RU2730090C2 - Method and system for liquefaction of natural gas feed flow - Google Patents

Abstract

FIELD: technological processes.SUBSTANCE: invention relates to liquefaction of natural gas stream. Provided is compressed process flow (25). First separated flow (32) is obtained from the compressed process flow and the first separated flow is expanded. Remaining portion of the compressed process flow (31) is cooled by an expanded first separated flow. Second separated flow (52) is obtained from pre-cooled process flow (41) and expanded. Remaining portion of the pre-cooled compressed process flow (51) is cooled by steam flow (56) obtained from the second separated flow. Additional cooled process flow (61) is expanded to produce flow (71) of liquefied natural gas. First separated flow (42) and steam flow (62) are passed into the repeated compression unit (200) to obtain recirculation flow (105), which must be combined with the natural gas feed flow to form a process flow.EFFECT: reduced capital expenditures.15 cl, 2 dwg

Description

This invention relates to a method and system for liquefying a natural gas feed stream.

Methods for liquefying hydrocarbon-containing gas streams are well known in the art. A hydrocarbon-containing gas stream, such as a natural gas stream, is desirably liquefied for a number of reasons. For example, natural gas is easier to store and transport over long distances in liquid form than in gaseous form because it takes up less volume and does not need to be stored under high pressure. Typically, prior to liquefaction, the contaminated hydrocarbon-containing gas stream is treated to remove one or more contaminants (such as H ₂ O, CO ₂ , H ₂ S, and the like) that may freeze out during the liquefaction process.

Liquefaction processes are known in the art, in which one or more closed refrigeration cycles are used to cool and liquefy a hydrocarbon-containing gas stream. Examples are the C3-MR process or the DMR process. The C3-MR process uses propane as the refrigerant in the first refrigeration step and the second refrigeration step uses a mixture of two or more refrigerants, such as a mixture of propane, ethane, methane and nitrogen. The DMR process uses two refrigeration cycles, each of which includes a mixed refrigerant.

Alternative liquefaction processes are known that do not use a separate refrigeration cycle.

WO 02014/166925 describes a method for liquefying a contaminated hydrocarbon-containing gas stream, the method comprising at least the steps:

1) providing a polluted hydrocarbon-containing gas stream;

2) cooling the polluted hydrocarbon-containing gas stream in the first heat exchanger to obtain a cooled polluted hydrocarbon-containing stream;

3) cooling the cooled contaminated hydrocarbon-containing stream in an expander to obtain a partially liquefied stream;

4) separating the partially liquefied stream in a separator to obtain a gas stream and a liquid stream;

5) expanding the liquid stream obtained in step 4) to obtain a multiphase flow, the multiphase flow comprising at least a vapor phase, a liquid phase and a solid phase;

6) separating the multiphase flow in the separator to obtain a gaseous flow and a slurry slurry flow (containing solid CO ₂ and liquid hydrocarbons);

7) separating the slurry stream in a solid / liquid separator to obtain a liquid hydrocarbon stream and a concentrated slurry slurry stream;

8) passing the gaseous stream obtained in step 4) through a first heat exchanger to obtain a heated gaseous stream, and

9) compressing the heated gaseous stream to obtain a compressed gaseous stream, and

10) mixing the compressed gas stream obtained in step 9) with the contaminated hydrocarbon-containing gas stream provided in step 1).

The process described in WO2014 / 166925 allows a contaminated hydrocarbon-containing gas stream to be liquefied using a relatively small amount of equipment without the need for a refrigeration cycle, thereby providing a simple and cost-effective method for liquefying a contaminated hydrocarbon-containing gas stream, in particular a methane-containing contaminated gas stream such as natural gas. The pollutant can be CO ₂ .

The method according to WO2014 / 166925 uses a freeze-out process for removing CO ₂ . In step 5), as described above, the process conditions in the liquid stream obtained in step 4) are outside the operating parameters for freezing CO ₂ (process conditions are, for example, 20 bar, -120 ° C, 1 mol% CO ₂ ), so that any further decrease in temperature will cause the CO _{2 to} freeze out. Temperature reduction is achieved in step 5) by decreasing the pressure in the throttle valve (Joule Thomson valve). The decrease in pressure leads to the evaporation of part of the liquid methane, thereby cooling the remaining liquid.

Other liquefaction methods are described, for example, in WO15110779 and WO12172281.

Other CO ₂ removal methods are known from the prior art, for example WO15017357, WO12068588 and WO12162690, which use different CO ₂ removal methods.

US3616652 describes a method for liquefying natural gas, including flashing a stream while lowering the pressure to a low pressure level to form a low pressure liquid and a flashing gas, as well as recirculating the flashing gas in a loop configured to help cool natural gas at an upper pressure level. by indirect heat exchange with it.

The aim is to provide an alternative, more efficient method and system for cooling and liquefying a hydrocarbon-containing gas stream.

One or more of the above or other objects are achieved by a method for liquefying a natural gas feed stream, the method comprising at least the steps of:

a) providing a process feed stream (11) by mixing a natural gas feed stream (1) with a recycle stream (105),

b) compressing the process feed stream (11) and cooling the process feed stream (11) by the environment in the compression unit (20) to obtain a compressed process stream (25), the pressure (P ₂₅ ) of which is at least 120 bar, and the first temperature (T ₂₅ ) is below 40 ° C,

c1) obtaining the first separated stream (32) from the compressed process stream (25) and expanding the first separated stream (32) in the precooling expander (33) to obtain an expanded first separated stream (34), the second temperature of which is lower than the first temperature,

c2) cooling the remainder of the compressed process stream (31) in the first heat exchanger (40) with the expanded first separated stream (34) to obtain a pre-cooled process stream (41) and a heated first separated stream (42),

d1) obtaining a second separated stream (52) from the precooled process stream (41) and expanding the second separated stream (52) in an expander (53) to obtain an expanded and cooled multiphase second separated stream (54), the third temperature of which is below the second temperature,

d2) separating the expanded and cooled multiphase second separated stream (54) in a phase separator (55) to obtain a vapor stream (56) and a liquid stream (57),

d3) cooling the remainder of the pre-cooled compressed process stream (51) in a second heat exchanger (60) with a steam stream (56) to provide additional cooled process stream (61) and a heated vapor stream (62),

e) expanding the additional cooled process stream (61) to produce a liquid natural gas stream (71),

f) passing the heated first separated stream (42) and heated vapor stream (62) to a recompression unit (200), wherein a recirculation stream (105) is formed in the recompression unit (200).

By compressing the process feed stream until a relatively high pressure is reached in step b), i.e. a pressure of at least 120 bar, the liquefaction efficiency is improved since the relatively high pressure leads to a significant cooling (liquefaction) effect. The pressure of the compressed process stream can be in the range from 120 to 200 bar or in the range from 130 to 190 bar, preferably in the range from 145 to 175 bar, more preferably in the range from 155 to 165 bar.

Although the power consumed by the compression unit will be relatively high, this is offset by the reduced recycle flow and therefore reduces the recompression loads required to match the pressure in the recycle stream to that of the natural gas feed stream.

The first split stream (32), which functions as a precooled stream, also has a relatively high pressure due to the relatively high compression in step b). Consequently, the first separated stream 32 has a relatively high specific heat and therefore provides effective (pre) cooling in the first heat exchanger (40), and as a result, the first separated stream (32) can have a relatively low mass flow.

Consequently, the equipment costs associated with the recycle stream (compressors, pipes) will be relatively low.

In addition, since no separate refrigerants and refrigeration cycles are required, the volume of fluid handling is greatly reduced, further reducing costs.

The absence of refrigerants, in particular the absence of propane as a refrigerant (component), further contributes to the safety of the installation.

The pressure in step b) is significantly higher than the critical pressure (supercritical pressure), preferably at least 50 bar above the critical pressure, resulting in a relatively constant temperature profile in the first heat exchanger (40, step c2) for the compressed process stream (31) from - for a relatively constant heat capacity under supercritical conditions, in contrast to the pressure, which would be in the immediate vicinity of the critical point, at which the heat capacity changes with temperature are large.

This makes it possible to use a very small LMTD (mean logarithmic temperature difference), which reduces local temperature regimes and reduces the external generation of entropy (thermodynamic inefficiency). Since the specific heat is relatively stable under supercritical conditions, in particular at least 30 bar or at least 50 bar above the critical point, the temperature profiles are essentially straight lines (in the temperature versus heat (Q) diagram) , which reduces the temperature difference between hot and cold streams and thus reduces thermodynamic inefficiency.

A pressure close to the critical point would result in a divergence between the two heat exchange streams on the cold side of the heat exchanger, resulting in inefficiency, which means that the compressed process stream (31) is less precooled (i.e., as a result, the first heat exchanger (40) remains at a higher temperature).

The pre-cooling pressure, that is, the pressure of the expanded first split stream (34), is an optimized parameter. The lower pressure results in a colder expanded first split stream (34), but requires more recompression. Therefore, the optimum pre-cooling pressure can be determined iteratively. The pre-cooling pressure can be further adjusted during operation to accommodate changes in operating conditions such as changes in ambient temperature.

In the following, embodiments of the invention will be described with reference to the following non-limiting drawings:

in fig. 1 is a schematic diagram of a method according to an embodiment of the invention;

in fig. 2 is a schematic diagram of a method according to an alternative embodiment of the invention.

Two embodiments of the invention will be described below with reference to FIG. 1 and FIG. 2, each of which illustrates a different embodiment of the invention. Like reference numbers are used to indicate like elements in different figures.

First, a natural gas feed stream 1 is provided. The natural gas feed stream 1 can also be referred to as a hydrocarbon feed stream 1. The natural gas feed stream 1 mainly contains methane. Although the natural gas feed stream 1 is not particularly limited, it is preferably a methane-rich gaseous stream, preferably containing at least 50 mol%. methane, more preferably at least 80 mol%. and more preferably at least 95 mol%. methane.

The remainder of the natural gas feed stream 1 is mainly formed from hydrocarbon molecules containing two, three or four carbon atoms (ethane, propane, butane).

The natural gas feed stream 1 may be generated in a gas processing step that removes contaminants and C5 + molecules. As one skilled in the art will appreciate, the precise control of the gas processing step may depend on the gas composition upstream of the gas processing step and the characteristics of the liquid natural gas.

Contaminants and hydrocarbon molecules containing five or more carbon atoms are preferably removed upstream.

Preferably less than 1 mol%. the natural gas feed stream 1 is formed by pollutants and hydrocarbon molecules containing five or more carbon atoms after removal. Preferably, the natural gas feed stream 1 contains less than 0.15 mol%. hydrocarbon molecules containing five or more carbon atoms. The number of hydrocarbon molecules containing five or more carbon atoms can be in the range of 0.10-0.15 mol%.

Alternatively, contaminants and hydrocarbon molecules containing five or more carbon atoms can be removed between the first and second heat exchangers 40, 60 instead of being removed upstream.

The natural gas feed stream 1 preferably has a pressure in the range of 50 to 80 bar, more preferably in the range of 55 to 75 bar, for example 65 bar. The natural gas feed stream 1 preferably has a temperature in the range of 0-40 ° C, for example 17 ° C.

In a first step a) process feed stream 11 is formed by mixing / combining natural gas feed stream 1 with recycle stream 105 using combiner 2. Recycle stream 105 will be described in more detail below.

In accordance with an embodiment of the invention, the mass flow rate of the natural gas feed stream 1 (MF ₁ ) and the mass flow rate of the recycle stream 105 (MF ₁₀₅ ) are in the range MF ₁ : MF ₁₀₅ = [1: 2 - 1: 4], preferably substantially equal to 1: 3.

In step b), the process stream 11 is fed to a compression unit 20 to obtain a compressed process stream 25 having a pressure of at least 120 bar and a first temperature below 40 ° C. As indicated above, the pressure of the compressed process stream can be in the range from 120 to 200 bar or in the range from 130 to 190 bar, preferably from 145 to 175 bar, more preferably in the range from 155 to 165 bar.

In accordance with the embodiment of the invention illustrated in FIG. 2, the compression unit 20 includes a single compressor 21 with a corresponding intercooler 22 located downstream of the compressor 21.

In accordance with an embodiment of the invention, the compression unit 20 includes a multi-stage compressor with intercoolers. Compression unit 20 may include a multistage compressor 20 having any suitable number of compressors and intercoolers to achieve a given pressure and temperature.

As illustrated in FIG. 1, compressor step 20 may include a first compressor 21 to produce a process stream 11, followed by a first intercooler 22, a second compressor 23, and a second intercooler 24.

The intercooler (s) preferably cools the process stream at the expense of the environment, such as ambient air or ambient water.

In step c1), the compressed process stream 25 is fed to a first splitter 30 to produce a first separated stream 32. The first splitter 30 can be any suitable type of splitter, including a simple T- or Y-joint.

The first spacer 30 can also be a controllable spacer for actively controlling and adjusting the separated portion during operation. The controlled splitter may contain one or two variable valves downstream of the connection to control the split ratio.

The split ratio is defined as the mass flow rate of the separated stream 32 (MF ₃₂ ) divided by the mass flow rate of the compressed process stream 25 (MF ₂₅ ), MF ₃₂ : MF ₂₅ . Typically the split ratio is 0.5–0.65.

The first separated stream 32 is expanded and thus cooled in the pre-cooling expander 33. Typically, the expansion has a pressure ratio in the range of 4-6, for example 5 to provide sufficient cold to precool the rest of the compressed process stream 31. The pressure ratio is defined as the pressure (P ₃₂ ) upstream of the precooling expander 33 divided by the pressure ( P ₃₄ ) downstream of the precooling expander 33.

The expanded first separated stream 34 may have a pressure P ₃₄ in the range of 26-38 bar, preferably 29-35 bar, more preferably in the range 31-33 bar. Expanded first separated stream 34 typically has a temperature in the range of minus 60 ° C to minus 80 ° C, usually minus 70 ° C.

In step c2), the remainder of the compressed process stream 31 is fed to the warm side of the first heat exchanger 40 and the expanded first separated stream 34 is fed to the cold side of the first heat exchanger 40 to allow the two streams to exchange heat, in particular to allow the expanded first decoupled stream 34 to be preliminarily cool the rest of the compressed process stream 31.

The first heat exchanger 40 can be any type of suitable heat exchanger including a spiral heat exchanger or a plate (finned) heat exchanger. The first heat exchanger 40 may comprise a plurality of serial and / or parallel slave heat exchangers (not shown).

From the first heat exchanger 34, a precooled process stream 41 is obtained on the cold side, and a heated first separated stream 42 is obtained on the warm side. The heated first separated stream 42 is directed to a recompression unit 200 to be included in recycle stream 105, as will be described in more detail below.

The heated first separated stream 42 may have a temperature in the range of 0 ° C to 40 ° C, for example 15 ° C. The precooled process stream 41 can have temperatures ranging from minus 50 ° C to minus 70 ° C, such as minus 60 ° C.

The pre-cooled process stream 41 is passed to a second splitter 50 to produce a second separated stream 52.

The second spacer 50 can be any suitable type of spacer, including a simple T- or Y-shaped connection. The second spacer 50 may also be a controllable spacer for actively controlling and adjusting the second split portion during operation. The second controllable splitter 50 may include one or two variable valves located downstream of the connection to control the second split ratio.

The second split ratio is defined as the mass flow rate of the second split stream 52 (MF ₅₂ ) divided by the mass flow rate of the precooled process stream 41 (MF ₄₁ ), MF ₅₂ : MF ₄₁ .

Typically, the second split ratio is in the range of 0.75–0.85.

In step d1), the second split stream 52 is fed to an expander 53, such as a dense phase expander, to expand and thus cool the second split stream 52 to enter the two-phase zone, thereby producing an expanded and cooled multiphase second split stream 54. Cooled multiphase second separated stream 54 typically expands to pressures in the 5-20 bar range, eg 8-12 bar, and to a third temperature in the range of –110 ° C to –130 ° C.

Expander 53 may function as a dense phase expander, i.e., an expander 53 that is suitable to receive a pressurized supercritical stream at the inlet of expander 53 and is designed to discharge multiphase stream 54 through the outlet of expander 53. Multiphase stream 54 may be a two-phase stream containing a vapor / gaseous phase and liquid phase.

In step d2), the expanded and cooled multiphase second separated stream 54 is evaporated in a phase separator 55, thereby producing a separate vapor stream 56 and a liquid stream 57. The mass ratio of the steam stream MF ₅₆ to the mass ratio of the expanded and cooled multiphase second separated stream 54 (MF ₅₄ ) is typically in the range MF ₅₄ : MF ₅₆ = 0.3–0.4.

The phase separator 55 can be any suitable vapor-liquid separator, such as a flash drum or droplet separator.

In step d3), the remainder of the pre-cooled compressed process stream 51 is fed to the warm side of the second heat exchanger 60, and the steam stream 56 is fed to the cold side of the second heat exchanger 60 to allow heat exchange of both streams, in particular so that the vapor stream 56 can be further cooled the remainder of the pre-cooled compressed process stream 51. Thus, additional cooled process stream 61 and heated vapor stream 62 are obtained.

The heated vapor stream 62 may be directed to a recompression unit 200 and must be included in recycle stream 105, as will be described in more detail below.

In accordance with an embodiment of the invention, the heated vapor stream 62 is first directed to a first heat exchanger 40 and then directed to a recompression unit 200, as will be described in more detail below.

The second heat exchanger 60 can be any type of suitable heat exchanger including a spiral heat exchanger or a plate (finned) heat exchanger. The second heat exchanger 60 may comprise a plurality of serial and / or parallel slave heat exchangers (not shown).

The heated steam stream 62 can have a temperature T ₆₂ in the range from -65 ° C to -85 ° C and a pressure P ₆₂ in the range from 5 to 20 bar.

The precooled process stream 51 can enter the second heat exchanger 60 having a temperature T ₅₁ in the range from minus 60 ° C to minus 80 ° C, and the additionally cooled process stream 61 can leave the second heat exchanger 60 having a temperature T ₆₁ in the range from minus 110 ° C to minus 130 ° C and a pressure that is still essentially equal to the pressure of the compressed process stream 25, excluding the (unintentional) pressure drop resulting from the flow of the flow through the pipeline and the first and second heat exchangers. The further cooled process stream 61 may be in a supercritical dense phase in which there is no distinction between gas and liquid.

In step e), the additionally cooled process stream 61 is expanded in a liquid expander 70, resulting in a liquefied natural gas stream 71 having a pressure in the range of 8 to 15 bar, for example 10 bar, and a temperature equal to the boiling point of the mixture at this pressure (for example , about minus 125 ° C at 10 bar). The liquefied natural gas stream 71 can be fed to a flash tank 80, thereby producing liquefied natural gas at pressures in the 1-3 bar range, for example at atmospheric pressure. The flash tank 80 may be a storage tank. Alternatively, liquefied natural gas is passed from flash tank 80 to a subsequent storage tank.

In accordance with an embodiment of the invention, the method further comprises passing a liquefied natural gas stream 71 into a flash tank 80 and obtaining a liquefied natural gas feed stream 81 as a bottoms stream from a flash tank 80. The liquefied natural gas feed stream 81 may be passed to a storage tank liquefied natural gas (LNG), such as an LNG storage tank on an LNG ship / ship or floating LNG storage facility.

In accordance with an embodiment of the invention, the method includes obtaining a flash gas stream 82 as an overhead stream from a flash tank 80, passing a flash gas stream 82 to a recompression unit 200, optionally at least partially passing a flash gas stream 82 through a third a heat exchanger 75, 75 'for cooling at least a portion of the liquid stream 57 obtained in step d2).

By passing the flash gas stream through the third heat exchanger 75, a high quality cold is obtained, while it is still possible to cold compress the flash gas stream in a recompression unit, i.e. compression, without the need for an intercooler.

In accordance with an embodiment of the invention, as illustrated in FIG. 1, the method includes:

e1) dividing the flow of liquid 57 obtained in step d2) into a first part of liquid 71 and a second part of liquid 74,

e2) expanding the first portion of the liquid 71 in the first pressure reducing device 72 to produce a second stream 73 of liquefied natural gas; and

e3) cooling the second portion of the liquid 74 by passing the second portion of the liquid through a third heat exchanger 75 and a second pressure reducing device 78 to produce a third stream 76 of liquefied natural gas,

e4) collecting the liquefied natural gas stream obtained in step e), with a second liquefied natural gas stream 73 being obtained in step e2) and a third liquefied natural gas stream 76 obtained in step e3) in a flash tank 80.

The first pressure reducing device can be a (Joule-Thomson) valve or an expander. The second pressure reducing device can be a (Joule-Thomson) valve or an expander. In accordance with an embodiment of the invention, the first pressure reducing device is an expander and the second pressure reducing device is a Joule-Thomson valve.

This embodiment provides the advantage that the separation in step e1) allows control of the flow rate of the second liquid through the third heat exchanger and thus allows better matching of the heating curves in the third heat exchanger 75, resulting in a lower logarithmic mean temperature difference (LMTD) and therefore lower energy losses in the third heat exchanger 75. This provides a more energy efficient method.

The separation in step e1) can be a predetermined separation, for example, can provide a predetermined flow rate of the second part of the liquid through the third heat exchanger. Alternatively, the separation can be a controlled separation provided by a controllable splitter that provides controlled separation that can be actively controlled during operation.

The second liquefied natural gas stream 73 and the third liquefied natural gas stream 76 are usually at the same pressure, which is close to atmospheric (in the range of 1-1.25 bar) and at temperatures close to or at -161.5 ° C (in the range minus 160 to minus 162 ° C), although slight pressure / temperature differences may exist due to compositional differences.

In step e3), the second part of the liquid 74 is cooled in the third heat exchanger 75 by at least a portion of the flash gas stream 82, whereby a heated flash gas stream 77 is obtained and passed to the recompression unit 200.

The pressure of the third liquefied natural gas stream 76, which is a subcooled liquid, can be effectively reduced, preferably (close to) storage conditions, by a second pressure reducing device, such as a Joule-Thomson valve 78, thereby minimizing vapor flash.

In accordance with an embodiment of the invention, as illustrated in FIG. 2, the method includes:

e1 ') passing the liquid stream 57 obtained in step d2) through a third heat exchanger 75' and an expander 78 'to obtain an additional liquefied natural gas stream 76',

e2 ') collecting the liquefied natural gas stream from step e) and the additional liquefied natural gas stream 76' from step e1 ') in a flash tank 80.

Expander 78 'may more generally be a pressure reducing device such as a (Joule-Thomson) valve.

The additional liquefied natural gas stream 76 'may have a pressure in the range of 1 to 1.25 bar, such as 1.05 bar, and a temperature in the range of –160 to –162 ° C, such as –160.6 ° C.

The heated flash gas stream 77 may be at atmospheric pressure, such as 1 bar, and at temperatures ranging from minus 120 to minus 130 ° C, such as minus 125 ° C.

The pressure in the flash tank 80 is substantially equal to atmospheric pressure and the collected liquefied natural gas is at the boiling point.

In accordance with an embodiment of the invention, the heated vapor stream 62 obtained from the second heat exchanger 60 in step d3) is passed through the first heat exchanger 40 to cool the remainder of the compressed process stream 31, thereby obtaining additional heated vapor stream 43 before passing into a recompression unit 200.

In step f), heated first separated stream 43 and heated vapor stream 62 arising from expanded and cooled multiphase second separated stream 54 are combined to be included in recycle stream 105 in recompression unit 200.

In accordance with an embodiment of the invention, step f) comprises separately passing the heated first separated stream 42 and one of the heated vapor stream 62 and the additional heated vapor stream 43 to a recompression unit 200 to obtain a recycle stream 105.

The recompression unit 200 may be a multi-stage recompression unit. The first separated stream 42 and one of the heated vapor stream 62 and the additional heated vapor stream 43 are preferably fed to different stages (pressures) in the recompression unit 200.

If heated steam stream 43 is passed through first heat exchanger 40, it is additional heated steam stream 43 that is passed to recompression unit 200 and must be included in recycle stream 105. In the description below, reference will be made to additional heated steam stream 43, but should be understood that it may be heated steam stream 62 if heated steam stream 62 is not passed through the first heat exchanger 40.

In accordance with an embodiment of the invention, step f) further comprises passing a flash gas stream (82) or a heated flash gas stream 77 to a recompression unit 200.

The flash gas stream 82 or heated flash gas stream 77 is passed to the recompression unit separately from the heated first separated stream 42, heated vapor stream 62 and additional heated steam vapor 43. Flash gas stream 82 or heated flash gas stream 77, heated the first separated stream 42, heated vapor stream 62, or additional heated vapor stream 43 are preferably fed to different stages (pressures) in the recompression unit 200.

Consequently, the pressure levels of the various streams passed to the recompression unit (200) are separated.

By passing the heated first decoupled stream 42 separately from the heated vapor stream 62 and the additional heated vapor stream 43 contamination of the heated first decoupled stream 42 with nitrogen is prevented, thereby allowing fuel to pass more efficiently.

The recompressor 200 may include a plurality of recompressors in series, with each recompressor including one or more compressors 90, 93, 102.

The number of recompressors may be equal to the number of streams passed to the recompressor 200, for example three in accordance with the embodiment illustrated in FIG. 1.

One or more recompression units may include one or more associated intercoolers. Then, the recompression unit 200 may be referred to as an intercooled multiphase recompression unit.

In accordance with the embodiment of the invention illustrated in FIG. 1, the recompression unit 200 is a three-stage recompression unit 200 including three recompression stages in series, that is, a pre-recompression stage, an intermediate recompression stage, and a final recompression stage.

As illustrated in FIG. 1, the pre-recompression unit may include a first compressor 90 comprising two successive auxiliary compressors configured to receive a heated flash gas stream 77 and compress the heated flash gas stream 77, thereby producing a first re-compressed stream 91 at a temperature T ₉₁ in range from 15 to 20 ° C. The pressure P _{91 of the} first re-compressed stream is substantially equal to the pressure P _{43 of the} heated steam stream 43, for example in the range of 8-12 bar, for example 10 bar.

Since the inlet stream of the first compressor 90 is relatively cold (with the flash gas stream 82 typically at –162 ° C, and the heated flash gas stream 77 at approximately –120 ° C to –130 ° C), power requirements compressions are relatively low and an intercooler is not required.

The pre-compressed stream 91 and the additional heated vapor stream 43 (or heated vapor stream 62) are combined and supplied to the intermediate recompression unit as a combined stream 92.

The intermediate recompression unit includes an intermediate compressor 93 and a corresponding intercooler 97 located downstream of the intermediate compressor 93. The intermediate recompression unit is configured to receive combined stream 92 and subsequently recompress and cool the combined stream 92 to obtain intermediate compressed stream 98. usually having an intermediate pressure P ₉₈ in the range 25–35 bar, for example 32 bar. The stream 96 exiting the intermediate compressor 93 is usually at a temperature above 100 ° C and is cooled by the intercooler 97, typically to a temperature T ₉₈ in the range from 15 ° C to 25 ° C.

The intermediate compressed stream 98 and the heated first separated stream 42 are combined and supplied to the final recompression unit as an additional combined stream 101.

The final recompression unit includes a final compressor 102 and a corresponding intercooler 104 located downstream of the final compressor 102. The final recompression unit is configured to obtain an additional combined stream 101 and then recompress and cool the additional combined stream 101 to obtain a recycle stream 105 The recycle stream 105 typically has a pressure P ₁₀₅ substantially equal to the pressure of the natural gas feed stream 1, typically in the range 50 to 80 bar, more preferably in the range 55 to 75 bar, for example 65 bar.

In accordance with one embodiment of the invention, the method further comprises:

g) obtaining fuel stream 95 from an intermediate location of recompression unit 200, preferably upstream of the location where heated first separated stream 42 is supplied to recompression unit 200.

Preferably, the fuel stream 95 is obtained at an intermediate location where the nitrogen concentration is relatively high. Since the flash gas stream 77, 82 and vapor stream 56 contain a relatively high amount of nitrogen compared to the first separated stream 32, 42, fuel stream 95 is preferably obtained upstream of the location where the heated first separated stream 42 enters the multistage recompressor unit. 200.

Fuel stream 95 is preferably obtained as a side stream from stream 96 exiting intermediate compressor 93. Fuel stream 95 is obtained at an intermediate location between intermediate compressor 93 and corresponding intercooler 97.

This results in an efficient fuel stream having a relatively large amount of nitrogen and reduces the amount of nitrogen recirculated.

In accordance with the example, the method used operates as follows. The process feed stream 11 is obtained by mixing the natural gas feed stream 1 taken after the condensation temperature is reached to meet the C5 + specification (<0.1 mol%), with the recycle stream 105 having a ratio of about 1: 3. Compressor stage 20 (auxiliary compressor) consisting of two stages with intercooling increases the pressure from 65 bar to 160 bar. Process feed stream 11 is cooled by intercooler (s) to approximately 17 ° C using water as the cooling medium. The compressed process stream 25 thus obtained is split into two parts, the first separating stream 32 (0.57 wt. Fraction) and the rest of the compressed process stream (0.43 wt. Fraction).

The first split stream is expanded in a precooling expander 33, which is a 30 MW expander, with a pressure ratio of about 5. Thus, the expanded first split stream 34 is obtained to provide cooling for the rest of the compressed process stream. These streams exchange heat in the first heat exchanger 40. The temperature of the hot outlet stream reaches -75 ° C, and the cold outlet stream is directed to the re-compression unit 200.

The precooled process stream 41 is then divided into a second separated stream 52 (0.8 wt. Fraction), which is expanded to 10 bar in expander 53, whereby it is cooled to about minus 123 ° C, entering the two-phase zone, thus obtaining an expanded and a cooled multiphase second split stream 54.

The expanded and cooled multiphase second separated stream 54 is flashed in a high pressure separator 55 to produce a vapor stream 56 (0.34 mole fraction).

After high pressure separator 55, steam stream 56 is used to further cool the remainder of the precooled compressed process stream 51 in a second heat exchanger 60 to about -123 ° C. Steam stream 56 (now heated steam stream 62) then provides cold to the first heat exchanger 40.

Thus obtained additional cooled process stream 61, which is a low temperature high pressure stream, is expanded in a liquid expander 70 to storage conditions.

The liquid stream 57 obtained from the separator 55 is split into two streams. The first liquid portion or main stream 71 (0.89 w / w) is expanded through a first pressure reducing device, such as a liquid expander 72, while the second liquid portion 74 or less (0.19 w / w) is subcooled by the flow flash gas 82 in the third heat exchanger 75, and then depressurized by a second pressure reducing device, such as a Joule-Thompson valve 78, before it is passed to flash tank 80.

The flash gas stream 82, after cooling at least a portion of the liquid stream 57 in the third heat exchanger 75, is directed to a recompression unit 200. The heated flash gas stream 77 is sent to cold recompression. By using cold compression (2 stages), low consumption requirements are achieved and there is no need for intercoolers. The outlet temperature of the first compressor 90 increased to 17 ° C. The outlet stream of the first compressor 90 is mixed with an additional heated steam stream 43 at a pressure of 10 bar exiting the first heat exchanger 40, the combined stream 92 of which is compressed by the intermediate compressor 93 to an intermediate pressure of 32 bar. The stream 96 exiting the intermediate compressor 93 is then mixed with the heated first separated stream 42 and subsequently compressed to a supply pressure of 65 bar to form a recycle stream 105.

Simulations have shown that the method diagrams described with reference to FIG. 1 and 2 require a relatively small recycle stream 105, which greatly improves efficiency, which more than balances the use of the higher back-up pressures required in compressor step 200.

Simulations have shown that the embodiment described with reference to FIG. 1, provides a specific power consumption of 9.816 kWh / t / day (235.6 kWh / t). This corresponds to an LNG production of 3.4 Mtpa using a 100 MW gas turbine as a mechanical drive, assuming an availability of 95%.

A person skilled in the art will readily understand that many modifications can be made without departing from the scope of the invention. For example, it should be understood that compressor step 20, as illustrated in FIG. 1 may be used in the embodiment of FIG. 2 and vice versa. If the word "stage" or "stages" is used in this text, it should be understood that this is not done to indicate a specific order (in time). The steps can be applied in any suitable order, including their simultaneous application.

Claims (46)

1. A method for liquefying a natural gas feed stream (1), comprising at least the steps: a) providing a process feed stream (11) by mixing a natural gas feed stream (1) with a recycle stream (105), b) compressing the process feed stream and cooling the process feed stream (11) by the environment in the compression unit (20), resulting in a compressed process stream (25), the pressure (P25) of which is at least 120 bar, and the first temperature (T25) below 40 ° C, c1) obtaining the first separated stream (32) from the compressed process stream (25) and expanding the first separated stream (32) in the precooling expander (33) to obtain an expanded first separated stream (34), the second temperature of which is lower than the first temperature, c2) cooling the remainder of the compressed process stream (31) in the first heat exchanger (40) by the expanded first separated stream (34) to obtain a precooled process stream (41) and a heated first separated stream (42), d1) obtaining a second separated stream (52) from the precooled process stream (41) and expanding the second separated stream (52) in an expander (53) to obtain an expanded and cooled multiphase second separated stream (54), the third temperature of which is below the second temperature, d2) separating the expanded and cooled multiphase second separated stream (54) in a phase separator (55) to obtain a vapor stream (56) and a liquid stream (57), d3) cooling the remainder of the pre-cooled compressed process stream (51) in a second heat exchanger (60) with a steam stream (56) to provide additional cooled process stream (61) and a heated vapor stream (62), e) expanding the additional cooled process stream (61) to obtain a liquid natural gas stream (71), f) passing the heated first separated stream (42) and heated vapor stream (62) to a recompression unit (200), wherein a recirculation stream (105) is formed in the recompression unit (200). 2. A method according to claim 1, characterized in that the mass flow rate MF1 of the natural gas feed stream (1) and the mass flow rate MF105 of the recycle stream (105) are in the range MF1: MF105 = 1: 2 - 1: 4, preferably substantially , is equal to 1: 3. 3. A method according to any one of the preceding claims, characterized in that the method further comprises passing the liquefied natural gas stream (71) into a flash tank (80) and receiving a liquefied natural gas production stream (81) as a bottom stream from the flash tank (80) ... 4. A method according to claim 3, characterized in that the method comprises obtaining a flash gas stream (82) in the form of an overhead stream from a flash tank (80), passing a flash gas stream (82) to a recompression unit (200), when however, passing the flash gas stream (82) to the recompression unit (200) optionally includes passing the flash gas stream (82) at least partially through a third heat exchanger (75, 75 ') to provide cooling of at least a portion of the liquid stream (57 ) obtained in step d2). 5. The method according to claim 4, characterized in that the method comprises: e1) dividing the liquid stream (57) obtained in step d2) into a first liquid portion (71) and a second liquid portion (74), e2) expanding the first portion (71) of liquid in the first pressure reducing device (72) to obtain a second stream (73) of liquefied natural gas; and e3) cooling the second part (74) of the liquid by passing the second part of the liquid through the third heat exchanger (75) and the second device (78) to reduce the pressure to obtain the third stream (76) of liquefied natural gas, e4) collecting the liquefied natural gas stream from step e), the second liquefied natural gas stream (73) from step e2) and the third liquefied natural gas stream (76) from step e3) in a flash tank (80 ). 6. The method according to claim 4, characterized in that the method comprises: e1 ') passing the liquid stream (57) obtained in step d2) through a third heat exchanger (75') and a valve or expander (78 ') to obtain an additional stream (76') of liquefied natural gas, e2 ') collecting the liquefied natural gas stream from step e) and the additional liquefied natural gas stream (76') from step e1 ') in a flash tank (80). 7. A method according to any of the preceding claims, characterized in that the heated steam stream (62) obtained from the second heat exchanger (60) in step d3) is passed through the first heat exchanger (40) to provide cooling of the rest of the compressed process stream (31) to obtain additional heated vapor stream (43) before passing it to the recompression unit (200). 8. A method according to any one of the preceding claims, characterized in that step f) comprises separately passing the heated first separated stream (42) and one of the heated vapor stream (62) and additional heated vapor stream (43) to the recompression unit (200) to obtain a recirculation stream (105). 9. The method according to any one of claims. 4-6, characterized in that step f) further comprises passing a flash gas stream (82) or a heated flash gas stream (77) to a recompression unit (200). 10. A method according to any of the preceding claims, wherein the method further comprises: g) obtaining a fuel stream (95) from an intermediate location of the recompression unit (200), preferably upstream of the location where the heated first separated stream (42) is supplied to the recompression unit (200). 11. A system for liquefying a natural gas feed stream (1), comprising: - a compression unit (20) configured to receive a process feed stream (11) containing a natural gas feed stream (1) and a recycle stream (105), wherein the compression unit (20) is additionally configured to compress the process feed stream (11) and cooling the process feed stream (11) to obtain a compressed process stream (25) having a pressure (P25) of at least 120 bar and a first temperature (T25) below 40 ° C, - the first separator (30) configured to receive the compressed process stream (25) and output the first separated stream (32) and the rest of the compressed process stream (31), a pre-cooling expander (33) configured to receive and expand the first separated stream (32) to obtain an expanded first separated stream (34), the second temperature of which is lower than the first temperature, - the first heat exchanger (40) configured to receive the expanded first separated stream (34) and the rest of the compressed process stream (31) with subsequent cooling of the rest of the compressed process stream (31) due to the expanded first separated stream (34) to obtain a preliminary the cooled process stream (41) and the heated first separated stream (42), - a second separator (50) adapted to receive the pre-cooled process stream (41) and discharge the second separated stream (52) and the rest of the pre-cooled compressed process stream (51), - an expander (53) configured to receive and expand the second separated stream (52) to obtain an expanded and cooled multiphase second separated stream (54), the third temperature of which is below the second temperature, - a phase separator (55) configured to receive an expanded and cooled multiphase second separated stream (54) and release a vapor stream (56) and a liquid stream (57), - a second heat exchanger (60) configured to receive a steam stream (56) and the rest of the precooled compressed process stream (51) with subsequent cooling of the rest of the precooled compressed process stream (51) due to the steam flow (56) to obtain additional cooled process stream (61) and heated steam stream (62), - a liquid expander (70) configured to receive an additional cooled process stream (61) to obtain a liquefied natural gas stream (71), - a recompression unit (200) configured to receive, combine and recompress at least the heated first separated stream (42) and the heated vapor stream (62) to obtain a recycle stream (105). 12. The system according to claim 11, characterized in that the system further comprises an evaporation tank (80) configured to receive a liquefied natural gas stream (71), and the evaporation tank (80) is additionally configured to discharge a production stream (81) of a liquefied natural gas. 13. The system according to claim 12, characterized in that the flash tank (80) is configured to discharge the flash gas stream (82), the system comprises a flash gas pipe (82, 77) adapted to pass the flash gas stream (82 ) flashing gas to the recompression unit (200), the system optionally comprising a third heat exchanger (75, 75 ') configured to receive the flash gas stream (82) and at least a portion of the liquid stream (57), followed by cooling along at least a portion of the liquid stream (57) by the flash gas stream (82). 14. The system of claim 13, comprising: - an additional separator configured to receive a liquid stream (57) and divide the liquid stream (57) into a first part (71) of a liquid and a second part (74) of a liquid, - a first pressure reducing device (72) configured to receive and expand the first portion (71) of liquid to obtain a second stream (73) of liquefied natural gas, - the third heat exchanger (75), configured to receive the flow (82) of the flash gas and the second part (74) of the liquid, followed by the cooling of the second part (74) of the liquid and transfer of the second part (74) of the liquid to the second device (78) to reduce pressure to obtain the third stream (76) liquefied natural gas, wherein the flash tank (80) is further configured to receive a second liquefied natural gas stream (73) and a third liquefied natural gas stream (76). 15. The system according to claim 13, characterized in that the system comprises a third heat exchanger (75, 75 ') configured to receive a flash gas stream (82) and at least part of a liquid stream (57) with subsequent cooling of at least part of the liquid stream (57) due to the flow (82) of the flash gas, and the system further comprises a valve or expander (78 ') located downstream of the third heat exchanger (75') configured to receive at least part of the liquid stream from a third heat exchanger (75 ') to expand at least a portion of the liquid stream (57) to obtain an additional stream (76') of liquefied natural gas, moreover, the evaporation tank (80) is additionally configured to receive an additional stream (76 ') of liquefied natural gas.

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