Hydrocarbon pyrolysis of nitrogen-containing feedstocks

Abstract

The present invention relates to hydrocarbon pyrolysis, such as steam cracking of a feed comprising hydrocarbons and a nitrogen-containing composition. The present invention also relates to apparatuses, systems, and devices useful in such pyrolysis, to products and byproducts of such pyrolysis, and to further processing of such products and coproducts, such as by polymerization.

Description

[0001] Cross-references to related applications

[0002] This application claims priority and benefit to U.S. Provisional Application No. 63 / 012,891, filed April 20, 2020, and EP Application No. 20184289.5, filed July 6, 2020, the disclosures of which are incorporated herein by reference in their entirety.

[0003] field

[0004] This invention relates to hydrocarbon pyrolysis, such as steam cracking of a feed comprising hydrocarbons and nitrogen-containing compositions. The invention also relates to apparatus, systems, methods, and devices for such pyrolysis, to the products and byproducts of such pyrolysis, and to further processing of such products and co-products, for example, by polymerization.

[0005] background

[0006] Various refining process streams can be generated by processing raw feedstocks such as crude oil. Many of these refining process streams are used as (and / or included in) feedstocks for hydrocarbon pyrolysis processes such as steam cracking. Steam cracking produces useful products such as light hydrocarbons from a feedstock containing hydrocarbons (“hydrocarbon feed”) and steam (“steam cracker feed”). In addition to molecular hydrocarbons, saturated hydrocarbons, and water, steam cracking also produces unsaturated products such as olefins, such as light (C) hydrocarbons including ethylene and propylene. 4- Olefins. Steam cracking also produces steam cracker tar, which can be used as fuel oil, pyrolysis gasoline, steam cracker gas oil, etc.

[0007] Some refining feedstocks used as hydrocarbon feedstocks in steam cracking processes are predominantly gaseous at 25°C and 1 bar (abs). Others are predominantly liquid under these conditions, such as refining feedstocks like naphtha, gas oil, and residual oil. Besides those obtainable from refining processes, predominantly liquid hydrocarbon feedstocks can also be obtained from other petrochemical facilities or from sources such as pipelines, transport containers, and storage containers. The advantage of obtaining such feedstocks from refining processes is that the refining processes used to produce hydrocarbon feedstocks typically remove various forms of nitrogen (e.g., N2 and other nitrogen-containing compositions such as nitrogen compounds) that are normally present in refining feedstocks. For example, nitrogen is present as ammonia in many refining product feedstocks.

[0008] Over time, demand for light olefins has grown faster than demand for refined products (such as fuels and lubricants), and this trend is expected to continue. As a result, the number and size of new or refurbished steam cracker plants have increased significantly compared to the number and size of new or refurbished refineries. Demand for predominantly liquid hydrocarbon feedstocks has increased interest in utilizing heavier liquid-phase feedstocks, such as those with an API gravity less than naphtha (“relatively heavy predominantly liquid hydrocarbon feedstocks,” also known as “dominant feedstocks”). While dominant feedstocks can include those that have already undergone pre-processing, such as certain gas oils, they can also include raw feedstocks such as crude oil, for example, crude oil containing medium and / or heavy hydrocarbons. For example, using dominant feedstocks containing raw feedstocks such as various crude oils will increase the supply of available liquid feedstocks and reduce the reliance of steam cracker plants on refining process streams to meet steam cracker feedstock needs. This, in turn, improves the plant's economic situation, for example, by reducing the cost of producing light hydrocarbons and by making relatively high-value refined feedstock available for other purposes.

[0009] The amount of nitrogen (in various forms, such as contaminants) in the feedstock can be an obstacle to its use in steam cracking. Using raw feedstocks containing nitrogen-containing compositions, such as crude oil, can lead to processing difficulties, for example, due to degradation of catalysts and other components in the steam cracker system by acetonitrile and / or other nitrogen-containing contaminants. For instance, nitrogen-containing compositions can poison catalysts such as acetylene converter catalysts, methylacetylene and propadiene (MAPD) ​​converter catalysts, pyrolysis gasoline hydrotreating catalysts, acidic catalysts such as those used in MTBE production, and other catalysts and / or catalyst beds. Steam cracker system components can also be corroded by ammonium salts and / or amine salts. The relatively high pH in steam cracker process streams generated by ammonia and / or amines can lead to oil-in-water problems. This, in turn, can cause equipment scaling and reduced catalyst performance. NOx formation in various process streams associated with steam cracking can undesirably affect refrigeration equipment and furnace emissions.

[0010] The presence of nitrogen-containing compositions in steam cracker feedstocks can be particularly challenging in the production of desired light olefin products. Product specifications for permissible levels of ammonia, amines, nitriles, and other nitrogen-containing compounds in ethylene and / or propylene streams are very stringent, for example, less than 1 part by weight per million parts by weight (“wppm”) of total nitrogen-containing compositions in ethylene and / or propylene grades used to produce polymer products such as polyethylene and polypropylene. Using feedstocks containing appropriate amounts of various forms of nitrogen can lead to difficulties in achieving light olefin streams with specified purity.

[0011] Conventional methods have been proposed for removing nitrogen-containing compositions from hydrocarbon feeds prior to steam cracking. One such method, feed hydrotreating, can remove some nitrogen-containing compositions; however, this method is costly and often results in undesirable conversion of feed hydrocarbon products into lower-value products such as methane. Another conventional method uses a flash separation vessel integrated with the steam cracker. This method removes and diverts at least some of the nitrogen-containing compositions from the hydrocarbon feed prior to steam cracking in the furnace's radiant section. However, further improvements are needed as the limits on the amount of nitrogen-containing compositions in the steam cracker products become increasingly stringent.

[0012] In particular, there is a need for improved systems, methods, and processes to manage nitrogen-containing compositions found in or generated from the steam cracking of dominant feedstocks such as crude oil. Effective management of nitrogen-containing compositions in hydrocarbon feedstocks for steam cracking is desired to: (i) meet increasingly stringent product specifications; (ii) reduce operating costs of steam cracking plants, such as those related to catalyst poisoning in the plant's recovery facilities; and / or (iii) reduce operating costs associated with corrosion caused by nitrogen-containing compositions such as ammonia.

[0013] Overview

[0014] Certain aspects of the present invention are disclosed, providing processes, methods, and apparatus for producing light olefins and mitigating or eliminating undesirable effects arising from the presence of various nitrogen-containing compositions in steam cracker feeds containing heavy hydrocarbons, as well as from other hydrocarbon streams and feeds.

[0015] This invention is based in part on the finding that, for a wide range of hydrocarbon feeds, particularly heavy feeds, the presence of various nitrogen-containing compositions in the feed results in nitrogen-containing compositions appearing in the streams separated from the steam cracker effluent. These separated streams have been observed to include nitrogen-containing compositions from the feed carried through the steam cracking process and into the steam cracker effluent, and / or nitrogen-containing compositions derived from, for example, those from the feed, converted from the form of nitrogen in the feed to the same or other forms of nitrogen in the steam cracking products.

[0016] Therefore, certain aspects of the invention relate to a method for steam cracking a hydrocarbon feed comprising hydrocarbons and a first nitrogen material. The hydrocarbon feed is cracked in a steam cracking furnace to produce a steam cracker effluent. Steam cracker tar and modified steam cracker effluent are separated from the steam cracker effluent. The method further includes separating (i) process gas comprising a second nitrogen material and (ii) pyrolysis gasoline comprising a third nitrogen material from the modified steam cracker effluent, wherein the second and third nitrogen materials are each a portion of the first nitrogen material and / or each derived from a portion of the first nitrogen material. A concentrated pyrolysis gasoline stream and separated water vapor containing at least a portion of the third nitrogen material are separated from the pyrolysis gasoline stream. A light effluent and a remaining water component are separated from the separated water vapor, wherein the light effluent contains at least a portion of the third nitrogen material. At least a portion of the third nitrogen material is removed from the light effluent to produce a purified light effluent.

[0017] In other respects, the present invention relates to a method for producing light olefins from a feed comprising heavy hydrocarbons and a first nitrogen material via steam cracking. The method includes separating steam cracker tar and modified steam cracker effluent from the steam cracker effluent, and separating from the modified steam cracker effluent at least (i) a process gas comprising a second nitrogen material and (ii) a pyrolytic gasoline comprising a third nitrogen material, wherein the second and third nitrogen materials are each a portion of the first nitrogen material and / or each derived from a portion of the first nitrogen material. The process gas is transferred through a compressor and condenser and into a separation drum to produce a compressed process gas comprising the second nitrogen material of the first portion of the process gas, a hydrocarbon-water mixture, and a washing fluid comprising the second nitrogen material of the second portion of the process gas. The compressed process gas is passed through an amine tower and an alkali tower to produce a purified process gas. Various usable products and co-products, such as polymer-grade light olefins, can be removed from the purified process gas.

[0018] In some aspects, the method includes introducing a hydrocarbon feed into a steam cracker to produce a steam cracker effluent, introducing the steam cracker effluent into a tar separation drum and separating steam cracker tar from the modified steam cracker effluent, and introducing the modified steam cracker effluent into a fractionator and a quench tower to produce at least a pyrolysis gasoline feed stream and process gas. The method also includes transferring the process gas through a compressor and condenser and into a tar drum to produce a treated light hydrocarbon feed stream, a hydrocarbon-water mixture, and a scrubbing fluid containing nitrogen contaminants, and passing the treated light hydrocarbon feed stream through an amine tower and an alkali tower to produce an alkali-treated feed stream containing light hydrocarbon products.

[0019] In other aspects, the present invention relates to systems and apparatuses for steam cracking of hydrocarbon feed comprising nitrogen-containing compositions, such as systems and apparatuses for performing any of the foregoing methods and processes. In some of these aspects, the steam cracker includes a convection line and a radiant line disposed within the convection line, a flash separation vessel fluidly connected to and downstream of the convection line and the radiant line, and a tar separation drum fluidly connected to and downstream of the radiant line. It also includes a fractionator fluidly connected to and downstream of the tar separation drum, such as a quench tower fluidly connected to and downstream of the fractionator, an oil-water separator fluidly connected to and downstream of the quench tower, and a water stripper fluidly connected to and downstream of the oil-water separator, wherein the water stripper has a top that is fluidly connected to and upstream of a condenser and vessel via a first line and fluidly connected to and upstream of the quench tower via a second line.

[0020] Brief description of the attached diagram

[0021] Therefore, a more specific description of the present disclosure, which has been briefly summarized above, can be obtained by referring to the embodiments, some of which are illustrated in the accompanying drawings. However, it should be noted that while the drawings illustrate typical embodiments of the present disclosure, these should not be considered as limiting the scope, as the present disclosure may acknowledge other effective embodiments.

[0022] Figure 1 A partial schematic diagram of a process system for producing light olefins, including hydrocarbon steam cracking and fractionation systems, described according to one or more aspects.

[0023] Figure 2 The description includes a system for separating and purifying pyrolysis gasoline and water, based on one or more aspects. Figure 1 Another schematic diagram of the process system described in the diagram.

[0024] Figure 3A The description includes a light hydrocarbon recovery system according to one or more aspects. Figure 1 Another schematic diagram of the process system described in the diagram.

[0025] Figure 3B Description based on one or more aspects Figure 3A A partial schematic diagram of the light hydrocarbon recovery system described in the text.

[0026] To facilitate understanding, the same reference numerals are used where possible to indicate common elements in the drawings. Elements and features of one embodiment can be beneficially incorporated into other embodiments without further description.

[0027] Detailed Explanation

[0028] In some aspects, the present invention relates to methods and apparatus for removing nitrogen-containing compositions, such as ammonia, from various locations in a steam cracker process. Nitrogen in such compositions can exist in various forms, such as as one or more nitrogen-containing compounds. Management of nitrogen-containing compositions at various locations in a steam cracking process improves process efficiency and cost-effectiveness, and provides products and co-products that meet increasingly stringent specifications.

[0029] Some aspects of the invention are made in a steam cracker plant comprising furnace facilities and recovery facilities. The furnace facilities typically include at least one steam cracker configured for pyrolysis feed. The steam cracker typically includes a convection section, a radiant section, and a gas-liquid separator typically integrated with the convection section. Various products and co-products are recovered from the steam cracker effluent in a recovery facility located downstream of the steam cracker facility. The recovery facility may include one or more containers (e.g., flash drums, such as tar separation drums) for separating steam cracker tar and modified steam cracker effluent from the steam cracker effluent. A primary fractionator is typically used to separate quench oil, gas oil, etc., from the modified steam cracker effluent. The vapor stream diverted from the top of the primary fractionator is typically quenched in at least one container (e.g., a quench tower) to recover naphtha boiling range compositions (e.g., pyrolysis gasoline), water, and process gases. Optionally, the primary fractionator may be combined with a quench tower. Additional product separation and recovery equipment is typically used, for example, for recovering ethylene and / or propylene. The invention is not limited to these aspects, and this description should not be construed as excluding other aspects of pyrolysis and product / coproduct recovery within the broader scope of the invention.

[0030] definition

[0031] "Hydrocarbon" refers to a class of compounds containing hydrogen atoms bonded to carbon. The term "C"... n "Hydrocarbon" refers to a hydrocarbon with n carbon atoms per molecule, where n is a positive integer. The term "C" is also used in this context. n+ "Hydrocarbon" means a hydrocarbon having at least n carbon atoms per molecule, where n is a positive integer. The term "C" is used in this context. n- "Hydrocarbon" means a hydrocarbon having no more than 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 (saturated and / or unsaturated) hydrocarbon compounds, including mixtures of hydrocarbon compounds with different n values. The term "unsaturated" or "unsaturated hydrocarbon" means a hydrocarbon containing at least one carbon atom directly bonded to another carbon atom via a double or triple bond. 2+Hydrocarbons. The term "olefin" means an unsaturated hydrocarbon containing at least one carbon atom directly bonded to another carbon atom via a double bond. In other words, an olefin is a compound containing at least one pair of carbon atoms, wherein the first and second carbon atoms of that pair are directly connected by a double bond. "Light olefin" means C 5- Alkenes.

[0032] "Heavy hydrocarbons" means a mixture containing hydrocarbons having an API specific gravity ranging from 5° to (but not limited to) 22°. "Medium hydrocarbons" means a mixture containing hydrocarbons having an API specific gravity ranging from 22° to 30°. "Relatively heavy" hydrocarbons have an API specific gravity less than that of naphtha. "Acidic" hydrocarbons are hydrocarbons based on the presence of ≥0.5% by weight of sulfur, such as crude oil, where the weight percentage covers one or more of all forms of sulfur in the hydrocarbon, such as elemental sulfur, sulfur bonded in compounds, sulfur bonded, entangled, or associated with aggregates such as asphaltenes and heavy tar.

[0033] Certain medium and / or heavy hydrocarbon feedstocks, such as certain primary hydrocarbon feedstocks, such as certain crude oils and crude oil mixtures, contain one or more of asphaltenes, asphaltenes precursors, and particulates. Asphaltenes are described in U.S. Patent No. 5,871,634, which is incorporated herein by reference in its entirety. Asphaltenes content can be determined using ASTM D6560-17. “Residue” means an oily mixture typically contained in or derived from crude oil having a standard boiling point range of ≥1050°F (566°C). Residue may include nonvolatile components, meaning a composition (organic and / or inorganic) having a standard boiling point range of ≥590°C. Certain nonvolatile components have a standard boiling point of ≥760°C. “Primary” feedstocks, such as primary hydrocarbon feedstocks, mean a feedstock that is primarily liquid and contains ≥25% by weight, for example ≥50% by weight, for example ≥75% by weight, or ≥90% by weight of crude oil that has not undergone prior desalting and / or prior reflux fractionation. "Crude oil" means a mixture of naturally occurring hydrocarbons of geological origin, wherein the mixture (i) contains ≥1% by weight, for example ≥5% by weight, or ≥10% by weight, residual oil and (ii) has an API gravity of ≤52°, for example ≤30°, for example ≤20°, or ≤10°, or <8°. Crude oil can be classified by API gravity; for example, heavy crude oil has an API gravity ranging from 5° to (but not limited to) 22°. Similarly, medium crude oil has an API gravity ranging from 22° to 30°.

[0034] "Predominantly liquid" means that ≥50% by weight, for example ≥75% by weight, or ≥90% by weight, of the composition is in the liquid phase. When ≥50% by weight, for example ≥75% by weight, or ≥90% by weight of the hydrocarbon feedstock is in the liquid phase at a temperature of 25°C and an absolute pressure of 1 bar, the hydrocarbon feedstock is predominantly liquid.

[0035] Standard (or "atmospheric pressure") boiling point and standard boiling point range can be measured by gas chromatographic distillation according to the methods described in ASTM D-6352-98 or D2887, as extended by extrapolation for materials ≥700°C. The term "T" 50 "T" means the temperature determined based on the boiling point distribution of a specific sample where 50% by weight has reached its boiling point. Similarly, "T" 90 “T” 95 "and "T 98 "Standard final boiling point" means that 90, 95, or 98 percent of a particular sample has reached its boiling point at that temperature. "Standard final boiling point" means that 99.5 percent of a particular sample has reached its boiling point at that temperature.

[0036] A "steam cracker" is a form of thermal cracking device having at least a convection section and a radiant section. The term "steam cracker" may be used interchangeably with "thermal cracking device," "pyrolysis furnace," "steam cracking furnace," or simply "furnace." While optional, steam may be added for various reasons, such as reducing hydrocarbon partial pressure, controlling residence time, and / or reducing coke formation. In some respects, the steam may be superheated, for example, in the convection section of the furnace, and / or the steam may be acidic or process steam. Heat to the furnace is provided by a burner located in the radiant section. The burner burns fuel and air, producing a flow of combustion effluent. The combustion effluent exits from the radiant section, flows through the convection section, and is then discharged from the steam cracking furnace. The convection section includes at least one tubular component ("convection coil"). Similarly, the radiant section also includes at least one tubular component ("radiant coil"). The outer surface of the radiant coil is heated at least by radiant heat from the burner. The outer surface of the convection coil is heated at least by the combustion effluent flowing through the convection section. The downstream end of the convection coil is in fluid communication with the upstream end of the radiant coil via a cross conduit. At least one gas-liquid separator may be integrated with the convection section, for example, in fluid communication with the convection coil and / or the cross conduit. A feed comprising hydrocarbons and various nitrogen-containing compositions (“hydrocarbon feed”) is introduced into the convection coil for preheating, typically after desalination. Steam is added to the preheated feed to produce a steam cracking feed. The steam may be superheated, for example in the convection section of the furnace, and / or the steam may be acidic or process steam for treatment. The predominantly gaseous pyrolysis feed and the predominantly liquid bottom feed stream may be separated from the preheated feed, for example, in a gas-liquid separator. The pyrolysis feed is introduced into the radiant coil, typically via a cross conduit and optionally after heating in one or more additional convection coils. The steam cracker effluent is diverted from the radiant coil outlet. To reduce excessive pyrolysis and other undesirable side reactions, the steam cracker effluent is rapidly cooled (“quenched”), for example, by indirect cooling in one or more heat exchangers (e.g., one or more transfer line exchangers) and / or by direct cooling by injecting a quench fluid (e.g., an oily quench fluid such as quench oil, liquid water, and steam, or one or more of these). The addition of steam at various points in the process is not detailed in each of the described embodiments. It should be further noted that any added steam may include untreated or treated process streams, and any added steam (whether treated or not) may be superheated. For example, superheating of the stream can occur when steam is generated from acidic water.

[0037] "Pyrolytic gasoline" means pyrolytic gasoline (also known as steam cracker naphtha "SCN"), which is (e.g., through one or more separations) a mixture derived from pyrolysis effluents (e.g., steam cracker effluents) and contains hydrocarbons having a standard boiling point conventionally referred to as the "naphtha boiling range," such as from an initial boiling point of about 30°F (1.1°C) to about 500°F (260°C), for example, from about 40°F (4.4°C) to about 450°F (232°C), or from about the boiling point of the mixed C5 hydrocarbons to about 430°F (221°C) at atmospheric pressure. Pyrolytic gasoline typically contains C 5+ Hydrocarbons such as C5-C 10+ Hydrocarbons have 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 instances, pyrolytic gasoline has 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 according to ASTM D2887-18.

[0038] "Steam cracker tar" (or "SCT") means a mixture comprising (i) aromatic compounds and optionally (ii) non-aromatic compounds and / or non-hydrocarbons, derived from hydrocarbon pyrolysis and having a T 90 ≥290°C, for example ≥500°C, for example ≥600°C or higher. In some aspects, SCT is separated from the quenched (or partially quenched) steam cracker stream in a separation vessel such as a tar separation drum, primary fractionator, etc. SCT may include hydrocarbon molecules (including mixtures and aggregates thereof) having (i) one or more aromatic components and (ii) about 50% by weight or more (e.g., 75% by weight or more, for example 90% by weight or more) of about C 15 Or larger molecular weight, based on the weight of SCT.

[0039] The nitrogen-containing compositions present in hydrocarbon feedstocks and products, co-products, byproducts, and other streams and compositions related to steam cracking may be in the form of or include one or more of the following: ammonia, ammonium or one or more ammonium cations or compounds, one or more amines, one or more nitriles, hydrogen cyanide, one or more NO. x Compound, NO x Compound ions and NO x Compound salts. The term "amine" means a compound and functional group containing a basic nitrogen atom with a lone pair (i.e., a non-shared pair or unbonded pair) of valence electrons, and encompasses all primary, secondary, and tertiary amines. Ammonium cations or compounds may be or include, for example, compounds having the chemical formula [R x NH (4-x) ] +One or more of those cations or compounds, wherein x is 0, 1, 2, 3, or 4, and each R is independently selected from alkyl, aryl (e.g., phenyl), or other organic groups. Exemplary ammonium cations or compounds may be or include one or more of, for example, ammonium, methylammonium, tetramethylammonium, ethylammonium, and salts of any of these. The term "amine" means a compound and functional group containing a basic nitrogen atom having a lone pair (i.e., a non-shared pair or unbonded pair) of valence electrons, and covers all primary, secondary, and tertiary amines. Amines may be or include, for example, those having the chemical formula R x NH (3-x) One or more of those, wherein x is 1, 2, or 3, and each R is independently selected from alkyl, aryl (e.g., phenyl), or other organic groups. Exemplary amines may be or include one or more of, for example, methylamine, dimethylamine, trimethylamine, ethylamine, diethylamine, triethylamine, methyl ethylamine (MEA), phenylamine, and any salts of these. Nitriles may be or include one or more of those having the chemical formula RCN, wherein R is alkyl, aryl (e.g., phenyl), or other organic groups. Exemplary nitrile may be or include one or more of acetonitrile, ethanenitrile, propionitrile, benzyl nitrile, and any derivatives of these. Exemplary nitrogen oxides (NOx) x The compound (or the ion of such a compound) may be or include one or more of, for example, nitric oxide (NO), nitrous oxide (N2O), dinitrogen dioxide (N2O2), nitrogen dioxide (NO2), nitrogen pentoxide (NO5), dinitrogen pentoxide (N2O5), and any of these ions.

[0040] Unless the context explicitly indicates otherwise, the amount of a particular nitrogen-containing compound in a particular feed stream, such as hydrocarbon feed, product, co-product, by-product, and other feed streams and compositions related to steam cracking, is the total mass of all nitrogen atoms relative to the total mass of the feed stream (including, for example, the mass of nitrogen atoms in aggregates, mixtures, compounds, complexes, etc.). This is typically expressed as a weight percentage of the feed stream. The amount of nitrogen in each nitrogen-containing composition is based on the weight of nitrogen atoms of the composition and is typically expressed as a weight percentage of the composition. Any suitable technique can be used to determine the amount of nitrogen atoms in a particular composition, including conventional techniques or reference to published tables and outlines. The term "nitrogen material" means one or more of the various forms of nitrogen-containing compositions, such as aggregates, mixtures, compounds, complexes, etc. The term nitrogen material covers both natural and synthetic forms of nitrogen. Those skilled in the art will appreciate that, depending on the context, the nitrogen material of a particular feed stream may mean one form of nitrogen, such as ammonia, or multiple forms of nitrogen. Unless explicitly stated otherwise in a specific context, the amount of nitrogen material in a process stream, such as the amount of nitrogen material present in the stream in various forms of nitrogen, means the total mass of all nitrogen forms present in the stream for a given mass, and is generally expressed as a weight percentage based on the weight of the stream. Any suitable method may be used to determine the amount of nitrogen material in a particular stream, including conventional methods. When a second stream is alleged to have less nitrogen material than a first stream by V%, (i) the first stream contains U% by weight of nitrogen material and (ii) U and V are real numbers ≥ 0, it means that the amount of nitrogen material in the second stream is U% by weight minus (V% multiplied by U%).

[0041] The term "non-volatile component" or "non-volatile matter" means a portion of a composition, such as a hydrocarbon composition, having a standard boiling point of about 590°C or greater as measured by ASTM D-6352-98 or D-2887. A non-volatile component can be further limited to a component having a boiling point of about 760°C or greater. The boiling point distribution of a hydrocarbon stream can be measured by gas chromatographic distillation according to the methods described in ASTM D-6352-98 or D2887, extended by extrapolation of materials above 700°C. Non-volatile components may include coke precursors, which are moderately heavy and / or reactive molecules, such as polycyclic aromatic compounds, which can be condensed in the gas phase and then form coke under the operating conditions encountered in one or more aspects of the invention.

[0042] In some respects, the hydrocarbon feed comprises (i) nitrogenous materials 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 description does not imply exclusion of other aspects within the broader scope of the invention, such as those in which the hydrocarbon feed is a medium hydrocarbon.

[0043] Hydrocarbon feed

[0044] Hydrocarbon feedstocks can include relatively high molecular weight hydrocarbons (heavy hydrocarbons), such as those that produce relatively large quantities of steam cracker naphtha (SCN), steam cracker gas oil (“SCGO”), and SCT during steam cracking. Heavy hydrocarbons typically include C42C4. 5+ Hydrocarbons, which may include SCGO and residue oil, gas oil, heating oil, jet fuel, fuel oil, diesel, kerosene, coking naphtha, SCN, catalytic cracked naphtha, hydrocracking oil, reformate, residual reformate, Fischer-Tropsch synthesis liquids, Fischer-Tropsch synthesis gases, distillates, crude oil, atmospheric tubular furnace bottoms, vacuum tubular furnace feed streams including bottoms, gas oil condensate, heavy non-straight-run hydrocarbons from refineries, vacuum gas oil, heavy gas oil, crude oil-contaminated naphtha, atmospheric residue, heavy residue, C4 / residue blends, naphtha residue blends, gas oil residue blends, low-sulfur waxy residue, atmospheric residue, and heavy residue are one or more of these. Heavy hydrocarbon feedstocks, such as crude oil, can be advantageously used. Such heavy hydrocarbon feedstocks may include, for example, economically advantageous heavy hydrocarbon feed streams containing non-volatile components and coke precursors, requiring minimal processing. The hydrocarbon feedstock may have a standard final boiling point of about 315°C or greater, such as about 400°C or greater, about 450°C or greater, or about 500°C or greater.

[0045] Hydrocarbon feeds may include one or more relatively low molecular weight hydrocarbons (light hydrocarbons). Light hydrocarbons typically consist of substantially saturated hydrocarbon molecules having fewer than five carbon atoms, such as ethane, propane, and mixtures thereof. While light hydrocarbon feeds generally produce greater yields of C2 unsaturated compounds (ethylene and acetylene) than feeds containing heavy hydrocarbons, and steam cracking of light hydrocarbons typically yields less SCN, SCGO, and SCT, the use of heavy hydrocarbons is increasingly attractive due to their lower cost and greater availability. The relative amounts of light hydrocarbons (typically in the gas phase) and heavy hydrocarbons (typically in the liquid phase) in a hydrocarbon feed can range from 100% by weight of light hydrocarbons to 100% by weight of heavy hydrocarbons, although typically about 1% by weight or more of heavy hydrocarbons are present in the hydrocarbon feed. For example, the hydrocarbon feed may include about 1% by weight or more of heavy hydrocarbons, based on the weight of the hydrocarbon feed, such as about 25% by weight or more, about 50% by weight or more, about 75% by weight or more, about 90% by weight or more, or about 99% by weight or more.

[0046] In addition to hydrocarbons, the hydrocarbon feed also contains nitrogenous materials. These nitrogenous materials may include one or more nitrogen-containing compositions. The amount of nitrogen as nitrogen atoms in the hydrocarbon feed (including nitrogen in all forms containing nitrogen) is typically in the range of about 20 parts by weight per million parts by weight (wppm), about 50 wppm, about 100 wppm, about 150 wppm, or about 200 wppm to about 300 wppm, about 500 wppm, about 600 wppm, about 800 wppm, about 1,000 wppm, about 1,150 wppm, about 1,300 wppm, about 1,500 wppm, or greater.

[0047] Desalination unit

[0048] To achieve a desired low concentration of sodium in the radiant section of a steam cracker, one or more desalters may be included to remove salts and particulate matter from the hydrocarbon feed prior to steam cracking. While acceptable levels of salts and / or particulate matter can vary with furnace design and operating conditions, adding at least one desalter may be desirable when the hydrocarbon feed contains ammonium salts, amine salts, alkali and / or alkaline earth salts (e.g., sodium chloride or magnesium carbonate) and / or other salts in amounts greater than several ppmw based on nitrogen atoms in all nitrogen-containing salts. Desalination removes salts and / or particulate matter to reduce catalyst poisoning, corrosion, scaling, and / or contamination problems. For example, by removing ammonium salts, amine salts, and / or other salts, corrosion problems in various downstream components and equipment throughout the process system can be reduced or eliminated.

[0049] In a typical desalination process, wash water (either fresh or deionized water) is mixed with heated hydrocarbon feed to create a water-in-oil emulsion, which in turn extracts salt, brine, and particulates from the oil. Wash water used to treat the hydrocarbon feed can originate from a variety of sources, and the water itself can be, for example, reused refinery water, recycled wastewater, purified water, purified wastewater, bottoms of acidic water strippers, top condensate, boiler feedwater, purified river water, or water from other sources or combinations thereof. The amount of salt in the water is expressed in parts by weight per thousand parts by weight (ppt) and is based on the weight of the water. Typically, wash water can range from fresh water (less than 0.5 ppt), brackish water (0.5–30 ppt), seawater (greater than 30 to 50 ppt) to brine (greater than 50 ppt). While deionized water can be used to facilitate the exchange of salts from crude oil to aqueous solutions, it is generally not required to desalinate crude oil feedstocks, although it can be mixed with recirculated water from the desalter to achieve specific ion or salt content in the water or specific ionic strength in the desalter emulsion prior to emulsification. The wash water rate can be approximately 5% to 7% of the total crude oil load, but can be higher or lower depending on the source and quality of the crude oil. Various water sources can be combined, determined by cost requirements, supply, water salt content, hydrocarbon feed salt content, and other specific factors of desalination conditions such as separator size and the desired degree of desalination.

[0050] Figure 1 This diagram illustrates a partial schematic of a pyrolysis process system 90 for producing light olefins from hydrocarbon feedstock 101. The pyrolysis process system 90 includes a steam cracking furnace and a recovery system 100 (e.g.,...). Figure 1 (As described in the text), pyrolysis gasoline and water separation and purification system 200 ( Figure 2 (as described in the text) and light hydrocarbon recovery system 300 ( Figure 3A and 3B (As described in the text).

[0051] like Figure 1 The text describes the generation of a salt emulsion by combining hydrocarbon feed 101 and wash water within a desalter 105 via line 103. Salt is separated from the hydrocarbon feed, resulting in (1) salt-rich water, transferred via line 107, and (2) desalted hydrocarbon feed, removed from the desalter 105 via line 109. During the separation phase of the desalting process, emulsion phases of varying compositions and thicknesses can form at the interface between the oil and water layers. Unrestricted growth in emulsion thickness can lead to carry-over of the desalted crude oil (causing equipment scaling) or carry-under of the water layer (interfering with the treatment of the salt-rich water). Suitable countermeasures include, for example, controlling emulsion formation and growth, removing the emulsion from the desalter, using additional processing steps, and dissociating the emulsion into its components (e.g., oil, water, and solids) to allow for reuse and / or disposal of one or more of the oil, water, and solids.

[0052] Methods for dissociating emulsions can include gravity or centrifugation. In gravity methods, the emulsion is allowed to settle in a separator, and the density difference between oil and water causes water to settle through and from the oil by gravity. In centrifugation methods, the stabilized emulsion is transferred from the desalting unit to a centrifuge (not shown), which separates the emulsion into separate water, oil, and solids. Gravity methods involve the use of time-intensive and therefore inefficient settling tanks and expensive methods for disposing of partially dissociated emulsions, while centrifugation involves building and operating large, expensive centrifuges. Another method for dissociating emulsions is to apply an electric field within the desalting unit. Applying an electric field can force water droplets to coalesce. Large, electro-coalesced droplets settle under gravity and penetrate the oil / large amount of dissociated water interface to immerse themselves in the large amount of dissociated aqueous phase at the bottom of the desalting unit.

[0053] Some hydrocarbon feedstocks contain contaminants, including contaminants that are and / or contain one or more nitrogen-containing compositions. Some hydrocarbon feedstock contaminants include asphaltenes, resins, and finely divided solid particles (e.g., those with an average size of less than 5 micrometers). Typically, at least some of these contaminants (e.g., ≥1%, e.g., ≥10%) may be present or associated with one or more nitrogen-containing compositions. Some of these contaminants, including those present or associated with one or more nitrogen-containing compositions, can act as natural surfactants, stabilizing the emulsion phase and causing the emulsion to remain in the desalting unit (the emulsion layer in the desalting unit is often referred to as the rag layer). Persistent emulsion problems are common in the processing of hydrocarbon feedstocks including crude oil due to high solids content. Hydrocarbon feedstocks with high solids content are generally not preferred because the presence of solids, typically with a particle size of less than 5 micrometers, can stabilize the emulsion and the oil / oil-water interface, leading to a gradual increase in the rag layer depth. The persistent presence of the rag layer may be attributed to the inability of electro-agglomerated droplets to disrupt the oil / oil-water interface. The crushing phase in a desalter typically contains high concentrations of oil, residual water, suspended solids, and salts (including those containing nitrogen), which in typical examples can be about 70% v / v water, 30% v / v oil, with 5,000-8,000 lb / 1000 barrels (PTB) (about 14 g / L to about 23 g / L) of solids and 200-400 PTB (about 570 mg / L to about 1,100 mg / L) of salt. The aqueous phase contains salts from the hydrocarbon feed, including nitrogen-containing salts.

[0054] One method to reduce the size and impact of persistent emulsion layers (fragmented layers) is the addition of demulsifiers. A suitable method for adding demulsifiers during desalination is described in U.S. Publication No. 2016 / 0208176, which is incorporated herein by reference. Demulsifiers commonly used in the treatment of hydrocarbon feedstocks including heavy hydrocarbons can be used in desalination processes, although the desalination process may not depend on the specific demulsifier chosen. Demulsifiers can be one or more of the following: polyethyleneimine, polyamine, succinate polyamine, polyol, ethoxylated alcohol sulfate, long-chain alcohol ethoxylate, long-chain alkyl sulfate, such as sodium lauryl sulfate, epoxy resin, and diepoxides (which may be ethoxylated and / or propoxylated). The addition of demulsifiers can be used to desalinate hydrocarbon feedstocks containing high levels of particulates or asphaltenes, which tend to stabilize fragmented layers.

[0055] The desalted oil phase forms the top layer, which is continuously removed via line 109 as the desalting hydrocarbon feed, and the large amount of dissociated water accumulates at the bottom of the desalter and is continuously removed via line 107 as salt-rich water. Figure 1 Salt-rich water can be sent for deionization and recycled or used in other processes, with or without further treatment.

[0056] Steam pyrolyzer

[0057] Steam pyrolysis is carried out in at least one steam pyrolysis furnace. The radiant section may include a combustion heater (e.g., a burner), and the flue gas from combustion using the combustion heater flows upward through the radiant section into the convection section and then exits as flue gas. Figure 1 As shown, the desalted hydrocarbon feed first enters the steam cracker in the convection section (upper part) via line 109 and is conveyed through convection line 113, where the desalted hydrocarbon feed is preheated by indirect exposure to flue gas in the convection section, thus producing a preheated feed. The preheated feed is mixed with dilution steam (not shown) to produce steam cracking feed. The steam cracking feed is conducted via line 115 to flash separation vessel 117 (also referred to as a separator or gas-liquid separator). In the separation vessel, the bottom material stream and the primarily gaseous pyrolysis feed are separated from the steam cracking feed. The separated bottom material stream is diverted via line 119. The pyrolysis feed is transferred via line 121 to steam cracker 111 and then through one or more radiant lines 123 in the radiant section (lower part) of steam cracker 111 for pyrolysis (cracking) to produce steam cracker effluent, which is transferred to line 125 for further processing.

[0058] Steam pyrolyzer convection section

[0059] The desalted hydrocarbon feed (via line 109) is first preheated in convection line 113 within the convection section of the steam cracker 111. Preheating of the desalted hydrocarbon feed may include indirect contact (within the convection section) of the feed into the hot flue gas from the furnace's radiant section, for example, by passing the desalted hydrocarbon feed through a row of heat exchange tubes (also referred to as convection coils) located within the convection section of the steam cracker. The preheated hydrocarbon feed may have a temperature of approximately 150°C to approximately 260°C, for example, approximately 160°C to approximately 230°C, or approximately 170°C to approximately 220°C.

[0060] The preheated hydrocarbon feed can be combined with steam (e.g., with dilution steam) and further preheated in a convection coil. At least one diluent containing steam is added to the desalted hydrocarbon feed to produce a steam cracking feed having a steam content ranging from about 10% to about 90% by weight, based on the weight of the steam cracking feed, wherein ≥90% by weight of the remaining steam cracking feed comprises preheated hydrocarbon feed. In some aspects, the steam-to-hydrocarbon weight ratio in the steam cracking feed can be from about 0.1 to about 1, for example from about 0.2 to about 0.6.

[0061] Flash separation vessel

[0062] The steam cracker 111 may have one or more flash separation vessels 117 integrated therewith, which are gas / liquid separation devices (sometimes referred to as flash tanks or flash drums) that can provide preheated feed for reforming. Such flash separation vessels are suitable when the preheated feed, based on the weight of the hydrocarbon composition of the convective product stream, includes about 0.1% by weight or more asphaltenes, for example, about 5% by weight or more. Preheating of the feed for reforming via gas / liquid separation can be accomplished using a flash separation vessel or other suitable device. Examples of suitable flash separation vessels include those disclosed in U.S. Patent Nos. 6,632,351; 7,090,765; 7,097,758; 7,138,047; 7,220,887; 7,235,705; 7,244,871; 7,247,765; 7,297,833; 7,311,746; 7,312,371; 7,351,872; 7,488,459 and 7,578,929 and 7,820,035, which are incorporated herein by reference.

[0063] When the flash separation vessel is integrated with the steam pyrolysis unit, at least a portion of the steam pyrolysis feed is in the gas phase. The steam pyrolysis feed (via line 115) is transferred to one or more flash separation vessels 117 and flashed to separate (i) a bottom feed stream containing at least a portion of high molecular weight molecules, such as asphaltenes, and (ii) a pyrolysis feed that is primarily in the gas phase. The bottom feed stream can be diverted from the flash separation vessel 117 as a byproduct via line 119. The separated bottom feed stream may include, for example, more than about 10% by weight of asphaltenes from the preheated feed. The pyrolysis feed is conducted to the steam pyrolysis unit 111 via line 121. Optionally, the pyrolysis feed is further indirectly heated in a separate convection coil (not shown), wherein the heated pyrolysis tar is conducted to a radiant coil 123 via a cross-connection (not shown).

[0064] Using a separation vessel 117 upstream of the radiative section increases the breadth of hydrocarbon feeds that can be used directly without pretreatment such as hydrotreating, fractionation (e.g., reflux fractionation). Such a flash separation vessel facilitates the treatment of hydrocarbon feed 101 containing about 50% by weight or more, for example, about 75% by weight or more, or about 90% by weight or more, heavy hydrocarbons (e.g., primary heavy hydrocarbons such as crude oil). Furthermore, adjusting the fractionation point of the flash separation vessel helps maintain the amount of certain contaminants in the pyrolysis feed (e.g., those containing one or more nitrogen-containing compositions) within desired limits. Depending on the selected separation conditions, such as the flow rate of the liquid in the convection section coil upstream of the separation vessel, the fractionation point temperature, pressure, etc., at least a portion (e.g., most or all) of any non-gas phase components in the steam cracking feed can be separated and diverted along with the bottom feed stream 119. Such non-gas phase components typically include salts and / or particulate matter, such as nitrogen-containing salts and / or nitrogen-containing particulate matter. Such non-gas phase components may also include at least a portion of any non-volatile matter present in the steam cracking feed, such as ≥10% by weight of any non-volatile matter present in the steam cracking feed (based on the total weight of non-volatile matter present in the steam cracking feed), for example ≥25% by weight, or ≥50% by weight, or ≥75% by weight, or ≥90% by weight. These features are particularly advantageous when <98% by weight of the hydrocarbons in the steam cracking feed are in the gas phase at the inlet of the flash separation vessel 117.

[0065] In some respects, sufficient liquid velocities are maintained in the convection coils upstream of the flash separator 117 to keep at least a portion of the non-gas phase components of the steam cracking feed (including any of these comprising one or more nitrogen-containing compositions) in suspension until they are removed along with the bottom feed stream 119. This has been observed to facilitate the separation of non-gas phase components, such as salts and / or particulates, such as nitrogen-containing salts and / or nitrogen-containing particulates, from the steam cracking feed in the flash separator 117. Typically, the amount of steam cracking feed separated and diverted as the bottom feed stream 119 will vary depending on the nature and composition of the hydrocarbon components of the steam cracking feed, the liquid velocities in the convection coils upstream of the flash separator, and the amount of non-gas phase components in the steam cracking feed. Maintaining the liquid velocities within a desired range can be achieved by adjusting the amount of liquid material in the steam cracking feed. When the hydrocarbon components of the steam cracking feed include viscous (typically heavier) liquid hydrocarbons, a smaller amount of gas phase material is required in the steam cracker feed to maintain the desired liquid velocities. Similarly, when the hydrocarbon component of the steam cracking feed comprises less viscous (typically lighter) liquid-phase hydrocarbons, a larger amount of gaseous material is required in the steam cracker feed to maintain the desired liquid velocity. Typically, maintaining about 2% (by weight) or more of the hydrocarbon component of the steam cracking feed in the liquid phase, such as about 5% or more, is sufficient to maintain adequate flow rates of salts and / or particulate matter in the suspension. At least a portion of the non-gase component of the steam cracking feed is in the liquid phase, and at least a portion of this liquid phase portion is diverted with the bottom feed stream 119. For example, ≥10% by weight, such as ≥25% by weight, or ≥50% by weight, or ≥75% by weight, or ≥90% by weight of the liquid phase component of the steam cracking feed (including liquid phase components comprising one or more nitrogen-containing compositions) may be diverted with the bottom feed stream 119 based on the weight of the steam cracking feed. Similarly, at least a portion of the non-gas phase components of the steam cracking feed is in a solid or semi-solid phase (collectively referred to as the "solid phase"), and at least a portion of this solid phase is diverted together with the bottom feed stream 119. For example, ≥10% by weight, such as ≥25% by weight, or ≥50% by weight, or ≥75% by weight, or ≥90% by weight of the solid phase components of the steam cracking feed (including solid phase components comprising one or more nitrogen-containing compositions) may be diverted together with the bottom feed stream 119 based on the weight of the steam cracking feed.

[0066] At least a portion of the nitrogen material in the steam cracking feed is transferred to the bottom stream of the separation vessel, where it is to be diverted via line 119. Because no nitrogen material in the pyrolysis feed is transferred to the bottom stream, the transferred nitrogen material will not be subjected to the pyrolysis conditions in the radiant coil 123, thus preventing the transferred nitrogen material from being converted into one or more of ammonia, amines, acetonitrile, etc. In other words, separating the pyrolysis feed from the steam cracking feed, which has fewer nitrogen-containing compositions (especially fewer nitrogen-containing compositions in the liquid and / or solid phases compared to the steam cracking feed), reduces the amount of ammonia, amines, and / or acetonitrile in the various process streams originating from the steam cracker effluent 125, for example, reducing the amount of acetonitrile in the C4 and / or pyrolysis gasoline streams.

[0067] For a wide range of hydrocarbon feeds containing medium and / or heavy hydrocarbons (e.g., primary hydrocarbons such as crude oil), it has been observed that selecting prescribed process conditions for the desalter (when in use), convection section, and gas-liquid separator results in ≤20% by weight of the nitrogen-containing composition (based on nitrogen atoms) of the hydrocarbon feed being converted to the total amount (based on nitrogen atoms) of ammonia, amines, and acetonitrile in the steam cracker effluent. In some instances, one or more of the following are achieved: the amount of ammonia in the steam cracker effluent is in the range of about 10 w ppm to about 100 w ppm, the amount of acetonitrile in the steam cracker effluent is in the range of about 10 w ppm to about 100 w ppm, and the amount of amine in the steam cracker effluent is in the range of about 10 w ppm to about 100 w ppm. Certain other nitrogen-containing compositions transferred from the steam cracker feed to the pyrolysis feed are not converted to ammonia, amines, and / or acetonitrile in the steam cracker effluent. Typically, these (or nitrogen-containing compositions derived therefrom) are removed from the process in the primary fractionator 141 and / or quench tower 147. When the pyrolysis feed includes a considerable amount of nitrogen-containing and oxygen-containing compositions, NOx compounds generated in the steam cracker effluent are typically removed downstream of the quench tower.

[0068] In some respects, the present invention relates to optimizing at least two conflicting parameters: (i) the amount of desired products produced by steam cracking, such as C 4- The amount of olefins, and (ii) the amount of nitrogenous material, such as nitrogen-containing salts, in the pyrolysis feed to the convection coil. It has been surprisingly found that for a wide range of hydrocarbon feeds containing heavy hydrocarbons and nitrogenous material, this optimization can be achieved by adjusting the following separator process conditions: the average temperature within the separator separation zone, the separator pressure, and the flow rate of the liquid in the convection coil upstream of the separation vessel. Adjusting these process conditions to shift a larger amount of steam cracker feed to the pyrolysis feed favors the first parameter. Adjusting these process conditions to shift a smaller amount of steam cracker feed to the pyrolysis feed favors the second parameter.

[0069] In these and other respects, the separation vessel 117 typically operates at an average temperature (in the separation zone) in the range of about 315°C to about 510°C and / or a pressure of about 275 kPa to about 1,400 kPa, for example, at a temperature of about 430°C to about 480°C and / or a pressure of about 700 kPa to about 760 kPa. Typically, the flow rate of the liquid phase material in the convection coils located upstream of the gas-liquid separator (i.e., those convection coils transporting the steam cracking feed) is adjusted to maintain about ≥2% (by weight) of the hydrocarbon component of the steam cracking feed in the liquid phase, for example, ≥3%, for example, ≥5%, or ≥10%, or ≥15% or greater.

[0070] Radiant section of steam pyrolyzer

[0071] The pyrolysis feed is transferred to the radiant section, where the pyrolysis tar is indirectly (in one or more radiant coils) exposed to combustion via a burner. For example... Figure 1 As shown, the pyrolysis feed is introduced into the radiation line 123 via line 121, wherein at least a portion of the pyrolysis feed undergoes hydrocarbon pyrolysis to produce steam cracker effluent, including C 2+ Olefins are transferred to line 125. The pyrolysis feed is typically in the gas phase at the inlet of the radiant coil, for example, about 90% by weight or more of the pyrolysis feed is in the gas phase, for example, about 95% by weight or more, or about 99% by weight or more.

[0072] Steam cracking conditions (pyrolysis conditions) may include exposing the pyrolysis feed in radiant line 123 to a temperature of about 400°C or greater, for example, about 400°C to about 1,100°C (measured at the outlet of the radiant line) and a pressure of about 10 kPa or greater, and a steam cracking residence time of about 0.01 seconds to 5 seconds. For example, steam cracking conditions may include one or more of the following: (i) a temperature of about 760°C or greater, for example, about 760°C to about 1,100°C, or about 790°C to about 880°C, or for a hydrocarbon feed containing light hydrocarbons, about 760°C to about 950°C; (ii) a pressure of about 50 kPa or greater, for example, 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. Steam cracking conditions may be sufficient to convert at least a portion of the hydrocarbon molecules in the pyrolysis feed into C23 by pyrolysis. 2+ Olefins.

[0073] Steam pyrolysis effluent typically includes unconverted pyrolysis feed and pyrolysis products. Pyrolysis products typically include C... 2+ Alkenes, molecular hydrogen, acetylene, aromatic hydrocarbons, saturated hydrocarbons, C 3+Dienes, and aldehydes, acidic gases such as H2S and / or CO2, and one or more thiols. Steam pyrolysis effluent can be classified as (i) gaseous products (i.e., products that are predominantly gaseous at 25°C and 1 bar absolute pressure) such as one or more of acetylene, ethylene, propylene, and butene, and (ii) products containing, for example, one or more C 5+ The gaseous products of hydrocarbons (i.e., at 25°C and a pressure of 1 bar, they will be mainly liquid products).

[0074] In some respects, steam cracker effluent contains molecular hydrogen, water (usually as steam), and C1-C. 10 Hydrocarbons, steam cracked gas oil (usually C 10 -C 17 Hydrocarbons) and SCT. In other aspects, the steam cracker effluent is molecular hydrogen, water (usually as steam), C1-C... 10 Hydrocarbons, SCGO (typically C40) with a standard boiling point range of about 174°C to about 216°C 10 -C 12 Hydrocarbon compositions), quenching oils having a standard boiling point range of about 216°C to about 302°C (typically C 12 -C 17 Hydrocarbons) and SCTs (typically C) with a standard boiling point range of about 302°C to about 600°C or greater. 17+ hydrocarbon).

[0075] Tar separation drum

[0076] Steam cracking processes typically produce slag carbon (SCT), relatively low-value, difficult-to-process compositions that can cause fouling under certain conditions. Generally, feedstocks containing a larger amount of higher-boiling-point hydrocarbons tend to produce a larger amount of SCT. One way to reduce SCT formation is to rapidly lower the steam cracker effluent temperature to a level where tar formation reactions are significantly slowed. This rapid reduction in steam cracker effluent temperature can be achieved in one or more stages using one or more methods and is referred to as quenching. Steam cracker effluent can be quenched by various methods, such as contact with cooled hydrocarbons (direct quenching), or alternatively, the steam cracker effluent can be rapidly cooled in a heat exchanger.

[0077] like Figure 1As shown, tar separation drum 127 receives steam pyrolysis effluent (via line 125) and separates SCT (which is transferred to line 129) and modified steam pyrolysis effluent (which is transferred to line 139) from the effluent. The steam pyrolysis effluent may undergo cooling or quenching before or during its introduction into the tar separation drum. Quenching may occur in one or more heat exchangers (not shown). Typically, the effluent exiting the first heat exchanger can be maintained at a temperature higher than the hydrocarbon dew point (temperature at which the first drop of liquid condenses) of the steam pyrolysis effluent. For a typical hydrocarbon feed containing heavy hydrocarbons under the indicated pyrolysis conditions, the hydrocarbon dew point of the steam pyrolysis effluent can be approximately 375°C to approximately 650°C, for example, approximately 480°C to approximately 600°C. Above the hydrocarbon dew point, the tendency for scaling is relatively low because gas-phase scaling is generally not severe, and there is little or no liquid that could cause scaling. The steam pyrolysis effluent can be further cooled by one or more of the following: (i) at least one additional heat exchanger, (ii) direct quenching before reaching the tar separation drum, and (iii) direct quenching within the tar separation drum.

[0078] In at least one embodiment, the steam pyrolysis effluent is directly quenched at one or more locations between the radiant line 123 and the tar separation drum 127. Quenching is accomplished by contacting the steam pyrolysis effluent with a liquid quench stream, instead of or supplemented by treatment with a transfer line heat exchanger. When used in conjunction with at least one transfer line heat exchanger, quench fluid may be introduced at a point downstream of the transfer line heat exchanger(s). Suitable quench fluids are typically derived from the liquid phase and at least partially vaporized upon contact with the steam pyrolysis effluent. Conventional quench fluids may be used, but the invention is not limited thereto. Typical quench fluids include one or more quench oils, such as those separated from the steam pyrolysis effluent or streams derived therefrom, for example, quench oil separated in one or more of the tar separation drum, clean fuel unit, and primary fractionator. Alternatively or additionally, the quench fluid may include pyrolytic fuel oil and / or water, which may be obtained from various suitable sources such as condensed dilution steam.

[0079] The temperature of the quenched steam pyrolyzer effluent entering the tar separation drum should be low enough to separate at least a portion of the SCT, for example, about 350°C or less, for example, in the range of about 200°C to about 350°C or about 240°C to about 320°C.

[0080] Conventional tar separation drums can be used, but the invention is not limited thereto. For example, tar separation drum 127 can be a simple empty container without distillation plates, trays, or stages. If desired, multiple separation drums can be connected in parallel so that individual drums can be taken out of service and cleaned during plant operation. The separated SCT typically has an initial boiling point of ≥150°C, for example ≥200°C, for example in the range of about 150°C to about 320°C.

[0081] In one or more embodiments, a wash stream is introduced into the tar separation drum 127 to reduce liquid-gas contact. When in use, the wash stream can be, for example, steam and / or substantially non-condensable hydrocarbons, such as those obtained from steam cracking, examples of which include cracked gas and tail gas. Surprisingly, molecular nitrogen has been found to be an effective wash stream and has not resulted in the addition of ammonia or NO to the modified steam cracker effluent. x The amount is significantly increased, even though the steam cracker effluent contains reactive hydrocarbons and oxygen-containing compounds and at least some NO is expected to be produced. x The tar separation drum is cleaned at the temperature at which it reacts with ammonia.

[0082] In some aspects, at least a portion of the steam pyrolysis effluent in the separation drum 127 is quenched, for example, by (directly or indirectly but usually directly) contacting the effluent with a cold (less than 350°C) quenching fluid. The cold quenching fluid can be generated by feeding the SCT stream taken from the bottom of the tar separation drum 127 and recirculating the cooled SCT stream to the pyrolysis tar drum 127 through a suitable heat exchanger (e.g., shell-and-tube exchanger, spiral wound exchanger, air fin exchanger, or dual-pipe exchanger). In at least one embodiment, the SCT is recirculated sufficiently to reduce the temperature at which the SCT is recovered from about 280°C to about 150°C. The rate of asphaltenes and tar formation in line 125 and tar separation drum 127 is significantly reduced to about 280°C or less compared to the higher temperature of the steam pyrolysis effluent when it leaves the radiant coil 123. In another embodiment, in the absence of or with a reduction in the addition of lower viscosity blended oil from external sources (which would otherwise be necessary without the aforementioned recirculation), recirculation is sufficient to reduce the viscosity of the separated SCT to a level sufficient to meet fuel oil viscosity requirements. In another embodiment, cooled SCT is introduced into the tar separation drum to provide an average temperature of approximately 175°C or less, for example, approximately 150°C or less, for the SCT within the tar separation drum. The quenching method can be adjusted to reduce or prevent asphaltenes formation. Up to approximately 70% by weight of asphaltenes formation can be prevented by quenching the steam cracker effluent in the tar separation drum 127 via line 125.

[0083] Clean fuel device

[0084] The SCT from the tar separator drum can be further processed in a clean fuel unit, such as one or more hydrotreating units. For example, the SCT, working fluid (optional), treatment gas including molecular hydrogen, and catalyst can be combined under hydrotreating conditions to produce a clean fuel product (modified SCT) having improved blending properties with other heavy hydrocarbons used to produce fuel oil blends, such as fuel oil and blending feedstock. The clean fuel unit can also remove at least a portion of the nitrogen-containing impurities from the SCT by hydrotreating. For at least this reason, the SCT and / or treatment gas may contain nitrogenous material that can be converted under hydrotreating conditions, typically producing ammonia during hydrotreating. At least a portion of any ammonia, for example in the hydrotreating processor effluent, can be removed from this method by amine and / or base treatment. Figure 1 As shown in some aspects, the clean fuel unit 131 receives the SCT 129 from the tar separation drum 127 and the lean amine feed stream via line 133. After hydrotreating and removal of sulfur and other impurities, the clean fuel unit 131 produces an amine-rich feed stream via line 135 and a clean fuel product feed stream via line 137.

[0085] SCT can be a T fraction with similar characteristics to vacuum gas oil and / or vacuum residue. 50 Highly aromatic products with high boiling points. SCTs are difficult to process using fixed-bed reactors because the various molecules within SCTs are highly reactive, leading to scaling and operational problems. Such processing difficulties can be further complicated by factors such as the high viscosity of SCTs, the presence of coke powder, and / or other properties related to the composition of SCTs.

[0086] It has been observed that using a working fluid in hydrotreated SCT reduces deposit formation and accumulation that would otherwise occur without a working fluid. Using a working fluid can provide a relatively lower viscosity and a lower atmospheric pressure (T) relative to the SCT. 50 and / or T 90 The cleaner fuel products, with their higher boiling point and increased hydrogen content, result in improved compatibility with fuel oils and fuel oil blends. Furthermore, hydrotreating SCT in the presence of a working fluid can produce fewer undesirable byproducts. It has also been found that hydrotreating SCT in the presence of a working fluid reduces the rate of increase in reactor pressure drop, which can improve cycle times during SCT processing. Conventional working fluids for SCT hydrotreating can be used, but the invention is not limited thereto. For example, the working fluid can be a portion of the separated and recycled clean fuel products. Suitable methods for using a working fluid for SCT hydrotreating and recycling a portion of the product stream are disclosed in U.S. Patent Nos. 9,777,227 and 9,809,756 and International Patent Application Publication No. WO 2013 / 033590, which are incorporated herein by reference.

[0087] During hydrotreating, the relative amounts of working fluid and SCT are typically about 20 wt% to about 95 wt% of SCT and about 5 wt% to about 80 wt% of working fluid, based on the total weight of working fluid and SCT. For example, the relative amounts of working fluid and SCT during hydrotreating may be, for example, about 20 wt% to about 90 wt% of SCT and about 10 wt% to about 80 wt% of working fluid, based on the total weight of SCT + working fluid conducted to the hydrotreating processor, for example, about 40 wt% to about 90 wt% of SCT and about 10 wt% to about 60 wt% of working fluid. In one embodiment, the working fluid:SCT weight ratio may be about 0.01 or greater, for example, about 0.05 to about 4, for example, about 0.1 to about 3, or about 0.3 to about 1.1.

[0088] The working fluid may include a solvent having a high content of aromatic compounds, and typically, the working fluid may also include a mixture of polycyclic compounds. The rings may be aromatic or non-aromatic and may contain various substituents and / or heteroatoms. For example, the working fluid may contain about 40% by weight or more, about 45% by weight or more, about 50% by weight or more, about 55% by weight or more, or about 60% by weight or more of aromatic and non-aromatic cyclic compounds, based on the total weight of the working fluid. The working fluid may have an ASTM D86 10% distillation point of about 60°C or more and a 90% distillation point of about 350°C or less. Optionally, the working fluid (which may be a solvent or a mixture of solvents) has an ASTM D86 10% distillation point of about 120°C or more, 140°C or more, or about 150°C or more and / or an ASTM D86 90% distillation point of about 300°C or less.

[0089] Hydrotreating is performed in the presence of hydrogen by (i) incorporating molecular hydrogen with the SCT and / or working fluid upstream of the hydrotreating process and / or (ii) conducting molecular hydrogen as a separate feedstock to the hydrotreating process. While relatively pure molecular hydrogen can be used for hydrotreating, it is generally desirable to use a “processing gas” containing sufficient molecular hydrogen for hydrotreating and optional other substances (e.g., light hydrocarbons such as methane) that generally do not adversely interfere with or affect the reaction or products. The processing gas may contain about 50% by volume or more of molecular hydrogen, for example, about 75% by volume or more, based on the total volume of processing gas conducted to the hydrotreating stage.

[0090] The amount of molecular hydrogen supplied to the hydrotreating stage can be approximately 300 SCF / B (standard cubic feet / barrel) (53S m 3 / m 3 - Approximately 5,000 SCF / B (890 S m) 3 / m3 Within the range of ), where B refers to the barrel of the hydrotreating stage pre-feed (e.g., tar feed stream plus working fluid). For example, the amount of molecular hydrogen can be approximately 1,000 SCF / B (approximately 178 S m). 3 / m 3 - Approximately 3,000 SCF / B (approximately 534 Sm) 3 / m 3 Those skilled in the art will appreciate that the amount of molecular hydrogen supplied to the hydrogenation process can depend on the composition and properties of the SCT. For example, when the SCT contains a large amount of C... 6+ When olefins, such as vinyl aromatic compounds, are present, a smaller amount of molecular hydrogen can be supplied. Similarly, when, for example, a tar stream contains a relatively large amount of sulfur-containing composition, a larger amount of molecular hydrogen can be supplied.

[0091] At least a portion of the hydrotreating of a clean fuel unit can be performed in the presence of one or more hydrotreating catalysts. Conventional hydrotreating catalysts, such as conventional homogeneous and / or heterogeneous catalysts, can be used, but the invention is not limited thereto. Suitable catalysts, for example, include those specified for use in SCT processing, residue processing, and / or heavy oil hydrotreating, such as one or more of the following: bulk (unsupported) catalysts, supported catalysts, and catalysts formed during hydrotreating, such as those formed during hydrotreating from precursors introduced upstream of the hydrotreating process. Examples of suitable hydrotreating catalysts include one or more of the following: KF860, available from Albemarle Catalysts Company LP, Houston, Texas; catalysts, for example 20, which can be obtained from the same source; The catalyst is available from Criterion Catalysts and Technologies, Houston, Texas, and may be one or more of DC-2618, DN-2630, DC-2635, and DN-3636. The catalyst, which may be obtained from the same source, such as one or more of DC-2532, DC-2534 and DN-3531; and the FCC pretreatment catalyst, such as DN3651 and / or DN3551, which may be obtained from the same source.

[0092] A wide range of hydrotreatment conditions can be used for SCT hydrotreatment, such as one or more of hydrocracking (including selective hydrocracking), hydrogenation, hydrotreatment, hydrodesulfurization, hydronitrogenation, hydrodemetallization, hydrodearomatization, hydroisomerization, and hydrodewaxing. Hydrotreatment of SCT can occur in one or more hydrotreatment stages in the presence of working fluid, process gas, and catalyst, said stages comprising one or more hydrotreatment vessels or areas located downstream of a steam cracker and optionally a tar cracker.

[0093] Catalytic hydrotreating conditions may include, for example, exposing the combined working fluid and SCT to temperatures close to molecular hydrogen and the hydrotreating catalyst, such as about 50°C–about 500°C, about 200°C–about 450°C, about 220°C–about 430°C, about 300°C–about 500°C, about 350°C–about 430°C, or about 350°C–about 420°C. The liquid hourly space velocity (LHSV) of the combined working fluid and SCT may be about 0.1 h⁻¹. -1 - Approximately 30 hours -1 or about 0.4h -1 approximately 25 hours -1 or about 0.5h -1 approximately 20 hours -1 For example, LHSV is approximately 5 hours. -1 Or larger, or about 10 hours -1 Or larger, or about 15 hours -1 Or higher. The partial pressure of molecular hydrogen during hydrotreating can be from about 0.1 MPa to about 8 MPa, or from about 1 MPa to about 7 MPa, or from about 2 MPa to about 6 MPa, or from about 3 MPa to about 5 MPa. In some embodiments, the partial pressure of molecular hydrogen is about 7 MPa or less, about 6 MPa or less, about 5 MPa or less, about 4 MPa or less, about 3 MPa or less, about 2.5 MPa or less, or about 2 MPa or less. Hydrotreating conditions can include pressures from about 1.5 mPa to about 13.5 mPa, or about 2 mPa to about 12 mPa, or about 2 mPa to about 10 mPa. Hydrotreating conditions can also include pressures of about 53 standard cubic meters per cubic meter (S m). 3 / m 3 - Approximately 445S m 3 / m 3 (300SCF / B to 2500SCF / B, where the denominator represents the molecular hydrogen consumption rate of the tar feed stream, such as the SCT bucket).

[0094] When SCT is hydrotreated under specified conditions, the clean fuel product exhibits improved properties compared to SCT and is more useful as a fuel oil and / or fuel oil blending component. For example, the clean fuel product typically displays improved viscosity, solubility, and insolubility values ​​relative to SCT, and lower sulfur content. The clean fuel product can be blended with other heavy hydrocarbons with little or no asphaltenes precipitation, and even without further treatment prior to blending.

[0095] If desired, the effluent from the hydrotreating processor in the clean fuel unit may include the separation of one or more streams from the clean fuel product, such as one or more overhead streams, middle fraction streams, and bottom streams. Separation equipment may be configured for this purpose, such as one or more of distillation columns, gas-liquid separators, splitters, fractionating columns, membranes, or absorbents. Describing the separation portions as overhead, middle, and bottom fractions does not exclude separation methods other than fractionation in a distillation column. In some aspects, one or more of the following streams may be separated from the clean fuel product: an overhead stream that may comprise about 0% to about 20% by weight of the clean fuel product, a middle fraction stream that may comprise about 20% to about 70% by weight of the clean fuel product, and a bottom stream that may comprise about 20% to about 70% by weight of the clean fuel product. One or more of these streams may be further treated, for example, to facilitate the removal of at least a portion of any remaining nitrogen-containing and / or sulfur-containing compositions that may be present. Typically, the bottom feedstream is at least hydrotreated (e.g., in one or more hydrotreatment reactors located in or downstream of a clean fuel unit) to convert at least a portion of any nitrogen-containing and / or sulfur-containing compositions in the feedstream. Hydrotreatment of the bottom feedstream is typically carried out under more stringent hydrotreatment conditions than those used to produce clean fuel products, without the addition of working fluids. In some aspects, such as those where relatively light fuel oils and / or naphtha are desired, bottom feedstream hydrotreatment may include hydrocracking. The hydrocracking catalyst may be selected from those that are nitrogen-tolerant, particularly ammonia-tolerant, for example, when the bottom feedstream contains a considerable amount of nitrogen-containing impurities. Alternatively or additionally, other techniques may be used to protect the hydrocracking catalyst from deactivation due to nitrogen-containing materials, such as one or more guard beds, adsorbents, pre-reactors, etc. Conventional techniques may be used, but the invention is not limited thereto.

[0096] At least a portion of the overhead fraction separated from the effluent of one or more of the indicated hydrotreatment reactors may include used and unused treatment gases, and may be recycled after removing at least a portion of any undesirable impurities such as H2S and NH3, for example, by contacting with lean amine and / or lean alkali solutions. The modified vapor product may be recycled as a portion of the treatment gas. Furthermore, molecular hydrogen may be added to the recycling section to maintain the level of hydrogen required for the SCT hydrotreatment process to enter the clean fuel unit. One advantage of this method is that it includes… Figure 3B In one aspect of the gas treatment method shown, the treated gas for recycling to one or more of the hydrotreatment reactors can be reformed in amine tower 305 and / or alkali tower 313, thereby eliminating the need for additional treated gas reforming facilities.

[0097] Primary fractionator

[0098] Back Figure 1 The modified steam cracker effluent is conducted via line 139 to separation stages, such as primary fractionator 141 and quench tower 147, for separating multiple product, by-product, and co-product streams. Product streams may include one or more of the following: (i) a primary fractionator bottom stream (typically a heavy hydrocarbon stream), which can be used in one or more pump cycles of the primary fractionator and / or as quench oil, and may be transferred to line 143; (ii) SCGO, carried away via line 145, the SCGO comprising approximately 90% by weight or greater C. 10 -C 17 Matter, based on having T 90 Materials in the temperature range of approximately 200°C to approximately 290°C (e.g., C) 10 -C 17 (iii) the weight of SCGO of hydrocarbons, and pyrolysis gasoline, which is transferred via pipeline 149 and contains C5-C 10 Hydrocarbons, and (iv) process gases, which are transferred via pipeline 151.

[0099] One or more of these streams may have the following properties: (i) the heavy hydrocarbon stream from pipeline 143 may contain C 12 -C 17 (ii) The quenched oil of hydrocarbons, and may have a standard boiling point range of about 216°C to about 302°C, and (ii) the SCGO in pipeline 145 may contain about 90% by weight or more of C. 10 -C 12 Hydrocarbons (based on the weight of SCGO) and may have T 90 Within the range of approximately 174°C to approximately 216°C, (iii) the pyrolysis gasoline of pipeline 149 may contain ≥90% by weight of C. 5+ Hydrocarbons, such as ≥90% by weight of C5-C 10(iv) Hydrocarbons, and process gases, which are transferred via line 151. When no tar drum is used upstream of the primary fractionator, the primary fractionator bottoms stream typically contains SCT. In these respects, the bottoms stream may contain ≥50% by weight of SCT, based on the weight of the bottoms stream, for example ≥75% by weight, for example ≥90% by weight, or ≥95% by weight. The SCT of the primary fractionator bottoms may have an initial boiling point of ≥290°C, for example ≥350°C, for example ≥400°C, or ≥450°C, or ≥500°C, or ≥550°C or even greater, and may contain hydrocarbon compounds with an average molecular weight of ≥212 g / mol.

[0100] Suitable primary fractionators and related equipment are described in U.S. Patent No. 8,083,931 and U.S. Publication No. 2016 / 0376511, which are incorporated herein by reference. Additional stages for heat removal (e.g., one or more transfer line heat exchangers) and tar removal (e.g., tar drums) may be located in or upstream of the primary fractionator. The overhead fraction from the primary fractionator may be transferred to a quench tower 147 via line 142. The quench tower and the primary fractionator may be combined in a single vessel (e.g., one above the other), eliminating the need for line 142, but this is not required.

[0101] The modified steam pyrolysis effluent is introduced into the primary fractionator 141 via line 139 to reduce contact with the gaseous material in the fractionator for more efficient fractionation. If the modified steam pyrolysis effluent is injected into the vapor space, it can be warmed, for example, as a result of mixing with a large amount of hot vapor present. This, in turn, can lead to undesirable absorption of certain light hydrocarbon compounds remaining in the vapor in the injected modified steam pyrolysis effluent. Alternatively, the modified steam pyrolysis effluent may be introduced near or preferably only below the liquid-gas interface into the bottom of the primary fractionator. Introducing the modified steam pyrolysis effluent below the gas-liquid interface ensures that the feed stream is cooled to or maintained at the desired temperature and reduces the absorption of the indicated light components. Additional baffles positioned above the gas-liquid interface can further reduce the contact between the modified steam pyrolysis effluent and the hot vapor.

[0102] The primary fractionator bottoms stream, primarily liquid, contains heavy hydrocarbons and can be removed from the primary fractionator via line 143. The primary fractionator bottoms stream can be combined with a primarily liquid hydrocarbon blend that has a lower viscosity and / or lower temperature than the primary fractionator bottoms stream. Adding the blend to the lower region of the primary fractionator can be used to control both the temperature (by cooling) and viscosity of the primary fractionator bottoms stream. Alternatively, the blend can be added to the primary fractionator bottoms stream at a location downstream of the primary fractionator. The primary fractionator bottoms stream can be pumped back to the primary fractionator and / or combined with the steam cracker effluent at one or more locations before the steam cracker effluent enters the tar separation drum (e.g., recirculated to line 125). The primary fractionator bottoms stream can also be recirculated to be combined with modified steam cracker effluent. In either case, the primary fractionator bottoms stream can provide liquid cooling during separations occurring in the tar separation drum or the primary fractionator.

[0103] Vapor-cracked gas oil can be condensed from the vapor phase within the primary fractionator 141. After the liquid phase material is separated and removed, the remaining vapor constitutes the vapor effluent from the upper region of the primary fractionator. The vapor effluent (the primary fractionator overhead fraction) can pass through line 142 and enter one or more quench towers 147, where the vapor is rapidly cooled (quenched) as it passes through water (vapor and / or liquid). Water can be obtained from one or more of various sources such as reused refined water, recycled wastewater, purified water, purified wastewater, bottom product of acid water stripper, overhead condensate, boiler feedwater, and other water sources. Water is often recycled to the quench tower from downstream oil-water separators, acid water separators, and pyrolysis gasoline stripper. Quench tower 147 condenses at least a portion of the pyrolysis gasoline present in the primary fractionator overhead fraction. The condensed pyrolysis gasoline and heated quench water are drawn from near the bottom of quench tower 147 as the pyrolysis gasoline feed stream.

[0104] Process gases (primarily gaseous light hydrocarbon feed streams) are collected from the top of quench tower 147 and discharged via line 151. When using specified pyrolysis feed and specified steam cracker conditions, the process gases may include, for example, about 10% by weight or more of C. 2+ Olefins, approximately 1% by weight or more of C 6+ Aromatic hydrocarbons, approximately 0.1% by weight or more dienes, saturated hydrocarbons, molecular hydrogen, acetylene, carbon dioxide, acetaldehyde, and C 1+ Thiols. Process gases can be directed to light hydrocarbon recovery systems to recover light (e.g., C2-C4) olefins, as well as other products, co-products, and byproducts.

[0105] In some embodiments, the modified steam cracker effluent is introduced via line 139 into the lower portion of primary fractionator 141 and quench tower 147 to produce at least a pyrolysis gasoline feed stream via line 149 and a process gas via line 151. In other embodiments, one or more fluids (e.g., light effluent or purified light effluent via line 237) may flow or otherwise transfer to line 142 and quench tower 147, as referenced. Figure 2 Further description.

[0106] oil-water separator

[0107] In one or more embodiments, the pyrolysis process system 90 includes a pyrolysis gasoline and water separation and purification system 200, such as Figure 2 As described in the text. Via pipeline 149 (and Figure 1 The pyrolysis gasoline stream from pipeline 149 can be separated from water in the downstream of oil-water separator 201, thereby forming separated pyrolysis gasoline via pipeline 203 and separated water containing nitrogenous contaminants via pipeline 217. The water from pipeline 202 (and...) Figure 3A The hydrocarbon-water mixture from pipeline 202 (described and discussed further below) can also be introduced into oil-water separator 201 and combined with and / or separated from the pyrolysis gasoline feed stream via pipeline 149 to form pyrolysis gasoline via pipeline 203 and separated water via pipeline 217.

[0108] The separated and concentrated pyrolysis gasoline (which typically also contains residual water) can be transferred via line 203 for further processing in pyrolysis gasoline stripping tower 205. The purified pyrolysis gasoline is drawn from the bottom portion of pyrolysis gasoline stripping tower 205 and may include C5-C. 10 Hydrocarbons are transferred via line 207 to gasoline hydrogenation unit 209 to produce various naphtha boiling point range products (e.g., gasoline) via line 211. Water and light hydrocarbons can be removed from the top or top of pyrolysis gasoline stripping tower 205, for example for recycling to the primary fractionator via line 213. Water can be removed from pyrolysis gasoline stripping tower 205 (not shown) and can be diverted to downstream processes and / or discharged.

[0109] Gasoline hydrogenation unit 209 typically includes one, two, three, or more stages for hydrotreating purified pyrolysis gasoline. Hydrotreating may include, for example, selective hydrotreating of gasoline dienes into olefins. Nitrogen-containing compounds, such as acetonitrile, can consume, poison, or otherwise reduce the activity of the catalysts contained in each stage of gasoline hydrogenation unit 209. Certain aspects of the invention avoid this problem by separating at least a portion of these contaminants from the pyrolysis gasoline from line 149 and diverting them along with separated water via line 217. Thus, the separated pyrolysis gasoline via line 203 and downstream products, such as purified pyrolysis gasoline via line 207, are effectively exposed to the catalyst of gasoline hydrogenation unit 209 without consumption, poisoning, and / or other reduction in catalyst activity.

[0110] Any water separated from pyrolysis gasoline in oil-water separator 201 or from concentrated pyrolysis gasoline in stripping tower 205 can be removed, for example, via lines 215 and / or 213 and recycled to a desalter, quench tower, or one or more steam generators. While such steam may be used at various locations within the pyrolysis process system 90, it is typically diverted to reduce the amount of nitrogenous compounds in the various feed streams of light hydrocarbon recovery system 300. The pH of the separated water removed from oil-water separator 201 is typically adjusted to either neutral or acidic to increase the amount of nitrogenous compounds, such as ammonia, in the solution. For example, the pH of the water separated from oil-water separator 201 can be adjusted to (i) about 7 or less, such as about 4, about 4.5, or about 5 to about 5.5, about 6, about 6.5, about 6.8, or less than 7, or (ii) about 7.2 or about 7.4 to about 7.5, about 7.6, about 7.8, or about 8.

[0111] In some respects, at least a portion of the separated water stream is transferred through line 216 for cleaning or degassing via a first cleaning fluid. The first cleaning fluid diverted via line 216 typically comprises a nitrogen-containing composition (e.g., ammonia, amines, etc.) and / or water. Alternatively or additionally, at least a portion of one or more of ammonia, amines, other nitrogen-containing compositions, hydrogen sulfide, and / or other non-gaseous impurities is removed from the separated water stream of line 217, for example, by stripping in an acidic water stripping tower 219.

[0112] The pH of the separated water in line 217 is typically adjusted to ≥7 or ≥8 to help drive the ammonia-ammonia balance toward ammonia. This can be done by adjusting the pH of the aqueous phase within or downstream of separator 201 (e.g., by adding one or more compatible pH control additives), adjusting the amount of separated water diverted via line 215, and adjusting the amount of first cleaning fluid removed via line 216. The separated water in line 217 typically has (or is adjusted to achieve) a pH of about 7.2, about 7.5, about 7.8, about 8, or about 8.2 to about 8.5, about 8.8, about 9, about 9.2, about 9.5, about 9.8, about 10, or greater. For example, the separated water containing nitrogen contaminants via pipeline 217 has a pH greater than 7 to about 10, about 7.2 to about 10, about 7.5 to about 10, about 7.8 to about 10, about 8 to about 10, greater than 8 to about 10, about 8.2 to about 10, about 8.5 to about 10, about 8.8 to about 10, about 9 to about 10, greater than 7 to about 9, about 7.2 to about 9, about 7.5 to about 9, about 7.8 to about 9, about 8 to about 9, greater than 8 to about 9, about 8.2 to about 9, about 8.5 to about 9, or about 8.8 to about 9.

[0113] Light hydrocarbons and H2S can be removed from the separated water in line 217, for example, in one or more acidic water strippers 219, and diverted as components of the light effluent via line 221. Conventional acidic water strippers can be used, but the invention is not limited thereto. The modified water removed from stripper 219 as a bottom feed stream can be diverted via line 223. At least a portion of the modified water can be directed to one or more dilution steam generators 225 to provide steam to steam cracking system 100 via line 227, for example, as dilution steam for generating steam cracking feed. The dilution steam generators can also generate a nitrogen-rich aqueous stream as a blowdown, which can be removed via line 229. This blowdown typically contains amines and may further contain other nitrogen-containing compositions. The advantages of the various aspects of the pyrolysis system 90 are that at least a portion of any amine present in the portion of the dilution steam used to generate the steam cracking feed line 227 can be converted into more easily removed ammonia in the steam cracking furnace 111 and removed at any one or more ammonia washing sites throughout the process system 90, such as in one or more washing streams of the light hydrocarbon recovery system 300.

[0114] In some respects, it is desirable to remove nitrogen-containing compositions, such as ammonia, and acidic gases, such as hydrogen sulfide, from the light effluent of line 221, for example, by diverting one or more of these to a location away from the process. For example, valve 239 may be maintained in a closed or partially closed position, which facilitates the condensation of at least a portion of the light effluent in one or more condensers 231. The condensers operate at temperatures of about 100°C to about 150°C, about 110°C to about 130°C, or about 115°C to about 120°C, for example, to condense at least a portion of any ammonia. The condensed effluent may be transferred to one or more containers, vessels, or drums 233, thereby being diverted away from the second cleaning fluid via line 235. The second cleaning fluid typically contains water and / or nitrogen-containing compositions, such as ammonia and / or amines. In these and other respects, the purified light effluent diverted via line 237 contains a smaller amount of nitrogenous composition, such as ammonia and / or amines (based on the weight of the purified light effluent), than the light effluent diverted via line 221 (based on the weight of the light effluent). Typically, the purified light effluent diverted via line 237 has about 5% less nitrogenous material than the light effluent diverted via line 221, for example, about 8%, or about 10% to about 15%, about 25%, or about 50%. With valve 239 closed, line 235 carries away about 5%, about 10%, or about 20% to about 30%, about 40%, or about 50% of the material from the separated water in line 217. When valve 239 is open or partially open, the portion of the light effluent diverted from line 221 that has not been condensed by condenser 231 can be transferred to quench tower 147 via lines 237 and 142.

[0115] Light effluents have a pH greater than 7 or greater to help drive the ammonia-ammonia balance favoring ammonia. Light effluents have a pH of about 7.2, about 7.5, about 7.8, about 8, or about 8.2 to about 8.5, about 8.8, about 9, about 9.2, about 9.5, about 9.8, about 10, or greater. For example, light effluents have a pH greater than 7 to about 10, about 7.2 to about 10, about 7.5 to about 10, about 7.8 to about 10, about 8 to about 10, greater than 8 to about 10, about 8.2 to about 10, about 8.5 to about 10, about 8.8 to about 10, about 9 to about 10, greater than 7 to about 9, about 7.2 to about 9, about 7.5 to about 9, about 7.8 to about 9, about 8 to about 9, greater than 8 to about 9, about 8.2 to about 9, about 8.5 to about 9, or about 8.8 to about 9. Excluding the condenser 231 and drum 233, the entire light effluent of line 221 can be conducted through valve 239 (open or partially open) and from there via lines 237 and 142 to quench tower 147.

[0116] Light hydrocarbon recovery system

[0117] Figure 3A and 3BThis illustration depicts certain aspects of the invention, using a pyrolysis process system such as system 90, which includes a light hydrocarbon recovery system 300. The invention is not limited to these aspects, and this description should not be construed as excluding other aspects of light hydrocarbon recovery within the broader scope of the invention. Process gas from the top of the quench tower is routed via line 151 (from...) Figure 1 The conduction is used for processing in one or more stages of the compressor handling system 310. The compressor handling system 310 includes one or more gas compressors 301, one or more condensers 302, and one or more separator drums 303. Although Figure 3A The invention is shown in the compressor-processing system 310, which comprises a gas compressor 301, a condenser 302, and a separator drum 303 connected in series in a fluid connection, but is not limited thereto. In other aspects, the compressor-processing system includes multiple (e.g., two, three, four, or more) or more fluidly connected compressor-condenser-separator drum assemblies, typically connected in series with each other (parallel connections and series-parallel connections are both within the scope of this invention).

[0118] Process gas from line 151 is compressed by gas compressor 301, condensed by condenser 302, and partially removed by separation drum 303, resulting in compressed process gas in line 304. A hydrocarbon-water mixture is separated from the compressed process gas (and / or from partially compressed process gas when separation drum 303 is located between compression stages) and diverted via line 202. Separation drums (one or more) 303 may be cleaning separation drums, i.e., separation drums that perform continuous, semi-continuous, periodic, and / or intermittent cleaning, and in those respects, a third cleaning fluid is diverted via line 306. The hydrocarbon-water mixture from line 202 may be transferred to oil-water separator 201, such as... Figure 2 As described in the description. The third cleaning fluid of line 306 is typically aqueous and comprises one or more nitrogen-containing compositions, such as ammonia and amines. Thus, the compressed process gas of line 304 contains less nitrogenous material (e.g., less ammonia and / or less amines) than the process gas of line 151. For example, the compressed process gas of line 304 may have about 5% less nitrogenous material (e.g., 5% less ammonia and / or 5% less amines) than the process gas of line 151, such as about 10%, or about 70%, or about 90%, for example in the range of about 20% to about 50%. Although the terms process gas, partially compressed process gas, compressed process gas, partially purified process gas, purified process gas, compressed purified process gas, modified process gas, etc., are used to describe the streams derived from the top of the quench tower in the stages of modification and purification, those skilled in the art will appreciate that referring to these streams as “gas” is a convenient designation but should not be construed as removing one or more liquid phase materials from these streams. Especially after compression, one or more, or at least one, portion of these material streams are typically in the liquid phase.

[0119] Although not required, the present invention is compatible with combining process gases (or one or more streams derived therefrom) with one or more streams from refining and / or petrochemical processes (e.g., processes for producing one or more of fuels, lubricants, and petrochemical products). This has been found to be effective, especially when the available refining stream contains molecular hydrogen and / or C2-C4 olefins. Excess capacity can occur in the process gas handling and separation stages, generated, for example, by initial over-design and / or during intervals of reduced process gas flow rates. This excess capacity can be utilized to (i) remove one or more desired products, such as C2–C4 olefins, from the indicated refining and / or petrochemical stream and (ii) optionally recycle any remaining portion of the refining and / or petrochemical stream (e.g., the portion containing saturated hydrocarbons) for cracking as feed to a steam cracker furnace and / or for combustion in a steam cracker furnace burner, burners in other furnaces, etc. Process gases (e.g., streams derived therefrom) may be combined with one or more refining and / or petrochemical process streams upstream and / or downstream of compressor(one or more) 301, for example, in one or more lines and / or containers between compressor(one or more) 301 and fractionator 317. For example, one or more of the indicated refining and / or petrochemical streams may be combined with one or more of process gases, partially compressed process gases, and compressed process gases after, before, and / or between one or more stages of compressor(one or more) 301, for example, in drum(one or more) 303.

[0120] like Figure 3A As described, compressed process gas is transferred via line 304 to amine tower 305 for at least partial purification. Amine tower 305 receives lean amine feed stream 307. The lean amine feed stream is typically aqueous and includes one or more of ethanolamine, diethanolamine, methyldiethanolamine, diisopropanolamine, diethylene glycolamine, and other amines. Contact between the compressed process gas and the lean amine transfers acidic gases such as hydrogen sulfide and carbon dioxide from the process gas to the lean amine, resulting in an amine-rich feed stream, which is discharged via line 309. For further removal of acidic gases, the partially purified process gas, after leaving amine tower 305, can be routed via line 311 to alkali tower 313, which may include an aqueous hydroxide solution, such as an aqueous sodium hydroxide solution. Alkali tower 313 transfers at least a portion of any remaining acidic gases (including hydrogen sulfide and carbon dioxide) and one or more of some weak acidic gases (e.g., thiols) from the partially purified process gas to the lean alkali feed stream. Figure 3A (Not shown in the image) to remove these. This produces purified process gas (discharged via line 315) and an alkali-rich feed stream ( Figure 3A (Not shown in the image).

[0121] exist Figure 3BThe diagram illustrates certain aspects of amine and alkali treatment. The invention is not limited to these aspects, and this description should not be construed as excluding aspects in which the order of treatment is altered or even reversed, or in which one of the treatments is omitted (e.g., when the hydrocarbon feed contains ≤1% by weight of sulfur-containing compounds). Figure 3B As shown, the inlet stream of amine tower 305 may include not only the compressed process gas from line 304 and the lean amine stream from line 307, but also an aqueous scrubbing stream (“water scrubbing”) via line 308. The outlet stream of amine tower 305 includes partially purified process gas from line 311, a fourth scrubbing fluid via line 312, and an amine-rich stream via line 314. The fourth scrubbing fluid is typically aqueous and may include one or more nitrogen-containing compositions such as ammonia and / or amines. Thus, the partially purified process gas from line 311 includes a smaller amount of nitrogenous material than the compressed process gas from line 304, for example, a smaller amount of ammonia, amines, and other nitrogen-containing compounds. The partially purified process gas in line 311 may have, for example, about 50% less nitrogen material (e.g., about 50% less ammonia and / or about 50% less amine) than the compressed process gas in line 304, such as about 60%, or about 90%, or about 95%, or in the range of about 70% to about 80%.

[0122] Surprisingly and unexpectedly, it was found that, due to the relatively high pH of the combined feed stream, the compressed process gas from line 304 entering amine tower 305 removed ammonia and / or other nitrogen contaminants.

[0123] Amine-rich feed is conveyed via line 314 to one or more amine regenerators 316 for regeneration, producing lean amine for recycling back into the process. The amine regenerator 316 has a lower portion and an upper portion; the lower portion is the part of the regenerator located at and below the second dashed line starting from the bottom. The upper portion is the part of the regenerator located at and above the third dashed line starting from the bottom. Those skilled in the art will appreciate... Figure 1 , 2The dashed lines shown in columns 3A and 3B represent internal column components such as trays, baffles, etc., used to facilitate the indicated separation. In some respects, the regenerator includes a heating system 318 connected to the lower section. An amine-rich stream is introduced via line 314 into the amine regenerator 316 to produce a lean amine stream (removed via line 307) and a byproduct stream (removed via line 320), the byproduct stream containing acidic and nitrogenous material, including acidic nitrogenous material. The lean amine stream from line 307 can be recycled to the amine column 305. The byproduct stream 320 can be cooled in one or more condensers 322 to produce a partially condensed byproduct stream, which is then diverted from the condenser via line 324. Before introducing the residue of the partially condensed byproduct stream into one or more containers or drums 328, at least a portion of the gaseous material (typically containing acidic vapors) in the partially condensed byproduct stream can be detached and removed via line 326. At least two streams can be removed from drum 328: drum effluent containing amine, which is returned to regenerator 316 via line 330 (e.g., as reflux), and a fifth cleaning fluid containing nitrogenous material (e.g., ammonia), which is diverted via line 332.

[0124] The inlet stream of alkali tower 313 includes at least a portion of partially purified process gas via line 311 and water scrubbing via line 334. The outlet stream of alkali tower 313 includes at least purified process gas via line 340 and a sixth scrubbing fluid via line 336. Alkali tower 313 also includes a circulation system 338 containing one or more pumps and inlet and outlet conduits. The scrubbing fluid via line 336 is typically aqueous and may include nitrogenous materials such as ammonia and / or amines. Thus, the purified process gas in line 340 includes a smaller amount of nitrogenous material than the partially purified process gas in line 311, for example, including smaller concentrations of ammonia, amines, and other nitrogen-containing compounds. The purified process gas in line 340 may have, for example, about 5% less nitrogen material (e.g., about 5% less ammonia and / or about 5% less amine) than the partially purified process gas in line 311, such as about 10%, or about 60%, or about 80%, or about 85%, or about 90%, or about 95%, or in the range of about 20% to about 40%.

[0125] The water wash in line 334 may include acid, for example, by introducing an acid equivalent per mole of an alkaline compound into the alkali tower, such as with the partially purified process gas. For example, based on the amount of alkaline nitrogen compound (e.g., ammonia and / or amine) contained in the partially purified process gas, an acid equivalent may be added to the water wash upstream of alkali tower 313. Exemplary acids may be or include one or more of hydrochloric acid, sulfuric acid, phosphoric acid, monosodium hydrogen phosphate (MSHP), acetic acid, and salts of one or more of these. The amount of acid added to the partially purified process gas can be adjusted to achieve a neutral or alkaline pH for the purified process gas in line 340.

[0126] In addition to alkaline treatment and amine treatment, the light hydrocarbon recovery system 300 may also include a compressor-processing system 350. For example... Figure 3B As described, the purified process gas can be conducted via line 340 to one or more stages of compressor-processing system 350. Compressor-processing system 350 typically includes one or more gas compressors 342, one or more condensers 344, and one or more separation drums 346. While each of the gas compressors 342, condensers 344, and separation drums 346 may be present in series fluidly connected within compressor-processing system 350, other aspects (not shown) include multiple (e.g., two, three, four, or more) groups of gas compressors 342, condensers 344, and separation drums 346 sequentially and fluidly connected to each other. Although these groups are typically connected in series, this is not necessary, and in some respects the connections are parallel or series-parallel.

[0127] Compressed purified process gas generated by compressor-processing system 350 is introduced via line 348 and passes through one, two, or more dryer-ammonia beds 352. The dryer-ammonia bed 352 may contain one, two, or more absorbent beds for removing ammonia and / or water to produce modified process gas, which is then discharged from the dryer-ammonia bed via line 315. The dryer-ammonia bed 352 can remove, for example, ammonia from the compressed purified process gas by, for example, from about 0.5 wppm to about 50 wppm, for example, from about 1 wppm to about 30 wppm, or from about 2 wppm to about 20 wppm. Thus, the modified process gas in line 315 has a smaller amount of ammonia and / or water than the compressed purified process gas in line 348. In one or more examples, the modified process gas may have ammonia content that is, for example, about 0.5% less than the compressed purified process gas, for example, about 1%, about 4%, or about 5%, or in the range of about 2% to about 3%.

[0128] In some instances, the dryer-ammonia bed 352 contains one, two, or more absorbent beds that have contaminant removal activity, such as the removal of water, amines, and NO. xOne or more of the following are active. While contaminant removal occurs in one, two, or more absorbent beds, other beds (one or more) can be at least partially regenerated offline (extracted from contaminant removal use). For this purpose, one or more lean regeneration gas streams are introduced via line 354 into the regenerator-dryer-ammonia bed 352. The lean regeneration gas removes contaminants, such as water, amines, and NO, from at least a portion of the regenerated beds. x One or more of the following are used to regenerate one or more desiccants or molecular sieve beds (e.g., UOP-type N-sieves) and / or absorbent beds within the ammonia bed 352 of the regenerator. A rich regeneration gas (filled with contaminants and typically containing at least some fluid and / or solids) is diverted from the regeneration bed (one or more) via line 356 for storage and / or further processing as a sixth cleaning gas. The sixth cleaning gas is typically aqueous and includes, for example, one or more nitrogenous materials such as ammonia and / or amines.

[0129] The modified process gas can be fed into one or more fractionation columns for separation and further purification of various hydrocarbon streams before further purification. (Continuing from...) Figure 3A A more detailed description includes certain aspects of separating various feed streams from line 315. As shown, initial separation is performed, wherein first and second feed streams are separated from the modified process gas in the first fractionator 317: the first feed stream contains molecular hydrogen, C1-C2 hydrocarbons, and some C 3+ Hydrocarbons and the second feed stream contain C 3+ Hydrocarbons. The invention is not limited to these aspects, and this description should not be construed as excluding other aspects within the broader scope of the invention, such as those wherein (i) the first feed stream comprises methane and molecular hydrogen, and the second feed stream comprises C... 2+ Hydrocarbons, or (ii) the first feed stream contains molecular hydrogen and C 3- Hydrocarbons and the second feed stream contain C 4+ Hydrocarbons.

[0130] like Figure 3A As shown, the first feed stream is removed from the separation stage (e.g., the first fractionator) 317 via line 319, and the second feed stream is removed via line 321. The C3 product feed stream (removed via line 325) and C... 4+ The product stream (removed via line 327) is separated from the second stream in the second fractionator 323. Optionally, the C-type of line 327 can be used. 4+ One or more water washes (typically liquid phase) of the product are used to reduce or eliminate nitrogen-containing compositions such as acetonitrile and / or other nitrogen-containing compounds. The C4 product stream (removed via line 331) and C... 5+ The hydrocarbon stream (removed via line 333) is distilled in the third fractionator 329 from the C of line 327. 4+ Product stream separation. Pipeline 207 C 5+Hydrocarbon feed stream (from the primary fractionator) and C from line 333 5+ The hydrocarbon feed streams are combined and can be passed through gasoline hydrogenation unit 209 to produce various naphtha boiling range products (e.g., one or more gasolines), which can be diverted from the process via line 335. Because the C4 product feed stream of line 331 may contain a considerable amount of acetonitrile, particularly when the hydrocarbon feed to the steam cracker includes heavy hydrocarbons such as crude oil, it can be advantageous to further treat this feed stream to remove at least a portion of the nitrogen-containing compounds. For example, the C4 product feed stream can be condensed (e.g., by indirect heat transfer to water) and then treated by contact with water. Doing so removes at least a portion of any acetonitrile in the C4 product feed stream of line 331, which can be diverted from the process, for example, for storage and / or further processing. Those skilled in the art will appreciate that removing acetonitrile from the C4 product feed stream can reduce the rate of catalyst deactivation during the process, for example, those catalysts that convert at least a portion of the isobutylene in the C4 product feed stream to MTBE and / or diisobutylene.

[0131] The C3 product stream from line 325 can be purified in a column that may include: (i) a methanol / COS bed 337, and then through line 339 to (ii) an arsine bed 341 to produce an arsine reduction stream, which is then passed through line 343 to (iii) a MAPD converter 345 for hydrogenation.

[0132] The arsine reduction stream of line 343 and / or the purified C3 stream of line 347 typically contain very small amounts (if present) of nitrogenous compositions. For example, these streams typically contain a total amount of ammonia and / or other nitrogenous compounds of ≤1 wppm, for example ≤1 wppm, or in the range of about 0.001 wppm to about 0.8 wppm.

[0133] Propylene (transferred via line 351) and propane (transferred via line 353) can be separated from purified C3 hydrocarbons in a fourth fractionator 349 (e.g., a C3 splitter). The recyclable separated propane can be used for further cracking and / or separation, for example, for storage and / or further processing. The propylene stream typically contains very small amounts (if present) of nitrogenous components. For example, this stream typically contains ammonia and / or other nitrogenous compounds in total amounts ≤1 wppm, for example, from about 0.001 wppm to about 0.8 wppm.

[0134] Returning to the first feed stream removed from fractionator 317, this stream can be transferred via line 319 for further compression in compressor 355. The compressed first feed stream can be routed via line 357 to a series of purification stages, which may include one or more of the following: (i) one or more beds 359 for removing sulfur-containing compositions (e.g., mercaptans and carbonyl sulfides removal beds), then via line 361 to (ii) one or more beds 363 for removing arsine, and then via line 365 to (iii) one or more converters 367 for selectively converting C2 acetylene to ethylene. The purified first feed stream is conducted via line 369 to demethanizer 371.

[0135] In demethanizer 371, the overhead feed stream containing methane and the bottom feed stream containing C2 hydrocarbons are separated from the purified first feed stream. The overhead feed stream is routed through line 373 to cryogenic chamber 375 to separate (i) methane (which is diverted via line 377) and (ii) molecular hydrogen (which is diverted via line 379) from the overhead feed stream. The methane in line 377 can be used, for example, as fuel gas and / or as feed and / or fuel for syngas production. At least a portion of the molecular hydrogen in line 379 can be recycled, for example, to a clean fuel unit for use in one or more hydrotreating units and / or (ii) for use in acetylene and MAPD converters 367 and / or 345. The bottom feed stream from the demethanizer can enter deethanizer 383 through line 381, which removes residual C2 hydrocarbons. 3+ and C 3+ Hydrocarbon recirculation occurs via line 385 to line 325 and from there to the methanol / COS bed 337. The overhead stream from fractionator 383, comprising C2 hydrocarbons, is routed via line 387 to C2 splitter 389 for separating ethylene (transferred via line 391) and ethane (transferred via line 393) from the overhead stream. Ethane can be recycled for further cracking and / or diversion, for example, for storage and / or further processing. The ethylene stream typically contains very small amounts (if present) of nitrogenous compounds. For example, this stream typically contains a total amount of ammonia and / or other nitrogenous compounds ≤1 wppm, for example, in the range of about 0.001 wppm to about 0.8 wppm.

[0136] Arsonia beds 341 and 363 each independently contain one or more materials for removing arsonia and / or other arsenic compounds, materials, or contaminants. For example, arsonia beds 341 and 363 each independently contain lead oxide, which is used to remove arsonia and / or other arsenic contaminants from the process stream upstream of converters containing catalyst beds, such as MAPD converter 345 and / or acetylene converter 367.

[0137] In general, it has been found that the removal of nitrogen-containing compositions from hydrocarbon feeds (which can be used for steam cracking) comprising heavy hydrocarbons can be accomplished by one or more of the following: (i) washing, separating and / or otherwise removing one or more nitrogen-containing compositions from the separated water components in lines downstream of an oil-water separator and upstream of an acid water stripper; (ii) washing, separating and / or otherwise removing one or more nitrogen-containing compositions from the overhead stripper of the light effluent in lines downstream of an acid water stripper and downstream of one or more condensers; and (iii) process gases (e.g., quench gases) collected from the overhead fraction of a quench tower. (iv) cleaning, separating and / or otherwise removing one or more nitrogen-containing compositions from the compressed or partially compressed process gas in one or more amine towers, one or more amine regenerators and / or one or more alkali towers, and / or (v) cleaning, separating and / or otherwise removing one or more nitrogen-containing compositions from the process gas through one or more dryer-ammonia bed to produce modified process gas.

[0138] Unless otherwise specified, the phrases “consistently composed of” and “consistently composed of” do not exclude the presence of other steps, elements or materials, whether or not specifically mentioned in this specification, provided that such steps, elements or materials do not affect the basis and novelty of this disclosure. In addition, they do not exclude impurities and variations that are generally associated with the elements and materials used.

[0139] For the sake of brevity and clarity, the following generalities apply. Each document described herein is incorporated by reference, including any test procedures, provided they do not contradict this document. While certain forms and aspects are illustrated and described, various changes may be made without departing from the spirit and scope of the invention. The term “comprising” is considered synonymous with the term “including.” Whenever a composition, element, or group of elements is preceded by the conjunction “comprising,” it should be understood that we also consider the same composition or group of elements preceded by the conjunctions “substantially constitutes…,” “consisting of…,” “selected from…,” or “is,” and vice versa. The scope of this description covers any lower limit together with any upper limit. Similarly, (i) a scope from any lower limit may be combined with any other lower limit, and (ii) a scope from any upper limit may be combined with any other upper limit. The scope of this description includes the respective points or individual values ​​between its endpoints. The scope includes the respective points or individual values ​​that can serve as their own lower or upper limits, combined with any other points or individual values ​​or any other lower or upper limits.

Claims

1. Steam pyrolysis methods, including: Provide hydrocarbon feedstock containing hydrocarbons and a first nitrogen material; Hydrocarbon feed is introduced into the steam cracker to produce steam cracker effluent; Separate steam pyrolysis tar and modified steam pyrolysis effluent from the steam pyrolysis effluent; Separating (i) process gas containing water and a second nitrogen material and (ii) pyrolytic gasoline containing a third nitrogen material from the modified steam cracker effluent, wherein the separation of pyrolytic gasoline and process gas is carried out in at least one primary fractionator and in at least one quench tower downstream of at least one primary fractionator, wherein the second and third nitrogen materials are each a portion of the first nitrogen material and / or each derived from a portion of the first nitrogen material. Compressing process gas to produce compressed process gas; A hydrocarbon-water mixture and a cleaning fluid are separated from a compressed process gas, wherein the compressed process gas contains a first portion of a second nitrogen material and the cleaning fluid contains a second portion of a second nitrogen material; The hydrocarbon-water mixture is combined with pyrolytic gasoline separated from the effluent of the modified steam cracker to produce a combined mixture; Separate concentrated pyrolysis gasoline and a separated water component containing at least a portion of a third nitrogen material from the combined mixture; The light effluent and the remaining water component are separated from the separated water component, wherein the light effluent contains at least a portion of the third nitrogen material; Separate at least a portion of the third nitrogen material from the light effluent to produce a purified light effluent; The third nitrogen material for separating at least a portion of the light effluent includes: Nitrogenous material that condenses at least a portion of the light effluent; and Transfer at least a portion of the condensed nitrogen material to at least one container; and At least a portion of the light effluent or at least a portion of the purified light effluent is transferred to a quench tower.

2. The method according to claim 1, wherein condensation occurs at a temperature in the range of 100°C to 150°C.

3. The method of claim 2, wherein condensation occurs at a temperature in the range of 120°C to 130°C.

4. The method according to any one of claims 1-3, wherein (i) concentrated pyrolysis gasoline and separated water components are separated in an oil-water separator, (ii) light effluent and remaining water components are separated in a water stripper, (iii) the separated water components contain at least a portion of a third nitrogen material; and further comprising removing at least a portion of the third nitrogen material from the separated water components at a location downstream of the oil-water separator and upstream of the water stripper.

5. The method according to any one of claims 1-3, wherein the compressed process gas is passed through a condenser and into a separation drum to separate the hydrocarbon-water mixture and the cleaning fluid.

6. The method according to claim 5, further comprising transferring at least a first portion of the compressed process gas as a second nitrogen material to an amine solution in an amine tower to generate a partially purified process gas.

7. The method of claim 6 further comprises circulating the amine solution between the amine tower and the amine regenerator.

8. The method of claim 7, further comprising removing at least a portion of a second nitrogen material from the amine solution in an amine regenerator.

9. The method according to claim 7 or claim 8, further comprising removing at least a portion of the second nitrogen material from the partially purified process gas to generate purified process gas.

10. The method of claim 9, wherein at least a portion of the partially purified process gas is transferred using water washing within the alkali tower.

11. The method of claim 10, wherein the water washing comprises acid.

12. The method according to claim 9 further includes compressed and purified process gas.

13. The method of claim 12, further comprising passing the compressed purified process gas through a dryer-ammonia bed to transfer at least a portion of any remaining second nitrogen material in the purified process gas to the dryer-ammonia bed to produce a modified process gas.

14. The method of claim 13, further comprising removing at least a portion of the transferred second nitrogen material from the dryer-ammonia bed.

15. The method of claim 13 or claim 14, further comprising (i) separating olefins from the purified process gas and (ii) polymerizing at least a portion of the separated olefins.

16. The method of claim 13, wherein the dryer-ammonia bed comprises a device for removing water, ammonia, amines, and NO. x One or more active absorbent beds.

17. The method according to any one of claims 1-3, wherein the third nitrogen material in the portion of the light effluent comprises one or more of the following: ammonia, ammonium, amine, nitrile, hydrogen cyanide, NO. x Compounds, and NO x Ions and / or salts of compounds.

18. The method of claim 1, wherein introducing the hydrocarbon feed into the steam pyrolyzer comprises preheating the hydrocarbon feed in the convection section of the steam pyrolyzer to produce a preheated hydrocarbon feed and introducing at least a portion of the preheated hydrocarbon feed into the radiative section of the steam pyrolyzer to produce a steam pyrolyzer effluent; the method further comprises: The remaining water component is introduced into one or more dilution steam generators to produce dilution steam, wherein the remaining water component contains amines; At least a portion of the dilution steam is combined with a preheated hydrocarbon feed to produce a steam cracking feed, wherein the steam cracking feed is introduced into the radiant section of the steam cracker, and wherein at least a portion of the amines in the steam cracker feed is converted into ammonia within the radiant section of the steam cracker.

19. A method for producing light olefins from a feed comprising heavy hydrocarbons and a first nitrogen material, comprising: Hydrocarbon feed is introduced into the steam cracker to produce steam cracker effluent; Separate steam pyrolysis tar and modified steam pyrolysis effluent from the steam pyrolysis effluent; At least (i) process gas containing water and a second nitrogen material and (ii) pyrolytic gasoline containing a third nitrogen material are separated from the effluent of the modified steam cracker, wherein the separation of the pyrolytic gasoline and process gas is carried out in at least one primary fractionator and in at least one quench tower downstream of at least one primary fractionator, wherein the second and third nitrogen materials are each a portion of the first nitrogen material and / or each is derived from a portion of the first nitrogen material. The process gas is transferred through a compressor and condenser and enters a separation drum to produce a compressed process gas containing a second nitrogen material containing the first part of the process gas, a hydrocarbon-water mixture, and a cleaning fluid containing the second nitrogen material containing the second part of the process gas; Compressed process gas is passed through amine and alkali towers to produce purified process gas; Compressed and purified process gases; Transfer at least a portion of any second nitrogen material from the compressed purified process gas to at least one dryer-ammonia bed to produce a modified process gas; At least a portion of the transferred second nitrogen material is removed from the dryer-ammonia bed; The hydrocarbon-water mixture is combined with pyrolytic gasoline separated from the effluent of the modified steam cracker to produce a combined mixture; Separate concentrated pyrolysis gasoline and a separated water component containing at least a portion of a third nitrogen material from the combined mixture; The light effluent and the remaining water component are separated from the separated water component, wherein the light effluent contains at least a portion of the third nitrogen material; Separate at least a portion of the third nitrogen material from the light effluent to produce a purified light effluent; The third nitrogen material for separating at least a portion of the light effluent includes: Nitrogenous material that condenses at least a portion of the light effluent; and Transfer at least a portion of the condensed nitrogen material to at least one container; and At least a portion of the light effluent or at least a portion of the purified light effluent is transferred to a quench tower.

20. The method of claim 19, further comprising a second nitrogen material for removing at least a portion of the compressed process gas in an amine tower, an alkali tower, or a combination thereof.

21. The method of claim 20, further comprising: An amine solution is circulated between the amine tower and the amine regenerator, wherein the amine solution contains at least a portion of a second nitrogen material removed from the compressed process gas; and A second nitrogen material from which at least a portion of the amine solution is removed by the amine regenerator.

22. The method according to any one of claims 19-21, wherein the second nitrogen material comprises ammonia and / or ammonium.

23. The method according to any one of claims 19-21, wherein the second nitrogen material comprises one or more of the following: amine; nitrile; hydrogen cyanide; NO. x Compound;NO x Ions of the compound and NO x Salts of compounds.

24. The method of claim 19, wherein removing at least a portion of the transferred second nitrogen material from the dryer-ammonia bed comprises introducing one or more lean regeneration gas streams into the dryer-ammonia bed and contacting the dryer-ammonia bed with the lean regeneration gas streams to produce a regenerated dryer-ammonia bed and a rich regeneration gas containing at least a portion of the transferred second nitrogen material, and wherein the rich regeneration gas is removed from the dryer-ammonia bed.

25. Heavy hydrocarbon conversion methods, including: The feed is introduced into the steam pyrolyzer to produce steam pyrolyzer effluent, wherein the feed contains heavy hydrocarbons and a first nitrogen material; At least steam pyrolysis tar and modified steam pyrolysis effluent are separated from the steam pyrolysis effluent in at least one tar separation drum; At least (i) process gas containing water and a second nitrogen material and (ii) pyrolytic gasoline containing a third nitrogen material are separated from the effluent of the modified steam cracker, wherein the separation is carried out in the primary fractionator and in the quench tower downstream of the primary fractionator, wherein the second nitrogen material is a portion of the first nitrogen material and / or derived from a portion of the first nitrogen material, and the third nitrogen material is a portion of the first nitrogen material and / or derived from a portion of the first nitrogen material. Compressing process gas and separating a hydrocarbon-water mixture and a cleaning fluid containing a portion of a second nitrogen material from the compressed process gas; Compressed process gas is contacted with a lean amine composition in at least one amine tower to produce a rich amine composition and partially purified process gas. The partially purified process gas is contacted with a lean alkali composition in at least one alkali tower to produce a rich alkali composition and purified process gas. At least a portion of any second nitrogen material in the rich amine composition is removed in at least one amine regenerator to produce a regenerated amine composition, and at least a portion of the regenerated amine composition is recycled as a lean amine composition; Remove at least a portion of any remaining second nitrogen material from the purified process gas in at least one dryer-ammonia bed to produce a modified process gas; The second nitrogen material is removed from the purified process gas by separating it from the dryer-ammonia bed; The hydrocarbon-water mixture is combined with pyrolytic gasoline separated from the effluent of the modified steam cracker to produce a combined mixture; In at least one oil-water separator, the water component is separated from the combined mixture to produce concentrated pyrolytic gasoline; In at least one stripping tower, a light effluent and a residual water component are separated from a separated water component to produce a light effluent and a residual water component, wherein the light effluent contains at least a portion of a third nitrogen material. At least a portion of the third nitrogen material is separated from the light effluent to produce a purified light effluent; The third nitrogen material from which at least a portion is separated from the light effluent includes: Nitrogenous material that condenses at least a portion of the light effluent; and Transfer at least a portion of the condensed nitrogen material to at least one container; and At least a portion of the light effluent or at least a portion of the purified light effluent is transferred to a quench tower.

26. The method of claim 25, further comprising (i) separating at least a C4 stream from the modified process gas, and (ii) contacting at least a portion of the C4 stream with water to produce a modified C4 stream comprising isobutylene, wherein at least a portion of any acetonitrile in the C4 stream is transferred to water.

27. The method of claim 26 further comprises catalytically converting at least a portion of the isobutylene into diisobutylene and / or MTBE.

28. The method of claim 22, wherein the dryer-ammonia bed comprises a device for removing water, ammonia, amines, and NO. x One or more active absorbent beds.

29. A system for managing nitrogen material during steam cracking of crude oil feed containing heavy hydrocarbons, the system comprising: It contains a steam pyrolyzer with convection and radiation lines; Flash separation vessel fluidly connected to a convection line and downstream of the convection line and fluidly connected to a radiation line and upstream of the radiation line; A tar separation drum that is fluidly connected to the radiation pipeline and located downstream of the radiation pipeline; A fractionator that is fluidly connected to the tar separation drum and located downstream of the tar separation drum; A quench tower that is fluidly connected to the fractionator and located downstream of the fractionator; An oil-water separator that is fluidly connected to the quench tower and located downstream of the quench tower; A water stripper fluidly connected to and downstream of an oil-water separator, wherein the water stripper includes a top pipeline that is fluidly connected to a condenser and a container via a first pipeline and upstream of the condenser and the container, and fluidly connected to a quench tower via a second pipeline and upstream of the quench tower; and A first compressor-processing system fluidly connected to and downstream of a quench tower, wherein the first compressor-processing system includes a pipeline fluidly connected to an oil-water separator.

30. The system of claim 29, further comprising: An amine tower that is fluidly connected to the first compressor-processing system and located downstream of the first compressor-processing system; An alkali tower that is fluidly connected to the amine tower and located downstream of the amine tower; A second compressor-processing system is fluidly connected to the alkali tower and located downstream of the alkali tower. One or more dryer-amine beds are fluidly connected to and downstream of the second compressor-processing system, wherein the one or more dryer-amine beds contain at least one absorbent bed having the function of removing water, ammonia, amines and NO. x One or more of the activities.

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