Well tool

Abstract

The invention concerns a method for installing tubing in a well as well as a well tool. The method enables pressure testing before completing the installation. The invention also concerns an assembly for controlling the operation that is directly connected to the tool and arranged to be located below the BOP.

Description

[0001] Well Tool

[0002] The present invention relates to a method for the installation of a tubing hanger in a subsea well.

[0003] The invention also relates to an installation tool.

[0004] When developing subsea hydrocarbon reserves a hole is drilled from into the seabed to a hydrocarbon producing formation. During the drilling process successive layers of pipe called casing, is installed into the borehole to isolate the well from the surrounding formations and to protect against oil spills. The well is completed by installing production tubing. The completion comprises a tubing hanger that is typically mounted in a production adapter base or in a tubing head spool which is mounted on the wellhead.

[0005] To install the tubing, it is attached to a tubing hanger running tool which is suspended from a drill string. The assembly is lowered down through a marine riser which extends from a drilling rig and is at its lower end connected to a blowout preventer (BOP) stack mounted on top of the wellhead, until the tubing hanger is landed in the internal profile of the production adapter base.

[0006] A BOP is equipped with a number of pipe rams and shear rams. In an emergency situation, the shear rams can be operated to sever a pipe and seal the well bore to allow the drill string to be withdrawn from the riser. The pipe rams (also called isolation valves are designed to seal around a pipe in the BOP and used for example to isolate the well in case of pressure buildup in the well. BOP's can exist having various length and with many different configurations of rams. This is known for persons skilled in the art.

[0007] In completion operations a special pipe called a slick joint is normally coupled between the tool (in this case a tubing hanger running tool or THRT) and the drill string. The slick joint will be located within the BOP isolation valves and is designed to facilitate BOP operations during an emergency.

[0008] In applicants Patent Application NO 2022 0537 there is described a control system for installing or pulling a production tubing and its tubing hanger. The control system consists of a number of modules arranged around the drill pipe above the slick joint and comprises an energy storage module such as a battery, an electric motor module powered by the battery that provides hydraulic fluid and a control valve module routing hydraulic fluid from the pump and a data processing module (19) controlling the operation. The hydraulic fluid is routed through lines in the slick joint from the pumps to the functions in the THRT (and the well).

[0009] However, there is scope for improving the operation by locating the control system just above the running tool. This will result in shorter lines for the supply of hydraulic fluids to the tool. This will eliminate problems with long hydraulic lines, such as pressure loss. It also results in a slick joint that can be made with none or only a few lines running through or, in the case of a fully automated system, be eliminated altogether. With this locating of the control system, it is possible to perform various tests before final installation of the tubing hanger. To enable a compact installation string the electrohydraulic control system is located in an area where high pressure testing is required. In its location it controls hydraulic functions that are located both in pressurized and non-pressurized area (static head pressure).

[0010] The advantage of the invention is that it enables better control over the installation. During the installation process it enables precise orientation of the TH and also enables pressure testing of the system to ensure a correct installation.

[0011] In the method according to the invention the assembly is lowered to the wellhead and partly seated before rotation. This makes it possible to verify the position of the tool before rotating and connection. After this the assembly is raised slightly to enable rotation of the assembly to enable correct orientation before the tubing hanger is lowered again and installed on the wellhead.

[0012] The present invention concerns a method for installing tubing in a subsea well. The tubing comprises a slick joint and an assembly consisting of a tubing hanger running tool, THRT, and a control unit comprising at least one pump, a hydraulic reservoir and at least one valve for routing hydraulic fluid from the at least one pump to functions in the THRT. The method comprises the following steps of: lowering the assembly to the wellhead, such that the top of the control unit is below the blowout preventer, BOP, landing out the assembly, closing a pipe ram around the slick joint, raising the assembly until the top of the control unit abuts the pipe ram, orienting the tubing hanger, TH, to its correct position, lowering the assembly to sit or place the TH in or on top of the wellhead, and pressure testing the installation.

[0013] The method can further comprise: using a soft-land piston, and measuring the pressure build-up during landing via the control unit in order to find the vertical positioning of the THRT.

[0014] The method can further comprise the step of using the pump (the at least one pump) to direct hydraulic fluid to the functions to be tested.

[0015] The method can further comprise the step of placing a friction plate between the THRT and the pipe ram.

[0016] The method can further comprise the step of pressuring up the space below the pipe ram in order to verify the connection between the TH and the wellhead. The invention concerns also a well tool for installation of a tubing hanger in a subsea well, comprising a control unit having at least one battery supplying electric power to at least one pump, at least one reservoir for hydraulic fluid connected to the suction side of the at least one pump, a number of directional control valves controlling the supply of hydraulic fluid from the pump to functions in the well tool, and a data processing unit controlling the operation, wherein the control unit is located below a BOP isolation valve and attached directly to the well tool.

[0017] The well tool can further comprise a slick joint located inside the BOP and connected to the tool.

[0018] The well tool can further comprise an orientation tool connected to the slick joint.

[0019] The well tool can further comprise a friction plate located between the THRT and the pipe ram.

[0020] The control valves can comprise piezo-electric actuators.

[0021] The data processing unit can comprise a data storge unit.

[0022] The data processing unit can further be configured to perform operations diagnostics.

[0023] The control unit can further comprise means for communication with a topside facility.

[0024] The well tool can further comprise a header distributing hydraulic fluid from the pump to the control valves.

[0025] An advantage of the present invention is that it allows pressure testing of both the tubing hanger to wellhead seal and of the various functions in the assembly.

[0026] In the preferred embodiment of the invention the control unit is located beneath the BOP isolation valves and in direct contact with the THRT.

[0027] In an aspect of the invention the control unit is connected to a slick joint that extends through the isolation valves to above the BOP.

[0028] In another aspect of the invention an orientation tool is connected to the top of the slick joint.

[0029] In yet another aspect of the invention the control unit comprises a data processing unit that can perform system diagnostics.

[0030] The invention shall now be described in more detail while referring to the enclosed drawings, where:

[0031] Fig. 1 is a drawing showing the invention in a subsea well,

[0032] Fig. 2 is a drawing showing the Tool according to the invention,

[0033] Fig. 3 is a section through the system showing a friction (isolation) plate in a first position,

[0034] Fig. 4 is a section through the system showing the pressure plate in a second position, Fig. 5 shows the pressure plate, and

[0035] Fig. 6 shows the areas during pressure testing.

[0036] In Fig. 1 there is shown a tubing hanger installation according to the present invention. A marine riser 1 is suspended from a drilling rig and at its end have a flex joint 2 connected to a BOP 5. The BOP 5 sits on top of the wellhead 11. The BOP includes a number of shear rams 8 and pipe rams 8a as it is known in the art. A tubing hanger running tool 9 (THRT) is shown having been lowered from the drilling rig suspended on a drill pipe 4. The running tool includes a tubing hanger (TH) 10 attached to the THRT 9.

[0037] A control unit 20 is attached to the upper end of the THRT. This will be described in more detail below.

[0038] A slick joint 12 extends through the BOP 5. At its lower end it is connected to the control unit 20. During operations it will be located within the BOP such that the pipe rams can be closed around the slick joint, if necessary, in order to isolate the lower part of the well.

[0039] A tubing hanger orientation tool 7 is located on top of and attached to the slick joint 12. This is preferably be the type disclosed in our co-pending application NO 2023 1224.

[0040] Referring now to Fig. 2 the control unit 20 is shown in more detail.

[0041] The control unit is preferably machined out from a solid block with spaces machined out for the various components as well as bores for the supply of hydraulic fluid and / or electrical lines. This construction makes the control unit more compact and able to withstand the higher well pressure. This again facilitates pressure testing of the assembly, as described below.

[0042] In one of the spaces in the unit 20 there are located batteries 23 and 24. However, while there is shown two batteries there may be more than two batteries as this number is governed by the capacity of the battery and the operational power need. Preferably the batteries include means for registering its status such as state of charge and can report any faults to the main server computer. The batteries supply power to one or more electric pumps 27 and 28.

[0043] A data processing unit 25 is prefer ably located close to the batteries. The unit oversees and controls the operation. Power cables 19 connects the batteries with pumps.

[0044] In another space in the unit 20 is located a hydraulic reservoir 26. This can be a simple reservoir or may be an accumulator storing fluid under pressure.

[0045] Pumps 27, 28 powered by the batteries has an inlet side connected to the reservoir and outputs hydraulic fluid under pressure to power functions in the installation tool. In a preferred embodiment there may be two pumps such that each pump can deliver fluid at different pressures. The output from the pumps is routed through pipes 31 and into bores (not shown) in the unit and to a header (not shown).

[0046] A control valve pack 29 comprises a number of individual valves clustered around the lower part of the unit 20. Hydraulic fluid from the pumps is supplied to thew header and then routed through the control valves and through lines 32 to functions in the tool or to downhole devices.

[0047] Preferably, each control valve comprises a piezo-electric actuator. This enables very fine control of the valve openings. Therefore, the valves can be used to deliver hydraulic fluid at different pressures.

[0048] Instead of having the master control system and the hydraulic power unit on the rig, all the necessary parts of the control system are now located close to the THRT.

[0049] The data processing module 25 monitors and controls the various parts of the unit and the running tool, including the electric motors. It is also powered by the battery. There are in addition communication lines extending into the well that is also controlled and monitored by the processing module. A data storage unit is incorporated in the processing module. Signals that for example register data from the system and the well as regards to pressure and temperature readings are stored in the storage unit.

[0050] The processor is preferably capable of taking autonomous actions based on pre-defined system triggers such as loss of communication or sudden increase or decrease of pressure in a line.

[0051] The tool can be put in deep sleep mode while the operation is held by trouble shooting or any other cause not directly related to the operation such as the need for disconnect in case of bad weather, this feature intends to reduce power consumption to its minimum to save battery for when the operation resumes.

[0052] In an emergency situation, for example in case communication is totally lost, the tubing hanger running tool can be unlocked from the tubing hanger so the tool can be retrieved to topside and can be fixed before the next try.

[0053] Before operations the unit 20 is assembled and connected to the THRT. When fully assembled the operator tests the unit by starting up the pumps and pressurize the system to the desired pressure. At this point, the valve control modules are fed with the operation specific pressure and can release the pressure to the tubing hanger running tool.

[0054] The full assembly including the tubing and tubing hanger (TH) is tested and lifted to the rig catwalk to be lowered into the well and landed inside the BOP.

[0055] The assembly has a soft-landing system (e.g. comprising a soft-land piston) that uses a pneumatic damper. This is known in the art. When landing in the wellhead there will be pressure build up which is recorded. The pressure reading relates to the position of the damper, and this enables the operator to verify the vertical position of the assembly.

[0056] In Fig. 3 there is shown the situation when the assembly has been landed. The slick joint 12 is located within the BOP 5. A friction cover 40 in the form of a cap or hood is located at the top of the control unit 20. The cover may be furnished in two parts 41, 42 held together with a screw 43 to facilitate assembly, as shown in Fig. 5. Preferably the friction cover is designed to rotate in relation to the pipe ram 8a. After the assembly has landed there is a gap 44 between the top of the friction cover and the underside of the upper pipe ram 8a as shown in Fig. 3. The pipe ram 8a is now closed around the slick joint 12 to isolate the assembly from the area above the ram. The assembly is now raised until the TH is clear of the wellhead. This closes the gap 43 and the top of the friction plate now abuts the underside of the pipe ram 8a. This is the position shown in Fig. 4.

[0057] In an alternative embodiment a slick joint is not used and the assembly is connected to the drill string.

[0058] The assembly is now rotated to its proper alignment for placing the TH in the wellhead. This is preferably done using the orientation tool 7. Alternatively, it may also be rotated from the surface by using the rig rotary. The use of the friction cover ensures that no damage is done to either the pipe ram or the control unit.

[0059] The area below the pipe ram is designated a high-pressure area. The next step is therefore to pressure test the TH to wellhead seal. This pressure test is conducted by pressurizing below the pipe ram 8a that seal against the slick joint 12.

[0060] In Fig. 5 there is shown the situation during the pressure testing. The TH 10 has been properly seated in the wellhead 11 and the pipe ram 8a has closed around the slick joint 12.

[0061] To secure that hydraulic functions located in the pressurized area are not influenced by the higher pressure, it is configured such that the supply and return delta pressure follows the pressurized area 50.

[0062] To protect over pressurizing external functions located outside (above or under) the pressurized area during pressure testing, the external functions are referenced to R2 which is the static head pressure.

[0063] The pump 27 (28) draws fluid from the reservoir 26. The reservoir is preferably a flexible bladder and is also the connection for the return R1 that is located in the high-pressure area. The reservoir provides fluid to the pump and therefore the input pressure to the pump is also referenced to the ambient pressure on the reservoir and return Rl. A header C or similar routes hydraulic pressure to the various functions (shown as F in the figure).

[0064] The system then tests said functions F. From the rig computer, the operator opens the required valve(s) in the control unit to pressurize the desired tubing hanger running tool functions F. The down hole sensors will also be visible at the operator.

[0065] The selection of return can be performed by installing a Rl or R2 logic plug depending on if the function is located in the high-pressure area or outside the high-pressure area.

[0066] The operation continues until all pressurization / bleed steps are completed. The battery status is monitored the whole time by the ROCS operator.

[0067] When the tubing hanger is installed, the unit is set in retrieve mode and the rig operator can pull the stack-up. The present invention is not restricted to the embodiments described above and a person of skill in the art will realize that there may be many modifications that can be made without departing from the basic idea of the invention.

Claims

CLAIMS1. Method for installing tubing in a subsea well, comprising a slick joint (12) and an assembly consisting of a tubing hanger running tool, THRT, (9) and a control unit (20) comprising at least one pump (27, 28), a hydraulic reservoir (26) and at least one valve for routing hydraulic fluid from the at least one pump (27, 28) to functions in the THRT (9), comprising the following steps of:- lowering the assembly to the wellhead (11), such that the top of the control unit (20) is below the blowout preventer, BOP, (5),- landing out the assembly,- closing a pipe ram (8a) around the slick joint (12),- raising the assembly until the top of the control unit (20) abuts the pipe ram (8a),- orienting the tubing hanger, TH, (10) to its correct position,- lowering the assembly to sit or place the TH (10) in or on top of the wellhead (11), and- pressure testing the installation.

2. Method according to claim 1, comprising using a soft-land piston, and measuring the pressure build-up during landing via the control unit (20) to find the vertical positioning of the THRT (9).

3. Method according to claim 1 or 2, comprising the step of using the pump (27) to direct hydraulic fluid to the functions (F) to be tested.

4. Method according to any previous claim, comprising the step of placing a friction plate between the THRT (9) and the pipe ram (8a).

5. Method according to any previous claim, comprising the step of pressuring up the space below the pipe ram (8a) to verify the connection between the TH (10) and the wellhead (11).

6. Well tool for installation of a tubing hanger (10) in a subsea well, comprising a control unit (20) having at least one battery (23, 24) supplying electric power to at least one pump (27, 28), at least one reservoir (26) for hydraulic fluid connected to the suction side of the at least one pump, a number of directional control valves (29) controlling the supply of hydraulic fluid from the pump (27, 28) to functions in the well tool, and a data processing unit (25) controlling the operation, characterized in that the control unit (20) is located below a BOP isolation valve (8) and attached directly to a tubing hanger running tool, THRT, (9).

7. Well tool according to claim 6, characterized in that it further comprises a slick joint (12) located inside the BOP (5) and connected to the tool.

8. Well tool according to claim 6 or 7, characterized in that it further comprises an orientation tool (7) connected to the slick joint (12).

9. Well tool according to any one of claims 6-8, characterized in that it further comprises a friction plate (40) located between the THRT (9) and the pipe ram (8a).

10. Well tool according to any one of claims 6-9, characterized in that the control valves (29) comprise piezo-electric actuators.

11. Well tool according to any one of claims 6-10, characterized in that the data processing unit (25) comprises a data storge unit.

12. Well tool according to any one of claims 6-11, characterized in that the data processing unit (25) is configured to perform operations diagnostics.

13. Well tool according to any one of claims 6-12, characterized in that the control unit (20) comprises means for communication with a topside facility.

14. Well tool according to any one of claims 6-13, characterized in that it further comprises a header distributing hydraulic fluid from the pump (27, 28) to the control valves (29).

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