Abstract:
A subsea well production system for a well including a subsea wellhead. The system includes a multi-section production tree that includes a landing section engageable with the subsea wellhead and including a landing section bore. The tree also includes a valve section separate from and engageable with the landing section, the valve section including a lateral production port extending through a valve section wall and in communication with a valve section bore. A production tubing supported by a tubing hanger is installed and supported in the landing section bore such that the tubing hanger extends into the valve section bore. The tubing hanger and production tubing are retrievable through the section bores without disengaging the valve section from the landing section. The valve section is also disengageable from the landing section with the tubing hanger remaining in the landing section.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a 35 U.S.C. §371 national stage application of PCT/US2009/040665 filed Apr. 15, 2009, which claims the benefit of U.S. Provisional Patent Application No. 61/045,133 filed Apr. 15, 2008, both of which are incorporated herein by reference in their entireties for all purposes. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not Applicable. 
     BACKGROUND 
     A well capable of producing oil or gas that is deep enough will typically have a well structure to provide support for the borehole and isolation capabilities for different formations. Typically, the well structure includes an outer structure, such as a conductor housing at the surface, that is secured to conductor pipe that extends a short depth into the well. A wellhead housing is landed in the conductor housing with an outer or first string of casing extending from the wellhead and through the conductor to a deeper depth into the well. Depending on the particular conditions of the geological strata above the target zone (typically, either an oil or gas producing zone or a fluid injection zone), one or more additional casing strings (e.g., production casing, casing, tubing, production tubing, etc.) will extend through the outer string of casing to increasing depths until the well is cased to its final depth. Each string of casing is supported at the upper end by a casing hanger that lands in and is supported by the wellhead housing, each set above the previous one. Between each casing hanger and the wellhead housing, a casing hanger seal assembly is set to isolate each annular space between strings of casing. The last, and innermost, string of casing extends into the well to the final depth and is referred to as the production casing. The strings of casing between the outer casing and the production casing are typically referred to as intermediate casing strings. 
     When drilling and running strings of casing in the well, it is critical that the operator maintain pressure control of the well. This is accomplished by establishing a column of fluid with predetermined fluid density inside the well that is circulated down into the well through the inside of the drill string and back up the annulus around the drill string to the surface, for example. This column of density-controlled fluid balances the downhole pressure in the well. A blowout preventer system (BOP) is also used to as a safety system to ensure that the operator maintains pressure control of the well. The BOP is located above the wellhead housing and is capable of shutting in the pressure of the well, such as in an emergency pressure control situation. 
     After drilling and installation of the casing strings, the well is completed for production by installing a string of production tubing that extends to the producing zone within the production casing, for example. Perforations are made in the production casing to allow fluids to flow from the formation into the productions casing at the producing zone. At some point above the producing zone, a packer seals the space between the production casing and the production tubing to ensure that the well fluids flow through the production tubing to the surface. The tubing is supported by a tubing hanger assembly that lands and locks above the production casing hanger. 
     Various arrangements of production control valves are arranged at the wellhead in an assembly generally known as a tree, which is generally either a vertical tree or a horizontal tree. With a vertical tree, after the production hanger and production tubing are installed in the wellhead housing, the BOP is removed and the vertical tree is locked and sealed onto the wellhead. The vertical tree has one or more production bores containing actuated valves that extend vertically to the respective lateral production fluid outlets in the vertical tree. The production bores and production valves are thus in-line with the production tubing. 
     With a vertical tree, the tree may be removed while leaving the completion (the production tubing and hanger) in place. However, if it is necessary to pull the completion, the vertical tree must be removed and replaced by a BOP, which involves setting and testing plugs or relying on downhole valves, which may be unreliable by not having been used or tested for a long time. Moreover, removal and installation of the tree and BOP assembly generally requires robust lifting equipment, such as a rig, that 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, which is a lengthy operation that usually involves plugging and/or killing the well. 
     Instead of vertical trees, trees with the arrangement of production control valves offset from the production tubing, generally called horizontal trees, can be used. One type of horizontal tree is a Spool Tree™ which is shown and described in U.S. Pat. No. 5,544,707, hereby incorporated herein by reference for all purposes. A horizontal tree also locks and seals onto the wellhead housing; but the tubing hanger, instead of being located in the wellhead, locks and seals in the tree bore. After the tree is installed, the tubing string and tubing hanger are run into the tree using a tubing hanger running tool. The production port extends through the tubing hanger and seals prevent fluid leakage and production fluid flows into the corresponding production port 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 horizontal tree from the wellhead housing. A problem with horizontal trees, however, is that 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 downhole valves, which may be unreliable by not having been used or tested for a long time. 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, should the seals requiring servicing. 
     To manage expected maintenance costs, which are especially high for an offshore well, an operator typically selects equipment best suited for the type of maintenance he or she expects will be required. For example, a well operator must 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 must decide whether the horizontal or vertical tree, each with its own advantages and disadvantages, is best suited for his or her purpose. 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. Just the opposite is true for a horizontal tree, where 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 could greatly increase the cost of production over the life of the well. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of the embodiments, reference will now be made to the following accompanying drawings: 
         FIG. 1  is a cross section of a subsea wellhead for installation of the multi-section tree; 
         FIG. 2  is a cross section of the subsea wellhead and the landing section of the multi-section tree installed; 
         FIG. 3  is a cross-section of the multi-section tree with both tree sections installed without the completion; 
         FIG. 4  is a cross-section of a multi-section tree with the landing section and the valve section and the completion installed on the subsea wellhead; 
         FIG. 5  is a cross-section of the multi-section tree with the tree cap and production seal assembly removed; 
         FIG. 6  is a cross section of the multi-section tree of  FIG. 5  with a protector installed on the completion; 
         FIG. 7  is a cross section of the multi-section tree with the valve section removed and the completion left installed with the protector; and 
         FIG. 8  is a cross section of the multi-section tree with the valve section removed and the completion left installed with a low profile protector. 
     
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
     In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. Any use of any form of the terms “connect”, form of the terms “connect”, “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings. 
       FIG. 1  illustrates a subsea wellhead  12  for installation of a multi-section tree  10  as shown in  FIGS. 2-4 , that includes a landing section  14  and a valve section  16 . When the well is ready for completion, the landing section  14  and valve section  16  are lowered and installed onto the wellhead  12  using hydraulically operated collet connectors  18 , with seals being formed by appropriate gaskets. Although not shown, appropriate valves for controlling fluid production from the multi-section tree  10  are located in or attached to the valve section  16 . Also, though shown in  FIGS. 2 and 3  as being installed separately, the landing section  14  and the valve section  16  may be connected on the surface and installed on the wellhead  12  at the same time. 
     As shown in  FIG. 5 , the multi-section tree  10  is used for installing a completion that includes a tubing hanger  20  attached to and supporting the weight of a string of production tubing  22  extending below the tubing hanger  20  and into the well. The tubing hanger  20  includes an internal bore  24  aligned on one end with the bore of the production tubing  22 . The other end of the internal bore  24  exits the tubing hanger  20  in alignment with a master production port  26  in the valve section  16  for producing well fluids to the surface. 
     When the well is ready for completion, appropriate plugs are set downhole from the wellhead  12  to maintain fluid pressure. The blowout preventer (BOP) and riser are then removed from the wellhead  12  and the multi-section tree  10  is installed either in separate sections or both sections at the same time. The BOP and riser are then reattached to the multi-section tree  10  and the plugs removed from the well using an appropriate tool run in through the riser. When installed, the multi-section tree  10  may be pressure tested to confirm the pressure integrity of the multi-section tree  10 . A tubing hanger running tool (THRT) is then used to lower the completion, including the tubing hanger  20  and the production tubing  22 , through the riser and land the tubing hanger  20  in the multi-section tree  10 . 
     As shown in  FIG. 4 , there are fluid connections between the tubing hanger  20  and the multi-section tree  10 . To align the tubing hanger  20  with the multi-section tree  10 , and thus align the connections, a passive vertical orientation sleeve  28  is installed to the bottom of the tubing hanger  20 . The orientation sleeve  28  also includes a ramp surface  30  that engages a key  32  on the inner surface of the landing section  14  to orient the tubing hanger  20 . As the tubing hanger  20  lands in the multi-section tree  10 , the engagement between the ramp surface  30  and the key  34  causes the tubing hanger  20  to rotate into position via a camming relationship therebetween. The tubing hanger  20  is thus aligned to its set position with the production tubing  22  extending through the orientation sleeve  28 . 
     As shown in  FIGS. 2-4 , the multi-section tree  10  includes a fluid line connection adapter  34  between the landing section  14  and the valve section  16 . Also, extending through the orientation sleeve  28  is a fluid line  36  that extends downhole to a surface-controlled subsurface safety valve (SCSSV) (not shown), which controls the flow of fluid through the production tubing  22  from the producing zone. The fluid line  36  extends from the SCSSV and into the tubing hanger  20  and routes into a passive coupler  40  that forms a fluid tight connection with an inlet fluid connector  38  in the adapter  34  when the tubing hanger  20  lands in the multi-section tree  10 . Fluid may then route through the adapter  34  to an outlet connector  42  that is connected to a tree fluid line connector  44 . From the tree fluid line connector  44 , the fluid line routes through the valve section  16 . Extending through the valve section  16 , the tree fluid line is accessible from outside the multi-section tree  10  by a hydraulic control line  46  that extends to the surface. When connected, the hydraulic control line  46  enables surface control of the SCSSV for well operations as discussed further below. The adapter  38  may alternatively be separated into two units that make the inlet connection in the landing section  14  and the outlet connection between the landing section  14  and the valve section  16  with a fluid line being routed in between through the landing section  14 . 
     With the completion set in position, a lockdown actuator (not shown) actuates a locking mechanism  48  that engages a corresponding lock groove on the tubing hanger  20 . The locking mechanism thus locks the tubing hanger  20  and the production tubing  22  in place within the multi-section tree  10 . The lockdown actuator is located externally, internally, or a combination thereof in the multi-section tree  10  and may include an unlock override to unlock the locking mechanism  48 . In the set position, the tubing hanger  20  seals against the inside wall of the multi-section tree  10  at various positions, including above and below the production port  26 . 
     The seals above and below the production port  26  seal the interface between the internal bore  24  of the tubing hanger  20  and the production port  26 . However, not all of the seals are necessary for every application. They may be located in different locations, not included at all, or have additional secondary barriers. Alternatively, the port  26  may be sealed to the port  24  directly, for example with a face seal, seal sub, or coupler. Additionally, these seals may be made from metal and/or non-metal composition depending on the performance characteristics needed. 
     With the completion set and locked, the well is ready for production. To create a barrier to fluid from escaping the internal bore  24  through the top of the tubing hanger  20 , plugs  50  are run into the internal bore  24  and set above the side outlet. Alternatively, a valve located in the internal bore  24  above the side outlet may be operated to the closed position. In the exemplary embodiment, the internal profile of the tubing hanger  20  may include features that allow setting of the plug  50  either above or below the master production port  26 . A tree cap  84  may now be installed through the drilling riser or by means of a remotely operated vehicle (ROV). The BOP and riser may then be removed from the multi-section tree  10  and retrieved. Using the hydraulic control line  46 , hydraulic fluid may be used to open the downhole SCSSV and allow fluid production to flow from the production tubing  22 , through the tubing hanger  20 , and into the production port  26  for flow to the surface or any other desired location. Additionally, as shown in  FIGS. 3 and 4 , the multi-section tree  10  allows for fluid communication from the production tubing  22  annulus below the tubing hanger  20  to the bore of the multi-section tree  10  above the tubing hanger  20 . Communication with the production tubing  22  annulus allows for pressure control downhole should pressure in the annulus need to be relieved during production. The fluid communication is controlled using an externally mounted annulus valve  54  that is in fluid communication on one side with a valve section bleed port  52 . On the other end, the annulus valve  54  communicates with the annulus below the tubing hanger  20  by connection with a landing section bleed port  60 . Also, the multi-section tree  10  includes a back up annulus valve  58  that further connects with an extra, manual connects with an extra, manual annulus block off (not shown). The annulus valve  54  and back up annulus valve  58  may be any appropriate standard API valve. The annulus valve  54  and the back up annulus valve  58  do not need to be externally connected. Instead, as shown in  FIG. 4 , the annulus valve  54  and back up annulus valve  58  may be connected through an additional port  62  within the valve section  16  and port  64  within the landing section  14 . 
     Also shown in  FIGS. 3 and 4 , the multi-section tree  10  includes an isolation sleeve  66  that includes seals on its outer surface to form an environment barrier between the inside wall of the landing section  14  and the wellhead  12 . Although the isolation sleeve  66  is located in the bore, the annulus surrounding the production tubing  22  is not blocked and fluid is allowed to pass around the orientation tool  28 . Another isolation sleeve (not shown) may also be included between the valve section  16  and landing section  14 . 
     At some point in the life of the well, the well may need to be accessed for additional drilling, maintenance, or other reasons. As shown in  FIG. 3 , to access the well the completion may be pulled from the multi-section tree  10  so that drilling equipment and/or tools may be run into the well. To pull the completion, both the BOP and the riser are installed to the top of the multi-section tree  10 . A THRT is run through to the multi-section tree  10  through the riser and engaged with the tubing hanger  20 . The lockdown actuator then releases the locking mechanism  48  so that the THRT may retrieve the completion from the multi-section tree  10 . Because the passive coupler  40  is a vertical connection, the removal of the tubing hanger  20  disconnects the hydraulic fluid line  36  from the inlet fluid connector  38  of the adapter  34  as the completion is pulled from the multi-section tree  10 . With the completion pulled and the well now accessible, work in the well may be performed without also having to pull the multi-section tree  10  from the well. Leaving the multi-section tree  10  in place thus saves considerable time and money for the well operator who does not have to go through the extra steps of removing and then reinstalling the multi-section tree  10  on the wellhead  12 . Moreover, the multi-section tree  10 , when bifurcated, is lighter than conventional trees, allowing installation with less robust equipment that is generally less expensive. 
     The same can also be said that at some point in the life of the well, the valves of the multi-section tree  10  may need to be serviced or replaced. As shown in  FIGS. 5-8 , the valve section  16  may be pulled by itself, leaving the landing section  14  and the completion in place on the wellhead  12 . Before the valve section  16  is removed, a second environmental barrier  15  is established in addition to closing the SCSSV in the production bore below the side outlet. The second barrier may be established by ROV interface and/or by access through a completion riser. A preferred method is to close an additional valve located in the production bore below the side outlet using ROV interface to inject hydraulic fluid to the ITC which in turn injects fluid through the tubing hanger and consequently to operate the valve located in the production bore, Alternatively, the ITC may be operated open water by an ROV or by a tool run through a riser and BOP to re-position the plug  50  from above the outlet to below the outlet ( FIGS. 4 and 5 ). If a riser and BOP are attached, plug  50  may be removed and another plug then installed below the side outlet. Unlike when removing the completion, however, the locking mechanism  48  is left in the engaged position. As discussed more fully below, the seals in the tubing hanger  20  on either side of the production port  26  may be included on a removable seal assembly  80  that surrounds the tubing hanger  20 . Although not necessary, typically the seal assembly is removed as shown in  FIG. 5  and a protector  86  that may be temporary is threaded onto the exposed tubing hanger  20  as shown in  FIG. 6 . 
     The hydraulically controlled upper collet connector  18  is then disengaged, and the valve section  16  may then be removed and lifted by attaching an ROV assisted Mechanical Tree Handling Tool coupled to a soft line extending down from a floating vessel, or by the riser and BOP if attached. The design of the coupler  40  allows the vertical separation of the valve section  16  from the landing section  14 . The landing section  14  and the completion are left in place on the wellhead  12 . With the valve section  16  now retrieved, the service and/or replacement work may be performed without having to pull the landing section  14  and the completion from the well. When the well is not being accessed, the protector  86  may remain in place on the tubing hanger  20 . Alternatively, a lower profile protector  88  shown in  FIG. 8  may be placed over the tubing hanger  20  and locked into the landing section  14  using any suitable locking engagement. Leaving the landing section  14  and completion in place thus saves considerable time and money for the well operator who does not have to go through the extra steps of removing and then reinstalling the completion just to be able to service the valve section  16 . 
     As previously mentioned and as shown in  FIGS. 4-8 , the seals in the tubing hanger  20  on either side of the production port  26  may be included on a replaceable seal assembly  80  that surrounds the tubing hanger  20 . The seal assembly  80  may also be pulled from the tubing hanger  20  either by itself or in conjunction with pulling the valve section  16  or pulling the tubing hanger  20 . The seal assembly  80  includes the seals installed on a retrievable body  82  that slides down over the tubing hanger  20  and is held in place using a tree cap  84  as shown or it&#39;s own retention device. The tree cap  84  can be installed above the tubing hanger  20  as a second barrier and/or a second lockdown for the tubing hanger  20 . The tree cap  84  can lock to the tree profile and/or the tubing hanger profile and seal to the tree profile, the tubing hanger profile, or both. The tree cap  84  could be ROV installable and retrievable or deployed and removed inside a riser or a combination thereof. The tree cap  84  could also be used to install or retrieve the hanger seal assembly  80  or to shift the seal assembly  80  to another position, e.g., rotate the seal assembly  80  to close off fluid flow into the production port  26 . It should also be appreciated that the tree cap  84  may be replaced with any suitable engagement mechanism, such as a threaded connection or lockable dogs engaging a profile on the tubing hanger  20 . 
     Because the locking mechanism  48  is located below the production port  26 , the top of the tubing hanger  20  is accessible from the bore of the multi-section tree  10  above the tubing hanger  20 . Thus, should the seal assembly  80  need repair or replacement, an appropriate tool or a subsea remote operated vehicle (ROV) may be used to replace the seal assembly  80  without having to pull the entire completion. The ROV may be used to engage the top of the multi-section tree  10  and with the SCSSV set in the closed position, the ROV may remove the seal assembly  80  for repair or replacement. 
     When the operation is compete, the ROV disengages the multi-section tree  10  and the SCSSV is set to the open position to resume production. With the seal assembly  80  being retrievable from the top of the tubing hanger  20 , the service and/or replacement work may be performed without having to pull the completion from the well. Leaving the completion in place thus saves considerable time and money for the well operator who does not have to go through the extra steps of removing and then reinstalling the completion just to be able to service the production production port  26  seals. The seal assembly  80  may be retrieved and re-installed with the tree valve section  16  or with the tubing hanger  20  as they are each individually retrieved or installed as discussed above. The seal assembly  80  may also be retrieved or installed using ROV interface or using a separate tool run through the riser. The seal assembly  80  may also be retrieved or installed by means or assistance of the tree cap  84  as shown, in conjunction with the additional methods just described. 
     While specific embodiments have been shown and described, modifications can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments as described are exemplary only and are not limiting. Many variations and modifications are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.