CARBON BLACK PRODUCTION WASTE GAS CLEANING PROCESSES AND ASSOCIATED SYSTEM AND PLANT

Abstract

The invention relates to a method for cleaning a gas stream. The gas stream may comprise a waste gas generated during the production of carbon black. The method implements several steps to systematically clean the starting gas stream to obtain a treated gas stream having a combustible value and to convert other portions of the gas stream to sulfur for recovery. The invention further relates to a plant or system comprising different operational units for carrying out the method.

Description

Title of the invention: METHODS FOR CLEANING CARBON BLACK PRODUCTION WASTE GAS AND ASSOCIATED SYSTEM AND PLANT

[0001] CONTEXT

[0002] The present embodiments relate to the cleaning of gas streams, such as industrial gas streams. More specifically, the present embodiments relate to methods for cleaning gas streams originating in part or in whole from carbon black production. The present embodiments further relate to installations and / or apparatus configurations and / or systems for cleaning such gas streams. The present embodiments further relate to methods for removing components such as sulfur from waste gas generated during carbon black production.

[0003] There is a growing demand and effort for cleaning industrial gas streams and this demand exists for the production of carbon black. In typical furnace black production processes, sulfur species in the tail gas are burned to form SOX (e.g., SO2 and SO3). Improvements in manufacturing sustainability require the reduction of SOX emissions. Typically, SOX is controlled after combustion of the tail gas. However, it would be desirable to control SOX emissions directly from the tail gas to reduce expenses and decrease water consumption and waste generation associated with these processes.

[0004] All patents and publications mentioned herein are incorporated in their entirety by reference. SUMMARY

[0005] One feature presented herein is to provide methods for cleaning gas streams, such as industrial gas streams, including, but not limited to, gas streams derived in part or entirely from waste gases generated during carbon black production.

[0006] Another feature is to provide processes for substantially removing sulfur from the gas stream with near-zero SOX emissions.

[0007] Further, a feature is to provide methods and plant for cleaning waste gas where the resulting gas volume is lower (e.g., 30% to 50% lower) than if the waste gas had been combusted to produce flue gas, thereby reducing the size of equipment for such treatment.

[0008] An additional feature is to provide methods and a facility (or system or configuration) for cleaning waste gas that may provide a reduction in operating cost compared to cleaning flared waste gas.

[0009] Another feature is to provide methods and an installation for cleaning a waste gas which does not increase the consumption of process water compared to methods in which a waste gas is combusted and the resulting flue gas is cleaned.

[0010] Another additional feature allows the condensate from the cooling of the waste gas to be reused in the production of carbon black, for example as a quenching fluid.

[0011] To achieve these and other advantages, and in accordance with the embodiments broadly described herein, the present embodiments relate, in part, to a method of cleaning a gas stream, for example from an industrial process. More particularly, the method of cleaning a gas stream preferably comprises a waste gas generated during the production of carbon black. The method comprises the steps of compressing the gas stream to obtain a compressed gas stream and performing several reactions on the gas stream. These reactions include, but are not limited to, 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 to H2S, and, optionally, performing at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining an O2-lean gas stream.The optional oxygen conversion reaction(s) include either an additional hydrogenation reaction to convert O2 to H2O, or a reduction reaction to convert carbon monoxide to carbon dioxide, or both. The method may optionally include performing at least one water gas conversion reaction to convert carbon monoxide and water to carbon dioxide and hydrogen.

[0012] The method further comprises removing at least a portion of the H2S from the conditioned syngas stream to obtain an H2S-containing sour gas stream and obtaining a treated gas stream having a combustible value. The method further comprises 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.

[0013] Before carrying out said at least one hydrolysis reaction or said at least one hydrogenation reaction, the method may further comprise removing at least a portion of any particles and any catalyst poisons from said gas stream or said compressed gas stream. Removing at least a portion of the possible particulates and possible catalyst poisons from said gas stream or said compressed gas stream may comprise passing said gas stream or said compressed gas stream through at least one filtration bed and through at least one adsorbent. The gas stream may consist of said waste gas generated during carbon black production, and / or may originate from two or more carbon black production units. Alternatively or additionally, the gas stream may further comprise a gaseous fuel from sources other than carbon black production. 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 further comprise trace amounts of sulfur species and nitrogen species, and optionally HCl and PH3 and optionally particulates.For example, at least 80% by volume of the gas stream may be CO, CO2, N2, O2, H2, hydrocarbons and water, and further includes trace amounts of sulfur species and nitrogen species, and optionally one or more of HCl, PH3 and particulates.

[0014] In any of these embodiments, the gas stream may comprise the following component concentrations:

[0015] 3 to 30% by volume of CO,

[0016] 0.5 to 10% by volume of CO2,

[0017] 3 to 50% by volume of H2,

[0018] 0.01 to 2% by volume of O2,

[0019] 0.5 to 10% by volume of hydrocarbons,

[0020] 1 to 50% by volume of water,

[0021] 50 ppm to 10,000 ppm by volume of sulfur species,

[0022] 50 ppm to 20,000 ppm by volume of nitrogen species,

[0023] 0 to 20 ppm by volume of HCl,

[0024] 0 to 10 ppm by volume of PH3, and

[0025] 0 mg / Nm3 to 80 mg / Nm3 of particles.

[0026] Alternatively or additionally, the compression may utilize at least one compressor. In any of these embodiments, the hydrolysis reaction(s) may be carried out using at least one hydrolysis catalyst, and / or the hydrogenation reaction(s) may be carried out using at least one hydrogenation catalyst. In any of these embodiments, the removal of at least a portion of said H2S from said conditioned syngas stream may be achieved using an amine treatment device, acid gas absorption with one or more non-amine solvents, or pressure swing adsorption, and / or the conversion of at least a portion of H2S in said acid gas stream to elemental sulfur may be achieved using a catalytic phase oxidation process. liquid or gas-phase combustion process. The gas-phase combustion process may use a Claus process that converts H2S and SO2 to H2O and S2.

[0027] In any of these embodiments, the gas stream and / or the compressed gas stream may be cooled during and / or immediately after said compression, and / or the removal of at least a portion of any particulates 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 of HCl and less than 5 ppm by volume of PH3. In any of these embodiments, the method may further comprise performing at least one reduction reaction of the compressed gas stream or the conditioned synthesis gas stream to convert at least a portion of the nitrogen-containing species to N2.

[0028] In any of these embodiments, the hydrolysis reaction(s) 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 hydrogenation reaction(s) may convert SO2 and SO3 to H2S and optionally convert O2 to H2O.

[0029] The present embodiments further relate to a plant (or system) for cleaning a gas stream that includes a waste gas generated during carbon black production. The plant includes at least one compressor for compressing the gas stream to obtain a compressed gas stream; a first catalytic converter unit including one or more fixed bed reactors that are configured to perform at least one hydrolysis reaction to obtain at least H2S and perform at least one hydrogenation reaction to obtain at least H2S, and optionally perform at least one oxygen shift reaction to remove O2 and obtain an O2-lean gas stream and obtain a conditioned syngas stream; an optional water gas shift unit for performing at least one water gas shift reaction to convert carbon monoxide and water into carbon dioxide and hydrogen;an acid gas capture unit for removing at least a portion of H2S from the conditioned syngas stream to obtain an acid gas stream containing H2S and obtaining a treated gas stream having a combustible value; and a sulfur conversion unit for converting at least a portion of the H2S in the acid gas stream to elemental sulfur and removing the elemental sulfur and obtaining a sulfur removal off-gas. ;

[0030] The plant may further comprise a gas conditioning unit for removing catalyst particles and poisons from the gas stream or compressed gas stream, and / or the fixed bed reactors may be or comprise at least one hydrogenation catalyst, at least one hydrolysis catalyst and at least one sulfur-resistant catalyst.

[0031] Alternatively or additionally, the installation may be characterized by one or more of the following features: The gas conditioning unit may be or comprise at least one filtration bed and at least one adsorbent, the filtration bed(s) and the adsorbent(s) being in the same container or in different containers. The acid gas capture unit may be or comprise an amine treatment device, an acid gas absorption unit with one or more non-amine solvents, or a pressure swing adsorption unit. The installation may further comprise at least one cooling device for regulating the temperature of the gas stream exiting the compressor(s).

[0032] It is to be understood that the above general description and the following detailed description are given solely by way of example and explanation and are intended to provide further explanation of the present embodiments according to the claims.

[0033] 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 THE DRAWINGS

[0034] [Fig. 1] is a process diagram of a waste gas cleaning process according to an exemplary embodiment.

[0035] [[Fig.2]] is a process diagram of a waste gas cleaning system or installation according to an exemplary embodiment. DETAILED DESCRIPTION

[0036] The present embodiments relate to methods and installations for cleaning a gas stream, such as an industrial gas stream. The gas stream may comprise, and preferably comprises, waste gas generated during the production of carbon black.

[0037] The general steps or aspects of the method of the present embodiments are as follows.

[0038] In the present embodiments, a method comprises or includes compressing a gas stream (e.g., an industrial gas stream such as waste gas) to obtain a compressed gas stream.

[0039] The method further comprises carrying out several reactions on the gas stream or the compressed gas stream.

[0040] The various reactions include, but are not limited to, the following: carrying out at least one hydrolysis reaction to obtain at least H2S; carrying out at least one hydrogenation reaction to convert at least one of SO2 and SO3 (or both) to H2S; and optionally carrying out at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining an O2-lean gas stream, wherein the at least one oxygen conversion reaction comprises, consists of, or includes an additional hydrogenation reaction to convert O2 to H2O or comprises a reaction with carbon monoxide to convert carbon monoxide to carbon dioxide or both of these reactions.

[0041] The method further comprises removing at least a portion of H2S from the conditioned syngas stream to obtain a sour gas stream containing the H2S and obtaining a treated gas stream having fuel value or utility as a feedstock for chemical production, H2 production and the like.

[0042] The process then comprises converting at least a portion of the H2S in the sour gas stream to elemental sulfur and removing the elemental sulfur and obtaining a sulfur removal off-gas.

[0043] Additional details of the method are described below.

[0044] With respect to the gas stream that is treated or cleaned by the present embodiments, the gas stream, as indicated, may be an industrial gas stream. The industrial gas stream may be or include waste gas from one or more sources. For example, the gas stream may include or be entirely or solely from waste gas generated during the production of carbon black.

[0045] The gas stream may comprise or be entirely or solely derived from one, two, or more carbon black production units (e.g., two or more carbon black reactors). There is no limit to the number of carbon black production units that may contribute to the gas stream processed by the present embodiments. The carbon black production units may be furnace black production units, plasma black production units, and / or other types of carbon black production units. The carbon black production units may be from units producing the same, similar, or different grades of carbon black.

[0046] Optionally, the gas stream that is processed by the present embodiments may further comprise a gaseous fuel from sources other than carbon black production. For example, the gas stream may comprise gas or gaseous fuel streams from one or more of the following optional sources: biomass, natural gas, liquefied petroleum gas (LPG) such as that from oil fields, coal seam gas such as that from processes from coking, by-product gas such as that from steel furnaces, and / or other or similar sources as illustrated herein.

[0047] For example, the gas stream (i.e., the starting gas stream) may comprise at least 25% by volume, at least 50% by volume, at least 75% by volume, at least 80% by volume, at least 90% by volume, at least 95% by volume, at least 99% by volume, or 100% by volume of a gas stream or waste gas from one or more carbon black production units.

[0048] The gas stream that is treated by the present embodiments may be a gas stream in which at least 80% by volume (e.g., at least 85% by volume, at least 90% by volume, at least 95% by volume, at least 99% by volume, such as from 80% by volume to 99% by volume or from 85% by volume to 99% by volume) 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 HCl and PH3 and optionally particulates.

[0049] The gas stream that is treated by the present embodiments may be a gas stream in which at least 80% by volume (e.g., at least 85% by volume, at least 90% by volume, at least 95% by volume, at least 99% by volume, such as from 80% by volume to 99% by volume or from 85% by volume to 99% by volume) of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons, and water, and further includes trace amounts of sulfur species and nitrogen species, and optionally includes one or more of HCl, PH3, and particulates.

[0050] The particles (e.g., solid particles), for example, may be carbon particles and / or inorganic particles 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).

[0051] The sulfur species may include, but are not limited to, H2S, COS, CS2, SO2, SO3 and / or C4H4S, and the like.

[0052] Nitrogen species may include, but are not limited to, HCN, NH3, NO and / or NO2, and the like.

[0053] As a further example, the gas stream may comprise the following component concentrations: 3 to 30% by volume or more of CO (e.g., 3 to 25% by volume, 3 to 20% by volume, 3 to 15% by volume, 3 to 10% by volume, 3 to 5% by volume, 5 to 30% by volume, 10 to 30% by volume, 15 to 30% by volume, 20 to 30% by volume) 0.5 to 10% by volume or more of CO2 (e.g., 0.5 to 7% by volume, 0.5 to 5% by volume, 0.5 to 2% by volume, 1 to 10% by volume, 2 to 10% by volume, 3 to 10% by volume, 5 to 10% by volume), 3 to 50% by volume or more of H2 (3 to 45% by volume, 3 to 40% by volume, 3 to 35% by volume, 3 to 30% by volume, 3 to 25% by volume, 3 to 20% by volume, 3 to 15% by volume, 3 to 10% by volume, 3 to 5% by volume, 5 to 50% by volume, 10 to 50% by volume, 15 to 50% by volume, 20 to 50% by volume, 25 to 50% by volume, 30 to 50% by volume, 35 to 50% by volume, 40 to 50% by volume), 0.01-2% by volume or more of O2 (e.g., 0.01-1.5% by volume, 0.01-1% by volume, 0.01-0.5% by volume, 0.01-0.1% by volume, 0.01-0.05% by volume, 0.02-2% by volume, 0.05-2% by volume, 0.07-2% by volume, 0.1-2% by volume, 0.5-2% by volume, 0.7-2% by volume, 1-2% by volume, 1.25-2% by volume); 0.5 to 10% by volume or more of hydrocarbons (e.g., 0.5 to 7% by volume, 0.5 to 5% by volume, 0.5 to 3% by volume, 0.5 to 1% by volume, 0.7 to 10% by volume, 1 to 10% by volume, 2 to 10% by volume, 5 to 10% by volume, 7 to 10% by volume) 1 to 50% by volume or more of water (e.g., 1 to 45% by volume, 1 to 40% by volume, 1 to 35% by volume, 1 to 30% by volume, 1 to 25% by volume, 1 to 20% by volume, 1 to 15% by volume, 1 to 10% by volume, 1 to 5% by volume, 2 to 50% by volume, 5 to 50% by volume, 10 to 50% by volume, 15 to 50% by volume, 20 to 50% by volume, 25 to 50% by volume, 30 to 50% by volume, 35 to 50% by volume, 40 to 50% by volume) from 50 ppm to 10,000 ppm or more by volume of sulfur species (e.g., 50 to 7,000 ppm, 50 to 5,000 ppm, 50 to 2,500 ppm, 50 to 2,000 ppm, 50 to 1,500 ppm, 50 to 1,000 ppm, 50 to 750 ppm, 50 to 500 ppm, 50 to 250 ppm, 50 to 100 ppm, 100 to 10,000 ppm, 200 to 10,000 ppm, 500 ppm to 10,000 ppm, 1,000 to 10,000 ppm, 2,000 to 10,000 ppm, 3,000 to 10,000 ppm, 5,000 to 10,000 ppm, from 7,000 to 10,000 ppm), 50 ppm to 20,000 ppm or more by volume of nitrogen species (e.g., 50 to 15,000 ppm, 50 to 12,500 ppm, 50 to 10,000 ppm, 50 to 7,000 ppm, 50 to 5,000 ppm, 50 to 2,500 ppm, 50 to 2,000 ppm, 50 to 1,500 ppm, 50 to 1,000 ppm, 50 to 750 ppm, 50 to 500 ppm, 50 to 250 ppm, 50 to 100 ppm, 100 to 20,000 ppm, 200 to 20,000 ppm, 500 ppm to 20,000 ppm, 1 000 to 20,000 ppm, 2,000 to 20,000 ppm, 3,000 to 20,000 ppm, 5,000 to 20,000 ppm, 7,000 to 20,000 ppm, 10,000 to 20,000 ppm, 12,500 to 20,000 ppm, 15,000 to 20,000 ppm, 17,500 to 20,000 ppm), 0 to 20 ppm or more by volume of HCl (e.g., 0.1 to 20 ppm, 0.5 to 20 ppm, 1 to 20 ppm, 5 to 20 ppm, 10 to 20 ppm, 0.1 to 15 ppm, 0.1 to 10 ppm, 0.1 to 5 ppm, 0.1 to 2.5 ppm), 0 to 10 ppm or more by volume of PH3 (e.g., 0.1 to 10 ppm, 0.5 to 10 ppm, 1 to 10 ppm, 5 to 10 ppm, 0.1 to 7 ppm, 0.1 to 5 ppm, 0.1 to 2 ppm, 0.1 to 1 ppm), and 0 mg / Nm3 to 80 mg / Nm3 or more of particles (e.g., 0.1 to 80 mg / Nm3, 0.5 to 80 mg / Nm3, 1 to 80 mg / Nm3, 5 to 80 mg / Nm3, 10 to 80 mg / Nm3, 15 to 80 mg / Nm3, 20 to 80 mg / Nm3, 30 to 80 mg / Nm3, 40 to 80 mg / Nm3, 50 to 80 mg / Nm3, 60 to 80 mg / Nm3, 70 to 80 mg / Nm3, 0.1 to 75 mg / Nm3, 0.1 to 70 mg / Nm3, 0.1 to 60 mg / Nm3, 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).

[0054] The gas conditions of the gas stream being treated are not critical. For any given unit process, if the incoming gas stream does not have the desired temperature or pressure, these are readily adjusted using methods known to those skilled in the art. For example, the gas in the gas stream to be treated may have a temperature ranging from room temperature (e.g., 20°C to 25°C) to 300°C or other temperatures. Similarly, the pressure of the gas stream to be treated may be 0 barg to 1 barg or other pressures outside this range.

[0055] With regard to the step of the method of compressing the gas flow, at least one compressor may be used to carry out this step. Several compressors may be used and / or the compressor may comprise several stages (multi-stage compression).

[0056] The gas compression may be performed 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 may be such that the gas is pressurized, for example, by a fan or a pre-compression compressor.

[0057] One objective of compressing the gas stream is to impart a desired pressure to the gas so as to overcome potential pressure drops in downstream steps of the process.

[0058] Compressing the gas stream results in a compressed gas stream. The compressed gas stream has a high pressure greater than atmospheric pressure or a gas pressure greater than the pressure of the starting gas entering the compressor(s). The high pressure may be 0.5 to 100 barg or more, for example 0.5 to 50 barg, 0.5 to 45 barg, 0.5 to 40 barg, 0.5 to 35 barg, 0.5 to 30 barg, 0.5 to 25 barg, 0.5 to 20 barg, 0.5 to 15 barg, 0.5 to 10 barg, 0.5 to 5 barg, 1 at 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.

[0059] Optionally, the gas stream entering the compression stage (i.e., the raw gas) may be partially cooled at the compressor inlet or cooled between multi-stage compressors (if applicable) and / or cooled after the last compression stage. The compressed gas exiting the one or more compressors may have a temperature, due to the cooling, below 500°C, for example, from 100°C to 500°C or other temperatures.

[0060] Optionally, the gas stream or compressed gas stream may be subjected to filtration of particles that may be present in the gas stream. In this step, in the gas stream or compressed gas stream, at least a portion of the particles present in the gas stream is removed, for example by filtration, using, for example, one or more filter beds, filter beds, or other forms of mechanical filtration mechanisms such as, but not limited to, a cartridge filter, a bag filter, a membrane filter, etc.

[0061] In addition to removing some, most, or all of the particulates (i.e., solid particles) in the gas stream, at least some (some, most, or all) of any catalyst poisons that may be present may be captured or removed at this step of the process (e.g., catalyst poison capture). Thus, this filtration step may further remove at least some (some, 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. Generally, the catalyst poisons are present in trace amounts (e.g., in amounts such as those previously described).

[0062] Performing such a catalyst poison filtration and / or capture step, which may be collectively referred to as gas conditioning or gas conditioning unit operation, may enable more stable operation of the catalytic processes on the gas stream and / or enable the catalytic process to operate more efficiently and / or extend the catalyst life.

[0063] For particle filtration, one or more filter beds loaded with filter media (which may be in particulate form) may be used. The particulate filter media may have various geometric shapes and sizes (e.g., spherical, extruded, cylindrical, trilobal, annular, and the like). Removal of some, most, or all of the particles may prevent clogging of the catalyst bed(s) described and used in downstream process steps. Particulate filter media that may be used in 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 may include different types of alumina such as y-Al2O3 or a-Al2O3 having different pore structures and surfaces.

[0064] Different configurations of the one or more filter beds may be used. One or more filter beds may be used. If more than one filter bed is used, the filter beds may be used in parallel or sequentially (in series) or one filter bed may be used and then a make-up filter bed may be used when the initial filter bed needs to be cleaned, regenerated or replaced. In general, a filter bed is exhausted as soon as a certain level of pressure increase occurs due to clogging. It will be apparent to those skilled in the art when this occurs.

[0065] If parallel filtration is used when one filter bed is on standby, filtration may be performed with one filter bed until the pressure drop increases to a target level, and a switchover may be performed to the standby filter bed to continue particle filtration, and during this switchover, the used filter media may be cleaned or replaced.

[0066] By filtering particles from the gas stream, the gas stream may have reduced particulate levels of 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 10-99 wt%, 50-99 wt% or 75-99 wt%, or 90-99 wt%, based on the total weight of particles present prior to filtration. The particulate content of the gas stream, after particle filtration, may be 50 mg / Nm3 or less, less than 40 mg / Nm3, less than 30 mg / Nm3, less than 20 mg / Nm3, less than 10 mg / Nm3, less than 5 mg / Nm3, less than 1 mg / Nm3, for example 0.01 mg / Nm3 to 50 mg / Nm3 or 0.01 mg / Nm3 to 10 mg / Nm3, or 0.01 mg / Nm3 to 5 mg / Nm3, or 0.01 mg / Nm3 to 1 mg / Nm3.

[0067] With respect to the capture of catalyst poisons, the catalyst poisons may be at least partially captured using one or more types of adsorbents that may be present in an adsorption vessel or bed. The adsorbent may be a multifunctional adsorbent or a mixture of two or more adsorbents (e.g., specialty adsorbents) that are capable of capturing, trapping, adsorbing, or otherwise retaining at least a portion of the catalyst poisons that, as noted, are or include HCl and / or PH3. The desired removal rate is a rate that allows downstream use of the catalyst for an acceptable or extended lifetime.

[0068] When multiple adsorbents are used, the adsorbents may be loaded into separate containers in series, or they may be loaded into the same container in layers or loaded together as a mixture of adsorbents.

[0069] Any commercially available sorbent or adsorbent having the desired function described herein may be used. The sorbents or adsorbents may be porous materials. The adsorbents may be, but are not limited to, alumina, silica, silica aluminate, in or magnesium oxide(s). The adsorbent(s) may optionally be modified with alkali and / or alkaline earth metal oxides to achieve improved 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 Clariant AG's SHIFTGUARD 200 sorbent, Topsoe A / S's TK-3000 catalyst / sorbent and HTG-10 sorbent, and Haiso Technology Co.'s ET-17 and EG-2 catalyst / sorbents.

[0070] Alternatively or additionally, other cleaning technologies, optionally including filtration technologies, may also be used. For example, wet scrubbers using water or a neutralizing solution may be used to remove catalyst poisons and optionally particulates. Such scrubbers may be in the form of a venturi, a packed tower, a spray tower, or other configurations known to those skilled in the art.

[0071] By capturing or removing at least a portion of the catalyst poisons, the amount of catalyst poisons, such as HCl and / or PH3 can then be reduced by at least 50% by volume, at least 60% by volume, at least 70% by volume, at least 80% by volume, at least 90% by volume, at least 95% by volume, for example 50 to 99% by volume or 75 to 99% by volume, or 90 to 99% by volume. The content of catalyst poisons as defined by HCl and / or PH3 in the exit gas stream, after capture of the poisons, can be less than 5 ppm for each of HCl and / or PH3, and preferably less than 1 ppm for each of HCl and / or PH3.

[0072] Preferably, the particulate filtration step, if used, is performed before the capture of catalyst poisons, for example before the gas compression step.

[0073] Preferably, the capture of catalyst poisons, if used, is carried out after the particulate filtration step, if applicable, for example, before the gas compression step.

[0074] The catalyst poison capture and / or particle filtration step may be carried out at a temperature of about 100°C to about 500°C. Other temperatures outside this range are possible.

[0075] With regard to the step of carrying out several reactions on the gas stream or the compressed gas stream, preferably this part of the process is carried out with the compressed gas stream.

[0076] Carrying out the hydrolysis reaction(s) to obtain at least H2S may be in the form of one or more reactions using the same or different catalysts. At least one hydrolysis catalyst may be used. 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 by one or more hydrolysis reactions with water or moisture in the gas stream.

[0077] The hydrolysis reaction preferably comprises one or both of the following reactions: CS2 + 2H2O -> 2H2S + CO2 COS + H2O -> H2S + CO2.

[0078] Carrying out the hydrogenation reaction(s) to convert at least one of SO2 and SO3 to H2S may be in the form of one or more reactions using the same or different catalysts. At least one hydrogenation catalyst may be used. 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 by one or more hydrogenation reactions with hydrogen in the gas stream.

[0079] The hydrogenation reaction preferably comprises one or both of the following reactions: SO2+ 3H2 -> H2S + 2H2O SO3+ 4H2 -> H2S + 3H2O.

[0080] The percentage conversion (by one or both of the hydrolysis and hydrogenation reactions) of 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% relative to the starting ppm levels of the sulfur species. The percentage conversion may be from 50% to 99% or more relative to the starting ppm levels of the sulfur species.

[0081] Carrying out the hydrolysis reaction(s) may further comprise a reaction for converting HCN to NH3. At least one hydrolysis catalyst as previously identified or an additional hydrolysis catalyst may be used for this particular reaction. In this additional hydrolysis reaction, HCN present in the gas stream (e.g., at least a portion of it) is converted to NH3 with water in the gas stream.

[0082] The percentage conversion of HCN to NH3 is preferably at least 50% or at least 60%, or at least 70% or at least 80%, or at least 90% relative to the starting ppm levels of HCN. The percentage conversion may be from 50% to 99% or more relative to the starting ppm levels of HCN.

[0083] The further hydrolysis reaction preferably comprises the following reaction: HCN + H2O -> NH3 + CO.

[0084] This part of the process may further comprise carrying out at least one reduction reaction of the compressed gas stream or the conditioned synthesis gas stream to convert at least a portion of the nitrogen-containing species to N2. In this part of the process, NO and / or NOX in the gas stream (or at least a portion thereof) may be converted to nitrogen gas (N2) by one or more reduction reactions. One or more reduction reaction catalysts may be used for this reaction.

[0085] By means of the reduction reaction, at least 50% by volume, at least 60% by volume, at least 70% by volume, at least 80% by volume, at least 90% by volume, at least 95% by volume (e.g. from 50% by volume to 99% by volume or more, or from 60% by volume to 99% by volume, or from 70% by volume to 99% by volume, or from 80% by volume to 99% by volume, from 90% by volume to 99% by volume, from 95% by volume to 99% by volume) of the NO and / or NOX present in the gas stream just before this reaction can be converted into N2.

[0086] Carrying out at least one oxygen conversion reaction to remove O2 from the compressed gas stream may be in the form of one reaction or multiple reactions using the same or different catalysts. At least one oxygen conversion catalyst may be used. In this oxygen conversion reaction, the oxygen conversion reaction comprises, consists of, or includes an additional hydrogenation reaction to convert O2 to H2O with hydrogen in the gas stream, or comprises 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 may be considered as a reaction to convert O2 to carbon dioxide with CO in the gas stream. Thus, in each of the possible reactions, oxygen is converted to H2O or carbon dioxide, or both.Oxygen removal is preferred to prevent oxidation of the amines used to remove H2S during sour gas capture, as described below. However, if an acid gas capture system . less affected by oxygen is used, or if the waste gas contains sufficiently low amounts of oxygen, e.g. not more than 0.2% by volume, then oxygen conversion is optional.

[0087] The percentage conversion of gaseous oxygen to H2O or carbon dioxide or both preferably represents at least 50% or at least 60%, or at least 70% or at least 80%, or at least 90% relative to the starting levels in % by volume of gaseous oxygen. The percentage conversion may be from 50% to 99% or more relative to the starting levels in % by volume of gaseous oxygen.

[0088] The oxygen conversion reaction preferably comprises one or both of the following reactions: O2 + 2H2 -> 2H2O O2 +2CO -> 2CO2.

[0089] Following the oxygen conversion reactions, a gas stream low in O2 is obtained.

[0090] With respect to the hydrolysis reaction(s), the hydrogenation reaction(s) and the oxygen shift reaction, and optionally the reduction reaction, one or more commercially available catalysts having the described functionality may be used. A combination of catalysts may be used. Examples of catalysts that may 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.

[0091] 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., a heating element) or other means for achieving this desired temperature range may be used before carrying out these reactions.

[0092] The reactions may be conducted or carried out with one reactor or reactor vessel (or several reactor vessels) which may contain the catalyst or a combination of catalysts. When several reactors or reactor vessels are used, the arrangement of the reactors may be in parallel in order to reduce the overall pressure drop, which may allow the performance of the reactor to be optimized. The one or more reactors may be fixed-bed reactors which enclose or contain the one or more of the catalysts mentioned.

[0093] Alternatively, the reactors, when several are used, and which each comprise a different catalyst for a different reaction, can be arranged in series.

[0094] Any reactor configuration (e.g., fixed bed reactors) known to those skilled in the art may be used. The configuration may be upflow, downflow, axial flow, radial flow, or horizontal flow.

[0095] After hydrogenation and hydrolysis, the gas stream, which may be considered a conditioned syngas stream, generally contains primarily H2, CO, CO2, N2, H2S, NH3, H2O and amounts (e.g., small amounts) of other possible unconverted components entrained with the raw gas stream, such as sulfur compounds and / or N species. H2, CO, CO2, N2, H2S, NH3, H2O combined represent 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., from 50 vol% to 99 vol% or from 75 vol% to 99 vol%) of the conditioned syngas stream.

[0096] The next step may then be to remove 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 a combustible value. This step may in part be referred to as sour gas capture and may be carried out using a sour gas capture unit. Optionally, a water gas shift reaction may be carried out on the conditioned syngas stream prior to sour gas capture.

[0097] The optional water gas shift reaction may be considered a CO-water gas shift reaction and may be one or more reactions. When used, the water gas shift reaction preferably occurs after the aforementioned hydrolysis reaction(s) and after the aforementioned hydrogenation reaction(s) and the aforementioned oxygen shift reaction.

[0098] One or more of the hydrolysis and hydrogenation reactions may optionally continue during the water gas shift reaction, if they have not been completed before the water gas shift reaction occurs. Alternatively or additionally, some of the water gas shift reactions described below may take place during the hydrolysis and / or hydrogenation.

[0099] The water gas shift reaction converts carbon monoxide in the gas stream (at least a portion thereof) to carbon dioxide by reaction with water in the gas stream to produce hydrogen gas (H2) via an exothermic reaction.

[0100] The gas to water conversion reaction preferably comprises the following reaction: CO + H2O -> CO2 + H2

[0101] Since the gas stream, at this stage, contains sulfur in the form of H2S and / or other unconverted sulfur species, the catalyst used for this reaction must be tolerant to sulfur poisoning (i.e., a sulfur-resistant catalyst). Thus, the water gas shift reaction (WGSR) is carried out using at least one sulfur-resistant catalyst that converts CO and H2O to CO2 and H2.

[0102] 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 catalyst from Haiso Technology Co., and KATALCO KB-11 and KATALCO K8-11 HA from Johnson Matthey.

[0103] The WSGR catalyst may be formed from a metal sulfide of cobalt, iron, molybdenum and / or nickel. The WSGR catalyst may be loaded onto porous supports, such as alumina, silica or similar support materials. The WSGR catalyst may be in the form of extrudates, pellets, spheres, rings and / or any other shapes to promote mass transfer and / or minimize pressure drop.

[0104] The WSGR catalyst may be presulfided prior to loading or obtained in oxide form and sulfided on-site after loading into the reactor. To enable on-site sulfidation, an auxiliary system may be used to provide the reactants (such as CS2, COS, etc.) and heat to enable adequate sulfidation prior to the introduction of the gas stream. Catalyst suppliers typically provide detailed procedures for such an on-site sulfidation process.

[0105] Sour gas capture separates H2S from the gas stream (e.g., the conditioned syngas stream or the conditioned syngas stream treated by the water gas shift reaction) to produce a sour gas stream containing H2S, some carbon dioxide, and some moisture. The remaining, unseparated gas components can be considered a treated gas stream having combustible value. This treated gas stream can be sent to a combustor for heat recovery, or treated by other widely known technology such as membrane, pressure swing adsorption (PSA), and the like to obtain a marketable pure hydrogen product (e.g., hydrogen gas having a purity of at least 95% by volume or at least 99% by volume), or used in any other process that can generate value from the treated gas stream or add value to the treated gas stream.

[0106] Separation of H2S from the gas stream (i.e., the conditioned syngas stream) can be accomplished using many commercially available technologies.

[0107] Examples of such technologies include, but are not limited to: amine treatment technology, methanol absorption, glycol absorption, and pressure swing adsorption for acid gas capture.

[0108] With respect to the amine treatment technology, in this process, a gas stream, conditioned to a desired temperature (e.g., 30 to 60°C) and a desired pressure (e.g., sufficient to overcome the absorber pressure drop and up to 100 barg), is contacted with an amine solution in a column. Different types of contacting columns may be used, such as a tray column, a random-packed column, a structured packing, or any combination thereof. H2S (or at least a portion thereof) and some carbon dioxide are absorbed by the one or more amine compounds, and the other components of the gas stream pass through this column as a product stream. The amine solution with absorbed H2S may be transferred to another column, where heat may be added to promote desorption of H2S from the amine solution.A regenerated amine stream, after temperature adjustment (e.g., 30 to 60 °C), is returned to the absorption column to increase H2S absorption. The heat input may depend on the sorbent type and design conditions used. The H2S released by the desorption process produces an acid gas stream that can be treated in the next unit operation.

[0109] Solvents that may be used in this method 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 may be an aqueous solution having a concentration (e.g., 5 to 50 wt.%) of one or more amines. One or more additives having different functions may also be used and, for example, may be mixed with the sorbent to improve corrosiveness and / or absorption efficiency and / or to achieve one or more other performances.

[0110] A gas stream conditioning step (i.e., the conditioned syngas stream) may be performed, for example, wherein, prior to entering the absorption unit for acid gas capture, the gas stream is cooled and, as a result, a condensate may form as the gas stream is cooled below its dew point. This aqueous condensate stream may be used in carbon black production as quench water and / or for other process water uses.

[0111] Another method that can be used for acid gas capture is one or more absorptions using 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 acid gas absorption units / techniques may 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 providers and EPC (engineering, procurement, and construction) engineering companies.

[0112] Another method / technique that may be used for acid gas capture includes pressure swing adsorption (PSA). For this PSA, one or more solid adsorbents may be used to capture H2S at elevated pressures (e.g., 2 barg to 100 barg), and then the solid adsorbent may 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 containing low amounts of H2S. For example, the clean gas stream may comprise the 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. As shown, the concentrated H2S stream can be considered as the acid gas stream, and the clean gas stream can be considered as the treated gas stream having combustible value.The calorific value of the treated gas may depend on the composition of the raw gas. For the clean gas stream, the calorific value of the treated gas may be from about 2 to about 6 MJ / Nm3 or other values ​​below or above this range. If other gas sources (such as biomass syngas, coke oven gas) are mixed with the feedstock, the calorific value range may be above or below this range.

[0113] Since the clean gas stream may still contain NOX-forming components (e.g., ammonia), removal technology or steps may optionally be implemented if the clean gas stream is combusted for any reason to generate a flue gas. Exemplary NOX removal methods include, but are not limited to, injecting ammonia or urea into a flue gas stream and selective catalytic reactor (SCR) methods known to those skilled in the art, including, but not limited to, the methods described in US9192891, the entire contents of which are incorporated herein by reference. Alternatively or additionally, a selective non-catalytic reactor (SNCR) method including, but not limited to, the methods described in the '891 patent may be used to remove NOX from a flue gas.Since SCR and SNCR processes are more efficient in particular temperature ranges (typically 275 to 500 °C and 900 to 1050 °C, respectively), man . A person skilled in the art can adjust the temperature of a flue gas using conventional boilers, heat exchangers, and other apparatus to enable the one or more selected processes to operate more efficiently. Alternatively or additionally, 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 used. Other methods known to those skilled in the art may also be used.

[0114] Once the sour gas stream is obtained, the next step of the process may be to convert at least a portion of the H2S in the sour gas stream to elemental sulfur and then remove the elemental sulfur to obtain a sulfur removal gas.

[0115] Various commercially available technologies may be used for this sulfur conversion 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 may utilize a Claus process, for example, as described in US3719744, incorporated herein in its entirety by reference, which converts H2S and SO2 to H2O and S2.

[0116] The relatively low concentration of H2S in the sour gas stream can be more adequately treated with liquid phase oxidation technology than with other processes, for example a Claus process. In a liquid phase oxidation process, a gaseous mixture of H2S and H2O and optionally CO2 is contacted with an aqueous solution of iron-based catalyst in a reactor column. The H2S is oxidized to elemental sulfur by reaction with Fe(III) to form Fe(II). The reaction product stream is transferred to a regeneration reactor, where ambient air is circulated through the liquid to reoxidize Fe(II) to Fe(III) to regenerate the catalyst. The regenerated catalyst liquid is recirculated to the oxidation reactor column to promote the oxidation of H2S. The elemental sulfur produced in this oxidation process forms crystalline sulfur suspended in the aqueous liquid solution.A slipstream of this solution is sent to a liquid-solid separator, such as a belt filter, a press and frame filter, or other type of separator to produce a solid sulfur product that is saleable (or usable material).

[0117] [Fig. 1] shows a process flow diagram of a process 100 of the present embodiments that may be used. In step 110, a gas stream that includes a waste gas, such as a waste gas generated during the production or manufacture of carbon black, is obtained.

[0118] In optional step A, the gas stream may contain at least a portion of the catalyst particles and / or poisons removed from the gas stream. This may occur before and / or after step 115 of compressing the gas stream to form a compressed gas stream.

[0119] In step 120, the compressed gas stream is subjected to at least one hydrolysis reaction so as to form at least H2S and convert HCN, if present, into NH3.

[0120] 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.

[0121] In step 130, the compressed gas stream is subjected to at least one oxygen conversion reaction to remove oxygen (O2). This reaction may be an additional hydrogenation reaction to convert O2 to H2O and / or a reduction reaction to convert CO to CO2.

[0122] Steps 120, 125 and 130 may be conducted in any order. Preferably, step 130 is conducted after steps 120 and 125 to obtain an O2-lean gas stream, which may be considered a conditioned synthesis gas stream.

[0123] 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 a combustible value is recovered / obtained and in step 150, an acid gas stream containing H2S is obtained or recovered or separated from the treated gas stream.

[0124] In step 155, at least a portion of the H2S present in the acid gas stream is converted to elemental sulfur and, in step 160, may be recovered, removed, or separated from the remainder of that gas stream.

[0125] The above method for cleaning the gas stream may be carried out in a facility or system that is configured to carry out the various steps described herein. Thus, the present embodiments further relate to a system and / or facility for cleaning a gas stream that includes waste gas generated during carbon black production.

[0126] The installation comprises at least one compression unit or at least one compressor for compressing the gas flow so as to obtain a compressed gas flow.

[0127] The plant further comprises a catalytic converter unit comprising one or more fixed bed reactors which are configured to carry out the above-mentioned hydrolysis reaction(s) to obtain at least H2S and carry out at least one hydrogenation reaction to obtain at least H2S, and carry out at least one oxygen conversion reaction to remove O2 from the gas stream or compressed gas stream.

[0128] The installation further comprises an acid gas capture unit for removing at least a portion of the H2S from the conditioned synthesis gas stream to obtain an acid gas stream containing H2S and obtain a treated gas stream having a combustible value.

[0129] The plant further comprises 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 obtaining a sulfur removal off-gas.

[0130] The installation may further comprise a gas conditioning unit for removing particulates and / or catalyst poisons from the gas stream or compressed gas stream as described herein.

[0131] The gas conditioning unit of the installation may be or comprise at least one filtration bed and at least one adsorbent, the filtration bed(s) and the adsorbent(s) being in the same container or in different containers.

[0132] The one or more fixed bed reactors may comprise at least one hydrogenation catalyst, at least one hydrolysis catalyst and at least one sulfur resistant catalyst.

[0133] The installation may further comprise at least one cooling device for regulating the temperature of the gas flow passing through the catalytic converter unit or exiting the catalytic converter unit, or both.

[0134] The acid gas capture unit may be or comprise an amine treatment device, an acid gas absorption unit with one or more non-amine solvents, or a pressure swing adsorption unit or any combination thereof.

[0135] The installation may further comprise at least one cooling device for regulating the temperature of the gas flow exiting the compressor(s), as described herein.

[0136] With reference to [Fig.2], in a schematic presentation, one possible configuration for a facility or system for carrying out the method of the present embodiments is exemplified. Variations of this functionality may be used as described herein.

[0137] In [Fig. 2], unit operations are described for the facility or system 200. A first unit operation 202 which is a compression of a gas stream or waste gas is described. A gas stream 220 which may include a raw waste gas that is separated from carbon black after leaving a carbon black furnace may be obtained and introduced into the first unit operation 202. This gas stream is introduced into a device 222 for compressing the gas stream and / or pressurizing the gas stream. The device 222 may be, for example, a fan, a compressor, or another device that can bring the gas stream to a pressure desired, either just high enough to overcome the pressure drop of downstream processes, or at a higher pressure for better efficiency.

[0138] The installation of one or more devices (not shown in [Fig.2]) for removing particles and / or catalyst poisons from the gas stream may be used in the installation. For example, a filtration column or other device, upstream or downstream of the device 222 used to compress the gas stream (e.g., a precompression fan), may be filled with solid particles of various shapes and / or sizes and is optional. The part of the installation or system is optionally used to trap particles, such as carbon black particles and / or other particles to prevent or reduce the risk of clogging downstream of other units, such as the one or more catalytic reactors.

[0139] Depending on the purity of the gas, a guard bed 205, scrubber, or other device may be installed downstream of device 222 or other unit to compress the gas stream (e.g., a precompression 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.

[0140] In a second unit operation 204, the compressed gas stream or waste gas is conditioned to perform hydrolysis and hydrogenation (e.g., as described in the equations below) using a multifunctional catalyst or a combination of catalysts having the desired functionalities. In this second unit operation 204, devices (e.g., a hydrolysis device 224 and a hydrogenation device 226) are used to perform 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 may occur in the second unit operation in one or more devices that may be arranged in series with each other. Hydrolysis: CS2 + 2H2O -> 2H2S + CO2 COS + H2O -> H2S + CO2 HCN + H2O -> NH3 + CO. Hydrogenation: SO2+ 3H2 -> H2S + 2H2O O2 + H2 H2O O2 +CO -> CO2.

[0141] In a third unit operation 208, carbon dioxide and hydrogen sulfide are captured via an amine treatment system from the off-gas from unit operation 204 to produce a treated gas stream 244 having a high combustible value, such as a high hydrogen fuel with a high calorific value. The gas from 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 being discharged and potentially used beneficially in the carbon black manufacturing process, for example, as quench water, or in the various unit processes, if necessary.The cleaned waste gas 244 has a high energy value and can be directed to various beneficial uses, for example, a ground incinerator 260, which can be used to generate hot gas for an optional waste heat boiler 262, with the cooled gases being vented. The dirty amine solution leaves the column 240 and is heated in the heat exchanger 238 before being directed to the regeneration column 236, where hydrogen sulfide and carbon dioxide are desorbed from the amine solution to form an acid gas that is directed to the unit operation 210. The regenerated amine solution is passed through a boiler (e.g., the boiler 234 or a separate boiler) and reheated. The regenerated amine solution is cooled in the heat exchanger 238 and other optional heat exchangers before being directed back to the column 240.In preferred embodiments, the hydrogen sulfide removal efficiency is at least 99% (by volume) or the hydrogen sulfide concentration in the treated gas is, for example, at most 1 ppm.

[0142] In a fourth unit operation 210, a hydrogen sulfide-containing gas is removed from the acid 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, a catalyst regenerator, and a liquid-solid separator (all not shown) to remove sulfur 256 from the gas stream directed to the unit operation 210. The surge tank and pumps move the liquid catalyst through the various apparatus of the unit operation 210. The unit operation 210 may further include a filtration step to at least partially dry the resulting sulfur 256. In preferred embodiments, the elemental sulfur generated in the fourth unit operation has a purity of at least 99% (on a solid basis, by weight).

[0143] H2S may be captured by a single unit operation of absorbing sour gas from the produced waste gas stream from unit process 204. The sour gas stream may be processed in the next unit operation to oxidize H2S to elemental sulfur as a saleable product. This oxidation step captures sulfur from the sour gas stream and produces a clean moisture-containing sulfur removal off-gas stream 258 that may be discharged to the atmosphere. The carbon dioxide concentration in this stream may be high enough to warrant compression or otherwise beneficial use of the off-gas stream 258.

[0144] The volume flow rate of the tail gas is significantly lower than the flow rate of the combusted flue gas or the starting gas stream. Therefore, a reduced amount of equipment is required to treat the tail gas. Similarly, a reduced amount of sorbent is required, which further reduces the resulting amount of solid pollutant. Cooling the tail gas produces a condensate that can be used in other unit processes of the carbon black production process.

[0145] The implementation of the present invention comprises the following aspects / embodiments / features in any order and / or in any combination:

[0146] 1. Method for cleaning a gas stream comprising a generated waste gas during the production of carbon black, said method comprising compressing the gas stream to obtain a compressed gas stream; carrying out at least one hydrolysis reaction to obtain at least H2S, carrying out at least one hydrogenation reaction to convert at least one of SO2 and SO3 into H2S, and optionally carrying out at least one oxygen conversion reaction to remove O2 from the compressed gas stream, thereby obtaining a conditioned synthesis gas stream; removing at least a portion of said H2S from said conditioned synthesis gas stream to obtain an acid gas stream containing said H2S and obtaining a treated gas stream having combustible value; and converting at least a portion of the H2S in said sour gas stream to elemental sulfur and removing said elemental sulfur and obtaining a sulfur removal off-gas; wherein the oxygen conversion reaction(s) comprises either an additional hydrogenation reaction to convert O2 to H2O or a reaction to convert carbon monoxide to carbon dioxide or both.

[0147] 2. Method according to any one of the embodiments / features / aspects preceding or following, comprising, before carrying out said hydrolysis reaction(s), said hydrogenation reaction(s), the elimination of at least a portion of the possible particles and / or possible catalyst poisons from said gas stream or said compressed gas stream.

[0148] 3. Method according to any one of the embodiments / features / aspects preceding or following further comprising, before elimination, carrying out at least one gas to water conversion reaction on the conditioned synthesis gas stream.

[0149] 4. Method according to any one of the embodiments / features / aspects preceding or following, wherein said at least one water gas shift reaction is carried out using at least one sulfur-resistant catalyst which converts CO and H2O to CO2 and H2.

[0150] 5. Method according to any one of the embodiments / features / aspects preceding or following, wherein said gas stream consists of said waste gas generated during the production of carbon black.

[0151] 6. Method according to any one of the embodiments / features / aspects preceding or following, wherein said gas stream comes from at least two carbon black production units.

[0152] 7. Method according to any one of the embodiments / features / aspects preceding or following, wherein said gas stream comes from sources other than carbon black production.

[0153] 8. Method according to any one of the embodiments / characteristics / preceding or following aspects, wherein at least 80% by volume of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons and water, and further comprises traces of sulfur species and nitrogen species, and optionally HCl and PH3 and optionally particulates.

[0154] 9. Method according to any one of the embodiments / features / aspects preceding or following, wherein at least 80% by volume of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons and water, and further comprises traces of sulfur species and nitrogen species, and optionally one or more of HCl, and PH3 and particulates.

[0155] 10. Method according to any one of the embodiments / features / aspects preceding or following, wherein the gas stream comprises the following component concentrations: 3 to 30% by volume of CO, 0.5 to 10% by volume of CO2, 3 to 50% by volume of H2, 0.01 to 2% by volume of O2, 0.5 to 10% by volume of hydrocarbons, 1 to 50% by volume of water, 50 ppm to 10,000 ppm by volume of sulfur species, 50 ppm to 20,000 ppm by volume of nitrogen species, 0 to 20 ppm by volume of HCl, 0 to 10 ppm by volume of PH3, and 0 mg / Nm3 to 80 mg / Nm3 of particles.

[0156] 11. Method according to any one of the embodiments / characteristics / preceding or following aspects, wherein said compression uses at least one compressor.

[0157] 12. Method according to any one of the embodiments / features / aspects preceding or following, wherein said at least one hydrolysis reaction is carried out using at least one hydrolysis catalyst.

[0158] 13. Method according to any one of the embodiments / features / aspects preceding or following, wherein said at least one hydrogenation reaction is carried out using at least one hydrogenation catalyst.

[0159] 14. Method according to any one of the embodiments / features / aspects preceding or following, wherein said removal of at least a portion of any particles and / or catalyst poisons from said gas stream or said compressed gas stream comprises passing said gas stream or said compressed gas stream through at least one filtration bed and / or through at least one adsorbent.

[0160] 15. Method according to any one of the embodiments / features / aspects preceding or following, wherein said removal of at least a portion of said H2 S from said conditioned synthesis gas stream is accomplished using an amine treatment device, acid gas absorption with one or more non-amine solvents or pressure swing adsorption.

[0161] 16. Method according to any one of the embodiments / features / aspects preceding or following, wherein said conversion of at least a portion of the H2S in said sour gas stream to elemental sulfur is carried out using a liquid phase catalytic oxidation process or a gas phase combustion process.

[0162] 17. Method according to any one of the embodiments / features / aspects preceding or following, wherein said gas phase combustion process uses a Claus process which converts H2S and SO2 to H2O and S2.

[0163] 18. Method according to any one of the embodiments / characteristics / preceding or following aspects, wherein, during and / or immediately after said compression, the gas stream and / or the compressed gas stream is cooled.

[0164] 19. Method according to any one of the embodiments / features / aspects preceding or following, wherein said removing 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 of HCl and less than 5 ppm by volume of PH3.

[0165] 20. Method according to any one of the embodiments / features / aspects preceding or following, said method further comprising carrying out at least one reduction reaction of the compressed gas stream or the conditioned synthesis gas stream to convert at least a portion of the nitrogen-containing species into N2.

[0166] 21. Method according to any one of the embodiments / features / aspects preceding or following, wherein said at least one hydrolysis reaction converts sulfur species in the compressed gas stream to H2S, and said sulfur species comprise CS2, COS and organic sulfur.

[0167] 22. Method according to any one of the embodiments / features / aspects preceding or following, wherein said at least one hydrolysis reaction further converts HCN to NH3.

[0168] 23. Method according to any one of the embodiments / features / aspects preceding or following, wherein said at least one hydrogenation reaction converts SO2 and SO3 to H2S and converts O2 to either H2O or CO2 or both.

[0169] 24. Installation for cleaning a gas flow comprising a waste gas generated during the production of carbon black, said installation comprising: at least one compressor for compressing the gas flow so as to obtain a compressed gas flow; a catalytic converter unit comprising one or more fixed bed reactors which are configured to carry out at least one hydrolysis reaction to obtain at least H2S and carry out at least one hydrogenation reaction to obtain at least H2S, and obtain a conditioned synthesis gas stream; an acid gas capture unit for removing at least a portion of said H2S from said conditioned synthesis gas stream to obtain an acid gas stream containing said H2S and obtain a treated gas stream having combustible 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 obtaining a sulfur removal off-gas.

[0170] 25. Installation according to any of the embodiments / characteristics / preceding or following aspects, said installation further comprising a gas conditioning unit for removing particles and catalyst poisons from said gas stream or said compressed gas stream.

[0171] 26. Installation according to any of the embodiments / characteristics / preceding or following aspects, wherein said one or more bed reactors fixed include at least one hydrogenation catalyst and at least one hydrolysis catalyst

[0172] 27. Installation according to any of the embodiments / characteristics / preceding or following aspects, wherein said catalytic converter unit comprises one or more fixed bed reactors which are configured to convert oxygen into water.

[0173] 28. Installation according to any of the embodiments / features / aspects preceding or following cts, wherein said one or more fixed bed reactors comprise at least one sulfur-resistant catalyst.

[0174] 29. Installation according to any of the embodiments / features / aspects preceding or following cts, wherein the catalytic converter unit comprises one or more fixed bed reactors which are configured to carry out at least one gas-to-water conversion reaction.

[0175] 30. Installation according to any of the embodiments / features / aspects preceding or following cts, in which the gas conditioning unit comprises at least one filtration bed and at least one adsorbent, the filtration bed(s) and the adsorbent(s) being in the same container or in different containers.

[0176] 31. Installation according to any of the embodiments / features / aspects preceding or following cts, wherein said acid gas capture unit comprises an amine treatment device, an acid gas absorption unit with one or more non-amine solvents, or a pressure swing adsorption unit.

[0177] 32. Installation according to any of the embodiments / characteristics / preceding or following aspects, wherein said acid gas capture unit is configured to use a liquid phase catalytic oxidation process or a gas phase combustion process.

[0178] 33. Installation according to any of the embodiments / characteristics / preceding or following aspects, wherein said sulfur conversion unit is configured to use a Claus process which converts H2S and SO2 to H2O and S2.

[0179] 34. Installation according to any of the embodiments / features / aspects preceding or following cts, in which said installation further comprises at least one cooling device for regulating the temperature of the gas flow leaving the compressor(s).

[0180] EXAMPLE

[0181] In order to quantitatively demonstrate the process of the present embodiments, a simulation was performed using an Aspen simulation and based on aggregated data of waste gases from carbon black production facilities. In the simulation, an operational unit configured similarly to that of [Fig.2] was used. [Table IA]: Item Number Units 220 Inlet 205 Inlet 204 Outlet 204 Outlet 234 Inlet 240 Description Raw TG 220 Compressor Outlet 222 Operation Inlet 204 Operation Outlet 204 Boiler TG Outlet 234 Column TG Inlet 240 Flow Rate kmol / h 5533 5533 5532 5532 5532 3971 Flow Rate Nm3 / h 124000 124000 124000 123976 123977 89009 Flow Rate kg / h 113412 113412 113412 113 412 113 412 85222 Temperature deg.C 230.0 326.2 220.0 280.3 200.0 47.6 Pressure barg 0.03 0.65 0.51 0.41 0.31 0.30 Composition H2S ppmvw 1218 1218 1218 3002 3002 4101 SO2 ppmvw 209 209 209 21 21 27 COS ppmvw 274 274 274 1 1 2 CS2 ppmvw 668 668 668 7 7 6 N2 Mole % 34.21% 34.21% 34.21% 34.22% 34.22% 47.63% 02% in moles 0.24% 0.24% 0.24% 0.24% 0.24% 0.33% CH4 % moles 0.38% 0.38% 0.38% 0.38% 0.38% 0.53% C2H2 % moles 0.13% 0.13% 0.13% 0.13% 0.13% 0.18% H2 % moles 14.93% 14.93% 14.93% 19.59% 19.59% 27.29% CO2 % moles 1.51% 1.51% 1.51% 6.32% 6.32% 8.74% CO % moles 9.43% 9.43% 9.43% 4.72% 4.72% 6.56 % . H2O % in moles 38.93% 38.93% 38.93% 34.10% 34.10% 8.32% HCl ppmv 2.0 2.0 0.0 0.0 0.0 0.0 S % in moles 0 0 0 0 0 0

[0182] [TableauxlB] Item Number Units Outlet 242 244 Inlet 2 10 258 256 Description Condensate Outlet 241 from Cooler 242 TG Outlet from Column 2 40 Acid Gas from Amine Treatment Device 2 08 CO 2 Flow 258 Solid Sulphur Cake 256 Flow kmol / h 3782 206 189 Flow Nm3 / h 84 770 4610 4241 Flow kg / h 27 790 77 049 8173 7928 695 Temperature deg. C 47.7 47.6 47.6 50.0 50.0 Pressure barg 2.30 0.05 0.30 0.20 Composition H2S ppmvw 160 215 74 649 164 0 SO2 ppmvw 4 1 487 533 0 COS ppmvw 0 2 0 0 0 CS2 ppmvw 7 6 0 0 0 N2% in weights 0.05% 50.01% 0.00% 0.00% 0.00% 02% in weights 0.00% 0.35% 0.00% 0.04% 0.00% CH4% in weights 0.00% 0.55% 0.00% 0.00% 0.00% C2H2 % in average 0.00% 0.19% 0.00% 0.00% 0.00% H2 % in average 0.00% 28.65% 0.00% 0.00% 0.00% CO2 % in average 0.11% 4.59% 83.75% 91.73% 0.00% CO % in average 0.01% 6.89% 0.00% 0.00% 0.00% H2O % in average 99.80% 8.73% 8.73% 8.16% 41.83% HCl ppmv 0.0 0.0 0.0 0.0 0.0 S % in average 0 0 0 0 58.17%

[0183] As shown in Tables IA and IB, the amount of sulfur in the feed gas stream is almost completely removed with only 2 ppm COS and 6 ppm CS2 in the cleaned tail gas 244. The process, in the simulation, produced 695 kg / h of marketable elemental sulfur containing about 42 wt% water. The purity of the recovered components would also meet the desired disposal specifications for commercial sale for third party use.

[0184] More specifically, in this model process, a hypothetical tail gas, representative of the commonly used 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, with other components listed in Table 1A, was treated 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 listed in Table 1B. A 92% carbon dioxide stream (the balance being water) was generated for further processing, such as compression, dehydration, liquefaction, etc., for sequestration or use in other beneficial processes.The 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.

[0185] The present embodiments may comprise any combination of these different features or different embodiments above and / or below, as described herein in sentences and / or paragraphs. Any combination of the features described herein is considered to be part of the present embodiments and no limitation is intended with respect to the features that can be combined.

[0186] Applicant specifically incorporates the entire contents of all cited references into this disclosure. Furthermore, where a quantity, concentration, or other value or parameter is given as a range, preferred range, or list of preferred upper and preferred lower values, this is to be understood as specifically indicating all ranges formed from any pair of any upper preferred range limit or value and any lower preferred range limit or value, regardless of whether the ranges are separately described. Where a range of numerical values ​​is herein referred to, unless otherwise indicated, the range is intended to include its endpoints, as well as all integers and fractions within the range.It is not intended that the scope of the embodiments be limited to the specific values ​​stated when defining a range.

[0187] Other embodiments of the present implementations will become apparent to those skilled in the art upon reading this description and practicing the presently disclosed embodiments. It is to be understood that this description and the examples are to be considered as given by way of example only, the true scope and spirit of the embodiments being indicated by the following claims and equivalents thereof.

[0188] The above description of preferred implementations of the present embodiments has been presented for purposes of illustration and description. Modifications and variations are possible in light of the above teachings, or may be determined from practice of the embodiments. The embodiments have been selected and described to explain the principles of implementation and their practical application to enable those skilled in the art to use the embodiments in different embodiments and with different modifications suitable for the particular use contemplated.

Claims

Claims

1. A method of cleaning a gas stream comprising a waste gas generated during carbon black production, said method 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 to H2S, and optionally performing 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 obtaining a treated gas stream having a combustible value; and converting at least a portion of the H2S in said sour gas stream to elemental sulfur and removing said elemental sulfur and obtaining a sulfur removal off-gas;wherein the oxygen conversion reaction(s) comprises either an additional hydrogenation reaction to convert O2 to H2O or a reaction to convert carbon monoxide to carbon dioxide or both.;

2. A method according to claim 1, comprising, before carrying out said at least one hydrolysis reaction, said at least one hydrogenation reaction, removing at least a portion of any catalyst particles and / or poisons from said gas stream or said compressed gas stream.

3. A method according to claim 1 or 2, further comprising, prior to removal, performing at least one water gas shift reaction on the conditioned synthesis gas stream.

4. The method of claim 3, wherein said at least one water gas shift reaction is carried out using at least one sulfur-resistant catalyst that converts CO and H2O to CO2 and H2.

5. A method according to any one of claims 1 to 4, wherein said gas stream consists of said waste gas generated during carbon black production.

6. A method according to any one of claims 1 to 5, wherein said gas stream originates from at least two carbon black production units.

7. A method according to any one of claims 1 to 6, wherein said gas stream is from sources other than carbon black production.

8. A method 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 further comprises traces of sulfur species and nitrogen species, and optionally HCl and PH3 and optionally particulates.

9. A method according to any one of claims 1 to 8, wherein at least 80% by volume of the gas stream is CO, CO2, N2, O2, H2, hydrocarbons and water, and further comprises traces of sulfur species and nitrogen species, and optionally one or more of HCl, PH3 and particulates.

10. A method according to any one of claims 1 to 9, wherein the gas stream comprises the following component concentrations: 3 to 30% by volume of CO, 0.5 to 10% by volume of CO2, 3 to 50% by volume of H2, 0.01 to 2% by volume of O2, 0.5 to 10% by volume of hydrocarbons, 1 to 50% by volume of water, 50 ppm to 10,000 ppm by volume of sulfur species, 50 ppm to 20,000 ppm by volume of nitrogen species, 0 to 20 ppm by volume of HCl, 0 to 10 ppm by volume of PH3, and 0 mg / Nm3 to 80 mg / Nm3 of particulates.

11. A method according to any one of claims 1 to 10, wherein said compression uses at least one compressor.

12. A method according to any one of claims 1 to 11, wherein said at least one hydrolysis reaction is carried out using at least one hydrolysis catalyst.

13. A method according to any one of claims 1 to 12, wherein said at least one hydrogenation reaction is carried out using at least one hydrogenation catalyst.

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

15. A method according to any one of claims 1 to 14, wherein said removal of at least a portion of said H2S from said conditioned syngas stream is accomplished using an amine treatment device, acid gas absorption with one or more non-amine solvents, or pressure swing adsorption.

16. A method according to any one of claims 1 to 15, wherein said conversion of at least a portion of the H2S in said sour gas stream to elemental sulfur is carried out using a liquid phase catalytic oxidation process or a gas phase combustion process.

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

18. A method according to any one of claims 1 to 17, wherein, during and / or immediately after said compression, the gas stream and / or the compressed gas stream are cooled.

19. The method of claim 2, wherein said removing 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 of HCl and less than 5 ppm by volume of PH3.

20. A method according to any one of claims 1 to 19, said method further comprising carrying out at least one reduction reaction of the compressed gas stream or the conditioned synthesis gas stream to convert at least a portion of the nitrogen-containing species to N2.

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

22. A method according to any one of claims 1 to 21, wherein said at least one hydrolysis reaction further converts HCN to NH3.

23. A method according to any one of claims 1 to 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 plant for cleaning a gas stream comprising a waste gas generated during the production of carbon black, said plant 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 which are configured to carry out at least one hydrolysis reaction to obtain at least H2S and carry out at least one hydrogenation reaction to obtain at least H2S, and obtain a conditioned syngas stream; an acid gas capture unit for removing at least a portion of said H2S from said conditioned syngas stream to obtain a acid gas stream containing said H2S and obtain a treated gas stream having a combustible 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 obtaining a sulfur removal off-gas.;

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

26. Plant according to claim 24 or 25, wherein said one or more fixed bed reactors comprise at least one hydrogenation catalyst and at least one hydrolysis catalyst

27. A plant according to any one of claims 24 to 26, wherein said catalytic converter unit comprises one or more fixed bed reactors which are configured to convert oxygen into water.

28. Plant according to claim 27, wherein said one or more fixed bed reactors comprise at least one sulfur-resistant catalyst.

29. An installation according to any one of claims 24 to 28, wherein the catalytic converter unit comprises one or more fixed bed reactors which are configured to carry out at least one gas-to-water conversion reaction.

30. Installation according to any one of claims 24 to 29, in which the gas conditioning unit comprises at least one filtration bed and at least one adsorbent, the filtration bed(s) and the adsorbent(s) being in the same container or in different containers.

31. Plant according to any one of claims 24 to 30, wherein said acid gas capture unit comprises an amine treatment device, an acid gas absorption unit with one or more non-amine solvents, or a pressure swing adsorption unit.

32. A plant according to any one of claims 24 to 31, wherein said acid gas capture unit is configured to use a liquid phase catalytic oxidation process or a gas phase combustion process.

33. A plant according to any one of claims 24 to 32, wherein said sulfur conversion unit is configured to use a Claus process which converts H2S and SO2 to H2O and S2.

34. Installation according to any one of claims 24 to 33, wherein said installation further comprises at least one cooling device for regulating the temperature of the gas flow leaving the compressor(s).

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