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WO2003086976A2 - Installation de production pour puits sous-marin - Google Patents

Installation de production pour puits sous-marin Download PDF

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Publication number
WO2003086976A2
WO2003086976A2 PCT/US2003/010617 US0310617W WO03086976A2 WO 2003086976 A2 WO2003086976 A2 WO 2003086976A2 US 0310617 W US0310617 W US 0310617W WO 03086976 A2 WO03086976 A2 WO 03086976A2
Authority
WO
WIPO (PCT)
Prior art keywords
subsea
water
hydrocarbons
separator
vessel
Prior art date
Application number
PCT/US2003/010617
Other languages
English (en)
Other versions
WO2003086976A3 (fr
Inventor
Clay F. Anderson
John Allen
Original Assignee
Abb Offshore Systems, Inc.
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 Abb Offshore Systems, Inc. filed Critical Abb Offshore Systems, Inc.
Priority to GB0423790A priority Critical patent/GB2404684B/en
Priority to AU2003226295A priority patent/AU2003226295A1/en
Publication of WO2003086976A2 publication Critical patent/WO2003086976A2/fr
Publication of WO2003086976A3 publication Critical patent/WO2003086976A3/fr
Priority to NO20044832A priority patent/NO20044832L/no

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
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/40—Separation associated with re-injection of separated materials
    • 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
    • E21B43/017—Production satellite stations, i.e. underwater installations comprising a plurality of satellite well heads connected to a central station
    • 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
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/36—Underwater separating arrangements

Definitions

  • This invention relates in general to offshore drilling and production equipment, and in particular for treating produced water from a subsea well.
  • Well fluid produced from a subsea well typically includes liquid hydrocarbons or oil, gaseous hydrocarbons or natural gas, and water. Transporting water from a subsea well decreases the transportation efficiency and increases the reservoir energy requirements and size of the pump (if used) required to pump the well fluid from the subsea well to a processing facility or to a collection manifold. Typically the processing facility is either on a platform or on land. Further, water in the hydrocarbon stream increases the risk of hydrates and the demand for chemicals to control hydrates.”
  • a subsea separator is placed adjacent a subsea well that separates the produced water from the well fluid.
  • the produced water which typically includes some residual gaseous and liquid hydrocarbon, is then reinjected into another subsea well.
  • the hydrocarbons exiting the subsea separator are pumped to a fully manned processing facility on a platform. After processing on the platform, the hydrocarbon is conveyed to a transport means.
  • the water with residual hydrocarbons must be reinjected into a subsea well because it is too contaminated to be released or dumped to sea.
  • rei ⁇ jecting water into a subsea well can be expensive and is not always feasible; subject to the availability of a suitable subsea reservoir.
  • a method and system for separating and treating water produced from a subsea well includes separation of the water from the well fluid at a subsea separator and further separation of the water from residual hydrocarbons on a vessel at the sea surface.
  • the vessel is preferably an unmanned, or not normally manned buoy.
  • the well fluid that contains oil, natural gas, and water is conveyed to the subsea separator where the water is removed and the oil and gas, or produced hydrocarbons, are conveyed to a subsea gathering facility for collection and processing at a facility away from the subsea well.
  • the water removed from the subsea separator, or "dirty water” typically has residual gaseous and sometimes liquid hydrocarbons.
  • the dirty water is pumped to the floating vessel at the surface where the water enters a surface separator. There can be a plurality of individual separators for removing the residual hydrocarbons from the dirty water.
  • the water exiting from the surface separator, or treated water is sufficiently clean to be dumped to the sea.
  • the treated water can be combined with sea water that is being injected into another subsea well during well flooding operations.
  • Any liquid residual hydrocarbons, or oil, from the surface separator can be pumped back subsea for collection and processing with the other produced hydrocarbons.
  • the gaseous residual hydrocarbons, or natural gas can also be transported subsea for further collection and processing with the other produced hydrocarbons.
  • the gaseous residual hydrocarbons can be compressed in order to convey the gaseous residual hydrocarbons subsea, or the gaseous residual hydrocarbons can be mixed with sea water to form a hydrate slurry that is capable of being pumped subsea.
  • the gaseous residual hydrocarbons at the surface vessel can be used as a fuel for gas powered equipment on the vessel or buoy.
  • the gas powered equipment can be used to drive various rotating machinery and generators for providing electricity to the vessel or buoy.
  • Gaseous hydrocarbons from the subsea separator can be pumped with the dirty water or separately to the vessel if more gaseous hydrocarbons are needed to fuel the gas powered equipment.
  • Figure 1 is a perspective view of a water treatment system constructed in accordance with the present invention.
  • Figure 2 is a schematic diagram of a portion the water treatment system of Figure 1 that is located on the vessel shown in Figure 1.
  • Figure 3 is a schematic diagram of an alternative embodiment of the water treatment system of Figure 1.
  • Figure 4 is a perspective view of alternative embodiment of the water treatment system of Figure 3.
  • Figure 5 is a schematic diagram of an alternative embodiment of the portion of the water treatment system of Figure 2.
  • Figure 6 is a perspective view of an alternative embodiment of the water treatment system of Figure 1.
  • a floating vessel or buoy 11 for subsea wells connects to one or more subsea wellheads 13 of subsea wells by risers 15 and 17.
  • Riser 15 is an optional riser capable of providing a passageway for intervention, communication, and control of the subsea well.
  • buoy 11 is a floating production buoy, but those skilled in the relevant art will readily appreciate that buoy 11 could also be a tanker.
  • Riser 17 is an optionally insulated and heated riser for the transportation of produced water from a subsea separator 19 to floating support buoy 11, and for the transportation of oil and gas from floating support buoy 11 to a production flow line 21 that runs along the ocean floor 23 to a production platform (not shown). Electricity for heating riser 17 is optionally generated by burning gas from subsea well that is conveyed to buoy 11 by riser 17.
  • Riser 17 has at least two separate flow lines 17a and 17b.
  • Subsea separator 19 may be a free-water knockout type, which could be a vertical vessel standing upright, or a horizontal vessel lying on its side.
  • subsea separator 19 can be a three-phase separator to separate water, liquid hydrocarbons, and gaseous hydrocarbons from well fluid conveyed from subsea wellhead 13.
  • the water that is separated in subsea separator 19 typically still has gaseous and possibly liquid residual hydrocarbons.
  • the water with gaseous and possibly liquid residual hydrocarbons is "dirty water” or "produced water” that is not acceptable to be dumped into the sea without further treatment.
  • the dirty water that is separated in subsea separator 19 is the produced water that is pumped in riser 17, typically up of flow line 17a, to floating support buoy 11 for treatment.
  • the liquid and gaseous hydrocarbons from subsea separator 19 are transported through a production flow line 21 for transportation to a production platform (not shown).
  • the liquid and gaseous hydrocarbons from subsea separator 19 are communicated from subsea separator to a collector or collection manifold 67, before being pumped through production flow line 21 to a production platform or production facility.
  • Collection manifold 67 can receive liquid and gaseous hydrocarbons from a cluster or a plurality of subsea wells associated with an oil field.
  • the size of a pump (not shown) at collection manifold 67 can be reduced because the pump does not have to pump well fluid containing water to the production platform.
  • the produced water is treated on buoy 11 in order to separate the remaining oil and gas, or liquid and gaseous residual hydrocarbons, from the dirty water.
  • the treated water can be discharged into the sea once the dirty or produced water is purified to the desired level.
  • a variety of processing systems may be used to purify the water.
  • Figure 2 is illustrative of the one system or method of treating the dirty water on buoy 11.
  • a produced water intake 25 receives the produced water coming from riser flow line 17a through riser 17 from subsea separator 19.
  • Water intake 25 leads to a first separator or degasser 27, which has a gas outlet flow line 29 and a liquid outlet flow line 31.
  • Degasser 27 may be a static gravity separator.
  • Liquid flow line 31 leads to a second separator 33, which has an oil outlet line 35 and a water outlet line 37.
  • second separator is a liquid separator for separating water from liquid residual hydrocarbons.
  • second separator 33 is a hydrocyclone, which separates oil and water using a vortex principle.
  • a hydrocyclone is a preferable apparatus for second separator 33 because there are no moving parts, and therefore requires minimal maintenance.
  • an automatic oil reject backflushing procedure may be provided for the hydrocyclone 33 unit in order to avoid build up of solids in the oil reject ports (not shown), which have a typical diameter of 2.0 mm.
  • a desanding system upstream of the hydrocyclone 33, in outlet line 31, may be included to avoid erosion settling in the inlet chamber of hydrocyclone 33 and secure high availability for the unit.
  • Hydrocyclone systems are simple and have no moving parts. They have high reliability if operated correctly and if fluids are suitable. They have minimal maintenance requirements.
  • hydrocyclones there are disadvantages for using hydrocyclones on the buoy 11. With separatorl9 at sea floor 23, the temperature of the oily water will be lower than what is normally the case. This makes it more difficult to reach the oil in water output specification. Another general disadvantage of hydrocyclone units is the relatively high pressure drop.
  • CODEFLO Compact Degassing and Flotation system
  • a patent on the CODEFLO system itself is pending, its application number is PCT/NOOO/00243, which we are incorporating by reference.
  • the CODEFLO system consists of the following main process steps: the degasser process; coagulation step (two steps if high turndown is required); and, the flotation process. Each of these main process steps are described in more detail in PCT/NOOO/00243.
  • the CODEFLO system in the second embodiment has the advantages of small size, low weight, low pressure drop, high separation efficiency and ease of operation. Disadvantages include the consumption of chemicals and related potential problems.
  • the produced water will be treated to local discharge standards or better.
  • This produced water stream would be monitored with an automated water quality meter (not shown).
  • These meters are typically automated optical sensors, which can be configured to give readings back to a central SCAD A system and interrogated remotely (a requirement for unmanned buoy applications.) These units are set up to be relatively maintenance free, self-diagnosing and self flushing/cleaning with remote diagnostics.
  • oil outlet line 35 from second separator 33 connects to a third separator 39, which is preferably another degasser having a gas outlet line 41 and an oil outlet line 43.
  • Water outlet line 37 leads to a fourth separator 45, which is also another degasser having a gas outlet line 47 and a water outlet line 49.
  • a first compressor 51 has an intake connected to gas outlet line 47.
  • Compressor 51 has a compressed gas outlet line 53 that joins the intake of a second compressor 55, which has an outlet line 57.
  • An air cooler 59 with a gas outlet flow line 61 has an inlet that receives compressed gaseous hydrocarbons from outlet line 57 of compressor 55.
  • Second degasser oil outlet line 43 connects to a single phase oil pump 63 with an oil outlet flow line 65.
  • Oil and gas outlet lines 61 and 65 connect to riser 17 to pump the oil and gas back down to a subsea manifold 67 and production flow line 21.
  • riser 17 carrying the water from subsea separator to the processing equipment on floating support buoy 11 may be insulated and/or heated so that the water temperature remains above a desired temperature. Insulating and, if necessary, heating flow line 17a of riser 17 can reduce the formation of hydrates in the water and residual hydrocarbons. Hydrates forming in flow line 17a reduce the flow rate of the water and increase the required head required to pump the water to buoy 11 at the surface. Reducing the formation of hydrates in flow line 17a helps reduce the problems and associated maintenance associated transported water with residual hydrocarbons from sea floor 23 to buoy 11 at the surface. If necessary, heating elements may also be located in riser 17 to ensure the temperature of the produced water stays above a desired minimum temperature.
  • first surface separator 27 which is preferably a degasser, for further removal of gas.
  • first surface separator 27 is preferably a degasser
  • second separator 33 is a hydrocyclone that uses centrifugal forces to separate the heavier water from the lighter oil or liquid residual hydrocarbons.
  • Third surface separator 39 can be a vertically oriented vessel that allows any remaining gas to separate from the oil. The gas discharges from third separator 39 into gas outlet line 41.
  • the remaining oil exits third separator 39 into oil outlet line 43, which transports the liquid residual hydrocarbons from the dirty water to pump 63.
  • Pump 63 then pumps the oil into pump outlet line 65, which will take the oil back down riser 17, preferably through flow line 17b, to subsea collection manifold or collector 67. From the subsea gathering manifold 67, the oil enters production flow line 21 to be taken to a processing platform or facility.
  • Water outlet line 37 takes the water and any remaining gaseous residual hydrocarbons from second separator 33 to fourth surface separator 45.
  • Fourth surface separator 45 is preferably another degasser and can be a vertical vessel that allows any remaining gas in the water stream to separate.
  • Fourth separator 45 discharges the remaimng water into water outlet line 49. Water in water line 49 is fully treated. In the embodiment shown in Figure 2, the treated water is dumped to sea from water line 49.
  • the treated or processed water is combined with sea water that is then pumped down an injection riser 15' to a subsea wellhead 13' located on a subsea well during water flood operations.
  • Subsea water injection wells have water injected into the well to help production of hydrocarbons at other wells that are producing from the same field.
  • fourth surface separator 45 discharges the remaining gas or gaseous residual hydrocarbons into gas outlet line 47.
  • the gaseous hydrocarbons from fourth surface separator flows through gas outlet line 47 and joins the gas in gas outlet line 41 coming from third surface separator 39.
  • the gases from surface separators 39 and 45 then enter first compressor 51.
  • First compressor 51 increases the pressure of the gas so that it is substantially equal to the gas pressure of the gas in gas outlet line 29 coming from first surface separator 27.
  • Gas from outlet lines 41 and 47 is compressed in first compressor 51 and exits first compressor 51 into gas outlet line 53, which transports the compressed gas to mix with the gas in gas outlet line 29.
  • Second compressor 55 increases the gas pressure in order to convey the gaseous residual hydrocarbons back down riser 17, either in flow line 17b or a separate additional flow line 17c, to subsea collection manifold 67.
  • Flow lines 17b and 17c are shown in Figure 1 as connecting to collection manifold 67.
  • flow lines 17b and 17c can also be connected to the intake of subsea separator 19.
  • the liquid and gaseous hydrocarbons that were removed from the dirty water at the surface are then conveyed into subsea separator 19 before being transported to collection manifold 67.
  • flow lines 17b and 17c could also be connected to a produced hydrocarbons flow line that transports hydrocarbons from subsea separator 19 when there is not a collection manifold 67.
  • the gas may be cooled after compression.
  • Second compressor 55 discharges the high pressure gas into gas outlet line 57, which takes the compressed gas to air cooler 59 to cool the exiting gas.
  • the gas coming out of air cooler 59 enters gas outlet line 61.
  • the gas in outlet line 61 is now cool enough and pressurized enough for conveyance down riser 17 to subsea gathering manifold 67 or back into subsea separator 19.
  • air is the preferred medium for cooling the gas after compression over sea water because scaling problems occur in sea water at high temperature.
  • the embodiment illustrated in Figure 3 is an alternative embodiment that uses the gaseous residual hydrocarbons to power buoy or vessel 11 rather than conveying the gas to subsea collector 67.
  • Gas from degasser surface separators 27', 39', 45' are in fluid communication with a gas powered apparatus 99 to provide mechanical power to consumer 101.
  • gas powered apparatuses 99 which are also typically either gas powered engines or gas turbines.
  • gas powered equipment 99 drives a generator for supplying electrical power to the buoy 11, or other pieces of rotating equipment like pumps or compressors.
  • First and second compressors 51', 55' and cooler 59' are shown in Figure 3, but may be modified, used, or not used to meet the inlet conditions desired for gas fuel entering particular gas powered apparatuses 99.
  • Figure 4 illustrates an optional system for supplying additional fuel to gas powered apparatuses 99.
  • an additional flow line 103 extends from a gas outlet of subsea separator 19' to flow line 17a'.
  • Flow line 103 preferably has a one-way, remote actuated valve 105 for regulating flow between riser flow line 17a' and the gas outlet of subsea separator 19'.
  • Flow line 103 transports a portion of the gaseous hydrocarbons from subsea separator 19' to flow line 17a'.
  • valve 105 is opened so that more gaseous hydrocarbons are conveyed up riser 17a' with the dirty water to buoy 11.
  • valve 105 is closed so that the gaseous hydrocarbons exit subsea separator 19', and are conveyed to subsea collector 67' for transportation to the production facility or platform.
  • Figure 5 shows another alternative embodiment for the treatment of the gaseous residual hydrocarbons at the buoy. Unlike the embodiments discussed above in Figures 1-4, there is no second compressor 55 and aftercooler 59.
  • the gaseous residual hydrocarbons from separators 27", 39", 45" combine with sea water from a sea water intake 107 on buoy 11. Adding sea water causes the formation of a hydrate slurry from the gaseous residual hydrocarbons and the sea water.
  • a hydrate slurry is made up of flowable hydrates of relatively small amounts of gas and the injection water. This process is described in detail in a Norwegian patent application on hydrate slurry injection, Norwegian Nr. 2000-4337.
  • the hydrate slurry process is described in detail in the above-referenced application, but can be characterized as the combination of water and the produced natural gas to make a hydrate slurry which is pumpable.
  • compressor 55 and aftercooler 59 Figures 1-4
  • the hydrate slurry can feed into either an additional pump 109, which pumps the hydrate slurry into outlet line 65" that feeds into riser flow line 17b from communication to subsea collector 67.
  • the hydrate slurry could flow directly into existing pump 63" that is pumping liquid residual hydrocarbons to subsea collector 67.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Physical Water Treatments (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

La présente invention concerne un procédé et un système permettant de séparer et traiter l'eau produite depuis un puits sous-marin. Ce procédé permet en l'occurrence de séparer l'eau au fond, puis de séparer sur le navire de surface l'eau des hydrocarbures résiduels. L'eau traitée en surface peut être rejetée à la mer ou injectée dans d'autres puits sous-marins. Les hydrocarbures séparés sur le navire de surface peuvent être renvoyés au fond en vue d'un transport vers une installation de traitement, en même temps que les hydrocarbures provenant du séparateur au fond. De la même façon, les hydrocarbures résiduels du séparateur de surface peuvent servir pour alimenter des équipements fonctionnant au gaz utilisés pour animer d'autres équipements, ou pour produire de l'électricité destinée au navire.
PCT/US2003/010617 2002-04-08 2003-04-08 Installation de production pour puits sous-marin WO2003086976A2 (fr)

Priority Applications (3)

Application Number Priority Date Filing Date Title
GB0423790A GB2404684B (en) 2002-04-08 2003-04-08 Subsea well production facility
AU2003226295A AU2003226295A1 (en) 2002-04-08 2003-04-08 Subsea well production facility
NO20044832A NO20044832L (no) 2002-04-08 2004-11-05 Fremgangsmate og behandlingssystem for produksjon av hydrokarboner fra et havbunnsbronnanlegg.

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US37121702P 2002-04-08 2002-04-08
US60/371,217 2002-04-08

Publications (2)

Publication Number Publication Date
WO2003086976A2 true WO2003086976A2 (fr) 2003-10-23
WO2003086976A3 WO2003086976A3 (fr) 2004-07-15

Family

ID=29250658

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2003/010617 WO2003086976A2 (fr) 2002-04-08 2003-04-08 Installation de production pour puits sous-marin

Country Status (4)

Country Link
AU (1) AU2003226295A1 (fr)
GB (1) GB2404684B (fr)
NO (1) NO20044832L (fr)
WO (1) WO2003086976A2 (fr)

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2008051087A1 (fr) 2006-10-27 2008-05-02 Statoilhydro Asa Système de traitement sous-marin
WO2013025686A1 (fr) * 2011-08-17 2013-02-21 Chevron U.S.A. Inc. Système, appareil et procédé pour exploiter un puits
WO2013124338A3 (fr) * 2012-02-23 2014-04-10 Fmc Kongsberg Subsea As Procédé et système pour acheminer un gaz combustible vers une installation de surface
US9909402B2 (en) 2011-08-17 2018-03-06 Chevron U.S.A. Inc. System, apparatus and method for producing a well
NO20180573A1 (en) * 2018-04-24 2019-10-25 Statoil Petroleum As System and method for offshore hydrocarbon Processing
GB2578148A (en) * 2018-10-18 2020-04-22 Equinor Energy As Optimized water quality injection strategy for reservoir pressure support
GB2586204A (en) * 2019-06-07 2021-02-17 Equinor Energy As Controlling the temperature of injection water for reservoir pressure support
EP4067616A1 (fr) * 2021-03-29 2022-10-05 Horisont Energi AS Système d'injection de carburant et procédés associés

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9638019B2 (en) * 2012-02-23 2017-05-02 Fmc Kongsberg Subsea As Offshore processing method and system

Family Cites Families (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3261398A (en) * 1963-09-12 1966-07-19 Shell Oil Co Apparatus for producing underwater oil fields
US3590919A (en) * 1969-09-08 1971-07-06 Mobil Oil Corp Subsea production system
US6068053A (en) * 1996-11-07 2000-05-30 Baker Hughes, Ltd. Fluid separation and reinjection systems

Cited By (22)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2008051087A1 (fr) 2006-10-27 2008-05-02 Statoilhydro Asa Système de traitement sous-marin
EP2087201A4 (fr) * 2006-10-27 2015-07-22 Statoil Petroleum As Système de traitement sous-marin
US9435186B2 (en) 2006-10-27 2016-09-06 Statoil Petroleum As Sub sea processing system
DK178832B1 (da) * 2006-10-27 2017-03-06 Statoil Petroleum As Undersøisk behandlingssystem
WO2013025686A1 (fr) * 2011-08-17 2013-02-21 Chevron U.S.A. Inc. Système, appareil et procédé pour exploiter un puits
US9909402B2 (en) 2011-08-17 2018-03-06 Chevron U.S.A. Inc. System, apparatus and method for producing a well
WO2013124338A3 (fr) * 2012-02-23 2014-04-10 Fmc Kongsberg Subsea As Procédé et système pour acheminer un gaz combustible vers une installation de surface
GB2588022B (en) * 2018-04-24 2022-06-15 Equinor Energy As System and method for offshore hydrocarbon processing
NO346560B1 (en) * 2018-04-24 2022-10-03 Equinor Energy As System and method for offshore hydrocarbon Processing
WO2019209119A1 (fr) * 2018-04-24 2019-10-31 Equinor Energy As Système et procédé de production et de stockage d'hydrocarbures en mer
US11549352B2 (en) 2018-04-24 2023-01-10 Equinor Energy As System and method for offshore hydrocarbon production and storage
WO2019209118A1 (fr) * 2018-04-24 2019-10-31 Equinor Energy As Système et procédé pour le traitement d'hydrocarbures en mer
GB2588022A (en) * 2018-04-24 2021-04-14 Equinor Energy As System and method for offshore hydrocarbon processing
GB2588312A (en) * 2018-04-24 2021-04-21 Equinor Energy As System and method for offshore hydrocarbon production and storage
US11339639B2 (en) 2018-04-24 2022-05-24 Equinor Energy As System and method for offshore hydrocarbon processing
NO20180573A1 (en) * 2018-04-24 2019-10-25 Statoil Petroleum As System and method for offshore hydrocarbon Processing
GB2588312B (en) * 2018-04-24 2022-08-03 Equinor Energy As System and method for offshore hydrocarbon production and storage
GB2578148A (en) * 2018-10-18 2020-04-22 Equinor Energy As Optimized water quality injection strategy for reservoir pressure support
GB2586204A (en) * 2019-06-07 2021-02-17 Equinor Energy As Controlling the temperature of injection water for reservoir pressure support
EP4067616A1 (fr) * 2021-03-29 2022-10-05 Horisont Energi AS Système d'injection de carburant et procédés associés
US12312893B2 (en) 2021-03-29 2025-05-27 Horisont Energi As Methods for installing risers in a fluid injection system
US12312892B2 (en) 2021-03-29 2025-05-27 Horisont Energi As Fluid injection system and related methods

Also Published As

Publication number Publication date
AU2003226295A8 (en) 2003-10-27
GB2404684A (en) 2005-02-09
GB0423790D0 (en) 2004-12-01
WO2003086976A3 (fr) 2004-07-15
GB2404684B (en) 2005-10-26
NO20044832L (no) 2004-11-05
AU2003226295A1 (en) 2003-10-27

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