NO347890B1 - An apparatus, a system, and a method for umbilical-less installation and operation of a tubing hanger - Google Patents
An apparatus, a system, and a method for umbilical-less installation and operation of a tubing hanger Download PDFInfo
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- NO347890B1 NO347890B1 NO20230196A NO20230196A NO347890B1 NO 347890 B1 NO347890 B1 NO 347890B1 NO 20230196 A NO20230196 A NO 20230196A NO 20230196 A NO20230196 A NO 20230196A NO 347890 B1 NO347890 B1 NO 347890B1
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- tubular body
- fluid
- line selector
- selector sleeve
- string
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- 238000009434 installation Methods 0.000 title claims description 26
- 238000000034 method Methods 0.000 title claims description 14
- 239000012530 fluid Substances 0.000 claims description 112
- 238000004891 communication Methods 0.000 claims description 32
- 238000009826 distribution Methods 0.000 claims description 9
- 230000004044 response Effects 0.000 claims description 7
- 238000012360 testing method Methods 0.000 claims description 7
- 238000012544 monitoring process Methods 0.000 claims description 3
- 238000007667 floating Methods 0.000 claims description 2
- 238000005553 drilling Methods 0.000 description 15
- 230000006870 function Effects 0.000 description 9
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 5
- 238000006073 displacement reaction Methods 0.000 description 4
- 241000191291 Abies alba Species 0.000 description 3
- 230000000694 effects Effects 0.000 description 3
- 238000002955 isolation Methods 0.000 description 3
- 238000004519 manufacturing process Methods 0.000 description 2
- 230000013011 mating Effects 0.000 description 2
- 238000013459 approach Methods 0.000 description 1
- 230000000712 assembly Effects 0.000 description 1
- 238000000429 assembly Methods 0.000 description 1
- 230000021615 conjugation Effects 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 239000007788 liquid Substances 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
- 230000001105 regulatory effect Effects 0.000 description 1
- 230000000284 resting effect Effects 0.000 description 1
- 238000007789 sealing Methods 0.000 description 1
- 230000001360 synchronised effect Effects 0.000 description 1
- 230000000007 visual effect Effects 0.000 description 1
Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/04—Casing heads; Suspending casings or tubings in well heads
- E21B33/043—Casing heads; Suspending casings or tubings in well heads specially adapted for underwater well heads
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
- E21B23/04—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
Description
AN APPARATUS, A SYSTEM, AND A METHOD FOR UMBILICAL-LESS INSTALLATION AND OPERATION OF A TUBING HANGER.
This invention relates to an apparatus for use in a system for umbilical-less installation, operation and function test of a tubing hanger, a system comprising the apparatus and a method using the apparatus for umbilical-less tubing hanger (TH) installation into a subsea wellhead from a drilling vessel.
More specifically, the apparatus according to the invention is configured to be connected to the top of a tubing hanger running tool (THRT) for operating the THRT and the TH.
Within the field of subsea oil and gas production, installing a valve tree on a subsea wellhead is known. Distinguishing between vertical valve trees, “Vertical Christmas Tree,” on one hand, and “Horizontal Christmas Tree” on the other hand is known. In the following, a vertical valve tree will be referred to using the abbreviation VXT, and a horizontal valve tree will be referred to using the abbreviation HXT. The tubing hanger (TH) will in the VXT scenario be installed into the wellhead, (or into an intermediate adapter unit to the wellhead), prior to the VXT installation, while a HXT will first be installed onto a wellhead, and during subsequent well completion operations, the TH will be oriented, landed and locked into a central cavity of the HXT.
A tubing hanger running tool (THRT) is known technology, typically operated from a Workover Control System, (WOCS) onboard a drilling vessel, via a so-called umbilical during running or retrieval of a well tubing string. During operation, the THRT is latched onto the upper end of the TH and carries the weight of the tubing string when it is suspended from a work-string inside a marine drilling riser that hangs from a drilling vessel and is coupled to a subsea blowout preventer (BOP) at the seabed. The TH is landed into a wellhead, an intermediate adapter unit, or into an HXT, depending on the valve tree type that is used. Bores in the THRT form conduits for control fluid distribution to stab connectors between the bottom end face of the THRT and the top end face of the TH. In addition to holding the weight of the tubing string, the THRT is configured to actuate the tubing hanger lock function when the TH has been fully landed. When the TH has been locked in place, the THRT is un-latched and pulled back to the surface with the work-string.
Hydraulic lines and signal communication lines for downhole safety valves, other downhole functions, as well as downhole instrumentation are continuously clamped to the tubing string while it is lowered from the vessel drill-floor. During the final phase of deployment, a TH is connected to the top of the well tubing string. Thereafter, downhole control lines are connected to the bottom face of the TH, which is equipped with line feedthroughs.
A starting condition for subsea well completion with a VXT is that the BOP is locked onto the wellhead after the drilling operations. The TH is oriented, landed and locked into the wellhead. Production and annulus bores in the TH will be temporarily isolated to allow subsequent removal of the BOP and the marine drilling riser. With the BOP removed, the VXT is installed and connected onto the wellhead. The subsea well will eventually be perforated and cleaned via an open water workover riser system, connecting the top of the VXT to the drilling vessel.
Traditionally, subsea running and retrieval tools for well completion and well permanent plugging and abandonment (PP&A) have been operated from the surface, via hydraulic lines in a twisted hose bundle with an external, reinforced jacket. This is known in the subsea industry as a hydraulic umbilical. The umbilical and associated clamps along 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 damage to the umbilical, and the consequences of loose parts from damaged umbilical clamps falling through the drilling riser, to the BOP, constitute a significant risk of lost productive rig time. Problems and economic consequences of such incidents will increase with increasing water depth. Another negative aspect of deep and ultra-deep water is that the time consumed for preparations, and for running- and retrieval operations with clamping and un-clamping of the umbilical to/-from the work-string, will be significant.
US 9,435,164 B2 discloses a running tool and a method for umbilical-less tubing hanger installation. The tool includes several fluid passages which together with pistons create a closed-loop hydraulic system to lock the TH into a wellhead housing (WH). Locking of the tool is energized by pressure applied to the work-string bore. Tool un-latch is facilitated with a closed-in pressure, applied via a choke/kill connection of the BOP stack to the outside of the tool.
Umbilical-less TH installation for the VXT scenario disclosed in US 9,435,164 B2 is encumbered with a drawback in that, unlike the HXT scenario, valves and hydraulic lines cannot be checked for possible leakage from the valve tree, since the VXT is not yet in place. The consequence of possible leakage faults, only discovered after VXT installation, can be that the VXT and the tubing hanger must be pulled back to the surface, with severe loss of operation time and cost.
US 2018320470 A1 discloses a subsea system includes in-riser equipment, and a surrounding structure configured to be coupled to a marine riser and a subterranean well. The in-riser equipment is positioned within the surrounding structure, and the surrounding structure comprises a power connection extending radially therethrough. The system also includes a power supply located outside of the surrounding structure. The power supply is connected to the in-riser equipment via the power connection through the surrounding structure, to communicate with the in-riser equipment.
Publication US 2010224373 A1 discloses methods and systems relating to subsea wellhead orientation.
Publication US 2021140290 A1 discloses system that includes a reception interface that receives sensor data of an artificial lift system disposed at least in part in a well.
Publication US 2011247799 A1 discloses a system that includes a tubing hanger running tool configured to position a tubing hanger within a wellhead.
Publication GB 2448262 A discloses an electrically operated tubing hanger running tool.
The invention has for its object to remedy or to reduce at least one of the drawbacks of the prior art, or at least provide a useful alternative to prior art, wherein one of the drawbacks is related to possible undetected TH hydraulic line leakage after TH installation in a VXT well completion scenario. The object is achieved according to the invention, through the features specified below, and in the subsequent patent claims.
The invention is defined by the independent patent claims. The dependent claims define advantageous embodiments of the invention.
In a first aspect of the invention, an apparatus for use in a system for umbilical less installation, operation, and function test of a tubing hanger prior to subsea vertical valve tree installation, is provided. The apparatus comprises:
- a rotatable first tubular body having a first end portion for being made-up with a workstring, and a second end portion;
- a second tubular body provided with a guide for, in a position of use, receiving an alignment pin protruding from a BOP stack;
The stationary second tubular body is axially secured to the first tubular body via a connector, the second tubular body comprising
- a control fluid inlet and outlet fluid channels for communicating control fluid to a tubing hanger running tool, each of the outlet fluid channels having a radial bore for providing fluid communication through an in inner wall of the second tubular body and into the outlet fluid channel;
- a line selector sleeve threadedly connected to the second end portion of the first tubular body and provided with an alignment groove for engaging a protrusion of the second tubular body, whereby the line selector sleeve is controllable movable within the stationary second tubular body in response to a rotation of the first tubular body, the line selector sleeve comprising a bridging channel for communicating fluid between the control fluid inlet and at least one selected radial bore of the outlet fluid channels of the second tubular body. By the term line is meant a fluid channel.
By rotating the first tubular body, a position of the line selector sleeve within the stationary second tubular body is changed. By changing a position of the line selector sleeve within the stationary second tubular body, a pressurized fluid from the control fluid inlet can be communicated to at least one selected outlet fluid channel. Thus, in operation wherein the apparatus is connected to a tubing hanger running tool, (THRT) and a work-string as will be discussed below, a pressurized fluid entering the apparatus through the control fluid inlet may be switched between one or more desired pressure outlet channels and into mating fluid channels of the THRT by providing a rotation of the work-string.
Providing the second tubular body with a guide, facilitates alignment of the apparatus with the BOP stack, and a fluid communication from the BOP stack into the apparatus via the control fluid inlet of the stationary second tubular body.
The alignment groove may extend axially so that the line selector sleeve is prevented from rotating with respect to the second tubular body when the protrusion is in engagement with the axially extending alignment groove. By axially is meant in parallel with a longitudinal axis of the line selector sleeve. Thus, the effect of an axially extending alignment groove is that the line selector sleeve is moved axially only when the tubular body is rotated. In such an embodiment wherein the alignment groove extends axially, the line selector sleeve may be provided with a fluid groove encircling a portion of the line selector sleeve. The fluid groove is configured for being brought into fluid communication with at least one selected outlet channel. Such a fluid groove allows more than one outlet channel within the tubular body to be brought in fluid communication with the control fluid inlet.
As an alternative to providing an axially extending alignment groove as discussed above, the alignment groove may extend helically so that the line selector sleeve is rotated with respect to the second tubular body when line selector sleeve is displaced axially in response to rotation of the rotatable first tubular body. Thus, when the first tubular body is rotated, the line selector sleeve is both moved axially and rotated with respect to the second tubular body.
The apparatus may be provided with a fluid supply pipe being in fluid communication with the control fluid inlet and extending into the bridging channel of the line selector sleeve. Such a fluid supply pipe has the effect of bridging a gap between the second tubular body and the line selector sleeve when the line selector sleeve is displaced axially away from the first tubular body. To allow for a combined axial and rotational movement of the line selector sleeve with respect to the second tubular body, the fluid supply pipe may be in fluid communication with the control fluid inlet via a rotatable annular element arranged in an annulus defined by a portion of the line selector sleeve and the second tubular body. In such an embodiment, the annular element is provided with an annular fluid distribution groove being in fluid communication with the control fluid inlet, and the fluid supply pipe extends into the bridging channel. Thus, the fluid supply pipe bridges a gap between the second tubular body and the line selector sleeve when the line selector sleeve is displaced axially away from the first tubular body and rotates with respect to the second tubular body.
Preferably, the inlet of each outlet channel is provided with a valve. The valve may be opened in response to a fluid pressure exceeding a predetermined level. Such a valve may prevent unintended inflow of fluid into the outlet channel.
As an alternative to displace the line selector sleeve axially in response to rotation of the first tubular body, the line selector sleeve may in one embodiment be secured to the first tubular body in a rotationally rigid manner, so that a rotation of the first tubular body causes a corresponding rotation of the line selector sleeve. In such an embodiment a fluid may be communicated from the control fluid inlet and into the bridging channel via an annular fluid distribution groove arranged in a surface portion of the line selector sleeve, and from the bridging channel to the at least one outlet channel via a radial bore.
In a second aspect of the invention, a system for umbilical less installation, operation, and function test of a tubing hanger prior to subsea vertical valve tree installation, is provided. The system comprises:
- the apparatus according to the first aspect of the invention,
- a twin apparatus for being arranged on a drill floor of a floating vessel, the twin apparatus having an identical configuration as the apparatus of the first aspect of the invention; and
- a work-string having a first end portion and a second portion,
wherein the first end portion of the work-string is made-up with the first end portion of the rotatable first tubing body of the apparatus, and the second portion of the work-string is rotationally secured to a twin apparatus first tubing portion, so that any movement within the apparatus is copied to the twin apparatus. Thus, the twin apparatus of the system analogously mirrors the position of the line selector sleeve with respect to the second tubing portion of the apparatus that in a position of use is connected to the tubing hanger running tool. The twin apparatus at surface is thus configured to simultaneously mirror fluid pressure output from the apparatus when in operation.
In a third aspect of the invention, a method for umbilical less installation and operation of a tubing hanger prior to subsea vertical valve tree installation, is provided. The method comprising the steps of:
a) connecting an apparatus according to the first aspect of the invention to a first end portion of a work-string, and to a tubing hanger via a tubing hanger running tool;
b) moving by means of the work-string the assembly of the apparatus, the tubing hanger running tool and the tubing hanger until the apparatus is aligned inside a BOP stack and the tubing hanger is landed in a wellhead; and
c) orienting the line selector sleeve to a desired position within the apparatus by rotating the work-string.
The method may further comprise function testing of the tubing hanger prior to subsea vertical valve tree installation, wherein the method prior to step c) comprises:
- securing a twin apparatus having an identical configuration as the apparatus, to a second portion of the work-string; and
- connecting a source of fluid to a control fluid inlet of the twin apparatus; and monitoring the outlet channels of the twin apparatus.
In what follows, an example of a preferred embodiment and method is described which is visualized in the accompanying drawings, where:
Fig. 1A schematically illustrates a drilling vessel, marine drilling riser, BOP stack and a subsea wellhead during a TH installation operation;
Fig. 1B schematically illustrates a BOP stack with an annular bag, upper shear-ram, lower shear-ram, upper pipe-ram, middle pipe-ram, and lower pipe-ram, and also an orientation pin and a stab coupler;
Fig. 2A shows an embodiment of an apparatus according to the invention configured to be interfaced with a tubing hanger running tool indicated by dotted lines;
Fig. 2B shows a cross-section of the apparatus in fig.2A;
Fig 2C shows the apparatus in fig.2A, seen from an opposite side;
Fig. 3A shows a cross-sectional view along a longitudinal axis of first tubular body forming part of the apparatus according to the invention;
Fig. 3B shows a perspective view of a line selector sleeve forming part of the apparatus according to the invention;
Fig. 4 shows a typical face of a THRT comprising a plurality of hydraulic stab couplers to be connected to a lower end face of the apparatus, wherein the THRT is configured for operating a TH for a mono-bore VXT;
Fig. 5 A shows a perspective view in cross-section of an embodiment of the apparatus according to the invention, wherein a line selector sleeve is in a first position;
Fig. 5B shows a cross section of the apparatus shown in fig.5A, but wherein the line selector sleeve has been displaced axially to a second position being different from the first position shown in fig.5A;
Fig. 5 C shows in larger scale a detail of a portion of the apparatus wherein a bridging channel in line selector sleeve is in fluid communication with an outlet fluid channel of the second tubular body;
Fig. 6 shows a twin apparatus which is clamped around the work-string, wherein the twin apparatus is secured to a support structure resting on a drill-floor.
Fig. 7 shows in a larger scale a detail of a top portion of fig.6;
Figs.8A-8D show an alternative embodiment of the apparatus according to the selector invention, wherein the line selector sleeve is rotationally secured to the first tubular body of the apparatus;
Fig. 9A shows a further alternative embodiment of the line selector sleeve, wherein the sleeve is provided with a helical alignment groove; and
Fig, 9B shows in a larger scale a cross-sectional view of a detail of the line selector sleeve in fig.9A.
The drawings are shown in a schematic and simplified manner, and features that are not necessary for explaining the invention may be left out. Identical reference numerals refer to identical or similar features in the drawings. For clarity reasons, some elements may in some of the figures be without reference numerals. The various features shown in the drawings may not necessarily be drawn to scale. A person skilled in the art will understand that the figures are just principal drawings. The relative proportions of individual elements may also be distorted. Any positional indications, such as for example upper and lower, refer to the position shown in the figures.
Reference is first made to figure 1A wherein a subsea BOP stack 1 has been locked onto a subsea wellhead 3 after a completed drilling operation. A downhole tubing string 5 and a tubing hanger (TH) 6 have, in a known manner, been deployed through a marine drilling riser 8 by means of a tubing hanger running tool (THRT) 10 connected to a work-string 11. The work-string 11 is suspended from a drill floor 12 of a drilling vessel 13. A VXT (not shown) will be installed onto the wellhead 3 after removal of the BOP stack 1 and marine drilling riser 8, as will be appreciated by a person skilled in the art.
Reference is now made to the figures 2A and 2B. An apparatus 14 according to the invention is operatively connected to a top portion of the THRT 10 indicated by dotted lines. The apparatus comprises a rotatable first tubular body 15 having a first end portion for being made-up with a work-string 11, (see fig.1A) and a second end portion mounted within a connector 16, here shown as a nut. A stationary second tubular body 17 is axially secured to the connector 16. The second tubular body 17 comprises a control fluid inlet 31 and outlet fluid channels 34 (two shown in fig.2B) for communicating control fluid to a tubing hanger running tool 10 (see fig.1A). Each of the outlet fluid channels 34 has a radial bore 50 for providing fluid communication through an in inner wall of the second tubular body 17 and into the outlet fluid channel 34. The apparatus further comprises a line selector sleeve 18 threadedly connected to the second end portion of the first tubular body 15 (see for example figures 3A and 3B). The line selector sleeve 18 is controllably movable within the stationary second tubular body 17 in response to a rotation of the first tubular body 15. The line selector sleeve 18 comprises a bridging channel 33 for communicating fluid between the control fluid inlet 31 and a radial bore 50 of one of the outlet fluid channels 34 of the second tubular body 17. In the embodiment shown, the bridging channel 33 communicates fluid to the radial bore 50 via a fluid distributing sleeve groove 36 as best seen in fig.5C.
Since the apparatus 14 is configured for use prior to installing a Vertical Christmas Tree, VXT, the apparatus 14 has in an operating position a vertical orientation wherein the first tubular body faces upwards, and the second tubular portion faces downwards. In the following the first tubular body 14 will therefore also be denoted upper tubular body 14, and the second tubular body 17 will also be denoted lower tubular body 17.
The connector or nut 16 is connected to a portion of a lower tubular body 17 of the apparatus 14. The nut 16 is designed for being capable of transferring a total weight of the THRT 10, the TH 6 and the downhole tubing string 5 from the lower tubular body 17 to the upper tubular body 15. As shown in fig.2B, the upper tubular body 15 comprises a drill pipe box interface at the top, so that it can be made-up with the lower end of the workstring 11. The upper tubular body 15 is rotatable within the nut 16 and the upper part of the lower tubular body 17, when the TH 6 has been landed and locked into the wellhead 3 and the weight of the apparatus 14, the THRT 10, the TH 6 and the downhole tubing string 5 is carried by the wellhead 3.
In operation, a rotation of the work-string 11 is transferred into rotation of the upper tubular body 15. The upper tubular body 15 is provided with a threaded portion 15’ that is in threaded engagement with a threaded portion 18’ in an upper part of an axially displaceable line selector sleeve 18. The threaded portion 15’ of the upper tubular body 15 and the mating threaded portion 18’ of the line selector sleeve 18 are shown in figure 3A and 3B, respectively. In operation, longitudinal grooves 19 at each side (only one shown in fig.3B) of the line selector sleeve 18 is in engagement with a corresponding guide pin (not shown) in the lower tubular body 17, which will prevent the line selector sleeve 18 from rotating with respect to the lower tubular body 17. Thus, a rotation of the upper tubular body 15 will axially displace the non-rotating line selector sleeve 18 inside the lower tubular body 17 of the apparatus 14.
When the TH 6 has been landed and locked into the wellhead 3, it will have a final orientation wherein interface couplers in the TH 6 are aligned with the interface of the VXT. Figure 4 shows an example with six interface couplers denoted AAV, THS, AIV; DHSV; IC1, and IC2, respectively, and six additional interface couplers 134 of an upper face of a THRT 10, configured to form a hydraulic interface with the outlet channels 34 of the lower tubular body 17 of the apparatus 14. Typically, four of the six additional interface couplers 134 are configured for operating pistons in the THRT 10 for operating the TH6 lock/unlock and THRT 10 latch/un-latch functions and do therefore not extend to a second or lower face of the THRT 10. Thus, an apparatus 14 configured for being connected to an upper face of the THRT 10 shown in fig.4, comprises twelve outlet channels 34. An interface corresponding to the six interface couplers AAV, THS, AIV; DHSV; IC1, and IC2 is provided between a lower face of the THRT 10 and an upper face of the TH 6 and an interface of a mono-bore VXT, respectively. The TH 6 interface couplers are identified as: THS – tubing hanger soft landing, AIV – annulus isolation valve, DHSV – down hole safety valve, AAV – annulus access valve, IC1 – isolation zone 1, IC2 – isolation zone 2. There may be further lines than those discussed above, including electrical connections to downhole sensors. Figure 4 shows one such electrical connection 136. Umbilical-less operation/pressurization of the hydraulic functions will be facilitated from a common pressure input line, with hydraulic output switching or change-over by means of the apparatus14.
Referring back to Figure 1B, a simplified example of a BOP stack 1 comprising an annular bag 20, upper shear-rams 21, lower shear-rams 22, upper pipe-rams 23, middle piperams 24, and lower pipe-rams 25, is shown. An essential feature for any TH installation is the hydraulically operated orientation pin 26, a known feature of a subsea BOP stack 1.
Reference is also made to figure 2A. An outer portion of the lower tubular body 17 of the apparatus 14 is provided with a recessed external surface area 27A, 27B defined by orienting-profile or alignment edges 28A, 28B. When a portion of the recessed surface areas 27A, 27B during lowering is level with the orientation pin 26 in the BOP stack 1, the pin 26 will be hydraulically actuated to abut against an arbitrary portion of the recessed external surface area 27A, 27B. While keeping hydraulic actuation pressure on the orientation pin 26, the apparatus14, the THRT 10, the TH 6 and the downhole tubing string 5 will be raised by means of the work-string 11, so that the orientation pin 26 will slide against one of the orientation profile alignment edges 28A, 28B, thereby forcing partial rotation of the work-string 11, and consequently also the suspended assemblies, TH 6, THRT 10, the apparatus 14, including the downhole tubing string 5. The activated orientation pin 26 will eventually slip into an orientation groove 29 extending axially between the recessed surface areas 27A, 27B. The suspended apparatus 14, the THRT 10, the TH 6 and the downhole tubing string 5 will be kept in final orientation during the landing of the TH 6 into the wellhead 3 by the orientation pin 26, which will slide along the orientation groove 29. The orientation pin 26 will be kept engaged after landing.
With the TH 6 fully landed in the wellhead 3, hydraulics will be used to carry out the subsequent operations with TH 6 lock, line-check, and finally un-latch of the THRT 10. As there will be no hydraulic umbilical from the surface, hydraulic fluid, suitable for use in the down-hole lines, has to be provided from an alternative source:
- One such alternative source known from publication GB 2554497 B is to provide a hydraulic fluid filled bladder located within a BOP stack 1 cavity to make it into a pressure source for tool operations (not shown). An internal volume of the BOP stack 1 is isolated through the closure of the annular bag 20 shown in fig.1B, or one of the pipe rams, to seal around the work-string 11. Pressure is then applied to the closed-in volume from a choke or kill line at the BOP stack 1, thus squeezing the bladder to provide hydraulic supply pressure. An advantage with this approach is that it will not be required to modify any third-party equipment, i.e., the BOP stack 1 or the marine drilling riser 8.
- The figures 1B and 2A, 2B illustrate an example of a preferred embodiment, where a pressure-regulated hydraulic fluid supply port into the BOP stack 1 has been provided with an actuated stab coupler 30 below the BOP stack hydraulically operated orientation pin 26, as illustrated in figure 1B. With the TH 6 oriented and fully landed in the wellhead 3 as discussed above, the stab coupler 30 can be actuated to mate with the aligned control fluid inlet 31 of the apparatus 14. The control fluid inlet 31 may also be denoted hydraulic stab receptacle. The control fluid inlet 31 is provided with an integral valve function (not shown) configured for opening/closing only after an un-pressurized connection. By the term un-pressurized is meant connection without pressure in a supply line outside the BOP 1.
- Another possibility, (not shown), for connection of hydraulic supply is by means of a “hot stab” from a remotely operated vehicle (ROV) into the BOP stack 1, that will mate with the control fluid inlet 31 of the apparatus 14.
Typically, a subsea well is provided with one or more sensors (not shown) for measuring at least one of well pressure and temperature. To check a communication with the at least one sensor, an integrity check should be executed. Since the apparatus 14 is operated by means of a work-string 11 only, and thus without any umbilical, there is no direct signal communication from the apparatus 14 to the surface via a cable. To execute such an integrity check, the apparatus 14 is in one embodiment provided with an integrity control apparatus 50 comprising a communication apparatus 54 as shown in figure 2C. The communication apparatus 54 is arranged in an electronics compartment 52, secured to a shoulder 16’ of the nut 16. A clearance is provided between an inner surface of the compartment and the upper tubular body 15 so that the upper tubular body 15 can rotate with respect to the nut 16.
The electronics compartment 52 holds a power source, such as a battery 55, and a preprogrammed communication and memory unit 56 for receiving and storing data from the at least one sensor arranged in the subsea well. Data from the at least one sensor are communicated to and stored in the communication and memory unit 56 via a data communication line 58 arranged in an axial recess 60 extending in a surface of the nut 16 and the lower tubular body 17. At a lower end of the recess 60 of the lower tubular body 17, the data communication line 16 enters into a conduit having an inlet 62, and an outlet in an end face of the lower tubular body 17. An end of the data communication line 16 terminates in an interface configured to mate with an interface coupler 136 of an upper face of a THRT 10 as shown in fig.4. A corresponding cable (not shown) runs through the THRT 10 and the TH 6 and provides connections to the sensors. In one embodiment, the data is collected from the memory unit at surface when the apparatus 14 and the THRT 10 have been retrieved after completed installation of the TH 6. In an alternative embodiment the data from the communication and memory unit is wirelessly communicated from the communication apparatus 54 to surface prior to retrieving the apparatus 14 and the THRT 10. The wireless communication may for example be provided by means of an hydroacoustic transponder arranged within the compartment 52 shown in fig.2C.
Reference is now made to the figures 5A – 5C wherein the active element of the apparatus14 is the axially displaceable line selector sleeve 18. The line selector sleeve 18 comprises the bridging channel 33 for fluid distribution to at least one of several outlet channels 34 in the lower tubular body 17 of the apparatus14. The line selector sleeve 18 is positioned along the inside of a wall of the lower tubular body 17, so that a fluid distributing sleeve groove 36, encircling the lower end of the line selector sleeve 18, with seals 37 on each side, may be controlled to communicate with at least one selected outlet channel 34 in the lower tubular body 17. Each outlet channel 34 extends towards a hydraulic stab coupler in the interface between the bottom face of the lower tubular body 17 and the top face of the THRT 10 (see fig.4). Seals are included where required, so that there will be no liquid contact between the outside and the inside of the apparatus 14 when it is mounted onto a THRT 10.
According to the invention, a position of the line selector sleeve 18 within the apparatus 14 is configured to be controlled from the surface (from the vessel 13) through the number and direction of turns of the work-string 11.
Figure 6 shows an analogue twin apparatus 40 forming part of a system according to the invention. The twin apparatus 40 is identical to the apparatus 14 and arranged on a drill floor 12. The twin apparatus 40 is mechanically linked to the upper tubular body 15 of the apparatus14 via the work-string 11. A shear-pin 41 between the lower tubular body 17 and the upper tubular body 15, (ref. figures 2B, 5A, 5B 8A and 8B), ensures that the analogue twin apparatus 40 operates synchronous with the apparatus 14. The shear-pin 41 is configured to break with the initial work-string 11 rotation. In operation, the analogue twin apparatus 40 is mounted to a support structure 44 at the drill floor 12 above a rotary table 43. When the TH 6 has been landed in the wellhead 3, anti-rotation wedges 45 (see fig.7) secured to the twin apparatus first tubing portion 415, are mounted to grip around the work-string 11, so that the work-string 11 will be locked together with the rotational elements (the upper tubular body) of the analogue twin apparatus 40. The rotational elements of the analogue twin apparatus 40 have identical thread pitch to the line selector sleeve 18 and the upper tubular body 15. Porting of the analogue twin apparatus 40 will be a copy of the apparatus 14 porting. The analogue twin apparatus 40 will thus reproduce the displacement of the line selector sleeve 18, and the resulting pressure output to the THRT 10. The analogue twin apparatus 40 is connected to a fluid source, for example a supply of service water, to visualize the operation at the surface (for example the vessel 13 in fig.1A. The outputs of the analogue twin apparatus 40 are marked according to the outputs of the apparatus 14. In its simplest embodiment, hoses are connected to the analogue twin apparatus 40 and water will flow out of the twin apparatus through an outlet channel corresponding to a selected outlet channel 34 of the apparatus 14. In an alternative embodiment, a more sophisticated monitoring solution is established through the introduction of pressure sensors at the outlet channels of the analogue twin apparatus 40. Pressure readings are used to establish an electronic representation of the operation with a simple lamp panel, or with a Visual Display Unit (VDU) with a graphic representation. This can be complemented by remote pressure readings of the inlet pressure of the apparatus 14, depending on the supply source used.
Figures 5A - 5C show details of the line switching features of the apparatus 14. A supply pipe 46 is configured to slide within a portion of the bridging channel 33 in the line selector sleeve 18. A first end of the supply pipe 46 is fixed into a connection port at the control fluid inlet 31 in the lower tubular body 17. A second end of the supply pipe 46 is provided with seals 48 that will seal against the bore of the bridging channel 33 as the line selector sleeve 18 is moved axially. In the embodiment shown, the supply pipe 46 may be completely inserted into the bridging channel 33 when the line selector sleeve 18 is in its upper position, as shown in figure 5A. When the line selector sleeve 18 has been repositioned downwards (to the right as illustrated in figure 5b) to pressurize a different outlet fluid channel 34, the supply pipe 46 bridges the gap between the shoulder of the line selector sleeve 18 and the supply pipe 46 termination point. By the repositioning of the line selector sleeve 18, the internal assembly of the analogue twin apparatus 40 of the system according to the invention, has moved correspondingly. As shown in figure 5C, a radial bore at the lower end of the line selector sleeve 18 is configured to distribute supply pressure from the bridging channel 33 to a fluid distribution groove 36. The groove 36 is in fluid communication with a selected radial bore 50 in the lower tubular body 17, which will, via a valve 52, direct hydraulic fluid to the respective outlet channel 34.
Figures 8A - 8D, and 9A - 9B show alternative embodiments of the invention.
A first alternative embodiment:
- Figures 8 A-D show a first alternative embodiment of an apparatus for re-positioning the line selector sleeve 18. The apparatus is operatively connected to an analogue twin apparatus 40 via a work-string 11. In this embodiment of the invention, the line selector sleeve 18 is configured to be partially rotated with the work-string 11, instead of axially displaced, to direct hydraulic supply pressure to a selected output channel 34. As shown in figure 8A, the upper tubular body 15 is in this embodiment of the invention fixed to the line selector sleeve 18 with bolts 56. A partial rotation of the workstring 11 (see fig.1A) is transferred to the upper tubular body 15, which will be rotatable within the nut 16, and the lower tubular body 17. Due to the bolts 56, the connected line selector sleeve 18 will in this case rotate with the upper tubular body 15. The analogue twin apparatus 40 will reproduce the partial rotation of the line selector sleeve 18. The synchronization shear pin 41 between the lower tubular body 17 and the upper tubular body 15 will ensure that the analogue twin apparatus 40 will have identical rotation with the upper tubular body 15 and will break with the initial rotation of the work-string 11.
Figure 8B shows a cross-section with details of a fluid distribution groove 57, with annular seals 58 on each side, encircling the line selector sleeve 18. The groove 57 is, via a radial bore 59, in fluid communication with a fluid bridging channel 33 so that hydraulic supply pressure from the lower tubular body 17 is distributed into the supply channel 33 in the line selector sleeve 18. The upper end of the fluid bridging channel 33 is provided with a sealing plug 60. A radial bore 61 in a lower end of the bridging channel 33 in the line selector sleeve 18 is, depending on the rotational orientation of the line selector sleeve 18, positioned to direct hydraulic fluid into one of several radial bores 50 that communicate with the respective outlet channels 34 in the lower tubular body 17.
The circular fluid distribution groove 57 has the effect of providing freedom for the placement of the hydraulic stab receptacle 31 into the lower tubular body 17. Figure 8C shows that the hydraulic stab receptacle 31 is placed within the vertical orientation groove 29. The vertical orientation groove 29 is shown in fig.2A.
Figure 8D shows the outside of the line selector sleeve 18, with double O-rings encircling the opening of the radial bore 61, to inhibit leakage between the radial bores 50 and 61.
A second alternative embodiment:
- Figures 9A and 9B show a second alternative embodiment of an apparatus for repositioning the line selector sleeve 18. The line selector sleeve 18 is configured for a combined axial and rotational displacement. The purpose of the second alternative embodiment is to accommodate a multitude of output channels 34 in the lower tubular body 17 of the apparatus 14.
Figure 9A shows a spiral guiding groove 63 of the line selector sleeve 18. The line selector sleeve 18 will thus be rotated during the axial displacement in the lower tubular body 17, which will be facilitated through screw-action between the threaded section of the upper tubular body 15 and the threaded section of the line selector sleeve 18, when rotated with the work-string 11. A single radial outlet 64 port with double O-rings is provided for fluid communication with the multiple outlet channels 34 along the twisted path of movement in the lower tubular body 17.
In the basic embodiment of the invention, shown in figures 5A and 5B, the supply pipe 46, configured to slide within a portion of the bridging channel 33 in the line selector sleeve 18, is fixed at the control fluid inlet 31 in the lower tubular body 17. Such a configuration will only work if the line selector sleeve 18 is displaced axially, but not when it is also configured to rotate. In the alternative embodiment shown in figures 9A and 9B of the invention, wherein the line selector sleeve in operation is subject to a combined axial and rotational displacement, the supply pipe 46 must instead be arranged so that it will follow the rotational movement of the line selector sleeve 18. Figure 9B shows that the upper end of the supply pipe 46 is fixed into an annular element 65, here in the form of a ring 65, configured to rotate with respect to the lower tubular body 17. A groove 66, which encircles the rotatable ring 65, is in fluid communication with the control fluid inlet 31 in the lower tubular body 17. The supply pipe 46 is in fluid communication with the groove 66 via a radial bore 67 in the rotatable ring 65. Seals 68 between the rotatable ring 65 and the lower tubular body 17 are located at each side of the groove 66. A bolt, (not shown in the figure 9B), extends radially from the rotatable ring 65 into the circular groove 69 around the inside of the lower tubular body 17. The purpose of this bolt and groove arrangement is to prevent the rotatable ring 65 from moving axially in the lower tubular body 17.
It should be noted that the above-mentioned embodiments illustrate rather than limit the invention, and that those skilled in the art will be able to design many alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. Use of the verb "comprise" and its conjugations does not exclude the presence of elements or steps other than those stated in a claim. The article "a" or "an" preceding an element does not exclude the presence of a plurality of such elements.
Claims (11)
1. An apparatus (14) for use in a system for umbilical-less installation, operation, and function test of a tubing hanger (6), prior to subsea vertical valve tree installation, wherein the apparatus (14) comprises:
- a rotatable first tubular body (15) having a first end portion for being made-up with a work-string (11), and a second end portion;
- a stationary second tubular body (17) provided with a guide (28A, 28B, 29) for, in a position of use, receiving an alignment pin (26) protruding from a BOP stack (1); c h a r a c t e r i z e d i n that the stationary second tubular body (17) is axially secured to the first tubular body (15) via a connector (16), the second tubular body (17) comprising
- a control fluid inlet (31) and outlet fluid channels (34) for communicating control fluid to a tubing hanger running tool (10), each of the outlet fluid channels (34) having a radial bore (50) for providing fluid communication through an inner wall of the second tubular body (17) and into the outlet fluid channel (34);
- a line selector sleeve (18) threadedly connected to the second end portion of the first tubular body (15) and provided with an alignment groove (19; 63) for engaging a protrusion of the second tubular body (17), whereby the line selector sleeve (18) is controllable movable within the stationary second tubular body (17) in response to a rotation of the first tubular body (15), the line selector sleeve (18) comprising a bridging channel (33) for communicating fluid between the control fluid inlet (31) and at least one selected radial bore (50) of the outlet fluid channels (34) of the second tubular body (17).
2. The apparatus (14) according to claim 1, wherein the alignment groove (19) extends axially so that the line selector sleeve (18) is prevented from rotating with respect to the second tubular body (17) when the protrusion is in engagement with the axially extending alignment groove (19).
3. The apparatus (14) according to claim 1, wherein the line selector sleeve (18) is provided with a fluid groove (36) encircling a portion of the line selector sleeve (18), the fluid groove (36) configured for being brought into fluid communication with at least one selected outlet channel (34).
4. The apparatus (14) according to claim 1, wherein the alignment groove (63) extends helically so that the line selector sleeve (18) is rotated with respect to the second tubular body (17) when line selector sleeve (18) is displaced axially in response to rotation of the rotatable first tubular body (15).
5. The apparatus (14) according to claim 1, wherein a fluid supply pipe (46) is in fluid communication with the control fluid inlet (31) and extends into the bridging channel (33).
6. The apparatus (14) according to claim 4, wherein a fluid supply pipe (46) is in fluid communication with the control fluid inlet (31) via a rotatable annular element (65) arranged in an annulus defined by a portion of the line selector sleeve (18) and the second tubular body (17), the annular element (65) being provided with an annular fluid distribution groove (66) being in fluid communication with the control fluid inlet (31), and wherein the fluid supply pipe extends into the bridging channel (33).
7. The apparatus (14) according to any of the preceding claims, wherein an inlet of each outlet channel (34) is provided with a valve (52).
8. The apparatus (14) according to claim 1, wherein the line selector sleeve (18) is secured to the first tubular body (15) in a rotationally rigid manner, so that a rotation of the first tubular body (15) causes a corresponding rotation of the line selector sleeve (18), wherein a fluid is communicated from the control fluid inlet (31) and into the bridging channel (33) via an annular fluid distribution groove (57) arranged in a surface portion of the line selector sleeve (18), and from the bridging channel (33) to the at least one outlet channel (34) via a radial bore (61).
9. A system for umbilical less installation, operation, and function test of a tubing hanger (6) prior to subsea vertical valve tree installation, the system comprises: - the apparatus (14) according to any one of the preceding claims,
- a twin apparatus (40) for being arranged on a drill floor (12) of a floating vessel (13), the twin apparatus (40) having an identical configuration as the apparatus (14); and
- a work-string (11) having a first end portion and a second portion,
wherein the first end portion of the work-string (11) is made-up with the first end portion of the rotatable first tubing body (15) of the apparatus (14), and the second portion of the work-string (11) is rotationally secured to a twin apparatus first tubing portion (415), so that any movement within the apparatus (14) is copied to the twin apparatus (40).
10. A method for umbilical less installation and operation of a tubing hanger (6) prior to subsea vertical valve tree installation, c h a r a c t e r i z e d i n that the method comprising the steps of:
a) connecting an apparatus (14) according to any of the claims 1-8 to a first end portion of a work-string (11), and to a tubing hanger (6) via a tubing hanger running tool (10);
b) moving by means of the work-string (11) the assembly of the apparatus (14), the tubing hanger running tool (10) and the tubing hanger (6) until the apparatus (14) is aligned inside a BOP stack (1) and the tubing hanger (6) is landed in a wellhead (3);
and
c) orienting the line selector sleeve (18) to a desired position within the apparatus (14) by rotating the work-string (11).
11. The method according to claim 10, further comprising function testing of the tubing hanger (6) prior to subsea vertical valve tree installation; the method comprising prior to step c):
- securing a twin apparatus (40) having an identical configuration as the apparatus (14), to a second portion of the work-string (11); and
- connecting a source of fluid to a control fluid inlet of the twin apparatus (40); and monitoring the outlet channels of the twin apparatus (40).
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| NO20230196A NO20230196A1 (en) | 2023-02-28 | 2023-02-28 | An apparatus, a system, and a method for umbilical-less installation and operation of a tubing hanger |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| NO20230196A NO20230196A1 (en) | 2023-02-28 | 2023-02-28 | An apparatus, a system, and a method for umbilical-less installation and operation of a tubing hanger |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| NO347890B1 true NO347890B1 (en) | 2024-04-29 |
| NO20230196A1 NO20230196A1 (en) | 2024-04-29 |
Family
ID=91075116
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| NO20230196A NO20230196A1 (en) | 2023-02-28 | 2023-02-28 | An apparatus, a system, and a method for umbilical-less installation and operation of a tubing hanger |
Country Status (1)
| Country | Link |
|---|---|
| NO (1) | NO20230196A1 (en) |
Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| GB2448262A (en) * | 2003-12-17 | 2008-10-08 | Fmc Technologies | Electrically operated THRT |
| US20100224373A1 (en) * | 2009-03-06 | 2010-09-09 | Gregory Williams | Wellhead Conversion System and Method |
| US20110247799A1 (en) * | 2010-04-09 | 2011-10-13 | Cameron International Corporation | Tubing hanger running tool with integrated landing features |
| US20180320470A1 (en) * | 2017-05-05 | 2018-11-08 | Onesubsea Ip Uk Limited | Power feedthrough system for in-riser equipment |
| US20210140290A1 (en) * | 2017-03-08 | 2021-05-13 | Schlumberger Technology Corporation | Dynamic artificial lift |
-
2023
- 2023-02-28 NO NO20230196A patent/NO20230196A1/en unknown
Patent Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| GB2448262A (en) * | 2003-12-17 | 2008-10-08 | Fmc Technologies | Electrically operated THRT |
| US20100224373A1 (en) * | 2009-03-06 | 2010-09-09 | Gregory Williams | Wellhead Conversion System and Method |
| US20110247799A1 (en) * | 2010-04-09 | 2011-10-13 | Cameron International Corporation | Tubing hanger running tool with integrated landing features |
| US20210140290A1 (en) * | 2017-03-08 | 2021-05-13 | Schlumberger Technology Corporation | Dynamic artificial lift |
| US20180320470A1 (en) * | 2017-05-05 | 2018-11-08 | Onesubsea Ip Uk Limited | Power feedthrough system for in-riser equipment |
Also Published As
| Publication number | Publication date |
|---|---|
| NO20230196A1 (en) | 2024-04-29 |
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