Dry gas light component separation and recovery system and method

Abstract

The invention provides a dry gas light component separation and recovery system and method. The system comprises a feed gas pressurizing and cooling unit, an absorbent pressurizing and cooling unit, a heavy hydrocarbon absorption tower, a light component pressurizing and preheating unit, a hydrogen membrane separation unit, a dehydrogenized gas light component temperature and pressure regulation and control unit and a methane membrane separation unit, a discharge port of the feed gas pressurizing and cooling unit is connected with a raw material inlet of the heavy hydrocarbon absorption tower, an outlet of the absorbent pressurizing and cooling unit is connected with an absorbent inlet of the heavy hydrocarbon absorption tower, and a light component outlet of the heavy hydrocarbon absorption tower is connected with a feed port of the light component pressurizing and preheating unit. A discharge port of the light component pressurizing and preheating unit is connected with a feed port of the hydrogen membrane separation unit, a permeable residual gas outlet of the hydrogen membrane separation unit is connected with a feed port of the hydrogen-removed light component temperature and pressure regulation and control unit, and a discharge port of the hydrogen-removed light component temperature and pressure regulation and control unit is connected with a feed port of the methane membrane separation unit. The system can realize synchronous high-purity and high-recovery-rate separation and recovery of hydrogen and methane in refinery dry gas.

Description

Technical Field

[0001] The present invention belongs to the technical field of refinery dry gas purification, and in particular relates to a dry gas light component separation and recovery system, and a dry gas light component separation and recovery method using the dry gas light component separation and recovery system. Background Art

[0002] Refinery dry gas mainly comes from the secondary processing of crude oil, such as heavy oil catalytic cracking, delayed coking, hydrocracking, hydroreforming, and non-condensable gas from crude oil atmospheric and vacuum decompression. The main components of dry gas are hydrogen and light hydrocarbon components such as methane, ethylene, ethane, propylene, and propane. At present, dry gas separation and recovery technology mainly focuses on recovering C2+ components such as ethylene in dry gas. Commonly used methods include cryogenic method, absorption method, shallow cold oil absorption method, etc. However, there is no mature method for simultaneously recovering hydrogen and methane in dry gas with high purity.

[0003] The technology of recovering ethylene from ethylbenzene by gas phase has gone through multiple generations of research and development and is one of the more mature dry gas recycling technologies. However, this technology is easily restricted by upstream raw materials and the production capacity of a single set is also relatively low.

[0004] Cryogenic separation is a process of separating mixed gases by cryogenic distillation based on the difference in relative volatility and boiling point of each component of dry gas. This method can recover ethylene, ethane, propylene and propane in dry gas with a yield of 96%-98% and a purity of polymerization grade. However, this method generally requires a cooling capacity of about -90℃ to -120℃ for gas separation, which has a large load, a complex process and strict requirements on the content of harmful impurities. Therefore, it is not very economical to use cryogenic separation in the case of dispersed refineries and low production capacity.

[0005] The absorption separation method can be divided into physical method and chemical method according to whether a chemical reaction occurs. The physical method is further divided into oil absorption process and solvent extraction. The oil absorption method often uses aromatic hydrocarbons or C3, C4 and other oil products as absorbents to separate gases with different solubility. According to the different operating temperatures, the oil absorption method can be divided into three processes: deep cold oil absorption (below -80°C), medium cold oil absorption (-20°C to -40°C) and shallow cold oil absorption (above 0°C). The typical technology used to recover refinery dry gas in the deep cold oil absorption process is the low-pressure deep cold absorption process. Under the operating conditions of 0.5-0.6MPa and -98°C, C3, C4 mixed oil products are used as absorbents to absorb ethylene and hydrocarbons above C2, thereby achieving the effect of separation from hydrogen, methane and nitrogen. However, because this technology belongs to low-temperature distillation, it consumes a lot of energy. The medium-cooled oil absorption process is a process technology for enriching ethylene in catalytic dry gas developed on the basis of the deep-cooled oil absorption process. Its operating temperature is significantly higher than that of the deep-cooled oil absorption process, but it still needs to reach -20℃ to -40℃, the energy consumption is still high, and the olefin loss is large. The shallow-cooled oil absorption process is developed on the basis of the medium-cooled oil absorption process. C4 or C5 fractions are used to recover the C2 component in the dry gas. The temperature condition is 10-15℃. The shallow-cooled oil absorption process is one of the most promising and market-competitive technologies for enriching ethylene due to its low energy consumption.

[0006] In summary, the current recovery of refinery gas is mostly concentrated on C2 and C3 components. Cryogenic method and shallow cold absorption are both commonly used processes for purifying C2+ components from dry gas. With the development of resource integration, C2 resources in refinery dry gas have been utilized to a certain extent, but there are still a large number of high-value components such as hydrogen and methane that have not been effectively recycled. The recovery of light hydrocarbon components such as methane and hydrogen in dry gas can not only achieve full utilization of resources, but also reduce environmental pollution and greenhouse effect. With the increase in the depth of heavy oil refining, methane and hydrogen play an increasingly important role in refineries. Methane is an important C1 chemical raw material, and hydrogen can be used as a hydrogenation raw material. However, at present, most of the methane and hydrogen in refinery dry gas are used as low-grade fuel gas or burned in flares, resulting in waste of resources and emission of a large amount of CO2. Recovering methane and hydrogen in refinery dry gas is of great significance to improving resource utilization and reducing carbon emissions. Therefore, it is very necessary to develop technologies that can separate and recover hydrogen and methane in refinery dry gas. Summary of the invention

[0007] The object of the present invention is to provide a dry gas light component separation and recovery technology capable of realizing the separation and recovery of hydrogen and methane in refinery dry gas.

[0008] In order to solve the above problems, the present invention provides the following two technical solutions.

[0009] In a first aspect, the present invention provides a dry gas light component separation and recovery system, wherein the separation system comprises a feed gas pressurization and cooling unit, an absorbent pressurization and cooling unit, a heavy hydrocarbon absorption tower, a light component pressurization and preheating unit, a hydrogen membrane separation unit, a dehydrogenated light component temperature and pressure control unit, and a methane membrane separation unit;

[0010] The discharge port of the raw gas pressurization and cooling unit is connected to the raw material inlet of the heavy hydrocarbon absorption tower, the outlet of the absorbent pressurization and cooling unit is connected to the absorbent inlet of the heavy hydrocarbon absorption tower, the light component outlet of the heavy hydrocarbon absorption tower is connected to the feed port of the light component pressurization and preheating unit, the discharge port of the light component pressurization and preheating unit is connected to the feed port of the hydrogen membrane separation unit, the residual gas outlet of the hydrogen membrane separation unit is connected to the feed port of the dehydrogenation light component temperature and pressure regulation unit, and the discharge port of the dehydrogenation light component temperature and pressure regulation unit is connected to the feed port of the methane membrane separation unit.

[0011] In the above-mentioned dry gas light component separation and recovery system, the pressurization and cooling of the refinery dry gas and the pressurization and cooling of the absorbent are achieved through the raw gas pressurization and cooling unit and the absorbent pressurization and cooling unit. The refinery dry gas after pressurization and cooling is contacted with the absorbent in the heavy hydrocarbon absorption tower, and the heavy components (C2 and C2+ components) in the refinery dry gas are removed by absorbent extraction (the heavy components are extracted into the solvent to form a solvent-rich phase), and the remaining light components in the refinery dry gas (mainly a mixture of hydrogen, methane gas and nitrogen) enter the light component pressurization and preheating unit for pressurization and temperature increase. The light components after pressurization and temperature increase enter the hydrogen membrane separation unit for hydrogen separation, and hydrogen is enriched on the permeate side. The gas on the residual side (mainly a mixture of methane gas and nitrogen) enters the dehydrogenation light component temperature and pressure control unit for temperature and pressure control, and then enters the methane membrane separation unit for methane gas separation, and methane gas is enriched on the permeate side.

[0012] According to a preferred embodiment of the first aspect, the hydrogen membrane separation unit includes a first mixer, a first-stage hydrogen membrane separation device, a second-stage hydrogen membrane separation temperature and pressure control device, a second-stage hydrogen membrane separation device, and a third-stage hydrogen membrane separation device;

[0013] The discharge port of the first mixer is connected to the feed port of the first-stage hydrogen membrane separation device, the residual gas outlet of the first-stage hydrogen membrane separation device is connected to the feed port of the third-stage hydrogen membrane separation device, the permeate gas outlet of the first-stage hydrogen membrane separation device is connected to the feed port of the second-stage hydrogen membrane separation temperature and pressure control device, and the discharge port of the second-stage hydrogen membrane separation temperature and pressure control device is connected to the feed port of the second-stage hydrogen membrane separation device; the feed port of the first mixer is connected to the discharge port of the light component boosting and preheating unit as the feed port of the hydrogen membrane separation unit, and the residual gas outlet of the third-stage hydrogen membrane separation device is connected to the feed port of the dehydrogenation light component temperature and pressure control unit as the residual gas outlet of the hydrogen membrane separation unit; the permeate gas outlet of the third-stage hydrogen membrane separation device and the residual gas outlet of the second-stage hydrogen membrane separation device are respectively connected to the feed port of the first mixer; the permeate gas outlet of the second-stage hydrogen membrane separation device is used as the hydrogen outlet;

[0014] The three-stage membrane separation technical solution provided in this preferred embodiment can effectively ensure the purity and utilization rate of hydrogen. The light components obtained after the refinery dry gas is deweighted are passed through the first-stage hydrogen membrane separation equipment, the second-stage hydrogen membrane separation equipment, and the third-stage hydrogen membrane separation equipment, so that high-purity hydrogen is enriched on the permeate side of the second-stage hydrogen membrane separation equipment, and the remaining methane and nitrogen (almost no hydrogen) are enriched on the residual side of the third-stage hydrogen membrane separation equipment.

[0015] More preferably, the second-stage hydrogen membrane separation temperature and pressure control equipment comprises a crude hydrogen compressor and a crude hydrogen cooler connected in sequence.

[0016] According to a preferred embodiment of the first aspect, the membrane used in the hydrogen membrane separation unit is a membrane that can achieve hydrogen permeation and methane and nitrogen non-permeation, and the membrane used in the hydrogen membrane separation unit can be but not limited to one or more of a polymer membrane, an inorganic non-metallic membrane, a metal membrane and other new material membranes; when a multi-stage membrane is provided, the type of each stage of the membrane can be the same or different, and can be freely specified according to the production situation;

[0017] Preferably, the membrane used in the hydrogen membrane separation unit is a polyimide membrane.

[0018] According to a preferred embodiment of the first aspect, the methane membrane separation unit includes a second mixer, a first-stage methane membrane separation device, a second-stage methane membrane separation temperature and pressure control device, and a second-stage methane membrane separation device;

[0019] The discharge port of the second mixer is connected to the feed port of the first-stage methane membrane separation device, the permeate outlet of the first-stage methane membrane separation device is connected to the feed port of the second-stage methane membrane separation temperature and pressure control device, and the discharge port of the second-stage methane membrane separation temperature and pressure control device is connected to the feed port of the second-stage methane membrane separation device; the feed port of the second mixer is connected to the discharge port of the dehydrogenation light component temperature and pressure control unit as the feed port of the methane membrane separation unit, and the permeate outlet of the second-stage methane membrane separation device is used as the nitrogen outlet; the residual gas outlet of the second-stage methane membrane separation device is connected to the feed port of the second mixer; the residual gas outlet of the first-stage methane membrane separation device is used as the methane outlet;

[0020] The two-stage membrane separation technology provided by this preferred implementation scheme can effectively ensure the purity and utilization rate of methane. The light component dehydrogenated gas obtained after the refinery dry gas is removed is processed by the first-stage hydrogen membrane separation equipment and the second-stage hydrogen membrane separation equipment. High-purity nitrogen (purity can reach more than 90%) is enriched on the permeate side of the first-stage methane membrane separation equipment, and nitrogen (almost free of methane) is enriched on the permeate side of the second-stage methane membrane separation equipment.

[0021] More preferably, the second-stage methane membrane separation temperature and pressure control equipment comprises a crude nitrogen compressor and a crude nitrogen cooler connected in sequence.

[0022] According to a preferred embodiment of the first aspect, the membrane used in the methane membrane separation unit is a membrane that can achieve nitrogen permeation and methane non-permeation, and the membrane used in the methane membrane separation unit can be but not limited to one or more of a polymer membrane, an inorganic non-metallic membrane, a metal membrane and other new material membranes; when a multi-stage membrane is provided, the type of each stage of the membrane can be the same or different, and can be freely specified according to the production situation;

[0023] More preferably, the membrane used in the methane membrane separation unit is a DD3R membrane.

[0024] According to a preferred embodiment of the first aspect, the theoretical plate number of the heavy hydrocarbon absorption tower is 7-25, the light component outlet of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower, the rich solvent phase outlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, the raw material inlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, and the absorbent inlet of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower;

[0025] More preferably, the theoretical plate number of the heavy hydrocarbon absorption tower is 7

[0026] According to a preferred embodiment of the first aspect, the dry gas light component separation and recovery system further comprises a heavy hydrocarbon analysis tower; the feed inlet of the heavy hydrocarbon analysis tower is connected to the rich solvent phase outlet of the heavy hydrocarbon absorption tower, and the solvent phase outlet of the heavy hydrocarbon analysis tower is connected to the feed inlet of the absorbent boost cooling unit;

[0027] More preferably, the theoretical plate number of the heavy hydrocarbon analysis tower is 30-60, the analysis gas phase outlet of the heavy hydrocarbon analysis tower is arranged at the top of the heavy hydrocarbon analysis tower, the solvent phase outlet of the heavy hydrocarbon analysis tower is arranged at the bottom of the heavy hydrocarbon analysis tower, and the theoretical plate number of the feed inlet position of the heavy hydrocarbon analysis tower is 10-20;

[0028] More preferably, the theoretical plate number of the heavy hydrocarbon analysis tower is 41, and the theoretical plate number of the feed inlet position of the heavy hydrocarbon analysis tower is 16.

[0029] According to a preferred embodiment of the first aspect, the raw gas supercharging and cooling unit includes an intake air compressor and an intake air cooler connected in sequence.

[0030] According to a preferred embodiment of the first aspect, the absorbent boost cooling unit comprises an absorbent boost pump and an absorbent cooler connected in sequence;

[0031] More preferably, when the dry gas light component separation and recovery system includes a heavy hydrocarbon analysis tower, the absorbent boost cooling unit further includes a third mixer having a feed port connected to a condenser discharge port; more preferably, the feed port of the third mixer is further connected to an absorbent supply pipeline to achieve absorbent replenishment.

[0032] According to a preferred embodiment of the first aspect, the light component pressurization and preheating unit comprises a light component compressor and a light component preheater connected in sequence.

[0033] According to a preferred embodiment of the first aspect, the dehydrogenation gas light component temperature and pressure control unit comprises a dehydrogenation gas light component pressure reducing valve and a dehydrogenation gas light component preheater which are connected in sequence.

[0034] According to a preferred embodiment of the first aspect, a water separator is further provided on the connecting pipeline between the discharge port of the raw gas boost cooling unit and the raw material inlet of the heavy hydrocarbon absorption tower.

[0035] In a second aspect, the present invention provides a method for separating and recovering light components of dry gas, which method is performed using a dry gas light component separation and recovery system and specifically comprises the following steps:

[0036] Heavy component separation step: pressurizing and cooling the refinery dry gas, pressurizing and cooling the absorbent, contacting the pressurized and cooled refinery dry gas with the pressurized and cooled absorbent in a heavy hydrocarbon absorption tower to extract the C2+ heavy components in the refinery dry gas into the absorbent, forming a C2+ heavy component-rich solvent liquid phase and a light component gas phase;

[0037] Hydrogen recovery step: the light component gas phase is pressurized and heated before entering a hydrogen membrane separation unit for hydrogen separation, wherein hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane mixed gas are enriched on the residual side; hydrogen is collected from the permeate gas outlet of the hydrogen membrane separation unit;

[0038] Methane recovery step: the nitrogen and methane mixed gas is temperature- and pressure-controlled and then enters a methane membrane separation unit for methane separation, wherein methane is enriched on the membrane filtrate side and nitrogen is enriched on the permeate side; methane is collected from the filtrate outlet of the methane membrane separation unit.

[0039] The method for separating and recovering light components of dry gas provided by the present invention can efficiently realize the simultaneous recovery of methane and nitrogen in refinery dry gas. The use of solvent to extract C2+ heavy components in refinery dry gas in the heavy component separation step is a physical separation process, which uses the difference in solubility of each component in the solvent for separation. When the solvent contacts the refinery dry gas, the solvent will selectively dissolve specific components in the refinery dry gas to form two phases with different compositions, thereby separating the components to be separated from the remaining components in the refinery dry gas. In the hydrogen recovery step and the methane recovery step, the hydrogen and methane separation using a hydrogen membrane separation unit and a methane membrane separation unit is a gas membrane separation process, which is based on the gas partial pressure difference on both sides of the membrane as a driving force. The gas is absorbed and dissolved on the high-pressure side, diffuses along the concentration gradient, and is analyzed and desorbed on the low-pressure side, thereby generating a difference in the transfer rate between components and achieving separation.

[0040] According to a preferred embodiment of the second aspect, the absorbent comprises toluene and / or benzene.

[0041] According to a preferred embodiment of the second aspect, during the contact process between the pressurized and cooled refinery dry gas and the pressurized and cooled absorbent in the heavy hydrocarbon absorption tower, the pressurized and cooled refinery dry gas and the pressurized and cooled absorbent are in countercurrent contact;

[0042] More preferably, the refinery dry gas after pressurization and temperature reduction enters the heavy hydrocarbon absorption tower from the top of the heavy hydrocarbon absorption tower, and the absorbent after pressurization and temperature reduction enters the heavy hydrocarbon absorption tower from the bottom of the heavy hydrocarbon absorption tower.

[0043] According to a preferred embodiment of the second aspect, in the heavy component separation step, the refinery dry gas is pressurized and cooled to 30-40 bar, -40°C to -45°C, the absorbent is pressurized and cooled to 30-40 bar, -40°C to -45°C, the theoretical plate number of the heavy hydrocarbon absorption tower is 7-25, the light component outlet of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower, the rich solvent phase outlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, the raw material inlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, and the absorbent inlet position of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower; the operating pressure of the heavy hydrocarbon absorption tower is 3-4MPa;

[0044] More preferably, the top temperature of the heavy hydrocarbon absorption tower is -32°C to -35°C, and the bottom temperature of the heavy hydrocarbon absorption tower is -13°C to -18°C;

[0045] In a specific embodiment, the refinery dry gas is pressurized and cooled to 35 bar and -40°C, the absorbent is pressurized and cooled to 35 bar and -40°C, the theoretical plate number of the heavy hydrocarbon absorption tower is 7, the light component outlet of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower, the rich solvent phase outlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, the raw material inlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, and the absorbent inlet position of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower; the operating pressure of the heavy hydrocarbon absorption tower is 3.5 MPa; the top temperature of the heavy hydrocarbon absorption tower is -33.4°C, and the bottom temperature of the heavy hydrocarbon absorption tower is -15.7938°C.

[0046] According to a preferred embodiment of the second aspect, the method further comprises:

[0047] Absorbent analysis step: the C2+ heavy component-rich solvent liquid phase enters the heavy hydrocarbon analysis tower to analyze the C2+ heavy component-rich phase to obtain a solvent phase and a C2+ heavy component phase, and the solvent phase is recycled as the absorbent used in the heavy component separation step;

[0048] More preferably, in the absorbent analysis step, the theoretical plate number of the heavy hydrocarbon analysis tower is 30-60, the analysis gas phase outlet of the heavy hydrocarbon analysis tower is arranged at the top of the heavy hydrocarbon analysis tower, the solvent phase outlet of the heavy hydrocarbon analysis tower is arranged at the bottom of the heavy hydrocarbon analysis tower, and the theoretical plate number of the feed inlet position of the heavy hydrocarbon analysis tower is 10-20; the feed temperature of the heavy hydrocarbon analysis tower is -13°C to -18°C, the operating pressure of the heavy hydrocarbon analysis tower is 2.3-2.7MPa, and the reflux ratio is 1.15-1.25;

[0049] More preferably, the top temperature of the heavy hydrocarbon analysis tower is -8°C to -11°C, and the bottom temperature of the heavy hydrocarbon analysis tower is -275°C to -1285°C;

[0050] More preferably, the D / F of the heavy hydrocarbon analysis tower is 0.27-0.30;

[0051] In a specific embodiment, in the absorbent analysis step, the theoretical plate number of the heavy hydrocarbon analysis tower is 41, the analysis gas phase outlet of the heavy hydrocarbon analysis tower is arranged at the top of the heavy hydrocarbon analysis tower, the solvent phase outlet of the heavy hydrocarbon analysis tower is arranged at the bottom of the heavy hydrocarbon analysis tower, and the theoretical plate number of the feed port position of the heavy hydrocarbon analysis tower is 16; the feed temperature of the heavy hydrocarbon analysis tower is -15.7938°C, the operating pressure of the heavy hydrocarbon analysis tower is 2.5MPa, and the reflux ratio is 1.2; the top temperature of the heavy hydrocarbon analysis tower is -9.1786°C, and the bottom temperature of the heavy hydrocarbon analysis tower is -280.329°C; the D / F of the heavy hydrocarbon analysis tower is 0.28707.

[0052] According to a preferred embodiment of the second aspect, in the hydrogen recovery step, the light component gas phase is pressurized and heated to 40-50° C. and 45-55 bar;

[0053] More preferably, in the hydrogen recovery step, the light component gas phase is pressurized and heated to 40° C. and 50 bar.

[0054] According to a preferred embodiment of the second aspect, the light component gas phase is pressurized and heated before entering a hydrogen membrane separation unit for hydrogen separation, which comprises:

[0055] The light component gas phase after pressurization and temperature increase is transported to the first mixer. The gas output from the first mixer enters the first-stage hydrogen membrane separation equipment for hydrogen separation. Hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane are enriched on the residual side.

[0056] The crude hydrogen output from the permeate outlet of the first-stage hydrogen membrane separation device is pressurized and temperature-controlled by the second-stage hydrogen membrane separation temperature and pressure control device, and then enters the second-stage hydrogen membrane separation device for hydrogen separation, hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane are enriched on the residual side; the gas output from the residual gas outlet of the second-stage hydrogen membrane separation device is transported to the first mixer and mixed with the pressurized and heated light component gas phase for recycling; the permeate outlet of the second-stage hydrogen membrane separation device outputs the separated hydrogen;

[0057] The crude nitrogen and methane mixed gas output from the residual gas outlet of the first-stage hydrogen membrane separation device enters the third-stage hydrogen membrane separation device for hydrogen separation, and hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane are enriched on the residual side; the gas output from the permeate gas outlet of the third-stage hydrogen membrane separation device is transported to the first mixer and mixed with the pressurized and heated light component gas for recycling, and the separated nitrogen and methane mixed gas is output from the residual gas outlet of the third-stage hydrogen membrane separation device;

[0058] The special three-stage membrane separation technology used in this preferred technical solution can effectively ensure the high purity of the recovered hydrogen (reaching more than 92%) and the high recovery rate of hydrogen;

[0059] More preferably, the membrane used in the first-stage hydrogen membrane separation device is a polyimide membrane, and the permeate side pressure is 1 / 2.5-1 / 3.5 (e.g., 1 / 3) of the permeate side pressure; further preferably, the operating temperature of the first-stage hydrogen membrane separation device is 40-50° C., the permeate side pressure is 45-55 bar, and the permeate side pressure is 15-19 bar; in a specific embodiment, the operating temperature of the first-stage hydrogen membrane separation device is 40° C., the permeate side pressure is 50 bar, and the permeate side pressure is 17 bar;

[0060] More preferably, the crude hydrogen output from the permeate outlet of the first-stage hydrogen membrane separation device is pressurized and temperature-controlled to 40-50° C. and 45-55 bar by the second-stage hydrogen membrane separation temperature and pressure control device; In a specific embodiment, the crude hydrogen output from the permeate outlet of the first-stage hydrogen membrane separation device is pressurized and temperature-controlled to 40° C. and 50 bar by the second-stage hydrogen membrane separation temperature and pressure control device;

[0061] More preferably, the membrane used in the second-stage hydrogen membrane separation device is a polyimide membrane, and the permeate side pressure is 1 / 2.5-1 / 3.5 (e.g., 1 / 3) of the permeate side pressure; the operating temperature of the second-stage hydrogen membrane separation device is 40-50° C., the permeate side pressure is 45-55 bar, and the permeate side pressure is 15-19 bar; in a specific embodiment, the operating temperature of the second-stage hydrogen membrane separation device is 40° C., the permeate side pressure is 50 bar, and the permeate side pressure is 17 bar;

[0062] More preferably, the membrane used in the third-stage hydrogen membrane separation equipment is a polyimide membrane, and the permeate side pressure is 1 / 2.5-1 / 3.5 (e.g. 1 / 3) of the residual side pressure; the operating temperature of the third-stage hydrogen membrane separation equipment is 40-50°C, the residual side pressure is 45-55 bar, and the permeate side pressure is 15-19 bar; in a specific embodiment, the operating temperature of the third-stage hydrogen membrane separation equipment is 40°C, the residual side pressure is 50 bar, and the permeate side pressure is 17 bar.

[0063] According to a preferred embodiment of the second aspect, in the methane recovery step, the temperature and pressure of the nitrogen and methane mixture are regulated to 30-40° C. and 4.5-5.5 bar;

[0064] More preferably, in the methane recovery step, the temperature and pressure of the nitrogen and methane mixture are controlled to 35° C. and 5 bar.

[0065] According to a preferred embodiment of the second aspect, the nitrogen and methane mixed gas is subjected to temperature and pressure control and then enters the methane membrane separation unit for methane separation, which includes:

[0066] The nitrogen and methane mixed gas after temperature and pressure control is transported to the second mixer. The gas output from the second mixer enters the first-stage methane membrane separation device for methane separation. Methane is enriched on the residual side of the membrane and nitrogen is enriched on the permeate side. The residual gas outlet of the first-stage methane membrane separation device outputs the separated methane.

[0067] The crude nitrogen gas outputted from the permeate gas outlet of the first-stage methane membrane separation device is subjected to temperature and pressure control by the second-stage methane membrane separation temperature and pressure control device and then enters the second-stage methane membrane separation device for methane separation, wherein methane is enriched on the membrane filtrate side and nitrogen is enriched on the permeate side; the gas outputted from the permeate gas outlet of the second-stage methane membrane separation device is transported to the second mixer and mixed with the nitrogen and methane mixed gas after temperature and pressure control for recycling; the permeate gas outlet of the second-stage methane membrane separation device outputs the separated nitrogen;

[0068] The special two-stage membrane separation technology used in this preferred technical solution can effectively ensure the high purity of the recovered methane (reaching more than 90%) and the high recovery rate of methane;

[0069] More preferably, the membrane used in the first-stage methane membrane separation device is a DD3R membrane, the operating temperature of the first-stage hydrogen membrane separation device is 30-40°C, the filtrate side pressure is 4.5-5.5 bar, and the permeate side pressure is 0.9-1.2 bar; in a specific embodiment, the operating temperature of the first-stage hydrogen membrane separation device is 35°C, the filtrate side pressure is 5 bar, and the permeate side pressure is 1 bar;

[0070] More preferably, the crude nitrogen gas output from the permeate outlet of the first-stage methane membrane separation device is temperature- and pressure-controlled to 30-40° C. and 4.5-5.5 bar by the second-stage methane membrane separation temperature- and pressure-controlling device; in a specific embodiment, the crude nitrogen gas output from the permeate outlet of the first-stage methane membrane separation device is temperature- and pressure-controlled to 35° C. and 5 bar by the second-stage methane membrane separation temperature- and pressure-controlling device;

[0071] More preferably, the membrane used in the second-stage methane membrane separation equipment is a DD3R membrane, the operating temperature of the second-stage methane membrane separation equipment is 30-40°C, the filtrate side pressure is 4.5-5.5 bar, and the permeate side pressure is 0.9-1.2 bar; in a specific embodiment, the operating temperature of the second-stage methane membrane separation equipment is 35°C, the filtrate side pressure is 5 bar, and the permeate side pressure is 1 bar.

[0072] Compared with the prior art, the technical solution provided by the present invention has the following beneficial effects:

[0073] 1. The technical solution provided by the present invention can achieve the simultaneous high-purity and high-recovery separation and recovery of hydrogen and methane in refinery dry gas; in the preferred technical solution, the purity of the recovered methane reaches more than 90% and the purity of the hydrogen reaches more than 92%.

[0074] 2. The technical solution provided by the present invention does not require cryogenic separation, thus avoiding the problems of large cooling load and complicated refrigeration process caused by cryogenic separation. BRIEF DESCRIPTION OF THE DRAWINGS

[0075] Figure 1 This is a schematic diagram of the structure of the heavy component separation and absorbent analysis part in the dry gas light component separation and recovery system in Example 1.

[0076] Figure 2 This is a schematic diagram of the structure of the membrane separation part in the dry gas light component separation and recovery system in Example 1. DETAILED DESCRIPTION

[0077] In order to have a clearer understanding of the technical features, purposes and beneficial effects of the present invention, the technical solution of the present invention is now described in detail below, but it should not be construed as limiting the applicable scope of the present invention.

[0078] Example 1

[0079] This embodiment provides a dry gas light component separation and recovery system, such as Figure 1 , Figure 2 As shown, the separation system includes a feed gas pressurization and cooling unit 1, an absorbent pressurization and cooling unit 2, a heavy hydrocarbon absorption tower 3, a heavy hydrocarbon analysis tower 4, a light component pressurization and preheating unit 5, a hydrogen membrane separation unit 6, a dehydrogenated light component temperature and pressure control unit 7, a methane membrane separation unit 8 and a water separator 9;

[0080] The discharge port of the raw gas boosting and cooling unit 1 is connected to the raw material inlet of the heavy hydrocarbon absorption tower 3, the outlet of the absorbent boosting and cooling unit 2 is connected to the absorbent inlet of the heavy hydrocarbon absorption tower 3, the light component outlet of the heavy hydrocarbon absorption tower 3 is connected to the feed port of the light component boosting and preheating unit 5, the discharge port of the light component boosting and preheating unit 5 is connected to the feed port of the hydrogen membrane separation unit 6, the residual gas outlet of the hydrogen membrane separation unit 6 is connected to the feed port of the dehydrogenation light component temperature and pressure regulation unit 7, the discharge port of the dehydrogenation light component temperature and pressure regulation unit 7 is connected to the feed port of the methane membrane separation unit 8, the rich solvent phase outlet of the heavy hydrocarbon absorption tower 3 is connected to the feed port of the heavy hydrocarbon analysis tower 4, the solvent phase outlet of the heavy hydrocarbon analysis tower 4 is connected to the feed port of the absorbent boosting and cooling unit 2, and the water separator 9 is arranged on the connecting pipeline between the discharge port of the raw gas boosting and cooling unit 1 and the raw material inlet of the heavy hydrocarbon absorption tower 3.

[0081] Among them, the raw gas boost cooling unit 1 includes an intake compressor 11 and an intake cooler 12 connected in sequence, the feed port of the intake compressor 11 serves as the feed port of the raw gas boost cooling unit 1, and the outlet port of the intake cooler 12 serves as the outlet port of the raw gas boost cooling unit 1.

[0082] Among them, the absorbent boost cooling unit 2 includes an absorbent boost pump 21, an absorbent cooler 22 and a third mixer 23 connected in sequence; the feed port of the absorbent boost pump 21 serves as the feed port of the absorbent boost cooling unit 2, and the discharge port of the third mixer 23 serves as the discharge port of the absorbent boost cooling unit 2; and the feed port of the third mixer 23 is also connected to the absorbent supply pipeline to realize the replenishment of the absorbent.

[0083] Among them, the theoretical plate number of the heavy hydrocarbon absorption tower 3 is 7, the light component outlet of the heavy hydrocarbon absorption tower 3 is set at the top of the heavy hydrocarbon absorption tower 3, the rich solvent phase outlet of the heavy hydrocarbon absorption tower is set at the bottom of the heavy hydrocarbon absorption tower 3, the raw material inlet of the heavy hydrocarbon absorption tower 3 is set at the bottom of the heavy hydrocarbon absorption tower, and the absorbent inlet of the heavy hydrocarbon absorption tower 3 is set at the top of the heavy hydrocarbon absorption tower.

[0084] Among them, a decondenser is arranged at the top of the heavy hydrocarbon analysis tower 4. The theoretical plate number of the heavy hydrocarbon analysis tower 4 is 41, the analysis gas phase outlet of the heavy hydrocarbon analysis tower 4 is arranged at the top of the heavy hydrocarbon analysis tower 4, the solvent phase outlet of the heavy hydrocarbon analysis tower 4 is arranged at the bottom of the heavy hydrocarbon analysis tower 4, and the theoretical plate number of the feed port position of the heavy hydrocarbon analysis tower 4 is 16.

[0085] Among them, the light component boosting and preheating unit 5 includes a light component compressor 51 and a light component preheater 52 connected in sequence, the feed port of the light component compressor 51 serves as the feed port of the light component boosting and preheating unit 5, and the discharge port of the light component preheater 52 serves as the discharge port of the light component boosting and preheating unit 5.

[0086] The hydrogen membrane separation unit 6 includes a first mixer 61, a first-stage hydrogen membrane separation device 62, a second-stage hydrogen membrane separation temperature and pressure control device 63, a second-stage hydrogen membrane separation device 64, and a third-stage hydrogen membrane separation device 65. The discharge port 61 of the first mixer is connected to the feed port of the first-stage hydrogen membrane separation device 62, the residual gas outlet of the first-stage hydrogen membrane separation device 62 is connected to the feed port of the third-stage hydrogen membrane separation device 65, the permeate gas outlet of the first-stage hydrogen membrane separation device 62 is connected to the feed port of the second-stage hydrogen membrane separation temperature and pressure control device 63, and the discharge port of the second-stage hydrogen membrane separation temperature and pressure control device 63 is connected to the feed port of the second-stage hydrogen membrane separation device 64; the feed port of the first mixer 61 serves as The feed port of the hydrogen membrane separation unit 6 is connected to the discharge port of the light component boosting and preheating unit 5, and the residual gas outlet of the third-stage hydrogen membrane separation device 65 is connected to the feed port of the dehydrogenation light component temperature and pressure control unit 7 as the residual gas outlet of the hydrogen membrane separation unit 6; the permeate outlet of the third-stage hydrogen membrane separation device 65 and the residual gas outlet of the second-stage hydrogen membrane separation device 64 are respectively connected to the feed port of the first mixer 61; the permeate outlet of the second-stage hydrogen membrane separation device 64 is used as the hydrogen outlet. The second-stage hydrogen membrane separation temperature and pressure control device 63 includes a crude hydrogen compressor 631 and a crude hydrogen cooler 632 connected in sequence, the feed port of the crude hydrogen compressor 631 is used as the feed port of the second-stage hydrogen membrane separation temperature and pressure control device 63, and the discharge port of the crude hydrogen cooler 632 is used as the discharge port of the second-stage hydrogen membrane separation temperature and pressure control device 63. Among them, the membranes used in the first-stage hydrogen membrane separation equipment 62, the second-stage hydrogen membrane separation equipment 64, and the third-stage hydrogen membrane separation equipment 65 are membranes that can achieve hydrogen permeation and methane and nitrogen non-permeation. The membrane used in the hydrogen membrane separation unit 6 can be but is not limited to one or more of polymer membranes, inorganic non-metallic membranes, metal membranes, and other new material membranes; when multiple stages of membranes are set, the types of membranes at each stage can be the same or different, and can be freely specified according to production conditions; polyimide membranes are used in this embodiment.

[0087] Among them, the dehydrogenation light component temperature and pressure control unit 7 includes a dehydrogenation light component pressure reducing valve 71 and a dehydrogenation light component preheater 72 connected in sequence, the feed port of the dehydrogenation light component pressure reducing valve 71 serves as the feed port of the dehydrogenation light component temperature and pressure control unit 7, and the discharge port of the dehydrogenation light component preheater 72 serves as the discharge port of the dehydrogenation light component temperature and pressure control unit 7.

[0088] Among them, the methane membrane separation unit 8 includes a second mixer 81, a first-stage methane membrane separation device 82, a second-stage methane membrane separation temperature and pressure control device 83, and a second-stage methane membrane separation device 84; the discharge port of the second mixer 81 is connected to the feed port of the first-stage methane membrane separation device 82, the permeate outlet of the first-stage methane membrane separation device 82 is connected to the feed port of the second-stage methane membrane separation temperature and pressure control device 84, and the discharge port of the second-stage methane membrane separation temperature and pressure control device 83 is connected to the feed port of the second-stage methane membrane separation device 84; the feed port of the second mixer 81 is connected to the discharge port of the dehydrogenation light component temperature and pressure control unit 7 as the feed port of the methane membrane separation unit 8, and the permeate outlet of the second-stage methane membrane separation device 84 is used as a nitrogen outlet; the residual gas outlet of the second-stage methane membrane separation device 84 is connected to the feed port of the second mixer 81; the residual gas outlet of the first-stage methane membrane separation device 82 is used as a methane outlet. The second-stage methane membrane separation temperature and pressure control device 83 includes a crude nitrogen compressor 831 and a crude nitrogen cooler 832 connected in sequence. The membrane used in the methane membrane separation unit 8 is a membrane that can achieve nitrogen permeation and methane non-permeation. The membrane used in the methane membrane separation unit can be, but is not limited to, one or more of a polymer membrane, an inorganic non-metallic membrane, a metal membrane, and other new material membranes; when a multi-stage membrane is set, the type of membrane at each stage can be the same or different, and can be freely specified according to production conditions; DD3R membranes are used in this embodiment.

[0089] Example 2

[0090] This embodiment does not provide a method for separating and recovering light components of dry gas. This method uses the dry gas light component separation and recovery system provided in Example 1 to separate and recover light components from dry gas from a catalytic cracking unit of a refinery. The catalytic cracking capacity of the refinery is 3 million tons, the catalytic dry gas yield is 2.78%, the output is 87,900 tons, and the dry gas composition is shown in Table 1.

[0091] Table 1 Composition of catalytic dry gas

[0092] Components Value (mol%) Components Value (mol%) <![CDATA[H2]]> 32.24 <![CDATA[CO2]]> 0.21 <![CDATA[O2]]> 0.31 <![CDATA[C2H4]]> 11.57 <![CDATA[N2]]> 13.39 <![CDATA[C2H6]]> 12.38 <![CDATA[CH4]]> 24.73 <![CDATA[C3H8]]> 0.66 <![CDATA[C4H8]]> 0.11 <![CDATA[C4H 10 ]]> 0.52 C5+ 0.38

[0093] The specific steps include:

[0094] 1. Steps for separation of heavy components:

[0095] The refinery dry gas is pressurized and cooled through the intake compressor 11 and the intake cooler 12 in turn, and the refinery dry gas after pressurization and cooling enters the water separator 9 for water removal; wherein, the feed temperature of the intake compressor 11 is 30°C, the discharge temperature is 437.274°C, the feed pressure is 1atm, and the discharge pressure is 35bar, the feed temperature of the intake cooler is 437.274°C, the discharge temperature is -40°C, the feed pressure is 35bar, and the discharge pressure is 35bar, the feed temperature of the water separator is -40°C, the discharge temperature is -40°C, the feed pressure is 35bar, and the discharge temperature is 35bar; wherein, the absorbent is a mixture of toluene and benzene (the volume ratio of toluene and benzene is maintained in the range of 2:3-3:2).

[0096] The absorbent discharged from the solvent phase of the heavy hydrocarbon analysis tower 4 is pressurized and cooled in turn through the absorbent booster pump 21 and the absorbent cooler 22. The refinery dry gas after pressurization and cooling can be selectively mixed with a supplementary absorbent (the supplementary absorbent is added when needed and not added when not needed) through the third mixer 23; wherein, the feed temperature of the absorbent booster pump 21 is 280.329°C, the discharge temperature is 283.019°C, the feed pressure is 2.5MPa, and the discharge pressure is 3.5MPa; the feed temperature of the absorbent cooler 22 is 283.019°C, the discharge temperature is -40°C, the feed pressure is 3.5MPa, and the discharge pressure is 3.5MPa.

[0097] The refinery dry gas from the outlet of the water separator 9 enters the heavy hydrocarbon absorption tower 3 from the raw material inlet of the heavy hydrocarbon absorption tower 3, and the absorbent from the third mixer 23 enters the heavy hydrocarbon absorption tower 3 from the absorbent inlet of the heavy hydrocarbon absorption tower 3. In the heavy hydrocarbon absorption tower 3, the absorbent and the refinery dry gas are in reverse contact to extract the C2+ heavy components in the refinery dry gas into the absorbent, and a C2+ heavy component-rich solvent liquid phase is formed at the bottom of the heavy hydrocarbon absorption tower 3, and a light component gas phase is formed at the top of the heavy hydrocarbon absorption tower 3; wherein, the absorbent feed temperature of the heavy hydrocarbon absorption tower 3 is -40°C, the refinery dry gas feed temperature is -40°C, the operating pressure is 3.5MPa, the top temperature is -33.4°C, and the bottom temperature is -15.7938°C.

[0098] 2. Absorbent analysis steps:

[0099] The C2+ heavy component-rich solvent liquid phase from the rich solvent phase outlet of the heavy hydrocarbon absorption tower 3 enters the heavy hydrocarbon analysis tower 4 through the feed port of the heavy hydrocarbon analysis tower 4 for C2+ heavy component-rich analysis, and a solvent phase is obtained at the bottom of the tower and a C2+ heavy component phase is obtained at the top of the tower. The solvent phase is discharged from the solvent phase outlet of the heavy hydrocarbon analysis tower 4 and transported to the absorbent booster pump 21 for recycling as the absorbent used in the heavy component separation step; wherein, the feed temperature of the heavy hydrocarbon analysis tower 4 is -15.7938°C, the top temperature is -9.1786°C, the bottom temperature is 280.329°C, the operating pressure is 2.5MPa, the number of theoretical plates is 41, the reflux ratio is 1.2, and the D / F is 0.28707.

[0100] 3. Hydrogen recovery steps:

[0101] The light components from the light component outlet of the heavy hydrocarbon absorption tower 3 are successively pressurized and heated by the light component compressor 51 and the light component preheater 52 and then transported to the first mixer 61. In the first mixer 61, the light components from the light component preheater 52 are mixed with the gas from the residual gas outlet of the second-stage hydrogen membrane separation device 64 and the gas from the permeate gas outlet of the third-stage hydrogen membrane separation device 65. The gas output from the first mixer 61 enters the first-stage hydrogen membrane separation device 62 for hydrogen separation. Hydrogen is enriched on the membrane permeation side, and nitrogen and methane are separated. Enrichment on the retentate side; wherein, the feed temperature of the light component compressor 51 is -33.4024°C, the discharge temperature is -0.1187°C, the feed pressure is 35 bar, and the discharge pressure is 50 bar, the feed temperature of the light component preheater 52 is -0.1187°C, the discharge temperature is 40°C, the feed pressure is 50 bar, and the discharge pressure is 50 bar, the feed temperature of the first-stage hydrogen membrane separation equipment 62 is 40°C, the discharge temperature is 40°C, the retentate side pressure is 50 bar, and the permeate side pressure is 17 bar.

[0102] The crude hydrogen gas outputted from the permeate outlet of the first-stage hydrogen membrane separation device 62 is successively pressurized and temperature-controlled by the crude hydrogen compressor 631 and the crude hydrogen cooler 632, and then enters the second-stage hydrogen membrane separation device 64 for hydrogen separation, wherein hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane are enriched on the permeate side; the gas outputted from the permeate outlet of the second-stage hydrogen membrane separation device 64 is transported to the first mixer 61, and the permeate outlet of the second-stage hydrogen membrane separation device 64 outputs the separated hydrogen; wherein the crude hydrogen gas The feed temperature of compressor 631 is -40°C, the discharge temperature is 184.944°C, the feed pressure is 17 bar, and the discharge pressure is 50 bar. The feed temperature of crude hydrogen cooler 632 is -184.944°C, the discharge temperature is 40°C, the feed pressure is 50 bar, and the discharge pressure is 50 bar. The feed temperature of the second-stage hydrogen membrane separation equipment 64 is 40°C, the discharge temperature is 40°C, the permeate side pressure is 50 bar, and the permeate side pressure is 17 bar.

[0103] The crude nitrogen and methane mixed gas output from the residual gas outlet of the first-stage hydrogen membrane separation device 62 enters the third-stage hydrogen membrane separation device 65 for hydrogen separation, and hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane are enriched on the residual side; the gas output from the permeate gas outlet of the third-stage hydrogen membrane separation device 65 is transported to the first mixer 61, and the separated nitrogen and methane mixed gas is output from the residual gas outlet of the third-stage hydrogen membrane separation device 65; wherein, the feed temperature of the third-stage hydrogen membrane separation device 65 is 40°C, the discharge temperature is 40°C, the residual side pressure is 50 bar, and the permeate side pressure is 17 bar.

[0104] 4. Methane recovery steps:

[0105] The separated nitrogen and methane mixed gas output from the residual gas outlet of the third-stage hydrogen membrane separation device 65 is sequentially passed through the dehydrogenation light component pressure reducing valve 71 and the dehydrogenation light component preheater 72 for temperature and pressure regulation. The nitrogen and methane mixed gas after temperature and pressure regulation is transported to the second mixer 81 to be mixed with the gas output from the residual gas outlet of the second-stage methane membrane separation device 84. The gas output from the second mixer 81 enters the first-stage methane membrane separation device 82 for methane separation. Methane is enriched on the residual gas side of the membrane and nitrogen is enriched on the permeate side. The first-stage methane membrane separation device The residual gas outlet 82 outputs the separated methane; wherein, the feed temperature of the dehydrogenation light component pressure reducing valve 71 is 40°C, the discharge temperature is 25.0141°C, the feed pressure is 50bar, and the discharge pressure is 5bar, the feed temperature of the dehydrogenation light component preheater 72 is -25.0141°C, the discharge temperature is 35°C, the feed pressure is 5bar, and the discharge pressure is 5bar, the feed temperature of the first-stage methane membrane separation equipment is 35°C, the discharge temperature is 35°C, the residual side pressure is 5bar, and the permeate side pressure is 1bar.

[0106] The crude nitrogen gas output from the permeate outlet of the first-stage methane membrane separation device 82 is successively temperature-controlled and pressure-regulated by the crude nitrogen compressor 831 and the crude nitrogen cooler 832, and then enters the second-stage methane membrane separation device 84 for methane separation, where methane is enriched on the membrane filtrate side and nitrogen is enriched on the permeate side; the gas output from the permeate outlet of the second-stage methane membrane separation device 84 is transported to the second mixer 81; the permeate outlet of the second-stage methane membrane separation device 84 outputs the separated nitrogen; wherein the crude nitrogen gas is The feed temperature of the nitrogen compressor 831 is -40°C, the discharge temperature is 184.944°C, the feed pressure is 1 bar, and the discharge pressure is 5 bar. The feed temperature of the crude nitrogen cooler 832 is -265.694°C, the discharge temperature is 35°C, the feed pressure is 5 bar, and the discharge pressure is 5 bar. The feed temperature of the second-stage methane membrane separation equipment 84 is 35°C, the discharge temperature is 35°C, the permeate side pressure is 5 bar, and the permeate side pressure is 1 bar.

[0107] In order to verify the effectiveness of this embodiment, the dry gas light component separation and recovery method in this embodiment was simulated and verified by the process simulation platform Aspen Plus; wherein, the physical property method of each device was carried out using RK-SOAVE; wherein, the Excel user model (permeation equation and material balance equation) was embedded in the membrane separation process in the dry gas light component separation and recovery method using the extended interface of Aspen Plus to simulate the Excel user model permeation equation and material balance equation:

[0108] X ip F p =J i ΔP i A

[0109] F F =F R +F P

[0110] X iF F F =X iR F R +X ip F p

[0111] ∑X iF =1,∑X iR =1,∑X iP =1

[0112] Calculate the driving force of the partial pressure difference on both sides of the membrane by using the arithmetic mean

[0113]

[0114] The component cutting rate is calculated using the following formula

[0115]

[0116] Where:

[0117] X iF , X iP , X iR are the molar fractions of the components of the feed gas, permeate gas, and retentate gas;

[0118] F F 、F P 、F R are the molar flow rates of feed gas, permeate gas, and retentate gas, in kmol / h;

[0119] J i Represents the permeability coefficient of each component, unit kmol / (h·m 2 kPa)

[0120] ΔP i Represents the driving force of partial pressure difference, unit is kPa;

[0121] A represents the membrane area, unit: m 2 .

[0122] The simulation results are as follows: the volume purities of the obtained methane and hydrogen are 90.5% and 92.9% respectively, and the recovery rates of methane and hydrogen are both between 90% and 93%.

[0123] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principle of the present invention should be included in the protection scope of the present invention.

Claims

1. A dry gas light component separation and recovery system, wherein: The separation system includes a feed gas pressurization and cooling unit, an absorbent pressurization and cooling unit, a heavy hydrocarbon absorption tower, a light component pressurization and preheating unit, a hydrogen membrane separation unit, a dehydrogenated light component temperature and pressure control unit, and a methane membrane separation unit; The discharge port of the raw gas pressurization and cooling unit is connected to the raw material inlet of the heavy hydrocarbon absorption tower, the outlet of the absorbent pressurization and cooling unit is connected to the absorbent inlet of the heavy hydrocarbon absorption tower, the light component outlet of the heavy hydrocarbon absorption tower is connected to the feed port of the light component pressurization and preheating unit, the discharge port of the light component pressurization and preheating unit is connected to the feed port of the hydrogen membrane separation unit, the residual gas outlet of the hydrogen membrane separation unit is connected to the feed port of the dehydrogenation light component temperature and pressure regulation unit, and the discharge port of the dehydrogenation light component temperature and pressure regulation unit is connected to the feed port of the methane membrane separation unit.

2. The system according to claim 1, wherein: The hydrogen membrane separation unit includes a first mixer, a first-stage hydrogen membrane separation device, a second-stage hydrogen membrane separation temperature and pressure control device, a second-stage hydrogen membrane separation device, and a third-stage hydrogen membrane separation device; The discharge port of the first mixer is connected to the feed port of the first-stage hydrogen membrane separation device, the residual gas outlet of the first-stage hydrogen membrane separation device is connected to the feed port of the third-stage hydrogen membrane separation device, the permeate gas outlet of the first-stage hydrogen membrane separation device is connected to the feed port of the second-stage hydrogen membrane separation temperature and pressure control device, and the discharge port of the second-stage hydrogen membrane separation temperature and pressure control device is connected to the feed port of the second-stage hydrogen membrane separation device; the feed port of the first mixer is connected to the discharge port of the light component boosting and preheating unit as the feed port of the hydrogen membrane separation unit, and the residual gas outlet of the third-stage hydrogen membrane separation device is connected to the feed port of the dehydrogenation light component temperature and pressure control unit as the residual gas outlet of the hydrogen membrane separation unit; the permeate gas outlet of the third-stage hydrogen membrane separation device and the residual gas outlet of the second-stage hydrogen membrane separation device are respectively connected to the feed port of the first mixer; The permeate gas outlet of the second-stage hydrogen membrane separation device serves as the hydrogen outlet.

3. The system according to claim 1, wherein: The methane membrane separation unit includes a second mixer, a first-stage methane membrane separation device, a second-stage methane membrane separation temperature and pressure control device, and a second-stage methane membrane separation device; The discharge port of the second mixer is connected to the feed port of the first-stage methane membrane separation equipment, the permeate gas outlet of the first-stage methane membrane separation equipment is connected to the feed port of the second-stage methane membrane separation temperature and pressure control equipment, and the discharge port of the second-stage methane membrane separation temperature and pressure control equipment is connected to the feed port of the second-stage methane membrane separation equipment; the feed port of the second mixer is connected to the discharge port of the dehydrogenation light component temperature and pressure control unit as the feed port of the methane membrane separation unit, and the permeate gas outlet of the second-stage methane membrane separation equipment is used as a nitrogen outlet; the residual gas outlet of the second-stage methane membrane separation equipment is connected to the feed port of the second mixer; the residual gas outlet of the first-stage methane membrane separation equipment is used as a methane outlet.

4. The system according to claim 1, wherein: The membrane used in the hydrogen membrane separation unit is a membrane that can achieve hydrogen permeation but not methane and nitrogen permeation; preferably, the membrane used in the hydrogen membrane separation unit is a polyimide membrane.

5. The system according to claim 1, wherein: The membrane used in the methane membrane separation unit is a membrane that allows nitrogen to pass through but does not allow methane to pass through; preferably, the membrane used in the methane membrane separation unit is a DD3R membrane.

6. The system according to claim 1, wherein: The theoretical plate number of the heavy hydrocarbon absorption tower is 7-25, the light component outlet of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower, the rich solvent phase outlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, the raw material inlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, and the absorbent inlet position of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower.

7. The system according to claim 1, wherein: The dry gas light component separation and recovery system further includes a heavy hydrocarbon analysis tower; the feed port of the heavy hydrocarbon analysis tower is connected to the rich solvent phase outlet of the heavy hydrocarbon absorption tower, and the solvent phase outlet of the heavy hydrocarbon analysis tower is connected to the feed port of the absorbent boost cooling unit. Preferably, the theoretical plate number of the heavy hydrocarbon analysis tower is 30-60, the analysis gas phase outlet of the heavy hydrocarbon analysis tower is arranged at the top of the heavy hydrocarbon analysis tower, the solvent phase outlet of the heavy hydrocarbon analysis tower is arranged at the bottom of the heavy hydrocarbon analysis tower, and the theoretical plate number of the feed port position of the heavy hydrocarbon analysis tower is 10-20.

8. The system according to claim 1, wherein: A water separator is further arranged on the connecting pipeline between the discharge port of the raw gas boost cooling unit and the raw material inlet of the heavy hydrocarbon absorption tower.

9. A method for separating and recovering light components of dry gas, the method being carried out using the dry gas light component separation and recovery system according to any one of claims 1 to 8, comprising the following steps: Heavy component separation step: pressurizing and cooling the refinery dry gas, pressurizing and cooling the absorbent, contacting the pressurized and cooled refinery dry gas with the pressurized and cooled absorbent in a heavy hydrocarbon absorption tower to extract the C2+ heavy components in the refinery dry gas into the absorbent, forming a C2+ heavy component-rich solvent liquid phase and a light component gas phase; Hydrogen recovery step: the light component gas phase is pressurized and heated before entering the hydrogen membrane separation unit for hydrogen separation, wherein: Hydrogen is enriched on the permeate side of the membrane, and the nitrogen and methane mixed gas is enriched on the retentate side; Collect hydrogen from the permeate gas outlet of the hydrogen membrane separation unit; Methane recovery step: the nitrogen and methane mixed gas is temperature- and pressure-controlled and then enters a methane membrane separation unit for methane separation, wherein methane is enriched on the membrane filtrate side and nitrogen is enriched on the permeate side; methane is collected from the filtrate outlet of the methane membrane separation unit.

10. The method according to claim 9, wherein: The absorbent includes toluene and / or benzene.

11. The method according to claim 9, wherein: In the heavy component separation step, the refinery dry gas is pressurized and cooled to 30-40 bar, -40°C to -45°C, the absorbent is pressurized and cooled to 30-40 bar, -40°C to -45°C, the theoretical plate number of the heavy hydrocarbon absorption tower is 7-25, the light component outlet of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower, the rich solvent phase outlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, the raw material inlet of the heavy hydrocarbon absorption tower is arranged at the bottom of the heavy hydrocarbon absorption tower, and the absorbent inlet position of the heavy hydrocarbon absorption tower is arranged at the top of the heavy hydrocarbon absorption tower; the operating pressure of the heavy hydrocarbon absorption tower is 3-4MPa; Preferably, the top temperature of the heavy hydrocarbon absorption tower is -32°C to -35°C, and the bottom temperature of the heavy hydrocarbon absorption tower is -13°C to -18°C.

12. The method according to claim 9, wherein: The method further includes: Absorbent analysis step: the C2+ heavy component-rich solvent liquid phase enters the heavy hydrocarbon analysis tower for C2+ heavy component-rich analysis to obtain a solvent phase and a C2+ heavy component phase, and the solvent phase is recycled as the absorbent used in the heavy component separation step.

13. The method according to claim 12, wherein: In the absorbent analysis step, the theoretical plate number of the heavy hydrocarbon analysis tower is 30-60, the analysis gas phase outlet of the heavy hydrocarbon analysis tower is arranged at the top of the heavy hydrocarbon analysis tower, the solvent phase outlet of the heavy hydrocarbon analysis tower is arranged at the bottom of the heavy hydrocarbon analysis tower, and the theoretical plate number of the feed inlet position of the heavy hydrocarbon analysis tower is 10-20; the feed temperature of the heavy hydrocarbon analysis tower is -13°C to -18°C, the operating pressure of the heavy hydrocarbon analysis tower is 2.3-2.7MPa, and the reflux ratio is 1.15-1.25; Preferably, the top temperature of the heavy hydrocarbon analysis tower is -8°C to -11°C, and the bottom temperature of the heavy hydrocarbon analysis tower is -275°C to -1285°C; Preferably, the D / F of the heavy hydrocarbon analysis tower is 0.27-0.

30.

14. The method according to claim 9, wherein: In the hydrogen recovery step, the light component gas phase is pressurized and heated to 40-50° C. and 45-55 bar.

15. The method according to claim 9 or 14, wherein: The light component gas phase is pressurized and heated before entering the hydrogen membrane separation unit for hydrogen separation, which includes: The light component gas phase after pressurization and temperature increase is transported to the first mixer. The gas output from the first mixer enters the first-stage hydrogen membrane separation equipment for hydrogen separation. Hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane are enriched on the residual side. The crude hydrogen output from the permeate outlet of the first-stage hydrogen membrane separation device is pressurized and temperature-controlled by the second-stage hydrogen membrane separation temperature and pressure control device, and then enters the second-stage hydrogen membrane separation device for hydrogen separation, hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane are enriched on the residual side; the gas output from the residual gas outlet of the second-stage hydrogen membrane separation device is transported to the first mixer and mixed with the pressurized and heated light component gas phase for recycling; the permeate outlet of the second-stage hydrogen membrane separation device outputs the separated hydrogen; The crude nitrogen and methane mixed gas output from the residual gas outlet of the first-stage hydrogen membrane separation equipment enters the third-stage hydrogen membrane separation equipment for hydrogen separation, hydrogen is enriched on the permeate side of the membrane, and nitrogen and methane are enriched on the residual side; the gas output from the permeate gas outlet of the third-stage hydrogen membrane separation equipment is transported to the first mixer and mixed with the pressurized and heated light component gas for recycling, and the separated nitrogen and methane mixed gas is output from the residual gas outlet of the third-stage hydrogen membrane separation equipment.

16. The method according to claim 15, wherein: The membrane used in the first stage hydrogen membrane separation equipment is a polyimide membrane, the operating temperature of the first stage hydrogen membrane separation equipment is 40-50°C, the permeate side pressure is 45-55 bar, and the permeate side pressure is 15-19 bar; and / or The crude hydrogen gas output from the permeate outlet of the first-stage hydrogen membrane separation device is pressurized and temperature-controlled to 40-50°C and 45-55bar by the second-stage hydrogen membrane separation temperature and pressure control device; and / or The membrane used in the second-stage hydrogen membrane separation equipment is a polyimide membrane, the operating temperature of the second-stage hydrogen membrane separation equipment is 40-50°C, the permeate side pressure is 45-55 bar, and the permeate side pressure is 15-19 bar; and / or The membrane used in the third-stage hydrogen membrane separation equipment is a polyimide membrane. The operating temperature of the third-stage hydrogen membrane separation equipment is 40-50°C, the pressure on the residual side is 45-55 bar, and the pressure on the permeate side is 15-19 bar.

17. The method according to claim 9, wherein: In the methane recovery step, the temperature and pressure of the nitrogen and methane mixed gas are regulated to 30-40° C. and 4.5-5.5 bar.

18. The method according to claim 9 or 17, wherein: The nitrogen and methane mixed gas is temperature- and pressure-controlled and then enters the methane membrane separation unit for methane separation, which includes: The nitrogen and methane mixed gas after temperature and pressure control is transported to the second mixer. The gas output from the second mixer enters the first-stage methane membrane separation device for methane separation. Methane is enriched on the residual side of the membrane and nitrogen is enriched on the permeate side. The residual gas outlet of the first-stage methane membrane separation device outputs the separated methane. The crude nitrogen output from the permeate gas outlet of the first-stage methane membrane separation device is temperature- and pressure-controlled by the second-stage methane membrane separation temperature- and pressure-control device, and then enters the second-stage methane membrane separation device for methane separation, with methane being enriched on the membrane filtrate side and nitrogen being enriched on the permeate side; the gas output from the filtrate gas outlet of the second-stage methane membrane separation device is transported to the second mixer and mixed with the temperature- and pressure-controlled nitrogen and methane mixed gas for recycling; the separated nitrogen is output from the permeate gas outlet of the second-stage methane membrane separation device.

19. The method according to claim 18, wherein: The membrane used in the first-stage methane membrane separation equipment is DD3R membrane, the operating temperature of the first-stage hydrogen membrane separation equipment is 30-40°C, the pressure on the residual side is 4.5-5.5 bar, and the pressure on the permeate side is 0.9-1.2 bar; and / or The crude nitrogen gas output from the residual gas outlet of the first-stage methane membrane separation device is temperature- and pressure-controlled to 30-40°C and 4.5-5.5 bar by the second-stage methane membrane separation temperature- and pressure-control device; and / or The membrane used in the second-stage methane membrane separation equipment is DD3R membrane. The operating temperature of the second-stage methane membrane separation equipment is 30-40°C, the pressure on the residual side is 4.5-5.5 bar, and the pressure on the permeate side is 0.9-1.2 bar.

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