Clean Liquid Fuel Hydrogen Carrier Process

Abstract

The present disclosure, in one embodiment, refers to a process for producing and transporting clean hydrogen fuel. The process may include hydrotreating, hydrocracking, or both hydrotreating and hydrocracking an aromatic feedstock under conditions to obtain a liquid hydrocarbon fuel. The liquid hydrocarbon fuel is hydrogenated to obtain a hydrogen-rich fuel that is transported to a dehydrogenation facility, which may also be at or near a hydrogen station. The hydrogen-rich fuel is used to obtain hydrogen and a second liquid hydrocarbon fuel.

Description

[Technical field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims priority to U.S. patent application Ser. No. 17 / 516,049, filed Nov. 1, 2021, the entire disclosure of which is incorporated herein by reference.

[0002] The present disclosure relates to a clean liquid fuel hydrogen carrier process. [Background technology]

[0003] Hydrogen is widely considered to be a clean fuel, for example when consumed in fuel cells, since water is the only by-product. Hydrogen can be produced by a variety of processes and from readily available resources, including, for example, natural gas, biomass, and nuclear power. Thus, hydrogen can potentially be used in automotive and power generation applications. Unfortunately, the world has been slow to adopt hydrogen applications, mainly because the storage and transportation of hydrogen from its production site to, for example, hydrogen gas stations, is very costly.

[0004] What is needed are new methods of producing and / or transporting hydrogen. It would be advantageous if such methods were cost-effective. It would also be advantageous if such methods could be employed using existing refinery processes and equipment. It would be further advantageous if the hydrogen produced had relatively low amounts of impurities such as sulfur, light hydrocarbon gases such as C1-C4 hydrocarbons, and / or CO. Additionally or alternatively, it would be desirable if the new process did not require, for example, recycling of hydrogen carriers, and / or if the hydrogen could be transported, for example, using existing distribution infrastructure (e.g., shipping ships, trucks, etc.).

[0005] The present application relates to new methods of producing and / or transporting hydrogen. Advantageously, the methods may be cost-effective and / or may be employed using existing refinery processes and equipment. Furthermore, the hydrogen produced may have relatively low amounts of impurities, such as sulfur. Also, in many embodiments, the process does not require recycling of the hydrogen carrier, which may of course be sold as a product if not recycled. Furthermore, hydrogen produced by the methods described herein may be transported, for example, using existing distribution infrastructure.

[0006] The present application relates in one embodiment to a process that includes hydrotreating, hydrocracking, or both hydrotreating and hydrocracking an aromatic feedstock under conditions to obtain a liquid hydrocarbon fuel having less than about 30 ppm sulfur and about 13.5 wt.% hydrogen. The liquid hydrocarbon fuel is hydrogenated under conditions to obtain a hydrogen-rich fuel having less than about 5 ppm sulfur and greater than about 13.5 wt.% hydrogen. The hydrogen-rich fuel is transported to a dehydrogenation facility where it is dehydrogenated under conditions to obtain hydrogen and a second liquid hydrocarbon fuel having less than about 5 ppm sulfur and less than about 13.5 wt.% hydrogen.

[0007] In another embodiment, the present application relates to a process that includes hydrogenating an aromatic feedstock containing less than 50 ppm sulfur under conditions to obtain a hydrogen-rich fuel containing less than about 1 ppm sulfur and greater than about 13.5 wt.% hydrogen. The hydrogen-rich fuel is transported to a dehydrogenation facility where it is dehydrogenated under conditions to obtain hydrogen and a second liquid hydrocarbon fuel containing less than about 5 ppm sulfur and less than about 13.5 wt.% hydrogen.

[0008] These and other objects, features, and advantages of the exemplary embodiments of the present disclosure will become apparent from a reading of the following detailed description of the exemplary embodiments of the present disclosure, when taken in conjunction with the appended claims.

[0009] The various embodiments of the present disclosure, together with further objects and advantages, may best be understood by reference to the following description taken in conjunction with the accompanying drawings, in which: [Brief description of the drawings]

[0010] [Figure 1] 1 illustrates an exemplary production and delivery of hydrogen to a hydrogen station or other desired facility. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0011] The following description of the embodiments provides non-limiting representative examples to specifically describe the features and teachings of different aspects of the present invention. It should be recognized that the described embodiments can be implemented separately or in combination with other embodiments from the description of the embodiments. Those skilled in the art who review the description of the embodiments should be able to learn and understand the different described aspects of the present invention. The description of the embodiments should facilitate the understanding of the present invention to the extent that other implementations are understood to be consistent with the application of the present invention within the knowledge of those skilled in the art who read the description of the embodiments, although not specifically covered.

[0012] definition Unless otherwise stated, the following terms, terminology, and definitions are applicable to this disclosure. If a term is used in this disclosure but is not specifically defined herein, the definition from the IUPAC Compendium of Chemical Terminology, 2nd ed (1997) may be applied, provided that such definition does not conflict with any other disclosure or definition applied herein or render any claim to which it applies unclear or unacceptable. In the event that any definition or usage set forth in any document incorporated herein by reference conflicts with the definition or usage set forth herein, the definition or usage set forth herein shall apply.

[0013] "Processing," "processed," "upgrade," "upgraded," and "upgraded," when used in conjunction with an oil feed, describe a hydrotreated or hydroprocessed feedstock, or a resulting material or crude product, having a reduced feed molecular weight, a reduced feed boiling range, a reduced concentration of asphaltenes, a reduced concentration of hydrocarbon free radicals, and / or a reduced amount of impurities such as sulfur, nitrogen, oxygen, halides, and metals.

[0014] "Hydroprocessing" refers to a process in which a carbonaceous feedstock is contacted with hydrogen and a catalyst at higher temperatures and pressures for the purpose of removing undesirable impurities and / or converting the feedstock into desired products. Examples of hydroprocessing processes include hydrocracking, hydrotreating, catalytic dewaxing, and hydrofinishing.

[0015] "Hydrocracking" refers to processes in which hydrogenation and dehydrogenation involve the cracking / fragmentation of hydrocarbons, e.g., converting heavier hydrocarbons to lighter hydrocarbons or converting aromatics and / or cycloparaffins (naphthenes) to non-cyclic branched paraffins.

[0016] "Hydrotreating" refers to the process of converting a sulfur- and / or nitrogen-containing hydrocarbon feed into hydrocarbon products having reduced sulfur and / or nitrogen content, typically in conjunction with hydrocracking, and producing hydrogen sulfide and / or ammonia (respectively) as by-products. Such processes or steps carried out in the presence of hydrogen include hydrodesulfurization, hydrodenitrogenation, hydrodemetallization, and / or hydrodearomatization of components (e.g., impurities) of the hydrocarbon feedstock, and / or hydrogenation of unsaturated compounds in the feedstock. Depending on the type of hydrotreating and reaction conditions, the products of the hydrotreating process may exhibit, for example, improved viscosity, viscosity index, saturates content, low temperature properties, volatility, and depolarization.

[0017] "Hydrocarbonaceous," "hydrocarbon," and similar terms refer to compounds containing only carbon and hydrogen atoms. When a particular group is present in the hydrocarbon, other identifiers may be used to indicate the presence of that particular group (e.g., a halogenated hydrocarbon indicates the presence of one or more halogen atoms replacing an equal number of hydrogen atoms in the hydrocarbon).

[0018] The term "periodic table" refers to the version of the IUPAC Periodic Table of the Elements dated June 22, 2007, where the numbering scheme for the periodic table groups is as set forth in Chem. Eng. News, 63(5), 26-27 (1985). "Group 2" refers to the IUPAC Group 2 elements, such as magnesium (Mg), calcium (Ca), strontium (Sr), barium (Ba), and combinations thereof, either in their elemental, compound, or ionic form. "Group 6" refers to the IUPAC Group 6 elements, such as chromium (Cr), molybdenum (Mo), and tungsten (W). "Group 7" refers to the IUPAC Group 7 elements, such as manganese (Mn), rhenium (Re), and combinations thereof, either in their elemental, compound, or ionic form. "Group 8" refers to the IUPAC Group 8 elements, such as iron (Fe), ruthenium (Ru), osmium (Os), and combinations thereof, in either their elemental, compound, or ionic form. "Group 9" refers to the IUPAC Group 9 elements, such as cobalt (Co), rhodium (Rh), iridium (Ir), and combinations thereof, in either their elemental, compound, or ionic form. "Group 10" refers to the IUPAC Group 10 elements, such as nickel (Ni), palladium (Pd), platinum (Pt), and combinations thereof, in either their elemental, compound, or ionic form. "Group 14" refers to the IUPAC Group 14 elements, such as germanium (Ge), tin (Sn), lead (Pb), and combinations thereof, in either their elemental, compound, or ionic form. The term "support", particularly when used in the term "catalyst support", refers to a conventional material, typically a solid with a high surface area, on which a catalytic material is attached. The support material may be inert or may participate in the catalytic reaction, and may be porous or non-porous.Typical catalyst supports include various types of carbon, alumina, silica and silica-alumina, such as amorphous silica aluminates, zeolites, alumina-boria, silica-alumina-magnesia, silica-alumina-titania, as well as materials obtained by adding other zeolites and other complex oxides.

[0019] "Molecular sieve" refers to a material having uniform pores of molecular dimensions within a framework structure; depending on the type of molecular sieve, only certain molecules can access the pore structure of the molecular sieve, while other molecules are excluded, for example, due to molecular size and / or reactivity. The terms "molecular sieve" and "zeolite" are synonymous and include (a) intermediate, and (b) final or end molecular sieves, as well as molecular sieves produced by (1) direct synthesis or (2) post-crystallization treatment (secondary modification). Secondary synthesis methods allow the synthesis of end materials from intermediate materials by heteroatom lattice substitution or other methods. For example, aluminosilicates can be synthesized from intermediate borosilicates by post-crystallization heteroatom lattice substitution of Al for B. Such techniques are known, for example, as described in U.S. Pat. No. 6,790,433. Zeolites, crystalline aluminophosphates, and crystalline silicoaluminophosphates are representative examples of molecular sieves.

[0020] In this disclosure, compositions and methods or processes are often described in terms of "comprising" various components or steps, but the compositions and methods can also "consist essentially of" or "consist of" the various components or steps, unless specified otherwise.

[0021] The terms "a," "an," and "the" are intended to include multiple alternatives, e.g., at least one. For example, disclosure of a "transition metal" or an "alkali metal" is meant to encompass one transition metal or alkali metal, or mixtures or combinations of multiple transition metals or alkali metals, unless otherwise specified.

[0022] All numerical values ​​within the detailed description and claims herein are modified by "about" or "approximately" the indicated value to account for experimental error and variations that would be expected by one of ordinary skill in the art.

[0023] General process The process of the present application varies depending on the available feedstock, equipment, and desired products. Although many different feedstocks can be used, the process typically uses aromatic feedstocks such as light cycle oil from a refinery aromatic rich stream, i.e., from a fluid catalytic cracking process stream. The properties of an aromatic feedstock such as light cycle oil can vary depending on the origin of the stream and its previous processing, if any. Other aromatic rich hydrocarbons are diesel products from cokers, residual desulfurization (RDS), and the like. In one embodiment, the aromatic rich hydrocarbon feedstock contains at least 50% ring compounds (e.g., aromatics and naphthenes). In one embodiment, it contains at least 60% ring compounds. It is preferred to have at least 65% ring compounds. Thus, the suitable density, sulfur content, cetane number, boiling point, aromatic content, and other properties of an aromatic feedstock such as light cycle oil can vary depending on the feedstock. The suitable density of the aromatic feedstock varies, and for light cycle oil or other aromatic feedstocks, the density is about 900 to about 960 kg / m 3 (Approx. 56 to 60 lbs / ft 3). Depending on the nature of the aromatic feedstock, it may contain sulfur or sulfur compounds. In some embodiments, the light cycle oil or other aromatic feedstock may contain greater than about 1000 ppm, or greater than about 2000 ppm, or even greater than about 5,000 ppm, although lower sulfur contents may be desirable. In some embodiments, the light cycle oil or other aromatic feedstock may contain nitrogen or nitrogen compounds. In some embodiments, the light cycle oil or other aromatic feedstock may contain a cetane number greater than about 20, or greater than about 25, up to about 30, or up to about 35, or up to about 40. The boiling point of the light cycle oil or other aromatic feedstock will vary depending on the particular process used, but in some embodiments, the boiling point may be less than about 430° C. (about 806° F.) or less than about 400° C. (about 752° F.) by ASTM D-86.

[0024] Hydrotreating / Hydrocracking The aromatic feedstock may be subjected to hydrotreating, hydrocracked, or both hydrotreating and hydrocracked under conditions to obtain a clean liquid hydrocarbon fuel that may meet specifications for use as, for example, diesel or aviation fuel. The properties of the resulting liquid hydrocarbon fuel may vary, but often contain less than about 60 ppm, less than about 50 ppm, or less than about 40 ppm, or less than about 30 ppm, or less than about 20 ppm sulfur, and / or less than about 10 ppm, or less than about 5 ppm, or less than 10 ppm N, or less than about 13.5 wt.% hydrogen. The liquid hydrocarbon fuel may in some cases be referred to as a clean liquid HC fuel, as shown in FIG. 1. In some cases, the aromatic feedstock may already contain sufficiently similar properties to the desired liquid hydrocarbon fuel, e.g., less than 50 ppm sulfur, so that hydrotreating and / or hydrocracking may not be necessary. In such cases, the aromatic feedstock may be directly hydrogenated without hydrotreating and / or hydrocracking the liquid hydrocarbon fuel.

[0025] Typically, for either hydrotreating or hydrocracking, the reaction temperature is from about 250° C. (482° F.) to about 500° C. (932° F.), the pressure is from about 3.5 MPa (500 psi) to about 24.2 MPa (3,500 psi), and the reaction time is from about 0.1 to about 20 hours. -1 The feed rate (oil volume / catalyst volume hr) may be 1000 sq. m. / kg oil (2,310 standard cubic feet / barrel; SCF / B) to 1780 standard liters H2 / kg oil (11,750 standard cubic feet / barrel). The preferred reaction temperature may range from about 340° C. (644° F.) to about 455° C. (851° F.). The preferred total reaction pressure may range from about 7.0 MPa (1,000 psi) to about 20.7 MPa (3,000 psi). The reactor may also be operated in any suitable catalyst bed arrangement mode, such as fixed bed, slurry bed, or ebulating bed, although fixed bed, cocurrent downflow is often utilized.

[0026] In one embodiment, the process operates by directing a feedstock, which may contain high levels of sulfur and nitrogen, to an initial hydrotreating reaction stage to convert a significant amount of the sulfur and nitrogen in the feed to inorganic forms, the primary objective of this step being the reduction of the feedstock sulfur content. Of course, if hydrotreating is not required, the feed may be passed directly to hydrocracking or hydrotreating.

[0027] The hydrotreating step is usually carried out in one or more reaction zones (catalyst beds) in the presence of hydrogen and a hydrotreating catalyst. The conditions used are suitable for hydrodesulfurization and / or denitrogenation, depending on the feed characteristics. If hydrocracking is used, the product stream is passed to a hydrocracking stage to affect the boiling range conversion. If desired, the hydrotreated and / or hydrocracked liquid hydrocarbon stream, along with hydrotreat gas and other hydrotreating / hydrocracking reaction products, which may include hydrogen sulfide and ammonia, may be passed to a separator, such as a distillation column, where hydrogen, light ends, and inorganic nitrogen and hydrogen sulfide are removed from the hydrocracked liquid product stream. The recycled hydrogen gas may be scrubbed to remove ammonia and may be subjected to an amine scrub to remove hydrogen sulfide, to improve the purity of the recycled hydrogen and to reduce the sulfur level of the product. If desired, a bed of hydrodesulfurization catalyst, such as a bulk polymetallic catalyst, may be provided at some point prior to hydrotreating.

[0028] Hydrotreating Catalyst The conventional hydrotreating catalyst may be any suitable catalyst. Typical conventional hydrotreating catalysts include catalysts consisting of at least one Group VIII metal, preferably Fe, Co, or Ni, more preferably Co and / or Ni, and most preferably Ni, and at least one Group VIB metal, preferably Mo or W, more preferably Mo, on a relatively high surface area support material, preferably alumina. Other suitable hydrodesulfurization catalyst supports include zeolites, amorphous silica-alumina, and titania-alumina. Noble metal catalysts can also be used, preferably where the noble metal is selected from Pd and Pt. Two or more hydrodesulfurization catalysts may be used in different beds in the same reaction vessel. The Group VIII metal is typically present in an amount ranging from about 2 to about 20 wt%, preferably from about 4 to about 12 wt%. The Group VIB metal is typically present in an amount ranging from about 5 to about 50 wt%, preferably from about 10 to about 40 wt%, and more preferably from about 20 to about 30 wt%. All metal weight percentages are based on the weight of the catalyst.

[0029] Hydrocracking Catalyst Examples of conventional hydrocracking catalysts that can be used include nickel, nickel-cobalt-molybdenum, nickel-cobalt-tungsten, nickel-molybdenum-tungsten, cobalt-molybdenum and nickel-tungsten, and / or nickel-molybdenum, the latter two of which are preferred. Non-limiting examples of precious metal catalysts include those based on platinum and / or palladium. Porous support materials that can be used for both precious and non-precious metal catalysts include refractory oxide materials such as alumina, silica, alumina-silica, kieselguhr, diatomaceous earth, magnesia, or zirconia, with alumina, silica, and alumina-silica being preferred and most common. Zeolite supports can also be used, particularly large pore faujasites such as USY and beta zeolites.

[0030] Numerous hydrocracking catalysts are available from different commercial suppliers and may be used according to the feedstock and product requirements, and their functionality may be determined empirically. The choice of hydrocracking catalyst is not critical. Any catalyst having the desired hydrocracking functionality at the selected operating conditions may be used, including conventional hydrocracking catalysts. As described above, hydrotreating and / or hydrocracking are carried out under conditions suitable to obtain a liquid hydrocarbon fuel having the aforementioned characteristics, which may contain, for example, less than about 30 ppm sulfur and less than about 13.5 wt. % hydrogen, if present.

[0031] Hydrogenation The liquid hydrocarbon fuel having the above-described characteristics is then hydrogenated. Hydrogenation conditions can vary, but are typically selected to obtain a hydrogen-rich fuel containing less than about 5, or less than about 2 ppm, or less than about 1 ppm, or about 0 ppm sulfur, with a greater amount of hydrogen than the starting liquid hydrocarbon fuel. Hydrogenation generally does not change the ring structure, but rather converts aromatic compounds to naphthenic compounds. The amount of hydrogen in the resulting hydrogen-rich fuel may be greater than about 13.5 wt%, or greater than about 13.8 wt%, or greater than about 14.0 wt%, or greater than about 14.5 wt%, or even more hydrogen.

[0032] Hydrogenation may be accomplished by any means to achieve the desired hydrogen-rich fuel. In one embodiment, the liquid hydrocarbon fuel may be hydrogenated by reaction with a catalyst and hydrogen gas under conditions that allow for hydrogenation.

[0033] In one embodiment, the hydrogenation catalyst may comprise or consist essentially of supported Group 7, 8, 9, and 10 metals. In some embodiments, the hydrogenation catalyst may be selected from the group consisting of one or more of Ni, Cu, Ag, Pd, Pt, Co, Rh, Fe, Ru, Os, Cr, Sn, Mo, and W supported on silica, alumina, silica-alumina, clay, titania, zirconia, or mixed metal oxide supports. In other embodiments, the hydrogenation catalyst may be nickel supported on diatomaceous earth, platinum and / or palladium supported on alumina, or nickel and / or platinum and / or palladium supported on alumina, alternatively nickel supported on diatomaceous earth, alternatively nickel and / or platinum and / or palladium supported on silica, or alternatively cobalt-molybdenum supported on alumina. In yet other embodiments, the hydrogenation catalyst can be one or more of the group consisting of nickel supported on diatomaceous earth, silica, alumina, clay, or silica-alumina.

[0034] In general, hydrogenation can be carried out in any type of process and / or reactor capable of hydrogenating the hydrogen-rich fuel to the desired properties. In an embodiment, hydrogenation can be carried out in a batch process, a continuous process, or any combination thereof, alternatively a batch process, or alternatively a continuous process. In some embodiments, hydrogenation can be carried out in a slurry reactor, a continuous stirred tank reactor, a fixed bed reactor, or any combination thereof, alternatively a slurry reactor, alternatively a continuous stirred tank reactor, or alternatively a fixed bed reactor.

[0035] If desired, the hydrogenated hydrogen-rich fuel can be filtered to separate the hydrogenation catalyst and / or catalyst fines from the hydrogen-rich fuel. Additionally, the hydrogen-rich fuel can be further refined or distilled to separate the high hydrogen-rich fuel.

[0036] The amount of hydrogenation catalyst utilized may depend on the identity of the hydrogenation catalyst and the particular hydrogenation process utilized. In general, the amount of hydrogenation catalyst used may be any amount capable of producing the desired hydrogen-rich fuel. In non-fixed bed hydrogenation processes (e.g., slurry reactors or continuous stirred tank reactors, among others), the amount of hydrogenation catalyst used in the hydrogenation may range from 0.001 wt.% to 20 wt.%, 0.01 wt.% to 15 wt.%, 0.1 wt.% to 10 wt.%, or 1 wt.% to 5 wt.%. The weight percent of the hydrogenation catalyst is based on the total weight of the hydrogenation catalyst and the liquid hydrocarbon fuel that has undergone hydrogenation.

[0037] In general, conditions under which liquid hydrocarbon fuels may be hydrogenated may include hydrogen pressure, temperature, contact time, or any combination thereof, alternatively hydrogen pressure and temperature, alternatively hydrogen pressure, temperature, and contact time, alternatively hydrogen pressure, alternatively temperature, or alternatively contact time. In one embodiment, hydrogenation temperatures that may be utilized may range from 25° C. (77° F.) to 350° C. (662° F.), 50° C. (122° F.) to 300° C. (572° F.), 60° C. (140° F.) to 250° C. (482° F.), or 70° C. (158° F.) to 200° C. (392° F.). In one embodiment, the hydrogen pressure that may be utilized may range from 100 kPa (14 psi) to 30 MPa (4351 psi), 250 kPa (36 psi) to 20 MPa (2901 psi), 500 kPa (72 psi) to 10 MPa (1450 psi), or 750 kPa (109 psi) to 5 MPa (725 psi). In one embodiment, the contact time that may be utilized may range from 1 minute to 100 hours, 2 minutes to 50 hours, 5 minutes to 25 hours, or 10 minutes to 10 hours. In a fixed bed process, the WHSV (weight hourly space velocity) of the liquid hydrocarbon fuel over the hydrogenation catalyst may range from 0.1 to 20, 0.5 to 10, or 1 to 5.

[0038] In some embodiments, the hydrotreating step generates significantly more heat than standard hydrotreating, and therefore at least a portion of the heat may be recycled and used, for example, in the hydrotreating / hydrocracking step(s).

[0039] The hydrogen-rich fuel produced by hydrogenation may then be transported if desired.

[0040] transportation If desired, the hydrogen-rich fuel is typically transported to the dehydrogenation facility in any convenient manner. Advantageously, the hydrogen-rich fuel may be transported, for example, using existing distribution infrastructure, including tankers (oil or chemical), container ships, trucks, railroad tank cars, pipelines, and / or any combination thereof.

[0041] dehydrogenation After transportation, the hydrogen-rich fuel is dehydrogenated to obtain hydrogen and a second liquid hydrocarbon fuel. Typically, the dehydrogenation is carried out under conditions to obtain hydrogen and a second liquid hydrocarbon fuel containing less than about 5 ppm, or less than about 2 ppm, or less than about 1 ppm, or less than about 0 ppm sulfur and less than about 13.5 wt. % hydrogen, and requires the addition of a significant amount of heat to achieve the dehydrogenation.

[0042] The hydrogen-rich fuel is typically contacted with the catalyst composite in a dehydrogenation reactor under dehydrogenation conditions. This contacting may be accomplished in a fixed catalyst bed system, a moving catalyst bed system, a fluidized bed system, or a batch type operation. The dehydrogenation reactor itself may contain one or more separate reactor zones with heating means therebetween to ensure that temperatures can be maintained at the inlet to each reaction zone to obtain the desired conversion. The hydrogen-rich fuel may be contacted with the catalyst composite in either an upward, downward, or radial flow mode. The hydrogen-rich fuel may be in the liquid phase, mixed gas phase liquid phase, or gas phase when contacting the catalyst.

[0043] Dehydrogenation conditions vary, with temperatures ranging from about 300°F (149°C) to about 1500°F (816°C), pressures ranging from about 0.1 kPa (0.01 psi) to about 2533 kPa (367 psi), and reaction times ranging from about 0.01 to about 50 hours. -1 The preferred temperatures may include a liquid hourly space velocity (LHSV) of about 0.05 hr. The preferred temperatures may be from about 350°F (177°C) to about 900°F (482°C), more preferably from about 400°F (204°C) to about 800°F (427°C), and more preferably from 450°F (232°C) to 700°F (371°C). The preferred pressures may range from about 10 kPa (1.5 psi) to about 507 kPa (74 psi). Atmospheric pressure is highly suitable for most processes, and generally the pressure in the dehydrogenation zone is kept as low as practicable, consistent with equipment limitations, to maximize the benefits of chemical equilibrium. The preferred LHSV value is about 0.05 hr. -1 ~About 10 hours -1or even more preferably in the range of about 0.1 to about 5 hr. Of course, one skilled in the art will select the desired temperature, pressure, and LHSV depending on the characteristics of the hydrogen-rich fuel and catalyst system utilized.

[0044] If desired, the hydrogen-rich fuel may be mixed with a diluent gas before, during, or after being passed through the dehydrogenation zone. The diluent material may be hydrogen, steam, methane, carbon dioxide, nitrogen, argon, and the like, or mixtures thereof. If a diluent gas is utilized, it is in an amount sufficient to ensure that the molar ratio of diluent gas to hydrocarbon is from about 0.1 to about 20, with best results being obtained when the molar ratio is in the range of from about 1 to 10. The diluted hydrogen stream passed through the dehydrogenation zone is typically recycled after hydrogen is separated from the effluent of the dehydrogenation zone in a hydrogen separation zone.

[0045] The dehydrogenation catalyst composite may exhibit high activity, high selectivity, and good stability. The dehydrogenation catalyst may be the same as or different from the hydrogenation catalyst described above. Particularly preferred catalyst composites of the present disclosure include composites comprising a Group VIII noble metal and a solid inorganic support. Such catalyst composites are well known to those skilled in the art, as represented by U.S. Patent Nos. 3,531,543, 3,631,215, 3,864,284, 3,584,060, 4,191,846, 4,716,143, 4,786,625, 4,827,072, and 4,902,849, the contents of which are incorporated herein by reference. Particularly preferred catalyst composites may include platinum, palladium, nickel, tin, and any combination thereof on an alumina catalyst.

[0046] The dehydrogenated hydrogen-rich fuel results in hydrogen and a second liquid hydrocarbon fuel. If desired, the hydrogen and the second liquid hydrocarbon fuel can be separated. The hydrogen can be stored at the on-site hydrogen station or transported to the hydrogen station. The resulting second liquid hydrocarbon fuel can be recycled in any convenient manner. In one embodiment, recycling the second liquid hydrocarbon fuel includes blending the second liquid hydrocarbon fuel with a liquid hydrocarbon fuel and then hydrogenating the blended liquid hydrocarbon fuel.

[0047] Example 1: LCO properties The physical properties of the LCO feedstock used in this study, i.e., ABQ3034, are shown in Table 1. This LCO contains about 63% aromatics by volume. Approximately 80% by volume of the molecules have ring structures. Its hydrogen content is about 10.7%, and therefore, it is a good feedstock for storing and transporting hydrogen. [Table 1]

[0048] Example 2: LCO hydrotreating and hydrocracking to produce clean liquid fuel CGQ7699 As shown in Table 1, LCO ABQ3034 contains over 2000 ppm S and over 600 ppm N. Both nitrogen and sulfur impurities are removed by hydrotreating to produce clean liquid fuel. Hydrodenitrogenation and hydrodesulfurization were carried out in a single pass standard hydrotreating unit packed with an ISOCRACKING™ catalyst system including converted commercial hydrocracking pretreatment catalyst ICR 514 / 1001 and hydrocracking catalyst ICR 183 under hydrotreating conditions of 0.88 LHSV, 8000 SCF / B, 1400 psia (9653 kPa) hydrogen partial pressure, and 675°F (357°C) catalyst average bed temperature.

[0049] The hydroprocessing product was distilled into two fractions. A diesel range product (380°F+ boiling point, CGQ7699) was selected for the clean liquid fuel hydrogen carrier study. Its physical properties are shown in Table 1. The results in Table 1 show that the LCO-derived clean liquid fuel CGQ7699 produced contained <0.3 ppm N and <5 ppm S. Its hydrogen content is about 13.2 wt.%. About 75% by volume of the hydrocarbons are molecules with ring structures suitable for carrying hydrogen.

[0050] Example 3: Clean Liquid Fuels as Hydrogen Carriers [Table 2]

[0051] The results in Table 2 show that ICR 419 further saturates the aromatics in the clean liquid fuel CGQ7699 to less than 1 wt% in the resulting liquid fuel containing ≧13.9 wt% hydrogen. ICR 419 also shows that it can produce hydrogen from hydrogen-rich liquid fuels by dehydrogenation, resulting in a liquid fuel containing ≦13.2 wt% hydrogen under process conditions.

[0052] Example 4: Clean Liquid Fuels as Hydrogen Carriers [Table 3-1] [Table 3-2]

[0053] The results in Table 3 show that ICR 731 can saturate aromatics in the clean liquid fuel CGQ7699 to less than 1 wt%. The resulting liquid fuel contained ≧13.9 wt% hydrogen. ICR 731 also shows that it can produce hydrogen from the clean liquid fuel resulting in a liquid fuel containing ≦13.0 wt% hydrogen.

[0054] 1 shows an embodiment of the present application in which light cycle oil is hydrotreated and / or hydrocracked into a liquid hydrocarbon fuel that is hydrogenated into a hydrogen-rich clean fuel. The hydrogen-rich clean fuel can then be transported without the recycle required by a liquid organic hydrogen carrier, such as a liquid organic hydrogen carrier (e.g., dibenzyltoluene). After transportation, hydrogen and clean liquid hydrocarbon fuel are produced by dehydrogenation.

[0055] In the foregoing specification, various embodiments have been described. It will be apparent, however, that various modifications and changes may be made and additional embodiments may be implemented without departing from the broader scope of the invention as set forth in the following claims. The specification and drawings are therefore, accordingly, to be regarded in an illustrative rather than a restrictive sense.

Claims

1. A process comprising: hydrotreating, hydrocrack, or both hydrotreating and hydrocrack an aromatic feedstock under conditions to obtain a liquid hydrocarbon fuel containing less than about 30 ppm sulfur and less than about 13.5 wt. % hydrogen; hydrogenating the liquid hydrocarbon fuel under conditions to obtain a hydrogen-rich fuel having less than about 5 ppm sulfur and greater than about 13.5 wt. % hydrogen; transporting the hydrogen-rich fuel to a dehydrogenation facility; dehydrogenating the hydrogen-rich fuel under conditions to obtain hydrogen and a second liquid hydrocarbon fuel having less than about 5 ppm sulfur and less than about 13.5 wt. % hydrogen; separating the hydrogen and the second liquid hydrocarbon fuel; recycling the second liquid hydrocarbon fuel; The process comprising:

2. 10. The process of claim 1, wherein the aromatic feedstock comprises hydrocarbons from a fluid catalytic cracking process.

3. 10. The process of claim 1, wherein the aromatic feedstock comprises light cycle oil.

4. 4. The process of claim 3, wherein the light cycle oil contains greater than about 2,000 ppm sulfur.

5. The light cycle oil has a viscosity of about 900 to about 960 kg / m ３ The process of claim 4 comprising a density of

6. The process of claim 4, wherein the light cycle oil comprises a cetane number of about 20 to about 35.

7. 5. The process of claim 4, wherein the light cycle oil comprises a boiling point of less than about 400° C. by ASTM D-86.

8. 10. The process of claim 1, further comprising transporting the hydrogen to a hydrogen station.

9. 2. The process of claim 1, wherein said recycling said second liquid hydrocarbon fuel comprises blending said second liquid hydrocarbon fuel with a liquid hydrocarbon fuel and then hydrogenating said blended liquid hydrocarbon fuel.

10. 2. The process of claim 1, wherein the conditions used for hydrotreating, hydrocracking, or both hydrotreating and hydrocracking include conditions suitable for removing nitrogen.

11. 10. The process of claim 1 further comprising recycling at least a portion of any heat generated in the hydrogenation step.

12. A process comprising: Hydrogenating an aromatic feedstock containing less than 50 ppm sulfur under conditions to obtain a hydrogen-rich fuel containing less than about 5 ppm sulfur and greater than about 13.5 wt. % hydrogen; transporting said hydrogen-rich fuel to a dehydrogenation facility; dehydrogenating the hydrogen-rich fuel under conditions to obtain hydrogen and a second liquid hydrocarbon fuel having less than about 5 ppm sulfur and less than about 13.5 wt. % hydrogen; separating the hydrogen and the second liquid hydrocarbon fuel; recycling the second liquid hydrocarbon fuel; The process comprising:

13. The process of claim 12 , wherein the aromatic feedstock comprises hydrocarbons from a fluid catalytic cracking process.

14. The process of claim 12 , wherein the aromatic feedstock comprises light cycle oil.

15. 15. The process of claim 14, wherein the light cycle oil contains greater than about 2,000 ppm sulfur.

16. The light cycle oil has a viscosity of about 900 to about 960 kg / m ３ The process of claim 14 comprising a density of

17. The process of claim 14, wherein the light cycle oil comprises a cetane number of about 20 to about 35.

18. 15. The process of claim 14, wherein the light cycle oil comprises a boiling point of less than about 400°C by ASTM D-86.

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