Process for cleaning off-gas from carbon black production and system and facility therefor

Abstract

A process of cleaning a gas stream is described. The gas stream may include a tail gas generated during the production of the carbon black. The process includes a plurality of steps to systematically clean the starting gas stream to obtain a treated gas stream of fuel value and to convert other portions of the gas stream to sulfur and carbon dioxide for recovery. Further described is an installation or system having various operating units for carrying out the process of the invention.

Description

Background Art

[0001] The present invention relates to the cleaning of gas streams, such as industrial gas streams. More specifically, the present invention relates to processes for cleaning gas streams that are derived in part or in whole from carbon black production. The present invention further relates to facilities and / or apparatus set-ups and / or systems for cleaning such gas streams. In addition, the present invention relates to processes for removing components such as sulfur and carbon dioxide from tail gases generated during carbon black production.

[0002] There is an increasing demand and effort in the cleaning of industrial gas streams, and this demand exists in parallel with carbon black production. In addition, for the cleaning of gas streams, there is also a need to reuse parts of the gas stream and thereby reduce the amount of gas discharged into the environment, and to do so in a more energy-efficient manner.

[0003] In a typical furnace carbon black production process, the carbon black yield (defined as the fraction of the raw material converted into the CB product) ranges from 35-65%, depending on the raw material quality and target form (Compilation of Air Pollutant Emission Factors, AP-42, Vol. 1, Section 6.1.1.1, US Environmental Protection Agency, Fifth Edition, 1995), and can be even higher, depending on carbon black and process conditions. As the additional carbon from the primary burner fuel (natural gas or oil) is converted into CO2, all the carbon from the fuel and raw materials will eventually be in the stream of the primary by-product (tail gas). When the tail gas is used as a fuel for a process heater or is processed by a thermal oxidizer to generate heat, the carbon species in the tail gas are converted into CO2 (a greenhouse gas). The sulfur species in the tail gas are burned to form SO x (such as SO2 and SO3).

[0004] Improvements in manufacturing continue to require SO x Emission reduction and CO2 capture. Typically, SO is controlled after tail gas combustion. x and carbon dioxide. However, it is desirable to control SO x vents and captures CO2 directly from the tail gas to reduce costs and cut water use and waste generation associated with these processes.

[0005] All patents and publications mentioned throughout are incorporated herein by reference in their entirety. Summary of the invention

[0006] A feature of the present invention is a process for providing a clean gas stream, such as an industrial gas stream, including but not limited to a gas stream derived partially or completely from tail gas generated during the production of carbon black.

[0007] A further feature of the present invention is to provide near zero SO x A process for substantially removing sulfur from a gas stream at the point of emission.

[0008] It is yet a further feature of the present invention to provide a process for substantially capturing or removing carbon dioxide from a gas stream and preferably having near zero emissions of carbon dioxide.

[0009] Additionally, it is a feature of the invention to provide a process and apparatus for cleaning tail gas wherein the resulting gas volume is smaller (e.g., 30% to 50% smaller) than if the tail gas had been combusted to produce flue gas, which allows for a reduction in the size of equipment used for such treatment.

[0010] Another feature of the present invention is to provide a process and facility (or system or apparatus) for cleaning tail gas that can allow for reduced operating costs compared to tail gas combustion.

[0011] Another feature of the present invention is to provide a process and facility for cleaning tail gas that does not increase process water consumption compared to a process in which the tail gas is burned and the resulting flue gas is cleaned.

[0012] Yet another feature of the present invention allows condensate (eg, quench fluid) from tail gas cooling to be reused in carbon black production.

[0013] To achieve these and other advantages, and in accordance with the purposes of the present invention, as embodied and broadly described herein, the present invention relates in part to a process for cleaning a gas stream, such as a gas stream from an industrial process. More specifically, the process for cleaning a gas stream preferably includes tail gas generated during carbon black production. The process comprises the steps of compressing the gas stream to obtain a compressed gas stream, and subjecting the gas stream to several reactions. These reactions include, but are not limited to, at least one hydrolysis reaction to obtain at least H2S, at least one hydrogenation reaction to convert at least one of SO2 and SO3 into H2S, and at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining an O2-depleted gas stream. The at least one oxygen conversion reaction comprises a further hydrogenation reaction to convert O2 into H2O or a reduction reaction to convert carbon monoxide into carbon dioxide, or both.

[0014] The process further comprises subjecting the O2-depleted gas stream to at least one water gas shift reaction to obtain at least CO2 and thereby obtain a conditioned syngas stream. The process also comprises removing at least a portion of H2S and CO2 from the conditioned syngas stream to obtain an acid gas stream containing H2S and CO2 and obtain a treated gas stream having fuel value. In addition, the process comprises converting at least a portion of the H2S in the acid gas stream into elemental sulfur and removing the elemental sulfur and obtaining a sulfur removal off gas; and capturing at least a portion of the CO2 in the sulfur removal off gas.

[0015] Prior to carrying out the at least one hydrolysis reaction, the at least one hydrogenation reaction and the at least one water-gas shift reaction, the process may further include removing at least a portion of any particulate matter and any catalyst poisons from the gas stream or the compressed gas stream. Removing at least a portion of any particulate matter and any catalyst poisons from the gas stream or the compressed gas stream may include passing the gas stream or the compressed gas stream through at least one filter bed and through at least one adsorbent. At least one water-gas shift reaction may occur after the at least hydrolysis reaction and after the at least hydrogenation reaction. The gas stream may be composed of the tail gas produced during carbon black production, and / or, may come from two or more carbon black production units. Alternatively, or in addition, the gas stream may further contain a gaseous fuel from a non-carbon black production source. In any of these embodiments, at least 80% by volume of the gas stream may be CO, CO2, N2, O2, H2, hydrocarbons and water, and may also contain trace amounts of sulfur species and nitrogen species, as well as optional HCl and PH3 and optional particulate matter. For example, at least 80% by volume of the gas stream may be CO, CO2, N2, O2, H2, hydrocarbons, and water, and also include trace amounts of sulfur species and nitrogen species, and optionally one or more of HCl, and PH3 and particulates.

[0016] In any of these embodiments, the gas stream may include the following component concentrations:

[0017] 3-30% by volume of CO,

[0018] 0.5-10% by volume of CO2,

[0019] 3-50% by volume of H2,

[0020] 0.01-2 volume % O2,

[0021] 0.5-10% by volume of hydrocarbons,

[0022] 1-50% by volume of water,

[0023] 50ppm to 10,000ppm sulfur substances by volume,

[0024] 50ppm to 20,000ppm of nitrogen substances,

[0025] 0 to 20 ppm by volume of HCl,

[0026] 0 to 10 ppm by volume of PH3, and

[0027] 0mg / Nm 3 Up to 80mg / Nm 3 of granular matter.

[0028] Alternatively, or in addition, compression may utilize at least one compressor. In any of these embodiments, the at least one hydrolysis reaction may be achieved by utilizing at least one hydrolysis catalyst, and / or, the at least one hydrogenation reaction may be achieved by utilizing at least one hydrogenation catalyst, and / or, the at least one gas shift reaction may be achieved by utilizing at least one sulfur-resistant catalyst that converts CO and H2O into CO2 and H2. In any of these embodiments, the at least one gas shift reaction may be performed in the presence of at least one cooling device to control the temperature during the gas shift reaction, and / or, removing at least a portion of the H2S and CO2 from the conditioned synthesis gas stream may be achieved by utilizing an amine scrubber, acid gas absorption with a non-amine solvent, or pressure swing adsorption, and / or, converting at least a portion of the H2S in the acid gas stream into elemental sulfur may be achieved by utilizing a liquid phase catalytic oxidation process or a gas phase combustion process. The gas phase combustion process may utilize a Claus process that converts H2S and SO2 into H2O and S2.

[0029] In any of these embodiments, the gas stream and / or compressed gas stream may be cooled during and / or immediately after said compression, and / or, removing at least a portion of any particulate matter and any catalyst poisons from said gas stream or said compressed gas stream may provide said gas stream or compressed gas stream having less than 5 ppm by volume HCl and less than 5 ppm by volume PH3. In any of these embodiments, the process may further include subjecting the compressed gas stream or conditioned synthesis gas stream to at least one reduction reaction to convert at least a portion of the nitrogen-containing species into N2.

[0030] In any of these embodiments, the at least one hydrolysis reaction may convert sulfur species in the compressed gas stream into H2S, and the sulfur species may include CS2, COS, and organic sulfur, and / or further convert HCN into NH3, and or the at least one hydrogenation reaction may convert SO2 and SO3 into H2S, and convert O2 into H2O or CO2 or both.

[0031] The present invention further relates to a facility (or system) for cleaning a gas stream, the gas stream comprising tail gas produced during the production of carbon black. The facility comprises: at least one compressor for compressing the gas stream to obtain a compressed gas stream; a first catalytic converter unit, the first catalytic converter unit comprising one or more fixed bed reactors, the fixed bed reactor being configured to perform at least one hydrolysis reaction to obtain at least H2S and at least one hydrogenation reaction to obtain at least H2S, and at least one oxygen conversion reaction to remove O2 and obtain an O2-depleted gas stream, and the facility further comprises a further catalytic converter unit, the further catalytic converter unit comprising one or more fixed bed reactors (preferably in the first catalytic converter unit) downstream), the fixed bed reactor being configured to perform at least one water gas shift reaction on the compressed gas stream to obtain CO2 and obtain a regulated synthesis gas stream; an acid gas capture unit, which is used to remove at least a portion of H2S and CO2 from the regulated synthesis gas stream to obtain an acid gas stream containing H2S and CO2 and obtain a treated gas stream with fuel value; a sulfur conversion unit, which is used to convert at least a portion of the H2S in the acid gas stream into elemental sulfur and remove the elemental sulfur and obtain a sulfur-removed exhaust gas; and a CO2 capture unit, which is used to capture at least a portion of the CO2 in the sulfur-removed exhaust gas.

[0032] The facility may further comprise a gas conditioning unit for removing particulates and catalyst poisons from the gas stream or compressed gas stream, and / or the fixed bed reactor may be or contain at least one hydrogenation catalyst, at least one hydrolysis catalyst and at least one sulfur tolerant catalyst.

[0033] Alternatively, or in addition, the facility may be characterized by one or more of the following features: The facility may further include at least one cooling device for controlling the temperature of the gas stream passing through the catalytic converter unit or leaving the catalytic converter unit or both. The gas conditioning unit may be or include at least one filter bed and at least one adsorbent, wherein the at least one filter bed and the at least one adsorbent are located in the same container or in different containers. The acid gas capture unit may be or include an amine scrubber, an acid gas absorption unit with a non-amine solvent, or a pressure swing adsorption unit. The facility may further include at least one cooling device for controlling the temperature of the gas stream leaving the at least one compressor.

[0034] It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are intended to provide further explanation of the invention as claimed.

[0035] The accompanying drawings, which are incorporated in and constitute a part of this application, illustrate various features of the present invention and, together with the description, serve to explain the principles of the present invention. BRIEF DESCRIPTION OF THE DRAWINGS

[0036] Figure 1 is a flow chart of an exhaust gas purification process according to an exemplary embodiment of the present invention.

[0037] Figure 2 is a block diagram of an exhaust gas purification system or facility according to an exemplary embodiment of the present invention.

[0038] Figure 3A and 3B Another block diagram of an exhaust gas purification system or plant according to a further exemplary embodiment of the present invention is shown together. DETAILED DESCRIPTION

[0039] The present invention relates to a process and an apparatus for cleaning a gas stream, such as an industrial gas stream. The gas stream may include and preferably includes tail gas generated during the production of carbon black.

[0040] The general steps or aspects of the process of the present invention are as follows.

[0041] In the process of the present invention, the process comprises or includes compressing a gas stream (eg, an industrial gas stream, such as tail gas) to obtain a compressed gas stream.

[0042] The process further includes performing a number of reactions on the gas stream or compressed gas stream.

[0043] The several reactions include but are not limited to the following:

[0044] performing at least one hydrolysis reaction to obtain at least H2S;

[0045] performing at least one hydrogenation reaction to convert at least one of SO2 and SO3 (or both) into H2S; and

[0046] At least one oxygen conversion reaction is performed to remove O2 from the compressed gas stream to obtain an O2-depleted gas stream, wherein the at least one oxygen conversion reaction comprises, consists of, or includes: a further hydrogenation reaction to convert O2 into H2O, or comprises a reaction with carbon monoxide to convert carbon monoxide into carbon dioxide, or both reactions.

[0047] The process then further comprises subjecting the O2-depleted gas stream to at least one water gas shift reaction to obtain at least CO2, and thereby obtain a conditioned synthesis gas stream.

[0048] The process further includes removing at least a portion of the H2S and CO2 from the conditioned synthesis gas stream to obtain an acid gas stream containing H2S and CO2, and to obtain a treated gas stream having fuel value or utility as a feedstock for chemical production, H2 production, etc.

[0049] The process then includes converting at least a portion of the H 2 S in the acid gas stream into elemental sulfur and removing the elemental sulfur and obtaining a sulfur-removed off-gas; and capturing at least a portion of the CO 2 in the sulfur-removed off-gas.

[0050] Further details of this process are described below.

[0051] With regard to the gas stream treated or cleaned by the present invention, as indicated, the gas stream can be an industrial gas stream. The industrial gas stream can be or include tail gas from one or more sources. For example, the gas stream can include or come entirely from or only from tail gas generated during carbon black production.

[0052] The gas stream may include or come entirely from or only from one, two or more carbon black production units (e.g., two or more carbon black reactors). There is no restriction on the number of carbon black production units that may contribute to the gas stream processed by the present invention. The carbon black production unit may be a furnace black production unit, a plasma carbon black production unit and / or other types of carbon black production units. The carbon black production unit may be from a unit that manufactures the same, similar or different grades of carbon black.

[0053] As an option, the gas stream treated by the present invention can further include a gaseous fuel from a non-carbon black production source. For example, the gas stream can include a gas stream or gaseous fuel from one or more of the following sources as an option: biomass, natural gas, liquefied petroleum gas (LPG) such as from an oil field, coal gas such as from a coking process, by-product gas such as from a steelmaking furnace, and / or other sources as exemplified herein or similar sources.

[0054] As an example, the gas stream (i.e., the starting gas stream) can contain at least 25 volume %, at least 50 volume %, at least 75 volume %, at least 80 volume %, at least 90 volume %, at least 95 volume %, at least 99 volume %, or 100 volume % of a gas stream or tail gas from one or more carbon black production units.

[0055] The gas stream treated by the present invention can be a gas stream in which at least 80 volume % (e.g., at least 85 volume %, at least 90 volume %, at least 95 volume %, at least 99 volume %, for example, 80 volume % to 99 volume % or 85 volume % to 99 volume %) of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons and water, and also contains trace amounts of sulfur species and nitrogen species, and optionally HCl and PH3 and optionally particulate matter.

[0056] The gas stream treated by the present invention may be a gas stream wherein at least 80 volume % (e.g., at least 85 volume %, at least 90 volume %, at least 95 volume %, at least 99 volume %, e.g., 80 volume % to 99 volume % or 85 volume % to 99 volume %) of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons and water, and also contains trace amounts of sulfur species and nitrogen species, and may contain one or more of HCl, PH3 and particulate matter.

[0057] For example, the particulate matter (e.g., solid particulate matter) can be carbon particulate matter and / or inorganic particulate matter of salts (e.g., metal salts (e.g., salts containing Fe, Si, Al, Ca, Cu and / or Zn in the form of corresponding carbonates, sulfates and / or oxides and / or other types of compounds)).

[0058] Sulfur species may include, but are not limited to, H2S, COS, CS2, SO2, SO3 and / or C4H4S, etc.

[0059] Nitrogen species may include, but are not limited to, HCN, NH3, NO and / or NO2, etc.

[0060] As a further example, the gas stream may include the following component concentrations:

[0061] 3-30 vol% or more CO (e.g., 3-25 vol%, 3-20 vol%, 3-15 vol%, 3-10 vol%, 3-5 vol%, 5-30 vol%, 10-30 vol%, 15-30 vol%, 20-30 vol%),

[0062] 0.5-10 vol% or more CO2 (e.g., 0.5-7 vol%, 0.5-5 vol%, 0.5-2 vol%, 1-10 vol%, 2-10 vol%, 3-10 vol%, 5-10 vol%),

[0063] 3-50 vol% or more H2 (3-45 vol%, 3-40 vol%, 3-35 vol%, 3-30 vol%, 3-25 vol%, 3-20 vol%, 3-15 vol%, 3-10 vol%, 3-5 vol%, 5-50 vol%, 10-50 vol%, 15-50 vol%, 20-50 vol%, 25-50 vol%, 30-50 vol%, 35-50 vol%, 40-50 vol%),

[0064] 0.01-2 vol% or more O2 (e.g., 0.01-1.5 vol%, 0.01-1 vol%, 0.01-0.5 vol%, 0.01-0.1 vol%, 0.01-0.05 vol%, 0.02-2 vol%, 0.05-2 vol%, 0.07-2 vol%, 0.1-2 vol%, 0.5-2 vol%, 0.7-2 vol%, 1-2 vol%, 1.25-2 vol%);

[0065] 0.5-10 vol% or more hydrocarbons (e.g., 0.5-7 vol%, 0.5-5 vol%, 0.5-3 vol%, 0.5-1 vol%, 0.7-10 vol%, 1-10 vol%, 2-10 vol%, 5-10 vol%, 7-10 vol%),

[0066] 1-50 vol% or more water (e.g., 1-45 vol%, 1-40 vol%, 1-35 vol%, 1-30 vol%, 1-25 vol%, 1-20 vol%, 1-15 vol%, 1-10 vol%, 1-5 vol%, 2-50 vol%, 5-50 vol%, 10-50 vol%, 15-50 vol%, 20-50 vol%, 25-50 vol%, 30-50 vol%, 35-50 vol%, 40-50 vol%),

[0067] 50 ppm by volume to 10,000 ppm by volume or more of sulfur species (e.g., 50-7,000 ppm, 50-5,000 ppm, 50-2,500 ppm, 50-2,000 ppm, 50-1,500 ppm, 50-1,000 ppm, 50-750 ppm, 50-500 ppm, 50-250 ppm, 50-100 ppm, 100-10,000 ppm, 200-10,000 ppm, 500 ppm-10,000 ppm, 1,000-10,000 ppm, 2,000-10,000 ppm, 3,000-10,000 ppm, 5,000-10,000 ppm, 7,000-10,000 ppm),

[0068] 50 ppm by volume to 20,000 ppm by volume or more of nitrogen species (e.g., 50-15,000 ppm, 50-12,500 ppm, 50-10,000 ppm, 50-7,000 ppm, 50-5,000 ppm, 50-2,500 ppm, 50-2,000 ppm, 50-1,500 ppm, 50-1,000 ppm, 50-750 ppm, 50-500 ppm, 50-250 ppm, 50-100 ppm, 100-20, 000ppm, 200-20,000ppm, 500ppm-20,000ppm, 1,000-20,000ppm, 2,000-20,000ppm, 3,000-20,000ppm, 5,000-2 0,000ppm, 7,000-20,000ppm, 10,000-20,000ppm, 12,500-20,000ppm, 15,000-20,000ppm, 17,500-20,000ppm),

[0069] 0-20 ppm by volume or more of HCl (e.g., 0.1-20 ppm, 0.5-20 ppm, 1-20 ppm, 5-20 ppm, 10-20 ppm, 0.1-15 ppm, 0.1-10 ppm, 0.1-5 ppm, 0.1-2.5 ppm),

[0070] 0-10 ppm by volume or more of PH3 (e.g., 0.1-10 ppm, 0.5-10 ppm, 1-10 ppm, 5-10 ppm, 0.1-7 ppm, 0.1-5 ppm, 0.1-2 ppm, 0.1-1 ppm), and

[0071] 0mg / Nm 3 -80mg / Nm 3 or more particles (e.g., 0.1-80 mg / Nm 3 , 0.5-80mg / Nm 3 、1-80mg / Nm 3 、5-80mg / Nm 3 、10-80mg / Nm 3 、15-80mg / Nm 3 、20-80mg / Nm 3 、30-80mg / Nm 3 、40-80mg / Nm 3 、50-80mg / Nm 3 、60-80mg / Nm 3 、70-80mg / Nm 3、0.1-75mg / Nm 3 、0.1-70mg / Nm 3 , 0.1-60mg / Nm 3 、0.1-50mg / Nm 3 , 0.1-40mg / Nm 3 , 0.1-30mg / Nm 3 , 0.1-20mg / Nm 3 , 0.1-10mg / Nm 3 , 0.1-5mg / Nm 3 ).

[0072] The gas condition of the gas stream being treated is not critical. For any given unit process, if the incoming gas stream does not have the desired temperature or pressure, these temperatures or pressures are easily adjusted using methods known to those skilled in the art. For example, the gas in the gas stream to be treated can have a temperature from ambient temperature (e.g., 20° C.-25° C.) to 300° C. or other temperatures. Similarly, the pressure of the gas stream to be treated can be 0 bar gauge (barg)-1 bar gauge or other pressures outside this range.

[0073] Regarding the step in the process of compressing the gas stream, this step may be achieved using at least one compressor. More than one compressor may be used, and / or the compressor may have multiple stages (multi-stage compression).

[0074] Gas compression can be achieved using any commercially available compression equipment, such as but not limited to centrifugal compressors, Roots compressors, screw compressors, positive displacement compressors, etc. Gas compression can be such that the gas is pressurized, such as by a booster blower or compressor.

[0075] One purpose of compressing a gas stream is to provide the gas with a desired pressure in order to overcome possible pressure drops in downstream steps of the process.

[0076] The compression of the gas stream produces a compressed gas stream. The compressed gas stream has an elevated pressure above atmospheric pressure or a gas pressure above the initial gas pressure entering the compressor. The elevated pressure may be 0.5-100 barg or greater, such as 0.5-50 barg, 0.5-45 barg, 0.5-40 barg, 0.5-35 barg, 0.5-30 barg, 0.5-25 barg, 0.5-20 barg, 0.5-15 barg, 0.5-10 barg, 0.5-5 barg, 1-90 barg, 5-80 barg, 10-70 barg, 15-60 barg, 20-50 barg, 25-50 barg, 30-50 barg, 35-50 barg, 40-50 barg).

[0077] As an option, the gas stream (i.e., feed gas) entering the compression step may be partially cooled at the inlet of the compressor or between multiple compressors (if used) and / or after the last compression stage. As a result of the cooling, the compressed gas leaving the one or more compressors may have a temperature of less than 500° C., such as 100° C. to 500° C. or other temperatures.

[0078] As an option, the gas stream or compressed gas stream may be subjected to filtering of particulate matter that may be present in the gas stream. In this step, the gas stream or compressed gas stream has at least a portion of the particulate matter present in the gas stream removed, for example, by filtering (using, for example, one or more filter beds, filter beds or other forms of mechanical filtering mechanisms (such as, but not limited to, cartridge filters, bag filters, membrane filters, etc.)).

[0079] In addition to removing some or most or all of the particulate matter (i.e., solid particulate matter) in the gas stream, at least a portion (some or most or all) of any catalyst poisons that may be present may be captured or removed at this stage of the process (e.g., catalyst poison capture). Thus, the filtering step may further remove at least a portion (some or most or all) of one or more catalyst poisons. Examples of catalyst poisons that may be present in the gas stream include, but are not limited to, HCl and / or PH3. Typically, catalyst poisons are present in trace amounts (e.g., in amounts as described above).

[0080] By performing such filtration steps and / or catalyst poison capture (which may be collectively referred to as gas conditioning or gas conditioning unit operations), this may enable the catalytic process to operate more stably on the gas stream and / or enable the catalytic process to operate more efficiently and / or extend catalyst service life.

[0081] To filter the particulates, one or more filter beds containing filter media (which may be in the form of particulates) may be used. The filter particulate media may have a variety of geometric shapes and sizes (e.g., spherical, extrudate, cylindrical, trilobal, annular, etc.). Removal of some, most, or all of the particulates may prevent clogging of the catalyst bed described and used in the downstream steps of the process. Filter particulate media that may be used in the one or more filter beds are commercially available, such as ceramic balls, alumina particles, silica particles, silicon aluminate particles, activated carbon particles, zeolites, and / or refractory particles, etc. Specific examples of filter media may include various alumina types, such as various pore structures and surface areas. -Al2O3 or -Al2O3.

[0082] Different configurations of filter beds can be used. One or more filter beds can be used. If more than one filter bed is used, the filter beds can be used in parallel or sequentially (in series), or one filter bed can be used and then a spare filter bed can be used when the initial filter bed needs to be cleaned or regenerated or replaced. Typically, a filter bed is spent once a certain level of pressure increase occurs due to clogging. One skilled in the art will understand when this occurs.

[0083] If parallel filtration is used with one filter bed in a standby state, filtering can be performed with one filter bed until the pressure drop increases to the target level and a switch can be made to the standby filter bed to continue filtering particulate matter, and during this switch, the spent filter media can be cleaned or replaced.

[0084] By filtering particulate matter from the gas stream, the gas stream can have a particulate matter level that is reduced by at least 10 wt % (e.g., at least 20 wt %, at least 30 wt %, at least 40 wt %, at least 50 wt %, at least 60 wt %, at least 70 wt %, at least 80 wt %, at least 90 wt %, at least 95 wt %, such as 10-99 wt %, 50-99 wt %, or 75-99 wt %, or 90-99 wt %) based on the total weight of particulate matter present before filtering. After particulate matter filtering, the gas stream can have a particulate matter content of 50 mg / Nm 3 Or lower, less than 40mg / Nm 3 , less than 30mg / Nm 3 , less than 20mg / Nm 3 , less than 10mg / Nm 3 , less than 5mg / Nm 3 , less than 1mg / Nm 3 , for example 0.01 mg / Nm 3 -50mg / Nm 3 , or 0.01mg / Nm 3 -10mg / Nm 3 , or 0.01mg / Nm 3 -5mg / Nm 3 , or 0.01mg / Nm 3 -1mg / Nm 3 .

[0085] With respect to capture of catalyst poisons, one or more types of adsorbents that may be present in an adsorption vessel or container or bed may be used to at least partially capture the catalyst poisons. The adsorbent may be a multifunctional adsorbent or a mixture of two or more adsorbents (e.g., a special adsorbent) that is capable of capturing or trapping or adsorbing or otherwise retaining at least a portion of the catalyst poisons, which as indicated are or include HCl and / or PH3. The desired level of removal is a level that allows the downstream use of the catalyst to achieve an acceptable or extended useful life.

[0086] When multiple adsorbents are used, the adsorbents may be loaded in series into separate vessels, or they may be loaded in layers into the same vessel or loaded together as a mixture of adsorbents.

[0087] Any commercially available sorbent or adsorbent with the desired function described herein can be used. The sorbent or adsorbent can be a porous material. The adsorbent can be, but is not limited to, alumina, silica, aluminosilicate, magnesium oxide. The adsorbent or sorbent can be optionally modified with alkali metal and / or alkaline earth metal oxides to improve performance. Examples of commercially available materials include calcium oxide-modified alumina, magnesium-modified alumina, Na2O / Al2O3, K2O / Al2O3, high surface area γ-alumina, etc. Commercially available examples include SHIFTGUARD 200 adsorbent from Clariant AG, TK-3000 catalyst / sorbent and HTG-10 adsorbent from Topsoe A / S, and ET-17 and EG-2 catalyst / sorbent from HaisoTechnology Co.

[0088] By capturing the catalyst poisons, the amount of catalyst poisons such as HCl and / or PH3 can then be reduced by at least 50 vol%, at least 60 vol%, at least 70 vol%, at least 80 vol%, at least 90 vol%, at least 95 vol%, such as 50-99 vol%, or 75-99 vol%, or 90-99 vol%. After poison capture, the catalyst poison content defined by HCl and / or PH3 in the exhaust gas stream can be below 5 ppm for each of HCl and / or PH3, and more preferably, below 1 ppm for each of HCl and / or PH3.

[0089] Preferably, the particulate filtration step (if used) occurs prior to capturing the catalyst poisons, for example prior to the gas compression step.

[0090] Preferably, capture of catalyst poisons (if used) occurs after the particulate filtration step (if used), for example, before the gas compression step.

[0091] The steps of capturing catalyst poisons and / or filtering particulate matter may be performed at a temperature of about 100° C. to about 500° C. Other temperatures outside of this range are also possible.

[0092] With regard to the step of performing several reactions on a gas stream or a compressed gas stream, preferably this part of the process takes place with a compressed gas stream.

[0093] Carrying out at least one hydrolysis reaction to obtain at least HS can be in the form of one reaction or multiple reactions using the same or different catalysts. At least one hydrolysis catalyst can be used. In the hydrolysis reaction, at least one or more sulfur species (e.g. CS2 and / or COS and / or organic sulfur) in the gas stream are converted into HS by one or more hydrolysis reactions with water or moisture in the gas stream.

[0094] The hydrolysis reaction preferably comprises one or both of the following reactions:

[0095]

[0096] .

[0097] Carrying out at least one hydrogenation reaction to convert at least one of SO2 and SO3 into H2S can be in the form of one reaction or multiple reactions using the same or different catalysts. At least one hydrogenation catalyst can be used. In the hydrogenation reaction, at least one or more sulfur species (e.g., SO2 and / or SO3) in the gas stream are converted into H2S by one or more hydrogenation reactions with hydrogen in the gas stream.

[0098] The hydrogenation reaction preferably comprises one or both of the following reactions:

[0099]

[0100] .

[0101] The percent conversion from sulfur species to HS (from one or both of the hydrolysis and hydrogenation reactions) is preferably at least 50%, or at least 60%, or at least 70%, or at least 80%, or at least 90%, based on the starting ppm level of the sulfur species. The percent conversion may range from 50% to 99% or more, based on the starting ppm level of the sulfur species.

[0102] Carrying out at least one hydrolysis reaction can further comprise the reaction that HCN is converted into NH .At least one hydrolysis catalyst as previously described or other hydrolysis catalyst can be used for this specific reaction.In this other hydrolysis reaction, HCN in the gas stream (for example, at least a portion thereof) is converted into NH with the water in the gas stream .

[0103] Based on the starting ppm level of HCN, the conversion percentage from HCN to NH3 is preferably at least 50%, or at least 60%, or at least 70%, or at least 80%, or at least 90%. Based on the starting ppm level of HCN, the conversion percentage can be from 50% to 99% or more.

[0104] The additional hydrolysis reaction preferably comprises the following reaction:

[0105] .

[0106] This portion of the process may further include subjecting the compressed gas stream or the conditioned synthesis gas stream to at least one reduction reaction to convert at least a portion of the nitrogen-containing species into N2. In this portion of the process, NO and / or NO in the gas stream are reduced to N2. x (or at least a portion thereof) can be converted into nitrogen (N2) by a reduction reaction. A reduction reaction catalyst can be used for the reaction.

[0107] Using a reduction reaction, NO and / or NO present in the gas stream just prior to the reaction can be x At least 50 vol%, at least 60 vol%, at least 70 vol%, at least 80 vol%, at least 90 vol%, at least 95 vol% (e.g., 50 vol%-99 vol% or more, or 60 vol%-99 vol%, or 70 vol%-99 vol%, or 80 vol%-99 vol%, 90 vol%-99 vol%, 95 vol%-99 vol%) of the gas is converted into N2.

[0108] Carrying out at least one oxygen conversion reaction to remove O from the compressed gas stream can be in the form of one reaction or multiple reactions using the same or different catalysts. At least one oxygen conversion catalyst can be used. In the oxygen conversion reaction, the oxygen conversion reaction comprises, consists of, or includes: a further hydrogenation reaction of converting O into H2O with hydrogen in the gas stream, or a reduction reaction of converting carbon monoxide into carbon dioxide with oxygen in the gas stream, or both reactions. In the reduction reaction, this can be considered as a reaction of converting O2 into carbon dioxide with CO in the gas stream. Therefore, in each possible reaction, oxygen is converted into H2O or carbon dioxide or both.

[0109] The conversion percentage from oxygen to H2O or carbon dioxide or both is preferably at least 50% or at least 60%, or at least 70% or at least 80%, or at least 90%, based on the starting volume % level of oxygen. The conversion percentage can be from 50% to 99% or more, based on the starting volume % level of oxygen.

[0110] The oxygen conversion reaction preferably includes one or both of the following reactions:

[0111]

[0112] .

[0113] As a result of the oxygen conversion reaction, an O2-depleted gas stream is obtained.

[0114] With respect to the at least one hydrolysis reaction, the at least one hydrogenation reaction and the oxygen conversion reaction and the optional reduction reaction, any commercially available catalyst having the described functions can be used. Combinations of catalysts can be used. Examples of catalysts that can be used include, but are not limited to, ACTISORB 405, ACTISORB 410 and ACTISORB O catalysts / sorbents from Clariant AG, DL-1 catalyst from Haiso Technology Co., and CKA-3 and TK-240 catalysts from Topsoe A / S.

[0115] The desired reaction temperature for these reactions may be from about 150° C. to about 350° C. or other temperatures outside this range. If the gas stream from upstream is at a temperature outside the desired range, a heat exchanger (i.e., heater) or other means may be used to achieve the desired temperature range prior to conducting these reactions.

[0116] The reaction can be carried out or achieved with a reactor or reactor vessel (or multiple reactor vessels) that can contain a catalyst or a combination of catalysts. When more than one reactor or reactor vessel is used, the arrangement of the reactors can be in parallel to reduce the overall pressure drop, which can achieve optimized performance of the reactor. The reactor can be a fixed bed reactor that accommodates or contains one or more of the catalysts.

[0117] In the alternative, when more than one reactor is used and each reactor has a different catalyst for a different reaction, the reactors may be arranged in series.

[0118] Any configuration of reactors known to those skilled in the art (eg, fixed bed reactors) can be used. The configuration can be upflow, or downflow, axial flow, radial flow, or horizontal flow.

[0119] After obtaining the O 2 -depleted gas stream, a step is performed of subjecting the O 2 -depleted gas stream to at least one water gas shift reaction to obtain at least CO 2 , in order to thereby obtain a conditioned synthesis gas stream.

[0120] The process of the present invention further comprises subjecting the O2-depleted gas stream to at least one water gas shift reaction to obtain at least CO2 and thereby obtain a regulated synthesis gas stream. With respect to this reaction, the reaction may be considered to be a CO-water gas shift reaction (WGSR). The reaction may be one or more reactions.

[0121] The water gas shift reaction preferably occurs after the aforementioned hydrolysis reaction and after the aforementioned hydrogenation reaction and the aforementioned oxygen conversion reaction.

[0122] One or more of the hydrolysis and hydrogenation reactions may optionally continue during the water gas shift reaction if it has not already been completed before the water gas shift reaction occurs.

[0123] The function of the water gas shift reaction is to convert carbon monoxide (at least a portion thereof) in a gas stream into carbon dioxide by reacting with water in the gas stream so as to produce hydrogen (H2).

[0124] The water gas shift reaction preferably comprises the following reaction:

[0125] .

[0126] Since the gas stream contains sulfur in the form of H2S and / or other unconverted sulfur species at this stage, the catalyst used for this reaction needs to be tolerant to sulfur poisoning (i.e., a sulfur-resistant catalyst). Therefore, the water gas shift reaction is achieved by utilizing at least one sulfur-resistant catalyst that converts CO and H2O into CO2 and H2.

[0127] Sulfur tolerant WGSR catalysts are commercially available. Suitable examples include, but are not limited to, SSK-10 and SSK-20 catalysts from Topsoe A / S, B303Q-S catalyst from Haiso Technology Co., and KATALCO KB-11 and Katalco K8-11 HA from Johnson Matthey.

[0128] The WSGR catalyst may be formed from metal sulfides of cobalt, iron, molybdenum and / or nickel. The WSGR catalyst may be supported on a porous support (e.g., alumina, silica, or similar support material). The WSGR catalyst may be in the form of extrudates, pellets, spheres, rings, and / or any other shape to facilitate mass transfer and / or minimize pressure drop.

[0129] WSGR catalysts can be pre-sulfided before loading, or obtained in oxide form and sulfided in situ after loading into the reactor. To achieve in situ sulfidation, auxiliary systems can be used to supply reactants (e.g., CS2, COS, etc.) and heat to achieve proper sulfidation before introduction of the gas stream. Catalyst suppliers typically provide detailed procedures for such in situ sulfidation processes.

[0130] The water gas shift reaction is generally an exothermic reaction. The heat of reaction may increase the temperature of the gas stream in the reactor or reactor bed. In addition, the water gas shift reaction is reversible and its conversion may be equilibrium limited if desired. Since higher temperatures are not conducive to achieving the desired high CO conversion, one option is to use temperature control, such as using one or more cooling techniques / devices, to maximize the overall CO conversion. Therefore, as an option, the portion of the process in which at least one gas shift reaction is performed is preferably performed in the presence of at least one cooling device to control the temperature during the gas shift reaction.

[0131] For example, the cooling process can be achieved by installing internal cooling tubes inside the reactor for the WGSR. One option is to install multiple WGSR reactors in series with interstage heat exchangers to remove heat from the intermediate product stream, or any other heat removal mechanism known in the industry.

[0132] As a result of WSGR, the overall conversion of CO in the gas stream can be at least 80 vol%, at least 85 vol%, at least 90 vol%, at least 95 vol%, at least 96 vol%, at least 97 vol%, at least 98 vol%, e.g., 80 vol%-99 vol% or more, or 85 vol%-99 vol%, or 90 vol%-95 vol%, or 95 vol%-98 vol%, based on the vol% of CO in the gas stream at this stage and the amount of residual CO in vol% present after WSGR.

[0133] Depending on the desired target for overall carbon capture efficiency, the WGSR portion of the process or the WGSR system can be designed for the desired conversion rate.

[0134] Due to the nature of the exothermic reaction, WSGR and WGSR reactors are generally not operated isothermally. Instead, WSGR and WGSR reactors may generally be operated in a temperature range such as about 180° C. to about 400° C. The exact temperature profile may depend on the selected catalyst, and / or the desired overall CO conversion and / or the selected cooling mechanism.

[0135] To optimize WGSR process performance, the water concentration in the gas stream may be adjusted. This may be achieved using standard techniques used in the industry, such as by passing the gas stream through a column of water, and / or injecting steam into the gas stream, and / or sparging water into the gas stream, or any combination thereof.

[0136] After the WGSR portion of the process, the gas stream that can be considered to be a conditioned synthesis gas stream typically contains primarily H2, CO2, N2, H2S, NH3, H2O, and some amount (e.g., a small amount) of any other unconverted components carried in with the raw gas stream, such as sulfur compounds, CO, and / or N species. The H2, CO2, N2, H2S, NH3, H2O combination comprises more than 50 vol%, more than 60 vol%, more than 70 vol%, more than 80 vol%, more than 90 vol%, more than 95 vol% (e.g., 50 vol%-99 vol% or 75 vol%-99 vol%) of the conditioned synthesis gas stream.

[0137] The next step may then be to remove at least a portion of the H 2 S and CO 2 from the conditioned synthesis gas stream to obtain an acid gas stream containing H 2 S and CO 2 and also to obtain a treated gas stream having fuel value.

[0138] This step may be referred to to some extent as acid gas capture and may be accomplished with an acid gas capture unit.

[0139] The acid gas capture separates CO2 and H2S from a gas stream (i.e., a conditioned synthesis gas stream) to produce an acid gas stream containing CO2, H2S, and some moisture. The remaining gas components that are not separated can be considered a treated gas stream with fuel value. The treated gas stream can be sent to a combustor for heat recovery, or treated with other widely known technologies such as membranes, pressure swing adsorption (PSA), etc. to produce a marketable pure hydrogen product (e.g., hydrogen with a purity of at least 95% by volume or at least 99% by volume), or used in any other process that can obtain value from or add value to the treated gas stream.

[0140] The separation of CO 2 and H 2 S from a gas stream (ie, a conditioned synthesis gas stream) can be performed using a number of commercially available techniques.

[0141] Examples of such technologies include, but are not limited to, amine scrubbing technology, methanol absorption, glycol absorption, and pressure swing adsorption for acid gas capture.

[0142] With regard to the amine scrubbing technology, in the process, a gas stream adjusted to a desired temperature (e.g., 30-60° C.) and pressure (e.g., sufficient to overcome the absorber pressure drop and up to 100 barg) is contacted with an amine solution in a tower. Various types of contact towers may be used, such as plate towers, randomly packed towers, structured packings, or any combination of these. CO2 and H2S (or at least a portion thereof) are absorbed onto the amine compound and the other components in the gas stream pass through the tower as a product stream. The amine solution with absorbed H2S and CO2 may be transferred to another tower, where heat may be added to promote desorption of H2S and CO2 from the amine solution. After temperature adjustment (e.g., 30-60° C.), the regenerated amine stream is circulated back to the absorption tower to further absorb H2S and CO2. The heat input may depend on the type of sorbent and the design conditions used, but may typically be from about 2 to about 5 MJ / (kg captured CO2). The H2S and CO2 released from the desorption process produce an acid gas stream which can be processed in the next unit operation.

[0143] Solvents that can be used in the process include primary amines (e.g., monoethanolamine (MEA), diglycolamine (DGA)), secondary amines (e.g., diethanolamine (DEA) and diisopropylamine (DIPA)), and / or tertiary amines (e.g., methyldiethanolamine (MDEA)). The sorbent can be an aqueous solution of one or more amines at a certain concentration (e.g., 5-50 wt%). One or more additives having different functions can be additionally used and, for example, can be blended with the sorbent to improve corrosivity and / or absorption efficiency and / or achieve one or more other properties.

[0144] A conditioning step for the gas stream (i.e., conditioned synthesis gas stream) may be performed, for example, wherein the gas stream is cooled prior to entering an absorption unit for acid gas capture, and as a result, condensate may form as the gas stream is cooled below its dew point. This stream of water condensate may be used as quench water and / or other process water uses in carbon black production.

[0145] Another process that can be used for acid gas capture is one or more absorptions using one or more solvents such as methanol or glycols or alkaline salt solutions. This process is very similar to the amine absorption process. Commercially available acid gas absorption units / technology can be used for this part of the process of the present invention. Commercially available units include those from Shell, Mitsubishi Heavy Industries, Honeywell / UOP, Linde, Technip, and many other technology suppliers, as well as engineering EPC (engineering, procurement and construction) companies.

[0146] Another process / technology that can be used for acid gas capture includes pressure swing adsorption (PSA). For this PSA, a solid adsorbent can be used to capture H2S and CO2 at an elevated pressure (e.g., a pressure of 2 barg to 100 barg), and then the solid adsorbent can be desorbed using a reduced pressure (e.g., atmospheric pressure to 100 barg) to obtain a concentrated H2S and CO2 stream and also obtain a clean gas stream with a small amount of H2S and CO2. For example, the clean gas stream may include treated gas and may contain up to 20 ppmv of H2S, e.g., up to 10 ppmv, up to 5 ppmv, or up to 1 ppmv of H2S or less. Alternatively, or in addition, it may contain up to 5% by volume of CO2, e.g., up to 2% by volume, up to 1% by volume, up to 0.5% by volume, or up to 0.1% by volume of CO2 or less. As noted, the concentrated H2S and CO2 stream can be considered an acid gas stream, and the clean gas stream can be considered a treated gas stream having fuel value. The calorific value of the treated gas can depend on the raw gas composition. For the clean gas stream, the treated gas calorific value can be from about 2 to about 6 MJ / Nm 3 Or other values ​​below or above this range. If other gas sources (eg, biomass syngas, coke oven gas) are blended into the starting feed, the heating value range may be above or below this range.

[0147] Since the clean gas stream may still contain the formed NO x components (e.g., ammonia), therefore, if the clean gas stream is burned to produce flue gas for any reason, NO x Removal Techniques or Procedures. Exemplary NO x Removal processes include, but are not limited to, injection of ammonia or urea into the flue gas stream and selective catalytic reactor (SCR) processes known to those skilled in the art, including but not limited to the process described in US9192891, the entire contents of which are incorporated herein by reference. Alternatively, or in addition, a selective non-catalytic reactor (SNCR) process (including but not limited to the process described in the '891 patent) may be used to remove NO from the flue gas. x Because the SCR and SNCR processes operate most efficiently within a specific temperature range (typically 275-500°C and 900-1050°C, respectively), one skilled in the art can use boilers, heat exchangers and other conventional equipment to adjust the temperature of the flue gas to allow the selected process to operate more efficiently. Alternatively, or in addition, a catalytic process (such as the catalytic process described in EP2561921, the contents of which are incorporated herein by reference), or a commercially available process (such as SNOX from Haldor Topsoe) may also be employed. TMAlternative methods known to those skilled in the art may also be employed.

[0148] Once the acid gas stream is obtained, the next step in the process may be to convert at least a portion of the H 2 S in the acid gas stream into elemental sulfur and then remove the elemental sulfur to obtain a sulfur-depleted off-gas.

[0149] Various commercially available technologies can be used for the conversion to sulfur step, such as, but not limited to, liquid phase catalytic oxidation technology or gas phase combustion technology, etc. The gas phase combustion process can utilize the Claus process (e.g., as described in US3719744, the entire contents of which are incorporated herein by reference), which converts H2S and SO2 into H2O and S2.

[0150] Relatively low concentrations of H2S in the acid gas stream can be more fully treated with liquid phase oxidation technology than with other processes (e.g., the Claus process). In the liquid phase oxidation process, a gas mixture of CO2, H2S and H2O is contacted with an aqueous solution of an iron catalyst in a reactor tower. H2S is oxidized to elemental sulfur by reacting with Fe(III) to form Fe(II). The reaction product stream is transferred to a regeneration reactor where ambient air is bubbled through the liquid to oxidize Fe(II) back to Fe(III) to regenerate the catalyst. The regenerated catalytic liquid is circulated back to the oxidation reactor tower to promote H2S oxidation. The elemental sulfur produced in the oxidation process forms crystalline sulfur suspended in an aqueous liquid solution. The slip stream of the solution is sent to a liquid-solid separator, such as a belt filter, a press frame filter, or any other type of separator, to produce a marketable solid sulfur product (or usable material).

[0151] CO2 is inert in the oxidation reactor tower, and CO2 passes through the reactor without conversion to form a high concentration, pure CO2 stream with a certain amount of moisture. The CO2 stream can be further processed by unit operations (e.g., operations that provide compression, drying and / or cryogenic liquefaction) to produce supercritical CO2, liquid CO2 and / or compressed CO2. The CO2 can be easily used for enhanced oil recovery (EOR) or other applications, or the CO2 can be isolated or collected in a suitable storage unit.

[0152] Alternatively, or in addition, the acid gas may be captured by separating H2S and CO2 from the conditioned gas in two separate steps. Each of the process technologies described above may be used to capture H2S and CO2 separately, with some adjustments to the sorbent properties and / or designed operating conditions (which are readily made by one skilled in the art). The H2S-rich stream may be oxidized to elemental sulfur using the catalytic processes described above, or it may be oxidized to elemental sulfur using the Claus process.

[0153] Figure 1 A flow diagram of a process 100 of the present invention that may be used is shown. In step 110, a gas stream comprising tail gas (such as tail gas generated during carbon black production or manufacturing) is obtained.

[0154] The gas stream may have at least some of the particulate matter and / or catalyst poisons removed from the gas stream in optional step A. This may occur before and / or after step 115 of compressing the gas stream to form a compressed gas stream.

[0155] In step 120, the compressed gas stream is subjected to at least one hydrolysis reaction to form at least H2S and convert HCN (if present) to NH3.

[0156] In step 125, the compressed gas stream is subjected to at least one hydrogenation reaction to form at least H2S from at least SO2 and / or SO3.

[0157] In step 130, the compressed gas stream is subjected to at least one oxygen conversion reaction to remove oxygen (O2). The reaction may be a further hydrogenation reaction to convert O2 into H2O and / or a reduction reaction to convert CO into CO2.

[0158] Steps 120, 125 and 130 may occur in any order. Preferably, step 130 is performed after steps 120 and 125 to obtain an O2-depleted gas stream.

[0159] In step 135, the gas from step 130 (preferred) or step 120 or 125 is subjected to at least one water gas shift reaction to form at least CO 2. This forms a conditioned synthesis gas stream.

[0160] In step 140, the conditioned synthesis gas stream is subjected to a process to remove at least a portion of the H2S and CO2 and form two gas streams, wherein in step 145, a treated gas stream having a fuel value is recovered / obtained, and in step 150, an acid gas stream containing H2S and CO2 is obtained or recovered or separated from the treated gas stream.

[0161] At least a portion of the H 2 S in the acid gas stream is converted to elemental sulfur in step 155 and may be recovered or removed or separated from the remainder of the gas stream in step 160 .

[0162] In step 165 , the remainder of the gas stream (the waste gas minus the sulfur) may be subjected to a process to capture at least a portion of the CO 2 .

[0163] The above-described process for cleaning a gas stream may be implemented in a facility or system configured to carry out the various steps described herein. Therefore, the present invention further relates to a system and / or facility for cleaning a gas stream, including tail gas generated during carbon black production.

[0164] The plant comprises at least a compressor unit or at least one compressor for compressing a gas stream in order to obtain a compressed gas stream.

[0165] The facility further includes a catalytic converter unit comprising one or more fixed bed reactors configured to perform the above-mentioned at least one hydrolysis reaction to obtain at least H2S and to perform at least one hydrogenation reaction to obtain at least H2S, and to perform at least one oxygen conversion reaction to remove O2 from the gas stream or compressed gas stream.

[0166] The facility further comprises a WGSR reactor bed for performing at least one water gas shift reaction on a compressed gas stream to obtain CO2 and to obtain a conditioned synthesis gas stream. This portion of the facility may optionally include one or more cooling devices or means to control the temperature of the gas before and / or after and / or during the residence time of the gas in the WGSR reactor bed. This portion of the facility may optionally include a water input device to introduce water or moisture into the gas stream before or during the residence time of the gas stream in the WGSR reactor.

[0167] The facility also includes an acid gas capture unit for removing at least a portion of H2S and CO2 from the conditioned synthesis gas stream to obtain an acid gas stream containing H2S and CO2 and to obtain a treated gas stream having fuel value.

[0168] The facility also includes a sulfur conversion unit for converting at least a portion of the H2S in the acid gas stream into elemental sulfur and removing the elemental sulfur and obtaining a sulfur-depleted off-gas.

[0169] The facility further comprises a CO 2 capture unit for capturing at least a portion of the CO 2 in the desulfurized flue gas.

[0170] The facility may further comprise a gas conditioning unit for removing particulate matter and / or catalyst poisons from a gas stream or a compressed gas stream as described herein.

[0171] The gas conditioning unit of the facility may be or include at least one filter bed and at least one adsorbent, wherein the at least one filter bed and the at least one adsorbent are in the same vessel or in different vessels.

[0172] The one or more fixed bed reactors may include or comprise at least one hydrogenation catalyst, at least one hydrolysis catalyst, and at least one sulfur tolerant catalyst.

[0173] The plant may further comprise or include at least one cooling device for controlling the temperature of the gas flow passing through the catalytic converter unit or leaving the catalytic converter unit or both.

[0174] The acid gas capture unit may be or include an amine scrubber, an acid gas absorption unit with a non-amine solvent, or a pressure swing adsorption unit, or any combination thereof.

[0175] The plant may further comprise at least one cooling device for controlling the temperature of the gas stream exiting at least one compressor as described herein.

[0176] refer to Figure 2 , in a schematic diagram, illustrates one possible setup of a facility or system for carrying out the process of the present invention. As described herein, variations of this facility may be employed.

[0177] exist Figure 2 In the embodiment of the present invention, five unit operations are provided for the facility or system 200. A first unit operation 202 is provided as a gas stream or tail gas compression. A gas stream 220, which may include raw tail gas separated from carbon black after leaving the carbon black furnace, can be obtained and fed to the first unit operation 202. The gas stream is fed into an apparatus 222 to compress the gas stream and / or pressurize the gas stream. For example, a tail gas heater can be used, which is pressurized to a desired pressure, such as with a booster blower, just enough to overcome the pressure drop of the downstream process or to a higher pressure for better efficiency.

[0178] In the facility, a device for removing particulate matter and / or catalyst poisons from a gas stream ( Figure 2 Installations (not shown) may be employed. For example, a filter tower or other equipment upstream or downstream of the equipment 222 for compressing the gas flow (e.g., a booster blower) may be filled with solid particulate matter of various shapes and / or sizes (which may be used and is optional). This portion of the facility or system is optionally used to capture particulate matter, such as carbon black particulate matter and / or other particulate matter, to prevent or reduce the risk of downstream blockage of other units (e.g., one or more catalytic reactors).

[0179] Depending on the gas purity, guard bed or other equipment ( Figure 2 A fan (not shown) may be installed downstream of the unit to compress the gas stream (e.g., a booster blower) to remove catalyst poisons such as hydrogen chloride, phosphine, etc.

[0180] In the second unit operation 204, a multifunctional catalyst or a combination of catalysts having the desired functions is used to adjust the compressed gas stream or tail gas to achieve hydrolysis and hydrogenation (e.g., as shown in the following equations). In this second unit operation 204, equipment (e.g., 224 and 226) is used to achieve at least one hydrolysis reaction, at least one hydrogenation reaction, and to perform at least one oxygen conversion reaction. The following one or more reactions can be performed in the second unit operation in one or more equipment that can be arranged in series with each other.

[0181] hydrolysis:

[0182]

[0183]

[0184] .

[0185] hydrogenation:

[0186]

[0187]

[0188] .

[0189] In the third unit operation 206, one or more devices 228, 232 (e.g., catalyst reactors) promote a water gas shift reaction (WGSR), such as a CO WGSR, to convert CO to CO 2 via reaction with H 2 O. The third unit operation may include a multi-stage reactor series 230 with intermittent heat removal to achieve desired performance.

[0190] Water Gas Shift Reaction:

[0191] .

[0192] The water gas shift reaction is optional before carbon dioxide capture is required. In a preferred embodiment, at least 99.9% (by volume) of the sulfur is converted to hydrogen sulfide, at least 99.9% (by volume) of the hydrogen cyanide is converted to ammonia, and the resulting gas has at most 0.1% by volume oxygen and at most 0.5% by volume carbon monoxide.

[0193] In the fourth unit operation 208, carbon dioxide and hydrogen sulfide are captured from the exhaust gas from the third unit operation 206 via an amine scrubbing system to produce a treated gas stream with high fuel value, such as a high hydrogen content fuel with a high heating value. The gas leaving the unit operation 206 transfers heat to the amine solution in the boiler 234 and is directed to the cooler 242. The cooled gas is directed to the tower 240, where it contacts the amine solution that adsorbs carbon dioxide and hydrogen sulfide. The cleaned tail gas 244 has a high energy value and can be directed to various beneficial uses. The dirty amine solution leaves the tower 240 and is heated in the heat exchanger 238 before being directed to the regeneration tower 236, where hydrogen sulfide and carbon dioxide are desorbed from the amine solution to form a gas directed to the unit operation 210. The regenerated amine solution is passed through the boiler 234 and reheated. Any additional carbon dioxide, hydrogen sulfide, and water vapor produced are returned to regeneration column 236 and ultimately directed to unit operation 210, while the regenerated amine solution is cooled in heat exchanger 238 and optional additional heat exchangers before being redirected to column 240. In a preferred embodiment, the removal efficiency of hydrogen sulfide is at least 99% (by volume), or the concentration of hydrogen sulfide in the treated gas is, for example, at most 1 ppm. In a preferred embodiment, less than 5% (by volume) of the carbon dioxide present after the third unit operation is removed during the fourth unit operation.

[0194] In the fifth unit operation 210, the gas containing hydrogen sulfide is removed from the conditioned gas stream, concentrated, and converted to elemental sulfur by one or more processes, such as the liquid phase process described above, which may utilize an oxidation reactor 246, a catalyst regenerator 248, and a liquid-solid separator 252 to remove sulfur 256 from the gas stream 9. A buffer tank 254 and pumps 258 and 250 move the liquid catalyst through the various facilities of the unit operation 210. In a preferred embodiment, the elemental sulfur produced in the fifth unit operation has a purity of at least 99% by weight.

[0195] H2S and CO2 can be captured from the product tail gas stream leaving the WGSR by a single unit operation of acid gas absorption. The acid gas stream can be processed in the next unit operation to oxidize the H2S to elemental sulfur as a marketable product. This oxidation step captures sulfur from the acid gas stream and produces a clean, moisture-containing CO2 stream (which can be easily stored (sequester) or used for enhanced oil recovery).

[0196] The volume flow of tail gas is significantly less than the flow of the combusted flue gas or the initial gas stream. Therefore, a reduced amount of equipment is required to treat the tail gas. Likewise, a reduced amount of sorbent is required, further reducing the amount of solid pollutants obtained. Cooling the tail gas produces a condensate that can be used in other unit processes in the carbon black production process.

[0197] Example

[0198] In order to quantitatively demonstrate the process of the present invention, an Aspen simulation was performed based on the collected tail gas data from a carbon black production facility. Figure 3A and 3B Operational settings / flowcharts from Figure 3A Continue to Figure 3B ,in Figure 3A The "to amine unit" in Figure 3B Continue at "From R-002" arrow.

[0199] exist Figure 3A-3B The abbreviations / symbols are as follows:

[0200] Z-01 - Exhaust Gas Compressor

[0201] G-01 / G-02 - Protective bed

[0202] B-01 / B-02 - Waste Heat Boiler

[0203] P-01 / P-02 - Boiler feed pump

[0204] H-01 / H-02 - Hydrolysis Reactor

[0205] R-01A / B - First Stage Water Gas Shift Reactor

[0206] R-02A / B - Second stage water gas shift reactor

[0207] E-01 - Reboiler

[0208] E-02 - chiller

[0209] V-01 / V-02 / V-03: Gas-liquid separator

[0210] C-01 - Absorber

[0211] C-02 - Regenerator

[0212] P03 / P04 - Sorbent Pumps

[0213] E03 / E04 / E05 - Heat exchanger

[0214] R-03 - H2S-Oxidation Reactor

[0215] R-04 - Catalyst Regenerator

[0216] P05 / P06 - Slurry Pumps

[0217] P-07 - Bleed pump

[0218] Z-02 - Blower

[0219] F-01 - Sulfur filter.

[0220] Use / simulate the following operating units:

[0221] First operating unit: gas compression (Z-01)

[0222] Second operating unit: gas regulation (G-01, G-02, B-01, B-02, P-01, P-02, H-01, H-02)

[0223] The third operating unit: CO conversion unit (R-01, R-02)

[0224] Unit 4: Amine Acid Gas Scrubber (E-01, E-02, V-01 / 02 / 03, C01, C02, P03 and P04, E03 / 04 / 05)

[0225] Final operating unit: Desulfurization unit (R03, R04, P05 / 06, P07, Z02, F01)

[0226] In this simulation, the following table lists the Figure 3A-3B The “Logistics Number” in the table represents the gas flow when the unit is operated. Figure 3A-3B The logistics location shown in .

[0227] Table 1A:

[0228]

[0229] Table 1B:

[0230]

[0231] Table 1C:

[0232]

[0233] As shown in the table, the amount of sulfur in the starting gas stream is almost completely removed, with only 2 ppm of COS and 7 ppm of CS2 in the cleaned tail gas 18. In this simulation, the process produces 871 kg / h of saleable elemental sulfur containing about 40 wt% water. The purity of the recovered components also meets the disposal specifications required for commercial sale for third party use.

[0234] More specifically, in this model process, a hypothetical tail gas representing a common carbon black production process (containing 1218 ppmvw hydrogen sulfide, 209 ppmvw SO2, 274 ppmvw COS, 668 ppmvw CS2, 34% by volume nitrogen, 15% by weight hydrogen, 1.5% by volume carbon dioxide, and 39% water, and other components listed in Table 1A) is processed to produce a cleaned tail gas (containing 53% by volume nitrogen, 37% by volume hydrogen, 7.9% by volume water, no carbon dioxide, and other components listed in Table 1C). A 97% carbon dioxide stream (the balance being water) is produced for further processing (e.g., compression, dehydration, liquefaction, etc.), for storage (sequestration), or for other beneficial processes.

[0235] The present invention may include any combination of these various features or embodiments above and / or below as set forth in any sentence and / or paragraph herein.Any combination of features disclosed herein is considered part of the present invention, and is not intended to limit the combinable features.

[0236] The applicant specifically incorporates the full content of all cited references into the present disclosure. In addition, when the list of equivalent, concentration or other values ​​or parameters as scope, preferred range or preferred upper limit and preferred lower limit is given, this should be understood as specifically disclosing all ranges formed by any pairing of any upper range limit or preferred value and any lower range limit or preferred value, and no matter whether scope is disclosed separately. In the case of enumerating numerical range in this article, unless otherwise indicated, the scope is intended to include all integers and fractions in its endpoint and the scope. When limiting the range, the scope of the present invention is not intended to be limited to the specified value.

[0237] Other embodiments of the invention will be apparent to those skilled in the art by consideration of the specification and practice of the invention disclosed herein.It is intended that the specification and examples be considered exemplary only, with the true scope and spirit of the invention being indicated by the following claims and their equivalents.

[0238] The foregoing description of preferred embodiments of the present invention has been presented for purposes of illustration and description. It is not intended to be exhaustive or to limit the present invention to the precise form disclosed. Modifications and variations are possible in light of the above teachings or may be obtained from the practice of the present invention. The embodiments are selected and described in order to explain the principles of the present invention and their practical application, so that those skilled in the art can utilize the present invention in various embodiments and with various modifications suitable for the intended specific use.

Claims

1. A process for cleaning a gas stream containing tail gases generated during the production of carbon black, the process comprising: compressing the gas stream to obtain a compressed gas stream; performing at least one hydrolysis reaction to obtain at least H2S, performing at least one hydrogenation reaction to convert at least one of SO2 and SO3 into H2S, and performing at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining an O2-depleted gas stream; subjecting said O2-depleted gas stream to at least one water gas shift reaction to obtain at least CO2 and thereby obtain a conditioned synthesis gas stream; removing at least a portion of said H2S and CO2 from said conditioned synthesis gas stream to obtain an acid gas stream containing said H2S and CO2 and to obtain a treated gas stream having fuel value; converting at least a portion of the H2S in the acid gas stream into elemental sulfur and removing the elemental sulfur to obtain a sulfur-free off-gas; and capturing at least a portion of said CO2 in said desulfurized flue gas, Wherein the at least one oxygen conversion reaction comprises a further hydrogenation reaction of converting O2 into H2O, or a reaction of converting carbon monoxide into carbon dioxide, or both.

2. A process according to claim 1, wherein at least a portion of any particulate matter and any catalyst poisons are removed from the gas stream or the compressed gas stream prior to carrying out the at least one hydrolysis reaction, the at least one hydrogenation reaction and the at least one water gas shift reaction.

3. A process according to claim 1 or claim 2, wherein the at least one water gas shift reaction occurs after the at least hydrolysis reaction and after the at least hydrogenation reaction.

4. The process according to any one of claims 1 to 3, wherein the gas stream consists of the tail gas generated during the production of carbon black.

5. The process of claim 4, wherein the gas streams are from two or more carbon black production units.

6. The process of any one of claims 1-5, wherein the gas stream further comprises a gaseous fuel from a non-carbon black producing source.

7. A process according to any one of claims 1 to 6, wherein at least 80% by volume of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons and water, and also contains trace amounts of sulfur species and nitrogen species, and optionally HCl and PH3 and optionally particulate matter.

8. A process according to any one of claims 1 to 7, wherein at least 80% by volume of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons and water, and also contains trace amounts of sulfur species and nitrogen species, and optionally one or more HCl, and PH3 and particulates.

9. The process according to any one of claims 1 to 8, wherein the gas stream comprises the following component concentrations: 3-30% by volume of CO, -10% by volume of CO2, 3-50% by volume of H2, -2% by volume of O2, - 10% by volume of hydrocarbons, 1-50% by volume of water, 50ppm to 10,000ppm sulfur substances by volume, 50ppm to 20,000ppm of nitrogen substances, 0 to 20 ppm by volume of HCl, 0 to 10 ppm by volume of PH3, and 0mg / Nm 3 Up to 80mg / Nm 3 of granular matter.

10. The process of any one of claims 1-9, wherein the compressing utilizes at least one compressor.

11. The process according to any one of claims 1 to 10, wherein the at least one hydrolysis reaction is achieved by utilizing at least one hydrolysis catalyst.

12. The process according to any one of claims 1 to 11, wherein the at least one hydrogenation reaction is achieved by utilizing at least one hydrogenation catalyst.

13. The process according to any one of claims 1 to 12, wherein the at least one gas shift reaction is achieved by utilizing at least one sulfur-tolerant catalyst that converts CO and H2O into CO2 and H2.

14. The process according to any one of claims 1 to 13, wherein the at least one gas shift reaction is carried out in the presence of at least one cooling device to control the temperature during the gas shift reaction.

15. The process of claim 2, wherein said removing at least a portion of any particulate matter and any catalyst poisons from said gas stream or said compressed gas stream comprises passing said gas stream or compressed gas stream through at least one filter bed and through at least one adsorbent.

16. The process of any one of claims 1-15, wherein said removing at least a portion of said H2S and CO2 from said conditioned synthesis gas stream is accomplished by utilizing an amine scrubber, acid gas absorption with a non-amine solvent, or pressure swing adsorption.

17. The process according to any one of claims 1 to 16, wherein the conversion of at least a portion of the H2S in the acid gas stream to elemental sulfur is achieved by utilizing a liquid phase catalytic oxidation process or a gas phase combustion process.

18. The process of claim 17, wherein the gas phase combustion process utilizes a Claus process for converting H2S and SO2 into H2O and S2.

19. The process according to any one of claims 1 to 18, wherein during and / or immediately after said compressing, said gas stream and / or compressed gas stream is cooled.

20. The process of claim 15, wherein said removing at least a portion of any particulate matter and any catalyst poisons from said gas stream or said compressed gas stream provides said gas stream or compressed gas stream having less than 5 ppm by volume of HCl and less than 5 ppm by volume of PH3.

21. The process of any one of claims 1-20, further comprising subjecting the compressed gas stream or the conditioned synthesis gas stream to at least one reduction reaction to convert at least a portion of the nitrogen-containing species into N2.

22. The process of any one of claims 1-21, wherein the at least one hydrolysis reaction converts sulfur species in the compressed gas stream into H2S, and the sulfur species include CS2, COS, and organic sulfur.

23. The process of any one of claims 1-22, wherein the at least one hydrolysis reaction further converts HCN to NH3.

24. The process of any one of claims 1 to 23, wherein the at least one hydrogenation reaction converts SO2 and SO3 into H2S and converts O2 into H2O or CO2 or both.

25. A plant for cleaning a gas stream containing tail gases produced during the production of carbon black, The facilities include: at least one compressor for compressing the gas flow in order to obtain a compressed gas flow; a catalytic converter unit comprising one or more fixed bed reactors configured to perform at least one hydrolysis reaction to obtain at least H2S and to perform at least one hydrogenation reaction to obtain at least H2S and to perform at least one water gas shift reaction on the compressed gas stream to obtain CO2 and to obtain a conditioned synthesis gas stream; an acid gas capture unit for removing at least a portion of said H2S and CO2 from said conditioned synthesis gas stream to obtain an acid gas stream containing said H2S and CO2 and to obtain a treated gas stream having fuel value; a sulfur conversion unit for converting at least a portion of the H2S in the acid gas stream into elemental sulfur and removing the elemental sulfur and obtaining a sulfur-free off-gas; and A CO2 capture unit is used to capture at least a portion of the CO2 in the sulfur-removed exhaust gas.

26. The facility of claim 25, further comprising a gas conditioning unit for removing particulate matter and catalyst poisons from the gas stream or the compressed gas stream.

27. The facility of claim 25 or 26, wherein the one or more fixed bed reactors comprise at least one hydrogenation catalyst, at least one hydrolysis catalyst and at least one sulfur tolerant catalyst.

28. A plant according to any one of claims 25 to 27, further comprising at least one cooling device for controlling the temperature of a gas flow passing through or leaving the catalytic converter unit or both.

29. The facility of claim 26, wherein: The gas conditioning unit comprises at least one filter bed and at least one adsorbent, wherein the at least one filter bed and the at least one adsorbent are located in the same container or in different containers.

30. The facility of any one of claims 25-29, wherein the acid gas capture unit comprises an amine scrubber, an acid gas absorption unit with a non-amine solvent, or a pressure swing adsorption unit.

31. The facility according to any one of claims 25 to 30, wherein: The plant further comprises at least one cooling device for controlling the temperature of the gas flow leaving the at least one compressor.

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