NO20151658A1 - Method for removal of HXT - Google Patents

Abstract

The present invention relates to a method for removing a subsea horizontal Christmas tree (HXT) from a wellhead (WH) of a subsea well. A production tubing (PT) of the well is hung off in a tubing hanger (TH) provided in the horizontal Christmas tree (HXT). The method comprises the steps of: a) connecting a subsea pressure control device (PCE) to the horizontal Christmas tree (HXT); b) establishing a first and a second barrier in the well; c) cutting the Production tubing (PT) at a cutting location (X) below the tubing hanger (TH); d) disconnecting the horizontal Christmas tree (HXT) from the wellhead (WH); e) elevating the horizontal Christmas tree (HXT) and the tree running tool (TRT) from the well head (WH).

Description

FIELD OF THE INVENTION

The present invention relates to a method for removing a horizontal Christmas tree and integrated tubing hanger from a subsea well without prior recovery of the completion string.

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 remove a horizontal Christmas tree (often referred to as a HXT).

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

Prior art technology for removing the HXT involves establishment of the required temporary well barrier plugs and retrieval of the completion string prior to removing the HXT. This requires subsea pressure control equipment such as a subsea blowout preventer (BOP) to be deployed onto the HXT from a drilling rig or drilling vessel. The BOP has to be detached again prior to removing the HXT, which is removed using a dedicated HXT pulling tool, often referred to as Tree Running Tool (TRT).

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

The horizontal subsea Christmas tree (HXT) is arranged on the seabed, on top of a subsea wellhead on a well extending into the seabed.

Prior to installing the subsea HXT on the wellhead, a production casing is run and hung off in the wellhead. The well/wellhead is then temporarily isolated with the required barrier element(s) until the HXT is Ianded and connected.

The tubing hanger (TH) and upper completion string is landed, locked and connected into the HXT body after drilling the lower section(s) and/or installing the lower completion(s).

The TH forms the connection between the production/injection tubing and the HXT and is typically monobore, with access to the annulus being provided via side entry ports above and below the hanger. A TH plug is usually installed inside the top of the TH to seal the vertical bore through the TH. An internat tree cap (ITC) is installed inside the top of the tree to provide a secondary barrier to sea. Alternative HXT systems incorporates a secondary TH plug to be installed. A tree cap (TC) is installed on to the 18<3>A" re-entry mandrel on top of the tree. The main difference between the HXT and VXT is that for HXT the TH is installed into the Christmas tree rather than the wellhead and the main production valves of a HXT are located on the lateral sides of the tree rather than vertically.

A wireline or drillpipe tool can be used to install and/or retrieve barrier elements in the HXT bores and/or in the well through e.g. a workover riser or marine drilling riser for plugging the well, prior to removing the HXT and subsequent to retrieval of the top completion. A cutting tool can be deployed on wireline or drillpipe for severing and freeing the completion string above the production packer in wells which are not equipped with a straight-pull release sub (Polished Bore Receptacle or Completion Release Device or similar) for successive completion recovery.

Control lines may also be provided from the topside through separate ports in the HXT and TH to lower parts of the well. A control line may be electrical, hydraulic, fiber optic etc and is typically used to transfer electric and hydraulic power and/or electric, hydraulic and optic signals respectively. The control lines, which are clamped externally to the tubing, are used during the completion installation and production/ injection process in order to control or transfer signals to or from downhole completion tools.

The object of the present invention is to reduce the complexity, time, costs, equipment/tools and personnel involved in operations related to well plugging and removal of HXT. The present invention enables such operations to be performed from vessels, as opposed to current technology which limits HXT removal to be performed from drilling rigs or drilling vessels.

SUMMARY OF THE INVENTION

The present invention relates to a method for removal of a subsea horizontal Christmas tree HXT from a wellhead WH of a subsea well, where a production tubing PT of the well is hung off in a tubing hanger TH provided in the horizontal Christmas tree HXT, and where the method comprises the steps of: a) connecting a subsea pressure control device PCE to the horizontal Christmas tree HXT; b) establishing a first and a second barrier in the well; c) cutting the production tubing PT at a cutting location X below the tubing hanger TH; d) disconnecting the horizontal Christmas tree HXT from the wellhead WH; e) elevating the horizontal Christmas tree HXT and the tree running tool TRT from the well head WH.

The above method may be performed by a wireline and wireline tools and a ROV. Hence, all the above steps a-e may be performed by a monohull vessel. Accordingly, no rig is needed, which contributes to reduced time and costs for such operations.

In one aspect, the method further comprises the step of setting a casing plug CP in the well head WH above the tubing hanger TH after step e). Typically, this will be done by the following steps: - connecting a subsea pressure control device PCE to the well head WH; - setting the casing plug CP in the well head WH through the subsea pressure control device PCE; - testing the integrity of the casing plug CP;

- disconnecting the subsea pressure control device PCE from the well head WH.

In one aspect, the method comprises the following step after step c):

- setting a high expansion plug HEP in a production casing PC directly below the cutting location X. The step of setting the high expansion plug HEP may establishing the second barrier. Accordingly, the step of establishing the first barrier may performed by setting a mechanical barrier plug MP below the cutting location X before step c).

Preferably, step c) further comprises the step of cutting of control lines provided radially outside of the production tubing PT at the cutting location.

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 tree HXT landed on a well head schematically, where the different valves in the tree are indicated by their respective names; Fig. 2 illustrates well schematic including casing, completion and with a tree HXT landed on a well head, where the different valves in the tree and main completion components are indicated by their respective names; Fig. 3a illustrates a first method for establishing a double barrier prior to the cutting operation; Fig. 3b illustrates a second method for establishing a double barrier prior to the cutting operation; Fig. 3c illustrates a third method, where only a first barrier is established prior to the cutting operation; Fig 4a illustrates the step of cutting the production tubing after the double barrier has been established; Fig. 4b illustrates the step of establishing a second barrier of fig. 3c after the cutting operation;

Fig 5 illustrates the step of removing the tree HXT from the well head WH

Fig 6 illustrates installation of an additional casing plug above the cut tubing.

The method according to the invention will now be described with reference to the enclosed drawings.

Initially, it should be mentioned that the purpose of the method is to remove a subsea horizontal Christmas tree HXT from the wellhead WH of a subsea well. In this type of subsea horizontal Christmas tree HXT, the production tubing PT of the well is hung off in a tubing hanger TH provided in the horizontal Christmas tree

HXT.

In fig. 2, it is shown that the subsea horizontal Christmas tree HXT comprises retrievable tree cap TC connected to a re-entry mandrel for vertical connection to the tree.

It is now referred to fig. 3a - 3c. Here, a vessel VS has been located at sealevel above the tree HXT. The tree cap TC is removed (by means of an operation performed from the vessel VS, and a subsea pressure control device PCE is lowered from the vessel VS and connected to the Christmas tree HXT re-entry mandrel.

The subsea pressure control device PCE consists of well control bore valves (pipe rams, shear ram) as required as per wireline type to be run, lubricator section and a packbox (stuffing box) or cap for sealing the wireline and/ or containing the well and the well fluids.

Following recovery of the tree cap (TC), in a first step, the subsea pressure control device PCE is connected to the top of the horizontal Christmas tree HXT. This operation is performed from the vessel VS. A remotely actuated vehicle (hereinafter referred to as a ROV) may also be used during this operation.

In a next step, a first and a second barrier is established in the well. Such a double barrier is required before the tree HXT can be disconnected from the well head WH. In wells with seawater gradient and absence of hydrocarbons it will be required to establish one barrier only before disconnection of the HXT.

There are several ways to establish such a first and second barrier:

1) In fig. 3a, the double barrier is established by first setting a lower mechanical plug LMP in the production liner PL or production tubing PT and then setting an upper mechanical plug UMP in the production liner PL or production tubing PT. The upper and lower mechanical plugs LMP, UMP are typically set below the production packer PP in the production annulus PA of the well. In some situations, the upper mechanical plug UMP may be set above the production packer PP.

The mechanical plugs LMP, UMP are run through the subsea pressure control device PCE and installed in the well as is considered known for a skilled person. Normally, prior to establishment of barriers by means of barrier plugs, fluid plugs or similar, the hydrocarbons in the production tubing PT is removed by injecting a fluid into the well through a subsea hose SH and into the reservoir. 2) In fig. 3b, the double barrier is established by first setting a mechanical plug MP in the production liner PL or production tubing PT below the production packer PP. Hence, the mechanical plug MP is providing the first barrier.

Then, communication is established between the production tubing and production annulus above the production packer by means of punching, perforation, cutting or similar. A punching, perforation, and/or cutting tool is run into the well and one or several holes are provided in the production tubing above the production packer PP. Then a subsea hose is connected to the subsea pressure control device PCE from the vessel VS and a barrier fluid, such as cement and/or resin or another suitabie fluid is supplied into the production tubing PT. The barrier fluid is considered known for a skilled person, and the present invention is not dependent on the type of barrier fluid.

The barrier fluid will fill, and potentially solidify, the production tubing PT and/or production liner PL above the mechanical plug MP and will also fill and solidify the production annulus PA above the production packer PP due to the prior communication established between the production tubing PT and production annulus P.

In fig. 3b, the second barrier provided by the barrier fluid is indicated by a hatched area in the production tubing above the mechanical plug and in the production annulus above the production packer.

It should also be noted that the arrows in flg. 3b is showing how the fluid is circulated from vessel, through the hose, the production tubing, the production annulus and out through the production line of the tree via the annulus bore AL. Of

course, the barrier fluid is not circulated out through the tree.

3) In fig. 3c, the first barrier is established by connecting a subsea hose connected to the subsea pressure control device PCE from the vessel VS and then supply a barrier fluid into the production tubing PT. The bottom of the well is then filled with fluid, as indicated with a hatched area in fig. 3c. The barrier fluid is considered known for a skilled person, and the present invention is not dependent on the type of barrier fluid.

The barrier fluid is supplied until the level of barrier fluid is above the production packer PP or a required length for plugging off the reservoir has been established. The barrier fluid may constitute one or two barrier elements based on the length and the integrity.

It should also be noted that the arrows in fig. 3c is showing how the fluid is supplied from the vessel. Here, there is no return fluid.

An alternative embodiment, includes installation of a the second mechanical barrier at a later stage, as will be described further in detail below.

It is now referred to fig. 4a. Here, the production tubing PT is cut at a cutting location indicated by line X. Preferably the cutting location X is provided below the tubing hanger TH and below the top of the well head WH. Preferably, the cutting location X is above the downhole safety valve DHSV of the production tubing PT.

If the production PT is cut too deep, this may cause trouble with handling the tree HXT topside on the vessel, as a part of the production tubing will then protrude from the tree HXT. If the production PT is cut too shallow, a well head casing plug may not be set in the well head (as will be described further in detail below).

The cutting operation may be performed by means of a tubing cutting tool run on wireline through the pressure control equipment PCE. Preferably, the tubing cutting tool is also cutting the control Iine(s) outside of the production tubing PT. These control Iine(s) are used to control the down hole safety valve DHSV and transfer signals or fluids to other downhole completion equipment installed in the well. Again, if these control line(s) are not cut properly, the control line will snap during the later elevation of the tree HXT to surface, however, the control line stump(s) may cause problems for the subsequent setting of a well head casing plug and recovery of the remaining production tubing PT.

After the cutting operation, the tension in the production tubing PT will be removed, as the production tubing PT is no longer hanging from the tubing hanger. The weight of the production tubing PT below the cut is also considerable. Hence, the uppermost part of the cut production tubing will be displaced a distance downwardly into the well. The distance will of course be dependent on the length and weight of the production tubing, well path, friction and other factors, but in most wells it is believed that the displacement distance will be from ca 40 - 250 cm.

If both the first and second barriers have been set, as in alternatives 1 and 2 above, then the subsea tree including its well head connector WHC may be disconnected from the well head WH and may be elevated to the vessel as will be described with reference to fig. 5 below.

However, if only the first barrier has been set, as in alternative 3 above, then a second barrier must be set. In fig. 4c it is shown that a high expansion plug HEP is set in the production casing PC directly below the cutting location X. The production casing PC is the pipe provided radially outside the production tubing PT. Access to the production casing PC has been enabled due to the cutting operation. Hence, a double barrier has been established also for alternative 3.

It is now referred to fig. 5. Here, the horizontal Christmas tree HXT and its well head connector WHC is disconnected from the wellhead WH and is elevated up to the vessel VS. The subsea pressure control device PCE may be elevated from the seabed while connected to the tree HXT, alternatively the subsea pressure control device PCE is elevated in a separate operation.

As an additional option, a subsea pressure control device PCE may be connected to the well head WH after the removal of the tree HXT. Then a casing plug CP may be set in the well head WH through the subsea pressure control device PCE. Finally, the subsea pressure control device PCE may be disconnected and retrieved from the well head WH. In this way, a third barrier is established in the well.

All of the above operations may be performed by means of wireline and/or wireline tools by using a monohull vessel. A monohull vessel is a type of vessel håving only one hull, unlike multihulled boats which can have two or more individual hulls connected to one another. Such a monohull vessel may be a supply vessel, an IMR (Inspection, Maintenance and Repair) vessel, a RLWI vessel, etc. with sufficient equipment for Iowering/lifting the abovementioned equipment into/from sea, ROV control capacity, capacity for the fluid circulation device and the other equipment needed for performing the method according to the invention.

Hence, no rig is needed in order to remove the tree HXT from the well head WH.

It should be noted that for all of the different embodiments of the first, second and third barriers described above, a testing operation for testing the respective barriers may be performed by increasing the pressure in the production tubing by means of the subsea pressure control device PCE through the subsea hose (SH) connected to the vessel VS pump system.

In order to perform a re-completion of the well to start production again, or for a permanent plugging and abandonment of the well, also the remaining production tubing PT should be removed from the well. Here, a drilling rig is needed for installation of a drilling BOP (Blow-Out Preventer) onto the well head WH. The drilling rig must also be used to retrieve the production tubing up through the BOP and to the rig.

List of abbreviations used in drawines

Claims (9)

1. Method for removal of a subsea horizontal Christmas tree (HXT) from a wellhead (WH) of a subsea well, where a production tubing (PT) of the well is hung off in a tubing hanger (TH) provided in the horizontal Christmas tree (HXT), where the method comprises the steps of: a) connecting a subsea pressure control device (PCE) to the horizontal Christmas tree (HXT); b) establishing a first and a second barrier in the well; c) cutting the production tubing (PT) at a cutting location (X) below the tubing hanger (TH); d) disconnecting the horizontal Christmas tree (HXT) from the wellhead (WH); e) elevating the horizontal Christmas tree (HXT) and the tree running tool (TRT) from the well head (WH).

2. Method according to claim 1, where the above steps a) - c) are performed by a wireline and/or wireline tools.

3. Method according to claim 1 or 2, where the above steps a) - e) are performed by a monohull vessel.

4. Method according to any one of the above claims, where the method further comprises the step of setting a casing plug (CP) in the well head (WH) above the tubing hanger (TH) after step e).

5. Method according to claim 4, comprising the steps of; - connecting a subsea pressure control device (PCE) to the well head (WH); - setting the casing plug (CP) in the well head (WH) through the subsea pressure control device (PCE); - testing the integrity of the casing plug (CP); - disconnecting the subsea pressure control device (PCE) from the well head (WH).

6. Method according to any one of the above claims, comprising the following step after step c): - setting a high expansion plug (HEP) in a production casing (PC) directly below the cutting location (X).

7. Method according to claim 6, where the step of setting the high expansion plug (HEP) is establishing the second barrier.

8. Method according to claim 7, where the step of establishing the first barrier is performed by setting a mechanical barrier plug (MP) below the cutting location (X) before step c).

9. Method according to any one of the above claims, where step c) further comprises: - cutting of control lines provided radially outside of the production tubing (PT) at the cutting location.