CN1208360A

CN1208360A - Method for removing sulfur-containing contaminants, aromatics and hydrocarbonsx from gas

Info

Publication number: CN1208360A
Application number: CN97191710A
Authority: CN
Inventors: 扬·阿道夫·拉加什; 特奥多鲁斯·约瑟夫·彼得鲁斯·万波尔
Original assignee: STORK COMPRIMO BV
Current assignee: STORK COMPRIMO BV
Priority date: 1996-01-19
Filing date: 1997-01-20
Publication date: 1999-02-17
Also published as: JP2000503293A; WO1997026069A1; NL1002134C2; TW381043B; AU1321397A; EP0880395A1; KR19990077361A; ZA97370B; CA2241790A1

Abstract

The invention relates to a method for removing sulfur-containing contaminants in the form of mercaptans and H2S from a hydrocarbon gas, which may also contain CO2 and higher aliphatic and aromatic hydrocarbons, and recovering elemental sulfur, wherein in a first absorption step the sulfur-containing contaminants are removed from the gas, to form on the one hand a purified gas stream and on the other hand a sour gas, which sour gas is hydrogenated in order to convert the greater part of the mercaptans to H2S, whereafter the hydrogenated sour gas is fed to a second absorption stage in which the sour gas is separated into an H2S-enriched first gas stream, which is fed to a Claus plant, followed by a selective oxidation step of H2S to elemental sulfur in the tail gas, and an H2S-reduced second gas stream, which second gas stream is combusted.

Description

Processfor removing sulfur-containing contaminants, aromatics and hydrocarbons from a gas

The invention relates to a quilt H₂S and sulfur compounds in the form of mercaptans and CO₂A process for the purification of contaminated gas, particularly hydrocarbon gas such as natural gas. More particularly, the invention relates to a process for converting mercaptans to H₂S and contains H₂CO removal from S gas₂Absorbed hydrocarbons and aromatics from H₂S to elemental sulphur.

In the purification of natural gas, refinery gas and synthetic gas, sulfur-containing gases, in particular H, are discharged₂S, which should be removed to limit their emission into the atmosphere, in particular to limit the SO formed when the sulphur compounds are burnt₂And is vented to the atmosphere. The degree of sulphide removal from natural gas depends on the use of the gas and the quality requirements set. H when the gas has to meet the so-called "pipeline specifications₂The S content should be reduced to less than 5mg/Nm³. It is also desirable to consider setting the maximum content of other sulfur compounds. A number of processes are disclosed in the prior art for reducing the content of sulfur compounds in gases such as natural gas.

In order to remove sulfur components from the gas, the following method is generally employed. In a first step, the treated gas is purified to remove sulphur-containing components from the gas, from which sulphur is recovered, after which a sulphur purification step of the residual gas is carried out. In this sulfur purification step, it is attempted to recover a final portion of the sulfur before the residual gas is vented to the atmosphere through a flue.

In the purification step, an aqueous solvent (absorbent) is usually used in the method used. These processes are divided into five processes, namely chemical solvent processes, physical/chemical solvent processes, redox processes, i.e. H in aqueous solution₂S is directly oxidized into sulfur; finally, a fixed bed method, adding H₂S is chemically or physically absorbed or adsorbed or selectively catalytically oxidized to elemental sulfur.

The first three treatment means described above are generally employed in industry for removing a large amount of sulfur components substantially present in a large amount of gas. The latter two treatment means are limited by the amount of sulfur to be treated and the concentration of the sulfur-containing components. Thus, both methods are less suitable for the removal of high concentrations of sulfur in large scale industrial gas purification plants.

The chemical solvent method includes a so-called amine method in which an aqueous solution of alkanolamine or a potassium carbonate solution is used.

In the physical solvent method, different chemical substances are used. For example polyethylene glycol (DMPEG), known under the name Selexol; n-methylpyrrolidone (NMP), known under the name puriol; or methanol, known under the name Rectisol.

Among the physical/chemical methods, the Sulfinol method is well known. In this process, a mixture of alkanolamine and sulfolane dissolved in a small amount of water is employed.

In the above three methods, an absorption apparatus and a regenerator are used. In the absorption unit, the sulfur-containing component is chemically or physically bound to the solvent. By depressurizing the regenerator and/or increasing the temperature, the sulfur-containing components are desorbed from the solvent, thereby allowing the solvent to be reused. For a detailed description of this method see: medox "Gas and Liquid sweeling" Campbell Petroleum Series (1977). In this process, in addition to the sulphur-containing component, depending on the solvent chosen, CO₂Or may be removed in whole or in part.

Removing sulfur compounds and CO from the regenerator₂Sent to a sulfur recovery plant to recover sulfur from H₂S and other sulfur compounds recover sulfur. Conventional for sulfur compounds obtained therefrom, in particular H₂The process for recovering sulphur in S is the Claus (Claus) process. This method is described in detail in the following documents: paskall, "Capability of the modified Claus process", Westernresearch Development, Calgary, Alberta, Canada, 1979.

The claus process comprises a heating step and typically a 2 or 3 reactor step. In the heating step, H of 1/3 is added₂Combustion of S to SO₂The following reaction formula

Thereafter, 2/3H remained₂S with SO formed₂React to form sulfur and water, as shown in the following reaction scheme

The efficiency of the claus process depends on a number of factors. For example, increasing the equilibrium of the water content claus reaction in the gas will be towards H₂And (4) transferring the S direction. The use of tail gas sulfur recovery equipment can increase the efficiency of the sulfur recovery equipment; the SUPERCLAUSTM method and the SCOT method are known as methods. In SUPERCLAUS^TMIn the process, a catalyst is used, as described in EP242920, EP409353 and WO-A9507856, wherein the catalyst is used in the third or fourth reactor section, as described below: "Hydrocarbon Processing" April 1989, pp.40-42.

Using this process, the final residual H present in the treated gas stream₂S is selectively oxidized into elemental sulfur according to the following reaction,

in this way, the efficiency of the sulfur recovery unit is easily increased to 99.5%. Sometimes the gas fed to the Claus plant contains a significant amount of CO₂E.g. up to 98.5%, which has a very large adverse effect on the flame temperature in the heating step. Large amount of CO₂May cause flame instability which in turn reduces the efficiency of the heating step and thus the overall efficiency of the claus plant.

Also, the gas may contain a large amount of hydrocarbons. When sour gas is processed to refinery gas, the hydrocarbon content is generally low, typically<2% by volume.

In natural gas purification processes, when physical or physical/chemical methods are used, the result of absorbing large amounts of hydrocarbons and aromatics, respectively, may end up in the gas (claus gas) that is passed to the sulfur recovery plant. In the heating section of the Claus plant, these hydrocarbons are completely combusted, sinceThe reaction rate of the hydrocarbon and the oxygen is higher than H₂The reaction rate of S with oxygen. When a large amount of CO is present₂When the flame temperature is higherLower and therefore the reaction rate of the components in the combustion process is also reduced. As a result, soot may be formed in the flame of the burner of the heating section.

Soot formation can cause plugging of the catalytic reactor of the claus plant, in particular the first reactor. Likewise, for mixing H₂The ratio of oxygen required for the conversion of S to sulfur to oxygen required for the combustion of hydrocarbons and aromatics may render the claus process no longer properly controllable. These problems are well known in industrial production.

More importantly, except for H₂S and the above-mentioned large amount of CO₂In addition, mercaptans are often present in the gas. In industrial production, mercaptans cannot be removed from gases to be purified, such as natural gas, using chemical methods, and thus re-purification using fixed bed methods is required. Molecular sieves are commonly used to remove these mercaptans.

However, when such fixed beds are saturated with mercaptans, the molecular sieves must be regenerated, for which purpose pure natural gas is generally used. This regeneration gas should then be purified again. During regeneration of the molecular sieve, the mercaptans are mostly released at the beginning of the regeneration. Also in some processes, mercaptans from the post-purification section may be returned to the claus plant. These mercaptans can create a peak burden on the heating section of the claus plant, thereby severely interfering with air control. This method is described in the following documents: oil and Gas Journal 57,19 August,1991, pp.57-59. Further, this process can result in natural gas losses, most likely up to about 10%.

Processes for the treatment of sulphur-containing gases containing carbonyl sulphide and/or other organic components such as mercaptans and/or dialkyl disulphides are also known. This process is described in GB1563251 and GB 1470950.

The invention aims to provide a catalyst which can contain CO₂And removal of mercaptans and H from hydrocarbon gases of higher aliphatic and aromatic hydrocarbons, such as natural gas₂S form and recovering elemental sulfur, the process of the present invention does not suffer from the drawbacks listed above. More specifically, the present invention relates toIt is an object of the invention to provide a method which results in exhaust gases which contain no or only very small amounts of harmful substances, so that the exhaust gases can be discharged into the atmosphere without objections. It is a further object of the present invention to provide a process which allows sulphur-containing contaminants to be recovered to a large extent as elemental sulphur, for example with a recovery of more than 90%, especially more than 95%.

The invention provides a simple process for the purification of contaminated hydrocarbon gases and the recovery of sulphur, according to which, in a first absorption step, sulphur-containing contaminants are removed from the gas to form a purified gas stream and an acid gas stream, and the acid gas is hydrogenated to convert the majority of the mercaptans to H₂S, thereafter, the hydrogenated acid gas is fed to a second absorption step, where the acid gas is separated into H-rich₂First gaseous stream of S and depleted of H₂A second gas stream of S, wherein the first gas stream is fed to a Claus plant via H₂The selective oxidation of S to elemental sulphur in the tail gas and the second gas stream is combusted.

It has surprisingly been found that with the process according to the invention a large amount of gas can be purified very effectively, while at the same time the strict requirements for the emission of non-toxic substances can be met and the recovery of sulphur can be met.

According to the invention, the acid gas is first passed into a hydrogenation reactor, the mercaptans in the gas being converted into H by means of the hydrogen supplied₂And S. Thereafter, the acid gas is separated into a so-called two-partgas enrichment unit, i.e. enriched in H₂S gas and CO rich gas₂The latter containing a major part of CO₂Hydrocarbons and aromatics. CO-riched hydrocarbon and aromatic compounds₂The gas (2) can be moderately combusted in the post-combustion equipment. The heat released during post-firing is very useful, for example, for producing steam.

Will be rich in H₂And introducing the gas of the S into a sulfur recovery device. By this process, H₂The concentration of S tends to increase by a factor of 2-6. This H-enriched fraction₂The S gas can be well treated in the Claus plant, the greatest advantage of which is the elimination of most of the CO₂A hydrocarbon andaromatic compounds do not cause any additional gas production in the plant when combusted. As a result, the claus plant can be designed smaller, while at the same time a higher sulfur recovery can be achieved.

The tail gas from the claus plant may be further treated in a tail gas recovery plant, and the sulphur compounds are selectively oxidised to elemental sulphur. The off-gas recovery unit is preferably a SUPERCLAUS reactor section.

The tail gas from the tail gas desulfurization unit may be combusted in a post combustor. The released heat can be used to produce steam.

According to the invention, the acid gas and hydrogen are passed through a hydrogenation reactor comprising a catalyst which is a sulphide of a group 6 and/or group 8 metal on a support.

Alumina is preferred as the support for such catalysts because, in addition to the desired thermal stability, alumina is able to disperse the active ingredient well. The catalytically active component is preferably a combination of cobalt and aluminium.

In the hydrogenation step, mercaptans in the gas are converted to H by the supplied hydrogen₂And S. To limit undesired H₂S and CO₂Formation of COS and H₂Reaction of O, water vapor is supplied to the hydrogenation step, thereby reducing the formation of COS.

Another method to prevent COS formation without the addition of water vapor is to provide a pre-absorber before the hydrogenation step to keep the H in the gas₂The S concentration is reduced to less than a quarter. The gas from the pre-absorber is then passed to a hydrogenation reactor to convert all mercaptans to H by the addition of hydrogen₂And S. Thereafter, residual H₂S is selectively absorbed in the second absorber of the second absorption step. Overall, the same H₂The S enrichment process can be accomplished in one absorber. However, with the above method, the risk of COS formation can be completely prevented or greatly reduced.

According to a preferred embodiment of the invention, the first absorption step is carried out by absorption with a chemical, physical or chemical/physical absorbent, essentially removing the natural gasAnd some contaminants. Preferred absorbents are based on sulfolane and are used in combination with secondary and/or tertiary amines. As previously mentioned, such systems are well known and have been used on a large scale for the purification of natural gas, particularly when the natural gas is to be liquefied after purification (e.g. SULFINOL-D process). The absorption process is carried out as in the conventional manner,the system used allows the contaminants to be absorbed in the solvent in a first column, and when the solvent is loaded with contaminants, the solvent is regenerated in a second column, for example by means of heating and/or pressure reduction. The temperature at which the absorption is carried out depends to a large extent on the solvent and the pressure used. At natural gas stream pressures of 2 to 100 bar, the absorption temperature is typically 15 to 50 ℃, although good results can be obtained outside this temperature range. The natural gas is preferably purified to meet pipeline specifications, which means that there is typically no more than 10ppm, preferably no more than 5ppm, of H₂S is present.

The gas stream discharged from the first absorption/desorption step contains a major portion of the contaminants such as H₂S, aromatics, hydrocarbons and mercaptans, and CO₂They are hydrogenated with hydrogen in the presence of a suitable catalyst such as Co/Mo on alumina. For this purpose, the gas stream should be heated to an absorption/desorption temperature of about 40 ℃ to a temperature of 200 ℃ and 300 ℃ required for the hydrogenation. This heating process is preferably carried out indirectly without the use of burners placed in the gas stream as in conventional processes. In fact, direct heating has the disadvantage of forming soot, which can lead to fouling and clogging of the hydrogenation process. As mentioned above, measures may be taken to reduce COS formation.

In a second absorption stage, the hydrogenated gas is separated into a H-rich fraction₂Gas of S and lean in H₂S gas. This absorption process preferably uses a solvent based on a secondary or tertiary amine, more specifically, an aqueous solution of methyldiethylamine, optionally in combination with an activator, or in combination with a hindered tertiary amine. This method is well known and described in the literature (MDEA method, UCARSOL, FLEXSORB-SE, etc.). This method operates in a manner corresponding to the first absorption step. The degree of enrichment is preferably at least 2-6 fold, which is partly dependent on H₂Beginning of SThe starting concentration. The degree of enrichment can be set by making a suitable choice of the structure of the absorber.

Will be rich in H₂The gas of S is fed to the heating section of the claus plant. Such devices are well known and the manner in which they operate, temperature and pressure, are described in detail in the publications cited.

The tail gas from the claus plant still contains residual sulphur compounds, which, if desired after additional hydrogenation, is fed to a tail gas treatment unit where the sulphur compounds are selectively oxidised to form elemental sulphur, which is separated in a plant suitable for this purpose, as described in EP 655414.

After the sulfur is separated out, the residual gases can be combusted, optionally forming steam, and vented to the atmosphere.

The selective oxidation process is preferably carried out in the presence of a catalyst which selectively converts sulphur compounds to elemental sulphur, examples of catalysts being those described in the aforementioned EP and WO patents. These publications are incorporated herein by reference, and they also indicate optimum processing conditions, such as temperature and pressure. However, pressure is generally not critical and the temperature may be between the dew point of sulfur and about 300 deg.C, preferably less than 250 deg.C.

The method of the invention is described below with reference to two figures, which are block diagrams. Acid gases are evolved from a first absorption unit (not shown) in which contaminated natural gas is separated into a gas stream having the required specifications and acid gases, which are introduced into line 1 and brought to the required hydrogenation temperature, hydrogen and/or carbon monoxide are added via line 2 and passed into hydrogenation reactor 3. Also, steam is added to line 1 via line 6 to suppress carbonyl sulfide formation in the hydrogenation reactor 3.

In the reactor 3, mercaptans and other organic sulphur compounds present in the gas are converted into H₂And S. The gas from the hydrogenation reactor 3, after cooling, is fed via line 7 to the absorber of the selective absorption/regeneration unit. During this cooling process, the supplied water vapour is condensedAnd recycled back to the hydrogenation reactor 3 via the evaporator 5.

Mainly composed of CO₂Hydrocarbons (including aromatics) and small amounts of H₂Unabsorbed gas components consisting of S are fed to the after burner 18 via line 8 and then discharged via flue 19. H-rich from the regeneration section of the absorption/regeneration apparatus 9₂The S gas mixture is fed via line 10 to a claus plant 11 where the majority of the sulphur compounds are converted to elemental sulphur, which is discharged via line 12.

To increase the efficiency of the claus plant, the tail gas is often passed via line 13 to a tail gas desulfurization stage 14. Such a desulfurization section employs a known desulfurization method and may be, for example, a dry bed oxidation section, an absorption section or a liquid oxidation section. Air for oxidation is supplied via line 15. Thereafter, the gas is discharged through line 17 into after burner 18 and then through flue 19.

As shown in fig. 2, the acid gas is discharged from a first absorption unit (not shown) in which the contaminated natural gas is separated into a gas stream having the required specifications and the acid gas, which is introduced via line 1 into the pre-absorber 2 of an absorption/regeneration plant, which plant also contains a second absorber and regenerator 9.

The gas from the pre-absorber 2 is passed via line 3 into a hydrogenation reactor 5 and brought to the desired hydrogenation temperature, hydrogen and/or carbon monoxide being added via line 4.

In the hydrogenation reactor 5 mercaptans and other organic sulphur compounds present in the gas are converted to H₂And S. Mainly composed of CO₂Hydrocarbons (including aromatics) and small amounts of H₂Unabsorbed gas components consisting of S are fed to the after burner 21 via line 8 and then discharged via flue 22.

H-rich from regeneration plant 9₂The gas mixture of S is fed via line 13 to claus plant 14 where most of the sulfur compounds are converted to elemental sulfur, which is discharged via line 15.

The regenerated absorbent is recycled back to the second absorber 7 and then to the pre-absorber 2 via line 11. Loaded with H₂S and CO₂From the pre-absorber 2 viaLine 12 returns to regenerator 9.

To increase the efficiency of the claus plant, the tail gas is passed via line 16 to a tail gas desulfurization stage 18. Such a desulfurization section employs a known desulfurization method and may be, for example, a dry bed oxidation section, an absorption section or a liquid oxidation section. Air for oxidation is supplied via line 17. The sulfur formed is discharged via line 19. Thereafter, the gas is discharged through a line 20 into a post-combustor 21 and then through a flue 22.

The invention is illustrated by the following non-limiting examples. Example 1

15545Nm of acid gas from regenerator of gas purification plant³H, having the following composition at 40 ℃ and 1.70 (absolute):

9.0 vol.% H₂S

60 ppm (volume) COS

0.22 vol.% CH₃SH

0.38 vol% C₂H₅SH

0.03 vol% C₃H₇SH

0.01 vol.% C₄H₉SH

81.53 vol% CO₂

4.23 vol.% H₂O

3.51 vol.% Hydrocarbon (C)_1-17)

1.08 vol.% aromatics (benzene, toluene, xylene)

3000Nm of an acid gas as described above is fed into a hydrogenation reactor containing a group 6 and/or group 8 metal sulfide catalyst (Co-Mo catalyst is used herein)³H of a reducing gas comprising hydrogen and carbon monoxide, which is then heated to 205 ℃ to hydrogenate all mercaptans present to H₂And S. With addition of 7000Nm to the acid gas³Water vapour/h to suppress COS formation in the hydrogenation reactor.

The temperature of the gas withdrawn from the reactor was 226 ℃.

The acid gas is cooled to 46 ℃, and the water vapor contained therein is condensed out. The recycling of this condensation process is carried out via the evaporator on the acid gases which are passed into the hydrogenation reactor.

The amount of gas from the hydrogenation reactor after condensation of the added water vapour was 18545Nm³H, having the following composition:

8.08 volume% H₂S

COS of 50 ppm (volume)

69.78 vol.% CO₂

6.4 vol.% H₂O

2.94% by volume of Hydrocarbon (C)_1-17)

0.91% by volume of aromatic compound (benzene, toluene, xylene)

1.03 vol.% H₂

10.86 vol% N₂

Thereafter, the cooled gas is contacted with a methyldiethanolamine solution in an absorber of a gas cleaning plant, thereby bringing about H₂S and part of CO₂Is absorbed. Product gas from absorber (rich in CO)₂Gas) in an amount of 15680Nm³H, having the following composition:

74.54 vol.% CO₂

500 ppm by volume of H₂S

60 ppm (volume) COS

6.78 vol% H₂O

3.48 vol.% Hydrocarbon (C)_1-17)

1.07 vol.% of aromatic Compound (benzene, toluene, xylene)

1.21 vol% H₂

12.86 volume% N₂

After passing throughBurning, and adding the gas into a flue. After desorption in the regenerator, the acidic H is₂S/CO₂Gas mixture (H-rich)₂S gas) to a sulfur recovery facility. Such H₂S/CO₂The amount of the gas mixture is 2870Nm³H at 40 ℃ and 1.7 bar (absolute)The composition of (A) is as follows:

51.9 vol% H₂S

43.8 vol.% CO₂

4.3 vol.% H₂O

2975Nm is supplied to the burners of the heating section of a sulfur recovery plant³H air, so that H is present in the treated gas after the second Claus reactor stage₂S is 1.14 vol.% and SO₂0.07 vol%. The treated gas is then fed to a tail gas desulfurization stage, which is operated with H₂An S selective oxidation reactor.

310Nm of gas is supplied into the gas³H air. The inlet temperature of the selective oxidation reactor was 220 ℃ and the outlet temperature was 292 ℃. The selective oxidation reactor is packed with a catalyst described in the following documents: EP242920 and 409353, International patent application WO-A95/07856.

The sulfur formed in the sulfur recovery unit is concentrated and discharged in each stage. And introducing the discharged inert gas into the flue after post-burning. Sulfur content of 2094 Nm³H is used as the reference value. As the original acid gas (containing 9.0 vol.% H)₂S) the total desulfurization rate was 97.7%.

Claims

1. One can contain CO₂And removal of mercaptans and H from hydrocarbon gases of higher aliphatic and aromatic hydrocarbons₂Process for the removal of sulphur-containing contaminants from a gas in the form of S and recovery of elemental sulphur, wherein in a first absorption step the sulphur-containing contaminants are removed from the gas to form a purge gas stream and an acid gas stream, the acid gas is hydrogenated to convert the majority of the mercaptans to H₂S, thereafter, the hydrogenated acid gas is fed to a second absorption step, where the acid gas is subjected toSeparated into H-rich₂First gaseous stream of S and depleted of H₂A second gas stream of S, wherein the first gas stream is fed to a Claus plant via H₂The selective oxidation of S to elemental sulphur in the tail gas and the second gas stream is combusted.

2. A process according to claim 1, wherein in the first absorption step substantially all sulphur compounds and CO are removed by absorption with a chemical, physical or chemical/physical absorbent₂。

3. A process according to claim 2, wherein the absorbent is based on sulfolane and is used in combination with a secondary or tertiary amine.

4. The process according to claim 1 or 2, wherein the second absorption step is carried out with an absorbent based on secondary and/or tertiary amines.

5. A process according to any one of claims 1 to 4, wherein the first absorption step is carried out in such a way that the gas contains no more than 10ppm, preferably no more than 5ppm of sulphur-containing contaminants.

6. A process according to claim 5 wherein the gas is natural gas which may optionally be liquefied after purification.

7. A process according to any one of claims 1 to 6, wherein the second absorption step is carried out in such a way that H is present in the first gas stream₂S content is at least greater than H in acid gas₂The S content is 2.5 times higher, preferably at least 4 times higher.

8. A process according to any one of claims 1 to 7 wherein the mercaptan content of the hydrogenated gas stream is less than 1 ppm.

9. The process according to any one of claims 1 to 8, wherein the hydrogenation is carried out in the presence of a supported catalyst loaded with a catalytically active component based on at least one metal of group VIB and at least one metal of group VIII of the periodic Table of the elements, preferably based on a combination of cobalt and molybdenum.