Integration of hydrogen-rich fuel gas production with olefins production facilities

Abstract

H2-rich fuel gas production facilities comprising a syngas production plant can be advantageously integrated with an olefins production facility comprising a steam cracker in at least one of the following: (i) fuel gas supply and consumption; (ii) feed supply and consumption; and (iii) steam supply and consumption, resulting in substantial savings in capital and operating costs, enhanced energy efficiency and reduced CO2 emissions compared to running the facilities separately.

Description

[0001] Cross-references to related applications

[0002] This application claims priority and benefit to U.S. Application No. 17 / 484,042, filed on September 24, 2021, the disclosure of which is incorporated herein by reference in its entirety. Invention Field

[0003] This disclosure relates to methods and systems for producing H2-rich fuel gas from hydrocarbons such as natural gas, and methods and systems for producing olefins. Background of the Invention

[0005] Many industrial processes require very high temperatures. Many of these processes achieve the required high temperatures by burning hydrocarbon fuel gases. The most commonly used fuel gas is natural gas, which primarily contains methane. In the combustion of methane, approximately 5.8 tons of CO2 are produced for every 100 MBtu of heat released (on a low calorific value (“LHV”) basis).

[0006] One such large-scale manufacturing process is the production of light olefins (e.g., ethylene, propylene, etc.). The primary method for producing light olefins is through steam cracking, where the hydrocarbon feedstock is heated to very high temperatures in the presence of steam. The high temperatures (>2100°F) required to provide a rapid heat input to the steam cracking furnace (also known as a pyrolysis reactor) are achieved through the combustion of fuel gas. In many olefin production facilities, fuel gas is generated internally as a byproduct of the cracking process and may consist primarily of methane (e.g., 70-90 mol%) with a moderate hydrogen content (e.g., 10-30 mol%). Modern worldwide olefin facilities can have up to 10 steam cracking furnaces, each capable of consuming up to 150 MW or 512 MBtu / hour of fuel (LHV basis), and each with a separate flue gas exhaust pipe. Therefore, modern olefin production facilities generate significant CO2 emissions over extended operating times.

[0007] Various technologies have been proposed to reduce net CO2 emissions from steam crackers and olefins facilities. An amine absorption and regeneration process has been proposed to capture CO2 from separate flue gas stacks. This process has been demonstrated on flue gas stacks in power generation facilities. Once captured from the flue gas stacks, CO2 can be compressed, liquefied, and isolated in suitable geological formations (i.e., carbon capture and sequestration, “CCS”). Applying this technology to olefins plants is extremely expensive, given the possibility of having 10 (or more) flue gas stacks from which CO2 must be captured, the low CO2 concentration in the flue gas, and the lack of available plot space near steam crackers in existing facilities. In particular, the large, internally isolated flue gas ducts, along with the auxiliary fans and isolation equipment required to transfer large volumes of flue gas from the furnace to the amine absorption unit location, significantly increase the cost of the equipment.

[0008] An alternative approach was proposed in which a high-hydrogen fuel gas stream is generated for combustion in a steam cracking furnace, thus facilitating the generation of the high temperatures required for the process, but significantly reducing CO2 emissions from the furnace.

[0009] Hydrogen production from natural gas is carried out on an industrial scale via steam reforming. A steam-methane reformer heats natural gas (or another suitable hydrocarbon) and, in the presence of a large volume of steam, passes it through tubes containing a suitable catalyst to produce a synthesis gas containing hydrogen, carbon monoxide, carbon dioxide, and unconverted methane. This process is typically carried out at pressures in the range of 300-400 psig. The process requires high temperatures, so various waste heat recovery heat exchangers are typically used in the reformer effluent stream. These waste heat recovery exchangers typically produce high-pressure steam (~600-650 psig), which is then superheated in the convection section of the reformer. Additionally, one or more "shift reactors" are typically used in the reformer effluent stream (at appropriate temperature conditions), where CO reacts with steam over a suitable catalyst to produce additional hydrogen and CO2. After the shift reactors (one or more), the reformer effluent is further cooled to condense the contained steam, leaving a stream primarily containing hydrogen and CO2, but also containing unconverted methane and CO. In most industrial facilities, a pressure swing adsorption (“PSA”) unit is then used to recover high-purity hydrogen (99+%) from the effluent stream. This also produces a so-called “PSA effluent” stream, consisting of CO2, CO, unconverted methane, and some hydrogen. In the past, the PSA effluent stream was typically used as part of the reformer’s fuel requirements.

[0010] While the steam-methane-reforming process for hydrogen production is well-established, several drawbacks remain for large-scale production of hydrogen-rich fuel gas for industrial applications. First, as described above, this method has high capital costs, requiring large reformers and multiple subsequent processing steps. Second, the combustion of the fuel gas to provide the high temperatures needed within the reformer itself is a significant source of CO2 emissions. Third, the PSA effluent stream must be properly disposed of. In the past, the PSA effluent stream was used as part of the reformer's fuel gas supply, but this also increased CO2 emissions from the reformer itself.

[0011] CO2 emissions from SMR can be reduced by installing an amine recovery system on the flue gas exiting the reformer stack. This approach further increases the system's capital and operating costs, particularly because the reformer stack gas is under low (ambient) pressure. This low operating pressure translates to a large gas volume, and therefore the amine contactor required to absorb CO2 becomes extremely large.

[0012] Therefore, there is a need for improved methods and systems for producing H2-rich fuel gas and for producing olefins. This disclosure addresses this need and other needs. Summary of the Invention

[0013] We have found that an H2-rich fuel gas production facility comprising a syngas production unit and an olefins production facility comprising a steam cracker can be integrated in at least one of the following regions: fuel gas supply and consumption, hydrocarbon feed supply and consumption, and steam supply and consumption, to achieve surprisingly high levels of capital and operating cost savings, significant improvements in energy efficiency, and marked reductions in CO2 emissions compared to operating the two facilities separately.

[0014] Therefore, a first aspect of this disclosure relates to a method comprising one or more of the following: (I) supplying a hydrocarbon feed and a steam feed to a syngas production unit containing a reforming reactor under syngas production conditions to generate a reformate stream exiting the reforming reactor, wherein the syngas production conditions include the presence of a reforming catalyst and the reformate stream contains H2, CO, and steam; (II) cooling the reformate stream using a waste heat recovery unit (“WHRU”) to generate a cooled reformate stream and a high-pressure steam (“HPS”) stream; (III) contacting the cooled reformate stream with a first shift catalyst in a first shift reactor under a first set of shift conditions to generate a first shift stream exiting the first shift reactor, wherein the first shift stream has a lower CO concentration and a higher CO2 concentration than the cooled reformate stream; (IV) cooling the first shift stream to obtain a cooled first shift stream; (V) In the second shift reactor, under the second set of shift conditions, the cooled first shift feed stream is contacted with the second shift catalyst to generate a second shift feed stream exiting the second shift reactor, wherein the second shift feed stream has a lower CO concentration and a higher CO2 concentration than the cooled first shift feed stream; (VI) The steam present in the second shift feed stream is reduced to generate a crude gas mixture feed stream containing CO2 and H2; (VII) At least a portion of the CO2 present in the crude gas mixture feed stream is recovered to generate a CO2 feed stream and an H2-rich feed stream, wherein the H2-rich feed stream contains H2 at a concentration of at least 80 mol% based on the total number of moles of molecules in the H2-rich feed stream; and (VIII) A portion of the H2-rich feed stream is supplied to an olefin production facility containing a steam cracker as at least a portion of the steam cracker fuel gas, and the steam cracker fuel gas is burned to provide heat energy to the steam cracker.

[0015] Brief description of the attached figures

[0016] Figure 1 The illustration includes the steam supply / consumption system of a conventional olefins production facility with one or more steam cracker furnaces.

[0017] Figure 2 The illustrative description includes a comparison of SMR with H2 production methods / facilities.

[0018] Figure 3 illustrative illustrations include Figure 2 The comparative method for H2 production facilities is to supply H2 fuel gas to olefin production facilities.

[0019] Figure 4 This illustrative description illustrates an exemplary method / facility for producing H2-rich fuel gas.

[0020] Figure 5This disclosure illustrates an inventive method / system that integrates a method / facility for producing H2-rich fuel gas with an olefin production facility.

[0021] Figure 6 The illustration shows the steam supply / consumption configuration of a comparative olefin production facility, which includes multiple steam crackers.

[0022] Figure 7 illustrative illustration from Figure 6 The present invention relates to the steam supply / consumption configuration of an olefin production facility that is modified and integrated with SMR steam.

[0023] Detailed Explanation

[0024] Various specific embodiments, variations, and examples of the invention will now be described, including preferred embodiments and definitions used for understanding the purposes of the claimed invention. While specific preferred embodiments are given in the detailed description below, those skilled in the art will appreciate that these embodiments are merely exemplary and that the invention may be practiced in other ways. For the purpose of determining infringement, the scope of the invention will refer to any one or more of the appended claims, including their equivalents and elements or limitations equivalent to those recited. Any reference to “invention” may refer to one or more of the invention as defined by the claims, but not necessarily all of them.

[0025] In this disclosure, a method is described as comprising at least one "step". It should be understood that each step is an action or operation that can be performed once or multiple times in the method, either continuously or discontinuously. Unless otherwise specified or the context clearly indicates otherwise, multiple steps in a method may be performed sequentially as they are listed, overlapping or not overlapping with one or more other steps, or in any other order, as applicable. Furthermore, with respect to the same or different batches of material, one or more or even all steps may be performed simultaneously. For example, in a continuous method, when the first step in the method can be performed with respect to the raw material just fed into the method at the start of the method, the second step can be performed simultaneously with respect to intermediate material produced by processing the raw material fed into the method earlier in the first step. Preferably, the steps are performed in the described order.

[0026] Unless otherwise stated, all numbers representing quantities in this disclosure should be understood to be modified by the term "about" in all cases. It should also be understood that precise numerical values ​​used in the specification and claims constitute specific embodiments. Efforts have been made to ensure the accuracy of data in the embodiments. However, it should be understood that any measured data inherently contains a certain level of error due to limitations in the techniques and / or equipment used to obtain the measurement results.

[0027] Certain embodiments and features are described herein using a set of numerical upper limits and a set of numerical lower limits. It is to be understood that, unless otherwise indicated, ranges that include any combination of any two values are covered, such as any combination of any lower value with any upper value, any combination of any two lower values, and / or any combination of any two upper values.

[0028] As used herein, the indefinite article "a" or "an" means "at least one / at least one kind of", unless otherwise specified or the context clearly indicates otherwise. Thus, unless otherwise specified or the context clearly indicates that only one reactor or conversion zone is used, embodiments using "a reactor" or "a conversion zone" include embodiments using one, two or more reactors or conversion zones.

[0029] The term "hydrocarbon" means (i) any compound composed of hydrogen and carbon atoms or (ii) any mixture of two or more such compounds as in (i). The term "Cn hydrocarbon", where n is a positive integer, means (i) any hydrocarbon compound that contains a total of n carbon atoms (one or more) in its molecule or (ii) any mixture of two or more such hydrocarbon compounds as in (i). Thus, C2 hydrocarbons can be ethane, ethylene, acetylene, or any mixture of at least two of these compounds in any proportion. "Cm to Cn hydrocarbons" or "Cm-Cn hydrocarbons", where m and n are positive integers and m < n, means any one of Cm, Cm+1, Cm+2, …, Cn-1, Cn hydrocarbons, or any mixture of two or more of them. Thus, "C2 to C3 hydrocarbons" or "C2-C3 hydrocarbons" can be any one of ethane, ethylene, acetylene, propane, propylene, propyne, allene, cyclopropane, and any mixture of two or more of them in any proportion between the components. "Saturated C2-C3 hydrocarbons" can be ethane, propane, cyclopropane, or any mixture of two or more of them in any proportion. "Cn+ hydrocarbons" means (i) any hydrocarbon compound that contains a total of at least n carbon atoms (one or more) in its molecule or (ii) any mixture of two or more such hydrocarbon compounds as in (i). "Cn- hydrocarbons" means (i) any hydrocarbon compound that contains a total of at most n carbon atoms in its molecule or (ii) any mixture of two or more such hydrocarbon compounds as in (i). "Cm hydrocarbon stream" means a hydrocarbon stream consisting essentially of Cm hydrocarbon(s). "Cm-Cn hydrocarbon stream" means a hydrocarbon stream consisting essentially of Cm-Cn hydrocarbon(s).

[0030] For the purposes of this disclosure, the nomenclature of the elements is according to the version of the periodic table described in Hawley's Condensed Chemical Dictionary, 16th Edition, John Wiley & Sons, Inc., (2016), Appendix V (in the new notation).

[0031] "consistent with" means that a given material or compound contains ≥60 mol%, preferably ≥75 mol%, preferably ≥80 mol%, preferably ≥90 mol%, preferably ≥95 mol%, preferably 98 mol% of a stream or mixture, based on the total number of moles of molecules in the stream or mixture.

[0032] "High-pressure steam" and "HPS" are used interchangeably, meaning steam with an absolute pressure of at least 4000 kPa. "Ultra-high-pressure steam" and "Super-HPS" are used interchangeably, meaning steam with an absolute pressure of at least 8370 kPa. Therefore, Super-HPS is HPS. "Medium-pressure steam" and "MPS" are used interchangeably, meaning steam with an absolute pressure of at least 800 kPa but less than 4000 kPa. "Low-pressure steam" and "LPS" are used interchangeably, meaning steam with an absolute pressure of at least 200 kPa but less than 800 kPa.

[0033] A "back-pressure turbine" is a turbine that receives steam feed but does not produce a steam stream with an absolute pressure below 100 kPa that is supplied to a surface condenser. Depending on the steam feed pressure and its configuration, a back-pressure turbine can produce one or more discharge streams, such as HPS streams, MPS streams, and LPS streams, or combinations thereof. In this disclosure, unless the context clearly indicates otherwise, a turbine is a steam turbine.

[0034] "Extraction steam turbine" means a steam turbine that receives a steam feed stream and produces at least two exhaust steam feed streams with different pressures. Depending on the steam feed pressure and its configuration, an extraction steam turbine can produce two or more steam feed streams, including one or more of the following: for example, HPS feed stream, MPS feed stream, and LPS feed stream, and a condensable feed stream with an absolute pressure of less than 100 kPa supplied to a surface condenser.

[0035] I. Methods and facilities for producing H2-rich fuel gas

[0036] One aspect of this disclosure relates to a method for producing H2-rich fuel gas, comprising the steps of: (I) supplying a hydrocarbon feed and a steam feed to a syngas production unit containing a reforming reactor under syngas production conditions to generate a reformate stream exiting the reforming reactor, wherein the syngas production conditions include the presence of a reforming catalyst and the reformate stream contains H2, CO, and steam; (II) cooling the reformate stream using a waste heat recovery unit (“WHRU”) to generate a cooled reformate stream and a high-pressure steam (“HPS”) stream; and (III) contacting the cooled reformate stream with a first shift catalyst in a first shift reactor under a first set of shift conditions to generate a first shift stream exiting the first shift reactor, wherein the first shift stream has a lower CO content than the cooled reformate stream. (IV) Cooling the first shift feed stream to obtain a cooled first shift feed stream; (V) Contacting the cooled first shift feed stream with a second shift catalyst in a second shift reactor under a second set of shift conditions to produce a second shift feed stream exiting the second shift reactor, wherein the second shift feed stream has a lower CO concentration and a higher CO2 concentration than the cooled first shift feed stream; (VI) Reducing the vapor present in the second shift feed stream to produce a crude gas mixture feed stream containing CO2 and H2; and (VII) Recovering at least a portion of the CO2 present in the crude gas mixture feed stream to produce a CO2 feed stream and an H2-rich feed stream, wherein the H2-rich feed stream contains H2 at a concentration of at least 80 mol% based on the total number of moles of molecules in the H2-rich feed stream. A system for producing such an H2-rich feed stream, preferably using the above methods, may be referred to herein as an H2-rich fuel gas production facility.

[0037] Step (I) of the method includes supplying a hydrocarbon feed and a steam feed to a syngas production unit containing a reforming reactor under syngas production conditions, thereby generating a reformate stream exiting the reforming reactor, wherein the syngas production conditions include the presence of a reforming catalyst, and the reformate stream contains H2, CO, and steam. The hydrocarbon feed may consist substantially of C1-C4 hydrocarbons (preferably saturated), preferably substantially of C1-C3 hydrocarbons (preferably saturated), preferably substantially of C1-C2 hydrocarbons (preferably saturated), and preferably substantially of CH4. The hydrocarbon feed and steam feed may be combined to form a combined stream before being fed into the syngas production unit. Alternatively, they may be fed into the syngas production unit as separate streams, wherein they are mixed with each other to form a mixture. The feed stream (one or more) may be preheated before being fed into the syngas production unit by, for example, a furnace, a heat exchanger, etc. The syngas production unit may include a pre-reformer that first receives the feed stream (one or more), especially if the hydrocarbon feed contains a large amount of C2+ hydrocarbons. In a pre-reforming unit, the hydrocarbon feed / steam feed mixture contacts a pre-reforming catalyst under conditions that preferentially convert C2+ hydrocarbons to CH4. Including a pre-reforming unit can reduce coking and fouling in downstream reforming reactors. The hydrocarbon feed can have temperatures ranging from, for example, 15°C, 20°C, 30°C, 40°C to 50°C, 60°C, 70°C, 80°C, 90°C to 95°C, 100°C, 110°C, 120°C, 130°C, 140°C, or even 150°C, and temperatures ranging from, for example, 1,300 kPa, 1,400 kPa, 1,500 kPa, 1,600 kPa, 1,700 kPa, 1,800 kPa, 1,900 kPa, 2,000 kPa to 2,100 kPa, 2,200 kPa, 2,300 kPa. Absolute pressures of 2,400 kPa, 2,500 kPa, 2,600 kPa, 2,700 kPa, 2,800 kPa, 2,900 kPa, 3,000 kPa to 3,000 kPa, 3,200 kPa, 3,400 kPa, 3,500 kPa, 3,600 kPa, 3,800 kPa, 4,000 kPa to 4,200 kPa, 4,400 kPa, 4,500 kPa, 4,600 kPa, 4,800 kPa, or even 5,000 kPa.The steam feed can have temperatures ranging from, for example, 250°C, 260°C, 270°C, 280°C, 290°C, 300°C to 310°C, 320°C, 330°C, 340°C, 350°C, 360°C, 370°C, 380°C, 390°C to 400°C, 410°C, 420°C, 430°C, 440°C, or even 450°C, and temperatures ranging from, for example, 1,300 kPa, 1,400 kPa, 1,500 kPa, 1,600 kPa, 1,700 kPa, 1,800 kPa, 1,900 kPa, 2,000 kPa to 2,100 kPa. Absolute pressures of 2,200 kPa, 2,300 kPa, 2,400 kPa, 2,500 kPa, 2,600 kPa, 2,700 kPa, 2,800 kPa, 2,900 kPa, 3,000 kPa to 3,000 kPa, 3,200 kPa, 3,400 kPa, 3,500 kPa, 3,600 kPa, 3,800 kPa, 4,000 kPa to 4,200 kPa, 4,400 kPa, 4,500 kPa, 4,600 kPa, 4,800 kPa, or even 5,000 kPa. Preferably, the steam feed is superheated steam.

[0038] The effluent from the pre-reformer can then be fed into a reforming reactor operating under syngas production conditions, where the following forward reaction is advantageous and desirable to occur in the presence of a reforming catalyst:

[0039]

[0040] Depending on the type of reformer and the syngas production conditions, syngas production conditions may include temperatures in the reformer, for example, from 750°C, 760°C, 780°C, 800°C, 850°C, 900°C to 950°C, 1,000°C, 1,050°C, 1,100°C to 1150°C, or even 1200°C, and absolute pressures, for example, from 700 kPa, 800 kPa, 900 kPa, 1,000 kPa to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa to 3,500 kPa, 4,000 kPa, 4,500 kPa, or even 5,000 kPa. Lower pressure in the reformate stream, and consequently lower pressure in the reformer, contributes to a higher CH4 conversion rate in the reformer, and thus a lower residual CH4 concentration in the reformate stream. The reformate stream exiting the reformer therefore contains CO, H2, residual CH4 and H2O, and optionally CO2, in various concentrations, depending among other things on the type of reformer and the syngas production conditions. Depending on the type of reformer and the syngas production conditions, the reformate stream can have temperatures, for example, from 750°C, 760°C, 780°C, 800°C, 850°C, 900°C to 950°C, 1,000°C, 1,050°C, 1,100°C to 1150°C, or even 1200°C, and absolute pressures, for example, from 700 kPa, 800 kPa, 900 kPa, 1,000 kPa to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa to 3,500 kPa, 4,000 kPa, 4,500 kPa, or even 5,000 kPa.

[0041] The preferred type of reforming reactor in a syngas production plant is the SMR (Self-Reforming Regulator). An SMR typically comprises one or more heated reforming tubes containing a reforming catalyst on their inner side. A hydrocarbon / steam feed stream enters the tubes, heated to a desired elevated temperature, and passes through the reforming catalyst to achieve the desired reforming reaction mentioned above. While SMRs can have many different designs, a preferred SMR comprises a furnace shell, a convection section (e.g., an upper convection section), a radiant section (e.g., a lower radiant section), and one or more burners located in the radiant section that burn fuel to produce hot flue gas and supply heat to heat both the radiant and convection sections. The hydrocarbon / steam feed stream enters the reforming tubes at a location in the convection section, flows downwards through the convection section, thereby preheating the rising hot flue gas produced by fuel combustion at the burners (or one or more), and then enters the radiant section adjacent to the burner flame, whereby it contacts the reforming catalyst loaded in the reforming tubes (or one or more) within the radiant section, thus producing a reformed feed stream exiting the SMR at a location in the radiant section. Syngas production conditions in the reformer (one or more) within the radiant section may include temperatures, for example, from 750°C, 760°C, 780°C, 800°C to 820°C, 840°C, 850°C to 860°C, 880°C, or even 900°C, and absolute pressures, for example, from 700 kPa, 800 kPa, 800 kPa, 900 kPa, 1,000 kPa to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa, or even 3,500 kPa. To achieve high CH4 conversion in the SMR and low CH4 concentration in the H2-rich feed stream produced by this method, syngas production conditions in the SMR preferably include absolute pressures of ≤2,169 kPa (300 psig), more preferably ≤1,825 kPa (250 psig). Descriptions of SMR can be found, for example, in The International Energy Agency Greenhouse Gas R&D Program (“IEAGHG”), “Techno-Economic Evaluation of SMR Based Standalone (Merchant) Plant with CCS”, February 2017; and IEAGHG, “Reference data and supporting literature Reviews for SMR based Hydrogen production with CCS”, 2017-TR3, March 2017, the contents of which are incorporated herein by reference.

[0042] Reformers in syngas production plants may include autothermal reformers (“ATRs”). An ATR typically receives a hydrocarbon / steam feed (one or more) and an O2 stream into a reaction vessel, where a portion of the hydrocarbons is combusted to generate heat, thereby heating the mixture to elevated temperatures and then contacting it with a bed of reforming catalysts to achieve the desired reforming reaction and produce a reformed feed stream exiting the vessel. ATRs can operate at higher temperatures and pressures than SMRs. Syngas production conditions in the ATR and the reformate stream leaving the ATR can have temperatures, for example, from 800°C, 850°C, 900°C to 950°C, 1,000°C, 1,050°C to 1,100°C, 1,150°C, or even 1,200°C, and absolute pressures, for example, from 800 kPa, 900 kPa, 1,000 kPa to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa to 3,500 kPa, 4,000 kPa, 4,500 kPa, or even 5,000 kPa. Commercially available ATRs are, for example, from Haldor Topsoe (address: Haldor Topsoe). Synor obtained from Al lé1, DK-2800, Kgs. Lyngby, Denmark (“Topsoe”) TM ATR can be used in the methods described in this disclosure.

[0043] The syngas production apparatus used in step (I) of the method of this disclosure may include only one or more SMRs, only one or more ATRs, or a combination of one or more of both.

[0044] The reformate stream exiting the reformer has high temperature and high pressure as described above. It is highly desirable to capture the heat energy contained therein. Therefore, in step (II), the reformate stream passes through a waste heat recovery unit (“WHRU”) to produce a cooled reformate stream and a high-pressure steam (“HPS”) stream. The cooled reformate stream may have temperatures ranging from, for example, 285°C, 290°C, 300°C to 310°C, 320°C, 330°C, 340°C, 350°C to 360°C, 370°C, 380°C, 390°C, or even 400°C. The cooled reformate stream may have substantially the same pressure as the reformate stream exiting the reformer. The WHRU may include, for example, one or more heat exchangers and one or more steam drums in fluid communication with the heat exchangers. The steam drums supply water to the heat exchangers, where it is heated, and the water / steam stream may then return to the steam drums, where the steam is separated from the liquid water. The HPS feed stream can have absolute pressures ranging from, for example, 4,000 kPa, 5,000 kPa, 6,000 kPa, 7,000 kPa, 8,000 kPa to 9,000 kPa, 10,000 kPa, 11,000 kPa, 12,000 kPa, 13,000 kPa, or even 14,000 kPa. The resulting HPS feed stream is a saturated steam feed stream. To make the HPS feed stream more useful, it can be further heated, for example, in a furnace to produce a superheated HPS (“SH-HPS”) feed stream. If the syngas production unit includes an SMR with a convection section as described above, the saturated HPS feed stream can advantageously be superheated in the convection section of the SMR and / or in an auxiliary furnace. If the syngas production unit includes one or more ATRs but no SMR, the saturated HPS feed stream can be superheated in an auxiliary furnace. The auxiliary furnace may include one or more burners to burn the fuel gas stream to supply the required thermal energy, as known to those skilled in the art. The SH-HPS flow may have one or two of the following: (i) a temperature from, for example, 350°C, 360°C, 370°C, 380°C, 390°C, 400°C to 410°C, 420°C, 430°C, 440°C, 450°C to 460°C, 470°C, 480°C, 490°C, 500°C to 510°C, 520°C, 530°C, 540°C or even 550°C; and (ii) an absolute pressure from, for example, 4,000 kPa, 5,000 kPa, 6,000 kPa, 7,000 kPa, 8,000 kPa to 9,000 kPa, 10,000 kPa, 11,000 kPa, 12,000 kPa, 13,000 kPa or even 14,000 kPa.

[0045] In step (III) of the method of this disclosure, the cooled reformate stream is contacted with a first shift catalyst in a first shift reactor under a first set of shift conditions to generate a first shift stream exiting the first shift reactor. The first set of shift conditions includes the presence of a first shift catalyst. Any suitable shift catalyst known to those skilled in the art can be used. A non-limiting example of a suitable shift catalyst for the first shift catalyst is a high-temperature shift catalyst available, for example, from Topsoe. The following forward reaction preferably occurs in the first shift reactor:

[0046]

[0047] Thus, the first shift reactor feed stream has a lower CO concentration and a higher CO2 concentration than the cooled reformate feed stream. The forward reaction of (R-2) is exothermic, resulting in the first shift reactor feed stream having a higher temperature than the cooled reformate feed stream entering the first shift reactor. The first shift reactor feed stream leaving the first shift reactor can have temperatures ranging from, for example, 335°C, 340°C, 350°C, 360°C to 370°C, 380°C, 400°C, 420°C to 440°C, 450°C, 460°C, 480°C, or even 500°C. The first shift reactor feed stream can have substantially the same absolute pressure as the cooled reformate feed stream.

[0048] While a single-stage shift reactor can convert sufficient CO in a cooled reformate stream to CO2, resulting in a low CO concentration in the first shift stream, it is preferable to include at least two shift reactors in the method of this disclosure to achieve a high level of CO to CO2 conversion and ultimately produce an H2-rich fuel stream with a low CO concentration. It is also preferred that a subsequent stage, such as a second shift reactor downstream of the first shift reactor, operates at a lower temperature than the first shift reactor, thereby further converting additional CO in the first shift stream to CO2 and producing additional H2. For this purpose, the first shift stream is preferably cooled in step (IV) to produce a cooled first shift stream. Such cooling can be achieved by using one or more cooling streams at temperatures lower than the first shift stream through one or more heat exchangers. In a preferred embodiment, the first shift stream can be cooled by a hydrocarbon feed stream or a branch stream thereof to be fed into the syngas production unit. Alternatively or additionally, the first shift stream can be cooled by a boiler water feed stream to produce a heated boiler water stream, steam stream, and / or water / steam mixture stream. The boiler water stream thus heated can be heated in a boiler to generate steam at various pressures. The thus heated boiler water stream, steam, and / or water / steam mixture stream can be further heated by another process stream in a separate heat exchanger to generate steam. In a preferred embodiment, the heated boiler water stream and / or steam stream can be fed into the steam drum of the WHRU to extract heat from the reforming stream as described above, wherein boiler feedwater can be sent to the WHRU exchanger for further heating, and any steam separated in the steam drum can be further superheated. The cooled first shift converter stream can have a temperature from, for example, 150°C, 160°C, 170°C, 180°C, 190°C, 200°C to 210°C, 220°C, 230°C, 240°C, or even 250°C and a pressure substantially the same as the first shift converter stream.

[0049] The cooled first shift feed stream is then subjected to cryogenic shifting in a second shift reactor under a second set of shifting conditions to produce a second shift feed stream. The second set of shifting conditions includes the presence of a second shift catalyst, which may be the same as or different from the first shift catalyst. Any suitable shift catalyst known to those skilled in the art can be used. A non-limiting example of a suitable catalyst for the second shift catalyst is a cryogenic shift catalyst available, for example, from Topsoe. The following forward reaction preferentially occurs in the second shift reactor:

[0050]

[0051] Thus, the second shift reactor feed stream has a lower CO concentration and a higher CO2 concentration than the cooled first shift reactor feed stream. The forward reaction of (R-3) is exothermic, resulting in the second shift reactor feed stream having a higher temperature than the cooled first shift reactor feed stream entering the second shift reactor. The second shift reactor feed stream leaving the second shift reactor can have temperatures ranging from, for example, 150°C, 160°C, 170°C, 180°C, 190°C, 200°C to 210°C, 220°C, 230°C, 240°C, 250°C to 260°C, 270°C, 280°C, 290°C, or even 300°C. The second shift reactor feed stream can have substantially the same absolute pressure as the cooled first shift reactor feed stream.

[0052] The second shift feed stream contains H2, CO2, CO, steam, and optionally CH4. In step (VI), the steam is then reduced by cooling and separation. Similar to step (IV) of cooling the first shift feed stream, the cooling of such a second shift feed stream can be achieved by using one or more cooling feed streams at temperatures lower than the second shift feed stream through one or more heat exchangers. In a preferred embodiment, the second shift feed stream can be cooled by the hydrocarbon feed stream to be fed into the syngas production unit or by a branch of it. Alternatively or additionally, the second shift feed stream can be cooled by the boiler water feed stream to produce a heated boiler water stream, steam stream, and / or water / steam mixture stream. The heated boiler water stream can be heated in a boiler to produce steam at various pressures. The heated boiler water stream, steam, and / or water / steam mixture stream can be further heated by another process feed stream in another heat exchanger to produce steam. In a preferred embodiment, a heated boiler water feed stream and / or steam feed stream may be fed into the steam drum of the WHRU to extract heat from the reformate stream as described above, wherein boiler feedwater may be sent to the WHRU exchanger for further heating, and any steam separated in the steam drum may be further superheated. Alternatively or additionally, a cooling water exchanger or an air finned heat exchanger may be used to at least partially cool the second shift synthesis gas feed stream. The cooled second shift feed stream may preferably contain condensate, which may be separated to produce a crude gas mixture feed stream containing a significantly lower concentration of steam than the second shift feed stream exiting the second shift reactor.

[0053] The crude gas mixture stream is therefore essentially composed of varying amounts of CO2, H2, optional CH4, and vapor and CO (as a minor component). The crude gas mixture stream may have absolute pressures ranging from, for example, 700 kPa, 800 kPa, 800 kPa, 900 kPa, 1,000 kPa to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa to 3,500 kPa, 4,000 kPa, 4,500 kPa, or even 5,000 kPa. In step (VII), a portion of the CO2 can be recovered to produce a CO2 stream and an H2-rich stream. Any suitable CO2 recovery process known to those skilled in the art can be used in step (VII), including but not limited to: (i) amine absorption and regeneration processes; (ii) cryogenic CO2 separation processes; (iii) membrane separation processes; (iv) physical absorption and regeneration processes; and (iv) any combination of any of (i), (ii), and (iii) above. In a preferred embodiment, an amine absorption and regeneration process can be used. Due to the increased pressure of the crude gas mixture stream, the size of the CO2 recovery equipment can be much smaller than that required to recover CO2 from the gas mixture at atmospheric pressure.

[0054] The CO2 stream preferably contains CO2 with a molar concentration from, for example, 90%, 91%, 92%, 93%, 94% to 95%, 96%, 97%, 98% or even 99%, based on the total number of moles of molecules in the CO2 stream. The CO2 stream may contain at least one and preferably all of the following, on a molar basis: (i) for example, from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9% to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.5% or even 5.0% CO; (ii) for example, from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7% CO. (iii) H2O, for example, from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9% to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.5% or even 6.0%; and CH4, for example, from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9% to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.5% or even 5.0%. The CO2 stream can have an absolute pressure ranging from, for example, 700 kPa, 800 kPa, 800 kPa, 900 kPa, 1,000 kPa to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa to 3,500 kPa, 4,000 kPa, 4,500 kPa, or even 5,000 kPa. The CO2 stream can be compressed, liquefied, diverted, stored, isolated, or used in any suitable application known to those skilled in the art. In one embodiment, the CO2 stream, optionally compressed, can be diverted in a CO2 pipeline. In another embodiment, the CO2 stream, optionally compressed and / or liquefied, can be injected and stored in a geological formation. In yet another embodiment, the CO2 stream, optionally compressed and / or liquefied, can be used to extract hydrocarbons present in a geological formation. Another exemplary use of the CO2 stream is in food applications.

[0055] The H2-rich stream may have an absolute pressure ranging from, for example, 700 kPa, 800 kPa, 800 kPa, 900 kPa, 1,000 kPa to 1,500 kPa, 2,000 kPa, 2,500 kPa, 3,000 kPa to 3,500 kPa, 4,000 kPa, 4,500 kPa, or even 5,000 kPa. The H2-rich stream preferably contains H2 with a molar concentration ranging from, for example, 80%, 81%, 82%, 83%, 84%, 85% to 86%, 87%, 88%, 89%, 90% to 91%, 92%, 93%, 94%, 95% to 96%, 97%, or even 98%, based on the total number of moles of molecules in the H2-rich stream. The H2-rich feed stream may contain at least one and preferably all of the following, on a molar basis: (i) for example, from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9% to 1.0%, 1.5%, 2.0%, 2.5% or even 3.0% CO; (ii) for example, from 0.1%, 0.2%, 0.3%, 0.4% CO. (iii) CO2, for example, from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.7%, 0.8%, 0.9%, or even 1.0%; and CH4, for example, from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9% to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.5%, or even 5.0%. A specific example of an H2-rich feedstream that can be produced by the methods of this disclosure has the following molar composition: 0.25% CO2, 1.75% CO, 93.87% H2, 0.23% N2, 3.63% CH4, and 0.29% H2O.

[0056] When an even higher purity H2 stream is required, a portion of the H2-rich stream can be further purified using methods and techniques known to those skilled in the art, such as pressure swing separation.

[0057] However, preferably, the H2-rich feed stream (although optionally containing low concentrations of CO, CO2, and CH4) is used as a fuel gas stream without further purification for heating in step (VIII) of the method, preferably in industrial applications, such as residential, office, and / or industrial applications. Because the total concentrations of CO, CO2, and CH4 are significantly lower compared to conventional fuel gases such as natural gas, the flue gas stream produced by burning the H2-rich feed stream can contain a significantly reduced concentration of CO2, resulting in significantly lower CO2 emissions into the atmosphere. Therefore, the flue gas flow may contain CO2 with a molar concentration ranging from, for example, 0.01%, 0.05% to 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9% to 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10% to 11%, 12%, 13%, 14%, 15%, 16%, 17%, 18%, 19% or 20%, preferably ≤10%, preferably ≤5%, preferably ≤3%, based on the total molar number of CO2 and H2O in the flue gas flow. Combustion may be carried out in the presence of, for example, air, O2-enhanced air, high-purity O2, etc., depending on the specific application.

[0058] For use as a fuel stream, the H2-rich feed stream preferably has an absolute pressure of ≤1,135 kPa (150 psig), more preferably ≤790 kPa (100 psig). To achieve such low pressures in the H2-rich feed stream, it is feasible to design upstream syngas production units incorporating SMR and / or ATR operating under syngas production conditions, including relatively low pressures, such as ≤2,169 kPa (300 psig), more preferably ≤1,825 kPa (250 psig). As mentioned above, the lower pressure in the reformer leads to a higher CH4 conversion rate in the reformer, and consequently a lower residual CH4 concentration in the H2-rich feed stream.

[0059] Preferably, the H2-rich stream is supplied to at least one, preferably most, preferably all, of the combustion devices used in the method / system for producing the H2-rich stream. Therefore, when the syngas production plant includes a pre-reformer comprising a furnace heated by one or more burners burning fuel gas, it is preferred that a portion of the H2-rich stream is supplied as at least a portion, preferably most, preferably all, of the fuel gas to such burners. When the syngas production plant includes an SMR comprising one or more SMR burners burning SMR fuel, it is highly desirable to supply a portion of the H2-rich stream as at least a portion, preferably most, preferably all, of the SMR fuel. When the H2-rich stream production method / system uses an additional boiler or auxiliary furnace to burn fuel gas, it is highly desirable to supply a portion of the H2-rich stream as at least a portion, preferably most, preferably all, of the fuel gas. By burning the H2-rich stream and capturing the CO2 stream, the H2-rich stream production method / system of this disclosure achieves significantly reduced CO2 emissions to the atmosphere compared to conventional H2 production methods that burn natural gas.

[0060] Compared with existing methods for producing syngas and / or H2-rich fuel gas, especially those that burn hydrocarbon fuels, the H2-rich fuel gas production method of this disclosure has at least one of the following advantages: (i) lower capital investment and production costs due to, for example, the absence of a PSA unit, a small-scale CO2 recovery unit, and operation of the syngas production unit, the first shift reactor, and the second shift gas reactor at relatively low pressures; and (ii) significantly reduced CO2 emissions if the CO2 feed stream is captured, stored, isolated, and / or utilized.

[0061] II. Integration of H2-rich fuel gas production facilities with olefin production facilities

[0062] Modern olefin production facilities typically operate by feeding hydrocarbon feedstock (e.g., ethane, propane, butane, naphtha, crude oil, and mixtures thereof) and steam into a steam cracker. The hydrocarbon feed / steam mixture is heated to an elevated cracking temperature for a desired residence time, thereby cracking the hydrocarbon feedstock to produce a steam cracker effluent exiting the pyrolysis reactor containing H2, CH4, ethane, propane, butane, C2-C4 olefins, C4 dienes, and C5+ hydrocarbons. Heating may include a preheating step in the convection section of the steam cracker, followed by transfer to the radiant section, where additional heating to an elevated cracking temperature and cracking occur. The thermal energy required for preheating in the convection section and heating in the radiant section is typically provided by multiple steam cracker burners that burn steam cracker fuel gas. The high-temperature steam cracker effluent is immediately cooled by quenching and / or indirect heat exchange and separated to produce a process gas stream containing C1-C4 hydrocarbons, among other things. The process gas stream is then typically compressed and supplied to a product recovery section, which includes cooling units. (train) and multiple distillation columns, such as demethanizers, deethaners, depropanizers, C2 splitters, and C3 splitters, thereby producing one or more of the following: (i) a steam cracker H2 feed stream, which may preferably contain H2 with a molar concentration from, for example, 80%, 81%, 82%, 83%, 84%, 85% to 86%, 87%, 88%, 89%, 90% to 91%, 92%, 93%, 94%, 95% to 96%, 97%, or even 98%, based on a steam cracker. (ii) the total molar number of molecules in the H2 feed stream; (ii) the CH4--rich feed stream (sometimes called the "tail stream") containing CH4 with molar concentrations ranging from, for example, 50%, 55%, 60%, 65%, 70% to 75%, 80%, 85%, 90% to 91%, 92%, 93%, 94%, 95%, 96%, 97%, or even 98%, based on the total molar number of molecules in the CH4--rich feed stream; (ii) the ethane feed stream; (iii) the ethylene product feed stream; (iv) the propane feed stream; and (v) the propylene product feed stream. Many configurations of the recovery section are possible. The steam pyrolyzer H2 feed stream may contain, for example, from 0.1%, 0.2%, 0.3%, 0.4%, 0.5%, 0.6%, 0.7%, 0.8%, 0.9% to 1.0%, 1.5%, 2.0%, 2.5%, 3.0%, 3.5%, 4.5%, 5.0% to 6.0%, 8.0%, 10%, 12%, 14%, 15% to 16%, 17%, 18%, 19%, or even 20% CH4, on a molar basis. Preferably, the steam pyrolyzer H2 feed stream is substantially free of CO2 and CO, for example, containing a total concentration of CO2 and CO from 0 to no more than 1 mol% based on the total number of moles of molecules in the steam pyrolyzer H2 feed stream.The CH4-rich feed stream may contain at least one and preferably all of the following, on a molar basis: (i) for example, from 1%, 5%, 10%, 15% to 20%, 25%, 30% to 35% or even 40%, 45% H2; (ii) for example, from 0.1%, 0.5%, 1% to 2%, 3%, 4%, 5% to 6%, 7%, 8%, 9% or 10% ethane; and (iii) for example, from 0.01%, 0.05%, 0.1% to 0.2%, 0.5%, 1% to 2%, 3%, 4% or 5% CO, based on the total number of moles of molecules in the CH4-rich feed stream.

[0063] II.1 Fuel Gas Integration

[0064] As described in Section I above, the H2-rich fuel gas production method / facility of this disclosure can be advantageously integrated with olefin production facilities to achieve enhanced energy efficiency and reduced CO2 emissions to the atmosphere compared to previous methods / systems and operating them separately, regardless of the specific construction of the recovery section in the facility.

[0065] In some preferred embodiments, a portion of the H2-rich feed stream can be combined with a portion of the H2 feed stream from the steam cracker to form a combined H2-rich feed stream, which can be used for residential, office, and / or industrial heating applications, particularly industrial heating applications such as fuel gas in olefin production facilities.

[0066] In a particularly desirable embodiment, a portion of an H2-rich feed stream, a steam pyrolysis H2 feed stream, or a combined H2-rich feed stream can be supplied to one or more steam pyrolysis burners as at least a portion, preferably a majority, and preferably all of the steam pyrolysis fuel gas. Steam pyrolysis burners consume large quantities of steam pyrolysis fuel gas, which has historically tended to contain significant amounts of hydrocarbons such as CH4. By replacing a portion, preferably a majority, and preferably all of the steam pyrolysis fuel gas with an H2-rich feed stream, a steam pyrolysis H2 feed stream, and / or a combined H2-rich feed stream (each containing a low concentration of carbonaceous material), a significant reduction in CO2 emissions from the steam pyrolysis fuel gas can be achieved. In some embodiments, the steam pyrolysis burner may preferably be equipped with a combustion air preheater to reduce the fuel consumption requirements of the steam pyrolysis burner. The combustion air preheater may preferably be heated by electric heating and / or by exchanging heat with a hotter feed stream (e.g., flue gas from the same or different furnaces, a steam feed stream (preferably a low-pressure steam feed stream), a hot water feed stream, and / or a hot oil feed stream).

[0067] Olefin production facilities may include one or more boilers and / or auxiliary furnaces that burn fuel gas as a supplement to a steam cracker. In such cases, it is highly desirable to supply a portion of the H2-rich feed stream, the steam cracker H2 feed stream, and / or a combined H2-rich feed stream to such boilers and / or auxiliary furnaces as at least a portion, preferably most, and preferably all of the required fuel gas. Doing so further reduces CO2 emissions from the olefin production facility into the atmosphere.

[0068] Olefins production facilities may include combined cycle power facilities containing one or more duct burners that burn duct burner fuel to generate heat. In such cases, it is highly desirable to supply a portion, preferably a majority, and preferably all, of the required duct burner fuel to the duct burners from the H2-rich feed stream, the steam cracker H2 feed stream, and / or a portion of the combined H2-rich feed stream.

[0069] In some embodiments, the H2-rich feedstream and / or steam cracker H2 feedstream can supply, for example, 60%, 65%, 70% to 75%, 80%, 85% to 90%, 95%, 98%, 99%, or even 100% of the total fuel gas required in the olefin production facility, based on Btu.

[0070] In Table I below, the CO2 footprints of steam crackers that burn the following fuel gases to emit flue gas produced by combustion are compared: (i) typical natural gas only (“Natural Gas”); (ii) tail gas produced by a steam cracker receiving typical naphtha steam cracking feed only (“Tail Gas”); (iii) CO-rich fuel gas (“CO-rich Fuel”) produced by a comparative method comprising a syngas production unit, followed by a single-stage high-temperature shift reactor, and then H2O reduction and CO2 recovery; and (iv) H2-rich feed stream (“H2-rich Fuel”) produced by the methods of this disclosure. In all cases, the following conditions are assumed: 2.0 wet volume% excess O2, 60°F (16°C) air, and fuel gas.

[0071] As can be seen from Table I, the H2-rich feedstream produced by the method of this disclosure has a significantly smaller CO2 footprint from the flue gas produced by combustion compared to the other three fuel gases. Although the H2-rich fuel contains only a slightly higher concentration of H2 and a slightly lower concentration of CO than the comparative CO-rich combustion, it exhibits a significantly lower CO2 footprint (40% lower). This demonstrates the significant advantage of the method of this disclosure, which utilizes at least two shift reactors, compared to using only a single-stage high-temperature shift reactor. While the CO-rich fuel can be further purified to produce fuel gas with a higher H2 concentration and a lower CO concentration comparable to the H2-rich fuel by using additional equipment such as a PSA unit, the installation and operation of a PSA unit incurs significantly higher investment and operating costs than adding a second shift reactor and reduces the energy efficiency of the method. Therefore, the method of this disclosure achieves the production of H2-rich fuel gas with a low CO2 footprint, reduced costs, and enhanced energy efficiency.

[0072] Table I

[0073]

[0074] II.2 Hydrocarbon Feed Integration

[0075] In a particularly advantageous embodiment, a CH4--rich feed stream from an olefins production facility can be fed into the syngas production unit along with, for example, a natural gas feed stream as at least part of the hydrocarbon feed. Because the CH4--rich feed stream from the olefins production facility may be substantially sulfur-free, it can be advantageously fed into the syngas production unit after a desulfurization unit, if sulfur is present. If the CH4-rich stream contains low molar concentrations of C2+ hydrocarbons (e.g., ethane), such as ≤3%, ≤2%, <1%, <0.5%, <0.1%, or for example from 0.01%, 0.02%, 0.04%, 0.05% to 0.06%, 0.08%, 0.1% to 0.2%, 0.4%, 0.5% to 0.6%, 0.8%, 1%, 2%, or even 3%, based on the total molar number of hydrocarbons in the CH4-rich stream, then if C2+ hydrocarbons are present, the CH4-rich stream can be supplied to the reformer downstream of the pre-reformer, as the need to convert C2+ hydrocarbons in the pre-reformer is reduced. The CH4-rich stream can contain varying amounts of H2, as noted above. However, it is not necessary to remove H2 from the CH4-rich stream before feeding it into the SMR. Excess hydrogen in the CH4-rich stream can consume water flow capacity in the SMR and is therefore undesirable. However, a small amount of hydrogen (preferably ≤10 mol%, preferably ≤5 mol%, based on the total number of moles of molecules in the CH4--rich feed stream) is acceptable and can effectively minimize the potential for coke or fouling in SMR.

[0076] In some embodiments, the pressure of the CH4--rich feed stream can be higher than the pressure of the hydrocarbon feed required to power the syngas production unit. In such cases, it is highly advantageous to expand the CH4--rich feed stream in a turboexpander and / or a Joule-Thompson valve to produce a cooled CH4--rich feed stream with a pressure near that of the hydrocarbon feed. The cooled CH4--rich feed stream can be heated, for example, by using any feed stream in a H2--rich production unit or olefin production facility at a temperature higher than that of the cooled CH4--rich feed stream, and then supplied to the syngas production unit.

[0077] In some implementations, the pressure of the CH4--rich feed stream can be lower than the hydrocarbon feed pressure required to feed into the syngas production unit. In such cases, it is desirable to compress the CH4--rich feed stream to a pressure close to the hydrocarbon feed pressure before feeding it into the syngas production unit.

[0078] II.3 Steam Integration

[0079] In an olefin production facility comprising one or more steam crackers, the steam cracker receives hydrocarbon feed and steam, and cracks the hydrocarbons under steam cracking conditions to produce a steam cracker effluent exiting the steam cracker. The high-temperature steam cracker effluent is immediately cooled by quenching and / or indirect heat exchangers, where a large amount of steam can be generated, which can then be superheated in the convection section of the steam cracker. The cooled steam cracker effluent can then be separated to produce, among other things, a process gas stream containing H2, methane, ethane, C2-C4 olefins, and dienes. To recover olefin products from the process gas stream, it is typically first compressed to elevated pressure, cooled under cryogenic conditions in a cooling unit, and then separated in distillation columns such as demethanizers, deethanerizers, depropanizers, C2 splitters, C3 splitters, etc. For this purpose, at least three (3) large gas compressors can be used: a process gas compressor (“PGC”), a propylene refrigeration compressor (“PRC”), and an ethylene refrigeration compressor (“ERC”). In modern, worldwide olefins facilities, the total shaft power of these compressors can exceed 100 MW (134,000 hp). This very high shaft power requirement is characteristic of olefins production facilities and distinguishes them from most other petrochemical equipment. Typically, large compressors are driven by steam turbines. Most of the steam can be generated, as described above, from steam produced from the effluent of a cooling steam cracker. If necessary, a boiler is used to supplement the required steam volume.

[0080] Because of the large shaft power requirements of the main compressor, it is important for efficient olefin production that the steam-power cycle be as efficient as possible. Multi-stage steam systems with a maximum steam pressure level of nominal 100 BarG (1500 psig, or 10.3 MPaG) or higher can be advantageously used. This Super-HPS can be superheated to maximize the turbine's specific output power (kW power / kg steam consumed). As a complement to the large compressor turbine, smaller turbine drives can be used for several applications within the olefin production facility (e.g., cooling water pumps, quench water pumps, boiler feed pumps, air compressors, etc.). These turbines can receive HPS, MPS, or LPS feed streams. Additionally, existing process heating loads in the olefin recovery unit can be met by condensing one or more HPS, MPS, or LPS feed streams.

[0081] We have discovered that steam feed streams (one or more) at various pressures generated and / or consumed in H2-rich fuel gas production facilities can be intelligently integrated with steam feed streams (one or more) at various pressures generated and / or consumed in olefin production facilities, thereby achieving significantly improved overall energy efficiency and cost efficiency. Therefore, a Super-HPS feed stream generated in an H2-rich fuel gas production facility (e.g., a stream generated by a WHRU) can advantageously be combined with another Super-HPS feed stream generated in an olefin production facility (e.g., a stream generated by a steam cracker and / or boiler) to form a combined feed stream, which is then supplied to consumption units located within the facility, such as turbines, syngas production units, etc. Similarly, HPS feed streams generated in the facility can be combined and supplied to consumption units, as can MPS and LPS feed streams.

[0082] The reformate stream leaving the H2-rich production facility's reformer exhibits high temperature and high pressure, as indicated above in section I. It is highly desirable to capture the heat energy contained therein. Therefore, preferably, the reformate stream passes through a waste heat recovery unit (“WHRU”) to produce a cooled reformate stream and a high-pressure steam (“HPS”) stream. The cooled reformate stream can have temperatures ranging from, for example, 285°C, 290°C, 300°C to 310°C, 320°C, 330°C, 340°C, 350°C to 360°C, 370°C, 380°C, 390°C, or even 400°C. The cooled reformate stream can have substantially the same pressure as the reformate stream leaving the reformer. The WHRU may include, for example, one or more heat exchangers and one or more steam drums in fluid communication with the heat exchangers. The steam drums supply water to the heat exchangers, heat it in the heat exchangers, and can then return it to the steam drums, where the steam is separated from the liquid water phase. HPS flow rates can have absolute pressures ranging from, for example, 4,000 kPa, 5,000 kPa, 6,000 kPa, 7,000 kPa, 8,000 kPa to 9,000 kPa, 10,000 kPa, 11,000 kPa, 12,000 kPa, 13,000 kPa, or even 14,000 kPa. In some embodiments, the HPS flow rate is preferably a Super-HPS flow rate. The resulting HPS flow rate is a saturated steam flow rate.

[0083] To make the HPS feed stream more useful, it can also be heated, for example, in a furnace to produce a superheated HPS (“SH-HPS”) feed stream. If the syngas production unit as described above includes a SMR with a convection section, the saturated HPS feed stream can advantageously be superheated in the convection section of the SMR and / or in an auxiliary furnace. If the syngas production unit includes one or more ATRs but no SMR, the saturated HPS feed stream can be superheated in an auxiliary furnace. The auxiliary furnace may include one or more burners that burn fuel gas streams to supply the required heat energy, preferably derived from H2-rich feed streams generated in H2-rich fuel gas production facilities and / or H2 feed streams generated in steam crackers in olefin production facilities, as described above. SH-HPS flow may have one or both of the following: (i) temperatures ranging from, for example, 350°C, 360°C, 370°C, 380°C, 390°C, 400°C to 410°C, 420°C, 430°C, 440°C, 450°C to 460°C, 470°C, 480°C, 490°C, 500°C to 510°C, 520°C, 530°C, 540°C or even 550°C; and (ii) absolute pressures ranging from, for example, 4,000 kPa, 5,000 kPa, 6,000 kPa, 7,000 kPa, 8,000 kPa to 9,000 kPa, 10,000 kPa, 11,000 kPa, 12,000 kPa, 13,000 kPa or even 14,000 kPa. Preferably, the SH-HPS feed stream has a temperature of at least 371°C and the steam feed in step (A) has an absolute pressure of at least 1700 kPa. In some embodiments, the SH-HPS feed stream preferably has a pressure higher than the steam feed supplied to the syngas production unit in step (A), such that the SH-HPS can be expanded to generate a steam feed stream with a pressure near that of the steam feed, which can then be supplied to the syngas production unit as at least a portion of the steam feed. Preferably, the SH-HPS feed stream has a temperature of at least 482°C and an absolute pressure of at least 10,000 kPa, and the steam feed has an absolute pressure of at least 1,700 kPa (e.g., at least 2,500 kPa). In a preferred embodiment, the SH-HPS feed stream can be supplied to HPS manifolds located in industrial facilities such as olefin production facilities and H2-rich fuel gas production facilities, thereby supplying HPS to suitable equipment that consumes the SH-HPS. In another embodiment, the SH-HPS stream can also be a Super-HPS stream and supplied to a Super-HPS manifold located in an industrial facility such as an olefin production facility, thereby supplying the Super-HPS to suitable equipment that consumes the superheated Super-HPS.

[0084] In some preferred embodiments, at least a portion of the SH-HPS stream derived from steam streams generated in H2-rich fuel production facilities (e.g., SH-HPS streams generated in WHRUs) and / or steam streams generated from olefin production facilities (e.g., SH-HPS streams generated by steam crackers and / or boilers) can be expanded in at least one stage of a steam turbine to generate shaft power and an expanded steam stream having a pressure equal to or higher than the steam feed pressure of the syngas production unit. The expanded steam stream can have a temperature ranging from, for example, 260°C, 270°C, 280°C, 290°C, 300°C to 310°C, 320°C, 330°C, 340°C, 350°C to 360°C, 370°C, 380°C, 390°C, 400°C, or even 405°C. The expanding steam stream has a lower pressure than the SH-HPS stream, ranging from, for example, 1,380 kPa, 1,400 kPa, 1,500 kPa, 1,600 kPa, 1,700 kPa, 1,800 kPa, 1,900 kPa, 2,000 kPa to 2,200 kPa, 2,400 kPa, 2,500 kPa, 2,600 kPa, 2,800 kPa, 3,000 kPa to 3,200 kPa, 3,400 kPa, 3,500 kPa, 3,600 kPa, 3,800 kPa, 4,000 kPa to 4,200 kPa, 4,400 kPa, or even 4,500 kPa. The expanding steam stream can be an HPS stream or an MPS stream. In some implementations, the turbine can generate multiple discharge streams, such as HPS stream and LPS stream; HPS stream and condensable stream supplied to the condenser; MPS stream and LPS stream; or MPS stream and condensable stream supplied to the condenser.

[0085] In some embodiments, a single-stage steam turbine is used to expand the SH-HPS feed stream. In other embodiments, multiple cascaded steam turbines can be used, wherein the expanded steam stream, preferably an HPS or MPS stream, generated by the upstream stage is supplied to a downstream turbine, where it expands to produce a lower-pressure steam stream and additional shaft power. The shaft power generated by one or more such turbines can be used for mechanical work, such as driving generators to produce electricity that can be transmitted to local and / or remote electrical equipment; driving compressors or pumps located in industrial facilities, such as process gas compressors, propylene refrigeration compressors, ethylene refrigeration compressors, air compressors, and / or various pumps located in olefin production facilities. The expanded steam stream can be supplied to a steam header with a suitable pressure rating in any industrial facility, such as an olefin production facility. In some embodiments, the SH-HP stream can be supplied to the olefin production facility at a pressure not less than the maximum pressure required for the operation of any steam turbine with a rated power of at least 1 megawatt (1MW, or ≥5MW, or ≥10MW, or ≥20MW). In some preferred embodiments, an SH-HPS feed stream (which may or may not be a Super-HPS feed stream) can be supplied to a first-stage turbine in the olefin production facility to drive a process gas compressor. An expanded steam feed stream (which may be an SH-HPS feed stream or an MPS feed stream) from the first-stage turbine can be supplied to a second-stage turbine to generate a second expanded steam feed stream and drive the shaft power of another process gas compressor, propylene refrigeration compressor, ethylene refrigeration compressor, air compressor, and / or pump in the olefin production facility. In another embodiment, an SH-HPS feed stream can be supplied to drive one or more process gas compressors, propylene refrigeration compressors, and ethylene refrigeration compressors, each generating an expanded steam feed stream with the same, similar, or different pressures. The expanded steam feed streams from the first and / or second stages can then be used to provide process heat or supplied to additional turbines, depending on their respective pressures. Additionally, one or more of the turbines can discharge a condensable steam feed stream, which is fed into a condenser to generate a condensate stream. Preferably, at least one, more preferably at least two, and more preferably all of the turbines driving the PGC, propylene refrigeration compressor, and ethylene refrigeration compressor are back-pressure turbines. Back-pressure turbines do not produce a steam feed stream supplied to a surface condenser, where the steam feed stream condenses, resulting in the release of heat energy into the atmosphere. By using back-pressure turbines, the conventional surface condenser used in conventional condensing turbines is eliminated, leading to a reduction in capital and operating costs, as well as a reduction in heat energy released into the atmosphere.

[0086] While the shaft power generated in the expanded SH-HPS feed stream can be used to drive the generator in the power island, in the preferred embodiment of this disclosure where shaft power is used to drive compressors, pumps, etc. in an integrated olefin production facility, such a power island can be eliminated or included in a smaller size, resulting in a significant reduction in capital and operating costs.

[0087] In some preferred embodiments of the H2-rich fuel gas production method, an amine CO2 capture device is used to recover at least a portion of the CO2 present in the crude gas mixture stream to produce a CO2 stream and an H2-rich stream (VII). Step (VII) may preferably include: (VIIa) obtaining an exhaust steam stream and shaft power with an absolute pressure of 200 kPa to 1,050 kPa from one or more pumped turbines and / or back-pressure turbines (preferably one or more back-pressure turbines) located in an olefin production facility; (VIIb) feeding a crude gas mixture stream and a lean amine stream containing amines into an absorption column; (VIIc) obtaining a CO2-rich amine stream and a CO2-depleted residual gas stream from the absorption column; (VIId) feeding at least a portion of the CO2-rich amine stream into a separation column; (VIIe) heating at least a portion of the CO2-rich amine stream in the separation column using the exhaust steam stream to produce a CO2-rich top stream and an amine-rich bottom stream; and (VIIf) recirculating at least a portion of the bottom stream back to the absorption column as at least a portion of the lean amine stream.

[0088] Olefin production facilities contain one or more extraction turbines and / or one or more back-pressure turbines as described in step (VIIa). Historically, these turbines in hydrocarbon processing facilities were conventionally constructed to generate exhaust steam streams at very low pressures, such as ≤100 kPa, ≤80 kPa, or ≤50 kPa, which were then supplied to surface condensers with high load ratings for condensation. Such condensation resulted in the release of significant amounts of heat into the atmosphere. Furthermore, surface condensers with high load ratings are expensive to purchase and operate. Therefore, it is highly desirable to reduce the size of surface condensers or eliminate at least some, preferably all, of them without causing operational problems for the turbine-driven units.

[0089] The extraction turbine and / or back-pressure turbine in step (VIIa) may receive HPS feed, such as Super-HPS feed or MPS feed (desirably superheated). Depending on the pressure of its steam feed, one or more of the extraction turbine and / or back-pressure turbines may, in addition to an exhaust steam stream with an absolute pressure of 200 kPa-1,050 kPa, produce one or more of the following: (i) an HPS stream, (ii) an MPS stream, and (iii) a condensable stream supplied to a surface condenser. Preferably, at least one, preferably all, of the extraction turbine and / or back-pressure turbines is a back-pressure turbine that does not produce (iii) the condensable stream supplied to the surface condenser (e.g., a steam stream with an absolute pressure ≤100 kPa). One or more extraction turbines and / or one or more back-pressure turbines may include one or more of the following: turbines driving process gas compressors, turbines driving one or more propylene refrigeration compressors, turbines driving one or more ethylene refrigeration compressors, turbines driving various air compressors, turbines driving various pumps, and turbines driving one or more generators, and combinations thereof.

[0090] An exhaust steam stream with an absolute pressure of 200 kPa to 1,050 kPa can be generated by a single extraction turbine or a back-pressure turbine. Alternatively, the exhaust steam stream can be a combined stream of several such exhaust steam streams with similar pressures generated by multiple extraction turbines and / or back-pressure turbines. This pressure range is particularly advantageous for supplying the heat required in the regeneration step of the amine CO2 capture process. Therefore, the exhaust steam stream can have an absolute pressure ranging from, for example, 200 kPa, 250 kPa, 300 kPa, 350 kPa, 400 kPa, 450 kPa, 500 kPa to 550 kPa, 600 kPa, 650 kPa, 700 kPa, 750 kPa, 800 kPa to 850 kPa, 900 kPa, 950 kPa, 1,000 kPa, or even 1,050 kPa. Preferably, the exhaust steam stream has an absolute pressure not exceeding 480 kPa.

[0091] In step (VIIb), the gas mixture stream and the lean amine stream containing the amine are fed into the absorption column. Any amine absorption column and amine known to those skilled in the art of CO2 separation can be used. Non-limiting examples of available amines include: monoethanolamine (“MEA”), diethanolamine (“DEA”), methyldiethanolamine (“MDEA”), diisopropanolamine (“DIPA”), diethylene glycolamine (“DGA”), and mixtures thereof. The most commonly used amines for CO2 separation and capture are DEA, MEA, and MDEA. In a preferred embodiment, the lean amine stream is supplied to the upper section of the absorption column, and the gas mixture is fed into the lower section of the absorption column. The countercurrent contact between the gas mixture and the amine in the absorption column in step (VIIc) results in a CO2-rich amine stream and a CO2-depleted residual gas stream. Preferably, the CO2-rich amine stream exits the absorption column from the bottom and the CO2-depleted residual gas stream exits from the top.

[0092] In step (VIId), at least a portion of the CO2-rich amine stream is fed into a separation column. Any design of separation column known to those skilled in the art can be used. The separation column is sometimes also called a regeneration column because the amine is regenerated from it. In step (VIId), at least a portion of the CO2-rich amine stream is heated in the separation column. Such heating can be achieved using a heat exchanger. At least a portion, preferably ≥30%, preferably ≥50%, preferably 60%, preferably 80%, preferably ≥90%, preferably all of the heat energy for heating is provided by the exhaust steam stream generated in step (VIId). Once heated to the desired temperature, CO2 separates from the amine in the separation column, producing a CO2-rich stream and an amine-rich stream. Preferably, the CO2-rich stream exits the separation column at the top and the amine-rich stream exits from the bottom. At least a portion of the amine-rich stream can be recycled to an absorption column as at least a portion of the amine-lean stream in step (vii). The CO2-rich stream can be compressed, liquefied, diverted, stored, isolated, or used in any suitable application known to those skilled in the art. In one embodiment, the CO2-rich stream, optionally compressed, can be diverted in a CO2 pipeline. In another embodiment, the CO2-rich stream, optionally compressed and / or liquefied, can be injected and stored in geological formations. In yet another embodiment, the CO2-rich stream, optionally compressed and / or liquefied, can be used to extract hydrocarbons present in geological formations. Another exemplary use of the CO2-rich stream is in food applications.

[0093] The exhaust steam stream with an absolute pressure of 200 kPa to 1,050 kPa (preferably no more than 800 kPa, preferably no more than 500 kPa, preferably no more than 480 kPa) generated in step (VIIa) by one or more extraction turbines and / or one or more back-pressure turbines is particularly suitable for supplying heat to the separation column to achieve the separation of CO2 and amines. Those skilled in the art can extract a suitable amount of exhaust steam stream from one or more extraction turbines and / or back-pressure turbines, as described below in this disclosure, to meet the heating load required in the CO2 / amine separation / regeneration column, thereby achieving the separation of any given amount of crude gas mixture (with any CO2 concentration). By generating the exhaust steam stream and supplying it to the separation column, useful work is performed by utilizing the residual heat energy in the exhaust steam stream. This contrasts with the prior art of generating a condensable steam stream that is further condensed in a surface condenser, in which the residual heat energy in the condensable stream is released to the atmosphere and lost. When an olefins production facility comprising multiple large steam turbines is integrated with an amine CO2-separation process steam according to various embodiments of this disclosure, substantial improvements in energy efficiency can be achieved, as illustrated in the following examples of this disclosure. Furthermore, such extraction of exhaust steam feed (one or more) can be performed in one or more back-pressure turbines, allowing each turbine to still generate sufficient shaft power to drive the target equipment. In some embodiments, it may be desirable to increase the steam feed of one or more extraction turbines and / or back-pressure turbines to ensure sufficient shaft power and exhaust steam feed. To this end, in some specific embodiments, an electric motor can replace the existing steam turbine, allowing the steam required by the replaced turbine to be supplied to the extraction turbine and / or back-pressure turbine, thereby generating sufficient exhaust steam feed and shaft power. In some embodiments, the exhaust steam stream is generated by a back-pressure turbine, and the exhaust stream provides a certain amount of energy to at least a portion of the CO2-rich amine stream in step (VIIe); and in the comparative method (which is the same as the method except that the back-pressure turbine is replaced with an extraction / condensing turbine with the same rated power), at least 30% (preferably ≥50%, preferably ≥60%, preferably ≥70%) of the energy is lost to the atmosphere.

[0094] The present disclosure is further illustrated by the exemplary but non-limiting embodiments shown in the accompanying drawings described below. In the drawings, the same reference numerals may have similar meanings. In the drawings illustrating the method / system of the present invention, in which multiple initial individual streams are shown forming a combined stream supplied to the next step or device, it should be understood (where appropriate) that alternatives are further included in which at least one of such multiple individual streams is individually supplied to the next step or device. When multiple initial individual streams having similar composition and / or application (e.g., H2-rich streams and steam cracker H2 streams) are shown forming a combined stream supplied to multiple next steps or devices, it should be understood (where appropriate) that alternatives are included in which at least one of the individual streams and the combined stream is supplied to at least one of the multiple next steps or devices. Therefore, when initial, separate fuel gas (e.g., H2-rich stream) X and fuel gas stream (e.g., steam cracker H2 stream) Y, generated from different devices but having similar fuel gas applications, are shown to form a combined stream Z supplied to two separate furnaces A and B, it should be understood that alternatives include supplying at least one of X, Y, and Z to at least one of A and B, including but not limited to: (i) supplying only stream Z to A and B; (ii) supplying both X and Y separately to at least one of A and B; (iii) supplying both X and Z separately to at least one of A and B; (iv) supplying both Y and Z separately to at least one of A and B; and (v) supplying only one of X and Y to at least one of A and B. The accompanying drawings are for illustrative purposes only of some embodiments of this disclosure, and those skilled in the art will recognize that alternatives may fall within the scope of this disclosure.

[0095] Figure 1 (contrast)

[0096] Figure 1 The illustration depicts a steam supply / consumption system 101 for a conventional olefins production facility, including one or more steam cracker furnaces. One or more Super-HPS feed streams 107 are generated by one or more steam cracker furnaces 103. One or more Super-HPS feed streams 109 are generated by one or more auxiliary steam boilers or COGEN units 105. As shown, feed streams 107 and 109 can be optionally combined in a Super-HPS manifold, from which the Super-HPS feed streams can be distributed to steam-consuming equipment. Figure 1As shown, one or more Super-HPS streams 113, one or more Super-HPS streams 115, and one or more Super-HPS streams 117 are supplied to one or more steam turbines 119, one or more steam turbines 129, and one or more steam turbines 141, respectively. Steam turbine(one or more) 119 can drive one or more process gas compressors. Steam turbine(one or more) 129 can drive one or more propylene refrigeration compressors. Steam turbine(one or more) 141 can drive one or more ethylene refrigeration compressors. Additional Super-HPS steam can be supplied to other consuming equipment / equipment / processes 111. One or more HPS streams 121 can be discharged from steam turbine(one or more) 119. Streams(one or more) 121 can be used to provide process heat, such as stream 125 in olefin production facilities or other equipment, or supplied to steam turbine 125 that receives HPS streams and discharges MPS streams, or supplied to steam turbine 125 that receives HPS streams and discharges LPS streams, thereby generating additional mechanical work that can be used to drive another process gas compressor, pump, etc. One or more condensable feed streams 123 are typically discharged from turbines (one or more) 119, which condense at condensers (one or more) 127 to produce one or more condensate streams 128. One or more MPS feed streams 131 may be discharged from turbines (one or more) 129. The feed streams (one or more) 131 may be used to provide process heat, such as feed streams 133 to olefin production facilities or other equipment, or to supply to turbines 133 that receive MPS feed streams and discharge LPS feed streams, thereby generating additional mechanical work that can be used to drive another compressor, pump, etc. One or more condensable feed streams 135 are discharged from turbines (one or more) 129, which then condense at condensers (one or more) 137 to produce one or more condensate streams 139. One or more LPS feed streams 143 may be discharged from turbines (one or more) 141. The feed streams (one or more) 143 may be used to provide process heat, such as feed streams 145 to olefin production facilities or other equipment. One or more condensable steam streams 147 are discharged from turbine(one or more) 141, which are then condensed at condenser(one or more) 149 to produce one or more condensate streams 151. The condensate streams 128, 139, and 151 are then combined and processed together at position 153. The generation of condensable steam streams 123, 135, and 147, subsequently condensed using surface condensers, increases the shaft power generation of turbines 119, 129, and 141. However, their condensation results in the release of a significant amount of heat energy into the atmosphere. Furthermore, surface condensers 127, 137, and 149 require substantial capital investment and operating costs.

[0097] Figure 2 (contrast)

[0098] Figure 2 The illustration includes a comparison H2 production facility for SMR. As shown, a natural gas feed stream 202, which may contain CH4, C2+ hydrocarbons of varying concentrations, and sulfur compounds of varying concentrations, is split into streams 203 and 204. Stream 203 is first fed into a desulfurization unit 205 to produce a sulfur-reduced stream 207. Stream 207 is combined with a steam stream 279 to form a hydrocarbon / steam mixture stream 209. Stream 209 is then fed into a pre-reformer 211 containing a pre-reform catalyst. Upon contact with the pre-reform catalyst, the heavier C2+ hydrocarbons are preferentially converted to methane (thus preventing coke formation in the downstream main reformer) to produce a pre-reformed effluent 213 containing methane and steam. Stream 213 is then fed into pipe 220a in the upper section 214 (sometimes called the convection section) of SMR 215, where stream 213 is heated. SMR 215 includes a lower section 216 (sometimes referred to as the radiant section) housing one or more tubes 220b in fluid communication with a tube 220a that receives the heated feed stream 213 in tube 220a. As shown, in some embodiments, tube 220a may extend from the convection section to the outside of the SMR furnace and then connect to one or more tubes 220b re-entering the SMR furnace. Multiple tubes 220b may be connected to a single tube 220a via one or more manifolds (not shown) outside the SMR furnace housing, although only one tube 220b is shown. SMR 215 includes one or more burners 218 in the radiant section 216, wherein SMR fuel is burned to supply energy to the radiant section 216 of SMR 215 and then to the convection section 214.

[0099] The reforming catalyst is loaded in tubes (one or more) 220b within the radiant section 216. Due to its proximity to the burner (one or more) 218, the reforming catalyst and the CH4 and steam mixture in tubes (one or more) 220b are heated / maintained at an elevated temperature. The following forward reactions preferentially occur:

[0100]

[0101] Additionally, various amounts of CO2 can be generated in tubes (one or more) 220b. Therefore, a reformate stream 221 containing CO, H2, residual CH4, residual H2O, and optionally various amounts of CO2 exits the outlet of the SMR tubes (one or more) 220b. The stream 221 is then cooled at a waste heat recovery unit ("WHRU") comprising a waste heat boiler ("WHB") 223 and a steam drum 271, resulting in a cooled reformate stream 225 and an HPS stream 267. As shown, a water stream 263 flows from the steam drum 271 to the WHB 223, and a steam-water mixture stream 265 flows from the WHB 223 to the steam drum 271.

[0102] The feed stream 267 (saturated steam feed stream) is then heated in the convection section 214 of the SMR 215 to produce superheated high-pressure steam (“SP-HP”) steam feed stream 269. A branch 279 of feed stream 269 is combined with a sulfur-reduced hydrocarbon feed stream 207 to form a combined feed stream 209, which is then fed to a pre-reformer 211 as described above. Another branch 277 of feed stream 269 is fed to a turbine 273, where the feed stream expands to produce an exhaust steam feed stream 283 and shaft power driving a generator 275 via shaft 281. The exhaust steam feed stream 283 may be condensable and condensed using a surface condenser.

[0103] like Figure 2 As shown, a cooled reformate stream 225 containing CO, H2, H2O, and optionally CO2 is then fed into a shift reactor 227 containing a shift catalyst loaded therein. When the shift reactor is in contact with the shift reactor under shift conditions, the following forward reaction preferentially occurs:

[0104]

[0105] Thus, the shift feed stream 229, containing a lower concentration of CO and a higher concentration of CO2 than feed stream 225, exits the shift reactor 227.

[0106] The feed stream 229 is then cooled in the heat exchanger 231 by the boiler feed stream 234 supplied by the boiler feed water treatment unit 233. The thus heated boiler feed stream 235 leaving the heat exchanger 231 is then supplied to the steam drum 271 and at least partially to the WHB 223, thereby generating a high-pressure steam stream 267 as previously described.

[0107] The cooled shift feed stream 236, containing CO, H2, H2O, and CO2, exits heat exchanger 231 and is then further cooled in heat exchanger 245. A portion of the residual vapor in stream 236, considered as liquid water in stream 247, can be fed to separator 249 to obtain condensed stream 251 and gaseous stream 253. The vapor-reduced stream 253 primarily contains H2 and CO2, CH4 and CO.

[0108] The feed stream 253 is then supplied to a transformer (“PSA”) unit 255 to produce an H2 feed stream 257 and a PSA discharge stream 259 containing CO, CO2, CH4, and H2. This H2 feed stream 257, along with a separate natural gas feed stream 204, is then fed into an SMR 215 as an SMR fuel feed stream 324. The SMR fuel is burned at one or more burners 218 to provide the heat required for the radiant and convective sections of the SMR 215. The PSA discharge stream 215 typically contains no more than 30% by volume of H2, based on the total volume of the feed stream 215.

[0109] exist Figure 2 In the H2 production method 201, the flue gas stream 219 leaving SMR 215 contains a significantly high concentration of CO2 due to the combustion of natural gas from feed stream 204 and carbon-rich PSA discharge stream 259. While CO2 emissions from method 201 can be reduced by capturing CO2 from feed stream 219 using an amine absorption / regeneration unit, such a unit requires high capital expenditure and, because feed stream 219 is at atmospheric pressure, also high operating costs. The PSA unit 255 also requires substantial capital and operating costs.

[0110] Figure 3

[0111] Figure 3 Illustrative illustration of comparison method / system 301, where from and Figure 2 A similar H2 production method supplies H2 to olefin production facilities that include one or more steam cracker furnaces. As shown, a branch of natural gas stream 303 is combined with steam stream 305 to form a combined stream 307, which is fed into a tube located in the convection section 309 of the SMR and heated therein, and then into a tube containing a reforming catalyst in the radiant section 311 of the SMR. The SMR receives the SMR fuel stream 317, which is combusted in the SMR to generate heat energy for heating the radiant section 311 and the convection section 309. Upon contact with the reforming catalyst, the CH4 / steam mixture undergoes a reforming reaction to produce a reformed stream 319 containing CO, CO2, H2, and CH4 exiting the SMR. Stream 319 is then cooled at a waste heat recovery unit 321 to obtain a cooled reformed stream 323 and an HPS stream 301. Stream 301 is then heated in the convection section of the SMR to obtain an SH-HPS stream 343. A branch 305 of feed stream 343 is combined with the natural gas feed stream to form a mixed feed stream 307 fed to the SMR as discussed above. Another branch 345 of feed stream 343 is then fed to turbine 347, where the feed stream expands to generate shaft power to drive generator 351 via shaft 349. The exhaust steam stream 353 (LPS stream) from turbine 347 can be sent to the amine regenerator of CO2 capture unit 355, as described below.

[0112] The cooled reformate stream 323 is then fed into a shift reactor 325, where it contacts a shift catalyst to convert a certain amount of CO / H2O into CO2 and H2, producing a shift stream 327 exiting the shift reactor 325. Stream 327 is then cooled at a heat exchanger 329 to produce a cooled shift stream 331 containing condensate. In a water separator 333, the condensate stream 335 is separated from stream 331 to produce a reduced-vapor stream 337 primarily containing H2, CO2, and CO. Stream 337 is then fed into a PSA unit 339 to produce an H2 stream 341 and a PSA discharge stream 315. Stream 315, containing CO, CO2, and H2, is combined with a natural gas stream 313 to form an SMR fuel stream 317. Stream 317 is burned in the SMR to produce thermal energy in the radiant heating section 311 and the convection section 309 as described above. The flue gas stream 357 exiting the SMR contains a significant amount of CO2. To reduce the CO2 footprint of the H2 production facility, stream 357 is fed into an amine CO2 capture unit 355 as described above. In unit 355, the amine regenerator is heated by a steam stream 353, thereby achieving the separation of the CO2 stream 359 exiting unit 355. The CO2 stream 359 can be transferred, stored, isolated, or used via pipeline.

[0113] like Figure 3As shown, H2 feed stream 341, or a portion thereof, is then supplied as feed stream 367 to a steam cracker 371 located in the olefin production facility as steam cracker fuel, wherein combustion of the feed stream provides the heat energy required for cracking and heating the steam cracker feed and produces a flue gas stream 378 exiting the steam cracker 371. If H2 feed stream 367 contains high-purity H2 (e.g., having an H2 concentration ≥ 99 mol%), the flue gas stream 378 may be substantially CO2-free. Steam cracker hydrocarbon feed stream 369 and dilution steam stream enter the steam cracker 371, are heated in its convection section, and then enter the radiant section, where cracking occurs at high temperatures with a short residence time, producing a steam cracker effluent containing H2, C1-C4 hydrocarbons containing desired C2-C4 olefins, and C5+ hydrocarbons, etc. The steam pyrolysis effluent is immediately cooled via indirect heat exchange and / or quenching in steam pyrolysis unit 371, resulting in a quenched steam pyrolysis effluent stream 375 and a large amount of HPS, which is then superheated to produce an SH-HPS stream 376. The quenched steam pyrolysis effluent stream 375 is sent to the hot end 378 of the recovery section, where it is further cooled. In section 378, dilution steam 373 is generated and sent to steam pyrolysis unit 371. Optionally, a branch 361 of the H2 stream 341 can be supplied to one or more boilers 363 to generate additional amounts of SH-HPS in stream 365. Streams 365 and 376 are combined to form stream 377. Separation of the cooled steam pyrolysis effluent stream 375 produces a process gas stream containing H2 and C1-C4 hydrocarbons including desired C2-C4 olefins. The process gas stream is compressed to an increased pressure in one or more compressors 380 and supplied to the cold end 379 of the recovery section, thereby generating, among other things, a tail gas stream 390 consisting mainly of CH4 and H2, an ethylene product stream 391, a propylene product stream 392, and one or more C4+ by-product streams 393, etc.

[0114] The SH-HPS stream 377 is supplied to one or more turbines driving one or more process gas and / or refrigeration compressors 380. The HPS stream 381 may be generated by one or more turbines and fed to another turbine, or used to provide process heating loads. The MPS stream 383 may be generated by one or more turbines, divided into a stream 386 fed to another turbine or used to provide process heating loads, and a stream 385 fed to the hot end 378 of the recovery section to generate dilution steam. The LPS stream 382 may be generated by one or more turbines and used to provide process heating loads. The turbines may discharge one or more condensable streams 384, supplying them to one or more surface condensers 387, where they are cooled by a cooling water stream 388 to generate a condensable stream 389.

[0115] In method 301, CO2 emissions from steam crackers (one or more) 371 are reduced by burning H2 from H2 feed stream 367, compared to conventional steam crackers (one or more) that burn natural gas or a mixture of natural gas and methane-rich tail gas; CO2 emissions from boilers (one or more) 363 are reduced if H2 feed stream 361 supplies fuel gas to boilers (one or more) 363, compared to conventional boilers that burn natural gas or a mixture of natural gas and methane-rich tail gas; and CO2 emissions are reduced by capturing CO2 feed stream 359 from SMR flue gas flow 357 using amine absorption / regeneration unit 355, compared to conventional H2 production facilities using SMR that burn natural gas without capturing CO2 from SMR flue gas. Nevertheless, method 301 has the following disadvantages: high capital costs due to the need for many devices; high costs of operating the amine CO2 capture device 355 due to the large volume of flue gas 357 at atmospheric pressure; and loss of heat to the atmosphere due to the use of surface condensers (one or more) 387.

[0116] Figure 4

[0117] Figure 4 This illustrative description illustrates an exemplary method / facility 401 for producing rich-H2 fuel gas according to some preferred embodiments of this disclosure. As shown, a hydrocarbon feed stream 403 (e.g., a natural gas stream primarily containing CH4) that may contain CH4, C2+ hydrocarbons of varying concentrations, and sulfur-containing compounds of varying concentrations is first fed into an optional desulfurization unit 405 to produce a sulfur-reduced feed stream 407 to prevent poisoning of catalysts used in downstream process steps (e.g., catalysts used in SMR units described below). The feed stream 407 is combined with an HPS feed stream 479 to form a hydrocarbon / steam mixture feed stream 409, optionally preheated via, for example, a heat exchanger or a furnace (not shown). The feed stream 409 can then be fed into a pre-reformer 411, which may be an adiabatic reactor containing a pre-reformation catalyst, optionally preheated via, for example, a heat exchanger or a furnace (not shown). Upon contact with the pre-reforming catalyst, heavier C2+ hydrocarbons are preferentially converted to methane (thus preventing coke formation in the downstream main reformer), producing a pre-reforming effluent 413 containing methane and steam. Flow 413 is then fed into tube 420a in the upper section 414 (sometimes called the convection section) of the SMR 415, where the flow 413 is heated. The SMR 415 includes a radiating section 416 housing one or more tubes 420b in fluid communication with the tube 420a receiving the heated flow 413. Figure 4As shown, in some embodiments, pipe 420a may extend from the convection section to the outside of the SMR furnace and then connect to pipe(s) 420b re-entering the SMR furnace. Multiple pipes 420b may be connected to a single pipe 420a via one or more manifolds (not shown) outside the SMR furnace housing, although only one pipe 420b is shown. The SMR 415 includes one or more burners 418 in the radiant section 416, where SMR fuel is burned to supply energy to the radiant section 416 of the SMR 415 and then to the convection section 414. For ease of illustration, pipes 420a and 420b in the SMR are shown as comprising multiple straight sections. In practice, portions of pipes 420a and 420b (particularly pipe 420a) may be curved or even form meandering windings.

[0118] The reforming catalyst is loaded in tubes (one or more) 420b in the radiant section 416. Due to its proximity to the burners (one or more) 418, the reforming catalyst, hydrocarbon feed, and steam in tubes (one or more) 420b are heated / maintained at elevated temperatures. Under syngas production conditions, the following forward reactions preferentially occur:

[0119]

[0120] Additionally, various amounts of CO2 can be generated in tubes (one or more) 420b. Therefore, a reformate stream 421 containing CO, H2, residual CH4, residual H2O, and optionally various amounts of CO2 exits the outlet of the SMR tubes (one or more) 420b at a temperature of, for example, 750°C–900°C and an absolute pressure of, for example, 700 kPa–3,500 kPa. The reformate stream 421 is then cooled at a waste heat recovery unit (“WHRU”) comprising a waste heat boiler (“WHB”) 423 and a steam drum 471, thereby producing a cooled reformate stream 425 and an HPS stream 467. As shown, a water stream 463 flows from the steam drum 471 to the WHB 423, and a steam-water mixture stream 465 flows from the WHB 423 to the steam drum 471.

[0121] The feed stream 467 (saturated steam feed stream) can then be heated in the convection section 414 of the SMR 415 to produce superheated high-pressure steam (“SH-HP”) steam feed stream 469, which can be fed into a steam header and supplied to any suitable equipment or process step. For example, as shown and described above, a branch 479 of feed stream 469 can be combined with a sulfur-reduced hydrocarbon feed stream 407 to form a combined feed stream 409, which is then fed to a pre-reformer 441. As another example, a branch 477 of feed stream 469 can be fed into a turbine 473, where the feed stream expands to produce an exhaust steam feed stream 483 and shaft power. The shaft power can be transferred via shaft 481 to any suitable equipment 475 to generate usable mechanical work. An example of equipment 475 is a generator that converts mechanical work into electrical energy that can be transmitted to any suitable local or remote electrical equipment. The exhaust steam stream 483 may have residual pressures and temperatures suitable for, for example, driving an additional steam turbine, heating other equipment, and / or the stream itself. In a specific case, the exhaust steam stream 485 may be an LPS stream used to provide heat to the amine regenerator in a CO2 capture unit.

[0122] like Figure 4 As shown, a cooled reformate stream 425 containing CO, H2, H2O, and optionally CO2 is then fed into the first shift reactor 427. The first shift reactor can be operated under a first set of shift conditions in the presence of a first shift catalyst loaded therein. Due to the relatively high temperatures in the first set of shift conditions, the first shift reactor 427 is sometimes referred to as a high-temperature shift reactor. When the first shift catalyst is contacted under the first set of shift conditions, the following forward reaction preferentially occurs:

[0123]

[0124] Therefore, the first shift reactor 429, containing a lower concentration of CO and a higher concentration of CO2 than the feed stream 425, exits the first shift reactor 427. Since the forward reaction is exothermic, feed stream 429 has a higher temperature than feed stream 425, assuming the first shift reactor 427 is an adiabatic reactor.

[0125] The first transformed feed stream 429 can then be further cooled in the heat exchanger 431 by any suitable feed stream at a temperature lower than that of the feed stream 429. For example... Figure 4As shown, in a preferred embodiment, the boiler feedwater stream 434 supplied from the boiler feedwater treatment unit 433 is used to cool the cooling stream 429. The thus heated boiler feedwater stream 435 exiting the heat exchanger 431 can be supplied to the steam drum 471 and at least partially to the WHB 423, thereby generating a high-pressure steam stream 467 as previously described, or supplied to any other suitable steam generator. Alternatively or additionally (not shown), the hydrocarbon feed stream 403 or a portion thereof can be heated via the stream 429 at the heat exchanger 431 or by another heat exchanger upstream or downstream of the heat exchanger 431.

[0126] The cooled first shift feed stream 436, containing CO, H2, H2O, and CO2, exiting heat exchanger 431, is then fed into the second shift reactor 437. The second shift reactor can be operated under a second set of shift conditions, including the presence of the second shift catalyst loaded therein and at a temperature lower than that in the first shift reactor 427. Due to the lower temperature, the second shift reactor 437 is sometimes referred to as a cryogenic shift reactor. Under the second set of shift conditions, when the second shift catalyst is in contact, the following forward reactions preferentially occur:

[0127]

[0128] Therefore, the second shift reactor 439, containing a lower concentration of CO and a higher concentration of CO2 than the feed stream 436, exits the second shift reactor 437. Since the forward reaction is exothermic, feed stream 439 has a higher temperature than feed stream 436, assuming the second shift reactor 437 is an adiabatic reactor.

[0129] The second conversion stream 439 can then be further cooled in heat exchanger 441 by any suitable stream at a temperature lower than that of stream 439. In a preferred embodiment, boiler feedwater stream (not shown) supplied from a boiler feedwater treatment device (e.g., device 433) can advantageously be used to cool stream 439. The thus heated boiler feedwater stream exiting heat exchanger 441 can be supplied (not shown) to steam drum 471 and at least partially to WHB 423, thereby generating high-pressure steam stream 467 as previously described, or to any other suitable steam generator. Alternatively or additionally (not shown), the hydrocarbon feed stream 403 or a portion thereof can be heated by stream 439 at heat exchanger 441 or by another heat exchanger upstream or downstream of heat exchanger 441.

[0130] The cooled stream 443 exiting heat exchanger 441 can be further cooled at heat exchanger 445 by any suitable cooling medium having a lower temperature than the stream 443, such as cooling water, ambient air (using, for example, an air finned cooler), etc. Preferably, a portion of the residual vapor in stream 443, considered as liquid water in stream 447, can be fed to separator 449 to obtain condensed stream 451 and gaseous stream 453. The vapor-reduced stream 453 (a crude gas mixture) mainly contains H2 and CO2, and optionally small amounts of residual CH4 and CO.

[0131] The feed stream 453 can then be supplied to a CO2 recovery unit 455 to produce a CO2 feed stream 457 and an H2-rich feed stream 459. Any suitable CO2 recovery unit known in the art can be used. A preferred CO2 recovery unit is an amine absorption and regeneration unit, wherein the crude gas mixture feed stream 453 contacts a countercurrent feed stream of amine absorbing CO2, the CO2 being subsequently released from the amine upon heating (“regeneration”). The CO2 feed stream 457 can be supplied to a CO2 line and diverted. The CO2 feed stream 457 can be compressed, liquefied, stored, isolated, or used in a manner known to those skilled in the art.

[0132] The H2-rich stream 459 may advantageously contain H2 with a molar concentration ranging from, for example, 80%, 81%, 82%, 83%, 84%, 85% to 86%, 87%, 88%, 89%, 90% to 91%, 92%, 93%, 94%, 95% to 96%, 97%, 98%, 99%, based on the total number of moles of molecules in the stream 459. In addition to H2, feed stream 459 may also contain: (i) CH4 with a molar concentration from, for example, 0.1%, 0.3%, 0.5%, 0.8% to 1%, 2%, 3%, 4% or 5%, based on the total number of moles in feed stream 459; (ii) CO with a molar concentration from, for example, 0.1%, 0.3%, 0.5%, 0.8% to 1%, 2% or 3%, based on the total number of moles in feed stream 459; and (iii) CO2 with a molar concentration from, for example, 0.1%, 0.2%, 0.3%, 0.4%, 0.5% to 0.6%, 0.7%, 0.8%, 0.9% or 1%, based on the total number of moles in feed stream 459. Feed stream 459 may advantageously be used as fuel gas for residential, office and / or industrial heating. Due to the high concentration of H2 and the low concentration of carbon molecules, combustion of feed stream 459 in the presence of an oxidant such as air or oxygen can produce a flue gas stream containing a low concentration of CO2. In some embodiments, the flue gas stream may contain a CO2 molar concentration not exceeding 20% ​​(e.g., from 0.1%, 0.2%, 0.4%, 0.5% to 0.6%, 0.8%, 1% to 2%, 4%, 5% to 6%, 8%, 10% to 12%, 14%, 15% to 16%, 18 mol%, or 20%), based on the total molar number of H2O and CO2 in the flue gas stream. It is advantageous to vent the flue gas stream into the atmosphere without the need for separation and capture of CO2 therefrom.

[0133] In the preferred embodiment, such as Figure 4 As shown, a branch 417 of the feed stream 459 can be supplied to the SMR 415, wherein the feed stream is burned in one or more burners 418 to supply heat energy to the SMR 415, thereby heating the lower radiant section 416 and the tubes (one or more) 420b therein, as well as the convection section 414 and the tubes 420a therein. Figure 2 Compared to the H2 production facility shown, the flue gas flow 419 exiting SMR 415 contains a significantly lower concentration of CO2, and can therefore be released into the atmosphere with significantly reduced CO2 emissions without the need for separation and capture of CO2 from it.

[0134] Figure 5

[0135] Figure 5This disclosure schematically illustrates the method / system 501 of the present invention, which integrates an H2-rich fuel gas production method / facility with an olefin production facility including a steam cracker. As shown, a natural gas feed stream 303 is combined with a CH4-rich feed stream 535 generated from the recovery section of the olefin production facility and an HPS feed stream 502 generated from a steam turbine (preferably a turbine driving a process gas or refrigeration compressor) 380 in the olefin production facility to form a combined feed stream 307, which is fed into a tube located in the convection section 309 of the SMR and heated therein, and then into a tube containing a reforming catalyst in the radiant section 311 of the SMR. The SMR receives an SMR fuel gas stream 516 (an H2-rich fuel gas stream as described below), which is combusted in the SMR to generate heat energy for heating the radiant section 311 and the convection section 309. Upon contact with the reforming catalyst, the CH4 / steam mixture undergoes a reforming reaction to produce a reformed gas stream 319 containing CO, CO2, H2, and CH4 exiting the SMR. Then, the feed stream 319 is cooled at the waste heat recovery unit 321 to obtain a cooled reformed feed stream 323 and an HPS feed stream (preferably a Super-HPS feed stream) 301. The feed stream 301 is then heated in the convection section of the SMR to obtain a superheated HPS (“SH-HPS”) (preferably superheated Super-HPS) feed stream 343. Preferably, the pressure of the feed stream 343 is higher than the steam feed 502 of the SMR. Thus, steam 343 or a diverter is not directly fed into the SMR, but... Figure 3 The method is compared. Then the feed stream 343 is supplied to the olefin production facility, in combination with other HPS feed streams (one or more) (preferably Super-HPS feed streams (one or more)) generated in the olefin production facility, such as feed streams (one or more) 375 generated by steam crackers (one or more) 371 and feed streams (one or more) 365 generated by boilers (one or more) 363, thereby supplying equipment, particularly steam turbines (one or more) in the olefin production facility that consume such HPS, as described below.

[0136] The cooled reformate stream 323 is then fed into a first high-temperature shift reactor 503, where it contacts a first shift catalyst to convert a certain amount of CO / H2O into CO2 and H2, resulting in a first shift stream 505 exiting the first shift reactor 503. Stream 505 is then cooled at one or more heat exchangers (not shown) and enters a second low-temperature shift reactor 507 to produce a second shift stream 509. Stream 509 is then cooled at one or more heat exchangers 511 to produce a cooled second shift stream 513 containing condensate. In a water separator 515, condensate stream 517 is separated from stream 513 to produce a reduced-vapor stream 519 mainly containing H2, CO2, and small amounts of CO and CH4. Then, feed stream 519, preferably at a pressure similar to that of feed streams 509 and 513 (above 200 kPa, preferably at least 700 kPa, preferably at least 1,000 kPa), is fed into amine CO2 absorption / regeneration unit 521 to generate CO2 feed stream 523 and H2-rich feed stream 524 (similar to...). Figure 4 (459) The CO2 stream 523 can be compressed, liquefied, diverted, stored, isolated, or used to reduce CO2 emissions into the atmosphere.

[0137] A feed stream 524 containing CO, CO2, and H2 can be combined with a steam cracker H2 feed stream 525 generated from the recovery section of an olefin production facility as described below to form a combined fuel stream 527. A branch stream 516 of feed stream 527 is supplied to the SMR and combusted therein to generate thermal energy for the heating radiant section 311 and convection section 309 as described above. Figure 3 Compared to the SMR flue gas flow 357, the flue gas flow 518 leaving the SMR contains a significantly reduced concentration of CO2. Therefore, it is not necessary to capture CO2 from the feed flow 518. Figure 3 The methods are used to form a comparison.

[0138] like Figure 5As shown, a branch stream 531 of the H2-rich fuel stream 527 is then supplied to one or more steam crackers 371 in the olefin production facility as steam cracker fuel, wherein combustion of the feed stream provides the heat required for heating and cracking of the steam cracker feed and produces a flue gas stream 533 exiting the steam cracker 371. Due to the limited amounts of CO and CH4 present in the feed stream 527, the flue gas stream 533 contains a limited amount of CO2, making CO2 capture from the flue gas stream 533 unnecessary. The steam cracker hydrocarbon feed stream 369 and the dilution steam stream 373 enter the steam cracker 371, are heated in its convection section, and then enter the radiant section, where cracking occurs at high temperatures with a short residence time, producing a steam cracker effluent containing H2, C1-C4 hydrocarbons containing desired C2-C4 olefins, and C5+ hydrocarbons, etc. The steam pyrolysis effluent is immediately cooled via indirect heat exchange and / or quenching in steam pyrolysis unit 371, resulting in a quenched steam pyrolysis effluent stream 375 and a large amount of HPS, which is then superheated to produce an SH-HPS stream 376. The quenched steam pyrolysis effluent stream 375 is sent to the hot end 378 of the recovery section, where it is further cooled. In section 378, dilution steam 373 is generated and sent to steam pyrolysis unit 371. A branch stream 529 of the H2-rich stream 527 can be supplied to one or more boilers 363 to generate an additional amount of SH-HPS in stream 365. Streams 343, 365, and 376 can be combined to form a combined stream 377. The separation of the cooled steam pyrolysis effluent streams produces a process gas stream containing H2 and C1-C4 hydrocarbons including desired C2-C4 olefins. The process gas stream is compressed to an increased pressure in one or more compressors 380 and supplied to the cold end 379 of the recovery section to produce, among other things, the steam cracker H2 feed stream 525 described above; the CH4--rich feed stream 535 consisting essentially of CH4 and H2; the ethylene product feed stream 391; the propylene product feed stream 392; and one or more C4+ by-product feed streams 393, etc.

[0139] SH-HPS feed stream 377 is supplied to one or more turbines driving one or more process gas and / or refrigeration compressors 380. HPS feed stream 381 may be generated by one or more turbines. A branch 502 of feed stream 381 may be fed to the SMR along with natural gas feed stream 303 and CH4-rich feed stream 535 as described above. Another branch of feed stream 381 may be fed to one or more other turbines, wherein the feed stream expands to generate additional shaft power or may be used for process heating loads. MPS feed stream 383 may be generated by one or more turbines, divided into feed stream 386 which feeds to one or more other turbines or may be used for process heating loads, and feed stream 385 which feeds to the hot end 378 of the recovery section to generate dilution steam. LPS feed stream 382 may be generated by one or more turbines. Figure 5 As shown, a portion (or all) of the feed stream 382 can be supplied to the amine CO2 absorption / regeneration unit 521, which is used to heat the regenerator to achieve separation of the CO2 feed stream 523 from the amine. The turbine can optionally discharge one or more condensable feed streams 584, supplying them to one or more surface condensers 587, where they are cooled by a cooling water stream 588 to produce a condensable feed stream 589.

[0140] exist Figure 5 In method 501, compared to conventional steam crackers (one or more) that burn natural gas, methane-rich tail gas, or a combination of natural gas and methane-rich tail gas, CO2 emissions from steam crackers (one or more) 371 are reduced by burning H2-rich feed stream 531; compared to conventional boilers that burn natural gas or a combination of natural gas and methane-rich tail gas, CO2 emissions from boilers (one or more) 363 are reduced by supplying H2-rich feed stream 529 to boilers (one or more) 363; and compared to conventional H2 production facilities using SMR that burn natural gas without capturing CO2 from SMR flue gas, CO2 emissions are reduced by capturing CO2 feed stream 523 from SMR flue gas flow 519 using amine absorption / regeneration unit 521. Figure 3 Compared to method / system 301, Figure 5 The integration method / system 501 has at least the following advantages: (i) lower capital and operating costs due to the elimination of the PSA device; (ii) because Figure 5 The amine CO2 capture device 521 in the ratio Figure 3The amine unit 355 in the method (which operates at atmospheric pressure) operates at significantly higher pressures than atmospheric pressure (e.g., ≥200 kPa absolute pressure, preferably ≥500 kPa absolute pressure, preferably ≥800 kPa absolute pressure), so unit 521 can be significantly smaller than unit 355, resulting in significantly lower capital and operating costs; (iii) because the CH4--rich feed stream 535 is fed into the SMR as part of the hydrocarbon feed, it is converted into part of the H2--rich feed stream 522 and part of the CO2 feed stream 523, which can be captured, resulting in a higher efficiency than the H2--rich feed stream 522. Figure 3 The method could result in significantly lower CO2 emissions into the atmosphere. Figure 3 The method typically involves burning a CH4-rich exhaust gas at 390°C to produce CO2-containing flue gas that is difficult and expensive to capture at atmospheric pressure; (iv) because... Figure 5 HPS feedstock 343 is supplied to olefin production facilities that include the main turbines, thus removing... Figure 3 The power island, including turbine 347 and generator 351, results in significantly lower capital and operating costs; (v) because it will be powered by... Figure 5 The LPS feed streams (one or more) generated by the turbines in the olefin production facility are supplied to the amine CO2 capture unit 521, so that... Figure 3 Compared to the condensable stream (one or more) 384 and the surface condenser (one or more) 387, the reduced amount of stream and / or reduced total amount of condensable stream (one or more) 584 can be supplied to fewer and / or less loaded surface condensers (one or more) 587, or the condensable stream 584 and the surface condenser 587 can be completely removed, resulting in a reduced amount of heat released to the atmosphere and significantly lower capital and operating costs.

[0141] Figure 6 (contrast)

[0142] Figure 6The schematic illustration includes the steam supply / consumption configuration 601 of a comparative olefins production facility comprising multiple steam crackers. As shown, the facility supplies superheated steam via lines 603, 605, 607, and 609 at the following temperatures and pressures: 930°F and 1500 psig (Super-HPS), 700°F and 660 psig (HPS), 570°F and 225 psig (MPS), and 450°F and 50 psig (LPS). Super-HPS of 1560 klb / hr (“klb / hr”) from stream 617 generated by turbine generator unit 611, Super-HPS of 540 klb / hr from stream 619 generated by multiple steam cracker furnaces 613, and Super-HPS of 596 klb / hr from stream 621 generated by boiler 615 are supplied to line 603. Super-HPS feed streams 625, 627, 629, 631, and 633 are supplied from line 603 to turbines 635, 637, 639, 641, and heat exchanger 643 at the following flow rates: 879 klb / hr, 710 klb / hr, 745 klb / hr, 301 klb / hr, and 3 klb / hr, respectively. Super-HPS at a rate of 58 klb / hr is discharged from line 603 to other application units 623. The steam feed streams entering the turbines expand therein, generating one or more steam feed streams and shaft power. The shaft power can be used to drive various equipment in the olefin production facility, such as process gas compressors (one or more), propylene refrigeration compressors (one or more), and pumps.

[0143] Pipeline 605 receives the input HPS stream 604 at 30 klb / hr, the HPS stream 645 from turbine 635 at 700 klb / hr, the HPS stream 649 from turbine 637 at 585 klb / hr, the HPS stream 657 from turbine 641 at 100 klb / hr, the HPS stream 667 from heat exchanger 643 at 3 klb / hr, and the HPS stream 665 from steam drum 663 at 10 klb / hr. All four turbines 635, 637, 639, and 641 also produce condensable steam streams that condense at surface condensers 647, 651, 655, and 661 at the following flow rates: 179 klb / hr, 124 klb / hr, 79 klb / hr, and 149 klb / hr, respectively. HPS flows 671, 673, and 620 from pipeline 605 are supplied to turbines 675 and 677 and other field-use units 622 at the following flow rates: 540 klb / hr, 127 klb / hr, and 68 klb / hr, respectively. HPS at a rate of 695 klb / hr is discharged from pipeline 605 to other field-use units 669.

[0144] Line 607 receives MPS stream 679 from back-pressure turbine 675 at 540 klb / hr and MPS stream 653 from turbine 639 at 667 klb / hr. Turbine 675 does not produce condensable streams for supply to the surface condenser. From line 607, MPS streams 685, 687, and 630 are supplied to turbine 689, field application unit 693, and field application unit 632 at the following flow rates: 324 klb / hr, 206 klb / hr, and 306 klb / hr, respectively. From line 607, 330 klb / hr of MPS is discharged to other application unit 683.

[0145] Line 609 receives input LPS stream 610 at a flow rate of 12 klb / hr, LPS stream 691 from back-pressure turbine 689 at 324 klb / hr, LPS stream 681 from back-pressure turbine 677 at 127 klb / hr, LPS stream 695 from steam drum 697 at 70 klb / hr, and LPS stream 659 from turbine 641 at 52 klb / hr. Neither turbine 689 nor 677 produces condensable streams for supply to the surface condenser. From line 609, LPS streams 640 and 650 are supplied to field application units 642 and 652 at flow rates of 261 klb / hr and 207 klb / hr, respectively. No LPS is output to external application unit 699.

[0146] Figure 7 (This invention)

[0147] Figure 7 illustrative illustration from Figure 6 The steam supply / consumption configuration 701 of the present invention pertains to the modification of facilities and integration with SMR steam in an olefin production facility. Figure 7 As shown, the facility supplies superheated steam via lines 603, 605, 607, and 609 at the following temperatures and pressures: 930°F and 1500 psig (Super-HPS), 700°F and 660 psig (HPS), 570°F and 225 psig (MPS), and 450°F and 50 psig (LPS), respectively. Figure 6The same applies. 1560 klb / hr of Super-HPS from stream 617 generated by turbine generator unit 611, 540 klb / hr of Super-HPS from stream 619 generated by multiple steam cracker furnaces 613, 262 klb / hr of Super-HPS from stream 721 generated by boiler 715, and 905 klb / hr of Super-HPS from stream 704 generated by SMR 703 are supplied to line 603. From line 603, Super-HPS streams 725, 727, 729, 731, and 633 are supplied to turbines 635, 637, 639, 641, and heat exchanger 643 at the following rates: 951 klb / hr, 808 klb / hr, 1073 klb / hr, 373 klb / hr, and 3 klb / hr, respectively. From line 603, 58 klb / hr of Super-HPS is output to other user units 623.

[0148] Pipeline 605 receives input HPS stream 604 at 30 klb / hr, HPS stream 745 from turbine 635 at 630 klb / hr, HPS stream 749 from turbine 637 at 700 klb / hr, HPS stream 753 from turbine 639 at 407 klb / hr, HPS stream 757 from turbine 641 at 149 klb / hr, HPS stream 667 from heat exchanger 643 at 3 klb / hr, and HPS stream 665 from steam drum 663 at 10 klb / hr. Turbines 637 and 641 also produce condensable steam streams that condense at surface condensers 751 and 761 at flow rates of 108 klb / hr and 89 klb / hr, respectively. HPS streams 671 and 673 are supplied from line 605 to turbines 675 and 677 and other field-use units 622 at the following flow rates: 540 klb / hr, 127 klb / hr, and 68 klb / hr, respectively. HPS at 695 klb / hr is output from line 605 to other-use unit 669. Additionally, HPS stream 705 is supplied from line 605 to SMR 703 at a flow rate of 499 klb / hr as steam feed for the SMR.

[0149] Line 607 receives MPS stream 679 from turbine 675 at 540 klb / hr and MPS stream 755 from turbine 639 at 666 klb / hr. Turbine 675 does not produce condensable streams for supply to the surface condenser. From line 607, MPS streams 685, 687, and 630 are supplied to turbine 689, field application unit 693, and field application unit 632 at the following flow rates: 324 klb / hr, 206 klb / hr, and 306 klb / hr, respectively. From line 607, 360 klb / hr of MPS is discharged to other application unit 683.

[0150] Line 609 receives input LPS stream 610 at a flow rate of 12 klb / hr, LPS stream 691 from turbine 689 at 324 klb / hr, LPS stream 681 from turbine 677 at 127 klb / hr, LPS stream 695 from steam drum 697 at 70 klb / hr, and LPS stream 759 from turbine 641 at 136 klb / hr. Neither turbine 689 nor 677 produces condensable streams for supply to the surface condenser. From line 609, LPS streams 640 and 650 are supplied to field application units 642 and 652 at flow rates of 261 klb / hr and 207 klb / hr, respectively. Additionally, from pipeline 609, LPS feed stream 707 is supplied at a flow rate of 487 klb / hr to the amine regenerator of the amine CO2 capture unit associated with SMR 703.

[0151] The present disclosure is further illustrated by the following non-limiting examples. Example

[0152] Used in these embodiments Figure 6 and 7 The olefin production facility described herein. Example 1 (Comparative Example) corresponds to... Figure 6 Example 2 corresponds to Figure 6 olefin production facilities and Figure 4 The combination of H2-rich fuel gas production facilities, wherein H2-rich feed stream 461 is supplied to steam cracker 613 as steam cracker fuel; and the tail gas generated in the olefin production facility (similar to...) Figure 3 The material flow 390) is fed into Figure 4 The pre-reformer 411 in the example serves as the hydrocarbon feed for the SMR. Example 3 corresponds to... Figure 5 and 7The H2-rich fuel gas production facility shown is integrated with the steam of the olefins production facility. The process conditions of the olefins facility, and consequently the compressor power requirements of the olefins facility, are assumed to remain constant in all three embodiments. In all three embodiments, the olefins production facility has the same steam cracker 613 with a total combustion rate of 2,240 MBtu / hr; and (ii) the same turbine generator unit 611, thereby producing 1,560 klb / hr of Super-HPS in feed stream 617 while supplying electricity to the olefins production facility and beyond. In all these embodiments, turbine 635 drives a low-pressure process gas compressor, turbine 637 drives a high-pressure process gas compressor, and turbines 639 and 641 drive propylene refrigeration compressors. The input steam streams 604 and 610, streams 665, 633, 667, 620, 630, 640, 650, 671, 673, 685, 691, 687, 695, and output streams 623, 669, 683, and 699 supplied to the device of use remain constant in all three embodiments.

[0153] Example 1 (Comparative)

[0154] Example 1 corresponds to Figure 6 The fuel gas supplied to steam pyrolysis unit 613 and boiler 615 is determined to contain an average of 35 mol% H2 and 65 mol% CH4, based on the total molar number of molecules in the fuel gas. Boiler 615 has a total combustion rate of 1,990 MBtu / hr. Therefore, the determined CO2 emissions from the steam pyrolysis unit and boiler are 1,780 thousand tons per year (“kta”). A total of 530 klb / hr of steam is compressed from the four main steam turbines 635, 637, 639 and 641, producing a total condenser load of 520 MBtu / hr (152 MW).

[0155] Example 2

[0156] Example 2 corresponds to Figure 6 olefin production facilities and Figure 4 The combination of H2-rich fuel gas production facilities, wherein H2-rich feed stream 461 is supplied to steam cracker 613 as steam cracker fuel; and the tail gas generated in the olefin production facility (similar to...) Figure 3 The material flow 390) is fed into Figure 4The pre-reformer 411 serves as the hydrocarbon feedstock for the SMR. Steam integration between the H2-rich fuel gas production facility and the olefins production facility is not covered in this Example 2. The reformer waste heat recovery system generates HPS feedstream 469, some of which (spinstream 479) is consumed in the SMR. The remainder (spinstream 477) passes through a steam turbine generator (STG), generating 21 MW of electrical power. The STG is a back-pressure LPS turbine, and the discharged LPS feedstream 485 is used for amines in the regenerated amine CO2 unit 455. The fuel-grade H2-rich feedstream 461 is combusted in the steam cracker 613 and boiler 615 in the olefins production facility. Feedstreams 459, 461, and 417 are identified as containing 85 mol% H2 and 15 mol% CH4. Feedstream 461 output to the olefins facility has an H2 content of 185 million standard cubic feet per day (“MMSC / D”).

[0157] In this Example 2, the total CO2 emissions from the steam cracker 613, boiler 615, and SMR were 969 kta, a reduction of 811 kta compared to Example 1. This is further reduced by considering STG (Steam Generator) at a CO2 intensity of 0.389 t / MWh. Figure 4 The electricity generated in generator 475 results in a net CO2 emission of 900 kta from the steam cracker 613, boiler 615, and H2-rich fuel gas facility, a reduction of 880 kta (49%) compared to Example 1. The total fuel burned in the steam cracker 613, boiler 615, and SMR increases from 4,230 MBtu / hr to 5,930 MBtu / hr, an increase of 40%.

[0158] The total CO2 in the segregable CO2 stream 457 is 1,410 kta, and the ratio of segregated CO2 to avoided CO2 is 1.60.

[0159] Example 3

[0160] Example 3 corresponds to, for example Figure 7 The H2-rich fuel gas production facility shown is integrated with the steam of the olefins production facility. Example 3 also corresponds to... Figure 5 In this embodiment 3, essentially the same H2-rich fuel gas facility used in embodiment 2 above is employed to provide... Figure 4 H2-rich material flow 461 (or Figure 5 The H2 contained in 185MMSCF / D in the feed stream 524 is supplied to the SMR and olefin production facilities for use in steam cracker 613 (or Figure 5 371) and boiler 615 (or Figure 5Combustion is carried out in 363 (of which). A CH4--rich feed stream 535 from the olefins production facility is supplied to the SMR as part of the hydrocarbon feed. The reformer waste heat recovery unit (“WHRU”) produces a Super-HP steam feed stream 704 (or) at 905 klb / hr. Figure 5 The feed stream 343 is completely discharged to the olefins plant Super-HPS line 603. HPS steam 705 required by the SMR is supplied from the olefins plant HP steam manifold in line 605.

[0161] Compared to Example 1, the two main steam turbines are modified to provide the desired steam system integration. Turbine 635 (low-pressure process gas compressor turbine) is changed from an HPS-extraction and condensing turbine to an HPS-extraction and LPS-back-pressure turbine. This reduces condensation energy loss to the atmosphere and provides LPS feed stream 747 to the amine regenerator in CO2 capture unit 455. Turbine 639 (propylene refrigeration compressor turbine) is changed from an MPS-extraction and condensing turbine to an HPS-extraction and MPS-back-pressure turbine. This reduces condensation energy loss to the atmosphere and provides HPS feed stream 705 to SMR 703. Turbine 637 (high-pressure process gas compressor turbine) and turbine 641 (propylene concentrator heat pump turbine) remain HPS-extraction and condensing turbines, but the rates of HPS feed streams 749 and 757 are increased, and the rate of condensable vapor condensed at surface condensers 751 and 761 is reduced. This also reduces the energy loss of condensation to the atmosphere and provides HPS steam 705 for SMR 703.

[0162] Compared to Examples 1 and 2, in Example 3, the required combustion rate of boiler 715 decreased from 1,990 MBtu / hr to 1,250 MBtu / hr, a reduction of 740 MBtu / hr (37%). Because the same volume of H2-rich fuel gas was input from the SMR, the hydrogen content in the fuel gas burned in the cracking furnace and boiler increased from 85 mol% in Example 2 to 91 mol% in this Example 3 due to the need for less supplemental natural gas.

[0163] In this Example 3, the total CO2 emissions from the steam cracker 613, boiler 615, and SMR chimney are 610 kta, a reduction of 1170 kta (66%) compared to Example 1 and a reduction of 290 kta (32%) compared to Example 2. Because there is no STG in the reformer / hydrogen facility, no electricity is included compared to Example 1. Compared to Example 2, the CO2 isolated / CO2 avoided ratio is reduced from 1.60 to 1.21 in this Example 3 due to the improved energy efficiency of the integrated system. Furthermore, in this Example 3, condenser energy loss to the atmosphere is reduced from 520 MBtu / hr to 190 MBtu / hr, a saving of 330 MBtu / hr (63%) compared to Examples 1 and 2. Key performance parameters are further provided / compared in Table II below:

[0164] Table II

[0165]

[0166] List of Implementation Plans

[0167] This disclosure may additionally include one or more of the following non-limiting embodiments:

[0168] A1. Methods, including:

[0169] (I) Supplying hydrocarbon feed and steam feed to a syngas production unit containing a reforming reactor under syngas production conditions to generate a reformate stream leaving the reforming reactor, wherein the syngas production conditions include the presence of a reforming catalyst and the reformate stream contains H2, CO and steam.

[0170] (II) A cooled reformate stream and a high-pressure steam ("HPS") stream are generated by using a waste heat recovery unit ("WHRU");

[0171] (III) In the first shift reactor, under the first set of shift conditions, the cooled reformate stream is brought into contact with the first shift catalyst to generate a first shift stream leaving the first shift reactor, wherein the first shift stream has a lower CO concentration and a higher CO2 concentration than the cooled reformate stream.

[0172] (IV) Cooling the first conversion stream to obtain a cooled first conversion stream;

[0173] (V) In the second shift reactor, under the second set of shift conditions, the cooled first shift feed stream is brought into contact with the second shift catalyst to generate a second shift feed stream leaving the second shift reactor, wherein the second shift feed stream has a lower CO concentration and a higher CO2 concentration than the cooled first shift feed stream;

[0174] (VI) Reduce the steam present in the second conversion stream to produce a crude gas mixture stream containing CO2 and H2;

[0175] (VII) Recovering at least a portion of the CO2 present in the crude gas mixture stream to produce a CO2 stream and an H2-rich stream, wherein the H2-rich stream contains H2 at a concentration of at least 80 mol%, based on the total number of moles of molecules in the H2-rich stream; and

[0176] (VIII) A portion of the H2-rich feed stream is supplied to an olefin production facility containing a steam cracker as at least a portion of the steam cracker fuel gas, and the steam cracker fuel gas is burned to provide heat energy to the steam cracker.

[0177] The method of A2.A1, wherein the H2-rich stream further comprises at least 85 mol% H2 and at least one and preferably all of the following: ≤5 mol% CH4, ≤3 mol% CO, and ≤1 mol% CO2, based on the total number of moles of molecules in the H2-rich stream.

[0178] Methods A3, A1, or A2 also include:

[0179] (IX) A CH4---rich feed stream is generated from the steam pyrolysis effluent; and

[0180] (X) Provide a portion of the CH4--rich feed stream as at least a portion of the hydrocarbon feed.

[0181] The methods of A4 and A3, wherein the CH4-rich stream contains at least one of the following: ≤40 mol% H2, ≤10 mol% ethane, and ≤5 mol% CO, based on the total number of moles of molecules in the CH4-rich stream.

[0182] Method A5.A3 or A4, wherein the absolute pressure of the CH4--rich feed stream is higher than the absolute pressure of the hydrocarbon feed supplied to the syngas production unit in step (I), and step (X) includes:

[0183] (Xa) The CH4--rich feed stream is expanded by a turboexpander and / or a Joule-Thompson valve to produce a cooled CH4--rich feed stream with a pressure near that of the hydrocarbon feed.

[0184] (Xb) A heated CH4-rich feed stream is generated by heating and cooling a CH4--rich feed stream via a heat exchanger in an olefin production facility; and

[0185] (Xc) provides at least a portion of a heated CH4--rich feed stream as at least a portion of the hydrocarbon feed.

[0186] The methods described in A6.A1 through A5 also include:

[0187] (XI) Generating H2 feed stream from the steam cracker at the olefins production facility; and

[0188] (XII) At least one of the following is supplied to the syngas production unit as at least a portion of the reforming fuel gas: (a) at least a portion of the H2-rich feed stream; (b) at least a portion of the H2 feed stream from the steam cracker; and (c) a combined feed stream of (a) and (b).

[0189] The methods described in A7.A1 through A6 also include:

[0190] (XIII) At least one of the following shall be supplied to the steam pyrolyzer as at least a portion of the steam pyrolyzer fuel gas: (a) at least a portion of the steam pyrolyzer H2 feed stream; (b) at least a portion of the steam pyrolyzer H2 feed stream; and (c) a combined feed stream of (a) and (b).

[0191] The methods described in A8.A1 through A7 also include:

[0192] (XIV) supplying at least one of the following to one or more boilers located in an olefin production facility as boiler fuel gas: (a) at least a portion of the steam cracker H2 feed stream; (b) at least a portion of the steam cracker H2 feed stream; and (c) a combined feed stream of (a) and (b); and burning the boiler fuel gas to supply heat energy to one or more boilers.

[0193] The methods in A9 and A8, wherein one or more boilers combined produce no more than 10% of the total HPS feed stream consumed by the olefin production facility.

[0194] The method of any one of A1 to A7, wherein the olefin production facility does not include a boiler that generates steam consumed by the olefin production facility.

[0195] The method of any one of A11, A6 to A10, wherein the H2-rich feed stream and the steam cracker H2 feed stream together provide at least 60% of the total fuel gas required by the olefin production facility, based on Btu.

[0196] A12. The method of claim A11, wherein the H2-rich feed stream provides at least 60% of the total fuel gas required for the operation of the olefin production facility, based on Btu.

[0197] A13. The method of any one of A1 to A12, wherein the HPS flow generated in step (II) has an absolute pressure of 4,000 kPa to 14,000 kPa, and the method further includes:

[0198] (XV) Heating the HPS stream to produce a superheated HPS (“SH-HPS”) stream with a temperature of 350°C-550°C; and

[0199] (XVI) At least a portion of the SH-HPS feed stream is supplied to at least one first turbine in an olefin production facility, and the SH-HPS feed stream is expanded in the at least one first turbine to generate shaft power and a first expanded steam feed stream.

[0200] The method of A14.A13, wherein in step (XVI), the portion of the SH-HPS feed stream is combined with SH-HPS generated by a steam cracker to form a combined SH-HPS feed stream, and then at least a portion of the combined SH-HPS feed stream is supplied to the first turbine.

[0201] The method of A15, A13 or A14, wherein at least one first steam turbine drives at least one of the following in an olefin production facility: a process gas compressor, a propylene refrigeration compressor, an ethylene refrigeration compressor or a combination thereof.

[0202] The method of any one of A16, A13, A14, and A15, wherein the pressure of the first expanding feed stream is near the pressure of the steam feed to the syngas production unit, and the method further includes:

[0203] At least a portion of the first expanded steam stream is supplied to the syngas production unit as at least a portion of the steam feed.

[0204] The methods described in A17.A13 through A16 also include:

[0205] (XVII) In a second steam turbine in an olefin production facility, at least a portion of the first expanded steam feed is expanded to generate additional shaft power and a second expanded steam feed.

[0206] The methods described in A18.A13 through A17 also include:

[0207] (XVIII) In the third turbine of the olefin production facility, at least a portion of the second expanded steam feed is expanded to generate additional shaft power and a third expanded steam feed.

[0208] A19. The method of any one of A13 to A18, wherein the SH-HPS stream obtained in step (XVI) is a Super-HPS stream, and the stream of the first expansion is an HPS stream, an MPS stream, or an LPS stream.

[0209] The method of any one of A20, A17 to A19, wherein the second expanding steam is an MPS stream or an LPS stream.

[0210] The method of any one of A21, A17 to A20, wherein the third expansion flow is an LPS flow.

[0211] A22. The method of any one of A13 to A21, wherein at least one of the first steam turbine, the second steam turbine and the third steam turbine does not generate a condensable material flow to be supplied to the surface condenser.

[0212] The method of any one of A23 to A13 to A22, wherein step (VII) is performed using an amine CO2 capture device comprising an amine regenerator, and the method further comprises:

[0213] (XIX) A process-heated steam stream is extracted from at least one of the first, second, and third steam turbines, and the process-heated steam stream has an absolute pressure of 200 kPa to 1,050 kPa; and

[0214] (XX) The process heating steam stream is supplied to the amine regenerator to achieve the separation of CO2 stream and H2- rich stream.

[0215] A24. The method of any one of A1 to A23, wherein the olefin production facility includes a combined cycle power facility, the combined cycle power facility includes one or more duct burners that burn duct burner fuel to generate heat energy, and the method further includes burning a portion of the H2-rich feed stream and / or a portion of the steam cracker H2 feed stream as at least a portion of the duct burner fuel.

[0216] A25. Any of A1 to A24, wherein any steam and any portion of the HPS feed stream generated in the olefin production facility is not supplied to the turbine driving the generator.

[0217] The method of any one of A26, A27 to A25, wherein the H2-rich feed stream and the steam cracker H2 feed stream together provide at least 60% of the total combustion fuel required for the operation of the olefin production facility, based on Btu.

[0218] A27. Any of A1 to A26, wherein a single water demineralization facility provides all the water required to generate steam in H2-rich gas production facilities and olefin production facilities.

[0219] A28. The method of any one of A1 to A27, wherein the reformate stream has at least one of the following: a temperature of 750°C to 1,200°C and an absolute pressure of 700 kPa to 5000 kPa.

[0220] A29. The method of any one of A1 to A28, wherein the cooled reformate stream produced in step (II) has a temperature of 285°C to 400°C.

[0221] The method of any one of A30.A1 to A29, wherein in step (III), the first change flow has at least one of the following: a temperature of 335°C to 500°C and an absolute pressure of 700 kPa to 5,000 kPa.

[0222] A31. A1 to A30, wherein step (IV) comprises cooling a first conversion stream via a heat exchanger by means of a cooling stream selected from: a stream containing hydrocarbon feed, a boiler feed stream, and combinations thereof.

[0223] A32. The method of any one of A1 to A31, wherein the cooled first transformation stream has at least one of the following: a temperature of 150°C to 250°C and an absolute pressure of 700 kPa to 5,000 kPa.

[0224] A33. The method of any one of A1 to A32, wherein in step (V), the second conversion stream has at least one of the following: a temperature of 150°C to 300°C, an absolute pressure of 700 kPa to 5000 kPa, and a CO concentration of not more than 5.0 mol%, based on the total number of moles of molecules in the second conversion stream.

[0225] A34. The method of any one of A1 to A33, wherein step (VI) includes:

[0226] (VIa) Cooling the second shift feed stream to condense a portion of the vapor in the second shift feed stream to form liquid water and obtain a cooled second shift feed stream; and

[0227] (VIb) Separate liquid water from a cooled second conversion stream to obtain a crude gas mixture stream.

[0228] A35. The method of any of the preceding claims, wherein step (VII) comprises at least one of the following:

[0229] (VII.1) At least a portion of the gas mixture is separated by using an amine absorption and regeneration process;

[0230] (VI I.2) Separating at least a portion of a gas mixture by using a low-temperature CO2 separation process;

[0231] (VII.3) Separating at least a portion of a gas mixture by using a membrane separation process; and

[0232] (VII.4) Separate at least a portion of the gas mixture by using physical absorption and regeneration processes.

[0233] A36. The method of any one of A1 to A35, wherein step (VII) includes the following:

[0234] (VIIa) Obtaining a discharge steam flow and shaft power with an absolute pressure of 200 kPa to 1,050 kPa from one or more pumped turbines and / or back-pressure turbines (preferably one or more back-pressure turbines) located in an olefin production facility.

[0235] (VIIb) Feed the crude gas mixture stream and the lean amine stream containing amine into the absorption column;

[0236] (VIIc) Obtain a CO2-rich amine feed stream and a CO2-depleted residual gas stream from the absorption column;

[0237] (VIId) Feed at least a portion of the CO2-rich amine feed stream into the separation column;

[0238] (VIIe) In a separation column, at least a portion of the CO2-rich amine stream is heated using the effluent steam stream to produce a CO2-rich top stream and an amine-rich bottom stream; and

[0239] (VIIf) At least a portion of the bottom feed stream is recycled to the absorption column as at least a portion of the lean amine feed stream.

[0240] A37. The method of any one of A1 to A36, wherein the syngas production apparatus includes a steam-methane-reformer (“SMR”) and / or an autothermal reformer (“ATR”).

[0241] The method in A38.A37, wherein:

[0242] Syngas production units include SMR;

[0243] An SMR comprises: one or more SMR burners in which SMR fuel is burned to supply heat to the SMR; a thermally heated radiant section in which the hydrocarbon feed and steam react under syngas production conditions; and a thermally heated convection section in which the hydrocarbon feed and steam are preheated before entering the radiant section; and

[0244] In step (VII), a portion of the H2-rich feed stream and / or a portion of the steam cracker H2 feed stream is supplied to multiple SMR burners as at least a portion of the reforming fuel gas.

[0245] The method of A39.A38, wherein step (XV) is performed, and in step (XV), the HPS stream is heated in the convection section of the SMR and / or in the auxiliary furnace to obtain the SH-HPS stream.

[0246] The method in A40.A37, wherein:

[0247] Syngas production units include an ATR;

[0248] The O2 feed stream is fed into the ATR;

[0249] ATR includes a reaction vessel into which hydrocarbon feed, steam feed and O2 stream are supplied;

[0250] Syngas production conditions include the presence of an ATR catalyst in the reaction vessel; and

[0251] The reformed material stream has at least one of the following: a temperature of 800℃-1,200℃ and an absolute pressure of 700kPa-5000kPa.

[0252] The method of A41.A40, wherein step (XV) is performed, and in step (XV), the HPS stream is heated in an auxiliary furnace to obtain the SH-HPS stream.

[0253] A42. Methods, including:

[0254] (1) A hydrocarbon feed and a steam feed are supplied to a syngas production unit containing a reforming reactor under syngas production conditions to generate a reformate stream leaving the reforming reactor, wherein the syngas production conditions include the presence of a reforming catalyst and the reformate stream contains H2, CO and steam.

[0255] (2) A cooled reformate stream and a high-pressure steam ("HPS") stream are generated by using a waste heat recovery unit ("WHRU");

[0256] (3) In the first shift reactor, the cooled reformate stream is brought into contact with the first shift catalyst under the first set of shift conditions to generate a first shift stream leaving the first shift reactor, wherein the first shift stream has a lower CO concentration and a higher CO2 concentration than the cooled reformate stream.

[0257] (4) Cool the first conversion stream to obtain a cooled first conversion stream;

[0258] (5) In the second shift reactor, under the second set of shift conditions, the cooled first shift feed stream is brought into contact with the second shift catalyst to generate a second shift feed stream leaving the second shift reactor, wherein the second shift feed stream has a lower CO concentration and a higher CO2 concentration than the cooled first shift feed stream.

[0259] (6) Reduce the steam present in the second conversion stream to generate a crude gas mixture stream containing CO2 and H2;

[0260] (7) Recover at least a portion of the CO2 present in the crude gas mixture stream to produce a CO2 stream and an H2-rich stream, wherein the H2-rich stream contains H2 at a concentration of at least 80 mol%, based on the total number of moles of molecules in the H2-rich stream;

[0261] (8) Combustion of a portion of the H2-rich feed stream in a steam pyrolysis unit located in an olefin production facility to generate heat and produce a flue gas stream containing CO2 at a concentration of no more than 20 mol%, based on the total number of moles of H2O and CO2 in the flue gas stream, wherein the steam pyrolysis unit operates under steam pyrolysis conditions to convert the steam pyrolysis feed into a steam pyrolysis effluent containing olefins.

[0262] (9) A CH4---rich feed stream is generated from the steam pyrolysis effluent; and

[0263] (10) Provide a CH4--rich feed stream as at least a portion of the hydrocarbon feed.

[0264] The method in A43.A42, wherein:

[0265] Syngas production units include SMR;

[0266] An SMR comprises: one or more SMR burners in which SMR fuel is burned to supply heat energy to the SMR; a thermally heated radiant section in which hydrocarbon feed and steam react under syngas production conditions; a thermally heated convection section in which the hydrocarbon feed and steam are preheated before entering the radiant section; and the method further comprises:

[0267] (11) A portion of the H2-rich feed stream is burned in multiple SMR burners as at least a portion of the SMR fuel.

[0268] The foregoing defines various terms. Where a term used in the claims is not defined above, it shall be given the broadest definition already provided to a person skilled in the art, as reflected in at least one printed publication or authorized patent. Furthermore, for all jurisdictions where such inclusion is permissible, all patents, test procedures, and other documents referenced in this application are fully incorporated by reference, provided that such disclosure does not contradict this application.

[0269] While the foregoing relates to embodiments of the invention, other and further embodiments of the invention may be devised without departing from the basic scope of the invention, the scope of which is defined by the appended claims.

Claims

1. A method for integrating hydrogen-rich fuel gas production with olefin production facilities, including: (I) Supplying hydrocarbon feed and steam feed to a syngas production unit containing a reforming reactor under syngas production conditions to generate a reformate stream leaving the reforming reactor, wherein the syngas production conditions include the presence of a reforming catalyst and the reformate stream contains H2, CO and steam. (II) A cooled reformate stream and a high-pressure steam HPS stream are generated by using a waste heat recovery unit (WHRU) to cool the reformate stream. (III) In the first shift reactor, under the first set of shift conditions, the cooled reformate stream is brought into contact with the first shift catalyst to generate a first shift stream leaving the first shift reactor, wherein the first shift stream has a lower CO concentration and a higher CO2 concentration than the cooled reformate stream. (IV) Cooling the first conversion stream to obtain a cooled first conversion stream; (V) In the second shift reactor, under the second set of shift conditions, the cooled first shift feed stream is brought into contact with the second shift catalyst to generate a second shift feed stream leaving the second shift reactor, wherein the second shift feed stream has a lower CO concentration and a higher CO2 concentration than the cooled first shift feed stream; (VI) Reduce the steam present in the second conversion stream to produce a crude gas mixture stream containing CO2 and H2; (VII) Recovering at least a portion of the CO2 present in the crude gas mixture stream to produce a CO2 stream and an H2-rich stream, wherein the H2-rich stream contains H2 at a concentration of at least 80 mol% based on the total number of moles of molecules in the H2-rich stream; and (VIII) A portion of the H2-rich feed stream is supplied to an olefin production facility containing a steam cracker as at least a portion of the steam cracker fuel gas, and the steam cracker fuel gas is burned to provide heat energy to the steam cracker.

2. The method according to claim 1, wherein the H2-rich stream further comprises H2 at a concentration of at least 85 mol% and at least one of the following: ≤5 mol% CH4, ≤3 mol% CO, and ≤1 mol% CO2, based on the total number of moles of molecules in the H2-rich stream.

3. The method according to claim 1 or claim 2, further comprising: (IX) A CH4----rich feed stream is generated from the steam pyrolysis effluent; and (X) Provide at least a portion of the CH4--rich feed stream as at least a portion of the hydrocarbon feed.

4. The method of claim 3, wherein the CH4-rich stream comprises at least one of the following: ≤40 mol% H2, ≤10 mol% ethane, and ≤5 mol% CO, based on the total number of moles of molecules in the CH4-rich stream.

5. The method according to claim 3, wherein the absolute pressure of the CH4--rich feed stream is higher than the absolute pressure of the hydrocarbon feed supplied to the syngas production unit in step (I), and step (X) comprises: (Xa) The CH4--rich feed stream is expanded by a turboexpander and / or a Joule-Thompson valve to produce a cooled CH4--rich feed stream with a pressure near that of the hydrocarbon feed. (Xb) A heated CH4-rich feed stream is generated by heating and cooling a CH4--rich feed stream via a heat exchanger in an olefin production facility; and (Xc) provides at least a portion of a heated CH4--rich feed stream as at least a portion of the hydrocarbon feed.

6. The method according to claim 1 or claim 2, further comprising: (XI) Generating H2 feed stream from the steam cracker at the olefins production facility; and (XII) At least one of the following is supplied to the syngas production unit as at least a portion of the reforming fuel gas: (a) at least a portion of the H2-rich feed stream; (b) at least a portion of the H2 feed stream from the steam cracker; and (c) a combined feed stream of (a) and (b).

7. The method according to claim 1, further comprising: (XI) Generating H2 feed stream from the steam cracker at the olefins production facility; and (XIII) At least one of the following shall be supplied to the steam cracker as at least a portion of the steam cracker fuel gas: (a) at least a portion of the H2-rich feed stream; (b) at least a portion of the steam cracker H2 feed stream; and (c) a combined feed stream of (a) and (b).

8. The method according to claim 1, further comprising: (XI) Generating H2 feed stream from the steam cracker at the olefins production facility; and (XIV) At least one of the following shall be supplied as boiler fuel gas to one or more boilers located in an olefin production facility: (a) at least a portion of an H2-rich feed stream; (b) at least a portion of a steam cracker H2 feed stream; and (c) a combined feed stream of (a) and (b); It also burns boiler fuel gas to supply heat energy to one or more boilers.

9. The method according to claim 7 or claim 8, wherein the H2-rich feed stream and the steam cracker H2 feed stream together provide at least 60% of the total fuel gas required by the olefin production facility, based on Btu.

10. The method of claim 9, wherein the H2-rich feed stream and the steam cracker H2 feed stream together provide at least 80% of the total fuel gas required for the operation of the olefin production facility, based on Btu.

11. The method of claim 9, wherein the H2-rich feed stream provides at least 60% of the total fuel gas required for the operation of the olefin production facility, based on Btu.

12. The method according to claim 1 or claim 2, wherein the HPS stream generated in step (II) has an absolute pressure of 4,000 kPa to 14,000 kPa, and the method further comprises: (XV) Heating the HPS feed stream generates superheated high-pressure steam SH-HPS feed stream with a temperature of 350℃-550℃; and (XVI) At least a portion of the SH-HPS feed stream is supplied to at least one first turbine in an olefin production facility, and the SH-HPS feed stream is expanded in the at least one first turbine to generate shaft power and a first expanded steam feed stream.

13. The method of claim 12, wherein in step (XVI), an SH-HPS stream is generated by a steam pyrolyzer, at least a portion of the SH-HPS stream is combined with the SH-HPS stream generated by the steam pyrolyzer to form a combined SH-HPS stream, and then at least a portion of the combined SH-HPS stream is supplied to a first steam turbine.

14. The method of claim 12, wherein at least one first steam turbine drives at least one of the following in an olefin production facility: a process gas compressor, a propylene refrigeration compressor, an ethylene refrigeration compressor, and combinations thereof.

15. The method of claim 12, wherein the pressure of the first expanding feed stream is near the pressure of the steam feed to the syngas production unit, and the method further comprises: At least a portion of the first expanded steam stream is supplied to the syngas production unit as at least a portion of the steam feed.

16. The method of claim 12, further comprising: (XVII) In a second steam turbine in an olefin production facility, at least a portion of the first expanded steam feed is expanded to generate additional shaft power and a second expanded steam feed.

17. The method of claim 12, wherein the SH-HPS feed stream supplied in step (XVI) is an ultra-high pressure steam Super-HPS feed stream, and the first expansion feed stream is a high pressure steam HPS feed stream, a medium pressure steam MPS feed stream, or a low pressure steam LPS feed stream.

18. The method of claim 16, wherein the second expanding steam stream is an MPS stream or an LPS stream.

19. The method of claim 12, wherein at least one of the first turbine and the second turbine does not generate a condensable feed stream supplied to the surface condenser.

20. The method of claim 12, wherein step (VII) is performed using an amine CO2 capture device comprising an amine regenerator, and the method further comprises: (XIX) A process heating steam stream is extracted from at least one of the first, second, and third steam turbines, and the process heating steam stream has an absolute pressure of 200 kPa to 1,050 kPa; and (XX) The process heating steam stream is supplied to the amine regenerator to achieve the separation of CO2 stream and H2- rich stream.

21. The method of claim 1 or claim 2, wherein the olefin production facility comprises a combined cycle power facility comprising one or more duct burners that burn duct burner fuel to generate heat, and the method further comprises burning a portion of the H2-rich feed stream and / or a portion of the steam cracker H2 feed stream as at least a portion of the duct burner fuel.

22. The method of claim 17, wherein the H2-rich feed stream and the steam cracker H2 feed stream together provide at least 60% of the total combustion fuel required for the operation of the olefin production facility, based on Btu.

23. The method of claim 1 or claim 2, wherein a single water demineralization facility provides all the water required for steam generation in the H2-rich gas production facility and the olefin production facility.

24. Methods for integrating hydrogen-rich fuel gas production with olefin production facilities, including: (1) A hydrocarbon feed and a steam feed are supplied to a syngas production unit containing a reforming reactor under syngas production conditions to generate a reformate stream leaving the reforming reactor, wherein the syngas production conditions include the presence of a reforming catalyst and the reformate stream contains H2, CO and steam. (2) A cooled reformate stream is generated by using a waste heat recovery unit (WHRU) to cool the reformate stream and generate a high-pressure steam HPS stream. (3) In the first shift reactor, the cooled reformate stream is brought into contact with the first shift catalyst under the first set of shift conditions to generate a first shift stream leaving the first shift reactor, wherein the first shift stream has a lower CO concentration and a higher CO2 concentration than the cooled reformate stream. (4) Cool the first conversion stream to obtain a cooled first conversion stream; (5) In the second shift reactor, under the second set of shift conditions, the cooled first shift feed stream is brought into contact with the second shift catalyst to generate a second shift feed stream leaving the second shift reactor, wherein the second shift feed stream has a lower CO concentration and a higher CO2 concentration than the cooled first shift feed stream. (6) Reduce the steam present in the second conversion stream to generate a crude gas mixture stream containing CO2 and H2; (7) Recover at least a portion of the CO2 present in the crude gas mixture stream to produce a CO2 stream and an H2-rich stream, wherein the H2-rich stream contains H2 at a concentration of at least 80 mol% based on the total number of moles of molecules in the H2-rich stream; (8) Combustion of a portion of the H2-rich feed stream in a steam pyrolysis unit located in an olefin production facility to generate heat and produce a flue gas stream containing CO2 at a concentration of no more than 20 mol%, based on the total number of moles of H2O and CO2 in the flue gas stream, wherein the steam pyrolysis unit operates under steam pyrolysis conditions to convert the steam pyrolysis feed into a steam pyrolysis effluent containing olefins. (9) A CH4---rich feed stream is generated from the steam pyrolysis effluent; and (10) Provide a CH4--rich feed stream as at least a portion of the hydrocarbon feed.

25. The method of claim 24, wherein: Syngas production units include steam-methane reformers (SMRs). An SMR comprises: one or more SMR burners in which SMR fuel is burned to supply heat energy to the SMR; and a radiant section heated by the heat energy, in which hydrocarbon feed and steam react under syngas production conditions. The method further includes: preheating the hydrocarbon feed and steam in a convection section heated by thermal energy before they enter the radiation section; and the method also includes: (11) A portion of the H2-rich feed stream is burned in multiple SMR burners as at least a portion of the SMR fuel.

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