Patent Abstract:
A wellbore junction. The junction includes a discrete primary leg and a discrete lateral leg connected to the primary leg, at least one of the legs comprising a plurality of non-nested flow passageways.

Full Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
   This application claims the benefit of an earlier filing date from U.S. Provisional Application Ser. No.: 60/647,207 filed Jan. 26, 2005, the entire disclosure of which is incorporated herein by reference. 

   BACKGROUND 
   The hydrocarbon exploration and recovery industry is forced with growing demand worldwide and therefore faced with the ever-increasing need for greater efficiency in completing boreholes for production both from cost and rapidity standpoints. In an effort to continue to raise the bar that represents these interests, inventors are constantly seeking out new ways to improve the process. While many improvements have been made and successfully implemented over the years, further improved procedures, configurations, etc. are still needed. In the downhole environment directly, multilateral wellbore construction and completion has become increasingly ubiquitous in recent years. Multilateral wellbores allow for a greater return on investment associated with drilling and completing a wellbore simply because more discrete areas/volumes of a subterranean hydrocarbon deposit (or deposits) is/are reachable through a single well. Moreover, such multilateral wellbore systems have a smaller footprint at the earths surface, reducing environmental concerns. Multilateral wellbores generally require “junctions” at intersection points where lateral boreholes meet a primary borehole or where lateral boreholes (acting then as sub primary boreholes) meet other lateral boreholes. “Junctions” as is familiar to one of skill in the art are “Y” type constructions utilized to create sealed flow paths at borehole intersections and are generally referred to as having a “primary leg” and a “lateral leg”. 
   There is a need in the industry for the flow of fluids at a multilateral intersection to be isolated from the formation. This is commonly known as a sealed junction. There are currently a number of ways of achieving this. For a given main well bore size two tubing strings can be run, one to the main bore and one to the lateral. If larger tubing strings are required then either a larger main bore is required or at least one of the tubing strings must be shaped prior to installation. An alternate to these is to construct the sealed junction downhole at the intersection of the main bore and lateral. Each of these methods has advantages and disadvantages. By utilizing two small tubes the junction can withstand high pressure differentials, but forgoes flow area and hence production rate. A large main bore and large tubing strings gains flow area and rate with moderate to high pressure ratings, but the increased sizes can have a major financial impact on numerous other related equipment in the overall well system. Junction systems where the tubing strings are not round end up with increases in flow area and rate over the small tubing strings, but are inherently lower in pressure and load rating. Systems where the sealing mechanism is assembled down hole have so far been complex to manufacture and install, with minimal increase in flow area, and with pressure ratings approximately equal to the non-round versions. 
   Since ease of installation, sealing and high overall strength characteristics are always a high priority, improved junction systems are always well received by the relevant art. 
   SUMMARY 
   Disclosed herein is a wellbore junction. The junction includes a discrete primary leg and a discrete lateral leg connected to the primary leg, at least one of the legs comprising a plurality of flow passageways. 
   Further enclosed herein is a wellbore system. The system includes a junction having a discrete primary leg and a discrete lateral leg connected to the primary leg, at least one of the legs comprising a plurality of flow passageways, the junction disposed at an intersection between a primary borehole and a lateral borehole. 
   Yet further disclosed herein is a method for installing a junction in a wellbore. The method includes running a junction having a discrete primary leg and a discrete lateral leg connected to the primary leg at least one of the legs comprising a plurality of flow passageways. The method further includes landing the junction at an intersection between a primary borehole and a lateral borehole and causing the lateral leg to enter the lateral borehole and causing the lateral leg to enter the lateral borehole. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     Referring now to the drawings wherein like elements are numbered alike in the several Figures: 
       FIG. 1  is a schematic representation of a wellbore intersection having a junction assembly illustrated therein; 
       FIG. 2  is a schematic view of a junction and sleeve assembly in a run-in position; 
       FIG. 3  is a schematic sectional view of a junction as disclosed in a casing segment; 
       FIG. 4  is a schematic view of a junction and sleeve assembly in a landed position; 
       FIG. 5  is a schematic view of a junction and sleeve assembly in a partially exploded condition; 
       FIG. 6  is a cross-sectional view taken along section line  6 - 6  of  FIG. 5 ; 
       FIG. 7  is a cross-sectional view taken along section line  7 - 7  of  FIG. 5 ; and 
       FIG. 8  is an alternate configuration employing the junction disclosed herein. 
   

   DETAILED DESCRIPTION 
     FIG. 1  is a schematic view of a first embodiment of a wellbore junction and ancillary components utilized therewith or forming a portion thereof. A wellbore  10  is generally illustrated having a primary borehole  12  and a lateral borehole  14 . It will be appreciated that additional laterals may exist in an actual wellbore and that this drawing merely illustrates a small portion of the overall wellbore system. 
   At an intersection  16  between primary borehole  12  and lateral borehole  14 , there is illustrated a hook hanger liner hanger  18 . This system is commercially available from Baker Oil Tools, Houston, Texas. As such, the hanger  18  does not require a detailed description of its structure and operation. At an uphole end of hanger  18  is an orientation profile  20  configured to provide a clear indication as to an angular location of the lateral borehole  14 . The hanger  18  is installed in the wellbore prior to running the junction, in accordance with well-established procedures. 
   In a subsequent run in the wellbore  10 , junction and sleeve assembly  22  (which comprises an external orientation sleeve  26  and a junction  34 , both more formally introduced hereunder) (see  FIG. 2 ) is run in the hole to mate with orientation profile  20  on hanger  18 . It is to be noted that numeral  22  does not appear on  FIG. 1  because it would require a bracket large enough to render the designation meaningless. A complete understanding of the component and its relative position will be gained by a consideration of other numerals appearing in both  FIGS. 1 and 2 . Referring to  FIGS. 1 and 2  simultaneously, an orientation profile  24  on an external orientation sleeve  26  is visible. It is this profile  24  that lands on profile  20  to orient the junction and sleeve assembly  22 , thereby ensuring that a lateral leg  28  of the junction  34  enters the lateral borehole  14  as appropriate. Orientation is particularly important in this embodiment as there is no diverter sub to direct the lateral leg  28  out of the primary borehole and into the lateral borehole  14 . Rather, in this embodiment, an offset sub  56  is used to encourage entry of the lateral leg  28  into the lateral borehole  14 . Referring to  FIG. 3 , the offset sub  56  includes a manifold  58  and a seal sub  60 . Manifold  58  is essentially a box having an inlet configured to receive the plurality of passageways of lateral leg  28  and join a flow volume therefrom to the seal sub  60 . Moreover, the manifold  58  offsets seal sub  60  as illustrated. The offset places an outside radial position of the manifold and seal sub at a radial distance from an axial center of body  52  that is greater than body  52  itself has. Moreover, the same dimension causes a perimetric dimension of the junction  34  to be larger overall than the diameter of a casing string through which it is run. Since the tool is urged into the casing anyway, the configuration of manifold  58  causes the lateral leg  28  to resiliently deflect toward the primary leg  38 . The lateral leg in such condition is energized to spring radially outwardly away from the primary leg  38  and the lateral leg  28  will do so when an opportunity is provided. This will occur when the offset sub reaches a window of the lateral borehole intersection. Because the seal sub is also offset from the axis of lateral leg  28 , the movement of offset sub  56  is sufficient to place seal sub  60  into lateral  14  and, laterally beyond a downhole intersection point  62  (see FIG.  1 ) of intersection  16 . This will cause the lateral leg  28  to automatically enter the lateral. A traditional “bent joint” concept could also be employed in some embodiments. 
   Once the external orientation sleeve  26  is seated at hanger  18 , sleeve  26  no longer moves downhole. Further, weight from uphole on the assembly causes a collet  30  to disengage from the initial collet profile  32 , (see  FIG. 2 ) in sleeve  26  thereby allowing a junction  34  (see  FIG. 5 ) to stroke downhole inside of sleeve  26  and through hanger  18 . For clarity of understanding, the junction and sleeve assembly  22  is illustrated in the stroked position apart from other components in  FIG. 4 . Referring back to  FIG. 2 , an alignment slot  36  is provided in sleeve  26  to assist in ensuring that the junction  34  remains orientated during the stroking process. In one embodiment the stroke is about 15 feet long. 
   Upon stroking of junction  34 , a primary leg  38  (see  FIGS. 6 and 7 ) of junction  34  extends through an opening  40  in hanger  18 . At a downhole end of primary leg  38  is a seal stack  42  to stab into a receptacle  44 , as collet  30  engages a “no-go” profile  46  in sleeve  26 . Also simultaneous to seals  42  stabbing into receptacle  44 , seals  48  of lateral leg  28  stab into lateral receptacle  50  (see  FIG. 1 ). 
   Focusing on junction  34 , and as is ascertainable from the foregoing explanation; the junction comprises primary leg  38  and lateral leg  28 . These are joined together at a more uphole portion of junction  34 , identified as body  52 . Body  52  is tubular in structure and houses the primary leg flow in an axial flow area of a sliding sleeve  54  as well as an annular flow comprising fluid from lateral bore leg  28 . The annular flow is defined by the sliding sleeve  54  and the inside of body  52 . If the sliding sleeve  54  is in an open position (choked or full open) then fluid from the lateral borehole  14  will flow into the sliding sleeve, and flow with the fluid from the primary borehole  12 . Alternately, if the sliding sleeve is positioned to prevent flow (closed) then the fluid from lateral borehole  14  is prevented from moving uphole. It should be appreciated that it is also possible to flow only the lateral borehole  14  in this arrangement by opening the sliding sleeve  54  and running a plug downhole of the sliding sleeve  54  to shut off the primary bore. 
   One feature of the junction  34  directly addresses one of the short comings of the prior art in that a significant flow area is obtained for the junction  34  while maintaining cylindrical seal surfaces and cylindrical flow areas. This is accomplished in one embodiment as is illustrated in  FIGS. 5 ,  6  and  7  by providing multiple tubulars that collectively makeup lateral leg  28 . The individual tubulars are numbered  1 - 5  in  FIGS. 6 and 7 . One of skill should readily appreciate that the flow area is significant when summing each of the numbered areas. In the  FIG. 6  location the tubulars are configured to run parallel to one another. In the  FIG. 7  location however, the tubes  1 - 5  have been reconfigured to cause the collection of the tubes to begin to bend away from the main leg  38 . More particularly, the lateral leg is biased into the lateral bore of the well by reconfiguring the five lateral tubes as shown in  FIG. 7 . The stiffness of tubes numbered one and five are used to bend leg number three away from primary leg  38  while number two and four remain straight. Such a configuration acts like a bent sub with respect to “desire” of the lateral leg (tubes  1 - 5 ) to move into the lateral bore. This is also to provide for a relatively circular pattern of the five tubes for entry to the manifold  58  described above. 
   While the drawing  FIGS. 6 and 7  are specifically related to a configuration of multiple tubulars making up the lateral leg, one of skill in the art will appreciate from this disclosure that the tubulars  1 - 5  could merely be passageways bored in a volume of material. The illustration of such will look identical to the  FIG. 6  view. Because the individual passageways are spread relatively uniformly in the “material”, that same material is relatively low in profile and therefore still achieves one of the goals of the invention by providing cylindrical flow areas while reducing the outside dimensions of the junction. In an alternate embodiment, referring to  FIG. 8 , the configuration is similar in representation to the figure one illustration but is illustrated even more schematically than is  FIG. 1 . The two embodiments each include junction  34  but this embodiment does not require sleeve  26  or offset sub  56  as a seal bore diverter  64  is used instead. Further, this embodiment has no need to stroke. 
   While preferred embodiments have been shown and described, modifications and substitutions may be made thereto without departing from the scope of the invention. Accordingly, it is to be understood that the present invention has been described by way of illustration and not limitation.

Technology Classification (CPC): 4