EP2432964A2 - Procédé de protection d'une colonne montante flexible et appareil correspondant - Google Patents

Procédé de protection d'une colonne montante flexible et appareil correspondant

Info

Publication number
EP2432964A2
EP2432964A2 EP10719358A EP10719358A EP2432964A2 EP 2432964 A2 EP2432964 A2 EP 2432964A2 EP 10719358 A EP10719358 A EP 10719358A EP 10719358 A EP10719358 A EP 10719358A EP 2432964 A2 EP2432964 A2 EP 2432964A2
Authority
EP
European Patent Office
Prior art keywords
fluid
riser
flexible
protection
stream
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Granted
Application number
EP10719358A
Other languages
German (de)
English (en)
Other versions
EP2432964B1 (fr
Inventor
Michalakis Efthymiou
Herman Theodoor Van Der Meyden
Johan Jan Barend Pek
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell Internationale Research Maatschappij BV
Original Assignee
Shell Internationale Research Maatschappij BV
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Shell Internationale Research Maatschappij BV filed Critical Shell Internationale Research Maatschappij BV
Priority to EP10719358.3A priority Critical patent/EP2432964B1/fr
Publication of EP2432964A2 publication Critical patent/EP2432964A2/fr
Application granted granted Critical
Publication of EP2432964B1 publication Critical patent/EP2432964B1/fr
Priority to CY20141100592T priority patent/CY1115428T1/el
Not-in-force legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/01—Risers
    • E21B17/015—Non-vertical risers, e.g. articulated or catenary-type
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/002—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling
    • E21B19/004—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling supporting a riser from a drilling or production platform
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/12—Underwater drilling

Definitions

  • the present invention provides a method of protecting one or more flexible risers which can carry a riser fluid, for instance a hydrocarbon production fluid such as natural gas, to or from a floating structure and an apparatus therefor.
  • a riser fluid for instance a hydrocarbon production fluid such as natural gas
  • the method disclosed herein seeks to protect the flexible risers from buckling caused by the heave and/or the pitch of the floating structure in response to wave motion in severe weather conditions .
  • the Floating Liquefaction of Natural Gas (FLNG) concept combines the natural gas treatment, liquefaction process, storage tanks, loading systems and other infrastructure into a single floating structure. Such a structure is advantageous because it provides an off- shore alternative to on-shore liquefaction plants.
  • FLNG Floating Liquefaction of Natural Gas
  • a FLNG vessel can be moored close to or at a gas field, in waters deep enough to allow off-loading of the LNG product onto a carrier vessel. It also represents a movable asset, which can be relocated to a new site when the gas field is nearing the end of its productive life, or when required by economic, environmental or political conditions .
  • the floating structure can be in fluid communication with the producing well heads of the reservoir.
  • the floating structure can be connected to one or more flexible risers.
  • the flexible risers can be secured to the sea bed by a riser base manifold.
  • a subsea flowline can connect the riser base manifold directly to the well heads or optionally via a well manifold.
  • a production hydrocarbon such as natural gas
  • a hydrocarbon reservoir such as a gas field
  • the riser base manifold is the point at which the production and any injection pipelines are connected to the flexible risers which convey the production hydrocarbon to the floating structure.
  • the flexible risers are connected to the floating structure at a hangoff point.
  • the hang-off point may be at a side of the floating structure, or situated within a moonpool in the floating structure, for example at the bottom of a turret.
  • the floating structure can be moored to the sea bed by a plurality of mooring lines which are anchored to the sea bed.
  • the flexible risers are flexible pipes suspended between the floating structure and riser base manifold, and can be configured as free-hanging catenaries or alternative configurations using buoyancy modules such as lazy wave and lazy S types.
  • buoyancy modules such as lazy wave and lazy S types.
  • WO-2006/031335-A1 is concerned with the prevention of hydrates in subsea equipment in a cold water production environment of relatively small offshore developments.
  • the disclosed system has at least one producing subsea well, a jumper for delivering produced fluids from the subsea well to a manifold, a production line for delivering produced fluids to a production gathering facility, and an umbilical for delivering chemicals to the manifold.
  • the umbilical terminates at the ocean floor.
  • the umbilical may transmit chemical inhibitors to the ocean floor and then to equipment of the subsea processing system.
  • the inhibitors are designed and provided in order to ensure that flow from the wells is not affected by the formation of solids in the flow stream such as hydrates, waxes and scale.
  • the system of WO-2006/031335-A1 uses an umbilical, which renders the system relatively expensive.
  • US-2003/008577-A1 discloses a system, wherein pipes such as riser flowlines are provided with one or more additional channels for buoyancy control.
  • the buoyancy of the flowlines can be dynamically controlled by filling the additional channels with a buoyancy control material, to provide positive or negative buoyancy.
  • the additional channels may be formed by pipes which are externally attached to the risers or by an additional annulus within the risers, which will however increase the costs of the risers .
  • WO-95/22678-Al discloses a riser assembly, comprising a pipe in a planar cyclically undulating configuration. Tension members extend in the longitudinal direction of the riser assembly and are secured to the pipe at spaced intervals so that they absorb tension forces.
  • US-5875848 discloses a system and a method for managing the weight of an underwater riser assembly.
  • the system includes a blocking mechanism for selectively blocking the bottom end of the riser assembly so that heavy drilling mud is retained within the riser assembly.
  • Upper and lower flooding valves are located in the riser assembly above the blocking mechanism and are spaced apart. The valves can be opened so that an annulus in the riser assembly is in fluid communication with surrounding water. Drilling fluid can be introduced to or removed from the annulus during deployment or disconnect conditions using the upper and lower flooding valves.
  • the lower flooding valve is mounted immediately above the closing mechanism.
  • the upper flooding valve is preferably arranged at approximately one-third of the distance between the ocean floor and the surface of the water.
  • the system of US-5875848 is therefore directed at filling the lower end of the annulus of the riser.
  • the present invention seeks to address the problem of riser buckling during severe heave and/or pitch of the floating structure caused by extreme weather conditions.
  • the present invention provides a method of protecting one or more flexible risers in a sub sea environment, comprising at least the steps of:
  • m mass of the flexible riser, including internal fluid
  • g gravity
  • C d normal drag coefficient
  • D drag is the drag diameter
  • p is the water density
  • V Term is the terminal velocity.
  • a flexible riser When a flexible riser is constrained, such that it is attached at a first end to a floating structure on the surface of the water and at a second end on the sea bed, vertical motion of the flexible riser can result from the heave and/or pitch of the floating structure in response to the water motion on the surface.
  • Damage to flexible risers may occur when the terminal velocity of the flexible riser in the sea water is exceeded by the velocity of the first end of the riser where it is connected to the floating structure. This point of connection is also called the hang-off point.
  • the hang-off velocity When the downward velocity of the flexible riser at the hang-off point due to the heave and/or pitch of the floating vessel (the "hang-off velocity") is greater than the terminal velocity of the flexible riser in the water, the riser will come under compression. Such compressive stresses can lead to buckling and permanent damage to the flexible riser. Compressive stress in the flexible riser can also be viewed as negative riser tension.
  • the possibility of buckling can occur when the ratio of the downward hang-off velocity of the riser to the terminal velocity of the riser in the water exceeds 1.
  • Compression modelling therefore allows the prediction of potential riser buckling for particular structure heave and/or pitch, riser type and the distance of the hang-off point from the centre of motion of the structure .
  • a protection fluid which has a higher density than the riser fluid, the apparent weight of the riser is increased. This leads to an increase in the terminal velocity of the riser in water.
  • higher hangoff velocities can be accommodated without riser buckling.
  • the flexible risers carrying protection fluid can therefore survive more severe weather conditions, and in particular increased wave heights, compared to those which have not been at least partly filled with protection fluid.
  • the floating structure comprises a protection fluid storage tank, said protection fluid storage tank comprising an outlet for a protection fluid stream; and each of said flexible risers has a first end connected to said floating structure, said first end in direct fluid communication with a first end connection for a riser fluid stream and an inlet for the protection fluid stream in fluid communication with the outlet of the protection fluid storage tank, said inlet being separate from said first end connection.
  • step (b) includes closing the second end; and step (c) includes introducing the protection fluid stream into the one or more risers via the inlet to replace at least a portion of the riser fluid; and removing the replaced portion of the riser fluid via the first end connection for the riser fluid stream.
  • the method of the present invention uses risers provided with a topside inlet for protection fluid.
  • Topside herein indicates the side of the riser attached to the floating structure.
  • Said inlet is separate from the topside first end connection (inlet or outlet) for riser fluid. The inlet enables rapid filling of the main fluid channel of the riser with the protection fluid, whereas at the same time the riser fluid can be removed via the first end connection.
  • the present invention provides an apparatus for protecting one or more flexible risers in a sub sea environment, said apparatus comprising at least:
  • a floating structure comprising a protection fluid storage tank, said protection fluid storage tank comprising an outlet for a protection fluid stream;
  • each of said flexible risers having a first end connected to said floating structure, said first end in direct fluid communication with a first end connection for a riser fluid stream and an inlet for the protection fluid stream in fluid communication with the outlet of the protection fluid storage tank, said inlet being separate from said first end connection, and each of said flexible risers having a second end on the sea bed, said second end having a second end connection for a riser fluid transfer stream in fluid communication with one or more riser fluid reservoirs.
  • the method and apparatus of the present invention provide a relatively inexpensive means to readily protect risers during adverse weather conditions.
  • the invention obviates an additional umbilical, pipe or annulus .
  • the risers are provided with an inlet for the protection fluid stream to enable rapid replacement of the riser fluid with protection fluid from the topside of the riser.
  • Figure 1 shows a first embodiment of a typical method and apparatus scheme according to the invention.
  • Figure 2 shows a second embodiment of a typical method and apparatus scheme according to the invention.
  • Figure 1 shows a cut-through section of a first method and apparatus 1 for the protection of one or more flexible risers 10, particularly during severe weather conditions.
  • the flexible risers convey a riser fluid between one or more riser fluid reservoirs 250 underneath the sea bed and a floating structure 100 on the sea surface.
  • the risers can be sub sea risers.
  • sub sea is intended to encompass both salt water and fresh water environments, and represents the region between the water surface and the bed of the body of water.
  • the floating structure 100 can be a floating vessel, or an off-shore floating platform.
  • a floating vessel may be any movable or moored vessel, generally at least having a hull, and usually being in the form of a ship such as a 'tanker'.
  • Such floating vessels can be of any dimensions, but are usually elongated. Whilst the dimensions of a floating vessel are not limited at sea, building and maintenance facilities for floating vessels may limit such dimensions.
  • the floating vessel or off-shore floating platform is less than 600m long such as 500m, and a beam of less than 100m, such as 80m, so as to be able to be accommodated in existing ship-building and maintenance facilities.
  • An off-shore floating platform may also be movable, but is generally more-permanently locatable than a floating vessel.
  • the method and apparatus of the invention are for instance advantageous for applications in deep water, such as water depths greater than 200 m, for instance 250 to 500 m, or greater than 1000 m.
  • the riser fluid is a hydrocarbon fluid such as natural gas
  • the one or more riser fluid reservoirs 250 are hydrocarbon fluid reservoirs such as natural gas reservoirs.
  • the hydrocarbon fluid would be conveyed from the hydrocarbon fluid reservoirs 250 under the sea bed 500 to the floating structure 100, where the hydrocarbon fluid can be stored and preferably treated.
  • the floating structure 100 comprises natural gas treatment and/or liquefaction units such that the natural gas can be treated to remove unwanted impurities and cooled to provide liquefied natural gas. This will be discussed in more detail in relation to Figure 2.
  • the method and apparatus disclosed herein can be used for carbon dioxide sequestration .
  • hydrocarbon reservoirs such as natural gas reservoirs may contain carbon dioxide, for instance in contents of 6-10%. This carbon dioxide could be separated in the floating structure from the hydrocarbon fluid, such as natural gas, removed from the reservoir, and then re-injected into the a riser fluid reservoir. 250.
  • the riser fluid reservoir can be any sealed subsurface geological formation such as a hydrocarbon reservoir, a depleted hydrocarbon reservoir, an aquifer or other sealed water containing layer.
  • the riser fluid can comprise carbon dioxide, preferably as a dense phase, such as supercritical carbon dioxide i.e. carbon dioxide having a pressure and temperature above the critical point.
  • the riser fluid comprising carbon dioxide would for instance be conveyed from a separation unit on the floating structure 100 to the one or more depleted hydrocarbon reservoirs 250 under the sea bed 500, where the riser fluid comprising carbon dioxide can be stored.
  • the riser fluid comprising carbon dioxide passed to the riser fluid reservoir 250 can come from any source.
  • the carbon dioxide may be generated at a location different from the floating structure 100, such as an on-shore location, and transferred to the floating structure 100 for sequestration underneath the sea bed.
  • the riser fluid and riser fluid reservoir 250 may be as defined in the previous embodiment.
  • the density of the riser fluid is less than 0.9 g/cm 3 , more preferably less than 0.7 g/cm 3 , still more preferably less than 0.5 g/cm 3 .
  • the floating structure 100 is a floating vessel.
  • the floating vessel is held in position by a plurality of mooring lines 610 which are connected to the floating vessel at a mooring point and maintain the mooring point of the floating vessel in a fixed position.
  • Figure 1 shows a trigonal arrangement of three bundles 620a, 620b, 620c of mooring lines, each bundle comprising four mooring lines 610a, b, c, d.
  • the mooring lines 610 are fastened securely to sea bed 500, for instance using anchor piles.
  • the one or more flexible risers 10 may be provided as free-hanging catenaries or in alternative configurations using buoyancy modules such as lazy wave and lazy S types. Each flexible riser 10 has a first end 20 connected to the floating vessel 100.
  • Figure 1 shows eight flexible risers 10 a-h, arranged in first and second riser bundles of four, connected to the floating vessel 100 at first ends 20 a-h respectively.
  • the flexible risers 10 a-h each have a second end 30 a-h on the sea bed 500.
  • the second ends 30 a-h of the flexible risers 10 a-h need not be in direct contact with the sea bed 500. It is preferred that the second ends 30 a-h of the flexible risers are adapted to be secured to the sea bed 500.
  • the second ends 30 of the flexible risers are connected to two riser base manifolds 300.
  • Second ends 30 a-d of the first riser bundle are connected to first riser base manifold 300a, while second ends 30 e-h of the second riser bundle are connected to second riser base manifold 300b.
  • the riser base manifolds 300 are fastened securely to sea bed 500, for instance using fixed piles. In this way, the first and second ends 20, 30 of the flexible risers 10 are secured to the floating vessel 100 and sea bed 500 respectively.
  • the riser base manifolds 300 provide a fluid connection between the flexible risers 10 and one or more riser fluid transfer streams 210.
  • the one or more riser fluid transfer streams convey the riser fluid between the riser base manifolds 300 and the riser well heads 200.
  • Figure 1 shows first riser base manifold 300a connected to four well heads 200 a-d via an optional well head manifold 220a.
  • Four riser fluid transfer streams 210 a-d connect well heads 200 a-d to the well head manifold 220a.
  • Two further riser fluid transfer streams 210 i, j connect the well head manifold 220a to the riser base manifold 300a.
  • second riser base manifold 300 is connected to four well heads 200 e-h via an optional well head manifold 220b.
  • Four riser fluid transfer streams 210 e-h connect well heads 200 e-h to the well head manifold 220b.
  • Two further riser fluid transfer streams 210 1, m connect the well head manifold 220 b to the riser base manifold 300b.
  • the well heads 200 are in fluid communication with the one or more riser fluid reservoirs 250 which lie beneath the sea bed 500.
  • riser fluid such as a hydrocarbon fluid can be conveyed from one or more hydrocarbon reservoirs 250 to the floating vessel 100.
  • a riser fluid comprising carbon dioxide can be conveyed from the floating vessel 100 to the one or more riser fluid reservoirs for carbon sequestration.
  • the mooring lines 610 are intended to maintain the mooring point of the floating vessel 100 in a fixed position.
  • the mooring lines 610 which may be steel chains, allow a degree of movement such that the mooring point of the floating vessel 100 can move in response to wave motion, such as the heave and/or pitch of the floating vessel 100.
  • riser buckling may occur when the terminal velocity of the riser in the sea water is exceeded by the hang-off velocity of the first end 20 of the riser 10 where it is connected to the floating structure 100.
  • the riser will come under compression. Such compressive stresses can lead to buckling and permanent damage to the flexible riser.
  • the method and apparatus disclosed herein seeks to alleviate the problem of riser damage during severe weather conditions.
  • the riser fluid such as a hydrocarbon fluid or a carbon dioxide comprising fluid
  • the density of the protection fluid is greater than the density of the riser fluid, such that the mass of the fluid in the riser 10 is increased for an equivalent fluid volume.
  • Increasing the mass of the fluid in the riser increases the overall mass of the riser (i.e. the mass of the riser plus fluid contents) .
  • Increasing the overall mass of the riser increases the terminal velocity of the riser in the water.
  • the density of the protection fluid is greater than 0.9 g/cm 3 , more preferably greater than 1.0 g/cm , still more preferably greater than 1.1 g/cm 3 .
  • the greater density of the protection fluid compared to the riser fluid the greater the terminal velocity increase of the flexible riser upon substitution of the riser fluid for the protection fluid.
  • the greater the increase in the terminal velocity of the flexible riser the greater the hang-off velocity which can be withstood without compressing the flexible riser.
  • the difference in density between the protection fluid and the riser fluid is at least 0.2 g/cm 3 , more preferably at least 0.4 g/cm 3 , even more preferably at least 0.6 g/cm 3 .
  • protection fluids are one or more of the group comprising monoethylene glycol and hydrocarbon condensate. These fluids are particularly useful as protection fluids in the case where the riser fluid is a hydrocarbon fluid.
  • the floating vessel 100 can comprise one or more hydrocarbon treatment units, such as a separation unit, for instance a low pressure gas/liquid separator, to provide hydrocarbon condensate from a hydrocarbon riser fluid.
  • the hydrocarbon fluid is preferably in stabilised form.
  • a store of hydrocarbon condensate may be present in the floating vessel, for instance in a condensate storage tank.
  • the store of hydrocarbon condensate can comprise one source of protection fluid.
  • the floating vessel 100 could comprise a hydrate inhibitor storage tank, such as a MEG storage tank.
  • the floating vessel 100 may also comprise a hydrate inhibitor regeneration unit, to separate the hydrate inhibitor from the riser fluid.
  • the store of hydrate inhibitor can comprise one source of protection fluid.
  • a MEG storage tank is provided having a capacity such that 15-20% of the tank capacity of MEG can completely fill all of the flexible risers 10 with protection fluid. In such a case, it is preferred to maintain a minimum content of MEG in the tank of 15-20% to ensure that sufficient MEG is available to provide maximum protection (i.e. completely fill) to each of the flexible risers 10.
  • the one or more flexible risers 10 are filled with protection fluid from the first end connected to the floating structure 100. This allows the protection fluid to be stored on the floating structure 100.
  • a portion of the riser fluid in each of the one or more flexible risers 10 is replaced with the protection fluid.
  • the portion of the riser fluid replaced with the protection fluid is the same in each riser. This is advantageous because the same mass is added to each riser. For identical risers, each riser will thus have the same terminal velocity in the sea water and therefore exhibit similar dynamic behaviour . It is not advisable to replace different portions of the riser fluid with protection fluid in each flexible riser, because different risers will exhibit different dynamic behaviour, which can lead to collisions between adjacent flexible risers in response to movement of the floating structure 100.
  • the method may comprise the further step of:
  • the zone around the floating structure 100 should be of a size sufficient to allow the method disclosed herein to be carried out before the arrival of the adverse weather conditions at the floating structure 100.
  • the zone may be 200 km around the floating structure 100, and more preferably 500 km around the floating structure 100 to allow sufficient time to replace the riser fluid with protection fluid.
  • the adverse weather conditions are evaluated using one or more weather variables.
  • the one or more weather variables include one or both of wind speed and wave height.
  • the predetermined criterion or criteria is indicative or predictive of a situation in which the hangoff velocity of the first end 20 of the flexible riser 10 approaches the terminal velocity of the flexible riser 10 in operation i.e. when filled with riser fluid.
  • the predetermined criterion can be selected from wind speeds in excess of 60 ms "1 .
  • wind speeds in the range of 70-74 ms "1 are indicative of a 10000 year cyclone.
  • the predetermined criterion can be selected from significant wave heights.
  • the predetermined criterion can be 16 m or greater significant wave height.
  • the significant wave height is for instance the wave height which is exceeded by 2/3 of the waves during a storm.
  • the spent protection fluid can be processed by a unit already present for the treatment of the riser fluid.
  • the riser fluid is a hydrocarbon fluid which has been treated with a hydrate inhibitor
  • the spent protection fluid which will be rich in hydrate inhibitor such as MEG, but may also contain a small amount of hydrocarbon fluid not displaced from the flexible riser, can be sent to the hydrate inhibitor treatment unit for processing. This procedure may result in a plug of hydrate inhibitor, such as MEG, requiring processing.
  • FIG. 2 provides a further schematic for the method and apparatus disclosed herein, and in particular shows the connectivity of the first and second ends 20, 30 of the flexible risers 10 to the sea bed 500 and floating structure 100.
  • the numbers of mooring lines 610a, e and flexible risers 10a, 1Oe have been reduced to two each, although any number, such as 4-6 arranged in two or more separate bundles is envisaged.
  • the flexible risers 10a, 1Oe have first ends 20a, 2Oe connected to the floating structure 100, which is shown as vessel in Figure 2.
  • the first ends 20 a, e of the flexible risers are secured to the floating vessel 100 at a turret 150.
  • the turret 150 is connected to the sea bed 500 by the mooring lines 610a, 610b.
  • the floating vessel 100 is provided with one or more bearings allowing the rotation of the vessel around the turret 150.
  • the floating vessel may weather- vane around the earth-fixed turret, such that the vessel may be orientated to present the bow to the direction of the prevailing weather conditions, such as the incoming wave or wind.
  • the turret 150 is provided towards an end of the floating vessel 100, to allow optimal rotation in response to the prevailing weather conditions.
  • processing units 400 such as a natural gas treatment and liquefaction unit, which is discussed in greater detail below, to be placed behind the turret 150 along the deck of the floating vessel .
  • the turret 150 comprises one or more bending stiffeners 160a, b which route the flexible risers 10a, e through one or more I-tubes 170a, b to a hang-off deck 180.
  • the hang-off deck 180 secures the first end 20 a, e of each of the flexible risers 10a, e.
  • the first end 20 a, e of each of the flexible risers 10a, e is in fluid communication with a first end connection 22a, 22e for the first riser fluid stream 40.
  • the first ends 20 a, e can be in communication with the first end connections 22 a, e via a turret piping connection.
  • Each first end connection 22a, 22e for the riser fluid stream 40 is connected to a riser emergency shutdown valve 190a, e.
  • An inlet 24a, 24e for the protection fluid stream 120 which is in fluid communication with the outlet 112 of a protection fluid storage tank 110, is also in fluid communication with the first end 20 a, e of each flexible riser 10 a, e.
  • the protection fluid stream 120 can be passed to each first inlet 22a, g and on to the first ends of the flexible risers 10a, e.
  • the protection fluid can displace at least a portion of the riser fluid in one or more of the flexible risers.
  • the displaced riser fluid which is less dense than the protection fluid, will be forced upwards as the flexible risers 10a, e fill with protection fluid such that the riser fluid can exit the risers at first ends 20 a, e, passing out of first end connection 24a, e, which can be an outlet.
  • the riser fluid can be passed to the processing units 400 as the riser fluid stream 40.
  • each flexible riser 10a, e is on the sea bed 500.
  • Each second end comprises a second end connection 32a, e which is in fluid communication with a riser fluid transfer stream 210a, b, g, h.
  • the riser fluid transfer streams 210a, b, g, h are in fluid communication with one or more riser fluid reservoirs 250.
  • the second end 30a, e of each flexible riser 10a, e is secured to the sea bed 500 by connection to a riser base manifold 300a, b.
  • the riser base manifold 300a, b is rigidly fixed to the sea bed 500.
  • the riser base manifolds 300a, b comprise first manifold connections 302a, b, c, d to the riser fluid transfer streams 210a, b, g, h.
  • Second manifold connections 304a, b are connected to the second end connections 32a, e of the flexible risers 10a, e.
  • the riser fluid transfer streams 210 may be natural gas transfer streams.
  • the one or more riser fluid reservoirs 250 can be natural gas reservoirs.
  • the riser fluid stream 40 can be a natural gas stream. In this case, the natural gas reservoirs 250 may be connected to the riser fluid transfer streams 210 via well heads 200a, b, g, h.
  • Figure 2 shows a natural gas treatment and liquefaction unit 400 on the floating structure 100.
  • This unit can be used for the pre-treating and cooling of the riser fluid when this is natural gas.
  • the arrangement discussed below is exemplary only and is not limited to the combination of the units described. Other, alternative line-ups will be known to the skilled person.
  • a natural gas stream 40 is comprised substantially of methane.
  • the natural gas stream comprises at least 50 mol% methane, more preferably at least 80 mol% methane.
  • natural gas may contain varying amounts of hydrocarbons heavier than methane such as in particular ethane, propane and the butanes, and possibly lesser amounts of pentanes and aromatic hydrocarbons. The composition varies depending upon the type and location of the gas.
  • the hydrocarbons heavier than methane are removed as far as efficiently possible from the natural gas stream prior to any significant cooling for several reasons, such as having different freezing or liquefaction temperatures that may cause them to block parts of a methane liquefaction plant.
  • the natural gas stream can first undergo acid gas removal by passing through an acid gas removal (AGR) unit or system, which may be a separate or dedicated unit, or integrated with one or more other units or apparatus.
  • AGR acid gas removal
  • the AGR system provides a process for the removal of carbon dioxide and hydrogen sulphide and/or COS in a manner known in the art, for example one or more of the methods described in WO 03/057348 Al.
  • the AGR system provides a treated natural gas stream.
  • the treated natural gas stream can then pass into a first cooling stage which may comprise part of a cooling system and/or liquefaction system.
  • the first cooling stage may comprise one or more heat exchangers in parallel and/or series, and is able to reduce the temperature of the treated natural gas stream, preferably below 0 0 C, and more preferably in the range -10 0 C to -70 0 C, and provide a cooled natural gas stream.
  • the first cooling stage may have any configuration known in the art, and generally includes one or more refrigerant circuits passing one or more refrigerants to provide cold or cold energy to the treated hydrocarbon stream.
  • An example refrigerant circuit is a propane refrigerant circuit known in the art.
  • a first refrigerant circuit can pass through the first cooling stage, from which the refrigerant stream, expanded after providing its cooling to treated hydrocarbon stream, passes into a first stage compressor for recompression.
  • the first stage compressor may comprise one or more compressors in series or parallel in a manner known in the art. Compression of the refrigerant usually increases the refrigerant temperature, such that it is commonly cooled by one or more heat exchangers downstream of the first stage compressor.
  • the downstream heat exchanger (s) may comprise one or more ambient water and/or air coolers known in the art.
  • the cooled natural gas stream can pass through a second cooling stage, again comprising one or more heat exchangers in parallel and/or series and designed to further cool and/or liquefy the cooled natural gas stream, to provide a further cooled natural gas stream, which is preferably a liquefied natural gas stream.
  • the further cooled natural gas stream can be passed into storage such as to one or more storage tanks, or be passed through a further pipeline or conduit to one or more storage tanks located elsewhere, such as on a land- based facility or other floating vessel.
  • the other floating vessel may be an LNG carrier.
  • the second cooling stage may involve one or more refrigerant circuits having a refrigerant adapted to provide the further cooling to the cooled natural gas stream.
  • An example refrigerant circuit is a mixed refrigerant, and the second cooling stage could reduce the temperature of the cooled natural gas stream to below -100 0 C, preferably below -150 0 C.
  • expanded refrigerant from the second cooling stage can pass through a second stage compressor (which may comprise one or more compressors in parallel and/or series), to provide a compressed stream which is usually then cooled by one or more downstream heat exchangers, for example ambient water and/or air coolers.
  • the refrigerant stream in the second refrigerant circuit can then pass through the first cooling stage in a manner known in the art, optionally with a first passage through the second cooling stage for further cooling, prior to reaching a valve for expansion and reuse in the second cooling stage in a manner known in the art .
  • One or more of the AGR system and the first and second cooling stages may include one or more generators such as gas turbines, to drive one or more devices, units or separators therein, such as, by way of example only, the first and second compressors.
  • generators such as gas turbines

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Physics & Mathematics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)
  • Rigid Pipes And Flexible Pipes (AREA)
  • Filling Or Discharging Of Gas Storage Vessels (AREA)
  • Pipeline Systems (AREA)

Abstract

La présente invention concerne un procédé pour protéger une ou plusieurs colonnes montantes flexibles qui peuvent transporter un fluide, par exemple un fluide de production d'hydrocarbure de type gaz naturel, à destination ou en provenance d'une structure flottante et un appareil associé. Ledit procédé comprend au moins les étapes qui consistent : (a) à utiliser une structure flottante (100), une ou plusieurs colonnes montantes flexibles (10), chaque colonne montante flexible transportant un fluide et possédant une première extrémité (20) reliée à la structure flottante (100) et une deuxième extrémité (30) sur le fond marin (500) et en communication fluidique avec un ou plusieurs réservoirs (250) de fluide; (b) à fermer la communication fluidique entre la ou les colonnes montantes flexibles (10) et le ou les réservoirs (250) de fluide; (c) à remplacer au moins une partie du fluide dans une ou plusieurs colonnes montantes flexibles (10) par un fluide de protection, la densité dudit fluide de protection étant supérieure à celle du fluide de la colonne montante.
EP10719358.3A 2009-05-20 2010-05-18 Procédé de protection d'une colonne montante flexible et appareil correspondant Not-in-force EP2432964B1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
EP10719358.3A EP2432964B1 (fr) 2009-05-20 2010-05-18 Procédé de protection d'une colonne montante flexible et appareil correspondant
CY20141100592T CY1115428T1 (el) 2009-05-20 2014-08-04 Μεθοδος προστασιας ευκαμπτου κατακορυφου σωληνα και εξοπλισμος για αυτην

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
EP09160763A EP2253796A1 (fr) 2009-05-20 2009-05-20 Procédé de protection d'une colonne montante flexible et appareil correspondant
EP10719358.3A EP2432964B1 (fr) 2009-05-20 2010-05-18 Procédé de protection d'une colonne montante flexible et appareil correspondant
PCT/EP2010/056768 WO2010133564A2 (fr) 2009-05-20 2010-05-18 Procédé de protection d'une colonne montante flexible et appareil associé

Publications (2)

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EP2432964A2 true EP2432964A2 (fr) 2012-03-28
EP2432964B1 EP2432964B1 (fr) 2014-05-21

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EP09160763A Withdrawn EP2253796A1 (fr) 2009-05-20 2009-05-20 Procédé de protection d'une colonne montante flexible et appareil correspondant
EP10719358.3A Not-in-force EP2432964B1 (fr) 2009-05-20 2010-05-18 Procédé de protection d'une colonne montante flexible et appareil correspondant

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KR (1) KR101679178B1 (fr)
CN (1) CN102428244B (fr)
AP (1) AP3886A (fr)
AU (1) AU2010251212B2 (fr)
BR (1) BRPI1012862B1 (fr)
CY (1) CY1115428T1 (fr)
WO (1) WO2010133564A2 (fr)

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EP3507452A4 (fr) * 2016-09-02 2020-04-01 FMC Technologies, Inc. Architecture améliorée de champ sous-marin

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GB2495287B (en) * 2011-10-03 2015-03-11 Marine Resources Exploration Internat Bv A riser system for transporting a slurry from a position adjacent to the seabed to a position adjacent to the sea surface
CN103453318B (zh) * 2013-09-04 2015-11-04 中国海洋石油总公司 海上平台贫乙二醇的储存及输送方法
JP2017505096A (ja) * 2014-01-15 2017-02-09 ブライト エナジー ストレージ テクノロジーズ，エルエルピーＢｒｉｇｈｔ Ｅｎｅｒｇｙ Ｓｔｏｒａｇｅ Ｔｅｃｈｎｏｌｏｇｉｅｓ，ＬＬＰ 圧縮流体を使用する水中エネルギ貯蔵
WO2023214218A1 (fr) * 2022-05-04 2023-11-09 Storeco2 Uk Limited Navire marin de transport et de séquestration de dioxyde de carbone

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Also Published As

Publication number Publication date
WO2010133564A3 (fr) 2011-03-31
AU2010251212B2 (en) 2013-10-03
AP3886A (en) 2016-11-07
BRPI1012862B1 (pt) 2019-11-26
AU2010251212A1 (en) 2011-11-17
EP2432964B1 (fr) 2014-05-21
CN102428244A (zh) 2012-04-25
AP2011005957A0 (en) 2011-10-31
KR101679178B1 (ko) 2016-11-24
EP2253796A1 (fr) 2010-11-24
BRPI1012862A2 (pt) 2018-02-27
CY1115428T1 (el) 2017-01-04
KR20120030372A (ko) 2012-03-28
WO2010133564A2 (fr) 2010-11-25
CN102428244B (zh) 2014-10-22

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