Note: Descriptions are shown in the official language in which they were submitted.
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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.
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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.
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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.
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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
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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
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-
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
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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.
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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
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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.
-
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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
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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.
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12
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
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
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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.
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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%.
EXAMPLE 2
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)
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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%.
