Steel industry decarbonization system and relative method

Abstract

A system to treat coke oven gas (COG), in particular coke oven gas produced by a steel plant, configured to receive a coke oven gas stream. The innovative system comprises a compression unit (100) configured to receive the coke oven gas stream, to compress it and to discharge a compressed coke oven gas stream; a separation unit (200) configured to receive the compressed coke oven gas stream, perform a hydrogen (=H2) separation and discharge an hydrogen stream and a gas stream comprising methane (=CH4) and other unreacted components of the coke oven gas stream; a pyrolysis unit (300) configured to receive the gas stream comprising methane and other unreacted components of the coke oven gas and perform pyrolysis of the stream comprising methane and other unreacted components of the coke oven gas stream so to discharge solid carbon (=C) and a gas stream comprising hydrogen and other unreacted components of the coke oven gas stream.

Description

TITLESteel industry decarbonization system and relative methodDESCRIPTIONTECHNICAL FIELD

[0001] The subject-matter disclosed herein relates to a system to treat coke oven gas (COG), in particular coke oven gas (COG) produced by a steel plant and a method for performing decarbonization of coke oven gas (COG) produced by a steel plant.BACKGROUND ART

[0002] Steel industry is one of the hard-to-abate emission industry, as it depends heavily on coal, in particular coke, as reducing agent in the iron production step. About 2 tons of carbon dioxide (CO2) is emitted for every ton steel produced. Because of the high CO2 footprint of the steel industry, there is the need to decarbonize the steel industry in order to meet Paris agreement on climate change.

[0003] In the steel-making process, coke is used in the blast furnace as a chemical-reducing agent for the reduction of iron oxides. Coke Oven Gas (COG) is one of the important by-product gases of the steel-making process. The main components of COG are hydrogen (~56%) and methane (~24.5%). COG also contains small amounts of CO (~6.3%), CO2 (~2%), N2 (~4.4%) and H2O (~6.7%). Most of the COG is traditionally burnt off in torches and even in some cases directly emitted to the air and in some cases only the latent heat of the COG is utilized. Consequently, COG represents serious ineffective use of energy, though it contains 60 mol% H2 and 30 mol% CH4, which also results in environmental pollution.

[0004] Therefore, there is the need of utilize the COG effectively. In particular, there is the need of reducing the carbon emissions (e.g. carbon dioxide) for the steelmaking process, advantageously to perform a carbon neutral or eventually carbon negative steelmaking process.SUMMARY

[0005] According to an aspect, the subject-matter disclosed herein relates to an innovative system to treat coke oven gas (=COG), in particular coke oven gas produced by a steel plant, configured to receive a coke oven gas stream. The innovative system comprises a compression unit configured to receive the coke oven gas stream, to compress it and to discharge a compressed coke oven gas stream; a separation unit configured to receive the compressed coke oven gas stream, perform a hydrogen (=H2) separation and discharge an hydrogen stream and a gas stream comprising methane (=CH4) and other unreacted components of the coke oven gas stream; a pyrolysis unit configured to receive the gas stream comprising methane and other unreacted components of the coke oven gas and perform pyrolysis of the stream comprising methane and other unreacted components of the coke oven gas stream so to discharge solid carbon (=C) and a gas stream comprising hydrogen and other unreacted components of the coke oven gas stream.

[0006] According to another aspect, the subject-matter disclosed herein relates to a steel plant comprising an innovative system to treat coke oven gas (COG).

[0007] According to another aspect, the subject-matter disclosed herein relates to a method for performing decarbonization of coke oven gas (COG) produced by a steel plant, the method comprising the steps of performing compression of the coke oven gas stream so to produce a compressed coke oven gas stream; perform separation of the compressed coke oven gas streamso to produce a hydrogen (=H2) stream and a gas stream comprising methane (=CH4); perform pyrolysis of the gas stream comprising methane so to produce solid carbon (=C) and a gas stream comprising hydrogen.BRIEF DESCRIPTION OF THE DRAWINGS

[0008] A more complete appreciation of the disclosed embodiments of the invention and many of the attendant advantages thereof will be readily obtained as the same becomes better understood by reference to the following detailed description when considered in connection with the accompanying drawings, wherein:Fig. 1 shows a schematic simplified diagram of a first embodiment of an innovative system to treat coke oven gas,Fig. 2 shows a schematic simplified diagram of a second embodiment of an innovative system to treat coke oven gas,Fig. 3 shows a schematic diagram of an example of pyrolysis unit of the innovative system of Fig. 1 or Fig. 2,Fig. 4 shows a schematic diagram of an example of residual carbon monoxide process unit of the innovative system of Fig. 2,Fig. 5 shows a schematic diagram of an example of methanation unit of the innovative system of Fig. 2, andFig. 6 shows a flow chart of an embodiment of a method for performing decarbonization of coke oven gas (COG) produced by a steel plant.DETAILED DESCRIPTION OF EMBODIMENTS

[0009] According to an aspect, the subject-matter disclosed herein relates to an innovative system to reduce carbon emissions (e.g. carbon dioxide) for the steelmaking process, in particular to perform a carbon neutral (or carbonnegative) steelmaking process. The innovative system is configured to treat coke oven gas (=COG) produced by a steel plant so to process and / or separate carbon components of the coke oven gas and exploit the hydrogen contained in the coke oven gas e.g. for producing electrical power and / or to generate a hydrogen stream to be used for example in steelmaking applications (in particular replacing the use of methane or other energy sources containing carbon components which may produce carbon dioxide). The innovative system proposes to use gas separation systems like Pressure Swing Adsorption (=PS A) technology to separate hydrogen (=H2) from coke oven gas after being compressed and to process tail gas from gas separation system, which is rich in methane (=CH4), through a methane pyrolysis process so to generate solid carbon (=C) and tail gas rich in hydrogen. Advantageously, tail gas rich in hydrogen is further compressed and processed so to separate hydrogen from other unreacted components of the coke oven gas stream (e.g. N2, CO2...). Unreacted components of the coke oven gas stream are sent to a CO2 capture unit so to separate carbon dioxide (=CO2) and discharge CO2 free flue gas to atmosphere. Finally, hydrogen is processed to be used for example in steelmaking applications (e.g. in the blast furnace or for Direct Reduced Ironmaking =DRI) or commercial use of hydrogen.

[0010] Reference now will be made in detail to embodiments of the disclosure, examples of which are illustrated in the drawings. The examples and drawing figures are provided by way of explanation of the disclosure and should not be construed as a limitation of the disclosure. In fact, it will be apparent to those skilled in the art that various modifications and variations can be made in the present disclosure without departing from the scope or spirit of the disclosure. In the following description, similar reference numerals are used for the illustration of figures of the embodiments to indicate elements performing the same or similar functions. Moreover, for clarity of illustration, some references may be not repeated in all the figures.

[0011] Fig. 1 shows a simplified diagram of a first embodiment of an innovative system to treat coke oven gas (=COG) 1000, referred in the following as “system 1000”. A second embodiment of an innovative system to treat coke oven gas (=COG) 2000 will be described in the following with the aid of Fig. 2. The system 1000 and 2000 is configured to receive a coke oven gas stream to be treated. According to a preferred solution, system 1000 and 2000 is configured to receive a coke oven gas stream produced by a steel plant. Fig. 3, Fig. 4 and Fig. 5 shows respectively a schematic diagram of an example of pyrolysis unit of the innovative system of Fig. 1 or Fig. 2, an example of a residual carbon monoxide process unit of the innovative system of Fig. 2 and an example of methanation unit of the innovative system of Fig. 2.

[0012] It is to be noted that, for the purpose of the present disclosure, the “coke oven gas” is a gas comprising hydrogen (=H2), methane (=CH4), carbon dioxide (=CO2), carbon monoxide (=CO), nitrogen (=N2) and water (=H2O). In particular, according to a possibility, the coke oven gas may have the following composition:

[0013] With non-limiting reference to Fig. 1, the system 1000 includes a firstcompression unit 100 which has a compression inlet 101 configured to receive the coke oven gas. For example, the compression inlet 101 may be fluidly coupled to a duct which may supply the coke oven gas stream. Advantageously, the duct may be fluidly coupled to a steel plant so to supply coke oven gas produced by the steel plant to the first compression unit 100. Typically, the coke oven gas stream is supplied to the compression inlet 101 at ambient pressure, e.g. 1 bar. The first compression unit 100 is configured to compress the coke oven gas stream so to discharge at a compression outlet 109 of the compression unit 100 a compressed coke oven gas stream. For example, the coke oven gas at the compression outlet 109 may be compressed up to around 20 bar.

[0014] The system 1000 further includes a first separation unit 200 which has a separation inlet 201 fluidly coupled to the compression outlet 109 of the first compression unit 100 and configured to receive the compressed coke oven gas stream from the compression outlet 109. The first separation unit 200 is configured to perform a hydrogen separation so to discharge a hydrogen stream at a first separation outlet 208 and a gas stream comprising methane (=CH4) and other unreacted components of the coke oven gas stream (e.g. N2, CO, CO2...) at a second separation outlet 209. According to a preferred embodiment, the first separation unit is configured to perform separation of hydrogen using a gas separation system, for example using Pressure Swing Adsorption (=PSA) technology; in other words, the first separation unit 200 comprises a plurality of adsorbent and desorbent vessels configured to perform Pressure Swing Adsorption.

[0015] Advantageously, the hydrogen stream discharged at the first separation outlet 208 may be further compressed, e.g. the system 1000 and 2000 may comprise at least another compression unit 810. In particular, the compression unit 810 has a compression inlet 811 fluidly coupled to the first separation outlet 208 and configured to receive the hydrogen stream from thefirst separation outlet 208. The compression unit 810 is configured to compress the hydrogen stream and to discharge a compressed hydrogen stream at a compression outlet 819 (see e.g. Fig. 1 and Fig. 2).

[0016] According to a first possibility, shown for example in Fig. 1, the compressed hydrogen stream discharged at the compression outlet 819 may be used to produce electrical power. In particular, the system 1000 may further comprise a power generation unit 820, which may be for example one or more fuel cell or gas turbine, fluidly coupled to the compression outlet 819. The power generation unit 820 is configured to receive the compressed hydrogen stream from the compression outlet 819 and to process it so to produce electrical energy. For example, the power generation unit 820 may be a gas turbine assembly comprising a gas turbine and an electrical generator and configured to use the compressed hydrogen stream as a fuel in the combustor of the gas turbine so to produce burned gas to be expanded in the gas turbine, thus producing mechanical energy to be converted by the electrical generator into electrical energy EE.

[0017] It is to be noted that the process of electrical energy production performed by the power generation unit 820 may be CO2 free. It is also to be noted that the electrical energy EE produced by the power generation unit 820 may be exported to an electrical grid or may be for self-use of the innovative system or of the steel plant which may provide coke oven gas to the innovative system.

[0018] According to a second possibility, shown for example in Fig. 2, the compressed hydrogen stream discharged at the compression outlet 819 may be stored and / or used for example in steelmaking applications (e.g. in the blast furnace or for Direct Reduced Ironmaking =DRI). It is to be noted that in Fig. 2 only one additional compression unit 810 is shown; however, the system 2000 may comprise a plurality of compression unit 810 in order to performcompression of hydrogen through a plurality of compression stages.

[0019] According to a third possibility, not shown in any figure, the compressed hydrogen stream discharged at the compression outlet 819 may be used both to produce electrical power and may be stored and / or used for example in steelmaking applications. In particular, a first portion of the compressed hydrogen stream discharged at the compression outlet 819 may be used to produce electrical power and a second portion of the compressed hydrogen stream discharged at the compression outlet 819 may be stored and / or used for example in steelmaking applications. Alternatively, the system 1000 and 2000 may include at least two compression unit 810 configured to respectively discharge a first stream of compressed hydrogen at a first outlet compression outlet 819 and a second stream of compressed hydrogen at a second outlet compression outlet 819, in which the first stream is provided to a power generation unit 820 and is used to produce electrical power and the second stream is stored and / or used for example in steelmaking applications.

[0020] With non-limiting reference to Fig. 1, the system 1000 includes further a pyrolysis unit 300 which has a pyrolysis inlet 301 fluidly coupled to the second separation outlet 209 and configured to receive the gas stream comprising methane and other unreacted components of the coke oven gas stream from the second separation outlet 209. The pyrolysis unit 300 is configured to perform pyrolysis of the stream comprising methane CH4 and other unreacted components of the coke oven gas COG stream.

[0021] According to a first possibility, the pyrolysis unit 300 is configured to perform a non-thermal pyrolysis, in particular a plasma-based pyrolysis or a microwave pyrolysis or any combination thereof. According to a second possibility, the pyrolysis unit is configured to perform a thermal pyrolysis.

[0022] It is known that the pyrolysis of methane produces solid carbon C and gaseous hydrogen H2 according to the pyrolysis reactionCH42H2+ C which is an endothermic reaction, therefore requiring energy (=Q) to be carried out. Advantageously, as it will better described in the following, the energy Q to carry out the pyrolysis reaction may be in form of heat (provided at least partially, eventually totally, by another unit of the system 2000) or electric power, depending on the type of pyrolysis performed by the pyrolysis unit 300. The pyrolysis unit 300 has a first pyrolysis outlet 308 configured to discharge solid carbon produced through the pyrolysis reaction and a second pyrolysis outlet 309 configured to discharge a gas stream comprising hydrogen (which is produced through the pyrolysis reaction) and other unreacted components of the coke oven gas stream (which come from the second separation outlet 209 and are not involved in the pyrolysis reaction).

[0023] In particular, if the pyrolysis unit 300 performs a non-thermal pyrolysis, the pyrolysis unit 300 is electrically coupled to a power source configured to provide electrical power to the pyrolysis unit 300. More in particular, the power source is one of the following sources: national electrical grid, microgrid, hydrogen or any low carbon fuel gas turbine, renewable plant, hydrogen or any low carbon fuel cell, microgrid. Advantageously, as it will better described below, the fuel of the gas turbine or the fuel cell power source may be hydrogen or a gas stream containing hydrogen produced by the innovative system 1000.

[0024] According but not limited to the embodiment shown in Fig. 2, the system 2000 further comprises a second compression unit 400 having a compression inlet 401 fluidly coupled to the second pyrolysis outlet 309 and configured to receive the gas stream comprising hydrogen and other unreacted components of the coke oven gas stream from the second pyrolysis outlet 309. The second compression unit 400 is configured to compress the gas stream comprising hydrogen and other unreacted components of the coke oven gasstream and to discharge a compressed gas stream comprising hydrogen and other unreacted components of the coke oven gas stream at a compression outlet 409.

[0025] Advantageously, the system 2000 further comprises a residual carbon monoxide process unit 500 having a residual carbon monoxide process inlet 501 fluidly coupled to the compression outlet 409 and configured to receive the compressed gas stream comprising hydrogen and other unreacted components of the coke oven gas stream from the compression outlet 409. Fig. 4 shows an example of a residual carbon monoxide process unit 500 which comprises a reactor 510 configured to perform water gas shift (=WGS) reaction and a second separation unit 520 configured to perform a hydrogen separation; advantageously, the second separation unit 520 is configured to perform separation of hydrogen using Pressure Swing Adsorption (=PSA) technology. In particular, the reactor 510 is configured to receive the compressed gas stream comprising hydrogen and other unreacted components of the coke oven gas stream at the residual carbon monoxide process inlet 501 and a steam flow at a secondary reactor inlet 502 and to perform water gas shift reaction co + H2O H2+ CO2

[0026] The reactor 510 is further configured to discharge an outlet stream of WGS reaction at a reactor outlet 519. In addition, it is to be noted that WGS reaction is an exothermic reaction, therefore energy, in particular in form of heat, is generated when the reaction is carried out; advantageously, the heat generated in the reactor 510 may be used for example to generate the steam flow to be supplied to the secondary reactor inlet 502.

[0027] With non-limiting reference to Fig. 4, the second separation unit 510 has a separation inlet 521 fluidly coupled to the reactor outlet 519 and configured to receive the outlet stream of WGS reaction. As previously mentioned, the second separation unit 520 is configured to perform hydrogenseparation of the outlet stream of WGS reaction so to discharge a hydrogen stream at a second residual carbon monoxide process outlet 509 and to discharge a stream of tail gas (i.e. a gas stream comprising carbon dioxide, unreacted methane, unreacted hydrogen and nitrogen) at a first residual carbon monoxide process outlet 508. Advantageously, as it will be better described in the following, the stream of tail gas discharged at the first residual carbon monoxide process outlet 508 has heating value and may be used to provide energy Q to the pyrolysis unit 300 in order to carry out the pyrolysis reaction.

[0028] In particular, Fig. 3 shows a schematic diagram of an example of the pyrolysis unit 300 of the innovative system 1000 and 2000. With non-limiting reference to Fig. 3, the pyrolysis unit 300 comprises a pyrolysis reactor 320 which is fluidly coupled to the pyrolysis inlet 301 and receives the gas stream comprising methane and other unreacted components of the coke oven gas stream from the second separation outlet 209 so to perform pyrolysis reaction and generate an outlet stream of pyrolysis reaction at a pyrolysis reactor outlet 329.

[0029] According but not limited to the example shown in Fig. 3, the pyrolysis unit 300 further comprises a carbon separator 340 having a carbon separator inlet 341 fluidly coupled to the pyrolysis reactor outlet 329 and configured to receive the outlet stream of pyrolysis reaction. The carbon separator 340 is configured to perform a separation of the outlet stream of pyrolysis reaction so to remove solid carbon C from the outlet stream of pyrolysis reaction and discharge solid carbon C at the first pyrolysis outlet 308 and a stream of the remaining components (i.e. a gas stream comprising hydrogen and other unreacted components of the coke oven gas stream) at a carbon separator outlet 349. It is to be noted that solid carbon discharged at the first pyrolysis outlet 308 may be used for example in the steelmaking process, in particular to replace coke typically used in the blast furnace.

[0030] Advantageously, the pyrolysis unit 300 further comprises a dryer 350 having a dryer inlet 351 fluidly coupled to the carbon separator outlet 349 and configured to receive the gas stream comprising hydrogen and other unreacted components of the coke oven gas stream. The dryer 350 is configured to remove water or any moisture from the gas stream comprising hydrogen and other unreacted components of the coke oven gas stream and discharge a gas stream comprising hydrogen and other unreacted components of the coke oven gas stream which does not contain water at the second pyrolysis outlet 309.

[0031] As already stated before, the pyrolysis reaction requires energy to be carried out. The system 2000 may further comprise a furnace 800 having a first furnace inlet 801 fluidly coupled to the first separation outlet 508 and configured to receive the gas stream comprising carbon dioxide, unreacted methane, unreacted hydrogen and nitrogen from the first separation outlet 508. The furnace 800 is configured to combust the gas stream comprising carbon dioxide, unreacted methane, unreacted hydrogen and nitrogen with air or oxygen supplied at a second furnace inlet 802 so to produce heat to be supplied to the pyrolysis unit 300, in particular to the pyrolysis reactor 320, and discharge flue gases, in particular comprising carbon dioxide CO2, at a furnace outlet 809. As it will be better described in the following, in order to discharge a CO2 free flue gases in atmosphere, the furnace outlet 809 may be advantageously fluidly coupled to a CO2 capture unit 700 so to capture CO2 in the CO2 capture unit 700.

[0032] Advantageously, as shown for example in Fig. 3, the first furnace inlet 801 and the second furnace inlet 802 may be coupled to a mixing unit 810 configured to mix the gas stream comprising carbon dioxide, unreacted methane, unreacted hydrogen and nitrogen with air or oxygen (i.e. generating a mixed stream) before being supplied to the furnace 800. Even more advantageously, the system 2000 may further comprise a heat exchanger 330 fluidly coupled to the furnace 800 and the pyrolysis reactor 320. In particular,as shown in Fig. 3, the heat exchanger 330 has an inlet 331 fluidly coupled to the pyrolysis reactor outlet 329 in order to receive the outlet stream of pyrolysis reaction and exploit heat capacity of the outlet stream of pyrolysis reaction so to transfer heat from the outlet stream of pyrolysis reaction to the mixed stream before being supplied to the furnace 800.

[0033] It is to be noted that the furnace 800 (and possibly the mixing unit 810 and / or the heat exchanger 330) may be integrated into the pyrolysis unit 300 (see for example Fig. 3) or may be external to the pyrolysis unit 300 (see the schematic simplified diagram of Fig. 2).

[0034] Advantageously, as shown in the embodiment of Fig. 2, the system 2000 may further comprise a methanation unit 600 having a methanation inlet 601 fluidly coupled to the second residual carbon monoxide process outlet 509 and configured to receive the hydrogen stream from the second residual carbon monoxide process outlet 509. The methanation unit 600 is configured to perform methanation of the hydrogen stream according to the reactionCO2+ 4W2CW4+ 2H2O which is an exothermic reaction, therefore generating energy, in particular in the form of heat, when carried out. Advantageously, as it will better described in the following, the heat produced by the methanation reaction may be at least partially, eventually totally, provided to another unit of the system 2000, for example to the residual carbon monoxide process unit 500. The methanation unit 600 has a first methanation outlet 608 configured to discharge a water stream, in particular a liquid water stream, produced through the methanation reaction and a second methanation outlet 609 configured to discharge a methane stream produced through the methanation reaction.

[0035] In particular, Fig. 5 shows a schematic diagram of an example of the methanation unit 600 of the innovative system 2000. With non-limitingreference to Fig. 5, the methanation unit 600 comprises a methanation reactor 610 configured to receive the hydrogen stream from the methanation inlet 601 and a CO2 stream at a second methanation inlet 602; advantageously, as it will be better described in the following, the CO2 stream is partially, at least totally provided by a CO2 capture unit 700 of the system 2000. Possibly, the hydrogen stream received by the methanation inlet 601 may be integrated with part of the hydrogen stream discharged by the first separation outlet 208 of the first separation unit 200. The methanation reactor 610 is configured to perform methanation of the hydrogen stream according to the methanation reaction provided above. The reactor 610 is further configured to discharge an outlet stream of methanation reaction at a reactor outlet 619.

[0036] The methanation unit 600 further comprises a methanation separator 630 which has a separator inlet 631 fluidly coupled to the reactor outlet 619 and configured to receive the outlet stream of methanation reaction from the reactor outlet 619. The methanation separator 630 is configured to perform separation of the outlet stream of methanation reaction in order to discharge a water stream, in particular a liquid water stream, at the first methanation outlet 608 and a methane stream at the second methanation outlet 609.

[0037] Advantageously, the methanation unit 600 further comprises a heat exchanger 620 fluidly coupled to the methanation reactor 610 and the methanation separator 630. In particular, as shown in Fig. 5, the heat exchanger 620 receives the outlet stream of methanation reaction and exploit heat capacity of the outlet stream of methanation reaction so to transfer heat from the outlet stream of pyrolysis reaction to another stream before being supplied to the methanation separator 630. Advantageously, the heat exchanger 620 is configured to transfer heat from the outlet stream of methanation reaction to a water stream (=W) in order to produce a steam flow (=S) which may be advantageously supplied to the residual carbon monoxide process unit 500, inparticular to the secondary reactor inlet 502 of the reactor 510.

[0038] As already mentioned above, the system 2000 may advantageously include a CO2 capture unit 700 (see for example Fig. 2), such as an amine- based system, configured to perform CO2 capture. The CO2 capture unit 700 has a main inlet 701 fluidly coupled to the first furnace outlet 809 and configured to receive the flue gas from the first furnace outlet 809. The CO2 capture unit 700 can separate CO2 from the flue gas so to discharge a CO2 free stream at a first outlet 708 and a CO2 stream at a second outlet 709. Advantageously, the second outlet 709 is fluidly coupled to the second methanation inlet 602 so to provide the CO2 stream to the methanation unit 600 in order to perform the methanation reaction. It is to be noted that the CO2 stream provided by the CO2 capture unit 700 to the methanation unit 600 may be enough to perform the methanation reaction or may be possibly integrated with another CO2 stream provided by an external CO2 source.

[0039] For example, with non-limiting reference to Fig. 2, the system 2000 may further comprise a mixer unit 900 having a first mixer inlet 901 and a second mixer inlet 902. In particular, the first mixer inlet 901 is configured to receive a CO2 stream from an external CO2 source and the second mixer inlet 902 is fluidly coupled to the second outlet 709 of the CO2 capture unit so to receive the CO2 stream from the second outlet 709. The mixer unit 900 has further a mixer outlet 903 and is configured to combine the CO2 streams from the first mixer inlet 901 and the second mixer inlet 902 so to discharge a combined CO2 stream at the mixer outlet 903. Advantageously, the mixer outlet 903 is fluidly coupled to the second methanation inlet 602 so to supply the combined CO2 stream to the methanation unit 600. It is to be noted that according to a possibility, the CO2 stream provided at the first mixer inlet 901 may be null (i.e. the stream supplied at the mixer outlet 903 is equal to the stream received at the second mixer inlet 902).

[0040] According to another aspect, the subj ect-matter disclosed herein refers to a steel plant comprising the innovative system 1000 and 2000 described above.

[0041] Typically, a steel plant comprises a blast furnace and / or a reduction unit. Advantageously, the hydrogen H2 stream(s) discharged by the system 1000 and 2000 is / are provided to the blast furnace and / or to the reduction unit as reducing agent for DRI application. According to another possibility, the hydrogen H2 stream(s) discharged by the system 1000 and 2000 may be sold.

[0042] The steel plant may further comprise a heating unit for providing heat plant for steel making processes. Advantageously, the hydrogen H2 stream(s) discharged by the system 1000 and 2000 is / are further provided to the heating unit and used for heating application within the steel plant for steel making processes, in particular for steel making processes such as steel casting, reheating, rolling, etc.

[0043] According to still another aspect, the subject-matter disclosed herein refers to a method 3000 for performing decarbonization of coke oven gas produced by a steel plant. With non-limiting reference to Fig. 6, the method comprises the steps of:A. Perform compression of the coke oven gas stream so to produce a compressed coke oven gas stream (see block 910 in Fig. 6);B. Perform separation of the compressed coke oven gas stream so to produce a hydrogen stream and a gas stream comprising methane (see block 920 in Fig. 6);C. Perform pyrolysis of the gas stream comprising methane so to produce solid carbon and a gas stream comprising hydrogen (see block 930 in Fig. 6).

[0044] As already mentioned, step B is preferably performed through Pressure Swing Adsorption (=PSA) process to separate hydrogen from the compressed coke oven gas. Advantageously, the hydrogen stream generated at step B is used in a power generation unit, in particular a gas turbine or a fuel cell, so to generate electrical energy, and / or in a blast furnace of the steel plant and / or in a reduction unit of the steel plant as reducing agent for DRI application and / or in a heating unit of the steel plant for heating application within the steel plant for steel making processes and / or is sold.

[0045] With non-limiting reference to Fig. 6, the method may further comprise a step D of performing compression of the gas stream comprising hydrogen produced at step C (see block 940 in Fig. 6).

[0046] With non-limiting reference to Fig. 6, the method may further comprise a step E of performing water gas shift reaction of the compressed gas stream comprising hydrogen produced at step D and subsequent separation so to produce a hydrogen stream and a gas stream comprising carbon dioxide, unreacted methane, unreacted hydrogen and nitrogen (see block 950 of Fig. 6).

[0047] Advantageously, the heat value of the gas stream comprising carbon dioxide, unreacted methane, unreacted hydrogen and nitrogen may be exploited and used to provide energy Q to perform step C. According to a first possibility, the energy Q is in the form of electrical power provided by an external power source, for example national electrical grid, microgrid, hydrogen or any low carbon fuel gas turbine, renewable plant, hydrogen or any low carbon fuel cell or microgrid. Advantageously, the fuel of the gas turbine or the fuel cell power source is hydrogen or a gas stream containing hydrogen produced at step E.

[0048] According to second possibility, the method 3000 may further comprise a step F of producing energy Q in form of heat (see block 960 of Fig.6) by combusting, in particular in a furnace, the gas stream comprising carbon dioxide, unreacted methane, unreacted hydrogen and nitrogen produced at step E so to produce heat (to be used to perform step C) and flue gases. Since flue gases produced at step F may contain CO2, the flue gases are advantageously treated by a CO2 capture unit, for example an amine-based system, so to generate a CO2 stream and a CO2 free stream.

[0049] With non-limiting reference to Fig. 6, the method may further comprise a step G of performing methanation of the hydrogen stream produced at step E and subsequent separation so to produce a water stream and a methane stream (see block 970 of Fig. 6). Advantageously, the CO2 stream generated by theCO2 capture unit may be used to perform the methanation of step G.

Claims

CLAIMS1. A system (1000, 2000) to treat coke oven gas (COG), the system being configured to receive a coke oven gas (COG) stream and comprising:A first compression unit (100) having a compression inlet (101) and a compression outlet (109), the first compression unit (100) being configured to receive the coke oven gas (COG) stream at the compression inlet (101), to compress it and to discharge a compressed coke oven gas (COG) stream at the compression outlet (109);A first separation unit (200) having a separation inlet (201), a first separation outlet (208) and a second separation outlet (209), the separation inlet (201) being fluidly coupled to the compression outlet (109) and configured to receive the compressed coke oven gas (COG) stream from the compression outlet (109), the first separation unit (200) being configured to perform an hydrogen (H2) separation so to discharge an hydrogen (H2) stream at the first separation outlet (208) and a gas stream comprising methane (CH4) and other unreacted components of the coke oven gas (COG) stream at the second separation outlet (209);A pyrolysis unit (300) having a pyrolysis inlet (301), a first pyrolysis outlet (308) and a second pyrolysis outlet (309), the pyrolysis inlet (301) being fluidly coupled to the second separation outlet (209) and configured to receive the gas stream comprising methane (CH4) and other unreacted components of the coke oven gas (COG) stream from the second separation outlet (209), the pyrolysis unit (300) being configured to perform pyrolysis of the stream comprising methane (CH4) and other unreacted components of the coke oven gas (COG) stream so to discharge solid carbon (C) at the first pyrolysis outlet (308) and a gas stream comprising hydrogen (H2) and other unreacted components of the coke oven gas (COG) stream at the second pyrolysis outlet (309).

2. The system (1000, 2000) of claim 1, wherein the pyrolysis unit (300) is configured to perform a non-thermal pyrolysis, in particular a plasmabased pyrolysis or a microwave pyrolysis or any combination thereof.

3. The system (1000, 2000) of claim 2, wherein the pyrolysis unit (300) is electrically coupled to a power source, the power source being configured to provide electrical power to the pyrolysis unit (300), the power source being one of the following sources: national electrical grid, microgrid, hydrogen or any low carbon fuel gas turbine, renewable plant, hydrogen or any low carbon fuel cell, microgrid.

4. The system (1000, 2000) of claim 1, wherein the pyrolysis unit (300) is configured to perform a thermal pyrolysis.

5. The system (1000, 2000) of claim 1, wherein the first separation unit (200) comprises a plurality of adsorbent and desorbent vessels configured to perform Pressure Swing Adsorption (PSA).

6. The system (2000) of claim 1, further comprising a second compression unit (400) having a compression inlet (401) and a compression outlet (409), the second compression unit (400) being fluidly coupled to the second pyrolysis outlet (309) and configured to receive the gas stream comprising hydrogen (H2) and other unreacted components of the coke oven gas stream from the second pyrolysis outlet (309), to compress it and to discharge a compressed gas stream comprising hydrogen (H2) and other unreacted components of the coke oven gas (COG) stream at the compression outlet (409).

7. The system (2000) of claim 6, further comprising a residual carbon monoxide process unit (500) having a residual carbon monoxide process inlet (501), a first residual carbon monoxide process outlet (508) and a second residual carbon monoxide process outlet (509), the residual carbon monoxide process inlet (501) being fluidly coupled to the compression outlet (409) and configured to receive the compressed gas streamcomprising hydrogen (H2) and other unreacted components of the coke oven gas (COG) stream from the compression outlet (409), wherein the residual carbon monoxide process unit (500) comprises a reactor (510) and a second separation unit (520), the reactor (510) being configured to receive the compressed gas stream comprising hydrogen (H2) and other unreacted components of the coke oven gas (COG) stream and a steam flow and to perform water gas shift reaction, the second separation unit (520) being configured to perform an hydrogen (H2) separation so to discharge an hydrogen (H2) stream at the second residual carbon monoxide process outlet (509) and a gas stream comprising carbon dioxide (CO2), unreacted methane (CH4), unreacted hydrogen (H2) and nitrogen (N2) at the first residual carbon monoxide process outlet (508).

8. The system (2000) of claim 7, further comprising a furnace (800) having a first furnace inlet (801), a second furnace inlet (802) and a furnace outlet (809), the first furnace inlet (801) being fluidly coupled to the first separation outlet (508) and configured to receive the gas stream comprising carbon dioxide (CO2), unreacted methane (CH4), unreacted hydrogen (H2) and nitrogen (N2) from the first separation outlet (508), the furnace (800) being configured to combust receive the gas stream comprising carbon dioxide (CO2), unreacted methane (CH4), unreacted hydrogen (H2) and nitrogen (N2) with air or oxygen supplied at the second furnace inlet (802) so to produce energy (Q) in form of heat to be supplied to the pyrolysis unit (300) and discharge flue gases at the furnace outlet (809).

9. The system (2000) of claim 7, further comprising a methanation unit (600) having a first methanation inlet (601), a first methanation outlet (608) and a second methanation outlet (609), the first methanation inlet (601) being fluidly coupled to the second residual carbon monoxide process outlet (509) and configured to receive the hydrogen (H2) stream from the second residual carbon monoxide process outlet (509),the methanation unit (600) being configured to perform methanation so to discharge a water stream (H2O) at the first methanation outlet (608) and a methane (CH4) stream at the second methanation outlet (609).

10. The system (2000) of claim 9, further comprising a CO2 capture unit (700) having a main inlet (701), a first outlet (708) and a second outlet (709), the main inlet (701) being fluidly coupled to the first furnace outlet (809) and configured to receive the flue gases from the first furnace outlet (809), the CO2 capture unit (700) being configured to perform CO2 capture so to discharge a CO2 free stream at the first outlet (708) and a CO2 stream at the second outlet (709), wherein the methanation unit (600) has a second methanation inlet (602) fluidly coupled to the second outlet (709), wherein the second methanation inlet (602) is configured to receive the CO2 stream from the second outlet (709).

11. The system (1000, 2000) of claim 1, further comprising at least a third compression unit (810) having a compression inlet (811) and a compression outlet (819), the third compression unit (810) being fluidly coupled to the first separation outlet (208) and configured to receive the hydrogen (H2) stream from the first separation outlet (208), to compress it and to discharge a compressed hydrogen (H2) stream at the compression outlet (819).

12. The system (1000) of claim 11, further comprising a power generation unit (820) fluidly coupled to the compression outlet (819), wherein the power generation unit (820) is configured to receive the compressed hydrogen (H2) stream from the compression outlet (819) and to process it so to produce electrical energy (EE).

13. A steel plant comprising a system (1000, 2000) according to claim 1.

14. The steel plant of claim 13, comprising a blast furnace and / or a reduction unit, wherein the hydrogen (H2) stream(s) discharged by the system (1000, 2000) is / are further provided to the blast furnace and / or to the reduction unit as reducing agent for DRI application.

15. The steel plant of claim 13, comprising a heating unit, wherein the hydrogen (H2) stream(s) discharged by the system (1000, 2000) is / are further provided to the heating unit and used for heating application within the steel plant for steel making processes, in particular for steel making processes such as steel casting, reheating, rolling, etc.

16. Method (3000) for performing decarbonization of coke oven gas (COG) produced by a steel plant, the method comprising the following steps:A. Perform (910) compression of the coke oven gas (COG) stream so to produce a compressed coke oven gas (COG) stream;B. Perform (920) separation of the compressed coke oven gas (COG) stream so to produce a hydrogen (H2) stream and a gas stream comprising methane (CH4);C. Perform (930) pyrolysis of the gas stream comprising methane (CH4) so to produce solid carbon (C) and a gas stream comprising hydrogen (H2).

17. The method (3000) of claim 16, wherein the step B is performed through Pressure Swing Adsorption (PSA) process.

18. The method (3000) of claim 16, wherein the hydrogen (H2) stream generated at step B is used in a power generation unit, in particular a gas turbine, so to generate electrical energy, and / or in a blast furnace of the steel plant and / or in a reduction unit of the steel plant as reducing agent for DRI application and / or in a heating unit of the steel plant for heating application within the steel plant for steel making processes.

19. The method (3000) of claim 11, further comprising a step D of performing (940) compression of the gas stream comprising hydrogen (H2) produced at step C.

20. The method (3000) of claim 19, further comprising a step E of performing (950) water gas shift reaction of the compressed gas stream comprising hydrogen (H2) produced at step D and subsequent separation so to producea hydrogen (H2) stream and a gas stream comprising carbon dioxide (CO2), unreacted methane (CH4), unreacted hydrogen (H2) and nitrogen (N2).

21. The method (3000) of claim 20, further comprising a step F of producing (960) energy (Q) in form of heat, wherein the gas stream comprising carbon dioxide (CO2), unreacted methane (CH4), unreacted hydrogen (H2) and nitrogen (N2) produced at step E is combusted so to produce heat and flue gases, wherein the heat produced is used to perform the pyrolysis at step C.

22. The method (3000) of claim 21, wherein flue gases produced at step F are treated by a CO2 capture unit so to generate a CO2 stream and a CO2 free stream.

23. The method (3000) of claim 22, further comprising a step G of performing (970) methanation of the hydrogen (H2) stream produced at step E and subsequent separation so to produce a water stream (H2O) and a methane (CH4) stream.

24. The method (3000) of claim 21, wherein the methanation of step G is performed using the CO2 stream generated by the CO2 capture unit.