1. Field of the Invention
The present invention relates to a subsea wellhead assembly for an oil and gas well, and more particularly relates to a universal tubing hanger suspension assembly for use in a subsea wellhead assembly.
2. Description of the Related Art
A typical subsea wellhead assembly includes a wellhead housing installed at the sea floor. With a drilling blowout preventer (BOP) stack installed on the wellhead housing, the well bore is drilled while successively installing concentric casing strings in the well bore. Typically, each successive casing string is cemented at its lower end and includes a casing hanger sealed with a mechanical seal assembly at its upper end in the wellhead housing.
In order to produce the cased well, a production tubing string and tubing hanger is typically run into the well bore through the BOP stack and the tubing hanger is landed, sealed and locked in the wellhead housing and/or the casing hanger. Upon sealing the bore(s) extending through the tubing hanger, the BOP stack is removed and a Christmas tree is lowered onto the wellhead housing. A Christmas tree is an oilfield term understood to include the control valves and chokes assembled at the top of a well to control the flow of oil and gas. It is vitally important to the operation and safety of the well that the proper connections are remotely formed between the Christmas tree, the wellhead housing, and the tubing hanger.
In a conventional completed well system, the Christmas tree is connected to the top of the wellhead housing over the tubing hanger. The tubing hanger supports at least one production tubing string which extends into the well bore. The tubing hanger provides a production bore within the tubing string and a conduit that communicates with the annulus surrounding the tubing string and inside the innermost or production casing string. In addition, the tubing hanger comprises at least one vertical production bore for communicating fluid between the tubing string and a corresponding production bore in the Christmas tree, and typically at least one vertical annulus bore for communicating fluid between the tubing annulus and a corresponding annulus bore in the Christmas tree. The tubing hanger may additionally include one or more service and control conduits for communicating control fluids and well chemicals through the tubing hanger or electrical power to devices or positions located in or below the tubing hanger.
A tubing hanger conventionally is sealed and rigidly locked into the wellhead housing or component in which it is landed. In a well having a conventional Christmas tree, the tubing hanger is landed in the wellhead housing. The tubing hanger typically includes an integral locking mechanism which, when activated, secures the tubing hanger to the wellhead housing or a profile in the casing hanger. The locking mechanism ensures that any subsequent pressure from within the well acting on the tubing hanger will not cause the tubing hanger to lift from the wellhead housing thereby resulting in an unsafe condition.
There are a limited number of subsea wellhead equipment manufacturers worldwide. Currently, the primary manufacturers of subsea wellhead housings are ABB Vetco Gray, Cooper Cameron Corp., Dril-Quip, FMC and Kvaerner. Each of the primary manufacturers has its own proprietary wellhead housing and casing hanger designs, dimensions and details. Quite frequently, a well is completed on Manufacturer A's wellhead housing and casing hangers using a tubing hanger and/or Christmas tree from Manufacturer B. However, since Manufacturer A's housing and casing hanger design is proprietary, Manufacturer B may not be able to connect its Christmas tree to Manufacturer A's housing without a license from Manufacturer A at a fee in order to design Manufacturer B's equipment to properly interconnect and mate with Manufacturer A's wellhead housing and casing hanger. This results in a substantial amount of additional engineering and costs or additional equipment (such as a tubing spool) when electing to purchase Manufacturer B's equipment for use with Manufacturer A's wellhead housing. Since each wellhead housing/system manufacturer has multiple models of housings and casing hangers with different proprietary details, it is not practical or economical for other manufacturers to build up an inventory of equipment for installation on other manufacturers' wellhead equipment. In addition to the added costs, it also increases the delivery time which is often vitally important to the well owner.
It is desirable to have a subsea well completion system that is adapted for use with wellhead housings from all manufacturers. It is further desirable to have a tubing hanger assembly adapted for positioning in the wellhead housing independently of any proprietary details of the wellhead housing. It is further desirable to have a universal tubing hanger assembly that is adapted for use in a plurality of wellhead housings, and even more desirable to have a universal tubing hanger assembly adapted for use in wellhead housings of two or more manufacturers.
The present invention includes a tubing hanger suspension assembly for an oil and gas well completion system and a method of installing same. The tubing hanger suspension assembly includes a tubing hanger housing which is positioned in the wellhead housing. The tubing hanger assembly includes a sealing and lockdown mechanism capable of providing sealing and load support of the production tubing in the production casing string. A stab sub assembly connected to the upper end of the tubing hanger suspension assembly and lower end of the Christmas tree assembly provides downhole hydraulic and electric functionality and annulus access to the production tubing.
The well completion system of the present invention is adapted for use with wellhead housings from all manufacturers. The tubing hanger suspension assembly of a preferred embodiment includes a tubing hanger housing positioned in the wellhead housing independently of any proprietary details of the wellhead housing. The preferred embodiment of the tubing hanger suspension assembly is “universal”, i.e., adapted for use in a plurality of wellhead housings, including wellhead housings of two or more manufacturers.
The objects, advantages, and features of the invention will become more apparent by reference to the drawings which are appended hereto and wherein like numerals indicate like parts and wherein an illustrated embodiment of the invention is shown, in which:
An embodiment of the invention is described in detail with specific reference to the drawings. This invention concerns completion of a well that has been drilled and which has its bore hole lined with casing. Referring to
Still referring to
Although not shown, the wellhead housing 14 typically includes several internal profiles, dimensions and details for landing, locking and sealing the stacked casing hangers 16a, 18a in the wellhead housing 14. Each wellhead manufacturer has several wellhead housings with corresponding casing hangers for each wellhead housing. As a result, the casing hangers 16a, 18a installed in the wellhead housing 14 are typically manufactured by the same company since each manufacturer's wellheads and casing hangers are different from any other manufacturer.
Following the setting of the casing as shown in
Referring still to
Although not necessary, it may be desirable to determine the distance between the top end 18c of the production casing hanger 18a and the upper face 14a of the wellhead housing 14. The depth of the top end 18c is typically determined from the known depth (dimensions) of the BOP stack 20. A typical wellhead housing 14 has approximately 24″ to 36″ between the housing upper face 14a and the top end 18c of the production casing hanger 18a.
Preferably, the length D between the top of one of the plurality of BOP rams 20r, for example ram 20r′ in
A universal tubing hanger suspension assembly 10 according to a preferred embodiment of the present invention is shown in
The tubing hanger housing 24 also preferably includes an annulus passageway 24b extending through the tubing housing hanger 24. In the preferred embodiment, an annulus isolation valve 28 is included in the tubing hanger housing 24. The annulus isolation valve 28 is arranged and designed to seal and close off the annulus passageway 24b.
Referring to
Since the length of the tubing string 22 is dependent on the depth of the production zone Z, the length of the lower assembly 32 relative to the tubing string 22 varies from well to well. Preferably, the lower assembly 32 has a length in the range of 1′ to 1,500′, more preferably in the range of 1′ to 300′, and most preferably in the range of 5′ to 100′.
Preferably, the sealing and lockdown assembly 34 is carried by the tubing hanger lower member 32. Preferably, the sealing/lockdown assembly 34 is located near the lower end of the tubing hanger lower member 32. An enlarged view of the sealing/lockdown assembly 32 is shown in
In the preferred embodiment, the lockdown apparatus 40 includes elements or slips, which may be metallic or non-metallic, adapted to engage the interior of the production casing 18. When engaged, the lockdown apparatus 40 engages the interior of the casing 18 and “fixes” or prevents vertical movement of the tubing hanger suspension assembly 10 relative to the production casing 18.
The sealing apparatus 38 includes a sealing element, which may be made of elastomerics or other materials (including composites) or a metal seal, adapted to form an annular seal between the production casing 18 and the tubular portion 36, as for example, by compression. The sealing apparatus 38 and the lockdown apparatus 40 may be independently activated or jointly activated. Preferably, the activation and de-activation of the lockdown apparatus 40 and the sealing apparatus 38 is hydraulically controlled through ports 42a and 42b as will be explained below. The activation and de-activation may also be electronically, mechanically, or electrically activated or de-activated.
As shown in
Referring again to
Referring to
Referring to
Referring to
With reference again to
The sealing and lockdown assembly 34 is activated, preferably hydraulically, via the hydraulic control lines to force the lockdown apparatus 40 into tight locked engagement with the production casing 18. Preferably, the engaged lockdown apparatus 40 prevents or substantially prevents relative vertical movement between the lower tubular member 32 and the production casing 18. Upon activation of the sealing apparatus 38, the sealing apparatus 38 forms a fluid- or gas-tight seal between the lower tubular member 32 and the production casing 18. The sealing and lockdown assembly 34 may comprise a set of slips having metal elements which grip the production casing 18. An elastomeric or other seal is preferably compressed by the set slips to form the fluid-tight seal. Preferably, the sealing and lockdown assembly 34 is a modified packer assembly of the type conventionally used in wells to isolate production zones, etc. Such representative packer assembly technology is generally described in U.S. Pat. Nos. 6,769,491; 5,988,276; 5,271,468; and 4,296,806, and commercially available from companies such as Halliburton Company, Baker Hughes Inc. and Weatherford/Lamb, Inc. Applicant incorporates by reference herein U.S. Pat. Nos. 6,769,491; 5,988,276; 5,271,468; and 4,296,806 in their entirety.
In this preferred embodiment of the present invention, the sealing and lockdown assembly 34 engaged with the production casing 18 provides the sealing and load support of the universal tubing hanger suspension assembly 10 in the well. The sealing and lockdown assembly 34 provides vertical load support to support the universal tubing hanger assembly 10 and to resist upward forces that may be exerted against the assembly 10. This sealing, locking and suspension of the tubing hanger assembly 10 is accomplished and installed independently of any critical and proprietary dimensions in the wellhead housing 14 and/or casing hangers 16a, 18a. Furthermore, in this preferred embodiment the tubing hanger housing 24 is not required to, and preferably does not, lock or seal with either the wellhead housing 14 or the casing hangers 16a, 18a.
With the sealing and lockdown assembly 34 activated and set, the seal may be pressure tested from above or below the sealing and lockdown assembly 34. The seal can be pressure tested from above by closing the annulus isolation valve 28 in the tubing hanger housing 24 and with the rams 20r′ sealed around the upper mandrel 46, pumping a fluid from the surface through the kill line 20k, down past open ram 20r″, around the outside of the tubing hanger running tool 30 within the BOP bore 20b, in the annular area between the wellhead housing 14 and the tubing hanger housing 24, and the annular area between the production casing 18 and the lower member 32.
Preferably, after the sealing and lockdown assembly 34 has been successfully tested, the lower packer 52 is set to seal off the production tubing annulus 22b proximal to the bottom of the production tubing string 22. The lower packer 52 can be tested from below by opening the annulus isolation valve 28 and closing the BOP rams 20r′ and lower rams 20r″ around the tubing hanger running tool 30. To pressure test, pressure is built up by pumping fluid down the installation tubing string bore 50a, the tubing hanger running tool production bore 30a, the tubing hanger production bore 24a and the production tubing bore 22a to beneath the packer 52. If, during the test, the packer 52 leaks fluid, pressure and fluid is taken up through the tubing annulus 22b, annulus valve 28 and annulus passageway 24b, between rams 20r′ and 20r″, and up the kill line 20k.
With reference to
After setting and testing the sealing and lockdown assembly 34, the lower packer 52 and the closure member 54, and with the subsurface safety valve 26 and the annulus isolation valve 28 closed, the tubing hanger running tool 30 is disconnected from the tubing hanger housing 24 and retrieved to the surface. The BOP stack 20 is then removed from the wellhead housing 14.
Next, a tree assembly 60 is lowered from the upper surface of the water via a pipe string 50, preferably a drill string, and a tree running tool 56 as shown in
The preferred tree assembly 60 shown in
In the preferred embodiment, the widths (measured along the longitudinal axis of the stab sub 74) of the peripheral grooves or galleries are larger than the respective diameters of the bores 74b, 74c and 74d to allow communication between the respective passageways over a range of vertical spacing variations between the tubing hanger housing 24 and the tree assembly 60. For example, the vertical elevation of the tubing hanger housing 24 relative to the wellhead housing upper face 14a is predetermined and set via the running tool upper mandrel 46 and adjust nut 48 as described above. The tree assembly 60 is installed on the wellhead housing 14. The stab sub 74 provides the fluids and controls linkage between the tubing hanger housing 24 and the tree assembly 60. Since the stab sub 74 is preferably joined to the tree assembly 60 prior to lowering the assembly, it is important that all of the fluids/controls connections between the tubing hanger housing 24 and the stab sub 74 automatically mate when the tree assembly 60 is secured to the wellhead housing 14. The enlarged widths of the peripheral grooves or galleries described above permits the desired mating over a range of distances between the tree assembly 60 and the tubing hanger housing 24. Preferably, the galleries allow the stab sub 74 to properly mate and communicate over a vertical distance range of approximately 1″ to 3″.
The galleries, as described above with respect to the preferred embodiment, allow the tree assembly 60, the stab sub 72 and the tubing hanger housing 24 to communicate and mate with each other independently of the angular orientation of the separate components. This is referred to as being “non-oriented” which simplifies the running and installation of the subsea components. It is to be understood that the invention may also be used with oriented subsea components.
With the tree assembly 60 secured and tested, the closure member 54 is retrieved to the surface through the bores of the production tubing 22, tubing hanger 24, stab sub assembly 74, Christmas tree assembly 60, tree running tool 56 and the installation tubing string 50.
Based upon the foregoing description of the present invention, a “universal” set of subsea well components is achievable. For example, a common size of wellhead housing 14 has an inside diameter (ID) of 18.625″ or 18.75″, depending on the manufacturer. The casing hangers installed in these wellhead housings 14 are typically 24″ to 36″ below the upper face of the wellhead housing. Thus, the tubing hanger housing 24 of the universal tubing hanger suspension assembly 10 can occupy a round cylindrical space of approximately 18.5″ in diameter and 24″ in height at the upper portion of the wellhead housing 14. Since the preferred tubing hanger housing 24 does not include a releasable locking mechanism for locking to the upper portion of the wellhead housing 14 (typical of conventional tubing hangers), the 18.5″ diameter is substantially fully usable by the tubing hanger housing 24. This is a substantial benefit of the present invention because the “usable space” for the various bores and passageways required to pass through the tubing hanger housing is substantially greater than in conventional tubing hangers.
Preferably, the length of the stab sub assembly 74 is the same regardless of the type of wellhead housing 14 and casing hangers 16a, 18a on which the tree assembly 60 is being installed. This is accomplished due to using the space out dimension D to substantially uniformly position the tubing hanger 24 relative to the top of the wellhead housing 14 regardless of the wellhead housing type. This provides simplicity in design from wellhead to wellhead and allows for a “universal” stab sub assembly 74 used with the preferred tree assembly 60. Certainly, separate stab sub assemblies are required for different size production tubing.
Thus, it is to be understood that the universal tubing hanger suspension assembly 10, the stab sub 74 and the tree assembly 60 are capable of installation on various wellhead housings 14, and are, to a great degree, “universal” and “off the shelf” items, eliminating significant engineering and fabrication costs incurred when installing Manufacturer A's tree assembly on Manufacturer B's wellhead housing. The present invention also eliminates the use of a tubing spool (wellhead connector and crossover wellhead housing) mounted to Manufacturer B's wellhead housing for carrying Manufacturer A's tubing hanger.
In the preferred embodiment of the present invention, the universal tubing hanger suspension assembly 10, the stab sub assembly 74 and the tree assembly 60 do not require angular orientation which significantly simplifies the installation procedure. However, it is to be understood that the present invention is not limited to non-orientation and may also be used with components requiring orientation with respect to each other. Techniques for orienting a tree assembly to a tubing hanger are well known in the art. One type of suitable orientation technique is disclosed in U.S. Pat. No. 5,544,707 and is hereby incorporated by reference. Another orientation technique is to modify the BOP stack 20 with a pin to orient the components as they pass through the BOP stack 20. Orientation of the components adds costs and complexity to the subsea installation process.
The present invention includes a tubing hanger suspension assembly 10 for an oil and gas well and a method of installing same. The tubing hanger suspension assembly 10 includes a tubing hanger housing 24 which is positioned in the wellhead housing 14. The tubing hanger assembly 10 includes a sealing and lockdown mechanism 34 capable of providing sealing and load support of the production tubing 22 in the production casing string 18. A stab sub assembly 74 connected to the upper end of the tubing hanger suspension assembly 10 and lower end of the Christmas tree assembly 60 provides downhole hydraulic and electric functionality and annulus access to the production tubing 22.
Using the BOP stack 20 for space out and placement of the tubing hanger suspension assembly 10 negates the need for exact dimensions of the wellhead housing 14 for space out and also negates the need for any internal stack up dimensions to interface the subsea tree assembly 60 to the stab sub assembly 74. Preferably, space out of the tubing hanger assembly 10 is accomplished through an adjustable space out nut 48 at the top of the upper mandrel 46 of the running tool 30 in the BOP stack 20. Alternatively, the space out predetermined elevation of the tubing hanger assembly 10 can be accomplished using a ring stop apparatus 80, preferably adjustable, landing in the production casing hanger 18. Using tubing packer technology for fixing the lower member elevation at a predetermined elevation through the BOP stack 20 rather than the wellhead housing 14 allows subsea tree interface in any industry wellhead system. The device or devices used in the system negates the use of the BOP stack 20 or the wellhead for orientation as well.
The apparatus and methods described above are advantageous because they are suitable for use in wellhead housings 14 independent of proprietary details pertaining to the housing. The tubing hanger suspension assembly 10 of the preferred embodiment of the present invention eliminates the need to use wellhead housing or casing hanger landing shoulders for locking and sealing the tubing hanger housing 24 in position. The tubing hanger suspension assembly 10 of the preferred embodiment of the present invention eliminates the need to seal the tubing hanger housing 24 to the wellhead housing 14. The preferred embodiment eliminates these requirements by sealing, anchoring and locking the sealing and lockdown assembly 34 in the production casing 18 suspended by the casing hanger 18a in the wellhead housing or system.
The present invention provides simplicity and reduced costs in completing a subsea well. The tubing hanger housing 24 is preferably not locked to, sealed with, or supported by the wellhead housing 14. Thus, the wellhead housing 14 no longer needs the details, profiles, etc. related specifically to the tubing hanger housing 24. Furthermore, no internal profiles, etc. are required in the production casing string 18 for cooperating with the sealing and lockdown assembly 34. This provides flexibility to install the tubing hanger housing 24 at the desired elevation for ensuring the proper spacing to be bridged by the stab sub assembly 74 as it is lowered with the tree assembly 60. Even the final elevation of the sealing and lockdown assembly 34 in the casing string 18 can be varied over a substantial distance by changing the length of the lower member 32. It is also to be understood that depending on various well related factors, the present invention could employ a plurality of sealing and lockdown assemblies 34 if deemed desirable.
It is also to be understood that the present invention provides a substantial amount of additional cross sectional area available for use in the tubing hanger housing 24 which is a tremendous benefit. The tubing hanger housing 24 may have a diameter that approaches the inside diameter of the wellhead housing 14. The additional area allows ample space for an increased production bore or multiple production bores, annulus and various other ports and controls, etc. that are required or desired in a tubing hanger housing.
A description of some of the benefits derived from the preferred embodiment of the tubing hanger suspension assembly of the present invention follow:
For the customer/user, the wellhead becomes invisible to the completion. This provides savings to the user in two ways: engineering and hardware interfacing. Engineering is reduced in determining tubing hanger interfaces such as stack up tolerances and dimensions and compatibility issues. Currently, this includes issues in subsea and surface completions.
It is to be understood that the present invention, including the universal tubing hanger suspension assembly 10, is not limited to the preferred embodiments described herein. The universal tubing hanger suspension assembly 10 is not limited to the tubing hanger housing being received in the wellhead housing. Rather, the universal tubing hanger suspension assembly 10 can also be used in wells in which the tubing hanger is received in tubing spools or horizontal trees mounted on the wellhead housing. It is to be understood that the sealing apparatus 38, and optionally the lockdown apparatus 40, would still be positioned in the casing string 18.
Preferred embodiments of the tubing hanger suspension assembly, well completion system and method of installing same according to the present invention have thus been set forth. However, the invention should not be unduly limited to the foregoing, which has been set forth for illustrative purposes only. Various modifications and alterations of the invention will be apparent to those skilled in the art, without departing from the true scope of the invention.
This application is a continuation of U.S. application Ser. No. 11/216,227, filed Aug. 31, 2005, now U.S. Pat. No. 7,419,001, which claims priority to U.S. Provisional Application Ser. No. 60/682,250, filed May 18, 2005, which is hereby incorporated by reference in its entirety.
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Number | Date | Country | |
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20080156478 A1 | Jul 2008 | US |
Number | Date | Country | |
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60682250 | May 2005 | US |
Number | Date | Country | |
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Parent | 11216227 | Aug 2005 | US |
Child | 12049093 | US |