Processes to clean tail gas from carbon black production and system and facility for same

Abstract

A process to clean a gas stream is described. The gas stream can include tail gas generated during carbon black production. The process involves a number of steps to systematically clean the starting gas stream so as to obtain a treat gas stream having fuel value and converting other parts of the gas stream to sulfur for recovery. A facility or system having various operation units to conduct the process is further described.

Description

PROCESSES TO CLEAN TAIL GAS FROM CARBON BLACK PRODUCTION AND SYSTEM AND FACILITY FOR SAMEBACKGROUND

[0001] The present embodiments relate to cleaning gas streams, such as industrial gas streams. More specifically, the present embodiments relates to processes to clean gas streams partly or entirely from carbon black production. The present embodiments further relate to facilities and / or apparatus set-ups and / or systems to clean such gas streams. The present embodiments, in addition, relate to processes to remove such components as sulfur from the tail gas generated during carbon black production.

[0002] There is more and more demand and effort in the cleaning of industrial gas streams and this demand exists with carbon black production. In typical furnace black production processes, the sulfur species in tail gas are combusted to form SOx (e.g., SO2 and SO3). Improvements in manufacturing sustainability require SOx emission reduction. Typically, SOx is controlled following combustion of the tail gas. However, it would be desirable to control SOx emissions directly from the tail gas to reduce expenses and to reduce water usage and waste generation connected with these processes.

[0003] All of the patents and publications mentioned throughout are incorporated in their entirety by reference herein.SUMMARY

[0004] One feature presented herein is to provide processes to clean gas streams, such as industrial gas streams, including, but not limited to, gas streams partly or entirely from tail gases generated during carbon black production.

[0005] A further feature is to provide processes to substantially remove sulfur from the gas stream with close to zero SOx emission.

[0006] Also, a feature is to provide processes and a facility to clean tail gas where 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 permits the equipment size to be reduced for such processing.

[0007] An additional feature is to provide processes and a facility (or system or set-up) to clean tail gas that can permit a reduction in operation cost in comparison to clean up of combusted tail gas.

[0008] Another feature is to provide processes and a facility to clean tail gas that does not add to process water consumption in comparison to processes in which tail gas is combusted and the resulting flue gas is cleaned.

[0009] Still another feature permits the condensate from the tail gas cooling to be reused in carbon black production, such as a quenching fluid.

[0010] To achieve these and other advantages, and in accordance with the embodiments broadly described herein, the present embodiements, in part, relate to a process to clean a gas stream, such as from an industrial process. More particularly, the process to clean a gas stream preferably includes tail gas generated during carbon black production. The process includes the steps of compressing the gas stream to obtain a compressed gas stream, and conducting several reactions to the gas stream. These reactions include, but are not limited to, at least one hydrolysis reaction to obtain at least H2S, conducting at least one hydrogenation reaction to convert at least one of SO2 and SO3 to H2S, and, optionally, conducting at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining an Ch-poor gas stream. The optional at least one oxygen conversion reaction either comprises a further hydrogenation reaction to convert O2 to H2O or a reduction reaction to convert carbon monoxide to carbon dioxide or both. The processmay optionally include conducting at least one water gas shift reaction to convert carbon monoxide and water to carbon dioxide and hydrogen.

[0011] The process also includes removing at least a portion of the H2S from the conditioned syngas stream to obtain a sour gas stream containing the H2S and obtain a treated gas stream having fuel value. The process, in addition, includes converting at least a portion of the H2S in the sour gas stream to elemental sulfur and removing the elemental sulfur to obtain a reduced sulfur off gas.

[0012] Prior to conducting said at least one hydrolysis reaction or said at least one hydrogenation reaction, the process may further include removing at least a portion of any particulates and any catalyst poisons from said gas stream or said compressed gas stream. Removing of the at least a portion of any particulates and any catalyst poisons from said gas stream or said compressed gas stream may include passing said gas stream or compressed gas stream through at least one fdtration bed and through at least one adsorbent. The gas stream may consist of said tail gas generated during carbon black production, and / or may be from two or more carbon black production units. Alternatively or in addition, the gas stream may further comprise gaseous fuel from non-carbon black production sources. In any of these embodiments, at least 80 vol% 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 HC1 and PH3 and optionally particulates. For example, at least 80 vol% 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 HC1, and PH3 and particulates.

[0013] In any of these embodiments, the gas stream may include the following component concentrations:

[0014] 3-30 vol% CO,

[0015] 0.5-10 vol% CO2,

[0016] 3-50 vol% H2,

[0017] 0.01-2 vol% O2,

[0018] 0.5 -10 vol% hydrocarbons,

[0019] 1-50 vol% water,

[0020] 50 ppm- 10,000 ppm by vol sulfur species,

[0021] 50 ppm-20,000 ppm by vol nitrogen species,

[0022] 0 to 20 ppm by vol HC1,

[0023] 0 to 10 ppm by vol PH3, and

[0024] 0 mg / Nm3to 80 mg / Nm3particulates.

[0025] Alternatively or in addition, compressing 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. In any of these embodiments, removing at least a portion of said H2S from said conditioned syngas stream may be achieved by utilizing an amine scrubber, sour gas absorption with non-amine solvent(s), or pressure swing adsorption, and / or converting of at least a portion of the H2S in said sour gas stream to elemental sulfur may be achieved by utilizing a liquid phase catalytic oxidation process or gas phase combustion process. The gas phase combustion process may utilize a Claus process that converts H2S and SO2to H2O and S2.

[0026] In any of these embodiments, the gas stream and / or compressed gas stream may be cooled during and / or immediately after said compressing, and / or removing of the at least a portion of anyparticulates 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 HC1 and less than 5 ppm by volume PH3. In any of these embodiments, the process may further comprise conducting at least one reduction reaction to the compressed gas stream or the conditioned syngas stream to convert at least a portion of the nitrogen containing species to N2.

[0027] In any of these embodiments, the at least one hydrolysis reaction may convert sulfur species in the compressed gas stream to H2S, and said sulfur species may include CS2, COS, and organic sulfur, and / or further convert HCN to NH3, and / or the at least one hydrogenation reaction may convert SO2, and SO3 to H2S and optionally convert O2 to H2O.

[0028] The present embodiments further relate to a facility (or system) to clean a gas stream that includes tail gas generated during carbon black production. The facility includes at least one compressor for compressing the gas stream so as to obtain a compressed gas stream; a first catalytic converter unit comprising one or more fixed bed reactors that are configured for conducting at least one hydrolysis reaction to obtain at least H2S and conducting at least one hydrogenation reaction to obtain at least H2S, and optionally conducting at least one oxygen conversion reaction to remove O2 and obtain an Ch-poor gas stream and obtain a conditioned syngas stream; an optional water gas shift unit for conducting at least one water gas shift reaction to convert carbon monoxide and water to carbon dioxide and hydrogen; a sour gas capturing unit for removing at least a portion of the H2S from the conditioned syngas stream to obtain a sour gas stream containing the H2S and obtain a treated gas stream having fuel value; and a sulfur conversion unit for converting at least a portion of the H2S in the sour gas stream to elemental sulfur and removing the elemental sulfur and obtain a sulfur removal off gas.

[0029] The facility can further include a gas conditioning unit for removing particulates and catalyst poisons from the gas stream or the compressed gas stream, and / or the fixed bed reactorscan be or comprise at least one hydrogenation catalyst, at least one hydrolysis catalyst, and at least one sulfur-resistant catalyst.

[0030] Alternatively or in addition, the facility may be characterized by one or more of the following features: The gas conditioning unit can be or include at least one filtration bed and at least one adsorbent, wherein the at least one filtration bed and the at least one adsorbent are in a same vessel or different vessels. The sour gas capturing unit can be or include an amine scrubber, a sour gas absorption unit with non-amine solvent(s), or a pressure swing adsorption unit. The facility may further include at least one cooling device for controlling temperature of the gas stream exiting the at least one compressor.

[0031] 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 a further explanation of the present embodiments as claimed.

[0032] The accompanying drawings, which are incorporated in and constitute a part of this application, illustrate various features of the present technology and, together with the description, serve to explain the principles of its implementation.BRIEF DESCRIPTION OF DRAWINGS

[0033] FIG. 1 is a flow diagram of a tail gas clean-up process according to an exemplary embodiment.

[0034] FIG. 2 is a block diagram of a tail gas clean up system or facility according to an exemplary embodiment.DETAILED DESCRIPTION

[0035] The present embodiments relates to processes and facilities to clean a gas stream, such as an industrial gas stream. The gas stream can include, and preferably includes, tail gas generated during carbon black production.

[0036] The general steps or aspects of the process of the present embodiments are as follows.

[0037] In the present embodiments, a process comprises or includes compressing a gas stream (e.g., an industrial gas stream such as a tail gas) to obtain a compressed gas stream.

[0038] The process further includes conducting several reactions to the gas stream or compressed gas stream.

[0039] The several reactions include, but are not limited to, the following: conducting at least one hydrolysis reaction to obtain at least H2S; conducting at least one hydrogenation reaction to convert at least one of SO2 and SO3 (or both) to H2S; and optionally conducting at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining an Ch-poor gas stream, wherein the at least one oxygen conversion reaction comprises, consists of, or includes a further hydrogenation reaction to convert O2 to H2O or includes a reaction with carbon monoxide to convert carbon monoxide to carbon dioxide or both of these reactions.

[0040] The process further includes removing at least a portion of the H2S from the conditioned syngas stream to obtain a sour gas stream containing the H2S and obtain a treated gas stream having fuel value or utility as feedstock for chemical production, H2 production and the like.

[0041] The process then includes converting at least a portion of the H2S in the sour gas stream to elemental sulfur and removing the elemental sulfur and obtain a sulfur removal off gas.

[0042] Further details of the process are described below.

[0043] With respect to the gas stream that is processed or cleaned by the present embodiments, the gas stream, as indicated, can be an industrial gas stream. The industrial gas stream can be or includes a tail gas from one or multiple sources. For instance, the gas stream can include or be entirely or solely from tail gas generated during carbon black production.

[0044] The gas stream can include or be entirely or solely from one, two, or more carbon black production units (e.g., two or more carbon black reactors). There is no limit on the number of carbon black production units that can contribute to the gas stream that is processed by the present embodiments. The carbon black production units can be furnace black production units, plasma black production units, and / or other types of carbon black production units. The carbon black production units can be from units that are making the same, similar, or different grades of carbon black.

[0045] As an option, the gas stream that is processed by the present embodiments can further include gaseous fuel from non-carbon black production sources. For instance, the gas stream can include gas streams or gaseous fuel from one or more of the following sources as an option: biomass, natural gas, liquified petroleum gas (LPG) such as from oil fields, coal gas such as from coking processes, byproduct gas such as from steel furnaces, and / or other sources or similar sources as exemplified here.

[0046] As an example, the gas stream (i.e., starting gas stream) can comprise at least 25 vol%, at least 50 vol%, at least 75 vol%, at least 80 vol%, at least 90 vol%, at least 95 vol%, at least 99 vol%, or 100 vol% of a gas stream or tail gas from one or more carbon black production units.

[0047] The gas stream that is processed by the present embodiments can be a gas stream where at least 80 vol% (e.g., at least 85 vol%, at least 90 vol%, at least 95 vol%, at least 99 vol%, such as from 80 vol% to 99 vol% or 85 vol% to 99 vol%) of the gas stream is CO, CO2, N2, O2, H2,hydrocarbons, and water, and also includes trace amounts of sulfur species and nitrogen species, and optionally HC1 and PH3 and optionally particulates.

[0048] The gas stream that is processed by the present embodiments can be a gas stream where at least 80 vol% (e.g., at least 85 vol%, at least 90 vol%, at least 95 vol%, at least 99 vol%, such as from 80 vol% to 99 vol% or 85 vol% to 99 vol%) of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons, and water, and also includes trace amounts of sulfur species and nitrogen species, and potentially includes one or more of HC1, PH3, and particulates.

[0049] The particulates (e.g., solid particulates), for instance, can be carbon particulates and / or inorganic particulates of salts, such as 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).

[0050] The sulfur species can include, but are not limited to, H2S, COS, CS2, SO2, SO3, and / or C4H4S, and the like.

[0051] The nitrogen species can include, but are not limited to, HCN, NH3, NO, and / or NO2, and the like.

[0052] As a further example, the gas stream can include the following component concentrations: 3-30 vol% or more CO (e.g., from 3 to 25 vol%, from 3 to 20 vol%, from 3 to 15 vol% from 3 to 10 vol%, from 3 to 5 vol%, from 5 to 30 vol%, from 10 to 30 vol%, from 15 to 30 vol%, from 20 to 30 vol%),0.5-10 vol% or more CCh(e.g., from 0.5 to 7 vol%, from 0.5 to 5 vol%, from 0.5 to 2 vol%, from 1 to 10 vol%, from 2 to 10 vol%, from 3 to 10 vol%, from 5 to 10 vol%),3-50 vol% or more H2 (from 3 to 45 vol%, from 3 to 40 vol%, from 3 to 35 vol%, from 3 to 30 vol%, from 3 to 25 vol%, from 3 to 20 vol%, from 3 to 15 vol%, from 3 to 10 vol%, from 3to 5 vol%, from 5 to 50 vol%, from 10 to 50 vol%, from 15 to 50 vol%, from 20 to 50 vol%, from25 to 50 vol%, from 30 to 50 vol%, from 35 to 50 vol%, from 40 to 50 vol%),0.01-2 vol% or more O2 (e.g., from 0.01 to 1.5 vol%, from 0.01 to 1 vol%, from 0.01 to 0.5 vol%, from 0.01 to 0.1 vol%, from 0.01 to 0.05 vol%, from 0.02 to 2 vol%, from 0.05 to 2 vol%, from 0.07 to 2 vol%, from 0.1 to 2 vol%, from 0.5 to 2 vol%, from 0.7 to 2 vol%, from 1 to 2 vol%, from 1.25 to 2 vol%);0.5-10 vol% or more hydrocarbons (e.g., from 0.5 to 7 vol%, from 0.5 to 5 vol%, from 0.5 to 3 vol%, from 0.5 to 1 vol%, from 0.7 to 10 vol%, from 1 to 10 vol%, from 2 to 10 vol%, from 5 to 10 vol%, from 7 to 10 vol%),1-50 vol% or more water (e.g., from 1 to 45 vol%, from 1 to 40 vol%, from 1 to 35 vol%, from 1 to 30 vol%, from 1 to 25 vol%, from 1 to 20 vol%, from 1 to 15 vol%, from 1 to 10 vol%, from 1 to 5 vol%, from 2 to 50 vol%, from 5 to 50 vol%, from 10 to 50 vol%, from 15 to 50 vol%, from 20 to 50 vol%, from 25 to 50 vol%, from 30 to 50 vol%, from 35 to 50 vol%, from 40 to 50 vol%),50 ppm-10,000 ppm or more by volume sulfur species (e.g., from 50 to 7,000 ppm, from 50 to 5,000 ppm, from 50 to 2,500 ppm, from 50 to 2,000 ppm, from 50 to 1,500 ppm, from 50 to 1,000 ppm, from 50 to 750 ppm, from 50 to 500 ppm from 50 to 250 ppm, from 50 to 100 ppm, from 100 to 10,000 ppm, from 200 to 10,000 ppm, from 500 ppm to 10,000 ppm, from 1,000 to 10,000 ppm, from 2,000 to 10,000 ppm, from 3,000 to 10,000 ppm, from 5,000 to 10,000 ppm, from 7,000 to 10,000 ppm),50 ppm-20,000 ppm or more by volume nitrogen species (e.g., from 50 to 15,000 ppm, from 50 to 12,500 ppm, from 50 to 10,000 ppm, from 50 to 7,000 ppm, from 50 to 5,000 ppm, from 50 to 2,500 ppm, from 50 to 2,000 ppm, from 50 to 1,500 ppm, from 50 to 1,000 ppm, from 50 to 750 ppm, from 50 to 500 ppm from 50 to 250 ppm, from 50 to 100 ppm, from 100 to 20,000ppm, from 200 to 20,000 ppm, from 500 ppm to 20,000 ppm, from 1 ,000 to 20,000 ppm, from 2,000 to 20,000 ppm, from 3,000 to 20,000 ppm, from 5,000 to 20,000 ppm, from 7,000 to 20,000 ppm, from 10,000 to 20,000 ppm, from 12,500 to 20,000 ppm, from 15,000 to 20,000 ppm, from 17,500 to 20,000 ppm),0 to 20 ppm or more by volume HC1 (e.g., from 0.1 to 20 ppm, from 0.5 to 20 ppm, from 1 to 20 ppm, from 5 to 20 ppm, from 10 to 20 ppm, from 0.1 to 15 ppm, from 0.1 to 10 ppm, from 0.1 to 5 ppm, from 0.1 to 2.5 ppm),0 to 10 ppm or more by volume PH3 (e.g., from 0.1 to 10 ppm, from 0.5 to 10 ppm, from 1 to 10 ppm, from 5 to 10 ppm, from 0.1 to 7 ppm, from 0.1 to 5 ppm, from 0.1 to 2 ppm, from 0.1 to 1 ppm), and0 mg / Nm3to 80 mg / Nm3or more particulates (e.g., from 0.1 to 80 mg / Nm3, from 0.5 to 80 mg / Nm3, from 1 to 80 mg / Nm3, from 5 to 80 mg / Nm3, from 10 to 80 mg / Nm3, from 15 to 80 mg / Nm3, from 20 to 80 mg / Nm3, from 30 to 80 mg / Nm3, from 40 to 80 mg / Nm3, from 50 to 80 mg / Nm3, from 60 to 80 mg / Nm3, from 70 to 80 mg / Nm3, from 0.1 to 75 mg / Nm3, from 0.1 to 70 mg / Nm3, from 0.1 to 60 mg / Nm3, from 0.1 to 50 mg / Nm3, from 0.1 to 40 mg / Nm3, from 0.1 to 30 mg / Nm3, from 0.1 to 20 mg / Nm3, from 0.1 to 10 mg / Nm3, from 0.1 to 5 mg / Nm3).

[0053] The gas conditions of the gas stream that is processed are not critical. For any given unit process, if the incoming gas stream does not have the desired temperature or pressure, these are easily adjusted using methods known to those of skill in the art. For example, the gas in the gas stream to be processed can have a temperature from ambient (e.g., 20°C to 25°C) to 300°C or other temperatures. Likewise, the pressure of the gas stream to be processed can be 0 barg to 1 barg or other pressures outside of this range.

[0054] Regarding the step in the process of compressing the gas stream, at least one compressor can be utilized to achieve this step. More than one compressor can be used and / or the compressor can have multiple stages (multi-stage compressing).

[0055] Gas compression can be achieved with any commercially available compression equipment, such as, but not limited to, a centrifugal compressor, a Roots compressor, a screw compressor, a positive displacement compressor, and the like. The gas compression can be such that the gas is pressurized, such as by a booster fan or compressor.

[0056] One purpose of compressing the gas stream is to provide a desired pressure to the gas so as to overcome potential pressure drops in downstream steps of the process.

[0057] The compressing of the gas stream results in a compressed gas stream. The compressed gas stream has an elevated pressure above atmospheric or a gas pressure above the starting gas pressure entering the compressor(s). The elevated pressure can be from 0.5 to 100 barg or greater, such as from 0.5 to 50 barg, from 0.5 to 45 barg, from 0.5 to 40 barg, from 0.5 to 35 barg, from 0.5 to 30 barg, from 0.5 to 25 barg, from 0.5 to 20 barg, from 0.5 to 15 barg, from 0.5 to 10 barg, from 0.5 to 5 barg, from 1 to 90 barg, from 5 to 80 barg, from 10 to 70 barg, from 15 to 60 barg, from 20 to 50 barg, from 25 to 50 barg, from 30 to 50 barg, from 35 to 50 barg, from 40 to 50 barg.

[0058] As an option, the gas stream entering the compressing step (i.e., the raw gas) can be partially cooled at the inlet of the compressor or cooled in between multi-stage compressors (if used) and / or cooled after the last stage of compression. The compressed gas exiting the one or more compressors can have a temperature, due to cooling, of below 500°C, such as from 100°C to 500°C or other temperatures.

[0059] As an option, the gas stream or compressed gas stream can be subjected to fdtration of particulates 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 particulates present in the gas stream removed, such as byfiltration, using, for instance, one or more filtration beds, filter beds or other forms of mechanical filtration mechanisms such as, but not limited to, cartridge filter, bag filter, membrane filter, etc.

[0060] Besides removing some or most or all of the particulates (i.e., solid particulates) in the gas stream, at least a portion (some or most or all) of any catalyst poisons that may be present can be captured or removed at this stage of the process (e.g., a catalyst poison capture). Thus, this filtration step can 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 HC1 and / or PH3. Generally, the catalyst poisons are present in trace amounts (e.g., in amounts as described earlier).

[0061] By conducting such a filtration step and / or catalyst poison capture, which can be collectively referred to as gas conditioning or a gas conditioning unit operation, this can enable a more stable operation of the catalytic processes on the gas stream and / or enable the catalytic process to operate more efficiently and / or extend catalyst service life.

[0062] For the filtration of the particulates, one or more filtration beds loaded with filter media (which can be in the form of particulates) can be used. The filter particulate media can have various geometric shapes and sizes (e.g., spherical, extrudate, cylindrical, trilobes, rings, and the like). The removal of some or most or all of the particulates can prevent the plugging of the catalyst bed(s) described and used in downstream steps of the process. Filter particulate media that can be utilized in the one or more filter beds are commercially available, such as ceramic spheres, alumina particles, silica particles, silicon aluminate particles, activated carbon particles, zeolites, and / or refractory type particles etc. Particular examples of filter media can include various alumina types such as Y-AI2O3 or 01-AI2O3 of various pore structures and surface areas.

[0063] Different configurations of the filter bed(s) can be utilized. 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 (inseries) or one filter bed can be used and then a back-up filter bed can be used when the initial filter bed needs cleaning or regenerating or replacing. Generally, a filter bed is spent once a certain level of pressure increase occurs due to blockage. Those skilled in the art would appreciate when this occurs.

[0064] If parallel filtration is utilized where one filter bed is on standby, the filtration can be done with one filter bed until the pressure-drop increases to a target level, and a switch can be made to the standby filter bed to continue filtration of the particulates, and during this switch over, the spent filter media can be cleaned or replaced.

[0065] By filtration of the particulates from the gas stream, the gas stream can have particulates levels reduced by at least 10 wt%, for example, 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 from 10 to 99 wt%, from 50 to 99 wt% or from 75 to 99 wt%, or from 90 to 99 wt%, based on total weight of particulates existing prior to filtration. The particulate content of the gas stream, after particulate filtration, can be 50 mg / Nm3or lower, below 40 mg / Nm3, below 30 mg / Nm3, below 20 mg / Nm3, below 10 mg / Nm3, below 5 mg / Nm3, below 1 mg / Nm3, such 0.01 mg / Nm3to 50 mg / Nm3or from 0.01 mg / Nm3to 10 mg / Nm3, or from 0.01 mg / Nm3to 5 mg / Nm3, or from 0.01 mg / Nm3to 1 mg / Nm3.

[0066] Regarding the capture of catalyst poisons, the catalyst poisons can be at least partially captured with the use of one or more types of adsorbents that can be present in an adsorption vessel or container or bed. The adsorbent can be a multifunctional adsorbent or a mixture of two or more adsorbents (e.g., special adsorbents) that are capable of capturing or trapping or adsorbing or otherwise retaining at least a portion catalyst poisons, which as indicated, are or include HC1 and / or PH3. The level of removal desired is a level that permits the downstream use of catalyst for an acceptable or extend service life.

[0067] When multiple adsorbents are used, the adsorbents can be loaded into separate vessels in series, or they can be loaded in the same vessel in layers or loaded together as a mixture of adsorbents.

[0068] Any commercially available sorbent or adsorbent with the desired function, described herein, can be used. The sorbents or adsorbents can be porous materials. The adsorbents can be, but are not limited to, alumina, silica, silica aluminate, magnesium oxide(s). The adsorbent or sorbents can be optionally modified with alkaline and / or alkaline earth metal oxides for improved performance. Examples of commercially available materials include calcium oxide modified alumina, magnesium modified alumina, Na2O / AhO3, K2O / AI2O3, high surface area y-alumina, etc. Commercially available examples include SHIFTGUARD 200 absorbent from Clariant AG, TK-3000 catalyst / sorbent and HTG-10 absorbent from Topsoe A / S, and ET-17 and EG-2 catalysts / sorbents from Haiso Technology Co.

[0069] Alternatively or in addition, other scrubbing technologies, optionally including filtration technologies, may be used as well. For example, wet scrubbers using water or a neutralizing solution may be used to remove catalyst poisons and optionally partictulates. Such scrubbers may be in the form of a venturi, a packed tower, a spray tower, or other configurations known to those of skill in the art.

[0070] By capturing or removing at least a portion of the catalyst poisons, the amount of catalyst poisons, such as HC1 and / or PH3 afterwards can 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 from 50 to 99 vol% or from 75 to 99 vol%, or from 90 to 99 vol%. The catalyst poison content as defined by HC1 and / or PH3 in the exiting gas stream, after poison capture, can be below 5 ppm for each of HC1 and / or PH3, and more preferably below 1 ppm for each of HC1 and / or PH3.

[0071] Preferably, the particulate filtration step if used occurs prior to the capturing of catalyst poisons, for example prior to the gas compression step.

[0072] Preferably, the capturing of the catalyst poisons if used occurs after the particulate filtration step if used, for example, prior to the gas compression step.

[0073] The step of capturing the catalyst poisons and / or the particulate filtration can be conducted at a temperature of from about 100°C to about 500°C. Other temperatures outside of this range are possible.

[0074] Regarding the step of conducting several reactions to the gas stream or compressed gas stream, preferably this part of the process occurs with the compressed gas stream.

[0075] The conducting of the at least one hydrolysis reaction to obtain at least H2S can be in the form of one reaction or multiple reactions using the same or different catalyst. At least one hydrolysis catalyst can be utilized. In this hydrolysis reaction, at least one or more sulfur species in the gas stream, such as CS2 and / or COS and / or organic sulfur are converted to H2S through one or more hydrolysis reactions with water or moisture in the gas stream.

[0076] The hydrolysis reaction preferably includes one or both of the following reactions:CS2+ 2H2O - 2H2S + CO2COS+H2O H2S +CO2

[0077] The conducting of the at least one hydrogenation reaction to convert at least one of SO2 and SO3 to H2S can be in the form of one reaction or multiple reactions using the same or different catalyst. At least one hydrogenation catalyst can be utilized. In this hydrogenation reaction, at least one or more sulfur species in the gas stream, such as SO2 and / or SO3 are converted to H2S through one or more hydrogenation reactions with hydrogen in the gas stream.

[0078] The hydrogenation reaction preferably includes one or both of the following reactions:S02+ 3H2- H2S + 2H2OS03+ 4H2H2S + 3H2O.

[0079] The percent of conversion (from either or both of the hydrolysis and hydrogenation reactions) from the sulfur species to H2S is preferably at least 50% or at least 60%, or at least 70% or at least 80%, or at least 90% based on starting ppm levels of the sulfur species. The percent of conversion can be from 50% to 99% or more based on starting ppm levels of the sulfur species.

[0080] The conducting of the at least one hydrolysis reaction can further include a reaction to convert HCN to NH3. The at least one hydrolysis catalyst as identified earlier or an additional hydrolysis catalyst can be utilized for this particular reaction. In this additional hydrolysis reaction, HCN in the gas stream (e g., at least a portion thereof) is converted to NH3 with water in the gas stream.

[0081] The percent of conversion 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 starting ppm levels of the HCN. The percent of conversion can be from 50% to 99% or more based on starting ppm levels of the HCN.

[0082] The additional hydrolysis reaction preferably includes the following reaction:HCN + H2O - NH3+ CO.

[0083] This part of the process can further include conducting at least one reduction reaction on the compressed gas stream or the conditioned syngas stream to convert at least a portion of the nitrogen containing species to N2. In this part of the process, NO and / or N0xin the gas stream (or at least a portion thereof) can be converted to nitrogen gas (N2) through a reduction reaction(s). A reduction reaction catalyst(s) can be used for this reaction.

[0084] With the reduction reaction, 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 from 50 vol% to 99 vol% or higher, or 60 vol% to 99 vol%, or 70 vol% to 99 vol%, or 80 vol% to 99 vol%, 90 vol% to 99 vol%, 95 vol% to 99vol%) of the NO and / or NOXpresent in the gas stream just prior to this reaction can be converted to N2.

[0085] The conducting at least one oxygen conversion reaction to remove O2 from the compressed gas stream can be in the form of one reaction or multiple reactions using the same or different catalyst. At least oxygen converting catalyst can be utilized. In this oxygen conversion reaction, the oxygen conversion reaction comprises, consists of, or includes a further hydrogenation reaction to convert O2 to H2O with hydrogen in the gas stream, or includes a reduction reaction to convert carbon monoxide to carbon dioxide with oxygen gas in the gas stream, or both of these reactions. In the reduction reaction, this can be considered a reaction to convert O2 to carbon dioxide with CO in the gas stream. Thus, in each of the possible reactions, oxygen is being converted to either H2O or carbon dioxide or both. Removal of oxygen is preferred to prevent oxidation of amines used to remove H2S during sour gas capturing, as described below. However, if a sour gas capturing system that is less affected by oxygen is employed, or the tail gas contains sufficiently low amounts of oxygen, e.g., no more than 0.2 vol%, then oxygen conversion is optional.

[0086] The percent of conversion from oxygen gas to either 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 starting volume % levels of the oxygen gas. The percent of conversion can be from 50% to 99% or more based on starting volume % levels of the oxygen gas.

[0087] The oxygen converting reaction preferably includes one or both of the following reactions:O2 + 2H2 — 2H2O

[0088] As a result of the oxygen converting reactions, an Ch-poor gas stream is obtained.

[0089] With respect to the at least one hydrolysis reaction, the at least one hydrogenation reaction, and the oxygen converting reaction, and optionally the reduction reaction, any commerciallyavailable catalyst(s) possessing the described functionality can be used. A combination of catalyst 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.

[0090] The desired reaction temperature for these reactions can be from about 150°C to about 350°C or other temperatures outside of this range. If the gas stream from upstream is at a temperature outside of the desired range, a heat exchanger (i.e., heater) or other means to achieve this desired temperature range can be utilized prior to conducting these reactions.

[0091] The reactions can be conducted or achieved with a reactor or reactor vessel (or multiple reactor vessels) which can contain the catalyst or combination of catalyst. 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(s) can be fixed bed reactors that house or contain the one or more mentioned catalyst.

[0092] In the alternative, the reactors, when more than one is used, and each have a different catalyst for a different reaction, can be arranged in series.

[0093] Any configuration of reactors (e.g., fixed bed reactors) known to those skilled in the art can be utilized. The configuration can be an up-flow, or down-flow, axial flow, radial flow, or horizontal flow.

[0094] After the hydrogenation and hydrolysis, the gas stream, which can be considered a conditioned syngas stream, generally contains mainly H2, CO, CO2, N2, H2S, NH3, H2O and amounts (e.g., small amounts) of any other unconverted components carried in with the raw gas stream, such as sulfur compounds and / or N species. The H2, CO, CO2, N2, H2S, NH3, H2O combined comprise over 50 vol%, over 60 vol%, over 70 vol%, over 80 vol%, over 90 vol%, over 95 vol% (e.g., from 50 vol% to 99 vol% or 75% vol to 99 vol%) of the conditioned syngas stream.

[0095] The next step can then be removing at least a portion of the H2S from the conditioned syngas stream to obtain a sour gas stream containing H2S and also obtain a treated gas stream having fuel value. This step can in part be referred to as sour gas capturing and can be achieved with a sour gas capturing unit. Optionally, a water gas shift reaction may be performed on the conditioned syngas stream prior to the sour gas capturing.

[0096] The optional water gas shift reaction can be considered a CO-water gas shift reaction and can be one or more reactions. When employed, the water gas shift reaction preferably occurs after the aforementioned hydrolysis reaction(s) and after the aforementioned hydrogenation reaction(s) and aforementioned oxygen conversion reaction.

[0097] One or more of the hydrolysis and hydrogenation reactions can optionally continue during the water gas shift reaction, if it has not been completed prior to the water gas shift reaction occurring. Alternatively or in addition, some of the water gas shift reactions described below may take place during hydrolysis and / or hydrogenation.

[0098] The water gas shift reaction converts carbon monoxide in the gas stream (at least a portion thereof) to carbon dioxide through reaction with water in the gas stream so as to produce hydrogen gas (H2) via an exothermic reaction.

[0099] The water gas shift reaction preferably includes the following reaction:

[0100] Since the gas stream, at this stage, contains sulfur in the form of H2S and / or other unconverted sulfur species, the catalyst utilized for this reaction needs to be tolerant to sulfur poisoning (i.e., a sulfur-resistant catalyst). Thus, the water gas shift reaction is achieved by utilizing at least one sulfur-resistant catalyst that converts CO and H2O to CO2 and H2.

[0101] Sulfur-resistant 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 catalystfrom Haiso Technology Co., and KATALCO KB-11 and KATALCO K8-11 HA from Johnson Matthey.

[0102] The WSGR catalyst can be formed of a metal sulfide of cobalt, iron, molybdenum, and / or nickel. The WSGR catalyst can be loaded on porous supports, such alumina, silica, or similar support materials. The WSGR catalyst can be in the form of extrudates, pellet, spheres, rings, and / or any other shapes to promote mass transfer and / or minimize pressure drop.

[0103] The WSGR catalyst can be pre- sulfurized before loading or obtained in the oxide form and sulfurized in place after loaded into the reactor. To enable the on-site sulfurization, an auxiliary system can be used to supply the reagents (such as CS2, COS, etc.) and heat to enable proper sulfurization before introduction of the gas stream. Catalyst suppliers generally provide detailed procedures for such an on-site sulfurization process.

[0104] The sour gas capturing separates H2S out from the gas stream (e.g., the conditioned syngas stream or the conditioned syngas stream as processed by the water gas shift reaction) to produce a sour gas stream containing H2S, some amount of carbon dioxide, and some moisture. The rest of the gas components, not separated out, can be considered a treated gas stream having fuel value. This treated gas stream can be sent to a combustor for heat recovery, or processed with other widely known technology such membrane, pressure swing adsorption (PSA), and the like to produce a marketable pure hydrogen product (e.g., hydrogen gas having a purity of at least 95 vol% or at least 99 vol%), or employed in any other process that can derive value from or add value to the treated gas stream.

[0105] Separation of H2S from the gas stream (i.e., the conditioned syngas stream) can be done with many commercially available technologies.

[0106] Examples of such technologies include, but are not limited to: amine scrubbing technology, methanol absorption, glycol absorption, and pressure swing adsorption for sour gas capture.

[0107] Regarding amine scrubbing technology, in this process, a gas stream, conditioned 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 brought in contact with an amine solution in a column. Various types of contacting columns can be used, such as a tray column, random packed column, structured packing or any combination of these. H2S (or at least a portion thereof) and some amount of carbon dioxide are absorbed onto the amine compound(s) and the other components in the gas stream pass through this column as a product stream. The amine solution with absorbed H2S can be transferred to another column, where heat can be added to promote the desorption of H2S from the amine solution. A regenerated amine stream, after temperature adjustment (e.g., 30-60°C), is circulated back to the absorption column for further H2S absorption. The heat input can depend on the type of sorbent and design conditions utilized. The H2S released from the desorption process produces a sour gas stream that can be processed in the next unit operation.

[0108] Solvents that can be used in this 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., methyl diethanolamine (MDEA)). The sorbent can be an aqueous solution having a concentration (e.g., 5-50 wt%) of one or more amines. One or more additives having different functions can be additionally used and, for instance, can be blended in with the sorbent to improve corrosivity and / or absorption efficiency and / or to achieve one or more other performances.

[0109] A conditioning step for the gas stream (i.e., the conditioned syngas stream) can be conducted, for instance, where, prior to entering the absorption unit for sour gas capturing, the gasstream is cooled and as a result, condensate may form as the gas stream is cooled below its dew point. This water condensate stream can be used in carbon black production as quenching water and / or other process water uses.

[0110] Another process that can be used for the sour gas capturing is one or more absorptions with the use of one or more solvents, such as methanol or a glycol or alkaline salt solution. This process is very similar to the amine absorption process. Commercially available sour gas absorption units / techniques can be adopted for this part of the process of the present embodiments. Commercially available units include those from Shell, Mitsubishi Heavy Industries, Honeywell / UOP, Linde, Technip, and many other technology suppliers, and engineering EPC (engineering, procurement, and construction) firms.

[0111] Another process / technique that can used for sour gas capturing includes pressure swing adsorption (PSA). For this PSA, a solid adsorbent(s) can be used to capture H2S at elevated pressures (e.g., a pressure of 2 barg to 100 barg), and then the solid adsorbent can be desorbed using reduced pressures (e.g., atmospheric pressure to 100 barg) to obtain a concentrated H2S stream and also obtain a clean gas stream with low amounts of H2S. For example, the clean gas stream may include the treated gas and may contain up to 20 ppmv H2S, for example, up to 10 ppmv, up to 5 ppmv, or up to 1 ppmv H2S, or less. As indicated, the concentrated H2S stream can be considered the sour gas stream, and the clean gas stream can be considered the treated gas stream having fuel value. The heating value of the treated gas can depend on the raw gas composition. For the clean gas stream, the treated gas heating value can be from about 2 to about 6 MJ / Nm3or other values below or above this range. If other gas sources (such as biomass syngas, coke oven gas) are blended into the starting feed, the heating value range can be above or below this range.

[0112] Since the clean gas stream can still contain NOx-forming components (e g., ammonia), NOx removal technology or steps can optionally be implemented if the clean gas stream is burned for any reason to generate a flue gas. Exemplary NOx removal processes include, but are not limited to, injection of ammonia or urea into a flue gas stream and selective catalytic reactor (SCR) processes known to those of skill in the art, including but not limited to methods described in US9192891, the entire contents of which are incorporated herein by reference. Alternatively to or in addition, a selective non-catalytic reactor (SNCR) process including, but not limited to, methods described in the ‘891 patent may be used to remove NOx from a flue gas. Because SCR and SNCR processes operate most efficiently in particular temperature ranges (typically 275-500 °C and 900- 1050 °C, respectively), those of skill in the art may adjust the temperature of a flue gas using boilers, heat exchangers, and other conventional apparatus to allow the selected process(es) to operate more effectively. Alternatively or in addition, a catalytic process such as that described in EP2561921, the contents of which are incorporated herein by reference, or commercially available processes such as the SNOX™ process from Haldor Topsoe may also be employed. Alternative methods known to those of skill in the art may also be employed.

[0113] Once the sour gas stream is obtained, the next step in the process can be to convert at least a portion of the EES in the sour gas stream to elemental sulfur and then remove the elemental sulfur so as to obtain a sulfur removal off gas.

[0114] Various commercially available technologies can be used for this converting to sulfur step, such as, but not limited to, liquid phase catalytic oxidation technology or gas phase combustion technology, and the like. The gas phase combustion process can utilize a Claus process, for example, as described in US3719744, incorporated in its entirety by reference herein, that converts H2S and SO2 to H2O and S2.

[0115] The relatively low concentration of H2S in the sour gas stream can be more adequately processed with liquid phase oxidation technology than with other processes, e.g., a Claus process. In a liquid phase oxidation process, a gas mixture of H2S and H2O and possibly CChis brought in contact with an aqueous solution of iron catalyst in a reactor column. The 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 bubbles 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 column to promote H2S oxidation. Elemental sulfur produced in this oxidation process forms crystalline sulfur suspended in the aqueous liquid solution. A slip stream of this solution is sent to a liquid-solid separator, such as a belt filter, press and frame filter or any other type of separator to produce a solid sulfur product which is marketable (or useable material).

[0116] FIG. 1 sets forth a flow diagram of a process 100 of the present embodiments that can be utilized. In step 110, a gas stream that includes tail gas, such as tail gas generated during carbon black production or manufacturing is obtained.

[0117] In optional step A, the gas stream can have at least some of the particulates and / or catalyst poisons removed from the gas stream. This can occur before and / or after the step 115 of compressing the gas stream that forms a compressed gas stream.

[0118] In step 120, the compressed gas stream is subjected to at least one hydrolysis reaction so as to form at least EES and convert HCN, if present, to NH3.

[0119] In step 125, the compressed gas stream is subjected to at least one hydrogenation reaction to form at least EES from at least SO2 and / or SO3.

[0120] In step 130, the compressed gas stream is subjected to at least one oxygen conversion reaction to remove oxygen (O2). This reaction can be a further hydrogenation reaction to convertO2 to H2O and / or a reduction reaction to convert CO to CO2.

[0121] Steps 120, 125, and 130 can occur in any order. Preferably, step 130 is performed after steps 120 and 125 to obtain a Ch-poor gas stream, which can be considered a conditioned syngas stream.

[0122] In step 140, the conditioned syngas stream is subjected to a process to remove at least a portion of the H2S and form two gas streams, where in step 145, a treated gas stream with fuel value is recovered / obtained and in step 150, a sour gas stream containing H2S is obtained or recovered or separated from the treated gas stream.

[0123] In step 155, at least a portion of the H2S in the sour gas stream is converted to elemental sulfur and in step 160, can be recovered or removed or separated from the rest of this gas stream.

[0124] The above process to clean the gas stream can be achieved in a facility or system that is set up to conduct the various steps described herein. Thus, the present embodiments further relate to a system and / or facility to clean a gas stream that includes tail gas generated during carbon black production.

[0125] The facility includes at least compressor unit or at least one compressor for compressing the gas stream so as to obtain a compressed gas stream.

[0126] The facility further includes a catalytic converter unit comprising one or more fixed bed reactors that are configured for conducting the above mentioned at least one hydrolysis reaction to obtain at least H2S and conducting at least one hydrogenation reaction to obtain at least H2S, and conducting at least one oxygen conversion reaction to remove O2 from the gas stream or compressed gas stream.

[0127] The facility also includes a sour gas capturing unit for removing at least a portion of the H2S from the conditioned syngas stream to obtain a sour gas stream containing the H2S and obtain a treated gas stream having fuel value.

[0128] The facility also includes a sulfur conversion unit for converting at least a portion of the H2S in the sour gas stream to elemental sulfur and removing the elemental sulfur and obtain a sulfur removal off gas.

[0129] The facility can further include a gas conditioning unit for removing particulates and / or catalyst poisons from the gas stream or the compressed gas stream as described herein.

[0130] The gas conditioning unit of the facility can be or include at least one filtration bed and at least one adsorbent, wherein the at least one filtration bed and the at least one adsorbent are in a same vessel or are in different vessels.

[0131] The one or more fixed bed reactors can include or comprise at least one hydrogenation catalyst, at least one hydrolysis catalyst, and at least one sulfur-resistant catalyst.

[0132] The facility can further include or comprise at least one cooling device for controlling temperature of the gas stream passing through the catalytic converter unit or exiting the catalytic converter unit or both.

[0133] The sour gas capturing unit can be or include an amine scrubber, a sour gas absorption unit with non-amine solvent(s), or a pressure swing adsorption unit or any combinations thereof.

[0134] The facility can further include at least one cooling device(s) for controlling temperature of the gas stream exiting the at least one compressor, as described herein.

[0135] Referring to FIG. 2, in a schematic presentation, one possible set up for a facility or system to conduct the process of the present embodiments is exemplified. Variations of this facility can be employed as described herein.

[0136] In FIG. 2, unit operations are provided for the facility or system 200. A first unit operation 202 that is gas stream or tail gas compression is provided. A gas stream 220 that can include raw tail gas that is separated from carbon black after leaving a carbon black furnace can be obtained and fed to the first unit operation 202 . This gas stream is fed into a device 222 tocompress the gas stream and / or pressurize the gas stream. Device 222 may be, e.g., a fan, compressor, or other device that can bring the gas stream to a desired pressure to either just high enough to overcome the pressure drop of the downstream processes or to higher pressure for better efficiency.

[0137] Installation of a device(s) (not shown in FIG. 2) to remove particulates and / or catalyst poisons from the gas stream can be used in the facility. For instance, a filtration column or other device, upstream or downstream of the device 222 used to compress the gas stream (e.g., booster fan), can be packed with solid particulates in various shapes and / or sizes can be used and is optional. The part of facility or system is optionally used for trapping the particulates, such as carbon black particulates and / or other particulates to prevent or reduce the risk of downstream plugging of other units, such as the one or more catalytic reactors.

[0138] Depending on the gas purity, a guard bed 205, scrubber, or other device can be installed downstream of device 222 or other unit to compress the gas stream (e.g., booster fan) to remove catalyst poisons such as hydrogen chloride, phosphorous hydride etc. Boilers and heat exchangers may be used before or after these devices to bring the gas temperature and pressure to a desired level.

[0139] In a second unit operation 204, the compressed gas stream or tail gas is conditioned to achieve hydrolysis and hydrogenation (e.g., as shown in the equations below) using a multifunctional catalyst or a combination of catalysts with desired functionalities. In this second unit operation 204, devices (e.g., hydrolysis device 224 and hydrogenation device 226) are used to achieve at least one hydrolysis reaction, at least one hydrogenation reaction and to conduct at least one oxygen conversion reaction. The following one or more reactions can take place in the second unit operation in one or multiple devices that can be arranged in series to each other.Hydrolysis:CS2+ 2H2O 2H2S + C02COS+H2O H2S +CO2HCN + H20 NH3+ CO.Hydrogenation:SO2+ 3H2H2S + 2H2OO2 + H2 > H2O

[0140] In a third unit operation 208, carbon dioxide and hydrogen sulfide are captured via an amine scrubbing system from the off gas from the unit operation 204 to produce a treated gas stream 244 having high fuel value, such as a high hydrogen content fuel with a high heating value. The gas leaving unit operation 204 transfers heat to an amine solution in a boiler 234 and is directed to a cooler 242. The cooled gas is directed to column 240 where it contacts the amine solution which adsorbs hydrogen sulfide, with condensed water 241 discharged and potentially beneficially used within the carbon black manufacturing process, e.g., as quench water, or where needed in the various unit processes. The cleaned tail gas 244 has high energy value and can be directed to a variety of beneficial uses, for example, ground incinerator 260, which may be used to generate hot gas for optional waste heat boiler 262, with the cooled gases discharged. The dirty amine solution leaves column 240 and is heated in heat exchanger 238 before being directed to regeneration column 236, where hydrogen sulfide and carbon dioxide are desorbed from the amine solution to form a sour gas that is directed to unit operation 210. The regenerated amine solution is passed through a boiler (e.g., boiler 234 or a separate boiler) and reheated. The regenerated amine solution is cooled in heat exchanger 238 and optional further heat exchangers before being redirected tocolumn 240. In preferred embodiments, the removal efficiency of hydrogen sulfide is at least 99% (by vol) or the concentration of hydrogen sulfide in the treated gas is, for instance, at most 1 ppm.

[0141] In a fourth unit operation 210, a gas containing hydrogen sulfide is removed from the sour gas stream, concentrated, and converted to elemental sulfur through one or processes, such as the liquid phase process described above, which can utilize an oxidation reactor, catalyst regenerator, and liquid-solid separator (all not shown) to remove sulfur 256 from the gas stream directed to unit operation 210. The buffer tank and pumps move the liquid catalyst through the various apparatus of unit operation 210. Unit operation 210 may also include a filtration step to at least partially dry the resulting sulfur 256. In preferred embodiments, elemental sulfur generated in the fourth unit operation has a purity of at least 99% (solid basis, by weight).

[0142] H2S can be captured through a single unit operation of sour gas absorption from the product tailgas stream exiting unit process 204. The sour gas stream can be processed in the next unit operation to oxidize H2S to elemental sulfur as a marketable product. This oxidation step captures sulfur from the sour gas stream and produces a clean moisture-containing sulfur removal off-gas stream 258 that can be discharged to atmosphere. The concentration of carbon dioxide in this stream may be high enough to warrant compressing or otherwise beneficially using off-gas stream 258.

[0143] The tail gas volume flow is significantly smaller than the flow of the combusted flue gas or starting gas stream. Therefore, a reduced amount of equipment is required to process the tail gas. Likewise, a reduced amount of sorbent is required, further reducing the resulting amount of solid pollutant. Cooling the tail gas produces condensate that can be used in other unit processes in the carbon black production process.

[0144] Implementation of the present embodiments include the following aspect / embodiment / features in any order and / or in any combination:

[0145] 1 A process to clean a gas stream comprises tail gas generated during carbon black production, said process comprising compressing the gas stream to obtain a compressed gas stream; conducting at least one hydrolysis reaction to obtain at least H2S, conducting at least one hydrogenation reaction to convert at least one of SO2 and SO3 to H2S, and optionally conducting at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining a conditioned syngas stream; removing at least a portion of said H2S from said conditioned syngas stream to obtain a sour gas stream containing said H2S and obtain a treated gas stream having fuel value; and converting at least a portion of the H2S in said sour gas stream to elemental sulfur and removing said elemental sulfur and obtain a sulfur removal off gas; wherein the at least one oxygen conversion reaction either comprises a further hydrogenation reaction to convert O2 to H2O or a reaction to convert carbon monoxide to carbon dioxide or both.

[0146] 2. The process of any preceding or following embodiment / feature / aspect, wherein prior to conducting said at least one hydrolysis reaction, said at least one hydrogenation reaction, removing at least a portion of any particulates and / or catalyst poisons from said gas stream or said compressed gas stream.

[0147] 3. The process of any preceding or following embodiment / feature / aspect, prior to removing, further comprising conducting at least one water gas shift reaction on the conditioned syngas stream.

[0148] 4. The process of any preceding or following embodiment / feature / aspect, wherein said at least one water gas shift reaction is achieved by utilizing at least one sulfur-resistant catalyst that converts CO and H2O to CO2 and H2.

[0149] 5 The process of any preceding or following embodiment / feature / aspect, wherein said gas stream consists of said tail gas generated during carbon black production.

[0150] 6. The process of any preceding or following embodiment / feature / aspect, wherein said gas stream is from two or more carbon black production units.

[0151] 7. The process of any preceding or following embodiment / feature / aspect, wherein said gas stream further comprises gaseous fuel from non-carbon black production sources.

[0152] 8. The process of any preceding or following embodiment / feature / aspect, wherein at least 80 vol% of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons, and water, and also includes trace amounts of sulfur species and nitrogen species, and optionally HC1 and PH3 and optionally particulates.

[0153] 9. The process of any preceding or following embodiment / feature / aspect, wherein at least 80 vol% of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons, and water, and also includes trace amounts of sulfur species and nitrogen species, and optionally one or more of HC1, and PH3 and particulates.

[0154] 10. The process of any preceding or following embodiment / feature / aspect, wherein the gas stream includes the following component concentrations:3-30 vol% CO,0.5-10 vol% CO2,3-50 vol% H2,0.01 -2 vol% O2,0.5-10 vol% hydrocarbons,1-50 vol% water,50 ppm-10,000 ppm by vol sulfur species,50 ppm-20,000 ppm by vol nitrogen species,0 to 20 ppm by vol HC1,0 to 10 ppm by vol PH3, and0 mg / Nm3to 80 mg / Nm3particulates.

[0155] 11. The process of any preceding or following embodiment / feature / aspect, wherein said compressing utilizes at least one compressor.

[0156] 12. The process of any preceding or following embodiment / feature / aspect, where said at least one hydrolysis reaction is achieved by utilizing at least one hydrolysis catalyst.

[0157] 13. The process of any preceding or following embodiment / feature / aspect, where said at least one hydrogenation reaction is achieved by utilizing at least one hydrogenation catalyst.

[0158] 14. The process of any preceding or following embodiment / feature / aspect, wherein said removing of the at least a portion of any particulates and / or catalyst poisons from said gas stream or said compressed gas stream comprising passing said gas stream or compressed gas stream through at least one filtration bed and / or through at least one adsorbent.

[0159] 15. The process of any preceding or following embodiment / feature / aspect, wherein said removing at least a portion of said H2S from said conditioned syngas stream is achieved by utilizing an amine scrubber, sour gas absorption with non-amine solvent(s), or pressure swing adsorption.

[0160] 16. The process of any preceding or following embodiment / feature / aspect, wherein said converting of at least a portion of the H2S in said sour gas stream to elemental sulfur is achieved by utilizing a liquid phase catalytic oxidation process or gas phase combustion process.

[0161] 17. The process of any preceding or following embodiment / feature / aspect, wherein said gas phase combustion process utilizes a Claus process that converts H2S and SO2 to H2O and S2.

[0162] 18. The process of any preceding or following embodiment / feature / aspect, wherein during and / or immediately after said compressing, the gas stream and / or compressed gas stream is cooled.

[0163] 19. The process of any preceding or following embodiment / feature / aspect, wherein said removing of the at least a portion of 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 HC1 and less than 5 ppm by volume PH3.

[0164] 21. The process of any preceding or following embodiment / feature / aspect, said process further comprising conducting at least one reduction reaction to the compressed gas stream or the conditioned syngas stream to convert at least a portion of the nitrogen containing species to N2.

[0165] 22. The process of any preceding or following embodiment / feature / aspect, wherein said at least one hydrolysis reaction converts sulfur species in the compressed gas stream to H2S, and said sulfur species include CS2, COS, and organic sulfur.

[0166] 23. The process of any preceding or following embodiment / feature / aspect, wherein said at least one hydrolysis reaction further converts HCN to NH3.

[0167] 24. The process of any preceding or following embodiment / feature / aspect, wherein said at least one hydrogenation reaction converts SO2, and SO3 to H2S and converts O2 to either H2O or CO2 or both.

[0168] 25. A facility to clean a gas stream comprising tail gas generated during carbon black production, said facility comprising: at least one compressor for compressing the gas stream so as to obtain a compressed gas stream; a catalytic converter unit comprising one or more fixed bed reactors that are configured for conducting at least one hydrolysis reaction to obtain at least H2S and conducting at least one hydrogenation reaction to obtain at least H2S, and obtain a conditioned syngas stream;a sour gas capturing unit for removing at least a portion of said H2S from said conditioned syngas stream to obtain a sour gas stream containing said H2S and obtain a treated gas stream having fuel value; and a sulfur conversion unit for converting at least a portion of the H2S in said sour gas stream to elemental sulfur and removing said elemental sulfur and obtain a sulfur removal off gas.

[0169] 26. The facility of any preceding or following embodiment / feature / aspect, said facility further comprising a gas conditioning unit for removing particulates and catalyst poisons from said gas stream or said compressed gas stream.

[0170] 27. The facility of any preceding or following embodiment / feature / aspect, wherein said one or more fixed bed reactors comprise at least one hydrogenation catalyst and at least one hydrolysis catalyst

[0171] 28. The facility of any preceding or following embodiment / feature / aspect, wherein said catalytic converter unit comprises one or more fixed bed reactors that is configured to convert oxygen to water.

[0172] 29. The facility of any preceding or following embodiment / feature / aspect, wherein said one or more fixed bed reactors comprises at least one sulfur-resistant catalyst.

[0173] 30. The facility of any preceding or following embodiment / feature / aspect, wherein the catalytic converter unit comprises one or more fixed bed reactors that are configured to conduct at least one water gas shift reaction.

[0174] 31 The facility of any preceding or following embodiment / feature / aspect, wherein the gas conditioning unit comprises at least one filtration bed and at least one adsorbent, wherein the at least one filtration bed and the at least one adsorbent are in a same vessel or different vessels.

[0175] 32. The facility of any preceding or following embodiment / feature / aspect, wherein said sour gas capturing unit comprises an amine scrubber, a sour gas absorption unit with non-amine solvent(s), or a pressure swing adsorption unit.

[0176] 33. The facility of any preceding or following embodiment / feature / aspect, wherein said sour gas capturing unit is configured to use a liquid phase catalytic oxidation process or a gas phase combustion process.

[0177] 34. The facility of any preceding or following embodiment / feature / aspect, wherein said sulfur conversion unit is configured to use a Claus process that converts H2S and SO2 to H2O and S2.

[0178] 35. The facility of any preceding or following embodiment / feature / aspect, wherein said facility further comprises at least one cooling device for controlling temperature of the gas stream exiting the at least one compressor.

[0179] EXAMPLE

[0180] To quantitatively demonstrate the process of the present embodiments, a simulation was conducted using Aspen simulation and based on aggregated tail gas data from carbon black production facilities. In the simulation, the operation unit set up similar to that in Figure 2 was used.Table 1A:Table IB

[0181] As shown in Tables 1A and IB, the sulfur amount in the starting gas stream is almost completely removed with only 2 ppm COS and 6 ppm of CS2 in the cleaned tailgas 244. The process, in the simulation, produced 695 kg / h of marketable elemental sulfur containing around 42wt% of water The purity of the recovered components would also meet desired disposal specifications for commercial sale for use by third parties.[00182J More specifically, in this model process, a hypothetical tail gas, that is representative for commonly used carbon black production process, containing 1218 ppmvw of hydrogen sulfide, 209 ppmvw of SO2, 274 ppmvw of COS, 668 ppmvw of CS2, 34 vol% nitrogen, 15 wt% hydrogen, 1.5 vol% carbon dioxide, and 39% water, with other components listed in Table 1 A, was processed to generate a cleaned tail gas containing 50 mol% nitrogen, 29 mol% hydrogen, about 9 mol%water, about 4.6 mol% carbon dioxide, and other components as listed in Table IB. A 92% carbon dioxide stream (balance water) was generated for further processing, such as compression, dewatering, liquification etc. for sequestration or use in other beneficial processes. Water generated during the process can be beneficially used in the gas treatment process or in the carbon black production process, for example, as quench water.

[0183] The present embodiments can include any combination of these various features or embodiments above and / or below as set forth in any sentences and / or paragraphs herein. Any combination of disclosed features herein is considered part of the present embodiments and no limitation is intended with respect to combinable features.

[0184] The applicant specifically incorporates the entire contents of all cited references in this disclosure. Further, when an amount, concentration, or other value or parameter is given as either a range, preferred range, or a list of upper preferable values and lower preferable values, this is to be understood as specifically disclosing all ranges formed from any pair of any upper range limit or preferred value and any lower range limit or preferred value, regardless of whether ranges are separately disclosed. Where a range of numerical values is recited herein, unless otherwise stated, the range is intended to include the endpoints thereof, and all integers and fractions within the range. It is not intended that the scope of the embodiments be limited to the specific values recited when defining a range.

[0185] Other embodiments of the present implementations will be apparent to those skilled in the art from consideration of the present specification and practice of the present embodiments disclosed herein. It is intended that the present specification and examples be considered as exemplary only with a true scope and spirit of the embodiments being indicated by the following claims and equivalents thereof.

[0186] The foregoing description of preferred implementations of the present embodiments has been presented for the purposes of illustration and description. Modifications and variations are possible in light of the above teachings, or may be acquired from practice of the embodiments. The embodiments were chosen and described in order to explain the principles of implementation and their practical application to enable one skilled in the art to utilize the embodiments in various embodiments and with various modifications as are suited to the particular use contemplated.

Claims

WHAT IS CLAIMED IS:

1. A process to clean a gas stream comprising tail gas generated during carbon black production, said process comprising compressing the gas stream to obtain a compressed gas stream; conducting at least one hydrolysis reaction to obtain at least H2S, conducting at least one hydrogenation reaction to convert at least one of SO2 and SO3 to H2S, and optionally conducting at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining a conditioned syngas stream; removing at least a portion of said H2S from said conditioned syngas stream to obtain a sour gas stream containing said H2S and obtain a treated gas stream having fuel value; and converting at least a portion of the H2S in said sour gas stream to elemental sulfur and removing said elemental sulfur and obtain a sulfur removal off gas; wherein the at least one oxygen conversion reaction either comprises a further hydrogenation reaction to convert O2 to H2O or a reaction to convert carbon monoxide to carbon dioxide or both.

2. The process of claim 1, wherein prior to conducting said at least one hydrolysis reaction, said at least one hydrogenation reaction, removing at least a portion of any particulates and / or catalyst poisons from said gas stream or said compressed gas stream.

3. The process of claim 1 or 2, prior to removing, further comprising conducting at least one water gas shift reaction on the conditioned syngas stream.

4. The process of claim 3, wherein said at least one water gas shift reaction is achieved by utilizing at least one sulfur-resistant catalyst that converts CO and H2O to CO2 and H2.

5. The process of any of claims 1-4, wherein said gas stream consists of said tail gas generated during carbon black production.

6. The process of any of claims 1-5, wherein said gas stream is from two or more carbon black production units.

7. The process of any of claims 1-6, wherein said gas stream further comprises gaseous fuel from non-carbon black production sources.

8. The process of any of claims 1-7, wherein at least 80 vol% of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons, and water, and also includes trace amounts of sulfur species and nitrogen species, and optionally HC1 and PH and optionally particulates.

9. The process of any of claims 1-8, wherein at least 80 vol% of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons, and water, and also includes trace amounts of sulfur species and nitrogen species, and optionally one or more of HC1, and PH3 and particulates.

10. The process of any of claims 1-9, wherein the gas stream includes the following component concentrations:3-30 vol% CO,0.5-10 vol% CO2,3-50 vol% H2,0.01-2 vol% O2,0.5-10 vol% hydrocarbons,1-50 vol% water,50 ppm-10,000 ppm by vol sulfur species,50 ppm-20,000 ppm by vol nitrogen species,0 to 20 ppm by vol HC1,0 to 10 ppm by vol PH3, and0 mg / Nm3to 80 mg / Nm3particulates.

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

12. The process of any of claims 1-11, where said at least one hydrolysis reaction is achieved by utilizing at least one hydrolysis catalyst.

13. The process of any of claims 1-12, where said at least one hydrogenation reaction is achieved by utilizing at least one hydrogenation catalyst.

14. The process of claim 2, wherein said removing of the at least a portion of any particulates and / or catalyst poisons from said gas stream or said compressed gas stream comprising passing said gas stream or compressed gas stream through at least one filtration bed and / or through at least one adsorbent.

15. The process of any of claims 1-14, wherein said removing at least a portion of said H2S from said conditioned syngas stream is achieved by utilizing an amine scrubber, sour gas absorption with non-amine solvent(s), or pressure swing adsorption.

16. The process of any of claims 1-15, wherein said converting of at least a portion of the H2S in said sour gas stream to elemental sulfur is achieved by utilizing a liquid phase catalytic oxidation process or gas phase combustion process.

17. The process of claim 16, wherein said gas phase combustion process utilizes a Claus process that converts H2S and SO2 to H2O and S2.

18. The process of any of claims 1-17, wherein during and / or immediately after said compressing, the gas stream and / or compressed gas stream is cooled.

19. The process of claim 2, wherein said removing of the at least a portion of 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 HC1 and less than 5 ppm by volume20. The process of any of claims 1-19, said process further comprising conducting at least one reduction reaction to the compressed gas stream or the conditioned syngas stream to convert at least a portion of the nitrogen containing species to N2.

21. The process of any of claims 1-20, wherein said at least one hydrolysis reaction converts sulfur species in the compressed gas stream to H2S, and said sulfur species include CS2, COS, and organic sulfur.

22. The process of any of claims 1-21, wherein said at least one hydrolysis reaction further converts HCN to NH3.

23. The process of any of claims 1-22, wherein said at least one hydrogenation reaction converts SO2, and SO3 to H2S and converts O2 to either H2O or CO2 or both.

24. A facility to clean a gas stream comprising tail gas generated during carbon black production, said facility comprising: at least one compressor for compressing the gas stream so as to obtain a compressed gas stream; a catalytic converter unit comprising one or more fixed bed reactors that are configured for conducting at least one hydrolysis reaction to obtain at least H2S and conducting at least one hydrogenation reaction to obtain at least H2S, and obtain a conditioned syngas stream; a sour gas capturing unit for removing at least a portion of said H2S from said conditioned syngas stream to obtain a sour gas stream containing said H2S and obtain a treated gas stream having fuel value; and a sulfur conversion unit for converting at least a portion of the H2S in said sour gas stream to elemental sulfur and removing said elemental sulfur and obtain a sulfur removal off gas.

25. The facility of claim 24, said facility further comprising a gas conditioning unit for removing particulates and catalyst poisons from said gas stream or said compressed gas stream.

26. The facility of claim 24 or 25, wherein said one or more fixed bed reactors comprise at least one hydrogenation catalyst and at least one hydrolysis catalyst27. The facility of any of claims 24-26, wherein said catalytic converter unit comprises one or more fixed bed reactors that is configured to convert oxygen to water.

28. The facility of claim 27, wherein said one or more fixed bed reactors comprises at least one sulfur-resistant catalyst.

29. The facility of any of claims 24-28, wherein the catalytic converter unit comprises one or more fixed bed reactors that are configured to conduct at least one water gas shift reaction.

30. The facility of any of claims 24-29, wherein the gas conditioning unit comprises at least one filtration bed and at least one adsorbent, wherein the at least one filtration bed and the at least one adsorbent are in a same vessel or different vessels.

31. The facility of any of claims 24-30, wherein said sour gas capturing unit comprises an amine scrubber, a sour gas absorption unit with non-amine solvent(s), or a pressure swing adsorption unit.

32. The facility of any of claims 24-31, wherein said sour gas capturing unit is configured to use a liquid phase catalytic oxidation process or a gas phase combustion process.

33. The facility of any of claims 24-32, wherein said sulfur conversion unit is configured to use a Claus process that converts H2S and SO2 to H2O and S2.

34. The facility of any of claims 24-33, wherein said facility further comprises at least one cooling device for controlling temperature of the gas stream exiting the at least one compressor.

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