RELATEDAPPLICATIONS
[0001] This application claims the benefit of U.S. Provisional Patent Application Serial No.
62/068,333, filed October 24, 2014, titled "INTEGRATED SYSTEM AND METHOD FOR
REMOVING ACID GAS FROM A GAS STREAM," the content of which is incorporated herein by
reference in its entirety.
TECHNICAL FIELD
[0002] The present invention generally relates to the 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 H2S,
SO2, COS, HC1, NH3, 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 H2, CO and/or CO2
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 H2. Syngas often contains contaminants
(including H2S, COS) depending on the starting raw material. The H2S 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 SO2 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® process by Dow Chemicals (licensed to UOP)
which uses a mixture of dimethyl ethers of polyethylene glycol (DEPG), RECTISOL® 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 H2S, COS, and C0 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 H2S and COS into
separate streams. H2S/COS stream is used further downstream, either for sulfur recovery or
production of sulfuric acid. The C0 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 C0 2 in a way that would optimize the removal of both sulfur compounds and C0 2, whereby
sulfur compounds could be reduced to lower levels in the process gas, and higher levels of purity of
the sulfur compounds and C0 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 H2, by converting
the CO to H2 via the water-gas-shift (WGS) process and removing the C0 2 in the gas stream and
purifying the treated gas using a pressure swing adsorption (PSA) or a membrane process. The H2 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 (CO2) and
diatomic hydrogen gas (H2) by reacting the CO with steam over a catalyst bed. WGS is an industrially
important process utilized to increase the H2/CO ratio to meet the downstream process requirements
of a particular application. For example, WGS finds applications in pre-combustion C0 2 capture
where a fuel is partially oxidized to produce synthesis gas (or "syngas," predominantly consisting of
CO + H2) . This syngas is shifted to maximize the H2 and C0 2 concentrations, and C0 2 removal prior
to combustion of the H2-rich clean gas in turbines for generating electricity. WGS also finds
widespread applications in chemicals production where the H2/CO ratio needs to be adjusted as per
the process requirements. For example, the synthesis of methanol (CH3OH), CO + 2 H2 ® CH3OH,
requires the H2/CO ratio to be 2.
[0010] In traditional AGR processes such as the RECTISOL® and SELEXOL® 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 (H2S) and carbonyl sulfide (COS)) and requires an expensive
catalyst that is sulfur tolerant and promotes the shift reaction in the presence of H2S and COS.
Examples of sulfur tolerant shift catalysts include cobalt-molybdenum (Co-Mo) and nickelmolybdenum
(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. Thus, it would be desirable to be able to decouple the
process of removing sulfur compounds from the process of removing C0 2 so as to facilitate
implementation of the WGS downstream of the sulfur removal process. This may enable better
control over the H2/CO ratio and/or removal of C0 2, as well as the use of the less expensive sweet
shift catalysts.
SUMMARY
[0011] 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.
[0012] According to one 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 sulfur
compounds from the feed gas, wherein the desulfurization unit produces a desulfurized gas; and
flowing the desulfurized gas into a CO2 removal unit to remove a substantial fraction of CO2 from
the desulfurized gas.
[0013] According to another embodiment, a method for removing acid gases from a gas stream
includes: flowing a feed gas stream comprising carbon monoxide (CO), carbon dioxide (CO2), 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 CO2, 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 CO2 removing agent in a CO2 removal unit to produce a treated
gas comprising CO and substantially reduced fractions of sulfur and CO2.
[0014] In some embodiments, the feed gas is flowed into the desulfurization unit at a temperature
of about 400 °F (204 °C) or greater.
[0015] In some embodiments, the desulfurized gas is flowed into CO2 removal unit at a
temperature of about -80 °F (-62 °C) or greater.
[0016] In some embodiments, the feed gas stream includes carbon monoxide (CO), carbon
dioxide (CO2), hydrogen (¾), syngas, shifted syngas, a hydrocarbon (HC), or natural gas.
[0017] In some embodiments, the sulfur compound of the feed gas stream includes hydrogen
sulfide (H2S), carbonyl sulfide (COS), carbon disulfide (CS2) and/or other disulfide(s), and/or one or
more mercaptans.
[0018] In some embodiments, the feed gas stream is subjected to a WGS reaction before
desulfurization or after desulfurization. In some embodiments, the WGS is performed after
desulfurization and before CO2 removal.
[0019] According to another embodiment, a gas processing system is configured for performing
any of the methods disclosed herein.
[0020] 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 CO2 removal unit positioned downstream from the desulfurization
unit, and configured for removing a substantial fraction of CO2 from the desulfurized gas.
[0021] According to another embodiment, the desulfurization unit, the CO2 removal unit, or both,
include at least one of the following: 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.
[0022] According to another embodiment, the gas processing system includes a water-gas shift
unit positioned upstream or downstream from the desulfurization unit, and configured for shifting the
process gas to produce carbon dioxide (CO2) and hydrogen gas (¾).
[0023] 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
[0024] 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.
[0025] Figure 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.
[0026] Figure 2 is a schematic view of an example of a desulfurization system (or unit) according
to some embodiments.
[0027] Figure 3 is a schematic view of an example of a CO2 removal system (or unit) according
to some embodiments.
[0028] Figure 4 is a schematic view of an example of a stand-alone RECTISOL® process utilized
for removal of S and CO2.
[0029] Figure 5 is a schematic view of an example of a warm gas desulfurization process
integrated with a decoupled RECTISOL® process configured for C0 2 scrubbing according to some
embodiments.
[0030] Figure 6 is a schematic view of an example of a stand-alone SELEXOL® process utilized
for removal of S and CO2.
[0031] Figure 7 is a schematic view of an example of a decoupled SELEXOL® process
configured for CO2 scrubbing, which is configured for integration with an upstream warm gas
desulfurization process, according to some embodiments.
DETAILEDDESCRIPTION
[0032] 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 (H2) .
Depending on the embodiment, syngas may additionally include other components such as, for
example, water, air, diatomic nitrogen gas (N2), diatomic oxygen gas (0 2), carbon dioxide (C02),
sulfur compounds (e.g., hydrogen sulfide (H2S), carbonyl sulfide (COS), sulfur oxides (SOx), etc.),
nitrogen compounds (e.g., nitrogen oxides (NOx), etc.), metal carbonyls, hydrocarbons (e.g., methane
(CH4)), ammonia (NH3), chlorides (e.g., hydrogen chloride (HQ)), 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.
[0033] 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 (CS2) and/or other disulfides, and mercaptans (thiols) such as
methanethiol (CH3SH) and ethanethiol (C2H5SH) and other organosulfur compounds.
[0034] 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 are suspended or carried. The term "gas" encompasses a gas that includes or
entrains 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.
[0035] As used herein, the term "process gas" generally refers to any gas initially containing one
or more sulfur compounds and C0 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 CO2
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, CO2, 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, CO2, H2, and hydrocarbon(s) (HCs).
[0036] 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 H2S 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 °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.
[0037] The WDP may be provided as an upstream process that is integrated with a downstream
CO2 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 CO2 removal process. In some embodiments, the CO2 removal process
may be an AGR process modified to primarily or exclusively (or selectively) remove CO2. In all such
embodiments, the integrated gas treatment process decouples the sulfur removal from the CO2
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 CO2 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 C02 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 CO2 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.
[0038] 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 CO2 removal unit
to remove a substantial fraction of CO2 from the desulfurized gas.
[0039] In various embodiments, the desulfurization unit and/or the CO2 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.
[0040] 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 (CO2), 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 CO2) 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 CO2 removing agent in a CO2
removal unit to produce a treated gas that includes CO and substantially reduced fractions of sulfur
and CO2. 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 CO2 removed by the CO2 removal unit is outputted from the CO2
removal unit and may be recovered or subjected to further processing as desired.
[0041] 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 CO2, 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 CO2 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.
[0042] 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 (N2) . 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 mih to about 175 mih.
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.
[0043] 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.
[0044] 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 (ZnAkC^) phase. More generally, the sorbent may include a support such
as, for example, alumina (AI2O3), silicon dioxide (S1O2), titanium dioxide (T1O2), a zeolite, or a
combination of two or more of the foregoing.
[0045] Taking metal oxide as an example of the sorbent, the reactions associated with removing
H2S and COS from the process gas may be expressed as follows:
[0046] MO + H2S ® MS + H20 , and
[0047] MO + COS ® MS + C0 2 ,
[0048] 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).
[0049] 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 (O2) 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:
[0050] MS + (3/2)0 2 ® MO + S0 2 .
[0051] After separating the regenerated sorbent compound from the SO2 or other sulfur
compound, the gas stream containing the SO2 or other sulfur compound may be routed to any desired
destination for any desired purpose, such as recovering the SO2 for further use, producing sulfuric
acid or other desired sulfur compound, and/or producing elemental sulfur by any suitable process.
[0052] 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 °F or greater. In some embodiments, the desulfurization process is implemented in the
absorber unit at a temperature in a range from about 400 °F to about 1100 °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 °F or greater. In some
embodiments, the regeneration process is implemented in the regenerator unit at a temperature in a
range from about 900 °F to about 1400 °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.
[0053] 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 abovedescribed
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.
[0054] 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.
[0055] 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.,
SO2) 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.
[0056] 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. Patent No. 8,696,792; U.S. Patent No. 6,951,635; U.S. Patent
No. 6,306,793; U.S. Patent No. 5,972,835; U.S. Patent No. 5,914,288; and U.S. Patent No. 5,714,431;
the entire contents of each of which are incorporated by reference herein.
[0057] 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.
[0058] As described above, the acid gas removal method includes flowing the desulfurized gas to
a C0 2 removal unit where it is contacted with a CO2 removing agent. By implementing the upstream
warm gas desulfurization process described herein, the application of external refrigeration or subambient
cooling requirements for removing CO2 are reduced or eliminated. In particular, the
desulfurized gas fed to the CO2 removal unit need not be cryogenically cooled via a refrigeration
system. In some embodiments, flowing the desulfurized gas into contact with the CO2 removing
agent is done at a temperature ranging from about -80 °F to about 30 °F. In other embodiments,
flowing the desulfurized gas into contact with the CO2 removing agent is done at a temperature
ranging from about 30 °F to about 130 °F. In other embodiments, a warm gas CO2 removal process
may be performed. As one non-limiting example of the latter case, the desulfurized gas may be
flowed into contact with the CO2 removing agent at a temperature ranging from about 200 °F to about
900 °F.
[0059] Generally, the CO2 removing agent may be any agent effective for capturing CO2 from
the desulfurized gas stream. In some embodiments, the CO2 removing agent may be a solvent-based
agent that removes CO2 by gas absorption and subsequent regeneration. Thus, in some embodiments,
the CO2 removing agent is a physical solvent such as utilized in the RECTISOL® process, the
SELEXOL® process, the PURISOL® process (Lurgi AG Corp., Frankfurt, Fed. Rep. of Germany),
and the Fluor Solvent™ process. Examples of such solvents effective as CO2 removing agents
include, but are not limited to, methanol, a mixture of dimethyl ethers of polyethylene (DEPG), Nmethyl-
2-pyrrolidone (NMP), sulfolane (2,3,4,5-tetrahydrothiophene-l,l-dioxide), propylene
carbonate (C4H6O3), and a combination of two or more of the foregoing.
[0060] In other embodiments, the CO2 removing agent may be a chemical solvent such as aminebased
solvents; formulated amines such as aMDEA (BASF Corp., Florham Park, New Jersey, USA),
ADIP (Shell Global Solutions International B.V, The Hague, The Netherlands), and Amine Guard™
FS process solvent (UOP A Honeywell Company, Des Plaines, Illinois, USA); and the Benfield™
process solvent (UOP). Examples of such solvents effective as CO2 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 (K2CO3), and a combination of two or more of the foregoing.
[0061] In other embodiments, the CO2 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 CO2 removing agent may be a
solvent or mixture of solvents such as Sulfinol™ (Shell), FLEXSORB® PS solvent (ExxonMobil
Chemical Company, Houston, Texas, USA), and UCARSOL® LE solvent (Union Carbide
Corporation, Danbury, Connecticut, USA). Examples of such solvents effective as CO2 removing
agents include, but are not limited to, a mixture of sulfolane (2,3,4,5-tetrahydrothiophene-l,ldioxide),
water, and one or more of methyldiethanolamine (MDEA), piperazine (C4H10N2), and
diisopropanolamine (DIPA).
[0062] In other embodiments, the CO2 removing agent may be a sorbent-based agent. Examples
include, but are not limited to, alkali metal oxides, alkali metal carbonates, lithium silicate, aminefunctionalized
solid sorbents, amine-functionalized silica, amine-functionalized zeolites, aminefunctionalized
hydrotalcites, amine-functionalized metal-organic frameworks, and a combination of
two or more of the foregoing.
[0063] In other embodiments, the CO2 removing agent may be a membrane effective for
dissolution and diffusion of CO2. The membrane material may, for example, be polymer- or
cellulose-based.
[0064] In some embodiments, the CO2 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 CCh-lean fluid
stream containing regenerated CO2 removing agent, an outlet for outputting the treated gas (the
process gas after CO2 removal), and another outlet for outputting a CCh-rich fluid stream containing
the CO2 removing agent and captured CO2. A liquid-based CO2 removing agent, or a particulatebased
CO2 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 CO2 removing agent provided as a
fixed-bed, or a membrane-based CO2 removing agent, these types of CO2 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 CCh-rich fluid stream
produced in the absorber unit via a transfer line, an outlet for outputting the CO2 removed from the
C0 2-rich fluid stream as a C0 2 output stream, and another outlet for returning the C0 2-lean fluid
back to the absorber unit via a transfer line. The mechanism for regenerating the C0 2 removing agent
(converting the C0 2-rich fluid into the C0 2-lean fluid) may depend on the type of C0 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
C0 2 for regeneration of the C0 2 removing agent.
[0065] In some embodiments, the treated gas outputted from the C0 2 removal unit has a C0 2
concentration of about 5% by volume or less.
[0066] The method may further include processing the C0 2 output stream from the regenerator
unit by any suitable technique for recovering C0 2 from the C0 2 output stream. The recovered C0 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.
[0067] 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 C0 2 removal unit need not also be effective for removing sulfur
species. Hence, the presently disclosed acid gas removal method enables the C0 2 removal process
to be optimized for C0 2 removal without regard for sulfur removal. In some embodiments, the C0 2
removal unit or process may be characterized as being effective for removing C0 2 without actively
removing sulfur, or without removing a substantial amount of sulfur. In some other embodiments,
the C0 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 C0 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
C0 2 removal could not. In all embodiments, the goal of optimized sulfur and C0 2 removal would be
the production of a treated gas and byproduct streams (sulfur compounds and C0 2) that eliminate or
substantially reduce the number or complexity of subsequent cleaning processing requirements.
[0068] 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:
[0069] CO + H20 ®C0 2 + H2 , DH0
298 = -41 .09 kiloJoules/mole (kJ/mol),
[0070] where DH° 2 98 is the enthalpy of reaction at 298 kelvin (K).
[0071] 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.
[0072] The water gas shift process uses steam to shift CO to C0 2 and produces H2 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 H2 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.
[0073] 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 C0 2 removal process, facilitates carrying out a sweet shift reaction downstream of the
desulfurization process, for example between the sulfur removal process and the C0 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 C0 2 removal unit. In this case, the desulfurized
gas is flowed into contact with steam in the presence of a shift catalyst to produce C0 2 and H2, and
subsequently is subjected to the C0 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 H2 richness or a desired H2/CO ratio. For example, the increased level of C0 2 in the process
gas outputted from the WGS unit may then be adequately removed by the downstream CO2 removal
unit.
[0074] Figure 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 Figure 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.
[0075] The gas processing system 100 may include a feed gas source 104, a desulfurization
system (or unit) 108, and a CO2 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 CO2 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, CO2 removal system 140, CO2 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 CO2 and H2, removing C0 2 from the process gas, optionally recovering the C0 2, and
optionally removing one or more other types of contaminants from the process gas, respectively. The
desulfurization system 108 and C0 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.
[0076] In the illustrated embodiment, and as described above, the desulfurization system 108 and
the C0 2 removal system 140 are integrated, yet distinct, systems utilizing separate units for
desulfurization and C0 2 removal, with the C0 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 C0 2), and the C0 2 removal system 140 may be configured for primarily or
exclusively removing C0 2 from the process gas (as opposed to other compounds such as sulfur
compounds).
[0077] 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 C0 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 CO2/H2 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 C0 2 removal system 140, where
substantially all of the CO2 may be captured and removed, yielding a clean (treated) process gas 178
that may predominantly be comprised of CO and H2, etc., depending on the composition of the feed
gas inputted into the gas processing system 100. The C0 2 may then be recovered by the C0 2 recovery
system 144 to provide the C0 2 for further use or processing. In some embodiments, the process gas
is then routed from the C0 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 C0 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.
[0078] The particular embodiment of the gas processing system 100 illustrated in Figure 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.
[0079] Figure 2 is a schematic view of an example of a desulfurization system (or unit) according
to some embodiments.
[0080] Figure 3 is a schematic view of an example of a C0 2 removal system (or unit) according
to some embodiments.
[0081] In the following Examples, process flow models were developed using ASPEN PLUS®
software (Aspen Technology, Inc., Burlington, Massachusetts, 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 C0 2 capture technologies disclosed herein. These
studies utilized a consistent design basis, thereby allowing for a direct comparison of the costs.
[0082] EXAMPLE 1
[0083] This example illustrates the processing and acid gases removal for methanol synthesis.
RECTISOL® solvent for sulfur and CO2 capture is used here as the base case for comparison with
the integrated WDP and CO2 capture disclosed herein. The syngas is reacted with steam to shift the
gas to obtain a H2/CO ratio of 2 (as required for methanol synthesis). The sulfur removal is carried
out downstream of the water gas shift for the RECTISOL® base case, but it can be done either
upstream or downstream of the water gas shift for the WDP integrated cases.
[0084] 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.
[0085] TABLE 1 - Inlet syngas composition used in Example 1
HC1 0.0000
Inerts 0.0585
Total 1.0000
[0086] (a) WDP + modified RECTISOL® process for C0 2 capture
[0087] Figure 4 is a schematic view of an example of the conventional RECTISOL® process
utilized for removal of S and C0 2. In particular, Figure 4 shows essential components of a selective
RECTISOL® process in which C0 2 is recovered as a product and an H2S enriched stream is sent to
a Claus unit to recover sulfur. The C0 2 from the Claus unit is recirculated back to the absorber to
enhance C0 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® design: 1) the absorber section, 2) the C0 2
recovery section, 3) the H2S enrichment sections, 4) the water rejection section and 5) the methanol
recovery section or the gas treatment section.
[0088] The raw syngas has to be cooled to roughly ambient temperature before it enters the
RECTISOL® battery limit. Methanol is injected to prevent any water from freezing as the gas is
chilled by exchanging heat with chilled treated syngas, C0 2 product gas and tail gas. In the absorber
section, raw syngas is washed with chilled methanol to reduce C0 2,H2S, NH3 and other contaminants
to desired levels. The rich solvent is then pre-flashed to recover H2 and CO, which partly dissolve
simultaneously in the chilled methanol. The pre-flashed methanol is flashed further to recover the
bulk of the C0 2. The last bit of C0 2 is stripped out using nitrogen. The flashed methanol is then sent
to the H2S enrichment section where hot regeneration of the solvent along with H2S enrichment is
achieved. The methanol in the C0 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.
[0089] The feed to the standalone RECTISOL® process for this study is taken from a sour shift
reactor which brings the H2 to CO ratio to 2:1. The temperature, pressure, and composition of the
inlet raw syngas, treated syngas, C0 2 product, tail gas and H2S enriched gas are estimated using an
ASPEN PLUS® process model and are given in Table 2 below.
[0090] TABLE 2
[0091] The selective removal of C0 2 and H2S while simultaneously 1) enriching H2S-rich stream,
2) maintaining H2S specs in the tail gas and the C0 2 product, and 3) keeping the percent C0 2 capture
near 90% makes the process design very complicated. The H2S-rich stream should have more than
25 mol% of H2S for sulfur recovery in the conventional Claus process. The H2S in the C0 2 product
as well as the tail gas should not exceed 5 ppm. The allowable H2S 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® 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 °F or lower
before it enters the absorber. An even larger heat exchange area is required to chill the hot regenerated
methanol to -40 °F or lower before it is recirculated back to the absorber.
[0093] The RECTISOL® plant and the refrigeration plant contribute almost equally to the total
electricity consumption. The largest power consumers in the RECTISOL® plant are: 1) the chilled
regenerated methanol pump, 2) the H2 and CO recirculating compressors, and 3) the C0 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 C0 2 and H2S 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 C0 2 capture
technologies in accordance with the present disclosure.
[0095] Figure 5 is a schematic view of an example of the WDP integrated with a decoupled
RECTISOL® process configured for C0 2 scrubbing according to some embodiments. The WDP
removes 99+% sulfur from the raw syngas and the RECTISOL® plant is designed to remove C0 2
and other trace components. All the process constraints related to H2S removal and recovery in a
conventional RECTISOL® design such as shown in Figure 4 vanish, which results in a greatly
simplified design. The result is that the decoupled RECTISOL® configuration, such as shown in
Figure 5, has very few process components compared to the conventional RECTISOL® configuration
shown in Figure 4.
[0096] As shown in Figure 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 H2
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® process for C0 2 removal
[0098] The main complexity in the selective removal of H2S and C0 2 in the SELEXOL® 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® solvent has a much greater
solubility of H2S than that of C0 2, with the solubility of COS in between those of H2S and C0 2.
Relative solubilities of H2S and COS (relative to C0 2) in the SELEXOL® solvent are as follows.
[0099] TABLE 3
[00100] When COS is absent, the desulfurization solvent flow-rate is set for essentially complete
H2S removal and only a small fraction of the C0 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 C0 2 absorbed, resulting in an increase in equipment cost and utility
requirements. The co-absorption of C0 2 is also increased by the higher solvent flow-rate.
[00101] Another approach to address the differences in solubilities for H2S and COS in the
SELEXOL® solvent is to carry out COS hydrolysis to convert the COS to H2S, upstream of the
SELEXOL® process. This approach, however, requires additional equipment and an additional
processing step, adding to the overall cost of the SELEXOL® process.
[00102] Figure 6 is a schematic view of an example of the stand-alone SELEXOL® process
utilized for removal of S and C0 2. The feed gas is sent to the sulfur absorber column, where a slipstream
of the C0 2-rich SELEXOL® solvent from the C0 2 absorption column is used to absorb H2S
and COS. The syngas, essentially free of H2S and COS, passes on to the C0 2 absorber column. The
C0 2-rich solution from the C0 2 absorber is flashed off in series of flash columns. Figure 6 shows
only one flash column, but typically two to three flashes are used to recover C0 2 at different pressures.
The gas from the first high pressure flash is recycled to recover H2 and CO, which comes off in the
first flash.
[00103] The H2S-rich solution from the sulfur absorber column needs to be further processed to
concentrate the H2S for the Claus process and remove C0 2. This is carried out in the H2S concentrator
column, followed by thermal regeneration in the stripper column. The C0 2 stream from the H2S
concentrator contains small amounts of H2S, and is recycled to the H2S absorber column.
[00104] By comparison, Figure 7 is a schematic view of an example of a decoupled SELEXOL®
process configured for C0 2 scrubbing, which is configured for integration with an upstream WDP,
according to some embodiments. Figure 7 illustrates that C0 2 capture is greatly simplified when
sulfur is captured upstream and only C0 2 is removed by a SELEXOL® process modified as disclosed
herein.
[00105] (c) WDP + activated MDEA.
[00106] Activated MDEA can also be used for C0 2 capture. Activated MDEA uses MDEA as an
aqueous solution which has been activated with some chemicals (example piperazine) to enhance the
C0 2 absorption in the solvent. Activated MDEA can be used for C0 2 capture after the sulfur species
has been removed by the WDP.
[00107] Results from the different cases are tabulated in Table 4.
[00108] 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®).
[00109]
1 includes cost of initial fills
2 Operating 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
[00110] It is seen that a substantial reduction in capital and operating costs is achieved by
decoupling the H2S and CO2 removal from syngas for all three cases.
[00111] During this study it was also found that the H2S enrichment for higher I CO ratios (3:1)
required for SNG and substantially higher for ¾ applications, becomes very difficult with the
conventional RECTISOL® process. Decoupling the sulfur and CO2 removal removes this bottleneck
and allows the use of chilled methanol-based CO2 only wash.
[00112] EXAMPLE 2
[00113] This example illustrates processing and acid gas cleanup of a syngas for ¾ production.
The syngas composition for this example is taken from a Department of Energy study for a solidsfed
gasifier with partial quench using PRB coal (case SIB), and is provided in Table 5 below. A
dual-stage (current state-of-the-art) SELEXOL® process for sulfur and CO2 removal is used in the
DOE example case and the treated syngas is suitable for ¾ 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® process
(for both S and CO2). These numbers are used here to compare against the "WDP + activated MDEA
for CO2" 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.
[00114] TABLE 5 - Inlet syngas composition used in Example 2
[00115] Two different cases are considered for illustration (a) conventional SELEXOL® process
for sulfur and CO2 removal, (b) WDP for sulfur removal and activated MDEA for CO2 removal.
[00116] ASPEN PLUS® process models were developed for the WDP, water gas shift, and sulfur
recovery process. Activated MDEA was modeled using PROMAX® modeling software (Bryan
Research & Engineering, Inc., Bryan, Texas, 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 CO2 removal to reduce the overall capital costs, which is possible only with the decoupling of the
S and CO2 removal. Hence, the water gas shift and the low temperature gas cooling were also
modeled and included in the cost comparison. The SELEXOL® process for S and CO2 capture
produces ¾ S and uses the Claus process for S recovery. The WDP process produces SO2 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® Economic Analyzer. The capital cost accounted for the cost
of the initial fill (catalysts, sorbents, SELEXOL®/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
[00117] The techno-economic analysis clearly shows the economic benefits of integrating the
WDP process with a downstream CO2 capture process according to the present disclosure.
[00118] The above Examples are for illustrative purposes only and do not restrict the invention to
the CO2 capture processes used in the examples. Similar savings are expected from integration of the
WDP with other CO2 capture processes.
[00119] 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.
[00120] 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.

CLAIMS
What is claimed is:
1. 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 gas; and
flowing the desulfurized gas into a CO2 removal unit to remove a substantial fraction of CO2
from the desulfurized gas.
2. The method of claim 1, wherein the feed gas comprises one or more of: carbon monoxide
(CO), carbon dioxide (CO2), hydrogen gas (H2), syngas, shifted syngas, a hydrocarbon (HC), and
natural gas.
3. The method of claim 1, wherein the sulfur compound of the feed gas is selected from the
group consisting of: hydrogen sulfide (H2S), carbonyl sulfide (COS), a disulfide, carbon disulfide
(CS2), a mercaptan, and a combination of two or more of the foregoing.
4. The method of claim 1, wherein flowing the feed gas into the desulfurization unit is done in a
temperature range selected from the group consisting of: about 400 °F or greater; about 400 °F to
about 1100 °F; and about 100 °C to about 900 °C.
5. The method of claim 1, wherein flowing the feed gas into the desulfurization unit is done at a
pressure ranging from about 1 atm to 100 atm.
6. The method of claim 1, wherein flowing the desulfurized gas into the C0 2 removal unit is
done in range selected from the group consisting of: about -80 °F to about 30 °F; about 30 °F to about
130 °F; and about 200 °F to about 900 °F.
7. The method of claim 1, wherein flowing the desulfurized gas into the C0 2 removal unit is
done at a pressure ranging from about 1 atm to about 100 atm.
8. The method of claim 1, wherein at least one of the desulfurization unit and the C0 2 removal
unit comprises a component selected from the group consisting of: a fixed-bed reactor, a movingbed
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.
9. The method of claim 1, wherein flowing the feed gas into the desulfurization unit comprises
flowing the feed gas into contact with a sorbent.
10. The method of claim 9, 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.
11. The method of claim 9, wherein the sorbent comprises a support selected from the group
consisting of: alumina (AI2O3), silicon dioxide (S1O2), titanium dioxide (T1O2), a zeolite, and a
combination of two or more of the foregoing.
12. The method of claim 9, wherein the sorbent is regenerable or non-regenerable.
13. The method of claim 9, wherein the sorbent has an average particle size in a range from about
35 mih to about 175 mih.
14. The method of claim 9, 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.
15. The method of claim 14, 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.
16. The method of claim 15, comprising separating the desulfurized gas from the sulfided sorbent.
17. The method of claim 16, wherein separating the desulfurized gas from the sulfided sorbent
comprises flowing the desulfurized gas and the sulfided sorbent into a solids separator.
18. The method of claim 17, wherein the solids separator is selected from the group consisting of:
a cyclone separator, an electrostatic precipitator, a filter, and a gravity settling chamber.
19. The method of claim 15, 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.
20. The method of claim 19, wherein flowing the sulfided sorbent into the regenerating unit is
done at a temperature of about 900 °F or greater.
21. The method of claim 19, wherein flowing the sulfided sorbent into the regenerating unit is
done at a temperature ranging from about 900 °F to about 1400 °F.
22. The method of claim 19, wherein flowing the sulfided sorbent into the regenerating unit
comprises flowing the sulfided sorbent into contact with a regenerating agent.
23. The method of claim 22, 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.
24. The method of claim 19, comprising separating the regenerated sorbent from the sulfur
compound produced in the regenerating unit.
25. The method of claim 24, 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.
26. The method of claim 1, wherein flowing the desulfurized gas into the C0 2 removal unit
comprises flowing the desulfurized gas into contact with a CO2 removing agent.
27. The method of claim 26, wherein the CO2 removing agent is a solvent-based agent that
removes CO2 by gas absorption and subsequent regeneration.
28. The method of claim 26, wherein the CO2 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-l,l-dioxide), propylene carbonate, and a combination of two
or more of the foregoing.
29. The method of claim 26, wherein the C0 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.
30. The method of claim 26, wherein the CO2 removing agent comprises a mixture of sulfolane
(2,3,4,5-tetrahydrothiophene-l,l-dioxide), water, and one or more of methyldiethanolamine
(MDEA), piperazine, and diisopropanolamine (DIPA).
31. The method of claim 26, wherein the CO2 removing agent comprises a FLEXSORB® PS
formulation or a UCARSOL® LE formulation.
32. The method of claim 26, wherein the CO2 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.
33. The method of claim 26, wherein the CO2 removing agent is regenerable or non-regenerable.
34. The method of claim 26, wherein the CO2 removing agent comprises a membrane effective
for dissolution and diffusion of CO2.
35. The method of claim 26, wherein the CO2 removing agent comprises a liquid-phase agent,
and further comprising flowing the liquid-phase agent into the CO2 removal unit.
36. The method of claim 1, wherein flowing the desulfurized gas into contact with the CO2
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 CO2.
37. The method of claim 36, wherein flowing the desulfurized gas into contact with the C0 2
removing agent produces in the absorber unit a CCh-rich fluid comprising the CO2 removing agent
and CO2, and further comprising:
flowing the CCh-rich fluid from the absorber unit to a regenerator unit;
removing CO2 from the CCh-rich fluid stream in the regenerator unit to produce a CCh-lean
fluid stream; and
flowing the CCh-lean fluid stream into the absorber unit.
38. The method of claim 1, wherein the CO2 removal unit produces a CO2 output stream, and
further comprising outputting the CO2 output stream from the CO2 removal unit and recovering CO2
from the CO2 output stream.
39. The method of claim 1, wherein the CO2 removal unit is effective for removing CO2 without
actively removing sulfur from the desulfurized gas.
40. The method of claim 1, wherein the CO2 removal unit is effective for removing CO2 without
removing a substantial amount of sulfur from the desulfurized gas.
41. The method of claim 1, wherein the desulfurized gas has a sulfur concentration of about 25
parts per million (ppm) by volume or less.
42. The method of claim 1, wherein the desulfurized gas has a sulfur concentration of about 100
parts per billion (ppb) by volume or less.
43. The method of claim 1, comprising flowing the desulfurized gas into the CO2 removal unit
without cryogenically cooling the desulfurized gas via external refrigeration.
44. The method of claim 1, comprising flowing the desulfurized gas into contact with steam in a
water-gas shift unit in the presence of a shift catalyst to produce carbon dioxide (CO2) and hydrogen
gas (H2) .
45. The method of claim 44, comprising flowing the desulfurized gas into contact with steam
before flowing the desulfurized gas into the C0 2 removal unit.
46. The method of claim 1, wherein flowing the desulfurized gas into the CO2 removal unit
produces a treated gas having a CO2 concentration of about 5% by volume or less.
47. A method for removing acid gases from a gas stream, the method comprising:
flowing a feed gas stream comprising carbon monoxide (CO), carbon dioxide (CO2), 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 CO2, 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 CO2 removing agent in a CO2 removal unit to
produce a treated gas comprising CO and substantially reduced fractions of sulfur and CO2.
48. A gas processing system configured for performing the method of any of the preceding claims.
49. 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 CO2 removal unit positioned downstream from the desulfurization unit, and configured for
removing a substantial fraction of CO2 from the desulfurized gas.
50. The gas processing system of claim 49, wherein at least one of the desulfurization unit and
the CO2 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.
51. The gas processing system of claim 49, comprising a water-gas shift unit positioned upstream
or downstream from the desulfurization unit, and configured for shifting the process gas to produce
carbon dioxide (C0 2) and hydrogen gas (H2) .