JP2002265964A - Process for removal of sulfur compound from natural gas - Google Patents

Abstract

PROBLEM TO BE SOLVED: To provide a process at a low cost and by a simple process flow, for removing all sulfur compounds to a high degree from a natural gas containing carbon dioxide, and hydrogen sulfide along with mercaptan and the other sulfur compounds. SOLUTION: This process is a process for refining a natural gas containing as impurities, at least hydrogen sulfide, carbon dioxide and mercaptan comprises a reaction process of converting the mercaptan contained in the natural gas into hydrogen sulfide, an absorption process of separating and removing hydrogen sulfide and carbon dioxide contained in the natural gas after the above reaction process by the chemical absorption process using an amine aqueous solution, and a collection processes of collecting sulfur from the hydrogen sulfide isolated by the above absorption process, and a characterized in that the reaction process is carried out by injecting steam or water to the natural gas at a radio of 0.1-5 mol.% thereto in the presence of a catalyst under a condition of a temperature of 260-350 deg.C and a pressure of 4-10 MPa.

Description

DETAILED DESCRIPTION OF THE INVENTION

[0001]

[0001] The present invention relates to a method for removing sulfur compounds from natural gas. Natural gas is a combustible gas mainly composed of hydrocarbons produced from underground gas fields.In addition to hydrogen and light hydrocarbons such as methane, propane, and butane, ordinary gas such as hydrogen sulfide and carbon dioxide are also used. Ingredients include sulfur compounds other than hydrogen sulfide such as mercaptan, BTX (generic term for benzene, toluene and xylene) and other heavy hydrocarbons, as well as oxygen and nitrogen. As they occur, their removal is strongly demanded from an environmental point of view.

[0002]

2. Description of the Related Art Sulfur compounds and carbon dioxide gas contained as impurities in natural gas are all acidic gases, and removal of such acidic gases when purifying natural gas has been generally performed. That is, liquefied and LNG
In general, it is necessary to reduce carbon dioxide gas to 50 ppm or less (volume ratio, the same applies hereinafter), hydrogen sulfide to 4 ppm or less, and the sulfur compound as a whole to 30 mg-S / Nm ³ or less. When used as a line gas, carbon dioxide is about 1% (volume ratio), and sulfur compounds such as hydrogen sulfide and mercaptan are removed to the same level as LNG.

[0003] As a method for removing acidic gas from natural gas, there are mainly a chemical absorption method and a physical absorption method, and an adsorption method using an adsorbent such as molecular sieve. The chemical absorption method is a method in which acidic gas is absorbed into an amine-based or carbonate-based alkaline aqueous solution. However, for natural gas purification, optimization of the system (circulation amount, number of stages, regeneration heat, etc.) is possible and low Because the cost can be reduced,
Generally, an amine process is used. However, mercaptans are weakly polar and have a weak bond with amines.
It is difficult to remove by such a chemical absorption method. Therefore, it is generally inappropriate to use the chemical absorption method alone for treating natural gas whose mercaptan content is not negligible. On the other hand, the physical absorption method is a method using an organic solvent that absorbs an acid gas component according to its partial pressure, and can remove not only carbon dioxide gas and hydrogen sulfide but also mercaptan and other sulfur compounds at the same time. However, the physical absorption method is disadvantageous in that the amount of circulating absorption liquid and the number of stages are increased in terms of chemical equilibrium and kinetics compared with the chemical absorption method. In contrast to the wet desulfurization method described above, the adsorption method is a dry desulfurization method that does not use a liquid.If the gas flows through a fixed bed filled with an adsorbent, the acid gas concentration at the outlet side can be extremely low. Although there is an advantage that it can be performed, when a large amount of natural gas containing a relatively high concentration of acidic gas is treated, the amount of the adsorbent to be charged increases and the frequency of regeneration of the adsorbent increases, which is not economical.

The sulfinol method using a mixture of sulfolane and diisopropanolamine as an absorbing solution is a combined type of chemical absorption and physical absorption, and efficiently removes hydrogen sulfide and mercaptan in natural gas when the content is large. As a possible method, it has been often used for absorbing and removing acidic gas from natural gas. FIG. 1 shows a basic flow of a process using the sulfinol method. The acidic gas contained in the natural gas is absorbed in the absorbing solution according to the sulfinol method in the acidic gas absorbing device 11, and then separated from the solution by heating the absorbing solution. The separated acid gas is led to a sulfur recovery device 12, where hydrogen sulfide is recovered as sulfur by the Claus method. However, in the sulfinol method, due to the nature of the absorbing solution, heavy hydrocarbons including BTX are simultaneously absorbed together with the acid gas, and in the sulfur recovery unit, a large amount of carbon dioxide gas and heavy hydrocarbons accompany hydrogen sulfide. Therefore, the sulfur recovery rate is at most 9 unless tail gas treatment (TGT) is performed.
It is about 5%.

As described above, in the sulfinol method, hydrogen sulfide, carbon dioxide, mercaptan and heavy hydrocarbons (hereinafter, also referred to as BTX) are simultaneously removed, and any of these is contained in the separated acid gas. Therefore, even if this is directly treated by the Claus method, the recovery rate of sulfur does not increase. For this reason, the separated acidic gas is treated by a hydrogen sulfide concentrator before being treated by the Claus method,
A process has been proposed in which carbon dioxide, mercaptan, and heavy hydrocarbons are separated and removed in advance (JP-A-9-255).
974). FIG. 2 shows the process flow. First, the natural gas containing the acid gas is led to the acid gas absorption device 21 based on the sulfinol method, and impurities such as hydrogen sulfide, carbon dioxide, mercaptan, and heavy hydrocarbons are separated from the natural gas. Next, the separated impurities are led to a hydrogen sulfide concentrating device (enrichment unit) 22 using alkanolamine, and are separated into a gas in which hydrogen sulfide is concentrated and an off-gas containing carbon dioxide, mercaptan, or heavy hydrocarbon. . The hydrogen sulfide concentrated gas is directly guided to the sulfur recovery device 23, where sulfur is recovered by the Claus method. On the other hand, off-gas containing mercaptan, carbon dioxide, and heavy hydrocarbons is led to the hydrotreating unit 24, where mercaptan is converted to hydrogen sulfide and then led to the sulfur recovery unit 23. According to this method, the sulfur recovery rate is 95 to 98%.
Then, if TGT is further performed, the sulfur recovery rate reaches about 99%.

[0006]

SUMMARY OF THE INVENTION As mentioned above,
When purifying natural gas containing mercaptan together with hydrogen sulfide and carbon dioxide gas, these acid gases were conventionally absorbed by the sulfinol method.However, in this case, any of hydrogen sulfide, carbon dioxide gas, mercaptan and heavy hydrocarbons was used. In order to increase the recovery rate of sulfur, it is necessary to further separate mercaptan from the separated gas and separately consider sulfur recovery from the separated gas. In addition, since the sulfinol method is a complex type of physical absorption and chemical absorption and also has the aspect of physical absorption, it is said that the cost is higher in terms of the circulation amount of the absorbing solution and the number of absorption tower stages than the simple chemical absorption method. There are difficulties.

On the other hand, when a chemical absorption method such as an amine process is used, mercaptan and heavy hydrocarbons are not absorbed in the absorbing solution, and an acidic gas consisting essentially of hydrogen sulfide and carbon dioxide is separated. From the separated acid gas, sulfur can be recovered to a certain degree with high efficiency by the Claus method. However, since mercaptan is included in refined natural gas, the problem that sulfur dioxide gas is discharged or the sulfur recovery rate does not increase unless this is removed and recovered cannot be solved. It is conceivable that the purified natural gas containing mercaptan is treated again by a physical absorption method or an adsorption method using a molecular sieve, but this still does not solve the problem of high cost.

In view of the above, the present invention provides a method for producing mercaptan by a low-cost and simple process flow without using a physical absorption method or an adsorption method, which requires a large amount of an absorbing solution or a molecular sieve. An object of the present invention is to provide a method for removing a sulfur compound from natural gas containing the same.

[0009]

SUMMARY OF THE INVENTION The present invention is a method for purifying natural gas containing at least hydrogen sulfide, carbon dioxide and mercaptan as impurities, comprising a reaction step of converting mercaptan in natural gas into hydrogen sulfide. An absorption step of separating and removing hydrogen sulfide and carbon dioxide gas contained in the natural gas after the reaction step by a chemical absorption method using an aqueous amine solution, and a recovery step of recovering sulfur from the hydrogen sulfide separated by the absorption step. Wherein the reaction step comprises adding steam or water to natural gas in the presence of a catalyst at a temperature of 260 to 350 ° C. and a pressure of 4 to 10 MPa.
A method characterized by being performed by injecting at a rate of 5 mol% is provided, thereby solving the above problem.

In the present invention, it is preferable to use a catalyst in which cobalt and molybdenum are supported on an alumina carrier (CoMox reaction catalyst) as the catalyst in the reaction step. Further, the absorption step is divided into a step of mainly absorbing hydrogen sulfide and a step of mainly absorbing carbon dioxide gas, and the recovery step mainly includes a step of absorbing a hydrogen sulfide-rich amine solution obtained from the step of absorbing hydrogen sulfide. It is preferable to recover sulfur from hydrogen sulfide obtained by regeneration. Further, heat exchange may be performed between the natural gas stream to be subjected to the reaction step and the natural gas stream after the reaction step, or the natural gas stream to be subjected to the reaction step after the heat exchange may be disposed of by a gas turbine. It is also preferable to carry out reheat exchange with a heater heated by heat.

[0011]

DESCRIPTION OF THE PREFERRED EMBODIMENTS The present invention will be described below based on embodiments of the present invention shown in the accompanying drawings. It is to be noted that what is shown in the accompanying drawings is a preferred mode for carrying out the present invention, and it goes without saying that the present invention is not limited to these embodiments.

FIG. 3 shows that natural gas produced from a natural gas field is purified in accordance with the present invention and is subject to pipeline gas or L
The basic process flow up to the production of NG is shown.
The natural gas produced from the natural gas field 1 first separates and removes liquid components such as water and condensate (liquid hydrocarbons having a relatively small number of carbon atoms) in the ordinary production facility 2 to obtain only gas components. The natural gas which has been converted into the gaseous component alone is then led to a mercaptan converter 3 in which mercaptan contained as impurities is converted to hydrogen sulfide by a reaction using a catalyst and steam or water (hereinafter collectively referred to as H2O). I do. The natural gas after the reaction contains hydrogen sulfide and carbon dioxide gas, and these acidic gases are separated and removed by the following acidic gas absorbing device 4. The purified natural gas from which the acidic gas has been removed is sent to a pipeline facility or a liquefaction facility 5 to be a pipeline gas or LNG. On the other hand, hydrogen sulfide and carbon dioxide gas separated by the acid gas absorption device
The sulfur is recovered from the hydrogen sulfide by treating with the Claus method in the sulfur recovery device 6.

In the reaction step of the present invention, the conversion of mercaptan to hydrogen sulfide is performed on the crude natural gas from which only the liquid component has been removed. This reaction is different from ordinary hydrogenation-reduction reaction in that it does not require a reducing agent such as carbon monoxide or hydrogen. That is, in this reaction, by the action of carbon dioxide in natural gas and newly added H2O, mercaptan is finally converted into alkanes and hydrogen sulfide in the presence of a catalyst. This reaction is a complicated parallel reaction, and the details of individual elementary reactions are not well understood.For example, assuming that methyl mercaptan is converted to hydrogen sulfide, the methyl mercaptan molecule is thermally decomposed at a high temperature to form a methyl radical. They produce mercapto radicals, which react with water molecules or react with each other to produce hydrogen sulfide and various intermediate products.These intermediate products are further hydrolyzed by the action of a catalyst to form hydrogen sulfide and carbon It is thought that it may generate hydrogen, carbon monoxide, carbon dioxide, and the like. In addition, in the case of the conversion reaction of methyl mercaptan, it is considered that the following reaction occurs as a whole in view of the material balance before and after the reaction. _{5CH 3 SH + 4H 2 O ---} > 5H 2 S + 2CH 4 +5
H ₂ + 2CO + CO _{2 In the} mercaptan conversion reaction in the present invention, sulfur compounds other than hydrogen sulfide / mercaptan, for example, carbonyl sulfide (COS), carbon disulfide, or thiophenes are also reduced to hydrogen sulfide.

The above mercaptan conversion reaction can be carried out in the presence of a known catalyst. Such catalysts include, for example, porous inorganic oxide carriers (alumina, silica, titania, boria, zirconia, silica-alumina, silica-magnesia, alumina-magnesia, alumina-titania, silica-titania, alumina-boria, Alumina-zirconia, etc.), Group V of the periodic table,
A material carrying an active metal selected from metals belonging to Group VI or Group VII (for example, vanadium, chromium, molybdenum, tungsten, cobalt, nickel, etc.) can be used. In particular, a catalyst in which cobalt and molybdenum are supported on an alumina carrier (CoMox reaction catalyst) is preferable because of its excellent catalytic activity and life. It is preferable to form a fluidized bed by packing the catalyst in granular form in the tower and flowing a natural gas stream upward from the bottom of the tower to prevent local heating due to the exothermic reaction, but it should be treated. Depending on the properties of natural gas, a fixed bed, an expanded bed, or a reactor filled with a molded catalyst may be used.

The mercaptan conversion reaction is carried out at a temperature of 260
H2O under the condition of ~ 350 ° C and pressure of 4 ~ 10MPa.
By injecting 0.1 to 5 mol% with respect to natural gas. If the reaction temperature is lower than 260 ° C., the conversion of mercaptan and the selectivity to hydrogen sulfide decrease, and if the reaction temperature is higher than 350 ° C., the reaction proceeds excessively and the catalyst deteriorates quickly. On the other hand, if the pressure is lower than 4 MPa, a practical reaction rate cannot be obtained, and even if the pressure is raised above 10 MPa, the reaction rate and the conversion are not improved. H2O required for reaction
Depends on the amount of mercaptan (and other sulfur compounds other than hydrogen sulfide) contained in natural gas, but the reaction does not proceed sufficiently unless at least 0.1 mol% is added to natural gas, Further, if the amount is more than 5 mol%, the energy required for heating increases, which is generally not preferable. The natural gas flow rate per catalyst unit charge is 1500
It may be about 2500 m ³ / m ³ .

Since the above reaction step is performed at 260 to 350 ° C. and the subsequent absorption step is performed at room temperature, heat exchange is performed between the stream before heating to be supplied to the reaction step and the stream after the reaction step. Preferably. Thereby, the load on the heating furnace and the cooler can be reduced. FIG. 4 shows the process flow of the reaction step of the present invention incorporating such heat exchange. Since the crude natural gas has been dehydrated by ordinary production equipment, the required amount of boiler feedwater (BFW) is again supplied to the natural gas stream before heating. The H2O added natural gas stream is passed through a gas / gas heat exchanger 41 to
The reactor 43 is heated to about 0 ° C. and then heated to 250 to 300 ° C. by a heater 42 utilizing low-temperature waste gas.
to go into. In the reactor, the temperature was further increased by 10 due to the exothermic reaction.
５０50 ° C. and the temperature required for the reaction
° C. The natural gas stream leaving the reactor is heat recovered in the gas / gas heat exchanger and cooled to 60-70 ° C,
Further, the water is cooled to a normal temperature by the cooler 44, and water condensed in the cooling process is separated and removed by the separation drum 45, and then sent to the absorption step. In addition, since many natural gases contain heavy hydrocarbons, if the surface temperature of the heating tube of the heater is too high, carbon deposition may occur. It is important not to make them too large. Therefore, it is preferable to provide a gas / gas heat exchanger in front of the heater, and as described above, using a heater that heats with low-temperature waste gas can prevent local heating of the heating tube. This is convenient because it can be done. As such low-temperature waste gas, waste heat from a gas turbine for driving a refrigeration compressor can be used. In particular, by using low-temperature waste gas of about 500 ° C. as a heating medium, thermal decomposition of heavy hydrocarbons present in natural gas can be effectively suppressed.

In the absorption step of the present invention, an acidic gas contained in natural gas is absorbed and removed in an absorption tower using an amine aqueous solution. Since mercaptans (and other organic sulfur compounds) have already been converted to hydrogen sulfide in the preceding reaction step, the acidic gases absorbed and removed here are almost only hydrogen sulfide and carbon dioxide gas. Hydrogen sulfide and carbon dioxide gas can be simultaneously absorbed in the amine aqueous solution, but then they will be released at the same time when the absorbent is regenerated, and the amount of gas to be processed by the sulfur recovery device will increase,
It is preferable to adjust the absorption conditions to absorb hydrogen sulfide and carbon dioxide gas sequentially and stepwise. The adjustment of the absorption conditions is performed by appropriately adjusting the type of amine used and the concentration of the amine aqueous solution according to the ratio of hydrogen sulfide / carbon dioxide gas in natural gas. The absorption tower may be divided into a hydrogen sulfide absorption section and a carbon dioxide absorption section using the same type and the same concentration of amine aqueous solution, or a plurality of absorption towers using amine aqueous solutions having different types or concentrations of amines may be used. Is also good. FIG.
Shows an example of a process flow when such sequential absorption is performed. First, natural gas is supplied to the lower part 5 of the amine absorption tower 51.
At 1a, it comes in countercurrent contact with lean amine at room temperature (aqueous amine solution that does not absorb much acidic gas), where hydrogen sulfide is selectively absorbed and the target concentration value (usually 4 ppm)
Below). Subsequently, the natural gas similarly comes into countercurrent contact with the lean amine at room temperature in the upper part 51b of the absorption tower, where the carbon dioxide gas which was hardly absorbed in the lower part of the absorption tower is mainly absorbed and the target concentration value (in the case of LNG, 50 ppm or less). The rich amine which has absorbed hydrogen sulfide at the lower part of the absorption tower (amine aqueous solution which has considerably absorbed acidic gas) is supplied to the lean / rich amine heat exchanger 52.
After passing through a and heated, it enters the amine regeneration tower 53.
On the other hand, the rich amine that has mainly absorbed carbon dioxide in the upper part of the absorption tower is heated after passing through the lean / rich amine heat exchanger 52b, and then enters the amine flash drum 54, where the carbon dioxide is released by low-pressure flash. After being converted into a semi-rich amine, the amine is combined with the rich amine coming from the lower part of the absorption tower by the amine intermediate pump 55 and sent to the amine regeneration tower. The amine aqueous solution at the bottom of the amine regeneration tower is circulated to the adjacent amine reboiler 56 and heated by steam or the like. In addition, the gas containing amine vapor and hydrogen sulfide emitted from the top of the amine regeneration tower is supplied to the amine condenser 5
7 and is cooled by exchanging heat with cooling water or the like, where most of the amine vapor condenses and reflux drum 5
It accumulates at 8 and is returned to the top of the amine regeneration tower by the reflux pump 59. On the other hand, the hydrogen sulfide remains in the gas and is sent to the sulfur recovery step as a hydrogen sulfide-rich gas. The amine aqueous solution at the lower part of the amine regeneration tower is a lean amine that has almost released the absorbed acid gas, and the amine supply pump 60
Allows the lean / rich amine heat exchangers 52a and 52
After cooling to room temperature in 2b, it is sent to the lower part and upper part of the absorption tower.

As the absorption liquid used in the absorption step, aqueous solutions of various amines generally used in a chemical absorption method can be used. Representative amines that can be used include:
Examples include diisopropanolamine (DIPA), methyldimethanolamine (MDEA), sterically hindered amines, activated MDEA, and the like. Compared to monoethanolamine (MEA) or diethanolamine (DEA), which has been generally used in the past, DIPA and MDEA have a higher selective absorption of hydrogen sulfide. Is preferably used. The amine concentration of the absorbing solution is set to about 4 mol as a standard, and adjusted according to the concentration of various acidic gases in natural gas.

In the recovery step of the present invention, sulfur is recovered from hydrogen sulfide. A typical process for recovering sulfur from hydrogen sulfide is the Claus method, which can be preferably used in the present invention. The Klaus method, in its original form, produces sulfur by reacting sulfur dioxide gas generated by burning part of hydrogen sulfide in a reaction furnace with the remaining hydrogen sulfide, but the raw material gas contains When the concentration of hydrogen sulfide is low, stable combustion cannot be maintained in the reaction furnace, and various improvement methods have been devised to perform stable treatment even in such a case. In the recovery step of the present invention, various Claus methods including those improved methods can be appropriately selected and adopted. However, in the present invention, since the conversion and chemical absorption of the mercaptan are performed in the former stage, the gas supplied to the recovery step has a simple composition consisting essentially of only hydrogen sulfide and a small amount of carbon dioxide gas. Because there are few problematic elements, there is little need to dare to adopt complex improvements. In particular, when hydrogen sulfide and carbon dioxide gas are sequentially absorbed in the former absorption step, and the absorbed carbon dioxide gas is separately diffused to use a gas enriched with hydrogen sulfide as a raw material gas in the recovery step,
Because the simplest full feed method can be adopted,
It is very advantageous in terms of cost.

The gas from which hydrogen sulfide has been removed by the Claus method is released as tail gas. The recovery rate of sulfur by the Claus method is about 95 to 99%, and the unrecoverable sulfur content is included in the tail gas.
If it is desired to be 9% or more, it is preferable to perform tail gas treatment (TGT) typified by the SCOT process or the like. However, in the method of the present invention, a sulfur recovery of 98% or more can be obtained without using TGT, and the adoption of TGT is not essential. Therefore, a simple and low-cost process can be realized. The SCOT process reduces all sulfur (other than sulfur dioxide and carrier sulfur, but also COS and carbon disulfide) in the tail gas from the sulfur recovery unit to hydrogen sulfide, and cools it. After removing condensed water, hydrogen sulfide in the gas is removed by a chemical absorption method. As the chemical absorption device used here, the one used in the absorption step of the present invention may be commonly used. Of course, the process used as the TGT is not necessarily limited to the SCOT process, and another process such as a Beavon process may be employed.

[0021]

EXAMPLES Tables 1 and 2 below show examples of typical material balances in the reaction step shown in FIG. 4 and the absorption step shown in FIG. 5, respectively.

[Table 1]

[Table 2]

[Brief description of the drawings]

FIG. 1 shows an example of a conventional process flow for removing acid gas from natural gas.

FIG. 2 shows another example of a conventional process flow for removing acid gas from natural gas.

FIG. 3 shows a representative example of a process flow for implementing the method of the present invention.

FIG. 4 shows a preferred process flow of a reaction step in the method of the present invention.

FIG. 5 shows a preferred process flow of the absorption step in the method of the present invention.

[Explanation of symbols]

 DESCRIPTION OF SYMBOLS 1 Natural gas field 2 Normal production equipment 3 Mercaptan conversion equipment 4 Acid gas absorption equipment 5 Pipeline equipment or liquefaction equipment 6 Sulfur recovery equipment 11 Acid gas absorption equipment 12 Sulfur recovery equipment 21 Acid gas absorption equipment 22 Hydrogen sulfide concentrator 23 Sulfur recovery Apparatus 24 Hydrotreating apparatus 41 Gas / gas heat exchanger 42 Heater 43 Reactor 44 Cooler 45 Separation drum 51 Amine absorption tower 51a Absorption tower upper part 51b Absorption tower lower 52a Lean / rich amine heat exchanger 52b Lean / rich amine Heat exchanger 53 Amine regeneration tower 54 Amine flash drum 55 Amine intermediate pump 56 Amine reboiler 57 Amine condenser 58 Reflux drum 59 Reflux pump 60 Amine supply pump

──────────────────────────────────────────────────続 き Continued on the front page (51) Int.Cl. ⁷ Identification symbol FI Theme coat ゛ (Reference) C01B 17/16 ZAB C10L 3/00 B (72) Inventor Tadashi Matsumoto 2- Tsurumichuo, Tsurumi-ku, Yokohama-shi, Kanagawa-ken 12-1 Inside Chiyoda Kako Construction Co., Ltd. (72) Inventor Etsuro Sato 2-2-1 Tsurumi Chuo, Tsurumi-ku, Yokohama, Kanagawa Prefecture Inside (72) Inventor Takeshi Nozawa Tsurumi, Tsurumi-ku, Yokohama, Kanagawa Prefecture Central 2-12-1 Chiyoda Chemical Works, Ltd. F-term (reference) 4D020 AA03 AA04 BA16 BB03 BC01 CB18 CC09 DA01 DB03

Claims (6)

[Claims] 1. A method for purifying natural gas containing at least hydrogen sulfide, carbon dioxide gas and mercaptan as impurities, comprising: a reaction step of converting mercaptan in natural gas to hydrogen sulfide; and a natural gas after the reaction step. An absorption step of separating and removing contained hydrogen sulfide and carbon dioxide gas by a chemical absorption method using an amine aqueous solution; and a recovery step of recovering sulfur from the hydrogen sulfide separated by the absorption step, wherein the reaction step comprises a catalyst. Temperature of 260-350 in the presence of
A method characterized in that steam or water is injected at a rate of 0.1 to 5 mol% with respect to natural gas at a temperature of 4 ° C. and a pressure of 4 to 10 MPa. 2. The method according to claim 1, wherein said catalyst is a CoMox reaction catalyst. 3. The absorption step is divided into a step of mainly absorbing hydrogen sulfide and a step of mainly absorbing carbon dioxide gas, and the recovery step is mainly a step of absorbing hydrogen sulfide rich in hydrogen sulfide obtained from the step of absorbing hydrogen sulfide. 3. The method according to claim 1, wherein sulfur is recovered from hydrogen sulfide obtained by regenerating the amine solution.
The described method. 4. The method according to claim 1, wherein heat is exchanged between the natural gas stream subjected to the reaction step and the natural gas stream after the reaction step. 5. A natural gas stream subjected to the reaction step and a natural gas stream subjected to the reaction step after heat exchange between the natural gas stream subjected to the reaction step and waste gas of a gas turbine The method according to claim 4, wherein the reheat exchange is performed by the heater heated in the step. 6. The method according to claim 1, wherein the sulfur recovery rate is 98% or more without performing tail gas treatment from the recovery step.