Method and apparatus for equalizing pressure with a wellbore

Abstract

A method, assembly and apparatus for equalizing pressure around a sealing device in a production or injection tree. The method includes coupling a circulating assembly to an oil field tree and forming an isolated region between a portion of the circulating assembly, a portion of the tree and a sealing device within the tree. Then, a circulating mechanism in the circulating assembly is adjusted to create a flow path between the interior of the circulating assembly and a location below the sealing device. When the pressure below the sealing device has substantially equalized with the pressure within the interior of the circulating assembly, the sealing device is removed through the circulating assembly. Further, remediation and production operations may be performed on wellbore tools or a subsurface formation below the tree.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 60/802,924, filed May 24, 2006.

FIELD OF THE INVENTION

This invention relates generally to an apparatus and method for equalizing pressure with a wellbore for production, injection and remediation operations. More particularly, this invention relates to a wellbore apparatus and method for equalizing pressure between a circulating tool and a location below a sealing device in and/or associated with an oil field tree. This pressure equalization may reduce potential damage within the wellbore when the sealing device is removed through the circulating tool.

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, problems may occur within the wellbore that limit or prevent the production of hydrocarbons from the subsurface formation. As a result, the well may have remediation operations performed on one or more of the intervals in the subsurface formation to enhance production operations.

In certain environments, the ability to perform the remediation operations may be difficult and expensive. In particular, the hydrostatic pressure within a riser in deep water environments may complicate the removal of a sealing device, such as a plug, from within a subsea tree because of the pressure differential around the sealing device. This may result in abandonment of the well if the sealing device cannot be removed. However, if the sealing device can be removed, the removal of the sealing device may damage tools within the wellbore and/or the subsurface formation if the sealing device is not removed properly. That is, the pressure differential around the sealing device may result in breaking wireline, loss of fluid to the formation and/or loss of one or more of the intervals in the completion. As such, removal of the sealing devices from a subsea tree may be problematic.

Typically, procedures and processes require multiple days of rig time to remove the sealing device properly. For example, a typical procedure to remove a sealing device, such as a plug, involves running and coupling a riser and blowout preventer (BOP) to a subsea tree. Once installed, a landing string is run multiple times into the riser to access and interact with the subsea tree. These different runs may involve removing the tree cap, latching the tubing hanger, using a nitrogen unit to lighten the column of fluid within the riser to equalize pressure above and below the plug, removing the plug if the pressure is equalized on both sides of the plug, and rigging down the units. The time to perform these plug removal operations may be about 100 hours of rig time.

Accordingly, the need exists for an efficient method and apparatus to equalize pressure around sealing devices in a subsea tree, such as a plug and/or packer. In particular, this apparatus and method may be utilized in plug removal procedures to reduce the time and cost associated with performing remediation operations for subsurface formations.

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 pressure equalizing apparatus for use with an oil field tree is described. The pressure equalizing apparatus including a first tubular member having a first end, a second end, at least one first tubular opening and a central opening within the first tubular member to provide a longitudinal fluid flow path between the first end and the second end. Further, the pressure equalizing apparatus includes a circulating mechanism coupled to the first tubular member and having a circulating position and an isolating position, wherein the circulating position provides at least one radial flow path between the central opening and a region external to the first tubular member through the at least one first tubular opening and the isolating position prevents fluid flow between the central opening and the region external to the first tubular member. The inner diameter of the apparatus is adapted to pass a sealing device through the apparatus. Further, the circulating mechanism may be mechanically, electrically, magnetically or hydraulically actuated.

In a second embodiment, an assembly for equalizing pressure is described. This assembly includes a blowout preventer having a first central opening and adapted to couple to an oil field tree. Further, the assembly includes a circulating assembly configured to be disposed at least partially within the first central opening and to engage the blowout preventer to form an isolated region between a portion of the circulating assembly and at least a portion of the interior of the blowout preventer. The circulating assembly has a first end, a second end and a plurality of subassemblies coupled together with a second central opening extending through the interior of the plurality of subassemblies to provide a first flow path between the first end and the second end. The plurality of subassemblies includes a first connection subassembly at the first end adapted to engage with the oil field tree; and a circulating tool coupled to the first connection subassembly and having a circulating position and an isolating position, wherein the circulating position provides a second flow path between the second central opening and the isolated region and the isolating position prevents fluid flow between the second central opening and the isolated region. Further, the plurality of subassemblies includes a second connection subassembly at the second end adapted to engage with landing string, wherein the circulating tool is coupled between the first connection subassembly and the second connection subassembly.

In a third embodiment, a method for equalizing pressure around a sealing device is described. The method includes coupling a circulating assembly to an oil field tree; forming an isolated region between a portion of the circulating assembly, a portion of the oil field tree and a sealing device within the oil field tree; adjusting a circulating mechanism in the circulating assembly to circulate fluid between the interior of the circulating assembly and a location below the sealing device; removing the sealing device through the circulating assembly when the pressure at the location has substantially equalized with the pressure within the interior of the circulating assembly. Further, remediation operations may be performed on wellbore tools or a subsurface formation below the oil field tree once the sealing device is removed. Then, the sealing device may be reinstalled. Once reinstalled, hydrocarbons may be produced from the subsurface formation or the stimulation fluids may be injected into the well.

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 installation and use of the circulating assembly and blowout preventer from FIG. 1 in accordance with aspects of the present techniques;

FIG. 3 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;

FIGS. 4A-4C are exemplary embodiments of the circulating tool of FIG. 3 that is mechanically actuated in accordance with aspects of the present techniques; and

FIGS. 5A-5B are exemplary embodiments of the circulating tool of FIG. 3 that is hydraulically actuated 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 one or more embodiments of a circulating tool that may be utilized with a blowout preventer and/or other subassemblies to equalize pressure around a sealing device, as described below. Under the present technique, an apparatus, system and method are described for utilizing a circulating tool having a circulating mechanism to equalize pressure around a sealing device, such as a plug in a production/injection oil field tree. In the method, the circulating tool may be coupled to other tools or subassemblies to engage with the oil field tree. Then, an isolated region is formed between at least a portion of the circulating tool, at least a portion of the BOP and at least a portion of the oil field tree. Once the isolated region is formed, the circulating mechanism is utilized to provide a fluid flow path between the interior of the circulating tool and a location external to the circulating tool within the isolated region. The oil field tree may also be adjusted to provide a flow path between a location below the sealing device and the isolated region. Through this fluid flow path, the pressure at the location below the sealing device equalizes with the pressure within the circulating tool. Then, the sealing device may be removed from the oil field tree through the circulating device without damaging to subsurface intervals and tools within the wellbore. As such, the present techniques may be used in well remediation operations to enhance hydrocarbon production, stimulation and/or remediation operations for a subsurface formation.

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 103 are coupled to a production or injection tree, such as a 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 “n” is any integer number. As the production intervals 108a-108n may have hydrocarbons, such as oil and gas, the production of hydrocarbons may involve accessing downhole tools or wellbores via the subsea tree 104 for remediation operations. 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 108a-108n 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 a depth near the production interval 108a, 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, flow control devices, such as sand control devices 138a-138n, may be utilized to manage the flow of fluids from the intervals to the production tubing string 128.

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 103 via a production umbilical 105. The floating production facility 103, 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 remediation 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 circulating operations, such as adjusting the circulating mechanisms in a circulating tool, equalizing pressure and/or removing plugs, along with other remediation operations, such as stimulating an interval within the wellbore or adjusting downhole tools. The blowout preventer 110 may be an assembly of tools coupled to the subsea tree 104 and utilized to maintain well control for circulating and remediation 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 is utilized to equalize pressure around the sealing device, which may be a plug in the subsea tree 104. With the pressure equalized, the plug may be removed from the subsea tree 104 without causing damage to the formation 107 and/or tools, such as the sand control devices 138a-138n. As such, various tools or subassemblies may be utilized as part of the circulating assembly.

For example, the circulating assembly 112 may include a tubing hanger running tool along with pipe joints (or subsea test tree) and the landing string 113. The circulating assembly 112 may then be coupled to the blowout preventer 110 to form an isolated region above a plug in the subsea tree 104. If the blowout preventer 110 has a choke and/or kill lines, these lines may be utilized to provide a lighter fluid to the isolated region. Then, valves within the subsea tree may be utilized to provide a flow path from the isolated region to a location below the plug to equalize pressure around the plug. However, these lines typically include debris from previous operations, which may result in increased rig time to remove the debris or work around the debris. As such, the circulating assembly 112 may include a circulating tool to provide an additional flow path directly from the landing string 113 within the isolated region. The process of installing and using the circulating assembly 112 is described further below in FIG. 2.

FIG. 2 is an exemplary flow chart of the installation and use of the circulating assembly and blowout preventer from FIG. 1 in accordance with aspects of the present techniques. 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 equalize fluid pressure between the interior of a circulating assembly and a location below a sealing device, such as a plug or packer in a subsea tree 104, is described. By equalizing pressure, the time and expense of remediation operations on a subsea tree may be reduced. That is, the present technique provides a mechanism for efficiently removing a sealing device by equalizing pressure around the sealing device. Thus, the circulating assembly and blowout preventer may enhance remediation and production operations.

The flow chart begins at block 202. At block 204, a riser 111 and blowout preventer (BOP) 110 may be installed. 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. At block 206, the circulating assembly 112 may be coupled to the oil field tree. 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, as discussed further in FIGS. 3, 4A-4C and 5A-5B. The circulating assembly 112 may be coupled to the landing string 113, run within the riser 111 via the landing string 113, and engaged with the subsea tree 104, as part of the coupling process. 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 208, 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 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 in FIG. 3, 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 equalize pressure for the removal of the sealing device within the subsea tree 104. At block 210, the circulating tool 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, fluid may be circulated into the circulating assembly 112 and isolated region via the landing string 113, as shown in block 212. This fluid may displace other fluid within the landing string 113 with a lighter or heavier fluid, such as nitrogen, to within a specific distance, such as 100 feet (ft) of the circulating tool in the circulating assembly 112. This fluid may be utilized to adjust the weight of the fluid within the circulating assembly 112 to match the fluid below the sealing device and/or within the wellbore. At block 214, a fluid flow path is provided for between the circulating assembly 112 and a location below the sealing device in the oil field tree. 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, the pressure around the sealing device may be monitored, as shown in block 216. The 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 218, if the pressure has not equalized, the monitoring of the pressure may continue in block 216. However, if the pressure has equalized, the sealing device may be removed through the circulating assembly in block 220. The sealing device may be removed by running slick line, electrical line or coil tubing with a receiving tool through the circulating assembly 112 to latch and pull a plug or packer in or below the subsea tree 104. Once the sealing device is removed, the circulating tool may be adjusted into an isolating configuration or position, as shown in block 221. Then, the remediation operations may be performed in block 222. The remediation operations may include stimulation treatments of one or more of the intervals 108, installing straddle bridges or plugs into certain intervals 108, adjusting sleeves for flow control devices 138a-138n, cutting tubing and preparing to complete another interval and/or reinstalling a plug or packer into the subsea tree 104. Once the remediation operations are completed, the production operations may be performed in block 224. The production operations may include setting plugs and sliding sleeves, monitoring the pressures associated with the wellbore, producing hydrocarbons and processing the hydrocarbons. Regardless, the process may end at block 226.

As a specific example, process described above may be utilized to remove a tubing hanger plug. In this example, the riser 111 and BOP 110 may be coupled to the subsea tree 104 via a connection, such as a threaded connection or H4 connector. Then, a tree cap may be removed from the subsea tree 104 and returned to the surface. Next, the circulating assembly 112, 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 112 and subsea tree 104. Then, the circulating tool in the circulating assembly 112 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. Once equalized, the tubing hanger plug is pulled to the surface and remediation operations may be performed on the intervals within the wellbore through the subsea tree 104, which are followed by production operations.

As another example, process described above may be utilized to remove a tree cap plug without removing the tree cap. In this example, the riser 111 and BOP 110 may again be coupled to the subsea tree 104 by a connection, such as a threaded connection or H4 connector. Then, the circulating assembly 112, which includes a circulating tool, is coupled to the subsea tree 104 and an isolated region is formed between the BOP 110, circulating assembly 112 and subsea tree 104. Once the isolated region is formed, the circulating tool in the circulating assembly 112 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 tree cap plug. Once equalized, the tree cap plug is pulled to the surface and remediation operations may again be performed on the intervals within the wellbore through the subsea tree 104. Then, the tree cap plug may be reinstalled and production operations performed.

Beneficially, the use of the circulating mechanism in circulating tool may enhance the operations of the well. For instance, the circulating tool may be used to remove a sealing device, such as a plug, from the subsea tree 104 in about 40 hours, while the previous methods, which are described above, may require about 100 hours to remove the sealing device from the subsea tree 104. As a result, time and expense of the rig operations may be reduced by one or more days in performing the remediation operations for a specific well. Further, the circulating tool may be used to displace fluids only in the production tubing string 128 and/or landing string 113 instead of fluids in the riser. That is, the isolated region in riser 111 is displaced, but the remaining riser 111 does not have to be displaced with the fluid utilized to adjust the weight of the fluid above the sealing device. As a result, the operational costs are reduced because the amount of fluid displaced is less than other approaches that utilize the riser 111. Also, the use of the landing string 113 to displace fluids reduces potential damage to the completion through the use of choke and/or kill lines, which may include trash or debris from other remediation or installation operations. Thus, the use of the circulating assembly 112 and landing string 113 provides enhanced control on the quality and type of fluids utilized in the sealing device removal and remediation operations.

For exemplary purposes, different embodiments of the circulating tool and assembly are described below. For instance, FIG. 3 illustrates an exemplary embodiment the subsea tree 104, blowout preventer 110, and the circulating assemblies 112 being coupled together. In this embodiment, the circulating tool may include a mechanically actuated circulating mechanism, a hydraulically actuated circulating mechanism, a magnetically actuated circulating mechanism and/or an electrically actuated circulating mechanism, which are shown in FIGS. 4A-4C and 5A-5B and discussed further below. Accordingly, it should be appreciated that these are merely exemplary embodiments, which may be modified to provide the functionality described under the present techniques.

FIG. 3 is an exemplary embodiment of the circulating assembly 112 and blowout preventer 110 coupled to the subsea tree 104 of FIG. 1 in accordance with aspects of the present techniques. In this embodiment, the subsea tree 104, circulating assembly 112 and blowout preventer 110 include various components or subassemblies utilized to equalize pressure around a tubing hanger plug 302 in the subsea tree 104. Accordingly, these components and subassemblies are described further below.

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 engages 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 the fluid pressure for well control. 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, an extension that engages with an H4 connector or other suitable profile and/or hubs (i.e. defined in API 16A/17D).

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, which is shown in greater detail in FIGS. 4A-4C and 5A-5B, 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 equalize pressure 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 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 isolated region. Thus, the fluid pressure within the isolated region and within the subsea tree 104 below the tubing hanger plug 302 may equalize through the flow path 360.

To interact with a subsea tree 104 and BOP 110, the dimensions of the circulating tool 356 is based upon various factors. The factors may include the outer diameter of the circulating tool 356, the internal diameter of the circulating tool 356 and the length of the circulating tool 356. The outer diameter of the circulating tool 356 is limited by the internal diameter of the BOP 110 and the amount of space required for the umbilical line 352. The inner diameter of the circulating tool 356 is limited by the size of the sealing device to be removed, such as the tubing hanger plug 302, tree cap plug, or packer, and the performance rating of the tool (such as pressure, tension, compression, torque, etc. The length of the circulating tool 356 may be limited by the other assembly tools and specific positioning of the circulating mechanism relative to the upper annular 330 in the BOP 110. Also, the circulating tool 356 may be positioned above the shear/seal ram 334 to reduce any potential damage to the circulating tool 356 in the event of a loss of well control. In addition, the length of the components of the circulating tool 356 may be limited by the movement of the circulating mechanism. Accordingly, these various factors and other embodiment specific aspects are discussed below in FIGS. 4A-4C and 5A-5B.

FIGS. 4A-4C are exemplary embodiments of the circulating tool 356 having a circulating mechanism that is mechanically actuated in accordance with embodiments of the present techniques. In these embodiments 400a and 400b of the circulating tool 356, which may be referred to as embodiments 400, the circulating mechanism includes a first tubular member 402 having one or more openings 406 and threads 407, and a second tubular member 404 having one or more openings 408 and threads 409. The tubular members 402 and 404 may be made from metal or metal alloys and have suitable strength. For instance, the tubular members 402 and 404 may have a differential pressure rating of up to 5,000 psi or up to 15,000 psi, operate in a temperature range of 32° F. (Fahrenheit) to 200° F., a torque rating of 50,000 foot-pounds (ft-lbs), internal pressure rating of 15,232 psi (pounds per square inch), and a tension rating of 1,149,234 lbs. As such, the combined load rating for the embodiment may be as much as 621,000-pounds tension with an internal pressure of 15,000 psi and torque of 50,000 ft-pounds. The openings 406 and 408 may be configured to provide fluid flow paths that provide volume flow that is greater than or equal to the volume flow through the landing string 113, bypass passage 312 and bypass conduit 314. In particular, the openings 406 and 408 may be about equal to the flow area of the landing string to prevent any material wash out. The threads 407 and 409 may be utilized to couple the circulating tool to other tools, as is know in the art. In these embodiments 400, the openings 406 and 408 are mechanically actuated by movement of the landing string or wireline to align into a circulating position, as shown in FIG. 4B, and to misalign in an isolating position, as shown in FIG. 4A. The various components of the embodiments 400 are shown below in greater detail.

In FIG. 4A, the first tubular member 402 and the second tubular member 404 are in an isolating position. In this configuration, the seals 410-412 isolate fluid flow from the exterior and interior of the tubular members 402 and 404. The seals 410-412 may include molded seals, o-rings, t-rings, chevron packing stack, poly-pak and/or other elastomeric and thermoplastic materials. Also, in the isolating position, the second tubular member 404 may include one or more recessed sections or slots 414, while the first tubular member 402 may include guide members 416 that engage with the slots 414. The slots 414, which may be straight slots or “J” slots, may be utilized to control the position of the openings 406 and 408 relative to each other in the various configurations. The guide members 416 may be a pin, screw, rod or other suitable component that engages with the slot 414. In this embodiment 400a, each of the guide members 416 is positioned at one end of the respective slots 414 that extends the circulating tool 400a to a length 418. In addition, it should be noted that one or more biasing members (not shown) may be utilized to fix the embodiment 400 into one of the positions. These may include shear pins, collets, or other suitable members.

In FIG. 4B, the first tubular member 402 and the second tubular member 404 are in the circulating position. In this configuration, the guide member 416 moves a longitudinal distance 421 within the slot 414 to engage with another end of the slot 414. This movement aligns the openings 406 and 408 to provide one or more radial fluid flow paths between the exterior and interior of the embodiment 400b. Further, in this circulating position, the embodiment 400b is compressed to a length 420.

As noted above, the embodiments 400 may be adapted to operate with the subsea tree 104 and BOP 110. As a result, the factors, such as the outer diameter 422 of the embodiment 400, the internal diameter 424 of the embodiment 400, the length of the embodiment 400, may be adjusted to maintain certain dimensional aspects of the circulating tool. For instance, the outer diameter 422 is limited by the internal diameter of the BOP 110, which may be between 7 1/16 inches and 28¾ inches, or typically about 18¾ inches, and the amount of space required umbilical line 352, which may be a single line or bundle of lines that are flexible enough for the movement of the tubular members 402 and 404. Accordingly, the outer diameter 422 is limited by the diameter of the BOP 110, which may be between about 11¾ inches and 18¾ inches. Similarly, the inner diameter 424 is limited by the size of the sealing device, such as the tubing hanger plug, tree cap plug or a packer, which is to be removed through the circulating tool 356. That is, the inner diameter is larger than the sealing device to provide for passage of the sealing device through the circulating tool. For instance, the sealing device may be a plug that is about 4.692 inches or 4.73 inches. Accordingly, the inner diameter 424 may be in a range between about 0 inches and about 4.7 inches, about 4.7 inches and about 10 inches, about 1.0 inches and about 10 inches or more preferably about 5.75 inches. The length of the embodiment 400 may be limited by the location of the sealing element in the BOP 110, the other tools in the circulating assembly 112, the location of the shear/seal ram 334 and the upper annular 330. For instance, if the upper annular 330 is the sealing element and shear/seal ram 334 are separated by about 215 inches, then the length of the embodiment 400 may be less than or equal to about 215 inches in the circulating position. As such, the length 420 is highly variable and based upon the distance separation of components of the BOP 110 and the other subassemblies in the circulating assembly 112. Finally, the stroke length 421 of the embodiment 400 may be limited to reduce wear on the seals 410-412 by limiting the movement of within the slot 414. For example, the stroke length 421 may be between 6 inches and 12 inches, or preferably about 9 inches.

As additional enhancements, the slot 414 may be a “J” slot and/or include both a straight slot and a “J” slot. A “J” slot may be utilized as a locking mechanism to fix the tubular members 402 and 404 into a specific configuration. For example, as shown in FIG. 4C, a partial view of the second tubular member 404 is shown. In this view, a straight slot 426 and a “J” slot 428 may be positioned on one end of the tubular member 404. These slots 426 and 428 may be indicated on the tubular member 404 by a specific marking, such as a “J” or a “I” to indicate the slot type. The length of the slots 426 and 428 may be a length 430 that is the stroke length 421 plus the width of the guide member 416. Beneficially, the use of the slots 426 and 428 provide flexibility in the operation of this embodiment 400 of the circulating tool 112. Further, in another embodiment, the slots 414 may be formed in the first tubular member 402, while the second tubular member 404 may include the guide member 416 to engage the slots 414. The guide members 416 may be a pin, screw, rod or other suitable component that engages with the slot 414.

FIGS. 5A-5B are exemplary embodiments of the circulating tool 356 having a circulating mechanism that is hydraulically actuated in accordance with embodiments of the present techniques. In these embodiments 500a and 500b of the circulating tool 356, which may be referred to as embodiments 500, the circulating tool includes a first tubular member 502 having one or more openings 506, an end cap 505 and threads 507 and 509. Also, the circulating tool includes a circulating mechanism, which is a sleeve or second tubular member 504 having one or more openings 508. It should be noted that these embodiments 500 may include components that are similar to the components described above in FIGS. 4A-4C. For instance, the tubular members 502 and 504, openings 506 and 508, threads 507 and 509 and seals 510-512 may be similar to the tubular members 402 and 404, openings 406 and 408, threads 407 and 409 and seals 410-412. However, in these embodiments 500, the openings 506 and 508 are adjusted by movement of the second tubular member 504 through the application of hydraulic pressure to align into a circulating position, as shown in FIG. 5B, and to misalign in an isolating position, as shown in FIG. 5A.

To provide the hydraulic actuation, the first tubular member 502 includes a recessed section 514 that is configured to receive a piston 516. The piston 516 may be a raised portion of the second tubular member 504 or a section of pipe welded to the second tubular member 504. Seals 520 and 521, which may be similar to the seals 510-512, may be utilized to form sealed chambers between the piston 516 and the tubular members 502 and 504. In one chamber, a return spring 524 may be positioned to bias the circulating mechanism into the isolating position, as shown in FIG. 5A. In a second chamber, a hydraulic conduit 526 may provide hydraulic fluid to the chamber for hydraulic actuation of the piston. The hydraulic conduit 526 is adapted to engage with piping or fluid flow lines, which may be part of an umbilical line. As the pressure increases in the second chamber, the piston 516 is moved a longitudinal distance 532 to compress the spring 524 and align the openings 506 and 508, as shown in FIG. 5B.

As noted above, the embodiments 500 may be adapted to operate with the subsea tree 104 and BOP 110. The factors to be adjusted may include the outer diameter 528 of the embodiment 500, the internal diameter 530 of the embodiment 500 and the length 518 of the embodiment 500. As noted above, the outer diameter 528, internal diameter 530 and length 518 may include the same ranges discussed above. However, in this embodiment 500, the length 518 is the same for the isolating position and the circulating position.

Further, it should be appreciated that the embodiments discussed above may be modified to perform the same functionality. For instance, the sleeve 504 in FIGS. 5A-5B may be modified to interact with wireline instead of relying on hydraulic lines. In addition, the sleeve 504 may also be modified to interact with an electric motor installed in the recessed chamber 514 that is coupled to electric lines in the control umbilical 352. As such, it should be appreciated that different embodiments of the circulating tool may be utilized to perform the present techniques.

Moreover, it should be appreciated that the other embodiments of the hydraulically actuated circulating tool may be utilized to further enhance the operation. For instance, the embodiment of the tool in FIGS. 5A and 5B is “pressure biased” with internal pressure. Assuming the hydraulic line is not in communication with the annulus (enclosed area), internal pressure may tend to act on the area between two seals on different diameters. In other words, the internal pressure may tend to shift the tool into different configurations or positions. In particular, if the fluid inside the circulating tool is heavier than the fluid used to activate the hydraulic system, adjustment of the circulating tool may be slow. Conversely, if heavy fluid is used for the hydraulic actuation, the circulating tool may tend to shift between certain positions. Accordingly, balance seals exposed to the tubing or annulus pressure may allow the hydraulic actuation to work solely against the spring. An example of this type of technology for use in a valve is described in DepthStar® Tubing-Retrievable Safety Valve by Halliburton.

In addition, it should be noted that guide member and slot may be include other embodiments. For instance, the slots may be grooves with the guide member being a raised portion of the circulating mechanism or second tubular member. Also, the circulating tool may include locking devices to hold torque from 0 ft lbs of torque to greater than 50,000 ft lbs of torque. The locking devices may include splines, wedges, screws, lugs, or keys that prevent rotation inside of the circulating tool other than the distance it takes to move between positions. These locking mechanisms may be part of the either of tubular member or both of the tubular members.

Also, it should be understood that the process to equalize fluid pressure between the interior of a circulating assembly and a location below a sealing device, which is described in the flow chart 200, may be modified in different embodiments. For instance, the adjustment of the circulating tool into the circulating position in block 210 may be performed prior to the forming of the isolated region in block 208. Also, the circulating of the fluid through the circulating tool in block 212 may follow the adjustment of the circulating tool in block 210, but be performed before the formation of the isolated region 208. Further, the providing of the fluid flow path between the circulating assembly 112 and the location below the sealing device in the subsea tree 104 in block 214 may be performed before blocks 210 and 212, but after the forming of the isolated region in block 208. Thus, the ordering of the different steps within the process described in the flow chart 200 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.

Claims

1. A pressure equalizing apparatus for use with an oil field tree comprising:

a first tubular member having a first end, a second end, at least one first tubular opening and a central opening within the first tubular member to provide a longitudinal fluid flow path between the first end and the second end;

a circulating mechanism coupled to the first tubular member and having a circulating position and an isolating position, wherein the circulating position provides at least one radial flow path between the central opening and a region external to the first tubular member through one or more of the at least one first tubular opening and the isolating position prevents fluid flow between the central opening and the region external to the first tubular member, and further wherein the inner diameter of the apparatus is adapted to pass a sealing device through the apparatus.

2. The apparatus of claim 1 wherein the first tubular member has a differential pressure rating up to about 15,000 pounds per square inch.

3. The apparatus of claim 1 wherein the apparatus has a torque rating of up to about 50,000 foot-pounds.

4. The apparatus of claim 1 wherein the inner diameter of the apparatus is in a range between about 4.7 inches and about 10 inches.

5. The apparatus of claim 1 wherein the outer diameter of the apparatus is in a range between about 11¾ inches and 18¾ inches.

6. The apparatus of claim 1 wherein the length of the apparatus is less than or equal to about 215 inches in the circulating position.

7. The apparatus of claim 1 wherein the first tubular member comprises at least one slot and the circulating mechanism comprises at least one guide member at least partially disposed within the at least one slot, wherein the at least one guide member is configured to provide the at least one radial flow path in the circulating position and prevent fluid flow in the isolating position.

8. The apparatus of claim 7 wherein the at least one slot comprises a straight slot and a “J” slot.

9. The apparatus of claim 1 wherein the first tubular member comprises at least one slot and the circulating mechanism comprises a guide member at least partially disposed within the at least one slot, wherein the guide member is configured to move between the circulating position and the isolating position.

10. The apparatus of claim 1 wherein the circulating mechanism is mechanically actuated.

11. The apparatus of claim 1 wherein the circulating mechanism comprises:

a second tubular member at least disposed partially within the first tubular member, the second tubular member having at least one second tubular opening and a plurality of threads at one end of the second tubular member opposite the end of the second tubular member at least disposed partially within the first tubular member; and

a plurality of seals disposed between the first tubular member and the second tubular member to isolate fluid flow through the at least one first tubular opening and the at least one second tubular opening in the isolating position.

12. The apparatus of claim 11 wherein the first tubular member comprises at least one slot and the circulating mechanism comprises a guide member that engages the at least one slot, wherein the guide member is configured to align the at least one first tubular opening and the at least one second tubular opening to provide the at least one radial flow path in the circulating position and misalign the at least one first tubular opening and at least one second tubular opening in the isolating position.

13. The apparatus of claim 1 wherein the circulating mechanism comprises:

a second tubular member disposed partially around the first tubular member, the second tubular member having at least one second tubular opening and a plurality of threads at one end of the second tubular member opposite the end of the second tubular member disposed partially around the first tubular member; and

a plurality of seals disposed between the first tubular member and the second tubular member to isolate fluid flow through the at least one first tubular opening and at least one second tubular opening in the isolating position.

14. The apparatus of claim 1 wherein the circulating mechanism is hydraulically actuated.

15. The apparatus of claim 1 wherein the circulating mechanism comprises:

a second tubular member disposed adjacent to the first tubular member and having at least one second tubular opening;

a plurality of isolation seals disposed between the first tubular member and the second tubular member to isolate fluid flow through the at least one first tubular opening and the at least one second tubular opening in the isolating position;

a piston disposed between the first tubular member and the second tubular member; wherein the piston is hydraulically actuated to move from the isolating position to align the at least one first tubular opening and the at least one second tubular opening to provide the at least one radial flow path in the circulating position.

16. The apparatus of claim 1 wherein the circulating mechanism is electrically actuated.

17. The apparatus of claim 1 wherein the circulating mechanism is magnetically actuated.

18. The apparatus of claim 1 wherein one of splines, wedges and screws prevent rotation of the first tubular member with respect to the circulating mechanism beyond the circulating position and the isolating position and the first tubular member and the circulating mechanism are not rotationally fixed with respect to each other.