Patent Publication Number: US-6712149-B2

Title: Apparatus and method for spacing out of offshore wells

Description:
This application claims the benefit of U.S. Provisional Application No. 60/262,745, filed on Jan. 19, 2001. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates generally to subsurface tools used in the completion of subterranean wells and, more particularly, provides an apparatus and method for use in spacing out tubular strings and components within a wellbore. 
     2. Description of Related Art 
     Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, i.e., a reservoir, by drilling a well that penetrates a hydrocarbon-bearing formation. Once a wellbore has been drilled, the well must be completed before hydrocarbons can be produced from the well. A completion involves the design, selection, and installation of equipment and materials in or around the wellbore for conveying, pumping, or controlling the production or injection of fluids. After the well has been completed, the production of oil and gas can begin. 
     Typically, one of the final steps taken in the completion of a well is the running into the well of the production tubing. Once the production tubing is inserted into the well, the bottom of the tubing string may need to be located at a certain position in relation to other downhole equipment, such as being inserted into a polished bore receptacle of a packer that had been previously set. Just as the bottom of the tubing string needs to be located in a predetermined depth, likewise the top of the tubing string has to be located so as to properly “land” the tubing hanger within the wellhead. In order for both the top and bottom of the tubing string to be in their proper locations, the length of the tubing string is measured and controlled. This operation is called the “spacing out” of the well. 
     For wells drilled on land, the spacing out of the production tubing is a relatively simple task. The tubing is run into the well to the depth of the packer until contact with the packer is indicated by a decrease in the weight of the tubing string. At a predetermined “slack off” weight, the tubing is marked and measured. The upper joint of tubing is removed and replaced with one or more shorter tubing sections, often called “subs”, that will make the overall tubing string the length needed for the proper well space out. Since the wellhead, completion unit and personnel are located at the surface, the spacing out of the tubing string is usually a minor task. 
     On wells that are drilled offshore that contain a subsea wellhead, the operation of spacing out a well can be difficult. The wellhead where the tubing must be landed is located on the ocean floor, not where the rig and personnel are located. For wells being completed from fixed platforms, the distance from the rig floor to the wellhead can be measured and compensated for. One method is to run the tubing into the well until the required slack off weight is seen. Then rather than just the top joint being removed, the length of tubing from the rig floor to the wellhead on the ocean floor must be pulled to enable the proper space out to be made. After the proper adjustments are made and the tubing hanger is attached, the modified tubing string length will be run back into the well. For example, a well drilled in a water depth of 2,000 feet that needs an adjustment of 10 feet for proper space out, would require the pulling and subsequent re-running of the 2,000 feet of tubing, for a total handling of 4,000 feet of tubing. Alternately, the tubing hanger can be attached to the tubing string on the initial run into the well at a location that is estimated to be correct. If the location is within the variance of the downhole tool, such as the length of the polished bore receptacle, the tubing will not need to be pulled and adjusted. Using specialized tools, such as packers with longer than usual polished bore receptacles and tubing seal assemblies with extra length and multiple seals, will increase the possibility of success with this alternate method, but will also increase the material cost incurred. 
     Wells being completed from floating drilling rigs such as semisubmersibles or drillships pose additional problems. The “heave” of the floating rig, along with variations in the positioning of the rig over the well, results in the distance from the rig floor to the wellhead not being a fixed length (i.e., being a variable length). This length can vary by as much as three feet or more, depending on tidal and wave conditions, which can make the methods of spacing out mentioned above unworkable, difficult or time consuming to perform. The amount of heave can also vary depending on the age, design and level of sophistication of the rig positioning system. To compensate for the rig heave, additional equipment, such as expansion joints, sliding sleeves, extended seal assembly lengths and multiple seals have been employed. 
     There is a need for improved tools and methods to enable the proper spacing out of offshore wells. 
     SUMMARY OF THE INVENTION 
     One embodiment of the present invention is a system for use in spacing components within a wellbore. The system comprises a well casing comprising at least one profile, the profile capable of being positioned at a known location within the wellbore and adapted to indicate the location of at least one component inserted into the wellbore. 
     Another embodiment of the present invention comprises an apparatus for use in spacing out tubular strings within a well comprising a casing having an inner wall where the casing includes at least one profile disposed within the inner wall. A landing tool is linked to well tubing and is sized so as to seat within the profile. A tubing hanger is attached to the well tubing, the tubing hanger being capable of landing within a wellhead. When the landing tool is seated within the profile, the length of well tubing needed to land the tubing hanger within the wellhead can be determined. The tubing string can be inserted within the well. The distance between the wellhead and the profile can be known. 
     The casing can comprise an upper profile and a lower profile and the distance between the upper profile and the lower profile can be known. The landing tool and the upper profile are capable of being in a releasably seated configuration. 
     Yet another embodiment of the invention can be used for the spacing out of tubular strings within a well that comprises a casing having an inner wall, the casing comprising an upper profile and a lower profile. A well tubing is movable longitudinally within the casing and a landing tool is linked to the well tubing. The landing tool can comprise seating projections that are adapted to sequentially seat in the upper profile and the lower profile. The landing tool and seating projections can be adapted to reversibly seat in the upper profile, allowing movement of the landing tool in either an upward or downward direction. The landing tool, seating projections and lower profile can be adapted such that when the landing tool is seated within the lower profile, the landing tool is restricted from any movement in a downward direction but can be unseated from the lower profile and moved in an upward direction. The landing tool and seating projections can be adapted to release from the upper profile when a predetermined slack off weight is exceeded. When the landing tool is seated within the upper profile, the length of well tubing needed to space out the well tubing can be determined. 
     Still another embodiment of the invention is a method of spacing components within a wellbore. The method comprises providing a well casing comprising at least one profile and inserting at least one component within the wellbore wherein at least one component can releasably engage with the at least one profile. The effects of the engagement of at least one component with the at least one profile are observed and the amount of component movement required to obtain a desired component placement within the wellbore is determined. 
     An alternate embodiment of the invention is a method of spacing out a tubular string within a well having a wellhead. This method comprises providing a casing string located within the well, the casing string having an inner wall and at least one profile within the casing inner wall. The casing can include an upper profile, and the profiles can be located at known distances apart from each other and from the wellhead. A tubular string linked to a landing tool is inserted into the well. The landing tool is seated within the upper profile and the correct tubular length required to properly space out the well is determined. The steps in the method can include attaching the landing tool to the tubular string to be spaced out and the landing tool can be capable of seating within the profiles. The method can further include inserting the tubular string to a depth where the landing tool seats within the upper profile, unseating the landing tool from the upper profile, modifying the length of the tubular string, attaching a tubing hanger to the tubular string and inserting the tubular string into the well to a depth where the tubing hanger is disposed within the wellhead. 
     When the tubing hanger is disposed within the wellhead, the landing tool can be seated within one of the profiles other than the upper profile. The well can further comprise a packer set within the casing string and the tubular string can further comprise a seal assembly capable of being seated within the packer. 
     Yet another embodiment of the invention is a method of spacing out a tubing string within a wellhead of an offshore well comprising providing a casing string having a first profile, inserting a tubing string within the well having a landing tool that can engage with the first profile, inserting the tubing string until the landing tool engages with the first profile. The length of tubing string needed for proper tubing space out can then be determined, the landing tool disengaged from the first profile, and the tubing string altered to achieve a predetermined length. A tubing hanger is then attached to the tubing string and the tubing string inserted to the depth where the tubing hanger is properly positioned within the wellhead. 
     The well can further comprise a packer set within the casing string and the tubular string can further comprise a seal assembly and the seal assembly can be capable of being seated within the packer. The disengaging of the landing tool from the first profile can be achieved by imposing a predetermined slack off weight onto the tubing string. 
     The casing string can comprise a second profile and when the tubing hanger is positioned within the wellhead, the tubing string can be spaced out so that the landing tool is engaged with the second landing profile. The landing tool in conjunction with the second landing profile can be capable of radially orienting the tubing string in relation to the casing string. The tubing string can contain an extension tool that allows the extension of the tubing string below the landing tool. The extension tool can enable the extension of more than one tubing string below the landing tool. The well can comprise at least one lateral wellbore and two tubing strings extend from the extension tool and the two tubing strings each enter separate wellbores. 
     Still another embodiment of the invention is a method of completing a well comprising providing a well casing comprising at least one profile on its inner wall and inserting the well casing within a wellbore comprising at least one lateral wellbore. At least one component is inserted within the wellbore on a tubular string, the at least one component comprising at least one landing tool that can releasably engage with the at least one profile. The effects of the engagement of at least one landing tool with the at least one profile are observed and the amount of tubular string movement required to obtain a desired component placement within the wellbore is determined. 
     Another embodiment is a method of completing a well comprising providing a well casing comprising at least one profile on its inner wall and inserting the well casing into a wellbore, the wellbore comprising at least one lateral wellbore. At least one landing tool that can releasably engage with the at least one profile is inserted into the wellbore on a tubular string, the at least one landing tool comprising at least one lower tubing string capable of extending from the at least one landing tool. The effects of the engagement of at least one landing tool with the at least one profile are observed and the amount of tubular string movement required to obtain a desired component placement within the wellbore is determined, the desired component placement comprising the landing of a tubing hanger within a wellhead. At least one lower tubing string is extended from the extension member into at least one lateral wellbore. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     FIG. 1 is a schematic of a typical offshore well. 
     FIG. 2 shows an embodiment of the present invention. 
     FIG. 3 shows an offshore well schematic in which the tubing string comprises an embodiment of the current invention. 
     FIG. 4 shows an offshore well schematic in which the tubing has been properly spaced out utilizing an embodiment of the present invention. 
     FIG. 5 shows an offshore well schematic which contains a lateral wellbore in which the tubing has been spaced out utilizing an embodiment of the present invention. 
     FIG. 6 shows a multilateral offshore well schematic in which the tubing has been spaced out utilizing an embodiment of the present invention. 
     FIG. 7 shows another multilateral offshore well schematic in which the tubing has been spaced out utilizing an embodiment of the present invention. 
     FIG. 8 shows an offshore well schematic including an embodiment of the present invention in which the landing tool is seated in the lower profile, but the deployed element has not yet been extended to the target location. 
     FIG. 9 shows an offshore well schematic including an embodiment of the present invention in which the landing tool is seated in the lower profile, and the deployed element has already been extended to the target location. 
    
    
     DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS 
     Referring to FIG. 1, an offshore well, shown generally as  10  is drilled and completed by an offshore drilling rig  12  that is located at the water surface  14 . The wellhead  16  is located at or near the ocean bottom (i.e., ocean floor)  18 . A wellbore  20  is drilled into a subterranean zone  22  and a casing string  24  is inserted and cemented in place to stabilize the wellbore  20 . A tubing string  30 , comprising a tubing hanger  34 , is run from the rig  12 , through the wellhead  16  and down the well  10 . The tubing hanger  34  is located at the wellhead  16  and may enable the sealing between the wellhead  16  and the tubing string  30 . 
     The tubing string  30  includes a deployed element  31  that is lowered to a target location  35  on the casing string  24 . The deployed element  31  shown in the Figures is a seal assembly  32 , and the target location  35  shown in the Figures is the receptacle  28  of a packer  26  that is set within the casing string  24 . The seal assembly  32  is adapted to mate with the receptacle  28  and provides a seal between the tubing string  30  and the receptacle  28 /packer  26 . 
     Unless otherwise described herein, a deployed element  31  for purposes of this application is an element lowered down a well that must be located at a particular spot in the well (the target location  35 ) when the tubing hanger  34  reaches the wellhead  16  (where space out is critical). In addition to the seal assembly  32  shown in the Figures, the deployed element  31  may also comprise a packer, perforating gun, a specific section of the tubing string, or one of the elements of a female/male mating mechanism. In addition to the receptacle  28  shown in the Figures, the target location  35  may also comprise a specific section of the casing string  24  or one of the elements of a female/male mating mechanism. 
     FIG. 2 shows an embodiment of the invention in which a well  10  having a casing string  24  comprises an upper profile  36  and a lower profile  38 . The distance between the wellhead  16  and the upper profile  36  is a known length  40 . The distance between the upper profile  36  and the lower profile  38  is a known length  42 . The packer  26  (target location  35 ) is at a known distance  44  below the lower profile  38 . The upper profile  36 , as shown, has angled recesses  46 , while the lower profile  38 , as shown, has one or more straight recesses  48 . Other types, styles and shapes of recesses can be used for the various profiles. 
     FIG. 3 shows the well as described above and shown in FIG. 2, but including a tubing string  30  that comprises a landing tool  50  that can seat in both the upper profile  36  and the lower profile  38 . The tubing string  30  also comprises a seal assembly  32  (deployed element  31 ) that is located at a known distance below the landing tool  50 . In this example the seal assembly  32  (deployed element  31 ) is located at a distance below the landing tool  50  that is the same as the distance  44  between the packer  26  (target location  35 ) and the lower profile  38 . In this example, when the landing tool  50  is landed within the lower profile  38 , the seal assembly  32  (deployed element  31 ) will be mated with the receptacle  28  of the packer  26  (target location  35 ). 
     In another embodiment (see FIGS. 8 and 9, for instance), the deployed element  31  (seal assembly  32 ) and the tubing can be designed to enable the extension of the tubing and deployed element  31  (seal assembly  32 ) from the landing tool  50  or from another tool attached to the tubing. Thus, the tubing and deployed element  31  (seal assembly  32 ) can be further extended into the wellbore after the landing tool  50  has been landed in the lower profile  38  in order to extend the deployed element  31  to the target casing  35 . This embodiment will be discussed in greater detail later in the specification. 
     The landing tool  50  can comprise a number of various embodiments. Examples of alternate embodiments include a packer type arrangement with elastomeric protrusions that expand into the casing profiles; a bow spring device, such as a centralizer, that will also expand into the casing profiles; and a mechanical device having latching “dogs” or spring loaded keys that expand into the profiles, but are able to be disengaged when needed. These are just a few examples of the many different landing tool  50  embodiments that could be used in conjunction with casing profiles. In the embodiment shown in the Figures, the landing tool  50  includes at least one spring loaded dog  51 . The dog  51  and upper profile  36  can be configured to releasably mate with each other. The dog  51  and lower profile  38  can be configured to securely mate with each other. The dog  51  and lower profile  38  can also be configured to enable the release of the dog  51  in one direction, such as with an upward movement, while restricting release in another direction, such as with a downward movement. 
     The primary service of the landing profiles can be to assist in the proper placement of the tubing hanger  34  within the wellhead  16 . As the tubing string  30  is inserted into the wellbore  20  the landing tool  50  will initially seat within the upper profile  36 . The seating of the landing tool  50  within the upper profile  36  will be seen at the rig  12  as a reduction in the tubing string weight, referred as a “slack off” of the string weight. Once the landing tool  50  is seated in the upper profile  36 , the tubing length adjustment needed to land the tubing hanger  34  within the wellhead  16  and the deployed element  31  at the target location  35  can be determined (providing proper space out). By keeping a tally of the lengths of the tubing joints being run into the well, the distance  52  between the rig  12  and the upper profile  36  can be determined. Since the distance  40  from the wellhead  16  to the upper profile  36  is known, the distance  54  from the rig  12  to the wellhead  16 , essentially the water depth, can be calculated (distance  54  equals distance  52  minus distance  40 ). Distance  54  may also be calculated by other methods. 
     In order to properly space the tubing hanger  34  (shown in FIG. 4) within the wellhead  16 , the length of additional tubing to be run or the length of tubing to be removed prior to adding the tubing hanger  34  to the tubing string  30  needs to be determined. The length of tubing adjustment needed prior to attaching the tubing hanger  34  to the tubing string  30  is the difference between the distance  42  between the two profiles  36 ,  38  and the distance  54  from the rig  12  to the wellhead  16  (length adjustment equals distance  42  minus distance  54 ). It is noted that in the embodiment in which the deployed element  31  is fixed to (does not extend from) the landing tool  50 , the distance  42  is equal to the distance  100  from the deployed element  31  to the target location  35  (when the landing tool  50  is seated in the upper profile  36 ). 
     If the distance  42  is greater than the distance  54 , the difference between them will be the amount of additional tubing that will need to be added prior to attaching the tubing hanger  34 . If the distance  42  equals distance  54 , no adjustment in the tubing length is needed prior to attachment of the tubing hanger  34 . If the distance  42  is less than distance  54 , the difference between them is the length of tubing needing to be removed prior to the attachment of the tubing hanger  34 . Once the tubing hanger  34  is attached, the tubing string  30  can be further inserted into the wellbore  20  up to an additional length equal to the distance  54  from the rig  12  to the wellhead  16 . The tubing hanger  34  can then be landed within the wellhead  16 , resulting in the desired spacing out of the tubing string  30  and any attachments to it. 
     It is preferable not to remove tubing from the well in order to properly space out the tubing hanger  34 , as is the case when the distance  42  is less than the distance  54 . Nevertheless, even in these circumstances, the use of the present invention is beneficial. Prior to the landing tool  50  seating in the upper profile  36 , an operator may install the tubing hanger  34  on the tubing string  30  at the location he/she estimates to provide the proper space out. Subsequently, as the tubing string  30  is continued to be deployed, the landing tool  50  will land on the upper profile  36 . The landing of the landing tool  50  on the upper profile  36  (and the subsequent “slack off” of the string weight) will provide a beneficial check to determine whether the estimated tubing hanger  34  placement is within the tolerances for the particular completion. This check advantageously occurs prior to the complete deployment of the completion. 
     This invention can also be used and the same calculations and results can be obtained without having a lower profile  38 , if that is desired, as long as the distance  100  between the packer  26  (target location  35 ) and the deployed element  31  (when the landing tool  50  is seated in the upper profile  36 ) is known. The distance  100  can be calculated by a variety of methods, including by subtracting the distance between the landing tool  50  and the deployed element  31  from the distance between the target location  35  and the upper profile  36 . The upper profile  36  would then provide a reference point from which the location of the tubing hanger  34  can be determined in order to land the tubing hanger  34  on the wellhead  16  and the deployed element  31  at the target location  35  (proper space out). In this case, when the landing tool  50  is seated in the upper profile  36 , the length of tubing adjustment needed prior to attaching the tubing hanger  34  is the difference between the distance  100  and the distance  54 . This equation is adequate however, only if the deployed element  31  is fixed to (does not extend from) the landing tool  50 . 
     In those embodiments including a lower profile  38 , the lower profile  38  can assist in holding the tubing string  30  in place, can be designed to radially orient the tubing or a well tool, and/or can be designed to additionally act as a safety stop, preventing the tubing string  30  from going further into the wellbore than is desired. The lower profile  38  can be very useful when used to radially orient a well tool. In this manner, for example, the lower profile  38  can orient tubing and attachments (including the deployed element  31 ) in both single wellbores and multilateral wells. Orientation by the lower profile  38  can be achieved by inclusion of a muleshoe or other orienting device in or proximate the lower profile  38 . 
     As shown in FIGS. 5-7, this invention may be used in multilateral wells having a main wellbore  20  and one or more lateral wellbores  60 ,  66 . In these embodiments, multiple tubing strings  64  and  68  can protrude from the landing tool  50 , each including a deployed element  31  to be located at a target location  35  within the relevant lateral wellbore  60 ,  66 . This invention can be used in multilateral wells that include either just the upper profile  36  or both the upper and lower profiles  36 ,  38 . 
     The same type of methodology as described above can be used to properly locate the landing tool  50  within the lower profile  38  when the tubing hanger  34  is landed within the wellhead  16  (providing proper space out). As mentioned above, the lower profile  38  can act in conjunction with the landing tool  50  to locate and/or orient the tubing string  30  and any attachments to it. It is noted that if the aim is to simply land the landing tool  50  on the lower profile  38 , then the landing tool  50  acts as the deployed element  31  and the lower profile  38  acts as the target location  35 . 
     In one embodiment of the invention, which is schematically shown in FIGS. 8-9, the deployed element  31  and the tubing string  30  are adapted to be extended once the landing tool  50  is seated in the lower profile  38 , thereby bringing the deployed element  31  to the target location  35  and the tubing hanger  34  on the wellhead  16 . In this embodiment, the landing tool  50  is seated in the lower profile  38  before the tubing hanger  34  is landed on the wellhead  16 . Premature extension of the tubing string  30  is prevented by, for instance, shear pins/rings  90  or locking dogs, which initially connect the tubing string  30  to the landing tool  50 . Note that the shear pins/rings  90  should be rated higher than the force necessary to pass the landing tool  50  through the upper profile  36 . Once the landing tool  50  is seated on the lower profile  38 , force is applied at the surface to the tubing string  30 . Since the lower profile  38  is constructed to securely mate with the landing tool  50 , such additional force will not move the landing tool  50  from the lower profile  38 . However, the additional force on the tubing (if high enough) will enable the extension of the tubing string  30  by releasing the tubing string  30  from the landing tool  50  (by, for example, shearing the shear pins/rings  90  or uncovering the locking dogs). Once released, the tubing string  30  extends downwardly until the deployed element  31  is at the target location  35  and the tubing hanger  34  is at the wellhead  16 . For this embodiment, the relevant calculations previously discussed would need to take into account the extension distance of the tubing string  30 . Thus, in this case, when the landing tool  50  is seated in the upper profile  36 , the length of tubing adjustment needed prior to attaching the tubing hanger  34  is the difference between the distance  42  and the distance  54 , plus the extension distance of the tubing string  30 . Another way to express the same equation is the difference between the distance  100  and the distance  54 , (as illustrated in FIG.  3 ). 
     Examples of landing tools  50  that can provide the additional extension of this embodiment are described in U.S. Pat. No. 6,311,776 entitled “Dual Diverter and Orientation Device for Multilateral Completions and Method” by Pringle, Milligan, and Coon which issued on Nov. 6, 2001 and is incorporated herein by reference. This patent describes landing tools that are used with multilateral wells so that multiple tubing strings are extended from the landing tool. It is understood that the same extension mechanism described in such applications can also be used in single bore wells to extend a single tubing string. 
     It is noted that the extension embodiment can also be incorporated into systems that include only an upper profile  36  and not a lower profile  38 . In this case, the length of tubing adjustment needed prior to attaching the tubing hanger  34  is the difference between the distance  100  and the distance  54 . 
     In another embodiment (not shown), the tubing hanger  34  first lands on the wellhead  16 . Subsequently, the lower tubing string underneath the landing tool  50  is extended until the deployed element  31  is at the target location  35 . Such extension of the lower tubing string underneath the landing tool  50  can be achieved by, for example, a hydraulic mechanism located downhole or further mechanical manipulation from the surface. In this case, the length of tubing adjustment needed prior to attaching the tubing hanger  34  is the difference between the distance  100  and the distance  54 , minus the extension distance of the lower tubing string. 
     This method of landing a tool and then extending a tubing string from the tool can also be used to extend multiple tubing branches. One possibility is with a dual tubing string where one extended tubing string connects with a packer within the main wellbore and a separate tubing string connects with a lateral wellbore coming off from the main wellbore. Another possibility is where a dual tubing string is extended and each tubing string extends into a separate lateral borehole. The landing tools described in the above referenced U.S. Pat. No. 6,311,776 enables the extension of multiple tubing strings. 
     As shown in FIG. 2, the upper profile  36  can be constructed with a particular configuration of recesses, such as an angled recess  46  that enables the landing tool  50  to seat and remain within the upper profile  36  so that the tubing weight slack off can be seen at the rig  12 . But the upper profile  36  is also designed to allow the landing tool  50  to unseat from the upper profile  36  when the tubing weight slack off exceeds a certain amount. For example, the landing tool  50 , when seated within the upper profile  36 , may be designed to withstand a slack off weight of 10,000 pounds and remain seated, but to release and travel further down the wellbore  20  once the slack off weight exceeds 20,000 pounds. 
     The lower profile  38  can be constructed with a different particular configuration than the upper profile  36 , such as with at least one straight recess  48  that enables the landing tool  50  to seat within the lower profile  38 , but will not allow the landing tool  50  to pass through the lower profile  38 , as it could with the upper profile  36 . The lower profile  38  can therefore act as a stop and can be made to not allow the tubing string  30  and/or any attachments to proceed further down the wellbore  16  than they were designed for, thereby avoiding potential damage. The lower profile  38  can be designed to enable the landing tool  50  to be released (such as by shearing or mechanical unlocking) from the lower profile  38  and be moved in an upward direction, to permit the removal of the tubing string  30  from the wellbore  20 . 
     FIG. 4 shows an embodiment of the invention having the seal assembly  32  seated within the receptacle  28  of the packer  26 , the landing tool  50  seated within the lower profile  38 , and the tubing hanger  34  landed at the proper location within the wellhead  16 . 
     FIG. 5 shows a well having a lateral wellbore  60  extending from the main wellbore  20 . This illustrates the possibility of using an embodiment of the present invention to properly land the tubing hanger  34  within the wellhead  16 , orient and land the landing tool  50  within the lower profile  38 , and then if required (optional) extend one tubing string  62  into the main wellbore  20  and extend a second tubing string  64  into a lateral wellbore  60 . 
     FIG. 6 shows a well having two lateral wellbores  60 ,  66  extending from the main wellbore  20 . This illustrates the possibility of using an embodiment of the present invention to properly land the tubing hanger  34  within the wellhead  16 , orient and land the landing tool  50  within the lower profile  38 , and then if required (optional) extend multiple tubing strings  64 ,  68  into separate lateral wellbores  60 ,  66 . 
     FIG. 7 is similar to the FIG. 6, except that FIG. 7 shows the use of the present invention with an integral Level  6  multilateral junction  104  described, for example, in U.S. Pat. No. 5,944,107, incorporated herein by reference. 
     The discussion and illustrations within this application may refer to a vertical main wellbore that has casing cemented in place. The present invention can also be utilized to complete wells that are not cased entirely and likewise to main wellbores that have an orientation that is deviated from vertical. 
     The particular embodiments disclosed herein are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction, operation, materials of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. Accordingly, the invention is therefore to be limited only by the scope of the following claims.