CA2243482A1 - Method for removing sulfur-containing contaminants, aromatics and hydrocarbons from gas - Google Patents
Method for removing sulfur-containing contaminants, aromatics and hydrocarbons from gas Download PDFInfo
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- CA2243482A1 CA2243482A1 CA002243482A CA2243482A CA2243482A1 CA 2243482 A1 CA2243482 A1 CA 2243482A1 CA 002243482 A CA002243482 A CA 002243482A CA 2243482 A CA2243482 A CA 2243482A CA 2243482 A1 CA2243482 A1 CA 2243482A1
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1406—Multiple stage absorption
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
- B01D53/75—Multi-step processes
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
- B01D53/86—Catalytic processes
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
- B01D53/86—Catalytic processes
- B01D53/8603—Removing sulfur compounds
- B01D53/8612—Hydrogen sulfide
-
- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B17/00—Sulfur; Compounds thereof
- C01B17/02—Preparation of sulfur; Purification
- C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
- C01B17/0404—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process
- C01B17/0408—Pretreatment of the hydrogen sulfide containing gases
Abstract
This invention relates to a method for removing sulfur-containing contaminants in the form of mercaptans and H2S from natural 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 fed to a second absorption step in which the sour gas is separated into an H2S-enriched and mercaptan-reduced 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 and mercaptan-enriched second gas stream, which second gas stream, if desired after further treatment, is subjected to a selective oxidation of sulfur compounds to elemental sulfur.
Description
W O 97/26070 PCTA~L97/00019 Title: Method for removi-ng sulfur-containing contaminants, aromatics and hydrocarbons from gas This invention relates to a method for purifying hydrocarbon gas, more particularly natural gas, which is contaminated with sulfur compounds in the form of ~2S and mercaptans, as well as with CO~. More particularly, the invention comprises a method for converting mercaptans to H2S
in, and removing Co2 and adsorbed 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 m~;mllm 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.
W O 97/26070 PCTn~L97/00019 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.~. 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.
W 097126070 ~ L97~0019 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 H2S + 1 5 ~2 -~ S~2 + H2O
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.
in, and removing Co2 and adsorbed 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 m~;mllm 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.
W O 97/26070 PCTn~L97/00019 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.~. 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.
W 097126070 ~ L97~0019 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 H2S + 1 5 ~2 -~ S~2 + H2O
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 H2S + 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 SCO~ 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.
WO 97/26070 PC~L97/00019 Using this method, the last residues of H2S present in the process gas stream are selectively oxidized to elemental sulfur according to the reaction H2S + 0 5 ~2 ~~> S + H2O.
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 th~rm~l 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 re~uirement for the combustion of the hydrocarbons and aromatics can take WO 97/26070 PCT~L97~000~9 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 fi~ed 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 ~ournal 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 2S 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-cont~i n; ng cont~m;n~nts in the form of mercaptans and H2S from hydrocarbon 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 W O 97/26070 PCT~L97/00019 -invention to provide a method whereby the sulfur-containing cont~m;n~nts are recovered to a large extent as elemental sulfur, for instance up to an amount of more than 90~, more particularly more than 95%.
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.
The present invention provides a simple method for purifying contAm;n~ted hydrocarbon gas with recovery of sulfur, according to which method in a first absorption step the sulfur-containing con~min~nts 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 fed to a second absorption step in which the soùr gas is separated into an H2S-enriched and mercaptan-reduced 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 and mercaptan-enriched second gas stream, which second gas stream, if desired after further treatment, is subjected to a selective oxidation of sulfur compounds to elemental sulfur.
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 cont~min~nts 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.
The absorption, as is conventional, is ~ased on a system whereby the cont~min~nts are absorbed in the solvent in a first column, whereafter, when the solvent is loaded with cont~min~nts, 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 WO 97126070 PCT~L97/OOOI9 is to a large extent dependent on the solvent and the pressure used. At the current pressures for natural gas of 2 to 10 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.
According to the method of the invention, in a second absorption stage the sour gas is first separated into two other gases, viz. an H2S-rich gas and a CO2-rich gas, which in addition to CO2 contains hydrocarbons, aromatics and the unabsorbed mercaptans. With this method the H2S
concentration can be increased 2 to 6 times.
This second absorption preferably occurs using a solvent based on a secondary or tertiary amine, more particularly with an aqueous solution of methyldiethanolamine, 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-rich first gas stream can be processed very well in the Claus plant, while 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.
Such a Claus plant is known and the manner in which it is operated as regards temperature, pressure and the like is described in detail in the publications cited in the introduction.
W O 97/26070 PCT~NL97/~0019 -The tail gas from the Claus plant, which still contains residual sulfur compounds is fed, if desired after additional 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 suita~le for that purpose, for instance as described in European patent application no. 655.414.
After separation of the sulfur, the remaining gas can be combusted in an afterburner. The heat released can be employed usefully for generating steam.
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 ~e between the dew point of sulfur and about 3~0~C, more particularly less than 250~C.
The CO2-rich second gas stream with the hydrocarbons, aromatics and mercaptans present, is admixed with the tail gas from the Claus sulfur recovery plant and passed to the tail gas recovery plant based on selective oxidation of the sulfur compounds to elemental sulfur. The tail gas recovery plant in this case is preferably the SUP~RCLAUS reactor stage, whereby the mercaptans are oxidized to elemental sulfur with the oxygen present.
Alternatively, the CO2-rich gas can also be treated separately in a SUPERCLAUS reactor stage. When the mercaptan content of the gas is high, it may ~e requisite to cool the SUPERCLAUS reactor to prevent the possibility of the temperature running up too high, as a result of which the selectivity decreases and too large an amount of SO2 is formed.
According to another embodiment of the method according to the invention, the CO2-rich gas, the second gas stream, coming from the enrichment unit, 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, pre~erably a combination of cobalt and molybdenum is used.
For the hydrogenation, 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 and the subsequent selective oxidation.
In the hydrogenation step the mercaptans in the gas are converted to H2S with the aid of the hydrogen supplied.
The CO2-rich gas from the hydrogenation step, containing CO2, H2S, hydrocarbons and aromatics, is a~m;~ with the tail gas from the Claus plant and then passed to the tail gas sulfur recovery unit, preferably a SUPERCLAUS reactor stage.
The gas from the hydrogenation reactor can also be treated in a separate SUPERCLAUS reactor.
It may be necessary to cool the SUPERCLAUS reactor to prevent the temperature of the catalyst from running up too high.
As has been indicated, the gas coming from the selective oxidation is finally combusted, whereby the residual organic contaminants are converted to water and CO2.
The invention will now be elucidated with reference to a few drawings, Fig. 1 showing in the form of a block diagram the variant with an additional hydrogenation step of the second, low-H2S gas stream. Fig. 2 shows the variant without hydrogenation.
-W 097/26070 PCT~NL97/00019 As is indicated in Fig. 1, 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 specifications and, on the other, the sour gas, is passed via line 1 to an absorber of a selective absorption/regeneration plant 3. The unabsorbed components of the gas, consisting of principally carbon dioxide, hydrocarbons (including aromatics), mercaptans and a low content of H2S, are directed via line 2 to the hydrogenation reactor 6. In line 2 the gas is brought to the desired hydrogenation temperature, under addition of hydrogen and/or carbon monoxide, before being passed into the hydrogenation reactor 6.
In the hydrogenation reactor 6 the mercaptans and other organic sulfur compounds present in the gas are converted to H2S. The gas from the hydrogenation reactor 6, after cooling, is passed via line 5 to the tail gas sulfur removal stage 11 of the Claus plant 8 to convert the H2S
present to elemental sulfur.
The H2S-rich gas mixture coming from the regeneration section of the absorption/regeneration plant 3 is supplied via line 7 to the Claus plant 8, in which the greater part of the sulfur compounds is converted to elemental sulfur, which is discharged via line 9.
To increase the efficiency of the Claus plant 8, the tail gas is passed via line 10 to a tail gas sulfur removal stage ll. 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 12. The sulfur formed is discharged via line 13.
The gas is then passed via line 14 to the afterburner 15 before the gas is discharged via stack 16.
As is indicated in Fig. 2, the sour gas, coming from a first absorption unit (not drawn) in which cont~m'n~ted natural gas has been split into, on the one hand, a gas stream with the desired specifications and, on the other, the sour W O 97/26U70 11 PCT~L97/OOO19 gas, is passed via line 1 to an absorber of an absorption/regeneration plant 3.
The H2S-rich gas mixture coming from the regeneration section of the absorption/regeneration plant 3 is supplied via line 4 to the Claus plant 5, in which the greater part of the sulfur compounds is converted to elemental sulfur, which is discharged via line 6.
To increase the efficiency of the Claus plant 5, the tail gas is passed via line 7 to a tail gas sulfur removal stage 8. The sulfur removal stage 8 operates according to the dry bed oxidation principle.
The unabsorbed components of the gas coming from the absorption section of the absorption/regeneration plant, consisting of principally carbon dioxide, hydrocarbons (including aromatics), mercaptans and a low content of H2S, are directed via line 2 to the oxidation reactor of the tail gas sulfur removal stage 8. The required air for oxidation of H2S and mercaptans is supplied via line 9. To limit the temperature rise in the oxidation reactor, cooled process gas is recirculated from line 12 to line 7 with the aid of a condenser 14. The sulfur formed is discharged via line 11. The gas is then passed via line 12 to the afterburner 16 before the gas is discharged via stack 17.
The invention is elucidated in and by the following examples, which are not intended as a limitation.
W 097/26070 PCTn~L97100019 EXAMPLE
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
0~01 vol.% COS
0.22 vol.% CH3SH
0.38 vol.% C2H5SH
0.03 vol.% C3H7SH
0.01 vol.% C4HgSH
81.53 vol.% CO2 4.23 vol.% H2O
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 SCO~ 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.
WO 97/26070 PC~L97/00019 Using this method, the last residues of H2S present in the process gas stream are selectively oxidized to elemental sulfur according to the reaction H2S + 0 5 ~2 ~~> S + H2O.
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 th~rm~l 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 re~uirement for the combustion of the hydrocarbons and aromatics can take WO 97/26070 PCT~L97~000~9 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 fi~ed 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 ~ournal 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 2S 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-cont~i n; ng cont~m;n~nts in the form of mercaptans and H2S from hydrocarbon 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 W O 97/26070 PCT~L97/00019 -invention to provide a method whereby the sulfur-containing cont~m;n~nts are recovered to a large extent as elemental sulfur, for instance up to an amount of more than 90~, more particularly more than 95%.
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.
The present invention provides a simple method for purifying contAm;n~ted hydrocarbon gas with recovery of sulfur, according to which method in a first absorption step the sulfur-containing con~min~nts 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 fed to a second absorption step in which the soùr gas is separated into an H2S-enriched and mercaptan-reduced 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 and mercaptan-enriched second gas stream, which second gas stream, if desired after further treatment, is subjected to a selective oxidation of sulfur compounds to elemental sulfur.
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 cont~min~nts 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.
The absorption, as is conventional, is ~ased on a system whereby the cont~min~nts are absorbed in the solvent in a first column, whereafter, when the solvent is loaded with cont~min~nts, 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 WO 97126070 PCT~L97/OOOI9 is to a large extent dependent on the solvent and the pressure used. At the current pressures for natural gas of 2 to 10 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.
According to the method of the invention, in a second absorption stage the sour gas is first separated into two other gases, viz. an H2S-rich gas and a CO2-rich gas, which in addition to CO2 contains hydrocarbons, aromatics and the unabsorbed mercaptans. With this method the H2S
concentration can be increased 2 to 6 times.
This second absorption preferably occurs using a solvent based on a secondary or tertiary amine, more particularly with an aqueous solution of methyldiethanolamine, 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-rich first gas stream can be processed very well in the Claus plant, while 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.
Such a Claus plant is known and the manner in which it is operated as regards temperature, pressure and the like is described in detail in the publications cited in the introduction.
W O 97/26070 PCT~NL97/~0019 -The tail gas from the Claus plant, which still contains residual sulfur compounds is fed, if desired after additional 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 suita~le for that purpose, for instance as described in European patent application no. 655.414.
After separation of the sulfur, the remaining gas can be combusted in an afterburner. The heat released can be employed usefully for generating steam.
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 ~e between the dew point of sulfur and about 3~0~C, more particularly less than 250~C.
The CO2-rich second gas stream with the hydrocarbons, aromatics and mercaptans present, is admixed with the tail gas from the Claus sulfur recovery plant and passed to the tail gas recovery plant based on selective oxidation of the sulfur compounds to elemental sulfur. The tail gas recovery plant in this case is preferably the SUP~RCLAUS reactor stage, whereby the mercaptans are oxidized to elemental sulfur with the oxygen present.
Alternatively, the CO2-rich gas can also be treated separately in a SUPERCLAUS reactor stage. When the mercaptan content of the gas is high, it may ~e requisite to cool the SUPERCLAUS reactor to prevent the possibility of the temperature running up too high, as a result of which the selectivity decreases and too large an amount of SO2 is formed.
According to another embodiment of the method according to the invention, the CO2-rich gas, the second gas stream, coming from the enrichment unit, 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, pre~erably a combination of cobalt and molybdenum is used.
For the hydrogenation, 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 and the subsequent selective oxidation.
In the hydrogenation step the mercaptans in the gas are converted to H2S with the aid of the hydrogen supplied.
The CO2-rich gas from the hydrogenation step, containing CO2, H2S, hydrocarbons and aromatics, is a~m;~ with the tail gas from the Claus plant and then passed to the tail gas sulfur recovery unit, preferably a SUPERCLAUS reactor stage.
The gas from the hydrogenation reactor can also be treated in a separate SUPERCLAUS reactor.
It may be necessary to cool the SUPERCLAUS reactor to prevent the temperature of the catalyst from running up too high.
As has been indicated, the gas coming from the selective oxidation is finally combusted, whereby the residual organic contaminants are converted to water and CO2.
The invention will now be elucidated with reference to a few drawings, Fig. 1 showing in the form of a block diagram the variant with an additional hydrogenation step of the second, low-H2S gas stream. Fig. 2 shows the variant without hydrogenation.
-W 097/26070 PCT~NL97/00019 As is indicated in Fig. 1, 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 specifications and, on the other, the sour gas, is passed via line 1 to an absorber of a selective absorption/regeneration plant 3. The unabsorbed components of the gas, consisting of principally carbon dioxide, hydrocarbons (including aromatics), mercaptans and a low content of H2S, are directed via line 2 to the hydrogenation reactor 6. In line 2 the gas is brought to the desired hydrogenation temperature, under addition of hydrogen and/or carbon monoxide, before being passed into the hydrogenation reactor 6.
In the hydrogenation reactor 6 the mercaptans and other organic sulfur compounds present in the gas are converted to H2S. The gas from the hydrogenation reactor 6, after cooling, is passed via line 5 to the tail gas sulfur removal stage 11 of the Claus plant 8 to convert the H2S
present to elemental sulfur.
The H2S-rich gas mixture coming from the regeneration section of the absorption/regeneration plant 3 is supplied via line 7 to the Claus plant 8, in which the greater part of the sulfur compounds is converted to elemental sulfur, which is discharged via line 9.
To increase the efficiency of the Claus plant 8, the tail gas is passed via line 10 to a tail gas sulfur removal stage ll. 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 12. The sulfur formed is discharged via line 13.
The gas is then passed via line 14 to the afterburner 15 before the gas is discharged via stack 16.
As is indicated in Fig. 2, the sour gas, coming from a first absorption unit (not drawn) in which cont~m'n~ted natural gas has been split into, on the one hand, a gas stream with the desired specifications and, on the other, the sour W O 97/26U70 11 PCT~L97/OOO19 gas, is passed via line 1 to an absorber of an absorption/regeneration plant 3.
The H2S-rich gas mixture coming from the regeneration section of the absorption/regeneration plant 3 is supplied via line 4 to the Claus plant 5, in which the greater part of the sulfur compounds is converted to elemental sulfur, which is discharged via line 6.
To increase the efficiency of the Claus plant 5, the tail gas is passed via line 7 to a tail gas sulfur removal stage 8. The sulfur removal stage 8 operates according to the dry bed oxidation principle.
The unabsorbed components of the gas coming from the absorption section of the absorption/regeneration plant, consisting of principally carbon dioxide, hydrocarbons (including aromatics), mercaptans and a low content of H2S, are directed via line 2 to the oxidation reactor of the tail gas sulfur removal stage 8. The required air for oxidation of H2S and mercaptans is supplied via line 9. To limit the temperature rise in the oxidation reactor, cooled process gas is recirculated from line 12 to line 7 with the aid of a condenser 14. The sulfur formed is discharged via line 11. The gas is then passed via line 12 to the afterburner 16 before the gas is discharged via stack 17.
The invention is elucidated in and by the following examples, which are not intended as a limitation.
W 097/26070 PCTn~L97100019 EXAMPLE
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
0~01 vol.% COS
0.22 vol.% CH3SH
0.38 vol.% C2H5SH
0.03 vol.% C3H7SH
0.01 vol.% C4HgSH
81.53 vol.% CO2 4.23 vol.% H2O
3.51 vol.% Hydrocarbons (Cl to C17) 15 1.08 vol.% Aromatics (Benzene, Toluene, Xylene) This sour gas was contacted in an absorber of a gas purification plant with a methyldiethanolamine solution, whereby the H2S and a part of the CO2 were absorbed.
The amount of product gas (CO2-rich gas) from the absorber was 13000 Nm3/h with the following composition:
88.47 vol.% C~2 500 ppm vol. H2S
25 70 ppm vol. COS
0.26 vol.% CH3SH
0.46 vol.% C2H5SH
0.04 vol.~ C3H7SH
0.01 vol.% C4HgSH
5.21 vol.% H2O
The amount of product gas (CO2-rich gas) from the absorber was 13000 Nm3/h with the following composition:
88.47 vol.% C~2 500 ppm vol. H2S
25 70 ppm vol. COS
0.26 vol.% CH3SH
0.46 vol.% C2H5SH
0.04 vol.~ C3H7SH
0.01 vol.% C4HgSH
5.21 vol.% H2O
4.2 vol.% Hydrocar~ons (cl to C17) 1.29 vol.% Aromatics (Benzene, Toluene, Xylene) To this product gas was supplied 2700 Nm3/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 contained a sulfided group 6 CA 02243482 l998-07-l7 W 097126~70 13 PCT~NL97/OOOI9 and/or group 8 metal catalyst, which is supported on an alumina carrier, in this case a Co-Mo catalyst.
The temperature of the gas from the reactor was 232~C. The sour gas was then cooled to 226~C and supplied to the tail gas sulfur removal stage of the sulfur recovery plant. The amount of the gas coming from the hydrogenation reactor was 15700 Nm3/h and had the following composition:
0.68 vol.% H2S
10 60 ppm vol. COS
74.22 vol.~ C~2 8.14 vol.~ H2O
3.48 vol.% Hydrocarbons (C1 to C17) 1.07 vol.% Aromatics (Benzene, Toluene, Xylene) 0.86 vol.~ H2 11.56 vol.% N2 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 was 2690 Nm3/h and had the following composition at 40~C and 1.7 bar abs.
51.7 vol.% H2S
44.0 vol.% CO2 4.3 vol.% H2O
To the burner of the thermal stage of the sulfur recovery plant was supplied 2780 Nm3/h air, so that after the second ~laus 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.
To this gas was supplied 875 Nm3/h air. The inlet temperature of the selective oxidation reactor was 220~C and the outlet temperature was 267~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.
CA 02243482 l998-07-l7 W O 97/26070 14 PCTn~L97/00019 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 2068 kg/h. The total desulfurization efficiency based on the original sour gas, which contained 9.0 vol.% H2S, was 96.5%.
An amount of sour gas of 15545 Nm3/h coming from the regenerator of a gas puri~ication plant had the following 10 composition at 40~C and a pressure of 1.70 bar abs.
9.0 vol.% H2S
0.01 vol.% COS
0.22 vol.% CH3SH
0.38 vol.% C2H5SH
0.03 vol.% C3H7SH
0.01 vol.% C4HgSH
81.53 vol.% CQ2 4.23 vol.% H2O
3.51 vol.% Hydrocarbons (C1 to C17) 20 1.08 vol.% Aromatics (Benzene, Toluene, Xylene) This sour gas was contacted in an absorber of a gas purification plant with a methyldiethanolamine solution, whereby the H2S and a part of the CO2 were absorbed.
The amount of product gas (CO2-rich gas) from the absorber was 13000 Nm3/h with the following composition:
88.47 vol.% C~2 S00 ppm vol. H2S
30 70 ppm vol. COS
0.26 vol.% CH3SH
0.46 vol.% C2H5SH
0.04 vol.% C3H7SH
0.01 vol.% C4HgSH
35 5.21 vol.% H2O
4.2 vol.% Hydrocarbons (C1 to C17) 1.29 vol.% Aromatics (Benzene, Toluene, Xylene) CA 02243482 l998-07-l7 WO 97/26070 PC~L97~aaI9 The product gas was then heated to 230~C and fed to the tail gas sulfur removal stage of the sulfur recovery plant.
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 2690 Nm3/h and had the following composition at 40~C and 1.7 bar abs.
51.7 vol.% H2S
44.0 vol.% CO2 4.3 vol.% H2~
To the burner of the thermal stage of the sulfur recovery plant was supplied 2780 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.
To this gas and the supplied product gas was supplied 875 Nm3/h air. The inlet temperature of the selective oxidation reactor was 230~C and the outlet temperature was 290~C. To limit the temperature rise in the oxidation reactor to 60~C, 13000 Nm3/h of the gas cooled after the reactor was recirculated over the reactor. The selective oxidation reactor was filled with catalyst as described in European patents 242.920 and 409.353 and in the International patent application no. 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 to the stack via an afterburning. The amount of sulfur was 2050 ~g/h. The total desulfurization efficiency based on the original sour gas, which contained 9.0 vol.% H2S, was 95.7%.
The temperature of the gas from the reactor was 232~C. The sour gas was then cooled to 226~C and supplied to the tail gas sulfur removal stage of the sulfur recovery plant. The amount of the gas coming from the hydrogenation reactor was 15700 Nm3/h and had the following composition:
0.68 vol.% H2S
10 60 ppm vol. COS
74.22 vol.~ C~2 8.14 vol.~ H2O
3.48 vol.% Hydrocarbons (C1 to C17) 1.07 vol.% Aromatics (Benzene, Toluene, Xylene) 0.86 vol.~ H2 11.56 vol.% N2 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 was 2690 Nm3/h and had the following composition at 40~C and 1.7 bar abs.
51.7 vol.% H2S
44.0 vol.% CO2 4.3 vol.% H2O
To the burner of the thermal stage of the sulfur recovery plant was supplied 2780 Nm3/h air, so that after the second ~laus 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.
To this gas was supplied 875 Nm3/h air. The inlet temperature of the selective oxidation reactor was 220~C and the outlet temperature was 267~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.
CA 02243482 l998-07-l7 W O 97/26070 14 PCTn~L97/00019 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 2068 kg/h. The total desulfurization efficiency based on the original sour gas, which contained 9.0 vol.% H2S, was 96.5%.
An amount of sour gas of 15545 Nm3/h coming from the regenerator of a gas puri~ication plant had the following 10 composition at 40~C and a pressure of 1.70 bar abs.
9.0 vol.% H2S
0.01 vol.% COS
0.22 vol.% CH3SH
0.38 vol.% C2H5SH
0.03 vol.% C3H7SH
0.01 vol.% C4HgSH
81.53 vol.% CQ2 4.23 vol.% H2O
3.51 vol.% Hydrocarbons (C1 to C17) 20 1.08 vol.% Aromatics (Benzene, Toluene, Xylene) This sour gas was contacted in an absorber of a gas purification plant with a methyldiethanolamine solution, whereby the H2S and a part of the CO2 were absorbed.
The amount of product gas (CO2-rich gas) from the absorber was 13000 Nm3/h with the following composition:
88.47 vol.% C~2 S00 ppm vol. H2S
30 70 ppm vol. COS
0.26 vol.% CH3SH
0.46 vol.% C2H5SH
0.04 vol.% C3H7SH
0.01 vol.% C4HgSH
35 5.21 vol.% H2O
4.2 vol.% Hydrocarbons (C1 to C17) 1.29 vol.% Aromatics (Benzene, Toluene, Xylene) CA 02243482 l998-07-l7 WO 97/26070 PC~L97~aaI9 The product gas was then heated to 230~C and fed to the tail gas sulfur removal stage of the sulfur recovery plant.
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 2690 Nm3/h and had the following composition at 40~C and 1.7 bar abs.
51.7 vol.% H2S
44.0 vol.% CO2 4.3 vol.% H2~
To the burner of the thermal stage of the sulfur recovery plant was supplied 2780 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.
To this gas and the supplied product gas was supplied 875 Nm3/h air. The inlet temperature of the selective oxidation reactor was 230~C and the outlet temperature was 290~C. To limit the temperature rise in the oxidation reactor to 60~C, 13000 Nm3/h of the gas cooled after the reactor was recirculated over the reactor. The selective oxidation reactor was filled with catalyst as described in European patents 242.920 and 409.353 and in the International patent application no. 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 to the stack via an afterburning. The amount of sulfur was 2050 ~g/h. The total desulfurization efficiency based on the original sour gas, which contained 9.0 vol.% H2S, was 95.7%.
Claims (14)
1. A method for removing sulfur-containing contaminants in the form of mercaptans and H2S from 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 fed to a second absorption step in which the sour gas is separated into an H2S-enriched and mercaptan-reduced 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 and mercaptan-enriched second gas stream, which second gas stream, if desired after further treatment, is subjected to a selective oxidation of sulfur compounds to elemental sulfur.
2. A method according to claim 1, wherein said second gas stream is hydrogenated prior to the selective oxidation.
3. A method according to claim 1 or 2, wherein said selective oxidation of the tail gas of the first gas stream and of the second gas stream occurs in the same reactor.
4. A method according to claim 1 or 2, wherein said selective oxidation of the tail gas of the first gas stream and of the second gas stream occurs in two separate reactors.
5. A method according to claims 1-4, 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 from the gas.
6. A method according to claim 5, wherein as absorption agent sulfolane, in combination with a secondary or tertiary amine, is used.
7. A method according to claims 1-6, wherein the second absorption step is carried out utilizing an absorption agent based on a secondary and/or tertiary amine.
8. A method according to claims 1-7, wherein the first absorption step is carried out in such a manner that the purified gas contains not more than 10, more particularly not more than 5 ppm of sulfur-containing contaminants.
9. A method according to claims 1-8, wherein natural gas is used as the gas to be purified, which is optionally liquefied after the purification.
10. A method according to claims 1-9, 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.
11. A method according to claims 1-10, wherein the content of mercaptans in the first gas stream is less than 1 ppm.
12. A method according to claims 2-11, 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.
13. A method according to claims 2-12, wherein the hydrogenation occurs in the presence of an amount of water.
14. A method according to claims 2-13, wherein the second gas stream is heated indirectly prior to the hydrogenation.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| NL1002135 | 1996-01-19 | ||
| NL1002135A NL1002135C2 (en) | 1996-01-19 | 1996-01-19 | Method for removing sulfur-containing impurities, aromatics and hydrocarbons from gas. |
Publications (1)
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|---|---|
| CA2243482A1 true CA2243482A1 (en) | 1997-07-24 |
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| CA002243482A Abandoned CA2243482A1 (en) | 1996-01-19 | 1997-01-20 | Method for removing sulfur-containing contaminants, aromatics and hydrocarbons from gas |
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| Country | Link |
|---|---|
| EP (1) | EP0885052A1 (en) |
| JP (1) | JP2000507151A (en) |
| KR (1) | KR19990077362A (en) |
| CN (1) | CN1209756A (en) |
| AU (1) | AU1321497A (en) |
| CA (1) | CA2243482A1 (en) |
| ID (1) | ID15833A (en) |
| NL (1) | NL1002135C2 (en) |
| TW (1) | TW372883B (en) |
| WO (1) | WO1997026070A1 (en) |
| ZA (1) | ZA97326B (en) |
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| GB0021409D0 (en) | 2000-08-31 | 2000-10-18 | Boc Group Plc | Treatment of a gas stream containing hydrogen sulphide |
| JP4837176B2 (en) * | 2001-03-07 | 2011-12-14 | 千代田化工建設株式会社 | Method for removing sulfur compounds from natural gas |
| DE10208253A1 (en) * | 2002-02-26 | 2003-09-04 | Lurgi Ag | Process for the removal of mercaptan from raw gas |
| DE10219900B4 (en) * | 2002-05-03 | 2004-08-26 | Lurgi Ag | Process for the purification of hydrocarbon gas |
| FR2875236B1 (en) * | 2004-09-10 | 2006-11-10 | Total Sa | METHOD AND INSTALLATION FOR TREATING DSO |
| FR2916652B1 (en) * | 2007-05-30 | 2009-07-24 | Inst Francais Du Petrole | PROCESS FOR INTEGRATED TREATMENT OF A NATURAL GAS FOR COMPLETE DEACIDIFICATION |
| CN101480560B (en) * | 2008-01-09 | 2011-11-30 | 中国石油化工股份有限公司 | Method for processing Claus tail gases by membrane separation |
| CA2745032A1 (en) * | 2008-11-28 | 2010-06-03 | Shell Internationale Research Maatschappij B.V. | Process for producing purified natural gas |
| JP6358631B2 (en) * | 2014-04-16 | 2018-07-18 | サウジ アラビアン オイル カンパニー | Improved sulfur recovery process for treating low to medium mole percent hydrogen sulfide gas feed containing BTEX in a Claus unit |
| RU2649442C2 (en) * | 2016-04-25 | 2018-04-03 | Общество с ограниченной ответственностью "Старт-Катализатор" | Apparatus, method and catalyst for the purification of a gaseous raw hydrocarbon from hydrogen sulfide and mercaptans |
| WO2018115919A1 (en) * | 2016-12-23 | 2018-06-28 | Total Sa | Integrated process for elemental sulphur treatment |
| CN108452652B (en) * | 2017-12-04 | 2021-06-08 | 盐城市兰丰环境工程科技有限公司 | Industrial gas desulfurization system |
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| US4088735A (en) * | 1974-07-10 | 1978-05-09 | Metallgesellschaft Aktiengesellschaft | Process for purifying gases from the gasification of fossil fuels |
| US3989811A (en) * | 1975-01-30 | 1976-11-02 | Shell Oil Company | Process for recovering sulfur from fuel gases containing hydrogen sulfide, carbon dioxide, and carbonyl sulfide |
| FR2501663A1 (en) * | 1981-03-13 | 1982-09-17 | Technip Cie | Simultaneous removal of carbon di:oxide and hydrogen sulphide - from natural gas etc., and recovery as conc. carbon di:oxide and sulphur |
| US4356161A (en) * | 1981-08-24 | 1982-10-26 | Shell Oil Company | Process for reducing the total sulfur content of a high CO2 -content feed gas |
| DE4206943A1 (en) * | 1992-03-05 | 1993-09-09 | Krupp Koppers Gmbh | METHOD FOR PURIFYING A GAS GIVEN BY CARBURATING CARBONATED MATERIAL |
-
1996
- 1996-01-19 NL NL1002135A patent/NL1002135C2/en not_active IP Right Cessation
-
1997
- 1997-01-15 ZA ZA97326A patent/ZA97326B/en unknown
- 1997-01-17 TW TW086100466A patent/TW372883B/en active
- 1997-01-17 ID IDP970125A patent/ID15833A/en unknown
- 1997-01-20 CA CA002243482A patent/CA2243482A1/en not_active Abandoned
- 1997-01-20 WO PCT/NL1997/000019 patent/WO1997026070A1/en not_active Application Discontinuation
- 1997-01-20 JP JP9525886A patent/JP2000507151A/en active Pending
- 1997-01-20 CN CN97191774A patent/CN1209756A/en active Pending
- 1997-01-20 KR KR1019980705511A patent/KR19990077362A/en not_active Application Discontinuation
- 1997-01-20 AU AU13214/97A patent/AU1321497A/en not_active Abandoned
- 1997-01-20 EP EP97900808A patent/EP0885052A1/en not_active Ceased
Also Published As
| Publication number | Publication date |
|---|---|
| WO1997026070A1 (en) | 1997-07-24 |
| JP2000507151A (en) | 2000-06-13 |
| AU1321497A (en) | 1997-08-11 |
| TW372883B (en) | 1999-11-01 |
| KR19990077362A (en) | 1999-10-25 |
| ZA97326B (en) | 1997-07-22 |
| NL1002135C2 (en) | 1997-07-22 |
| ID15833A (en) | 1997-08-14 |
| EP0885052A1 (en) | 1998-12-23 |
| CN1209756A (en) | 1999-03-03 |
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