Background of the Invention Field of the Invention 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.

Distribution and storage of an adequate supply of natural gas are important to the establishment of power generation facilities. Because of the high volumes involved in storing of natural gas, other methods of storing and supplying natural gas have been used. The most common method of storing natural gas is in its liquid state.

Liquefied natural gas ("LNG") is produced when natural gas is cooled to a cold, colorless liquid at-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 be distributed through pipelines to various end users.

One advantage of LNG is that 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.

Summary of the Invention 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.

In a preferred embodiment, the structure further comprises docking equipment disposed on the body, wherein the docking equipment is configured to couple a liquefied natural gas carrier to 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 LNG from an LNG carrier; storing the LNG in one or more LNG storage tanks; and processing the LNG to natural gas using vaporization equipment.

In an embodiment, 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, also referred to as a gravity-based 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.

In one embodiment, an LNG structure includes a body disposed in a body of water. The body at least partially rests upon 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.

In one embodiment, 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. Additionally, 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. In an embodiment, 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. By placing and/or modifying the body to have different elevations for the docking equipment and the other LNG processing equipment, the structure may accommodate LNG carriers directly alongside the structure, in some embodiments, without the use of separate mooring structures. Additionally, fenders may be placed at various positions about the body to protect the body from collisions with LNG carriers. In one embodiment, 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. In one embodiment, projections extend from the bottom of the LNG structure body.

In addition to projections, a system of ballast storage areas, also referred to as 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. In one embodiment, 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.

In one embodiment, 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. In some embodiments, one or more platforms may be at a height of at least about 5 meters above the upper surface of the body. In this manner, the equipment may be protected from water running over the structure during extreme weather conditions. Additionally, wave deflectors may be positioned on at least a portion of the edge of the LNG structure body.

In one embodiment, 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.

Additionally, it is expected that LNG carriers of up to about 200,000 cubic meters in net storage capacity may be available in the future. To be able to accommodate a wide variety of LNG carriers, 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.

In one embodiment, multiple pipelines may be coupled to the LNG structure. Each of the pipelines may connect the LNG structure to different'natural gas pipeline systems. Natural gas may be diverted from one pipeline with bottlenecking or an outage to another pipeline that may accommodate additional flow. Economic dispatching may drive the gas flow to utilize one pipeline to a greater extent than the next pipeline and so forth until all of the gas is sold for the day.

Brief Description of the Drawings Advantages of the present invention will become apparent to those skilled in the art with the benefit of the following detailed description of embodiments and upon reference to the accompanying drawings, in which: 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 an embodiment of docking equipment; and FIG. 5 depicts a top view of an embodiment of the structure.

While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

Detailed Description of the Invention 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.

Figure 1 depicts an embodiment of the LNG structure.

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. In an embodiment, the layout of the structure may be designed to maximize safety of the living quarters.

In some embodiments, living quarters may be positioned on the structure. The living quarters may be positioned proximate an opposite end from the flare and/or vent. In certain embodiments, living quarters on the structure may be positioned to be proximate living quarters on an LNG carrier during unloading. The living quarters may be substantially resistant to fire, blast, smoke, etc. In an embodiment, the living quarters may be positioned on a separate platform in the body of'water.

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.

In an embodiment, the units may be separately towed to an offshore site. The units may be towed together to a site.

In certain embodiments, 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. In certain embodiments, 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. 5 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. 5 are depicted as cylindrical tanks, 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.

In some embodiments, 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. In some embodiments, 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.

For example, in some embodiments comprising two units, 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.

In some embodiments, 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. In some embodiments, 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. In some embodiments, 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.

In some embodiments, 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.

For example, 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. In some embodiments, 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 support apparatus and/or structure utilized to support various processing equipment typically utilized for off- shore production of hydrocarbons, LNG, and the like and combinations thereof. Examples of companies that may be able to provide steel jackets suitable for use in an embodiment of an LNG structure disclosed herein include, but are not limited to, J. Ray McDermott, Inc. (New Orleans, Louisiana or Morgan City, Louisiana) and Kiewit Offshore Constructors, Ingleside (Corpus Christi, Texas).

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 m3) of LNG. In some embodiments, 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. In certain embodiments, the structure may include greater than about 100, 0, 00 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. Currently, 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 m3/h LNG). In certain embodiments, an optimal storage capacity of the structure may be about 180,000 cubic meters.

In some embodiments, 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 m3/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, but not limited to 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. The LNG tank may be cylindrical, rectangular, partially spherical, or irregularly shaped.

In some embodiments, 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. In certain embodiments, tanks may be SPB (Self-supporting Prismatic shape IMO Type "B") tanks commercially available from Ishikawajima-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. In certain embodiments, solid ballasting material may be maintained proximate the tank to avoid water proximate tank walls.

In certain embodiments, 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 tank may include a secondary barrier positioned between the primary barrier and the concrete. In an embodiment, PermaglassTM may form the secondary barrier. 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).

In some embodiments, insulation may be positioned between the primary barrier, such as 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. 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.

In some embodiments, 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 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.

In some embodiments, 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. In an embodiment, the LNG may not contact the roof of a tank. The roof may not be liquid proof. In an embodiment, 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.

In some embodiments, 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. In an embodiment, 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.

In some embodiments, 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. In an embodiment, the primary and secondary insulation space may communicate at the top of the tank to maintain pressure equilibrium.

Between LNG storage tanks and the outer walls and bottom of the structure, a grid of ballast storage areas may be used for ballasting. In some embodiments, 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. In certain embodiments, sand and/or iron ore may be used as solid ballast material. Water drainage and/or monitoring systems may be installed to monitor and regulate water ingress through the external walls of the ballast storage areas.

In certain embodiments, to inhibit water penetration ballast storage areas filled with solid ballast material are positioned next to the LNG storage tank. Solid ballast material in ballasts 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.

In certain embodiments, water ballast may be partially replaced with solid ballast.

In some embodiments, 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.

In some embodiments, projections may at least partially form the foundation for the structure. The projections may provide at least some structural stability to 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 projections. Furthermore, the projections may be arranged to inhibit bowing of the structure while resting on the bottom of the body of water.

In some embodiments, 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.

In some embodiments, no under base grouting may be required after full penetration of the projections. In an embodiment, 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.

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.

The projection dimensions may be selected to be 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 skirt tips. Uppermost soils may have insufficient shear strength and so the projections must at least partially penetrate adequately into the overconsolidated clay.

In some embodiments, under keel clearance may affect the design of the LNG structure. For example, an available channel depth may be about 13.7m. 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/m3. Liapor, Lytag and/or Solite, commercially available lightweight concrete aggregates, may be used in certain embodiments.

In some 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 to minimize the development of holes and imposed deformations on the pipeline proximate tie-in locations for exporting pipelines. 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. z The type and thickness of the scour protection may depend on the velocities at various spots around the structure. In some embodiments, 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"). The normal BOG rate may be about 0.1 % per day of the total storage volume.

In some embodiments, 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. In certain embodiments, BOG may be compressed by a BOG compressor and routed to a recondenser, also referred to as a condenser, that recondenses BOG. In an embodiment, 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. In some embodiments, 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. In certain embodiments, unloading may be delayed when a send-out rate is approximately zero. In an embodiment, 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. In some embodiments, 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.

In some embodiments, a recondenser may process BOG not returned to the LNG carrier. In an embodiment, the recondenser may be stainless steel. The internal vessel of the recondenser may not be inspected. In an embodiment, the recondenser vessel may be externally inspected. In some embodiments, the recondenser may use subcooled LNG to condense BOG. In an embodiment, a recondenser bypass may be used to accommodate higher than expected LNG sendout rates.

The bypass may send BOG to flare or vent systems.

In some embodiments, 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. Then 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.

During the production of natural gas, high-pressure pumps may transfer, LNG from the tanks to one or more heat exchangers, also referred to as heaters or vaporizers. In another embodiment, the LNG may be vaporized at high pressures in the heat exchangers. In one embodiment, the heat exchanger is an open rack vaporizer. In another embodiment, 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. In an embodiment, two or more water inlets may be used. In this manner if one inlet is offline, another inlet may provide water to the structure. In an embodiment, 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. In an embodiment, 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.

The one or more water inlets may be at different heights and locations. In some embodiments, the height and location of the one or more water inlets may be variable by utilizing, for example, but not limited to, one or more flange connections. Providing for a variable or flexible system for the one or more water inlets may help minimize the impact on marine life including, but not limited to, eggs, larvae, plankton, fisheries, and the like and combinations thereof.

In some embodiments, the variable or flexible system for the one or more water inlets may be located on the structure and/or body of the structure, such as, but not limited to, when the one or more water inlets are located on the structure and/or body of the structure.

In an embodiment, 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).

In an embodiment, the crane may be positioned on an elevated top surface of the structure. In some embodiments, 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. In an embodiment, the pressurized cleaning system may include cleaning screens with pressurized water. The pressurized cleaning system may also be used in outlets. A platform above inlets and/or outlets may allow screens to be lifted above water level for maintenance. In some embodiments, 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. In some embodiments, 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.

In certain embodiments, open rack vaporizers vaporize LNG. In some embodiments, 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.

Using a short inner tube at the LNG inlet of the tube bank to extend the initial heat transfer rate over a greater length of the tube, may reduce the chance of ice formation at the point where LNG enters the heat exchanger.

In some embodiments, 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. Some LNG may vaporize during unloading from a carrier 620. Some LNG may vaporize in the storage tanks 110. The vaporized LNG may be called boil-off gas ("BOG").

Some BOG may be returned to the carrier 620 through one or more unloading arms 630. Returning BOG to the carrier 620 may be part of a vapor balance system. In addition to, or in lieu of, passing BOG to the carrier 620, 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 recondensers 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. In some embodiments, 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. In some embodiments, 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.

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. In certain embodiments, 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.

In some embodiments, 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. In certain embodiments, 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.

In some embodiments, 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. In some embodiments, the structure may comprise a water intake system that may be configured to draw water from the body of water and supply water to the vaporization equipment.

In some embodiments, 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, 400m3/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 m3/h LNG). In an embodiment, 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 m3/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.

In some embodiments, 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.

In some embodiments, 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. In an embodiment, 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.

In some embodiments, 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.

In some embodiments, the structure may include facilities for on-site generation of sodium hypochlorite from seawater via electrolysis. 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.

In some embodiments, 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. In an embodiment, 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 for the tank 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. In an embodiment, 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.

The structure may be designed to accommodate severe weather conditions such as hurricanes, tropical depressions, tsunamis, tidal waves, and/or electrical storms. During severe weather conditions, large waves may impact the structure and green water may flow over a deck of the structure. At least one meter of water present on a horizontal face of the structure may be classified as green water. Raising the structure deck level (see, for example, FIG. 3,710), constructing a wave wall, constructing a wave deflector 770, and/or raising topsides 750 on steel modules 760 above green water may decrease the risk of damage to the structure 100 by overtopping waves. 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. Structure topsides may be elevated for ease of construction.

In some embodiments, the structure may include docking, also referred to as mooring, 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 switch directions (e. g. , a southwest current may switches to a northeast current).

Allowing a structure to berth in either direction (i. e. , bi- directional berthing) may increase the efficiency of the structure.

In some embodiments, 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. In an embodiment, 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.

An LNG carrier may approach the structure with the help of one or more tugboats.

In an embodiment, an 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. 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.

In certain embodiments, units may be positioned in order to provide adequate breakwater length for LNG carriers.

In some embodiments, the structure may be constructed in a graving dock location prior to towing and/or floating the structure to a desired location for operation. In an embodiment, 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 re- installed to achieve sufficient under keel clearance for final positioning. In certain embodiments, it may be desirable to decommission an LNG structure. The structure may be removed from the site to be reused or completely decommissioned. In some embodiments, 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. In some embodiments, 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. In certain embodiments, 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.

In some embodiments, 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. In some embodiments, 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. In some embodiments, 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. In some embodiments, 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.

In some embodiments, 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. In some embodiments, 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.

Mooring lines may lead directly from the carrier fairleads to the mooring hooks 850 on the structure 100, as depicted in FIG. 4. Mooring lines may be designed to comply with OCIMF guidelines. In an embodiment, mooring line load forces may be kept below 55% of the Minimum Breaking Load.

Increasing mooring line length by leading lines through fairleads on the structure to remote Quick Release Hooks (QRH) may cause chafing. In some embodiments, mooring line flexibility is in the nylon tail pennant. Increasing a length of the mooring line may not have a substantial impact on a moored ship's operability. Lengthening mooring lines may only improve mooring operability by about 10%.

Monitoring systems may be in place at the berth to detect vessel speed of approach carriers; mooring line loads through strain gauges on QRHs ; and/or pressure monitoring system in air block fenders. Data from the monitoring systems may be centrally collected and displayed in a control room.

The centerline of the unloading arms may be positioned to create a maximum degree of protection for all types of common LNG carriers. In an embodiment, the unloading arms may be positioned such that additional dolphins and/or jackets next to the structure are not necessary for docking.

When berthed alongside a structure, the stern of some LNG carriers may extend beyond an end of the structure.

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. "Overhang"may depend on the manifold eccentricity of the various LNG carrier designs.

Overhang of the ship's stern beyond the structure may also expose the ship to the environmental conditions.

A mooring line length of at least about 15 meters between the outermost compressed fender line and the QRH may ensure the nylon pennant and joining shackle are clear of the ship's fairlead and not subjected to chafing. In an embodiment, the minimum safe working load of each mooring hook may be more than the minimum-breaking load of the strongest mooring line anticipated. In some embodiments, the operational mooring line may not exceed the greater of 2.5 times the winch brake holding capacity or 2500 KN. The extreme mooring load may not exceed the greater of 2.5 times the minimum breaking load line or 3125 KN. The capstan barrel may be at a suitable height to permit safe handling of messenger lines. The QRH-assembly may be electrically isolated from the platform decks. The isolation may provide an electrical resistance of at least about 1 mega-Ohm.

QRHs may be positioned on the structure. QRHs 850 may be located on concrete platforms, as depicted in FIG. 4. The concrete platforms may be attached to a wall of a tank or the structure. In addition to, or in lieu of, concrete platforms, support structures, also referred to as mooring substructures, may be located or positioned directly on the structure or body of the structure for supporting docking or mooring equipment such as QRHs. In some embodiments, the concrete platforms and/or mooring substructures may be located on an upper surface of the structure and/or body of the structure. In some embodiments, the concrete platforms and/or mooring substructures may be located on a second upper surface where the upper surface of the structure and/or body of the structure comprises a first upper surface above a second upper surface. One or more mooring points may be positioned on a dolphin. In some embodiments, substantially all of the mooring points may be positioned on the structure.

The mooring lines may lead directly from the vessel fairleads to the QRHs on the structure. The optimum height of the QRHs may be 13.0 m above the deck. Platforms may be located on ballast tanks. Each platform may be equipped with a triple quick release hook to receive the breast, stern and/or headlines. QRHs may be located on the platform so that the mooring lines may not coincide with the concrete structure. Decks may have rounded edges in front of the mooring hooks to prevent chafing of the mooring lines. The platforms may be accessible from both the top of the structure and the roof of the ballast tanks by means of caged ladders. The caged ladders may be positioned on the rear side of the QRH assembly to prevent stumbling in the vicinity of moored lines.

In some embodiments, one mooring point may be positioned on a separate mooring dolphin off the structure. The QRH may be mounted on a pedestal of the mooring dolphin. In some embodiments, one or more mooring points may be positioned on separate mooring dolphins off the structure. One or more QRHs may be mounted on the pedestals of the mooring dolphins.

The main structure of a mooring dolphin may consist of two vertical steel piles spaced 10 m center-to-center and interconnected by means of a horizontal steel beam. A mooring dolphin may be located at least about 20 meters from the structure. A catwalk may connect the structure and the mooring dolphin.

The distance between tank wall and berthing line may be selected to insure a sufficient mooring line length. Fender support structures 860 may be used between side ballast storage areas 210 and fenders 870 to ensure a sufficient mooring line length, as depicted in FIG. 4. The dotted lines in FIG. 4 indicate a compression of fender 870. The face of fender 870 may be compressed by the mass of the LNG carrier 740. Insufficient mooring line length may cause large variations in horizontal line angles for the various vessels.

A relatively large number of QRH assemblies may be required to minimize angle variations. Insufficient mooring line length may cause large variations in vertical plane.

Although tidal variations, draft variations, and"manifold above waterline variations"are relatively small, insufficient length distance may trigger difficulties in designing acceptable mooring line geometry. QRH levels for the ship's forward mooring lines may be different than the stern mooring lines, due to height difference among LNG carriers. In an embodiment, all QRH assemblies are at the same level. A larger gap between the QRH and outer fender line increases line length and may be favorable. In an embodiment, fender support structures may not be necessary to increase mooring line length.

In some embodiments, docking equipment may include breasting lines and/or spring line mooring points to facilitate docking. The mooring points may include QRHs.

Berthing may require specific angles between the mooring points and the carriers. Breasting line mooring points may be positioned predominantly on the structure. Spring line mooring points may be located on the fender support structures. Spring line mooring points may be substantially parallel to the berthing line. In an embodiment, spring line mooring points may be positioned on the roofs of ballast tanks.

Fenders may be placed on a 5 meter wide support structure to ensure sufficient distance between the berthing line and the QRHs on the structure. In some embodiments, at least six fenders may be used on the structure. In some embodiments, the number of fenders used on a structure may be the number sufficient to substantially avoid contact between the carrier and the structure. The fender support structure may be constructed from concrete and/or steel. In some embodiments, fender support may be a steel conical type structure. The fender support may be connected to the structure by welding it to steel plates that are pre-cast in the structure concrete outer wall. In some embodiments, one or more fenders may be positioned about a perimeter of the body. In some embodiments, one or more fenders may be configured to absorb a substantial portion of a load from a carrier colliding with the fender.

The fender may have a substantially round, substantially oval, substantially square, substantially rectangular, or substantially irregular cross-section. The fender may be an air block fender. The air block fender may be made of rubber. The type of fender used may be based on the absolute energy absorption capacity, reaction force, and material stiffness. In an embodiment, the fender may be a floating pneumatic Yokohama fender. A softer fender may increase the flexibility of the mooring system. A soft fender system may reduce the resultant line forces significantly and may have an effect on the operability of the moored ship. The fender may be able to transfer a friction force of not less than the product of the catalogued fender reaction force at ultimate deflection and a specified design friction coefficient.

Corner protection on the structure may be used to avoid substantial damage from ship impact. During a final approach and berthing operations, the carrier may be guided by tugboats. In order to reduce the risk of damage to the structure, two corner protection devices may be used. The corner protection system may be an integrated system in the structure. In an embodiment, the corner protection system may be freestanding. The corner protection system may be freestanding flexible steel dolphins. If a freestanding pile is hit, there may be no impact on the structure. Piles may be easy to replace and/or repair without interfering with the structure. Additional piles may be more cost effective than constructing a steel space framework. Steel corner protection piles may absorb the accidental impact energy of a typical LNG carrier sailing at about 2 knots, substantially parallel to the berthing line. The piles may be capable of plastic deformation. The piles may be located at least about 7 meters off 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. 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.

In some embodiments, 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. In an embodiment, unloading arms may be used for either liquid or vapor service, as required, allowing maintenance of any of the unloading arms. Between unloading operations, the unloading system may be kept cold by re- circulation of a small quantity of LNG.

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. In an embodiment, 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. In some embodiments, there may be one or more fixed vertical risers and mobile sections depending on the number of LNG unloading arms.

Unloading arms may be equipped with an emergency release system. 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. Automatic disconnection of the unloading arms from the ship manifold may then occur. 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 design of the structure may account for severe weather conditions. To decrease the environmental impact on the slender and flexible unloading arms, the unloading arms may be put in"hurricane resting position"when hurricane conditions are expected. In hurricane resting position, the unloading arm riser may remain vertical but the inner and outer arm will be tied-back horizontally. In some embodiments, a support frame may be positioned behind unloading arms, to secure the horizontal part of the unloading arm by an extra fixation point. In some embodiments, at least a portion of the unloading arms can be positioned in a substantially horizontal position during storage of the unloading arms.

The unloading pipework may slope continuously down to the tanks. In an embodiment, 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. In some embodiments, 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.