Patent Publication Number: US-10309190-B2

Title: System and method for accessing a well

Description:
BACKGROUND 
     This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present invention, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art. 
     As will be appreciated, oil and natural gas have a profound effect on modern economies and societies. Indeed, devices and systems that depend on oil and natural gas are ubiquitous. For instance, oil and natural gas are used for fuel in a wide variety of vehicles, such as cars, airplanes, boats, and the like. Further, oil and natural gas are frequently used to heat homes during winter, to generate electricity, and to manufacture an astonishing array of everyday products. 
     In order to meet the demand for such natural resources, companies often invest significant amounts of time and money in searching for and extracting oil, natural gas, and other subterranean resources from the earth. Particularly, once a desired resource is discovered below the surface of the earth, drilling and production systems are often employed to access and extract the resource. These systems may be located onshore or offshore depending on the location of a desired resource. Further, such systems generally include a wellhead assembly through which the resource is extracted. These wellhead assemblies may include a wide variety of components, such as various casings, hangers, valves, fluid conduits, and the like, that control drilling and/or extraction operations. Sometimes it is difficult, as well as expensive, to get direct downhole access during a subsea workover operation. 
    
    
     
       DRAWINGS 
       Various features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein: 
         FIG. 1  is an illustrative completion system; 
         FIG. 2  is a cross-sectional side view of an illustrative embodiment of a completion system arrangement; 
         FIG. 3  is a cross-sectional side view of an illustrative, embodiment of a completion system arrangement where the structure is circumferentially disposed about the spool; 
         FIG. 4  is a top view of the completion system arrangement shown in  FIG. 3 ; 
         FIG. 5  is a cross-sectional side view of an alternative embodiment of the completion system; 
         FIG. 6  is a cross-sectional side view of another alternative embodiment of the completion system; and 
         FIG. 7  is a cross-sectional side view of another alternative of the completion system. 
     
    
    
     DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS 
     One or more specific embodiments of the present invention will be described below. These described embodiments are only exemplary of the present invention. Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers&#39; specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. 
     When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Moreover, the use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience, but does not require any particular orientation of the components. 
     Various arrangements of production control valves may be coupled to a wellhead in an assembly generally known as a tree, such as a vertical tree or a horizontal tree. With a vertical tree, after the tubing hanger and production tubing are installed in the high pressure wellhead housing or a spool such as a tubing spool, a blowout prevent (BOP) may be removed and the vertical tree may be locked and sealed onto the wellhead. The vertical tree includes one or more production passages containing actuated valves that extend vertically to respective lateral production fluid outlets in the vertical tree. The production passages and production valves are thus in-line with the production tubing. 
     With a vertical tree, the tree may be removed while leaving the completion (e.g., the production tubing and hanger) in place. However, to pull the completion, the vertical tree must be removed and replaced with a BOP, which involves setting and testing plugs or relying on down-hole valves, which may be unreliable due to lack of use and/or testing. Moreover, removal and installation of the tree and BOP assembly generally requires robust lifting equipment, such as a rig, that may have high daily rental rates, for instance. The well is also in a vulnerable condition while the vertical tree and BOP are being exchanged and neither of these pressure-control devices is in position. 
     Alternatively, trees with the arrangement of production control valves offset from the production tubing, generally called horizontal trees or spool trees, may be utilized. A spool tree also locks and seals onto the wellhead housing. However, the tubing hanger, instead of being located in the wellhead, locks and seals in the tree passage. After the tree is installed, the tubing string and tubing hanger are run into the tree using a tubing hanger running tool. A production passage extends through the tubing hanger, and seals to prevent fluid leakage, thereby facilitating a flow of production fluid into a corresponding production passage in the tree. A locking mechanism above the production seals locks the tubing hanger in place in the tree. With the production valves offset from the production tubing, the production tubing hanger and production tubing may be removed from the tree without having to remove the spool tree from the wellhead housing. Unfortunately, if the tree needs to be removed, the entire completion must also be removed, which takes considerable time and also involves setting and testing plugs or relying on down-hole valves, which may be unreliable due to lack of use and/or testing. Additionally, because the locking mechanism on the tubing hanger is above and blocks access to the production port seals, the entire completion must be pulled to service the seals. 
     To manage expected maintenance costs, which are especially high for an offshore well, an operator may select equipment best suited for the expected type of maintenance. For example, a well operator may predict whether there will be a greater need in the future to pull the tree from the well for repair, or pull the completion, either for repair or for additional work in the well. Depending on the predicted maintenance events, an operator will decide whether the horizontal or vertical tree, each with its own advantages and disadvantages, is best suited for the expected conditions. For instance, with a vertical tree, it is more efficient to pull the tree and leave the completion in place. However, if the completion needs to be pulled, the tree must be pulled as well, increasing the time and expense of pulling the completion. Conversely, with a spool tree, it is more efficient to pull the completion, leaving the tree in place. However, if the tree needs to be pulled, the entire completion must be pulled as well, increasing the time and expense of pulling the tree. The life of the well could easily span 20 years and it is difficult to predict at the outset which capabilities are more desirable for maintenance over the life of the well. Thus, an incorrect prediction may significantly increase the cost of production over the life of the well. Further, jurisdiction regulations and other industry practices require the plugs on subsea equipment to include dual seal barriers between fluids in the well and open water environments, a so-called dual barrier requirement. With the production control equipment located at the surface, another system for accomplishing dual barrier protection is needed. 
       FIG. 1  is a block diagram that illustrates an exemplary well completion system  10 . The illustrated well completion system  10  can be configured to extract various minerals and natural resources, including hydrocarbons (e.g., oil and/or natural gas), or configured to inject substances into the earth. In some embodiments, the well completion system  10  is land-based (e.g., a surface system) or subsea (e.g., a subsea system). As illustrated, the system  10  is a subsea system that includes a wellhead  12  coupled to a mineral deposit  14  via a well  16 , wherein the well  16  includes a wellhead hub  18 , which can be a high pressure wellhead housing and a well bore  20 . The wellhead hub  18  generally includes a large diameter hub that is disposed at the termination of the well bore  20 . The wellhead hub  18  provides for the connection of the wellhead  12  to the well  16 . Although described as a subsea system, it should be appreciated that the well completion system  10  may also be used as surface system. 
     The wellhead  12  typically includes multiple components that control and regulate activities and conditions associated with the well  16 . For example, the wellhead  12  generally includes bodies, valves, and seals that route produced minerals from the mineral deposit  14 , provide for regulating pressure in the well  16 , and provide for the injection of chemicals into the well bore  20  (downhole). In the illustrated embodiment, the wellhead  12  includes a subsea tree  22 , a spool  24  (e.g., a tubing spool), and a tubing hanger  26 . The system  10  may include other devices that are coupled to the wellhead  12 , and devices that are used to assemble and control various components of the wellhead  12 . For example, in the illustrated embodiment, the system  10  includes a tubing hanger running tool (THRT)  28  suspended from a drill string  30 . In certain embodiments, the THRT  28  is lowered (e.g., run) from an offshore vessel to the well  16  and/or the wellhead  12 . A blowout preventer (BOP)  32  may also be included, and may include a variety of valves, fittings and controls to block oil, gas, or other fluid from exiting the well in the event of an unintentional release of pressure or an overpressure condition. 
     As illustrated, the spool  24  is coupled to the wellhead hub  18 . Typically, the spool  24  is one of many components in a modular subsea or surface completion system  10  that is run from an offshore vessel or surface system. The spool  24  includes a longitudinal passage  34  configured to support the tubing hanger  26 . In addition, the passage  34  may provide access to the well bore  20  for various completion and workover procedures. For example, components can be run down to the wellhead  12  and disposed in the spool passage  34  to seal-off the well bore  20 , to inject chemicals down-hole, to suspend tools down-hole, to retrieve tools down-hole, and the like. 
     As will be appreciated, the well bore  20  may contain elevated pressures. For example, the well bore  20  may include pressures that exceed 10,000 pounds per square inch (PSI), that exceed 15,000 PSI, and/or that even exceed 20,000 PSI. Accordingly, well completion systems  10  employ various mechanisms, such as mandrels, seals, plugs and valves, to control and regulate the well  16 . For example, the illustrated tubing hanger  26  is typically disposed within the wellhead  12  to secure tubing suspended in the well bore  20 , and to provide a path for hydraulic control fluid, chemical injections, and the like. The hanger  26  includes a longitudinal bore  36  that extends through the center of the hanger  26 , and that is in fluid communication with the well bore  20 . As illustrated in the embodiment of  FIG. 2 , the hanger  26  also includes a lateral flow passage  38  in fluid communication with the longitudinal passage  36 . The lateral flow passage  38  of the tubing hanger  26  is configured to transfer product (e.g., oil, natural gas, etc.) from the longitudinal tubing hanger passage  36  to a lateral flow passage  40  of the spool  24 . In the present embodiment, the lateral flow passage  40  of the spool  24  extends from the longitudinal spool passage  34  to a hub connection  42 . The hub connection  42  is configured to interface with a mating hub connection  44  of the subsea tree  22 , thereby establishing a flow path from the longitudinal passage  36  of the tubing hanger  26  through the lateral flow passages  38  and  40  and into the subsea tree  22 . While the interface between the hub connection  42  and the mating hub connection  44  is oriented along a plane substantially parallel to the longitudinal passage  34  of the spool  24 , it should be appreciated that alternative embodiments may employ an interface along a plane substantially perpendicular to the longitudinal passage  34 . 
       FIG. 2  is a cross-sectional side view of an embodiment of a spool  24  and subsea tree  22  that may be used in the completion system  10 . As previously discussed, the spool  24  is configured to be positioned between the wellhead hub  18  and the BOP  32 . Consequently, the spool  24  includes a first end  46  configured to interface with the wellhead hub  18 , and a second end  48  configured to interface with the BOP  32 . The longitudinal passage  34  extends in an axial direction  45  between the first end  46  and the second end  48 , thereby establishing a flow path through the spool  24 . In the present embodiment, a collet connector  50  serves to secure the first end  46  of the spool  24  to the wellhead hub  18 . In addition, a cap  52  (e.g., an internal tree cap) is disposed within the longitudinal passage  34  between the tubing hanger  26  and the second end  48  to block fluid flow into and out of the spool  24 . As illustrated, the cap  52  includes a fluid barrier  54 , such as a wireline plug, and a seal  56 , such as a rubber o-ring, for example. More than one fluid barrier  54  may also be used. As will be appreciated, the cap  52  may include a locking mechanism configured to secure the cap  52  to the longitudinal passage  34  of the spool  24 . Consequently, the cap  52  may be retrieved by releasing the locking mechanism, and then extracting the cap  52  from the passage  34 . In addition, the plug may be removable (e.g., via a wireline) to provide fluid communication with the longitudinal passage  34 . In addition, the fluid barrier  54  may be an adjustable barrier, such as an actuatable valve. The valve may be any suitable valve, such as by non-limiting example, a ball valve, a sliding sleeve valve, a shuttle valve, or a gate valve. The adjustable barrier(s) can thus open and close a longitudinal passage running through the cap  52  to allow mechanical and circulation access through the cap during workover operations, without having to pull plugs in the cap  52 . 
     More than one fluid barrier  54  may also be used in the cap  52  and the fluid barriers  54  may be different types, such as one plug and one valve. 
     As previously discussed, the tubing hanger  26  is configured to support a tubing string  57  that extends down the well bore  20  to the mineral deposit  14 . As will be appreciated, an annulus  58  of the spool  24  surrounds the tubing string  57 , and may be filled with completion fluid. A fluid barrier  60 , such as a plug or an adjustable barrier, is disposed within the longitudinal passage  36  of the tubing hanger  26  and serves as a barrier between the product extracted from the mineral deposit  14  and the completion fluid within the annulus  58 . The tubing hanger  26  may also include a profile for installing a fluid barrier  60  in the hanger longitudinal passage  36 . Thus, a fluid barrier  60  such as a plug or an actuatable valve may be interchangeable in the profile. More than one barrier  60  may also be used. Consequently, the barrier  60  may block the flow of fluid up through the top of the tubing hanger  26 . The barrier  60  may be an adjustable barrier such as an actuatable valve. The valve may be any suitable valve, such as by non-limiting example, a ball valve, a sliding sleeve valve, a shuttle valve, or a gate valve. The valve may be actuated electrically, hydraulically, mechanically, or by any other suitable means. More than one barrier  60  may also be used. The valve can thus open and close the longitudinal passage  36  of the tubing hanger  26  to allow direct downhole mechanical and circulation access during workover operations, without having to pull crown plugs in the tubing hanger  26 . 
     At least one of the barriers  54 ,  60  is an adjustable barrier. If a barrier  54  or  60  is not an adjustable barrier, it is a non-adjustable barrier, such as a removable plug. Any combination of barriers where at least one of the barriers is adjustable may be used. For example, all of the barriers  54 ,  60  may be adjustable barriers. 
     In addition, the tubing hanger  26  includes a seal  62  (e.g., rubber o-ring) disposed against the longitudinal passage  34  of the spool  24  and configured to block fluid flow around the tubing hanger  26 . The illustrated wellhead configuration also includes an isolation sleeve  64  disposed within the passage  34 , and extending from the first end  46  of the spool  24  to the wellhead hub  18 . As illustrated, the isolation sleeve  64  includes a first seal  66  (e.g., rubber o-ring) in contact with the passage of the wellhead hub  18 , and a second seal  68  (e.g., rubber o-ring) in contact with the passage  34  of the spool  24 . In this configuration, the isolation sleeve  64  may facilitate pressure testing of the seal between the wellhead hub  18  and the spool  24 . The isolation sleeve  64  may also serve as an additional barrier to block a flow of completion fluid from exiting the wellhead  12  through the interface between the spool  24  and the wellhead hub  18 . 
     Furthermore, the tubing hanger  26  includes a first seal  70  positioned adjacent to the passage  34  of the spool  24 , and located in a downward direction  71  from the lateral flow passage  38 . The tubing hanger  26  also includes a second seal  72  positioned adjacent to the passage  34 , and located in an upward direction  73  from the lateral flow passage  38 . In the present embodiment, the seals  70  and  72  are configured to block flow of completion fluid into the lateral flow passage  38 , and to block flow of product (e.g., oil and/or natural gas) into the annulus  58 . Consequently, a flow path will be established between the tubing string  57  and the lateral flow passage  40  of the spool  24 , thereby facilitating the flow of product to the subsea tree  22 . Specifically, product will flow from the tubing string  57  in the upward direction  73  into the longitudinal passage  36  of the tubing hanger  26 . Because the actuatable valve  60  blocks the flow of product from exiting the top of the tubing hanger  26 , the product will be directed through the lateral flow passage  38  of the tubing hanger  26  and into the lateral flow passage  40  of the spool  24 . The product will then flow into the subsea tree  22  via the interface between the hub connection  42  and the mating hub connection  44 . While the actuatable valve  60  serves to block the flow of product out of the top of the tubing hanger  26 , it should be appreciated that the plug  54  within the cap  52  serves as a backup seal to block product from exiting the spool  24 , thereby providing a dual barrier between the product and the environment. 
     In the present embodiment, the spool  24  includes one or more valves  74 , such as production valves, coupled to the lateral flow passage  40 . As shown, the spool includes both production valves  74  but it should also be appreciated that only one production valve  74  may be included. It should also be appreciated that the term “production” as used to describe valve  74  is for convenience and that the valve  74  may be used to regulate flow in either direction and for injection as well as production. The production valves  74  are configured to control the flow of product between the spool  24  and the tree  22 . For example, one or both of the production valves  74  may be closed prior to retrieving the tree  22 , thereby blocking the flow of product from entering the environment. Conversely, once the tree  22  has between run or lowered into position, the valves  74  may be opened to facilitate product flow to the subsea tree  22 . When two production valves  74  are used and both in respective closed positions, two barriers are provided between the product flow and the environment, even when the tree  22  is removed. While the present embodiment includes valves  74 , it should be appreciated that alternative embodiments may employ any suitable device (e.g., wireline plug) configured to substantially block production flow from the well  16  to the hub connection  42 . As illustrated, with the hub connection  42  coupled to the mating hub connection  44 , the lateral flow passage  40  of the spool  24  is in fluid communication with a product flow passage  75  of the subsea tree  22 . In the present embodiment, the hub connection  42  is coupled to the mating hub connection  44  with a clamp  77 , such as a manual clamp or a hydraulic connector. 
     In the present embodiment, the product flow passage  75  includes a first valve  76  and a second valve  78 . As illustrated in  FIG. 2 , the first valve  76  is positioned upstream of an annulus crossover valve  80 , and the second valve  78  is positioned downstream from the annulus crossover valve  80 . Valves  76  and  78  may be first and second production valves. As discussed in detail below, the valves  76 ,  78  and  80  may be controlled to vary fluid flow into and out of the annulus  58  and tubing string  57 . In addition, the product flow passage  75  includes a choke  82  positioned downstream from the valves  76  and  78 , and configured to regulate pressure and/or flow rate of product through the flow passage  75 . The flow passage  75  also includes a flowline isolation valve  84  configured to selectively block fluid flow between the tree  22  and the surface. As illustrated, the product flow passage  75  terminates at a flowline hub  86  configured to interface with a conduit or manifold that conveys the product from the wellhead  12  to a surface vessel or platform. 
     Because the tubing hanger  26  is substantially sealed to the passage  34  of the spool  24  via the seals  62 ,  70 , and  72 , flow of completion fluid through the annulus  58  is blocked. Consequently, the spool  24  includes an upper annulus flow passage  88  and a lower annulus flow passage  90  to regulate completion fluid pressure within an upper region  89  above the tubing hanger  26  and a lower region  91  below the tubing hanger  26 , respectively. Specifically, the upper annulus flow passage  88  extends from the upper region  89  to a lateral flow passage  92 , and the lower annulus flow passage  90  extends from the lateral flow passage  92  to the lower region  91 . In this configuration, completion fluid may be supplied and/or removed from each region  89  and  91  of the annulus  58 . In the present embodiment, the upper annulus flow passage  88  includes an upper annulus valve  94 , and the lower annulus flow passage  90  includes a lower annulus valve  96 . The valves  94  and  96  are configured to control fluid flow to the upper region  89  and lower region  91 , respectively. 
     As illustrated, the lateral annulus flow passage  92  extends through the hub connection  42  and interfaces with an annulus flow passage  97  of the subsea tree  22 , thereby establishing a completion fluid flow path between the spool  24  and the subsea tree  22 . In the present embodiment, the annulus flow passage  97  includes an annulus valve  98  positioned upstream of the annulus crossover valve  80 , and an annulus monitor valve  100  positioned downstream from the annulus crossover valve  80 . As will be appreciated, the annulus valves  98  and  100  may be controlled along with the valves  76  and  78  and the annulus crossover valve  80  to adjust fluid flow to and from the annulus  58  and the tubing string  57 . For example, if the annulus valve  98 , the annulus monitor valve  100 , the first valve  76 , and the second valve  78  are in the open position, and the annulus crossover valve  80  is in the closed position, then a fluid connection will be established between the flowline hub  86  and the tubing string  57 , and between an annulus junction  101  and the annulus  58 . 
     In the present embodiment, the tubing hanger  26  includes a valve  63 , or other closure element below the lateral flow passage  38 . The valve  63  is configured to selectively block product flow to the subsea tree  22  and may be operated hydraulically or otherwise. The valve  63  may also be included in a sub or other extension below the tubing hanger  26 . The valve  63  works together with the barrier  60  but also with the valve  102  (discussed below) to provide an environmental barrier to fluid flow, such as production fluid flow, when either the subsea tree  22  or the cap  52  are not installed. 
     In the present embodiment, the tubing string  57  includes a downhole valve  102 , such as for example a surface-controlled subsurface safety valve (SCSSV)  102  configured to selectively block product flow to the subsea tree  22 . For example, as an SCSSV, the valve  102  may be hydraulically operated and biased toward a closed position (i.e., failsafe closed) to ensure that the SCSSV closes if the system experiences a reduction in hydraulic pressure. With at least two of the downhole valve  102 , the valve  63 , and at least one or both of the valves  74  in respective closed positions, two barriers are provided between the fluid flow and the environment, even when the tree  22  is removed. In the present embodiment, the SCSSV  102  is hydraulically controlled via a conduit  104  extending from the hub connection  42  to the SCSSV  102 . As illustrated, the conduit  104  connects with a conduit  110  within the subsea tree  22  when the hub connection  42  is mounted to the mating hub connection  44 , thereby establishing a fluid connection between the conduit  104  within the spool  24  and the conduit  110  within the subsea tree  22 . The connection may be any type of sealing connection, such as a stab connection. The connection may also be configured to substantially block fluid flow into and out of the respective conduits  104  and  110  when disengaged. As illustrated, the conduit  110  is coupled to a valve  112  configured to selectively block hydraulic fluid flow to the downhole valve  102 . 
     The spool  24  also includes a vent/test conduit  114  configured to regulate fluid flow to certain regions of the tubing hanger  26 . As illustrated, the conduit  114  connects with a conduit  120  within the subsea tree  22  when the hub connection  42  is mounted to the mating hub connection  44 , thereby establishing a fluid connection between the conduit  114  within the spool  24  and the conduit  120  within the subsea tree  22 . The connection may be any type of sealing connection, such as a stab connection. The connection may also be configured to substantially block fluid flow into and out of the respective conduits  114  and  120  when disengaged. As illustrated, the conduit  120  is coupled to a valve  122  configured to selectively block fluid flow to the vent/test conduit  114 . 
     In the present embodiment, the spool  24  also includes a chemical injection conduit  124  configured to inject chemicals, such as methanol, polymers, surfactants, etc., into the well bore  20  to improve recovery. As illustrated, the conduit  124  connects with a conduit  130  within the subsea tree  22  when the hub connection  42  is mounted to the mating hub connection  44 , thereby establishing a fluid connection between the conduit  124  within the spool  24  and the conduit  130  within the subsea tree  22 . The connection may be any type of sealing connection, such as a stab connection. The connection may also be configured to substantially block fluid flow into and out of the respective conduits  124  and  130  when disengaged. As illustrated, the conduit  130  is coupled to a valve  132  configured to selectively block the flow of chemicals into the well bore  20 . 
     In the present embodiment, the spool  24  also includes another hydraulic conduit  134  configured to operate a sliding sleeve within the tubing string  57 . For example, the tubing string  57  may terminate in a first region of the mineral deposit  14  and the sliding sleeve may be aligned with a second region of the mineral deposit  14 . In this configuration, when the sliding sleeve is in a closed position, the tubing string  57  may extract product from the first region. Conversely, when the sliding sleeve is in an open position, the tubing string  57  may extract product from the second region. Consequently, product may be selectively extracted from various regions of the mineral deposit  14  with a single tubing string  57 . As illustrated, the conduit  134  connects with a conduit  140  within the subsea tree  22  when the hub connection  42  is mounted to the mating hub connection  44 , thereby establishing a fluid connection between the conduit  134  within the spool  24  and the conduit  140  within the subsea tree  22 . The connection may be any type of sealing connection, such as a stab connection. The connection may also be configured to substantially block fluid flow into and out of the respective conduits  134  and  140  when disengaged. As illustrated, the conduit  140  is coupled to a valve  142  configured to selectively block hydraulic fluid flow to the sliding sleeve. 
     While the present embodiment includes four conduits  104 ,  114 ,  124  and  134  extending from the subsea tree  22  to the spool  24 , it should be appreciated that alternative embodiments may include more or fewer conduits. For example, certain embodiments may include additional valves controlled by additional hydraulic conduits, additional sliding sleeves controlled by additional conduits and/or additional chemical injection conduits. 
     If valve maintenance is desired, the tree  22  may be pulled by a ship, thereby substantially reducing maintenance costs compared to spool tree configurations in which a rig is employed to retrieve the spool tree. 
     Similarly, the tubing hanger  26  may be retrieved without removing the subsea tree  22 . For example, to remove the tubing hanger  26 , the well bore  20  may be plugged to block the flow of product into the environment. Next, the cap  52  may be removed to provide access to the tubing hanger  26 . Finally, the tubing hanger  26  and attached tubing string  57  may be retrieved via a rig, for example. Because the subsea tree  22  does not block access to the longitudinal passage  34  of the spool  24 , the tree  22  may remain attached to the spool  24  during the tubing hanger retrieval process. Consequently, maintenance costs may be significantly reduced compared to vertical tree configurations in which the vertical tree is removed prior to accessing the tubing hanger  26 . 
     It should be appreciated that the embodiment shown in  FIG. 2  may be used a subsea or surface system. 
       FIG. 3  is a cross-sectional side view of another embodiment of the spool  24  and subsea tree  22  that may be used in the completion system  10  of  FIG. 1 . In this, the subsea tree  22  includes a structure that is circumferentially disposed about the spool  24 , as compared to the embodiments described above, in which the subsea tree structure is positioned at one circumferential location radially outward from the spool  24 . As discussed in detail below, the structure of the subsea tree  22  may be substantially equally balanced in the radial direction  47 , thereby facilitating the running and/or retrieval processes. In addition, because the valves may be positioned farther apart than the embodiments described above, a remote operated vehicle (ROV) may have enhanced access to valve actuators. While a cap  52  is employed in this embodiment with a plug  54 , it should be appreciated that the tubing hanger  26  includes a fluid barrier  60  above the lateral flow passage  38  creating a dual-barrier configuration. 
     In the present embodiment, the subsea tree  22  is separated into a production valve block  151  and an annulus valve block  152 . As illustrated, both valve blocks  151  and  152  are disposed radially outward from the spool  24 , with each valve block located at a different circumferential position. As mentioned above, production valve block is not meant to limit the valve block  151  only to production, as it may also be used for injection. As discussed in detail below, the production valve block  151  is supported by a frame that circumferentially extends about the spool  24 . In the present embodiment, the production valve block  151  includes the production flow passage  75  and the SCSSV hydraulic conduit  110 , while the annulus valve block  152  includes the annulus flow passage  97 , the vent/test conduit  120 , the chemical injection conduit  130 , and the sliding sleeve hydraulic conduit  140 . However, it should be appreciated that the conduits  110 ,  120 ,  130  and  140  may be disposed within a different valve block in alternative embodiments. For example, in certain embodiments, the production valve block  151  may contain each of the conduits  110 ,  120 ,  130  and  140 , while the annulus valve block  152  only includes the annulus flow passage  97 . Alternatively, the annulus valve block  152  may contain each of the conduits  110 ,  120 ,  130  and  140 , while the production valve block  151  only includes the production flow passage  75 . It should be appreciated that corresponding lines extending from the subsea tree  22  to the surface may be connected to the appropriate valve block to establish a fluid connection with the conduits  110 ,  120 ,  130  and  140 . 
     As illustrated, the production valve block  151  includes the mating hub connection  44  configured to interface with the hub connection  42 . In the present embodiment, the hub connection  42  interfaces with the mating hub connection  44  along a plane  149  substantially perpendicular to the longitudinal passage  34  of the spool  24 . However, it should be appreciated that the hub connection  42  may interface with the mating hub connection  44  along a plane substantially parallel to the longitudinal passage  34  in alternative embodiments. As illustrated, the interface between the hub connection  42  and the mating hub connection  44  establishes fluid connections between the lateral flow passage  40  and the production flow passage  75 , and between the SCSSV conduits  104  and  110 . 
     Similarly, the annulus valve block  152  includes an annulus connector  154  configured to interface with an annulus hub  156  of the spool  24 . In the present embodiment, the annulus hub  156  interfaces with the annulus connector  154  along a plane  149  substantially perpendicular to the longitudinal passage  34  of the spool  24 . However, it should be appreciated that the annulus hub  156  may interface with the annulus connector  154  along a plane substantially parallel to the longitudinal passage  34  in alternative embodiments. As illustrated, the interface between the annulus hub  156  and the annulus connector  154  establishes fluid connections between the annulus lateral flow passage  92  and the annulus flow passage  97  within the subsea tree  22 . In addition, connections are established between the vent/test conduits  114  and  120 , between the chemical injection conduits  124  and  130 , and between the sliding sleeve hydraulic conduits  134  and  140 . Consequently, each conduit within the spool  24  is fluidly coupled to a corresponding conduit with the subsea tree  22 . 
     In another embodiment, the subsea tree  22  includes an annulus crossover loop  158  extending between the annulus valve block  152  and the production valve block  151 . As illustrated, the annulus crossover loop  158  contains an annulus conduit  160  extending between the annulus flow passage  97  and the annulus crossover valve  80 , thereby establishing a fluid connection between the annulus  58  and the tubing string  57 . The subsea tree  22  also includes a fluid flow loop  162  extending between the production valve block  151  and a production choke assembly  164 . As illustrated, the production choke assembly  164  includes the choke  82  and the flowline isolation valve  84 . The flow loop  162  contains the flow passage  75 , thereby establishing a fluid connection between the valve  78  and the choke  82 . Furthermore, the flowline connection hub  86  is coupled to the choke assembly  164  to facilitate fluid flow between the subsea tree  22  and the surface. Because the components of the subsea tree  22  are circumferentially distributed about the spool  24 , the tree  22  may be substantially balanced, thereby facilitating running and retrieving operations. However, in this embodiment, a cap  52  includes a fluid barrier  54 , and it should be appreciated that the tubing hanger  26  also includes a fluid barrier  60  to create the dual-barrier configuration. 
       FIG. 4  is a top view of the spool  24  and subsea tree  22  shown in  FIG. 3 . As previously discussed, the subsea tree  22  includes a frame  166  circumferentially disposed about the spool  24  and configured to support the production valve block  151 . As illustrated, the frame  166  also supports the choke assembly  164  and an electronic control pod  168 . In contrast, the annulus valve block  152  is supported by the annulus cross over loop  158  and the annulus connector  154 . However, because the present annulus valve block  152  only includes a limited number of valves, the weight of the valve block  152  may not induce significant stress within the loop  158  or the connector  154 . Because the structure of the subsea tree  22  is circumferentially disposed about the spool  24 , the subsea tree  22  may be substantially balanced, thereby facilitating running and retrieving operations. 
     In addition, because the valves are located in various circumferential positions within the subsea tree  22 , an ROV may have enhanced access to valve actuators. For example, in the present embodiment, the production valve block  151  includes a production valve actuator  170  configured to control the production valve  78 , an annulus crossover valve actuator  172  configured to control the annulus crossover valve  80 , and an SCSSV valve actuator  174  configured to control the SCSSV valve  112 . In addition, the choke assembly  164  includes a flowline isolation valve actuator  176  configured to control the flowline isolation valve  84 . Furthermore, the annulus valve block  152  includes an annulus valve actuator  178  configured to control the annulus valve  98 , an annulus monitor valve actuator  179  configured to control the annulus monitor valve  100 , a vent/test valve actuator  180  configured to control the vent/test valve  122 , a chemical injection valve actuator  182  configured to control the chemical injection valve  132 , and a sliding sleeve valve actuator  184  configured to control the sliding sleeve valve  142 . By circumferentially distributing the actuators about the tree  22 , the ROV may readily access each actuator. In addition, the spool  24  includes valve actuators configured to control the valves within the spool  24 . Specifically, the spool  24  includes a production valve actuator  186  configured to control the production valve  74 , an upper annulus valve actuator  188  configured to control the upper annulus valve  94 , and a lower annulus valve actuator  190  configured to control the lower annulus valve  96 . 
     It should be appreciated that the embodiment shown in  FIGS. 3 and 4  may be used a subsea or surface system. 
     In  FIG. 5 , another embodiment is presented including fluid barriers  54  in the cap  52  and fluid barriers  60  in the tubing hanger  26 , similar to the embodiment shown in  FIG. 2 . It should be appreciated that the following discussion regarding fluid barriers may also be used in an embodiment similar to the embodiment shown in  FIGS. 3 and 4 . As with previous embodiments, the tubing hanger  26  may also include a profile for installing a fluid barrier  60  in the hanger longitudinal passage  36 . Thus, a fluid barrier  60  such as a plug or an actuatable valve may be interchangeable in the profile. In the embodiment shown in  FIG. 5 , more than one barrier  54  is shown in the cap  52  and more than one barrier  60  is shown in the tubing hanger  26 . Although the barriers  60  are both shown above the lateral flow passage  38  in the tubing hanger  26 , it should be appreciated that one or both of the barriers may also be located below the lateral flow passage  38 . As mentioned in the discussion above with respect to  FIG. 2 , more than one of the barriers  54 ,  60  may be an adjustable fluid barrier, such as an actuatable valve. Additionally, at least one of the barriers  54 ,  60  is an adjustable barrier. If not an adjustable barrier, the remaining barriers  54 ,  60  are non-adjustable barriers, such as removable plugs. Any combination of barriers where at least one of the barriers is adjustable may be used. For example, all of the barriers  54 ,  60  may be adjustable barriers. Additionally, if the tubing hanger  26  includes two barriers  60 , then the cap  52  is not necessary and need not be used. 
     The adjustable barrier may include a valve (or valves) that serve as the fluid barrier that can open and close the passage in the cap  52  and or the longitudinal passage  36  in the tubing hanger  26  to allow direct downhole access during a subsea workover operation. In at least some configurations, this can be done without having to pull plugs when the tubing hanger passage is open, thus allowing passage to the production tubing. 
     An example of the utility of using an adjustable barrier is that an alternate downhole fluid path for well circulation can be achieved by opening the valve(s)  54  in the cap longitudinal passage. With the valve(s) open, fluid may be pumped down through the cap  52  to above the tubing hanger  26  and into an opened annulus crossover circulation loop in the tree. The annulus crossover circulation loop connects to the production master valve passage run extending through the tree and hanger and then connecting to the tubing hanger vertical passage just below a tubing hanger barrier and therefore down into the production tubing. Alternatively or additionally, fluid may flow through the barriers  54  as communicated with the production tubing annulus  58  through the upper annulus flow passage  88  and a lower annulus flow passage  90  in the spool  24 . 
     In this or other embodiments, having a valve that can open and close the longitudinal passage in the tubing hanger passage will allow direct down hole mechanical and circulation access during a subsea workover operation, without having to pull plugs. In this configuration, the master valve located in the tubing head spool could be now located in the upper tree section. 
     It should be appreciated that the embodiment shown in  FIG. 5  may be used a subsea or surface system. 
     In  FIG. 6 , an alternate or additional embodiment incorporating an annulus access valve(s)  55  located in an annulus access passage in the cap  52  separate from and adjacent to the longitudinal passage will also allow well circulation. This is achieved by pumping fluid through the choke and kill lines located below closed rams and through the riser down to the cap. The valve(s)  55  in the cap  52  is then opened allowing the fluid (or gas) to circulate below the cap  52  as discussed above. 
     An alternate or additional arrangement further incorporates an annulus access valve(s)  61  in annulus access passage not located in the tubing hanger longitudinal passage  36  but adjacent to it will also allow annulus access from above the tubing hanger  26  to below the tubing hanger  26 . When used with or without the cap barriers  54  or annulus access valve(s)  55 , fluid may circulate between above the cap  52  and the production tubing annulus  58  going through the tubing hanger  26  itself. This would eliminate the need for an annulus route typically located in the tree or spool body which by-passes the tubing hanger  26 . 
     It should be appreciated that the embodiment shown in  FIG. 6  may be used a subsea or surface system. 
     In  FIG. 7 , another embodiment is presented including fluid barriers  60  in the tubing hanger  26 , similar to the embodiment shown in  FIG. 5 . It should be appreciated that the following discussion regarding fluid barriers may also be used in an embodiment similar to the embodiment shown in  FIGS. 5 and 6 . As with previous embodiments, the tubing hanger  26  may also include a profile for installing a fluid barrier  60  in the hanger longitudinal passage  36 . Thus, a fluid barrier  60  such as a plug or an actuatable valve may be interchangeable in the profile. In the embodiment shown in  FIG. 7 , the tubing hanger  24  is landed in the spool  24  and a subsea vertical tree  22  is connected with the spool  24 . The vertical subsea tree  22  is in fluid communication with the tubing hanger longitudinal passage  36  to transfer the fluid between the spool  24  to the vertical subsea tree  22 . The spool  24  may either be a tubing head spool or a high pressure wellhead housing. 
     More than one barrier  60  is shown in the longitudinal passage  36  of the tubing hanger  26 . As mentioned in the discussion above with respect to  FIG. 5 , more than one of the barriers  60  may be an adjustable fluid barrier, such as an actuatable valve. Additionally, at least one of the barriers  60  is an adjustable barrier. If not an adjustable barrier, the remaining barriers  60  are non-adjustable barriers, such as removable plugs. Any combination of barriers where at least one of the barriers is adjustable may be used. For example, all of the barriers  60  may be adjustable barriers. 
     The adjustable barrier may include a valve (or valves) that serve as the fluid barrier that can open and close the passage in the longitudinal passage  36  in the tubing hanger  26  to allow direct downhole access during a subsea workover operation. In at least some configurations, this can be done without having to pull plugs when the tubing hanger passage is open, thus allowing passage to the production tubing. 
     In the embodiment shown in  FIG. 7 , the tubing hanger  26  includes a fluid barrier  63 , such as an actuatable valve or other closure element below the tubing hanger  26 . The valve  63  is configured to selectively block product flow to the subsea tree  22  and may be operated hydraulically or otherwise. The valve  63  may also be included in a sub or other extension below the tubing hanger  26 . The valve  63  works together with the barrier(s)  60  but also with the valve  102  (not shown) to provide an environmental barrier to production fluid flow when the subsea tree  22  is not installed. 
     Also shown in  FIG. 7  are optional annulus access valve(s)  61  in annulus access passage  65  not located in the tubing hanger longitudinal passage  36  but adjacent to it will also allow annulus access from above the tubing hanger  26  to below the tubing hanger  26 . Annulus access valve(s)  61  would eliminate the need for an annulus route typically located in the tree or spool body which by-passes the tubing hanger  26 . Although not shown, the spool  24  may also include an upper annulus flow passage and a lower annulus flow passage as discussed above to regulate pressure within an upper region  89  above the tubing hanger  26  and a lower region  91  below the tubing hanger  26 , respectively. 
     An example of the utility of using an adjustable barrier is that an alternate downhole fluid path for well circulation can be achieved by opening the adjustable barriers  60 ,  61  in the tubing hanger  26 . With the valve(s) open, fluid may flow through the hanger longitudinal passage  36  and the annulus access passage  65  to circulate fluid in the well. In this or other embodiments, having a valve that can open and close the production passage in the tubing hanger passage will allow direct down hole mechanical and circulation access during a subsea workover operation, without having to pull plugs. 
     It should be appreciated that the embodiment shown in  FIG. 7  may be used a subsea or surface system. 
     In all of the embodiments described above and shown in  FIGS. 1-7 , accessing either or both of the tubing hanger longitudinal passage  36  and the cap longitudinal passage could save the operator time and money as opposed to the required steps necessary to pull plugs to gain access. In addition, the embodiments eliminate any potential issues previously seen involving the removal of stuck plugs or the re-establishment of new plugs in a damaged or debris filled passage. Additionally, all of the embodiments shown in  FIGS. 1-7  may be used a subsea or surface system. 
     While the invention may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.