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:

<p dir="rtl">5 Including crude oils, to form chemical products and intermediate compounds</p>

.intermediaries

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 of minerals, including

<p dir="rtl">10 involves hydrodemetallation treatment with at least two switchable reaction zones, containing a hydrodemetallation catalyst and optionally a hydrodenitrification catalyst, followed by hydrorefining treatment to reduce the organic nitrogen content, followed by fixed-bed hydrocracking treatment fixed-bed hydrocracking treatment</p>

<p dir="rtl">15 And a refining step.</p>

U.S. Application No. 1A 2016/369185 is directed to a process for converting high boiling point hydrocarbon feedstock into lower boiling hydrocarbon products. The lighter boiling hydrocarbon products are suitable as feedstock for petrochemical processes. Said conversion process includes the following steps: Boiling &lt; 350°C

<p dir="rtl">20 To cascade falls with hydrocracking unit(s), feeding the bottom stream to the hydrocracking unit as feedstock for a subsequent hydrocracking unit, where the process conditions for each hydrocracking unit are different from the other, as the hydrocracking conditions increase the hydrocracking unit The first to the next unit in terms of</p>

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Intensity, and processing of the lower boiling hydrocarbon products between each hydrocracking unit as feedstock for one or more petrochemical processes.

European Patent No. 1A 1600491 is directed to a process for the catalytic hydrotreatment of crude oil or heavy oil from which the naphtha fraction and lighter parts of the naphtha fraction 5 are removed by combined exposure of the crude oil or crude oil from which the naphtha fraction is removed. And a lighter part than

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

Of mesopores on the inner surface of mesopore titanium-group metal oxide particles 10

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, 8, 9 and 10 of 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.

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 basic intermediates. intermediates for a large portion of the petrochemical industry20. 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 Gas oil In addition, petrochemical feedstocks can be converted into transportation fuels such as gasoline, diesel, etc. 25 However, as the demand for these basic intermediate compounds such as fuel increases, production methods other than traditional refining operations must be considered.

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General description of the invention

There is a need for processes that produce chemical intermediates, such as ethylene, propylene, butenes, butadiene, and aromatic compounds such as benzene, toluene, and xylene from heavy oil feeds, such as crude oil. In one or more embodiments, processing operations are described

<p dir="rtl">5 catalytic treatment processes (sometimes referred to herein as pretreatment, hydroprocessing, or hydrotreating) and catalysts for use in these processes. In one or more embodiments, the catalyst for use in these processes has enhanced catalytic functionality and, in particular, has Enhanced functional performance for the breakdown of aromatic compounds. Through these catalytic treatment processes, heavy oils can be upgraded and converted into chemical intermediates.</p>

<p dir="rtl">10 At least by subsequent steam cracking. Steam cracking can be performed without any intermediate steps</p>

Which reduces the final boiling point of upgraded oil.

The catalytic treatment process currently described (i.e., upgrading) may have enhanced catalytic functionality with respect to reducing at least the aromatic content, metal content, and nitrogen content of the crude oil feedstock, which may be refined

<p dir="rtl">15 Later to petrochemical products required through a number of processes</p>

Different ones are shown here. According to one or more embodiments, the heavy oils may be treated by four sequentially arranged desorption catalysts, wherein the primary function of the first catalyst (i.e., the hydrodemetalization catalyst) is to remove metals from the heavy oil, the primary function of the second catalyst (i.e., the hydrodemetalization catalyst) is to remove metals from the heavy oil. Transition catalyst (transition catalyst) is the removal of metals, sulfur, and nitrogen

<p dir="rtl">20 of heavy oil and providing a transition area between the first and third catalysts. The primary function of the third catalyst (i.e., the hydrodenitrogenic catalyst) is also to remove nitrogen, sulfur, or both, and saturate the aromatic compounds from the heavy oil. The primary function of the Four (i.e., hydrocracking catalyst) are to reduce the aromatic content in the heavy oil. The pretreatment process as a whole may</p>

<p dir="rtl">25 To one or more increases in the concentration of paraffins, the concentration of aromatic hydrocarbons decreases</p>

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Polynuclear aromatic hydrocarbons, lowering the final boiling point of pretreated oil for heavy oil feedstock.

After hydrotreatment, the upgraded heavy oil can be further processed by steam cracking. For example, upgraded heavy oil can be passed directly to...

<p dir="rtl">5 Steam cracker for processing. In additional embodiments, there may be some intermediate steps, but the heavier fraction of the upgraded heavy oil may be retained in the steam-cracking stream.</p>

According to one or more embodiments herein described, the heavy oil may be processed by a method which may include upgrading at least a portion of the heavy oil to form upgraded oil, wherein the upgrading comprises communication

<p dir="rtl">10 heavy oil with a hydrodemineralization catalyst, a transition catalyst, a hydrodenitrification catalyst, and a hydrocracking catalyst to remove at least a portion of the metal, nitrogen, or aromatic content of the heavy oil and form the refined oil; passing the upgraded oil to the steam cracking unit and cracking the upgraded oil to form a steam-cracked effluent; Where the final boiling point of the refined oil is less than or equal to 540 degrees Celsius.</p>

<p dir="rtl">15 According to one or more additional embodiments presently described, heavy oil may be processed by a method which may</p>

It includes upgrading at least a portion of the heavy oil to form a upgraded oil, wherein the upgrading comprises contacting the heavy oil with a hydrodemineralization catalyst, a transition catalyst, a hydrodenitrification catalyst, and a hydrocracking catalyst to remove at least a portion of the minerals, nitrogen, or aromatic content of the oil Heavy and refined oil; The refined oil is passed to a steam and oil cracking unit

<p dir="rtl">20 Steam quencher to form a stream that has been steam crushed; The heavier components at least of the refined oil are passed directly to the steam cracking unit.</p>

Additional features and benefits of the technology described in this disclosure will be identified in the following detailed description, and will be partially readily apparent to those experts in the field from the description or are realized by practicing the technology as described in this disclosure, including in the following detailed description, elements 25 protection, plus attached drawings.

Brief explanation of the drawings

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The following detailed description of specific embodiments of the present disclosure can be better understood when read in conjunction with the following drawings, where similar construction is indicated by similar reference numbers and which have:

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

<p dir="rtl">5 Figure 2 depicts a general schematic diagram of a chemical pretreatment system which includes an HDM hydrodemetalization catalyst, a transition catalyst, an HDN hydrodenitrification catalyst, and a hydrocracking catalyst, according to one or more embodiments described in this disclosure;</p>

Figure 3 depicts a general block diagram of a chemical pretreatment system that includes a demineralization catalyst

<p dir="rtl">10 Hydrogenation, transition catalyst, hydrogenation denitrification catalyst, and pretreatment reactor</p>

A downstream packed bed reactor comprising a hydrocracking catalyst, according to one or more embodiments described in this disclosure;

Figure 4 shows a general diagram of a chemical pretreatment system that includes a hydrodemineralization catalyst, a transition catalyst, a hydrodenitrification catalyst, and a fluidized bed pretreatment reactor.

<p dir="rtl">15 In the same direction comprising a hydrocracking catalyst, according to one or more embodiments described in this disclosure;</p>

Figure 5 depicts a general diagram of a chemical processing system used after a chemical pretreatment system in which the upgraded heavy oil is fed directly to a steam cracker, according to one or more embodiments described in this disclosure; And

<p dir="rtl">20 Figure 6 depicts a general diagram of a chemical treatment system used after a chemical pretreatment system where the light fraction of the upgraded heavy oil is fed directly into a cracking unit</p>

By steam, the heavy fraction of the upgraded heavy oil is recycled to the pretreatment system, according to one or more embodiments described in this disclosure.

For the purpose of simplified schematic illustrations and descriptions in Figures 1-6, valves are not included

<p dir="rtl">25 Multiple valves, temperature sensors, electronic controllers and the like which may be used and well known to these lay experts.</p>

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In the field of certain chemical treatment processes. Furthermore, associated components that are often included in conventional chemical processing operations, such as refineries, such as, for example, air supplies, catalyst hoppers, and flue gas handlers are not depicted. It will be known that these ingredients are included in the spirit

<p dir="rtl">5 The scope of current models is shown. However, operational components, such as those described in the present disclosure, may be added to embodiments described in this disclosure.</p>

It should also be noted that the arrows in the graphics indicate process streams. However, arrows may equivalently indicate transfer lines which may serve to transfer process currents between two or more system components. Additionally, arrows that connect components identify

<p dir="rtl">10 System inputs or outputs in each particular system component. The direction of the arrow generally corresponds to the main direction of movement of materials of stream within the physical transfer line indicated by the arrow. Furthermore, arrows not connecting two or more system components indicate a product stream that may exit the depicted system or a system inlet stream that may enter the depicted system. Product streams can be processed</p>

<p dir="rtl">15 Additional streams 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 a facultative step or facultative current. For example, there may be recycle streams in the system</p>

<p dir="rtl">20 optional. However, it should be realized that all connected lines may represent required transmission lines or chemical streams.</p>

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.

<p dir="rtl">25 Detailed description</p>

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10

In general, this disclosure describes various models of systems and methods for treating heavy oils such as crude oil. According to one or more embodiments, heavy oil processing may include an upgrading process followed by steam cracking. In general, the upgrading process may result in the removal of 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 breakdown of aromatic moieties in the heavy oil. According to one or more embodiments, the heavy oil may be processed using a hydrodemineralization catalyst (sometimes referred to in this disclosure as an “HDM catalyst”), a transition catalyst, a hydrodenitrification catalyst (referred to in this disclosure as an “HDN catalyst”), A hydrocracking catalyst, a transition catalyst, a hydrogen denitrification catalyst and a hydrocracking catalyst may be located in series, either in a single reactor, such as a packed bed reactor with several layers, or in a group of reactors.

reactors arranged in a row.

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 "chemical treatment system", or alternatively as a "post pretreatment process" or "final treatment".

<p dir="rtl">15 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 (i.e., post-pretreatment process) via steam cracking. It should be recognized that any models of pretreatment systems, such as those depicted In Figures 1-4 or described in relation to Figures 1-4, can</p>

<p dir="rtl">20 Use it 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.</p>

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 optionally in the presence of one or more catalysts. For example, a reactor may include a storage or reactor

<p dir="rtl">25 A tubular reactor configured to operate as a batch reactor, a continuous stirred-tank reactor (CSTR). Or a plug flow reactor.</p>

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Examples of reactors include packed bed reactors such as fixed bed reactors, and fluidized bed reactors. One or more reaction zones may be organized in the reactor. As used in this disclosure, “reaction zone” refers to a region where a particular reaction occurs in a reactor. For example,

<p dir="rtl">5 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.</p>

As used in this disclosure, “separation unit” refers to any 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 separate

<p dir="rtl">10 Chemical species differ from each other selectively, to form one or more chemical fractions. Without limitation, examples of separation units include distillation columns, flash drums, knock-out drums, knock-out pots, centrifuges, filtration devices, traps, scrubbers, etc. expansion devices, membranes, devices</p>

<p dir="rtl">15 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 separation processes described in this disclosure “at least partially” separate different chemical components from each other, even if not expressly stated so, and it should be understood that the separation may involve only partial separation. And as</p>

<p dir="rtl">20 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. In general, the light fraction stream has a lower boiling point than the heavy fraction stream. It should also be understood that where</p>

<p dir="rtl">25 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</p>

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distillation column with multiple outlets, and it is expected that different separators arranged in series may equally separate the feed stream and such embodiments are within the scope of the embodiments currently described.

It should be understood that “reaction effluent” generally refers to the current that exits a separator unit,

<p dir="rtl">5 A reactant, or reaction zone after a specific 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, a slip stream may carry some stream away, meaning only part of the stream enters the downstream system unit.</p>

<p dir="rtl">10 As used in this disclosure, “catalyst” refers to any substance that increases the rate of a specified chemical reaction.</p>

The catalysts described in this disclosure may be used to enhance various reactions, including, but not limited to, hydrodesulfurization, hydrodenitrification, hydrodearomatization, aromatic cracking, or combinations thereof. As used in this disclosure, “cracking” generally refers to

<p dir="rtl">15 A chemical reaction in which a molecule containing carbon-carbon bonds is broken down into more than one molecule by breaking one or more carbon-carbon bonds; Where a compound that includes a cyclic moiety, such as aromatic compounds, is transformed into a compound that does not include a cyclic moiety. Or where a molecule containing carbon-carbon double bonds is reduced to carbon-carbon single bonds. Some stimuli may contain multiple forms of catalytic activity, and naming a stimulus does not</p>

<p dir="rtl">20 with one specific function rendering this 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 may also include mixing by direct introduction of both streams into a reactor, separation unit, or other system component that is identical.</p>

<p dir="rtl">25 It should be understood that catalytic-promoted reactions 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, it may be a stripping catalyst</p>

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Hydrogenated metals present in an amount effective to promote a reaction that removes a portion of one or more metals from the process stream. The hydrodenitrification 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 hydrodesulfurization catalyst (HDS) may be present in an effective amount to promote the reaction that removes a portion of the sulfur present.

<p dir="rtl">5 In the process stream. In addition, a hydrocracking catalyst, such as an aromatic dehydrogenase catalyst, may be present in an effective amount to promote a reaction that reduces the amount of aromatic moieties in the process stream by saturating and cracking those aromatic moieties. It should be understood that, throughout this disclosure, a particular catalyst is not necessarily limited to the functionality of removing or breaking down a particular chemical moiety or component when it is indicated as having a particular functional performance. For example, the trigger specified in this could</p>

<p dir="rtl">10 Disclosed as a hydrodenitrification catalyst additionally providing the functional performance of hydrodearomatization (HDA), the functional performance of hydrodesulfurization, or both.</p>

15

20

25

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.

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 BET analysis. 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 hydrotreating catalyst system 132 according to Figure 1 are described in detail in Figures 2-4. However, it must be understood that the feed materials, products, recycling streams, etc., of the generalized pretreatment system 100 in accordance with Figure 1 also apply to the embodiments described in connection with Figures 2-4.

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Referring to Figure 1, according to embodiments of this disclosure, a heavy oil feed stream 101 may be mixed with a hydrogen stream 104. The hydrogen stream 104 may include unused hydrogen gas from a component stream, recycled process gas 113, make-up hydrogen from a stream

<p dir="rtl">5 Hydrogen feed 114 hydrogen feed stream, or both, for mixing with the heavy oil feed stream 101 and forming a pretreatment catalyst input stream 105. In one or more embodiments, the pretreatment catalyst input stream 105 may be heated to a process temperature of 350 degrees Celsius (C°) to 450°C. The pretreatment catalyst input stream 105 may enter and pass through the hydrotreating catalyst system 132. As such Described here, may</p>

<p dir="rtl">10 The hydrotreatment catalyst system 132 includes a series of reaction zones, including a hydrodemetalization reaction zone, a transition reaction zone, and a hydrodenitrification reaction zone.</p>

reaction zone, and hydrocracking reaction zone

The systems and processes described are applicable to a wide range of heavy oil feed materials (in Heavy Oil Feed Stream 15 101), including crude oils, vacuum residue, cat sands, etc.

tar sands, bitumen and vacuum gas oils using a catalytic hydrotreating pretreatment process. If the heavy oil feed is crude oil, it may have an American Petroleum Institute specific gravity of 25° to 50°. For example, the oil feed may be

<p dir="rtl">20 The heavy oil used is Arab Heavy crude oil. Typical properties of Arabian heavy crude oil are shown in Table 1.</p>

Table 1- Arab Heavy Export Feedstock

<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>

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<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">In terms of parts per million</p><p>Parts per million by weight (ppmw) weight</p></td><td><p>Nickel 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">Sodium chloride content</p><p>(NaCl) sodium chloride</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><p>Conradson Carbon</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 C5</p><p>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 C7</p><p>Asphaltenes</p></td></tr>

Still referring to Figure 1, the reaction effluent stream of pretreatment catalyst 109 may be formed by the interaction of the pretreatment catalyst input stream 105 with the hydrotreating catalyst stream 132. The reaction effluent stream of the pretreatment catalyst 109 may enter a separation unit 112 It can be separated into a recycled process gas component stream 113 and an intermediate liquid product stream 5 115 intermediate liquid product stream. In one embodiment, it can also be purified

Pretreatment catalyst reaction stream 109 to remove hydrogen sulfide and other process gases to increase hydrogen purity to be recycled in the recycled process gas component stream 113. The hydrogen consumed in the process can be compensated by adding pure hydrogen from the make-up hydrogen feed stream 114 make-up hydrogen feed stream, which may be

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Derived from steam, naphtha reformer, or other source. The recycled process gas component stream 113 and the make-up hydrogen feed stream 11 4 may combine to form a hydrogen stream 104. In one embodiment, the intermediate liquid product stream 115 may be separated in a separation unit 116 to separate the light hydrocarbon fraction stream 117 and the final liquid product stream

<p dir="rtl">5 of pretreatment 118; However, it should be understood that this separation step is optional. In other embodiments, the separation unit 116 may be a flash vessel. In one embodiment, the light hydrocarbon fraction stream 117 is recirculated and is mixed with a fresh light hydrocarbon diluent stream 102 to create a stream of</p>

Dilution of light hydrocarbons 103 light hydrocarbon diluent stream. Current can be used

<p dir="rtl">10 Pure light hydrocarbon diluent 102 as needed to provide a make-up diluent to the process to help further reduce the deactivation of one or more catalysts in the hydrotreatment catalyst system 132.</p>

In one or more embodiments, one or more of the pretreatment catalyst reaction stream 109, intermediate liquid product stream 115, and final pretreatment liquid product stream 118 15 may have a reduced aromatics content compared to the heavy oil feed stream 101. Additionally , in models,

One or more of the pretreatment catalyst reaction streams 109 may have an intermediate liquid product stream

115, and the final liquid product stream from pretreatment 118 has a significantly reduced content of sulfur, metals, asphaltenes, Co-Ardson carbon, nitrogen, or combinations thereof, as well as increased API specific gravity and increased diesel and vacuum distillate yields.

20 Vacuum distillate yields 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 95 wt% of nitrogen 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 85% by weight, a reduction

<p dir="rtl">25 not less than 90 wt%, or even a reduction of not less than 99 wt% of sulfur with respect to the stream</p>

Heavy oil feed 101. According to another embodiment, it may be a pretreatment catalyst reaction stream 109

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A reduction of at least about 70 wt%, a reduction of at least 80 wt%, or even a reduction of at least 85 wt% of the aromatics content with respect to the heavy oil feed stream 101. According to another embodiment, it may be in the pretreatment catalyst reaction stream 109 A reduction of at least about 80% by weight, a reduction of at least 90% by weight, or even a reduction of at least 99% by weight of the metal.

<p dir="rtl">5 Regarding heavy oil feed stream 101.</p>

With reference to Figure 1, in various embodiments, 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 suitable for use as an upgraded oil stream 220 for cracking systems. 400 and 500 steam cracking systems according to Figures 5 and 6, respectively, as described below.

<p dir="rtl">10 That's in this reveal. 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 “purchased oil” which may be finally treated by the systems according to Figs. 5 or 6 at least. Upgraded oils may, in some embodiments, have a final boiling point less than or equal to 540°C, which may increase the efficiency of other conversions in</p>

<p dir="rtl">15 Final steam cracking. In additional embodiments, at least 90% by weight, at least 95% by weight, or even at least 99% by weight of the refined oil may have a boiling point less than or equal to 540°</p>

percentage. In additional embodiments, the upgraded oil may have a final boiling point less than or equal to 520°

Celsius, 500°C, 480°C, 460°C, 440°C, 420°C

Celsius, 400°C, 380°C, 360°C, 340°C, 320°C

<p dir="rtl">20 Celsius, or up to 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>

Referring now to Figure 2, according to one or more embodiments, the system may include a processing catalyst

<p dir="rtl">25 Hydrogenation 132 or consisting of reaction zones with multiple packed layers arranged in succession (e.g., hydrogenation demineralization reaction zone 106, transition reaction zone 108, demineralization reaction zone</p>

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5

10

15

hydrogenated nitrogen 110, and a hydrocracking reaction zone 120) and each of these reaction zones may include a catalyst bed. Each of these reaction zones may be present in a single reactor such as a packed bed reactor with multiple layers in series, as shown as pretreatment reactor 130 in Figure 2. In these embodiments, the pretreatment reactor 130 includes a hydro-denitrification catalyst layer comprising a hydro-denitrification catalyst in the hydro-denitrification reaction region 106, a transition catalyst layer comprising a transition catalyst in the transition reaction region 108, a hydro-denitrification catalyst layer comprising a catalyst Hydrocracking in the hydrocracking reaction zone 110, and a hydrocracking catalyst layer comprising a hydrocracking catalyst in the hydrocracking reaction zone 120. In other embodiments, the hydrodemineralization reaction zone 106, the transition reaction zone 108, the hydrodenitrification reaction zone 110, and the hydrocracking reaction zone 120 may each be present in a plurality of packed bed reactors arranged in series. In other embodiments, each reaction zone is located in a single, separate packed bed reactor. 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...

It is recommended that these catalysts be contained in separate reactors.

According to one or more embodiments, the pretreatment catalyst input stream 105, which includes a heavy oil, is introduced to the hydrodemineralization reaction zone 106 and connected to the hydrodemineralization catalyst. The connection of the demineralization catalyst may be enhanced hydrogenally with the pretreatment catalyst input stream

<p dir="rtl">20 105 A reaction that removes at least a portion of the metals present in the processing catalyst input stream</p>

Pretreatment 105. After connecting to the hydrodemineralization catalyst, the pretreatment catalyst input stream 105 can be converted into a hydrodemineralization reaction stream. The hydrodemineralization reaction stream may have a reduced metal content compared to the contents of the pretreatment catalyst input stream 105. For example, the hydrodemineralization reaction stream may contain at least 70%

<p dir="rtl">25 by weight, at least 80 wt%, or even at least 95 wt% metals below the input current</p>

Pretreatment catalyst 105.

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

The hydrodemetalization catalyst may comprise one or more metals from groups 5, 6, or 8-10 of the periodic table. For example, the hydrodemineralization catalyst may include molybdenum. The hydrodemineralization catalyst may also include a support 10 material, and metal may be deposited on the support material. In one embodiment, the hydrodemineralization catalyst may include a molybdenum metal catalyst on an alumina support (sometimes referred to as a “molybdenum (Mo)/alumina (Al2O3) catalyst”). It should be understood throughout this disclosure that The minerals present in any of the detected catalysts may be present in the form of sulfides, oxides, or even other compounds15.

In one embodiment, the hydrodemetalization catalyst may include a metal sulfide on a carrier material, where the metal is selected from the group consisting of the IUCN elements groups 5, 6, and 8-10 of the periodic table, and combinations thereof. The carrier material may be gamma-alumina or silica/alumina extrudates, cylinders, granules, pellets, and combinations thereof.

In one embodiment, the hydrodemineralization catalyst may include a gamma-alumina carrier, having a surface area of 100 m²/g to 160 m²/g)eg, from 100 m²/g to 130 m²/g, or from 130 m²/g to 160 m²/g). The hydrodemineralization 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 25 to at least 1.0 cm³/g). The pore size of the hydrogen demineralization catalyst can often be large

(i.e., it has a pore size larger than 50 nm). This may provide significant metal adsorption capacity

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On the surface of the hydrodemineralization catalyst and optionally dopants. In one embodiment, the dopant may be selected from the group consisting of boron, silicon, halogens, phosphorus, and combinations thereof.

In one or more embodiments, the hydrodemineralization catalyst may comprise from 0.5 wt.% to 5 wt.% oxide or sulfide of molybdenum (such as from 2 wt.%

to 10 wt% or from 3 wt% to 7 wt% molybdenum oxide or sulfide), and from 88 wt% to 99.5 wt% alumina (such as from 90 wt% to 98 wt% or from 93 wt% to 97 wt% alumina).

Without being limited to theory, in some embodiments, it is believed that during the reaction in the 10-hydrogen-demineralization reaction region 106, the hydrogen-demineralization catalyst promotes the hydrogenation of porphyrin-type compounds

Porphyrin type compounds present in heavy oil transhydrogenate to create an intermediate compound. After this initial 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 final metal sulfide 15 is deposited on the demineralization catalyst. Hydrogenically, metal sulfide is thus removed from the virgin crude oil.

Sulfur is also removed from organic compounds that contain 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. The remaining 20 sulfur-free hydrocarbon fragments remain in the liquid hydrocarbon stream.

The hydrodemineralization reaction stream may be passed from the hydrodemineralization reaction region 106 to the transition reaction region 108 where it contacts the transition catalyst. Contact of the transfer catalyst with the hydrodemineralization reaction stream may promote a reaction that removes at least a portion of the metals in the hydrodemineralization reaction stream and may further remove at least a portion of the nitrogen in the hydrodemineralization stream

<p dir="rtl">25 Hydrogen demineralization reaction flow. After contact with the transition catalyst, the demineralization reaction stream is hydrolyzed into a transition reaction effluent. It may be a reaction stream</p>

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Transition metal content and reduced nitrogen content compared to the hydrogen demineralization reaction stream. For example, the transition reaction stream may have at least 50 wt %, at least 80 wt %, or even at least 90 wt % less metal content than the hydrodemineralization reaction stream. In addition, the transition reaction stream may contain 10% less nitrogen by weight

<p dir="rtl">5 At least, at least 15 wt %, or even at least 20 wt % of the hydrodemineralization reaction stream.</p>

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, and the transition catalyst may completely fill the transition reaction region 108.

<p dir="rtl">10 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 hydrodemineralization reaction stream. The transition catalyst may include an alumina-based carrier in the form of an extrusion product.</p>

In one embodiment, the transition catalyst comprises one IUCN Group 6 metal and one IUCN Group 8 metal

<p dir="rtl">15 10. Examples of IUCP Group 6 metals include molybdenum</p>

And tungsten. Examples of IUCP metals in Groups 8-10 include nickel and cobalt. For example, the transition catalyst may include molybdenum and nickel on a titania support (sometimes referred to as a “nickel-molybdenum/alumina catalyst”). The transition catalyst may also contain a dopant which is

<p dir="rtl">20 Choose from a 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 m²The transition catalyst may have a mesoporous structure that has pore sizes in the range from 12 nm to 50</p>

<p dir="rtl">25 nm. These properties provide balanced activity in hydrodemineralization and hydrodesulfurization.</p>

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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 % molybdenum oxide or sulfide), from 1% by weight to 7% by weight sulfide of nickel (such as from 2% by weight to 6% by weight or from 3% by weight to 5% by weight oxide or sulfide

<p dir="rtl">5 Nickel), and from 75 wt% to 89 wt% alumina (such as from 77 wt% to 87 wt% or from 79 wt% to 85 wt% alumina).</p>

The transition reaction stream may be passed from the transition reaction zone 108 to the hydrogen denitrification reaction zone 110 where it connects to the hydrogen denitrification catalyst. Connecting a hydrogen denitrification catalyst to the transition reaction stream may promote a reaction that removes at least a portion of the nitrogen present in

<p dir="rtl">10 Stream of the transition reaction stream. After contacting with a hydrogen denitrification catalyst, the transition reaction stream can be converted into a hydrogen denitrification reaction stream. The hydrogen denitrification reaction stream may have a reduced metal and nitrogen content compared to the transition reaction stream. For example, a hydrodenitrification 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 reaction stream</p>

<p dir="rtl">15 Transitional. In another embodiment, the hydrodenitrification reaction stream may have a reduction in sulfur content of at least 80 wt%, at least 90 wt%, or even at least 95 wt% for the transition reaction stream. In another embodiment, the hydrodenitrification reaction stream may have 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.</p>

<p dir="rtl">20 According to the models, the hydrogen denitrification reaction zone has a weighted average layer temperature of 110.</p>

From 370°C to 410°C. The hydrodenitrification reaction zone 110 includes a hydrodenitrification catalyst, and the hydrodenitrification catalyst may completely fill the hydrodenitrification reaction zone 110.

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

<p dir="rtl">25 The mineral is chosen from the group consisting of groups of the International Union of Pure Chemistry</p>

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5

10

15

20

25

and applied 5, 6, and 8-10 of the periodic table, and combinations thereof. The support material may include gamma-alumina, mesoporous alumina, silica, or both, in the form of extrusions, balls, cylinders and pellets. According to one embodiment, the hydrogen denitrification catalyst includes a gamma alumina based carrier 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 for a hydrodenitrification catalyst with a smaller pore size (e.g., less than 1.0 cm).³/g, less than 0.95 cm³/g, or even less than 0.90 cm³/g). In one embodiment, the hydrodenitrification catalyst comprises at least one IUCP Group 6 metal, such as molybdenum, and at least one IUCP Group 8-10 metal, such as nickel. The catalyst may include The hydrogen denitrification also includes at least one dopant selected from the group consisting of boron, phosphorus, silicon, halogens, and combinations thereof. In one embodiment, the hydrogen denitrification catalyst may include cobalt, which also promotes desulfurization. In one embodiment, the hydrogen denitrification catalyst has a higher active phase metal loading than the hydrogen denitrification catalyst. This increase in metal loading may lead to increased catalytic activity. In one embodiment, the hydrodenitrification catalyst comprises nickel and molybdenum, having a nickel to molybdenum molar ratio (Nickel/(Nickel+Molybdenum)()) of 0.1 to 0.3 (such as 0.1 to 0.2 or 0.2 to 0.3). In one embodiment including cobalt (Co), the molar ratio of (cobalt+nickel)/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 hydrodenitrification 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 hydrodenitrification catalyst may comprise mesoporous alumina having an average pore size of at least 30 nm, or even at least 35 nm. Hydrodenitrification catalysts with a relatively small average pore size, such as less than 2 nanometers, may be referred to as conventional hydrodenitrification catalysts in this disclosure, and may have relatively poor catalytic performance compared to the larger pore size hydrodenitrification catalysts shown. currently. maybe

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5

10

15

20

25

Embodiments of hydrodenitrification catalysts with an alumina carrier having average pore sizes from 2 nm to 50 nm are referred to in this disclosure as “meso porous alumina supported catalysts.” In one or more embodiments, the mesoporous alumina of the hydrodemineralization catalyst may have an average pore size in the range from 2 nm to 50 nm, 25 nm to 50 nm, from 30 nm to 50 nm, or from 35 nm to 50 nm. According to embodiments, the hydrogen denitrification catalyst may include alumina having a relatively large surface area, a relatively large pore volume, 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, or from 300 m²/g to 400 m²/g. In one or more embodiments, 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 limited by theory, it is thought that a mesoporous alumina-supported hydrodenitrification catalyst may provide additional active sites and larger pore channels that may facilitate the transfer of larger molecules into and out of the catalyst. Additional active sites and larger pore channels may result in higher catalytic activity, longer catalytic life, or both. In one embodiment, the hydrogen denitrification catalyst may include a dopant, which may be selected from the group consisting of boron, silicon, halogens, phosphorus, and combinations thereof.

According to described embodiments, a hydrodenitrification catalyst may be produced by mixing a carrier, such as alumina, with a binder, such as acid peptized alumina. Water or other solvent may be added to a carrier mixture and bonded 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).

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Calcined extrudates may be impregnated with an aqueous solution containing catalyst precursor materials, such as molybdenum, nickel, or combinations thereof. For example, the aqueous solution may contain ammonium heptanmolybdate Nickel nitrate, and phosphoric acid

<p dir="rtl">5 phosphoric acid to form a hydrogen denitrification catalyst comprising compounds including molybdenum, nickel, and phosphorus.</p>

In embodiments where a mesoporous alumina carrier is used, the 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

<p dir="rtl">10 Water solution with nitric acid ratio:⁺0.3 Al³ to 3.0 and the solution is stirred at 60°C to 90°C for several hours, such as 6 hours, to obtain a solution. Polymer can be added</p>

A copolymer, such as a triblock copolymer, into solution at room temperature, where the molar ratio of the copolymer: aluminum (alumnium) is 0.02 to 0.05 and persists for several hours, such as three hours. The solution/copolymer mixture is dried for several times

<p dir="rtl">15 Hours and then his tongue.</p>

According to one or more embodiments, the hydrodenitrification catalyst may comprise from 10 wt% to 18 wt% molybdenum oxide or sulfide (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% to 6 wt% oxide or sulfide

<p dir="rtl">20 Nickel), 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>

In a similar manner to the hydrodemineralization catalyst, and again with no intention of being bound to any theory, it is believed that hydrodenitrification and hydrodearomatics can be carried out via related reaction mechanisms. Each involves some degree of hydrogenation. For removal

<p dir="rtl">25 Nitrogen is hydrogen, usually organic nitrogen compounds</p>

In the form of heterocyclic ring structures, the atom is heterocyclic

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heteroatom nitrogen. These heterocyclic structures may be saturated before the nitrogen atom is removed

Heteroatom of nitrogen. Similarly, the process of hydrodearomatics involves saturation of aromatic rings. Each of these reactions may occur to a different degree depending on the amount and type of catalyst because each catalyst may selectively enhance one of the

<p dir="rtl">5 Types of transfers over others and because transfers are competitive.</p>

It should be understood that some embodiments of methods and systems currently described may utilize a hydrodenitrification 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 dir="rtl">10 Still referring to Figure 2, the hydro-denitrification reaction stream may be passed from the hydro-denitrification reaction zone 110 to the hydrocracking reaction zone 120 where it is connected to the hydrocracking catalyst. Connecting the hydrocracking catalyst to the HDD reaction stream may promote a reaction that reduces the aromatics content in the HDD reaction stream. After contacting the hydrocracking catalyst, the hydrogen denitrification reaction stream is converted into...</p>

<p dir="rtl">15 Pretreatment catalyst reaction stream 109. The pretreatment catalyst reaction stream 109 may have a reduced aromatics content compared to the hydrogen denitrification reaction stream. For example, pretreatment catalyst reaction stream 109 may have a 50% lower aromatics content by weight</p>

At least, at least 60 wt% less, or even at least 80 wt% less than the flow

Hydrogen denitrification reaction.

<p dir="rtl">20 The hydrocracking catalyst may comprise one or more metals from International Union of Pure and Applied Chemistry groups 5, 6, 8, 9, or 10 of the periodic table. For example, the hydrocracking 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 hydrocracking catalyst may include:</p>

<p dir="rtl">25 Molybdenum or tungsten from IUCP Group 6 and nickel and cobalt from IUCP Groups 8, 9, or 10. The demineralization catalyst may include</p>

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It is also hydrogenated on a carrier material, such as zeolite, and the metal may be placed on the carrier material. In one embodiment, the hydrocracking catalyst may comprise a tungsten and nickel metal catalyst on a zeolite carrier that is mesoporous (sometimes referred to as a “tungsten (W)-nickel/zeolite mesoporous catalyst”). In another embodiment, the catalyst may include Hydrocracking on a catalyst

<p dir="rtl">5 Molybdenum and nickel metal on a zeolite carrier that is mesoporous (sometimes referred to as a “nickel-molybdenum/meso-zeolite catalyst”).</p>

According to hydrocracking catalyst embodiments for hydrotreatment catalytic systems described in this disclosure, the carrier material (i.e., mesoporous zeolite) can be characterized as mesoporous having an average pore volume of

<p dir="rtl">10 2nm to 50nm. By comparison, hydrocracking catalysts based on...</p>

Traditional zeolites contain zeolite-based hydrocracking catalysts

Porous, meaning it has an average pore size of less than 2 nanometers. Without being bound by theory, it is believed that the relatively large pore size (i.e., mesoporosity) of the currently described hydrocracking catalyst allows the diffusion of larger molecules into the zeolite, which is thought to improve reaction activity and catalyst selectivity.

<p dir="rtl">15 Because of the increased pore size, aromatic-containing molecules can diffuse more easily into the catalyst and aromatic breakdown may increase. For example, in some conventional embodiments, the feed material converted by the hydroprocessing catalyst may be vacuum gas oils, light cycle oils from, for example, a fluid catalytic cracking reactor; Or coker gas oils from, for example</p>

<p dir="rtl">20 Example, coking unit. The molecular sizes in these oils are relatively small compared to those of heavy oils such as crude and atmospheric residues, which may be the feed material according to current methods and systems. Heavy oils are usually able to diffuse into conventional zeolites and are transferred onto the active sites within the zeolites. Thus, zeolites with larger pore sizes (i.e., mesoporous zeolites) may allow molecules larger than</p>

<p dir="rtl">25 Heavy oils overcome the diffusion limitation and may enhance the reaction and conversion of larger molecules into heavy oils.</p>

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The zeolite carrier material is not necessarily limited to a specific type of zeolite. However, it is expected that zeolites such as Beta, Y, AWLZ-15-15, LZ-45-Y-82, LZ-84, 210-LZ-25, Silicalite, Or mordenite may be suitable for use in the currently described hydrocracking catalyst. For example, medium zeolites are described

<p dir="rtl">5 Suitable pores that may be impregnated with one or more catalytic metals such as Mo, Ni, W, or combinations thereof, at least in US Patent No. 7,785,563; Zhang et al.,</p>

Microporous and Mesoporous, Powder Technology 183 (2008) 73–78; Liu et al.

Catalysis Science &amp; Materials, 181 (2013) 116–122; and Garcia-Martinez et al.

. 2012 (DOI: 10.1039/c2cy00309k),Technology

<p dir="rtl">10 In one or more embodiments, the hydrocracking catalyst may comprise from 18 wt% to 28 wt% sulfide or oxide of tungsten (such as from 20 wt% to 27 wt% or from 22 wt% to 26 wt% tungsten, sulfide or tungsten oxide), 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 Average pores (such as 10%</p>

<p dir="rtl">15 by weight to 35 wt% or from 10 wt% to 30 wt% zeolite. In another embodiment, the hydrocracking catalyst may comprise from 12 wt% to 18 wt% molybdenum oxide or sulfide (such as from 13 wt% to 17 wt% or From 14 wt% to 16 wt% molybdenum oxide or sulphide), from 2 wt% to 8 wt% nickel oxide or sulphide (such as from 3 wt% to 7 wt% or from 4 wt% to 6 wt% nickel oxide or sulphide) , and from 5% by weight to 40% by weight</p>

<p dir="rtl">20 Mesoporous zeolite (e.g. 10 wt% to 35 wt% or 10 wt% to 30 wt% mesoporous zeolite).</p>

The hydrocracking catalyst described may be prepared by selecting a mesoporous zeolite and impregnating the mesoporous zeolite with one or more catalytic minerals or by combining the mesoporous zeolite with other components. For the impregnation method, mesoporous zeolite, active alumina (e.g., boehmite alumina), and bond (on

For example, alumina peptide for acid. An appropriate amount of water can be added to form a dough which

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It can be extruded using an extruder. The extruded product can be dried at 80°C to 120°C for 4 to 10 hours and then calcined at 500°C to

550 Degrees Celsius for a period of 4 to 6 hours. The calcinated extrudate can be impregnated with an aqueous solution prepared with compounds including nickel, tungsten, molybdenum,

<p dir="rtl">5 Cobalt, or combinations thereof. Two or more materials may be used to produce catalytic metals</p>

metal precursors when two catalytic metals are required. However, some models may contain only one of nickel, tungsten, molybdenum, or cobalt. For example, the catalyst carrier may be impregnated with a mixture of nickel nitrate hexahydrate (i.e., Ni(NO3)2•6H2O) and ammonium metatungstate (i.e.,

<p dir="rtl">10 NH4)6H2W12O40)(if a tungsten-nickel hydrocracking catalyst is required. It can be dried</p>

Impregnated extrudate at 80°C to 120°C for

From 4 hours to 10 hours, then calcined at 450°C to 500°C for a period of 4 to 6 hours. For the aggregate method, the mesoporous zeolite may be mixed with alumina, bonding, and compounds comprising tungsten or molybdenum, nickel or cobalt (e.g., molybdenum trioxide (MoO3) or nickel hexahydrate if the molybdenum-nickel is required(.

It should be understood that some embodiments of the methods and systems currently described can use a hydrocracking 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 nm (i.e., 20 micropores).

According to one or more embodiments described, the volume ratio of hydrodemineralization catalyst: transition catalyst: hydrodenitrification catalyst: hydrocracking catalyst may be 5-20:5-30:70-30:30-5. The percentage of catalyst may depend at least in part on the metal content of the processed oil feedstock.

<p dir="rtl">25 Now referring to Figure 3, according to additional embodiments, the hydrogenation catalyst system 132 may include multiple consecutively arranged packed layer reaction zones (e.g., a demineralization reaction zone</p>

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(hydrogenation 106, transition reaction zone 108, and hydrogen denitrification reaction zone 110) Each of these reaction zones may include a catalyst bed. Each of these zones may be present in a single reactor such as a packed bed reactor with several layers arranged in succession, shown as a packed bed hydrogenation reactor Before me 134 upstream packed bead hydrotreating reactor in figure 3, hydrotreating reactor

<p dir="rtl">5 136 downstream packed bed hydrocracking reactor. In other embodiments, the hydro-denitrification reaction zone 106, the transition reaction zone 108, and the hydro-denitrification reaction zone 110 may be located in a plurality of packed bed reactors arranged in series with a post-packed bed hydrocracking reactor 136. In other embodiments, each reaction zone is In a single, separate packed bed reactor. The packed bed hydrogenation reactor 134 may include a preprint or a group of reactors</p>

<p dir="rtl">10 The pre-packed bed hydrocracking reaction zone 106, the transition reaction zone 108, the hydro-denitrification reaction zone 110. The post-packed bed hydrocracking reactor 136 may include the hydrocracking reaction zone 120. In these embodiments, the hydrogen demineralization reaction zone 106 may be used, Transition reaction zone 108, hydrogen denitrification reaction zone 110, hydrocracking reaction zone 120, special catalysts, processing conditions, etc.,</p>

<p dir="rtl">15 shown in relation to the system in accordance with Figure 2. The configuration of the prepacked bed hydrogenation reactor 134 or the set of prepacked bed reactors in accordance with Figure 3 may be particularly useful when the reaction conditions include, but are not limited to, the hydrogen content, temperature, or pressure of the reactor process Packed bed prehydrogenation 134 or combination of prepacked bed reactors and packed bed posthydrocracking reactor 136 are different. In these embodiments, stream 131 is passed from the hydrogenation reactor</p>

<p dir="rtl">20 The prepacked bed reactor 134 or the set of packed bed reactors upstream to the postpacked bed hydrocracking reactor 136.</p>

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., hydro-denitrification reaction zone 106, transition reaction zone 108, and hydro-denitrification reaction zone 110) and may include

<p dir="rtl">25 Each of these reaction zones is on a catalyst layer. Each of these regions may be present in a single reactor such as a packed bed reactor with several layers in succession, shown as a prepacked bed hydrogenation reactor 134 in</p>

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

<p dir="rtl">5 In other embodiments, each reaction zone is located in a single, separate packed bed reactor. The upstream packed bed hydrogenation reactor 134 or the upstream packed bed reactor assembly may include a hydrodemineralization reaction zone 106, a transition reaction zone 108, and a hydrodenitrification reaction zone 110. The postfluidized bed hydrocracking reactor 138 may include a hydrocracking reaction zone 120. In this Embodiments, may use the hydrogen demineralization reaction region 106, region</p>

<p dir="rtl">10 Transition reaction 108, hydro-denitrification reaction zone 110, hydrocracking reaction zone 120, special catalysts, processing conditions, etc., shown in relation to the system according to Figure 2. The configuration may be the pre-packed bed hydrogenation reactor 134 or the pre-packed bed reactor combination According to Figure 3, it is especially useful when the reaction conditions such as, but not limited to, the hydrogen content, temperature, or pressure of the prehydrogenation reactor process are</p>

<p dir="rtl">15 Packed bed 134 or a combination of pre-packed bed reactors and post-fluidized bed hydrocracking reactor 138 are different. The process fluid 139 may fluidize the hydrocracking catalyst to the hydrocracking reaction zone 120. In these embodiments, stream 131 is passed from the upstream packed bed hydrogenation reactor 134 or upstream packed bed reactor assembly to the afterflow fluidized bed hydrocracking reactor 138. The bed may be The fluidized fluid model of Figure 4 is useful</p>

<p dir="rtl">20 With a hydrocracking catalyst, especially compared to the packed bed configurations according to Figures 2 and 3.</p>

Referring now to Figure 5, a steam cracking and separation system 400 is depicted. The upgraded oil stream 303 (which may include any one or more) may be passed

Catalyst reaction effluent stream 109, intermediate liquid product stream 115, or final pretreatment liquid product stream 118 of pretreatment systems 100 according to Figs.

25 4-1) Directly to the steam cracker unit 348 steam cracker unit. The cracking unit may include

With steam, 348 convection zones, 350 convection zones, and pyrolysis zones.

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<p dir="rtl">351. The upgraded oil stream 303 may pass through the convection zone 350 with steam 305. In the convection zone 350, the upgraded oil stream 303 may be preheated to the desired temperature, such as from 400°C to 650°C. The contents of the refined oil stream 303 located in the pyrolysis zone 350 may then be passed to the pyrolysis zone 351 where it is steam cracked.</p>

<p dir="rtl">5 The steam-cracked effluent stream 307 may exit the steam cracker 348 and be passed through the heat exchanger 308 where the process fluid 309, such as water or pyrolysis fuel oil, is cooled. Steam cracked 307 to form the cooled steam cracked stream 310. The steam cracked stream 307 and the cooled steam cracked stream 310 may include a mixture of existing materials</p>

<p dir="rtl">10 Contains cracked hydrocarbon-based materials that can be separated into one or more petrochemical products contained in one or more system product streams. For example, the steam-cracking stream 307 and the cooled steam-cracking stream 310 may include one or more pyrolysis fuel oil, pyrolysis gasoline, mixed butenes, butadiene, propene, ethylene. ,methane</p>

<p dir="rtl">15 methane, and hydrogen, which may be additionally mixed with water from steam cracking.</p>

According to one or more embodiments, pyrolysis zone 351 may operate at a temperature from 700°C to 900°C. Pyrolysis zone 351 may operate with a residence time of 0.05 seconds to 2 seconds. The mass ratio of steam 305 to the refined oil stream 303 may be from about 1:0.3 to about 1:2.

<p dir="rtl">20 The refrigerated steam crushed stream 310 can be separated by a separation unit 311 into the system product streams. For example, separation unit 311 may be a series of separation vessels which separate the contents of the cooled steam-crushed stream 310 into one or more fuel oil stream 312, gasoline stream 313, and mixed butenes stream 314. , butadiene stream 315, propene stream 316 propene stream, stream</p>

<p dir="rtl">25 Ethylene stream 317 ethylene stream, methane stream 318 methane stream, and hydrogen stream 319 stream. As used in this disclosure, system product currents may be referred to (e.g</p>

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Fuel oil 312, gasoline stream 313, mixed butanes stream 314, butadiene stream 315, propane stream 316, ethylene stream 317, and methane stream 318) are products of the system, sometimes used as feedstocks in downstream chemical processing.

According to additional embodiments, all or part of the fuel oil stream 312 may be recycled to the pretreatment system 5 100 according to Figures 1-4. The fuel oil stream 312 may be conveyed to the pretreatment system 100 via the fuel oil recycle stream 362. The fuel oil recycling stream may be combined with any stream in the pretreatment system 100 resulting in the hydrotreatment catalyst system 132.

In additional embodiments, the gas condensate 364 may be combined with the upgraded oil stream 10 303, and the upgraded oil and gas condensate enter the steam cracker 348. Alternatively, the upgraded oil and gas condensate may enter the steam cracking unit 348.

The gas condensate directly enters the steam cracking unit 348.

Gas condensate may be gas condensate available from the Khuff geological formation. Characteristics of the Khuff gas condensate are shown in Table 2.

Table 2 - Example of Khuff gas condensation product

<tr><td><p dir="rtl">the value</p></td><td><p dir="rtl">Units</p></td><td><p dir="rtl">Property</p></td></tr><tr><td><p>52.8</p></td><td><p dir="rtl">grades</p></td><td><p dir="rtl">Specific gravity according to the American Petroleum Institute</p></td></tr><tr><td><p>0.7695</p></td><td><p dir="rtl">Grams per cubic centimeter (g/cm).³(</p></td><td><p dir="rtl">Density</p></td></tr><tr><td><p>0.03</p></td><td><p dir="rtl">Weight percentage (% by weight)</p></td><td><p dir="rtl">Sulfur content</p></td></tr><tr><td><p dir="rtl">Less than 20</p></td><td><p dir="rtl">Parts per billion weight</p><p>parts per billion by weight (ppbw)</p></td><td><p dir="rtl">Nickel</p></td></tr><tr><td><p dir="rtl">Less than 20</p></td><td><p dir="rtl">Parts per billion weight</p></td><td><p dir="rtl">Vanadium</p></td></tr><tr><td><p dir="rtl">Less than 20</p></td><td><p dir="rtl">Parts per billion weight</p></td><td><p dir="rtl">Iron</p></td></tr>

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<tr><td><p dir="rtl">Less than 20</p></td><td><p dir="rtl">Parts per billion weight</p></td><td><p>Copper</p></td></tr><tr><td><p>50</p></td><td><p dir="rtl">Parts per billion weight</p></td><td><p dir="rtl">Sodium chloride content</p></td></tr><tr><td><p>0.03</p></td><td><p dir="rtl">% by weight</p></td><td><p dir="rtl">carbon cohn ardson</p></td></tr><tr><td><p dir="rtl">Less than 10</p></td><td><p dir="rtl">Parts per million Parts per</p><p>(ppm) million</p></td><td><p dir="rtl">Basic nitrogen</p><p>nitrogen</p></td></tr>

Referring now to Figure 6, in additional embodiments, the feed stream 101, such as crude oil, may be separated into a light feed fraction stream 372 and a heavy feed fraction stream 374 fraction stream. Separation may be performed in a separation unit 376, which may be a flash drum or other suitable separation device. The heavy part can be divided from the heavy part stream 374

<p dir="rtl">5 The light portion of the light portion stream 372 by a cut-off point, wherein the contents of the heavy portion generally have a boiling point greater than the cut-off point and the contents of the light portion generally have a boiling point lower than the cut-off point. According to one or more embodiments, the separation cutoff point of separation unit 376 may be from 300°C to 400°C, such as from 325°C to 375°C, from 340°C to 360°C, or from 345°C to 355 Celsius. According to</p>

<p dir="rtl">10 For additional embodiments, the separation cutoff point in separation unit 376 may be from 120°C to 230°C, such as from 150°C to 210°C, from 160°C to 200°C, from 170°C to 190°C, or From 175°C to 185°C. The heavy fraction stream 374 may be passed to the pretreatment system 100 according to either of Figures 4-1 where it is hydrogenated via the hydrogenation catalyst system 132. The light feed fraction stream may be passed directly</p>

<p dir="rtl">15 To steam cracker 348. In this embodiment, relatively light components of the feed stream may bypass the pretreatment, thereby increasing the effectiveness of the combined system. It is noted that while Figure 6 depicts a combination of the light feed portion stream 372 and the upgraded oil stream 303, these streams can also be passed separately to the stream crusher 348.</p>

Examples

<p dir="rtl">20 Various examples 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>

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Example 1 – Preparation of a mesoporous hydrocracking catalyst

A hydrocracking catalyst comprising a mesoporous zeolite is composed as described earlier in this disclosure. 74.0 g of commercial NaY zeolite (commercially available as CBV-100 from Zeolyst) was added to 400 milliliters (ml) of sodium hydroxide solution.

<p dir="rtl">5 3 (NaOH) hydroxide molar and mixed at 100°C for 12 hours. After that it was added</p>

<p dir="rtl">60.0 g of 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 an autoclave. Teflon-lined stainless steel autoclave and crystallized at</p>

<p dir="rtl">10 100°C for 24 hours. After crystallization, the sample was washed with deionized water</p>

water, dried at 100°C for 12 hours, and calcined at 550°C for 6 hours. The sample was ion exchanged with 2.5 M ammonium nitrate solution (2.5 M NH4NO3) at 90°C for 2 hours, and then treated with steam (at a flow rate of 1 milliliter per minute (mL/min)) at 500°C for One hour later, the sample ions were exchanged again with 2.5 M ammonium nitrate solution, and finally the sample was dried

100 C for 12 hours and calcined at 550°C for 4 hours to form mesoporous zeolite Y. In a mortar, 34 g of mesoporous zeolite Y, 15 g of molybdenum trioxide, and 20 g of hexahydrate Ni(NO3)2•6H2O) nickel(II) nitrate hexahydrate), and 30.9 g of alumina (commercially available as 20 14/150 PURALOX® HP from Sasol). Then, 98.6 g of alumina was added. Laces made of

Alumina (commercially available as CATAPAL® from Sasol) and dilute nitric acid (70% loss on ignition by weight), which bonded the mixture to form a paste by adding an appropriate amount of water. The paste was extruded with an extruder to form a cylindered extrudate. The extruded product was dried at 110 °C overnight and calcined at 500 °C for 4 h.

<p dir="rtl">25 Example 2 – Preparation of a conventional hydrocracking catalyst</p>

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A conventional hydrocracking catalyst (including microporous zeolite) was produced by a method similar to Example 1 where a commercial microporous zeolite was used. In a slurry, 34 g of microporous zeolite (commercially available as CPV- 600 CBV ZEOLYST® from Micrometrics), 15 g molybdenum trioxide, 20 g nickel hexahydrate, and 30.9 g alumina (commercially available as 14/150 PURALOX® HP from Sasol).

Then, 98.6 g of a binder made from boehmite alumina (commercially available as CATAPAL® from Sasol) and dilute nitric acid (with a loss on ignition of 70% by weight) were added, which bonded the mixture to form a paste by adding an appropriate amount of water. The dough was made using 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.

Example 3 - Analysis of prepared hydrocracking gas catalyst

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 mesopores (larger than 2 nm). The results are shown in Table 3, 15 which show that the catalyst with Example 1 (conventional) had a micropore surface area and volume Micropores are larger than the surface area of mesopores and the volume of mesopores. Additionally, the catalyst of Example 2 had a mesopore surface area and mesopore volume greater than the micropore surface area and micropore volume. 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 3 - 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><tr><td><p>415</p></td><td><p>747</p></td><td><p dir="rtl">Fine pores (&lt; 2 nm) (m /g)</p></td></tr><tr><td><p>480</p></td><td><p>155</p></td><td><p dir="rtl">Mesopores (&gt;2 nanometers) m²/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>

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<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><tr><td colspan="3"><p dir="rtl">Example 4 – Preparation of a mesoporous hydrodenitrification catalyst</p></td></tr>

The mesoporous hydrodenitrification catalyst was prepared by the described method, where the mesoporous hydrodenitrification catalyst had an average measured pore size of 29.0 nm. First, 50 gm mesoporous alumina was prepared by mixing 68.35 gm alumina powder

<p dir="rtl">5 Boehmet (commercially available as CATAPAL® from Sasol) was added in 1000 ml of water at 80°C. Then, 378 ml of one M nitric acid was added at a molar ratio of⁺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 then 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). Suitable from water to</p>

<p dir="rtl">15 The mixture was mixed to form a dough, and the dough was extruded to form trilobe extrudates. The extruded products were dried at 110 °C overnight and calcined at 550 °C for 4 h. The calcined extrudates were impregnated with a wet initiator of 50 mL of aqueous solution containing 94.75 g of ammonium heptane molybdate, 12.5 g of nickel nitrate, and 3.16 g of phosphoric acid. The impregnated catalyst was dried at 110 °C overnight</p>

20 Calcined at 500°C for 4 hours.

Example 5 – Preparation of a conventional hydrogen denitrification catalyst

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

<p dir="rtl">5 Trilobite extrusion. The extruded products were dried at 110 °C overnight and calcined at 550 °C for 4 h. The calcined extrudates were impregnated with a wet initiator of 50 mL of aqueous solution containing 94.75 g of ammonium heptane 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 catalyst had moderate conventional hydrogen denitrification measured</p>

<p dir="rtl">10 Pore size of 10.4 nm.</p>

Example 6 - Catalytic performance of the prepared hydrogen denitrification catalyst

To compare the performance of the AZT catalyst reaction in 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 4. The results showed that the denitrification performance

<p dir="rtl">15 The hydrogen value of the catalyst in Example 4 is better than that of the conventional catalyst in Example 5.</p>

Table 4 - Analysis of the porosity of the cement using Example 4 and Example 5

<tr><td><p dir="rtl">Example 4</p></td><td><p dir="rtl">Example 5</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><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</p><p>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></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td><p dir="rtl">Product properties</p></td></tr>

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<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">Carbon (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">Hydrogen (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">Sulfur (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">Nitrogen (ppm by weight)</p></td></tr><tr><td></td><td></td><td></td><td></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 hydrogen denitrification and hydrotreatment 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-bed reactor unit. The four-layer reactor unit included a hydrodemineralization catalyst, a transition catalyst,

<p dir="rtl">5 A hydrogen denitrification catalyst, and a hydrocracking catalyst, all arranged in series. Feed and reactor conditions were the same as those listed in Table 4. Table 5 shows the components and volumetric amounts of each component in the sample systems. A 300 ml reactor was used for the test.</p>

Table 5 – 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><tr><td><p>15</p></td><td><p dir="rtl">Hydrodemineralization catalyst available</p><p dir="rtl">Commercially</p></td><td><p dir="rtl">Demineralization catalyst</p><p dir="rtl">Hydrolyzed is commercially available</p></td><td><p dir="rtl">Hydrogen demineralization catalyst</p></td></tr>

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<tr><td><p>15</p></td><td><p dir="rtl">Transition catalyst with demineralization functions</p><p dir="rtl">Hydrogenically and dehydrationally</p><p dir="rtl">Sulfur is hydrogenated</p><p dir="rtl">Commercially available</p></td><td><p dir="rtl">Transition catalyst with hydrodemineralization and desulfurization functions</p><p dir="rtl">Hydrolyzed is commercially available</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">Stripping catalyst</p><p dir="rtl">Hydrogenically nitrogen</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">pH</p></td></tr>

Table 6 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 Example 1 and Example 4 (sample system 2) showed better performance in hydrogen denitrification, hydrogen desulfurization, and residue conversion above 540 degrees Celsius.

5 Table 6 – Catalyst performance results

<tr><td colspan="2"><p>0.3</p></td><td colspan="2"><p>0.2</p></td><td><p dir="rtl">Ratio of weight of feed liquid to weight of catalyst 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><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>

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<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 form a range of that

Property, and all range combinations consisting of all quantitative values mentioned in 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 treating the heavy oil, the method comprising: upgrading at least a portion of the heavy oil to form an upgraded oil, the upgrading comprising contacting the heavy oil with a hydrodemineralization catalyst, a transition catalyst, a hydraulic denitrification catalyst, and a hydrocracking catalyst for Remove at least part of</p>

<p dir="rtl">15 Minerals, nitrogen, or aromatic content of heavy oil and refined oil composition; And pass</p>

Upgrading oil to a steam cracker, and steam cracking the upgrading oil to form a stream that has been steam cracked; The final boiling point of the refined oil is less than or equal to 540 degrees Celsius.

The second aspect may include a method for treating heavy oil. The method includes: upgrading at least a portion of the heavy oil to form a refined oil. The upgrading includes contacting the heavy oil with a stripping catalyst.

<p dir="rtl">20 Mineral hydrolysis, a transition catalyst, a hydrodenitrification catalyst, and a hydrocracking catalyst for the removal of at least a portion of the metals, nitrogen, or aromatic content of heavy oil</p>

The composition of the refined oil; passing the refined oil to a steam cracking device, and steam cracking the refined oil to form a stream that has been steam cracked; The heavier components of the refined oil are at least directly passed to a steam cracker.

<p dir="rtl">25 Another aspect includes any of the previous aspects, where the feed oil is crude oil with a specific gravity according to the American Petroleum Institute from 25 degrees to 50 degrees.</p>

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10

15

20

Another aspect includes any of the previous aspects, and also includes separating the feed oil into a heavy feed fraction and a light feed fraction; And pass the light feed portion to a steam crusher; The heavy feed portion represents the heavy oil being upgraded.

Another aspect includes any of the previous aspects, where the cut-off point for the light feed portion relative to the heavy feed portion ranges from 300°C to 400°C.

Another aspect includes any of the previous aspects, where the cut-off point for the light feed portion and the heavy feed portion ranges from 120°C to 230°C.

Another aspect includes any of the foregoing, wherein the hydrodemineralization catalyst, the transition catalyst, and the hydraulic denitrification catalyst are respectively placed in a plurality of reactors; The hydrocracking catalyst is placed in a reactor after the reactor group.

Another aspect includes any of the above, where the reactor after the reactor group is a packed bed reactor.

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

Another aspect including any of the foregoing aspects, wherein the hydrocracking 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; or the hydrodenitrification catalyst comprises one or more metals on an alumina carrier, the alumina carrier having an average pore size ranging from 2 nm to 50 nm; Or both.

Another aspect includes any of the foregoing, and also includes steam cracking of a gas condensate with upgraded oil.

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