U.S. patent application number 15/379088 was filed with the patent office on 2017-06-22 for thermal stage and reduction absorption sulfur recovery process.
The applicant listed for this patent is Saudi Arabian Oil Company. Invention is credited to John P. O'Connell.
Application Number | 20170173527 15/379088 |
Document ID | / |
Family ID | 57822023 |
Filed Date | 2017-06-22 |
United States Patent
Application |
20170173527 |
Kind Code |
A1 |
O'Connell; John P. |
June 22, 2017 |
THERMAL STAGE AND REDUCTION ABSORPTION SULFUR RECOVERY PROCESS
Abstract
An elemental sulfur recovery unit comprising a thermal unit
configured to combust an acid gas feed comprising hydrogen sulfide,
an oxygen source, and a fuel gas to create a reaction furnace
outlet stream, comprising elemental sulfur, a waste heat boiler
configured to capture heat from the reaction furnace outlet stream
to create a waste heat boiler effluent, a condenser configured to
condense the waste heat boiler effluent to produce a non-condensed
gases stream and a condensed stream comprising elemental sulfur, a
process gas reheater configured to generate a hot gases stream, a
hydrogenation reactor configured to convert the hot gases stream to
create a hydrogenation effluent comprising hydrogen sulfide, a
process desuperheater configured to cool the hydrogenation effluent
to generate a cooled effluent, and an absorber unit configured to
absorb the hydrogen sulfide from the cooled effluent to produce a
hydrogen sulfide recycle stream and a waste gas stream.
Inventors: |
O'Connell; John P.;
(Dhahran, SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Saudi Arabian Oil Company |
Dhahran |
|
SA |
|
|
Family ID: |
57822023 |
Appl. No.: |
15/379088 |
Filed: |
December 14, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62268110 |
Dec 16, 2015 |
|
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
B01D 53/1481 20130101;
C01B 17/0404 20130101; B01D 2252/20421 20130101; B01D 2252/20431
20130101; B01D 2252/20489 20130101; C01B 17/0456 20130101; Y02P
20/129 20151101; C01B 17/0447 20130101; B01D 53/1431 20130101; B01D
53/1468 20130101; B01D 2252/20405 20130101; C01B 17/162 20130101;
B01D 2252/20426 20130101 |
International
Class: |
B01D 53/86 20060101
B01D053/86; B01D 53/14 20060101 B01D053/14; C01B 17/04 20060101
C01B017/04; B01D 53/00 20060101 B01D053/00 |
Claims
1. An elemental sulfur recovery unit for processing an acid gas
feed to recover elemental sulfur, the elemental sulfur recovery
unit comprising: a thermal unit, the thermal unit configured to
combust the acid gas feed, an oxygen source, and a fuel gas to
create a reaction furnace outlet stream, wherein the thermal unit
comprises a main burner and a reaction furnace, the main burner
configured to combust the acid gas feed, the oxygen source, and the
fuel gas to a minimum reaction furnace temperature, wherein the
acid gas feed comprises hydrogen sulfide, wherein an amount of the
hydrogen sulfide is converted to elemental sulfur in the reaction
furnace; a waste heat boiler fluidly connected to the reaction
furnace of the thermal unit, the waste heat boiler configured to
capture heat from the reaction furnace outlet stream to create a
waste heat boiler effluent, wherein the heat captured from the
reaction furnace outlet stream heats a boiler feedwater stream to
create saturated steam; a sulfur condenser fluidly connected to the
waste heat boiler, the sulfur condenser configured to cool the
waste heat boiler effluent to produce a condensed liquid sulfur
stream and a non-condensed gases stream, wherein the condensed
liquid sulfur stream comprises the elemental sulfur, and wherein
the non-condensed gases stream comprises hydrogen sulfide,
elemental sulfur vapor, sulfur-containing contaminants, sulfur
dioxide, and water vapor; a gas reheater fluidly connected to the
sulfur condenser, the gas reheater configured to heat the
non-condensed gases stream to a hydrogenation temperature to
generate a hot gases stream, wherein the hot gases stream comprises
sulfur dioxide and elemental sulfur; a hydrogenation reactor
fluidly connected to the gas reheater, the hydrogenation reactor
configured to convert the hot gases stream to create a
hydrogenation effluent, wherein the hydrogenation reactor comprises
a hydrogenation catalyst in a catalyst bed, wherein the
hydrogenation effluent comprises hydrogen sulfide, carbon dioxide,
water vapor, and hydrogen; a process desuperheater fluidly
connected to the hydrogenation reactor, the process desuperheater
configured to condense the majority of the water vapor in the
hydrogenation effluent to produce condensed water and further
configured to generate a cooled effluent, wherein the condensed
water is separated from the cooled effluent in the process
desuperheater; an absorber unit fluidly connected to the process
desuperheater, the absorber unit configured to absorb hydrogen
sulfide from the cooled effluent to generate an absorbed hydrogen
sulfide rich solvent stream and a waste gas stream, wherein the
absorber unit comprises an absorbing solvent, wherein the absorbed
hydrogen sulfide rich solvent stream comprises hydrogen sulfide,
wherein the waste gas stream comprises hydrogen sulfide and
sulfur-containing contaminants; and a regenerator fluidly connected
to the absorber, the regenerator configured to desorb the hydrogen
sulfide from the absorbed hydrogen sulfide rich solvent stream to
generate a hydrogen sulfide recycle stream and a regenerated
solvent, wherein the hydrogen sulfide recycle stream comprises
hydrogen sulfide.
2. The elemental sulfur recovery unit of claim 1, wherein the
minimum reaction furnace temperature is between 1050.degree. C. and
1250.degree. C.
3. The elemental sulfur recovery unit of claim 1 further comprising
a tail gas analyzer configured to analyze a concentration of the
hydrogen sulfide and the sulfur dioxide in the non-condensed gases
stream.
4. The elemental sulfur recovery unit of claim 1, wherein the hot
gases stream is at a temperature between 125.degree. C. and
300.degree. C.
5. The elemental sulfur recovery unit of claim 1, wherein the gas
reheater is a direct-fired reducing gas producing reheater, the
direct-fired reducing gas producing reheater configured to combust
a fuel feed and an air feed sub-stoichiometrically to produce
hydrogen and carbon monoxide, wherein the hot gases stream
comprises hydrogen and carbon monoxide.
6. The elemental sulfur recovery unit of claim 1, wherein the
hydrogenation reactor is configured to reduce the sulfur dioxide
and elemental sulfur in the hot gases stream to hydrogen
sulfide.
7. The elemental sulfur recovery unit of claim 1, wherein the
hydrogenation catalyst in the hydrogenation reactor comprises a
cobalt-molybdenum based catalyst.
8. The elemental sulfur recovery unit of claim 7, wherein the
catalyst bed further comprises titanium.
9. The elemental sulfur recovery unit of claim 1, wherein the
absorbing solvent is selected from the group consisting of DEA,
MEA, MDEA, DTPA, 2-(2-aminoethoxy)ethanol, FLEXSORB.RTM. solvents,
and a combination of the same.
10. The elemental sulfur recovery unit of claim 1, wherein the
hydrogen sulfide recycle stream is recycled to the thermal
unit.
11. The elemental sulfur recovery unit of claim 1, wherein the
hydrogen sulfide recycle stream comprises hydrogen sulfide in an
amount greater than 25% by volume.
12. The elemental sulfur recovery unit of claim 1 further
comprising: an oxidizer fluidly connected to the absorber unit, the
oxidizer configured to burn the waste gas stream with an air stream
and a fuel stream to produce a sulfur dioxide waste stream, wherein
the H.sub.2S and sulfur-containing contaminants in the waste gas
stream are converted to sulfur dioxide in the oxidizer.
13. A sulfur recovery process to recover elemental sulfur from an
acid gas feed, the sulfur recovery process comprising the steps of:
feeding the acid gas feed, an oxygen source, and a fuel gas to a
main burner of a thermal unit, the main burner configured to
combust the acid gas feed, the oxygen source, and the fuel gas to a
minimum reaction furnace temperature, the acid gas feed comprising
hydrogen sulfide; reacting the acid gas feed, the oxygen source,
and the fuel gas at the minimum reaction furnace temperature in a
reaction furnace of the thermal unit to create a reaction furnace
outlet stream, wherein the reaction furnace outlet stream comprises
elemental sulfur and sulfur-containing contaminants; recovering
heat from the reaction furnace outlet stream in a waste heat boiler
to create a waste heat boiler effluent, the waste heat boiler
configured to capture heat from the reaction furnace outlet stream
to heat a boiler feedwater stream to create saturated steam;
condensing the waste heat boiler effluent in a sulfur condenser to
produce a condensed liquid sulfur stream and a non-condensed gases
stream, the condensed liquid sulfur stream comprising the elemental
sulfur, the non-condensed gases stream comprising water vapor and
the sulfur-containing contaminants; reheating the non-condensed
gases stream in a gas reheater to a hydrogenation temperature to
generate a hot gases stream; feeding the hot gases stream to a
hydrogenation reactor, the hydrogenation reactor comprising a
hydrogenation catalyst; reacting the hot gases stream in the
hydrogenation reactor to produce a hydrogenation effluent, wherein
the hydrogenation effluent comprises hydrogen sulfide and water
vapor; cooling the hydrogenation effluent to produce a condensed
water and a cooled effluent, wherein the cooled effluent comprises
hydrogen sulfide; feeding the cooled effluent to an absorber,
wherein the absorber comprises an absorbing solvent, wherein the
absorbing solvent is configured to absorb hydrogen sulfide from the
cooled effluent to generate an absorbed hydrogen sulfide rich
solvent stream and a waste gas stream; and feeding the absorbed
hydrogen sulfide rich solvent stream into a regenerator, the
regenerator configured to desorb the hydrogen sulfide from the
absorbed hydrogen sulfide rich solvent stream to generate a
hydrogen sulfide recycle stream and a regenerated solvent.
14. The sulfur recovery process of claim 13, wherein the minimum
reaction furnace temperature is between 1050.degree. C. and
1250.degree. C.
15. The sulfur recovery process of claim 13, wherein the hot gases
stream is between 125.degree. C. and 300.degree. C.
16. The sulfur recovery process of claim 13, further comprising the
step of venting the waste gas stream to atmosphere.
17. The sulfur recovery process of claim 13, wherein the absorbing
solvent is selected from the group consisting of DEA, MEA, MDEA,
DTPA, 2-(2-aminoethoxy)ethanol, FLEXSORB.RTM. solvents, and a
combination of the same.
18. The sulfur recovery process of claim 13, wherein the amount of
hydrogen sulfide in the hydrogen sulfide recycle stream is greater
than 25% by volume.
19. The sulfur recovery process of claim 13 further comprising the
step of: combusting the waste gas stream, an air stream, and fuel
stream in an oxidizer to produce a sulfur dioxide waste stream, the
sulfur dioxide waste stream comprising sulfur dioxide.
20. The sulfur recovery process of claim 19, further comprising the
steps of: removing an amount of sulfur dioxide from sulfur dioxide
waste stream to produce a sulfur dioxide recycle stream and a waste
effluent stream such that the waste effluent stream comprises less
than 1% by volume sulfur dioxide; and recycling the sulfur dioxide
recycle stream to the main burner of the thermal unit.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from U.S. Provisional
Application No. 62/268,110 filed on Dec. 16, 2015. For purposes of
United States patent practice, this application incorporates the
contents of the Provisional Application by reference in its
entirety.
TECHNICAL FIELD
[0002] Disclosed are an apparatus and process for recovery of
elemental sulfur. More specifically, embodiments relate to an
apparatus and process for converting hydrogen sulfide (H.sub.2S)
and other sulfur-containing compounds in an acid gas feed stream to
elemental sulfur.
BACKGROUND
[0003] The sulfur recovery industry has been using the gas phase
Claus reactions as the basis for recovering elemental sulfur from
hydrogen sulfide (H.sub.2S) since the 1940s. The Claus plant, the
long-standing `workhorse` of the industry, uses the Claus chemistry
to achieve conventionally between 96 percent (%) to 98% recovery of
elemental sulfur from an acid gas stream. The Claus reactions
produce gas phase elemental sulfur that is subsequently condensed
and recovered in the liquid form.
[0004] The vast majority of all operating Claus plants worldwide
include a thermal stage (for example, a free-flame reaction furnace
and a wasteheat boiler) followed by either two or three catalytic
converters, or catalytic stages; a two-stage design results in
recovery efficiencies of about 96% and a three-stage design results
in recovery efficiencies of about 98%. There are only a handful of
four-stage designs in the world because early on the sulfur
recovery industry recognized that a fourth catalytic stage only
marginally increased the recovery efficiency greater than 98% and
was therefore uneconomical.
[0005] Owing to the negative impact of acid rain, formed due to
high levels of sulfur dioxide (SO.sub.2) in the atmosphere,
emissions controls, normally via governmental environmental
regulatory bodies, limit the amount of SO.sub.2 emitted in the
effluent of Claus plants. In response, the industry began
developing Tail Gas Treatment (TGT) technologies to be placed
immediately downstream of the Claus plant to further improve the
recovery efficiency of the sulfur recovery unit to greater than
99%, or in some cases greater than 99.9%, effectively reducing
SO.sub.2 from the effluent.
[0006] By far the most common combination of Claus plant and TGT
for achieving greater than 99.9% recovery is a Claus plant followed
by a reduction/absorption amine-based technology. This technology
requires the reduction and hydrolysis of sulfur bearing compounds
back to the form of H.sub.2S to allow for absorption in an amine
contactor. The H.sub.2S that is absorbed into the amine is then
regenerated and sent back to the front end of the Claus plant as a
recycle acid gas stream.
[0007] In addition to recovering elemental sulfur, Claus plants
also destroy contaminants present in acid gas streams. Contaminants
can include hydrocarbons having between one carbon and six carbons
(C.sub.1-C.sub.6 hydrocarbons), benzene, toluene, ethyl benzene,
and xylenes (including ortho-xylene, meta-xylene, and para-xylene)
(BTEX), methanol (CH.sub.3OH), ammonia (NH.sub.3), hydrogen
cyanide, mercaptans, and other organosulfur compounds. The thermal
stage of the Claus plant plays a critical role in the destruction
of these contaminants. If these contaminants are not properly
destroyed in the thermal stage they can negatively impact the
purity of the sulfur product, can cause problems in the downstream
units including catalytic deactivation, and can end up being
emitted to the atmosphere in an uncombusted form.
[0008] While the conventional Claus plant does provide a path for
recovery of sulfur, it is not without drawbacks. The catalytic
stages require catalyst regeneration and catalyst replacement
(typically replacement occurs every 2 to 6 years) due to catalyst
fouling, deactivation, and plugging. The regeneration of catalyst
or complete catalyst changeout can result in significant downtime,
potentially putting the entire processing unit offline. The
catalytic stages, with alumina and/or titania catalyst, are
sensitive to the presence of contaminants and thermal excursions.
These sensitivities can make managing the catalytic stages
cumbersome and costly.
SUMMARY
[0009] Disclosed are an apparatus and process for recovery of
elemental sulfur. More specifically, embodiments relate to an
apparatus and process for converting hydrogen sulfide (H.sub.2S)
and other sulfur-containing compounds in an acid gas feed stream to
elemental sulfur.
[0010] In a first aspect, an elemental sulfur recovery unit for
processing an acid gas feed to recover elemental sulfur is
provided. The elemental sulfur recovery unit includes a thermal
unit. The thermal unit is configured to combust the acid gas feed,
an oxygen source, and a fuel gas to create a reaction furnace
outlet stream. The thermal unit includes a main burner and a
reaction furnace. The main burner is configured to combust the acid
gas feed, the oxygen source, and the fuel gas to a minimum reaction
furnace temperature. The acid gas feed includes hydrogen sulfide
and an amount of the hydrogen sulfide is converted to elemental
sulfur in the reaction furnace. A waste heat boiler is fluidly
connected to the reaction furnace of the thermal unit. The waste
heat boiler is configured to capture heat from the reaction furnace
outlet stream to create a waste heat boiler effluent, where the
heat captured from the reaction furnace outlet stream heats a
boiler feedwater stream to create saturated steam. A sulfur
condenser is fluidly connected to the waste heat boiler. The sulfur
condenser is configured to cool the waste heat boiler effluent to
produce a condensed liquid sulfur stream and a non-condensed gases
stream. The condensed liquid sulfur stream includes the elemental
sulfur and the non-condensed gases stream includes hydrogen
sulfide, elemental sulfur vapor, sulfur-containing contaminants,
sulfur dioxide, and water vapor. A gas reheater is fluidly
connected to the sulfur condenser. The gas reheater is configured
to heat the non-condensed gases stream to a hydrogenation
temperature to generate a hot gases stream, where the hot gases
stream includes sulfur dioxide and elemental sulfur. A
hydrogenation reactor is fluidly connected to the gas reheater. The
hydrogenation reactor is configured to convert the hot gases stream
to create a hydrogenation effluent, where the hydrogenation reactor
includes a hydrogenation catalyst in a catalyst bed and the
hydrogenation effluent includes hydrogen sulfide, carbon dioxide,
water vapor, and hydrogen. A process desuperheater is fluidly
connected to the hydrogenation reactor. The process desuperheater
is configured to condense the majority of the water vapor in the
hydrogenation effluent to produce condensed water and is further
configured to generate a cooled effluent, where the condensed water
is separated from the cooled effluent in the process desuperheater.
An absorber unit is fluidly connected to the process desuperheater.
The absorber unit is configured to absorb the hydrogen sulfide from
the cooled effluent to generate an absorbed hydrogen sulfide rich
solvent stream and a waste gas stream. The absorber unit includes
an absorbing solvent. The absorbed hydrogen sulfide rich solvent
stream includes hydrogen sulfide. The waste gas stream includes
hydrogen sulfide and sulfur-containing contaminants. A regenerator
fluidly connected to the absorber, the regenerator configured to
desorb the hydrogen sulfide from the absorbed hydrogen sulfide rich
solvent stream to generate a hydrogen sulfide recycle stream and a
regenerated solvent, where the hydrogen sulfide recycle stream
include hydrogen sulfide.
[0011] In certain aspects, the minimum reaction furnace temperature
is between 1050.degree. C. and 1250.degree. C. In certain aspects,
the elemental sulfur recovery unit further includes a tail gas
analyzer configured to analyze a concentration of the hydrogen
sulfide and the sulfur dioxide in the non-condensed gases stream.
In certain aspects, the hot gases stream is between 125.degree. C.
and 300.degree. C. In certain aspects, the gas reheater is a
direct-fired reducing gas producing reheater configured to combust
a fuel feed and an air feed sub-stoichiometrically to produce
hydrogen and carbon monoxide, where the hot gases stream includes
hydrogen and carbon monoxide. In certain aspects, the hydrogenation
reactor is configured to reduce the sulfur dioxide and elemental
sulfur in the hot gases stream to hydrogen sulfide. In certain
aspects, the hydrogenation catalyst in the hydrogenation reactor
includes a cobalt-molybdenum based catalyst. In certain aspects,
the catalyst bed further includes titanium. In certain aspects, the
absorbing solvent is selected from the group consisting of DEA,
MEA, MDEA, DIPA, 2-(2-aminoethoxy)ethanol, FLEXSORB.RTM. solvents,
and a combination of the same. In certain aspects, the hydrogen
sulfide recycle stream is recycled to the thermal unit. In certain
aspects, the hydrogen sulfide recycle stream includes hydrogen
sulfide in an amount greater than 25% by volume. In certain
aspects, the elemental sulfur recovery unit further includes an
oxidizer fluidly connected to the absorber unit configured to burn
the waste gas stream with an air stream and a fuel stream to
produce a sulfur dioxide waste stream, where the hydrogen sulfide
and sulfur-containing contaminants in the waste gas stream are
converted to sulfur dioxide in the oxidizer.
[0012] In a second aspect, a sulfur recovery process to recover
elemental sulfur from an acid gas feed is provided. The sulfur
recovery process includes the steps of feeding the acid gas feed,
an oxygen source, and a fuel gas to a main burner of a thermal
unit, reacting the acid gas feed, the oxygen source, and the fuel
gas at the minimum reaction furnace temperature in a reaction
furnace of the thermal unit to create a reaction furnace outlet
stream, where the reaction furnace outlet stream includes elemental
sulfur and sulfur-containing contaminants, recovering heat from the
reaction furnace outlet stream in a waste heat boiler to create a
waste heat boiler effluent, the waste heat boiler configured to
capture heat from the reaction furnace outlet stream to heat a
boiler feedwater stream to create saturated steam, condensing the
waste heat boiler effluent in a sulfur condenser to produce a
condensed liquid sulfur stream and a non-condensed gases stream,
the condensed liquid sulfur stream includes the elemental sulfur,
the non-condensed gases stream includes water vapor and the
sulfur-containing contaminants. The process further includes the
steps of reheating the non-condensed gases stream in a gas reheater
to a hydrogenation temperature to generate a hot gases stream,
feeding the hot gases stream to a hydrogenation reactor, the
hydrogenation reactor includes a hydrogenation catalyst, reacting
the hot gases stream in the hydrogenation reactor to produce a
hydrogenation effluent, where the hydrogenation effluent includes
hydrogen sulfide and water vapor, cooling the hydrogenation
effluent to produce a condensed water and a cooled effluent, where
the cooled effluent comprises hydrogen sulfide, feeding the cooled
effluent to an absorber, where the absorber includes an absorbing
solvent configured to absorb hydrogen sulfide from the cooled
effluent to generate an absorbed hydrogen sulfide rich solvent
stream and a waste gas stream, and feeding the absorbed hydrogen
sulfide rich solvent stream into a regenerator configured to desorb
the hydrogen sulfide from the absorbed hydrogen sulfide rich
solvent stream to generate a hydrogen sulfide recycle stream and a
regenerated solvent.
[0013] In certain aspects, the sulfur recovery process further
includes step of venting the waste gas stream to atmosphere. In
certain aspects, the sulfur recovery process further includes the
step of combusting the waste gas stream, an air stream, and fuel
stream in a oxidizer to produce a sulfur dioxide waste stream that
includes sulfur dioxide. In certain aspects, the sulfur recovery
process further includes removing an amount of sulfur dioxide from
sulfur dioxide waste stream to produce a sulfur dioxide recycle
stream and a waste effluent stream such that the waste effluent
stream contains less than 1% by volume sulfur dioxide, and
recycling sulfur dioxide recycle stream to the main burner of the
thermal unit.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] These and other features, aspects, and advantages will
become better understood with regard to the following descriptions,
claims, and accompanying drawings. It is to be noted, however, that
the drawings illustrate only several embodiments and are therefore
not to be considered limiting of the scope as it can admit to other
equally effective embodiments.
[0015] FIG. 1 is a process diagram of an embodiment of the
elemental sulfur recovery unit.
[0016] FIG. 2 is a process diagram of an embodiment of the
elemental sulfur recovery unit.
DETAILED DESCRIPTION
[0017] While the scope will be described with several embodiments,
it is understood that one of ordinary skill in the relevant art
will appreciate that many examples, variations and alterations to
the apparatus and methods described are within the scope and spirit
of the embodiments. Accordingly, the embodiments described here are
set forth without any loss of generality, and without imposing
limitations, on the claims. Those of skill in the art understand
that the scope includes all possible combinations and uses of
particular features described in the specification. In both the
drawings and the detailed description, like numbers refer to like
elements throughout.
[0018] Referring to FIG. 1, a process diagram of an embodiment of
elemental sulfur recovery unit 100 is provided. Acid gas feed 4 and
oxygen source 8 are fed to main burner 104 of thermal unit 105.
Thermal unit 105 can be a free-flame thermal unit suitable to
combust H.sub.2S and other components.
[0019] Acid gas feed 4 can be from any source. Acid gas feed 4 can
include H.sub.2S, water (H.sub.2O), process gases, process
contaminants, sulfur-containing contaminants, and combinations of
the same. Process gases can include carbon monoxide (CO), carbon
dioxide (CO.sub.2), nitrogen (N.sub.2), hydrogen (H.sub.2), and
combinations of the same. Process contaminants can include
hydrocarbons, BTEX, CH.sub.3OH, NH.sub.3, and combinations of the
same. Sulfur-containing contaminants can include carbonyl sulfide
(COS), carbon disulfide (CS.sub.2), mercaptans, other organosulfur
compounds, and combinations of the same. As used throughout,
"organosulfur compounds" refers to organic compounds that include
at least one sulfur atom. The nature and composition of the process
gases, the process contaminants, and the sulfur-containing
contaminants depends on the process that is the source for acid gas
feed 4. The precise composition of acid gas feed 4 depends upon the
source and can be determined using any technology capable of
analyzing the composition of an acid gas feed stream. In at least
one embodiment, the source of acid gas feed 4 is a refinery, and
acid gas feed 4 includes NH.sub.3. In an alternate embodiment, the
source of acid gas feed 4 is a sour gas plant and acid gas feed 4
is in the absence of NH.sub.3.
[0020] Oxygen source 8 can be any oxygen (O.sub.2) containing gas
suitable for use in thermal unit 105. Example gases suitable for
use as oxygen source 8 include air, oxygen-enriched air, pure
O.sub.2, or any combination thereof. In at least one embodiment,
oxygen source 8 is air. In at least one embodiment, oxygen source 8
is provided such that O.sub.2 is supplied in stoichiometric excess
to combust all of the fuel gas components and one-third of the
hydrogen sulfide, such that reaction furnace outlet stream 16 has a
stoichiometric ratio of H.sub.2S:SO.sub.2 in the range of 2:1 to
15:1.
[0021] Fuel gas 12 can be any fuel gas suitable for co-firing in
thermal unit 105. Fuel gas 12 provides additional fuel to adjust
the temperature in main burner 104 to achieve the minimum reaction
furnace temperature. In at least one embodiment, elemental sulfur
recovery unit 100 operates in the absence of fuel gas 12. Elemental
sulfur recovery unit 100 can operate in the absence of fuel gas 12
when no temperature adjustment is needed. In at least one
embodiment, fuel gas 12 is natural gas. In at least one embodiment,
fuel gas 12 includes C.sub.1-C.sub.6 hydrocarbons. In at least one
embodiment, fuel gas 12 includes C.sub.1-C.sub.6+ hydrocarbons. As
used throughout "C.sub.6+" refers to hydrocarbons with 6 or more
carbon atoms, such as a hydrocarbon with 6 carbon atoms, a
hydrocarbon with 7 carbon atoms, a hydrocarbon with 8 carbon atoms,
or a hydrocarbon with more than 8 carbon atoms.
[0022] Thermal unit 105 is designed and operated to convert
H.sub.2S and the sulfur-containing contaminants to elemental
sulfur, SO.sub.2, H.sub.2O, and combinations of the same. Thermal
unit 105 is designed and operated to destroy the process
contaminants contained in acid gas feed 4. As used throughout,
"destroy" refers to conversion of the components into forms that
can be released into the atmosphere. The temperature of thermal
unit 105 affects the amount of elemental sulfur, SO.sub.2, and
H.sub.2O present in reaction furnace outlet stream 16 and the
amount of process contaminants that are destroyed. Main burner 104
allows for mixing and combustion of acid gas feed 4, oxygen source
8, and fuel gas 12 at the minimum reaction furnace temperature. The
minimum reaction furnace temperature is determined based on the
composition of acid gas feed 4. The minimum reaction furnace
temperature is in the range of 850 degrees Celsius (.degree. C.) to
1300.degree. C., alternately between 1050.degree. C. and
1250.degree. C. In at least one embodiment, acid gas feed 4 is in
the absence of NH.sub.3 and the minimum reaction furnace
temperature is at least 1050.degree. C. In at least one embodiment,
acid gas feed 4 includes NH.sub.3 and the minimum reaction furnace
temperature is 1250.degree. C.
[0023] In at least one embodiment, acid gas feed 4 is preheated.
Preheating acid gas feed 4 reduces the fuel gas and oxygen needed
in the thermal unit, which can make the thermal unit smaller and
reduce costs. In some embodiments, preheating units are added
upstream of main burner 104. In at least one embodiment, oxygen
source 8 is air, which is preheated. The addition of fuel gas 12
can increase the temperature in main burner 104 and reaction
furnace 106. The need for preheating units and the ratio of oxygen
and fuel gas to acid gas feed 4 depends on the concentration of
H.sub.2S in acid gas feed 4.
[0024] Acid gas feed 4, oxygen source 8, and fuel gas 12 are
combusted in main burner 104 before passing to reaction furnace
106. H.sub.2S can be converted to SO.sub.2 and elemental sulfur
through conversion reactions. The bulk of the conversion reactions
occur in reaction furnace 106. The conversion of H.sub.2S to
elemental sulfur can occur according to the following
reactions:
2H.sub.2S+3O.sub.2.fwdarw.2SO.sub.2+2H.sub.2O
2H.sub.2S+SO.sub.2.fwdarw.3S+2H.sub.2O (Claus reaction)
[0025] The conversion of the H.sub.2S entering thermal unit 105 to
elemental sulfur is between 30 mole percent (mol %) and 80 mol %,
alternately between 40 mol % and 78 mol %, alternately between 50
mol % and 75 mol %, alternately between 60 mol % and 70 mol %. In
at least one embodiment, the amount of H.sub.2S converted to
elemental sulfur in reaction furnace 106 is between 50 mol % and 75
mol %. Without being bound to a particular theory, it is understood
by one of skill in the art that a reaction furnace is considered a
complex kinetically limited vessel rather than an equilibrium
vessel. In the absence of catalytic converters, the conversion of
H.sub.2S entering thermal unit 105 is expected to achieve a
conversion of H.sub.2S and sulfur-containing contaminants of
between 50 mol % and 70 mol % to elemental sulfur in thermal unit
105. In at least one embodiment, side reactions in thermal unit 105
can form sulfur-containing contaminants.
[0026] Destruction reactions of the process contaminants can also
occur in thermal unit 105. The process contaminants present in acid
gas feed 4 can be reduced by 95 weight percent (wt %), alternately
by 97 wt %, alternately by 99 wt %, alternately by 99.5 wt %,
alternately by 99.9 wt %, alternately by 99.99 wt %, and
alternately by 100 wt %.
[0027] Reaction furnace outlet stream 16 exits reaction furnace 106
at the minimum reaction furnace temperature and is cooled prior to
further processing. In at least one embodiment, the heat energy of
reaction furnace outlet stream 16 is recovered and used to heat
other streams. Reaction furnace outlet stream 16 leaves reaction
furnace 106 and enters waste heat boiler 110. Waste heat boiler 110
can capture heat energy from reaction furnace outlet stream 16 to
heat a boiler feedwater stream (not shown) to create a saturated
steam stream (not shown). By producing saturated steam, waste heat
boiler 110 captures and removes bulk heat from reaction furnace
outlet stream 16. Waste heat boiler 110 can be designed to generate
saturated steam at any process conditions desirable. In some
embodiments, waste heat boiler 110 can be designed to generate high
pressure saturated steam. In at least one embodiment, the saturated
steam produced by waste heat boiler 110 is high pressure saturated
steam at a pressure of 600 psig (pounds per square inch gauge)
(4.14 megapascals (MPa)). The amount of heat energy captured from
reaction furnace outlet stream 16 controls the temperature of waste
heat boiler effluent 20. In at least one embodiment, the
temperature of waste heat boiler effluent 20 is between 295.degree.
C. and 370.degree. C. In at least one embodiment, waste heat boiler
110 is a horizontal shell and tube exchanger.
[0028] Reaction furnace outlet stream 16 and waste heat boiler
effluent 20 can contain H.sub.2S, elemental sulfur, SO.sub.2,
sulfur-containing contaminants, H.sub.2O (vapor), process gases,
and process contaminants. The exact composition of reaction furnace
outlet stream 16 and waste heat boiler effluent 20 depends on the
composition of acid gas feed 4 and the conditions in thermal unit
105, including the minimum reaction furnace temperature. The amount
of H.sub.2S, process contaminants, and sulfur-containing
contaminants present in reaction furnace outlet stream 16 and waste
heat boiler effluent 20 are reduced relative to the amount of those
components present in acid gas feed 4. In at least one embodiment,
oxygen source 8 is air, such that argon (Ar) is present in reaction
furnace outlet stream 16 and waste heat boiler effluent 20.
[0029] Waste heat boiler effluent 20 is fed to sulfur condenser 115
to produce condensed liquid sulfur stream 24 and non-condensed
gases stream 28. Sulfur condenser 115 further reduces the
temperature of waste heat boiler effluent 20 causing the elemental
sulfur vapor present in waste heat boiler effluent 20 to condense
as condensed liquid sulfur stream 24. The temperature of condensed
liquid sulfur stream 24 is between 120.degree. C. and 155.degree.
C., alternately between 125.degree. C. and 150.degree. C. Condensed
liquid sulfur stream 24 contains greater than 95 wt % elemental
sulfur, alternately greater than 97 wt % elemental sulfur,
alternately greater than 99 wt % elemental sulfur, alternately
greater than 99.5 wt % elemental sulfur, alternately greater than
99.9 wt % elemental sulfur.
[0030] Non-condensed gases stream 28 contains those components
present in waste heat boiler effluent 20 that do not condense in
sulfur condenser 115. Non-condensed gases stream 28 can contain
H.sub.2S, elemental sulfur vapor, SO.sub.2, sulfur-containing
contaminants, H.sub.2O vapor, process gases, process contaminants,
and combinations of the same. The exact composition of
non-condensed gases stream 28 depends on the composition of waste
heat boiler effluent 20. In at least one embodiment, non-condensed
gases stream 28 contains less than 1% by volume elemental sulfur
vapor. Non-condensed gases stream 28 can be at a temperature
between 120.degree. C. and 155.degree. C., alternately between
125.degree. C. and 150.degree. C.
[0031] In at least one embodiment, sulfur condenser 115 can be used
to capture heat energy from waste heat boiler effluent 20 to heat a
boiler water stream (not shown) to create a saturated steam stream
(not shown). In at least one embodiment, the saturated steam stream
is a low pressure saturated steam at a pressure of 50 psig (0.345
MPa).
[0032] Non-condensed gases stream 28 is fed to gas reheater 125.
Gas reheater 125 heats non-condensed gases stream 28 to the
hydrogenation temperature to generate hot gases stream 32. Gas
reheater 125 is any heat exchanger or fired heater capable of
heating non-condensed gases stream 28. In at least one embodiment,
gas reheater 125 is a direct-fired reducing gas producing reheater
capable of combusting fuel gas and oxygen sub-stoichiometrically to
produce hydrogen and carbon monoxide (CO). As used throughout,
"stoichiometric," "stoichiometric amount" or "stoichiometrically"
refers to the relative quantities of reactants, such that when the
reaction proceeds to completion, all of the reactants are consumed,
there is no deficiency of a reactant and there is no excess of a
reactant. Thus, "oxygen sub-stoichiometrically" means that there is
a deficiency of oxygen in gas reheater 125 such that CO and H.sub.2
can form in addition to H.sub.2O and CO.sub.2. Fuel feed 22 and air
feed 18 can be fed to gas reheater 125, as shown in FIG. 1. In
embodiments where gas reheater 125 is a direct-fired reducing gas
producing reheater, fuel feed 22 and air feed 18 can be combusted
and can produce H.sub.2, CO, CO.sub.2, and H.sub.2O. Fuel feed 22
can be from the same source as fuel gas 12. Air feed 18 can be from
the same source as oxygen source 8. Non-condensed gases stream 28
can be heated in gas reheater 125. Non-condensed gases stream 28
can be introduced to gas reheater 125 downstream of the point where
combustion of fuel feed 22 and air feed 18 occurs to avoid
combustibles in non-condensed gases stream 28 from becoming
involved in combustion. In embodiments where gas reheater 125 is a
direct fired reducing gas producing reheater, hot gases stream 32
contains more hydrogen than non-condensed gases stream 28. Hot
gases stream 32 can include H.sub.2S, elemental sulfur vapor,
SO.sub.2, sulfur-containing contaminants, water vapor, process
gases, process contaminants, and combinations of the same. In at
least one embodiment, hot gases stream 32 includes reducing gases,
such as H.sub.2 and CO. In at least one embodiment, hot gases
stream 32 can include H.sub.2S, SO.sub.2, elemental sulfur, and
reducing gases. The hydrogenation temperature is the temperature at
which hydrogenation reactor 130 operates. The hydrogenation
temperature of hot gases stream 32 can be between 125.degree. C.
and 300.degree. C., alternately between 200.degree. C. and
300.degree. C., alternately between 220.degree. C. and 280.degree.
C., and alternately between 240.degree. C. and 260.degree. C. In at
least one embodiment, the hydrogenation temperature is between
220.degree. C. and 280.degree. C. Hot gases stream 32 is fed to
hydrogenation reactor 130.
[0033] Hydrogenation reactor 130 can convert the elemental sulfur,
SO.sub.2, and sulfur-containing contaminants in hot gases stream 32
to H.sub.2S. Examples of reactions in hydrogenation reactor 130
that can convert elemental sulfur, SO.sub.2, and the
sulfur-containing contaminants include reduction reactions,
hydrolysis reactions, water-gas shift reactions, sour-gas shift
reactions, and combinations of the same. As used throughout,
"reduction reaction" refers to any reaction in which the reactants
use H.sub.2 to form H.sub.2S. Examples of reduction reactions that
can occur in hydrogenation reactor 130 include the following:
SO.sub.2+3H.sub.2.fwdarw.H.sub.2S+2H.sub.2O
S.sub.vap+H.sub.2.fwdarw.H.sub.2
S.sub.LR+H.sub.2.fwdarw.H.sub.2
[0034] In at least one embodiment, reduction of SO.sub.2 to
H.sub.2S occurs to complete conversion.
[0035] Possible sources of hydrogen (H.sub.2) can include H.sub.2
formation in thermal unit 105, H.sub.2 formation from a
substoichiometric burn of fuel gas in gas reheater 125, a water gas
shift reaction with CO in hydrogenation reactor 130, or a
supplemental H.sub.2 stream (not shown) added upstream of
hydrogenation reactor 130. In at least one embodiment, CO is formed
in thermal unit 105.
[0036] As used throughout, "hydrolysis" or "hydrolysis reaction"
refers to a breakdown of a compound due to reaction with water.
Examples of hydrolysis reactions that can occur in hydrogenation
reactor 130 include the following:
COS+H.sub.2O.fwdarw.H.sub.2S+CO.sub.2
CS.sub.2+2H.sub.2O.fwdarw.2H.sub.2S+CO.sub.2
[0037] In at least one embodiment, hydrolysis of CS.sub.2 occurs to
complete conversion. In at least one embodiment, hydrolysis of COS
proceeds to equilibrium.
[0038] An example of a water-gas shift reaction that can occur in
hydrogenation reactor 130 includes the following:
CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2
[0039] In at least one embodiment, the water-gas shift reaction
proceeds to equilibrium.
[0040] Hydrogenation reactor 130 can include a hydrogenation
catalyst. The hydrogenation catalyst can be any catalyst capable of
enabling reactions in hydrogenation reactor 130 that convert
sulfur-containing compounds to H.sub.2S. In at least one
embodiment, the hydrogenation catalyst is a cobalt-molybdenum based
catalyst. In at least one embodiment, hydrogenation reactor 130 is
a fixed bed reactor. In at least one embodiment, hydrogenation
reactor 130 is a fixed bed reactor with the catalyst bed having a
thickness between three feet and four feet. In at least one
embodiment, hydrogenation reactor 130 is a fixed bed reactor
charged with a three foot to four foot thick cobalt-molybdenum
catalyst bed. In at least one embodiment, the catalyst bed includes
a titanium-based catalyst capable of enabling the hydrolysis
reactions. The titanium-based catalyst can be added below the
hydrogenation catalyst in the catalyst bed of hydrogenation reactor
130. The H.sub.2S formed in hydrogenation reactor 130 exit
hydrogenation reactor 130 as hydrogenation effluent 36.
Hydrogenation effluent 36 can include H.sub.2S, H.sub.2O, CO.sub.2,
H.sub.2, and combinations of the same.
[0041] Process desuperheater 145 reduces the temperature of
hydrogenation effluent 36 to produce condensed water 40 and cooled
effluent 44. Reducing the temperature of hydrogenation effluent 36
can condense the majority of the water vapor present in
hydrogenation effluent 36 to liquid water. As used throughout,
"majority" refers to 51 percent or more. Condensed water 40
contains the liquid water condensed in process desuperheater 145.
Cooled effluent 44 contains the gases not condensed in process
desuperheater 145. In some embodiments, process desuperheater 145
separates the liquid water from the gases. In some embodiments,
process desuperheater 145 can be any type of desuperheater capable
of cooling hydrogenation effluent 36 and separating the liquid
water that condenses and the gases that do not condense. Examples
of desuperheaters include indirect contact desuperheaters, direct
contact desuperheaters, and water spray desuperheaters. In at least
one embodiment, process desuperheater 145 can be a contact
condenser. In a least one embodiment, process desuperheater 145
includes a desuperheater and a contact condenser. The temperature
of cooled effluent 44 is between 25.degree. C. and 55.degree. C.,
alternately between 30.degree. C. and 50.degree. C., and
alternately between 35.degree. C. and 45.degree. C. In at least one
embodiment, the temperature of cooled effluent 44 is between
30.degree. C. and 50.degree. C. Condensed water 40 is separated
from cooled effluent 44. In at least one embodiment, condensed
water 40 can be collected, stored, or further processed. In at
least one embodiment, condensed water 40 includes sulfides, such
that condensed water 40 is sour water, and can be further processed
to remove the sulfides. "Sulfide" as used throughout includes
hydrogen sulfide, and any sulfide salt. Cooled effluent 44 is fed
to absorber unit 150. Advantageously, cooling hydrogenation
effluent 36 and condensing the water in process desuperheater 145
in order to separate the water as condensed water 40 prevents
excess water from entering absorber unit 150. As used throughout,
"excess water" refers to the amount of water greater than the
amount of water than can be processed in the absorber, such that
excess water is the amount of water greater than the concentration
of water in the overhead of absorber unit 150. By separating out
the excess water upstream of absorber unit 150, the excess water is
not carried into absorber unit 150, where the presence of excess
water would dilute the solvent and reduce its effectiveness. As a
result, removing excess water in process desuperheater 145
maintains a constant concentration of water in absorber unit 150.
In addition, the presence of water in absorber unit 150 would
result in an accumulation in absorber unit 150, which cannot handle
such accumulation.
[0042] Absorber unit 150 removes H.sub.2S from cooled effluent 44.
Cooled effluent 44 is fed to absorber unit 150 where the H.sub.2S
is absorbed producing absorbed hydrogen sulfide rich solvent stream
48 and waste gas stream 56. Absorber unit 150 can operate at a
pressure of between 1 psig and 2 psig. Absorber unit 150 includes
an absorbing solvent. The absorbing solvent can be any material
capable of absorbing H.sub.2S. In at least one embodiment, the
absorbing solvent can preferentially absorb the H.sub.2S over the
CO.sub.2 into the absorbing solvent. Examples of the absorbing
solvent can include DEA, MEA, MDEA, DIPA, 2-(2-aminoethoxy)ethanol,
FLEXSORB.RTM. solvents, and hindered amines, or a combination of
the same. In at least one embodiment, absorber unit 150 includes an
absorbing solvent capable of achieving an overall recovery
efficiency of greater than 99.9 percent of total inlet equivalent
sulfur in acid gas feed 4. In other words, elemental sulfur
recovery unit 100 is capable of removing greater than 99.9% of the
elemental sulfur present in acid gas feed 4. In a particular
embodiment, waste gas stream 56 is vented to the atmosphere. Waste
gas stream 56 can be vented to the atmosphere where allowed by
environmental emissions regulations. In a particular embodiment,
the temperature of waste gas stream 56 is between 25.degree. C. and
55.degree. C.
[0043] In at least one embodiment, cooled effluent 44 contains an
amount of H.sub.2S. In at least one embodiment, the amount of
hydrogen sulfide is between 10% by weight and 50% by weight. The
amount of hydrogen sulfide present in cooled effluent 44 is
dependent on the hydrogen sulfide content of acid gas stream 4 and
the amount of H.sub.2S converted to elemental sulfur in reaction
furnace 105.
[0044] Absorbed hydrogen sulfide rich solvent stream 48 is fed to
regenerator 160. Regenerator 160 desorbs the H.sub.2S from absorbed
hydrogen sulfide rich solvent stream 48 to generate hydrogen
sulfide recycle stream 52 and regenerate the absorbing solvent to
produce regenerated solvent 50. Regenerator 160 is any regenerator
capable of stripping the H.sub.2S from the absorbing solvent.
Regenerator 160 can operate at a pressure of between 5 psig and 20
psig. One of skill in the art will understand that absorber unit
150 and regenerator 160 can include pumps, heat exchangers and
other units to effect fluid transfer between the two units and
ensure proper functioning. For example, a pump (not shown) can be
used to transfer lean amine in regenerated solvent 50 from the
bottom of regenerator 160 through heat exchangers (not shown) to
absorber unit 150. Hydrogen sulfide recycle stream 52 can be
stored, sent for further processing, or recycled. In a particular
embodiment, hydrogen sulfide recycle stream 52 is recycled in the
process to thermal unit 105. In a particular embodiment, hydrogen
sulfide recycle stream 52 is greater than 25% H.sub.2S by volume,
alternately greater than 50% H.sub.2S by volume, alternately
greater than 75% H.sub.2S by volume, and alternately greater than
90% H.sub.2S by volume. The regenerated absorbing solvent can be
returned to absorber unit 150 as regenerated solvent 50.
[0045] In addition to separating H.sub.2S for recycle to the inlet
of thermal unit 105, absorbing unit 150 provides a method to
separate non-reactant (non-combustible) gases, such as N.sub.2,
A.sub.2, and CO.sub.2, such that the non-reactant gases do not
accumulate in elemental sulfur recovery unit 100.
[0046] Waste gas stream 56 can include H.sub.2S, sulfur-containing
contaminants, process gases, and combinations of the same. In at
least one embodiment, waste gas stream 56 further includes
sulfur-containing contaminants, such as COS. The amount of
sulfur-containing contaminants, process gases and COS in waste
stream 56 depends on the reaction efficiency in hydrogenation
reactor 130. For example, as the hydrogenation catalyst deactivates
over time, the amount of elemental sulfur, SO.sub.2, process gases,
and sulfur-containing contaminants can increase. In at least one
embodiment, the amount of sulfur-containing contaminants in waste
gas stream 56 is between 1 ppm and 50 ppm. In at least one
embodiment, waste gas stream 56 can be vented to atmosphere where
permitted by governmental regulations.
[0047] In at least one embodiment, waste gas stream 56 can be
further processed. In at least one embodiment, waste gas stream 56,
air stream 60, and fuel stream 64 are fed to oxidizer 165. Oxidizer
165 can be any oxidizer capable of combusting sulfur-containing
compounds to produce SO.sub.2. Examples of oxidizers suitable for
use as oxidizer 165 include a free-flame thermal oxidizer and a
catalytic oxidizer. In at least one embodiment, oxidizer 165 is a
free-flame thermal oxidizer suitable to combust sulfur-containing
contaminants, elemental sulfur and H.sub.2S to SO.sub.2. Air stream
60 can be any O.sub.2 containing gas suitable for use in oxidizer
165. Example gases suitable for use as air stream 60 include air,
O.sub.2 enriched air, pure O.sub.2, or any combination thereof. In
at least one embodiment, air stream 60 is air. In at least one
embodiment, air stream 60 provides a stoichiometric excess of
oxygen in oxidizer 165, where the stoichiometric excess of O.sub.2
is operable to drive the conversion of sulfur-containing compounds
to SO.sub.2. In at least one embodiment, air stream 60 is from the
same source as oxygen source 8. Fuel stream 64 can be any fuel gas
suitable for firing in oxidizer 165. Fuel stream 64 provides
additional fuel to adjust the temperature in oxidizer 165. In at
least one embodiment, fuel stream 64 is selected from the group
consisting of natural gas, and any C.sub.1-C.sub.6+ hydrocarbon, or
combinations of the same. In at least one embodiment, fuel stream
64 is from the same source as fuel gas 12. Oxidizer 165 can combust
the H.sub.2S and sulfur-containing contaminants in the presence of
excess O.sub.2 to create SO.sub.2 along with other combustion
products to create sulfur dioxide waste stream 68. Sulfur dioxide
waste stream 68 includes SO.sub.2, process gases, and trace amounts
of sulfur and sulfur-containing contaminants. Sulfur dioxide waste
stream 68 can be further processed or vented to atmosphere, where
permitted by governmental regulations.
[0048] In at least one embodiment, as shown in FIG. 1 and FIG. 2,
sulfur dioxide waste stream 68 is fed to sulfur dioxide scrubbing
unit 170 to create sulfur dioxide recycle stream 72 and waste
effluent stream 76. Sulfur dioxide scrubbing unit 170 can be any
type of scrubbing unit capable of removing an amount of SO.sub.2
from a process stream. Waste effluent stream 76 can include process
gases, SO.sub.2, and trace levels of sulfur-containing contaminants
and process contaminants. Waste effluent stream 76 contains
SO.sub.2 in an amount less than 1% by volume, alternately less than
0.1% by volume, alternately less than 0.01% by volume, alternately
less than 0.001% by volume, alternately less than 0.0001% by
volume, alternately less than 0.00005% by volume, alternately less
than 0.00001% by volume. Waste effluent stream 76 can be sent for
further processing, vented to atmosphere, or used in another
processing unit. In at least one embodiment, waste effluent stream
76 is vented to atmosphere.
[0049] Sulfur dioxide recycle stream 72 contains the amount of
SO.sub.2 removed from sulfur dioxide waste stream 68 in sulfur
dioxide scrubbing unit 170. In at least one embodiment, the amount
of SO.sub.2 in sulfur dioxide recycle stream 72 is between 80% and
99.99% by volume, alternately greater than 80% by volume,
alternately greater than 99% by volume, alternately greater than
99.3% by volume, alternately greater than 99.5% by volume,
alternately greater than 99.7% by volume, alternately greater than
99.9% by volume, alternately greater than 99.95% by volume,
alternately greater than 99.99% by volume of the SO.sub.2 generated
in oxidizer 165. In at least one embodiment, sulfur dioxide recycle
stream 72 contains saturated water in an amount between 3% by
volume and 20% by volume. In at least one embodiment, sulfur
dioxide recycle stream 72 is recycled to main burner 104 of thermal
unit 106. In at least one embodiment, a hydrogen sulfide source and
a sulfur dioxide source are fed to main burner 104 in addition to
acid gas feed 4 to maintain a stoichiometric ratio of H.sub.2S to
SO.sub.2 of 15:1, alternately a stoichiometric ratio of H.sub.2S to
SO.sub.2 of greater than 10:1, alternately a stoichiometric ratio
of H.sub.2S to SO2 of 10:1, alternately a stoichiometric ratio of
H.sub.2S to SO.sub.2 of 5:1, and alternately a stoichiometric ratio
of H.sub.2S to SO.sub.2 of greater than 2:1 at the outlet of
reaction furnace 105. In at least one embodiment, the hydrogen
sulfide source is hydrogen sulfide recycle stream 52. In at least
one embodiment, the hydrogen sulfide source is the combined stream
of hydrogen sulfide recycle stream 52 and acid gas feed 4. In at
least one embodiment, the sulfur dioxide source is sulfur dioxide
recycle stream 72. The ratio of H.sub.2S to SO.sub.2 in thermal
unit 105 contributes to the overall conversion of H.sub.2S and
sulfur-containing contaminants to elemental sulfur.
[0050] Hydrogen sulfide recycle stream 52 can be recycled to main
burner 104. The flow rate of oxygen source 8 can be adjusted, such
that together with acid gas feed 4 and hydrogen sulfide recycle
stream 52 a target stoichiometric ratio of H.sub.2S to SO.sub.2 at
the outlet of thermal unit 105 can be achieved. In at least one
embodiment, the target stoichiometric ratio of H.sub.2S to SO.sub.2
is greater than about 15:1, alternately the target stoichiometric
ratio of H.sub.2S to SO.sub.2 is greater than about 10:1,
alternately the target stoichiometric ratio of H.sub.2S to SO.sub.2
is about 10:1, alternately the target stoichiometric ratio of
H.sub.2S to SO.sub.2 is about 5:1, and alternately the target
stoichiometric ratio of H.sub.2S to SO.sub.2 is greater than about
2:1 at the outlet of thermal unit 105.
[0051] The pressure drop in elemental sulfur recovery unit 100 can
be less than 5 psi. In at least one embodiment, the pressure of
acid gas feed 4 is between 7 psig and 15 psig. Thermal unit 105,
waste heat boiler 110, sulfur condenser 115, gas reheater 125, and
hydrogenation reactor 130 are at operating conditions that maintain
the water in a vapor phase. In at least one embodiment, the
pressure of acid gas feed 4 is due to the pressure of an upstream
unit that operates at a pressure at or less than 20 psig.
[0052] Various process control elements can be included in the
process to provide for better control of the process units and the
overall conversion of H.sub.2S and sulfur-containing contaminants
to elemental sulfur. Referring to FIG. 2, tail gas analyzer 220 can
be installed after sulfur condenser 115 to analyze the composition
in non-condensed gases stream 28. Tail gas analyzer 220 can be any
instrument capable of measuring the components of a stream as part
of a feedback control loop of the thermal unit. In at least one
embodiment, tail gas analyzer 220 can analyze the concentration of
hydrogen sulfide and sulfur dioxide in non-condensed gases stream
28. In at least one embodiment, the results from tail gas analyzer
220 can be used to adjust the flow rate of oxygen source 8. A
temperature sensor (not shown) can be included in thermal unit 105.
The temperature sensor can be used as part of a temperature
controlled feedback loop to ensure the minimum reaction furnace
temperature is being maintained. In at least one embodiment, the
temperature sensor can be used to adjust the flow rate of fuel gas
12 as needed to maintain or reach the minimum reaction furnace
temperature. Hydrogen analyzer 224 can be installed after process
desuperheater 145 to measure the amount of H.sub.2 in cooled
effluent 44. Hydrogen analyzer 224 can be any instrument capable of
measuring the components of a stream as part of a feedback control
loop. In at least one embodiment, the results from hydrogen
analyzer 224 can be used to control gas reheater 125 or to control
the addition of surplus hydrogen to the process to meet the
operating condition of hydrogenation reactor 130 having a minimum
excess of two percent hydrogen at the outlet of hydrogenation
reactor 130 to ensure completion of the reduction reactions in
hydrogenation reactor 130.
[0053] The overall conversion of H.sub.2S and sulfur-containing
contaminants in acid gas feed 4 to elemental sulfur is greater than
99 mol %, alternately greater than 99.2 mol %, alternately greater
than 99.4 mol %, alternately greater than 99.6 mol % alternately
greater than 99.8 mol %, alternately greater than 99.9 mol %.
[0054] In at least one embodiment, elemental sulfur recovery unit
100 recovers greater than 99.9% of the sulfur introduced to the
system.
[0055] In at least one embodiment, elemental sulfur recovery unit
100 is in the absence of any conventional Claus plant catalytic
stages, that use catalyst to convert hydrogen sulfide and sulfur
dioxide to elemental sulfur. A conventional Claus plant can include
between two and four (4) catalytic stages. Elemental sulfur
recovery unit 100 contains no Claus plant catalytic stages.
Advantageously, elemental sulfur recovery unit 100, in the absence
of a conventional Claus plant catalytic stage, can handle acid gas
feed streams with a concentration of H.sub.2S at or greater than 50
percent, alternately at or greater than 40 percent, alternately at
or greater than 30 percent, alternately at or greater than 20
percent, alternately at or greater than 10 percent, and alternately
at or greater than 5 percent.
[0056] One of skill in the art understands that certain components
introduced in thermal unit 105 are non-combustible gases and can be
present in every stream of elemental sulfur recovery unit 100;
venting waste gas stream 56 or waste effluent stream 76 prevents
these non-combustible gases from building up in elemental sulfur
recovery unit 100. In addition, one of skill in the art understands
that where a unit is said to react certain reactants to produce a
product stream, the product stream can contain amounts of the
reactants unless specifically stated otherwise.
[0057] Advantageously, the elemental sulfur recovery unit addresses
the presence of carbonyl sulfide and carbon disulfide in the
effluent from the thermal unit without the need for a conventional
Claus plant catalytic stage. The hydrogenation reactor of the
elemental sulfur recovery unit can be designed to handle carbonyl
sulfide and carbon disulfide. In at least one embodiment, the
hydrogenation reactor can include a supplemental titanium layer
underneath the hydrogenation catalyst. In at least one embodiment,
the absorber unit can be designed to handle the higher load of
H.sub.2S to the absorber that occurs as a result of the absence of
a conventional Claus plant catalytic stage.
[0058] Although the embodiments have been described in detail, it
should be understood that various changes, substitutions, and
alterations can be made hereupon without departing from the
principle and scope. Accordingly, the scope should be determined by
the following claims and their appropriate legal equivalents.
[0059] The singular forms "a," "an," and "the" include plural
referents, unless the context clearly dictates otherwise.
[0060] Optional or optionally means that the subsequently described
event or circumstances can or may not occur. The description
includes instances where the event or circumstance occurs and
instances where it does not occur.
[0061] Ranges may be expressed as from one particular value to
another particular value. When such a range is expressed, it is to
be understood that another embodiment is from the one particular
value to the other particular value, along with all combinations
within said range.
[0062] Throughout this application, where patents or publications
are referenced, the disclosures of these references in their
entireties are intended to be incorporated by reference into this
application, in order to more fully describe the state of the art
to which the embodiments pertain, except when these references
contradict the statements made here.
[0063] As used throughout and in the appended claims, the words
"comprise," "has," "contains" and "include" and all grammatical
variations thereof are each intended to have an open, non-limiting
meaning that does not exclude additional elements or steps.
[0064] As used here, terms such as "first" and "second" are
arbitrarily assigned and are merely intended to differentiate
between two or more components of an apparatus. It is to be
understood that the words "first" and "second" serve no other
purpose and are not part of the name or description of the
component, nor do they necessarily define a relative location or
position of the component. Furthermore, it is to be understood that
that the mere use of the term "first" and "second" does not require
that there be any "third" component, although that possibility is
contemplated under the scope.
* * * * *