EP1352203B1 - Method for refrigerating liquefied gas and installation therefor - Google Patents

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

The present invention relates, in a general manner and according to a first aspect, to the gas industry, and in particular to a process for refrigerating pressurized gas containing methane and C2 hydrocarbons and higher, with a view to their separation.

More specifically, the invention relates to a method according to the preamble of claim 1.

Refrigeration processes of this type are well known to those skilled in the art and have been in use for many years, particularly in the document US 3646652 .

The refrigeration process of liquefied natural gas (LNG) according to the preamble above is used in a known manner in order to eliminate the nitrogen sometimes present in large quantities in natural gas. In this In this case, the fuel gas obtained by this process is enriched with nitrogen, whereas the refrigerated liquefied natural gas is depleted of nitrogen.

Natural gas liquefaction plants have well-defined technical characteristics and limitations imposed by the capacity of the elements of production constituting them. As a result, a liquefied natural gas production facility is limited by its maximum production capacity under normal operating conditions. The only way 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 depreciation.

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 mainly on the power of the compressors used to allow refrigeration and liquefaction of natural gas.

In this context, a first object of the invention is to propose a method, moreover in accordance with the generic definition given in 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.

The subject of the invention is a method according to claim 1 and an installation according to claim 4.

A first merit of the invention is to have found that a production unit operating at 100% of its capacity, producing a certain flow of liquefied natural gas at a temperature of -160 ° C and a pressure of around 50 bar all other operating parameters being constant, can only increase its flow, and therefore its production, by an increase in the production temperature of the liquefied natural gas.

However, the GNI is stored at about -160 ° C at low pressure (less than 1.1 bar absolute), and an increase in its storage temperature would result in an increase in its storage pressure, which represented prohibitive costs, but especially transport difficulties, because of the very large quantities of GEL produced.

Therefore, it is usual that the LNG is prepared at a temperature of -160 ° C prior to storage.

A second merit of the invention is to present an elegant solution to these production limitations by the use of a process of LNG refrigeration that can adapt to a pre-existing LNG production process, not requiring the use of 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 approximately -1.60 ° C, then its refrigeration at about -160 ° C by the process according to the invention.
A third merit of the invention is to have modified a nitrogen-rich liquefied natural gas refrigeration process known and in accordance with the preamble above, and to have allowed its use both with nitrogen-rich LNG and with LNG that is low in nitrogen. In the latter case, the fuel gas obtained by this process contains very little nitrogen, and therefore has a composition close to that of liquefied natural gas deficient in nitrogen.

The method according to the invention may have one or more of the features of claims 2 to 3

The plant according to the invention may comprise one or more of the features of claims 5 to 11

• La figure 1 représente un schéma synoptique fonctionnel d'une installation de liquéfaction de gaz naturel conforme à un mode de réalisation de l'art antérieur;
• La figure 2 représente un schéma synoptique fonctionnel d'une installation de déazotation à gaz naturel liquéfié conforme a un premier mode de réalisation de l'art antérieur;
• La figure 3 représente un schéma synoptique fonctionnel d'une installation de déazotation de gaz naturel liquéfié conforme à un deuxième mode de réalisation de l'art antérieur;
• Les figures 4, 5, 6 et 7 représentent des schémas synoptiques fonctionnels d'installations éventuellement de déazotation de gaz naturel liquéfié conforme à des modes de réalisation préférés de l'invention.

The invention will be better understood and other objects, characteristics, details and advantages thereof will appear more clearly in the following description with reference to the accompanying diagrammatic drawings, which are given by way of non-limiting example and wherein :

• The figure 1 represents a functional block diagram of a natural gas liquefaction plant according to an embodiment of the prior art;
• The figure 2 represents a functional block diagram of a liquefied natural gas denitrogenation plant according to a first embodiment of the prior art;
• The figure 3 represents a functional block diagram of a liquefied natural gas denitrogenation plant according to a second embodiment of the prior art;
• The figures 4 , 5 , 6 and 7 represent functional block diagrams of installations possibly denitrogenation of liquefied natural gas in accordance with preferred embodiments of the invention.

In these seven figures, the symbols "FC. Meaning "flow controller", "GT" meaning "gas turbine", "GE" meaning "power generator", "LC" meaning "liquid level controller", "PC" meaning "controller" "SC" meaning "speed controller" and "TC" meaning "temperature controller".

For the sake of clarity and brevity, the lines used in Figures 1 to 7 will be taken by the same reference signs as the gaseous fractions that circulate there.

By referring to the figure 1 , the plant shown is intended to treat, in known manner, a dried natural gas, desulfurized and decarbonated 100, 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 a primary cooling at approximately minus 30 ° C. in an exchanger E3 by expansion and vaporization of liquid propane. The heated and expanded vapor propane is then compressed in a second stage. compressor K2, then the compressed gas obtained 102 is then cooled and liquefied in water coolers 103, 104 and 105.

A second refrigerant circuit 106, generally corresponding to a cycle using a mixture of nitrogen, methane, ethane and propane, allows a significant cooling of the natural gas to be treated in order 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, and then cooled in a water cooler 114, to obtain a fluid 107. The latter is then cooled and liquefied in the exchanger E3 to provide a cooled and liquefied stream 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 heat 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 flowing in the lower part of the exchanger, by spraying on conduits carrying fluids. to cool, by means of spray bars. The vapor phase 109 circulates in the lower part of the cryogenic exchanger 111 to be cooled and liquefied, then is further cooled by circulation in an upper part of the cryogenic exchanger 111. Finally, this fraction 109 cooled and liquefied is relaxed in a valve 115, and is used to cool the fluids circulating in the upper part of the cryogenic exchanger 111, by spraying on conduits carrying fluids to be cooled. The refrigerant liquids sprayed inside the cryogenic exchanger 111, are then collected at the bottom of the latter to provide the flow 106 which is sent to the compressor K3.

The dried, desulphurized and decarbonated natural gas 100 is cooled in a propane heat exchanger 113 and then subjected to a desiccation treatment, which may be, for example, a passage over a molecular sieve, for example a zeolite, and a demercurization treatment, for example by passing on a silver foam or other mercury scavenger, in a chamber 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 provide a liquefied natural gas 1. The latter is usually obtained at a temperature below minus 120 ° C.

Now referring to the figure 2 , the installation shown is intended to treat, as a known mason, a liquefied natural gas 1 rich in nitrogen, for obtaining, on the one hand, a liquefied natural gas that is cooled and poor in nitrogen 4, and on the other hand of a compressed first fraction 5 which is a nitrogen-rich compressed fuel gas.

LNG 1 is first expanded and cooled in an X3 expansion turbine which is regulated by a controller LNG flow circulating in the pipe 1, then is again expanded and cooled in a valve 18 whose opening depends on the pressure of the LNG at the output of compressor X3, to provide a stream of liquefied natural gas expanded 2. The latter is then separated into a relatively more volatile first head fraction 3 and a relatively less volatile first foot fraction 4 in a V1 flask. The first bottom fraction 4 consisting of refrigerated liquefied natural gas is collected and pumped into a pump P1, circulates in a valve 19 whose opening is regulated by a liquid level controller in the bottom of the tank V1, and then leaves the tank. installation and be stored.

The first head fraction 3 is heated in a first heat exchanger E1 and is then 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 step, the compressed gases are cooled by passing through a heat exchanger, preferably with water. The first head fraction 3 provides, at the end of the compression and cooling steps, the nitrogen-rich compressed fuel gas 5. This combustible gas is then collected and leaves the installation.

A small portion of the fuel gas 5 is taken which corresponds to a stream 6. This stream 6 is refrigerated in the exchanger E1 by yielding its heat to the first head fraction 3, to give a cooled flow 22. This cooled flow 22 flows 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 expanded liquefied natural gas stream 2.

Now referring to the figure 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, nitrogen-poor liquefied natural gas 4, and on the other hand, a compressed first fraction 5 which is a nitrogen-rich compressed fuel gas. In this installation, the separation tank V1 was replaced by a distillation column C1 and a heat exchanger E2.

The LNG 1 is first expanded and cooled in an expansion turbine X3 whose speed is regulated by an LNG flow controller flowing 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, whose opening is controlled by a pressure controller located on the pipe 20, upstream of said valve 21, to provide a stream of liquefied natural gas expanded 2. The flow of liquefied natural gas relaxed 2 is then separated into a relatively more volatile first head fraction 3 and a relatively less volatile first foot fraction 4 in column C1. The first bottom fraction 4 consisting of refrigerated liquefied natural gas is collected and pumped into a pump P1, circulates in a valve 19 whose opening is regulated by a liquid level controller in the bottom of the tank V1, and then leaves the tank. installation and be stored.

Column C1 comprises a bottom reboiler 16 which uses liquid contained on a plate 17. The flow flowing in the reboiler 16 is heated in the heat exchanger E2 and then introduced into the bottom of the column C1.

The first top fraction 3 follows the same treatment as presented on the figure 2 , to obtain a first compressed gas fraction 5, which is a nitrogen-rich compressed fuel gas, and a second compressed fraction 6 which is a compressed fuel gas sampling fraction. Similarly, this last fraction is heated in the exchanger E1 to This stream 22 is also mixed with the expanded liquefied natural gas stream 2.

Now referring to the 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, for obtaining on the one hand, a liquefied natural gas cooled and low in nitrogen 4, and secondly, a nitrogen-rich compressed fuel gas 5.

This installation has elements common to the figure 3 , in particular the expansion and cooling of the LNG 1 to obtain the expanded LNG stream 2. Similarly, the separation into the first top fraction 3 and the first bottom fraction 4 is carried out similarly in the column C1. Finally, the flow of fuel gas 5 is obtained, as previously, by successive compression and cooling. Unlike the process presented on the figure 3 a second compressed fraction 6 taken from the first fraction of compressed gas 5 feeds a compressor XK1 coupled to an expansion turbine X1 to obtain a third compressed fraction 7. This is cooled in a water cooler 24 , then separated into a compressed fourth fraction 8 and a compressed fifth fraction 9.

The fourth compressed fraction 8 is cooled in the heat exchanger E1 to provide a fraction 25 which is expanded in the turbine X1. The turbine X1 provides a relaxed flow 10 which is heated in the exchanger E1 to give a heated expanded flow 26. This heated expanded 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 E1 to provide a fraction 22 which is expanded in a valve 23 and is then mixed with the expanded LNG fraction 2.

The regulator X1 comprises an inlet guide valve 27, allowing, by varying the angle of introduction of the flow 25 on the blades of the turbine X1, to vary the speed of rotation of the latter, and consequently to vary the power delivered to the compressor XK1.

Now referring to the 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, for obtaining, on the one hand, a gas Liquefied natural gas cooled and poor in nitrogen 4, and secondly, a nitrogen-rich compressed fuel gas 5, in the case where liquefied natural gas 1 contains it.

This installation has elements common to the figure 4 , especially the production, by a distillation column C1 of a first head fraction 3, and a first foot fraction 4. Similarly, the first head fraction 3 is compressed in a compressor K1 and cooled in refrigerants 31-34 for obtaining a first compressed fraction 5. A second sampling fraction 6 is withdrawn from the first compressed fraction 5 to be compressed in a compressor XK1 coupled to an expansion turbine X1, which produces an output of third compressed fraction 7. The latter is separated into a compressed fourth fraction 8 and a compressed fifth fraction 9.

The fourth compressed fraction 8 is cooled in the heat exchanger E1 to provide a fraction 25 which is expanded in the turbine X1. The turbine X1 provides a relaxed flow 10 which is heated in the exchanger E1 to give a heated expanded flow 26. This heated expanded 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 E1 to provide a fraction 22 which is expanded in a valve 23 and is then mixed with the relaxed LNG fraction 2.

The regulator X1 comprises an inlet guide valve 27, the function of which has been defined in the description of the figure 4 .

Unlike the figure 4 , the installation represented on the figure 5 further comprises a separator tank V2 in which the expanded natural gas stream 2 is separated into a second top fraction 12 and a second bottom fraction 13.

The second head fraction 12 is heated in the exchanger E1 and is introduced into a medium pressure stage 14 of the compressor K1, at an intermediate pressure between the inlet pressure of the low pressure stage 15 and that of the stage medium pressure 11.

The second bottom fraction 13 is cooled in an exchanger E2 to produce a fraction of cooled LNG 20. The latter fraction is expanded and cooled in a valve 28 to produce a fraction of cooled and cooled LNG 29. The opening of the valve 28 is controlled by a liquid level controller contained in the balloon V2. The stream 29 is then introduced into the column C1 to be separated into the first top fraction 3 and the first bottom fraction 4.

As stated in the description of the figure 4 Column C1 comprises a reboiler 16, which takes 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 foot fraction 4 is pumped by a pump P1 and passes through a valve 19 whose opening is controlled by a liquid level controller present in the bottom of the column C1.

Now referring to the 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 low in nitrogen, for obtaining, on the one hand, a liquefied natural gas cooled and deficient in nitrogen 4, and on the other hand, a nitrogen-rich compressed gas fuel 5, in the case of the use LNG 1 rich in nitrogen.

This installation has elements common to the figure 2 and to figures 4 and 5 .

In a simplified way, the figure 6 is structurally similar to the figure 4 , except column C1, which has been replaced by a separating balloon V1, and the exchanger E2 which has been omitted, because of the absence of a reboiler when using a separating balloon . The expanded LNG stream 2 is then introduced directly into the separator tank V1 to be separated into a first head fraction 3 and a first bottom fraction 4.

The replacement of the column C1 by the balloon V1 does not modify the progress of the steps of the method as it has been described for the figure 5 . On the other hand, because of the poorer separation performance of the flask V1 with respect to the column C1, the refrigerated LNG 4 will normally contain more nitrogen in the case of the use of a device according to the invention. figure 6 that in the case of the use of a device conforming to the figure 5 . Of course, the LNG 1 used in both cases is physically and chemically identical and contains at least a little nitrogen.

By referring to the 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, for obtaining, on the one hand, a cooled liquefied natural gas 4, and secondly, a compressed combustible gas 5.

This installation has elements common to the figure 2 and to figures 4 , 5 and 6 .

In a simplified way, the figure 7 is structurally similar to the figure 5 , with the exception of column C1 which has been replaced by a balloon. separator V1, and the exchanger E2 which has been removed, because of the absence of reboiler when using a separating balloon. The expanded LNG stream 2 is then introduced directly into the separator tank V2 to be separated into a second head fraction 12 and a second bottom fraction 13.

The second head fraction 12 is heated in an exchanger E1 and is introduced into a compressor K1 at a medium pressure stage 14, intermediate between a low pressure stage 15 and a medium pressure stage 11, in the same way as described for the figure 5 .

The replacement of the column C1 by the balloon V1 does not modify the progress of the steps of the method as it has been described for the figure 5 . On the other hand, because of the poorer separation performance of the flask V1 with respect to the column C1, the refrigerated LNG 4 will normally contain more nitrogen in the case of the use of a device according to the invention. figure 6 that in the case of the use of a device conforming to the figure 5 . Of course, in order to allow a good comparison, the LNG 1 used in both cases is identical physically and chemically.

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

These examples are given on the basis of two different natural gases "A" and "B" whose composition is given below in Table 1: Table 1 Component Natural gas A Natural gas B Molar composition (%) Mass Composition (%) Molar composition (%) Composition, mass (%) Nitrogen 0,100 0.155 3,960 6,127 Methane 91.400 81.378 88.075 78.039 Ethane 4,500 7.510 5,360 8.902 Propane 2,500 6,118 1,845 4,493 i-Butane 0,600 1,935 0.290 0.931 n-Butane 0,900 2,903 0,470 1,509 Total 100,000 100,000 100,000 100,000

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

• Température du gaz naturel humide 100 : 37°C
• Pression du gaz naturel humide 100 : 54 bar
• Pré-refroidissement par le réfrigérant 113 avant séchage : 23°C
• Température du gaz sec après passage dans l'enceinte 116 : 23,5°C
• Pression du gaz sec : 51 bar
• Température d'eau de refroidissement : 30°C
• Température en sortie d'échangeur à eau : 37°C
• Température de condensation du propane : 47°C.
• Rendement des compresseurs centrifuges K1, K2 et K3 : 82 %
• Rendement de la turbine de détente X2: 85 %
• Rendement du compresseur axial XK1: 86 %
• Puissance sur une ligne d'arbre GE6 : 31570 kW
• Puissance sur une ligne d'arbre GE7 : 63140 kW
• Puissance sur une ligne d'arbre GE5D : 24000 kW

The other operating conditions are identical and conform to the following (the reference figures refer to the fig.1 ):

• Temperature of wet natural gas 100: 37 ° C
• Pressure of wet natural gas 100: 54 bar
• Pre-cooling with coolant 113 before drying: 23 ° C
• Dry gas temperature after passage in the chamber 116: 23.5 ° C.
• Dry gas pressure: 51 bar
• Cooling water temperature: 30 ° C
• Water exchanger outlet temperature: 37 ° C
• Condensation temperature of propane: 47 ° C.
• Efficiency of centrifugal compressors K1, K2 and K3: 82%
• Efficiency of the expansion turbine X2: 85%
• Efficiency of axial compressor XK1: 86%
• Power on a GE6 shaft line: 31570 kW
• Power on a GE7 shaft line: 63140 kW
• Power on a GE5D shaft line: 24000 kW

Power on a shaft line represents the power available on a General Electric GESD, GE6 and GE7 gas turbine shaft. Turbines of this type are coupled to the compressors K1, K2 and K3 represented on the Figures 1-7 .

• Utilisation pour l'entraînement d'une turbine GE6 et d'une turbine GE7, ce qui correspond à un débit de GNL produit à -160°C d'environ 3 millions de tonnes par an.
• Utilisation pour l'entraînement de deux turbines GE7, ce qui correspond à un débit de GNL produit à -160°C d'environ 4 millions de tonnes par an.
• Utilisation pour l'entraînement de trois turbines GE7, ce qui correspond à un débit de GNL produit à -160°C d'environ 6 millions de tonnes par an.

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

• Used for driving a GE6 turbine and a GE7 turbine, which corresponds to a flow of LNG produced at -160 ° C of about 3 million tons per year.
• Use for driving two GE7 turbines, which corresponds to a flow of LNG produced at -160 ° C of about 4 million tons per year.
• Used for driving three GE7 turbines, which corresponds to a flow of LNG produced at -160 ° C of about 6 million tons 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.

• W1-2 = T0 × (S1 - S2) - (H1 - H2) avec :
  • W1-2: travail théorique (kJ/kg)
  • T0 : température de rejet de la chaleur (K)
  • S1 : entropie dans l'état 1 (kJ/(K.kg))
  • S2 : entropie dans l'état 2 (kJ/(K.kg))
  • H1 : enthalpie dans l'état 1 (kJ/kg)
  • H2 : enthalpie dans l'état 2 (kJ/kg)

The theoretical work that must be done for a system to change from state 1 to state 2 is given by the following equation:

• W1-2 = T0 × (S1 - S2) - (H1 - H2) with:
  • W1-2: theoretical work (kJ / kg)
  • T0: heat rejection temperature (K)
  • S1: entropy in state 1 (kJ / (K.kg))
  • S2: entropy in state 2 (kJ / (K.kg))
  • H1: enthalpy in state 1 (kJ / kg)
  • H2: enthalpy in state 2 (kJ / kg)

In this case, the reject temperature will be taken as 310.15 K (37 ° C). State 1 will be gas natural at 37 ° C and 51 bar and state 2 will be LNG at T2 temperature and at 50 bar.

Table 2 below shows the evolution of the theoretical work for the liquefaction of natural gas A and B as a function of the LNG temperature at the end of the liquefaction process. When the power of the refrigeration compressors is constant, the reduction of the theoretical work results in a possible increase in the capacity of the liquefaction cycle. Table 2 LNG temperature 1 (° C) Natural gas A Theoretical work (kJ / kg) Theoretical work (%) Possible capacity (%) -130 356.63 71.19 140.46 -135 376.93 75.25 132.90 -140 398.45 79.54 125.72 -145 421.57 84.16 118.82 -150 446.24 89.08 112.26 -155 472.64 94.35 105.99 -160 500.93 100.00 100.00 *************** Natural gas B -130 355.89 71.35 140.16 -135 376.04 75.39 132.65 -140 397.43 79.67 125.51 -145 420.23 84,24 118.70 -150 444.56 89.12 112.21 -155 470.74 94.37 105.97 -160 498.82 100.00 100.00

It is observed that the figures obtained with the gases A and B are very close. The possible increase in capacity is approximately 1.14% per ° C of LNG 1 obtained at the output of the liquefaction unit presented on the figure 1 .

The capacity C1 for a temperature T1 of the LNG produced is expressed as a function of the capacity C0 at the temperature T0, according to the following equation: $$\mathrm{VS}\mathrm{1}\mathrm{=}\mathrm{VS}\mathrm{0}\mathrm{\times }\mathrm{1}\mathrm{,}{\mathrm{0114}}^{\left(\mathrm{T}\mathrm{1}\mathrm{-}\mathrm{T}\mathrm{0}\right)}$$

• C1 : capacité de production de GNL à T1 (kg/h)
• C0 : capacité de production de GNL de référence à T0 (kg/h)
• T1 : Température de production de GNL (°C)
• T2 : Température de production de GNL de référence (°C)

With:

• C1: LNG production capacity at T1 (kg / h)
• C0: Reference LNG production capacity at T0 (kg / h)
• T1: LNG production temperature (° C)
• T2: Reference LNG production temperature (° C)

As a result, at -140 ° C, the capacity of the LNG 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 chosen process. The process presented on the 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 that makes it very efficient: the propane cycle has 4 stages and the refrigeration of the MCR (multicomponent refrigerant, stream 106, fig.1 ) and propane (stream 102, fig.1 ) is performed in the heat exchanger E3, which is a brazed aluminum plate heat exchanger.

The results obtained are shown in Table 3: Table 3 LNG temperature 1 (° C) Natural gas A Actual work (kJ / kg) Real work (%) Possible capacity (%) -130 702.77 72.23 138.45 -135 739.93 76,05 131.50 -140 781.25 80.29 124.54 -145 820.56 84.33 118.58 -150 867.88 89.20 112.11 -155 917.44 94.29 106.05 -160 972.99 100.00 100.00 *************** Natural gas B -130 688.86 71.24 140.37 -135 728.22 75.31 132.78 -140 772.16 79.86 125.23 -145 814.34 84,22 118.74 -150 861.75 89.12 112.21 -155 94.37 105.97 -160 100.00 100.00

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

The efficiency of the liquefaction process can be calculated from actual work and theoretical work. This is substantially constant and is around 51.5%, as can be seen from the results presented in Table 4: Table 4 LNG temperature 1 (° C) Natural gas A Theoretical work (kJ / kg) Real work (%) Efficiency (%) -130 356.63 702.77 50.75 -135 376.93 739.93 50.94 -140 398.45 781.25 51,00 -145 421.57 820.56 51.38 -150 446.24 867.88 51.42 -155 472.64 917.44 51.52 -160 500.93 972.99 51.48 *************** Natural gas B -130 355.89 688.86 51.66 -135 376.04 728.22 51,64 -140 397.43 772.16 51.47 -145 420.23 814.34 51,60 -150 444.56 861.75 51.59

This result is particularly satisfying. The user of the process will always be sure to make the most of the liquefaction process, regardless of the chosen LNG production temperature. 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 be up to about 40% to -130. ° C.

LNG 1 obtained at the output of a production unit previously described for the figure 1 , can be denoted in a unit of denitration as represented on the figure 2 or on the figure 3 . This denitrogenation operation is necessary when the natural gas extracted 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 schematically represented on the figure 2 is a denitrogen unit of LNG, with final flash. The flash is obtained at the time of separation of the expanded LNG 2 into a relatively more volatile, nitrogen-rich first head fraction 3 and a relatively less volatile, nitrogen-poor first foot fraction 4. This separation takes place in a flask V1, as previously described.

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 at a pressure of 1.15 bar. The two-phase mixture obtained 2 is separated in the separator tank V1 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 the storage, as described above. . The flash gas 3, which constitutes the first gaseous fraction, is heated in the exchanger E1 to -70 ° C before being compressed to 29 bar in the compressor K1. The compressor K1 produces a first compressed fraction 5 which constitutes the fuel 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 E1 by heat exchange with the flash gas 3, and is then mixed with the flow of cooled and relaxed LNG. 2.

This arrangement allows to liquefy part of the flash gas (about 23%) and reduce the amount of fuel gas produced. The performance of a denitrogenation unit according to this scheme 2 is presented in Table 5 below, in which the column labeled "1 GE6 + 1 GE7" corresponds to an LNG production unit 1 according to scheme 1, using 1 GE6 gas turbine 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 Unit 1 GE7 + 1 GE6 2 GE7 3 GE7 LNG 1 temperature ° C -150 -150 -150 debit kg / h 406665 542219 813330 Refrigerated LNG 4 debit kg / h 368990 491985 737980 specific low thermal value kJ / kg 48412 48412 48412 nitrogen content mol% 1.38 1.38 1.38 LNG production 4, low thermal value GJ / h 17864 23818 35727 % 100 100 100 Fuel gas 5 debit kg / h 37676 50235 75352 specific low thermal value kJ / kg 27492 27492 27492 fuel gas production 5, specific low thermal value GJ / h 1036 1381 2072. Unit of denunciation K1 compressor power kW 7037 9383 14074 performances specific production capacity of LNG kJ / kg 1019 1019 1019 Power ratio of K1 / LNG production 4 0.0210 0.0210 0.0210

The installation schematically represented on the figure 3 is a unit of denitrogenation of LNG to column of denitrogenation. The replacement of the flash in the balloon V1 by a denazotation column C1 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 to 5 bar in the expansion hydraulic turbine X3, and is cooled from -146.2 ° C to -157 ° C in the E2 exchanger by heat exchange with the liquid circulating in the bottom reboiler 16 to obtain a flow of cooled and expanded LNG 20. The flow 20 undergoes a second expansion at 1.15 bar in a valve 21 and feeds the column of denitrogenation C1 mixed with LNG ^- 22 from the partial recycling of the compressed fuel gas 5.

At the bottom of the C1 denitrogenation column, the LNG contains 0.06% nitrogen, whereas the nitrogen content of the LNG using a final flash was 1.38% ( fig.2 and Table 5). This bottom of the column LNG is pumped by a pump P1 and represents a cooled fraction of LNG 4 which is sent to storage.

The fuel gas 3, which is the first top fraction from the column C1, is warmed to -75 ° C in the exchanger E1, then is compressed to 29 bar in the compressor K1 and cooled by the water coolers 31. 34 to provide a compressed combustible gas 5.

A stream 6, which represents 23% of the compressed gas 5 is recycled to the column C1 after heating the stream 3 in the exchanger E1.

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 the fig.2 . The same is true when using larger LNG production units (2 or 3 GE7).

The use of the column denitrogenation technique increased the capacity of the liquefaction train by 5.62%, for a minor additional cost.

It must be understood that it is the combination of the use of a denitrogenation column C1 and the recycling of fuel gas that leads to this very encouraging result.

• 8087 kW pour une unité de GNL utilisant 1 GE6 associée à 1 GE7,
• 10783 kW pour une unité de GNL utilisant 2 GE7,
• 16174 kW une unité de GNL utilisant 3 GE7.

The power of the fuel gas compressor K1 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 one LNG unit using 2 GE7,
• 16174 kW one LNG unit using 3 GE7.

The powers of these machines and the startup problems make it desirable to use a gas turbine to drive the fuel gas compressor K1. The other performances of the process are presented in Table 6: Table 6 Unit 1 GE7 + 1 GE6 2 GE7 3 GE7 LNG 1 temperature ° C -145.5 -145.5 -145.5 debit kg / h 428175 570899 856350 Refrigerated LNG 4 debit kg / h 381659 508877 763318 specific low thermal value kJ / kg 49434 49434 49434 nitrogen content mol% 0.06 0.06 0.06 LNG production 4, low thermal value GJ / h 18867 25156 37734 % 105.62 105.62 105.62 Fuel gas 5 debit kg / h 46517 62023 93034 specific low thermal value kJ / kg 22191 22191 22191 fuel gas production 5, specific low thermal value GJ / h 1032 1376 2065 Unit of denunciation K1 compressor power kW 8087 10783 16174 performances specific production capacity of LNG kJ / kg 995 995 995 Power ratio of K1 / LNG production 4 0.0201 0.0201 0.0201 Additional LNG production kg / h 12669 16892 25338 GJ / h 1003 1338 2007

One of the main problems encountered in industrial gas treatment and liquefaction plants is the optimal use of compressors, which represent a significant investment, both in terms of purchase and from the point of view of energy consumption. Indeed, compressors that require a power of the order of several tens of thousands of kW must be reliable and can be used under optimal performance conditions over a load range as large as possible. Of course, this remark also applies to the means used to make them work. These means being usually here gas turbines, because of the range of commercially available powers.

Gas turbines, to be effective, must be used at full capacity. By taking for example a denitrogenation unit operating according to any of the embodiments described in figures 2 and 3 , the gas turbine driving the compressor K1 must have a maximum power adapted to the power required by the compressor, in order to obtain the most favorable compression performance possible.

However, it may happen that a gas turbine works under conditions such that the power delivered to the compressor is well below its capacity.

This is the case for example when a gas turbine GE5d, having a power of 24000 kW is coupled to the compressor K1 during denazotation by final flash or by separation in a column. The consequence of this underutilization of the turbine is a reduction in the energy efficiency of the compression relative to the energy consumption of the turbine.

• 15913 kW pour une unité de GNL utilisant 1 turbine GE6 associée à 1 turbine GE7,
• 13217 kW pour une unité de GNL utilisant 2 turbines GE7,
• 7826 kW pour une unité de GNL utilisant 3 turbines GE7.

Of course, the compressor power K1 varies according to the size of the unit, as explained above. Thus, the use of a GE5d turbine makes it possible to benefit from a surplus of power which amounts to:

• 15913 kW for an LNG unit using 1 GE6 turbine associated with 1 GE7 turbine,
• 13217 kW for one LNG unit using 2 GE7 turbines,
• 7826 kW for one LNG unit using 3 GE7 turbines.

It is therefore desirable to use this excess of available energy. The method according to the invention proposes in particular to use all of the power available 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 to obtain the flow of LNG 1, and to use the surplus power available on the gas turbine driving K 1 in order to cool the LNG at minus 160 ° C.

In addition, the process according to the invention makes it possible, by virtue of the possibility of increasing the temperature of the LNG 1 produced for example according to the APCI process, to increase the flow rate of LNG cooled to -160 ° C. to a large extent, in some cases, up to about 40%.

The method of the invention has the merit of being able to be implemented easily, because of the simplicity of the means necessary for its realization.

An embodiment according to the method of the invention, implementing a denitrogenation column C1, is presented on the figure 4 , described above. For the same turbine power driving the compressor K1, the operating conditions will depend on the capacity of the liquefaction unit of natural gas.

LNG 1 is produced at -140.5 ° C by the APCI process shown in FIG. figure 1 . This process was implemented using two GE7 gas turbines for the drive of compressors K2 and K3. This LNG 1 enters the installation presented on the figure 4 . It is expanded to 6.1 bar in the X3 hydraulic expansion turbine driving an electricity generator, then cooled from -141.2 to -157 ° C in a heat exchanger E2 by heat exchange with a liquid circulating in a 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 stream 22, as indicated above in the description of the figures.

The flow of LNG 4, withdrawn at the bottom of column C1, comprises 0.00% nitrogen.

The fuel gas 3 is heated to -34 ° C in the exchanger E1 and is compressed to 29 bar in the compressor K1 to supply a fuel gas network.

A first difference with the known method comes from the amount of compressed gas 6 taken from the flow of fuel gas 5: it now amounts to about 73%. This compressed gas 6 is compressed at 38.2 bar in the compressor XK1 to provide a fraction 7. The latter is cooled to 37 ° C in a water exchanger 24 and is separated into two streams 8 and 9.

Current 8, the majority, which represents 70% of the stream 7, is cooled to -82 ° C by passing through the exchanger E1, then feeds the turbine X1, coupled to the compressor XK1. The expanded flow at the turbine outlet 10, at a pressure of 9 bar and a temperature of -138 ° C is heated in the exchanger E1 at 32 ° C, then feeds the compressor K1 to a medium pressure stage 11 which is the third floor.

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

The fuel 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 a use of a denitrogenation column, the recycling of compressed fuel gas and the expansion turbine cycle which leads to this very surprising result.

For the other sizes of LNG production units, the results are shown in Table 7: Table 7 Unit 1 GE7
+
1 GE6 2 GE7 3 GE7 LNG 1 temperature ° C -138.5 -140.5 -143.5 debit kg / h 462359 602827 875470 Refrigerated LNG 4 debit kg / h 413619 537874 781438 specific low thermal value kJ / kg 49479 49479 49474 nitrogen content mol% 0.00 0.00 0.00 LNG production 4, low thermal value GJ / h 20465 26613 38661 % 114.57 111.74 108.21 Fuel gas 5 debit kg / h 48713 64994 94055 specific low thermal value kJ / kg 21008 21535 21521 gas-fuel production 5, specific low thermal value GJ / h 1023 1400 2024 Unit of denunciation K1 compressor power kW 23963 23970 23990 power of the regulator X1 kW 2835 2058 1175 performances specific production capacity of LNG kJ / kg 1056 1030 983 Power ratio of K1 / LNG production 4 0.0213 0.0208 0.0199 Additional LNG production kg / h 44629 45889 43458 GJ / h 2602 2795 2934

• 14,2 % pour une unité de GNL utilisant une turbine GE7 associée à une turbine GE6,
• 11,7 % pour une unité de GNL utilisant deux turbines GE7,
• 8,21 % pour une unité de GNL utilisant trois turbines GE7.

We observe that the increases in capacity are:

• 14.2% for an LNG unit using a GE7 turbine associated with a GE6 turbine,
• 11.7% for one LNG unit using two GE7 turbines,
• 8.21% for one LNG unit using three GE7 turbines.

The method according to the invention also has a considerable interest for the regulation of the amount of fuel gas produced. Indeed, it is therefore possible to have a sustained production of fuel gas, as shown by a numerical example in Table 8, below: Table 8 Unit 2 GE7 LNG 1 temperature ° C -135 debit kg / h 641176 Refrigerated LNG 4 debit kg / h 546088 specific low thermal value kJ / kg 49454 nitrogen content mol% 0.00 LNG production 4, low thermal value GJ / h 27006 % 113.39 Fuel gas 5 debit kg / h 95092 specific low thermal value kJ / kg 29361 fuel gas production 5, value
specific low thermal GJ / h 2792 Unit of denunciation K1 compressor power kW 23900 power of the regulator X1 kW 802 performances Specific output power of LNG 4 kJ / kg 1014 Power ratio of K1 / LNG production 4 0.0205 Additional LNG production kg / h 54103 GJ / h 3188

It can be seen that when the quantity of fuel gas increases from 1400 to 2800 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 according to the method of the invention, implementing a denitrogenation column C1, is presented on the figure 5 , described above. To the difference from the figure 4 this embodiment involves a separator balloon V2.

LNG 1, composition "B" obtained at -140.5 ° C, at a pressure of 48.0 bar with a flow rate of 33294 kmol / h, is expanded to 6.1 bar and minus 141.25 ° C in the hydraulic turbine X3, then is again expanded to 5.1 bar and -143.39 ° C in the valve 18, to provide the expanded flow 2.

Stream 2 (33294 kmol / h) is mixed with stream 35 (2600 kmol / h) to obtain stream 36 (35894 kmol / h) at -146.55 ° C.

Stream 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% % n-butane, is separated in the flask V2 in the second top fraction 12 (1609 kmol / h), and in the second foot fraction 13 (34285 kmol / h).

The stream 12 (45.58% of nitrogen, 54.4% of methane and 0.02% of ethane) is heated up to 33 ° C. in the exchanger E1, to provide a stream 37 which supplies, at 4.9 bar, compressor K1 on the medium pressure stage 14.

Stream 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 stream at -157 ° C and 4.6 bar. The latter is expanded in the valve 28 to obtain the stream 29 at -165.21 ° C and 1.15 bar, which is introduced into the column C1.

Column C1 produces the first top fraction 3 (4032 kmol / h) at -165.13 ° C. Fraction 3 (41.73% nitrogen and 58.27% methane) is reheated in exchanger E1 to give stream 41 at -63.7 ° C and 1.05 bar. The flow 41 supplies the low pressure suction 15 of the compressor K1.

Column C1 produces first foot fraction 4 at -159.01 ° C and 1.15 bar with a flow rate of 30253 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 pump P1 to provide a fraction 39 at 4.15 bar and -158.86 ° C, and then leaves the installation.

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

The compressor K1 produces the compressed stream 5 at 37 ° C and 29 bar with a flow rate of 11341 kmol / h. This flow of combustible gas (42.90% nitrogen and 57.09% methane) is separated into a stream 40, which represents 3041 kmol / h, which leaves the installation, and in a stream 6, which represents 8300 kmol / h, which is compressed in the compressor XK1.

The compressor XK1 produces the compressed stream 7. at 68.18 ° C and 39.7 bar. The stream 7 is cooled to 37 ° C in the water exchanger 24, and is separated into the streams 8 and 9.

Stream 8 (5700 kmol / h) is cooled in exchanger E1 to give the stream at -74 ° C and 38.9 bar.

Stream 9 (2600 kmol / h) is cooled in exchanger E1 to give stream 22 at -155 ° C and 38.4 bar. The latter is then expanded in the valve 23 to provide the flow at -168 ° C and 5.1 bar.

Stream 25 is expanded in the expansion turbine X1 which produces fraction 10 at a temperature of -139.7 ° C and a pressure of 8.0 bar. This fraction is then reheated in exchanger E1 which produces fraction 26 at a temperature of 32 ° C. and a pressure of 7.8 bar.

Fraction 26 feeds the compressor K1 on the medium-pressure stage 11. The compressor K1 and the expander X1 have the following performances:
Unit of denunciation K1 compressor power 22007 kW power of the regulator X1 2700 kW

The use of the V2 balloon allows a kid about 2000 kW on the power of the compressor K1.

• l'augmentation de la température du GNL en sortie du procédé de liquéfaction permet d'obtenir une augmentation de capacité de production de GNL de 1,2 % par °C,
• l'utilisation d'une colonne de déazotation associée à une liquéfaction d'une partie du gaz combustible produit est beaucoup plus efficace qu'un flash final,
• la saturation de la puissance de la turbine à gaz attelée au compresseur K1 par l'utilisation du nouveau procédé permet d'obtenir un gain important de capacité de production de GNL,
• l'augmentation de la quantité de gaz combustible produit permet d'obtenir une augmentation supplémentaire de la capacité de production de GNL,
• l'ajout du ballon séparateur V2 permet d'améliorer la charge du compresseur K1 et de baisser le coût de son utilisation.

From these studies on gas B, rich in nitrogen, it follows from the process according to the invention that:

• the increase in the LNG temperature at the outlet of 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 liquefaction of a portion of the fuel gas produced is much more effective than a final flash,
• the saturation of the power of the gas turbine coupled to the compressor K1 by the use of the new process makes it possible to obtain a significant gain in LNG production capacity,
• the increase in the quantity of fuel gas produced makes it possible to obtain an additional increase in the LNG production capacity,
• the addition of the separator tank V2 makes it possible to improve the load of the compressor K1 and to lower 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 fuel gas.

In known manner, natural gas containing very little nitrogen does not require the use of a final flash.

The LNG can then be produced directly at -160 ° C and shipped to the storage after expansion in a hydraulic turbine, for example similar to X3: This is the technique of deep subcooling.

• gaz de tête de déméthaniseur,
• gaz de tête de colonne de stabilisation des condensats,
• gaz d'évaporation des bacs de stockage,
• gaz de régénération des sécheurs de gaz naturel, etc.

When selecting the deep subcooling, the sources of fuel gas can be of various origins:

• demethanizer head gas,
• condensate stabilization column head gas,
• evaporation gas from storage tanks,
• regeneration gas from natural gas driers, etc.

It is no longer possible to add a combustible gas source without creating a risk of excess fuel gas. If one wishes to increase the capacity of the LNG production line by increasing the temperature of the LNG produced by the liquefaction process, it is necessary to set up a process that produces no or little fuel gas.

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

This process is presented at figure 6 , and has been described above. For the same turbine power coupled to the compressor K1, the operating conditions will depend on the capacity of the liquefaction unit. The case of using LNG 1 from an LNG production unit with 2 GE7 turbines is described below as an example:

The 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 at 1.15 bar in the valve 18, and supplies the flash ball V1 mixed with LNG from the liquefaction of the compressed fuel gas 5.

In bottom of balloon V1, the LNG is at -159, 2 ° C and 1.15 bar. He then leaves the installation to be stored.

The fuel gas 3, which is the first head fraction, is heated up to 32 ° C in the exchanger E1 before being compressed to 29 bar in the compressor K1 to possibly feed the fuel gas network. In this case, all of the fuel gas is sent into the compressor XK1 to provide the compressed stream 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 supplying the turbine X1 coupled to the compressor XK1. The turbine X1 provides the expanded gas 10 at a pressure of 9 bar and a temperature of -127 ° C. This flow 10 is heated in the exchanger E1 to obtain a heated flow 26 at 32 ° C, then feeds the compressor K1 on the suction of its third stage.

The stream 9, which represents 21% of the stream 7, is liquefied and cooled to -141 ° C. in the exchanger E1 and returns to the flash tank V1.

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

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

• le tableau 9, qui correspond aux caractéristiques d'une unité fonctionnant selon le mode de réalisation du procédé de l'invention tel que présenté sur la figure 6,
• le tableau 10, donné à titre de comparaison, qui présente les caractéristiques d'une unité de réfrigération de GNL par la technique du sous refroidissement poussé.

Tableau 9 Unité 1 GE7 + 1 GE6 2 GE7 3 GE7 GNL 1 température °C -144 -147 -151 débit kg/h 430862 556506 799127 GNL réfrigéré 4 débit kg/h 430862 556506 799127 valeur thermique basse spécifique kJ/kg 49334 49334 49334 contenu en azote %mol 0,10 0,10 0,10 production de GNL 4, valeur GJ/h 21256 27455 39424 thermique basse % 100 115,82 115,82 Gaz combustible 5 débit kg/h 0 0 0 valeur thermique basse spécifique kJ/kg 0 0 0 production de gaz combustible 5, valeur thermique basse spécifique GJ/h 0 0 0 Unité de flash final puissance du compresseur K1 kW 24000 24000 23543 puissance du détendeur X1 kW 4719 4719 4850 Performances puissance spécifique de production de GNL 4 kJ/kg 1014 995 984 rapport Puissance de K1/Production de GNL 4 0,0206 0,0202 0,0199 Production supplémentaire de kg/h 70489 76010 78381 GNL GJ/h 3477 3749 3866 Tableau 10 Unité 1 GE7 + 1 GE6 2 GE7 3 GE7 GNL 1 température °C -160 -160 -160 débit kg/h 360373 480496 720746 GNL réfrigéré 4 débit kg/h 360373 480496 720746 valeur thermique basse spécifique kJ/kg 49334 49334 49334 contenu en azote %mol 0,10 0,10 0,10 production de GNL 4, valeur GJ/h 17779 23705 35558 thermique basse % 100,00 100,00 100,00 Gaz combustible 5 débit kg/h 0 0 0 valeur thermique basse spécifique kJ/kg 0 0 0 production de gaz combustible 5, valeur thermique basse spécifique GJ/h 0 0 0 Unité de flash final puissance du compresseur K1 kW 0 0 0 puissance du détendeur X1 kW 0 0 0 Performances puissance spécifique de production de GNL 4 kJ/kg 973 973 973 rapport Puissance de K1/Production de GNL 4 0,0197 0,0197 0,0197 Production supplémentaire de kg/h 0 0 0 GNL GJ/h 0 0 0 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 on the figure 6 ,
• Table 10, for comparison, which shows the characteristics of an LNG refrigeration unit by the technique of deep subcooling.

Table 9 Unit 1 GE7 + 1 GE6 2 GE7 3 GE7 LNG 1 temperature ° C -144 -147 -151 debit kg / h 430862 556506 799127 Refrigerated LNG 4 debit kg / h 430862 556506 799127 specific low thermal value kJ / kg 49334 49334 49334 nitrogen content mol% 0.10 0.10 0.10 LNG production 4, value GJ / h 21256 27455 39424 low thermal % 100 115.82 115.82 Fuel gas 5 debit kg / h 0 0 0 specific low thermal value kJ / kg 0 0 0 fuel gas production 5, specific low thermal value GJ / h 0 0 0 Final flash unit K1 compressor power kW 24000 24000 23543 power of the regulator X1 kW 4719 4719 4850 performances Specific output power of LNG 4 kJ / kg 1014 995 984 Power ratio of K1 / LNG production 4 0.0206 0.0202 0.0199 Additional production of kg / h 70489 76010 78381 LNG GJ / h 3477 3749 3866 Unit 1 GE7 + 1 GE6 2 GE7 3 GE7 LNG 1 temperature ° C -160 -160 -160 debit kg / h 360373 480496 720746 Refrigerated LNG 4 debit kg / h 360373 480496 720746 specific low thermal value kJ / kg 49334 49334 49334 nitrogen content mol% 0.10 0.10 0.10 LNG production 4, value GJ / h 17779 23705 35558 low thermal % 100.00 100.00 100.00 Fuel gas 5 debit kg / h 0 0 0 specific low thermal value kJ / kg 0 0 0 fuel gas production 5, specific low thermal value GJ / h 0 0 0 Final flash unit K1 compressor power kW 0 0 0 power of the regulator X1 kW 0 0 0 performances Specific output power of LNG 4 kJ / kg 973 973 973 Power ratio of K1 / LNG production 4 0.0197 0.0197 0.0197 Additional production of kg / h 0 0 0 LNG GJ / h 0 0 0

• 19,6 % pour une unité de GNL utilisant 1 turbine GE6 associée à une turbine GE7,
• 15,8 % pour une unité de GNL utilisant 2 turbines GE7,
• 10, 9 % pour une unité de GNL utilisant 3 turbines GE7.

The increases in capacity for the use of an installation according to the method of the invention, compared with the technique of deep subcooling 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 process according to the invention according to figure 6 also allows the production of fuel gas, when desired. This eventuality is illustrated by a numerical example in Table 11, below: Table 11 Unit 1 GE7 + 1 GE6 LNG 1 temperature ° C -143 debit kg / h 583534 Refrigerated LNG 4 debit kg / h 567402 specific low thermal value kJ / kg 49351 nitrogen content mol% 0.06 LNG production 4, low thermal value GJ / h 28002 % 118,13 Fuel gas 5 debit kg / h 16132 specific low thermal value kJ / kg 48659 fuel gas production 5, value
specific low thermal GJ / h 785 Final flash unit K1 compressor power kW 23888 power of the regulator X1 kW 3520 performances Specific output power of LNG 4 kJ / kg 976 Power ratio of K1 / LNG production 4 0.0198. Additional LNG production kg / h 86906 GJ / h 4297

When the production of fuel gas goes from 0 to 785 GJ / h, it is then possible to increase the capacity of 18,13%, that is to say that 2,31% increase of capacity (18,13% minus 15.82%) are due to the production of fuel gas. This result is much clearer than that obtained with a denitrogenation plant.

Another embodiment according to the method of the invention, implementing a denitrogenation column C1, is presented on the figure 7 , described above. To the difference from the figure 6 this embodiment involves a separator balloon V2.

LNG 1, composition "A" obtained at -147 ° C. under a pressure of 48.0 bar with a flow rate of 30885 kmol / h, is expanded to 2.7 bar and minus 147.63 ° C. in the hydraulic turbine X3, then is again expanded to 2.5 bar and minus 148.33 ° C in the valve 18, to provide the expanded flow 2.

Stream 2 (30885 kmol / h) is mixed with stream 35 (3127 kmol / h) to obtain stream 36 (34012 kmol / h) at -149.00 ° C.

The stream is composed of 3.17% nitrogen, 96.82% methane and 0.01% 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% % n-butane, is separated in the flask V2 in the second top 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 up to 34 ° C in the exchanger E1, to provide a stream 37 which feeds, at 2.4 bar, compressor K1 on medium pressure stage 14.

Stream 13 (0.03% nitrogen, 91.85% methane, 4.16% ethane, 2.31% propane, 0.55% isobutane and 0.83% n butane) is expanded in the valve 28 to obtain the stream 29 at -159,17 ° C and 1.15 bar, which is introduced into the separator tank V1.

The flask V1 produces at its head the first top fraction 3 (2564 kmol / h) at -159.17 ° C. Fraction 3 (2.72% nitrogen, 97.27% methane and 0.01% ethane) is reheated in exchanger E1 to give stream 41 at minus 32.21 ° C and 1.05. bar. The flow 41 supplies the low pressure suction 15 of the compressor K1.

The V1 flask produces the first foot fraction 4 at -159.17 ° C and 1.15 bar with a flow rate of 30886 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 pump P1 to provide a fraction 39 at 4.15 bar and -159.02 ° C, and then leaves the installation.

The compressor K1 produces the compressed stream 5 at 37 ° C and 29 bar with a flow rate of 13426 kmol / h. This flow of fuel gas (3.18% nitrogen, 96.81% methane and 0.01% ethane) is completely compressed in the compressor XK1, without production of fuel gas 40.

The XK1 compressor produces the compressed stream 7 at 72.51 ° C and 42.7 bar. The stream 7 is cooled to 37 ° C in the water exchanger 24, and is separated into the streams 8 and 9.

Stream 8 (10300 kmol / h) is cooled in exchanger E1 to give the stream at -56 ° C and 41.9 bar.

Stream 9 (3126 kmol / h) is cooled in exchanger E1 to give stream 22 at -141 ° C and 41.4 bar. The latter is then expanded in the valve 23 to provide the flow at -152.37 ° C and 2.50 bar.

Stream 25 is expanded in the expansion turbine X1 which produces fraction 10 at a temperature of -129.65 ° C and a pressure of 8.0 bar. This fraction 10 is then reheated in exchanger E1 which produces fraction 26 at a temperature of 34 ° C. and a pressure of 7.8 bar.

Fraction 26 feeds the compressor K1 on the suction of the medium-pressure stage 11. The compressor K1 and the expander X1 have the following performances:
K1 denazaction unit K1 compressor power 23034 kW power of the regulator X1 2700 kW

The use of the balloon V2 allows a gain of about 1000 kW on the power of the compressor K1.

• l'augmentation de la température du GNL en sortie du procédé de liquéfaction permet d'obtenir une augmentation de capacité de production de GNL de 1,2 % par °C, ce résultat étant identique à celui obtenu avec le gaz A,
• l'utilisation d'un flash final (ballon V1) et la saturation de la puissance de la turbine à gaz entraînant le compresseur K1 permet d'obtenir, grâce au procédé de l'invention, un gain important de capacité de production de GNL, sans produire de gaz combustible,
• la production de gaz combustible permet d'obtenir une augmentation de la capacité de production de GNL. Ce gain est non négligeable et peut s'avérer un facteur décisif,
• l'ajout du ballon séparateur V2 permet d'améliorer la charge du compresseur K1 et de réduire le coût de son utilisation.

Finally, from these studies on the gas A, low in nitrogen, it follows from the process according to the invention that:

• the increase in the LNG temperature at the outlet of 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 the gas A,
• the use of a final flash (ball V1) and the saturation of the power of the gas turbine driving the compressor K1 provides, thanks to the method of the invention, a significant gain in LNG production capacity, without producing combustible gas,
• the production of fuel gas makes it possible to obtain an increase in LNG production capacity. This gain is significant and can be a decisive factor,
• the addition of the separator tank V2 makes it possible to improve the load of the compressor K1 and to reduce the cost of its use.

Claims (11)

1. Method of refrigerating a pressurised, liquefied natural gas (1) containing methane and C₂ and higher hydrocarbons, comprising a first step (I) during which (Ia) said pressurised, liquefied natural gas (1) is expanded in order to obtain a flow of expanded, liquefied natural gas (2), during which (Ib) said expanded, liquefied natural gas (2) is split into a first top fraction (3) which is more volatile relatively speaking, and a first bottom fraction (4) which is less volatile relatively speaking, during which (Ic) the first bottom fraction (4) made up of refrigerated, liquefied natural gas is collected, during which (Id) the first top fraction (3) is heated, compressed in a first compressor (K1) and cooled to obtain a first compressed fraction (5) of combustible gas which is collected, during which (Ie) a second compressed fraction (6) is drawn off from the first compressed fraction (5) which is then cooled and then mixed with the flow of expanded, liquefied natural gas (2), characterised in that it comprises a second step (II) during which (IIa) the second compressed fraction (6) is compressed in a second compressor (XK1) coupled with an expansion turbine (X1) to obtain a third compressed fraction (7), during which (IIb) the third compressed fraction (7) is cooled and then separated into a fourth compressed fraction (8) and a fifth compressed fraction (9), during which (IIc) the fourth compressed fraction (8) is cooled and expanded in the expansion turbine (X1) coupled with the second compressor (XK1) to obtain an expanded fraction (10) which is then heated and then introduced into a first medium-pressure stage (11) of the compressor (K1), and during which (IId) the fifth compressed fraction (9) is cooled and then mixed with the flow of expanded, liquefied natural gas (2).
2. Method as claimed in claim 1, characterised in that the expanded, liquefied flow of natural gas (2) is separated into a second top fraction (12) and a second bottom fraction (13) prior to step (Ib), in that the second top fraction (12) is heated and then introduced into the first compressor (K1) at an intermediate, second medium-pressure stage (14) between the first medium-pressure stage (11) and a low-pressure stage (15), and in that the second bottom fraction (13) is separated into the first top fraction (3) and the first bottom fraction (4).
3. Method as claimed in claim 1 or claim 2, characterised in that each compression step is followed by a cooling step.
4. Installation for refrigerating a pressurised, liquefied natural gas (1) containing methane and C₂ and higher hydrocarbons, comprising means for implementing a first step (I) during which (Ia) said pressurised, liquefied natural gas (1) is expanded to obtain a flow of expanded, liquefied natural gas (2), during which (Ib) said expanded, liquefied natural gas (2) is separated into a first top fraction (3) which is more volatile relatively speaking, and a first bottom fraction (4) which is less volatile relatively speaking, during which (Ic) the first bottom fraction (4) made up of refrigerated, liquefied natural gas is collected, during which (Id) the first top fraction (3) is heated, compressed in a first compressor (K1) and cooled to obtain a first compressed fraction (5) of combustible gas which is collected, during which (Ie) a second compressed fraction (6) is drawn off from the first compressed fraction (5) which is then cooled and then mixed with the flow of expanded, liquefied natural gas (2), characterised in that it has means for implementing a second step (II) during which (IIa) the second compressed fraction (6) is compressed in a second compressor (XK1) coupled with an expansion turbine (X1) to obtain a third compressed fraction (7), during which (IIb) the third compressed fraction (7) is cooled and then separated into a fourth compressed fraction (8) and a fifth compressed fraction (9), during which (IIc) the fourth compressed fraction (8) is cooled and expanded in the expansion turbine (X1) coupled with the second compressor (XK1) to obtain an expanded fraction (10) which is then heated and then introduced into a first medium-pressure stage (11) of the compressor (K1), and during which (IId) the fifth compressed fraction (9) is cooled and then mixed with the flow of expanded, liquefied natural gas (2).
5. Installation as claimed in claim 4, characterised in that it has means for separating the flow of expanded, liquefied natural gas (2) into a second top fraction (12) and a second bottom fraction (13) prior to step (Ib), and in that it has means for heating the second top fraction (12) and then introducing it into the first compressor (K1) at an intermediate second medium-pressure stage (14) between the first medium-pressure stage (11) and a low-pressure stage (15), and that it has means for separating the second bottom fraction (13) into the first top fraction (3) and the first bottom fraction (4).
6. Installation as claimed in claim 4 or claim 5, characterised in that the first top fraction (3) and the first bottom fraction (4) are separated in a first separator balloon (V1).
7. Installation as claimed in claim 4 or claim 5, characterised in that the first top fraction (3) and the first bottom fraction (4) are separated in a distillation column (C1).
8. Installation as claimed in any one of claims 4 to 7, characterised in that the flow of expanded, liquefied natural gas (2) is separated into the second top fraction (12) and the second bottom fraction (13) in a second separator balloon (V2).
9. Installation as claimed in claim 7, characterised in that the distillation column (C1) has at least one lateral reboiler and/or column base (16), in that liquid drawn from a plate (17) of the distillation column (C1) circulating in the reboiler (16) is heated in a heat exchanger (E2) and is then reintroduced into the distillation column (C1) at 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).
10. Installation as claimed in any one of claims 4 to 9, characterised in that cooling of the first top fraction (3) and expanded fraction (10), and heating of the fourth compressed fraction (8) and fifth compressed fraction (9) take place in a single first heat exchanger (E1).
11. Installation as claimed in any one of claims 4 to 10 in combination with claim 5, characterised in that the second top fraction (12) is heated in the first heat exchanger (E1).

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