WO1997026069A1

WO1997026069A1 - Method for removing sulfur-containing contaminants, aromatics and hydrocarbons from gas

Info

Publication number: WO1997026069A1
Application number: PCT/NL1997/000018
Authority: WO
Inventors: Jan Adolf Lagas; Theodorus Joseph Petrus Van Pol
Original assignee: Stork Engineers & Contractors B.V.
Priority date: 1996-01-19
Filing date: 1997-01-20
Publication date: 1997-07-24
Also published as: AU1321397A; NL1002134C2; JP2000503293A; CN1208360A; EP0880395A1; TW381043B; CA2241790A1; ZA97370B; KR19990077361A

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

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

This invention relates to a method for purifying gas, more particularly 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 comprises a method for converting mercaptans to H2S in, and removing CO2, absorbed hydrocarbons and aromatics from H2S containing gas to form elemental sulfur from H2S.

In the purification of natural gas, the purification of refinery gases and the purification of synthesis gas, sulfur-containing gases are liberated, in particular H2S, which should be removed in order to limit the emission into the atmosphere of particularly SO2 which is formed upon combustion of such sulfur compounds. The extent to which the sulfur compounds are to be removed from, for instance, natural gas, depends on the intended use of the gas and the quality requirements set. When the gas must satisfy the so-called "pipeline specifications" the H2S content should be reduced to a value lower than 5 mg/Nm3. Requirements are also set with regard to the maximum content of other sulfur compounds. From the prior art a large number of methods are known by which the amount of sulfur compounds in a gas, such as natural gas, can be reduced.

For the removal of sulfur-containing components from gases, the following process route is usually employed. In a first step the gas to be treated is purified, whereby sulfur- containing components are removed from the gas, followed by a recovery of sulfur from these sulfur-containing components, whereafter a sulfur purification step of the residual gas ensues. In this sulfur purification step it is attempted to recover the last percents of sulfur before the residual gas is emitted via the stack into the atmosphere.

In the purification step, processes are used in which often aqueous solvents (absorption agents) are used. These processes are divided into five main groups, viz. chemical solvent processes, physical solvent processes, physical/chemical solvent processes, redox processes, whereby H2S is oxidized directly to sulfur in an aqueous solution and finally a group of fixed bed processes whereby H2S is chemically or physically absorbed or adsorbed or is selectively catalytically oxidized to elemental sulfur. The first three groups mentioned are normally employed in the industry for the removal of large amounts of sulfur-containing components, mostly present in often large amounts of gas. The last two groups are limited with regard to the amount of sulfur to be removed and the concentration of the sulfur-containing components. These processes are therefore less suitable for the removal of high concentrations of sulfur in large industrial gas purification plants. The chemical solvent processes include the so-called amine processes in which use is made of aqueous solutions of alkanolamines or of potassium carbonate solutions.

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

In the group of the physical/chemical processes, the Sulfinol process is well-known. In this process, use is made of a mixture of an alkanolamine with sulfolane dissolved in a small amount of water.

In the three above-mentioned methods, an absorbing device and a regenerator are used. In the absorbing device the sulfur-containing components are chemically or physically bound to the solvent. Through pressure reduction and/or temperature increase in the regenerator the sulfur-containing components are desorbed from the solvent, whereafter the solvent can be re-used. A detailed description of this method is to be found in R.N. Medox "Gas and Liquid Sweetening" Campbell Petroleum Series (1977). In this method, in addition to the sulfur-containing components, also CO2 is wholly or partly removed, depending on the solvent chosen. The removed sulfur compounds together with the CO2 are routed from the regenerator to a sulfur recovery plant in order to recover the sulfur from H2S and other sulfur compounds . A frequently used process for recovering sulfur from the thus obtained sulfur compounds, in particular H2S, is the Claus process. This process is described in detail in H.G. Paskall, "Capability of the modified Claus process", Western Research Development, Calgary, Alberta, Canada, 1979. The Claus process consists of a thermal step followed by typically 2 or 3 reactor steps. In the thermal step one-third of the H2S is combusted to SO2 according to the reaction

H S + 1.5 0₂ → S0₂ + H₂0

whereafter the remainder, that is, 2/3 of the H2S reacts with the SO2 formed, according to the Claus reaction, to form sulfur and water.

2 H S + S0₂ → 3 S + 2 H₂0.

The efficiency of the Claus process is dependent on a number of factors. For instance, the equilibrium of the Claus reaction shifts in the direction of H2S with an increasing water content in the gas. The efficiency of the sulfur recovery plant can be increased by the use of a tail gas sulfur recovery plant; known processes are the SUPERCLAUS™ process and the SCOT process. In the SUPERCLAUS™ process use is made of a catalyst as described in European patent applications nos. 242.920 and 409.353, as well as in international patent application WO-A 95.07856, where this catalyst is employed in a third or fourth reactor stage as described inter alia in "Hydrocarbon Processing" April 1989, pp. 40-42. Using this method, the last residues of H2S present in the process gas stream are selectively oxidized to elemental sulfur according to the reaction

H S + 0.5 0₂ --> S + H 0.

In this way the efficiency of the sulfur recovery unit can easily be raised to 99.5%. The gas fed to the Claus plant may sometimes contain large amounts of CO2, for instance up to 98.5%, which has a highly adverse effect on the flame temperature in the thermal step. A large amount of CO2 can give rise to instability of the flame and moreover the efficiency in the thermal step will decrease, so that the total efficiency of the Claus plant decreases. Also, the gas may contain large amounts of hydrocarbons. When sulfur-containing gas is processed in an oil refinery gas the hydrocarbon content will generally be low, mostly < 2% by volume.

In the purification of natural gas where physical or physical/chemical processes are used, as a result of absorption larger amounts of hydrocarbons and aromatics, respectively, can end up in the gas which is passed to the sulfur recovery plant (Claus gas). In the thermal stage of a Claus plant these hydrocarbons are completely combusted because the rate of reaction of the hydrocarbons with oxygen is higher than the rate of reaction of H2S and oxygen. When large amounts of CO2 are present, the flame temperature will consequently be lower, and hence also the rate of reaction of the components during combustion. As a result, it is possible for soot formation to occur in the flame of the burner of the thermal stage.

Soot formation gives rise to clogging problems in the catalytic reactors of a Claus plant, in particular the first reactor. Also, the ratio between the oxygen requirement for the conversion of H2S to sulfur and the oxygen requirement for the combustion of the hydrocarbons and aromatics can take such values that the Claus process can no longer be properly controlled. These problems are known in the industry.

What is more, in addition to H₂S and the above- mentioned large amounts of CO2, often mercaptans are also present in the gas. In the industry, chemical processes are used in which these mercaptans are not removed from the gas to be purified, for instance natural gas, so that no after-cleaning with a fixed bed process is needed. Often molecular sieves are used for the removal of these mercaptans . However, when such a fixed bed is saturated with mercaptans, the molecular sieves must be regenerated, for which purpose often the purified natural gas is used. This regeneration gas should then be purified in turn. In the regeneration of the molecular sieves, the mercaptans are liberated for the most part at the beginning of the regeneration. There are also processes in which the mercaptans from an after-purification stage are returned to the Claus plant. These mercaptans then give a peak load in the thermal stage of the Claus plant so that the air control is seriously disturbed. Such a process route is described in Oil and Gas

Journal 57, 19 August, 1991, pp. 57 - 59. Moreover, this leads to loss of natural gas, which can easily run up to about 10%.

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

An object of the present invention is inter alia to provide a method for the removal of sulfur-containing contaminants in the form of mercaptans and H₂S from hydrocarbon gas, such as natural gas, which may also contain CO₂ and higher aliphatic and aromatic hydrocarbons, and the recovery of elemental sulfur, in which method the disadvantages outlined above do not occur. More particularly, it is an object of the invention to provide a method whereby the tail gases contain no or only very few harmful substances, so that these can be discharged into the atmosphere without any objection. It is also an object of the invention to provide a method whereby the sulfur-containing contaminants are recovered to a large extent as elemental sulfur, for instance up to an amount of more than 90%, more particularly more than 95%. The present invention provides a simple method for purifying contaminated hydrocarbon gas with recovery of sulfur, according to which method 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 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 step 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 H S to elemental sulfur in the tail gas, and an H₂S-reduced second gas stream, which second gas stream is combusted.

Surprisingly, it has been found that with the method according to the invention, large gas streams can be purified in a very efficient manner, while at the same time stringent requirements with regard to the emission of noxious substances and recovery efficiency of sulfur can be met.

According to the invention, the sour gas is first passed through a hydrogenation reactor, whereby the mercaptans in the gas are converted to H2S with the aid of supplied hydrogen. Thereafter the sour gas is separated in a so-called enrichment unit in two other gases, viz. an H2S-rich gas and a Cθ2-rich gas, which contains the greater part of the CO2, hydrocarbons and aromatics. The C02~rich gas with the hydrocarbons and aromatics present allows of proper burning in an afterburning plant. The heat released in this afterburning can be employed very usefully, for instance for generating steam.

The H2S-rich gas is passed to the sulfur recovery plant. With this method, the H2S concentration can easily be increased 2 to 6 times. This H2S-rich gas can be processed very well in a Claus plant, the great advantage being that the absence of a large part of the CO2, hydrocarbons and aromatics does not cause any additional gas throughput in the plant upon combustion. As a consequence, the Claus plant can be made of much smaller design, while moreover much higher sulfur recovery efficiencies are achieved.

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

The off-gases from this tail gas desulfurization unit are burned in an afterburner. The heat released can be employed usefully for generating steam.

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

As carrier, preferably alumina is used with this kind of catalysts, since this material, in addition to the desired thermal stability, also enables a good dispersion of the active component. As catalytically active material, preferably a combination of cobalt and molybdenum is used.

In the hydrogenation step the mercaptans in the gas are converted to H2S with the aid of the hydrogen supplied. To limit the undesired reaction between H₂S and CO₂ to COS and

H₂O, water vapor is supplied in the hydrogenation step, so that less COS is formed.

An alternative method of preventing COS formation, but without water vapor being supplied, is the installation of a pre-absorber before the hydrogenation stage, whereby the H₂S concentration in the gas is reduced to less than a quarter. The gas from this pre-absorber is then passed through a hydrogenation reactor, whereby all mercaptans are converted to H₂S with the aid of the added hydrogen. The residual H S is then selectively absorbed in a second absorber, of the second absorption step. On balance, the same H₂S enrichment is then obtained as with a single absorber. With this method, however, the risk of COS formation is entirely or largely prevented.

According to a preferred embodiment of the invention, the first absorption step is carried out using a chemical, physical or chemical/physical absorption agent which removes all contaminants from the natural gas. Preferably, this is an absorption agent which is based on sulfolane, in combination with a secondary and/or tertiary amine. As has already been indicated, such systems are known and already being used on a large scale for purifying natural gas, especially when natural gas is liquefied after purification (for instance the SULFINOL-D process). The absorption, as is conventional, is based on a system whereby the contaminants are absorbed in the solvent in a first column, whereafter, when the solvent is loaded with contaminants, this solvent is regenerated in a second column, for instance through heating and/or through pressure reduction. The temperature at which the absorption takes place is to a large extent dependent on the solvent and the pressure used. At the current pressures for natural gas of 2 to 100 bar, the absorption temperature is generally 15 to 50°C, although outside these ranges good results can be obtained as well. The natural gas is preferably purified so as to meet the pipeline specifications, which means that in general not more than 10, more particularly not more than 5 ppm of H₂S may be present.

The gas stream emanating from the first absorption/desorption, which contains the greater part of the contaminants such as H₂S, 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. To that end, however, the gas stream should be heated from the absorption/desorption temperature of about 40°C to the temperature of 200 to 300°C required for the hydrogenation. This heating preferably occurs indirectly and not with a burner arranged in the gas stream, as is conventional. In fact, the disadvantage of direct heating is that direct heating in this case gives rise to substantial soot formation, which can lead to fouling and clogging in the hydrogenation. As has already been indicated hereinabove, measures can be taken to reduce COS formation.

In the second absorption stage, the hydrogenated gas is split into an H₂S-enriched gas and an H2S-reduced gas. This absorption preferably occurs using a solvent based on a secondary or tertiary amine, more particularly with an aqueous solution of methyldiethylamine, optionally in combination 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 manner of operating such processes is comparable to the first absorption stage. The extent of enrichment is preferably at least 2 to 6 times or more, which is partly dependent on the initial concentration of H₂S. The extent of enrichment can be set through an appropriate choice of the construction of the absorber.

The H₂S-enriched gas is fed to the thermal stage of a

Claus plant. Such a plant is known and the manner in which it is operated as regards temperature and pressure has been described in detail in the publications cited in the introduction.

The tail gas from the Claus plant, which still contains residual sulfur compounds is fed, if desired after supplemental hydrogenation, to a tail gas processing apparatus wherein through selective oxidation of the sulfur compounds, elemental sulfur is formed, which is separated in a plant suitable for that purpose, for instance as described in

European patent application no. 655.414. After separation of the sulfur, the remaining gas can be burnt, optionally to form steam, and discharged into the atmosphere.

The selective oxidation is preferably carried out in the presence of a catalyst which selectively converts sulfur compounds to elemental sulfur, for instance the catalysts described in the European and international patent applications mentioned earlier. These publications, whose content is incorporated herein by reference, also indicate the most suitable process conditions, such as temperature and pressure. In general, however, the pressure is not critical, and temperatures may be between the dew point of sulfur and about 300°C, more particularly less than 250°C.

The invention will now be elucidated with reference to two drawings in which in the form of a block diagram the method according to the invention is described. The sour gas, emanating from a first absorption unit (not drawn), in which contaminated natural gas has been separated into, on the one hand, a gas stream with the desired specification and, on the other, the sour gas, is brought in line 1 to the desired hydrogenation temperature, under addition of hydrogen and/or carbon monoxide via line 2, before being passed into the hydrogenation reactor 3. Also, via line 6 water vapor is fed into line 1 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 passed via line 7 to an absorber of a selective absorption/regeneration plant. In this cooling, the water vapor supplied is condensed and via an evaporator 5 recirculated to the hydrogenation reactor 3. The unabsorbed components of the gas, consisting of principally carbon dioxide, hydrocarbons (including aromatics) and a low content of H2S, are directed via line 8 to an afterburner 18 before the gas is discharged via stack 19. The H2S-rich gas mixture coming from the regeneration section of the absorption/regeneration plant 9 is supplied via line 10 to the Claus plant 11, in which the greater part of the sulfur compounds is converted to elemental sulfur 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 sulfur removal stage 14. This sulfur removal stage can be a known sulfur removal process, such as, for instance, a dry bed oxidation stage, an absorption stage, or a liquid oxidation stage. The required air for the oxidation is supplied via line 15. The sulfur formed is discharged via line 16. The gas is then passed via line 17 to the afterburner 18 before the gas is discharged via stack 19.

As is indicated in Fig. 2, the sour gas, coming from a first absorption unit (not drawn) in which contaminated natural gas has been split into, on the one hand, a gas stream with the desired specification and, on the other, the sour gas, is passed via line 1 to a pre-absorber 2 of an absorption/regeneration plant, further consisting of a second absorber and a regenerator 9.

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

In the hydrogenation reactor 5 the mercaptans and other organic sulfur compounds present in the gas are converted to H₂S. The gas from the hydrogenation reactor, after cooling, is passed via line 6 to a second absorber. The unabsorbed components of the gas, substantially consisting of carbon dioxide, hydrocarbons (including aromatics) and a minimal amount of H₂S, are routed via line 8 to the afterburner 21 before the gas is discharged via stack 22. The H₂S-rich gas mixture, coming from the regenerator

9, is fed via line 13 to the Claus plant 14, in which the greater part of the sulfur compounds is converted to elemental sulfur which is discharged via line 15.

The regenerated absorption agent 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 loaded with H₂S and CO₂ is returned via line 12 to regenerator 9.

To increase the efficiency of the Claus plant, the tail gas is passed via line 16 to a tail gas sulfur removal stage 18. This sulfur removal stage can be a known sulfur removal process such as a dry bed oxidation stage, an absorption stage or a liquid oxidation stage. The required air for the oxidation is supplied via line 17. The sulfur formed is discharged via line 19. The gas is then passed via line 20 to the afterburner 21 before the gas is discharged via stack 22.

The invention is elucidated in and by the following non-limiting example.

EXAMPLE 1

An amount of sour gas of 15545 Nm³/h coming from the regenerator of a gas purification 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 vol. % C H₅SH

0.03 vol. % C3H7SH

0.01 vol.% C4H9SH

81.53 vol.% C0₂

4.23 vol.% H₂0

3.51 vol.% Hydrocarbons (Cι_ to C17)

1.08 vol. % Aromatics (Benzene, Toluene, Xylene)

To this sour gas was supplied 3000 Nm^/h reducing gas containing hydrogen and carbon monoxide and then heated to 205°C to hydrogenate all mercaptans present to H2S in the hydrogenation reactor which contains a sulfided group 6 and/or group 8 metal catalyst, in this case a Co-Mo catalyst. Also supplied to this sour gas was 7000 Nm³/h water vapor to suppress COS formation in the hydrogenation reactor.

The temperature of the gas from the reactor was 226°C. The sour gas was then cooled to 46°C and the water vapor contained therein was condensed. This condensation was recirculated, via an evaporator, to the sour gas which is passed to the hydrogenation reactor.

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

8.08 vol.% H₂S

50 ppm vol . COS

69.78 vol.% C0₂

6.4 vol.% H₂0

2.94 vol.% Hydrocarbons (C^ to C17)

0.91 vol.% Aromatics (Benzene, Toluene, Xylene)

1.03 vol.% H

10.86 vol.% N₂

Thereafter the cooled gas was contacted in an absorber of a gas purification plant with a methyldietanolamine solution, whereby the H2S and a part of the CO2 were absorbed. The amount of product gas (C02^_rich gas) from the absorber was 15680 Nm³/h with the following composition:

74.54 vol.% C0₂

500 ppm vol. H₂S

60 ppm vol. COS

6.78 vol.% H₂0

3.48 vol.% Hydrocarbons (C_ to ±-j )

1.07 vol.% Aromatics (Benzene, Toluene, Xylene)

1.21 vol.% H

12.86 vol.% N₂

Via an afterburning, this gas was passed to the stack. After desorption in a regenerator the sour H2S/CO2 gas mixture (H2S-rich gas) was passed to a sulfur recovery plant. This H2S/CO2 gas mixture amounted to 2870 Nm³/h and had the following composition at 40°C and 1.7 bar abs.

51.9 vol. ,% H₂S

43.8 vol. .% C0₂

4.3 vol . .% H₂0

To the burner of the thermal stage of the sulfur recovery plant was supplied 2975 Nm³/h air, so that after the second Claus reactor stage 1.14 vol.% H2S and 0.07 vol .% SO2 was present in the process gas. The process gas was then fed to the tail gas sulfur removal stage, consisting of a selective H2S oxidation reactor.

To this gas was supplied 310 Nm³/h air. 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 the International patent application WO-A 95/07856. The sulfur formed in the sulfur recovery plant was condensed after each stage and discharged. The exiting inert gas was passed via an afterburning to the stack. The amount of sulfur was 2094 kg/h. The total desulfurization efficiency based on the original sour gas, which contained 9.0 vol.% H2S, was 97.7%.

Claims

£LAJLM£

1. 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 step 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.

2. A method according to claim 1, wherein the first absorption step is carried out utilizing a chemical, physical, or chemical/physical absorption agent, which removes substantially all sulfur compounds and CO₂.

3. A method according to claim 2, wherein the absorption agent 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 utilizing an absorption agent based on a secondary and/or tertiary amine.

5. A method according to claims 1-4, wherein the first absorption step is carried out in such a manner that the gas contains not more than 10, more particularly not more than 5 ppm of sulfur-containing contaminants.

6. A method according to claim 5, wherein the gas is natural gas, which is optionally liquefied after the purification.

7. A method according to claims 1-6, wherein the second absorption step is carried out in such a manner that the content of H₂S in the first gas stream is at least 2.5 times, more particularly at least 4 times higher than the content of H₂S in the sour gas.

8. A method according to claims 1-7, wherein the content of mercaptans in the hydrogenated gas stream is less than 1 ppm.

9. A method according to claims 1-8, wherein the hydrogenation occurs in the presence of a catalyst on support, with a catalytically active component based on at least one metal from Group VIB and at least one metal from Group VIII of the Periodic System of the Elements, more particularly on a combination of cobalt and molybdenum.