NO343789B1 - Device for enabling removal or installation of a horizontal Christmas tree and methods thereof - Google Patents

Description

FIELD OF THE INVENTION

The present invention relates to a device for enabling removal of a horizontal Christmas tree from a wellhead, or for enabling installation of a horizontal Christmas tree on a wellhead.

The present invention also relates to a method for performing a well operation in a hydrocarbon well with a horizontal Christmas tree.

In particular, the present inventions are related to the possible use of a monohull vessel instead of a drilling rig, a drill ship or a jack-up rig during the well operation.

BACKGROUND OF THE INVENTION

There is an increasing demand to simplify well operations on subsea oil and/or gas wells in order to reduce time and costs for the well operations. Such operations may be to install, remove or replace a horizontal Christmas tree (often referred to as a HXT).

During top completion of a well using a horizontal Christmas tree (HXT), the blowout preventer (BOP) has to be retrieved from the wellhead (WH) in order for the Christmas tree to be installed using a dedicated tree running tool, that amongst others could be the device described herein. Prior to retrieval of the blowout preventer (BOP) the well is temporarily isolated with lower and upper barrier elements until the blowout preventer (BOP) is re-landed and re-connected. The upper barrier element is normally a casing plug. After the Christmas tree is installed on top of the wellhead (WH) the blowout preventer (BOP) is run and re-landed on top of the newly installed Christmas tree enabling the top completion string and the tubing hanger (TH) to be run and locked into the Christmas tree (HXT) after the barrier element or elements have been retrieved.

Except for the Christmas tree installations the above operations are today only performed using a drilling rig, a drill ship or a jack-up rig. Installation of the specified Christmas tree may be performed from a drilling rig, a drill ship, a jack-up rig, a riserless light well intervention (RLWI) vessel or another monohull vessel suitable for such operations.

If the Christmas tree (HXT) is run and installed from a riserless light well intervention (RLWI) vessel or another monohull vessel suitable for such operations, the Christmas tree (HXT) will be left on the wellhead (WH) with only a debris cap or corrosion cap on the top, as the well is already equipped with the required barriers. At a later stage a drilling rig, drill ship or a jack-up rig will arrive at the location to install the top completion string with the tubing hanger (TH).

Removal of the HXT from the wellhead is an operation performed during a temporary or permanent plug and abandonment operation of the well, or when the HXT is experiencing malfunction(s) and must be replaced.

Prior art technology for removing the HXT involves the use of a drilling rig, a drill ship, a jack-up rig or a RLWI vessel with subsea pressure control equipment, such as a blowout preventer (BOP) or a RLWI pressure control stack respectively.

There are two different methods to control the well during abandonment operations. Either the operations are performed in a pressurized well or the well is bullheaded/killed prior to establishing the needed barrier(s). In some cases a deep barrier plug must be installed in the production tubing, or the production tubing may comprise flow control valves (FCV) and/or gas lift valves (GLV) that could be closed or the well could be filled with a kill pill and brine or kill mud from perforations/screens to surface to maintain the requirement for a deep barrier. The flow control valves (FCV) and/or gas lift valves (GLV) can be controlled from the host platform or from the rig/vessel via the respective control systems.

Initially, a short description of the horizontal Christmas tree (HXT) will be given with reference to fig. 1.

The HXT controls the flow of fluids in the well, in particular produced hydrocarbons flowing out from the well and constitutes a barrier between the well and the environment.

The HXT is arranged on the seabed, on top of a subsea wellhead on a well extending into the seabed. After installing the HXT on the wellhead a tubing hanger (TH)/tubing is run, landed and locked in the HXT. As of today all operations, involving running or retrieving of tubing/upper completion strings include utilization of drilling rigs, drill ships or jack-up rigs as well as installation of subsea BOPs on top of the HXTs or use of high pressure riser from HXT to surface BOP prior to handling the upper completion strings.

A HXT as referred to, only have one bore, which allows the upper completion string/tubing to be run into the well/casing, the TH to be landed on a landing shoulder in the HXT bore aligned with the horizontal production outlet from the HXT and then locked in the HXT. Hence, produced fluid is guided from the production bore and out into the manifold and then into the pipeline to the designated location.

To allow the production fluid to be guided into the manifold, the vertical bore is, after the upper completion string is installed in the HXT, isolated with two individual barrier plugs that are installed using either wireline (WL) or drill pipe (DP). The lower plug is installed in the TH bore above the production outlet and the upper plug is installed in the HXT bore. These plugs shut off/barrier off any eventually leakage originating from the tubing production bore and permits the removal of the BOP after installation of the upper completion. During the installation and/or retrieval phase of the upper completions, the BOP rams will be used to shut off/barrier off the access to the well if necessary.

When the upper and lower plugs are retrieved or prior to installation of a HXT, there is vertical access to the well from topside through the HXT and the completion string. This allows for wireline (WL) tools and/or drill pipe to be used to install and/or retrieve barrier elements and other remedies in the HXT and the completion string through e.g. a workover riser, a marine riser or similar.

There is only fluid communication with the tubing annulus, which is the annular space between the production tubing and the well casing.

Prior to retrieval of a HXT there will be need to retrieve the upper and lower TH-plugs to allow for access to the well for further necessary operations that in the first hand could be to bullhead/kill the well or run a deep barrier plug enabling the upper completion string to be retrieved prior to pull the HXT.

During the above operations, there could be a need to pump and circulate fluid and to run wireline (WL) or drill pipe (DP) into the well via the HXT in order to e.g. bullhead/kill the well, pressure test barriers, change the type of fluid in the well, retrieve and install barrier elements and different kind of completion equipment etc. These operations are today performed by a drilling rig, a drill ship, a jack-up rig or a RLWI vessel. Retrieval of the upper completion string/TH can not be performed by a RLWI-vessel, thus the RLWI-vessel can just prepare the well for the aforementioned retrieval operation.

The objective of the present invention is to reduce the potential safety issue of handling heavy equipment onboard floating work platforms as well as to reduce the complexity, time, cost, equipment/tools and personnel involved with such operations through the possibility to run and retrieve Christmas trees (HXT) from other work platforms than a drilling rig, a drill ship or a jack-up rig.

US 2014/0048278 A1 describes a subsea well assembly having a Xmas tree and wellhead. From a tubing hanger a tubing extends into the well. A part of a production flow passage extends vertically from the tubing hanger in a vertical bore of the Xmas tree. A fail close production master valve is arranged in the production flow passage. The tubing hanger is arranged below the Xmas tree, such as in the wellhead. The Xmas tree exhibits a branch that deviates from the vertical bore, which branch constitutes part of the production flow passage. The fail close type production master valve is arranged in the branch.

US 2015/0275608 describes a subsea hydrocarbon production system comprising a tubing hanger which is positioned at an upper end of a well bore, a tubing string which extends from the tubing hanger into the well bore and is fluidly connected to the tubing hanger production bore, and a christmas tree which is positioned above the tubing hanger. The christmas tree comprises a production bore which is fluidly connected to the tubing hanger production bore, a production outlet which is connected to the production bore, a first barrier element which is positioned in the production outlet, and a first closure device which is positioned in the production bore above the production outlet, and a outlet. In this manner access from above the Christmas tree through the production bore does not require passage through a barrier element.

WO 1998/49422 describes a method and apparatus utilizing a tree running tool for guiding a conventional or horizontal tree for the purpose of connection to a subsea wellhead or wellhead system without the use of guidelines or guide funnels. The horizontal tree has an orientation sleeve projecting downwardly from tree body, and the tree running tool has a lower stabbing extension or stinger which extends below the orientation sleeve for guiding and aligning the orientation sleeve into engagement with a high pressure wellhead housing and associated production casing hanger for connection of the tree body to the high pressure wellhead housing.

SUMMARY OF THE INVENTION

The present invention relates to a device for enabling removal of a horizontal Christmas tree from a wellhead or for installing a horizontal Christmas tree on a wellhead and is defined in the independent claim 1. The present invention also relates to a method for removal of a horizontal Christmas tree from a wellhead and a method for installing a horizontal Christmas tree on a wellhead as defined in claims 15 and 17 respectively. Aspects of the invention are defined in the dependent claims.

DETAILED DESCRIPTION

Embodiments of the invention will be described herein in detail with reference to the enclosed drawings, where:

Fig. 1 illustrates a prior art horizontal Christmas tree HXT landed on a subsea wellhead schematically, where the different main valves in the tree are indicated by their respective names;

Figs. 2a – 2m illustrates different embodiments of the present invention

schematically;

Fig. 3 illustrates schematically the submerging of the device from a vessel and down to a Christmas tree;

Figs 4 – 10 illustrates different steps of how the embodiments of the invention may be used.

Fig. 1 is considered to be described in the introduction above.

It is now referred to figs. 2a – 2m, illustrating a device generally referred to with reference number 1. In some of the drawings, the term SPPA is also used for the device 1, which is an abbreviation for "Subsea Pump and Plug Adapter".

As mentioned in the introduction, the present invention can be used to enable removal of a horizontal Christmas tree from a wellhead WH or for installation of a horizontal Christmas tree on a wellhead. In the following description, the term HXT is used as an abbreviation for a horizontal Christmas tree. A list of other abbreviations used in the drawings are provided in the end of the description below.

There are several embodiments of the present invention. In particular, the number of valves provided in the device 1 will vary between the different embodiments. For example, some valves may be omitted for HXTs where barriers can be established below the HXT themselves. Such a barrier will typically be a downhole safety valve DHSV. However, in HXTs where such a barrier is not present, or in situations where such a barrier can not be thrusted, more valves may be necessary to be installed in the device 1 itself, or a bore plug may have to be installed in the production bore using wireline (WL).

The number of valves may also be dependent on safety regulations determined by the owner of the well. For example, if wireline operations above the DHSV will take place there could be necessary to introduce two bore valves in the vertical bore where one of the valves is intended for cutting the wireline and the other valve is used to barrier off the well bore.

In figs. 2a – 2m, the device 1 is illustrated. The device 1 comprises a housing device 10 having a bore 11 provided through the housing 10. The bore 11 is provided for alignment with the production bore PB of the horizontal Christmas tree HXT. The device 1 may comprises a removable cap 14 provided in the upper part of the bore 11. The cap 14 may be a debris cap for preventing debris to enter the bore 11.

Alternatively, the cap 14 may be a high pressure end cap 14.

A lower connector 15 is provided for connection directly to an upper re-entry mandrel on the horizontal Christmas tree HXT or to the dedicated connection interface of a dedicated tree running and retrieval tool. If the lower connector 15 is connected to the Christmas tree HXT upper mandrel directly, the device 1 may have to comprise special functionalities that a tree running and retrieval tool could include. Such functionalities could be to e.g. hydraulically operate soft landing cylinders or jacks, include a connection point for umbilical and/or relevant hydraulic supplies to the HXT, include ROV-panel for operating of the HXT, have the capabilities to lift the complete HXT-stack, in this case the device 1 and the HXT or the device 1, the tree running and retrieval tool and the HXT, have attached a bumper structure for any under- and/or over-hull guiding structure interface etc.

The device 1 further comprises a fluid communication port 30 provided in fluid communication with the bore 11 via a fluid line 31.

The device 1 also comprises a first fluid line valve 41 provided in the fluid line 31 or a first production bore valve 51 provided in the bore 11.

In fig. 2a, the device 1 comprises a first fluid line valve 41 provided in the fluid line 31, a second fluid line valve 42 provided in the fluid line 31, a first production bore valve 51 provided in the bore 11 and a second production bore valve 52 provided in the bore 11. The second production bore valve 52 is provided below the first production bore valve 51. The second fluid line valve 42 is provided closer to the fluid line 31 entry point 31a than the first fluid line valve 42. Here, the fluid line 31 entry point 31a is provided below the second production bore valve 52.

Fig. 2b is similar to fig. 2a, but here, there is only one fluid line valve, that is fluid line valve 41.

Fig. 2c is similar to fig. 2a, but here, the fluid line 31 entry point 31a is provided below the first production bore valve 51 and above the second production bore valve 52.

Fig. 2d is similar to fig. 2c, but here, there is only one fluid line valve, that is fluid line valve 41.

Fig. 2e is similar to fig. 2a, but here, the fluid line 31 entry point 31a is provided above the first production bore valve 51.

Fig. 2f is similar to fig. 2e, but here, there is only one fluid line valve, that is fluid line valve 41.

Fig. 2g is similar to fig. 2a, but here, there is only one production bore valve, that is production bore valve 51.

Fig. 2h is similar to fig. 2a, but here, there is only one fluid line valve 41 and only one production bore valve 51, as indicated in the drawings.

Fig. 2i shows an embodiment where the device 1 comprises two housing sections 10a, 10b connected above each other, and where the fluid line 31 and fluid port 30 are provided in the upper housing section 10a. Here, the upper housing section 10 corresponds to fig. 2g (i.e. two fluid line valves 41, 42 and one production bore valve 51) while the lower housing section 10b comprises the second fluid valve 52. In addition, a third production bore valve 53 is provided in the bore 11 between the upper first valve 51 and the lower second valve 52. The design in fig. 2i allows for the lower section 10b to be left on the HXT to act as a barrier in case of eventually well challenges that has to be cured through a subsea BOP and consequently the possibility to use other remedies to intervene in the well. In such cases the subsea BOP could be landed on top of the lower section 10b and the valves 52 and 53 could be opened to allow access into the well bore.

It should be noted that this solution, with two housing sections 10a, 10b, can be used with the other embodiments of the device 1 as well.

Fig. 2j corresponds to fig. 2a, here the device 1 further comprises a guide sleeve 61 provided in the bore 11. The purpose of the guide sleeve 61 is to guide tools etc from the bore 11 of the device 1 having a wider diameter into the production bore PB of the HXT having a narrower diameter. Such a guide sleeve 61 may be provided in the other embodiments as well.

Fig. 2k corresponds to fig. 2g, here the device 1 further comprises an upper shear ram device 62 and a lower shear ram device 63 provided in the bore 11. The purpose of the shear ram devices 62, 63 is to cut wires etc. provided in the bore 11 in case objects connected to the wire are stuck below the device 1. The shear rams may for example be operated by means of a ROV.

In fig. 2l, the device 1 only comprises the first and second fluid line valves 41, 42.

In fig. 2m, the device 1 only comprises the first and second production bore valves 51, 52. Here, the fluid line 31 entry point 31a is provided above the first and second production valves 51, 52. Hence, the valves 51, 52 will prevent fluid from the well to arrive at the top of the production bore 11 and also to prevent fluid from the well to arrive into the fluid line 31.

In addition, the device 1 may be equipped with gauges for pressure and/or temperature reading at different locations in the bore 11 and/or fluid line 31.

The device 1 could also be equipped with lifting points enabling lifting of the complete stack, i.e. device 1, tree running tool and the HXT - both with or without the vessel- or ROV-operated tool running and/or retrieval unit 18/16 connected (as shown in fig. 6, 9 and 10).

It is now referred to fig. 3. Here, a vessel 100 is disclosed at sealevel SL above the seabed SB. A subsea well is provided on the seabed, illustrated as a wellhead WH with a Christmas tree XT. The vessel 100 comprises a lifting device 101 that is used to lower the device 1 down towards the Christmas tree via a wire 102.

The vessel 100 is preferably a monohull vessel. Alternatively, other vessels, such as a drilling rig may be used. However, monohull vessels are often a less expensive solution.

The lifting device 101 may be a crane, an A-frame, a module handling system MHS or drillpipe DP with its drill pipe derrick and draw-works.

The wire 102 may be a wire or a drillpipe.

In addition, a remotely operated vehicle ROV 120 is controlled from the vessel 100 via a control and power cable 122. In the various embodiments above, the valves 41, 42, 51, 52 and/or 53 are preferably configured to be operated by a remotely operated vehicle 120. As is known, ROV 120 is commonly used to open/close valves of XTs and to perform other types of subsea operations. These operations can be performed mechanically with the ROV manipulator and/or a ROV hydraulic operated tool and/or with hot lining from a ROV hydraulic test skid to connection points on the subsea equipment. Alternatively, the device 1 could be configured so that the different hydraulic functions to be performed on device 1 and if applicable the tree running and retrieval tool as well as the Christmas tree, are controlled and supplied from the vessel 100 via a separate umbilical attached to the device 1 from the vessel 100.

The fluid communication port 30 is provided for connection to a fluid circulation device 110. The fluid circulation device 110 may be provided topside on the vessel, and may for example be a pumping device. The fluid circulation device 110 may be connected to a fluid reservoir containing fluids with desired properties e.g. mud, brine, seawater etc.

As shown in fig. 3, the fluid circulation device 110 is connected to the fluid communication port 30 of the device 1 via a hose 111. Preferably, the hose is a high pressure hose, and the fluid circulation device 110 is a high pressure pump for applying a high fluid pressure into the port 30 of the device 1. The fluid circulation device 110 could comprise pressure, temperature and flow meters to measure the pressure and temperature of the fluid in port 30 and/or the fluid rate through port 30. The fluid circulation device 110 and hose 111 are used to pressure test/operate the tree and well barriers during the well operation as well as to provide for circulating different fluids in the well. A non-return valve may also be provided in the hose.

All of the embodiments of the devices 1 can be deployed and operated from any work platform, e.g. mono-hull vessel, drilling rig, platform etc.

The conveyance method for running and retrieving activities from a monohull vessel will be by wire. If the SPPA is run/retrieved from a drilling rig, a drill ship and a jack-up without the possibility to run equipment on wire, a drill-pipe solution could be used.

The most effective and less complicated method using drill pipe (DP) would be to use a forerunner between a DP lifting sub made up to the lower end of the DP and the lifting arrangement on device 1. Such a solution will either require a standard lifting sub to be made up to the DP and use of the aforementioned high pressure pumping hose run down from the rig to device 1, or it would require a special lifting adapter with a side outlet for pumping purposes. The idea behind such a purposemade side outlet adapter is twofold; lifting of the XT stack, similar function as the standard lifting sub, and in addition make pumping activities possible without the need for a surface hose reel and the corresponding high pressure pumping hose. If using a purpose-made side outlet adapter the required fluid could be pumped down the DP through the adapter outlet and a high-pressure hose and into the well through the port 30 on the device 1, thus enabling bullheading/killing of well, pressure testing, pumping of prong/plug, etc. - “as normal”.

The above-mentioned DP conveyance methods will enable the forerunner to be disconnected from the device 1 by use of a ROV, as will also be the situation if deploying device 1 by a wire, hence there is no “locked to bottom”-situation requiring weak-link, drive-off/drift-off calculations/evaluations, control systems etc. The high pressure pumping hose will still be connected to both the device 1 port 30 and the special lifting adapter side outlet, thus demanding the hose connector to either be equipped with a disconnect device/design enabling both disconnect and reconnect or a guillotine solution to cut the hose in an emergency. A non-return/shutin valve taking care of the integrity of device 1 in a drive-off/drift-off situation would also be part of the overall design. The same situation and means will apply for situations where the high pressure hose is run from the vessel to device 1 port 30 if an emergency situation would occur.

In addition, the device 1 may comprise a ROV-operated tool running and/or retrieval unit 16 or a vessel-operated tool running and/or retrieval unit 18.

The vessel-operated tool running and/or retrieval unit 18 is shown in fig. 6 and comprises a production bore lubricator 18a, a tool 18f provided in the production bore lubricator 18a and a production bore stuffing box 18b. Preferably, the tool further comprises a tool dropping barrier 18g to prevent the tool 18f to enter the bore 11 before it is desired, as well as to avoid dropping the tool 18f during running and pulling operations of running and retrieval unit 18. The tool dropping barrier 18g is preferably operated by means of a ROV. The tool running and/or retrieval unit 18 is connected to the upper part of the bore 11 by a ROV subsea operated high pressure connector or a fixed or removable high pressure connection made up to device 1 on surface. A wire 18d is connected to the tool 18f and is guided out from the lubricator and stuffing box up to the vessel 100.

The ROV-operated tool running and/or retrieval unit 16 is shown in fig. 9. Similar to the unit 18, the unit 16 comprises a lubricator 16a, stuffing box 16b, wire 16d, tool 16f and tool dropping barrier 16g. In addition, the unit 16 further comprises a ROV-operable handle 16e, and a wire sheave 16c, where the tool 16f is connected by means of a wire 16d via the sheave 16c to the handle 16.

Alternatively, as shown in fig. 10, the unit 16 may comprise a winch unit 16j for controlling the wire 16d instead of the ROV-operated handle 16e. The winch unit 16j can either be supplied from a ROV/skid or supplied from surface. The winch could be operated manually with a ROV manipulator and/or a mechanical tool device or by a ROV-operated hydraulic torque tool.

Below, examples of the use of some of the above embodiments of the device 1 will be described with reference to the drawings. These examples are meant only as examples, and do not prevent the above alternatives to be used in other types of operations.

Initially, it should be mentioned that, depending on the type of operation and the type of HXT, a rig may be needed in order to prepare the well, the wellhead and/or the HXT before the device 1 can be used. These prerequisite operations will be described very short in the examples, as such rig operations are considered to be known for the skilled person. As monohull vessels have advantages over rigs with respect to costs etc. as discussed above, it may still be advantageous to use the present invention for only parts of the well operation.

Moreover, in the examples below, some details will be omitted as they are considered known for the skilled person. For example the ROV technology and general communication technology (sending and receiving communication signals from sensors for sensing fluid flow, fluid pressure, fluid temperature, valve status etc) between the ROV 120, the vessel 110 and the device 1 will not be described. Moreover, the connection between the device 1 and the HXT with or without the tree running tool TRT is considered prior art. Systems to position a monohull vessel, a rig or a jack-up rig above the well such as anchoring, dynamic positioning or resting on legs penetrated into the seabed are considered prior art knowledge for a skilled person and will not be further described. Further, the operational aspects of functioning a gas lift valve or a flow control valve is also considered prior art and will not be described. Preparations prior to entering the well with the device 1 will not be described as these also are considered prior art. The different type of plugs that could be opened by pumping - plugs with shear open device, electronic activated plugs, etc. are considered prior art technology and will not be further explained.

Example 1: Installation of a horizontal Christmas HXT tree on a wellhead WH

An example of an operation of installing a vertical dual bore Christmas tree XT on a wellhead WH by using the device 1 will now be described in detail.

Initially, the device 1 according to fig. 2a is connected to the Christmas tree topside on the vessel. A tree running tool TRT could be used for connecting the device 1 to the Christmas tree. Then the device 1 and the Christmas tree HXT are lowered by means of the vessel 100 down to the well head.

In fig. 4, the device 1 and the Christmas tree have been landed on to the well head WH.

In fig. 5, the connection between the Christmas tree HXT and the well head WH, the valves of the Christmas tree HXT and the upper barrier plug set in the casing bore are tested by pumping a high pressure fluid into port 30 and further into the bore 11 of the device 1 and further down. If pressure test is approved, then the device 1 may be disconnected from the Christmas tree HXT and elevated up to the vessel. During this entire operation, the bore valves 51, 52 are closed, while fluid line valves 41, 42 are opened for allowing fluid into the bore. The fluid line valves are closed after the pressure testing operation. After retrieving device 1 a debris cap, a corrosion cap or a high pressure cap could be installed on the HXT upper mandrel to protect the bore from eventual debris falling into the HXT/on top of the upper barrier plug.

The above operations may be performed by lighter vessels, i.e. vessels other than drilling rig, a drill ship or a jack-up rig. Of course, the vessel should have wireline capabilities and should have the above-mentioned fluid circulation device (110). In addition, the vessels should have ROV capabilities.

When these operations are completed a drilling rig, drillship or jack-up rig could be positioned above the well to continue the operation to prepare the well for production by installing the upper completion string.

Example 2: Removal of Christmas tree

Here, the device 1 comprises the above described unit 18. A tree running tool TRT is connected below the device 1 for connecting the device 1 to the Christmas tree. In fig. 6, the tree running tool TRT and device 1 has been connected to the Christmas tree.

In fig. 7, the tool holder 18g is opened, and the plug running and retrieval tool 18f is lowered into the bore 11 of the device 1, and further down into the production bore of the Christmas tree HXT. Here, the tool 18f is connected to the tubing hanger TH plug.

In fig. 8, the tool 18f and the TH plug is retrieved into the lubricator. Fluid is pumped into port 30 and further into the production bore to bullhead/kill the well. Here, bore valves 51, 52 are closed.

After the well has been killed and stabilized the vessel-operated tool running and/or retrieval unit 18 is disconnected from the device 1 and pulled to surface for disconnection of the TH plug and corresponding pulling tool 18f and replacement with a production bore barrier plug and corresponding plug setting tool 18f. Then the vessel-operated tool running and/or retrieval unit 18 with the new tool and plug 18f is re-run and connected to the device 1 prior to open the bore valves 51 and 52 to give access to the production tubing bore for setting of this upper barrier plug on a predefined depth above the down hole safety valve DHSV.

After above operations are completed the vessel-operated tool running and/or retrieval unit 18 with the plug setting tool 18f is disconnected from the device 1 and pulled to surface for disconnection of the aforementioned plug setting tool 18f. A new tool 18f, a cutting tool, is connected to the wire 18d and the vessel-operated tool running and/or retrieval unit 18 with the cutting tool 18f is re-run and connected to the device 1 prior to open the bore valves 51 and 52 to give access to the production tubing bore. Thereafter the cutting tool 18f is lowered into the production bore to a predefined depth cutting the tubing apart. The cutting tool 18f is now pulled back into the vessel-operated tool running and/or retrieval unit 18.

The fluid line valves 41, 42 and the bore valves 51,52 are then closed and the Christmas tree HXT together with the device 1 and the TRT is now free to be retrieved from the wellhead WH following normal established procedures for such operations.

After retrieving device 1 and the Christmas tree HXT a debris cap, a corrosion cap or a high pressure cap could be installed on the wellhead WH to protect the well from eventual falling debris that could end up in the well.

The above operations can be performed with the above embodiments of the device 1. For example, if the device 1 comprises shear rams 62, 63, these can be used to cut wires if necessary.

List of abbreviations used in description and drawings:

Claims (17)

1. Device (1) for enabling removal of a horizontal Christmas tree (HXT) from a wellhead (WH) or for installation of a horizontal Christmas tree (HXT) on a wellhead, characterized in that the device (1) is comprising:

- a housing device (10) having a bore (11) provided through the housing (10) for alignment with the production bore (PB) of the horizontal Christmas tree (HXT);

- a lower connector (15) for connection to an upper re-entry mandrel of the horizontal Christmas tree (HXT);

- a fluid communication port (30) provided in fluid communication with the bore (11) via a fluid line (31);

- a first fluid line valve (41) provided in the fluid line (31) or a first production bore valve (51) provided in the bore (11).

2. Device (1) according to claim 1, where the device (1) further comprises a second production bore valve (52) provided in the bore (11), where the second production bore valve (52) is provided below the first production bore valve (51).

3. Device (1) according to claim 1 or 2, where the device (1) further comprises a second fluid line valve (42) provided in the fluid line (31), where the second fluid line valve (42) is provided closer to the fluid line (31) entry point (31a) than the first fluid line valve (42).

4. Device (1) according to any one of claims 1 - 3, where the fluid communication port (30) is provided for connection to a fluid circulation device (110) via a hose (111).

5. Device (1) according to any one of claims 1 – 4, where the device (1) comprises a removable cap (14) provided in the upper part of the bore (11).

6. Device (1) according to any one of claims claim 1 – 4, where the device (1) comprises a tool running and/or retrieval unit (16; 18) comprising a production bore lubricator (16a; 18a), a tool (16f; 18f) provided in the production bore lubricator (16a; 18a) and a production bore stuffing box (16b; 18b), where the tool running and/or retrieval unit (16; 18) is connected to the upper part of the bore (11).

7. Device (1) according to claim 6, where the tool running and/or retrieval unit (16; 18) comprises a tool dropping barrier (16g; 18g).

8. Device (1) according to claim 6 or 7, where the tool running and/or retrieval unit is a ROV-operated tool running and/or retrieval unit (16), where the unit (16) further comprises a ROV-operable handle (16e), and a wire sheave (16c), where the tool (16f) is connected by means of a wire (16d) via the sheave (16c) to the handle (16).

9. Device (1) according to claim 6 or 7, where the tool running and/or retrieval unit is a winch-operated tool running and/or retrieval unit (16), where the unit (16) further comprises a winch (16j), and a wire sheave (16c), where the tool (16f) is connected by means of a wire (16d) via the sheave (16c) to the winch (16j).

10. Device (1) according to claim 6 or 7, where the tool running and/or retrieval unit is a vessel-operated tool running and/or retrieval unit (18), where the tool (18f) is connected by means of a wire (18d) to a vessel (100).

11. Device (1) according to any one of the above claims, where the device (1) further comprises a guide sleeve (61) provided in the bore (11).

12. Device (1) according to any one of the above claims, where the device (1) further comprises a shear ram device (62) provided in the bore (11).

13. Device (1) according to any one of the above claims, where the first production bore valve (51) is provided below the fluid line (31) entry point (31a) into the bore (11).

14. Device (1) according to any one of the above claims, where the lower connector (15) is connected to the upper re-entry mandrel of the vertical Christmas tree via a tree running tool (TRT).

15. Method for removal of a horizontal Christmas tree (HXT) from a wellhead (WH), characterized in that the method is comprising the steps of:

a) submerging a device (1) according to any one of claim 1 - 12 from a vessel (100) down to the Christmas tree (XT);

b) connecting the device (1) to the Christmas tree (XT) by aligning a bore (11) of the device (1) with a production bore (PB) of the Christmas tree (XT);

c) establishing a first and a second barrier below the Christmas tree (XT);

cd) cutting the production tubing below the Christmas tree (XT) and above the barriers;

ed) disconnecting the Christmas tree (XT) from the wellhead (WH);

fe) elevating the Christmas tree (XT) and the device (1) to the vessel (100).

16. Method according to claim 13, further comprising the step of:

- testing the connection between the device (1) and the Christmas tree (XT) by pumping a fluid under pressure from the vessel (100) into the device (1) by means of a fluid circulation device (110) via a hose (111).

17. Method for installing a horizontal Christmas tree (HXT) on a wellhead (WH), characterized in that the method is comprising the steps of:

a) connecting a device (1) according to any one of claims 1 - 12 to the Christmas tree (HXT) by aligning a bore (11) of the device (1) with a bore (PB) of the Christmas tree (XT);

b) submerging the device (1) from a vessel (100) down to the Christmas tree (XT);

c) connecting the Christmas tree (XT) and the device (1) to the wellhead (WH);

d) disconnecting the device (1) from the Christmas tree (XT);

e) elevating the device (1) to the vessel (100).