Integrated steam cracking unit with blue hydrogen unit to reduce CO2 emissions

Abstract

A method and system for integrating a steam cracking unit with a blue hydrogen unit wherein a methane-rich gas stream, a hydrogen-rich gas stream, or both from the steam cracking unit is fed to the blue hydrogen unit and a high purity hydrogen stream from the blue hydrogen unit is directed to the steam cracking unit.

Description

[0001] This application claims the benefit of U.S. Provisional Application No. 63 / 515,295, filed July 24, 2023, and U.S. Provisional Application No. 63 / 581,586, filed September 8, 2023, both of which are incorporated herein by reference in their entirety. Technical Field

[0002] This invention relates to a system and method for integrating a steam cracking unit with a blue hydrogen unit to reduce CO2 emissions. Background Technology

[0003] Olefin production typically involves steam cracking—a process that can be extremely energy-intensive and contribute significantly to global CO2 emissions. The primary source of direct CO2 emissions is the cracking furnace, where fuel gas is burned to provide the heat required for net process heating to satisfy the heat of the cracking reaction (endothermic reaction), and waste heat is used to generate steam.

[0004] The fuel gas used in the steam cracking unit can contain up to 80 mol%-85 mol% H2 in an ethane cracking unit, or as low as 10 mol%-15 mol% in a liquid cracking unit, with the remainder being primarily methane. The combustion of hydrogen does not result in associated CO2 emissions, while the combustion of methane produces a combustion load of approximately 230 kg CO2 / Gcal.

[0005] In a typical steam cracking unit, combustion air enters the furnace without preheating. With cold combustion air, heating the combustion air to combustion temperature alone requires a significant portion of the combustion load and results in associated CO2 emissions. This produces a relatively large flue gas stream, which is then used to provide net heat for feed preheating and superheated high-pressure (SHP) steam generation. Summary of the Invention

[0006] An exemplary embodiment of integrating a steam cracking unit with a blue hydrogen unit to reduce CO2 emissions can significantly avoid one or more problems caused by the limitations and disadvantages of the prior art.

[0007] Additional features and advantages of the invention will be set forth in the following description, and will be apparent in part from that description, or may be learned by practice of the invention. The objects and other advantages of the invention will be realized and attained by means of the structures particularly pointed out in the written description, the claims, and the drawings.

[0008] In one example, a system may include a steam cracking unit; a blue hydrogen unit including a hydrogen recovery system configured to generate a high-purity hydrogen stream; a first conduit configured to direct at least a portion of the high-purity hydrogen stream to the steam cracking unit for use as fuel; and a second conduit configured to direct at least a portion of a methane-rich stream from the steam cracking unit to the blue hydrogen unit.

[0009] In one example, the steam cracking unit may include a cracking furnace and a recovery stage configured to recover the methane-rich gas stream from the effluent gas from the cracking furnace of the steam cracking unit. In another example, the system may include a second conduit configured to direct at least a portion of the methane-rich gas stream to the blue hydrogen unit for use as feed, fuel, or both.

[0010] In one example, the system may include a compressor configured to compress at least a portion of the methane-rich gas stream before it reaches the blue hydrogen unit.

[0011] In one example, the system may include a recovery stage, which is part of the steam cracking unit and configured to receive effluent from the cracking furnace and separate at least a hydrogen-rich gas stream and a methane-rich gas stream from the effluent; and a third conduit configured to deliver at least a portion of the hydrogen-rich gas stream from the recovery stage to the hydrogen recovery system of the blue hydrogen unit.

[0012] In one example, the system may include a gas expander for expanding the high-purity hydrogen stream before it reaches the steam cracking unit.

[0013] In one example, the system may include a heater for preheating the high-purity hydrogen stream before it reaches the gas expander.

[0014] In one example, the system may include a compressor configured to compress at least a portion of the methane-rich gas stream before it reaches the blue hydrogen unit, wherein energy recovered by the gas expander is used to power the compressor.

[0015] In one example, a method may include generating a high-purity hydrogen stream in a blue hydrogen unit that includes a hydrogen recovery system; feeding the high-purity hydrogen stream to a steam cracking unit as fuel; and directing a methane-rich stream from the steam cracking unit to the blue hydrogen unit.

[0016] In one example, the method may include recovering the methane-rich gas stream from the effluent of the steam cracking unit; and directing the methane-rich gas stream as feed, fuel, or both to the blue hydrogen unit.

[0017] In one example, the steam cracking unit may include a cracking furnace. In another example, the method may include recovering a hydrogen-rich gas stream from the tail gas of the cracking furnace in the steam cracking unit; and transferring at least a portion of the recovered hydrogen-rich gas stream to the hydrogen recovery system of the blue hydrogen unit.

[0018] In one example, the method may include compressing the methane-rich gas stream before directing it to the blue hydrogen unit.

[0019] In one example, the method may include expanding the high-purity hydrogen gas stream before feeding it into the steam cracking unit.

[0020] In one example, the method may include preheating the high-purity hydrogen gas stream before expanding it.

[0021] In one example, the method may include recovering energy during the expansion of the high-purity hydrogen gas stream.

[0022] In one example, the method may include using a compressor to compress the methane-rich gas stream before directing it to the blue hydrogen unit, and using the energy recovered from the expansion of the high-purity hydrogen gas stream to power the compressor.

[0023] In one example, the steam cracking unit may include a cracking furnace, and the method may include preheating the combustion gas used as fuel in the cracking furnace of the steam cracking unit.

[0024] In this example, the steam cracking unit may include a cracking furnace, and the method may include preheating the feed to the cracking furnace of the steam cracking unit.

[0025] It should be understood that both the foregoing general description and the following detailed description are exemplary and explanatory, and are intended to provide further explanation of the invention as claimed. Attached Figure Description

[0026] The accompanying drawings, which are included to provide a further understanding of the invention and are incorporated in and form part of this specification, illustrate embodiments of the invention and, together with the description, serve to explain the principles of the invention.

[0027] In the attached diagram:

[0028] Figure 1 This is a schematic diagram of an example of an integrated steam cracking unit and a blue hydrogen unit.

[0029] Figure 2 This is a schematic diagram of an exemplary pyrolysis furnace for a steam pyrolysis unit that can be used in the described integrated system.

[0030] Figure 3 This is a schematic diagram of another example of a pyrolysis furnace for a steam pyrolysis unit that can be used in the described integrated system.

[0031] Figure 4 This is a schematic diagram of an exemplary recovery system for a steam cracking unit that can be used in the described integrated system. Detailed Implementation

[0032] In one example, a method and system for integrating a steam cracking unit with a hydrogen unit are disclosed. In this example, the hydrogen unit is a blue hydrogen unit. For the purposes of this disclosure, the term "blue hydrogen unit" is used to refer to a unit (or facility or system) that produces hydrogen via steam methane reforming (SMR) while simultaneously capturing and storing carbon dioxide (CO2) emissions generated during the production process. In this example, the disclosed method and system can achieve low or zero CO2 emissions through the integration of the steam cracking unit with the blue hydrogen unit.

[0033] In this example, the steam cracking unit may include an olefin unit configured to produce one or more olefins through the thermal cracking of a hydrocarbon feedstock (such as, for example, naphtha, ethane, propane, or butane) in the presence of steam. In this example, the high-temperature, high-pressure method can break down larger hydrocarbon molecules into smaller molecules, primarily ethylene and propylene. In this example, the olefins can be used in a variety of industrial applications.

[0034] Hydrogen recovery from the effluent gas of a steam cracking unit can be performed, but is typically limited in the purity levels that can be generated. Hydrogen can be recovered in the steam cracking unit via coarse separation of the effluent products. In one example, the separation can separate olefins from the hydrogen and methane effluents. In another example, further separation yields a hydrogen-rich stream and a methane-rich stream. In yet another example, the separation of hydrogen and methane can be performed in a cold box to produce a high-pressure hydrogen-rich stream with a purity of approximately 90 mol%–95 mol% and a low-pressure methane-rich stream, typically used as fuel gas. A portion of the hydrogen-rich stream can be injected into the methane-rich stream to achieve the necessary temperature drive in the cold box, thereby enabling cooling and separation. Therefore, the usable hydrogen recovery rate can be limited to approximately 80%–85%.

[0035] While the system can reduce carbon emissions, it may not be sufficient to achieve the desired results.

[0036] To address some of these issues, this paper discloses a method and system in which a steam cracking unit or olefin unit is integrated with a blue hydrogen unit. In one example, the integration can be configured such that tail gas from the steam cracking unit can be used as feed to the blue hydrogen unit. In another example, the integration can be configured such that a higher hydrogen concentration can be achieved in the hydrogen-rich gas stream separated from the effluent gas from the cracking furnace of the steam cracking unit using the blue hydrogen unit. In yet another example, the integration can be configured such that additional hydrogen is supplied to the steam cracking unit to supplement and / or replace the hydrogen-rich gas stream.

[0037] Reducing CO2 emissions has become a key factor in assessing the feasibility of projects or technologies. In practice, systems and methods described in this paper offer effective ways to achieve net-zero carbon emissions and have significant potential for environmental and economic benefits.

[0038] 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 this invention pertains. Unless otherwise stated, all patents, patent applications, published applications and publications, websites and other published materials mentioned throughout this disclosure are incorporated herein by reference in their entirety. Where a term has multiple definitions, the definition in this section shall prevail. In the reference to URLs or other such identifiers or addresses, it should be understood that such identifiers may change and information on the Internet may vary, but equivalent information can be found by searching the Internet. References to them demonstrate the availability and public dissemination of such information.

[0039] As used herein, unless the context clearly indicates otherwise, the singular forms “a / an” and “the” may contain plural references.

[0040] As used herein, the terms first, second, third, etc., can describe various elements, components, regions, layers, and / or segments, which should not be limited by these terms. These terms may be used only to distinguish one element, component, region, layer, or segment from another. Terms such as “first,” “second,” and other numerical terms used herein do not imply order or sequence unless the context clearly indicates otherwise. Therefore, without departing from the teachings of exemplary embodiments, the first element, component, region, layer, or segment discussed below may be referred to as a second element, component, region, layer, or segment.

[0041] As used herein, ranges and quantities can be expressed as “about” a specific value or range. “About” also includes precise quantities. Thus, “about 5 percent” means about 5 percent other than 5 percent. The term “about” means within the typical experimental error expected for the intended application or purpose.

[0042] As used herein, “and / or” includes any and all combinations of one or more of the associated enumerated items.

[0043] As used in this article, "combination" refers to any association between two or more items. Association can be spatial or refers to using two or more items for a common purpose.

[0044] As used herein, “include” and “include” should be interpreted as “includes but not limited to” and “including but not limited to”, respectively.

[0045] As used herein, "optional" or "optionally" means that an event or condition described below may or may not occur, and that the description includes both the possibility that the event or condition occurs and the possibility that it does not occur. For example, an optional component in a system means that the component may or may not exist in the system.

[0046] As used in this article, “generally” means “mostly but not entirely in accordance with the specification”.

[0047] Figure 1 A diagram illustrating the integration scheme between the steam cracking unit and the blue hydrogen unit is shown. In an example, such as... Figure 1 As demonstrated, the methods and systems disclosed herein use external high-purity hydrogen, such as that generated in the Blue Hydrogen unit, as fuel to the cracking furnace in the steam cracking unit, with the goal of achieving net-zero emissions in the steam cracking unit. In an example, the methods and systems disclosed herein can use supplemental hydrogen from the Blue Hydrogen unit to reduce carbon emissions in the steam cracking unit (potentially achieving complete net-zero emissions).

[0048] In an example, such as Figure 1 As shown, the integration method and system 100 can integrate a steam cracking unit 110 and a blue hydrogen unit 120. In one example, the integration method and system 100 may include a steam cracking unit 110 in fluid communication with the blue hydrogen unit 120. In one example, the integration 100 of the steam cracking unit 110 and the blue hydrogen unit 120 may be achieved by feeding a methane-rich effluent from the steam cracking unit 110 into the blue hydrogen unit 120. In one example, the integration 100 of the steam cracking unit 110 and the blue hydrogen unit 120 may be achieved by using a methane-rich effluent from the steam cracking unit 110 as fuel for the blue hydrogen unit 120. In one example, the integration 100 of the steam cracking unit 110 and the blue hydrogen unit 120 may be achieved by using a high-purity hydrogen stream from the blue hydrogen unit 120 as fuel for the steam cracking unit 110. In one example, the integration 100 may include using the blue hydrogen unit 120 to purify at least a portion of the hydrogen-rich effluent from the steam cracking unit 110.

[0049] In one example, the steam cracking unit 110 may include a cracking furnace 112. In another example, the steam cracking unit 110 may include a recovery system 114.

[0050] The blue hydrogen unit 120 can be configured in different ways while still achieving the benefits of the present invention. For the purposes of this specification, Figure 1 An implementation of the blue hydrogen unit 120 and its integration with the steam cracking unit 110 are shown. In an example, such as... Figure 1 As shown, the Blue Hydrogen Unit 120 may include a hydrogen synthesis system 122, one or more carbon capture systems 124 (e.g., 124a and 124b), and a hydrogen recovery system 126.

[0051] In examples, a blue hydrogen unit may involve using steam methane reforming (SMR) technology to produce hydrogen from natural gas hydrocarbons such as methane. In examples, a blue hydrogen unit may also include a carbon capture and storage (CCS) system to mitigate carbon emissions associated with the method.

[0052] like Figure 1 As shown, the blue hydrogen unit 120 may include a natural gas feed 128. In an example, the natural gas feed 128 may include methane (CH4). In an example, natural gas or methane may be used as a hydrogen source in the blue hydrogen production method.

[0053] In this example, natural gas feed 128 is supplied to hydrogen synthesis system 122. In this example, hydrogen synthesis system 122 may include a hydrogen generator or a steam methane reformer. In this example, steam feed 130 is also supplied to hydrogen synthesis system 122. In this example, during steam methane reforming, natural gas hydrocarbons or methane feed may react with steam (H2O). In this example, the reaction may be performed under pressure at a high temperature, for example, between about 700°C and 1,000°C. In this example, heating of hydrogen synthesis system 122 may be provided electrically and / or by burning fuel stream 138.

[0054] In this example, steam methane reforming can produce hydrogen (H2) and carbon monoxide (CO) through a series of chemical reactions. For instance, in the initial step, hydrocarbons or methane can react with water molecules in steam to produce carbon monoxide and hydrogen, as shown in equation (1):

[0055] CH4 + H2O -> CO + 3H2(1)

[0056] In the example, the carbon monoxide produced in this step can further react with steam to produce additional hydrogen and carbon dioxide, as shown in equation (2):

[0057] CO + H2O -> CO2 + H2(2)

[0058] In this example, the blue hydrogen unit may include one or more carbon capture systems 124. In this example, one or more carbon capture systems 124 may be used to remove carbon dioxide generated during SMR from the effluent stream 132 of the hydrogen synthesis system 122. In this example, one or more carbon capture systems 124 may be used to capture carbon from burning fuel to heat the hydrogen synthesis system 122.

[0059] In an example, the carbon capture process may involve separating CO2 from hydrogen and other gases produced during a reforming process. Various techniques, such as absorption, adsorption, and membrane separation, can be used for this purpose. In an example, the carbon capture system 124 may include any equipment suitable for any of these methods, such as a tower, a rotating packed bed, a separation membrane, or other equipment.

[0060] In an example, such as Figure 1 As shown, the blue hydrogen unit 120 may include one or more carbon capture systems 124. For example, the blue hydrogen unit 120 may include a first carbon capture system 124a and a second carbon capture system 124b. In an example, the carbon capture system 124a may be configured to capture carbon dioxide from the effluent of the hydrogen synthesis system 122.

[0061] In one example, another carbon capture system 124b may be configured to capture carbon from the flue gas stream 146 of the hydrogen synthesis system 122, which is generated by burning hydrocarbons such as methane as fuel stream 138 to produce heat. In another example, the hydrogen synthesis system 122 does not use hydrocarbons (such as methane) in fuel stream 138 to produce heat. In such examples, an additional carbon capture system 124b may not be required. For example, the fuel stream 138 to the hydrogen synthesis system 122 may include pure hydrogen. In another example, fuel stream 138 may be supplied by a hydrogen stream generated by the blue hydrogen unit 120.

[0062] Once CO2 is captured, it can be compressed and transported to suitable geological storage sites. The compressed CO2 can be transported as a stream to be stored in one or more reservoirs, such as depleted oil and gas fields or deep saline aquifers.

[0063] In one example, the effluent stream 134 from the carbon capture system 124a may be a hydrogen-rich stream. In another example, the effluent stream 134 may include a hydrogen concentration of approximately 95 mol%, with the remainder being methane and carbon monoxide. In an example not shown, a portion of the effluent stream 134 may be used as fuel stream 138 to the hydrogen synthesis system 122, or to supplement that fuel stream. In an example not shown, a portion of the effluent stream 134 may be combined with at least a portion of the hydrogen-rich stream 142 and used as fuel for the cracking furnace 112 of the steam cracking unit 110. In a later example, the hydrogen-rich stream 142 may or may not be injected into the blue hydrogen unit 120.

[0064] In this example, the hydrogen produced in the SMR method as part of the hydrogen-rich effluent 134 may undergo purification. In this example, the hydrogen-rich effluent 134 from the carbon capture system 124a may be directed to one or more hydrogen recovery systems 126. In this example, the hydrogen recovery system 126 may include a purification system. In this example, the hydrogen recovery system 126 may include a pressure swing adsorption (PSA) system or method, membrane separation, or any combination thereof. In this example, the hydrogen recovery system 126 may include PSA as a purification system.

[0065] In an example, such as Figure 1 As shown, the hydrogen recovery system 126 may include a PSA system or method. The PSA system may include one or more towers with one or more adsorbents. In an example, the hydrogen-rich effluent 134 from the carbon capture system 124a may include some impurities and / or carbon contents. In an example, by passing the hydrogen-rich effluent 134 through the hydrogen recovery system 126, a high-purity hydrogen stream 136 with a hydrogen concentration >95 mol%, for example >98 mol%, for example about 98.5 mol% or greater, for example about >99 mol% or greater, for example about 99.5 mol% or greater, for example about 100 mol%.

[0066] In one example, a high-purity hydrogen stream 136 can be used to replace or supplement the fuel stream 138 of the hydrogen synthesis system 122. In another example, at least a portion of the high-purity hydrogen stream 136 (e.g., stream 150) can be used as fuel for the hydrogen synthesis system 122. In yet another example, at least a portion of the high-purity hydrogen stream 136 can be combined with a methane-rich stream 140 and used as fuel for the hydrogen synthesis system 122. In yet another example, a portion of the high-purity hydrogen stream 136 can be directed to the hydrogen synthesis system 122 as its sole fuel.

[0067] In an example, the hydrogen recovery system 126 (such as a PSA system) may include tail gas 144. In an example, tail gas 144 may include methane. In an example, tail gas 144 may be directed to a hydrogen synthesis system 122 for use as fuel. In an example, tail gas 144 may be combined with at least a portion of a high-purity hydrogen stream 136 and / or a methane-rich stream 140 for use as fuel for the hydrogen synthesis system 122.

[0068] In one example, the integration of the steam cracking unit 110 and the blue hydrogen unit 120 may include feeding methane-rich gas from the steam cracking unit 110 into the blue hydrogen unit 120. In another example, the integration of the steam cracking unit 110 and the blue hydrogen unit 120 may include feeding hydrogen from the blue hydrogen unit 120 into the steam cracking unit 110. In yet another example, the integration of the steam cracking unit 110 and the blue hydrogen unit 120 may include feeding a hydrogen-rich gas stream from the steam cracking unit 110 into the blue hydrogen unit 120. In yet another example, the integration of the steam cracking unit 110 and the blue hydrogen unit 120 may include a combination of two or more of these elements. In yet another example, the integration of the steam cracking unit 110 and the blue hydrogen unit 120 may include a combination of all of these elements.

[0069] In this example, the steam cracking unit 110 may include a recovery system 114. In this example, using the recovery system 114, a method may be included to separate a methane-rich gas stream 140 (stream 1) and a hydrogen-rich gas stream 142 (stream 2). In this example, the recovery system 114 may be configured to recover internally generated hydrogen from the effluent of the cracking furnace 112. In this example, the recovery of internally generated hydrogen into the hydrogen-rich gas stream 142 may be maximized. In this example, the recovery system 114 may produce a hydrogen-rich gas stream 142 that may include approximately 90 mol% to approximately 95 mol% hydrogen.

[0070] In one example, integration may include feeding at least a portion of the methane-rich gas stream 140 to the blue hydrogen unit 120. In another example, at least a portion of the methane-rich gas stream 140 may be directed to the hydrogen synthesis system 122. In another example, the methane-rich gas stream 140 or a portion thereof may be combined with natural gas feed 128 and fed into the hydrogen synthesis system 122 for hydrogen production. In another example, the methane-rich gas stream 140 or a portion thereof (e.g., 140a) may be fed separately from the natural gas feed 128 but in the same manner into the hydrogen synthesis system 122. In another example, the methane-rich gas stream 140 or a portion thereof may be the only feed other than to the hydrogen synthesis system 122 for hydrogen production, without requiring the natural gas feed 128. In another example, the methane-rich gas stream 140 or a portion thereof (e.g., 140b) may be used to replace or supplement the fuel stream 138 fed into the hydrogen synthesis system 122. In one example, a first portion 140a of the methane-rich gas stream 140 may be fed into the hydrogen synthesis system 122 to produce hydrogen together with the natural gas feed 128, and a second portion 140b of the methane-rich gas stream 140 may be directed into the hydrogen synthesis system 122 to be used as or supplemental to the fuel stream 138 for heating the hydrogen synthesis system 122. In another example, a larger portion of the methane-rich gas stream 140 may be fed into the hydrogen synthesis system 122 to produce hydrogen, and a smaller portion of the methane-rich gas stream 140 may be used as or supplemental to the fuel stream 138 for heating the hydrogen synthesis system 122.

[0071] In one example, the steam cracking unit 110 can be controlled such that at least a portion of the methane-rich gas stream 140 fed into the hydrogen synthesis system 122 as a hydrogen source to produce hydrogen can have a flow rate based on the amount of hydrogen produced by the blue hydrogen unit 120. In another example, the amount of methane-rich gas in the methane-rich gas stream 140 can be fed into the hydrogen synthesis system 122 for hydrogen production at a ratio of approximately 3.2 kg to approximately 4.0 kg of methane-rich gas per 1 kg of high-purity hydrogen stream 136 produced in the blue hydrogen unit 120.

[0072] In this example, one or more controllers may be used to control the flow rate of the methane-rich gas stream 140. In this example, the flow rate of the methane-rich gas stream 140 fed into the hydrogen synthesis system 122 for hydrogen production may be controlled via one or more valves. In this example, a portion of the methane-rich gas stream 140 may be diverted for use as fuel in the hydrogen synthesis system 122. In this example, the flow rate of the methane-rich gas stream 140 fed into the hydrogen synthesis system 122 for hydrogen production may be controlled by changing the amount of the methane-rich gas stream 140 diverted for use as fuel in the hydrogen synthesis system 122. In this example, changing the flow rate of the feed to the hydrogen synthesis system 122 controls the amount of the methane-rich gas stream 140 diverted for use as fuel in the hydrogen synthesis system 122. In this example, a portion of the methane-rich gas stream 140 (not shown) may be extracted and stored or otherwise disposed of. In this example, the flow rate of the methane-rich gas stream 140, to be fed into the hydrogen synthesis system 122 for hydrogen production and / or to be used as fuel for the hydrogen synthesis system 122, can be controlled by varying the amount drawn from it. Any combination of these controls, actuated by one or more controllers and valve systems, can be used to control the flow rate of the methane-rich gas stream 140 or a portion thereof fed into the hydrogen synthesis system 122 for hydrogen production, to be used as fuel for the hydrogen synthesis system 122, or both.

[0073] In this example, the overall fuel gas surplus of the steam cracking unit determines how the flow rate of the methane-rich gas stream 140 is controlled. In this example, the flow rate of the methane-rich gas stream 140 from the steam cracking unit 110 to the blue hydrogen unit 120 can be controlled based on the hydrogen demand of the blue hydrogen unit 120. For example, if the system detects an excess hydrogen source, the excess methane-rich gas stream 140 can be redirected for export. However, if the system detects an insufficient hydrogen supply, more or all of the methane-rich gas stream 140 can be redirected to the hydrogen synthesis system 122 for hydrogen production. In this example, if a hydrogen shortage is still detected after redirecting all of the methane-rich gas stream 140 to the hydrogen synthesis system 122 for hydrogen production, an external natural gas feed 128 can be increased.

[0074] In one example, a methane-rich gas stream 140, used as feed to the hydrogen synthesis system 122 to produce hydrogen, may be compressed. In another example, the integrated system 100 may include compressing the methane-rich gas stream 140 to a desired feed gas pressure for the blue hydrogen unit 120. In another example, the methane-rich gas stream 140, or a portion thereof, may be compressed to a pressure of approximately 20 barg to approximately 40 barg. In another example, the system 100 may include a compressor 180. In another example, the compressor 180 may include a gas compressor. In another example, the compressor 180 may be electrically powered. In another example, at least a portion of the methane-rich gas stream 140 may be compressed by the compressor 180 before reaching the blue hydrogen unit 120. In another example, at least a portion of the methane-rich gas stream 140 may be compressed by the compressor 180 before being fed into the hydrogen synthesis system 122 for hydrogen production in the blue hydrogen unit 120. In one example, the methane-rich gas stream 140, or a portion thereof, fed into the hydrogen synthesis system 122 along with or as natural gas feed 128, may be compressed by compressor 180 before being fed into the hydrogen synthesis system 122 for hydrogen production. In another example, a portion of the methane-rich gas stream 140 that may be directed to the hydrogen synthesis system 122 for use as fuel for heat generation may be uncompressed.

[0075] In this example, the hydrogen-rich gas stream 142 can be used as fuel for the cracking furnace 112. In this example, the hydrogen-rich gas stream 142 can be supplemented by at least a portion of the effluent stream 134 from the carbon capture system 124a. In this example, the hydrogen-rich gas stream 142 can be supplemented by at least a portion of the high-purity hydrogen gas stream 136.

[0076] However, using a hydrogen stream containing some methane as fuel in cracking furnace 112 can result in some carbon emissions in the flue gas of cracking furnace 112. In this example, to reduce and / or eliminate carbon emissions, it may be desirable to use a higher purity hydrogen stream as fuel in cracking furnace 112.

[0077] In one example, to obtain a higher purity hydrogen stream as fuel feed to the cracking furnace 112, the integration 100 may include exporting all or at least a portion of the hydrogen-rich gas stream 142 from the steam cracking unit 110 to the blue hydrogen unit 120. In another example, the integration 100 may include exporting all or at least a portion of the hydrogen-rich gas stream 142 from the recovery system 114 of the steam cracking unit 110 to the blue hydrogen unit 120.

[0078] In one example, all or at least a portion of the hydrogen-rich gas stream 142 from the recovery system 114 of the steam cracking unit 110 may be injected upstream of the hydrogen recovery system 126. In another example, the hydrogen-rich gas stream 142 may be injected immediately upstream of the hydrogen recovery system 126. In another example, if the hydrogen recovery system 126 includes a PSA, the hydrogen-rich gas stream 142 may be injected upstream of the PSA, for example, immediately upstream of the PSA of the blue hydrogen unit 120. In yet another example, before the PSA or other hydrogen recovery system 126, all or at least a portion of the hydrogen-rich gas stream 142 may be combined with the effluent stream 134 from the carbon capture system 124a of the blue hydrogen unit 120.

[0079] In one example, integration may include introducing high-purity hydrogen from the blue hydrogen unit 120 into the steam cracking unit 110. In one example, at least a portion of the high-purity hydrogen stream 136 generated by the blue hydrogen unit 120 may be used as fuel for the cracking furnace 112. In one example, at least a portion of the high-purity hydrogen stream 136 generated by the blue hydrogen unit 120 may be used as the sole fuel, combined with combustion air, to generate heat in the cracking furnace 112. In one example, at least a portion of the high-purity hydrogen stream 136 generated by the blue hydrogen unit 120 may be used as part of the fuel for the cracking furnace 112. In one example, a portion of the high-purity hydrogen stream 136 may be collected at 152. In one example, another portion of the high-purity hydrogen stream 136 may be directed to the cracking furnace 112 for use as fuel. In one example, a portion of the high-purity hydrogen stream 136 may be directed to the cracking furnace 112 as the sole fuel for the cracking furnace 112. In an example not shown, a portion of the high-purity hydrogen stream 136 may be combined with at least a portion of the hydrogen-rich stream 142 and fed into the cracking furnace 112.

[0080] In this example, the high-purity hydrogen introduced from the blue hydrogen unit 120 into the steam cracking unit 110 may be at least partially derived from the hydrogen-rich gas stream 142, the hydrogen produced by the methane-rich gas stream 140 in the hydrogen synthesis system 122, or a combination thereof.

[0081] In this example, before directing the high-purity hydrogen stream 136 to the cracking furnace 112 as fuel, it may be desirable to adjust the pressure of the stream based on the fuel gas back pressure of the cracking furnace 112. In this example, the pressure of the high-purity hydrogen stream 136 can be adjusted to a range of approximately 3 barg to approximately 8 barg. In this example, an expander 190 can be used to adjust the pressure of the high-purity hydrogen stream 136. In this example, the expander 190 may include a turboexpander. In this example, the expander 190 can be configured to recover energy, such as electrical energy, from the expansion of the high-purity hydrogen stream 136. In this example, the recovered energy can be used for any suitable application. In this example, the energy recovered from the expander 190 can be used at least partially to power the compressor 180. In this example, the expander 190 can be used to drive the compressor 180 in a directly coupled arrangement. In this example, the power for the compressor 180 can come from a source other than the expander 190.

[0082] In this example, the integration may optionally include preheating at least a portion of the high-purity hydrogen stream 136. In this example, at least a portion of the high-purity hydrogen stream 136 introduced into the steam cracking unit 110 for use as fuel in the cracking furnace may be preheated. In this example, system 100 may include heater 170. In this example, heater 170 may be an electric heater, a heat exchanger, a low-pressure steam heater, or any combination thereof. In this example, heater 170 may be upstream of expander 190. In this example, heater 170 may be configured to heat at least a portion of the high-purity hydrogen stream 136 before it enters expander 190. In this example, power recovery may be increased or maximized by heating the high-purity hydrogen stream 136 before depressurization in expander 190. In this example, a target preheating temperature for the high-purity hydrogen stream 136 may be set to achieve an expander outlet temperature close to ambient temperature. In one example, the high-purity hydrogen stream 136 introduced into the steam cracking unit 110, or at least a portion thereof, may be preheated to a temperature of approximately 120°C-150°C, for example, approximately 140°C.

[0083] In this example, the steam cracking unit 110 may receive feed 154 and combustion air stream 156. In this example, the steam cracking unit 110 may crack hydrocarbons to produce olefins. In this example, the product output stream 158 of the steam cracking unit 110 is directed to a recovery system 114. In this example, after separating a methane-rich stream 140 and a hydrogen-rich stream 142 from the product output stream 158, the recovery system 114 may output an olefin stream 160. In this example, the recovery system 114 may output one or more byproduct streams 162. In this example, by using a high-purity hydrogen stream 136 as fuel in the steam cracking unit 110, the exhaust stream 164 of the steam cracking unit 110 may include little to no CO.

[0084] In this example, one or more lines, pipes, and / or conduits may be used to fluidly connect the steam cracking unit 110 to the blue hydrogen unit 120. In this example, one or more valves (not shown) may be included to control the flow rate through one or more lines, pipes, and / or conduits. In this example, one or more pipes, lines, and / or conduits may be used to guide or transfer one or more streams, feeds, or effluents between the steam cracking unit 110 and the blue hydrogen unit 120.

[0085] In the example, the described integration 100 can be implemented together with the steam cracking unit 110, wherein the cracking furnace 112 may include gas feed or liquid feed. Figure 2 An exemplary pyrolysis furnace with gas feed is shown in the image.

[0086] In an example, the steam cracking unit 110 may include a cracking furnace 200 with a gas feed, such as, for example... Figure 2 As shown. In this example, the cracking furnace 200 may include a radiant section 202 and a convection section 204. A combustion air source 206 may be used together with fuel gas 208 as a combustion mixture for the radiant section 202 of the furnace. In this example, the combustion air may be preheated. In this example, the preheating of the combustion air may be achieved using a heater 210 that recovers heat from the flue gas in the convection section 204 of the cracking furnace 200. In this example, a hydrocarbon gas feed 212 may be fed into one or more reaction tubes 214 disposed in the radiant section 202 of the cracking furnace 200. In this example, the feed 212 may be preheated before being fed into one or more reaction tubes 214. In this example, the feed 212 may be preheated via a heater 216 that recovers heat from the convection section of the furnace, via a feed / effluent heat exchanger 218 that transfers heat from the effluent through the cracked gas to the feed 212, or a combination thereof. In this example, the cracking reaction may occur in one or more reaction tubes 214. In this example, the cracking reaction may produce a cracked gas effluent. In this example, the cracked gas effluent may contain methane, hydrogen, and one or more olefins. In this example, the cracked gas effluent may be cooled by one or more quenchers 220. In this example, the fuel gas 208 may include a hydrogen-rich gas stream or a high-purity hydrogen gas stream.

[0087] In an example, such as Figure 3 As shown, the steam cracking unit 110 may include a cracking furnace 300 with a liquid feed. For example... Figure 3As shown, the cracking furnace 300 of the steam cracking unit may include a liquid naphtha feed (LN feed) 302. In one example, as shown, the liquid feed 302 may be preheated before entering one or more reaction tubes 304 in the radiant section 306 of the cracking furnace 300. In one example, one or more heaters 308 may be used to preheat the feed for vaporization before injection into one or more reaction tubes 304. In one example, one or more heaters 308 may be configured to recover heat from the flue gas from the convection section 316 of the cracking furnace. In one example, fuel gas 310 and combustion air 312 may be fed into the radiant section 306 of the cracking furnace 300 for combustion and heat generation. One or more quenchers 314 may be used to quench the effluent from the furnace 300 via the cracked gas.

[0088] In one example, the steam cracking unit 110 may include a recovery system 114 and a method in which the effluent cracked gas can be treated to further separate methane, olefins, and hydrogen. In another example, the method may produce a hydrogen-rich gas stream, an olefin stream, and a methane-rich gas stream.

[0089] In an example, a pyrolysis furnace design may include one or more burners capable of burning 100% pure hydrogen.

[0090] In this example, the cracking furnace can use high-purity hydrogen as fuel gas to achieve net-zero CO2 emissions from the furnace. In this example, high-purity hydrogen may be the only fuel gas besides combustion air. In this example, the combustion air contains no or substantially no hydrocarbons (i.e., no more than trace amounts or 1 mol% or less).

[0091] In this example, pyrolysis furnace design can utilize one or more features to provide the most energy-efficient capital and energy solutions to achieve the lowest overall carbon emissions.

[0092] In this example, the combustion air can be preheated to minimize the required furnace combustion load and associated inlet hydrogen. In this example, the feed to the cracking furnace can be preheated. In this example, both the combustion air and the feed can be preheated. In this example, the combustion air can be preheated by recovering heat from the convection section of the cracking furnace using a heat exchanger, one or more electric heaters, or any combination thereof. In this example, the hydrocarbon feed to the cracking furnace can be preheated via one or more heat exchangers, using cracking furnace effluent, by recovering heat from the convection section of the cracking furnace, or by one or more electric heaters, or any combination thereof. In this example, the liquid naphtha feed can be heated to produce a gaseous feed before entering one or more reactor tubes of the cracking furnace.

[0093] In one example, the combustion air may be preheated to a temperature of approximately 400°C to approximately 450°C or approximately 650°C to approximately 750°C. In another example, the hydrocarbon feed stream to the cracking furnace may be preheated to approximately 620°C to approximately 640°C before being introduced into one or more reactor tubes of the cracking furnace.

[0094] In examples, the cracking furnace may be configured to employ a combustion air preheating design, such as that disclosed in co-pending U.S. Application No. 17 / 880,973, filed August 4, 2022, entitled “Low CO2emission Ethane Cracker,” which is incorporated herein by reference in its entirety. In examples, the cracking furnace may be configured to preheat the combustion air, as described in co-pending U.S. Application No. 63 / 516,104, filed July 27, 2023, entitled “Net Zero Ethane Cracker with no External Hydrogen Import,” which is incorporated herein by reference in its entirety. In examples, the cracking furnace may be configured to preheat the hydrocarbon feed and / or combustion air, as described, for example, in co-pending U.S. Application No. 63 / 516,066, filed July 27, 2023, entitled “100% Hydrogen-Fired Liquid Cracking Furnace,” which is incorporated herein by reference in its entirety.

[0095] like Figure 1 As shown, and discussed, for example, in co-pending U.S. Application No. 17 / 880,973, the steam cracking unit may include a recovery system 114 to recover methane-rich gas streams, hydrogen-rich gas streams, and olefin streams.

[0096] Figure 4 An example of recycling system 114 is shown. Figure 4 This is just an example, and other recycling system designs may also be used.

[0097] Figure 4An example of a recovery system 114 is shown. In this example, recovery system 114 can be configured as system 400. In this example, system 400 can be implemented for an ethane cracking process. The cracked gas process stream from the cracking furnace may include hydrogen, methane, and ethylene. In this example, the cracked gas process stream may enter the illustrated process at a temperature of, for example, about –73°C. The temperatures and pressures in this description of system 400 are only illustrating a specific embodiment of the method. In this example, the temperature / pressure may vary. The cracked gas process stream may be cooled in a cold box 408. In this example, cold box 408 may include other hot and cold piping not shown herein.

[0098] In this example, the light fraction from the cracked gas process stream of cracking furnace 112 can be gradually cooled and passed through separators 402 and 404 to separate ethylene. In this example, the light fraction from the cracked gas process stream of cracking furnace 112 may include hydrogen, methane, carbon monoxide, ethylene, ethane, or any combination thereof. The cooling temperature can be configured to manage the near-temperature within the cold box. According to some embodiments, the temperature of the first separator 402 may be approximately -115°C ± 10°C, and the temperature of the second separator may be approximately -130°C to approximately -145°C. The ethylene-rich bottom streams from separators 402 and 404 can be combined to an ethylene-rich stream 406. The ethylene-rich stream 406 can be recompressed using a turboexpander / compressor 410 to provide an ethylene-rich ethylene recovery fraction 412.

[0099] In this example, the top streams from the methane- and hydrogen-rich separators 402 and 404 can be further cooled in a cold box and supplied to the third separator 414. In this example, the temperature of the third separator 414 can be approximately -163°C ± 10°C. The top stream 416 from the third separator 414 is rich in hydrogen. The bottom stream 418 from the third separator 414 is rich in methane. The temperature of the third separator 414 determines the amount of methane separated, i.e., it determines the purity of the hydrogen stream.

[0100] In this example, the methane-rich bottom stream 418 can be reheated in a cold box and then exit the system as a methane-rich stream 420.

[0101] The hydrogen-rich topstream 416 can be reheated in a cold box to provide a reheated hydrogen-rich stream 422. In an example, the temperature of the reheated hydrogen-rich stream 422 can be about -140°C and its pressure can be about 20 barg to about 45 barg.

[0102] In one example, when the hydrogen-rich stream ultimately output from recovery system 114 or 400 is to be used as fuel for the cracking furnace of a steam cracking unit from which hydrocarbons are recovered, a turboexpander / compressor 410 can be used to expand the hydrogen-rich stream 422 to produce an expanded hydrogen-rich stream 424. In one example, expansion can result in a decrease in the temperature and pressure of the expanded hydrogen-rich stream 424. For example, after expansion, the temperature of the hydrogen-rich stream 424 can be approximately -177°C, and the pressure can be less than approximately 10 barg, for example, approximately 6 barg. In one example, the expanded hydrogen-rich stream 424 can be reintroduced into cold box 408, thereby providing a cold flow within the cold box that provides a sufficient temperature pathway to achieve the separation of methane and hydrogen in separator 414. The expanded hydrogen-rich stream 424 can ultimately exit the cold box as a hydrogen-rich stream 426.

[0103] In this example, the hydrogen-rich top stream 416 from tank 414 can be kept under pressure, provided that the hydrogen-rich gas stream ultimately output from recovery system 114 or 400 is directed to blue hydrogen unit 120 for further purification. In this example, the hydrogen-rich top stream 416 can simply be reheated and sent to blue hydrogen unit 120 to be combined with effluent stream 134 before hydrogen recovery system 126. In this example, expansion of the hydrogen-rich top stream 416 is not performed. To still provide a sufficiently cold stream to provide the required cooling in the coldest section of the cold box to achieve the target conditions in tank 414, in this example, a portion (e.g., about 10%-15%) of the hydrogen-rich top stream 416 can be stripped and mixed with methane-rich bottom stream 418 before being directed to blue hydrogen unit 120, and then reheated in the cold box. In this way, the vaporization temperature of the methane-rich bottom stream 418 is reduced, and thus it is able to provide the desired near-temperature.

[0104] In this example, the hydrogen-rich gas stream 426 may include greater than 90 mol% or greater than 95 mol% hydrogen, with the majority of the remainder consisting of methane. In this example, system 400 can recover more than 90% or more than 95% of the usable hydrogen in the cracked gas process stream.

[0105] In this example, the methane-rich gas stream and hydrogen-rich gas stream exiting the recovery system 114 of the steam cracking unit 110 are methane-rich gas stream 140 and hydrogen-rich gas stream 142 that can be guided to the blue hydrogen unit 120 of the integrated system 100.

[0106] In the examples, the described methods and systems may include one or more of the following: selectively using an electric drive for the main compressor in the recovery section to achieve a neutral or net outflow balance between the combined steam cracking unit 110 and the blue hydrogen unit 120; and using green-input electricity that does not have associated CO2 emissions.

[0107] In the examples described herein (including integrated systems and methods), one or more control systems, sensors, and other standard components may be included to implement control and operation of the system.

[0108] In the examples, although not shown, the systems described herein may include one or more sensors commonly used in the art. In the examples, the sensors may be used to monitor the operation of the described system. Non-limiting examples of one or more sensors may include temperature sensors, pressure sensors, flow meters, and other similar sensors.

[0109] In the examples (but not shown), one or more control systems may include one or more controllers, and / or other suitable computing devices that can be used to control one or more parts of the system described herein. A controller may include one or more processors and memory communicatively coupled to each other. In the illustrated examples, the memory may be used to store logical instructions for operating and / or controlling and / or monitoring the operation of one or more components of the described system. In the examples, the controller may include or be coupled to input / output devices such as a monitor, keyboard, speaker, microphone, computer mouse, etc. In the examples, one or more controllers may also include one or more communication components, such as transceivers or similar structures, to enable wired and / or wireless communication. In the examples, this enables remote operation of one or more systems described herein.

[0110] In examples, the memory associated with one or more controllers and / or other suitable computing devices may be a non-volatile computer-readable medium. The memory may store an operating system and one or more software applications, instructions, programs, and / or data to implement the methods described herein and the functions attributed to the various systems. In various implementations, the memory may be implemented using any suitable memory technology, such as static random access memory (SRAM), synchronous dynamic RAM (SDRAM), non-volatile / flash memory, or any other type of memory capable of storing information. The control system may include any number of logical components, program components, and physical components.

[0111] Logical instructions may include one or more software modules and / or other information sufficient to enable autonomous operation, secure procedures, and routine maintenance processes. Any operation of the described system may be implemented in hardware, software, or a combination thereof. In the context of software, an operation represents computer-executable instructions stored on one or more computer-readable storage media that, when executed by one or more processors, perform the referenced operation. Generally, computer-executable instructions include routines, programs, objects, components, data structures, etc., that perform one or more functions or implement specific abstract data types.

[0112] In this example, the integration of the described steam cracking unit with the blue hydrogen unit can provide one or more benefits. In this example, integration can reduce and / or minimize the combined unit's capital costs through shared equipment (e.g., a shared PSA for the blue hydrogen unit). In this example, integration can reduce and / or minimize the combined unit's capital costs by increasing and / or maximizing the utilization of internally generated hydrogen and / or increasing and / or maximizing air preheating on the furnace. This can reduce and / or minimize the net hydrogen required for the blue hydrogen unit. In this example, integration can reduce and / or minimize the net hydrogen required to reduce CO2 generated in the blue hydrogen unit that would otherwise have to be captured and / or stored. In this example, efficient integration of the feed and product streams can reduce the combined unit's energy consumption.

[0113] Examples of integration with ethane steam cracking units

[0114] This can be achieved by using SCORE with the assumption of KBR. ® The basic examples of the SC-1 short residence time furnace technology are compared to highlight the features and benefits of the described method and system, which employs a single-pass radiant coil design where the feed enters at the bottom and exits from the top of the furnace radiant section via pyrolysis gas. It should be noted that SC-1 was chosen for illustrative purposes only. The described integration can also be applied using other coil types and is not limited to SC-1.

[0115] To demonstrate the potential benefits of integration, for cases using high-purity hydrogen, including combustion air preheated to 425°C, this reduces the combustion load by approximately 25% compared to the baseline case. In this exemplary system, the cracking furnace convection section, feed preheating, and effluent cooling, as discussed in co-pending U.S. Application No. 17 / 880,973, are reconfigured relative to the relative loads of feed preheating and steam generation. In particular, the relative loads of feed preheating and steam generation vary due to the change in the calorific value of pure hydrogen, which produces less flue gas and thus provides less load available for feed preheating and steam generation compared to the case described in the co-pending application.

[0116] The following table shows an exemplary calculation for an ethane cracking unit, comparing a conventional ethane cracking unit (basic) with a net-zero design featuring integrated blue hydrogen units.

[0117]

[0118] The following table shows the results when the electricity is imported based on grey electricity (based on fossil fuels) or green electricity (without associated CO2 emissions).

[0119]

[0120] The application of maximum air preheating enables a significant reduction in the required furnace combustion load and associated net hydrogen input. Through integration between the steam cracking unit and the Blue Hydrogen unit, nearly 100% of the hydrogen produced in the cracking furnace can be used as fuel for the furnace, while hydrogen produced from methane-rich gas accounts for only about 14% of the cracking furnace load requirement. This integration allows for net-zero total emissions (assuming green electricity is available) using a relatively small Blue Hydrogen unit.

[0121] Examples of integration with liquid feed pyrolysis units

[0122] In the example below, the basic case uses tail gas (methane-rich) fuel gas and a conventional arrangement in which feed vaporization, dilution steam (DS) superheating, and mixed feed superheating occur in the convection section. The basic case example assumes the use of KBR's SCORE® SC-1 short residence time furnace technology, which employs a single-pass radiant coil design, where the feed enters at the bottom and exits from the top of the furnace radiant section via cracked gas.

[0123] To demonstrate the potential benefits of the invention, Case 1 uses pure hydrogen as fuel gas and also includes combustion air preheated to 450°C.

[0124] This example is based on cracked light naphtha, with a total unit capacity of 1000 KTA (ethane and propane are recycled to depletion).

[0125]

[0126]

[0127]

[0128] *Adjusted to exclude the offset of available internal H2.

[0129] Electricity import (export) for neutral steam balancing

[0130]

[0131] *Electrify the parts that require the main compressor.

[0132]

[0133] The use of preheated combustion air reduced the combustion load of the pyrolysis furnace by approximately 25%, which significantly reduced the need for external hydrogen import. This also significantly reduced steam generation on the pyrolysis furnace, so it is assumed that any steam imbalance will be offset by switching one of the compressors in the main compressors of the recovery system to electric drive.

[0134] Liquid-phase cracking may not produce a large amount of hydrogen, and some hydrogen may be needed for gasoline hydrotreating, which has been taken into account when determining the net hydrogen available from the steam cracking unit. In this case, 87% of the hydrogen used as fuel is produced in the hydrogen unit, with only 13% originating from steam cracking. Assuming a green power supply, it is possible to achieve near-zero emissions from the liquid-phase cracking unit. Overall, there is a small variation in the fuel gas balance—Case 1 has a slightly excess of methane-rich tail gas compared to the base case.

[0135] It will be apparent to those skilled in the art that various modifications and variations can be made to the invention without departing from its spirit or scope. Therefore, this invention is intended to cover any modifications and variations that fall within the scope of the appended claims and their equivalents. Claims (as amended under Article 19 of the Treaty) 1. A system comprising: Steam cracking unit; A blue hydrogen unit, comprising a hydrogen recovery system configured to generate a high-purity hydrogen stream; A first conduit, configured to direct at least a portion of the high-purity hydrogen gas stream to the steam cracking unit for use as fuel; and A second conduit is configured to direct at least a portion of the methane-rich gas stream from the steam cracking unit to the blue hydrogen unit. 2. The system of claim 1, wherein the steam cracking unit comprises a cracking furnace and a recovery system configured to recover the methane-rich gas stream from the effluent of the cracking furnace of the steam cracking unit, and further comprises a second conduit configured to direct at least a portion of the methane-rich gas stream to the blue hydrogen unit for use as feed, fuel, or both. 3. The system of claim 2, further comprising a compressor configured to compress at least a portion of the methane-rich gas stream before it reaches the blue hydrogen unit. 4. The system according to claim 1, further comprising: A recovery system, as part of the steam cracking unit, is configured to receive the effluent from the cracking furnace and separate at least a hydrogen-rich gas stream and a methane-rich gas stream from the effluent; and A third conduit is configured to deliver at least a portion of the hydrogen-rich gas stream from the recovery system to the hydrogen recovery system of the blue hydrogen unit. 5. The system of claim 1, further comprising a gas expander for expanding the high-purity hydrogen gas stream before it reaches the steam cracking unit. 6. The system of claim 5, further comprising a heater for preheating the high-purity hydrogen gas stream before it reaches the gas expander. 7. The system of claim 5, further comprising a compressor configured to compress at least a portion of the methane-rich gas stream before it reaches the blue hydrogen unit, wherein energy recovered by the gas expander is used to power the compressor. 8. A method comprising: A high-purity hydrogen stream is generated in the Blue Hydrogen unit, which includes a hydrogen recovery system; The high-purity hydrogen stream is fed into the steam cracking unit as fuel; and The methane-rich gas stream from the steam cracking unit is directed to the blue hydrogen unit. 9. The method of claim 8, further comprising: The methane-rich gas stream is recovered from the effluent of the steam cracking unit; and The methane-rich gas stream is directed to the blue hydrogen unit as feed, fuel, or both. 10. The method of claim 9, wherein the steam pyrolysis unit comprises a pyrolysis furnace, the method further comprising: The hydrogen-rich gas stream is recovered from the tail gas of the pyrolysis furnace in the steam pyrolysis unit; and At least a portion of the recovered hydrogen-rich gas stream is transferred to the hydrogen recovery system of the Blue Hydrogen Unit. 11. The method of claim 9, further comprising compressing the methane-rich gas stream before directing it to the blue hydrogen unit. 12. The method of claim 8, further comprising expanding the high-purity hydrogen stream to recover energy before feeding the high-purity hydrogen into the steam cracking unit. 13. The method of claim 11, further comprising preheating the high-purity hydrogen gas stream before expanding it. 14. The method of claim 11, further comprising using a compressor to compress the methane-rich gas stream before directing it to the blue hydrogen unit and powering the compressor with energy recovered from the expansion of the high-purity hydrogen gas stream. 15. The method of claim 8, wherein the steam cracking unit comprises a cracking furnace, and the method further comprises: The combustion air used as fuel is preheated in the pyrolysis furnace of the steam pyrolysis unit; and The feed to the pyrolysis furnace of the steam pyrolysis unit is preheated. 16. The method of claim 8, further comprising: The hydrogen recovery system recovers tail gas containing methane; and The exhaust gas is supplied to the blue hydrogen unit as fuel for the steam reformer. 17. The system of claim 4, wherein the hydrogen recovery system is configured to generate the high-purity hydrogen stream from the hydrogen-rich stream and from the hydrogen-rich effluent generated from the carbon capture system located within the blue hydrogen unit. 18. The system of claim 4, wherein the recovery system of the steam cracking unit comprises a cold box for cooling the effluent from the cracking furnace and one or more separatory tanks for separating the cooled effluent to at least generate the hydrogen-rich gas stream and the methane-rich gas stream. 19. The system of claim 18, wherein the one or more separators further separate ethylene from the effluent of the cracking furnace to produce an ethylene-rich stream. 20. The system of claim 19, wherein the recovery system of the steam cracking unit further comprises an expander and a compressor configured to expand the hydrogen-rich gas stream thereby compressing the ethylene-rich gas stream, and wherein the expansion of the hydrogen-rich gas stream produces a cooled hydrogen-rich gas stream, the cooled hydrogen-rich gas stream being supplied to the cold box to regulate the temperature of the cold box, thereby providing a temperature difference for achieving the separation of methane and hydrogen in the one or more separatory tanks.

Claims

1. A system comprising: Steam cracking unit; A blue hydrogen unit, comprising a hydrogen recovery system configured to generate a high-purity hydrogen stream; A first conduit, configured to direct at least a portion of the high-purity hydrogen gas flow to the steam cracking unit for use as fuel; as well as A second conduit is configured to direct at least a portion of the methane-rich gas stream from the steam cracking unit to the blue hydrogen unit.

2. The system of claim 1, wherein the steam pyrolysis unit comprises a pyrolysis furnace and a recovery stage, the recovery stage being configured as follows: The methane-rich gas stream is recovered from the effluent gas from the cracking furnace of the steam cracking unit, and further includes a second conduit configured to direct at least a portion of the methane-rich gas stream to the blue hydrogen unit for use as feed, fuel, or both.

3. The system of claim 2, further comprising a compressor configured to compress at least a portion of the methane-rich gas stream before it reaches the blue hydrogen unit.

4. The system according to claim 1, further comprising: A recovery stage, which is part of the steam cracking unit, is configured to receive the effluent from the cracking furnace and separate at least a hydrogen-rich gas stream and a methane-rich gas stream from the effluent; as well as A third conduit is configured to deliver at least a portion of the hydrogen-rich gas stream from the recovery stage to the hydrogen recovery system of the blue hydrogen unit.

5. The system of claim 1, further comprising a gas expander for expanding the high-purity hydrogen gas stream before it reaches the steam cracking unit.

6. The system of claim 5, further comprising a heater for preheating the high-purity hydrogen gas stream before it reaches the gas expander.

7. The system of claim 5, further comprising a compressor configured to compress at least a portion of the methane-rich gas stream before it reaches the blue hydrogen unit, wherein energy recovered by the gas expander is used to power the compressor.

8. A method comprising: A high-purity hydrogen stream is generated in the Blue Hydrogen unit, which includes a hydrogen recovery system; The high-purity hydrogen gas stream is fed into the steam cracking unit as fuel; as well as The methane-rich gas stream from the steam cracking unit is directed to the blue hydrogen unit.

9. The method of claim 8, further comprising: The methane-rich gas stream is recovered from the effluent of the steam cracking unit; as well as The methane-rich gas stream is directed to the blue hydrogen unit as feed, fuel, or both.

10. The method of claim 9, wherein the steam pyrolysis unit comprises a pyrolysis furnace, the method further comprising: The hydrogen-rich gas stream is recovered from the tail gas of the pyrolysis furnace in the steam pyrolysis unit; as well as At least a portion of the recovered hydrogen-rich gas stream is transferred to the hydrogen recovery system of the Blue Hydrogen Unit.

11. The method of claim 9, further comprising compressing the methane-rich gas stream before directing it to the blue hydrogen unit.

12. The method of claim 8, further comprising expanding the high-purity hydrogen gas stream before feeding the high-purity hydrogen-rich gas into the steam cracking unit.

13. The method of claim 11, further comprising preheating the high-purity hydrogen gas stream before expanding it.

14. The method of claim 11, further comprising recovering energy during the expansion of the high-purity hydrogen gas stream.

15. The method of claim 14, further comprising using a compressor to compress the methane-rich gas stream before directing it to the blue hydrogen unit and powering the compressor with energy recovered from the expansion of the high-purity hydrogen gas stream.

16. The method of claim 8, wherein the steam cracking unit comprises a cracking furnace, and the method further comprises preheating the combustion air used as fuel in the cracking furnace of the steam cracking unit.

17. The method of claim 8, wherein the steam cracking unit comprises a cracking furnace, and the method further comprises preheating the feed to the cracking furnace of the steam cracking unit.

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