GB2492414A - Adding weight to a sag bend of a pipe during initial stages of pipeline laying - Google Patents

Abstract

The invention relates to the initiation of laying of an elongate flexible riser / pipeline 10 on the sea bed 16, wherein a termination head 12 is provided at an end of the pipeline, the termination head connected in turn to an anchor 14, wherein a sag bend curvature 24 is imparted to the pipeline by adding weight 30 locally to the pipeline at a sag bend region, wherein the termination head and portion of adjoining pipeline 26 are oriented towards the horizontal while above the seabed. Ideally, an installation vessel 28 applies tension to the riser / pipeline during the start of the laying process, which coupled with the addition of ballasts, causes the end region of the pipeline to curve towards the horizontal, parallel to the sea floor. The weights may take the form of individual ballast modules 30, or a thickened, possibly denser, region of the pipe end itself. Other independent claims relate to different stages of the initial pipe laying process.

Description

Initiation of lightweight flexible pipelines and umbilicals This invention relates to subsea laying of elongate flexible products such as lightweight flexible pipelines and umbilicals. The invention relates particularly to the initiation of installation operations.

Pipeline installation will be used to exemplify the invention in the following discussion.

However, it should be understood that the broad inventive concept extends to subsea laying of other lightweight elongate flexible products or elements, such as umbilicals.

To facilitate the initiation of pipelay, a subsea anchor must be preinstalled to provide a fixed point for a pipelay vessel to act against during the pipe pulling process. An example of a subsea anchor is a pile embedded in the seabed; other examples are an anchor held by its weight and/or by friction or engagement with the seabed, subsea structures such as templates, platform foundations and so on.

Initiation rigging is typically preinstalled with, and attached to, the anchor; this rigging typically comprises a wire rope of fixed length, although it could comprise a chain. A first portion of the initiation rigging may be preinstalled with the anchor and a second portion of the initiation rigging may be lowered with the pipeline to be connected to the first portion.

The initiation' stage of a pipeline installation operation typically involves the steps of: deploying and lowering a termination head toward the seabed, at the end of a pipeline extending from a pipelay vessel to the termination head; connecting the termination head to the initiation rigging anchored to the seabed; and laying the termination head and the adjoining section of the pipeline down on the seabed.

Initiation may also involve creating a tie-in loop in the pipeline for the termination head to be connected subsequently to a subsea structure, where the pipeline is laid in a curved (for example, serpentine) configuration after the termination head has been landed. Expansion loops are used to provide for controlled displacement of the pipeline with fluctuations in temperature and pressure so as to limit forces transferred to tie-in structures.

The initiation stage is to be distinguished from the subsequent normal lay' stage of a pipeline installation operation, as initiation suffers from particular problems that the present invention aims to address. For example, the normal lay stage can use the full layback range of the pipeline and so can be performed under correspondingly high sea states, whereas the initiation stage cannot.

As the normal lay stage cannot start until the initiation stage has been completed, the initiation stage is a key limiting factor in a pipeline installation operation. Problems affecting the initiation stage therefore have a disproportionate effect on the pipeline installation operation as a whole.

The initiation sequence is performed in steps of paying out product and moving the installation vessel after connecting up the initiation rigging between the termination head and the anchor point. The governing design criteria are typically found to be: pipeline limiting curvature, expressed as the minimum bend radius or MBR; pipeline departure angle at hang-off, to avoid contact with the hull of the pipelay vessel and/or over-bending of the pipeline; seabed clearance before landing the termination head, to avoid damaging the termination head; the landing angle of the termination head, to avoid over-bending or compression; and horizontal bottom tension when laying tie-in loops after landing the termination head.

As noted above, the initiation stage is often limited by pipeline curvature, expressed as the MBR of the pipeline. There is a risk of over-bending the pipe after initial touchdown of the termination head occurs, especially at the end of a bending restrictor commonly provided at the interface between the flexible pipeline and the rigid termination head; there is also a risk of damage to the termination head itself. To limit these risks, the termination head and the adjoining section of pipeline are required to be as close as possible to parallel with the seabed before touchdown. If water depth and pipeline bending stiffness allow, this is achieved by extending the pipeline configuration horizontally and forming a sag bend.

When establishing the iay configuration for a pipeline, the following parameters are typically used to control the initiation operation: anchor point elevation above the seabed; initiation rigging length; deployed length of pipeline; and position of the installation vessel.

Optimally, the subsea anchor point to which the initiation rigging is attached should be as high above the seabed as possible to help with levelling of the termination head and the adjoining section of pipeline: ideally the anchor point should be at an elevation of say 2 to 5 metres above the seabed. If the anchor point is close to the seabed, longer initiation rigging is regarded as the better option. In practice, however, various restrictions may thwart this optimal configuration.

The elevation of the anchor point and the length of the initiation rigging are typically dictated by an existing seabed layout, and may not be optimal for the initiation operation. In other words, the seabed layout may restrict the length of the initiation rigging and may also dictate an anchor point undesirably close to the seabed; for example, an elevation above the seabed of approximately 0.5 metre. Other disadvantageous factors are: relatively high product bending stiffness; a heavy termination head; shallow water depth; and a restriction in the pipeline departure angle from a pipelay vessel leading to a risk of over-bending at the hang-off point.

A heavy, robust but flexible pipeline with a lightweight termination head is the optimal combination, which in principle could be initiated without any form of installation aid.

Conversely, the combination of a lightweight but relatively stiff pipeline such as an ISU or integrated service umbilical with a heavy termination head is a challenging combination often resulting in a landing angle that is too steep and so requires some form of installation aid. The need for an installation aid increases if it is not possible to increase the anchor point elevation or to lengthen the initiation rigging length to allow a sag bend to form before landing the termination head.

These challenges result in the need for ancillary equipment to level the termination head and the adjoining section of pipeline during the initiation stage. The traditional and well-proven method is to use subsea buoyancy modules of typically 1 to 2 tonnes nominal buoyancy, connected to the termination head using slings. In this respect, reference is made to Figures 1 and 2 of the accompanying drawings, in which Figure 1 shows, schematically, a known pipeline initiation operation employing one or more buoyancy modules and Figure 2 shows known buoyancy modules that may be used in that operation. Figure 1 is a schematic view and is not to scale.

Referring particularly to Figure 1, this shows a lightweight flexible pipeline 10 hanging in the water column, suspended from a pipelay vessel that is omitted from this view. A termination head 12 is at the end of the pipeline 10.

Asubsea anchor 14 such as a pile is embedded in and extends above the seabed 16.

A wire rope serving as initiation rigging 18 is attached to the anchor 14 at a position above the seabed 16 and extends from there to the termination head 12. The termination head 12 and the pipeline 10 attached to it may therefore pivot about the anchor 14 via the initiation rigging 18.

A buoyancy module 20 also shown in Figure 2 is attached to the termination head 12 by a sling 22 to apply upward supporting force to the termination head 12. Commonly more than one such module 20 will be used but only one module 20 is shown in Figure 1 for simplicity. This upward force near the end of the pipeline 10 imparts a sag bend 24 in the pipeline 10 and brings the termination head 12 and the adjoining section 26 of the pipeline 10 closer to the horizontal. The relatively horizontal orientation of the termination head 12 and the adjoining section 26 of the pipeline 10 helps to reduce the bending stresses that tend to arise between the flexible pipeline 10 and the rigid termination head 12 upon touchdown.

Whilst Figure 1 shows the operation after the termination head 12 has been attached to the initiation rigging 18, the buoyancy modules 20 are attached to the termination head 12 earlier in the operation, typically at the surface or on the installation vessel.

It is relatively easy to lift the termination head 12 with buoyant forces in this way, controlling levelling and landing the termination head 12 and the adjoining section 26 of the pipeline 10 safely on the seabed 16. However, deployment and retrieval of the subsea buoyancy module(s) 20 affects the schedule of the operation and increases its risk. Also, due to the dynamics of the system, the limiting sea state for performing the initiation operation is often low.

Another significant issue is that tie-in loops must often be laid within tight tolerances after the termination head 12 has been landed. This task is limited by the horizontal bottom tension or lateral restriction force, and sets limitations on the layback which in turn results in a low limiting operational sea state. This may result in expensive waiting on weather, reduces the choice of suitable installation vessels and also increases the risk level of the operation. Also, use of temporary turn points may be necessary, adding vessel time before and after the initiation operation.

It is against this background that the present invention has been made.

In one sense, the invention resides in a method of initiating laying of an elongate flexible product on the seabed, comprising tensioning the product between an anchored termination head and an installation vessel, while imparting a sag bend curvature to the product by weight added locally to the product at a sag bend region, to orient the termination head and a section of the product adjoining the termination head toward the horizontal while they remain above the seabed.

In another sense within the same inventive concept, the invention resides in various subsea arrangements arising at different stages of the initiation process.

One such subsea arrangement for initiating laying of an elongate flexible product on the seabed comprises: a termination head at an end of the product; an anchor to which the termination head is attached; and weight added locally to the product at a sag bend region that imparts a sag bend curvature to the product to orient the termination head and a section of the product adjoining the termination head toward the horizontal while they remain above the seabed.

Another such arrangement comprises: a termination head at an end of the product and an anchor to which the termination head is attached, the termination head and an adjoining section of the product being laid on the seabed while a weighted sag bend region remains above the seabed, weight being added locally to the product at the sag bend region to impart a sag bend curvature to the product.

Another such arrangement comprises: a termination head at an end of the product and an anchor to which the termination head is attached, the termination head, an adjoining section of the product and a weighted sag bend region of the product being laid on the seabed, weight being added locally to the product at the sag bend region. The product may be laid on the seabed in a curved configuration when viewed from above, in which case the weighted sag bend region is preferably part of the curve.

The added weight may be distributed along the sag bend region of the product, for example by being disposed at a plurality of discrete locations spaced along the sag bend region. Alternatively the added weight may be disposed along a continuous length of the product extending along the sag bend region. In that case, the added weight may comprise segments in mutual contact along the continuous length of the product.

The section of the product adjoining the termination head suitably spaces the sag bend region from the termination head.

Weight may be added to the product by attaching one or more weight modules to the product at the sag bend region, in which case the or each weight module and/or the product preferably has grip-enhancing formations for engaging the seabed. Such weight modules are suitably attached to the product on the installation vessel or before the product is loaded onto the installation vessel.

It is possible for the added weight to be incorporated into the product as manufactured.

For example, the added weight may be defined by one or more sections at the sag bend region where the product is enlarged, thickened or of increased density.

The termination head is suitably anchored by initiation rigging extending to a subsea anchor, and may then be supported above the seabed by tension between the product and the initiation rigging. By means of the invention, the termination head is preferably supported above the seabed without added buoyancy.

In summary, therefore, the invention contemplates the use of added ballast as an installation aid for initiating lightweight elongate products such as flexible pipelines and umbilical cables, as an alternative to the traditional method of using added temporary buoyancy modules. The installation of the ballast can often be performed before connecting up to the initiation anchor point, and hence can be performed away from adjacent lines on the seabed, or in close vicinity to platforms or other structures.

The added ballast is preferably permanently mounted to or integral with the product, to remain with the product after the product has been laid on the seabed. This reduces the time and risk involved in retrieving subsea buoyancy modules.

The invention may employ distributed ballast modules or a continuous length of added weight to aid initiation. This helps to level the termination head by adding weight in the region of the sag bend. The added weight also improves the dynamic response of the system, resulting in a higher limiting sea state for performing the operation.

The distributed or continuous added weight of the invention improves the tie-in operation in most cases by giving the product a higher submerged weight. After the section of the elongate product adjoining the termination head has landed on the seabed, the added weight and increased friction between the product and the seabed enables a larger layback when laying a curve such as a tie-in loop, making it easier to install the product in a curved configuration and increasing resistance of the product to lateral sliding across the seabed. This also increases the limiting sea state for performing the operation, compared to traditional pipeline initiation methods that use added buoyancy.

The added weight and increased seabed friction increases natural hold-back forces, hence avoiding temporary turn points and reducing the need for an extra hold-back winch often used when pulling-in during a tie-in operation.

Advantageously, by virtue of the invention, tie-in loops can be tighter in radius, more accurate in position and start closer to the termination head.

Friction between the product and the seabed can be increased by using grip-enhancing formations such as a serrated outer wall on the pipeline and/or on ballast modules attached to the pipeline.

Ballast attached to the pipeline also helps to protect and insulate the installed pipeline.

The invention therefore aims to reduce or eliminate the need for an additional buoyancy element when initiating lightweight flexible pipelines towards a subsea anchor point as well as increasing the operational sea state for laying the subsequent tie-in loops. This reduces the risk of expensive waiting on weather, increases the choice of suitable installation vessels and also increases the safety level of the operation.

The traditional pipeline initiation method described previously with reference to Figures 1 and 2 may still be preferred where the maximum hang-off load is limiting, and the tie-in loops and pull-in operation are not limiting. The alternative pipeline initiation method provided by the invention is preferred when the introduction of a buoyancy module reduces the limiting sea state, and tie-in loops are challenging to achieve due to factors including light weight of the product; high bending stiffness of the product, or low friction between the product and the seabed.

Reference has already been made to Figures 1 and 2 of the accompanying drawings to

explain the prior art, where:

Figure 1 is a schematic side view of a pipeline initiation operation known in the art, after attachment of a termination head to initiation rigging; and Figure 2 is a perspective view, on land, of buoyancy modules that may be used

in the prior art operation of Figure 1.

In order that the invention may be more readily understood, reference will now be made, by way of example, to the remaining drawings in which: Figure 3 is a schematic side view of a pipeline initiation operation in accordance with the invention, with distributed ballast modules attached to the pipeline in the region of the sag bend; Figure 4 is a schematic perspective view of a pipeline laid on the seabed as part of a pipeline initiation operation in accordance with the invention, again with distributed ballast modules, showing the pipeline laid in a curved configuration when viewed from above; Figure 5 is a schematic side view of a pipeline initiation operation in accordance with the invention, in a variant with a continuous ballast module attached to the pipeline in the region of the sag bend; Figure 6 is a schematic part-sectional side view of a pipeline initiation operation in accordance with the invention, in a further variant where the pipeline has a section of thickened wall to increase weight locally in the region of the sag bend; Figures 7a and 7b are snap-shots from computer simulations of system behaviour at an early stage of the initiation process, which compare the prior art system shown in Figure 7a with the system of the invention shown in Figure 7b under the same sea state; and Figures 8a and 8b are snap-shots from computer simulations of system behaviour at a later stage of the initiation process, which compare the prior art system shown in Figure Ba with the system of the invention shown in Figure 8b under the same sea state.

Reference will also be made, by way of example, to the appended Table 1, which shows the effect of added weight upon limiting horizontal tension for a given lay radius.

Referring firstly to Figure 3, this corresponds partially to Figure 1 and like numerals are used for like features. As before, a lightweight flexible pipeline 10 hangs in the water column, suspended from a pipelay vessel 28, with a termination head 12 at its lower end. A pile serving as a subsea anchor 14 is embedded in and extends above the seabed 16. A wire rope serving as initiation rigging 18 is attached to the anchor 14 at a position above the seabed 16 and extends from there to the termination head 12, such that the termination head 12 and the pipeline 10 may pivot about the anchor 14 while tension is applied between the anchor 14 and the pipelay vessel 28 via the pipeline 10 and the initiation rigging 18.

Before reaching the position shown in Figure 3, the termination head 12 and the pipeline 10 attached to it are launched from the pipelay vessel 28 before being coupled to the anchor 14 via the initiation rigging 18, typically using an ROy. After that, the termination head 12 and the pipeline 10 are landed on the seabed 16; the pipeline 10 may be landed in a curved configuration, as Figure 4 will show, to form a tie-in loop.

In accordance with the invention, at least one and preferably all of the buoyancy modules 20 shown in Figures 1 and 2 are rendered unnecessary by the addition of weight to the pipeline 10. The added weight also helps to protect the pipeline 10, by providing localised impact and abrasion resistance.

In the variant shown in Figure 3, the added weight is provided by ballast modules 30 permanently mounted to and distributed along a section of the pipeline lOin a region close to, but spaced from, the termination head 12. The combined, longitudinally spread, downward weight forces of the ballast modules 30 impart the desirable sag bend 24 to the pipeline 10.

The added weight at the sag bend 24 brings the termination head 12 and the adjoining portion 26 of the pipeline 10 closer to the horizontal to reduce bending stresses between the pipeline 10 and the termination head 12 upon touchdown. It will be noted that the termination head 12 and the adjoining portion 26 of the pipeline 10 are oriented substantially closer to the horizontal than a section of the pipeline 10 immediately above the sag bend 24.

The gap between the ballast modules 30 and the termination head 12 also helps to reduce bending stresses in the portion 26 of the pipeline 10 adjacent to the termination head 12.

Whilst Figure 3 shows the pipeline initiation operation after the termination head 12 has been attached to the initiation rigging 18, the ballast modules 30 are attached to the pipeline 10 earlier in the operation, typically on the installation vessel.

In addition to levelling the termination head 12, the ballast modules 30 reduce the departure angle of the pipeline 10 by changing its configuration. The added weight in the system improves its dynamic behaviour and increases the resistance of the pipeline 10 to lateral sliding across the seabed 16 when laying tie-in loops, thus increasing the allowable sea state for the start-up phase or initiation stage of the installation. There is also a reduced need for a hold-back winch during a pull-in operation.

The ballast modules 30 may, for example, comprise Duraguard HD (high density) modules supplied by Balmoral Offshore Engineering of Aberdeen or Uraduct modules supplied by Trelleborg Offshore of Stavanger. An alternative is to use Polyspace modules also supplied by Trelleborg Offshore with a ballast system to provide additional submerged weight. Duraguard', Balmoral', Uraduct', Polyspace' and Trelleborg are acknowledged herein as trade marks.

The Duraguard system was developed for the protection of subsea cables, flexible jumpers, flexible flowlines and riser touchdown zones to provide localised impact resistance and abrasion protection. Its polyurethane modules are supplied as pairs of interlocking half shells secured around the core product using circumferential straps. A ballasted variant is used in ballast or stabilising systems, with heavy filler materials added to the polyurethane mix to increase density and hence overall weight. The ballast adds on-bottom stability and reduces the risk of clashing between adjacent lines.

Duraguard modules can be fitted during unreeling/laying or before reeling. Adjacent segments with overlapping ends may be added to provide a continuous protected and ballasted length.

The Uraduct system has been used on fibre-optic cables, power and umbilical cables, flexible and rigid flowlines, hoses and bundled products, particularly where additional protection is required, such as on a rocky seabed, at touchdown locations, at shore landings and at cable or pipeline crossings. It is an alternative to known protection methods such as rock dumping or concrete mattressing.

Like Duraguard, Uraduct comprises cylindrical half-shells moulded from polyurethane.

The half-shells overlap and interlock around the core product and are secured in place using corrosion-resistant bands. For ease of handling and transportation, Uraduct modules are manufactured in lengths of up to two metres with flexing characteristics to suit the required minimum bend radius of the product or ancillary shipboard lay equipment.

High-density polyurethane with a specific gravity of 2.3gIcm3 (offering an in-water weight equivalent to concrete) may be used where additional stability is required, for example where cables will be exposed to strong seabed currents and so additional weight will be beneficial. A super-heavyweight Uraduct variant combines polyurethane with the added weight of lead inserts encapsulated in each half-shell during moulding.

The ratio of lead to polyurethane can be varied to give an average specific gravity in excess of 3.Og/cm3.

Polyspace is a product designed to maintain a positive clearance between cables and existing pipelines at crossing points. Alternative methods such as pre-lay rock dumping, concrete mattressing and steel structures are expensive, time consuming and difficult to place accurately.

Again, Polyspace modules comprise interlocking half-shells fastened around the cable by bands as the cable is deployed from an installation vessel at a crossing location. In this case, the half-shells are manufactured from UV-stable, marine grade, high density polyethylene. Each moulding is free-flooding and can be supplied with a ballast system to provide up to 9Okg/m3 of additional submerged weight to suit the application.

Figure 4 shows the pipeline 10 laid on the seabed 16 in a curved configuration representing a tie-in loop or expansion loop. Engagement between the seabed 16 and the pipeline 10 and/or the ballast modules 30 resists lateral sliding of the pipeline 10 after touchdown, which would deform the loop unpredictably. For example, the loop could otherwise tend to straighten under the tension of the normal lay phase of the pipelay operation.

Friction between the pipeline 10 and the seabed 16 can be increased to improve engagement by using grip-enhancing formations such as a serrated or corrugated outer wall on the pipeline 10 and/or on the ballast modules 30 attached to the pipeline 10. By way of example, Figure 4 shows corrugations 32 on the ballast modules 30, the corrugations 32 being oriented longitudinally to resist lateral sliding of the pipeline 10 across the seabed 16. Other orientations and grip-enhancing configurations are possible.

The variants shown in Figures 5 and 6 largely correspond to Figure 3 but show that the added weight need not comprise discrete spaced modules but could instead comprise a continuous section. The variant in Figure 5 employs a single elongate tubular ballast module 34 attached to the pipeline 10 and extending along its sag bend region. The ballast module 34 is preferably flexible and it need not be in a single piece: it may be segmented or articulated, for example comprising overlapping or interlocking Duraguard modules as described above. Conversely the variant in Figure 6 adds weight to the pipeline 10 by virtue of a thickened wall portion 36 extending along its sag bend region. Again, grip-enhancing formations may be provided on the elongate ballast module 34 or on the thickened wall portion 36, although such formations are omitted from Figures 5 and 6.

Other variations are possible without departing from the inventive concept. For example, it may be appropriate to shape the sag bend 24 by varying the effective weight per unit length of the pipeline 10 along the length of the sag bend 24. Where discrete ballast modules 30 are used as in Figure 3, the ballast modules 30 need not be of the same weight; nor do they have to be equally spaced from each other. It would therefore be possible to vary the spacing between the ballast modules 30 or their relative weights. It would also be possible to achieve a similar effect in the variants shown in Figures 5 and 6, for example by varying density along the length of the elongate tubular ballast module 34 of Figure 5 or by varying wall thickness along the length of the thickened wall portion 36 of Figure 6.

Moving on now to Figures 7a and 7b, these are snapshots' taken from two simulations with the same sea state. Figure 7a illustrates a prior art system with modular buoyancy to lift the termination head, whereas Figure 7b illustrates a system in accordance with the invention having distributed weight to lower the sag bend. In both cases, the termination head and the pipeline have been attached to initiation rigging but have not yet been landed on the seabed.

A regular wave with height of 8.0 metres and period of 6.5 seconds is introduced to the model, applied 30 degrees off head seas. The starting or static stage is similar for the two systems, i.e. with the termination head just 1.0 metre above the seabed. This step in the initiation process is normally governed with reference to over-bending at the hang-off, or alternatively violating a departure angle criterion.

As can be seen, the system of Figure 7a including a buoyancy module introduces a larger dynamic response of the termination head. Snap forces are observed in the initiation rigging, and the product experiences over-bending at the end of the bend restrictor section adjoining the termination head. In contrast, the configuration of Figure 7b gives far better dynamic response than the configuration of Figure 7a and does not violate any of the assumed criteria.

The maximum departure angle in the prior art system of Figure 7a is approximately eighteen degrees, which is three degrees more than the system with distributed weight of Figure 7a in accordance with the invention.

The conclusion from the comparison between Figures Ja and 7b is that the prior art system with modular buoyancy will have a much lower limiting sea state than the system of the invention with added ballast. By virtue of the invention, an increase in the limiting sea state of approximately 25%-30% is expected for this stage of the initiation operation.

Later in the initiation operation, maximum curvature is traditionally observed when the back end of the bend restrictor section is to be landed on the seabed. This phase is illustrated in Figures 8a and 8b for the same two systems as shown in Figures 7a and 7b, in the same sea state, again with modular buoyancy and with added weight respectively.

Again the system of the invention with added weight shown in Figure 8b fares better than the prior art system with modular buoyancy shown in Figure 8a. It is noted in Figure 8a that the prior art system with modular buoyancy violates the curvature criterion, just aft of the bend restrictor section. The system of the invention with added weight shown in Figure 8b has a much better dynamic response, and there is no violation of the curvature criterion. The departure angle is also less extreme for the weighted system of the invention. The conclusion from a comparison between Figures Ba and Bb is that the weighted system of the invention is installable in the sea state on which the model is based, while the traditional system using a buoyancy module needs a reduced sea state. The difference between the allowable sea states is assumed to be in the range of 25%-30%, or more, in favour of the weighted system of the invention.

The systems of the invention modelled in Figures 7b and 8b have not been optimised with respect to the location and the amount of added weight. They simply illustrate the differences and investigate the effects of having a weight section in the system.

To have a significant effect on the configuration, it is anticipated that a considerable length of added weight will be needed with a relatively large mass per unit length.

However, the touchdown tension is about three times higher for the weighted system of the invention compared to the traditional system with modular buoyancy. This also means that there will be higher forces in the initiation rigging. A stronger anchor point is therefore required, which may limit the amount of weight to be added. The increased load in the initiation rigging and the increased hang-off load may restrict the use of the method of the invention to cases where it is difficult to achieve a reasonable limiting sea state with the traditional initiation method using modular buoyancy.

Evaluation of lateral curve stability is necessary to ensure that planned curves can be accommodated during installation of a pipeline. Possible restrictions in layback and/or limiting sea state need to be established in order to keep the touchdown tension low enough to avoid the pipeline sliding laterally out of the planned lay corridor. If a curve is found to be impractical to achieve due to operational restrictions, the requirements for turn points need to be established.

Various methods are available for calculating the minimum curve radius, or the maximum horizontal boftom tension (touchdown tension) with increasing complexity, such as the inclusion of passive soil resistance or seabed mechanics. However, for comparison purposes, a simplified relationship between the tension, radius, submerged weight of pipeline and lateral seabed friction may be used.

Table 1 shows the effect of added weight upon limiting horizontal tension for a given lay radius and lateral friction factor. In Table 1, the curve radius is assumed to be fixed to 40 metres as a typical tie-in loop radius and minimum route curve radius, and the effect of added ballast is investigated by increasing the submerged weight. The results illustrate the added value of the weighted section, and clearly depict how the increased submerged weight increases the operability for curve lay by increasing the limiting horizontal tension prior to sliding.

In practice, the lateral friction factor and the passive soil resistance will also increase, thus further increasing the limiting horizontal bottom tension due to the increase of submerged weight by using weight modules. The weighted section will increase the minimum layback (governed by the curvature at the touchdown region) and hence the static touchdown tension. However, this increase is less than the increase of limiting horizontal bottom tension for curve lay. It is therefore possible to lay the curve in a higher sea state without increasing the risk of excessive lateral displacement.

The increase of limiting horizontal bottom tension before sliding reduces the need for turn points in case of tight turns. Further, the allowable sea state will increase due to the weighted section, hence reducing the risk of costly vessel standby time due to waiting on weather during installation.

Clearly, there will be some extra time involved in mounting weight modules on the pipeline during initiation or normal lay compared to not using weight modules at all, although this need not adversely affect the critical path. However, the possibility of installing the pipeline in higher sea states instead of waiting on the weather will in many cases be the preferred option. The invention also reduces or eliminates the need for added buoyancy attached to the termination head and so reduces or eliminates the time and risk necessary to attach and to remove buoyancy modules.

Claims (1)

1. <claim-text>Claims 1. A method of initiating laying of an elongate flexible product on the seabed, comprising tensioning the product between an anchored termination head and an installation vessel, while imparting a sag bend curvature to the product by weight added locally to the product at a sag bend region, to orient the termination head and a section of the product adjoining the termination head toward the horizontal while they remain above the seabed.</claim-text> <claim-text>2. The method of Claim 1, wherein the added weight is distributed along the sag bend region of the product.</claim-text> <claim-text>3. The method of Claim 2, wherein the added weight is disposed at a plurality of discrete locations spaced along the sag bend region.</claim-text> <claim-text>4. The method of Claim 2, wherein the added weight is disposed along a continuous length of the product extending along the sag bend region.</claim-text> <claim-text>5. The method of Claim 4, wherein the added weight comprises segments in mutual contact along the continuous length of the product.</claim-text> <claim-text>6. The method of any preceding claim, wherein the section of the product adjoining the termination head spaces the sag bend region from the termination head.</claim-text> <claim-text>7. The method of any preceding claim, wherein weight is added to the product by attaching one or more weight modules to the product at the sag bend region.</claim-text> <claim-text>8. The method of Claim 7, wherein the or each weight module and/or the product has grip-enhancing formations for engaging the seabed.</claim-text> <claim-text>9. The method of Claim 7 or Claim 8, wherein the or each weight module is attached to the product on the installation vessel or before the product is loaded onto the installation vessel.</claim-text> <claim-text>10. The method of any of Claims ito 6, wherein the added weight is incorporated into the product as manufactured.</claim-text> <claim-text>11. The method of Claim 10, wherein the added weight is defined by one or more sections at the sag bend region where the product is enlarged, thickened or of increased density.</claim-text> <claim-text>12. The method of any preceding claim, wherein the termination head is anchored by initiation rigging extending to a subsea anchor.</claim-text> <claim-text>13. The method of Claim 12, wherein the termination head is supported above the seabed by tension between the product and the initiation rigging.</claim-text> <claim-text>14. The method of Claim 13, wherein the termination head is supported above the seabed without added buoyancy.</claim-text> <claim-text>15. The method of any preceding claim, further comprising landing the termination head and the adjoining section of the product on the seabed while the weighted sag bend region remains above the seabed.</claim-text> <claim-text>16. The method of Claim 15, further comprising subsequently landing the weighted sag bend region upon the seabed.</claim-text> <claim-text>17. The method of Claim 15 or Claim 16, wherein the product is laid on the seabed in a curved configuration when viewed from above.</claim-text> <claim-text>18. The method of Claim 17, wherein the weighted sag bend region is part of the curve.</claim-text> <claim-text>19. A subsea arrangement for initiating laying of an elongate flexible product on the seabed, the arrangement comprising: a termination head at an end of the product; an anchor to which the termination head is attached; and weight added locally to the product at a sag bend region that imparts a sag bend curvature to the product to orient the termination head and a section of the product adjoining the termination head toward the horizontal while they remain above the seabed.</claim-text> <claim-text>20. A subsea arrangement for initiating laying of an elongate flexible product on the seabed, the arrangement comprising a termination head at an end of the product and an anchor to which the termination head is attached, the termination head and an adjoining section of the product being laid on the seabed while a weighted sag bend region remains above the seabed, weight being added locally to the product at the sag bend region to impart a sag bend curvature to the product.</claim-text> <claim-text>21. A subsea arrangement for initiating laying of an elongate flexible product on the seabed, the arrangement comprising a termination head at an end of the product and an anchor to which the termination head is attached, the termination head, an adjoining section of the product and a weighted sag bend region of the product being laid on the seabed, weight being added locally to the product at the sag bend region.</claim-text> <claim-text>22. The arrangement of Claim 21. wherein the product is laid on the seabed in a curved configuration when viewed from above.</claim-text> <claim-text>23. The arrangement of Claim 22, wherein the weighted sag bend region is part of the curve.</claim-text> <claim-text>24. The arrangement of any of Claims 19 to 23, wherein the added weight is distributed along the sag bend region of the product.</claim-text> <claim-text>25. The arrangement of Claim 24, wherein the added weight is disposed at a plurality of discrete locations spaced along the sag bend region.</claim-text> <claim-text>26. The arrangement of Claim 24, wherein the added weight is disposed along a continuous length of the product extending along the sag bend region.</claim-text> <claim-text>27. The arrangement of Claim 26, wherein the added weight comprises segments in mutual contact along the continuous length of the product.</claim-text> <claim-text>28. The arrangement of any of Claims 19 to 27. wherein the section of the product adjoining the termination head spaces the sag bend region from the termination head.</claim-text> <claim-text>29. The arrangement of any of Claims 19 to 28, wherein weight is added to the product by weight modules attached to the product at the sag bend region.</claim-text> <claim-text>30. The arrangement of Claim 29. wherein the or each weight module and/or the product has grip-enhancing formations for engaging the seabed.</claim-text> <claim-text>31. The arrangement of any of Claims 19 to 30, wherein the added weight is incorporated into the product as manufactured.</claim-text> <claim-text>32. The arrangement of Claim 31, wherein the added weight is defined by one or more sections at the sag bend region where the product is enlarged, thickened or of increased density.</claim-text> <claim-text>33. The arrangement of any of Claims 19 to 32, wherein initiation rigging extends from the termination head to a subsea anchor.</claim-text> <claim-text>34. The arrangement of Claim 33 when appendant to Claim 19, wherein the termination head is supported above the seabed by tension between the product and the initiation rigging.</claim-text> <claim-text>35. The arrangement of Claim 34, wherein the termination head is supported above the seabed without added buoyancy.</claim-text>