EP1352203A1

EP1352203A1 - Method for refrigerating liquefied gas and installation therefor

Info

Publication number: EP1352203A1
Application number: EP01271522A
Authority: EP
Inventors: Henri Paradowski
Original assignee: Technip France SAS
Current assignee: Technip Energies France SAS
Priority date: 2000-12-18
Filing date: 2001-12-13
Publication date: 2003-10-15
Anticipated expiration: 2021-12-13
Also published as: PT1352203E; AU1930102A; AU2002219301B2; JP2004527716A; GC0000378A; FR2818365B1; RU2003122063A; BR0116288B1; EP1352203B1; CN1266445C; WO2002050483A1; US20040065113A1; FR2818365A1; NO20032543L; ES2373218T3; NO20032543D0; RU2270408C2; CY1112363T1; DZ3483A1; KR20030081349A

Abstract

The invention concerns a method for refrigerating liquefied natural gas under pressure ( 1 ), comprising a first step wherein the LNG ( 1 ) is cooled, expanded and separated (a) in a first base fraction ( 4 ) which is collected, and (b) a first top fraction ( 3 ) which is heated, compressed in a compressor (K 1 ) and cooled into a first compressed fraction ( 5 ) which is collected; a second compressed fraction ( 6 ) is drawn from the fuel gas ( 5 ), cooled then mixed with the cooled and expanded LNG ( 1 ). The invention is characterised in that it comprises a second step wherein the second compressed fraction ( 6 ) is compressed and cooled, and a flux is ( 8 ) drawn and cooled, expanded and introduced in the compressor (K 1 ). The invention also describes other embodiments.

Description

LIQUEFIED GAS REFRIGERATION PROCESS AND INSTALLATION USING THE SAME

The present invention relates, in general and according to a first of its aspects, the gas industry, and in particular a process for refrigeration of pressurized gases containing methane and C2 hydrocarbons

10 and above, with a view to their separation.

More specifically, the invention relates, according to its first aspect, to a method of refrigerating a liquefied natural gas under pressure containing methane and C2 and higher hydrocarbons, comprising a

First step (I) in which (la) the said liquefied natural gas is expanded under pressure to provide a flow of expanded liquefied natural gas, in which (Ib) said expanded liquefied natural gas is separated into a first relatively more volatile overhead fraction , and an

20 • relatively less volatile first fraction of the bottom, in which (the) the first fraction of the bottom consisting of refrigerated liquefied natural gas is collected, in which (Id) is heated, compressed in a first compressor and the first fraction is cooled overhead to provide a first compressed fraction of combustible gas which is collected, in which (the) a second compressed fraction is taken from the first compressed fraction which is then cooled and then mixed with the flow of liquefied natural gas

30 relaxed.

Refrigeration methods of this type are well known to those skilled in the art and have been used for many years.

The refrigeration process for liquefied natural gas

35 (LNG) in accordance with the preamble above is used in a known manner with the aim of eliminating the nitrogen sometimes present in large quantities in natural gas. In this In this case, the combustible gas obtained by this process is enriched in nitrogen, while the refrigerated liquefied natural gas is depleted in nitrogen.

Natural gas liquefaction plants have well-defined technical characteristics and limitations imposed by the capacity of the production elements constituting them. Consequently, a liquefied natural gas production installation is limited by its maximum production capacity, under the usual operating conditions. The only solution to increase production is to build a new production unit.

Given the costs of such an investment, it is necessary to ensure that the desired increase in production will be sustainable, in order to facilitate the amortization.

Currently, there is no solution to increase, even temporarily, the production of a liquefied natural gas production unit, when it is operating at its maximum capacity, without resorting to a heavy and costly investment consisting of construction of another production unit.

The production capacity of liquefied natural gas (LNG) depends essentially on the power of the compressors used to allow the refrigeration and liquefaction of natural gas.

In this context, a first object of the invention is to propose a process, moreover in accordance with the generic definition given by the preamble above, which allows the increase of the capacity of an LNG production unit. , without resorting to the construction of another LNG production unit, which is essentially characterized in that it comprises a second stage (II) in which (Ha) the second compressed fraction is compressed in a second compressor coupled to an expansion turbine to provide a third compressed fraction, in which (Ilb) the third compressed fraction is cooled and then separated into a fourth compressed fraction and a fifth compressed fraction, in which (Ile) the fourth compressed fraction is cooled and expanded in the expansion turbine coupled to the second compressor to provide a relaxed fraction which is then reheated then introduced to a first stage at medium pressure of the compressor (Kl), and in which (Ild) the fifth compressed fraction is cooled and then mixed with the flow of expanded liquefied natural gas.

A first merit of the invention is to have found that a production unit operating at 100% of its capacities, producing a certain flow rate of liquefied natural gas at a temperature of -160 ° C. and at a pressure close to 50 bar. all other operating parameters constant, can increase its throughput, and hence its production, ^'by a temperature increase production of liquefied natural gas.

However, LNG is stored at around -160 ° C at low pressure (less than 1.1 bar absolute), and an increase in its storage temperature would increase its storage pressure, which represents prohibitive costs, but especially transport difficulties, due to the very large quantities of LNG produced.

Consequently, it is usual for LNG to be prepared at a temperature in the region of -160 ° C before its storage.

A second merit of the invention is to present an elegant solution to these production limitations by the use of an LNG refrigeration process capable of adapting to a preexisting LNG production process, not requiring the use of significant material and financial resources for the implementation of this process. This solution includes the production, by a pre-existing LNG production unit, of LNG at a temperature above about -160 ° C, then its refrigeration at approximately -160 ° C by the process according to the invention.

A third merit of the invention is to have modified one. refrigeration process for liquefied natural gas rich in known nitrogen and in accordance with the preamble above, and to have allowed its use both with LNG rich in nitrogen as with LNG poor in nitrogen. In the latter case, the combustible gas obtained by this process contains very little nitrogen, and therefore has a composition close to that of liquefied natural gas poor in nitrogen.

According to a first aspect of the method of the invention, the flow of expanded liquefied natural gas can be separated before step (Ib) into a second fraction of the top and in a second fraction of the bottom, the second fraction of the top can be reheated then introduced into the first compressor at a second stage at medium pressure intermediate between the first stage at medium pressure and a stage at low pressure, and the second fraction of foot can be separated into the first fraction of head and the first fraction of foot .

According to the first aspect of the method of the invention, each compression step can be followed by a cooling step.

According to a second of its aspects, the invention relates to a refrigerated liquefied natural gas and a combustible gas obtained by any of the previously defined methods.

According to a third of its aspects, the invention relates to an installation for refrigerating a pressurized liquefied natural gas containing methane and C2 and higher hydrocarbons, comprising means for carrying out a first step (I) in which (la) said liquefied natural gas is expanded under pressure to provide a flow of expanded liquefied natural gas, in which (Ib) said expanded liquefied natural gas is separated into a first fraction which is relatively more volatile, and a first fraction of relatively less volatile base, in which (the) the first base fraction consisting of refrigerated liquefied natural gas is collected, in which (Id) is heated, it is compressed in a first compressor and the first head fraction is cooled to provide a first compressed fraction of combustible gas which is collected, in which (the) a second compressed fraction is withdrawn from the first compressed fraction which is then cooled and then mixed with the flow of expanded liquefied natural gas, characterized in that it comprises means for effecting a second step

(II) in which (Ha) the second compressed fraction is compressed in ^" a second compressor coupled to an expansion turbine to provide a third compressed fraction, in which (Ilb) the third compressed fraction is cooled and then separated into a fourth compressed fraction and eri a fifth compressed fraction, in which (Ile) the fourth compressed fraction is cooled and expanded in the expansion turbine coupled to the second compressor to provide a relaxed fraction which is then heated and then introduced to a first stage at medium pressure of the compressor, and in which (Ild) the fifth compressed fraction is cooled and then mixed with the expanded liquefied natural gas stream.

According to a first variant in accordance with its third aspect, the invention relates to an installation comprising means for separating the flow of liquefied natural gas expanded before step (Ib) into a second fraction of head and into a second fraction of foot, in that it includes means for heating and then introducing the second overhead fraction into the first compressor at a second stage at medium pressure intermediate between the first stage at medium pressure and a stage at low pressure, and in that it comprises means for separating the second foot fraction into the first head fraction and the first foot fraction. According to a first embodiment in accordance with its third aspect, the invention relates to an installation in which the first head fraction and the first foot fraction are separated in a first separator tank.

According to a second embodiment in accordance with its third aspect, the invention relates to an installation in which the first head fraction and the first foot fraction are separated in a distillation column.

According to an embodiment in accordance with the first variant of its third aspect, the invention relates to an installation in which the flow of expanded liquefied natural gas can be separated into the second head fraction and the second foot fraction in a second balloon separator.

According to its second ^mode of embodiment according to its third aspect, the invention concerns an installation wherein the distillation column comprises at least one side reboiler and / or the column bottom, in that the liquid withdrawn from a tray of the distillation column circulating in said reboiler is heated in a second heat exchanger then is reintroduced into the distillation column on a stage lower than said tray, and in that the flow of expanded liquefied natural gas is cooled in said second heat exchanger.

According to a third embodiment in accordance with its third aspect, the invention relates to an installation in which the cooling of the first overhead fraction and of the expanded fraction, and the heating of the fourth compressed fraction and of the fifth compressed fraction, s 'performs in a single first heat exchanger. According to the first variant in accordance with its third aspect, the invention relates to an installation in which the second overhead fraction is heated in the first heat exchanger.

The invention will be better understood and other aims, characteristics, details and advantages thereof will appear more clearly during the description which follows, with reference to the appended schematic drawings, given solely by way of non-limiting example and wherein:

FIG. 1 represents a functional block diagram of a natural gas liquefaction installation in accordance with an embodiment of the prior art;

Figure ^~ 2 shows a functional block diagram of a liquefied natural gas denitrogenation installation according to a first embodiment of the prior art;

FIG. 3 represents a functional block diagram of a liquefied natural gas denitrogenation installation in accordance with a second embodiment of the prior art;

- Figures 4, 5, 6 and 7 show functional block diagrams of installations possibly denitrogenation of liquefied natural gas according to preferred embodiments of the invention. On these seven figures, one can read in particular the symbols “FC” which means “flow controller”, “GT” which means “gas turbine”, “GE” which means “electric generator”, “LC” which means “controller liquid level "," PC "which means" pressure controller "," SC "which means

"Speed controller" and "TC" which means "temperature controller".

For the sake of clarity and conciseness, the pipes used in the installations of FIGS. 1 to 7 will be indicated by the same reference signs as the gaseous fractions which circulate there. Referring to FIG. 1, the installation shown is intended to treat, in a known manner, a dried, desulphurized and decarbonated natural gas 100, in order to obtain liquefied natural gas 1, generally available at a temperature below minus 120 ° C.

This LNG liquefaction facility has two independent refrigeration circuits. A first refrigerant circuit 101, corresponding to a propane cycle, makes it possible to obtain primary cooling to approximately minus 30 ° C. in an exchanger E3 by expansion and vaporization of liquid propane. the heated and expanded steam propane is then compressed in a second compressor K2, then the compressed gas obtained 102 is then cooled and liquefied in water refrigerants 103, 104 and 105.

A second refrigerant circuit 106, generally corresponding to a cycle using a mixture of nitrogen, methane, ethane and propane, allows significant cooling of the natural gas to be treated to obtain liquefied natural gas 1. The fluid coolant present in the second refrigerant cycle is compressed in a third compressor K3 and cooled in water exchangers 118 and 119, then is cooled in a water refrigerant 114, to obtain a fluid 107. The latter is then cooled and liquefied in the exchanger E3 to provide a cooled and liquefied flow 108. The latter is then separated into a vapor phase 109 and a liquid phase 110 which are both introduced into the lower part of a cryogenic exchanger 111. After cooling , the liquid phase

110 then leaves the exchanger 111 to be expanded in a turbine X2 coupled to an electric generator. The expanded fluid 112 is then introduced into the cryogenic exchanger 111 above its lower part, where it is used to cool the fluids circulating in the lower part of the exchanger, by spraying on pipes carrying fluids. to cool, using spray bars. The vapor phase 109 circulates in the lower part of the cryogenic exchanger 111 to be cooled and liquefied there, then is further cooled by circulation in an upper part of the cryogenic exchanger 111. Finally, this cooled and liquefied fraction 109 is expanded in a valve 115, then is used to cool the fluids circulating in the upper part of the cryogenic exchanger 111, by spraying on pipes carrying fluids to be cooled. The coolants sprayed inside the cryogenic exchanger 111 are then collected at the bottom of the latter to supply the flow 106 which is sent to the compressor K3. The dried, desulfurized and decarbonated natural gas 100 is cooled in a propane heat exchanger 113, then is subjected to a desiccation treatment, which can be, for example, a passage through a molecular sieve, for example in zeolite, and to a demercurization treatment, for example by passing over a silver foam or any other mercury scavenger, in an enclosure 116 to supply a purified natural gas 117. The latter is then cooled and partially liquefied in the heat exchanger E3, circulates in the lower part, then in the upper part of the cryogenic exchanger 111 to supply a liquefied natural gas 1. The latter is usually obtained at a temperature below minus 120 ° C.

Referring now to Figure 2, the installation shown is intended to treat, in known manner, a liquefied natural gas 1 rich in nitrogen, to obtain on the one hand, a cooled liquefied natural gas and poor in nitrogen 4, and on the other hand a first compressed fraction 5 which is a compressed combustible gas rich in nitrogen.

LNG 1 is first expanded and cooled in an expansion turbine X3 which is regulated by a controller LNG flow rate flowing in line 1, then is again expanded and cooled in a valve 18 whose opening depends on the pressure of the LNG leaving. compressor X3, to provide a flow of expanded liquefied natural gas 2. The latter is then separated into a first fraction of head 3 relatively more volatile, and a first fraction of foot 4 relatively less volatile in a balloon VI. The first fraction of a foot 4 consisting of refrigerated liquefied natural gas is collected and pumped in a pump PI, circulates in a valve 19 whose opening is regulated by a liquid level controller in the bottom of the flask VI, then to leave the installation and be stored.

The first overhead fraction 3 is heated in a first heat exchanger El, then is introduced into a low pressure stage 15 of a compressor K1 coupled to a gas turbine GT. This compressor K1 comprises a plurality of compression stages 15, 14, 11 and 30, at progressively high pressures, and a plurality of water coolers 31, 32, 33 and 34. After each compression stage, the compressed gases are cooled by passage through a heat exchanger, preferably with water. The first overhead fraction 3 supplies, at the end of the compression and cooling stages, the compressed nitrogen-rich combustible gas 5. This combustible gas is then collected and leaves the installation.

A small part of the combustible gas 5 which corresponds to a flow 6 is taken. This flow 6 is refrigerated in the exchanger El by yielding its heat to the first overhead fraction 3, to give a cooled flow 22. This cooled flow 22 circulates then in a valve 23 whose opening is controlled by a flow controller at the outlet of the exchanger E2. The stream 22 is finally mixed with the stream of expanded liquefied natural gas 2. Referring now to FIG. 3, the installation shown is intended to treat, in known manner, a liquefied natural gas 1 rich in nitrogen, to obtain on the one hand, a cooled liquefied natural gas poor in nitrogen 4, and on the other hand, a first compressed fraction 5 which is a combustible gas, compressed rich in nitrogen. In this installation, the separation flask VI has been replaced by a distillation column Cl and a heat exchanger E2.

The LNG 1 is first expanded and cooled in an expansion turbine X3, the speed of which is regulated by an LNG flow controller circulating in the pipe 1, then is cooled in the heat exchanger E2., To provide a cooled flow. 20. The latter circulates in a valve 21, the opening of which is controlled by a pressure controller located on the pipe 20, upstream of said valve 21, to supply a flow of expanded liquefied natural gas 2. The flow of natural gas liquefied relaxed 2 is then separated into a first overhead fraction 3 relatively more ^volatile, and a first bottom fraction 4 relatively less volatile in the column Cl. the first bottom fraction 4 consists of refrigerated liquefied natural gas is collected and pumped into a pump PI circulates in a valve 19, the opening of which is regulated by a liquid level controller in the bottom of the tank VI, in order to then leave the installation and be stored. Column Cl includes a reboiler at the bottom of column 16 which uses liquid contained on a tray 17. The flow circulating in reboiler 16 is heated in the heat exchanger E2 to then be introduced into the bottom of column Cl. head fraction 3 follows. same treatment as presented in FIG. 2, for obtaining a first fraction of compressed gas 5, which is a compressed combustible gas rich in nitrogen, and of a second compressed fraction 6 which is a fraction of sampling of combustible gas compressed. Similarly, this last fraction is reheated in the exchanger El to give a cooled stream 22. This stream 22 is also mixed with the expanded liquefied natural gas stream 2.

Referring now to Figure 4, the installation shown is intended to treat, using a device according to the method of the invention, a liquefied natural gas 1 rich in nitrogen, to obtain a on the one hand, a cooled liquefied natural gas poor in nitrogen 4, and on the other hand, a compressed combustible gas rich in nitrogen 5. This installation comprises elements common to FIG. 3, in particular the expansion and the cooling of the LNG 1 to obtain the expanded LNG flow 2. Similarly, the separation ^" into the first head fraction 3 and the first foot fraction 4 is carried out in a similar manner in column Cl. Finally, the flow of combustible gas 5 is obtained, as before, by successive compressions and coolings Unlike the process presented in FIG. 3, a second compressed fraction 6, taken from the first fraction of compressed gas 5 feeds an XKl compressor coupled to a turbine expansion valve XI to obtain a third compressed fraction 7. This is cooled in a water cooler 24, then is separated into a fourth compressed fraction 8 and into a fifth compressed fraction 9.

The fourth compressed fraction 8 is cooled in the heat exchanger El to provide a fraction 25 which is expanded in the turbine XI. The turbine XI provides a relaxed flow 10 which is heated in the exchanger El to give a heated heated flow 26. This heated heated flow 26 is introduced at a medium pressure stage 11 of the compressor K1.

The fifth compressed fraction 9 is cooled in the heat exchanger El to provide a fraction 22 which is expanded in a valve 23 and is then mixed with the expanded LNG fraction 2. The regulator XI comprises an inlet guide valve 27, making it possible, by varying the angle of introduction of the flow 25 onto the blades of the turbine XI, to vary the speed of rotation of the latter, and consequently to vary the power delivered to the compressor XKl.

Referring now to Figure 5, the installation shown is intended to treat, using a device according to the method of the invention, a liquefied natural gas 1 preferably rich in nitrogen, to obtain on the one hand, a cooled liquefied natural gas poor in nitrogen 4, and on the other hand, a "compressed combustible gas 5 rich in nitrogen, in the case where liquefied natural gas 1 contains it.

This installation comprises elements common to FIG. 4, in particular the production, by a distillation column C1, of a first fraction of the head 3, and of a first fraction of the foot 4. Similarly, the first fraction of the head 3 is compressed in a compressor K1 and cooled in refrigerants 31-34 to obtain a first compressed fraction 5. A second sampling fraction 6 is withdrawn from the first compressed fraction 5 to be compressed in an XKl compressor coupled to a expansion turbine XI, which produces a third compressed fraction at the output 7. The latter is separated into a fourth compressed fraction 8 and into a fifth compressed fraction 9.

The fourth compressed fraction 8 is cooled in one heat exchanger El to provide a fraction 25 which is expanded in the turbine XI. The turbine XI provides a relaxed flow 10 which is heated in the exchanger El to give a heated heated flow 26. This heated heated flow 26 is introduced at a medium pressure stage 11 of the compressor K1.

The fifth compressed fraction 9 is cooled in the heat exchanger El to provide a fraction 22 which is expanded in a valve 23 and is then mixed with the expanded LNG fraction 2.

The regulator XI includes a guide valve _. input 27, the function of which has been defined in the description of FIG. 4.

Unlike FIG. 4, the installation shown in FIG. 5 further comprises a separator tank V2 in which the flow of expanded natural gas 2 is separated into a second fraction of the head 12 and a second fraction of the foot 13.

The second overhead fraction 12 is reheated in the heat exchanger El and is then introduced into a medium pressure stage 14 ^" of the compressor Kl, at a pressure intermediate between the inlet pressure of the low pressure stage 15 and that of the medium pressure stage 11.

The second fraction of the bottom 13 is cooled in an exchanger E2 to produce a fraction of cooled LNG 20. This latter fraction is expanded and cooled in a valve 28 to produce a fraction of expanded and cooled LNG 29. The opening of the valve 28 is controlled by a liquid level controller contained in the V2 tank. The flow 29 is then introduced into the column Cl to be separated therein into the first fraction of head 3 and into the first fraction of foot 4. As indicated during the description of FIG. 4, column Cl comprises a reboiler 16, which takes the liquid contained on a plate 17 of the column C1 to heat it in the exchanger E2 by heat exchange with the flow 13, and introduce it at the bottom of the column. Similarly, the first fraction of the bottom 4 is pumped by a pump PI and passes through a valve 19 whose opening is controlled by a liquid level controller present in the bottom of the column C1.

Referring now to Figure 6, the installation shown is intended to treat, using a device according to the method of the invention, a liquefied natural gas 1 preferably poor in nitrogen, for obtaining on the one hand, a cooled liquefied natural gas and poor in nitrogen 4, and on the other hand, a compressed combustible gas 5 rich in. nitrogen, in the case of the use of LNG 1 rich in nitrogen.

This installation includes elements common to Figure 2 and Figures 4 and 5.

In a simplified manner, FIG. 6 is structurally similar to FIG. 4, with the exception of the column C1 which has been replaced by a separation flask VI, and the exchanger E2 which has been deleted, due to the no reboiler when using a separating flask. The relaxed LNG flow. 2 is then directly introduced into the separator flask VI to be separated into a first fraction of the head 3 and into a first fraction of the foot 4.

The replacement of column C1 by balloon VI does not modify the course of the steps of the method as described for FIG. 5. On the other hand, due to a poorer performance in separating balloon VI compared to Column Cl, the refrigerated LNG 4 will normally contain more nitrogen when using a device according to FIG. 6 than when using a device according to FIG. 5. Of course , the LNG 1 used in both cases is physically and chemically identical and contains at least a little nitrogen.

Referring to Figure 7, the installation shown is intended to treat, using a device according to the method of the invention, a liquefied natural gas 1, preferably low in nitrogen, to obtain on the one hand, of a cooled liquefied natural gas 4, and on the other hand, of a compressed combustible gas 5. This installation comprises elements common to FIG. 2 and to FIGS. 4, 5 and 6. In a simplified manner, FIG. 7 is structurally similar to FIG. 5, with the exception of the column Cl which has been replaced by a separating flask VI, and the exchanger E2 which has been deleted, due to the absence reboiler when using a separation flask. The expanded LNG flow 2 is then directly introduced into the separator tank V2 to be separated into a second overhead fraction 12 and into a second bottom fraction 13. The second overhead fraction 12 is reheated in an exchanger El then is introduced into a compressor Kl with a medium pressure stage 14, intermediate between a low pressure stage 15 and a medium pressure stage 11, in the same manner as described for FIG. 5. The replacement of the column Cl by the tank VI does not modify the course of the steps of the method as it has been described for FIG. 5. On the other hand, due to a poorer separation performance of the tank VI compared to the column Cl, the refrigerated LNG 4 will normally contain more nitrogen in the case of the use of a device in accordance with FIG. 6 than in the case of the use of a device in accordance with FIG. 5. Of course, in order to allow a good comparison, the LNG 1 u used in both cases is physically and chemically identical.

In order to allow a concrete appreciation of the performance of an installation operating according to a process in accordance with the invention, numerical examples are now presented, for purposes of illustration and not of limitation.

These examples are given on the basis of two different natural gases "A" and "B", the composition of which is given below in Table 1:

Table 1

These gases are voluntarily free of C5 and higher hydrocarbons, so as not to weigh down the calculations.

The other operating conditions are identical and comply with the following (the reference figures refer to fig.l): - Temperature of wet natural gas 100: 37 ° C

- Pressure of wet natural gas 100: 54 bar

- Pre-cooling with refrigerant 113 before drying: 23 ° C

Dry gas temperature after passage through enclosure 116: 23.5 ° C

- Dry gas pressure: 51 bar

- Cooling water temperature: 30 ° C

- Temperature . at the water heat exchanger outlet: 37 ° C

- Propane condensation temperature: 47 ° C - - Efficiency of centrifugal compressors Kl, K2 and K3: 82%

- Efficiency of the expansion turbine X2: 85%

- Efficiency of the axial compressor XKl: 86%

- Power on a GE6 shaft line: 31570 k - Power on a GE7 shaft line: 63140 kW

- Power on a GE5D shaft line: 24,000 kW The power on a shaft line represents the power available on a General Electric gas turbine shaft of reference GE5D, GE6 and GE7. Des _. turbines of this type are coupled to compressors K1, K2 and K3 shown in Figures 1-7.

The natural gas flow rates to be liquefied will be chosen so as to saturate the powers available on the shaft lines. The following three cases are considered (for a liquefaction process described in Figure 1):

- Use for driving a turbine and a GE6 GE7 turbine, which corresponds to an LNG flow produced at -160 ° C e ^'bout 3 million tons per year..

- Use for driving two GE7 turbines, which corresponds to an LNG flow produced at -160 ° C of around 4 million tonnes per year.

- Use for the drive of three GE7 turbines, which corresponds to an LNG flow produced at -160 ° C of around 6 million tonnes per year. One of the ways to easily calculate the influence of a parameter without going into the details of a process is that of the notion of Theoretical Work associated with that of Exergy.

The theoretical work which it is necessary to provide to a system so that it passes from a state 1 to a state 2 is given by the following equation: l-2 = T0 x (SI - S2) - (Hl - H2) with: Wl-2: theoretical work (kj / kg) T0: heat rejection temperature (K)

51: entropy in state 1 (kJ / (K.kg))

52: entropy in state 2 (kJ / (K.kg)) Hl: enthalpy in state 1 (kJ / kg)

H2: enthalpy in state 2 (kj / kg) In the present case, the rejection temperature will be taken equal to 310.15 K (37 ° C). State 1 will be gas natural at 37 ° C and 51 bar and state 2 will be LNG at temperature T2 and 50 bar.

Table 2 below shows the evolution of the theoretical work for the liquefaction of natural gases A and B as a function of the temperature of the LNG leaving the liquefaction process. When the power of the refrigeration compressors is constant, the reduction in theoretical work results in a possible increase in the capacity of the liquefaction cycle.

Table 2

We observe that the figures obtained with gases A and B are very close. The possible increase in capacity is approximately 1.14% per ° C of the temperature of the LNG 1 obtained at the outlet of the liquefaction unit presented in FIG. 1.

The capacity Cl for a temperature Tl of the LNG produced is expressed as a function of the capacity C0 at the temperature T0, according to the following equation:

Cl = C0 x 1.0114 ^{(T1 ~ τo)} With:

Cl: LNG production capacity at Tl (kg / h) C0: Reference LNG production capacity at T0 (kg / h)

Tl: LNG production temperature (° C) T2: Reference LNG production temperature (° C)

As a result, at -140 ° C, the capacity of the LNG production unit is 125.5% of its capacity at -160 ° C, which is considerable.

The actual work of an LNG production unit will obviously depend on the process chosen. The process shown in Figure 1, which is known as MCR ^® is a method well known and widely used that was developed by the APCI society.

This process is implemented here in a particular way which makes it very efficient: the propane cycle comprises 4 stages and the refrigeration of the MCR (refrigerant with multiple components, flow 106, fig.l) and propane (flow 102, fig .l) takes place in the heat exchanger E3, which is a brazed aluminum plate exchanger.

The results obtained are presented in Table 3:

Table 3

It is observed that these results corroborate perfectly those which were obtained with the theoretical work calculations presented in Table 1.

The efficiency of the liquefaction process can be calculated from the actual work and the theoretical work. This is substantially constant and is around 51.5%, as can be seen from the results presented in Table 4:

Table 4

This result is particularly satisfactory. The user of the process will always be sure to get the most out of the liquefaction process, regardless of the LNG production temperature chosen. It is also noted that the composition of the natural gas to be liquefied does not matter.

Thus, the new use of the known liquefaction process makes it possible to increase the temperature of the LNG 1 obtained at the outlet of the production unit while allowing a substantial increase in the quantity produced, which can range up to around 40% at -130 ° C.

The LNG 1 obtained at the output of the production unit described above for FIG. 1 can be denitrogenated in a denitrogenation unit as shown in FIG. 2 or in FIG. 3. This denitrogenation operation is necessary when the natural gas extracted of the deposit contains nitrogen in a relatively large proportion, for example from about more than 0.100 mol% to about 5 to 10 mol%.

The installation shown diagrammatically in FIG. 2 is a LNG denitrogenation unit with final flash. The flash is obtained at the time of the separation of the expanded LNG 2 into a first fraction of head 3 relatively more volatile, rich in nitrogen, and in a first fraction of foot 4 relatively less volatile, poor in nitrogen. This separation takes place in a VI flask, as described above.

According to one operating mode, the LNG 1 of composition "B" containing nitrogen, produced at -150 ° C. and 48 bar is expanded in the hydraulic turbine X3 at a pressure of approximately 4 bar and then in a valve 18 to a pressure of 1.15 bar. The two-phase mixture obtained 2 is separated in the separator flask VI on the one hand into the nitrogen-rich flash gas 3, and on the other hand into the refrigerated LNG 4. The refrigerated LNG is sent to storage, as described above. . The flash gas 3, which constitutes the first gaseous fraction, is heated in the exchanger El to -70 ° C before being compressed to 29 bar in the compressor Kl. The compressor K1 produces a first compressed fraction 5 which constitutes the combustible gas enriched in nitrogen.

About 23% of the first compressed fraction 5 is recycled in the form of a fraction 6. The latter is cooled in the exchanger El by heat exchange with the flash gas 3, then is mixed with the cooled and expanded LNG stream. 2.

This arrangement makes it possible to liquefy part of the flash gas (approximately 23%) and to reduce the quantity of combustible gas produced. The performances of a denitrogenation unit according to this diagram 2 are presented in table 5 below, in which the column entitled “1 GE6 + 1 GE7” corresponds to an LNG production unit 1 according to diagram 1, using 1 gas turbine GE6 and 1 GE7 gas turbine for K2 and K3 compressors, "2 GE7" corresponds to the use of 2 GE7 turbines for the production of LNG 1, and "3 GE7" for the use of 3 turbines:

Table 5

The installation shown diagrammatically in FIG. 3 is an LNG denitrogenation unit with a column of denitrogenation. The replacement of the flash in the tank VI by a column of denitrogenation Cl allows a significant improvement in the extraction efficiency of the nitrogen contained in the LNG 1. In this installation, the LNG 1 at -145.5 ° C is expanded up to 5 bar in the expansion hydraulic turbine X3, pus is cooled from -146.2 ° C to -157 ° C in the exchanger E2 by heat exchange with the liquid circulating in the column bottom reboiler 16 to obtaining a relaxed and cooled LNG stream 20. The stream 20 undergoes a second expansion at 1.15 bar in a valve 21 and feeds the denitrogenation column C1 in mixture with LNG ^" 22 from the partial recycling of the gas compressed fuel 5. At the bottom of the C1 denitrogenation column, the LNG contains 0.06% nitrogen, while the nitrogen content of the LNG using a final flash was 1.38% (fig. 2 and table 5) This column bottom LNG is pumped by a PI pump and represents a fraction of cooled LNG 4 which is exp Dedicated to storage.

The combustible gas 3, which is the first overhead fraction coming from the column Cl, is heated to -75 ° C. in the exchanger El, then is compressed to 29 bar in the compressor Kl and cooled by the water refrigerants 31- 34 to supply compressed fuel gas 5.

A, flow 6, which represents 23% of the compressed gas 5 is recycled to the column Cl after having heated the flow 3 in the exchanger El.

The fuel gas produced, which represents 1032 GJ / h in the case of the use of a GE6 turbine and a GE7, is substantially identical in total calorific value to that of the final flash unit of FIG. 2 . The same is true when using larger LNG production units (2 or 3 GE7). The use of the column denitrogenation technique made it possible to increase the capacity of the liquefaction train by 5.62%, for a minor additional cost. It should be understood that it is the combination of the use of a denitrogenation column Cl and the recycling of combustible gas which leads to this very encouraging result. The power of the fuel gas compressor Kl depends on the size of the unit. It will be:

- 8087 kW for an LNG unit using 1 GE6 associated with 1 GE7,

- 10783 kW for an LNG unit using 2 GE7, - 16174 kW for an LNG unit using 3 GE7.

The power of these machines and the starting problems make it desirable to use a gas turbine to drive the fuel gas compressor Kl. The other performances of the process are presented in table 6:

Table 6

One of the main problems encountered in industrial gas processing and liquefaction installations relates in particular to the optimal use of compression apparatuses, which represent a significant investment, both from the point of view of purchasing and from the point of view of energy consumption. Indeed, compressors that require a. power on the order of several tens of thousands of kW must be reliable and able to be used under conditions of optimal efficiency over a load range as large as possible. Of course, this remark also applies to the means used to make them work. These means are usually gas turbines here, because of the range of powers available commercially.

Gas turbines, to be efficient, must be used at full capacity. Taking for example a denitrogenation unit operating according to any of the embodiments described in FIGS. 2 and 3, the gas turbine driving the compressor K1 should have a maximum power adapted to the power required by the compressor, in order to '' obtain the most favorable compression performance possible. However, it can happen that a gas turbine works under conditions such that the power delivered to the compressor is significantly below its capacity.

This is the case, for example, when a GE5d gas turbine, with a power of 24,000 kW is coupled to the compressor K1 during denitrogenation by final flash or by separation in a column. The consequence of this under-use of the turbine is a reduction in the energy efficiency of the compression relative to the energy consumption of the turbine.

Of course, the compressor power K1 varies as a function of the size of the unit, as explained above. So the use of a turbine

GE5d allows you to benefit from an excess of power which amounts to:

- 15913 kW for an LNG unit using 1 GE6 turbine associated with 1 GE7 turbine, 13217 kW for an LNG unit using 2 GE7 turbines,

- 7826 kW for an LNG unit using 3 GE7 turbines. It is therefore desirable to use this excess available energy. The method according to the invention proposes in particular to use all of the available power to drive the compressor K1.

The method according to the invention also makes it possible to increase the temperature at the outlet of the liquefaction process for obtaining the LNG flow 1, and to use the excess power available on the gas turbine driving Kl in order to cool the LNG at minus 160 ° C. In addition, the process according to the invention makes it possible, because of the possibility of increasing the temperature of the LNG 1 produced for example according to the APCI process, to significantly increase the flow rate of LNG cooled to -160 ° C. in some cases up to around 40%.

The method of the invention has the merit of being able to be implemented easily, due to the simplicity of the means necessary for carrying it out.

An embodiment according to the method of ^'the invention, implementing a denitrogenation column Cl is shown in Figure 4, described above. For the same turbine power driving the compressor Kl, the operating conditions will depend on the capacity of the natural gas liquefaction unit. LNG 1 is produced at -140.5 ° C by the APCI process shown in Figure 1. This process was implemented using two GE7 gas turbines for driving compressors K2 and K3. This LNG 1 enters the installation shown in Figure 4. It is expanded to 6.1 bar in the hydraulic expansion turbine X3 driving an electricity generator, then it is cooled from -141.2 to -157 ° C in a heat exchanger E2 by heat exchange with a liquid circulating in a column bottom reboiler 16, to provide a cooled LNG 21. The latter is expanded to 1.15 bar in a valve 21 to obtain a relaxed flow 2 which feeds a column C1 mixed with a flow 22, as indicated above in the description of the figures.

The LNG 4 flow, withdrawn at the bottom of column Cl, contains 0.00% nitrogen.

3 the fuel gas is warmed to -34 ° C in the exchanger El, is then compressed to 29 bar in the compressor Kl for supplying ^a fuel gas network.

A first ^" difference with the known process comes from the quantity of compressed gas 6 withdrawn from the fuel gas flow 5: it now amounts to approximately 73%. This compressed gas 6 is compressed to 38.2 bar in the compressor XKl for supply a fraction 7. The latter is cooled to 37 ° C in a water exchanger 24 then is separated into two streams 8 and 9. The main stream 8, which represents 70% of the stream 7, is cooled to -82 ° C by passage through the exchanger El, then feeds the turbine XI, coupled to the compressor XKl. The expanded flow at the outlet of the turbine 10, at a pressure of 9 bar and a temperature of -138 ° C is reheated in the exchanger El at 32 ° C, then supplies the compressor Kl to a medium-pressure stage 11 which is the third stage.

The minority stream 9, which represents 30% of the stream 7, is liquefied and cooled to -160 ° C. and returns to the denitrogenation column C1.

The combustible gas produced represents 1400 GJ / h, it is identical in total calorific value to that of the final flash unit. The use of the denitrogenation technique and the process of the invention made it possible to increase the capacity of the liquefaction train by 11.74%, for a reasonable additional cost. It must be understood that it is the combination of the use of a denitrogenation column, the recycling of compressed combustible gas and the expansion turbine cycle, which leads to this very surprising result.

For the other sizes of LNG production unit, the results are presented in Table 7:

Table 7 We observe that the capacity increases are:

- 14.2% for an LNG unit using a GE7 turbine associated with a GE6 turbine,

11.7% for an LNG unit using two GE7 turbines,

8.21% for an LNG unit using three GE7 turbines. The method according to the invention is also of considerable interest for regulating the quantity of combustible gas produced. Indeed, it is therefore possible to have ^" a sustained production of combustible gas, as shown by an example quantified in table 8, below:

Table 8

It can be seen that when the quantity of combustible gas goes from 1,400 to 2,800 GJ / h, it is then possible to increase the capacity by 13.39%, that is to say that 1.65% increase in capacity (13 , 39% minus 11.74%) are due to the increase in fuel gas production.

Another embodiment in accordance with the method of the invention, implementing a denitrogenation column C1, is presented in FIG. 5, described above. To the Unlike FIG. 4, this embodiment involves a separator balloon V2.

LNG 1, of composition "B" obtained at -140.5 ° C under a pressure of 48.0 bar with a flow rate of 33,294 kmol / h, is expanded to 6.1 bar and less 141.25 ° C in the hydraulic turbine X3, then is again expanded to 5.1 bar and -143.39 ° C in valve 18, to provide the expanded flow 2.

Flow 2 (33,294 kmol / h) is mixed with flow 35 (2,600 kmol / h) to obtain flow 36 (35,894 kmol / h), at -146.55 ° C.

Flow 35 is composed of 42.97% nitrogen, 57.02

% methane and 0 ^" , 01% ethane.

Stream 36, which is composed of 6.79% nitrogen, 85.83% methane, 4.97% ethane, 1.71% propane, 0.27% isobutane and 0.44 % of n-butane, is separated in the balloon V2 in the second fraction of head 12 (1609 kmol / h), and in the second fraction of foot 13 (34285 kmol / h). Flow 12 (45.58% nitrogen, 54.4% methane and

0.02% ethane) is heated to 33 ° C in the exchanger El, to provide a flow 37 which feeds, at

4.9 bar, compressor Kl on the medium pressure stage

14. Flow 13 (4.97% nitrogen, 87.30% methane,

5.20% ethane, 1.79% propane, 0.28% isobutane and 0.46% n-butane) is cooled in the heat exchanger E2 to provide the flow 20 at -157 ° C and 4.6 bar.

The latter is expanded in valve 28 to obtain flow 29 at -165.21 ° C and 1.15 bar, which is introduced into column Cl.

Column C1 produces at the head the first head fraction 3 (4032 kmol / h) at -165.13 ° C. Fraction 3 (41.73

% nitrogen and 58.27% methane) is heated in the exchanger El to give the flow 41 at -63.7 ° C and 1.05 bar. The stream 41 supplies the low pressure suction 15 of the compressor K1. Column C1 produces the first fraction of 4 foot at -159.01 ° C and 1.15 bar with a flow rate of 30,253 kmol / h. This fraction 4 (0.07% nitrogen, 91.17% methane, 5.90% ethane, 2.03% propane, 0.32% isobutane and 0.52% n- butane) is pumped by the PI pump to provide a fraction 39 at 4.15 bar and -158.86 ° C, then leaves the installation.

Column C1 is equipped with the column bottom reboiler 16, which cools the flow 13 to obtain the flow 20.

The compressor Kl produces the compressed flow 5 at 37 ° C and 29 bar with a flow rate of 11,341 kmol / h. This flow of combustible gas 5 (42.90% nitrogen and 57.09% methane) is separated into a flow 40, which represents 3041 kmol / h, which leaves the installation, and into a flow 6, which represents 8300 kmol / h, which is compressed in the XKl compressor.

The XKl compressor produces the compressed flow 7 at 68.18 ° C and 39.7 bar. Flow 7 is cooled to 37 ° C in one water exchanger 24, then is separated into flows 8 and 9. Flow 8 (5700 kmol / h) is cooled in exchanger El to give flow 25 to - 74 ° C and 38.9 bar.

Flow 9 (2600 kmol / h) is cooled in the exchanger El to give flow 22 at -155 ° C and 38.4 bar. The latter is then expanded in valve 23 to provide flow 35 at -168 ° C and 5.1 bar.

The flow 25 is expanded in the expansion turbine XI which produces the fraction 10 at a temperature of -139.7 ° C and a pressure of 8.0 bar. This fraction 10 is then reheated in the exchanger El which produces the fraction 26 at a temperature of 32 ° C and a pressure of 7.8 bar.

Fraction 26 supplies the compressor Kl on the medium-pressure stage 11. The compressor Kl and the regulator XI have the following performances: Denitrogenation unit compressor power Kl 22007 kW regulator power XI 2700 kW

The use of the V2 tank allows a gain of around 2000 kW on the power of the compressor Kl. From these studies on gas B, rich in nitrogen, it follows from the process according to the invention that:

- the increase in the temperature of the LNG leaving the liquefaction process makes it possible to obtain an increase in LNG production capacity of 1.2% per ° C, the use of a denitrogenation column associated with a liquefaction of part of the combustible gas produced is much more efficient than a final flash, - the saturation of the power of the gas turbine coupled to the compressor Kl by the use of the new process allows a significant gain in production capacity to be obtained LNG,

- the increase in the quantity of combustible gas produced makes it possible to obtain an additional increase in the LNG production capacity,

- the addition of the separator tank V2 improves the charge of the compressor Kl and lowers the cost of its use. The following study concerns the use of nitrogen-poor gas A, in which the final flash unit does not produce combustible gas.

In known manner, natural gas containing very little nitrogen does not require the use of a final flash. LNG can then be produced directly at -160 ° C and be sent to storage after expansion in a hydraulic turbine, for example similar to X3: This is the technique of advanced sub-cooling. When one chooses the deep sub-cooling, the sources of combustible gas can be of various origins:

- demethanizer overhead gas, - condensate stabilization column overhead gas,

- evaporation gas from storage tanks,

- regeneration gas from natural gas dryers, etc. It is then no longer possible to add a source of combustible gas without creating a risk of excess combustible gas. If it is desired to increase the capacity of the production line ^"LNG by increasing the LNG product temperature by the liquefaction process, it is necessary to establish a process which does not occur or little combustible gas.

The method according to the invention achieves this goal. It makes it possible to increase the temperature of the LNG at the outlet of the liquefaction process and consequently to increase the flow rate of cooled LNG 4, produced for storage purposes.

This process is presented in Figure 6, and has been described above. For the same turbine power coupled to the compressor Kl, the operating conditions will depend on the capacity of the liquefaction unit. The case of using LNG 1 from an LNG production unit comprising 2 GE7 turbines is described below by way of example:

LNG 1 at a temperature of -147 ° C is expanded to 2.7 bar in the hydraulic turbine X3 driving an electric generator, then undergoes a second expansion to 1.15 bar in the valve 18, and supplies the flash VI balloon mixed with LNG from the liquefaction of compressed fuel gas 5. At the bottom of tank VI, LNG is at -159, 2 ° C and 1.15 bar. It then leaves the installation to be stored. The combustible gas 3, which is the first overhead fraction, is heated to 32 ° C in the exchanger El before being compressed to 29 bar in the compressor K1, to optionally supply the fuel gas network. In the present case, all of the combustible gas is sent to the compressor XKl to supply the compressed flow 7 at 41.5 bar. This stream is then cooled to 37 ° C in the water exchanger 24, then is divided into two streams 8 and 9. The stream 8, which represents 79% of the stream 7, is cooled to -60 ° C before d '' supply the turbine XI coupled to the compressor XKl. The turbine XI supplies the expanded gas 10, at a pressure of 9 bar and a temperature of -127 ° C. This flow 10 is heated in the exchanger El to obtain a heated flow 26, at 32 ° C, then supplies the compressor K1 on the suction of its third stage.

Stream 9, which represents 21% of stream 7, is liquefied and cooled to -141 ° C in the exchanger El and returns to the flash tank VI.

The use of the new process increased the capacity of the liquefaction train by 15.82%, at a reasonable additional cost.

It should be understood that it is the combination of the recycling of compressed combustible gas and the expansion turbine cycle which leads to this very surprising result.

For LNG production units of different sizes, the results are presented in: - Table 9, which corresponds to the characteristics of a unit operating according to the embodiment of the method of the invention as presented in FIG. 6,

- Table 10, given for comparison, which presents the characteristics of an LNG refrigeration unit by the technique of extensive sub-cooling.

Table 9

Table 10 The capacity increases for the use of an installation in accordance with the process of the invention, compared to the technique of deep sub-cooling are as follows: - 19.6% for an LNG unit using 1 GE6 turbine associated with a GE7 turbine,

- 15.8% for an LNG unit using 2 GE7 turbines,

- 10.9% for an LNG unit using 3 GE7 turbines.

The embodiment of the method according to the invention according to Figure 6 also allows the production of combustible gas, when desired.

This possibility is illustrated by an example quantified in table 11, below:

Table 11

When the production of combustible gas goes from 0 to 785 GJ / h, it is then possible to increase the capacity by 18.13%, that is to say that 2.31% increase in capacity (18.13% minus 15.82%) are due to the production of combustible gas. This result is much clearer than that obtained with a denitrogenation plant.

Another embodiment in accordance with the method of the invention, using a denitrogenation column C1, is presented in FIG. 7, described above. To the Unlike FIG. 6, this embodiment involves a separator balloon V2.

LNG 1, of composition "A" obtained at -147 ° C under a pressure of 48.0 bar with a flow rate of 30,885 kmol / h, is expanded to 2.7 bar and less 147.63 ° C in the hydraulic turbine X3, then is again expanded to 2.5 bar and less 148.33 ° C in valve 18, to provide the expanded flow 2.

Flow 2 (30,885 kmol / h) is mixed with flow 35 (3,127 kmol / h) to obtain flow 36 (34,012 kmol / h), at -149.00 ° C.

Flow 35 is composed of 3.17% nitrogen, 96.82% methane and 0.0 "!% Ethane.

Stream 36, which is composed of 0.38% nitrogen, 91.90% methane, 4.09% ethane, 2.27% propane, 0.54% isobutane and 0.82 % of n-butane, is separated in the balloon V2 in the second ^• head fraction 12 (562 kmol / h), and in the second foot fraction 13 (33450 kmol / h). The stream 12 (5.41% nitrogen, 94.57% methane and 0.02% ethane) is heated to 34 ° C in the exchanger El, to provide a stream 37 which feeds, at 2.4 bar, compressor Kl on the medium pressure stage 14. Flow 13 (0.03% nitrogen, 91.85% methane, 4.16% ethane, 2.31% propane 0.55% isobutane and 0.83% n-butane) is expanded in valve 28 to obtain flow 29 at -159.17 ° C and 1.15 bar, which is introduced into the separator flask VI. Balloon VI produces at the head the first fraction of head 3 (2564 kmol / h) at -159.17 ° C. Fraction 3 (2.72% nitrogen, 97.27% methane and 0.01% ethane) is heated in the El exchanger to give flow 41 at minus 32.21 ° C and 1.05 bar. The stream 41 supplies the low pressure suction 15 of the compressor K1.

Balloon VI produces the first fraction of a foot 4 at -59.17 ° C and 1.15 bar with a flow rate of 30,886 kmol / h. This fraction 4 (0.10% nitrogen, 91.40% methane, 4.50% ethane, 2.50% propane, 0.60% isobutane and 0.90% n- butane) is pumped by the PI pump to provide a fraction 39 at 4.15 bar and -159.02 ° C, then leaves the installation.

The compressor Kl produces the compressed flow 5 at 37 ° C. and 29 bar with a flow rate of 13,426 kmol / h. This fuel gas flow 5 (3.18% nitrogen, 96.81% methane and 0.01

% ethane) is fully compressed in the XKl compressor, without producing combustible gas 40.

The XKl compressor produces the compressed flow 7 to

72.51 ° C and 42.7 bar. Stream 7 is cooled to 37 ° C in the 24 "water exchanger, then separated into streams 8 and 9.

Flow 8 (10300 kmol / h) is cooled in the exchanger El to give flow 25 at -56 ° C and 41.9 bar.

Flow 9 (3126 kmol / h) is cooled in the exchanger El to give flow 22 at -141 ° C and 41.4 bar. The latter is then expanded in valve 23 to provide flow 35 at -152.37 ° C and 2.50 bar.

The flow 25 is expanded in the expansion turbine XI which produces the fraction 10 at a temperature of -129.65 ° C and a pressure of 8.0 bar. This fraction 10 is then reheated in the exchanger El which produces the fraction 26 at a temperature of 34 ° C and a pressure of 7.8 bar.

Fraction 26 supplies the compressor Kl on the suction of the medium-pressure stage 11. The compressor Kl and the regulator XI have the following performances:

Denitrogenation unit Kl

The use of the V2 tank allows a gain of approximately 1000 kW on the power of the compressor Kl. Finally, from these studies on gas A, poor in nitrogen, it follows from the process according to the invention that:

the increase in the temperature of the LNG leaving the liquefaction process makes it possible to obtain an increase in LNG production capacity of 1.2% per ° C, this result being identical to that obtained with gas A,

the use of a final flash (balloon VI) and the saturation of the power of the gas turbine driving the compressor Kl makes it possible to obtain, thanks to the method of the invention, a significant gain in LNG production capacity , without producing combustible gas,

- the production of combustible gas allows an increase in the LNG production capacity. This gain is not negligible and can prove to be a decisive factor, the addition of the separator tank V2 improves the load of the compressor Kl and reduces the cost of its use.

Claims

1. Method for refrigerating a liquefied natural gas (1) under pressure containing methane and C ₂ and higher hydrocarbons, comprising a first step (I) in which (la) the said liquefied natural gas (1) is expanded pressure to provide a flow of expanded liquefied natural gas (2), wherein (Ib) separating said expanded liquefied natural gas (2) into a first fraction of head (3) relatively more volatile, and a first fraction of foot (4 ) relatively less volatile, in which (the) first fraction of a foot

(4) consisting of refrigerated liquefied natural gas is collected, in which (Id) is heated, it is compressed in a first compressor (Kl) and the first overhead fraction (3) is cooled to provide a first compressed fraction (5) of combustible gas which is collected, in which (the) a second compressed fraction (6) is taken from the first compressed fraction (5) which is then cooled and then mixed with the stream of expanded liquefied natural gas (2), characterized in that it comprises a second step (II) in which (IIa) the second compressed fraction (6) is compressed in a second compressor (XKl) coupled to an expansion turbine (XI) to provide a third compressed fraction (7), in which (Ilb) the third compressed fraction (7) is cooled and then separated into a fourth compressed fraction (8) and into a fifth compressed fraction (9), in which (Ile) the fourth compressed fraction (8) is cooled e t expanded in the expansion turbine (XI) coupled to the second compressor (XKl) to provide a relaxed fraction (10) which is then reheated then introduced to a first stage at medium pressure (11) of the compressor (Kl), and in which (Ild) the fifth compressed fraction (9) is cooled and then mixed with the stream of expanded liquefied natural gas (2).

2. Method according to claim 1, characterized in that the stream of expanded liquefied natural gas (2) is separated before step (Ib) into a second head fraction (12) and into a second foot fraction (13) , in that the second overhead fraction (12) is reheated and then introduced into the first compressor (Kl) at a second medium pressure stage (14) intermediate between the first medium pressure stage (11) and a low pressure stage (15), and in that the second fraction of the foot (13) is separated into the first fraction of the head (3) and the first fraction of the foot (4).

3. Method according to claim 1 or claim 2, characterized in that each compression step is followed by a cooling step.

4. Refrigerated liquefied natural gas (4) obtained by the process according to any one of the preceding claims.

5. Combustible gas (5) obtained by the process according to any one of claims 1 - 3.

6. Installation for refrigerating a liquefied natural gas (1) under pressure containing methane and C ₂ and higher hydrocarbons, comprising means for carrying out a first step (I) in which (la) the said liquefied natural gas is expanded (1) under pressure to provide a flow of expanded liquefied natural gas (2), wherein (Ib) separating said expanded liquefied natural gas (2) into a first fraction (3) which is relatively more volatile, and a first fraction relatively less volatile base (4), in which (the) the first base fraction (4) consisting of refrigerated liquefied natural gas is collected, in which

(Id) it is heated, it is compressed in a first compressor (Kl) and the first overhead fraction (3) is cooled to provide a first compressed fraction (5) of combustible gas which is collected, from which (the) is taken from the first compressed fraction (5) a second compressed fraction (6) which is then cooled then mixed with the stream of expanded liquefied natural gas (2), characterized in that it comprises means for carrying out a second step (II) in which (IIa) la. second compressed fraction (6) is compressed in a second compressor (XKl) coupled to an expansion turbine (XI) to provide a third compressed fraction (7), in which (Ilb) the third compressed fraction (7) is cooled and then separated in a fourth compressed fraction (8) and in a fifth compressed fraction (9), in which (Ile) the fourth compressed fraction (8) is cooled and expanded in the expansion turbine (XI) coupled to the second compressor (XKl) for supplying a relaxed fraction ( ^" 10) which is then reheated and then introduced to a first medium-pressure stage (11) of the compressor (Kl), and in which (Ild) the fifth compressed fraction (9) is cooled and then mixed with the flow of expanded liquefied natural gas (2).

7. Installation according to claim 6, characterized in that it comprises means for separating the flow of expanded liquefied natural gas (2) before step (Ib) into a second overhead fraction (12) and into a second fraction foot (13), in that it comprises means for heating and then introducing the second head fraction (12) into the first compressor (Kl) at a second stage at medium pressure

(14) intermediate between the first medium pressure stage (11) and a low pressure stage (15), and in that it comprises means for separating the second fraction of the foot (13) into the first fraction of the head ( 3) and in the first fraction of a foot (4).

8. Installation according to claim 6 or claim 7, characterized in that the first head fraction (3) and the first foot fraction (4) are separated in a first separator tank (VI).

9. Installation according to claim 6 or claim 7, characterized in that the first top fraction (3) and the first bottom fraction (4) are separated in a distillation column (Cl).

10. Installation according to any one of claims 6 - 9, characterized in that the flow of expanded liquefied natural gas (2) is separated into the second head fraction (12) and the second foot fraction (13) in a second separator tank (V2).

11. Installation according to claim 9, characterized in that the distillation column (Cl) comprises at least one lateral reboiler and / or column bottom (16), in that the liquid taken from a tray (17) of the distillation column (Cl) circulating in said reboiler (16) is reheated in a heat exchanger (E2) then is reintroduced into the distillation column (Cl) on a stage lower than said plate (17), and in that the flow of expanded liquefied natural gas (2) is cooled in said heat exchanger (E2).

12. Installation according to any one of claims 6 to 11, characterized in that the cooling of the first head fraction (3) and the expanded fraction (10), and the heating of the fourth compressed fraction (8) and of the fifth compressed fraction (9), takes place in a single first heat exchanger (El).

13. Installation according to any one of claims 6 to 12, in combination with claim 7, characterized in that the second head fraction (12) is heated in the first heat exchanger (El).