System and method for producing sulfur from sour natural gas

Abstract

This invention relates to the field of sulfur production technology from natural gas, specifically to a system and method for producing sulfur from sour natural gas. The system includes an oxidation unit connected in series via pipelines; a gas-liquid separation unit connected via pipeline to the oxide outlet of the oxidation unit; a hydrogenation unit connected via pipeline to the gas phase outlet of the gas-liquid separation unit; and a sulfur adsorption unit and / or carbon adsorption unit connected via pipeline to the hydrogenated stream outlet of the hydrogenation unit; wherein the hydrogenated stream outlet of the hydrogenation unit is connected via pipeline to the sour natural gas feed inlet of the oxidation unit. This system, through the series connection of the oxidation unit, gas-liquid separation unit, hydrogenation unit, sulfur removal unit, and carbon removal unit, ensures that the process can be carried out under constant pressure throughout the entire process, and features low energy consumption and a simple process.

Description

Technical Field

[0001] This invention relates to the field of sulfur production technology from natural gas, and more specifically to a system and method for producing sulfur from acidic natural gas. Background Technology

[0002] There are two main types of natural gas desulfurization processes: one is the amine solvent absorption process, which is mainly suitable for large-scale natural gas fields; the other is the complexed iron process, which is mainly suitable for small-scale natural gas wells. The former uses organic amine solvents to remove sulfides and CO2 from natural gas under high pressure, employing a fixed-bed reactor for CO2 removal to obtain finished natural gas that meets Class I gas standards. The amine-rich solution after H2S absorption regenerates H2S and enters a sulfur recovery unit to recover sulfur under atmospheric pressure, achieving the first-grade quality standards of industrial sulfur (GB2449-2014). However, this process is energy-intensive and complex. The latter uses a complexed iron process to remove sulfur from natural gas. This process utilizes Fe... 3+ Liquid-phase catalysts convert H2S into elemental sulfur, enabling natural gas products to meet Class I gas standards. However, the recovered sulfur exists in the form of sulfur paste, and the quality of the sulfur cannot meet national standards. Furthermore, additional fees must be paid to treatment units to process the waste sulfur paste, and market prices are trending upwards.

[0003] CN103421566B discloses a natural gas desulfurization and recovery process and apparatus, relating to a natural gas purification method, specifically a method and equipment for removing hydrogen sulfide and recovering elemental sulfur from natural gas. The apparatus comprises a hydrophobic membrane module, an oxidation regeneration tank, and an absorbent tank. Through steps of natural gas desulfurization, catalytic solution regeneration, and elemental sulfur recovery, it utilizes a membrane-based absorption method for natural gas desulfurization, achieving a hydrogen sulfide removal rate of over 99%. A catalytic oxidation system is constructed using iron ions combined with different complexing agents and catalysts under air, effectively converting the absorbed hydrogen sulfide into elemental sulfur for recovery. The lean solution, after regeneration, can be recycled as absorbent. In the natural gas desulfurization process, the feed gas is pressurized and introduced into the tubing of the membrane module; desulfurization is carried out under high pressure, while subsequent steps are conducted under atmospheric pressure. This method also suffers from the problem of generating waste sulfur paste.

[0004] CA2523037A discloses a method for removing sour gas from high-pressure sulfur-containing natural gas. First, the natural gas to be desulfurized is introduced into an absorption tower, where sulfur-containing components and other absorbable components are absorbed by the lean solution. The rich solution is then heated and sent to a high-pressure flash evaporator, where desorbed sour gas is separated. The desorbed sour gas is cooled, and the evaporated absorbent is condensed. The pressure during the high-pressure flash stage needs to be adjusted so that the desorbed sour gas can be condensed out using cooling water or cooling air. This method belongs to the amine solvent absorption process, with the desulfurization stage carried out under high pressure, while the subsequent sulfur recovery process from the sour gas is carried out under normal pressure. It is not a complete high-pressure natural gas desulfurization process and suffers from high energy consumption and process complexity. Summary of the Invention

[0005] The purpose of this invention is to overcome the problems of high energy consumption, complex process, and low sulfur quality in the existing technology, and to provide a system and method for preparing sulfur from acidic natural gas. This system can ensure that the process is carried out under constant pressure throughout the process, and has the characteristics of low energy consumption and simple process. It can directly obtain high-quality sulfur, thereby reducing the investment and operating costs of the system equipment, and has significant economic and social benefits.

[0006] To achieve the above objectives, a first aspect of the present invention provides a system for preparing sulfur from sour natural gas. The system includes an oxidation unit connected in series via pipelines; a gas-liquid separation unit connected via a pipeline to the oxide outlet of the oxidation unit; a hydrogenation unit connected via a pipeline to the gas phase outlet of the gas-liquid separation unit; and a sulfur adsorption unit and / or a carbon adsorption unit connected via a pipeline to the hydrogenated stream outlet of the hydrogenation unit; wherein the hydrogenated stream outlet of the hydrogenation unit is connected via a pipeline to the sour natural gas feed inlet of the oxidation unit.

[0007] A second aspect of the present invention provides a method for preparing sulfur from sour natural gas, the method being carried out in the system described in the first aspect, comprising the following steps: S1. Mixing sour natural gas with oxidizing gas to form an oxide feedstock, which is then fed into an oxidation device to undergo an oxidation reaction, obtaining an oxidized stream; S2. Passing the oxidized stream into a gas-liquid separation device for condensation and gas-liquid separation, obtaining liquid sulfur and a gaseous stream, wherein the gaseous stream is hydrogenated, and the hydrogenated stream is divided into two streams; S3. One of the hydrogenated streams from step S2 is recycled back into the sour natural gas, and the other stream is sent to a sulfur adsorption device and / or a carbon adsorption device to remove hydrogen sulfide and / or carbon dioxide to obtain purified natural gas.

[0008] Through the above technical solution, the present invention has the following advantages: The system of this invention, through the series connection of an oxidation device, a gas-liquid separation device, a hydrogenation device, a sulfur removal device, and a carbon removal device, can ensure that the process can be carried out under constant pressure throughout the entire process, and has the characteristics of low energy consumption and simple process.

[0009] The method of the present invention is carried out in the system described above, which can ensure that the process is carried out under constant pressure throughout the entire process, and can directly obtain high-quality sulfur, thereby reducing the investment and operating costs of the system equipment, and has significant economic and social benefits.

[0010] Compared with existing technologies, the present invention performs natural gas purification and desulfurization simultaneously, directly oxidizing the sulfide in natural gas into sulfur without producing wastewater or waste sulfur paste, thus effectively improving the quality of sulfur. Attached Figure Description

[0011] Figure 1 This is a schematic diagram of the process flow of one embodiment of the present invention.

[0012] Explanation of reference numerals in the attached figures 1. Natural gas feed separator; 2. Blower; 3. Air compressor; 4. Primary preheater; 5. Primary direct oxidation reactor; 6. Primary sulfur condenser; 7. Secondary preheater; 8. Secondary direct oxidation reactor; 9. Secondary sulfur condenser; 10. Liquid sulfur buffer tank; 11. Gas-to-gas heat exchanger; 12. Hydrogenation preheater; 13. Hydrogenation reactor; 14. Primary hydrogenation cooler; 15. Electrolytic hydrogen production; 16. Secondary hydrogenation cooler; 17. Separator; 18-1, 18-2, hydrogen sulfide adsorbers; 19-1, 19-2, carbon dioxide adsorbers. Detailed Implementation

[0013] The endpoints and any values ​​of the ranges disclosed herein are not limited to the precise ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoint values ​​of the various ranges, the endpoint values ​​of the various ranges and individual point values, and individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed herein.

[0014] This invention provides a system for producing sulfur from sour natural gas. The system includes an oxidation unit connected in series via pipelines; a gas-liquid separation unit connected via a pipeline to the oxide outlet of the oxidation unit; a hydrogenation unit connected via a pipeline to the gas phase outlet of the gas-liquid separation unit; and a sulfur adsorption unit and / or a carbon adsorption unit connected via a pipeline to the hydrogenated stream outlet of the hydrogenation unit; wherein the hydrogenated stream outlet of the hydrogenation unit is connected via a pipeline to the sour natural gas feed inlet of the oxidation unit.

[0015] The system of this invention, through the series connection of an oxidation device, a gas-liquid separation device, a hydrogenation device, a sulfur removal device, and a carbon removal device, can ensure that the process can be carried out under constant pressure throughout the entire process, and has the characteristics of low energy consumption and simple process.

[0016] According to a preferred embodiment of the present invention, the oxidation device includes at least one oxidation unit, preferably two to six reaction units.

[0017] According to a preferred embodiment of the present invention, when there is more than one oxidation unit, a gas-liquid separation unit is provided between adjacent oxidation units. The outlet of the oxidation product of the previous oxidation unit is connected to the inlet of the gas-liquid separation unit, and the gas phase outlet of the gas-liquid separation unit is connected to the inlet of the next oxidation unit.

[0018] In this invention, each of the gas-liquid separation devices and / or gas-liquid separation units independently includes a condenser.

[0019] In this invention, the structure of the oxidation reaction device is a conventional choice in the art. For example, the oxidation reaction device can be a tubular reaction device, a horizontal reaction device, or a vertical reaction device.

[0020] In this invention, the carbon removal device is a conventional choice in the art; for example, a carbon dioxide adsorber can be used for carbon removal. The carbon dioxide adsorber is not limited to any particular combination; preferably, two carbon removal devices are connected in parallel and can be switched at any time, with the other being switched when one becomes saturated.

[0021] In this invention, the sulfur removal device is a conventional choice in the art; for example, a hydrogen sulfide adsorber can be used for sulfur removal. The hydrogen sulfide adsorber is not limited to any particular combination; preferably, two sulfur removal devices are connected in parallel and can be switched at any time, with the other being switched when one becomes saturated.

[0022] According to a preferred embodiment of the present invention, the system further includes a hydrogen supply device and an oxygen supply device, wherein the hydrogen outlet of the hydrogen supply device is connected to the hydrogen inlet of the hydrogenation device via a pipeline, and the oxidant outlet of the oxygen supply device is connected to the oxidant inlet of the oxidation device via a pipeline.

[0023] In this invention, there are no special requirements for the source of hydrogen in the hydrogen supply device; the concentration only needs to meet the requirements of hydrogenation of equivalent methanethiol and sulfides. Since natural gas purification plants generally do not supply hydrogen externally, and hydrogen consumption here is extremely low, it is recommended to purchase hydrogen externally or add PEM (parts-embedded hydrogen generator) to provide hydrogen.

[0024] In this invention, the oxidizing gas is an oxygen-containing gas, preferably a gas with an oxygen volume content of not less than 20%, such as air, pure oxygen, or a mixture of oxygen and an inert gas, preferably pure oxygen.

[0025] In this invention, a cooling device and a dehydration device are sequentially installed on the connecting pipeline between the hydrogenation device and the sulfur adsorption device and / or the carbon adsorption device. The cooling device and the dehydration device are conventional choices in the art, and may include, for example, a condenser and a separator. The number of condensers and separators is not limited. This invention uses two condensers and one separator as an example for illustration.

[0026] In this invention, the dehydrated stream outlet of the dehydration device is connected to the raw material inlet of the oxidation device via a pipeline.

[0027] In this invention, the liquid outlet of the gas-liquid separation device is connected to a sulfur collection device via a pipeline, and the sulfur collection device is also connected to the liquid phase outlet of the gas-liquid separation unit in the oxidation device. The sulfur collection device can be a conventional choice in the art, such as a liquid sulfur buffer tank.

[0028] In this invention, the system further includes a heat exchange unit and / or a heating unit, for example, a heating unit is provided before each oxidation reactor, and a heat exchange unit and / or a heating unit is provided before the hydrogenation unit. The heat exchange and / or heating methods are conventional choices in the art, such as gas-to-gas heat exchangers, electric heating, and steam heating.

[0029] According to a preferred embodiment of the present invention, the system further includes a pretreatment device, which is provided with outlets for a gas phase, a liquid phase, and a solid phase, wherein the gas phase outlet of the pretreatment device is connected to the raw material inlet of the oxidation device.

[0030] In this invention, as long as the purpose of this invention can be achieved, there are no special requirements for the type of pretreatment device, such as a separator.

[0031] In this invention, the system further includes a heat exchange unit and / or a heating unit. The heat exchange and / or heating methods are conventional choices in the art, such as gas-to-gas heat exchangers, electric heating, or steam heating.

[0032] This invention provides a method for preparing sulfur from sour natural gas. The method is carried out in the system described above and includes the following steps: S1. Mixing sour natural gas with oxidizing gas to form an oxide feedstock, which is then fed into an oxidation device to undergo an oxidation reaction, obtaining an oxidized stream; S2. Passing the oxidized stream into a gas-liquid separation device for condensation and gas-liquid separation, obtaining liquid sulfur and a gaseous stream. The gaseous stream is then hydrogenated, and the hydrogenated stream is divided into two streams; S3. One of the hydrogenated streams from step S2 is recycled back into the sour natural gas, while the other stream is sent to a sulfur adsorption device and / or a carbon adsorption device to remove hydrogen sulfide and / or carbon dioxide to obtain purified natural gas.

[0033] The method of the present invention is carried out in the system described above, which can ensure that the process is carried out under constant pressure throughout the entire process, and can directly obtain high-quality sulfur, thereby reducing the investment and operating costs of the system equipment, and has significant economic and social benefits.

[0034] In this invention, the hydrogenation includes hydrogenating non-hydrogen sulfide gas into hydrogen sulfide.

[0035] In this invention, the main oxidation reaction is the reaction of H2S with O2 to produce elemental sulfur, but it is also accompanied by side reactions such as the formation of thiols and sulfur dioxide.

[0036] According to a preferred embodiment of the present invention, based on the total mass of sour natural gas, the sour natural gas contains: 0.002-10% hydrogen sulfide; preferably, the sour natural gas further contains: 0-200 mg / m³ 3 COS, 0-2000mg / m 3 Thiols, 0-1500 mg / m 3 Sulfides.

[0037] According to a preferred embodiment of the present invention, the hydrogenation conditions include the use of a cobalt-based and / or molybdenum-based hydrogenation catalyst. The cobalt-based and / or molybdenum-based hydrogenation catalyst is a conventionally used catalyst in the art and will not be described in detail herein.

[0038] According to a preferred embodiment of the present invention, the hydrogenation conditions include a reaction pressure of 1-9 MPa, for example, 2 MPa, 3 MPa, 4 MPa, 5 MPa, 6 MPa, 7 MPa, and 8 MPa, preferably 4-7 MPa. By adopting the aforementioned preferred scheme, the quality of sulfur can be further improved.

[0039] According to a preferred embodiment of the present invention, the reaction temperature of the hydrogenation is 200-330°C, preferably 230-320°C.

[0040] In this invention, the gas hourly space velocity (GHSV) for hydrogenation is a conventional choice in the art, and the following description is exemplary but does not limit the scope of the invention. According to a preferred embodiment of the invention, the GHSV is 200-2000 h⁻¹. -1 Preferably 800-1200h -1 .

[0041] According to a preferred embodiment of the present invention, the conditions for the oxidation reaction include: using a titanium oxide-based and / or silicon oxide-based catalyst.

[0042] According to a preferred embodiment of the present invention, the oxidation reaction includes at least one primary oxidation reaction, wherein the primary oxidation reaction employs a titanium dioxide-based catalyst. By adopting the aforementioned preferred embodiment, the natural gas purification effect and the quality of sulfur can be further improved.

[0043] According to a preferred embodiment of the present invention, the TiO2 content in the titanium oxide-based catalyst is above 80% by mass, for example, it can be 83%, 85%, 88%, 92%, 95%, 97%, 99%, and 100%, preferably above 90%. By adopting the aforementioned preferred embodiment, the natural gas purification effect and the quality of sulfur can be further improved.

[0044] According to a preferred embodiment of the present invention, the pore size of the titanium oxide-based catalyst exhibits a bimodal distribution.

[0045] According to a preferred embodiment of the present invention, in the titanium oxide-based catalyst, the pore volume of pores with a diameter of 3-10 nm accounts for 25-35% of the total pore volume, the pore volume of pores with a diameter of 10-75 nm accounts for 40-55% of the total pore volume, and the pore volume of pores with a diameter >75 nm accounts for 20-25% of the total pore volume. By adopting the aforementioned preferred embodiment, the quality of sulfur can be further improved.

[0046] According to a preferred embodiment of the present invention, the total pore volume of the titanium oxide-based catalyst is 0.30-0.35 mL / g, and the specific surface area is 130-140 m². 2 / g. By adopting the aforementioned preferred scheme, the quality of sulfur can be further improved.

[0047] According to a preferred embodiment of the present invention, the oxidation reaction conditions include a reaction pressure of 1-9 MPa, for example, 2 MPa, 3 MPa, 4 MPa, 5 MPa, 6 MPa, 7 MPa, and 8 MPa, preferably 4-7 MPa. By adopting the aforementioned preferred scheme, the quality of sulfur can be further improved.

[0048] In this invention, as long as the purpose of this invention can be achieved, there are no special requirements for the reaction temperature of the oxidation reaction. The following is an illustrative description, but it does not limit the scope of this invention. According to a preferred embodiment of this invention, the reaction temperature is 200-340°C, preferably 230-330°C.

[0049] In this invention, the gas hourly space velocity (GHSV) for the oxidation reaction is a conventional choice in the art, as illustrated below, but not to limit the scope of the invention. According to a preferred embodiment of the invention, the GHSV is 200-2000 h⁻¹. -1 Preferably 800-1200h -1 .

[0050] In this invention, the temperature for condensation gas-liquid separation is 120-160℃.

[0051] According to a preferred embodiment of the present invention, in step S3, the volume of a hydrogenated stream accounts for 20%-60% of the total volume of the hydrogenated stream, preferably 30%-60%. By adopting the aforementioned preferred scheme, the quality of sulfur can be further improved.

[0052] To further improve the quality of sulfur, according to a preferred embodiment of the present invention, in step S3, the proportion of a hydrogenated stream in the acidic natural gas is 20%-50%, preferably 30%-40%.

[0053] The methods for removing sulfur and / or carbon are conventional techniques in the art. For example, hydrogen sulfide removal uses a carbonyl iron catalyst and / or activated carbon adsorbent; carbon dioxide removal uses a solid amine catalyst, which is prepared by chemical bonding using a weakly basic ion exchange resin as a support. The amine is preferably a secondary or primary amine. In this invention, the regeneration method of the adsorbent and / or adsorption catalyst is conventional in the art. For example, a saturated carbon dioxide adsorber is regenerated using an inert gas, preferably nitrogen, and the regeneration conditions include a regeneration temperature of 50-120°C, preferably 80-110°C.

[0054] In this invention, the conditions for desulfurization and decarbonization are each independently selected by the conventional methods, and will not be described in detail here. The desulfurization conditions in this invention include: an adsorption pressure of 1-9 MPa, preferably 4-7 MPa, an adsorption temperature of 30-60°C, and a space velocity of 200-2000 h⁻¹. -1 The conditions for carbon removal include: an adsorption pressure of 1-9 MPa, preferably 4-7 MPa, an adsorption temperature of 10-50℃, and a space velocity of 200-2000 h⁻¹. -1 .

[0055] like Figure 1 As shown, this invention provides a coupling scheme for two-stage oxidation, hydrogenation, recycling, and hydrogen sulfide and carbon dioxide adsorption: like Figure 1The apparatus shown includes: a natural gas feed separator 1, an oxygen source (i.e., a blower 2 and an air compressor 3), a primary direct oxidation reactor 5 connected to the outlets of the feed separator 1 and the air compressor 3 via pipelines, a preheater installed on the connecting pipelines, the outlet of the primary direct oxidation reactor 5 connected to a primary sulfur condenser 6 via a pipeline, the liquid phase outlet of the primary sulfur condenser 6 connected to a liquid sulfur buffer tank 10, and the gas phase outlet connected to the next stage, the secondary direct oxidation reactor 8 via a pipeline, a secondary preheater 7 installed on the connecting pipelines, the outlet of the secondary direct oxidation reactor 8 connected to a secondary sulfur condenser 9 via a pipeline, the liquid phase outlet of the secondary sulfur condenser 9 connected to the liquid sulfur buffer tank 10, and the gas phase outlet connected to a hydrogenation reactor 13 via a pipeline, with a gas-to-gas heat exchanger 11 and a hydrogenation preheater sequentially installed on the connecting pipelines. The device 12 is equipped with an electrolytic hydrogen production unit 15 in the hydrogen feed pipeline. After hydrogenation, the material outlet pipeline passes through the gas-to-gas heat exchanger 11 and is connected to the first-stage hydrolysis cooler 14 and the second-stage hydrolysis cooler 16 in sequence. After cooling by the second-stage hydrolysis cooler 16, the material outlet is connected to the separator 17 in a pipeline. The gas phase outlet of the separator is connected to the first-stage preheater 4, the second-stage preheater 7 and the hydrogen sulfide adsorber, respectively. The hydrogen sulfide adsorber includes hydrogen sulfide adsorber 18-1 and hydrogen sulfide adsorber 18-2, with one adsorber in standby mode. The outlets of hydrogen sulfide adsorber 18-1 and hydrogen sulfide adsorber 18-2 are connected to carbon dioxide adsorber 19-1 and carbon dioxide adsorber 19-2 in pipeline. The outlet of the carbon dioxide adsorber is connected to the purified natural gas storage tank (not shown) in pipeline.

[0056] like Figure 1The process shown includes: natural gas produced from the natural gas field is separated into liquid and solid phases by a feed separator 1, then mixed with oxidizing gas. After preheating by a primary preheater 4, the mixture is fed into a first oxidation reactor 5, where an oxidation reaction occurs. The oxidized material is then fed into a first condenser 6 for condensation, yielding a first liquid sulfur and a first gaseous stream. The first gaseous stream is preheated by a secondary preheater 7 and then fed into a second oxidation reactor 8, where an oxidation reaction occurs. The oxidized material is then fed into a second condenser 9 for condensation, yielding a second liquid sulfur and a second gaseous stream. The first and second liquid sulfur streams merge and enter a liquid sulfur buffer tank 10. The second gaseous stream passes through a heat exchanger... After preheating in the heat exchanger and hydrogenation preheater 12, the gas enters the hydrogenation reactor 13 for hydrogenation treatment (i.e., hydrogenating non-hydrogen sulfide gases such as methanethiol, dimethyl sulfide, and some COS into hydrogen sulfide). After hydrogenation, the gas stream is sent to the hydrogenation primary cooler 14, the hydrogenation secondary cooler 16, and the separator 17 for dehydration treatment. After removing the water, the gas stream is divided into two streams. One stream is recycled back to the first oxidation reactor 5 and / or the second oxidation reactor 8, and the other stream is sent to the hydrogen sulfide adsorber 18-1 or 18-2 and the carbon dioxide adsorber 19-1 or 19-2 to remove hydrogen sulfide and carbon dioxide in sequence, thus obtaining purified natural gas.

[0057] The present invention will be described in detail below through embodiments. In the following embodiments, The quality of natural gas is evaluated in accordance with GB17820-2018; The quality of sulfur was evaluated in accordance with GB / T 2449.2-2015; Unless otherwise specified, all raw materials are commercially available products, and "%" refers to mass content.

[0058] Example 1 Adopting such Figure 1 The system processes natural gas from a certain natural gas field. The wellhead pressure is 4.0 MPa, and the operating pressure is maintained at 4.0 MPa throughout the entire process. The main sulfide components in the natural gas are as follows: hydrogen sulfide content 2.6%, COS content 10 mg / m³. 3 Methanethiol 151 mg / m 3 Dimethyl sulfide 5mg / m 3The remaining CO2 and methane. The feedstock natural gas is introduced from the wellhead through a natural gas feed separator to remove carried liquid and solid particles. The filtered natural gas feedstock is mixed with oxidizing gas to form an oxide feedstock, heated to 200°C, and sent to an oxidation unit (two-stage oxidation reactor-gas-liquid separator) for oxidation reaction, obtaining an oxidized stream. This oxidized stream is then passed to a gas-liquid separator for condensation to 150°C, yielding liquid sulfur and a gaseous stream. The gaseous stream is then passed to a hydrogenation unit for hydrogenation, obtaining a hydrogenated stream. This hydrogenated stream is divided into two streams: one stream is recycled back to the sour natural gas, and the other stream is sequentially sent to a sulfur removal unit and a carbon removal unit to remove hydrogen sulfide and carbon dioxide, obtaining purified natural gas. Among these: The operating conditions of the hydrogenation unit include: hydrogen is purchased externally, the amount of hydrogen is the equivalent amount required for the hydrogenation reaction, a cobalt-molybdenum series hydrogenation catalyst is used, the catalyst support is a titanium-aluminum oxide composite support (titanium oxide accounts for 25% of the support mass), the active component has a molybdenum oxide content of 11% and a cobalt oxide content of 1.6%, the bed temperature is controlled at 300℃, and the space velocity is 800 h⁻¹. -1 ; The oxidation unit uses a vertical fixed-bed reactor; The operating conditions of the oxidation unit include: The first oxidation reactor uses a titanium oxide-based sulfur recovery catalyst with a titanium oxide content of 91%. The catalyst exhibits a bimodal pore size distribution: pores with a diameter of 3-10 nm account for 28% of the total pore volume, pores with a diameter of 10-75 nm account for 48%, and pores with a diameter >75 nm account for 24%. The total pore volume is 0.3 ml / g, and the specific surface area is 136 m². 2 / g. The hourly space velocity (HSV) is 2000 h⁻¹. -1 Control the bed temperature at 330℃; The second oxidation reactor uses a silica-based sulfur recovery catalyst, which uses nano-silica as a carrier material and has an active component, iron oxide, with a mass content of 5.6%. The gas hourly space velocity is 1200 h⁻¹. -1 The H2S feed concentration is 0.6%, and the bed temperature is controlled at 300℃.

[0059] The hydrogenated stream is divided into two streams, with the volume ratio of one hydrogenated stream to the other being 50%, and the hydrogenated stream accounting for 35% of the sour natural gas. The conditions for hydrogen sulfide removal include: using a carbonyl iron catalyst with an iron content of 20%, an adsorption temperature of 35℃, and a space velocity of 1000 h⁻¹. -1 ; The conditions for carbon dioxide removal included: using a solid amine catalyst, prepared via a chemical bonding method using a macroporous divinylbenzene-styrene crosslinked resin as a support; and employing diethylenetriamine as the amine type. The adsorption temperature was 38℃, and the space velocity was 1000 h⁻¹. -1 ; The carbon dioxide adsorber that has reached adsorption saturation is regenerated with nitrogen at a regeneration temperature of 120℃.

[0060] Evaluation of sulfur in purified natural gas and buffer tanks: Total sulfur in purified natural gas was 10 mg / m³. 3 Hydrogen sulfide 2 mg / m³ 3 The purified natural gas meets the Class I gas standard, and the sulfur content of the product is 99.98%, meeting the requirements for superior grade sulfur.

[0061] Example 2 Adopting such Figure 1 The system processes natural gas from a certain natural gas field. The wellhead pressure is 5.0 MPa, and the operating pressure is maintained at 5.0 MPa throughout the entire process. The main sulfide components in the natural gas are as follows: hydrogen sulfide content 1%, COS content 100 mg / m³. 3 Methanethiol 300mg / m 3 Dimethyl sulfide 20mg / m 3 The remaining components are CO2 and methane. The feedstock natural gas is introduced from the wellhead through a natural gas feed separator to remove carried liquid and solid particles. The filtered natural gas feedstock is mixed with oxidizing gas to form an oxide feedstock, heated to 210°C, and then fed into an oxidation unit (two-stage oxidation reactor-gas-liquid separator) to undergo an oxidation reaction, obtaining an oxidized post-gas stream. This post-gas stream is then passed into a gas-liquid separator for condensation to 145°C, yielding liquid sulfur and a gaseous stream. The gaseous stream is then fed into a hydrogenation unit for hydrogenation, obtaining a hydrogenated post-gas stream. This hydrogenated post-gas stream is divided into two streams: one stream is recycled back to the sour natural gas, and the other stream is sequentially sent to a sulfur removal unit and a carbon removal unit to remove hydrogen sulfide and carbon dioxide, obtaining purified natural gas. Among these: The operating conditions of the hydrogenation unit include: hydrogen is purchased externally; the amount of hydrogen is the equivalent amount required for the hydrogenation reaction; a cobalt-molybdenum series hydrogenation catalyst is used; the catalyst support is a titanium-aluminum oxide composite support (titanium oxide accounts for 25% of the support mass); the active components contain 12% molybdenum oxide and 1.9% cobalt oxide; the bed temperature is controlled at 320℃; and the space velocity is 1000 h⁻¹. -1 ; The oxidation unit uses a horizontal fixed-bed reactor; The operating conditions of the oxidation unit include: The first oxidation reactor uses a titanium oxide-based sulfur recovery catalyst, which is 90% titanium oxide by mass. The catalyst exhibits a bimodal pore size distribution: pores with a diameter of 3-10 nm account for 26% of the total pore volume, pores with a diameter of 10-75 nm account for 52%, and pores with a diameter >75 nm account for 22%. The total pore volume is 0.31 ml / g, and the specific surface area is 130 m². 2 / g. The hourly space velocity (HSV) is 1500 h⁻¹. -1 Control the bed temperature to 320℃; The second oxidation reactor uses a silica-based sulfur recovery catalyst, which uses nano-silica as a carrier material and has an active component, iron oxide, with a mass content of 5.6%. The gas hourly space velocity is 1000 h⁻¹. -1 The H2S feed concentration was 0.4%, and the bed temperature was controlled at 310℃.

[0062] The hydrogenated stream is divided into two streams, with one stream accounting for 60% of the total volume of the hydrogenated stream, and the other stream accounting for 30% of the sour natural gas. The conditions for hydrogen sulfide removal include: using an activated carbon catalyst, an adsorption temperature of 35℃, and a space velocity of 1000 h⁻¹. -1 ; The conditions for carbon dioxide removal included: using a solid amine catalyst, prepared via a chemical bonding method using a macroporous divinylbenzene-styrene crosslinked resin as a support; and employing diethylenetriamine as the amine type. The adsorption temperature was 45℃, and the space velocity was 900 h⁻¹. -1 ; The carbon dioxide adsorber that has reached adsorption saturation is regenerated with nitrogen at a regeneration temperature of 115℃.

[0063] Evaluation of sulfur in purified natural gas and buffer tanks: Total sulfur in purified natural gas was 8 mg / m³. 3 Hydrogen sulfide 2 mg / m³ 3 The purified natural gas meets the Class I gas standard, and the sulfur content of the product is 99.98%, meeting the requirements for superior grade sulfur.

[0064] Example 3 Adopting such Figure 1 The system processes natural gas from a certain natural gas field. The wellhead pressure is 5.0 MPa, and the operating pressure is maintained at 5.0 MPa throughout the entire process. The main sulfide components in the natural gas are as follows: hydrogen sulfide content 0.5%, COS content 200 mg / m³. 3 Methanethiol 150mg / m 3 Dimethyl sulfide 10mg / m 3The remaining components are CO2 and methane. The feedstock natural gas is introduced from the wellhead through a natural gas feed separator to remove carried liquid and solid particles. The filtered natural gas feedstock is mixed with oxidizing gas to form an oxide feedstock, heated to 220°C, and then fed into an oxidation unit (two-stage oxidation reactor-gas-liquid separator) to undergo an oxidation reaction, obtaining an oxidized post-gas stream. This post-gas stream is then passed into a gas-liquid separator for condensation to 152°C, yielding liquid sulfur and a gaseous stream. The gaseous stream is then fed into a hydrogenation unit for hydrogenation, obtaining a hydrogenated post-gas stream. This hydrogenated post-gas stream is divided into two streams: one stream is recycled back to the sour natural gas, and the other stream is sequentially sent to a sulfur removal unit and a carbon removal unit to remove hydrogen sulfide and carbon dioxide, obtaining purified natural gas. Among these: The operating conditions of the hydrogenation unit include: hydrogen is purchased externally; the amount of hydrogen is the equivalent amount required for the hydrogenation reaction; a cobalt-molybdenum series hydrogenation catalyst is used, with alumina as the catalyst support; the active components contain 11.8% molybdenum oxide and 1.7% cobalt oxide; the bed temperature is controlled at 320℃; and the space velocity is 800 h⁻¹. -1 ; The oxidation unit uses a vertical fixed-bed reactor; The operating conditions of the oxidation unit include: The first oxidation reactor uses a titanium oxide-based sulfur recovery catalyst with a titanium oxide content of 90.8%. The catalyst exhibits a bimodal pore size distribution: pores with a diameter of 3-10 nm account for 30% of the total pore volume, pores with a diameter of 10-75 nm account for 47%, and pores with a diameter >75 nm account for 23%. The total pore volume is 0.32 ml / g, and the specific surface area is 138 m². 2 / g. The hourly space velocity (HSV) is 1100 h⁻¹. -1 Control the bed temperature at 330℃; The second oxidation reactor uses a silica-based sulfur recovery catalyst, which uses nano-silica as a carrier material and has an active component, iron oxide, with a mass content of 6.2%. The gas hourly space velocity is 800 h⁻¹. -1 The H2S feed concentration is 0.1%, and the bed temperature is controlled at 330℃.

[0065] The hydrogenated stream is divided into two streams, with one stream accounting for 40% of the total volume of the hydrogenated stream, and the other stream accounting for 20% of the sour natural gas. The conditions for hydrogen sulfide removal include: using an activated carbon catalyst, an adsorption temperature of 42℃, and a space velocity of 800 h⁻¹. -1 ; The conditions for carbon dioxide removal included: using a solid amine catalyst, prepared via a chemical bonding method using a macroporous divinylbenzene-styrene crosslinked resin as a support; and employing diethylenetriamine as the amine type. The adsorption temperature was 38℃, and the space velocity was 1000 h⁻¹. -1; The carbon dioxide adsorber that has reached adsorption saturation is regenerated with nitrogen at a regeneration temperature of 120℃.

[0066] Evaluation of sulfur in purified natural gas and buffer tanks: Total sulfur in purified natural gas was 12 mg / m³. 3 Hydrogen sulfide 2 mg / m³ 3 The purified natural gas meets the Class I gas standard, and the sulfur content of the product is 99.98%, meeting the requirements for superior grade sulfur.

[0067] Example 4 Similar to Example 1, except that the hydrogenated stream is divided into two streams, with the volume ratio of one hydrogenated stream to the other being 70%, and the hydrogenated stream accounting for 40% of the sour natural gas; Evaluation of sulfur in purified natural gas and buffer tanks: Total sulfur in purified natural gas was 16 mg / m³. 3 Hydrogen sulfide 3 mg / m³ 3 The purified natural gas meets the Class I gas standard, and the sulfur content of the product is 99.98%.

[0068] Example 5 Similar to Example 1, except that the hydrogenated stream is divided into two streams, with the volume ratio of one hydrogenated stream to the other being 30%, and the hydrogenated stream accounting for 22% of the sour natural gas; Evaluation of sulfur in purified natural gas and buffer tanks: Total sulfur in purified natural gas was 18 mg / m³. 3 Hydrogen sulfide 4 mg / m³ 3 The purified natural gas meets the Class I gas standard, and the sulfur content of the product is 99.98%.

[0069] Example 6 Similar to Example 1, except that the titanium-based catalyst has a titanium oxide content of 85%.

[0070] Evaluation of sulfur in purified natural gas and buffer tanks: Total sulfur in purified natural gas was 18 mg / m³. 3 Hydrogen sulfide 5 mg / m³ 3 The product has a sulfur content of 99.98%.

[0071] Example 7 Similar to Example 1, the difference is that the pore structure of the titanium oxide-based sulfur recovery catalyst is not a bimodal structure, and the pore volume of pores with a diameter >10 nm accounts for 90% of the total pore volume.

[0072] Evaluation of sulfur in purified natural gas and buffer tanks: Total sulfur in purified natural gas was 20 mg / m³. 3 Hydrogen sulfide 5 mg / m³ 3 The product has a sulfur content of 99.98%.

[0073] Example 8 Similar to Example 1, except that the catalyst used in the first oxidation reactor is the same as that used in the second oxidation reactor.

[0074] Evaluation of sulfur in purified natural gas and buffer tanks: Total sulfur in purified natural gas was 20 mg / m³. 3 Hydrogen sulfide 6 mg / m³ 3 The product has a sulfur content of 99.98%.

[0075] Comparative Example 1 Similar to Example 1, except that hydrogenation was not performed in a hydrogenation unit, and the sulfur in the purified natural gas and buffer tank was evaluated: the total sulfur in the purified natural gas was approximately 200 mg / m³. 3 Hydrogen sulfide 5 mg / m³ 3 The purified natural gas cannot meet the Class I gas standard, and the sulfur content of the product is 99.98%.

[0076] The preferred embodiments of the present invention have been described in detail above; however, the present invention is not limited thereto. Within the scope of the inventive concept, various simple modifications can be made to the technical solutions of the present invention, including combinations of various technical features in any other suitable manner. These simple modifications and combinations should also be considered as the content disclosed in the present invention and are all within the protection scope of the present invention.

Claims

1. A system for preparing sulfur from acidic natural gas, characterized in that, The system includes an oxidation device; and A gas-liquid separation device connected to the oxide outlet of the oxidation device via a pipeline; A hydrogenation unit connected to the gas phase outlet of the gas-liquid separation device via a pipeline; A sulfur adsorption unit and / or a carbon adsorption unit connected via a pipeline to the hydrogenated stream outlet of the hydrogenation unit. The hydrogenated stream outlet of the hydrogenation unit is connected to the acidic natural gas feed inlet of the oxidation unit via a pipeline.

2. The system according to claim 1, wherein, The oxidation device includes at least one oxidation unit, preferably two to six reaction units; preferably, When there is more than one oxidation unit, a gas-liquid separation unit is provided between adjacent oxidation units. The outlet of the oxidation product of the previous oxidation unit is connected to the inlet of the gas-liquid separation unit, and the gas phase outlet of the gas-liquid separation unit is connected to the inlet of the next oxidation unit.

3. The system according to claim 1 or 2, wherein, The system further includes a hydrogen supply device and an oxygen supply device. The hydrogen outlet of the hydrogen supply device is connected to the hydrogen inlet of the hydrogenation device via a pipeline, and the oxidation outlet of the oxygen supply device is connected to the oxidation inlet of the oxidation device via a pipeline; and / or A cooling device and a dehydration device are sequentially installed on the connecting pipeline between the hydrogenation device and the sulfur adsorption device and / or the carbon adsorption device; preferably, the dehydrated stream outlet of the dehydration device is connected to the raw material inlet of the oxidation device through a pipeline. and / or The liquid outlet of the gas-liquid separator is connected via a pipeline to a sulfur collection device; and / or The system also includes a heat exchange unit and / or a heating unit.

4. The system according to any one of claims 1-3, wherein, The system also includes a pretreatment device, which has outlets for gas, liquid and solid phases respectively. The gas outlet of the pretreatment device is connected to the raw material inlet of the oxidation device.

5. A method for preparing sulfur from acidic natural gas, characterized in that, The method is performed in the system described in any one of claims 1-4, and includes the following steps: S1. Acidic natural gas and oxidizing gas are mixed to form an oxide feedstock, which is then fed into an oxidation unit to undergo an oxidation reaction, yielding an oxidized feedstock. S2. The oxidized stream is fed into a gas-liquid separator for condensation and gas-liquid separation to obtain liquid sulfur and gas stream. The gas stream is hydrogenated and then split into two streams. S3. One stream of hydrogenated gas from step S2 is recycled back into the sour natural gas, while the other stream is sent to a sulfur adsorption unit and / or a carbon adsorption unit to remove hydrogen sulfide and / or carbon dioxide to obtain purified natural gas.

6. The method according to claim 5, wherein, Based on the total mass of the sour natural gas, the sour natural gas contains: 0.002-10% hydrogen sulfide; preferably. The sour natural gas also contains: 0-200 mg / m³ 3 COS, 0-2000mg / m 3 Thiols, 0-1500 mg / m 3 Sulfides.

7. The method according to claim 5 or 6, wherein, The conditions for hydrogenation include: Cobalt-based and / or molybdenum-based hydrogenation catalysts are used; and / or The reaction pressure is 1-9 MPa, preferably 4-7 MPa; and / or The reaction temperature is 200-330℃, preferably 230-320℃; and / or air space velocity 200-2000 h -1 Preferably 800-1200h -1 .

8. The method according to any one of claims 5-7, wherein, The conditions for the oxidation reaction include: The catalyst used is a titanium dioxide-based catalyst and / or a silicon dioxide-based catalyst; preferably, The oxidation reaction includes at least one first-stage oxidation reaction, wherein the first-stage oxidation reaction employs a titanium dioxide-based catalyst; and / or The titanium dioxide-based catalyst contains more than 80% TiO2 by weight, preferably more than 90%; and / or The titanium oxide-based catalyst exhibits a bimodal pore size distribution; more preferably, pores with a diameter of 3-10 nm account for 25-35% of the total pore volume, pores with a diameter of 10-75 nm account for 40-55% of the total pore volume, and pores with a diameter >75 nm account for 20-25% of the total pore volume; and / or The total pore volume of the titanium oxide-based catalyst is 0.30-0.35 mL / g, and the specific surface area is 130-140 m². 2 / g; and / or The reaction pressure is 1-9 MPa, preferably 4-7 MPa; and / or The reaction temperature is 200-340℃, preferably 230-330℃; and / or air space velocity 200-2000 h -1 Preferably 800-1200h -1 .

9. The method according to any one of claims 5-8, wherein, The temperature for condensation and liquid separation is 120-160℃.

10. The method according to any one of claims 5-9, wherein, In step S3, the volume of the hydrogenated stream accounts for 20%-60% of the total volume of the hydrogenated stream; and / or The proportion of hydrogenated stream in sour natural gas is 20%-50%, preferably 30%-40%.

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