NL1002134C2 - Method for removing sulfur-containing impurities, aromatics and hydrocarbons from gas. - Google Patents

Description

Title: Method for removing sulfur-containing impurities, aromatics and hydrocarbons from gas

The invention relates to a process for purifying gas, more in particular hydrocarbon gas, such as natural gas, which is contaminated with sulfur compounds in the form of H2S and mercaptans, as well as with CO2. More particularly, the invention includes a process for converting mercaptans to H 2 S in, and removing CO2 / absorbed hydrocarbons and aromatics from H 2 S containing gas to form elemental sulfur from H 2 S.

Purification of natural gas, purification of refinery gases and purification of synthesis gas release sulfur-containing gases, in particular H2S, which must be removed in order to limit the emissions into the atmosphere, in particular of SO2 which, when burning such sulfur compounds arises. The extent to which the sulfur compounds must be removed from, for example, natural gas depends on the intended application of the gas and the quality requirements. If the gas must meet the so-called "pipe line specificaton", the H2S content must be reduced to a value lower than 5 mg / Nm3. Requirements are also imposed on the maximum content of other sulfur compounds. A large number of methods are known from the prior art with which the amount of sulfur compounds in a gas, such as natural gas, can be reduced.

Usually, the following process route is used to remove sulfur-containing components from gases. In a first step, the gas to be treated is purified, whereby sulfur-containing components are extracted from the gas 1 0 0 2 5 3 4.

2 are removed, followed by recovery of sulfur from these sulfur-containing components, followed by a sulfur cleaning step of the residual gas. In this sulfur cleaning step an attempt is made to recover the last percent sulfur before the residual gas is emitted into the atmosphere via the chimney.

In the purification step, processes are often used in which aqueous solvents (absorbents, also called solvents) are used. These processes are divided into five main groups, namely chemical solvent processes, physical solvent processes, physical / chemical solvent processes, redox processes, where H2S is directly oxidized to sulfur in an aqueous solution and finally a group of fixed bed processes where H2S is chemical or physical 15 is absorbed or adsorbed or selectively oxidized catalytically to elemental sulfur.

The first three groups are generally used in industry for removing large amounts of sulfur-containing components, usually present in mostly large amounts of gas. The last two groups are limited in terms of the amount of sulfur to be removed and the concentration of the sulfur-containing components. These processes are therefore less suitable for removing high concentrations of sulfur in large industrial gas purification plants.

Chemical solvent processes include so-called amine processes using aqueous solutions of alkanolamines or potassium carbonate solutions.

In the physical solvent processes, different chemicals are used. For example, polyethylene glycol (DMPEG) known under the name Selexol, N-Methyl-Pyrrolidone (NMP) known under the name Purisol or methanol known under the name Rectisol.

The Sulfinol process is well known in the group of physical / chemical processes. This process uses 10 0 2 'i Λ Λ.

3 made from a mixture of an alkanolamine with sulfolane dissolved in a small amount of water.

In the above three methods, an absorber and a regenerator are used. In the absorber, the sulfur-containing components are chemically or physically bound to the solvent. The sulfur-containing components are desorbed from the solvent by pressure reduction and / or temperature increase in the regenerator, after which the solvent can be reused. A detailed description of this method can be found in R.N. Medox "Gas and Liquid Sweetening" Cambell Petroleum Series (1977). In this process, in addition to the sulfur-containing components, CO2 is also completely or partially removed, depending on the chosen solvent.

The removed sulfur compounds are sent together with the CO2 from the regenerator to a sulfur recovery plant, in order to recover the sulfur from H2S and other sulfur compounds. It is a frequently used process for the recovery of sulfur from the sulfur compounds, in particular H2S, thus obtained

Claus process. This process is described in detail from H.G. Paskall, "Capability of the modified Claus process" Western Research Development, Calgary, Alberta, Canada, 1979.

The Claus process consists of a thermal step 25 followed by usually 2 or 3 reactor steps. In the thermal step, a third of the H2S is burned to SO2 according to the reaction

H2S + 1.5 02 SO2 + H2O

30, after which the remainder, i.e. 2/3 of the H2S, reacts with the SO2 formed according to the Claus reaction to form sulfur and water.

35 2 H2S + S02 -> 3 S + 2 H20.

1C C 2 13 4.

4

The efficiency of the Claus process depends on a number of factors. For example, with an increasing water content in the gas, the equilibrium of the Claus reaction shifts in the direction of H2S. The efficiency of the sulfur recovery plant can be increased by using a tail gas sulfur recovery plant; known processes are the SUPERCLAUS ™ process and the SCOT process. The SUPERCLAUS ™ process uses a catalyst as described in European patent applications Nos. 242,920 and 10 409,353, as well as in international patent application WO-A 95.07856, this catalyst being used in a third or fourth reactor stage as described inter alia in " Hydrocarbon Processing "April 1989, pages 40-42.

Using this method, the last residues of H 2 S present in the process gas stream are selectively oxidized to elemental sulfur according to the reaction H 2 S + 0.5 O 2 -> S + H 2 O.

In this way, the efficiency of the sulfur recovery plant can easily be increased to 99.5%. The gas supplied to the Claus plant can sometimes contain large amounts of CO2 / for instance up to 98.5%, which has a very detrimental effect on the flame temperature in the thermal step. With a large amount of CO2, instability of the flame can occur and the efficiency in the thermal stage will also decrease, as a result of which the overall efficiency of the Claus installation will decrease.

The gas can also contain large amounts of hydrocarbons. When processing sulfur-containing gas in an oil refinery gas, the hydrocarbon content will generally be low, usually <2% by volume.

In the purification of natural gas, in which physical or physical / chemical processes are applied, larger quantities of hydrocarbons, resp. aromatics, in the gas that is fed to the sulfur recovery plant (Clausgas). In the 10 02 134.

In a Claus plant thermal stage, these hydrocarbons are completely burned because the reaction rate of the hydrocarbons with oxygen is higher than the reaction rate of H2S and oxygen. When large amounts of CO2 are present, the flame temperature will consequently be lower and so will the reaction speed of the components during combustion. Therefore, it is possible for soot to form in the flame of the burner of the thermal stage.

Carbon black formation gives rise to blockage problems in the catalytic reactors of a Claus plant, in particular the first reactor. The ratio between the oxygen requirement for the conversion of H 2 S to sulfur and the oxygen requirement for the combustion of the hydrocarbons and aromatics can also assume such values that the Claus process can no longer be properly controlled. These problems are known in the industry.

In addition, besides H2S and the above-mentioned large amounts of CO2, mercaptans are also often present in the gas. Chemical processes are used in industry, whereby these mercaptans are not removed from the gas to be purified, eg natural gas, so that after-cleaning is required with a fixed bed process. Molecular sieves are often used to remove these mercaptans.

However, when such a fixed bed is saturated with mercaptans, the molecular sieves must be regenerated, often using the purified natural gas. This regeneration gas then has to be purified again. When the molecular sieves are regenerated, the mercaptans are largely released at the start of regeneration. There are also processes in which the mercaptans are returned from a post-purification stage to the Claus plant. These mercaptans then give a peak load in the thermal stage 35 of the Claus plant, as a result of which the air regulation is seriously disrupted. Such a process route is described in Oil and Gas Journal 57, August 19, 1991, pp. 57-59. In addition, 10 02 134.

6 this leads to a loss of natural gas, which can easily rise to about 10%.

A method of processing sulfur-containing gases containing carbonyl sulfide and / or other organic components such as mercaptans and / or di-alkyl disulfides is known. This method is described in British patent number 1563251 and in British patent number 1470950.

The object of the present invention is inter alia to provide a process for removing sulfur-containing impurities in the form of mercaptans and H2S from hydrocarbon gas, such as natural gas, which can also contain CO2 and higher aliphatic and aromatic hydrocarbons, and recover of elemental sulfur, the disadvantages outlined above not occurring. More particularly, it is an object of the invention to provide a method in which the residual gases contain no or only very few harmful substances, so that they can be discharged into the atmosphere without any problem. It is also an object of the invention to provide a method in which the sulfur-containing impurities are largely recovered as elemental sulfur, for example to an amount of more than 90, more particularly more than 95%.

The present invention provides a simple method for the purification of contaminated hydrocarbon gas with sulfur recovery, according to which method in a first absorption step the sulfur-containing impurities are removed from the gas, on the one hand forming a purified gas stream and on the other an acid gas, which acid gas is hydrogenated to convert the majority of the mercaptans to H2S, after which the hydrogenated acid gas is supplied to a second absorption step in which the acid gas is separated into a first gas stream enriched in H2S, which is fed to a Claus plant , Followed by a selective oxidation step of H 2 S to elemental sulfur in the tail gas, and an H 2 S depleted second gas stream, which second gas stream is burned.

10 02 134.

7

Surprisingly, it has been found that with the method according to the invention large gas flows can be purified in a very efficient manner, while also meeting strict requirements with regard to emission of harmful substances and recovery efficiency of sulfur.

According to the invention, the acid gas is first passed through a hydrogenation reactor in which the mercaptans in the gas are converted into H 2 S using supplied hydrogen. The acid gas is then separated into two other gases in a so-called enrichment unit, namely an H2S-rich gas and a CO2-rich gas, which contains the majority of the CO2, hydrocarbons and aromatics.

The CO2-rich gas with the hydrocarbons and aromatics present can be burned well in a post-combustion installation. The heat released during this afterburning can be used very usefully, for example for generating steam.

The H2S-rich gas is sent to the sulfur recovery plant. With this method, the H2S 20 concentration can easily be increased two to six times. This H2S-rich gas can be processed very well in a Claus plant, the great advantage of which is that the absence of a large part of the CO2, hydrocarbons and aromatics during combustion does not cause additional gas throughput in the installation. The Claus 25 plant can therefore be built much smaller, while achieving much higher sulfur recovery efficiencies.

The residual gas obtained from the Claus plant is further processed in a residual gas recovery plant on the basis of selective oxidation of the sulfur compounds to elemental sulfur. The residual gas recovery plant is preferably the SUPERCLAUS reactor stage.

The waste gases from this residual gas desulfurization unit 35 are burned in an afterburner. The heat released can be used to generate steam.

1002134. " 8

According to the invention, the acid gas is passed with hydrogen over a hydrogenation reactor containing a sulfided group 6 and / or group 8 metal catalyst which is supported.

As a carrier, alumina is preferably used as a carrier in this type of catalyst, since this material, in addition to the desired thermal stability, also permits good dispersion of the active component. The catalytically active material is preferably a combination of cobalt and 10 molybdenum.

In the hydrogenation step, the mercaptans in the gas are converted into H2S using the hydrogen supplied. In order to limit the undesired reaction between H2S and CO2 to COS and H2O, water vapor is supplied in the hydrogenation step, whereby less COS is formed.

An alternative method to prevent COS formation, but without the addition of water vapor, is to install a pre-absorber before the hydrogenation step, reducing the H2S concentration in the gas to less than a quarter. The gas from this pre-absorber is then passed through a hydrogenation reactor, in which all the mercaptans are converted into H2S using the added hydrogen. The remaining H 2 S is then selectively absorbed in a second absorber, from the second absorption step. On balance, the same H2S enrichment is obtained as with one absorber. With this method, however, the danger of COS formation has completely or largely disappeared.

According to a preferred embodiment of the invention, the first absorption step is performed using a chemical, physical or chemical / physical absorbent that removes all contaminants from the natural gas. Preferably, this is a sulfolane-based absorbent in combination with a secondary and / or tertiary amine. As already indicated, such systems are known and are already widely used for the purification of natural gas, especially when natural gas is liquefied after purification (for example the SÜLFINOL-D process). The absorption is, as usual, based on a system in which the impurities in a first column are absorbed in the solvent, after which, if the solvent is loaded with impurities, this solvent is regenerated in a second column, for example by heating and / or by reducing pressure. The temperature at which the absorption takes place depends largely on the solvent and the applied pressure. At the pressures of 2 to 100 bar common for natural gas, the absorption temperature is generally 15 to 50 ° C, although good results can also be obtained outside these ranges. The natural gas is preferably purified to meet the pipeline specification, which means that generally no more than 10, more particularly no more than 5 ppm of H2S may be present.

The gas stream from the first absorption / desorption, which contains the majority of impurities such as H 2 S, aromatics, hydrocarbons and mercaptans, as well as CO2, is then hydrogenated in the presence of a suitable catalyst such as Co / Mo on alumina, and hydrogen. For this purpose, however, the gas stream must be heated from the absorption / desorption temperature of about 40 ° C, to the temperature required for the hydrogenation from 200 to 300 ° C. This heating preferably takes place indirectly and not with a burner arranged in the gas flow, as is customary. The drawback of direct heating is that direct heating in this case gives rise to strong soot formation, which can lead to pollution and blockage in the hydrogenation. As indicated above, measures can be taken to reduce COS formation.

In the second absorption step, the hydrogenated gas is split into an H2S-enriched gas and an H2S-depleted gas. This absorption is preferably effected using a solvent based on a secondary or tertiary amine, more in particular with an aqueous solution of methyl diethyl amine, optionally in combination 10 02 134.

10 with an activator therefor, or with a hindered tertiary amine. Such processes are known and described in the literature (MDEA process, UCARSOL, FLEXSORB-SE, and the like). The mode of operation of such processes is comparable to the first absorption stage. The degree of enrichment is preferably at least 2 to 6 times or more, which partly depends on the starting concentration of H 2 S. The degree of enrichment can be adjusted by suitable choice of the construction of the absorber.

The gas enriched in H2S is fed to the thermal stage of a Claus installation. Such an installation is known and the manner in which it is operated with regard to temperature and pressure are described in detail in the publications cited in the introduction.

The residual gas from the Claus plant, which still contains residual sulfur compounds, is supplied, if desired after additional hydrogenation, to a residual gas processing plant in which elemental sulfur is formed by selective oxidation of the sulfur compounds, which is separated in a suitable plant, for example as described in European patent application No. 655,414.

After separation of the sulfur, the residual gas can be burned, optionally with the formation of steam, and discharged to the atmosphere.

The selective oxidation is preferably carried out in the presence of a catalyst that selectively converts sulfur compounds to elemental sulfur, for example, the catalysts described in the aforementioned European and international patent applications. These publications, the contents of which are incorporated herein by reference, also indicate the most suitable process conditions, such as temperature and pressure. In general, however, the pressure is not critical, while temperatures may range from the sulfur dew point to about 300 ° C, more typically less than 250 ° C.

TO 02 134.

11

The invention will now be explained with reference to two figures, in which the method according to the invention is described in the form of a block diagram. The sour gas, originating from a first, not drawn, absorption unit, in which 5 contaminated natural gas is separated into a gas stream of the desired specification on the one hand and the sour gas on the other hand, is brought to the desired hydrogenation temperature in line 1 with addition of hydrogen via line 2 and / or carbon monoxide, before being introduced into hydrogenation reactor 3. Also, in line 1, water vapor is supplied through line 6 to suppress the formation of carbonyl sulfide in the hydrogenation reactor 3.

In the hydrogenation reactor 3, the mercaptans and other organic sulfur compounds present in the gas are converted to H2S. The gas from the hydrogenation reactor 3, after cooling, is led via line 7 to an absorber of a selective absorption / regeneration installation. In this cooling, the supplied water vapor condensed through a evaporator 5 is recycled to the hydrogenation reactor 3.

20 The non-absorbed components of the gas, consisting mainly of carbon dioxide, hydrocarbons (including aromatics) and a low content of H2S, are led via line 8 to the afterburner 18 before the gas is removed via chimney 19. The H2S-rich gas mixture 25 comes from from the regeneration section of the absorption / regeneration installation 9 is fed via line 10 to the Claus installation 11, in which the majority of the sulfur compounds are converted into elemental sulfur which is removed via line 12.

In order to increase the efficiency of the Claus installation, the residual gas is usually fed via line 13 to a residual gas sulfur removal stage 14. This sulfur removal step can be a known sulfur removal process such as e.g. a dry bed oxidation step, an absorption step or a liquid oxidation step. The air required for the oxidation is supplied via line 15. The sulfur formed is discharged via line 16. The gas then becomes 10 0 2 13 4.

12 passed through line 17 to the afterburner 18 before the gas is discharged through chimney 19.

As shown in figure 2, the sour gas, originating from a first absorption unit, not shown, in which polluted natural gas is split into a gas flow of the desired specification on the one hand and the sour gas on the other hand, via line 1 to a pre-absorber 2 of a absorption / regeneration installation, further comprising a second absorber and a regenerator 9, guided.

The gas from the pre-absorber 2 is fed via line 3 to the hydrogenation reactor 5 and brought to the desired hydrogenation temperature with addition via line 4 of hydrogen and / or carbon monoxide.

In the hydrogenation reactor 5, the mercaptans and other organic sulfur compounds present in the gas 15 are converted into H 2 S. The gas from the hydrogenation reactor, after cooling, is passed via line 6 to a second absorber. The non-absorbed components of the gas, mainly consisting of carbon dioxide, hydrocarbons (including 20 aromatics) and a minimal amount of H2S, are led via line 8 to the afterburner 21 before the gas is removed via chimney 22.

The H2S rich gas mixture from the regenerator 9 is fed via line 13 to the Claus 25 installation 14, in which the majority of the sulfur compounds are converted into elemental sulfur which is removed via line 15.

The regenerated absorbent is recirculated over the second absorber 7 and then returned via line 11 to the pre-absorber 2. From the pre-absorber 2, the absorbent charged with H2S and CO2 is returned via line 12 to regenerator 9.

In order to increase the efficiency of the Claus installation, the residual gas is led via line 16 to a residual gas sulfur removal stage 18. This sulfur removal step can be a known sulfur removal process such as a 1 0 0 2 * 34.

13 dry bed oxidation step, absorption step or liquid oxidation step. The air required for the oxidation is supplied via line 17. The sulfur formed is discharged via line 19. The gas is then led via line 20 to the afterburner 21 before the gas is removed via chimney 22.

The invention is illustrated by the following, non-limiting example.

10 EXAMPLE 1

An amount of acid gas of 15545 Nm / h from the regenerator of a gas treatment plant had the following composition at 40 ° C and a pressure of 1.70 bar abs.

9.0 vol. % H2S

60 ppm vol. COS

0.22 vol. % CH3SH

0.38% by volume of C 2 H 5 SH

0.03% by volume of C3H7SH

0.01 vol% C4H9SH

81.53 vol.% C02 4.23 vol.% H20 3.51 vol.% Hydrocarbons (C3 to C17) 25 1.08 vol.% Aromatics (Benzene, Toluene, Xylene)

To this acid gas was fed 3000 Nm 3 / h reducing gas containing hydrogen and carbon monoxide and then heated to 205 ° C to hydrogenate all the mercaptans present to H2S in the hydrogenation reactor containing a sulfided group 6 and / or group 8 metal catalyst in this case a Co-Mo catalyst. Also, this acid gas was supplied with 7000 Nm 2 / h water vapor to suppress COS formation in the hydrogenation reactor.

The temperature of the gas from the reactor was 226 ° C.

10 02 1 34.

14

The acid gas was then cooled to 46 ° C and the water vapor contained therein was condensed. This condensate was recycled via an evaporator to the sour gas, which is fed to the hydrogenation reactor.

The amount of gas coming out of the hydrogenation reactor after condensation of the water vapor supplied was 18545 Nm3 / h and had the following composition

8.08 vol.% H2S

10 50 ppm vol. COS

69.78 vol.% CO2 6.4 vol.% H20 2.94 vol.% Hydrocarbons (Ci to C17) 0.91 vol.% Aromatics (Benzene, Toluene, Xylene) 15 1.03 vol.% H2 10.86 vol.% N2

The cooled gas was then contacted in an absorber from a scrubber with a methyl diethanolamine solution to absorb the H 2 S and part of the CO2. The amount of product gas (CO2 rich gas) from the absorber was 15680 Nm3 / h with the following composition: 74.54% by volume CO2

500 ppm vol. H2S

60 ppm vol. COS

6.78 vol.% H20 3.48 vol.% Hydrocarbons (C ^ to C17) 30 1.07 vol.% Aromatics (Benzene, Toluene, Xylene) 1.21 vol.% H2 12.86 vol.% N2

This gas was fed to the chimney via a post-combustion. After desorption in a regenerator, the acidic H2S / CO2 gas mixture (H2S rich gas) was fed to a sulfur recovery plant. This H2S / CO2 gas mixture 10 0 2 13 4.

15 was 2870 Nm / h and had the following composition at 40 ° C and 1.7 bar abs.

51.9 vol% H2S

43.8 vol.% CO2 4.3 vol.% H 2 O

2975 Nm-Vh of air was fed to the burner of the thermal stage of the sulfur recovery plant, so that after the second Claus reactor stage 1.14% by volume H2S and 0.07% by volume SO2 was present in the process gas. The process gas

was then fed to the residual gas sulfur removal stage, consisting of a selective H2S

oxidation reactor.

310 Nm 3 / h air was supplied to this gas. The inlet temperature of the selective oxidation reactor was 220 ° C and the outlet temperature was 292 ° C. The selective oxidation reactor was filled with catalyst as described in European patents 242,920 and 409,353 and in International patent application WO-A 95/07856.

The sulfur formed in the sulfur recovery plant was condensed and discharged after each stage. The escaping inert gas was led to the chimney via afterburning. The amount of sulfur was 2094 kg / h.

The total desulfurization efficiency based on the original acid gas, which contained 9.0% by volume H 2 S, was 97.7%.

10 0 2 "7"

Claims (10)

1. A method for removing sulfur-containing impurities 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, in a first absorption step the sulfur-containing impurities are removed from the gas to form a purified gas stream on the one hand and an acid gas on the other, which acid gas is hydrogenated to convert most of the mercaptans to H 2 S, after which the hydrogenated acid gas is fed to a second absorption step in which the acid 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 residual gas, and a H2S-depleted second gas stream, which second gas stream is burned. 2. A method according to claim 1, wherein the first absorption step is performed using a chemical, physical, or chemical / physical absorbent, which removes substantially all sulfur compounds and CO2. The method of claim 2, wherein the absorbent is based on sulfolane, in combination with a secondary or tertiary amine. 4. A method according to claim 1 or 2, wherein the second absorption step is carried out using an absorbent based on a secondary and / or tertiary amine. A method according to claims 1-4, wherein the first absorption step is carried out such that the gas contains no more than 1002 134. more than 10, more particularly no more than 5 ppm, of sulfur-containing impurities. A method according to claim 5, wherein the gas is natural gas, after which it is optionally liquefied. A method according to claims 1-6, wherein the second absorption step is carried out such that the content of H2S in the first gas stream is at least 2.5 times, more in particular at least 4 times, higher than the content of H2S in the sour gas. A method according to claims 1-7, wherein the content of mercaptans in the hydrogenated gas stream is less than 1 ppm. 9. Process according to claims 1-8, wherein the hydrogenation takes place in the presence of a supported catalyst, with a catalytically active component based on at least one Group VIB metal and at least one Group VIII metal of the Periodic Table of the Elements , more particularly on a combination of cobalt and molybdenum. 10 02 134.