System and method for decarbonization and energy improvement for integrated production of olefins and hydrogen

Abstract

Systems and methods for simultaneous production of olefins and hydrogen. Some such methods comprise: cracking a feed stream in a cracker to produce an olefin product stream, a flue gas stream, and a tailgas stream; directing the tailgas stream to a pressure swing adsorption (PSA) system to separate the tailgas stream into a hydrogen product stream and a methane-rich stream; and directing the methane-rich stream to a fuel inlet of the cracker. Some such systems comprise: a steam cracking system, a pressure swing adsorption (PSA) system, and a CO2 removal system. The steam cracking system is configured to crack a hydrocarbon-containing feedstock to generate an olefins product stream, a flue gas stream, and a tailgas stream; the PSA system is configured to separate hydrogen from the tailgas stream to generate a hydrogen product stream and a methane- rich stream, and to direct the methane-rich stream to the furnace of the steam cracking system for combustion; and the CO2 removal system is configured to remove CO2 from the flue gas stream to generate a captured CO2 stream.

Description

23T&I0044-WO-ORDSYSTEMS & METHODS FOR DECARBONIZATION AND ENERGY IMPROVEMENT FOR INTEGRATED PRODUCTION OF OLEFINS AND HYDROGENFIELD OF DISCLOSURE

[0001] The present disclosure relates generally to production of olefins and hydrogen and, more particularly but not by way of limitation, to systems and methods for reducing the carbon footprint and improvement of energy efficiency of integrated production of olefins and hydrogen.BACKGROUND

[0002] Many countries have pledged to decrease their emissions of certain greenhouse gases or GHGs, such as carbon dioxide (CO2). Even in the absence of legal requirements, there are additional social and economic pressures on private entities to also reduce GHG emissions.

[0003] From the perspective of an individual entity, such GHG emissions may be classified as Scope 1, Scope 2, or Scope 3 emissions. Scope 1 are generally GHG emissions arising directly from sources owned or controlled by the entity, such as equipment in a chemical production plant. Scope 2 emissions are generally GHG emissions arising from the generation of electricity purchased or otherwise acquired by the entity. Scope 3 emissions are generally GHG emissions arising from all indirect emissions outside the entity but that arise in course of the entity’s operations (e.g., arising in the production and transport of raw materials and equipment acquired by the company). Entities typically have the most direct control over Scope 1 emissions, but may also indirectly influence Scope 2 and Scope 3 emissions through various sourcing decisions and interactions with suppliers and vendors.

[0004] An entity desiring to reduce total GHG emissions therefore may wish to balance reductions in Scope 1 emissions with potential increases in Scope 2 or Scope 3 emissions. For example, electrification to reduce Scope 1 emissions may reduce overall GHG emissions if any increase in Scope 2 emissions due to the production of the required electricity is smaller than the reduction of Scope 1 emissions. However, the balance between Scope 1, Scope 2, and Scope 3 emissions is often more complicated. For example, decarbonization or removal of CO2 from emissions can be costly and energy intensive, as doing so typically requires additional equipment and significant amounts of energy. Moreover, generating electrical energy via conventional means such as combustion of hydrocarbon also creates such gases (CO2), meaning conventional approaches to reducing Scope 1 emissions may impact additional Scope 2 and / or Scope 323T&I0044-WO-ORD emissions. Thus, while reducing GHG emissions is a common desire, achieving net reductions in total GHG can be elusive, particularly in industries that require combustion or other chemical reactions that necessarily produce greenhouse gases like CO2.SUMMARY

[0005] Chemical production presents unique challenges to decarbonizing a chemical plant in that a chemical plant often requires enormous amounts of thermal energy that is typically provided by combustion, and may rely on chemical reactions that necessarily produce greenhouse gases like CO2. Several options are available for reducing GHG emissions of a plant, such as carbon capture directly at a combustion stack to remove CO2 from flue gasses, or utilizing blue hydrogen (H2) as a combustion fuel instead of fossil fuels. However, such options are localized to a given plant and do not involve integrating multiple plants. Moreover, the production of hydrogen typically occurs in reformers that produce their own CO2 emissions, or electrolyzers that are highly energy intensive. And the production of H2 becomes even more energy intensive when the reformer needs to reduce the CO2 emissions via carbon capture and storage (CCS).

[0006] Olefins are typically produced by cracking ethane, propane LPG and / or naphtha. A cracker used for such a process typically generates tailgas that includes a mix of byproducts including hydrogen and methane. These unpreventable byproducts, are typically returned to the cracker to provide energy for combustion, and are not used to produce chemicals. Of these byproducts, hydrogen is typically produced in separate plants as a fuel and / or raw material for other chemicals.

[0007] The present systems and methods can be configured and implemented to produce olefins while capturing CO2 from the cracker, reducing the amount of CO2 produced, and capturing hydrogen (H2) produced by the cracker for use as a raw material, thereby reducing the overall GHG emissions and energy intensity for the produced olefins and hydrogen. Such systems and methods route tail gases from the cracker to a pressure shift adsorption (PSA) system to remove hydrogen from the tail gases to generate a hydrogen stream and a methane-rich stream, to returning the methane-rich stream to the cracker for combustion to heat the cracker. This routing of tailgas to the PSA system means that hydrogen is produced without requiring a separate reformer (or combustion fuel or carbon capture system (CCS) for such a reformer), or the much larger electricity generation requirements that would otherwise be required for an electrolyzer. Rather, the PSA23T&I0044-WO-ORD system does not generate additional CO2 and instead routes remaining tailgas (after removal of hydrogen) back to the cracker for extraction of energy via combustion, thereby allowing for a single point of carbon capture from cracker flue gases via a single CCS system. Additionally, by removing the hydrogen prior to combustion of the methane-rich stream (e.g., all remaining tailgas), the CO2 concentration increases in the flue gas from the cracker, improving the energy efficiency with which the CO2 can be captured by the CCS.

[0008] In some configurations of the present systems for production of olefins and hydrogen, the system comprises: a steam cracking system, a pressure swing adsorption (PSA) system, and a CO2 removal system. In some such configurations, the steam cracking system comprises: a reactor configured to crack a hydrocarbon-containing feedstock to generate an olefins product stream, a flue gas stream, and a tailgas stream; and a furnace configured to combust a fuel to heat the reactor. In some such configurations, the PSA system is configured to receive the tailgas stream from the steam cracking system, to separate hydrogen from the tailgas stream to generate a hydrogen product stream and a methane-rich stream, and to direct the methane-rich stream to the furnace of the steam cracking system for combustion. In some such configurations, the CO2 removal system configured to receive the flue gas stream from the steam cracking system and remove CO2 from the flue gas stream to generate a captured CO2 stream.

[0009] In some of the foregoing configurations, the system for production of olefins and hydrogen is configured to operate such that the captured CO2 stream and any CO2 emissions are generated at a combined rate by mass that is less than 115% of the combined rate by mass at which the olefin product stream and hydrogen product stream are produced.

[0010] In some of the foregoing configurations, the CO2 removal system is configured to direct the captured CO2 stream into a CO2 transport system.

[0011] In some of the foregoing configurations, the steam cracking system comprises a feed inlet configured to receive the feedstock, a fuel inlet configured to receive fuel for the furnace, a product outlet, a flue gas outlet, and a tailgas outlet. In some such configurations, the CO2 removal system comprises a gas inlet, a gas outlet, a CO2 outlet, a solvent inlet, and a solvent outlet; the gas inlet is in fluid communication with the flue gas outlet of the steam cracking system to receive the flue gas stream; and the CO2 removal system is configured such that as the flue gas stream flows through the CO2 removal system and a physical solvent flows through the CO2 removal system, CO2 is removed from the flue gas stream to produce a captured CO2 stream through23T&I0044-WO-ORD captured CO2 outlet, and a reduced-CCh flue gas stream through the gas outlet. In some such configurations, the gas outlet of the CO2 capture system is in fluid communication with a CO2 transport system.

[0012] In some of the foregoing configurations, the PSA system comprises a tailgas inlet, a methane outlet, and a hydrogen outlet; the tailgas inlet is in fluid communication with the tailgas outlet of the steam cracking system to receive the tailgas stream, and the methane outlet is in fluid communication with the fuel inlet of the steam cracking system, and the PSA system is configured to direct the hydrogen stream through the hydrogen outlet, and to direct the methane-rich stream through the methane outlet.

[0013] In some of the foregoing configurations, the steam cracking system is configured to mix the methane-rich stream with a fuel stream.

[0014] In some implementations of the present methods, the method comprises: cracking a feed stream in a cracker to produce an olefin product stream, a flue gas stream, and a tailgas stream; directing the tailgas stream to a pressure swing adsorption (PSA) system to separate the tailgas stream into a hydrogen product stream and a methane-rich stream; and directing the methane-rich stream to a fuel inlet of the cracker.

[0015] Some of the foregoing implementations further comprise: capturing CO2 from the flue gas stream to generate a captured CO2 stream. Some such implementations further comprise: directing the captured CO2 stream to a CO2 transportation system.

[0016] Some of the foregoing implementations further comprise: combusting the methane- rich stream and a fuel stream to heat a reactor of the cracking system. Some such implementations further comprise: mixing the methane-rich stream with the fuel stream prior to the combusting.

[0017] In some of the foregoing implementations, the rate by mass at which the hydrogen product stream is produced is in excess of seven (7) percent of the rate by mass at which the olefin product stream is produced.

[0018] In some of the foregoing implementations, the combined Captured CO2 (if any) and Scope 1 emissions are generated at a rate by mass that is less than 115% of the combined rate by mass at which the olefins and hydrogen product streams are produced.

[0019] The term “coupled” is defined as connected, although not necessarily directly, and not necessarily mechanically; two items that are “coupled” may be unitary with each other. The terms “a” and “an” are defined as one or more unless this disclosure explicitly requires otherwise. The23T&I0044-WO-ORD term “substantially” is defined as largely but not necessarily wholly what is specified (and includes what is specified; e.g., substantially 90 degrees includes 90 degrees and substantially parallel includes parallel), as understood by a person of ordinary skill in the art. In any embodiment of the present apparatuses, kits, and methods, the term “substantially” may be substituted with “within [a percentage] of’ what is specified, where the percentage includes 0.1, 1, 5, and / or 10 percent.

[0020] The terms “comprise” (and any form of comprise, such as “comprises” and “comprising”), “have” (and any form of have, such as “has” and “having”), “include” (and any form of include, such as “includes” and “including”) and “contain” (and any form of contain, such as “contains” and “containing”) are open-ended linking verbs. As a result, an apparatus or kit that “comprises,” “has,” “includes” or “contains” one or more elements possesses those one or more elements, but is not limited to possessing only those elements. Likewise, a method that “comprises,” “has,” “includes” or “contains” one or more steps possesses those one or more steps, but is not limited to possessing only those one or more steps.

[0021] Further, an apparatus, device or system that is configured in a certain way is configured in at least that way, but it can also be configured in other ways than those specifically described.

[0022] Any embodiment of any of the present apparatuses and methods can consist of or consist essentially of - rather than comprise / include / contain / have - any of the described steps, elements, and / or features. Thus, in any of the claims, the term “consisting of’ or “consisting essentially of’ can be substituted for any of the open-ended linking verbs recited above, in order to change the scope of a given claim from what it would otherwise be using the open-ended linking verb.

[0023] Details associated with the embodiments described above and others are presented below.

[0024] Some details associated with the various configurations and implementations of the present systems and methods are described above, and others details are described below. Other implementations, advantages, and features of the present disclosure will become apparent after review of the entire application, including the Brief Description of the Drawings, Detailed Description, and the Claims.23T&I0044-WO-ORDBRIEF DESCRIPTION OF THE DRAWINGS

[0025] The following drawings illustrate by way of example and not limitation. For the sake of brevity and clarity, every feature of a given structure is not always labeled in every figure in which that structure appears. Identical labels or reference numbers do not necessarily indicate an identical structure. Rather, the same reference number may be used to indicate a similar feature or a feature with similar functionality, as may non-identical reference numbers.

[0026] FIG. 1 depicts a block flow diagram of a generalized steam cracking plant or process.

[0027] FIG. 2 depicts a block flow diagram of a system having a steam cracker for olefin production and a steam methane reformer for production of hydrogen.

[0028] FIG. 3 depicts a block flow diagram of a system having a steam cracker for olefin production and a steam methane reformer for production of hydrogen, with respective carbon capture systems for each of the cracker and the reformer.

[0029] FIG. 4 depicts a block flow diagram of an example of the present systems including a steam cracker for olefin production and pressure swing adsorption (PSA) system for production of hydrogen from a tailgas stream from the cracker, with a carbon capture system for the cracker.

[0030] FIG. 5 depicts a more-detailed block flow diagram of one example of a system like that of FIG. 2.

[0031] FIG. 6 depicts a more-detailed block flow diagram of one example of a system like that of FIG. 3.

[0032] FIG. 7 depicts a more-detailed block flow diagram of one example of a system like that of FIG. 4.DETAILED DESCRIPTION

[0033] Referring now to the drawings, and more particularly to Figure 1, shown there is a block flow diagram of an example of a generalized steam cracking plant or process, which includes one or more of the following process sections for converting a feed stream 5 into a desired olefin product stream 50: a feed pretreatment section 10, a pyrolysis reaction section 20, a primary fractionation and compression section 30, a product fractionation (separation) and compression section 40, or a combination thereof. Such sections will be described briefly in the next few paragraphs, and in more detail hereinbelow.23T&I0044-WO-ORD

[0034] Feed pretreatment section 10 can be configured to adjust the pressure of a feed 5, possibly remove undesirable components (e.g., carbon dioxide (CO2), mercury, water) from a feed, combine an incoming feed with a stored feed to minimize variations in the feed to the pyrolysis reaction section 20, and / or preheat the feed 5, to provide a pretreated feed stream 15.

[0035] Pyrolysis reaction section 20 can comprise at least one steam cracker or ‘pyrolysis’ furnace configured to crack hydrocarbons in the presence of steam to produce a cracked gas stream and a transfer line exchanger (TLE) or other heat transfer device to quench (and optionally harvest heat from) the cracked gas stream to provide a cooled cracked stream 25. Conventionally, the furnaces of a steam cracking plant create a high temperature environment by the combustion of fuels such as methane, which produces carbon dioxide emissions from a conventional steam cracking plant / process.

[0036] The primary fractionation and compression section 30 can be configured to provide further heat recovery from and quenching of the cooled cracked gas stream 25, remove one or more components (e.g., fuel oil, hydrogen sulfide, carbon dioxide, water, or a combination thereof) from the cracked gas stream 25, and / or compress the cracked gas stream 25, thus providing a compressed cracked gas stream 38.

[0037] The product fractionation or separation section 40 can be configured to fractionate the compressed cracked gas stream 38, selectively hydrogenate one or more streams produced during the fractionation, and provide one or more olefin (e.g., ethylene, propylene) product streams 50. The product fractionation or separation section 40 may also provide one or more byproduct streams 60, such as, without limitation, a Ci stream, a C2 saturate stream, a C3 saturate stream, a C4 saturate stream, an acetylene stream, a butadiene stream, a 1-butene stream, an isobutylene stream, an aromatics stream, a hydrogen stream, a pyrolysis gasoline stream, and / or a fuel oil stream, or streams comprising a combination of these components. Some of these streams may be recycled to one or more sections of the steam cracking plant. For example, without limitation, the C2, C3, and / or C4 saturates streams may be recycled to one or more of the pyrolysis furnaces of the pyrolysis reaction section 20, hydrogen may be purified (e.g., via a pressure swing adsorption unit (PSA) and a methanation reactor to remove CO) and recycled to a hydrogenation reactor (e.g., a C2, C3, acetylene, or di-olefin hydrogenator) and / or utilized as a fuel source (e.g., via fuel cell). The Ci stream may also be recycled for use as a fuel (e.g., for the production of hydrogen therefrom).23T&I0044-WO-ORD

[0038] Figure 2 depicts a block flow diagram of an example 100a of a system having a steam cracker 104 for olefin production and a steam methane reformer 108 for production of hydrogen. As shown, cracker 104 receives a cracker feed stream 112 of ethane, propane LPG and / or naphtha, as well as a combustion fuel stream 116 of natural gas. The combustion fuel is combusted to heat the cracker, in which the cracker feed stream is “cracked” to produce a product stream 120 predominantly comprising olefins and a tail gas byproduct stream 124 comprising hydrogen and methane. In this example of a conventional system, the tail gas is returned to the cracker with the combustion fuel and burned to heat the cracker, thereby producing a flue gas stream 128 that includes CO2. As shown, steam methane reformer 108 receives a natural gas feed stream 132 and a natural gas combustion fuel stream 136. The combustion fuel stream is burned to heat the reformer, which separates hydrogen from the methane in the feed stream to produce a product stream 140 of hydrogen. The combustion of the fuel stream to heat the reformer also produces a flue gas stream 144 that includes CO2. In this example, natural gas is provided as a combustion fuel for both the cracker and the reformer, its combustion for both produces two separate flue gas streams containing CO2. In past approaches, all of this CO2 is emitted to the atmosphere.

[0039] Figure 3 depicts a block flow diagram of an example 100b of system having a steam cracker 104 for olefin production and a steam methane reformer 108 for production of hydrogen, with respective carbon capture systems (CCSs) 148 and 152 for each of the cracker and the reformer. System 100b is substantially similar to system 100a, with the exception of the addition of the CCSs 148, 152. As such, the same reference numerals used to designate similar components, and the differences are therefore primarily described here. As shown, system 100b includes a first carbon capture system 148 that receives flue gas stream 128 from cracker 104, and a second carbon capture system 152 that receives flue gas stream 144 from reformer 108. First CCS 148 captures a majority (e.g., greater than 90%) of CO2 from flue gas stream 128 to generate a captured CO2 stream 156 for sequestration, and the remaining minority of CO2 from flue gas stream 128 is released to the atmosphere in a CO2 emission stream 160 (i.e., a reduced-CCh flue gas stream). Similarly, second CCS 152 captures a majority (e.g., greater than 90%) of CO2 from flue gas stream 144 to generate a captured CO2 stream 164 for sequestration, and the remaining minority of CO2 from flue gas stream 144 is released to the atmosphere in a CO2 emission stream 168 (i.e., a reduced-CCh flue gas stream). In this example, a majority of carbon dioxide is captured from each of the cracker and the reformer, but the hydrogen produced by the cracker is burned.23T&I0044-WO-ORD

[0040] Figure 4 depicts a block flow diagram of an example 100c of the present systems including a steam cracker 104 for olefin production and a pressure swing adsorption (PSA) system 200 for production of hydrogen from tailgas stream 124 from the cracker, with a carbon capture system 148 for the cracker. Certain aspects of system 100c are substantially similar to those of system 100b, with the exception that PSA system 200 is used to capture hydrogen from the cracker tailgas instead of using a reformer to generate hydrogen. As such, the same reference numerals are used to designate similar components, and the differences are primarily described here. As shown, rather than returning all of tail gas steam 124 to the cracker as combustion fuel, tail gas stream 124 is instead routed to a pressure shift adsorption (PSA) system to extract hydrogen from the tail gas to thereby generate hydrogen product stream 140. The remaining methane-rich stream 204 (e.g., all tailgas remaining after removal of hydrogen) is returned to the cracker with the combustion fuel (stream 116) and burned to heat the cracker, thereby producing a flue gas stream 128a that includes CO2. However, because the hydrogen is removed from tail gas stream 124 prior to its combustion, system 100c is configured to generate flue gas stream 128a with more CO2 than that of the flue gas stream 128 of system 100a or system 100b. Counterintuitively, the increased proportion of CO2 can be beneficial to carbon capture by making it “easier” and thereby less energy intensive for CCS 148 to capture the CO2 from flue gas 128a. Additionally, system 100c is less energy intensive for given rates of production of olefins and hydrogen because PSA 200 requires less energy than a reformer (e.g., reformer 108 of systems 100a, 100b) to produce a similar quantity of hydrogen, and the omission of the reformer reduces the quantity of CO2 generation because combustion is not required to heat the reformer.Comparative Examples

[0041] Referring now to Figures 5-7, Figure 5 depicts a more-detailed block flow diagram of one example 100a-l of a system like that (system 100a) of Figure 2; Figure 6 depicts a more- detailed block flow diagram of one example 100b-l of a system like that (system 100b) of Figure 3; and Figure 7 depicts a more-detailed block flow diagram of one example 100c-l of a system like that (system 100c) of Figure 4. As shown, the respective systems were modeled for like quantities of product streams, in particular, 1325 kilotonnes per annum (kta) of Cracker Products (olefins) and 98 kta of hydrogen. For these product streams, the systems — including utilities) were modeled to determine expected inputs (natural gas and electricity) and outputs (including Scope 1 and Scope 2 emissions and, where applicable, Captured CO2) in kilotonnes per annum (kta). Some23T&I0044-WO-ORD modeled values for individual streams are shown in the figures. Additionally, Table 1 below summarizes the results for comparative purposes. As shown in Figure 6, in addition to the hydrogen product stream, reformer 108 produces a CO2 stream that can be captured along with the captured CO2 streams from CCSs 148, 152.Table 1: Results of Modeling Comparative Examples of FIGs. 5-7

[0042] As shown in Table 1, the present systems can be configured to simultaneously generate olefins and hydrogen, with the hydrogen generated at a rate by mass (e.g., in kta) that exceeds seven (7) percent of the rate by mass (e.g., in kta) at which olefins are generated, and with combined Captured CO2 (if any) and Scope 1 emissions generated at a rate by mass that is less than 115% of the combined rate by mass at which the olefins and hydrogen product streams are produced. In contrast, the combined Captured CO2 and Scope 1 emissions of system 100a-l (FIG. 5) are produced at a combined rate by mass (1657 kta) that is roughly 116% of the combined rate by mass (1423 kta) at which the olefins and hydrogen product streams are produced; and the Captured CO2 and Scope 1 emissions of system 100b-l (FIG. 6) are produced at a combined rate by mass (1859 kta) that is roughly 131% of the combined rate by mass (1423 kta) at which the olefins and hydrogen product streams are produced. Thus, in the present systems, integration of hydrogen production with cracking by removing hydrogen from cracker tailgas significantly reduces natural gas demand (even relative to system 100a-l with no carbon capture) as well as overall production of CO2 and, thereby, significantly reduces the volume of CO2 for potential sequestration. Additionally, while electricity demand and corresponding Scope 2 emissions increase, the increased reliance on electricity allows for further improvements in Scope 223T&I0044-WO-ORD emissions via sourcing and use of renewable energy sources such as solar and wind power rather than electricity generated via combustion of fossil fuels.* * *

[0043] Additional details about various components of steam cracking plants and processes can be found in International Patent Application Publication No. W02020 / 150244, which is incorporated by reference in its entirety.

[0044] The above specification and examples provide a complete description of the structure and use of exemplary embodiments. Although certain embodiments have been described above with a certain degree of particularity, or with reference to one or more individual embodiments, those skilled in the art could make numerous alterations to the disclosed embodiments without departing from the scope of this invention. As such, the various illustrative embodiments of the present devices are not intended to be limited to the particular forms disclosed. Rather, they include all modifications and alternatives falling within the scope of the claims, and embodiments other than the one shown may include some or all of the features of the depicted embodiment. For example, components may be combined as a unitary structure, and / or connections may be substituted. Further, where appropriate, aspects of any of the examples described above may be combined with aspects of any of the other examples described to form further examples having comparable or different properties and addressing the same or different problems. Similarly, it will be understood that the benefits and advantages described above may relate to one embodiment or may relate to several embodiments.

[0045] The claims are not intended to include, and should not be interpreted to include, means- plus- or step-plus-function limitations, unless such a limitation is explicitly recited in a given claim using the phrase(s) “means for” or “step for,” respectively.

Claims

23T&I0044-WO-ORDCLAIMS1. A system for production of olefins and hydrogen, the system for production of olefins and hydrogen comprising: a steam cracking system comprising: a reactor configured to crack a hydrocarbon-containing feedstock to generate an olefins product stream, a flue gas stream, and a tailgas stream; and a furnace configured to combust a fuel to heat the reactor; a pressure swing adsorption (PSA) system configured to receive the tailgas stream from the steam cracking system, to separate hydrogen from the tailgas stream to generate a hydrogen product stream and a methane-rich stream, and to direct the methane- rich stream to the furnace of the steam cracking system for combustion; a CO2 removal system configured to receive the flue gas stream from the steam cracking system and remove CO2 from the flue gas stream to generate a captured CO2 stream.

2. The system for production of olefins and hydrogen of claim 1, where the system for production of olefins and hydrogen is configured to operate such that the captured CO2 stream and any CO2 emissions are generated at a combined rate by mass that is less than 115% of the combined rate by mass at which the olefin product stream and hydrogen product stream are produced.

3. The system for production of olefins and hydrogen of any of claims 1-2, where the CO2 removal system is configured to direct the captured CO2 stream into a CO2 transport system.

4. The system for production of olefins and hydrogen of any of claims 1-2, where: the steam cracking system comprises a feed inlet configured to receive the feedstock, a fuel inlet configured to receive fuel for the furnace, a product outlet, a flue gas outlet, and a tailgas outlet.

5. The system for production of olefins and hydrogen of claim 4, where the CO2 removal system comprises a gas inlet, a gas outlet, a CO2 outlet, a solvent inlet, and a solvent outlet; the gas inlet is in fluid communication with the flue gas outlet of the steam cracking system to receive the flue gas stream; and the CO2 removal system is configured such that as the flue gas stream flows through the CO2 removal system and a physical solvent flows through the CO2 removal23T&I0044-WO-ORD system, CO2 is removed from the flue gas stream to produce a captured CO2 stream through captured CO2 outlet, and a reduced-CCh flue gas stream through the gas outlet.

6. The system for production of olefins and hydrogen of claim 5, where the gas outlet of the CO2 capture system is in fluid communication with a CO2 transport system.

7. The system for production of olefins and hydrogen of any of claims 3-6, where: the PSA system comprises a tailgas inlet, a methane outlet, and a hydrogen outlet; the tailgas inlet is in fluid communication with the tailgas outlet of the steam cracking system to receive the tailgas stream, and the methane outlet is in fluid communication with the fuel inlet of the steam cracking system, and the PSA system is configured to direct the hydrogen stream through the hydrogen outlet, and to direct the methane-rich stream through the methane outlet.

8. The system for production of olefins and hydrogen of any of claims 1-7, where the steam cracking system is configured to mix the methane-rich stream with a fuel stream.

9. A method for producing olefins and hydrogen, the method comprising: cracking a feed stream in a cracker to produce an olefin product stream, a flue gas stream, and a tailgas stream; directing the tailgas stream to a pressure swing adsorption (PSA) system to separate the tailgas stream into a hydrogen product stream and a methane-rich stream; and directing the methane-rich stream to a fuel inlet of the cracker.

10. The method for producing olefins and hydrogen of claim 9, further comprising: capturing CO2 from the flue gas stream to generate a captured CO2 stream.

11. The method for producing olefins and hydrogen of claim 10, further comprising: directing the captured CO2 stream to a CO2 transportation system.

12. The method for producing olefins and hydrogen of any of claims 9-11, further comprising: combusting the methane-rich stream and a fuel stream to heat a reactor of the cracking system.

13. The method for producing olefins and hydrogen of claim 12, further comprising: mixing the methane-rich stream with the fuel stream prior to the combusting.23T&I0044-WO-ORD14. The method for producing olefins and hydrogen of any of claims 9-13, where the rate by mass at which the hydrogen product stream is produced is in excess of seven (7) percent of the rate by mass at which the olefin product stream is produced.

15. The method for producing olefins and hydrogen of any of claims 9-14, where the combined Captured CO2 (if any) and Scope 1 emissions are generated at a rate by mass that is less than 115% of the combined rate by mass at which the olefins and hydrogen product streams are produced.

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