CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 60/808,198, filed May 24, 2004.

FIELD OF THE INVENTION

This invention relates generally to a method and system for installing equipment for production and/or injection operations. More particularly, this invention relates to a system and method for installing subsea completion equipment in conjunction with tubing hanger installation using pre-installed tubing hanger plugs, and/or activating downhole devices with tubing hanger plugs pre-installed.

BACKGROUND

This section is intended to introduce the reader to various aspects of art, which may be associated with exemplary embodiments of the present invention, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with information to facilitate understanding of particular techniques of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.

The production of hydrocarbons, such as oil and gas, has been performed for numerous years. However, when producing hydrocarbons from subsurface or subsurface formations, it becomes more challenging because of the location of the subsurface formations. For example, some subsurface formations are located in ultra-deep water and in remote locations. In these locations, the ability to perform installation, production and injection operations may be difficult and expensive. In particular, the hydrostatic pressure within a riser in deep water environments may complicate the installation of a sealing device, such as a plug, into a subsea tree because of the pressure differential and debris around the sealing device. This may result in additional rig time to install the sealing device before production or injection operations for the subsurface formation may begin.

Typically, procedures and processes require multiple days of rig time to install the sealing device. For example, a typical procedure to install a sealing device, such as a plug, starts with running and coupling a riser and blowout preventer (BOP) to a subsea tree. After the subsea tree is installed the wellbore is normally conditioned and then perforating is performed. If fluid losses occur, a fluid loss pill is pumped and later acidized after upper completion is installed. After pulling out of wellbore with the perforation guns, the lower completion is installed. Then, the upper completion is installed and run with a tubing hanger that lands out in the subsea tree (i.e. Horizontal subsea Christmas Tree (HXT)). Typically, two tubing hanger plugs are installed on two separate wireline (W/L) runs via slickline and pressure tested. The time to perform the tubing hanger plug installations may be at least 12 hours of rig time, and typically averages about 3 days (72 hours) of rig time in offshore operations. One of the problems that extends this operation is debris issues interfering with the sealing of the tubing hanger plugs.

Further, other procedures and processes may also require multiple days of rig time to activate downhole devices. For instance, perforating intervals of a subsurface formation normally involves one or more separate trips prior to running the lower completion. Then, the perforation guns, such as tubing-conveyed perforating (TCP) guns, are pulled out of the wellbore after well fluid losses or gains (gas kicks) are handled. The normal time to run perforation guns, perforate, and remove the perforation guns is at least 2 to 3 days of rig time and usually more due to fluid losses and live well problems.

Accordingly, the need exists for an efficient method and system to provide an alternative flow path around sealing devices in a subsea tree for installation purposes. In particular, this apparatus and method may be utilized in the installation of a component coupled to the subsea tree with a plug installed in the component prior to installation. This method and system may reduce the time and cost associated with performing the well operations, such as installation operations.

Other related material may be found in at least U.S. Pat. No. 6,612,368; U.S. Pat. No. 6,681,850; U.S. Pat. No. 6,840,494; and U.S. Patent Application Publication No. 2004/0188083.

SUMMARY

In one embodiment, a method for installing a component into an oil field tree is described. The method includes installing a sealing device into a component to block a primary flow path through the component; coupling the component with the sealing device installed to an oil field tree in fluid communication with a wellbore; adjusting at least one valve in the oil field tree to provide an alternative flow path that bypasses the sealing device; and performing installation operations via the alternative path. Further, in other embodiments, the oil field tree may be a production tree utilized to produce hydrocarbons from the wellbore or an injection tree utilized to injection fluids into the wellbore.

In an alternative embodiment, another method for installing a component into an oil field tree is described. The method includes installing at least one downhole device in a wellbore and an oil field tree in fluid communication with the wellbore; installing a sealing device into a component to block a primary flow path through the component; coupling the component with the sealing device installed to a circulating assembly; running the component and circulating assembly to the oil field tree; forming an isolated region between a portion of the circulating assembly, a portion of the oil field tree and a portion of the sealing device; adjusting at least one valve in the oil field tree to provide an alternative flow path that bypasses the sealing device; and increasing pressure within the wellbore via the alternative flow path to activate downhole devices. Further, in other embodiments, the oil field tree may be a production tree utilized to produce hydrocarbons from the wellbore or an injection tree utilized to injection fluids into the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other advantages of the present technique may become apparent upon reading the following detailed description and upon reference to the drawings in which:

FIG. 1 is an exemplary production system in accordance with certain aspects of the present techniques;

FIG. 2 is an exemplary flow chart of the use of choke and/or kill lines in the installation of a plugged tubing hanger and subsequent operations in accordance with aspects of the present technique;

FIG. 3 is an exemplary flow chart of the use of a circulating tool in the installation of a plugged tubing hanger and subsequent operations in accordance with aspects of the present technique; and

FIG. 4 is an exemplary view of the circulating assembly with the blowout preventer and subsea tree from FIG. 1 in accordance with aspects of the present techniques.

DETAILED DESCRIPTION

In the following detailed description, the specific embodiments of the present invention are described in connection with its preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, it is intended to be illustrative only and merely provides a concise description of the exemplary embodiments. Accordingly, the invention is not limited to the specific embodiments described below, but rather; the invention includes all alternatives, modifications, and equivalents falling within the true scope of the appended claims.

The present technique includes a method and system that may be utilized to install plugged equipment or components into an oil field tree and to activate downhole devices in a more efficient manner. Under the present technique, a system and method are described for providing an alternative path around a component that has a sealing device installed prior to installation. In addition, the alternative path may be utilized to activate downhole devices, such as perforation guns, in a more efficient manner. For instance, these methods may use a blowout preventer (BOP) and circulating assembly coupled to a subsea tree. The alternative path for these methods may include the use of choke and/or kill lines in a BOP or a circulating tool in a circulating assembly. The use of the present techniques may reduce sand face damage, reduce trip well control issues, perforate well with tubing in place, eliminate fluid loss pills, and/or facilitate perforating under balanced wells. As such, the present techniques may be used to enhance well installation, drilling, production and injection operations.

Turning now to the drawings, and referring initially to FIG. 1, an exemplary production system 100 in accordance with certain aspects of the present techniques is illustrated. In the exemplary production system 100, a floating drilling rig 102 and production facility (not shown) are coupled to an oil field tree, such as a production or injection subsea tree 104 located on the sea floor 106. The subsea tree 104 is an interface between one or more subsurface formations, such as subsurface formation 107, and equipment or devices coupled to the wellbore 114. The subsurface formation 107 may include multiple production intervals or zones 108a-108n, wherein number â€œnâ€ is any integer number. As the production intervals 108a-108n (herein referred to as intervals 108) may have hydrocarbons, such as oil and gas, downhole tools and production tubing strings may provide access to the intervals 108 via the subsea tree 104. However, it should be noted that the production system 100 is illustrated for exemplary purposes and the present techniques may be useful for other specific subsea or land locations.

Within the wellbore 114, various equipment and components are utilized to access the production intervals 108 and to provide hydrocarbons to the subsea tree 104. For instance, a surface casing string 124 may be installed from the sea floor 106 to a location at a specific depth beneath the sea floor 106. Within the surface casing string 124, an intermediate or production casing string 126, which may extend down to the production intervals 108, may provide support for the walls of the wellbore 114. Within the surface and production casing strings 124 and 126, a production tubing string 128 may be utilized to provide a flow path through the wellbore 114 for hydrocarbons and other fluids. A subsurface safety valve 132 may be utilized to block the flow of fluids from portions of the production tubing string 128 in the event of rupture, while packers 134 and 136 may be utilized to isolate specific zones within the wellbore annulus from each other. Also, downhole devices 138a-138n, such as perforation guns and other downhole tools, may be utilized to provide a flow path for formation fluids from the intervals to the production tubing string 128. The perforation guns may include tubing-conveyed perforating (TCP) guns with various shot densities along with packers and downhole circulating valves to allow the intervals 108 and casing string 126 to be shot under-balanced or over-balance and maintain well control.

Above the wellbore 114 at the sea floor 106, the subsea tree 104 provides an interface to other equipment that may be utilized in producing hydrocarbons from the wellbore 114. For instance, the subsea tree 104 may be coupled to a floating production facility via a production umbilical 105. The floating production facility, which may be utilized to produce and process hydrocarbons from the subsurface formation 107, may be a floating production facility or platform that include vessels capable of managing the production of fluids, such as hydrocarbons, from subsea wells. The production umbilical 105 may include one or more fluid flow lines and/or electrical cables.

Also, the subsea tree 104 may be coupled to the floating drilling rig 102 via a blowout preventer 110 and riser 111 and an additional connection via a circulating assembly 112 and landing string 113. The floating drilling rig 102 may be configured to monitor and/or perform well operations on the equipment/tools associated with the wellbore 114. In particular, the floating drilling rig 102 may include various tools that are utilized for well operations, such as adjusting the circulating mechanisms in a circulating tool, adjusting valves in the choke or kill lines, installing equipment into the wellbore, activating perforation guns along with other installation and drilling operations, such as stimulating intervals within the wellbore. The blowout preventer 110 may be an assembly of tools coupled to the subsea tree 104 and utilized to maintain well control for installation and drilling operations. The riser 111 and landing string 113 may be tubular members or piping, such as rig marine riser, casing pipe and/or drilling pipe. The landing string 113 may also include a control umbilical (not shown), which has electrical and/or hydraulic control lines, for controlling and communicating with various devices from the floating drilling rig 102. The circulating assembly 112 is configured to fit within or at least partially within the blowout preventer 110 and has a circulating tool that equalizes fluid pressure between the interior of the circulating assembly 112 and a location below a sealing device in the subsea tree 104.

Beneficially, the circulating assembly 112 and/or choke or kill lines in the BOP 110 may be utilized in the installation of the tubing hanger with one or more tubing hanger plugs already installed to reduce rig time. By using these components, a more efficient mechanism is utilized over kill lines or choke lines for installing the tubing hanger with the one or more plugs installed. In addition, the circulating assembly along with kill and choke lines may also be utilized in this configuration to increase pressure within the wellbore to activate perforation guns. In particular, if the tubing hanger is installed with the plug installed, the circulating assembly, kill line, or choke lines may be utilized to increase pressure within the wellbore without having to pump down the landing string or drill pipe. As such, various tools or subassemblies may be utilized to enhance well processes, as discussed further below.

FIG. 2 is an exemplary flow chart of the use of choke and/or kill lines in the installation of a plugged tubing hanger and subsequent well operations in accordance with aspects of the present technique. This flow chart, which is referred to by reference numeral 200, may be best understood by concurrently viewing FIG. 1. In this flow chart 200, a process to install a tubing hanger with one or more sealing devices already installed is described. This process provides a more efficient installation process, which reduces drilling rig cost and time. In addition, the process may also enhance operations that activate downhole devices. That is, the use of the choke and/or kill lines may reduce drilling rig time and cost by providing an alternative flow path that may activate downhole devices, such as perforation guns, disposed within the wellbore. Thus, the choke and/or kill lines of the blowout preventer may enhance well installation and drilling operations.

The flow chart begins at block 202. At block 204, a sealing device may be installed into the tubing hanger and tested. The sealing device may include includes one or more tubing hanger plugs, such as two wireline plugs, that are to be installed into the subsea tree 104. The installation may be performed at the drilling rig 102 or a location prior to shipment to the drilling rig 102. The testing includes verifying that the pressure holds below the bottom plug, in between both plugs and above the top plug if two wireline plugs are used. At block 205, a riser 111 and blowout preventer (BOP) 110 may be coupled to the oil field tree. The riser 111 and BOP 110 may be installed by coupling the riser 111 to the BOP 110, running the coupled BOP 110 and riser 111 to the subsea tree 104 and engaging the BOP 110 to the subsea tree 104. Once installed, the wellbore may be cleaned out in block 206. Cleaning out the wellbore may include displacing oil based mud along with cuttings out of the wellbore with clean filtered brine. Then, the lower completion assembly may be run into the wellbore 114, as shown in block 207. The lower completion assembly may include the packers 134 and 136 and downhole devices 138a-138n. At block 208, the circulating assembly 112, tubing hanger, production tubing string 128 may be run into the riser. The circulating assembly 112, which may be a single tool or two or more tools or subassemblies coupled together, may include various subassemblies adapted to engage with the subsea tree 104 and BOP 110. In this configuration, the circulating assembly 112 may be coupled to the landing string 113 and run within the riser 111 via the landing string 113.

Then, the circulating assembly 112 and the tubing hanger are coupled to the oil field tree, as shown in block 210. In addition, the coupling of the circulating assembly 112 may include picking up a coil tubing lift frame to compensate for movement of the floating drilling rig 102 due to the water and a big bore surface tree for well control. Then, the coil tubing lift frame and big bore surface tree are attached to the landing string 113 and the tubing hanger running tool may be latched to the tree tubing hanger. At block 212, an isolated region may be formed with a portion of the BOP 110, a portion of the circulating assembly 112 and a portion of the oil field tree, such as subsea tree 104. This isolated region may be formed to include one or more of the valves attached to choke or kill lines on the BOP 110 by engaging a packer between the BOP 110 and a section of the circulating assembly 112, as discussed further in FIG. 4, or by engaging a sealing mechanism from a portion of the circulating assembly 112 to a portion of the subsea tree 104.

With the isolated region formed, various steps may be performed to provide a flow path between the circulating assembly 112 and the wellbore 114 through the oil field tree. At block 214, the valves on the choke or kill lines in the BOP 110 are adjusted into a circulating configuration or position. This adjustment may include a mechanical actuation, electrical actuation, or hydraulic actuation of the valves, as is known in the art. Then, a fluid flow path is provided between the choke or kill lines and a location below the sealing device in the oil field tree, as shown in block 216. The flow path may be provided by opening various valves within the subsea tree 104 to provide a flow path between fluids inside the landing string 113 and the subsea tree 104 under the sealing device.

With the fluid communicating with each other on both sides of the sealing device, other operations may be performed within the wellbore through the flow path that bypasses the sealing device. At block 218, the pressure within the wellbore may be increased by pumping fluid with a cement unit to pressure up and fire the TCP guns via pressure actuation. The increase in pressure may be indicated by various sensors or gauges positioned near or around the sealing device in the subsea tree 104 and in the circulating assembly 112. At block 220, if the pressure has reached a certain pressure range, downhole devices installed in the wellbore may be activated. The activation of the downhole devices may include firing the TCP guns, opening check (MCX) valves, injecting fluid into intervals of the subsurface formation, pressurizing the downhole devices, such as perforating guns, to form perforations (not shown) into the casing string 126 at or near the intervals 108. If the downhole devices have not been activated, the pressure in the wellbore may continue to increase in block 218. However, if the downhole devices have been activated, well operations may be performed, as shown in block 222. Well operations may include producing hydrocarbons or injecting treatment fluids into the formation via the production tubing string 128. The well operations may also include coupling the subsea tree 104 to a production facility via the control umbilical 105, monitoring the pressures within the wellbore and/or processing the hydrocarbons. Regardless, the process may end at block 224.

As a specific example, process described above may be utilized to install a tubing hanger having a tubing hanger plug installed prior to shipment to the drilling rig 102, which is coupled to the production tubing string 128. In this example, the riser 111 and BOP 110 may be coupled to the subsea tree 104 via a connection, such as a H4 connector. Then, the tubing hanger is coupled between the production tubing string 128 and the circulating assembly 112 and run in the riser 111. The circulating assembly 112 is coupled to the subsea tree 104 and an isolated region is formed between portions of the BOP 110, circulating assembly 112 and subsea tree 104. Then, the valves on the kill or choke lines may be adjusted into a circulating position along with valves in the subsea tree 104 to provide a fluid communication path between fluid above and below the tubing hanger plug. This flow path may be used to pressure up the wellbore to fire perforation guns, to inject fluid, to underbalance well, etc.

As another example, process described above may include perforation guns that are coupled to the production tubing string 128. Again, a tubing hanger having a tubing hanger plug installed prior to shipment to the drilling rig 102 is coupled to the production tubing string 128. In this example, perforation guns are part of the lower completion assembly that is placed within the wellbore. Then, the riser 111, BOP 110, tubing hanger, production tubing string 128 and the circulating assembly 112 may be coupled together similar to the example above to form the isolated region. However, once the fluid path is opened the pressure within the wellbore 114 may be increased to fire the perforation guns. This flow path may be used to pump fluid from cement unit to pressure up firing head to initiate detonation of perforation guns.

Beneficially, the use of the kill or choke lines may enhance the well operations, such as installation operations. For instance, the kill or choke lines may be used to pump fluid below a tubing hanger with the tubing hanger plug installed in less than an hour, while the other methods, which are described above, may require three days or more to install tubing hanger plugs. As a result, time and expense of the drilling rig operations may be reduced by three or more days in performing the drilling and installation operations for a specific well. Further, the kill or choke lines may be used to enhance other subsequent well operations, such as perforating intervals with perforation guns on injectors because everything is installed or â€œbuttoned upâ€ (i.e. no fluid losses, separate perforation trips, etc.).

However, the choke and/or kill lines typically include debris from previous operations, such as oil base mud, brine, plastic coating, etc., and have a reduced internal diameter that further compounds the problem with debris. If the kill and/or choke lines are utilized to provide a flow path, the debris may damage equipment or have to be removed for other equipment to function properly. In particular, for injection, the debris may block the flow path that injection operations are trying to utilize. To address this problem, the circulating assembly 112 may include a circulating tool to provide an additional flow path directly from the landing string 113 to the isolated region. The process of installing the tubing hanger with sealing devices and activating downhole devices within the wellbore in a more efficient manner with the circulating assembly 112 is described further below in FIG. 3.

FIG. 3 is an exemplary flow chart of the use of a circulating tool in the installation of a plugged tubing hanger and subsequent operations in accordance with aspects of the present technique. This flow chart, which is referred to by reference numeral 250, may be best understood by concurrently viewing FIGS. 1 and 2. In this flow chart 250, a process to install a plugged tubing hanger and activate downhole devices in a more efficient manner is described. In this process, a circulating tool in the circulating assembly is utilized to further enhance operations instead of the choke or kills lines. Accordingly, it should be noted that this process utilizes some similar blocks to those described in FIG. 2, which are referenced to in the associated discussion of FIG. 2.

The flow chart begins at block 252. In blocks 254-262, the BOP 110, riser 111, lower completion assembly, tubing hanger, circulating assembly, production tubing string 128 may be installed to form the isolated region similar to the discussion of blocks 204-212. However, in this process, the circulating assembly 112, which may be a single tool or two or more tools or subassemblies coupled together, may include a circulating tool having a circulating mechanism that is mechanically, hydraulically, magnetically or electrically actuated. An example of a circulating tool is discussed further in U.S. Provisional Application by Lary Ratliff et al., entitled â€œA Method and Apparatus for Equalizing Pressure with a Wellbore,â€ and filed on May 24, 2006, which is incorporated by reference. Accordingly, the isolated region may be formed to include at least a portion of the circulating tool by engaging a packer between the BOP 110 and a section of the circulating assembly 112, as discussed further in FIG. 4, or by engaging a sealing mechanism from a portion of the circulating assembly 112 to a portion of the oil field tree (i.e. subsea tree 104).

With the isolated region formed, various steps may be performed to provide a flow path between the circulating assembly 112 and the wellbore 114 through the subsea tree 104. At block 264, the circulating tool in the circulating assembly is adjusted into a circulating configuration or position. This adjustment may include a mechanical actuation, electrical actuation, or hydraulic actuation of a section of the circulating tool, as noted above. For instance, if the circulating mechanism of the circulating tool is mechanically actuated, it may be placed into the circulating position to provide a fluid flow path between the interior of the circulating tool and the isolated region. Then, a fluid flow path is provided between the circulating assembly 112 and a location below the sealing device in the subsea tree 104, as shown in block 266. With the fluid communicating with each other on both sides of the sealing device, the downhole devices may be activated and other well operations performed in blocks 268-272, which are similar to blocks 218-222. Regardless, the process may end at block 274.

As a specific example, process described above may be utilized to install a tubing hanger having a tubing hanger plug installed prior to shipment to the drilling rig 102, which is coupled to the production tubing string 128. In this example, the riser 111 and BOP 110 may be coupled to the subsea tree 104 via a connection, such as a H4 connector. Then, the tubing hanger is coupled between the production tubing string 128 and the circulating assembly and run in the riser 111. The circulating assembly, which includes a circulating tool, is coupled to the subsea tree 104 and an isolated region is formed between portions of the BOP 110, circulating assembly and subsea tree 104. Then, the circulating tool in the circulating assembly may be adjusted into a circulating position along with valves in the subsea tree 104 to provide a fluid communication path between fluid above and below the tubing hanger plug going directly down the landing string or drill pipe (DP), which typically has a larger internal diameter than the internal diameter of the choke and kill lines and is less likely to have debris issues.

As another example, process described above may include perforation guns that are coupled to the production tubing string 128. Again, a tubing hanger having a tubing hanger plug installed prior to shipment to the drilling rig 102 is coupled to the production tubing string 128 and perforation guns. In this example, the riser 111, BOP 110, tubing hanger, production tubing string 128 and the circulating assembly may be coupled together similar to the example above to form the isolated region. However, once the fluid path is opened, pressure is increased in the isolated region and wellbore to actuate the perforation guns. Then, hydrocarbons may be produced from the interval or treatment fluids injected into one or more intervals.

As a third example, process described above may include perforation guns that are coupled to the production tubing string 128 for injection operations. Again, a tubing hanger has one or more tubing hanger plugs installed prior to shipment to the drilling rig 102 and is coupled to the production tubing string 128 and perforation guns. In this example, the riser 111, BOP 110, tubing hanger, production tubing string 128 and the circulating assembly may be coupled to form the isolated region, as noted above. However, once the fluid path is opened pressure is increased to actuate the perforation guns. Then, via the same path, brine, base oil, gas, etc. can be injected into the formation. As a result, three days of rig time are reduced for installation operations per injector well.

Beneficially, the use of the circulating mechanism in circulating tool may enhance the well operations, such as installation operations for the well. For instance, the circulating tool may be used to install a tubing hanger with the tubing hanger plug installed and have substantially reduced (i.e. up to about 95%) chance of no debris. Further, the rig time utilized to clean the drill string as compared to pumping down choke and kill lines is less because the use of the kill or choke lines have a higher debris risk and longer time to clean up. As a result, time and expense of the drilling rig operations may be reduced by three or more days in performing the drilling and installation operations for a specific well. Further, the circulating tool may be used to enhance other subsequent operations, such as perforating intervals with perforation guns because of the reduced debris and enhanced efficiency. Also, the use of the landing string 113 to reduces potential damage and delays to drilling operations because trash or debris are present from the choke and/or kill lines. Thus, the use of the circulating assembly 112 and landing string 113 provides efficient mechanism for installing a plugged tubing hanger along with other components.

For exemplary purposes, the circulating tool and circulating assembly are described further below in FIG. 4. FIG. 4 illustrates an exemplary embodiment the subsea tree 104, blowout preventer 110, and the circulating assembly 112 being coupled together. In this embodiment, the circulating tool may include a mechanically actuated circulating mechanism, which is one possible embodiment. Accordingly, it should be appreciated that these are merely exemplary embodiments, which may be modified to provide the functionality described under the present techniques.

The subsea tree 104 includes various components utilized to provide access for remediation operations and manage the flow of fluid from the formation 107, as is known in the art. For instance, the subsea tree 104 has a body 304 that includes various sections configured to couple with tools, such as the BOP 110 or circulating assembly 112, the production tubing string 128 and a production manifold (not shown) that interfaces with the production umbilical 105. One of the sections of the body 304 interfaces with tools, such as the BOP 110 or circulating assembly 112, and includes a tubing hanger 306 and a tubing hanger plug 302. The tubing hanger plug 302 prevents the flow of fluids from the wellbore through this access point. In addition, this section of the body 304 may include a bypass passage 310 coupled to a bypass conduit 312 that provides a fluid flow path from the interior of the subsea tree 104 above the tubing hanger plug 302 to production conduits 314. Within and/or associated with the conduits 312 and 314, various valves 316-322 and pressure monitors 323-324 may be utilize to manage the flow of fluids through the subsea tree 104. These valves 316-322 and pressure monitors 323-324 may be controlled by control logic 326 to manage the flow of fluids, as is known in the art. Also, a choke 327 may be positioned along the production conduit 314 to manage the flow of fluids from the wellbore to the production umbilical 105.

The blowout preventer (BOP) 110 includes various components that are utilized to provide well control, which are also known in the art. For instance, the BOP 110 includes an upper annular 330 and a lower annular 332 that form a seal with different types of pipes. Also, the BOP 110 includes a shear/seal ram 334 that seals together by cutting any tool or piping across that portion of the BOP 110 and three VBRs (variable bore rams) 336, 338 and 340 that are pipe rams configured to operate for various pipe diameters, such as pipe in the range of 5 inches to 7 inches, for example. In addition, the BOP 110 includes a choke line 342 with choke valves 343 and a kill line 344 with kill valves 345 that provide fluid paths from the subsea tree 104 to reduce or increase the fluid pressure for well control or device activation. Further, the BOP 110 includes a tree connection section configured to engage and form a sealed connection with the subsea tree 104. This section may include threads internal to the BOP 110 that engage with threads external to a section of the subsea tree 104, or an extension that engages with an H4 connector.

The circulating assembly 112 includes various tools and subassemblies that are utilized to engage with the subsea tree 104 and provide flow paths for fluids through the landing string 113 to the subsea tree 104. For instance, the circulating assembly 112 may include a tubing hanger running tool (THRT) 348 to latch to the tubing hanger 306, a slick joint 350 coupled to umbilical line 352, a shear joint pup 354 to go across the shear rams 334, a circulating tool 356, a spacer pup 355 and a pack off subassembly 358. The THRT 348 may include a tool that unlatches the tubing hanger or tree cap from the subsea tree 104 and makes a seal with the tubing hanger and tree cap. The slick joint 350 may include a gun drilled joint of pipe to pass hydraulic pressure. The shear joint pup 354 may include a piece of pipe that has a pressure rating and tensile strength that is below the ratings of the shear ram 334. The circulating tool 356 may include hydraulic, electric and mechanical mechanisms to provide a radial flow path between the exterior and interior of the circulating tool 356. The spacer pup 355 may include a piece of pipe that has a pressure rating and is adapted to pass hydraulic fluid through the interior of the spacer pup 355, while the pack off subassembly 358 may include a gun drilled joint of pipe adapted to pass hydraulic fluid through the interior.

To provide the additional flow path around the tubing hanger plug 302, the upper annular 330 may be expanded to form an isolated region or annulus between a portion of the BOP 110, circulating assembly 112 and tubing hanger plug 302. Then, the circulating tool is adjusted into a circulating position. If the circulating mechanism is mechanically activated, this adjustment may include moving the landing string 113 to align openings 359 and to provide a fluid flow path 360 from the interior of the landing string 113 to the isolated region. Regardless, the valves 316, 317, 319 and 321 may be placed into the open position, while the valves 318 and 320 are placed into the closed position. With these valves 316-321 in the various positions, fluid may flow between a location below the plug 302 through the conduits 312 and 314 along the fluid flow path 360 into the circulating assembly.

As additional embodiments, it should be understood that the processes of FIGS. 2 and 3 may be modified in different embodiments. For instance, the adjustment of the circulating tool into the circulating position in blocks 214 and 254 may be performed prior to the forming of the isolated region in blocks 212 and 252. Further, the providing of the fluid flow path between the circulating assembly 112 and the location below the sealing device in the oil filed tree in blocks 216 and 256 may be performed before blocks 214 and 254, but after the forming of the isolated region in blocks 212 and 252. Thus, the ordering of the different steps within the processes described may be modified in other embodiments.

While the present techniques of the invention may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown by way of example. However, it should again be understood that the invention is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques of the invention are to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.