A method for separating gas-liquid mixed phase light hydrocarbon in an LNG receiving station

Abstract

The application relates to the technical field of light hydrocarbon cryogenic separation, and provides a gas-liquid mixed-phase light hydrocarbon separation method of an LNG receiving station, which comprises the following steps: cooling raw material natural gas to a first preset temperature zone, and conveying the cooled raw material natural gas to a first inlet of a demethanizer; preheating raw material LNG to a second preset temperature zone, and conveying the preheated raw material LNG to a second inlet of the demethanizer; guiding lean natural gas at the top of the demethanizer to the outside of the demethanizer; guiding demethanization liquid at the bottom of the demethanizer to the outside of the demethanizer; and exchanging heat between the raw material natural gas and the raw material LNG. The application can solve the problem that LNG cold energy cannot be fully utilized.

Description

Technical Field

[0001] This application relates to the field of cryogenic separation technology for light hydrocarbons, and in particular to a method for separating gas-liquid mixed light hydrocarbons in an LNG receiving station. Background Technology

[0003] Besides methane, LNG-rich environments also contain small amounts of ethane and liquefied petroleum gas (LPG). Ethane can replace naphtha in ethylene production and is more economical than naphtha, diesel, and kerosene. Therefore, separating and recovering ethane from LNG is beneficial for improving the utilization efficiency of LNG and promoting the development of my country's ethylene industry.

[0004] Currently, the light hydrocarbon separation process applicable to LNG receiving terminals involves passing the natural gas exported from the LNG receiving terminal into a light hydrocarbon separation unit for light hydrocarbon separation. However, this method cannot fully utilize the cold energy of LNG. Summary of the Invention

[0005] This application provides a method for separating gas-liquid mixed light hydrocarbons in LNG receiving terminals, which can solve the problem that the cold energy of LNG cannot be fully utilized.

[0006] To achieve the above objectives, this application adopts the following technical solution:

[0007] In a first aspect, this application provides a method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal, comprising the following steps:

[0008] The raw natural gas is cooled to the first preset temperature zone, and the cooled raw natural gas is transported to the first inlet of the demethanizer;

[0009] The feedstock LNG is preheated to the second preset temperature zone, and the preheated feedstock LNG is transported to the second inlet of the demethanizer;

[0010] The lean natural gas at the top of the demethanizer is discharged to the outside of the demethanizer;

[0011] The demethanized liquid at the bottom of the demethanizer is diverted to the outside of the demethanizer;

[0012] In this process, the raw material natural gas is exchanged for heat with the raw material LNG.

[0013] In some embodiments, cooling the feedstock natural gas to a first preset temperature zone and then conveying the cooled feedstock natural gas to the first inlet of the demethanizer includes the following steps:

[0014] The raw natural gas is transported to the first heat exchanger for initial cooling.

[0015] The raw natural gas, which has undergone the first cooling process, is expanded and depressurized to cool it a second time.

[0016] The raw natural gas, which has been cooled a second time, is transported to the first inlet of the demethanizer.

[0017] In some implementations, the expansion decompression can be performed at the expansion end of the expansion compressor unit;

[0018] Alternatively, expansion pressure reduction can be achieved by expanding and reducing pressure through a throttle valve.

[0019] In some embodiments, the feedstock LNG is preheated to a second preset temperature zone, and the preheated feedstock LNG is then conveyed to the second inlet of the demethanizer, including the following steps:

[0020] The feedstock LNG is transported to the second heat exchanger for initial preheating.

[0021] The raw LNG, after the first preheating, is transported to the first heat exchanger for a second preheating.

[0022] The preheated LNG feedstock is transported to the second inlet of the demethanizer.

[0023] In some implementations, the feedstock LNG exchanges heat with the feedstock natural gas within the first heat exchanger.

[0024] In some embodiments, the feedstock LNG is preheated to a second preset temperature zone, and the preheated feedstock LNG is then conveyed to the second inlet of the demethanizer, including the following steps:

[0025] The feedstock LNG is transported to the second heat exchanger for initial preheating.

[0026] The preheated LNG feedstock is transported to the second inlet of the demethanizer.

[0027] In some embodiments, the lean natural gas at the top of the demethanizer is discharged to the outside of the demethanizer, including the following steps:

[0028] Lean natural gas is delivered to the compression end of the expansion compressor unit to pressurize the lean natural gas;

[0029] The pressurized lean natural gas is cooled for the first time so that it condenses into liquid lean natural gas;

[0030] Liquid lean natural gas is transported to the top of the demethanizer;

[0031] And / or, pressurize and reheat liquefied lean natural gas to vaporize it into high-pressure lean natural gas.

[0032] In some implementations, the pressurized lean natural gas is first cooled to condense it into liquid lean natural gas, including the following steps:

[0033] The pressurized lean natural gas is transported to the first heat exchanger to cool and condense it.

[0034] The condensed liquid lean natural gas is discharged to the outside of the first heat exchanger.

[0035] In some embodiments, the process of delivering liquefied lean natural gas into the interior of a demethanizer includes the following steps:

[0036] The liquefied lean natural gas is transported to a second heat exchanger for subcooling.

[0037] The supercooled liquefied lean natural gas is pumped into the demethanizer.

[0038] In some embodiments, the liquid lean natural gas is pressurized and reheated to vaporize it into high-pressure lean natural gas, including the following steps:

[0039] The liquefied lean natural gas is delivered to the lean liquid booster pump to pressurize the liquefied lean natural gas;

[0040] The pressurized liquefied lean natural gas is transported to the first heat exchanger to reheat it and vaporize it into high-pressure lean natural gas.

[0041] In some embodiments, after pressurized liquid lean natural gas is conveyed to a first heat exchanger to reheat the liquid lean natural gas and vaporize it into high-pressure lean natural gas, the following steps are further included:

[0042] High-pressure lean natural gas is heated to a preset external transmission temperature zone using heating components.

[0043] In some embodiments, after diverting the demethanized liquid from the bottom of the demethanizer to the outside of the demethanizer, the following steps are also included:

[0044] The demethanizing liquid is transported into the deethanizer;

[0045] The liquefied petroleum gas at the bottom of the deethaner is diverted to the outside of the deethaner;

[0046] The ethane at the top of the deethaner is cooled and then refluxed back to the deethaner.

[0047] Secondly, this application provides a method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal, comprising the following steps:

[0048] The raw natural gas is cooled to the first preset temperature zone, and the cooled raw natural gas is transported to the first inlet of the demethanizer;

[0049] The feedstock LNG is preheated to the second preset temperature zone, and the preheated feedstock LNG is transported to the second inlet of the demethanizer;

[0050] The lean natural gas at the top of the demethanizer is discharged to the outside of the demethanizer;

[0051] The demethanized liquid at the bottom of the demethanizer is diverted to the outside of the demethanizer;

[0052] In this process, the raw material natural gas and the raw material LNG exchange heat through the first heat exchanger.

[0053] In this gas-liquid mixed light hydrocarbon separation method for LNG receiving terminals, the raw material natural gas is cooled to a first preset temperature zone, and the raw material LNG is preheated to a second preset temperature zone. This fully utilizes the cold energy of LNG to cool the raw material natural gas, thereby reducing the energy consumption of the light hydrocarbon separation unit. At the same time, the cold energy of LNG is used to liquefy lean natural gas, thereby reducing the energy consumption for pressurizing lean natural gas for external transmission.

[0054] Therefore, the gas-liquid mixed light hydrocarbon separation method for LNG receiving terminals provided in this application can solve the problem that the cold energy of LNG cannot be fully utilized. Attached Figure Description

[0055] To more clearly illustrate the technical solutions in the embodiments of this application or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0056] Figure 1 A schematic diagram of one of the structural components of the LNG receiving station gas-liquid miscible light hydrocarbon separation process system provided in the embodiments of this application;

[0057] Figure 2 The second schematic diagram shows the structure of the LNG receiving station gas-liquid miscible light hydrocarbon separation process system provided in the embodiments of this application.

[0058] Explanation of reference numerals in the attached figures:

[0059] 100 - First heat exchanger;

[0060] 200 - Second heat exchanger;

[0061] 300-Demethanizer;

[0062] 400 - Heating Component;

[0063] 410 - Air heater; 420 - Heater;

[0064] 500-Deethaner column;

[0065] 600 - Third heat exchanger;

[0066] 700-Rich Liquid Booster Pump;

[0067] 800-Lean Solution Booster Pump;

[0068] 900 - Fourth heat exchanger;

[0069] 1000-expansion compressor unit;

[0070] 1100-Ethane reflux branch;

[0071] 1110 - Reflux tank; 1120 - Reflux pump;

[0072] 1200 - Refrigerant circulation path;

[0073] 1210 - Suction tank; 1220 - Compressor; 1230 - Throttling valve;

[0074] 1300-Reboiler. Detailed Implementation

[0075] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application. Unless otherwise specified, the following embodiments and features can be combined with each other.

[0076] To overcome the shortcomings of existing technologies, the raw material natural gas is cooled to a first preset temperature zone, and the raw material LNG is preheated to a second preset temperature zone. This fully utilizes the cold energy of LNG to cool the raw material natural gas, thereby reducing the energy consumption of the light hydrocarbon separation unit. At the same time, the cold energy of LNG is used to liquefy lean natural gas, thereby reducing the energy consumption of pressurizing lean natural gas for external transmission.

[0077] Therefore, the gas-liquid mixed light hydrocarbon separation method for LNG receiving terminals provided in the embodiments of this application can solve the problem that the cold energy of LNG cannot be fully utilized.

[0078] The contents of this application will now be described in detail with reference to the accompanying drawings, so that those skilled in the art can have a clearer and more detailed understanding of the contents of this application.

[0079] like Figure 1 and Figure 2 As shown in the embodiment of this application, a gas-liquid miscible light hydrocarbon separation method for an LNG receiving station includes the following steps: cooling the raw natural gas to a first preset temperature zone and conveying the cooled raw natural gas to the first inlet of a demethanizer 300; preheating the raw LNG to a second preset temperature zone and conveying the preheated raw LNG to the second inlet of the demethanizer; exporting the lean natural gas at the top of the demethanizer 300 to the outside of the demethanizer 300; and guiding the demethanized liquid at the bottom of the demethanizer 300 to the outside of the demethanizer 300, wherein the raw natural gas and the raw LNG exchange heat.

[0080] The following sections provide a detailed description of the specific structure and various possible implementation methods for the gas-liquid miscible light hydrocarbon separation method at LNG receiving terminals.

[0081] It should be noted that the feedstock LNG is liquefied natural gas.

[0082] It should be noted that lean natural gas is methane, while demethanized liquid is light hydrocarbons.

[0083] It should be noted that the temperature range of the first preset temperature zone is between -90 degrees Celsius and -50 degrees Celsius.

[0084] It is understandable that the above-described implementation method can keep the raw natural gas in a gaseous state, thereby making the transportation of the raw natural gas safer.

[0085] In one embodiment, the temperature range of the first preset temperature zone is between -80 degrees Celsius and -60 degrees Celsius.

[0086] It is understandable that the above-described implementation method can keep the raw natural gas in a gaseous state, thereby making the transportation of the raw natural gas safer.

[0087] It should be noted that the preset temperature range for the second preset temperature zone is between -120 degrees Celsius and -60 degrees Celsius.

[0088] It is understandable that the above-described implementation method can keep the raw material LNG in a liquid state, thereby making the transportation of the raw material LNG safer.

[0089] In one embodiment, the preset temperature range of the second preset temperature zone is between -100 degrees Celsius and -60 degrees Celsius.

[0090] It is understandable that the above-described implementation method can keep the raw material LNG in a liquid state, thereby making the transportation of the raw material LNG safer.

[0091] In one embodiment, the feedstock natural gas is transported to the demethanizer 300 at a pressure between 1 MPa and 4 MPa, and the feedstock LNG is transported to the demethanizer 300 at a pressure between 1 MPa and 4 MPa.

[0092] It is understandable that the above implementation method can reduce the pressure fluctuation inside the demethanizer 300 and enable the raw material natural gas and raw material LNG to be smoothly transported into the demethanizer 300, thereby reducing the occurrence of the line failure caused by excessive pressure inside the demethanizer 300.

[0093] It should be noted that the source pressure of the raw natural gas can be between 7MPa and 9MPa, or between 4MPa and 7MPa, or greater than 9MPa. There are no restrictions here, and it can be selected according to the actual use requirements.

[0094] It should be noted that the heat exchange between raw natural gas and raw LNG can be achieved through heat exchange, heat convection, or other methods. There are no restrictions on the specific method, and the appropriate method can be selected based on actual usage requirements.

[0095] In some implementations, the mass fraction ratio of feedstock natural gas to feedstock LNG is satisfied to be 1:9 to 9:1.

[0096] It is understandable that the above implementation methods can improve the flexibility of feeding raw materials such as natural gas and LNG.

[0097] In one implementation, the mass ratio of raw material natural gas to raw material LNG is 1:1.

[0098] It is understandable that, through the above implementation method, the mass fraction of the raw material natural gas and raw material LNG entering the demethanizer 300 can be better controlled, so that the internal pressure of the demethanizer 300 can be more stable.

[0099] The embodiment of this application provides a method for cooling natural gas to a first preset temperature zone and then conveying the cooled raw natural gas to the first inlet of the demethanizer 300, which includes the following steps: conveying the raw natural gas to the first heat exchanger 100 for a first cooling of the raw natural gas; expanding and depressurizing the raw natural gas after the first cooling for a second cooling of the raw natural gas; and conveying the second-cooled raw natural gas to the first inlet of the demethanizer 300.

[0100] Understandably, by first cooling the raw natural gas, the cold energy carried by the raw LNG can be initially utilized. Then, by expanding and depressurizing the raw natural gas, it can be cooled a second time, recovering pressure energy while further generating low temperature, ensuring the low temperature environment necessary for the operation of the demethanizer and improving the yield of the demethanizer.

[0101] Specifically, there are no restrictions on the target temperatures of the first and second cooling processes, which can be selected according to actual usage needs. Furthermore, the target temperatures of the first and second cooling processes are not the focus of protection in this application.

[0102] The expansion and decompression provided in the embodiments of this application have a variety of different implementation methods, and the implementation methods of expansion and decompression will be described by example below.

[0103] In one implementation, the expansion decompression can be performed at the expansion end of the expansion compressor.

[0104] It is understood that, through the above implementation method, the expansion compressor unit 1000 can perform expansion and decompression treatment on the raw material natural gas. In this case, the pressure energy of the raw material natural gas can be recovered by the expansion compressor unit 1000, so as to facilitate the reuse of the pressure energy of the raw material natural gas.

[0105] In some possible implementations, expansion pressure reduction can be achieved through a throttle valve.

[0106] It is understandable that the above implementation method enables the throttle valve to perform expansion and pressure reduction treatment on the raw material natural gas.

[0107] Understandably, there are no restrictions on the specific methods of expansion and decompression; they can be selected based on actual usage requirements.

[0108] The embodiments of this application provide a method for preheating raw LNG to a second preset temperature zone and conveying the preheated raw LNG to the second inlet of the demethanizer 300, comprising the following steps: conveying the raw LNG to the second heat exchanger 200 for a first preheating of the raw LNG; conveying the raw LNG after the first preheating to the first heat exchanger 100 for a second preheating of the raw LNG; and conveying the second preheated raw LNG to the second inlet of the demethanizer 300.

[0109] It is understood that, through the above implementation method, the raw material LNG can be preheated twice. After the raw material LNG has been preheated twice, it is transported to the second inlet of the demethanizer 300, so that the raw material LNG and raw material natural gas can be distilled in the demethanizer 300 to separate the methane and C2+ components in the raw material natural gas and raw material LNG.

[0110] Specifically, there are no restrictions on the target temperatures for the first and second preheating, which can be selected according to actual usage requirements, and the target temperatures for the first and second preheating are not the focus of protection in this application.

[0111] Furthermore, within the first heat exchanger 100, the raw material LNG exchanges heat with the raw material natural gas.

[0112] It is understood that, through the above implementation method, the first heat exchanger 100 can provide a heat exchange environment for raw material LNG and raw material natural gas. In this process, heat is exchanged between the raw material LNG with a lower temperature and the raw material natural gas with a higher temperature, which raises the temperature of the raw material LNG and lowers the temperature of the raw material natural gas.

[0113] In the LNG receiving station gas-liquid mixed light hydrocarbon separation method provided in the embodiments of this application, the raw material LNG is preheated to a second preset temperature zone and the preheated raw material LNG is transported to the second inlet of the demethanizer 300, including the following steps: the raw material LNG is transported to the second heat exchanger 200 to preheat the raw material LNG for the first time, and the first preheated raw material LNG is transported to the second inlet of the demethanizer 300.

[0114] It is understood that, through the above implementation method, the preheated raw material LNG can be transported to the demethanizer 300 through the second inlet of the demethanizer 300. During this process, it provides cooling capacity for the precooling of the raw material natural gas and the liquefaction of lean natural gas, and the cold energy of the raw material LNG is fully utilized.

[0115] It should be noted that there are several different implementation methods for exporting the lean natural gas from the top of the demethanizer 300 to the outside of the demethanizer 300. The following are examples illustrating the implementation methods for exporting the lean natural gas from the top of the demethanizer 300 to the outside of the demethanizer 300.

[0116] In some possible implementations, the lean natural gas at the top of the demethanizer 300 is discharged to the outside of the demethanizer 300 by the following steps: delivering the lean natural gas to the compression end of the expansion compressor unit 1000 to pressurize the lean natural gas, subjecting the pressurized lean natural gas to a first cooling process to condense the lean natural gas into liquid lean natural gas, and delivering the liquid lean natural gas to the top of the demethanizer 300.

[0117] It is understood that, through the above implementation method, the lean natural gas separated by the demethanizer 300 can be pressurized, condensed, and returned to the top of the demethanizer 300 to provide the necessary liquid for the operation of the demethanizer, while further improving the recovery rate of light hydrocarbon resources such as ethane in the demethanizer.

[0118] In some possible implementations, the lean natural gas at the top of the demethanizer 300 is discharged to the outside of the demethanizer 300, including the following steps: the lean natural gas is transported to the compression end of the expansion compressor unit 1000 to pressurize the lean natural gas; the pressurized lean natural gas is cooled for the first time to condense the lean natural gas into liquid lean natural gas; and the liquid lean natural gas is pressurized and reheated to vaporize the liquid lean natural gas into high-pressure lean natural gas.

[0119] It is understood that, through the above implementation method, the pressure energy recovered after the expansion and decompression of the raw natural gas can be utilized to pressurize the lean natural gas. After pressurization, the lean natural gas can be cooled for the first time so that it can be condensed into liquid lean natural gas. The liquid lean natural gas can then be pressurized and reheated to vaporize it into high-pressure lean natural gas. In this process, compared to directly pressurizing the lean natural gas into high-pressure lean natural gas, the energy consumption of using a pump to pressurize the liquid lean natural gas in this application can be significantly reduced.

[0120] In one embodiment, the process of exporting lean natural gas from the top of the demethanizer 300 to the outside of the demethanizer 300 includes the following steps: supplying lean natural gas to the compression end of the expansion compressor unit 1000 to pressurize the lean natural gas; subjecting the pressurized lean natural gas to a first cooling process to condense the lean natural gas into liquid lean natural gas; supplying the liquid lean natural gas to the top of the demethanizer 300; and pressurizing and reheating the liquid lean natural gas to vaporize it into high-pressure lean natural gas.

[0121] It is understood that, through the above implementation method, the pressure energy recovered after the expansion and depressurization of the raw natural gas can be utilized to pressurize the lean natural gas. After pressurization, the lean natural gas can undergo a first cooling process so that it can be condensed into liquid lean natural gas. The liquid lean natural gas can be transported to the top of the demethanizer 300 through two different pipeline paths. The liquid lean natural gas on one path is transported to the top of the demethanizer 300 to provide the necessary liquid for the operation of the demethanizer, while further improving the recovery rate of light hydrocarbon resources such as ethane in the demethanizer.

[0122] In another pathway, the liquefied lean natural gas is pressurized and reheated, and then vaporized into high-pressure lean natural gas. In this process, compared to directly pressurizing the lean natural gas into high-pressure lean natural gas, the energy consumption of using a pump to pressurize the liquefied lean natural gas in this application can be significantly reduced.

[0123] It is understood that the specific implementation methods provided in this application for exporting lean natural gas from the top of the demethanizer 300 to the outside of the demethanizer 300 are not limited and can be selected according to actual usage requirements.

[0124] It should be noted that liquefied lean natural gas can be liquid methane.

[0125] In the LNG receiving station gas-liquid mixed light hydrocarbon separation method provided in the embodiments of this application, the pressurized lean natural gas is cooled for the first time so that the lean natural gas condenses into liquid lean natural gas, including the following steps: the pressurized lean natural gas is transported to the first heat exchanger 100 so that the lean natural gas is cooled and condensed, and the condensed liquid lean natural gas is discharged to the outside of the first heat exchanger 100.

[0126] It is understood that, through the above-described embodiments, the first heat exchanger 100 can cool and condense the pressurized lean natural gas into liquid lean natural gas, which can then be discharged to the outside of the first heat exchanger 100 after condensation. Furthermore, the cold energy within the first heat exchanger 100 can be utilized to provide heat to the first heat exchanger 100.

[0127] It should be noted that the temperature of liquefied lean natural gas is between -100 degrees Celsius and -80 degrees Celsius.

[0128] In the LNG receiving station gas-liquid miscible light hydrocarbon separation method provided in the embodiments of this application, the liquid lean natural gas is transported to the interior of the demethanizer 300, including the following steps: transporting the liquid lean natural gas to the second heat exchanger 200 to subcool the liquid lean natural gas, and pumping the subcooled liquid lean natural gas into the demethanizer 300.

[0129] It is understood that, through the above implementation method, the raw material LNG can provide cooling within the second heat exchanger 200 to subcool the liquid lean natural gas. By pumping the subcooled liquid lean natural gas into the demethanizer 300, the low-temperature methane in the demethanizer 300 can be refluxed. In addition, the liquid lean natural gas can also provide heat within the second heat exchanger 200 to improve energy utilization efficiency.

[0130] In the LNG receiving station gas-liquid miscible light hydrocarbon separation method provided in the embodiments of this application, the liquid lean natural gas is pressurized and reheated to vaporize the liquid lean natural gas into high-pressure lean natural gas, including the following steps: the liquid lean natural gas is transported to the lean liquid booster pump 800 to pressurize the liquid lean natural gas, and the pressurized liquid lean natural gas is transported to the first heat exchanger 100 to reheat the liquid lean natural gas and vaporize the liquid lean natural gas into high-pressure lean natural gas.

[0131] Understandably, through the above-described implementation method, the lean liquid booster pump 800 can pressurize the liquefied lean natural gas. After pressurization, it can be reheated through the first heat exchanger 100 to vaporize into high-pressure lean natural gas. During this process, the liquefied lean natural gas can absorb heat within the first heat exchanger 100 and provide cooling to the first heat exchanger 100, thereby improving energy utilization efficiency. Furthermore, pressurizing the liquid before reheating reduces the energy consumption for pressurization and vaporization in the formation of high-pressure lean natural gas.

[0132] In the LNG receiving station gas-liquid mixed light hydrocarbon separation method provided in the embodiments of this application, after the pressurized liquid lean natural gas is transported to the first heat exchanger 100 to reheat the liquid lean natural gas and make the liquid lean natural gas vaporize into high-pressure lean natural gas, the method further includes the following step: heating the high-pressure lean natural gas to a preset external transmission temperature zone through the heating component 400.

[0133] It is understandable that the above implementation method ensures that the lean natural gas reaches the export temperature.

[0134] It should be noted that the preset external temperature range is greater than or equal to 1 degree Celsius.

[0135] It is understandable that the above-described implementation method allows high-pressure lean natural gas to be maintained in a gaseous state, facilitating its external transportation.

[0136] It is understandable that the above-described embodiments can separate ethane from the demethanizing liquid and collect liquefied petroleum gas.

[0137] It should be noted that liquefied petroleum gas is the same as LPG.

[0138] This application provides a gas-liquid mixed-phase light hydrocarbon separation method for an LNG receiving station, comprising the following steps: cooling the raw natural gas to a first preset temperature zone and conveying the cooled raw natural gas to the first inlet of a demethanizer 300; preheating the raw LNG to a second preset temperature zone and conveying the preheated raw LNG to the second inlet of the demethanizer; exporting the lean natural gas at the top of the demethanizer 300 to the outside of the demethanizer 300; and guiding the demethanized liquid at the bottom of the demethanizer 300 to the outside of the demethanizer 300. The raw natural gas and the raw LNG exchange heat through a first heat exchanger 100.

[0139] This application provides a gas-liquid mixed-phase light hydrocarbon separation process system for an LNG receiving station, including a first heat exchanger 100; a second heat exchanger 200; a demethanizer 300, wherein the feedstock natural gas is connected to the first inlet of the demethanizer 300 via the first heat exchanger 100; the feedstock LNG is connected to the second inlet of the demethanizer 300 via the second heat exchanger 200 and the first heat exchanger 100 in sequence; a heating assembly 400, wherein the gas outlet of the demethanizer 300 is connected to the inlet of the heating assembly 400 via the first heat exchanger 100, the second heat exchanger 200 and the first heat exchanger 100 in sequence; a deethanizer 500, wherein the liquid outlet of the demethanizer 300 is connected to the first inlet of the deethanizer 500; and a third heat exchanger 600, wherein the gas outlet and the liquid outlet of the deethanizer 500 are respectively connected to the two side inlets of the third heat exchanger 600.

[0140] It should be noted that the LNG receiving terminal gas-liquid miscible light hydrocarbon separation process system is used to implement the LNG receiving terminal gas-liquid miscible light hydrocarbon separation method.

[0141] It should be noted that there are no specific requirements for the structure of the demethanizer 300 and the deethaner 500; they can be plate towers or packed towers, and staff can choose according to their needs.

[0142] In practice, the raw material natural gas is fed into the demethanizer 300 via the first heat exchanger 100; the raw material LNG is fed into the demethanizer 300 via the second heat exchanger 200 and the first heat exchanger 100 in sequence; the gas at the top of the demethanizer 300 is heated by the first heat exchanger 100, the second heat exchanger 200, the first heat exchanger 100, and the heating component 400 in sequence to prepare lean natural gas and output; the liquid at the bottom of the demethanizer 300 is separated by the deethaner 500 and heat-treated by the third heat exchanger 600 to prepare LPG and ethane and output.

[0143] In this embodiment, since LNG has a large amount of cold energy, when the raw material LNG is introduced into the light hydrocarbon separation process system, its internal cold energy will first be transferred to the liquid lean natural gas from the first heat exchanger 100 through the second heat exchanger 200, so as to make it subcooled and prevent cavitation from occurring during the pressurization process of the liquid lean natural gas. Then, the raw material LNG flows through the first heat exchanger 100, transferring the cold energy to the lean natural gas from the demethanizer 300 to liquefy it. After the liquid natural gas rises to a suitable temperature, it is introduced into the demethanizer 300.

[0144] When the feedstock natural gas is fed into the light hydrocarbon separation process system, it will transfer heat to the pressurized liquefied lean natural gas, causing it to vaporize. After the feedstock natural gas is cooled to a suitable temperature, it is fed into the demethanizer tower 300.

[0145] Compared to existing light hydrocarbon separation processes, this application provides a gas-liquid miscible light hydrocarbon separation process system for LNG receiving terminals, which can improve the light hydrocarbon recovery rate of the light hydrocarbon separation process system. Using gaseous natural gas and LNG as raw materials, the cold energy contained in LNG is used as the sole cold source to provide cooling for the light hydrocarbon separation process system, reducing energy consumption in the light hydrocarbon separation process. Utilizing the cold energy of LNG to liquefy lean natural gas can significantly reduce the pressurization energy consumption required for exporting natural gas. Then, the heat of the raw material natural gas is used to vaporize the liquefied lean natural gas for export, further reducing the energy consumption for LNG vaporization during the export process from the LNG receiving terminal.

[0146] In some embodiments, the system further includes a rich liquid booster pump 700 and a lean liquid booster pump 800, with the second heat exchanger 200 connected to the first heat exchanger 100 via a first pipeline; the outlet of the rich liquid booster pump 700 is connected to the second inlet of the demethanizer 300 via the second heat exchanger 200 and the first heat exchanger 100 in sequence; and the lean liquid booster pump 800 is located on the first pipeline.

[0147] In practice, the rich liquid booster pump 700 is used to increase the pressure of the raw material LNG to provide power for the raw material LNG to enter the demethanizer 300; while the lean liquid booster pump 800 is used to increase the pressure of the liquid after lean natural gas liquefaction so that it reaches the necessary external transmission pressure.

[0148] At the same time, by using the cooling capacity of LNG to liquefy lean natural gas in advance, the energy consumed to increase the pressure of the liquid phase is much less than the energy consumed to pressurize the gas phase, which reduces the pressurization load of the lean liquid booster pump 800.

[0149] Furthermore, in some embodiments, the outlet of the rich liquid booster pump 700 is connected to the third inlet of the demethanizer 300 via the second heat exchanger 200; it also includes a fourth heat exchanger 900, and the gas outlet of the demethanizer 300 is connected to the fourth inlet of the demethanizer 300 in sequence via the first heat exchanger 100, the second heat exchanger 200 and the fourth heat exchanger 900; the outlet of the rich liquid booster pump 700 is connected to the fifth inlet of the demethanizer 300 via the fourth heat exchanger 900.

[0150] In the above embodiments, two additional paths are provided for the feedstock LNG to enter the demethanizer 300.

[0151] Meanwhile, in order to improve the recovery rate of light hydrocarbons, a portion of the liquid after liquefaction of lean natural gas is refluxed to the demethanizer tower 300 via the fourth heat exchanger 900. At this time, the internal cooling capacity of the raw material LNG will be transferred to the liquid through the fourth heat exchanger 900 to lower the liquid to a suitable temperature, thereby realizing the further utilization of the cold energy of the raw material LNG.

[0152] Of course, staff can reassemble the fourth heat exchanger 900 according to the actual situation (see reference). Figure 2 This allows the cold energy of the feedstock LNG to be concentrated for the liquefaction of lean natural gas and the cooling of the feedstock natural gas.

[0153] In some embodiments, the heating assembly 400 includes an air heater 410 and a heater 420 connected to each other; the outlet of the demethanizer 300 is connected to the inlet of the air heater 410 via a first heat exchanger 100, a second heat exchanger 200 and the first heat exchanger 100 in sequence.

[0154] Here, an air heater 410 is provided to heat the gasified lean natural gas and reheat it; the heater 420 then heats the reheated lean natural gas to the export temperature; the multi-stage heating system consisting of the air heater 410 and the heater 420 improves the heating efficiency of the lean natural gas and reduces the energy consumption of the process system; at the same time, the air heater 410 has the characteristics of small size and high heating efficiency.

[0155] In practice, the lean natural gas is divided into two streams by passing through the first heat exchanger 100 and the second heat exchanger 200. By controlling the flow rate of one stream, it can be directly heated by the first heat exchanger 100 to reach the specified export temperature. The other stream is vaporized by the first heat exchanger 100 and then heated by multiple stages of air heater 410 and heater 420 before being output.

[0156] In some embodiments, the system further includes an expansion compressor unit 1000, which includes an expansion end and a compression end; a first heat exchanger 100 is connected to the first inlet of a demethanizer 300 via a second pipeline, and the outlet of the demethanizer 300 is connected to the first heat exchanger 100 via a third pipeline; the expansion end of the expansion compressor unit 1000 is located on the second pipeline, and the compression end of the expansion compressor unit 1000 is located on the third pipeline.

[0157] In the above embodiment, an expansion compressor unit 1000 is provided. On the one hand, it recovers the pressure energy of the raw material natural gas to reduce it to a suitable temperature. On the other hand, it pressurizes the lean natural gas separated by the demethanizer tower 300 to increase the bubble point temperature of the lean natural gas, making it easier for the lean natural gas to be completely liquefied in the first heat exchanger 100 and the second heat exchanger 200.

[0158] In some embodiments, the first outlet of the demethanizer 300 is connected to the sixth inlet of the demethanizer 300 via a first heat exchanger 100.

[0159] To improve the recovery rate of light hydrocarbons, a portion of the liquid from the liquefaction of lean natural gas is subcooled in the fourth heat exchanger 900 and then refluxed into the demethanizer 300, which increases the heating load of the demethanizer 300. Therefore, in the above embodiment, a portion of the liquid is drawn from the demethanizer 300, vaporized in the heat exchange section of the first heat exchanger 100, and then introduced into the demethanizer 300 to reduce the proportion of liquid phase in the demethanizer 300, thereby reducing the heating load of the demethanizer 300.

[0160] In some embodiments, the system further includes an ethane reflux branch 1100, on which a reflux tank 1110 and a reflux pump 1120 are provided; the first heat exchanger 100 also has an eleventh channel capable of heat exchange; the outlet of the deethaner 500 is connected to the second inlet of the deethaner 500 in sequence via the first heat exchanger 100, the reflux tank 1110 and the reflux pump 1120.

[0161] To reduce the propane content in the ethane product, a portion of the ethane is refluxed to the deethaner 500 via the first heat exchanger 100, reflux tank 1110, and reflux pump 1120.

[0162] In practice, ethane is liquefied in the first heat exchanger 100 and introduced into the reflux tank 1110 for separation. The gas at the top of the reflux tank 1110 is output to the external environment, and the liquid at the bottom of the reflux tank 1110 is pressurized by the reflux pump 1120 and then refluxed back into the de-ethane tower 500. The reflux pump 1120 is used to increase the pressure of the liquid after ethane liquefaction to provide power for its reflux.

[0163] In some embodiments, a refrigerant circulation path 1200 is further included, on which a suction tank 1210, a compressor 1220 and a throttle valve 1230 are provided, so that the refrigerant inside the first heat exchanger 100 flows back to the first heat exchanger 100 in sequence through the suction tank 1210, the compressor 1220 and the throttle valve 1230.

[0164] As a bridge for heat transfer between raw material LNG and raw material natural gas and lean natural gas, in order to obtain different grades of cooling capacity, a refrigerant circulation path 1200 is set up in the above embodiment so that the refrigerant in the first heat exchanger 100 can circulate. The compressor 1220 is used to provide power for the flow of refrigerant.

[0165] In some embodiments, both the demethanizer 300 and the deethanizer 500 are equipped with a reboiler 1300 at the bottom.

[0166] In the above embodiment, a reboiler 1300 is provided to vaporize the liquid portion at the bottom of the demethanizer 300 and the deethanizer 500, providing the necessary gaseous feedstock for the operation of the demethanizer 300 and the deethanizer 500.

[0167] It should be noted that there are no requirements for the reboiler 1300; it can be natural gas, steam, heat transfer oil, or seawater, and the staff can choose the heat source according to the required temperature.

[0168] This application also proposes a method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal based on the aforementioned process system, referring to... Figure 1 As shown, it includes:

[0169] Heat exchange section: After pre-cooling in the first heat exchanger 100, the raw natural gas is expanded and cooled by the expansion compressor unit 1000 to recover its pressure energy and further reduce its temperature before entering the demethanizer 300; the raw LNG is pressurized by the rich liquid booster pump 700 and divided into three streams: one stream enters the second heat exchanger 200 and the first heat exchanger 100 in sequence to provide cooling, and then serves as the liquid feed at the top of the demethanizer 300; another stream enters the second heat exchanger 200 to provide cooling and then serves as the liquid feed at the top of the demethanizer 300; and the third stream enters the third heat exchanger 600 to provide cooling and then serves as the liquid feed at the top of the demethanizer 300.

[0170] Demethanizing section: The lean natural gas exiting from the top of the demethanizer 300 is compressed and pressurized by the expansion compressor unit 1000, then enters the first heat exchanger 100 for liquefaction, and then enters the second heat exchanger 200 for subcooling, after which it is divided into two streams. One stream is further subcooled by the third heat exchanger 600 and serves as the liquid phase reflux at the top of the demethanizer 300. The other stream is pressurized by the lean liquid booster pump 800 and then divided into two streams entering the first heat exchanger 100. After the two lean liquid streams are vaporized and reheated by the first heat exchanger 100, one stream is directly heated to the external output temperature and then output, while the other stream is heated and reheated by the air heater 410 and then heated to the external output temperature by the heater 420 before being output. A stream of low-temperature hydrocarbon liquid is extracted from the middle of the demethanizer 300 and enters the first heat exchanger 100. After reheating, it returns to the demethanizer 300. The hydrocarbon liquid at the bottom of the demethanizer 300 is heated by the reboiler and then transported to the deethaner 500 in liquid phase.

[0171] De-ethane removal section: The demethanized liquid from the bottom of the demethanizer 300 is sent to the middle of the de-ethaner 500. The top gas phase of the de-ethaner 500 enters the first heat exchanger 100 for condensation and then enters the reflux tank 1110. It is then pressurized by the reflux pump 1120 and used as reflux for the de-ethaner 500. The bottom hydrocarbon liquid of the de-ethaner 500 is heated and separated in a reboiler. The liquid phase then exchanges heat with another portion of the gaseous ethane from the top of the de-ethaner 500 in the second heat exchanger 200 before being separately discharged.

[0172] It should be noted that the terms "one embodiment," "embodiment," "exemplary embodiment," "some embodiments," etc., mentioned in the specification indicate that the described embodiment may include a specific feature, structure, or characteristic, but not every embodiment necessarily includes that specific feature, structure, or characteristic. Furthermore, such phrases do not necessarily refer to the same embodiment. Moreover, when a specific feature, structure, or characteristic is described in connection with an embodiment, implementing such a feature, structure, or characteristic in conjunction with other embodiments, whether explicitly described or not, is within the knowledge scope of those skilled in the art.

[0173] Generally speaking, terms should be understood at least in part by their use in context. For example, at least in part by context, the term "one or more" as used in the text can be used to describe any feature, structure, or characteristic of the singular meaning, or a combination of features, structures, or characteristics of the plural meaning. Similarly, at least in part by context, terms such as "a" or "the" can also be understood to convey either singular or plural usage.

[0174] It should be readily understood that the terms “on,” “above,” and “on top of” in this application should be interpreted in the broadest possible sense, such that “on” means not only “directly on something” but also “on something” with an intermediate feature or layer therebetween, and that “above” or “on top of” means not only “on something” but also “on something” without an intermediate feature or layer therebetween (i.e., directly on something).

[0175] Furthermore, for ease of explanation, spatially relative terms such as "below," "below," "under," "above," and "above" may be used to describe the relationship of one element or feature relative to other elements or features as shown in the figures. Spatially relative terms are intended to encompass different orientations of the device in use or operation other than those shown in the figures. The device may have other orientations (rotated 90° or in other orientations), and the spatially relative descriptive terms used herein may be interpreted accordingly.

[0176] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit them. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some or all of the technical features therein. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of this application.

Claims

1. A method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal, characterized in that, Includes the following steps: The raw material natural gas is cooled to a first preset temperature zone, and the cooled raw material natural gas is transported to the first inlet of the demethanizer (300); The raw material LNG is preheated to the second preset temperature zone, and the preheated raw material LNG is transported to the second inlet of the demethanizer (300); The lean natural gas at the top of the demethanizer (300) is discharged to the outside of the demethanizer (300); The demethanized liquid at the bottom of the demethanizer (300) is diverted to the outside of the demethanizer (300); The raw material natural gas is exchanged for heat with the raw material LNG.

2. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to claim 1, characterized in that, The process of cooling the raw natural gas to a first preset temperature zone and then conveying the cooled raw natural gas to the first inlet of the demethanizer (300) includes the following steps: The raw natural gas is transported to the first heat exchanger (100) to cool the raw natural gas for the first time; The raw natural gas, which has undergone the first cooling process, is expanded and depressurized to cool it a second time. The raw material natural gas, which has been cooled for the second time, is transported to the first inlet of the demethanizer (300).

3. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving station according to claim 2, characterized in that, Expansion and decompression can be performed on the expansion end of the expansion compressor unit (1000). Alternatively, expansion pressure reduction can be achieved by expanding and reducing pressure through a throttle valve.

4. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to claim 2, characterized in that, The step of preheating the raw material LNG to a second preset temperature zone and then conveying the preheated raw material LNG to the second inlet of the demethanizer (300) includes the following steps: The raw material LNG is transported to the second heat exchanger (200) for the first preheating of the raw material LNG; The raw material LNG, after being preheated for the first time, is transported to the first heat exchanger (100) for a second preheating of the raw material LNG; The preheated LNG feedstock is then transported to the second inlet of the demethanizer (300).

5. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to claim 4, characterized in that, Within the first heat exchanger (100), the raw material LNG exchanges heat with the raw material natural gas.

6. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to any one of claims 1-5, characterized in that, The step of preheating the raw material LNG to a second preset temperature zone and then conveying the preheated raw material LNG to the second inlet of the demethanizer (300) includes the following steps: The raw material LNG is transported to the second heat exchanger (200) for the first preheating of the raw material LNG; The preheated LNG feedstock is transported to the second inlet of the demethanizer (300).

7. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to any one of claims 1-5, characterized in that, The process of removing lean natural gas from the top of the demethanizer (300) to the outside of the demethanizer (300) includes the following steps: The lean natural gas is delivered to the compression end of the expansion compressor unit (1000) to pressurize the lean natural gas; The pressurized lean natural gas is cooled for the first time so that it condenses into liquid lean natural gas; The liquefied lean natural gas is transported to the top of the demethanizer (300); And / or, pressurize and reheat the liquid lean natural gas to vaporize it into high-pressure lean natural gas.

8. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to claim 7, characterized in that, The pressurized lean natural gas is first cooled to condense into liquid lean natural gas, including the following steps: The pressurized lean natural gas is transported to the first heat exchanger (100) so that the lean natural gas is cooled and condensed. The condensed liquid lean natural gas is discharged to the outside of the first heat exchanger (100).

9. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to claim 7, characterized in that, The process of conveying the liquid lean natural gas into the interior of the demethanizer (300) includes the following steps: The liquid lean natural gas is transported to a second heat exchanger (200) to subcool the liquid lean natural gas; The supercooled liquid lean natural gas is pumped into the demethanizer (300).

10. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to claim 7, characterized in that, The liquid lean natural gas is pressurized and reheated to vaporize it into high-pressure lean natural gas, comprising the following steps: The liquefied lean natural gas is delivered to a lean liquid booster pump (800) to pressurize the liquefied lean natural gas; The pressurized liquid lean natural gas is transported to the first heat exchanger (100) to reheat the liquid lean natural gas and vaporize it into high-pressure lean natural gas.

11. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to claim 7, characterized in that, After pressurizing the liquid lean natural gas, it is transported to the first heat exchanger (100) to reheat the liquid lean natural gas and vaporize it into high-pressure lean natural gas. Then, the following steps are also included: The high-pressure lean natural gas is heated to a preset external transmission temperature zone by a heating component (400).

12. The method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal according to any one of claims 1-5, characterized in that, After diverting the demethanized liquid at the bottom of the demethanizer (300) to the outside of the demethanizer (300), the following steps are also included: The demethanized liquid is then fed into the deethaner (500); The liquefied petroleum gas at the bottom of the deethaner (500) is diverted to the outside of the deethaner (500); The ethane at the top of the deethaner (500) is cooled and then refluxed back to the deethaner (500).

13. A method for separating gas-liquid miscible light hydrocarbons in an LNG receiving terminal, characterized in that, Includes the following steps: The raw material natural gas is cooled to a first preset temperature zone, and the cooled raw material natural gas is transported to the first inlet of the demethanizer (300); The raw material LNG is preheated to the second preset temperature zone, and the preheated raw material LNG is transported to the second inlet of the demethanizer (300); The lean natural gas at the top of the demethanizer (300) is discharged to the outside of the demethanizer (300); The demethanized liquid at the bottom of the demethanizer (300) is diverted to the outside of the demethanizer (300); The raw material natural gas and the raw material LNG exchange heat through a first heat exchanger (100).

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