Separation system for separating ethane from liquefied natural gas

Abstract

The invention discloses a separation system for separating ethane from liquefied natural gas, which comprises a condensation assembly, a flash absorption tower, a demethanizer, a deethanizer and an ethane storage tank, the liquefied natural gas storage tank is sequentially connected with the condensation assembly, the flash absorption tower, the demethanizer, the deethanizer and the ethane storage tank through a first valve, and the ethane storage tank is connected with the deethanizer. The ethane storage tank is used for storing ethane, and an outlet of the ethane storage tank is communicated between the first valve and the condensation assembly. When the separation system is shut down, ethane in the ethane storage tank is introduced into the separation system, methane in the separation system is replaced, the temperature in the condensation assembly, the flash absorption tower and the demethanizer is reduced, cold insulation is achieved during the shut down period of the separation system, the temperature is close to the temperature of receivable materials, and the pre-cooling time when the separation system is started is shortened; and quick starting of the separation system is realized.

Description

Technical Field

[0001] This application belongs to the technical field of separating light hydrocarbons from liquefied natural gas, specifically relating to a separation system for separating ethane from liquefied natural gas. Background Technology

[0002] Liquefied natural gas (LNG) is classified as lean or rich based on its light hydrocarbon content. Rich LNG has a high light hydrocarbon content, allowing for the separation of light hydrocarbons for calorific value adjustment or the extraction of high-value-added products such as ethane and liquefied petroleum gas (LPG) as high-quality chemical feedstocks. Although the calorific value of LNG decreases after the removal of light hydrocarbons, it still meets the calorific value requirements for pipeline natural gas.

[0003] With the development of China's new materials and chemical industry, ethane has attracted increasing attention as a chemical raw material. Separating ethane from liquefied natural gas using an ethane separation unit has become a feasible solution. The operating temperature range of the ethane separation unit is -150℃ to -60℃. To ensure the normal operation of the ethane separation unit, it needs to be cooled to a temperature suitable for receiving materials, typically -100℃ to -90℃.

[0004] The ethane separator and the LNG receiving terminal are located a long distance apart, necessitating the laying of insulated pipelines to the ethane separator. This would utilize the cooling capacity of the liquefied natural gas (LNG) within the LNG receiving terminal to maintain the ethane separator's temperature during shutdowns, reducing the time required to cool the material to the receiving temperature upon restarting and thus improving the separator's separation capacity and efficiency. However, due to the long distance of the insulated pipelines, the insulation effect on the ethane separator is far less than the requirements for restarting, resulting in poor insulation performance and low technical and economic efficiency during shutdowns. Summary of the Invention

[0005] To address the technical problems of poor insulation and uneconomical practices in related technologies where ethane separation units are connected to LNG receiving terminals via long-distance insulated pipelines for insulation during ethane separation unit shutdowns, this application provides a liquefied natural gas (LNG) ethane separation system. The LNG ethane separation system includes:

[0006] A condensation assembly connected to a liquefied natural gas storage tank via a first valve;

[0007] A flash absorption tower is connected to the condensation assembly;

[0008] A demethanizing tower, connected to the flash absorption tower, is used to remove methane from the liquefied natural gas treated by the flash absorption tower;

[0009] An ethane removal tower, connected to the demethanizer tower, is used to remove ethane from the liquefied natural gas that has been processed by the demethanizer tower;

[0010] An ethane storage tank is connected to the de-ethane tower. The ethane storage tank is used to store ethane, and the outlet of the ethane storage tank is connected between the first valve and the condensation assembly.

[0011] In some embodiments, the separation system further includes:

[0012] A pressure gauge is connected in series to the pipeline connecting the top of the flash absorption tower and the top of the demethanizer tower;

[0013] The seventh valve has its inlet connected to the pipeline connecting the top of the flash absorption tower and the top of the demethanizer tower, and its outlet connected to the outside or related equipment.

[0014] In some embodiments, the separation system further includes:

[0015] An ethane vaporizer, connected to the ethane storage tank, is used to vaporize the ethane output from the ethane storage tank.

[0016] An ethane reheater and compressor are connected between the top of the demethanizer and the outlet of the ethane vaporizer.

[0017] In some embodiments, the condensation assembly includes:

[0018] A primary condenser, the cold side inlet of which is connected to the liquefied natural gas storage tank, and the hot side inlet of which is connected to the top of the flash absorption tower;

[0019] A secondary condenser, wherein the cold-side inlet of the secondary condenser is connected to the cold-side outlet of the primary condenser, the cold-side outlet of the secondary condenser is connected to the demethanizer, and the hot-side inlet of the secondary condenser is connected to the top of the flash absorption tower and the top of the demethanizer.

[0020] A condensate storage tank, the inlet of which is connected to the hot-side outlet of the primary condenser and the hot-side outlet of the secondary condenser, and the outlet of which is connected to the LNG receiving terminal.

[0021] In some embodiments, the condensation assembly further includes:

[0022] An inlet buffer tank and a booster are connected between the flash absorption tower and the secondary condenser.

[0023] In some embodiments, the condensate storage tank includes:

[0024] A primary condensate tank is connected to the hot-side outlet of the primary condenser;

[0025] The secondary condensate tank is connected to the hot-side outlet of the secondary condenser. The primary condensate tank is connected to the secondary condensate tank via a first pump body, and the secondary condensate tank is connected to the LNG receiving station via a second pump body.

[0026] In some embodiments, the separation system further includes:

[0027] An ethane condenser and an ethane condensate tank are provided. The hot-side inlet of the ethane condenser is connected to the top of the de-ethane tower, and the hot-side outlet of the ethane condenser is connected to the ethane storage tank. The cold side of the ethane condenser is connected between the secondary condensate tank and the LNG receiving station.

[0028] In some embodiments, the ethane condensate tank is connected to the top of the deethaner column.

[0029] In some embodiments, the outlet of the secondary condensate tank is connected to the top of the flash absorption tower and the top of the demethanizer.

[0030] In some embodiments, the separation system further includes:

[0031] The first reboiler is connected between the demethanizer and the deethanizer, and the heat source of the first reboiler includes a steam heat source, a circulating hot water heat source and an ambient heat source.

[0032] In some embodiments, the separation system further includes:

[0033] The second reboiler is connected between the deethaner and the LNG receiving station. The heat sources for the second reboiler include a steam heat source, a circulating hot water heat source, and an ambient heat source.

[0034] A liquefied natural gas (LNG) ethane separation system according to one or more embodiments of this application includes a condensation assembly, a flash absorption tower, a demethanizer, a deethaner, and an ethane storage tank. The LNG storage tank is sequentially connected to the condensation assembly, flash absorption tower, demethanizer, deethaner, and ethane storage tank via a first valve. The ethane storage tank is connected to the deethaner and is used to store ethane. The outlet of the ethane storage tank is connected between the first valve and the condensation assembly. When the separation system is shut down, ethane from the ethane storage tank is introduced into the separation system to displace the methane, thereby lowering the temperature in the condensation assembly, flash absorption tower, and demethanizer. This provides cooling during system shutdown, keeping the temperature close to the acceptable material temperature, reducing the pre-cooling time during system startup, and enabling rapid system startup. Attached Figure Description

[0035] Figure 1 This is a schematic diagram of a system structure for separating light hydrocarbons from liquefied natural gas in related technologies;

[0036] Figure 2 This is a schematic diagram of the structure of a separation system for separating ethane from liquefied natural gas in one or more embodiments of this application.

[0037] Explanation of reference numerals in the attached figures:

[0038] B-1, First valve; B-2, Second valve; B-3, Third valve; B-4, Fourth valve; B-5, Fifth valve; PT, Pressure gauge; B-7, Seventh valve;

[0039] E-1, Primary condenser; E-2, Secondary condenser; T-1, Flash absorption tower; P-2, Second pump body; T-2, Demethanizer; E-3, First reboiler; T-3, Deethanerizer; E-5, Second reboiler; P-3, Third pump body; E-4, Ethane condenser; V-4, Ethane condensate tank; P-4, Fourth pump body; TK-1, Ethane storage tank; P-5, Fifth pump body; E-6, Ethane vaporizer; P-1, First pump body; V-1, Primary condensate tank; V-2, Secondary condensate tank; V-3, Inlet buffer tank; C-1, Booster compressor; E-7, Ethane reheater; C-2, Compressor. Detailed Implementation

[0040] To enable those skilled in the art to more clearly understand this application, the technical solutions in the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of this application, and not all of the embodiments. Based on the embodiments of this application, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the scope of protection of this application.

[0041] Liquefied natural gas (LNG) has seen widespread development globally in recent years due to its cleanliness, efficiency, and flexible supply. With the adjustment of China's energy consumption structure and the rapid growth of its annual natural gas consumption, LNG, as an important supplement to overseas natural gas resources, has seen its imports increase year by year. In 2021, China's LNG imports reached 79.27 million tons, surpassing Japan to become the world's largest importer. LNG resources are mainly composed of methane, but also contain some ethane and other light hydrocarbons, and contain a large amount of cold energy. Therefore, fully utilizing LNG resources has significant economic and social implications.

[0042] Liquefied natural gas (LNG) is classified as lean or rich based on its light hydrocarbon content. Rich LNG has a high light hydrocarbon content, which can be separated to adjust its calorific value or to obtain high-value-added products such as ethane and liquefied petroleum gas (LPG) as high-quality chemical feedstocks. Although the calorific value of LNG decreases after removing light hydrocarbons, it still meets the calorific value requirements for pipeline natural gas.

[0043] Compared to ethylene production technologies using naphtha and other feedstocks through cracking, ethylene production using light feedstocks such as ethane and propane has significant techno- and economic advantages. In particular, with the increasing use of lighter feedstocks in ethylene plants both domestically and internationally, the demand for light hydrocarbons such as ethane and propane is growing rapidly, with the ethane market experiencing a supply shortage. As a major LNG importer, my country should refer to [further details needed]. Figure 1 Separating light hydrocarbons such as ethane from LNG resources has become an effective supplementary method for obtaining high-quality ethylene feedstock.

[0044] During normal operation, it is feasible to remove light hydrocarbons from LNG through distillation. However, considering that LNG resources come from typical domestic LNG receiving terminals, and that the export operation patterns of these terminals are greatly affected by seasonal gas consumption fluctuations, LNG receiving terminals generally exhibit uneven export volumes. According to statistical data on the monthly gasification export volumes of domestic 7 million tons / year LNG receiving terminals over the past five years, a significant unevenness is observed. Gasification export volumes are lower from April to July each year, relatively stable during the peak summer season from August to October, and higher during the winter supply period from November to March of the following year, with a monthly export unevenness coefficient reaching 4.2 times.

[0045] The uneven distribution of LNG receiving terminals, wide load adjustment range, and high frequency of load changes place high demands on the flexibility of LNG ethane separation units. This also requires high flexibility and adaptability in the control logic of these units. Furthermore, the operating temperature range of the ethane separation unit is -150℃ to -60℃, which is very low. When multiple units are shut down due to uneven LNG receiving terminal gas flow, the cryogenic media in the critical equipment and systems must be emptied to prevent accidental overpressure releases. Similarly, when multiple units are started up due to uneven LNG receiving terminal gas flow, additional cooling is required to gradually cool the critical equipment and systems to an acceptable temperature, typically -100℃ to -90℃, before process materials can be introduced. The shutdown and startup processes consume significant pre-cooling time and raw materials. In China, ethane separation units typically take 5 to 7 days to recover from pre-cooling at room temperature, limiting their ethane separation capacity and utilization rate.

[0046] With the development of China's new materials and chemical industry, ethane has received increasing attention as a chemical raw material. However, the LNG receiving terminal industry has been developing for nearly 30 years. At present, no LNG receiving terminals with an annual capacity of more than 3 million tons per year have reserved land for ethane separation units during construction. This means that new ethane separation units need to be built around the LNG receiving terminals.

[0047] The ethane separator and the LNG receiving terminal are located a long distance apart, necessitating the laying of insulated pipelines to the ethane separator. This would utilize the cooling capacity of the liquefied natural gas (LNG) at the LNG receiving terminal during ethane separator downtime, reducing the time required to cool the material to the receiving temperature upon restarting, thus improving the separator's separation capacity and efficiency. However, due to the long distance of the insulated pipelines, the cooling effect of the ethane separator is far less than the requirements for restarting, resulting in poor cooling performance and low technical and economic efficiency during downtime. Furthermore, the cooling capacity of the LNG at the receiving terminal is transported to the ethane separator via these pipelines, and the control feedback cycle for cooling the ethane separator to the receiving temperature is approximately 3 to 4 days, leading to a long operational feedback cycle and poor economic efficiency. Additionally, the ethane separator generates a large amount of boil-off methane gas (BOG) during operation, requiring a separate refrigeration and liquefaction unit for collection and storage, resulting in significant power consumption.

[0048] In summary, for ethane separation units, matching the operating load, number of operating series, shutdown and start-up cycles of the ethane separation unit with the uneven distribution of gas volume in the LNG receiving terminal market is crucial to the efficient and economical operation of the ethane separation unit.

[0049] To resolve the above issues, please refer to Figure 2 This application provides a separation system for separating ethane from liquefied natural gas (LNG). The system includes a condensation assembly, a flash absorption tower T-1, a demethanizer tower T-2, a deethanizer tower T-3, and an ethane storage tank TK-1. The condensation assembly is connected to the LNG storage tank via a first valve B-1. The flash absorption tower T-1 is connected to the condensation assembly. The demethanizer tower T-2 is connected to the flash absorption tower T-1 and is used to remove methane and nitrogen from the LNG processed by the flash absorption tower T-1. The deethanizer tower T-3 is connected to the demethanizer tower T-2 and is used to remove ethane and propane from the LNG processed by the demethanizer tower T-2. The ethane storage tank TK-1 is connected to the deethanizer tower T-3 and is used to store ethane. The outlet of the ethane storage tank TK-1 is connected between the first valve B-1 and the condensation assembly.

[0050] The separation system also includes pressure gauge PT, seventh valve B-7, ethane vaporizer E-6, ethane reheater E-7, compressor C-2, ethane condenser E-4, and ethane condensate tank V-4. Pressure gauge PT is connected in series to the pipeline connecting the top of flash absorption tower T-1 and the top of demethanizer T-2. The inlet of seventh valve B-7 is connected to the pipeline connecting the top of flash absorption tower T-1 and the top of demethanizer T-2, and the outlet of seventh valve B-7 is connected to the outside environment or related equipment. Ethane vaporizer E-6 is connected to ethane storage tank TK-1 and is used to vaporize the ethane output from ethane storage tank TK-1. Ethane reheater E-7 and compressor C-2 are connected between the top of demethanizer T-2 and the outlet of ethane vaporizer E-6. Ethane condenser E-4 and ethane condensate tank V-4 are connected between deethanizer T-3 and ethane storage tank TK-1. Ethane condenser E-4 is connected between secondary condensate tank V-2 and the LNG receiving terminal. Ethane condensate tank V-4 is connected to the top of deethanizer T-3. The outlet of secondary condensate tank V-2 is connected to the top of flash absorber T-1 and the top of demethanizer T-2.

[0051] The separation system also includes a first reboiler E-3 and a second reboiler E-5. The first reboiler E-3 is connected between the demethanizer T-2 and the deethanizer T-3, and its heat sources include steam, circulating hot water, and ambient heat. The second reboiler E-5 is connected between the deethanizer T-3 and the LNG receiving terminal, and its heat sources include steam, circulating hot water, and ambient heat.

[0052] The condensation assembly includes a primary condenser E-1, a secondary condenser E-2, a condensate storage tank, an inlet buffer tank V-3, and a booster compressor C-1. The cold-side inlet of the primary condenser E-1 is connected to the liquefied natural gas storage tank, and the hot-side inlet of the primary condenser E-1 is connected to the top of the flash absorption tower T-1. The cold-side inlet of the secondary condenser E-2 is connected to the cold-side outlet of the primary condenser E-1, and the cold-side outlet of the secondary condenser E-2 is connected to the flash absorption tower T-1. The hot-side inlet of the secondary condenser E-2 is connected to the top of both the flash absorption tower T-1 and the demethanizer tower T-2.

[0053] The inlet of the condensate storage tank is connected to the hot-side outlet of the primary condenser E-1 and the hot-side outlet of the secondary condenser E-2. The outlet of the condensate storage tank is connected to the LNG receiving terminal. The inlet buffer tank V-3 and the booster compressor C-1 are connected between the flash absorption tower T-1 and the secondary condenser E-2. The flash absorption tower T-1 is connected to the secondary condenser E-2 through the inlet buffer tank V-3 and the booster compressor C-1.

[0054] The condensate storage tanks include a primary condensate tank V-1 and a secondary condensate tank V-2. The primary condensate tank V-1 is connected to the hot-side outlet of the primary condenser E-1. The secondary condensate tank V-2 is connected to the hot-side outlet of the secondary condenser E-2. The primary condensate tank V-1 is connected to the secondary condensate tank V-2 via a first pump body, and the secondary condensate tank V-2 is connected to the LNG receiving terminal via a second pump body.

[0055] The separation system also includes ethane storage tank TK-1, ethane condenser E-4, ethane condensate tank V-4, ethane vaporizer E-6, first reboiler E-3, and second reboiler E-5. Eethane storage tank TK-1 is connected to the de-ethanizer T-3 and is used to store ethane. Eethane condensate tank V-4 is connected to the top of the de-ethanizer T-3. The hot-side inlet of ethane condenser E-4 is connected to the top of the de-ethanizer T-3, and the hot-side outlet of ethane condenser E-4 is connected to ethane storage tank TK-1. The cold side of ethane condenser E-4 is connected between the secondary condensate tank V-2 and the LNG receiving terminal. Eethane vaporizer E-6 is connected to ethane storage tank TK-1 and is used to vaporize the ethane output from ethane storage tank TK-1. The first reboiler E-3 is connected between the demethanizer T-2 and the deethanizer T-3. The heat sources for the first reboiler E-3 include steam, circulating hot water, and ambient heat. The second reboiler E-5 is connected between the deethanizer T-3 and the LNG receiving terminal. The heat sources for the second reboiler E-5 include steam, circulating hot water, and ambient heat.

[0056] Normal operating procedure: The LNG feedstock rich liquid (pressure approximately 1.0 MPa) pumped out from the LNG storage tank at the LNG receiving terminal directly enters the first-stage condenser E-1 of the LNG ethane separation system. There is no need to set up a feedstock booster pump to pressurize the LNG feedstock rich liquid, thereby reducing the pressure level of the upstream equipment and pipelines of the demethanizer T-2.

[0057] The rich LNG feedstock is heated sequentially by a series of primary condensers E-1 and E-2 before entering the flash absorption tower T-1. The lean gas at the top of flash absorption tower T-1 contains more than 99% mol of methane. To utilize the cooling capacity of LNG in stages, a portion of the lean gas at the top of flash absorption tower T-1 (approximately 20% of the LNG feed) is not pressurized and directly enters the primary condenser E-1, where it is condensed into a lean liquid at approximately -130°C by the LNG feed. This lean liquid is then stored in the primary condensate tank V-1 and, after being pressurized by the first pump P-1, enters the secondary condensate tank V-2.

[0058] Another portion of the lean gas from the top of flash absorption tower T-1 enters the inlet buffer tank V-3, where it is pressurized by booster compressor C-1 to the pressure of the gas output from the top of the demethanizer T-2. The lean gas from the top of flash absorption tower T-1 is divided into two parts and enters the primary condenser E-1 and the secondary condenser E-2 for condensation, respectively. This ensures that the lean gas from the top of flash absorption tower T-1, which is directly fed into the primary condenser E-1, is not pressurized by booster compressor C-1. This staged condensation method significantly reduces the power consumption of booster compressor C-1.

[0059] The bottom product of flash absorber T-1 is pressurized by the second pump P-2 and then enters demethanizer T-2, which operates at a pressure below 1.5 MPa. The top product of demethanizer T-2 is methane at -116°C, which mixes with lean gas from the outlet of booster C-1 and enters the secondary condenser E-2. There, it is condensed by the LNG feed into a lean liquid at approximately -126°C and stored in the secondary condensate tank V-2.

[0060] The methane gas produced at the top of the flash absorber T-1 and the demethanizer T-2 is rationally distributed within the primary condenser E-1 and secondary condenser E-2, respectively. The LNG feed carries its own cooling capacity, which is then reliquefied into lean LNG. This fully utilizes the LNG's own cooling energy for condensation, eliminating the need for external cooling and reducing condensation energy consumption. Furthermore, it facilitates the return of the condensed methane to the vaporizer inlet of the LNG receiving terminal via pumping, further saving energy. Lean LNG discharged from the secondary condensate tank V-2 is introduced from the tops of both the flash absorber T-1 and the demethanizer T-2 as absorbent and cold reflux, improving the recovery and utilization rate of light hydrocarbons.

[0061] Part of the methane condensate in the secondary condensate tank V-2 enters the top of the flash absorption tower T-1 as absorbent and cold reflux. The remainder is pressurized by the third pump P-3, and part of it is sent to the top of the demethanizer tower T-2 as absorbent and cold reflux. The remainder provides cooling to the top of the deethanizer tower T-3 and then returns to the vaporizer inlet of the LNG receiving station.

[0062] The bottom of the demethanizer T-2 contains C2+ light hydrocarbons, which are then fed into the deethanizer T-3. The deethanizer T-3 operates at a pressure of 0.2 MPa. The ethane vapor at the top of the deethanizer T-3 is condensed in the ethane condenser E-4 at the top of the deethanizer T-3 using lean liquid before the vaporizer inlet returned to the LNG receiving station, resulting in a liquid phase of approximately -71°C. This liquid then enters the ethane condensate tank V-4 at the top of the deethanizer T-3. Part of the condensate in ethane condensate tank V-4 is returned to the top of the deethanizer T-3 as absorbent and cold reflux, while the remainder is pressurized by the fourth pump P-4 for external storage or transported to the ethane storage tank TK-1. By integrating the ethane condenser E-4 at the top of the deethaner T-3 tower with the lean methane condensate after the removal of light hydrocarbons, the cooling capacity of the lean methane condensate returning to the LNG receiving terminal is significantly reduced while supplying cooling capacity to the top of the deethaner T-3 tower, thereby reducing the energy consumption of the vaporizer in the downstream LNG receiving terminal.

[0063] Ethane condensate in ethane storage tank TK-1 is pressurized by the fifth pump P-5 and then transported to ethane vaporizer E-6. The ethane condensate vaporized by ethane vaporizer E-6 is then transported to downstream units as a chemical feedstock, realizing the deep utilization of ethane separated from liquefied natural gas.

[0064] The bottom of the deethaner T-3 tower is pressurized by the second reboiler E-5 and the third pump P-3, and then the liquefied petroleum gas (LPG) is returned to the vaporizer inlet of the LNG receiving station.

[0065] The low operating pressures of the demethanizer T-2 and deethanizer T-3 reduce equipment investment costs, improve the efficiency of liquefied natural gas separation of light hydrocarbons, and lower energy consumption. The first reboiler E-3 at the bottom of the demethanizer T-2 and the second reboiler E-5 of the deethanizer T-3 can both utilize steam, circulating hot water, or ambient heat sources (such as seawater) as heat sources, further reducing energy consumption in these two reboilers.

[0066] Shutdown and Cold Storage Procedure: Close valves B-1, B-2, B-3, B-4, and B-5. Automatically control valve B-7 via pressure gauge PT to maintain the operating pressure in flash absorber T-1 and demethanizer T-2 at 0.4 MPa, discharging the liquefied natural gas volatilized from the separation system into the fuel gas system of other light hydrocarbon units. As the pressure in flash absorber T-1 and demethanizer T-2 stabilizes, gradually open valve B-5 to introduce ethane from ethane storage tank TK-1 into the primary condenser E-1, achieving liquid ethane input into the separation system and displacing the methane within the system. Ethane from ethane storage tank TK-1 (temperature -88℃) is pressurized by the fifth pump body P-5 and then transported to the first-stage condenser E-1 through the fifth valve B-5, thus introducing liquid ethane into the separation system. The ethane is then heated sequentially by the first-stage condenser E-1 and the second-stage condenser E-2 connected in series before entering the flash absorption tower T-1, the second pump body P-2, and the demethanizer T-2. The ethane gas delivered to the flash absorption tower T-1 and the demethanizer T-2 replaces the evaporated gas of the liquefied natural gas, thereby reducing the temperature in the first-stage condenser E-1, the second-stage condenser E-2, the flash absorption tower T-1, and the demethanizer T-2, and enabling the separation system to be shut down and kept cold.

[0067] When the methane content detected at pressure gauge PT is less than 3%, close valve B-7 (seventh valve). Ethane pumped from ethane storage tank TK-1 enters the separation system, simplifying the shutdown and cooling process of the separation system. At the same time, the pressure rating of most equipment and pipelines in the separation system can be maintained at 150#, saving on engineering construction investment and reducing the operational hazards of process facilities.

[0068] Turn on the ethane reheater E-7 and the reciprocating compressor C-2. The ethane vapor in the separation system is reheated by the ethane reheater E-7 and then pressurized by the reciprocating compressor C-2. The pressurized ethane (temperature 40℃) enters the downstream of the ethane vaporizer E-6 and is fed into the low-pressure ethane export pipeline (pressure 1.5MPag).

[0069] By maintaining a slightly positive operating pressure (30 kPaG) in the flash absorption tower T-1 and the demethanizer tower T-2 within the separation system, the separation system is kept at a low temperature between -80°C and -88°C. This cold preservation during system shutdown keeps the temperature close to the acceptable material temperature, reducing the pre-cooling time during system startup and enabling rapid system start-up.

[0070] During the shutdown and cold preservation process, the flash absorption tower T-1 and the demethanizer tower T-2 operate under low pressure. The ethane operating temperature is low, and the cold preservation effect is good, which reduces the cold preservation operation cost of the separation system and the investment in the separation system, and improves the technical and economic efficiency.

[0071] It should be noted that the downstream equipment of the demethanizer T-2 is cooled to an acceptable material temperature simultaneously with the cooling of both the upstream and downstream equipment of the demethanizer T-2. Maintaining the cold insulation of the demethanizer T-2 and its upstream equipment during the shutdown and cold insulation process of the separation system reduces the pre-cooling time during system startup, enabling rapid system startup. This reduces the cold insulation cost during system shutdown and improves technical and economic efficiency.

[0072] The ethane separation system for liquefied natural gas (LNG) is suitable for production plants where the ethane separation unit is located far from the LNG receiving terminal. It separates ethane and liquefied petroleum gas (LPG) from the rich LNG feedstock unloaded from the LNG receiving terminal to produce high-quality chemical feedstocks. The system utilizes ethane storage tank TK-1, pressure gauge PT, seventh valve B-7, ethane reheater E-7, and compressor C-2 to maintain coolness during system shutdown, reducing pre-cooling time during startup and enabling rapid system start-up. This improves the technical and economic efficiency of LNG light hydrocarbon separation and aligns with sustainable development principles, yielding significant economic and social benefits. Furthermore, the switching operation from normal operation to shutdown and cool-keeping is simple, enhancing the flexibility and convenience of the switching process.

[0073] In related technologies, after an ethane separation unit connected to an LNG receiving terminal is shut down, restarting it requires approximately 5 to 7 days of pre-cooling from ambient temperature to restore it to normal operating temperature. This limits the ethane separation capacity of the ethane separation unit and reduces its utilization rate. The ethane separation system for liquefied natural gas described in this application, through a system shutdown and cooling process, can shorten the start-up time of the separation system to 2 to 3 hours, thereby enhancing the ethane separation capacity and utilization rate of the system.

[0074] The ethane separation system for liquefied natural gas can seamlessly connect the operating series, shutdown and start-up cycles of the separation system with the unevenness of market gas volume at LNG receiving terminals. The switching operation between normal operation and precooling process is simple, improving the flexibility and convenience of switching operations.

[0075] In this application, unless otherwise expressly specified and limited, "above" or "below" the second feature can include direct contact between the first and second features, or contact between the first and second features through another feature between them. Furthermore, "above," "over," and "on top" of the second feature includes the first feature being directly above or diagonally above the second feature, or simply indicates that the first feature is at a higher horizontal level than the second feature. "Below," "below," and "under" the second feature includes the first feature being directly below or diagonally below the second feature, or simply indicates that the first feature is at a lower horizontal level than the second feature.

[0076] In the description of this application, it should be understood that the terms "center", "longitudinal", "lateral", "length", "width", "thickness", "upper", "lower", "front", "rear", "left", "right", "vertical", "horizontal", "top", "bottom", "inner", "outer", "clockwise", and "counterclockwise" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing this application and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this application.

[0077] In this application, unless otherwise expressly specified and limited, the terms "connection," "fixed," etc., should be interpreted broadly. For example, "fixed" can mean a fixed connection, a detachable connection, or an integral part; it can mean a mechanical connection or an electrical connection; it can mean a direct connection or an indirect connection through an intermediate medium; it can mean the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this application according to the specific circumstances.

[0078] Furthermore, the use of terms such as "first" and "second" in this application is for descriptive purposes only and should not be construed as indicating or implying their relative importance or implicitly specifying the number of technical features indicated. Therefore, features defined with "first" or "second" may explicitly or implicitly include one or more features. In the description of this application, "multiple" means two or more, unless otherwise explicitly specified.

[0079] Although embodiments of this application have been shown and described, those skilled in the art will understand that various changes, modifications, substitutions and variations can be made to these embodiments without departing from the principles and spirit of this application, the scope of which is defined by the claims and their equivalents.

Claims

1. A separation system for separating ethane from liquefied natural gas, characterized in that, include: A condensation assembly connected to a liquefied natural gas storage tank via a first valve; A flash absorption tower is connected to the condensation assembly; A demethanizing tower, connected to the flash absorption tower, is used to remove methane from the liquefied natural gas treated by the flash absorption tower; An ethane removal tower, connected to the demethanizer tower, is used to remove ethane from the liquefied natural gas that has been processed by the demethanizer tower; An ethane storage tank is connected to the de-ethane tower. The ethane storage tank is used to store ethane, and the outlet of the ethane storage tank is connected between the first valve and the condensation assembly.

2. The ethane separation system for liquefied natural gas according to claim 1, characterized in that, The separation system also includes: A pressure gauge is connected in series to the pipeline connecting the top of the flash absorption tower and the top of the demethanizer tower; The seventh valve has its inlet connected to the pipeline connecting the top of the flash absorption tower and the top of the demethanizer tower, and its outlet connected to the outside or related equipment.

3. The ethane separation system for liquefied natural gas according to claim 2, characterized in that, The separation system also includes: An ethane vaporizer, connected to the ethane storage tank, is used to vaporize the ethane output from the ethane storage tank. An ethane reheater and compressor are connected between the top of the demethanizer and the outlet of the ethane vaporizer.

4. The ethane separation system for liquefied natural gas according to claim 1, characterized in that, The condensation assembly includes: A primary condenser, the cold side inlet of which is connected to the liquefied natural gas storage tank, and the hot side inlet of which is connected to the top of the flash absorption tower; A secondary condenser, wherein the cold-side inlet of the secondary condenser is connected to the cold-side outlet of the primary condenser, the cold-side outlet of the secondary condenser is connected to the demethanizer, and the hot-side inlet of the secondary condenser is connected to the top of the flash absorption tower and the top of the demethanizer. A condensate storage tank, the inlet of which is connected to the hot-side outlet of the primary condenser and the hot-side outlet of the secondary condenser, and the outlet of which is connected to the LNG receiving terminal.

5. The ethane separation system for liquefied natural gas according to claim 4, characterized in that, The condensation assembly also includes: An inlet buffer tank and a booster are connected between the flash absorption tower and the secondary condenser.

6. The ethane separation system for liquefied natural gas according to claim 4, characterized in that, The condensate storage tank includes: A primary condensate tank is connected to the hot-side outlet of the primary condenser; The secondary condensate tank is connected to the hot-side outlet of the secondary condenser. The primary condensate tank is connected to the secondary condensate tank via a first pump body, and the secondary condensate tank is connected to the LNG receiving station via a second pump body.

7. The separation system for separating ethane from liquefied natural gas according to any one of claims 4 to 6, characterized in that, The separation system also includes: An ethane condenser and an ethane condensate tank are provided. The hot-side inlet of the ethane condenser is connected to the top of the de-ethane tower, and the hot-side outlet of the ethane condenser is connected to the ethane storage tank. The cold side of the ethane condenser is connected between the secondary condensate tank and the LNG receiving station.

8. The separation system for separating ethane from liquefied natural gas according to claim 7, characterized in that, The ethane condensate tank is connected to the top of the de-ethane tower.

9. The separation system for separating ethane from liquefied natural gas according to claim 7, characterized in that, The outlet of the secondary condensate tank is connected to the top of the flash absorption tower and the top of the demethanizer.

10. The separation system for separating ethane from liquefied natural gas according to any one of claims 1 to 6 and 8 to 9, characterized in that, The separation system also includes: The first reboiler is connected between the demethanizer and the deethanizer, and the heat source of the first reboiler includes a steam heat source, a circulating hot water heat source and an ambient heat source.

11. The separation system for separating ethane from liquefied natural gas according to any one of claims 1 to 6 and 8 to 9, characterized in that, The separation system also includes: The second reboiler is connected between the deethaner and the LNG receiving station. The heat source for the second reboiler includes a steam heat source, a circulating hot water heat source, and an ambient heat source.

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