AU2008219346B2

AU2008219346B2 - Sheltered LNG production facility

Info

Publication number: AU2008219346B2
Application number: AU2008219346A
Authority: AU
Inventors: Stuart Mckay
Original assignee: Woodside Energy Ltd
Current assignee: Woodside Energy Ltd
Priority date: 2007-09-28
Filing date: 2008-09-15
Publication date: 2012-06-28
Anticipated expiration: 2028-09-15
Also published as: AU2008219346A1

Abstract

- 23 Abstract A fixed LNG production facility located in a offshore or near shore body of water is described. The production facility comprises a plurality of spaced-apart modules, each 5 module provided with plant equipment related to a pre-determined function associated with the production of LNG, and wherein the modules are positioned within a lagoon defined by a reef, whereby the reef provides shelter for the modules against environmental loads.

Description

SHELTERED LNG PRODUCTION FACILITY FIELD OF THE INVENTION The present invention relates to a fixed offshore or near-shore liquefied natural gas 5 ("LNG") production facility combining upstream gas receiving facilities along with downstream LNG processing facilities offshore. The present invention relates particularly, though not exclusively, to a fixed LNG production facility which is provided with shelter from environmental loads. 10 BACKGROUND TO THE INVENTION Natural gas ("NG") is routinely transported from one location to another location in its liquid state as "Liquefied Natural Gas ("LNG"). Liquefaction of the natural gas makes it more economical to transport as LNG occupies only about 1/600'h of the volume that the 15 same amount of natural gas does in its gaseous state. After liquefaction, LNG is typically stored in cryogenic containers either at or slightly above atmospheric pressure. LNG is regasified before distribution to end users through a pipeline or other distribution network at a temperature and pressure that meets the delivery requirements of the end users. 20 Conventional LNG production from offshore gas fields involves the use of upstream receiving facilities which deliver treated wellhead gas through large diameter gas pipelines to shore, onshore LNG plants, onshore storage terminals and deepwater export terminal jetties. Commonly there is further treatment of the gas onshore. 25 Typically the only offshore treatment is drying and sometimes removal of liquids. Further treatment (removal of acid gases, drying to < 1 ppm water, mercury removal and removal of LPGs to obtain desired heating value) is generally done onshore. These conventional facilities are typically large and the costs associated with building and operating such facilities are significant. One of the most significant development costs 30 associated with conventional onshore LNG production is the cost of laying and maintaining the offshore pipeline that links the offshore gas field with the onshore LNG production facility, some of which can be more than 400 km in length.

-2 Various floating offshore development concepts have been considered in the past that combine upstream receiving facilities along with downstream processing facilities on a singular offshore facility to process stranded gas or associated gas. 5 For example, US Publication Number 2006/0000615 describes a method for developing a sub-sea hydrocarbon field. Sub-sea flow lines convey the natural gas output from a sub-sea oil/gas separator to a Floating Production Storage Shuttle Vessel (FPSSV). Natural gas is liquefied using an LNG Production Facility located aboard the FPSSV, the LNG so produced being stored in storage tanks onboard the FPSSV. When the storage 10 tanks are full, the FPSSV transports the LNG to an onshore terminal. At the onshore terminal, the LNG is re-gasified and a new batch of liquid nitrogen is produced using energy recovered during LNG regasification. US Publication Number 2006/0010910 and US Publication Number 2006/0010911 A 15 each describe methods and systems for transportation of a cryogenic fluid. The system includes a floating liquefaction unit receiving a gas from a source, a shuttle vessel for carrying liquefied gas away from the liquefaction unit, and a floating regasification unit for receiving the liquefied gas from the vessel, regassifying the liquefied gas and providing the gas to a distribution system. The cryogenic fluid is preferably LNG. The 20 floating liquefaction unit is positioned on a body of water and is moored via a connection to a source of natural gas. This source of natural gas may be a direct pipeline connection to natural gas being produced from a well(s), a mobile vessel(s), or to storage tanks. Periodic connections could also be made to land or marine transport vessels carrying storage tanks of natural gas. 25 US Publication Number 2003/0226373 A describes a process and apparatus for exploitation and liquefaction of natural gas in offshore stranded gas reserves. Two ordinary nautical vessels are used to produce, store and unload LPG and LNG. Typical front end gas processing is performed on the first vessel to produce a treated inlet gas 30 stream. The treated inlet gas is transported to the second vessel where the stream goes through liquefaction and storage until the LNG can be offloaded to a transport vessel for shipment. The liquefaction process utilizes two refrigerant cycles that utilize two expanded refrigerants, at least one of which is circulated in a gas phase refrigeration -3 cycle. The refrigerants and the inlet gas stream are transported between the two vessels by the use of piping. US Patent 6,003,603 (Breivik) teaches the use of two ships for the processing and 5 storage of offshore natural gas. The first ship includes the field installation for gas treatment. The treated gas is then transferred in compressed form to an LNG Carrier for conversion to a liquefied form, which is stored on the LNG Carrier. Breivik utilizes a single refrigerant for cooling purposes within the liquefaction process, which is either in a liquid phase or a mixed phase. Once the LNG Carrier storage vessels are full, the LNG 10 Carrier is disconnected from a buoy to which it is attached and sets sail. Another LNG Carrier takes its place to receive the treated inlet gas for liquefaction. The LNG Carrier is required to be seaworthy in order to transport the LNG product from the stranded reserves to facilities for further use. 15 GB Patent 1596330 relates to a process for the production of a liquefied natural gas, preferably offshore, which process comprises the steps of supplying gaseous natural gas to a sea-going vessel which is adapted to store and transport LNG, and passing the said gaseous natural gas and a liquefied gas through a heat exchanger situated on board the said sea-going vessel so that the said gaseous natural gas is liquefied and the 20 said liquefied gas is gasified, the said liquefied gas having a boiling point at atmospheric pressure which is lower than the critical temperature of methane. Liquid air or nitrogen is produced on shore and transported in a tanker to the field. The tanker is equipped with heat exchangers and other equipment for gas liquefaction. At the field are one or more mooring terminals to which the tanker can be moored and connected to a supply of 25 gas from the production facilities, most probably via a subsea flowline, buoy riser, and loading hose. After mooring, gas is admitted to the liquefaction plant on or in the tanker and liquefied by heat exchange with the liquid air/nitrogen. Before its liquefaction each gas has to be pre-treated to remove therefrom impurities, such as water and carbon dioxide, to an extent which is sufficient to avoid blockages. The liquefied gas is then 30 stored in the cryogenic tanks on the tanker until a full or substantial load is achieved. The tanker unmoors and returns to port. Here, LNG is discharged, liquid air/nitrogen reloaded, and the cycle re-commenced. By the use of more than one tanker and mooring terminal, continuous gas liquefaction can be achieved by the field.

-4 International Patent Publication Number W02002/021060 describes a floating plant for liquefying natural gas comprising a barge which is provided with a liquefaction plant, means for receiving natural gas, means for storing LNG and means for discharging LNG. The liquefaction plant includes a heat exchanger in which heat removed when 5 liquefying natural gas is transferred to water. The liquefied natural gas is stored in the barge and it can be discharged into a vessel suitable for transporting the liquefied natural gas to shore. European Patent Publication Number EP130066 relates generally to a method and 10 system for producing natural gas from wells located offshore, and making it available to a terminal installation. This patent describes transporting pressure vessel means mounted on watercraft, which are utilized to recover raw natural gas from shut-in offshore wells. After a discrete batch of raw gas is contained within the transporting pressure vessel means, the watercraft is moved to a processing station, also preferably 15 located on a platform offshore. At the processing station, liquids are separated from the natural gas, and then the natural gas is passed through a dehydrator and compressor before entering a pipeline. In all of these prior art offshore concepts, the LNG production facilities are located on a 20 floating barge or vessel. The limited space onboard such a floating facility requires that the LNG production facility must be designed to fit within the compact footprint of a barge or vessel and is restricted to a particular fixed size. This results in an unacceptable risk being carried. The layout issues are further complicated by some of the equipment being sensitive to motion during different sea states. There are also large 25 loads placed on plant equipment on such barges as a consequence of wave motion or the impact of "green water" upon these floating structures which can cause shutdowns during severe weather conditions. The term "green water" is used to describe at least one meter of water flowing over a horizontal face of an offshore structure. Such floating structures can avoid sever weather conditions by shutting down, being disconnected and 30 sailing away which leads to disruption in production and lengthy start up times. There remains a need to explore alternative designs for LNG production facilities.

-5 SUMMARY OF THE INVENTION According to a first aspect of the present invention there is provided a fixed LNG production facility located in a offshore or near shore body of water, the production facility comprising a plurality of spaced-apart modules, each module provided with plant 5 equipment related to a pre-determined function associated with the production of LNG, and wherein the modules are positioned within a lagoon defined by a reef, whereby the reef provides shelter for the modules against environmental loads. In one form, the reef may be an atoll. The atoll may be a naturally-occurring atoll or a 10 man-made reef or atoll. Preferably, at least a portion of a bottom surface of each module rests upon a portion of a bottom of the lagoon. One or more of the modules may be a gravity based structure. In one form, the gravity based structure may include a ballast storage compartment and 15 one or more liquids selected from the group consisting of: water; condensate; monoethylene glycol; methanol; diesel; demineralised water; diesel; and, LPG, is stored in the ballast storage compartment. Alternatively or additionally, one or more of the modules may have an adjustable ballast such that the module is transportable from a construction location to the second location. 20 In one form, a first and a second module may be linked together using one or more bridges positioned, in use, above the body of water. One or more air fin coolers may be located on the bridges for cooling a refrigerant used to cause liquefaction of a treated well gas. 25 In one form, the plurality of spaced-apart modules may include: a) at least one gas processing module for receiving raw hydrocarbons from a producing well and treating the raw hydrocarbons to remove contaminants therefrom to produce a stream of treated gas; 30 b) at least one liquefaction modules for receiving the stream of treated gas from a gas processing module and liquefying the natural gas to produce LNG; c) at least one storage modules operatively associated with the liquefaction module for receiving and storing LNG; and, -6 d) at least one berthing module including LNG transfer facilities to transfer the LNG from a storage module to an LNG Carrier. In one form, the storage module may comprise at least one cryogenic tank for storing 5 LNG from the liquefaction module and at least one non-cryogenic tank for storing a liquid from the gas processing module selected from the group consisting of: natural gas liquids, condensate, water or LPG. In one form, in use, wellhead hydrocarbons may be delivered to a gas processing 10 modules via a flow line from a wellhead located outside the reef. Preferably, the flow line may be directionally drilled through the reef to reduce environmental impact. According to a second aspect of the present invention there is provided a method of using a LNG production facility described in relation to the first aspect of the present 15 invention, the method comprising the steps of: a) receiving natural gas from a well; b) liquefying the natural gas to form LNG; c) transferring the LNG from a liquefaction module to a storage module; d) storing the liquefied natural gas in the storage module; and 20 e) loading the LNG from the storage module onto an LNG Carrier. According to a third aspect of the present invention there is provided an LNG production facility substantially as herein described with reference to and as illustrated in the accompany drawings. 25 BRIEF DESCRIPTION OF THE DRAWINGS In order to facilitate a more detailed understanding of the nature of the invention several embodiments of the present invention will now be described in detail, by way of example only, with reference to the accompanying drawings, in which: 30 FIG. 1 is a schematic plan view of one embodiment of the present invention; FIG. 2 is a side view of one embodiment of the present invention illustrating the use of horizontal directional drilling to provide a pipeline connecting the gas processing module with the wellhead; -7 FIG. 3 is a process diagram illustrating the use of a plurality of independent construction locations, an assembly location and relocatability of the LNG production facility from a first location to a second location; FIG. 4 illustrates a flow chart for cooling of a refrigerant using one or more 5 fin fan or air fin coolers with fans used to direct the flow of air towards the outside surface of the air fin coolers as the refrigerant passing through the tubes thereof; and, FIG. 5 is a cross-sectional view of two air fin coolers stacked at an angle on a bridge in an A-frame arrangement to maximize the surface area available for cooling for a given footprint size available on the bridges. 10 DETAILED DESCRIPTION OF PARTICULAR EMBODIMENTS Particular embodiments of the present invention are now described. The terminology used herein is for the purpose of describing particular embodiments only, and is not intended to limit the scope of the present invention. Unless defined otherwise, all 15 technical and scientific terms used herein have the same meanings as commonly understood by one of ordinary skill in the art to which this invention belongs. With reference to FIG.1, the present invention relates to a fixed LNG production facility 10 positioned in a body of water 12 at a production location 14, such as an offshore or 20 near shore gas field. The term "fixed" as used throughout this specification means "set in position at a predetermined or prearranged location". It is to be clearly understood that this does not imply that the production facility must remain at a given production location permanently. The production location 14 can be remote offshore or near-shore. The LNG production facility 10 comprises a plurality of spaced-apart modules 16, each 25 module having a pre-determined function associated with the production of LNG. The modules are positioned within a lagoon 18 defined by a reef 20 whereby the reef 20 provides shelter for the modules 16 against environmental loads. The natural harbor provided by the reef 20 overcomes the need to disconnect the 30 modules 16 during severe weather conditions, such as a cyclone, a hurricane, a tropical depression, a tsunami or tidal wave, and/or an electrical storm. The modules 16 are is in this way able to be designed to withstand lower environmental loading which leads to a reduction in costs and downtime. The reef can be naturally-occurring or man-made and -8 can be stand-alone or form a portion of an atoll. The term "atoll" as used throughout this specification, refers to a ring-like coral island enclosing a lagoon. The LNG production facility 10 includes at least the following modules: 5 a) at least one gas processing module 22 for receiving raw hydrocarbons from a producing well and treating the raw hydrocarbons to remove contaminants therefrom to produce a stream of treated gas; b) at least one liquefaction module 24 for receiving the stream of treated gas from a gas processing module 22 and liquefying the natural gas to produce LNG; 10 c) at least one storage module 26 operatively associated with the liquefaction module 24 for receiving and storing LNG; and, d) at least one berthing module 28 including LNG transfer facilities 30 to transfer the LNG from a storage module 26 to an LNG Carrier 32 on an as-needs basis. 15 Other additional modules may be included in the fixed LNG production facility 10 of the present invention. Advantageously, utilities may be shared using a separate spaced apart utility module 34 which acts as a hub servicing some or all of the other modules in the LNG production facility 10. Alternatively, each other module 16 may be associated with its own separate utility module 40. The utility module 34 provides such services as 20 power, potable water, compressed air, nitrogen, and heated water to the liquefaction module 24 and/or the gas processing module 22. When the LNG production facility 10 is manned, accommodation for the personnel may be provided on the gas processing or liquefaction modules 22 and 24 respectively, or a separate spaced-apart accommodation module 36 can be used for greater safety. A supply system 38 in the 25 form of piping and associated pumps, manifolds and valves, etc is also provided for transferring treated gas from a gas processing module 22 to a liquefaction module 24 and for transferring LNG from a liquefaction module 24 to a storage module 26. The water depth within the lagoon may be in the range of 2 to 50 meters, preferably 10 30 to 35 meters, more preferably 15 to 30 meters or 2 to 20 meters. The berthing module water is arranged in water that is at least deep enough to allow passage of an LNG carrier into and out of the lagoon.

-9 In the embodiment illustrated in FIGS. 1 and 2, the modules 16 are gravity based structures such as a steel or concrete barge or "brick" positioned within the lagoon 18 such that at least a portion 40 of a bottom surface 42 of the module 16 rests upon the sea floor 44. By way of example, the gravity based substructure can be constructed 5 using lightweight or semi-lightweight concrete (having a density of less than about 2000kg/M 3 ). Gravity based structures are used for maximum stability to maximize the operational availability of each module 16 during extreme weather conditions. This results in significant savings over the costs which would otherwise be incurred during a weather-induced shut down. The sub-structure of the modules 16 can be constructed 10 using sub-modular construction and assembly with the topside equipment arranged on that substructure as described in greater detail below. With reference to FIG. 3, the modules 16 can be separately constructed at one or more independent construction location(s) 50 and then transported to the production location 15 14, where the modules are installed and then operatively linked to produce and store LNG. Constructing the modules 16 at a plurality of separate independent construction locations 50 provides a number of advantages over prior art methods. Construction of each type of module can occur at different construction locations to take advantage of expertise of different suppliers located at different construction locations. Similarly, 20 construction can occur at different times to allow overall construction time to be fast tracked. For example, the construction of the liquefaction modules can take place in the Middle East, with construction of the storage modules taking place in South East Asia and the construction of the gas processing module can occur in Australia, all to service the needs of a production location off the coast of Africa or the Gulf of Mexico. 25 Each module 16 may comprise a plurality of similarly-sized sub-modules 52, which can be integrated at the production location or at an independent assembly location 54. The sub-modules 52 may be constructed a separate construction locations 50 and towed to a common assembly location 54 for integration. This option is particularly attractive if 30 there is a restriction on the space available at the dry dock or "graving dock" or restrictions on the towable or installable size of a given module. Advantageously, once the sub-modules 52 have been assembled to form a module 16 at the assembly location 54, testing or commissioning of the module 16 can be conducted before transportation of - 10 the module to the production location 14. It is particularly advantageous when such commissioning can be done at an assembly location onshore prior to transportation of the module to a production location offshore. 5 The present invention provides significant advantages over prior art offshore LNG plants in terms of flexibility. The modular construction allows for additional modules or sub modules 52 to be added or removed, if applicable due to late changes to the process functionality. The number and size of the various modules 16 and/or sub-modules 52 can be tailored to suit the changing needs of a particular site or to suit the changing flow 10 from a reservoir over its production life cycle of a gas reservoir - for example, the number of liquefaction modules 24 may vary from time to time. The flexibility of the LNG production facility 10 of the present invention allows economic exploitation of small offshore gas fields that would otherwise not be developed. This significantly increases the number of gas reserves around the world that can be developed as LNG, particular 15 those that are far from the mainland or those which would require onshore plants with significant civil engineering, environmental or social challenges. Moreover, the operating capacity of the LNG production facility 10 may change over time based on a number of factors including depletion of hydrocarbons in the field over time, 20 changes in the storage capacity of the LNG Carriers into which the LNG produced at the production facility is loaded, the desired peak production capacity of the production facility, the rate at which LNG from a storage module is transferred to an LNG Carrier, and/or costs associated with operating the LNG production facility. Additional storage modules 26 may be added at a latter date if it becomes apparent that production is 25 higher than anticipated or loading schedules are longer than anticipated. In some cases, the production capability need only be small, for example, in the range of one to two million tonnes a year. When supply of gas at a particular location diminishes or increases or stops, the size and location of the modular LNG plant can change to suit the change in conditions. 30 In one embodiment, the modules 16 are transportable in that they are movable from the construction location(s) 50 to the production location 14 by towing or on floating barges. This feature not only allows the modules to be deployed where required but is also - 11 advantageous when maintenance or upgrading is required. To reduce frictional drag on the modules 16 during transport, the bow section of the substructure of the module 16 can be shaped (in an analogous manner to the bow of a ship). 5 The various modules 16 can equally be re-deployed at different locations at different times to suit LNG supply and demand. Similarly individual modules 16 or sub-modules 52 can be moved to another location where demand is higher. In one embodiment, individual modules 16 or sub-modules 52 can be reused or relocated or replaced at a point in time when they are no longer required due to changes in the capacity of the 10 production facility 10 or towards the end of the field life. Thus with reference to FIG. 2, one or more of the modules 16 can be moved from a first production location 14' to a second production location 14". Combining the upstream gas receiving facilities and the downstream LNG processing 15 facilities at a single production location has a number of advantages. Firstly, the need to install, operate, maintain and pay tariffs on an expensive gas pipeline to shore is removed, making production of stranded gas fields economically feasible. More importantly, combining these facilities at a single production location provides a number of synergistic benefits. The upstream and downstream facilities are able to share 20 personnel, consumables and power to reduce overall operating costs associates with the LNG production facility. A common utility module 34 is used to provide power to both the gas processing module 22 and the liquefaction module 24 to reduce overall sparing. Similarly, the common utility module 34 is arranged to distribute air, water and nitrogen between the gas processing 22 and liquefaction module 24. Excess heat from power 25 generation associated with the utility module 34 can be used to provide heating to the MEG (monoethyleneglycol) recovery system. In one embodiment, each transportable module 16 is towed from the construction or assembly location 50 or 54 respectively, to the production location 14 and then arranged 30 in a suitable pre-determined position to suit the needs of the LNG production facility 10. If the pre-determined position is located in shallow water, settling is achieved by adjusting the ballast or buoyancy of each transportable module 16, for example through the addition of water, iron ore or other suitable ballasting material. The transportable - 12 modules are settled into the shallow water such that at least a portion 40 of the base 42 of each module 16 rests on the sea floor 44 to secure the position of the module 16. This provides the modules 16 positioned within the lagoon 18 with maximum stability. To facilitate the ballasting process, the modules 16 are provided with a ballast storage 5 compartment 60 arranged around the periphery or toward the base 48 of the module 16 for ballasting. In use, the ballast storage compartment 60 is at least partially filled with solid and/or liquid ballast material. For example, in certain embodiments, sand and/or iron ore may be used as solid ballast material. The amount of ballast required to secure the shallow water modules depends on a number of relevant factors including but not 10 limited to the shear strength of the underlying clay or silt material found at the bottom of the body of water. In one embodiment of the present invention, water, condensate, monoethylene glycol (MEG), methanol, diesel, demineralised water, diesel, LPG or combinations thereof are 15 stored in the ballast storage compartments 60 to supplement the permanent liquid or solid ballast used to ground the module 16 positioned within the lagoon 18. This reduces the number of additional storage tanks which would otherwise be needed and allows much larger quantities of the liquids to be stored at the LNG production facility 10 (enhancing facility operability) at minimal extra cost. 20 For best results, the liquefaction module 24 should be positioned as close as possible to the wellhead 62 allowing for an increase in throughput through the liquefaction module 24, compared the prior art in which the gas pressure is reduced during transport of treated natural gas through a pipeline to an onshore LNG plant. Another advantage of 25 receiving gas at wellhead pressures is that as the pressure of the reservoir drops over its life, less compression of the gas is required to remove residual gas from the reservoir. It is advantageous for the gas processing module 22 to positioned as close as practical to the liquefaction module 24 to minimize any drop in pressure after the treated wellhead gas has been cooled and to overcome the need to provide additional pumping capacity 30 to transport treated wellhead gas from the gas processing module 22 to the liquefaction module 24. An exemplary example of embodiments of the fixed LNG production facility of the - 13 present invention are now described with reference to FIG. 1 and FIG. 2 for which like reference numerals refer to like parts. It is to be understood that the specific number of each type of module may vary depending on such factors as the production location geometry, the quality of the wellhead gas, the production capacity of the LNG production 5 facility and may also vary over the production life of the field. In the embodiment illustrated in FIG. 1, the fixed LNG production facility 10 which includes two gas processing modules 22 for conditioning the wellhead gas, two liquefaction modules 24 for liquefying treated natural gas to form LNG, a single utility 10 module 34 including power generation, two storage modules 26 for receiving and storing LNG from the liquefaction modules 24, one berthing module 28, two spaced-apart flares 46 and a supply system 38. In this embodiment, the accommodation module 36 is spaced-apart at a safe distance from both the gas processing module 22 and the liquefaction module 24 and the flares 46 to maximize safety. 15 In FIG.1 the contours of the production location 14 are such that the wellhead is positioned outside the reef 20, with the gas processing modules 22, the flares 46, the utility module 34, the accommodation module 36, the liquefaction modules 24 and storage modules 26 being concrete gravity based structures positioned within the lagoon 20 18. It is equally possible for the wellhead 62 to be positioned within the lagoon 18 or for the production location 14 to include at least one wellhead 62 outside of the lagoon 18 and at least one wellhead 62 inside the lagoon 18. In this embodiment, the plurality of spaced-apart modules 16 are linked by bridges 48, the bridges 48 being elevated at a clearance of at least 20 metres, at least 25 metres or 25 at least 30 metres above the slash zone. The bridges 48 perform various functions. They can be used as walkways or used as roadways to facilitate vehicle access between the spaced-apart modules 16. More advantageously, when the supply system 38, including piping and associated pumps, instrumentation, manifolds and valves etc are arranged on the bridges 48, several benefits are realised. Firstly, locating the supply 30 system above the splash-zone means that the supply system 38 is exposed to a marine environment which is less severe than a sub-sea environment, leading to a reduction in costs as materials of construction. For example, carbon steel piping painted with marine grade paint can be used instead of more expensive stainless steels. Secondly, locating - 14 the supply system above the splash zone leads to reduced costs associated with maintenance and inspection operations given that maintenance and inspection are easier to perform in a marine environment than a sub-sea environment. For example, maintenance can be carried out using floating barge cranes (not shown) which are 5 manoeuvrable along the bridges 48. Thirdly, arranging the supply system 38 on the bridges 48 leads to a reduction in the impact on the sub-sea environment which occurs when trenching is used to lay sub-sea pipelines. The bridges 48 are able to be constructed on site using a plurality of prefabricated 10 sections. The sections are constructed to accommodate thermal expansion in use. In one embodiment of the present invention, the prefabricated sections include sections of piping which can be joined together on-site. In use, wellhead hydrocarbons are delivered to the gas processing modules 22 via a flow 15 line 84 from a wellhead 62 located outside the reef 20. Prior to entry into the flow line 84, the wellhead hydrocarbons may be passed through a sub-sea slug-catcher 64 to allow removal of condensate to ensure a steady flow of gas entering the gas processing modules 22. To gain entry into the lagoon 18 with minimal impact on the reef 20, the flow line 84 is directionally drilled or directionally bored through the reef 20 at an angle of 20 incline relative to the sea floor 44. Directional drilling is a steerable, trenchless method of installing the subterranean flow line 84 along a prescribed path with minimal impact on the surrounding area to minimize environmental disruption. A pilot hole is drilled first, along the prescribed path, which is then enlarged using a reaming tool (not shown) to allow placement of the flow line within the enlarged hole, with casing installed if desired. 25 The gas processing modules 22 include a separator for effecting initial separation of natural gas from particulates, natural gas liquids (NGL) and condensate. The NGL and condensate streams can be subjected to further fractionation to produce LPG or for use as refrigerants, if desired. 30 The separated natural gas is then subjected to conditioning on the gas processing modules 22 to remove contaminants prior to liquefaction. More specifically, hydrogen sulphide and carbon dioxide can be removed using a suitable process such as amine - 15 absorption. When amine absorption is used, the absorber and regeneration equipment are located on the gas processing modules 28. The heat required for amine regeneration is taken from waste heat from gas turbines used to drive LNG train compressors. Advantageously, due to the proximity of the reservoir, the carbon dioxide 5 so removed can be dewatered, compressed, liquefied and re-injected into the reservoir to reduce greenhouse gas emissions. The natural gas is subjected to further conditioning to remove water and other contaminants, such as mercury and heavy hydrocarbons prior to liquefaction. Removal of water can be achieved using conventional methods, for example a molecular sieve. 10 The treated natural gas from the gas processing modules is delivered to one or more liquefaction modules 24. The liquefaction module is designed to receive natural gas from the gas processing module and liquefy the natural gas to produce LNG which is sent out to the storage module(s). Liquefaction is achieved onboard each liquefaction 15 module using methods of well established in the art which typically involve compression, expansion and cooling. Such processes include processes based on a nitrogen cycle, the APCI C3/MRm or Split MRWm or AP-Xm processes, the Phillips Optimized Cascade Process, the Linde Mixed Fluid Cascade process or the Shell Double Mixed Refrigerant or Parallel Mixed Refrigerant process. 20 Regardless of the choice of liquefaction process, a refrigerant is used to reduce the temperature of the treated wellhead gas to a temperature of around -160 0 C to form LNG, resulting in warming of the refrigerant to a temperature in the order of 70*C. In the embodiment illustrated in FIG. 5, the refrigerant is cooled using one or more fin fan or air 25 fin coolers 66 from a temperature in the order of 70 0 C to a temperature in the order of 30 0 C. One or more fans 68 are used to direct the flow of air towards the outside surface of the air fin coolers 66 with the refrigerant passing through the tubes thereof. Downstream of the air fin coolers 66, the refrigerant is directed to flow through one or more compressors 70 and one or more expanders 72 before recycle to the liquefaction 30 unit 74. The compressors 70 may be driven using gas turbines or electric motors depending on the power requirements and layout issues. Whilst it is possible to use water to cool the refrigerant, the use of ambient air is - 16 preferred as this is understood to be more environmentally friendly. If seawater is used as cooling water, the best source is seawater extracted from a deep water location where the temperature is lower and the water is cleaner than near the waterline. 5 When ambient air is used to cool the refrigerant, a large number of air fin coolers 66 are required to be used as the higher the inlet temperature to the compressor 70, the more compression is required to cool the refrigerant. Due to the large amount of power required for operation of the liquefaction process, the layout of piping and process apparatus onboard the liquefaction module 24 is already quite congested. In order to 10 address this problem, one aspect of the present invention is to locate the air fin coolers 66 on the bridges 48. Preferably, the air fin coolers 66 are located either on the bridge 48 linking the gas processing module 22 to the liquefaction module 24 or the bridge 48 linking the liquefaction module 24 to the storage module 26, or both. The size of each bridge 48 is adjusted to suit the footprint and weight of the air fin coolers 66 located 15 thereon. In the embodiment illustrated in FIG. 5 for which like reference numerals refer to like parts, the air fin coolers 66 are stacked at an angle on the bridge 48 in an A-frame arrangement to maximize the surface area available for cooling for a given footprint size 20 available on the bridges 48. Locating the air fin coolers 66 on the bridges 48 alleviates the problem to trying to fit the required number of air fin coolers within the available footprint of the liquefaction module 24. This allows the size of the liquefaction module 24 to be kept to a minimum (which 25 has a flow on benefit of a reduction in cost) and further allows the remaining equipment located on the liquefaction module 24 to be optimised to maximise operating pressure. In FIG.1, the liquefaction module 24 and gas processing module 22 share common storage modules 26, the storage module being arranged to accommodate at least one 30 cryogenic storage tank 80 for storing LNG and at least one non-cryogenic storage tank 82 for storing other liquids including but not limited to water, condensate, monoethylene glycol (MEG), methanol, diesel, demineralised water, diesel, LPG or combinations thereof. The storage module(s) 26 are hydrostatically stable when partially filled to - 17 reduce sloshing. To reduce the effects of sloshing, in certain instances the storage tanks are provided with a plurality of internal baffles and has a supporting hull structure capable of withstanding the loads imposed from intermediate filling levels when the module is subject to harsh, multi-directional environmental conditions. The cryogenic 5 storage tank may be a double containment, full containment, prismatic or membrane systems with a primary tank constructed from, by way of example, but not limited to stainless steel, aluminum, and/or 9%-nickel steel. The cryogenic storage tanks may include pre-tensioned concrete to provide structural resistance to the stored LNG, boil off gas pressure loads and to external hazards. 10 The berthing module 28 is arranged in sufficiently deep water within the lagoon 18 to allow an LNG carrier 32 to berth directly alongside to load LNG transferred from the storage module(s) 28. In use, the LNG Carriers 32 berth at regular intervals at the LNG production facility 10 so as to receive a cargo of LNG and may approach the berthing 15 modules 28 from either direction depending on the prevailing weather conditions. Depending on the size of the LNG carrier 32, the stern of the LNG carrier 32 may extend beyond an end of the berthing module 28 when the LNG Carrier 32 is berthed alongside the berthing module 28. An overhang of the LNG Carrier's stern beyond the berthing module may expose the LNG Carrier to adverse environmental conditions. To minimize 20 this effect, the berthing module 28 has at least one lateral side which has a length of a sufficient size to allow a range of sizes of LNG carrier to be moored along alongside without overhang of the stern. The berthing module 28 can be fitted with fendering equipment (not shown) arranged to 25 absorb a substantial portion of a load generated by impact of the LNG carrier 32 with the berthing module 28 during berthing. The berthing module may be designed to allow an LNG Carrier to moor on one or more lateral sides of the berthing module. In one embodiment, the berthing module is arranged to allow bi-directional berthing of an LNG Carrier with the longitudinal axis of the berthing module aligned to be substantially 30 parallel to the direction of the predominant current. The berthing module 28 includes LNG transfer equipment 30 to transfer LNG from the storage module 26 to the storage tanks (not shown) onboard the LNG carrier 32. Any - 18 suitable LNG transfer equipment 30 may be used such as a fixed or swivel joint loading arm, preferably fitted with an emergency release system. Between loading operations, the LNG transfer equipment 30 may be kept cold by re- circulation of a small quantity of LNG. The LNG transfer equipment 30 may include an emergency safety system to allow 5 loading to be stopped if required 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. The emergency safety system may be designed to allow LNG transfer to be restarted with minimum delay after corrective action has been taken. Loading of LNG from the storage modules 26 to the LNG carrier 32 is achieved using any of the loading 10 methods well established in the industry. After receiving its cargo of LNG, the LNG carrier 32 travels to a delivery location (not shown) where the LNG is offloaded and regasified. The LNG Carrier can dock at an import terminal associated with an onshore regasification facility or transfer the LNG to a 15 second LNG Carrier with onboard regasification capability or deliver the LNG to any other suitable offshore storage and regasification facility. Now that an embodiment of the invention have been described in detail, it will be apparent to persons skilled in the relevant art that numerous variations and modifications 20 can be made without departing from the basic inventive concepts. For example, a LNG Carrier with onboard storage and regasification capability may be used as the storage module and operate for a period of time as part of the LNG production facility. When the LNG Carrier is full, the LNG Carrier disconnects and travels to a mooring location where the LNG stored onboard the LNG Carrier is regasified onboard the LNG Carrier to form 25 natural gas (NG) which is then transferred to an onshore gas distribution facility. The LNG Carrier then returns to pick up another load of LNG from the loading modules or another export terminal. In the meantime, another LNG Carrier is temporarily stationed at the production location forming part of the LNG production facility. In one embodiment, the LNG Carrier serves the function of a storage module. The LNG Carrier 30 may have an onboard regasification facility. All such modifications and variations are considered to be within the scope of the present invention, the nature of which is to be determined from the foregoing description and the appended claims.

- 19 It will be clearly understood that, although a number of prior art publications are referred to herein, this reference does not constitute an admission that any of these documents forms part of the common general knowledge in the art, in Australia or in any other country. In the summary of the invention, the description and claims which follow, 5 except where the context requires otherwise due to express language or necessary implication, the word "comprise" or variations such as "comprises" or "comprising" is used in an inclusive sense, i.e. to specify the presence of the stated features but not to preclude the presence or addition of further features in various embodiments of the invention. 10

Claims

1. A fixed LNG production facility located in a offshore or near shore body of water, the production facility comprising a plurality of spaced-apart modules, each 5 module provided with plant equipment related to a pre-determined function associated with the production of LNG, and wherein the modules are positioned within a lagoon defined by a reef, whereby the reef provides shelter for the modules against environmental loads. 10

2. The LNG production facility of claim 1 wherein the reef is an atoll.

3. The LNG production facility of claim 2 wherein the atoll is a naturally-occurring atoll. 15

4. The LNG production facility of any one of the preceding claims wherein at least a portion of a bottom surface of each module rests upon a portion of a bottom of the lagoon.

5. The LNG production facility of any one of the preceding claims wherein a 20 module is a gravity based structure.

6. The LNG production facility of claim 5 wherein the gravity based structure includes a ballast storage compartment and one or more liquids selected from the group consisting of: water; condensate; monoethylene glycol; methanol; diesel; demineralised 25 water; diesel; and, LPG, is stored in the ballast storage compartment.

7. The LNG production facility of any one of the preceding claims wherein a module has an adjustable ballast such that the module is transportable from a construction location to the second location. 30

8. The LNG production facility of any one of the preceding claims wherein a first and a second module are linked together using one or more bridges positioned, in use, above the body of water. - 21

9. The LNG production facility of claim 8 further comprising one or more air fin coolers located on the bridges for cooling a refrigerant used to cause liquefaction of a treated well gas. 5

10. The LNG production facility of any one of the preceding claims wherein the plurality of spaced-apart modules includes: a) at least one gas processing module for receiving raw hydrocarbons from a producing well and treating the raw hydrocarbons to remove contaminants therefrom to 10 produce a stream of treated gas; b) at least one liquefaction modules for receiving the stream of treated gas from a gas processing module and liquefying the natural gas to produce LNG; c) at least one storage modules operatively associated with the liquefaction module for receiving and storing LNG; and, 15 d) at least one berthing module including LNG transfer facilities to transfer the LNG from a storage module to an LNG Carrier.

11. The LNG production facility of any one of the preceding claims wherein the storage module comprises at least one cryogenic tank for storing LNG from the 20 liquefaction module and at least one non-cryogenic tank for storing a liquid from the gas processing module selected from the group consisting of: natural gas liquids, condensate, water or LPG.

12. The LNG production facility of any one of the preceding claims wherein, in use, 25 wellhead hydrocarbons are delivered to a gas processing modules via a flow line from a wellhead located outside the reef.

13. The LNG production facility of claim 12 wherein the flow line is directionally drilled through the reef. 30 - 22

14. A method of using a LNG production facility described in any one of claims I to II comprising the steps of: a) receiving natural gas from a well; b) liquefying the natural gas to form LNG; 5 c) transferring the LNG from a liquefaction module to a storage module; d) storing the liquefied natural gas in the storage module; and e) loading the LNG from the storage module onto an LNG Carrier.

15. An LNG production facility substantially as herein described with reference to 10 and as illustrated in the accompany drawings.