WO2025090469A1 - Methods of light olefin production - Google Patents

Abstract

A method of producing light olefins including introducing a hydrocarbon feedstock into a steam-cracking unit, and cracking the hydrocarbon feedstock to obtain a cracked product. Then, introducing the cracked product into a separating unit, and separating the cracked product to obtain a methane stream, a hydrogen stream, and a light olefin containing stream. Introducing the methane stream into a reforming unit, and producing reformer synthesis gas (syngas). Then, introducing process hydrogen, the reformer syngas, an optional additional syngas stream, or combinations thereof into a syngas conversion unit, and converting the process hydrogen, the reformer syngas, the additional syngas stream, or combinations thereof into a syngas conversion product. The process hydrogen comprises hydrogen separated from the cracked product, hydrogen obtained from a water-gas-shift unit, or combinations thereof, and energy required for the steam-cracking unit is at least partially provided by the process hydrogen, by electricity, or by combinations thereof.

Description

85415-WO-PCT/DOW 85415 WO METHODS OF LIGHT OLEFIN PRODUCTION CROSS-REFERENCE TO RELATED APPLICATIONS [0001] This application claims the benefit of U.S. Provisional Application Serial No. 63/592,743 filed October 24, 2023, the content of which is incorporated in its entirety herein. TECHNICAL FIELD [0002] The present disclosure relates to methods of light olefin production. In particular, the present disclosure relates to methods of light olefin production with increased carbon conversion efficiency. BACKGROUND [0003] Light olefin production technology is currently dominated by steam-cracking hydrocarbon feedstocks such as ethane, propane, butane, naphtha, and combinations thereof. In the steam- cracking process, the feedstocks are exposed to high temperatures (> 760 °C), which cracks the feedstocks to obtain desired products such as ethylene, propylene, crude C4, pyrolysis gasoline, BTX (benzene/toluene/xylene)-streams, and combinations thereof, with a product distribution that is dependent on the selected feedstock. Byproducts, such as off-gasses and heavy oils, are produced during steam cracking. The off-gases are primarily a mixture of CH4 and H2. The relative amount of CH4 and H2 in the off-gases depends on the selected feedstock. [0004] To achieve high thermal efficiencies for the steam-cracking process, by-product off-gas is typically used as a fuel gas for the cracker furnaces to provide the energy requirements for feedstock conversion and steam generation through cracked gas and flue gas heat recovery. However, burning CH₄ to provide energy for the steam-cracking process leads to substantial carbon dioxide emissions associated with the production of light olefins and a loss of carbon to the atmosphere. Accordingly, a need exists for methods of producing light olefins with increased carbon conversion efficiency and reduced CO₂ footprint. 85415-WO-PCT/DOW 85415 WO SUMMARY [0005] Embodiments disclosed herein are directed to methods of producing light olefins, the methods including introducing a hydrocarbon feedstock into a steam-cracking unit, cracking the hydrocarbon feedstock in the steam-cracking unit to obtain a cracked product, introducing the cracked product into a separating unit, separating the cracked product to obtain a methane stream, a hydrogen stream, and a light olefin stream, introducing the methane stream into a reforming unit, producing reformer syngas in the reformer unit, introducing process hydrogen, reformer syngas, an additional syngas stream, or combinations thereof into a syngas conversion unit, and converting the process hydrogen, the reformer syngas, the additional syngas stream, or combinations thereof into a syngas conversion product, wherein the process hydrogen comprises hydrogen separated from the cracked product, hydrogen obtained from a water-gas-shift unit, or combinations thereof, wherein the energy required for the steam-cracking unit is at least partially provided by the process hydrogen, by electricity, or by combinations thereof. [0006] These and other features, aspects, and advantages will become better understood with reference to the following description and the appended claims. [0007] Additional features and advantages of the embodiments described herein will be set forth in the detailed description that follows, and in part will be readily apparent to those skilled in the art from that description or recognized by practicing the embodiments described herein, including the detailed description that follows, the claims, as well as the appended drawings. [0008] It is to be understood that both the foregoing general description and the following detailed description describe various embodiments and are intended to provide an overview or framework for understanding the nature and character of the claimed subject matter. The accompanying drawings are included to provide a further understanding of the various embodiments, and are incorporated into and constitute a part of this specification. The drawings illustrate the various embodiments described herein, and together with the description serve to explain the principles and operations of the claimed subject matter. 85415-WO-PCT/DOW 85415 WO BRIEF DESCRIPTION OF THE DRAWINGS [0009] FIG. 1 illustrates a system for performing the methods of producing light olefins using an electrified cracker and an air separation unit according to embodiments described herein. [0010] FIG. 2 illustrates a system for performing the methods of producing light olefins using an electrified cracker and an electrolysis unit according to embodiments described herein. [0011] FIG. 3 illustrates a system for performing the methods of producing light olefins using a hydrogen-fired cracker according to embodiments described herein. [0012] FIG. 4 illustrates a system for performing the methods of producing light olefins using a hydrogen fired cracker and recycling a syngas conversion product according to embodiments described herein. [0013] FIG. 5 illustrates a system for performing the methods of producing light olefins using an electrified cracker and recycling a syngas conversion product according to embodiments described herein. [0014] FIG. 6 illustrates a comparative system for performing comparative methods of producing light olefins. [0015] FIG. 7 illustrates a second comparative system for performing comparative methods of producing light olefins. DETAILED DESCRIPTION [0016] Reference will now be made in detail to embodiments of methods of producing light olefins, the methods including introducing a hydrocarbon feedstock into a steam-cracking unit, cracking the hydrocarbon feedstock in the steam-cracking unit to obtain a cracked product, introducing the cracked product into a separating unit, separating the cracked product to obtain a methane stream, a hydrogen stream, and a light olefin stream, introducing the methane stream into a reforming unit, producing reformer syngas in the reformer unit, introducing process hydrogen, 85415-WO-PCT/DOW 85415 WO reformer syngas, an additional syngas stream, or combinations thereof into a syngas conversion unit, and converting the process hydrogen, the reformer syngas, the additional syngas stream, or combinations thereof into a syngas conversion product, wherein the process hydrogen comprises hydrogen separated from the cracked product, hydrogen obtained from a water-gas-shift unit, or combinations thereof, wherein the energy required for the steam-cracking unit is at least partially provided by the process hydrogen, by electricity, or by combinations thereof. [0017] Referring to FIG. 1, the method includes introducing a hydrocarbon feedstock 820 into a steam-cracking unit 800. The hydrocarbon feedstock 820 may include hydrocarbon feedstock. As used herein, the phrase “hydrocarbon feedstock” refers to feedstock that includes ethane, propane, butane, naphtha, other petroleum intermediates, or combinations thereof. The hydrocarbon feedstock 820 may include fossil feedstock. As used herein, the phrase “fossil feedstock” refers to feedstock that includes fossilized carbon products. At the steam-cracking unit 800, the hydrocarbon feedstock is cracked into different products. [0018] In embodiments, the hydrocarbon feedstock 820 is cracked in the steam-cracking unit 800 to obtain a cracked product 850. The steam-cracking unit 800 operates at a temperature of greater than or equal to 760 °C, such as greater than or equal to 780 °C, or greater than or equal to 800 °C. The cracked product 850 includes, according to one or more embodiments, methane, hydrogen, and light olefins. As used herein, the phrase “light olefins” refers to ethylene, propylene, butene, or combinations thereof. The cracked product 850 may also include pyrolysis gasoline (pygas), benzene, toluene, and xylene (BTX), or combinations thereof. The cracker product 850 may also include light paraffins, such as ethane, propane, butane, or combinations thereof. The cracked product 850 is then transferred to a separating unit 900. [0019] At the separating unit 900, the cracked product 850 is separated to obtain a by-product stream rich in methane 950, a process hydrogen stream 980, and a light olefin stream 970. The specific separation unit process sequence is known to one skilled in the art, and can comprise both front-end and tail-end hydrogenation configurations for acetylenes and diolefin removal from olefin product streams as described by Edgar L. Mohundro. Overview on C2 and C3 selective hydrogenation in ethylene plants. In 15th Ethylene Produces Conference, volume 15. AIChE, 2003. Session 64: Ethylene Plant Technology C2 and C3 Hydrogenation Technology Review, the 85415-WO-PCT/DOW 85415 WO entirety of which is hereby incorporated by reference. The separating unit 900 may be any separating device capable of separating the cracked product 850 into a by-product stream rich in methane 950, a process hydrogen 980, and a light olefin stream 970. In embodiments, the steam- cracking unit 800 and the separating unit 900 may be part of a single physical unit (not shown). In one or more embodiments, the separating unit 900 may contain a hydrogen purification unit, which comprises of a Pressure Swing Absorber (PSA) or hydrogen recovery membrane or combinations thereof, to produce process hydrogen from a hydrogen rich by-product (not shown). In embodiments, the steam-cracking unit 800 and the separating unit 900 may be separate physical units. According to one or more embodiments, any hydrocarbon feedstock 820 that is not converted in the steam-cracking unit 800 may also be separated by the separating unit 900, and the uncracked hydrocarbon feedstock and separated light paraffins may be combined with the feedstock 820 and sent back to the steam-cracking unit 800 for further processing (not shown). [0020] The light olefin stream 970 exits the separating unit 900 and may be further processed or collected for use in other processes. According to one or more embodiments, the light olefin stream 970 primarily comprises ethylene and propylene. The process hydrogen 980 exits the separating unit 900 and, according to one or more embodiments, is recycled back into the system by being introduced into a synthesis gas (syngas) conversion block 700, which will be discussed in more detail below. The by-product stream 950 exits the separator 900 and is introduced into a reforming unit 200. [0021] At the reforming unit 200, the by-product stream rich in methane 950 is combined with oxygen 150 and reacted to make reformer syngas 250. In one or more embodiments, the reforming unit may include a carbon dioxide removal unit (not shown) for the partial removal of carbon dioxide from the reformer flue gas or reformer syngas. In embodiments, the reforming unit 200 may be an autothermal reforming (ATR) unit. In other embodiments, the reforming unit may be a partial oxidation (POx) unit. In embodiments, the reforming unit 200 may be a steam reforming unit (SMR). Examples of appropriate reforming units are described in K. Aasberg-Petersen, T.S. Christensen, I. Dybkjaer, J. Sehested, M. Østberg, R.M. Coertzen, M.J. Keyser, A.P. Steynberg, Chapter 4 - Synthesis gas production for FT synthesis, Editor(s): André Steynberg, Mark Dry, Studies in Surface Science and Catalysis, Elsevier, Volume 152, 2004, Pages 258-405, ISSN 0167-2991, ISBN 9780444513540, the entirety of which is hereby incorporated by reference. It 85415-WO-PCT/DOW 85415 WO should be understood that CO₂ generated from a furnace heaters (not shown) in the reforming unit 200 may exit the reforming unit and be captured and/or re-used in other processes. The reformer syngas 250 is combined with an additional syngas stream 650 and introduced into a syngas conversion unit 700. [0022] In embodiments, the oxygen 150 that is fed to the reforming unit 200 is produced by introducing air 110 into an air separation unit (ASU) 100 and separating oxygen 150 from the air 110. Any separating unit capable of separating oxygen out of air may be used. In embodiments, oxygen 150, and/or steam (not shown), or combinations thereof is fed to the reforming unit 200, the gasifier 600, or combinations thereof. In one or more embodiments, the oxygen stream 150 is split into a second oxygen stream 160 that is sent from the air separation unit 100 to a gasifier 600, which will be discussed in more detail below. In one or more embodiments, steam may be generated within the reforming unit 200 that can be used within reforming unit 200 or exported for external use (not shown). It should be understood that although FIG. 1 depicts using an air separation unit 100 to separate oxygen 150, 160 from air, in other embodiments, the oxygen streams 150 and 160 may be oxygen from any source and is not limited to oxygen from an air separation unit 100. [0023] As noted above, the reformer syngas 250 exits the reforming unit 200 and is introduced into the syngas conversion unit 700, where the reformer syngas 250 is combined with process hydrogen 980 and an optional additional syngas stream 650. At the syngas conversion unit 700, the process hydrogen 980, the reformer syngas 250, and the optional additional syngas stream 650 are converted into a syngas conversion product 750. The syngas conversion product is dependent on the syngas technology employed, including but not limited to liquid hydrocarbons through Fischer-Tropsch, methanol from methanol synthesis, light olefins from combined methanol synthesis and methanol-to olefins, light hydrocarbons through the direct conversion of syngas to light hydrocarbons over a bifunctional MeOH-MTO catalyst technology. As used herein, the phrase “light hydrocarbons” refers to hydrocarbons containing 1 to 7 carbon atoms in their molecular structure. Conversion technologies and catalysts for direct syngas conversion to synthetic LPG and synthetic olefins are described in U.S. Patent Number 10,513,471B2, International Publication Number WO2020/139600A2 and International Publication Number WO 2022/182592A1, the entireties of which are hereby incorporated by reference. In one or more 85415-WO-PCT/DOW 85415 WO embodiments, the syngas conversion includes, at least partially, converting syngas to methanol by known techniques and then using known methanol-to-olefins conversion technology to convert the methanol to olefins. In such embodiments, an additional conversion unit for converting methanol to olefins may be required; this additional conversion unit may be a separate unit or it may be physically integrated into the syngas conversion unit 700. In other embodiments, the syngas conversion includes converting syngas directly to olefins without first converting the syngas to methanol. The syngas conversion product 750 can then be combined with the feedstock 820 and introduced into the steam-cracking unit 800, which is described above. In other embodiments, the syngas conversion product stream can be combined with the cracked product 850 for separation in the separation section 900 (not shown). [0024] In embodiments depicted in FIG. 1, the additional syngas stream 650 is gasifier syngas generated by a gasification process in a gasifier 600. In one or more embodiments, the gasifier 600 uses gasification to form the additional syngas stream 650 from a solid carbonaceous feedstock 610. In one or more embodiments, the solid carbonaceous feedstock 610 is waste plastic. As used herein, the phrase “waste plastic” refers to plastic that has been discarded after its intended use. In one or more embodiments, the solid carbonaceous feedstock 610 is selected from biomass, municipal solid waste; refuse derived fuel, solid recovered fuel, automotive shredder residue, or mixtures thereof. In other embodiments, the solid carbonaceous feedstock 610 may be any hydrocarbon feedstock capable of producing syngas by gasification processes, and any suitable gasifier may be used according to embodiments. In other embodiments, the gasifier type may be selected from an entrained flow gasifier, a bubbling fluid bed gasifier, a circulating fluid bed gasifier, a plasma gasifier, a rotary kiln gasifier, an updraft or downdraft moving bed gasifier, a moving grate gasifier or any combination thereof. Exemplary gasifiers of embodiments are disclosed in, for example, Lopez, G., Artetxe, M. Amutio, M., Alvarez, J., Bilbao, J., Olazar, M., 2018. Recent advances in the gasification of waste plastics. A critical overview. Renewable and Sustainable Energy Reviews, 82, pp.576-596. Although the embodiments depicted in FIG.1 show that the additional syngas stream 650 is formed by gasification, in some embodiments, the additional syngas stream 650 may be from any suitable source. In addition, according to embodiments, the additional syngas stream 650 may not be present and the syngas conversion unit 700 may operate entirely from reformer syngas stream 250. 85415-WO-PCT/DOW 85415 WO [0025] With reference now to FIG. 2, embodiments using an electrolysis unit 500 to produce oxygen and hydrogen will be described. As shown in a comparison of FIG. 1 and FIG. 2, the electrolysis unit 500 in FIG. 2 replaces the air separation unit 100 in FIG. 1. Accordingly, the function of the syngas conversion unit 700, the steam-cracking unit 800, the separating unit 900, the reforming unit 200, and the gasifier 600 are essentially the same in FIG.2 as they were in FIG. 1. However, in FIG. 2 oxygen is formed using an electrolysis unit 500. A water stream 510 is introduced into the electrolysis unit 500, where the water 510 is split into its component parts; hydrogen and oxygen. Oxygen stream 580 is sent to the reforming unit 200, where it may be used to reform by-product stream 950, as disclosed above. Oxygen stream 525 is sent to the gasifier 600, where it can be used to gasify a carbonaceous feedstock 610 into the additional syngas stream 650. Hydrogen produced in the electrolysis unit 500 may exit the electrolysis unit 500 as hydrogen stream 560 and be combined with the additional syngas stream 650 and introduced into the syngas conversion unit 700. Although not depicted, an electrolysis unit 500 may be used in conjunction with an air separation unit 100 to provide oxygen and hydrogen to various components within the systems disclosed and described herein. However, for the sake of clarity, the air separation unit 100 and the electrolysis unit 500 are provided in separate figures, FIG.1 and FIG.2, respectively. [0026] According to the embodiments depicted in FIG. 1 and FIG. 2, the energy required for the steam-cracking unit 800 is provided primarily by electricity. In this instance, combustible gases, such as the process hydrogen 980 separated at the separating unit 900 do not need to be recycled back to the steam-cracking unit 800 to power the steam-cracking unit 800. In embodiments, where the steam-cracking unit 800 is an electric steam-cracking unit, the electricity used to power the steam-cracking unit may include electricity from sustainable sources, such as electricity generated by wind, solar, geothermal, or nuclear sources. [0027] Systems and methods using hydrogen-fired steam-cracking units will now be described with reference to FIG. 3. The method includes introducing a hydrocarbon feedstock 820 into a steam-cracking unit 800. The hydrocarbon feedstock 820 may include hydrocarbon feedstock. In embodiments, the hydrocarbon feedstock 820 may include fossil feedstock. At the steam-cracking unit 800, the hydrocarbon feedstock is cracked into different products. 85415-WO-PCT/DOW 85415 WO [0028] In embodiments, the hydrocarbon feedstock 820 is cracked in the steam-cracking unit 800 to obtain a cracked product 850. The steam-cracking unit 800 operates at a temperature of greater than or equal to 760 °C, such as greater than or equal to 780 °C, or greater than or equal to 800 °C. The cracked product 850 includes, according to one or more embodiments, methane, hydrogen, and light olefin. The cracked product 850 may also include pyrolysis gasoline (pygas), benzene, toluene, and xylene (BTX), or combinations thereof. The cracker product 850 may also include light paraffins, such as ethane, propane, butane, or combinations thereof. The cracked product 850 is then transferred to a separating unit 900. [0029] At the separating unit 900, the cracked product 850 is separated to obtain a by-product stream rich in methane 950, process hydrogen 980, and a light olefin stream 970. The separating unit 900 may be any separating device capable of separating the cracked product 850 into a by- product stream rich in methane 950, a process hydrogen 980, and a light olefin stream 970. The specific separation unit process sequence is known to one skilled in the art, and can comprise both front-end and tail-end hydrogenation configurations for acetylenes and diolefin removal from olefin product streams as described by Edgar L. Mohundro. Overview on C₂ and C₃ selective hydrogenation in ethylene plants. In 15th Ethylene Produces Conference, volume 15. AIChE, 2003. Session 64: Ethylene Plant Technology C2 and C3 Hydrogenation Technology Review, the entirety of which is hereby incorporated by reference. In embodiments, the steam-cracking unit 800 and the separating unit 900 may be part of a single physical unit (not shown). In one or more embodiments, the separating unit 900 may contain a hydrogen purification unit, which comprises of a Pressure Swing Absorber (PSA) or hydrogen recovery membrane or combinations thereof, to produce process hydrogen from a hydrogen rich by-product (not shown). In embodiments, the steam-cracking unit 800 and the separating unit 900 may be separate physical units. According to one or more embodiments, any hydrocarbon feedstock 820 that is not converted in the steam- cracking unit 800 may also be separated by the separating unit 900, and the uncracked hydrocarbon feedstock may be combined with the feedstock 820 and sent back to the steam- cracking unit 800 for further processing (not shown). [0030] The light olefin stream 970 exits the separating unit 900 and may be further processed or collected for use in other processes. According to one or more embodiments, the light olefin stream 970 primarily comprises ethylene and propylene. The process hydrogen 980 exits the 85415-WO-PCT/DOW 85415 WO separating unit 900 and, according to one or more embodiments, is recycled back into the system by being introduced into the steam-cracking unit 800, where the process hydrogen 980 may be used, such as by combustion, to heat the steam-cracking unit 800. The by-product stream rich in methane 950 exits the separator 900 and is introduced into a reforming unit 200. [0031] At the reforming unit 200, the by-product stream 950 is combined with oxygen 150 and reacted to make reformer syngas 250. In embodiments, the reforming unit 200 may be an autothermal reforming (ATR) unit. In embodiments, the reforming unit 200 may be a steam reforming unit (SMR). In other embodiments, the reforming unit may be a partial oxidation (POx) unit. Examples of appropriate reforming units are described in K. Aasberg-Petersen, T.S. Christensen, I. Dybkjaer, J. Sehested, M. Østberg, R.M. Coertzen, M.J. Keyser, A.P. Steynberg, Chapter 4 - Synthesis gas production for FT synthesis, Editor(s): André Steynberg, Mark Dry, Studies in Surface Science and Catalysis, Elsevier, Volume 152, 2004, Pages 258-405, ISSN 0167-2991, ISBN 9780444513540, the entirety of which is hereby incorporated by reference. The reformer syngas 250 produced at the reforming unit 200 exits the reforming unit 200 and is introduced into a water-gas-shift unit 300. [0032] In embodiments, the oxygen 150 that is fed to the reforming unit 200 is produced by introducing air 110 into an air separation unit 100 and separating oxygen 150 from the air 110. Examples of appropriate air separation units with associated energy requirements may be found in Alsultanny, Y. A. and Al-Shammari, N. N., 2014. Oxygen Specific Power Consumption Comparison for Air Separation Units, Eng. J., vol. 18, no. 2, pp. 67-80. Any separating unit capable of separating oxygen out of air may be used. In embodiments, oxygen 150, steam, (not shown) or combinations thereof is fed to the reforming unit 200, the gasifier 600, or combinations thereof. In one or more embodiments, the oxygen stream 150 is split into a second oxygen stream 160 that is sent from the air separation unit 100 to a gasifier 600, which will be discussed in more detail below. It should be understood that although FIG.3 depicts using an air separation unit 100 to separate oxygen 150, 160 from air, in other embodiments, the oxygen streams 150 and 160 may be oxygen from any source and is not limited to oxygen from an air separation unit 100. [0033] As noted above, reformer syngas 250 produced at the reforming unit 200 is sent to a water- gas-shift unit 300. Steam 310 is also introduced into the water-gas-shift unit 300, where a water- 85415-WO-PCT/DOW 85415 WO gas-shift product 350 is produced. In some embodiments, the water-gas-shift product 350 may be produced by a water-gas-shift unit that includes two water-gas-shift reactors operating in series, namely High Temperature followed by Low Temperature water-gas-shift. Examples of appropriate water-gas-shift units, appropriate water-gas-shift reactors, and appropriate operating conditions may be found in Dagle, R.A., Karim, A., Li, G., Su, Y. , King, D.L., 2011. Syngas Conditioning. In: Shekhawat, D., Spivey, J.J., Berry, D.A., Fuel Cells: Technologies for Fuel Processing, pp 361-408, the entirety of which is hereby incorporated by reference. In embodiments, any suitable water-gas-shift unit may be used. The water-gas-shift product 350 comprises hydrogen and CO2 and is sent to a separation unit 400, where the CO2 is separated from the hydrogen. Any suitable separation unit that separates CO2 from hydrogen may be used as the separation unit 400. The CO₂450 produced at the separation unit 400 may then be collected and re-used in other processes (not shown). The hydrogen 440 produced at the separation unit 400 is sent to the steam-cracking unit 800 and the syngas conversion unit 700. The hydrogen 440 sent to the steam-cracking unit 800 can be used to heat the steam-cracking unit 800, and the hydrogen 440 sent to the syngas conversion unit 700 may be used to convert the additional syngas stream 650 into a syngas conversion product 750. [0034] As noted above, hydrogen 440 exits separation unit 400 and is introduced into the syngas conversion unit 700, where the hydrogen 440 is combined the additional syngas stream 650. At the syngas conversion unit 700, the hydrogen 440 and the additional syngas stream 650 are converted into a syngas conversion product 750. In embodiments, the syngas conversion product 750 comprises light olefins. The syngas conversion product is dependent on the syngas technology employed, including but not limited to liquid hydrocarbons through Fischer-Tropsch, methanol from methanol synthesis, light olefins from combined methanol synthesis and methanol-to olefins, light hydrocarbons through the direct conversion of syngas to light hydrocarbons over a bifunctional MeOH-MTO catalyst technology. Conversion technologies and catalysts for direct syngas conversion to synthetic LPG and synthetic olefins are described in U.S. Patent Number 10,513,471B2, International Publication Number WO2020/139600A2 and International Publication Number WO 2022/182592A1, the entireties of which are hereby incorporated by reference. 85415-WO-PCT/DOW 85415 WO [0035] In one or more embodiments, the syngas conversion includes, at least partially, converting syngas to methanol by known techniques and then using known methanol-to-olefins conversion technology to convert the methanol to olefins. In such embodiments, an additional conversion unit for converting methanol to olefins may be required; this additional conversion unit may be a separate unit or it may be physically integrated into the syngas conversion unit 700. In other embodiments, the syngas conversion includes converting syngas directly to olefins without first converting the syngas to methanol. The syngas conversion product 750 can then be collected and used in other processes (not shown). Although not shown in FIG. 3, in some embodiments, the syngas conversion product 750 may be passed to steam-cracking unit 800. In various embodiments, the syngas conversion product 750 may be combined with feedstock 820 before being passed to the steam-cracking unit 800. In one or more embodiments, the syngas conversion product 750 may be passed to the separator 900. In some embodiments, the syngas conversion product 750 may be combined with cracked product 850 before being passed to the separator 900. In one or more embodiments, the syngas conversion product 750 primarily comprises ethylene and propylene. [0036] In embodiments depicted in FIG. 3, the additional syngas stream 650 is gasifier syngas generated by a gasification process in a gasifier 600. In one or more embodiments, the gasifier 600 uses gasification to form the additional syngas stream 650 from a solid carbonaceous feedstock 610. In one or more embodiments, the solid carbonaceous feedstock 610 is waste plastic. As used herein, the phrase “waste plastic” refers to plastic that has been discarded after its intended use. In one or more embodiments, the solid carbonaceous feedstock 610 is selected from biomass, municipal solid waste; refuse derived fuel, solid recovered fuel, automotive shredder residue, or mixtures thereof. In other embodiments, the solid carbonaceous feedstock 610 may be any hydrocarbon feedstock capable of producing syngas by gasification processes, and any suitable gasifier may be used according to embodiments. In other embodiments, the gasifier type may be selected from an entrained flow gasifier, a bubbling fluid bed gasifier, a circulating fluid bed gasifier, a plasma gasifier, a rotary kiln gasifier, an updraft or downdraft moving bed gasifier, a moving grate gasifier or any combination thereof. Exemplary gasifiers of embodiments are disclosed in, for example, Lopez, G., Artetxe, M. Amutio, M., Alvarez, J., Bilbao, J., Olazar, M., 2018. Recent advances in the gasification of waste plastics. A critical overview. Renewable and Sustainable Energy Reviews, 82, pp. 576-596. Although the embodiments depicted in FIG. 3 85415-WO-PCT/DOW 85415 WO show that the additional syngas stream 650 is formed by gasification, it should be understood that in other embodiments the additional syngas stream 650 may be from any suitable source. [0037] With reference now to FIG. 4, the syngas conversion product 750 may comprise light olefins and methane. In such embodiments, the syngas conversion product 750 may be combined with the cracked product 850 and sent to the separating unit 900 where the methane is separated from the light olefins. Otherwise, the system and methods depicted in FIG. 4 operates similar to the system and methods depicted in FIG. 3. [0038] If the steam-cracking unit 800 is a hydrogen fired steam-cracking unit, the steam-cracking unit 800 may be powered by combusting process hydrogen 980. If the steam-cracking unit 800 is a hydrogen fired steam-cracking unit, the steam-cracking unit 800 may be powered by combusting a combination of process hydrogen 980 as well as hydrogen from other sources, as shown in FIG. 3 and FIG. 4. In other embodiments, the steam-cracking unit 800 might be partially fired with hydrogen, and partially heated using electricity. EXAMPLES [0039] The following Examples are offered by way of illustration and are presented in a manner such that one skilled in the art should recognize are not meant to be limiting to the present disclosure as a whole or to the appended claims. [0040] The Examples below are based on unit ratios and energy requirements for key process technologies for waste plastic gasification, autothermal reforming, water gas shift, CO2 separation and liquefaction, steam cracking, methanol synthesis, methanol to olefins, and Fischer-Tropsch to Naphtha, using operating conditions that result in a low chain growth probability, the so-called α value (0.7-0.8) in the Anderson-Schulz-Flory distribution, as detailed in Cheng. et al., Chapter Three - Advances in Catalysis for Syngas Conversion to Hydrocarbons, Advance in Catalysis 60 (2017) 125, the entirety of which is hereby incorporated by reference. Experimental data was used for the Synthetic LPG and Synthetic Olefin technologies. 85415-WO-PCT/DOW 85415 WO [0041] Waste plastic conversion to syngas via gasification was modelled using a waste plastic feed composition (Table 1) as described by the Phylllis2 database (MSW – plastic fraction) for The Netherlands. Currently available at https://phyllis.nl/Browse/Standard/ECN-Phyllis##1877. The gasification of the waste plastic was modelled using an equilibrium model in Aspen Plus Process Simulator using conditions described by Lopez. et al., Recent advances in the gasification of waste plastics. A critical overview, Renewable and Sustainable Energy Reviews 82 (2018) 576 for Plastic Waste co-gasification, yielding a syngas with a H2/CO ratio of 0.8 – 1.2. Table 1: Waste Plastic feed composition (as received) used for equilibrium gasification model

[0042] Conversion technologies and catalysts for direct syngas conversion to synthetic LPG and synthetic olefins are described in U.S. Patent Number 10,513,471B2 and International Publication Number WO 2022/182592A1, the entireties of which are hereby incorporated by reference. Integrated flowsheets were developed in Aspen Plus Process Simulator, including syngas recycle, CO₂ recovery, and hydrocarbon recovery from the unreacted syngas. Syngas composition of the fresh syngas feed and the combined stream including syngas recycle are shown in Table 2. Obtained single pass conversion and product selectivities are shown in Table 3. Table 2: Modelled Syngas Feed Composition (vol%) for Synthetic LPG and Synthetic Olefin Processes

85415-WO-PCT/DOW 85415 WO Table 3: Per-Pass Conversion and Selectivity on carbon-basis for Synthetic LPG and Synthetic Olefin Processes

[0043] Conversion and Selectivity are calculated using the following equations: CO Conversion (%) = [(η_{CO, in} – η_{CO, out})/ η_{CO, in}] · 100 (Equation 1) COx Conversion (%) = [(ηCO_x, in – ηCO_x, out)/ ηCO_x, in] · 100 (Equation 2) S_j (Cmol%) = [α_j · η_{j, out} / (η_{COx, in} – η_{COx, out})/] · 100 (Equation 3) where “η, in” is defined as the molar inlet flow of the component (mol/min), “η, out” is the molar outlet flow of the component (mol/min), “S_j” is defined as the carbon based selectivity to product j (%), and “α_j” is the number of carbon atoms for product j. [0044] Table 4 shows the ethane, propane, methane, hydrogen, C4, pygas, and heavy fraction yields when using ethane, propane, or naphtha as feedstocks using conventional steam-cracking methods. Table 4: Yields of Steam Cracker for Various Feedstocks 85415-WO-PCT/DOW 85415 WO

[0045] Data in Table 4 referenced from U.S. Patent No. 11,220,469. [0046] Table 5 shows modelled fuel requirements for a steam cracker for ethane, propane, and naphtha feedstocks. Table 5: Modelled Fuel Requirements of for a Steam Cracker for Various Feedstocks

[0047] Data referenced from Ren, T., Patel, M., Blok, K., 2006. Olefins from conventional and heavy feedstocks: Energy use in steam cracking and alternative processes. Energy, 31, pp: 425- 451 & U.S. Department of Energy, 2000. [0048] For the integrated processes, various integrated mass and energy balances were developed using Aspen Plus Process Simulator flowsheets. Diagrams for the Examples and the Comparative Examples are as shown in FIGs. 1-7. The boundary for the integrated heat and mass balance includes the ASU/Electrolysis, Syngas Conversion, Autothermal Reforming, Cracker Furnace, and CO₂ separation and liquefaction. Energy balance for the waste gasification and the product separation at the cracker back-end is outside of the boundary of the scope. According to embodiments, the stream rich in methane 950 and process hydrogen stream 980 are recovered in the separating unit 900 into two separate streams, or in a single combined stream (not shown) and combined with a methane stream before being combusted in cracking unit 800. Example 1: Electrified Ethane Steam Cracker + Synthetic LPG from CH4 and Waste gasification integrated with air separation. 85415-WO-PCT/DOW 85415 WO [0049] The process of Example 1 is as shown in FIG.1. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances were considered for the cracker 800, excluding the integrated energy balance for the downstream product separation. The heat for the thermal cracking reaction in cracker 800 was powered by electricity. The byproduct stream rich in CH₄950 was reformed through an ATR unit 200, and process H2 980 was utilized to supplement the reformer syngas 250 and waste-plastic derived syngas 650. Both syngas streams 250 and 650 were combined into the syngas conversion block 700, generating non-fossil synthetic LPG 750 and displacing fossil feedstock 820. Comparative Example 1. Electrified Ethane Steam Cracker + Synthetic LPG from CH4, excess H2 fueling and waste gasification integrated with electrolysis. [0050] The process of Comparative Example 1 is as shown in FIG. 2. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances were considered for the cracker 800, excluding the integrated energy balance for the downstream product separation. The cracker 800 was powered by electricity. The byproduct stream rich in CH₄950 was reformed through ATR unit 200, and cracker H₂980 was utilized to supplement the reformer syngas 250 and waste-plastic derived syngas 650. Green H2560 obtained from PEM electrolysis (51.7 kWh/kg H2) was utilized to supplement the waste-plastic derived syngas 650. The O₂ streams 580 and 525 obtained from electrolysis was used to respectively feed the ATR 200 and waste plastic gasifier 600. Both syngas stream 250 and syngas stream 650 are combined into the syngas conversion block 700, generating non-fossil feedstock 750 and displacing fossil feedstock 820. Example 2. H2-fired Ethane/Propane (40/60) Cracker with excess H2 utilization + MeOH-MTO from waste-derived syngas. [0051] The process of Example 2 is as shown in FIG.3. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances were considered for the cracker 800, excluding the integrated energy balance for the downstream product separation. The byproduct stream rich in CH4950 is reformed through an ATR unit 200, and the obtained syngas 250 was subsequently shifted in a water-gas-shift (WGS) unit 300 to obtain H2 and CO2350. After CO2 separation and liquefaction in unit 400, part of the resulting H2 85415-WO-PCT/DOW 85415 WO 440 is used as fuel in the cracker 800 and part of the H₂440 is used to supplement the waste plastic derived syngas 650. The amount of waste plastic 610 processed through gasification was determined by the amount of H2440 that is not needed to fuel the cracker 800. The syngas stream 650 is then passed to the syngas conversion unit 700 generating non-fossil ethylene and propylene steam 750. In the syngas conversion unit 700, the syngas stream 650 is converted to methanol, and the methanol is subsequently converted to light olefins 750 using methanol-to-olefins (MTO) technology. Non-fossil ethylene and propylene steam 750 supplements the production of ethylene and propylene stream 970 from fossil hydrocarbon feedstock 820. Comparative Example 2. Conventional Ethane Cracker. [0052] The process of Comparative Example 2 is as shown in FIG. 6. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances were considered for the ethane cracker 800, excluding the integrated energy balance for the downstream product separation. [0053] An ethane fossil feedstock 820 was fed into the cracker 800 and converted into a cracked product 850 that comprises methane, hydrogen, and light olefins. The cracked product 850 was introduced into a separating unit 900 where the cracked product was separated into byproduct stream rich in methane 950, cracker hydrogen 980, and a light olefin stream 970. The byproduct stream rich in methane 950 was combined with a fossil methane stream 910 and fed to the cracker 800 where they were combusted to close the fuel requirement of the cracker 800. The cracker hydrogen 980 is also fed to cracker 800 where it was combusted to close the fuel requirement of the cracker 800. According to embodiments, the byproduct stream rich in methane 950 and cracker hydrogen 980 were recovered in the separating unit 900 in two separate streams (shown in FIG. 6), or in a single combined stream (not shown). Example 3A. H₂-fired Propane/Naphtha (60/40) Cracker with excess H₂ utilization + SynOlefin from waste-derived syngas. [0054] The process of Example 3A is as shown in FIG. 4. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances were considered for the cracker 800, excluding the integrated energy balance for the downstream 85415-WO-PCT/DOW 85415 WO product separation. The byproduct stream rich in CH₄950 was reformed using an ATR unit 200, and the obtained syngas 250 is subsequently shifted in a WGS unit 600 to obtain H2 and CO2 stream 350. After CO2 separation and liquefaction in unit 400, part of the resulting H2440 is used as fuel in the cracker 800 and part of the H₂440 is used to supplement the waste plastic derived syngas 650. The amount of waste plastic 610 processed through gasification was determined by the amount of H2 440 that is not needed to fuel the cracker 800. The syngas stream 650 was converted to light olefins in a direct syngas-to-olefin processing unit 700, generating non-fossil ethylene and propylene stream 760 and supplementing the production of ethylene and propylene stream 850 from fossil hydrocarbon feedstock 820 containing a mix of propane and naphtha. Example 3B. Electrified Propane/Naphtha (40/60) Steam Cracker + Fischer-Tropsch Naphtha from CH₄, excess H₂ fueling and waste gasification integrated with electrolysis. [0055] The process of Example 3B is as shown in FIG. 5. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances are considered for the cracker, excluding the integrated energy balance for the downstream product separation. The byproduct stream rich in CH₄950 was reformed through ATR unit 200, and some process H2 980 was utilized to supplement the reformer syngas 250 and waste-plastic derived syngas 650. CO2 in the ATR unit product stream is removed using an amine acid gas removal system to generate CO₂ rich by-product that is recycled to the feed of the ATR unit (internal recycle in ATR unit 200). CO2 generated in furnace heaters of ATR unit 200 can be captured and re-used in other processes (not shown). Excess process H2980 was used to lower the electrification requirement of the cracker 800. Green H₂ 550 obtained from PEM electrolysis unit 500 (51.7 kWh/kg H2) was utilized to supplement waste-plastic derived syngas 650 at the same scale as Example 4. The O2570 obtained from electrolysis unit 500 was used to feed the ATR unit 200, reducing the O₂ requirement from the ASU 100 for the ATR unit 200. Both syngas streams 650 and 250 were combined into the syngas conversion block 700, generating non-fossil naphtha 750 and displacing fossil feedstock 820. Example 4. Electrified Propane/Naphtha (40/60) Steam Cracker + Fischer-Tropsch Naphtha from CH₄ and waste 85415-WO-PCT/DOW 85415 WO [0056] The process of Example 4 is as shown in FIG.1. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances were considered for the cracker 800, excluding the integrated energy balance for the downstream product separation. The byproduct stream rich in CH₄950 was reformed in an ATR unit 200, and cracker H₂ 980 was utilized to supplement the reformer syngas 250 and waste-plastic derived syngas 650. CO2 in the ATR unit product stream is removed using an Amine acid gas removal system to generate CO2 rich by-product that is recycled to the feed of the ATR unit (internal recycle in ATR unit 200). CO₂ generated in furnace heaters of ATR unit 200 can be captured and re-used in other processes (not shown). Both syngas streams 250 and 650 were combined into the syngas conversion block 700, generating non-fossil naphtha 750 and displacing fossil feedstock 820. Comparative Example 4. Conventional Ethane/Propane Cracker (40/60) [0057] The process of Comparative Example 4 is as shown in FIG. 7. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances were considered for the cracker 800, excluding the integrated energy balance for the downstream product separation. [0058] A fossil feedstock comprising 40/60 mixture of ethane/propane 820 was fed into the cracker 800 and converted into a cracked product 850 that comprises methane, hydrogen, and light olefins. The cracked product 850 was introduced into a separating unit 900 where the cracked product was separated into byproduct stream rich in methane 950, cracker hydrogen 980, and a light olefin stream 970. The byproduct stream rich in methane 950 was fed to the cracker 800 where it was combusted to close the fuel requirement of the cracker 800. The cracker hydrogen 980 is also fed to cracker 800 where it was combusted to close the fuel requirement of the cracker 800. According to embodiments, the byproduct stream rich in methane 950 and cracker hydrogen 980 were recovered in the separating unit 900 in two separate streams (shown in FIG. 7), or in a single combined stream (not shown). Comparative Example 5. Conventional Propane/Naphtha Cracker (40/60) 85415-WO-PCT/DOW 85415 WO [0059] The process of Comparative Example 5 is as shown in FIG. 7. Mass balances were determined based on the unit ratios given above for the respective technologies. Furnace energy balances were considered for the cracker 800, excluding the integrated energy balance for the downstream product separation. [0060] A fossil feedstock comprising 40/60 mixture of propane/naphtha 820 was fed into the cracker 800 and converted into a cracked product 850 that comprises methane, hydrogen, and light olefins. The cracked product 850 was introduced into a separating unit 900 where the cracked product was separated into byproduct stream rich in methane 950, cracker hydrogen 980, and a light olefin stream 970. The byproduct stream rich in methane 950 was fed to the cracker 800 where it was combusted to close the fuel requirement of the cracker 800. The cracker hydrogen 980 is also fed to cracker 800 where it was combusted to close the fuel requirement of the cracker 800. According to embodiments, the byproduct stream rich in methane 950 and cracker hydrogen 980 were recovered in the separating unit 900 in two separate streams (shown in FIG. 7), or in a single combined stream (not shown). [0061] The product carbon efficiencies of the above examples are shown Table 6, expressed by the amount of C2 and C3 olefins produced divided by the fossil feed intake. Additionally, the amount of non-fossil feedstock in the form of waste plastic is also calculated. In the case of an electrified cracker, the e-cracker energy requirement (including the air separation unit (ASU), electrolysis unit, and electrified furnaces) per kg of C2 and C3 olefins was also calculated. [0062] As can be observed from Table 6, the integration of cracker H2 and reforming of cracker CH₄ from an electrified ethane cracker complex with a syngas to LPG technology (Example 1) leads to higher C2-C3 olefin yields per fossil feed intake than a conventional ethane cracker (Comparative Example 2) and allows for the intake of non-fossil feedstocks like waste plastic. Additionally, the integration with the e-cracker H₂ is more energy efficient compared to the integration with green H₂ obtained from electrolysis (Comparative Example 1). [0063] Similarly, the amount of C2-C3 olefins per fossil feed intake can also be increased for a H2-fired mixed ethane/propane cracker integrated with MeOH/MTO (Example 2) or mixed propane/naphtha cracker integrated with direct Syngas to Olefins technology (Example 3A) compared to conventional crackers with equal feed intake (Comparative Example 4), through the 85415-WO-PCT/DOW 85415 WO integration of off-gas reforming, using part of the H₂ for firing the furnaces and utilizing the excess (blue) H2 for integrating with syngas derived from waste plastics through gasification. [0064] Additionally, the integration of cracker H2 and reforming of cracker CH4 from an electrified propane/naphtha cracker complex with a naphtha-selective Fischer Tropsch process (Example 4) leads to higher C₂-C₃ olefin yielded per fossil feed intake than a conventional propane/naphtha cracker (Comparative Example 5) and allowed for the intake of non-fossil feedstocks like waste plastic. Additionally, the integration with the e-cracker H2 is more energy efficient compared to the integration with green H₂ obtained from electrolysis (Comparative Example 4). Table 6: Olefin Yields, E-cracker power requirement and Non-Fossil feed input for integrated process configurations

85415-WO-PCT/DOW 85415 WO [0065] *Direct CO₂ emissions represents the CO₂ that is generated and released to the atmosphere from the conversion of the cracker CH4 (i.e. Combustion in the cracker furnace or conversion to syngas with residual CO2 formation for process heating) [0066] ^ Represents total electrical power requirement for e-cracking, oxygen provision to the reforming unit from an Air Separation Unit and water electrolysis [0067] It is noted that the terms “substantially” and “about” may be utilized herein to represent the inherent degree of uncertainty that may be attributed to any quantitative comparison, value, measurement, or other representation. These terms are also utilized herein to represent the degree by which a quantitative representation may vary from a stated reference without resulting in a change in the basic function of the subject matter at issue. The term “substantially” is used herein also to represent the degree by which a quantitative representation may vary from a stated reference without resulting in a change in the basic function of the subject matter at issue. Thus, it is used to represent the inherent degree of uncertainty that may be attributed to any quantitative comparison, value, measurement, or other representation, referring to an arrangement of elements or features that, while in theory would be expected to exhibit exact correspondence or behavior, may in practice embody something less than exact. [0068] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the present disclosure belongs. The terminology used in the description herein is for describing particular embodiments only and is not intended to be limiting. As used in the specification and appended claims, the singular forms “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. [0069] It is noted that one or more of the following claims utilize the term “wherein” as a transitional phrase. For the purposes of defining the present technology, it is noted that this term is introduced in the claims as an open-ended transitional phrase that is used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.” 85415-WO-PCT/DOW 85415 WO [0070] It should be understood that where a first component is described as “comprising” or “including” a second component, it is contemplated that, in some embodiments, the first component “consists” or “consists essentially of” the second component. Additionally, the term “consisting essentially of” is used in this disclosure to refer to quantitative values that do not materially affect the basic and novel characteristic(s) of the disclosure. [0071] It should be understood that any two quantitative values assigned to a property or measurement may constitute a range of that property or measurement, and all combinations of ranges formed from all stated quantitative values of a given property or measurement are contemplated in this disclosure. [0072] While particular embodiments have been illustrated and described herein, it should be understood that various other changes and modifications may be made without departing from scope of the claimed subject matter. Moreover, although various aspects of the claimed subject matter have been described herein, such aspects need not be utilized in combination. It is therefore intended that the appended claims cover all such changes and modifications that are within the scope of the claimed subject matter.

Claims

85415-WO-PCT/DOW 85415 WO CLAIMS 1. A method of producing light olefins, the method comprising: introducing a hydrocarbon feedstock into a steam-cracking unit; cracking the hydrocarbon feedstock in the steam-cracking unit to obtain a cracked product; introducing the cracked product into a separating unit; separating the cracked product to obtain a methane stream, a hydrogen stream, and a light olefin containing stream; introducing the methane stream into a reforming unit; producing reformer synthesis gas (syngas) in the reforming unit; introducing process hydrogen, the reformer syngas, an additional syngas stream, or combinations thereof into a syngas conversion unit; and converting the process hydrogen, the reformer syngas, the additional syngas stream, or combinations thereof into a syngas conversion product, wherein the process hydrogen comprises hydrogen separated from the cracked product, hydrogen obtained from a water-gas-shift unit, or combinations thereof, and wherein energy required for the steam-cracking unit is at least partially provided by the process hydrogen, by electricity, or by combinations thereof. 2. The method of claim 1, wherein the methane stream and the process hydrogen stream are recovered from the cracked product in a separating unit that is configured with front-end hydrogenation or configured with tail-end hydrogenation. 3. The method of claim 1 or claim 2, further comprising: introducing the reformer syngas and steam into the water-gas-shift unit; producing a water-gas-shift product comprising carbon dioxide and hydrogen in the water- gas-shift unit; separating the water-gas-shift product into carbon dioxide and hydrogen in a separation unit; and introducing the hydrogen into the syngas conversion unit. 4. The method of any one of claims 1 to 3, wherein the additional syngas stream is a gasifier syngas that is generated by gasification of a solid carbonaceous feedstock in a gasifier. 85415-WO-PCT/DOW 85415 WO 5. The method of any one of claims 1 to 4, wherein the syngas conversion product is combined with the hydrocarbon feedstock and introduced into the steam-cracking unit. 6. The method of any one of claims 1 to 5, wherein the steam-cracking unit is an electric steam-cracking unit. 7. The method of claim 1, wherein the process hydrogen is hydrogen obtained from the water- gas-shift unit. 8. The method of any one of claims 1 to 7, wherein the syngas conversion product comprises light olefins, liquid hydrocarbons, light hydrocarbons, or combinations thereof. 9. The method of any one of claims 1 to 8, wherein the syngas conversion product comprises methanol. 10. The method of claim 9, wherein the methanol is converted to olefins. 11. The method of any one of claims 1 to 10, wherein the syngas conversion product is combined with the cracked product and introduced into the separating unit. 12. The method of any one of claims 1 to 11, wherein the steam-cracking unit is a hydrogen fired steam cracker unit. 13. The method of claim 12, wherein the hydrogen stream separated from the cracked product is recycled, together with hydrogen produced from reforming methane in the cracked product, back to the steam-cracking unit for combustion. 14. The method of any one of claims 1 to 13, wherein the hydrocarbon feedstock comprises, naphtha, propane, ethane, or combinations thereof. 15. The method of any one of claims 1 to 14, wherein oxygen, steam, or combinations thereof is fed to the reforming unit, the gasifier, or combinations thereof.