GB2458982A

GB2458982A - Subsea flowhead

Info

Publication number: GB2458982A
Application number: GB0723075A
Authority: GB
Inventors: Neil Sutherland Duncan
Original assignee: SUBSEA ENGINEERING SERVICES Ltd
Current assignee: SUBSEA ENGINEERING SERVICES Ltd
Priority date: 2007-11-23
Filing date: 2007-11-23
Publication date: 2009-10-14
Also published as: GB0723075D0

Abstract

A subsea flowhead system which overcomes the disadvantages of separately deploying a tubing hanger and a production tree during well completions. The system comprises an adaptor having a main body 1 which is connected to a subsea wellhead (3, figure 2) or casing hanger (4, figure 2) with connector 2 and seal 9. Connection device 5 provides communication to a subsea flowline and an opening through which fluids may flow into or out of the adaptor from the subsea flowline. The system is deployed via handling and running connection 7. Extension 11 provides a conduit 12 for fluids to pass to and from the well via flowline 6 and seals directly and internally to the wellhead casing string (14, figure 2) by means of seals 10 or lockdown mechanism (18, figure 3) such as a packer. Barriers such as valves or plugs (19, Figure 4) may also be incorporated to control flow through the system.

Description

I

This invention relates to a Subsea Flowhead system that can be deployed onto a subsea welihead in lieu of a Xmas Tree and Tubing Hanger system.

The traditional means of completing subsea production or injection wells is by means of a Tubing Hanger (TH) and Xmas Tree (XT). The TH and XT would normally be deployed as separate units. Both these units are usually deployed from a Mobile Offshore Drilling Unit (MODU) and both are time consuming and expensive to install.

The XI and TH equipment requires a significant number of support tools to install the system. The cost and lead times for the XT and supporting tooling can be significant.

A typical subsea XT will weigh around 40 Tonnes and have a footprint of 4m x 4m. The XT will typically have a multitude of susbsea valves controlled via a XT mounted Subsea Control Module (SCM). Often a separate Flow Support Base (FSB) typically weighing around 15 lonnes or more will be required to be landed on the welihead to allow the flowlines to be connected ahead of deploying the XT.

Both Conventional and Horizontal Xmas Tree Systems are typically used. Conventional systems require the TH to be landed into the wellhead prior to deploying the XT and Horizontal systems require the TH to be deployed first followed by the XT. Both XT systems are expensive and cumbersome and require the use of a MODU for deployment.

A traditional tubing hanger system is deployed through the BOP and marine riser. The tubing hanger suspends the tubing string and isolates the well from the production casing by sealing to the productionlinjection casing hanger. A packer is nonnally deployed at the bottom of the productionlinjection tubing string to isolate the production/injection casing just above the reservoir.

A Surface Controlled Sub Surface Safety Valve (SCSSV) iusually included in the production/injection tubing string to isolate the bore of the production/injection tubing.

This valve is normally a Fail Safe Close (FSC) device that. closes automatically in the event of loss of system control pressure.

The tubing hanger (TH) would usually incorporate a nipple profile or profiles to accept a wireline plug or plugs. This allows a plug or plugs to be deployed on wireline and set in the TH to provide a second barrier to the production/injection string prior to recovery of the Blow Out Preventer (BOP) stack.

A Tree Cap (TC) is also required and this is deployed on top of the XT to provide a secondary barrier and protection for the XT.

Intervention equipment such as a Lower Riser Package (LRP) and Emergency Disconnect Package (EDP) are traditionally required to be landed on the XI during well intervention. This equipment is expensive to purchase and maintain and again requires the use of a MODU for deployment.

Injection wells are traditionally completed and intervened using the same equipment and barrier philosophy as production wells. Injection wells inject produced water or gas and re-inject into the wellhead and can be used to boost reservoir recovery of the production wells.

Some reservoirs have such low pressures that they are unable to flow naturally to the environment and it has been traditional to utilise a XT and TH package on these wells.

In such instances where the reservoir pressure cannot flow to the environment then a traditional TH and XI and barrier system may not be required. In such applications it should be possible to utilise much simpler and cost effective equipment that can be deployed if required from a vessel of opportunity thereby dispensing with the need for a MODU.

The following invention describes a system that could be used in lieu of the more traditional Xmas Tree and Tubing Hanger systcms as described above. This system should minimise the hardware requirements the installation time and hence significantly reduce costs. The invention described here offers the following advantages over a traditional XT and TH system usually employed: Advantages of the Sub sea Flowhead Arrangement 1, Minimum amount of subsea hardware required.

2. Does not require a Workover Controls System (WOCS) or riser.

3. Does not require wireline operations.

4. Does not require a MODU to deploy it.

5. Dispenses with the requirement for a tubing hanger.

6. Dispenses with a requirement for a Xmas Tree.

7. Dispenses with the need for a separate protection strUcture.

8. Can be moonpool or vessel deployed with a compact integral protection structure.

9. Is non orienting to the subsea welihead and mating equipment.

10. Can accommodate a large diameter flow bore.

An example of the invention will now be described solely by way of example and with reference to the accompanying drawings in which: Figure 1 shows the Subsea Flowhead concept.

Figure 2 shows the Subsea Flowhead landed on the Wellhead and connected to the flow pipework.

Figure 3 shows an embellishment of the Subsea Flowhead to incorporate a locking and sealing device to allow the Flowhead to lock and seal direct to the casing string at a suitable point below the casing hanger.

Figure 4 shows another embellishment of the Subsea Flowhead to incorporate barriers such as, but not necessarily limited to, valves or wirelirie plugs, either above or below or above and below the injection inlet and a suitable interface for a subsea wireline lubricator or coil tubing BOP.

Figure 5 shows a further embellishment of the Subsea Flowhead that allows the Flowhead to be connected to a tubing string at surface and deployed subsea as a unitised assembly.

Figure 6 that shows yet a further embellishment of the system that allows the Subsea Flowhead to connect to a previously deployed tubing string.

Figures 1 and 2 show the concept of the Subsea Flowhëad.

The main body 1 provides the pressure containing housing. A connector 2 provides a means of locking the Sub sea Flowhead 1 to the subsea Wellhead 3 or Casing Hanger 4.

The connector 2 may be integral to the Flowspool body 1 or a separately attached member and either lock internally or externally to the Wellhead 3 or Casing Hanger 4. A flowline connection device 5 is connected to the Flowhead 1 and provides a profile to allow the Flowhead 1 to be connected to the mating flowline 6. The flowline connection device 5 could be a Flange or Connector or other such connecting device.

A handling and running device 7 is connected to the body 1 and provides a suitable profile for the attachment of a nmning tool 8 that could either be integral or separately connected to the body 1. A method of deploying such as, but not necsarily limited to, drill pipe, riser, tubing, lift wire, or other such suitable device could be used.

The body 1 incorporates a seal 9 that seals to the wellhead 3. A further seal 10 provides a method of sealing to the welihead 3 or casing hanger 4 or the casing string 14. When sealing to the casing string 14 a suitable sealing device such as, but not necessarily limited to, a packer could be used to provide a seal and a method of connecting or locking the Flowhead 1 to the casing string 14.

A body extension 11 provides a conduit 12 for fluids to pass to and from the well from via the flowline 6. The body extension 11 could either be integral to the body 1 or separately connected. An optional diffuser and wireline guide mechanism 13 provides a controlled flow transition into the well.

A conduit 15 and valve 16 provides a means of accessing the whd seal area in order to perform a test of the seals 9 and 10.

Figure 2 shows the Flowhead 1, connected to the welihead 3. A compact protective structure 17 is shown attached to the Flowhead 1. The protective structure 17 could either be connected to the Flowhead 1 prior to subsea deployment or be connected following deployment of the Flowhead 1 onto the wellhead 3.

Figure 3 shows an embellishment of the Subsea Flowhead I to allow it to seal and lock directly to the welihead casing string 14. A suitable sealing and lockdown mechanism 18 such as, but not necessarily limited to, a packer is attached to the Flowhead extension 11.

The sealing and lock mechanism 18 could be used in lieu of or in addition to the welihead or casing hanger connector 2.

Figure 4 shows a further embellishment of the Subsea Flowhead 1 to incorporate one or more well barriers 19 such as, but not necessarily limited to, valves or wireline plugs, positioned either above or below or above and below the Subsea Flowhead inlet 20. This arrangement would also incorporate a suitable interface 21 for a device such as a wireline lubricator or coil tubing BOP.

Figures 5a and Sb shows yet a further embellishment of the Subsea Flowhead 1 to allow it to connect to a tubing string 22 prior to deployment sübsea.

Figure 5a shows the Flowhead 1 connected to the tubing string 22 using a suitable connecting device 23. A sealing and lockdown device such as, but not necessarily limited to, a packer 18 is shown attached to the tubing string 22 to provide a sealing and lockdown device for the Subsea Flowhead 1 direct to the casing string 14. The packer 18 could be used in lieu of the Subsea Flowhead connector 2 or in addition to the Subsea Flowhead connector 2. The packer 18 could be positioned anywhere along the casing string 14.

The Flowhead 1 would be connected to the tubing string 22 at the surface and the assembly deployed through the rotary table or moonpool of the MODU.

Figure 5b shows the Flowhcad I and tubing 22 landed on the subsea weiihead 3 and the packer element 18 coimected and sealing to the casing string 14.

Figure 6 shows yet a further embellishment of the Subsea Flowhead I to allow it to land and seal to a previously deployed Flowhead Tubing string 24. A tubing nubbing 25 attached to the top of the tubing string 24 provides a load shoulder 26 to allow the tubing string 24 to be supported in the welihead 3 or casing hanger 4. At the lower rend of the tubing string 24 a packer element 18 provides a means of locking and sealing the tubing string to the casing string 14.

The Subsea Flowhead would then be deployed on a suitable tool 8 engaging the Flowhead seals 28 into the nubbing seal profile 27. The Subsea Flowhead I would then land on the wellhead 3 and be locked to the welihead 3 by the connector 2.

Claims

CLAIMS1. A Subsea Flowhead that can be used in lieu of a subsea Xmas Tree and Tubing Hanger.
2. A Subsea Flowhead in 1) that locks and seals to a subsea welihead, casing hanger or casing string and provides a conduit for fluids to and from the subsea well.
3. A Susb sea Flowhead in 1) that can incorporate either none or one or more flowpath isolation devices.
4. A Subsea Flowhead in 1) that can be deployed with or without an integral protection structure.
5. A Subsea Flowhead in 1) that can incorporate a means of providing wireline access to the well by means of a suitable adapter.
6. A Subsea Flowhead in 1) that can be connected to a tubing string at surface and deployed subsea as a unitised arrangement.
7. A Subsea Flowhead in 1) that can be deployed onto and seal to a previously deployed tubing string.
8. A Subsea Flowhead in 1) that incorporates a sealing and lockdown element directly to the productionlinjection casing string.
9. A Subsea Flowhead in 1) that can accommodate a sdàling and or locking device to the welihead or casing hanger or both wellhead and casing hanger.Amended daims have been filed as foUows:-CLAIMSI An apparatus for injecting fluids into a subsea well comprising an adaptor which is releasably couplable to a subsea wellhead, the adaptor having: i) a first end comprising first coupling means for releasably coupling the adaptor to a subsea fiowline and an opening through which the injected fluids can flow into the adaptor from the subsea flowline, ii) a second end comprising a second coupling means for releasably coupling the adaptor to a running tool, iii) a coupling means for releasably coupling the adaptor to a subsea wellhead, and iv) a third end comprising a conduit extending into the wellhead, the third end conduit being in fluid communication with the opening of the first end.2. An apparatus as claimed in claim 1, wherein the third end incorporates a means of sealing to the inside of a casing hanger for the purpose of isolating the casing hanger from the injected fluids passing through the third end of the adaptor.3. An apparatus as claimed in claim 1, wherein the third end optionally incorporates a means of sealing to the inside of a casing string for the purpose of isoiating the 0 0 casing from the injected fluids passing through the third end of the adaptor. 0 4. An apparatus as claimed in claim 1, wherein the second end is adapted to provide a means of reieasably coupling the adaptor to a riser. p 5. An apparatus as claimed in claim 1 wherein the third end fluid conduit extends vertically through the adaptor body from the third end opening to the second end opening, the third end conduit also being in fluid communication with the first end opening.6. An apparatus as claimed in claim 5 wherein the vertical conduit incorporates a fluid isolation device positioned in the vertical bore below the intersection of the first end opening with the third end opening thereby preventing flow of fluid from the first end opening to the third end opening.7. An apparatus as claimed in claim 5 wherein the vertical conduit incorporates a fluid isolation device positioned in the vertical bore above the intersection of the first end opening with the third end opening thereby preventing flow of fluid from the first end opening to the second end opening.8. An apparatus as claimed in claim 5 wherein the vertical conduit incorporates two or more fluid isolation devices positioned in the vertical bore, the vertical bore having: i) at least one such isolation device positioned above the fluid intersection of the first end with the vertical bore thereby preventing fluid flow from the first end opening to the second end opening, and ii) at least one such isolation device positioned below the fluid intersection of the first end with the vertical bore thereby preventing fluid flow from the first end opening to the third end opening.9. An apparatus as claimed in claim 1 wherein the third end has a releasably coupling means of connecting the third end to a completion tubing string such that the apparatus can be connected to the tubing string prior to subsea deployment of the apparatus and the tubing string. * .* ** * * .* * *** * * * *I* * * * *** *SS. **SSS S. S * * S S 55