WO2005045306A1 - Structure de stockage de gaz naturel liquefie comprenant des deflecteurs de vagues - Google Patents

Structure de stockage de gaz naturel liquefie comprenant des deflecteurs de vagues Download PDF

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Publication number
WO2005045306A1
WO2005045306A1 PCT/US2004/036000 US2004036000W WO2005045306A1 WO 2005045306 A1 WO2005045306 A1 WO 2005045306A1 US 2004036000 W US2004036000 W US 2004036000W WO 2005045306 A1 WO2005045306 A1 WO 2005045306A1
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WO
WIPO (PCT)
Prior art keywords
natural gas
lng
liquefied natural
water
equipment
Prior art date
Application number
PCT/US2004/036000
Other languages
English (en)
Inventor
Robert Forrest Figgers
Denby Grey Morrison
Paul Johannes Gerardus Wilhelmus Van Weert
Original Assignee
Shell Internationale Research Maatschappij B.V.
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 B.V. filed Critical Shell Internationale Research Maatschappij B.V.
Publication of WO2005045306A1 publication Critical patent/WO2005045306A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E02—HYDRAULIC ENGINEERING; FOUNDATIONS; SOIL SHIFTING
    • E02B—HYDRAULIC ENGINEERING
    • E02B17/00—Artificial islands mounted on piles or like supports, e.g. platforms on raisable legs or offshore constructions; Construction methods therefor
    • E02B17/0017—Means for protecting offshore constructions
    • E—FIXED CONSTRUCTIONS
    • E02—HYDRAULIC ENGINEERING; FOUNDATIONS; SOIL SHIFTING
    • E02B—HYDRAULIC ENGINEERING
    • E02B17/00—Artificial islands mounted on piles or like supports, e.g. platforms on raisable legs or offshore constructions; Construction methods therefor
    • E02B17/02—Artificial islands mounted on piles or like supports, e.g. platforms on raisable legs or offshore constructions; Construction methods therefor placed by lowering the supporting construction to the bottom, e.g. with subsequent fixing thereto
    • E02B17/025—Reinforced concrete structures
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C13/00—Details of vessels or of the filling or discharging of vessels
    • F17C13/08—Mounting arrangements for vessels
    • F17C13/082—Mounting arrangements for vessels for large sea-borne storage vessels
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C3/00—Vessels not under pressure
    • F17C3/02—Vessels not under pressure with provision for thermal insulation
    • F17C3/025—Bulk storage in barges or on ships
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C7/00—Methods or apparatus for discharging liquefied, solidified, or compressed gases from pressure vessels, not covered by another subclass
    • F17C7/02—Discharging liquefied gases
    • F17C7/04—Discharging liquefied gases with change of state, e.g. vaporisation
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C9/00—Methods or apparatus for discharging liquefied or solidified gases from vessels not under pressure
    • F17C9/02—Methods or apparatus for discharging liquefied or solidified gases from vessels not under pressure with change of state, e.g. vaporisation
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2203/00—Vessel construction, in particular walls or details thereof
    • F17C2203/06—Materials for walls or layers thereof; Properties or structures of walls or their materials
    • F17C2203/0634—Materials for walls or layers thereof
    • F17C2203/0678—Concrete
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F17—STORING OR DISTRIBUTING GASES OR LIQUIDS
    • F17C—VESSELS FOR CONTAINING OR STORING COMPRESSED, LIQUEFIED OR SOLIDIFIED GASES; FIXED-CAPACITY GAS-HOLDERS; FILLING VESSELS WITH, OR DISCHARGING FROM VESSELS, COMPRESSED, LIQUEFIED, OR SOLIDIFIED GASES
    • F17C2265/00—Effects achieved by gas storage or gas handling
    • F17C2265/05—Regasification

Definitions

  • the invention generally relates to structures configured to store liquefied natural gas and distribute natural gas. More specifically the invention relates to liquefied natural gas processing. Description of Related Art Natural gas is becoming a fuel of choice for power generation in the U.S. and other countries. Natural gas is an efficient fuel source that produces lower pollutant emissions than many other fuel sources. Additionally, gains in efficiency of power generation using natural gas and the relatively low initial investment costs of building natural gas based power generation facilities, make natural gas an attractive alternative to other fuels.
  • LNG Liquefied natural gas
  • -160 °C -256 °F
  • Storage of LNG requires much less volume for the same amount of natural gas .
  • a number of storage tanks have been developed to store LNG. In order to use LNG as a power source, the LNG may be converted to its gaseous state using a re-vaporization process. The re-vaporized LNG may then distributed through pipelines to various end users.
  • LNG may be transported by ship to markets further than would be practical with pipelines.
  • This technology allows customers who live or operate a long way from gas reserves to enjoy the benefits of natural gas.
  • Importing LNG by ships has led to the establishment of LNG storage and re-vaporization facilities at on-shore locations that are close to shipping lanes.
  • the inherent dangers of handling LNG make such on-shore facilities less desirable to inhabitants who live near the facilities. There is therefore a need to explore other locations for the storage and processing of LNG.
  • the invention provides a liquefied natural gas storage structure positioned in a body of water comprising a body, one or more liquefied natural gas storage tanks contained within the body, wherein at least a portion of a bottom surface of the body rests upon a portion of a bottom of the body of water.
  • the structure further comprises one or more wave deflectors coupled to at least a portion of the body.
  • the invention also provides a method of using a liquefied natural gas storage structure, as described herein, in a body of water, comprising receiving liquefied natural gas from a liquefied natural gas carrier; storing the liquefied natural gas in one or more liquefied natural gas storage tanks; and processing the liquefied natural gas to natural gas using vaporization equipment.
  • LNG receiving, storage, and processing facilities are positioned in an off-shore location.
  • the LNG storage and processing facility in one embodiment, may be a gravity base structure.
  • a gravity base structure is a structure that at least partially rests upon the bottom of a body of water and partially extends out of the body of water.
  • the gravity base structure includes equipment for receiving, storing, and processing LNG.
  • an LNG structure in one embodiment, includes a body disposed in a body of water. The body at least partially rests on a bottom of the body of water, while an upper surface of the body extends above the surface of the water.
  • One or more LNG storage tanks may be contained within the body.
  • Equipment for transfer and processing of LNG may be disposed on the upper surface of the body.
  • docking equipment may be disposed on an upper surface of the body. The docking equipment may be configured to couple an LNG carrier to the body. By placing the docking equipment directly on the body, instead of using, for example, separate mooring platforms, the LNG carrier may be coupled closer to the body. Coupling an LNG carrier close to the body may facilitate transfer of LNG from the LNG carrier to the LNG storage tanks.
  • the body may also provide some protection from waves while the LNG carrier is docked alongside the body. Mooring of an LNG carrier with the LNG structure may be accomplished using mooring lines.
  • docking equipment may be placed at a different elevation than the other LNG processing equipment.
  • the docking equipment may be placed at an elevation to minimize the angles on mooring lines between the docking equipment and a docked LNG carrier.
  • the control of mooring line angles has traditionally been accomplished by the use of separate mooring structures having the appropriate height.
  • fenders may be placed at various positions about the body to protect the body from collisions with LNG carriers.
  • fenders may be placed along a docking side of the structure and at corners of the structure .
  • the body of the LNG structure at least partially rests on the bottom of a body of water.
  • projections extend from the bottom of the LNG structure body.
  • ballast cells may be disposed throughout the body. Ballast may be used to maintain the structure on the bottom of the body of water.
  • Vaporization equipment may be disposed on the body to vaporize LNG to natural gas.
  • vaporization equipment includes a heat exchange vaporization system.
  • a heat exchange vaporization system may, in some embodiments, use water from the body of water to convert LNG to natural gas .
  • Water from the body of water may be obtained using a variety of water intake systems .
  • the water intake systems may be configured to reduce the amount of sea life and debris that enters the heat exchange vaporization system.
  • the various components of LNG transfer, storage, and processing may be disposed on an upper surface of the body.
  • one or more platforms may be constructed on the upper surface of the body.
  • Various LNG storage, transfer, and processing equipment may be disposed on top of platforms, rather than directly on the upper surface of the LNG structure.
  • one or more platforms may be at a height of at least about 5 meters above the upper surface of the body.
  • wave deflectors may be positioned on at least a portion of the edge of the LNG structure body. Wave deflectors may extend outward from the sidewalls of the structure. In this manner, waves that impact the side of the structure may be inhibited from flowing over an upper surface of the body.
  • living quarters, flare towers, and export line metering equipment may be disposed on the body of the structure. By placing these areas directly on the body, the use of auxiliary platforms to hold these structures may be avoided, therefore reducing construction costs.
  • Typical LNG carriers have a net LNG capacity ranging from 125,000 cubic meters to about 165,000 cubic meters.
  • LNG carriers of up to about 200,000 cubic meters in net storage capacity may be available in the future .
  • the LNG capacity of the LNG structure may be optimized based on a number of factors.
  • LNG structures may be constructed on-shore. After an LNG structure has been constructed the structure may be towed to an appropriate site and positioned on the bottom of a body of water. Trapping air underneath the structure may improve the buoyancy of the structure.
  • a combination of structural- grade lightweight concrete and air compartments may also be used to improve the buoyancy of the structure .
  • multiple pipelines may be coupled to the LNG structure. Each of the pipelines may connect the LNG structure to different natural gas pipeline systems.
  • FIG. 1 depicts a top view of an embodiment of the structure
  • FIG. 2 depicts a representation of an embodiment of the vaporization process
  • FIG. 3 depicts a cross-sectional view of an embodiment of a structure
  • FIG. 4 depicts a top view of an embodiment of the structure .
  • An offshore liquefied natural gas (“LNG”) receiving and storage structure may allow LNG carriers to berth directly alongside the structure and unload LNG.
  • the LNG structure may include one or more tanks capable of storing LNG.
  • the LNG structure may transfer LNG from the tanks to an LNG vaporization plant disposed on the structure.
  • the vaporized LNG may then be distributed among commercially available pipelines.
  • An LNG structure 100 may have a layout that includes LNG tanks 110 on the structure with vaporization process equipment 120 and utilities, docking equipment, living quarters 130, flares 140, vents 150, metering equipment 160, and pipelines 170 for exporting natural gas.
  • the living quarters 130, vaporization plant 120, and/or other process equipment may be positioned on an upper surface of the structure 100, such as on an upper surface of unit 180 and/or unit 190.
  • the layout may be designed according to Fire/Explosion Risk assessment guidelines.
  • the layout of the structure may be designed to maximize safety of the living quarters.
  • living quarters may be positioned on the structure.
  • the living quarters may be positioned proximate an opposite end from the flare and/or vent.
  • the living quarters may not be positioned proximate the heat exchangers and/or recondensers .
  • living quarters on the structure may be positioned to be proximate living quarters on an LNG carrier during unloading. Aligning living quarters on the structure with living quarters on the carrier may maximize safety.
  • the living quarters may be substantially resistant to fire, blast, smoke, etc.
  • the living quarters may be reinforced to substantially withstand explosion overpressure.
  • the living quarters may be designed to inhibit the ingress of gas and smoke .
  • the living quarters may be positioned on a separate platform in the body of water.
  • the platform may be coupled to the structure by a connecting bridge. Overall there may be little or no difference between the risks to living quarters on the structure and living quarters on a separate platform. In an embodiment, living quarters on the structure are at least partially protected from waves by the structure.
  • the body of the LNG structure may include one or more units. In some embodiments, the units may be, for example, but not limited to, steel-reinforced concrete units, steel jackets, and the like and combinations thereof. The one or more units may square, rectangular, partially spherical, and the like and combinations thereof .
  • the structure may include only one unit . In an embodiment, the structure may include ' two units. The one or more units may be coupled together. The units may be substantially similarly sized.
  • More than one unit may be used because of ease of construction, soil conditions, restricted space available in existing graving docks, and/or difficulties with tow out and installation.
  • the units may be built onshore, towed to the site, and set down at a desired location using well-proven construction methods and technology as known to one skilled in the art.
  • the units may be separately towed to an offshore site.
  • the units may be towed together to a site.
  • the LNG structure may be composed of two or more units, each unit including one or more LNG storage tanks.
  • the units may be placed end to end to form the structure .
  • a bridge structure may couple units together.
  • LNG storage tanks 110 in each unit 180, 190 may be coupled together. See FIG. 1.
  • the two or more units may be coupled together.
  • a gap 200 between units 180, 190 may be closed off to prevent erosion of the seabed between the units.
  • Each unit 180, 190 may contain different equipment, living quarters 130, and/or liquefied natural gas tanks 110.
  • living quarters 130 may be on one unit 180 and a vaporization plant 120 and other process equipment may be on a different unit 190.
  • the docking equipment may be distributed on one or more units, such as on unit 180 and/or unit 190.
  • FIG. 4 depicts an embodiment of an LNG structure of the present invention.
  • An LNG structure 100 may have a layout that includes LNG tanks 110 on a unit 180 of the structure. While the tanks in FIG.
  • the tanks may be, for example, but not limited to, cylindrical, square, rectangular, partially spherical, irregularly shaped, and the like and combinations thereof.
  • the vaporization process equipment 120 and utilities, docking equipment, living quarters 130, flares 140, vents 150, metering equipment 160 and pipelines 170 for exporting natural gas are on a unit 190 of the structure.
  • the living quarters 130, vaporization plant 120, and/or other process equipment may be positioned on an upper surface of the structure 100, such as on an upper surface of unit 190.
  • the units may be, for example, but not limited to, concrete units, also referred to as concrete caissons, steel jackets, and the like and combinations thereof.
  • the units may be, for example, but not limited to, square, rectangular, partially spherical, and the like and combinations thereof.
  • the units may be coupled together.
  • the docking equipment may be distributed on one or more units, such as on unit 180 and/or unit 190.
  • the units may be placed end to end to form the structure.
  • a bridge structure may couple units together.
  • LNG storage tanks 110 in unit 180 may be coupled together.
  • the units may be coupled together.
  • a gap 200 between units 180 and 190 may be closed off to prevent erosion of the seabed between the units.
  • the LNG structure may be composed of more than one unit, such as two units, comprising concrete units, steel jackets, and the like and combinations thereof.
  • the units may be square, rectangular, partially spherical, and the like and combinations thereof.
  • one of the units may be square or rectangular and comprise one or more tanks that can be, for example, but not limited to, cylindrical, rectangular, partially spherical, irregularly shaped, and the like and combinations thereof.
  • one of the two units may be a concrete square or rectangle comprising two cylindrical tanks.
  • the other unit may be a concrete square or rectangle and comprise the vaporization process equipment and utilities, living quarters, flares, vents, metering equipment and pipelines. Docking equipment may be on one or more of the units.
  • the units may be coupled together.
  • an LNG structure of the present invention may be composed of more than one unit, such as three units, where the units may be, for example, but not limited to, concrete units, also referred to as concrete caissons, steel jackets, and the like and combinations thereof.
  • the units may be, for example, but not limited to, square, rectangular, partially spherical, and the like and combinations thereof.
  • the units may be coupled together.
  • the LNG structure may be comprised of three units where all three units are concrete units or caissons with two of the concrete units or caissons comprising one or more LNG tanks, and the third concrete unit or caisson comprising the vaporization process equipment and utilities, living quarters, flares, vents, metering equipment and pipelines.
  • Docking equipment may be on one or more of the units. Such an embodiment may allow for the two units comprising the one or more LNG tanks to be reduced in length and the unit comprising the utilities may be smaller as well compared to a structure comprising two units.
  • non-cryogenic LNG components may be placed on the third unit.
  • the concrete units may be, for example, but not limited to, square, rectangular, partially spherical, and the like and combinations thereof.
  • the units may be coupled together.
  • an LNG structure of the present invention may be composed of more than one unit, such as two units, where one unit comprises a concrete unit or caisson and the other unit comprises a steel jacket.
  • the concrete unit may be, for example, but not limited to, square, rectangular, partially spherical, and the like and combinations thereof, and comprise one or more tanks that can be, for example, but not limited to, cylindrical, rectangular, partially spherical, irregularly shaped, and the like and combinations thereof.
  • the steel jacket unit may be, for example, but not limited to, square, rectangular, partially spherical, and the like and combinations thereof.
  • one of the two units can be a concrete square or rectangle comprising two round tanks.
  • the other unit may be a steel jacket unit and comprise the vaporization process equipment and utilities, living quarters, flares, vents, metering equipment and pipelines. Docking equipment may be on one or more of the units.
  • the units may be coupled together.
  • one or more steel jackets may be utilized to provide additional units that provide, for example, but not limited to, a separate unit for vaporization process equipment and utilities, flares and vents, a separate unit for metering equipment and pipelines, and a separate unit for living quarters. Docking equipment may be on one or more of the units. The units may be coupled together.
  • the phrase "steel jacket” or "steel jacket unit” referred to herein means any steel jacket that can be utilized according to an embodiment of an LNG structure disclosed herein.
  • Steel jacket refers to any steel template, space-frame support apparatus, platform and/or structure utilized to support various processing equipment typically utilized for off-shore production of hydrocarbons, LNG, and the like and combinations thereof.
  • Each unit may include one or more LNG storage tanks . Insulation in the tanks may be designed to limit LNG boil- off to approximately 0.1 % of the contained LNG volume per day. The capacity of a tank may be up to approximately 566,000 bbl (90,000 m 3 ) of LNG.
  • the structure may include less than about 250,000 cubic meters of net LNG storage. In certain embodiments, the structure may include greater than about 50,000 cubic meters of net LNG storage.
  • the structure may include greater than about 100,000 cubic meters of net LNG storage.
  • the LNG capacity of a structure may be optimized based on a number of factors including LNG capacity of one or more LNG carriers, desired peak regasification capacity of the structure for converting LNG to a natural gas, the rate at which LNG from an LNG carrier is transferred from a carrier to one or more LNG storage tanks, and/or costs associated with operating the structure.
  • carriers have a capacity of about 125,000 cubic meters to about 200,000 cubic meters.
  • Peak natural gas production may be at least about 1 billion cubic feet per day (1,960 m 3 /h LNG) .
  • an optimal storage capacity of the structure may be about 180,000 cubic meters .
  • the LNG structure has a storage capacity of less than about 200,000 cubic meters of LNG. In some embodiments, the structure is configured to produce natural gas at a peak capacity of greater than about 1.2 billion cubic feet per day (2,400 m 3 /h LNG). In some embodiments, the LNG structure is configured to offload LNG from carriers having a storage capacity of greater than about 100,000 cubic meters. In some embodiments, the body of the structure has a length that is at least equal to a length required to provide sufficient berthing alongside the body for an LNG carrier having an LNG capacity of greater than about 100,000 cubic meters . LNG tanks may substantially store vapor and liquefied natural gas. LNG tanks may be double containment systems. LNG storage tanks may include a liquid and gas tight primary tank constructed in a concrete interior of the structure .
  • the primary tank may be formed from, for example, stainless steel, aluminum, and/or 9%-nickel steel.
  • the LNG containment system may be, for example, a SPB (Self-supporting Prismatic shape IMO Type "B" ) rectangular tank system, a 9% nickel-steel cylindrical tank system, and/or a membrane tank system.
  • LNG tanks may be freestanding tanks and/or self-supporting tanks.
  • each unit of the structure contains at least one steel membrane type LNG containment tank.
  • the LNG tank may be cylindrical, rectangular, partially spherical, or irregularly shaped.
  • the tank may be a membrane tank.
  • Membrane tanks may be commercially available from, for example, Technigaz, Mitsubishi Heavy Industries, Inc., and Kawasaki Heavy Industries, Inc.
  • tanks may be SPB (Self-supporting Prismatic shape IMO Type "B") tanks commercially available from Ishikawaj ima-Harima Heavy Industries Co., Ltd. (IHI) (Japan) .
  • the tank may be a commercially available 9% nickel cylindrical tank. Water ingress through the concrete tank walls may cause freezing of the entrained water, which may damage the tanks. Installation of an extensive heating system (e.g., electric) in the tank walls and slab may decrease the likelihood of freezing water proximate the tank.
  • a temperature of concrete surfaces may be regulated to substantially inhibit icing on the surfaces of the concrete.
  • a heating system may be provided on the walls and bottom to maintain a temperature of at least about 5°C. In some embodiments, a heating system is configured to maintain a temperature of the outer wall at or above about 5°C.
  • a watertight coating on tank walls may inhibit water ingress.
  • solid ballasting material may be maintained proximate the tank to avoid water proximate tank walls.
  • an LNG storage tank may include pre-tensioned concrete and may provide structural resistance to inner LNG and gas pressure loads and to outer hazards .
  • the tank may include a primary barrier, such as stainless steel corrugated membrane.
  • the stainless steel membrane may constitute a liquid and vapor tight inner containment.
  • the tank may include a secondary barrier positioned between the primary barrier and the concrete.
  • PermaglassTM may form the secondary barrier.
  • PermaglassTM may be a polyester/glass cloth composite.
  • the secondary barrier may be incorporated in the insulating panels under the primary barrier.
  • the secondary barrier may be incorporated in the insulation between the concrete structure and the primary barrier.
  • the secondary barrier may retain liquid and vapor in case of a leakage of the primary barrier.
  • the secondary liner may be applied on the entire bottom and wall surfaces of the tank. The continuity of the secondary liner between two panels may be ensured by aluminum foil between two glass cloth layers (e.g., Triplex).
  • insulation may be positioned between the membrane and the concrete wall . Insulation may be formed of polyurethane foam (PUF) . Insulation may keep the concrete tank walls at an acceptable temperature.
  • PPF polyurethane foam
  • a predetermined acceptable boil off rate may determine the insulation thickness.
  • the insulation may transmit the inner LNG loads from the membrane containment system to the concrete tank walls by means of an epoxy mastic.
  • the secondary barrier should be insulated from the concrete support structure.
  • the insulating structure may comprise the secondary barrier.
  • the insulating structure may comprise insulating material .
  • carriers may act as backup storage. If LNG storage tanks are incapable of receiving more LNG (e.g., full tanks, failure of tanks, failure of unloading arms, etc.) , an LNG carrier may be store LNG until tanks are capable of receiving additional LNG. In an embodiment, if two carriers arrive at the structure at substantially the same time, LNG may be stored on one of the carriers until the structure is capable of receiving additional LNG from the carrier.
  • a suspended deck may provide insulation on top of the tank.
  • the roof insulation may be placed on top of the suspended deck.
  • the length of the aluminum deck hangers may be selected such that the hangers do not act as cold bridges to the concrete roof .
  • the suspended deck may include open vents to ensure equilibrium of gas pressure on both sides of the suspended deck.
  • a level of LNG in the tank may be regulated below an inner top surface of the tank.
  • the LNG may not contact the roof of a tank.
  • the roof may not be liquid proof.
  • the ingress of water vapor through the concrete outer tank and egress of product vapor through the concrete outer tank roof may be inhibited by application of a suitable system on the interior surface of the concrete tank.
  • the liquefied natural gas storage tanks may comprise an outer wall, an insulating structure, wherein the insulating structure is positioned on an inner surface of the outer wall, a secondary barrier, wherein the secondary barrier is positioned on an inner surface of the insulating structure, and a primary barrier, wherein the primary barrier is configured to contain, or provide containment of, liquefied natural gas and/or vapor.
  • the secondary barrier may be configured to at least partially contain any vapor and/or liquefied natural gas from leaking from the primary barrier.
  • drainage systems, pressure monitors and regulators, nitrogen purge systems, and/or temperature monitoring systems may be positioned between tank components.
  • the structure may include back-up monitors and regulators for temperature and/or pressure.
  • the temperature may be maintained such that water does not freeze proximate tank components.
  • An Emergency Diesel Generator may heat tank walls.
  • drainage systems remove water ingress.
  • a piping network may be installed proximate the insulated space. The piping system may monitor and/or regulate conditions in the tank.
  • purge/vent systems may be installed. The purge/vent system may be positioned in the insulation space in the tank, behind the membrane, in the corrugations, in front of the secondary Permaglass liner, and/or between the secondary liner and the concrete hull of the structure.
  • the system may be designed such that it may be also be used for ammonia leak tests, space gas sampling of the insulation space by sampling the nitrogen circulation, regulation of absolute pressure in the insulation space, and/or nitrogen sweeping of the insulation space in case LNG vapor is detected.
  • the purge/vent system may include a nitrogen injection network that allows sweeping and purging, as needed.
  • the primary and secondary insulation space may communicate at the top of the tank to maintain pressure equilibrium.
  • a purge system may be positioned between the primary barrier and the secondary barrier where the purge system is configured to remove natural gas leaking through the primary barrier.
  • a grid of ballast storage areas may be used for ballasting.
  • ballast storage areas also referred to as ballast cells, may be disposed throughout the structure. Ballast storage areas may be used to facilitate transportation to the site, and to ground and secure the structure to the seafloor. Ballast storage areas may be used to obtain sufficient on bottom weight .
  • One or more ballast storage areas may be incorporated into the structure or body of the structure . Ballast storage areas may be at least partially filled with solid and/or liquid ballast material. In some embodiments, water is used as a liquid ballast material. Sand may be used as solid ballast material. In some embodiments, a heavier material than sand may be used as solid ballasting material. Iron ore may be used as a solid ballasting material.
  • ballast ballast ballast may be replaced with approximately 40,000 m 3 of iron ore ballast.
  • Water drainage and/or monitoring systems may be installed to monitor and regulate water ingress through the external walls of the ballast storage areas.
  • ballast storage areas filled with solid ballast material or "dry ballast" are positioned next to the LNG storage tank.
  • sand may be placed in ballast storage areas next to tanks in order to achieve sufficient on-bottom weight for the structure. Solid ballast material in ballast storage areas may maintain a dry condition to avoid water ingress into tank walls.
  • Ballast storage areas positioned below a tank may be filled with liquid ballast material instead of solid ballast material. Using liquid ballast material may facilitate decommissioning.
  • - water ballast may be partially replaced with solid ballast.
  • the structure includes projections, also referred to as skirts, on a bottom surface of the body. The projections may at least partially project into a bottom of a body of water. Ballast storage areas may be filled such that the weight of the structure at least partially embeds at least a portion of the projections in the bottom of a body of water.
  • projections may at least partially form the foundation for the structure. Projections may be positioned on a bottom surface of the structure.
  • the projections may be arranged in a repetitive grid of plane walls and slabs. The spacing and positioning of the projections may be such that the structure may be at least partially supported on the projections. Furthermore, the projections may be arranged to inhibit bowing of the structure while resting on the bottom of the body of water.
  • the foundation may include ribs on a gravel berm. In some embodiments, at least some of the projections are arranged in a grid pattern. In some embodiments, the foundation of the structure may include a rectangular base. The foundation may be equipped with a plurality of projections arranged as concrete projections in combination with ribs.
  • the projections may be 6.5 m deep, 0.30 m wide at their tip, with a wedge angle lower than 1°, and/or connected to the structure bottom through ribs.
  • a projection length may be designed based on the required penetration depth for different environmental loading, clay strength, structure orientation, and/or structure weight.
  • a factor in structure stability under such environmental conditions is the horizontal "direct simple" shear strength of the underlying clays in the upper 10 meters of a bottom, of a body of water. Shear strength may be measured directly in the laboratory by cycling a shear load across clay samples at vertical pressures equivalent to the in-situ condition and assessing the "cyclic" strength of the clays. The testing aims to replicate the 100-year design storm passing across the structure causing a sliding of the whole structure at the projection tips.
  • no under base grouting may be required after full penetration of the projections.
  • no specific seabed preparation may be required other than normal offshore hazard surveys and detailed bathymetrical survey work prior to installation. If the maximum apparent weight of the structure during installation is not large enough to enable a desired penetration of the projections into a bottom of a body of water, suction may be used to achieve the required penetration depth. Air trapped in the compartments of the projections may provide some buoyancy to the structure. At least a portion of the trapped air may be suctioned out of the compartments. Removal of at least a portion of the air may cause the projections to penetrate or further penetrate the bottom of a body of water.
  • Suction may occur by means of the piping system installed for air cushions used during installation of the structure at a site.
  • at least some of the projections are oriented such that one or more compartments are formed on the bottom of the body of the structure.
  • at least a portion of the compartments are configured to entrap air between the body and the water surface.
  • trapping air in at least a portion of the compartments increases the buoyancy. of the body.
  • the projection dimensions may be selected to enable penetration into competent soil layers.
  • the length of the projections may be selected such that failure occurs due to horizontal sliding of the structure along a plane at the projection tips. Uppermost soils may have insufficient shear strength and so the projections must at least partially penetrate adequately into the overconsolidated clay.
  • At least a portion of the projections are at least partially embedded in the bottom of the body of water. In some embodiments, at least some of the projections inhibit lateral movement of the structure .
  • under keel clearance may affect the design of the LNG structure. For example, an available channel depth may be about 13.7 meters (m) . The structure may be designed to maintain a specific under keel clearance in such channel depths. Channel depth may also affect draft of the structure. Lightweight concrete, semi-lightweight concrete, buoyancy caissons, and/or widening the structure base may be used to increase under keel clearance. The decision to use lightweight concrete or the partial use of lightweight concrete for the construction of offshore structures has implications for the design and construction of the structure .
  • Lightweight concrete may have a density of less than about 2000 kg/m 3 .
  • Liapor, Lytag and/or Solite, commercially available lightweight concrete aggregates may be used in certain embodiments.
  • scour protection may be installed to inhibit erosion of a bottom of a body of water proximate the structure. Erosion proximate the foundation of the structure may affect stability. Scour protection may be positioned around the structure. In an embodiment, scour protection may be installed proximate portions of the foundation that at least partially extend into a bottom of a body of water. Scour protection may be used proximate tie-in locations for exporting pipelines.
  • the scour protection along the structure may be extended beyond the location of pipeline tie-ins to minimize the development of holes and imposed deformations on the pipeline.
  • the pipeline tie-ins may be positioned at least partially above the scour protection.
  • Scour protection may be used to minimize damage from LNG carrier thrusters and/or propeller impacts.
  • Scour protection may be configured to inhibit soil erosion about a base of the structure.
  • Scour protection may at least partially circumscribe the structure .
  • the type and thickness of the scour protection may depend on the velocities at various spots around the structure.
  • the scour protection may be substantially cubic.
  • Scour protection may have a substantially square, substantially circular, substantially oval, substantially rectangular, or substantially irregular cross-section.
  • Scour protection may be concrete- or sand- filled mattresses or heavy concrete elements. Scour protection may include a gabion type solution. A rock filled gabion-type scour protection mattress may substantially prevent undermining the foundation integrity and/or stability. The gabion mattress may be attached to the structure such that the mattress may follow a developing scour hole.
  • An offshore LNG storage and receiving structure may be designed to receive liquefied natural gas from carriers and transfer the LNG to one or more LNG storage tanks. The LNG may then be vaporized in a heat exchange vaporization system. The vaporized natural gas may be sent out among several pipelines that distribute natural gas to other facilities for further processing and/or distribution . . The. LNG storage tanks may contain vapor and liquefied natural gas.
  • Natural gas vapor may form due to heat ingress into the storage tank. Heat may be introduced to the tank during ship unloading. Heat may enter the storage tanks from the LNG recirculation lines and by changes in the fluid composition when LNG is unloaded into the storage tanks. This vaporized LNG is typically referred to as boil-off gas ( "BOG" ) .
  • BOG boil-off gas
  • the normal BOG rate may be about 0.1 % per day of the total storage volume .
  • BOG may be used to regulate the pressure in the LNG carrier while unloading. BOG may be used to regulate a pressure in LNG tanks.
  • BOG may be compressed by a BOG compressor and routed to a recondenser, also referred to as a condenser, that recondenses BOG.
  • compressors may be centrifugal compressors.
  • the recondensed BOG may mix with LNG inside the recondenser. The mixture may be routed to the gasification trains.
  • the recondenser may be designed to process all BOG generated in the structure .
  • the recondenser may be designed to process vapor from unloading carriers.
  • one or more recondensers may be coupled to one or more LNG storage tanks .
  • the recondensers may be configured to convert natural gas to LNG.
  • BOG compressors may be designed to accommodate BOG from a carrier unloading during minimum send-out rate conditions. As a rate of LNG send-out increases, the greater the structure may accommodate boil-off gas. At peak send-out rates, send-out gas may be recycled to tanks to maintain tank pressures.
  • unloading may be delayed when a send-out rate is approximately zero.
  • LP (low pressure) pumps may pull a vacuum when send-out rates are high without recycling at least a part of send-out gas.
  • a compressor may be used to direct boil-off gas during severe weather to pipelines. Spare boil-off gas compressors may be installed.
  • one or more boil-off gas compressors may be coupled to one or more LNG storage tanks. The one or more boil-off gas compressors may be configured to provide a source of compressed natural gas to the structure . During hurricanes, the terminal may be abandoned and gas send-out will cease. All non-critical operations may be shut down and excess BOG may be flared rather than reprocessed.
  • the recondenser may recondense at least a part of the BOG and provide sufficient pressure and surge volume at the suction of the high-pressure LNG send-out pumps.
  • the main flow of LNG from the in-tank pumps may be routed directly to the recondenser.
  • BOG may be recondensed by mixing it with a portion of cold LNG from the storage tanks.
  • a recondenser may process BOG not returned to the LNG carrier.
  • the recondenser may be stainless steel .
  • the internal vessel of the recondenser may not be inspected.
  • the recondenser vessel may be externally inspected.
  • the recondenser may use subcooled LNG to condense BOG.
  • a recondenser bypass may be used to accommodate higher than expected LNG sendout rates .
  • the bypass may send BOG to flare or vent systems .
  • the recondenser may not be regulated.
  • Subcooled LNG from the in-tank pumps may enter the recondenser at one or more locations.
  • LNG for condensation may enter at the top of the recondenser.
  • LNG may pass through a distributor and into a packed bed section.
  • the LNG may cause condensation of BOG in the packed bed section.
  • a second LNG stream may bypass the packing and enter the recondenser proximate the bottom of the vessel. The second stream may mix with the condensing BOG to produce a subcooled liquid stream.
  • LNG may exit the recondenser through anti-vortex arrangements from the bottom of the vessel before passing to the pumps.
  • high-pressure pumps may transfer LNG from the tanks to one or more heat exchangers, also referred to as heaters or vaporizers.
  • LNG may be vaporized at high pressures in the heat exchangers.
  • the heat exchanger is an open rack vaporizer.
  • the heat exchanger is a submerged combustion vaporizer.
  • LNG may be fed through aluminum tubes.
  • a heating medium may flow from the top of the vaporizers over the tubes, whereby vaporization occurs.
  • the temperature drop across the heat exchanger of the heating medium may be less than or equal to about 10°C (18°F) .
  • Seawater may be used as the heating medium for one or more heat exchangers .
  • the heat exchangers may use water from the body of water the structure is positioned in to vaporize LNG in a once-through configuration. Intake screens, velocity, location, and/or orientation may be selected to minimize marine life entrainment and impingement.
  • the water may be treated to minimize marine growth within the water intake system.
  • the water intake system may discharge water at an outlet structure .
  • a water intake and outlet system may be installed to circulate the required volume of water from the body of water, through the facilities on the structure deck, and back to the body of water. Scour protection may be positioned proximate inlets, outlets, outlet bends, and/or connections to the bottom of a body of water.
  • the water intake system may include equipment (e.g., pumps) that provides water to the heat exchangers; fixed hardware that channels water from the body of water, through the vaporization system, and back to the body of water, such as the ocean, again; pump chambers, from which water may be pumped to heat exchangers; and water inlets and outlets off the structure.
  • the water intake system may be designed to have redundancy.
  • two or more water inlets may be used. In this manner if one inlet is offline, another inlet may provide water to the structure.
  • the outlet system may include only one outlet. Water may flow over a side of the deck if the outlet is offline. Water may flow from the single water intake conduit into a water-receiving chamber in the structure.
  • water may be filtered in the structure.
  • Baffles that reduce the effects of standing waves on water levels in water receiving chambers and/or flow in the water intake system may be positioned in water receiving ends, water inlet conduits, inlets, and/or water receiving chambers.
  • Water intake systems may be positioned at a distance from the structure such that rapid water level variations do not substantially affect the flow of water in the intake system.
  • Water inlets may be positioned directly on the surface of the structure. In some embodiments, the inlet may be designed such that reflections of waves impacting the structure (e.g., standing waves) do not substantially affect the flow of water in the intake system.
  • screens may be positioned in inlet and/or water receiving chamber to inhibit impingement or ingress of marine life.
  • a crane positioned on the structure may facilitate maintenance of the water intake system (e.g., removing screens and/or baffles for maintenance or repair) .
  • the crane may be positioned on an elevated top surface of the structure.
  • the mechanical effects of pump impellers in the water intake system may inhibit marine life from entering the system.
  • Screen systems may be periodically cleaned. Cleaning may include compressed air dislodging debris from the screens.
  • the pressurized cleaning system may include cleaning screens with pressurized water.
  • the pressurized cleaning system may also be used in outlets.
  • a platform above water inlets and/or outlets may allow screens to be lifted above water level for maintenance.
  • cranes may remove and/or position one or more screens from the inlets and/or outlets.
  • Water from the water intake systems may flow to a heat exchanger vaporization system.
  • Heat exchangers may be used to vaporize LNG received from LNG carriers.
  • LNG from one or more storage tanks may flow to one or more heat exchangers.
  • the vaporized natural gas may be provided to one or more commercially available pipelines coupled to the LNG structure .
  • open rack vaporizers vaporize LNG.
  • submerged combustion vaporizers vaporize LNG.
  • LNG may be pumped upwards through a parallel set of tubes, for example, a parallel, horizontal set of tubes, while water runs downward through the exterior of the tubes by gravity. The heat from the water may regassify the LNG. Heat transfer efficiency may be improved using fins.
  • LNG may be vaporized as schematically illustrated in FIG. 2.
  • Heat exchangers 610 may be open rack vaporizers. Heat exchangers 610 may be submerged combustion vaporizers. In an embodiment, open rack vaporizers may be a cost-effective heat exchanger option. Water may be transferred from the water inlet 310 to the heat exchangers 610 to vaporize LNG. Water may then be released back into the body of water through the water outlet 320. LNG from a carrier 620 may be transferred to one or more storage tanks 110 via unloading arms 630.
  • BOG boil-off gas
  • BOG may also be compressed in a BOG compressor 640.
  • the BOG may pass through a BOG compressor scrubber 635 before transfer to the BOG compressor 640.
  • the BOG may pass through a BOG desuperheater (not shown) before entering the BOG compressor scrubber 635.
  • Compressed BOG may be recondensed in a recondenser 650 and returned (not shown) to storage tanks 110 and/or transferred to a heat exchangers 610. While not shown, in some embodiments compressed BOG and/or recondensed BOG, from the BOG desuperheater, BOG compressor scrubber 635, BOG compressor 640 and/or recondenser 650, may be transferred back to storage tanks 110 through separate drain lines and/or though valving and flow control of existing lines. LNG may be pumped from storage tanks 110 to heat exchangers 610 to be vaporized.
  • LNG may be pumped, utilizing low pressure pumps (not shown) that may be in storage tanks 110, to recondenser 650 and then, utilizing pumps 655, preferably high pressure pumps, the LNG may be pumped to heat exchangers 610.
  • Vaporized LNG may be warmed in a heater 660 to inhibit hydrate formation.
  • the heater 660 may use waste heat 670 to warm natural gas .
  • Natural gas may enter export metering lines 680. Natural gas may be distributed from the export metering lines 680 to commercially available pipelines 690 coupled to the structure . Some natural gas may be used as fuel 700 on the structure.
  • vaporization equipment may be coupled to an upper surface of the body.
  • the vaporization equipment may be configured to vaporize the LNG to natural gas during use .
  • a water intake system may be configured to draw water from a body of water and supply water to the vaporization equipment.
  • heat exchangers may be designed based on regasifying LNG at peak send-out rates and minimum heat transfer rates.
  • the heat exchanger may inhibit no more than a predetermined change in temperature of the water.
  • a heat exchanger may allow at most a 10°C drop in the temperature of water across the heat exchanger.
  • the temperature drop of the water across the heat exchanger may be at least partially controlled by applicable codes. Environmental codes may regulate the temperature at which water may be released into a marine environment .
  • the amount of water flow required in the heat exchanger is related to the selected temperature drop across the heat exchanger.
  • the amount of cold energy or cold thermal inertia returned to the sea may be the same if a smaller amount of water is returned at a lower temperature or a higher flow rate is returned at a slightly warmer temperature.
  • a larger temperature drop across the heat exchanger may cause ice formation in the water intake system. Smaller temperature drops across the heat exchanger for the water may be possible.
  • warmer sea temperatures may permit a higher temperature drop across the heat exchanger and reduce the water flow rate .
  • the water intake system may ensure that water returned to the body of water from the heat exchanger does not exceed a desired lower temperature limit.
  • the design of the water outlets may ensure that the temperature 100m from the structure does not decrease by more than 3°C, as per World Bank Standards.
  • the design of the water intake system may minimize cold-water recirculation between the outlets and the inlets. Water may be heated prior to re-release through the outlet system.
  • the water intake system may release water from the structure to the body of water through one or more outlets.
  • a diffuser with multiple outlets over a distance may also be used as an outlet system.
  • a single point diffuser with vertical outlet openings may be utilized because of simplicity and cost. Screens may be positioned in the outlets.
  • outlets and inlets may be separated such that cold water from the outlets does not substantially mix with ambient water proximate the inlets.
  • Outlets may be positioned at a distance from the structure to accommodate a working boat and/or platform alongside the structure .
  • the structure may comprise vaporization equipment coupled to the upper surface of the body wherein the vaporization equipment is configured to vaporize liquefied natural gas to natural gas during use.
  • the structure may comprise a water intake system wherein the water intake system is configured to draw water from the body of water and supply water to the vaporization equipment.
  • the structure may be designed to vaporize LNG delivered by LNG carriers and export natural gas into the existing pipeline network.
  • the structure may have a capacity to offload and regassify at a peak export rate of about 1.2 bscf/day (2,400 m 3 /h LNG) to the gas network.
  • the structure may be designed to have a nominal regassification rate of about 1.0 bscf/day (1,960 m 3 /h LNG) .
  • the structure may be designed such that the peak regassification rate is expandable.
  • the structure may have a peak sendout rate of about 1.8 bscf/day (3,600 m 3 /h LNG) .
  • the structure may allow offloading from a range of LNG carrier sizes.
  • the carriers may unload their cargo at cryogenic temperatures into the storage tanks contained within the structure.
  • the structure may be designed to process a range of LNG compositions ranging from Nigeria High composition (Rich) and Venezuela composition (Lean) . Custody transfer metering may occur on the structure prior to export into the pipeline network.
  • Natural gas exiting the heat exchangers may be metered into pipelines and flow to tie-in locations onshore.
  • the reduction in pressure along the pipelines may produce a cooling effect.
  • the cooling effect may only be partly compensated by heat ingress from the surrounding seawater.
  • the send-out gas may be heated in order to mitigate the possibility of hydrate formation in the takeaway pipelines.
  • the natural gas stream may be divided between the pipelines connected to the structure .
  • the gas may be routed from the sales gas header to one or more superheaters .
  • the superheaters may use tempered water from waste heat recovery units to warm natural gas .
  • the superheaters may direct warm natural gas into one or more common sendout headers .
  • the warmed send-out gas may then be metered to subsea export pipelines.
  • the send-out gas may experience a pressure drop across the metering lines.
  • natural gas may be heated by a tempered water system.
  • Waste heat from a gas turbine power plant on the structure may be utilized as the primary heating source for the tempered water system.
  • the waste heat recovery system may be able to discharge a surplus of waste heat as well as additionally heating within its operation window.
  • a tempered water system may be • equipped with a gas fired auxiliary boiler to add heat to the system in case waste heat capacity of the power plant (s) is not sufficient.
  • a structure may include a common header arrangement, also referred to as a common gas header arrangement .
  • the common header arrangement may permit greater opportunities for future expansion.
  • the use of a common header design may allow gas to be distributed among several pipelines.
  • the gas may be distributed according to a price of natural gas in the region served by the pipeline.
  • the pipeline capacities may be designed such that gas may be distributed among the pipelines in equal, nonequal, or proportional amounts.
  • Natural gas may be exported from the structure to markets for sale and/or further processing.
  • Each pipeline may be coupled to a metering station consisting of two or more metering runs .
  • the structure may include facilities for on-site generation of sodium hypochlorite from seawater via electrolysis.
  • the unit may be designed to allow continuous shock dosing by adding sodium hypochlorite into the system.
  • the structure may include hydrogen degassing tanks, air blowers to vent hydrogen gas to a safe location, storage facilities, and/or sodium hypochlorite injection pumps .
  • the structure may produce nitrogen on board.
  • the structure may have water inlet lift pumps that supply seawater for the fresh and potable water systems. Seawater may be strained through self-cleaning strainers.
  • the pumps may feed the electro-chlorination unit and a desalination package.
  • the system may be designed to prevent contamination of the potable water system by using a break tank to prevent contamination of the potable water system from non-sterilized sources.
  • a structure may include a relief system.
  • the relief system may include relief headers, lit flare headers, thermal safety valves, and/or emergency vent headers (low pressure and high pressure vents) .
  • Flare headers connected to the tank vapor space, balance line, and/or depressuring lines may operate during tank cool down, overpressure scenarios, and/or in hurricane situations where the structure will be de-manned and the vaporization process stopped.
  • the vent stack may be designed to accommodate all relief loads from the tank and/or may be used during flare maintenance.
  • An offshore LNG receiving and storage structure may accommodate LNG storage tanks, allow LNG vaporization plant and other process equipment and utilities to be positioned on the upper surface of the structure, and safely enable LNG carriers to berth directly alongside the structure.
  • An embodiment of the LNG structure is depicted in FIG. 3.
  • the structure 100 may include a first upper surface 710 with LNG transfer equipment 320.
  • the structure 100 may also include a second upper surface 720 below the first upper surface 710.
  • the second upper surface 720 may include docking equipment 730.
  • Docking equipment 730 may couple a liquefied natural gas carrier 740 with the structure 100.
  • the structure 100 may allow a carrier 740 to dock on one or more sides of the structure.
  • docking equipment 730 may be positioned on both lateral sides of the structure 100, in an embodiment.
  • a "buffer belt" around a periphery of a LNG tank may provide protection against carrier impact.
  • the top slab level of the structure 100 may be determined by structural stiffness requirements and consideration of the LNG tank 110 dimensions.
  • Topsides 750 of the structure 100 may be constructed and/or integrated in a dry dock prior to positioning the structure in a body of water.
  • the structure topsides 750 may be elevated on about 5m high steel module support frames 760.
  • Structure topsides 750 may be elevated for ease of construction. Elevating the topsides 750 of the structure 100 may also allow water to run over the deck 710 under severe weather conditions without substantially submerging equipment, such as heat exchangers 610 and LNG transfer equipment 320, on the topsides.
  • Structure topsides may be elevated for ease of construction.
  • the structure may be designed to accommodate severe weather conditions such as hurricanes, tropical depressions, tsunamis, tidal waves, and/or electrical storms.
  • the structures may include steel modules that raise the topsides equipment at a height above the deck to reduce damage from overtopping waves and/or green water.
  • the structure may comprise one or more platforms positioned on an upper surface of the body wherein the liquefied natural gas transfer equipment is disposed on at least one of the platforms and wherein one or more of the platforms are at a height such that liquefied natural gas transfer equipment disposed on a platform is substantially protected from water running over the body during use.
  • the structure may further comprise one or more platforms positioned on an upper surface of the body wherein the liquefied natural gas transfer equipment is disposed on at least one of the platforms and wherein one or more of the platforms are at a height of at least about 5 meters above an upper surface of the body.
  • Non-linear effects such as wave breaking and interaction of incoming and reflected waves may result in a large vertical jet being formed in front of the structure.
  • the topsides of the structure may be at risk to the standing waves .
  • the structure design may be influenced by the possibility of greenwater traveling at a high velocity over the deck. During hurricane conditions with strong winds, most of the water in the vertical water jet may blow over the deck.
  • a wave deflector on the structure may be effective in reducing the amount of overtopping water. The higher the deflector is located above the water level, the more effective it is in deflecting only the vertical jet, as opposed to the entire incoming wave.
  • Wave deflectors may have a flat vertical face. In some embodiments, wave deflectors have a substantially curved face .
  • a curved steel wave deflector about 2.5 m wide and about 3.5 m high may be installed.
  • the wave deflector may have an indented or notched shape.
  • the wave deflector may be installed over a full length of the structure.
  • the wave deflector may only be installed only on the side of the structure most likely impacted by waves.
  • the structure may include wave deflectors on the exposed sides of the structure.
  • one or more wave deflectors may be coupled to at least a portion of the body wherein at least one of the wave deflectors is configured to reduce a height of waves hitting the body during use.
  • the one or more wave deflectors may comprise a curved barrier extending outward • from one or more sides of the body.
  • the structures may additionally include steel modules that raise the topsides equipment above the deck level. Modules may be positioned at a height above the deck to reduce damage from overtopping waves and/or green water. Excessive wave run-up and passage of green water onto the terminal deck during hurricane conditions may be minimized by the installation of a curved steel wave deflector along one or more exposed sides of the structure.
  • the structure may include docking equipment on one or more sides of the structure. The structure may include one dock. Berthing facilities, dolphins, fenders, and/or cryogenic unloading arms may allow bi-directional berthing of carriers directly alongside the structure. Approximately 15% of the time, the predominant current switches directions (e.g., a southwest current may switch to a northeast current) .
  • Allowing a structure to berth in either direction may increase the efficiency of the structure.
  • the structure may be positioned substantially parallel to the direction of the predominant current.
  • Ship-shore interfaces may be such that carriers can berth and offload directly alongside the structure.
  • docking directly on the structure may avoid the construction of separate berthing and offloading structures.
  • a structure may be configured to allow a carrier to approach the structure without substantially damaging the structure.
  • a LNG carrier may approach the structure with the help of one or more tugboats.
  • a LNG carrier may dock such that the structure substantially protects the carrier from waves.
  • the structure may be configured to provide a breakwater length for a carrier.
  • the carrier When a carrier docks directly on the structure, the carrier may be at least partially protected from waves that impact the structure rather than the carrier.
  • units may be positioned in order to provide adequate breakwater length for LNG carriers .
  • the structure may be constructed in a graving dock location prior to towing and/or floating the structure to a desired location for operation.
  • an air cushion may be used to float the structure. Air may be injected below the projections of the structure to at least partially facilitate floating of the structure .
  • the structure may be moved away from dry dock by means of fixed winches, hauling lines, and/or one or more tug boats.
  • the air cushion may be gradually released as soon as the water depth is sufficient and/or at least partly reinstalled to achieve sufficient under keel clearance for final positioning.
  • it may be desirable to decommission an LNG structure.
  • the structure may be removed from the site to be reused or completely decommissioned.
  • decommissioning may include performing the marine installation in reverse.
  • An LNG carrier may be berthed directly on the structure .
  • the structure may be oriented in the substantially same direction as the predominant current.
  • the berthing may occur some distance from the structure using berthing dolphins .
  • the structure may be configured to have a breakwater function for carriers docked directly on the structure.
  • the structure may include docking equipment configured to allow carriers to dock directly on the structure.
  • the structure 100 may include a first surface 710 where process equipment 610 is located, as depicted in FIG. 3.
  • the structure 100 may have a second surface 720, below the first surface 710, configured to ease docking with a carrier 740.
  • the second surface 720 may be at a height similar to the carrier 740.
  • Docking equipment 320 may be positioned on the second surface 720.
  • the structure may be configured to allow carriers with capacities greater than approximately 125,000 cubic meters to dock. Docking equipment may be approximately 8 m from the structure wall. In some embodiments, no purpose built mooring dolphins and/or breasting dolphins may be required.
  • Navigation beacons may be positioned on the structure.
  • Mooring dolphins to facilitate docking larger carriers or to allow bi-directional docking of carrier may be positioned proximate to the structure. Corner protection piles may be also be installed proximate the structure.
  • the first and second upper surfaces are above the surface of a body of water.
  • the height of an upper surface, such as the second upper surface, above the surface of the body of water may be such that an angle of mooring lines extending from the docking equipment to the liquefied natural gas carrier coupled to the body is less than about 30 degrees.
  • one or more fenders may be positioned about a perimeter of the body. The one or more fenders may be configured to absorb a substantial portion of a load from an LNG carrier colliding with the one or more fenders.
  • the structure may be positioned in a body of water such that the longitudinal axis of the structure is substantially aligned with the predominant current direction.
  • the body has a length that is at least equal to a length required to provide sufficient berthing alongside the body for a liquefied natural gas carrier having a liquefied natural gas capacity of greater than about 100,000 cubic meters.
  • one or more docking platforms may be positioned in the body of water proximate to the body.
  • the one or more docking platforms may comprise docking equipment.
  • the one or more docking platforms may be positioned in the body of water such that liquefied natural gas carriers can dock with the body in different orientations.
  • the docking equipment may be positioned on the body such that an angle of mooring lines extending from the docking equipment to the liquefied natural gas carrier coupled to the body is less than about 30 degrees .
  • the structure may include docking, also referred to as mooring, equipment configured to allow carriers to dock directly on the structure.
  • docking also referred to as mooring
  • Additional mooring dolphins may be positioned proximate an end of the structure to protect a portion of the LNG carrier that extends beyond the structure. Corner protection piles and/or fenders may be also be installed proximate the structure.
  • Structure 100 may include an unloading platform 880, depicted in FIG. 3.
  • the unloading platform 880 elevation may be at a predetermined height 890 above a top surface of the body of water.
  • the unloading platform may be made of concrete. An edge of the platform may protrude over the side of the structure.
  • the unloading platform 880 may support LNG transfer equipment 320.
  • the LNG transfer equipment 320 may offload LNG from an LNG carrier 740.
  • the LNG transfer equipment 320 may include unloading arms 900, also referred to as loading arms. Unloading arms may be Chiksan unloading arms available from FMC Energy Systems.
  • the LNG transfer equipment may include power packs, controls, piping and piping manifolds, protection for the piping from mechanical damage, ship/shore access gangway with an operation cubicle, gas detection, fire detection, telecommunications capabilities, space for maintenance, Emergency Release Systems (ERS) , Quick Connect / Disconnect Couplers (QCDC) , monitoring systems, and/or drainage systems.
  • LNG may be transferred from an LNG carrier to the LNG storage tanks by means of one or more unloading arms, for example, but not limited to, swivel joint unloading arms .
  • the unloading arms may be used for unloading the LNG.
  • One or more unloading arms may be used for returning vapor displaced in the storage tanks back to an LNG carrier.
  • unloading arms may be used for either liquid or vapor service, as required, allowing maintenance of any of the unloading arms .
  • the LNG unloading arms 900 depicted in FIG. 3, may include a fixed vertical riser 910 and two mobile sections, the inboard arm 920 and the outboard arm 930.
  • a flange 940 for connection to a carrier 740 may be positioned proximate an end of the outboard arm 930. Swivel joints may enable the arms and the connecting flange to move freely in all directions .
  • the length of the unloading arm may be designed to accommodate different LNG carrier sizes.
  • Unloading arm length may accommodate the elevation change between a fully laden and an empty LNG carrier, the movement of the ship due to tides and longitudinal and transfer drift, and the elevation of the structure.
  • the design of an unloading arm may be optimized.
  • a length of an unloading arm may be optimized.
  • Unloading arms may be located proximate a center of the structure.
  • Unloading arms may be equipped with an emergency release system and hurricane safe positions. When the connecting flange reaches the limit of its operating envelope, an alarm may sound, the cargo pumps may shut down, and the unloading arm valves may close.
  • the arms will normally be operated from a control panel in a cabinet or control room located on the structure (see 950 in FIG. 3) proximate the arms.
  • the unloading arm riser may remain vertical but the inner and outer arm will be tied-back horizontally.
  • a support frame may secure the horizontal part of the unloading arm.
  • the unloading pipework may slope continuously down to the tanks.
  • the unloading piping system may continuously slope down to at least one tank. Sloping the pipelines towards the tanks may eliminate a need for a ⁇ Jetty' drain drum and associated lines. Pressure control may be used to maintain the LNG unloading line under pressure and to control the unloading flow.
  • Regulation of the pressure may be necessary to prevent tank overpressure and/or vibration within the unloading line.
  • a significant topside inventory of LNG on the structure may be held in the recondenser vessel and pump suction header. Drainage of the system may be by gravity flow back into the tank underneath the recondenser. Residual pressure within the system may at least partially assist the gravity flow back to the tanks .
  • the structure may include one or more emergency safety systems.
  • the LNG unloading operation may cease in a quick, safe, and controlled manner by closing the isolation valves on the unloading and tank fill lines and stopping the cargo pumps of the LNG carrier.
  • Emergency systems may be designed to allow LNG transfer to be restarted with minimum delay after corrective action has been taken.

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  • Engineering & Computer Science (AREA)
  • General Engineering & Computer Science (AREA)
  • Mechanical Engineering (AREA)
  • Civil Engineering (AREA)
  • Structural Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Filling Or Discharging Of Gas Storage Vessels (AREA)

Abstract

Selon l'invention, une structure de stockage de gaz naturel liquéfié de haute mer peut recevoir, stocker et traiter le gaz naturel liquéfié acheminé par des navires transporteurs. Une structure peut être une structure gravitaire comprenant des déflecteurs de vagues. Les déflecteurs de vagues empêchent les vagues qui viennent heurter le flanc de la structure de se répandre sur une surface supérieure de la structure.
PCT/US2004/036000 2003-10-29 2004-10-28 Structure de stockage de gaz naturel liquefie comprenant des deflecteurs de vagues WO2005045306A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US51538803P 2003-10-29 2003-10-29
US60/515,388 2003-10-29

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Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2012076018A1 (fr) * 2010-12-10 2012-06-14 Envision Energy (Denmark) Aps Déflecteur de déferlement de vagues pour éolienne en mer
WO2015039169A1 (fr) * 2013-09-21 2015-03-26 Woodside Energy Technologies Pty Ltd Installation extensible de traitement de gaz naturel liquéfié (gnl)
US9315239B2 (en) 2012-01-31 2016-04-19 Exxonmobil Upstream Research Company Load compensating mooring hooks
WO2021096253A1 (fr) * 2019-11-14 2021-05-20 삼성중공업 주식회사 Procédé de test de cale de gnl, structure en haute mer à laquelle celui-ci est appliqué, et système d'alimentation en azote liquide de structure en haute mer

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GB656945A (en) * 1949-01-14 1951-09-05 Richfield Oil Corp Island for well drilling
US3766583A (en) * 1970-07-02 1973-10-23 Gulf Oil Corp Offshore liquefied gas terminal
US3828565A (en) * 1973-02-16 1974-08-13 Chicago Bridge & Iron Co Offshore liquid storage facility
US4015552A (en) * 1975-08-25 1977-04-05 Korkut Mehmet D Semi-submersible drill barge
GB1486572A (en) * 1973-10-04 1977-09-21 Khd Pritchard Gmbh Floatable vessel
US4579481A (en) * 1983-04-29 1986-04-01 Standard Oil Company Mobile offshore drilling structure for the arctic
US4648749A (en) * 1982-06-11 1987-03-10 Bow Valley Industries Ltd. Method and apparatus for constructing an artificial island
US5292207A (en) * 1993-02-15 1994-03-08 Allen Bradford Resources, Inc. Ice crush resistant caisson for arctic offshore oil well drilling
US5823132A (en) * 1996-09-30 1998-10-20 Donavon; Brooks L. Floating deck
US6371695B1 (en) * 1998-11-06 2002-04-16 Exxonmobil Upstream Research Company Offshore caisson having upper and lower sections separated by a structural diaphragm and method of installing the same
WO2002048602A1 (fr) * 2000-12-15 2002-06-20 Ove Arup Partnership Limited Cuve de stockage de gaz d'hydrocarbures liquefie, comprenant des parois de beton non revetu
US20020174662A1 (en) * 2001-05-23 2002-11-28 Frimm Fernando C. Method and apparatus for offshore LNG regasification

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Publication number Priority date Publication date Assignee Title
GB656945A (en) * 1949-01-14 1951-09-05 Richfield Oil Corp Island for well drilling
US3766583A (en) * 1970-07-02 1973-10-23 Gulf Oil Corp Offshore liquefied gas terminal
US3828565A (en) * 1973-02-16 1974-08-13 Chicago Bridge & Iron Co Offshore liquid storage facility
GB1486572A (en) * 1973-10-04 1977-09-21 Khd Pritchard Gmbh Floatable vessel
US4015552A (en) * 1975-08-25 1977-04-05 Korkut Mehmet D Semi-submersible drill barge
US4648749A (en) * 1982-06-11 1987-03-10 Bow Valley Industries Ltd. Method and apparatus for constructing an artificial island
US4579481A (en) * 1983-04-29 1986-04-01 Standard Oil Company Mobile offshore drilling structure for the arctic
US5292207A (en) * 1993-02-15 1994-03-08 Allen Bradford Resources, Inc. Ice crush resistant caisson for arctic offshore oil well drilling
US5823132A (en) * 1996-09-30 1998-10-20 Donavon; Brooks L. Floating deck
US6371695B1 (en) * 1998-11-06 2002-04-16 Exxonmobil Upstream Research Company Offshore caisson having upper and lower sections separated by a structural diaphragm and method of installing the same
WO2002048602A1 (fr) * 2000-12-15 2002-06-20 Ove Arup Partnership Limited Cuve de stockage de gaz d'hydrocarbures liquefie, comprenant des parois de beton non revetu
US20020174662A1 (en) * 2001-05-23 2002-11-28 Frimm Fernando C. Method and apparatus for offshore LNG regasification

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2012076018A1 (fr) * 2010-12-10 2012-06-14 Envision Energy (Denmark) Aps Déflecteur de déferlement de vagues pour éolienne en mer
US9315239B2 (en) 2012-01-31 2016-04-19 Exxonmobil Upstream Research Company Load compensating mooring hooks
WO2015039169A1 (fr) * 2013-09-21 2015-03-26 Woodside Energy Technologies Pty Ltd Installation extensible de traitement de gaz naturel liquéfié (gnl)
WO2021096253A1 (fr) * 2019-11-14 2021-05-20 삼성중공업 주식회사 Procédé de test de cale de gnl, structure en haute mer à laquelle celui-ci est appliqué, et système d'alimentation en azote liquide de structure en haute mer

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