Patent Application
20230399913
This invention concerns a device and a method for installing a production tubing and an associated tubing hanger (TH) in a subsea wellhead or a subsea horizontal X-mas tree.
More specifically it concerns a tool that should be operable without the use of hydraulic cables from the surface and without the need for hydraulic valves for controlling the functions. The invention concerns a method for operating the tool: coupling it to a tubing hanger before installation, locking a tubing hanger in a subsea wellhead or X-mas tree, verifying locking and disconnecting the tool from a locked tubing hanger.
Traditionally, subsea tools for well completion have been hydraulically operated from the surface via hydraulic cables in a twisted hose bundle with an external, reinforced jacket, also called hydraulic umbilicals, which are clamped to a work string. The work string, which can consist of connected drill pipes or riser joints, will typically vary between an inner diameter of 75 mm (3″) and 180 mm (7″). The dimension of the umbilical typically varies between an outer diameter of 70 and 100 mm.
In the well completion phase, the drilled well is provided with a production tubing that is in a stepwise manner made up of pipe joints and lowered down into the well. The equipment is lowered down through a marine riser that is hanging from a drilling vessel and is coupled to a subsea blowout preventer (BOP) on the seabed. The BOP can be locked to a wellhead or X-mas tree that is locked to a wellhead.
The marine riser, typically with an outer diameter of 535 mm (21″), projects up from a lower marine riser package (LMRP) on the BOP to the underside of the drill deck of the vessel, and is filled with drilling or completion fluid that is in connection with the well.
The upper end of the production tubing and hydraulic lines for controlling a downhole valve are coupled to the underside of a tubing hanger, which at its upper end is coupled to a tubing hanger running tool (THRT).
It is currently common to use a simplified landing string when installing a tubing hanger. In this case, the work string will consist of drill pipe joints. The work string can also be a work-over riser if the tubing hanger running tool forms a lower part of a complete landing string, which in addition to a slick-joint with inner bores and a pipe joint that can be sheared with the BOP's shear ram, is an assembly of well barrier valves. This tool system can be used if the well is to be flowed to a test separator aboard the drilling vessel in connection with cleaning of the well after perforation of the production tubing in the well.
The simplified landing string typically consists of a drill pipe joint adapted to the BOP, various hydraulic pipes and a slick-joint with inner bores for coupling hydraulic pipes to the tubing hanger running tool at the lower end and pipe connections for coupling an umbilical at the upper end. The umbilical is clamped to the work string as the equipment is lowered down through the riser. Finally, the tubing hanger is rotated into landing position by means of orientation grooves before it is landed and locked in a locking groove in the wellhead or in a X-mas tree. The simplified landing string is arranged so that the transition pipe is placed directly above one of the BOP's pipe rams, which can be made to clamp about it in a sealing manner.
For tool systems and well equipment being operated at depths down to 500 m, direct hydraulic actuation from the surface is commonly used, which is controlled with directional control valves with hydraulic fluid being supplied from the control system's hydraulic power unit (HPU). Hydraulic outlets from the control system are connected to the tool system through surface distribution and umbilical systems. Subsea control modules with directional control valves for actuating functions have been developed for deep waters and operation of tool systems with many functions. The control module is installed on the top side of the tool system. This reduces response time and how many hydraulic umbilical lines are needed.
The umbilical and the associated clamps for the work string are exposed to damage inside the marine riser in that they can be squeezed between the work string and the inside of the marine riser when the vessel and the marine riser move due to external environmental loads like waves and ocean currents. Potential damages to the umbilical and the consequences of loose parts from damaged clips falling down through the riser to the BOP, constitute a significant risk of lost productive rig time. Great water depths will make the problems and the financial consequences of such events worse.
Due to said and other disadvantages of clamping the umbilical to the work string and the advantages a tool system without an umbilical will have;—increased efficiency, lesser damage potential for the completion string and personnel, lower equipment costs etc.—an alternative solution has been developed that will be operable without hydraulic directional control valves and an umbilical from the surface.
Prior art for landing strings shows them being provided with a secondary system for operating emergency functions. The system consists of a module with hydraulic shuttle valves that are normally open for actuating tool functions via the primary hydraulic system, but in an emergency can switch to operating selected tool functions with completion fluid. Burst disks that form part of the secondary system burst in a predetermined sequence as the pressure is pumped up in a closed annulus in the BOP that surrounds the valve module. The annulus is pressurised from the surface via existing pipe connections, so-called choke and kill lines, that are otherwise used actively in well control situations. Pressurised completion fluid penetrates through the ports with the burst disks and activates selected functions via the shuttle valves in the valve module.
From patent literature the following is cited as background art:
US2005217845A1 describes a solution where completion fluid is pressurised in a closed annulus in a BOP through kill/choke lines to the surface. Pressurised completion fluid is distributed as hydraulic supply to a subsea control module. The control module is provided with electrically activated directional control valves that via communication from the surface are commanded to pressurise hydraulic outlets of control lines that distribute fluid for actuating the tool functions of a lower landing string assembly (LLSA) and the associated tubing hanger running tool/tubing hanger. The tool system can thereby be of a standard type, i.e. hydraulically operated, corresponding to that which is operated from the surface via an umbilical. One difference is that completion fluid is used instead of pure hydraulic fluid, with the challenges that this entails.
US2013175045A1 describes a closed hydraulic system with accumulators that supply hydraulic fluid to directional control valves in a control module. The pressure in the hydraulic system can be recharged when the supply pressure becomes too low to carry out further tool operations. At least one hydraulic piston pump charges the hydraulic accumulators. The pump is driven by pressurised completion fluid from a closed annulus in a BOP connected to the surface via kill/choke lines.
WO2019004842A1 describes a solution where a bladder functioning as a hydraulic reservoir is disposed in a closed annulus in a BOP. The annulus is connected to the surface via kill/choke lines. When the annulus is pressurised, the bladder is squeezed and supplies hydraulic fluid to a control module with directional control valves to actuate tool functions.
US2011/0247799A1 describes a method for installing a production tubing and a tubing hanger in a subsea wellhead or X-mas tree wherein the apparatus comprises an upper transition pipe coupled to a work string, a lower centre element with a through-going centre passage and several hydraulic channels, a housing that surrounds the upper part of the centre element, an expandable locking ring for locking the centre element to an internal groove in the tubing hanger, a ring piston that surrounds the central part of the centre element and is arranged to expand the locking ring, and locking balls or gripping fingers that can engage with the locking sleeve when they are being radially displaced. Shearable locking pins arranged for locking movable components that surround the centre element are not described. Also not described herein is a housing that surrounds the lower part of the centre element and that is provided with threads that can engage with external threads on the centre element.
The purpose of the invention is to eliminate the need for an umbilical from the surface for hydraulic supply and control of tool functions in subsea well completion, as well as the need for controlled directional control valves for hydraulic actuation of the tool functions.
The purpose is fulfilled by features specified in the description below and subsequent patent claims.
According to a first aspect of the invention, a tubing hanger running tool provided with hydraulic function pistons for operating functions by means of pressurised completion fluid is provided, as well as devices for mechanically releasing the apparatus from a locked tubing hanger.
According to a second aspect of the invention, a method is provided for installing a tubing hanger in a wellhead or X-mas tree using the tubing hanger running tool according to the first aspect of the invention on the surface, and pressurising ring piston functions by means of surrounding completion fluid in isolated annuli in a BOP for actuating tool functions in connection with locking the tubing hanger in the wellhead or the X-mas tree.
The method may comprise verifying locking of a tubing hanger by registering a pressure drop in the annulus via channels in the tubing hanger running tool that open to the top side of the isolated annulus after the ring pistons have completed their stroke and the tubing hanger is locked.
The method may also comprise releasing the tubing hanger running tool from a locked tubing hanger. Rotation of the work string from the surface results in devices in the apparatus being screwed out of locked engagement with the tubing hanger.
Also provided are alternative methods for releasing the tubing hanger running tool from the locked tubing hanger. A ring piston that keeps the apparatus locked to the tubing hanger via a locking ring, is pushed back via pressurisation from the underside with a fluid from the surface supplied via the work string. The fluid flows through channels in an installed plug in the centre element of the apparatus and further through a side channel in the centre element with an outlet to the underside of the ring piston. Alternatively, the fluid is pressurised from a pressurised annulus in the BOP and distributed to the underside of the ring piston via a deep-hole bore in the tool.
In its first aspect, the invention more specifically concerns a tubing hanger running tool arranged for installing a production tubing with a tubing hanger in a subsea wellhead or in a subsea X-mas tree, characterised in that the tubing hanger running tool comprises:
In its second aspect, the invention more specifically concerns a method for installing a tubing hanger in a wellhead or X-mas tree (9) using the tubing hanger running tool according to the first aspect of the invention, characterised in that before the tubing hanger is installed in the wellhead or the X-mas tree, the tubing hanger running tool is coupled to the tubing hanger through the following steps:
The method may comprise these further steps for locking the tubing hanger to the wellhead or the X-mas tree:
The method may comprise these further steps for verifying locking of the tubing hanger to the wellhead or the X-mas tree:
The method may comprise these further steps for pressure testing the tubing hanger after it has been installed in the wellhead or the X-mas tree:
The method may comprise steps for disconnecting the tubing hanger running tool from the tubing hanger after the tubing hanger has been installed in the wellhead or X-mas tree:
Alternatively, the method for disconnecting the tubing hanger running tool from the tubing hanger after the tubing hanger has been installed in the wellhead or the X-mas tree can comprise the steps of:
In the following, a device and a method for tubing hanger installation in a wellhead or X-mas tree is described, wherein:
In
The present solution is based on hydraulic energy for operating the tool functions being supplied through pressurisation of a lower, closed-off annulus 25 and an upper, closed-off annulus 27 in the BOP 2 via a choke line 29 or kill line 31 to the surface. The annuli 25, 27 are formed by the BOP's pipe rams closing about parts of the landing string 1. Hydraulic pistons that are integrated with a tubing hanger running tool 3 are exposed to confined pressure in the annuli 25, 27 and are arranged to actuate certain function for the tubing hanger running tool/tubing hanger, while other functions are activated mechanically by rotation of the work string 15 from the surface.
The tubing hanger running tool 3 is built up of different ring pistons and an upper housing 37 and a lower housing 39 that surround a centre element 41. This is shown in
Coupling of the tubing hanger running tool 3 and the tubing hanger 5 is done by the lower part of the centre element 41 with the lower housing 39 being inserted into the tubing hanger 5 with anti-rotation elements 43 oriented relative to corresponding locking grooves in the tubing hanger 5. When the tubing hanger running tool 3 reaches an end stop in the tubing hanger 5, a first ring piston 45 is actuated hydraulically via a first bore 47 that runs axially through the upper part of the centre element 41. A number of spring-loaded locking pins 49 jump into an external groove on the first ring piston 45 when it has been displaced to its end position, and concurrently the lower part of the first ring piston 45 pushes the locking ring 51 out into engagement with a corresponding locking groove on the inside of the tubing hanger 5. Thereafter, a second ring piston 53 is pushed towards the tubing hanger 5. The front end of the second ring piston 53 pushes a number of locking balls 55 partially out through corresponding holes in a third, outer ring piston 57 on the tubing hanger running tool 3. The balls 55 engage with the underside of an inner lip on the upper locking sleeve 61 of the tubing hanger 5. When the second ring piston 53 is displaced to its end position, a number of spring-loaded locking pins 59 jump into corresponding, recessed holes on the back end of the third, outer ring piston 57 and lock the second and third ring piston 53, 57 together. Thereafter, a second bore (not shown) that runs axially through the upper part of the centre element 41 is pressurised. The bore is in connection with an annulus 63 between the second ring piston 53 and the upper housing 37. Pressurising the annulus 63 leads to the ring pistons 53, 57 being pushed somewhat back and pulling with them a locking sleeve 61 for the tubing hanger 5 until the locking sleeve 61 meets an end stop. A number of locking pins 65 is thereafter mounted through bores from the outside of the second ring piston 53 and into corresponding, recessed holes in the upper housing 37, so that the second and the third ring piston 53, 57 and the locking sleeve 61 of the tubing hanger 5 are locked in the upper position.
Reference is made to
Reference is made to
As shown in
The tubing hanger 5 is thereby locked to internal locking grooves in the wellhead 7 or the X-mas tree 9.
As shown in
After the tubing hanger 5 has been locked in the wellhead 7 or the X-mas tree 9, the lower BOP pipe ram 73 is opened as the first step in pressure testing the tubing hanger 5 from above. A second pipe ram 81 is then closed sealingly about the transition pipe 33 of the landing string 1 to the work string 15. The annulus in the BOP under an upper pipe ram 81 is then pressurised via the choke line 29. A stable pressure, verified on the surface, indicates that the seal is working.
Reference is made to
The primary method for releasing the tubing hanger running tool 3 from the tubing hanger 5 is to twist the work string 15 to the right so that a set of locking pins 85, which attach the centre element 41 to the lower housing 39, are sheared off and allow for the centre element 41 to be screwed upwards in the threaded portion 83 in the lower housing 39. The devices on the upper part of the tubing hanger running tool 3 rotate with the centre element 41. The first ring piston 45, which keeps the locking ring 51 stretched out and in engagement with locking grooves on the inside of the tubing hanger 5, is screwed upwards until it clears the locking ring 51, which then springs back and disengages from the locking grooves in the tubing hanger 5. The locking ring 51 stays on top of the lower housing 39. Thereby the tubing hanger running tool 3 can be pulled out of the tubing hanger 5 and up to the surface, as illustrated in
The tubing hanger running tool 3 is thereby released from the tubing hanger 5 and can be hoisted in a stepwise manner to the surface with the work string 15.
Necessary seals are not described, but are known to a skilled person.
| Number | Date | Country | Kind |
|---|---|---|---|
| 20201191 | Oct 2020 | NO | national |
This application is the U.S. national stage application of International Application PCT/NO2021/050215, filed Oct. 18, 2021, which international application was published on May 5, 2022, as International Publication WO 2022/093033 in the English language. The International Application claims priority of Norwegian Patent Application No. 20201191, filed Oct. 30, 2020. The international application and Norwegian application are both incorporated herein by reference, in entirety.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/NO2021/050215 | 10/18/2021 | WO |
