A natural gas recovery ethane system and a method for recovering ethane coproduced with helium

Abstract

The application discloses a natural gas recovery ethane system and a method for recovering ethane and co-producing helium, and belongs to the technical field of natural gas processing. The natural gas recovery ethane system comprises a natural gas decarburization device, a natural gas dehydration and mercury removal device, a first heat exchange device, a demethanizer, a deethanizer, a helium extraction column, a heavy hydrocarbon separator, a helium extraction cooler and a helium extraction separator. The discharge port of the natural gas decarburization device is connected with the feed port of the natural gas dehydration and mercury removal device, the discharge port of the natural gas dehydration and mercury removal device is connected with the feed port of the heavy hydrocarbon separator, the gas phase outlet of the heavy hydrocarbon separator is connected with the feed port of the helium extraction column through the first heat exchange device, the gas phase outlet of the helium extraction column is connected with the feed port of the helium extraction separator through the helium extraction cooler, the gas phase outlet of the helium extraction separator is used for discharging crude helium, the liquid phase outlet of the helium extraction separator is connected with the helium extraction column, and the liquid phase outlet of the helium extraction column is connected with the demethanizer. The above scheme can solve the problem that the utilization rate of natural gas is low.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of natural gas recovery of ethane, and particularly relates to a natural gas recovery of ethane system and a method for recovering ethane and co-producing helium. BACKGROUND

[0002] The ethylene industry is the core of the petrochemical industry. Ethane is usually used as the main raw material for cracking to produce ethylene. The construction investment and operation cost of an ethylene plant using ethane as the raw material are very low.

[0003] The main component of natural gas is alkane, of which methane accounts for the majority, and there are small amounts of ethane, propane and other components. In order to make better use of natural gas, achieve product diversification of natural gas and improve economic value, it is a good choice to recover and utilize ethane in natural gas.

[0004] However, in addition to alkane, the main component of natural gas also contains helium, which has a wide range of uses and can be used in medical research, aerospace and military industries. The natural gas recovery of ethane system in the related art does not recover helium, so the natural gas recovery of ethane system in the related art has a low utilization rate of natural gas. SUMMARY

[0005] The present application discloses a natural gas recovery of ethane system and a method for recovering ethane and co-producing helium to solve the problem of low utilization rate of natural gas.

[0006] In order to solve the above problems, the present application adopts the following technical solutions:

[0007] A natural gas recovery of ethane system, comprising a natural gas decarburization device, a natural gas dehydration and mercury removal device, a first heat exchange device, a demethanizer, a deethanizer, a helium extraction column, a heavy hydrocarbon separator, a helium extraction cooler and a helium extraction separator;

[0008] The discharge port of the natural gas decarburization device is in communication with the feed port of the natural gas dehydration and mercury removal device, the discharge port of the natural gas dehydration and mercury removal device is in communication with the feed port of the heavy hydrocarbon separator, the gas phase outlet of the heavy hydrocarbon separator is in communication with the feed port of the helium extraction column through the first heat exchange device, the gas phase outlet of the helium extraction column is in communication with the feed port of the helium extraction separator through the helium extraction cooler, the gas phase outlet of the helium extraction separator is used for discharging crude helium, the liquid phase outlet of the helium extraction separator is in communication with the helium extraction column, the liquid phase outlet of the helium extraction column is in communication with the demethanizer, and the liquid phase outlet of the demethanizer is in communication with the feed port of the deethanizer.

[0009] Optionally, the natural gas recovery ethane system further comprises a tail gas compressor, a gas phase outlet of the tail gas compressor being in communication with a gas phase outlet of the acid gas separator of the natural gas decarburization device, a liquid phase outlet of the tail gas compressor being in communication with a feed inlet of the acid gas separator of the natural gas decarburization device, and a gas phase inlet of the tail gas compressor being used for discharging compressed gas.

[0010] Optionally, the natural gas recovery ethane system further comprises a demethanization reboiler and a helium extraction reboiler, the helium extraction reboiler being used for providing heat for the helium extraction column, and the demethanization reboiler being used for providing heat for the demethanization column.

[0011] A feed outlet of the natural gas dehydration and mercury removal device is in communication with the first heat exchange device through the demethanization reboiler, and the first heat exchange device is in communication with a feed inlet of the heavy hydrocarbon separator through the helium extraction reboiler.

[0012] Optionally, the natural gas recovery ethane system further comprises at least one liquid phase extraction pipeline and at least one liquid phase reflux pipeline, at least one of the liquid phase extraction pipelines being in one-to-one correspondence with at least one of the liquid phase reflux pipelines, one end of the liquid phase extraction pipeline being in communication with the demethanization column, the other end of the liquid phase extraction pipeline being in communication with one end of the liquid phase reflux pipeline through the first heat exchange device, and the other end of the liquid phase reflux pipeline being in communication with the demethanization column, the communication between the demethanization column and each of the liquid phase reflux pipelines being located between the communication between the demethanization column and the liquid phase extraction pipeline corresponding to the liquid phase reflux pipeline and the gas phase outlet of the demethanization column.

[0013] Optionally, the natural gas recovery ethane system further comprises a first throttling expansion valve, a liquid phase outlet of the helium extraction column being in communication with a feed inlet of the demethanization column through the first throttling expansion valve.

[0014] Optionally, the natural gas recovery ethane system further comprises a second heat exchange device, the second heat exchange device being in communication with the deethanization column.

[0015] Optionally, the natural gas recovery ethane system further comprises a first refrigeration device and a second refrigeration device, the second refrigeration device being used for providing cold energy for the second heat exchange device, and the first refrigeration device being used for providing cold energy for the first heat exchange device.

[0016] Optionally, the first refrigeration device comprises a first mixed refrigerant compressor, a third throttling expansion valve, a fourth throttling expansion valve, a methane compressor, and a fifth throttling expansion valve.

[0017] The first heat exchange device is provided with a first heat exchange flow channel, a second heat exchange flow channel, a third heat exchange flow channel, a fourth heat exchange flow channel, and a fifth heat exchange flow channel.

[0018] The first heat exchange channel is connected to the refrigerant inlet of the first mixed refrigerant compressor; the liquid phase outlet of the first mixed refrigerant compressor is connected to the second heat exchange channel; the second heat exchange channel is connected to the third throttling expansion valve; and the third throttling expansion valve is connected to the first heat exchange channel. The gas phase outlet of the first mixed refrigerant compressor is connected to the third heat exchange channel; the third heat exchange channel is connected to the fourth throttling expansion valve; and the fourth throttling expansion valve is connected to the first heat exchange channel.

[0019] The refrigerant outlet of the methane compressor is connected to the fourth heat exchange channel, the fourth heat exchange channel is connected to the fifth throttling expansion valve, the fifth throttling expansion valve is connected to the helium extraction cooler, the helium extraction cooler is connected to the fifth heat exchange channel, and the fifth heat exchange channel is connected to the refrigerant inlet of the methane compressor.

[0020] Optionally, the second refrigeration unit includes a second refrigerant compressor, a sixth throttling expansion valve, and a seventh throttling expansion valve;

[0021] The second heat exchange device is provided with a sixth heat exchange channel, a seventh heat exchange channel and an eighth heat exchange channel;

[0022] The seventh heat exchange channel is connected to the refrigerant inlet of the second mixed refrigerant compressor; the liquid phase outlet of the second mixed refrigerant compressor is connected to the sixth heat exchange channel; the sixth heat exchange channel is connected to the sixth throttling expansion valve; and the sixth throttling expansion valve is connected to the seventh heat exchange channel. The gas phase outlet of the second mixed refrigerant compressor is connected to the eighth heat exchange channel; the eighth heat exchange channel is connected to the seventh throttling expansion valve; and the seventh throttling expansion valve is connected to the seventh heat exchange channel.

[0023] Optionally, the natural gas ethane recovery system further includes an ethane collection tank, an eighth throttling expansion valve, a first pipeline, a second pipeline, and a third pipeline. The second heat exchange device is provided with a ninth heat exchange channel and a tenth heat exchange channel. The gas phase outlet of the de-ethane tower is connected to the tenth heat exchange channel through the first pipeline. The tenth heat exchange channel is connected to the feed inlet of the de-ethane tower through the second pipeline. The second pipeline is connected to the ninth heat exchange channel through the third pipeline. The ninth heat exchange channel is connected to the feed inlet of the ethane collection tank through the eighth throttling expansion valve.

[0024] A method for recovering ethane and co-producing helium, wherein the method for recovering ethane and co-producing helium is applied to the aforementioned natural gas ethane recovery system, the method comprising:

[0025] Natural gas is sequentially fed into a natural gas decarbonization unit and a natural gas dehydration and mercury removal unit to perform decarbonization, dehydration and mercury removal treatment on the natural gas;

[0026] The natural gas, after being decarbonized, dehydrated, and demercured, is fed into a heavy hydrocarbon separator for separation to obtain a first gas phase and a first liquid phase.

[0027] The first gas phase is introduced into the helium extraction tower after heat exchange through the first heat exchange device. The helium extraction tower separates the first gas phase to obtain the second liquid phase and the second gas phase.

[0028] The second liquid phase is fed into a demethanizer, which separates the second liquid phase to obtain a third liquid phase and a third gas phase; the third liquid phase is then fed into an ethane remover.

[0029] The second gas phase is passed through a helium extraction cooler for heat exchange and then into a helium extraction separator. The helium extraction separator separates the third gas phase to obtain a fourth gas phase and a fourth liquid phase. The fourth gas phase is crude helium, and the fourth liquid phase is passed into the helium extraction tower.

[0030] The technical solution adopted in this invention can achieve the following beneficial effects:

[0031] In the natural gas ethane recovery system disclosed in this invention, natural gas is fed into a heavy hydrocarbon separator for separation to obtain a first gas phase and a first liquid phase. The first gas phase is then passed through a first heat exchanger and fed to the top of a helium stripping tower, where it is separated to obtain a second liquid phase and a second gas phase. The second liquid phase is then fed to the top of a demethanizer tower. This second liquid phase contains a large amount of liquid methane and liquid ethane, thus enabling the recovery of methane and ethane. The second gas phase separated from the helium stripping tower contains a large amount of helium. This second gas phase is then fed into a helium cooler for deep cooling, thereby condensing the ethane, methane, and other gaseous components carried within the helium. After further separation by a separator, crude helium is obtained. The scheme disclosed in this application co-produces helium, thereby improving the utilization rate of natural gas. Attached Figure Description

[0032] The accompanying drawings, which are included to provide a further understanding of the invention and form part of this invention, illustrate exemplary embodiments of the invention and are used to explain the invention, but do not constitute an undue limitation of the invention. In the drawings:

[0033] Figure 1 This is a schematic diagram of the natural gas ethane recovery system disclosed in an embodiment of the present invention;

[0034] Figure 2 This is a flowchart of an ethane recovery method disclosed in an embodiment of the present invention.

[0035] Explanation of reference numerals in the attached figures:

[0036] 100-Natural gas decarbonization unit, 101-Absorber tower, 102-Subcooler, 103-Regeneration tower, 104-Acid gas separator, 105-Purified gas separator, 110-Tail gas compressor,

[0037] 200-Natural Gas Dehydration and Mercury Removal Unit

[0038] 310 - First heat exchanger, 311 - First heat exchange channel, 312 - Second heat exchange channel, 313 - Third heat exchange channel, 314 - Fourth heat exchange channel, 315 - Fifth heat exchange channel, 320 - Second heat exchanger, 321 - Sixth heat exchange channel, 322 - Seventh heat exchange channel, 323 - Eighth heat exchange channel, 324 - Ninth heat exchange channel, 325 - Tenth heat exchange channel

[0039] 400 - Demethanizer, 410 - Demethanizer reboiler, 420 - First feed inlet, 430 - Second feed inlet, 440 - External gas compressor, 450 - Liquid phase extraction line, 460 - Liquid phase reflux line, 470 - First throttling expansion valve, 480 - Second throttling expansion valve, 491 - First reflux pipe, 492 - Second reflux pipe

[0040] 500 - Deethaner column, 510 - First pipeline, 520 - Second pipeline, 530 - Third pipeline, 540 - Ethane collection tank, 550 - Eighth throttling expansion valve.

[0041] 600 - Helium extraction tower, 610 - Helium extraction cooler, 620 - Helium extraction separator, 630 - Helium extraction reboiler.

[0042] 700-Heavy Hydrocarbon Separator

[0043] 811-First mixed refrigerant compressor, 812-Third throttling expansion valve, 813-Fourth throttling expansion valve, 814-Methane compressor, 815-Fifth throttling expansion valve, 821-Second mixed refrigerant compressor, 822-Sixth throttling expansion valve, 823-Seventh throttling expansion valve. Detailed Implementation

[0044] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions of this invention will be clearly and completely described below in conjunction with specific embodiments and corresponding drawings. Obviously, the described embodiments are only a part of the embodiments of this invention, and not all of them. Based on the embodiments of this invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this invention.

[0045] The technical solutions disclosed in the various embodiments of the present invention will be described in detail below with reference to the accompanying drawings.

[0046] likeFigure 1 As shown in the figure, an embodiment of the present invention discloses a natural gas ethane recovery system, which includes a natural gas supply device, a first heat exchange device 310, a demethanizer 400, a deethaner 500, a helium extraction tower 600, a heavy hydrocarbon separator 700, a helium extraction cooler 610, and a helium extraction separator 620.

[0047] The natural gas supply unit is used to supply natural gas to the heavy hydrocarbon separator 700. The outlet of the natural gas supply unit is connected to the inlet of the heavy hydrocarbon separator 700. Specifically, the natural gas supply unit includes a natural gas decarbonization unit 100 and a natural gas dehydration and mercury removal unit 200. Natural gas is introduced into the natural gas decarbonization unit 100 through a pipeline. After being decarbonized by the natural gas decarbonization unit 100, it is discharged through the outlet of the natural gas decarbonization unit 100. Then, it enters the natural gas dehydration and mercury removal unit 200 through the inlet of the natural gas dehydration and mercury removal unit 200. After being dehydrated and mercury removed in the natural gas dehydration and mercury removal unit 200, it is discharged through the outlet of the natural gas dehydration and mercury removal unit 200 and then introduced into the heavy hydrocarbon separator 700 through the inlet of the heavy hydrocarbon separator 700.

[0048] At this point, the natural gas passes through the natural gas decarbonization unit 100 and the natural gas dehydration and mercury removal unit 200, which remove substances such as carbon dioxide, water vapor and mercury from the natural gas, thereby improving the cleanliness of the natural gas.

[0049] In the above embodiments, the natural gas decarbonization device 100 includes, but is not limited to, an absorption tower 101, a subcooler 102, a regeneration tower 103, an acid gas separator 104, and a purified gas separator 105. Specifically, the process flow can be as follows: natural gas is subcooled by the subcooler 102 and then fed to the bottom of the absorption tower 101. After being absorbed by the absorbent in the absorption tower 101, it is discharged from the top of the absorption tower 101. The discharged natural gas then passes through the subcooler 102 again and enters the purified gas separator 105 for purification and separation. The purified natural gas then enters the natural gas dehydration and mercury removal device 200. The absorbent in the absorption tower 101 absorbs carbon dioxide to produce a rich solution with a high carbon dioxide concentration. The rich solution passes through a flash tank and then enters the top of the regeneration tower 103. The rich solution is regenerated in the regeneration tower 103, and after regeneration, it becomes a lean solution, which is then circulated back to the top of the absorption tower 101 for reuse. The acid gas discharged from the top of regeneration tower 103 is introduced into acid gas separator 104. After the acid gas passes through acid gas separator 104 and the condensate is recovered, it is discharged. The condensate separated from acid gas separator 104 is sent back to regeneration tower 103 via pipeline and reflux pump to maintain the system solution concentration. The gas phase separated by acid gas separator 104 is discharged. Optionally, the gas phase separated by acid gas separator 104 can be discharged together with the gas compressed by external gas compressor 440 mentioned below.

[0050] The working principle of the natural gas decarbonization device 100 in the above embodiments is a well-known technology and will not be described in detail here.

[0051] In the above scheme, the natural gas dehydration and mercury removal device 200 includes, but is not limited to, a drying tank, a mercury removal tank, and a storage tank. The decarbonized natural gas is sequentially fed into the drying tank, mercury removal tank, and other equipment for water and mercury removal operations. The natural gas after dehydration and mercury removal is stored in the storage tank, which is connected to the aforementioned heavy hydrocarbon separator 700. The working principle of the natural gas dehydration and mercury removal device is well-known technology and will not be elaborated upon here.

[0052] The gas phase outlet of the heavy hydrocarbon separator 700 is connected to the feed inlet of the helium stripping tower 600 via the first heat exchanger 310. The gas phase outlet of the helium stripping tower 600 is connected to the feed inlet of the helium stripping separator 620 via the helium stripping cooler 610. The gas phase outlet of the helium stripping separator 620 is used to discharge crude helium, and the liquid phase outlet of the helium stripping separator 620 is connected to the helium stripping tower 600. The liquid phase outlet of the helium stripping tower 600 is connected to the demethanizer tower 400. The liquid phase outlet of the demethanizer tower 400 is connected to the feed inlet of the deethaner tower 500.

[0053] In the specific process, the natural gas supply unit feeds natural gas into the heavy hydrocarbon separator 700 for separation to obtain a first gas phase and a first liquid phase. The first gas phase includes, but is not limited to, light hydrocarbons such as methane, ethane, and helium, while the first liquid phase includes, but is not limited to, liquid petroleum hydrocarbons such as octane, which are heavy hydrocarbons. The first liquid phase separated by the heavy hydrocarbon separator 700 can be subjected to combustion treatment, or it can be collected. The scheme disclosed in this application is for the recovery of light hydrocarbons such as ethane; therefore, the treatment of heavy hydrocarbons is not limited herein.

[0054] The first gas phase is passed through the first heat exchanger 310 and then introduced into the top of the helium extraction tower 600. The helium extraction tower 600 separates the first gas phase to obtain a second liquid phase and a second gas phase. Since helium is difficult to liquefy, the gas phase separated by the helium extraction tower 600 usually contains a large amount of helium; therefore, the helium in the natural gas is removed by the helium extraction tower 600. The second liquid phase produced in the helium extraction tower 600 contains liquid methane and liquid ethane.

[0055] The second liquid phase is introduced into a demethanizer 400, which separates the introduced liquid phase to obtain a third liquid phase and a third gas phase. The third gas phase is the removed methane, while the third liquid phase is a condensate rich in liquid ethane. The third liquid phase is introduced into a deethaner 500 for deethane removal.

[0056] The second gas phase is passed through a helium stripping cooler 610 for heat exchange and then into a helium stripping separator 620. The helium stripping separator 620 separates the third gas phase to obtain a fourth gas phase and a fourth liquid phase. The fourth gas phase is crude helium, and the fourth liquid phase is fed into a helium stripping tower 600. The second gas phase separated in the helium stripping tower 600 contains a large amount of helium. This second gas phase is then passed through the helium stripping cooler 610 for deep cooling, thereby condensing the ethane, methane, and other gaseous liquids carried within the helium. After further separation in the helium stripping separator 620, the separated fourth liquid phase is returned to the top of the helium stripping tower 600 for further distillation. Simultaneously, the fourth liquid phase forms a reflux stream, thus improving the reflux effect of the helium stripping tower 600. The gas phase separated in the helium stripping separator 620 is crude helium, which can be fed into a distillation unit to obtain helium with higher purity. This application only relates to the co-production of crude helium; the helium purification and distillation apparatus is not described in detail herein.

[0057] The natural gas ethane recovery system disclosed in this application removes helium before removing ethane and methane. Therefore, the technical solution disclosed in this application can also co-produce helium, thereby improving the utilization rate of natural gas.

[0058] In addition, this application first removes helium to avoid excessive helium in the subsequent methane and ethane, thus improving the purity of methane and ethane.

[0059] Furthermore, in the embodiments disclosed in this application, the liquid phase separated by the helium stripping tower 600 is introduced into the demethanizing tower 400, resulting in a larger contact area between the liquid phase and the ethane flash vapor, thus achieving better condensation and improving the ethane recovery rate.

[0060] In the above embodiments, the demethanizer 400, deethaner 500, helium stripper 600, and heavy hydrocarbon separator 700 can be plate distillation columns or packed distillation columns, and of course, other separation devices are also possible; this document does not impose any limitations. Furthermore, the specific working principles of the demethanizer 400, deethaner 500, helium stripper 600, heavy hydrocarbon separator 700, helium cooler 610, and helium separator 620 are well-known technologies and will not be elaborated upon herein.

[0061] In another optional embodiment, the natural gas ethane recovery system may further include an external gas compressor 440, a first reflux pipe 491, and a second reflux pipe 492. The gas phase outlet of the demethanizer 400 is connected to the inlet of the external gas compressor 440 via a first heat exchanger 310. The outlet of the external gas compressor 440 is connected to the first reflux pipe 491, the first reflux pipe 491 is connected to the second reflux pipe 492 via the first heat exchanger 310, and the second reflux pipe 492 is connected to the feed inlet of the demethanizer 400.

[0062] In the specific process, the demethanizer 400 separates a third gas phase. This third gas phase is then heated by the first heat exchanger 310 and compressed by the external gas compressor 440 to obtain the fifth gas phase. At this point, the low-pressure third gas phase is boosted to a high-pressure fifth gas phase. Both the third and fifth gas phases contain methane. A portion of the fifth gas phase is discharged and collected. The other portion of the fifth gas phase is fed back into the first heat exchanger 310 via the first reflux pipe 491 for further heat exchange. After heat exchange, it is fed back into the demethanizer 400 via the second reflux pipe 492, forming another reflux stream.

[0063] The aforementioned external gas compressor 440 can be a piston compressor, screw compressor, or centrifugal compressor. The specific working principle of the external gas compressor 440 is well-known technology and will not be elaborated in this article.

[0064] In the above embodiments, a portion of the fifth gas phase is fed into the demethanizer 400 after heat exchange through the first heat exchanger 310, forming another reflux. The two refluxes can further improve the reflux effect in the demethanizer 400, thus further improving the ethane recovery rate.

[0065] In another alternative embodiment, the demethanizer 400 may have a first inlet 420 and a second inlet 430. The first inlet 420 may be connected to the liquid phase outlet of the helium stripping tower 600, and the second inlet 430 may be connected to a second reflux pipe 492. Along the direction from the gas phase outlet to the liquid phase outlet of the demethanizer 400, the first inlet 420 is located between the second inlet 430 and the gas phase outlet of the demethanizer 400. Specifically, the gas phase outlet of the demethanizer 400 is located at the top of the demethanizer 400, and its liquid phase outlet is located at the bottom of the demethanizer 400. The first inlet 420 and the second inlet 430 may be located between the gas phase outlet and the liquid phase outlet of the demethanizer 400, with the first inlet 420 located above the second inlet 430.

[0066] In this scheme, the first feed inlet 420 is located above the second feed inlet 430. The first feed inlet 420 is for the liquid phase, while the second feed inlet 430 is for the gas phase. As the gas phase rises, it can form mixed flow with the liquid phase, thereby further improving the reflux effect in the demethanizer 400.

[0067] To further improve the reflux effect within the demethanizer 400, in another optional embodiment, the natural gas ethane recovery system further includes at least one liquid phase extraction line 450 and at least one liquid phase reflux line 460, with each liquid phase extraction line 450 and the liquid phase reflux line 460 connected in a one-to-one correspondence. One end of the liquid phase extraction line 450 can be connected to the demethanizer 400, and the other end of the liquid phase extraction line 450 can be connected to one end of the liquid phase reflux line 460 via a first heat exchange device 310. The other end of the liquid phase reflux line 460 can be connected to the demethanizer 400. The connection point between the demethanizer 400 and each liquid phase reflux line 460 can be located between the corresponding connection point of the liquid phase extraction line 450 and the demethanizer 400 and the gas phase outlet of the demethanizer 400.

[0068] In this scheme, the liquid phase extraction pipeline 450 extracts part of the liquid phase from the demethanizing unit. After the extracted liquid phase recovers its cooling capacity through the first heat exchanger 310, it is returned to the upper tray at its extraction position through the liquid phase return pipeline 460. This allows for the condensation of the evaporated gas phase, thereby further improving the reflux effect and thus further increasing the ethane recovery rate.

[0069] In another optional embodiment, the natural gas ethane recovery system may further include a tail gas compressor 110. The inlet of the tail gas compressor 110 may be connected to the gas phase outlet of the acid gas separator 104 of the natural gas decarbonization unit 100, and the liquid phase outlet of the tail gas compressor 110 may be connected to the inlet of the acid gas separator 104. The gas phase outlet of the tail gas compressor 110 is used to discharge the compressed gas. In this case, the compressed gas from the tail gas compressor 110 is discharged together with the gas.

[0070] In this scheme, the exhaust gas compressor 110 compresses the acid gas, thereby removing the water vapor from the acid gas, so that the water vapor condenses and the water separated by the exhaust gas compressor 110 can be reintroduced into the acid gas separator 104, thereby reducing the damage to the water in the natural gas decarbonization device 100.

[0071] Optionally, the exhaust compressor 110 can be a piston compressor, screw compressor or centrifugal compressor. The specific working principle of the exhaust compressor 110 is well known technology and will not be described in detail here.

[0072] In the above embodiments, the natural gas ethane recovery system may further include a demethanizing reboiler 410 and a helium-extraction reboiler 630. Specifically, the demethanizing reboiler 410 may be located at the bottom of the demethanizing tower 400, and the helium-extraction reboiler 630 may be located at the bottom of the helium-extraction tower 600. The helium-extraction reboiler 630 is used to provide heat to the helium-extraction tower 600. The demethanizing reboiler 410 is used to provide heat to the demethanizing tower 400.

[0073] The heat for the helium-boiling reboiler 630 and the demethanizing reboiler 410 can be provided by the first heat exchanger 310, or by a separate heat exchange mechanism. However, this would increase the energy consumption of the natural gas ethane recovery system.

[0074] Based on this, in another optional embodiment, the outlet of the natural gas supply device can be connected to the first heat exchange device 310 through the demethanizer reboiler 410, and the first heat exchange device 310 can be connected to the inlet of the heavy hydrocarbon separator 700 through the helium-lifting reboiler 630.

[0075] The specific process flow is as follows: the natural gas supplied by the natural gas supply unit is first fed into the demethanizer reboiler 410 to provide heat to the demethanizer reboiler 410, and then fed into the helium-extracting reboiler 630 after heat exchange in the first heat exchange device 310 to provide heat to the helium-extracting reboiler 630, and finally fed into the heavy hydrocarbon separator 700.

[0076] In this scheme, the heat of the demethanizing reboiler 410 and the helium-recovering reboiler 630 is provided by natural gas, so there is no need to provide heat through the first heat exchange device 310 or a separate heat exchange mechanism, thereby reducing the energy consumption of the natural gas ethane recovery system.

[0077] In another optional embodiment, the natural gas ethane recovery system may further include a first throttling expansion valve 470, through which the liquid phase outlet of the helium stripping tower 600 can be connected to the feed inlet of the demethanizer tower 400. In this scheme, the liquid phase in the helium stripping tower 600 is throttled and depressurized by the first throttling expansion valve 470, causing the high-pressure fluid to expand and depressurize, generating a low temperature to cool the liquid phase entering the demethanizer tower 400, thereby preventing partial vaporization of the liquid phase during transmission and maintaining pressure stability during liquid phase transmission.

[0078] The specific working principle of the throttling expansion valve in the above embodiments is common knowledge and will not be described in detail here.

[0079] In another optional embodiment, the natural gas ethane recovery system may further include a second throttling expansion valve 480, and the second return pipe 492 may be equipped with the second throttling expansion valve 480. In this scheme, a portion of the fifth gas phase, after heat exchange through the first heat exchange device 310, passes through the second throttling expansion valve 480 for pressure reduction, further ensuring that the temperature of the return gas is at a lower level. This allows the return gas to better condense the flash vapor of ethane, thereby further improving the ethane recovery rate.

[0080] To avoid overly complex structures in the heat exchanger of the natural gas ethane recovery system, in another optional embodiment, the natural gas ethane recovery system may further include a second heat exchanger 320, which can be connected to the deethaner 500. In this case, the second heat exchanger 320 can be used to exchange heat with the gas phase of the deethaner 500. In this scheme, the deethaner 500 is equipped with a separate heat exchanger, thereby simplifying the structure of the heat exchanger in the natural gas ethane recovery system and avoiding excessive complexity.

[0081] In the above embodiments, the first heat exchanger 310 and the second heat exchanger 320 can be provided with cooling capacity by the same refrigeration device. In this case, a single refrigeration device is insufficient to meet the cooling capacity requirements of different heat exchangers.

[0082] Based on this, in another optional embodiment, the natural gas ethane recovery system may further include a first refrigeration unit and a second refrigeration unit, wherein the second refrigeration unit can be used to provide cooling capacity to the second heat exchanger 320, and the first refrigeration unit can be used to provide cooling capacity to the first heat exchanger 310.

[0083] In this scheme, the first heat exchange device 310 and the second heat exchange device 320 are equipped with corresponding refrigeration devices, which can meet the different heat exchange requirements of the first heat exchange device 310 and the second heat exchange device 320, thereby further improving the heat exchange effect of the natural gas ethane recovery system.

[0084] In another alternative embodiment, the first refrigeration device may include a first mixed refrigerant compressor 811, a third throttling expansion valve 812, and a fourth throttling expansion valve 813. The first heat exchange device 310 may be provided with a first heat exchange channel 311, a second heat exchange channel 312, and a third heat exchange channel 313.

[0085] The first heat exchange channel 311 is connected to the refrigerant inlet of the first mixed refrigerant compressor 811. The liquid phase outlet of the first mixed refrigerant compressor 811 is connected to the second heat exchange channel 312, and the second heat exchange channel 312 is connected to the third throttling expansion valve 812. The third throttling expansion valve 812 is connected to the first heat exchange channel 311; the gas phase outlet of the first mixed refrigerant compressor 811 is connected to the third heat exchange channel 313, the third heat exchange channel 313 is connected to the fourth throttling expansion valve 813, and the fourth throttling expansion valve 813 is connected to the first heat exchange channel 311.

[0086] The first mixed refrigerant compressor 811 is used to pressurize the refrigerant and also to separate the refrigerant. The refrigerant in the first mixed refrigerant compressor 811 is usually composed of several combinations of methane, nitrogen, ethane, propane, isobutane and isopentane.

[0087] In the specific process, the first mixed refrigerant compressor 811 separates the refrigerant into a gas phase and a liquid phase. The liquid phase separated by the first mixed refrigerant compressor 811 is introduced into the second heat exchange channel 312 through its liquid phase outlet for heat exchange. Then, after being throttled and depressurized by the third throttling expansion valve 812, it is introduced into the first heat exchange channel 311. After heat exchange in the first heat exchange channel 311, it returns to the refrigerant inlet of the first mixed refrigerant compressor 811. The gas phase separated by the first mixed refrigerant compressor 811 is first introduced into the third heat exchange channel 313 for heat exchange. Then, after being throttled and depressurized by the fourth throttling expansion valve 813, it is introduced into the first heat exchange channel 311 for heat exchange again. Finally, it returns to the first mixed refrigerant compressor 811 through the refrigerant inlet, thus completing the cycle.

[0088] In this scheme, the first refrigeration unit adopts a two-stage throttling method, which can make full use of the cooling capacity of the refrigerant, thereby reducing the energy consumption of the natural gas ethane recovery system.

[0089] In the above embodiments, the first mixed refrigerant compressor 811 may include a compressor, a cooler, and a separator. The compressor is connected to the separator via the cooler. The refrigerant, after being compressed and cooled, is introduced into the separator to separate into a gas phase and a liquid phase. The refrigerant inlet of the first mixed refrigerant compressor 811 is the compressor's feed inlet, and the gas phase outlet and liquid phase outlet of the first mixed refrigerant compressor 811 are the gas phase outlet and liquid phase outlet of the separator, respectively. The specific working principle of the first mixed refrigerant compressor 811 is known technology and is not limited herein.

[0090] In another alternative embodiment, the second refrigeration device may include a second mixed refrigerant compressor 821, a sixth throttling expansion valve 822, and a seventh throttling expansion valve 823. The second heat exchange device 320 may be provided with a sixth heat exchange channel 321, a seventh heat exchange channel 322, and an eighth heat exchange channel 323.

[0091] The seventh heat exchange channel 322 can be connected to the refrigerant inlet of the second mixed refrigerant compressor 821, and the liquid phase outlet of the second mixed refrigerant compressor 821 can be connected to the sixth heat exchange channel 321. The sixth heat exchange channel 321 can be connected to the sixth throttling expansion valve 822, and the sixth throttling expansion valve 822 can be connected to the seventh heat exchange channel 322. The gas phase outlet of the second mixed refrigerant compressor 821 can be connected to the eighth heat exchange channel 323, and the eighth heat exchange channel 323 can be connected to the seventh throttling expansion valve 823, and the seventh throttling expansion valve 823 can be connected to the seventh heat exchange channel 322.

[0092] The refrigerant in the second mixed refrigerant compressor 821 is typically a combination of several of the following: methane, nitrogen, ethane, propane, isobutane, and isopentane. The structure of the second mixed refrigerant compressor 821 can be the same as that of the first mixed refrigerant compressor 811, so it will not be described in detail here.

[0093] In the specific process, the second refrigerant compressor 821 separates the refrigerant into a gas phase and a liquid phase. The liquid phase separated by the second refrigerant compressor 821 is introduced into the sixth heat exchange channel 321 through its liquid phase outlet for heat exchange. Then, after being throttled and depressurized by the sixth expansion valve 822, it is introduced into the seventh heat exchange channel 322. After heat exchange in the seventh heat exchange channel 322, it returns to the refrigerant inlet of the second refrigerant compressor 821. The gas phase separated by the second refrigerant compressor 821 is first introduced into the eighth heat exchange channel 323 for heat exchange. Then, after being throttled and depressurized by the seventh expansion valve 823, it is introduced into the seventh heat exchange channel 322 for heat exchange again. Finally, it returns to the second refrigerant compressor 821 through the refrigerant inlet, thus completing the cycle.

[0094] In this scheme, the second refrigeration unit adopts a two-stage throttling method, which can make full use of the cooling capacity of the refrigerant, thereby reducing the energy consumption of the natural gas ethane recovery system.

[0095] In the above embodiments, the natural gas ethane recovery system may further include an ethane collection tank 540. The natural gas ethane recovery tank can be connected to the gas phase outlet of the de-ethane tower 500 through a second heat exchange device 320. After being subcooled, the gas phase outlet forms liquid ethane, which is then stored in the ethane collection tank 540.

[0096] In another alternative embodiment, the natural gas ethane recovery system may further include an eighth throttling expansion valve 550, a first pipeline 510, a second pipeline 520, and a third pipeline 530. A ninth heat exchange channel 324 and a tenth heat exchange channel 325 may be provided within the second heat exchange unit 320. The gas phase outlet of the deethaner 500 can be connected to the tenth heat exchange channel 325 via the first pipeline 510. The tenth heat exchange channel 325 can be connected to the feed inlet of the deethaner 500 via the second pipeline 520. The second pipeline 520 can be connected to the ninth heat exchange channel 324 via the third pipeline 530. The ninth heat exchange channel 324 is connected to the feed inlet of the ethane collection tank 540 via the eighth throttling expansion valve 550.

[0097] In the specific process, the gas phase in the deethaner 500 is introduced into the tenth heat exchange channel 325 through the first pipeline 510. After heat exchange in the tenth heat exchange channel 325, part of the gas phase returns to the deethaner 500 through the second pipeline 520 to form reflux, and part of the gas phase is introduced into the ninth heat exchange channel 324 through the third pipeline 530. After heat exchange, it is introduced into the eighth throttling expansion valve 550. After throttling and depressurization by the eighth throttling expansion valve 550, liquid ethane is formed and introduced into the ethane collection device for collection.

[0098] This scheme returns a portion of the gas phase after heat exchange in the ethane stripper 500 to the top of the ethane stripper 500, thus forming a reflux to condense other substances in the ethane, thereby further improving the purity of the ethane.

[0099] Furthermore, the natural gas ethane recovery system may also include an ethane deboiler, which can be located at the bottom of the ethane deboiler 500. Part of the liquid phase in the ethane deboiler 500 returns to the bottom of the ethane deboiler 500 after passing through the ethane deboiler. At this time, the liquid phase separated in the ethane deboiler 500 can provide heat to the ethane deboiler.

[0100] In the above embodiments, the natural gas ethane recovery system may further include a booster pump. The liquid phase outlet of the demethanizer 400 is connected to the feed inlet of the deethaner 500 via the booster pump, thereby improving the liquid phase inflow efficiency and preventing liquid phase reflux.

[0101] In another optional embodiment, the first refrigeration device may further include a methane compressor 814 and a fifth throttling expansion valve 815. The first heat exchange device 310 may also include a fourth heat exchange channel 314 and a fifth heat exchange channel 315. The refrigerant outlet of the methane compressor 814 may be connected to the fourth heat exchange channel 314, the fourth heat exchange channel 314 may be connected to the fifth throttling expansion valve 815, the fifth throttling expansion valve 815 may be connected to a helium-lifting cooler 610, the helium-lifting cooler 610 may be connected to the fifth heat exchange channel 315, and the fifth heat exchange channel 315 may be connected to the refrigerant inlet of the methane compressor 814.

[0102] The methane compressor 814 uses methane as a refrigerant. After compressing the methane, it is introduced into the fourth flow channel for heat exchange through its refrigerant outlet. Then, after being throttled and depressurized by the fifth throttling expansion valve 815, it is introduced into the helium cooling device, thereby providing helium cooling capacity to the helium cooler 610. Finally, it returns to the refrigerant inlet of the methane compressor 814 through the fifth heat exchange flow channel 315.

[0103] In this scheme, the methane refrigerant compressor provides cooling capacity to the helium cooler 610, thereby further optimizing the heat exchange process of the natural gas ethane recovery system and avoiding uneven heat exchange.

[0104] In the above embodiments, the methane compressor 814 may include a methane feed tank, a compressor, and a cooler. The refrigerant inlet of the methane compressor 814 is the feed port of the methane feed tank, and the discharge port of the methane feed tank is connected to the compressor. After the compressor compresses the methane, it passes through the cooler for heat exchange and then enters the fourth heat exchange channel 314.

[0105] In the above embodiments, each material can have a corresponding heat exchange channel when it enters the first heat exchange device 310 for heat exchange, which will not be listed one by one in this article.

[0106] Based on any of the above embodiments of the natural gas ethane recovery system of the present invention, the present invention also discloses a method for recovering ethane and co-producing helium, applicable to any of the natural gas ethane recovery systems described above, such as... Figure 2 As shown, the method for recovering ethane and co-producing helium includes:

[0107] S100. Natural gas is sequentially fed into a natural gas decarbonization unit and a natural gas dehydration and mercury removal unit to perform decarbonization, dehydration and mercury removal treatment on the natural gas.

[0108] S200: The decarbonized, dehydrated and mercury-free natural gas is fed into the heavy hydrocarbon separator 700 for separation to obtain the first gas phase and the first liquid phase.

[0109] The first liquid phase here consists of heavy hydrocarbons, and the first gas phase consists of light hydrocarbons.

[0110] S300, the first gas phase is introduced into the helium extraction tower 600 after heat exchange through the first heat exchange device 310. The helium extraction tower 600 separates the first gas phase to obtain the second liquid phase and the second gas phase.

[0111] The second liquid phase here is rich in liquid ethane and liquid methane, while the first gas phase contains helium, which is then separated from the natural gas.

[0112] S400, the second liquid phase is introduced into the demethanizer 400, which separates the introduced second liquid phase to obtain a third liquid phase and a third gas phase; the third liquid phase is introduced into the deethanizer 500.

[0113] The third liquid phase is rich in liquid ethane, thus enabling the deethane removal process.

[0114] S500, the second gas phase is passed through the helium extraction cooler 610 for heat exchange and then into the helium extraction separator 620. The helium extraction separator 620 separates the third gas phase to obtain a fourth gas phase and a fourth liquid phase. The fourth gas phase is crude helium, and the fourth liquid phase is passed into the helium extraction tower 600.

[0115] This step removes the crude helium gas contained in the second gas phase.

[0116] The natural gas ethane recovery system disclosed in this application removes helium before removing ethane and methane. Therefore, the technical solution disclosed in this application can also co-produce helium, thereby improving the utilization rate of natural gas.

[0117] like Figure 1 As shown, this application discloses a specific process flow. The natural gas after decarbonization, dehydration, and mercury removal is first used as a heat source at the bottom of the demethanizer 400. After exchanging heat with the reboiler of the demethanizer 400, its temperature is reduced to 25-32°C. It then enters the first heat exchange device 310, is cooled to -50°C, and enters the helium reboiler 630 at the bottom of the helium stripping tower 600. It serves as a heat source for the helium reboiler 630, heating the temperature at the bottom of the helium stripping tower 600 from -91°C to -88°C. At the same time, the temperature of the stream is reduced to -63°C, and it enters the heavy hydrocarbon separator 700. Natural gas from the top of the heavy hydrocarbon separator 700 is cooled to -105°C by the first heat exchanger 310 and then enters the helium stripping tower 600. After rectification in the helium stripping tower 600, the gaseous phase at the top of the tower enters the helium stripping cooler 610 at the top of the helium stripping tower 600, where it is cooled to -142°C by methane refrigerant before being separated in the helium stripping separator 620 at the top of the helium stripping tower 600. The liquid phase at the bottom of the helium stripping separator 620 is refluxed back into the helium stripping tower 600. The crude helium separated from the top of the helium stripping separator 620 is reheated to room temperature and then sent to the helium purification unit to extract high-purity helium. The natural gas condensate at the bottom of the helium stripping tower 600 is depressurized to 1.9–2.6 MPaG and enters the top of the demethanizer tower 400. Natural gas from the top of the demethanizer 400 is reheated to ambient temperature by the first heat exchanger 310 and then compressed by the external gas compressor 440 to 4.5–6.0 MPaG. Simultaneously, a portion of dry gas is separated and cooled to -106°C by the first heat exchanger 310, then depressurized to 1.9–2.6 MPaG by the throttling expansion valve before entering the upper part of the demethanizer 400. Ethane-rich liquid from the bottom of the demethanizer 400 is pressurized to 2.2–2.9 MPaG by a booster pump before entering the deethanizer 500. The deethaner 500 is equipped with a deethaner reboiler. Natural gas condensate is produced at the bottom of the deethaner 500. Ethane gas at the top of the deethaner 500 is cooled to -7°C by the second heat exchanger 320 and then split into two streams. One stream returns to the top of the deethaner 500 as reflux, while the other stream is further cooled to -100°C by the second heat exchanger 320 and then throttled by the expansion valve before being sent to the ethane collection tank 540 for storage. The operating pressure of the demethanizer 400 can be 1.7–2.6 MPaG, the top temperature can be -110°C, and the bottom temperature can be -5°C. The operating pressure of the deethaner 500 is 2.2–2.9 MPaG, the top temperature is -3°C, and the bottom temperature can be 67°C.

[0118] The above embodiments of the present invention focus on describing the differences between the various embodiments. As long as the different optimization features between the various embodiments are not contradictory, they can be combined to form a better embodiment. For the sake of brevity, they will not be described in detail here.

[0119] The above description is merely an embodiment of the present invention and is not intended to limit the invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principle of the present invention should be included within the scope of the claims of the present invention.

Claims

1. A natural gas ethane recovery system, characterized in that, The system includes a natural gas decarbonization unit (100), a natural gas dehydration and mercury removal unit (200), a first heat exchange unit (310), a demethanizer (400), a demethanizer reboiler (410), a deethaner (500), a helium extraction tower (600), a heavy hydrocarbon separator (700), a helium extraction cooler (610), a helium extraction separator (620), and a helium extraction reboiler (630), wherein the helium extraction reboiler (630) provides heat to the helium extraction tower (600); and the demethanizer reboiler (410) provides heat to the demethanizer tower (400). The outlet of the natural gas decarbonization device (100) is connected to the inlet of the natural gas dehydration and mercury removal device (200). The outlet of the natural gas dehydration and mercury removal device (200) is connected to the first heat exchange device (310) through the demethanizer reboiler (410). The first heat exchange device (310) is connected to the inlet of the heavy hydrocarbon separator (700) through the helium-lifting reboiler (630). The gas phase outlet of the heavy hydrocarbon separator (700) is connected to the helium-lifting tower (630) through the first heat exchange device (310). The inlet of the helium extraction tower (600) is connected to the inlet of the helium extraction cooler (610). The gas phase outlet of the helium extraction tower (600) is connected to the inlet of the helium extraction separator (620) through the helium extraction cooler (610). The gas phase outlet of the helium extraction separator (620) is used to discharge crude helium. The liquid phase outlet of the helium extraction separator (620) is connected to the helium extraction tower (600). The liquid phase outlet of the helium extraction tower (600) is connected to the demethanizer tower (400). The liquid phase outlet of the demethanizer tower (400) is connected to the inlet of the deethaner tower (500).

2. The natural gas ethane recovery system according to claim 1, characterized in that, The natural gas ethane recovery system also includes a tail gas compressor (110), the inlet of which is connected to the gas phase outlet of the acid gas separator (104) of the natural gas decarbonization device (100), the liquid phase outlet of which is connected to the inlet of the acid gas separator (104) of the natural gas decarbonization device (100), and the gas phase outlet of which is used to discharge compressed gas.

3. The natural gas ethane recovery system according to claim 1, characterized in that, The natural gas ethane recovery system further includes at least one liquid phase extraction pipeline (450) and at least one liquid phase reflux pipeline (460). At least one liquid phase extraction pipeline (450) and at least one liquid phase reflux pipeline (460) are connected in a one-to-one correspondence. One end of the liquid phase extraction pipeline (450) is connected to the demethanizer (400), and the other end of the liquid phase extraction pipeline (450) is connected to one end of the liquid phase reflux pipeline (460) through the first heat exchange device (310). The other end of the liquid phase reflux pipeline (460) is connected to the demethanizer (400). The connection point between the demethanizer (400) and each liquid phase reflux pipeline (460) is located between the connection point of the corresponding liquid phase extraction pipeline (450) and the demethanizer (400) and the gas phase outlet of the demethanizer (400).

4. The natural gas ethane recovery system according to claim 1, characterized in that, The natural gas ethane recovery system also includes a first throttling expansion valve (470), and the liquid phase outlet of the helium extraction tower (600) is connected to the feed inlet of the demethanizer tower (400) through the first throttling expansion valve (470).

5. The natural gas ethane recovery system according to claim 1, characterized in that, The natural gas ethane recovery system also includes a second heat exchanger (320), which is connected to the de-ethane tower (500).

6. The natural gas ethane recovery system according to claim 5, characterized in that, The natural gas ethane recovery system also includes a first refrigeration unit and a second refrigeration unit, the second refrigeration unit being used to provide cooling capacity to the second heat exchange unit (320), and the first refrigeration unit being used to provide cooling capacity to the first heat exchange unit (310).

7. The natural gas ethane recovery system according to claim 6, characterized in that, The first refrigeration device includes a first mixed refrigerant compressor (811), a third throttling expansion valve (812), a fourth throttling expansion valve (813), a methane compressor (814), and a fifth throttling expansion valve (815). The first heat exchange device (310) is provided with a first heat exchange channel (311), a second heat exchange channel (312), a third heat exchange channel (313), a fourth heat exchange channel (314) and a fifth heat exchange channel (315). The first heat exchange channel (311) is connected to the refrigerant inlet of the mixed refrigerant compressor, the liquid phase outlet of the mixed refrigerant compressor is connected to the second heat exchange channel (312), the second heat exchange channel (312) is connected to the third throttling expansion valve (812), and the third throttling expansion valve (812) is connected to the first heat exchange channel (311); the gas phase outlet of the mixed refrigerant compressor is connected to the third heat exchange channel (313), the third heat exchange channel (313) is connected to the fourth throttling expansion valve (813), and the fourth throttling expansion valve (813) is connected to the first heat exchange channel (311); The refrigerant outlet of the methane compressor (814) is connected to the fourth heat exchange channel (314), the fourth heat exchange channel (314) is connected to the fifth throttling expansion valve (815), the fifth throttling expansion valve (815) is connected to the helium-lifting cooler (610), the helium-lifting cooler (610) is connected to the fifth heat exchange channel (315), and the fifth heat exchange channel (315) is connected to the refrigerant inlet of the methane compressor (814).

8. The natural gas ethane recovery system according to claim 6, characterized in that, The second refrigeration unit includes a second mixed refrigerant compressor (821), a sixth throttling expansion valve (822), and a seventh throttling expansion valve (823). The second heat exchange device (320) is provided with a sixth heat exchange channel (321), a seventh heat exchange channel (322) and an eighth heat exchange channel (323). The seventh heat exchange channel (322) is connected to the refrigerant inlet of the second mixed refrigerant compressor (821), the liquid phase outlet of the second mixed refrigerant compressor (821) is connected to the sixth heat exchange channel (321), the sixth heat exchange channel (321) is connected to the sixth throttling expansion valve (822), and the sixth throttling expansion valve (822) is connected to the seventh heat exchange channel (322); the gas phase outlet of the second mixed refrigerant compressor (821) is connected to the eighth heat exchange channel (323), the eighth heat exchange channel (323) is connected to the seventh throttling expansion valve (823), and the seventh throttling expansion valve (823) is connected to the seventh heat exchange channel (322).

9. The natural gas ethane recovery system according to claim 5, characterized in that, The natural gas ethane recovery system also includes an ethane collection tank (540), an eighth throttling expansion valve (550), a first pipeline (510), a second pipeline (520), and a third pipeline (530). The second heat exchange device (320) is provided with a ninth heat exchange channel (324) and a tenth heat exchange channel (326). The gas phase outlet of the de-ethane tower (500) is connected to the tenth heat exchange channel (326) through the first pipeline (510). The tenth heat exchange channel (326) is connected to the feed inlet of the de-ethane tower (500) through the second pipeline (520). The second pipeline (520) is connected to the ninth heat exchange channel (324) through the third pipeline (530). The ninth heat exchange channel (324) is connected to the feed inlet of the ethane collection tank (540) through the eighth throttling expansion valve (550).

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