Abstract:
A method and apparatus for completing a junction of plural wellbores includes providing a casing junction assembly having plural outlets for communicating with corresponding wellbores. A tool has plural extendable conduits for engaging in the outlets. The casing junction assembly has an integral diverter with guiding surfaces to guide the conduits into the outlets.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS  
       [0001]    This claims the benefit under 35 U.S.C. §119(e) to U.S. Provisional Application Serial No. 60/262,899, filed Jan. 19, 2001. This is also a continuation-in-part of U.S. Ser. No. 09/518,365, filed Mar. 3, 2000, which is a continuation of U.S. Pat. No. 6,056,059, which is a continuation-in-part of U.S. Pat. No. 5,944,107, which claims priority under 35 U.S.C. §119(e) to U.S. Provisional Application Nos. 60/013,227, filed Mar. 11, 1996, 60/025,033, filed Aug. 27, 1996, and 60/022,781, filed Jul. 30, 1996, all hereby incorporated by reference. 
     
    
     
       TECHNICAL FIELD  
         [0002]    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 multilateral completions.  
         BACKGROUND  
         [0003]    Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, such as a reservoir, by drilling a well that penetrates the 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.  
           [0004]    It is increasingly commonplace within the industry to drill and complete multilateral wells. These are wells that contain one or more lateral wellbores that extend out from a main wellbore running to the earth&#39;s surface. These lateral wellbores can increase the production capacity and ultimate recovery from a single productive formation, or may allow multiple reservoirs to be depleted from a single well. This is particularly true when drilling from an offshore platform where multiple wells must be drilled to cover the great expenses of offshore drilling.  
           [0005]    Standard completion practices are to complete the lateral wellbores separately. This requires separate trips into the well to perform the completion operations, with each trip resulting in significant costs of money and time.  
           [0006]    There is a need for apparatus and methods to reduce the time and expense of completing multilateral wells.  
         SUMMARY OF THE INVENTION  
         [0007]    In general, according to an embodiment, a downhole assembly comprises a casing junction assembly adapted to be installed at a junction of plural wellbores, the casing junction assembly defining plural outlets to respective plural lateral wellbores, and the casing junction assembly having an integrated diverter providing plural guide surfaces proximate corresponding outlets.  
           [0008]    A method of completing a well at a junction of plural wellbores comprises providing a casing junction assembly having plural outlets for establishing communication with respective plural wellbores, and providing a diverter integrated with the casing assembly, with the diverter having plural guide surfaces. A tool having plural conduits is engaged with the casing junction assembly, and the conduits are guided into respective outlets with the plural guide surfaces.  
           [0009]    Other or alternative features will become apparent from the following description, from the drawings, and from the claims. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0010]    [0010]FIG. 1 is a schematic of an example embodiment of a casing assembly installed in a multilateral well.  
         [0011]    FIGS.  2 - 4  show further completion of the multilateral well of FIG. 1.  
         [0012]    [0012]FIG. 5 shows an alternate embodiment of the invention.  
         [0013]    FIGS.  6 - 10  show longitudinal and cross section illustrations of various embodiments of the present invention.  
         [0014]    FIGS.  11 - 13  show alternate embodiments of the present invention within a multilateral well.  
         [0015]    FIGS.  14 - 15  show section views of an embodiment of the casing junction.  
         [0016]    FIGS.  16 - 22  show an alternate embodiment of a landing tool.  
         [0017]    [0017]FIG. 23 shows an alternate embodiment of the present invention.  
         [0018]    FIGS.  24 - 25  show another longitudinal section view of the landing tool illustrated in FIGS.  16 - 22 . 
     
    
     DETAILED DESCRIPTION  
       [0019]    In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled 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.  
         [0020]    As used here, the terms “up” and “down”; “upper” and “lower”; “upwardly” and downwardly”; “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly described some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationship as appropriate.  
         [0021]    Referring to FIG. 1, a multilateral well, shown generally as  10 , includes a main wellbore  12  that is drilled into a subterranean zone  14 . The main wellbore  12  is stabilized by inserting a string of casing  20  that is cemented  22  in place. The casing  20  may include a casing junction assembly  28 , which may be cemented in place concurrently with the remainder of the casing  20 . A first lateral wellbore  16  and a second lateral wellbore  18  are shown that have been drilled from the main wellbore  12  and from the casing junction  28  assembly. The lateral wellbores may have smaller diameters than the main wellbore. However, that is not necessarily the case in other embodiments. The casing junction assembly  28  thus completes a junction of plural wellbores. As used here, the term “wellbore” or “bore” refers to either a main wellbore or a lateral wellbore.  
         [0022]    [0022]FIG. 2 shows a multilateral well  10  having a casing junction assembly  28  set within the main wellbore  12  and other junction equipment installed in the casing junction assembly  28 . The casing junction assembly  28  provides the connection of the main wellbore  12  and the lateral wellbores  16 ,  18 . The casing junction assembly  28  is attached to the remainder of the casing  20  and run into the well and cemented with the remainder of the casing  20  (cement layer shown at  22 ). The casing junction  28  can be run into the well in a collapsed or collapsed configuration and expanded to its final configuration prior to being cemented in place, as described in U.S. Pat. No. 6,283,216, which application is incorporated herein by reference.  
         [0023]    The lateral wellbores  16  and  18  are drilled after the casing  20  and the casing junction  28  are cemented in place. Once a lateral wellbore is drilled, a liner  96 ,  98  can be run into the lateral wellbore  16 ,  18  and set in place with a packer type device, also known as a liner hanger. Packers  24 ,  26  attached to liners  96 ,  98  are shown located within the first and second branch legs  15 ,  17  of the casing junction assembly  28 . In alternative embodiments, the packers  24 ,  26  can be set directly within the first and second lateral wellbores  16 ,  18 . The first and second legs  15 ,  17  are aligned to communicate with the first and second lateral wellbores  16 ,  18 .  
         [0024]    The casing junction assembly  28  includes a first guide surface  30  that serves to deflect items towards the first leg  15  and the first lateral wellbore  16 , and a second guide surface  32  that serves to deflect items towards the second leg  17  and the second lateral wellbore  18 . The casing junction assembly  28  shown also includes a projection  34  that extends upwardly. The first guide surface  30 , second guide surface  32 , and projection  34  are part of a diverter  68 . Since the casing junction assembly  28  can be symmetrical in shape and includes the diverter  68 , a separate tool, such as a typical whipstock, is not needed to deflect a tubing string into each of the legs and lateral wellbores. The packers  24 ,  26  include polished bore receptacles  36 ,  38  and are located above the zones to be produced.  
         [0025]    The diverter  68  is an “integrated” diverter; that is, it is part of the casing junction assembly  28 , as contrasted with a diverter that is run in separately for engagement with the casing junction assembly  28 . The diverter  68  can either be integrally formed with the casing junction assembly  28 , or the diverter  68  can be affixed permanently to the casing junction assembly  28  by an attachment mechanism. The diverter is integrated in the sense that it is part of the casing junction assembly  28  when the casing junction assembly  28  is installed at the junction to be completed.  
         [0026]    Referring to FIG. 3, an embodiment of the invention where a landing tool  40  is placed within the main wellbore  12  is shown. After the casing  20  and the casing junction assembly  28  have been cemented in place, the lateral wellbores  16 ,  18  are drilled and the first and second packers  24 ,  26  are set in place within the first and second legs  15 ,  17 , respectively. An assembly including a landing tool  40 , a first tubing string  42 , and a second tubing string  44  may be connected to a deployment string  500  and inserted into the main wellbore  12 . The first tubing string  42  includes a seal assembly  48 , extends from the landing tool  40 , and is generally aligned with the first leg  15  and first lateral wellbore  16 . The second tubing string  44  includes a seal assembly  50 , extends from the landing tool  40 , and is generally aligned with the second leg  17  and the second lateral wellbore  18 . The landing tool  40  is lowered into the well casing  20  and is aligned with respect to the lateral wellbores in a manner discussed below. Once the landing tool  40  is set and locked in place, a weight may be placed down on the deployment string  500  to simultaneously extend the tubing strings  42 ,  44  out from the landing tool  40  to enter the first and second legs  15 ,  17  and engage in the polished bore receptacles  36 ,  38  of respective packers  24 ,  26 .  
         [0027]    Although the Figures show that the landing tool  40  is set and locked in place within the casing junction assembly  28 , the landing tool  40  may be set and locked in place in the casing  20  above the casing junction assembly  28  in other embodiments.  
         [0028]    In one embodiment, the deployment string  500  can then be disconnected from the landing tool  40  and removed to the earth&#39;s surface. In this embodiment, the remaining completion equipment is deployed in another downhole trip, resulting in two trips being performed to complete the well. In an alternative embodiment, the deployment string  500  comprises permanent completion tubings and/or components that remain downhole after the extension of the tubing strings  42 ,  44 . Thus, in this alternative embodiment, only one trip is required to complete the well.  
         [0029]    The landing tool  40  is fixed in place by a setting element  66  that restricts any longitudinal or rotational movement of the landing tool  40 . The setting element  66  includes slips that extend out to engage the inner wall of the casing junction assembly  28  (see FIG. 5) or casing  20 . Other forms of the setting element  66 , such as locking elements/dogs  200  (see FIGS.  16 - 22 ), can be used in other embodiments. The setting element  66  (or locking elements/dogs  200 ) are examples of landing elements engageable with landing profiles at the junction.  
         [0030]    Once the landing tool  40  is correctly oriented in relation to the lateral wellbores  16 ,  18 , the landing tool  40  is then locked in position by the setting element  66 . The setting element  66  is engaged by exerting a downward force onto the tool that breaks a shear element and extends slips to engage with the casing junction  28  or casing  20 .  
         [0031]    After the tool is locked in place by the setting element  66 , a further downward force can be exerted onto the tool that will break yet another shear element and will enable the extension of the tubing strings, as shown in FIG. 4. As the tubing strings  42 ,  44  extend from the landing tool  40 , the diverter  68  deflects each of the tubing strings  42 ,  44  into its respective casing junction leg  15 ,  17 . Specifically, as the first tubing string  40  extends from the landing tool  40 , it contacts first guide surface  30 . First guide surface  30  then serves to guide the first tubing string  40  towards the first leg  15 . Concurrently, as the second tubing string  42  extends from the landing tool  40 , it contacts second guide surface  32 . Second guide surface  32  then serves to guide the second tubing string  42  towards the second leg  17 . The first tubing string  42  and the second tubing string  44  proceed until they seat in their respective polished bore receptacles  36 ,  38 . The diverter  68  is located between the two tubing strings  42 ,  44 , thus preventing them from both going into a single leg or lateral wellbore. It is noted that the tubing strings  42 ,  44  can be connected in some way, such as by a pin or strap that can be broken as the tubing strings are deflected away from each other by the diverter  68 .  
         [0032]    As shown in FIG. 23, the tubing strings  42 ,  44  can be constructed in a manner so as to be biased away from each other when not connected. The tubing strings  42 ,  44  can be connected, such as by a pin or strap  201 . In this way, when the connection  201  is broken as shown by the dashed lines in FIG. 23, the tubing strings  42 ,  44  naturally deflect from each other based on the bias to facilitate the separation and insertion of the tubing strings into the legs  15 ,  17 . The connection  201  can be broken into parts  202 ,  203 , such as by the separation induced by the diverter  68 . In this embodiment, the diverter  68  cooperates with the biasing of the tubing strings  42 ,  44  to induce deflection of the tubing strings into the lateral wellbores  16 ,  18 .  
         [0033]    In the embodiment shown in FIG. 4, the deployment string  500  is removed and dual production tubing strings  52 ,  54  are run into the main wellbore  12  and attached to the landing tool  40  so as to establish fluid communication with the first and second tubing strings  42 ,  44 , respectively. In an alternative embodiment, the deployment string  500  includes the dual production tubing strings  52 ,  54  and so the landing tool  40  is run downhole together with the dual production tubing strings  52 ,  54 .  
         [0034]    In the discussion above, the landing tool  40  is described as being capable of orienting the string, setting the string within the casing, and also extending the tubing strings. These different operations can be separated from each other and performed by two or more separate tools. For example, a completion assembly may include three separate tools: one tool used for orienting the completion assembly, a second tool used to set the completion assembly within the casing to prevent any longitudinal or rotational movement, and a third tool used to extend the tubing strings through the junction and into their respective lateral wellbore. This description is not meant to limit the manner in which these operations can be performed.  
         [0035]    [0035]FIG. 5 illustrates an alternate embodiment where a single production tubing string  56  is used, instead of the dual tubings  52 ,  54  as shown in FIG. 4. In one embodiment, a swivel  58  is connected between the tubing  56  and a wireline reentry tool  60 , which has two relatively short sections of production tubing or “tubing subs”  62 ,  64  for engagement with the landing tool  40  and the tubing strings  42 ,  44 . In this embodiment, the wireline reentry tool  60  is deployed after the retrieval of the deployment string  500 . In another embodiment, the deployment string  500  includes a Y-block mechanism connected at its bottom to the dual production tubing strings  52 ,  54  and at its top to the single production tubing string  56 . In this embodiment, the deployment string  500  is not retrieved after the landing tool  40  is set.  
         [0036]    If it is desired pull the landing tool  40  and tubing strings  42 ,  44  out of the well  10 , the tubing strings  42 ,  44  can be withdrawn from the packers  24 ,  26  and pulled back into their pre-extended configuration. An upward force can then be exerted on the landing tool  40  by pulling on the deployment string  500  until yet another shear element is broken, which causes the setting element  66  to retract and release the landing tool  40  to be pulled out of the well  10 .  
         [0037]    Referring to FIGS. 6 and 7, the landing tool  40  according to one embodiment includes a body  80  and an orienting key  82  that is biased outwardly, for example, by one or more springs  84 . The orienting key  82  is disposed within a first recess  86  in the body  80 . The orienting key  82  is capable of radial movement within the first recess  86 . A locking key  88  is movably secured to the body  80 , and is biased outwardly, for example by a leaf spring  92 , which may be secured to the locking key  88 . The locking key  88  can be disposed within a second recess  94  in the body  80  and is coupled to the body  80  by a hinge pin  96 , for example.  
         [0038]    [0038]FIG. 8 shows an illustration of the casing  20  or casing junction assembly  28  (recall that the landing tool  40  may be set either in the casing junction assembly  28  or in the casing  20  above the casing junction assembly  28 ) in a particular embodiment of the apparatus. The casing  20  or casing junction assembly  28  includes an orienting slot  70 , a locking slot  72  and an orienting profile  74  that can be used in conjunction with the landing tool  40  (FIGS. 6 and 7). The profile  74 , orienting slot  70  and locking slot  72  may be formed as part of the well casing  20  or casing junction  28 , or as a separate component (sometimes called a “muleshoe” or a “discriminator”  76 ), that is attached to the casing  20 /casing junction assembly  28 .  
         [0039]    [0039]FIGS. 9 and 10 illustrate the landing tool  40  engaged within the well casing  20 /casing junction assembly  28 . As the landing tool  40  is inserted into the well casing  20 /casing junction assembly  28 , a lower edge  83  of the orienting key  82  (FIG. 6) contacts the profile  74  (FIG. 8). Continued downward movement of the landing tool  40  causes the orienting key  82  to move along the profile  74  and into engagement with the orienting slot  70 , thereby rotating the landing tool  40 , and any attached items, into alignment with the diverter  28  and the first and second lateral wellbores  16 ,  18  (FIGS. 3 and 4). The lower edge  83  of the orienting key contacts a lower ledge  71  of the orienting slot  70 , which restricts any further downward movement. As the orienting key  82  moves into the orienting slot  70 , the locking key  88  is longitudinally and radially aligned with the locking slot  72 . As the lower edge  83  of the orienting key bottoms out on the lower ledge  71  of the orienting slot  70 , the locking key  88  will be moved into the locking slot  72  under force from the locking key spring  92 . Any upward movement is then prevented by contact of the upper edge  89  of the locking key  88  with the upper edge  73  of the locking slot  72 .  
         [0040]    [0040]FIG. 11 shows a multilateral well  10  having packers  24 ,  26  located within the first and second lateral wellbores  16 ,  18 . A diverter  168 , which is a part of the casing junction assembly  28 , is shown set within the main wellbore  12  proximal the junction of the main wellbore  12  and the lateral wellbores  16 ,  18 . The diverter  168  can be positioned within the well in numerous ways. For example, the diverter  168  can be retrievably set in a manner such as a packer, the diverter  168  can be cemented in place, or the diverter  168  can be included as an integral part of the casing  20 . The diverter  168  has a first guide surface  130  that serves to deflect items towards the first lateral wellbore  16 , and a second guide surface  132  that serves to deflect items towards the second lateral wellbore  18 . The diverter  168  shown also includes a projection  134  that extends upwardly from the diverter  168 . The packers  24 ,  26  include polished bore receptacles  36 ,  38  and are located above the zones to be produced.  
         [0041]    Referring to FIG. 12, another embodiment is shown. After the casing  20  has been cemented in place, first and second packers  324 ,  326  are set in place within the lateral wellbores  16 ,  18 , respectively. An assembly including a landing tool  340 , a first tubing string  342  and a second tubing string  344  is connected to a deployment string (not shown) and inserted into the main wellbore  12 . The first tubing string  342  includes a seal assembly  348 , extends from the landing tool  340 , and is aligned with the first guide surface  330  of a diverter  368 . The second tubing string  344  includes a seal assembly  250 , extends from the landing tool  340 , and is aligned with the second guide surface  332 . The first lateral wellbore  16  contains a first packer  324  having a receptacle  336  and a sand screen assembly  346 . The second lateral wellbore  18  contains a second packer  326  having a receptacle  338  and a sand screen assembly  348 . The landing tool  340  is lowered into the well casing  20  and is aligned with respect to the lateral wellbores. Once the landing tool  340  is set in place, a weight may be placed down on the deployment string (not shown) to simultaneously extend the tubing strings  342 ,  344  out from the landing tool  340  to contact the diverter  368 . The extended tubing strings enter the lateral wellbores  16 ,  18  and engage with their respective packers  324 ,  326 . The deployment string (not shown) can then be disconnected from the landing tool  340  and removed to the earth&#39;s surface.  
         [0042]    [0042]FIG. 13 shows yet another embodiment. A landing tool  440  is fixed in place by a setting element  466  that restricts any longitudinal or rotational movement of the landing tool  440 . A first tubing string  442  and second tubing string  444  extend from the landing tool  440 . The first tubing string  442  is separated from the second tubing string  444  by the projection  434 . The first tubing string  442  is deflected by the first guide surface  430  into the first lateral wellbore  16  where it seats in the receptacle  436  of a first packer  424 . The second tubing string  444  is deflected by a second guide surface  432  into the second lateral wellbore  18  until it seats in a receptacle  438  of a second packer  426 .  
         [0043]    Phrases such as “separation of tubing strings by a diverter projection” are meant to mean that the diverter projection is located between the two tubing strings thus restricting them from both going into a single lateral wellbore and aligning them in respect to the applicable guide surface. The phrase is not meant to imply a physical attachment between them that is being broken, although that is possible. In the embodiment of FIG. 13, the deployment string (not shown) has been removed and dual production tubings  452 ,  454  have been run into the main wellbore  12  and attached to the landing tool  440 , so as to establish fluid communication with the first and second tubing strings  442 ,  444 , respectively.  
         [0044]    [0044]FIG. 14 is an overhead view of an embodiment of the casing junction assembly  28 . The two legs  15 ,  17  that form the starting point of lateral wellbores  16  and  18  are shown as cylindrical tubes. The projection  34  having guide surfaces  30 ,  32  is located between the two legs  15 ,  17 .  
         [0045]    [0045]FIG. 15 is a longitudinal sectional side view of the casing junction assembly of FIG. 14. The legs  15 ,  17  can be seen to project outward to provide communication to the lateral wellbores  16  and  18 . The projection  34  is shown to extend above the openings of the lateral legs  15 ,  17 . The diverter  68  portion of this embodiment is shown to be between the two legs  15 ,  17 . The guide surfaces  30 ,  32  are shown sloping towards the respective lateral wellbore.  
         [0046]    FIGS.  16 - 22  illustrate one embodiment of the landing tool  40  in greater detail. Similar to the landing tool  40  depicted in FIGS. 6 and 7, the landing tool  40  of this embodiment includes a body  80 ′ (FIG. 16B) and at least one orienting key  82 ′ that is biased outwardly, for example, by one or more leaf springs  84 ′. The orienting key  82 ′ is disposed within a first recess  86 ′ in the body  80 ′. The orienting key  82 ′ is held within the first recess  86 ′ by at least one retainer  301  and is capable of radial movement within the first recess  86 ′. The orienting mechanism of this embodiment functions in the same manner as the orienting mechanism of the landing tool  40  embodiment depicted in FIGS.  6 - 9 .  
         [0047]    The landing tool  40  of FIGS.  16 - 22  further includes at least one locking element  200  (similar to setting element  66  of FIGS. 3 and 4) movably secured to the body  80 ′. The body  80 ′ can include a plurality of locking elements  200 , each element  200  biased outwardly by one or more springs  202  and held within corresponding one or more second recesses  204  by at least one retainer  303   
         [0048]    The body  80 ′ may include a first body part  206  and a second body part  208  that may slide in relation to each other. In one embodiment, the orienting key  82 ′ is located on the first body part  206 , and the locking elements  200  are located on the second body part  208 . First body part  206  includes at least one protruding element  210 , such as at least one finger, extending from its bottom portion. Protruding element  210  may also be a sleeve in other embodiments. The fingers  210  may or may not be integral with the remainder of the first body part  206 . Each finger  210  is housed and can slide in a slot  212  formed on the second body part  208 . Each second recess  204  is part of a slot  212 . The fingers  210 , the slots  212 , the locking elements  200 , and the second recess  204  are constructed so that each finger  210  can slide into a second recess  204  and next to a locking element  200 , thereby preventing further radial movement of such locking element  200 .  
         [0049]    Body  80 ′ further includes two passages  300  (FIG. 20B) therethrough. Note that the longitudinal sectional view of FIGS.  20 A- 20 C is taken along a plane perpendicular to that of the longitudinal sectional view of FIGS.  16 A- 16 C. Dual production tubing strings  52 ,  54  may be passed through the passages  300 . The production tubing strings  52 ,  54  are attached to the first and second tubing strings  42 ,  44 . In the embodiment shown in FIGS.  20 A- 20 C, the production tubing strings  52 ,  54  are attached to the first and second tubing strings  42 ,  44  within the passages  300 .  
         [0050]    FIGS.  16 A-C show the landing tool  40  in its run or deployment position. In this position, the fingers  210  are not abutting the locking elements  200  and are instead located above the locking elements  200  within their respective slots  212 . The first body part  206  and the second body part  208  are attached to each other in this configuration by way of shear pins, such as first shear pins  214  shown in FIG. 21. As the landing tool  40  is run downhole, the orienting key  82 ′ interacts with a matching orienting slot (not shown but similar to orienting slot  70 ) to orient the landing tool  40  within the casing  20  or casing junction  28 , as previously discussed. As the orienting key  82 ′ comes to its final position in the orienting slot, each locking element  200  becomes longitudinally and radially aligned with a matching locking slot  72 ′ (similar to locking slot  72 , albeit different in shape) and the springs  202  bias the locking elements  200  into the locking slots  72 ′. The locking slots  72 ′ and locking elements  200  include mating straight surfaces  216  that prevent further downward movement of the landing tool  40 . At this point, the landing tool  40  is landed within the locking slots  72 ′ and is appropriately oriented.  
         [0051]    FIGS.  17 A- 17 C show the landing tool  40  locked in position to prevent inadvertent longitudinal motion. To lock the landing tool  40  in place, a downward force is exerted on the landing tool  40  by way of dual production tubing strings  52 ,  54 , for example. If high enough, the downward force acts to shear the first shear pins  214  and allows the downward motion of the first body part  206  in relation to the second body part  208 . It is noted that the second body part  208  remains stationary due to its engagement with the locking slots  72 ′ by way of locking elements  200 . As the first body part  206  slides, the fingers  210  become wedged next to the locking elements  200 , thereby preventing any radial inward movement of the locking elements  200  and thus effectively locking the second body part  208  in place. In addition, once the first body part  206  slides a sufficient distance, openings  222  on the second body part  208  become aligned with openings  224  on the fingers  210  to allow locking pins  220  that are spring loaded within the openings  222  to be biased partially into the openings  224 . Once the locking pins  220  are located within the openings  222 ,  224 , the locking pins  220  lock the first and second body parts  206 ,  208  together.  
         [0052]    FIGS.  18 A-D show the landing tool  40  with the first and second tubing strings  42 ,  44  extended in the direction of the first and second lateral wellbores. For purposes of clarity, the landing tool  40  of this embodiment is shown without placement in a main wellbore including lateral wellbores. To extend the first and second tubing strings  42 ,  44 , a downward force is exerted on the landing tool  40  by way of the dual production tubing strings  52 ,  54 , for example. If high enough, the downward force acts to shear a set of second shear pins  218  (see FIGS. 20B and 22) that attach the first and second tubing strings  42 ,  44  (or the dual production tubing strings  52 ,  54 ) to the body  80 ′ (and more particularly to the first body part  206 ). Once the second shear pins  218  are sheared, the first and second tubing strings  42 ,  44  can be extended within/through passages  300  and out of landing tool  40 . As previously discussed, the first and second tubing strings  42 ,  44  are then guided in the direction of the first and second lateral wellbores by the diverter  68 .  
         [0053]    As best seen in FIG. 20C, the lower end of each of the first and second tubing strings  42 ,  44  may include an inclined surface  302 . The inclined surface  302  cooperates with the diverter  68  to more easily facilitate the extension and diversion of the first and second tubing strings  42 ,  44  into the first and second legs  15 ,  17 .  
         [0054]    FIGS.  19 A- 19 C show the landing tool  40  in its unset and retrieval position. Once the operator is ready to retrieve the landing tool  40 , an upward force is exerted on the landing tool  40  by way of the dual production tubing strings  52 ,  54 , for example. If high enough, the upward force acts to shear the locking pins  220  (compare FIGS. 18B and 19B) that attach the first and second body parts  206 ,  208 . Once the locking pins  220  are sheared, continued upward force on the dual production tubing strings  52 ,  54  acts to pick up first body part  206  by way of internal shoulder  226  (FIG. 20B). As the first body part  206  slides in relation to the second body part  208  (which is still locked in place), the fingers  210  slide out of abutment with the locking elements  200 , thereby allowing the locking elements  200  to be biased radially both inwardly and outwardly.  
         [0055]    As the first body part  206  continues to be pulled upward, the first body part  206  eventually picks up and supports the second body part  208 . FIGS. 24 and 25 show a longitudinal cross-sectional view of the landing tool  40  shown in FIGS.  16 - 22  taken along a different phase of the body  80 ′. FIG. 24 shows the tool  40  in the deployment position, and FIG. 25 shows the tool  40  in the retrieval configurations. As can be seen in the Figures, first body part  206  includes at least one radial slot  500  therein, and second body part  208  includes a pin  502  slidingly disposed within each slot  500 . Each pin  502  is securely attached to the second body part  208 . When the landing tool  40  is in the deployment position (FIG. 24), the pin  502  is proximate the upper end  504  of the slot  500 . As the first body part  206  is pulled up during retrieval (FIG. 25), the lower end  506  of the slot  500  eventually abuts and picks up its corresponding pin  502 , thereby also picking up the second body part  208 .  
         [0056]    With the slots and pins  500 ,  502  providing a secure connection between the first and second body parts  206 ,  208 , continued upward movement of the first body part  206  retrieves the second body part  208  and the first and second tubing strings  42 ,  44  from the wellbore. Due to the mating angles of the locking element  200  and locking slots  72 ′ and because the locking element  200  can now be biased within second recess  204 , the connection between the locking elements  200  and the locking slots  72 ′ does not prevent upward movement of the landing tool  40 .  
         [0057]    In addition, the upward movement of the first body part  206  (during the initial retrieval process) results in the mating of a teeth profile  228  (FIG. 19B) located on an inner surface  230  of each finger  210  with a teeth profile  232  located on ratchet keys  234 . The ratchet keys  234  are located within grooves  236  on second body part  208  and are biased outwardly by springs  236 , for instance. The mating teeth profiles  228 ,  232  are designed so that they do not allow relative motion in the downward direction, but allow relative motion in the upward direction. This is desirable so that, if the landing tool  40  becomes stuck in the wellbore as it is being retrieved, an operator may push and/or pull on the relevant retrieving tool/string without fear of inadvertently locking the locking elements  200  and the landing tool  40  within the wellbore once again. In this manner, regardless of the direction of the jarring force exerted by the operator, the mating teeth  228 ,  232  prevent the fingers  210  from sliding downwardly and wedging against the locking elements  200  (and thereby locking the locking elements  200 ).  
         [0058]    It is noted that in the run-in position (FIG. 16B), the ratchet keys  234  are covered by a sleeve  238 , which is secured to the second body part  208  by way of a set of shear pins  240 . As the fingers  210  slide down to lock the landing tool  40  in place (FIG. 17B), the fingers  210  push the sleeve  238  downwardly, shearing the shear pins  240 , and uncovering the ratchet keys  234 .  
         [0059]    It is noted that the shear pins used in the landing tool  40  should be rated to enable the sequence previously described. Thus, for instance, the first set of shear pins  214  are rated lower than the second set of shear pins  218 .  
         [0060]    The discussion and illustrations within this application 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 wells that contain main wellbores that have an orientation that is deviated from vertical.  
         [0061]    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.