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 water intake system for a structure positioned in a body of water comprising one or more water inlets, wherein at least one water inlet comprises a water inlet conduit, and wherein the water inlet conduit comprises a water receiving end and a water dispensing end, wherein the water receiving end of at least one water inlet conduit is positioned at a distance from the structure such that waves reflecting off of the structure do not substantially effect the flow of water into the water receiving end during use.

The invention also provides a water intake system for a structure positioned in a body of water comprising a water inlet, a first water receiving chamber coupled to the water inlet, wherein the first water receiving chamber is configured to receive water from the water inlet, a. second water receiving chamber coupled to the first water receiving chamber, wherein the second water receiving chamber is configured to receive water from the first water receiving chamber, and a filter positioned between the first and second water receiving chambers, wherein the filter is configured to filter water passing from the first water receiving chamber to the second water receiving chamber.

The invention also provides a method of using a water intake system as described herein comprising providing water to one or more water inlets, passing the water from the one or more water inlets to one or more water receiving chambers, and providing the water from the one or more water receiving chambers to one or more pumps.

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 that at least partially rests upon the bottom of a body of water and partially extends out of the body of water.

In one embodiment, an LNG structure 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. In one embodiment, docking equipment may be disposed on an upper surface of the body.

In one embodiment, projections extend from the bottom of the off-shore structure body. The projections may contact the bottom of the body of water, and, in some embodiments, may become at least partially embedded in the bottom of the body of water. The projections may be configured to substantially inhibit movement of the structure due to waves and weather conditions. 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.

Off-shore structures may require water for various processes carried out on the structure, including vaporizing LNG and desalinization for human consumption. A 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 for an offshore structure. The water intake systems may be configured to reduce the amount of sea life and debris that enters the heat exchange vaporization system.

In one embodiment, a water intake system may include a water inlet conduit to deliver water to a water receiving chamber. The water receiving end of the conduit may be positioned at a distance from the structure. In one embodiment, the water receiving end of the conduit is positioned at a distance from the structure such that standing waves proximate the structure do not substantially effect the flow of water into the water receiving end. Water entering the water inlet conduit may be transferred to a water receiving chamber. Filters may be positioned at the water receiving end of the water inlet. The filters may be configured to inhibit sea life and debris from entering the water inlet conduit.

In some embodiments, a water intake system may be at least partially positioned in the body of the structure. The water intake system may include filters. The filters may be configured to at least partially inhibit sea life and debris from entering the water inlet of the water intake system.

Additionally, baffles may be positioned in the water inlet.

The baffles may be configured to substantially minimize the effect of standing waves. Standing waves may be created by the impact of waves against the side of the structure.

In certain embodiments, more than one water-receiving chamber may be used to collect water for the water pumps. In one embodiment, a first chamber may collect water from the body of water through a water inlet. A filter may be disposed along a wall of the first chamber. The filter may separate the first chamber from a second chamber. The second chamber may include one or more baffles configured to reduce the effects standing waves on the intake of water. Water pumps may provide water from the second chamber to one or more heat exchangers.

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. In one embodiment, one or more platforms may be constructed on the upper surface of an off-shore structure. Various LNG storage, transfer, and processing equipment may be disposed on top of platforms. 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.

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 an embodiment of a gabion mattress as scour protection; FIG. 3A depicts a top view of embodiments of the structure and water inlets and outlets; FIG. 3B depicts a side view of an embodiment of a water outlet; FIG. 3C depicts a side view of an embodiment of a water inlet; FIG. 3D depicts a side view of an embodiment of a water inlet; FIG. 4 depicts a top view of an embodiment of an arrangement of water inlets; FIG. 5 depicts a cross-sectional view of a water inlet positioned on a structure; FIG. 6 depicts a cross-sectional view of an embodiment of screens in a water inlet; FIG. 7 depicts an embodiment of a system to clean screens; FIG. 8 depicts a cross-sectional view of water inlets positioned on platforms; FIG. 9 depicts a representation of an embodiment of the vaporization process; FIG. 10 depicts a top view of an embodiment of the structure; FIG. 11 depicts a top view of an embodiment of an arrangement of water inlets; and FIG. 12 depicts a cross-sectional view of a water inlet positioned on a 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.

FIG. 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. The living quarters may not be positioned proximate the heat exchangers and/or recondensers. In certain embodiments, 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. In an embodiment, the living quarters may be designed to inhibit the ingress of gas and smoke.

In an embodiment, 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.

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. 10 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. 10 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 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.

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 100,000 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. 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, 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 may be 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, Permaglass may form the secondary barrier. PermaglassTM may be a polyester/glass 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 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.

The concrete may be equipped with a heating system to maintain a temperature of inner surfaces of concrete walls and slab such that water does not freeze proximate tank components. An Emergency Diesel Generator may be used to heat tank walls. In an embodiment, drainage systems remove water ingress. A piping network may be installed proximate the insulated space to 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 and 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 of the secondary insulation space, as needed.

In some embodiments, LNG tanks may be equipped with automatic continuous tank level gauging, density monitoring, and density measuring. Each level indicator may have high and low alarms and will automatically stop in-tank pumps or unloading operations, as required. A temperature measurement system may be installed in the LNG tanks at various levels. Pressure transmitters may be provided in each tank to control the boil-off gas compressor, the vent system, alarms and to actuate the emergency shutdown system.

The tank pressure relief valves may release to atmosphere via a vent system. Natural gas from the pressure relief valves may be routed to the flare tower.

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.

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. Assuming a water-saturated density of solid ballast material is 3.0 t/m3, 78,400 m3 of sand ballast may be replaced with approximately 40,000 m3 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.

In certain embodiments, to inhibit water penetration ballast storage areas filled with solid ballast material may be positioned next to the LNG storage tank. Solid ballast material in ballast storage areas may maintain a dry condition to avoid water ingress into tank walls. Ballast storage areas 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. The spacing and positioning of the projections may be such that the structure may be at least partially supported on the projections. The projections may be arranged to inhibit bowing of the structure while resting on the bottom of the body of water. In some embodiments, at least some of the projections are arranged in a grid pattern.

In some embodiments, under base grouting may not be required after full penetration of the projections.

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.

Ballast storage areas may be filled such that at least a portion of the projections are embedded in the bottom of a body of water. If the maximum apparent weight of the structure during installation is not large enough to enable a desired penetration of the projections, suction may be used to achieve the required penetration depth. Air trapped in the compartments may be removed to enable further penetration.

In some embodiments, under keel clearance may affect the design of the LNG structure. Lightweight concrete, semi- lightweight concrete, buoyancy caissons, and/or widening the structure base may be used to increase under keel clearance.

Lightweight concrete may have a density of less than about 2000 kg/m3.

In some embodiments, scour protection may be installed to inhibit erosion of a bottom of a body of water proximate the structure. Scour protection may be positioned around the structure. 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 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 sizing of the scour protection may be selected based upon hydrodynamic conditions (e. g. , waves, currents, and LNG carrier propeller jet streams), subsoil data, the geometry of the structure, and/or water depth. Scour protection may be installed based on design code recommendations. In an embodiment, scour protection may substantially affect foundation integrity and/or projection design. The projection design selected may be dependent on the scour protection used in the structure.

The scour protection may be governed by the depth of the granular material in the top layers of the seabed. The granular material depth may anticipate the depth of possible scour holes and consequently the required width of the required scour protection. In an embodiment, the anticipated depth of scour is related to the scour protection width installed proximate the structure. A slope, developed by a geotechnical failure caused by scouring, may be substantially covered by scour protection to stabilize the bottom of the structure.

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. In some embodiments, the scour protection may be substantially square, substantially circular, substantially oval, substantially rectangular, or substantially irregular cross-sectioned. Scour protection may be concrete-or sand-filled mattresses, heavy concrete elements, and/or gabion type solutions. A rock filled gabion-type scour protection mattress may substantially prevent undermining the foundation integrity and/or stability. Below a gabion mattress, a suitable filter material may be applied to prevent washout through transitions and voids in the rock fill of the mattress.

Filter material may be a geotextile and/or a granular filter, such as gravel.

Gabion mattresses consist of steel wire boxes filled with relatively small rocks. The gabion mattresses may be attached to the structure with chains to avoid leakage of small rocks and/or sand. The gabion mattress may be attached to the structure such that the mattress may follow a developing scour hole. An embodiment of the falling apron principle of scour protection is depicted in FIG. 2. The gabion mattress 270 may allow a mattress to self heal scour holes 280. A scour hole 280 may extend to a layer of stiff clay 290 in the bottom 300 of the body of water. The gabion mattress 270 may fall into the scour hole 280 and at least partially protect the bottom 300 of the body of water from further erosion.

Different hydrodynamic phenomena occur at the"long straight"sides of the structure than at the corners and short straight sides. The thickness and rock fill of the scour protection may differ in different areas of the structure. The required thickness of the mattress may be less at the long straight sides than at the corners/short straight side.

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 and/or 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.

During hurricanes, the terminal may be abandoned and gas send-out may cease. 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, a recondenser bypass may be used to accommodate higher than expected LNG sendout rates. The bypass may send BOG to flare or vent systems.

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. LNG may be vaporized at high pressures in the heat exchangers.

In one embodiment, the heat exchanger may be an open rack vaporizer. In some embodiments, the heat exchanger may be 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. Water lift pumps may deliver water to the heat exchangers from a water intake system. 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.

FIG. 3A depicts an embodiment of a water intake system.

The water intake 310 and outlet 320 structures may be at least partially positioned on a bottom of a body of water.

The inlet structures 310 may be positioned relatively close to the structure 100 and outside strong concentrations of currents and waves. One or more outlets 320 of the water intake system may extend from the structure 100. The outlets 320 may not be located proximate the structure 100.

An embodiment of an outlet of a water intake system is depicted in FIGS. 3A-B. An outlet conduit 330 may extend from the structure 100 and release water away from water inlet 310. The outlet 320 may include vertical diffusers 340. The flow rate at the outlet may be relatively low.

Scour protection 350 may be positioned proximate outlet bends and/or connections to the bottom of a body of water.

Scour protection 350 may be positioned proximate the inlets 310, the outlets 320, the structure 100, and/or between the units 180,190 to inhibit erosion. Scour protection along the structure may extend beyond the location of the outlet pipeline to minimize the development of holes and/or imposed deformations.

FIG. 3C depicts an embodiment of an inlet structure of a water intake system. Additional bends in the inlet 310 and/or outlet line may be included at the interface of a buried section of the inlet/outlet and a section running over the scour protection 350 to accommodate differential settlement. In an embodiment, concrete ballast mattresses may couple the water intake conduit to the sea floor. Scour protection may be applied proximate the concrete mattress to inhibit erosion of the ballast mattress.

FIG. 3D depicts an embodiment of an inlet structure of a water intake system. The break in water conduit 380 is to indicate, though not shown, that water conduit 380 may be routed to the vaporization equipment located on an upper surface of the structure and then routed from the vaporization equipment to a water outlet.

In some embodiments, the same scour protection 350 may be used for the long sides 360 of the structure 100 and the inlet structures 310. In an embodiment, a gabion mattress is not installed at the outlets. A standard scour protection may be applied at the one or more outlets. In an embodiment, standard scour protection may include 60-300 kg rocks (0.5 m thick) upon a filter layer of either geotextile or gravel.

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. The water inlet may comprise a water inlet conduit comprising a water receiving end and a water dispensing end.

FIG. 4 and FIG. 11 depict embodiments of water inlets.

The water intake system may include one or more inlets 310.

In some embodiments, identical independent water intake systems may be installed on the structure to have redundancy.

Environmental and/or permitting issues may complicate the introduction of additional intake lines at later stages. In an embodiment, only a single intake line may be installed.

The water inlet 310 structures may be coupled to each other and/or the structure 100 via bridge structures 370.

Water inlets 310 may be coupled via water conduits 380.

Water may enter an opening in the water-receiving end 390 (see FIG. 3C) of the inlet 310. The water-receiving end 390 may be positioned at a distance from the structure 100. In one embodiment, the water-receiving end 390 of the water intake conduit 380 may be positioned at a distance from the structure 100 such that standing waves created proximate the structure do not substantially affect the flow of water into the water-receiving end. Screens may be positioned at the water-receiving end of the water inlet to inhibit sea life and debris from entering the water inlet conduit. Water may flow from inlets 310 via one or more water inlet conduits 380 to one or more water receiving chambers in the structure 100.

Water from the water intake line may flow into an intake collection header. Water may flow from the collection header to a single intake conduit. 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. Screens may be positioned in the water-receiving chamber. Pumps may transfer water from the chamber to heat exchangers and/or other locations. The water inlet conduit may be a cement-lined carbon steel pipeline. One or more of the water-receiving ends may be positioned within a water intake cage. The water intake cage may comprise an intake header. The intake header may be supported above the bottom of the body of water by a support structure. One or more water receiving ends of the inlet conduit may be positioned in the intake header. The water intake cage may surround the water inlet. The water intake cage may be larger than the water inlet. The water intake cage may reduce the velocity of water entering the water inlet.

Scour protection may at least partially circumscribe the water intake cage. The water intake cage may comprise a grating coupled to the intake header. The grating may be configured to inhibit debris from entering the intake header.

The water intake cage may comprise one or more water filters disposed within the intake header. The one or more water filters may be configured to inhibit debris from entering one or more of the inlet conduits. The filters may be for example, but not limited to, screen filters, wrapped wire filters, and the like and combinations thereof. In some embodiments, a water inlet may be positioned above the bottom of the body of water such that sediment at the bottom of the body of water is inhibited from entering the water receiving end during use. The water inlet may comprise an intake header supported above the bottom of the body of water by a support structure and a grating coupled to the intake header.

The grating may be configured to inhibit debris from entering the intake header.

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. Orifices positioned in the inlet may substantially equalize flow among the inlets. In an embodiment, pressure drops across screens may be smaller than pressure drops across the collection header.

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. In some embodiments, the distance of the inlet from the structure may be more than about 0.25 times the wavelength of water. The distance an inlet is positioned away from the structure may be selected to have marginal wave reflection. In an embodiment, the water intake structure may be located at a distance of at least about 50 m from the structure wall.

FIG. 5 and FIG. 12 depict embodiments of an inlet 310 positioned on a vertical wall 400 of the structure 100.

Water inlets may be positioned directly on the surface of the structure. An inlet 310 may be positioned ona surface of the structure 100 below a water level of a body of water. In some embodiments, the inlet 310 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 inlet may reduce the effect of standing waves on a water level in one or more containment regions 410, also referred to as water-receiving chambers.

Baffles may be positioned in openings in the inlet 310 and/or water receiving chambers. In some embodiments, baffles may reduce the effect of wave reflections against the structure and/or on water levels in containment regions and/or the flow in water intake systems. FIG. 12 depicts an embodiment of baffles 415 in an area below water receiving chamber 410. Baffles may reduce the risk of pumps cavitating when a standing wave pulls water from a chamber. In an embodiment, baffles may separate a first water-receiving chamber from a second water-receiving chamber. The level in the second water-receiving chamber may not rapidly change due to the baffles. Maintaining water in the second water- receiving chamber may prevent pump cavitation. Pumps 420 may transfer water from a water-receiving chamber 410 to a heat exchanger or other process equipment. In some embodiments, one or more baffles may be coupled to one or more water inlets. The one or more baffles may reduce the effects of waves on the water entering the one or more water inlets. In some embodiments, one or more baffles may be coupled to a second water-receiving chamber. The one or more baffles may reduce the effects of waves on the water entering the second water-receiving chamber.

In an embodiment, screens 430 may be positioned in inlet 310 and/or water receiving chamber 410 to inhibit impingement or ingress of marine life. A crane 440 positioned on the structure 100 may facilitate maintenance of the water intake system (e. g. , removing screens and/or baffles for maintenance or repair). In an embodiment, the crane 440 may be positioned on an elevated top surface 450 of the structure 100.

In some embodiments, the inlet may have dimensions of about 5m (length) by about 5m (width) by about 3.5m (height).

The intake velocity may be no more than about 0.15 meters-per second (m/s). The intake velocity may be about 0.5 meters per second. The water intake velocity may depend on the diameter of the one or more water inlets. In an embodiment, the inlet velocity may be prescribed by the environmental agencies (e. g.. Environmental Protection Agency). In certain embodiments, the center of the inlet may be located at a height of 1/3 of the depth of a body of water above the bottom of the body of water. The height of the inlet above the bottom of the body of water may be selected to reduce the amount of sand ingress into the water intake system. The height of the inlet may be selected to substantially reduce the impact of the water intake system on marine species. In some embodiments, the height of the water inlet may be positioned at a distance of greater than about 5 meters from the bottom of the body of water. For example, in some \ embodiments, a water-receiving end of at least one water inlet conduit may be positioned at a distance of greater than about 5 meters from the bottom of the body of water.

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.

One or more screens may be positioned in water intake system. Screens may inhibit debris and/or marine life from entering inlet systems. In some embodiments, the mechanical effects of pump impellers in the water intake system may inhibit marine life from entering the system. The screens may be of different sizes and shapes.

Openings of inlets and/or outlets may be barred to prevent entry of large debris. The bars may have a cage configuration. Screens may include a wire mesh'. The screen selected may comply with National Oceanic and Atmospheric Administration recommendations. In an embodiment, screens may prevent an ingress of marine life such as fish. In an embodiment, the screen may be environmentally sensitive.

Screens may be designed to comply with environmental regulations. Screens may prevent marine life and/or sand from falling into the inlet or outlet.

Screens may be aquatic filter barriers as described in U. S. Patent Application No. 10/153, 295, published as US 2003/0010704 Al, entitled"COOLING MAKEUP WATER INTAKE CARTRIDGE FILTER FOR INDUSTRY"to Claypoole et al.. Aquatic filter barriers may include sheets of fine polyethylene/polypropylene mesh fabric.

In some embodiments, wedge wire screens commercially available from Johnson Screens may be used. Wedge wire screens may be cylindrical filters made by winding wire around cylindrical support rods and forming a series of gaps between the wires.

Screens may be a system of one or more vertical screens positioned around inlets and/or outlets. An embodiment of a water intake system with multiple screens is depicted in FIG.

6. One or more screens may be positioned horizontally, vertically, or at an angle in inlets of a water intake system. Water may flow through the screens 430 and into an inlet chamber 460. In an embodiment, all water processed by the screens 430 may flow into a common inlet chamber 460.

Water may exit the inlet chamber 460 via a water conduit 380.

The inlet may be positioned at a distance above a bottom of a body of water.

Screen systems may be periodically cleaned. Screens 430 may be cleaned in place. Valves 470 may isolate a water inlet 310 and screens may be cleaned. Cleaning may include compressed air dislodging debris from the screens. In an embodiment, inlet controller 480 may open an air valve 490 to release compressed air. Compressed air may enter the water inlet 310 and free debris and/or trapped marine life from the screens 430. A compressor 500 may be connected to the air valve 490 to provide compressed air. Air 510 may enter the compressor 500 and be compressed to a desired pressure. In an embodiment, compressed air may be provided from a pressurized canister. A similar system may be used to clean outlets.

FIG. 7 depicts an embodiment of a pressurized screen cleaning system. Prior to activating a pressurized cleaning system 520, the inlet may be isolated. An inlet valve 470 may isolate the inlet 310 from the water inlet conduit 380.

An inlet controller'480 may activate the pressurized screen cleaning system 520 and/or open the air valve 490. The pressurized screen cleaning system 520 may include cleaning the screens 430 with compressed air. Air may be pressurized by a compressor 500. The compressed air may flow into the inlet 310 via the air valve 490. Pressurized air in the inlet may blast debris and/or marine life from the screens 430. In an embodiment, pressurized air may be stored in an air container. Compressed air may flow from the air container to the air valve, as needed.

In an embodiment, the pressurized cleaning system 520 may include cleaning screens 430 with pressurized water. The inlet controller 480 may open a hydroburst valve 540.

Compressed air may flow through the air valve 490 and the hydroburst valve 540 to a water pressurizer 550. Pressurized water may enter the inlet 310 and loosen debris and marine life from screens 430. In an embodiment, an orifice and/or valve may pressurize water instead of compressed air. The pressurized cleaning system may also be used in outlets.

In some embodiments, screens may be removed from the intake or outlet system prior to cleaning as depicted, for example in FIG. 8. In an embodiment, openings in water inlet 310 may be positioned at a height 570 above a bottom of the body of water. Screens 430 may be positioned in the openings. A platform 580 above inlets 310 and/or outlets may allow screens 430 to be lifted above water level 590 for maintenance. In some embodiments, one or more cranes 600 may be positioned above inlets 310 and/or outlets. The one or more cranes 600 may remove and/or position one or more screens 430 from the inlets and/or outlets. The cranes may facilitate cleaning and/or replacing screens. In some embodiments, the water intake system may comprise a compressed air source that may be coupled to the water intake cage. The compressed air source may be configured to supply compressed air to the water intake cage to clean filters disposed within the water intake cage during use. In some embodiments, a crane may be coupled to the water intake cage.

The crane may be configured to remove filters disposed within the one or more water intake cages for cleaning during use.

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, also referred to as heaters or vaporizers. 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. 9. 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 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. 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.

In some embodiments, 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. In an embodiment, 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 may be 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 warme'r temperature. In some embodiments, 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. In certain embodiments, 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. 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. In an embodiment, a single point outlet system may be used. 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 an embodiment, bars across an opening may inhibit debris and/or large objects from entering the outlet system.

In an embodiment, an outlet may be a concrete box with vertical openings. The outlet may be approximately 4m by about 4m in horizontal plane and about 3m high. The outlet opening may be substantially circular. Diameters of openings in the outlets may be selected based on the amount of mixing necessary. Environmental guidelines may regulate the amount of mixing required at outlets. Discharge velocity may also control the diameter of an opening in the outlet. The outlet may be coupled to the structure by an outlet conduit. The outlet conduit may be a Glass fiber Reinforced Plastic (GRP).

Concrete and/or steel outlet conduits may also connect outlets with the structure.

' An outlet may be positioned at least approximately 500 meters from an inlet. 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, an end of at least one water outlet conduit may be positioned at a distance from the water intake system such that water exiting the water outlet conduit does not substantially effect the temperature of water entering the water intake system.

In some embodiments, no spare water outlet system may be constructed. A spare outlet system may not be required. If the water outlet system breaks down, water may be temporarily run directly over an edge of the structure. In an embodiment, a sluice gate may be opened below water level to release water from the structure if the water outlet system is offline.

In certain embodiments, flow controllers may regulate the natural gas send-out flow rates from the heat exchangers.

Flow controllers may include a flow transmitter on the heat exchanger outlet and a control valve on the vaporizer inlet.

If the gas outlet temperature or seawater exit temperature becomes excessively cold, the flow controller may be overridden. Regasification and send-out equipment may be designed for an average throughput of natural gas. In an embodiment, regasification and send-out equipment may be designed for an average throughput of about 7.7 million ton per annum (mtpa) and a peak factor of about 1.2 billion cubic feet per day (2,400 m3/h LNG).

The LNG structure may be designed to permit a rapid start-up of the heat exchangers. Maintaining a small flow of LNG through a heat exchanger on standby may permit rapid start-ups. The use of thermal expansion joints that allow rapid cool down of the LNG inlet line may permit rapid start- ups. In an embodiment, a structure may have one or more spare heat exchangers, such that spare heat exchangers may be used during maintenance and/or repair of other heat exchangers.

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 (2,400 m3/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, 600m3/h LNG). 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.

In certain embodiments, as the gas enters the existing wet associated gas pipelines, it must be above about 21. 1°C (70°F) to avoid hydrate formation. A spare sales gas heater may be installed to heat the send out gas. In an embodiment, demineralized hot water may heat send-out gas.

The natural gas stream may be divided between the pipelines connected to the structure. In an embodiment, each pipeline may have its own pressure reduction station and two or more 10-inch ultrasonic custody transfer meters to accommodate the export flow rate.

In some embodiments, the structure may comprise an export metering system disposed on the body of the structure and coupled to'the vaporization equipment. The export metering system may be configured to monitor the flow of produced natural gas from the structure to an on-shore location. In some embodiments, the structure may comprise a plurality of natural gas transfer pipelines coupled to the vaporization equipment. Each of the pipelines may be coupled to a separate on-shore natural gas pipeline system.

Control of the transfer of natural gas through each of the pipelines may be performed using one or more controllers on the structure.

The gas from all the heat exchangers may be combined in one or more common sales gas headers. The natural gas exiting the heat exchangers may vary in temperature according to the LNG throughput and the seawater temperature. In an embodiment, the send-out gas exit temperature from the heat exchangers may be about 1°C to about 22°C. The sendout gas from the structure must be in excess of about 35°C (at the maximum pressure of 86 bar gauge upstream of the flow control valves) to prevent hydrate formation where the natural gas export lines tie into the wet associated gas pipelines. In an embodiment a maximum gas export temperature may be about 49°C. Gas export temperatures may be regulated by applicable codes. Gas temperature may be controlled using a hot water bypass control loop.

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 regassification rate is expandable. The structure may have a peak sendout rate of about 1.8 bscf/day (3, 600m3/h LNG). 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.

In certain embodiments, as the gas enters the existing wet associated gas pipelines, it must be above about 21. 1°C (70°F) to avoid hydrate formation. A spare sales gas heater may be installed to heat the send out gas. In an embodiment, demineralized hot water may heat send-out gas.

The natural gas stream may be divided between the pipelines connected to the structure. In an embodiment, each pipeline may have its own pressure reduction station and two or more 10-inch ultrasonic custody transfer meters to accommodate the export flow rate.

In some embodiments, the structure may comprise an export metering system disposed on the body of the structure and coupled loathe vaporization equipment. The export metering system may be configured to monitor the flow of produced natural gas from the structure to an on-shore location. In some embodiments, the structure may comprise a plurality of natural gas transfer pipelines coupled to the vaporization equipment. Each of the pipelines may be coupled to a separate on-shore natural gas pipeline system.

Control of the transfer of natural gas through each of the pipelines may be performed using one or more controllers on the structure.

The gas from all the heat exchangers may be combined in one or more common sales gas headers. The natural gas exiting the heat exchangers may vary in temperature according to the LNG throughput and the seawater temperature. In an embodiment, the send-out gas exit temperature from the heat exchangers may be about 1°C to about 22°C. The sendout gas from the structure must be in excess of about 35°C (at the maximum pressure of 86 bar gauge upstream of the flow control valves) to prevent hydrate formation where the natural gas export lines tie into the wet associated gas pipelines. In an embodiment a maximum gas export temperature may be about 49°C. Gas export temperatures may be regulated by applicable codes. Gas temperature may be controlled using a hot water bypass control loop.

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 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. In an embodiment, the structure may produce nitrogen on board.

Fresh water may be needed on the structure. The structure may have water inlet lift pumps that supply seawater for the fresh and potable water systems. The seawater may enter the lift pumps through the water intake system. Seawater may be strained through self-cleaning strainers. The pumps may feed the electro-chlorination unit and a desalination package, including reverse osmosis units.

Potable water may be made from fresh water by a remineralization package. Potable water systems may at least meet the World Health Organization's standard for potable water. 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. Water in the line may be replenished with newly sterilized water by flushing connections and/or long runs of piping.

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 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. The structure may include a first upper surface with LNG transfer equipment and a second upper surface with docking equipment.

The structure may also include a second upper surface below the first upper surface. Docking equipment may couple a liquefied natural gas carrier with the structure. A"buffer belt"around a periphery of a LNG tank may provide protection for the tank against carrier impact.

The structure may be designed to accommodate severe weather conditions such as hurricane, 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, constructing a wave wall, constructing a wave deflector, and/or raising topsides on steel modules above green water may decrease the risk of damage to the structure 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, docking, also referred to as mooring, equipment on one or more sides of the structure may allow a carrier to dock directly on a structure. Berthing facilities, dolphins, fenders, and/or cryogenic unloading arms may allow bi-directional berthing of carriers directly alongside the structure. In some embodiment, the structure may be positioned substantially parallel to the direction of the predominant current.

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.

In certain embodiments, the structure may include docking, also referred to as mooring, equipment configured to allow carriers to dock directly on the structure. 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. Corner protection piles and/or fenders may be also be installed proximate the structure.

Monitoring systems may detect carrier speed; mooring. line loads on QRHs (Quick Release Hooks); and/or pressure in air block fenders.

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.

Structure may include an unloading platform at a predetermined height above a top surface of the body of water that supports LNG transfer equipment. One or more unloading arms, for example, but not limited to, swivel joint unloading arms, may be used to transfer LNG from a carrier to the LNG storage tanks and to return BOG to the 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. Unloading arms may be equipped with an emergency release system and hurricane safe positions. In hurricane resting position, 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. 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 dz 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 restart with minimum delay after corrective action has been taken.