US20190049174A1

US20190049174A1 - Method and system for liquefying a natural gas feed stream

Info

Publication number: US20190049174A1
Application number: US16/086,491
Authority: US
Inventors: Thijs GROENENDIJK; Carlos ARNAIZ DEL POZO
Original assignee: Shell Oil Company
Current assignee: Shell USA Inc
Priority date: 2016-03-21
Filing date: 2017-03-20
Publication date: 2019-02-14
Also published as: RU2018136794A3; AU2017237356B2; RU2730090C2; WO2017162566A1; EP3433556A1; CN108779953A; AU2017237356A1; RU2018136794A; CA3017839A1

Abstract

The invention relates to a method of liquefying a natural gas feed stream. A first split-off stream from a compressed process stream is expanded. A remainder of the compressed process stream is cooled against the expanded first split-off stream. A second split-off stream from the precooled process stream is expanded, while a remainder of the precooled compressed process stream is cooled against a vapour stream obtained from the second split-off stream. The further cooled process stream is expanded, thereby obtaining a liquid natural gas stream. The first split-off stream and the vapour stream are passed to a recompression stage to obtain a recycle stream to be combined with a natural gas feed stream to form the process stream.

Description

The present invention relates to a method and system for liquefying a natural gas feed stream.
Methods of liquefying hydrocarbon-containing gas streams are well known in the art. It is desirable to liquefy a hydrocarbon-containing gas stream such as natural gas stream for a number of reasons. As an example, natural gas can be stored and transported over long distances more readily as a liquid than in gaseous form, because it occupies a smaller volume and does not need to be stored at high pressures. Typically, before being liquefied, the contaminated hydrocarbon-containing gas stream is treated to remove one or more contaminants (such as H₂O, CO₂, H₂S and the like) which may freeze out during the liquefaction process.
Processes of liquefaction are known from the prior art in which one or more closed refrigerant cycles are used to cool and liquefy the hydrocarbon-containing gas stream. Examples are a C3-MR process or a DMR process. In a C3-MR process a first cooling stage uses propane as refrigerant and the second cooling stages uses a mixture of two or more refrigerants, such as a mixture of propane, ethane, methane and nitrogen. In a DMR process, two refrigerant cycles are used, each comprising a mixed refrigerant.
Alternative methods of liquefaction are known in which no separate refrigerant cycle is used.
WO2014/166925 describes a method of liquefying a contaminated hydrocarbon-containing gas stream, the method comprising at least the steps of:
(1) providing a contaminated hydrocarbon-containing gas stream;
(2) cooling the contaminated hydrocarbon-containing gas stream in a first heat exchanger thereby obtaining a cooled contaminated hydrocarbon-containing stream;
(3) cooling the cooled contaminated hydrocarbon-containing stream in an expander thereby obtaining a partially liquefied stream;
(4) separating the partially liquefied stream in a separator thereby obtaining a gaseous stream and a liquid stream;
(5) expanding the liquid stream obtained in step (4) thereby obtaining a multiphase stream, the multiphase stream containing at least a vapour phase, a liquid phase and a solid phase;
(6) separating the multiphase stream in a separator thereby obtaining a gaseous stream and a slurry stream (comprising solid CO2 and liquid hydrocarbons);
(7) separating the slurry stream in a solid/liquid separator thereby obtaining a liquid hydrocarbon stream and a concentrated slurry stream;
(8) passing the gaseous stream obtained in step (4) through the first heat exchanger thereby obtaining a heated gaseous stream; and
(9) compressing the heated gaseous stream thereby obtaining a compressed gas stream; and
(10) combining the compressed gas stream obtained in step (9) with the contaminated hydrocarbon-containing gas stream provided in step (1).
The method as described in WO2014/166925 allows liquefying a contaminated hydrocarbon-containing gas stream with a relatively low equipment count, without the need of a refrigerant cycle, thereby providing a simple and cost-effective method of liquefying a contaminated hydrocarbon-containing gas stream, in particular a methane-containing contaminated gas stream such as natural gas. The contaminant may be CO2.
The method according to WO2014/166925 uses a freeze out process scheme to remove CO2. In step (5) as described above, the process conditions in the liquid stream obtained in step (4) are just outside the CO2 freeze out envelope (the process conditions are for example 20 bar, −120° C., 1 mol % CO2) such that any further temperature reduction will provoke freeze out of CO2. The temperature reduction is achieved in step (5) by pressure reduction over a Joule Thomson valve. The pressure reduction evaporates part of the liquid methane, thus cooling the remaining liquid.
Further methods of liquefaction are for instance described in WO15110779 and WO12172281.
Other methods to remove CO2 are know from the prior art, such as WO15017357, WO12068588 and WO12162690 which use different ways to remove CO2.
U.S. Pat. No. 3,616,652 describes a process for liquefying natural gas comprising flashing the stream to a low pressure level to form a low pressure liquid and a flash gas and recirculating the flash gas in a circuit arranged to assist in the cooling of the natural gas at the upper pressure level by indirect heat exchange therewith.
It is an object to provide an alternative, more efficient method and system to cool and liquefy a hydrocarbon containing gas stream.
One or more of the above or other objects are achieved by a method of liquefying a natural gas feed stream, the method comprising at least the steps of:
(a) providing a process feed stream (11) by mixing the natural gas feed stream (1) with a recycle stream (105),
(b) compressing the process feed stream (11) and cooling the process feed stream (11) against ambient in a compressor stage (20), thereby obtaining a compressed process stream (25) having a pressure (P₂₅) of at least 120 bar and a first temperature (T₂₅) below 40° C.,
(c1) obtaining a first split-off stream (32) from the compressed process stream (25) and expanding the first split-off stream (32) in a precool expander (33), thereby obtaining an expanded first split-off stream (34), having a second temperature below the first temperature,
(c2) cooling a remainder of the compressed process stream (31) in a first heat exchanger (40) against the expanded first split-off stream (34), thereby obtaining a precooled process stream (41) and a warmed first split-off stream (42),
(d1) obtaining a second split-off stream (52) from the precooled process stream (41) and expanding the second split-off stream (52) in an expander (53), thereby obtaining an expanded and cooled multiphase second split-off stream (54), having a third temperature below the second temperature,
(d2) splitting the expanded and cooled multiphase second split-off stream (54) in a phase separator (55) to obtain a vapour stream (56) and a liquid stream (57),
(d3) cooling a remainder of the precooled compressed process stream (51) in a second heat exchanger (60) against the vapour stream (56), thereby obtaining a further cooled process stream (61) and a warmed vapour stream (62),
(e) expanding the further cooled process stream (61) thereby obtaining a liquid natural gas stream (71),
(f) passing the warmed first split-off stream (42) and the warmed vapour stream (62) to a recompression stage (200), the recompression stage (200) generating the recycle stream (105).
By compressing the process feed stream to a relatively high pressure in (b), i.e. to a pressure of at least 120 bar, the liquefaction efficiency is improved, as the relatively high pressure translates into a significant cooling (liquefaction) effect. The pressure of the compressed process stream may be in the range of 120-200 bar or in the range of 130-190 bar, preferably 145-175 bar, more preferably in the range of 155-165 bar.
Although the power consumed by the compressor stage will be relatively high, this is compensated by a reduced recycle stream and thus reduced recompression duties needed for getting the pressure of the recycle stream to match the pressure of the natural gas feed stream.
The first split-off stream (32), which functions as a pre-cooling stream, also has a relatively high pressure as a consequence of the relatively high compression in step (b). Consequently, the first split-off stream 32 has a relatively high specific heat capacity and therefore provides efficient (pre-)cooling in the first heat exchanger (40) and as a result the first split-off stream (32) may have a relatively low mass flow.
Consequently, the hardware costs associated to the recycle stream (compressors, pipes) will be relatively low.
Also, as no separate refrigerants and refrigerant cycles are required, the amount of liquid handling is significantly reduced, further reducing costs.
The absence of refrigerants, in particular the absence of propane as refrigerant (component), further contributes to the safety of the plant.
The pressure in step (b) is well above the critical pressure (supercritical pressure), preferably at least 50 bars above the critical pressure, which results in a relatively constant temperature profile in the first heat exchanger (40, step c2) for the compressed process stream (31), because of a relatively constant heat capacity at supercritical conditions, as opposed to a pressure that would be in the proximity of the critical point, where heat capacity variations with temperature are large.
This enables a very small LMTD (logarithmic mean temperature differences) reducing the local temperature approaches and reducing external entropic generation (thermodynamic inefficiency). Since the specific heat capacity is relatively constant at supercritical conditions, in particular at least 30 bars or at least 50 bars above the critical point, the temperature profiles are substantially straight lines (in a temperature vs heat (Q) diagram), reducing the temperature difference between hot and cold streams and thus reducing thermodynamic inefficiency.
A pressure close to the critical point would result in a divergence between the two heat exchanging streams at the cold of the heat exchanger, thereby resulting in inefficiencies, meaning that the compressed process stream (31) is less precooled (i.e. leaves the first heat exchanger (40) at a higher temperature).
The precooling pressure, i.e. the pressure of the expanded first split-off stream (34) is an optimized parameter. A lower pressure results in a colder expanded first split-off stream (34) but requires more recompression duty. The optimum precooling pressure may therefore be determined by an iterative process. The precooling pressure may further be adjusted during operation to take into account changes in operation conditions, such as a changing ambient temperature.

Hereinafter embodiments will be described with reference to the following non-limiting drawings:

FIG. 1 schematically shows a process scheme according to an embodiment,

FIG. 2 schematically shows a process scheme according to an alternative embodiment.

Below, two embodiments will be described with reference to FIG. 1 and FIG. 2 each showing a different embodiment. Same reference numbers are used to refer to similar items in the different figures.
First, a natural gas feed stream 1 is provided. The natural gas feed stream 1 may also be referred to as a hydrocarbon feed stream 1. The natural gas feed stream 1 mainly comprises methane. Although the natural gas feed stream 1 is not particularly limited, it preferably is a methane-rich gas stream, preferably comprising 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 primarily formed of hydrocarbon molecules comprising two, three or four carbon atoms (ethane, propane, butane).
The natural gas feed stream 1 may originate from a gas treatment stage in which the contaminants and C5+ molecules are removed. As will be understood by the skilled person, the exact line-up of the gas treatment stage may depend on the gas composition upstream of the gas treatment stage and the liquid natural gas specifications.
Contaminants and hydrocarbon molecules comprising five or more carbon atoms are preferably removed upstream.
Preferably less than 1 mol % of the natural gas feed stream 1 is formed by contaminants and hydrocarbon molecules comprising five or more carbon atoms after removal. Preferably, the natural gas feed stream 1 comprises less than 0.15 mol % hydrocarbon molecules comprising five or more carbon atoms. The amount of hydrocarbon molecules comprising five or more carbon atoms may be in the range of 0.10-0.15 mol %.
Alternatively, the contaminants and hydrocarbon molecules comprising five or more carbon atoms may be removed in between the first and second heat exchangers 40, 60, instead of upstream removal.
The natural gas feed stream 1 preferably has a pressure in the range of 50-80 bar, more preferably in the range of 55-75 bar, e.g. 65 bar. The natural gas feed stream 1 preferably has a temperature in the range of 0-40° C., e.g. 17° C.
In a first step (a), a process feed stream 11 is formed by mixing/combining the natural gas feed stream 1 with a recycle stream 105 by means of a combiner 2. The recycle stream 105 will be described in more detail below.
According to an embodiment, the mass flow rate of the natural gas feed stream 1 (MF₁) and the mass flow rate of the recycle stream 105 (MF₁₀₅) is in the range MF₁:MF₁₀₅=[1:2-1:4], preferably substantially equal to 1:3.
In step (b), the process stream 11 is passed to a compressor stage 20 to obtain a compressed process stream 25, having a pressure of at least 120 bars and a first temperature below 40° C. As indicated above, the pressure of the compressed process stream may be in the range of 120-200 bar or in the range of 130-190 bar, preferably 145-175 bar, more preferably in the range of 155-165 bar.
According to an embodiment, shown in FIG. 2, the compressor stage 20 comprises a single compressor 21 with an associated intercooler 22 positioned downstream of the compressor 21.
According to an embodiment, the compressor stage 20 comprises a multi-stage compressor with intercoolers. The compressor stage 20 may comprise a multi-stage compressor 20 having any suitable number of compressors and intercoolers to obtain the intended pressure and temperature.
As shown in FIG. 1, the compressor stage 20 may comprise a first compressor 21 to receive the process stream 11, subsequently followed by a first intercooler 22, a second compressor 23 and a second intercooler 24.
The intercooler(s) preferably cool(s) the process stream against ambient, such as against ambient air or ambient water.
In step (c1), the compressed process stream 25 is fed to a first splitter 30 to obtain a first split-off stream 32. The first splitter 30 may be any suitable type of splitter, including a simple T- or Y-junction.
The first splitter 30 may also be a controllable splitter to actively control and adjust the split-off portion during operation. The controllable splitter may comprise one or two controllable valves positioned downstream of the junction to control the split ratio.
The split ratio is defined as the mass flow of the split-off stream 32 (MF₃₂) divided by the mass flow of the compressed process stream 25 (MP₂₅), MF₃₂:MF₂₅. Typically, the split ratio is in the range of 0.5-0.65.
The first split-off stream 32 is expanded and thereby cooled in a precool expander 33. The expansion typically has a pressure ratio in the range of 4-6, e.g. 5, to provide sufficient cold to precool the remainder of the compressed process stream 31. The pressure ratio is defined as the pressure (P₃₂) upstream of the precool expander 33 divided by the pressure (P₃₄) downstream of the precool expander 33.
The expanded first split-off stream 34 may have a pressure P₃₄in the range of 26-38 bar, preferably 29-35 bar, more preferably in the range of 31-33 bar. The expanded first split-off stream 34 typically has a temperature in the range of minus 60°-minus 80° C., typically minus 70° C.
In step (c2), the remainder of the compressed process stream 31 is fed to a warm-side of a first heat exchanger 40 and the expanded first split-off stream 34 is fed to a cold-side of the first heat exchanger 40 to allow the two streams to exchange heat, in particular to allow the expanded first split-off stream 34 to precool the remainder of the compressed process stream 31.
The first heat exchanger 40 may be any type of suitable heat exchanger including a coil wound heat exchanger or a plate (fin) heat exchanger. The first heat exchanger 40 may comprise a plurality of serial and/or parallel sub-heat exchangers (not shown).
From the first heat exchanger 34 a precooled process stream 41 is obtained on the cold-side and a warmed first split-off stream 42 is obtained on the warm-side. The warmed first split-off stream 42 is forwarded to the recompression stage 200 to be comprised in the recycle stream 105 as will be described in more detail below.
The warmed first split-off stream 42 may have a temperature in the range of 0° C.-40° C., e.g. 15° C. The precooled process stream 41 may have a temperature in the range of minus 50° C.-minus 70° C., e.g. minus 60° C.
The precooled process stream 41 is passed to a second splitter 50 to obtain a second split-off stream 52.
The second splitter 50 may be any suitable type of splitter, including a simple T- or Y-junction. The second splitter 50 may also be a controllable splitter to actively control and adjust a second split-off portion during operation. The second controllable splitter 50 may comprise one or two controllable valves positioned downstream of the junction to control the second split ratio.
The second split ratio is defined as the mass flow of the second split-off stream 52 (MF₅₂) divided by the mass flow of the precooled process stream 41 (MF₄₁), MF₅₂:MF₄₁.
Typically, the second split ratio is in the range of 0.75-0.85.
In step (d1) the second split-off stream 52 is passed to an expander 53, e.g. a dense phase expander, to expand and thereby cool the second split-off stream 52 to enter the two phase region thereby obtaining an expanded and cooled multiphase second split-off stream 54. The cooled multiphase second split-off stream 54 is typically expanded to a pressure in the range of 5-20 bar, e.g. in the range 8-12 bar and to a third temperature in the range of minus 110° C.-minus 130 ° C.
The expander 53 may function as a dense phase expander, i.e. an expander 53 which is suitable to receive a pressurized supercritical flow at an inlet of the expander 53 and arranged to discharge a multiphase stream 54 via an outlet of the expander 53. The multiphase stream 54 may be a two phase stream comprising a vapour/gas phase and a liquid phase.
In step (d2), the expanded and cooled multiphase second split-off stream 54 is flashed in a phase separator 55 thereby obtaining a separate vapour stream 56 and a liquid stream 57. The mass ratio of the vapour stream MF₅₆to the mass ratio of the expanded and cooled multiphase second split-off stream 54 (MF₅₄) is typically in the range MF₅₄:MF₅₆=0.3-0.4.
The phase separator 55 may be any suitable vapour-liquid separator, such as a flash drum or knock-out vessel.
In step (d3) the remainder of the precooled compressed process stream 51 is fed to a warm-side of a second heat exchanger 60 and the vapour stream 56 is fed to a cold-side of the second heat exchanger 60 to allow the two streams to exchange heat, in particular to allow the vapour stream 56 to further cool the remainder of the precooled compressed process stream 51. Thereby, a further cooled process stream 61 and a warmed vapour stream 62 are obtained.
The warmed vapour stream 62 may be forwarded to the recompression stage 200 to be comprised in the recycle stream 105 as will be described in more detail below.
According to an embodiment, the warmed vapour stream 62 is first forwarded to the first heat exchanger 40 and then forwarded to the recompression stage 200, as will be described in more detail below.
The second heat exchanger 60 may be any type of suitable heat exchanger including a coil wound heat exchanger or a plate (fin) heat exchanger. The second heat exchanger 60 may comprise a plurality of serial and/or parallel sub-heat exchangers (not shown).
The warmed vapour stream 62 may have a temperature T₆₂in the range of minus 65° C.-minus 85° C. and a pressure P₆₂in the range of 5-20 bar.
The precooled process stream 51 may enter the second heat exchanger 60 having a temperature T₅₁in the range of minus 60° C.-minus 80° C. and the further cooled process stream 61 may leave the second heat exchanger 60 having a temperature T₆₁in the range of minus 110° C.-minus 130° C. and a pressure which is still substantially equal to the pressure of the compressed process stream 25, except for a (undeliberate) pressure drop resulting from flowing through the piping and 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 further cooled process stream 61 is expanded in a liquid expander 70 thereby obtaining a liquid natural gas stream 71 having a pressure in the range of 8-15 bar, e.g. 10 bar, and a temperature equal to the boiling temperature of the composition at that pressure (e.g. approximately minus 125° C. at 10 bar). The liquid natural gas stream 71 may be passed to a flash vessel 80 thereby obtaining liquid natural gas at a pressure in the range of 1-3 bar, e.g. atmospheric pressure. Flash vessel 80 may be a storage vessel. Alternatively, the liquid natural gas is passed from flash vessel 80 to a subsequent storage vessel.
According to an embodiment the method further comprises passing the liquid natural gas stream 71 to a flash vessel 80 and obtaining a liquid natural gas product stream 81 as bottom stream from the flash vessel 80. The liquid natural gas product stream 81 may be passed to a LNG storage tank such as a LNG storage tank on a LNG carrier vessel/ship or floating LNG facility.
According to an embodiment the method comprises obtaining a flash gas stream 82 as top stream from the flash vessel 80, passing the flash gas stream 82 to the recompression stage 200, wherein the flash gas stream 82 is optionally at least partially passed through a third heat exchanger 75, 75′ to provide cooling to at least part of the liquid stream 57 obtained in (d2).
By passing the flash gas stream through a third heat exchanger 75, high quality cold is recovered while cold compression of the flash gas stream in the recompression stage, i.e. compression without the need of an intercooler, is still possible.
According to an embodiment, as depicted in FIG. 1, the method comprises
(e1) splitting the liquid stream 57 obtained in (d2) into a first liquid portion 71 and a second liquid portion 74,
(e2) expanding the first liquid portion 71 in a first pressure reduction device 72 to obtain a second liquid natural gas stream 73, and
(e3) cooling the second liquid portion 74 by passing the second liquid portion through the third heat exchanger 75 and a second pressure reduction device 78 to obtain a third liquid natural gas stream 76,
(e4) collecting the liquid natural gas stream obtained in (e), the second liquid natural gas stream 73 obtained in (e2) and the third liquid natural gas stream 76 obtained in (e3) in the flash vessel 80.
The first pressure reduction device may be a (Joule-Thomson) valve or an expander. The second pressure reduction device may be a (Joule-Thomson) valve or an expander. According to an embodiment, the first pressure reduction device is an expander and the second pressure reduction device is a Joule-Thomson valve.
This embodiment provides the advantage that the splitting in (e1) makes it possible to control the flow rate of the second liquid portion through the third heat exchanger and thereby allows for a better matching of the heating curves in the third heat exchanger 75, yielding a lower logarithmic mean temperature difference (LMTD) and hence lower exergy losses in the third heat exchanger 75. This provides a more energy efficient method.
The splitting in (e1) may be a predetermined split, e.g. may provide for a predetermined flow rate of the second liquid portion through the third heat exchanger. Alternatively, the splitting may be a controllable split provided by a controllable splitter, which provides for an adjustable split, which can be controlled actively during operation.
The second liquid natural gas stream 73 and the third liquid natural gas stream 76 are typically at the same pressure, being close to atmospheric (in the range 1-1.25 bar) and at a temperature close to or at −161.5° C. (in the range minus 160-minus 162° C.), although small difference in pressure/temperature may exist due to differences in composition.
In step (e3) the second liquid portion 74 is cooled in the third heat exchanger 75 against at least part of the flash gas stream 82, thereby obtaining a warmed flash gas stream 77, which is passed to the recompression stage 200.
The third liquid natural gas stream 76, which is a sub-cooled liquid, can effectively be reduced in pressure, preferably (close) to storage conditions with the second pressure reduction device, e.g. Joule-Thomson valve 78, minimizing the flashing of vapour.
According to an embodiment, as depicted in FIG. 2, the method comprises
(e1′) passing the liquid stream 57 obtained in (d2) through the third heat exchanger 75′ and an expander 78′ to obtain a further liquid natural gas stream 76′,
(e2′) collecting the liquid natural gas stream obtained in (e) and the further liquid natural gas stream 76′ obtained in (e1′) in the flash vessel 80.
Expander 78′ may more generally be a pressure reduction device, such as a (Joule-Thomson) valve.
Further liquid natural gas stream 76′ may have a pressure in the range of 1-1.25 bar, e.g. 1.05 bar, and a temperature in the range minus 160-minus 162° C., e.g. minus 160.6° C.
The warmed flash gas stream 77 may be at atmospheric pressure, e.g. 1 bar, and at a temperature in the range of minus 120-minus 130° C., e.g. minus 125° C.
The pressure in the flash vessel 80 is substantially equal to atmospheric pressure and the collected liquid natural gas is at its boiling point.
According to an embodiment, the warmed vapour stream 62 obtained from the second heat exchanger 60 in (d3) is passed through the first heat exchanger 40 to provide cooling to the remainder of the compressed process stream 31 thereby obtaining a further warmed vapour stream 43 before being passed to the recompression stage 200.
In step (f) the warmed first split-off stream 43 and the warmed vapour stream 62 originating from the expanded and cooled multiphase second split-off stream 54 are combined to be comprised in the recycle stream 105 in the recompression stage 200.
According to an embodiment, (f) comprises separately passing the warmed first split-off stream 42 and one of the warmed vapour stream 62 and the further warmed vapour stream 43 to the recompression stage 200 to obtain the recycle stream 105.
The recompression stage 200 may be a multi-stage re-compressor stage. The first split-off stream 42 and one of the warmed vapour stream 62 and the further warmed vapour stream 43 are preferably fed to different (pressure) stages of the recompression stage 200.
In case the warmed vapour stream 43 is passed through the first heat exchanger 40, it is the further warmed vapour stream 43 that is passed to the recompression stage 200 to be comprised in the recycle stream 105. In the description below reference will be made to the further warmed vapour stream 43, but it will be understood that this may be the warmed vapour stream 62 in case the warmed vapour stream 62 is not passed through the first heat exchanger 40.
According to an embodiment, (f) further comprises passing the flash gas stream (82) or the warmed flash gas stream 77 to the recompression stage 200.
The flash gas stream 82 or warmed flash gas stream 77 is passed to the recompression stage separately from the warmed first split-off stream 42, the warmed vapour stream 62 and the further warmed vapour stream 43. The flash gas stream 82 or warmed flash gas stream 77, the warmed first split-off stream 42, the warmed vapour stream 62 or the further warmed vapour stream 43 are preferably fed to different (pressure) stages of the recompression stage 200.
Consequently, the pressure levels of the different streams passed to the recompression stage 200) are decoupled.
By passing the warmed first split-off stream 42 separately from the warmed vapour stream 62 and the further warmed vapour stream 43, pollution of the warmed first split-off stream 42 with nitrogen is prevented, allowing a more efficient fuel bleed.
The recompression stage 200 may comprise a number of recompression stages positioned in series, each recompression stage comprising one or more compressors 90, 93, 102.
The number of recompression stages may be equal to the number of streams being passed to the recompression stage 200, e.g. three according to the embodiment depicted in FIG. 1.
One or more recompression stages may comprise one or more associated intercoolers. The recompression stage 200 may then be referred to as an intercooled multi-stage re-compressor stage.
According to the embodiment depicted in FIG. 1, the recompression stage 200 is a three-stage recompressor stage 200 comprising three recompression stages positioned in series, i.e. a pre-recompression stage, an intermediate recompression stage and a final recompression stage.
As depicted in FIG. 1, the pre-recompression stage may comprise a first compressor 90 comprising two serial sub-compressors, arranged to receive the warmed flash gas stream 77 and compress the warmed flash gas stream 77 thereby obtaining a first recompressed stream 91 having a temperature T₉₁in the range of 15° C.-20° C. The pressure P₉₁of the first recompressed stream is substantially equal to the pressure P₄₃of the warmed vapour stream 43, e.g. in the range of 8-12 bar, e.g. 10 bar.
As the inlet stream of the first compressor 90 is relatively cold (flash gas stream 82 typically having a temperature of −162° C. and warmed flash gas stream 77 typically having a temperature of approximately minus 120° C.-minus 130° C.) compression power requirements are relatively low and no intercooler may be needed.
The pre-compressed stream 91 and the further warmed vapour stream 43 (or warmed vapour stream 62) are combined and are fed to the intermediate recompression stage as combined stream 92.
The intermediate recompression stage comprises an intermediate compressor 93 and associated intermediate intercooler 97 positioned downstream of the intermediate compressor 93. The intermediate recompression stage is arranged to receive the combined stream 92 and further recompress and cool the combined stream 92 to obtain intermediate compressed stream 98 typically having an intermediate pressure P₉₈in the range of 25-35 bar, e.g. 32 bar. The stream 96 leaving intermediate compressor 93 typically has a temperature of above 100° C. and is cooled by intercooler 97 typically to a temperature T₉₈in the range of 15° C.-25° C.
Intermediate compressed stream 98 and warmed first split-off stream 42 are combined and are fed to the final recompression stage as further combined stream 101.
The final recompression stage comprises a final compressor 102 and associated intercooler 104 positioned downstream of the final compressor 102. The final recompression stage is arranged to receive the further combined stream 101 and further recompress and cool the further combined stream 101 to obtain recycle stream 105. The recycle stream 105 typically has a pressure Plos substantially equal to the pressure of the natural gas feed stream 1, typically in the range of 50-80 bar, more preferably in the range of 55-75 bar, e.g. 65 bar.
According to an embodiment, the method further comprises
(g) obtaining a fuel stream 95 from an intermediate position of the recompression stage 200, preferably upstream of the position at which the warmed first split-off stream 42 is fed to the recompression stage 200.
Preferably, the fuel stream 95 is obtained at an intermediate position at which the nitrogen concentration is relatively high. As the flash gas stream 77, 82 and the vapour stream 56 contain a relatively high amount of nitrogen compared to the first split- off stream 32, 42, the fuel stream 95 is preferably obtained upstream from the position at which the warmed first split-off stream 42 enters the multi-stage re-compressor unit 200.
The fuel stream 95 is preferably obtained as a side stream of stream 96 leaving intermediate compressor 93. The fuel stream 95 is obtained at an intermediate position in between the intermediate compressor 93 and associated intermediate intercooler 97.
This results in an effective fuel stream having a relatively high amount of nitrogen and reduces the amount of nitrogen being recycled.
According to an example, the method in use with function as follows. The process feed stream 11 is obtained by mixing the natural gas feed stream 1, taken after dew pointing to meet the C5+ specification (<0.1% mol) with recycle stream 105 in a ratio of approximately 1:3. A (booster) compressor stage 20, comprising two stages with intercooling rises the pressure from 65 bar to 160 bar. The process feed stream 11 is cooled down by the intercooler(s) to approximately 17° C. using water as a cooling media. The thereby obtained compressed process stream 25 is split in two fractions, the first split-off stream 32 (0.57 mass fraction) and a remainder of the compressed process stream (0.43 mass fraction).
The first split-off stream is expanded in the precool expander 33, being a 30 MW expander, with a pressure ration of approximately 5. Thereby the expanded first split-off stream 34 is obtained to provide cold for the remainder of the compressed process stream. These streams exchange heat in the first heat exchanger 40. The hot outlet reaches −75° C. and the cold outlet is directed to the recompression stage 200.
The precooled process stream 41 is subsequently split into a second split-off stream 52 (0.8 mass fraction), which is expanded to 10 bar in expander 53, thereby cooling itself to approximately minus 123° C., entering the two phase region thereby obtaining the expanded and cooled multiphase second split-off stream 54. The expanded and cooled multiphase second split-off stream 54 is flashed in a high pressure separator 55 to obtain the vapour stream 56 (0.34 mole fraction).
After the high pressure separator 55, the vapor stream 56 is employed to further cool the remainder of the precooled compressed process stream 51 in the second heat exchanger 60 to approximately −123 ° C. Subsequently, the vapor stream 56 (now being warmed vapour stream 62) provides cold in the first heat exchanger 40.
The thereby obtained further cooled process stream 61, being a high pressure low temperature stream, is expanded in a liquid expander 70 to storage conditions.
The liquid stream 57 obtained from the separator 55 is split into two. The first liquid portion or main stream 71 (0.89 mass fraction) is expanded through a first pressure reduction device, for instance liquid expander 72, whereas the second liquid portion 74 or minor fraction (0.19 mass fraction) is subcooled against the flash gas stream 82 in third heat exchanger 75 and subsequently let down in pressure with a second pressure reduction device, such as a J-T valve 78 before being passed to the flash vessel 80.
The flash gas stream 82, after having cooled at least part of the liquid stream 57 in the third heat exchanger 75, is forwarded to the recompression stage 200. The warmed flash gas stream 77 is directed to cold recompression. By use of cold compression (2 stages), low duty requirements are achieved and there is no need for intercoolers. The outlet temperature of the first compressor 90 has risen to 17° C. The outlet stream of the first compressor 90 is mixed with the 10 bar further warmed vapour stream 43 coming out of the first heat exchanger 40 which combined stream 92 is compressed by intermediate compressor 93 to an intermediate pressure of 32 bar. Next, the stream 96 leaving intermediate compressor 93 is mixed with the warmed first split-off stream 42 and successively compressed to feed pressure level of 65 bar to form the recycle stream 105.
Simulations have shown that process schemes as described with reference to FIGS. 1 and 2 need a relatively small recycle stream 105 which greatly improves efficiency, which more than balances the cost of higher boosting pressures needed by the compressor stage 200.
The simulations have shown that the embodiment described with reference to FIG. 1 allows for a specific power consumption of 9.816 kW/tpd (235.6 kWh/ton). This corresponds to a LNG production of 3.4 mpta using a 100 MW gas turbine as mechanical drive, assuming 95% availability.
The person skilled in the art will readily understand that many modifications may be made without departing from the scope of the invention. For instance, it will be understood that the compressor stage 20 as shown in FIG. 1 may be used in the embodiment of FIG. 2 and vice versa. Where the word step or steps is used in this text, it will be understood that this is not done to imply a specific order (in time). The steps may be applied in any suitable order, including simultaneously.

Claims

1. A method of liquefying a natural gas feed stream, the method comprising at least the steps of:

(a) providing a process feed stream by mixing the natural gas feed stream with a recycle stream,

(b) compressing the process feed stream and cooling the process feed stream against ambient in a compressor stage, thereby obtaining a compressed process stream having a pressure of at least 120 bar and a first temperature below 40° C.,

(c1) obtaining a first split-off stream from the compressed process stream and expanding the first split-off stream in a precool expander, thereby obtaining an expanded first split-off stream, having a second temperature below the first temperature,

(c2) cooling a remainder of the compressed process stream in a first heat exchanger against the expanded first split-off stream, thereby obtaining a precooled process stream and a warmed first split-off stream,

(d1) obtaining a second split-off stream from the precooled process stream and expanding the second split-off stream in an expander, thereby obtaining an expanded and cooled multiphase second split-off stream having a third temperature below the second temperature,

(d2) splitting the expanded and cooled multiphase second split-off stream in a phase separator to obtain a vapour stream and a liquid stream,

(d3) cooling a remainder of the precooled compressed process stream in a second heat exchanger against the vapour stream, thereby obtaining a further cooled process stream and a warmed vapour stream,

(e) expanding the further cooled process stream thereby obtaining a liquid natural gas stream,

(f) passing the warmed first split-off stream and the warmed vapour stream to a recompression stage, the recompression stage generating the recycle stream.

2. The method according to claim 1, wherein the mass flow rate of the natural gas feed stream (MF₁) and the mass flow rate of the recycle stream (MF₁₀₅) is in the range MF₁:MF₁₀₅=1:2-1:4.

3. The method according to claim 1, wherein the method further comprises the step of passing the liquid natural gas stream to a flash vessel and obtaining a liquid natural gas product stream as bottom stream from the flash vessel.

4. The method according to claim 3, wherein the method comprises the step of obtaining a flash gas stream as top stream from the flash vessel, passing the flash gas stream to the recompression stage.

5. The method according to claim 17, wherein the method comprises the steps of:

(e1) splitting the liquid stream obtained in (d2) into a first liquid portion and a second liquid portion,

(e2) expanding the first liquid portion in a first pressure reduction device to obtain a second liquid natural gas stream, and

(e3) cooling the second liquid portion by passing the second liquid portion through the third heat exchanger and a second pressure reduction device to obtain a third liquid natural gas stream,

(e4) collecting the liquid natural gas stream obtained in (e), the second liquid natural gas stream obtained in (e2) and the third liquid natural gas stream obtained in (e3) in the flash vessel.

6. The method according to claim 17, wherein the method comprises the steps of:

(e1′) passing the liquid stream obtained in (d2) through the third heat exchanger and a valve or an expander to obtain a further liquid natural gas stream,

(e2′) collecting the liquid natural gas stream obtained in (e) and the further liquid natural gas stream obtained in (e1′) in the flash vessel.

7. The Method according to claim 1, wherein the warmed vapour stream obtained from the second heat exchanger in (d3) is passed through the first heat exchanger to provide cooling to the remainder of the compressed process stream thereby obtaining a further warmed vapour stream before being passed to the recompression stage.

8. The method according to claim 1, wherein (f) comprises separately passing the warmed first split-off stream and one of the warmed vapour stream and the further warmed vapour stream to the recompression stage to obtain the recycle stream.

9. The method according to claim 4, wherein (f) further comprises passing the flash gas stream or the warmed flash gas stream to the recompression stage.

10. The method according to claim 1, wherein the method further comprises:

(g) obtaining a fuel stream from an intermediate position of the recompression stage.

11. A system for liquefying a natural gas feed stream, the system comprising:

a compressor stage being arranged to receive a process feed stream comprising the natural gas feed stream and a recycle stream, the compressor stage further being arranged to compress the process feed stream and cool the process feed stream to obtain a compressed process stream having a pressure of at least 120bar and a first temperature below 40° C.,

a first splitter arranged to receive the compressed process stream and output a first split-off stream and a remainder of the compressed process stream,

a precool expander arranged to receive and expand the first split-off stream to obtain an expanded first split-off stream, having a second temperature below the first temperature,

a first heat exchanger arranged to receive the expanded first split-off stream and the remainder of the compressed process stream thereby cooling the remainder of the compressed process stream against the expanded first split-off stream obtaining a precooled process stream and a warmed first split-off stream,

a second splitter arranged to receive the precooled process stream and discharge a second split-off stream and a remainder of the precooled compressed process stream,

an expander arranged to receive and expand the second split-off stream thereby obtaining an expanded and cooled multiphase second split-off stream, having a third temperature below the second temperature,

a phase separator arranged to receive the expanded and cooled multiphase second split-off stream and discharge a vapour stream and a liquid stream,

a second heat exchanger arranged to receive the vapour stream and the remainder of the precooled compressed process stream thereby cooling the remainder of the precooled compressed process stream against the vapour stream obtaining a further cooled process stream and a warmed vapour stream,

a liquid expander arranged to receive the further cooled process stream obtaining a liquid natural gas stream, and

a recompression stage arranged to receive, combine and recompress at least the warmed first split-off stream and the warmed vapour stream to obtain the recycle stream.

12. The system according to claim 11, wherein the system further comprises a flash vessel arranged to receive the liquid natural gas stream, the flash vessel further being arranged to discharge a liquid natural gas product stream.

13. The system according to claim 12, wherein the flash vessel is arranged to discharge a flash gas stream, the system comprising a flash gas conduit arranged to pass the flash gas stream to the recompression stage.

14. The system according to claim 19, comprising:

a further splitter arranged to receive the liquid stream and split the liquid stream into a first liquid portion and a second liquid portion,

a first pressure reduction device arranged to receive and expand the first liquid portion to obtain a second liquid natural gas stream,

the third heat exchanger being arranged to receive the flash gas stream and the second liquid portion thereby cooling the second liquid portion and forwarding the second liquid portion to a second pressure reduction device to obtain a third liquid natural gas stream,

wherein the flash vessel is further arranged to receive the second liquid natural gas stream and the third liquid natural gas stream.

15. The system according to claim 19, wherein the third heat exchanger is arranged to receive the flash gas stream and at least part of the liquid stream, thereby cooling the at least part of the liquid stream against the flash gas stream, the system further comprising a valve or an expander positioned downstream of the third heat exchanger arranged to receive the at least part of the liquid stream from the third heat exchanger to expand the at least part of the liquid stream thereby obtaining a further liquid natural gas stream,

wherein the flash vessel is further arranged to receive the further liquid natural gas stream.

16. The method according to claim 1, wherein the mass flow rate of the natural gas feed stream (MF₁) and the mass flow rate of the recycle stream (MF₁₀₅) is MF₁:MF₁₀₅=1:3.

17. The method according to claim 4, wherein passing the flash gas stream to the recompression stage comprises passing the flash gas stream at least partially through a third heat exchanger to provide cooling to at least part of the liquid stream obtained in (d2).

18. The method according to claim 10, wherein the fuel stream is obtained upstream of the position at which the warmed first split-off stream is fed to the recompression stage.

19. The system according to claim 13, further comprising a third heat exchanger arranged to receive the flash gas stream and at least part of the liquid stream thereby cooling the at least part of the liquid stream against the flash gas stream.