METHOD FOR TRANSFERRING FLUID BETWEEN A FIRST OFFSHORE ASSEMBLY LOCATED IN A BODY OF WATER AND AN ASSEMBLY FLOATING ON THE BODY OF WATER, ASSOCIATED ASSEMBLY AND FACILITY

Description

CROSS REFERENCE TO RELATED APPLICATIONS

The present application claim priority of French Patent Application No. 2413499 filed Dec. 5, 2024. The entire contents of which are hereby incorporated by reference.

FIELD

The present invention relates to a method for transferring fluid between an offshore assembly located in a body of water, the offshore assembly having a first fluid storage capacity, and a floating assembly on the body of water having a second fluid storage capacity, the method comprising the following steps:

• • positioning a lateral face of the floating assembly opposite a lateral face of the offshore assembly to place the floating assembly side by side with the offshore assembly;
  • installing and mechanical tensioning of a plurality of mooring lines between the offshore assembly and the floating assembly, each mooring line having a first attachment point on the offshore assembly, a second attachment point on the floating assembly, and an active length under mechanical tension between the first point and the second point;
  • fluidic connection between the first fluid storage capacity and the second fluid storage capacity via a fluid transfer system, and transfer of fluid between the first fluid storage capacity and the second fluid storage capacity.

BACKGROUND

The method applies in particular to the transfer of cryogenic petroleum fluids, such as liquefied natural gas or liquefied petroleum gases. The method also applies to the transfer of treated liquefied gases obtained by processing petroleum or natural gas extracted at sea or, more generally, from liquefied gases produced or recovered offshore.

The offshore assembly is, for example, a floating liquefied natural gas unit (FLNG), a floating storage and regasification unit (FSRU) or a floating export unit of liquefied petroleum gases (LPG). In a variant, the offshore assembly is intended for the storage and transport of liquefied gases such as carbon dioxide or ammonia.

The floating assembly is a ship or a barge, for example, to bring the liquefied gas back to the coast. The floating assembly is a methane carrier in particular or, more generally, a liquefied gas transport vessel.

Liquefied gas production terminals at sea must be unloaded regularly of the fluid they produce or process. In this context, when no pipeline suitable for transporting cryogenic fluid between the production terminal and the coast exists, it is known to recover the fluid stored on the offshore assembly using transport ships or barges that bring the fluid back to the coast.

In benign maritime conditions, that is, with calm water or in protected areas, it is known to carry out a side-by-side fluid transfer by mooring the floating assembly to the offshore assembly, parallel to each other along their lateral faces, and by placing unloading arms or flexible pipes between them to transfer the fluid.

This transfer method, although effective, has limitations as soon as the weather deteriorates. In particular, mooring cannot be carried out beyond a certain relative amplitude of movement between the floating assembly and the offshore assembly, otherwise the moorings are likely to break. Furthermore, in the case where unloading arms are used, these are limited in terms of specification to absorb relative displacements.

In more complicated environments, it is known to unload the fluid by placing the floating assembly in tandem with the offshore assembly, or even by placing a discharge buoy between the two, connected to the respective floating assembly and offshore assembly by flexible pipes.

Such a solution exists in the unloading of oil but remains much less suitable for the transfer of cryogenic fluids. In particular, the flexible pipes that are frequently used for oil transfer do not have an industrial application for unloading cryogenic fluids over long distances. In addition, a fleet of transport barges specifically adapted to this unloading is required.

SUMMARY

An object of the invention is therefore to obtain a method of fluid transfer between an offshore assembly located in a body of water and a floating assembly, which can be used in less favorable weather conditions than those generally used for side-by-side transfer, the transfer method being simple to implement, with floating assemblies not dedicated to tandem transfer.

To this end, the invention relates to a fluid transfer method of the aforementioned type, characterized by the following steps:

• • continuous measurement of the mechanical tension applied to the active length of at least one mooring line;
  • control by a control system, of the active length of the at least one mooring line, to keep the mechanical tension applied to the at least one mooring line within a preset mechanical tension interval.

The method according to the invention may comprise one or more of the following features, taken alone or in any technically possible combination:

• • it comprises the following steps:
    • continuous measurement of the mechanical tension applied to the active length of a plurality of mooring lines, in particular of all the mooring lines connecting the offshore assembly and the floating assembly;
    • control of the active length of each mooring line to keep the mechanical tension applied to each mooring line within a preset mechanical tension interval;
  • the at least one mooring line is connected at either the first point or the second point to a reel, with control of the active length of the at least one mooring line being carried out by winding or/and unwinding the at least one mooring line on the reel;
  • it comprises the connection of the other of the first point and the second point of the at least one mooring line to a fixed mooring point;
  • the reel includes a kinetic energy recovery system, the method comprising the recovery of electrical energy during the unwinding of the at least one mooring line and the winding of the at least one mooring line using at least part of the electrical power recovered by the kinetic energy recovery system;
  • it comprises the measurement of a relative movement between the offshore assembly and the floating assembly, the method comprising the control of the active length of the at least one mooring line by the control system, to keep a relative movement amplitude between the offshore assembly and the floating assembly within a preset movement amplitude interval;
  • the side-by-side arrangement of the lateral face of the offshore assembly and the lateral face of the floating assembly comprises the abutting of at least one fender,
  • preferably of a plurality of fenders, spaced longitudinally, between the lateral face of the offshore assembly and the lateral face of the floating assembly;
  • the abutting of the or each fender comprises a positioning of the or each fender on a spacing frame configured to increase the distance between the lateral face of the offshore assembly and the lateral face of the floating assembly during the side-by-side arrangement of the lateral face of the offshore assembly and the lateral face of the floating assembly;
  • the fluid transfer is carried out through an articulated unloading arm or/and through a flexible pipe.

The invention also relates to a fluid transfer assembly between an offshore assembly located in a body of water, with the offshore assembly having a first fluid storage capacity, and a floating assembly on the body of water, having a second fluid storage capacity, the fluid transfer assembly comprising:

• • a mooring system comprising a plurality of mooring lines between the offshore assembly and the floating assembly, configured to be installed and mechanically tensioned so that each mooring line has a first attachment point on the offshore assembly; a second attachment point on the floating assembly, and an active length under mechanical tension between the first point and the second point;
  • a fluid transfer system configured to establish a fluidic connection between the first fluid storage capacity and the second fluid storage capacity and a fluid transfer between the first fluid storage capacity and the second fluid storage capacity;
  • characterized by a control system of the mooring system comprising at least one sensor for continuous measurement of the mechanical tension applied to the active length of at least one mooring line, the control system comprising a control unit configured to control the active length of the at least one mooring line, to keep the mechanical tension applied to the at least one mooring line within a preset mechanical tension interval.

The fluid transfer system according to the invention may comprise one or more of the following features, taken alone or in any technically possible combination:

• • the mooring system comprises at least one reel, the at least one mooring line being connected at either the first point or the second point to the at least one reel, the control system controlling the active length of the at least one mooring line by winding or/and unwinding the at least one mooring line on the reel;
  • the control system comprises at least one sensor for continuous measurement of a relative positioning between the offshore assembly and the floating assembly, to determine a relative movement between the offshore assembly and the floating assembly, the method comprising the control by the control system of the active length of the at least one mooring line, to keep a relative movement amplitude between the offshore assembly and the floating assembly within a preset amplitude of movement interval;
  • the reel includes a kinetic energy recovery system configured to recover electrical energy during the unwinding of the at least one mooring line and to provide at least part of the recovered electrical power to wind the at least one mooring line.

The invention also relates to a fluid exploitation facility, comprising:

• • an offshore assembly intended to be placed in a body of water, the offshore assembly having a first fluid storage capacity;
  • a floating assembly, having a second fluid storage capacity, and a fluid transfer assembly as defined above, configured to be mounted between the offshore assembly and the floating assembly.

The facility according to the invention may comprise the following feature:

• • the offshore assembly is a platform, floating or fixed, for example, a floating liquefied natural gas unit, a floating storage and regasification unit, a floating export unit of liquefied petroleum gas, with the floating assembly advantageously being a ship or a fluid transport barge.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be better understood, based on the following description, given solely as an example, and made in reference to the appended drawings, in wherein:

FIG. 1 is a schematic top view of a fluid exploitation facility including a system for fluid transfer between an offshore assembly and a floating assembly for the implementation of a transfer method according to the invention;

FIG. 2 is a flowchart illustrating the main steps of a fluid transfer method according to the invention; and

FIG. 3 is a view of the mechanical tension applied over time on a mooring line deployed between the offshore assembly and the floating assembly during the implementation of the fluid transfer method according to the invention, and, in comparison, without implementing the fluid transfer method according to the invention.

DETAILED DESCRIPTION

A first fluid transfer method according to the invention is implemented in a fluid exploitation facility 10, schematically represented in FIG. 1.

As illustrated in FIG. 1, the facility 10 comprises an offshore assembly 12, located in a body of water 14, and a floating assembly 16 movable in relation to the offshore assembly 12 on the body of water 14, between a fluid transfer configuration represented in FIG. 1, wherein it is moored to the offshore assembly 12, and a fluid transport configuration away from the offshore assembly 12, wherein it navigates on the body of water 14 to a discharge facility, advantageously on the coast.

The facility 10 further comprises a fluid transfer assembly 18 according to the invention, configured to moor the floating assembly 16 to the offshore assembly 12 by placing them side by side, to enable the transfer of fluid between the offshore assembly 12 and the floating assembly 16.

The body of water 14 is an ocean, a sea, a lake or a river, for example. The depth of the body of water 14 with regard to the facility 10 is between 15 m and 4000 m, for example.

The offshore assembly 12 is a terminal for the production and/or processing of cryogenic fluid offshore, for example. The offshore assembly 12 is in particular a floating liquefied natural gas unit (FLNG), a floating storage and regasification unit (FSRU), or a floating export unit of liquefied petroleum gases (LPG).

The offshore assembly 12 comprises a hull 20, which, here, is floating on the body of water 14. In a variant, the offshore assembly 12 is a fixed platform on the body of water 14.

The offshore assembly 12 further comprises a first fluid storage capacity 22, of cryogenic fluid in particular, arranged in and/or on the hull 20.

A cryogenic fluid is a substance that is used or stored at low temperatures, often below 150° C. (−238° F.). These fluids have particular properties due to their low temperatures and are often gases at room temperature that become liquids when cooled. Common examples of cryogenic fluids include liquefied natural gas (LNG), liquefied petroleum gases (LPG), liquid nitrogen, liquid helium, liquid oxygen, etc.

The hull 20 here extends along a first longitudinal axis A-A′ between a first longitudinal end 24 and a second longitudinal end 26.

The hull 20 is advantageously closed horizontally by at least one upper deck 24 on which utilities are arranged, in particular fluid transfer pumps and/or fluid processing systems and possibly surface infrastructures. The hull 20 defines lateral faces 30A, 30B, one of which lateral face 30A is intended for mooring the floating assembly 16.

The floating assembly 16 is a barge or a ship, for example. It comprises a floating hull 40, closed by at least one upper deck 42.

The floating assembly 16 further comprises a second fluid storage capacity 44 of cryogenic fluid, in particular, arranged in and/or on the hull 40, the second fluid storage capacity 44 being intended to be connected to the first fluid storage capacity 22 to carry out a fluid transfer between the offshore assembly 12 and the floating assembly 16 via the fluid transfer assembly 18.

The floating assembly 16 further includes at least one autonomous propulsion system 46, such as at least one engine associated with at least one propeller or at least one thruster, allowing the floating assembly 16 to move in relation to the offshore assembly 12 between the fluid transport configuration, away from the offshore assembly 12, and the fluid transfer configuration visible in FIG. 2, moored to the offshore assembly 12.

The hull 40 extends between a stern 50 and a bow 48 along a second longitudinal axis B-B′. It has lateral faces 52A, 52B, one of which face 52A is intended to be placed opposite the lateral face 30A in the mooring configuration.

With reference to FIG. 1, the fluid transfer assembly 18 comprises a dynamic mooring system 60, intended to be placed between the offshore assembly 12 and the floating assembly 16, a control system 62 of the dynamic mooring system 60, and a fluid transfer system 64, configured to fluidically connect the first storage capacity 22 to the second storage capacity 44 when the dynamic mooring system 60 is in place.

The fluid transfer assembly 18 further comprises a system 66 for keeping a minimum spacing between the offshore assembly 12 and the floating assembly 16 in the fluid transfer configuration.

In this example, the dynamic mooring system 60 includes a plurality of mooring lines 70 configured to be mechanically tensioned. For each mooring line 70, the dynamic mooring system 60 comprises a reel 72 arranged on either the offshore assembly 12 or the floating assembly 16 to control an active length 76 of the mooring line 70 and a mooring point 74 arranged on the other of the offshore assembly 12 and the floating assembly 16.

In this example, the mooring system 60 comprises a plurality of mooring lines 70, each associated with a reel 72 on either the offshore assembly 12 or the floating assembly 16, and a mooring point 74 on the other of the offshore assembly 12 and the floating assembly 16.

In particular, the mooring system 60 comprises a plurality of mooring lines 70 extending from a region of the deck 28 of the offshore assembly 12, located near the first longitudinal end 24, to a region of the deck 42 of the floating assembly 16, located near the stern 50.

The mooring system 60 further comprises a plurality of mooring lines 70 extending between a region of the deck 28 of the offshore assembly 12 located near the second longitudinal end 26 to a region of the deck 42 of the floating assembly 16 located near the bow 48 on the deck 42.

Again, in this example, all the reels 72 are arranged on the offshore assembly 12, while all the mooring points 74 are located on the floating assembly 16.

In a variant, at least one reel 72 is located on the floating assembly 16, and at least one mooring point 74 is located on the offshore assembly 12. In another variant, all the reels 72 are located on the floating assembly 16 and all the mooring points 74 are located on the offshore assembly 12.

Thus, each mooring line 70 comprises an active length 76, intended to be mechanically tensioned, extending between a first point located on a reel 72 and a second point, constituted by the mooring point 74.

Each mooring line 70 is formed of a cable or a chain, for example, in particular a cable made of non-metallic material such as a polymer material, in particular nylon.

Each reel 72 comprises a rotary drum 80 intended to increase or decrease the active length 76 of the mooring line 70, a drive motor 82 for rotating the drum 80 selectively in both directions of rotation, a brake 84 to lock the drum 80 and set a determined active length 76, and, advantageously, a kinetic energy storage system 86, configured to store the kinetic energy related to the rotation of the drum 80 during the unwinding of the mooring line 70 to increase its active length 76.

The kinetic energy storage system 86 comprises an electric generator, for example, whose rotor is linked to the drum 80, a stator, and at least one storage battery or/and a flywheel.

The energy storage system 86 is connected to the motor 82 to provide electrical power enabling the driving rotation of the motor 82 during the winding of the mooring line 70.

For each mooring line 70, the control system 62 includes a sensor 90 for measuring the mechanical tension applied to the mooring line 70. It further comprises sensors 92A, 92B for determining the relative positioning of the offshore assembly 12 and the floating assembly 16.

The control system 62 further includes a central control unit 94, configured to receive data from the sensors 90, 92A, 92B, and to control the mechanical tension applied to each mooring line 70, to keep it within a preset mechanical tension interval and, advantageously, to determine the amplitude of movement of the floating assembly 16 in relation to the offshore assembly 12 and control the length of the mooring line 70, to keep the amplitude of movement within a preset amplitude of movement interval.

The mechanical tension measurement sensor 90 on each mooring line 70 is arranged in the reel 72, for example.

Each positioning sensor 92A, 92B is a geographic positioning sensor, for example, arranged on the offshore assembly 12 and on the floating assembly 16, respectively.

The central control unit 94 includes a computer, for example, including at least one processor 96 and at least one memory 98 comprising software modules suitable for being executed by the processor 96, to perform functions. In a variant, the control unit 94 is at least partially in the form of one or more programmable circuits, such as of the FPGA (Field-Programmable Gate Array) type, or in the form of a dedicated application electronic circuit, of the ASIC (Application-Specific Integrated Circuit) type.

The central control unit 94 advantageously includes a module 100 for determining the mechanical tension applied to each mooring line 70 from the data received from each mechanical tension measurement sensor 90, a module 102 for determining a relative movement amplitude between the offshore assembly 12 and the floating assembly 16, from the data received from the positioning sensors 92A, 92B, by difference between the geographic data obtained from each positioning sensor 92A, 92B, for example.

The central control unit 94 further includes a module 104 for developing a command for the active length 76 of each mooring line 70, configured to control each motor 82 and the associated drum 80 to wind or unwind the mooring line 70, to keep the mechanical tension applied to the mooring line 70 within a preset mechanical tension interval, as determined by the mechanical tension determination module 100, between a minimum mechanical tension and a maximum mechanical tension, and, advantageously, to simultaneously keep a movement amplitude within a preset movement amplitude interval, such as a horizontal movement amplitude between the floating assembly 16 and the offshore assembly 12, as determined by the amplitude determination module 102.

The preset mechanical tension interval is between 5 tons and 30 tons, for example, in particular between 5 tons and 10 tons.

The preset movement amplitude interval is between −10 m and +10 m, for example, in particular between −2 m and +2 m.

In particular, the command development module 104 is configured to reduce the active length 76 of each mooring line 70 when the mechanical tension applied to the mooring line 70 determined by the mechanical tension determination module 100 approaches the lower boundary of the preset mechanical tension interval, and/or when the movement amplitude determined by the amplitude determination module 102 approaches the upper boundary of the preset movement amplitude interval.

The command development module 104 is also configured to increase the active length 76 of the mooring line 70 when the mechanical tension applied to the mooring line 70 determined by the mechanical tension determination module 100 approaches the upper boundary of the preset mechanical tension interval and/or when the movement amplitude determined by the amplitude determination module 102 approaches the lower boundary of the preset movement amplitude interval.

Preferably, if both the requirements of keeping the mechanical tension and the movement amplitude, cannot be met, the command development module 104 is configured to control the active length 76 of the mooring line 70 within the preset mechanical tension interval without simultaneously keeping the movement amplitude within the preset movement amplitude interval.

The fluid transfer system 64 in this example includes at least one articulated unloading arm 110, preferably several articulated unloading arms 110 mounted on either the offshore assembly 12 or the floating assembly 16, being connected to the capacity 22, 44 of this assembly 12, 16, and at least one connection flange 112, mounted on the other of the offshore assembly 12 and the floating assembly 16, being connected to the capacity 22, 44 of this assembly.

In the example shown in FIG. 1, the articulated unloading arms 110 are mounted on the deck 28 of the offshore assembly 12, being connected to the first fluid storage capacity 22, while the connection flanges 112 are mounted on the deck 42 of the floating assembly 16, being connected to the second fluid storage capacity 44.

Each articulated unloading arm 110 is thus movable towards the connection flange 112 in the fluid transfer configuration to connect to the connection flange 112 and fluidically connect the first fluid storage capacity 22 to the second fluid storage capacity 44.

The maintenance system 66 comprises at least one fender 120 intended to be interposed between the respective lateral faces 30A, 52A of the respective hulls 20, 40 and advantageously, in this example, a spacing frame 122 of each fender 120 to define an intermediate spacing, between the lateral faces 30A, 52A opposite, greater than the spacing defined by the fenders 120, taken perpendicularly to the longitudinal axes A-A′, B-B′, and to reduce the hydrodynamic interactions between the offshore assembly 12 and the floating assembly 16.

The fenders 120 and the spacing frames 122 define an intermediate spacing between the lateral faces 30A, 52A that is greater than 0.5 m, in particular between 2 m and 8 m.

In this example, the spacing frames 122 are fixedly mounted on the hull 20, preferably from the lateral face 30A, protruding transversely in relation to the longitudinal axis A-A′. The fenders 120 are advantageously deployable from the deck 28 to be interposed between the spacing frame 122 and the lateral face 52A.

In a variant, at least one fender 120 and possibly a spacing frame 122 carrying the fender 120 are mounted integral with the hull 40, extending transversely from the lateral face 52A.

The fender 120 is a floating fender, for example, formed of a block of elastomeric material.

A fluid transfer method within the exploitation facility 10 between the offshore assembly 12 and the floating assembly 16 will now be described, with reference to FIGS. 1 and 2.

Initially, when the first storage capacity 22 of the offshore assembly 12 needs to be unloaded, the floating assembly 16 moves near the offshore assembly 12.

At step 150, the floating assembly 16 is placed side by side with the offshore assembly 12, with the respective longitudinal axes A-A′, B-B′ of the offshore assembly 12 and the floating assembly 16 being arranged in parallel.

The first lateral face of the floating assembly 52A is then located opposite and away from the first lateral face 30A of the offshore assembly 12 with interposition of the distance maintenance system 66, in particular of each fender 120 possibly mounted on a frame 122. This keeps the elements located on the respective decks 24, 42 at a distance, in particular the infrastructures present on each of the decks 24, 42.

Then, at step 152, a plurality of mooring lines 70 are installed, each from a reel 72 to a mooring point 74, and are mechanically tensioned.

Thus, each mooring line 70 has an active length 76 under mechanical tension between a first point defined on a reel 72 and a second point defined by a mooring point 74.

The mechanical tension of the active length 76 is adjusted to be equal to a value located within the preset mechanical tension interval.

Then, at step 154, the fluid transfer system 64 is mounted, to fluidically connect the first storage capacity 22 to the second storage capacity 44.

In the example shown in FIG. 1, the articulated unloading arms 110 are moved towards the connection flanges 112 and are each connected to a connection flange 112.

The fluid transfer is then activated in this example from the first storage capacity 22 to the second storage capacity 44.

At step 156, during the transfer of fluid, a continuous measurement is carried out (at a frequency greater than 1 Hz, for example) using each mechanical tension measurement sensor 90 connected to a mooring line 70 and continuous measurements are carried out (at a frequency greater than 1 Hz, for example) using the positioning sensors 92A, 92B on the offshore assembly 12 and on the floating assembly 16, respectively. The measurements are received by the control system 62, in particular by the central control unit 94.

The mechanical tension determination module 100 then calculates the mechanical tension applied to each mooring line 70 and determines whether the mechanical tension is within the preset mechanical tension interval. The amplitude determination module 102 determines a measure of the relative movement between the offshore assembly 12 and the floating assembly 16, such as a measure of horizontal movement amplitude between these assemblies 12, 16.

At step 158, the control unit 94 then controls the active length 76 of each mooring line 70, primarily to keep the mechanical tension applied to the mooring line 70 within the preset mechanical tension interval.

To this end, the command development module 100 develops a command for winding or unwinding the mooring line 70, based on the value of the mechanical tension applied to the mooring line 70.

For example, if the mechanical tension on the mooring line 70 approaches or exceeds the upper boundary of the preset mechanical tension interval, the command development module 104 establishes a command for unwinding the mooring line 70, to reduce the mechanical tension on the mooring line 70.

Conversely, if the mechanical tension applied to the mooring line 70 decreases towards the lower boundary of the preset mechanical tension interval or exceeds it, the command development module 104 develops a command for winding the mooring line 70.

Advantageously, the command development module 104 also takes into account the amplitude of movement of the floating assembly 16 in relation to the offshore assembly 12.

If the amplitude of movement decreases and approaches the lower boundary of the preset movement amplitude interval or exceeds it, the command development module 104 establishes or corrects the command for unwinding the mooring line 70.

Conversely, if the amplitude of movement increases and approaches the upper limit of the preset movement amplitude interval, then the command development module 104 develops a command or corrects a command for winding the mooring line 70.

The command intended to be applied to each mooring line 70 is then transmitted to the reel 72 to perform a winding or unwinding corresponding to the command, using the motor 82, which is possibly followed by locking, using the brake 84.

During the execution of an unwinding command, the kinetic energy storage system 86 activates, to convert the mechanical energy of rotation of the drum 80 into electrical power stored in the battery.

Conversely, in the case of winding, the battery of the kinetic energy storage system 86 delivers electrical power for driving the drum in rotation to the motor 80.

At step 160, steps 156 and 158 are repeated as long as the floating assembly 16 is moored to the offshore assembly 12, side by side with it.

At the end of the transfer of fluid, at step 162, the mooring lines 70 are released from their mooring point 74 and are wound on the reels 72. The floating assembly 16 is then released from the offshore assembly 12 and transports the fluid it contains in the second capacity 44 to a destination, located on the coast, for example.

In FIG. 3, the curve 170 illustrates the temporal variations of the mechanical tension of a mooring line 70 between the floating assembly 16 and the offshore assembly 12 during a side-by-side mooring of the prior art, not including continuous measurement of the mechanical tension applied to the mooring line 70, nor control of the mechanical tension.

As visible in FIG. 2, the curve 170 includes intervals wherein the mooring line 70 is slack and its mechanical tension is zero, followed by intervals of high mechanical tensions on the mooring line 70, which implies numerous dynamic fatigue constraints on the mooring line 70.

The curve 172, on the other hand, illustrates the mechanical tension applied to the mooring line 70 in the case of using the transfer method according to the invention, with a mechanical tension control applied to the mooring line 70. The curve 172 does not comprise intervals wherein the mooring line 70 is slack and its mechanical tension is zero, nor excursions into high mechanical tensions.

The curves 170, 172 were obtained by simulation with a limit agitation environment of the body of water 14 to perform a traditional side-by-side transfer operation comprising 1.5 m of amplitude due to the sea and wind and 2.5 m of amplitude due to the swell.

The maximum mechanical tension applied to the most mechanically tensioned mooring lines 70 is thus reduced from about 47 tons to about 20 tons.

This enables operating with wave heights that can increase from 0.5 m to 1.5 m, for example, depending on the periods and directions.

The annual operability rate is therefore increased by about 10 to 15%, for example, using conventional equipment. The relative movement envelope between the offshore assembly 12 and the floating assembly 16 is also kept within acceptable intervals.

By means of the invention just described, it is therefore possible to control the mechanical tensions applied to the mooring lines 70 in a coordinated manner, based on the agitation of the body of water 14, by limiting the mechanical tension peaks in the mooring lines 70 at the level of the active length 76, and by keeping an acceptable envelope of relative movement between the offshore assembly 12 and the floating assembly 16.

This control is carried out without direct measurement of wave height, nor of the high-frequency component of the ships' movements.

The method according to the invention smooths the mechanical tension peaks in the mooring lines 70 very effectively, thus enabling operation in more severe environments where mechanical tensions in the mooring lines generally limit the use of side-by-side transfer.

Thus, offshore assemblies 12 that produce cryogenic fluids in much more agitated areas can be designed with a reduced fluid storage capacity, which limits their sizes and saves investment costs, particularly in the case of floating liquefied natural gas units.