RU2622212C2 - Method and device for removing nitrogen from cryogenic hydrocarbon composition - Google Patents

Abstract

FIELD: chemistry.

SUBSTANCE: nitrogen is removed from the cryogenic hydrocarbon composition. The cryogenic hydrocarbon composition is divided into a first portion and a second portion having the same composition and phase as the first portion. The first part is fed to a desorption column of nitrogen operating at a desorption pressure, from which a nitrogen-depleted liquid is discharged. The second portion is fed to a nitrogen-depleted liquid or to a liquid hydrocarbon product stream or process steam that is produced from nitrogen-depleted liquid by performing at least a pressure-depletion stage of the nitrogen-depleted liquid to a flash point that is lower than the desorption pressure. The second portion bypasses the nitrogen desorption column between the flow division and the supply of the second portion to the nitrogen-depleted liquid, or the liquid hydrocarbon product stream, or process steam.

EFFECT: reducing the size of the installation and increasing the reliability.

20 cl, 2 dwg

Description

The present invention relates to a method and apparatus for removing nitrogen from a cryogenic hydrocarbon composition.

Liquefied natural gas (LNG) is an economically important example of such a cryogenic hydrocarbon composition. Natural gas is a useful source of fuel, as well as a source of various hydrocarbon compounds. The liquefaction of natural gas in a natural gas liquefaction plant at or near a source of a natural gas stream is often desirable for a number of reasons. For example, natural gas can be more easily stored and transported over long distances in the form of a liquid, rather than in a gaseous form, since it will occupy a smaller volume and will not require storage under high pressure.

WO 2011/009832 describes a method for treating a multiphase hydrocarbon stream obtained from natural gas, in which lower boiling components, such as nitrogen, are separated from the multiphase hydrocarbon stream to produce a liquefied natural gas stream with a lower content of such lower boiling components. Two sequential gas-liquid separators operating at different pressures are used. A multiphase hydrocarbon stream is fed into the first gas-liquid separator at a first pressure. The bottoms stream from the first gas-liquid separator enters the second gas-liquid separator, which provides steam at a second pressure that is lower than the first pressure. The steam is compressed in the head stream compressor, and returned to the first gas-liquid separator as a stripping steam stream.

The disadvantage of the method and device described in WO 2011/009832 is that two large gas-liquid separators are required.

The present invention provides a method for removing nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase, which comprises:

- providing a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase;

- supplying a first stream of nitrogen stripper feed at a stripping pressure to a nitrogen stripping column containing at least one internal stripping section located inside the nitrogen stripping column, said first nitrogen stripping feed stream comprising a first portion of said cryogenic hydrocarbon composition;

- removal of nitrogen-depleted liquid from the region of the collection of the nitrogen desorption column located under the desorption section;

- obtaining at least a stream of liquid hydrocarbon product and process steam from a nitrogen-depleted liquid, comprising at least a step of depressurizing the nitrogen-depleted liquid to an instantaneous vapor pressure that is lower than the desorption pressure;

- compressing said process steam to at least a desorption pressure, thereby obtaining compressed steam;

- passing a stream of stripping steam into said nitrogen stripping column at a level lower down from said stripping section, said stream of stripping steam containing at least a stripping portion of said compressed steam;

- the allocation of the vapor fraction containing the withdrawn fraction of the steam overhead obtained from the head of the specified column desorption of nitrogen, in the form of exhaust gas;

- dividing the cryogenic hydrocarbon composition stream into said first part and second part having the same composition and phase as the first part;

- pressure relief of the second part to the specified pressure instantaneous evaporation;

- supplying the second part to at least one stream from the group consisting of: a nitrogen-depleted liquid, a liquid hydrocarbon product, and process steam; moreover, from the specified division of the flow to the specified feed of the second part, the second part bypasses the specified column of nitrogen desorption.

In another aspect, the present invention provides a device for removing nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase, which contains:

- a cryogenic feed line connected to a source of a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase;

- a nitrogen desorption column in fluid communication with the cryogenic feed line, said nitrogen desorption column comprising at least one internal desorption section located inside the nitrogen desorption column;

- a steam discharge line of the overhead steam, communicating with the nitrogen desorption column through the head region inside the nitrogen desorption column;

- the discharge line of a nitrogen-depleted liquid in communication with the collection area located inside the nitrogen desorption column downward from the desorption section;

- an intermediate pressure relief device in the discharge line of a nitrogen-depleted liquid in fluid communication with a nitrogen desorption column configured to receive a nitrogen-depleted liquid from an area of the collector of a nitrogen desorption column and relieve pressure of a nitrogen-depleted liquid, said intermediate pressure relief device being located at the interface between the desorption pressure side including the nitrogen desorption column and the flash side;

- a line of liquid hydrocarbon product located on the pressure side of instantaneous evaporation to divert a stream of liquid hydrocarbon product obtained from a nitrogen-depleted liquid;

- a process steam line located on the pressure side of flash flash to receive process steam obtained from a nitrogen-depleted liquid;

- a process compressor located in the line of process steam configured to receive process steam and compress process steam to create compressed steam at the outlet of the process compressor, said process compressor being at a specified interface between the desorption pressure side and the flash side;

- a line of stripping steam in fluid communication with the nitrogen stripping column at a level lower down from the stripping section and configured to receive at least the stripping portion of said compressed steam from the process compressor;

- a feed stream divider located in the cryogenic feed line, configured to divide the cryogenic hydrocarbon composition into a first part and a second part having the same composition and phase as the first part;

- a first feed line for transporting a first portion from a feed stream divider to a nitrogen desorption column;

- a second feed line for transporting a second part from the feed stream divider to at least one line from the group consisting of: a line of a nitrogen-depleted liquid, a line of a liquid hydrocarbon product, and a process steam line, said second feed line bypassing a nitrogen desorption column.

Further in this document, the invention will be further illustrated by way of examples and with reference to the drawings, in which:

in FIG. 1 is a schematic flow diagram of a process representing a method and apparatus including an embodiment of the invention; and

in FIG. 2 is a schematic flow diagram of a process representing a method and apparatus including another embodiment of the invention.

In these figures, the same reference numerals will be used to mean the same or similar parts. In addition, one reference position will be used to designate a channel or line, as well as a stream transported along that line.

The present invention relates to the removal of nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase. The cryogenic hydrocarbon composition is divided into the first part and the second part having the same composition and phase as the first part. The first part is fed to a nitrogen desorption column operating at a desorption pressure, from which a nitrogen-depleted liquid is withdrawn. The second part is fed to a nitrogen-depleted liquid or to a liquid hydrocarbon product stream or to process steam, which are obtained from a nitrogen-depleted liquid by performing at least the stage of depressurizing the nitrogen-depleted liquid to an instantaneous vapor pressure that is lower than the desorption pressure. The stripping steam stream is fed to a nitrogen stripping column, the stripping steam stream containing at least a stripping portion of the process steam after being compressed.

The second part bypasses the nitrogen desorption column between dividing the stream and feeding the second part to a nitrogen-depleted liquid and / or liquid hydrocarbon product stream and / or process steam.

In this case, the liquid load of the nitrogen desorption column is reduced compared to the case when the entire supply of the cryogenic hydrocarbon composition is supplied to the nitrogen desorption column, while at the same time a sufficient amount of liquid can be stored in the nitrogen desorption column to facilitate effective desorption using a stream of desorption steam. Therefore, the nitrogen desorption column can be made smaller than in the case described in WO 2011/009832, in which the first gas-liquid separator receives the entire multiphase hydrocarbon stream to be processed.

Using the solution of the present invention, the amount of nitrogen remaining in the resulting liquid hydrocarbon product stream can be kept below a certain maximum standard nitrogen content, with not all cryogenic hydrocarbon composition passing through the nitrogen desorption column. The liquid hydrocarbon product stream can be stored and transported at its cryogenic temperature and approximately atmospheric pressure.

The proposed solution also leads to the formation of an exhaust gas consisting of a vapor fraction containing a vented overhead vapor fraction obtained from the head of a nitrogen desorption column. The vapor fraction may contain a significant amount of nitrogen, possibly from 50 mol% to 95 mol% of nitrogen. However, this vapor fraction can still be used as a fuel gas stream, preferably at a fuel gas pressure not exceeding the desorption pressure.

Preferably, the off-gas is consumed at a fuel gas pressure not exceeding the stripping pressure. This eliminates the need for a special fuel gas compressor. In addition, by selecting a desorption pressure at a pressure higher than the fuel gas pressure, any compression applied to the process steam has an additional related advantage, such as adding enthalpy to the process steam, which allows it to be used as a stripping steam.

It is believed that the method and apparatus of the present invention are most advantageous when the cryogenic hydrocarbon composition contains from 1.5 mol%, preferably from 1.8 mol% to 5 mol% of nitrogen. Existing alternative approaches may also work adequately when the nitrogen content is below about 1.8 mol% and / or below about 1.5 mol%.

The proposed method and device is particularly suitable for use in combination with a hydrocarbon liquefaction system, such as a natural gas liquefaction system, in order to remove nitrogen from the crude liquefied product that is formed in the hydrocarbon liquefaction system. It was found that even when the crude liquefied product (or cryogenic hydrocarbon composition) contains a sufficiently high amount of nitrogen, from 1 mol.% (Or from about 1 mol.%) To 5 mol.% (Or up to about 5 mol.%) Formed as a result, the liquid hydrocarbon product may correspond to a nitrogen content that is within the range of standards from 0.5 to 1 mol.% nitrogen. The rest of the nitrogen is discharged as part of the vapor fraction in the exhaust gas, together with a controlled amount of methane.

The figure 1 shows a device comprising an embodiment of the invention. The cryogenic feed line 8 is in fluid communication with the nitrogen desorption column 20 through the first inlet system 21.

Upstream of the cryogenic feed line 8, a liquefaction system 100 may be provided. The liquefaction system 100 functions as a source of a cryogenic hydrocarbon composition. The liquefaction system 100 is in fluid communication with a cryogenic feed line 8 through a main pressure relief system 5, which communicates with the liquefaction system 100 through a crude liquefied product line 1. In the shown embodiment, the main pressure relief system 5 consists of a dynamic device, such as a turboexpander 6, and a static device, such as a Joule-Thomson valve 7, but other options are possible.

The first feed line 10 connects the cryogenic feed line 8 to the first inlet system 21 of the nitrogen desorption column 20 through a feed stream divider 9 located between the cryogenic feed line 8 and the first feed line 10.

The second feed line 11 is connected to its upstream side with a splitter 9 of the feed stream. This second feed line 11 bypasses the nitrogen desorption column 20, as will be further explained below. The feed stream divider 9 is configured to divide the cryogenic hydrocarbon composition, which passes along the cryogenic feed line 8, into a first part that enters the first feed line 10, and a second part that enters the second feed line 11. An advantage of the second feed line 11 and the feed stream divider 9 is that the nitrogen desorption column 20 may be smaller than when the cryogenic feed line 8 and the first feed line 10 would be directly connected without a divider, as a result, the entire cryogenic hydrocarbon composition would enter the nitrogen desorption column 20 through the first inlet system 21.

The bypass flow control valve 15 is located in the second feed line 11. The bypass flow control valve is operatively connected to the FC flow regulator provided in the first feed line 10. The flow controller FC is configured to maintain the flow rate of the first part through the first feed line 10 at a predetermined target flow rate by adjusting the ratio of the division into the first and second parts of the cryogenic hydrocarbon composition flowing through the cryogenic feed line 8.

The nitrogen desorption column 20 comprises an internal desorption section 24 located inside the nitrogen desorption column 20. The steam removal line 30 of the overhead steam is connected to the nitrogen desorption column 20 through the head portion 26 inside the nitrogen desorption column 20. The nitrogen depleted liquid discharge line 40 communicates with the nitrogen desorption column 20 through a collection region 28 inside the nitrogen desorption column 20, which is located downward from the desorption section 24.

The nitrogen desorption column 20 may comprise means for enhancing vapor / liquid contact to enhance separation of components and nitrogen removal. Depending on the permissible amount of nitrogen in the nitrogen-depleted liquid and the amount of nitrogen in the cryogenic feed line 8, a total of 2 to 8 theoretical stages may be necessary. In one particular embodiment, 4 theoretical steps were required. Such contact reinforcing means may be provided in the form of trays and / or nozzles, in the form of either a structured or unstructured nozzle. At least a portion of the vapor / liquid contact enhancing means respectively forms part of the internal desorption section 24.

An intermediate pressure relief device 45 is located in the discharge line 40 of the nitrogen-depleted liquid and thus is in fluid communication with the nitrogen desorption column 20. The intermediate pressure relief device 45 is operatively connected to an LC level controller that interacts with a region 28 of the collector of the nitrogen desorption column 20.

An intermediate pressure relief device 45 is located at the interface between the desorption pressure side including the nitrogen desorption column 20 and the flash side. The flash side includes a liquid hydrocarbon product line 90 configured to divert a liquid hydrocarbon product stream obtained from a nitrogen-depleted liquid 40, and a process steam line 60 configured to receive a process vapor obtained from a nitrogen-depleted liquid 40. C using the divider 9 of the feed stream and the second feed line 11, which were briefly described above, the cryogenic feed line 8 is connected to at least one group line s consisting of: exhaust line 40 depleted liquid nitrogen, line 90 of the liquid hydrocarbon product 60 and process steam lines. Preferably, the second feed line 11 does not pass through any indirect heat exchanger that functions to indirectly exchange heat with any process stream.

In the embodiment shown, the flash side further comprises a cryogenic storage tank 210 connected to the liquid hydrocarbon product line 90, for storing the liquid hydrocarbon product stream, an optional flash gas supply line 230 and an optional flash flash separator 50.

If such an end flash separator 50 is provided, such as, for example, in the embodiment of FIG. 1, the second feed line 11 suitably feeds the flash instant separator 50. In addition, such an end flash separator 50 may be in fluid communication with a nitrogen desorption column 20 through an intermediate pressure relief device 45 and a nitrogen depleted liquid discharge line 40. The final flash evaporator 50 may also be connected to a cryogenic storage tank 210 through a liquid hydrocarbon product line 90. A cryogenic pump 95 may be present in the liquid hydrocarbon product line 90 to facilitate transporting the liquid hydrocarbon product to the cryogenic storage tank 210.

Process steam line 60, as shown in the embodiment of FIG. 1 may be coupled to an optional flash end separator 50 via flash steam line 64 and a flash steam control valve 65, as well as to a cryogenic storage tank 210 through optional flash gas supply line 230. An advantage of the latter compound is that it allows the use of at least a portion of the stripping gas from the cryogenic tank 210 as part of the process steam.

In addition, process compressor 260 is provided at the interface between the desorption pressure side and the flash side. Preferably, process compressor 260 is driven by an electric motor. Process compressor 260 is located in line 60 of process steam for receiving process steam and for compressing process steam. The compressed steam discharge line 70 is in fluid communication with the outlet 261 of the process compressor 260. Suitably, the process compressor 260 may be equipped with an anti-surge controller and recirculate cooler, which are used when the process compressor is in recycle mode and during start-up (not shown in drawing).

The stripping steam line 71 is in fluid communication with the nitrogen stripping column 20 through a second inlet system 23 located at a level lower vertically from the stripping section 24 and preferably above the collection area 28. A stripping steam line 71 is connected to a compressed steam discharge line 70 through an optional bypass divider 79. A stripping steam valve 75 is provided in the stripping steam line 71.

Optionally, an external stripping steam supply line 74 is provided in fluid communication with the second inlet system 23 of the nitrogen stripping column 20. In one embodiment, as shown in FIG. 1, an optional external stripping steam supply line 74 is connected to a compressed steam discharge line 70. An external desorbing steam flow control valve 73 is provided in an optional external desorbing steam supply line 74. In one embodiment, an optional external stripping steam supply line 74 is respectively connected to a hydrocarbon steam line in or upstream of the liquefaction system 100.

The combustion device 220 is configured to receive at least the fuel portion of the steam from the overhead lead line 30. The combustion device may include multiple combustion units and / or it may include, for example, one or more of the following devices: furnace, boiler, incinerator, dual-fuel diesel engine, or combinations thereof. A boiler and a dual-fuel diesel engine can be connected to an electric generator.

The steam recirculation line 87 is optionally configured to receive at least a steam recirculation portion of the steam from the overhead line 30. The steam recirculation line 87 bypasses the nitrogen desorption column 20, and provides a reverse supply to at least one of the lines of the group consisting of: the liquid hydrocarbon product line 90 and the process steam line 60. The steam recirculation flow control valve 88 is preferably provided in the steam recirculation line 87. The advantage of the proposed line 87 steam recirculation is that it allows you to selectively increase the nitrogen content in the stream 90 of the liquid hydrocarbon product. If an optional flash flash separator 50 is provided, the steam recirculation line 87 suitably feeds the flash flash separator 50.

Optionally, the nitrogen desorption column 20 contains an internal distillation section 22 in addition to the internal desorption section 24. The internal distillation section 22 is located inside the nitrogen desorption column 20 higher vertically than the desorption section 24. The first inlet system 21 is located vertically between the internal distillation section 22 and the internal desorption section 24. The head part 26 is formed by the area inside the nitrogen desorption column 20 upward from the distillation section 22.

The optional internal distillation section 22 may include vapor / liquid contact enhancing means similar to those found in the internal desorption section 24 to enhance separation of components and nitrogen removal.

Typically, the nitrogen desorption column 20 interacts with a condenser to create a downward flow of liquid through the internal desorption section 24 and / or an optional internal distillation section 22. For example, in FIG. 1, the condenser is provided as a head overhead condenser 35 external to the desorption column 20 nitrogen, whereas in figure 2 it is provided as an integrated internal overhead condenser 235, which is made inside the head portion 26 in the nitrogen desorption column 20.

Such a condenser can advantageously be used to re-condensate at least a portion of the compressed process steam from the compressed steam discharge line 70. For example, in the embodiment of FIG. 1, the overhead condenser 35 is located on the overhead steam withdrawal line 30. Inside the overhead condenser 35, the overhead steam can be brought into indirect heat exchange contact with the auxiliary refrigerant stream 132, as a result of which heat is transferred from the overhead steam to the auxiliary refrigerant stream in an amount of cold flow. The auxiliary refrigerant flow control valve 135 is provided in the auxiliary refrigerant line 132.

A cold capacity controller 34 may be provided to control cold performance, which is the degree to which heat is transferred from the overhead steam to the auxiliary refrigerant stream. Accordingly, the cold capacity controller 34 is configured to control cold performance in response to an indicator of the calorific value of the off-gas relative to the heat demand. In the shown embodiment, the cold capacity controller 34 is configured as a pressure controller PC and an auxiliary refrigerant flow control valve 135, which are functionally connected to each other.

Referring again to FIG. 1, the overhead separator 33 is located on the downstream side of the overhead steam withdrawal line 30. The steam overhead line 30 is unloaded into the head overhead separator 33. The overhead separator 33 is configured to separate any non-condensed vapor fraction from any condensed overhead vapor fraction. The steam fraction discharge line 80 is configured to discharge the vapor fraction.

Suitably, a combustion device 220 is provided at the downstream end of the steam fraction discharge line 80 for receiving at least a fuel portion from the vapor fraction in the steam fraction discharge line 80. Suitably, the configuration of the optional steam recirculation line 87 includes an optional steam fraction divider 89, which may be provided in the steam fraction line 80, providing controlled fluid communication between the steam fraction line 80 and the steam recirculation line 87.

The cold recovery heat exchanger 85 may be provided in the steam fraction discharge line 80 to maintain the cold present in the steam fraction 80 by heat exchange with the cold recovery stream 86 before supplying the steam fraction 80 to any combustion device.

In one embodiment, the cold recovery stream 86 may comprise or consist of a side stream originating from a hydrocarbon feed stream in a hydrocarbon feed line 110 of the liquefaction system 100. The resulting cooled side stream may, for example, be combined with a cryogenic hydrocarbon composition in a cryogenic feed line 8. Thus, heat transfer for cold recovery in the cold recovery heat exchanger 85 complements the performance of the cryogenic hydrocarbon composition. In another embodiment, the cold recovery stream 86 may comprise or consist of overhead steam in the overhead steam withdrawal line 30, preferably a portion of the overhead steam withdrawal line 30 through which the overhead steam flows from the nitrogen desorption column 20 to the overhead condenser 35. In this case, the performance required from the auxiliary refrigerant stream 132 in the overhead condenser 35 can be reduced.

The reverse irrigation system is configured to allow at least a portion 36 of the reverse irrigation from the condensed fraction to the nitrogen desorption column 20 at a level above the distillation section 22. In the embodiment of FIG. 1, the reverse irrigation system includes a condensed fraction discharge line 37 connected in fluid with the bottom of the overhead separator 33, an optional reverse irrigation pump 38 provided in the condensed fraction discharge line 37, and an optional divider 39 ensirovannoy fraction. An optional condensed fraction divider 39 fluidly couples the condensed fraction withdrawal line 37 to a nitrogen desorption column 20 through a reverse irrigation part line 36 and a reverse irrigation inlet system 25, and an optional liquid recirculation line 13. An optional liquid recirculation line 13 is in fluid communication with a liquid hydrocarbon product line 90. A fluid communication means that the liquid recirculation line 13 is connected to any suitable place from which at least a portion of the liquid recirculation part can flow to the liquid hydrocarbon product line 90, while remaining in the liquid phase. Thus, the liquid recirculation line 13 can, for example, be directly connected to one or more elements selected from the group consisting of: nitrogen desorption column 20, cryogenic feed line 8, first feed line 10, second feed line 11, line 40 discharge nitrogen depleted liquid, optional final separator 50 instantaneous evaporation and line 90 of the liquid hydrocarbon product. A recirculation valve 14 is provided in an optional liquid recirculation line 13. An optional back-irrigation valve 32, functionally controlled by a back-irrigation flow regulator (not shown), may preferably be provided in the back-irrigation part line 36.

The liquid recirculation line 13 is in fluid communication with the liquid hydrocarbon product line 90, preferably via a recirculation path that does not pass through the distillation section 22, if provided. Thus, the liquid recirculation line 13 helps to avoid supplying too much liquid to the distillation section 22 and to prevent the recirculation liquid from passing through the distillation section 22. This is useful in order to avoid imbalance in the nitrogen desorption column 20.

An optional bypass divider 79 is in fluid communication with the overhead steam discharge line 30, preferably on the side upstream of the overhead condenser 35, if one is provided. For this, an optional steam bypass line 76 may be provided between the optional bypass divider 79 and the steam overhead line 30 of the overhead. A steam bypass control valve 77 is preferably provided in the steam bypass line 76. The advantage of such a steam bypass line 76 is that when there is an excess of process steam, it can be treated together with the off-gas in the steam fraction discharge line 80 without disturbing the material balance in the nitrogen desorption column 20. The steam bypass line 76 suitably extends along the bypass between the bypass divider 79 and the steam overhead line 30 on the side of the overhead from the upstream side of the overhead condenser 35. A bypass route passes between the bypass divider 79 and the steam removal line 30 of the overhead and / or the steam fraction discharge line 80. A bypass does not pass through the internal desorption section 24 in the nitrogen desorption column 20. Thus, it is possible to avoid the passage of the non-desorbing portion through the internal desorption section 24, which helps to avoid imbalance in the nitrogen desorption column 20.

The liquefaction system 100 in the present description has so far been presented very schematically. It may be any suitable hydrocarbon liquefaction system and / or process, in particular any natural gas liquefaction process producing liquefied natural gas, and the invention is not limited to the particular choice of a liquefaction system. Examples of suitable liquefaction systems employ single-circuit refrigerant refrigeration processes (typically single-circuit mixed refrigerant refrigeration — SMR processes such as PRICO described by KR Johnsen and P. Christiansen “LNG Production on floating platforms” presented at the Gastech 1998 conference in Dubai). but it is also possible to use a single-component refrigerant process, such as, for example, the BHP-cLNG process, also described in the aforementioned work by KR Johnsen and P. Christiansen); dual-circuit refrigerant cooling processes (for example, the often used mixed refrigerant-propane process with the frequent abbreviation C3MR, described, for example, in US Pat. No. 4,440,408, or, for example, mixed-refrigerant dual-circuit cooling processes, DMR, an example of which is described in US 6658891, or, for example, processes with two circuits in which each refrigerant circuit contains a single component refrigerant); and processes based on three or more compressor sequences for three or more cooling circuits, an example of which is described in US Pat. No. 7,114,351.

Other examples of suitable liquefaction systems are described in patents: US 5832745 (Shell SMR); US 6295833 and US 5657643 (both are Black & Veatch SMR variants); US 6,370,910 (Shell DMR). Another suitable example of a DMR process is the so-called Axens LIQUEFIN process, described, for example, in an article by PY Martin et al entitled “LIQUEFIN: AN INNOVATIVE PROCESS TO REDUCE LNG COSTS” presented at the 22nd World Gas Conference in Tokyo, Japan ( 2003). Other suitable three-loop processes are described, for example, in US Pat. Nos. 6,962,060; WO 2008/020044; US 7127914; DE3521060A1; US 5669234 (commercially known as optimized cascade process); US 6253574 (commercially known as cascaded mixed refrigerant process); US 6308531; in the publication of application US 2008/0141711; Mark J. Roberts et al, "Large Capacity Single Train AP-X (TM) Hybrid LNG Process", Gastech 2002, Doha, Qatar (October 13-16, 2002). These references are provided to demonstrate the broad applicability of the invention, and are not an exclusive and / or exhaustive list of possibilities.

Preferably, but not necessarily, any compressor that is part of the hydrocarbon liquefaction process in the liquefaction system, in particular any refrigerant compressor, is driven by one or more electric motors, without mechanical actuation of any steam and / or gas turbine. Such a compressor can be driven solely by one or more electric motors. Not all examples above use electric motors as drives for refrigerant compressors. It should be understood that any drives other than electric motors can be replaced with an electric motor to benefit most from the present invention.

An example in which the liquefaction system 100 is based, for example, on C3MR or Shell DMR, is briefly illustrated in Figure 2. It uses a cryogenic heat exchanger 180, in this case in the form of a spiral heat exchanger containing lower and upper bundles (181 and 182, respectively) pipes for the hydrocarbon product, the lower and upper bundles (183 and 184, respectively) of pipes for light mixed refrigerant (LMR) and a bundle of 185 pipes for heavy mixed refrigerant (HMR).

The lower and upper bundles 181 and 182 of pipes for the hydrocarbon product fluidly couple the crude liquefied product line 1 to the hydrocarbon feed line 110. At least one pre-cooling heat exchanger 115 for the chilled hydrocarbon may be provided in the hydrocarbon feed line 110 upstream of the cryogenic heat exchanger 180.

The primary refrigerant in the form of mixed refrigerant is supplied to the primary refrigerant circuit 101. The main refrigerant circuit 101 contains an exhaust refrigerant line 150 connecting the cryogenic heat exchanger 180 (in this case, the annular zone 186 of the cryogenic heat exchanger 180) to the main suction side of the main refrigerant compressor 160, and a compressed refrigerant line 120 connecting the outlet of the main refrigerant compressor 160 with MR separator 128 (mixed refrigerant separator). One or more heat exchangers are provided in a compressed refrigerant line 120 including, in the present example, at least one heat exchanger 124 using an ambient temperature coolant and at least one pre-cooling heat exchanger 125 with cooled main refrigerant. The MR separator 128 is in fluid communication with the lower tube bundle 183 for the LMR through the light mixed refrigerant line 121, and with the tube bundle for the HMR through the heavy mixed refrigerant line 122.

At least one pre-cooling heat exchanger 115 of the cooled hydrocarbons and at least one pre-cooling heat exchanger 125 of the cooled main refrigerant are cooled by the pre-cooling refrigerant (along lines 127 and 126, respectively). The same pre-refrigerant can be transferred from the same cycle to the pre-refrigerant. In addition, at least one pre-cooling heat exchanger 115 for a chilled hydrocarbon and at least one pre-cooling heat exchanger 125 with a cooled main refrigerant can be combined into one pre-cooling heat exchanger (not shown). Reference is made to US Pat. No. 6,370,910 as a non-limiting example.

The optional external stripping steam supply line 74 (if provided) may suitably be connected to the hydrocarbon feed line 110, or at a point upstream of at least one pre-cooling cooled hydrocarbon exchanger 115, downstream of at least one heat exchanger 115 pre-cooling the cooled hydrocarbons, or (for example, if it is possible to provide two or more heat exchangers pre-cooling the cooled hydrocarbons) between two successive heat exchangers pre-cooling the cooled hydrocarbons, to obtain part of the flow of hydrocarbon feed from line 110 of the hydrocarbon feed.

At the transition point between the upper (182, 184) and lower (181, 183) tube bundles, the HMR tube bundle 185 is in fluid communication with the HMR line 141 in which the 144 HMR control valve is provided. The HMR line 141 is in fluid communication with the annulus 186 of the cryogenic heat exchanger 180 and, through said annulus 186 and in the heat exchange configuration, with each one of the lower pipe bundle 181 for the hydrocarbon product, the lower pipe bundle 183 for the LMR and the pipe bundle 185 for HMR, with a line of 150 spent refrigerant.

Above the upper tube bundles 182 and 184, near the upper part of the cryogenic heat exchanger 180, the tube bundle 184 for the LMR is in fluid communication with the LMR line 131. The first LMR return line 133 establishes a fluid communication between the LMR line 131 and the annulus 186 of the cryogenic heat exchanger 180. An LMR control valve 134 is provided in the first LMR return line 133. The first LMR return line 133 is in fluid communication with the spent refrigerant line 150 through said annulus 186, and in a heat exchange configuration with each one of the upper and lower bundles 182 and 181 of the hydrocarbon product tubes, and each one of the bundles 183 and 184 pipes for LMR, and a bunch of 185 pipes for HMR.

In FIG. 2 shows one possible source of auxiliary refrigerant. The LMR line 131 is divided into the auxiliary refrigerant line 132 and the first LMR return line 133. The second LMR return line 138 at its upstream end is fluidly connected to the auxiliary refrigerant line 132 through the overhead condenser (which may be in the form of an internal overhead overhead condenser 235), and at the downstream end, the second the LMR return line 138 is ultimately connected to the spent refrigerant line 150, respectively, through the first HMR line 141.

The lines around the nitrogen desorption column 20 in FIG. 2 are similar to the lines shown in FIG. 1 and will not be described in detail again. Optional lines including an optional liquid recirculation line 13, an optional external stripping steam supply line 74, an optional steam bypass line 76 and an optional steam recirculation line 87 may be provided, but were not shown in FIG. 2 for purposes of clarity.

One of the differences that should be noted when comparing the embodiment of FIG. 2 with the embodiment of FIG. 1 is that the overhead condenser 35, the overhead separator 33, and the reverse irrigation system were implemented as an integrated internal overhead condenser 235, known in areas of technology. If necessary, an optional liquid recirculation line 13 can also be provided in the case shown in FIG. 2, for example, by providing an optional condensed fraction divider 39 in the form of a partial liquid sampling plate (not shown) located vertically between the internal head capacitor 235 shoulder strap and distillation section 22.

A device and method for removing nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase can work as follows.

The cryogenic hydrocarbon composition 8 containing a nitrogen and methane-containing liquid phase is preferably provided at an initial pressure of 2 to 15 bar abs. and preferably at a temperature below -130 ° C.

Cryogenic hydrocarbon composition 8 can be obtained from reservoirs of natural gas or oil, or coal seams. Alternatively, the cryogenic hydrocarbon composition 8 can also be obtained from another source, including, for example, an artificial source, such as the Fischer-Tropsch process. Preferably, the cryogenic hydrocarbon composition 8 contains at least 50 mol% of methane, more preferably at least 80 mol% of methane.

In typical embodiments, a temperature below -130 ° C can be achieved by passing the hydrocarbon feed stream 110 through the liquefaction system 100. In such a liquefaction system 100, a hydrocarbon feed stream 110 containing a vaporous hydrocarbon-containing feed may be heat exchanged, for example, in a cryogenic heat exchanger 180, with a main refrigerant stream, thereby causing the vaporous feed to be liquefied from the feed stream to form a crude liquefied stream in line 1 of the crude liquefied product. The desired cryogenic hydrocarbon composition 8 can then be obtained from the crude liquefied stream 1.

The main refrigerant stream can be generated by circulating the main refrigerant in the main refrigerant circuit 101, in which the spent refrigerant 150 is compressed in the main refrigerant compressor 160 to form compressed refrigerant 120 from the used refrigerant 150. Heat is removed from the compressed refrigerant taken out from the main refrigerant compressor 160, through one or more heat exchangers provided in the compressed refrigerant line 120. This results in the formation of a partially condensed compressed refrigerant which is phase separated in an MR separator 128 into a light refrigerant fraction 121 consisting of vaporous components of a partially condensed compressed refrigerant and a heavy refrigerant fraction 122 composed of liquid components of a partially condensed compressed refrigerant.

The light refrigerant fraction 121 passes sequentially through the lower LMR bundle 183 and the upper LMR bundle 184 of the cryogenic heat exchanger 180, while the heavy refrigerant fraction 122 passes through the HMR bundle 185 of the cryogenic heat exchanger 180 to the transition point. When passing through these respective tube bundles, the corresponding light and heavy fractions of the refrigerant are cooled with the help of light and heavy fractions of the refrigerant, which evaporate in the annulus 186, again forming the spent refrigerant 150, which completes the cycle. At the same time, the hydrocarbon feed stream 110 passes through a cryogenic heat exchanger 180, sequentially through the lower hydrocarbon bundle 181 and the upper hydrocarbon bundle 182, and is liquefied and supercooled by the same evaporation of light and heavy refrigerant fractions.

Depending on the source, the hydrocarbon feed stream 110 may contain various amounts of components other than methane and nitrogen, including one or more non-hydrocarbon components other than water, such as CO ₂ , Hg, H ₂ S and other sulfur compounds; and one or more hydrocarbons heavier than methane, such as, in particular, ethane, propane and butanes, and possibly smaller amounts of pentanes and aromatic hydrocarbons. Hydrocarbons with a molecular weight corresponding to at least the mass of propane may be referred to herein as C ₃ + hydrocarbons, and hydrocarbons with a molecular mass corresponding to at least the mass of ethane may here be referred to as C ₂ + hydrocarbons.

Optionally, the hydrocarbon feed stream 110 may be pretreated to reduce the quantity and / or removal of one or more undesirable components, such as CO ₂ and H ₂ S, or sent to other stages, such as pre-compression or the like. Such steps are well known to those skilled in the art, and their mechanisms are not discussed further here. The composition of the hydrocarbon feed stream 110 thus varies depending on the type and location of the gas source and the applied pre-treatment (s).

The crude liquefied stream 1 may contain from 1 mol.% To 5 mol.% Nitrogen, have an initial temperature of from -165 ° C to -120 ° C and usually a liquefaction pressure of from 15 to 120 bar abs. In many cases, the initial temperature can be from -155 ° C to -140 ° C. Within this narrower range, lower cooling capacity in the liquefaction system 100 is required than when lower temperatures are desired, while the amount of subcooling at a pressure above 15 bar abs. high enough to avoid excessive flash vapor formation when depressurizing up to 1-2 bar abs.

The cryogenic hydrocarbon composition 8 can be obtained from the crude liquefied stream 1 using a main pressure relief of the crude liquefied stream 1 from the liquefaction pressure to the initial pressure. When the cryogenic hydrocarbon composition 8 enters the feed divider 9, the cryogenic hydrocarbon composition 8 is divided in the feed divider 9 into a first part as a first nitrogen desorber feed stream in a first feed line 10 and a second part as a bypass feed stream in a second line 11 supply of raw materials. The second part has the same composition and phase as the first part.

The first nitrogen desorber feed stream 10 is obtained from the cryogenic hydrocarbon composition 8 and then fed to the nitrogen desorption column 20 at a desorption pressure through the first inlet system 21.

The desorption pressure is usually less than or equal to the initial pressure. The desorption pressure in preferred embodiments is selected in the range of 2 to 15 bar abs. Preferably, the desorption pressure is at least 4 bar abs, since with a slightly higher desorption pressure, the desorption vapor in the desorption vapor line 71 can benefit from some additional enthalpy ( in the form of heat of compression), which is added to the process stream 60 in the process compressor 260. Preferably, the desorption pressure is not more than 8 bar abs. to facilitate efficiency and separation in a nitrogen desorption column 20. In addition, if the desorption pressure is in the range of 4 to 8 bar abs., The off-gas in the vapor fraction line 80 can be easily used as a so-called low pressure fuel stream without the need for additional compression.

In one example, the initial temperature of the crude liquefied stream 1 was −161 ° C., while the liquefaction pressure was 55 bar abs. The main pressure relief can be carried out in two stages: the first dynamic stage is carried out using a turbo expander 6 to reduce the pressure from 55 bar abs. up to about 10 bar abs., followed by a further pressure relief up to 7 bar abs. at the static stage using Joule-Thomson valve 7. It was assumed that the desorption pressure in this case was 6 bar abs.

A stream of 30 steam overhead is obtained from the head part 26 of the nitrogen desorption column 20. The vapor fraction 80 obtained from the overhead steam stream 30 and containing the withdrawn steam fraction 30 of the overhead is discharged in the form of exhaust gas. Suitably, at least the fuel portion of the vapor fraction 80 is supplied to the combustion device 220 at a fuel gas pressure that does not exceed the desorption pressure.

The nitrogen-depleted liquid 40 is withdrawn from the region 26 of the collector of the nitrogen desorption column 20. The temperature of the nitrogen-depleted liquid 40 is usually higher than the temperature of the first stream 10 of the nitrogen stripper feed. It is generally assumed that the temperature of the nitrogen-depleted liquid 40 is higher than the temperature of the first stream 10 of the nitrogen stripper feed and is from −140 ° C. to −80 ° C., preferably from −140 ° C. to −120 ° C.

The nitrogen-depleted liquid 40 is then subjected to a pressure relief, preferably by means of an intermediate pressure relief device 45, to a flash pressure that is lower than the desorption pressure, corresponding to a range of 1 to 2 bar abs. Preferably, the flash pressure is in the range of 1.0 to 1.4 bar abs. With a slightly higher difference between flash pressure and stripping pressure, the stripping vapor in the stripping vapor line 71 can benefit from some additional compression heat that is added to the process stream 60 in the process compressor 260.

The intermediate pressure relief device 45 may be controlled by an LC level controller configured to increase the flow rate through the intermediate pressure relief device if the level of liquid accumulated in the region 26 of the collection of the nitrogen desorption column 20 exceeds a target level. As a result of pressure relief, the temperature usually drops below -160 ° C. The stream 90 of the liquid hydrocarbon product, which is formed in this case, can usually be stored at atmospheric pressure in an open isothermal cryogenic storage tank.

Process steam 60 also forms. Process steam 60 may comprise flash vapor 64, which is often generated by depressurizing a nitrogen-depleted liquid 40 and / or depressurizing a feed bypass stream 11.

The second part of the cryogenic hydrocarbon composition 8 in the form of a bypass stream 11 of the feedstock, can be fed, for example, to an optional final flash separator 50. The division of the stream 8 of the cryogenic hydrocarbon composition into the first and second parts is such that the second part 11 has the same composition and phase as the first part 10.

The division ratio, defined as the flow rate of the second part relative to the flow rate of the cryogenic hydrocarbon composition in line 8 of the cryogenic hydrocarbon composition, can be adjusted using the bypass control valve 15. This bypass flow control valve 15 can be adjusted using an FC flow regulator to maintain a predetermined target flow rate of the first nitrogen desorber feed stream 10 to the nitrogen desorption column 20. The FC flow regulator will increase the open portion of the bypass flow control valve 15 if there is an excess flow in excess of the target flow, and decrease the open portion if there is insufficient flow compared to the target flow.

As a general recommendation, the division ratio can preferably be selected from 50% to 95%. Lower values are generally recommended for a higher nitrogen content in the cryogenic hydrocarbon composition, while higher values are preferred for a lower nitrogen content. In one example, the nitrogen content in the cryogenic hydrocarbon composition 8 was 3.0 mol%, with the result that the selected fission ratio was 75%.

The second part, leaving the divider 9 of the initial stream, can also be depressurized to the indicated flash pressure before it is subsequently fed to at least one line from the group consisting of: line 40 for discharge of the nitrogen-depleted liquid, line 90 for the liquid hydrocarbon product, and line 60 process steam; while bypassing the nitrogen desorption column 20. Accordingly, an optional second part is fed to an optional flash flash separator 50. However, the second part, originating from the splitter 9 of the feed stream, is preferably not subjected to any functional indirect heat transfer along the path from the splitter 9 of the feed stream to the subsequent feed. In this context, the expression "functional indirect heat transfer" is intended to eliminate the characteristic "non-functional" heat transfer and / or slight heat transfer between the second part in the second feed line 11 and the environment of the second feed line 11.

Stripping gas 230 is usually formed by adding heat to the liquid hydrocarbon product stream 90, whereby a portion of the liquid hydrocarbon product stream 90 evaporates to form a stripping gas. In a typical LNG plant, the formation of stripping gas can exceed the flash steam consumption by several times, especially during operation of the installation in the so-called loading mode, and therefore, an important advantage lies not only in the re-condensation of the flash vapor, but also in the re-condensation of the stripped gas gas, and also if there is not enough local heat demand for the use of all methane contained in the stripping gas.

In order to facilitate the transfer of the off-gas to the process steam stream 60, preferably an optional off-gas line 230 connects the steam region in the cryogenic storage tank 210 to the process steam line 60. In order to facilitate the transfer of the flash vapor 64 to the process steam stream 60 and to further deactivate the liquid hydrocarbon product stream 90, preferably the nitrogen-depleted liquid after depressurization is fed to an optional flash flash separator, where it undergoes phase separation under flash pressure per stream 90 of a liquid hydrocarbon product and steam 64 flash evaporation. The flash pressure is equal to or lower than the flash pressure, and accordingly is in the range of 1 to 2 bar abs. It is envisaged that in one embodiment, the instantaneous separation pressure is 1.05 bar abs.

Process steam 60 is compressed to at least a desorption pressure, thereby producing a compressed steam stream 70. The stripping steam stream 71 is obtained from the compressed steam stream 70 and is sent to the nitrogen stripping column 20 through the second inlet system 23. This stripping steam can leak up through the stripping section 23, in countercurrent contact with liquids leaking down through the stripping section 23.

If the external desorption steam supply line 74 is provided in fluid communication with the second inlet system 23, the external desorption steam may optionally be supplied to the nitrogen desorption column 20 through the second inlet system 23. In this way, a significant malfunction of the nitrogen desorption column 20 can be avoided, for example , in the case when the process compressor 260 does not provide a sufficient flow of compressed steam stream 70.

Obtaining a stripping steam stream 71 from a compressed steam stream 70 may include dividing the compressed steam stream 70 into a stripping steam stream 71 and a bypass steam portion that does not contain a stripping portion and which can be selectively introduced into the overhead steam line 30, thereby bypassing nitrogen desorption column 20. Selective entry can be adjusted using the bypass control valve 77 steam. Accordingly, the steam bypass control valve 77 is controlled by a pressure regulator in the compressed steam line 70, which is configured to increase the open portion of the steam bypass control valve 77 in response to an increase in pressure in the compressed steam line 70. It is assumed that the flow rate of the bypassed portion of the steam, which can pass through the steam bypass line 76 into the overhead steam stream 30, is particularly high in the so-called loading mode, during which the quantity of stripping gas is usually much higher than usually during the so-called storage mode. Preferably, the steam bypass control valve 77 is completely closed during normal storage operation.

In preferred embodiments, a partially condensed intermediate stream is generated from the overhead steam 30. This includes indirect heat transfer from the overhead steam 30 to the auxiliary refrigerant stream 132, as a result of which heat is transferred from the overhead steam 30 to the auxiliary refrigerant stream 132 at a selected cold output. The resulting partially condensed intermediate stream contains a condensed fraction and a vapor fraction.

In the context of the present description, the performance of the cold reflects the degree to which heat exchange occurs in the capacitor, which can be expressed in units of power (for example, in watts or megawatts). Cold performance is associated with the consumption of auxiliary refrigerant sent for heat exchange with steam overhead.

The auxiliary refrigerant stream 132 preferably has a boiling point under standard conditions at a lower temperature than the boiling point of a 30-steam overhead stream under standard conditions (standard conditions of ISO 13443: 15 ° C at 1.0 atmosphere. This facilitates re-condensation of relatively a high amount of methane present in the overhead steam stream 30, which, in turn, facilitates the adjustability of the methane content in the vapor fraction 80. For example, the auxiliary refrigerant may contain from 5 mol.% to 75 mol% nitrogen. In a preferred embodiment, the auxiliary refrigerant stream is generated by a discharge stream from the main refrigerant stream, more preferably a light stream of the refrigerant, is removed. This latter case is illustrated in Figure 2, but can also be used in the embodiment of Figure 1 Such a vent stream can conveniently be directed back to the main refrigerant circuit through the annulus 186 of the cryogenic heat exchanger 180, where it can still contribute to heat dissipation. from the flow in the upper and / or lower bundles of pipes.

For example, the intended composition of the auxiliary refrigerant contains from 25 mol.% To 40 mol.% Nitrogen; from 30 mol.% to 60 mol.% methane and up to 30 mol.% C2 (ethane and / or ethylene), as a result of which the auxiliary refrigerant contains at least 95% of these components, and / or the total content of nitrogen and methane is at least 65 mol.%. Composition within these ranges can be easily accessed from the main refrigerant circuit if mixed refrigerant is used to supercool the liquefied hydrocarbon stream.

You can also use a separate cooling circuit to partially condense a stream of 30 steam overhead. However, the use of a stream diverted from the main refrigerant stream has the advantage that the amount of additional equipment that needs to be installed is minimal. For example, an additional auxiliary refrigerant compressor and auxiliary refrigerant condenser are not required.

The condensed fraction is separated from the vapor fraction in the overhead separator 33 at a separation pressure that may be lower than the desorption pressure, and is preferably in the range of 2 to 15 bar abs. The vapor fraction is discharged along the line 80 of the allocation of the vapor fraction. The condensed fraction is discharged from the overhead separator 33 into the reverse irrigation system, for example, along the condensed fraction discharge line 37.

Thus, the overhead condenser 35 provides the opportunity for re-condensation of the vapor of methane, which was previously part of the crude liquefied product 1, provided that it exceeds the target methane content in the exhaust vapor fraction 80, by adding any such vaporous methane-containing stream to the stream (compressed) process steam. Previously forming part of process steam 60 or compressed process steam 70, vapor methane can find its way to heat exchange with auxiliary refrigerant 132, with which it selectively condenses from steam 30 of the overhead of the nitrogen desorption column 20, while allowing most of the nitrogen to be vented to the off-gas . In this case, it becomes possible to remove a sufficient amount of nitrogen from the cryogenic hydrocarbon composition 8 to obtain a stream 90 of liquid hydrocarbon product within the desired maximum standard for nitrogen content, while not creating more thermal power in the exhaust gas than necessary.

Vapor methane, which was previously part of the crude liquefied product 1, can be formed for various reasons. In the normal operation of a natural gas liquefaction plant, methane-containing steam is formed from a (crude) liquefied product in the form of:

- flash vapor resulting from the flash evaporation of the crude liquefied product during pressure relief; and

- stripping gas resulting from thermal evaporation caused by heat supplied to the liquefied product, for example, in the form of heat leakage into storage tanks, LNG pipelines, and heat from the pumps of the LNG plant. In this mode of operation, known as the storage mode, the storage tanks are filled with a liquefied hydrocarbon product, as it leaves the unit, without any loading and transport operations being carried out at the same time. In storage mode, methane-containing vapors are formed on the installation side of the storage tanks.

The operating mode of the LNG facility while carrying out loading and transportation operations (usually ship loading operations) is known as loading mode operation. During operation in loading mode, stripping gas is additionally generated in the storage tanks on the side of the vessel, for example, due to the initial cooling of the vessel’s tanks; steam displacement from the vessel’s tanks; heat leakage through the pipeline and tanks connecting storage tanks and vessels, and heat from LNG loading pumps.

The proposed solution can facilitate the handling of these pairs during operations of both storage mode and boot mode. It combines the removal of nitrogen from the cryogenic hydrocarbon composition 8 with the re-condensation of excess vapor methane. This creates an elegant solution in situations where a little fuel is needed for the plant’s own needs, as can be the case with an electric drive system using electricity from an external power supply.

The calorific value of the withdrawn steam fraction 80 is accordingly regulated by adjusting the performance for cold in the overhead condenser 35. This can be done using the cold performance controller 34. By adjusting the productivity in the cold, in which heat is transferred from the overhead steam to the auxiliary refrigerant stream, the relative methane content in the exhaust gas can be controlled. As a result, the calorific value of the vented steam fraction can be adjusted to match a specific heat demand. This makes the exhaust gas suitable for use as a fuel gas stream, even in circumstances in which the demand for calorific value is variable.

When the vapor fraction 80 is supplied to the combustion device 220 and consumed by it as fuel, the calorific value can be controlled by the combustion device 220 in accordance with the actual heat demand.

Adjustable heating value may be selected in accordance with the possible circumstances of the intended use of the off-gas as fuel gas. The calorific value can be determined in accordance with DIN 51857. For many applications, the regulated calorific value can be proportional to the lower calorific value (LHV; sometimes called calorific value), which can be defined as the amount of heat released when a certain amount of fuel is burned (initially at 25 ° C) and bringing the temperature of the combustion products to 150 ° C. This suggests that the latent heat of water vaporization in the reaction products is not taken into account.

However, in order to control the calorific value in the context of the present invention, the actual calorific value of the vented vapor fraction does not need to be determined on an absolute basis. As a rule, it turns out to be sufficient to regulate the calorific value relative to the actual need for thermal power in order to minimize any drawback and excess of the provided thermal power.

Preferably, the cold performance is automatically adjusted in response to a signal that is associated with a causal relationship to the controlled calorific value. In embodiments in which the vapor fraction is supplied to one or more selective methane consumers, such as, for example, the combustion device 220 shown in FIG. 1, the regulation can be carried out in accordance with the required heat output, whereby the partial consumption of methane is adjusted to achieve calorific value that meets the need. Accordingly, the auxiliary refrigerant flow control valve 135 can be controlled by the pressure regulator PC to maintain the desired target flow rate of the auxiliary refrigerant stream 132 through the overhead condenser 35. The actual pressure in the steam fraction lead line 80 is due to a causal relationship with adjustable calorific value. The PC pressure regulator will be configured to decrease the open portion of the auxiliary refrigerant flow control valve 135 when the pressure drops below a predetermined target level, which indicates a higher methane consumption rate than the steam supply rate of 80. On the other hand, the PC pressure regulator will configured to increase the open portion of the auxiliary refrigerant flow control valve 135 if the pressure exceeds a predetermined target level.

It is assumed that the vapor fraction 80 contains from 50 mol.% To 95 mol.% Nitrogen, preferably from 70 mol.% To 95 mol.% Nitrogen or from 50 mol.% To 90 mol.% Nitrogen, more preferably from 70 mol. % to 90 mol% of nitrogen, even more preferably from 75 mol% to 95 mol% of nitrogen, most preferably from 75 mol% to 90 mol% of nitrogen. It is assumed that the condensed fraction 37 contains less than 35 mol.% Nitrogen.

If the nitrogen desorption column 20 is equipped with an optional internal distillation section 22, as described above, the overhead steam stream 30 is preferably obtained from the head of the nitrogen desorption column 20 above the distillation section 22. At least a portion 36 of the reflux from the condensed fraction enters the desorption column 20 nitrogen, starting at the level above the distillation section 22. In the case of the embodiment of FIG. 1, the condensed fraction can be supplied through an optional reverse irrigation pump 38 (and / and whether it can drain by gravity). A part of the reverse irrigation is further obtained from the condensed fraction and sent to the nitrogen desorption column 20 through the reverse irrigation inlet system 25 and the reverse irrigation part line 36. In the case of the embodiment of FIG. 2, the condensed fraction is separated inside the head of the nitrogen desorption column 20 and thus becomes accessible above the distillation section to seep down through the distillation section 22, in contact with vapors rising upward through the distillation section 22.

The reverse irrigation portion may contain the entire condensed fraction, but the optionally condensed fraction is separated in the optionally provided condenser fraction divider 39 into a recirculating liquid portion that is introduced through the liquid recirculation line 13, for example, into the first feed stream 10, and a reverse irrigation portion that is introduced into a nitrogen desorption column 20 through a reverse irrigation inlet system 25 and a reverse irrigation part line 36. The possibility of separating the condensed fraction into the reverse irrigation part 36 and the recirculating liquid part 13 is preferable for directing any excess condensed fraction around the distillation section 22 so as not to disturb the operation of the distillation section 22. The recirculation valve 14 can accordingly be adjusted using the flow regulator provided in the discharge line 37 the condensed fraction, and / or the level controller provided on the overhead separator 33.

Partial condensation may also include direct and / or indirect heat exchange with other streams in other successive overhead heat exchangers. For example, the cold recovery heat exchanger 85 may be such an overhead heat exchanger in which partial condensation of the overhead stream further includes indirect heat exchange with the vapor fraction 80.

The optional steam recirculation line 87 can be used selectively, respectively, by selectively opening the steam recirculation control valve 88 to increase the amount of nitrogen that remains in the liquid hydrocarbon product stream 90. This can be done by diverting part of the recycle steam from the vapor fraction, depressurizing part of the recycle steam to flash pressure and subsequently pumping part of the recycle steam into nitrogen-depleted liquid 40. The remaining part of the vapor fraction 80, which does not enter the steam recycle line 87, may form a fuel portion that can be transmitted to the combustion device 220.

In some embodiments, the target amount of nitrogen dissolved in the liquid hydrocarbon product stream 90 is from 0.5 to 1 mol%, preferably as close to 1.0 mol% as possible, but not more than 1.1 mol%. The recirculation valve 88 of the steam recirculation stream controls the amount of vapor fraction stream 80, which is fed back, for example, to the final flash separator 50, while bypassing the nitrogen desorption column 20. By this, the amount of nitrogen in the stream 90 of the liquid hydrocarbon product can be affected. To further contribute to the achievement of the target nitrogen content, the recirculating steam flow recirculation valve 88 may be controlled in accordance with a signal from a QMI quality measuring device, which is optionally provided in the liquid hydrocarbon product line 90.

Table 1. Storage mode; reference numbers correspond to figure 1 Reference Position Number one 8 10 eleven 13 thirty 36 40 60 64 70 71 76 80 87 90 Phase (vapor / liquid, (P / F) F F F F F P F F P P P P - P P F Consumption (kg / s) 134 134 36.1 99 0.55 11.3 6.60 45.8 14.4 12.4 14.4 14.4 0.00 4.1 1.44 134 Temperature (° C) -162 -163 -163 -163 -159 -143 -159 -137 -162 -164 -72 -72 - -159 -159 -164 Pressure (bar abs) 55 6.4 6.4 6.4 6.4 6.2 6.2 6.3 1.00 1.05 6.8 6.3 - 5.8 5.8 1.05 Nitrogen (mol%) 1.66 1.66 1.91 1.66 20.1 37.7 20.1 1.77 18.0 18.3 18.0 18.0 - 80.0 80.0 0.86 Methane (mol%) 98.3 98.3 98.1 98.3 79.9 62.3 79.9 98.2 82.0 81.7 82.0 82.0 - 20.0 20.0 99.1

table 2 Boot mode; reference numbers correspond to figure 1 Reference Position Number one 8 10 eleven 13 thirty 36 40 60 64 70 71 76 80 87 90 Phase (vapor / liquid, (P / F) F F F F F P F F P P P P P P P F Consumption (kg / s) 134 134 36.8 102 4.80 17.8 6.91 45.0 19.1 14.6 19.1 13.5 5.53 6.1 3.3 136 Temperature (° C) -162 -163 -162 -162 -160 -115 -160 -138 -154 -164 -56 -57 -57 -160 -160 -164 Pressure (bar abs) 55 6.4 6.4 6.4 6.4 6.2 6.2 6.3 1.00 1.05 6.8 6.3 6.2 5.8 5.8 1.05 Nitrogen (mol%) 1.66 1.66 3.90 1.66 20.9 37.3 20.9 2.15 21.3 22.5 21.3 21.3 21.3 81.0 81.0 1.09 Methane (mol%) 98.3 98.3 96.1 98.3 79.1 62.7 79.1 97.9 78.7 77.5 78.7 78.7 78.7 19.0 19.0 98.9

Static simulation was carried out on the embodiment shown in figure 1, both for the storage mode (table 1) and for the loading mode (table 2). It was assumed that the cryogenic hydrocarbon composition 8 consists of more than 90 mol.% A mixture of nitrogen and methane (98,204 mol.%). In the example, the amount of nitrogen (1.654 mol.%) And methane (98.204 mol.%) Is more than 99.8 mol.%, While the remaining part (0.142 mol.%) Consists of carbon dioxide (0.005 mol.%). Carbon dioxide leaves the process with nitrogen-depleted liquid 40 and a stream 90 of liquid hydrocarbon product. The division ratio in the divider 9 of the original stream was approximately 75% in both cases.

It can be seen that both in the storage mode and in the loading mode, despite the large difference in the amount of process steam, the amount of methane in the steam fraction 80 can be kept at about 80 mol% and, to a large extent, in the range of 10 mol.% up to 25 mol.%, while the nitrogen content in the stream 90 of the liquid hydrocarbon product is maintained within the target values, close to 1.0 mol.%, but not exceeding 1.1 mol.%.

In the storage mode, about 2.0 kg / s of stripping gas, consisting of about 17 mol.% Nitrogen and 83 mol.% Methane, was added to the process via the stripping gas supply line 230, while in the loading mode this amount was about 4.4 kg / s

In the storage mode, steam was not directed through the steam bypass line 76, while in the loading mode 30% of the compressed steam 70 was directed through the steam bypass line 76 to accommodate the additional steam caused by the additional influx of stripping gas. The amount of recycle liquid 13 in the loading mode also increased, from about 8% to about 41% of the condensed fraction in the condensed fraction discharge line 37. The additional addition of the condensed fraction is the result of additional re-condensed methane.

When calculating the liquefaction system 100, the circuit shown in FIG. 2 was used with mixed refrigerant in the compressed refrigerant line 120 with the composition shown in table 3 in column “120”.

Table 3 The composition of the mixed refrigerant (in mol.%) 120 121; 131; 132 Storage Loading Nitrogen 21.5 33.1 33.5 Methane 33.3 40.9 40.8 Ethane 0.13 0.07 0.07 Ethylene 32.6 23.1 22.8 Propane 12.2 2.79 2.81 Bhutan 0.25 0.02 0.02

In the storage mode, the pressure in the compressed refrigerant line 120 was 58 bar abs., In the loading mode it was higher - 61 bar abs. The total pressure drop in the lower and upper beams (183 and 184, respectively) of the LMR cryogenic heat exchanger tubes was 13 bar in both cases. The pressure drop caused by the auxiliary refrigerant flow control valve 135 was 39 bar in the case of storage mode and 42 bar in operation in the loading mode, so that the pressure in the annular region 186 of the cryogenic heat exchanger 180 was the same in both the storage mode and the loading mode.

The relative flow rate of auxiliary refrigerant stream 132 was 11% of the total LMR flow in line 131 of the LMR. In boot mode, it was 18%. In addition, the actual flow rate was 1.6 times higher than in the case of the storage mode, but the separation of the HMR and LMR in the MR separator 128 was slightly more in favor of the HMR when operating in boot mode than in storage mode.

In the above example, it was assumed that the cryogenic hydrocarbon composition does not contain hydrocarbons heavier than methane (C ₂ + hydrocarbons), as would be the case if the cryogenic hydrocarbon composition is made from unconventional gas sources such as coalbed methane, shale gas, or, perhaps some artificial sources. However, the proposed methods and device can also be used when the cryogenic hydrocarbon composition contains up to about 15 mol% of C ₂ + hydrocarbons, including one or more hydrocarbons selected from the group consisting of ethane, propane, i-butane, n-butane and pentane. In fact, it is not expected that these additional C ₂ + hydrocarbons will change the functioning of the proposed methods and devices, since it is assumed that none of these C ₂ + hydrocarbons will be detected in the steam 30 of the overhead or in the exhaust gas in the steam fraction discharge line 80, like carbon dioxide from the example.

One skilled in the art will understand that the present invention may be practiced in various ways without departing from the scope of the appended claims.

Claims (51)

1. The method of removing nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase, which includes: - providing a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase; - supplying a first stream of nitrogen stripper feed at a stripping pressure to a nitrogen stripping column containing at least one internal stripping section located inside the nitrogen stripping column, said first nitrogen stripping feed stream comprising a first portion of said cryogenic hydrocarbon composition; - removal of nitrogen-depleted liquid from the region of the collection of the nitrogen desorption column located under the desorption section; - obtaining at least a stream of liquid hydrocarbon product and process steam from a nitrogen-depleted liquid, comprising at least a step of depressurizing the nitrogen-depleted liquid to an instantaneous vapor pressure that is lower than the desorption pressure; - compressing said process steam to at least a desorption pressure, thereby obtaining compressed steam; - passing a stream of stripping steam into the nitrogen stripping column at a level lower vertically from said stripping section, wherein said stripping steam stream contains at least a stripping portion of said compressed steam; - abstraction of the vapor fraction containing the withdrawn fraction of the overhead vapor obtained from the head of the nitrogen desorption column in the form of exhaust gas; - dividing the cryogenic hydrocarbon composition stream into said first part and second part having the same composition and phase as the first part; - pressure relief of the second part to the specified pressure instantaneous evaporation; - supplying the second part to at least one stream from the group consisting of: a nitrogen-depleted liquid, a liquid hydrocarbon product, and process steam; moreover, from the specified division of the flow to the specified feed of the second part, the second part bypasses the nitrogen desorption column. 2. The method according to p. 1, further comprising a stage: - regulating the ratio of the division of the cryogenic hydrocarbon composition into the specified first part and the specified second part, defined as the flow rate of the specified first part relative to the total flow rate of the first and second parts together, thereby maintaining the flow rate of the specified first part at a given target flow rate. 3. The method according to p. 1, in which the desorption pressure is in the range from 2 to 15 bar abs. And / or in which the flash pressure is from 1 to 2 bar abs. 4. The method according to claim 1, further comprising transmitting at least the fuel portion of the vapor fraction to the combustion device at a fuel gas pressure not exceeding the desorption pressure. 5. The method according to claim 1, wherein the process steam contains stripping gas obtained by adding heat to the liquid hydrocarbon product stream, as a result of which a portion of the liquid hydrocarbon product stream evaporates to form the specified stripping gas. 6. The method according to claim 1, wherein during said depressurization of said nitrogen-depleted liquid to said flash pressure, flash steam is generated, said process steam containing said flash vapor. 7. The method of claim 6, wherein said formation of said at least liquid hydrocarbon product stream and process steam from a nitrogen-depleted liquid further comprises the step of phase separating the nitrogen-depleted liquid in a flash flash separator at a flash point that is equal to or less, than flash pressure, on the liquid hydrocarbon product stream and said flash vapor. 8. The method according to p. 7, in which the specified supply of the second part to the specified at least one stream from the group consisting of: nitrogen-depleted liquid, liquid hydrocarbon product and process steam, includes: supplying the second part to the final flash evaporator after said depressurization of said second part to said instant flash pressure. 9. The method according to claim 1, wherein the nitrogen desorption column further comprises at least one internal distillation section located vertically higher than said desorption section in said nitrogen desorption column; moreover, the specified method further includes: - the formation of a partially condensed intermediate stream from the overhead steam obtained from the head of the nitrogen desorption column above the distillation section, said partially condensed intermediate stream comprising a condensed fraction and a vapor fraction, said formation comprising partial condensation of the overhead steam due to heat exchange of the overhead steam with a stream of auxiliary refrigerant and, thus, heat from the overhead steam to the auxiliary stream th refrigerant in the amount of performance in the cold; - separation of the condensed fraction from the vapor fraction at a separation pressure; - allow at least part of the reverse irrigation from the condensed fraction to enter the distillation section in the nitrogen desorption column at a level above the distillation section. 10. The method of claim 1, wherein said providing said cryogenic hydrocarbon composition comprises: - heat transfer of a feed stream containing a hydrocarbon-containing vaporous feedstock in a cryogenic heat exchanger with a main refrigerant stream leading to liquefaction of the vaporous feedstock from the feedstream to produce a liquefied stream; and - obtaining a cryogenic hydrocarbon composition from a liquefied stream. 11. The method according to claim 1, wherein said second part does not undergo any functional indirect heat transfer along the path to said subsequent supply to at least one stream from the group consisting of: a nitrogen-depleted liquid, a liquid hydrocarbon product, and process steam; moreover, from the specified division of the flow to the specified feed of the second part, the second part bypasses the nitrogen desorption column. 12. The method according to p. 1, further comprising: - the removal of the vapor recycle portion from the specified vapor fraction; - depressurization of said vaporous recycle portion to flash pressure; - introducing a vaporous recycle portion into at least one stream from the group consisting of: a nitrogen-depleted liquid, a liquid hydrocarbon product, and process steam. 13. The method according to p. 1, in which the vapor fraction contains from 50 mol.% To 95 mol.% Nitrogen. 14. The method according to p. 1, in which the condensed fraction contains less than 35 mol.% Nitrogen. 15. The method according to any one of paragraphs. 1-14, further comprising selectively introducing a bypass portion of said compressed steam, which does not contain said stripping portion, into the overhead steam, while bypassing at least the desorption section of the nitrogen desorption column. 16. A device for removing nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase, which contains: - a cryogenic feed line connected to a source of a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase; - a nitrogen desorption column in fluid communication with the cryogenic feed line, said nitrogen desorption column comprising at least one internal desorption section located inside the nitrogen desorption column; - a steam discharge line of the overhead steam, communicating with the nitrogen desorption column through the head region inside the nitrogen desorption column; - the discharge line of a nitrogen-depleted liquid in communication with the collection area inside the nitrogen desorption column located downright from the desorption section; - an intermediate pressure relief device in the discharge line of a nitrogen-depleted liquid in fluid communication with a nitrogen desorption column configured to receive a nitrogen-depleted liquid from an area of the collector of a nitrogen desorption column and relieve pressure of a nitrogen-depleted liquid, said intermediate pressure relief device being located at the interface between the desorption pressure side including the nitrogen desorption column and the flash side; - a line of liquid hydrocarbon product, located on the pressure side of the flash, to divert the flow of liquid hydrocarbon product obtained from a nitrogen-depleted liquid; - a process steam line located on the pressure side of flash flash to receive process steam obtained from a nitrogen-depleted liquid; - a process compressor located in the line of process steam configured to receive process steam and compress process steam to create compressed steam at the outlet of the process compressor, said process compressor being at a specified interface between the desorption pressure side and the flash side; - a line of stripping steam in fluid communication with the nitrogen stripping column at a level lower down from the stripping section and configured to receive at least the stripping portion of said compressed steam from the process compressor; - a feed stream divider located in the cryogenic feed line, configured to divide the cryogenic hydrocarbon composition into a first part and a second part having the same composition and phase as the first part; - a first feed line for transporting a first portion from a feed stream divider to a nitrogen desorption column; - a second feed line for transporting the second part from the feed stream divider to at least one line from the group consisting of: a line of nitrogen-depleted liquid, a line of liquid hydrocarbon product and a process steam line, said second feed line bypassing the nitrogen desorption column. 17. The device according to claim 16, wherein a bypass flow control valve is located in the second feed line. 18. The device of claim 17, wherein said bypass flow control valve is operatively coupled to an FC flow regulator located in a first feed line. 19. The device according to p. 18, in which the specified FC flow regulator is configured to maintain the flow rate of the first part through the first feed line at a predetermined target flow rate by adjusting the division ratio of the cryogenic hydrocarbon composition flowing through the cryogenic feed line to the first and the second part. 20. The device according to any one of paragraphs. 16-19, wherein said second feed line does not pass through any indirect heat exchanger that functions to indirectly exchange heat with any process stream.

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