Technical field

The present invention relates in particular to the provision of structures for connecting flow-control apparatus to a foundation for a well on the seabed. More specifically, the invention relates to a structure for supporting a flow-control apparatus on a seabed foundation for a well, a subsea assembly comprising the structure, a method of assembling the structure, and a method of deploying and installing the structure. In various embodiments, the flow-control apparatus may be a blow out preventer, a Christmas tree, or a production flow base, or another device which may be operable for controlling fluid flow in a wellbore of the well.

Background

Wells are increasingly established in the subsea environment, in particular in the hydrocarbon exploration and production industry for the purpose of recovering hydrocarbons from deep in the Earth's subsurface. The work involved in establishing such a well can be substantial, and involves typically stages of construction, completion, and then production. The equipment to be used on site at the well varies between stages.

During construction, the wellbore is drilled, typically in stages where casing is run in, hung off from hangers at the top of the well, and cemented in place to obtain a cased borehole. Completion may include gravel, packing, running screens and inserting production tubing inside the well. Finally, the production can commence during which fluid recovered from the reservoir may travel uphole and out of the top of the well, and onward for processing downstream.

Initial steps of well construction often involve providing a "foundation" at the seabed in the desired location of the well and lowering a conductor tubing into the upper few metres of subsurface beneath the seabed. The seabed generally consists of wet, unconsolidated mud. In this way, the foundation and the conductor may typically provide foundation on which equipment can be supported, and normally remains in place for the life-time of the well. A recent advancement has been to use suction caissons as well foundations.

Different flow-control apparatus may be needed at the top of the well at the different stages mentioned above. Such apparatus may be used to control the flow of fluids in or out of the wellbore, because as is known in the art, the pressure conditions increase with depth in the wellbore and it may be necessary to contain or control that pressure appropriately in order to progress with wel lbore operations safely and efficiently. Examples of such apparatus include: a blow-out preventer or other fluid control valves such as may be used during drilling; a production flow base for production; and/or a Christmas tree.

The flow-control apparatus are generally supported on the foundation. Furthermore, it is often sought to provide support for the flow-control apparatus in a location a short distance of perhaps a meter or so above the seabed. A "wellhead" is typically provided at the top of the wellbore on the foundation and a flow-control apparatus may then typically be connected onto the wellhead.

A challenge with this can be that the flow-control apparatus is often large and massive and builds height onto the wellhead. The connecting structure may also extend significantly upward into the water column. As a result, when the flow-control apparatus is connected, the connecting structure between onto the foundation can experience adverse forces, which can be problematic.

An example prior art connecting structure is illustrated in Figure 1 . The connecting structure includes parts of a wellhead connected to a well foundation. More specifically, the structure has a so called high-pressure wellhead housing 240 connected to a so called low-pressure wellhead housing 230. The low-pressure wellhead housing 230 is in turn connected to a conductor casing 220, notably by a circumferential weld 221 . Furthermore, the high-pressure housing 240 is connected to a casing string 250 by a circumferential weld 242. The low-pressure wellhead housing and the conductor string serves as a low-pressure barrier, intended to endure structural loads and to transfer said loads to a seabed and/or an underlying formation. The high-pressure wellhead housing and the first casing string serves as a high-pressure barrier, intended to endure and contain a high fluid pressure from a wellbore.

The three types of structural loads of particular concern are: axial loads, torsional loads, and bending loads. Coping with such loads and designing an appropriate structure can be time consuming and costly. It may be undesirable to use material unnecessarily. Much effort goes into such activity.

In Figure 1 , the loads are typically transferred through the connecting structure from the high- pressure wellhead housing to the low-pressure wellhead housing and onward via the conductor pipe and the foundation to the seabed sediment.

The connecting structure indicated in Figure 1 provides a solution to provide a wellhead and to connect flow-control apparatus to the foundation that has been adopted widely in the industry. Once the low-pressure housing is connected to the foundation, the high-pressure housing can be received into the top end of the low-pressure housing. The flow-control apparatus can then be attached via the fitting to the high-pressure housing. A solid connection between the low pressure and high-pressure housings is obtained and the housings may interlock simply by lowering the high-pressure housing into the low-pressure housing. Although this arrangement can suitably transfer forces in many cases, it may suffer in that the connection between the low- and high-pressure housings has substantial complexity in order to provide an appropriate interlock to transfer the different loads.

Another, longstanding difficulty with connecting structure of Figure 1 has been a structural weakness associated with the circumferential weld of the low-pressure housing to the conductor. The weld reduces the integrity of the metal from which the tubular low-pressure housing is formed because of the exposure to the heat of the weld. The material of the tubular is therefore modified or defective in proximity to the weld location. Post treatment of the structure and the affected weld region is one way to revive the structural character of the welded material but is not practical in a structure of the size concerned. As a result, the weld location may lack the structural capacity of steel bodies above and below. In load modelling and tests, this may be seen as a localised anomaly in the resistance to fatigue and bending loads. Although recognised to be a problem, the presence of the weld is generally considered an acceptable trade off and a required feature of the connection to the foundation in order to obtain the desired connectivity between the high and low- pressure housings. The low-pressure housing such as in Figure 1 has a specific construction to mate with the high-pressure housing , and with this taken into consideration the process of welding the low-pressure housing to the conductor has been favoured to attach the housing in place on the conductor.

The circumferential weld connecting the high-pressure wellhead housing to the casing string may also be problematic for the same reasons as described above. As the load transfer from the high- pressure wellhead housing to the low-pressure wellhead housing is imperfect, the weld between the high-pressure wellhead housing and the casing string will also see structural loads.

The susceptibility of the welds to structural loads and forces may also be exacerbated in foundations where a rigid connection with the subsurface at the seabed, such as may be achieved by a suction caisson. This is because a well foundation may limit the mobility the foundation, such that the parts connecting between the foundation and flow-control apparatus directly above the foundation need to accommodate a greater stress.

A significant amount of time and resource typically goes into determining and understanding the stress and load performance of the assembly, particularly due to the welds but also due to the complexity of the connection between high and low-pressure housings. This may be inconvenient and may introduce uncertainty, cost, and undesired limitation to the longevity of the connecting structure. The fatigue life of said welds can be of particular interest as it is typically the weakest point compared with the loads it has to endure, particularly if a suction-caisson foundation is used.

Another issue is that the connecting structure of Figure 1 has been developed with a sequential subsea installation procedure in mind. The connection of the low-pressure and high pressure wellhead housings is normally designed at least partly to facilitate for sequential subsea installation . Furthermore, wellhead structures for deep wells have in practice often been applied identically in shallow wells. As such, in many cases the shallow well solutions have been over-dimensioned for their purpose.

There is a need for solutions which are efficient in use of materials, simple in design and easy to employ, and yet which are reliable.

At least one object of the invention is to remedy or to alleviate one or more drawbacks or difficulties in the prior art.

Summary of the invention

According to a first aspect of the invention, there is provided structure for supporting a flow-control apparatus on a seabed foundation for a well, the flow-control apparatus being configured for performing at least one operation in a wellbore of the well, the structure comprising:

a first section comprising a first bore, the first section configured to be connected to the flow-control apparatus; and

a second section comprising a second bore, the second section configured to be connected to the subsea foundation;

wherein the first and second sections are connected together through a joint which is made up by means of a connector, wherein the first and second bores are arranged longitudinally end to end, for transmitting a load through the joint from the flow-control apparatus to the subsea foundation.

The structure can provide a structurally strong connection between the first and second sections, which can be sufficient without requiring a circumferential weld. The joint may typically have a structural capacity that is equal to or stronger than above and below pipe segments, such as the first section and the second section, in axial, bending and torsional dimensions.

Either or both of the first and second bores may have at least one hanger for suspending a length of casing for the wellbore from the hanger. Either or both of the first and second bores may have a plurality of casing hangers. The plurality of casing hangers may preferably be arranged in the bore of the first section, but one or more casing hangers may be arranged in the bore of the second section. The first section may be configured to perform the functionality of the high-pressure wellhead housing of a conventional subsea system.

The first bore may have a tubing hanger for suspending a length of tubing for the wellbore from the hanger.

A body of the first section and a body of the second section may be connected longitudinally end- to-end. This may be beneficial for transfer of structural loads as they can be transferred directly vertically. The first section of the structure may comprise a body having a radially extending flange. The second section of the structure may comprise a body having a radially extending flange. The flange of the first section may be arranged to mate with the corresponding flange of the second section. The connector may comprise a bolt for connecting the flanges together to make up the joint.

Either the first or the second section of the structure may have a threaded collar arranged on a body of the first or second section for connecting with a corresponding thread on a body of the other of the first and second sections to connect the first and second sections together to make up the joint.

The threaded connector may be hydraulically operated.

The flow-control apparatus may be any one of a blowout preventer, a production flow base; a swab valve; a tree cap; or a Christmas tree. The first section may have a fitting for selectively connecting to any one of: the blowout preventer, the production flow base; the swab valve; the tree cap; or the Christmas tree. The fitting may comprise an H4 profile or other profile for matching a corresponding fitting of the flow-control apparatus.

The first section may comprise a tubular body adapted to receive a housing on an inside of the tubular body, the housing including at least one hanger for suspending a length of casing for the wellbore from the hanger.

The second section of the structure may be connected to the foundation. The second section may be connected to the foundation by a welded connection. The foundation may comprise one or more support members extending from a wall or another structure of the foundation to the second section, to which the second section may be welded. The support structures may be for example ribs or webs or other plate or beam structures, and may be welded to the second section substantially longitudinally along an outer wall of the second section. The support structure and/or the second section may be configured for optimizing a connection between them for transfer of structural loads from the second section to the support structure. For example, the second section may comprise at least one protrusion for facilitating connection of the second section to the subsea foundation, wherein the protrusion may be a protrusion on an outer surface of the second section.

The second section may comprise a neck extending from the foundation above the seabed, when installed.

The joint may be pre-made at surface prior to installation of the structure on the seabed.

According to a second aspect of the invention, there is provided a subsea assembly comprising: the structure according to the first aspect of the invention; and

a well foundation. The well foundation may be a template or may be a suction caisson. The structure may be connected to the foundation. The structure may be connected to the foundation in the same manner as the second section of the structure as set out under the first aspect of the invention. The subsea assembly may be assembled in a topsides facility onshore or offshore, prior to installation subsea.

The second section of the structure may be connected to the foundation. The foundation may be supported on the seabed, such that the connected first and second bores may be arranged stack- wise end-to-end, and a structural load may be transmitted through the joint from the flow-control apparatus to the foundation.

The subsea assembly may further comprise a third section. The third section may be connected by a circumferential weld to the second section of the structure, wherein a bore of the third section and the bore of the second section may be arranged longitudinally end-to-end. The third section may form an outer wall of an annulus formed if later installing a casing string within the bore of the third section. The annulus may be at least partly filled with cement for supporting the casing string in place.

The subsea assembly may comprise a Christmas tree. The subsea assembly may comprise a production flow base. The subsea assembly may comprise a swab valve. The subsea assembly may comprise a tree cap. The subsea assembly may comprise a protective structure. The subsea assembly may comprise an annulus vent line. The subsea assembly may comprise a B-annulus line. The subsea assembly may comprise a C-annulus line. The subsea assembly may comprise a crossover line. The subsea assembly may comprise an inductive downhole line pressure sensing system. The subsea assembly may comprise one or more valves, one or more pressure and/or temperature sensors, and the subsea assembly may comprise one or more hot-stab connectors. The one or more hot-stab connectors may be hot-stab connectors comprising valves, such as an ROV valve stab connector.

The first section of the structure may comprise, may be connected to and/or may be a part of one of or a plurality of the features mentioned in the above paragraph.

The subsea assembly of the second aspect of the invention, the structure of the first aspect of the invention, and optionally the third section, may be made to provide a relatively simple system for an exploration well, for subsequent connection to a blowout preventer and/or a subsequent connection to a Christmas tree, or it may be made as a more complex system for a well for production of hydrocarbons, comprising a Christmas tree and optionally other of the features above as part of the first section or connected to the first section. Either way, the subsea assembly may be assembled in a topsides facility offshore or onshore, and may comprise a bore with a diameter sufficient for drilling for installation of casing strings of diameters up to at least 17 inches (43 cm) subsequent of installation of the assembly into a seabed. Furthermore, the subsea assembly may further comprise means for monitoring stress in the structure of the assembly. The means may comprise at least one sensor for detecting a deflection or strain in a material of the structure. The sensor may be a strain gauge. This may facilitate determining the fatigue or exposure of the structure to loads, and may help to obtain knowledge of ensure the loads are known and/or to avoid exceeding usable life.

According to a third aspect of the invention, there is provided a method of assembling a structure according to the first aspect of the invention. The method comprises the steps of:

providing the first and second sections; and

making up the joint using the connector to connect the first and second sections together, the first and second bores arranged longitudinally end-to-end.

The method may further comprise the step of connecting the second section to the foundation.

Furthermore, the method may comprise connecting the flow-control apparatus to the first section.

The method may be performed on a topsides facility offshore or onshore, e.g. on dry deck or dry land.

According to a fourth aspect of the invention, there is provided a method of deploying and installing the structure according to the first and second aspects of the invention, the method comprising the steps of:

providing the foundation on the seabed; and

supporting the structure on the foundation, so as to allow a load to be transmitted through the joint from the flow-control apparatus to the foundation, the first and second bores arranged stackwise end-to-end.

The method may further include lowering the structure through the sea to position the structure so as to be supported on the foundation at the seabed.

The method may comprise the step of assembling the structure by applying the method according to the third aspect of the invention, e.g. by assembling the structure prior to lowering the structure into a body of water.

According to a fifth aspect of the invention, there is provided a section of a structure for supporting a flow-control apparatus on a seabed foundation for a well, the flow-control apparatus being configured for performing at least one operation in a wellbore of the well, the section comprising a bore for accessing the well and being configured to be connected to the seabed foundation.

The section may comprise at least one protrusion from an outer wall of a tubular body of the section for facilitating the connection to the seabed foundation.

The section may be configured to connect to a further section with the bore arranged end-to-end with a bore of the further section, via a joint which may be made up by a connector. Brief description of the drawings

There will now be described, by way of example only, embodiments of the invention with reference to the accompanying drawings, in which:

Fig. 1 is a cross-sectional view of connections of a prior art connecting structure high- pressure wellhead housing to a low-pressure wellhead housing, a high-pressure wellhead housing to a casing string and a low-pressure wellhead housing to a conductor string in a typical subsea system ;

Fig. 2 is a representation of the first section and the second section according to an embodiment of the invention ;

Fig. 3 is a cross-sectional view of a subsea assembly according to another embodiment of the invention;

Fig. 4 is a cross-sectional view of the subsea assembly of Figure 3 installed into a seabed;

Fig. 5 is a cross-sectional view of a subsea assembly according to another embodiment of the invention, wherein the subsea assembly has cement return lines;

Fig. 6 is a representation in smaller scale of a subsea assembly, wherein the subsea assembly is a subsea assembly for a production well according to another embodiment;

Fig. 7 is a representation of the subsea assembly for a production well installed into a seabed according to yet another embodiment;

Fig. 8 is a representation in larger scale of the first section of the structure, wherein the first section comprises features advantageous for a subsea assembly for a production well;

Fig. 9 is a representation the first section of a structure according to another embodiment, wherein the first section comprises further features that may be advantageous ;

Fig. 10 is a representation in larger scale of a structure according to another embodiment, wherein the second section comprises further advantageous features;

Fig. 1 1 is a representation of a structure according to yet another an embodiment; and

Fig. 12 is a representation of a structure according to an embodiment of the invention.

Detailed description Figure 2 shows a structure 100, comprising a first tubular section 4 and a second tubular section 2. The second section 2 has an upper end arranged with a radially extending flange 21 , and the first section 4 has a lower end with a corresponding radially extending flange 43. The two flanges 21 , 43 are connected through a joint 101 made up by means of a connector 102 comprising receivers 22, 44 for a bolt on each of the flanges 21 , 43 and a bolt 1 1 for each of the shown receivers 22, 44. The connector 102 may comprise a number of receivers 22, 44 and bolts 1 1 . The number may be for example one, four, eight, twelve or sixteen. A mechanical connection such as the one shown in the Figure may be highly advantageous compared to the circumferential weld 221 , 241 connecting a high-pressure wellhead 240 to a casing 250 or a low-pressure wellhead 230 to a conductor 220 in a conventional system, as it will typically have a structural capacity that is equal to or stronger than pipe segments above and below, unlike the circumferential weld 221 . Although the structure 100 is shown in Figure 2 and in other figures with a gap between the first structure 4 and the second structure 2 it should be noted that when assembled, the two section 4, 2 should be fit tightly and rigidly together.

The first section 4 and the second section 2 are connected end-to-end, with the lower end of the first section 4 placed directly on top of the second section 2. This way, the structure 100 is designed for transferring loads in a more simple, efficient and structurally more robust manner compared to the conventional subsea system 200. All of the three types of loads, the axial loads, the torsion loads and the bending loads are transferred efficiently from the flange 43 of the first section 4 to the flange 21 of the second section 2 by the rigid, high-friction connection caused by the first structure 4 sitting directly on top of the second structure 2 and being locked to it by use of bolts 1 1 . Whereas the transfer of loads of the conventional subsea system 200 may require transfer through a shoulder for axial loads, anti-rotation dogs to avoid slipping for transferring torsion loads, contact rings and a rigid-lock-down assembly for transferring bending loads, the structure 100 may transfer the loads simply through a bolted, flange connection. Furthermore, with the structure 100, a subsea assembly does not require the loads to be transferred through a circumferential weld prior to transferring at least a substantial amount of the loads to a foundation.

The two sections 2, 4 may each be completely made by forging and/or machining. An advantage of having flanges 21 , 43 is that the flanges 21 , 43 may be parts of the forged and/or machined sections 2, 4, which means a connection can be established without requiring any parts welded to the sections. Furthermore, the flange area is large, meaning loads may be distributed over a larger cross-sectional area than the simple wall thickness.

The structure 100 may be assembled by providing the first and second sections 4, 2, and by making up the joint 101 using the connector 102 to connect the first and second sections 4, 2 together, the first and second bores 8 arranged longitudinally end-to-end.

Although not shown in Figure 2, the flanges 21 , 43 may typically be pre-loaded, to enhance the rigidity of a connection between the first section 4 and the second section 2. The structure 100 may be assembled by providing the first and second sections 4, 2 and making up the joint 1 01 using the connector 102 to connect the first and second section 4, 2 together, with the bores 8 of the first and second sections 4, 2 being arranged longitudinally end-to-end.

The first and second section 4, 2 may be made from machining a piece of metal, typically steel, and may be weld free.

In Figure 3, an embodiment of the structure 100 is shown as part of a subsea assembly 1 . The subsea assembly further comprises a flow-control apparatus 6, such as a blowout preventer or a Christmas tree, a suction caisson 3 and a third section 5.

The second section 2 of the structure 100 of the subsea assembly 1 has an outer portion 23 for a longitudinal welded connection 25 of the second section 2 to the suction caisson 3. Two longitudinal welded connections 25 combines the second section 2 to support structures 31 , 32 of the suction caisson 3. As they are substantially vertical, the welded connections connecting the second section 2 to the suction caisson 3 are not as vulnerable to the cyclical, lateral forces that are problematic to the aforementioned circumferential welds of the conventional system 200. It should be noted that only two support structures 31 , 32 are shown connected to the outer portion 23 because of the cross-sectional perspective of the figure. Typically, the foundation, e.g. suction caisson 3, will have more than two support structures 31 , 32 connected to the outer portion 23, such as six, eight, twelve or sixteen support structures 31 , 32.

Lastly, the second section 2 has a lower end for an end-to-end circumferential welded connection 26 to an upper end 51 of the third section 5. The circumferential welded connection 26 of the second section 2 to the third section 5 is not as exposed to structural loads caused by lateral forces when the subsea assembly 1 is in use, as a majority of the load will be transferred to the suction caisson 3 and a surrounding seabed through the support structures 31 , 32 above the circumferential weld 26.

The first section 4 further has two casing hanger profiles 41 , 42 for suspending casing strings (not shown). Although two casing hanger profiles 41 , 42 are shown, there could be zero, one, two, three, four or more than four casing hanger profiles 41 , 42 inside the first section 4. In a top portion of the first section 4, the first section is arranged with a fitting 46 for connecting to a flow-control apparatus 6, such as a blowout preventer, a Christmas tree or other equipment. The fitting 46 may typically be an H4 profile. Typically there may also be a tubing hanger profile (not shown) for suspending a tubing string (not shown) in the first section 4.

The third section 5 is an extension of the second section 2 through to a lower end of the suction caisson 3. In addition to being connected to the second section 2 by the circumferential weld 26, the third section 5 is connected to the suction caisson 3 by having longitudinal welds 53 along an outer portion 52 of the third section 5 to support structures 33, 34 of the suction caisson 3. There may typically be more than two support structures 33, 34 connected to the outer portion 52 of the third section 5, such as four, six, eight or twelve support structures 33, 34.

As shown in Figure 3 and as explained, the welded connections 25, 26, 53 of the subsea assembly 1 are not as exposed and/or vulnerable to the structural loads as a weld above a foundation would typically be, and thus are not as critical. As the quality of welds can typically not be guaranteed, even with extensive quality assurance procedures, the risk of major accidents may be reduced by lowering the criticality of the welds.

In Figure 4, the subsea assembly 1 can be seen installed into a seabed 9.

The structural loads affecting the subsea assembly 1 will typically follow a path through the assembly 1 as follows: From the flow-control apparatus 6 to the first section 4, further to the second section 2, to the support structures 31 , 32, to an outer wall of the suction caisson 3 and finally to a soil below the seabed 9. Advantageously, the loads will not have to travel through a largely unsupported, circumferential end-to-end weld connecting two tubular structures above the seabed 9.

The structure 100, aligned with an end-to-end connection of cylinders, facilitates a shortest possible vertical transfer of loads between the two by having the wall of the upper cylinder, the first section 4, resting directly vertically on top of the lower cylinder, the second section 2.

The bore 8 through the first section 4 may be of a diameter allowing for all necessary drilling operations to install the subsea assembly 1 as a hydrocarbon-producing subsea assembly 1 . The bore 8 may typically have an inner diameter sufficient to fit a 13 3/8 inches (34 cm) casing string as the first casing string 7, or an even greater inner diameter, such as an inner diameter to fit a 17 inches (43 cm) casing string as the first casing string 7. The first section 4 may further comprise other systems as part of the first section 4 or connected to the first section 4, such as a production flow base, an annulus line, a bleed/vent line, and more. The subsea assembly 1 , with said first section 4, the second section 2, the third section 5 and the suction caisson 3, is invented and designed to typically be assembled in a topsides facility, typically onshore. The subsea assembly 1 may be assembled as a single unit onshore, and lowered to a seabed in a position where there exists no preinstalled well or foundation. The installation may then only require operations such as drilling for and installing casing strings, drilling for and installing a production tubing string and downhole completion, all of which may be performed through the bore 8 of the subsea assembly 1 , and connecting to an external flow line (not shown) to be ready for production of hydrocarbons.

After installation of the subsea assembly 1 into a seabed 9, drilling operations and installation of casing strings can be performed through the bore 8 running longitudinally through the first section 4, the second section 2 and the third section 5. A first casing string 7 installed after the installation of the subsea assembly 1 may form an annulus 72 between a wall of the first casing string 7 and a wall of the bore 8 of the subsea assembly 1 . Subsequently, a cementing operation will typically be performed to complete the installation procedure of the casing string 7, to provide a secure connection of the casing string 7 to the third section 5, to support the casing string 7. The first casing string 7 will typically be suspended from the lowermost casing hanger profile 42 of the first section 4, but other embodiments of the subsea assembly 1 may have a first casing string 7 suspended from the second section 2.

As the first casing string 7 is suspended from a casing hanger profile 42, there are no welds in the system exposed to high-pressure conditions. The welds of the subsea assembly 1 may only be used to connect structures, they are not part of the subsea assembly's 1 pressure-integrity function.

When installing and cementing the first casing string 7 in place, it is advantageous to have it cemented firmly in place at least partly through the suction caisson 3 to ensure a rigid connection of the casing string 7 to the suction caisson 3. In the subsea assembly 1 , comprising the second section 2, having the invented connection between the second section 2 and the first section 4, there is no separation of the internal part of the first section 4 from the annulus 72 formed between the second and third section 2, 5 and the first casing string 7. Therefore, return cement from the cementing of the first casing string 7, coming up through the annulus 72, could potentially reach and pollute the inside of the first section 4. This may be particularly problematic in embodiment of the first section 4 having hanger profiles 42 and/or where valves and/or other sensitive features may be exposed to the return cement. To avoid the issue, the subsea assembly 1 may comprise means to release return cement before it reaches the inside of the first section 4.

Figure 5 shows the subsea assembly 1 comprising a solution to the above-mentioned problem in the form of cement release lines 81 , for releasing return cement from the annulus 72 onto the seabed 9. The arrangement shown in Figure 5 has two release lines 81 , each comprising an opening 82 in the outer wall of the annulus 72. The openings 82 each provide a pathway to a pipe 83 having a valve 84, the pipe 83 leading to a point above the seabed 9 where the cement can be released. The opening 82 in the outer wall of the annulus 72 may be an opening 82 in the second section 2, and/or in the third section 5 below the second section 2. Preferably, the openings 82 in the annulus 72 wall for the cement release lines 81 are placed low enough in the system that return cement in the annulus 72 can be securely evacuated from the annulus 72 before it can pollute the first section 4, and high enough that the first casing string 7 can be sufficiently cemented to the foundation 3. Typically, the second section 2 may have the openings 82 above an end-to-end, circumferential welded connection (not shown) to a third section 5 (not shown) and below a longitudinal welded connection (not shown) to a support structure 31 , 32 of a suction caisson 3.

The subsea assembly 1 may be for drilling for an exploration well or a more complex subsea assembly 1 for a well for production of hydrocarbons. In embodiments of the subsea assembly 1 for drilling exploration wells, the first section 4 may be quite simple, as shown in figures 2-5, where the first section 4 is arranged to connect to a blowout preventer, whereas the first section 4 in embodi- merits of the subsea assembly 1 for a well for production of hydrocarbons may be more complex, as shown in figures 6-9.

The subsea assembly 1 may be a subsea assembly 1 like the one shown in Figure 6, wherein the subsea assembly 1 comprises a suction caisson 3, a second section 2, cement return lines 81 , a protective structure 10 comprising an openable lid 16, a tree cap 19, and a first section 4 forming a part of a Christmas tree 460 and an external circulation line 430.

In Figure 7, the subsea assembly 1 of Figure 6, is shown installed in a sediment of a seafloor 9.

Figure 8 shows the first section 4, in greater detail, for a well for production of hydrocarbons, wherein the first section 4 forms part of a flow-control apparatus. It is shown that the first section 4 is connected to a swab valve 480 which in turn is connected to a mandrel 490. The first section 4 has an upper fitting 46 for a bolted connection to the swab valve 480. The swab valve 480 has a lower fitting 481 for the bolted connection to the first section 4 and an upper fitting 489 for a bolted connection to the mandrel 490. The mandrel 490 has a fitting 491 for the bolted connection to the swab valve 480 and an upper fitting 499 for a connection for a tree cap (not shown).

The first section 4 comprises casing hanger profiles 402, 403 and latching grooves 404 for enabling casing hanger latching rings to lock casings to the first section 4. Furthermore, it comprises a concentric tubing hanger 409. In the Figure, it is also shown casings 902, 903 and a tubing 909, suspended from the aforementioned profiles 402, 403, 409 in the main bore 8 of the subsea assembly 1 .

The first section 4 has an outlet through a wall to a flow line 410 for flow of a produced fluid from the main bore 8. The flow line 410 has a production master inner valve 413 and a production wing valve 414, which are both fail-safe valves. Furthermore, the flow line 410 has a production bore pressure and temperature sensor 415, for monitoring of pressure and temperature of a fluid in the production line 410 between the production master inner valve 413 and the production wing valve 414. The flow line 410 further has a flow-line connector 416 for connecting to an external flow line (not shown).

The first section 4 further has an outlet for an external circulation line 430. The external circulation line 430 is shown having a hot-stab connector 431 and extending from said hot-stab connector to an annulus of the subsea assembly 1 through a wall 131 of the main bore 8. The connector 431 may comprise a barrier element, such as a fail-safe barrier valve (not shown) as there may be need for a double barrier between the end of the external circulation line and the main bore 8. Furthermore, there is a crossover line 420, leading from the external circulation line 430 to the flow line 410, provided with a crossover valve 421 . There is also provided an annulus-bore pressure and temperature sensor 434 and a fail-safe annulus master valve 435 in the external circulation line 430. Furthermore, the first section 4 comprises outlets to control lines 442 for a control line system 440 that may be accessed through a hot-stab connector 441 . The control line system 440 has three control lines 442 and three tubing-hanger down-hole line seals 449 for sealing off down-hole tubing-hanger ports.

There is also provided an inductive downhole line pressure and temperature sensor system 450, for reading pressure and temperature from downhole sensors, comprising means for inductive communication for sending power to and sending and/or receiving signals from a not shown down- hole gauge system of the subsea assembly 1 .

The first section 4 is further shown having an upper tubing hanger seal 408 and a lower tubing hanger seal 407, providing a sealing system for sealing off the flow line 410.

It should be noted that embodiments of the first section 4 may further comprise, be part of and/or be connected to one or more parts and/or lines not shown in Figure 8, such as more valves, more hanger profiles, more sensors, etc., and that embodiments of the first section 4 may be without one or more of the parts and/or lines shown in Figure 8. Furthermore, it should be noted that embodiments of the first section 4, such as the ones shown in figures 8 and 9, with all the features said in the description that the first section 4 comprises, is connected to and/or forms part of, will typically have a body forged or machined for receiving or connecting to said other parts and/or lines and/or features.

In Figure 9, an embodiment of the first section 4 is shown further having an outlet for a B-annulus line 470 for monitoring pressure and temperature in a B-annulus of a subsea assembly 1 , and/or for circulating fluid and/or for injecting cement into the B-annulus. For the purpose of monitoring pressure and temperature conditions, the B-annulus line 470 has a pressure and temperature sensor 475. The line further has two valves 472, 473 and a hot-stab connector 474. The sensor 475 is placed between the two valves 472, 473. An embodiment of the B-annulus line 470 may have a hot-stab connector comprising a valve, such that the valve 472 mounted upstream the sensor 475 in the line may normally be kept in an open state to allow monitoring of annulus conditions while maintaining a double barrier between the main bore and the environment.

The subsea assembly 1 may typically be assembled in a topsides facility offshore or onshore. The assembly 1 may comprise the second section 2 and the third section 5 mounted to a suction caisson 3 or a template, e.g. by welding the second section 2 and the third section 5 together end-to- end with a circumferential weld and welding the second section and the third section 5 to the suction caisson 3 or the template by welding them to a support structure of the suction caisson 3 or the template. Other methods of joining the mentioned parts may also be possible, such as mechanically connecting the third section 5 to the second section 2 provided they are provided with means for such a connection. Furthermore, the assembly may comprise the first section 4 mechanically connected to the second section 2, e.g. by a joint made up by means of a connector. The first section may form part of a flow-control apparatus, as the one shown in Figures 8 or 9, and the flow-control apparatus may be assembled prior to a connection of the first section 4 to the second section 2.

The subsea assembly 1 may be assembled at different locations, e.g. with a suction caisson 3, a third section 5 and a second section 2 being assembled at one location, e.g. at a workshop, and then with a first section 4 mounted to the second section 2 at another location, e.g. a dock, prior to shipping the subsea assembly 1 offshore.

Assembling the subsea system 1 in a topsides facility may be highly advantageous, as it may make the subsea installation procedure less demanding with regards to complexity and time, and thus also with regards to cost. The subsea assembly 1 may, after having been assembled topsides, be lowered as one unit to a seabed 9 at a location for establishing a well without any pre-drilling having to be performed at the location for establishing the well prior to the installation of the assembled unit into the seabed 9.

The bore of the assembly 1 should be large enough to run drilling equipment through the bore to establish a well below the subsea assembly post installation of the subsea assembly 1 in the seabed 9. Typically, the diameter of the bore of the subsea assembly 1 may be between 20 inches (51 cm) and 15 inches (38 cm), more preferably between 16 inches (41 cm) and 19 inches (48 cm), more preferable between 17 inches (43 cm) and 18 inches (46 cm), but it could be larger than 20 inches (51 cm) and smaller than 15 inches (38 cm). A smaller diameter than 1 5 inches (38 cm) could be enough for some types of wells, particularly for shallow wells, whereas a bore having a diameter of more than 20 inches (51 cm) may be beneficial for a deeper well.

Further parts of the subsea assembly 1 than shown in Figure 9 may also be assembled to the subsea assembly prior to a lowering of the subsea assembly 1 onto a seabed 9, such as a protective structure, a tree cap, a swab valve, and more.

When installing the subsea assembly 1 , it will typically be lowered as one assembled unit to a seabed 9, and thereafter sucked into the seabed 9 by use of vacuum pumps.

The subsea assembly 1 may be further developed by drilling for and installing one or more further casing strings. When drilling further it may be necessary to have the subsea assembly 1 comprise or be connected to a flow-control apparatus, such as a BOP.

Figure 10 shows an embodiment of the structure 100, where the structure 100 is configured for better communication of loads to a foundation through protrusions 28 from an outer portion of the second section 2 of the structure 100. The protrusions 28 may typically be arranged to align with an upper and a lower portion of a structure of a well foundation, such as a support structure of a suction caisson, to which the structure 100 is to be connected by weld. The protrusions 28 changes the interface geometry of the structures, to reduce stress concentration and to allow the weld to be moved away from an area most susceptible to fatigue damage, to extend the fatigue life of the weld.

The second section 2 of the structure 1 00 is further seen having a locking mechanism 27 for fixing a casing to the second section 2. The locking mechanism 27, a latch 27, may provide additional lock-down capacity to mitigate a risk of a casing hanger being pushed upwards in event of extreme vertical loading being subjected to the foundation.

Figure 1 1 shows a structure 100, wherein the first section 4 has a threaded collar 47 for receiving a corresponding thread on a body 27 of the second section 2.

Figure 12 shows a possible embodiment of the structure 100, wherein the first section 4 forms a housing for receiving a high-pressure wellhead housing 54.