Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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Title: Method for removing sulfur-contain ng contaminants,
aromatics and hydrocarbons from gas
This invention relates to a method for purifying
gas, more particularly hydrocarbon gas, such as natural gas,
~hich is contaminated with sulfur compounds in the form of H2S
and mercaptans, as well as with CO~. More particularly, the
invention comprises a method for converting mercaptans to H2S
in, and removing C02, 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 S02 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 vaiue lower than 5 mg/Nm3. Requirements are also set with
regard to the maximum content of other sulfur compounds. From
2C 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 ste~, 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 a~ueous solution and
finallv 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. ~or 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 'l~as and Liquid Sweetening"
Campbell Petroleum Series (1977). In this method, in addition
to the sulfur-containing components, also CO2 is wholly or
partll 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 fre~uently used process for recovering sulfur
from the thus obtained sulfur compounds, in partlcular 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 S02 according to the
reaction
1~ 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 + SO2 ~ 3 S + 2 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 SUPERCLAUSTM
process and the SCOT process. In the SUPERCLAUSTM process use
is made of a catalyst as descri~ed 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
descri~ed inter alia in "Hydrocar~on Processing" April l9R3,
pp. 40-42.
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Using this method, the last residues of H2S present
in the process gas stream are selectivel~ 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 ~e 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 ~e
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
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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 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
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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 a~sorption step in
which the sour gas is separated into an H~S-enriched first gas
stream, which is fed to a Claus plant, followed by a selective
~5 oxidation step of H2S 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
CO2-rich gas, which contains the greater part of the CO2,
hydrocarbons and aromatics.
The CO2-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
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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 ~3 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 ~2S
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 H2S is
then selectively absorbed in a second absorber, of the second
absorption step. On balance, the same H2S enrichment is then
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obtained as w th a single absorber. With this method, however,
the ris~ of COS formation is entirely or largelv 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 ~hat 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 lndirectly 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
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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
5 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 tertia-y 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 constructlon 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
2~ 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
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content is incorporated herein ~y 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 no~ be elucidated with reference
to two drawings in which ln the form of a bloc~ 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 specifieation 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
after~urner 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
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11
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 dlscharged 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
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12
absorplion 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
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.% C2HsSH
0.03 ~ol.% C3H7SH
20 0.01 vol.% C4HgSH
81.53 vol.% CO2
4.23 vol.% H2O
3.51 vol.% ~ydrocarbons (cl to C17)
1.08 vol.% Aromatics (Benzene, Toluene, Xylene
To this sour gas was supplied 3000 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 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.
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13
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
10 50 ppm vol. COS
69.78 vol.% CO2
6.4 vol.~ H2O
2.94 vol.% Hydrocarbons (cl to C17)
0.91 vol.% Aromatics (Benzene, Toluene, Xylene
1.03 vol.% H2
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 ~CO2-rich
gas) from the absorber was 15680 Nm3/h with the following
composition
74.54 vol.% CO2
500 ppm vol. H2S
ppm vol. COS
6.78 vol.% H2o
3.48 vol.% Hydrocarbons (Cl to C17)
30 1.07 vol.% Aromatics (Benzenet Toluene, Xylene)
1.21 vol.~ H2
12.86 vol.% N2
Vla 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.
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14
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.% H~S
43.8 vol.% CO2
4.3 vol~% H2O
To the burner of the thermal stage o~ 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 qas sulfur removal stage, consisting of a
selective H2S oxidation reactor.
To this gas was supplied 310 Nm3/h alr. 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~.
