Process for natural gas liquefaction

Abstract

A natural gas liquefaction process suited for offshore liquefaction of natural gas produced in association with oil production is described.

Claims

1. A process for the offshore liquefaction of a natural gas feed produced in association with offshore crude oil production, the process-comprising: (a) contacting the natural gas feed with a biphasic non-flammable refrigerant at a temperature T1, wherein the biphasic non-flammable refrigerant operating in a closed loop vapor compression cycle accounts for a first portion of a total electrical load; (b) contacting the natural gas feed with a first gaseous refrigerant operating in a closed loop compressor loaded single expander cycle at a temperature T2; (c) expanding the refrigerated natural gas feed using an expansion device to form a flash gas stream and a liquefied natural gas stream; wherein T1 and T2 satisfy the inequality T1T2, wherein at least a portion of the first gaseous refrigerant following contact with the natural gas feed is expanded in a isentropic process and used to further cool the natural gas feed; and wherein the first gaseous refrigerant operating in a closed loop compressor loaded expander cycle accounts for a second portion of the total electrical load, wherein the second portion of the total electrical load is at least 65% of the total electrical load; wherein the liquefaction takes place in one cryogenic heat exchanger; and wherein at least a portion of the biphasic refrigerant contacts the natural gas feed upstream of the cryogenic heat exchanger.

2. The process of claim 1, wherein the biphasic non-flammable refrigerant is a liquid-gaseous refrigerant.

3. The process of claim 1, wherein the biphasic non-flammable refrigerant operates in the closed loop vapor compression cycle in a low pressure level kettle.

4. The process of claim 3, wherein the vapor compression cycle is electric motor driven.

5. The process of claim 1, wherein the first gaseous refrigerant comprises substantially nitrogen.

6. The process of claim 1, wherein the closed loop compressor loaded single expander cycle is gas turbine driven.

7. The process of claim 1, wherein the natural gas feed is pre-treated to recover any less volatile hydrocarbons that is present in the natural gas feed prior to the liquefaction process.

8. The process of claim 7, wherein the less volatile hydrocarbons are returned to a crude production facility for management.

9. The process of claim 1, wherein a separate LPG stream is recovered in addition to the liquefied natural gas stream.

10. The process of claim 1, wherein ethane, propane and butane are retained in the liquefied natural gas stream.

11. The process of claim 1, wherein the expansion device is selected from the group consisting of: an expansion valve, a liquid turbine with a liquid outlet followed by an expansion valve, a flashing expander, and a turboexpander.

12. The process of claim 1, wherein more than one pressure of the flash gas stream is: (1) returned to the cryogenic heat exchanger, (2) warmed, and (3) fed to a flash gas compressor.

13. The process of claim 1, wherein the natural gas feed undergoes dehydration and mercury removal prior to liquefaction.

14. The process of claim 13 further comprising: compressing the flash gas stream to at least the pressure of the natural gas feed after dehydration and mercury removal; and mixing the flash gas stream with the natural gas feed.

15. The process of claim 14, wherein the step of mixing the flash gas stream with the natural gas feed further includes: compressing mixed flash gas stream and natural gas feed in at least one stage of compression prior to forming a liquefied natural gas stream.

16. The process of claim 1, wherein the flash gas stream is recycled for use as a second gaseous refrigerant in the liquefaction process, contacting the natural gas feed at a temperature T3, wherein T2 and T3 satisfy the inequality T2T3.

17. The process of claim 1, wherein at least a portion of the biphasic refrigerant contacts the natural gas feed upstream of, and only upstream of, the cryogenic heat exchanger.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) Embodiments of the invention will now be described, by way of example only and without limitation, with reference to the accompanying drawings and examples, in which:

(2) FIG. 1 is a process schematic of a liquefaction process according to the present invention;

(3) FIG. 2 shows typical cooling curves for the process of the present invention indicating the efficient thermodynamic performance;

(4) FIG. 3 shows another embodiment of the process suitable for LPG recovery; and

(5) FIG. 4 shows examples of expansion device configurations possible for the end-flash.

DETAILED DESCRIPTION OF THE INVENTION

(6) Referring to FIG. 1, natural gas 1 flows into the liquefaction process from the offshore production facility. This natural gas is typically associated gas and has undergone various degrees of treatment. The present description will address the case when the feed gas from a crude stabilization unit is at a pressure in the range of about 20 bar to about 30 bar or has been compressed to a pressure in the range of about 20 bar to about 30 bar in oil production gas compressors but has undergone minimal additional treatment such as hydrocarbon dewpointing, dehydration, and acid gas removal. As those skilled in the art will appreciate, the degree of gas treatment at the offshore production facility is highly variable and typically a function of the minimum treatment required to either export via existing pipeline or re-inject the gas. The feed associated gas normally contains more heavy hydrocarbon components than the non-associated gas/stranded gas, and typically comprises methane in the range of from about 60% to about 80%; about 10% of ethane, and propane in the range of from about 5% to about 10%, in mole fraction.

(7) The feed natural gas is firstly cooled and partially condensed in feed gas chiller 5 to a temperature of approximately 5 C. above the hydrate formation temperature. This temperature may be in the range of from about 15 C. to about 20 C. The cooling media for the chiller may be a non-flammable, non-toxic refrigerant operating in a vapour compression cycle, depicted generally at 90. This may be a commercially available refrigerant with a track record in offshore installations such as R134a. Alternative refrigerants such as R507 may be used if lower temperatures are required.

(8) Following chilling, the partially condensed feed gas enters feed gas separator 6 where liquids and vapour are separated. Not shown in FIG. 1, this separator may be a three phase separator if a liquid water phase is present. The vapour is fed to an intermediate tray in distillation or scrub column 11. The liquid hydrocarbon stream is fed to an intermediate tray lower than the vapour from the feed gas separator. The purpose of the scrub column is to remove any heavy hydrocarbon components that could form waxes or freeze as the natural gas is cooled and condensed in the liquefaction equipment.

(9) The scrub column overhead stream is cooled and partially condensed in a scrub column overhead condenser 13 against another high pressure refrigerant from the closed loop refrigeration system 90. Again, because this stream may be subject to free liquids, the hydrate formation temperature for the stream must be avoided. Operation at a temperature in the range of from about 10 C. to about 20 C. is considered typical for associated gas and allows sufficient recovery of heavy hydrocarbons to avoid deposition in downstream equipment and operating within acceptable margins with regard to hydrate formation. The vapour and liquid phases leaving 13 are separated in a scrub column reflux drum 14.

(10) The vapour phase leaving 14 continues to the gas superheater 20 which is a gas-gas heat exchanger that serves to ensure the feed gas entering the amine contactor 25 is at an appropriate temperature for reasonable amine absorption reactivity and to ensure that no free hydrocarbon liquids can drop out in the contactor leading to amine foaming problems. The liquid phase leaving the reflux drum 14 is pumped through the scrub column reflux pump 15 and returned to the top tray as reflux to the scrub column 11.

(11) A bottoms specification, typically based on vapour pressure of the scrub column, is maintained using a scrub column reboiler 12 against a warm heating media stream. The heating media is typically either hot water, steam, or hot oil with a general preference towards hot water systems in the offshore environment. In one preferred embodiment, the stabilised condensate bottom product 81 is returned to the oil production facility to be blended with the crude product via condensate export pump(s) 80. Naturally, this does not preclude alternative arrangements such as on-board storage that may be assessed on a project-by-project basis as needed. The general preference to return condensate to the crude production facility is reflective of the objective to minimise hydrocarbon inventory, operation, and exportation complexity associated with storage and export of an additional product.

(12) The scrub column 11 operates at or near the feed pressure to the plant and several factors must be considered. Firstly, if the feed gas has not been dehydrated in the oil production facilities, free liquids will form in both chillers 5 and 13 creating the hydrate formation risk that has already been identified as well as the potential to flood the trays of the scrub column with free water. Water entering the column will be vaporised near the bottom but largely condensed in the much cooler top of the column, meaning that water will build up in the column unless the design accommodates this feature when required. In these cases the design should include some provision for water management with the scrub column likely including either a boot to allow water draw off from the reflux drum 14 or a water draw off tray(s) in the upper section of scrub column 11 that will allow a condensed water product to be drawn off the trays to avoid water recycle and flooding.

(13) The warmed, superheated gas leaving the gas superheater 20 enters the Acid Gas Removal Unit (AGRU) block 25. The AGRU is typically an amine package that removes CO.sub.2 and sulphur species to levels acceptable in the liquefaction process. The lower of two requirements will determine the specification of the amine unit: 1) the level at which acid gas components are soluble in the LNG and 2) the receiving terminal gas send-out specification. Generally, the LNG specification will be the more arduous of the specifications. A typical specification could be higher than the 50-200 ppm(v) CO.sub.2 acceptable in most onshore liquefaction terminals depending on both the LNG production pressure (that may be higher than near-atmospheric pressure and the C2-C4 concentration that tends to increase CO.sub.2 solubility in liquefied natural gas.

(14) The gas leaving the amine block is water saturated and effectively acid gas component free. It flows through the gas superheater 20 where it is cooled against the gas stream flowing to the AGRU. This reduces the temperature and some water condenses in preparation to the dehydration and mercury removal block 26. Lower temperature feed gas and lower water content both improve the performance of the dehydration system. The feed gas is typically dehydrated to a concentration of less than 1 ppm(v) of water to ensure that water is not deposited as solids in the downstream cold process equipment. The dehydration block typically uses a molecular sieve zeolite to dry the feed gas in a temperature swing adsorption cyclical process. The regeneration gas for the process is taken from the fuel gas stream 30 because this is a bone dry and relatively lean stream.

(15) For simplicity, the mercury removal step has been shown as included in the dehydration block. Mercury removal is required to avoid the potential of mercury attack on aluminium plate fin heat exchangers and is typically removed in a fixed absorbent bed containing either sulphur impregnated carbon or increasingly a Zn/Cu sulphide. This base case does not preclude regenerative mercury removal systems that can be combined with the dehydration beds and regenerated at elevated temperature thus decreasing equipment count and required space on the topsides.

(16) The gas leaving the dehydration and mercury removal block 26 is mixed with a partially compressed flash gas from the liquefaction process and compressed in feed gas compressor 27 to a pressure of at least about three bar greater than the fuel gas delivery pressure. A slip stream that is less than the fuel gas demand and typically less than 10% of the feed gas is used as a regeneration case for the molecular sieve dehydration unit. This gas is heated, regenerates the dehydration bed and is then cooled down and free water is removed. This discharge pressure of feed gas compressor 27 is such that the slip stream can regenerate the dehydration bed and then be sent to the gas turbines without further compression. This avoids the need for a dedicated fuel gas or regeneration gas compressor.

(17) The gas leaving compressor 27 is cooled in feed gas compressor aftercooler 28 and then chilled against closed loop vapour compression refrigeration system 90 in a low pressure level kettle (LP Kettle) 29. This kettle cools and may partially condense the feed gas to enhance the thermodynamic efficiency of the process. The optimum temperature is a balance between efficiency and the size of the refrigeration system.

(18) After leaving the LP Kettle 29, the feed gas is cooled and condensed in the main cryogenic heat exchanger (MCHE) 40 against reduced pressure N.sub.2 refrigerant operating in the compressor loaded expander cycle and against flash gas streams, prior to flashing across expansion device 50 into the LNG flash drum 51. In one embodiment the expansion device will be a cage guided isenthalpic expansion valve that is proven in this service but thermodynamically inefficient. Alternatives for this expansion device envisaged for the present invention include, but are not limited to, a liquid turbine followed by an expansion valve, a dense phase turboexpander, and a flashing expander as will be understood by those skilled in the art. These alternatives will be described in more detail below.

(19) The fluid leaving expansion device 50 will be reduced in temperature and become biphasic, comprising a vapour portion, referred to as flash gas, which is preferentially enriched in more volatile components such as methane and nitrogen, and a liquid stream referred to as LNG. The vapour molar fraction will typically be at least sufficient to meet the fuel gas demands of the system but not more than about 25% on a molar basis with the optimal value being determined on a project specific basis. The vapour fraction is typically at a temperature in the range of from about 163 C. to about 140 C. and is returned as a cold stream to the MCHE 40 where it cools and condenses the incoming feed gas and is particularly important to provide cooling at the lowest temperatures in the liquefaction system. In some cases, it may be advantageous to mix the vapour fraction from the LNG flash drum with a cold vapour stream (boil off gas or BOG) from LNG storage to recover the cold from this stream and improve the efficiency of the process.

(20) The low pressure, warmed flash gas is recompressed in flash gas compressor 60 and then cooled in flash gas compressor aftercooler 61. This compression will occur in a number of stages depending on the LNG production pressure, feed gas pressure, and other factors. This compressed flash gas is combined with the treated feed gas to complete a cycle prior to compression in feed gas compressor 27.

(21) The majority of the refrigeration required by the process is generated by the closed loop compressor loaded expander cycle, a closed loop, wholly or primarily gaseous turboexpanded-based system. This cycle will be described starting with the warm, lower pressure stream R which is referred to as the LPN Refrigerant (Low Pressure Nitrogen Refrigerant). This stream consists primarily of a N.sub.2 refrigerant at a pressure in the range of from about 8 bar to about 15 bar. It should be noted that in some cases the refrigerant may include some natural gas to enhance the performance of the process or may include some other components that typically make-up air.

(22) The LPN refrigerant is compressed in the Nitrogen refrigerant compressor 41 to a pressure in the range of from about 50 bar to about 90 bar in at least one stage of compression. Additional compressor stages may be required. The high pressure N.sub.2 refrigerant (HPN refrigerant) is cooled in HPN aftercooler 42 prior to further compression in the expander-compressor 43 that has a typical pressure ratio of 1.5 generating the highest pressure in the closed loop at the outlet of the compressor.

(23) Aftercooler 45 cools the HPN refrigerant to a temperature in the range of from about 3 C. to about 10 C. above the cooling media that is typically either seawater or air. From a thermodynamic perspective, a lower aftercooled discharge temperature results in an increased LNG production for the same refrigeration compressor power.

(24) The HPN refrigerant enters the MCHE and is cooled against the cold LPN refrigerant and flash gas streams to an intermediate temperature. At least a portion of the cooled HPN refrigerant leaves the MCHE and is expanded in the turboexpander 44 that expands the HPN to produce the cold LPN refrigerant. This expansion is completed in a turboexpander to effect a primarily isentropic expansion and a resultant large decrease in temperature. As those skilled in the art will appreciate, an efficient expansion process greatly enhances the efficiency of the process.

(25) Whilst in the illustrated embodiment the turboexpander 44 is loaded with compressor 43 boosting the pressure of the HPN refrigerant, many other embodiments are possible. For instance, the turboexpander shaft power could be converted to electrical power in a generator loaded turboexpander. Alternatively, a compressor loading the expander could recompress the LPN refrigerant prior to compression in the N.sub.2 refrigerant compressor. In the case where multiple expanders used for small-scale liquefaction are required, the turboexpander could even rely on an oil brake for loading in a less efficient but simple configuration. It should also be noted that there is a general preference for oil free magnetic bearing machines for this application because they take up less space offshore and eliminate the possibility of oil contamination of cryogenic equipment from the expander system.

(26) The LPN refrigerant at the outlet of the turboexpander 44 is returned as a cold stream to the MCHE 40 and used to provide further cooling. This gas is at a temperature considerably colder that the cooled HPN refrigerant but warmer than the flash gas coming from the LNG flash drum 51 such that it opens the cooling curves in the MCHE at warmer and intermediate temperatures. Typically, the LPN refrigerant is at a temperature in the range of from about 150 C. to about 120 C. This gas is warmed against the warm feed gas and HPN refrigerant streams prior to recompression in the N.sub.2 refrigerant compressor 41 to complete the cycle.

(27) The process conditions that optimise performance and equipment sizing for the N.sub.2 refrigeration system are a function of project specific variables. What is important is that the closed loop N.sub.2 refrigerant system operates at conditions that are within the equipment supplier limits whilst at high enough pressures to avoid excessively large equipment. It is also important that the N.sub.2 refrigeration system provides cooling between the flash gas and the feed gas cooling temperature range.

(28) FIG. 2 shows the cooling curve of the process described above. The upper line represents the cooling of the natural gas stream. The lower line represents the consolidated heating curve for the refrigerant streams of the present invention. The close fit of the warm stream and cold stream indicates the high liquefaction efficiency of this associated gas liquefaction process.

(29) FIG. 3 shows an alternative embodiment of the process that has been modified to recover sufficient LPGs to market to existing LNG receiving terminals.

(30) Referring to FIG. 3, the feed gas 1, which is typically associated gas, flows into the liquefaction process from the offshore production facility by first of all passing a metering device 2. The feed gas passes a suction scrub 3 before being fed to the feed gas compressor 4 which compresses it to about 45 bar, and is subsequently cooled down using air cooler 31 or a seawater cooler. The cooled natural gas is further cooled in a chiller and partially condensed in condenser 7 using a high pressure non-flammable refrigerant operating in the closed loop vapour compression cycle of refrigeration system 90.

(31) Following chilling, the partially condensed feed gas enters three-phase feed gas separator 8 where water, liquids and vapour are separated. The vapour passes through a gas sweetening plant (e.g. amine contactor), dehydration bed and mercury removal bed, and then is fed to an intermediate tray in scrub column 11. The purpose of the scrub column is to control the overhead vapour quality that is directly related to the final LNG's higher heating value (HHV) which is typically around 1100 MMBtu/scf, and also remove the heavy hydrocarbon components that could form waxes or freeze when the natural gas is cooled and condensed in the cryogenic liquefaction equipment. The scrub column overhead stream is cooled and partially condensed in a scrub column overhead condenser 13 against a low pressure refrigerant stream from the closed loop refrigeration system 90. Again, to obtain a lean overhead vapour stream that satisfies the LNG specification, operation at a temperature in the range of from about 50 C. to about 40 C. for the scrub overhead condenser 13 is considered typical for associated gas. The fluid with vapour and liquid phases leaving the condenser 13 is separated in a scrub column reflux drum 14.

(32) The liquid phase leaving the reflux drum 14 is pumped by a scrub column reflux pump 15 and returned to the top tray as reflux to the scrub column 11. A reboiler operating at about 120 C. using hot media is used in order to get a better separation of the scrub column. The bottom stream from scrub column 11 is decompressed to a pressure of around 25 bar by decompressor 32 before being further fed to deethanizer column 17. Another liquid hydrocarbon stream from the three phase separator 8 is dehydrated and fed to an intermediate tray of the deethanizer column 17. The purpose of the deethanizer column is to remove the redundant ethane in the feed stream, so that the bottom stream which is fed into the 3rd column can satisfy the LPG and condensate true vapour pressure (TVP) requirement.

(33) A low pressure refrigerant evaporator 18 at typically 22 C. is used to partially condense the deethanizer overhead stream against refrigerant from refrigerant system 90. The liquid is separated in the drum 19 and pumped back to the deethanizer column 17 as a reflux stream by pump 33. The vapour from the drum is sent to the fuel gas system which is used to drive the gas turbines.

(34) The pressure of the deethanizer bottom liquid is further reduced to about 10 bar in pressure reducer 21 and is fed to the 3.sup.rd column, i.e. debutanizer 23. The debutanizer column is used to separate the LPG at the overhead and the condensate at the bottom. The condensate has the true vapour pressure of 1 bar at 37 C., and is cooled down in chiller 37 and spiked to the crude storage tank on an oil FPSO using a pump 38. The operating temperature range of debutanizer column 23 is 55 C. (overhead) to 135 C. (bottom). The overhead vapour is fully condensed using air cooler 24 or a water cooler and supplied to a receiver 34.

(35) Part of the liquid collected from the receiver 34 is recycled back to debutanizer column 23 as a reflux stream via pump 35, whilst the rest is exported as a final LPG product 27 and stored either in a pressure vessel at room temperature or in a low temperature vessel at ambient pressure, with the latter needing a chiller using LP refrigerant to cool down to 33 C. and reduce pressure using a JT valve to achieve ambient pressure.

(36) The overhead vapour stream of the scrub column reflux drum 14 is fed into the main cryogenic heat exchanger (MCHE) 40 against cryogenic N.sub.2 as refrigerant to supply the main cold energy. The main cryogenic heat exchanger may comprise aluminium brazed plate fins. The inlet natural gas is fully condensed in the MCHE to 145 C. and isenthalpically expanded to around 1-3 bar by passing either a JT valve 50, liquid turbine, dense phase turboexpander, or flashing expander, as described above. The fluid leaving expansion device 50 will be reduced in temperature and become a two-phase stream which is collected in the LNG receiver 51.

(37) The liquid separated from the LNG receiver is stored in LNG tank and exported as LNG product, while the flash gas which mainly contains methane and nitrogen is returned as a side cold stream to the MCHE 40 where it cools and condenses the incoming feed gas and is particularly important to providing cooling at the lowest temperatures in the liquefaction system. The recovery of cold in the flash gas improves the overall process efficiency.

(38) The low pressure, warmed flash gas is recompressed in flash gas compressor 60 and then cooled in a flash gas compression aftercooler 61. This flash gas compression may occur in a number of stages depending on the LNG production pressure, feed gas pressure, and other factors. This compressed flash gas can be served as the molecular sieve regeneration gas, and combined with the deethanizer 17 overhead gas, and the balance untreated feed gas to serve as the fuel gas for the gas turbines.

(39) The nitrogen refrigeration system to provide the main cold for MCHE is as described for the compressor loaded expander cycle in FIG. 1. The process conditions that optimise performance and equipment sizing for the N.sub.2 refrigeration system are a function of project specific variables to operate the nitrogen system at conditions that are within the equipment supplier limits (e.g. the limit of design temperature and pressure of the MCHE, the export power limit of turboexpander) whilst at high enough pressures to avoid excessively large equipment. It is also important that the N.sub.2 refrigeration system provides the cooling between the cryogenic flash gas and the warm feed gas cooling temperature range.

(40) FIG. 4 shows a number of expansion device configurations that could be used in the low temperature open cycle end flash in the process. The first sketch shows the simplest embodiment of the process. As previously described, the cooled and condensed natural gas leaving the MCHE 40 is flashed across expansion device 50 into the LNG flash drum 51. As shown in this sketch, an isenthalpic expansion occurs across an expansion valve designed for the severe cryogenic flashing service. In one embodiment the expansion device will be a cage guided isenthalpic expansion valve that is proven in this service but thermodynamically inefficient. The limited efficiency of this isenthalpic expansion manifests itself in a lower liquid fraction at the outlet of the valve and ultimately decreased overall thermodynamic efficiency of the liquefaction process. Alternative arrangements are included within the scope of the present invention and described below.

(41) The second sketch shows a configuration that is commonly used in large-scale LNG installations to improve thermodynamic cycle performance. The cold high pressure fluid from MCHE 40 is reduced in pressure to slightly above the bubble point to ensure a liquid outlet in a liquid turbine 54 in an approximately isentropic expansion. The liquid is then further expanded in isenthalpic expansion valve 55 and flashed into the vapour dome to form the two-phase mixture of flash gas and LNG. Back-up expansion valve 53 is installed in parallel for use during transient operation such as start-up and to allow continued operation when the liquid turbine is down for maintenance.

(42) Note that in this scheme liquid turbine 54 has a liquid or dense liquid-like phase inlet and a liquid outlet. Liquid turbine 54 is loaded by a generator 57 that produces a relatively small amount of power. The value of this generator is that the work extracted from the stream in expansion results in an increased liquid yield and whilst the electrical power could be synchronised with the main electrical power system and be used, it will typically be destroyed in a load cell.

(43) A second alternative to an expansion valve that further enhances the efficiency of the liquefaction process is seen in the third sketch of FIG. 4. In this embodiment, the cold high pressure fluid from MCHE 40 is expanded directly into the vapour dome using a flashing turbine expander 58 in an approximately isentropic expansion. A back-up expansion valve 53 is installed in parallel for use during transient operation such as start-up and to allow continued operation when the liquid turbine is down for maintenance.

(44) Note that in this scheme the flashing expander 58 has a liquid or dense liquid-like phase inlet and a two-phase outlet. The liquid turbine is loaded by a generator 59 that produces more power than generator 57 from the previously described scheme but again, the principal benefit of the isentropic expansion is the resultant increased liquid yield and process efficiency.

(45) The main advantage of the plant as discussed with reference to FIG. 1 and FIG. 3 is the heat integration of LPG production and natural gas liquefaction. By using the closed loop vapour compression cycle refrigeration system 90 to cool the natural gas feed, the overall efficiency of the liquefaction process is improved. Moreover, the improvement of the process efficiency does not compensate on the process safety due to the use of non-flammable, non-toxic refrigerants such as R134A, R507.

EXAMPLES

(46) The present invention has been compared with some other liquefaction cycles. The following examples are given in terms of compressor duty for 80 mmscfd (millions of standard cubic feet per day) of associated gas feed. For all examples, the liquefied natural gas is passed through an expansion device and the resulting flash gas is recycled to provide cooling at the lowest temperatures of the liquefaction process. Table 1 summarises the findings discussed below.

Comparative Example 1

(47) The duty for a single N.sub.2 expander cycle driven by gas turbine is 37 MW. This is because when rich gas is served as feed gas, the huge requirement for initial, upper temperature cooling makes the nitrogen refrigerant cycle highly inefficient.

Comparative Example 2

(48) Use of the dual N.sub.2 expander cycle reduced the total nitrogen compression duty to 27 MW, which indicates that a smaller gas turbine could be used to drive the nitrogen compressors.

Example 1

(49) In accordance with the present invention, use of the vapour compression cycle refrigerant, in conjunction with a single N.sub.2 expander cycle greatly reduces the total duty by more than 13 MW. Furthermore the compressor duty for the nitrogen compressors of this Example is actually smaller than the dual N.sub.2 expander cycle of Comparative Example 2. This indicates the small CAPEX need for the plant as the gas turbine is a big cost in the total CAPEX.

Example 2

(50) Use of the vapour compression cycle refrigerant in conjunction with a dual N.sub.2 expander cycle results in an even greater reduction in compressor duty. Although the duty is 2 MW less than for Example 1, the same model of gas turbine is still needed, which indicates no cost saving on the gas turbine but greater CAPEX on the second turboexpander.

(51) It is obvious that the present invention is advantageous in terms of the overall process efficiency (with an overall thermal efficiency of 91.13%) and CAPEX.

(52) TABLE-US-00001 TABLE 1 Performance comparison of different natural gas liquefaction cycles Vapour compression cycle compressor N.sub.2 For 80 duty compressor mmscfd driven by duty driven N.sub.2 of feed Total electrical by gas compressor associated Compressor motor turbine gas turbine gas duty (MW) (MW) (MW) selection Comparative 37 0 37 LM6000, Example 1 Comparative 27 0 27 PGT25+, Example 2 RB211-6762 Example 1 23.7 4.6 19.1 PGT25, RB211-6556, Titan 250 Example 2 21.7 4.6 17.1 PGT25, RB211-6556, Titan 250