KR20070085611A - Lng transportation vessel and method for transporting hydrocarbons - Google Patents

Abstract

A vessel for transporting liquefied natural gas is provided. The vessel generally includes a gas transfer system for on-loading and off-loading natural gas to and from the vessel at essentially ambient temperature. The vessel further includes a gas processing facility for selectively providing liquefaction and regasification of the natural gas. The vessel also includes a containment structure for containing the liquefied natural gas during transport. The vessel may be a marine vessel or a barge vessel for transporting LNG over water, or a trailer vessel for transporting LNG over-the-road. A method for transporting LNG is also provided, that provides on-loading of natural gas onto a vessel, condensing the natural gas, storing the gas on the vessel in liquefied form, transporting the gas to an import terminal, vaporizing the gas, and off-loading the gas at the terminal.

Description

LNK TRANSPORTATION VESSEL AND METHOD FOR TRANSPORTING HYDROCARBONS

This application claims the benefit of priority in US Provisional Patent Application No. 60 / 625,388, filed November 5, 2004.

Embodiments of the present invention generally relate to hydrocarbon transport. In particular, embodiments of the present invention relate to an integrated design for a liquefied natural gas carrier. Further embodiments of the present invention relate to a method of combining liquefaction, conveying and regasification processes.

Clean burning natural gas has become the fuel of choice in many industrial and consumer markets worldwide. However, natural gas sources are often far from commercial markets that need gas. This means that natural gas is sometimes produced at geographically distant locations and transported across the ocean using large marine vessels.

In order to maximize the gas volume during transport, the gas is liquefied. Liquefied natural gas ("LNG") is formed by cooling a gas containing very light hydrocarbons, such as methanol, to about -160 ° C. Liquefied gas can be stored at atmospheric pressure, in particular in cryogenic tanks arranged in large vessels. Alternatively, LNG can be liquefied at increased pressure and warmer temperatures, eg -160 ° C. or higher in the case of pressurized LNG (“PLNG”). For the purposes of this disclosure, PLNG and LNG will be referred to collectively as "LNG".

Transportation of LNG to the country of import or to the place of import is expensive. In current development, the gas is liquefied at a location near the production site. This means that a huge collection and liquefaction center will be established in the producing country. Alternatively, the liquefaction process may occur on ships or platforms, such as offshore production, storage and unloading (FPSO) ships. From there, hydrocarbon products are loaded on marine transport vessels in liquefied state. Such ships are known as LNG tankers.

As soon as the target country is reached, the LNG product is unloaded at the receiving terminal. The receiving terminal will be on the beach or "near the beach" of the importing country. In some cases, the gas is temporarily cooled and liquefied and kept in the reservoir. Liquefaction can be stored in isolated tanks until a large amount of gas is injected into gas grids or delivered to consumers. In some cases, the cooled gas is transported in isolated containers, in particular behind the trailer, and on the road up to the market. In some cases, imported LNG is "vaporized" into the pipeline for the purchaser.

LNG technology typically requires large investments in capital and resources at shipping and receiving terminals. Each end also requires cryogenic transfer of the liquid. In many locations, natural gas resources represent insufficient quantities to justify the cost of constructing gas liquefaction facilities in the producing country or production site. In addition, cryogenic mass transfer, particularly from FPSO, is difficult. Alternatively, consumer demand at the place of import may not justify the construction of regasification facilities economically. Therefore, there is a need for an integrated vessel that has the capacity to accommodate light hydrocarbon products at the shipping terminal of the producing country and the ability to cool the gas to a liquefied state and then transport the gas to the desired market location. In addition, there is a need for a ship with the ability to regasify light hydrocarbons upon loading to the loading or arrival terminal. Moreover, there is a need for ships traveling on oceans, rivers or roads.

Further information regarding LNG liquefaction, transportation, and / or regasification techniques can be found in U.S. Patent No. 5,878,814 (Breivik et al.), German Laid-Open Patent Publication No. 32 00 958 (Linde AG), and U.S. Patent No. 5,025,860 (Mandrin et al. ), US Pat. No. 6,517,286 to Latchem, International Publication No. 2004/081441 (conversion gas import), US Publication No. 2003/185631 (other than Bliault), International Publication No. 2004/000638 (ABB Lummus Global , U.S. Patent No. 3,766,583 to Phelps, U.S. Patent Publication 2003/182948 to Nierenberg, U.S. Patent Publication 2002/174662 to Frimm et al, and U.S. Patent 6,089,022 to Zednik And others).

First, a method of conveying liquefied natural gas is provided. The method includes loading a substantially gaseous natural gas into a vessel at a first location, cooling the natural gas in the vessel to convert it into substantially liquefied natural gas, storing the liquefied gas in an isolated vessel. Transporting the liquefied natural gas in the vessel from the first position to the second position, heating the liquefied natural gas in the vessel to substantially reconvert to the gaseous state, removing the natural gas from the vessel in the second position. Unloading step. Preferably, the step of cooling the natural gas and the step of heating the liquefied natural gas are each completed using a gas treatment facility. More preferably, the same gas treatment plant is used both to cool (liquefy) natural gas and to heat liquefied natural gas.

Methods for transporting LNG are completed on various vessels. Examples include marine vessels, barges and road trailers.

In another aspect, a method is provided for transporting liquefied natural gas in a vessel. In general, the method comprises providing a gas delivery system for a vessel, loading natural gas, which is essentially gaseous, onto the vessel via the gas delivery system, and optionally treating the gas in the vessel to cool and heat the natural gas. Providing a facility, passing natural gas through a gas treatment facility to cool the natural gas to a lower temperature at which the natural gas is substantially liquefied, and containment in the vessel to receive liquefied natural gas during transportation. Providing a structure.

In addition, a vessel for transporting liquefied natural gas is provided. In one embodiment, the vessel comprises a gas delivery system for loading and unloading natural gas into the vessel in an essentially gaseous state; Optionally (i) cooling the natural gas from a temperature at which the natural gas is in a gaseous state to a lower temperature at which the natural gas is in a substantially liquefied state, and (ii) from the temperature at which the natural gas is in a substantially liquefied state. A gas processing facility for heating said natural gas to a temperature such that gas is converted back to a gaseous state; And a generator for powering the gas treatment facility; And a containment structure for receiving liquefied natural gas during transport.

The vessel may again be some form of hauling vessel, including, for example, a marine vessel, a barge, or a road trailer. When the vessel is a marine vessel, the gas delivery system additionally includes a floated line for fluid communication between the gas treatment plant and the marine jumper. When the vessel is a ground reference vessel, such as a vessel on a trailer, the gas delivery system additionally includes a line for fluid communication between the gas treatment facility and the ground hose.

 In a marine vessel the containment structure may be one or more morse spherical tanks, a membrane tank, or a plurality of pressurized bottles in fluid communication. Under pressure above atmospheric, many bottles hold LNG.

In one aspect, the gas treatment plant comprises at least one heat exchanger in which natural gas is in thermal contact with a heat exchange fluid through a heat exchanger; And at least one fluid movement device. The fluid moving device may be a compressor or a pump.

In one arrangement, the gas treatment plant comprises a first heat exchanger for cooling the natural gas by thermal contact between the heat exchange fluid and the natural gas; A compressor for compressing and temporarily warming the heat exchange fluid therein after passing through the first heat exchanger; A second heat exchanger for cooling the compressed heat exchange fluid therein; And before returning through the first heat exchanger, the natural gas is cooled by providing an expander to depressurize and further cool the compressed heat exchange fluid therein. Alternatively, the gas treatment plant may comprise a first heat exchanger that warms the natural gas by thermal contact between the natural gas and the heat exchange fluid; The natural gas is heated by providing the second heat exchanger which internally warms the heat exchange fluid after passing through the first heat exchanger. The heat exchange fluid transfer device will be a compressor that compresses and further warms the heat exchange fluid after passing through the second heat exchanger and before returning through the first heat exchanger. Alternatively, the fluid moving device is a pump arranged between the first and second heat exchangers to pressurize the liquefied heat exchange fluid.

Preferably, the generator is configured to selectively provide power to propel the vessel when natural gas is stored in the containment structure and to power the gas treatment facility when the natural gas is cooled or heated. Optionally, the vessel may further have an auxiliary compressor to circulate and cool the heat exchange fluid, in order to recondense any natural gas vaporized during transportation or to keep the heat exchange fluid and system equipment cold while the vessel is carrying LNG. will be.

The following figures are provided to assist in understanding the various inventions described herein.

1A shows a top view of the main deck of a fluid carrying vessel. Exemplary vessels are marine vessels. In this figure, the bridge, cargo storage area, and gas treatment facilities can be seen. The cargo storage area represents one or more individual tanks within the liquefied gas containment structure.

1B shows an alternative marine vessel for delivering fluids in a temperature controlled environment. The containment structure of the LNG carrier ship of FIG. 1B is a Morse spherical tank.

1C shows an additional alternative marine vessel for still delivering fluid in a temperature controlled environment. The containment structure of the LNG carrier ship of Figure 1c is a membrane tank. The vessel described is again a marine vessel.

2 is a side view of the vessel of FIG. 1A; The outline of the ship can be seen. In this figure a side view of the containment structure of FIG. 1A can be seen.

3 shows, as one embodiment, a schematic diagram of the gas treatment plant of FIG. 1A. The arrows depict the process by which light hydrocarbons are liquefied.

4A shows another schematic diagram of the gas treatment plant of FIG. 1A. In this figure, the arrows depict the process of regasification of light hydrocarbons.

4b shows an alternative arrangement for the regasification plant of FIG. 4a. In this figure, the arrows depict the process of regasification of light hydrocarbons.

5A depicts an LNG carrying vessel that is a barge. The barge is attracted by the tug boat.

5B depicts an LNG carrier ship that is a trailer ship. The trailer ship is pulled by a rig on the road.

The words and phrases below are specifically defined for the claims and descriptions herein. It should not be defined to expand the terms, but should be given in the broadest sense given by those skilled in the relevant arts as terms reflected in printed publications, dictionaries and / or issued patents.

By "natural gas" is meant a mixture of light hardrocarbon gas or two or more light hydrocarbon gases and containing at least 25 mole percent methane in the hydrocarbon species main component. For example, natural gas will contain methane along with other hydrocarbon components such as, but not limited to, ethane, propane, butane, or isomers thereof. Natural gas is, for example, non-hydrocarbon contaminants such as carbon dioxide, hydrogen sulfide, water, carbonyl sulfide, mercaptans, and nitrogen. contaminant species) may also be included.

"LNG" or "liquefied natural gas" means that natural gas or part is liquefied. The term collectively includes any light hydrocarbon or substantially two or more light hydrocarbon mixtures that are substantially liquefied, comprising at least 25 mole percent methane on a hydrocarbon species molar basis. LNG includes, for example, natural gas induced in a liquefied state by cooling near atmospheric pressure and application of pressures above atmospheric pressure such as "PLNG" and cooling.

"Vessel" means any fluid delivery structure. Unlimited number of ships include marine vessels, barge vessels, or trailer vessels.

"Marine vessel" means a vessel configured to be transported in a large fluid ocean or a large body of water, such as LNG.

"Barge vessel" means a vessel configured to carry a large amount of fluid, such as LNG, through a river or at the sea inlet or bay.

By "trailer vessel" is meant a vessel configured to carry a large amount of fluid, such as LNG, on a trailer. Trailers are attracted by trucks, rigs, and other mechanized vehicles on the road.

 "On-loading" and "off-loading" relate to the movement of the fluid up and down, respectively, relative to the vessel. The term is not limited to the state in which fluid movement is complete.

"Gas transfer system" means a system for loading or unloading a fluid at least partially in a gaseous state. Unlimited examples of features for a gas delivery system include compressors, valves, conduits and pumps.

"Ambient temperature" refers to the prevailing temperature at any particular location.

"Expander" means any device that includes, but is not limited to, expansion valves or turboexpanders and that can reduce pressure in the fluid line.

Some embodiments of the present invention include apparatus and methods for liquefying natural gas. In some embodiments the natural gas comprises a light hydrocarbon gas or a mixture comprising two or more light hydrocarbon gases containing at least 25 mole percent methane. Alternatively, natural gas may comprise at least 40 mole percent methane or at least 70 mole percent methane on a hydrocarbon species basis.

Some embodiments of the present invention include methods and apparatus for liquefying natural gas to form LNG or gasifying it again to convert LNG to natural gas. In some embodiments, the LNG comprises liquefied natural gas or part thereof. LNG includes any light hydrocarbon or substantially two or more light hydrocarbon mixtures that are substantially liquefied, comprising at least 25 mole percent methane on a hydrocarbon species molar basis. Alternatively, the LNG may comprise at least 40 mole percent methane or at least 70 mole percent methane on a hydrocarbon species basis.

In the following a description of the particular embodiments shown in the figures is provided.

1A shows a top view of a fluid carrying vessel 100. The fluid carrying vessel 100 described is a marine vessel. Vessel 100 is particularly formed for transporting liquefied natural gas, or “LNG”, in the ocean or other large body of water. In one aspect, the vessel 100 has a nominal length of 300 meters. The vessel 100 includes a main deck 12 shown in the top view of FIG. 1A.

FIG. 2 provides a side view of the vessel 100 of FIG. 1A. The contour of the vessel 100 can be defined and viewed by a hull 16. The hull 16 is generally below the main deck 12. The hull 16 is preferably provided for a self-propelled "ship-shaped" ship. However, it should be understood that the scope of the present invention is not limited to linear or self propelled vessels.

The marine vessel 100 includes a bridge 20. The bridge 20 is typically in front of or behind the ship. The bridge 20 is seen in the bow of the vessel 100 of FIGS. 1A and 2. The bridge 20 is located on the deck 12 and provides a living space for the ship's high-class sailors and sailors. Bridge 20 also provides navigation and operational control of ship 100. The vessel will also have a navigation system including steering or guiding mechanisms, rudders and means (not shown).

The marine vessel 100 further includes a cargo storage space 30, or "containment structrue" 30. The containment structure 30 is schematically shown in Figures 1A and 2 and is a single "isolated compartment. "contained structure". The containment structure 30 described includes a plurality of vessels 30A formed to hold cryogenic fluid, such as LNG, under pressure. 1A and 2 are each delivered to expose a sample of 30A) The containment structure 30 is not limited to a single “isolated compartment” in which containers 30A can be individually isolated.

The sets of selected bottles 30A are in fluid communication with each other to form a "tank". Bottles 30A have a valve 32 suitable for moving LNG into and out of bottles 30A. In one aspect, 4 inch pipe connections are provided to move the cryogenic fluid into and out of the vessels 30A, although it is understood that other dimensions may apply. The vessels 30A may include cooled natural gas at a temperature of about −160 ° F (−106.7 ° C.) or less, at atmospheric or slightly higher atmospheric pressure to provide liquefaction. In general, natural gas may include natural gas cooled at a temperature of about −190 ° F. (−123.3 ° C.) or less. Alternatively, the vessel may comprise natural gas cooled at temperatures between about -200 ° F (-128.3 ° C.) and 270 ° F (-167.8 ° C.) at atmospheric or slightly higher atmospheric pressure. Vessel 30A may alternatively be stored at a pressure higher than about 150 psi, and at a temperature of about -193 ° F (-125 ° C.) or higher. Alternatively, the vessels may be stored at a pressure ranging from about 250 psi to 450 psi, and at a temperature between about -175 ° F (-115 ° C) and -130 ° F (-90 ° C). Those skilled in the art will understand that the liquefaction temperature of the hydrocarbon will depend on the pressure and the mixture.

The bottles 30A are preferably cylindrical in shape and are typically made of steel material. The vessels 30A here serve as pressure vessels, which are preferably made of steel with walls of suitable thickness. One or more bottles 30A in fluid communication together form a single “tank”.

Various other LNG containment structures are known for offshore vessels. Examples are provided in FIGS. 1B and 1C. FIG. 1B shows the containment structure for the LNG carrier vessel 100B as a plurality of Moss sphere tanks 30B. Exemplary vessel 10 is again a marine vessel. Morse spherical tanks 30B may have a semispherical or elongated in shape, and a diameter of up to 40 m or more. Typically, three to five Morse spherical tanks will be deployed in a single marine vessel. LNG is stored in morse spherical tanks at atmospheric pressure.

1C shows the containment structure 30C for an LNG carrier vessel 100C as a membrane tank. The example vessel 100C is again a marine vessel. The membrane tank is a fluid-waterproof compartment. Spherical or rectangular structures, typically with steel lining (not shown), to provide a tight compartment, which is supported by structurally isolated frames, which hold cargo holds. For example, each membrane tank 30C would be 40 meters by 40 meters at ground plane.

Each described marine vessel 100, 100B, 100C also includes a gas treatment facility. A gas treatment facility 40 is schematically shown and is intended to represent any facility that can selectively cool or heat a fluid, such as natural gas. Preferably, the gas treatment plant 40 will first cool the natural gas from the intrinsic ambient temperature at which the natural gas is in the gaseous state to a lower temperature at which the natural gas is substantially liquefied. This occurs in connection with the procedure for loading natural gas into a vessel, for example vessel 100. In addition, the gas treatment plant 40 will also preferably heat natural gas, in which the natural gas is substantially liquefied, to the intrinsic ambient temperature at which the natural gas is converted back to the gaseous state. This occurs in connection with the procedure for unloading natural gas in the vessel 100, 100B, or 100C.

3 shows a more detailed view of the gas treatment facility 40 as one embodiment. In this figure, the gas treatment facility 40 is installed for cooling, or “liquefying” the fluid. The arrows depict the flow of fluid for the cooling process of natural gas. More specifically, arrow g shows the movement of gas through the gas treatment facility 40 located in the vessel 100, while arrow c shows the pumping action of the coolant to cool the gas to cryogenic temperatures. .

4A and 4B show another schematic diagram of the gas treatment facility 40 of FIGS. 1, 1B and 1C. In these figures, the gas treatment facility 40 is installed to heat or "regasification" the fluid. The arrows indicate the flow of fluid for the treatment of regasification of light hydrocarbons. Arrow g shows the movement of the gas through the gas treatment facility 40 located in the vessel 100, while arrow h shows the pumping action of the heat exchange fluid to warm the gas. 4A and 4B provide alternative gas treatment systems for regasification.

The gas treatment facility of FIG. 3 is an arbitration facility between the storage of LNG in a containment structure 30 for the receipt and transport of natural gas from a field. Similarly, the gas treatment facilities of FIGS. 4A and 4B respectively provide an intervening facility between the loading structure and the import terminal of natural gas from the containment structure 30. In order to accommodate the movement of hydrocarbons loaded and unloaded on ships, a gas delivery system is provided. The gas delivery system is schematically represented by line 50 in FIGS. 3, 4A, and 4B. In practice, the gas delivery system 50 will include a line that provides fluid communication between the gas delivery facility 40 and a line (not shown) outside the vessel 100. For example, when the fluid transport vessel is a marine vessel (such as vessel 100 of FIG. 1A) or a barge (shown in FIG. 5A), the line will be connected to a marine jumper. The marine jumper will preferably float in one piece or fixed to the buoys. When the fluid delivery vessel is a trailer ship (shown in FIG. 5B), the line will be connected to a land hose.

5A shows an LNG transport vessel as barge 500A. Barge 500A is attracted by tug boat 510A. Vessel 500A includes a gas delivery system 502A, a gas processing facility 504A, and a fluid containment structure 506A. Gas delivery system 502A will typically define a hose configured to connect with a marine jumper line (not shown). Barge 500A is preferably pulled by tug 510A. The vessel 500A may be integral with the tug 510A, or preferably separate floating apparaturs that are hitched and unhitched. 5A shows pulling line 501A. Of course, the tug 510A includes an engine and a propeller (not shown). Engines are typically diesel or gasoline powered and operate to drive propellers in water (W). Barge 510A also includes a battery (not shown) for powering an electrical device such as a light. Preferably, gas treatment facility 504A is powered by a battery or engine of tug 510A.

5B shows an LNG transport vessel, such as trailer ship 500B. Vessel 500B includes a gas delivery system 502B, a gas processing facility 504B, and a fluid containment structure 506B. Gas delivery system 502B will typically be defined as a valve and possibly a hose configured to connect with a supply line (not shown). Trailer ship 500B is attracted by rig 510B on the roadway. Trailer ship 500B is disposed in a multi-axle trailer 520B for ground-based transport.

The trailer ship 500B is propelled by being pulled behind the rig 510B, or "truck". Vessel 500B may be integrated with truck 510B, or may be on segregated trailer 520B, which may preferably be pulled and released. The truck 510B naturally includes an engine and a shaft (not shown). The engine is typically diesel or gasoline powered and is operated to drive a shaft that transmits rotational motion to the transmission. Truck 510B also includes a battery (not shown) for powering the electrical device. Preferably, gas treatment facility 504B is powered by a truck 510B engine that reduces device requirements. The engine will drive a generator to generate electrical power for gas treatment facility 504B.

In practice, large quantities of fluid, such as natural gas, are brought from the source to the gathering center. Collection centers may be located above ground, adjacent shore, or offshore. Natural gas is essentially stored at ambient temperature. In the case of the ocean, such as vessels 100, 100B, and 100C, the vessel is offshore and receives natural gas pumped from a gathering facility (not shown) to the vessel via a gas delivery system 50. Natural gas is not stored directly in the containment structure 30 of the vessel 100, but is pumped through the gas treatment facility 40 for liquefaction according to FIG. 3.

Referring to FIG. 3, the gas treatment facility 40 is shown again. Gas treatment facility 40 is used to condense a fluid, such as natural gas. The arrow g depicts the flow of gas upon liquefaction as depicted above.

The gas treatment facility 40 includes a first heat exchanger 42. The first heat exchanger 42 serves to cool the natural gas by thermal contact between the natural gas and the heat exchange fluid. The first heat exchanger 42 provides respective adjacent fluid channels (not shown) for guiding the hydrocarbon and the heat exchange fluid, so that the two channels are in thermal contact with each other. Through this sequence, the heat exchange fluid acts as a coolant flowing through the lines "c".

The gas treatment facility 40 also includes a compressor 44. Compressor 44 receives heat exchange fluid, or coolant, while circulating from the first heat exchanger and compressing the coolant. The process of compressing the coolant also serves to temporarily warm the coolant as it moves through the compressor 44. In one arrangement, the coolant is about 35 ° F. (1.7 ° C.) at the outlet of the first heat exchanger 42 and 300 ° F. (148.9 ° C.) at the outlet of the compressor 44.

The gas treatment facility 40 also includes a second heat exchanger 46. The compressed coolant is cooled in the second heat exchanger 46. Second heat exchanger 46 provides adjacent fluid channels (not shown) through which coolant and coolant fluid flow pass. The coolant fluid acts to cool the coolant through thermal contact. In the environment of a marine vessel, such as vessel 100 of FIG. 1A, the coolant will be abundantly available seawater or air. In the environment of a barge (such as shown in FIG. 5A), the coolant will be fresh water or air. In trailer ships (such as 500B shown in FIG. 5B), the coolant is typically air.

Gas treatment facility 40 also includes an inflator 48. The expander 48 serves to expand the compressed coolant. Inflator 48 may be an expansion valve, a turboexpander, or any other device for inflating fluid. The process of expanding the compressed coolant not only depressurizes the coolant, but also cools the coolant further. In one arrangement, the coolant is about 65 ° F. at the outlet of the second heat exchanger 46 and −170 ° F. at the outlet of the expander 48. The significantly cooled coolant is circulated back through the first heat exchanger 42 which again acts to cool the natural gas. As a result, natural gas condenses to a substantially liquefied state. Therefore, the gas treatment facility 40 of FIG. 3 acts as a liquefaction facility.

Referring to FIG. 4A, the gas treatment facility 40 is shown again. However, in this arrangement, gas treatment facility 40 is used to heat a fluid such as natural gas. Arrow (g) depicts the process of regasifying light hydrocarbons as described above. The arrows are generally guided in opposite directions from the arrows of FIG. 3.

The gas treatment facility 40 again includes a first heat exchanger 42. In this case, however, the first heat exchanger 42 serves to warm the natural gas by thermal contact between the natural gas and the heat exchange fluid. In this sequence, the heat exchange fluid serves to heat the fluid flow through the lines "h". The first heat exchanger 42 provides suitable fluid channels (not shown) and heat exchange fluid for guiding the natural gas in the liquefied state, as a result of which the two channels are in thermal contact with each other. In this sequence, the heat exchange fluid acts to heat the fluid.

After circulating through the first heat exchanger 42, the heat exchange fluid moves to the second heat exchanger 46. The heat exchange fluid bypasses the inflator. In FIG. 4A arrows can be seen not indicative of the flow of fluid through the inflator 48.

In the regasification process shown in FIG. 4A, the second heat exchanger 46 now serves to warm the heat exchange fluid. In this respect, the process of circulating the heat exchange fluid through the first heat exchanger 42 results in the cooling of the heat exchange fluid. The heat exchange fluid is now very cooled at the outlet of the heat exchanger 42. Therefore, the heat exchange fluid warms up in the second heat exchanger 46. The second heat exchanger 46 provides adjacent fluid channels (not shown) through which the heat exchange fluid and the warm fluid flow. The warm fluid acts to warm the heat exchange fluid through thermal contact. In the environment of a marine vessel, such as vessel 100 of FIG. 1A, the warm fluid will be seawater. Alternatively, the warm fluid is fresh water maintained in the vessel at ambient temperature by combustion or other warming processes not shown. Alternatively, the second heat exchanger 46 may be a tank that directly heats and receives fresh water through such as combustion. In the environment of a barge (such as vessel 500A shown in FIG. 5A), or in the environment of a trailer vessel (such as vessel 500B shown in FIG. 5B), the warm fluid may be air or water.

From the second heat exchanger 46, the heat exchange fluid moves through the compressor 44. Compressor 44 compresses the heated fluid and delivers it to the first heat exchanger 42 in a warmer state. As noted above, the process of compressing the fluid also acts to warm the fluid while moving through the compressor 44. In one arrangement, the heat exchange fluid is about 55 ° F. at the outlet of the second heat exchanger 46 and 300 ° F. at the outlet of the compressor 44. The significantly warmed heat exchange fluid is circulated back through the first heat exchanger 42 which again acts to warm the natural gas. As a result, natural gas is vaporized substantially in the gaseous state for loading. Therefore, the gas treatment facility 40 of FIG. 4 acts as a regasification facility.

 Specific temperatures are provided in connection with certain components of the gas treatment facility 40. However, if the temperature of the heat exchange fluid entering the first heat exchanger is low enough to liquefy the natural gas (or other fluid) during the liquefaction process and high enough to vaporize the natural gas (or other fluid) during the regasification process, The scope of the invention is not limited to specific temperatures. However, it should be noted that the gas treatment plant 40 operates more effectively where there is water available for the second heat exchanger 46 that is warm, i.e., 5 ° F or above freezing point. In environments lacking a medium for heating to a suitable ambient temperature, integrated heat exchangers of liquefaction and vaporization are difficult. In this overview, the gas treatment plant 40 may preferably use vaporization means to burn and heat a portion of the natural gas product. The vaporization plants that are combusted will benefit from the integration of facilities such as fuel gas systems and water supply with liquefaction.

As noted above, FIG. 4B shows an alternative arrangement of the gas treatment facility of FIG. 4A. In this figure, the arrows again depict the process of regasifying light hydrocarbons. System 40 'is now shown. In the arrangement of FIG. 4B, the heat exchange fluid is circulated back through the first heat exchanger to warm (“regasify”) the LNG. Regasified hydrocarbons exit gas treatment facility 40 ′ via line 50. As a result, natural gas is vaporized substantially in the gaseous state for loading. Therefore, the gas treatment facility 40 'of FIG. 4B also acts as a regasification facility. Circulating the heat exchange fluid through the first heat exchanger 42 results in cooling of the heat exchange fluid and substantially liquefies the heat exchange fluid. To reheat the heat exchange fluid, the heat exchange fluid is first moved through the pump 49. The pump 49 acts as an alternative fluid movement device facing each other with the compressor 44. It will again be seen that the heat exchange fluid bypasses the inflator 48 again. A pump 49 is provided behind the first heat exchanger 42 to warm and energize the heat exchange fluid. Pump 49 also delivers a liquid heat exchange fluid, ie seawater, to second heat exchanger 46.

In the installation 40 of FIG. 4, the second heat exchanger 46 acts to warm the heat exchange fluid. The second heat exchanger 46 provides adjacent fluid channels (not shown) through which the heat exchange fluid and the warm fluid flow. The warm fluid acts to warm the heat exchange fluid through thermal contact. In the environment of a marine vessel, such as vessel 100 of FIG. 1A, the warm fluid will again be seawater or freshwater warmed through direct combustion. In the environment of a barge (such as vessel 500A shown in FIG. 5A), or in the environment of a trailer vessel (such as vessel 500B shown in FIG. 5B), the warm fluid may be air or water.

From the second heat exchanger 46, the heat exchange fluid returns directly to the first heat exchanger, which again acts to warm the natural gas. In FIG. 4B it will be seen to bypass the compressor 44. Compressor 44 is not optionally used when pump 49 is used. The process of pumping fluid through the pump 44 provides the pressure necessary to purify the heat exchange fluid through the system 40 '.

It can be seen from the arrangement of FIGS. 3, 3a and 4b that substantially the same physical equipment and heat exchange fluids for liquefaction and regasification operations can be used. By modifying the regasification system operation shown in FIG. 3, the same heat exchangers and heat transfer fluid may be used to vaporize the gas via the systems 40, 40 ′ of FIGS. 4A and 4B. This is due to the storage equipment on board the vessel. When the vessel is a marine vessel, if the water temperature is warm at the point of arrival, ie a medium that is above about 5 ° F or above freezing point or which heats any kind of ambient temperature, is available from a source near the position of arrival. If so, it is possible to install the liquefaction and regasification equipment 40 on the vessel, ie vessel 100, in a more cost-effective manner.

In the gas treatment facility 40 shown in FIGS. 3 and 4A, the heat exchange fluid is moved through the system 40 by compression. Compression will be completed by using compressor 44 as the fluid movement device. In the gas treatment facility 40 ′ shown in FIG. 4B, the heat exchange fluid is moved through the system by pumping. Pumping can be completed in connection with the pump 49 as a fluid moving device. Power is provided by the generator to the compressor 44 or to the pump 49 (and other mechanical parts of the gas treatment facilities 40 and 40 '). 3, 4a and 4b the generator 41 is schematically shown.

The generator 41 is preferably an engine. The engine may be gas powered by natural gas from the LNG stored in the containment structure 30 or by gas provided from an independent fuel supply (not shown). Alternatively, the engine may be diesel powered. In this case, a diesel supply (not shown) may be provided to the ship. In the arrangement of FIGS. 3 and 4A, it can be seen that the generator 41 drives the motor 43m. An arrow "e" indicates an electric line that powers the motor 43m. The motor 43m provides mechanical power for operating the propulsion system 43 of the ship, which is schematically shown. Arrow "s" indicates the mechanical shaft going to the propulsion system 43.

The ship propulsion system 43 is preferably integrated with a power system for powering the gas treatment facility 40 or 40 '. Therefore, when the ship is not carrying, the generator will be used to drive the separate motors 44m and 49m (49m is not shown). In turn, the motors 44m and 49m provide mechanical power to the compressor 44 (in the arrangement of FIGS. 3 and 4a and b) or the pump 49 (in the arrangement of FIG. 4b), respectively.

In order for the gas treatment facility 40 to share the generator 41 and the ship propulsion system 43, the power requirements must generally be similar. Similar, single, integrated power plant and electric or hydrocarbon motor propulsion and gas processing power requirements will be installed to provide the power needed for both operations. In this arrangement, the gas compressor 44 and the ship propeller 43 may preferably not be used at the same time to minimize the total amount of power required for the ship. In one embodiment, the generator 41 is a power plant that provides a single variable frequency drive (VFD). The VFD is alternatively used to control the ship's thrusters 43 and to power the cooling motors 44m and 49m. It is understood that the present invention is not limited to how power is shared or transferred between propulsion system 43 and gas treatment facility 40. Other power arrangements can be used, such as the use of a gear box system used for mechanical shafts, or a modification of motor windings.

In another embodiment, the ship's generator 41 will be used for the initial liquefaction of natural gas as described above in connection with FIG. 3. However, a smaller, separate compressor 45 is optionally provided for powering the gas treatment plant 40 in the conveying stage. In this respect, the vaporized natural gas will be captured in the first heat exchanger 42 because the temperature increases within the containment structure 30 during transport. The compressor 45 will be activated by the small auxiliary motor 45m to temporarily activate the condensation process for re-cooling the natural gas without disturbing the ship's propulsion motor 43. The auxiliary motor 45m draws less power from the generator 41. The electric line "e" is shown between the generator 41 and the small generator 45m. Moreover, the mechanical shaft "s" is shown to enter the compressor 45. Finally, a bypass loop "b" is provided to circulate the heat exchange fluid through the compressor 45 which is smaller than the first compressor 44.

The use of a small, auxiliary compressor 45 has many advantages. First of all, this arrangement allows for the reliquefaction of hydrocarbons during transport. This receives a higher boil-off gas rate from the containment structure 30. This also reduces the isolation requirements for cryogenic storage. Moreover, the use of a small, auxiliary compressor 45 keeps the heat exchange fluid and system equipment cold during transport and allows ships to be ready faster to accommodate natural gas when docked at the export terminal for liquefaction. Allow.

In another embodiment, two independent power generation systems are provided. One system operates to power the ship's propulsion system 43, while the other system operates the gas treatment plant 40 along with the miscellaneous treatment equipment associated with liquefaction and vaporization. Such treatment equipment will include fire fighting equipment, gas treatment controls, fluid pumps, and drain valves.

Also provided is a method of conveying liquefied natural gas of a vessel. The vessel may be a marine vessel such as vessel 100 of FIG. 1A, a barge such as vessel 500A of FIG. 5A, or a trailer vessel such as vessel 500B of FIG. 5B. A gas delivery system such as system 50 of FIG. 3 is provided on a ship. Moreover, the containment structure is provided to the vessel for receiving liquefied natural gas. For example, the containment structure is one of the structures shown in FIG. 1A, 1B, 1C, 5A, or 5B. In addition, a gas treatment facility is provided on the ship. The gas treatment facility is the same as facility 40 of FIGS. 3 and 4A or facility 40 'of FIG. 4B and will optionally cool and heat natural gas.

As part of the method, natural gas is loaded onto the equipped vessel at the shipping terminal. Natural gas is loaded via the gas delivery system essentially at ambient temperature and gaseous state. The transport vessel will optionally be integrated with the natural gas production system. The vehicle will provide facilities for receiving the raw fluid from the wall and for treating the fluid with gas, ambient hydrocarbon liquid, and produced water. Production plants benefit and benefit from integration with liquefaction and gasification plants. The conveying means also has a storage capacity for delivering and conveying any surrounding liquid hydrocarbon products made in the production system.

Natural gas flows through the first heat exchanger 42 of the gas treatment facility 40 to cool the natural gas from ambient temperature. Natural gas is brought to a lower temperature in a substantially liquefied state. Therefore, natural gas is "liquefied." The liquefied natural gas is stored in the containment structure 30 and is ready for transportation from the vessel to the arrival terminal.

In the loading process, the ship propulsion system 43 is preferably stationary. The ship's generator 41 diverts power to liquefaction treatment facilities 40. Once the ship cargo is full, the gas treatment system 40 stops and the ship propulsion system 43 moves. The vessel 100 then carries the cryogenic cargo to the arrival terminal.

Upon arrival at the arrival terminal, the gas is unloaded. To unload the gas, it is pumped through the gas treatment facility 40 to heat the natural gas from a temperature at which the natural gas is substantially liquefied to a temperature at which the natural gas is converted into a gaseous state. Natural gas is then unloaded through the gas delivery system 50. While staying at the unloading position, the ship's propulsion system 43 stops again and the cryogenic cargo is regasified to unload from the vessel 100. This optionally enables a generator in which the ship's propulsion system 43 and gas treatment plant 40 are integrated.

Method In one embodiment of the invention, the partially regasified fluid is pumped from the ground to the gas storage device. One example is the salt dome cavern facility. The gas storage device is integrated with the vessel to store pressurized gas unloaded at the gas receiving terminal. The plant can be designed to be sized to allow continuous gas supply at an average rate of delivery between the transmitters. Pressurized gas storage is ideal because cryogenic fluids can be pumped at low cost to storage pressure prior to vaporization rather than with expensive gas compression with storage facilities.

Therefore, it can be seen that the LNG carrier ship is provided, and a method of transporting LNG or other hydrocarbon fluid is also provided. In one aspect, the delivery method combines liquefaction, delivery, and regasification processes. In addition, it can be seen that an integrated system is provided for natural gas delivery.

Conventional gas delivery means require large rates of delivery beyond the economically attractive 25 to 30 year period. As a result, many resources are currently underdeveloped, including less than about five TSCFs (trillion standard cubic feet) of gas. Open technology allows investors to monetize these less hydrocarbon reserves. The three functions of liquefaction, transport and regasification can be integrated into a single re-deployable unit for the cost-effective transport of natural gas. Another method mentioned is that the integration of liquefaction, vaporization and transport means enables the recovery of standardized hydrocarbon resources of other methods and also reduces the overall manpower for operation and maintenance, thus reducing operating costs and required sources. . Ships can monetize less gas resources and are switchable to enable the development of a series of less resources.

Claims (66)

A loading step of loading the vessel with natural gas that is substantially gaseous at the first location; A cooling step of cooling the natural gas in the vessel to substantially convert it into liquefied natural gas; A storage step of storing the liquefied natural gas in an isolated container; A conveying step of conveying the liquefied natural gas in the vessel from the first position to a second position; A heating step of heating the liquefied natural gas in the vessel to convert the liquefied natural gas in the vessel into a substantially gaseous state again; And And unloading the natural gas from the vessel at the second location. The method of claim 1, Wherein said cooling step of cooling said natural gas and said heating step of heating said liquefied natural gas are completed by using a gas treatment facility, respectively. The method of claim 2, The same gas treatment facility is used both to cool the natural gas and to heat the liquefied natural gas. The method of claim 1, And the vessel is a marine vessel. The method of claim 1, And the vessel is a barge. The method of claim 1, And the vessel is a trailer ship on the road. The method of claim 1, The cooling step of cooling the natural gas is completed by using a gas treatment facility, The gas treatment facility, A first heat exchanger for cooling said natural gas by thermal contact between said natural gas and a heat exchange fluid; A compressor for compressing and temporarily warming the heat exchange fluid after passing through the first heat exchanger; A second heat exchanger for cooling the compressed heat exchange fluid; And And an expander to depressurize and further cool the compressed heat exchange fluid prior to returning through the first heat exchanger. The method of claim 1, The heating step of heating the natural gas is completed by using a gas treatment facility, The gas treatment facility, A first heat exchanger that warms the natural gas by thermal contact between the natural gas and a heat exchange fluid; A second heat exchanger that warms the heat exchange fluid after passing through the first heat exchanger; And A liquefied natural gas delivery method comprising a heat exchange fluid transfer device. The method of claim 8, And the heat exchange fluid transfer device comprises a compressor for compressing and further warming the heat exchange fluid after passing through the second heat exchanger and before returning through the first heat exchanger. The method of claim 8, And said fluid transfer device comprises a pump arranged between said first and said second heat exchangers to pressurize said liquefied heat exchange fluid. The method of claim 8, And said second heat exchanger heats said heat exchange fluid by providing thermal contact between seawater and said heat exchange fluid at ambient ocean temperature. The method of claim 8, And said second heat exchanger heats said heat exchange fluid by providing thermal contact between said heat exchange fluid and air. The method of claim 8, And the heat exchange fluid is heated by thermal contact with an intermediate fluid that is itself heated by an external combustion source of the second heat exchanger. The method of claim 8, And the second heat exchanger heats the heat exchange fluid by thermal contact between the heat exchange fluid and a combustion source. The method of claim 7, wherein Wherein said heat exchange fluid comprises light hydrocarbons. The method of claim 8, Wherein said heat exchange fluid comprises light hydrocarbons. The method of claim 1, The cooling step of cooling the natural gas and the heating step of heating the liquefied natural gas are each completed by using a single gas treatment facility, The single gas treatment facility, (a) a first heat exchanger for cooling said natural gas by thermal contact between said heat exchange fluid serving as a coolant and said natural gas; A compressor for compressing and temporarily warming said coolant after passing said first heat exchanger; A second heat exchanger for cooling the compressed coolant; And Before returning through the first heat exchanger, the natural gas is cooled by providing an expander to depressurize and further cool the compressed coolant, (b) the first heat exchanger to warm the natural gas by thermal contact between the natural gas and the heat exchange fluid; The second heat exchanger to warm the heat exchange fluid after passing through the first heat exchanger; And A method of delivering liquefied natural gas, wherein the natural gas is heated by providing a fluid transfer device. The method of claim 17, And the fluid transfer device comprises a compressor for compressing and further warming the heat exchange fluid after passing through the second heat exchanger and before returning through the first heat exchanger. The method of claim 17, And said fluid transfer device comprises a pump arranged between said first and said second heat exchangers to pressurize said liquefied heat exchange fluid. The method of claim 17, Wherein said heat exchange fluid for cooling said natural gas and said heat exchange fluid for heating said natural gas are at least partially different. Providing a marine gas delivery system; Providing the vessel with a gas treatment facility for selectively cooling and heating natural gas; Loading said natural gas in an essentially gaseous state onto said vessel via said gas delivery system; Passing the natural gas through the gas treatment facility to cool the natural gas to a lower temperature that becomes essentially liquefied; And Providing a containment structure to the vessel for receiving the liquefied natural gas during transportation. The method of claim 21, Pumping the natural gas through the gas treatment facility to heat the natural gas from a temperature at which the natural gas is in liquefied state to a temperature at which the natural gas is at least partially converted to a gaseous state; And And unloading said natural gas from said vessel via said gas delivery system. The method of claim 21, And the vessel is a marine vessel. The method of claim 21, And the vessel is a barge. The method of claim 21, And the vessel is a trailer ship on the road. The method of claim 21, The gas delivery system includes a connection for receiving a buoyed line for placing the gas treatment facility in fluid communication with a marine jumper line. The method of claim 21, The gas delivery system includes a connection for receiving a line for placing the gas treatment facility in fluid communication with a hose. The method of claim 21, And said containment structure is a plurality of pressure vessels for maintaining said liquefied natural gas under pressure. The method of claim 21, And the containment structure is one or more morse spherical tanks. The method of claim 21, And the containment structure is a membrane tank. The method of claim 21, The gas treatment facility, At least one heat exchanger in which the natural gas is in thermal contact with a heat exchange fluid through a heat exchanger; And A method of transporting liquefied natural gas in a vessel comprising at least one compressor for compressing the heat exchange fluid. The method of claim 21, The gas treatment facility, A first heat exchanger for cooling said natural gas by thermal contact between said natural gas and a heat exchange fluid; A compressor for compressing the heat exchange fluid after passing through the first heat exchanger; A second heat exchanger for cooling the compressed heat exchange fluid; And A method of transporting liquefied natural gas in a vessel to cool the natural gas by providing an expander to depressurize and further cool the compressed heat exchange fluid prior to returning through the first heat exchanger. The method of claim 21, The gas treatment facility, A first heat exchanger that warms the natural gas by thermal contact between the natural gas and a heat exchange fluid; A second heat exchanger that warms the heat exchange fluid after passing through the first heat exchanger; And A method of transporting liquefied natural gas in a vessel for heating the natural gas by providing a fluid movement device. The method of claim 33, wherein And the fluid transfer device comprises a compressor for compressing and further warming the heat exchange fluid after passing through the second heat exchanger and before returning through the first heat exchanger. The method of claim 33, wherein And said fluid transfer device comprises a pump arranged between said first and said second heat exchangers to pressurize said liquefied heat exchange fluid. The method of claim 33, wherein And the second heat exchanger heats the heat exchange fluid by providing thermal contact between seawater and the heat exchange fluid at ambient ocean temperature. The method of claim 33, wherein And the second heat exchanger is on board a vessel that heats the heat exchange fluid by providing thermal contact between the heat exchange fluid and air. The method of claim 33, wherein And said second heat exchanger is on board a vessel that heats said heat exchange fluid by providing thermal contact between said heat exchange fluid and a combustion source. The method of claim 33, wherein And the heat exchange fluid is in a vessel heated by thermal contact with an interventional fluid that is itself heated by an external combustion source of the second heat exchanger. The method of claim 21, The gas treatment facility, (a) a first heat exchanger for cooling said natural gas by thermal contact between said heat exchange fluid serving as a coolant and said natural gas; A compressor for compressing and temporarily warming said coolant after passing said first heat exchanger; A second heat exchanger for cooling the compressed coolant; And Before returning through the first heat exchanger, the natural gas is cooled by providing an expander to further depressurize and cool the compressed coolant, (b) the first heat exchanger to warm the natural gas by thermal contact between the natural gas and the heat exchange fluid; The second heat exchanger to warm the heat exchange fluid after passing through the first heat exchanger; And A method of transporting liquefied natural gas in a vessel heating the natural gas by providing a compressor for compressing and further warming the heat exchange fluid after passing through the second heat exchanger and before returning through the first heat exchanger. The method of claim 40, Wherein said heat exchange fluid for cooling said natural gas and said heat exchange fluid for heating said natural gas are at least partially in another vessel. A gas delivery system for loading and unloading natural gas into the vessel in an essentially gaseous state; Gas processing equipment; A generator for powering the gas treatment facility; And A containment structure for receiving liquefied natural gas during transport, The gas treatment facility, Optionally (i) cooling the natural gas from a temperature at which the natural gas is in a gaseous state to a lower temperature at which the natural gas is in a substantially liquefied state, and (ii) heating said natural gas from a temperature at which said natural gas is substantially liquefied to a temperature such that said natural gas is converted back to a gaseous state. The method of claim 42, And the vessel is a marine vessel. The method of claim 42, And the vessel is a barge. The method of claim 42, And the vessel is a trailer ship on the road. The method of claim 42, And said gas delivery system comprises a floated line for placing said gas treatment facility in fluid communication with a marine jumper line. The method of claim 42, And the gas delivery system includes a line for placing the gas treatment facility in fluid communication with a hose. The method of claim 42, And the containment structure is a plurality of pressure vessels for maintaining the liquefied natural gas under pressure. The method of claim 42, And the containment structure is one or more morse spherical tanks. The method of claim 42, And the containment structure is a membrane tank. The method of claim 42, The gas treatment facility, At least one heat exchanger in which the natural gas is in thermal contact with a heat exchange fluid through a heat exchanger; And And a fluid moving device for moving said heat exchange fluid. The method of claim 42, The gas treatment facility, A first heat exchanger for cooling said natural gas by thermal contact between said natural gas and a heat exchange fluid; A compressor for compressing and temporarily warming the heat exchange fluid after passing through the first heat exchanger; A second heat exchanger for cooling the compressed heat exchange fluid; And And liquefying the natural gas by providing an expander to depressurize and further cool the compressed heat exchange fluid prior to returning through the first heat exchanger. The method of claim 42, The gas treatment facility, A first heat exchanger that warms the natural gas by thermal contact between the natural gas and a heat exchange fluid; A second heat exchanger that warms the heat exchange fluid after passing through the first heat exchanger; And A method of delivering liquefied natural gas, wherein the natural gas is heated by providing a fluid transfer device. The method of claim 53 wherein And the fluid transfer device comprises a compressor for compressing and further warming the heat exchange fluid after passing through the second heat exchanger and before returning through the first heat exchanger. The method of claim 53 wherein And said fluid transfer device comprises a pump arranged between said first and said second heat exchangers to pressurize said liquefied heat exchange fluid. The method of claim 53 wherein And said second heat exchanger heats said heat exchange fluid by providing thermal contact between seawater and said heat exchange fluid at ambient ocean temperature. The method of claim 53 wherein And the second heat exchanger heats the heat exchange fluid by providing thermal contact between the heat exchange fluid and a combustion source. The method of claim 53 wherein And the heat exchange fluid is heated by thermal contact with an interventional fluid that is itself heated by an external combustion source of the second heat exchanger. The method of claim 42, The gas treatment facility, (a) a first heat exchanger for cooling said natural gas by thermal contact between said heat exchange fluid serving as a coolant and said natural gas; A compressor for compressing and temporarily warming said coolant after passing said first heat exchanger; A second heat exchanger for cooling the compressed coolant; And Before returning through the first heat exchanger, the natural gas is cooled by providing an expander to depressurize and further cool the compressed coolant, (b) the first heat exchanger to warm the natural gas by thermal contact between the natural gas and the heat exchange fluid; The second heat exchanger to warm the heat exchange fluid after passing through the first heat exchanger; And And heating said natural gas by providing a compressor for compressing and further warming said heat exchange fluid after passing through said second heat exchanger and before returning through said first heat exchanger. The method of claim 42, The generator optionally; Provide power to propel the vessel when the natural gas is stored in the containment structure, A method of transporting liquefied natural gas to power the gas treatment plant when the natural gas is cooled or heated. The method of claim 60, Liquefied natural further comprising an auxiliary compressor for circulating and cooling the heat exchange fluid to recondense any natural gas vaporized during transportation or to keep the temperature inside the gas treatment plant cold while the vessel is carrying LNG. Gas delivery method. The method of claim 59, Wherein said heat exchange fluid for cooling said natural gas and said heat exchange fluid for heating said natural gas are at least partially different. Providing a marine gas delivery system for receiving substantially raw fluid from an offshore natural gas production system; Providing a fluid treatment system for separating produced gas from any other produced fluid; Loading the fluid produced from the natural gas production system; Providing a gas treatment facility on the vessel to convert the produced gas into liquefied natural gas; Passing the natural gas through the gas treatment facility to cool the natural gas from ambient temperature to a lower temperature at which the natural gas becomes substantially liquefied; Providing a containment structure in the vessel for receiving the liquefied natural gas during transportation; And Heating the liquefied natural gas to convert the liquefied natural gas in the vessel into a substantially gaseous state again. The method of claim 63, wherein Providing a separate containment structure on the vessel for receiving any produced liquid hydrocarbons during transportation. The method of claim 63, wherein Wherein said gas is in a marine vessel being unloaded into a gas storage device at a shipping location. 66. The method of claim 65, The gas storage device is a liquefied natural gas delivery method in a marine vessel is an underground rock salt gas storage cave.

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