Abstract:
The present invention provides a method and apparatus for mechanically interconnecting a lateral wellbore liner to a main, or parent, wellbore casing. The present invention further provides a method of wellbore construction for the construction of multiple wellbores which are interconnected downhole to form a manifold of pipelines in a reservoirs of interest. Provision is made for flow controls, sensors, data transmission, power generation, and other operations positioned in the lateral wellbores during the drilling, completion and production phases of such wellbores.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates generally to wellbore construction and more particularly to the construction of multiple wellbores which are interconnected downhole to form a manifold of pipelines in the reservoirs of interest. Provision is made for flow controls, sensors, data transmission, power generation, and other operations positioned in the lateral wellbores during the drilling, completion and production phases of such wellbores. 
     2. Background of the Related Art 
     To obtain hydrocarbons such as oil and gas, wellbores or boreholes are drilled from one or more surface locations into hydrocarbon-bearing subterranean geological strata or formations (also referred to herein as reservoirs). A large proportion of the current drilling activity involves drilling deviated and/or substantially horizontal wellbores extending through such reservoirs. To develop an oil and gas field, especially offshore, multiple wellbores are drilled from an offshore rig or platform stationed at a fixed location. A template is placed on the sea bed, defining the location and size of each of the multiple wellbores to be drilled. The various wellbores are then drilled from the template along their respective pre-determined wellpaths (or drilling course) to their respective reservoir targets. Frequently, ten to thirty offshore wells are drilled from an offshore rig stationed at a single location. In some regions such as the North Sea, as many as sixty separate wellbores have been drilled from an offshore platform stationed at a single location. The initial drilling direction of several thousand feet of each such wellbore is generally vertical and typically lies in a non-producing (non-hydrocarbon bearing) formation. 
     Each wellbore is then completed to produce hydrocarbons from its associated subsurface formations. Completion of a wellbore typically includes placing casings through the entire length of the wellbore, perforating production zones, and installing safety devices, flow control devices, zone isolation devices, and other devices within the wellbore. Additionally each wellbore has associated wellhead equipment, generally referred to as a “tree” and includes closure valves, connections to flowlines, connections for risers and blowout preventors, and other devices. 
     As an example, ten wellbores may be drilled from a single offshore platform, each wellbore having a nine-inch internal diameter. Assuming that there is no production zone for the initial five thousand feet for any of the wellbores, there would be a total of fifty thousand feet (five thousand for each of ten wellbores) of non-producing wellbore that must be drilled and completed, serving little useful purpose. It may, therefore, be desirable to drill as few upper portions as necessary from a single location or site, especially as the cost of the drilling and completing offshore wellbores can range from $100 to $300 per foot of wellbore drilled and completed. 
     Multilateral well schemes have been proposed since the 1920&#39;s. Various methods of constructing these well geometry&#39;s have been disclosed showing methods of creating the wellbores, methods of mechanically connecting casings in the various wellbores drilled, methods of sealing the casing junctions, and various methods of providing re-entry access to the lateral wellbores for remedial treatments. 
     Multilateral wellbore junction construction is currently thought of as fitting into one of six levels of complexity. Level 1 is generally thought of as open hole sidetracks where lateral wellbores are drilled from an open hole (uncased) section of the main well. No casing is present in the main well or lateral well at the junction of the two wellbores. This method is generally the least expensive but does not ensure wellbore stability, does not provide a method of easy lateral re-entry, and it does not seal the junction in a manner to allow future flow control of the lateral versus the main wellbore. 
     Level 2 multilateral junctions are those where the lateral exits from a cased main well using section miling or whipstock methods to create the exit. The lateral wellbore may be left as open hole or a liner may be run and “dropped off” outside the main well casing exit such that the lateral liner and main casing are not connected and an openhole junction results. This method is currently a little more costly than Level 1; it provides some more assurance of re-entry access to laterals, and it can provide some flow control of the various wellbores. It does not however protect or reinforce the junction area against potential collapse of the open hole wellbore wall. 
     Level 3 junctions provide laterals exiting from a cased main well and a lateral liner is run in the lateral wellbore and mechanically connected to the main casing but no seal of the junction is achieved. This method supports the borehole created and provides access to laterals but the lack of a seal at the junction can lead to sand production or fluid inflow or outflow into the junction rock strata. In many applications this inflow or outflow of fluids at junction depth is not desirable as the laterals may penetrate strata of different pressures and the unsealed junction could result in an underground blow out. 
     Level 4 junctions also provide a lateral wellbore exiting from a cased main well and a lateral liner is run into the lateral wellbore with the top end of the lateral casing extending back to the main casing with the junction of the lateral liner and main casing sealed with cement or some other hardening liquid material that can be pumped in place around the junction. This method achieves isolation of the junction from adjoining strata providing a sufficient length annular seal can be placed around the lateral liner and provided the main casing has an annular seal between the casing and the main wellbore wall. Various methods of reentry access to the laterals is provided using deflectors or other devices. The pressure seal integrity achieved in this type of wellbore junction is generally dependent on rock properties of the junction strata and cannot exceed the junction strata fracture pressure by more than a few hundred pounds per square inch. In addition the guaranteed placement and strength of liquid cementatious hardening materials in a downhole environment is extremely difficult with washouts causing slow fluid velocities, debris causing contamination of sealing materials, fluid mixing causing dilution, gelled drilling muds resisting displacement, etc. The junction may be isolated from adjoining zones but seal reliability specifically at the junction is difficult. 
     Level 5 systems generally provide lateral wellbores exiting from a cased main well. Liners are run in the lateral wellbore and may be “dropped off” outside the window in the main casing or a Level 4 type cemented intersection may be created. The Level 5 systems however use production tubulars and mechanical packer devices to mechanically connect and seal the main casing and lateral liners to each other. Level 5 systems can achieve a junction seal exceeding the junction strata capability by five to ten thousand psi. These systems do however restrict the diameter of access to the lateral and main casings below the junctions due to the relatively small tubular diameters compared to casing sizes. Well designs must also generally consider the possibility of a leak in the junction tubulars. This limits the application of Level 5 systems to generally those applications where the junction pressures are abnormal for the junction rock only due to surface applied pressures such as may be encountered in injection wells or during well stimulations. Flow rates achievable through such junctions are also restricted to the rates possible through the smaller diameter tubulars. 
     Level 6 junctions create a mechanically sealed junction between the main casing and lateral liner without using the restricting bores of production tubulars to achieve the seal. The methods devised to date generally are of two categories. One category uses prefabricated junctions in which one or both bores are deformed. This prefabricated piece is lowered into the well bore on a casing string and located in an enlarged or underreamed section of hole such that it can be expanded or unfolded into its original shape/size. The casing string with the prefabricated junction is then cemented in the wellbore. The lateral borehole is then drilled from the lateral stub outlet and a lateral liner is hung/sealed in the lateral stub outlet. A second category of Level 6 junction currently used creates an oversized main well borehole and full size underformed junctions are run into the main wellbore on the main casing. Laterals can then be drilled from a lateral stub outlet as described from the previous category. 
     FIGS. 1 a  to  1   f  illustrate several conventional methods  200   a  to  200   f  for forming multiple lateral wellbores into reservoirs  202   a  and  202   b . Multiple lateral wellbores or drainholes  204  are conventionally drilled from the cased main wellbore  208  or from the openhole section  206  of the main wellbore. When constructing the laterals  204   a  from a cased hole  208 , a whipstock  214  is usually anchored in main well casing  208  by means of a packer or anchoring mechanism  216 . A milling tool (not shown) is deflected by the whipstock face  218  to cut a window  210  in the casing  208 . The lateral wellbore  204   a  is then directionally drilled to intersect its targeted reservoir  202   a . The whipstock face  218  is typically 1 to  6  degrees out of alignment with the longitudinal axis of the whipstock  214  and the lateral wellbore  204   a  is directed away from the main wellbore casing  208  at a substantially equal angle. The intersection or junction between the lateral liner  220  and the main well casing  208  thus created is elliptical in its side view, curved in its cross section, and lengthy due to the shallow angle of departure from the main well casing  208 . This conventional prior art method  200   a-d  creates a geometry that is difficult to seal with appreciable mechanical strength or differential pressure resistance. Method  200   e  of FIG. 1 e  uses tubulars and packers to mechanically seal the junction but restricts the final production flow area and access diameters to the two production bores. Method  200   f  of FIG. 1 f  uses a prefabricated junction which is deployed in place in an underreamed or enlarged section of the wellbore. This method requires an enlarged wellbore to the surface or an underreamed portion. If the underreamed wellbore approach is used then current technology deforms the junction piece in the underrearned section and by nature of design uses a low yield strength material which causes low pressure ratings. Alternatively this method may use an oversized diameter main wellbore to allow a prefabricated junction to be placed at the desired depth. 
     In the conventional multilateral wellbore construction methods described above, the lateral borehole is typically drilled from the main casing and departs the main casing at a shallow angle of 1 to 6 degrees relative to the longitudinal axis of the main casing. Recently, however, multilateral wellbores have been constructed by drilling separate lateral wellbores towards the main well casing, from the outside of the main casing so that the downhole end of the lateral wellbore is located proximate perforations in the main wellbore or even intersecting with the main wellbore if possible. Production fluids such as hydrocarbons can, therefore, be flowed between the main wellbore and the lateral wellbores. 
     However, such prior methods of constructing multilateral wellbores do not provide a mechanical connection or other suitable seal against downhole pressures between the main wellbore and the lateral wellbores. Accordingly, in a particular application such conventional techniques may only be desirable in situations in which the lateral wellbore intersects a production zone co-extensive with a production zone of the main wellbore. The present invention provides a method of mechanically connecting the lateral liner to the main casing and sealing the junction, which may be beneficial for multilateral wellbore construction where it is desirable to intersect a main wellbore with lateral wellbores drilled from outside the main wellbore in a direction generally towards the main wellbore. 
     In operations in which high pressure connections are desired, the less desirable conventional drilling techniques described above may heretofore have been employed which require deviating the lateral wellbores from within the main, or parent, wellbore. However, these conventional multilateral wellbore construction techniques may also cause undue casing wear in the parent wellbore when many lateral wellbores are drilled from a common parent well. In such a case, the parent well casing may be exposed to thousands of drillpipe rotations and reciprocations executed in the drilling. This drilling process wears away the metal walls of the casing internal diameter. Drill pipe is also used over and over and is therefore commonly treated with a hard coating on the tool joints to minimize the wear on the drill pipe itself. This wear resistant coating on the drill pipe can increase the wear on the casing. Since the production of the wellbore typically flows through the parent wellbore to the surface, the parent casing typically must have sufficient strength after drilling wear to contain wellbore pressures while also accounting for corrosion and erosion expected during the production phase of the well. Accordingly, a need has arisen to provide mechanical connection methods and apparatus between lateral wellbores and parent wellbores for operations in which it may be beneficial to drill the lateral wellbores from outside the parent wellbore in a direction towards the parent wellbore. 
     Further, during the completion of a wellbore, a number of devices are utilized in the wellbore to perform specific functions or operations. Such devices may include packers, sliding sleeves, perforating guns, fluid flow control devices, and a number of sensors. To efficiently produce hydrocarbons from wellbores drilled from a single location or from multilateral wellbores, various remotely actuated devices can be installed to control fluid flow from various subterranean zones. Some operators are now permanently installing a variety of devices and sensors in the wellbores. Some of these devices, such as sleeves, can be remotely controlled to control the fluid flow from the producing zones into the wellbore. The sensors are used to periodically provide information about formation parameters, condition of the wellbore, fluid properties, etc. Until now the flow control devices and sensors have been installed in the main well production tubing necessitating a reduction in the production flow area for a given main casing size. For example devices are now available matching 5½ inch nominal tubing to fit in 9⅝ inch nominal casing. 7 inch nominal tubing could be used in 9⅝ inch casing but the remotely operated production control devices are restricted to 5½. The present invention provides a method of placing the production control devices out of the main casing and into the lateral wellbore so they do not restrict the main casing tubular design or size and yet production of each lateral wellbore is controlled independently. 
     In deepwater fields (generally oil and gas fields lying below ocean water depths greater than 1000 ft), the costs of field development are even more extreme than the costs previously mentioned. In these environments satellite wells might be used with seafloor flowlines connected back to a central seafloor manifold for processing and a flowline extends from the central manifold to the sea surface where it is connected to a floating vessel or from the central manifold along the seafloor to a nearby existing platform or pipeline infrastructure. In these deepwater applications the reservoir fluids are subjected to cold ocean floor temperatures (which are generally 40 degrees Fahrenheit or less). These cold temperatures can cause problems in flow assurance since many hydrocarbons contain waxes which will crystallize when the fluid is cooled and can plug pipelines or flowlines especially if flow is stopped for any reason. The typical solution is to insulate individual wellbore risers from the seafloor to the sea surface and/or to insulate flowlines on the seafloor or even make provisions for flowline heating. These solutions have an associated high cost. The present invention provides for connecting wellbores at reservoir depth such that the wellbore fluids remain at substantially reservoir temperatures and pressures until they reach a common outflow wellbore to the surface thus addressing a portion of the well flow assurance concerns. 
     Accordingly, there is a need for a method and apparatus for providing mechanical connections between a main wellbore and a lateral wellbore, in which the lateral wellbore has been drilled from outside the main wellbore in a direction generally towards the main wellbore. The present invention provides a method and apparatus for providing mechanical connections between a main wellbore and a lateral wellbore, in which the lateral wellbore has been drilled from outside the main wellbore in a direction generally towards the main wellbore 
     In addition, there is a need for measurement and control apparatus in the lateral wellbores so that production through the lateral wellbores can be controlled independent of the production through the main wellbore. The present invention provides measurement and control apparatus in the lateral wellbores so that production through the lateral wellbores can be controlled independent of the production through the main wellbore. 
     SUMMARY OF THE INVENTION 
     In a particular aspect, the present invention is directed to downhole well system including a main wellbore and a lateral wellbore, wherein the lateral wellbore is drilled from outside the main wellbore in a direction generally towards the main wellbore, a wellbore junction, comprising: a mechanical seal between the lateral wellbore and the main wellbore. 
     A feature of this aspect of the invention is that the main wellbore may include a lateral receiver coupling, and wherein a fluid sealant such as cement has been pumped through the lateral wellbore and hardened to mechanically seal the lateral wellbore within the lateral receiver coupling. 
     Another feature of this aspect of the invention is that the fluid sealant may be pumped through a cementing port collar disposed within the lateral wellbore. The main wellbore may include a lateral receiver coupling, wherein the lateral wellbore includes a mechanical latching mechanism adapted to engage with the lateral receiver coupling of the main wellbore. The mechanical latching mechanism may be spring-actuated; and the spring-actuated latching mechanism may include at least one locking dog adapted to mate with a latch profile within the lateral receiver coupling. 
     Yet another feature of this aspect of the invention is that the mechanical latching mechanism may comprises: a plurality of tapered keys spaced apart and disposed about an outer surface of the lateral liner; and a plurality of tapered keys spaced apart and disposed about an inside surface of the lateral receiver coupling, whereby a keyway is provided between each of the plurality of tapered keys, and whereby rotation of the lateral liner causes the keys of the lateral liner to engage with the keys of the lateral receiver coupling to urge the lateral liner against a sealing surface associated with the lateral receiver coupling. 
     In another aspect, the present invention is directed to a latching system for mechanically interconnecting a lateral wellbore with a main wellbore, comprising: a lateral receiver coupling associated with the main wellbore; and a mechanical latching mechanism associated with the lateral wellbore. A feature of this aspect of the present invention is that the lateral receiver coupling may be adapted to receive a portion of the lateral wellbore therein. The lateral wellbore liner may also include the mechanical latching mechanism on its distal end proximate the main wellbore; and the lateral receiver coupling may also be an axial receiver coupling for joining two axially oriented wellbores. 
     Another feature of this aspect of the invention is that the lateral receiver coupling may include a receiving bore for receiving a lateral liner of the lateral wellbore. The receiving bore may extend from the main wellbore at an angle substantially 90 degrees from the long axis of the main wellbore, the receiving bore may extend from the main wellbore at an angle generally towards the wellhead, or the receiving bore may extend from the main wellbore at an angle generally away from the wellhead. 
     In yet another aspect, the present invention is directed to a method of forming a plurality of interconnected wellbores for producing hydrocarbons from or injecting fluids into earth formations comprising the steps of: forming a parent wellbore with a parent wellbore casing with one or more lateral wellbore receiver couplings placed in its casing; forming a lateral wellbore with a lateral wellbore liner to intersect the parent wellbore casing proximate the lateral wellbore receiver coupling; and mechanically connecting the lateral wellbore liner to the parent wellbore casing. 
     A feature of this aspect of the invention is that the step of forming the lateral wellbore to intersect the parent wellbore casing proximate the lateral wellbore receiver coupling may further compirse the steps of: providing a beacon within proximate the receiver coupling to emit signals adapted to be received by a sensor in a lateral wellbore drilling assembly; and steering the drilling assembly towards the lateral wellbore receiver coupling in response to the signals emitted by the beacon and received by the sensor in the drilling assembly. 
     Another feature of this aspect of the invention is that the signal emitted by the beacon may be of a type selected from the group consisting of acoustic, electromagnetic, or thermographic signals. The main wellbore may be formed in an oilfield having at least one existing wellbore and the method may further comprise the steps of establishing fluid communication between one or more of the existing wellbores and the main wellbore. 
     Yet another feature of this aspect of the invention is that the method may further comprise a step of underreaming the end of the lateral wellbore adjacent the receiver coupling to allow lateral movement and flexibility of the lateral liner for minor alignment adjustments in the mating of the lateral liner to the receiver coupling. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features, advantages and objects of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings. 
     It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
     FIGS. 1 a - 1   f  illustrate conventional methods of constructing multilateral wellbore junctions. 
     FIG. 2 is a perspective view of a main wellbore according to a first embodiment of the present invention wherein the intersection to be formed is perpendiculars 
     FIG. 3 a  is a cross-sectional view of the main wellbore of FIG. 2 showing a drilling assembly being guided by guidance beacons to intersect with a lateral receiver coupling according to an embodiment of the present invention. 
     FIG. 3 b  is a cross-sectional view of the main wellbore of FIG. 2 showing the lateral wellbore drilled according to the embodiment of FIG. 3 a , and also showing an under-reamed portion of the wellbore proximate the lateral receiver coupling according to an embodiment of the present invention. 
     FIG. 3 c  is a cross-sectional view of the main wellbore of FIG. 2 showing a lateral liner run into the lateral borehole of FIG. 3 b  and coupled to the lateral receiver coupling of the main wellbore of FIG.  2 . 
     FIG. 4 is a cross-sectional view of an embodiment of a wellbore intersection according to the present invention wherein the intersection of the two wellbores is axial. 
     FIG. 5 is a cross-sectional view of the intersected and connected liners of the main wellbore and lateral wellbore according to the embodiment shown in FIG.  2 . 
     FIG. 6 is a cross-sectional view of a portion of the lateral liner of FIG. 5, taken along section  6 — 6 . 
     FIG. 7 is a cross-sectional view of a portion of the lateral liner of FIG. 5, taken along section  7 — 7 . 
     FIG. 8 is a cross-sectional view of the intersected and connected liners of a main wellbore and a lateral wellbore according to the embodiment of FIG. 2 with flow controls and other equipment installed. 
     FIG. 9 a  is a cross-sectional view of a latching mechanism according to a first embodiment of the present invention. 
     FIG. 9 b  is a perspective view of a locking dog of the latching mechanism of FIG. 9 a  according to an embodiment of the present invention. 
     FIG. 9 c  is a side view of the locking dog within the sleeve of the latching mechanism of FIG. 9 a  and also showing the spring and push ring thereof. 
     FIG. 10 is a cross-sectional view of a latching mechanism according to a second embodiment of the present invention. 
     FIG. 11 is a projected plan view of the keys and keyways of the latching mechanism of FIG.  10 . 
     FIG. 12 is a cross-sectional view of the intersected and connected liners of a main wellbore and a lateral wellbore according to a third embodiment of the present invention. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The present invention generally provides a method and apparatus for interconnecting multilateral wellbores with a main, or parent, wellbore whereby the lateral wellbores are drilled from outside the main wellbore in a direction generally towards the main wellbore. A wellbore junction according to the present invention is generally provided by a lateral receiver coupling  22  engaged by mechanical connection with a lateral liner  50 , as described further hereinbelow. 
     Referring to FIG. 2, a perspective view of a main wellbore casing  32  is shown having lateral receiver coupling  22  connected to or otherwise disposed in connection with the outer surface thereof. The main wellbore casing  32  is adapted to be lowered or otherwise provided in a main, or parent wellbore using conventional casing methods known in the art. A plurality of guidance beacons  34  are placed at multiple positions along the lateral receiver coupling  22  or on the adjoining main well casing  32  and are known distances from the centerline  37  of the connecting lateral bore opening  36  formed by the walls of lateral receiver coupling  22 . 
     Referring now to FIG. 3 a , main wellbore casing  32  is shown in partial cross-section lowered in place within a main, or parent, wellbore  18 . It should be noted that the main wellbore may be vertical, horizontal, or have any other orientation in a particular application. In addition, the main wellbore may have separate sections which may be independently vertical, horizontal, or some other orientation relative to the surface. The main, or parent, wellbore may typically be a primary production wellbore; however, to the extent consistent herewith, the terms “main wellbore” or “parent wellbore” herein refer to any wellbore to which it may be desired to remotely couple a separate wellbore drilled from a location outside the main wellbore towards the main wellbore after the main wellbore is already in place. To the extent the context herein does not indicate anything to the contrary, the term “wellbore” herein refers to a conduit drilled through a particular geological formation and may also refer to the drilled conduit including well casing, tubing, or other members therein. The term “lateral wellbore” refers generally to the separate wellbore being drilled towards and intended to connect with the main wellbore. 
     Still with reference to FIG. 3 a , wellbore casing  32  includes lateral receiver coupling  22  disposed in connection therewith. A conventional guidance system known in the art such as guidance beacons  34  are shown in connection with the casing  32  and preferably send signals into the surrounding strata. Preferably, a plurality of guidance beacons  34  are provided on the well casing  32  and are spaced-apart from centerline  37 , which passes through the center of receiving bore  36 . A separate guidance beacon  34  may also be preferably provided on a receiving bore cap  35  initially connected to the lateral receiving coupling  22 . It should be noted that the guidance system described herein is illustrative only and that other guidance systems as may be known in the art may also be employed. 
     Still with reference to FIG. 3 a , lateral borehole  44  is shown being drilled by bit  38  provided at the end of a drilling string. Bit  38  is steered by conventional directional steering tools known in the art such as directional steering tool  41 . In the directional steering tool  41  shown, the path of the drilling bit  38  is adjusted as conventional guidance sensors  40  detect and interpret the current borehole location relative to the centerline  37  of receiving bore  36 . Receiving bore  36  is in a known spatial relationship relative to the guidance beacons  34 . Preferably, a rotary steerable drilling assembly such as the “Autotrak” drilling assembly available from Baker Oil Tools or other suitable steering drill assembly may be modified to have an added guidance sensor  40  to detect the source location of guidance beacons  34 . 
     Referring now to FIG. 3 b , the lateral borehole  44  has preferably been drilled so that the centerline of the lateral receiver coupling  22  and the centerline of the lateral borehole  44  are generally co-extensive. An under-reamed section  46  of borehole  44  is created as shown proximate lateral receiver coupling  22  using conventional drilling techniques. Although not shown, a conventional running tool may be run through the lateral borehole  44  and used to remove the cover  35  from the lateral receiver coupling  22  so that a lateral liner may be inserted within the receiving bore  36  of the lateral receiver coupling  22  as described further below. 
     Hardenable Fluid Sealant Embodiment 
     Referring now to FIG. 3 c , lateral liner  50 , which may be wellbore casing or some other suitable tubular assembly, has been run into the lateral borehole  44  using conventional techniques and is inserted into the receiving bore  36  of lateral receiver coupling  22 . A stage tool or cementing port collar  52  may be provided within lateral liner  50  proximate the end of the lateral liner  50  inserted into the receiving bore  36  of lateral receiver coupling  22 . A hardenable liquid sealant or cement  48  may then be pumped through the lateral liner  50 , through cementing port collar or stage tool  52 , and into annulus  49  formed defined by the under-reamed section  46 . The stage tool or port collar  52  may then be closed, thus creating in one embodiment a mechanical seal between the lateral liner  50  and the lateral receiver coupling  22  and, accordingly, the main wellbore casing  32  to which the lateral receiver coupling  22  is connected. It should be noted that, in this embodiment, essentially no sealing mechanism or sealing substance is provided within the production bore of either the lateral liner  50  or the main wellbore casing  32  so that flow therethrough is not significantly impeded. It should further be noted that this embodiment may be used as a primary mechanical seal or it may be used in connection with the latching mechanism embodiments described below. 
     Referring to FIGS. 2-3,  5 , and  12 , the lateral receiver coupling  22  is shown having a receiving bore  36  extending generally 90 degrees to direction of the main wellbore casing  32  to form a “T” intersection. However, the receiving bore  36  of lateral receiver coupling  22  may also extend at any desired angle relative to the main wellbore casing  32 . Referring to FIG. 4, it will be readily apparent that receiver coupling  24  may also be an axial receiver coupling  24  provided axially at a distal end of the main wellbore casing  32  to form an “end-to-end” intersection. In this embodiment, guidance beacons  34  may preferably be spaced apart and on opposing sidewalls of axial lateral receiver coupling  24 . 
     Lateral Connector 
     Referring now to FIG. 5, lateral liner  50  is shown intersecting with and connected to lateral receiving coupling  22 . Lateral liner  50  may include lateral connector  62 , which may be attached to the distal end  66  of the lateral liner  50  to be connected to the lateral receiver coupling  22  of the main wellbore casing  32 . The lateral connector  62  generally comprises: seal bore receptacle  76 , equipment receptacle  74 , and latch mechanism  56 . Seal bore receptacle  76  is preferably threadedly attached to the distal end  66  of the lateral liner  50  and receptacle  76  preferably has a polished seal bore surface  80  suitable for mating with a sealing member (not shown). Equipment receptacle  74  is preferably threadedly attached to the opposite end of the seal bore receptacle  76 . 
     A cylindrical wall of equipment receptacle  74  preferably defines bore  78  therewithin. Referring now to FIG. 6, equipment receptacle  74  is shown in a cross-section taken along section  6 — 6  of FIG.  5 . As shown in FIG. 6, the cross-section of bore  78  of equipment receptacle  74  may preferably be square (shown in FIG.  6 ). It should be noted, however, that the cross-section of bore  78  of equipment receptacle  74  may also be cylindrical (not shown) or have some other suitable cross-section. In the preferred embodiment, the cross-section of bore  78  is rectangular. 
     In the event that the cross-section of bore  78  is rectangular, transitional cross-sectional areas may be required to suitably mate with the preferably cylindrical cross-sectional area of seal bore  80  of seal bore receptacle  76 . Accordingly, surface  82  may preferably be spherical or conical to provide the transition from the preferably square equipment receptacle bore  78  to the preferably cylindrical seal bore  80 . 
     Referring now to FIG. 7, seal bore receptacle  76  is shown in a cross-sectional view taken along section  7 — 7  of FIG.  5 . The preferred diameter of seal bore receptacle  76  defining seal bore surface  80  is shown relative to the internal diameter of the bore  88  of the lateral liner  50  and also relative to the outer diameter of the outside surface  86  of lateral liner  50 . Referring again to FIG. 5, latch mechanism  56  is shown threadedly attached to the end of the equipment receptacle  74 . 
     Latch mechanism  56  will be described in more detail below with reference to FIGS. 9,  10  and  11 . 
     Equipment Assembly 
     Referring now to FIG. 8, lateral connector  62  is shown having equipment assembly  89  disposed within equipment receptacle  74 . Equipment assembly  89  comprises seal assembly  92 , which has a proximal end adapted to sealingly engage seal bore surface  80  to create a hydraulic pressure retaining seal between the outside diameter of the seal assembly  92  and the inside diameter of the seal bore receptacle  76 . A portion of seal assembly  92  preferably has an enlarged outside diameter  93  defining shoulder  95 . Shoulder  95  is adapted to bear on landing  97  associated with equipment receptacle  74  to limit the movement of the seal assembly  92  beyond a given point in the seal bore  76 . 
     A face seal  94  is preferably located on the distal end of the seal assembly  92 . A sealing force may be applied to an adjoining equipment module  90  against seal assembly  92 , whereby the face seal  94  will create a pressure seal between the equipment module  90  and the seal assembly  92 . A plurality of equipment modules  90  may be similarly joined with face seals  94  provided between each set of adjoining module  90 . Each of the equipment modules  90 , the seal assembly  92 , and the latch module  99  include a flow through bore  100 . Equipment modules  90  may preferably include conventional monitoring or control modules, providing, for example: a) well flow control devices (having choked positions or full open or full closed positions); b) monitoring devices for sensing wellbore parameters such as water cut, gas/oil ratios, fluid composition, temperature, pressure, solids content, clay content, or tracer/marker identification; c) a fuel cell, battery, or power generation device; or d) a pumping device. 
     The last module  90  to be inserted into the equipment receptacle  74  proximate the distal end of the lateral liner  50  is preferably latch module  99 . Latch module  99  preferably includes a face seal  94  to seal it to the adjoining equipment module  90 , and also preferably includes a conventional latch mechanism  98  adapted to retain the latch module  99  within the equipment receptacle  74  by engaging a recessed profile  101  within the lateral liner  50 . 
     First Latching Mechanism Embodiment 
     Referring now to FIG. 9 a , a first embodiment of latching mechanism  56  is shown in detail. Main mandrel  241  of latch mechanism  56  is preferably threadedly attached to the equipment receptacle  76  (shown in FIG. 5) as previously described. A plurality of seals  244  may be mounted on an outer seal surface  247  of main mandrel  241 . A snap ring  249  is preferably installed in groove  251  to hold the seals in place about the main mandrel  241 . Stop nut  242  preferably has a threaded inner surface and is preferably screwed onto a threaded portion of mandrel  241  until it reaches stop shoulder  237 . Sleeve  252  is preferably provided about the main mandrel  241  proximate the distal end of main mandrel  241 . End cap  240 , is threadedly attached to the main mandrel to provide a tapered, conical, surface  255  between the main mandrel  241  and the sleeve  252 . 
     A plurality of locking dogs  248 , preferably having wings  235  extending therefrom (as shown in FIG. 9 b ), are provided within sleeve  252  and have a portion thereof which are adapted to selectively extend through slots  253  provided in sleeve  252  (as shown in FIG. 9 c ). Locking dogs  248  are adapted and positioned to partially extend through slots  253  as they slide along tapered surface  255  of end cap  240 . Locking dogs  248  are further adapted to include a latching portion adapted to protrude past the outside diameter of a sleeve  252 . Locking dogs  248  are retained within sleeve  252  by wings  235  (shown in FIG. 9 b  and  9   c ) which engage the inner surface of sleeve  252 . 
     Push ring  254  is provided between the end cap  240  and sleeve  252  to press uniformly on the ends of the locking dogs  248  as spring  246  inserted behind the push ring  254  biases push ring  254  away from stop nut  242 . The slots  253  allow the locking dogs  248  to slide axially along the tapered surface  255  of end cap  240 . As the latching mechanism  56  is inserted into the lateral receiver coupling  22 , the latching dogs slide backward against spring  246  or other biasing member and inward toward the smaller diameter of conical surface  255 . When the latching mechanism  56  reaches the full insertion depth into the lateral receiver coupling  22 , the latch dogs  248  mate with a latch profile within the lateral receiver coupling  22  and are pushed up the conical surface  255  by spring  246  such that they protrude into the latch profile and engage bearing shoulder  257 . 
     Accordingly, a spring-actuated latching mechanism  56  is provided to automatically engage the lateral liner  50  within the lateral receiver coupling as the lateral liner  50  is inserted into the lateral receiver coupling  22 . 
     To ensure alignment of the locking dogs  248  and the mating latch profile as the latching mechanism  56  is inserted into the lateral receiver coupling  22 , key  245  may be machined into the outer surface of the main mandrel  241  and adapted to engage a matching keyway  250  provided in the lateral receiver coupling  22  to index the rotational position of the lateral connector  62  relative to the receiver coupling  22 . Seals  244  may be elastomeric interference fit, or chevron shaped non-elastomeric interference fit, or non-elastomeric spring metal energized or expandable metal or shape memory alloy or lens ring crush seals or other suitable seal design and material. 
     Second Latching Mechanism Embodiment 
     With reference now to FIGS. 10 and 11, a second embodiment of latching mechanism  56  is shown intersecting lateral receiver coupling  22 . In this embodiment, at least one seal  244  is mounted onto the main mandrel  24  Ion a surface  263 . A plurality of seals  244  may be separated and held in position by a snap ring  249  positioned in a groove  267 . A stop shoulder  268  retains seals  244  on main mandrel  241 . In this embodiment, a plurality of keys  260  are preferably machined onto the outer surface of main mandrel  241 . Keys  260  preferably have a flat lower face  261  facing the distal end of the main mandrel  241  and also facing lateral receiver coupling  22 . Keys  260  preferably further include an angled upper face  259  facing the running length of the lateral liner  50 . A plurality of opposing keys  273  are preferably machined onto the inner surface of lateral receiver coupling  22 . 
     Referring now to FIG. 11, a set of keys  273  of lateral receiver coupling  22  and the keys  260  of main mandrel  241  are shown in a flat projection to illustrates the relationship of the various keys and keyways. The keys  273  are machined into the lateral receiver coupling  22  to create a set of keyways  269  therebetween. The keys  260  of main mandrel  241  are adapted to fit through the keyways  269  of the lateral receiver coupling  22  as main mandrel  241  is inserted within the lateral receiver coupling  22 . In particular, a set of latch keys  271  includes a plurality of narrow keys  260   a  and a wide key  260   b . The narrow keys  260   a  fit through a mating plurality of narrow keyways  269   a  and the wide key  260   b  must pass through a wide keyway  269   b . When the latch mandrel  241  is inserted into the coupling  22 , the set of latch keys  271  follows the path of arrow y and pass beyond the plurality of latch keys  273 . Thereafter, main mandrel  241  is rotated clockwise in the direction of arrow x so that angled faces  259  engage angled faces  275  interlocking the lateral connector  62  with the lateral receiver coupling  22 . Due to the singular wide key  260   b  there is only one orientation in which the two parts will engage. As the lateral connector is rotated clockwise the angled faces  259  and  275  bear against one another creating an axial movement of the connector  62  into the coupling  22 . Referring again to FIG. 10, a nose seal  258  is preferably machined into the end of the mandrel  266  with a gap  256  ensuring that the nose seal  258  has suitable flexibility to sealingly engage a seal face  270  as the angled faces  259  and  275  move the seal mandrel  266  into the coupling  22 . Stop shoulder  272  prevents the rotational over travel of the keys to rotationally index the connector  62  and coupling  22  and to prevent improper deformation of the nose seal  258 . 
     FIG. 12 shows a cross section of an alternative embodiment of the receiver coupling  22  and a lateral connector  362 . In this embodiment the lateral connector  362  need not be rotationally indexed with the coupling  22  since the connector  362  in this case only consists of a latch mechanism  56  connected directly to the lateral liner  277 . A seal bore  276  and an equipment receptacle  278  are in this case suspended below a packer  274  which is set in lateral liner  277  to anchor these devices in the lateral liner. An indexing member  280  engages a mating profile in the coupling  22  before the packer  274  is set. The indexing member may be a clutch mechanism as described relative to FIG. 9 or it may be a spring loaded key which finds a mating recess in coupling  22  or other such devices known to those skilled in the art. The full bore of liner  277  is available for operations in the lateral liner in this embodiment until the assembly comprising items  278 ,  280 ,  274 , and  276  is inserted. This inserted assembly may also be retrievable through lateral liner  277  or permanently installed. 
     In operation, a main vertical wellbore  18  may be drilled through which production fluids are desired to be pumped or otherwise recovered to the surface. Thereafter, a production string of main wellbore casing, including lateral receiver coupling is inserted within the main vertical wellbore. A lateral wellbore, which may be horizontal or have some other orientation, is drilled from a location outside of the main wellbore casing in a direction generally towards the lateral receiver coupling until the lateral wellbore interconnects with the main wellbore. Thereafter, lateral liner having a latching mechanism according to the present invention connected to the distal end thereof is inserted within the lateral wellbore until it reaches the lateral receiver coupling. The lateral liner is then inserted further within the lateral receiver coupling until the latching mechanism engages within the lateral receiver coupling. In a first embodiment, the latching mechanism is automatically engaged with the lateral receiver coupling as the locking dogs reach the matching profile within the lateral receiver coupling. In the second embodiment, the latching mechanism is engaged with the lateral receiver coupling by rotating the lateral liner and thereby rotating the locking mechanism until the tapered keys associated with the lateral liner engage with the matched tapered keys associated with the lateral receiver coupling. 
     After the lateral wellbore has been connected to the main, substantially vertical wellbore, the lateral wellbore may be referred to as the main wellbore. Consequently, this new main wellbore may include axial receiver couplings to interconnect successive lengths of lateral liners  50  and/or include lateral receiver couplings to receive locking mechanisms of other lateral wellbores. Accordingly, a wide variety of downbole manifold systems may be contemplated using the method and apparatus of the present invention. By incorporating measurement and flow control devices within the lateral wellbores, each of the lateral wellbores can be independently monitored and/or controlled to have complete control of the downhole manifold system. Accordingly, since there may be redundant pathways to the surface through multiple lateral wellbores, the production of all feeder laterals need not be halted to service the main wellbore. Only the wellbores between the bore to be used for servicing and the target wellbore to be serviced need be remotely closed. Flow of other wellbores may be diverted to the alternate main wellbore until servicing operations are complete. Servicing robots may contain “equipment cars” alternated with “push/pull cars”. The equipment cars carry items such as the seal assembly  92 , the modules  90 , or the latch modules  98  and the pushlpull devices may move the equipment between the cars and the lateral connector equipment receptacles  74 . The robot “train” may also include “cars” containing repair modules, inspection modules, testing modules, data downloading modules, or device activation modules. 
     Service work on the feeder wellbores can also be performed through the wellbore from which the feeder wellbores were drilled to allow more extended access or more complete workover/treatment capability without risking operations in the main wellbore. 
     While the foregoing is directed to the preferred embodiment of the present invention, other and further embodiments of the invention may be devised without departing from the basis scope thereof. For example, the mechanical connection between the lateral receiver coupling and the lateral connector may be achieved by threading the two mating parts and screwing them together downhole, or they may be joined by expanding or swaging the end of the lateral connector inside the receiver coupling, or by a collet on the connector snapped into a groove in the coupling with a sleeve shifted behind the collet to lock it in place, or other such connection methods as are known in the art. Further, the guidance beacons  34  on the lateral receiver coupling  22  may also be sensors receiving signals generated by a drilling tool. The location data collected by these sensors may then be used to guide the corresponding drilling assembly to the desired intersection point. The beacons or sensors may be permanently mounted on the main casing or they may be retrievably located in the main casing in known spatial relationship to the receiver coupling. Accordingly, the scope of the present invention is determined only by the claims that follow.