Hydrocarbon Pyrolysis of Silicon-Containing Feeds

Abstract

A method and system for pyrolyzing a hydrocarbon feed for a predetermined period of time, such as by steam cracking. The method may include determining a first amount of silicon material present in a hydrocarbon feed to be steam cracked to produce a steam cracker effluent. The method may also include determining a second amount of silicon material to be present in a steam cracker naphtha to be separated from the steam cracker effluent.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims priority to and benefits of U.S. Provisional Application No. 63 / 002,433, filed on March 31, 2020, and EP Application No. 20184304.2, filed on July 6, 2020, the disclosures of which are incorporated herein by reference in their entirety. Technical Field

[0003] Embodiments disclosed herein generally relate to 5+ Pyrolysis methods for hydrocarbon conversion, for example, conversion of heavy oils such as crude oil. More particularly, such methods relate to pyrolysis methods and systems for pyrolyzing hydrocarbon feeds containing one or more forms of silicon. Background Art

[0004] Pyrolysis processes, such as steam cracking, convert lower value hydrocarbonaceous feedstocks into higher value products, such as ethylene and propylene. In addition, pyrolysis can also produce naphtha, gas oil and a large number of lower value heavy products, such as pyrolysis tar.

[0005] When the steam cracker is operated in pyrolysis mode, the hydrocarbon feed is preheated and combined with steam in the tubular convection coil located in the convection section of the steam cracking furnace. The feed-steam mixture or its gas phase portion is pyrolyzed in the tubular radiant coil located in the radiant section of the steam cracking furnace. During the pyrolysis mode operation, the separation equipment located downstream of the steam cracking furnace is generally used to separate various products from the steam cracker effluent, such as process gas, steam cracker naphtha (SCN), steam cracker gas oil (SCGO), steam cracker quench oil (SCQO), steam cracker tar (SCT), etc. Because coke accumulates in the position within the steam cracking furnace, the furnace is generally switched from the pyrolysis mode to the decoking mode to remove coke, for example, from the radiant coil. During the decoking mode, the flow of hydrocarbon feed to the steam cracking furnace is reduced or stopped, and the flow of the decoking fluid is established instead. The decoking fluid generally contains one or more of steam, water and air. In continuous decoking, the decoking fluid contains little or no air and a portion of the radiant coils is maintained in the pyrolysis mode while another portion of the radiant coils is operated in the decoking mode.

[0006] As technology for pyrolyzing predominantly liquid hydrocarbon feeds improves, there has been an increased interest in utilizing heavier liquid feeds, such as those predominantly liquid hydrocarbon feeds having an API gravity less than that of naphtha ("heavier predominantly liquid hydrocarbon feeds," also referred to as "advantaged feeds"). While advantageous feeds may include those that have undergone prior processing, such as certain gas oils, advantageous feeds may also include raw materials, such as crude oils, such as crude oils containing medium hydrocarbons and / or heavy hydrocarbons. For example, utilizing advantageous feeds containing virgin feedstocks (e.g., various crude oils) will increase the supply of available liquid feeds and will reduce the reliance of steam cracker units on refinery process streams to meet steam cracker feed requirements. This in turn will improve steam cracker facility economics, such as by reducing light olefin production costs and by making higher value refinery streams available for other purposes.

[0007] Although heavier hydrocarbon feeds have become an attractive option, for example from a cost perspective, such feeds may introduce significant levels of contaminants, such as various forms of silicon-containing compositions, into the pyrolysis process, which is generally not a problem in conventional pyrolysis processes using higher value feedstocks, such as C2-C4 hydrocarbons. The presence of silicon-containing materials may interfere with the pyrolysis process, and in particular may interfere with the separation, recovery and upgrading of certain pyrolysis products. This in turn may result in a shortened operating period of indeterminate duration, after which equipment and materials used in the process require repair, regeneration or other recovery activities before the pyrolysis process can resume operation.

[0008] Therefore, there is a need for improved pyrolysis processes, such as steam cracking, to pyrolyze hydrocarbon feeds containing one or more silicon-containing contaminants. In particular, there is a need for methods and systems capable of pyrolyzing hydrocarbon feeds containing one or more forms of silicon-containing compositions and recovering desired products from the pyrolysis effluent for a predetermined period of time. Summary of the invention SUMMARY OF THE INVENTION

[0010] The present invention is based in part on the discovery that pyrolysis converts at least a portion of certain forms of silicon (e.g., elemental silicon and / or silicon dioxide) present in the hydrocarbon feed into other forms of silicon-containing compositions, such as silicones that appear in the pyrolysis effluent. In addition to silicones produced by the conversion, it has also been found that unconverted silicones may also appear in the pyrolysis effluent, such as silicones that are present in the hydrocarbon feed and carried via pyrolysis. It has been observed that the presence of certain forms of silicon (e.g., silicones produced by pyrolysis or carried via pyrolysis) may result in difficulty in processing the pyrolysis effluent. More specifically, it has been found that certain forms of silicon (e.g., silicones) with atmospheric boiling points in the naphtha boiling range may deactivate the catalyst used to hydrotreat the naphtha boiling range fraction of the pyrolysis effluent, resulting in a shortened run length of the hydrotreating reactor. This in turn limits the duration of the period over which the pyrolysis can operate. After the hydrotreating catalyst has been replaced, regenerated, restored, or otherwise recovered, the pyrolysis may be returned to operation.

[0011] Therefore, certain aspects of the present invention relate to processes, methods, apparatus and systems for pyrolyzing a hydrocarbon feed containing one or more forms of silicon-containing compositions for a predetermined period of time. In these and other aspects, the types and amounts of various silicon-containing compositions in the hydrocarbon feed can be determined ("feed composition information"). It is observed for various hydrocarbon feeds that the composition information of the hydrocarbon feed can be used to determine the types and amounts of silicon-containing compositions of the naphtha boiling range fractions produced by pyrolysis or carried to the pyrolysis effluent via pyrolysis ("naphtha composition information"). Naphtha composition information can be used to preselect the amount of hydroprocessing catalyst so that hydroprocessing of the naphtha fraction of the pyrolysis effluent can be performed within a predetermined period of time without the need to replace, regenerate and / or restore the catalyst, or otherwise restore the activity of the catalyst (collectively referred to as "replacement or reactivation").

[0012] In aspects where pyrolysis includes steam cracking, a hydrocarbon feed and an aqueous composition comprising water, steam, or a mixture of water and steam may be mixed and heated (in any order) to produce a steam cracking feed. Gas phase products and liquid phase products may be separated from the steam cracking feed. The gas phase product (referred to herein as the pyrolysis feed) may be steam cracked to produce a steam cracker effluent. Steam cracker naphtha and process gas that may comprise ethylene and propylene may be separated from the steam cracker effluent. The steam cracker naphtha may be hydrotreated for at least a predetermined period of time.

[0013] Steam cracking may include measuring a first amount of silicon in a hydrocarbon feed. The first amount of silicon is equal to the total mass of silicon present in the form of all silicon in a given mass of hydrocarbon feed. A second amount of silicon to be present in a steam cracker naphtha to be separated from a steam cracker effluent may be determined based at least in part on the first amount of silicon. The second amount of silicon is equal to the total mass of silicon present in the form of all silicon in a given amount of steam cracker naphtha. A sufficient amount of at least one catalyst may be introduced into a hydroprocessing unit to allow the hydroprocessing unit to hydroprocess the steam cracker naphtha to be separated from the steam cracker effluent for at least a predetermined period of time without the need to replace or reactivate at least partially deactivated catalyst, wherein the deactivation is caused by the second amount of silicon in the steam cracker naphtha. BRIEF DESCRIPTION OF THE DRAWINGS

[0014] In order to understand the above-mentioned features of the present invention in detail, a more specific description of the present invention briefly summarized above can be obtained by referring to some of the embodiments shown in the accompanying drawings. However, it should be noted that the accompanying drawings only illustrate typical embodiments of the present invention and are therefore not considered to be limiting of the scope of the present invention, because the present invention can be implemented with other equally effective embodiments.

[0015] Figure 1 Depicted is a schematic diagram of an illustrative system for steam cracking a hydrocarbon feed, separating a product therefrom including a steam cracker naphtha, and hydrotreating the steam cracker naphtha for at least a predetermined period of time, according to one or more embodiments.

[0016] Figure 2 Depicted is a schematic diagram of another illustrative system for steam cracking a hydrocarbon feed, separating a product therefrom comprising a steam cracker naphtha, and hydrotreating the steam cracker naphtha for at least a predetermined period of time in accordance with one or more embodiments. DETAILED DESCRIPTION OF THE INVENTION

[0018] It should be understood that the following disclosure describes several exemplary embodiments for implementing the different features, structures and / or functions of the present invention. The exemplary embodiments of components, arrangements and configurations are described below to simplify the present disclosure; however, these exemplary embodiments are provided as examples only and are not intended to limit the scope of the present invention. In addition, the present disclosure may repeat reference numerals and / or letters in various exemplary embodiments and in the accompanying drawings provided herein. This repetition is for the purpose of simplicity and clarity, and does not itself indicate the relationship between the various exemplary embodiments and / or configurations discussed in the drawings. In addition, the exemplary embodiments provided below may be combined in any manner, that is, any element from one exemplary embodiment may be used in any other exemplary embodiment without departing from the scope of the disclosure. For this description and the appended claims, the following terms are defined.

[0019] "Hydrocarbon" refers to a class of compounds containing hydrogen bonded to carbon. n "Hydrocarbon" refers to a hydrocarbon containing n carbon atoms per molecule, where n is a positive integer. The term "C n+ "Hydrocarbon" means a hydrocarbon containing at least n carbon atoms per molecule, where n is a positive integer. n- "Hydrocarbon" refers to a hydrocarbon containing up to n carbon atoms per molecule, where n is a positive integer. "Hydrocarbon" encompasses (i) saturated hydrocarbons, (ii) unsaturated hydrocarbons, and (iii) mixtures of hydrocarbons, including mixtures of hydrocarbon compounds (saturated and / or unsaturated), including mixtures of hydrocarbon compounds having different values ​​of n.

[0020] "Heavy hydrocarbons" refers to a mixture comprising hydrocarbons having an API gravity in the range of 5° to (but not including) 22°. "Medium hydrocarbons" refers to a mixture comprising hydrocarbons having an API gravity in the range of 22° to 30°. "Heavier" hydrocarbons have an API gravity less than naphtha.

[0021] The term "unsaturated" or "unsaturated hydrocarbon" refers to a C-atom containing at least one carbon atom directly bonded to another carbon atom by a double bond or a triple bond. 2+ Hydrocarbon. The term "olefin" refers to an unsaturated hydrocarbon containing at least one carbon atom directly bonded to another carbon atom by a double bond. In other words, an olefin is a compound containing at least one pair of carbon atoms in which the first and second carbon atoms of the pair are directly connected by a double bond. "Light olefin" refers to a C 5- Olefins.

[0022] "Predominantly in liquid phase" refers to a composition in which ≥50 wt%, such as ≥75 wt%, such as ≥90 wt% is in liquid phase. A hydrocarbon feedstock is predominantly in liquid phase when ≥50 wt% of the hydrocarbon feedstock is in liquid phase at a temperature of 25° C. and an absolute pressure of 1 bar (e.g. ≥75 wt%, such as ≥90 wt%).

[0023] A "virgin" feedstock, such as a virgin hydrocarbon feedstock, refers to a predominantly liquid phase feedstock comprising ≥ 25 wt% crude oil that has not undergone prior desalting and / or prior reflux fractionation processing, such as ≥ 50 wt%, such as ≥ 75 wt%, or ≥ 90 wt%.

[0024] "Crude oil" refers to a mixture comprising naturally occurring hydrocarbons of geological origin, wherein the mixture (i) comprises ≥ 1 wt% residual oil, such as ≥ 5 wt%, such as ≥ 10 wt%, and (ii) has an API gravity of ≤ 52°, such as ≤ 30°, such as ≤ 20°, or ≤ 10°, or < 8°. Crude oils can be classified by API gravity, such as heavy crude oils having an API gravity in the range of 5° to (but not including) 22°.

[0025] Normal (or "atmospheric") boiling points and normal boiling ranges may be measured by gas chromatographic distillation according to the method described in ASTM D-6352-98 or D2887, as extended by extrapolation for materials above 700°C.

[0026] Hydrocarbon feedstock, such as C 5+ Hydrocarbons, such as hydrocarbons that are primarily in the liquid phase at a temperature of 25° C. and a pressure of 1 bar (absolute), can be mixed, blended, combined, or otherwise contacted with an aqueous composition comprising water, steam, or a mixture thereof to produce a steam cracking feed. The hydrocarbon feed can be heated before and / or after it is combined with the aqueous composition. A pyrolysis feed that is primarily in the gas phase and a liquid phase product can be separated from the steam cracking feed. The pyrolysis feed can be heated and subjected to steam cracking conditions to produce a steam cracker effluent. The steam cracker effluent can be cooled to produce a cooled steam cracker effluent. For example, the steam cracker effluent can be directly contacted with a quenching fluid and / or indirectly cooled via one or more heat exchangers (e.g., a transmission line exchanger (“TLE”)) to produce a cooled steam cracker effluent. One of the products that can be separated from the cooled steam cracker effluent can be a steam cracker naphtha. Steam cracker naphtha is C 5+ Hydrocarbons, such as C5-C 10+A complex mixture of hydrocarbons having an initial atmospheric boiling point of about 25°C to about 50°C and a final boiling point of about 220°C to about 265°C as measured according to ASTM D2887-18. In some examples, the steam cracker naphtha may have an initial atmospheric boiling point of about 33°C to about 43°C and a final atmospheric boiling point of about 234°C to about 244°C as measured by ASTM D2887-18. The hydrocarbon feed contains one or more forms of silicon, such as silicon materials.

[0027] "Silicon material" refers to a composition comprising silicon, such as a composition comprising one or more of elemental silicon, silicon oxides (including silicon dioxide). The term silicon material encompasses natural and synthetic forms of silicon, for example, the silicon material may be one or more of an aggregate, a mixture, an ore, a compound, a complex, and the like.

[0028] Steam cracker naphtha can be hydrotreated to produce a stabilized or hydrotreated steam cracker naphtha product. For example, steam cracker naphtha can be hydrotreated in the presence of molecular hydrogen and one or more catalysts to produce a hydrotreated steam cracker naphtha, which can also be referred to as a stabilized steam cracker naphtha. The hydrotreated steam cracker naphtha can hydrogenate at least a portion of any dienes present in the steam cracker naphtha to monoolefins and / or convert at least a portion of any olefins to paraffins, and / or convert at least a portion of any sulfur compounds to hydrogen sulfide that may be present in the steam cracker naphtha. In some examples, a motor gasoline ("mogas") blending stock can be produced. Mogas blending stock is a C4-C4 blending stock comprising C4-C4 blending stocks having an initial atmospheric boiling point of about 35°C and a final boiling point of about 200°C. 12 A mixture of hydrocarbons. The mogas blendstock may include stabilized steam cracker naphtha.

[0029] It has been surprisingly and unexpectedly discovered that when the hydrocarbon feed contains silicon materials, hydroprocessing of steam cracker naphtha to produce hydrotreated steam cracker naphtha can be a limiting factor in how long the steam cracking process can be operated before the steam cracker needs to be shut down or shut down. More specifically, it has been discovered that one or more catalysts used in the hydroprocessing of steam cracker naphtha can become deactivated, degraded, poisoned, or otherwise become less effective (collectively referred to as "deactivation") before rendering another processing unit ineffective for performing its processing function. It has been discovered that deactivation is primarily caused by silicon materials in the hydrocarbon feed subjected to steam cracking and silicon materials derived from silicon materials in the hydrocarbon feed. Silicon materials contained in naphtha deactivate the catalyst(s) used in the hydroprocessing of steam cracker naphtha. Thus, methods and systems for steam cracking a hydrocarbon feed containing high levels of silicon material (e.g., 0.05 parts per million by weight or "wppm" to about 50 wppm of silicon material or about 0.1 wppm to about 25 wppm of silicon material) can be configured to operate for a predetermined period of time before requiring a shutdown or outage due to catalyst deactivation.

[0030] The predetermined period that the steam cracking process can be configured to operate can be any desired length of time, as long as the hydroprocessing reactor has sufficient capacity for the predetermined amount of hydroprocessing catalyst (one or more). In some examples, the predetermined period can be about 1 day, about 2 days, or about 3 days to about 1 month, about 6 months, about 1 year, about 1.5 years, about 2 years, about 3 years, or about 4 years. In some examples, the predetermined period can be based at least in part on the required volume of hydrocarbon feed directed to the steam cracker for steam cracking during the predetermined period.

[0031] A method for upgrading or steam cracking a hydrocarbon feed for a predetermined period of time may include estimating, measuring or otherwise determining a first amount of silicon, i.e., the amount of silicon present in the hydrocarbon feed in its various forms (e.g., the total mass (in grams) of silicon in all forms present in a given mass of hydrocarbon feed). The amount of silicon material in the hydrocarbon feed (and / or the amount of silicon in the silicon material) may be measured or otherwise determined using any suitable technique. In some examples, a representative sample of the hydrocarbon feed may be analyzed via an atomic emission detector, an x-ray fluorescence (XRF) spectrometer, an inductively coupled plasma mass spectrometer (ICP-MS), an inductively coupled plasma atomic emission spectrometer (ICP-AES), or a combination thereof to measure the amount of silicon material therein. The amount of silicon material may be measured by an inductively coupled plasma mass spectrometer according to UOP1006-14, Trace Silicon in Petroleum Liquids by ICP-MS, ASTM International, West Conshohocken, PA, 2014. The amount of silicon material may be measured by inductively coupled plasma atomic emission spectrometry according to ASTM D5708-15. In some examples, the amount of silicon material can be measured via inductively coupled plasma mass spectrometry according to ASTM D8110-17.

[0032] In certain aspects, the hydrocarbon feed comprises (i) silicon material and (ii) heavy and / or medium hydrocarbons. These aspects will now be described in more detail. The invention is not limited to these aspects, and this specification is not meant to exclude other aspects within the broader scope of the invention, such as those aspects in which the hydrocarbon feed is medium and / or light hydrocarbons.

[0033] Hydrocarbon feed

[0034] In some aspects, the hydrocarbon feed comprises hydrocarbons and silicon materials. It will be appreciated by those skilled in the art that the term "hydrocarbon feed" is a convenient designation, but does not mean that the feed contains only hydrocarbons. Although at least a portion of the silicon material of the hydrocarbon feed may be added to the hydrocarbon feed, generally most or even all of the silicon materials should be present in the feed at the feed source. For example, the silicon material in the hydrocarbon feed may be a silicon material naturally present in certain heavy hydrocarbons, such as a silicon material naturally present in crude oil. In these and other aspects, the hydrocarbon may have a standard final boiling point of about 315°C or higher, such as about 400°C or higher, about 450°C or higher, or about 500°C or higher.

[0035] In certain aspects, the hydrocarbons of the feed can be higher molecular weight hydrocarbons, such as heavy hydrocarbons, such as those that are pyrolyzed during steam cracking to produce larger amounts of steam cracker naphtha (also known as pyrolysis gasoline), steam cracker gas oil ("SCGO"), and SCT. The heavy hydrocarbons can include one or more of the following: residual oil (also known as residual oil or residue), gas oil, heating oil, jet fuel, diesel, kerosene, coker naphtha, hydrocracked products, reformate, raffinate reformate, distillate, crude oil, atmospheric still bottoms, vacuum still streams including bottoms, condensate, heavy non-straight run hydrocarbon streams from refineries, vacuum gas oil, heavy gas oil, naphtha contaminated with crude oil, atmospheric residue, heavy residue, C4 / residue mixture, naphtha residue mixture, gas oil residue mixture, low sulfur waxy residue, atmospheric residue, and heavy residue.

[0036] In certain aspects, the hydrocarbon feed includes economically advantageous, least processed heavy hydrocarbons containing non-volatile components and coke precursors. For example, the hydrocarbon feed may include about 1 wt % or more of heavy hydrocarbons, based on the weight of the hydrocarbon feed, such as about 25 wt % or more, about 50 wt % or more, about 75 wt % or more, about 90 wt % or more, or about 99 wt % or more. The hydrocarbon feed may include one or more raw materials, such as one or more crude oils, be composed of one or more raw materials, such as one or more crude oils, or be substantially composed of one or more raw materials, such as one or more crude oils.

[0037] In certain aspects, the hydrocarbon feed also comprises hydrocarbons (e.g., medium hydrocarbons and / or light hydrocarbons) of lower molecular weight. Light hydrocarbons typically include naphtha boiling range hydrocarbons and substantially saturated hydrocarbon molecules with less than five carbon atoms, such as ethane, propane, and mixtures thereof. Although hydrocarbon feedstocks comprising light hydrocarbons typically produce higher yields of C2 unsaturates than hydrocarbon feedstocks comprising heavy hydrocarbons, heavy hydrocarbons receive increasing attention due to lower cost and higher availability.

[0038] In these and other aspects, silicon materials (natural and / or synthetic) may be present in the hydrocarbon feed. For example, the hydrocarbon feed may include one or more of silicon, silicon-containing compounds, and compositions comprising silicon and / or silicon-containing compounds. Such silicon-containing compounds include inorganic silicon compounds and / or organic silicon compounds. Illustrative inorganic silicon compounds may be or include, but are not limited to, silicon dioxide, one or more silicates, or any mixture thereof. Illustrative organic silicon compounds may be or include, but are not limited to, silicones, also known as polysiloxanes. In some examples, the polysiloxane may be or include, but are not limited to, a compound having the chemical formula CH3[SiO] n CH3 polymethylsiloxane, one or more having the chemical formula (CH3)3SiO[(CH3)2SiO] nPolydimethylsiloxane of Si(CH3)3, or mixtures thereof. The natural and / or synthetic silicon material that may be found in the hydrocarbon feed may be or include one of the following, or be included in one or more of the following: sand; clay; other earthy and / or mineral forms of silicon-containing compositions (e.g., earthy aggregates such as rocks, stones, dirt, etc.); quartz; glass; lava; soapstone and pumice.

[0039] In certain aspects, the hydrocarbon feed contains silicon included in natural and / or synthetic minerals, such as one or more forms of silicate and / or non-silicate minerals, including compositions containing natural and / or synthetic silicon-containing minerals. For example, the hydrocarbon feed may contain natural and / or synthetic silicates, such as one or more of neosilicates, sorosilicates, cyclosilicates, inosilicates (single and multiple chains), phyllosilicates, tectosilicates (including those with and without zeolite HO), and silicon-substituted germanates. Alternatively or in addition, the hydrocarbon feed may contain silicon in the form of natural and / or synthetic non-silicate minerals. Typical silicon-containing, non-silicate minerals include one or more of those metals, alloys, carbides, silicides, nitrides and / or phosphides containing silicon in any form, such as silicon carbide; one or more of those halides, oxyhalides and hydroxyhalides containing silicon in any form, such as chukhrovite; one or more of those oxides and hydroxides, vanadates, arsenites, antimonates, bismuthates, sulfites and iodates containing silicon in any form, such as one or more silicon-containing spinels, such as triclinic magnesium aluminum ... 2+ (V 5+ ,As 5+ ,Si)3O 12 ); amorphous siliceous minerals; and organosilicon minerals.

[0040] At least a portion of the silicon (in all forms) in the hydrocarbon feed is present in the pyrolysis feed. For example, ≥10 wt % of the silicon (in all forms) present in the hydrocarbon feed (based on the weight of the feed) is typically present in the pyrolysis feed, such as ≥25 wt %, or ≥50 wt %, or ≥75 wt %, or ≥90 wt %, or in a range of 5 wt % to 95 wt %, or 10 wt % to 90 wt %. Because there is typically little, if any, conversion of one form or silicon to another form at a location upstream of the radiant coils in the steam cracking furnace, ≥10 wt % of the silicon material present in the hydrocarbon feed (based on the weight of the feed) is typically present in the pyrolysis feed, such as ≥25 wt %, or ≥50 wt %, or ≥75 wt %, or ≥90 wt %, or in a range of 5 wt % to 95 wt %, or 10 wt % to 90 wt %. As will be appreciated by those skilled in the art, the amount of silicon material in the hydrocarbon feed that appears in the pyrolysis feed will depend, for example, on whether a gas-liquid separator is used to separate the pyrolysis feed from the steam cracking feed, and if so, on the cut point established for the gas-liquid separator.

[0041] Steam cracking pyrolysis feed under steam cracking process conditions generally results in at least a portion of certain forms of silicon in the pyrolysis feed being converted into other forms of silicon. For example, steam cracking may result in at least a portion of any polysiloxane in the hydrocarbon feed and / or pyrolysis feed being converted into other forms of smaller molecular weight silicones, such as linear and / or cyclic polysiloxanes. Although the amount of each of the various forms of silicon may increase or decrease due to steam cracking, the total mass of silicon (all forms) in the steam cracker effluent is generally substantially the same as the total mass of silicon (all forms) in the pyrolysis feed. Therefore, the silicon material in the steam cracker naphtha may correspond to the silicon material present in the hydrocarbon feed before steam cracking and / or the silicon material produced during the steam cracking of hydrocarbons. It will be appreciated by those skilled in the art that certain forms of steam cracking furnace equipment, such as steam cracker tubes, such as certain forms of radiant coils, contain silicon materials that can be transferred to the steam cracker effluent in small amounts during pyrolysis mode and continuous decoking mode. Typically, however, the amount of such transported silicon material in the steam cracker effluent is ≤ 1 wt %, based on the weight of the steam cracker effluent, such as ≤ 0.1 wt % or ≤ 0.01 wt %, such as in the range of 0.01 wt % to 1 wt %.

[0042] Because the amount of silicon material in the steam cracker effluent from other sources has been found to be small, the amount of silicon (in all forms) that may be present in the steam cracker naphtha fraction of the steam cracker effluent can be calculated or otherwise determined from the amount of silicon (in all forms) in the hydrocarbon feed. For example, the amount of silicon in the steam cracker effluent can be determined with an accuracy of 1% or better (on a weight basis) by multiplying the mass of silicon (found in all its forms) in the hydrocarbon feed by the mass of the hydrocarbon feed. During the pyrolysis mode, a first portion of the silicon material of the hydrocarbon feed can be removed from the process by a gas-liquid separation integrated with the convection section of the steam cracking furnace. When used, the gas-liquid separation includes separating at least two streams from the steam cracking feed: (i) a first stream comprising a primarily gas phase portion of the steam cracking feed and (ii) a second stream comprising a primarily liquid phase portion of the steam cracking feed. In some examples, about 25% (by weight) of the silicon material in the hydrocarbon feed is transferred to the second stream, such as about 30%, such as about 35%, or about 40% to about 55%, or about 60%, or about 65%, about 70%, or about 75%. Therefore, in some examples, about 25% (by weight) of the silicon material in the hydrocarbon feed is transferred to the first stream, such as about 30%, such as about 35%, or about 40% to about 55%, or about 60%, or about 65%, or about 70%, or about 75%. After optional additional heating, for example, in the convection section of the steam cracking furnace, the first stream can be introduced as a pyrolysis feed into the radiant coils of one or more steam cracking furnaces.

[0043] In addition to steam cracker naphtha, multiple products can be separated from the cooled steam cracker effluent. Illustrative products that can be separated from steam cracker naphtha can be or include, but are not limited to, process gas, steam cracker gas oil, steam cracker quench oil and steam cracker tar or tar products containing ethylene and propylene. Similar to steam cracker naphtha, steam cracker gas oil and steam cracker quench oil each contain a mixture of compounds, mainly a mixture of hydrocarbon compounds. In some instances, at least a portion of steam cracker quench oil can be mixed, blended, combined or otherwise contacted with steam cracker effluent to produce cooled steam cracker effluent. It should be understood that there is usually an overlap in the composition and boiling point range between steam cracker naphtha and steam cracker gas oil. The final atmospheric boiling point of steam cracker gas oil is generally about 275°C to about 285°C, measured according to ASTM D2887-18. It should also be understood that there is generally overlap in composition and boiling point ranges between steam cracker naphtha and steam cracker quench oil. Steam cracker quench oil generally has a final atmospheric boiling point of about 455°C to about 475°C, measured according to ASTM D2887-18. Steam cracker tar may have a final atmospheric boiling point of >650°C.

[0044] During the process of separating products from a cooled steam cracker effluent, a first portion of the silicon material of the steam cracker effluent can be removed from the process as a component of the steam cracker naphtha, a second portion of the silicon material can be removed from the process as a component of the steam cracker gas oil, and a third portion of the silicon material can be removed from the process as a component of the tar product. In some examples, about 28 wt%, about 30 wt%, about 32 wt%, or about 34 wt% to about 36 wt%, about 38 wt%, about 40 wt%, or about 42 wt% of the silicon material in the cooled steam cracker effluent can be removed from the process as a component of the steam cracker gas oil and / or the tar product. In some examples, the steam cracker gas oil may also contain silicon, such as about 1 wt% to about 40 wt% of the silicon material in the cooled steam cracker quench oil.

[0045] The steam cracker naphtha contains a second amount of silicon, wherein the second amount of silicon is equal to the total mass of silicon present in all silicon forms in a given mass of steam cracker naphtha. The second amount can be about 5% to about 75% of the first amount of silicon, such as about 10% to about 60%, such as about 15% to about 52.5%, or about 20% to about 50%. Those skilled in the art will understand that the upper limits of these ranges can be used when determining the amount of hydrotreating catalyst required to hydrotreat the steam cracker naphtha for a predetermined period of time. Therefore, when the first amount of silicon is known, the predetermined amount of all forms of silicon in the steam cracker naphtha can be determined or estimated to be about 75% of the first amount, such as about 60% of the first amount, such as about 52.5% of the first amount, or about 50% of the first amount.

[0046] Thus, certain aspects of the present invention are based in part on the discovery of how various forms of silicon in a hydrocarbon feed are distributed in a steam cracking process. Once a first amount of all forms of silicon in a hydrocarbon feed is measured, estimated, or otherwise determined, a second amount of all forms of silicon in a steam cracker naphtha can be determined for a specified steam cracking configuration and process conditions. And once the second amount of all forms of silicon in the steam cracker naphtha is determined, the amount of catalyst required for hydrotreating the naphtha can also be determined, for example, to allow the steam cracking process to operate for a predetermined period of time. In other words, (i) the amount and composition of silicon material in the hydrocarbon feed and (ii) the amount of catalyst required to be arranged in one or more catalyst beds within one or more naphtha hydrotreaters to allow the steam cracking process to operate for a predetermined period of time can be predetermined based on the type and amount of various forms of silicon that make up the silicon material in the hydrocarbon feed. Prior to starting the steam cracking process, a sufficient amount of catalyst can be loaded or otherwise arranged within the hydrotreater to enable the steam cracker naphtha to be hydrotreated for at least as long as the predetermined period of time. Once a sufficient amount of catalyst is disposed within the hydrotreater, the hydrocarbon feed can be steam cracked, and the steam cracking can continue for a predetermined period of time without requiring shutdown due to silicon materials in the steam cracker naphtha.

[0047] The amount of catalyst disposed within the hydroprocessor may be sufficient to allow one or more forms of silicon to accumulate on the catalyst in an amount of silicon (total silicon included in all forms of silicon present on the catalyst) of about 0.3 wt%, about 0.5 wt%, about 1 wt%, about 2 wt%, or about 3 wt% to about 5 wt%, about 10 wt%, or about 15 wt% or more, based on the weight of the catalyst. It should be understood that, at least in the hydroprocessing environment that a given catalyst may optionally include, the weight of the catalyst includes the catalytically active components and any optional support materials and / or other optional components that are not catalytically active. The amount of silicon material that a given catalyst can accommodate may depend, at least in part, on the specific catalyst and / or specific processing conditions within the hydroprocessor.

[0048] After determining the second amount of silicon in the steam cracker naphtha and generally also determining the amount of silicon material (based on weight) in the steam cracker naphtha, one skilled in the art can easily calculate or otherwise determine the amount of catalyst that needs to be arranged in one or more hydroprocessors to operate the steam cracking process for a predetermined period of time. For any given amount of various forms of silicon in the steam cracker naphtha, the amount of catalyst that should be arranged in one or more hydroprocessors can depend at least in part on the specific catalyst, the mass flow rate of the steam cracker naphtha passing through the one or more hydroprocessors, the predetermined period of time, and / or the hydroprocessing conditions in the one or more hydroprocessors. The properties that can be considered for a specific catalyst can include, but are not limited to, the surface area of ​​the catalyst, the pore volume of the catalyst, the pore size of the catalyst, the catalyst particle size, and / or the type and amount of catalytically active material in the catalyst. The hydroprocessing conditions that can be considered can include, but are not limited to, for example, temperature, pressure, hydrogen partial pressure, and / or weight hourly space velocity.

[0049] In some examples, the silicon material in the steam cracker naphtha may include about 0.01 wt%, about 0.05 wt%, about 0.1 wt%, or about 0.2 wt% to about 0.5 wt%, about 0.7 wt%, or about 1 wt% of C5-C6 silicones, about 10 wt%, about 15 wt%, or about 20 wt% to about 30 wt%, about 35 wt%, or about 50 wt% of C7-C9 silicones, and about 60 wt%, about 65 wt%, or about 70 wt% to about 80 wt%, about 85 wt%, or about 90 wt% of C 10+ Silicone, based on the weight of the silicon material in the steam cracker naphtha. In other examples, the silicon material in the steam cracker naphtha may include ≤ 1 wt % C5-C6 silicone, about 10 wt % to about 50 wt % C7-C9 silicone, and about 60 wt % to about 90 wt % C 10+ Silicones, based on the weight of silicon materials in the steam cracker naphtha.

[0050] It is observed for a variety of heavy hydrocarbon feeds that determining the amount of silicon material in the hydrocarbon feed (based on mass) also provides the amount (based on mass) of any organosilicon compound in the feed relative to the combined amount (based on mass) of any elemental silicon and any inorganic silicon compound in the feed. In a specific example, if the amount of silicon material in the hydrocarbon feed is determined to be about 0.25 wppm, the silicon material in the hydrocarbon feed consists of about 0.15 wppm of organosilicon compound and about 0.1 wppm of combined amount of inorganic silicon compound and elemental silicon. For various heavy hydrocarbon feeds and a wide range of wppm of silicon material in the hydrocarbon feed, such as in the range of about 0.01 wppm to about 1 wppm, such as 0.05 wppm to 0.5 wppm, this distribution of silicon material in the hydrocarbon feed in (i) organosilicon compound and (ii) combination of inorganic silicon compound and elemental silicon is observed. Based on these values, one skilled in the art can easily estimate the first silicon amount in the hydrocarbon feed from the amount of silicon material in the hydrocarbon feed.

[0051] It is also observed for a variety of heavy hydrocarbon feeds that determining the amount of silicon material in the hydrocarbon feed (based on mass) also provides the relative amounts of elemental silicon, inorganic silicon compounds, and organosilicon compounds relative to each other (based on mass). In a specific example, if the total amount of silicon material in the hydrocarbon feed (based on mass) is determined to be about 0.2wppm, the relative amounts of various forms of silicon material are present in the following amounts (based on mass): about 0.1wppm of inorganic silicon compounds, about 0.08wppm of organosilicon compounds, and about 0.02wppm of elemental silicon. For a wide range of wppm of silicon material in various heavy hydrocarbon feeds and hydrocarbon feeds, such as in the range of about 0.01wppm to about 1wppm, such as 0.05wppm to 0.5wppm, it is observed that the silicon material in the hydrocarbon feed is distributed in (i) inorganic silicon compounds, (ii) organosilicon compounds, and (iii) elemental silicon. Based on these values, a person skilled in the art can easily determine the first silicon amount in the hydrocarbon feed. Based on these values, one skilled in the art can easily make an improved estimate of the first amount of silicon in the hydrocarbon feed based on the amount of silicon material in the hydrocarbon feed.

[0052] Steam cracker naphtha can be subjected to hydrotreating conditions to produce hydrotreated steam cracker naphtha. Steam cracker naphtha generally contains various forms of silicon. Silicon present in these various forms generally includes at least a portion of silicon present in various forms in the hydrocarbon feed. Hydrotreating can be carried out in one or more hydrotreating stages under hydroconversion conditions, and the hydroconversion conditions can be independently selected for each stage, such as under the conditions of one or more of pretreatment, hydrocracking (including selective hydrocracking), hydrogenation, hydrotreating, hydrodesulfurization, hydrodenitrogenation, hydrodemetallization, hydrodearomatization, hydroisomerization or hydrodewaxing for carrying out tar products according to the specific circumstances. In some examples, steam cracker naphtha can be hydrotreated in one or more hydrotreating units, and the hydrotreating unit may include one or more hydrotreating containers or zones. Hydrotreating containers or zones may include one or more catalysts arranged therein. The catalyst may be in a fixed catalyst bed, a circulating or slurry bed or any other configuration. In some examples, the steam cracker naphtha may be subjected to one or more separation processes prior to being subjected to hydroprocessing, for example to remove at least a portion of any water and / or steam and / or to remove at least a portion of any C4 and lighter hydrocarbons.

[0053] In some examples, the steam cracker naphtha hydrotreating conditions may include a temperature of about 40°C, about 75°C, or about 100°C to about 200°C, about 300°C, or about 370°C. In some examples, the steam cracker naphtha hydrotreating conditions may be conducted at an absolute pressure of about 600 kPa, about 1,000 kPa, or about 1,500 kPa to about 2,000 kPa, about 2,750 kPa, or about 4,000 kPa. In some examples, the steam cracker naphtha hydrotreating conditions may be conducted at an absolute pressure of about 1 h. -1 , about 3h -1 or about 5h -1 About 8 hours -1 , about 12h -1 or about 15h -1 In at least one example, the steam cracker naphtha hydroprocessing conditions may include a temperature of about 40°C to about 370°C, an absolute pressure of about 600 kPa to about 4,000 kPa, and a pressure of about 1 h -1 About 15h -1 Catalyst weight hourly space velocity (WHSV) of . Illustrative hydrotreaters and methods of operating the same that can be used to hydrotreat steam cracker naphtha may include those disclosed in U.S. Pat. No. 8,894,844; and U.S. Patent Application No.: 2016 / 0376511.

[0054] In some examples, hydrotreating steam cracker naphtha may include hydrotreating steam cracker naphtha under a first set of hydrotreating conditions to produce an intermediate or pretreated steam cracker naphtha. The pretreated steam cracker naphtha may be hydrotreated under a second set of hydrotreating conditions to produce a hydrotreated steam cracker naphtha. In some aspects, the first hydrotreating conditions are substantially the same as the second hydroprocessing conditions, but in other aspects, they are different.

[0055] In some instances, the steam cracker naphtha can be hydrotreated under a first set of hydroprocessing conditions in the presence of molecular hydrogen and a first catalyst to produce a pretreated steam cracker naphtha, and the pretreated steam cracker naphtha can be hydrotreated under a second set of hydroprocessing conditions in the presence of molecular hydrogen and a second catalyst to produce a hydrotreated steam cracker naphtha. In some aspects, the first catalyst is substantially the same as the second catalyst, but in other aspects, the catalyst is different. In some instances, the first catalyst can be or include nickel. For example, the first catalyst can be or include nickel sulfide. In some instances, the second catalyst can be or include nickel, molybdenum, cobalt, its alloy or a mixture or combination thereof. In some instances, the second catalyst can be or include a nickel-molybdenum catalyst and / or a cobalt-molybdenum catalyst.

[0056] In some examples, the amount of the first catalyst that the steam cracker naphtha may contact during the first hydrotreatment may be greater than the amount of the second catalyst that the pretreated steam cracker naphtha may contact during the second hydrotreatment. In other examples, the amount of the first catalyst that the steam cracker naphtha may contact during the first hydrotreatment may be less than the amount of the second catalyst that the pretreated steam cracker naphtha may contact during the second hydrotreatment. In still other examples, the amount of the first catalyst that the steam cracker naphtha may contact during the first hydrotreatment may be almost the same as the amount of the second catalyst that the pretreated steam cracker naphtha may contact during the second hydrotreatment.

[0057] In some examples, when the hydroprocessing of the steam cracker naphtha includes two hydroprocessing units, about 5 wt%, about 10 wt%, about 12 wt%, or about 15 wt% to about 20 wt%, about 25 wt%, about 30 wt%, about 35 wt%, or about 40 wt% of the silicon material in the steam cracker naphtha can be deposited, trapped, contained, retained, reacted, or otherwise disposed on the first catalyst, based on the total weight of the silicon material in the steam cracker naphtha. In some examples, about 60 wt%, about 65 wt%, or about 70 wt% to about 80 wt%, about 85 wt%, about 90 wt%, or about 95 wt% of the silicon material in the pretreated steam cracker naphtha can be deposited, trapped, contained, retained, reacted, or otherwise disposed on the second catalyst, based on the total weight of the silicon material in the steam cracker naphtha. Typically, when the hydroprocessing of steam cracker naphtha includes two hydroprocessing units, about 5 wt%, about 10 wt%, about 12 wt%, or about 15 wt% to about 20 wt%, about 25 wt%, about 30 wt%, about 35 wt%, or about 40 wt% of the silicon derived from the silicon material in the steam cracker naphtha, based on the total weight of silicon present in various forms in the steam cracker naphtha, can be deposited, trapped, contained, maintained, reacted, or otherwise disposed on the first catalyst. For example, about 60 wt%, about 65 wt%, or about 70 wt% to about 80 wt%, about 85 wt%, about 90 wt%, or about 95 wt% of the silicon derived from the silicon material in the pretreated steam cracker naphtha, based on the total weight of silicon present in various forms in the steam cracker naphtha, can be deposited, trapped, contained, maintained, reacted, or otherwise disposed on the second catalyst.

[0058] Once a sufficient amount of catalyst is introduced into the hydroprocessing unit to allow the hydroprocessing unit to hydroprocess the steam cracker naphtha that can be separated from the steam cracker effluent for at least a predetermined period of time, the steam cracking process can be started and the hydrocarbon feed can be steam cracked. For example, once a sufficient amount of a first catalyst is introduced into the first hydroprocessing unit and a sufficient amount of a second catalyst is introduced into the second hydroprocessing unit to allow the hydroprocessing unit to hydroprocess the steam cracker naphtha that can be separated from the steam cracker effluent for at least a predetermined period of time, the steam cracking process can be started and the hydrocarbon feed can be steam cracked for at least a predetermined period of time without the need to replace or reactivate the first and second catalysts due to catalyst deactivation caused by silicon material present in the steam cracker naphtha.

[0059] In some examples, when hydrotreating steam cracker naphtha includes hydrotreating under a first set of hydrotreating conditions to produce pretreated steam cracker naphtha and hydrotreating under a second set of hydrotreating conditions to produce hydrotreated steam cracker naphtha, when the same or different amounts of silicon material are deposited, retained, included, maintained, reacted or otherwise arranged on the first catalyst and the second catalyst, the first catalyst and the second catalyst may become less effective, deactivated or otherwise consumed. The increase in the pressure drop from the inlet to the outlet through the hydrotreating reactor can be an indication of the catalyst being ineffective. For example, the hydrotreating reactor pressure drop increases by 1.1 times (e.g., 1.2 times, or 1.5 times, or 1.75 times, or 2 times) of the reactor pressure drop at the beginning of hydrotreating, which can indicate that the catalyst is ineffective.

[0060] In some examples, if a first set of hydroprocessing conditions selectively hydrogenates dienes to mono-olefins (wherein some hydrodesulfurization optionally occurs) and a second set of hydroprocessing conditions selectively hydrosulfurizes (wherein some hydrogenation optionally occurs), the first catalyst may become less effective, deactivated, or otherwise consumed when the first catalyst accumulates a first amount of silicon material, and the second catalyst may become less effective, deactivated, or otherwise consumed when the second catalyst accumulates a second amount of silicon material. The first amount may be less than, equal to, or greater than the second amount. In some instances, the first catalyst may become less effective, deactivated, or otherwise consumed when the first catalyst accumulates about 0.3 weight percent, about 0.4 weight percent, about 0.5 weight percent, or about 0.6 weight percent to about 0.7 weight percent, about 0.8 weight percent, about 0.9 weight percent, about 1 weight percent, about 1.1 weight percent, about 1.2 weight percent, about 1.3 weight percent, about 1.4 weight percent, or about 1.5 weight percent of the silicon material (or silicon derived from the silicon material) disposed thereon, based on the weight of the catalyst. In this embodiment, it has also been found that when the catalyst accumulates about 2 wt%, about 2.5 wt%, about 3 wt%, about 3.5 wt%, about 4 wt%, or about 5 wt% to about 6 wt%, about 7 wt%, about 8 wt%, about 9 wt%, about 10 wt%, about 11 wt%, about 12 wt%, about 13 wt%, about 14 wt%, or about 15 wt% of the silicon material (or silicon derived from the silicon material) disposed thereon, the second catalyst may become less effective, deactivated, or consumed. It should be understood that the development of more robust catalysts may result in an increase in the amount of silicon material that can be disposed on the first catalyst and / or the second catalyst before the catalyst becomes less effective, deactivated, or otherwise consumed.

[0061] Now refer to Figure 1Certain aspects of the invention are described, which include a gas-liquid separator integrated with a convection section of a steam cracking furnace. The invention is not limited to these aspects, and this description should not be interpreted as excluding other aspects within the broader scope of the invention, such as aspects that do not include such a gas-liquid separator.

[0062] Figure 1 A system 100 is schematically shown for steam cracking a hydrocarbon feed in line 101, separating a product comprising steam cracker naphtha therefrom via line 131, and hydrotreating the steam cracker naphtha in line 131 for at least a predetermined period of time, according to one or more aspects. The hydrocarbon feed (e.g., containing C 5+ A hydrocarbon feed) and an aqueous stream via line 102 comprising water, steam, or a mixture of water and steam are mixed, blended, combined, or otherwise contacted to produce a steam cracking feed, which is conducted via line 103. In certain aspects, the hydrocarbon feed of line 101 is preheated in a convection section 106 of a furnace 105 before it is combined with the aqueous stream of line 102. In some examples, the hydrocarbon feed can be or include a hydrocarbon or hydrocarbon feedstock disclosed in U.S. Patent Nos. 7,993,435; 8,696,888; 9,327,260; 9,637,694; 9,657,239; and 9,777,227; and PCT Patent Application Publication No. WO2018 / 111574.

[0063] In some aspects, the hydrocarbon feed is introduced into the inlet of at least one convection coil located in the convection section of the steam cracking furnace for preheating. The preheating of the hydrocarbon feed can include indirect contact between the feed in the convection section of the steam cracker and the hot flue gas traveling upward from the radiant section of the furnace. Typically, the hydrocarbon feed is distributed between a plurality of convection coils. These can be in the form of a group of heat exchange tubes located in the convection section of the steam cracker. Typically, the amount of the water-containing stream in the steam cracking feed of pipeline 103 is based on the weight of the steam cracking feed. ≥5 weight%, such as in the range of about 10 weight % to about 90 weight % or about 10 weight % to about 95 weight %. Typically, ≥90 weight % of the remainder of the steam cracking feed is preheated hydrocarbon feed, such as ≥95 weight %, such as ≥99 weight %. In some aspects, the steam cracking feed has a weight ratio of steam to hydrocarbon feed of about 0.1 to about 1, such as about 0.2 to about 0.6.

[0064] The steam cracking feed in line 103 can be heated to a temperature of, for example, about 200° C. to about 585° C. to produce heated steam cracking feed. For example, the steam cracking feed in line 103 can be heated in the convection section 106 of the furnace 105 to produce heated steam cracking feed via line 108.

[0065] The vapor and liquid products may be separated from the heated steam cracking feed by introducing the heated steam cracking feed into one or more separators, such as one or more flash separators, of a "first separation stage" 110 via line 108. The vapor products via line 111 and the liquid products (pyrolysis feed) via line 112 may be carried away from the first separation stage 110. While it is applicable in other respects, it is particularly suitable to utilize a first separation stage in the process when the hydrocarbon feed or preheated hydrocarbon feed contains about 0.1 wt % or more, such as about 5 wt % or more, of asphaltenes based on the weight of the hydrocarbon feed. In some examples, first separation stage 110 can be or can include separators and / or other devices disclosed in U.S. Pat. Nos. 7,138,047; 7,090,765; 7,097,758; 7,820,035; 7,311,746; 7,220,887; 7,244,871; 7,247,765; 7,351,872; 7,297,833; 7,488,459; 7,312,371; 6,632,351; 7,578,929 and 7,235,705. The first separation stage can be configured (e.g., by selecting a vapor-liquid fractionation point) to remove about 5 wt% to 95 wt% (or about 25 wt% to about 75 wt%) of the silicon material in the hydrocarbon feed in line 101 as a component of the liquid bottoms stream via line 112. Thus, in some examples, about 5 wt % to about 95 wt % (or about 25 wt % to about 75 wt %) of the silicon material in the hydrocarbon feed in line 101 can be a component of the gas-phase product (pyrolysis feed) in line 111. The bottoms stream can include, for example, (i) at least about 5 wt % of the total silicon content (all forms of silicon) of the hydrocarbon feed, and (ii) at least about 10 wt % of the asphaltenes in the hydrocarbon feed. Typically, ≥10 wt % of the total silicon content (all forms of silicon) of the hydrocarbon feed is present in the bottoms stream, such as ≥15 wt %, such as ≥20 wt %, or ≥25 wt %, or ≥30 wt %, or in the range of about 5 wt % to 50 wt %, or about 10 wt % to 30 wt %; and ≥75 wt % of the remainder of the total silicon content of the hydrocarbon feed is present in the pyrolysis feed, such as ≥90 wt %.

[0066] It has been found that utilizing a first separation stage increases the variety of hydrocarbon feeds that can be introduced into a steam cracking furnace with little or no pretreatment. For example, it has been found that utilizing a first separation stage having at least one flash separation vessel integrated with a convection section of a steam cracking furnace facilitates steam cracking of a wide range of hydrocarbon feeds, including those containing ≥50 wt % (e.g., ≥75 wt % or ≥90 wt %) of one or more of medium hydrocarbons, heavy hydrocarbons, original heavy hydrocarbons, original medium hydrocarbons, desalted heavy hydrocarbons and / or desalted medium hydrocarbons, heavy and / or medium crude oils, desalted heavy crude oils and / or desalted medium crude oils, etc., based on the weight of the hydrocarbon feed.

[0067] It has also been found that utilizing the first separation stage results in improved management of undesirable contaminants in the steam cracking feed, because gas phase contaminants (e.g., those transferred to the pyrolysis feed) can be kept within predetermined limits. In certain aspects, utilizing the first separation stage advantageously transfers ≥50 wt % of any salts and particles in the liquid phase portion of the steam cracking feed to the bottoms stream, such as ≥75 wt %, such as ≥90 wt %, or ≥99 wt %. The composition of the hydrocarbon feed directed to the steam cracking furnace, the amount of hydrocarbon feed directed to the furnace, the amount of preheat of the hydrocarbon feed, the amount of dilution steam combined with the preheated hydrocarbon feed, and any amount of heating of the steam cracking feed upstream of the first separation stage are typically selected to achieve ≥2 wt %, such as ≥5 wt %, such as ≥10 wt %, or ≥20 wt %, or ≥50 wt %, or ≥75 wt %, or ≥90 wt %, or ≥95 wt % or more vaporization of the hydrocarbon portion of the steam cracking feed at the location where the steam cracking feed enters the separation vessel. For example, these selections can be made to achieve vaporization of the hydrocarbon portion of the steam cracking feed by about 5 wt % to about 98 wt %, such as about 10 wt % to about 95 wt %, such as about 20 wt % to about 80 wt %, or about 25 wt % to about 75 wt %. Typically, ≥ 75 wt % (the portion not in the gas phase) of the remainder of the hydrocarbon portion of the steam cracking feed is in the liquid phase, such as ≥ 90 wt % or ≥ 95 wt %.

[0068] The composition (and therefore properties, such as viscosity and API gravity) of the hydrocarbon portion of the steam cracking feed, the flow rate of the steam cracking feed (particularly the flow rate of the liquid portion of the steam cracking feed), and the type and amount of salts and / or particulate matter in these flows can be selected to achieve a predetermined amount of liquid phase of the steam cracking feed. For feeds that exhibit smaller flow rates, particularly smaller flow rates of the liquid phase portion, it is indicated that the amount of steam cracking feed in the liquid phase is greater. This is typically the case when the hydrocarbon feed contains more viscous, typically heavier hydrocarbons. It is generally desirable to select these properties and conditions to maintain about 2% or more, such as about 5% or more, of the hydrocarbon portion of the steam cracking feed in the liquid phase, based on weight, at the location where the steam cracking feed enters the separation vessel.

[0069] The first separation stage can include at least one flash separation vessel operated at a temperature of about 315°C to about 510°C and / or a pressure of about 275kPa to about 1400kPa, for example, a temperature of about 430°C to about 480°C and / or a pressure of about 700kPa to about 760kPa. Depending on the composition of the hydrocarbon feed and the conditions used in the convection section and the flash separation vessel, the various forms of sulfur present in the pyrolysis feed may be different from those of the hydrocarbon feed. The bottom stream can be taken away from the flash separation vessel, for example, for storage and / or further processing. The silicon-poor, mainly gas-phase pyrolysis feed is directed to the radiant section for pyrolysis. Optionally, the pyrolysis feed can be subjected to further heating in the convection section before it is introduced into the radiant section.

[0070] Those skilled in the art will appreciate that a wide range of pyrolysis conditions may be used, and that the selection of specific pyrolysis conditions will depend, for example, on the composition of the selected hydrocarbon feed and the relative amounts of various products and co-products in the steam cracker effluent, such as the relative amounts of ethylene and propylene. For example, the pyrolysis conditions typically include heating the pyrolysis feed in a radiant coil to achieve a temperature of the radiant coil effluent (measured at the outlet of the radiant coil) of about 400°C or more, such as about 400°C to about 1100°C, a pressure of about 10 kPa or more (measured at the outlet of the radiant coil), and a residence time in the radiant coil of about 0.01 seconds to 5 seconds. In certain aspects, such as those in which the hydrocarbon feed comprises crude oil or desalted crude oil, the pyrolysis conditions may include one or more of the following: (i) a temperature of about 760° C. or higher, such as about 760° C. to about 1100° C., or about 790° C. to about 880° C., (ii) a pressure of about 50 kPa or higher, such as about 60 kPa to about 500 kPa, or about 90 kPa to about 240 kPa; and / or (iii) a residence time of about 0.1 seconds to about 2 seconds. For hydrocarbon feeds containing lighter hydrocarbons, temperatures in the range of about 760° C. to about 950° C. are generally used. The specified steam cracking conditions may be sufficient to convert at least a portion of the hydrocarbon molecules of the pyrolysis feed into C 2+ olefins and converts a portion of the sulfur of the pyrolysis feed into smaller molecular weight forms.

[0071] In certain aspects, the pyrolysis feed in line 111 can be heated to a temperature ≥ 400° C., such as a temperature of about 425° C. to about 825° C., and introduced into the radiant section 107 of the furnace 105 to produce a steam cracker effluent that can be taken away via line 113. In some examples, the gas-phase products in line 111 can be heated in the convection section 106 of the furnace 105 before being introduced into the radiant section 107 of the furnace 105. In some examples, additional water and / or steam can be mixed, blended, combined, or otherwise contacted with the pyrolysis feed prior to being introduced into the radiant section 107 of the furnace 105 for pyrolysis (steam cracking). In some examples, the pyrolysis feed in line 111 can be steam cracked according to the methods and systems disclosed in U.S. Patent Nos. 6,419,885; 7,993,435; 9,637,694; and 9,777,227; U.S. Patent Application Publication No. 2018 / 0170832; and PCT Patent Application Publication No. WO2018 / 111574.

[0072] The steam cracker effluent typically includes unconverted components of the pyrolysis feed and pyrolysis products. The pyrolysis products typically include C 2+ Olefins, molecular hydrogen, acetylene, aromatic hydrocarbons, saturated hydrocarbons, C 3+ Diolefins, aldehydes, CO2, steam cracker tars, and various forms of silicon. In some examples, the steam cracker effluent via line 113 can be introduced into one or more separators of a "second separation stage" 125. In other examples, the steam cracker effluent in line 113 can be mixed, blended, combined, or otherwise contacted with a quench fluid in line 127 to produce a cooled steam cracker effluent in line 120, which can be introduced into the second separation stage 125. In some examples, the steam cracker effluent in line 113 can be at a temperature of ≥300°C, ≥400°C, ≥500°C, ≥600°C, or ≥700°C, or ≥800°C, or higher. In certain aspects, the maximum temperature of the steam cracker effluent in line 113 when initially contacted with the quench fluid in line 127 can be about 425°C to 850°C, such as about 450°C to about 800°C.

[0073] Those skilled in the art will appreciate that the amount of quench fluid contacted with the steam cracker effluent should be sufficient to cool the steam cracker effluent to facilitate separation of the desired product in the second separation stage 125 (e.g., a primary fractionator). While the amount of quench fluid required to do so may vary significantly from facility to facility, the weight ratio of quench fluid to steam cracker effluent is typically from about 0.1 to about 10, such as from 0.5 to 5, such as from 1 to 4. In a particular case, the desired weight ratio may be determined, for example, by any one or more of a number of factors, such as the amount of steam cracker effluent to be cooled, the temperature of the steam cracker effluent at the quench location, the composition and thermodynamic properties (e.g., enthalpy, C ) of the quench fluid and steam cracker effluent, and the composition and thermodynamic properties (e.g., enthalpy, C ) of the quench fluid and steam cracker effluent. P %, etc.), the desired temperature of the quench fluid-steam cracker effluent mixture at the inlet of the primary fractionator (i.e., the cooled steam cracker effluent), etc. For example, in certain aspects, the cooled steam cracker effluent in line 120 can include quench fluid in an amount of about 5 wt % to about 95 wt %, about 25 wt % to about 90 wt %, or about 50 wt %, or about 80 wt %, based on the weight of the cooled steam cracker effluent.

[0074] like Figure 1 As shown, the steam cracker quench oil taken away from the second separation stage 125 via line 127 can be contacted with the steam cracker effluent in line 113 to produce a cooled steam cracker effluent in line 120. In some examples, instead of using steam cracker quench oil to cool the steam cracker effluent in line 113 or in addition to using steam cracker quench oil to cool the steam cracker effluent in line 113, steam cracker gas oil and / or one or more application fluid products via line 133 can also be used. Suitable application fluid products can include those disclosed in U.S. Patent Nos. 9,090,836; 9,637,694; and 9,777,227; and PCT Patent Application Publication No. WO 2018 / 111574.

[0075] In some examples, a variety of products can be recovered from the second separation stage 125. For example, overhead or process gas via line 129, steam cracker naphtha via line 131, steam cracker gas oil via line 133, steam cracker quench oil via line 127, and / or tar products via line 135 can be taken away from the second separation stage 125. In some examples, products that can be separated from the process gas in line 129 can include, but are not limited to, tail gas, ethane, ethylene, propane, propylene, crude C4 hydrocarbons, or any combination thereof. The second separation stage 125 can be or include one or more fractionators, knockout drums, combined quench towers and primary fractionators, compressors, contaminant removal units, such as CO2 and / or H2S removal units, acetylene converters, and the like.

[0076] In some examples, conventional separation equipment can be used to separate various products, such as steam cracker naphtha, from the cooled steam cracker effluent. For example, one or more flash drums, separation drums, fractionators, water quenching towers, indirect condensers, etc. In some examples, illustrative separation stages may include, for example, those disclosed in U.S. Patent No. 8,083,931. In other examples, products that can be separated from the cooled steam cracker effluent (e.g., steam cracker naphtha) can be separated according to the methods and systems disclosed in U.S. Patent Application Publication No. 2014 / 0357923.

[0077] In some examples, at least a portion of the steam cracker naphtha via line 131 and molecular hydrogen via line 132 may be introduced into one or more hydroprocessing units 155 to produce hydrotreated steam cracker naphtha via line 163. The steam cracker naphtha may be hydrotreated in the presence of molecular hydrogen and one or more catalysts (e.g., catalyst bed 160) under hydroprocessing conditions sufficient to produce hydrotreated steam cracker naphtha that may be taken away via line 163. Hydroprocessing the steam cracker naphtha may convert one or more diolefins in the steam cracker naphtha to monoolefins, convert one or more olefins in the steam cracker naphtha to paraffins, convert one or more sulfur compounds in the steam cracker naphtha to hydrogen sulfide, and / or produce dimers.

[0078] The steam cracker naphtha recovered from the second separator 125 can be introduced into the hydroprocessor 155 via pipeline 131. Alternatively or additionally, the steam cracker naphtha can be treated before being introduced into the hydroprocessor 155. For example, the steam cracker naphtha can include water, steam and / or light hydrocarbons, such as C4 hydrocarbons. Therefore, the steam cracker naphtha in pipeline 131 can be introduced into one or more separation stages. In some examples, the steam cracker naphtha via pipeline 131 can be introduced into one or more separators of the third separation stage, which is configured to remove at least a portion of any water contained therein to produce a water-depleted steam cracker naphtha that can be introduced into the steam cracker naphtha hydroprocessor 155. In other examples, the water-depleted steam cracker naphtha can be introduced into one or more separators of the fourth separation stage to separate at least a portion of any C4 and lighter hydrocarbons that may be contained therein. Thus, in some examples, the steam cracker naphtha introduced into the steam cracker hydrotreater 155 via line 131 may be introduced directly from the second separation stage 125 , or may have undergone one or more additional separations or other treatments to produce the steam cracker naphtha that may be introduced into the steam cracker hydrotreater 155 .

[0079] In some examples, the steam cracker naphtha in line 131 can be divided or otherwise distributed into multiple parts, such as a first steam cracker naphtha and a second steam cracker naphtha having substantially the same composition. The first steam cracker naphtha can be subjected to hydrotreating conditions to produce a hydrotreated steam cracker naphtha. The second steam cracker naphtha can be recycled to the second separation stage 125, for example as a reflux. The options for separating the steam cracker naphtha into two or more parts, separating water from the steam cracker naphtha, separating C4 hydrocarbons from the steam cracker naphtha, and / or other treatments thereof can include those disclosed in U.S. Patent Application Publication No. 2016 / 0376511.

[0080] Catalyst bed 160 can be or include any catalyst capable of hydrotreating steam cracker naphtha. For example, the catalyst can be or include, but is not limited to, one or more elements selected from Groups 7-10 of the periodic table and optionally, one or more elements selected from Groups 4-6 of the periodic table. In some examples, the catalyst may contain ≥1 wt % of one or more of Pt, Pd, Ni, Co, Mo, and W, based on the weight of the catalyst. In some examples, the catalyst may include one or more refractory oxides, such as silica and / or alumina as a binder or carrier material. Conventional steam cracker naphtha catalysts can be used, but the methods and systems disclosed herein are not limited thereto.

[0081] The steam cracker naphtha hydroprocessing conditions in the hydroprocessor 155 may include a temperature of about 40° C., about 75° C., or about 100° C. to about 200° C., about 300° C., or about 375° C. The steam cracker naphtha hydroprocessing conditions in the hydroprocessor 155 may be conducted at an absolute pressure of about 600 kPa, about 1,000 kPa, or about 1,500 kPa to about 2,000 kPa, about 2,750 kPa, or about 4,000 kPa. The steam cracker naphtha hydroprocessing conditions in the hydroprocessor 155 may be conducted at an absolute pressure of about 1 h. -1 , about 3h -1 or about 5h -1 About 8 hours -1 , about 12h -1 or about 15h -1 In some examples, the steam cracker naphtha hydroprocessing conditions in the hydroprocessor 155 include a temperature of about 40° C. to about 370° C., an absolute pressure of about 600 kPa to about 4,000 kPa, and a pressure of about 1 h -1 About 15h -1Catalyst weight hourly space velocity (WHSV) of . Illustrative hydrotreaters and methods of operating the same that can be used to hydrotreat steam cracker naphtha may include those disclosed in U.S. Pat. No. 8,894,844; and U.S. Patent Application Nos.: 2007 / 0170098; and 2016 / 0376511.

[0082] Figure 2 A schematic diagram of another illustrative system 200 for steam cracking a hydrocarbon feed in line 101, separating a product comprising steam cracker naphtha therefrom via line 131, and hydrotreating the steam cracker naphtha in line 131 for at least a predetermined period of time is depicted according to one or more embodiments. System 200 can be similar to system 100. As shown, system 200 can include one or more separators of a third separation stage 205 that can separate tar products from the cooled steam cracker effluent in line 120 via line 135 before introducing the cooled steam cracker effluent into one or more separators of a "second separation stage" 225. More specifically, the cooled steam cracker effluent via line 120 can be introduced into the third separation stage 205, and overhead via line 207 and tar products via line 209 can be taken away therefrom. The overhead via line 207 may be introduced into a second separation stage 225 and process gas via line 129, steam cracker naphtha via line 131, steam cracker gas oil via line 133, and steam cracker quench oil via line 227 may be removed therefrom as described above with reference to Figure 1 In some examples, the overhead in line 207 can be further cooled by mixing, blending, combining, or otherwise contacting the overhead with steam cracker quench oil via line 228. In other examples, in addition to or in lieu of contacting the overhead in line 207, steam cracker quench oil via line 228, steam cracker gas oil via line 133, a portion of steam cracker naphtha via line 131, and / or one or more application fluids can be contacted with the overhead in line 207 to further cool the overhead.

[0083] The system 200 may also include a hydroprocessing unit 229, which may include two or more hydroprocessors (two are shown, 230, 240). Steam cracker naphtha via line 131 and molecular hydrogen via line 132 may be introduced into the first hydroprocessor 230. The steam cracker naphtha may be hydroprocessed in the presence of molecular hydrogen and a first catalyst (e.g., a first catalyst bed 235) to produce an intermediate or pretreated steam cracker naphtha that may be taken away via line 237. In some examples, the first hydroprocessor 230 may be operated under conditions that favor hydrogenation of dienes to monoolefins relative to hydrodesulfurization. Pretreated steam cracker naphtha via line 237 and molecular hydrogen via line 238 may be introduced into the second hydroprocessor 240. In some examples, in addition to or in lieu of introducing molecular hydrogen via line 238, molecular hydrogen may be cascaded from the first hydroprocessor 230 to the second hydroprocessor 240 along with pretreated steam cracker naphtha via line 237. The pretreated steam cracker naphtha may be hydroprocessed in the presence of molecular hydrogen and a second catalyst (e.g., second catalyst bed 245) to produce hydrotreated steam cracker naphtha that may be taken away via line 247. In some embodiments, the second hydroprocessor 240 may be operated under conditions that favor desulfurization of the hydrogenated product recovered from the first hydroprocessor 230 over hydrogenation of dienes to mono-olefins.

[0084] The steam cracker naphtha may be hydrotreated under first hydroprocessing conditions in the first hydroprocessor 230, and the pretreated steam cracker naphtha may be hydrotreated under second hydroprocessing conditions in the second hydroprocessor 240. The first hydroprocessing conditions may be the same as or different from the second hydroprocessing conditions.

[0085] In some examples, the first hydroprocessing conditions in the first hydroprocessor 230 may include a temperature of about 40° C., about 75° C., or about 100° C. to about 200° C., about 300° C., or about 375° C. The first hydroprocessing conditions in the first hydroprocessor 230 may be performed at an absolute pressure of about 600 kPa, about 1,000 kPa, or about 1,500 kPa to about 2,000 kPa, about 2,750 kPa, or about 4,000 kPa. The first hydroprocessing conditions in the first hydroprocessor 230 may be performed at about 1 hour. -1 , about 3h -1 or about 5h -1 About 8 hours -1 , about 12h -1 or about 15h -1 The reaction was carried out at a weight hourly space velocity (WHSV).

[0086] In some examples, the second hydroprocessing conditions in the second hydroprocessor 240 may include a temperature of about 40° C., about 75° C., or about 100° C. to about 200° C., about 300° C., or about 375° C. The first hydroprocessing conditions in the first hydroprocessor 230 may be performed at an absolute pressure of about 600 kPa, about 1,000 kPa, or about 1,500 kPa to about 2,000 kPa, about 2,750 kPa, or about 4,000 kPa. The first hydroprocessing conditions in the first hydroprocessor 230 may be performed at about 1 h -1 , about 3h -1 or about 5h -1 About 8 hours -1 , about 12h -1 or about 15h -1 The reaction was carried out at a weight hourly space velocity (WHSV).

[0087] The first hydroprocessing condition may be the same or different from the second hydroprocessing condition. In some instances, relative to the desulfurization of steam cracker naphtha, the first hydroprocessing condition may be sufficient to promote the hydrogenation of dienes to monoolefins, and relative to the hydrogenation of dienes, the second stage hydroprocessing condition may be sufficient to promote the desulfurization of pretreated steam cracker naphtha. In other instances, relative to the hydrogenation of dienes in steam cracker naphtha, the first hydroprocessing condition may be sufficient to promote the desulfurization of steam cracker naphtha, and relative to the desulfurization of pretreated steam cracker naphtha, the second stage hydroprocessing condition may be sufficient to promote the hydrogenation of dienes in pretreated steam cracker naphtha. In some instances, the temperature in the first hydroprocessor 230 may be lower than the temperature in the second hydroprocessor 240. It should be understood that hydrogenation and desulfurization can be carried out in the first hydroprocessor and the second hydroprocessor. In some examples, suitable hydroprocessors and / or hydroprocessing conditions for the first hydroprocessor and / or the second hydroprocessor may include those disclosed in U.S. Pat. Nos. 5,807,477; 5,679,241; 5,851,383; 8,163,167; 8,894,844; and U.S. Patent Application Nos.: 2007 / 0170098; and 2016 / 0376511.

[0088] The first hydroprocessor 230 and the second hydroprocessor 240 may include any type of hydroprocessor. Conventional hydroprocessors may be used, but the present invention is not limited thereto. In some examples, the first hydroprocessor 230 and the second hydroprocessor 240 may be or include fixed bed reactors, such as downflow fixed bed reactors, expanded bed reactors, reactive distillation columns, and / or other types of hydroprocessors.

[0089] Prior to steam cracking the hydrocarbon feed in line 101 in steam cracking systems 100 and 200, the amount of catalyst that needs to be disposed within hydroprocessing units 155, 229 to allow steam cracking systems 100 and 200 to operate for a predetermined period of time can be calculated or otherwise determined. As described above, it has been surprisingly and unexpectedly discovered that if the hydrocarbon feed in line 101 contains silicon material, the silicon material can render the catalyst (e.g., catalyst bed 160, 235, 245) disposed within hydroprocessing units 155, 229 ineffective before the silicon material renders another processing unit ineffective. Thus, the amount of catalyst that needs to be disposed within catalyst bed 160, 235, 245 to allow hydroprocessing units 155, 229 to operate for at least up to a predetermined period of time can be determined based at least in part on the amount of silicon material in the hydrocarbon feed in line 101. A sufficient amount of catalyst may be arranged in the catalyst beds 160, 235, 245 prior to the hydrocarbon feed in the steam cracking line 101 to enable the hydrotreating unit 155, 229 to hydrotreat the steam cracker naphtha for at least a predetermined period of time before the catalyst becomes insufficiently effective and requires shutting down the steam cracking system 100, 200 to regenerate and / or replace them.

[0090] Other aspects of the invention

[0091] In other aspects, the present invention relates to methods, systems and apparatus for performing hydrocarbon upgrading for a predetermined period of time. Hydrocarbon upgrading can include various processes for producing process effluents from one or more specified hydrocarbon feeds, such as thermal conversion processes such as pyrolysis (including, for example, steam cracking), catalytic conversion processes, etc. These and other aspects can include measuring a first amount of silicon (the total mass of silicon present in the hydrocarbon feed in the form of all silicon). A second amount of silicon can be determined by the first amount of silicon, wherein the second amount of silicon is equal to the total mass of silicon present in the form of all silicon in the naphtha boiling range stream separated from the process effluent. The second amount of silicon is predetermined by the first amount of silicon and optionally by the conditions used in hydrocarbon upgrading (e.g., unit configuration and / or process conditions). A sufficient amount of one or more catalysts can be introduced into a hydroprocessing unit so that the hydroprocessing unit hydroprocesses the naphtha boiling range stream for at least a predetermined period of time without the need to replace or reactivate one or more catalysts due to deactivation caused by silicon present in various forms in the naphtha boiling range stream. In these and other aspects, the naphtha boiling range stream can have an initial boiling point of about 30°F (1.1°C) to about 500°F (260°C), such as about 40°F (4.4°C) to about 450°F (232°C), or an atmospheric boiling point range of about the boiling point of mixed C5 hydrocarbons to 430°F (221°C).

[0092] The present invention also relates to systems, methods and devices for performing all or part of any of the pyrolysis, steam cracking, hydrocarbon upgrading and separation. For example, the upgrading or predetermined period of the hydrocarbon feed may include a steam cracker, a first separator, a second separator and a hydroprocessing unit. The steam cracker may be configured to combine and indirectly heat (in any order) an aqueous composition comprising water and / or steam and one or more of the hydrocarbon feeds shown to produce a steam cracking feed. The pyrolysis feed comprising at least a vapor portion of the steam cracking feed may be separated from the steam cracking feed, for example, in one or more first separators, for example, in one or more gas-liquid separators (e.g., one or more flash drums). The pyrolysis feed may be pyrolyzed in one or more radiant coils in a steam cracking furnace to produce a steam cracker effluent. The second separator may be configured to separate steam cracker naphtha and process gases that may contain ethylene and propylene from the steam cracker effluent. The hydroprocessing unit may include one or more catalysts arranged therein. The hydroprocessing unit can be configured to hydrotreat steam cracker naphtha in the presence of one or more catalysts and molecular hydrogen for at least a predetermined period of time without the need to replace or reactivate one or more catalysts due to catalyst deactivation caused by one or more forms of silicon present in the steam cracker naphtha. In some instances, the amount of one or more catalysts in the hydroprocessing unit can be determined according to the method. For example, the first amount of silicon material (and / or the amount of silicon in various forms) in the hydrocarbon feed can be measured. The first amount of silicon can be used to determine the second amount of silicon (and / or silicon material) in the steam cracker naphtha. The amount of one or more catalysts that should be arranged in the hydroprocessing unit can be determined at least in part based on the second amount of silicon. By utilizing process configuration and process conditions, such as by setting a predetermined fractionation point in the first and / or second separator, it is possible to achieve an improved accuracy in determining the second amount of silicon.

[0093] In these and other aspects, the hydrocarbon can be or include, but is not limited to, naphtha, gas oil, vacuum gas oil, waxy residue, atmospheric residue, crude oil, or a mixture thereof. The hydrocarbon feed is steam cracked under steam cracking conditions to produce a steam cracker effluent. The steam cracker naphtha is separated from the steam cracker effluent, wherein the steam cracker naphtha has a second amount of silicon equal to the total mass of silicon present in all silicon forms in the steam cracker naphtha. The silicon forms present in the steam cracker naphtha may include: ≤ 1 wt % C5-C6 silicones, about 10 wt % to about 50 wt % C7-C9 silicones, and about 60 wt % to about 90 wt % C 10+Silicones, wherein the weight percentages are based on the total weight of all silicon forms present in the steam cracker naphtha. The steam cracker naphtha can be hydrotreated in a first hydroprocessing unit for at least a predetermined period of time to produce a pretreated steam cracker naphtha. The pretreated steam cracker naphtha can be hydrotreated in a second hydroprocessing unit for at least a predetermined period of time to produce a hydrotreated steam cracker naphtha.

[0094] One or more first catalysts may be introduced into the first hydroprocessing unit in an amount sufficient to allow the first hydroprocessing unit to hydroprocess the steam cracker naphtha to be separated from the steam cracker effluent for at least a predetermined period without replacing or reactivating the one or more first catalysts due to catalyst deactivation caused by silicon present in one or more forms in the steam cracker naphtha. One or more second catalysts may be introduced into the second hydroprocessing unit in an amount sufficient to allow the second hydroprocessing unit to hydroprocess the pretreated steam cracker naphtha to be recovered from the first hydroprocessing unit for at least a predetermined period without replacing or reactivating the one or more second catalysts due to catalyst deactivation caused by silicon present in one or more forms in the pretreated steam cracker naphtha.

[0095] Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It is understood that ranges from any lower limit to any upper limit should be considered unless otherwise indicated. Certain lower limits, upper limits, and ranges appear in one or more claims below. All numerical values ​​are "about" or "approximately" indicative values, and take into account experimental errors and deviations that would be expected by a person of ordinary skill in the art.

[0096] Various terms have been defined above. If a term used in a claim is not defined above, it should be given the broadest definition persons in the relevant art have given that term as reflected in at least one printed publication or issued patent. In addition, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent this disclosure is not inconsistent with the present invention and for all jurisdictions in which such incorporation is permitted.

[0097] While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope of the invention is determined by the claims that follow.

Claims

1. A method for upgrading hydrocarbons for a predetermined period of time, comprising: measuring a first amount of silicon material in a hydrocarbon feed to be steam cracked in a steam cracker to produce a steam cracker effluent; and determining a second amount of silicon material to be present in a steam cracker naphtha to be separated from the steam cracker effluent based at least in part on the first amount of silicon material present in the hydrocarbon feed to be steam cracked, wherein the second amount of silicon material to be present in the steam cracker naphtha is from 5% to 75% of the first amount of silicon-containing material present in the hydrocarbon feed to be steam cracked; introducing a sufficient amount of one or more catalysts into the hydroprocessing unit to allow the hydroprocessing unit to hydroprocess the steam cracker naphtha to be separated from the steam cracker effluent for at least a predetermined period of time without requiring replacement or reactivation of the one or more catalysts due to catalyst deactivation caused by silicon materials present in the steam cracker naphtha; and heating a mixture comprising a hydrocarbon feed to be steam cracked and water, steam, or a mixture of water and steam to produce a heated mixture comprising steam and the hydrocarbon feed to be steam cracked; separating a vapor product and a liquid product from the heated mixture comprising steam and a hydrocarbon feed to be steam cracked; steam cracking the gas phase product to produce a steam cracker effluent; separating the steam cracker naphtha and a process gas containing ethylene and propylene from the steam cracker effluent; and The steam cracker naphtha is hydrotreated for at least the predetermined period of time.

2. The method of claim 1, wherein the one or more catalysts comprise a nickel sulfide catalyst, a nickel molybdenum catalyst, a cobalt molybdenum catalyst, or a mixture thereof.

3. The process of any one of claims 1 to 2, wherein the second amount of silicon material to be present in the steam cracker naphtha is from 15% to 52.5% of the first amount of silicon material present in the hydrocarbon feed to be steam cracked.

4. The process of any one of claims 1 to 2, wherein the first amount of silicon material present in the hydrocarbon feed to be steam cracked is from 0.1 ppm by weight to 25 ppm by weight, based on the weight of the hydrocarbon feed to be steam cracked, and wherein the second amount of silicon material to be present in the steam cracker naphtha is from 0.015 ppm by weight to 13.125 ppm by weight.

5. The process of any one of claims 1 to 2, wherein the silicon material in the steam cracker naphtha comprises ≤ 1 wt% C5-C6 silicones, 10 wt% to 50 wt% C7-C9 silicones and 60 wt% to 90 wt% C 10+ Silicones, based on the weight of silicon materials in the steam cracker naphtha.

6. The method of any one of claims 1 to 2, wherein: The hydroprocessing unit includes a first hydroprocessor and a second hydroprocessor, the first hydroprocessor including a first catalyst disposed therein, the second hydroprocessor including a second catalyst disposed therein, The first hydrotreater converts diolefins in the steam cracker naphtha into monoolefins to produce a first hydrotreated naphtha, the second hydrotreater converts olefins in the first hydrotreated naphtha into paraffins and sulfur compounds in the first hydrotreated naphtha into hydrogen sulfide to produce a second hydrotreated naphtha, and The amount of the first catalyst introduced into the first hydroprocessor is less than the amount of the second catalyst introduced into the second hydroprocessor.

7. The method of any one of claims 1 to 2, wherein: The hydroprocessing unit includes a first hydroprocessor and a second hydroprocessor, the first hydroprocessor including a first catalyst disposed therein, the second hydroprocessor including a second catalyst disposed therein, The first hydrotreater converts diolefins in the steam cracker naphtha into monoolefins to produce a first hydrotreated naphtha, the second hydrotreater converts olefins in the first hydrotreated naphtha into paraffins and sulfur compounds in the first hydrotreated naphtha into hydrogen sulfide to produce a second hydrotreated naphtha, and The amount of the first catalyst introduced into the first hydroprocessor is greater than the amount of the second catalyst introduced into the second hydroprocessor.

8. The process of any one of claims 1 to 2, wherein the hydrocarbon feed to be steam cracked comprises naphtha, gas oil, vacuum gas oil, waxy residue, atmospheric residue, crude oil or a mixture thereof.

9. The process of any one of claims 1 to 2, wherein the steam cracker naphtha comprises C5 to C 10+ A mixture of hydrocarbons and having an initial boiling point at atmospheric pressure of 25°C to 50°C and a final boiling point at atmospheric pressure of 220°C to 265°C as measured according to ASTM D2887-18.

10. A system for upgrading hydrocarbons for a predetermined period of time, comprising: a steam cracker configured to indirectly heat a mixture comprising steam and a hydrocarbon feed to produce a heated mixture, and steam cracking a gas phase product separated from the heated mixture to produce a steam cracker effluent; a first separator configured to separate a gas phase product and a liquid phase product from the heated mixture; a second separator configured to separate steam cracker naphtha and a process gas comprising ethylene and propylene from the steam cracker effluent; and A hydroprocessing unit comprising one or more catalysts disposed therein and configured to hydroprocess the steam cracker naphtha in the presence of the one or more catalysts and molecular hydrogen for at least a predetermined period of time without replacing or reactivating the one or more catalysts due to catalyst deactivation caused by silicon materials present in the steam cracker naphtha, wherein the amount of the one or more catalysts in the hydroprocessing unit is determined according to a method comprising the steps of: measuring a first amount of silicon material present in the hydrocarbon feed; determining a second amount of silicon material to be present in a steam cracker naphtha to be separated from the steam cracker effluent based at least in part on the first amount of silicon material present in the hydrocarbon feed; and An amount of the one or more catalysts that should be disposed in the hydroprocessing unit is determined based at least in part on the second amount of silicon material that will be present in a steam cracker naphtha that will be separated from the steam cracker effluent.

11. The system of claim 10, wherein the hydroprocessing unit comprises a first hydroprocessor comprising a first catalyst disposed therein and a second hydroprocessor comprising a second catalyst disposed therein, wherein the first hydroprocessor is configured to convert diolefins in the steam cracker naphtha to monoolefins in the presence of molecular hydrogen and the first catalyst to produce a first hydrotreated naphtha, and wherein the second hydroprocessor is configured to convert olefins in the first hydrotreated naphtha to paraffins and convert sulfur compounds to hydrogen sulfide in the presence of molecular hydrogen and the second catalyst to produce a second hydrotreated naphtha.

12. The system of claim 11, wherein the first catalyst comprises a sulfided nickel catalyst, and wherein the second catalyst comprises a nickel-molybdenum catalyst, a cobalt-molybdenum catalyst, or a mixture thereof.

13. The system of claim 10 or 11, further comprising an atomic emission detector, an x-ray fluorescence spectrometer, an inductively coupled plasma mass spectrometer, or a combination thereof configured to measure the first amount of silicon material present in the hydrocarbon feed to be steam cracked.

14. A method for upgrading hydrocarbons for a predetermined period of time, comprising: measuring a first amount of silicon material in a hydrocarbon feed to be steam cracked in a steam cracker to produce a steam cracker effluent, wherein the hydrocarbon feed comprises naphtha, gas oil, vacuum gas oil, waxy residue, atmospheric residue, crude oil, or a mixture thereof; and determining a second amount of silicon material to be present in a steam cracker naphtha to be separated from the steam cracker effluent based at least in part on the first amount of silicon material present in the hydrocarbon feed to be steam cracked, wherein the second amount of silicon material to be present in the steam cracker naphtha is from 5% to 75% of the first amount of silicon-containing material present in the hydrocarbon feed to be steam cracked; introducing a sufficient amount of one or more first catalysts into a first hydroprocessing unit to allow the first hydroprocessing unit to hydroprocess steam cracker naphtha to be separated from a steam cracker effluent for at least a predetermined period of time without requiring replacement or reactivation of the one or more first catalysts due to catalyst deactivation caused by silicon material present in the steam cracker naphtha; and introducing into the second hydroprocessing unit a sufficient amount of one or more second catalysts to allow the second hydroprocessing unit to hydroprocess the pretreated steam cracker naphtha to be recovered from the first hydroprocessing unit for at least a predetermined period of time without requiring replacement or reactivation of the one or more second catalysts due to catalyst deactivation caused by silicon materials present in the steam cracker naphtha, heating a mixture comprising a hydrocarbon feed to be steam cracked and water, steam, or a mixture of water and steam to produce a heated mixture comprising steam and the hydrocarbon feed to be steam cracked; separating a vapor product and a liquid product from the heated mixture comprising steam and a hydrocarbon feed to be steam cracked; and The gas phase product is steam cracked to produce a steam cracker effluent.

15. The method of claim 14, further comprising: The steam cracker naphtha and the process gas containing ethylene and propylene are separated from the steam cracker effluent, wherein the silicon material in the steam cracker naphtha comprises ≤ 1 wt % of C5-C6 silicones, 10 wt % to 50 wt % of C7-C9 silicones and 60 wt % to 90 wt % of C 10+ Silicones, based on the weight of silicon materials in the steam cracker naphtha; hydrotreating the steam cracker naphtha in the first hydrotreating unit for at least a predetermined period to produce the pretreated steam cracker naphtha; and The pretreated steam cracker naphtha is hydrotreated in the second hydroprocessing unit for at least a predetermined period of time to produce a hydrotreated steam cracker naphtha.

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