NO20141176A1 - Process and plant for the production of LNG - Google Patents

Description

Technical Field

[0001] The present invention relates to improvements in methods and facilities for liquefaction of natural gas to provide liquefied natural gas (LNG) with improved economy, better safety for personnel and a reduction of environmental impact. More specifically, the present invention relates to a method and a facility for LNG production that is environmentally suitable for locations at sea, or for locations near coastlines, which can satisfy the requirements set with regard to increased safety, the environment and efficiency in

liquefaction.

Background technology

[0002] Natural gas is becoming more important as the world's energy needs increase and as concerns about emissions to air and water increase. Natural gas is readily available, especially with the new technologies for using shale gas. It is much more clean-burning than oil and coal, and is not associated with the problems of safety or waste landfills associated with nuclear power. Emissions of greenhouse gases are lower than for oil, and only about a third of such emissions result from burning coal.

[0003] There is significant international trade in natural gas. Price and availability vary significantly in different parts of the world. A large part of this trade is in the form of liquefied natural gas (LNG), which mainly consists of natural gas components lighter than pentane. These components are methane, ethane, propane, butane and traces of nitrogen. The methane concentration is typically over 85% on a molar basis, often over 90%, ethane can range from less than 1 to about 10% on a molar basis, propane can range from less than 0.1 to 3 mol%, while butane can be in range from less than 0.1 to 1%. The nitrogen concentration may be in the range of less than 0.1 to 1 mol%.

[0004] LNG is produced using two major treatment steps. The first step is gas pretreatment to remove CO2, H2S and water that can become solids and clog pipes in the cryogenic liquefaction process. The first step also includes the removal of trace elements, such as mercury, which can form amalgam - especially with aluminum process components, and lead to erosion / corrosion. Hydrocarbon fractions heavier than methane, collectively referred to as natural gas liquids (NGL), 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, for example 50 to 100 ppm on a mole basis, since these can solidify in

the liquefaction process. Other NGLs, ethane, propane and butane are removed to varying degrees depending on economic logic. NGL can be removed from the gas in the first LNG treatment stage, or as an integral part of the second treatment stage. The second treatment step is mainly condensation of the thus purified gas, which then mainly consists of methane. These first and second treatment steps take place at elevated pressures, usually in the range from 40 to 100 bar absolute (bara).

[0006] A final treatment step, downstream of the liquefaction process, comprises depressurizing to atmospheric pressure, and removing any remaining amount of nitrogen, typically any amount exceeding one mole%. This is done by flashing to LNG at atmospheric pressure. This produces the final LNG product, and a much smaller hydrocarbon gas stream enriched in nitrogen, which is usually used as fuel. The final LNG product is liquid at atmospheric pressure and approximately -163°C. It is stored in buffer tanks, and is then unloaded and shipped to destinations in LNG tankers. At the destination, the compressed LNG is re-gasified and sent to consumers in pipelines.

[0007] Treatment of natural gas to produce LNG has traditionally been done in large land-based facilities that include the two steps of pretreatment and condensing at the same site. The latest developments in technology and markets have enabled the construction of LNG plants on floating structures, a development that has inspired the relocation of a significant part of LNG processing plants offshore on floating Liquefied Natural Gas (FLNG) facilities to exploit large offshore gas reservoirs. The FLNGs are usually designed to be located at a distance from a coast and are connected to natural gas reservoirs via subsea pipelines. The FLNGs are also typically designed to act as buffer storage and as terminals for loading LNG tankers used to transport LNG to the markets.

[0008] The later development towards FLNGs has made offshore natural gas resources more available on the market compared to sending the gas ashore in pipes for condensation, and has resulted in a reduction of capital costs for establishing an LNG plant. Other important drivers include reducing environmental impacts onshore; reduction of problems related to land use for equipment and infrastructure; and reduced likelihood of resistance from local communities. The entire FLNG facility can be built in a shipyard, which is efficient and provides better quality, cost control and reduces construction time. FLNGs are also mobile and can be transferred to alternative locations if necessary.

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

[0010] The safety concerns associated with hydrocarbons on a narrow vessel's deck are the potential loss of hydrocarbons, in combination with ignition sources. This can lead to vapor 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 amount of hydrocarbons released and containment and containment in the area of the release. A well-known incident was the steam cloud explosion at Flixborough Works in the UK in 1974. Around 30 tonnes of reactive hydrocarbons were released and ignited about one minute after the release. The explosion led to 28 deaths and damage to approximately 2,000 homes in the local community (Reference Center for Chemical Process Safety, "Guidelines for vapor cloud explosions, pressure vessel burst, BLEVE and Flash Fire Hazards", 2nd edition, Wiley, 2010). The situation at FLNGs is that in order to obtain high LNG production rates, wet gas components are often preferred as refrigerants. For a plant of 4 million tonnes of LNG per year, the inventory of NGL components on deck can be in the order of a hundred tonnes for the LNG plant, with additional amounts in onboard extraction and storage facilities for LNG, as described in WO9801335, in the name of Den norske state oil company AS (now Statoil ASA). This is much more than the mentden that exploded at Flixborough Works, contained in a much smaller area.

[0011] Environmental concerns with FLNG are associated with significant amounts of process waste heat that 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 used as cooling liquid. Extremely large quantities are used, and then discharged at a higher temperature. Environmental concerns arise due to mechanical stress in the seawater pipes, increased seawater temperature and the use of toxic chemicals, which are harmful to marine life. The use of seawater coolant will probably be banned in many coastal waters, such as in the state of Louisiana, in the near future.

[0012] Concerns about FLNG production capacity are combined with safety concerns, since lower production capacity reduces the vessel's inventory of NGL components. It is also linked to environmental considerations, as lower production capacity reduces the process's cooling needs and the use of seawater coolant. However, the most challenging problem, which limits the production capacity, is the limited space on deck. This is only approximately 5% of the area that will be used on land for similar facilities with capacities. In this limited area, gas pre-processing and/or NGL extraction, liquefaction with associated power generation, auxiliary systems, unloading systems, and marine specific equipment must be located. Reduced LNG production capacity reduces the space needed for all this, reduces crowding and simplifies equipment layout.

[0013] Ongoing work with these challenges, of which the innovation described in this patent is a part, has resulted in a new adaptation of FLNG. This is the Coastal Liquefaction, Storage and Offloading (CLSO) facility. The CLSO adaptation addresses FLNG safety, environmental impact and issues around processing capacity. Unlike FLNG systems, where the first treatment step, gas pre-processing is carried out entirely onshore, at separate terminals or on separate floating systems, instead of taking up valuable space on the liquefaction vessel. This remote pre-processing includes the extraction of NGLs. Fully pre-processed gas is transported by pipeline to one or more floating CLSOs, which now have much more deck space available, freed up by removing pre-processing. The extra space is used to increase safety by using nitrogen cooling in the liquefaction process instead of hydrocarbon refrigerants. This reduces the hydrocarbon inventory on the vessel's deck by a factor of 10 or more. This stock mainly consists of pre-processed gas, or methane, which is significantly less reactive than NGL components. The extra space is also used for better environmental properties, by using air cooling instead of seawater cooling. Finally, the additional space is used for additional liquefaction capacity, to significantly improve overall system economics.

[0014] Liquid end systems that use nitrogen cooling are less efficient than those systems that use hydrocarbon coolant. This results in increased specific power consumption. Gas turbines, which are usually used for power generation, are available in standard sizes, and only a few of these are certified for use on offshore floats. Therefore, if the largest available gas turbine is used, increased specific power consumption means reduced LNG production rates. Furthermore, nitrogen systems are available in only smaller sizes, for example 1 to 1.5 million tonnes per year (MTPa), in contrast to hydrocarbon systems which are available in sizes above 4 MTPA. A greater number of plants are required when nitrogen refrigerants are used, which potentially increases the space requirement.

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

[0016] Table 1 shows a comparison 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 condensing plants, expressed in kWh/kg of LNG, which when multiplied by the LNG production rate in kg/hour gives the power required. It is also based on the total enthalpy change of pre-processed gas in the LNG process, expressed in 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, the power used in the liquefaction process and heat removed from the gas, is the amount of excess process heat that must be transferred to water or air. Table 1 is based on the following: • Gas composition: 1 mol% N2, 95 mol% methane, 2 mol% ethane, 1 mol% propane and 1 mol% butane (0.5 mol% i-butane and 0.5 mol% n -butane).

• LNG production rate: 122,000 kg /1 or 34 kg / s (approx. 1 MTPA),

• Specific power consumption, hydrocarbon-based coolant with water cooling:

0.27 kWh/kg,

• Specific power consumption, nitrogen cooler with water cooling: 0.45 kWh / kg.

This is based on typical efficiency for the most common nitrogen-based LNG system, which is called double nitrogen.

• Increase in specific power consumption when air cooling is used: 20%

• Enthalpy change of the pre-processed gas in the liquefaction process (dH in table 1): 800kJ/kg

• Air cooling space requirements: 1000 m<2>per 100 MW of cooling.

Comparison of work and cooling duty for liquefaction processes

Note 1: Hydrocarbon air-cooled systems which are not normally used on floats

Note 2: CLSO uses a nitrogen air-cooled system on floats. Air cooler area required is 931 m<2>.

[0018] In relation to water-cooled hydrocarbon-based condensing systems, CLSOs with nitrogen refrigerant and air cooling result in a significant increase in the compressor's power requirement, and in cooling effect. The additional space required for air coolers, 931 m<2>, is significant. But the environment and safety are paramount

CLSO.

[0019] On a CLSO, available deck space is limited by the size of the vessel. Therefore, the safest and most environmentally friendly liquefaction process is challenging if production rates corresponding to the most efficient systems, hydrocarbon refrigerant and water cooling are required.

[0020] Although improved air coolers have been developed in recent years, see e.g. US8,376,0337, to GEA Batignolles Technologies THERMIQUES, air coolers that significantly reduce cover area compared to traditional air coolers, and improved liquefaction processes are being developed, see e.g. eg US 8,656,733B2 to Air Products and Chemicals Inc., further development to create a more efficient LNG process is necessary to make an LNG process meet the relevant safety and environmental requirements, and at the same time be economically feasible.

[0021] Natural gas precooling using lithium bromide, CFC or HCFC based systems is known to reduce nitrogen LNG plant energy requirements. It also increases the liquefaction capacity. However, the pre-cooling equipment requires considerable space on deck. This reduces the available condensing plant and thus the liquefaction capacity, and defeats the purpose of such pre-cooling space. Therefore, the net benefit of traditional pre-cooling may be small.

[0022] An aim of the present invention is to provide a method and a plant for LNG production which is environmentally suitable in places at sea, or in places near coastlines, which will satisfy the requirements set with regard to the risk of personnel, a risk that must be as low as reasonably practicable, which will satisfy the strictest requirements for environmental protection, which in particular means no use of seawater for cooling purposes, and which at the same time maintains the highest condensing efficiency and the lowest power requirement for liquid LNG facilities on board.

[0023] A second aim of the present invention is to provide a method and a system for the production of LNG from natural gas on CLSO devices which enables maximized production rates, minimal power requirements and minimum cooling requirements, but which at the same time has the best safety and environmental performance, without using much extra deck space. An object of the invention is therefore essentially to improve the efficiency of air-cooled nitrogen systems, within the limitations imposed by CLSO technology where gas pre-processing takes place at a remote platform or on land, where the gas must be transferred to CLSO in sub -sea pipelines, and where space at CLSO is limited. It is important that the gas that is transferred in submarine pipelines must have a temperature close to seawater temperature, to avoid damage to pipelines in the event of phenomena such as overturning buckling. Therefore, it is not possible to significantly pre-cool gas upstream of the underwater pipeline, or in the subsea

pipeline.

Summary of the invention

[0024] According to a first aspect, the present invention provides a method for LNG production, where natural gas that is pre-treated in a finishing unit to give a pre-treated gas stream that mainly comprises methane, and where compounds that potentially solidify in the condensation 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 submarine pipeline to a remote floating LNG condensing unit, where the gas transferred to the liquid The LNG condensing unit is expanded to a pressure of 40 to 100 bar absolute, and then fed into an LNG heat exchanger and cooled against a refrigerant to produce liquefied natural gas (LNG), where the gas stream after arriving on board the liquefied LNG condensing unit, after being expanded and before entering the LNG heat exchanger, is split into two gas streams to provide a first partial gas flow that is fed into the LNG heat exchanger, and a second partial gas flow that is heated by heat exchange against the incoming pressurized gas flow for cooling them, where the

heated second gas stream is transferred to the pretreatment unit.

[0025] By splitting the expanded and thus cooled gas on board the floating LNG condensing unit into two streams, introducing a first partial flow into the LNG heat exchanger, introducing a second partial flow into a heat exchanger for heat exchange of said second partial flow against the the incoming pressurized gas, the temperature and enthalpy of the incoming pressure stream are further reduced. The temperature and enthalpy reduction results in lower power and cooling requirements on board the floating LNG unit. It also results in raising the temperature of the second substream to approximately the same temperature as the incoming gas, which enables transfer to the pretreatment unit in subsea pipelines without problems that may result from thermal expansion or contraction of the pipe material. All this is achieved at the expense of an increased power requirement for compressing a larger volume of pre-treated natural gas at the pre-treatment unit. But space constraints and availability of power are normally far less limited at the pretreatment unit than on board a floating LNG unit. Accordingly, the recirculation loop functions as a heat pump, transferring heat from the liquid LNG condensing unit to the pretreatment unit, without creating problems of thermal expansion or contraction in subsea pipeline materials.

[0026] According to one embodiment, expansion of the gas after arrival on board the liquid LNG condensation unit, and before the introduction of gas into the LNG heat exchanger, comprises an isenthalpic expansion. All or part of the expansion of the gas may be isenthalpic. The gas is isenthalpically expanded and then split into a first and second sub-stream, and heat exchange equipment requires far less space and equipment on board the deck of the external LNG unit than the traditional gas pre-cooling systems such as lithium bromide, CFC or HKFK units. This increases safety by providing more space for safety barriers. It improves the environmental aspect by eliminating the possibility of emission of lithium bromide, CFC or HKFK.

[0027] According to one embodiment, after being transferred to the pretreatment unit, the second heated gas is mixed with the pretreated gas stream, compressed together with the pretreated gas stream and is transferred to the liquid LNG condensing unit. The pre-treated gas is "LNG ready", i.e. unwanted components in the gas are removed or reduced to acceptable concentrations, eg below 50 ppm. The recycled gas has not been mixed with any unwanted components, and is still clear LNG gas and can be recycled directly.

[0028] According to one embodiment, the pre-treated gas is compressed at a pressure ratio of at least 1.5, preferably at least 2.0 or at least 3.0, before being transferred to the liquid LNG condensation unit, and that the gas after arrival the liquid LNG unit expands isenthalpically by substantially the same ratio as compression. Compression at the pretreatment unit and expansion at the liquid LNG condensing unit at substantially the same ratio results in a gas pressure in the recirculating gas that is substantially the same as that of the pretreated gas introduced into the compressor unit at the pretreatment unit for compressing the gas. Accordingly, no or minor changes in pressure are required to introduce the recycled gas into the compression unit along with the pretreated gas. The expansion of the liquid LNG condensing unit can 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 it is transferred to the liquid LNG condensing unit to overcome the pressure drop across transport lines, heat exchangers etc, a pressure difference which is covered by the expression "substantially the same ratio".

[0029] 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 approx. 50%. The amount of gas in the first split stream is fed into the LNG heat exchanger, and the amount of gas for cooling the incoming gas to the liquid LNG condensing unit must be optimized for the plant in question and the climate in question. The higher the fraction of gas in the first split gas stream, the lower the fraction of gas in the second split gas stream, resulting in a reduced cooling effect in the heat exchanger for cooling incoming gas into the liquid LNG condensing unit. A high proportion of recycled gas through the heat exchanger will give a greater cooling effect at the expense of increased load on the compressor on the pretreatment unit and the need for high capacity in the gas return pipeline back to the pretreatment unit.

[0030] According to one embodiment, the pre-treated and compressed gas stream is cooled to a temperature of 5 to 60 °C before it is transferred in the submarine pipeline. Preferably, the pre-treated and compressed natural gas is cooled to ambient temperature, i.e. the temperature of the area in question, to avoid damage to the pipeline due to thermal expansion or contraction of the pipe materials, resulting in undesirable phenomena such as expansion buckling. Obviously, some cooling will occur if the gas inside the pipeline is warmer than the surrounding sea, but the cooling effect is not reliable due to fouling of the outside of the pipeline, and is not important to system performance. In addition, a temperature gradient over the pipeline can be environmentally undesirable in that it creates areas around the pipeline with higher or lower than normal temperatures.

[0031] The method according to any one of the preceding claims, wherein the coolant in the LNG heat exchanger is nitrogen. Nitrogen is a preferred refrigerant as nitrogen is inert, non-toxic and has no impact on the environment if accidentally released into the atmosphere. Alternative coolants are either flammable and can cause violent fires and/or explosions, are toxic or can lead to undesirable effects on the environment. However, nitrogen is less effective as a refrigerant than some of the other alternatives and requires measures, such as those described above, to be an economically viable alternative.

[0032] The method according to any one of the preceding claims, where the coolant is heated by liquefaction of LNG that has been withdrawn from the LNG heat exchanger and is compressed in compression stages, where the coolant is cooled in a cooling cycle with air coolers between the coolant compression stages. The method described above makes it possible to use air coolers without the need to increase the area of the liquid LNG condensing unit to an unacceptable degree, or to reduce LNG condensing capacity, thus making the use of air coolers an economically and technically viable alternative.

[0033] According to another aspect, the present invention relates to a system for liquefaction of natural gas to produce LNG, where the system comprises a pretreatment unit to remove or reduce the concentration of compounds that can form solids in the liquefaction process to below 50 ppm and a gas compressor unit to compressing the pre-treated natural gas, a gas transfer unit comprising a gas transfer pipeline for transferring the pre-treated gas to an external liquid LNG condensing unit, where the liquid LNG condensing unit comprises one or more expansion unit(s) for expanding the gas, an LNG heat exchanger for cooling and thereby condensing the gas to produce LNG, an LNG export line for withdrawing produced LNG from the LNG heat exchanger, and an LNG coolant cooling system for cooling heated coolant and recycling the cooled coolant to the LNG heat exchanger, where the system additionally comprises a gas recycling pipe dning to extract a portion of the gas after being expanded and before it is introduced into the LNG heat exchanger, the recycle pipeline being adapted to introduce extracted 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 extracted gas from the heat exchanger back to the pretreatment unit.

[0034] According to one embodiment, the one or more expansion unit(s) comprise a

or several valves for isenthalpic expansion of the gas.

[0035] According to one embodiment, the gas return pipeline is connected to the compressor unit for re-compression and recycling of the gas to the liquid LNG condensing unit.

[0036] According to another embodiment, a cooler is arranged after the compression unit to cool the gas before it is introduced into the gas transfer pipeline.

[0037] According to yet another embodiment, two or more compression units for compressing the refrigerant are connected in series, and air coolers for cooling

the refrigerant after the compression stages.

Brief description of the drawings

[0038]

Figure 1 is an overview of a pre-treatment unit, subsea pipelines and a CLSO, Figure 2 is a schematic diagram of a first embodiment of the present invention, Figure 3 is a schematic diagram of a second embodiment of the present invention, and Figure 4 is an illustration of reduction of gas enthalpy as a function of the discharge pressure of the pretreatment unit's compressor.

Detailed description of the invention

[0039] 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 subgroup of FLNG or, as used in a broader sense herein, "floating LNG unit", all facilities and units are normally floating units, or vessels. The term "gas" is used for a gas consisting of lower hydrocarbons, found in geological formations, either together with oil, in gas fields, and in shale as shale gas. Depending on the source, natural gas can vary in hydrocarbon composition, but methane is almost always the dominant gas. The professional in this field has a good knowledge of the abbreviations LNG and NGL, i.e. Liquefied Natural Gas, and Natural Gas Liquids respectively. LNG consists of methane, as normal with a smaller concentration of C2, C3 and C4 hydrocarbons, and practically no C5 + hydrocarbons. LNG is a liquid at atmospheric pressure at - 163 °C. NGL, on the other hand, is a collective term for mainly C2+ hydrocarbons, found in untreated natural gas. LPG is an abbreviation for liquefied petroleum gas, and mainly consists of propane and butane. The unit "bara" is "bar absolute". Consequently, 1.013 is just the normal atmospheric pressure at sea level. The term "ambient temperature" as used herein may vary with the climate for operating the plant according to the present invention. Normally, the ambient temperature for operation of the present plant is from approx. 0 to 40 °C, but the temperature can also be from below zero to slightly above 40 °C, for example 50 °C, under certain operating conditions.

[0040] Figure 1 is a schematic diagram of a system according to the present

invention, comprising a gas pre-treatment unit 1 which can be arranged on an offshore terminal, on a barge or another float or on land-based facilities, a high pressure gas transfer unit 2 comprises a gas transfer pipeline 7 to a floating LNG unit 3, and a high pressure gas recycling pipeline 9 for gas recycling from the liquid LNG condensation unit 3 to the gas pretreatment unit 1. The liquid LNG unit 3 according to the present invention is also identified herein as a CLSO.

[0041] The 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 can be called "LNG ready natural gas". Pretreatment usually consists of, but is not limited to:

• Hg removal,

• Gas sweetening, i.e. removal of unwanted acid gases, such as CO2 and H2S from natural gas, • Dehydration, i.e. removal of water that could otherwise lead to the formation of hydrates from gas, • Full NGL extraction and processing, i.e. separation of NGLs from the gas, including separation of essentially all C5 + components. Optional fractionation of NGL into salable products, which depending on the NGL composition may include Liquefied Petroleum Gas (LPG).

[0042] During the pretreatment, components removed from the gas always include all components that can solidify at condensing 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 will depend on the component itself, for example water is preferably reduced to a maximum level of 1 ppb.

[0043] Figure 2 illustrates a first embodiment of the present invention with further details. The natural gas pre-treated in the pre-treatment unit 1, flows via the gas line 4 at a pressure of typically 40 to 100 bar absolute, is mixed with recycled gas 8, which is at the same pressure as the gas in the pipeline 4, and introduced into a compressor unit 5. The gas mixture is compressed in the compressor unit at a pressure ratio

of at least 1.5, for example at least 2, or even more preferably at least three,

depending on the pressure in the line 4 which is typically from 40 to 100 bara to a pressure that is typically from 100 to 250 bar absolute, and is cooled in a cooling unit 6 typically to a temperature close to ambient temperature, i.e. from approx. 5 to 55 °C depending on the climate. The cooling unit 6 is suitably an air-cooled heat exchanger.

[0044] The pre-treated, compressed and cooled natural gas is transferred to the liquid LNG condensation unit 3 via the gas transfer pipeline 7, a pipeline arranged on the seabed and which can be several kilometers long. The gas temperature may increase or decrease somewhat in the gas transfer pipeline 7 due to some heat exchange with the surrounding seawater, but such effects are immaterial in the present invention.

[0045] On board the floating LNG condensing unit 3, the gas is pre-cooled in a heat exchanger 11 against a recycling gas flow which will be described in more detail below. The pre-cooled gas in the heat exchanger 11 is taken out in a pipeline 21 to an expansion unit 12, above which the pressure of the gas is reduced by a pressure reduction factor of at least 1.5, for example at least 2, or more preferably at least 3, for to result in a pressure of typically 45 to 100 bar absolute, typically to a pressure close to the pressure in line 4, as mentioned above. The expansion unit 12 may be a valve or may include a valve in combination with another expansion device, such as an expander. A valve for expansion of the gas is isenthalpic pressure reduction in the gas. An expander takes work from the expansion process, thereby reducing the enthalpy of the gas, which is an advantage for the downstream condensation process. The expanded gas is taken out through a pipeline 22, and is split into a recycling gas pipeline 10 and a process gas pipeline 13. The gas in the gas recycling pipeline 10 has essentially the same pressure as the gas in the process pipeline 13.

[0046] The amount of gas in the recycling pipeline 10 is preferably from about 30 to about 70%, such as about 40 to 60%, or about 50% of the gas in the pipeline 22. A person skilled in the art will understand that the distribution between the recycling pipeline 10 and the process pipeline 13 can be controlled in a conventional way, such as valves not shown, back pressure in pipelines or downstream equipment, etc.

[0047] The gas in the recycling pipeline 10 is fed into the heat exchanger 11 for cooling incoming gas which is introduced via the gas transfer pipeline 7. The remaining gas from pipeline 22 is taken out through pipeline 13 to be liquefied, without further compression or expansion.

[0048] The gas which is introduced into the heat exchanger 11 from the recycling gas line 10, after being used for cooling incoming gas from the pipeline 7, is withdrawn from the heat exchanger 11 via a gas recycling line 23 and is returned to the pretreatment unit 1 in an underwater gas pipeline 9. The temperature in the recycle line 23 is usually close to ambient temperature, as indicated above for the gas in line 7.

[0049] The gas is recycled to the pretreatment unit in a

gas recycling pipeline 9 and is fed into a transfer line 8, and fed into the compressor unit 5 together with the incoming

pre-treated gas in pipeline 4. This re-introduction of gas into the suction of the compressor 5 completes the gas pre-cooling circuit, and the final result is a significant reduction of gas enthalpy in the process gas line 13. The effect of the reduction in enthalpy on the cooling demand for the further LNG process is reduced .

[0050] The gas pressure in line 4 and in line 13 is preferably essentially the same, although small differences in the pressure in the lines may occur. Any pressure differences in lines 4 and 13 are normally due to the pressure drop across different parts of the path for recycling gas, and more specifically due to the pressure drop in lines 10, 23, 9 and 8, and the heat exchanger 11 for a recycled gas part. Consequently, the reduction in gas enthalpy in process line 13 relative to the gas in line 4 is mainly caused by a reduction in

gas temperature.

[0051] Gas temperature reduction in line 21, in relation to the temperature in supply gas line 4, can be in the range 20 to 70 ° C. In other words, by starting with a gas at a temperature of typically 20 ° C introduced in the present plant in line 4, the temperature of the gas in the line 21 will typically be from about 0 to about -50 °C. In many cases, the outlet temperature of the underwater pipeline 7 will be essentially the same as the temperature in line 4. Therefore, the temperature drop across the heat exchanger 11 can also be in the range of 20 to 70 °C. The temperature reduction of the gas in line 13, in relation to the temperature in the supply gas line 4, can be in the range 40 to 90 ° C. This mainly depends on the fraction of gas from line 22

which is recycled via line 10, the pressure drop in the expansion device 12,

exemplified with a valve, and approximate temperature in the heat exchanger 11.

[0052] The low-enthalpy process gas in line 13 is condensed in a nitrogen condensation unit. The person skilled in the art knows that various designs of such condensing systems exist, for example single or double nitrogen systems, and that all of these take advantage of any upstream reduction in the enthalpy of the gas. Figure 2 shows the simplest and least efficient of the nitrogen condensation systems, a simple nitrogen system.

[0053] The process gas in line 13 is further cooled, condensed and subcooled in an LNG heat exchanger 14. The condensed gas is expanded to a pressure close to atmospheric pressure in valve 15, and sent via an LNG export line 15' to a flash unit not shown, where excess nitrogen and smaller quantities of non-liquefied natural gas are separated and removed. The liquid phase is then transferred to buffer storage on the liquid LNG unit for later unloading and export.

[0054] The cooling medium in the LNG heat exchanger 14 is preferred due to the environmental and safety reasons stated above, nitrogen. The described refrigerant cooling circuit shown in figures 2 and 3 is a simple and well known concept. Heated gaseous refrigerant is withdrawn from the LNG heat exchanger 14 through a refrigerant withdrawal pipeline 20' and introduced into series-connected compressors 18, 18', 18". Air coolers 19, 19', 19'' are arranged after each compressor to cool the compressed refrigerant. It the compressed and cooled refrigerant is fed into the LNG heat exchanger via a refrigerant line 20 for further cooling, and is withdrawn from the LNG heat exchanger in a pre-cooled cooling line 16. The pre-cooled refrigerant is then introduced into an expander 17 to expand and further reduce the temperature and enthalpy, and is recycled to the LNG heat exchanger 14 where it is used as a coolant.

[0055] Typically, the target temperature for hydrocarbon in the LNG heat exchanger is -163 °C, a temperature at which several compounds found in the natural gas produced will solidify. To avoid sedimentation of solids, and the possibility of blocking of low-temperature elements in an LNG plant, all compounds that can form solids in the process system during processing and condensation are removed or the concentration of the compounds is reduced during the pretreatment of the gas to levels usually below 50 ppm to avoid such problems.

[0056] Figure 3 shows a second embodiment of the present invention. All reference numbers found in both figures 2 and 3 relate to the same elements, and only the non-common elements are described in more detail below. Depending on operating parameters, some liquid may have separated in the expansion unit 12, so that stream 22 is a two-phase gas/liquid stream. A liquid separation tank 23 can be arranged to separate liquid from the gas, and gives a pure liquid stream 27, and a pure gas stream 26. Part of the gas stream can be mixed with the liquid stream by means of valves 24 and 25, and give a liquid rich power to the LNG exchanger 14, where further

cooling and condensation are completed.

Examples

Example 1

[0057] Figure 4 shows the enthalpy reduction in line 22, in relation to gas at 40 bar and 20 C, which has been given 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 mol% nitrogen, 95.0 mol% methane, 2.0 mol% ethane, 1.0 mol% propane and 1.0 mol% butane. The horizontal axis shows the outlet pressure from the pretreatment unit 1 compressor unit 5. The vertical axis shows gas enthalpies in relation to 40 bar and 20 °C gas. The following is common to all cases: • gas is compressed in the compressor 5 from 40 bara to the compressor outlet pressure shown in Figure 4, and then cooled in the cooler 6 to 20 °C. • There is no gas heating or cooling in the underwater pipeline 7 as the gas temperature is approximately equal to the ambient sea temperature.

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

• The gas temperature in line 23 is 10 °C

[0058] The upper line, labeled "No gas recycling" shows enthalpy reduction without return of gas from the CLSO to the platform, which is the state of the art. This enthalpy reduction is only a function of the gas pressure, since the calculation is based on isenthalpic expansion in expansion unit 12. Higher compression gas pressure gives lower gas enthalpy.

[0059] The line below, labeled "50% gas recycle", shows the relative enthalpy of gas in line 22 when 50% of the liquid in line 22 is recycled to the platform via the heat exchanger 11 and gas recycle pipeline 9.

[0060] The line labeled "66% gas recycle" below this shows the relative enthalpy of gas in line 22 when 66% of the liquid in line 22 is recycled to the platform via the heat exchanger 11 and the gas recirculation pipeline 9.

[0061] Finally, the bottom horizontal line, labeled "Enthalpy LNG", shows the relative enthalpy of the final LNG product. Reduced enthalpy in the gas in line 22 and thus line 13, reduces the remaining enthalpy to be removed to reach the "Enthalpy LNG" line. The load on the CLSO liquefaction process is correspondingly reduced. This in turn reduces the size of the LNG exchanger 14, the load on compressors 18, 18' and 18'', and the size and space requirements of air coolers for liquefaction of a predetermined amount of LNG.

[0062] The reduction of gas enthalpy as a function of the compressor discharge pressure from compressor 5, as shown in the figure, can be calculated to reduce the compressor's load and space requirements for air coolers for the production of a predetermined quantity of LNG, for example compared to compressor load and air cooler space requirements according to the state of the art, i.e. without recirculation of partially expanded natural gas as described here.

[0063] During operation according to the known technique, compression and cooling at the pretreatment unit 1 results from, for example, 40 to 200 bar absolute, and expansion of the gas on board the floating LNG unit or CSLO, compared to a "base case" transport of the natural gas in line 4 on board the liquid LNG unit at 40 bar and 20 °C, in a reduction in LNG heat exchanger size, compressor load and air cooler space requirements of the order of 18%. Consequently, compression of the natural gas prior to transport through pipelines results both in reduced cooling requirements on board the liquid LNG condensing unit, and reduces the volume of gas to be transported, which allows for the use of smaller diameter pipelines.

[0064] It can also be seen from Figure 4 that the recycling of 50% of the gas transported on board the floating LNG unit or CLSO according to the invention results in a reduction in the corresponding LNG storage, compressor duty and air cooler space requirements to approximately 36 % compared to the "base case", or approximately twice the savings shown for the previously known solution without re-circulation.

[0065] By further increasing the recycling flow, to 66%, it can be seen that the corresponding reductions are almost 50% compared to the "base case". The person skilled in the art will understand that reductions in the load as described above can be used to reduce the load on the CLSO equipment, to reduce the size of the liquid LNG condensing unit, or to significantly increase the LNG production capacity, and significantly improve the system's financial return. Note that a reduction in the load on the equipment on board the floating LNG unit is achieved because the load on platform equipment, particularly compressor 5 and air cooler 6, has been increased. However, this compressor and air cooler are necessary in all cases, and larger capacity does not cost much extra. As shown by the above calculations, the present invention makes it possible to increase the load or increase the production of the liquid LNG condensing unit, while maintaining the highest safety and

environmental standards.

Example 2

[0066] Table 2 shows simulation results for another example based on Figure 2 and with gas containing 1 mol% nitrogen, 95 mol% methane, 2 mol% ethane, 1 mol% propane, 0.5 mol% i-butane and 0 .5 mol% n -butane. LNG production rate is 122 metric tons per hour and the two columns show case 1 with a 0% and case 2 where 60% of the flow in stream 22 is recycled from CLSO to the platform in subsea pipeline 9.

[0067] The condensing plant's compressor 18, 18' and 18'' have a polytropic efficiency of 82%, the liquefaction expander has a polytropic efficiency of 79% and all air coolers have gas outlet temperatures of 20°C. Subsea pipelines 7 and 9 each have negligible pressure drop and the seawater temperature is 20 °C, so there is no heat exchange with seawater.

[0068] Table 2 shows that the net power required on board the CLSO, i.e. the power of the compressors 18, 18', 18", and expander 17, has been reduced from 72.4 MW to 56.2 MW, or by about 22% , according to the present invention, using exemplified parameters and a simple nitrogen condensing system. It is significant that the net power required on the pretreatment unit plus CLSO, i.e. the power on the compressors 5, 18, 18', 18", and expander 17, is also reduced according to the invention, from

79.3 MW to 73.3 MW, or with approx. 8%, all compared to traditional plants without heat exchange with the incoming gas to a gas recycling back to the pre-treatment unit. This is an unexpected result. The explanation for this is that the CLSO LNG plant uses a simple nitrogen cycle

cooling system, which has a relatively low efficiency.

[0069] The reduction of the enthalpy and temperature of the gas introduced into the LNG heat exchanger 14 from pipeline 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 shows that the present invention provides a solution that both reduces the net power requirement and reduces the cooler effect on board the CLSO. Accordingly, the present invention provides 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 an LNG plant that satisfies the requirements for safety and the environment, with a significantly reduced

specific power requirement.

Example 3

[0070] Table 3 shows simulation results for a third example based in part on figure 2, where the gas pre-cooling loop is identical to figure 2 according to the invention, but where the LNG plant downstream of stream 13 has been replaced with the most efficient nitrogen LNG plant available. This condensing plant is described in a patent owned by Air Products and Chemicals, Inc., patent number US 8,656,733 B2, more specifically, the description in connection with Figure 1 found in column 4, line 36 to column 5, line 67.

[0071] In the same way as Example 2, it contains pretreated gas in line 4 1 mol% nitrogen, 95 mol% methane, 2 mol% ethane, 1 mol% propane, 0.5 mol% i-butane and 0.5 mol % n-butane . The LNG production rate is 122 tonnes per hour. The LNG plant's compressor, which, like the compressor 18, 18' and 18'' in Figure 2, compresses nitrogen, has a polytropic efficiency of 82%. The deliquescent expanders all have a polytropic efficiency of 79%. All air coolers, which operate as compressor coolers and aftercoolers, have a nitrogen gas outlet temperature of 20 °C. Subsea pipelines 7 and 9 each have negligible pressure drop and the seawater temperature is 20 °C, so there is no heat exchange with seawater.

[0072] The two columns in table 3 show case 1 with 0% and case 2 where 60% of the flow in stream 22 is recycled from CLSO to the platform in underwater pipeline 9.

[0073] Table 3 shows that the net power required on board the CLSO, i.e. the net power supply to the compressor and expansion system, is reduced from 38.5 MW to 31.5 MW, or by approximately 18%, according to the present invention, by using exemplified parameters and one of the most advanced and efficient nitrogen liquefaction systems available (Air Products and Chemicals, Inc., patent number US 8656733 B2). Based on this, the purpose of the present invention is fully achieved even with

the most advanced nitrogen condensation system.

Example 4

[0074] Example 4 shows a comparison of a very efficient condensing system based on hydrocarbon refrigerant, one of the most common and relatively efficient condensing 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 TH ERM IQU ES). US8,376,033B2, relates to heat exchangers consisting of tubes with grooved fins, see in particular figures 2, 3, 4, 5, 6 and the corresponding detailed description in column 4, line 4 to column 5, line 56.

[0075] US patent 8,656,733B2 describes an extremely efficient condensation process using nitrogen refrigerant. Essentially, this is a two-stage process, which splits cooling loads between cooler and warmer levels. A large part of the nitrogen is pre-cooled and expanded so that the temperature is suitable for gas cooling at relatively hot levels. A smaller amount is pre-cooled and expanded to a lower temperature and pressure, suitable for the low temperature cooling effect.

[0076] Patent US8,376,033B2 describes a method for improving the efficiency of air coolers. In air coolers, the fluid to be cooled flows inside the pipes. The outside of the pipes is equipped with cooling fins, effectively increasing the contact area between the pipes and the air. However, some parts of the heatsinks are in the "shadow" of the pipes. In essence, this patent describes an invention where the air flows all the way around the tubes, eliminating this "shadow", and thus using a large part of the total cooling fin area.

[0077] The results of the comparison are shown in table 4, based on the following: • Gas composition: 1 mol% N2, 95 mol% methane, 2 mol% ethane, 1 mol% propane and 1 mol% butane (0.5 mol% in -butane and 0.5 mol% n-butane).

• LNG production rate: 122,000 kg /1 or 34 kg / s (approx. 1 MTPA)

• Specific power consumption, hydrocarbon-based coolant with water cooling:

0.27 kWh/kg

• Specific power consumption, dual nitrogen condensation with water cooling: 0.45 kWh / kg. This is based on typical efficiency for the most common nitrogen-based LNG systems, dual nitrogen.

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

[0078] Space requirements for air coolers: 1000 m2 per 100 MW of cooling. This has been reduced to 800 m2 per 100 MW of cooling using air-cooled heat exchangers according to patent US8,376,033.

[0079] As table 4 shows, the present invention in combination with patents US 8,656,733B2 and US8,376,033B2 requires less energy at CLSO, is superior in terms of environment and safety, and uses air coolers with a very moderate footprint requirement of 470 m2. In contrast, as shown in Table 1, a traditional draftless dual nitrogen condensing system of the present invention with improvements regarding the condensing process and air coolers, respectively, as described in patents US 8,656,733B2 and US 8,376,033B2, would require 931 m2, or more than twice as much space. These advantages can be used to increase the condensation rate on CLSO, significantly improving the economics of liquefaction projects based on CLSO technology.

[0080] For a person skilled in the field, and depending on permits and environmental conditions, it will be possible to optimize the system by means of an expansion device instead of, or in combination with, valve 22. Underwater pipelines can be a single pipe or parallel pipes from the platform to the CLSO or several parallel flexible or rigid pipes. The same will be the case for the recirculation pipe. The expert also knows, as shown in figures 2 and 3, that there is no extraction of natural gas liquids (NGL) at CLSO. All gas arriving at CLSO is liquefied and stored in LNG tanks before export, with the exception of a small side stream of fuel gas. The person skilled in the art also knows that on the platform, highly efficient combined cycle power plants can be used, so that while Table 2 shows a net increase in compressor 5 power, the operating costs of compressor 5 are lower than the operating costs of CLSO single cycle gas turbines. While the platform is assumed in the examples, the remote pretreatment and compression of gas can also take place on land or on a separate floating vessel.

Claims (14)

1. 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 solidified in the condensation process are reduced to a level lower than 50 ppm, where the pre-treated gas stream is compressed to a pressure of 100 - 300 bar absolute, where the pre-treated and compressed gas is transferred in a subsea pipeline to a remote floating LNG condensing unit, where the gas transferred to the floating LNG condensing unit is expanded to a pressure of 40 to 100 bar abs, and then fed into an LNG heat exchanger and cooled against a refrigerant to produce liquefied natural gas (LNG), characterized in that the gas stream, after arriving on board the liquid LNG condensing unit, after being expanded and before being introduced into the LNG heat exchanger, is split into two gas streams to provide a first split gas stream which is fed into the LNG heat exchanger, and a second split gas stream which is heated by heat exchange against the incoming pressurized gas for cooling it, where the heated second gas stream is transferred to the pretreatment unit. 2. Method according to claim 1, characterized in that the expansion of the gas after arrival on board the floating LNH liquefaction unit and before introduction of the gas into the LNG heat exchanger comprises an isenthalpic expansion. 3. Method according to claim 1 or 2, characterized in that the heated second gas, after being transferred to the pretreatment unit, is mixed with the pretreated gas stream, compressed together with the pretreated gas stream and transferred to the liquid LNG liquefaction unit. 4. Method according to any one of the preceding claims, characterized in that the pre-treated gas is compressed at a pressure ratio of at least 1.5, preferably at least 2.0 or at least 3.0, before it is transferred to the liquid LNG condensation unit, and that gas after arrival at the liquid LNG unit is expanded isenthalpically at essentially the same ratio as compression. 5. Method according to any one of the preceding claims, characterized in that the first split gas flow constitutes 30 to 70% of the expanded gas flow. 6. Method according to claim 2, characterized in that the first split gas flow constitutes 40 - 60% of the expanded gas flow, such that approx. 50%. 7. Method according to any one of the preceding claims, characterized in that the pre-treated and compressed gas stream is cooled to a temperature of -10 to 60 °C before being transferred in the submarine pipeline. 8. Method according to any one of the preceding claims, characterized in that the coolant in the LNG heat exchanger is nitrogen. 9. Method according to any one of the preceding claims, characterized in that the coolant heated by liquefaction of LNG is withdrawn from the LNG heat exchanger and compressed in compression stages, where the coolant is cooled in a cooling cycle by means of air coolers between the coolant compression stages. 10. A system for liquefaction of natural gas to produce LNG, where the system comprises a pretreatment unit (1) to remove or reduce the concentration of compounds that can form solids in the liquefaction process to below 50 ppm and a gas compressor unit (5) to compress the pretreated natural gas, a gas transfer unit (2) comprising a gas transfer pipeline (7) for transferring the pre-treated gas to an external liquefied LNG condensing unit (3), wherein the liquefied LNG condensing unit comprises one or more expansion unit(s) (12) for expansion of the gas, an LNG heat exchanger (14) for cooling and thereby condensing the gas to produce LNG, an LNG export line (15') for extracting the produced LNG from the LNG heat exchanger (14), and an LNG cooler cooling system (18, 19) for cooling heated coolant, and recycling the cooled cooling water to the LNG heat exchanger, characterized in that the system also includes a gas recirculation eration pipeline (10) for withdrawing part of the gas after being expanded and before it is introduced into the LNG heat exchanger (14), the recycling pipeline (10) being arranged to introduce the extracted gas into a heat exchanger (11) for cooling of 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 (11) and back to the pretreatment unit (1). 11. System according to claim 10, characterized in that one or more expansion units (e) (12) comprise one or more valves for isenthalpic expansion of the gas. 12. System according to claim 10 or 11, characterized in that the gas return pipeline (9) is connected to the compressor unit (5) for re-compression and recycling of the gas to the liquid LNG condensation unit (3). 13. The system according to any one of claims 10 to 12, characterized in that a cooler (6) is arranged after the compression unit (5) to cool the gas before it is introduced into the gas transfer pipe (7). 14. The system according to any one of claims 10 to 13, characterized in that one or more serially connected compression units (18, 18', 18") for compressing refrigerant and air coolers (19, 19', 19") for cooling the refrigerant are arranged according to the compression stages.