Untitled record

Full description

Sister Ar'a's background

The present disclosure relates to processes and devices for processing petroleum based feeds. More specifically, embodiments of the present disclosure relate to the processing of heavy oils, including crude oils, to form chemical intermediates and products.

<p dir="rtl">5 Petrochemical feeds, such as crude oils, can be converted into chemical intermediates such as ethylene, propylene, butenes, butadiene, and aromatic compounds such as benzene, toluene, and xylene, which are major intermediates. For a large part of the petrochemical industry. 10 They are obtained primarily through thermal cracking (sometimes referred to as “steam pyrolysis” or “steam cracking”) of petroleum gases and distillates such as naphtha, kerosene, or Even oil gas. In addition, petrochemical feedstocks can be converted into transportation fuels such as gasoline, diesel, etc. However, as the demand for these basic intermediate compounds such as fuels increases, production methods other than traditional refining operations must be considered.</p>

US Application No. 1A 2010/155293 is directed to a process for hydrocracking hydrocarbon feedstocks having 200 ppm by weight to 2 wt% asphaltenes/or more than 10 ppm by weight minerals, including hydrodemetallization. Treatment with at least two transferable reaction zones 20, containing a hydrodemetallation catalyst and optionally a hydrodenitrification catalyst catalyst, then hydrorefining treatment to reduce the percentage of organic nitrogen

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content, followed by fixed-bed hydrocracking treatment and a refining step.

US Application No. 1A 2016/369185 is directed to a process for converting high boiling point hydrocarbon feedstock into lower boiling hydrocarbon products, the higher boiling hydrocarbon products being

<p dir="rtl">5 The lighter one is suitable as a feedstock for petrochemical processes. The aforementioned conversion process includes the following steps: feeding the hydrocarbon feedstock with a boiling point &lt; 350 °C to the cascade beds of the hydrocracking unit(s), feeding the bottom stream to the hydrocracking unit as feedstock for the hydrocracking unit(s). Subsequent hydrocracking, where the process conditions for each hydrocracking unit are different from the others, increasing</p>

<p dir="rtl">10 Hydrocracking conditions from the first hydrocracking unit to the next unit in terms of intensity, and treating the lower-boiling hydrocarbon products between each hydrocracking unit as feedstock for one or more petrochemical processes.</p>

US Application No. 1A 2010/018904 is directed to a pre-refining catalytic hydrotreating process for desulfurization, demethylation.

<p dir="rtl">15 Demetallization and upgrading of heavy, sour oils that operate at moderate temperature and pressure by utilizing moving catalyst bed technology.</p>

European Patent No. 1A 1600491 is directed to a process for the catalytic hydrotreatment of crude oil or heavy oil from which the naphtha portion and lighter portions of the naphtha portion are removed by combined exposure of the crude oil or crude oil from which the naphtha portion and portions are removed. lighter than

<p dir="rtl">20 Naphtha portion, for hydroprocessing steps including hydrodemetallization, hydrocracking and hydrodesulfurization, wherein said hydrocracking is carried out in the presence of a catalyst including a carrier made of a composition containing zeolite and ultrafine titanium group metal oxide particles</p>

Of mesopores on the inner surface of mesopore titanium-group metal oxide particles

<p dir="rtl">25 zeolite, a catalytically active component which is based on a carrier and made of at least one element selected from a group consisting of metals belonging to groups 6,</p>

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<p dir="rtl">8, 9 and 10 in the periodic table. According to the process of the present invention, the quality grades of kerosene and gas oil produced may be significantly improved, such that it will be possible to produce ultra-low sulfur kerosene and gas oil having a sulfur content of less than 10 ppm.</p>

General description of the invention

<p dir="rtl">5 There is a need for processes that produce transportation fuels from heavy oil feeds, such as crude oil. In one or more embodiments, catalytic treatment processes (sometimes referred to herein as pretreatment, hydroprocessing, or hydrotreating) and catalysts for use in such processes are described. In one or more embodiments, catalysts for use in such processes are described. Operations Enhanced motivational job performance</p>

<p dir="rtl">10 And, in particular, enhanced aromatic cracking functionality. Through these catalytic processing processes, heavy oils can be upgraded and converted into transport fuels at least by subsequent refining. Refining processing can be performed without any intermediate steps, which reduces the final boiling point of upgraded oil.</p>

The currently described catalytic treatment process (e.g., upgrading) may have a functional performance

<p dir="rtl">15 Enhanced catalysis with respect to reducing at least the aromatic content, metal content, and nitrogen content of the crude oil feedstock, which may subsequently be refined into the desired petrochemical products by a number of different processes described herein. According to one or more embodiments, heavy oils may be treated by four sequentially arranged catalytic converters, where the primary function of the first catalyst (i.e., hydrocarbon demineralization catalyst) is</p>

<p dir="rtl">20 HDM (hydrodemetalization catalyst) is the removal of metals from heavy oil. The basic function of the second catalyst (i.e., the transition catalyst) is to remove metals, sulfur, and nitrogen from heavy oil and provide a transition area between the first and third catalysts. The function The basic components of the third catalyst (i.e., the catalyst for removing nitrogen from hydrocarbons).</p>

HDN (hydrodenitrogenation catalyst) is also the removal of nitrogen, sulfur, or both, and saturation

<p dir="rtl">25 aromatics of heavy oil, and the primary function of the four catalysts (i.e., hydrocracking catalyst) is to reduce the aromatic content in heavy oil. It may</p>

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The pretreatment process as a whole results in one or more increases in the concentration of paraffins, a decrease in the concentration of polynuclear aromatic hydrocarbons, and a decrease in the final boiling point of the pretreated oil relative to the heavy oil feedstock.

After hydroprocessing, the upgraded heavy oil can be further processed

<p dir="rtl">5 By distillation into at least one or more transportation fuels. For example, heavy oil that has been upgraded can be passed directly to the refinery operation for further processing. In additional embodiments, there may be some intermediate steps, but the heavier portion of the upgraded heavy oil may be retained in the stream passed through an atmospheric distillation column for the refining process.</p>

<p dir="rtl">10 According to one embodiment, the heavy oil may be processed by a method which may include upgrading a fraction on</p>

Less than heavy oil to form higher grade oil, where raising the grade involves contacting the heavy oil with a hydrocarbon demineralization catalyst, a transition catalyst, a hydrocarbon denitrification catalyst, and a hydrocarbon cracking catalyst to remove at least a portion of the metals, nitrogen, or content The aromaticity of the heavy oil and the composition of the high grade oil. The process may also include and pass at least a portion

<p dir="rtl">15 From high grade oil to refining process.</p>

According to another embodiment, the heavy oil may be processed by a method which may include upgrading at least a portion of the heavy oil to form a higher grade oil, wherein the upgrading includes contacting the heavy oil with a hydrocarbon demineralization catalyst, a transition catalyst, or a hydrocarbon denitrification catalyst. , and a hydrocarbon cracking catalyst to remove at least a portion of the minerals, nitrogen, or aromatic content 20 from the heavy oil and from the high grade oil. The process may also include passing at least part of...

The oil is raised to a refining process. The final boiling point of superheated oil may be less than or equal to 540°C.

In yet another embodiment, the heavy oil may be processed by a method that may include upgrading at least a portion of the heavy oil to form an upgraded oil, wherein the upgrading includes contact with the heavy oil

<p dir="rtl">25 With a hydrocarbon demineralization catalyst, a transition catalyst, a hydrocarbon denitrification catalyst, and a hydrocarbon cracking catalyst to remove at least a portion of the metal, nitrogen, or aromatic content</p>

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Of heavy oil and high grade oil. The process may also include passing at least a portion of the high grade oil to a refining process. At least the heavier components of higher grade oil can be passed on to the refining process.

Additional features and benefits of the technology described in this disclosure will be identified in the following detailed description,

<p dir="rtl">5 It will be partially readily apparent to those skilled in the art from the description or be understood by practicing the technology as described in this disclosure, including the following detailed description, protection elements, as well as the accompanying drawings.</p>

Brief explanation of the drawings

The following detailed description of specific embodiments of the present disclosure can be better understood when read in conjunction

<p dir="rtl">10 With the following drawings, where the similar structure is indicated by similar reference numbers which have:</p>

Figure 1 depicts a general schematic diagram of a chemical pretreatment system, according to one or more embodiments described in this disclosure;

Figure 2 depicts a general diagram of a chemical pretreatment system that includes a hydrocarbon demineralization catalyst, a transition catalyst, a hydrocarbon denitrification catalyst, and a hydrocarbon cracking catalyst.

<p dir="rtl">15 According to one or more embodiments described in this disclosure;</p>

Figure 3 depicts a general diagram of a chemical pretreatment system comprising a hydrocarbon demineralization catalyst, a transition catalyst, a hydrocarbon denitrification catalyst, and a packed bed pretreatment reactor in the same orientation including a hydrocarbon cracking catalyst, according to one or more embodiments described in This revelation;

<p dir="rtl">20 Figure 4 depicts a general diagram of a chemical pretreatment system comprising a hydrocarbon demineralization catalyst, a transition catalyst, a hydrocarbon denitrification catalyst and a co-directional fluidized bed pretreatment reactor including a hydrocarbon cracking catalyst, according to one or more embodiments described herein detection;</p>

Figure 5 depicts a general block diagram of a chemical treatment system used after a chemical pretreatment system

<p dir="rtl">25 wherein the upgraded heavy oil is fed into a fractionator with some of the resulting stream sent to a hydrocracker, according to one or more embodiments described in this disclosure; And</p>

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Figure 6 depicts a general diagram of another chemical processing system used after the chemical pretreatment system, where high grade heavy oil is fed into a refinery fractionator with some of the resulting stream sent to a fluid catalytic cracking conversion unit (FCC). , according to one or more embodiments described in this disclosure.

<p dir="rtl">5 For the purpose of simplified schematic illustrations and descriptions in Figures 1-6, valves are not included</p>

Numerous valves, temperature sensors, electronic controllers and the like may be used and well known to those who are ordinary experts in the field of particular chemical treatment processes. Furthermore, the associated components that are often included in conventional chemical processing processes, such as refineries,

<p dir="rtl">10 Such as, for example, air supplies, catalyst hoppers, and flue gas handlers are not pictured. It will be known that these components are within the spirit and scope of the current embodiments described. However, operational components, such as those described in the present disclosure, may be added to the embodiments described in this disclosure.</p>

It should also be noted that the arrows in the drawings indicate the process streams. However, the arrows may indicate

<p dir="rtl">15 Equivalently to transmission lines which may carry process currents between two or more system components. In addition, arrows connecting system components identify inlets or outlets in each particular system component. The direction of the arrow generally corresponds to the main direction of movement of stream materials within the physical transfer line indicated by the arrow. Furthermore, arrows that do not connect two or more components of the system indicate a productive current which may exit the system</p>

<p dir="rtl">20 The imager or system inlet stream that may enter the imager system. Additional product streams may be processed in accompanying chemical processing systems or may be marketed as finished products. System inlet streams may be streams transported from associated chemical treatment systems, or they may be non-processed feedstock streams. In addition, dashed or dotted lines may indicate an optional step</p>

<p dir="rtl">25 Or optional stream. For example, there may be recycle streams in the system</p>

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optional. However, it should be realized that all connected lines may represent required transmission lines or chemical streams.

Various models will now be referred to in more detail, some of which are illustrated in the accompanying drawings. Whenever possible, the same reference numbers will be used throughout the drawings to refer to the same or similar parts.

Detailed description

In general, this disclosure describes various models of systems and methods for treating heavy oil types such as crude oil. According to one or more embodiments, heavy oil processing may include an upgrading process followed by a refining operation. In general, a grade 10 upgrading process may remove one or more of at least a portion of the nitrogen, sulfur and one or more metals from the heavy oil, and may also result in the breakage of aromatic moieties in the heavy oil. According to one or more embodiments, heavy oil may be processed using a hydrocarbon demineralization catalyst (sometimes referred to in this disclosure as an “HDM catalyst”), a transition catalyst, a hydrocarbon denitrification catalyst (referred to in this disclosure as an “HDM catalyst”) HDN", and hydrocarbon cracking catalyst. The 15 hydrocarbon demineralization catalyst, transition catalyst, hydrocarbon denitrification catalyst and hydrocarbon cracking catalyst may be located in series, either in a single reactor, such as a multi-layer packed bed reactor, or in two or more reactors arranged in series.

Here, models of the pretreatment process are described, as well as other processes following the pretreatment process. Systems that can be used after pretreatment may be referred to as a “20 chemical treatment system”, or alternatively as a “post pretreatment process” or “final treatment”.

It should be understood that any of the chemical treatment systems shown may be applied in conjunction with any of the pretreatment processes described herein. For example, Figures 1-4 depict models of the pretreatment process, and Figures 5 and 6 depict models of chemical pretreatment systems (e.g., post-pretreatment) by refining. It should be recognized that none of the 25 models of pretreatment systems, e.g. those depicted in Figures 1-4 or described in connection with Figures 1-4,

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They may be used with any of the final processing configurations described herein, such as those of Figures 5 or 6, or any other processing configuration described in connection with Figures 5 or 6.

As used in this disclosure, “reactor” refers to any vessel, container or the like, in which one or more chemical reactions may occur between one or more reactants 5 optionally in the presence of one or more catalysts. For example, a reactor may include a storage or reactor

A tubular reactor configured to operate as a batch reactor, a continuous stirred-tank reactor (CSTR). Or a plug flow reactor. Examples of reactors include packed bed reactors such as fixed bed reactors, and fluidized bed reactors. One can be organized

<p dir="rtl">10 One or more reaction zones in the reactor. As used in this disclosure, “reaction zone” refers to a region where a particular reaction occurs in a reactor. For example, a packed bed reactor with multiple catalyst beds may have multiple reaction zones, where each reaction zone is defined by the area of each catalyst bed. As used in this disclosure, “separation unit” refers to any separation device</p>

<p dir="rtl">15 separation device that at least partially separates one or more chemicals mixed in the process stream from each other. For example, a separation unit may selectively separate different chemical species from each other, to form one or more chemical molecules. Without limitation, examples of separation units include, distillation columns, flash drums, knock-out drums, knock-out pots, centrifuges</p>

<p dir="rtl">20 Centrifuges, filtration devices, traps, scrubbers, expansion devices, membranes, solvent extraction devices, and the like. It should be understood that the separation processes described in this disclosure may not completely separate each chemical substance from all other chemical components. It should be understood that the separations described in this disclosure are “at least partly” separative</p>

<p dir="rtl">25 Chemical components are different from each other, even if not explicitly stated, and it should be understood that a separation may only include a partial separation. And as it is</p>

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As used in this disclosure, one or more chemical components may be “separated” from the process stream to form a new process stream. In general, the process stream may enter a separation unit and be divided or separated into two or more process streams of the desired combination. Furthermore, in some separation processes, a “light fraction” and a “heavy fraction” may exit separately from the separator. And in a capacity

<p dir="rtl">5 In general, the light fraction stream has a lower boiling point than the heavy fraction stream. It should also be understood that where</p>

Only one separation unit is visualized or described in the figure, two or more separation units may be used to implement identical or substantially identical separation. For example, where a distillation column is described with multiple outlets, it is expected that different separators arranged in series may equally separate the feed stream and such embodiments are within the scope of embodiments

<p dir="rtl">10 currently described.</p>

It should be understood that “reaction effluent” generally refers to the current that exits a separation unit, reactant, or reaction zone after a particular reaction or separation. In general, the reaction stream has a different composition than the stream that has entered the separation unit, reactant, or reaction zone. It should be understood that when a stream is passed to another system unit, only part of that system stream may be passed. for example

<p dir="rtl">15 For example, a slip stream may carry some stream away, meaning only part of the stream enters the downstream system unit.</p>

As used in this disclosure, “catalyst” refers to any substance that increases the rate of a specified chemical reaction. The catalysts described in this disclosure may be used to enhance various reactions, including, but not limited to, hydrocarbon demineralization, hydrodesulfurization.

<p dir="rtl">20 (HDS), removal of nitrogen from hydrocarbons, removal of aromatic compounds from hydrocarbons</p>

HDA (hydrodearomatization), aromatic cracking, or combinations thereof. As used in this disclosure, “cracking” generally refers to a chemical reaction in which a molecule containing carbon-carbon bonds is broken into more than one molecule by By breaking one or more carbon-carbon bonds; a compound containing a cyclic moiety is transformed, e.g

<p dir="rtl">25 Aromatic compounds, to a compound that does not contain a cyclic moiety; Or where a molecule containing carbon-carbon double bonds is reduced to carbon-carbon single bonds. Some archives may contain</p>

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Multiple forms of catalytic activity, and naming a catalyst for one specific function does not render that catalyst incapable of being catalytically active for other functions.

It should be understood that two or more process streams can be “mixed” or “combined” when two or more lines intersect in the schematic flowcharts of Figures 1-6. Mixing or combining 5 may also include mixing by direct introduction of both streams into a reactor, separation unit, or other system component.

identical.

It should be understood that reactions promoted by catalysts as described in this disclosure may remove a chemical component, such as only a portion of a chemical component, from a process stream. For example, a hydrocarbon demineralization catalyst may be present in an amount effective to promote a reaction that removes 10 parts of one or more metals from the process stream. The hydrocarbon denitrification catalyst may be present in an amount effective to promote the reaction that removes a portion of the nitrogen present in the process stream. A hydrocarbon desulfurization catalyst may be present in an amount effective to promote the reaction that removes a portion of the sulfur present in the process stream. In addition, a hydrocarbon cracking catalyst, such as a hydrocarbon aromatics removal catalyst, may reduce the amount of aromatic radicals in the process stream by saturating and cracking those 15 aromatic radicals. It should be understood that, throughout this disclosure, it is not necessarily limited to a particular stimulus

On the functional performance of removing or breaking down a specific chemical moiety or component when it is indicated as having a specific functional performance. For example, the catalyst identified in this disclosure as a hydrocarbon denitrification catalyst can additionally provide the functionality for removing aromatics from the hydrocarbon, the functionality for removing sulfur from the hydrocarbon, or both.

<p dir="rtl">20 It should also be understood that streams may be named for components of the stream, and the component after which the stream is named may be the major component of the stream (e.g. comprising 50% by weight (wt%), 70% (wt%), 90% (wt%), 95% by weight, or even from 95% by weight of the stream contents to 100% by weight of the stream contents.</p>

It should be understood that pore size, as used throughout this disclosure, relates to the average pore size unless otherwise specified. The average pore size can be determined from Brunauer–Emmett–Teller analysis

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BET(). Also, the average pore size can be confirmed by transmission electron microscope (TEM) characterization.

Referring now to Figure 1, a pretreatment system 100 is depicted which includes a generalized hydrotreatment catalyst system 132. It should be understood that additional embodiments of the system

<p dir="rtl">5 The hydrotreating catalyst 132 according to Figure 1 is described in detail in Figures 2-4. However, it must be understood that the feed materials, products, recycle streams, etc., of the generalized pretreatment system 100 according to Figure 1 also apply to the embodiments described in connection with Figures 2-4.</p>

Referring to Figure 1, according to embodiments of this disclosure, a heavy oil feed stream may be mixed

<p dir="rtl">10 101 stream with 104 hydrogen stream. The hydrogen stream 104 may include</p>

Unused hydrogen gas from the recycled process gas component stream 113 process gas component stream, make-up hydrogen from the hydrogen feed stream 114, or both, for mixing with the heavy oil feed stream 101 and forming a pretreatment catalyst input stream 105. In one or more embodiments, an input stream may be heated

<p dir="rtl">15 Pretreatment catalyst 105 to a process temperature of 350 degrees Celsius (C°) to 450°C. The input stream of pretreatment catalyst 105 may enter and pass through the hydrotreating catalyst system 132. As described herein, the hydrotreating catalyst system 132 may include hydrotreatment catalyst system A series of reaction zones, including a hydrocarbon demineralization reaction zone, a transition reaction zone, a demineralization reaction zone</p>

<p dir="rtl">20 Nitrogen of hydrocarbon, and hydrocarbon cracking reaction zone.</p>

The systems and processes described are applicable to a wide range of heavy oil feed materials (in Heavy Oil Feed Stream 101), including crude oil types, vacuum residue, tar sands, bitumen and vacuum gas oils using Catalytic hydrotreating pretreatment process if

<p dir="rtl">25 Heavy oil feed is crude oil, it may have a specific gravity according to the American Petroleum Institute (API) that ranges from 25 degrees to 50 degrees. For example, the feed may be</p>

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The heavy oil used is Arab Heavy crude oil. Typical properties of Arabian heavy crude oil are shown in Table 1.

Table 1- Heavy Arabic feedstock for export

<tr><td><p dir="rtl">the value</p></td><td><p dir="rtl">Units</p></td><td><p dir="rtl">Analysis</p></td></tr><tr><td><p>27</p></td><td><p dir="rtl">Class</p></td><td><p dir="rtl">Specific gravity according to the Institute</p><p dir="rtl">American petroleum</p></td></tr><tr><td><p>0.8904</p></td><td><p dir="rtl">grams per cubic centimeter (g/cm3)</p></td><td><p dir="rtl">Density</p></td></tr><tr><td><p>2.83</p></td><td><p dir="rtl">Weight percentage (% by weight)</p></td><td><p dir="rtl">Sulfur content</p></td></tr><tr><td><p>16.4</p></td><td><p dir="rtl">Parts per million by weight</p></td><td><p dir="rtl">Nickel</p></td></tr><tr><td><p>56.4</p></td><td><p dir="rtl">Parts per million by weight</p></td><td><p dir="rtl">Vanadium</p></td></tr><tr><td><p>5&lt;</p></td><td><p dir="rtl">Parts per million by weight</p></td><td><p dir="rtl">NaCl content</p></td></tr><tr><td><p>8.2</p></td><td><p dir="rtl">% by weight</p></td><td><p dir="rtl">carbon cohn ardson</p></td></tr><tr><td></td><td></td><td><p dir="rtl">Residue (CCR)</p></td></tr><tr><td><p>7.8</p></td><td><p dir="rtl">% by weight</p></td><td><p dir="rtl">C5 asphaltenes</p></td></tr><tr><td><p>4.2</p></td><td><p dir="rtl">% by weight</p></td><td><p dir="rtl">C7 asphaltenes</p></td></tr>

Still referring to Figure 1, a pretreatment catalyst reaction stream 109 can be generated by 5 interacting the pretreatment catalyst input stream 105 with the hydrotreating catalyst stream 132.

The pretreatment catalyst reaction stream 109 enters a separation unit 112 and can be separated into a recycled process gas component stream 113 and an intermediate liquid product stream 115. In one embodiment, the pretreatment catalyst reaction stream 109 can also be purified to remove hydrogen sulfide and gas. The other process is to increase the purity of hydrogen to be recycled into the process gas component stream

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Recycled 113. The hydrogen consumed in the process may be replaced by adding pure hydrogen from the compensating hydrogen feed stream 114, which may be derived from steam, a naphtha reformer, or another source. The recycled process gas component stream 113 and the compensating hydrogen feed stream 114 may combine to form 5 hydrogen stream 104. In one embodiment, the intermediate liquid product stream 115 may be separated in a separator

116 to separate the light hydrocarbon fraction stream 117 and a final liquid product stream from the pretreatment 118; However, it should be understood that this separation step is optional. In other embodiments, the separation unit 116 may be a flash receptacle. In one embodiment, the light hydrocarbon fraction stream 117 is recirculated and is mixed with a pure stream of light hydrocarbon diluent 102 to create

<p dir="rtl">10 103 light hydrocarbon diluent stream. The pure light hydrocarbon diluent stream 102 may be used as needed to provide a compensatory diluent to help further reduce the deactivation of one or more catalysts in the hydrotreatment catalyst system 132.</p>

In one or more embodiments, the one or more catalyst reaction stream 15 effluent stream may have pretreatment 109, intermediate liquid product stream 115,

and the final liquid product stream from pretreatment 118 has a reduced aromatics content compared to the heavy oil feed stream 101. Additionally, in embodiments, one or more of the pretreatment catalyst reaction stream 109, intermediate liquid product stream 115, and final liquid product stream may have From pretreatment 118 reduced content of sulfur, metals, asphaltenes, carbon

<p dir="rtl">20 Conradson carbon, nitrogen, or combinations thereof, in addition to increasing the specific gravity</p>

American Petroleum Institute and Increased Diesel and Vacuum Distillate Productivity Compared to Heavy Oil Feed Stream 101.

According to one or more embodiments, the pretreatment catalyst reaction stream 109 may have a reduction of at least about 80 wt%, a reduction of at least 90 wt%, or even a reduction of at least about

<p dir="rtl">25 95% by weight of nitrogen with respect to heavy oil feed stream 101. According to another embodiment, it may be</p>

With a pretreatment catalyst reaction stream 109 reduction of at least about 85% by weight, reduction

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Not less than 90 wt.%, or even a reduction of at least 99 wt.% of sulfur with respect to the heavy oil feed stream 101. According to another embodiment, the pretreatment catalyst reaction stream 109 may have a reduction of at least about 70 wt.%, a reduction of no less than 80% by weight, or until a reduction of at least 85% by weight, of the aromatics content with respect to the heavy oil feed stream 101. According to Embodiment

<p dir="rtl">5 Else, the pretreatment catalyst reaction stream 109 may have a reduction of at least about 80 wt%, a reduction of at least 90 wt%, or even a reduction of at least 99 wt% of metal with respect to the heavy oil feed stream 101.</p>

With reference to Figure 1, in various embodiments, one or more may be one or more of the pretreatment catalyst reaction stream 109, the intermediate liquid product stream 115, and the final liquid product stream from the pretreatment

<p dir="rtl">10 Preset 118 is suitable for use as a raised oil stream 422 from refining process 200 and 300 according to Figures 5 and 6, respectively, as described later in this disclosure. As used in this disclosure, one or more of the pretreatment catalyst reaction stream 109, the intermediate liquid product stream 115, and the final pretreatment liquid product stream 118 may be referred to as “upgraded oil” which may be finally processed by systems according to For figures 5 or 6 at least. It may be of different types</p>

<p dir="rtl">15 High grade oil, in some embodiments, has a final boiling point below 540°C, which may increase efficiency or further conversion in post-refining. In additional embodiments, at least 90% by weight, at least 95% by weight, or even at least 99% by weight of the upgraded oil may have a boiling point less than or equal to 540°C. In additional embodiments, the elevated oil may have a final boiling point less than or equal to 520°C, 500°C, 480°C, 460°</p>

<p dir="rtl">20 Celsius, 440°C, 420°C, 400°C, 380°C, 360°C, 340°C, 320°C, or even 300°C. It should be understood that the final boiling point of the upgraded oil is equal to the final boiling point of the pretreatment reaction catalyst stream 109 because only light fractions are removed by optional subsequent separation steps in the pretreatment system 100.</p>

<p dir="rtl">25 Referring now to Figure 2, according to one or more embodiments, the hydrotreating catalyst system 132 may include or consist of reaction zones with multiple packed layers arranged in series (e.g.</p>

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For example, hydrocarbon demineralization reaction zone 106, transition reaction zone 108, hydrocarbon denitrification reaction zone 110, and hydrocarbon cracking reaction zone 120) each of these reaction zones may include a catalyst layer. Each of these reaction zones may be present In a single reactor such as a packed bed reactor with multiple layers arranged in a row, shown as a reactor

<p dir="rtl">5 Pretreatment 130 is shown in Figure 2. In these embodiments, the pretreatment reactor 130 includes a hydrocarbon demineralization catalyst layer comprising a hydrocarbon demineralization catalyst in the hydrocarbon demineralization reaction zone 106, a transition catalyst layer comprising a transition catalyst in The transition reaction zone 108, hydrocarbon denitrification catalyst layer includes the hydrocarbon denitrification catalyst in the hydrocarbon denitrification reaction zone 110, and a</p>

<p dir="rtl">10 The hydrocarbon cracking catalyst includes a hydrocarbon cracking catalyst in the hydrocarbon cracking reaction zone 120. In other embodiments, the hydrocarbon denitrification reaction zone 106, the transition reaction zone 108, the hydrocarbon denitrification reaction zone 110, and the hydrocarbon cracking reaction zone may each be 120 Hydrocracking reaction zone is present in many series packed bed reactors. In other embodiments, each reaction zone is located in a packed bed reactor</p>

<p dir="rtl">15 Single, separate. It should be understood that embodiments envisaged include those in which consecutively arranged packed catalyst layers are contained in a single reactor or in multiple reactors each containing one or more catalyst layers. It should be noted that when relatively large amounts of catalyst are required, it may be desirable to contain those catalysts in separate reactors.</p>

According to one or more embodiments, an input stream is introduced to the pretreatment catalyst 105, which

<p dir="rtl">20 Comprising heavy oil, it leads to the hydrocarbon demineralization reaction zone 106 and is connected to the hydrocarbon demineralization catalyst. Contact of the hydrocarbon demineralization catalyst with the pretreatment catalyst input stream 105 may promote a reaction that removes at least a portion of the metals present in the pretreatment catalyst input stream 105, such as a hydrocarbon demineralization reaction. After contact with the hydrocarbon demineralization catalyst, the pretreatment catalyst input stream 105 can be converted</p>

<p dir="rtl">25 To the reaction flow of the removal of metals from hydrocarbons. The hydrocarbon demineralization reaction stream may have a reduced metal content compared to the contents of the pretreatment catalyst input stream 105.</p>

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For example, the hydrocarbon demineralization reaction stream may contain at least 70 wt%, at least 80 wt%, or even at least 95 wt% less metals than the pretreatment catalyst input stream 105.

According to one or more embodiments, the hydrocarbon demineralization reaction zone 106 may have a 5-weighted average layer temperature from 350°C to 450°C, such as from 370°C to 415°C, and may have a pressure of 30 bar To 200 bar, such as from 90 bar to 110 bar. The hydrocarbon demineralization reaction zone 106 includes a hydrocarbon demineralization catalyst, and the hydrocarbon demineralization catalyst may completely fill the hydrocarbon demineralization reaction zone 106.

<p dir="rtl">10 The hydrocarbon demetalization catalyst may comprise one or more metal combination groups</p>

International Union of Pure and Applied Chemistry

<p dir="rtl">(IUPAC 5, 6, or 8-10 of the periodic table. For example, the hydrocarbon demetalization catalyst may include molybdenum). The hydrocarbon demetalization catalyst may also include a support material, which may The metal is placed on the support material.</p>

<p dir="rtl">15 In one embodiment, the hydrocarbon removal catalyst may include a molybdenum metal catalyst on an alumina support (sometimes referred to as a “Mo/Al2O3 catalyst”). It should be understood that throughout this disclosure, metals may be present Present in any of the detected catalysts in the form of sulfides, oxides, or even other compounds.</p>

<p dir="rtl">20 In one embodiment, the hydrocarbon demetalization catalyst may include a metal sulfide on a support material, where the metal is selected from the group consisting of the elements of IUCP groups 5, 6, and 8-10 of the periodic table, and combinations thereof. The support material may be gamma-alumina or silica/alumina extrusion products, sheets, cylinders, granules, pellets, and combinations thereof.</p>

<p dir="rtl">25 In one embodiment, the hydrocarbon demineralization catalyst may include a gamma alumina support, having a surface area of 100 m²/g to 160 m²/g)eg, from 100 m²/Aesthetic</p>

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130 M²/g, or from 130 m²/g to 160 m²/g). The hydrocarbon demineralization catalyst can best be described as having a relatively large pore size, such as at least 0.8 cm³/g (for example, at least 0.9 cm).³/g, or even at least 1.0 cm³/g). The pore size of the hydrocarbon demineralization catalyst may often be large (i.e., have a pore size greater than 50 nm).

<p dir="rtl">5 This may provide significant metal adsorption capacity on the surface of the hydrocarbon demineralization catalyst and optionally dopants. In one embodiment, the dopant may be selected from the group consisting of boron, silicon, halogens, phosphorus, and combinations thereof.</p>

In one or more embodiments, the hydrocarbon demineralization catalyst may comprise from 0.5%

<p dir="rtl">10 by weight to 12 wt.% oxide or sulfide of molybdenum (as from 2 wt.% to 10 wt.% or from 3 wt.% to 7 wt.% of molybdenum oxide or sulfide), and from 88 wt.% to 99.5 wt.% alumina (as of 90 wt% to 98 wt% or from 93 wt% to 97 wt% alumina).</p>

Without being bound by theory, in some embodiments, it is believed that during the reaction in the reaction zone the metals are removed from

<p dir="rtl">15 Hydrocarbon 106 The hydrocarbon demineralization catalyst promotes the hydrogenation of porphyrin-type compounds in heavy oil via hydrogen to create an intermediate compound. After this primary hydrogenation, the nickel or vanadium located at the center of the porphyrin molecule in the intermediate compound is reduced by hydrogen and then further reduced to the corresponding sulfide by hydrogen sulfide (H2S). The metal sulfide precipitates.</p>

<p dir="rtl">20 The final catalyst is used to remove metals from the hydrocarbon, and thus metal sulfide is removed from the virgin crude oil. Sulfur is also removed from organic compounds containing sulfur through a parallel pathway. The rates of these parallel reactions may depend on the types of sulfur being considered. Generally, hydrogen is used to extract sulfur, which is converted to hydrogen sulfide in the process. Sulfur-free hydrocarbon fragments remain</p>

<p dir="rtl">25 sulfur-free hydrocarbon fragments, remaining in the liquid hydrocarbon stream.</p>

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The hydrocarbon demineralization reaction effluent may be passed from the hydrocarbon demineralization reaction zone 106 to the transition reaction zone 108 where it contacts the transition catalyst. Contact of the transfer catalyst with the hydrocarbon demineralization reaction stream may promote a reaction that removes at least a portion of the metals present in the hydrocarbon demineralization reaction stream as well as

<p dir="rtl">5 To reactions that may remove at least a portion of the nitrogen present in the hydrocarbon demineralization reaction stream. After contact with the transition catalyst, the hydrocarbon demineralization reaction stream is converted into a transition reaction stream. The transition reaction stream may have a reduced metal content and nitrogen content compared to the hydrocarbon demineralization reaction stream. For example, the transition reaction stream may have a metal content of at least 50 wt%, 80 wt% at least</p>

<p dir="rtl">10 The least, or even at least 90% by weight, of the hydrocarbon demineralization reaction stream. In addition, the transition reaction stream may contain at least 10 wt % less nitrogen, at least 15 wt %, or even at least 20 wt % less nitrogen than the hydrocarbon demineralization reaction stream. According to the models, the transition reaction zone 108 has a weighted average layer temperature of approximately 370°C to 410°C. The transition reaction region 108 includes the transition catalyst, which may</p>

<p dir="rtl">15 The transition catalyst completely fills the transition reaction region 108.</p>

In one embodiment, the transition reaction zone 108 can be operated to remove an amount of metal components and an amount of sulfur components from the reaction effluent stream. The transition catalyst may include an alumina-based support in the form of extrudates

<p dir="rtl">20 In one embodiment, the transition catalyst comprises one IUCN Group 6 metal and one IUCN Group 8-10 metal. An example of IUCP group metals includes Group 6 molybdenum and tungsten. Examples of IUCP group metals include Groups 8-10, nickel and cobalt. For example</p>

<p dir="rtl">25 For example, the transition catalyst may include molybdenum and nickel on a titania support (sometimes referred to as a “Mo-Ni/Al2O3 catalyst”). The transition catalyst may also contain a dopant which</p>

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They are selected from the group consisting of boron, phosphorus, halogens, silicon, and combinations thereof. The transition catalyst may have a surface area of 140 m²/g to 200 m²/g) as from 140 m²/g to 170 m²/g or from 170 m²/g to 200 m²/g). The transition catalyst may have an average pore size of 0.5 cm³/g to 0.7 cm³/g) such as 0.6 cm³/g). The transition catalyst may generally include:

<p dir="rtl">5 The mesoporous structure has pore sizes in the range from 12 nm to 50 nm. These properties provide balanced activity in removing metals from hydrocarbons and removing sulfur from hydrocarbons.</p>

In one or more embodiments, the transition catalyst may comprise from 10 wt% to 18 wt% molybdenum oxide or sulfide (such as from 11 wt% to 17 wt% or from 12 wt% to 16 wt%)

<p dir="rtl">10 By weight molybdenum oxide or sulfide), from 1 wt% to 7 wt% nickel oxide or sulfide (such as from 2 wt% to 6 wt% or from 3 wt% to 5 wt% nickel oxide or sulfide), and from 75% by weight to 89 wt% alumina (such as from 77 wt% to 87 wt% or from 79 wt% to 85 wt% alumina).</p>

The transition reaction effluent can be passed from the transition reaction zone 15 108 to the hydrocarbon denitrification reaction zone 110, where

It is connected to the catalyst for removing nitrogen from hydrocarbons. Contact of the hydrocarbon denitrification catalyst with the transition reaction stream may promote a reaction that removes at least a portion of the nitrogen present in the transition reaction stream, such as a hydrocarbon denitrification reaction. After contacting with the hydrocarbon denitrification catalyst, the transition reaction stream can be converted into a denitrification reaction stream.

<p dir="rtl">20 Nitrogen is a hydrocarbon. The hydrocarbon denitrification reaction stream may have a reduced metal and nitrogen content compared to the transition reaction stream. For example, the hydrocarbon denitrification reaction stream may have a reduction in nitrogen content of at least 80 wt%, at least 85 wt%, or even at least 90 wt% for the transition reaction stream. In another embodiment, the hydrocarbon denitrification reaction stream may have a reduced sulfur content</p>

<p dir="rtl">25 At least 80 wt%, at least 90 wt%, or even at least 95 wt% for the transition reaction stream. In another embodiment, the reaction stream may remove nitrogen from the hydrocarbon</p>

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A reduction in aromatics content of at least 25 wt%, at least 30 wt%, or even at least 40 wt% for the transition reaction stream.

According to the embodiments, the hydrocarbon denitrification reaction zone 110 has a weighted average layer temperature of 370°C to 410°C. The reaction zone includes the denitrification of...

<p dir="rtl">5 The hydrocarbon 110 is based on the hydrocarbon denitrification catalyst, and the hydrocarbon denitrification catalyst may completely fill the hydrocarbon denitrification reaction zone 110.</p>

In one embodiment, the hydrocarbon denitrification catalyst includes a metal oxide or sulfide on a material

Support, where the metal is chosen from the group consisting of IUC groups

Pure and applied 5, 6, and 8-10 of the periodic table, and combinations thereof. May include supporting material

<p dir="rtl">10 Gamma-alumina, mesoporous alumina, silica, or both, in the form of extrusions, balls, cylinders and pellets.</p>

According to one embodiment, the hydrocarbon denitrification catalyst includes a gamma alumina-based support that has a surface area of 180 m²/g to 240 m²/g) as from 180 m²/g to 210 m²/g, or from 210 m²/g to 240 m²/g). This relatively large surface area allows the catalyst to remove nitrogen

<p dir="rtl">15 of hydrocarbon with a smaller pore size (e.g., less than 1.0 cm).³/g, less than 0.95 cm³/g, or even less than 0.9 cm³(g). In one embodiment, the hydrocarbon denitrification catalyst contains at least one metal from IUCP Group 6, such as molybdenum, and at least one metal from IUCP Groups 8-10, such as nickel. The hydrocarbon denitrification catalyst also includes a substance</p>

<p dir="rtl">20 At least one alloy selected from the group consisting of boron, phosphorus, silicon, halogens, and combinations thereof. In one embodiment, the hydrocarbon denitrification catalyst may include cobalt, which also enhances sulfur removal. In one embodiment, the hydrocarbon denitrification catalyst has a higher metal loading for the active phase compared to the hydrocarbon denitrification catalyst. This increase in metal loading may lead to increased catalytic activity. in</p>

<p dir="rtl">25 In one embodiment, the hydrocarbon denitrification catalyst comprises nickel and molybdenum, having a nickel to molybdenum molar ratio of (0.1) Ni/(Ni+Mo) to 0.3 (such as 0.1 to 0.2 or 0.2).</p>

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10

To 0.3). In one embodiment including cobalt, the molar ratio of (Co+Ni)/molybdenum may be in the range from 0.25 to 0.85 (such as 0.25 to 0.5 or 0.5 to 0.85).

According to another embodiment, the hydrocarbon denitrification catalyst may comprise a mesoporous material, such as mesoporous alumina, which may have an average pore size of at least 25 nm. For example, the hydrocarbon denitrification catalyst may comprise mesoporous alumina having an average pore size of at least 30 nm, or even at least 35 nm. Hydrocarbon denitrification catalysts with a relatively small average pore size, such as less than 2 nm, may be referred to as conventional hydrocarbon denitrification catalysts in this disclosure, and may have relatively poor catalytic performance compared to hydrocarbon denitrification catalysts. Hydrocarbons with larger pore sizes currently shown. Embodiments of hydrocarbon denitrification catalysts with an alumina carrier having an average pore size from 2 nm to 50 nm may be referred to in this disclosure as “mesoporous alumina supported catalysts.” In one or more embodiments, the alumina may have mesoporous pores

The hydrocarbon demineralization catalyst has an average pore size in the range from 2 nm to 50 nm, 25 nm to 50 nm, 30 nm to 50 nm, or 35 nm to 50 nm.

<p dir="rtl">15 According to embodiments, the hydrocarbon denitrification catalyst may include alumina having a large surface area</p>

Relatively large pore size, or both. For example, mesoporous alumina may have a relatively large surface area having a surface area of at least about 225 m²/g, at least about 250 m²/g, at least about 275 m²/g, at least about 300 m²/g, or even at least about 350 m²/g, as from 225 m²/g to 500 m²/g, from 200 m²/g to 450 m²/g,

<p dir="rtl">20 Or from 300 AD²/g to 400 m²/g. In one or more embodiments, the mesoporous alumina may have a relatively large pore volume having a pore volume of at least about 1 mL/g, at least about 1.1 mL/g, at least 1.2 mL/g, or even at least 1.2 mL /g, such as from 1 ml/g to 5 ml/g, from 1.1 ml/g to 3, or from 1.2 ml/g to 2 ml/g. Without being bound by theory, it is believed that a hydrocarbon denitrification catalyst supported by mesoporous alumina may provide sites for</p>

<p dir="rtl">25 Additional actives and channels with larger pores which may facilitate the transfer of larger molecules into and out of the catalyst. Additional active sites and channels with larger pores may result in higher catalytic activity and catalytic lifetime</p>

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Longer, or both. In one embodiment, the hydrocarbon denitrification catalyst may include a dopant, which may be selected from the group consisting of boron, silicon, halogens, phosphorus, and combinations thereof.

According to the described embodiments, a hydrocarbon denitrification catalyst may be produced by mixing a substance

<p dir="rtl">5 A support, such as alumina, with a binder, such as acid peptized alumina. Water or another solvent may be added to a mixture of support and binder to form an extrudable phase, which is then extruded to the desired shape. The extrusion can be dried at an elevated temperature (e.g. above 100°C, e.g. 110°C) and then calcined at a suitable temperature (e.g. at least 400°C or at least 450°C, e.g. 500°C).</p>

<p dir="rtl">10 (Celsius). Calcined extrudates may be impregnated with an aqueous solution containing catalyst precursor materials, such as products containing molybdenum, nickel, or combinations thereof. For example, the aqueous solution may contain ammonium heptanmolybdate, net Nickel nitrate and phosphoric acid to form a hydrocarbon denitrification catalyst comprising compounds containing molybdenum,</p>

<p dir="rtl">15 Nickel and phosphorus.</p>

In embodiments where a meso-porous alumina support is used, mesoporous alumina may be synthesized by dispersing boehmite powder in water at 60°C to 90°C. Then, an acid such as nitric acid (HNO3) can be added to the boehmite in the water solution at the nitric acid ratio:⁺0.3 Al³ to

<p dir="rtl">20 3.0 The solution is stirred at 60°C to 90°C for several hours, such as 6 hours,</p>

To obtain a solution. A copolymer, such as a triblock copolymer, can be added to the solution at room temperature, with a molar ratio of Al:Aluminum copolymer of 0.02 to 0.05 and maintained for several hours, such as three hours. The solution mixture is dried/ Copolymer for several hours and then calcined.

<p dir="rtl">25 According to one or more embodiments, the hydrocarbon denitrification catalyst may comprise from 10%</p>

by weight to 18 wt% molybdenum oxide or sulfide (such as from 13 wt% to 17 wt% or from

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<p dir="rtl">14% by weight to 16% by weight molybdenum oxide or sulfide), from 2% by weight to 8% by weight nickel oxide or sulfide (such as from 3% by weight to 7% by weight or from 4% by weight to 6% by weight nickel oxide or sulfide), and from 74 wt% to 88 wt% alumina (such as from 76 wt% to 84 wt% or from 78 wt% to 82 wt% alumina).</p>

<p dir="rtl">5 In a similar manner to the hydrocarbon demineralization catalyst, and again with no intention of being bound by any theory, it is believed that hydrocarbon denitrification and hydrocarbon aromatics can be carried out via related reaction mechanisms. Each involves some degree of hydrogenation. For hydrocarbon removal of nitrogen, organic nitrogen compounds are usually in the form of heterocyclic structures, with a heteroatom</p>

<p dir="rtl">10 Nitrogen. These heterocyclic structures may be saturated before the heterocyclic nitrogen atom is removed. Similarly, the process of aromaticization from a hydrocarbon involves saturation of the aromatic rings. Each of these interactions may occur to a different degree depending on the amount or type of each catalyst because each catalyst may selectively promote one type of conversion over another and because the conversions are competitive.</p>

<p dir="rtl">15 It should be understood that some embodiments of methods and systems currently described may utilize a hydrocarbon denitrification catalyst comprising porous alumina having an average pore size of at least 25 nm. However, in other embodiments, the average pore size of the porous alumina may be less than about 25 nm, and may even be micropore (i.e., have an average pore size of less than 2 nm).</p>

Still, referring to Figure 2, the reaction flow for denitrification of hydrocarbon can be passed from an area

<p dir="rtl">20 Nitrogen removal reaction from the hydrocarbon 110 to the hydrocarbon cracking reaction zone 120 where it contacts the hydrocarbon cracking catalyst. Contact of the hydrocarbon cracking catalyst with the hydrocarbon denitrification reaction stream may promote a reaction that reduces the aromatic content in the hydrocarbon denitrification reaction stream, such as the removal of aromatic compounds from the hydrocarbon. After contact with the hydrocarbon cracking catalyst, the hydrocarbon denitrification reaction stream is converted into a hydrocarbon denitrification reaction stream.</p>

<p dir="rtl">25 Pretreatment catalyst reaction 109. The pretreatment catalyst reaction stream 109 may have a reduced aromatic content compared to the hydrocarbon denitrification reaction stream. For example, may</p>

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The pretreatment catalyst reaction stream 109 has an aromatics content that is at least 50% lower by weight, at least 60% lower by weight, or even at least 80% lower than the hydrocarbon denitrification reaction stream.

The hydrocarbon cracking catalyst may comprise one or more IUCN metals

<p dir="rtl">5 Applied to groups 5, 6, 8, 9, or 10 of the periodic table. For example, a hydrocarbon cracking catalyst may comprise one or more metals from IUCN Groups 5 or 6, and one or more metals from IUCP Groups 8, 9, or 10 of the periodic table. For example, the hydrocarbon cracking catalyst may include molybdenum or tungsten IUCP Group 6, nickel, and cobalt</p>

<p dir="rtl">10 of the International Union of Pure and Applied Chemistry Groups 8, 9, or 10. The hydrocarbon demineralization catalyst may also include a support material, such as zeolite, and the metal may be deposited on the support material. In one embodiment, the hydrocracking catalyst may comprise a tungsten-nickel metal on a zeolite support that is mesoporous (sometimes referred to as a “tungsten-nickel/zeolite meso-catalyst”).</p>

<p dir="rtl">15 Hydrocarbon on molybdenum metal and nickel on a zeolite support that is mesoporous (sometimes referred to as a “molybdenum-nickel/zeolite mesocatalyst”).</p>

According to hydrocarbon cracking catalyst embodiments for hydrotreatment catalytic systems described in this disclosure, the support material (i.e., mesoporous zeolite) can be characterized as mesoporous having an average pore size from 2 nm to 50 nm.

<p dir="rtl">20 By comparison, conventional zeolite-based hydrocracking catalysts contain microporous zeolites, meaning they have an average pore size of less than 2 nanometers. Without being limited by theory, it is believed that the relatively large pore size (i.e., mesoporosity) of the hydrocarbon cracking catalyst currently described allows the diffusion of larger molecules into the zeolite, which is thought to improve reaction activity and catalyst selectivity.</p>

<p dir="rtl">25 pores, molecules containing aromatics can diffuse more easily into the catalyst and aromatic cracking may increase. For example, in some conventional embodiments, the converted feed material may be</p>

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Hydroprocessing catalysts are vacuum gas oils, light cycle oils from, for example, a fluid catalytic cracking reactor; Or types of coker gas oils from, for example, a coking unit. The molecular sizes in these types of oil are relatively small compared to those of heavy oil types such as crude and atmospheric residues, which may be

Feed material according to current methods and systems. Heavy oil species are usually able to diffuse into conventional zeolites and are converted onto active sites within the zeolites. Thus, zeolites with larger pore sizes (i.e., mesoporous zeolites) may allow molecules larger than heavy oil species to overcome the diffusion constraint, and may enhance the interaction and transformation of molecules

<p dir="rtl">10 Larger for heavy oil types.</p>

Zeolite support material is not necessarily limited to a specific type of zeolite. However, it is expected that zeolites such as Y-82, LZ-45, AWLZ-15, Beta, Y-84, LZ-25, LZ-210, silicalite, or mordenite may be suitable for use in a catalyst. Hydrocracking catalyst currently described. For example, 15 suitable mesoporous zeolites that may be impregnated with one or more catalytic metals such as tungsten, nickel, molybdenum, or combinations thereof are described at least in US Patent No. 7,785,563; Powder Technology 183 (2008) 73–78; Liu et al.,Zhang et al,

Microporous and Mesoporous Materials 181 (2013) 116–122; and Garcia-Martinez et

. 2012 (DOI: 10.1039/c2cy00309k), Catalysis Science &amp; Technology, al.

<p dir="rtl">20 In one or more embodiments, the hydrocarbon cracking catalyst may comprise from 18 wt% to 28 wt% tungsten sulfide or oxide (such as from 20 wt% to 27 wt% or from 22 wt% to 26 wt% tungsten, sulfide or tungsten oxide of tungsten), from 2 wt% to 8 wt% nickel oxide or sulfide (such as from 3 wt% to 7 wt% or from 4 wt% to 6 wt% nickel oxide or sulfide), and from 5 wt% to 40 wt% zeolite Medium pores (e.g. from 10 wt% to 35 wt% or from 10 wt% to 30 wt% zeolite). In another embodiment, the hydrocarbon cracking catalyst may comprise from 12 wt% to 18 wt% molybdenum oxide or sulfide.</p>

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(such as from 13 wt.% to 17 wt.% or from 14 wt.% to 16 wt.% molybdenum oxide or sulfide), from 2 wt.% to 8 wt. nickel oxide or sulfide (such as from 3 wt.% to 7 wt.% or from 4 wt. % by weight to 6 wt% nickel oxide or sulfide), and from 5 wt% to 40 wt% mesoporous zeolite (e.g. from 10 wt% to 35 wt% or from 10 wt% to 30 wt%

<p dir="rtl">5 Medium pore zeolite.</p>

The hydrocarbon cracking catalysts described may be prepared by selecting a mesoporous zeolite and impregnating the mesoporous zeolite with one or more catalytic metals or by assembling the mesoporous zeolite with other components. For the impregnation method, mesoporous zeolite, active alumina (for example, boehmite alumina) can be mixed

<p dir="rtl">10 (alumina,), and bind (for example, acid peptized alumina). An appropriate amount of water can be added to form a dough which can be extruded using an extruder. The extrudate can be dried at 80°C to 120°C For a period of 4 to 10 hours, then calcining at 500°C to 550°C for a period of 4 to 6 hours. The calcined extrusion product can be impregnated with an aqueous solution prepared with compounds including</p>

<p dir="rtl">15 Contains nickel, tungsten, molybdenum, cobalt, or combinations thereof. Two or more catalytic metals may be used when two catalytic metals are required. However, some models may include only one of nickel, tungsten, molybdenum, or cobalt. For example, the catalyst support material may be impregnated with a mixture of nickel nitrate hexahydrate (i.e., Ni(NO3)2•6H2O) and ammonium metatungstate</p>

<p dir="rtl">20 metatungstate (i.e., NH4)6H2W12O40) if a tungsten-nickel hydrocarbon cracking catalyst is required. The impregnated extrusion can be dried at 80°C to 120°C for 4 to 10 hours and then calcined at 450°C to 500° Celsius for a period of 4 to 6 hours. For the aggregate method, mesoporous zeolite may be mixed with alumina, binders, and compounds containing tungsten, molybdenum, nickel, or cobalt (e.g.,</p>

<p dir="rtl">25 Molybdenum trioxide (MoO3) or nickel hexahydrate if molybdenum-nickel is required.</p>

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It should be understood that some embodiments of the methods and systems currently described can use a hydrocarbon cracking catalyst that includes a mesoporous zeolite (i.e., having an average pore size from 2 nm to 50 nm). However, in other embodiments, the average pore size of the zeolite may be less than 2 nanometers (i.e., microporous).

According to one or more of the described embodiments, the volume fraction of the metal removal catalyst may be...

Hydrocarbon: Transition catalyst: Catalyst for removing nitrogen from hydrocarbon: Hydrocarbon cracking catalyst 5-20: 5-30: 30-70: 5-30. The percentage of the stimulus may depend at least in part on...

Metal content in processed heavy oil feedstock.

Now referring to Figure 3, and according to additional embodiments, the hydrogenation catalyst system 132 may include regions

<p dir="rtl">10 A reaction with multiple packed bed reaction zones arranged in a row (e.g., hydrocarbon denitrification reaction zone 106, transition reaction zone 108, and hydrocarbon denitrification reaction zone 110) and each of these reaction zones may include a catalyst layer. Each of these regions may be present in a single reactor such as a packed bed reactor with several layers arranged in succession, shown as a prepacked bed hydrogenation reactor 134 in Figure 3, and a packed bed hydrotreatment reactor</p>

<p dir="rtl">15 In other embodiments, the hydrocarbon demineralization reaction zone 106, the transition reaction zone 108, and the hydrocarbon denitrification reaction zone 110 may be located in a plurality of packed bed reactors arranged in series with the dimensional packed bed hydrocarbon cracking reactor 136. In In other models, each reaction zone is located in a single, separate packed bed reactor. The prepacked bed hydrogenation reactor 134 or the set of prepacked bed reactors 134 may include a removal reaction zone</p>

<p dir="rtl">20 Metals from the hydrocarbon 106, transition reaction zone 108, hydrocarbon denitrification reaction zone 110. The postpacked bed hydrocarbon cracking reactor 136 may include a hydrocarbon cracking reaction zone 120. In these embodiments, the hydrocarbon denitrification reaction zone 106, zone Transition reaction 108, hydrocarbon denitrification reaction zone 110, hydrocarbon cracking reaction zone 120, special catalysts, processing conditions, etc.,</p>

<p dir="rtl">25 shown in relation to the system in accordance with Figure 2. The configuration of the pre-packed bed hydrogenation reactor 134 or the combination of pre-packed bed reactors according to Figure 3 may be particularly advantageous when the reaction conditions are</p>

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For example, but not limited to, the hydrogen content, temperature, or pressure of the packed bed upstream hydrogenation reactor process 134 or the combination of upstream packed bed reactors and packed bed afterhydrocarbon cracking reactor 136 are different. In these embodiments, stream 131 is passed from the upstream packed bed hydrogenation reactor 134 or upstream packed bed reactor assembly to the upstream packed bed hydrocarbon cracking reactor 5 136 .

Referring now to Figure 4, and according to additional embodiments, the hydrogenation catalyst system 132 may include multiple successively arranged packed layer reaction zones (e.g., hydrocarbon demineralization reaction zone 106, transition reaction zone 108, and hydrocarbon denitrification reaction zone 110) Each of these reaction zones may include a catalyst bed. Each of these 10 zones may be present in a single reactor such as a packed bed reactor with several layers in series, shown as a hydrogenation reactor

134 packed bead hydrotreating reactor in Figure 3, and a 138 downstream fluidized bed hydrocracking reactor. In other embodiments, the hydrocarbon demineralization reaction zone 106, the transition reaction zone 108, and the hydrocarbon denitrification reaction zone 110 may be located in a plurality of 15 packed bed reactors arranged in series with a post-packed bed hydrocarbon cracking reactor 136.

In other embodiments, each reaction zone is located in a single, separate packed bed reactor. The upstream packed bed hydrogenation reactor 134 or the plurality of upstream packed bed reactors may include a hydrocarbon demineralization reaction zone 106, a transition reaction zone 108, and a hydrocarbon denitrification reaction zone 110. The postfluidized bed hydrocarbon cracking reactor 20 may include 138 Hydrocarbon cracking reaction zone 120. In these embodiments, may be used

Hydrocarbon demineralization reaction zone 106, transition reaction zone 108, hydrocarbon denitrification reaction zone 110, hydrocarbon cracking reaction zone 120, special catalysts, processing conditions, etc., shown in relation to the system in accordance with Figure 2. Configuration of the pre-packed bed hydrogenation reactor 134 or a set of pre-packed bed reactors 25 according to Figure 3 may be particularly useful when the reaction conditions are such as e.g.

For example, but not limited to, the hydrogen content, temperature, or pressure of the prehydrogenation reactor process

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Packed bed 134 or a combination of pre-packed bed reactors and post-fluidized bed hydrocarbon cracking reactor 138 are different. The process fluid 139 may dilute the hydrocarbon cracking catalyst to the hydrocarbon cracking reaction zone 120. In these embodiments, stream 131 is passed from the prepacked bed hydrogenation reactor 134 or the prepacked bed reactor assembly to the cracking reactor

<p dir="rtl">5 Dimensional Fluidized Bed Hydrocarbon 138. The fluidized bed model of Figure 4 may be useful with hydrocracking catalysts, especially compared to the packed bed configurations of Figures 2 and 3.</p>

Referring now to Figures 5 and 6, in the embodiments of the systems and processes described, an upstream oil grade 220 may be used as feedstock or as part of the feedstock for a downstream refinery process

<p dir="rtl">10 operation, such as refining coke 200 by a hydrocarbon cracking process unit as shown in Figure 5 or refining coke 300 by a fluid catalytic cracking conversion unit as shown in Figure 6. In these embodiments, the high grade oil stream 220 is processed to form a refining fraction one or more (such as, for example, gasoline, distillate oil, fuel oil, or coke) by introducing high-grade oil to the refinery fractionator</p>

<p>5 230 In the forms of atmospheric distillation column, such as fractionator 15</p>

<p dir="rtl">and 6) Subsequently subjecting the fractions to the refinery fractionator to a refining treatment such as one or more hydrocarbon cracking or fluid catalytic cracking processing. If the 220 grade oil stream is used as part of a feedstock, the feedstock balance may be crude oil not derived from the processing step The presets are described with reference to Figure 1. A simplified schematic diagram of a simplified refinery is visualized in Figure 5. In</p>

<p dir="rtl">20 While embodiments of refining post-processing systems are described in this disclosure with reference to Figures 5 and 6, it should be understood that these post-processing operations are not limited to the pre-processing, step-up process described by reference to Figures 1-4. In addition, it should be understood that while Figures 5 and 6 depict representations of some refinery systems, other refinery systems are projected, such as any refinery system currently used to make transportation fuels from crude oil.</p>

<p dir="rtl">25 Figure 5 represents a first model of a 200 delayed coking refinery that contains a coke refinery with a hydrocracking process unit. In figure 5,</p>

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Enters the upgraded oil stream 220, which may comprise either an effluent stream 109 pretreatment catalyst reaction, an intermediate liquid product stream 115 intermediate liquid product stream or a final pretreatment liquid product stream 118 of Figure 1, column Atmospheric distillation 230, where it may be separated into at least, not

<p dir="rtl">5 To name a few, three parts. The three parts may include a straight-run naphtha stream 232, an atmospheric gas oil stream 234, and an atmospheric residue stream 236. In a further embodiment, virgin crude oil may be added to the upgraded oil stream 220 as feedstock for later coke refining operations. 300, 200 delayed coking refineries according to Figures 5 and 6.</p>

The 236 Atmospheric residue stream may enter a vacuum distillation column

<p dir="rtl">10 240 distillation column, whereby the atmospheric residue stream 236 can be separated into a vacuum gas oil stream</p>

242 And the vacuum residue stream 244. In the embodiment shown in Figure 5, the collected stream 246 can be removed from the discharge residue stream 244 and sent to the fuel oil collection tank 206. The remainder of the discharge residue stream 244 may enter a delayed coking process unit 250, where the discharge residue stream 244 may be processed to create naphtha stream 252,

<p dir="rtl">15 254 coker gas oil stream, heavy refining unit gas oil stream 256, and raw coke stream 258, with the raw coke stream 258 then sent to the coke collection tank 208. Raw coke, as used in this disclosure, is another name for high-quality coke. Besides lower coke yields, higher liquid yields can be observed resulting in greater amounts of coker gas oil stream 254 and heavy coker gas oil stream 256.</p>

<p dir="rtl">20 The coking unit gas oil stream 254 may be fed into the systems and methods shown for the gas oil hydrocarbon treatment unit 270 gas oil hydrotreater. According to some embodiments, the coker gas oil stream 254 may contain a relatively large amount of unsaturated content, particularly olefins, which may inactivate the posthydrocarbon denitrification catalyst. Increasing the throughput of this stream would normally limit the cycle length of the Gas Oil Hydrocarbon Processing Unit catalyst 270. However, in embodiments of systems and methods</p>

<p dir="rtl">25 shown, this feed increment can be processed to the gas oil hydrocarbon processing unit 270 because</p>

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Improving the characteristics of the atmospheric gas oil stream 234 (i.e., less sulfur and aromatics in the feed).

Still referring to Figure 5, the coker gas oil stream 254 may be sent together with the atmospheric gas oil stream to the coker gas oil hydrocarbon processing unit 270 for further removal of impurities.

<p dir="rtl">5 According to some embodiments, the coker gas oil stream 254 and the atmospheric gas oil stream 234 contain quantities</p>

High unsaturated content, especially olefins, which can deactivate the catalyst for denitrification of post-hydrocarbons. The excess throughput of these streams may normally be limited by the catalyst cycle length of the hydrocarbon gasoil processor 270. However, according to the systems embodiment and methods shown, the excess feed to the hydrocarbon gasoil processor 270 can be addressed due to improved characteristics of the atmospheric gasoil stream

<p dir="rtl">10 234 and coker gas oil stream 254. Distillate fuel stream is introduced</p>

272 Outflow from the hydrocarbon oil gas 270 processor to the distillate fuel collection tank

.204 fuel collection tank

The coker naphtha stream 252 coker naphtha stream, along with the 232 straight run naphtha stream, is sent to the naphtha hydrotreater

<p dir="rtl">15 280. Due to the fact that the coker naphtha stream 252 and the straight-line operating naphtha stream 232 contain</p>

contains smaller amounts of sulfur and aromatic compounds than they would normally contain. In the absence of the pretreatment steps described by reference to Figures 1-4, it may not be necessary for the hydrocarbon processing unit 280 to perform desulfurization of the hydrocarbon as would normally be required, allowing for increased productivity and Ultimately greater production of gasoline parts.

<p dir="rtl">20 Another advantage of the embodiment of the systems and methods shown, which also allows for increased productivity in the delayed coking process unit 250, is the fact that the atmospheric gas oil stream 234 may have a significantly lower sulfur content.</p>

The discharge gas oil stream 242 can be sent together with a heavy stream of coker gas oil 256 to the hydrocarbon cracker 260 for upgrading to form a hydrocracked naphtha stream.

<p dir="rtl">25 262 naphtha stream and hydrocracked middle distillate stream</p>

264 middle distillate stream, with a middle distillate stream fed by hydrocarbon cracking

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264, along with the distillate fuel stream 272, to the distillate fuel collection tank 204.

The hydrocarbon processing naphtha stream 282 and the hydrocarbon cracking naphtha stream 262 are fed to the naphtha reformer 290, where the hydrocarbon processing naphtha stream 282 and the hydrocarbon cracking naphtha stream can be converted

<p dir="rtl">5 262 From low-octane fuels to high-octane liquid products</p>

It is known as gasoline 292. It is believed that naphtha reformer 290 may rearrange or restructure hydrocarbon molecules in naphtha feedstocks in addition to breaking some molecules into smaller molecules. The overall effect may be that the product reforming product contains hydrocarbons that have more complex molecular shapes with greater octane values than the hydrocarbons in the ores.

<p dir="rtl">10 Naphtha feed. Thus, the naphtha reformer 290 separates the hydrogen atoms from the hydrocarbon molecules and produces large quantities of byproduct hydrogen gas for use as a make-up hydrogen feed stream 114 in accordance with Figures 1-4.</p>

Conventionally operated coke refineries will be limited in production by a 250 delayed coking unit. Therefore the maximum refining production will also be limited by the maximum possible production quantity.

<p dir="rtl">15 Through a delayed coking process unit. However, the pre-treatment systems and methods helpfully described allow an increased amount of heavy oil to be processed through refining with surprisingly improved results.</p>

If, as in the case of the systems and methods described, upgraded heavy oil can be processed in the refinery as shown in Figure 5, a reduction in at least the sulfur and aromatic content will beneficially affect postprocess performance.

<p dir="rtl">20 In embodiments in which the upgraded heavy oil is combined with unprocessed crude oil as feedstock for subsequent refining operations (not shown), for example a delayed coking facility containing a delayed coking unit, the delayed coking unit may be operated at the same coal handling capacity Essentially the coke originally designed, but with improved yields in all liquid products and improved quality of petroleum coke (less sulfur and metals). One of the positive impacts on</p>

<p dir="rtl">25 The late coking process unit 250 is that the feed stream will contain less minerals, carbon and sulfur,</p>

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High grade crude oil acts as a diluent. A lower sulfur effect will mean that the final coke product will be of a higher grade, resulting in increases in the raw coke stream 258.

Another refinery embodiment 300, shown in Figure 6, includes a coke refinery having a fluid catalytic cracking conversion unit, which uses the same bottoms conversion but a different vacuum gas oil conversion. in

<p dir="rtl">5 In this embodiment, the upgraded oil stream 220 can be fed to this refinery as in Figure 5. The embodiments of Figures 5 and 6 are identical except that Figure 6 uses a combination of a vacuum gas oil hydrocarbon processing unit 225 and a fluid catalytic cracking conversion unit 265 instead of a hydrocarbon cracking unit. As described by reference to the process depicted in Figure 5, pretreatment of the 220 grade oil stream will affect many or all of these process units within the refining configuration according to Figure 6.</p>

<p dir="rtl">10 The benefits seen with the 250 delayed coker are similar to the previous model, such as increased liquid throughput and reduced coke production. As discussed previously. This may enable higher throughput through the later coking unit 250, thus allowing higher throughput through refining. In addition, there may be overcapacity of another coker gas oil stream 254 in the gas oil hydrocarbon processing unit 270, due to the low sulfur content of the coker gas oil stream 254</p>

<p dir="rtl">15 And its impact on the low hydrocarbon desulfurization requirements of the 270 TPH processing unit.</p>

As depicted in Figure 6, a desulfurized vacuum 257 gas oil stream (from the vacuum gas oil 255 hydrotreater) can be fed to the FCC conversion unit 265, where it can be processed by cracking

<p dir="rtl">20 To produce multiple art streams. These streams may include a light cycle oil stream 266, a FCC gasoline stream 267, and a heavy cycle oil stream 269. The light ring oil stream 266 may be combined with the atmospheric gas oil stream 234 and the coker gas oil stream 254 at the gas oil hydrocarbon processing unit 270 to form the distillate fuel stream 272. The heavy ring oil stream 269 may be combined with the combined stream 246 at the storage tank.</p>

<p dir="rtl">25 Fuel oil collection 206. The FCC gasoline stream 267 may be joined by a gasoline stream 292 at the gasoline sump collection tank 202.</p>

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Examples

Various types of methods and systems for upgrading heavy fuel will also be illustrated through the following examples. The examples are illustrative in nature and should not be understood as limiting the scope of the research subject matter of the present disclosure.

<p dir="rtl">5 Example 1 – Preparation of a mesoporous hydrocarbon cracking catalyst</p>

A hydrocarbon cracking catalyst comprising a mesoporous zeolite is composed as described previously in this disclosure. 74.0 g of commercial NaY zeolite (commercially available as 100-CBV from Zeolyst) was added to 400 milliliters (mL) of 3 M sodium hydroxide (NaOH) solution and mixed at 100 °C for 12 hours. Then 60.0 g of bromide was added

<p dir="rtl">10 Cetyl trimethylammonium bromide (CTAB) in a mixture prepared under acid control at pH 10 with a 3 M hydrochloric acid solution. The mixture was aged at 80°C for 9 hours, and then transferred to a stainless steel autoclave lined with pteflon and crystallized at 100 °C for 24 h. After crystallization, the sample was washed with deionized water, dried at 100 °C for 12 h, and calcined at 550 °C.</p>

<p dir="rtl">15 For 6 hours. The sample was ion exchanged with 2.5 M ammonium nitrate solution (NH4NO3) at 90°C for 2 hours, and then steam treated (at a flow rate of 1 milliliter per minute (ml/min)) at 500°C for 1 hour. The sample ions were then exchanged again with 2.5 M ammonium nitrate solution, and finally the sample was dried at 100 °C for 12 hours and calcined at 550 °C for 4 hours to form zeolite Y.</p>

<p dir="rtl">20 Medium pores. In a mortar, 34 g of mesoporous zeolite Y, 15 g of molybdenum trioxide, 20 g of nickel(II) nitrate hexahydrate (Ni(NO3)2•6H2O)(II), and 30. 9 g of alumina (commercially available as 14/150 PURALOX® HP from Sasol). Then, 98.6 g of alumina binder (commercially available as CATAPAL® from Sasol) and dilute nitric acid (with a loss on ignition of 70% by weight) were added (, which</p>

<p dir="rtl">25 I knead the mixture to form a paste by adding an appropriate amount of water. The dough was extruded by</p>

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An extrusion device for creating a cylindrical extrusion product. The extruded product was dried at 110 °C overnight and calcined at 500 °C for 4 h.

Example 2 – Preparation of a conventional hydrocarbon cracking catalyst

A conventional hydrocarbon cracking catalyst (including microporous zeolite) was produced

<p dir="rtl">5 zeolite) by a method similar to Example 1 where a commercial microporous zeolite was used. In a slurry, gently mix 34 g of microporous zeolite (commercially available as 600-ZEOLYST® CBV from Micrometrics), 15 g of molybdenum trioxide, 20 g of Ni(NO3)26H2O, and 30.9 g of alumina (commercially available as 14/150 PURALOX® HP from Sasol). Then, 98.6 g of boehmite alumina binder (commercially available as CATAPAL®) was added. From Sasol(</p>

<p dir="rtl">10 and diluted nitric acid (with a loss on ignition of 70% by weight), which pasted the mixture to form a paste by adding an appropriate amount of water. The paste was extruded by an extruder to form a cylindrical extruded product. The extruded product was dried at 110°C overnight and calcined at 500°C for 4 hours.</p>

Example 3 - Analysis of prepared hydrocarbon cracking gases

<p dir="rtl">15 The catalysts prepared in Examples 1 and 2 were analyzed by Brunauer–Emmett–Teller analysis to determine the surface area and pore volume. Additionally, the surface area and pore volume were determined for micropores (less than 2 nm) and for mesopores (larger than 2 nm). The results are shown in Table 2, which show that the catalyst with Example 1 (conventional) had a micropore surface area and pore volume Minute greater than the surface area of the mesopore and the volume of the mesopore additionally, the catalyst with e.g</p>

<p dir="rtl">20 2 had a mesopore surface area and a mesopore volume larger than the micropore surface area</p>

And the size of fine pores. These results indicate that the catalyst with Example 1 was microporous (i.e., an average pore size of less than 2 nm) and that the catalyst with Example 2 was mesoporous (i.e., an average pore size of at least 2 nm).

Table 2 - Analysis of the porosity of the cement using Example 1 and Example 2

<tr><td><p dir="rtl">Catalyst example 1</p></td><td><p dir="rtl">Example 2 catalyst (conventional)</p></td><td><p dir="rtl">the sample</p></td></tr><tr><td><p>895</p></td><td><p>902</p></td><td><p dir="rtl">Surface area (m²/g(</p></td></tr>

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<tr><td><p>415</p></td><td><p>747</p></td><td><p dir="rtl">Micropores (&lt;2 nanometers) m²/g(</p></td></tr><tr><td><p>480</p></td><td><p>155</p></td><td><p dir="rtl">Mesopores (&gt;2 nm) (m /g)</p></td></tr><tr><td><p>53.6</p></td><td><p>17.2</p></td><td><p dir="rtl">Average pore ratio (%)</p></td></tr><tr><td><p>1.05</p></td><td><p>0.69</p></td><td><p dir="rtl">Pore volume, ml/g</p></td></tr><tr><td><p>0.25</p></td><td><p>0.41</p></td><td><p dir="rtl">Micropores (&lt; 2 nm) (ml/g)</p></td></tr><tr><td><p>0.8</p></td><td><p>0.28</p></td><td><p dir="rtl">Mesopores (&gt;2 nm) (ml/g)</p></td></tr><tr><td><p>76.2</p></td><td><p>40.6</p></td><td><p dir="rtl">Average pore ratio (%)</p></td></tr>

Example 4 - Preparation of a catalyst for the removal of nitrogen from a mesoporous hydrocarbon

The mesoporous hydrocarbon denitrification catalyst was prepared by the described method, whereby the mesoporous hydrocarbon denitrification catalyst had an average measured pore size of 29.0 nm. First, 50 g of mesoporous alumina was prepared by mixing 68.35 g of 5 boehmite alumina powder (commercially available as CATAPAL® from Sasol) in 1000 ml of water at

80 Celsius. Then, 378 ml of one molar nitric acid was added by molar ratio⁺H to⁺Al³ It equals 1.5 and the mixture was mixed at 80°C for 6 hours to obtain a solution. Then, 113.5 g of triblock copolymer (commercially available as PLURONIC® P123 from BASF) was dissolved in the solution at room temperature and then aged for 3 hours, where the molar ratio of 10 copolymer to aluminum was 0.04). The mixture was dried at 110°C overnight and then calcined at 500°C for 4 hours to form mesoporous alumina.

The catalyst was prepared from mesoporous alumina by mixing 50 g (dry basis) of mesoporous alumina with 41.7 g (12.5 g of alumina dry basis) of acid treated alumina (commercially available as CATAPAL® from Sasol). Appropriate water to 15 mixture to form a paste, and the paste was extruded to form three-lobed extruded products and the extruded products were dried

at 110°C overnight and calcined at 550°C for 4 hours. The calcined extrudates were impregnated with a wet initiator of 50 ml of aqueous solution containing 94.75 g of ammonium heptanmolybdate, 12.5 g of nickel nitrate, and 3.16 g of nickel nitrate.

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Phosphoric acid. The impregnated catalyst was dried at 110 °C overnight and calcined at 500 °C for 4 h.

Example 5 - Preparation of a conventional hydrocarbon denitrification catalyst

A conventional alumina catalyst was prepared by mixing 50 g (dry basis) of alumina (commercially available as 14/150 PURALOX® HP from Sasol) with 41.7 g (i.e., 12.5 g of alumina

On a dry basis) of acid peptized alumina (commercially available as CATAPAL® from Sasol). An appropriate amount of water was added to the mixture to form a paste, and then, the paste material was extruded to form trilobe extrudates. The products were dried Extruded at 110 °C overnight and calcined at 550 °C for 4 h the products were impregnated

<p dir="rtl">10 Calcinated extrudates with a wet starter of 50 ml of an aqueous solution containing</p>

94.75 g of ammonium molybdate, 12.5 g of nickel nitrate, and 3.16 g of phosphoric acid. The impregnated catalyst was dried at 110 °C overnight and calcined at 500 °C for 4 h. The conventional hydrocarbon denitrification catalyst had an average pore size of 10.4 nm.

<p dir="rtl">15 Example 6 - Catalytic performance of the prepared hydrocarbon denitrification catalyst</p>

To compare the reaction performance of the AZT catalyst Example 4 and Example 5, both catalysts were tested in a fixed bed reactor. In each run, 80 ml of the chosen catalyst was loaded. The feedstock properties, operating conditions, and results are summarized in Table 3. The results showed that the hydrocarbon nitrogen removal performance of the catalyst in Example 4 is better than that of the conventional catalyst in Example 5.

<p dir="rtl">20 Table 3 - Analysis of the porosity of the cement using Example 4 and Example 5</p><table border="1"><tbody><tr><td><p dir="rtl">Example 4</p></td><td><p dir="rtl">Example 5 (traditional)</p></td><td><p dir="rtl">Nutrition oil</p></td><td><p dir="rtl">Catalyst</p></td></tr><tr><td></td><td></td><td></td><td><p dir="rtl">Circumstances</p></td></tr><tr><td><p>390</p></td><td><p>390</p></td><td></td><td><p dir="rtl">Temperature (°C)</p></td></tr><tr><td><p>150</p></td><td><p>150</p></td><td></td><td><p dir="rtl">Pressure (bar)</p></td></tr></tbody></table>

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<tr><td><p>0.5</p></td><td><p>0.5</p></td><td></td><td><p dir="rtl">The ratio of the weight of the feed liquid to the weight of the catalyst</p><p>Liquid hourly space per hour per hour(( (LHSV) velocity</p></td></tr><tr><td><p>1200</p></td><td><p>1200</p></td><td></td><td><p dir="rtl">Hydrogen/oil ratio (L/L)</p></td></tr><tr><td colspan="4"></td></tr><tr><td></td><td></td><td></td><td><p dir="rtl">Product properties</p></td></tr><tr><td><p>0.8391</p></td><td><p>0.8423</p></td><td><p>0.8607</p></td><td><p dir="rtl">Density</p></td></tr><tr><td><p>86.51</p></td><td><p>86.43</p></td><td><p>85.58</p></td><td><p dir="rtl">C (% by weight)</p></td></tr><tr><td><p>13.44</p></td><td><p>13.45</p></td><td><p>12.37</p></td><td><p dir="rtl">H (% by weight)</p></td></tr><tr><td><p>298</p></td><td><p>764</p></td><td><p>19810</p></td><td><p dir="rtl">S (ppm by weight)</p></td></tr><tr><td><p>169</p></td><td><p>388</p></td><td><p>733</p></td><td><p dir="rtl">N (ppm by weight)</p></td></tr><tr><td colspan="4"></td></tr><tr><td><p>17.62</p></td><td><p>17.00</p></td><td><p>20.19</p></td><td><p dir="rtl">180 – C5 °C (% by weight)</p></td></tr><tr><td><p>39.00</p></td><td><p>36.93</p></td><td><p>30.79</p></td><td><p dir="rtl">180-350°C (% by weight)</p></td></tr><tr><td><p>29.12</p></td><td><p>30.65</p></td><td><p>30.27</p></td><td><p dir="rtl">350-540 °C (% by weight)</p></td></tr><tr><td><p>12.67</p></td><td><p>14.32</p></td><td><p>18.75</p></td><td><p dir="rtl">&lt; 540°C</p></td></tr>

Example 7 - Catalytic performance of a hydrocarbon denitrification and hydrotreating catalyst

To compare a conventional catalyst system, including the catalyst of Example 2 and the catalyst of Example 5 with a catalyst system including the catalyst of Example 1 and the catalyst of Example 4, experiments were performed in a four-layer reactor unit. The four-layer reactor unit included a hydrocarbon demineralization catalyst, a transition catalyst, and a demineralization catalyst.

<p dir="rtl">5 Nitrogen of hydrocarbon, hydrocarbon cracking catalyst, all arranged in succession. She was</p>

Feed and reactor conditions are the same as those listed in Table 3. Table 4 shows the components and volumetric amounts of each component in the sample systems. A 300 ml reactor was used for the test.

Table 4 – Catalyst layer loading

<tr><td><p dir="rtl">Size (ml)</p></td><td><p dir="rtl">Sample system 2</p></td><td><p dir="rtl">Sample system 1 (conventional)</p></td><td></td></tr>

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<tr><td><p>15</p></td><td><p dir="rtl">Catalyst for removing metals from hydrocarbons</p><p dir="rtl">Commercially available</p></td><td><p dir="rtl">Hydrocarbon demineralization catalyst available</p><p dir="rtl">Commercially</p></td><td><p dir="rtl">Catalyst for removing metals from hydrocarbons</p></td></tr><tr><td><p>15</p></td><td><p dir="rtl">A transition catalyst with the functions of removing metals from hydrocarbons and removing sulfur from</p><p dir="rtl">Hydrocarbon available</p><p dir="rtl">Commercially</p></td><td><p dir="rtl">Transition catalyst with metal removal functions</p><p dir="rtl">Hydrocarbon and its removal</p><p dir="rtl">Sulfur from</p><p dir="rtl">Hydrocarbon available</p><p dir="rtl">Commercially</p></td><td><p dir="rtl">Transition catalyst</p></td></tr><tr><td><p>90</p></td><td><p dir="rtl">Motivator with example 4</p></td><td><p dir="rtl">Motivator with example 5</p></td><td><p dir="rtl">Removal catalyst</p><p dir="rtl">Nitrogen from</p><p dir="rtl">hydrocarbon</p></td></tr><tr><td><p>30</p></td><td><p dir="rtl">Motivator with example 1</p></td><td><p dir="rtl">Motivator with example 2</p></td><td><p dir="rtl">Cracking catalyst</p><p dir="rtl">hydrocarbon</p></td></tr>

Table 5 shows the catalytic results for Sample System 1 and Sample System 2 in Table 4 with ratios of feed liquid weight to catalyst weight per hour of 0.2/hour and 0.3/hour. The results showed that the catalyst system that included the catalysts in Example 1 and Example 4 (sample system 2) showed better performance in removing nitrogen from the hydrocarbon, removing sulfur from the hydrocarbon, and converting the residue above 540 degrees Celsius.

5 Table 5 – Catalyst performance results

<tr><td colspan="2"><p>0.3</p></td><td colspan="2"><p>0.2</p></td><td><p dir="rtl">Feed liquid to catalyst weight per hour (/hour)</p></td></tr><tr><td><p dir="rtl">Catalyst system 2</p></td><td><p dir="rtl">Catalyst system 1 (conventional)</p></td><td><p dir="rtl">Catalyst system 2</p></td><td><p dir="rtl">Catalyst system 1 (conventional)</p></td><td><p dir="rtl">Catalyst system</p></td></tr><tr><td colspan="5"><p dir="rtl">Product properties</p></td></tr>

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<tr><td><p>0.8181</p></td><td><p>0.8442</p></td><td><p>0.771</p></td><td><p>0.8306</p></td><td><p dir="rtl">Density</p></td></tr><tr><td><p>238</p></td><td><p>301.7</p></td><td><p>230</p></td><td><p>73</p></td><td><p dir="rtl">Sulfur</p><p dir="rtl">(ppm by weight)</p></td></tr><tr><td><p>23</p></td><td><p>237.3</p></td><td><p>&gt;5</p></td><td><p>5</p></td><td><p dir="rtl">Nitrogen</p><p dir="rtl">(ppm by weight)</p></td></tr><tr><td colspan="5"><p dir="rtl">Product yield,% by weight</p></td></tr><tr><td><p>0.6</p></td><td><p>0.4</p></td><td><p>0.4</p></td><td><p>0.3</p></td><td><p>C1</p></td></tr><tr><td><p>0.3</p></td><td><p>0.4</p></td><td><p>0.6</p></td><td><p>0.3</p></td><td><p>C2</p></td></tr><tr><td><p>0.5</p></td><td><p>0.8</p></td><td><p>2.1</p></td><td><p>0.4</p></td><td><p>C3</p></td></tr><tr><td><p>0.1</p></td><td><p>0.1</p></td><td><p>3.8</p></td><td><p>0.1</p></td><td><p>nC4</p></td></tr><tr><td><p>0.6</p></td><td><p>0.5</p></td><td><p>2.7</p></td><td><p>0.4</p></td><td><p>iC4</p></td></tr><tr><td><p>24.4</p></td><td><p>17.0</p></td><td><p>53.3</p></td><td><p>18.4</p></td><td><p dir="rtl">&gt; 180 degrees</p><p dir="rtl">percentage</p></td></tr><tr><td><p>46.1</p></td><td><p>37.4</p></td><td><p>31.7</p></td><td><p>41.4</p></td><td><p dir="rtl">350-180 degrees</p><p dir="rtl">percentage</p></td></tr><tr><td><p>22.0</p></td><td><p>30.6</p></td><td><p>3.2</p></td><td><p>30.5</p></td><td><p dir="rtl">540-350 degrees</p><p dir="rtl">percentage</p></td></tr><tr><td><p>3.9</p></td><td><p>13.0</p></td><td><p>0.0</p></td><td><p>8.4</p></td><td><p dir="rtl">540 °C&gt;</p></td></tr><tr><td><p>96.4</p></td><td><p>98.1</p></td><td><p>88.1</p></td><td><p>98.7</p></td><td><p>C5+</p></td></tr>

It is noted that one or more of the following claims use the term “where” as a transitional word.

For the purposes of defining current technology, it is noted that this term is included in the protection elements

It is an open-ended transitional statement used to introduce an account of a series of properties of a structure that should be interpreted

In the same way as the more commonly used term for the open preamble "includes".

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It should be understood that any two quantitative values assigned to a property may constitute a range of that property, and all combinations of ranges consisting of all quantitative values assigned to a particular property are contemplated in this disclosure.

After describing the research subject matter of the present disclosure in detail and with reference to specific embodiments, it is noted that

<p dir="rtl">5 The various details described in this disclosure should not be taken to mean that such details relate to items that are essential components of the various models described in this disclosure, even in cases where a particular item is illustrated in each of the drawings accompanying the present description. Instead, the safeguards appended herein should be considered the sole representation of the breadth of the present disclosure and the corresponding scope of the various embodiments described in this disclosure. Furthermore,</p>

<p dir="rtl">10 It will be clear that modifications and changes are possible without deviating from the scope of the attached protection elements. The present disclosure includes one or more non-limiting aspects. The first aspect may include a method for processing heavy oil, and the method includes: raising the grade of at least a portion of the heavy oil to form a higher grade oil, and raising the grade includes contacting the heavy oil with a hydrocarbon demineralization catalyst, a transition catalyst, and a denitrification catalyst. Hydrocarbon, cracking catalyst</p>

<p dir="rtl">15 hydrocarbon to remove at least part of the minerals, nitrogen, or aromatic content of the heavy oil and form a higher grade oil; At least part of the high-grade oil is passed to the refining process.</p>

The second aspect may include a method for processing heavy oil. The method includes: raising the grade of at least part of the heavy oil to form higher grade oil. Raising the grade includes contact with the heavy oil.

<p dir="rtl">20 with a hydrocarbon demineralization catalyst, a transition catalyst, a hydrocarbon denitrification catalyst, and a hydrocarbon cracking catalyst for removing at least a portion of the metal, nitrogen, or aromatic content from the heavy oil and forming the higher grade oil; passing at least a portion of the high grade oil to a refining process; The final boiling point of high grade oil is less than or equal to 540 degrees Celsius.</p>

<p dir="rtl">25 A third aspect may include a method of processing heavy oil, the method comprising: upgrading at least a portion of the heavy oil to form a higher grade oil, the upgrading comprising contacting the heavy oil with a catalyst</p>

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10

15

20

Hydrocarbon demineralization, a transition catalyst, a hydrocarbon denitrification catalyst, and a hydrocarbon cracking catalyst for the removal of at least a portion of the metals, nitrogen, or aromatic content of the heavy oil and the composition of the high grade oil; Passing at least a portion of the high-grade oil to the refining process; The heavier components of higher grade oil are passed to the refining process.

Another aspect includes any of the foregoing aspects, wherein the final boiling point of the elevated oil is less than or equal to 540°C; At least the heavier components of higher grade oil are passed into the refining process; Or both.

Another aspect includes any of the foregoing, wherein the hydrocarbon demineralization catalyst, the transition catalyst, and the hydrocarbon denitrification catalyst are respectively placed in a plurality of reactors; The hydrocarbon cracking catalyst is placed in a reactor after the reactor group. Another aspect includes any of the previous aspects, where the reactor after the reactor group is a packed bed reactor.

Another aspect includes any of the previous aspects, where the reactor after the reactor group is a fluidized bed reactor.

Another aspect includes any of the above, where the refining process is coke refining. Another aspect includes any of the above, coke refining involves a hydrocarbon cracking process unit.

Another aspect includes any of the above, where coke refining includes a fluid catalytic cracking conversion unit.

Another aspect includes any of the above, where the refining process involves an atmospheric distillation column, and where the high-grade oil is passed to an atmospheric distillation column.

Another aspect including any of the foregoing, wherein the hydrocarbon cracking catalyst comprises a mesoporous zeolite and one or more minerals, wherein the mesoporous zeolite has an average pore size ranging from 2 nm to 50 nm.

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Another aspect includes any of the foregoing aspects, wherein the hydrocarbon denitrification catalyst includes one or more metals on an alumina carrier, and the alumina carrier has an average pore size ranging from 2 nanometers to 50 nanometers.

Another aspect includes any of the previous aspects, where heavy oil includes crude oil, and where crude oil has a specific gravity according to the American Petroleum Institute that ranges from 25 degrees to 50 degrees.

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