U.S. patent application number 15/135984 was filed with the patent office on 2016-10-27 for systems and methods for water gas shift with reduced steam consumption.
The applicant listed for this patent is Research Triangle Institute. Invention is credited to David L. Denton, Raghubir P. Gupta, Vijay Gupta, Himanshu Paliwal, Brian S. Turk.
Application Number | 20160311682 15/135984 |
Document ID | / |
Family ID | 55761399 |
Filed Date | 2016-10-27 |
United States Patent
Application |
20160311682 |
Kind Code |
A1 |
Turk; Brian S. ; et
al. |
October 27, 2016 |
SYSTEMS AND METHODS FOR WATER GAS SHIFT WITH REDUCED STEAM
CONSUMPTION
Abstract
A water gas shift reaction is carried out on a feed gas
comprising carbon monoxide to produce carbon dioxide and hydrogen
gas. The feed gas is split into multiple input streams flowed into
respective reactors coupled in series. Steam is supplied to the
input stream fed to the first reactor. The shift reaction is
carried out in each reactor, with an overall reduced consumption of
steam relative to the amount of gas shifted. The water gas shift
reaction may be performed in conjunction with removing acid gas
compounds from a process gas such as, for example, syngas or
natural gas, by flowing a feed gas into a desulfurization unit to
remove a substantial fraction of sulfur compounds from the feed gas
and flowing the resulting desulfurized gas into a CO.sub.2 removal
unit to remove a substantial fraction of CO.sub.2 from the
desulfurized gas.
Inventors: |
Turk; Brian S.; (Durham,
NC) ; Gupta; Vijay; (Cary, NC) ; Denton; David
L.; (Kingsport, TN) ; Gupta; Raghubir P.;
(Durham, NC) ; Paliwal; Himanshu; (Durham,
NC) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Research Triangle Institute |
Research Triangle Park |
NC |
US |
|
|
Family ID: |
55761399 |
Appl. No.: |
15/135984 |
Filed: |
April 22, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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PCT/US2015/056391 |
Oct 20, 2015 |
|
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15135984 |
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62068333 |
Oct 24, 2014 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
B01D 2252/2021 20130101;
B01D 2257/306 20130101; C01B 2203/0283 20130101; C01B 3/52
20130101; B01J 2219/0059 20130101; C01B 17/74 20130101; C01B
2203/042 20130101; Y02P 20/151 20151101; C10L 2290/541 20130101;
B01J 2219/00594 20130101; B01D 53/52 20130101; B01D 53/83 20130101;
B01J 19/0046 20130101; C10L 2290/547 20130101; B01D 53/96 20130101;
B01D 2257/304 20130101; C10K 1/004 20130101; C10K 1/005 20130101;
C10L 2290/542 20130101; B01J 20/3483 20130101; C01B 2203/1258
20130101; C10K 1/10 20130101; C10L 3/104 20130101; B01D 2257/308
20130101; C10L 2290/54 20130101; B01D 53/62 20130101; C01B 17/0404
20130101; Y02C 20/40 20200801; C01B 2203/0485 20130101; C01B
2203/061 20130101; B01J 7/02 20130101; C01B 2203/0475 20130101;
B01D 53/1425 20130101; B01D 53/1475 20130101; C01B 2203/0415
20130101; Y02A 50/20 20180101; C01B 3/16 20130101; B01D 2253/1124
20130101; C01B 2203/0294 20130101; C10K 1/20 20130101; B01D 53/48
20130101; C10L 3/103 20130101; B01D 53/1462 20130101; B01D
2252/20489 20130101; B01D 2257/504 20130101; B01D 53/1437 20130101;
C10L 2290/12 20130101; B01J 20/3458 20130101; B01J 2219/00756
20130101; B01J 2219/00759 20130101; C10K 1/32 20130101; C10K 3/04
20130101; C01B 3/56 20130101 |
International
Class: |
C01B 3/16 20060101
C01B003/16; B01J 7/02 20060101 B01J007/02; B01J 19/00 20060101
B01J019/00; C01B 3/56 20060101 C01B003/56 |
Claims
1. A method for producing a water-gas shifted gas comprising
CO.sub.2 and H.sub.2, the method comprising: splitting a flow of
feed gas comprising carbon monoxide (CO) into a plurality of feed
gas streams comprising at least a first feed gas stream, a second
feed gas stream, and a third feed gas stream; combining the first
feed gas stream with a steam stream to produce a first input gas
stream; flowing the first input gas stream into a first shift
reactor containing a first shift catalyst; reacting the CO with the
steam in the presence of the first shift catalyst to produce a
first product gas stream comprising carbon dioxide (CO.sub.2) and
hydrogen (H.sub.2); combining the first product gas stream with the
second feed gas stream to produce a second input gas stream heated
by the first product gas stream; before combining the first product
gas stream with the second feed gas stream, adding water as a spray
to the first product gas stream to vaporize the water into steam,
wherein the first product gas stream is cooled before being
combined with the second feed gas stream; flowing the second input
gas stream into a second shift reactor containing a second shift
catalyst; reacting the CO of the second input gas stream with the
steam in the presence of the second shift catalyst to produce a
second product gas stream comprising CO.sub.2 and H.sub.2;
combining the second product gas stream with the third feed gas
stream to produce a third input gas stream heated by the second
product gas stream; before combining the second product gas stream
with the third feed gas stream, adding water as a spray to the
second product gas stream to vaporize the water into steam, wherein
the second product gas stream is cooled before being combined with
the third feed gas stream; flowing the third input gas stream into
a third shift reactor containing a third shift catalyst; and
reacting the CO of the third input gas stream with the steam in the
presence of the third shift catalyst to produce a third product gas
stream comprising CO.sub.2 and H.sub.2.
2. The method of claim 1, comprising adding water as a spray into
the first feed gas stream or the first input gas stream.
3. The method of claim 1, wherein the feed gas comprises
syngas.
4. The method of claim 1, wherein the feed gas comprises a sulfur
compound, and the first shift catalyst, the second shift catalyst,
and the third shift catalyst are sulfur-tolerant.
5. The method of claim 4, comprising removing at least part of the
sulfur compound from the third product gas stream.
6. The method of claim 1, wherein the feed gas comprises a sulfur
compound, and comprising removing at least part of the sulfur
compound from the flow of feed gas to reduce the amount of sulfur
compound in the first feed gas stream, the second feed gas stream,
and the third feed gas stream.
7. The method of claim 1, wherein the plurality of feed gas streams
comprises one or more additional feed gas streams, and further
comprising reacting the CO of the one or more additional feed gas
streams with steam in one or more additional shift reactors,
respectively, downstream from the third shift reactor.
8. The method of claim 1, comprising producing a local steam supply
by flowing liquid water into thermal contact with a heated gas
stream selected from the group consisting of: the first feed gas
stream; the second feed gas stream; the third feed gas stream; the
first input gas stream; the second input gas stream; the third
input gas stream; and a combination of two or more of the
foregoing.
9. The method of claim 8, wherein combining the first feed gas
stream with the steam stream comprises flowing steam from the local
steam supply into the first feed gas stream.
10. The method of claim 1, comprising heating the first feed gas
stream or the first input gas stream by flowing the first feed gas
stream or the first input gas stream into thermal contact with a
heated gas stream selected from the group consisting of: the first
product gas stream; the second product gas stream; the third
product gas stream; and a combination of two or more of the
foregoing.
11. The method of claim 1, wherein the plurality of feed gas
streams comprises a bypass gas stream, and further comprising
combining the bypass gas stream with the third product gas stream
to produce an output gas stream having a desired H.sub.2/CO
ratio.
12. The method of claim 1, comprising controlling a steam/dry gas
ratio in the first input gas stream by controlling a flow rate of
the steam stream added to the first feed gas stream, controlling a
flow rate of a liquid water stream added to the first feed gas
stream, or both of the foregoing.
13. The method of claim 1, comprising controlling a steam/dry gas
ratio in at least one of the second input gas stream and the third
input gas stream by controlling a flow rate of a liquid water
stream added to at least one of the second feed gas stream, the
second input gas stream, the third feed gas stream, and the third
input gas stream.
14. A water gas shift reaction system, comprising: a flow splitter
configured for splitting a flow of feed gas comprising carbon
monoxide (CO) into at least a first feed gas stream, a second feed
gas stream, and a third feed gas stream; a first input gas line
configured for conducting a first input gas stream, the first input
gas stream comprising a combination of the first feed gas stream
and steam; a first shift reactor comprising a first vessel, a first
shift catalyst disposed in the first vessel, a first inlet
configured for conducting the first input gas stream into the first
vessel, and a first outlet, wherein the first shift reactor is
configured for reacting the CO and the steam in the first input gas
stream in the presence of the first shift catalyst to produce a
first product gas stream comprising carbon dioxide (CO.sub.2) and
hydrogen (H.sub.2); a first product gas line configured for
receiving the first product gas stream from the first outlet; a
sprayer configured for adding water as a spray into the first
product gas stream; a second input gas line configured for
conducting a second input gas stream, the second input gas stream
comprising a combination of the second feed gas stream and the
first product gas stream; a second shift reactor comprising a
second vessel, a second shift catalyst disposed in the second
vessel, a second inlet configured for conducting the second input
gas stream into the second vessel, and a second outlet, wherein the
second shift reactor is configured for reacting the CO and the
steam in the second input gas stream in the presence of the second
shift catalyst to produce a second product gas stream comprising
CO.sub.2 and H.sub.2; a second product gas line configured for
receiving the second product gas stream from the second outlet; a
sprayer configured for adding water as a spray into the second
product gas stream; a third input gas line configured for
conducting a third input gas stream, the third input gas stream
comprising a combination of the third feed gas stream and the
second product gas stream; and a third shift reactor comprising a
third vessel, a third shift catalyst disposed in the third vessel,
a third inlet configured for conducting the third input gas stream
into the third vessel, and a third outlet, wherein the third shift
reactor is configured for reacting the CO and the steam in the
third input gas stream in the presence of the third shift catalyst
to produce a third product gas stream comprising CO.sub.2 and
H.sub.2.
15. The water gas shift reaction system of claim 14, comprising a
sprayer configured for adding water as a spray into the first input
gas stream.
16. A method for removing acid gases from a gas stream, the method
comprising: flowing a feed gas into a desulfurization unit to
remove a substantial fraction of a sulfur compound from the feed
gas, wherein the desulfurization unit produces a desulfurized feed
gas; flowing the desulfurized feed gas into a CO.sub.2 removal unit
to remove a substantial fraction of CO.sub.2 from the desulfurized
feed gas; and before or after desulfurizing the feed gas,
subjecting the feed gas to a water-gas shift reaction by: splitting
a flow of feed gas comprising carbon monoxide (CO) into a plurality
of feed gas streams comprising at least a first feed gas stream, a
second feed gas stream, and a third feed gas stream; combining the
first feed gas stream with a steam stream to produce a first input
gas stream; flowing the first input gas stream into a first shift
reactor containing a first shift catalyst; reacting the CO with the
steam in the presence of the first shift catalyst to produce a
first product gas stream comprising carbon dioxide (CO.sub.2) and
hydrogen (H.sub.2); combining the first product gas stream with the
second feed gas stream to produce a second input gas stream heated
by the first product gas stream; flowing the second input gas
stream into a second shift reactor containing a second shift
catalyst; reacting the CO of the second input gas stream with the
steam in the presence of the second shift catalyst to produce a
second product gas stream comprising CO.sub.2 and H.sub.2;
combining the second product gas stream with the third feed gas
stream to produce a third input gas stream heated by the second
product gas stream; flowing the third input gas stream into a third
shift reactor containing a third shift catalyst; and reacting the
CO of the third input gas stream with the steam in the presence of
the third shift catalyst to produce a third product gas stream
comprising CO.sub.2 and H.sub.2.
17. The method of claim 16, comprising a step selected from the
group consisting of: before combining the first product gas stream
with the second feed gas stream, adding water as a spray to the
first product gas stream to vaporize the water into steam, wherein
the first product gas stream is cooled before being combined with
the second feed gas stream; before combining the second product gas
stream with the third feed gas stream, adding water as a spray to
the second product gas stream to vaporize the water into steam,
wherein the second product gas stream is cooled before being
combined with the third feed gas stream; and both of the
foregoing.
18. The method of claim 16, comprising adding water as a spray into
the first feed gas stream or the first input gas stream.
19. The method of claim 16, wherein flowing the feed gas into the
desulfurization unit is done in a temperature range selected from
the group consisting of: about 400.degree. F. or greater; about
400.degree. F. to about 1200.degree. F.
20. The method of claim 16, wherein flowing the desulfurized gas
into the CO.sub.2 removal unit is done in range selected from the
group consisting of: about -80.degree. F. to about 30.degree. F.;
about 30.degree. F. to about 130.degree. F.; and about 200.degree.
F. to about 900.degree. F.
21. The method of claim 16, wherein flowing the feed gas into the
desulfurization unit comprises flowing the feed gas into contact
with a sorbent.
22. The method of claim 21, wherein sorbent is selected from the
group consisting of: a metal oxide, zinc oxide, copper oxide, iron
oxide, vanadium oxide, manganese oxide, stannous oxide, nickel
oxide, a metal titanate, zinc titanate, a metal ferrite, zinc
ferrite, copper ferrite, a sorbent comprising an alumina
(Al.sub.2O.sub.3) support, a sorbent comprising a silicon dioxide
(SiO.sub.2) support, a sorbent comprising a titanium dioxide
(TiO.sub.2) support, a sorbent comprising a zeolite support, a
sorbent having an average particle size in a range from about 35
.mu.m to about 175 .mu.m, and a combination of two or more of the
foregoing.
23. The method of claim 21, wherein flowing the feed gas into
contact with a sorbent comprises flowing the feed gas into contact
with a sorbent stream comprising the sorbent and a carrier gas.
24. The method of claim 23, wherein flowing the feed gas into
contact with the sorbent stream is done in an absorber unit, and
further comprising outputting the desulfurized gas and sulfided
sorbent from the absorber unit.
25. The method of claim 24, comprising flowing the sulfided sorbent
into a regenerating unit to produce a regenerated sorbent and a
sulfur compound, and flowing the regenerated sorbent into the
absorber unit.
26. The method of claim 16, wherein flowing the desulfurized gas
into the CO.sub.2 removal unit comprises flowing the desulfurized
gas into contact with a CO.sub.2 removing agent.
27. The method of claim 26, wherein flowing the desulfurized gas
into contact with the CO.sub.2 removing agent is done in an
absorber unit, and further comprising outputting from the absorber
unit a treated gas comprising the substantially reduced fractions
of sulfur and CO.sub.2.
28. The method of claim 27, wherein flowing the desulfurized gas
into contact with the CO.sub.2 removing agent produces in the
absorber unit a CO.sub.2-rich fluid comprising the CO.sub.2
removing agent and CO.sub.2, and further comprising: flowing the
CO.sub.2-rich fluid from the absorber unit to a regenerator unit;
removing CO.sub.2 from the CO.sub.2-rich fluid stream in the
regenerator unit to produce a CO.sub.2-lean fluid stream; and
flowing the CO.sub.2-lean fluid stream into the absorber unit.
29. A gas processing system, comprising: a desulfurization unit
configured for removing a substantial fraction of a sulfur compound
from a process gas to produce a desulfurized gas; and a CO.sub.2
removal unit positioned downstream from the desulfurization unit,
and configured for removing a substantial fraction of CO.sub.2 from
the desulfurized gas; and a water-gas shift unit positioned
upstream or downstream from the desulfurization unit, the water-gas
shift unit comprising: a flow splitter configured for splitting a
flow of feed gas comprising carbon monoxide (CO) into at least a
first feed gas stream, a second feed gas stream, and a third feed
gas stream; a first input gas line configured for conducting a
first input gas stream, the first input gas stream comprising a
combination of the first feed gas stream and steam; a first shift
reactor comprising a first vessel, a first shift catalyst disposed
in the first vessel, a first inlet configured for conducting the
first input gas stream into the first vessel, and a first outlet,
wherein the first shift reactor is configured for reacting the CO
and the steam in the first input gas stream in the presence of the
first shift catalyst to produce a first product gas stream
comprising carbon dioxide (CO.sub.2) and hydrogen (H.sub.2); a
first product gas line configured for receiving the first product
gas stream from the first outlet; a second input gas line
configured for conducting a second input gas stream, the second
input gas stream comprising a combination of the second feed gas
stream and the first product gas stream; a second shift reactor
comprising a second vessel, a second shift catalyst disposed in the
second vessel, a second inlet configured for conducting the second
input gas stream into the second vessel, and a second outlet,
wherein the second shift reactor is configured for reacting the CO
and the steam in the second input gas stream in the presence of the
second shift catalyst to produce a second product gas stream
comprising CO.sub.2 and H.sub.2; a second product gas line
configured for receiving the second product gas stream from the
second outlet; a third input gas line configured for conducting a
third input gas stream, the third input gas stream comprising a
combination of the third feed gas stream and the second product gas
stream; and a third shift reactor comprising a third vessel, a
third shift catalyst disposed in the third vessel, a third inlet
configured for conducting the third input gas stream into the third
vessel, and a third outlet, wherein the third shift reactor is
configured for reacting the CO and the steam in the third input gas
stream in the presence of the third shift catalyst to produce a
third product gas stream comprising CO.sub.2 and H.sub.2.
30. The gas processing system of claim 29, comprising a component
selected from the group consisting of: a sprayer configured for
adding water as a spray into the first product gas stream; a
sprayer configured for adding water as a spray into the second
product gas stream; and both of the foregoing.
31. The gas processing system of claim 29, comprising a sprayer
configured for adding water as a spray into the first input gas
stream.
Description
RELATED APPLICATIONS
[0001] This application is a continuation-in-part of and claims
priority to International Patent Application Serial No.
PCT/US2015/056391, filed Oct. 20, 2015, titled "INTEGRATED SYSTEM
AND METHOD FOR REMOVING ACID GAS FROM A GAS STREAM," which claims
the benefit of U.S. Provisional Patent Application Ser. No.
62/068,333, filed Oct. 24, 2014, titled "INTEGRATED SYSTEM AND
METHOD FOR REMOVING ACID GAS FROM A GAS STREAM," the contents of
both of which are incorporated herein by reference in their
entireties.
TECHNICAL FIELD
[0002] The present invention generally relates to the water gas
shift reaction, and specifically to implementing the reaction with
reduced steam consumption. The invention further relates to
implementing the water gas shift reaction in conjunction with
treating or purifying a gas stream, particularly removing acid
gases such as sulfur compounds and carbon dioxide from a gas
stream.
BACKGROUND
[0003] Gas processing and cleanup is a critical operation in the
chemical industry. Several industrial processes utilize gases that
need to be cleaned and the various contaminants (such as H.sub.2S,
SO.sub.2, COS, HCl, NH.sub.3, etc.) removed prior to their use. In
addition to removal of contaminants, the gas composition may also
need to be adjusted to meet process requirements for H.sub.2, CO
and/or CO.sub.2 content.
[0004] One of the process gases that are used heavily for
production of chemicals and power is synthesis gas or "syngas".
Syngas is produced from partial combustion of organic feedstocks
(coal, petcoke, biomass, oil) and consists primarily of CO and
H.sub.2. Syngas often contains contaminants (including H.sub.2S,
COS) depending on the starting raw material. The H.sub.2S and COS
in the syngas can de-activate the catalysts used in the downstream
processes and need to be removed to very low levels. In case of
power production, the sulfur species can oxidize and produce
SO.sub.2 during combustion which is regulated by the Environmental
Protection Agency (EPA) to reduce acid rain. As appreciated by
persons skilled in the art, other process gases likewise often
require cleanup, one further example being natural gas.
[0005] Several technologies have been developed to meet this need.
Most of the technologies use a solvent-based approach where the gas
species that need to be removed are absorbed in the solvent under
pressure at ambient or sub-ambient temperatures, and the solvent is
later regenerated by either flashing the solvent (reducing the
pressure) or by use of thermal energy (heating the solvent).
Examples of such processes include the SELEXOL.RTM. process by Dow
Chemicals (licensed to UOP) which uses a mixture of dimethyl ethers
of polyethylene glycol (DEPG), RECTISOL.RTM. by The Linde Group and
Lurgi AG which uses methanol as the solvent, amines (such as MDEA,
MEA, DEA etc.) as well as activated MDEA by BASF Corporation, Shell
Corporation, and UOP. These solvent-based removal processes are
typically referred to as acid gas removal (AGR) processes.
[0006] The H.sub.2S, COS, and CO.sub.2 are soluble in the different
solvents to varying degrees, and the solvent-based processes are
quite complex and are designed to separate out the H.sub.2S and COS
into separate streams. H.sub.2S/COS stream is used further
downstream, either for sulfur recovery or production of sulfuric
acid. The CO.sub.2 stream can be used in enhanced oil recovery
(EOR) or stored in geological aquifers or can be used to produce
value-added products such as algae, among other uses.
[0007] Chemical applications of syngas, such as methanol conversion
or Fischer-Tropsch conversion to fuels, typically require the
sulfur levels in the syngas to be very low, such as less than 100
ppbv. This ultra-low sulfur requirement is difficult for most AGR
processes to achieve. It would be desirable to be able to decouple
the process of removing sulfur compounds from the process of
removing CO.sub.2 in a way that would optimize the removal of both
sulfur compounds and CO.sub.2, whereby sulfur compounds could be
reduced to lower levels in the process gas, and higher levels of
purity of the sulfur compounds and CO.sub.2 could be achieved, than
would be possible from performing any of the conventional AGR
processes alone. Such decoupling could enable a number of these AGR
technologies to be used effectively in process gas-to-chemicals or
fuels applications where these AGR technologies cannot be used
currently and/or could enable a reduction in capital costs and/or
utility costs.
[0008] Syngas is the starting material for production of a variety
of chemicals. Syngas can also be used for power production in a gas
turbine. Syngas can also be used to produce H.sub.2, by converting
the CO to H.sub.2 via the water-gas-shift (WGS) process and
removing the CO.sub.2 in the gas stream and purifying the treated
gas using a pressure swing adsorption (PSA) or a membrane process.
The H.sub.2 to CO ratio of the process gas needs to be carefully
adjusted to meet the downstream applications demand.
[0009] The WGS reaction is utilized to shift carbon monoxide (CO)
to carbon dioxide (CO.sub.2) and diatomic hydrogen gas (H.sub.2) by
reacting the CO with steam over a catalyst bed. WGS is an
industrially important process utilized to increase the H.sub.2/CO
ratio to meet the downstream process requirements of a particular
application. For example, WGS finds applications in pre-combustion
CO.sub.2 capture where a fuel is partially oxidized to produce
synthesis gas (or "syngas," predominantly consisting of
CO+H.sub.2). This syngas is shifted to maximize the H.sub.2 and
CO.sub.2 concentrations, and CO.sub.2 removal prior to combustion
of the H.sub.2-rich clean gas in turbines for generating
electricity. WGS also finds widespread applications in chemicals
production where the H.sub.2/CO ratio needs to be adjusted as per
the process requirements. For example, the synthesis of methanol
(CH.sub.3OH), CO+2H.sub.2.fwdarw.CH.sub.3OH, requires the
H.sub.2/CO ratio to be 2.
[0010] WGS is a moderately exothermic reversible reaction and is
expressed by:
CO+H.sub.2OCO.sub.2+H.sub.2, .DELTA.H.sup.0.sub.298=-41.09
kiloJoules/mole (kJ/mol),
[0011] where .DELTA.H.sup.0.sub.298 is the enthalpy of reaction at
298 kelvin (K).
[0012] The equilibrium constant of the reaction decreases with
increasing temperature. The reaction is thermodynamically favored
at low temperatures and kinetically favored at high temperatures.
As there is no change in the volume from reactants to products, the
reaction is not affected by pressure.
[0013] The equilibrium of this reaction shows significant
temperature dependence and the equilibrium constant decreases with
an increase in temperature, that is, higher carbon monoxide
conversion is observed at lower temperatures. In order to take
advantage of both the thermodynamics and kinetics of the reaction,
the industrial scale WGS is conducted in multiple adiabatic stages
with cooling in-between the reactors.
[0014] In traditional AGR processes such as the RECTISOL.RTM. and
SELEXOL.RTM. processes, the WGS is done upstream of the AGR process
and is called a "sour gas shift." The gas to be shifted contains
sulfur (as hydrogen sulfide (H.sub.2S) and carbonyl sulfide (COS))
and requires an expensive catalyst that is sulfur tolerant and
promotes the shift reaction in the presence of H.sub.2S and COS.
Examples of sulfur tolerant shift catalysts include
cobalt-molybdenum (Co--Mo) and nickel-molybdenum (Ni--Mo). When the
shift is carried out downstream of the AGR, it is termed as "sweet
gas shift" and does not require a sulfur tolerant catalyst. The
sweet shift catalysts are less expensive than the sulfur-tolerant
sour gas shift catalyst. Examples of sweet shift catalysts include
chromium or copper promoted iron-based catalysts.
[0015] Thus, it would be desirable to be able to decouple the
process of removing sulfur compounds from the process of removing
CO.sub.2 so as to facilitate implementation of the WGS downstream
of the sulfur removal process. This may enable better control over
the H.sub.2/CO ratio and/or removal of CO.sub.2, as well as the use
of the less expensive sweet shift catalysts.
[0016] The water gas shift process uses steam to shift CO to
CO.sub.2 and produces H.sub.2 in the process. In addition to being
a reactant, the steam also serves to move the equilibrium of the
water gas shift forward to higher H.sub.2, controlling the
temperature rise from the exothermic water gas shift reaction,
which if left unchecked could de-activate the catalyst. The steam
is also required to prevent coking on the catalyst surface, which
also deactivates the catalyst. Most catalyst vendors require a
steam to dry gas ratio of 2.0 or higher to prevent catalyst
de-activation. This high steam requirement of the water gas shift
process imposes a large parasitic load penalty on the shift
process. In the case of performing an integrated gasification
combined cycle (IGCC) for power production, this steam could be
sent to the steam turbine to generate additional power.
[0017] Traditionally, WGS is carried out using two reactors in
series to carry out a high temperature shift (HTS) followed by a
low temperature shift (LTS). Steam is added to the syngas fed to
the first reactor. The syngas from the outlet of the first reactor
is cooled to the desired shift inlet temperature by raising steam
and the cooled syngas is fed to the second reactor. The amount of
steam required and the equipment needed for generating the steam
represent significant energy costs.
[0018] It would therefore also be desirable to reduce energy costs
by reducing the amount of steam required for the carrying out the
WGS reaction.
SUMMARY
[0019] To address the foregoing problems, in whole or in part,
and/or other problems that may have been observed by persons
skilled in the art, the present disclosure provides methods,
processes, systems, apparatus, instruments, and/or devices, as
described by way of example in implementations set forth below.
[0020] According to one embodiment, a method for producing a
water-gas shifted gas comprising CO.sub.2 and H.sub.2 includes:
splitting a flow of feed gas comprising carbon monoxide (CO) into a
plurality of feed gas streams comprising at least a first feed gas
stream, a second feed gas stream, and a third feed gas stream;
combining the first feed gas stream with a steam stream to produce
a first input gas stream; flowing the first input gas stream into a
first shift reactor containing a first shift catalyst; reacting the
CO with the steam in the presence of the first shift catalyst to
produce a first product gas stream comprising carbon dioxide
(CO.sub.2) and hydrogen (H.sub.2); combining the first product gas
stream with the second feed gas stream to produce a second input
gas stream heated by the first product gas stream; before combining
the first product gas stream with the second feed gas stream,
adding water as a spray to the first product gas stream to vaporize
the water into steam, wherein the first product gas stream is
cooled before being combined with the second feed gas stream;
flowing the second input gas stream into a second shift reactor
containing a second shift catalyst; reacting the CO of the second
input gas stream with the steam in the presence of the second shift
catalyst to produce a second product gas stream comprising CO.sub.2
and H.sub.2; combining the second product gas stream with the third
feed gas stream to produce a third input gas stream heated by the
second product gas stream; before combining the second product gas
stream with the third feed gas stream, adding water as a spray to
the second product gas stream to vaporize the water into steam,
wherein the second product gas stream is cooled before being
combined with the third feed gas stream; flowing the third input
gas stream into a third shift reactor containing a third shift
catalyst; and reacting the CO of the third input gas stream with
the steam in the presence of the third shift catalyst to produce a
third product gas stream comprising CO.sub.2 and H.sub.2.
[0021] According to another embodiment, a water gas shift reaction
system is configured to perform any of the methods disclosed
herein.
[0022] According to another embodiment, a water gas shift reaction
system includes: a flow splitter configured for splitting a flow of
feed gas comprising carbon monoxide (CO) into at least a first feed
gas stream, a second feed gas stream, and a third feed gas stream;
a first input gas line configured for conducting a first input gas
stream, the first input gas stream comprising a combination of the
first feed gas stream and steam; a first shift reactor comprising a
first vessel, a first shift catalyst disposed in the first vessel,
a first inlet configured for conducting the first input gas stream
into the first vessel, and a first outlet, wherein the first shift
reactor is configured for reacting the CO and the steam in the
first input gas stream in the presence of the first shift catalyst
to produce a first product gas stream comprising carbon dioxide
(CO.sub.2) and hydrogen (H.sub.2); a first product gas line
configured for receiving the first product gas stream from the
first outlet; a sprayer configured for adding water as a spray into
the first product gas stream; a second input gas line configured
for conducting a second input gas stream, the second input gas
stream comprising a combination of the second feed gas stream and
the first product gas stream; a second shift reactor comprising a
second vessel, a second shift catalyst disposed in the second
vessel, a second inlet configured for conducting the second input
gas stream into the second vessel, and a second outlet, wherein the
second shift reactor is configured for reacting the CO and the
steam in the second input gas stream in the presence of the second
shift catalyst to produce a second product gas stream comprising
CO.sub.2 and H.sub.2; a second product gas line configured for
receiving the second product gas stream from the second outlet; a
sprayer configured for adding water as a spray into the second
product gas stream; a third input gas line configured for
conducting a third input gas stream, the third input gas stream
comprising a combination of the third feed gas stream and the
second product gas stream; and a third shift reactor comprising a
third vessel, a third shift catalyst disposed in the third vessel,
a third inlet configured for conducting the third input gas stream
into the third vessel, and a third outlet, wherein the third shift
reactor is configured for reacting the CO and the steam in the
third input gas stream in the presence of the third shift catalyst
to produce a third product gas stream comprising CO.sub.2 and
H.sub.2.
[0023] According to another embodiment, a method for removing acid
gases from a gas stream includes: flowing a feed gas into a
desulfurization unit to remove a substantial fraction of a sulfur
compound from the feed gas, wherein the desulfurization unit
produces a desulfurized feed gas; flowing the desulfurized feed gas
into a CO.sub.2 removal unit to remove a substantial fraction of
CO.sub.2 from the desulfurized feed gas; and before or after
desulfurizing the feed gas, subjecting the feed gas to a water-gas
shift reaction by: splitting a flow of feed gas comprising carbon
monoxide (CO) into a plurality of feed gas streams comprising at
least a first feed gas stream, a second feed gas stream, and a
third feed gas stream; combining the first feed gas stream with a
steam stream to produce a first input gas stream; flowing the first
input gas stream into a first shift reactor containing a first
shift catalyst; reacting the CO with the steam in the presence of
the first shift catalyst to produce a first product gas stream
comprising carbon dioxide (CO.sub.2) and hydrogen (H.sub.2);
combining the first product gas stream with the second feed gas
stream to produce a second input gas stream heated by the first
product gas stream; flowing the second input gas stream into a
second shift reactor containing a second shift catalyst; reacting
the CO of the second input gas stream with the steam in the
presence of the second shift catalyst to produce a second product
gas stream comprising CO.sub.2 and H.sub.2; combining the second
product gas stream with the third feed gas stream to produce a
third input gas stream heated by the second product gas stream;
flowing the third input gas stream into a third shift reactor
containing a third shift catalyst; and reacting the CO of the third
input gas stream with the steam in the presence of the third shift
catalyst to produce a third product gas stream comprising CO.sub.2
and H.sub.2.
[0024] According to another embodiment, a gas processing system is
configured to perform any of the methods disclosed herein.
[0025] According to another embodiment, a gas processing system
includes: a desulfurization unit configured for removing a
substantial fraction of a sulfur compound from a process gas to
produce a desulfurized gas; and a CO.sub.2 removal unit positioned
downstream from the desulfurization unit, and configured for
removing a substantial fraction of CO.sub.2 from the desulfurized
gas; and a water-gas shift unit positioned upstream or downstream
from the desulfurization unit, the water-gas shift unit comprising:
a flow splitter configured for splitting a flow of feed gas
comprising carbon monoxide (CO) into at least a first feed gas
stream, a second feed gas stream, and a third feed gas stream; a
first input gas line configured for conducting a first input gas
stream, the first input gas stream comprising a combination of the
first feed gas stream and steam; a first shift reactor comprising a
first vessel, a first shift catalyst disposed in the first vessel,
a first inlet configured for conducting the first input gas stream
into the first vessel, and a first outlet, wherein the first shift
reactor is configured for reacting the CO and the steam in the
first input gas stream in the presence of the first shift catalyst
to produce a first product gas stream comprising carbon dioxide
(CO.sub.2) and hydrogen (H.sub.2); a first product gas line
configured for receiving the first product gas stream from the
first outlet; a second input gas line configured for conducting a
second input gas stream, the second input gas stream comprising a
combination of the second feed gas stream and the first product gas
stream; a second shift reactor comprising a second vessel, a second
shift catalyst disposed in the second vessel, a second inlet
configured for conducting the second input gas stream into the
second vessel, and a second outlet, wherein the second shift
reactor is configured for reacting the CO and the steam in the
second input gas stream in the presence of the second shift
catalyst to produce a second product gas stream comprising CO.sub.2
and H.sub.2; a second product gas line configured for receiving the
second product gas stream from the second outlet; a third input gas
line configured for conducting a third input gas stream, the third
input gas stream comprising a combination of the third feed gas
stream and the second product gas stream; and a third shift reactor
comprising a third vessel, a third shift catalyst disposed in the
third vessel, a third inlet configured for conducting the third
input gas stream into the third vessel, and a third outlet, wherein
the third shift reactor is configured for reacting the CO and the
steam in the third input gas stream in the presence of the third
shift catalyst to produce a third product gas stream comprising
CO.sub.2 and H.sub.2.
[0026] Other devices, apparatus, systems, methods, features and
advantages of the invention will be or will become apparent to one
with skill in the art upon examination of the following figures and
detailed description. It is intended that all such additional
systems, methods, features and advantages be included within this
description, be within the scope of the invention, and be protected
by the accompanying claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0027] The invention can be better understood by referring to the
following figures. The components in the figures are not
necessarily to scale, emphasis instead being placed upon
illustrating the principles of the invention. In the figures, like
reference numerals designate corresponding parts throughout the
different views.
[0028] FIG. 1 is a schematic view of an example of a gas processing
system in which acid gas removal methods disclosed herein may be
implemented according to some embodiments.
[0029] FIG. 2 is a schematic view of an example of a
desulfurization system (or unit) according to some embodiments.
[0030] FIG. 3 is a schematic view of an example of a CO.sub.2
removal system (or unit) according to some embodiments.
[0031] FIG. 4 is a schematic view of an example of a stand-alone
RECTISOL.RTM. process utilized for removal of S and CO.sub.2.
[0032] FIG. 5 is a schematic view of an example of a warm gas
desulfurization process integrated with a decoupled RECTISOL.RTM.
process configured for CO.sub.2 scrubbing according to some
embodiments.
[0033] FIG. 6 is a schematic view of an example of a stand-alone
SELEXOL.RTM. process utilized for removal of S and CO.sub.2.
[0034] FIG. 7 is a schematic view of an example of a decoupled
SELEXOL.RTM. process configured for CO.sub.2 scrubbing, which is
configured for integration with an upstream warm gas
desulfurization process, according to some embodiments.
[0035] FIG. 8 is a schematic view of an example of a water gas
shift reaction system according to some embodiments.
[0036] FIG. 9A is a schematic view of an example of a gas
processing system in which a WGS system may be integrated according
to some embodiments.
[0037] FIG. 9B is a schematic view of another example of a gas
processing system in which a WGS system may be integrated according
to some embodiments.
[0038] FIG. 10 is a cross-sectional schematic view of a sprayer
positioned in fluid communication with a gas stream line according
to an embodiment.
DETAILED DESCRIPTION
[0039] As used herein, the term "syngas" refers to synthesis gas.
In the context of the present disclosure, syngas is a mixture of at
least carbon monoxide (CO) and diatomic hydrogen gas (H.sub.2).
Depending on the embodiment, syngas may additionally include other
components such as, for example, water, air, diatomic nitrogen gas
(N.sub.2), diatomic oxygen gas (O.sub.2), carbon dioxide
(CO.sub.2), sulfur compounds (e.g., hydrogen sulfide (H.sub.2S),
carbonyl sulfide (COS), sulfur oxides (SO.sub.x), etc.), nitrogen
compounds (e.g., nitrogen oxides (NO.sub.x), etc.), metal
carbonyls, hydrocarbons (e.g., methane (CH.sub.4)), ammonia
(NH.sub.3), chlorides (e.g., hydrogen chloride (HCl)), hydrogen
cyanide (HCN), trace metals and metalloids (e.g., mercury (Hg),
arsenic (As), selenium (Se), cadmium (Cd), etc.) and compounds
thereof, particulate matter (PM), etc.
[0040] As used herein, the term "natural gas" refers to a mixture
of hydrocarbon (HC) gases consisting primarily of methane and
lesser amounts of higher alkanes. Depending on the embodiment,
natural gas may additionally include non-HC species such as one or
more of those noted above, as well as carbon disulfide (CS.sub.2)
and/or other disulfides, and mercaptans (thiols) such as
methanethiol (CH.sub.3SH) and ethanethiol (C.sub.2H.sub.5SH) and
other organosulfur compounds.
[0041] As used herein, the term "fluid" generally encompasses the
term "liquid" as well as term "gas" unless indicated otherwise or
the context dictates otherwise. The term "fluid" encompasses a
fluid in which particles may be suspended or carried. The term
"gas" encompasses a gas that may include or entrain a vapor or
liquid droplets. The term "fluid," "liquid" or "gas" encompasses a
"fluid," "liquid" or "gas" that includes a single component
(species) or a mixture of two or more different components.
Examples of multicomponent mixtures include, but are not limited
to, syngas and natural gas as described above.
[0042] As used herein, the term "process gas" generally refers to
any gas initially containing one or more sulfur compounds and
CO.sub.2. A process gas at an initial stage of a gas processing
method as disclosed herein, i.e., when initially inputted to a gas
processing system as disclosed herein, may also be referred to as a
"raw gas" or a "feed gas." A process gas after undergoing
desulfurization and CO.sub.2 removal according to a gas processing
method as disclosed herein may also be referred to as a "treated
gas," "clean gas," "cleaned gas," or "purified gas." The term
"process gas" generally is not limiting as to the composition of
the gas at any particular stage of the gas processing method. For
example, the term "process gas" does not by itself provide any
indication of the concentrations of sulfur compounds, CO.sub.2, or
other species in the gas at any particular time. Examples of
process gases include, but are not limited to, syngas and natural
gas as described above. Further examples of process gases are gases
that include one or more of: CO, CO.sub.2, H.sub.2, and
hydrocarbon(s) (HCs).
[0043] The present disclosure provides methods for removing acid
gases from a gas stream. In certain embodiments, the method entails
a warm-gas desulfurization process (WDP) in which a solid sorbent
is utilized to selectively remove sulfur compounds such as H.sub.2S
and COS from a process gas. The sorbent may be regenerable or
disposable. The desulfurization process may take place at a
temperature of about 400.degree. F. or greater. The sulfur
compounds removed from the process gas may thereafter be recovered,
or utilized to produce other sulfur compounds, and/or utilized to
recover elemental sulfur by performing the conventional Claus
process or other sulfur recovery process.
[0044] The WDP may be provided as an upstream process that is
integrated with a downstream CO.sub.2 removal process to provide an
overall AGR process. The WDP may further be integrated with
additional downstream processes effective for removing other
contaminants or impurities, thereby providing a comprehensive gas
cleaning process. Generally, it is presently contemplated that the
WDP is compatible with any CO.sub.2 removal process. In some
embodiments, the CO.sub.2 removal process may be an AGR process
modified to primarily or exclusively (or selectively) remove
CO.sub.2. In all such embodiments, the integrated gas treatment
process decouples the sulfur removal from the CO.sub.2 removal,
which may simplify the process and dramatically reduce the capital
costs and operating expenses of the process. Moreover, the
decoupling of removal of sulfur and CO.sub.2 using WDP may enable
the combination of WDP and any existing or emerging AGR process to
remove sulfur to lower levels and produce purer sulfur and CO.sub.2
byproduct streams than achievable by any of the AGR processes
alone. Moreover, the upstream placement of WDP may enable a number
of these AGR technologies to be used effectively in process
gas-to-chemicals or fuels applications where they cannot be used
currently. Furthermore, the decoupling of upstream WDP from the
CO.sub.2 removal opens up the possibility of performing a WGS
process downstream of the sulfur removal process, i.e., sweet gas
shifting. As noted above, the sweet shift catalysts are
significantly less expensive than the sulfur-tolerant sour gas
shift catalysts, thus leading to further cost savings.
[0045] According to some embodiments, the method for removing acid
gases from a gas stream includes flowing a feed gas into a
desulfurization unit to remove a substantial fraction of sulfur
compounds from the feed gas. The resulting desulfurized gas is then
flowed into a CO.sub.2 removal unit to remove a substantial
fraction of CO.sub.2 from the desulfurized gas.
[0046] In various embodiments, the desulfurization unit and/or the
CO.sub.2 removal unit may include one of the following
configurations: a fixed-bed reactor, a moving-bed reactor, a
fluidized-bed reactor, a transport reactor, a monolith, a
micro-channel reactor, an absorber unit, or an absorber unit in
fluid communication with a regenerator unit.
[0047] According to further embodiments, the method for removing
acid gas from a gas stream may include flowing a feed gas stream
including carbon monoxide (CO), carbon dioxide (CO.sub.2), and a
sulfur compound into contact with a sorbent stream in an absorber
unit to produce a first output gas stream. The first output gas
stream includes a desulfurized gas (including at least CO and
CO.sub.2) and a sulfided (or sulfur loaded) sorbent. The
desulfurized gas is then separated from the sulfided sorbent. The
resulting desulfurized gas is then flowed into contact with a
CO.sub.2 removing agent in a CO.sub.2 removal unit to produce a
treated gas that includes CO and substantially reduced fractions of
sulfur and CO.sub.2. During the desulfurization process, the
sorbent compound is regenerated. Specifically, after separating the
sulfided sorbent from the desulfurized gas, the sulfided sorbent is
flowed into contact with a regenerating agent in a regenerator unit
to produce a second output gas stream that includes regenerated
sorbent compound and a sulfur compound. The regenerated sorbent
compound is then separated from the sulfur compound produced in the
regenerator unit, and the regenerated sorbent compound is then
flowed into the absorber unit for reuse in the desulfurization
process. The sulfur compound produced in the regenerator unit is
outputted from the regenerator unit and may be recovered, or
subjected to further processing to synthesize different sulfur
compounds of interest or elemental sulfur. Additionally, the
CO.sub.2 removed by the CO.sub.2 removal unit is outputted from the
CO.sub.2 removal unit and may be recovered or subjected to further
processing as desired.
[0048] The process gas subjected to the foregoing acid gases
removal method may be any gas that includes one or more types of
sulfur compounds and CO.sub.2, and may be supplied from any
suitable feed gas source. Examples of process gases include, but
are not limited to, exhaust gases (or flue gases) outputted from a
combustion process (e.g., from a power plant, boiler, furnace, kiln
or the like fired by a fossil fuel such as coal or other
carbonaceous materials, an internal combustion engine, etc.);
natural gas; a syngas produced by the gasification of fossil fuels
or biomass materials or waste materials or reforming of natural
gases; or the byproduct of a chemical conversion or synthesis
process. In some embodiments in which the process gas is syngas,
the syngas may be a shifted syngas, thus containing an increased
amount of CO.sub.2 to be removed by the acid gas removal method.
The shifted syngas may be the result of a process (e.g., water-gas
shift) carried out upstream of the desulfurization stage of the
acid gas removal method.
[0049] The sorbent stream may be formed by a solid particulate
sorbent carried in any suitable process gas such as, for example,
syngas or inert carrier gas (or aeration gas) such as, for example,
nitrogen (N.sub.2). The sorbent stream may flow through the
absorber unit in a co-flow, counter-flow, or cross-flow relation to
the flow of the feed gas in the absorber unit. In some embodiments,
the particles of the sorbent compound have an average particle size
in a range from about 35 .mu.m to about 175 .mu.m. In the present
context, "size" or "characteristic dimension" refers to a dimension
that appropriately characterizes the size of the particle in view
of its shape or approximated shape. For example, the particles may
be characterized as being at least approximately spherical, in
which case "size" may correspond to diameter. Generally, no
limitation is placed on the dispersity of the particle size of the
particles.
[0050] Generally, the particulate sorbent may be any sorbent
compound effective for removing the sulfur compound from the feed
gas stream, by any suitable mechanism or combination of mechanisms
such as adsorption, absorption, or chemical reaction. Examples of
sorbent compounds effective for sulfur removal include, but are not
limited to, metal oxides such as zinc oxide, copper oxide, iron
oxide, vanadium oxide, manganese oxide, stannous oxide, and nickel
oxide; metal titanates such as zinc titanate; metal ferrites such
as zinc ferrite and copper ferrite; and a combination of two or
more of the foregoing. The sorbent may be regenerable or
non-regenerable (or at least disposable). Thus, certain embodiments
of the method may entail regenerating the sorbent, while other
embodiments do not.
[0051] In some embodiments, the particles may be polyphase
materials. For example, the particles may comprise a metal oxide
phase and a metal aluminate phase, e.g. a zinc oxide (ZnO) phase
and a zinc aluminate (ZnAl.sub.2O.sub.4) phase. More generally, the
sorbent may include a support such as, for example, alumina
(Al.sub.2O.sub.3), silicon dioxide (SiO.sub.2), titanium dioxide
(TiO.sub.2), a zeolite, or a combination of two or more of the
foregoing.
[0052] Taking metal oxide as an example of the sorbent, the
reactions associated with removing H.sub.2S and COS from the
process gas may be expressed as follows:
MO+H.sub.2S.fwdarw.MS+H.sub.2O, and
MO+COS.fwdarw.MS+CO.sub.2,
[0053] where M is the active metal of the metal oxide sorbent, MO
is the metal oxide, and MS is the metal sulfide (the sulfided
sorbent).
[0054] Generally, the regenerating agent may be any compound
effective for removing sulfur from the particular sulfided sorbent
utilized in the method, i.e., for regenerating the sorbent compound
or enhancing regeneration of the sorbent compound in the
regenerator unit. In some embodiments, the regenerating agent may
be a stripping gas that is flowed into contact with the sulfided
sorbent to enhance recovery of the sorbent compound during a flash
vaporization regeneration process. In some embodiments, the
regenerating agent desorbs the sulfur from the sulfided sorbent. In
some embodiments, the regenerating agent comprises air or oxygen
gas (O.sub.2) or an oxygen compound, and the sulfur compound of the
second output gas stream comprises sulfur dioxide. In this case,
again taking metal oxide as an example of the sorbent, the
regeneration process converts the metal sulfide back to the metal
oxide, as expressed by:
MS+(3/2)O.sub.2.fwdarw.MO+SO.sub.2.
[0055] After separating the regenerated sorbent compound from the
SO.sub.2 or other sulfur compound, the gas stream containing the
SO.sub.2 or other sulfur compound may be routed to any desired
destination for any desired purpose, such as recovering the
SO.sub.2 for further use, producing sulfuric acid or other desired
sulfur compound, and/or producing elemental sulfur by any suitable
process.
[0056] As noted above, the desulfurization process is a warm gas
desulfurization process. In some embodiments, the desulfurization
process is implemented in the absorber unit at a temperature of
about 400.degree. F. or greater. In some embodiments, the
desulfurization process is implemented in the absorber unit at a
temperature in a range from about 400.degree. F. to about
1100.degree. F. In some embodiments, the desulfurization process is
implemented in the absorber unit at a pressure in a range from
about atmospheric pressure to about 1500 psia. The regeneration
process is typically carried out at a higher temperature than the
desulfurization process. In some embodiments, the regeneration
process is implemented in the regenerator unit at a temperature of
about 900.degree. F. or greater. In some embodiments, the
regeneration process is implemented in the regenerator unit at a
temperature in a range from about 900.degree. F. to about
1400.degree. F. In some embodiments, the regeneration process is
implemented in the absorber unit at a pressure in a range from
about atmospheric pressure to about 1500 psia.
[0057] The absorber unit generally may have any configuration
suitable for maintaining flows of the feed gas and the sorbent
stream with sufficient time of contact between the feed gas and
sorbent, and at a temperature and pressure, effective for reducing
the concentration of sulfur compounds in the feed gas by a desired
amount. For such purposes, the absorber unit generally may include
a vessel having an inlet for the feed gas, an inlet for the
regenerated sorbent, and an outlet for the above-described first
output gas stream (desulfurized gas and sulfided sorbent).
Alternatively, the vessel may include a solids separation zone, in
which case the vessel may include respective outlets for a
desulfurized gas stream and a sulfided sorbent stream. In some
embodiments, the vessel may also include one or more inlets for
adding fresh make-up sorbent, inert carrier gas, and/or any other
additive fluid. In some embodiments, the absorber unit may include
two or more vessels fluidly coupled by transfer pipes. Multiple
vessels may be configured for implementing multiple absorption
stages, and/or for implementing different functions. For example,
one vessel may be configured primarily for accumulating or holding
sorbent material and/or for establishing a sorbent-laden gas
stream, while another vessel may be configured primarily for
establishing a fluidized zone in which the interaction (or the
majority of the interaction) between the feed gas and sorbent takes
place. As another example, a vessel may be configured for
temperature control, pressure control, or solids separation.
[0058] The regenerator unit may be fluidly coupled to the absorber
unit by one or more transfer pipes or other appropriate plumbing.
The regenerator unit generally may have any configuration suitable
for promoting contact between the sulfided sorbent and regenerating
agent for a period of time and at a temperature and pressure
effective for regenerating an acceptable amount of sorbent for
redeployment in the absorber unit. For such purposes, the
regenerator unit generally may include a vessel having an inlet for
the sulfided sorbent, an inlet for the regenerating agent, and an
outlet for the above-described second output gas stream
(regenerated sorbent compound and off-gas sulfur compound).
Alternatively, the vessel may include a solids separation zone, in
which case the vessel may include respective outlets for a
regenerated sorbent stream and an off-gas sulfur compound stream.
Similar to the absorber unit, in some embodiments the regenerator
unit may include two or more vessels for implementing multiple
regeneration stages and/or specific functions.
[0059] The process of separating the desulfurized gas from the
sulfided sorbent in the absorber unit, and the process of
separating the regenerated sorbent compound from the sulfur
compound (e.g., SO.sub.2) produced in the regenerator unit, may
generally be implemented by any means effective for the composition
of the gases and sulfided sorbent to be separated. In some
embodiments, separation may be implemented by flowing the first
output gas stream produced in the absorber unit, and the second
output gas stream produced in the regenerator unit, into respective
solids separators (solid separator devices). The respective solids
separators may be physically located downstream of the absorber
unit and the regenerator unit, or alternatively may be integrated
with the absorber unit and the regenerator unit in respective
separation zones thereof. Examples of a solids separator include,
but are not limited to, a cyclone separator, an electrostatic
precipitator, a filter, and a gravity settling chamber.
[0060] In some embodiments, the composition and properties of the
sorbent compound, the method for fabrication of the sorbent
compound, the use of the sorbent compound in removing sulfur
compounds, the subsequent regeneration of the sorbent compound, and
the configuration of the absorber unit and the regenerator unit,
may be in accordance with descriptions provided in one or more of
the following references: U.S. Pat. No. 8,696,792; U.S. Pat. No.
6,951,635; U.S. Pat. No. 6,306,793; U.S. Pat. No. 5,972,835; U.S.
Pat. No. 5,914,288; and U.S. Pat. No. 5,714,431; the entire
contents of each of which are incorporated by reference herein.
[0061] Embodiments of the acid gas removal method may be highly
effective for removing substantially all sulfur content from the
process gas, while minimizing attrition of the sorbent utilized for
desulfurization. In some embodiments, the desulfurized gas
outputted from the absorber unit (and separated from the
sulfur-laden sorbent) has a sulfur concentration of about 25 parts
per million (ppm) by volume or less. In some embodiments, the
desulfurized gas has a sulfur concentration of about 100 parts per
billion (ppb) by volume or less.
[0062] As described above, the acid gas removal method includes
flowing the desulfurized gas to a CO.sub.2 removal unit where it is
contacted with a CO.sub.2 removing agent. By implementing the
upstream warm gas desulfurization process described herein, the
application of external refrigeration or sub-ambient cooling
requirements for removing CO.sub.2 are reduced or eliminated. In
particular, the desulfurized gas fed to the CO.sub.2 removal unit
need not be cryogenically cooled via a refrigeration system. In
some embodiments, flowing the desulfurized gas into contact with
the CO.sub.2 removing agent is done at a temperature ranging from
about -80.degree. F. to about 30.degree. F. In other embodiments,
flowing the desulfurized gas into contact with the CO.sub.2
removing agent is done at a temperature ranging from about
30.degree. F. to about 130.degree. F. In other embodiments, a warm
gas CO.sub.2 removal process may be performed. As one non-limiting
example of the latter case, the desulfurized gas may be flowed into
contact with the CO.sub.2 removing agent at a temperature ranging
from about 200.degree. F. to about 900.degree. F.
[0063] Generally, the CO.sub.2 removing agent may be any agent
effective for capturing CO.sub.2 from the desulfurized gas stream.
In some embodiments, the CO.sub.2 removing agent may be a
solvent-based agent that removes CO.sub.2 by gas absorption and
subsequent regeneration. Thus, in some embodiments, the CO.sub.2
removing agent is a physical solvent such as utilized in the
RECTISOL.RTM. process, the SELEXOL.RTM. process, the PURISOL.RTM.
process (Lurgi AG Corp., Frankfurt, Fed. Rep. of Germany), and the
Fluor Solvent.TM. process. Examples of such solvents effective as
CO.sub.2 removing agents include, but are not limited to, methanol,
a mixture of dimethyl ethers of polyethylene (DEPG),
N-methyl-2-pyrrolidone (NMP), sulfolane
(2,3,4,5-tetrahydrothiophene-1,1-dioxide), propylene carbonate
(C.sub.4H.sub.6O.sub.3), and a combination of two or more of the
foregoing.
[0064] In other embodiments, the CO.sub.2 removing agent may be a
chemical solvent such as amine-based solvents; formulated amines
such as aMDEA (BASF Corp., Florham Park, N.J., USA), ADIP (Shell
Global Solutions International B.V, The Hague, The Netherlands),
and Amine Guard.TM. FS process solvent (UOP A Honeywell Company,
Des Plaines, Ill., USA); and the Benfield.TM. process solvent
(UOP). Examples of such solvents effective as CO.sub.2 removing
agents include, but are not limited to, methyldiethanolamine
(MDEA), activated MDEA (aMDEA), monoethanolamine (MEA),
diethanolamine (DEA), triethanolamine (TEA), diisopropanolamine
(DIPA), diglycolamine (DGA), potassium carbonate (K.sub.2CO.sub.3),
and a combination of two or more of the foregoing.
[0065] In other embodiments, the CO.sub.2 removing agent may be a
hybrid solvent that combines the high purity gas treatment offered
by chemical solvents with the flash regeneration and lower energy
requirements of physical solvents. Thus, in some embodiments, the
CO.sub.2 removing agent may be a solvent or mixture of solvents
such as Sulfinol.TM. (Shell), FLEXSORB.RTM. PS solvent (ExxonMobil
Chemical Company, Houston, Tex., USA), and UCARSOL.RTM. LE solvent
(Union Carbide Corporation, Danbury, Conn., USA). Examples of such
solvents effective as CO.sub.2 removing agents include, but are not
limited to, a mixture of sulfolane
(2,3,4,5-tetrahydrothiophene-1,1-dioxide), water, and one or more
of methyldiethanolamine (MDEA), piperazine
(C.sub.4H.sub.10N.sub.2), and diisopropanolamine (DIPA).
[0066] In other embodiments, the CO.sub.2 removing agent may be a
sorbent-based agent. Examples include, but are not limited to,
alkali metal oxides, alkali metal carbonates, lithium silicate,
amine-functionalized solid sorbents, amine-functionalized silica,
amine-functionalized zeolites, amine-functionalized hydrotalcites,
amine-functionalized metal-organic frameworks, and a combination of
two or more of the foregoing.
[0067] In other embodiments, the CO.sub.2 removing agent may be a
membrane effective for dissolution and diffusion of CO.sub.2. The
membrane material may, for example, be polymer- or
cellulose-based.
[0068] In some embodiments, the CO.sub.2 removal unit may include a
vessel configured as an absorber unit and another vessel configured
as a regenerator unit. The absorber unit may include an inlet for
receiving the desulfurized gas to be treated, and another inlet for
receiving a CO.sub.2-lean fluid stream containing regenerated
CO.sub.2 removing agent, an outlet for outputting the treated gas
(the process gas after CO.sub.2 removal), and another outlet for
outputting a CO.sub.2-rich fluid stream containing the CO.sub.2
removing agent and captured CO.sub.2. A liquid-based CO.sub.2
removing agent, or a particulate-based CO.sub.2 removing agent
carried in a carrier gas, may flow into contact with the
desulfurized gas in the absorber unit. On the other hand, in the
case of a solid-based CO.sub.2 removing agent provided as a
fixed-bed, or a membrane-based CO.sub.2 removing agent, these types
of CO.sub.2 removing agents may be supported by appropriate means
in the absorber unit so as to be adequately exposed to the flow of
the desulfurized gas. The regenerator unit may include an inlet for
receiving the CO.sub.2-rich fluid stream produced in the absorber
unit via a transfer line, an outlet for outputting the CO.sub.2
removed from the CO.sub.2-rich fluid stream as a CO.sub.2 output
stream, and another outlet for returning the CO.sub.2-lean fluid
back to the absorber unit via a transfer line. The mechanism for
regenerating the CO.sub.2 removing agent (converting the
CO.sub.2-rich fluid into the CO.sub.2-lean fluid) may depend on the
type of CO.sub.2 removing agent being utilized in the method, and
whether thermal or flash regeneration is implemented. In some
embodiments, water in the regenerator unit is utilized as a
regenerating agent. The use of an inert gas such as, for example,
nitrogen may sometimes be used to facilitate stripping of the
absorbed CO.sub.2 for regeneration of the CO.sub.2 removing
agent.
[0069] In some embodiments, the treated gas outputted from the
CO.sub.2 removal unit has a CO.sub.2 concentration of about 5% by
volume or less.
[0070] The method may further include processing the CO.sub.2
output stream from the regenerator unit by any suitable technique
for recovering CO.sub.2 from the CO.sub.2 output stream. The
recovered CO.sub.2 may thereafter by utilized for any purpose, such
as an end product or for chemical synthesis or for enhanced oil
recovery or for geologic sequestration.
[0071] It will be noted that because the upstream desulfurization
process is effective for removing substantially all of the sulfur
species from the process gas, or down to any level of concentration
required for the process gas, the CO.sub.2 removal unit need not
also be effective for removing sulfur species. Hence, the presently
disclosed acid gas removal method enables the CO.sub.2 removal
process to be optimized for CO.sub.2 removal without regard for
sulfur removal. In some embodiments, the CO.sub.2 removal unit or
process may be characterized as being effective for removing
CO.sub.2 without actively removing sulfur, or without removing a
substantial amount of sulfur. In some other embodiments, the
CO.sub.2 removal unit or process may complement the upstream
desulfurization process by further reducing any residual sulfur in
the desulfurized process gas. The combined integrated processes can
thus achieve a lower residual sulfur content in the final cleaned
process gas than could be achieved by either process step alone.
The decoupling and subsequent integration of sulfur removal and
CO.sub.2 removal process steps could enable an AGR process to meet
sulfur level requirements for conversion of process gas to
chemicals or fuels, where a single AGR process that combines sulfur
removal and CO.sub.2 removal could not. In all embodiments, the
goal of optimized sulfur and CO.sub.2 removal would be the
production of a treated gas and byproduct streams (sulfur compounds
and CO.sub.2) that eliminate or substantially reduce the number or
complexity of subsequent cleaning processing requirements.
[0072] In some embodiments, the presently disclosed method further
includes subjecting the process gas to one or more stages of a
water-gas shift (WGS) reaction. WGS is a moderately exothermic
reversible reaction and is expressed by:
CO+H.sub.2OCO.sub.2+H.sub.2, .DELTA.H.sup.0.sub.298=-41.09
kiloJoules/mole (kJ/mol),
[0073] where .DELTA.H.sup.0.sub.298 is the enthalpy of reaction at
298 kelvin (K).
[0074] The equilibrium of this reaction shows significant
temperature dependence and the equilibrium constant decreases with
an increase in temperature. The reaction is thermodynamically
favored at low temperatures and kinetically favored at high
temperatures. Thus, higher carbon monoxide conversion is observed
at lower temperatures. In order to take advantage of both the
thermodynamics and kinetics of the reaction, the industrial scale
WGS is conventionally conducted in multiple adiabatic stages with
cooling in-between the reactors. As there is no change in the
volume from reactants to products, the reaction is not affected by
pressure.
[0075] The water gas shift process uses steam to shift CO to
CO.sub.2 and produces H.sub.2 in the process. In addition to being
a reactant, the steam also serves to move the equilibrium of the
water gas shift forward to higher H.sub.2 and to control the
temperature rise from the exothermic water gas shift reaction,
which if left unchecked could de-activate the catalyst. The steam
is also required to prevent coking on the catalyst surface, which
also deactivates the catalyst. Most catalyst vendors require a
steam to dry gas ratio of 2.0 or higher to prevent catalyst
de-activation.
[0076] Generally, the WGS may be implemented upstream or downstream
of the desulfurization process. As noted above, the method
disclosed herein, by decoupling the sulfur removal process and the
CO.sub.2 removal process, facilitates carrying out a sweet shift
reaction downstream of the desulfurization process, for example
between the sulfur removal process and the CO.sub.2 removal
process. Thus, in some embodiments a WGS unit including a suitable
shift catalyst (which may be inexpensive compared to known
sulfur-tolerant shift catalysts) and an input for steam may be
positioned between the desulfurization unit and the CO.sub.2
removal unit. In this case, the desulfurized gas is flowed into
contact with steam in the presence of a shift catalyst to produce
CO.sub.2 and H.sub.2, and subsequently is subjected to the CO.sub.2
removal process. This configuration may be useful, for example,
when it is desired that the treated gas resulting from the
presently disclosed method have a desired level of H.sub.2 richness
or a desired H.sub.2/CO ratio. For example, the increased level of
CO.sub.2 in the process gas outputted from the WGS unit may then be
adequately removed by the downstream CO.sub.2 removal unit.
[0077] FIG. 1 is a schematic view of an example of a gas processing
system 100 in which acid gas removal methods disclosed herein may
be implemented according to some embodiments. Generally, the gas
processing system 100 may represent any system configured for
cleaning or treating a gas stream, particularly for removing acid
gas compounds (and optionally other contaminants or impurities)
from the gas stream. Thus, the gas processing system 100 may have
utility in a wide range of different applications. In some
embodiments, the gas processing system 100 may be or be part of an
integrated gasification combined cycle (IGCC) system. Generally,
the gas processing system 100 includes a plurality of units in
which specific functions are performed on the process gas stream
flowing or contained in that particular unit
(absorption/adsorption, regeneration, reaction, solids separation,
etc.). In FIG. 1 (and in other schematic figures included in the
present disclosure), the various lines between the units and other
components schematically represent the fluid plumbing utilized to
conduct various gas streams from one point to another in the gas
processing system 100, and arrows represent the general direction
of fluid flow through a line. Thus, the fluid lines may represent
various types of fluid conduits and other types of fluidic
components utilized to establish, control and manipulate fluid
flows or streams of fluid (e.g., pumps, valves, fluid fittings,
fluid couplings, mixers, fluid stream mergers, heaters, coolers,
pressure regulators, etc.), as well as measuring instruments (e.g.,
temperature sensors, pressure sensors, etc.). The fluid plumbing
may be arranged and configured in a variety of ways as appreciated
by persons skilled in the art. Unless the context dictates
otherwise, a reference to a "stream" or "flow" may also encompass a
reference to the "line" in which the stream or flow is
conducted.
[0078] The gas processing system 100 may include a feed gas source
104, a desulfurization system (or unit) 108, and a CO.sub.2 removal
system (or unit) 140. In various different embodiments, the gas
processing system 100 may further include one or more of the
following: a sulfur recovery system (or unit) 112, a water-gas
shift (WGS) system (or unit) 120, a CO.sub.2 recovery system (or
unit) 144, and a contaminant removal system (or unit) 148. The gas
processing system 100 may further include one or more additional
systems that consume the clean process gas produced by the gas
processing system 100 such as, for example, a power generation
system (power plant) 152 and/or a chemical or fuel synthesis system
156. Generally, the desulfurization system 108, sulfur recovery
system 112, WGS system 120, CO.sub.2 removal system 140, CO.sub.2
recovery system 144, and contaminant removal system 348 may have
any configurations, now known or later developed, suitable for
removing sulfur compounds from the process gas, optionally
recovering the sulfur, optionally shifting the CO in the process
gas to CO.sub.2 and H.sub.2, removing CO.sub.2 from the process
gas, optionally recovering the CO.sub.2, and optionally removing
one or more other types of contaminants from the process gas,
respectively. The desulfurization system 108 and CO.sub.2 removal
system 140 may be configured and operated as described above, and
as further described below by way of additional embodiments and
examples. The contaminant removal system 148 may schematically
represent one or more different systems configured for removing one
or more types of contaminants such as, for example, nitrogen
compounds, metal carbonyls, hydrocarbons, ammonia, chlorides,
hydrogen cyanide, trace metals and metalloids, particulate matter
(PM), etc. The power generation system 152 may include one or more
gas turbines and associated electrical power generators, boilers,
steam turbines and associated electrical power generators, etc. as
appreciated by persons skilled in the art.
[0079] In the illustrated embodiment, and as described above, the
desulfurization system 108 and the CO.sub.2 removal system 140 are
integrated, yet distinct, systems utilizing separate units for
desulfurization and CO.sub.2 removal, with the CO.sub.2 removal
process performed downstream of the desulfurization process. In
such embodiments, the desulfurization system 108 may be configured
for primarily or exclusively removing sulfur compounds from the
process gas (as opposed to other compounds such as CO.sub.2), and
the CO.sub.2 removal system 140 may be configured for primarily or
exclusively removing CO.sub.2 from the process gas (as opposed to
other compounds such as sulfur compounds).
[0080] In operation, a feed gas stream 116 is routed from the feed
gas source 104 to the desulfurization system 108, where
substantially all of the sulfur compounds may be removed, yielding
a desulfurized output gas stream which, in some embodiments, is
then fed to the CO.sub.2 removal system 140, or to the WGS system
120 if present as illustrated. Off-gas or tail gas containing
sulfur compounds may then be processed by the sulfur recovery
system 112 to recover elemental sulfur and/or recover or synthesize
sulfur compounds as described above. In some embodiments in which
the WGS system 120 is present, the gas processing system 100 may be
configured (not specifically shown) to fully or partially bypass
the WGS system 120 if desired. The WGS system 120 produces a
shifted gas stream containing a desired H.sub.2/CO ratio. In some
embodiments where the feed gas source 104 or the power generation
system 152 is sufficiently local to the WGS system 120, steam may
be supplied to the WGS system 120 via a steam line 162 from the
feed gas source 104 (e.g., steam generated from heat produced by a
coal gasifier) or via a steam line (not shown) from the power
generation system 152. Water may be supplied to the WGS system 120
from a suitable source, such as a boiler feed water line 166 from
the power generation system 152. The shifted gas stream outputted
from the WGS system 120 is then routed to the CO.sub.2 removal
system 140, where substantially all of the CO.sub.2 may be captured
and removed, yielding a clean (treated) process gas 178 that may
predominantly be comprised of CO and H.sub.2, etc., depending on
the composition of the feed gas inputted into the gas processing
system 100. The CO.sub.2 may then be recovered by the CO.sub.2
recovery system 144 to provide the CO.sub.2 for further use or
processing. In some embodiments, the process gas is then routed
from the CO.sub.2 removal system 140 to the contaminant removal
system 148, yielding a clean (treated) process gas 178
substantially free of contaminants in addition to sulfur compounds
and CO.sub.2. The clean process gas 178 may then be utilized as a
source gas by the power generation system 352 to generate power
and/or the chemical or fuel synthesis system 156 to synthesize
chemicals or fuels.
[0081] The particular embodiment of the gas processing system 100
illustrated in FIG. 1 is configured for implementing a sweet gas
shifting process. From the present disclosure, however, it will be
readily appreciated that the gas processing system 100 may be
reconfigured to implement a sour gas shifting process.
[0082] FIG. 2 is a schematic view of an example of a
desulfurization system (or unit) according to some embodiments.
[0083] FIG. 3 is a schematic view of an example of a CO.sub.2
removal system (or unit) according to some embodiments.
[0084] In the following Examples, process flow models were
developed using ASPEN PLUS.RTM. software (Aspen Technology, Inc.,
Burlington, Mass., USA), and were utilized in detailed
techno-economic analyses to compare the capital and operating costs
for leading technologies for stand-alone AGR and the integrated WDP
and CO.sub.2 capture technologies disclosed herein. These studies
utilized a consistent design basis, thereby allowing for a direct
comparison of the costs.
Example 1
[0085] This example illustrates the processing and acid gases
removal for methanol synthesis. RECTISOL.RTM. solvent for sulfur
and CO.sub.2 capture is used here as the base case for comparison
with the integrated WDP and CO.sub.2 capture disclosed herein. The
syngas is reacted with steam to shift the gas to obtain a
H.sub.2/CO ratio of 2 (as required for methanol synthesis). The
sulfur removal is carried out downstream of the water gas shift for
the RECTISOL.RTM. base case, but it can be done either upstream or
downstream of the water gas shift for the WDP integrated cases.
[0086] Syngas from a solids-fed gasifier, using a Powder River
Basin (PRB) coal is used here. This coal contains 0.73 wt % of
total sulfur. Total volume of gas used in this example corresponds
to the use of two large commercial-scale gasifiers. The syngas
composition for this case is taken from a Department of Energy
study (DOE-NETL. Cost and Performance Baseline for Fossil Energy
Plants. Volume 3a: Low Rank Coal to Electricity: IGCC Cases2011 May
2011 Contract No.: DOE/NETL-2010/1399) and is provided in Table 1
below.
TABLE-US-00001 TABLE 1 Inlet syngas composition used in Example 1
Temperature, .degree. F. 500 Pressure, psia 605 Molar flow rate,
lbmol/hr 77,885 V-L Mole Fraction H.sub.2 0.1456 CO 0.2832 CO.sub.2
0.0257 H.sub.2S 0.0015 COS 0.0001 H.sub.2O 0.4854 HCl 0.0000 Inerts
0.0585 Total 1.0000
[0087] (a) WDP+Modified RECTISOL.RTM. Process for CO.sub.2
Capture
[0088] FIG. 4 is a schematic view of an example of the conventional
RECTISOL.RTM. process utilized for removal of S and CO.sub.2. In
particular, FIG. 4 shows essential components of a selective
RECTISOL.RTM. process in which CO.sub.2 is recovered as a product
and an H.sub.2S enriched stream is sent to a Claus unit to recover
sulfur. The CO.sub.2 from the Claus unit is recirculated back to
the absorber to enhance CO.sub.2 capture. Heat integration and some
process loops are not shown for the sake of brevity. As shown,
there are five main sections in a RECTISOL.RTM. design: 1) the
absorber section, 2) the CO.sub.2 recovery section, 3) the H.sub.2S
enrichment sections, 4) the water rejection section and 5) the
methanol recovery section or the gas treatment section.
[0089] The raw syngas has to be cooled to roughly ambient
temperature before it enters the RECTISOL.RTM. battery limit.
Methanol is injected to prevent any water from freezing as the gas
is chilled by exchanging heat with chilled treated syngas, CO.sub.2
product gas and tail gas. In the absorber section, raw syngas is
washed with chilled methanol to reduce CO.sub.2, H.sub.2S, NH.sub.3
and other contaminants to desired levels. The rich solvent is then
pre-flashed to recover H.sub.2 and CO, which partly dissolve
simultaneously in the chilled methanol. The pre-flashed methanol is
flashed further to recover the bulk of the CO.sub.2. The last bit
of CO.sub.2 is stripped out using nitrogen. The flashed methanol is
then sent to the H.sub.2S enrichment section where hot regeneration
of the solvent along with H.sub.2S enrichment is achieved. The
methanol in the CO.sub.2 product and the tail gas streams is
recovered by washing the gas streams with demineralized water in
the methanol recovery section. The water-methanol mixture from the
gas treatment at the inlet and the outlet is separated in the water
rejection section by simple distillation.
[0090] The feed to the standalone RECTISOL.RTM. process for this
study is taken from a sour shift reactor which brings the H.sub.2
to CO ratio to 2:1. The temperature, pressure, and composition of
the inlet raw syngas, treated syngas, CO.sub.2 product, tail gas
and H.sub.2S enriched gas are estimated using an ASPEN PLUS.RTM.
process model and are given in Table 2 below.
TABLE-US-00002 TABLE 2 Raw Treated CO.sub.2 H.sub.2S en- Mole Frac
Syngas Syngas product Tail gas riched gas H.sub.2 0.437 0.589 0.002
0.000 1.22E-06 CO 0.218 0.293 0.005 0.001 1.73E-07 CO.sub.2 0.274
0.029 0.951 0.257 0.713 CH.sub.4 0 0 0 0 0 H.sub.2S 2.64E-03 0
4.74E-06 2.28E-04 0.253 COS 1.79E-04 0 2.49E-08 2.92E-06 1.73E-02
NH.sub.3 3.74E-05 0 0 0 2.90E-03 N.sub.2 + Ar 0.067 0.090 0.030
0.727 1.88E-03 H.sub.2O 0.002 0.000 0.012 0.016 4.31E-08 CH.sub.3OH
0 9.93E-05 8.47E-05 1.71E-06 0.011 Total Flow, 43547 32254 11280
1083 458 lbmol/hr Temper- 86 70 48 54 68 ature, .degree. F.
Pressure, psia 561 550 15 15 16
[0091] The selective removal of CO.sub.2 and H.sub.2S while
simultaneously 1) enriching H.sub.2S-rich stream, 2) maintaining
H.sub.2S specs in the tail gas and the CO.sub.2 product, and 3)
keeping the percent CO.sub.2 capture near 90% makes the process
design very complicated. The H.sub.2S-rich stream should have more
than 25 mol % of H.sub.2S for sulfur recovery in the conventional
Claus process. The H.sub.2S in the CO.sub.2 product as well as the
tail gas should not exceed 5 ppm. The allowable H.sub.2S in the
treated syngas can vary from ppm to a few ppb depending on the end
use.
[0092] Apart from the design complexity, the RECTISOL.RTM. process
is extremely capital intensive as well as requires large operating
costs due to cryogenic operating conditions. A significant portion
of the capital cost contribution comes from the large required heat
exchangers. A very large heat exchange area is required as the raw
syngas is chilled from ambient conditions to -20.degree. F. or
lower before it enters the absorber. An even larger heat exchange
area is required to chill the hot regenerated methanol to
-40.degree. F. or lower before it is recirculated back to the
absorber.
[0093] The RECTISOL.RTM. plant and the refrigeration plant
contribute almost equally to the total electricity consumption. The
largest power consumers in the RECTISOL.RTM. plant are: 1) the
chilled regenerated methanol pump, 2) the H.sub.2 and CO
recirculating compressors, and 3) the CO.sub.2 recirculation
compressor from the Claus unit. In the refrigeration plant, the
compressors alone contribute to the entire power consumption.
[0094] By comparison, decoupling the CO.sub.2 and H.sub.2S sections
significantly simplifies the design and results in large reductions
in the capital and operating costs, as illustrated in the following
Examples, which illustrate the benefits from the integration of the
WDP and the CO.sub.2 capture technologies in accordance with the
present disclosure.
[0095] FIG. 5 is a schematic view of an example of the WDP
integrated with a decoupled RECTISOL.RTM. process configured for
CO.sub.2 scrubbing according to some embodiments. The WDP removes
99+% sulfur from the raw syngas and the RECTISOL.RTM. plant is
designed to remove CO.sub.2 and other trace components. All the
process constraints related to H.sub.2S removal and recovery in a
conventional RECTISOL.RTM. design such as shown in FIG. 4 vanish,
which results in a greatly simplified design. The result is that
the decoupled RECTISOL.RTM. configuration, such as shown in FIG. 5,
has very few process components compared to the conventional
RECTISOL.RTM. configuration shown in FIG. 4.
[0096] As shown in FIG. 5, this embodiment includes an absorber
section in which the raw syngas is chilled and treated with chilled
methanol. The rich solvent is pre-flashed to recover the H.sub.2
and CO products. The solvent is then flashed to atmospheric
pressure. The flash regenerated methanol is divided into three sub
streams. The first sub stream is recirculated back to the absorber.
The second sub stream is stripped using nitrogen and then
recirculated to absorber. The third sub stream undergoes hot
regeneration and returns to the absorber.
[0097] (b) WDP+Modified SELEXOL.RTM. Process for CO.sub.2
Removal
[0098] The main complexity in the selective removal of H.sub.2S and
CO.sub.2 in the SELEXOL.RTM. process comes from the presence of
COS. COS in the feed stream poses difficulties in desulfurization
when physical solvent absorption systems are employed. The
SELEXOL.RTM. solvent has a much greater solubility of H.sub.2S than
that of CO.sub.2, with the solubility of COS in between those of
H.sub.2S and CO.sub.2. Relative solubilities of H.sub.2S and COS
(relative to CO.sub.2) in the SELEXOL.RTM. solvent are as
follows.
TABLE-US-00003 TABLE 3 DEPG, 25.degree. C. CO.sub.2 1.00 COS 2.30
H.sub.2S 8.82
[0099] When COS is absent, the desulfurization solvent flow-rate is
set for essentially complete H.sub.2S removal and only a small
fraction of the CO.sub.2 is co-absorbed. When COS is present, a
substantially higher flow-rate is required to obtain complete
absorption and desulfurization, with consequent increase in amount
of CO.sub.2 absorbed, resulting in an increase in equipment cost
and utility requirements. The co-absorption of CO.sub.2 is also
increased by the higher solvent flow-rate.
[0100] Another approach to address the differences in solubilities
for H.sub.2S and COS in the SELEXOL.RTM. solvent is to carry out
COS hydrolysis to convert the COS to H.sub.2S, upstream of the
SELEXOL.RTM. process. This approach, however, requires additional
equipment and an additional processing step, adding to the overall
cost of the SELEXOL.RTM. process.
[0101] FIG. 6 is a schematic view of an example of the stand-alone
SELEXOL.RTM. process utilized for removal of S and CO.sub.2. The
feed gas is sent to the sulfur absorber column, where a slip-stream
of the CO.sub.2-rich SELEXOL.RTM. solvent from the CO.sub.2
absorption column is used to absorb H.sub.2S and COS. The syngas,
essentially free of H.sub.2S and COS, passes on to the CO.sub.2
absorber column. The CO.sub.2-rich solution from the CO.sub.2
absorber is flashed off in series of flash columns. FIG. 6 shows
only one flash column, but typically two to three flashes are used
to recover CO.sub.2 at different pressures. The gas from the first
high pressure flash is recycled to recover H.sub.2 and CO, which
comes off in the first flash.
[0102] The H.sub.2S-rich solution from the sulfur absorber column
needs to be further processed to concentrate the H.sub.2S for the
Claus process and remove CO.sub.2. This is carried out in the
H.sub.2S concentrator column, followed by thermal regeneration in
the stripper column. The CO.sub.2 stream from the H.sub.2S
concentrator contains small amounts of H.sub.2S, and is recycled to
the H.sub.2S absorber column.
[0103] By comparison, FIG. 7 is a schematic view of an example of a
decoupled SELEXOL.RTM. process configured for CO.sub.2 scrubbing,
which is configured for integration with an upstream WDP, according
to some embodiments. FIG. 7 illustrates that CO.sub.2 capture is
greatly simplified when sulfur is captured upstream and only
CO.sub.2 is removed by a SELEXOL.RTM. process modified as disclosed
herein.
[0104] (c) WDP+Activated MDEA.
[0105] Activated MDEA can also be used for CO.sub.2 capture.
Activated MDEA uses MDEA as an aqueous solution which has been
activated with some chemicals (example piperazine) to enhance the
CO.sub.2 absorption in the solvent. Activated MDEA can be used for
CO.sub.2 capture after the sulfur species has been removed by the
WDP.
[0106] Results from the different cases are tabulated in Table
4.
TABLE-US-00004 TABLE 4 Results from the techno-economic analysis
for Example 1 showing projected savings with the integration of the
WDP and the AGR technologies over the base case (dual-stage
RECTISOL .RTM.). RECTISOL .RTM. WDP + for S and CO2 WDP + WDP +
Activated removal RECTISOL .RTM. SELEXOL .RTM. MDEA Capital
Cost.sup.1, 2011 1 31% reduction 35% reduction 35% reduction
$(Million) Annual Operating 58% positive 9% positive 22% positive
costs.sup.2, 2011 $(Million) cash flow cash flow cash flow
.sup.1includes cost of initial fills .sup.2Operating cost is net
cash flow due to steam generation in water gas shift and low
temperature gas cooling which generates higher cash flow than
consumed in electricity, cooling water and consumables
[0107] It is seen that a substantial reduction in capital and
operating costs is achieved by decoupling the H.sub.2S and CO.sub.2
removal from syngas for all three cases.
[0108] During this study it was also found that the H.sub.2S
enrichment for higher H.sub.2:CO ratios (3:1) required for SNG and
substantially higher for H.sub.2 applications, becomes very
difficult with the conventional RECTISOL.RTM. process. Decoupling
the sulfur and CO.sub.2 removal removes this bottleneck and allows
the use of chilled methanol-based CO.sub.2 only wash.
Example 2
[0109] This example illustrates processing and acid gas cleanup of
a syngas for H.sub.2 production. The syngas composition for this
example is taken from a Department of Energy study for a solids-fed
gasifier with partial quench using PRB coal (case S1B), and is
provided in Table 5 below. A dual-stage (current state-of-the-art)
SELEXOL.RTM. process for sulfur and CO.sub.2 removal is used in the
DOE example case and the treated syngas is suitable for H.sub.2
production. The treated syngas can be purified using a pressure
swing adsorption (PSA) step. The same study also reports the
operating costs and the capital costs (bare erected costs) for acid
gas cleanup using the SELEXOL.RTM. process (for both S and
CO.sub.2). These numbers are used here to compare against the
"WDP+activated MDEA for CO.sub.2" case. The WDP+activated MDEA uses
the Direct Sulfur Recovery Process (DSRP) as opposed to the Claus
process for the base case. DSRP was also modeled and included in
the economic analysis. As the PSA step is common to both processes,
it is not modeled here. All costs are reduced to 2011 $, for
consistency.
TABLE-US-00005 TABLE 5 Inlet syngas composition used in Example 2
Temperature, .degree. F. 450 Pressure, psia 570 Molar flow rate,
lbmol/hr 66,477 V-L Mole Fraction H.sub.2 0.1508 CO 0.3470 CO.sub.2
0.0183 H.sub.2S 0.0017 COS 0.0003 H.sub.2O 0.4386 HCl 0.0000 Inerts
0.0433 Total 1.0000
[0110] Two different cases are considered for illustration (a)
conventional SELEXOL.RTM. process for sulfur and CO.sub.2 removal,
(b) WDP for sulfur removal and activated MDEA for CO.sub.2
removal.
[0111] ASPEN PLUS.RTM. process models were developed for the WDP,
water gas shift, and sulfur recovery process. Activated MDEA was
modeled using PROMAX.RTM. modeling software (Bryan Research &
Engineering, Inc., Bryan, Tex., USA). The WDP allows the choice
between the sweet gas shift and the sour gas shift. This allows for
integration of the water gas shift with the WDP and the CO.sub.2
removal to reduce the overall capital costs, which is possible only
with the decoupling of the S and CO.sub.2 removal. Hence, the water
gas shift and the low temperature gas cooling were also modeled and
included in the cost comparison. The SELEXOL.RTM. process for S and
CO.sub.2 capture produces H.sub.2S and uses the Claus process for S
recovery. The WDP process produces SO.sub.2 and uses the Direct
Sulfur Recovery Process (DSRP). DSRP was also modeled and included
in the cost comparison. The heat and mass balance were used to size
equipment and determine equipment and installed costs using the
ASPEN PLUS.RTM. Economic Analyzer. The capital cost accounted for
the cost of the initial fill (catalysts, sorbents,
SELEXOL.RTM./MDEA solvent). Economic analysis of the two cases
shows a 35% reduction in the capital costs (installed equipment
cost) for WDP+activated MDEA when compared to the base case. The
electricity consumption was similar for the two cases. However,
with the sweet gas shift, there was a net generation of 18,000
lbs/hr of high pressure steam in the WDP+activated MDEA case
compared to net consumption of 369,000 lb/hr of high pressure
steam
[0112] The techno-economic analysis clearly shows the economic
benefits of integrating the WDP process with a downstream CO.sub.2
capture process according to the present disclosure.
[0113] The above Examples are for illustrative purposes only and do
not restrict the invention to the CO.sub.2 capture processes used
in the examples. Similar savings are expected from integration of
the WDP with other CO.sub.2 capture processes.
[0114] The present disclosure also describes a method for the water
gas shift (WGS) process that may significantly lower steam
consumption required. The WGS process is applicable to both the
sour gas shift as well as the sweet gas shift, and has wide
application in power production (e.g., electricity and H.sub.2) and
for production of chemicals. The WGS process may be carried out on
any feed gas that includes CO, one example being syngas.
[0115] According to some embodiments, the WGS process takes the
syngas or other CO-containing gas and splits it into multiple
streams that are then fed into separate shift reactors. The output
from each shift reactor is then combined with the syngas stream
being fed to the next reactor. Thus the shift is carried out in
series with the syngas fed in parallel to multiple reactors. In
some embodiments, steam is added only to the first reactor, with
water (e.g., boiler feed water) added to subsequent reactors if
needed. The heat generated from the exothermic WGS reaction may be
utilized as latent heat to vaporize the added water to generate
steam in situ. Since the first reactor contains only a fraction of
the total syngas stream, the steam requirement is reduced
dramatically.
[0116] No specific limitations are placed on the configuration of
the shift reactors. Generally, each shift reactor may have any
configuration suitable for carrying out the WGS reaction. For this
purpose, each shift reactor generally may include a vessel having
an inlet and an outlet, and a shift catalyst in the vessel.
Depending on the type of shift catalyst utilized, each shift
reactor may include a structural support for the shift
catalyst.
[0117] No specific limitation is placed on the number of shift
reactors utilized in series. In a typical embodiment, as described
below in conjunction with FIG. 1, three shift reactors are provided
in series. However, two shift reactors may be sufficient in some
embodiments. Moreover, additional (more than three) shift reactors
may be provided. The determination of the number of shift reactors
to deploy may depend on a comparison of the cost of adding shift
reactors with the cost reduction resulting from further reductions
in steam consumption.
[0118] In some embodiments, all shift reactors are configured or
operated to carry out a high temperature shift (HTS) reaction. In
other embodiments, all shift reactors are configured or operated to
carry out a low temperature shift (LTS) reaction. In still other
embodiments, one or more of the shift reactors are configured or
operated to carry out an HTS reaction, while one or more of the
other shift reactors are configured or operated to carry out a LTS
reaction. In some embodiments, in an HTS reaction the inlet
temperature of the gas fed to a shift reactor ranges, for example,
from 570 to 700.degree. F. In some embodiments, in a LTS reaction
the inlet temperature of the gas fed to a shift reactor ranges, for
example, from 400 to 550.degree. F. Depending on the type of shift
reaction performed in the respective shift reactors, the shift
reactors may include the same type (composition) of shift catalyst
or different types of shift catalyst.
[0119] Generally, the shift catalyst may be provided and supported
in any form suitable for carrying out the WGS reaction. For
example, the shift catalyst may be provided as a fixed bed that is
positioned in the shift reactor such that gases are able to flow
through the catalyst bed. The composition of the shift catalyst may
depend on the operating temperature of the shift reactor and the
composition of the gas to be processed by the shift reactor. For
example, for implementing the sour gas shift the shift catalyst
should be a sulfur-tolerant catalyst. Examples of suitable
catalysts for implementing the sour gas shift include, but are not
limited to, cobalt-molybdenum (Co--Mo) and nickel-molybdenum
(Ni--Mo) catalysts. Examples of suitable catalysts for implementing
the sweet gas shift include, but are not limited to, chromium or
copper promoted iron-based catalysts and zinc oxide-promoted copper
catalysts.
[0120] FIG. 8 is a schematic view of an example of a water gas
shift reaction (WGS) system 800 according to some embodiments. The
WGS system 800 includes a plurality of shift reactors fluidly
communicating with each other in series. That is, the fluid outlet
of each shift reactor communicates with the fluid inlet of the
succeeding shift reactor, with the fluid outlet of the last shift
reactor in the series serving as the fluid output of the WGS system
800. In FIG. 1, the various lines between the shift reactors and
other components schematically represent the fluid plumbing
utilized to conduct various fluid streams from one point to another
in the WGS system 800, and arrows represent the general direction
of fluid flow through a line. Thus, the fluid lines may represent
various types of fluid conduits and other types of fluidic
components utilized to establish, control and manipulate flows or
streams of fluid (e.g., pumps, valves, fluid fittings, fluid
couplings, mixers, fluid stream mergers, heaters, coolers, pressure
regulators, etc.), as well as measuring instruments (e.g.,
temperature sensors, pressure sensors, etc.). The fluid plumbing
may be arranged and configured in a variety of ways as appreciated
by persons skilled in the art.
[0121] In the illustrated embodiment, the WGS system 800 includes a
first shift reactor 804, a second shift reactor 806, and a third
shift reactor 808. A flow splitter 812 splits the flow of a feed
gas supplied by a feed gas source 816 into a plurality of separate
feed gas streams. The flow splitter 812 is schematically
represented by two tee-connections, but more generally may be any
device suitable for splitting the flow of feed gas supplied to the
WGS system 800. One or more flow metering devices (e.g., valves)
may be included to enable adjustment of the split ratio of the feed
gas streams. In the illustrated embodiment, the flow splitter 812
splits the flow of the feed gas into a first feed gas stream 820
directed to the inlet of the first shift reactor 804, a second feed
gas stream 824 directed to the inlet of the second shift reactor
806, and a third feed gas stream 828 directed to the inlet of the
third shift reactor 808. As described above, the feed gas may be
any gas that includes CO, and the feed gas source 816 may be any
source of such a gas. In some embodiments, the feed gas is syngas.
In this case, the feed gas source 816 may be the output of a syngas
production system (e.g., a coal gasification system), or the output
of an intermediate gas processing system that carries out one or
more processes on as-produced syngas upstream of the illustrated
WGS system 800.
[0122] A steam source 832 supplies a flow of steam to the first
feed gas stream 820 at a merge point upstream of the inlet of the
first shift reactor 804, thereby establishing a first input gas
stream conducted into the first shift reactor 804. As described
above, steam need only be supplied to the first shift reactor 804.
The ratio of steam to CO in the first input gas stream may be
controlled as needed considering factors such as, for example, a
desired moisture content (steam/dry gas ratio) of the first input
gas stream, a desired gas inlet temperature of the first shift
reactor 804, the type of shift catalyst utilized in the first shift
reactor 804 and the requirements for preventing de-activation of
the shift catalyst, etc. In the first shift reactor 804, the CO
reacts with the steam in the presence of the shift catalyst,
thereby shifting CO to CO.sub.2 and producing H.sub.2 gas as
described above. Consequently, the first shift reactor 804 outputs
a first product gas stream 836 that includes CO.sub.2, H.sub.2,
residual steam, and some amount of un-shifted CO. It is also
understood that the first product gas stream 836 (and other product
gas streams of the WGS system 800) may also include other
components of the raw feed gas introduced into the WGS system 800
that were not removed by an upstream process.
[0123] The first product gas stream 836 is routed from the outlet
of the first shift reactor 804 to a merge point upstream of the
inlet of the second shift reactor 806, at which the first product
gas stream 836 combines with the second feed gas stream 824. This
merging of streams forms a second input gas stream that includes a
mixture of the CO.sub.2, H.sub.2, residual steam, and un-shifted CO
outputted from the first shift reactor 804, and the fraction of
CO-containing feed gas (e.g., syngas in some embodiments) split
from the main input of feed gas into the second feed gas stream
824. The second input gas stream is then conducted into the second
shift reactor 806. The process conditions (e.g., split ratio
implemented by the flow splitter 812, flow rates of the first
product gas stream 836 and second feed gas stream 824, optional
addition of water such as boiler feed water, etc.) may be set as
needed to achieve a desired gas moisture content and inlet
temperature of the second shift reactor 806. In the second shift
reactor 806, the water gas shift reaction is again carried out as
described above. Consequently, the second shift reactor 806 outputs
a second product gas stream 840 that includes CO.sub.2, H.sub.2,
residual steam, and some amount of un-shifted CO.
[0124] The second product gas stream 840 is routed from the outlet
of the second shift reactor 806 to a merge point upstream of the
inlet of the third shift reactor 808, at which the second product
gas stream 840 combines with the third feed gas stream 828. This
merging of streams forms a third input gas stream that includes a
mixture of the CO.sub.2, H.sub.2, residual steam, and un-shifted CO
outputted from the second shift reactor 806, and the fraction of
CO-containing feed gas (e.g., syngas in some embodiments) split
from the main input of feed gas into the third feed gas stream 828.
The third input gas stream is then conducted into the third shift
reactor 808. The process conditions (e.g., split ratio implemented
by the flow splitter 812, flow rates of the second product gas
stream 840 and third feed gas stream 828, optional addition of
water such as boiler feed water, etc.) may be set as needed to
achieve a desired gas moisture content and inlet temperature of the
third shift reactor 808. In the third shift reactor 808, the water
gas shift reaction is again carried out as described above.
Consequently, the third shift reactor 808 outputs a third product
gas stream 844 that includes CO.sub.2, H.sub.2, residual steam, and
some amount of un-shifted CO.
[0125] Assuming, as in the illustrated embodiment, the third shift
reactor 808 is the final shift reactor in the WGS system 800, the
third product gas stream 844 may serve as a final output gas stream
848 of the WGS system 800. In other embodiments in which one or
more additional shift reactors (not shown) are deployed, the third
product gas stream 844 may be routed to the inlet of the next shift
reactor to carry out an additional water gas shift process, and so
on. In all such cases, the final output gas stream 848 may be
routed to any downstream system(s)/process(es) 852 depending on the
application such as, for example, low temperature gas cooling
(LTGC), CO.sub.2 capture/removal, sulfur removal, removal of other
contaminants, an end use for the as-produced H.sub.2 and/or
CO.sub.2, etc. The process parameters of the WGS system 800 may be
set so as to achieve either full (100%) or partial shifting of CO
to CO.sub.2.
[0126] In some embodiments, the H.sub.2/CO ratio in the final
output gas stream 848 may be tuned or adjusted by providing a
bypass gas line (not shown) leading from the input feed gas stream
(from the feed gas source 816) directly to the final output gas
stream 848. That is, the bypass gas line bypasses all of the shift
reactors provided in the WGS system 800. For example, the flow rate
into the bypass gas line may be controlled by the flow splitter
812. In this manner, an unreacted feed gas mixture (containing CO,
or CO and H.sub.2, etc.) may be added to the product gas in the
final output gas stream 848 to achieve a desired fraction of
components in the output gas mixture.
[0127] In some embodiments, all or part of the steam supplied to
the first shift reactor 804 may be generated locally by using heat
generated from the exothermic water gas shift reaction to vaporize
a stream of water supplied from an appropriate water source. For
example, in the illustrated embodiment, a water stream from a
boiler feed water source 856 is routed to a heat exchanger 860 in
thermal contact with the third input stream leading into the third
shift reactor 808. Heat from the third input stream is transferred
into the water stream via the heat exchanger 860, thereby providing
a local steam supply 864. The steam from the local steam supply 864
may then be routed to the first feed gas stream 820. Alternatively
or additionally, the water stream may be routed to a heat exchanger
(not shown) that is in thermal contact with the second input stream
leading into the second shift reactor 806.
[0128] In some embodiments, water supplied from an appropriate
water source such as the above-noted boiler feed water source 856
may be added to one or more of the input gas streams leading into
the first shift reactor 804, second shift reactor 806, and third
shift reactor 808, respectively, as schematically depicted by
respective water feed lines 868, 872, and 876. In any one of the
input gas streams, water may be added at a desired flow rate to
achieve a desired moisture content in the input gas stream, to
achieve a desired inlet gas temperature into the shift reactor,
and/or to provide an in situ source of steam for the water gas
shift reaction.
[0129] In some embodiments, water is added to an input gas stream
in the form of a spray (aerosol), i.e., very fine droplets. In the
illustrated embodiment, aerosolized water is added to the first
input gas stream by conducting a stream of liquid water through the
first water feed line 868 to a first sprayer (aerosolizer, or
atomizer) 869 positioned in fluid communication with the first
input gas stream line. The sprayer 869 converts the liquid water
stream into a spray, and injects the spray into the first input gas
stream. Similarly, aerosolized water is added to the second input
gas stream by conducting a stream of liquid water through the
second water feed line 872 to a second sprayer 873 positioned in
fluid communication with the second input gas stream line, and
aerosolized water is added to the third input gas stream by
conducting a stream of liquid water through the third water feed
line 876 to a third sprayer 877 positioned in fluid communication
with the third input gas stream line. In the illustrated
embodiment, the second sprayer 873 is positioned to inject
aerosolized water into the first product gas stream 836 (i.e., into
the first product gas stream line) and the third sprayer 877 is
positioned to inject aerosolized water into the second product gas
stream 840 (i.e., into the first product gas stream line), although
the sprayers 869, 873, and 877 may be positioned at other locations
as appropriate. Generally, the sprayers 869, 873, and 877 may have
any configuration suitable for converting a continuous stream of
liquid into an aerosol containing very fine droplets. As
appreciated by persons skilled in the art, the sprayers 869, 873,
and 877 may include internal fluid passages and nozzles
specifically configured to generate spray, and may or may not be
pneumatically assisted.
[0130] Adding water as a spray to the gas stream(s) provides
advantages over adding water as a continuous stream. The water
droplets provide significantly increased surface area available for
heat transfer, thereby increasing the efficiency of the heat
transfer from the gas to the water. When introduced in the gas
stream, the water droplets become vaporized (i.e., converted to
steam), thereby cooling the gas. The amount of water added via the
water feed lines 868, 872, and 876, and the split ratio among the
first feed gas stream 820, the second feed gas stream 824, and the
third feed gas stream 828, may be controlled so as to obtain the
desired water content and temperature in the first feed gas stream
820, the second feed gas stream 824, and the third feed gas stream
828 before they reach the respective inlets of the first shift
reactor 804, second shift reactor 806, and third shift reactor 808.
Preferably, the conditions are controlled such that all water added
is vaporized upstream to the first shift reactor 804, second shift
reactor 806, and third shift reactor 808, to avoid the presence of
liquid-phase water (droplets or otherwise) in the first shift
reactor 804, second shift reactor 806, and third shift reactor 808,
which might de-activate the shift catalyst.
[0131] In some embodiments, the water added to the first input
stream may be heated by conducting a product gas stream into
thermal contact with the first input stream at a heat exchanger
880. In the illustrated embodiment, the product gas stream
supplying the heat at the heat exchanger 880 is the third product
gas stream 844 from the third shift reactor 808. Use of the heat
exchanger 880 is optional, but may be desired in a case where the
temperature of the first feed gas stream 820 needs to be raised
upstream of the inlet of the first shift reactor 804.
Alternatively, the moisture may be added to the first feed gas
stream 820 entirely via addition of steam from the steam source
832.
[0132] FIG. 9A is a schematic view of an example of a gas
processing system 900 in which a WGS system, such as the WGS system
800 described above and illustrated in FIG. 8, may be integrated
according to some embodiments. The gas processing system 900 may
include a feed gas source 904 such as described above. The feed gas
may be syngas or another type of process gas that includes CO and
also includes one or more types of sulfur compounds desired to be
removed from the process gas. The gas processing system 900 may
also include the WGS system 800 and a desulfurization system 908.
In some embodiments, the gas processing system 900 may further
include a sulfur recovery system 912. The desulfurization system
908 and sulfur recovery system 912 may have any configurations, now
known or later developed, or as described herein, suitable for
removing sulfur compounds from the process gas and recovering the
sulfur. In the present embodiment, the gas processing system 900 is
configured for carrying out a sour gas shift. Hence, the WGS system
800 is positioned upstream of the desulfurization system 908.
[0133] In operation, a feed gas stream 916 is routed from the feed
gas source 904 to the WGS system 800, where the feed gas is
subjected to the WGS reaction as described above, yielding a
gas-shifted gas stream 920 containing a desired H.sub.2/CO ratio.
The gas-shifted gas stream 920 is then routed to the
desulfurization system 908, where substantially all of the sulfur
compounds may be removed, yielding a desulfurized output gas stream
924 (which may be substantially sulfur-free). In some embodiments,
the sulfur compounds removed from the process gas may be subjected
to a sulfur recovery process, producing a quantity of elemental
sulfur 928 for a desired use. In some embodiments, the gas
processing system 900 may also include a bypass line 932 for
partially or fully bypassing the WGS system 800 as desired for a
particular application.
[0134] FIG. 9B is a schematic view of another example of a gas
processing system 950 in which a WGS system, such as the WGS system
800 described above and illustrated in FIG. 8, may be integrated
according to some embodiments. The gas processing system 950 is
configured for carrying out a sweet gas shift. Hence, the WGS
system 800 is positioned downstream of the desulfurization system
908. The configuration and operation of the gas processing system
950 may otherwise be substantially similar to the gas processing
system 900 described above and illustrated in FIG. 9A.
[0135] The gas processing system 100 described above and
illustrated in FIG. 1 is a further example of a system in which a
WGS system as described herein may be integrated according to some
embodiments.
[0136] FIG. 10 is a cross-sectional schematic view of a sprayer
1004 positioned in fluid communication with a gas conduit (gas
stream line) 1008 according to an embodiment. The sprayer 1004 and
gas conduit 1008 may correspond to any of the sprayers 869, 873,
and 877 and associated gas lines described above and illustrated in
FIG. 8. Generally, the sprayer 1004 may include one or more nozzles
1012 mounted by any suitable means in the gas conduit 1008, and one
or more water feed tubes 1016 communicating with one or more
internal passages of the nozzle 1012. The feed tube 1016 may extend
through an opening in the wall of the gas conduit 1008 in a
fluid-sealed manner. The nozzle 1012 includes one or more exit
orifices 1020 configured in any manner suitable for emitting or
producing a spray 1024, i.e., fine droplets of water. As
appreciated by persons skilled in the art, the exit orifice 1020
may have any geometry suitable for emitting or producing the spray
1024, taking into account the parameters of the water flow and gas
flow contemplated (e.g., pressure, flow rate, etc). As non-limiting
examples, the exit orifice 1020 may be a simple or flat orifice, or
may have a converging, diverging, or converging-diverging geometry.
The nozzle 1012 may be positioned in any orientation in the gas
conduit 1008 that results in an effective interaction between the
spray 1024 and gas flowing through the gas conduit 1008. Depending
on the configuration of the nozzle 1012 and the exit orifice 1020,
the spray 1024 may begin to form inside the nozzle 1012, at the
exit orifice 1020, or just outside the exit orifice 1020 and nozzle
1012. Depending on the embodiment, the gas flowing through the gas
conduit 1008 (or an auxiliary supply of gas, not shown) may or may
not serve a role in assisting in the formation of the spray 1024.
In the illustrated example, the nozzle 1012 is positioned along or
parallel to the central, longitudinal axis of the gas conduit 1008.
Alternatively, the nozzle 1012 may be positioned along a radial
direction (orthogonal to the central, longitudinal axis of the gas
conduit 1008) or at any other angle relative to the central,
longitudinal axis of the gas conduit 1008. In the illustrated
example, the nozzle 1012 is positioned such that the spray 1024 is
generally directed from the nozzle 1012 in a counter-flow relation
to the direction of gas flow 1028 through the gas conduit 1008.
Alternatively, the nozzle 1012 may be positioned such that the
spray 1024 is generally directed from the nozzle 1012 in a co-flow
relation to the direction of gas flow 1028 (in the same direction
as the gas flow 1028) or in a cross-flow relation to the direction
of gas flow 1028.
Example 3
[0137] Process flow models that integrate the acid gas removal and
water gas shift processes were employed to determine the steam
requirements to achieve a minimum of 93% CO conversion to CO.sub.2.
Four different cases were considered:
[0138] (a) Traditional sour gas shift (SGS) using two reactors in
series.
[0139] (b) Sour WGS using three reactors as disclosed herein and as
illustrated in FIG. 8.
[0140] (c) Traditional sweet gas shift using two reactors in
series.
[0141] (d) Sweet WGS using three reactors as disclosed herein and
as illustrated in FIG. 8.
[0142] In each case, the feed gas was syngas generated from coal
gasification. For the sweet WGS as disclosed herein, a warm
desulfurization process (WDP) as disclosed herein was utilized to
remove sulfur from the syngas. The inlet syngas composition, along
with temperature, pressure, and molar flow-rate is provided in
Table 6 below. This is used as an illustrative example to compare
the different reactor configurations. Similar results are expected
from other syngas compositions.
TABLE-US-00006 TABLE 6 Inlet syngas composition Temperature,
.degree. F. 450 Pressure, psia 570 V-L Mole Fraction Ar 0.00000
CH.sub.4 0.00000 CO 0.34912 CO.sub.2 0.01841 COS 3.02E-04 H.sub.2
0.15172 H.sub.2O 0.44128 H.sub.2S 1.71E-03 HCl 2.52E-05 N.sub.2
0.03501 NH.sub.3 0.00241 O.sub.2 0.00000 SO.sub.2 0.00000 Total
1.0000
[0143] Syngas inlet temperature for the sour gas shift (SGS) was
kept at 550.degree. F., while the inlet temperature for the sweet
gas shift (or high temperature shift (HTS)) was fixed at
600.degree. F. Steam was added to the first shift reactor to
control the reactor outlet temperature under 900.degree. F. and to
maintain a minimum Steam/Dry Gas ratio of 2 at the inlet. In the
traditional WGS cases (cases (a) and (c)), the outlet syngas from
the first shift reactor is cooled to the minimum inlet temperature
by raising high pressure (HP) steam before being fed to the second
shift reactor. In the new WGS cases disclosed herein (cases (b) and
(d)), steam was added only to first shift reactor, with boiler feed
water (BFW) added to subsequent reactors, if needed, to control the
outlet temperature to a maximum of 900.degree. F. This approach
reduced the steam consumption and generated the needed steam in
situ.
[0144] The four different cases outlined above were simulated using
ASPEN PLUS.RTM. software (Aspen Technology, Inc., Burlington,
Mass., USA), a process flow modeling software program. The model
solved for the heat and mass balance for each reactor configuration
and provided information on the steam requirements for comparison
of the different cases. It is expected that similar results would
be achieved using other software models. Assumptions and process
conditions used in the model are provided in Table 7 below.
TABLE-US-00007 TABLE 7 Parameter Value High Temperature Shift
Minimum inlet temperature 600.degree. F. (315 .degree. C.) Maximum
outlet temperature 900.degree. F. (482 .degree. C.) Sour Gas Shift
Minimum inlet temperature 550.degree. F. (288 .degree. C.) Maximum
outlet temperature 900.degree. F. (482 .degree. C.) Pressure drop
across each shift reactor 10 psia Gas Hourly Space Velocity (GHSV)
10,000 h.sup.-1 used to calculate reactor volume Steam/Dry Gas
ratio Need to control outlet temperature Min S/DG ratio at inlet 1
= 2.0 (to avoid coking on catalyst) HP Boiler Feed Water (BFW)
conditions 450.degree. F., 750 psig HP Steam conditions 500.degree.
F., 650 psig
[0145] The results from the four different cases are provided in
Table 8 below.
TABLE-US-00008 TABLE 8 Traditional- New Sour Traditional- New HTS
Units Sour WGS WGS HTS WGS WGS # Reactors 2 3 2 3 Syngas split
fractions Inlet Temperature .degree. F. 550 550 600 600 Max outlet
.degree. F. 900 900 900 900 Temperature Steam/Dry Gas 2 2 2.35 2.35
(reactor 1 inlet) CO Conversion % 98.3 93.0 98.1 93.0 Steam Usage
HP BFW added (A) lb./hr. 0 80,353 0 44,913 HP steam added (B)
lb./hr. 809,780 145,760 1,048,610 241,098 Steam generated lb./hr.
440,261 204,750 443,514 259,398 with inter-stage cooling (C) Net
Steam in Syngas lb./hr. 809,780 226,113 1,048,610 286,011 (A + B)
Net Steam lb./hr. 369,519 -58,990 604,218 -18,300 Consumption (B -
C) Total catalyst lbs. 536,602 393,425 604,218 442,513 Required
Catalyst cost $/lb. $11.71 $11.71 $5.62 $5.62 (2011$) Annual VOX $
(.times.1000) $1,257 $921 $679 $497 (2011$)-catalyst only Capital
Cost (2011$)- $ (.times.1000) $10,517 $9,230 WGS & LTGC
[0146] Based on the modeling results, it is observed that the use
of the new split-flow WGS configuration disclosed herein results in
overall lower steam requirements compared to the traditional
configuration. The amount of catalyst needed is also reduced, thus
providing additional economic benefits. Moreover, the split-flow
WGS configuration is operative for both the sour gas shift as well
as the high temperature sweet gas shift.
[0147] It is also observed that the overall CO conversion resulting
from the use of the new split-flow WGS configuration is somewhat
lower than what is observed for the traditional configuration.
However, the overall CO conversion for the new split-flow
configuration may be improved by implementing the LT shift in the
last reactor, and/or through further refinements to the method.
Exemplary Embodiments
[0148] Exemplary embodiments provided in accordance with the
presently disclosed subject matter include, but are not limited to,
the following:
[0149] 1. A method for producing a water-gas shifted gas comprising
CO.sub.2 and H.sub.2, the method comprising: splitting a flow of
feed gas comprising carbon monoxide (CO) into a plurality of feed
gas streams comprising at least a first feed gas stream, a second
feed gas stream, and a third feed gas stream; combining the first
feed gas stream with a steam stream to produce a first input gas
stream; flowing the first input gas stream into a first shift
reactor containing a first shift catalyst; reacting the CO with the
steam in the presence of the first shift catalyst to produce a
first product gas stream comprising carbon dioxide (CO.sub.2) and
hydrogen (H.sub.2); combining the first product gas stream with the
second feed gas stream to produce a second input gas stream heated
by the first product gas stream; before combining the first product
gas stream with the second feed gas stream, adding water as a spray
to the first product gas stream to vaporize the water into steam,
wherein the first product gas stream is cooled before being
combined with the second feed gas stream; flowing the second input
gas stream into a second shift reactor containing a second shift
catalyst; reacting the CO of the second input gas stream with the
steam in the presence of the second shift catalyst to produce a
second product gas stream comprising CO.sub.2 and H.sub.2;
combining the second product gas stream with the third feed gas
stream to produce a third input gas stream heated by the second
product gas stream; before combining the second product gas stream
with the third feed gas stream, adding water as a spray to the
second product gas stream to vaporize the water into steam, wherein
the second product gas stream is cooled before being combined with
the third feed gas stream; flowing the third input gas stream into
a third shift reactor containing a third shift catalyst; and
reacting the CO of the third input gas stream with the steam in the
presence of the third shift catalyst to produce a third product gas
stream comprising CO.sub.2 and H.sub.2.
[0150] 2. The method of embodiment 1, comprising adding water as a
spray into the first feed gas stream or the first input gas
stream.
[0151] 3. The method of embodiment 1, wherein the feed gas
comprises syngas.
[0152] 4. The method of embodiment 1, wherein the feed gas
comprises a sulfur compound, and the first shift catalyst, the
second shift catalyst, and the third shift catalyst are
sulfur-tolerant.
[0153] 5. The method of embodiment 4, comprising removing at least
part of the sulfur compound from the third product gas stream.
[0154] 6. The method of embodiment 1, wherein the feed gas
comprises a sulfur compound, and comprising removing at least part
of the sulfur compound from the flow of feed gas to reduce the
amount of sulfur compound in the first feed gas stream, the second
feed gas stream, and the third feed gas stream.
[0155] 7. The method of embodiment 1, wherein 30%-80% of the total
steam requirement for the water-gas shift process is supplied as
liquid water.
[0156] 8. The method of embodiment 1, wherein flowing the first
input gas stream into the first shift reactor is done at an inlet
temperature ranging from 400 to 700.degree. F.
[0157] 9. The method of embodiment 1, wherein flowing the second
input gas stream into the second shift reactor is done at an inlet
temperature ranging from 400 to 700.degree. F.
[0158] 10. The method of embodiment 1, wherein flowing the third
input gas stream into the third shift reactor is done at an inlet
temperature ranging from 400 to 700.degree. F.
[0159] 11. The method of embodiment 1, wherein the plurality of
feed gas streams comprises one or more additional feed gas streams,
and further comprising reacting the CO of the one or more
additional feed gas streams with steam in one or more additional
shift reactors, respectively, downstream from the third shift
reactor.
[0160] 12. The method of embodiment 1, comprising producing a local
steam supply by flowing liquid water into thermal contact with a
heated gas stream selected from the group consisting of: the first
feed gas stream; the second feed gas stream; the third feed gas
stream; the first input gas stream; the second input gas stream;
the third input gas stream; and a combination of two or more of the
foregoing.
[0161] 13. The method of embodiment 12, wherein combining the first
feed gas stream with the steam stream comprises flowing steam from
the local steam supply into the first feed gas stream.
[0162] 14. The method of embodiment 12, wherein the liquid water is
boiler feed water.
[0163] 15. The method of embodiment 1, comprising heating the first
feed gas stream or the first input gas stream by flowing the first
feed gas stream or the first input gas stream into thermal contact
with a heated gas stream selected from the group consisting of: the
first product gas stream; the second product gas stream; the third
product gas stream; and a combination of two or more of the
foregoing.
[0164] 16. The method of embodiment 1, comprising adding liquid
water to a gas stream selected from the group consisting of: the
first feed gas stream; the second feed gas stream; the third feed
gas stream; the first input gas stream; the second input gas
stream; the third input gas stream; and a combination of two or
more of the foregoing.
[0165] 17. The method of embodiment 16, wherein the liquid water is
boiler feed water.
[0166] 18. The method of embodiment 1, wherein the plurality of
feed gas streams comprises a bypass gas stream, and further
comprising combining the bypass gas stream with the third product
gas stream to produce an output gas stream having a desired
H.sub.2/CO ratio.
[0167] 19. The method of embodiment 1, comprising controlling a
steam/dry gas ratio in the first input gas stream by controlling a
flow rate of the steam stream added to the first feed gas stream,
controlling a flow rate of a liquid water stream added to the first
feed gas stream, or both of the foregoing.
[0168] 20. The method of embodiment 1, comprising controlling a
steam/dry gas ratio in at least one of the second input gas stream
and the third input gas stream by controlling a flow rate of a
liquid water stream added to at least one of the second feed gas
stream, the second input gas stream, the third feed gas stream, and
the third input gas stream.
[0169] 21. The method of embodiment 1, wherein the first feed gas
stream has a steam to CO ratio ranging from 0.12 to 1.5.
[0170] 22. A water gas shift reaction system configured to perform
the method of any of the preceding embodiments.
[0171] 23. A water gas shift reaction system, comprising: a flow
splitter configured for splitting a flow of feed gas comprising
carbon monoxide (CO) into at least a first feed gas stream, a
second feed gas stream, and a third feed gas stream; a first input
gas line configured for conducting a first input gas stream, the
first input gas stream comprising a combination of the first feed
gas stream and steam; a first shift reactor comprising a first
vessel, a first shift catalyst disposed in the first vessel, a
first inlet configured for conducting the first input gas stream
into the first vessel, and a first outlet, wherein the first shift
reactor is configured for reacting the CO and the steam in the
first input gas stream in the presence of the first shift catalyst
to produce a first product gas stream comprising carbon dioxide
(CO.sub.2) and hydrogen (H.sub.2); a first product gas line
configured for receiving the first product gas stream from the
first outlet; a sprayer configured for adding water as a spray into
the first product gas stream; a second input gas line configured
for conducting a second input gas stream, the second input gas
stream comprising a combination of the second feed gas stream and
the first product gas stream; a second shift reactor comprising a
second vessel, a second shift catalyst disposed in the second
vessel, a second inlet configured for conducting the second input
gas stream into the second vessel, and a second outlet, wherein the
second shift reactor is configured for reacting the CO and the
steam in the second input gas stream in the presence of the second
shift catalyst to produce a second product gas stream comprising
CO.sub.2 and H.sub.2; a second product gas line configured for
receiving the second product gas stream from the second outlet; a
sprayer configured for adding water as a spray into the second
product gas stream; a third input gas line configured for
conducting a third input gas stream, the third input gas stream
comprising a combination of the third feed gas stream and the
second product gas stream; and a third shift reactor comprising a
third vessel, a third shift catalyst disposed in the third vessel,
a third inlet configured for conducting the third input gas stream
into the third vessel, and a third outlet, wherein the third shift
reactor is configured for reacting the CO and the steam in the
third input gas stream in the presence of the third shift catalyst
to produce a third product gas stream comprising CO.sub.2 and
H.sub.2.
[0172] 24. The water gas shift reaction system of embodiment 23,
comprising a sprayer configured for adding water as a spray into
the first input gas stream.
[0173] 25. A method for removing acid gases from a gas stream, the
method comprising: flowing a feed gas into a desulfurization unit
to remove a substantial fraction of a sulfur compound from the feed
gas, wherein the desulfurization unit produces a desulfurized feed
gas; flowing the desulfurized feed gas into a CO.sub.2 removal unit
to remove a substantial fraction of CO.sub.2 from the desulfurized
feed gas; and before or after desulfurizing the feed gas,
subjecting the feed gas to a water-gas shift reaction by: splitting
a flow of feed gas comprising carbon monoxide (CO) into a plurality
of feed gas streams comprising at least a first feed gas stream, a
second feed gas stream, and a third feed gas stream; combining the
first feed gas stream with a steam stream to produce a first input
gas stream; flowing the first input gas stream into a first shift
reactor containing a first shift catalyst; reacting the CO with the
steam in the presence of the first shift catalyst to produce a
first product gas stream comprising carbon dioxide (CO.sub.2) and
hydrogen (H.sub.2); combining the first product gas stream with the
second feed gas stream to produce a second input gas stream heated
by the first product gas stream; flowing the second input gas
stream into a second shift reactor containing a second shift
catalyst; reacting the CO of the second input gas stream with the
steam in the presence of the second shift catalyst to produce a
second product gas stream comprising CO.sub.2 and H.sub.2;
combining the second product gas stream with the third feed gas
stream to produce a third input gas stream heated by the second
product gas stream; flowing the third input gas stream into a third
shift reactor containing a third shift catalyst; and reacting the
CO of the third input gas stream with the steam in the presence of
the third shift catalyst to produce a third product gas stream
comprising CO.sub.2 and H.sub.2.
[0174] 26. The method of embodiment 25, comprising a step selected
from the group consisting of: before combining the first product
gas stream with the second feed gas stream, adding water as a spray
to the first product gas stream to vaporize the water into steam,
wherein the first product gas stream is cooled before being
combined with the second feed gas stream; before combining the
second product gas stream with the third feed gas stream, adding
water as a spray to the second product gas stream to vaporize the
water into steam, wherein the second product gas stream is cooled
before being combined with the third feed gas stream; and both of
the foregoing.
[0175] 27. The method of embodiment 25, comprising adding water as
a spray into the first feed gas stream or the first input gas
stream.
[0176] 28. The method of embodiment 25, wherein the feed gas
comprises one or more of: carbon monoxide (CO), carbon dioxide
(CO.sub.2), hydrogen gas (H.sub.2), syngas, shifted syngas, a
hydrocarbon (HC), and natural gas.
[0177] 29. The method of embodiment 25, wherein the sulfur compound
of the feed gas is selected from the group consisting of: hydrogen
sulfide (H.sub.2S), carbonyl sulfide (COS), a disulfide, carbon
disulfide (CS.sub.2), a mercaptan, and a combination of two or more
of the foregoing.
[0178] 30. The method of embodiment 25, wherein flowing the feed
gas into the desulfurization unit is done in a temperature range
selected from the group consisting of: about 400.degree. F. or
greater; about 400.degree. F. to about 1200.degree. F.
[0179] 31. The method of embodiment 25, wherein flowing the feed
gas into the desulfurization unit is done at a pressure ranging
from about 1 atm to 100 atm.
[0180] 32. The method of embodiment 25, wherein flowing the
desulfurized gas into the CO.sub.2 removal unit is done in range
selected from the group consisting of: about -80.degree. F. to
about 30.degree. F.; about 30.degree. F. to about 130.degree. F.;
and about 200.degree. F. to about 900.degree. F.
[0181] 33. The method of embodiment 25, wherein flowing the
desulfurized gas into the CO.sub.2 removal unit is done at a
pressure ranging from about 1 atm to about 100 atm.
[0182] 34. The method of embodiment 25, wherein at least one of the
desulfurization unit and the CO.sub.2 removal unit comprises a
component selected from the group consisting of: a fixed-bed
reactor, a moving-bed reactor, a fluidized-bed reactor, a transport
reactor, a monolith, a micro-channel reactor, an absorber unit, and
an absorber unit in fluid communication with a regenerator
unit.
[0183] 35. The method of embodiment 25, wherein flowing the feed
gas into the desulfurization unit comprises flowing the feed gas
into contact with a sorbent.
[0184] 36. The method of embodiment 35, wherein sorbent is selected
from the group consisting of: a metal oxide, zinc oxide, copper
oxide, iron oxide, vanadium oxide, manganese oxide, stannous oxide,
nickel oxide, a metal titanate, zinc titanate, a metal ferrite,
zinc ferrite, copper ferrite, and a combination of two or more of
the foregoing.
[0185] 37. The method of embodiment 35, wherein the sorbent
comprises a support selected from the group consisting of: alumina
(Al.sub.2O.sub.3), silicon dioxide (SiO.sub.2), titanium dioxide
(TiO.sub.2), a zeolite, and a combination of two or more of the
foregoing.
[0186] 38. The method of embodiment 35, wherein the sorbent is
regenerable or non-regenerable.
[0187] 39. The method of embodiment 35, wherein the sorbent has an
average particle size in a range from about 35 .mu.m to about 175
.mu.m.
[0188] 40. The method of embodiment 35, wherein flowing the feed
gas into contact with a sorbent comprises flowing the feed gas into
contact with a sorbent stream comprising the sorbent and a carrier
gas.
[0189] 41. The method of embodiment 40, wherein flowing the feed
gas into contact with the sorbent stream is done in an absorber
unit, and further comprising outputting the desulfurized gas and
sulfided sorbent from the absorber unit.
[0190] 42. The method of embodiment 41, comprising separating the
desulfurized gas from the sulfided sorbent.
[0191] 43. The method of embodiment 42, wherein separating the
desulfurized gas from the sulfided sorbent comprises flowing the
desulfurized gas and the sulfided sorbent into a solids
separator.
[0192] 44. The method of embodiment 43, wherein the solids
separator is selected from the group consisting of: a cyclone
separator, an electrostatic precipitator, a filter, and a gravity
settling chamber.
[0193] 45. The method of embodiment 41, comprising flowing the
sulfided sorbent into a regenerating unit to produce a regenerated
sorbent and a sulfur compound, and flowing the regenerated sorbent
into the absorber unit.
[0194] 46. The method of embodiment 45, wherein flowing the
sulfided sorbent into the regenerating unit is done at a
temperature of about 900.degree. F. or greater.
[0195] 47. The method of embodiment 45, wherein flowing the
sulfided sorbent into the regenerating unit is done at a
temperature ranging from about 900.degree. F. to about 1400.degree.
F.
[0196] 48. The method of embodiment 45, wherein flowing the
sulfided sorbent into the regenerating unit comprises flowing the
sulfided sorbent into contact with a regenerating agent.
[0197] 49. The method of embodiment 48, wherein the regenerating
agent comprises air or oxygen gas or an oxygen compound, and the
sulfur compound produced in the regenerating unit comprises sulfur
dioxide.
[0198] 50. The method of embodiment 45, comprising separating the
regenerated sorbent from the sulfur compound produced in the
regenerating unit.
[0199] 51. The method of embodiment 50, comprising, after
separating the regenerated sorbent compound from the sulfur
compound, producing sulfuric acid, elemental sulfur, or both
sulfuric acid and elemental sulfur, from the sulfur compound.
[0200] 52. The method of embodiment 25, wherein flowing the
desulfurized gas into the CO.sub.2 removal unit comprises flowing
the desulfurized gas into contact with a CO.sub.2 removing
agent.
[0201] 53. The method of embodiment 52, wherein the CO.sub.2
removing agent is a solvent-based agent that removes CO.sub.2 by
gas absorption and subsequent regeneration.
[0202] 54. The method of embodiment 52, wherein the CO.sub.2
removing agent is selected from the group consisting of: methanol,
dimethyl ethers of polyethylene (DEPG), N-methyl-2-pyrrolidone
(NMP), sulfolane (2,3,4,5-tetrahydrothiophene-1,1-dioxide),
propylene carbonate, and a combination of two or more of the
foregoing.
[0203] 55. The method of embodiment 52, wherein the CO.sub.2
removing agent is selected from the group consisting of:
methyldiethanolamine (MDEA), activated MDEA (aMDEA),
monoethanolamine (MEA), diethanolamine (DEA), triethanolamine
(TEA), diisopropanolamine (DIPA), diglycolamine (DGA), potassium
carbonate, and a combination of two or more of the foregoing.
[0204] 56. The method of embodiment 52, wherein the CO.sub.2
removing agent comprises a mixture of sulfolane
(2,3,4,5-tetrahydrothiophene-1,1-dioxide), water, and one or more
of methyldiethanolamine (MDEA), piperazine, and diisopropanolamine
(DIPA).
[0205] 57. The method of embodiment 52, wherein the CO.sub.2
removing agent comprises a FLEXSORB.RTM. PS formulation or a
UCARSOL.RTM. LE formulation.
[0206] 58. The method of embodiment 52, wherein the CO.sub.2
removing agent comprises a particulate sorbent selected from the
group consisting of: alkali metal oxides, alkali metal carbonates,
lithium silicate, amine-functionalized solid sorbents,
amine-functionalized silica, amine-functionalized zeolites,
amine-functionalized hydrotalcites, amine-functionalized
metal-organic frameworks, and a combination of two or more of the
foregoing.
[0207] 59. The method of embodiment 52, wherein the CO.sub.2
removing agent is regenerable or non-regenerable.
[0208] 60. The method of embodiment 52, wherein the CO.sub.2
removing agent comprises a membrane effective for dissolution and
diffusion of CO.sub.2.
[0209] 61. The method of embodiment 52, wherein the CO.sub.2
removing agent comprises a liquid-phase agent, and further
comprising flowing the liquid-phase agent into the CO.sub.2 removal
unit.
[0210] 62. The method of embodiment 25, wherein flowing the
desulfurized gas into contact with the CO.sub.2 removing agent is
done in an absorber unit, and further comprising outputting from
the absorber unit a treated gas comprising the substantially
reduced fractions of sulfur and CO.sub.2.
[0211] 63. The method of embodiment 62, wherein flowing the
desulfurized gas into contact with the CO.sub.2 removing agent
produces in the absorber unit a CO.sub.2-rich fluid comprising the
CO.sub.2 removing agent and CO.sub.2, and further comprising:
flowing the CO.sub.2-rich fluid from the absorber unit to a
regenerator unit; removing CO.sub.2 from the CO.sub.2-rich fluid
stream in the regenerator unit to produce a CO.sub.2-lean fluid
stream; and flowing the CO.sub.2-lean fluid stream into the
absorber unit.
[0212] 64. The method of embodiment 25, wherein the CO.sub.2
removal unit produces a CO.sub.2 output stream, and further
comprising outputting the CO.sub.2 output stream from the CO.sub.2
removal unit and recovering CO.sub.2 from the CO.sub.2 output
stream.
[0213] 65. The method of embodiment 25, wherein the CO.sub.2
removal unit is effective for removing CO.sub.2 without actively
removing sulfur from the desulfurized gas.
[0214] 66. The method of embodiment 25, wherein the CO.sub.2
removal unit is effective for removing CO.sub.2 without removing a
substantial amount of sulfur from the desulfurized gas.
[0215] 67. The method of embodiment 25, wherein the desulfurized
gas has a sulfur concentration of about 25 parts per million (ppm)
by volume or less.
[0216] 68. The method of embodiment 25, wherein the desulfurized
gas has a sulfur concentration of about 100 parts per billion (ppb)
by volume or less.
[0217] 69. The method of embodiment 25, comprising flowing the
desulfurized gas into the CO.sub.2 removal unit without
cryogenically cooling the desulfurized gas via external
refrigeration.
[0218] 70. The method of embodiment 25, wherein flowing the
desulfurized gas into the CO.sub.2 removal unit produces a treated
gas having a CO.sub.2 concentration of about 5% by volume or
less.
[0219] 71. A method for removing acid gases from a gas stream, the
method comprising: flowing a feed gas stream comprising carbon
monoxide (CO), carbon dioxide (CO.sub.2), and a sulfur compound
into contact with a sorbent stream in an absorber unit to produce a
first output gas stream, wherein the sorbent stream comprises a
particulate sorbent compound effective for removing the sulfur
compound from the feed gas stream, and the first output gas stream
comprises a desulfurized gas comprising CO and CO.sub.2, and a
sulfided sorbent; separating the desulfurized gas from the sulfided
sorbent; flowing the sulfided sorbent into contact with a
regenerating agent in a regenerator unit to produce a second output
gas stream, wherein the regenerating agent has a composition
effective for removing sulfur from the sulfided sorbent, and the
second output gas stream comprises regenerated sorbent compound and
a sulfur compound; separating the regenerated sorbent compound from
the sulfur compound; flowing the regenerated sorbent compound into
the absorber unit; flowing the desulfurized gas into contact with a
CO.sub.2 removing agent in a CO.sub.2 removal unit to produce a
treated gas comprising CO and substantially reduced fractions of
sulfur and CO.sub.2.
[0220] 72. A gas processing system configured for performing the
method of any of the preceding embodiments.
[0221] 73. A gas processing system, comprising: a desulfurization
unit configured for removing a substantial fraction of a sulfur
compound from a process gas to produce a desulfurized gas; and a
CO.sub.2 removal unit positioned downstream from the
desulfurization unit, and configured for removing a substantial
fraction of CO.sub.2 from the desulfurized gas; and a water-gas
shift unit positioned upstream or downstream from the
desulfurization unit, the water-gas shift unit comprising: a flow
splitter configured for splitting a flow of feed gas comprising
carbon monoxide (CO) into at least a first feed gas stream, a
second feed gas stream, and a third feed gas stream; a first input
gas line configured for conducting a first input gas stream, the
first input gas stream comprising a combination of the first feed
gas stream and steam; a first shift reactor comprising a first
vessel, a first shift catalyst disposed in the first vessel, a
first inlet configured for conducting the first input gas stream
into the first vessel, and a first outlet, wherein the first shift
reactor is configured for reacting the CO and the steam in the
first input gas stream in the presence of the first shift catalyst
to produce a first product gas stream comprising carbon dioxide
(CO.sub.2) and hydrogen (H.sub.2); a first product gas line
configured for receiving the first product gas stream from the
first outlet; a second input gas line configured for conducting a
second input gas stream, the second input gas stream comprising a
combination of the second feed gas stream and the first product gas
stream; a second shift reactor comprising a second vessel, a second
shift catalyst disposed in the second vessel, a second inlet
configured for conducting the second input gas stream into the
second vessel, and a second outlet, wherein the second shift
reactor is configured for reacting the CO and the steam in the
second input gas stream in the presence of the second shift
catalyst to produce a second product gas stream comprising CO.sub.2
and H.sub.2; a second product gas line configured for receiving the
second product gas stream from the second outlet; a third input gas
line configured for conducting a third input gas stream, the third
input gas stream comprising a combination of the third feed gas
stream and the second product gas stream; and a third shift reactor
comprising a third vessel, a third shift catalyst disposed in the
third vessel, a third inlet configured for conducting the third
input gas stream into the third vessel, and a third outlet, wherein
the third shift reactor is configured for reacting the CO and the
steam in the third input gas stream in the presence of the third
shift catalyst to produce a third product gas stream comprising
CO.sub.2 and H.sub.2.
[0222] 74. The gas processing system of embodiment 73, comprising a
component selected from the group consisting of: a sprayer
configured for adding water as a spray into the first product gas
stream; a sprayer configured for adding water as a spray into the
second product gas stream; and both of the foregoing.
[0223] 75. The gas processing system of embodiment 73, comprising a
sprayer configured for adding water as a spray into the first input
gas stream.
[0224] 76. The gas processing system of embodiment 73, wherein at
least one of the desulfurization unit and the CO.sub.2 removal unit
comprises a component selected from the group consisting of: a
fixed-bed reactor, a moving-bed reactor, a fluidized-bed reactor, a
transport reactor, a monolith, a micro-channel reactor, an absorber
unit, and an absorber unit in fluid communication with a
regenerator unit.
[0225] In general, terms such as "communicate" and "in . . .
communication with" (for example, a first component "communicates
with" or "is in communication with" a second component) are used
herein to indicate a structural, functional, mechanical,
electrical, signal, optical, magnetic, electromagnetic, ionic or
fluidic relationship between two or more components or elements. As
such, the fact that one component is said to communicate with a
second component is not intended to exclude the possibility that
additional components may be present between, and/or operatively
associated or engaged with, the first and second components.
[0226] It will be understood that various aspects or details of the
invention may be changed without departing from the scope of the
invention. Furthermore, the foregoing description is for the
purpose of illustration only, and not for the purpose of
limitation--the invention being defined by the claims.
* * * * *