WO2016050840A1

WO2016050840A1 - Method and plant for coastal production of liquefied natural gas

Info

Publication number: WO2016050840A1
Application number: PCT/EP2015/072548
Authority: WO
Inventors: Tor Christensen; Pål Leo ECKBO
Original assignee: Global Lng Services Ltd.
Priority date: 2014-09-30
Filing date: 2015-09-30
Publication date: 2016-04-07
Also published as: NO20141176A1

Abstract

A method for LNG production, where natural gas is pre-treated in a pre-treatment unit to give a pre-treated gas stream mainly comprising methane, and where compounds potentially solidifying in the liquefaction process are reduced to a level lower than 50 ppm, where the pre-treated gas stream is compressed to a pressure of 100 - 300 bara, where the pre-treated and compressed gas is transferred in a subsea pipeline to a remote floating LNG liquefaction unit, where the gas transferred to the floating LNG liquefaction unit is expanded to a pressure of 40 to 100 bara, and then introduced into a LNG heat exchanger and cooled against a coolant to produce Liquefied Natural Gas (LNG), wherein the gas stream is split in two streams after being expanded and before being introduced into the LNG heat exchanger to give a first split gas stream that is introduced into the LNG heat exchanger, and a second split gas stream that is heated by heat exchanging against the incoming pressurized gas stream for cooling thereof, where the heated second gas stream is transferred to the pre-treatment unit for re-circulation to the remote floating LNG liquefaction unit, and a system using the method, are described.

Description

METHOD AND PLANT FOR COASTAL PRODUCTION OF LIQUEFIED

NATURAL GAS

Technical Field

[0001] The present invention relates to improvements in methods and plants for liquefaction of natural gas to provide Liquefied Natural Gas (LNG) which is stable in atmospheric pressure and suitable for transport in LNG shuttle tankers, with improved economics, improved personnel safety and a reduction of the

environmental impact. More specifically, the present invention relates to a method and plant for LNG production environmentally suited to locations offshore, or for locations near coastlines, which can satisfy the requirements set with regard to increased safety, environmental protection and liquefaction efficiency.

Background Art

[0002] Natural gas is becoming more important as the world's energy demand increases as well as its concerns about air and water emissions increase. Natural gas is readily available, in particular with the new technologies to utilize shale gas. It is much cleaner-burning than oil and coal, and does not have the hazard or waste deposition problems associated with nuclear or coal power. The emission of greenhouse gases is lower than for oil, and only about one third of such emissions resulting from combustion of coal.

[0003] There is substantial international trade in natural gas. Price and availability vary significantly in different parts of the world. A large fraction of this trade is in the form of Liquefied Natural Gas (LNG), which mainly comprises natural gas components lighter than pentane. These components are methane, ethane, propane, butane and traces of nitrogen. Methane concentration is typically above 85% on a molar basis, often above 90%, ethane may range from below 1 to about 10% on a molar basis, propane may be in the range from below 0.1 to about 3 mole%, while butane may be in the range from below 0.1 to 1 %. Nitrogen concentration may be in the range from below 0.1 to 1 mole%. Additionally, to be safely transported in shuttle tankers, the LNG has to be stabilized , i.e. not separate into a gas and a liquid phase, at a temperature at which it is stableat atmospheric pressure.

[0004] LNG is produced using two major processing steps. The first step is gas pre-treatment to remove CO2, H2S and water which may become solids and plug pipes in the cryogenic liquefaction process. The first step also includes the removal of trace elements, such as e.g. mercury, which can form amalgams - in particular with aluminium process components, and cause erosion / corrosion. Hydrocarbon fractions heavier than methane, collectively referred to as Natural Gas Liquids (NGLs), include ethane, propane, butane, pentane and heavier components, are removed from the gas to varying degrees.

[0005] Pentane and heavier are removed to very low residual concentrations such as 50 to 100 ppm on a mole basis, since these may solidify in the liquefaction process. Other NGLs, ethane, propane and butanes are removed to varying degrees depending on economic logic. The NGLs may be removed from the gas in the first LNG processing step, or as an integrated part of the second processing step. The second processing step is mainly liquefaction of the thus purified gas, which then comprises mainly methane. These first and second processing steps all take place at elevated pressures, typically in the range from 40 to 100 bar absolute (bara).

[0006] A final processing step, downstream of the liquefaction process, includes pressure reduction to atmospheric pressure, and removal of any excessive amount of nitrogen, typically any amount that exceeds 1 mole%. This is done by flashing of the LNG at atmospheric pressure. This produces the final LNG product, and a much smaller hydrocarbon gas stream enriched in nitrogen, typically used for fuel. The final LNG product is a stable liquid at atmospheric pressure and about -163°C. It is stored in buffer storage tanks, then offloaded and shipped to destinations in LNG shuttle tankers. At the destination, the LNG is compressed, re-gasified and piped to consumers. [0007] Processing of natural gas to produce LNG has traditionally been done in large land based facilities which include the two steps of pre-treatment and liquefaction in the same location. Recent developments in technology and markets have enabled construction of LNG plants on floating structures, a development that has inspired movement of a substantial portion of LNG

processing facilities offshore to Floating Liquefied Natural Gas (FLNG) facilities to exploit large offshore gas reservoirs. The FLNGs are typically designed to be located at a distance from a coast and are connected to natural gas reservoirs through sub-sea piping systems. The FLNGs typically are also designed to serve as buffer storage and as terminals for loading of LNG tankers that are used for transport of the LNG to the markets.

[0008] The recent development towards FLNGs has made offshore natural gas resources more available to the market relative to piping the gas to shore for liquefaction, and has resulted in a reduction of capital cost for establishing an LNG plant. Other key drivers include reduction of onshore environmental impacts; reduction of land use issues for equipment and infrastructure; and reduced likelihood of opposition from local communities. The entire FLNG plant can be modularized and built in a shipyard, which is efficient and improves quality control, cost control and reduces construction time. FLNG's are also mobile and can be transferred to alternative locations if required.

[0009] Numerous studies of FLNG technologies have been carried out over the last couple of decades. Currently, several projects are underway worldwide. The FLNGs have both safety, environmental and production capacity issues.

[0010] The safety concern associated with hydrocarbons on a confined vessel deck is potential loss of hydrocarbon containment, in combination with ignition sources. This may cause vapour cloud explosions or flash fires. Historically, such incidents have occurred within chemical plants containing reactive hydrocarbon components including NGLs. The severity of incidents has been determined by the quantity of hydrocarbons released and the confinement and congestion in the area of release. A well-known incident was the vapour cloud explosion at the Flixborough Works in the UK in 1974. About 30 tons of reactive hydrocarbons was released and ignited about one minute after the release. The explosion resulted in 28 fatalities and the damage of approximately 2,000 homes in the local community (Reference Center for Chemical Process Safety, "Guidelines for vapour Cloud Explosions, Pressure Vessel Burst, BLEVE and Flash Fire Hazards", 2^nd edition, Wiley, 2010). The situation on FLNGs is that in order to get high LNG production rates, NGL components are often preferred as refrigerants. For a 4 million ton LNG per year plant, the inventory of NGL components on deck may be in the hundred ton range for the liquefaction plant, with additional amounts in the onboard NGL extraction and storage facilities, such as described in WO9801335, in the name of Den norske Stats Oljeselskap AS (now Statoil ASA). This is much more than the amount which exploded at the Flixborough Works, confined to a much smaller area.

[001 1] FLNG environmental concerns are associated with the substantial amounts of process waste heat, which must be transferred to the surroundings. Due to the proximity to water, the efficiency of water-coolers and relatively stable water temperatures, seawater is normally employed as coolant. Extremely large amounts are used and subsequently discharged at a higher temperature. Environmental concerns arise because of shear forces in sea water pipes, increased seawater temperature and the use of toxic chemicals, which are harmful to marine life. The use of seawater coolant will probably be prohibited in many coastal waters, such as in the state of Louisiana, in the near future.

[0012] FLNG production capacity concerns are coupled with the safety concern, since lower production capacity reduces the vessel inventory of NGL components. It is also connected to the environmental concerns, since lower production capacity reduces the process cooling requirements and use of seawater coolant. The most challenging problem, which limits the production capacity, is however, the limited deck space. This is only about 5% of the area that would be used onshore for similar plant capacities. On this limited area gas pre-processing and / or NGL extraction, liquefaction with associated power generation, utilities, offloading systems, and marine specific equipment must be located. Reduced LNG production capacity reduces the space needed for all of this, reduces congestion and simplifies the equipment layout.

[0013] Ongoing work with these challenges, of which the innovation described in this patent is one part, has resulted in a novel adaptation of FLNG. This is the Coastal Liquefaction, Storage and Offloading (CLSO) facility. The CLSO

adaptation addresses FLNG safety, environmental impact and processing capacity issues. In contrast to FLNG systems, the first processing step, gas pre-processing, is performed in its entirety on shore, on separate terminals or on dedicated floating systems, instead of occupying valuable space on the liquefaction vessel. This remote pre-processing includes the extraction of NGLs. Fully pre-processed gas is piped to one or more floating CLSO's, which now have much more deck space available, freed up by removing pre-processing. The extra space is used for much enhanced safety by employing nitrogen refrigerant in the liquefaction process instead of hydrocarbon refrigerants. This reduces the hydrocarbon inventory on the vessel deck by a factor of 10 or more. The remaining inventory comprises mainly pre-processed gas, or methane, which is much less reactive than NGL components. The extra space is also used for improved environmental

performance, in that air-cooling is employed instead of seawater cooling. Finally, the extra space is used for extra liquefaction capacity, significantly improving the overall system economics.

[0014] Liquefaction systems employing nitrogen refrigerant are less efficient than the systems using hydrocarbon refrigerant. This results in increased specific power consumption. Gas turbines, typically used for power production, are available in standard sizes, and only a few of these are certified for use on offshore floaters. Therefore, if the largest available gas turbine is used, increased specific power consumption means reduced LNG production rates. Furthermore, nitrogen systems are available in smaller sizes only, such as 1 to 1.5 million tons per year (mtpa), in contrast to hydrocarbon systems which are available in sizes above 4 mtpa. A larger number of plants is required when nitrogen refrigerants are used, potentially increasing the space requirement.

[0015] Air cooling further aggravates this problem, because they are less efficient than water cooled systems, air temperatures vary much more than water temperatures, and approach temperatures below about 15°C is difficult to obtain or require substantial increases in space requirements. This lower efficiency further increases the specific power needed in the liquefaction plant.

[0016] Table 1 shows comparisons of the liquefaction alternatives: Hydrocarbon refrigerant and nitrogen refrigerant in combination with water-cooling, and hydrocarbon refrigerant and nitrogen refrigerant in combination with air cooling.

[0017] The table is based on specific power consumption for the liquefaction plants, expressed as kWh/kg LNG, which when multiplied by the LNG production rate in kg/hour gives the power required. It is also based on total enthalpy change of the pre-processed gas in the liquefaction process, expressed as kJ/kg LNG, which when multiplied by the LNG production rate gives the amount of energy removed from the gas. The sum of these two, power used in the liquefaction process and heat removed from the gas, is the amount of process waste heat which must be transferred to water or air. Table 1 is based on the following:

• Gas composition: 1 mole% N2, 95 mole% methane, 2 mole% ethane, 1 mole% propane and 1 mole% butane (0.5 mole% i-butane and 0.5 mole% n-butane).

• LNG production rate: 122,000 kg/h or 34 kg/s (about 1 mtpa)

• Specific power consumption, hydrocarbon based refrigerant with water cooling: 0.27 kWh/kg

• Specific power consumption, nitrogen refrigerant with water cooling: 0.45 kWh/kg. This is based on typical efficiency for the most common nitrogen based liquefaction system, called dual nitrogen.

• Increase in specific power consumption when air cooling is used: 20% • Enthalpy change of pre-processed gas in the liquefaction process (dH in Table 1 ): 800 kJ/kg

• Air cooler space requirement: 1000 m2 per 100 MW cooling.

Table 1

Comparison of work and cooling duty for liquefaction processes

Note 1 : Hydrocarbon air-cooled systems normally not used on floaters Note 2: CLSO employs the nitrogen air-cooled system on floaters. Air cooler space required is 931 m2.

[0018] Relative to water cooled hydrocarbon based liquefaction systems, CLSOs with nitrogen refrigerant and air-cooling results in a substantial increase in the compressor power requirement and in the cooling duty. Extra space required by the air coolers, 931 m2, is substantial. However, safety and environmental performance are superior for the CLSO.

[0019] On a CLSO, the available deck space is limited by the vessel size.

Therefore, the safest and most environmentally friendly liquefaction process is challenging if production rates similar to the most efficient system, hydrocarbon refrigerant and water-cooling, is required.

[0020] Even though improved air-coolers have been developed the last few years, see e.g. US 8,376,0337, to GEA Batignolles Technologies Thermiques, air coolers that reduces the deck area substantially over traditional air-coolers, and improved liquefaction processes are being developed, see e.g. US 8,656,733B2 to Air Products and Chemicals Inc., further developments to create a more efficient LNG process is necessary to make a LNG process fulfilling the relevant safety and environmental requirements, and at the same time being economically feasible.

[0021] WO2013/022529 relates to a gas processing facility for liquefaction of a natural gas stream, comprising a pre-processing unit for separation of the natural gas and deliver a methane rich gas stream to a liquefaction unit. The natural gas is delivered to the liquefaction unit at a moderate pressure, and is compressed to a high pressure in the liquefaction unit. The compressed natural gas is cooled in two serially connected heat exchangers, against recycled flash gas and also against coolant from an external cooling circuit, and thereafter expanded to produce a fluidized natural gas at a pressure of 3.5 to 31 bar, and a flashed off natural gas, that is recycled and used as cooling medium to cool the compressed gas, and returned to be recompressed together with incoming natural gas. The produced liquefied natural gas is a pressurized Liquefied Natural Gas (PLNG), which is not suitable for transport in LNG tankers. For efficient transport of high volumes of liquefied natural gas in LNG tankers, the natural gas has to be stable, i.e. not release gas, at atmospheric pressure at a temperature of about -163°. PLNG may be used locally, or be shipped small pressure tanks not suitable for high volume transport.

[0022] WO01/44735 relates to a process of liquefying natural gas by expansion cooling, mainly as described for the liquefaction unit of WO2013/022529. The produced liquefied natural gas is PLNG, and is not stable at -163 °C.

[0023] Natural gas pre-cooling using lithium bromide, CFC or HCFC based systems is known to reduce the nitrogen liquefaction plant energy requirement. It also increases the liquefaction capacity. However, the pre-cooling equipment requires substantial deck space. This reduces the space available for liquefaction plants and hence the liquefaction capacity, defeating the purpose with such pre- cooling. Therefore, the net advantage of traditional pre-cooling may be small.

[0024] An object of the present invention is to provide a method and a plant for LNG production environmentally suited to locations offshore, or for locations near coastlines, which will satisfy the requirements set with regard to risk to personnel, a risk which shall be as low as reasonable practicable, which will satisfy the most stringent requirements set to environmental protection, which in particular means no use of sea water for cooling purposes, and which at the same time maintains the lowest liquefaction specific power, and lowest on-board power requirements for floating liquefaction plants.

[0025] Another object of the present invention is to provide a method and a system for producing LNG from natural gas on CLSO facilities that allows for maximized production rates, minimum power requirements and minimum cooling requirements on the CLSO while at the same time having the best safety and environmental performance, without using much extra deck space. One object of the invention is therefore substantially to reduce the specific power consumption of air-cooled nitrogen systems, within the constraints imposed by the CLSO

technology where gas pre-processing takes place at a remote platform or on shore, where gas must be transferred to the CLSO in sub-sea pipelines, where the space on the CLSO is limited, and where the LNH shall be stable at atmospheric pressure. It is important that the gas transferred in the sub-sea pipelines must have a temperature close to the seawater temperature in order not to damage the pipelines by phenomena such as upheaval buckling. Therefore, substantial pre- cooling of gas upstream of the sub-sea pipeline, or in the sub-sea pipeline, is not possible.

Summary of invention

[0026] According to a first aspect, the present invention provides for a method for LNG production, where natural gas is pre-treated in a pre-treatment unit to give a pre-treated gas stream mainly comprising methane, and where compounds potentially solidifying in the liquefaction process are reduced to a level lower than 50 ppm, where the pre-treated gas stream is compressed to a pressure of 100 - 300 bara , where the pre-treated and compressed gas is transferred in a subsea pipeline to a remote floating LNG liquefaction unit, where the gas transferred to the floating LNG liquefaction unit is expanded to a pressure of 40 to 100 bara, and subsequently introduced into a downstream LNG heat exchange system where the gas is cooled against a coolant to produce Liquefied Natural Gas (LNG), wherein the gas stream after arriving onboard the floating LNG liquefaction unit, after being expanded and before being introduced into the LNG heat exchange system, is split in two gas streams to give a first split gas stream that is introduced into the LNG heat exchange system, and a second split gas stream that is heated by heat exchanging against the incoming pressurized gas stream for cooling thereof, where the heated second gas stream is transferred to the pre-treatment unit.

[0027] The transfer of the gas to the LNG liquefaction unit at high pressure and expansion of the gas when onboard the LNG liquefaction unit, constitutes a pre- cooling of the gas. By splitting the expanded and thus cooled gas onboard the floating LNG liquefaction unit into two streams, introducing a first split stream into the LNG heat exchanger, introducing a second split stream into a heat exchanger for heat exchanging of said second split stream against the incoming pressurized gas, the temperature, and the enthalpy, of the incoming pressurized stream is further reduced. This temperature and enthalpy reduction result in lowering the power and cooling demand onboard the floating LNG liquefaction unit. It also results in increasing the temperature of the second split stream to almost the same temperature as the incoming gas, which enables transfer to the pre-treatment unit in sub-sea pipelines without problems arising from thermal expansion or

contraction of the pipe material. All of this is accomplished at the cost of an increased power demand for compression of a larger volume of pre-treated natural gas at the pre-treatment unit. However, the space restrictions and availability of power is normally far less restricted at the pre-treatment unit than onboard a floating LNG liquefaction unit. Accordingly, the loop for recycling has a function of a heat pump, transferring heat from the floating LNG liquefaction unit to the pre- treatment unit, without creating thermal expansion or contraction problems in sub- sea pipeline materials.

[0028] According to one embodiment, the wherein the expansion of the gas after arriving onboard the floating LNG liquefaction unit and before introduction of the gas into the LNG heat exchanger, comprises an isenthalpic expansion. All or a part of the expansion of the gas may be isenthalpic. The gas that is expanded isenthalpic and thereafter being split in a first and second stream and heat exchange equipment requires far less equipment and space onboard the deck of the remote LNG liquefaction unit than do traditional gas pre-cooling systems such as lithium bromide, CFC or HCFC units. This increases safety by leaving more space for safety barriers. It improves environmental performance by eliminating possibilities for lithium bromide, CFC or HCFC emissions.

[0029] According to one embodiment, the heated second gas after being transferred to the pre-treatment unit is mixed with the pre-treated gas stream, compressed together with the pre-treated gas stream and transferred to the floating LNG liquefaction unit. The pre-treated natural gas is "LNG ready", i.e. unwanted components of the gas are removed or reduced to acceptable concentrations, such as e.g. below 50 ppm. The recycled gas is has not been mixed with any unwanted components and is still LNG ready gas and may be recycled directly.

[0030] According to one embodiment, the pre-treated gas is compressed by a pressure ratio of at least 1.5, preferably at least 2.0 or at least 3.0, before being transferred to the floating LNG liquefaction unit, and that the gas after arriving at the floating LNG liquefaction unit is expanded isenthalpic by substantially the same ratio as the compression. Compression at the pre-treatment unit and expansion at the floating LNG liquefaction unit at substantially the same ratios results in a gas pressure of the recycling gas that is substantially the same as the pre-treated gas introduced into the compressor unit at the pre-treatment unit for compression of the gas. Accordingly, no or minor adjustments in pressure are necessary for introducing the recycled gas into the compression unit together with the pre-treated gas. The expansion at the floating LNG liquefaction unit may be to a pressure sufficiently higher than the pressure of the gas introduced into the compressor unit at the pre-treatment unit for compression of the gas before being transferred to the floating LNG liquefaction unit to overcome the pressure drop over transport pipelines, heat exchangers etc., a pressure difference that is covered by the expression "substantially the same ratio".

[0031] According to one embodiment, the first split gas stream constitutes 30 to 70 % of the expanded gas stream, such as 40 - 60% of the expanded gas stream, such as about 50%. The amount of gas in the first split stream introduced into the LNG heat exchanger and the amount of gas for cooling of the incoming gas onto the floating LNG liquefaction unit, has to be optimized for the plant in question and the climate in question. The higher the fraction of gas in the first split gas stream is, the lower the fraction of the gas in the second split gas stream is, resulting in reduced cooling effect in the heat exchanger for cooling the incoming gas into the floating LNG liquefaction unit. A high fraction of recycled gas through the heat exchanger will give a higher cooling effect at the cost of increased compressor load at the pre-treatment unit and the need for high capacity of the gas return pipeline back to the pre-treatment unit.

[0032] According to one embodiment, the pre-treated and compressed gas stream is cooled to a temperature of 5 to 60° C before being transferred in the subsea pipeline. Preferably, the pre-treated and compressed natural gas is cooled to near ambient temperature, i.e. the temperature at the site in question, to avoid damages to the pipeline caused by thermal expansion or contraction of the pipe material, resulting in undesirable phenomena such as upheaval buckling. It is evident that some cooling will occur if the gas inside the pipeline is hotter than the surrounding sea, but this cooling effect is not reliable due to outside fouling of the pipeline, and not important for the system performance. Additionally, a

temperature gradient over the pipeline may be environmentally undesirable by creating areas around the pipeline with higher or lower than normal temperatures.

[0033] The method of any of the preceding claims, wherein the coolant in the LNG heat exchanger is nitrogen. Nitrogen is a preferred coolant as nitrogen is inert, non-toxic and has no impact on the environment, if accidentally released into the atmosphere. Alternative coolants are either inflammable, and may cause violent fires and/or explosions, are toxic or may cause unwanted impact on the environment. However, nitrogen is less efficient as a coolant than some of the other alternatives and requires measures to be taken, such as the pre-cooling measures described above, to be an economically viable alternative.

[0034] The method of any of the preceding claims, wherein coolant heated by liquefying LNG is withdrawn from the LNG heat exchanger system and

compressed in compression steps, where the coolant is cooled in a cooling cycle using air-coolers between the coolant compression steps. The method as described above makes it possible to use air-coolers without needing to increase the area of the floating LNG liquefaction unit to an unacceptable extent, or to reduce the LNG liquefaction capacity, and thus make the use of air-coolers an economically and technically viable alternative.

[0035] According to a second aspect, the present invention relates to a system for liquefaction of natural gas to produce LNG, the system comprising a pre-treatment unit to remove or to reduce the concentration of compounds that may form solids in the liquefaction process to below 50 ppm and a gas compressor unit to compress the pre-treated natural gas, a gas transfer unit comprising a gas transfer pipeline for transferring the pre-treated gas to a remote floating LNG liquefaction unit, the floating LNG liquefaction unit comprising one or more expansion unit(s) for expansion of the gas, a LNG heat exchanger system for cooling and thus liquefying the gas to produce LNG, an LNG export line for withdrawing the produced LNG from the LNG heat exchange system, and a LNG coolant compression and cooling system for reduction of the enthalpy of the coolant and recycling the compressed and cooled coolant to the LNG heat exchange system, wherein the system additionally comprises a gas recycle pipeline for withdrawing a part of the gas after being expanded and before being introduced into the LNG heat exchanger, the recycle pipeline being arranged to introduce the withdrawn gas into a heat exchanger for cooling the incoming compressed gas from the gas transfer pipeline, and where a subsea gas return pipeline is arranged to transfer the withdrawn gas from the heat exchanger and back to the pre-treatment unit.

[0036] According one embodiment, the one or more expansion unit(s) includes one or more valves for isenthalpic expansion of the gas.

[0037] According to one embodiment, the one or more expansion unit(s) includes one or more turbo expanders for polytrophic expansion of the gas.

[0038] According to one embodiment, the gas return pipeline is connected to the compressor unit for re-compression and recycling of the gas to the floating LNG liquefaction unit.

[0039] According to another embodiment, a cooler is arranged after the compression unit to cool the gas before being introduced into the gas transfer pipeline.

[0040] According to yet an embodiment, two or more serially connected compression units for compression of coolant, and air-coolers for cooling of the coolant after the compression steps.

Brief description of drawings

[0041]

Figure 1 is an overall overview of a pre-treatment unit, sub-sea pipelines and a CLSO,

Figure 2 is a principle drawing of a first embodiment of the present invention, Figure 3 is a principle drawing of a second embodiment of the present invention, and

Figure 4 is an illustration of gas enthalpy reduction as a function of pre-treatment unit compressor discharge pressure.

Detailed description of the invention

[0042] In the present description and claims, FLNG is used as an abbreviation for Floating Liquefied Natural Gas facilities. CLSO is an abbreviation for a Coastal Liquefaction, Storage and Offloading facility. The abbreviation CLSO is thus used to describe a subgroups of FLNG's or, as used more broadly herein, "floating LNG liquefaction unit", all of which facilities and units normally are floating units, or vessels. The term "natural gas" is used for a gas comprising lower hydrocarbons, found in geological formations either together with oil, in gas fields, and in shale as shale gas. Dependent on the source, natural gas may differ in hydrocarbon composition but methane is almost always the predominant gas. The skilled person within this technical area has good knowledge of the abbreviations LNG and NGL, i.e., Liquefied Natural Gas, and Natural Gas Liquids, respectively. LNG consists of methane normally with a minor concentration of C2, C3 and C₄ hydrocarbons, and virtually no C5+ hydrocarbons. LNG is in the present description and claims used for a liquefied natural gas that is a stable liquid at atmospheric pressure at about -163 °C, unless specified otherwise. A stable liquid, is used to describe a liquefied gas that does not spontaneously separate into gas and liquid at the indicated temperature and pressure, to clearly distinguish the expression LNG from Pressurized Liquefied Natural Gas (PLNG). NGL, at the other hand, is a collective term for mainly C2+ hydrocarbons, which exist in unprocessed natural gas. LPG is an abbreviation for liquefied petroleum gas and consists mainly of propane and butane. The unit "bara" is "bar absolute". Accordingly, 1.013 bara is the normal atmospheric pressure at sea level. The expression "ambient temperature" as used herein may differ with the climate for operation of the plant according to the present invention. Normally, the ambient temperature for operation of the present plant is from about 0 to 40 °C, but the ambient

temperature may also be from sub-zero levels to somewhat higher than 40°C, such as 50 °C, during some operating conditions.

[0043] Figure 1 is a principle sketch of a system according to the present invention, comprising a gas pre-treatment unit 1 that may be arranged on an offshore terminal, on a barge or other floater, or on land based facilities, a high pressure gas transfer unit 2 to a floating LNG liquefaction unit 3, and a high pressure gas recirculation pipeline 9 for gas recirculation from the floating LNG liquefaction unit 3 to the gas pre-treatment unit 1. The floating LNG liquefaction unit 3 according to the present invention is herein also identified as a CLSO.

[0044] Natural gas from a gas field or from a combined oil and gas field is pre- treated in the pre-treatment unit 1. The full pre-treatment of the natural gas at the remote location to produce what may be called "LNG ready natural gas". The pre- treatment normally comprises but is not limited to:

1. Hg removal,

2. Gas sweetening, i.e. removal of unwanted acid gases, such as CO2 and H2S from the natural gas,

3. Dehydration, i.e. removal of water that may otherwise cause formation of hydrates from the gas,

4. Full NGL extraction and processing, i.e. separation of the NGL from the gas, including separation of substantially all C5+ components. Optional fractionation of the NGL into saleable products, which depending on the NGL composition might include Liquefied

Petroleum Gas (LPG).

[0045] During the pre-treatment, components removed from the gas always include all components that may solidify at liquefaction temperatures, down to about -163 °C, are removed or at least reduced to a concentration of less than 50 ppm. The upper limit for the concentration of solidifying components depends on the actual component, as e.g. water preferably is reduced to a maximum level of 1 ppb.

[0046] Figure 2 illustrates a first embodiment of the present invention with further details. The natural gas pre-treated in the pre-treatment unit 1 , flowing via gas pipeline 4 at a pressure of typically about 40 to 100 bara, is mixed with recycled gas 8 which is at the same pressure as the gas in pipeline 4, and introduced into a compressor unit 5. The gas mixture is compressed in the compressor unit by a pressure ratio of at least 1.5, such as at least 2, or even more preferred at least 3, dependent on the pressure in line 4 which typically is from about 40 to to 100 bara to a pressure typically from 100 to 250 bara, and cooled in a cooling unit 6 typically to a temperature close to the ambient temperature, i.e. from about 5 to 55 °C dependent on the climate. The cooling unit 6 is conveniently an air-cooled heat exchanger.

[0047] The pre-treated, compressed and cooled natural gas is transferred to the floating LNG liquefaction unit 3 via the gas transfer pipeline 7, a pipeline arranged at the sea bed and that may be several kilometres long. The gas temperature may increase or decrease slightly in gas transfer pipeline 7 by some heat exchange with the surrounding sea-water, but such effects are unimportant in the present invention.

[0048] Onboard the floating LNG liquefaction unit 3, the gas is pre-cooled in a heat exchanger 1 1 against a recycle gas stream as will be described further below. The gas pre-cooled in heat exchanger 1 1 is withdrawn in a pipeline 21 to an expansion unit 12, over which the pressure of the gas is reduced by a factor for pressure reduction of at least 1.5, such as at least 2, or more preferred at least 3, to result in a pressure of typically 45 to 100 bara, typically to a pressure close to the pressure in line 4, as stated above. The expansion unit 12 may be a valve or may include a valve in combination with another expansion device, such as a turbo expander. A valve for expansion of the gas is isenthalpic pressure reduction of the gas. A turbo expander takes work out of the expansion process and thus reduces the gas enthalpy, which is an advantage for the downstream liquefaction process. The expanded gas is withdrawn through a pipeline 22, and is split into a recycle gas pipeline 10 and a process gas line 13. The gas in the gas recycle pipeline 10 is at substantially the same pressure as the gas in process pipeline 13.

[0049] The amount of gas in recycle pipeline 10 is preferably from about 30 to about 70 %, such as about 40 to 60 %, or about 50% of the gas in pipeline 22. The skilled person will understand that the distribution between recycle pipeline 10 and process pipeline 13 may be controlled by conventional means, such as not shown valves, counter pressure in the pipelines or downstream equipment, etc. [0050] The gas in recycle pipeline 10 is introduced into the heat exchanger 1 1 for cooling of the inconning gas introduced via the gas transfer pipeline 7. The remaining gas from pipeline 22 is withdrawn through process pipeline 13 to be liquefied, without further compression or expansion.

[0051] The gas introduced into the heat exchanger 1 1 from recycle gas pipeline 10, is, after being used for cooling of the incoming gas from pipeline 7, withdrawn from the heat exchanger 1 1 via a gas recycle line 23 and transferred back to the pre-treatment unit 1 in a sub-sea gas pipeline 9. The temperature in recycle line 23 is normally near ambient temperature, as indicated above for the gas in line 7.

[0052] The gas is recycled to the pre-treatment unit 1 in the gas recycle pipeline 9 and introduced into a transfer line 8, and introduced into the compressor unit 5 together with the incoming pre-treated gas in pipeline 4. This re-introduction of gas into the suction of compressor 5 completes the gas pre-cooling circuit, and the ultimate result is substantial reduction of gas enthalpy in process gas line 13. The effect of the reduction in enthalpy is that the cooling duty for the further LNG process is reduced.

[0053] Preferably, the gas pressure in line 4 and in line 13 are substantially the same, even though minor differences in pressure in the lines may occur. Any pressure differences in lines 4 and 13 are normally due to the pressure drop over different parts of the path of recycling of the gas, and more specifically due to the pressure drop in lines 10, 23, 9 and 8 and the heat exchanger 1 1 for the recycling gas part. Accordingly, the reduction in gas enthalpy in process line 13 compared to the gas in line 4, is mainly caused by a reduction in gas temperature.

[0054] The gas temperature reduction in line 21 , relative to the temperature in feed gas line 4, might be in the range 20 to 70°C. In other words, by starting with a gas at a temperature of typically 20 °C introduced into the present plant in line 4, the temperature of the gas in line 21 will typically be from about 0 to about -50 °C. In many cases, the outlet temperature of sub-sea pipeline 7 will be substantially the same as the temperature in line 4. Therefore, the temperature drop over heat exchanger 1 1 might also be in the range 20 to 70°C. The gas temperature reduction in line 13, relative to the temperature in feed gas line 4, might be in the range 40 to 90°C. This depends mainly on the fraction of gas from line 22 that is recycled via line 10, the pressure drop in expansion device 12, exemplified with a valve, and the approach temperature in heat exchanger 1 1.

[0055] Low enthalpy process gas in line 13 is liquefied in a nitrogen liquefaction unit. The skilled person knows that various designs of such liquefaction plants exist, such as single or dual nitrogen systems, and that all of these benefit from any upstream reduction in gas enthalpy. Figure 2 shows the simplest and least efficient of the nitrogen liquefaction systems, a single nitrogen system.

[0056] The process gas in line 13 is further cooled, liquefied and sub-cooled in an LNG heat exchanger 14. The liquefied gas is expanded to a pressure close to atmospheric pressure in valve 15, and sent via a LNG export line 15' to a not shown flash unit where excess nitrogen and minor amounts of not liquefied natural gas are separated and removed. The liquid phase, stable at atmospheric pressure, is then transferred to buffer storage on the floating LNG liquefaction unit for later off-loading and export.

[0057] The cooling medium in LNG heat exchanger 14 is preferably due to the environmental and safety explanations above, nitrogen. The described coolant cooling circuit illustrated in the figures 2 and 3, is a basic, and well known, concept. Heated gaseous coolant is withdrawn from the LNG heat exchanger 14 through a coolant withdrawal line 20' and introduced into serially connected compressors 18, 18', 18". Air coolers 19, 19', 19" are arranged after each compressor for cooling the compressed coolant. The compressed and cooled coolant is introduced into the LNG heat exchanger via a coolant line 20 for further cooling, and withdrawn from the LNG heat exchanger in a pre-cooled coolant line 16. The pre-cooled coolant is then introduced into an expander 17 to expand and further reduce the temperature and enthalpy, and recycled to the LNG heat exchanger 14 where it is used as coolant. [0058] Typically, the target hydrocarbon temperature in the LNG heat exchanger is -163 °C, a temperature at which several compounds found in natural gas as produced, will solidify. To avoid sedimentation of solids and the possibility of blocking of low-temperature elements of a LNG plant, all compounds that may form solids in the process system during the processing and liquefaction are removed or the concentration of the compounds are reduced during the pre- treatment of the gas to levels typically below 50 ppm to avoid such problems.

[0059] Figure 3 shows a second embodiment of the present invention. All reference numbers found both in Figures 2 and 3 relate to the same elements and only the non-common elements are further described below. Depending on operating parameters, some liquid may have precipitated in the expansion unit 12, so that stream 22 is a two-phase gas / liquid stream. A liquid knock-out tank 23 may then be provided to separate the liquid from the gas, providing a pure liquid stream 27, and a pure gas stream 26. Some of the gas stream may be mixed with the liquid stream using valves 24 and 25, providing a liquid rich stream to the LNG exchanger 14, where further cooling and liquefaction is completed.

[Examples

[Example 1

[0060] Figure 4 shows the enthalpy reduction in line 22, relative to gas at 40 bara and 20°C, which has been assigned an enthalpy of 0 kJ/kg. In this example, this represents the enthalpy of the gas in line 4. The gas composition is 1.0 mole% nitrogen, 95.0 mole% methane, 2.0 mole% ethane, 1.0 mole% propane, and 1.0 mole% butane. The horizontal axis shows discharge pressure of the pre-treatment unit 1 compressor unit 5. The vertical axis shows gas enthalpies relative to the 40 bara and 20°C gas. The following is common for all cases:

• Gas is compressed in compressor 5 from 40 bara to the compressor

discharge pressure shown on Figure 4, and subsequently cooled in cooler 6 to 20°C. • There is no gas heating or cooling in sub-sea pipeline 7 as the gas temperature is approximately equal to the surrounding sea temperature.

• Gas is expanded to 40 bara in expansion unit 12.

• Gas temperature in line 23 is 10°C

[0061] The upper line, marked "No gas recycle" shows enthalpy reduction with no gas return from the CLSO to the platform, which is the situation according to the prior art. This enthalpy reduction is only a function of the gas pressure, since the calculation is based on isenthalpic expansion over expansion unit 12. Higher compression gas pressure gives lower gas enthalpy.

[0062] The line below, marked with "50% gas recycle", shows the relative enthalpy of gas in line 22, when 50% of the fluid in line 22 is recycled to the platform via heat exchanger 1 1 and the gas re-circulation pipeline 9.

[0063] The line marked "66 % gas recycle" below this shows the relative enthalpy of gas in line 22, when 66% of the fluid in line 22 is recycled to the platform via heat exchanger 1 1 and the gas re-circulation pipeline 9.

[0064] Finally, the lowermost horizontal line, marked "Enthalpy LNG", shows the relative enthalpy of the final LNG product. Reduced enthalpy of the gas in line 22 and hence line 13 reduces the remaining enthalpy to be removed in order to reach the "Enthalpy LNG" line. The load on the CLSO liquefaction process is reduced correspondingly. This in turn reduces the size of the LNG exchanger 14, the duty of compressors 18, 18' and 18", and the size and space requirements of air coolers for liquefying of a predetermined amount of LNG.

[0065] The reduction of gas enthalpy as a function of compressor discharge pressure from compressor 5, as illustrated in figure, may be calculated into reduction of compressor duty and air cooler space requirement for production of a predetermined amount of LNG, e.g. compared to the compressor duty and air cooler space requirement according to the state of the art, i.e. without any recycling of partly expanded natural gas as described herein. [0066] When operated according to the prior art, the compression and cooling at the pre-treatment unit 1 from e.g. 40 to 200 bara, and expanding of the gas onboard the floating LNG liquefaction unit or CSLO, compared to a "base case" transporting the natural gas in line 4 onboard the floating LNG liquefaction unit at 40 bara and 20 °C, result in a reduction in LNG exchanger size, compressor duty and air cooler space requirement in the order of 18%. Accordingly, compressing the natural gas before transport through pipelines results both in reduced cooling requirement onboard the floating LNG liquefaction unit, and reduces the volume of gas to be transported, which allows for using smaller diameter pipelines.

[0067] It may also been seen from figure 4 that recycling of 50% of the gas transported onboard the floating LNG liquefaction unit or CLSO according to this invention, results in a reduction in the corresponding LNG exchanger, compressor duty and air cooler space requirement to about 36% compared to the "base case", or approximately twice the savings shown for the prior art solution without any recirculation.

[0068] By further increasing the recycle flow, to 66%, it can be seen that the corresponding reductions are almost 50% compared to the "base case". The skilled person will understand that the reductions in load as described above might be used for reducing the load on the CLSO equipment, reducing the size of the floating LNG liquefaction unit, or for a substantial increase in the LNG production capacity, significantly improving the system economic return. Note that reduction in load on the equipment onboard the floating LNG liquefaction unit is

accomplished because the load on the platform equipment, in particular

compressor 5 and air cooler 6, is increased. However, this compressor and air cooler are needed in any case, and larger capacity does not cost much extra. As illustrated by the calculations above, the present invention makes it possible to increase the load or increase the production on the floating LNG liquefaction unit, while maintaining the highest safety and environmental standards.

[Example 2 [0069] Table 2 shows simulation results for another example based on Figure 2 and with gas containing 1 mole% nitrogen, 95 mole% methane, 2 mole% ethane, 1 mole% propane, 0.5 mole% i-butane and 0.5 mole% n-butane. LNG production rate is 122 metric tons per hour, and the two columns are showing case 1 with 0% and case 2 with 60% of the flow in stream 22 being recycled from the CLSO to the platform in sub-sea pipeline 9.

[0070] The liquefaction plant compressor 18, 18' and 18" has polytrophic efficiency 82%, the liquefaction expander has a polytrophic efficiency of 79% and all air coolers have gas outlet temperatures of 20°C. Sub-sea pipelines 7 and 9 each have negligible pressure drop and the seawater temperature is 20°C, so there is no heat exchange with seawater.

Figure 2 Reference Variable Unit Case 1 Case 2

0% recycle 60% flow recycle flow

Compressor 5 Flow tons/h 122 305 Platform compressor Inlet pressure bara 80 80

Outlet pressure bara 250 250

Duty MW 6.9 17.1

Heat exchanger 1 1 Duty MW 12.4 CLSO gas /gas exchanger

Expansion unit 12 Pressure drop bar 170 170

Stream 13 Flow tons/h 122 122

Gas flow to CLSO liquefaction Pressure bara 80 80

Temperature °C -20 -51

Enthalpy relative to gas kJ/kg -175 -321 at 20°C and 40 bara

Stream 10 Flow tons/h 0 183

Recycle flow to platform Pressure bara — 80

Enthalpy relative to gas kJ/kg -321 at 20°C and 40 bara

Compressor 18, 18', 18" Duty MW 93.9 73.0 CLSO liquefaction compressor

Expander 17 Duty MW -21.5 -16.8 CLSO liquefaction expander

Compressor 18, 18' , 18" Net power required MW 72.4 56.2 Expander 17 CLSO

CLSO liquefaction plant kWh/kg 0.59 0.46 efficiency

Compressor 5 Net power required MW 79.3 73.3 Compressor 18, 18' , 18" Platform + CLSO

Expander 17

Table 2

[0071] Table 2 shows that the net power required onboard the CLSO, i.e. the duty of the compressors 18, 18', 18", and expander 17, is reduced from 72.4 MW to

56.2 MW, or by about 22%, according to this invention, using the example parameters and a single nitrogen liquefaction system. Significantly, the net power required on the pre-treatment unit plus the CLSO, i.e. the duty of the compressors 5, 18, 18', 18", and expander 17, is also reduced according to this invention, from

79.3 MW to 73.3 MW, or by about 8%, all compared to the traditional plant without heat exchanging of the incoming gas towards a gas recycle back to the pre- treatment unit. This is an unexpected result. The explanation for this is that the CLSO liquefaction plant employs a single nitrogen cycle refrigeration system, which has relatively low efficiency, and pre-cooling by pre-treated gas expansion is more efficient than pre-cooling by heat exchanging with nitrogen refrigerant which would otherwise be required.

[0072] The reduction of the enthalpy and the temperature of the gas introduced into the LNG heat exchanger 14 from line 13, i.e. an enthalpy reduction from -175 to -321 kJ/kg, and a temperature reduction from -20 to -51 °C of the same gas flow, clearly illustrates that the present invention provides for a solution that both reduces the net power requirement, and reduces the duty of coolers onboard the CLSO. Accordingly, the present invention provides for a solution for coastal liquefaction of LNG that makes it possible to use nitrogen as a coolant for the LNG heat exchanger and thus provides for a LNG facility that satisfies the requirements for safety and environment, with a significantly reduced specific power

requirement.

Example 3

[0073] Table 3 shows simulation results for a third example based partly on Figure 2, where the gas pre-cooling loop is identical to Figure 2 according to this invention, but where the liquefaction plant downstream of stream 13 has been replaced with the most efficient nitrogen liquefaction plant available. This liquefaction plant is described in a patent owned by Air Products and Chemicals, Inc., patent number US 8,656,733 B2, more specifically, the description related to Figure 1 found at column 4, line 36 to column 5, line 67.

[0074] Similar to example 2, the pre-treated gas in line 4 contains 1 mole% nitrogen, 95 mole% methane, 2 mole% ethane, 1 mole% propane, 0.5 mole% i- butane and 0.5 mole% n-butane. LNG production rate is 122 metric tons per hour. The liquefaction plant compressor, which similar to the compressor 18, 18' and 18" in Figure 2 compresses nitrogen, has polytropic efficiency 82%. The liquefaction expanders all have polytropic efficiency of 79%. All air coolers, operating as compressor intercoolers and after-cooler, have nitrogen gas outlet temperature of 20°C. Sub-sea pipelines 7 and 9 each have negligible pressure drop and the seawater temperature is 20°C, so there is no heat exchange with seawater.

[0075] The two columns in Table 3 show case 1 with 0% and case 2 with 60% of the flow in stream 22 being recycled from the CLSO to the platform in sub-sea pipeline 9.

Figure 2 Reference Variable Unit Case 1 Case 2

0% recycle 60% flow recycle flow

Compressor 5 Flow tons/h 122 305 Platform compressor Inlet pressure bara 80 80

Outlet pressure bara 250 250 Duty MW 6.9 17.1

Heat exchanger 1 1 Duty MW 12.4 CLSO gas /gas exchanger

Expansion unit 12 Pressure drop bar 170 170

Stream 13 Flow tons/h 122 122

Gas flow to CLSO liquefaction Pressure bara 80 80

Temperature °C -20 -51

Enthalpy relative to gas kJ/kg -175 -321 at 20°C and 40 bara

Stream 10 Flow tons/h 0 183

Recycle flow to platform Pressure bara — 80

Enthalpy relative to gas kJ/kg -321 at 20°C and 40 bara

CLSO liquefaction compressor Duty MW 56.4 44.7

CLSO liquefaction expanders Duty MW -17.9 -13.2

CLSO net power Compressor + expander MW 38.5 31.5

CLSO liquefaction plant kWh/kg 0.32 0.26 efficiency

Total power CLSO + platform CLSO net power + MW 45.4 48.6 compressor 5 power

Overall efficiency kWh/kg 0.37 0.40 (CLSO + compressor 5)

Table 3

[0076] Table 3 shows that the net power required onboard the CLSO, i.e. the net power input to the compressor and expander system, is reduced from 38.5 MW to 31.5 MW, or by about 18%, according to this invention, using the example parameters and one of the most advanced and efficient nitrogen liquefaction systems available (Air Products and Chemicals, Inc., patent number US 8,656,733 B2). Based on this, the objective with the present invention is fully achieved even with the most advanced nitrogen liquefaction system.

[Example 4

[0077] Example 4 shows comparison of a very efficient liquefaction system based on hydrocarbon refrigerant, one of the most standard and relatively efficient liquefaction systems based on nitrogen refrigerant, and the present invention in combination with patents US 8,656,733B2, as described above with reference to example 3, and US8,376,033B2 (GEA Batignolles Technologies Thermiques). US8,376,033B2, relates to heat exchangers comprising tubes with grooved fins, see especially figures 2, 3, 4, 5, 6 and the corresponding detailed description in column 4, line 4 to column 5, line 56.

[0078] Patent US 8,656,733B2 describes an extremely efficient liquefaction process using nitrogen refrigerant. In essence, this is a two-stage process, dividing refrigeration loads between cooler and warmer levels. Much of the nitrogen is pre-cooled and expanded such that the temperature is suitable for gas cooling at relatively warm levels. A smaller amount is pre-cooled and expanded to a lower temperature and pressure, suitable for the lowest temperature cooling duty.

[0079] Patent US8,376,033B2 describes a method to enhance the efficiency of air coolers. In air coolers, the fluid to be cooled flows inside tubes. The outside of the tubes are equipped with cooling fins, effectively increasing the contact area between the tubes and the air. However, some parts of the cooling fins are in the "shadow" of the tubes. In essence, this patent describes an invention where air flows all the way around the tubes, eliminating this "shadow" and thus utilizing a large part of total cooling fin area.

[0080] Results of the comparison are shown in Table 4, based on the following:

• LNG production rate: 122,000 kg/h or 34 kg/s (about 1 mtpa)

• Specific power consumption, hydrocarbon based refrigerant with water cooling: 0.27 kWh/kg • Specific power consumption, dual nitrogen liquefaction with water-cooling: 0.45 kWh/kg. This is based on typical efficiency for the most common nitrogen based liquefaction system, dual nitrogen.

• Enthalpy change of pre-processed gas in the liquefaction process (dH in Table 4): 800 kJ/kg

• Air cooler space requirement: 1000 m2 per 100 MW cooling. This is

reduced to 800 m2 per 100 MW cooling by use of air cooled heat exchangers according to patent US8, 376,033.

Table 4

[0081] As table 4 shows, the present invention in combination with patents US

8,656,733B2 and US8,376,033B2 requires less energy at the CLSO, has superior environment and safety performance, and employs air coolers with very moderate footprint requirement of 470 m2. In contrast, as shown in Table 1 , a traditional dual nitrogen liquefaction system without the features of the present invention, the improvements regarding liquefaction process and air coolers, respectively, as described in the patents US 8,656,733B2 and US8,376,033B2, would require 931 m2 or more than the double amount of space. These advantages can be used to substantially increase the liquefaction rate on the CLSO, substantially improving the economics of liquefaction projects based on the CLSO technology.

[0082] For a person skilled in the art, and depending on permits and

environmental conditions, it would be possible to optimize the system by using a turbo expander instead of, or in combination with, valve 22. Sub-sea pipelines could be a single pipe or parallel pipes from the platform to the CLSO, or multiple parallel flexible or rigid pipelines. The same would be the case for the recycle flow pipe. A person skilled in the art also knows that as shown in Figures 2 and 3, there is no extraction of natural gas liquids (NGLs) on the CLSO. All gas arriving at the CLSO is liquefied and stored in LNG tanks before export, with the exception of a small side draw of fuel gas. A person skilled in the art also knows that on the platform, highly efficient combined cycle power plant may be used, such that while Table 2 shows the net increase in compressor 5 power, the operating cost of compressor 5 is lower than the operating cost of the CLSO single cycle gas turbines. While platform is assumed in the examples, the remote pre-treatment and compression of gas may also take place on shore or on a separate floating vessel.

Claims

1. A method for LNG production, where natural gas is pre-treated in a pre- treatment unit to give a pre-treated gas stream mainly comprising methane, and where compounds potentially solidifying in the liquefaction process are reduced to a level lower than 50 ppm, where the pre-treated gas stream is compressed to a pressure of 100 - 300 bara , where the pre-treated and compressed gas is transferred in a subsea pipeline to a remote floating LNG liquefaction unit, where the gas transferred to the floating LNG liquefaction unit is expanded to a pressure of 40 to 100 bara, and subsequently introduced into a downstream LNG heat exchange system where the gas is cooled against a coolant to produce Liquefied Natural Gas (LNG), which is suitable for storage at atmospheric pressure, wherein the gas stream after arriving onboard the floating LNG liquefaction unit, after being expanded and before being introduced into the LNG heat exchange system, is split in two gas streams to give a first split gas stream that is introduced into the LNG heat exchange system, and a second split gas stream that is heated by heat exchanging against the incoming pressurized gas stream for cooling thereof, where the heated second gas stream is transferred back to the pre-treatment unit.

2. The method of claim 1 , wherein the expansion of the gas after arriving onboard the floating LNG liquefaction unit and before introduction of the gas into the LNG heat exchange system, comprises an isenthalpic expansion or a polytropic expansion.

3. The method of claim 1 or 2, wherein the heated second gas after being

transferred to the pre-treatment unit, is mixed with the pre-treated gas stream, compressed together with the pre-treated gas stream and transferred to the floating LNG liquefaction unit.

4. The method of any of the preceding claims, wherein the pre-treated gas is compressed by a pressure ratio of at least 1.5, preferably at least 2.0 or at least 3.0, before being transferred to the floating LNG liquefaction unit, and that the gas after arriving at the floating LNG liquefaction unit is expanded isenthalpic by substantially the same ratio as the compression.

5. The method of any of the preceding claims, wherein the first split gas stream constitutes 30 to 70% of the expanded gas stream.

6. The method of claim 2, wherein the first split gas stream constitutes 40 - 60% of the expanded gas stream, such as about 50%.

7. The method of any of the preceding claims, wherein the pre-treated and

compressed gas stream is cooled to a temperature of -10 to 60 °C before being transferred in the subsea pipeline.

8. The method of any of the preceding claims, wherein the coolant in the LNG heat exchanger is nitrogen.

9. The method of any of the preceding claims, wherein coolant heated by

liquefying LNG is withdrawn from the LNG heat exchange system and compressed in compression steps, where the coolant is cooled in a cooling cycle using air-coolers between the coolant compression steps.

10. A system for liquefaction of natural gas to produce LNG, the system

comprising a pre-treatment unit (1 ) to remove or to reduce the concentration of compounds that may form solids in the liquefaction process to below 50 ppm and a gas compressor unit (5) to compress the pre-treated natural gas, a gas transfer unit (2) comprising a gas transfer pipeline (7) for transferring the pre- treated gas to a remote floating LNG liquefaction unit (3), the floating LNG liquefaction unit comprising one or more expansion unit(s) (12) for expansion of the gas, a LNG heat exchange system (14) for cooling and thus liquefying the gas to produce LNG, an LNG export line (15') for withdrawing the produced LNG from the LNG heat exchange system (14) , and a LNG coolant

compression and cooling system (18, 19) for reduction of the enthalpy of the coolant and recycling the compressed and cooled coolant to the LNG heat exchange system, wherein the system additionally comprises a gas recycle pipeline (10) for withdrawing a part of the gas after being expanded and before being introduced into the LNG heat exchange system (14), the recycle pipeline (10) being arranged to introduce the withdrawn gas into a heat exchanger (1 1 ) for cooling the incoming compressed gas from the gas transfer pipeline (7), and where a subsea gas return pipeline (9) is arranged to transfer the withdrawn gas from the heat exchanger (1 1 ) and back to the pre-treatment unit

(1 ).

1 1. The system according to claim 10, wherein the one or more expansion unit(s) (12) includes one or more valves for isenthalpic expansion of the gas.

12. The system according to claim 10, wherein the one or more expansion unit(s) (12) includes one or more turbo expanders for polytrophic expansion of the gas.

13. The system according to claim 10, 1 1 or 12, wherein the gas return pipeline (9) is connected to the compressor unit (5) for re-compression and recycling of the gas to the floating LNG liquefaction unit (3).

14. The system according to any of the claims 10 to 13, wherein a cooler (6) is arranged after the compression unit (5) to cool the gas before being introduced into the gas transfer pipeline (7).

15. The system according to any of the claims 10 to 14, wherein two or more

serially connected compression units (18, 18', 18") for compression of coolant, and air-coolers (19, 19', 19") for cooling of the coolant after the compression steps.