WO2002025060A1

WO2002025060A1 - Shunting of a well stream

Info

Publication number: WO2002025060A1
Application number: PCT/NO2001/000380
Authority: WO
Inventors: Knut Olaf Nyborg
Original assignee: Aker Engineering As
Priority date: 2000-09-19
Filing date: 2001-09-19
Publication date: 2002-03-28
Also published as: AU2001292449A1; NO20005595D0

Abstract

The present invention relates a method and an arrangement for preventing hydrate formation in a shut down pipeline (1) by removing or reducing the hydrostatic pressure produced by the fluid in a riser (2) on the fluid in the pipeline (1) by a complete or partial drainage of the fluid in the riser (2). The invention is characterized in that the fluid in the riser (2) is shunted into at least one other pipeline and riser system by means of a shunting manifold (6).

Description

SHUNTING OF A WELL STREAM

The present invention relates to a method and an apparatus to prevent hydrate formation in a shutdown pipeline . This is especially relevant where the pipeline is connected to a riser at a depth sufficient to give a fluid pressure in the riser, and where the surrounding temperature can lead to hydrate formation.

Hydrates may form when the temperature and pressure are in the so-called hydrate stable area. The pressure/temperature curve limiting the hydrate stable area will depend on the actual fluid and its composition. Reference may be made to relevant literature for a more detailed description of hydrates.

It is well known that hydrate formation in wellstream can be avoided utilising one of the following methods:

• Maintain of/increase the temperature • Reduce the pressure

• Introduce chemicals to the wellstream (displace the hydrate curve for the actual fluid)

• Remove the water

As of today several methods for prevention of hydrates exist within one or several of these methods .

Pressure reduction is not normally used for pipelines and risers where depth and temperature conditions can promote hydrate formation. This is mainly due to lack of suitable methods and arrangements . US 4 589 4343 discloses an apparatus and a method for preventing hydrate formation in subsea oil and gas pipelines . In this, the riser is depleted of fluids to reduce the hydrostatic pressure by leading these into a reservoir. The invention does not describe the interaction between several pipeline and riser systems and how such interaction can be exploited in a practical and efficient way. Further the invention is limited to solving the hydrate problem and does not describe the possibility to use an arrangement at the connection between the riser and the pipeline also for continuous treatment of the wellstream.

The object of the present invention is to provide a method and an apparatus which is not encumbered with the above mentioned disadvantages.

The present invention provides an efficient and cost- effective method and arrangement to prevent hydrate formation in a submerged, shut-in pipeline connected to a riser, where depth and temperature may promote hydrate formation. The invention is characterised by shunting the wellstream to another pipeline and riser system.

The present invention is further characterised by a mani- fold system so that the entire wellstream, or a part of it, may be shunted from one pipeline and riser system over to another. This manifold system is provided with a pumping device if the supply of additional energy is necessary.

^w Part of the wellstream" can, in this context, be either a relatively large part of all phases, or it can be one or more specific phases, such as water, oil, gas or particles. According to one aspect of the present invention, pressure in the riser and pipeline is reduced so as to prevent hydrate formation. At subsequent start-up, hydrate formation is avoided by keeping the pressure at a sufficiently low level .

According to another aspect of the present invention, produced water may be separated from the wellstream in one or more pipeline and riser systems, and transferred to an injection pipeline and riser system.

Below, a more detailed, but non-limiting description, of the present invention follows with reference to the at- tached figures, where

Fig. 1 shows a first embodiment of the present invention,

Fig. 2 shows schematically one possible embodiment of a shunting manifold according to the present invention,

Fig. 3 shows another embodiment of the present invention with a tank installed in connection with the shunting manifold,

Fig. 4 shows a third embodiment of the present invention that makes a faster pressure reduction of the pipeline possible,

Fig. 5 shows schematically a fourth possible embodiment of a manifold according to the present invention that makes treatment of the wellstream possible, and Fig. 6 shows how modules for treatment of the wellstream can be adapted according to requirements .

With reference to figures 1 and 2, two or more pipelines

(1) are shown, either production pipelines (1) or injection pipelines (100) , which is tied in to one or more riser bases (3) , where the individual pipeline is connected to its dedicated riser (2) . The separate pipeline and riser systems are initially isolated from one another.

A shunting manifold (6) is arranged between the lower riser connector (4) and the pipeline connection (5) , in that the shunting manifold arrangement (6) makes it possible to shunt wellstream, entirely or in part, to possible necessary processing, before it is shunted further into another pipeline and riser system. The individual pipeline and riser systems are isolated from the manifold (6) by means of isolation valves (7) .

The fluid from one pipeline and riser system is shunted over to another by opening the isolation valves (7) for the two systems. The necessary manifold valves (8) are also opened so that the fluid can be lead to the inlet side of the pumping device (9) ensuring that the fluid is supplied with sufficient energy so that it flows over to the other pipeline and riser system through this system' s isolation valve. The pumping device (9) is one of several possible processing facilities that can be installed in the shunting manifold (6) . The arrangement will be shaped according to the physical arrangement of pipelines (1) and risers (2) and the tie-in arrangements of the risers. The number of manifold valves (8) is decided by the number of pipelines and risers, and the flexibility required. Figure 2 shows how four pipelines, three production pipelines (1) and one injection pipeline (100) , are coupled directly to their dedicated risers (respectively 2 and 200) . Here the system is divided into two, where pipelines and risers on the one side can be drained to risers on the other side, or vice versa. It is not possible to drain to risers on the same side of the manifold.

Further, the mentioned pumping device (9) can have either hydraulic or electric motor. In the case with hydraulic motor, pressure energy can be supplied by shunting injection water to the hydraulic turbine motor of the pump, as shown in figure 2, using a so-called shunting pipe (20) for injection water.

Figure 2 also shows an arrangement in which all pipelines and risers are placed on one common riser base. The arrangement can also be arranged in such a way that pipelines and risers are divided between several riser bases. Such a solution can be preferable if it shall be used in connection with risers tied in to several PipeLine End Modules (PLEMs) distributed around a floating production installation.

The shunting manifold arrangement may also include alternative means for the treatment of the wellstream before it enters a riser. Such means may be installed initially or later in the field life when needed. Equipment for treatment of the wellstream can be placed on the base, or as a process module located on a separate foundation. The content in the process module may be adapted to the need for treatment of the wellstream, which may alter during the field lifetime. Examples of equipment in such a process module may be :

• Multiphase pump for boosting the flow from low pressure wells

• Water separator to remove produced water

• Desander to remove sand and other particles

• Separator to separate the wellstream in gas, oil and water phases

Additionally, a shunting manifold may, together with a shunting manifold, make use of a tank for depressurisation of a pipeline and riser at shut-in condition. Figure 3 illustrates integration of a tank for pressure reduction characterised by combining the tank with a shunting manifold installed in connection with one or several pipeline end modules .

The following five examples show how a shunting manifold according to the present invention can be exploited, by that the examples are only meant as non-limiting illustrations on preferred embodiments.

1 . Draining and depressurisation utilising a subsea pump 2. Draining and depressurisation utilising a subsea tank and - pump 3. Isolation and depressurisation utilising a subsea tank and - pump 4. Isolation and depressurisation utilising subsea tanks and - pump with a common gas manifold 5. Shunting of one phase of the wellstream from one pipeline and riser system to another.

1. Draining and depressurisation utilising a subsea pump

Shutdown Refer to Figure 1 and 2. The backpressure having effect on the liquid column in the riser (2) is eliminated in a normal way by releasing the pressure from the top of each riser. The hydrostatic pressure from the liquid column in the riser (2) will thus be the only source to a riser pres- sure and a backpressure in the adjacent pipeline (1) exceeding the hydrate forming pressure at the surrounding temperature . By draining this liquid column into another active riser (2) , or into another suitable buffer volume, the potential for hydrate formation will be removed simul- taneously reducing the backpressure in the pipeline (1) sufficiently to avoid hydrate formation. One must be aware of that when the backpressure in the pipeline (1) is reduced the content in this will expand due to gas flashing off. Most probably this will result in additional liquid flow into the riser (2) . Due draining of the riser must continue until the system is stabilised at a sufficiently low pressure, or possibly until the entire system is ready for start-up. Instruments (10) at the seabed may be utilised to monitor and control the draining operation.

Shunting of fluid from one riser and pipeline system into another takes place by that the isolation valves (7) be- tween riser (1) and shunting manifold (6) for the two systems are opened, necessary manifold valves (8) are opened and the fluid may be lead into the suction side of a pumping device (9) , supplying sufficient energy to the fluid before it is shunted via the isolation valve (7) and into the mixing point (11) , where it is mixed with flowing fluid from the_. other pipeline and riser system.

This shunting operation ought to be performed before the fluid in the shutdown riser and pipeline system is cooled down to below the hydrate forming temperature at the backpressure experienced by the pumping device (9) . Alternatively hydrate inhibitor must be injected upstream the pumping device (9) , to avoid hydrate formation in the seg- ment between the pressure side of the shunting device and the mixing point (11) .

Start-up

After draining and shutdown the fluid in the pipeline (1) and the pipeline material in the liquid emptied riser (2) may be close to the surrounding temperature . Further the fluid in the shutdown pipeline (1) is not inhibited with hydrate preventing chemicals. Thus naturally flowing startup most probably would result in formation of hydrates due to the increased hydrostatic pressure from the increasing liquid column.

This can be avoided by starting up in the same mood as utilised for draining and pressure reduction, that is by shunting the cold fluid via a shunting manifold (6) and pumping device (9) into another riser. Start-up is initiated by opening the wellhead choking valves (12) gradually so that the pressure and with that also the fluid flow is increased gradually in the pipeline (1) . As long as non inhibited fluid is present in the pipeline and/or the driving pressure is non sufficient to transport the liquid up through the drained pipeline (2) , there will be a need to shunt wellstream via the shunting manifold (6) , where the pumping device (9) supplies the energy needed, and into a flowing riser. The pumping device (9) will maintain a low backpressure in the pipeline (1) avoiding hydrate formation in the cold non-inhibited fluid. During the entire start-up hydrate inhibitor must be injected upstream the pumping device (9) so that hydrate formation in the segment between the pressure side of the pumping device and the mixing point (11) is avoided.

If one, in connection with start-up of a drained and pressure reduced system, choose to inject hydrate inhibitor at the wellhead, natural flow in the drained riser (2) is reestablished as soon as the fluid arriving the riser (2) is sufficiently inhibited also at the hydrostatic pressure corresponding to a completely liquid filled riser. If one choose to inject hydrate inhibitor at the riser (2) only, one must assure that the arriving fluid temperature at the transfer pipeline and riser exceeds the hydrate forming temperature at the hydrostatic pressure corresponding to an entirely filled riser (2) .

When this is accomplished, the isolation valves (7) may be closed, the pumping device (9) stopped and normal produc- tion can be established in the risers (2) which have been drained earlier. Since the fluid will be cooled when it flows upwards in the drained riser (2) hydrate inhibitor injection close to the seabed into the riser (2) must continue until the arriving temperature at the surface exceeds the hydrate forming temperature at the hydrostatic pressure corresponding to liquid filled riser (2) .

2. Draining and depressurisation utilising a subsea tank and - pump

Refer to Figure 3. Draining of the riser (2) and depressurisation of the pipeline (1) can also be performed through a tank (13) placed at the seabed in connection with the riser base (3) . The tank (13) has as least one inlet (14) and one gas outlet (15) . Normally there will also be one or more liquid outlets (16/17) . The gas outlet (15) is in contact with the surface via a gas pipe (18) .

The figure and further description shows a suitable pipe (14) between the pipeline (1) and the tank (13) . This solution gives a very flexible functionality. A simplified solution will be to couple the tank (13) directly to the shunting manifold (6) . Draining to the tank will then be performed through the shunting manifold.

It is assumed that the risers involved are depressurised from the surface, so that only the hydrostatic pressure from the liquid column in the riser is affecting the belonging pipeline.

The tank (13) is integrated in the riser base and can be of a size corresponding to maximum liquid volume in all the installed risers (2) plus additional buffer volume corresponding to the liquid content that can be transported from the pipelines (1) in connection with expansion of the fluid due to flashing of gas. Each pipeline and riser system is connected to the tank (13) via a pipe (14), in which an isolation valve (27) is located and will be closed under normal production. Further the tank (13) is connected to the surface via a gas pipe (18) in where a choking device (19) is installed and can be utilised to control the pressure inside the tank (13) .

Figure 3 illustrates the tank (13) and the risers inte- grated in one common riser base. Alternatively the tank can be arranged on a foundation and be connected to other pipeline end modules, or the tank can be located departed from the risers.

Shutdown

Opening the isolation valves (27) to the riser and pipeline systems, which shall be depressurised/drained, does draining of risers and pressure reduction of pipelines. At the same time the pressure inside the tank (13) is controlled to a desired level via the gas pipe (18) and the choking arrangement (19) installed at the surface. Since the pressure in the tank is reduced, more and more of the liquid in the risers (2) will be drained into the tank. At the same time the fluid in the pipeline (1) will expand due to the depressurisation, and liquid will most probably flow into the tank (13) . Basically the tank (13) shall be large enough to handle liquid from all risers (2) and the additional liquid from the pipelines (1) . However, an arrangement for level monitoring should be installed. It will then be possible to open the liquid outlet (16) when needed, and allow partly stabilised liquid to flow into the shunting manifold (6) at the suction side of the pumping device (9) , through the pumping device (9) and into one of the risers that is already drained or alternatively into one of the pipelines which is still operating.

Injection of chemicals will most probably be needed to avoid possible wax problems or similar problems in the tank (13) . Alternatively a sufficiently warm tank during the entire shutdown period must be ensured, or arrangements for hot flushing of the wax layer being prepared.

Start-up

After draining and shutdown the fluid in the pipeline (1) and the pipeline material in the liquid emptied riser (2) may be close to the surrounding temperature. Further the fluid in the shutdown pipeline (1) is not inhibited with hydrate preventing chemicals. Thus naturally flowing startup most probably would result in formation of hydrates due to increased hydrostatic pressure from the increasing liquid column.

This can be avoided by utilising the same method as described for " Draining and depressurisation utilising a subsea pump" , or by using a slightly modified method as described below.

The fluid from the pipeline which is started up, is transferred into the tank (13) , which by means of the gas pipe (18) and choking device (19) operates in a pressure region which will not form hydrates in the non inhibited and cold fluid. The gas is flashed off and sent through the gas pipe (18) and a relatively gas free liquid phase can be transferred into the shunting manifold (6) , where a pumping de- vice (9) supplies the liquid with sufficient energy before it is shunted into another riser (2) where it is mixed with hot flowing fluid. This will go on as long as the fluid arriving the riser is non-inhibited and/or the driving pressure is sufficient to transport the liquid through the drained riser (2) . Even if a relatively gas free liquid out from the tank (13) is assumed, hydrate inhibitor upstream the pumping device (9) during the entire start-up ought to be injected.

If injection of hydrate inhibitor at the wellhead is utilised during start-up of drained and depressurised system, natural flow in drained riser (2) can be re-established as soon as the fluid arriving the riser (2) is sufficiently inhibited also at the hydrostatic pressure corresponding to entirely filled riser. If one choose to inject hydrate inhibitor at the riser (2) only, one must assure that the arriving fluid temperature at the transfer pipeline and riser exceeds the hydrate forming temperature at the hydrostatic pressure corresponding to entirely filled riser (2) . Necessary instruments (10) at the pipeline end modules are installed to monitor this. When these conditions are fulfilled, the isolation valves (7 and 27) can be closed, the pumping device (9) can be stopped and normal production can be established in the risers (2) which have been drained. Since the fluid will be cooled when it flows upward in the drained riser (2) injection of hydrate inhibitor into the riser (2) close to the seabed must continue until the arriving temperature at the surface exceeds the hydrate form- ing temperature at the hydrostatic pressure corresponding to liquid filled riser. 3. Isolation and depressurisation utilising a subsea tank and - pump

An option of the previous procedure is illustrated in Figure 4. Here a course of action is shown where the liquid column in the riser (2) is isolated from the pipeline (1) by using a riser isolation valve (21) , on which the isolation valve (27) between the pipeline (1) and the inlet (14) to the tank (13) is opened, allowing fluid in the pipeline (1) to flow into the tank (13) .

Thereafter depressurisation of the pipeline will be performed using the same procedure as described for " Draining and depressurisation utilising a subsea tank and - pump" . The start-up sequence will also be performed utilising the same procedure.

Closing the riserbase isolation valve (21) will for the backpressure in the pipeline (1) have the same effect as draining the riser. The difference is that while the drain- ing operation takes some time, the isolation operation will elapse very fast . The disadvantage is that nothing is done to the hydrate problem in the riser (2) . By utilisation of this procedure, hydrate prevention in the shut down riser (2) must be avoided utilising another method, either by in- hibition or heating.

4. Isolation and depressurisation utilising subsea tanks and - pump with a common gas manifold

A third option of " Draining and depressurisation utilising a subsea tank and - pump" is to divide the tank (13) into several small depressurisation tanks. In this case each pipeline (1) and riser (2) , or groups of pipelines and ris- ers can be depressurised into dedicated tanks. The gas outlet from the smaller tanks is connected to a gas manifold with a common gas pipe (18) , as for the solution with a common tank. The advantage with such a solution may be re- duced cost for the tanks and reduced total cost for solutions consisting of several riser bases.

The solution with several depressurisation tanks is prepared to utilise the depressurisation tank on more perma- nent basis, as separator, of which the object is to separate gas, water or particles from the wellstream.

5. Shunting of one phase of the wellstream from one pipeline and riser system to another By installation of a separation device (22) (refer to Figure 5 and 6) and utilisation of the invention's shunting manifold arrangement it will be possible, also in normal operation, to separate one or more phases from the well- stream before it is shunted into another pipeline and riser system placed at the same riser base. Alternatively the shunting manifold arrangement can include several riser bases, and the equipment separating the phases from the wellstream can be arranged on a separate foundation or on another suitable place .

A separating device (22) is installed in the segment between the lower riser connector (4) and the pipeline connection (5) . The separating device has one inlet (23) which is connected to the pipeline side of the segment and two outlets, of which one (24) is connected to the riser side of the same segment and the other (25) is connected to the shunting manifold (6) . What kind of phase to be separated out and thus what kind of separating device being installed is flexible. The separated phase may be water, particles and gas, or combinations of these. Separation of water is described below as an illustration of the procedure.

The object is to separate water from the wellstream in a production pipeline (1) , and shunt the water to the water injection pipeline (100) . The wellstream is lead from the production pipeline (1) to the separating device (22) , which separates most of the water phase. The treated well- stream (without water) is lead to the production riser (2) , whereas the separated water is shunted into a water injection shunting manifold (6) . A pumping device (9) will supply the wellstream with sufficient energy before the water is shunted to the water injection system where it is mixed with other injection water and lead into the water injection pipeline (100) .

Figure 6 also shows that the separating device may consist of a pipe (28) only. The content in the installation may vary dependent of the wellstream composition and pressure. Since the separating device is implemented as a replaceable module in the riser system, the device can be replaced when needed. In an early phase of the field lifetime it may not be necessary with wellstream processing, and the module will then only consist of a pipe connecting the pipeline with the riser. If the water content in the pipeline increases as a function of production time, the pipe can be replaced with a separating device that separates the water from the rest of the wellstream. Thus the shunting manifold invention makes it possible to prepare for later treatment of the wellstream in an economically favourable way: The arrangement is prepared for treatment of the wellstream when at the same time much of the cost is postponed to later in the file life.

Claims

C l a i m s

1. Method to prevent hydrate formation in a shut down pipeline (1) by removing or reducing the hydrostatic pressure produced by the fluid in a riser (2) on the fluid in the pipeline (1) by a complete or partial drainage of the fluid in the riser (2) , c h a r a c t e r i z e d i n the fluid in the riser (2) being shunted into at least one other pipe- line and riser system by means of a shunting manifold (6) .

2. The method according to claim 1, c h a r a c t e r i z e d i n the fluid in the pipeline (1) and the riser (2) being pumped out via at least one pipe (6) into at least one other pipeline and riser system (1, 2) .

3. The method according to claim 2 , c h a r a c t e r i z e d i n the fluid from the pipeline and riser system (1, 2) being mixed with a fluid from at least one other pipeline (1) such that the temperature in the resulting mixed fluid is sufficient to avoid hydrate formation in the riser (2) transporting the mixed fluid to the surface.

4. The method according to claim 2 , c h a r a c t e r i z e d i n at least two pipeline and riser systems (1, 2) being connected by means of a suitable manifold (6) , said manifold (6) being provided with at least one pump (9) , said at least one pump (9) contributing to the depressurisation of at least one pipeline and riser system (1, 2) possible via at least one of the other pipeline and riser systems (1, 2) .

5. The method according to claim 4, c h a r a c t e r i z e d i n each of the pipeline and riser systems (1, 2) being connected with the manifold by means of the pipe (6) , said pipe (6) being provided with an isolation valve (7) , a number of valves (8) in the manifold (6) and between the pipeline and riser systems (1, 2) and the manifold (6) being opened and closed when needed.

6. The method according to claim 4 or 5, c h a r a c t e r i z e d i n a number of additional risers (2) being connected to the manifold (6) , an additional riser (2) being dedicated to depressurisation.

7. The method according to claim 4 or 5, c h a r a c t e r i z e d i n a tank (13) being connected to the manifold (6) , said tank (13) having at least one inlet (14) and at least one gas outlet (15) , possibly also at least one liquid outlet (16) , said gas outlet (15) communicating with the surface via a gas pipe (18) .

8. The method according to claim 7, c h a r a c t e r i z e d i n the content in the pipeline (1) and the riser (2) being lead to the tank

(13) by opening the isolation valve (27) between the pipeline (1) and the inlet (14) , said tank (13) possi- bly also functioning as a slug catcher during the depressurisation.

9. The method according to claim 7, c h a r a c t e r i z e d i n the liquid column in the riser (2) being isolated from the pipeline (1) by means of an isolation valve (21) , the isolation valve (27) between the pipeline (1) and the inlet (14) to the tank (13) being opened in order for the fluid in the pipeline (1) to be lead into the tank (13) , said tank (13) possibly functioning as a slug catcher during depressurisation.

10. The method according to claim 8 or 9, c h a r a c t e r i z e d i n the pressure in the tank (13) and thus the pipeline (1) being guided by means of a choking device (19) on the gas pipe (18) , the reduced pressure in the tank (13) and the pipeline (1) resulting in flashing of gas, the gas being trans- ferred to the surface via gas pipe (18) .

11. The method according to claim 8 or 9, c h a r a c t e r i z e d i n the liquid phase in the tank (13) being pumped out by means of a suitable pump (9) , the liquid outlet (16) from the tank (13) being connected to another pipeline and riser system (1, 2) or another storage device.

12. The method according to claim 8 or 9, c h a r a c t e r i z e d i n the pipeline and riser systems (1, 2) being depressurised by means of several smaller tanks (13) , each tank handling the de- pressurisation of each pipeline and riser system (1, 2) or groups of pipeline and riser systems.

13. The method according to claim 12, c h a r a c t e r i z e d i n the pipeline and riser systems (1, 2) being depressurised by means of the tanks (13) , said tanks (13) being connected by a gas manifold, said manifold comprising a common gas pipe (18) to the surface.

14. The method according to claim 4 or 5, c h a r a c t e r i z e d i n separating one or more phases from the wellstream in one or more pipelines (1) during normal operation by shunting the separated phase (s) into another pipeline and riser system (1, 2) .

15. The method according to claim 14, c h a r a c t e r i z e d i n the wellstream being treated in a separation device provided between the lower riser connector (4) and the pipeline connection (5) , the separating device only having an inlet (23) and two outlets (24, 25) , said inlet being connected to the pipeline side of the segment, one of the two outlets (24) being connected to the riser side of the same segment and the other (25) being connected to a shunting manifold (6) .

16. The method according to claim 15, c h a r a c t e r i z e d i n the separated phase (s) being supplied with sufficient energy by a pumping device (9) before the phase (s) is/are shunted by a shunting manifold (6) and transferred into a water injection pipe (200) .

17. The method according to claim 14, c h a r a c t e r i z e d i n the separating device (22) being modified or replaced during the lifetime of the installation dependent of the functional requirements and the wellstream composition and pressure.

18. Arrangement to prevent hydrate formation in a shut down pipeline (1) , said arrangement facilitating removal or reduction of the hydrostatic pressure produced by the fluid in a riser (2) on the fluid in the pipeline (1) by means of a complete or partial drain- age of the fluid in the riser (2) , c h a r a c t e r i z e d i n that the pipeline (1) is connected with at least one other pipeline and riser system (1) by means of a shunting manifold (6) .

19. The arrangement according to claim 18, c h a r a c t e r i z e d i n that more than two pipeline and riser systems (1, 2) are connected via a suitable manifold (6) and at least one pump (9) , said pump (9) making depressurisation of one or several pipeline and riser systems (1, 2) possible via at least one of the other pipeline and riser systems (1, 2) .

20. The arrangement according to claim 18 or 19, c h a r a c t e r i z e d i n that each of the pipeline and riser systems (1, 2) are connected with the manifold (6) by means of a pipe, said pipe being provided with an isolation valve (7) , wherein a number of valves (8) in the manifold (6) and between the pipeline and riser systems (1, 2) and the manifold (6) are opened and closed when needed.

21. The arrangement according to claim 18, 19 or 20, c h a r a c t e r i z e d i n that an additional riser (2) is connected the manifold (6) , said additional riser (2) being dedicated to depressurisation.

22. The arrangement according to claims 18-21, c h a r a c t e r i z e d i n that a tank (13) is connected to the manifold (6) , said tank (13) having at least one inlet (14) and at least one gas outlet (15) , possibly also at least one liquid outlet (16) , said gas outlet (15) communicating with the surface via a gas pipe (18) .

23. The arrangement according to claim 22, c h a r a c t e r i z e d i n that an isolation valve (21) is provided between the pipeline (1) and the riser (2) in order to isolate the liquid column from the pipeline (1) , said isolation valve (27) between the pipeline (1) and the inlet (14) to the tank (13) being opened in order to let the fluid in the pipeline (1) into the tank (13) .

24. The arrangement according to claim 23, c h a r a c t e r i z e d i n that the liquid phase in the tank (13) is pumped out by means of a suitable pump (9) , said liquid outlet (16) from the tank (13) being connected to another pipeline and riser system (1, 2), or another storage device.

25. The arrangement according to claims 18-20, c h a r a c t e r i z e d i n that the pipeline and riser systems (1, 2) are connected to smaller tanks (13) , each tank takeing care of depressurisation of each pipeline and riser system (1, 2) or groups of pipeline and riser systems.

26. The arrangement according to claim 25, c h a r a c t e r i z e d i n that the gas outlet (15) from the tanks (13) being connected by a gas manifold with a common gas pipe (18) to the surface.

27. The arrangement according to claims 18-26, c h a r a c t e r i z e d i n that the wellstream is transferred to a separating device provided between the lower riser connector (4) and the pipeline connection (5) , said separating device comprising one inlet (23) and two outlets (24, 25) , said inlet (23) being connected to the pipeline side of the segment, one of said outlets (24) being connected to the riser side of the same segment and the other (25) being connected to the shunting manifold (6) .

28. The arrangement according to claim 18-28 or 29, c h a r a c t e r i z e d i n that the separating device (22) is modified or replaced during the lifetime of the installation dependent of the functional requirements and the wellstream composition and pressure.