阅读说明：本技术 重质燃料油到化学产品的转化 (Conversion of heavy fuel oil to chemical products ) 是由 U·K·慕克吉 于 2018-12-28 设计创作，主要内容包括：用于将高硫燃料油转化为石化产品的方法和系统,包括在燃料油加氢裂化器中加氢裂化高硫燃料油以形成裂化的燃料油流出物,该裂化的燃料油流出物可以分离为轻质馏分和重质馏分。可以使重质馏分气化以产生合成气,并且该合成气或从该合成气中回收的氢气可以被送至燃料油加氢裂化器。轻质馏分可以在馏出物加氢裂化器中加氢裂化以形成裂化的流出物,该裂化的流出物可以分离为氢气馏分、轻质烃馏分、轻质石脑油馏分以及重质石脑油馏分。重质石脑油馏分可以被重整以生产氢气以及苯、甲苯和二甲苯中的至少一种。轻质烃馏分和/或轻质石脑油馏分可以被蒸汽裂化以生产乙烯、丙烯、苯、甲苯和二甲苯中的至少一种。(A method and system for converting high sulfur fuel oil to petrochemicals includes hydrocracking the high sulfur fuel oil in a fuel oil hydrocracker to form a cracked fuel oil effluent that can be separated into a light fraction and a heavy fraction. The heavy fraction may be gasified to produce synthesis gas, and the synthesis gas or hydrogen recovered from the synthesis gas may be sent to a fuel oil hydrocracker. The light fraction may be hydrocracked in a distillate hydrocracker to form a cracked effluent, which may be separated into a hydrogen fraction, a light hydrocarbon fraction, a light naphtha fraction, and a heavy naphtha fraction. The heavy naphtha fraction may be reformed to produce hydrogen and at least one of benzene, toluene, and xylene. The light hydrocarbon fraction and/or the light naphtha fraction may be steam cracked to produce at least one of ethylene, propylene, benzene, toluene, and xylene.)

1. A process for converting high sulfur fuel oil to petrochemicals, the process comprising:

hydrocracking the high sulfur fuel oil in an ebullated bed or slurry bed fuel oil hydrocracker to form a cracked fuel oil effluent;

separating the cracked fuel oil effluent into a light fraction and a heavy fraction;

hydrocracking the light fraction in a distillate hydrocracker to form a cracked effluent;

separating the cracked effluent into a hydrogen fraction, a light hydrocarbon fraction, a light naphtha fraction, and a heavy naphtha fraction;

reforming the heavy naphtha fraction to produce a reformer effluent comprising hydrogen and at least one of benzene, toluene, and xylene;

steam cracking the light hydrocarbon fraction and/or the light naphtha fraction to produce a steam cracker effluent comprising at least one of ethylene, propylene, benzene, toluene, and xylene.

2. The method of claim 1, further comprising:

gasifying the heavy fraction to produce a synthesis gas comprising carbon monoxide and hydrogen; and

passing the synthesis gas or hydrogen recovered from the synthesis gas to the fuel oil hydrocracker.

3. The method of claim 1, further comprising separating the steam cracker effluent into a hydrogen fraction, one or more light olefin fractions, one or more aromatic fractions, and a thermally cracked gas oil fraction.

4. The process of claim 3, further comprising sending a hydrogen fraction of the steam cracker effluent to the distillate hydrocracker.

5. The method of claim 3, further comprising sending the thermally cracked gas oil fraction to the fuel oil hydrocracker.

6. The method of claim 1, further comprising separating the reformer effluent to form a hydrogen fraction and one or more aromatic fractions.

7. The method of claim 6, further comprising sending a hydrogen fraction of the reformer effluent to the distillate hydrocracker.

8. A system for converting high sulfur fuel oil to petrochemicals, the system comprising:

an ebullated or slurry bed fuel oil hydrocracker for hydrocracking high sulfur fuel oil to form a cracked fuel oil effluent;

a first separation system for separating the cracked fuel oil effluent into a light fraction and a heavy fraction;

a distillate hydrocracker for hydrocracking the light fraction to form a cracked effluent;

a second separation system for separating the cracked effluent into a hydrogen fraction, a light hydrocarbon fraction, a light naphtha fraction, and a heavy naphtha fraction;

a catalytic reformer for reforming the heavy naphtha fraction to produce a reformer effluent comprising hydrogen and at least one of benzene, toluene, and xylene;

a steam cracker for steam cracking the light hydrocarbon fraction and/or the light naphtha fraction to produce a steam cracker effluent comprising at least one of ethylene, propylene, benzene, toluene and xylene.

9. The system of claim 8, further comprising:

a gasifier for gasifying said heavy fraction to produce a synthesis gas comprising carbon monoxide and hydrogen; and

a flow line for sending the synthesis gas or hydrogen recovered from the synthesis gas to the fuel oil hydrocracker.

10. The system of claim 8, further comprising a third separation system for separating the steam cracker effluent into a hydrogen fraction, one or more light olefin fractions, one or more aromatic fractions, and a thermally cracked gas oil fraction.

11. The system of claim 10, further comprising a flow line for sending a hydrogen fraction of the steam cracker effluent to the distillate hydrocracker.

12. The system of claim 10, further comprising a flow line for sending the thermally cracked gas oil fraction to the fuel oil hydrocracker or the distillate hydrocracker or both.

13. The system of claim 8, further comprising a fourth separation system for separating the reformer effluent to form a hydrogen fraction and one or more aromatic fractions.

14. The system of claim 13, further comprising a flow line for sending the hydrogen fraction of the reformer effluent to the distillate hydrocracker.

15. The system of claim 8, further comprising a separator for separating the thermally cracked gas oil fraction into a light thermally cracked gas oil fraction and a heavy thermally cracked gas oil fraction.

16. The system of claim 15, further comprising a flow line for sending the heavy thermally cracked gas oil fraction to the fuel oil hydrocracker and a flow line for sending the light thermally cracked gas oil fraction to the distillate hydrocracker.

17. A process for converting high sulfur fuel oil to petrochemicals, the process comprising:

hydrocracking a high sulfur fuel oil in an ebullated bed or slurry bed fuel oil hydrocracker to form a cracked fuel oil effluent;

separating the cracked fuel oil effluent into a light fraction and a heavy fraction;

hydrocracking the light fraction in a distillate hydrocracker to form a cracked effluent;

separating the cracked effluent to recover one or more gas fractions comprising hydrogen, hydrogen sulfide and/or ammonia, and to recover two or more hydrocarbon fractions including a light hydrocarbon fraction and a heavy hydrocarbon fraction;

hydrocracking the heavy hydrocarbon fraction to produce a hydrocracked effluent comprising a naphtha range and lighter hydrocarbons;

sending the light hydrocarbon fraction and the hydrocracking effluent to an ethylene complex plant to produce petrochemicals comprising ethylene, propylene, butadiene, benzene, toluene, xylene, and/or methyl tertiary butyl ether.

18. The method of claim 17, further comprising:

gasifying the heavy fraction to produce a synthesis gas comprising carbon monoxide and hydrogen; and

passing the synthesis gas or hydrogen recovered from the synthesis gas to the fuel oil hydrocracker.

19. The method of claim 17, further comprising sending the heavy fraction to a delayed coking unit or a cement plant.

20. The process of claim 17, wherein the heavy fraction is an IMO compliant ultra low sulfur fuel oil containing less than 0.5 wt% sulfur.

21. The method of claim 17, wherein the production of petrochemicals at an ethylene complex plant comprises one or more of steam cracking, catalytic cracking, metathesis, etherification, butadiene extraction, aromatic extraction, and/or disproportionation.

22. The method of claim 17, wherein the hydrocracking the light fraction in a distillate hydrocracker to form a cracked effluent comprises:

reacting the light fraction in a first reaction zone comprising a hydrotreating catalyst;

reacting the effluent of the first reaction zone in a second reaction zone comprising an unsupported trimetallic catalyst; and is

Reacting the effluent of the second reaction zone in a third reaction zone comprising a nitrogen tolerant hydrocracking catalyst.

23. A process according to claim 22, wherein each of the first, second and third reaction zones is operated at a temperature in the range of about 340 ℃ to about 430 ℃, a pressure in the range of about 150bara to about 180bara, about 0.5h^-1To about 2.5h^-1In the liquid hourly space velocity range of (a).

24. The method of claim 17, wherein the hydrocracking the heavy hydrocarbon fraction to produce a hydrocracked effluent comprising a naphtha range and lighter hydrocarbons comprises:

reacting the heavy hydrocarbon fraction in a reaction zone comprising an unsupported trimetallic catalyst; and is

Reacting the effluent of the reaction zone in a downstream reaction zone comprising a noble metal zeolite catalyst.

25. A process according to claim 24, wherein each of the reaction zone and the downstream reaction zone is operated at a temperature in the range of from about 300 ℃ to about 400 ℃, a pressure in the range of from about 150bara to about 180bara, about 0.5h^-1To about 3.0h^-1In the liquid hourly space velocity range of (a).

26. The process of claim 17, wherein the hydrocracking of the high sulfur fuel oil in a fuel oil hydrocracker comprises subjecting the high sulfur fuel oil to a temperature range of about 390 ℃ to about 440 ℃, a pressure range of about 170bara to about 195bara, about 0.1h^-1To about 0.5h^-1Is operated in a liquid hourly space velocity range.

27. A system for converting high sulfur fuel oil to petrochemicals, the system comprising:

an ebullated or slurry bed hydrocracker for hydrocracking high sulfur fuel oil to form a cracked fuel oil effluent;

a separator for separating the cracked fuel oil effluent into a light fraction and a heavy fraction;

a distillate hydrocracker for hydrocracking the light fraction to form a cracked effluent;

a separation system for separating the cracked effluent to recover one or more gas fractions comprising hydrogen, hydrogen sulfide and/or ammonia, and to recover two or more hydrocarbon fractions including a light hydrocarbon fraction and a heavy hydrocarbon fraction;

a hydrocracker for hydrocracking the heavy hydrocarbon fraction to produce a hydrocracked effluent comprising a naphtha range and lighter hydrocarbons;

an ethylene complex plant for converting the light hydrocarbon fraction and the hydrocracking effluent to produce petrochemicals including ethylene, propylene, butadiene, benzene, toluene, xylene and/or methyl tertiary butyl ether.

28. The system of claim 27, further comprising:

a gasifier for gasifying said heavy fraction to produce a synthesis gas comprising carbon monoxide and hydrogen; and

a flow line for sending said syngas or hydrogen recovered from said syngas to said fuel oil hydrocracker.

29. The system of claim 27, wherein the ethylene complex plant comprises one or more of a steam cracker, a catalytic cracker, a metathesis unit, an etherification unit, a butadiene extraction unit, an aromatics extraction unit, and/or a disproportionation unit.

30. The system of claim 27, wherein the distillate hydrocracker comprises:

a first reaction zone comprising a hydrotreating catalyst;

a second reaction zone comprising an unsupported trimetallic catalyst; and

a third reaction zone comprising a nitrogen tolerant hydrocracking catalyst.

31. The system of claim 27, wherein the hydrocracker for hydrocracking the heavy hydrocarbon fraction to produce a hydrocracked effluent comprises:

a reaction zone comprising an unsupported trimetallic catalyst; and

a downstream reaction zone comprising a noble metal zeolite catalyst.

Background

To date, most crude oils are partially converted into chemical products in large refinery-petrochemical complex plants. The emphasis of refineries is on the production of transportation fuels such as gasoline and diesel. Low value streams from refineries (e.g., LPG and light naphtha) are sent to petrochemical complex plants that may or may not be adjacent to the refinery. The petrochemical complex then produces chemical products such as benzene, para-xylene, ethylene, propylene, and butadiene. Such a typical complex plant is shown in fig. 1, wherein the units and streams are indicated by the following reference numerals.

Fuel oils that can be produced from the resid conversion unit of a refinery typically contain high sulfur contents. International Maritime Organization (IMO) is currently considering regulations to reduce sulfur emissions from ships. Specifically, the new requirement is expected to reset sulfur emissions from the current maximum 3.5 wt% on fuel content to 0.5 wt%.

Typically, refiners have sold vacuum residua from their refineries as high sulfur fuel oils, blended the vacuum residua to form low sulfur fuel oils, or converted the vacuum residua to vacuum gas oils or lighter distillates using residua hydrocracking or delayed coking, or in some cases, desulfurized the vacuum residua to oils suitable for addition to the residua FCC unit. Alternatively, the vacuum resid can be sent to a resid hydrocracking unit to convert the vacuum resid to vacuum gas oil and other light fractions, which can be sent for further upgrading in a distillate hydrotreating unit or a distillate hydrocracking unit. Alternatively, the vacuum residue may be sent to a sulfur deasphalting unit to recover a deasphalted oil fraction, which may be blended with high sulfur fuel oil or low sulfur fuel oil, or used as road asphalt where possible.

Each of these applications involves the production of transportation fuels and is associated with oil refineries. In each case, high sulfur fuel oil will be a very low value product. Furthermore, in the near future, the above IMO regulations may eliminate the path to market high sulfur fuels.

Disclosure of Invention

The embodiments herein relate to a process for directly converting high sulfur fuel oils to petrochemicals to produce higher value end products. IMO regulations will result in an unacceptable and very low value surplus of high sulfur fuel oil as feedstock. The embodiments herein convert low value fuel oil to petrochemicals rather than transportation fuels. The embodiments herein may also maintain hydrogen equilibrium.

In one aspect, embodiments disclosed herein relate to a method for converting high sulfur fuel oil to petrochemicals. The process can include hydrocracking a high sulfur fuel oil in an ebullated bed or slurry bed fuel oil hydrocracker to form a cracked fuel oil effluent. The cracked fuel oil effluent can be separated into a light fraction and a heavy fraction. The light fraction may be hydrocracked in a distillate hydrocracker to form a cracked effluent, which may be separated into a hydrogen fraction, a light hydrocarbon fraction, a light naphtha fraction and a heavy naphtha fraction. The heavy naphtha fraction can be reformed to produce a reformer effluent comprising hydrogen and at least one of benzene, toluene, and xylene. The light hydrocarbon fraction and/or the light naphtha fraction may be steam cracked in a steam cracker to produce a steam cracker effluent comprising at least one of ethylene, propylene, benzene, toluene, and xylene.

In some embodiments, the heavy fraction may be gasified to produce a syngas comprising carbon monoxide and hydrogen. The synthesis gas or hydrogen recovered from the synthesis gas may be sent to a fuel oil hydrocracker. In other embodiments, the heavy fraction (unconverted oil) may be sent to a delayed coking unit, a cement plant, or, in the case where the heavy fraction is an IMO compliant ultra low sulfur fuel oil, it may be used internally or sold as a high value product.

In another aspect, embodiments disclosed herein relate to a system for converting high sulfur fuel oil to petrochemicals. The system may include an ebullated bed or slurry bed fuel hydrocracker for hydrocracking high sulfur fuel oil to form a cracked fuel oil effluent. A first separation system may be provided for separating the cracked fuel oil effluent into a light fraction and a heavy fraction. The system may also include a gasifier for gasifying the heavy fraction to produce a syngas comprising carbon monoxide and hydrogen. A flow line may be provided for sending the synthesis gas or hydrogen recovered from the synthesis gas to a fuel oil hydrocracker. The system may further include a distillate hydrocracker, a catalytic reformer, and a steam cracker. The distillate hydrocracker may hydrocrack the light fraction to form a cracked effluent, and a second separation system may separate the cracked effluent into a hydrogen fraction, a light hydrocarbon fraction, a light naphtha fraction, and a heavy naphtha fraction. The catalytic reformer may reform the heavy naphtha fraction to produce a reformer effluent comprising hydrogen and at least one of benzene, toluene, and xylene. The steam cracker may crack the light hydrocarbon fraction and/or the light naphtha fraction to produce a steam cracker effluent comprising at least one of ethylene, propylene, benzene, toluene, and xylene.

In another aspect, embodiments disclosed herein relate to a method for converting high sulfur fuel oil to petrochemicals. The process can include hydrocracking a high sulfur fuel oil in an ebullated bed or slurry bed fuel oil hydrocracker to form a cracked fuel oil effluent. The cracked fuel oil effluent may then be separated into a light fraction and a heavy fraction. The process may also include hydrocracking the light fraction in a distillate hydrocracker to form a cracked effluent, and separating the cracked effluent to recover one or more gaseous fractions (e.g., hydrogen sulfide, and/or ammonia), and recovering two or more hydrocarbon fractions (including a light hydrocarbon fraction and a heavy hydrocarbon fraction). The heavy hydrocarbon fraction may then be hydrocracked to produce a hydrocracked effluent comprising naphtha range hydrocarbons and lighter hydrocarbons. The light hydrocarbon fraction and the hydrocracked effluent may be sent to an ethylene complex to produce petrochemicals including ethylene, propylene, butadiene, benzene, toluene, xylene, and/or methyl tertiary butyl ether.

In another aspect, embodiments disclosed herein relate to a system for converting high sulfur fuel oil to petrochemicals. The system may include an ebullated bed or slurry bed fuel oil hydrocracker for hydrocracking high sulfur fuel oil to form a cracked fuel oil effluent. The system may also include a separator for separating the cracked fuel oil effluent into a light fraction and a heavy fraction. A distillate hydrocracker may be provided for hydrocracking the light fraction to form a cracked effluent. A separation system may be provided for separating the cracked effluent to recover one or more gaseous fractions comprising hydrogen, hydrogen sulfide and/or ammonia, and to recover two or more hydrocarbon fractions including a light hydrocarbon fraction and a heavy hydrocarbon fraction. The system may also include a hydrocracker for hydrocracking the heavy hydrocarbon fraction to produce a hydrocracked effluent comprising naphtha range hydrocarbons and lighter hydrocarbons. An ethylene complex plant may be provided for converting the light hydrocarbon fraction and the hydrocracking effluent to produce petrochemicals including ethylene, propylene, butadiene, benzene, toluene, xylene and/or methyl tertiary butyl ether.

Other aspects and advantages will be apparent from the following description and appended claims.

Drawings

Fig. 1 is a simplified process flow diagram of a typical refinery-petrochemical complex.

Fig. 2 is a simplified process flow diagram of a process for converting high sulfur fuel oil to petrochemicals according to embodiments herein.

Fig. 3 is a simplified process flow diagram of a process for converting high sulfur fuel oil to petrochemicals according to embodiments herein.

Fig. 3A is a simplified process flow diagram of an integrated two-stage hydrocracking system that may be used in a process for converting high sulfur fuel oil to petrochemicals according to embodiments herein.

Fig. 4 is a simplified process flow diagram of a process for converting high sulfur fuel oil to petrochemicals according to embodiments herein.

Detailed Description

Embodiments herein relate to methods and systems that can directly convert high sulfur fuel oils to petrochemicals. Feedstocks useful in the examples herein include High Sulfur Fuel Oil (HSFO). HSFO as used herein refers to fuel oil having a sulfur content of greater than 1 wt%. Other feedstocks useful in the examples herein may include, for example, pitch from a solvent deasphalting unit, decant oil, and thermal cracking fuel oil from a steam cracker. In some embodiments, the feedstock may be a blend of high sulfur fuel oil and thermal cracking fuel oil. The feedstock herein may include vacuum gas oil obtained from a residue conversion process that has not only sulfur but also a relatively high content of polycyclic aromatic compounds as well as nitrogen content.

The feedstocks used in the examples herein typically have a sulfur content of greater than 0.5 wt%, in other embodiments greater than 1.0 wt%, in other embodiments greater than 2.0 wt%, and in other embodiments may be up to 7.0 wt%. Typically, the density of the feedstock at 15 ℃ is greater than 900kg/m³And/or the kinematic viscosity at 50 ℃ may be at least 180mm²And s. The initial boiling point of the feedstock may be greater than 350 ℃ in some embodiments; and may be greater than 450 ℃ in other embodiments; and in other embodiments may be greater than 580 deg.c. Typically, the initial boiling point of the feedstock is greater than 500 ℃. Although HSFO is defined above as containing greater than 1 wt% sulfur, the values described herein refer to feedstocks that are useful in the examples herein, and feedstocks other than HSFO may have lower sulfur content.

The feedstock herein is converted to petrochemicals including light olefins using an integrated high pressure hydrocracker, wherein the HSFO cracker may be a single high pressure loop utilizing a two stage system with recycle. Those skilled in the art generally do not suggest converting low hydrogen content feedstocks (e.g., HSFO) into petrochemicals. However, embodiments herein may use a combination of catalysts, process conditions, and process units as described below to efficiently and effectively convert such feedstocks to petrochemicals.

The HSFO can be converted to a Vacuum Gas Oil (VGO) (typically at 370 ℃ to 580 ℃) product in an ebullated bed or slurry bed hydrocracking unit. The hydrocracking unit may utilize an extrudate in an ebullated bed reactor (a heterogeneous reactor using liquid circulation) or a slurry catalyst in the presence of hydrogen (a homogeneous reactor). The slurry catalyst can be used in a liquid circulation reactor such as an EB reactor or a slurry bubble phase reactor. This fuel oil hydrocracking step is referred to herein as step 1.

The conversion in the hydrocracking unit is only partial. In some embodiments, unreacted oil or bitumen may be sent to the gasifier. The gasifier may be used to convert unconverted oil or bitumen into syngas, providing hydrogen for the fuel oil hydrocracking step and the subsequent integrated distillate hydrocracking step (described below). The gasifier may also be used to generate electricity, if desired. In other embodiments, the heavy fraction (unconverted oil) may be sent to a delayed coking unit or a cement plant. In a further example, an ultra low sulfur fuel oil can be recovered from the hydrocracking unit (step 1), which can be used internally or sold as a high value product.

The fuel oil hydrocracking step (step 1) is integrated with the hydrocracking step (step 2) which further converts the product from step 1 into heavy naphtha, light naphtha, LPG and lighter products (e.g. ethane). The product from step 1 is a meta-aromatic and therefore not suitable for steam cracking to produce olefins. Step 2 hydrogenates the product from step 1 and hydrocracks the VGO and diesel range material to naphtha which is more suitable as a feed to a downstream ethylene complex plant which may include, for example, a steam cracker for the production of olefins.

In some embodiments, step 2 and step 1 may share the same high pressure hydrogen loop.

Step 2 may comprise an integrated two-stage hydrocracking system.

The ethane, LPG and/or naphtha products from step 2 may then be sent to an ethylene complex plant, which may include a steam cracker. The heavy naphtha rich in naphthenes from step 2 may be sent to a reactor for catalytic reforming if desired. The process is also flexible and the light naphtha stream as well as part or all of the heavy naphtha stream can be fed to a steam cracker where more olefins are required than aromatics.

Both the ethylene compounding plant and the catalytic reformer produce hydrogen. The hydrogen can be sent back to step 1 and step 2. In this way, the integrated unit can maintain hydrogen equilibrium or be substantially in hydrogen equilibrium, producing most or all of the hydrogen internally. Furthermore, in some embodiments, the thermally cracked gas and/or thermally cracked fuel oil produced in the ethylene complex plant may be used as an additional feedstock for the fuel oil hydrocracking step 1.

An ethylene compounding plant useful in the embodiments herein may include various unit operations. For example, the ethylene complex plant may include a cracker, such as a steam cracker. Other cracking operations may also be used. The ethylene complex plant may also include an olefin recovery unit, a butadiene extraction unit, an MTBE unit, a C4 selective hydrogenation unit, a pyrolysis gasoline hydrotreating unit, an aromatics extraction unit, a metathesis unit, and/or a disproportionation unit, etc., that may be used to produce and recover olefins and other light hydrocarbons. The products of an ethylene compounding plant may include, for example, ethylene, propylene, butadiene, benzene, MTBE, mixed xylenes, and the like.

The process disclosed herein does not rely on refineries to produce petrochemicals. For example, a system according to embodiments herein may be located proximate to a petrochemical complex plant having an imported high sulfur fuel oil as the sole feed. After IMO regulations are enforced in 2020, the price of high sulfur fuel oil may be much lower than crude oil, and the embodiments herein may convert these low cost feedstocks into higher value petrochemicals. Embodiments herein may also eliminate the need for refineries and the need to produce any transportation fuels from these low value hydrocarbons, may greatly reduce investment costs through integration, and/or may provide excellent export of thermally cracked fuel oil from steam crackers.

Referring now to fig. 2, a simplified process flow diagram of a method for converting high sulfur fuel oil to petrochemicals according to embodiments herein is shown. The high sulfur fuel oil 100 can be sent to a fuel oil hydrocracking reaction zone 102, which fuel oil hydrocracking reaction zone 102 can include one or more slurry or ebullated bed fuel oil hydrocrackers that can operate in series and/or parallel. The high sulfur fuel oil 100 can be reacted with hydrogen (from 108, 122, 130, described below) over a hydrocracking catalyst in a slurry or ebullated bed fuel oil hydrocracker to convert at least a portion of the fuel oil hydrocarbons to lighter molecules.

For example, in some embodiments, the hydrocracker in the fuel oil reaction zone may be operated under conditions to provide a conversion of 40 wt% to 98 wt%; in other embodiments, a conversion of greater than 60 wt% may be provided; in other embodiments, a conversion of greater than 80 wt% may be provided. The hydrocracking reaction in the fuel oil hydrocracking reaction zone may be carried out at a temperature in the range of from about 360 ℃ to about 460 ℃; in other embodiments, it may be performed at a temperature in the range of about 400 ℃ to about 440 ℃. In some embodiments, the pressure in the fuel oil hydrocracking reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, it may be in the range of about 100bara to about 180 bara. In some embodiments, the hydrocracking reaction may also be at about 0.1hr^-1To about 3.0hr^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2hr^-1To about 2hr^-1Is carried out within the range of (1).

Hydrocarbon conversion is defined herein as the percentage of material in the reactor feed stream that boils above a temperature threshold (described below) minus the percentage of material in the reactor effluent that boils above the same temperature threshold and dividing the difference by the percentage of material in the reactor feed stream that boils above the temperature threshold. In some embodiments, for example for the conversion of high sulfur fuel oils, the threshold temperature may be defined as 500 ℃, e.g., 520 ℃ or another TBP cut point designated for the feed fuel oil grade hydrocarbon; in other embodiments, the threshold temperature may be defined as 540 ℃ + and in other embodiments, the threshold temperature may be defined as 560 ℃ +.

The hydrocarbon effluent from the ebullated bed or slurry bed hydrocracker may then be separated into a light (converted) hydrocarbon fraction 110 and a heavy (unconverted) hydrocarbon fraction 104. The final boiling point of the light hydrocarbon fraction may range from about 450 ℃ to about 550 ℃, for example about 520 ℃ in some embodiments. The light hydrocarbon fraction 110 may then be forwarded to a distillate hydrocracking reaction stage 112.

The heavy hydrocarbon fraction 104 may be sent to a gasifier 106 and converted to syngas, which may include CO and H₂And other by-products. Syngas or just hydrogen separated therefrom may be used as the feed 108 to provide hydrogen to the fuel oil hydrocracking reaction stage 102 and subsequently downstream to the distillate hydrocracking reaction stage 112. As described above, in other embodiments, the heavy hydrocarbon fraction 104 (unconverted oil) may be sent to a delayed coking unit or a cement plant (not shown). In yet other embodiments, an ultra low sulfur fuel oil can be recovered from the hydrocracking unit (step 1), which can be used internally or sold as a high value product.

The distillate hydrocracking reaction stage 112 may include one or more fixed bed, ebullated bed, or slurry bed hydrocrackers that may operate in series and/or parallel. An inter-reactor gas-liquid separator may be included to separate the converted products from the unconverted residue. In some embodiments, the hydrocracking reactions in the distillate hydrocracking reaction stage 112 may be conducted at a temperature in the range of from about 300 ℃ to about 440 ℃; in other embodimentsMay be carried out at a temperature in the range of from about 360 ℃ to about 440 ℃; in other embodiments, it may be performed at a temperature in the range of about 400 ℃ to about 440 ℃. In some embodiments, the pressure in the distillate hydrocracking reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, it may be in the range of about 100bara to about 180 bara. In some embodiments, the hydrocracking reaction may also be at about 0.1hr^-1To about 4.0hr^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2hr^-1To about 2.5hr^-1Is carried out within the range of (1).

The hydrocarbon effluent from the distillate hydrocracker 112 may then be separated into two or more fractions, such as a light or LPG fraction 113, a light naphtha fraction 114, and a heavy naphtha fraction 115. The LPG fraction 113 and the light naphtha fraction 114 may then be forwarded to a steam cracking reaction stage 124, and the heavy naphtha fraction 115 may be sent to a catalytic reforming reaction zone 116.

The catalytic reforming reaction zone 116 may include a dehydrogenation reactor, if desired, and a catalytic aromatization reactor. A dehydrogenation reactor may be included when the heavy naphtha feed from the distillate hydrocracking reaction is expected to be rich in saturated components. The catalyst used in the catalytic aromatization reactor may include promoting one or more reactions (e.g., conversion of olefin molecules and paraffin molecules to small olefins via cracking and hydrogen transfer, formation of C via conversion, oligomerization, cracking, and isomerization reactions₂To C₁₀Olefins, and aromatics formation by cyclization and hydrogen transfer). The catalyst may be adjusted to be suitable for the desired reaction based on the starting materials and conditions used.

The reaction product from the catalytic reformer may then be processed in a fractionation zone (internal to block 116, not shown) using one or more distillation columns to separate the reaction product into two or more hydrocarbon fractions. The resulting hydrocarbon fractions may include a benzene fraction 118, a para-xylene fraction 120, and a hydrogen fraction 122, among other fractions.

As described above, the LPG fraction 113 and the light naphtha fraction 114 may be sent to the steam cracking reaction zone 124. The steam cracking reaction zone 124 may include a heater comprising one or more convection coils and/or radiant coils for cracking the light naphtha and LPG in the presence of steam. Steam cracking may be carried out at gas outlet temperatures in excess of 700 ℃ (e.g., in the range of about 750 ℃ to about 1100 ℃). The effluent recovered from the steam hydrocracking system may be separated to separate unreacted hydrogen 130 from the hydrocarbons in the effluent for recovery and condensation of steam. The hydrocarbon effluent may be fractionated using one or more distillation columns to form two or more hydrocarbon fractions, including one or more light hydrocarbon fractions 126 (propylene, ethylene, etc.), one or more aromatic fractions 128 (benzene, toluene, xylene, etc.), and a thermally cracked gas oil and/or fuel oil fraction 132.

A flow line may be provided to send the thermally cracked gas oil fraction to the fuel oil hydrocracker 102, the distillate hydrocracker 112, or both. In some embodiments, the thermally cracked gas oil fraction may be separated in a separator to form a light thermally cracked gas oil fraction and a heavy gas oil fraction, and flow lines may be provided to send the respective fractions recovered to a desired reactor, such as sending the heavy thermally cracked gas oil fraction to the fuel oil hydrocracker 102 and the light thermally cracked gas oil fraction to the distillate hydrocracker 112.

The hydrogen fractions 122 and 130 recovered from the reformer 116 and the steam cracker 124, respectively, may be sent to the fuel oil hydrocracker 102 and/or the distillate hydrocracker 112 as described above. The hydrogen fractions 108, 122, 130 may maintain the system at or near hydrogen equilibrium, producing most or all of the hydrogen internally.

Referring now to fig. 3 and 3A, a simplified process flow diagram of a method for converting high sulfur fuel oil to petrochemicals according to embodiments herein is shown, where like numerals represent like components. The high sulfur fuel oil 100 may be sent to a fuel oil hydrocracking reaction zone 102EB, which fuel oil hydrocracking reaction zone 102EB may include one or more reactors in either an ebullated bed or a slurry bed that may be operated in series and/or in parallel. The high sulfur fuel oil 100 can be reacted with hydrogen (from 108, 122, 130, described further below) over one or more catalysts having specific functions designed for hydrodemetallization, hydrodesulfurization, CCR conversion, hydrodenitrogenation, aromatic saturation, and hydrocracking. Part of the conversion process is a thermal process and part is a catalytic process. In a fuel oil hydrocracker, thermal and catalytic conversion processes convert at least a portion of the hydrocarbon fuel oil into lighter molecules. Hydrocracking catalysts in ebullated bed or slurry bed reactors can have very high hydrogenation activity, which can maximize hydrodesulfurization and other reactions. Depending on the reactor used in the fuel oil hydrocracking step, the catalyst may be a Ni, Mo or organo-molybdenum component on a silica-alumina substrate or a molybdenum salt promoted with another base metal.

For example, in some embodiments, the hydrocracker in the fuel oil reaction zone may be operated under conditions to provide a conversion of 40 wt% to 90 wt%; in other embodiments, a conversion of greater than 60 wt% may be provided; in other embodiments, a conversion of greater than 80 wt% may be provided. The hydrocracking reaction in the fuel oil hydrocracking reaction zone may be carried out at a temperature in the range of from about 360 ℃ to about 460 ℃; in other embodiments, it may be performed at a temperature in the range of about 390 ℃ or 400 ℃ to about 440 ℃. In some embodiments, the pressure in the fuel oil hydrocracking reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, may be in the range of about 100bara to about 200bara, for example, in other embodiments may be in the range of about 170bara to about 195 bara. In some embodiments, the hydrocracking reaction may also be at about 0.1h^-1To about 3.0h^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2h^-1To about 2h^-1E.g., in other embodiments, may be in about 0.1h^-1To about 0.5h^-1Is carried out within the range of (1).

The effluent from ebullated bed hydrocracking reaction zone 102EB may include a mixture of hydrocarbons including light and heavy naphtha, diesel and vacuum gas oil range hydrocarbons. The light naphtha range product may include, for example, 60 wt% to 75 wt% paraffins, 15 wt% to 30 wt% naphthenes, 2 wt% to 10 wt% aromatics, and up to 50wppm nitrogen and up to 500wppm sulfur. The heavy naphtha range product may include, for example, 20 wt% to 50 wt% paraffins, 35 wt% to 55 wt% naphthenes, 12 wt% to 20 wt% aromatics, and up to 150wppm nitrogen and up to 200wppm sulfur. The diesel range product may comprise, for example, 15 wt% to 35 wt% paraffins, 15 wt% to 30 wt% naphthenes, 35 wt% to 55 wt% aromatics with up to 750wppm nitrogen and up to 2000wppm sulfur. The product in the VGO range may comprise, for example, 15 wt% to 25 wt% paraffins, 15 wt% to 30 wt% naphthenes, 40 wt% to 60 wt% aromatics with up to 3500wppm sulfur and nitrogen and a weight average polycyclic aromatic (having more than 4 rings) in the range from about 10000wppm to about 25000 wppm. Each of these product fractions is unsuitable for use as a feed to a steam cracker because they may result in rapid fouling, low olefin conversion (low ethylene yield), may result in high yields of thermal cracking fuel oil, and/or may be rapidly converted to coke at the high temperatures of the steam cracker. Heavy naphtha is not suitable for use as a feed to a catalytic reformer because heavy naphtha has very high sulfur and nitrogen, whereas most catalytic reforming catalysts require less than 0.5 parts per million of sulfur and nitrogen.

The effluent from the fuel oil hydrocracker may then be separated into a light (converted) hydrocarbon fraction 110 and a heavy (unconverted) hydrocarbon fraction 104 in order to improve the transferability of the effluent from the first step fuel oil hydrocracking. The final boiling point of the light hydrocarbon fraction may be in the range of about 450 ℃ to about 550 ℃, for example about 520 ℃ in some embodiments. The light hydrocarbon fraction 110 may then be forwarded to a two-stage distillate hydrocracking reaction stage 112TS as further illustrated in fig. 3A.

The heavy hydrocarbon fraction 104 may be sent to a gasifier 106 and converted to syngas, which may include CO and H₂And other by-products. Syngas or only hydrogen separated therefrom may be used as feed 108 to provide hydrogen to the fuel oil hydrocracking reaction stage 102 and then downstream to the distillate hydrocracking reaction stage 112 TS. Turbines and other equipment associated with the gasifier 106 may also be used to generate the electrical power output 109.

The two-stage distillate hydrocracking reaction stage 112TS may include one or more fixed bed, ebullated bed, or slurry bed hydrocrackers, which may be operated in series and/or parallel. In some embodiments, the two-stage distillate hydrocracking reaction stage 112TS may include a first stage reactor that includes a catalyst mixture to perform hydrotreating, deep hydrogenation, ring opening and hydrodenitrogenation, and hydrocracking.

In some embodiments, for example, the first stage can include a fixed bed reactor 302, the fixed bed reactor 302 comprising: a type II hydrotreating catalyst (e.g., Ni — Mo catalyst) in the first contacting bed 304; an unsupported trimetallic catalyst system in the second contact bed 306 for deep hydrogenation, ring opening, and hydrodenitrogenation; and a layer of nitrogen tolerant hydrocracking catalyst in the third contact bed 308, which may be amorphous or zeolitic, with a base metal (e.g., Ni, Mo or W).

The reactor effluent 310 from stage 1 may be flashed, for example in a flash drum or separator 312, to recover a vapor fraction 314 and remove ammonia and hydrogen sulfide from the hydrocarbons, which vapor fraction 314 may include hydrogen for recycle. The remaining hydrocarbon effluent 316 may then be directed to an intermediate fractionator or separation zone 318 to recover various hydrocarbon fractions. The overhead fraction and/or side-draw fraction recovered from fractionator 318 may include one or more light hydrocarbon fractions 320, such as one or more C2-C12 fractions (C2, C3, C4, C5, C6, C7, C8, C9, C10, C11, C12, alone or in combination). A heavy fraction including unconverted hydrocarbons (oil) from stage 1 can be recovered from the fractionator or separation zone 318 via stream 322.

The unconverted oil from stage 1 may then be converted in a stage 2 reactor, which may include one or more fixed bed, ebullated bed, or slurry bed hydrocrackers that may be operated in series and/or parallel. The second stage reactor 324 may contain a hydrocracking catalyst 326 for converting unconverted oil from stage 1 into highly hydrogenated naphtha and lighter products, which are recovered as effluent 328, which effluent 328 may be recovered in a common fractionator 318 with the effluent of stage 1 or in a separate dedicated fractionator (not shown). The hydrocracking catalyst in the second stage may be zeolitic or amorphous or a mixture of both. The catalyst may comprise a base metal (e.g. Ni, Mo or W) or a precious metal (e.g. platinum or palladium). In some embodiments, the hydrocracking catalyst may be laminated with a hydrotreating catalyst.

For example, the light naphtha range product from stage 2 may include 75 wt% to 85 wt% paraffins, 15 wt% to 20 wt% naphthenes, 2 wt% to 5 wt% aromatics, and less than 1wppm sulfur and nitrogen. For example, a heavy naphtha range product may include 40 wt% to 50 wt% paraffins, 45 wt% to 50 wt% naphthenes, 8 wt% to 10 wt% aromatics, and less than 0.5wppm nitrogen and sulfur.

In some embodiments, the total naphtha yield from the hydrocracking reaction stage 112TS may be in the range of about 85 wt% to 92 wt%. Further, as described above with respect to fig. 2, the recovered C2 fraction 117, C3/LPG fraction 113, and light naphtha product 114 may be desirable feedstocks for a downstream steam cracker or thermal cracking furnace in the ethylene cracker complex 124. In some embodiments, the streams 320, 328 may be sent directly to the ethylene compounding plant 124. In other embodiments, streams 320 and/or 328 may be separated into multiple fractions for separate processing (e.g., cracking, at temperatures, pressures, and residence times that are preferred for each respective fraction). In some embodiments, for example, the effluent 328 from the second stage may be separated to recover a light naphtha fraction 114 and a heavy naphtha fraction 115, which light naphtha fraction 114 and heavy naphtha fraction 115 may be treated in the cracking zone 124 and in the optional reforming zone 116 as described above with respect to fig. 2.

In some embodiments, the hydrocracking reactions in the distillate hydrocracking reaction stage 112TS may be conducted at a temperature range of about 280 ℃ or 300 ℃ to about 440 ℃; in other embodiments, it may be performed at a temperature in the range of about 360 ℃ to about 440 ℃. In some embodiments, the pressure in the distillate hydrocracking reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, may be in the range of about 100bara to about 200bara, for example may be in the range of about 140bara to about 190 bara. In some embodiments, the hydrocracking reaction may also be at about 0.1h^-1To about 4.0h^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2h^-1To about 2.5h^-1Can be carried out, for example, in a period of about 0.5h^-1To about 2.5h^-1Or 3.0h^-1Is carried out within the range of (1).

In the first stage, for example, in some embodiments, the reaction may be conducted at a temperature in the range of about 300 ℃ to about 440 ℃; in other embodiments, it may be performed at a temperature in the range of about 320 ℃ to about 440 ℃; and in other embodiments, may be performed at a temperature in the range of about 340 ℃ to about 430 ℃. In some embodiments, the pressure in the first stage reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, may be in the range of about 100bara to about 200bara, for example may be in the range of about 140bara to about 190bara or about 150bara to about 180 bara. In some embodiments, the hydrocracking reaction in the first stage reaction zone may also be at about 0.1h^-1To about 4.0h^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2h^-1To about 3.0h^-1Can be carried out, for example, in a period of about 0.5h^-1To about 2.5h^-1Is carried out within the range of (1).

In the second stage, for example, in some embodiments, the reaction may be conducted at a temperature in the range of about 280 ℃ to about 440 ℃; in other embodiments, it may be performed at a temperature in the range of about 300 ℃ to about 400 ℃; and in other embodiments, may be performed at a temperature in the range of about 320 ℃ to about 380 ℃.In some embodiments, the pressure in the second stage reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, may be in the range of about 100bara to about 200bara, for example may be in the range of about 140bara to about 190bara or about 150bara to about 180 bara. In some embodiments, the hydrocracking reaction in the second stage reaction zone may also be at about 0.1h^-1To about 4.0h^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2h^-1To about 3.5h^-1Can be carried out, for example, in a period of about 0.5h^-1To about 3.0h^-1Is carried out within the range of (1).

Referring again to fig. 3, as described above, the hydrocarbon effluent 320, 328 from the two-stage distillate hydrocracking reaction zone 112TS may be forwarded to an ethylene complex to produce petrochemicals. In some embodiments, one or both of fractions 320, 328 may be separated into two or more fractions, for example, a light fraction 117, a C3 or LPG fraction 113, a light naphtha fraction 114, and a heavy naphtha fraction 115. The light (C2) fraction 117, the C3/LPG fraction 113, and the light naphtha fraction 114 may be forwarded to the steam cracking reaction stage 124. In some embodiments, a heavy fraction (e.g., a heavy naphtha fraction 115 or other heavy fraction containing unconverted effluent from the fuel oil hydrocracker and/or the first or second stage hydrocracker) may optionally be sent to the catalytic reforming reaction zone 116.

When a catalytic reforming reaction zone 116 is present, the catalytic reforming reaction zone 116 may include a dehydrogenation reactor (if desired), and may also include a catalytic aromatization reactor. A dehydrogenation reactor may be included when the heavy naphtha feed sent from the distillate hydrocracking reaction is expected to be rich in saturated components. The catalyst used in the catalytic aromatization reactor may include promoting one or more reactions (e.g., conversion of olefin molecules and paraffin molecules to small olefins via cracking and hydrogen transfer, formation of C via conversion, oligomerization, cracking, and isomerization reactions₂To C₁₀Olefins, and aromatics formation by cyclization and hydrogen transfer). May be based on the source usedThe catalyst used in the reforming reaction zone 116 is tailored to the desired reaction by the materials and conditions.

The reaction product from the catalytic reformer may then be processed in a fractionation zone (inside zone 116, not shown) using one or more distillation columns to separate the reaction product into two or more hydrocarbon fractions. The resulting hydrocarbon fractions may include, for example, a benzene fraction 118, a paraxylene fraction 120, and a hydrogen fraction 122, among other fractions.

As described above, the C3/LPG fraction 113 and the light naphtha fraction 114 may be sent to the steam cracking reaction zone 124. The steam cracking reaction zone 124 may include a heater comprising one or more convection coils and/or radiant coils for cracking the light naphtha and LPG in the presence of steam. Steam cracking may be carried out at gas outlet temperatures in excess of 700 ℃ (e.g., in the range of about 750 ℃ to about 1100 ℃). The effluent recovered from the steam hydrocracking system may be separated to recover unreacted hydrogen 130 from the hydrocarbons in the effluent and condense the steam. The hydrocarbon effluent may be fractionated using one or more distillation columns to form two or more hydrocarbon fractions including, for example, one or more light hydrocarbon fractions 125, 126 (propylene, ethylene, etc.), butadiene or C4-containing fraction 127, one or more aromatic fractions 128, 129 (benzene, toluene, xylene, etc.), and a thermally cracked gas oil and/or fuel oil fraction 132.

A flow line may be provided to send the thermally cracked gas oil fraction to the fuel oil hydrocracker 102EB, the distillate hydrocracker 112TS, or both. In some embodiments, the thermally cracked gas oil fraction may be separated in a separator to form a light thermally cracked gas oil fraction and a heavy gas oil fraction, and flow lines may be provided to send the respective fractions recovered to a desired reactor or reaction stage, such as sending the heavy thermally cracked gas oil fraction to the fuel oil hydrocracker 102 and the light thermally cracked gas oil fraction to the distillate hydrocracker 112 TS.

The hydrogen fractions 122 and 130 recovered from the reformer 116 and the steam cracker 124, respectively, may be sent to the fuel oil hydrocracker 102EB and/or the distillate hydrocracker 112TS as described above. The hydrogen fractions 108, 122, 130 may maintain the system at or near hydrogen equilibrium, producing most or all of the hydrogen internally.

Referring now to fig. 4, a simplified process flow diagram of a method for converting high sulfur fuel oil to petrochemicals according to embodiments herein is shown, where like numerals represent like components. The high sulfur fuel oil 100 can be sent to a fuel oil hydrocracking reaction zone 102S, which fuel oil hydrocracking reaction zone 102S can include one or more slurry fuel oil hydrocrackers that can operate in series and/or parallel. The high sulfur fuel oil 100 can be reacted with hydrogen (from 108, 122, 130, described further below) over a hydrocracking catalyst in a slurry fuel oil hydrocracker to convert at least a portion of the fuel oil hydrocarbons to lighter molecules. Hydrocracking catalysts in slurry reactors can have very high hydrogenation activity, which can maximize hydrodenitrogenation and other reactions.

For example, in some embodiments, the hydrocracker in the fuel oil reaction zone 102S may be operated under conditions to provide a conversion of 40 wt% to 98 wt%; in other embodiments, a conversion of greater than 60 wt% may be provided; in other embodiments, a conversion of greater than 80 wt% may be provided. The hydrocracking reaction in the fuel oil hydrocracking reaction zone 102S may be carried out at a temperature in the range of about 360 ℃ to about 460 ℃; in other embodiments, it may be performed at a temperature in the range of about 390 ℃ or 400 ℃ to about 440 ℃. In some embodiments, the pressure in the fuel oil hydrocracking reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, may be in the range of about 100bara to about 200bara, for example, in other embodiments may be in the range of about 170bara to about 195 bara. In some embodiments, the hydrocracking reaction may also be at about 0.1h^-1To about 3.0h^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2h^-1To about 2h^-1E.g., in other embodiments, may be in about 0.1h^-1To about 0.5h^-1Is carried out within the range of (1).

The effluent from the slurry hydrocracking reaction zone 102S may include a mixture of hydrocarbons including light and heavy naphtha, diesel and vacuum gas oil range hydrocarbons. The light naphtha range product may include, for example, 60 wt% to 75 wt% paraffins, 15 wt% to 30 wt% naphthenes, 2 wt% to 10 wt% aromatics, and up to 50wppm nitrogen and up to 500wppm sulfur. The heavy naphtha range product may include, for example, 20 wt% to 50 wt% paraffins, 35 wt% to 55 wt% naphthenes, 12 wt% to 20 wt% aromatics, and up to 150wppm nitrogen and up to 200wppm sulfur. The diesel range product may comprise, for example, 15 wt% to 35 wt% paraffins, 15 wt% to 30 wt% naphthenes, 35 wt% to 55 wt% aromatics with up to 750wppm nitrogen and up to 2000wppm sulfur. The product in the VGO range may comprise, for example, 15 wt% to 25 wt% paraffins, 15 wt% to 30 wt% naphthenes, 40 wt% to 60 wt% aromatics and up to 1000wppm sulfur and nitrogen and a weight average polycyclic aromatic (having more than 4 rings) in the range from about 10000wppm to about 25000 wppm. Each of these product fractions is unsuitable for use as a feed to a steam cracker because they may result in rapid fouling, low olefin conversion (low ethylene yield), may result in high yields of thermal cracking fuel oil, and/or may be rapidly converted to coke at the high temperatures of the steam cracker.

In order to improve the transferability of the effluent from the first step slurry bed hydrocracking, the effluent from the ebullated bed hydrocracker may then be separated into a light (converted) hydrocarbon fraction 110 and a heavy (unconverted) hydrocarbon fraction 107, such as an ultra low sulfur fuel oil fraction, which may be used internally or sold as a high value product. The end point of the light hydrocarbon fraction may be in the range of about 450 ℃ to about 550 ℃, for example about 520 ℃ in some embodiments. The light hydrocarbon fraction 110 may then be transferred to a two-stage distillate hydrocracking reaction stage 112TS and processed similar to that described above with respect to fig. 3 and 3A. In other embodiments, as described above, the heavy fraction (unconverted oil) may be sent to a gasifier, a delayed coking unit, or a cement plant (not shown).

The two-stage distillate hydrocracking reaction stage 112TS may include one or more fixed bed, ebullated bed, or slurry bed hydrocrackers, which may be operated in series and/or parallel. In some embodiments, the two-stage distillate hydrocracking reaction stage 112TS may include a first stage reactor that includes a catalyst mixture to perform hydrotreating, deep hydrogenation, ring opening and hydrodenitrogenation, and hydrocracking.

In some embodiments, for example, the first stage can include a fixed bed reactor 302, the fixed bed reactor 302 comprising: a type II hydrotreating catalyst (e.g., Ni — Mo catalyst) in the first contacting bed 304; an unsupported trimetallic catalyst system in the second contact bed 306 for deep hydrogenation, ring opening, and hydrodenitrogenation; and a nitrogen tolerant hydrocracking catalyst layer in the third contacting bed 308.

The reactor effluent 310 from stage 1 may be flashed, for example in a flash drum or separator 312, to recover a vapor fraction 314 and remove ammonia and hydrogen sulfide from the hydrocarbons, which vapor fraction 314 may include hydrogen for recycle. The remaining hydrocarbon effluent 316 may then be directed to an intermediate fractionator or separation zone 318 to recover various hydrocarbon fractions. The overhead fraction and/or side-draw fraction recovered from fractionator 318 may include one or more light hydrocarbon fractions 320, such as one or more C2-C12 fractions (C2, C3, C4, C5, C6, C7, C8, C9, C10, C11, C12, alone or in combination). A heavy fraction including unconverted hydrocarbons (oil) from stage 1 can be recovered from the fractionator or separation zone 318 via stream 322.

The unconverted oil from stage 1 may then be converted in a stage 2 reactor, which may include one or more fixed bed, ebullated bed, or slurry bed hydrocrackers that may be operated in series and/or parallel. The second stage reactor 324 can contain a hydrocracking catalyst 326 for converting unconverted oil from stage 1 into highly hydrogenated naphtha and lighter products, which are recovered as effluent 328.

For example, the light naphtha range product from stage 2 may include 75 wt% to 85 wt% paraffins, 15 wt% to 20 wt% naphthenes, 2 wt% to 5 wt% aromatics, and less than 1wppm sulfur and nitrogen. For example, a heavy naphtha range product may include 40 wt% to 50 wt% paraffins, 45 wt% to 50 wt% naphthenes, 8 wt% to 10 wt% aromatics, and less than 0.5wppm nitrogen and sulfur.

In some embodiments, the total naphtha yield from the hydrocracking reaction stage 112TS may be in the range of about 85 wt% to 92 wt%. Furthermore, as described above with respect to fig. 2 and 3, the recovered C2 fraction 113, C3/LPG fraction 114, and naphtha product 117 (light range or full range) may be ideal feedstocks for a downstream steam cracker or thermal cracking furnace in the ethylene cracker complex 124. In some embodiments, the streams 320, 328 may be sent directly to the ethylene compounding plant 124. In other embodiments, streams 320 and/or 328 may be separated into multiple fractions for separate processing (e.g., cracking, at temperatures, pressures, and residence times that are preferred for each respective fraction). In some embodiments, for example, the effluent 328 from the second stage may be separated to recover the full range naphtha fraction 117 that is sent to the ethylene complex 124. In other embodiments, for example, the effluent 328 may be separated to recover the light naphtha fraction 117 and the heavy naphtha fraction 115, which light naphtha fraction 117 and heavy naphtha fraction 115 may be treated in the cracking zone 124 and in the optional reforming zone 116 as described above with respect to fig. 3.

In some embodiments, the hydrocracking reactions in the distillate hydrocracking reaction stage 112TS may be conducted at a temperature range of about 280 ℃ or 300 ℃ to about 440 ℃; in other embodiments, it may be performed at a temperature in the range of about 360 ℃ to about 440 ℃; and in other embodiments, may be performed at a temperature in the range of about 330 ℃ to about 440 ℃. In some embodiments, the pressure in the distillate hydrocracking reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, may be in the range of about 100bara to about 200bara, for example may be in the range of about 140bara to about 190baraAnd (4) the following steps. In some embodiments, the hydrocracking reaction may also be at about 0.1h^-1To about 4.0h^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2h^-1To about 2.5h^-1Can be carried out, for example, in a period of about 0.5h^-1To about 2.5h^-1Or 3.0h^-1Is carried out within the range of (1).

In the first stage, for example, in some embodiments, the reaction may be conducted at a temperature in the range of about 300 ℃ to about 460 ℃; in other embodiments, it may be performed at a temperature in the range of about 320 ℃ to about 440 ℃; and in other embodiments, may be performed at a temperature in the range of about 340 ℃ to about 430 ℃. In some embodiments, the pressure in the first stage reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, may be in the range of about 100bara to about 200bara, for example may be in the range of about 140bara to about 190bara or about 150bara to about 180 bara. In some embodiments, the hydrocracking reaction in the first stage reaction zone may also be at about 0.1h^-1To about 4.0h^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2h^-1To about 3.0h^-1Can be carried out, for example, in a period of about 0.5h^-1To about 2.5h^-1Is carried out within the range of (1).

In the second stage, for example, in some embodiments, the reaction may be conducted at a temperature in the range of about 280 ℃ to about 440 ℃; in other embodiments, it may be performed at a temperature in the range of about 300 ℃ to about 400 ℃; and in other embodiments, may be performed at a temperature in the range of about 320 ℃ to about 380 ℃. In some embodiments, the pressure in the second stage reaction zone may be in the range of from about 70bara to about 230 bara; in other embodiments, may be in the range of about 100bara to about 200bara, for example may be in the range of about 140bara to about 190bara or about 150bara to about 180 bara. In some embodiments, the hydrocracking reaction in the second stage reaction zone may also be at about 0.1h^-1To about 4.0h^-1In the Liquid Hourly Space Velocity (LHSV) range; in other embodiments, it may be at about 0.2h^-1To about 3.5h^-1Can be carried out, for example, in a period of about 0.5h^-1To about 3.0h^-1Is carried out within the range of (1).

Referring again to fig. 4, as described above, the hydrocarbon effluent 320, 328 from the two-stage distillate hydrocracking reaction zone 112TS may be forwarded to an ethylene complex to produce petrochemicals. In some embodiments, one or both of fractions 320, 328 may be separated into two or more fractions, such as a light (C2) fraction 117, a C3 or LPG fraction 113, a naphtha fraction 114. The light fraction 117, the C3/LPG fraction 113 and the naphtha fraction 114 may be forwarded to a steam cracking reaction stage 124. As described above with respect to fig. 3, if heavy fraction 115 is recovered, it may be sent to catalytic reforming reaction zone 116.

As described above, the light fraction 117, the C3/LPG fraction 113, and the naphtha fraction 114 may be sent to the steam cracking reaction zone 124. The steam cracking reaction zone 124 may include a heater comprising one or more convection coils and/or radiant coils for cracking the light naphtha and LPG in the presence of steam. Steam cracking may be carried out at gas outlet temperatures in excess of 700 ℃ (e.g., in the range of about 750 ℃ to about 1100 ℃). The effluent recovered from the steam hydrocracking system may be separated to recover unreacted hydrogen 130 from the hydrocarbons of the effluent and condense the steam. The hydrocarbon effluent may be fractionated using one or more distillation columns to form two or more hydrocarbon fractions including, for example, one or more light hydrocarbon fractions 125, 126 (propylene, ethylene, etc.), butadiene or C4-containing fraction 127, one or more aromatic fractions 128, 129 (benzene, toluene, xylene, etc.), and a thermally cracked gas oil and/or fuel oil fraction 132. In some embodiments, the ethylene cracker complex 124 may include an MTBE unit, producing an MTBE-containing fraction 131.

A flow line may be provided to send the thermally cracked gas oil fraction to the fuel oil hydrocracker 102S, the distillate hydrocracker 112TS, or both. In some embodiments, the thermally cracked gas oil fraction may be separated in a separator to form a light thermally cracked gas oil fraction and a heavy gas oil fraction, and flow lines may be provided to send the respective fractions recovered to a desired reactor or reaction stage, such as sending the heavy thermally cracked gas oil fraction to the fuel oil hydrocracker 102S and the light thermally cracked gas oil fraction to the distillate hydrocracker 112 TS.

The hydrogen fractions 122 and 130 recovered from the reformer 116 and the steam cracker 124, respectively, may be sent to the fuel oil hydrocracker 102S and/or the distillate hydrocracker 112TS as described above. The hydrogen fractions 122, 130 may maintain the system at or near hydrogen equilibrium, producing most or all of the hydrogen internally.

As described above, the catalyst that can be used in step 1 (hydrocracking reaction zone of ebullated bed or slurry bed) may include a catalyst having very high hydrogenation activity, and hydrodenitrogenation and other reactions may be maximized. Exemplary catalysts that may be used include extrudates or liquid recycle catalysts suitable for use in ebullated bed and/or slurry bed reactors, or other catalysts suitable for use in other types of reactors that may be used, including the fixed bed reactors described above.

In an ebullated-bed reactor, the catalyst may include a hydrodemetallization catalyst of very large pore size with Ni and Mo on silica alumina followed by a Ni-Mo catalyst of progressively smaller pore size and progressively larger surface area to achieve the target levels of HDS, DCCR, and asphaltene conversion without forming excessive deposits. In a slurry bed reactor, the catalyst may be a nano-sized organo-molybdenum compound promoted with another base metal (e.g., Ni) or a micro-sized molybdenum sulfide. The catalyst system is designed to maximize conversion while keeping hydrogenation always before the resin damage limit, which can result in precipitation of residual asphaltenes (unconverted asphaltenes).

The catalyst useful in stage 2, stage 1, may comprise a catalyst or mixture of catalysts for hydrotreating, deep hydrogenation, ring opening, and hydrodenitrogenation and hydrocracking. In some embodiments, the step 2 stage 1 reactor may comprise multiple catalyst beds, wherein the first layer may comprise a type II hydrotreating catalyst, such as a Ni — Mo catalyst; an unsupported trimetallic catalyst system for deep hydrogenation, ring opening and hydrodenitrogenation can be disposed in the second contact bed; and in the third contacting bed, a nitrogen tolerant hydrocracking catalyst layer may be used.

Examples of type II hydroprocessing catalysts can include chelated Ni-Mo or Co-Mo or Ni-Co-Mo catalysts dispersed on a porous material, typically alumina. These catalysts are advanced over conventional hydrotreating catalysts in that the metals to which hydrogenation and desulfurization occur can be accessed and the porosity adjusted.

The unsupported trimetallic catalyst may be, for example, a Ni-W-Mo catalyst. An all-metal catalyst can serve two functions: (1) the catalyst may have a suitable porosity to bring HPNAs larger than normal from residue hydrocracking close to the active site; (2) the high concentration of metal causes saturation of the HPNA and produces lower boiling aromatics. Such catalysts may also have sufficiently high activity to open the cycloalkane ring, thereby opening the embedded nitrogen, which can then be treated. Thus, the all-metal catalyst may allow subsequent hydrodenitrogenation and hydrocracking to occur, which would otherwise be severely inhibited. The use of an all-metal catalyst can allow nitrogen to be converted at lower temperatures. Without such a catalyst and associated activity, one would only try to convert nitrogen by higher temperatures, which would lead to the formation of higher amounts of HPNA, for example by Scholl condensation reaction. In addition, in the case of an inability to access the active sites of an all-metal catalyst, the larger HPNA will tend to form carbonaceous deposits, thereby contaminating the catalyst. Exemplary all-metal catalysts can include those available from Grace Catalyst Technologies1000。

Catalysts useful in stage 2, may include hydrocracking catalysts for converting heavy hydrocarbons (oils) from stage 1 to highly hydrogenated naphtha and light products. The desired activity may be provided, for example, by a noble metal zeolite catalyst. In some embodiments, a guard bed comprising an all-metal catalyst may also be used in stage 2 to further protect the noble metal zeolite catalyst or other catalyst used, if desired.

Examples of the invention

The following is an example of the conversion of middle east high sulfur fuel oil (ME HSFO) according to the examples herein. The ME HSFO feed comprised 4.5 wt% sulfur, 3300ppm nitrogen, 10.3 wt% hydrogen, 84.8 wt% carbon, 130ppm nickel and vanadium and 23 wt% Conradson carbon.

ME HSFO is contacted with the catalyst in the reactor of step 1 (ebullating bed containing extrudate catalyst or slurry bed reactor including liquid circulating catalyst). The operating conditions in step 1 may include an operating temperature in the range of about 390 ℃ to about 440 ℃, an operating pressure in the range of 170bar to 195bar and 0.1h^-1To 0.5h^-1Liquid hourly space velocity within the range.

The product after the first conversion stage may be as shown in table 1.

TABLE 1

The product components listed above from step 1 may have the following compositions, as shown in table 2.

TABLE 2

The light naphtha product cannot be sent to a steam cracker based on its composition. Similarly, heavy naphtha cannot be sent to a catalytic reformer or steam cracker. If diesel is sent to a steam cracker this will lead to fast fouling and lower ethylene yields. And VGO cannot be sent to the steam cracker because HPNA is converted to coke very rapidly at the high temperature of the steam cracker, resulting in very low ethylene yield and very high yield of thermal cracking fuel oil.

The product from step 1 can then be upgraded in step 2, which step 2 comprises an integrated two-stage hydrocracker with recycle. Stage 2 stage 1 comprises a catalyst system comprising a type II hydrotreating catalyst (e.g., a Ni — Mo catalyst), followed by an unsupported trimetallic catalyst system for deep hydrogenation and ring opening (followed by HDN), followed by a nitrogen tolerant hydrocracking catalyst layer. The operating conditions in stage 1 of step 2 may comprise an operating temperature in the range of from about 340 ℃ to about 430 ℃, an operating pressure in the range of from 150bar to 180bar and 0.5h^-1To 2.5h^-1Liquid hourly space velocity within the range. The operating conditions of stage 2 of step 2 may include an operating temperature in the range of from about 300 ℃ to about 400 ℃, an operating pressure in the range of from 150bar to 180bar and 0.5h^-1To 3.0h^-1Liquid hourly space velocity within the range.

After hydrocracking stage 1, the reactor effluent is flashed to recover hydrogen for recycle and to remove ammonia and hydrogen sulfide. The effluent is then directed to an intermediate fractionator to recover products. The bottoms from the fractionator are directed to a clean second stage (step 2 stage 2) where another hydrocracking catalyst converts unconverted oil from stage 1 to highly hydrogenated naphtha and lighter products. The final product mix resulting from stage 2 can be as shown in table 3.

TABLE 3

Fraction (b) of	Composition (I)	Measurement of
			Light naphtha
	Alkane hydrocarbons	75wt％-85wt％
				Cycloalkanes	15wt％-20wt％
	Aromatic compound	2wt％-5wt％
				Sulfur + nitrogen	<1wppm
Heavy naphtha
				Alkane hydrocarbons	40wt％-45wt％
	Cycloalkanes	45wt％-50wt％
				Aromatic compound	8wt％-10wt％
	Sulfur + nitrogen	<0.5wppm

Thus, the total naphtha yield suitable for petrochemical production may range from 85 wt% to 92 wt%. C2, C3, LPG and light naphtha are ideal components for steam crackers. Heavy naphtha, which is very rich in nitrogen and aromatics, is well suited for catalytic reformers, but can also be sent to a steam cracker.

By avoiding the production of diesel or VGO, embodiments herein eliminate the risk of fouling in the transfer line heat exchanger or thermal cracking furnace in a steam cracker. For steam crackers, the specification for the HPNA content is very strict. This is not a known concept to those with knowledge of refinery units or ethylene units, but requires a thorough understanding of the molecular conversions in each unit.

As a result of the above treatment, when the whole naphtha is fed to the steam cracker, 23 wt% to 30 wt% of ethylene, 13 wt% to 16 wt% of propylene, 6 wt% to 7 wt% of butadiene, and less than 5 wt% of aromatics and thermal cracking fuel oil can be produced. The thermally cracked fuel oil can be recycled to the resid hydrocracking section. Unconverted bitumen can be used as fuel or converted to hydrogen using a partial oxidation unit. The steam cracker can also provide hydrogen for the resid hydrocracking and integrated hydrocracking stages.

As noted above, the reactor configuration, operating conditions, and catalyst system described herein can produce the correct feed for petrochemical production. VGO generated by residual oil conversion has extremely high weight-average polycyclic aromatic hydrocarbon content and nitrogen; if this VGO is sent to a typical hydroprocessing unit containing a conventional Ni-Mo catalyst, the catalyst will deactivate quickly because the feed HPNA molecules will form higher molecular weight HPNA (weight average polycyclic aromatic compounds). Even if VGO is converted, the products of diesel and naphtha range distillates will have a higher naphthene ring content, which if sent to a steam cracker will not result in high olefin yields.

In contrast, the embodiments herein integrate a high pressure hydrocracker with an HSFO cracker in a single high pressure loop using a two stage belt recycle hydrocracker to: (i) minimizing the conversion of vacuum gas oil from residuum under non-favorable conditions (high ammonia environment); (ii) maximizing Hydrodenitrogenation (HDN) using a catalyst with very high hydrogenation activity in the first stage; and (iii) maximizing conversion in a clean (ammonia and hydrogen sulfide free) environment in the second stage to produce a naphtha product with the correct molecular structure for catalytic reforming or steam cracking.

Also as described above, the embodiments herein provide for the conversion of low cost feedstocks (e.g., high sulfur fuel oils) to higher value petrochemicals (including aromatics). Embodiments herein may also eliminate the need for refineries and the need to produce any transportation fuels from these low value hydrocarbons, may employ integration to greatly reduce investment costs, and/or may provide excellent export of thermally cracked fuel oil from steam crackers.

In addition, embodiments herein provide for cell integration, and there may be a significant amount of thermal integration in addition to the process flow between cells. For example, in particular, heat integration may be provided between hydrocrackers (fuel oil and distillate) and especially ethylene (steam) crackers (in certain embodiments, catalytic reformers). Since the entire hydrocracking process can be considered as feed preparation for the steam cracker and the catalytic reformer, the net exothermic hydrocracker can be integrated with the severely endothermic steam cracker and catalytic reformer. For example, since the product will be directed directly to the cracker, there is no need to discharge the product from the hydrocracker.

While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the disclosure. Accordingly, the scope of the invention should be limited only by the attached claims.