GB2554076A

GB2554076A - Subsea hydrocarbon processing

Info

Publication number: GB2554076A
Application number: GB1615682.0A
Authority: GB
Inventors: Bakke William; Stokke Ragnar; Brekken Rudolf
Original assignee: Statoil Petroleum ASA
Current assignee: Equinor Energy AS
Priority date: 2016-09-15
Filing date: 2016-09-15
Publication date: 2018-03-28
Also published as: GB201615682D0

Abstract

An offshore hydrocarbon processing facility comprises an offshore platform 16 having a jacket 46; and subsea processing equipment 29 disposed within the jacket. Optionally, the jacket comprises a plurality of tubular legs having metal bracings formed between adjacent tubular legs. Optionally, the subsea processing equipment is entirely disposed within the jacket or least part of the subsea processing equipment rests within the jacket on the seabed or on a structure resting on the seabed. Optionally the subsea processing equipment is formed integrally with the jacket. Optionally, the subsea processing equipment comprises a separator (figure 2, 30), which can be a gravity separator or a compressor. Optionally, the offshore hydrocarbon processing facility is a normally unmanned hydrocarbon processing facility. There is also provided a method of installing the subsea equipment by providing the subsea processing equipment at a location that is subsea and outside of the jacket. After installing the jacket the subsea processing equipment is manoeuvred within the jacket.

Description

(71) Applicant(s):

Statoil Petroleum AS

Forusbeen 50, Stavanger 4035, Norway (72) Inventor(s):

William Bakke Ragnar Stokke Rudolf Brekken (74) Agent and/or Address for Service:

Dehns

St. Bride's House, 10 Salisbury Square, LONDON, EC4Y 8JD, United Kingdom (51) INT CL:

E21B 43/36 (2006.01) E02B 17/00 (2006.01) (56) Documents Cited:

WO 2001/074473 A1 US 4793418 A US 4506735 A US 2767802 A

US 20120285656 A1 (58) Field of Search:

INT CL B01D, E02B, E21B Other: EPODOC, WPI, GOOGLE (54) Title of the Invention: Subsea hydrocarbon processing

Abstract Title: Offshore processing facility with subsea processing equipment disposed within a jacket (57) An offshore hydrocarbon processing facility comprises an offshore platform 16 having a jacket 46; and subsea processing equipment 29 disposed within the jacket. Optionally, the jacket comprises a plurality of tubular legs having metal bracings formed between adjacent tubular legs. Optionally, the subsea processing equipment is entirely disposed within the jacket or least part of the subsea processing equipment rests within the jacket on the seabed or on a structure resting on the seabed. Optionally the subsea processing equipment is formed integrally with the jacket. Optionally, the subsea processing equipment comprises a separator (figure 2, 30), which can be a gravity separator or a compressor. Optionally, the offshore hydrocarbon processing facility is a normally unmanned hydrocarbon processing facility. There is also provided a method of installing the subsea equipment by providing the subsea processing equipment at a location that is subsea and outside of the jacket. After installing the jacket the subsea processing equipment is manoeuvred within the jacket.

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At least one drawing originally filed was informal and the print reproduced here is taken from a later filed formal copy.

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- 1 SUBSEA HYDROCARBON PROCESSING

The present invention relates to the processing of hydrocarbons, and particularly to the arrangement of processing equipment for processing hydrocarbons.

Natural-gas processing is a complex industrial process designed to clean raw natural gas by removing impurities, such as undesired hydrocarbons and other fluids, to produce what is known as pipeline-quality dry natural gas. A fully operational gas processing plant delivers pipeline-quality dry natural gas that can be used as fuel by residential, commercial and industrial consumers.

There are a great many ways in which to configure the various unit processes used in the processing of raw natural gas. An exemplary processing cycle is as follows.

Raw natural gas is commonly collected from a group of adjacent wells and is first processed at that collection point for removal of free, liquid water and natural gas condensate. The condensate is usually then transported to an oil refinery and the water is disposed of as wastewater. The raw gas is piped to a gas processing plant.

Initial purification is usually the removal of acid gases (hydrogen sulphide and carbon dioxide). There are many processes that are available for this purpose, such as membrane separation or amine treating. The next step in the gas processing plant is to remove water vapour from the gas, which is commonly performed using glycol dehydration. Mercury is then removed by using adsorption processes, such as activated carbon or regenerable molecular sieves. Although not common, nitrogen is sometimes also removed and rejected using a cryogenic or absorption process.

The next step is to recover the natural gas liquids (NGL) for which most large, modern gas processing plants use a cryogenic low-temperature distillation process involving expansion of the gas through a turbo-expander followed by distillation in a demethanizing fractionating column. The residue gas from the NGL recovery section is the final, purified sales gas which is pipelined to the end-user markets.

For offshore hydrocarbon production wells, the above processing may be performed by a central offshore production facility, which processes the natural gas

-2produced by multiple subsea wells. In such a facility, it has been conventional to locate all of the processing equipment on a floating or fixed platform.

In more recent times, there has been a move towards locating a small number of components on the seabed to improve the efficiency of the production system. For example, separators have been located above wellheads to separate gases and liquids at this point. This provides some benefits to production efficiency, but has been found to increase the number of subsea pipelines required, increase the chemicals required for transporting the separated fluids, and increase the risk of damage to the separators from falling debris or fishing trawling.

Viewed from a first aspect, the present invention provides an offshore hydrocarbon processing facility comprising: an offshore platform having a jacket; and subsea processing equipment disposed within the jacket.

This configuration provides various improvements compared to existing systems. By moving processing equipment from the topside to subsea, it is possible to reduce the quantity of processing equipment on the platform allowing for a smaller, more compact platform. The subsea processing equipment is located within the jacket, ensuring that the equipment is at least partially protected from certain types of damage, such as from debris falling from ships in the vicinity of the platform, or damage by fishing nets or the like being used nearby.

Furthermore, when the subsea processing equipment is located within the jacket, it is vertically below the topside structure. It is therefore still very close to the topside platform, reducing the distance that the separated fluids need to travel. As a result, fewer pipes are needed (e.g. a single multi-phase pipeline may supply the processing equipment, whilst the processing equipment may output to multiple single-phase pipelines). Also, less chemicals, such as hydrate inhibitors, need to be injected into the output lines as the processed hydrocarbons are only transported a short distance, e.g. to surface level.

The offshore platform is preferably a fixed platform, although it will be appreciated that certain aspects of the disclosure may apply also to floating platforms.

The offshore hydrocarbon processing facility may be located in water having a depth of less than 500m, and preferably between 50m and 200m, which are the depths where fixed platforms are commonly used.

- 3The jacket preferably comprises a plurality of tubular legs having metal bracings formed between adjacent tubular legs. Each of the tubular legs may be supported by a piled foundation.

The jacket is preferably a steel jacket, which is the most commonly used material for jacket-type offshore platforms.

The subsea processing equipment is preferably entirely disposed within the jacket. This ensures that the jacket can protect the processing equipment from damage, such as discussed above.

In one embodiment, at least part of the subsea processing equipment may be suspended within the jacket. For example, the subsea processing equipment may be connected to the legs or bracings of the jacket, or may be supported on a structure connected to the legs or bracings of the jacket.

In one embodiment, at least part of the subsea processing equipment may rest on the seabed or on a structure resting on the seabed within the jacket.

The subsea processing equipment may comprise a separator. Positioning a separator within the jacket minimises the time that separated fluids must be transported subsea. Such transport requires the injection of chemicals to prevent hydrates and the like, and therefore the use of such chemicals is minimised by this configuration, whilst still avoiding the need for large separation equipment to be located on the topside platform.

The separator may be configured as a gravity separator. The gravity separator preferably has a height of at least 10 meters, more preferably at least 20 metres, and in some embodiments at least 50 metres. Greater height allows for more efficient separation of the incoming fluid, and by positioning the separator within the jacket it is possible to take advantage of the subsea height of the platform to use a large separator. Such a large separator on a topside platform would not only use a large amount of space, but would also require significant reinforcement against lateral loading, which would be undesirable on a small platform.

The gravity separator may comprise at least a gas outlet at an upper region and a first liquid outlet at a lower region. The gravity separator may further comprise a second liquid outlet in an intermediate region. The first liquid outlet may be a water outlet and the second liquid outlet may be a liquid hydrocarbon outlet.

The separator preferably has at least a gas outlet and a liquid outlet. In some embodiments, the separator may be a three-phase separator, such as described above. The facility may be arranged such that the gas outlet connects to

-4topside processing equipment of the facility. The liquid outlet(s) may be arranged to connect to a subsea pipeline. That is to say, the liquid outlet does not connect to the topside processing equipment of the facility.

The subsea processing equipment may comprise a compressor. For example, the compressor may boost the gas to transport it to surface level. The compressor may be arranged downstream from the separator, and may be arranged to compress the gas stream from the separator.

Preferably, the facility comprises topside processing equipment located on the platform. The topside processing equipment may be configured to process a hydrocarbon gas. The topside equipment is preferably configured to process the hydrocarbon gas to a rich gas pipeline transportation specification.

By way of example, a typical rich gas specifications might be expected to require at least a water dew point and a hydrocarbon dew point that are point below the surrounding temperature (e.g. seabed temperature, which may typically be below -5° C) within the operational pressure window (typically 90 - 250 bar).

The topside processing equipment may comprise water removal equipment, or in some embodiments gas drying equipment (e.g. to dry the gas to a water content of below 40 mg/Sm³). The topside processing equipment may comprise acid gas removal equipment. The topside processing equipment may comprise mercury removal equipment. The topside processing equipment may comprise compression equipment for compressing the gas, e.g. for transport to another location.

The facility is preferably configured such that a hydrocarbon fluid to be processed is processed first by the subsea equipment and then by the topside equipment. That is to say, the processing is performed partially subsea and partially topside.

The hydrocarbon processing facility preferably does not comprise a production well. That is to say, the hydrocarbon processing facility may be for processing only, and contain no production facilities. Specifically, there is no well located within or beneath the jacket of the platform.

In one embodiment, the hydrocarbon processing facility may be configured to receive hydrocarbons from a production well at least 500m away from the platform. Preferably a well stream from the production well is transported to the processing facility via an insulated pipeline. Preferably the well stream from the production well supplied to the processing facility without processing, except for the

- 5optional addition of chemicals for transportation. That is to say, preferably no separation occurs before the well stream reaches the processing facility.

The hydrocarbon processing facility may be a normally-unmanned hydrocarbon processing facility. That is to say, it is a platform that has no permanent personnel and may only be occupied for particular operations, such as maintenance and/or installation and/or testing of equipment.

The unmanned platform may be a platform where no personnel are required to be present for the platform to carry out its normal function, for example day-today functions relating to handling of oil and/or gas products at the platform. That is to say that all processing equipment within the facility is capable of running essentially without direct human intervention (although various parts may be controlled remotely from a control centre remote from the hydrocarbon processing facility). It will be appreciated that a normally-unmanned hydrocarbon processing facility may have the capability to be manned, such as for testing or maintenance, but is still capable of running when no personnel are present within the facility.

An unmanned platform may be a platform with no provision of facilities for personnel to stay on the platform, for example there may be no shelters for personnel, no toilet facilities, no drinking water and/or no personnel operated communications equipment. The unmanned platform may also include no heli-deck and/or no lifeboat, and advantageously may be accessed in normal use solely by the gangway or bridge.

An unmanned platform may alternatively or additionally be defined based on the relative amount of time that personnel are needed to be present on the platform during operation. This relative amount of time may be defined as maintenance hours needed per annum, for example, and an unmanned platform may be a platform requiring fewer than 10,000 maintenance hours per year, optionally fewer than 5000 maintenance hours per year, perhaps fewer than 3000 maintenance hours per year.

Preferably the platform topside has a footprint of less than 25m by 25m and more preferably less than 20m by 20m. This is much smaller than conventional platforms, and can be achieved particularly through the arrangement of certain components subsea, as described above.

Viewed from a second aspect, the present invention provides a method of installing an offshore hydrocarbon processing facility comprising installing a jacket

-6of an offshore platform and subsea processing equipment, such that the subsea processing equipment is disposed within the jacket.

In one implementation, the subsea processing equipment is formed integrally with the jacket. Thus, the subsea processing equipment is located in the correct location by installing the jacket.

In another implementation, installing the subsea equipment may comprise placing the subsea processing equipment subsea outside of the jacket and, after installing the jacket, manoeuvring the subsea processing equipment within the jacket.

The jacket may comprise an opening sized to receive the subsea processing equipment. The step of manoeuvring the subsea processing equipment may comprise manoeuvring the subsea processing equipment through the opening.

A driving force for the manoeuvring may be provided by a line connecting the subsea processing equipment to a vessel, wherein the line preferably passes through the opening.

The method may comprise attaching one or more buoyant elements to the subsea processing equipment, e.g. before the step of manoeuvring. The method may comprise attaching one or more friction-reducing elements (such as one or more sliding or rolling elements) to the underside of the subsea equipment, e.g. before the step of manoeuvring. Thus, the forces required and the risk of damage to the equipment is reduced.

Optionally, the processing equipment may comprise a plurality of units. In this case, some units may be formed integrally with the jacket and some may be installed after the jacket has been installed. Also, whilst the units may be maneuverer as a singled unit into the jacket, they may instead also be individually maneuverer into the jacket and assembled once inside.

The subsea processing equipment and/or the jacket and/or the processing facility may optionally comprise any one or more or all of the elements discussed above. In particular, the processing equipment preferably comprises at least a separator.

Certain preferred embodiments of the present invention will now be described in greater detail by way of example only and with reference to the accompanying drawings, in which:

Figures 1 and 2 show the layout of an offshore field development;

Figure 3 is a perspective view of the production platform; and

- 7Figure 4 shows the installation of the platform.

The following embodiment is described in the context of a proposed field development 10. A 6-slots subsea production system (SPS) 12 is proposed at a first remote site, A. Approximately 12 km away, within a second remote site, B, is proposed an Unmanned Wellhead Platform (UWP) 14 and an Unmanned Processing Platform (UPP) 16.

The distance between remote site A and remote site B is approximately 12 km, while the distance from remote site B to the tie-in point at a host pipeline is approximately 34 km. A schematic illustration of the pipeline systems is shown in Figures 1 and 2. The water depth both at remote site A and remote site B and in the host area is in the range of 100 to 110 metres, and the seabed bathymetry is in general flat with no major features or pockmarks.

Oil, gas and water from the reservoir of remote site A are produced to the SPS 12. The well fluid is transported through an insulated and heat traced pipe-inpipe pipeline 18 to remote site B. The UPP subsea and topside facility 16 at remote site B is protected from the high well shut-in pressure by a subsea high-integrity pressure protection system (HIPPS) system 20.

Oil, gas and water from the reservoir of remote site B are produced to the UWP 14. The UPP subsea and topside facility 16 is protected from the high well shut-in pressure by a topside HIPPS system 22 on the UWP 14.

Injection of water for pressure support is planned for the reservoirs of both remote site A and remote site B via respective water injection pipelines 24, 26.

Produced fluid from remote site A and remote site B is mixed upstream of a subsea separator 30. The subsea separator 30 is a three phase separator operating at approximately 40 bar initially. The temperature in the separator 30 is high (90°C) and good separation is expected.

Oil and water leaving the separator 30 is metered by a multiphase flow meter 32 and exported to a host 34. The receiving pressure at the host 34 will be kept at the same pressure as the subsea separator 30 to avoid flashing and multiphase flow in the export pipeline or inlet heater at the host 34. The oil is only partly stabilized in the subsea separator 30, and further stabilization to pipeline export specification is assumed at the host 34.

The subsea separator 30 and pumps (not shown) are provided as a subsea separator and booster station (SSBS) 29, which is located as close to the UPP 16

- 8as possible to minimize condensation and liquid traps in the gas piping from the separator 30 to the UPP 16.

An umbilical 50 connects the UPP 16 to the host 34. The umbilical provides remote control of the operations of the UPP 16, as well as of the operations of the SPS 12, UWP 14 and SSBS 29 via secondary umbilicals 52, 54, 56. The secondary umbilicals 52, 54, 56 also supply any required power and chemicals required from the UPP 16 to the SPS 12, UWP 14 and SSBS 29.

Gas at 40 bar is delivered from the separator 30 to the UPP 16 topside inlet cooler 36 through a dedicated riser 38. The inlet cooler 36 comprises a seawatercooled shell and tube heat exchanger. TEG is injected into the gas for hydrate inhibition before cooling the gas to 20°C in the seawater-cooled shell and tube inter stage cooler 36.

Condensed water and hydrocarbons are removed in a downstream scrubber 37. Liquid from the scrubber 37 flows by gravitation back down to the subsea separator 30 through a dedicated riser 40.

The gas from the scrubber 37 is then compressed to around 80 bar in a first stage compressor with a discharge temperature of around 80°C. The temperature should ideally be as low as possible to reduce the amount of glycol required for dehydration.

The maximum cricondenbar pressure of the export gas is 110 barg. The cricondenbar is the pressure below which no liquid will be formed regardless of temperature. The cricondenbar is a property of the gas. The cricondenbar is determined by the conditions in the inlet scrubber 37.

The pressure in the scrubber 37 is determined by the pressure in the subsea separator 30. A low pressure in the separator 30 will reduce the flash gas in the export oil and is at some point in time required to realize the production profiles. The required compression work and power consumption will however increase with a lower pressure. The separator 30 will operate at about 40 bar initially and the pressure will be reduced to 30 bar or even lower towards the end of the lifetime.

The temperature in the scrubber 37 is determined by the inlet cooler discharge temperature. A lower temperature corresponds to a lower cricondenbar. The hydrate formation temperature is about 15°C and a 5°C margin gives a minimum cooler discharge temperature of 20°C.

- 9The gas from the scrubber 37 is then dehydrated using the glycol dehydration to meet the appropriate export specification. For example, the maximum water content is 40 mg/Sm³ for gas exported to Statpipe.

The gas is compressed to the required export pressure after dehydration. For example, the maximum operating pressure of the Statpipe Rich Gas pipeline is 167 barg. The required export pressure will be a function of allocated gas volumes and selected operational pressure in the pipeline and could be lower than the maximum pressure specified.

The gas is metered and measured according to requirements in a dedicated metering package, before entering the export riser and gas export pipeline 44.

In one example, the discharge temperature from the compressor is about 80°C at 167 barg. However, the gas will be cooled in the 45 km long, un-insulated gas export pipeline 44 and the gas temperature is well below the maximum operating temperature for Statpipe when it reaches the tie-in point.

The selected UPP 16 design facilitates the unmanned processing of oil and gas in remote site B. A combination of subsea processing and topside processing on the UPP 16 can maximise operability and minimise capital and operational expenditure.

The UPP 16 has a steel jacket configuration, as shown in Figure 3. The jacket is square with a spacing of 14 metres between the support columns.

The UPP 16 uses a piled, four legged, symmetrically battered jacket 46 to support the topside 48. The topside is 19.8m x 19.8m between main structural with 3 decks and an intermediate deck on cellar deck level to provide additional area for electrical equipment.

Umbilicals will be pulled into the platform 48 with a winch located on the weather deck and a umbilical slot and reserved space are provided for this activity in centre of the platform 48. The slot and reserved space can be used for other purposes on the module deck areas once the pulling operation is completed.

The SSBS 29 is located on the seabed within the jacket 46. A subsea separator 30 is used instead of a topside solution on the UPP 16 because a topside solution would require an additional level on the UPP 16 due to the size and weight requirement.

The separator 30 is based on a symmetrical design with a central top inlet arrangement and top outlet arrangements at both ends combined with cyclones for gas polishing. Likewise oil and water outlets are at the bottom part inside and

- 10outside respective baffle-plates. Operation of the subsea separator 30 is performed using several distinct control loops.

The levels in the separator 30 are measured by a profiler level detector system. Water level control will adjust speed of the water injection pump and the level of oil will adjust speed of the export pump. The pressure in the subsea separator 30 is adjusted by the speed of the 1st stage compressor (suction pressure control). The control loops will be closed at the host 34 using fiber optic cables in an umbilicals 50, 56.

The installation sequence for the UPP 16 will now be discussed.

Separate jacket 46 and topside 48 transportation and installation may be used for installation of the UPP 16. The marine operations for such installation are largely conventional.

Trailer load-out may be used for both the jacket 46 and the topside 48. The jacket 46 and topside 48 will be transported on a barge from the fabrication site to the installation site. The jacket 46 will be lift installed by a dual crane installation vessel. The piles will then be driven and the pile sleeves will be grouted. An illustration of jacket lift and upending is shown in Figure 4.

In one implementation, the separator 30 and pumps may be integrated into the jacket 46 such that no separate installation is required.

In another implementation, the SSBS 29 may be installed after the jacket 46 of the platform 16 has been installed, as illustrated in Figure 5.

In this method, the jacket 46 is constructed so as to provide a separator slot 58 to receive the SSBS 29 . After the jacket 46 is installed, the SSBS 29 is placed subsea in the vicinity of the platform 16, for example within about 100m of the platform 16. The SSBS 29 may be placed on skids 60 and/or balloons 62 may be used to provide buoyancy to the SSBS 29.

A pull line 64 may be connected from a support vessel or the like to the SSBS 29 through the slot 58 in the jacket 46. As the pull-line is drawn in, the SSBS 29 is slid along the seabed and through the separator slot 58 of the jacket 62. The SSBS 29 may be guided through the separator slot 58 and/or connected to the riser 38 or the like by divers.

Whilst the preferred embodiment of the invention has been described in the context of a fixed platform, it will be appreciated that some of the described advantages also arise when using a similar arrangement in the context of a floating platform.

- 11 For example, where the processing equipment (separator and pump) are located directly beneath the floating platform, damage from falling debris is reduced because debris tends to fall directly vertically downwards. Similarly, trawling damage is less likely because fishing ships cannot pass directly over the subsea equipment due to the platform.

Also, for the same reasons as discussed above, the distance to the surface platform is again minimised by such a configuration, thus reducing the quantity of subsea pipelines and chemicals required compared to alternative subsea configurations.

Claims

CLAIMS:

1. An offshore hydrocarbon processing facility comprising: an offshore platform having a jacket; and subsea processing equipment disposed within the jacket.
2. An offshore hydrocarbon processing facility according to claim 1, wherein the jacket comprises a plurality of tubular legs having metal bracings formed between adjacent tubular legs.
3. An offshore hydrocarbon processing facility according to claim 1 or 2, wherein the subsea processing equipment is entirely disposed within the jacket.
4. An offshore hydrocarbon processing facility according to any preceding claim, wherein at least part of the subsea processing equipment rests within the jacket on the seabed or on a structure resting on the seabed.
5. An offshore hydrocarbon processing facility according to any preceding claim, wherein the subsea processing equipment comprises a separator.
6. An offshore hydrocarbon processing facility according to claim 5, wherein the separator is configured as a gravity separator.
7. An offshore hydrocarbon processing facility according to claim 6, wherein the gravity separator has a height of at least 20 metres.
8. An offshore hydrocarbon processing facility according to claim 5, 6 or 7, wherein the separator has at least a gas outlet and a liquid outlet, and wherein the gas outlet connects to topside processing equipment of the facility.
9. An offshore hydrocarbon processing facility according to claim 8, wherein the liquid outlet is arranged to connect to a subsea pipeline.
10. An offshore hydrocarbon processing facility according to any preceding claim, wherein the subsea processing equipment comprises a compressor.

- 1311. An offshore hydrocarbon processing facility according to any preceding claim, comprising:

topside processing equipment located above sea level on the offshore platform.
12. An offshore hydrocarbon processing facility according to claim 11, wherein the topside processing equipment is configured to process a hydrocarbon gas to a rich gas pipeline transportation specification.
13. An offshore hydrocarbon processing facility according to claim 11 or 12, wherein the topside processing equipment comprises at least one of: water removal equipment, gas drying equipment, acid gas removal equipment, mercury removal equipment, and gas compression equipment.
14. An offshore hydrocarbon processing facility according to claim 11, 12 or 13, wherein the facility is configured such that a hydrocarbon fluid to be processed is processed first by the subsea equipment and then by the topside equipment.
15. An offshore hydrocarbon processing facility according to any preceding claim, wherein the offshore hydrocarbon processing facility is a normally-unmanned hydrocarbon processing facility.
16. A method of installing an offshore hydrocarbon processing facility comprising installing a jacket of an offshore platform and subsea processing equipment such that the subsea processing equipment is disposed within the jacket.
17. A method according to claim 16, wherein the subsea processing equipment is formed integrally with the jacket.
18. A method according to claim 16, wherein installing the subsea equipment comprises:

providing the subsea processing equipment at a location that is subsea and outside of the jacket, and

- 14after installing the jacket, manoeuvring the subsea processing equipment within the jacket.
19. A method according to claim 18, wherein the jacket comprises an opening 5 sized to receive the subsea processing equipment, and wherein the step of manoeuvring comprises manoeuvring the subsea processing equipment through the opening.
20. A method according to claim 18 or 19, wherein a driving force for the

10 manoeuvring is provided by a line connecting the subsea processing equipment to a vessel.

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