KR20120040700A - Method for treating a multi-phase hydrocarbon stream and an apparatus therefor - Google Patents

Abstract

Polyphase hydrocarbon stream 145 is treated to provide a treated liquid hydrocarbon stream 165, such as a liquefied natural gas (LNG) stream. The polyphase hydrocarbon stream 145 is directed to a first gas / liquid separator 150, which is subjected to a first pressure to provide a first separator hydrocarbon vapor stream 205 and a first separator bottom stream 155. Is separated from. The first separator bottoms stream 155 is then subjected to a second gas / liquid separator (at a second pressure lower than the first pressure to provide a second separator hydrocarbon vapor stream 175 and a treated liquid hydrocarbon stream 165). 160). The second separator hydrocarbon vapor stream 175 is compressed in an overhead stream compressor 185 to provide a stripping vapor stream 185 that is directed to the first gas / liquid separator 150.

Description

METHOD FOR TREATING A MULTI-PHASE HYDROCARBON STREAM AND AN APPARATUS THEREFOR}

The present invention relates to a method and apparatus for treating a multiphase hydrocarbon stream.

This method and apparatus provide a treated liquid hydrocarbon stream. A low pressure fuel gas stream may additionally be provided.

A common source for a multiphase hydrocarbon stream is a multiphase stream produced from natural gas by forming a natural gas stream or a multiphase stream comprising vapor phase and liquid phase, for example, through pressure change and / or cooling of natural gas. Thus, the methods described herein may be used to provide a treated liquid hydrocarbon stream in the form of a liquefied natural gas (LNG) stream.

Natural gas is not only a source of various hydrocarbon compounds but also a useful fuel source. Often, for a number of reasons it is desirable to liquefy natural gas in a liquefied natural gas (LNG) plant at or near the source of the natural gas stream. As an example, natural gas can be transported and stored more easily as a liquid than gaseous form, because the liquid occupies less volume and does not need to be stored at high pressure.

Usually, natural gas, consisting mostly of methane, enters the LNG plant at elevated pressures and is pretreated to produce a purified feed stream suitable for liquefaction at cryogenic temperatures. The purified gas is processed through a plurality of cooling stages using a heat exchanger to gradually reduce its temperature until liquefaction is achieved. Thereafter, the liquid natural gas is further cooled and expanded to a final atmospheric pressure suitable for storage and transportation. Flashed vapor from each expansion can be used as a source of fuel gas.

Some hydrocarbon streams, such as natural gas, contain significant amounts of nitrogen, so fuel gas and any liquefied hydrocarbon streams produced undesirably high nitrogen levels unless special measures are taken to remove at least some of the nitrogen from the hydrocarbon stream. It may also include. Many LNG specifications require less than 1 mole percent nitrogen in the final product.

US 2008/0066493 discloses a process for treating liquefied natural gas to provide a liquid natural gas stream having a reduced content of low boiling point components such as nitrogen (N ₂ ). The method comprises the steps of expanding liquefied natural gas to provide an expanded multiphase fluid, a bottom liquid stream having a reduced content of low boiling point components and an overhead gas stream rich in low boiling point components such as nitrogen Introducing a multiphase fluid into the column below the gas-liquid contact portion to obtain The bottom liquid stream is sent to a flash vessel. The overhead gas stream enriched in the low boiling point component is heated in a heat exchanger and then compressed to fuel gas pressure to obtain fuel gas. The recycle stream is separated from the fuel gas and is at least partially condensed inside the heat exchanger for the overhead gas stream enriched in the low boiling point component and as a reflux stream and above the gas-liquid contact portion. Flows into. In many embodiments of US 2008/0066493, the second gas stream (from the flash vessel) is also heated in a heat exchanger, compressed to fuel gas pressure and added to the circulating stream.

Thus, at least the cryogenic portion present in the overhead gas stream is used to recondense the circulating stream to create a backflow, which cannot be used to cool other process streams elsewhere in the process.

In a first aspect, the present invention provides a method of treating a multiphase hydrocarbon stream to provide a treated liquid hydrocarbon stream, the method comprising at least:

Generating a multiphase hydrocarbon stream from natural gas comprising a vapor phase and a liquid phase;

Moving said polyphase hydrocarbon stream to a first gas / liquid separator;

Separating the multiphase hydrocarbon stream at a first pressure in the first gas / liquid separator to provide a first separator hydrocarbon vapor stream and a first separator bottoms stream comprising hydrocarbon and nitrogen;

Separating the first separator bottoms stream in a second gas / liquid separator at a second pressure lower than the first pressure to provide a liquid hydrocarbon stream and a second separator hydrocarbon vapor stream treated in the form of LNG;

Compressing the second separator hydrocarbon vapor stream in an overhead stream compressor to provide a stripping vapor stream; And

Moving the stripping vapor stream to the separator at a level that is gravitationally lower than the level at which the multiphase hydrocarbon stream is directed to the first gas / liquid separator.

In a further aspect, the present invention provides an apparatus for treating a multiphase hydrocarbon stream consisting of a liquid phase and a vapor phase to provide a liquid hydrocarbon stream treated in the form of LNG, the apparatus comprising:

Means for producing a multiphase hydrocarbon stream from natural gas and comprising at least one of a liquefaction unit and at least one hydrocarbon stream expansion device;

A first inlet configured to receive the multiphase hydrocarbon stream and to separate the stream into a first separator hydrocarbon vapor stream and a first separator bottoms stream comprising hydrocarbons and nitrogen, and to direct the multiphase hydrocarbon stream to a first gas / liquid separator A first outlet for discharging the first separator hydrocarbon vapor stream from the first gas / liquid separator, a second outlet for discharging the first separator bottom stream from the first gas / liquid separator, and stripping into the first gas / liquid separator A first gas / liquid separator having a second inlet located at a gravity lower level than the first inlet for conveying a vapor stream;

A first receiving the first separator bottoms stream and separating the stream into a liquid hydrocarbon stream and a second separator hydrocarbon vapor stream treated in the form of LNG, and transferring the first separator bottoms stream to a second gas / liquid separator A first inlet in fluid communication with a second outlet of the gas / liquid separator, a first outlet for exhausting the second separator hydrocarbon vapor stream from the second gas / liquid separator, and a treated liquid hydrocarbon stream from the second gas / liquid separator. A second gas / liquid separator having a second outlet to discharge;

A bottom stream expansion device disposed between the second outlet of the first gas / liquid separator and the first inlet of the second gas / liquid separator to reduce the pressure of the first separator bottom stream; And

-Compress the second separator hydrocarbon vapor stream to provide a stripping vapor stream, inlet in fluid communication with the first outlet of the second gas / liquid separator to receive the second separator hydrocarbon vapor stream, and to discharge the stripping vapor stream And an overhead stream compressor having an outlet in fluid communication with a second inlet of the first gas / liquid separator.

Embodiments of the invention will now be described by way of example only with reference to the attached non-limiting drawings:

1 is a schematic of a method and apparatus for treating a multiphase hydrocarbon stream according to one embodiment.
2 is a schematic diagram of a method and apparatus for liquefying a hydrocarbon feed stream comprising a method and apparatus for processing a multiphase hydrocarbon stream.

To illustrate the present description, a single reference numeral will be given to a line and a stream carried in that line.

The methods and apparatus disclosed herein propose an improvement in component separation of the multiphase stream in two subsequent steps of two gas / liquid separators operating at different pressures. The second separator hydrocarbon vapor stream from the second gas / liquid separator is compressed in an overhead stream compressor and returned to the first gas / liquid separator as a stripping vapor stream.

Advantageously, the present invention provides a method and apparatus for treating a multiphase hydrocarbon stream to provide a treated liquid hydrocarbon stream that does not require a cold portion in the overhead gas stream to be used to produce the countercurrent stream.

Advantageously, the method and apparatus of the present invention utilize stripping steam in a first gas / liquid separator provided by compression of the vapor stream from a second gas / liquid separator to enhance component separation. Generating stripping vapor from the second gas stream allows the second gas stream to be used to aid in component separation without the need to recondense the second gas stream or portions thereof.

Thus, in US 2008/0066493 the low temperature portion of the first separator hydrocarbon vapor stream, which was necessary to produce a countercurrent to achieve the desired efficiency in component separation, is now free to be used in any way. Of course, the present invention does not exclude the option that a countercurrent stream may still be produced (using a cold section from the first separator hydrocarbon vapor and / or external refrigerant) and may be used to further enhance component separation, which is now completely optional. to be. One group of embodiments of the invention does not require a backflow stream as used in US 2008/0066493.

One or more hydrocarbon stream expansion devices and the first and second gas / liquid separators may form part of the LNG end flash system. Likewise, the pressure reduction of the at least partially liquefied hydrocarbon stream to provide a multiphase hydrocarbon stream and subsequent separation in the first and second gas / liquid separators may form part of the LNG end flash process.

Therefore, the production of the multiphase hydrocarbon stream from natural gas is carried out in the following steps,

Providing a hydrocarbon feed stream from the natural gas stream at elevated pressure;

Extracting a continuous hydrocarbon stream from the hydrocarbon feed stream;

Moving the continuous stream to a cooling and liquefaction unit in which the continuous stream is cooled and at least partially liquefied to provide at least partially liquefied hydrocarbon streams; And

Moving the at least partially liquefied hydrocarbon stream to the inlet of the at least one hydrocarbon stream expansion device and reducing the pressure of the at least partially liquefied hydrocarbon stream to provide a multiphase hydrocarbon stream.

The multiphase stream may consist of vapor phase and liquid phase. In particular when provided in the form of LNG, the treated liquid hydrocarbon stream produced in accordance with the invention may have a specification suitable for it to be vaporized and used as a network gas.

Without being bound to the following description by analogy, the Applicant believes that an overhead stream compressor acts as a special reboiler by providing compressed heat to the second separator hydrocarbon vapor stream, thereby acting as a special reboiler for the first gas / liquid separator. It is proposed to provide a stripping vapor stream at a higher pressure and temperature than the second hydrocarbon vapor stream. This stripping vapor stream enhances the separation of lower boiling components such as nitrogen from the expanded hydrocarbon stream in the first gas / liquid separator. The lower boiling component is withdrawn to the first separator hydrocarbon vapor stream.

If the first separator hydrocarbon vapor stream is not pure nitrogen, but it also consists of an inventory of hydrocarbons, it can be used as fuel gas. Therefore, this method,

Directing a low pressure (LP) fuel gas stream from the first separator hydrocarbon vapor stream; And

Moving the low pressure fuel gas stream to the combustion device at a fuel gas pressure not higher than the pressure of the first separator hydrocarbon vapor stream. The first pressure of the first gas / liquid separator may be equal to or higher than the fuel gas pressure. Advantageously neither the first separator hydrocarbon vapor stream nor the low pressure fuel gas stream is compressed prior to use in the combustion device.

In US 2008/0066493, the N ₂ and other vapor components which are separated in the tower are compressed and discharged into the high pressure fuel gas stream. Table 1 of US 2008/0066493 shows that a natural gas transfer stream having a nitrogen content of 3.05 mol% provides a liquefied natural gas stream having a nitrogen content of 0.65 mol% and a fuel gas having a nitrogen content of 24 mol%. An embodiment to be processed is disclosed. However, high nitrogen content fuel gas streams generally present significant problems when used in fuel gas turbines used to drive compressors or generators within a liquefaction plant. For example, many aeroderivative gas turbines are currently unable to tolerate nitrogen content in excess of 15 mol% in fuel gas.

Thus, in a preferred embodiment of the present method and apparatus, a first separator hydrocarbon vapor stream is used as the low pressure fuel gas stream. Fuel gases with large amounts of nitrogen can still be used as low pressure fuel gases, for example for fueling furnaces, boilers and / or dual fuel diesel engines.

As used herein, the term "low pressure" in a low pressure fuel gas stream is relative to the high pressure fuel gas stream needed to fuel the gas turbine. For the purpose of this specification, the low pressure fuel gas may be at a pressure in the range of 2 to 15 bara, in particular in the range of 2 to 10 bara. The high pressure (HP) fuel may be at a pressure in excess of 15 bara, generally in the range of 15 to 40 bara, in particular in the range of 20 to 30 bara.

Advantageously the first gas / liquid separator may be operated above a suitable fuel gas pressure, so that the first separator hydrocarbon vapor stream advantageously is at a sufficiently high pressure that does not require any compression or any extensive compression before use. May be provided. Thus, it is desirable to select the first pressure of the first gas / liquid separator so that the first separator hydrocarbon vapor stream is provided above the desired fuel gas pressure.

Particularly when used as a low pressure fuel, the first separator hydrocarbon vapor stream of the present invention may comprise N ₂ in a wide range, for example in the range from 30 mol% to 95 mol%, more preferably in the range from 60 mol% to 95 mol%. It may be.

Thus, the present invention may advantageously be used to provide a low pressure fuel gas stream suitable for use in combustion equipment such as furnaces or incinerators or in dual fuel diesel engines that may be used, for example, in generators. The low pressure fuel gas stream may be derived from the first separator hydrocarbon vapor stream by warming up. The first separator hydrocarbon vapor stream can be sent to any suitable heat exchanger device in which it can be used to cool the process stream. Advantageously, the process stream may be provided in the form of a portion of natural gas to cool this portion of the natural gas.

In order to provide a high pressure (HP) fuel gas stream suitable for use as fuel for a gas turbine, the treatment methods and apparatus disclosed herein may be included in a method and apparatus for liquefying a hydrocarbon transfer stream. The high pressure fuel gas may be extracted from the hydrocarbon feed stream prior to liquefaction. This is advantageous because the hydrocarbon feed stream may have a low nitrogen content as compared to the low pressure fuel gas stream derived from the first separator hydrocarbon vapor stream. In addition, the hydrocarbon feed stream is a high pressure stream, so no further pressurization of a portion of this stream for use as a fuel gas stream is required. Thus, no high pressure fuel gas compressor is required. If necessary, where the pressure of the hydrocarbon transport stream is too high, the pressure of the extracted fuel gas may optionally be reduced before use as fuel.

The method disclosed herein is also advantageous because it does not use a gas stream produced by expansion of the liquefied hydrocarbon stream as a high pressure fuel gas stream. This gas stream generated by a gas / liquid separation step, such as an end flash process, will have a higher content of lower boiling point components such as nitrogen as compared to the liquid product produced by the separator.

Referring to the drawings, FIG. 1 shows a method and apparatus 1 for treating a polyphase hydrocarbon stream 145 according to the first embodiment. Polyphase hydrocarbon stream 145 is derived from natural gas. Multiphase hydrocarbon stream 145 comprises a vapor phase and a liquid phase. One embodiment of how the polyphase hydrocarbon stream 145 can be provided is reviewed in more detail below with reference to FIG. 2.

The polyphase hydrocarbon stream 145 is directed to the first inlet 148 of the first gas / liquid separator 150. The first gas / liquid separator 150 provides the first separator hydrocarbon vapor stream 205 as an overhead stream at the first outlet 151 and the second near or near the bottom of the first gas / liquid separator 150. At the outlet 152 provides a first separator bottoms stream 155a which is a liquid stream. The first gas / liquid separator 150 may be in the form of a separation column, such as a fractionation tower or a distillation column. The first gas / liquid separator 150 is preferably provided in the form of a nitrogen separation tower. The first separator hydrocarbon vapor stream 205 generally consists of hydrocarbons, usually mainly methane and nitrogen.

Separation takes place at a first pressure, preferably in the range of 2 to 15 bara, more preferably 2 to 10 bara, to achieve a much lower nitrogen content in the liquid hydrocarbon stream and still be usable as a low pressure fuel gas stream.

To enhance separation within the first gas / liquid separator 150, a stripping vapor stream 185a is provided to the second inlet 149. Second inlet 149 generally consists of a vapor inlet device known to those skilled in the art. The second inlet 149 is at a gravity lower than the first inlet 148 to provide efficient stripping of lighter components of the hydrocarbon mixture, such as nitrogen, from the liquid phase to the vapor phase of the multiphase hydrocarbon stream. desirable. The first inlet 148 generally consists of an inlet distributor known to those skilled in the art.

In a preferred embodiment, the first gas / liquid separator 150 preferably comprises a contact section consisting of contact enhancing means 154, such as a tray or packing, to enhance separation. Preferably, the contact enhancement means 154 is disposed gravitationally between the first and second inlets 148, 149.

The contact enhancement means comprises a plurality of stacked trays which can be arranged such that the liquid phase can flow horizontally along each tray before falling to the next tray, where the vapor phase forms bubbles through holes in the tray. This increases the amount of contact area between the liquid and vapor phases. Alternatively, the contact enhancing means may consist of a packing. The contact section of the packing operates in a manner similar to a tray with packing, which may be systematic or random, thereby increasing the contact area between the liquid and vapor phases.

The first separator hydrocarbon vapor stream 205 may consist of at least 30 mol% N ₂ inventory and hydrocarbons. The first separator hydrocarbon vapor stream 205 preferably has a pressure of 10 bara or less.

The low pressure fuel gas stream 215 may be derived from the first separator hydrocarbon vapor stream 205. For example, the first separator hydrocarbon vapor stream 205 may be moved to a fuel gas heat exchanger 210, where the first separator hydrocarbon vapor stream is a low pressure fuel gas, for example, at a pressure of about 5 or 6 bara. Heated to heated stream 355 to provide stream 215. At the same time, the heated stream is cooled into a cooled heated stream 365.

The fuel gas heat exchanger 210 may be a heater, such as an ambient heater, in which case the heated stream 355 is ambient air or ambient to provide a cooled heated stream 365 in the form of cooled air or a cooled water stream. It may be provided in the form of water. The cooled heated stream 365 may be used as an intermediate stream to chill other streams. However, in preferred embodiments, the heated stream 355 is provided in the form of a process stream that needs to be cooled, providing an additionally cooled process stream. In this way, cooling energy from the first separator hydrocarbon vapor stream 205 can be efficiently used to cool the process stream inside the device 1, such as a hydrocarbon or refrigerant stream. Examples thereof are provided in comparison with the embodiment of FIG. 2.

The low pressure fuel gas stream 215 may consist of at least 30 mol% N ₂ . The low pressure fuel gas stream 215 can then be moved to a low pressure fuel gas network. 1 shows a low pressure fuel gas stream 215 that is directed directly to one or more low pressure fuel gas consumer 220, for example a furnace, a boiler, or a combustion device such as a dual fuel diesel engine. Such combustion devices may generally allow high levels of nitrogen in low pressure fuel gases as is known to those skilled in the art.

The first separator bottom stream 155a may be moved from the first gas / liquid separator 150 to the first inlet 158 of the second gas / liquid separator 160. The second gas / liquid separator 160 operates at a second pressure lower than the first pressure used to provide separation in the first gas / liquid separator 150. The second pressure is preferably less than 4 bara, more preferably less than 2 bara. The second pressure may be suitable for atmospheric pressure or an atmospheric pressure approximation. For the purposes of this disclosure, atmospheric pressure or atmospheric pressure approximation is preferably understood as a pressure between 1 and 1.3 bara.

If the pressure drop between the first and second gas / liquid separators 150 and 160 is insufficient to provide a suitable second pressure, the first separator bottom stream 155a may pass through the bottom stream expansion device 200. Which provides a first separator bottoms stream 155b (expanded) to a first inlet 158 of a second gas / liquid separator 160 at a second pressure.

The second gas / liquid separator 160 provides the second separator hydrocarbon vapor stream 175 as an overhead stream at the first outlet 161 and returns the treated liquid hydrocarbon stream 165 at the second outlet 162. to provide. The second gas / liquid separator 160 may be a suitable flash container.

The treated liquid hydrocarbon stream 165, which may be an LNG stream when the polyphase hydrocarbon stream 145 is derived from natural gas, may be provided at atmospheric or atmospheric pressure approximation. The treated liquid hydrocarbon stream 165 may be transferred to a storage tank 170, such as a cryogenic storage tank.

The second separator hydrocarbon vapor stream 175 is moved to an overhead stream compressor 180 where the second separator hydrocarbon vapor stream is compressed to provide a stripping vapor stream 185. The overhead stream compressor 180 may be mechanically driven by an overhead stream compressor driver 190 such as a gas turbine, steam turbine and / or electric motor. The stripping vapor stream 185 passes the combined stripping vapor stream 185a before it is moved to the second inlet 149 of the first gas / liquid separator 150 to enhance separation therein. May optionally be combined with the supplemental stripping vapor stream 235 to form. The stripping vapor stream 185 generally has a third pressure that must be equal to or slightly higher than the first pressure, such as the second inlet 149 of the first gas / liquid separator 150 and the overhead stream compressor 180. It is the sum of the first pressure and any pressure loss between the outlets. For example, the third pressure may be in the range of 0-2 bara higher than the first pressure.

The supplemental stripping vapor stream 235 may consist of a boil off gas from the cryogenic storage tank. In the case of cryogenic storage of the treated liquid hydrocarbons, some degree of vaporization of the treated liquid hydrocarbons from the storage tank 170 may be expected due to incomplete thermal insulation and temperature fluctuations. The resulting boil off vapor may be removed from storage tank 170 as boil off gas (BOG) stream 195. The boil off gas stream 195 can be moved to a boil off gas compressor 230, where the boil off gas stream is compressed to provide a compressed boil off gas stream 235 for use as a supplemental stripping vapor stream. . The boil off gas compressor 230 may be driven by a boil off gas compressor driver 240, such as a gas or steam turbine and / or an electric motor.

In an alternative embodiment not shown in FIG. 1, the supplemental stripping vapor stream 235 may be moved directly to a separate additional inlet of the first gas / liquid separator 150. The final choice of supplying the supplemental stripping vapor 235 to the first gas / liquid separator may be made by the temperature and composition of the supplemental stripping vapor stream 235, such as a compressed boil off gas stream.

In one preferred embodiment, the method disclosed herein can be used as part of a liquefaction process for a hydrocarbon transfer stream, in which case the multiphase hydrocarbon stream to be treated may be formed by varying the pressure of the hydrocarbon transfer stream and / or cooling. . The hydrocarbon transfer stream may be any suitable gas stream that can be cooled and liquefied, but is usually a natural gas stream obtained from natural gas or oil beds. As an alternative, the hydrocarbon feed stream may be obtained from other sources that also include a synthetic source, such as a Fischer-Tropsch process.

Usually, the natural gas stream is a hydrocarbon composition consisting essentially of methane. Preferably the hydrocarbon feed stream consists of at least 50 mol% methane, more preferably at least 80 mol% methane.

Hydrocarbon compositions such as natural gas may also include non-hydrocarbons such as H ₂ O, N ₂ , CO ₂ , Hg, H ₂ S and other sulfur compounds. If desired, natural gas may be pretreated prior to cooling and any liquefaction. This pretreatment may include steps such as reduction and / or removal of undesirable components such as CO ₂ and H ₂ S or other premature cooling, preliminary pressurization and the like. Since these steps are well known to those skilled in the art, the mechanism is not discussed further here.

Thus, the term “hydrocarbon transfer stream” is partially, significantly or completely, for the reduction and / or removal of one or more compounds or substances, as well as compositions prior to any treatment, including washing, dewatering and / or scrubbing. It may include any composition that is processed, sulfur, including sulfur compounds, carbon dioxide, water, Hg and one or more C _{2 +} hydrocarbons but are not limited to.

Depending on the source, natural gas may include variable amounts of hydrocarbons, in particular heavier than methane, such as ethane, propane and butane, and possibly the least amount of pentane and aromatic hydrocarbons. This composition changes depending on the form and location of the gas.

Conventionally, hydrocarbons heavier than methane are removed to varying degrees from the hydrocarbon transport stream prior to liquefaction for a variety of reasons, such as providing different specifications for the liquefied product or having different freezing or liquefaction temperatures that may block part of the methane liquefaction plant. . C _{2 +} hydrocarbons may be methane-rich overhead stream and a C _{2 +} hydrocarbons to provide a bottom stream comprising the lean methane hydrocarbons separated from the hydrocarbon feed stream by a demethanizer or its content reduced. The methane lean bottoms stream can then be transferred to an additional separator to provide liquefied petroleum gas (LPG) and to condense the stream.

After separation, the hydrocarbon stream thus produced can be further cooled and preferably liquefied. Cooling can be provided by a number of methods known in the art. The hydrocarbon stream is moved relative to one or more refrigerant streams in one or more refrigerant circuits. Such refrigerant circuits may include one or more refrigerant compressors to compress the at least partially vaporized refrigerant stream to provide a compressed refrigerant stream. The compressed refrigerant stream may then be cooled inside a cooler such as an air cooler or a water cooler to provide a coolant stream. The refrigerant compressor may be driven by one or more gas and / or steam turbines and / or electric motors.

Cooling of the hydrocarbon stream may be carried out in one or more stages. Initial cooling, also referred to as pre-cooling or sub-cooling, is performed using pre-cooling refrigerants such as mixed refrigerants in the pre-cooling refrigerant circuit inside one or more pre-cooling heat exchangers to provide a pre-cooled hydrocarbon stream. Can be. The pre-cooled hydrocarbon stream is preferably partially liquefied, such as at temperatures below 0 ° C.

Preferably, such pre-cooling heat exchanger may comprise a pre-cooling stage, wherein any subsequent cooling may include one or more main heat exchangers to liquefy a fraction of the hydrocarbon stream in one or more main and / or sub-cooling stages. Is carried out in the

In this way, two or more cooling stages may be included, each stage having one or more steps, portions, or the like. For example, each cooling stage may comprise one to five heat exchangers. The fraction of hydrocarbon stream and / or refrigerant cannot pass through all and / or all of the same heat exchanger in the cooling stage.

In one embodiment, the hydrocarbon may be cooled and liquefied in a method consisting of two or three cooling stages. Preferably, the pre-cooling stage attempts to reduce the temperature of the hydrocarbon feed stream to less than 0 ° C, usually in the range of -20 ° C to -70 ° C.

The main cooling stage is preferably separated from the pre-cooling stage. In other words, the main cooling stage comprises one or more separate main heat exchangers. Preferably, the main cooling stage attempts to reduce the temperature of the hydrocarbon stream, usually at least one fraction of the hydrocarbon stream cooled by the pre-cooling stage, below -100 ° C.

Heat exchangers or any main heat exchanger used for two or more pre-coolings are well known in the art. The pre-cooling heat exchanger is preferably a shell and tube heat exchanger.

At least one of any main heat exchanger is preferably a spool-wound cryogenic heat exchanger known in the art. Optionally, the heat exchanger may include one or more coolers within its shell, and each cooler may be considered as a 'heat exchanger' separated in a cooling stage or other cooling location.

In another embodiment, one or both of the pre-cooling refrigerant stream and any main refrigerant stream may pass through one or more heat exchangers, preferably the two or more pre-cooling and main heat exchangers described above to provide a cooled refrigerant stream. Can be.

If the refrigerant is a mixed refrigerant in a mixed refrigerant circuit, such as a pre-cooled refrigerant circuit or any main refrigerant circuit, it is at least two components selected from the group consisting of nitrogen, methane, ethane, ethylene, propane, propylene, butane, pentane and the like. It may also be formed from a mixture of. One or more other refrigerants may be used in separate or overlapping refrigerant circuits or other cooling circuits.

The pre-cooling refrigerant circuit may comprise mixed pre-cooling refrigerant. The main refrigerant circuit may consist of mixed main refrigerant. As mentioned herein, the mixed refrigerant or the mixed refrigerant stream comprises at least 5 mole% of two other components. More preferably, the mixed refrigerant consists of two or more in the group consisting of nitrogen, methane, ethane, ethylene, propane, propylene, butane and pentane.

The common composition for the pre-cooled mixed refrigerant is:

Methane (Cl) 0-20 mol%

Ethane (C2) 5 ~ 80 mol%

Propane (C3) 5 to 80 mol%

Butane (C4) may be from 0 to 15 mol%.

The total composition consists of 100 mol%.

The common composition for the main cooling mixed refrigerant is:

Nitrogen 0-10 mol%

Methane (Cl) 30 to 70 mol%

Ethane (C2) 30 ~ 70 mol%

Propane (C3) 0-30 mol%

Butane (C4) 0 to 15 mol%.

The total composition consists of 100 mol%.

In another embodiment, the pre-cooled hydrocarbon stream, such as the pre-cooled natural gas stream, may be further cooled to provide an at least partially, preferably fully liquefied hydrocarbon stream, such as an LNG stream. Further cooling may be performed in the main cooling stage. Preferably, the treated liquid hydrocarbon stream provided in the methods and apparatus described herein may be stored in one or more storage tanks. The fully liquefied hydrocarbon stream is preferably co-cooled. For example, further cooling in the main cooling stage or in a separate sub-cooling stage may comprise auxiliary cooling of the liquefied hydrocarbon stream.

After liquefaction, the at least partially, preferably fully liquefied, hydrocarbon stream can be expanded to provide a multiphase hydrocarbon stream that can be further processed according to the methods and apparatus described herein.

FIG. 2 shows a second embodiment of an apparatus in which the pressurized hydrocarbon feed stream 85 is treated, cooled, at least partially liquefied and expanded to provide a multiphase hydrocarbon stream 145 for use in the treatment methods disclosed herein. Shows. In more detail, the polyphase hydrocarbon stream 145 is:

Providing at least partially, preferably a fully liquefied hydrocarbon stream 115; And

Expanding the at least partially, preferably fully liquefied hydrocarbon stream 115 in at least one hydrocarbon stream expansion device 120, 140 to provide the polyphase hydrocarbon stream 145 in the form of an expanded hydrocarbon stream. May be provided.

At least partially, the fully liquefied hydrocarbon stream 115 is:

Providing a hydrocarbon feed stream 105;

Dividing the hydrocarbon feed stream 105 into a high pressure fuel gas stream 107 and a continuous hydrocarbon stream 108; And

At least partially, continuously cooling the continuous hydrocarbon stream 108 by cooling at least a portion of the continuous stream 108 in one or more heat exchangers 110a, 110b to provide at least partially, fully liquefied hydrocarbon stream 115. As an alternative, it may be provided by a step of completely liquefying.

The high pressure fuel gas stream 107 may have one or both of a nitrogen content of less than 15 mol% and a pressure of greater than 15 bara. The high pressure fuel gas stream 107 may be suitably moved to one or more high pressure fuel gas consumer 300, such as a gas turbine.

The feed stream separation device 80 may be provided to separate the hydrocarbon feed stream 105 into a continuous hydrocarbon stream 108 and a high pressure fuel gas stream 107. The feed stream separation device 80 has an inlet 78 for the hydrocarbon feed stream 105, a first outlet 81 for the high pressure fuel gas stream 107, and a second outlet for the continuous hydrocarbon stream 108 ( 82) may be included as appropriate.

In some embodiments, at least partially, preferably the complete liquefaction step is:

Pre-cool at least a portion of the continuous hydrocarbon stream 108 in one or more pre-cooling heat exchangers 110a for the pre-cooled refrigerant in the pre-cooled refrigerant circuit to provide a pre-cooled hydrocarbon stream 113. Making; And

At least partially, for the main cooling refrigerant circulated in the main cooling refrigerant circuit to provide a fully liquefied hydrocarbon stream 115, the pre-cooled hydrocarbon stream in at least one main cooling heat exchanger 110b ( It may consist of at least partially, preferably completely liquefying, at least part 113b of 113. This embodiment is:

Moving a portion 113b of the pre-cooled hydrocarbon stream 113 as a heated stream 355 to the fuel gas heat exchanger 210;

Cooling said portion (113b) of the pre-cooled hydrocarbon stream inside the fuel gas heat exchanger (210) for the first separator hydrocarbon vapor stream (205) to provide a cooled process stream (365); And

Moving the cooled process stream 365 to one of the one or more hydrocarbon stream expansion devices 120, 140.

Thus, the apparatus provides at least one cooling stage 110 for cooling and at least partially, preferably fully liquefying the continuous hydrocarbon stream 108 to provide at least partially, preferably fully liquefied hydrocarbon stream 115. It may also include. The one or more cooling stages 110 include inlets 109 and one or more hydrocarbon stream expansion devices 120, 140 for continuous hydrocarbon stream 108 in fluid communication with a second outlet 82 of feed stream separation device 80. May comprise suitably an outlet 112 for an at least partially, preferably fully liquefied, hydrocarbon stream 115 connected to the inlet 118.

The hydrocarbon feed stream 85, which may be a natural gas stream, is provided as a pressurized stream, usually at a pressure in the range of 30 to 90 bara. The hydrocarbon transfer stream 85 may be directed to an acidic gas removal unit 90. The acidic gas removal unit 90 lowers the acidic gas content, such as carbon dioxide and hydrogen sulfide, in the hydrocarbon feed stream 85 by known methods to provide the treated hydrocarbon stream 95.

 The treated hydrocarbon stream 95 may then be transferred to a natural gas liquid (NGL) extraction unit 100, optionally via a dryer (not shown). In the NGL extraction unit 100, at least a portion of any natural gas liquids such as propane, butane and pentane can be removed together with heavier hydrocarbons using, for example, one or more scrub columns or fractionation towers. have. NGL extraction unit 100 provides a hydrocarbon feed stream 105 from which natural gas liquid can be depleted.

2 shows a hydrocarbon feed stream 105 which is directed to the inlet 78 of the feed stream separation unit 80, where the hydrocarbon feed stream is the high pressure fuel gas stream 107 and the second at the first outlet 81. At the outlet 82 it is split into a continuous hydrocarbon stream 108.

In an alternative embodiment not shown in FIG. 2, the high pressure fuel gas stream 107 can be introduced from the hydrocarbon feed stream 85 and / or the treated hydrocarbon stream 95 instead of the hydrocarbon feed stream 105. The blowout point for the high pressure fuel gas stream 107 will be determined by the composition of the hydrocarbon mixture. For example, if the hydrocarbon mixture is low in acid gas, of course, the high pressure fuel gas stream 107 can be drawn from the hydrocarbon transfer stream 85 and the pressure is reduced in a device such as a valve 106 provided in line 107 so that It can be adapted to high pressure fuel pressure conditions as desired.

Alternatively (not shown), the high pressure fuel gas stream may be drawn from the NGL extraction unit 100 at a lower pressure if the NGL extraction unit 100 is operated at a lower pressure. Along with this, this can avoid spending power on unnecessarily recompressing a portion of the hydrocarbon feed stream 105 to be extracted as fuel gas.

The high pressure fuel gas stream 107 may then be moved to a high pressure fuel gas network or directly to one or more high pressure fuel gas consumer 300, such as a gas turbine, as shown in FIG. 2. The gas turbine may mechanically drive a generator for generating power or, more preferably, mechanically drive a compressor such as is present in the refrigerant circuit.

Thereafter, from the second outlet 82 of the feed stream separation unit 80, the continuous hydrocarbon stream 108 can be moved to a cooling and liquefaction unit 110, in which the continuous hydrocarbon stream is cooled and at least partially , Preferably completely liquefied. Liquefaction unit 100 provides a hydrocarbon stream 115 that is at least partially, preferably fully liquefied, in the first outlet 112. Such liquefaction units are well known in the art, for example as US Pat. No. 6,370,910.

The liquefaction unit 110 shown in FIG. 2 comprises first and second cooling stages. The first cooling stage includes one or more pre-cooling heat exchangers 110a for cooling the continuous hydrocarbon stream 108 for the pre-cooling refrigerant in a pre-cooling refrigerant circuit (not shown). One or more pre-cooled heat exchangers 110a provide a pre-cooled hydrocarbon stream 113.

The pre-cooled hydrocarbon stream 113 can be moved to a pre-cooled stream separation unit 70, where the pre-cooled hydrocarbon stream is optionally (continuous) pre-cooled hydrocarbon stream portion 113b. And a process stream to be used as the heating stream 355.

 The pre-cooled hydrocarbon stream 113 or the continuous pre-cooled hydrocarbon stream portion 113b is moved to the second cooling stage. The second cooling stage is one which at least partially, preferably completely liquefies, the pre-cooled hydrocarbon stream 113 or at least its continuous portion 113b for the main cooling refrigerant in the main cooling refrigerant circuit (not shown). The above-mentioned main cooling heat exchanger 110b is included. One or more main cooling heat exchangers 110b provide a hydrocarbon stream 115 that is at least partially, preferably fully liquefied.

In alternative embodiments, the NGL extraction unit 100 may be located anywhere inside the liquefaction unit 110 instead of upstream of the liquefaction unit as shown in FIG. 2. In this case, feed stream separation device 80 may also be located inside liquefaction unit 110. Both the NGL extraction unit 100 and the feed stream separation device 80 will preferably be located upstream where complete condensation of the feed stream is achieved. A good location will generally be upstream of the second cooling stage.

At least partially, preferably the fully liquefied hydrocarbon stream 115 is one or more such as two or more continuous expansion devices that sequentially reduce the pressure of the stream to provide the multiphase hydrocarbon stream 145 at the outlet 142. May be moved to an inlet 118 of a hydrocarbon stream expansion device 120, 140. In the embodiment shown in FIG. 2, at least partially, preferably a sufficiently liquefied hydrocarbon stream 115 can be moved to a first hydrocarbon stream expansion device 120, which may be a turbine, where the liquefied hydrocarbon stream Is dynamically expanded to provide an expanded hydrocarbon stream 125. The energy released during the dynamic expansion of the at least partially, preferably fully liquefied, hydrocarbon stream 115 in the first expansion device 120 may, for example, include other devices such as a generator 130 or a compressor (not shown). It can be recovered by driving it mechanically.

The expanded hydrocarbon stream 125 can then be moved to the expanded hydrocarbon stream splitting apparatus 60 to provide the expanded hydrocarbon slip stream 305 and the (continuous) expanded hydrocarbon stream 125b. Thereafter, the (continuous) expanded hydrocarbon stream 125b may be passed to a second expansion device 140, such as a Joule-Thompson valve, in which the expanded hydrocarbon stream provides a multiphase hydrocarbon stream 145. To expand.

In the embodiment of FIG. 2, the heated stream 355 is suitable for forming the stream 145 portion after being cooled in the fuel gas heat exchanger 210 to provide a cooled heated stream 365. In this case, after suitable decompression, for example in an expander or Joule-Thompson apparatus 121, the cooled heated stream 365 is expanded (continuously) to be sent to the second hydrocarbon stream expansion apparatus 140 as already discussed. To the hydrocarbon stream 125b. In some embodiments, it may be advantageous to recombine the cooled heated stream 365 and the liquefied hydrocarbon stream 115 upstream of the expansion device 120 so that the streams can expand together.

In the embodiment of FIG. 2, the heated stream 355 is provided in the form of a slip stream recovered from the hydrocarbon stream 113 pre-cooled by the pre-cooled stream separation unit 70. However, the heated stream may also be obtained at different pressures from other sources, which source is generally equipped with a fractional distillation train (not shown) to fractionate the NGL product obtained from the NGL extraction unit 100 or the NGL extraction unit 100. ), But is not limited to such.

In another group of embodiments, the pre-cooled hydrocarbon stream can never be split so that the heated stream 355 consists of a completely different process stream, such as a refrigerant (slip) stream or an intermediate cooling fluid stream.

The polyphase hydrocarbon stream 145 may be moved to a first inlet 148 of the first gas / liquid separator 150a in which the polyphase hydrocarbon stream is converted into a gaseous fraction and a liquid fraction similar to the embodiment of FIG. 1. Are separated. The first separator vapor stream 205 exits the first gas / liquid separator 150a upwards through an internal first outlet 151. The first separator bottom stream 155a, which is a liquid stream, exits through the second outlet 152 near the bottom or bottom of the first gas / liquid separator 150a. The combined stripping vapor stream 185a is directed to a second inlet 149 located gravitationally lower than the first gas / liquid separator 150a and the first inlet 148. The second inlet 149 can be above the second outlet 152.

The expanded hydrocarbon slip stream 305 is further expanded using, for example, the Joule Thomson valve 310, such that the additional expanded hydrocarbon slip stream 315 is allowed to draw some gas at the top of the first gas / liquid separator 150a. Pass backflow condenser 320 to recondense. Counterflow condenser 320 may be located at a level between the first inlet 148 and the first outlet 151 to provide a countercurrent to enhance the separation of the lighter components of the multiphase hydrocarbon stream. As is known to those skilled in the art, an external countercurrent condenser may be used in place of this internal condenser 320.

A further expanded hydrocarbon slip stream 315 is heated inside condenser 320 to provide a heated hydrocarbon slip stream 325, which is heated to the (expanded) first separator bottom stream 155b. Can be moved. The first separator bottom stream 155b (expanded) that carries the heated hydrocarbon from the heated hydrocarbon slip stream 325 is the combined stream 155c as the inlet 158 of the second gas / liquid separator 160. Can be moved to. Reference is made to the foregoing description of the stream and further processing drawn from the second gas / liquid separator 160 and FIG. 1.

Returning to the first gas / liquid separator 150a, the separator may comprise two sections having contact enhancement means 154a, 156a formed, for example, of trays and / or packings to improve separation and nitrogen removal. have. The first of the two sections, similar to the embodiment of FIG. 1, is located between the first inlet 148 and the second inlet 149. The second of the two sections 156a is located between the first outlet 151 for the first separator hydrocarbon vapor stream 205 and the first inlet 148 for the multiphase hydrocarbon stream 145. The second section 156a should be under condenser 320 or under inlet means for backflow from an external condenser to take advantage of the backflow provided by condensation of hydrocarbon vapor on condenser 320.

The first separator hydrocarbon vapor stream 205 exiting the first outlet 151 is configured to provide a low pressure fuel gas stream 215 and a cooled heated stream 365 in order for the first separator hydrocarbon vapor stream to be heated. 365 may be moved to a fuel gas heat exchanger 210 that is heated to. If the heated stream is provided in the form of a process stream, a portion of the cooling energy of the first separator hydrocarbon vapor stream 205 can be used to cool the process stream, which bypasses one or more main heat exchangers 110b and provides thermal efficiency. To improve.

As already mentioned above, the heating stream 355 may also be a process stream in the form of a refrigerant stream, such as a pre-cooling and / or main cooling refrigerant stream. In this case, a portion of the cooling energy of the first separator hydrocarbon vapor stream 205 can be returned to one or both of the cooling stages 110 by cooling the refrigerant.

The advantages of the methods and apparatus disclosed herein will be apparent from the following non-limiting examples.

Example

This example shows the various streams generated from the natural gas hydrocarbon feed stream 105 according to the three comparative examples calculated according to the embodiment of FIG. 3 of US 2008/0066493 described above and the line-up of FIG. 2. Provides a comparison of nitrogen content.

The nitrogen content of the hydrocarbon feed stream 105 consisting of natural gas, high pressure and low pressure fuel gas streams 107, 215, boyoff gas stream 195 and LNG stream 165 may be added to the lineup of FIG. 2 disclosed herein. Calculated with data and shown below in the table below "invention".

In the embodiment of FIG. 3 of US 2008/0066493, the high pressure fuel gas stream is subjected to the overload of the top 10 'top 10u after heat exchange and compression combined with the overhead 42 of the flash vessel 101 after heat exchange and compression. From the head 25 is provided by a conduit 34a. The conduit 33, which arises only from the heat exchange and compression of the overhead 25 of the upper portion 10u of the tower 10 ', cannot provide sufficient high pressure fuel gas, which is instead drawn from the conduit 34a in this comparison. Point out. In the absence of a check valve in line 34, the conduits 33, 34a will be in fluid communication.

US 2008/0066493 does not disclose a corresponding low pressure fuel gas stream. For this comparison, it was assumed that the low pressure fuel gas stream was extracted from the conduit 25 carrying the overhead of the top 10u of the tower 10 '. The boil off gas stream is found in conduit 22.

The data calculated according to the modified lineup of FIG. 3 of US 2008/0066493 is shown under “Comparative Example 1”, “Comparative Example 2” and “Comparative Example 3” in Table 1 below. "Comparative Example 1" shows a comparison with the method according to FIG. 2 disclosed herein taken at the same natural gas transport stream, low pressure fuel stream, high pressure fuel stream, boil off gas stream and LNG stream production rates. "Comparative Example 2" shows a comparison with the method according to FIG. 2 disclosed herein taken at the same natural gas feed stream velocity, low pressure and high pressure fuel gas heating values. "Comparative Example 3" shows a comparison with the method according to FIG. 2 disclosed herein taken at the same natural gas feed stream and LNG stream speed and low pressure fuel gas heating values.

It is evident from Table 1 below that the methods and apparatus disclosed herein remove nitrogen from low pressure fuel gas stream 215 while generating LNG stream 165 and high pressure fuel gas stream 107 having an acceptably low nitrogen content. Become.

Invention Comparative Example 1 Comparative Example 2 Comparative Example 3 N ₂ mole fraction
Natural gas transport stream 0.056 0.056 0.056 0.056 N ₂ mole fraction
HP fuel gas stream 0.056 0.248 0.285 0.298 N ₂ mole fraction
LP fuel gas stream 0.805 0.418 0.409 0.445 N ₂ mole fraction
BOG stream 0.223 0.154 0.141 0.154 N ₂ mole fraction
Treated Liquid Hydrocarbon Stream 0.009 0.006 0.005 0.006 Heating value
Low pressure fuel gas stream 64 234 65 64 Specific power
(kW / tpd LNG) 14.8 14.2 14.4 14.3 Net power
(kW / tpd LNG) 14.6 13.9 14.1 14.1 produce
340 stream day / MPTA 3.60 3.60 3.56 3.60

Those skilled in the art will understand that the invention can be carried out in many different ways without departing from the scope of the appended claims.

Claims (17)

A method of treating a multiphase hydrocarbon stream to provide a treated liquid hydrocarbon stream, the method comprising at least:
Generating a multiphase hydrocarbon stream from natural gas comprising a vapor phase and a liquid phase;
Moving said polyphase hydrocarbon stream to a first gas / liquid separator;
Separating the multiphase hydrocarbon stream at a first pressure in the first gas / liquid separator to provide a first separator hydrocarbon vapor stream and a first separator bottoms stream comprising hydrocarbon and nitrogen;
Separating the first separator bottoms stream in a second gas / liquid separator at a second pressure lower than the first pressure to provide a liquid hydrocarbon stream and a second separator hydrocarbon vapor stream treated in the form of LNG;
Compressing the second separator hydrocarbon vapor stream in an overhead stream compressor to provide a stripping vapor stream; And
Moving the stripping vapor stream to the separator at a level that is gravityly lower than the level at which the multiphase hydrocarbon stream is directed to the first gas / liquid separator. The method of claim 1,
Compressing the second separator hydrocarbon vapor stream in the overhead stream compressor to provide a stripping vapor stream providing a stripping vapor stream at a third pressure that is above the first pressure. The method according to claim 1 or 2,
Directing a low pressure fuel gas stream from the first separator hydrocarbon vapor stream; And
Moving the low pressure fuel gas stream to a combustion device at a fuel gas pressure not higher than the pressure of the first separator hydrocarbon vapor stream. The method of claim 3, wherein
Wherein the first pressure of the first gas / liquid separator is above the fuel gas pressure and neither the first separator hydrocarbon vapor stream nor the low pressure fuel gas stream is compressed prior to use in a combustion device. The method according to claim 3 or 4,
Wherein said combustion device is one of a group consisting of a furnace, a boiler, a dual fuel diesel engine. 6. The method according to any one of claims 3 to 5,
Directing the low pressure fuel gas stream from the first separator hydrocarbon vapor stream,
Heating the first separator hydrocarbon vapor stream to a warming stream in a fuel gas heat exchanger to provide a low pressure fuel gas stream and a cooled heating stream. The method according to claim 6,
Generating a multiphase hydrocarbon stream from the natural gas comprising the vapor phase and the liquid phase,
Cooling the cooled heated stream by cooling a portion of natural gas as the heated stream in a fuel gas heat exchanger for a first separator hydrocarbon vapor stream to provide the cooled heated stream in the form of a cooled process stream. A process for treating a multiphase hydrocarbon stream, comprising providing in the form of a process stream. The method according to any one of claims 1 to 7,
Wherein the first separator hydrocarbon vapor stream comprises 30 mol% to 95 mol% nitrogen and / or has a pressure between 2 bara and 15 bara. The method according to any one of claims 1 to 8,
Wherein the treated liquid hydrocarbon stream contains less than 1 mol% nitrogen. The method according to any one of claims 1 to 9,
Generating the multiphase hydrocarbon stream from the natural gas comprising the vapor phase and the liquid phase comprises changing and / or cooling the pressure of the natural gas. The method according to any one of claims 1 to 10,
Generating a multiphase hydrocarbon stream from the natural gas comprising the vapor phase and the liquid phase,
Providing a hydrocarbon feed stream from the natural gas stream at elevated pressure;
Extracting a continuous hydrocarbon stream from said hydrocarbon feed stream;
Moving the continuous stream to a cooling and liquefaction unit that cools and at least partially liquefies the continuous stream to provide at least partially liquefied hydrocarbon streams; And,
Moving the at least partially liquefied hydrocarbon stream to an inlet of at least one hydrocarbon stream expansion device therein to reduce the pressure of the at least partially liquefied hydrocarbon stream to provide a multiphase hydrocarbon stream. How to handle it. The method of claim 11,
-Splitting the hydrocarbon feed stream into one or both of a nitrogen content of less than 15 mol% and a pressure of greater than 15 bara, and splitting into a continuous hydrocarbon stream. . An apparatus for treating a multiphase hydrocarbon stream consisting of a liquid phase and a vapor phase to provide a liquid hydrocarbon stream treated in the form of LNG, the apparatus comprising at least:
Means for producing a multiphase hydrocarbon stream from natural gas and comprising at least one of a liquefaction unit and at least one hydrocarbon stream expansion device;
A first inlet configured to receive the multiphase hydrocarbon stream and to separate the stream into a first separator hydrocarbon vapor stream and a first separator bottoms stream comprising hydrocarbons and nitrogen, and to direct the multiphase hydrocarbon stream to the first gas / liquid separator A first outlet for discharging the first separator hydrocarbon vapor stream from the first gas / liquid separator, a second outlet for discharging the first separator bottom stream from the first gas / liquid separator, and a stripping vapor stream to the first gas / liquid A first gas / liquid separator having a second inlet located at a gravity level lower than the first inlet for delivery to the separator;
Arranged to receive a first separator bottoms stream and separate it into a second separator hydrocarbon vapor stream and a liquid hydrocarbon stream treated in the form of LNG, and to transfer the first separator bottoms stream to a second gas / liquid separator. A first inlet in fluid communication with a second outlet of the first gas / liquid separator, a first outlet for exhausting the second separator hydrocarbon vapor stream from the second gas / liquid separator, and a treated liquid hydrocarbon stream from the second gas / liquid separator A second gas / liquid separator having a second outlet for discharging the gas;
A bottom stream expansion device disposed between the second outlet of the first gas / liquid separator and the first inlet of the second gas / liquid separator to reduce the pressure of the first separator bottom stream; And
-Compressing the second separator hydrocarbon vapor stream to provide a stripping vapor stream, inlet in fluid communication with the first outlet of the second gas / liquid separator to receive the second separator hydrocarbon vapor stream, and evacuating the stripping vapor stream At least an overhead stream compressor having an outlet in fluid communication with a second inlet of the first gas / liquid separator. The method of claim 13,
At least one hydrocarbon stream expansion device is connected to the liquefaction unit and downstream thereof to expand at least a partially liquefied hydrocarbon stream exiting the liquefaction unit to provide a multiphase hydrocarbon stream, wherein the at least one hydrocarbon stream expansion device is at least partially And an outlet for evacuating the polyphase hydrocarbon stream, the outlet being connected to the first inlet of the first gas / liquid separator. The method according to claim 13 or 14,
And a combustion device operating at a fuel gas pressure not higher than the pressure of the first separator hydrocarbon vapor stream and arranged to receive the low pressure fuel gas derived from the first separator hydrocarbon stream. The method of claim 15,
Apparatus for treating a multiphase hydrocarbon stream without a compressor between the first outlet of the first gas / liquid separator and the combustion device. The method according to claim 15 or 16,
Wherein the combustion device is one of a group consisting of a furnace, a boiler, and a dual fuel diesel engine.

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