Subsea well installation

Abstract

A subsea well installation is provided, comprising a first pipeline comprising a first valve arrangement and a second pipeline comprising a second valve arrangement. The first valve arrangement is connected to a first subsea well and the second valve arrangement is connected to a second subsea well. The first valve arrangement is connected to the second valve arrangement. The installation is arranged such that fluid can be routed from the first well to any of the first pipeline and second pipeline. Each valve arrangement may comprise three two-way ball valves. Also provided is a method of installing the subsea well installation and a method of operating the subsea well installation.

Claims

1. A method of installing a subsea well installation, the method comprising: deploying a first pipeline comprising a first valve arrangement; deploying a second pipeline comprising a second valve arrangement; connecting the first valve arrangement to a first subsea well; connecting the second valve arrangement to a second subsea well; and connecting the first valve arrangement to the second valve arrangement, wherein the subsea well installation is arranged such that fluid can be routed from the first well to any of the first pipeline and second pipeline; wherein the step of connecting the first valve arrangement to the first subsea well comprises connecting the first valve arrangement and the first subsea well with a first jumper, wherein the first jumper is piggybacked to the first pipeline during deployment of the first pipeline by means of straps, and wherein the method further comprises the step of cutting the straps in order to release the first jumper prior to the step of connecting the first valve arrangement to the first subsea well.

2. A method as claimed in claim 1, wherein deploying the first and second valve arrangements comprises installing the first and second valve arrangements in first and second pipeline sections respectively, wherein the method further comprises connecting the first and second pipeline sections inline of the first and second pipelines, respectively.

3. A method as claimed in claim 1, wherein the first valve arrangement comprises three two-way valves: first, second and third valves, each having two ports; wherein: the first two-way valve has a first port connected to the first subsea well and a second port connected to a space communicating between second ports of the first, second and third two-way valves and wherein the step of connecting the first valve arrangement to the first subsea well comprises connecting the first port of the first two-way valve to the first subsea well; the second two-way valve has a first port connected to the first pipeline and a second port connected to the space communicating between second ports of the first, second and third two-way valves; and the third two-way valve has a first port connected to the second valve arrangement and a second port connected to the space communicating between second ports of the first, second and third two-way valves and wherein the step of connecting the first valve arrangement to the second valve arrangement comprises connecting the first port of the third two-way valve of the first valve arrangement to the second valve arrangement.

4. A method as claimed claim 1, wherein the step of connecting the second valve arrangement to the second subsea well comprises connecting the second valve arrangement and the second subsea well with a second jumper, wherein the second jumper is piggybacked to the second pipeline during deployment of the second pipeline by means of straps, and wherein the method further comprises the step of cutting the straps in order to release the second jumper prior to the step of connecting the second valve arrangement to the second subsea well.

5. A method as claimed in claim 1, wherein the first pipeline comprises a third valve arrangement and the second pipeline comprises a fourth valve arrangement, and the method further includes connecting the third valve arrangement to a third subsea well, connecting the fourth valve arrangement to a fourth subsea well and connecting the third valve arrangement to the fourth valve arrangement, such that fluid can be routed from the third well to any of the first pipeline and the second pipeline.

6. A method as claimed in claim 1, wherein the steps of deploying the first pipeline and deploying the second pipeline comprise laying the pipelines into or onto a carrier at a landing structure such that the carrier supports the pipelines.

7. A method as claimed in claim 6, wherein the carrier is slidably mounted to the landing structure and the method comprises the step of sliding the carrier so as to axially align the first and second pipelines.

8. A method as claimed in claim 6, wherein each pipeline comprises two lever arms and the carrier comprises two supports, each support having two openings for receiving the lever arms of a pipeline; and the step of laying the pipelines into or onto the carrier comprises laying the pipelines into or onto the supports and locating the lever arms in the openings of the supports.

9. A method as claimed in claim 1, wherein the installation is arranged such that fluid can be routed from the first well to the first pipeline via the first valve arrangement and to the second pipeline via the first valve arrangement and the second valve arrangement.

10. A method of installing a subsea well installation, the method comprising: deploying a first pipeline comprising a first valve arrangement; deploying a second pipeline comprising a second valve arrangement; connecting the first valve arrangement to a first subsea well; connecting the second valve arrangement to a second subsea well; and connecting the first valve arrangement to the second valve arrangement, wherein the subsea well installation is arranged such that fluid can be routed from the first well to any of the first pipeline and second pipeline; wherein the step of connecting the second valve arrangement to the second subsea well comprises connecting the second valve arrangement and the second subsea well with a jumper, wherein the jumper is piggybacked to the second pipeline during deployment of the second pipeline by means of straps, and wherein the method further comprises the step of cutting the straps in order to release the jumper prior to the step of connecting the second valve arrangement to the second subsea well.

11. A method as claimed in claim 10, wherein deploying the first and second valve arrangements comprises installing the first and second valve arrangements in first and second pipeline sections respectively, wherein the method further comprises connecting the first and second pipeline sections inline of the first and second pipelines, respectively.

12. A method as claimed in claim 10, wherein the first valve arrangement comprises three two-way valves: first, second and third valves, each having two ports; wherein: the first two-way valve has a first port connected to the first subsea well and a second port connected to a space communicating between second ports of the first, second and third two-way valves and wherein the step of connecting the first valve arrangement to the first subsea well comprises connecting the first port of the first two-way valve to the first subsea well; the second two-way valve has a first port connected to the first pipeline and a second port connected to the space communicating between second ports of the first, second and third two-way valves; and the third two-way valve has a first port connected to the second valve arrangement and a second port connected to the space communicating between second ports of the first, second and third two-way valves and wherein the step of connecting the first valve arrangement to the second valve arrangement comprises connecting the first port of the third two-way valve of the first valve arrangement to the second valve arrangement.

13. A method as claimed in claim 10, wherein the first pipeline comprises a third valve arrangement and the second pipeline comprises a fourth valve arrangement, and the method further includes connecting the third valve arrangement to a third subsea well, connecting the fourth valve arrangement to a fourth subsea well and connecting the third valve arrangement to the fourth valve arrangement, such that fluid can be routed from the third well to any of the first pipeline and the second pipeline.

14. A method as claimed in claim 10, wherein the steps of deploying the first pipeline and deploying the second pipeline comprise laying the pipelines into or onto a carrier at a landing structure such that the carrier supports the pipelines.

15. A method as claimed in claim 14, wherein the carrier is slidably mounted to the landing structure and the method comprises the step of sliding the carrier so as to axially align the first and second pipelines.

16. A method as claimed in claim 14, wherein each pipeline comprises two lever arms and the carrier comprises two supports, each support having two openings for receiving the lever arms of a pipeline; and the step of laying the pipelines into or onto the carrier comprises laying the pipelines into or onto the supports and locating the lever arms in the openings of the supports.

17. A method as claimed in claim 10, wherein the installation is arranged such that fluid can be routed from the first well to the first pipeline via the first valve arrangement and to the second pipeline via the first valve arrangement and the second valve arrangement.

Description

(1) Preferred embodiments of the present invention will now be described by way of example only and with reference to the accompanying drawings, in which:

(2) FIG. 1 illustrates a pipeline section having valves installed therein prior to installation, according to an embodiment of the invention;

(3) FIG. 2 illustrates a subsea well installation according to an embodiment of the invention;

(4) FIG. 3a is a side view of a valve viewed in the direction of arrow A in FIG. 1;

(5) FIG. 3b is a side view of the valve of FIG. 3a viewed in the direction of arrow B of FIG. 1;

(6) FIG. 4 is a schematic view of the valve of FIGS. 3a and 3b;

(7) FIG. 5 is a cross-section of the valve taken along the line C-C of FIG. 3b;

(8) FIG. 6 schematically illustrates flow paths in the subsea well installation of FIG. 2;

(9) FIG. 7 illustrates a foundation structure which may form part of the subsea well installation of FIG. 2;

(10) FIG. 8 illustrates a pipeline having a pipeline section connected inline thereof and

(11) FIGS. 9A and 9B illustrate an embodiment of a carrier.

(12) A pipeline section 1 is illustrated in FIG. 1. This section of pipeline 1 is typically 40 to 50 m long and is a section that is connectable inline of a complete pipeline. It may be termed a header pipe or header pipe joint. The pipeline section 1 will typically be connected inline of a complete pipeline prior to deployment subsea. A pipeline 100 having pipeline section 1 connected inline thereof by connectors 50 is illustrated in FIG. 8. Note that none of the features of pipeline section 1 are illustrated, this drawing merely shows the connection of the pipeline section 1 inline of the pipeline. The drawing can also be said to show the connection of a pipeline section 10 inline of a pipeline 110; pipeline section 10 is described later below.

(13) The pipeline section 1 is shown in its pre-installed configuration, i.e. the configuration which it is in prior to and during deployment to the sea bed. Two valve arrangements (valve assemblies) 4, 4′ are installed in (i.e. integrated into and/or supported by) the pipeline section 1 on the uppermost side of the pipeline section 1. Each valve arrangement is a three ball-valve arrangement, i.e. comprising three ball-valves, which will be described in more detail later with reference to FIGS. 3a, 3b, 4 and 5. Each ball valve 5a, 5b, 5c of the first valve arrangement 4 and each ball valve 5a′, 5b′ 5c′ of the second valve arrangement 4′ has an actuation interface 6a, 6b, 6c, 6a′, 6b′, 6c′ respectively, by which the ball valve is actuated (controlled, operated). The ball valves may be actuated in different ways depending on the particular scenario. In one embodiment the actuation interfaces may be interfaces for ROV actuation. In another embodiment the actuation interfaces may be interfaces for electric actuators. ROV actuation may, in some situations, be simpler and cheaper than electric actuation. However, if the ball valves may need to be actuated relatively frequently, it may be less expensive to use electric actuators and install the necessary power supply rather than repeated uses of ROVs.

(14) Two flexible jumpers 2, 7 and 2′, 7′ are connected to each valve arrangement 4, 4′ respectively. Flexible jumper 2, 2′ is configured for connecting to an xmas tree at a well. Flexible jumper 7, 7′ is configured for connecting to another valve arrangement installed in another pipeline. Each flexible jumper 7, 7′ comprises an ROV installable connector 9, 9′ at an end thereof so that an ROV can connect the jumper 7, 7′ to the other valve arrangement.

(15) The valve arrangements 4, 4′ will typically be fabricated, welded into the pipeline section 1 and then tested on-shore. The flexible jumpers 2, 7 and 2′, 7′ will be connected to the valve arrangements 4, 4′ and are then strapped to the pipeline section 1 by straps 3, also on-shore. This is known as piggy-backing. Thus, the connections between the valve arrangements and the jumpers are already complete before a pipeline comprising the pipeline section is deployed subsea, hence avoiding the need to carry out these connections subsea, and thus minimising cost.

(16) The preassembled pipeline section 1 comprising the valve arrangements and piggybacked jumpers is then supplied to the laying vessel, and connected (e.g. by welding) inline of a pipeline 100 topside on the vessel prior to laying of the pipeline 100 subsea. Hence, the pipeline section 1 becomes part of the pipeline 100. A laying operation is then performed to lay the pipeline, having the pipeline section 1 installed therein, at a landing structure at the seabed. An embodiment of a landing structure 40 is illustrated in FIG. 7. This comprises a foundation comprising a suction anchor 36 on which is mounted a support frame 35. A carrier 30 is mounted on the support frame, and has two curved supports 31, 32, each for holding and supporting a pipeline. This will be described in more detail later.

(17) FIG. 2 illustrates a subsea well installation comprising a first pipeline having the pipeline section 1 inline thereof. The first pipeline has been laid into a curved support 31 of the carrier 30, mounted on the support frame of the support structure (not shown in FIG. 2). The installation also comprises a second pipeline having a second pipeline section 10 inline thereof which is substantially identical to the pipeline section 1 (although jumpers for connecting the valve arrangements of the second pipeline to the valve arrangements of the first pipeline may not be present on the second pipeline as the jumpers for connecting the valve arrangements are provided on the first pipeline), and which has been laid into a curved support 32 of the carrier 30. FIG. 2 illustrates the installation when the valve arrangements 4, 4′ of the pipeline section 1, and the valve arrangements 14, 14′ of the pipeline section 10, have been fully connected up. The connection process will now be described.

(18) After the pipeline section 1 and the pipeline section 10 have been laid into the supports 31, 32 of the carrier 30, an ROV cuts the straps 3 which were strapping the flexible jumpers 2, 2′ and 7, 7′ to the pipeline section 1. Similar straps are also cut which were strapping the flexible jumpers 12, 12′ to the pipeline section 10.

(19) An ROV connects the flexible jumper 2 to the xmas tree of a well 8. Similarly an ROV connects the flexible jumper 2′ to the xmas tree of a well 8′, connects the flexible jumper 12 to the xmas tree of a well 18, and connects the flexible jumper 12′ to the xmas tree of a well 18′. It will be appreciated that the wells are shown as considerably smaller than they are in practice, for ease of illustration.

(20) An ROV connects the connector 9 of the flexible jumper 7 of the valve arrangement 4 to the valve arrangement 14 of the pipeline section 10. It also connects the connector 9′ of the flexible jumper 7′ of the valve arrangement 4′ to the valve arrangement 14′ of the pipeline section 10. The valve arrangements 14 and 14′ do not need their own flexible jumpers similar to flexible jumpers 7, 7′ of the valve arrangements 4, 4′. In this way, the pipeline sections 1 and 10 are therefore not identical. The same ROV may perform all the connections in the same operation. Once the connections have all been made, well production can start.

(21) The valve arrangement 4′ will now be described in more detail with reference to FIGS. 3a, 3b, 4 and 5. It will be appreciated that the valve arrangements 4 is essentially the same as the valve arrangement 4′, though the particular configuration of components and location of connections varies slightly. For example, the ROV interface 6c of the valve arrangement 4 is on the opposite side to where the ROV interface 6c′ is located on the valve arrangement 4′, for ease of access. The valve arrangement 4′ is substantially the same as the valve arrangement 14′, whilst the valve arrangement 4 is substantially the same as the valve arrangement 14. Therefore, to avoid repetition, only the valve arrangement 4′ is described in detail as the same essential features and functions apply equally to the other valve arrangements.

(22) FIG. 3a illustrates the side of the valve arrangement 4′ viewed in the direction of arrow A of FIG. 1. The ROV interfaces 6a′ and 6b′ extend from the top of the valve arrangement 4′, whilst the ROV interface 6c′ extends from a side. FIG. 3b is a side view of the valve arrangement 4′ viewed in the direction of arrow B of FIG. 1 and FIG. 3a.

(23) FIG. 4 schematically illustrates the ball valve functionality of the valve arrangement 4′. A first ball valve 5a′ providing a two-way valve functionality is controllable by ROV via actuation interface 6a′. A second ball valve 5b′ providing a two-way valve functionality is controllable by ROV via actuation interface 6b′. A third ball valve 5c′ providing a two-way valve functionality is controllable by ROV via actuation interface 6c′. The ball valves may for example be standard 5-6 inch (0.127 m-0.152 m) or 8-9 inch (0.203 m-0.229 m) ball valves.

(24) FIG. 5 is a cross-sectional view taken along line C-C of FIG. 3b, and shows the internal components of the valve arrangement 4′. The valve arrangement comprises three ball valves, 5a′, 5b′ and 5c′. Fluid flow can enter and leave the valve arrangement 4′ via flexible jumper 2′, flexible jumper 7′ and the pipeline section 1 (and therefore the pipeline 100). The ball valves can be individually electrically actuated by ROV via interfaces 6a′, 6b′ and 6c′ so as to receive flow from and direct flow to any of the flexible jumper 2′, flexible jumper 7′ and pipeline section 1. For example, if it is desired for flow produced from well 8′ to enter the pipeline 100, then ball valves 6b′ and 6c′ are actuated so as to allow entry of flow from flexible jumper 2′ and direct the flow to the pipeline section 1. If it is desired for flow from the valve arrangement 14′ to enter the pipeline 100, then ball valves 6a′ and 6c′ are actuated so as to allow entry of flow from flexible jumper 7′ and direct the flow to the pipeline section 1.

(25) FIG. 6 schematically illustrates the various flow paths provided in the subsea well installation in more detail. The letters a, b, c, d, e, f, g and h denote various flow entry and exit points in the arrangement comprising: valve arrangements 4 and 14, wells 8 and 18, and pipeline sections 1 and 10. The letters a′, b′, c′, d′, e′, f′, g′ and h′ denote the various flow entry and exit points in the arrangement comprising: valve arrangements 4′ and 14′, wells 8′ and 18′ and pipeline sections 1 and 10.

(26) Considering first the arrangement comprising valve arrangement 4 and 14, wells 8 and 18 and pipeline sections 1 and 10; flow may exit the well 8 at point a, travel through flexible jumper 2 and enter valve arrangement 4 at point b. Flow may be directed within the valve arrangement 4 either to point d where it enters pipeline section 1, or to point c where it exits valve arrangement 4 and travels through flexible jumper 7 to point 3 where it enters valve arrangement 14. The flow may be directed within valve arrangement 14 to point f where it enters pipeline section 10.

(27) If flow was routed to point g where it exits valve arrangement 14 and travels through flexible jumper 12 to point h, it could potentially enter well 18 causing back flow. Therefore, flow would generally not be routed in this way. Furthermore, well-known backflow prevention methods may be used, for example chokes at the xmas tree outlets which equalise the pressure from well 8 and well 18.

(28) Conversely, flow may exit well 18 at point h, travel through flexible jumper 12 and enter valve arrangement 14 at point g. Flow may be directed within the valve arrangement 14 either to point f where it enters pipeline 10, or to point e where it exits the valve arrangement 14 and travels through flexible jumper 7 to point c where it enters valve arrangement 4. The flow may be directed within valve arrangement 4 to point d where it enters pipeline section 1. As described above, it would not be desirable to route flow to point b where it exits valve arrangement 4 and travels through flexible jumper 2 to point a as it could then cause backflow into well 8. A choke arrangement could be used to avoid backflow as discussed previously.

(29) Similar flowpaths are provided by the second arrangement comprising valve arrangements 4′ and 14′, wells 8′ and 18′ and pipeline sections 1 and 10, and so these will not be described here.

(30) The flowpaths provided by the subsea well installation 20 of the present invention thus enable flow to be routed as desired depending for example on the flow rate of fluid from the wells, e.g. hydrocarbons being produced. For example, if there is a high flow rate in pipeline 100 but a lower flow rate in pipeline 110, it may be desirable to route the flow from both wells 8 and 18 into pipeline 110 to even out the flow rate in the pipelines.

(31) Generally, flow from one well will not be divided between two pipelines, the whole flow will be provided to one pipeline.

(32) The landing structure 40 of FIG. 7 will now be described in more detail. As discussed above, the landing structure 40 comprises a suction anchor 36 on which is mounted a support frame 35 having a carrier 30. The carrier comprises two curved supports 31, 32, each for holding and supporting a pipeline section 1, 10 respectively. During the laying process, the pipeline sections 1, 10 are laid into the curved supports 31, 32, which are of a complementary shape to the pipeline sections. The carrier 30 is located and orientated on the support frame 35 in the correct lateral and vertical position and orientation such that once the pipeline sections are laid in the supports 31, 32 they are correctly aligned and orientated.

(33) As can be seen in FIG. 2, each pipeline section 1, 10 is provided with two lever arms 25, one extending from each side, which are used to locate the pipeline in the support (the lever arms are not shown in FIG. 1). The lever arms 25 may alternatively be termed locking pins, locating pins or shafts. The lever arms 25 are illustrated as being cylindrical, but in other embodiments may take other shapes. The lever arms may be fixed, e.g. welded, to the pipeline section 1, 10 topside e.g. on the laying vessel. Each curved support 31, 32 has two openings 33, arranged to receive the lever arms 25 of the pipeline section 1, 10 when the pipeline is laid into the support. The reception of the lever arms 25 in the openings 33 both locates and orientates the pipeline sections 1, 10 in the correct position in the support, and rotationally aligns the pipeline sections 1, 10 in terms of roll, pitch and yaw. This ensures that the valve arrangements 4, 4′, 14, 14′ are on the uppermost part of the pipeline 1, 10, as laid. Once the pipelines are laid in the supports they are locked in place such that they are prevented from moving.

(34) It is important for the pipelines to be correctly positioned, so that the valve arrangements 4, 4′, 14, 14′ can be connected up to each other and to the wells 8, 8′, 18, 18′ by the jumpers 7, 7′, 2, 2′, 12, 12′. If the pipelines were not correctly positioned, then for example the jumpers may not reach the wells to which they are to be connected (though since flexible jumpers are used, an element of flexibility is provided).

(35) In another embodiment of the carrier 66 as illustrated in FIGS. 9A and 9B, the carrier 66 may be slidably held in a carrier holder 65 on the support frame, so that it can be slid back and forth with respect to the support frame. Thus, once the pipelines 100, 110 having pipeline sections 1, 10 have been laid in the carrier 66, the carrier 66 can be slid in order to adjust the axial alignment of the pipelines. Once the correct axial alignment has been achieved, the carrier 66 can be locked in position in the carrier holder 65. The ability to adjust the axial alignment of the pipelines may be useful to correctly position them with respect to the wells. This embodiment will now be discussed in further detail.

(36) Note that FIGS. 9A and 9B do not show the jumpers and strapping, for simplicity. The carrier holder 65 has a carrier 66 slidably held therein. The carrier holder 65 is attached to a support frame of the landing structure (not shown in FIGS. 9A and 9B). The carrier 66 is slidable back and forth in the direction of arrows N. The carrier 66 is configured to receive the pipeline section 1 when the pipeline 100 is laid at the structure. FIG. 9A illustrates the pipeline section 1 approaching the carrier 66 during the laying process. Rigging 77 is attached between the carrier holder 65 and the pipeline section 1 to guide the pipeline section 1 into place, as it moves down and along in the direction of arrows L and M.

(37) The pipeline section 1 is provided with two lever arms 25, one extending from each side, which are used to locate the pipeline section in the carrier 66. The lever arms 25 may alternatively be termed locking pins, locating pins or shafts. The lever arms 25 are illustrated as being cylindrical, but in other embodiments may take other shapes. The lever arms may be fixed, e.g. welded, to the pipeline section 1 topside, preferably onshore.

(38) When the pipeline section 1 reaches the carrier 66, it is received and supported by a support 67 of the carrier. The support 67 comprises two plates extending upwardly from the base of the carrier 66, one plate arranged on each side of the carrier so that the pipeline section 1 can be received therebetween.

(39) Each plate comprises a base portion 67″ having an opening (slot, groove) 68 therein for receiving a lever arm 25 of the pipeline section 1. The opening in this embodiment is a slot with straight sides and a curved bottom. Each plate also comprises two guiding faces 67′, each extending from the top of the base portion 67″ on either side of the opening 68.

(40) The guiding faces 67′ are each triangularly shaped, with a straight edge extending at an angle from the top of a straight side of the slot to an apex. Thus, an obtuse angle is formed between the straight side of the slot and the edge of the guiding face 67′. The obtuse angle is preferably at least 225° or more.

(41) This angled edge of the guiding faces 67′ act as a guiding system for the lever arm 25 of the pipeline section 1. As the pipeline section is lowered into the support, the angled edges “catch” the lever arms 25 and guide them down into the slot.

(42) Furthermore, the guiding faces 67′ bend outwards from the base portion 67″ of each plate. In other words, they are at an angle to the base portion from which they extend. These angled guiding faces 67′ act as a guiding system for the pipeline section 1. As the pipeline section 1 is laid into the support 67, the guiding faces 67′ can “catch” the pipeline section 1 once it comes near the support 67, and guide it into and towards the bottom of the support 67.

(43) The reception of the lever arms 25 in the openings 68 locates the pipeline section 1 in the correct position in the support 67/carrier 66. Arm 69 has a wedge 69′ which is then slid across the top of each opening which forces each lever arm 25 to the bottom of the opening 68. The lever arms are positioned on the pipeline section so that when they are held at the bottom of the openings 68, the pipeline section 1 is correctly rotationally aligned within the support 67/carrier 66. Thus, by forcing the lever arms 25 to the bottom of the openings 68, the pipeline section 1 is correctly rotationally aligned in terms of roll, pitch and yaw. Rotational alignment is important so that the valve arrangements in the pipeline section are “upended”, i.e. extend straight upwards, so that the actuation interfaces 6a, 6b, 6a′, 6b′ are easily accessible and so that the jumpers 2, 2′ are correctly positioned so as to be connected up to the wells.

(44) The carrier 66 is located on the landing structure in the correct lateral and vertical position, and thus once the pipeline section 1 is laid in the carrier, it is correctly aligned in terms of sway and heave. Surge (i.e. axial alignment) is adjusted as described later by sliding the carrier.

(45) The wedges 69′ may be slid across each opening by means of a screw mechanism at arm 69. They may then be locked in place across the top of each opening 68, thus locking the pipeline section 1 in the correct position. This is illustrated in FIG. 9B.

(46) The pipeline section 1 can then be adjusted to the correct axial position by sliding the carrier 66 in the direction of arrows N.

(47) Once correct axial alignment has been achieved, the carrier 66 is locked in position in the carrier holder 65, for example by a locking device such as screws, lugs, wedges or similar. Thus, the pipeline section 1 (and thereby the pipeline 100 it is inline of) is locked in the carrier 66, which is locked to the carrier holder 65, which is in turn attached to the support frame mounted on the suction anchor.

(48) In this embodiment, the carrier 66 is powered to cause it to slide within the carrier holder 65 and thus enable easy positioning of the carrier 66 and thus the pipeline section 1 held therein. The position of the carrier is controlled by hydraulic jacking cylinders operated by an ROV.

(49) It will be readily appreciated by the skilled person that various features of the sliding carrier of FIGS. 9A and 9B may be useful with the non-sliding carrier of FIG. 7. Whilst these features will not all be repeated again here for the sake of brevity, one example would be that the two curved supports 31, 32 may be provided with arms having wedges to slide across the top of the openings 33 to force the lever arms 25 to the bottom of the openings 33 and lock the pipeline section 1 in place. In another embodiment, a separate carrier may be provided for each pipeline, each carrier being independently slidable with respect to the other (or a single carrier may be provided having independently slidable curved supports). Thus, the axial alignment of the pipelines can be independently adjusted with respect to each other by separately sliding the carriers (or the curved supports). Once the correct axial alignment has been achieved, the carriers can be locked in position.

(50) The ability to adjust the axial alignment of the pipelines with respect to each other may be useful to correctly position the valve arrangements of one of the pipelines in relation to the valve arrangements of the other pipeline, to facilitate connection therebetween.