RU2612974C2 - Method and apparatus for removing nitrogen from cryogenic hydrocarbon composition - Google Patents

Abstract

FIELD: chemistry.

SUBSTANCE: invention relates to method and device to remove nitrogen from cryogenic hydrocarbon compositions, nitrogen-containing and methane-containing liquid phase. By-product vapour from cryogenic hydrocarbon composition, at low pressure of 0.1 to 0.2 MPa, is compressed to separation pressure in range from 0.2 to 1.5 MPa. Said compressed vapour is partially liquefied by heat exchange of compressed vapour with auxiliary flow of coolant and, thus, inflow of heat from compressed vapour into stream of auxiliary coolant into cooling mode. Condensed fraction of partially liquefied compressed vapour is subjected to pressure release and at least a portion thereof is re-fed into cryogenic hydrocarbon composition. Exhaust gas, consisting of non-condensed vapour fraction of partially liquefied compressed vapour, is removed from first gas-liquid separator. Cooling mode is corrected to adjust calorific capacity removed vapour fraction.

EFFECT: technical result is enabling adjustment of calorific capacity of removed vapour fraction.

17 cl, 4 dwg, 5 tbl

Description

The present invention relates to a method and apparatus for removing nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase.

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. It is often desirable to liquefy natural gas in a natural gas liquefaction plant located at or near the source of a natural gas stream 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 2006/120127 describes a method for separating LNG and installation. Liquefied natural gas in liquid form is sent to a separation unit in which a nitrogen-free LNG stream and nitrogen-enriched steam are formed. In the separation plant, two columns are used. Nitrogen-enriched steam, the nitrogen content of which is more than 80 mol%, is re-condensed in the overhead condenser of one of the columns using liquid refrigerant. At the same time, the formation of LNG is increased, since methane molecules, otherwise lost with nitrogen-enriched vapor, can now be obtained in the form of LNG. Vapors leaking from storage can also be processed and re-condensed. Nitrogen contained in natural gas can be used with technical purity.

The disadvantage of this LNG separation method is that the nitrogen-rich stream is not suitable as a fuel stream.

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

- providing a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase at an initial pressure of 1 to 2 bar abs. (0.1-0.2 MPa);

- selection of side steam from the cryogenic hydrocarbon composition;

- compression of the specified side steam to the processing pressure in the range from 2 to 15 bar abs. (0.2-1.5 MPa), thereby obtaining compressed steam;

- the formation of a partially condensed intermediate stream from compressed steam containing the condensed fraction and the vapor fraction, and this formation includes partial condensation of the compressed steam by heat exchange of the compressed steam with the auxiliary refrigerant stream and, thus, the heat from the compressed steam into the auxiliary refrigerant stream in cooling mode;

- separation of the condensed fraction from the vapor fraction in the first gas-liquid separator, with a separation pressure of 2 to 15 bar abs. (0.2-1.5 MPa);

- removal of the vapor fraction from the first gas-liquid separator in the form of exhaust gas, wherein said vapor fraction has a calorific value;

- removal of the condensed fraction from the first gas-liquid separator;

- depressurization of the condensed fraction to a pressure not lower than the initial pressure, thereby forming a portion of the reduced pressure recirculate;

introducing a portion of the reduced pressure recirculate into the cryogenic hydrocarbon composition;

- adjustment of the cooling mode to regulate the calorific value of the vapor fraction discharged from the first gas-liquid separator.

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

- a gas holder for a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase at an initial pressure;

- a line of secondary steam, fluidly connected to the gas tank and configured to select side steam from the gas tank;

- a by-product compressor located in the by-product line configured to compress at least said by-product steam to a treatment pressure that exceeds the initial pressure to provide compressed steam at the by-product compressor outlet;

at least one condensing heat exchanger in fluid communication with the outlet of the compressor and configured to receive compressed steam and form a partially condensed intermediate stream from the compressed steam, the partially condensed intermediate stream containing a condensed fraction and a vapor fraction, and said condensing the heat exchanger, in addition, is configured to bring compressed steam into heat exchange contact with the auxiliary refrigerant stream, in p result of which during operation receives heat from the compressed vapor to the auxiliary refrigerant flow in a cooling mode;

a first gas-liquid separator configured to receive a partially condensed intermediate stream and to separate the condensed fraction from the vapor fraction at a separation pressure;

- a steam fraction discharge line fluidly coupled to the first gas-liquid separator, configured to transport the vapor fraction far from the first gas-liquid separator;

a condensed fraction discharge line adapted to transport the condensed fraction far from the first gas-liquid separator, said condensed fraction discharge line on the inlet side being fluidly connected to the first gas-liquid separator and on the outlet side fluidly connected to the inlet point at the junction with cryogenic hydrocarbon composition;

- a pressure relief system placed in the discharge line of the condensed fraction, configured to depressurize the condensed fraction to a pressure not lower than the initial pressure, thereby forming a portion of the reduced pressure recirculate;

- a cooling mode controller configured to adjust the cooling mode to control the calorific value of the vapor fraction discharged from the first gas-liquid separator.

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

in FIG. 1 is a schematic flowchart showing a method and apparatus according to an embodiment of the invention;

in FIG. 2 is a schematic flowchart showing a method and apparatus in accordance with another embodiment of the invention;

in FIG. 3 is a schematic flow diagram of a process including a method and apparatus in accordance with yet another embodiment of the invention; and

in FIG. 4 is a schematic flow diagram of a process including a method and apparatus in accordance with yet 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 description relates to the removal of nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase. The by-product steam from the cryogenic hydrocarbon composition, which is at a low pressure of 1 to 2 bar abs, is compressed to a separation pressure in the range of 2 to 15 bar abs. (0.2-1.5 MPa). Such compressed steam is partially liquefied by heat exchange of the compressed steam with the auxiliary refrigerant stream and, thereby, heat from the compressed steam to the auxiliary refrigerant stream in the cooling mode. The condensed fraction of partially liquefied compressed steam is depressurized and at least a portion of it is reintroduced into the cryogenic hydrocarbon composition. Exhaust gas consisting of an uncondensed vapor fraction of partially liquefied compressed steam is discharged from the first gas-liquid separator. The cooling mode is adjusted to regulate the calorific value of the extracted steam fraction.

By adjusting the cooling mode in which heat is transferred from the compressed 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.

Preferably, the exhaust gas is consumed at a fuel gas pressure not exceeding the separation pressure. This eliminates the need for a special fuel gas compressor.

In the context of the present description, the cooling mode reflects the intensity with which heat transfer occurs in a condensing heat exchanger, which can be expressed in units of power (for example, in watts or megawatts). The cooling mode is associated with the consumption of auxiliary refrigerant sent for heat exchange with compressed steam.

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 cooling mode is automatically adjusted in response to a signal that is linked by a causal relationship to the controlled calorific value.

It is believed that the methods and apparatus of the present invention are most useful when the crude liquefied product or cryogenic hydrocarbon composition contains from 0.5 mol% to 1.8 mol% of nitrogen. Existing alternative approaches may also work adequately when the nitrogen content is outside this range. For example, for higher nitrogen contents, a nitrogen desorption column may be used.

The proposed method and device creates the opportunity for the re-condensation of vaporous methane, which was previously part of the crude liquefied product, provided that it exceeds the target methane content in the exhausted vapor fraction by adding any such vaporous methane-containing stream to the vapor or compressed stream. Previously, vaporous methane forming part of the compressed steam can find its way to heat exchange with auxiliary refrigerant, with the help of which it selectively condenses from the compressed steam, while allowing most of the nitrogen to be removed with the exhaust gas. In this case, it becomes possible to remove a sufficient amount of nitrogen from the cryogenic hydrocarbon composition to obtain a stream 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, may form in an LNG plant for various reasons. In the normal operation of a natural gas liquefaction plant, methane-containing by-product steam is generated 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 side fumes 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 side pairs during operations of both storage mode and boot mode. It combines the removal of nitrogen from a cryogenic hydrocarbon composition with the re-condensation of excess vaporous 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 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. It was found that even when the crude liquefied product (or cryogenic hydrocarbon composition) contains a sufficiently high amount of nitrogen, from 1.0 mol.% (Or from about 1.0 mol.%) To 1.8 mol.% (Or up to about 1 , 8 mol.%) Of nitrogen, the resulting liquid hydrocarbon product may correspond to a nitrogen content in the regulatory range from 0.5 to 1 mol.% Of 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.

Nevertheless, the proposed solution is also advisable for cryogenic hydrocarbon compositions containing less than 1.0 mol.% Nitrogen, since the proposed solution can be carried out with the possibility of containing the stripping gas, while maintaining control over the amount of methane that is discharged as part of the vapor fraction in the exhaust gas in order to minimize any shortage and excess of the provided heat capacity in comparison with the actual demand for heat power.

It should be noted that WO 2011/009832 describes a method by which nitrogen can be separated from a multiphase hydrocarbon stream in which steam is compressed and returned to the first gas-liquid separator in vapor form as a stripping steam stream. The first gas-liquid separator from WO 2011/009832 is essentially a column because it uses a contact zone containing contact enhancing means.

In the present invention, the steam stream is partially condensed before it is fed to the first gas-liquid separator. The vapor fraction is not used as a stripping vapor, but is simply separated from the condensed fraction. It is characteristic that the temperature of the vapor fraction withdrawn from the first gas-liquid separator is essentially the same (for example, does not differ by more than 2 ° C or preferably more than 1 ° C) as the temperature of the condensed fraction withdrawn from the first gas-liquid separator. The first gas-liquid separator can be essentially the only equilibrium stage in which the vapor and liquid inside the gas-liquid separator are in thermodynamic equilibrium. An advantage of the device and methods proposed in the present invention is that the first gas-liquid separator may consist of a drum that does not contain any internal elements forming a vapor / liquid contacting section. This may be a simple phase separator vessel configured to separate an incoming vapor phase from an incoming liquid phase.

This makes it significantly cheaper and less difficult to operate than, for example, in the circuit described in WO 2006/120127, in which two columns are used, or in WO 2011/009832, in which essentially one column is used.

In FIG. 1 shows a device including an embodiment of the invention. The cryogenic feed line 8 is in fluid communication with the cryogenic storage tank 210, so that at least a portion of the cryogenic hydrocarbon composition transported to the cryogenic feed line 8 is transported to the cryogenic storage tank 210. In the embodiment of FIG. 1, a liquid hydrocarbon product line 90 connects a cryogenic feed line 8 to a cryogenic storage tank 210.

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. 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.

In the embodiment of FIG. 1, a cryogenic storage tank 210 functions as a gas holder for a cryogenic hydrocarbon composition. The present invention is not limited to gas holders in the form of a cryogenic storage tank, such as illustrated in FIG. 1, but works with any type of gas tank for a cryogenic hydrocarbon composition, including, for example, a pipe, a phase separator, a cargo tank on a conveyor, or various combinations. In FIG. 2, which will be described in more detail below, an example is shown in which the gas holder includes a combination of a pipe, a phase separator and a cryogenic storage tank.

The by-product steam line 60 is fluidly coupled to the cryogenic storage tank 210. The by-product steam line 60 is configured to take by-product steam from the gas tank. A by-product compressor 260 is placed in the by-product steam line 60 to compress the by-product in the by-product line 60. A compressed steam discharge line 70 is fluidly coupled to an outlet 261 of a by-product compressor 260. Accordingly, the by-product compressor 260 is equipped with an anti-surge controller and a recirculate cooler, which are used when the by-product compressor is in recycle mode and during start-up (not shown in the drawing).

A series 235 of condensing heat exchangers comprising at least one condensing heat exchanger 35 is provided in a compressed steam discharge line 70 in fluid communication with the compressor outlet 261. The condensing heat exchanger series 235 may include at least one auxiliary condensing heat exchanger 35 'in addition to a condensing heat exchanger 35, in which the auxiliary condensing heat exchanger 35' of the compressed steam line 70 is configured to indirectly heat exchange with the auxiliary refrigerant line 142. The auxiliary refrigerant line can be supplied with any selected auxiliary cooling stream. Examples of such auxiliary condensing heat exchangers 35 'will be described below. By operating such an auxiliary condensing heat exchanger 35 ', the capacity required from the auxiliary refrigerant stream 132 in the condensing heat exchanger 35 will be reduced.

A series of 235 condensing heat exchangers is configured to receive compressed steam from the compressor outlet 261. Inside the condensing heat exchanger 35, the compressed steam may be brought into indirect heat exchange contact with the auxiliary refrigerant stream 132, whereby during operation, heat is transferred from the compressed steam to the auxiliary refrigerant stream 132 in cooling mode. The auxiliary refrigerant flow control valve 135 is provided in the auxiliary refrigerant line 132.

The cooling mode controller 34 controls the cooling mode, determining the intensity with which heat is transferred from the compressed steam to the auxiliary refrigerant stream in accordance with the calorific value of the exhaust gas as applied to the heat demand. In the shown embodiment, the cooling mode controller 34 is in the form of a pressure controller PC and an auxiliary refrigerant flow control valve 135, which are functionally connected to each other.

The first gas-liquid separator 33 is located at the outlet end of the compressed steam discharge line 70. The vapor fraction discharge line 80 is fluidly coupled to the first gas-liquid separator 33, and is configured to transport the vapor fraction which is discharged from the first gas-liquid separator 33, far from the first gas-liquid separator 33. The vapor fraction thus withdrawn forms an off-gas.

A combustion device 220 is provided at the outlet end of the steam fraction abstraction line 80 for receiving at least a fuel portion from the vapor fraction in the vapor fraction abstraction line 80. A combustion device may comprise a plurality of combustion units, and / or it may include, for example, one or more of the following devices: a furnace, a boiler, an incinerator, a dual-fuel diesel engine, or combinations thereof. A boiler and a dual-fuel diesel engine can be connected to an electric generator.

A heat exchanger 85 for recovering cold exhaust gas may be provided in the vapor fraction discharge line 80 to maintain the cold present in the vapor fraction 80 by heat exchange with the cold recovery stream 86 before supplying the vapor fraction 80 to any combustion device.

Accordingly, the heat exchanger 85 for recovering cold exhaust gas may form part of a series of 235 condensing heat exchangers in the position of the auxiliary condensing heat exchanger 35 ', as a result of which the cold recovery stream 86 may comprise or consist of compressed steam in the compressed steam discharge line 70, and as a result wherein the vapor fraction 80 functions as auxiliary cooling stream 142. Preferably, the exhaust gas cold recovery heat exchanger 85 is configured in part of a compressed steam discharge line 70 through which compressed steam passes from the compressor outlet 261 to a condensing heat exchanger 35.

The condensed fraction discharge line 40 at its inlet end is fluidly connected to the first gas-liquid separator 33 and is configured to transport the condensed fraction far from the first gas-liquid separator 33. At its outlet end, the condensed fraction discharge line 40 is in fluid communication with point 48 input to line 8 supply of cryogenic raw materials. The entry point 48 is located at the junction with the cryogenic hydrocarbon composition and forms a connection between the cryogenic feed line 8 and the liquid hydrocarbon product line 90.

The pressure relief system 45 is located in the condensed fraction discharge line 40. The pressure relief system 45 may accordingly be connected to a level controller cooperating with the first gas-liquid separator 33 to maintain a constant amount of the condensed fraction that is held inside the first gas-liquid separator 33.

In FIG. 2 shows an embodiment generally similar to FIG. 1, in which a second gas-liquid separator is provided between the cryogenic feed line 8 and the liquid hydrocarbon product line 90. The second gas-liquid separator is usually provided in the form of an end flash separator 50. If the condensed fraction discharge line 40 is unloaded into the second gas-liquid separator, the second gas-liquid separator can replace the entry point 48 to the cryogenic feed line 8. Alternatively, an injection point 48 (shown by the dashed line in FIG. 2) to line 8 of the cryogenic hydrocarbon composition is used, whereby a combined stream 10 is first formed between the condensed reduced pressure fraction and the cryogenic hydrocarbon composition in line 8 of the cryogenic hydrocarbon composition. Thus, in such embodiments, in order from the cryogenic feed line 8, the cryogenic feed line 8 is in fluid communication with the cryogenic storage tank 210 through: flash flash separator 50, liquid hydrocarbon product line 90 which is fluidly coupled to the bottom of the flash flash separator 50.

An optional cryogenic pump (not shown in FIG. 2, but shown in FIG. 3) may be present on the liquid hydrocarbon product line 90 to facilitate transport of any liquid hydrocarbon product that is discharged from the flash flash separator to the cryogenic storage tank 210.

The liquefaction system 100 in the embodiment of FIG. 2 is in fluid communication with a cryogenic feed line 8 through a primary pressure relief system 5. The main pressure relief system 5 is in communication with the liquefaction system 100 through a crude liquid product line 1. The primary pressure relief system 5 may comprise a dynamic device, such as a turboexpander, and a static device, such as a Joule-Thomson valve, or a combination thereof. Many configurations are possible.

Side steam line 60, as shown in the embodiment of FIG. 2, may be connected to the flash flash separator 50 via flash flash line 64. Optionally (not shown in FIG. 3), the flash vapor line 64 is configured in an indirect heat exchange configuration with a compressed steam line 70, respectively using one of the auxiliary condensing heat exchangers 35 ', as described above.

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. Therefore, it is preferable that the by-product line 60 is also in fluid communication with the cryogenic storage tank 210, for example via the optional stripping gas supply line 230. An advantage of the latter connection is that it allows re-condensation of at least a portion of the stripping gas from the cryogenic storage tank 210 using a series of 235 condensing heat exchangers in addition to re-condensation of the flash vapor removed from the flash flash separator 50. In this embodiment, the gas holder for the cryogenic hydrocarbon composition includes both an end flash separator 50 and a cryogenic storage tank 210. If the liquid hydrocarbon product line 90 is relatively long, it can act as an additional source of stripping gas, and therefore also forms part of the gas holder for the cryogenic hydrocarbon composition.

The remaining components in the embodiment of FIG. 2 correspond to the components already described above with reference to FIG. one.

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 utilize single refrigerant cycle processes (typically a single mixed refrigerant cycle - SMR processes such as PRICO described in KRJohnsen and P. Christiansen's “LNG Production on floating platforms” presented at the Gastech 1998 conference ( 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 KRJohnsen and P.Christiansen); processes with two refrigerant cycles (for example, the often used process with mixed refrigerant and propane with the frequent abbreviation C3MR, described, for example, in US Pat. No. 4,440,408, or, for example, processes with two mixed refrigerants - DMR, an example of which is described in US 6658891 , or, for example, processes with two cycles in which each refrigerant cycle contains a single component refrigerant); and processes based on three or more compressor sequences for three or more refrigeration cycles, 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. 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 a C3MR or Shell DMR, is briefly illustrated in FIG. 3. It uses a cryogenic heat exchanger 180, in this case in the form of a spiral heat exchanger containing the lower and upper bundles (181 and 182, respectively) of pipes for a hydrocarbon product, the lower and upper bundles (183 and 184, respectively) of pipes for a light fraction of refrigerant (LMR) and a bundle of 185 pipes for the heavy fraction of 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 a waste 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 a separator 128. One or more heat exchangers is provided in a compressed refrigerant line 120 including, in the present example, at least one heat exchanger 124 using an ambient heat transfer medium and at least one pre-cooling heat exchanger 125 with a cooled main refrigerant. The MR separator 128 is in fluid communication with the lower tube bundle 183 for the LMR through the refrigerant light line 121, and with the tube bundle for the HMR through the heavy 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.

At the transition point between the upper (182, 184) and lower (181, 183) tube bundles, the HMR tube bundle 185 is fluidly coupled to the HMR line 141. The HMR line 141 is in fluid communication with the annulus 186 of the cryogenic heat exchanger 180 through the first HMR return line 143 in which the HMR control valve 144 is provided. Through said annulus 186 and in a 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 the HMR, the first HRM return line 143 is fluidly connected to the spent refrigerant line 150.

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 annular zone 186, and in a heat exchange configuration with each one of the upper and lower bundles 182 and 181 of hydrocarbon product tubes, respectively, and each one of bundles 183 and 184 pipes for LMR, and a bunch of 185 pipes for HMR.

The circuit around the first gas-liquid separator separates many of the elements explained above with reference to FIG. 1 and / or FIG. 2, and these elements will not be explained in detail again. In FIG. 3 shows one possible source of auxiliary refrigerant, which can also be used in the embodiments of FIG. 1 and 2: 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 inlet end is fluidly connected to the auxiliary refrigerant line 132 through a condensing heat exchanger 35, and at the outlet end, the second LMR return line 138 is ultimately connected to the spent refrigerant line 150, respectively, through the first HMR return line 143.

As another example of a series of 235 condensing heat exchangers, an auxiliary condensing heat exchanger 35 '(shown in FIG. 1) is provided in the form of a discharge heat exchanger 37, as shown in FIG. 3. The auxiliary refrigerant line 142 (described above with reference to FIG. 1) in this case is connected to one of the refrigerant circuits (for example, the primary refrigerant circuit 101) of the liquefaction system 100 to receive the separated stream from the liquefaction system 100. In the example shown in FIG. 3, the HMR line 141 is divided into an auxiliary refrigerant line 142 and a first HMR return line 143. A second HMR return line 148 (at its inlet end) is fluidly connected to the auxiliary refrigerant line 142 through the exhaust heat exchanger 37, and at the outlet end, this second HMR return line 148 is connected to the spent refrigerant line 150. Alternatively, the auxiliary refrigerant line 142 may, for example, be connected to a separated stream from the pre-cooling circuit of the refrigerant from the liquefaction system 100.

In the embodiment of FIG. 3, a heat exchanger 85 for recovering a cold exhaust gas is placed in a stripping gas supply line 230. The heat that could be obtained by the stripping gas in its way from the cryogenic storage tank 210 to the by-product compressor 260 can be partially or completely removed by the steam fraction 80, before the stripping gas is supplied from the stripping gas supply line 230 to the by-product compressor 260 and / or in line 60 by-product steam. This can be especially useful if the cryogenic storage tank 210 is located at a considerable distance D, for example more than 1 km (for example, D = about 4 km), from the by-product compressor 260. The transport compressor 270 may also be placed in the stripping gas supply line 230, in place of the cryogenic storage tank 210 (e.g., 100 m from the cryogenic storage tank 210). In addition to the leakage of heat to the stripping gas supply line 230, such a transport compressor 270 also adds enthalpy to the stripping gas.

In alternative embodiments, 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. In such embodiments, heat exchange for recovering cold in the heat exchanger 85 for recovering cold exhaust gas complements the rate of formation of the cryogenic hydrocarbon composition.

Alternatively, a heat exchanger 85 for recovering cold exhaust gas can be configured in part of a compressed steam discharge line 70 through which compressed steam passes from a compressor outlet 261 to a condensing heat exchanger 35.

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

A cryogenic hydrocarbon composition 8 containing a nitrogen and methane-containing liquid phase is provided at an initial pressure of 1 to 2 bar abs. (0.2-1.5 MPa) 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 of less than -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 formed 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 consisting 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.

If necessary, the hydrocarbon feed stream 110 may be pretreated to reduce and / or remove 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 0.5 mol% to 1.8 mol% of nitrogen, have an initial temperature of from -165 ° C to -120 ° C and a liquefaction pressure of from 15 to 120 bar abs. (1.5-12.0 MPa), if the system 5 of the main pressure relief is provided. If such a main pressure relief system 5 is not provided, as, for example, in the embodiment of FIG. 1, the liquefaction pressure is preferably in the range of 1 to 15 bar abs. (0.1-1.5 MPa), preferably at an initial pressure in the range of 1 to 2 bar abs. (0.1-0.2 MPa) for direct delivery of the cryogenic hydrocarbon composition 8 in the form of a crude liquefied stream. In other cases, the cryogenic hydrocarbon composition 8 can be obtained from the crude liquefied stream 1 using the main pressure relief of the crude liquefied stream 1 from the pressure of the liquefaction to the initial pressure. Flash vapor usually forms during such a pressure release.

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. (1.5 MPa) is high enough to avoid excessive formation of flash vapor when depressurizing to an initial pressure of 1-2 bar abs. (0.1-0.2 MPa).

The invention is particularly useful in embodiments in which the crude liquefied stream 1 contains from 1 mol.% To 1.8 mol.% Nitrogen.

In the embodiment of FIG. 1, the cryogenic hydrocarbon composition 8 enters directly into line 90 of the liquid hydrocarbon product. In the embodiments of FIG. 2 and 3, only the non-evaporated fraction of the cryogenic hydrocarbon composition 8 is discharged to the liquid hydrocarbon product line 90 through the flash flash separator 50.

Side steam 60 is withdrawn from the cryogenic hydrocarbon composition 8. This may respectively include stripping gas from the cryogenic storage tank 210, possibly via a stripping gas supply line 230, if such a line is provided. Stripping gas is formed by adding heat to at least a portion of the cryogenic hydrocarbon composition, whereby a portion of said methane-containing liquid phase evaporates to form said stripping gas. In embodiments comprising an optional flash flash separator 50, sidestream 60 removal, instead of or in addition to stripping gas, may include flash flash vapor removal from the flash flash separator 50 via flash line 64.

Such selected by-product steam 60 is then compressed to a treatment pressure in the range of 2 to 15 bar abs., Thereby producing compressed steam 70 in the compressed-steam discharge line 70 at the outlet 261 of the by-product compressor 260.

Compressed steam 70 passes through a series of 235 condensing heat exchangers, thereby forming a partially condensed intermediate stream from compressed steam 70. The partially condensed intermediate stream contains a condensed fraction and a vapor fraction. A partially condensed intermediate stream is formed by partially condensing the compressed steam 70 by heat exchange of the compressed steam 70 with at least auxiliary refrigerant stream 132, whereby heat is transferred from the compressed steam 70 to the auxiliary refrigerant stream 132 in cooling mode.

Optionally, heat also enters the auxiliary cooling streams, such as, for example, auxiliary refrigerant stream 142 and / or exhaust gas transported to the vapor fraction discharge line 80.

The partially condensed intermediate stream is separated into a condensed fraction and a vapor fraction, with a separation pressure of 2 to 15 bar abs. (0.2-1.5 MPa). For this, a partially condensed intermediate stream can be supplied to the first gas-liquid separator 33. The vapor fraction is discharged from the first gas-liquid separator in the form of exhaust gas through the steam fraction discharge line 80. The vapor fraction 80 has a selected calorific value. The calorific value can be selected according to the heat demand.

Accordingly, at least a fuel portion of the vapor fraction 80 is supplied to the combustion device 220 at a fuel gas pressure that does not exceed the separation pressure.

The cooling mode in the condensing heat exchanger 35 is automatically adjusted to control the calorific value of the exhausted steam fraction 80. In embodiments in which the steam fraction 80 is supplied to one or more selected 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 a calorific value that meets the need. Accordingly, the auxiliary refrigerant flow control valve 135 can be adjusted using a pressure regulator PC to maintain a predetermined target flow rate of the auxiliary refrigerant stream 132 through a condensing heat exchanger 35. The actual pressure in the vapor fraction discharge line 80 is due to a causal relationship with the controlled calorific value. The pressure regulator PC will be configured to reduce the open part 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 80. On the other hand, the pressure regulator PC 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 30 mol.% To 90 mol.% Nitrogen, preferably from 30 mol.% To 70 mol.% Nitrogen or from 45 mol.% To 90 mol.% Nitrogen, more preferably from 30 mol. % to 60 mol% of nitrogen, even more preferably from 45 mol% to 70 mol% of nitrogen, most preferably from 45 mol% to 60 mol% of nitrogen.

To achieve a nitrogen content of about 60 mol%, a sufficient amount of methane must be re-condensed from the by-product steam stream. It was found that this can be done using a compressed steam flow pressure of 4 to 8 bar abs. (0.4-0.8 MPa), and the achievement of the temperature of the partially condensed intermediate stream from -150 ° C to -135 ° C.

Returning to the first gas-liquid phase separator 33, the condensed fraction is discharged from the first gas-liquid separator 33 through the condensed fraction discharge line 40. Typically, the condensed fraction is expected to contain less than 10 mol% of nitrogen. With a higher nitrogen content, the cryogenic hydrocarbon composition in the cryogenic storage tank 210 may have a nitrogen content exceeding the desired maximum of about 1.1 mol%. A portion of the reduced pressure recirculate is formed from the condensed fraction in the condensed fraction discharge line 40 by depressurizing the condensed fraction to a pressure not lower than the initial pressure. A portion of the reduced pressure recirculate is then introduced into the cryogenic hydrocarbon composition, for example, through the point 48 of entry into the cryogenic hydrocarbon composition 8, through a flash flash separator 50, or even directly into the liquid hydrocarbon product line 90.

The auxiliary refrigerant stream 132 preferably has a boiling point under standard conditions at a lower temperature than the boiling point of the overhead vapor stream 70 under standard conditions (standard conditions according to ISO 13443: 15 ° C at an absolute pressure of 1.0 atmosphere (0, 1 MPa) This facilitates the re-condensation of the relatively high amount of methane present in the by-product steam stream 60, which in turn facilitates the controllability of the methane content in the vapor fraction 80. For example, auxiliary refrigerant can t contain from 5 mol.% to 75 mol.% nitrogen. In a preferred embodiment, the auxiliary refrigerant stream is formed by a discharge stream from the main refrigerant stream, more preferably by a light stream of a refrigerant stream. This latter case is illustrated in Fig. 3, but can also be used in the embodiment of Fig. 1 and 2. Such a discharge 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 heat removal from the stream 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 for partial condensation of the stream 70 of compressed steam. However, the use of a flow 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.

Preferably, the separation pressure is in the range of 4 to 8 bar abs. (0.4-0.8 MPa), moreover, this pressure meets the requirements for low-pressure fuel gas flow, suitable for transporting the exhaust gas to the combustion device 220 without the need for additional compression. A higher pressure can be selected if the combustion device 220 is located at a relatively large distance from the first gas-liquid phase separator, under these conditions, an additional pressure drop can be expected during the transportation of the exhaust gas to the combustion device 220.

Preferably, the processing pressure exceeds the separation pressure by more than about 1 bar (0.1 MPa) in order to allow pressure drop caused by the passage of compressed steam 70 through a series of 235 condensing heat exchangers, but preferably not more than 5 bar (0.5 MPa) ), since this will require excessive compression power of the by-product compressor 260.

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%.

Elements of various configurations of the series 235 condensing heat exchangers, which have been described above with reference to FIG. 1-3 may be combined to form new embodiments.

As an example in FIG. 4 shows an embodiment in which a series of 235 condensing heat exchangers, in addition to the condensing heat exchanger 35, comprises three auxiliary condensing heat exchangers: one in the form of a flash recovery heat exchanger 36 for instantaneous evaporation; another in the form of a heat exchanger 85 for recovering cold exhaust gas; and one heat exchanger 38 using a heat carrier with an ambient temperature. The cold recovery heat exchanger 36 of flash vapor is located adjacent to the condensing heat exchanger 35, while the compressed steam 70 is brought into indirect heat exchange contact with the flash vapor line 64. Near the heat exchanger 36 for recovering cold instantaneous vapor vapor, there is a heat exchanger 85 for recovering cold exhaust gas, in which the compressed steam 70 is brought into indirect heat exchange contact with the steam fraction line 80. Near the heat exchanger 85 for recovering cold exhaust gas and on the other side to the outlet 261 of the by-product compressor 260 is a third auxiliary condensing heat exchanger in the form of a heat exchanger 38 using an ambient temperature coolant. A heat exchanger 38 using a heat carrier with an ambient temperature can be made in the form of an air-using heat exchanger in which the ambient air stream is brought into indirect heat exchange contact with a compressed steam line 70, or in the form of a water-using heat exchanger in which the water stream is brought into an indirect heat-exchange contact with a line 70 of compressed steam. In the same manner, as shown with reference to FIG. 3, the auxiliary refrigerant source 132 for the condensing heat exchanger 35 may be the LMR line 131 of the primary refrigerant circuit 101 (shown in FIG. 3 but not shown in FIG. 4). The second LMR return line 138 at its inlet end is fluidly connected to the auxiliary refrigerant line 132 through a condensing heat exchanger 35, and at its outlet end is ultimately connected to the spent refrigerant line 150 (not shown in FIG. 4).

The remaining elements shown in FIG. 4 and optional elements not shown in FIG. 4 are similar to the elements described above with reference to FIG. 1-3, and will not be described here again. Similar to that shown and described in the embodiment of FIG. 3, the cryogenic storage tank 210 may be located at a considerable distance D from the by-product compressor 260.

Static simulations were carried out in the embodiment shown in FIG. 3, provided that it operates both in storage mode (tables 1 and 2) and in boot mode (table 3). In all cases, it was assumed that the cryogenic hydrocarbon composition 8 consists of more than 90 mol.% A mixture of nitrogen and methane (98,204 mol.%). The example in table 1 is the base case, in which the amount of nitrogen is 0.77 mol%, and methane 95.89 mol%, which gives a total of more than 96.6 mol%. In the example of table 4, the amount of nitrogen is higher, 1.53 mol.%. The residue in both cases consists of a mixture of alkanes of the C2-C4 group, consisting of ethane, propane, normal butane and isobutane; and carbon dioxide. These components leave the process with a stream of 90 liquid hydrocarbon product.

The calorific value of the exhaust gas in this basic version was 62 MW, which was aimed at satisfying the boiling demand for the selected heat exchanger over an average period with ambient temperature. The selected heat exchanger delivers process heat to a number of modules, including an inlet separator head gas preheater, an acid gas removal unit reboiler and fractionation line reboilers, in a selected liquefaction system designed to deliver about 6 million tons / year (megatons per year) of liquefied natural gas.

The compressor power consumed by the by-product compressor 260 was 1.1 MW in the base nitrogen embodiment, compared to 1.3 MW in the high nitrogen version. The cooling capacity consumed in the base nitrogen variant was 2.8 MW (1.0 MW in the exhaust flow heat exchanger 37 and 1.8 MW in the condensing heat exchanger 35), while in the high nitrogen variant it was 3.5 MW (1.1 MW in the heat exchanger 37 of the exhaust stream and 2.4 MW in the condensing heat exchanger 35).

The calorific value provided in the off-gas 80 was, in the high-nitrogen version, 50 MW. This was intended for the operation of the same liquefaction system, adopted for modeling the base case, but at a higher ambient temperature (summer period), and not at an average ambient temperature. Of course, at higher ambient temperatures, the need for process heat is lower. It is interesting to note that the lower heat demand was consistent with the circuit of FIG. 3, even though more nitrogen had to be vented with the off-gas. The amount of nitrogen in the stream of 90 liquid hydrocarbons was still within the maximum allowable level of 1.1 mol%.

Similarly, it is possible to adjust the calorific value in the same circuit to about 80 MW in order to satisfy the need for process heat in the winter.

Table 3 shows the simulation results of the variant with a high nitrogen content corresponding to table 2, in boot mode. In the calculations, an additional consumption of stripping gas of 0.7 mol.% LNG supplied to the vessel was adopted.

The cooling capacity in the condensing heat exchanger was adjusted to 3.0 MW to maintain the same calorific value of 50 MW in the steam fraction 80. In addition, the cooling capacity in the heat exchanger 37 of the exhaust flow was increased, compared with the storage mode of table 3, to 1.45 MW, due to a few degrees warmer side steam in line 60 of the side steam.

Table 4 shows the results of the simulation carried out in the embodiment shown in FIG. 4, subject to operation in storage mode. In this case, the composition of the cryogenic hydrocarbon composition 8 was the same as in the base case, which forms the basis for table 1. The transport compressor 270 can also be placed in the stripping gas supply line 230, in place of the cryogenic storage tank 210. It is assumed that the heat exchanger 38, using a coolant with an ambient temperature, was a water-cooled heat exchanger.

The by-product compressor capacity in the variant of table 4 was 2.2 MW, compared to 1.1 MW in the variant of table 1, this difference is due to the fact that the temperature of the by-product steam 60 is higher in the variant of table 4, resulting in a lower density. This is because the flash vapor stream 64 and the flash gas stream 230 are used to cool the compressed steam 70. However, only 2.1 MW of cooling capacity is used from the main cryogenic refrigerant circuit compared to 2.8 MW for the variant of table 1. Compressed steam temperature 70, obtained from the by-product compressor 260, is first lowered to + 21 ° C by dissipating 1.4 MW of power into the surrounding water; followed by the transfer of 0.6 MW of power to the off-gas using indirect heat exchange in the heat exchanger 85 for the recovery of cold exhaust gas, thereby lowering the temperature of the stream of compressed steam 70 to -29 ° C; followed by the transfer of 1.0 MW of power to a flash vapor pair 64 in the heat exchanger 36 for recovering cold instant flash vapor by indirect heat exchange with a flash vapor stream 64, thereby lowering the temperature of the compressed steam stream 70 to -109 ° C; followed by the final condensing heat transfer in the condensing heat exchanger 35 with the auxiliary refrigerant stream 132 in the form of a discharge stream of light fraction of the refrigerant from the liquefaction system 100 to lower the temperature to -139 ° C, using 2.1 MW. This is the only external cooling capacity needed to partially condense the compressed steam stream 70.

Finally, the scope of the invention was investigated by further modeling using the embodiment of FIG. 4. The results are shown in table 5. In options 1-5, it was studied how the invention can work for increasing nitrogen contents in cryogenic hydrocarbon composition 8, while maintaining a constant heat output of 62 MW in the vapor fraction 80 of the exhaust gas. It can be noted that the heat output can be maintained by increasing the cooling capacity in the condensing heat exchanger 35 (reflected in Table 5 by the lower temperature in the first gas-liquid separator 33). At 1.8 mol% of nitrogen in the cryogenic hydrocarbon composition 8, the amount of nitrogen in the stream 90 of the liquid hydrocarbon product begins to exceed the maximum allowable level of about 1.1 mol%. Thus, the invention works for nitrogen contents in a crude liquefied product of up to about 1.8 mol%, for example 1.7 mol%.

Options 6 and 7 show that the heat capacity in the exhaust gas can be reduced by increasing the cooling capacity in the condensing heat exchanger. However, the disadvantage of this is the re-condensation of more nitrogen, which ultimately enters the stream 90 of the liquid hydrocarbon product.

Comparative options 7 and 8 show that the cooling capacity in the condensing heat exchanger can be reduced by increasing the pressure of the compressed steam stream 70 (which allows a higher separation pressure in the first gas-liquid separator 33).

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 (38)

1. The method of removing nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase, and this method includes: - providing a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase at an initial pressure of 1 to 2 bar abs. (0.1-0.2 MPa); - selection of side steam from the cryogenic hydrocarbon composition; - compression of the specified side steam to the processing pressure in the range from 2 to 15 bar abs. (0.2-1.5 MPa), thereby obtaining compressed steam; - the formation of a partially condensed intermediate stream from compressed steam containing the condensed fraction and the vapor fraction, and this formation includes partial condensation of the compressed steam by heat exchange of the compressed steam with the auxiliary refrigerant stream and, thus, the heat from the compressed steam into the auxiliary refrigerant stream in cooling mode; - separation of the condensed fraction from the vapor fraction in the first gas-liquid separator, with a separation pressure of 2 to 15 bar abs. (0.2-1.5 MPa); - removal of the vapor fraction from the first gas-liquid separator in the form of exhaust gas, wherein said vapor fraction has a calorific value; - removal of the condensed fraction from the first gas-liquid separator; - depressurization of the condensed fraction to a pressure not lower than the initial pressure, thereby forming a portion of the reduced pressure recirculate; - the introduction of a portion of the recirculated reduced pressure in the cryogenic hydrocarbon composition; - adjustment of the cooling mode to regulate the calorific value of the vapor fraction discharged from the first gas-liquid separator. 2. The method according to claim 1, further comprising supplying the vapor fraction to the combustion device at a fuel gas pressure not exceeding the separation pressure. 3. The method according to claim 1, wherein the by-product steam from the cryogenic hydrocarbon composition comprises stripping gas obtained by adding heat to at least a portion of the cryogenic hydrocarbon composition, whereby a portion of said methane-containing liquid phase evaporates to form said stripping gas. 4. 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, thereby leading to liquefaction of the vaporous feedstock from the feedstock to obtain a crude liquefied stream; and - obtaining a cryogenic hydrocarbon composition from a crude liquefied stream. 5. The method of claim 4, wherein said preparation of a cryogenic hydrocarbon composition from said liquefied stream includes depressurizing the crude liquefied stream from the liquefaction pressure to the initial pressure. 6. The method of claim 5, wherein the flash vapor is generated during said depressurization, and wherein the side steam from the cryogenic hydrocarbon composition comprises said flash flash. 7. The method of claim 6, wherein the flash vapor is separated from the cryogenic hydrocarbon composition in a second gas-liquid separator. 8. The method according to claim 7, in which the crude liquefied stream enters at a reduced pressure into a second gas-liquid separator, and wherein said introduction of a portion of reduced pressure recirculate to the cryogenic hydrocarbon composition is carried out by introducing a portion of reduced pressure recirculate into one element from the group consisting of a liquefied a stream at reduced pressure passing through a second gas-liquid separator and a second gas-liquid separator. 9. The method according to any one of paragraphs. 4-8, in which the auxiliary refrigerant stream is formed by a discharge stream from the main refrigerant stream. 10. The method according to any one of paragraphs. 1-8, in which the auxiliary refrigerant contains from 5 to 75 mol.% Nitrogen. 11. The method according to any one of paragraphs. 1-8, in which the vapor fraction contains from 30 to 90 mol.% Nitrogen. 12. The method according to any one of paragraphs. 1-8, in which the condensed fraction contains less than 10 mol.% Nitrogen. 13. The method according to any one of paragraphs. 1-8, in which the temperature of the partially condensed intermediate stream is from -150 to -135 ° C. 14. The method according to any one of paragraphs. 1-8, in which the first gas-liquid separator is essentially the only equilibrium stage in which the vapor and liquid inside the gas-liquid separator are in thermodynamic equilibrium. 15. A device for removing nitrogen from a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase, and this device contains: - a gas holder for a cryogenic hydrocarbon composition containing a nitrogen and methane-containing liquid phase at an initial pressure; - a line of secondary steam, fluidly connected to the gas tank and configured to select side steam from the gas tank; - a by-product compressor located in the by-product line configured to compress at least said by-product steam to a treatment pressure that exceeds the initial pressure to provide compressed steam at the by-product compressor outlet; at least one condensing heat exchanger in fluid communication with the outlet of the compressor and configured to receive compressed steam and form a partially condensed intermediate stream from the compressed steam, the partially condensed intermediate stream containing a condensed fraction and a vapor fraction, and said condensing the heat exchanger, in addition, is configured to bring compressed steam into heat exchange contact with the auxiliary refrigerant stream, in p result of which during operation receives heat from the compressed vapor to the auxiliary refrigerant flow in a cooling mode; a first gas-liquid separator configured to receive a partially condensed intermediate stream and to separate the condensed fraction from the vapor fraction at a separation pressure; - a steam fraction discharge line fluidly coupled to the first gas-liquid separator, configured to transport the vapor fraction far from the first gas-liquid separator; a condensed fraction discharge line adapted to transport the condensed fraction far from the first gas-liquid separator, said condensed fraction discharge line on the inlet side being fluidly connected to the first gas-liquid separator and on the outlet side fluidly connected to the inlet point at the junction with cryogenic hydrocarbon composition; - a pressure relief system placed in the discharge line of the condensed fraction, configured to depressurize the condensed fraction to a pressure not lower than the initial pressure, thereby forming a portion of the reduced pressure recirculate; - a cooling mode controller configured to adjust the cooling mode to control the calorific value of the vapor fraction discharged from the first gas-liquid separator. 16. The device according to p. 15, in which the first gas-liquid separator consists of a drum that does not contain any internal elements forming a vapor / liquid contacting section. 17. The device according to p. 15 or 16, in which the first gas-liquid separator is essentially the only equilibrium stage, in which the vapor and liquid inside the gas-liquid separator are in thermodynamic equilibrium.

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