Patent Publication Number: US-9416638-B2

Title: Multi-lateral well system

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to operations in a wellbore associated with the production of hydrocarbons. More specifically, the invention relates to systems for developing and producing dual-lateral wells. 
     2. Description of the Related Art 
     Often in the recovery of hydrocarbons from subterranean formations, wellbores are drilled with multiple highly deviated or horizontal portions that extend through separate hydrocarbon-bearing production zones. Each of the separate production zones can have distinct characteristics such as pressure, porosity and water content, which, in some instances, can contribute to undesirable production patterns. Many onshore and offshore fields with multiple reservoirs utilize high level technology advancement multi-lateral (TAML) systems to provide the ability to produce two separate reservoirs with different pressure regimes and separate lateral access. However such high level TAML systems are costly due to very expensive equipment, and the significant number of rig operating days required for their use. TAML systems also historically have an inherent risk of completion problems and failures. 
     As a separate matter, any workover involving entry into a branched lateral portion of a well in an open hole environment can be lengthy, costly, and introduce risk due to uncertainties in entering the branched lateral portion. Entering a particular lateral is often done by trial and error using a bent-sub as a guide and rotating an associated tool string in order to orient the guide. A measurement while drilling (MWD) device on a tool is sometimes used to help orient the guide, and a retrievable bridge plug or a drillable plug is sometimes installed in the motherbore in connection with these techniques to act as a temporary barrier. So if a lateral wellbore is tagged by any tool at the bottom of the string, the tool string can be pulled back up and reworked into the desired lateral wellbore. This is not always practical because typical completion equipment has a limited torque capability and often requires a ball operated pressure release device that precludes use of a MWD tool. Also, rotating completion equipment accidently across the window exit from, the motherbore can damage the equipment. 
     Another approach sometimes employed for entering a lateral bore involves running and setting a retrievable whipstock in the exact location and orientation of a previous whipstock location, so that the whipstock can easily guide any work string into the lateral wellbore. However, this approach is not often attempted because setting a whipstock at an exact location and orientation along an existing wellbore remains a challenge and retrieval of the whipstock may not be always assured. 
     SUMMARY OF THE INVENTION 
     The systems and methods of this disclosure provide a multi-lateral well design that can allow selective full access for production logging, reservoir stimulation, or water shut-off in multiple lateral wellbores to maximize production of each development, and can be used on developments with offshore platforms with limited slots and on onshore well sites. Embodiments of this disclosure allow for optimization of the field development potential. Production from two lateral wellbores can be commingled, or produced separately, without a complicated and expensive high level TAML system, substantially simplifying the construction of multi-lateral junctions while still providing for pressure isolation of the laterals. 
     Embodiments of this disclosure addresses rig operational risks such as being unable retrieve a whipstock, and failure to complete the multi-lateral well because of a complicated requirement of properly orienting a tool across the window exit/lateral conjunction, as well as risks associated with having limited the access to the lateral bores. 
     In an embodiment of this disclosure, a production system for use in a wellbore having a main bore with an axis, a lower lateral bore, and an upper lateral bore, includes a hollow whipstock with a central bore. The hollow whipstock is secured to the main bore between the lower lateral bore and the upper lateral bore. A sleeve assembly has a moveable inner sleeve with an outer diameter smaller than an inner diameter of the central bore of the hollow whipstock, and a moveable outer sleeve with an outer diameter larger than the inner diameter of the central bore of the hollow whipstock. A flow control valve is located in the main bore above the upper lateral bore. The flow control valve has an inner tubing member in selective fluid communication with the lower lateral bore and an annular conduit in selective fluid communication with the upper lateral bore. 
     In alternate embodiments, the sleeve assembly can have an upper end located in the main bore axially above the upper lateral bore. The inner sleeve can be sized to be selectively insertable into the central bore of the hollow whipstock. The outer sleeve can be sized to be selectively insertable into the upper lateral bore. The sleeve assembly can have an intermediate member that circumscribes a portion of the moveable inner sleeve and is circumscribed by a portion of the moveable outer sleeve. The intermediate member can be a tubular member that is statically secured within the main bore. 
     In other alternate embodiments, the flow control valve has a sliding sleeve system. The sliding sleeve system includes a sliding sleeve moveable between an open position where fluids from the annular conduit can flow into an exit port of the annular conduit, and a closed position where fluids from the annular conduit are prevented from flowing into the exit port. A biasing member urges the sliding sleeve towards an open position or a closed position. An opening pressure surface is acted on by main bore fluids. A closing pressure surface is acted on by inner tubing member fluids such that when forces on the closing pressure surface exceed forces on the opening pressure surface and overcome the biasing member, the sliding sleeve is moved towards a closed position. 
     In yet other alternate embodiments, the system has a production packer sealing the main bore axially above the sleeve assembly. The inner tubing member of the flow control valve has a tubing entry end in fluid communication with the sleeve assembly, and a tubing exit end in fluid communication with the main bore axially above the production packer. The annular conduit of the flow control valve has an annulus entry end in fluid communication with the main bore axially below the production packer, and an exit port in fluid communication with the tubing exit end. 
     In still other alternate embodiments, the flow control valve has a valve member located in the inner tubing member moveable between an open position where fluids can pass through the inner tubing member of the flow control valve, a closed position where fluids are prevented from passing through the inner tubing member of the flow control valve, and intermediate positions between the open position and the closed position. The flow control valve can have a choke member, the choke member being extendable across an annular exit port, varying a cross sectional area of the annular exit port. 
     In other alternate embodiments, an inner tubing member pressure gauge senses an inner tubing member fluid pressure, and pressure an annular conduit pressure gauge senses an annular conduit fluid pressure. A hydraulic control system is in communication with a valve member located in the inner tubing member and with a choke member located between a central flow path of the inner tubing member and the annular conduit. 
     In another embodiment of the current application, a production system for use in a wellbore having a main bore with au axis, a lower lateral bore, and an upper lateral bore includes a hollow whipstock with a central bore. The hollow whipstock is secured to the main bore between the lower lateral bore and the upper lateral bore. A sleeve assembly has a moveable inner sleeve with an outer diameter smaller than an inner diameter of the central bore of the hollow whipstock. A moveable outer sleeve has an outer diameter larger than the inner diameter of the central bore of the hollow whipstock. An intermediate member is located between the moveable inner sleeve and the moveable outer sleeve, the intermediate member being statically secured within the main bore. A flow control valve is located in the main bore above the upper lateral bore. The flow control valve has an inner body with a central flow path in fluid communication with the sleeve assembly, and an outer casing circumscribing a portion of the inner body and defining annular conduit between the inner body and the outer casing, the annular conduit being in fluid communication with the main bore. 
     In alternate embodiments, the flow control valve has a sliding sleeve system that includes a sliding sleeve moveable between an open position where fluids from the annular conduit can flow from the annular conduit into an exit port of the annular conduit, and a closed position where fluids from the annular conduit are prevented from flowing into the exit port. A biasing member urges the sliding sleeve towards the open position or a closed position. An opening pressure surface is acted on by main bore fluids and a closing pressure surface is acted on by central flow path fluids such that when forces on the closing pressure surface exceeds forces on the opening pressure surface and overcome the biasing member, the sliding sleeve is automatically moved towards a closed position. 
     In other alternate embodiments, the flow control valve has a valve member located in the central flow path of the inner body and moveable between an open position where fluids can pass through the central flow path, a closed position where fluids are prevented from passing through the central flow path, and intermediate positions between the open position and the closed position. 
     In another embodiment of this disclosure, a method for producing fluids from a wellbore having a main bore with an axis and a lower lateral bore includes setting a hollow whipstock in the main bore above the lower lateral bore and drilling an upper lateral bore, the hollow whipstock having a central bore. An upper completion is run into the main bore and set in the main bore axially above the upper lateral bore. The upper completion includes a sleeve assembly with a moveable inner sleeve having an outer diameter smaller than an inner diameter of the central bore of the hollow whipstock, and a moveable outer sleeve with an outer diameter larger than the inner diameter of the central bore of the hollow whipstock. A flow control valve has an inner tubing member in fluid communication with the sleeve assembly and an annular conduit in fluid communication with the main bore. An end of the moveable inner sleeve is inserted into the central bore of the hollow whipstock. The volume of fluids being produced from the lower lateral bore and from the upper lateral bore is controlled with the flow control valve. 
     In alternate embodiments, the end of the moveable inner sleeve is pulled out of the central bore of the hollow whipstock. An end of the moveable outer sleeve is inserted into the upper lateral bore. The upper lateral bore is accessed and a production procedure is performed in the upper lateral bore. The production procedure can be, for example, production logging, reservoir stimulation or water shut-off. 
     In other alternate embodiments, the step of pulling the end of the moveable inner sleeve out of the central bore of the hollow whipstock includes engaging the inner sleeve with an inner sleeve setting tool on wireline. The step of inserting the end of the moveable outer sleeve into the upper lateral bore can include engaging the outer sleeve with an outer sleeve setting tool on a coiled tubing. 
     In yet other alternate embodiments, the step of controlling the volume of fluids being produced from the lower lateral bore includes operating a valve member located in the lateral bore to move the valve member between an open position where fluids can pass through the inner tubing member of the flow control valve, to a closed position where fluids are prevented from passing through the inner tubing member of the flow control valve, and intermediate positions between the open position and the closed position. Alternately, the step of controlling the volume of fluids being produced from the upper lateral bore includes operating a choke member that is extendable across an exit port between the annular conduit and the inner tubing member, varying the cross sectional area of the port. 
     In still other alternate embodiments, the upper completion has a production packer and the step of setting the upper completion in the main bore includes setting the production packer in the main bore axially above the upper lateral bore. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above-recited features, aspects and advantages of the invention, as well as others that will become apparent, 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 that are illustrated in the drawings that form a part of this specification. It is to be noted, however, that the appended drawings illustrate only preferred embodiments of the invention and are, therefore, not to be considered limiting of the invention&#39;s scope, for the invention may admit to other equally effective embodiments. 
         FIG. 1  is a schematic partial section view of a multi-lateral production system in accordance with an embodiment of this disclosure, shown with an end of the moveable inner sleeve located in the hollow whipstock. 
         FIG. 2  is a schematic partial section view of the multi-lateral production system of  FIG. 1 , shown with and end of the moveable outer sleeve located in the upper lateral. 
         FIG. 3  is a schematic section view of the sleeve assembly of  FIG. 1 , shown with an end of the moveable inner sleeve located in the hollow whipstock. 
         FIG. 4  is a schematic cross section view of the sleeve assembly of  FIG. 3 . 
         FIG. 5  is a schematic section view of the sleeve assembly of  FIG. 1 , shown with the moveable outer sleeve in an extended position. 
         FIG. 6  is a schematic section view of the flow control valve of  FIG. 1 , shown with the sliding sleeve in an open position, the valve member in an open position, and the choke member in a retracted position. 
         FIG. 7  is a schematic section view of the flow control valve of  FIG. 1 , shown with the sliding sleeve in a closed position, the valve member in a closed position, and the choke member in a retracted position. 
         FIG. 8  is a schematic section view of the flow control valve of  FIG. 1 , shown with the sliding sleeve in an open position, the valve member in an open position, and the choke member in an extended position. 
     
    
    
     DETAILED DESCRIPTION OF THE EXEMPLARY EMBODIMENTS 
     The present invention will now be described more fully hereinafter with reference to the accompanying drawings which illustrate embodiments of the invention. This invention may, however, be embodied in many different forms and should not be construed as limited to the illustrated embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the invention to those skilled in the art. Like numbers refer to like elements throughout, and the prime notation, if used, indicates similar elements in alternative embodiments or positions. 
     In the following discussion, numerous specific details are set forth to provide a thorough understanding of the present invention. However, it will be obvious to those skilled in the art that the present invention can be practiced without such specific details. Additionally, for the most part, details concerning well drilling, reservoir testing, well completion and the like have been omitted inasmuch as such details, are not considered necessary to obtain a complete understanding of the present invention, and are considered to be within the skills of persons skilled in the relevant art. 
     Referring to  FIGS. 1-2 , a multi-lateral well system  11  includes a wellbore  13 . In the illustrated embodiment, wellbore  13  includes a main bore  15  with a central axis  17 . Main bore  15  can be a vertical well bore or can be angled relative to a horizontal plane, as shown in  FIGS. 1-2 . Wellbore  13  also includes lower lateral bore  19  and upper lateral bore  21 , each having a heel  23  and a toe  25  extending generally horizontally from main bore  15 . Wellbore  13  can be installed with liner  27  which is cemented in place with a cement layer  29 . Cement layer  29  can protect liner  27  and act as an isolation barrier. Upper and lower lateral bores  19 ,  21  can be uncased, as shown. 
     Production system  31  is located within wellbore  13 . Production system  31  includes isolation packer  33  with tail pipe  35 . Isolation packer  33  is set within main bore  15  axially located between lower lateral bore  19  and upper lateral bore  21 . Tail pipe  35  is a tubular member that extends axially downward from isolation packer  33 . A packer bore  36  ( FIG. 3 ) extends through both the isolation packer  33  and tail pipe  35 . Isolation packer  33  seals an annulus between tail pipe  35  and main bore  15  and can isolate main bore  15  axially above isolation packer  33  from fluids in wellbore  13  axially below isolation packer  33 , other than fluids that pass through tail pipe  35 . 
     Hollow whipstock  37  is set on top of isolation packer  33  so that a bottom surface of hollow whipstock  37  mates with a top surface of isolation packer  33 . Hollow whipstock  37  has central bore  39  that extends through the axial length of hollow whipstock  37 . Central bore  39  is in fluid communication with packer bore  36 . Hollow whipstock  37  is secured within main bore  15  by anchor slips  41 , which are located axially between lower lateral bore  19  and upper lateral bore  21 . Packer element  43  can optionally be used to seal between an outer diameter of hollow whipstock  37  and an inner diameter of main bore  15 . 
     Upper completion  45  is set in main bore  15  axially above upper lateral bore  21 . Upper completion  45  is set within main bore  15  with production packer  47 . Production packer  47  seals an annulus between tubular  49  and main bore  15 , and can isolate main bore  15  axially above production packer  47  from fluids in wellbore  13  axially below production packer  47 , other than fluids that pass through tubular  49 . Tubular  49  can be, for example, production tubing. 
     Looking now at  FIGS. 1-4  upper completion  45  includes sleeve assembly  51 . An upper end of sleeve assembly  51  is located in main bore  15  axially above upper lateral bore  21 . Sleeve assembly  51  has moveable inner sleeve  53  and moveable outer sleeve  55 . Moveable inner sleeve  53  is a tubular shaped member with a central bore. Moveable inner sleeve  53  is sized to be selectively insertable into central bore  39  of hollow whipstock  37 . For example, moveable inner sleeve  53  has an outer diameter that is smaller than an inner diameter of central bore  39  of hollow whipstock  37  and has a sufficient axial length to extend downward and into central bore  39  of hollow whipstock  37 . 
     When the end of moveable inner sleeve  53  is located within the central bore  39  of hollow whipstock  37 , at least one pressure seal  56  seals the annular space between the outer diameter of moveable inner sleeve  53  and the inner diameter of central bore  39 . Therefore fluids in the wellbore  13  axially below isolation packer  33  can travel into tail pipe  35 , through isolation packer  33  and into moveable inner sleeve  53 . 
     Moveable outer sleeve  55  is a tubular shaped member with a central bore. The central bore of moveable outer sleeve  55  has a larger inner diameter than the outer diameter of moveable inner sleeve  53 . Moveable outer sleeve  55  is concentric with, and circumscribes a portion of, moveable inner sleeve  53 . An outer diameter of moveable outer sleeve  55  is larger than the inner diameter of central bore  39  of hollow whipstock  37  so that moveable outer sleeve  55  cannot be inserted into central bore  39  of hollow whipstock  37 . Moveable outer sleeve  55  is instead sized to be selectively insertable into upper lateral bore  21 . Stabilizers  57  are located on an outside surface of moveable outer sleeve  55  and be fixed on moveable outer sleeve  55  to move with moveable outer sleeve  55  within wellbore  13 . Stabilizers  57  can be spaced around a circumference of moveable outer sleeve  55  and can center moveable outer sleeve  55  within wellbore  13 . 
     Sleeve assembly  51  also includes intermediate member  59 . Intermediate member  59  is a non-moveable tubular member with a central bore. Intermediate member  59  circumscribes a portion of moveable inner sleeve  53  and is circumscribed by a portion of moveable outer sleeve  55 . Intermediate member  59  is statically secured within main bore  15  by production packer  47 . Intermediate member  59  is coupled to production packer  47  by way of intermediate components of upper completion  45 . 
     A series of locks  61  and grooves  63  of sleeve assembly  51  operate to maintain the desired position of moveable inner sleeve  53  and moveable outer sleeve  55  relative to intermediate member  59 . Locks  61  can be spring loaded compressible locks and located proximate to an upper end of moveable inner sleeve  53  on an outer diameter of moveable inner sleeve. Similar locks can also be located proximate to an upper end of moveable outer sleeve  55 , on an inner diameter surface of moveable outer sleeve  55 . Locks  61  have an outer profile that mate with an inner profile of grooves  63 . Grooves  63  for mating with locks  61  of moveable inner sleeve  53  are located at upper and lower ends of an inner diameter surface of intermediate member  59 . Grooves  63  for mating with locks  61  of moveable outer sleeve  55  are located at upper and lower ends of an outer diameter surface of intermediate member  59 . 
     Intermediate member  59  also includes an inner stop ring  65  and an outer stop ring  67 . Inner stop ring  65  can engage a stop ring, lock  61  or other protrusion of moveable inner sleeve  53  to limit downward axial moveable inner sleeve  53  and prevent moveable inner sleeve  53  from traveling completely out of the lower end of intermediate member  59 . Outer stop ring  67  can engage a stop ring, lock  61  or other protrusion of moveable outer sleeve  55  to limit downward axial moveable outer sleeve  55  and prevent moveable inner sleeve  53  from traveling completely out of the lower end of intermediate member  59 . 
     Each of the moveable inner sleeve  53  and moveable outer sleeve  55  have extended and contracted positions, relative to intermediate member  59 . As seen in  FIG. 3 , when moveable inner sleeve  53  is in an extended position, a maximal length of moveable inner sleeve  53  protrudes from a bottom end of intermediate member  59  and the end of moveable inner sleeve  53  is located within central bore  39  of hollow whipstock  37 . In such an extended position, lock  61  of movable inner sleeve  53  is located within groove  63  located at the lower end of intermediate member  59 . As seen in  FIG. 5 , when moveable inner sleeve  53  is in a contracted position, a lesser length of moveable inner sleeve  53  protrudes from a bottom end of intermediate sleeve  59 . In such a contracted position, lock  61  of moveable inner sleeve  53  is located within groove  63  located at the upper end of intermediate member  59 . 
     Looking now at  FIGS. 3 and 5 , moveable inner sleeve  53  has a sleeve profile  69  on an inner diameter of inner sleeve  53 , proximate to the upper end of moveable inner sleeve  53 . In order to move moveable inner sleeve  53  between the extended position and contracted position, inner sleeve setting tool  71  can be lowered through wellbore  13  and into the central bore of moveable inner sleeve  53  on a wireline  73 . An outer profile on inner sleeve setting tool  71  can engage sleeve profile  69  and wireline  73  can be used to raise and lower moveable inner sleeve  53 . 
     As seen in  FIG. 5 , when moveable outer sleeve  55  is in an extended position, a maximal length of moveable outer sleeve  55  protrudes from a bottom end of intermediate member  59  and the end of moveable outer sleeve  55  is located within upper lateral bore  21 . In the extended position, moveable outer sleeve  55  is in a bent or curved shape in order to extend through the transition between main bore  15  and upper lateral bore  21 . In such an extended position, lock  61  of moveable outer sleeve  55  is located within groove  63  located at a lower end of intermediate member  59 . As seen in  FIG. 3 , when moveable outer sleeve  55  is in a contracted position, a lesser length of moveable outer sleeve  55  protrudes from a bottom end of intermediate member  59 . In such a contracted position, lock  61  of moveable outer sleeve  55  is located within groove  63  located at the upper end of intermediate sleeve  59 . 
     Looking now at  FIG. 5 , in order to move moveable outer sleeve  55  between the extended position and contracted position, outer sleeve setting tool  75  can be lowered through wellbore  13 , through the central bore of moveable inner sleeve  53 , and into the central bore of movable outer sleeve  55 , on coiled tubing  77 . Outer sleeve setting tool  75  can be an inflatable packer that is then inflated to engage the central bore of moveable outer sleeve  55 . Coiled tubing  77  can be used to raise and lower moveable outer sleeve  55 . 
     Turning now to  FIGS. 1-2 and 6-8 , upper completion  45  also includes flow control valve  79 . Flow control valve  79  is located in main bore  15  axially above upper lateral bore  21 . Flow control valve  79  has inner tubing member  81 , which is an inner body with a central flow path  83 . Central flow path  83  of inner tubing member  81  is in fluid communication with sleeve assembly  51 . Flow control valve  79  also has outer casing  85 , which is tubular member that circumscribes a portion of inner tubing member  81 . Annular conduit  87  is defined between outer casing  85  and inner tubing member  81 . Annular conduit  87  is in fluid communication with main bore  15  between isolation packer  33  and production packer  47 . 
     Inner tubing member  81  has tubing entry end  89  in fluid communication with sleeve assembly  51 , and tubing exit end  91  that is in fluid communication with main bore  15  above production packer  47 . Annular conduit  87  has annular entry end  93  in fluid communication with main bore  15  axially below production packer  47 , and exit port  95  in fluid communication with tubing exit end  91 . Exit port  95  can be a radially extending bore through a sidewall of tubing member  81 . A plurality of exit ports  95  can be spaces round inner tubing member  81 . 
     Flow control valve  79  includes sliding sleeve system  97 . Sliding sleeve system  97  includes sliding sleeve  99  that is moveable between an open position where fluids from annular conduit  87  can flow into exit port  95 , and a closed position where fluids from annular conduit  87  are prevented from flowing into exit port  95 . Sliding sleeve  99  is a generally tubular member that circumscribes inner tubing member  81 . An end of sliding sleeve  99  has opening pressure surface  101  on one side and closing pressure surface  103  on an opposite side. Opening pressure surface  101  is acted on by fluid from main bore  15  between isolation packer  33  and production packer  47  that flows into annular conduit  87  of flow control valve  79 . The force of such fluids acting on opening pressure surface  101  urges sliding sleeve  99  towards the open position. 
     Closing pressure surface  103  is acted on by biasing member  105 , urging sliding sleeve  99  towards the open position when biasing member  105  is compressed ( FIG. 8 ), and urging sliding sleeve  99  towards the closed position when biasing member  105  is extended ( FIG. 7 ). In addition, closing pressure surface  103  is acted on by fluid from inner tubing member  81 . When the forces of fluids from inner tubing member  81  and biasing member  105  acting on closing pressure surface  103  exceeds the forces on opening pressure surface  101  by fluids in annular conduit  87 , sliding sleeve  99  is moved towards the closed position, as shown in  FIG. 7 . Conversely, when the forces on opening pressure surface  101  by fluids in annular conduit  87  exceed the forces of fluids from inner tubing member  81  and biasing member  105  acting on closing pressure surface  103 , sliding sleeve  99  is moved towards the open position, as shown in  FIGS. 6 and 8 . When the forces on opening pressure surface  101  by fluids in annular conduit  87  is essentially equal to the forces of fluids from inner tubing member  81  acting on closing pressure surface  103 , biasing member  105  will be relaxed and sliding sleeve  99  is in a neutral position, as shown in  FIG. 6 . In the neutral position, fluids from annular conduit  87  can flow into exit port  95 . Biasing member  105  can be, for example, a spring. 
     Looking at  FIGS. 6-8 , flow control valve  79  additionally includes valve member  107  that is located within inner tubing member  81 . Valve member  107  is moveable between an open position where fluids can pass through inner tubing member  81  of flow control valve  79 , as seen in  FIGS. 6 and 8 . Valve member  107  is also movable to a closed position where fluids are prevented from passing through inner tubing member  81  of flow control valve  79  (not shown). Valve member  107  can be located at intermediate positions between the open position and the closed position where some fluids can pass through inner tubing member  81  of flow control valve  79 , as seen in  FIG. 7 . Valve member  107  can be a hydraulically operated ball valve. A hydraulic control system can include hydraulic control line  110  for moving valve member  107  to a closed position. A spring member  111  can urge valve member  107  towards a normal open position. 
     Looking again at  FIGS. 6-8 , flow control valve  79  has a choke member  109 . Choke member  109  can be a pin that extends across exit port  95 , varying the cross sectional area of exit port  95  so that the flow from of fluids annular conduit  87  to central flow path  83  through exit port  95  is restricted. The hydraulic control system can also include hydraulic control line  113  for moving choke member  109  into an extended condition into exit port  95 . Spring  114  can urge choke member  109  into a retracted position where choke member does not extend into exit port  95 . Each exit port  95  can have a separate choke member  109 . 
     Flow control valve  79  can further include tubing pressure gauge  115  and annular conduit pressure gauge  117 . Tubing pressure gauge  115  is located in, or adjacent to, central flow path  83  and can sense an inner tubing fluid pressure, that is, the pressure of the fluid within central flow path  83  of inner tubing member  81 . Annular conduit fluid pressure gauge  117  is located in, or adjacent to, annular conduit  87  cam can sense an annular conduit fluid pressure, that is, the pressure of the fluids within annular conduit  87 . Data cable  119  can transmit pressure data from tubing pressure gauge  115  and annular conduit pressure gauge  117  to an operator. 
     In an example of operation, looking at  FIG. 1 , main bore  15  can be drilled and liner  27  can be cemented in place in a conventional manner. Liner  27  can be cleaned out and lower lateral bore  19  can be drilled. Lower lateral bore  19  can be cleaned out and displacement operations can be undertaken with brine in lower lateral bore  19 . Isolation packer  33  with tail pipe  35  can be set within main bore  15 . Tail pipe  35  can have a ceramic disk or retrievable plug (not shown) to prevent fluids from passing through tail pipe  35  while production system  31  is installed in wellbore  13 . 
     Hollow whipstock  37  can then be run into wellbore  13 , oriented, and set on top of isolation packer  33  in main bore  15 . Hollow whipstock  37  can have a debris catcher (not shown) located within central bore  39 . Exit window  121  can be cut through liner  27  and cement layer  29  and upper lateral bore  21  can be drilled with a directional drilling assembly. Upper lateral bore  21  can be cleaned out and displacement operations can be undertaken with brine in upper lateral bore  21 . The debris catcher can then be retrieved from the central bore  39  of hollow whipstock  37 . 
     Upper completion  45  can be run into main bore  15  and set. Production packer  47  can set upper completion  45  in main bore  15  axially above upper lateral bore  21 . Moveable inner sleeve  53  can be in an extended position and the end of moveable inner sleeve  53  can be inserted into central bore  39  of hollow whipstock  37 . Ceramic disk located in tail pipe  35  can then be ruptured, or retrievable plug located in tail pipe  35  can be retrieved, as applicable. Well system  11  is now ready to begin producing. 
     Because the end of moveable inner sleeve  53  is sealingly located in central bore  39  of hollow whipstock  37 , fluids entering central flow path  83  of flow control valve  79  will be from lower lateral bore  19  and fluids entering annular conduit  87  will be from upper lateral bore  21 . Flow control valve  79  can both automatically and mechanically control the volume of fluids being produced from lower lateral bore  19  and upper lateral bore  21 . Looking at  FIG. 6 , when the pressure of fluids in annular conduit  87  is similar to the pressure of fluids in central flow path  83 , sliding sleeve  99  is in the neutral position, and biasing member  105  is relaxed. Fluids from annular conduit  87  can flow into exit port  95 . With valve member  107  in the open position and choke member  109  in the retracted position, both lower lateral bore  19  and upper lateral bore  21  are being produced. 
     Turning to  FIG. 7 , when the pressure of fluids in annular conduit  87  is significantly less than the pressure of fluids in central flow path  83 , biasing member  105  is in an extended position and sliding sleeve  99  is in the closed position. Fluids from annular conduit  87  cannot flow into exit port  95  and only fluids from lower lateral bore  19  can be produced. This will prevent dumping into the upper lateral bore  21 . As pressure depletes in the lower lateral bore  19  and becomes similar to the pressure of upper lateral bore  21 , siding sleeve  99  will automatically move to the neutral position and both lower lateral bore  19  and upper lateral bore  21  will be produced, as shown in  FIG. 6 . 
     Turning now to  FIG. 8 , when the pressure of fluids in annular conduit  87  is significantly greater than the pressure of fluids in central flow path  83 , biasing member  105  is in a contracted position and sliding sleeve  99  is in the open position. Fluids from annular conduit  87  can flow into exit port  95 . Although fluids from both lower lateral bore  19  and upper lateral bore  21  can be produced, due to the difference in pressures, it will be mainly fluids from upper lateral bore  21  that are being produced. In this way, flow control valve will automatically allow the higher pressure reservoir produce first. 
     The operator can at any time review pressure data received from tubing pressure gauge  115  and annular conduit pressure gauge  117  by way of data cable  119 . The operator can choose to use the hydraulic control system to move valve member  107  into an intermediate or closed position ( FIG. 7 ) in order to reduce or stop the flow of produced fluids from lower lateral bore  19 , to optimize production. The operator can also choose to use the hydraulic control system to extend choke member  109  partially into, or fully across exit port  95  ( FIG. 8 ) in order to reduce or stop the flow of produced fluids from upper lateral bore  21 , to optimize production. 
     Turning back to  FIG. 3 , if is desirable for a production procedure, such as production logging, reservoir stimulation or water shut-off, to be performed in upper lateral bore  21 , inner sleeve setting tool  71  can be lowered into wellbore  13  on wireline  73 . The outer profile on inner sleeve setting tool  71  can engage sleeve profile  69  and wireline  73  can be used to pull moveable inner sleeve  53  upwards and into the intermediate sleeve  59  so that movable inner sleeve  53  is in the contracted position and lock  61  of moveable inner sleeve  53  is located within groove  63  located at the upper end of intermediate sleeve  59 . Inner sleeve setting tool  71  can then be retrieved. 
     Looking now at  FIG. 5 , outer sleeve setting tool  75  can then be run into wellbore  13  on coiled tubing  77 . After passing completely through moveable inner sleeve  53 , outer sleeve setting tool  75  can be inflated to engage moveable outer sleeve  55 . Moveable outer sleeve  55  can then be moved downward. Because the outer diameter of moveable outer sleeve  55  is too large to fit within central bore  39  of hollow whipstock  37 , hollow whipstock  37  will defect the lower end of moveable outer sleeve  55  into upper lateral bore  21 . Moveable outer sleeve  55  can be moved downward until lock  61  of moveable outer sleeve  55  is located within groove  63  located at a lower end of intermediate member  59 . Outer sleeve setting tool  75  can then be deflated and retrieved. Upper lateral bore  21  is then ready for reservoir access procedures such as, for example, logging, stimulation, or water-shut-off. Moveable outer sleeve  55  is not sealingly engaged with upper lateral bore  21 . Therefore, while the lower end of moveable outer sleeve  55  is located in upper lateral bore  21 , fluids from both lower lateral bore  19  and upper lateral bore  21  will mingle and can enter either central flow path  83  or annular conduit  87 . If the lower lateral bore  19  is required for pressure isolation during the above stated procedure in the upper lateral bore, a retrievable plug can be run and set in the tail pipe  35  (not shown). 
     The use of hollow whipstock  37  eliminates the common practice of retrieving the whipstock, and ensures an effective production conduit and full access to lower lateral bore  19 . Sleeve assembly  51  enables full access to both lower lateral bore  19  and upper lateral bore  21  for reservoir production logging, stimulation, and or water shut-off process. Sleeve assembly  51  also enables a bigger pass-through diameter for full access to both laterals, than traditional methods. Flow control valve  79  provides automated flow control and downhole pressure gauge data collection for production monitoring purpose and independent choke mechanisms for both lower lateral bore  19  and upper lateral bore  21  by way of the hydraulic control system. 
     The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.