so as to expand additional lengths of the patch. At the same time, the telescoping member is actuated to translate the expander tool in order to extend the length of the patch within the wellbore. Alternatively, or in addition, the expander tool is translated by raising or lowering the working string from the surface. 
     In a further aspect, a method is provided which comprises providing coiled tubing which has been severed into an upper section and a lower section. An expansion assembly is then assembled which comprises a first slip, a second slip, a motor, a telescoping member, a cutting tool, a first expander tool, and a second expander tool. The first slip is activated to engage the upper section of coiled tubing. Similarly, the second slip is activated to engage the lower section of coiled tubing. The first and second slip of the expansion assembly are positioned together so that the upper and lower sections of coiled tubing are joined. In this manner, a continuous length of coiled tubing is essentially formed. The expansion assembly is run into the wellbore on the coiled tubing. The second expander tool is actuated to partially expand the lower section of tubing into frictional engagement with the surrounding casing in the wellbore. The second expander tool is de-activated, and the second slip is also then de-activated. The upper section of coiled tubing is then raised so as to align the first expander tool substantially with the upper end of the lower section of coiled tubing. The first expander tool is then actuated so as to begin expanding the lower section of tubing into the surrounding casing. At the same time, the expansion assembly is translated within the wellbore so as to form a patch of a desired length. 
     In one aspect, the first expander tool is configured to have pitched rollers. The pitched rollers cause the expansion assembly, including the first expander tool, to “walk” downward within the wellbore as the first expander tool is rotated. In another aspect, the first expander tool is further translated by actuating the telescoping member. After the patch has been fully formed, the upper section of coiled tubing is retrieved from the hole, thereby removing the expansion assembly as well. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
     FIG. 1 is a schematic view of a wellhead. Visible above the wellhead is an assembly of the present invention for expanding a section of coiled tubing. The assembly is being run into a wellbore. 
     FIG. 2 is an exploded view of view of a cutting tool as might be used in the methods of the present invention. 
     FIG. 3 is a cross-sectional view of the cutting tool of FIG. 3, taken across line  3 — 3 . 
     FIG. 4 is an exploded view of an expander tool as might be used in the methods of the present invention. 
     FIG. 5 is a cross-sectional view of the expander tool of FIG. 4, taken across line  5 — 5  of FIG.  4 . 
     FIG. 6 is a schematic view of the wellhead of FIG. 1, showing a cross-sectional view of a wellbore receiving an assembly for expanding coiled tubing. 
     FIG. 7A is a sectional view of the wellbore of FIG.  6 . In this view, an assembly for expanding coiled tubing has been run into the wellbore. Visible in this view is a string of coiled tubing, a section of which will be expanded into frictional engagement with the surrounding casing. 
     FIG. 7B is a sectional view of the wellbore of FIG. 7A, with the coiled tubing now being expanded into the surrounding casing. As can be seen, the expander tool has been actuated to accomplish expansion. 
     FIG. 7C is a sectional view of the wellbore of FIG.  7 B. The coiled tubing has been expanded along a desired length into frictional engagement with the surrounding casing. The cutting tool is now being actuated so as to sever the coiled tubing in situ. 
     FIG. 7D is a sectional view of the wellbore of FIG.  7 C. In this view, the severed upper portion of coiled tubing is being removed from the wellbore, along with the expansion assembly. 
     FIG. 8A is a sectional view of the wellbore of FIG.  7 D. In this view, a second assembly for expanding coiled tubing is being run into the wellbore. The second expansion assembly does not have the cutting tool. 
     FIG. 8B is a sectional view of the wellbore of FIG.  8 A. In this view, the second expansion assembly has been run into the wellbore. The expander tool is seen expanding the entire length of patch into the surrounding casing. 
     FIG. 9A is a sectional view of a wellbore having an alternate embodiment of an expansion assembly of the present invention. The expansion assembly is being run into the wellbore on a string of severed coiled tubing. Separate slip members are shown for supporting upper and lower sections of coiled tubing. In addition, two separate expander tools are shown. 
     FIG. 9B is a cross-sectional view of the wellbore of FIG.  9 A. The lower expander tool has been actuated so as to begin expanding the section of coiled tubing into the surrounding casing. 
     FIG. 9C is a section view of the wellbore of FIG.  9 B. In this view, the lower expander tool has been deactivated. The upper expander tool has been actuated in its place and is “walking” down through the lower section of coiled tubing in order to form a patch. 
     FIG. 9D presents a cross-sectional view of the wellbore of FIG.  9 C. Here, the coiled tubing has been completely expanded into the surrounding casing. The upper section of coiled tubing is being pulled from the wellbore, leaving a patch in place wellbore. The alternate expansion assembly is now being removed from the wellbore. 
     FIG. 10A is a sectional view of a wellbore having still another alternate expansion assembly of the present invention. This arrangement of an expansion assembly utilizes a telescoping member. In one arrangement, the telescoping extension member translates the expander tool through the lower section of the coiled tubing. 
     FIG. 10B is a sectional view of the wellbore of FIG.  10 A. In this view, the lower section of coiled tubing is being further expanded into surrounding casing. 
     FIG. 11A is a cross-sectional view of a wellbore having a section of coiled tubing expanded therein. In this view, a section of coiled tubing has been completely expanded along a desired length in order to seal off a perforated portion of casing. 
     FIG. 11B is a cross-sectional view of a wellbore having a section of coiled tubing expanded therein. In this view, the coiled tubing has been expanded at points above and below a perforated portion of casing in order to form a straddle. 
     FIG. 11C is a cross-section view of a wellbore having a section of coiled tubing expanded therein. In this view, the coiled tubing has been expanded at a point above a perforated portion of casing in order to form a velocity tube. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     FIG. 1 is a schematic view of a wellhead  100 . Visible above the wellhead  100  is an expansion assembly  200  of the present invention. As will be set forth in greater detail below, the expansion assembly  200  is designed to be hydraulically activated via pressurized fluid so as to expand a section of coiled tubing  110  into contact with a surrounding tubular body, such as a string of casing  106 . In this respect, the outer surface of the coiled tubing  110  has a smaller outside diameter than the inner surface of the casing  106  prior to expansion. 
     The expansion assembly  200  is disposed within a string of coiled tubing  110  at a lower end thereof. The coiled tubing  110  is well known in the art and defines a continuous tubular product which is not only capable of carrying pressurized fluid, but is also flexible enough to be unrolled from a reel for convenient transportation and delivery into a wellbore  105 . The expansion assembly  200  is preferably assembled at the surface. Thereafter, and as shown in FIG. 1, the assembly  200  is preferably run on the coiled tubing  110  through the wellhead  100  and into a wellbore  105 . 
     The expansion assembly  200  shown in FIG. 1 is comprised of a series of components. The first component is a slip  205 . The slip  205  is typically disposed at the top of the expansion assembly  200 . The slip  205  is used to hang the remainder of the expansion assembly  200  within the coiled tubing  110 . Preferably, the slip  205  defines an expandable tubular member which, when actuated, engages the inner surface of the surrounding string of coiled tubing  110 . The outwardly actuated members typically define at least one outwardly extending serration or edged tooth (not shown) to provide a more secure frictional engagement with the inner surface of the coiled tubing  110 . Optionally, the outwardly actuated members may land within a circumferential profile within the surrounding string of coiled tubing  110 . 
     The slip  205  includes a hollow, threaded inner bore. The bore is internal to the slip  205 , and permits fluid to flow from the coiled tubing  110  downward through the slip  205 . From there, fluid flows to the other components of the expansion assembly  200 . 
     Below the slip  205  is a motor  210 . In one arrangement, a threaded, hollow make-up joint  215  connects the slip  205  to the motor  210 , and places them in fluid communication with each other. Alternatively, the motor  210  is directly connected to the slip  205 . The motor  210  may be any motor capable of providing rotation to the cutting tool  220  and the expander tool  225 , which are both described below. For example, the motor  210  may be any electric or mud motor which are both well known in the art. 
     Disposed below the motor  210  is a cutting tool  220 . An exploded view of a cutting tool  220  as might be used in the assembly  200  of the present invention is presented in FIG.  2 . The cutting tool  220  primarily defines a central body  222  which is hollow and generally tubular. The cutting tool  220  includes connectors  224  and  226  disposed at the top and bottom ends of the central body  222 . The connectors  224  and  226  are of a reduced diameter compared to the outside diameter of the central body  222 , and are connectable to other components of the expansion assembly  200 . 
     One or more expandable members  228  is disposed radially around the central body  222 . In one arrangement, three expandable members  228  are circumferentially spaced apart around the central body  222  at  120  degree intervals. The expandable members  228  are more fully shown in the cross-sectional view of FIG.  3 . FIG. 3 presents a cross-sectional view of the cutting tool of FIG. 2, taken across line  33 . It can be seen that each expandable member  228  resides within a recess  227  in the central body  222 . Each expandable member  228  defines a roller  221  connected to a slidable piston  223 . The piston  223  is capable of sliding partially outwardly from its respective recess  227 , thereby allowing the roller  221  to contact the inner surface of the coiled tubing  110  upon actuation. 
     The cutting tool  220  is designed to be actuated upon the injection of fluid under pressure into the coiled tubing  110 . In operation, fluid flows through the tubular core  225  of the cutting tool  220 , and contacts the backside of the piston  227  in each expandable member  228 . Pressurized hydraulic pressure applied internal to the cutting tool  220  forces the rollers  221  radially outward to engage the surrounding coiled tubing  110 . Each expandable member  228  includes a hard rib  229  which serves as a cutting instrument. The hard ribs  229  cause a compressive yield and a localized reduction in wall thickness of the coiled tubing  110  when extended, thereby severing the coiled tubing  110  at the point of engagement. 
     The cutting tool  220  presented in FIGS. 2 and 3 are exemplary only. It is to be appreciated that other rotary cutting tools may be used. Further, as used herein, the term “sever” includes any means of disconnecting an expanded portion of coiled tubing from an unexpanded portion of coiled tubing. Thus, the present invention encompasses disconnecting an expanded coiled tubing portion from an unexpanded coiled tubing portion. 
     The expansion assembly  200  of the present invention also includes an expander tool  230 . In the arrangement shown in FIG. 1, the expander tool  230  is positioned below the cutting tool  220 . A larger exploded view of the expander tool  230  is shown in FIG.  4 . FIG. 5 presents the same expander tool  230  in cross-section, with the view taken across line  5 — 5  of FIG.  4 . 
     The expander tool  230  has a body  232  which is hollow and generally tubular. Connectors  234  and  236  are provided at opposite ends of the body  232  for connection to other components of the assembly  200 . The connectors  234  and  236  are of a reduced diameter (compared to the outside diameter of the body  232  of the tool  230 ). The hollow body  232  allows the passage of fluids through the interior of the expander tool  230  and through the connectors  234  and  236 . As with the cutting tool  220 , the expander tool  230  has three recesses  237  to hold a respective roller  231 . Each of the recesses  237  has parallel sides and holds a roller  231  capable of extending radially from the radially perforated tubular core  235  of the tool  230 . 
     In one embodiment of the expander tool  230 , rollers  231  are near-cylindrical and slightly barreled. Each of the rollers  231  is supported by a shaft  238  at each end of the respective roller  231  for rotation about a respective rotational axis. The rollers  231  are generally parallel to the longitudinal axis of the tool  100 . The plurality of rollers  231  are radially offset at mutual 120-degree circumferential separations around the central body  232 . In the arrangement shown in FIG. 5, only a single row of rollers  231  is employed. However, additional rows may be incorporated into the body  232 . 
     While the rollers  231  illustrated in FIG. 4 have generally cylindrical or barrel-shaped cross sections, it is to be appreciated that other roller shapes are possible. For example, a roller may have a cross sectional shape that is conical, truncated conical, semi-spherical, multifaceted, elliptical or any other cross sectional shape suited to the expansion operation to be conducted within the coiled tubing  110 . 
     Each shaft  238  is formed integral to its corresponding roller  231  and is capable of rotating within a corresponding piston  233 . The pistons  233  are radially slidable, one piston  233  being slidably sealed within each radially extended recess  237 . The back side of each piston  233  is exposed to the pressure of fluid within the hollow core  235  of the tool  230  by way of the coiled tubing  110 . In this manner, pressurized fluid provided from the surface of the well, via the coiled tubing  110 , can actuate the pistons  233  and cause them to extend outwardly whereby the rollers  231  contact the inner surface of the coiled tubing  110  to be expanded. 
     The expander tool  230  is preferably designed for use at or near the end of a coiled tubing  110 . In order to actuate the expander tool  230 , fluid is injected into the coiled tubing  110  from the surface. Fluid under pressure then travels downhole through the coiled tubing  110  and into the perforated tubular core  235  of the tool  230 . From there, fluid contacts the backs of the pistons  233 . As hydraulic pressure is increased, fluid forces the pistons  233  from their respective recesses  237 . This, in turn, causes the rollers  231  to make contact with the inner surface of the coiled tubing  110 . Fluid finally exits the expander tool  230  through connector  236  at the base of the tool  230 . The circulation of fluids to and within the expander tool  230  is regulated so that the contact between and the force applied to the inner wall of coiled tubing  110  is controlled. Control of the fluids provided to the pistons  233  ensures precise roller control capable of conducting the tubular expansion operations of the present invention that are described in greater detail below. 
     FIG. 6 presents a schematic view of the wellhead of FIG.  1 . The wellhead  100  is again positioned over the wellbore  105 . The wellhead components  105  typically include a casing head  154 , one or more blowout preventers  156 , a production tee  158 , and a stuffing box  160 . The stuffing box  160  serves to seal around the coiled tubing  110  as the coiled tubing  110  is lowered into the wellbore  105 . In the view of FIG. 6, the wellbore  105  is receiving the coiled tubing  110  with the expansion assembly  200  therein. Visible in FIG. 6 is a reel  125  used to deliver the string of coiled tubing  110  into the wellhead  100 . The coiled tubing  110  is delivered from the reel  125 , and run into the wellbore  105  as one continuous tubular. An expandable section of coiled tubing is shown at  115 . 
     As shown in FIG.  1  and FIG. 6, the wellbore  105  is typically lined with casing  106  that is permanently set with cement  107 . The expansion assembly  200  and coiled tubing  110  therearound are lowered to a pre-determined depth adjacent a troubled perforation or corroded section of casing, for example for expanding a section of coiled tubing  110 . Expansion of the coiled tubing  110  can then begin. 
     In one aspect of the present invention, a one-trip method is provided for expanding coiled tubing  110  into surrounding casing  106 . Referring to FIGS. 7A-7D, an expansion assembly  700  is run into the wellbore  105  and positioned above or adjacent a group of perforations (not shown) or corroded casing (not shown) to be isolated. The expansion assembly  700  shown in FIG. 7A includes a slip  205 , a motor  210 , a cutting tool  220 , and an expander tool  230  having rollers  231 . 
     In operation, pressurized hydraulic pressure is supplied through the coiled tubing  110  and down to the expander tool  230 . An initial application of elevated pressure causes the rollers  231  in the expander tool  230  to extend radially outward from the central body  232 . The outward force of the rollers  231  causes the coiled tubing  231  to deform such that a point of frictional engagement is created between the outer surface of the coiled tubing  231  and the inner surface of the surrounding casing  106 . The motor  210  is also actuated, causing the expander tool  230  to rotate within the coiled tubing  110 . This provides for a radial expansion of the coiled tubing  110  against the casing  106 . 
     The initially expanded state of the coiled tubing  110  is depicted in FIG.  7 B. FIG. 7B is a sectional view of the wellbore of FIG. 7A, with the coiled tubing  110  now being expanded into the surrounding casing  106 . As can be seen, the expander tool  230  has been actuated to accomplish initial expansion. Deformation of the coiled tubing  110  creates a localized reduction in wall thickness, and a corresponding increase in wall diameter. The expansion process effectively removes the annular region between the coiled tubing  110  and the casing  106  at the expanded depth. 
     FIG. 7C is a sectional view of the wellbore of FIG.  7 B. In this view, the cutting tool  220  is now being actuated so as to sever the coiled tubing  110  in situ. In this respect, the expandable members  228  of the cutting tool  220  have been expanded by the application of additional hydraulic pressure through the coiled tubing  110 . Actuation of the expandable members  228  causes the cutting instrument  229  to contact the inner surface of the coiled tubing  110 . Rotation of the cutting tool  220  by the motor  210  creates a radial cut in the coiled tubing  110 , thereby severing the coiled tubing string  110  from the portion of coiled tubing  703  being expanded, thereby forming a severed upper string of coiled tubing  110  and an expanded lower patch  703 . 
     It is noted that the ports  225  of the cutting tool  220  in the arrangement of FIG. 7C are configured to require greater hydraulic pressure to actuate than is necessary for actuation of the expander tool  230 . In this respect, a first pressure may be injected into the coiled tubing  110  in order to actuate the expander tool  230 . The coiled tubing  110  may optionally be raised and lowered by translating the coiled tubing string  110  from the surface in order to increase the length of the patch  703 . Once the desired expansion has been accomplished, an increased pressure. can be applied through the coiled tubing  110  downhole. The increased pressure will then actuate the cutting tool  220 . 
     Once the coiled tubing  110  has been severed and the patch  703  has been formed, the pressure in the expansion assembly  700  is reduced to disengage both the expandable members  228  of the cutting tool  220  and the rollers  231  of the expander tool  230 . The expansion assembly  700  is then retrieved from the wellbore  105 , as shown in FIG.  7 D. Because the expansion assembly  700  remains connected to the coiled tubing  110  by means of the slips  205 , removal of the coiled tubing  110  removes the expansion assembly  700 . An expanded patch  703  is thus left within the wellbore  105 . 
     In the arrangement of FIGS. 7A-7D, the expandable section of coiled tubing  115  includes an optional sealing member  705  disposed circumferentially around the outer wall of the coiled tubing  115 . Preferably, the sealing member  705  defines two separate sealing rings positioned at the upper and lower ends of the severed section  115 . The sealing member  705  is incorporated onto the coiled tubing  110  at the surface before expansion operations begin. In this way, the patch  703  provides a more secure fluid seal against the surrounding casing  106 . 
     The seal rings  705  are fabricated from a suitable material based upon the service environment that exists within the wellbore  105 . Factors to be considered when selecting a suitable sealing member  705  include the chemicals likely to contact the sealing member, the prolonged impact of hydrocarbon contact on the sealing member, the presence and concentration of erosive compounds such as hydrogen sulfide or chlorine and the pressure and temperature at which the sealing member must operate. In a preferred embodiment, the sealing member  705  is fabricated from an elastomeric material. However, non-elastomeric materials or polymers may be employed as well, so long as they substantially prevent production fluids from passing from the formation and into the wellbore  105  at the point of the patch  703 . 
     The expandable section of coiled tubing  115  may also optionally include a hardened gripping surface (not shown) such as a carbide button. Upon expansion of the coiled tubing  115 , the gripping surface would bite into the surrounding casing  106 , thereby further providing frictional engagement therebetween. 
     An alternate method of the present invention provides for the installation of a patch of coiled tubing through two-trips. Referring to FIG. 8A, a first expansion assembly  800  is run into the wellbore  105 . This first expansion assembly  801  comprises a slip  205 , a rotary motor  210 , a cutting tool  220  and an expander tool  225 . Thus, expansion assembly  801  is comparable to expansion assembly  600  used in the one trip method shown in FIG. 7A-7D. Expansion assembly  801  is run into the wellbore on the coiled tubing  110 . The expansion assembly  801  and attached coiled tubing  110  are positioned at the wellbore depth at which a patch  803  is to be installed. The patch  803  is then installed according to the method outlined above in connection with FIGS. 7A-7D. 
     FIG. 8A shows a severed portion  115  of coiled tubing  110  left in the wellbore  105 . A portion of the severed tubing  115  has been expanded in order to serve as a patch  803 . The first expansion assembly  801  is being retrieved by pulling the coiled tubing  110  from the hole  105 . This represents the first trip. 
     FIG. 8B presents the second trip of the alternate method of the present invention. As shown in FIG. 8B, a second expansion assembly  802  is run into the wellbore  105 . The second expansion assembly  802  comprises a slip  205 , a rotary motor  210 , and a rolling tool  240 . The rolling tool  240  is, in actuality, a second expander tool. The second expansion assembly  802  is run into the wellbore  105  on a working string  810  such as coiled tubing. The rolling tool  240  is similar to the expander tool  230  described in FIGS. 4 and 5, except that rollers  241  of the rolling tool  240  are pitched relative to a center line of the body  232 . Because rollers  241  are angled, the rolling tool  240  is able to “walk” downward along an inner surface of the severed coiled tubing  115 . In this respect, rotation of the rolling tool  240  by the downhole motor  210  causes the rolling tool  240  to self-progress axially from top to bottom, thereby forming a patch  803  which extends the length of the severed tubing  115 . 
     In order to aid the translation of the expander tool  241  in FIG. 8B, an extendable joint, or telescoping member  215  is provided. The telescoping member  215  is positioned below the rotary motor  210 . The telescoping member  215  allows the radially expanding tool  240  to move axially within the wellbore  105  without having to manipulate the depth of the coiled tubing  1010  from the surface. 
     In FIGS. 8A and 8B it can be seen that the severed portion of coiled tubing  115  has been positioned over perforations  850 . In FIG. 8A, the severed portion of coiled tubing  115  has been partially expanded so that the severed portion  115  is in frictional engagement with the inner surface of the casing  106 . In this manner, the severed portion is hung in the wellbore  105  by use of the first expansion assembly  801 . Then, in FIG. 8B, the second expansion assembly  802  is used to more fully expand the severed portion of coiled tubing  115  into frictional engagement with the casing  106 . Thus, a two-trip method for installing a coiled tubing- patch  803  is provided. 
     In yet another aspect of the present invention, an expansion assembly  900  is provided for expanding coiled tubing into surrounding casing. Referring to FIGS. 9A-9D, coiled tubing  110  is run into the wellbore in two sections. The two sections represent an upper section  910  and a lower section  915 . The upper  910  and lower  915  sections of coiled tubing are formed by severing the coiled tubing string at the surface before the tubing is run into the wellbore  105 . Thus, downhole cutting tool  210  is not needed for expansion assembly  900  as the coiled tubing  910  is pre-cut. 
     FIG. 9A depicts an expansion assembly  900  for an alternate one-trip patching method. The components for expansion assembly  900  comprise an upper slip  905 U, a lower slip  905 L, a rotary motor  210 , a pitched rolling tool  240  and an expander tool  230 . The rotary motor  210 , the pitched rolling tool  240  and the expander tool  230  are as described for the one and two-trip methods disclosed above. However, expansion assembly  900  differs in that it employs a dual slip system. The upper slip  905 U engages the upper section of coiled tubing  910 , while the lower slip  905 L engages the lower section of coiled tubing  915 . The lower section of coiled tubing  915  will be expanded to serve as the patch  903  for this alternate method. 
     As shown in FIG. 9A, the upper  910  and lower  915  sections of coiled tubing are retained adjacent to each other with a point of contact therebetween. At the surface, the coiled tubing  910  is partially introduced into the wellbore  105 , and then severed. This creates the upper section  910  above the surface and the lower section  915  at least partially disposed within the wellbore  105 . Slip  905 U is actuated to engage the upper section  910  of coiled tubing, and slip  905 L is actuated to engage the lower section  915  of coiled tubing. Slips  905 U and  905 L may be separate slips, or are preferably a single slip have slip members that are de-activated independently. 
     When the slips  905 U and  905 L are actuated, the expansion assembly  900  is run into and located within the wellbore  105  adjacent one or more perforations  950  to be isolated as illustrated in FIG.  9 A. It is understood, however, that the patching operation may be employed to simply patch a corroded section of tubular without perforations. 
     FIG. 9B is a section view showing a portion of the coiled tubing  915  expanded by the expander tool  230 . The expander tool  230  is actuated to form an annular extension  903  of the coiled tubing  915 . Once the lower section  915  of coiled tubing has been expanded, thus anchoring the lower section  915  to the casing  106 , the lower slip  905 L is de-activated. This releases the lower section  915  of coiled tubing from the expansion assembly  900 . 
     The next set in this alternate patching method is the raising of the expansion assembly  900 . In this respect, the upper section  910  of coiled tubing is lifted so as to align the rolling tool  240  with the upper end of the lower section of coiled tubing  915 . Once this alignment is made, the rolling tool  240  is activated. As discussed above, rotation of the pitched rolling tool  240  causes the tool  240  to “walk” downward along an inner surface of the severed coiled tubing  915 . In this respect, rotation of the rolling tool  240  by the rotary motor  210  causes the rolling tool  240  to self-progress axially from top to bottom, thereby forming a patch  903  which extends the length of the severed tubing  915 . 
     FIG. 9C is a section view showing the coiled tubing  915  being expanded along its length by the rolling tool  240 . The upper slip  905 U is still engaged to the upper section  910  of coiled tubing. The rolling tool  240  is activated and allowed to “walk” and expand the inner surface of the lower section  915  of tubing. As the rolling tool  240  expands the inner diameter of the lower section  915  of tubing, the expansion assembly  900  and upper section  910  of coiled tubing pass through the expanded diameter of the lower section  915  of tubing. 
     FIG. 9D shows the lower section of coiled tubing  915  completely expanded into the casing  106 . At this stage, the coiled tubing patch  903  is fully installed. In this respect, the patch  903  is now synonymous with the lower section of tubing  915 . The severed upper portion of coiled tubing  910  is being removed from the wellbore. 
     In yet another aspect of the present invention, a one-trip method for installing a coiled tubing patch is provided which utilizes an extendable or telescoping member to vertically translate the roller tool  240 . The telescoping member  215  is depicted in FIG. 10A, and is positioned below the rotary motor  210 . The telescoping member  215  allows the radially expanding tool  230  to move axially within the wellbore  105  without having to manipulate the depth of the coiled tubing  1010  from the surface. 
     It is noted that the telescoping member  215  can be employed in any of the methods which fall within the scope of the present invention. In this respect, the makeup joint shown as  215  in the various figures herein may constitute a telescoping member. The telescoping member  215  may be electrically operated so as to mechanically move the expanding tools  230  and  240 . Alternatively, the telescoping member  215  may be actuated through hydraulic pressure applied through the coiled tubing  1010  from the surface. Alternatively, the telescoping member  215  may be fixed in a recessed position by a shearable screw (not shown) or other releasable connection, until the roller tool  240  is actuated. In this arrangement, actuation of the roller tool  240  (shown in FIGS. 9A-9D) would cause the releasable connection to release, thereby allowing the telescoping member  215  to extend while the roller tool  240  “walks” itself. The roller tool  240  preferably has rollers  241  which are pitched to walk downward upon rotation. However, the pitch of the rollers  241  may be oriented to cause the roller tool  240  to walk upward. 
     It is also noted that the use of an electrically or hydraulically actuated telescoping member  215  will remove the necessity for the roller tool  240 . In this regard, the telescoping member  215  would itself translate the expander tool  230 , causing the coiled tubing  1015  to be expanded along a desired length. In FIG. 10A, the pitched roller tool is removed. Thus, the expansion assembly  1000  does not employ either a downhole cutting instrument or a pitched roller tool. 
     FIG.  10 A and FIG. 10B demonstrate the operation of the telescoping member  215 . In FIG. 10A, the telescoping member  215  is extended so that the expander tool  230  is translated downward to the bottom end of the lower section of tubing  1015 . In FIG. 10B, the telescoping member  215  is being retracted so as to raise the expander tool  230 . The upper section of tubing  1010  is also being optionally raised to further raise the expander tool  230  within the lower section of tubing  1015 . It is noted that a more uniform expansion and patch job is obtained by translating the expander tool  230  from downhole, rather than by trying to pull the coiled tubing  1010  from the surface. In this respect, downhole translation avoids problems associated with pipe stretch and recoil which interfere with a smooth and uniform patch. 
     Once the coiled tubing  1015  has been satisfactorily expanded to form a patch, the upper section of coiled tubing  1010  is retrieved from the hole  105 . The expansion assembly  1000  is thereby removed from the hole  105  due to the connection with slip  905 U. 
     The wellbore arrangements shown in FIGS. 8B and 9D present a section of coiled tubing completely expanded into a surrounding string of casing along a desired length. In this way, a coiled tubing patch is formed. Such a coiled tubing patch may be used not only to support casing or sand screen, but also to seal perforations. FIG. 11A is a cross-sectional view of a wellbore  105  having a section of coiled tubing  115  expanded therein. In this view, the section of coiled tubing has been completely expanded along a desired length in order to seal off perforations  125  within the casing  106  and surrounding formation  107 . 
     FIG. 11B presents an alternate method for installing a patch. FIG. 11B shows a cross-sectional view of a wellbore  105  having a section of coiled tubing  115  expanded therein. In this view, the coiled tubing  115  has been expanded at points above and below perforations  125  within the casing  106  and surrounding formation  107  in order to form a straddle. 
     FIG. 11C presents yet an alternate method for installing a patch. FIG. 11C shows a cross-section view of a wellbore  105  having a section of coiled tubing  115  expanded therein. In this view, the coiled tubing  115  has been expanded at a point above a perforated portion of casing  106  and surrounding formation  107  in order to form a velocity tube. 
     While the foregoing is directed to the preferred embodiment of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.