Patent Application
20160311682
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.
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, HCl, 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.
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.
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.
The H2S, COS, and CO2 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 CO2 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.
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 CO2 in a way that would optimize the removal of both sulfur compounds and CO2, whereby sulfur compounds could be reduced to lower levels in the process gas, and higher levels of purity of the sulfur compounds and CO2 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.
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 CO2 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.
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 CO2 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 CO2 concentrations, and CO2 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+2H2→CH3OH, requires the H2/CO ratio to be 2.
WGS is a moderately exothermic reversible reaction and is expressed by:
CO+H2OCO2+H2, ΔH0298=−41.09 kiloJoules/mole (kJ/mol),
where ΔH0298 is the enthalpy of reaction at 298 kelvin (K).
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.
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.
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 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.
Thus, it would be desirable to be able to decouple the process of removing sulfur compounds from the process of removing CO2 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 CO2, as well as the use of the less expensive sweet shift catalysts.
The water gas shift process uses steam to shift CO to CO2 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, 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.
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.
It would therefore also be desirable to reduce energy costs by reducing the amount of steam required for the carrying out the WGS reaction.
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.
According to one embodiment, a method for producing a water-gas shifted gas comprising CO2 and H2 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 (CO2) and hydrogen (H2); 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 CO2 and H2; 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 CO2 and H2.
According to another embodiment, a water gas shift reaction system is configured to perform any of the methods disclosed herein.
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 (CO2) and hydrogen (H2); 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 CO2 and H2; 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 CO2 and H2.
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 CO2 removal unit to remove a substantial fraction of CO2 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 (CO2) and hydrogen (H2); 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 CO2 and H2; 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 CO2 and H2.
According to another embodiment, a gas processing system is configured to perform any of the methods disclosed herein.
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; 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 (CO2) and hydrogen (H2); 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 CO2 and H2; 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 CO2 and H2.
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.
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.
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 (O2), carbon dioxide (CO2), 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 (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.
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.
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.
As used herein, the term “process gas” generally refers to any gas initially containing one or more sulfur compounds and CO2. 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).
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.
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 CO2 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.
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.
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.
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.
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.
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 μm to about 175 μm. 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.
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.
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 (ZnAl2O4) phase. More generally, the sorbent may include a support such as, for example, alumina (Al2O3), silicon dioxide (SiO2), titanium dioxide (TiO2), a zeolite, or a combination of two or more of the foregoing.
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:
MO+H2S→MS+H2O, and
MO+COS→MS+CO2,
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).
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:
MS+(3/2)O2→MO+SO2.
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.
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.
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.
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.
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.
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.
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.
As described above, the acid gas removal method includes flowing the desulfurized gas to a CO2 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 sub-ambient 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.
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), N-methyl-2-pyrrolidone (NMP), sulfolane (2,3,4,5-tetrahydrothiophene-1,1-dioxide), propylene carbonate (C4H6O3), and a combination of two or more of the foregoing.
In other embodiments, the CO2 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™ FS process solvent (UOP A Honeywell Company, Des Plaines, Ill., 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.
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, Tex., USA), and UCARSOL® LE solvent (Union Carbide Corporation, Danbury, Conn., 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-1,1-dioxide), water, and one or more of methyldiethanolamine (MDEA), piperazine (C4H10N2), and diisopropanolamine (DIPA).
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, 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.
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.
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 CO2-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 CO2-rich fluid stream containing the CO2 removing agent and captured CO2. A liquid-based CO2 removing agent, or a particulate-based 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 CO2-rich fluid stream produced in the absorber unit via a transfer line, an outlet for outputting the CO2 removed from the CO2-rich fluid stream as a CO2 output stream, and another outlet for returning the CO2-lean fluid back to the absorber unit via a transfer line. The mechanism for regenerating the CO2 removing agent (converting the CO2-rich fluid into the CO2-lean fluid) may depend on the type of CO2 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 CO2 for regeneration of the CO2 removing agent.
In some embodiments, the treated gas outputted from the CO2 removal unit has a CO2 concentration of about 5% by volume or less.
The method may further include processing the CO2 output stream from the regenerator unit by any suitable technique for recovering CO2 from the CO2 output stream. The recovered CO2 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.
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 CO2 removal unit need not also be effective for removing sulfur species. Hence, the presently disclosed acid gas removal method enables the CO2 removal process to be optimized for CO2 removal without regard for sulfur removal. In some embodiments, the CO2 removal unit or process may be characterized as being effective for removing CO2 without actively removing sulfur, or without removing a substantial amount of sulfur. In some other embodiments, the CO2 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 CO2 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 CO2 removal could not. In all embodiments, the goal of optimized sulfur and CO2 removal would be the production of a treated gas and byproduct streams (sulfur compounds and CO2) that eliminate or substantially reduce the number or complexity of subsequent cleaning processing requirements.
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+H2OCO2+H2, ΔH0298=−41.09 kiloJoules/mole (kJ/mol),
where ΔH0298 is the enthalpy of reaction at 298 kelvin (K).
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.
The water gas shift process uses steam to shift CO to CO2 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.
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 CO2 removal process, facilitates carrying out a sweet shift reaction downstream of the desulfurization process, for example between the sulfur removal process and the CO2 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 CO2 removal unit. In this case, the desulfurized gas is flowed into contact with steam in the presence of a shift catalyst to produce CO2 and H2, and subsequently is subjected to the CO2 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 CO2 in the process gas outputted from the WGS unit may then be adequately removed by the downstream CO2 removal unit.
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 CO2 from the process gas, optionally recovering the CO2, and optionally removing one or more other types of contaminants from the process gas, respectively. The desulfurization system 108 and CO2 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.
In the illustrated embodiment, and as described above, the desulfurization system 108 and the CO2 removal system 140 are integrated, yet distinct, systems utilizing separate units for desulfurization and CO2 removal, with the CO2 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 CO2), and the CO2 removal system 140 may be configured for primarily or exclusively removing CO2 from the process gas (as opposed to other compounds such as sulfur compounds).
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 CO2 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 H2/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 CO2 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 CO2 may then be recovered by the CO2 recovery system 144 to provide the CO2 for further use or processing. In some embodiments, the process gas is then routed from the CO2 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 CO2. 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.
The particular embodiment of the gas processing system 100 illustrated in
In the following Examples, process flow models were developed using ASPEN PLUS® 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 CO2 capture technologies disclosed herein. These studies utilized a consistent design basis, thereby allowing for a direct comparison of the costs.
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.
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.
(a) WDP+Modified RECTISOL® Process for CO2 Capture
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, CO2 product gas and tail gas. In the absorber section, raw syngas is washed with chilled methanol to reduce CO2, 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 CO2. The last bit of CO2 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 CO2 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.
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, CO2 product, tail gas and H2S enriched gas are estimated using an ASPEN PLUS® process model and are given in Table 2 below.
The selective removal of CO2 and H2S while simultaneously 1) enriching H2S-rich stream, 2) maintaining H2S specs in the tail gas and the CO2 product, and 3) keeping the percent CO2 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 CO2 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.
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.
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 CO2 recirculation compressor from the Claus unit. In the refrigeration plant, the compressors alone contribute to the entire power consumption.
By comparison, decoupling the CO2 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 CO2 capture technologies in accordance with the present disclosure.
As shown in
(b) WDP+Modified SELEXOL® Process for CO2 Removal
The main complexity in the selective removal of H2S and CO2 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 CO2, with the solubility of COS in between those of H2S and CO2. Relative solubilities of H2S and COS (relative to CO2) in the SELEXOL® solvent are as follows.
When COS is absent, the desulfurization solvent flow-rate is set for essentially complete H2S removal and only a small fraction of the CO2 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 CO2 absorbed, resulting in an increase in equipment cost and utility requirements. The co-absorption of CO2 is also increased by the higher solvent flow-rate.
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.
The H2S-rich solution from the sulfur absorber column needs to be further processed to concentrate the H2S for the Claus process and remove CO2. This is carried out in the H2S concentrator column, followed by thermal regeneration in the stripper column. The CO2 stream from the H2S concentrator contains small amounts of H2S, and is recycled to the H2S absorber column.
By comparison,
(c) WDP+Activated MDEA.
Activated MDEA can also be used for CO2 capture. Activated MDEA uses MDEA as an aqueous solution which has been activated with some chemicals (example piperazine) to enhance the CO2 absorption in the solvent. Activated MDEA can be used for CO2 capture after the sulfur species has been removed by the WDP.
Results from the different cases are tabulated in Table 4.
1includes cost of initial fills
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
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.
During this study it was also found that the H2S enrichment for higher H2:CO ratios (3:1) required for SNG and substantially higher for H2 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.
This example illustrates processing and acid gas cleanup of a syngas for H2 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® process for sulfur and CO2 removal is used in the DOE example case and the treated syngas is suitable for H2 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.
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.
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, 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 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 H2S 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
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.
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.
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 H2) and for production of chemicals. The WGS process may be carried out on any feed gas that includes CO, one example being syngas.
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.
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.
No specific limitation is placed on the number of shift reactors utilized in series. In a typical embodiment, as described below in conjunction with
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° 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° 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.
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.
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.
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 CO2 and producing H2 gas as described above. Consequently, the first shift reactor 804 outputs a first product gas stream 836 that includes CO2, H2, 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.
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 CO2, H2, 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 CO2, H2, residual steam, and some amount of un-shifted CO.
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 CO2, H2, 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 CO2, H2, residual steam, and some amount of un-shifted CO.
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), CO2 capture/removal, sulfur removal, removal of other contaminants, an end use for the as-produced H2 and/or CO2, 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 CO2.
In some embodiments, the H2/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 H2, 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.
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.
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.
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.
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.
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.
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 H2/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.
The gas processing system 100 described above and illustrated in
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 CO2. Four different cases were considered:
(a) Traditional sour gas shift (SGS) using two reactors in series.
(b) Sour WGS using three reactors as disclosed herein and as illustrated in
(c) Traditional sweet gas shift using two reactors in series.
(d) Sweet WGS using three reactors as disclosed herein and as illustrated in
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.
Syngas inlet temperature for the sour gas shift (SGS) was kept at 550° F., while the inlet temperature for the sweet gas shift (or high temperature shift (HTS)) was fixed at 600° F. Steam was added to the first shift reactor to control the reactor outlet temperature under 900° 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° F. This approach reduced the steam consumption and generated the needed steam in situ.
The four different cases outlined above were simulated using ASPEN PLUS® 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.
The results from the four different cases are provided in Table 8 below.
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.
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 provided in accordance with the presently disclosed subject matter include, but are not limited to, the following:
1. A method for producing a water-gas shifted gas comprising CO2 and H2, 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 (CO2) and hydrogen (H2); 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 CO2 and H2; 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 CO2 and H2.
2. The method of embodiment 1, comprising adding water as a spray into the first feed gas stream or the first input gas stream.
3. The method of embodiment 1, wherein the feed gas comprises syngas.
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.
5. The method of embodiment 4, comprising removing at least part of the sulfur compound from the third product gas stream.
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.
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.
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° F.
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° F.
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° F.
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.
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.
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.
14. The method of embodiment 12, wherein the liquid water is boiler feed water.
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.
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.
17. The method of embodiment 16, wherein the liquid water is boiler feed water.
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 H2/CO ratio.
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.
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.
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.
22. A water gas shift reaction system configured to perform the method of any of the preceding embodiments.
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 (CO2) and hydrogen (H2); 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 CO2 and H2; 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 CO2 and H2.
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.
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 CO2 removal unit to remove a substantial fraction of CO2 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 (CO2) and hydrogen (H2); 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 CO2 and H2; 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 CO2 and H2.
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.
27. The method of embodiment 25, comprising adding water as a spray into the first feed gas stream or the first input gas stream.
28. The method of embodiment 25, 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.
29. The method of embodiment 25, 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.
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° F. or greater; about 400° F. to about 1200° F.
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.
32. The method of embodiment 25, wherein flowing the desulfurized gas into the CO2 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.
33. The method of embodiment 25, wherein flowing the desulfurized gas into the CO2 removal unit is done at a pressure ranging from about 1 atm to about 100 atm.
34. The method of embodiment 25, 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.
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.
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.
37. The method of embodiment 35, wherein the sorbent comprises a support selected from the group consisting of: alumina (Al2O3), silicon dioxide (SiO2), titanium dioxide (TiO2), a zeolite, and a combination of two or more of the foregoing.
38. The method of embodiment 35, wherein the sorbent is regenerable or non-regenerable.
39. The method of embodiment 35, wherein the sorbent has an average particle size in a range from about 35 μm to about 175 μm.
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.
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.
42. The method of embodiment 41, comprising separating the desulfurized gas from the sulfided sorbent.
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.
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.
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.
46. The method of embodiment 45, wherein flowing the sulfided sorbent into the regenerating unit is done at a temperature of about 900° F. or greater.
47. The method of embodiment 45, wherein flowing the sulfided sorbent into the regenerating unit is done at a temperature ranging from about 900° F. to about 1400° F.
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.
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.
50. The method of embodiment 45, comprising separating the regenerated sorbent from the sulfur compound produced in the regenerating unit.
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.
52. The method of embodiment 25, wherein flowing the desulfurized gas into the CO2 removal unit comprises flowing the desulfurized gas into contact with a CO2 removing agent.
53. The method of embodiment 52, wherein the CO2 removing agent is a solvent-based agent that removes CO2 by gas absorption and subsequent regeneration.
54. The method of embodiment 52, 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-1,1-dioxide), propylene carbonate, and a combination of two or more of the foregoing.
55. The method of embodiment 52, wherein the CO2 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.
56. The method of embodiment 52, wherein the CO2 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).
57. The method of embodiment 52, wherein the CO2 removing agent comprises a FLEXSORB® PS formulation or a UCARSOL® LE formulation.
58. The method of embodiment 52, 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.
59. The method of embodiment 52, wherein the CO2 removing agent is regenerable or non-regenerable.
60. The method of embodiment 52, wherein the CO2 removing agent comprises a membrane effective for dissolution and diffusion of CO2.
61. The method of embodiment 52, wherein the CO2 removing agent comprises a liquid-phase agent, and further comprising flowing the liquid-phase agent into the CO2 removal unit.
62. The method of embodiment 25, 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.
63. The method of embodiment 62, wherein flowing the desulfurized gas into contact with the CO2 removing agent produces in the absorber unit a CO2-rich fluid comprising the CO2 removing agent and CO2, and further comprising: flowing the CO2-rich fluid from the absorber unit to a regenerator unit; removing CO2 from the CO2-rich fluid stream in the regenerator unit to produce a CO2-lean fluid stream; and flowing the CO2-lean fluid stream into the absorber unit.
64. The method of embodiment 25, 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.
65. The method of embodiment 25, wherein the CO2 removal unit is effective for removing CO2 without actively removing sulfur from the desulfurized gas.
66. The method of embodiment 25, wherein the CO2 removal unit is effective for removing CO2 without removing a substantial amount of sulfur from the desulfurized gas.
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.
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.
69. The method of embodiment 25, comprising flowing the desulfurized gas into the CO2 removal unit without cryogenically cooling the desulfurized gas via external refrigeration.
70. The method of embodiment 25, 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.
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 (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.
72. A gas processing system configured for performing the method of any of the preceding embodiments.
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 CO2 removal unit positioned downstream from the desulfurization unit, and configured for removing a substantial fraction of CO2 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 (CO2) and hydrogen (H2); 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 CO2 and H2; 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 CO2 and H2.
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.
75. The gas processing system of embodiment 73, comprising a sprayer configured for adding water as a spray into the first input gas stream.
76. The gas processing system of embodiment 73, 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.
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.
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.
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.
| Number | Date | Country | |
|---|---|---|---|
| 62068333 | Oct 2014 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | PCT/US2015/056391 | Oct 2015 | US |
| Child | 15135984 | US |
