Hydrocarbon pyrolysis of sulfur-containing feedstocks

Abstract

This disclosure relates to methods, apparatus, and systems for removing sulfur compounds from heavy hydrocarbon feedstocks as part of a steam cracking process for producing light olefins. In at least one embodiment, the method includes introducing a hydrocarbon feedstock having a first sulfur content into a steam cracker to produce a steam cracker effluent having a second sulfur content less than the first sulfur content. The method further includes introducing the steam cracker effluent into a fractionation system to produce a light hydrocarbon product stream having a third sulfur content less than the second sulfur content.

Description

[0001] This invention patent application is a divisional application of application number 202180020357.4, application date March 9, 2021, and invention title "Hydrocarbon Pyrolysis with Sulfur-Containing Feed".

[0002] Cross-reference to related applications

[0003] This application claims priority and interest in U.S. Provisional Application No. 62 / 988,278, filed March 11, 2020, and European Patent Application No. 20188287.5, filed July 29, 2020, the disclosures of which are incorporated herein by reference in their entirety. Technical Field

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

[0005] Various refinery processing streams can be produced by processing feedstocks such as crude oil. Many of these refinery processing streams are used as feedstocks (and / or included in) hydrocarbon pyrolysis processes such as steam cracking. Steam cracking produces useful products, such as light olefins, 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, like light (C4) hydrocarbons. 4- Olefins, including ethylene and propylene. Steam cracking also produces steam cracker tar ("SCT", which can be used as fuel oil), pyrolysis gasoline (pygas), steam cracker gas oil, etc.

[0006] Some refinery feedstocks used as hydrocarbon feedstocks in steam cracking processes are predominantly gaseous at 25°C and 1 bar (absolute pressure). Others are predominantly liquid under these conditions, such as refinery streams like naphtha, gas oil, and residual oil. Besides those obtainable from refining processes, predominantly liquid hydrocarbon feedstocks can be obtained from other petrochemical facilities or from sources such as pipelines, transport containers, and container equipment. The advantage of obtaining such feedstocks from refining processes is that the refining processes used to produce hydrocarbon feedstocks typically remove various forms of sulfur (e.g., sulfur and other sulfur-containing compounds, such as sulfur compounds) commonly present in refinery feedstocks. For example, in many refinery product streams, sulfur is primarily present as hydrogen sulfide (H₂S). H₂S can be removed from these refinery streams prior to steam cracking, for example, by conventional methods such as amine and / or caustic treatment. Other sulfur compounds in these streams are usually present in sufficiently small amounts that the stream does not significantly affect the product and co-product recovery facilities of the steam cracking unit.

[0007] Over time, demand for light olefins has grown faster than demand for refinery products such as fuels and lubricants, and this trend is expected to continue. As a result, the number and size of new or retrofitted steam cracker units have increased significantly compared to the number and size of new or retrofitted refineries. This increased demand for predominantly liquid-phase hydrocarbon feedstocks has fueled interest in utilizing heavier liquid-phase feedstocks, such as those with an API gravity less than that of naphtha ("heavier predominantly liquid-phase hydrocarbon feedstocks," also known as "favorable feedstocks"). While favorable feedstocks can include those that have already undergone prior processing, such as certain gas oils, they can also include feedstocks such as crude oil, including crude oil containing medium hydrocabon and / or heavy hydrocarbons. For example, utilizing favorable feedstocks containing virgin feedstocks (e.g., various crude oils) will increase the supply of available liquid feedstocks and reduce the dependence of steam cracker units on refinery processed feedstreams to meet steam cracker feedstock demands. This will, for example, improve equipment economics by reducing the production costs of light olefins and by making higher-value refinery feedstock available for other purposes.

[0008] The amount of sulfur in a favorable feedstock can be an obstacle to its use in steam cracking. Many favorable feedstocks, including most of the world's crude oil, are sour. While sour feedstocks are generally less expensive, high sulfur content can make steam cracking difficult. Using sour hydrocarbon steam cracker feedstocks can lead to increased corrosion in processing equipment, for example, from acidic sulfur compounds present in the feedstock. Using sour hydrocarbon feedstocks may also require specialized equipment and additional processing in steam cracking units and related facilities to produce, for example, fuel oils such as low-sulfur fuel oil (LSFO).

[0009] Steam cracking feedstocks containing sulfur-containing hydrocarbons, such as those derived from high-sulfur crude oils, typically produce steam cracker products containing several sulfur compounds, such as H₂S, ethyl mercaptan, methyl mercaptan, carbonyl sulfides, other sulfides, carbon disulfide, and various thiophenes. Especially when using feedstocks containing crude oil hydrocarbons, these sulfur-containing impurities may be present in moderate to high concentrations, potentially leading to processing difficulties, such as catalyst poisoning in downstream recovery facilities. Because the limits for sulfur compounds in products or reactor feedstocks can be small, for example, approximately parts per million, understanding the distribution and efficiency of various sulfur removal methods is crucial for appropriately managing the amount of such sulfur compounds in downstream products.

[0010] Conventional methods for removing sulfur from hydrocarbon feedstocks prior to steam cracking have been developed. While feedstock hydrotreating has been proposed, this approach is expensive and often results in undesirable conversion of lower-value feedstock hydrocarbon products such as methane. Another conventional method utilizes a flash separation vessel integrated with the convection section of the steam cracker. This removes and carries away at least some of the sulfur from the hydrocarbon feedstock before steam cracking occurs in the furnace's radiant section. However, further improvements are needed as the limits on sulfur content in steam cracker products become increasingly stringent.

[0011] In particular, there is a need for improved systems, methods, and processes to manage sulfur found in favorable feedstocks or generated through steam cracking of favorable feedstocks (e.g., feedstocks, such as crude oil). Effective management of sulfur-containing compositions in hydrocarbon feedstocks used for steam cracking is desired in order to: (i) meet increasingly stringent product specifications; (ii) reduce operating costs of steam cracking equipment, such as those associated with catalyst poisoning in the equipment's recovery facilities; and / or (iii) reduce operating costs associated with corrosion from sulfur-containing compounds (e.g., H2S). Summary of the Invention

[0012] We have found that steam cracking of hydrocarbon feedstocks containing high concentrations of sulfur (e.g., crude oil) can lead to the formation of high concentrations of many sulfur-containing compounds in the steam cracker effluent, such as H₂S, methyl mercaptan (CH₃SH), ethyl mercaptan (C₂H₅SH), COS, CS₂, dimethyl sulfide (CH₃SCH₃), C5-range sulfur-containing organic compounds, and C₂S. 6+A wide range of sulfur-containing organic compounds are present, typically absent or present only in very low amounts, in the comparative steam cracker effluent from steam cracking low-sulfur hydrocarbon feedstocks such as ethane, propane, and naphtha. These sulfur-containing compounds have boiling points spanning a broad range, resulting in some being distributed in the process gas stream, some in the heavy pyrolysis gasoline stream, some in the gas oil stream, and some in the steam cracker tar stream during quenching and separation of the steam cracker effluent. Their presence and varied distribution pose significant challenges to conventional product recovery and processing sections. It has been found that, for example (i) during methods for recovering various products (e.g., C2-C4 olefin products) from process gas streams, (a) measures can be taken in an amine tower and / or a caustic tower to reduce the increased levels of methyl mercaptan, ethyl mercaptan, CS2, and COS, in addition to H2S and CO2, and (b) an adsorbent bed can be used to reduce COS from hydrocarbon streams prior to any acetylene converter; (ii) when processing pyrolysis gasoline from process gas streams and / or heavy pyrolysis gasoline streams, the increased levels of CS2, dimethyl sulfide, and thiophene can be addressed by using hydrogenation and / or hydrodesulfurization to produce various final products with acceptable levels of such sulfur-containing compounds.

[0013] In some aspects, the present invention relates to a steam cracking method. A hydrocarbon feed is provided, wherein (i) the hydrocarbon feed comprises hydrocarbons and sulfur, and (ii) the hydrocarbon feed has a first sulfur content. At least one steam cracker is provided, wherein the steam cracker is integrated with a flash separation vessel. The hydrocarbon feed is introduced into the steam cracker to produce a steam cracker effluent having a second sulfur content less than the first sulfur content. The sulfur-rich feed stream is removed from the flash separation vessel. The steam cracker effluent is introduced into at least one recovery facility to produce a process gas feed stream having a third sulfur content less than the second sulfur content.

[0014] In other aspects, a hydrocarbon feedstock is provided, the hydrocarbon feedstock having a first sulfur content. After non-essential desalting, the hydrocarbon feedstock or desalted hydrocarbon feedstock (as applicable) is preheated to produce a preheated feedstock. The preheated feedstock is combined with steam to produce a steam cracking feedstock. A pyrolysis feedstock, primarily gaseous, is separated from the steam cracking feedstock, wherein ≥20% (by weight) of the sulfur from the hydrocarbon feedstock is present in the pyrolysis feedstock. The pyrolysis feedstock is pyrolyzed under pyrolysis conditions to produce a steam cracker effluent. SCT and upgraded steam cracker effluent are separated from the steam cracker effluent, wherein ≥25% of the sulfur from the pyrolysis feedstock is present in the steam cracker tar. Primarily liquid cracked gasoline and primarily gaseous process gas streams are separated from the upgraded steam cracker effluent, wherein ≥0.5% (by weight) of the sulfur from the cracked feedstock is present in the cracked gasoline.

[0015] The present invention also relates to systems and apparatus for performing any of the foregoing aspects.

[0016] In particular, the present invention relates to the following aspects.

[0017] Item 1. Steam cracking methods, including:

[0018] A hydrocarbon feed comprising hydrocarbons and sulfur is provided, the hydrocarbon feed having a first sulfur content;

[0019] The hydrocarbon feed is introduced into a steam cracker integrated with a flash separation vessel to produce a steam cracker effluent with a second sulfur content that is less than the first sulfur content.

[0020] Remove the sulfur-rich feed stream from the flash separation vessel; and

[0021] The steam cracker effluent is introduced into a recovery facility to generate a process gas stream, wherein the process gas stream has a third sulfur content, which is less than the second sulfur content, and wherein the process gas stream contains H2S and methyl mercaptan.

[0022] Item 2. The method of Item 1, wherein the first sulfur content is at least 0.07% by weight, based on the total weight of the hydrocarbon feed.

[0023] Item 3. The method of Item 2, wherein the first sulfur content is at least 1.0% by weight, based on the total weight of the hydrocarbon feed.

[0024] Item 4. The methods mentioned above also include:

[0025] The process gas stream is introduced into the compressor unit to generate a compressed process gas stream;

[0026] The compressed process gas stream is introduced into the amine tower, thereby removing most of the H2S and a portion of the methyl mercaptan from the compressed process gas stream to form a partially purified process gas stream.

[0027] The partially purified process gas stream is introduced into an alkali tower, thereby removing a portion of the H2S and methyl mercaptan from the compressed process gas stream to produce a purified process gas stream with a fourth sulfur content lower than the third sulfur content; and

[0028] At least a portion of the water contained in the purified process gas stream is removed to obtain an upgraded process gas stream.

[0029] Item 5. The method of Item 4, wherein the amine tower comprises a tray having an outer weir of at least 75 mm.

[0030] Item 6. The method of Item 4 or 5, wherein the alkali tower includes a single-pass caustic alkali circulation, wherein a fresh caustic alkali feed stream enters the top of the alkali tower and exits at the bottom of the top section of the alkali tower to a caustic alkali treatment unit, so as to achieve the removal of at least 80% of methyl mercaptan from the compressed process gas feed stream by using the combination of the amine tower and the alkali tower.

[0031] Item 7. The method of any one of items 4 to 6, wherein the process gas stream further comprises ethyl mercaptan, and a portion of the ethyl mercaptan is removed in the amine tower, and a portion of the ethyl mercaptan is removed in the alkali tower.

[0032] Item 8. The method of any one of items 4 to 7, wherein the process gas stream further comprises COS, and a portion of the COS is removed in the amine tower.

[0033] Item 9. The method in Item 8 also includes:

[0034] The process gas stream generates C containing acetylene and COS. 3- Hydrocarbon flow;

[0035] From the C 3- At least a portion, preferably substantially all, of the COS is removed from the hydrocarbon feed stream to obtain purified COS. 3- Hydrocarbon flow; and

[0036] Make the C 3- The hydrocarbon feed stream flows to the acetylene converter to convert at least a portion of the acetylene into olefins in the presence of an acetylene conversion catalyst.

[0037] Item 10. The method of Item 9, wherein the alkyne converter is a front-end converter.

[0038] Item 11. The method of Item 9, wherein C 3- The hydrocarbon feed stream is a C3 hydrocarbon feed stream, and the alkyne converter is a MAPD converter.

[0039] Item 12. The methods mentioned above also include:

[0040] The process gas stream generates a C4 hydrocarbon stream containing methyl mercaptan and 1,3-butadiene;

[0041] The C4 hydrocarbon stream is passed through a second alkali tower to remove the methyl mercaptan, thereby obtaining a purified C4 hydrocarbon stream; and

[0042] The purified C4 hydrocarbon stream is contacted with molecular hydrogen and a hydrogenation catalyst to produce an upgraded C4 hydrocarbon stream containing less 1,3-butadiene than the purified C4 hydrocarbon stream.

[0043] Item 13. The method of any one of items 4 to 12, wherein the process gas stream further comprises CS2, and a portion of the CS2 is removed in the amine tower.

[0044] Item 14. The methods mentioned above also include:

[0045] The process gas stream generates a cracked gasoline stream containing ethyl mercaptan and / or CS2;

[0046] It is not necessary to produce a heavy pyrolysis gasoline feedstock containing CS2 from the steam cracker effluent; and

[0047] The cracked gasoline feed stream is hydrotreated in a hydrorefining unit in the presence of a hydrorefining catalyst, which is not necessarily combined with the heavy cracked gasoline feed stream.

[0048] Item 15. The method of any of the preceding items, wherein the process gas stream comprises dimethyl sulfide, and the method further comprises:

[0049] A cracked gasoline feed stream is generated from a process gas feed stream containing dimethyl sulfide;

[0050] Unnecessarily, the steam cracker effluent is used to produce a heavy cracked gasoline feedstock containing dimethyl sulfide; and

[0051] The cracked gasoline feed stream is optionally combined with the heavy cracked gasoline feed stream and subjected to hydrodesulfurization to remove at least a portion of the dimethyl sulfide therein.

[0052] Item 16. The method of any of the preceding items, wherein the process gas stream comprises thiophene, and the method further comprises:

[0053] A cracked gasoline feed stream is generated from a process gas feed stream containing thiophene;

[0054] Optionally, the steam cracker effluent is used to produce a heavy cracked gasoline feedstock containing thiophene; and

[0055] The cracked gasoline feed stream, which may be combined with the heavy cracked gasoline feed stream, is subjected to hydrogenation to remove at least a portion of the thiophene therein.

[0056] Item 17. Steam cracking methods, including:

[0057] A hydrocarbon feedstock is provided, wherein (i) the hydrocarbon feedstock comprises hydrocarbons and sulfur, and (ii) the hydrocarbon feedstock has a first sulfur content;

[0058] The hydrocarbon feed is preheated to produce a preheated feed;

[0059] The preheated feed is combined with steam to produce a steam cracking feed;

[0060] Separate a bottom stream, which is mainly liquid, and a pyrolysis feed, which is mainly gas, from the steam cracking feed, wherein ≥20% (by weight) of sulfur from the hydrocarbon feed is present in the pyrolysis feed;

[0061] The pyrolysis feed is pyrolyzed under pyrolysis conditions to produce steam cracker effluent;

[0062] Separating steam cracker tar and upgraded steam cracker effluent from the steam cracker effluent, wherein ≥25% of the sulfur in the pyrolysis feed is present in the steam cracker tar; and

[0063] The pyrolysis feedstock is separated from the effluent of the upgraded steam cracker into a predominantly liquid pyrolysis gasoline and a predominantly gaseous process gas stream, wherein ≥0.5% (by weight) of sulfur from the pyrolysis feedstock is present in the pyrolysis gasoline.

[0064] The method of Item 18.17, wherein 0.5% to 50% by weight (based on weight) of sulfur in the pyrolysis feed is present in the pyrolysis gasoline.

[0065] The method of item 19, item 17 or 18, wherein 25% to 75% by weight of sulfur in the hydrocarbon feed is present in the pyrolysis feed.

[0066] Item 20. The method of any one of items 17 to 19, wherein (i) ≥25% by weight of sulfur in the hydrocarbon feed is present in the bottom feed stream, wherein ≥90% by weight of the remaining sulfur in the hydrocarbon feed is present in the pyrolysis feed, and (ii) ≥25% by weight of hydrocarbons in the hydrocarbon feed is present in the pyrolysis feed, wherein ≥90% by weight of the remaining hydrocarbons in the hydrocarbon feed is present in the bottom feed stream.

[0067] Item 21. The method of any one of items 17 to 20 further includes (i) recovering a stream containing C4 hydrocarbons and sulfur from the process gas stream and removing sulfur from one or more of the cracked gasoline, the steam cracker tar and the stream containing C4 hydrocarbons and sulfur.

[0068] Item 22. Steam cracking methods, including:

[0069] Provides hydrocarbon feedstock containing hydrocarbons and sulfur;

[0070] The hydrocarbon feed is introduced into a steam cracker to produce steam cracker effluent;

[0071] The steam cracker effluent is introduced into a recovery facility to generate a process gas stream containing mercaptans, C2, C3 and C4 hydrocarbons;

[0072] Separating C4 hydrocarbons and thiols from the process gas stream; and

[0073] The separated C4 hydrocarbons are upgraded, wherein at least a portion of the separated thiols is removed prior to the upgrading.

[0074] Item 23. Steam cracking methods, including:

[0075] Provides hydrocarbon feedstock containing hydrocarbons and sulfur;

[0076] The hydrocarbon feed is introduced into a steam cracker to produce a product containing dimethyl sulfide, C2-C4 hydrocarbons, and C... 5+ Hydrocarbon steam cracker effluent;

[0077] Separate at least a portion containing the dimethyl sulfide and the C from the steam cracker effluent. 5+ A mixture of at least a portion of hydrocarbons;

[0078] Hydrotreating the mixture to convert at least a portion of the dimethyl sulfide therein into a high molecular weight sulfur compound and to produce a hydrotreating processor effluent; and

[0079] Separate from the hydrotreating processor effluent (i) a second mixture containing at least a portion of C5 hydrocarbons and the dimethyl sulfide and (ii) C 6+ Hydrocarbon flow. Attached Figure Description

[0080] To gain a more detailed understanding of the features listed above in this disclosure, a more specific description of the disclosure, which has been briefly outlined above, can be obtained by referring to some of the implementation methods shown in the accompanying drawings. However, it should be noted that the drawings illustrate typical implementation methods of this disclosure and should not be considered as a limitation of its scope, as other equivalent implementation methods are permissible.

[0081] Figure 1 This is a flowchart of an implementation scheme for the steam cracking and fractionation of hydrocarbon feedstock.

[0082] Figure 2 This is a flowchart of an implementation plan for a method for separating and purifying light hydrocarbons.

[0083] For ease of understanding, the same reference numerals are used where possible to denote elements with similar functions common in the figures. It is anticipated that elements and features of one implementation can be advantageously incorporated into other implementations without further description. Detailed description

[0084] This disclosure relates to methods, processes, apparatus, and systems for steam cracking sulfur-containing hydrocarbon feedstocks. Sulfur can be in various forms, such as elemental sulfur, one or more sulfur-containing compounds, etc. Management of feed sulfur allows for more cost-effective processing while meeting the operational requirements of the steam cracker and the products to specifications.

[0085] Some aspects of this invention are carried out in a steam cracker apparatus that includes a furnace facility and a recovery facility. The furnace facility typically includes at least one desalter and at least one steam cracker. The steam cracker typically includes a convection section, a radiant section, and a gas-liquid separator 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 cracking facility. The recovery facility may include one or more containers (e.g., flash drums, such as tar separation drums) for separation from the steam cracker effluent SCT and the upgraded steam cracker effluent. A primary fractionator is typically used to separate quench oil, gas oil, etc., from the upgraded steam cracker effluent. The vapor stream carried away from the top of the primary fractionator is typically quenched in at least one container (e.g., a quench tower) to recover naphtha, water, and process gas streams. Optionally, the primary fractionator may be combined with a quench tower. Additional product separation and recovery equipment is typically used, for example, for the recovery of ethylene and / or propylene.

[0086] For the purposes of this description and the appended claims, the following terms are defined.

[0087] definition

[0088] "Hydrocarbons" refer to a class of compounds containing hydrogen atoms bonded to carbon. The term "C" is also used. n "A hydrocarbon is a hydrocarbon containing n carbon atoms per molecule, where n is a positive integer. (Terminology "C")" n+ "A hydrocarbon is a hydrocarbon containing at least n carbon atoms per molecule, where n is a positive integer. (Term "C")" n- "A hydrocarbon is a hydrocarbon containing at most n carbon atoms per molecule, where n is a positive integer." The term "hydrocarbon" encompasses (i) saturated hydrocarbons, (ii) unsaturated hydrocarbons, and (iii) mixtures of hydrocarbons, including mixtures of hydrocarbon compounds (saturated and / or unsaturated), including mixtures of hydrocarbon compounds with different n values. The term "unsaturated" or "unsaturated hydrocarbon" refers to 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" refers to 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 olefins" refer to C... 5- Olefins.

[0089] "Heavy hydrocarbons" refers to a mixture containing hydrocarbons, where the API specific gravity of the mixture is 5. o Up to (but not including) 22 o Within the range. "Medium hydrocarbons" refers to a mixture containing hydrocarbons, wherein the API specific gravity of the mixture is within 22. o Up to 30 o Within this range. "Heavier" hydrocarbons have a lower API gravity than naphtha.

[0090] In this disclosure, "acetylene" refers to a compound having a carbon-carbon triple bond in its molecular structure. "Acetylene converter" or "acetylene converter" interchangeably refers to a reactor unit that receives a feed comprising an olefin, acetylene, and molecular hydrogen, allowing the acetylene and molecular hydrogen to contact a conversion catalyst arranged in the reactor to convert at least a portion of the acetylene into an olefin, producing a conversion effluent of acetylene in reduced quantity compared to the feed. "Thiophene" refers to thiophene (… ), any compound having a thiophene ring structure in which one or more hydrogen atoms are replaced by one or more other atoms, and any mixture thereof. “Methylthiol” refers to CH3-SH. “Ethylthiol” refers to C2H5-SH. “Dimethyl sulfide” refers to CH3-S-CH3.

[0091] The term "sour" in conjunction with hydrocarbons refers to hydrocarbons, such as crude oil, containing ≥0.5% by weight of sulfur based on the weight of said hydrocarbon. This weight percentage encompasses one or more forms of sulfur in the hydrocarbon, such as elemental sulfur, sulfur bound in compounds, sulfur bound to, entangled with, or associated with aggregates such as asphaltenes and heavy tar. Unless otherwise stated, the amount of a particular sulfur-containing molecule (or sulfur-containing compound) in a particular composition (e.g., the amount of methyl mercaptan in a process gas stream) is expressed as a weight percentage based on the total weight of said composition.

[0092] "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 (e.g., ≥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 primarily liquid.

[0093] "Plain" feedstock, such as plain hydrocarbon feedstock, refers to feedstock that is primarily liquid and contains ≥25% by weight crude oil that has not undergone prior desalting and / or prior reflux fractionation, for example ≥50% by weight, ≥75% by weight, or ≥90% by weight.

[0094] "Crude oil" means a mixture containing naturally occurring hydrocarbons of geological origin, wherein the mixture (i) contains ≥1% by weight of residue oil, for example ≥5% by weight, for example ≥10% by weight, and (ii) has ≤52% by weight of crude oil.o For example, ≤30 o For example, ≤20 o , or ≤10 o , or ≤8 o The API gravity. Crude oil can be classified by its API gravity; for example, heavy crude oil has an API gravity of 5. o Up to (but not including) 22 o Within that range. Similarly, the API gravity of medium crude oil is around 22. o Up to 30 o Within the range.

[0095] Standard 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, such as by extrapolation for materials above 700°C. The term "T" 50 "T" refers to the temperature determined based on the boiling point distribution, at which 50% by weight of a specific sample has reached its boiling point. Similarly, "T" 90 "、"T 95 "and"T 98 "Nominal final boiling point" refers to the temperature at which 90, 95, or 98% by weight of a specific sample has reached its boiling point.

[0096] Certain medium and / or heavy hydrocarbons, such as certain feedstock hydrocarbons, including certain crude oils and crude oil mixtures, contain one or more of asphaltenes, asphaltenes precursors, and particles. Asphaltenes are described in U.S. Patent No. 5,871,634, the entire contents of which are incorporated herein by reference. Asphaltenes content can be determined using ASTM D6560-17. "Residue oil" refers to an oily mixture typically contained in or derived from crude oil, with a standard boiling point range ≥1050°C. o F (566℃). Residue oil may include "non-volatile components," which are compositions (organic and / or inorganic) with a standard boiling point range ≥590℃. Some non-volatile components have a standard boiling point ≥760℃.

[0097] A "steam cracker" or "steam cracking furnace" is a pyrolysis apparatus having at least a convection section and a radiant section. The furnace's heat is provided by a burner located in the radiant section. The burner burns fuel and air, producing a combustion effluent. The combustion effluent exits the radiant section, passes through the convection section, and is then carried away from the steam cracking furnace. The convection section includes at least one tubular member ("convection coil"). Similarly, the radiant section also includes at least one tubular member ("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 passing 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-connection. At least one gas-liquid separator is typically integrated with the convection section, for example, in fluid communication with the convection coil. A feed containing hydrocarbons and sulfur ("hydrocarbon feed") is introduced into the convection coil for preheating, typically after desalting. Steam is added to the preheated hydrocarbon feed to produce a steam cracking feed. Steam can be added for various reasons, such as reducing hydrocarbon partial pressure, controlling residence time, and / or reducing coke formation. Steam can be overheated, for example, in the convection section of the furnace, and / or the steam can be sulfur-containing or treated process steam. A non-essential gas-liquid separator can be used to separate the predominantly gaseous pyrolysis feed and the predominantly liquid bottom stream from the steam cracking feed. The pyrolysis feed is typically directed to the radiant coils after being heated via cross-connections and, non-essentially, in one or more additional convection coils. The steam cracker effluent is carried away from the radiant coil outlet. To reduce over-cracking 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 quenching fluid (e.g., one or more oily quenching fluids such as quench oil, liquid water, and steam).

[0098] The term "steam cracker tar" ("SCT") refers to (a) a mixture of hydrocarbons having one or more aromatic components and, unnecessarily, (b) non-aromatic and / or non-hydrocarbon molecules, said mixture being derived from hydrocarbon pyrolysis and having a T value of ≥290°C, for example ≥500°C, such as ≥600°C or higher. 90 In some respects, SCTs are separated from quenched (or partially quenched) steam cracker effluents in separation vessels such as tar separation drums, primary fractionators, etc. SCTs may comprise hydrocarbon molecules (including mixtures and aggregates thereof) having (i) one or more aromatic components and (ii) about 50% by weight or higher (e.g., 75% by weight or higher, such as 90% by weight or higher) of about C 15 Or higher molecular weight, based on the weight of SCT.

[0099] In each of the described embodiments, the addition of steam at various points in the method is not described in detail. It should also be noted that any steam added may include sulfur-containing or treated process steam, and any steam added (whether sulfur-containing or not) may be overheated. For example, when the steam comes from sulfur-containing water, the feed stream may be overheated.

[0100] In certain aspects of the invention, the hydrocarbon feed comprises (i) sulfur and (ii) heavy and / or medium hydrocarbons. These aspects will now be described in more detail. The invention is not limited to these aspects, and this specification is not intended to exclude other aspects within the broader scope of the invention, such as those in which the hydrocarbon feed is a medium hydrocarbon.

[0101] Hydrocarbon feed

[0102] In some respects, the hydrocarbon feed contains sulfur-containing hydrocarbons. Those skilled in the art will understand that the term "hydrocarbon feed" is a designation and does not imply that the feed contains only hydrocarbons. While at least a portion of the sulfur may be added to the hydrocarbon feed, typically most or all of the sulfur is present in the feed at the feed source. For example, the sulfur in the hydrocarbon feed may be naturally occurring sulfur in certain heavy hydrocarbons, such as sulfur naturally occurring in crude oil. In these and other respects, the hydrocarbons may have a nominal final boiling point of about 315°C or higher, such as about 400°C or higher, about 450°C or higher, or about 500°C or higher.

[0103] In some respects, the feed hydrocarbons can be higher molecular weight hydrocarbons, such as heavy hydrocarbons, such as those pyrolyzed during steam cracking to produce larger quantities of steam cracker naphtha (also known as pyrolytic gasoline), steam cracker gas oil ("SCGO"), and SCT. Heavy hydrocarbons can include one or more of the following: residue (also known as residual oil or sludge), gas oil, heating oil, jet fuel, diesel, kerosene, coking naphtha, hydrocracking products, reforming products, raffinate reforming products, distillates, crude oil, atmospheric tubular distillation bottoms, vacuum tubular distillation feed including bottoms, condensate, heavy non-straight-run hydrocarbon feed from refineries, vacuum gas oil, heavy gas oil, crude oil-contaminated naphtha, atmospheric residue, heavy residue, C4 / residue mixture, naphtha residue mixture, gas oil residue mixture, low-sulfur waxy residue, atmospheric residue, and heavy residue.

[0104] In some respects, hydrocarbon feedstocks include economically viable, minimally processed heavy hydrocarbons containing nonvolatile components and coke precursors. For example, a hydrocarbon feedstock may contain about 1% by weight or more of heavy hydrocarbons, or, based on the weight of the hydrocarbon feedstock, 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. A hydrocarbon feedstock may contain one or more feedstocks, such as one or more crude oils; consist of one or more feedstocks, such as one or more crude oils; or consist substantially of one or more feedstocks, such as one or more crude oils.

[0105] In some respects, hydrocarbon feedstocks also include lower molecular weight hydrocarbons (e.g., medium and / or light hydrocarbons). Light hydrocarbons typically include naphtha-boiling-range hydrocarbons and substantially saturated hydrocarbon molecules with fewer than five carbon atoms, such as ethane, propane, and mixtures thereof. While hydrocarbon feedstocks containing light hydrocarbons generally produce higher yields of C2 unsaturated compounds (ethylene and acetylene) than those containing heavy hydrocarbons, heavy hydrocarbons are gaining increasing attention due to their lower cost and greater availability.

[0106] In addition to hydrocarbons, hydrocarbon feedstocks also include sulfur, such as elemental sulfur, one or more inorganic sulfur compounds, one or more organic sulfur compounds, sulfur associated with aggregates such as asphaltenes, and mixtures thereof. Typical sulfur compounds that can be present in hydrocarbon feedstocks include hydrogen sulfide (H₂S), methyl mercaptan ("MM"), ethyl mercaptan ("EM"), carbonyl sulfides ("COS"), carbon disulfide ("CS₂"), dimethyl sulfide ("DMS"), and one or more C₂S. 3+ Thiols, one or more thiophenes, or any combination thereof.

[0107] The sulfur content ("primary sulfur content") of the hydrocarbon feed can be measured according to ASTM D1552. Based on the weight of the hydrocarbon feed, the primary sulfur content can be about 5% by weight or less, and for sulfur-containing hydrocarbon feeds, about 0.5% or more. For example, the primary sulfur content can be about 0.5% by weight to about 5% by weight, about 1% by weight to about 4% by weight, about 2% by weight to about 4% by weight, or about 3% by weight to about 4% by weight. The methods and systems of this disclosure are particularly advantageous for steam cracking of hydrocarbon feedstocks with high first sulfur content having a weight percentage of c1 to c2, based on the total weight of the hydrocarbon feedstock, where c1 and c2 can be independently, for example, 0.07, 0.08, 0.09, 0.1, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.1, 1.2, 1.3, 1.4, 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.2, 2.4, 2.5, 2.6, 2.8, 3.0, 3.2, 3.4, 3.5, 3.6, 3.8, 4.0, 4.2, 4.4, 4.5, 4.6, 4.8, 5.0, provided c1 < c2. While the methods and systems of this disclosure can be used for steam cracking of hydrocarbon feedstocks containing less than 700 ppm by weight of low sulfur content, such as ethane feedstocks, propane feedstocks, naphtha feedstocks, etc., they are more preferably used for steam cracking of hydrocarbon feedstocks with high sulfur content, such as those mentioned above, such as crude oil, vacuum gas feedstocks, gas feedstocks, and mixtures thereof.

[0108] Steam cracker

[0109] Now refer to Figure 1 Certain aspects of the invention are described in more detail. These aspects include processing hydrocarbon feedstocks containing sulfur and heavy hydrocarbons in steam cracking units having furnace facilities and recovery facilities. The invention is not limited to these aspects, and this specification does not imply exclusion of other aspects within the broader scope of the invention, such as those in which the hydrocarbon feedstock is a desalted feedstock, those in which the hydrocarbon feedstock contains different hydrocarbons, and / or those in which the furnace and recovery facilities are located in different locations.

[0110] Figure 1A partial schematic diagram of a method and system 90 for producing light olefins and simultaneously reducing or even eliminating sulfur, such as sulfur, from various feed streams derived from and / or generated from hydrocarbon feed 101 is depicted. As shown, the hydrocarbon feed first enters a steam cracker 103 via line 101, entering the convection section of the steam cracker, i.e., the upper part of the steam cracker 103 (not shown separately). The hydrocarbon feed is preheated in at least one convection coil located in the convection section by indirectly transferring heat from the furnace combustion effluent (mainly flue gas) to the hydrocarbon feed. The resulting preheated hydrocarbon feed is carried away from the steam cracker 103 via line 105. Steam is introduced into the preheated hydrocarbon feed via line 131 to produce a steam cracking feed. In a flash separation vessel 107, a pyrolysis feed, which is mainly gaseous, and a bottom stream, which is mainly liquid, are separated from the steam cracker feed. The bottom stream, which is mainly liquid, contains various forms of sulfur and non-boiling hydrocarbons and is carried away via line 109. The pyrolysis feed is returned to the steam cracker 103 via cross pipe 111. The pyrolysis feed is introduced into the inlet of at least one radiant coil and guided through the radiant section (lower part of the furnace, not shown) of the steam cracker 103 for pyrolysis (cracking). Pyrolysis produces a steam cracker effluent, which is transferred via line 113 for further processing, such as quenching, and then various products and coproducts are purified and recovered from the quenched steam cracker effluent in the steam cracker's recovery facility.

[0111] The invention will now be described in more detail with reference to representative convection sections, representative flash separators, and representative radiation sections. The invention is not limited to these representative components of a steam cracker, and this specification should not be construed as excluding other forms of steam crackers within the broader scope of the invention, such as those without a flash separator integrated with the convection section.

[0112] Convection section

[0113] The hydrocarbon feed is introduced into the inlet of at least one convection coil located in the convection section of the steam cracker for preheating. Preheating of the hydrocarbon feed may involve indirect contact between the feed in the convection section of the steam cracker and hot flue gas traveling upwards from the radiant section of the furnace. Typically, the hydrocarbon feed is distributed among multiple convection coils. These may take the form of a set of heat exchange tubes located within the convection section of the steam cracker. The preheated hydrocarbon feed may have a temperature of about 150°C to about 260°C, for example, about 160°C to about 230°C, or about 170°C to about 220°C.

[0114] The steam cracking feed may also be preheated, typically upstream of the flash separation vessel 107. Typically, the steam content in the steam cracking feed is ≥5% by weight, for example, in the range of about 10% to about 90% by weight. Typically, the remaining ≥90% by weight of the steam cracking feed is preheated hydrocarbon feed, for example, ≥95% by weight, or ≥99% by weight. In some aspects, the steam cracking feed has a steam-to-hydrocarbon feed weight ratio of about 0.1 to about 1, for example, about 0.2 to about 0.6.

[0115] flash separator

[0116] A flash separator separates at least (i) a pyrolysis feed that is primarily gaseous and (ii) a bottom stream gas phase that is primarily liquid from the steam cracking feed. The flash separator may include one or more conventional flash separation vessels, such as one or more flash tanks, flash drums, etc., but the invention is not limited thereto. While they are suitable for other applications, such flash separation vessels are particularly suitable when the preheated hydrocarbon feed contains about 0.1% by weight or more, for example, about 5% by weight or more, asphaltenes based on the weight of the preheated hydrocarbon feed. Examples of suitable flash separation vessels and configurations for integrating these with steam crackers are disclosed in U.S. Patent Nos. 6,632,351; 7,138,047; 7,090,765; 7,097,758; 7,820,035; 7,311,746; 7,220,887; 7,244,871; 7,235,705; 7,247,765; 7,351,872; 7,297,833; 7,488,459; 7,312,371; and 7,578,929, each of which is incorporated herein by reference.

[0117] Refer again Figure 1 The flash separation performed in vessel 107 typically results in the transfer of at least a portion of the sulfur (in various forms) from the steam cracking feed and at least a portion of the high molecular weight molecules from the steam cracking feed, such as asphaltenes, to the bottom stream. The sulfur-rich bottom stream is carried away from vessel 107 via line 109. The bottom stream may include, for example, (i) at least about 25% by weight of the total sulfur content (in all forms of sulfur) of the preheated hydrocarbon feed, and (ii) at least about 10% by weight of the asphaltenes in the preheated hydrocarbon feed. Typically, ≥30% by weight of the total sulfur content (in all forms of sulfur) of the preheated hydrocarbon feed is present in the bottom stream, for example, ≥35% by weight, such as ≥40% by weight, or ≥45% by weight. The sulfur-depleted, predominantly gaseous pyrolysis feed is directed to the radiant section via cross-pipe 111. Optionally, the pyrolysis feed may undergo further heating in the convection section before being introduced into the cross-pipe.

[0118] It has been found that utilizing a designated flash separation vessel increases the width of hydrocarbon feed that can be introduced into the steam cracker via line 101 with minimal pretreatment. For example, it has been found that integrating a flash separation vessel with the convection section of the steam cracker facilitates steam cracking of a wide range of hydrocarbon feeds, including those containing ≥50% by weight, for example ≥75% by weight, or ≥90% by weight of one or more of the following: medium hydrocarbons, heavy hydrocarbons, crude heavy hydrocarbons, crude medium hydrocarbons, desalted heavy hydrocarbons and / or desalted medium hydrocarbons, heavy and / or medium crude oil, desalted heavy crude oil and / or desalted medium crude oil, based on the weight of the hydrocarbon feed.

[0119] It has also been found that the use of a designated flash separation vessel results in improved management of undesirable contaminants in the steam cracking feed, as gaseous contaminants (e.g., those transferred to the pyrolysis feed) can be kept within predetermined limits. In some aspects, the use of a designated flash separation vessel advantageously transfers ≥50% by weight of any salts and particles in the liquid phase portion of the steam cracking feed to the bottom stream, for example, ≥75% by weight, ≥90% by weight, or ≥99% by weight. Typically, the composition of the hydrocarbon feed directed to the steam cracker, the amount of hydrocarbon feed directed to said furnace, the amount of preheating of the hydrocarbon feed, the amount of dilution steam combined with the preheated hydrocarbon feed, and any heating of the steam cracking feed upstream of the separation vessel are selected to achieve ≥2% by weight, for example, ≥5% by weight, ≥10% by weight, or ≥20% by weight, or ≥50% by weight, or ≥75% by weight, or ≥90% by weight, or ≥95% by weight or more of the hydrocarbon portion of the steam cracking feed at the point where the steam cracking feed enters the separation vessel. For example, these options can be made to achieve the evaporation of approximately 5% by weight to approximately 98% by weight of the hydrocarbon fraction of the steam cracking feed, such as approximately 10% by weight to approximately 95% by weight, such as approximately 20% by weight to approximately 80% by weight, or approximately 25% by weight to approximately 75% by weight. Typically, ≥75% by weight of the remaining hydrocarbon fraction of the steam cracking feed (the portion not in the gas phase) is in the liquid phase, such as ≥90% by weight or ≥95% by weight.

[0120] Similarly, it has been found that maintaining sufficient flow rates in the convection section upstream of the flash separator (e.g., in a convection coil), particularly in the liquid phase portion of the steam cracking feed, can more effectively transfer salts and particles that may be present in the steam cracking feed to the bottom stream in the flash separator. It can be seen that doing so results in salts and / or particulate matter remaining suspended, leading to an increase in the amount of these substances transferred to the bottom stream. The composition (and therefore properties, such as viscosity and API gravity) of the hydrocarbon portion of the steam cracking feed, the flow rate of the steam cracking feed (particularly the flow rate of the liquid portion of the steam cracking feed), and the type and amount of salts and / or particulate matter in these streams can be selected to achieve a predetermined amount of liquid phase in the steam cracking feed. A lower flow rate, particularly in the liquid phase portion, indicates a larger amount of steam cracking feed in the liquid phase. This is typically the case when the hydrocarbon feed contains more viscous, and generally heavier, hydrocarbons. These properties and conditions are typically chosen to retain approximately 2% or more, for example, approximately 5% or more, of the hydrocarbon fraction of the steam cracking feed in the liquid phase, based on weight, at the point where the steam cracking feed enters the separation vessel. It has been found that doing so increases the amount of salt and / or particulate matter retained in the suspension.

[0121] The flash separation vessel can be operated at a temperature of about 315°C to about 510°C and / or a pressure of about 275 kPa to about 1400 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.

[0122] In some aspects, one or more of the following are selected: hydrocarbon feed composition, preheating conditions, steam quality and quantity, and steam cracker feed separation conditions to transfer ≥25% by weight of sulfur from the hydrocarbon feed to the bottom stream, for example, ≥50% by weight, for example, ≥60% by weight, or 50% to 80% by weight; wherein the remaining ≥90% by weight of sulfur from the hydrocarbon feed is present in the pyrolysis feed, for example, ≥95% by weight, for example, ≥99% by weight. In other aspects, ≥20% by weight of hydrocarbons from the hydrocarbon feed is transferred to the pyrolysis feed, for example, ≥25% by weight, for example, ≥50% by weight, or ≥60% by weight, or 50% to 80% by weight; wherein the remaining ≥90% by weight of hydrocarbons from the hydrocarbon feed is present in the bottom stream, for example, ≥95% by weight, for example, ≥99% by weight. For example, the amount of sulfur present in the hydrocarbon feed (based on weight, all forms of sulfur in the hydrocarbon feed) can be ≥75%, for example ≥90%, or 20% to 95% by weight, for example 20% to 90% by weight, for example 25% to 75% by weight. Depending on the composition of the hydrocarbon feed and the conditions used in the convection section and flash separation vessel, the various forms of sulfur present in the pyrolysis feed may differ from those in the hydrocarbon feed. The bottom stream can be removed from the flash separation vessel, for example for storage and / or further processing, and directs the pyrolysis feed to the radiant section of the steam cracker. The sulfur content of these streams will now be described in more detail.

[0123] The pyrolysis feed has a sulfur content ("second" sulfur content) which can be measured, for example, in weight % according to ASTM D1552 and is based on the weight of the pyrolysis feed. The second sulfur content ("Sulfcon2") is less than the first sulfur content (the sulfur content of the hydrocarbon feed, "Sulfcon1"). For example, Sulfcon2 can be expressed as a factor F multiplied by Sulfcon1 (Sulfcon2 = F×Sulfcon1), where (i) F is in the range of F1 to F2; (ii) F, F1, and F2 are positive real numbers, and (iii) F1 < F2. Typically, F1 is in the range of 0.30 to about 0.90, and F2 is in the range of about 0.90 to about 0.99. More specifically, F1 can be one of 0.30, 0.35, 0.45, 0.50, 0.55, 0.60, 0.65, 0.70, 0.75, 0.80, 0.85, and 0.90; F2 can be one of 0.99, 0.95, 0.90, 0.85, 0.80, 0.75, 0.70, and 0.65; and F can be one of 0.30, 0.35, 0.45, 0.50, 0.55, 0.60, 0.65, 0.70, 0.75, 0.80, 0.85, 0.90, 0.95, and 0.99 weight % of the first sulfur content. Those skilled in the art will understand that the amount of sulfur (in all forms of sulfur) in the bottoms stream of the flash separator (e.g., via line 109) can be predetermined primarily based on (i) the initial amount of sulfur in each form in the hydrocarbon feed and (ii) the process conditions (e.g., temperature, pressure, flow rate, etc.) selected for the convection section of the steam cracker and the flash separation vessel.

[0124] In some aspects, Sulfcon2 ≤ 1.5 weight %. Sulfur compounds typically present in the pyrolysis feed include H2S, MM, EM, COS, CS2, or C 2+ mercaptans and thiophenes. Most of the sulfur in the pyrolysis feed can be bound as C 2+ mercaptans and thiophenes. For example, ≥ 50 weight % of the total amount of sulfur (in any form) present in the pyrolysis feed can be in the form of C 2+ mercaptans and thiophenes, such as ≥ 60 weight %, or ≥ 70 weight %, or ≥ 80 weight %, or ≥ 90 weight %, or ≥ 99 weight %, or more, based on the total weight of sulfur (in any form) in the pyrolysis feed. The total amount of C 2+ mercaptans and thiophenes in the pyrolysis feed can be from about 500 wppm to about 3000 wppm, or from about 2500 wppm to about 2900 wppm. Some forms of sulfur have a lower molecular weight than ethyl mercaptan (low molecular weight sulfur forms, or "LMW sulfur"). Examples of LMW sulfur include carbonyl sulfide, methyl mercaptan, and hydrogen sulfide. In some embodiments, C 2+The molar ratio of sulfur compounds to LMW sulfur compounds is about 10:1 or greater, about 100:1 or greater, about 1000:1 or greater, or about 10,000:1 or greater.

[0125] Radiation segment

[0126] The pyrolysis feedstock is pyrolyzed under pyrolysis conditions in multiple furnace tubes to produce steam cracker effluent. The furnace tubes (radiant tubes or radiant coils) are located in the radiant section of the furnace. The heat used for pyrolysis is primarily provided by burners. The burners are located in combustion chambers within the radiant section to provide radiant heating to the outer surfaces of the furnace tubes. The burners are typically located in or near the floor of the combustion chamber. (Back to...) Figure 1 The pyrolysis feed is introduced via line 111 into at least one radiant coil located in the radiant section (bottom) of the steam cracker 103, wherein hydrocarbons and certain sulfur-containing substances in the pyrolysis feed are pyrolyzed to produce steam cracker effluent. 2+ Olefins) and new types of sulfur-containing compositions. In other words, pyrolysis converts at least some forms of sulfur present in the pyrolysis feed into different forms of sulfur in the steam cracker effluent. The steam cracker effluent is carried away from the radiant section via line 113. The amount of pyrolysis feed in the gas phase at the radiant coil inlet is typically about 90% by weight or more, for example about 95% by weight or more, or about 99% by weight or more.

[0127] Those skilled in the art will understand that a wide range of pyrolysis conditions can be used, and the selection of specific pyrolysis conditions will depend, for example, on the composition of the selected hydrocarbon feed and the relative amounts of various products and co-products in the steam cracker effluent, such as the relative amounts of ethylene and propylene. For example, pyrolysis conditions typically include heating the pyrolysis feed in a radiant coil to achieve a radiant coil effluent temperature (measured at the outlet of the radiant coil) of about 400°C or higher, for example, about 400°C to about 1100°C, a pressure of about 10 kPa or higher (measured at the outlet of the radiant coil), and a residence time in the radiant coil of about 0.01 seconds to 5 seconds. In some aspects, such as those where the hydrocarbon feedstock includes crude oil or desalted crude oil, the pyrolysis conditions may include one or more of the following: (i) a temperature of about 760°C or higher, for example, about 760°C to about 1100°C, or about 790°C to about 880°C; (ii) a pressure of about 50 kPa or higher, 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. For hydrocarbon feedstocks containing lighter hydrocarbons, temperatures in the range of about 760°C to about 950°C are typically used. The specified steam cracking conditions are sufficient to convert at least a portion of the hydrocarbon molecules in the pyrolysis feedstock into C2O2 via pyrolysis. 2+ Olefins convert a portion of the sulfur in the pyrolysis feed into a form with a smaller molecular weight.

[0128] Steam cracker effluent typically includes unconverted components of the pyrolysis feed and pyrolysis products. Pyrolysis products typically include C... 2+ Alkenes, molecular hydrogen, acetylene, aromatic hydrocarbons, saturated hydrocarbons, C 3+ Dienes, aldehydes, CO2, steam cracker tar, and various forms of sulfur. Sulfur in steam cracker effluent typically exists in the following forms: (i) sulfur bound to or associated with larger molecular weight aggregates, such as those commonly found in SCTs, and (ii) compounds including one or more of H2S, COS, CS2, DMS, thiophene, and / or thiols. Various components of steam cracker effluent can be classified as (i) those that will be predominantly gaseous at 25°C and 1 bar (absolute) pressure, such as one or more of acetylene, ethylene, propylene, butene, H2S, MM, and COS, and (ii) those that will be predominantly liquid under these conditions, including, for example, C 5+ Molecules, thiophene, DMS, C 2+ One or more of thiols and mixtures thereof. Under these conditions, some sulfur compounds can be separated between the gas and liquid phases. For example, at 25°C and 1 bar (absolute pressure), the separation of ethyl mercaptan from steam cracker effluent in a gas-liquid form during conventional separation will result in approximately 80% of the ethyl mercaptan being separated by the gas phase and approximately 20% by the liquid phase.

[0129] Pyrolysis typically converts at least a portion of the sulfur in the pyrolysis feed into a lower molecular weight form of sulfur. For example, C in steam cracker effluent... 2+ The ratio of sulfur compounds to LMW sulfur compounds can be less than that of C in the pyrolysis feed. 2+ The ratio of sulfur compounds to LMW sulfur compounds. In some respects, the C in the pyrolysis feed... 2+ The molar ratio of sulfur compounds to LMW can be about 1000:1 or greater, about 100:1 or greater, or about 10:1 or greater, and / or the C content in the steam cracker effluent can be [missing information]. 2+ The molar ratio of sulfur compounds to LMW can be about 1:10 or less, about 1:1 or less, or about 10:1 or less. Pyrolysis can increase the amount of LMW sulfur compounds in the steam cracker effluent compared to the amount in the pyrolysis feed, for example, by ≥ about 100 wppm, for example, ≥ about 500 wppm, for example, ≥ about 1000 wppm, or ≥ about 1500 wppm, or about 100 wppm to about 3000 wppm, or about 500 wppm to about 2500 wppm, or about 1000 wppm to about 2000 wppm.

[0130] The amount of LMW sulfur in the steam cracker effluent depends primarily on the amount of sulfur in the pyrolysis feed that generates LMW sulfur. In some embodiments, the pyrolysis reduces the C2 of the pyrolysis feed. 2+ ≥30% of sulfur compounds are converted to LMW sulfur compounds, such as ≥40%, ≥50%, ≥60%, or ≥70%. For example, if the pyrolysis feed contains approximately 3000 wppm of C... 2+ Sulfur compounds, then the steam cracker effluent may contain ≥ about 900 wppm of LMW sulfur compounds, or ≥ about 1200 wppm, or ≥ about 1500 wppm, or ≥ about 1800 wppm, or ≥ about 2100 wppm, for example about 900 wppm to about 2500 wppm, or about 1200 wppm to 2200 wppm.

[0131] Without being bound by theory, the ease with which lighter sulfur compounds (e.g., LMW sulfur compounds) can be removed from steam cracker effluents compared to attempting to remove sulfur compounds from hydrocarbon feeds, steam cracking feeds, or pyrolysis feeds prior to pyrolysis allows for more efficient removal methods. This is especially true when the feed contains more refractory forms of sulfur, such as C5+ mercaptans and thiophene sulfur. In those cases, pyrolysis converts the feed sulfur into forms that can be more easily removed from the effluent, such as H2S and C62S. 4- Thiols.

[0132] Steam cracker effluent contains useful products such as molecular hydrogen and C1-C. 10 Hydrocarbons, steam cracker gas oil (mainly C) 10 -C 17 The invention relates to a combination of hydrocarbons and SCTs. SCTs are high-boiling-point, viscous, reactive materials that can be upgraded to fuel oil, for example, through blending and / or hydrotreating, but may cause fouling of equipment under certain conditions. Typically, pyrolysis feeds containing higher-boiling-point materials tend to produce larger amounts of SCTs. SCT formation primarily occurs downstream of the radiant coil outlet. Quenching the steam cracker effluent can reduce the amount of SCT produced, for example, by rapidly reducing the temperature of the steam cracker effluent near the radiant coil outlet to a value that significantly slows down the tar formation reaction. The steam cracker effluent can be quenched by various methods, such as contact with cooled hydrocarbons, for example, by direct quenching with quenching oil. Optionally or additionally, the steam cracker effluent can be rapidly cooled in a heat exchanger such as a transfer line exchanger. Conventional quenchers can be used, but the invention is not limited thereto.

[0133] While a single transfer line heat exchanger can be used, the use of two or more transfer line heat exchangers is also within the scope of this invention. For example, the steam cracker effluent can be quenched by rapid but indirect cooling with water and / or steam in two or more transfer line heat exchangers. Typically, the partially quenched effluent leaving the first transfer line heat exchanger is maintained at a temperature above the dew point (the temperature at which the first drop of liquid condenses) of the steam cracker effluent. For typical hydrocarbon feeds containing heavy hydrocarbons and typical pyrolysis conditions, the hydrocarbon dew point of the steam cracker effluent can be from about 375°C to about 650°C, for example, from about 480°C to about 600°C. Above the hydrocarbon dew point, the tendency for scaling is lower because gas-phase scaling is generally not severe, and there is little or no liquid that could cause scaling.

[0134] In addition to quenching in one or more transfer line exchangers, or otherwise, the steam cracker effluent may undergo direct quenching at a point between steam cracker 103 and fractionation system 115. Direct quenching is accomplished by contacting the steam cracker effluent with a liquid quenching stream. When used in conjunction with at least one transfer line exchanger, quenching liquid may be introduced at a point downstream of the transfer line exchanger(s). Suitable quenching liquids include one or more of liquid quenching oils, such as SCT, hydrotreated SCT, primary fractionator bottom or side streams, pyrolysis fuel oil, and water, which may be obtained from a variety of suitable sources, such as condensed dilution steam.

[0135] At least a portion of the effluent from the quenched steam cracker is carried away from the furnace facilities to the recovery facility of the steam cracking unit for the separation and purification of various products and co-products. References will follow below. Figure 1 Certain aspects of a representative recovery facility are described in more detail. Among these aspects, the recovery facility includes in its main components a fractionation system, a sulfur-containing water stripping and dilution steam system, a compressor train, an acid gas removal system, and a product recovery equipment assembly. The invention is not limited to these aspects, and this specification should not be construed as excluding other forms of recovery facilities within the broader scope of the invention.

[0136] Fractionation system

[0137] like Figure 1As shown, the fractionation system 115 receives steam cracker effluent (via line 113). While these functions can be combined in a single separator (e.g., a fractionator), fractionation facilities typically include a gas-liquid separator vessel (e.g., a tar separation drum) and a fractionator (e.g., a primary fractionator). The gas-liquid separator vessel is configured to separate the predominantly gaseous upgraded steam cracker effluent from a predominantly liquid bottom stream containing SCT, such as ≥90% by weight of the bottom stream from the tar separation drum. SCT may be present in the quenched steam cracker effluent and / or may be formed from at least a portion of the SCT precursors in the quenched steam cracker effluent. The upgraded steam cracker effluent is directed to a fractionator configured to separate various products and co-products from the upgraded steam cracker effluent.

[0138] like Figure 1 As shown, the bottom stream containing SCT can be removed via line 117. In addition to the tar separation drum, the fractionation system 115 also includes a primary fractionator and a quench tower. The quench tower and primary fractionator can be combined in a single vessel (e.g., one above the other), but this is not required. Conventional tar separation drums, primary fractionators, and quench towers can be used, but the invention is not limited thereto. Suitable primary fractionators and related equipment are described in U.S. Patent No. 8,083,931 and U.S. Patent Publication No. 2016 / 0376511, which are incorporated herein by reference. If desired, additional stages for heat removal (e.g., one or more transfer line heat exchangers) and tar removal (e.g., tar drum) can be located in or upstream of the primary fractionator.

[0139] In addition to the quenching performed in the furnace facility, the quenched steam cracker effluent may undergo further cooling or quenching before and / or during its introduction into the tar separation drum. The temperature of the quenched steam cracker effluent entering the tar separation drum should be sufficiently low to separate the SCT from the quenched steam cracker effluent and to accumulate the separated SCT in the lower region of the tar separation drum. It can be observed that SCT separates rapidly at temperatures of approximately 350°C or lower, for example, approximately 200°C to approximately 350°C or approximately 240°C to approximately 320°C.

[0140] Conventional tar separation drums can be used, but the invention is not limited thereto. For example, a tar separation drum can be a simple empty container without distillation plates or stages. In some embodiments, the tar separation drum is an open flash zone at the bottom of a fractionating column, such as in the flash zone of a primary fractionator. If desired, multiple separation drums can be connected in parallel, allowing individual drums to be taken out of service and cleaned while the equipment is operating. SCTs typically have a T 90The standard boiling point range is typically ≥290°C, for example ≥500°C, such as ≥600°C or higher, and generally comprises molecules, compounds, aggregates, and mixtures thereof with a molecular weight of about 212 g / mol or higher. SCT accumulated in the tar separation drum typically has an initial standard boiling point of ≥150°C, for example ≥200°C, such as about 150°C to about 320°C. Optionally, a purge stream can be introduced into the tar separation drum to reduce liquid-vapor contact. Typically, the purge stream is selected from steam, inert gases such as nitrogen, and substantially non-condensable hydrocarbons, such as those obtained from steam cracking, examples of which include steam cracker gases and tail gas.

[0141] Optionally, additional quenching of the quenched steam cracker effluent is performed within the separation drum. This additional quenching can be achieved by passing the quenched steam cracker effluent feed through a cold (less than 350°C) quenching fluid (e.g., one or more of the aforementioned quenching fluids). The cold quenching fluid can be generated by feeding the SCT stream taken from the bottom of the tar separation drum through a suitable heat exchanger (e.g., a shell-and-tube exchanger, a spiral wound exchanger, an air-finned exchanger, or a coaxial exchanger) and circulating the cooled SCT stream back to the tar separation drum. In at least one embodiment, sufficient cooling SCT is circulated to reduce the temperature of the accumulated SCT in the tar separation drum from about 280°C to about 150°C. A reduced rate of asphaltenes and SCT accumulation in line 113 and the tar separation drum is observed when the accumulated SCT has a temperature of about 280°C or lower, compared to the significantly higher temperature of the steam cracker effluent exiting the radiant coil outlet. In another embodiment, circulation is sufficient to reduce the viscosity of the SCT removed from the tar separation drum to a level sufficient to meet viscosity specifications, without or reducing the need for additional light blending feedstock from external sources that would otherwise be necessary without such circulation. In another embodiment, cooled SCT is introduced into the separation vessel to provide the tar within the vessel with an average temperature of about 175°C or lower, for example, about 150°C or lower. The quenching method can be adjusted to prevent asphaltenes formation. Asphaltenes formation of up to about 70% by weight can be prevented by quenching the steam cracker effluent via line 113 or within the tar separation drum.

[0142] Back Figure 1 The effluent from the upgrading steam cracker is directed to fractionation system 115 to separate it into multiple hydrocarbon product streams. The fractionation system typically includes a primary fractionator and a quench tower. Product streams that can be separated from the upgrading steam cracker effluent include one or more of the following: (i) an oily bottom stream that can be used as quench oil, and (ii) an SCGO stream, which is carried away via line 119, said SCGO typically containing about 90% by weight or more of C based on the weight of the SCGO. 10 -C 17Hydrocarbons, and having a T90 boiling point of about 160°C to about 290°C, (iii) a heavy pyrolysis gasoline feed stream ("heavy cracked gasoline feed stream" or "steam cracker naphtha"), which is carried away via pipeline 121, typically including C5-C 10 Hydrocarbons, and (iv) a process gas stream that is primarily gaseous, are carried away via line 123. Typically, pyrolysis results in a transfer of ≥0.5% (by weight) of sulfur from the pyrolysis feed to the heavy pyrolysis gasoline stream, for example, ≥1% by weight, for example, ≥2% by weight, or ≥5% by weight, or ≥10% by weight, or ≥20% by weight, or 0.5% to 50% by weight, or 1% to 25% by weight.

[0143] The upgraded steam cracker effluent can be introduced into the primary fractionator in a manner that reduces contact with vapor in the fractionator for more efficient fractionation. For example, injecting the upgraded steam cracker effluent into the vapor space within the fractionator may result in undesirable vapor absorption into the effluent. Conversely, introducing the upgraded steam cracker effluent near the liquid-gas interface at the bottom of the primary fractionator has been observed to reduce vapor absorption into the effluent. Unnecessary baffles placed above the gas-liquid interface can further reduce contact between the fractionation feed and vapor. Optionally or additionally, the upgraded steam cracker effluent can be introduced into the primary fractionator in a manner that reduces contact with liquid in the fractionator. The fractionation feed can be injected into the vapor space, allowing for rapid separation of the vapor and liquid components within the fractionation feed.

[0144] Because most (if not all) of the SCT is separated from the steam cracker effluent in the tar separation drum, the liquid phase of the primary fractionator contents primarily comprises heavy hydrocarbons. This predominantly liquid heavy hydrocarbon bottom stream can be carried away from the primary fractionator via line 117, for example, as quench oil. The viscosity of the primary fractionator bottom stream can be controlled by adding a light blend, which can be added directly to the bottom of the primary fractionator to provide cooling for the SCT stream. Such a light blend may include SCGO, distillate quench oil, and catalytic cycle oil, and is characterized by a viscosity of about 1,000 centistokes (cSt) or less at a temperature of 93°C, for example, about 500 cSt or less, or about 100 cSt or less.

[0145] SCGO can be condensed (or otherwise removed) from the vapor phase within the primary fractionator. The predominantly vapor-phase top stream is carried away from the primary fractionator, or alternatively from the primary fractionator section of a combined primary fractionator-quencher. The quenching medium in such a quencher is typically water, which can be obtained from various sources, such as circulating refinery water, circulating wastewater, purified fresh water, purified wastewater, sulfur-containing water stripper bottoms, top condensate, boiler feedwater, or from other water sources or combinations thereof. Water is typically recycled from downstream oil-water separators, sulfur-containing water separators, and cracked gasoline stripper towers. The quencher condenses at least a portion of the cracked gasoline present in the vapor effluent and a large portion of the steam supplied to the furnace. In some aspects, the top stream from the primary fractionator is fed into a quencher (or the quench section of a combined primary fractionator-quencher), where the vapor is rapidly cooled (quenched) as it passes through water (vapor or liquid). The condensed cracked gasoline and heated quench water are discharged as cracked gasoline feed 121 from a position near the bottom of the quench tower.

[0146] A predominantly gaseous top feed stream (referred to herein as the "process gas stream") is removed from the quench tower and conveyed via line 123 to the process gas compressor unit 145 to produce a compressed process gas stream. The process gas stream typically contains molecular hydrogen, light hydrocarbons (saturated and unsaturated hydrocarbons), acid gases, and various forms of sulfur, which are predominantly gaseous under fractionation conditions present where the quench tower top distillate is removed from the quench tower. Other forms of sulfur are removed from other locations, such as from fractionator side fractions and fractionator bottoms. When using specified hydrocarbon feeds and specified steam cracker conditions, the process gas stream may contain, for example, about 10% by weight or more of C. 2+ Olefins, about 1% by weight or more of C 6+ Aromatic hydrocarbons and / or about 0.1% by weight or more of any of the following: dienes, saturated hydrocarbons, molecular hydrogen, acetylene, CO2, aldehydes, and C. 1+ Thiols. The sulfur content ("third" sulfur content) of the process gas feed stream is less than the second sulfur content of the steam cracker effluent from line 113. In some embodiments, the third sulfur content of the light hydrocarbon feed stream line 123 is about 7,500 wppm or less, for example, about 5,000 wppm or less.

[0147] Sulfur-containing water stripping tower and dilution steam system

[0148] For example, any hydrocarbons present in the quench water recovered from the quench tower (or a combined quench tower-primary fractionator) can be separated from the recovered water in one or more oil-water separators. These hydrocarbons typically have a standard boiling point range spanning quench oil, SCGO, and cracked gasoline. The separated water components from the oil-water separator can be recycled to a water regeneration system 127 via a water circulation line 125, which may include a sulfur-containing water stripper and / or a dilution steam generator. The sulfur-containing water stripper removes at least a portion of any hydrogen sulfide and at least a portion of any ammonia present in the circulating water. Sulfur-containing water stripping typically provides at least partial degassing of the sulfur-containing water, removing at least a portion of any remaining light hydrocarbon vapors and at least a portion of any remaining molecular hydrogen from the circulating water. The sulfur-containing water stripper can be a steam reboiler distillation column, which allows for the overhead stripping of hydrogen sulfide and ammonia. Once the acid gases and ammonia are removed, the stripped water can be heated to generate steam, for example, in a dilution steam generator. The dilution steam can be circulated via the following lines: (i) to the hydrocarbon feed in line 101 via line 129, (ii) to the preheated hydrocarbon feed in line 105 via line 131, (iii) to the fractionation system 115 via line 133, (iv) to the dilution steam discharge system (not shown) via line 135, or (v) any combination thereof. The overhead distillate from the sulfur-containing water stripper can be conveyed via line 137 to the water purging unit 139. The water purging unit 139 includes a condenser and a drum to allow the purging of H2S and ammonia (NH3) from the overhead of the sulfur-containing water stripper. Partially upgraded water is generated in this process and can be circulated via line 141 to the fractionation system or via line 143 for storage and / or for other processes.

[0149] Process gas flow and compressor equipment group

[0150] Process gas flow is transmitted through pipeline 123 (from Figure 1 The gas is guided from the top of the quench tower to one or more stages of the compressor unit 145 to form a compressed process gas stream. Any water and heavy hydrocarbons recovered during and / or as a result of compression can be recycled to the fractionation system via line 147 for reuse.

[0151] Although not required, the present invention is compatible with combining process gas streams (or one or more streams derived therefrom) with one or more refinery and / or petrochemical processing streams (e.g., processes for producing one or more of fuels, lubricants, and petrochemicals). This has been found to be effective, particularly when the available refinery streams contain molecular hydrogen and / or C2 to C4 olefins. For example, during reduced process gas flow intervals, excess capacity in the process gas stream processing and separation stages can be used to (i) remove one or more desired products, such as C2-C4 olefins, from the refinery and / or petrochemical streams, and (ii) unnecessarily recycle any remaining portion of the refinery and / or petrochemical stream (e.g., the portion containing saturated hydrocarbons) for cracking as feedstock to a steam cracker and / or for combustion in a steam cracker burner, burners in other furnaces, etc. The process gas streams (or streams derived therefrom) can be combined with one or more refinery and / or petrochemical processing streams upstream and / or downstream of compressor unit 145. Alternatively or additionally, one or more of the indicated material flows may be combined between one or more stages of the compressor unit 145.

[0152] Suitable refinery and petrochemical feedstocks include those obtained or derived from one or more of the following: cracking; hydrotreating; alcohol production and / or alcohol conversion; reforming; natural gas to olefins; polymerization, including oligomerization; hydrocarbon combustion; and hydrocarbon distillation. Representative cracking methods include thermal cracking and / or catalytic cracking, such as fluidized bed catalytic cracking. Representative hydrotreating methods include catalytic and / or non-catalytic hydrotreating, such as hydrotreatment, hydrogenation (including hydrodearomatization), hydrodewaxing, dehydrogenation, hydrocracking, hydroisomerization, and / or ring opening, among one or more of these. Representative alcohol production and / or alcohol conversion methods include, for example, catalytic and / or non-catalytic methods, such as alcohol synthesis methods (including carbonyl synthesis of alcohols) and alcohol conversion methods, such as catalytic and / or non-catalytic alcohol dehydration.

[0153] In some aspects, process gas feed streams are combined with light hydrocarbon gases obtained from fluidized bed catalytic cracking (FCC) processes (e.g., process gas feed streams originating from the top of FCC fractionators). Suitable fluidized bed catalytic crackers and associated equipment and methods of operation may include those disclosed in Handbook of Petroleum Refining Processes, 2nd Edition, RA; Meyers, 3.3-3.111, McGraw-Hill, but the invention is not limited thereto. For example, refinery feed streams containing light hydrocarbon products originating from FCC processes (e.g., from the top of FCC fractionators) can be used... Figure 1One or more locations in the process shown are combined with process gas feed streams (not shown), for example, by introducing light hydrocarbon products into one or more of lines 123, 149, 153, 161, and 165; at least one stage in compression unit group 145; and one or more of containers 151, 155, and 163. The location of the introduction of light hydrocarbon products into the process may depend primarily on the type and amount of impurities present therein. For example, in addition to light olefins, light hydrocarbon products may contain one or more of molecular hydrogen, methane, ethane, propane, butane, ammonia, carbon dioxide, arsine, mercury, hydrogen sulfide, carbonyl sulfides, thiols and carbon disulfides, oxygenates, and water.

[0154] In some aspects, the light hydrocarbon product is treated to at least partially remove one or more of the non-olefin compounds shown. Pretreatment may include, for example, demethanizing the light hydrocarbon product in one or more demethanizing towers to produce a tail gas and demethanized C2O3. 2+ Products. Conventional demethanizing towers, such as one or more cryogenic demethanizing towers and / or one or more absorption demethanizing towers, can be used, but the invention is not limited thereto. Additional pretreatment stages can be used, such as for the demethanized C4 products. 2+ Other non-hydrocarbon compounds are removed from the product. This additional pretreatment stage may include stages for removing at least a portion of one or more of ammonia, carbon dioxide, arsine, mercury, hydrogen sulfide, carbonyl sulfides, thiols and carbon disulfide, oxygen-containing compounds, and water. The pretreated light hydrocarbon product may be introduced into the process gas stream and / or a stream derived from the process gas stream as shown.

[0155] Alternatively or additionally, at least a portion of one or more of the indicated refinery and / or petrochemical processing feed streams may be combined with the feed to a steam cracker, such as with one or more of hydrocarbon feed, desalting feed, preheated feed, and pyrolysis feed. This may be done with little or no pretreatment of the refinery and / or petrochemical processing feed streams.

[0156] For simplicity, the following description will refer to the processing of compressed process gas streams that have not yet been combined with refinery and / or petrochemical processing streams. The invention is not limited to this form of process gas stream processing, and this description should not be construed as excluding other forms within the broader scope of the invention, such as those involving the combination of process gas streams with refinery and / or petrochemical processing streams.

[0157] Acid gas removal system

[0158] The compressed process gas stream can be conveyed via line 149 to amine tower 151 and alkali tower 155 to produce a purified process gas stream. The amine tower accepts a light amine stream, including aqueous solutions of one or more of ethanolamine, diethanolamine, methyldiethanolamine, diisopropanolamine, diethylene glycolamine, and other amines. The amine tower removes acid gases, such as hydrogen sulfide and carbon dioxide, from the amine-rich stream to form a light hydrocarbon product stream. Suitable amine towers are described in U.S. Patent Nos. 4,100,257; 4,112,051; and 4,894,178, which are incorporated herein by reference. The partially purified process gas stream is directed from the amine tower to the alkali tower for further processing. The amine tower removes the major amounts of H2S and CO2 carried with the process gas stream, for example, removing substantially all of these acid gases. The alkali tower can be used to remove other forms of sulfur, such as C1 and C2 mercaptans, for example, substantially all of these compounds. Conventional alkali towers can be used, but the invention is not limited thereto.

[0159] exist Figure 1 In the aspect schematically illustrated, alkali tower 155 is configured to contact a partially purified process gas stream with a caustic alkali solution disposed within the tower. The caustic alkali solution may comprise any alkaline reagent capable of extracting at least a portion of any remaining acidic gases (including, for example, hydrogen sulfide, carbon dioxide, and thiols) from the partially purified process gas stream. For example, the caustic alkali solution may comprise an aqueous solution of ammonia or an alkali metal hydroxide (e.g., sodium hydroxide or potassium hydroxide). The tower may accept fresh caustic alkali from line 157 and release spent caustic alkali via line 159 for regeneration. Conventional alkali towers and amine towers may be used, but the invention is not limited thereto. Suitable alkali towers are described in U.S. Patent Nos. 2,998,382; 3,107,213 and 5,209,828, which are incorporated herein by reference. The purified process gas stream is carried away via line 161.

[0160] Continue to refer to Figure 1 The purified process gas stream is delivered via line 161 to adsorbent system 163, which removes at least a portion of any residual water and, unnecessarily, at least a portion of any residual nitrogen oxides from the purified process gas stream to produce an upgraded process gas stream. The upgraded process gas stream is directed via line 165 to an additional product separation and purification stage, such as for the recovery of ethylene and propylene. When regeneration of one or more adsorbents in adsorbent system 163 is required, the waste regeneration medium can be removed via line 167 for storage and / or further processing.

[0161] The upgraded gas stream can be fed to a light hydrocarbon recovery unit for separation and further purification of various hydrocarbon streams before further purification. (Continuing to refer to...) Figure 2This section describes some aspects of the light hydrocarbon recovery unit assembly in more detail. Among these aspects, initial separation is performed, wherein molecular hydrogen, methane, C2 hydrocarbons, and some C2 hydrocarbons are separated from the upgraded process gas stream in fractionator 317. 3+ The first feed stream of hydrocarbons and containing C 3+ The second feed stream of hydrocarbons. The invention is not limited to these aspects, and this description should not be construed as excluding other light hydrocarbon recovery apparatuses 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 contains C 4+ Those hydrocarbons. In other words, the main components of the recovery facility can be in direct and / or indirect fluid communication.

[0162] Light hydrocarbon recovery equipment group

[0163] exist Figure 2 In the aspects shown, separator 317 is used to separate at least (i) from the upgraded process gas stream attributable to molecular hydrogen, methane, and C2 hydrocarbons (containing some C2 hydrocarbons) removed via line 319. 3+ (ii) the flow of material containing C removed via pipeline 321; and (ii) the material containing C removed via pipeline 321. 3+ Hydrocarbon feed stream. Fractionator 323 is used to extract hydrocarbon feed from a stream containing C. 3+ The hydrocarbon stream is separated from at least (i) a stream containing C3 hydrocarbons removed via line 325, and (ii) a stream containing C2 hydrocarbons removed via line 327. 4+ Hydrocarbon feed stream. Fractionator 329 is used to extract hydrocarbons from a stream containing C... 4+ The hydrocarbon stream is separated from at least (i) a stream containing C4 hydrocarbons removed via pipeline 331, and (ii) a stream containing C4 hydrocarbons removed via pipeline 333. 5+ Cracking gasoline feed stream of hydrocarbons. Cracking gasoline obtained by separation and stripping from quench water associated with the quench tower can be introduced into the cracking gasoline feed stream of line 333 via line 207 to produce a combined cracking gasoline feed stream.

[0164] Non-essential C4 recovery systems can be used, such as systems including equipment for fractionating, isomerizing, and / or hydrogenating the C4 hydrocarbon stream removed via line 331. The C4 recovery system can be used to recover one or more of butane, 1-butene, 2-butene, butadiene, or other products as needed. Conventional C4 recovery systems can be used, but the invention is not limited thereto.

[0165] The combined cracked gasoline feed stream can be directed through gasoline hydrogenation stage 209 to produce various gasoline products delivered via line 335. Gasoline hydrogenation stage 209 may include one or more units for cracked gasoline hydrogenation, a tail column, and additional fractionators (not shown). In at least one embodiment, gasoline hydrogenation stage 209 includes a first cracked gasoline hydrogenation unit located upstream of the tail column, wherein the tail column is located upstream of a second cracked gasoline hydrogenation stage. In some aspects, at least two streams are separated from the hydrotreating processor effluent 335: (i) a feed stream containing at least a portion of C5 hydrocarbons and any remaining DMS and (ii) C... 6+ Hydrocarbon feed stream (which typically contains small amounts of C5 hydrocarbons and DMS). If desired, at least a portion of the DMS in the C5 hydrocarbon feed stream can be converted into higher molecular weight sulfur compounds. C... 6+ The hydrocarbon feed stream is introduced into a depentanizer to recover purified C. 6+ Bottom stream and top stream that can be further processed to obtain additional DMS.

[0166] The C3 hydrocarbon-containing feed stream is typically directed via line 325 to an additional processing stage, which may include (i) a bed 337 for removing at least a portion of any methanol and COS, then via line 339 to (ii) a bed 341 for removing arsenic, and via line 343 to (iii) a methylacetylene and propadiene (MAPD) ​​converter 345 for hydrogenation. The purified C3 hydrocarbon-containing feed stream is directed via line 347 to a C3 splitter 349 (e.g., a fractionator) to separate at least propylene (delivered via line 351) and propane (delivered via line 353). The propane from line 353 can be recycled for further cracking or for other refinery processes. The sulfur content of the COS-lean C3 hydrocarbon feed stream can be measured according to ASTM D5504. The sulfur content of propylene can be measured according to ASTM D5504 (if measured as a gas) and ASTM D5623 (if measured as a compressed liquid). Suitable COS removal systems are described in U.S. Patent Nos. 4,217,237; 4,217,238; and 7,427,385, which are incorporated herein by reference.

[0167] The feed stream carried away from separator 317 via line 319 is conveyed to compressor 355 for further compression (e.g., compressor 355 is located downstream of compressor 301). This will contain compressed molecular hydrogen, methane, and C2 hydrocarbons (containing some C...). 3+ The feed stream is directed from compressor 355 via line 357 to a series of purification processes, which may include (i) a carbonyl sulfide removal bed 359, then via line 361 to (ii) an arsine bed 363, then via line 365 to (iii) a C2 acetylene converter 367. The feed will contain molecular hydrogen, methane, ethane, ethylene, and some C2...3+ The purified feed stream is conveyed via line 369 to separator 371. Separator 371 is used to separate at least (i) a first feed stream containing molecular hydrogen and methane, which has been removed via line 373, from at least a portion of the purified feed stream from line 369; and (ii) a second feed stream containing C2 hydrocarbons, which is conveyed via line 381 to fractionator 383. Fractionator 383 is used to separate (i) any residual C2 hydrocarbons from this second feed stream. 3+ For example, a feed line 325 is used for circulation via line 385 to the methanol / COS bed 337; and (ii) a feed stream containing purified C2 hydrocarbons, which is removed via line 387 to a C2 splitter 389. The C2 splitter 389 is used to separate at least (i) ethylene (delivered via line 391) and (ii) ethane (delivered via line 393) from the purified C2 hydrocarbons. The sulfur content of the ethylene can be measured according to ASTM D5504 (if measured as a gas) and ASTM D5623 (if measured as a compressed liquid).

[0168] Ethane can be recycled for further cracking or for use in other refinery processes. Additional separation may be performed, for example, using separator 375 to separate at least (i) methane removed via line 377 and (ii) molecular hydrogen removed via line 379 from the tail gas stream of line 373. At least a portion of the separated methane can be used as fuel gas and / or the steam can be cracked again to produce syngas and hydrogen. At least a portion of the separated molecular hydrogen can be recycled to one or more hydrogenation units, for example, as a hydrogen source in one or more SCT hydrotreatment stages.

[0169] Removal of sulfur compounds

[0170] H2S can be removed at various locations according to the methods, systems, and processes covered by the broader scope of this invention. Even so, sufficient H2S removal can be achieved by operating a combination of amine and alkali towers. In at least one embodiment, the amine tower removes about 99% by weight or more of H2S from the compressed process gas stream, and the alkali tower removes substantially all remaining H2S from the partially purified process gas stream. Some small amounts (about 10 w ppm or less) of H2S can be found in the aqueous phase of dilution steam or various water purgings, which can be recycled to a quench tower or a sulfur-containing water stripping tower. Because H2S may be entrained in the water, a portion of the steam cracking process can undergo metallurgical upgrading of one or more hydrocarbon streams to address corrosion that may be caused by H2S in the circulating water.

[0171] Similarly, methyl mercaptan (MM) can be removed at different locations. An amine column can remove approximately 20% by weight or more of MM from a compressed process gas stream, depending on the amount of H2S and CO2 in the liquid on the trays within the amine column. An alkali column can remove approximately ≥70% by weight of residual MM from a partially purified process gas stream, for example, ≥80% by weight, or ≥90% by weight or more. It may be desirable for C4 recovery systems to include a stage for the hydrogenation of C4 hydrocarbons, for example, to remove butadiene. Some catalysts used for hydrogenation to remove butadiene have an upper limit of approximately 1 w ppm of MM in the C4 hydrocarbon stream. In these respects, any residual MM in the C4 hydrocarbon stream can be removed prior to hydrogenation, for example, by treatment with a caustic alkali.

[0172] Similarly, ethyl mercaptan (EM) can also be removed at various locations, such as in the amine tower and / or the alkali tower. The amine tower can remove approximately 20% by weight or more of EM from the compressed process gas stream, depending on the amount of H2S and CO2 in the liquid on the trays within the amine tower. The alkali tower can remove approximately 85% by weight or more of EM from the partially purified process gas stream. Any EM retained in the upgraded process gas stream is typically present in the combined cracked gasoline stream (hydrotreating unit 245). In aspects using at least two cracked gasoline hydrogenation stages, a tail tower is provided between them, where approximately 95% or more of EM is converted to a heavy sulfur form in the first cracked gasoline hydrogenation stage and separated and removed along with the hydrogenated heavy oil byproducts.

[0173] Similarly, carbonyl sulfides (COS) can be removed at various locations, including amine and alkali towers. Amine towers can remove approximately 50% by weight or more of COS from the compressed process gas stream, depending on the amount of H2S and CO2 in the liquid on the trays within the amine tower. Alkali towers do not significantly reduce the amount of COS in the partially purified process gas stream. Any residual COS in the upgraded process gas stream is typically present in the C2 and C3 hydrocarbon streams in a mass ratio ranging from approximately 25:75 to 75:25. Because some acetylene converter catalysts and some MAPD converter catalysts are sensitive to sulfur compounds, an adsorbent bed for COS removal is typically included before each of these converters. However, it is generally observed that COS is essentially absent in the C4 hydrocarbon stream.

[0174] Similarly, carbon disulfide (CS2) can be removed at various locations. CS2 is removed in fractionation system 115 ( Figure 1The process gas stream is divided into two streams, with approximately 80% by weight flowing to the amine tower. 90% by weight or more of the remaining CS2 is observed in the bottom stream 117 and the cracked gasoline stream 121. The amine tower typically removes approximately 15% or more of the CS2 from the compressed process gas stream. The alkali tower does not significantly reduce the amount of CS2 in the partially purified process gas stream. Any residual CS2 in the upgraded process gas stream is typically present in the combined cracked gasoline stream. In aspects using at least two cracked gasoline hydrogenation stages, a tail tower is provided between them, where approximately 95% or more of the CS2 is converted to a heavy sulfur form in the first cracked gasoline hydrogenation stage and separated and removed along with the hydrogenated heavy oil byproducts.

[0175] Although dimethyl sulfide (DMS) is not typically removed from the compressed or partially purified process gas streams in the amine and alkali towers, it can be found in considerable quantities in the combined cracked gasoline streams. In aspects using at least two cracked gasoline hydrogenation stages, a tail tower is provided between them, where approximately 95% or more of the DMS is converted to a heavy sulfur form in the first cracked gasoline hydrogenation stage and separated and removed along with the hydrogenated heavy oil byproducts. In aspects where the hydrogenated cracked gasoline stream is to be blended with gasoline, a hydrodesulfurization unit may be included as part of the cracked gasoline processing.

[0176] The major amount of thiophene sulfur (e.g., thiophene) in the effluent from the upgraded steam cracker is fed in fractionation unit 115 to cracked gasoline feed stream 121, and from there via line 207 to the combined cracked gasoline feed stream. In the aspect where at least two cracked gasoline hydrogenation stages are used, with a tail column between them, the first hydrotreating stage converts about 10% to about 30% by weight of thiophene. In the aspect including a tail column upstream of a second hydrotreating stage, about 20% to about 25% by weight of thiophene is then fed to the bottom of the tail column and removed along with heavy oil byproducts. Those skilled in the art will understand that, due to these findings regarding the separation and removal of thiophene from the process, the second hydrotreating stage can be readily configured to remove most (if not all) of the remaining thiophene fed there from the tail column.

[0177] The sulfur forms in the steam cracker effluent, which have a standard boiling point range substantially the same as those in the SCT, are removed along with the bottom stream from the tar separation drum. This stream can typically be hydrotreated in the presence of a hydrocarbon diluent to convert at least a portion of the sulfur forms in the SCT into predominantly gaseous forms (e.g., H₂S) with lower standard boiling points. After H₂S separation, the upgraded SCT can then be removed.

[0178] Design of light hydrocarbon recovery equipment group

[0179] Another aspect of this disclosure is the design of refinery and / or petrochemical equipment systems to compensate for varying levels of sulfur compounds in hydrocarbon feedstocks, which can be selected from a variety of crude oils with different forms and amounts of sulfur compounds. The use of hydrocarbon feedstocks with higher sulfur compound content may involve modifications or upgrades to portions of the steam cracking process and / or specific equipment.

[0180] In at least one embodiment, the first sulfur content is used to determine whether a tail column should be connected after a first hydrotreating stage or a second hydrotreating stage in a multi-stage hydrotreating system. For example, if the first sulfur content is about 4% by weight or higher, a tail column configuration downstream of the first hydrotreating stage may be preferred, and / or if the first sulfur content is about 3% by weight or lower, a tail column configuration downstream of the second hydrotreating stage may be preferred to produce a purified cracked gasoline product stream suitable for blending with gasoline products.

[0181] Example

[0182] Table 1 illustrates the typical range of sulfur-containing compositions (in wppm) in high-sulfur hydrocarbon feedstocks following flash separation vessel and also following steam cracking.

[0183] Table 1

[0184]

[0185] Sulfur compounds can be effectively managed by various removal techniques according to the systems, methods, and processes of the present invention, as shown in Table 2, which are composed of mixtures of representative hydrocarbon feedstocks containing crude oil. For example, a combination of an amine tower and an alkali tower can remove approximately ≥90 wt% H2S, approximately ≥70 wt% MM, approximately ≥50 wt% EM, approximately ≥50 wt% COS, and approximately ≥15 wt% CS2 from the process gas stream. A cracked gasoline hydrotreating unit (e.g., stage 209) can remove substantially all remaining EM, CS2, and thiophene (depending on the number of stages) from cracked gasoline and / or combined cracked gasoline.

[0186] Table 2

[0187]

[0188] In summary, it has been found that a portion of the various forms of sulfur that can be introduced into steam cracking processes can be converted into other forms of sulfur in a predictable and predetermined manner. It has also been found that the predictable and predetermined nature of the indicated conversions can be utilized to configure steam crackers and recovery facilities for the efficient steam cracking of hydrocarbon feedstocks containing heavy hydrocarbons and significant amounts of sulfur. In particular, predetermined recovery facilities can be configured without excessive experimentation, which has so far been required to: (i) effectively remove sulfur (in the form of sulfur converted by steam cracking and the form of sulfur not converted by steam cracking) and (ii) recover desired products that meet or exceed product specifications, such as ethylene, propylene, C4 hydrocarbons, and C6 hydrocarbons. 5+ Hydrocarbons. In other words, the discovery of various forms of sulfur fractionation at different stages of the steam cracking process allows for the design of steam cracking processes and equipment that can produce hydrocarbon products with less sulfur content than those of existing technologies.

[0189] This disclosure may also include at least non-limiting aspects and / or implementation methods:

[0190] A1. Steam cracking methods, including:

[0191] A hydrocarbon feed comprising hydrocarbons and sulfur is provided, the hydrocarbon feed having a first sulfur content;

[0192] The hydrocarbon feed is introduced into a steam cracker integrated with a flash separation vessel to produce a steam cracker effluent with a second sulfur content that is less than the first sulfur content.

[0193] Remove the sulfur-rich feed stream from the flash separation vessel; and

[0194] The steam cracker effluent is introduced into a recovery facility to generate a process gas stream, wherein the process gas stream has a third sulfur content, which is less than the second sulfur content, and wherein the process gas stream contains H2S and methyl mercaptan.

[0195] The method of A2.A1, wherein the first sulfur content is at least 0.07% by weight, based on the total weight of the hydrocarbon feed.

[0196] The method of A3.A2, wherein the first sulfur content is at least 1.0% by weight, based on the total weight of the hydrocarbon feed.

[0197] The methods of any one of A4, A1 to A3 also include:

[0198] The process gas stream is introduced into the compressor unit to generate a compressed process gas stream;

[0199] The compressed process gas stream is introduced into the amine tower, thereby removing most of the H2S and a portion of the methyl mercaptan from the compressed process gas stream to form a partially purified process gas stream.

[0200] The partially purified process gas stream is introduced into an alkali tower, thereby removing a portion of the H2S and methyl mercaptan from the compressed process gas stream to produce a purified process gas stream with a fourth sulfur content lower than the third sulfur content; and

[0201] At least a portion of the water contained in the purified process gas stream is removed to obtain an upgraded process gas stream.

[0202] The method of A5.A4, wherein the amine tower comprises a tray having an outer weir of at least 75 mm.

[0203] The method of A6, A4 or A5, wherein the alkali tower includes a once-through caustic cycle, wherein a fresh caustic alkali feed stream enters the top of the alkali tower and exits at the bottom of the top section of the alkali tower to a caustic alkali treatment unit, so as to achieve the removal of at least 80% of methyl mercaptan from the compressed process gas stream by using the combination of the amine tower and the alkali tower.

[0204] The method of any one of A7, A4 to A6, wherein the process gas stream further comprises ethyl mercaptan, and a portion of the ethyl mercaptan is removed in the amine tower, and a portion of the ethyl mercaptan is removed in the alkali tower.

[0205] The method of any one of A8, A4 to A6, wherein the process gas stream further comprises COS, and a portion of the COS is removed in the amine tower.

[0206] The methods in A9 and A8 also include:

[0207] The process gas stream generates C containing acetylene and COS. 3- Hydrocarbon flow;

[0208] From the C 3- At least a portion, preferably substantially all, of the COS is removed from the hydrocarbon feed stream to obtain purified COS. 3- Hydrocarbon flow; and

[0209] Make the C 3- The hydrocarbon feed stream flows to the acetylene converter to convert at least a portion of the acetylene into olefins in the presence of an acetylene conversion catalyst.

[0210] The method of A10.A9, wherein the yetne converter is a front-end converter.

[0211] The method of A11.A9, wherein C 3- The hydrocarbon feed stream is a C3 hydrocarbon feed stream, and the alkyne converter is a MAPD converter.

[0212] A12. The method of any of the above implementation schemes further includes:

[0213] The process gas stream generates a C4 hydrocarbon stream containing methyl mercaptan and 1,3-butadiene;

[0214] The C4 hydrocarbon stream is passed through a second alkali tower to remove the methyl mercaptan, thereby obtaining a purified C4 hydrocarbon stream; and

[0215] The purified C4 hydrocarbon stream is contacted with molecular hydrogen and a hydrogenation catalyst to produce an upgraded C4 hydrocarbon stream containing less 1,3-butadiene than the purified C4 hydrocarbon stream.

[0216] A13. The method of any one of claims A4 to A12, wherein the process gas stream further comprises CS2, and a portion of the CS2 is removed in the amine tower.

[0217] A14. The method of any of the above implementation schemes further includes:

[0218] A cracked gasoline stream is produced from a process gas stream containing ethyl mercaptan and / or CS2;

[0219] It is not necessary to produce a heavy pyrolysis gasoline feedstock containing CS2 from the steam cracker effluent; and

[0220] The cracked gasoline feed stream is hydrotreated in a hydrorefining unit in the presence of a hydrorefining catalyst, which is not necessarily combined with the heavy cracked gasoline feed stream.

[0221] A15. The method of any of the above embodiments, wherein the process gas stream comprises dimethyl sulfide, and the method further comprises:

[0222] A cracked gasoline feed stream is generated from a process gas feed stream containing dimethyl sulfide;

[0223] Unnecessarily, the steam cracker effluent is used to produce a heavy cracked gasoline feedstock containing dimethyl sulfide; and

[0224] The cracked gasoline feed stream is optionally combined with the heavy cracked gasoline feed stream and subjected to hydrodesulfurization to remove at least a portion of the dimethyl sulfide therein.

[0225] A16. The method of any of the above embodiments, wherein the process gas stream comprises thiophene, and the method further comprises:

[0226] A cracked gasoline feed stream is generated from a process gas feed stream containing thiophene;

[0227] Optionally, the steam cracker effluent is used to produce a heavy cracked gasoline feedstock containing thiophene; and

[0228] The cracked gasoline feed stream, which may be combined with the heavy cracked gasoline feed stream, is subjected to hydrogenation to remove at least a portion of the thiophene therein.

[0229] A17. Steam cracking methods, including:

[0230] A hydrocarbon feedstock is provided, wherein (i) the hydrocarbon feedstock comprises hydrocarbons and sulfur, and (ii) the hydrocarbon feedstock has a first sulfur content;

[0231] The hydrocarbon feed is preheated to produce a preheated feed;

[0232] The preheated feed is combined with steam to produce a steam cracking feed;

[0233] Separate a bottom stream, which is mainly liquid, and a pyrolysis feed, which is mainly gas, from the steam cracking feed, wherein ≥20% (by weight) of sulfur from the hydrocarbon feed is present in the pyrolysis feed;

[0234] The pyrolysis feed is pyrolyzed under pyrolysis conditions to produce steam cracker effluent;

[0235] Separating steam cracker tar and upgraded steam cracker effluent from the steam cracker effluent, wherein ≥25% of the sulfur in the pyrolysis feed is present in the steam cracker tar; and

[0236] The effluent from the upgraded steam cracker is separated into a liquid-phase pyrolysis gasoline and a gas-phase process gas stream, wherein ≥0.5% (by weight) of sulfur from the pyrolysis feed is present in the pyrolysis gasoline.

[0237] The method of A18.A17, wherein at least a portion of the preheating is carried out in a convection section of at least one steam cracker, wherein the steam cracker further includes a gas-liquid separator integrated with and in fluid communication with the convection section, and a pyrolysis section in fluid communication with the convection section.

[0238] The method of A19.A18, wherein (i) the pyrolysis feed separation is carried out in a gas-liquid separator, (ii) the pyrolysis feed is directed to a pyrolysis section, (iii) at least a portion of the pyrolysis is carried out in the pyrolysis section, and (iv) the steam cracker effluent is removed from the pyrolysis section.

[0239] The method of any one of A20, A17 to A19 further includes quenching the steam cracker effluent before separating the steam cracker tar and the upgraded steam cracker effluent.

[0240] The method of any one of A21, A18-A20, wherein the sulfur in the pyrolysis feed comprises 0.5% to 50% by weight (based on weight) in the pyrolysis gasoline.

[0241] A23. The method of any of the above embodiments, wherein 25% to 75% by weight of sulfur in the hydrocarbon feed is present in the pyrolysis feed.

[0242] A24. The method of any one of A18-A23, wherein (i) ≥25% by weight of sulfur in the hydrocarbon feed is present in the bottom stream, wherein ≥90% by weight of the remaining sulfur in the hydrocarbon feed is present in the pyrolysis feed, and (ii) ≥25% by weight of hydrocarbons in the hydrocarbon feed is present in the pyrolysis feed, wherein ≥90% by weight of the remaining hydrocarbons in the hydrocarbon feed is present in the bottom stream.

[0243] The method of any one of A25, A18-A24 further includes (i) recovering a stream containing C4 hydrocarbons and sulfur from the process gas stream and removing sulfur from one or more of the cracked gasoline, the steam cracker tar and the stream containing C4 hydrocarbons and sulfur.

[0244] A26. A processing system for hydrocarbon feed containing sulfur and hydrocarbons, said system comprising:

[0245] At least one steam cracker in fluid communication with the source fluid of the hydrocarbon feed;

[0246] A flash separation vessel in fluid communication with the steam cracker;

[0247] At least one recovery facility in fluid communication with the steam cracker and downstream of the steam cracker, wherein the recovery facility comprises:

[0248] (i) Compressor equipment group;

[0249] (ii) An amine tower connected to the compressor unit and downstream of the compressor unit;

[0250] (iii) An alkali tower that is fluidly connected to the amine tower and downstream of the amine tower;

[0251] (iv) A dryer that is fluidly connected to the alkali tower and located downstream of the alkali tower;

[0252] (v) A C2 separator in fluid communication with the dryer;

[0253] (vi) A C3 separator in fluid communication with the dryer;

[0254] (vii) A first COS remover in fluid communication with the C2 separator;

[0255] (viii) An acetylene converter that is in fluid communication with the first COS remover and is downstream of the first COS remover;

[0256] (ix) a second COS remover in fluid communication with the C3 separator; and

[0257] (x) A methylacetylene and propadiene (MAPD) ​​converter that is in fluid communication with the second COS remover and is downstream of the second COS remover.

[0258] The system of A27.A26, wherein the C2 separator is in direct and / or indirect fluid communication with the dryer.

[0259] In systems A28, A26, or A27, wherein the C3 separator is in direct and / or indirect fluid communication with the dryer.

[0260] The system of any one of A29, A26-A28 further includes a C2 splitter in fluid communication with the acetylene converter and a C3 splitter in fluid communication with the MAPD converter.

[0261] A30. Steam cracking methods, including:

[0262] Provides hydrocarbon feedstock containing hydrocarbons and sulfur;

[0263] The hydrocarbon feed is introduced into a steam cracker to produce steam cracker effluent;

[0264] The steam cracker effluent is introduced into a recovery facility to generate a process gas stream containing mercaptans, C2, C3 and C4 hydrocarbons;

[0265] Separating C4 hydrocarbons and thiols from the process gas stream; and

[0266] The separated C4 hydrocarbons are upgraded, wherein at least a portion of the separated thiols is removed prior to the upgrading.

[0267] A31. Steam cracking methods, including:

[0268] Provides hydrocarbon feedstock containing hydrocarbons and sulfur;

[0269] The hydrocarbon feed is introduced into a steam cracker to produce a product containing dimethyl sulfide, C2-C4 hydrocarbons, and C... 5+ Hydrocarbon steam cracker effluent;

[0270] Separate at least a portion containing the dimethyl sulfide and the C from the steam cracker effluent. 5+ A mixture of at least a portion of hydrocarbons;

[0271] Hydrotreating the mixture to convert at least a portion of the dimethyl sulfide therein into a high molecular weight sulfur compound and to produce a hydrotreating processor effluent; and

[0272] Separate from the hydrotreating processor effluent (i) a second mixture containing at least a portion of C5 hydrocarbons and the dimethyl sulfide and (ii) C 6+ Hydrocarbon flow.

[0273] While certain ranges are explicitly disclosed, a range from any lower limit can be combined with any upper limit to describe a range not explicitly stated, and a range from any lower limit can be combined with any other lower limit to describe a range not explicitly stated, and in the same manner, a range from any upper limit can be combined with any other upper limit to describe a range not explicitly stated. Furthermore, each point or individual value between the two endpoints is included in the range, even if not explicitly stated. Thus, each point or individual value can itself serve as a lower or upper limit, combined with other points or individual values ​​or other lower or upper limits to define a range not explicitly stated. Those skilled in the art will understand that, although certain aspects have been shown and described in more detail, various modifications can be made without departing from the spirit and scope of this disclosure. Similarly, it should be understood that the term "comprising" is considered synonymous with the term "including," and whenever a composition, element, or group of elements precedes the transitional phrase "comprising," it should be understood that we also consider the same composition or group of elements preceding the description of the composition, element, or plurality of elements with the transitional phrase "consistently composed of," "composed of," "selected from," or "is," and vice versa.

Claims

1. Steam cracking methods, including: A hydrocarbon feed comprising hydrocarbons and sulfur is provided, the hydrocarbon feed having a first sulfur content, wherein the first sulfur content is 2.0%-5.0% by weight, based on the total weight of the hydrocarbon feed; The hydrocarbon feed is introduced into a steam cracker integrated with a flash separation vessel to produce a steam cracker effluent with a second sulfur content that is less than the first sulfur content. Remove the sulfur-rich feed stream from the flash separation vessel; and The steam cracker effluent is introduced into a recovery facility to generate a process gas stream, wherein the process gas stream has a third sulfur content, which is less than the second sulfur content, and wherein the process gas stream contains H2S and methyl mercaptan. and The method further includes: The process gas stream is introduced into the compressor unit to generate a compressed process gas stream; The compressed process gas stream is introduced into the amine tower, thereby removing most of the H2S and a portion of the methyl mercaptan from the compressed process gas stream to form a partially purified process gas stream. The partially purified process gas stream is introduced into an alkali tower, thereby removing a portion of the H2S and methyl mercaptan from the compressed process gas stream to produce a purified process gas stream with a fourth sulfur content lower than the third sulfur content; and At least a portion of the water contained in the purified process gas stream is removed to obtain an upgraded process gas stream.

2. The method of claim 1, wherein the amine tower comprises a tray having an outer weir of at least 75 mm.

3. The method of claim 1 or claim 2, wherein the alkali tower comprises a single-pass caustic alkali circulation, wherein a fresh caustic alkali feed stream enters the top of the alkali tower and exits at the bottom of the top section of the alkali tower to a caustic alkali treatment unit, so as to achieve the removal of at least 80% of methyl mercaptan from the compressed process gas feed stream by using the combination of the amine tower and the alkali tower.

4. The method of any one of claims 1 to 3, wherein the process gas stream further comprises ethyl mercaptan, and a portion of the ethyl mercaptan is removed in the amine tower, and a portion of the ethyl mercaptan is removed in the alkali tower.

5. The method of any one of claims 1 to 4, wherein the process gas stream further comprises COS, and a portion of the COS is removed in the amine tower.

6. The method of claim 5, further comprising: The process gas stream generates C containing acetylene and COS. 3- Hydrocarbon flow; From the C 3- At least a portion, preferably substantially all, of the COS is removed from the hydrocarbon feed stream to obtain purified COS. 3- Hydrocarbon flow; and Make the C 3- The hydrocarbon feed stream flows to the acetylene converter to convert at least a portion of the acetylene into olefins in the presence of an acetylene conversion catalyst.

7. The method of claim 6, wherein the alkyne converter is a front-end converter.

8. The method of claim 6, wherein C 3- The hydrocarbon feed stream is a C3 hydrocarbon feed stream, and the alkyne converter is a MAPD converter.

9. The method of any one of the preceding claims further comprises: The process gas stream generates a C4 hydrocarbon stream containing methyl mercaptan and 1,3-butadiene; The C4 hydrocarbon stream is passed through a second alkali tower to remove the methyl mercaptan, thereby obtaining a purified C4 hydrocarbon stream; and The purified C4 hydrocarbon stream is contacted with molecular hydrogen and a hydrogenation catalyst to produce an upgraded C4 hydrocarbon stream containing less 1,3-butadiene than the purified C4 hydrocarbon stream.

10. The method of any one of claims 1 to 9, wherein the process gas stream further comprises CS2, and a portion of the CS2 is removed in the amine tower.

11. The method of any one of the preceding claims further comprises: The process gas stream generates a cracked gasoline stream containing ethyl mercaptan and / or CS2; Unnecessarily, a heavy pyrolysis gasoline feedstock containing CS2 is produced from the steam cracker effluent; and The cracked gasoline feed stream is hydrotreated in a hydrorefining unit in the presence of a hydrorefining catalyst, which is not necessarily combined with the heavy cracked gasoline feed stream.

12. The method of any of the preceding claims, wherein the process gas stream comprises dimethyl sulfide, and the method further comprises: A cracked gasoline feed stream is generated from a process gas feed stream containing dimethyl sulfide; Unnecessarily, the steam cracker effluent is used to produce a heavy cracked gasoline feedstock containing dimethyl sulfide; and The cracked gasoline feed stream is optionally combined with the heavy cracked gasoline feed stream and subjected to hydrodesulfurization to remove at least a portion of the dimethyl sulfide therein.

13. The method of any of the preceding claims, wherein the process gas stream comprises thiophene, and the method further comprises: A cracked gasoline feed stream is generated from a process gas feed stream containing thiophene; Unnecessarily, a heavy cracked gasoline feedstock containing thiophene is produced from the steam cracker effluent; and The cracked gasoline feed stream, which may be combined with the heavy cracked gasoline feed stream, is subjected to hydrogenation to remove at least a portion of the thiophene therein.

14. Steam cracking methods, including: Provide a hydrocarbon feedstock, wherein (i) the hydrocarbon feedstock comprises hydrocarbons and sulfur, and (ii) the hydrocarbon feedstock has a first sulfur content, wherein the first sulfur content is 2.0%-5.0% by weight, based on the total weight of the hydrocarbon feedstock; The hydrocarbon feed is preheated to produce a preheated feed; The preheated feed is combined with steam to produce a steam cracking feed; Separate a bottom stream, which is mainly liquid, and a pyrolysis feed, which is mainly gas, from the steam cracking feed, wherein ≥20% (by weight) of sulfur from the hydrocarbon feed is present in the pyrolysis feed; The pyrolysis feed is pyrolyzed under pyrolysis conditions to produce steam cracker effluent; Separating steam cracker tar and upgraded steam cracker effluent from the steam cracker effluent, wherein ≥25% of the sulfur in the pyrolysis feed is present in the steam cracker tar; and The pyrolysis feedstock is separated from the effluent of the upgraded steam cracker into a liquid-phase pyrolysis gasoline and a gas-phase process gas stream, wherein ≥0.5% (by weight) of sulfur from the pyrolysis feedstock is present in the pyrolysis gasoline. and The method further includes: The process gas stream is introduced into the compressor unit to generate a compressed process gas stream; The compressed process gas stream is introduced into the amine tower, thereby removing most of the H2S and a portion of the methyl mercaptan from the compressed process gas stream to form a partially purified process gas stream. The partially purified process gas stream is introduced into an alkali tower, thereby removing a portion of the H2S and methyl mercaptan from the compressed process gas stream to produce a purified process gas stream with a fourth sulfur content lower than the third sulfur content; and At least a portion of the water contained in the purified process gas stream is removed to obtain an upgraded process gas stream.

15. The method of claim 14, wherein 0.5% to 50% by weight (based on weight) of sulfur in the pyrolysis feedstock is present in the pyrolysis gasoline.

16. The method of claim 14 or claim 15, wherein 25% to 75% by weight of sulfur in the hydrocarbon feed is present in the pyrolysis feed.

17. The method of any one of claims 14 to 16, wherein (i) ≥25% by weight of sulfur in the hydrocarbon feed is present in the bottom stream, wherein ≥90% by weight of the remaining sulfur in the hydrocarbon feed is present in the pyrolysis feed, and (ii) ≥25% by weight of hydrocarbons in the hydrocarbon feed is present in the pyrolysis feed, wherein ≥90% by weight of the remaining hydrocarbons in the hydrocarbon feed is present in the bottom stream.

18. The method of any one of claims 14 to 17, further comprising (i) recovering a stream containing C4 hydrocarbons and sulfur from the process gas stream and removing sulfur from one or more of the cracked gasoline, the steam cracker tar, and the stream containing C4 hydrocarbons and sulfur.

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