Crude oil to chemical thermal cracking and hydrocracking integrated unit

Abstract

The present disclosure provides a thermal cracking and hydrocracking integrated system and method for efficiently cracking hydrocarbon mixtures, such as mixtures including compounds having a standard boiling point greater than 450 DEG C, 500 DEG C, or even greater than 550 DEG C, such as whole crude oil.

Description

[0001] Cross Reference to Related Applications

[0002] This application is a divisional application of the patent application with application number 201880040681.0, filed on July 18, 2018, and titled “Integrated thermal cracking and hydrocracking unit for crude to chemicals”. TECHNICAL FIELD

[0003] Embodiments disclosed herein generally relate to integrated thermal cracking and hydrocracking of a hydrocarbon mixture (e.g., whole crude or other hydrocarbon mixture) to produce olefins and other chemicals. BACKGROUND

[0004] Hydrocarbon mixtures with end points exceeding 550°C are generally not processed directly in a thermal cracking reactor to produce olefins because the reactor would coke rather quickly. While limiting the reaction conditions can slow the tendency to foul, less severe conditions result in a significant reduction in yield.

[0005] It is a common consensus in the art that hydrocarbon mixtures with a wide boiling range and / or high end point hydrocarbons need to be first separated into a number of fractions (e.g., gases / light hydrocarbons, naphtha range hydrocarbons, and gas oil, etc.) and then each fraction is cracked under specific conditions (e.g., in different cracking furnaces). Although the fractionation (e.g., via a distillation column) and separate processing can be capital and energy intensive, it is generally believed that separate and individual processing of the fractions provides the most benefit in process control and yield.

[0006] To date, most of the crude oil has been partially converted into chemicals in large refinery-petrochemical complex plants. The focus of the refinery is to produce transportation fuels, such as gasoline and diesel. The low value streams from the refinery (e.g., liquefied petroleum gas, LPG, and light naphtha) are sent to a petrochemical plant, which can or can not be adjacent to the refinery. The petrochemical plant then produces chemicals, such as benzene, p-xylene, ethylene, propylene, and butadiene. Figure 1 A typical complex plant is shown.

[0007] In a conventional process, crude oil is desalted and preheated and sent to a crude distillation column. There various fractions are produced, including naphtha, kerosene, diesel, gas oil, vacuum gas oil (VGO), and resid. Some of the fractions, such as naphtha and gas oil, are used as feed to produce olefins. VGO and resid are hydrocracked to produce fuels. Products obtained from the crude column (atmospheric distillation) and vacuum column are used as fuels (gasoline, jet fuel, and diesel, etc.) that often do not meet fuel specifications. Thus, these products are isomerized, reformed, and / or hydrotreated (hydrodesulfurized, hydrodenitrogenated, and hydrocracked) before being used as fuels. Depending on the refinery, an olefins plant can receive feed before and / or after refining. SUMMARY

[0008] A thermal cracking and hydrocracking integrated process has now been developed for the flexible processing of whole crude and other hydrocarbon mixtures containing high boiling point coke precursors. The embodiments herein can advantageously reduce coking and fouling in the thermal cracking process, even at high severity conditions, effectively and efficiently integrate hydrocracking of the heavier portion of whole crude, obtain comparable olefins yields to naphtha crackers, while significantly reducing capital and energy requirements associated with pre-fractionation and separate processing that is typically associated with the processing of whole crude.

[0009] In one aspect, embodiments disclosed herein relate to a thermal cracking and hydrocracking integrated process for converting a hydrocarbon mixture to generate olefins. The process can include mixing whole crude and gas oil to form a hydrocarbon mixture. The hydrocarbon mixture can then be heated in a heater to vaporize a portion of the hydrocarbons in the hydrocarbon mixture and form a heated hydrocarbon mixture. The heated hydrocarbon mixture can then be separated in a first separator into a first vapor fraction and a first liquid fraction. The first vapor fraction, optionally mixed with steam, and the resulting mixture can be superheated in a convection zone and sent to a first radiant coil in a radiant zone of a thermal cracking reactor. The first liquid fraction, or a portion of the first liquid fraction, can be sent, along with hydrogen, to a hydrocracking reactor system for contacting the first liquid fraction with a hydrocracking catalyst to crack a portion of the hydrocarbons in the first liquid fraction. The effluent recovered from the hydrocracking reactor system can be separated to recover unreacted hydrogen from the hydrocarbons in the effluent, and the hydrocarbons in the effluent can be fractionated to form two or more hydrocarbon fractions, including a gas oil fraction.

[0010] On the other hand, the embodiments disclosed herein relate to an integrated thermal cracking and hydrocracking method for converting hydrocarbon mixtures to produce olefins. This method may include mixing crude oil and gas oil to form a hydrocarbon mixture. The hydrocarbon mixture may be heated in a heater to vaporize a portion of the hydrocarbons in the mixture and form a heated hydrocarbon mixture. The heated hydrocarbon mixture may be separated into a first vapor fraction and a first liquid fraction in a first separator. The first liquid fraction may then be heated in the convection zone of the thermal cracking reactor to vaporize a portion of the hydrocarbons in the first liquid fraction and form a second heated hydrocarbon mixture. The second heated hydrocarbon mixture may then be separated into a second vapor fraction and a second liquid fraction in a second separator. Steam may be mixed with the first vapor fraction, the method comprising superheating the resulting mixture in the convection zone and feeding the superheated mixture to a first radiant coil in the radiant zone of the thermal cracking reactor. Steam may also be mixed with a second vapor fraction, the method comprising superheating the resulting mixture in the convection zone and feeding the superheated mixture to a second radiant coil in the radiant zone of the thermal cracking reactor. The second liquid fraction, or a portion thereof, can be fed together with hydrogen into a hydrocracking reactor system. This system is used to contact the second liquid fraction with a hydrocracking catalyst to crack a portion of the hydrocarbons in the second liquid fraction and to recover the effluent from the hydrocracking reactor system. Unreacted hydrogen can be separated from the hydrocarbons in the effluent, and the hydrocarbons in the effluent can be fractionated to form two or more hydrocarbon fractions, including gas oil fractions and residue oil fractions.

[0011] In another respect, the embodiments disclosed herein relate to a system including means for performing the methods described above.

[0012] In some embodiments, such as those described herein, a system for producing olefins and / or dienes may include a thermal cracking heater having a convection heating zone and a radiation heating zone. A heating coil may be provided in the convection heating zone for partially vaporizing whole crude oil to form liquid and vapor fractions. A second heating coil may be provided in the convection heating zone for superheating the vapor fraction. A radiation heating coil may be further provided in the radiation heating zone for thermally cracking the superheated vapor fraction to produce a cracked hydrocarbon effluent containing a mixture of olefins and alkanes. A hydrocracking reaction zone may be used to hydrocrackle at least a portion of the liquid fraction to produce a hydrocracking hydrocarbon effluent containing additional olefins and / or dienes. The system may include flow lines, valves, controllers, pumps, and other equipment to provide the necessary connections and flow as described above.

[0013] The system described herein may include a separator for separating hydrocracking hydrocarbon effluents to recover two or more hydrocarbon fractions, including a gas oil fraction. The system may also include means for mixing the gas oil fraction with whole crude oil upstream of a heating coil. Means for mixing steam with a vapor fraction upstream of a second heating coil may also be provided. For example, the mixing means may include pipe tees or connections, pumps, and static mixers, as well as other mixing means known in the art.

[0014] For example, the system described herein may further include: a third heating coil in a convection heating zone for partially vaporizing a liquid fraction to form a second liquid fraction and a second vapor fraction; and / or a fourth heating coil in a convection heating zone for superheating the second vapor fraction. A second radiant heating coil in a radiant heating zone may be used for thermally cracking the superheated vapor fraction to produce a second cracked hydrocarbon effluent comprising a mixture of olefins and alkanes. Flow lines may be provided for feeding the second liquid fraction as at least a portion of the liquid fraction to the hydrocracking step.

[0015] The system described herein may also include means for mixing steam with various hydrocarbon-containing streams. For example, the system may include means for mixing steam with partially vaporized whole crude oil and separating the partially vaporized whole crude oil to form a liquid fraction and a vapor fraction, and / or means for mixing steam with partially vaporized liquid fractions and separating the partially vaporized liquid fractions to form a second liquid fraction and a second vapor fraction.

[0016] In embodiments of this disclosure, whole crude oil can be fed to a pyrocracking unit after desalting. In the convection section, light feedstock can be vaporized in the presence of steam and reacted in the radiative section. Heavy feedstock is fed to a hydrocracker. Products from the hydrocracker can be sold as fuel and / or processed in the pyrocracking unit to produce additional chemicals. Heavy products from the pyrocracking unit (olefins unit), such as pyrocracking gas oil and fuel oil, can be fed to the hydrocracker for upgrading along with fresh feedstock from the crude oil. Feedstock and products exchange heat between the integrated pyrocracking and cracking units to produce the maximum amount of chemicals and / or fuels as needed. Only a small fraction is discarded as tar.

[0017] The embodiments described herein do not require a crude oil separation unit. Therefore, it reduces the costs and energy consumption associated with that unit. One or more hydrocrackers operating under different conditions can be used to optimize chemical / fuel production. The effluent / tar from the hydrocracker is a very heavy, high-boiling-point material that can be sold as a product to maximize catalyst lifetime. Since the hydrocracker is designed to process residual oil, the thermally cracked gas oil and fuel oil produced in the cracker and / or thermal cracking unit can be used as feedstock in the hydrocracker. This maximizes the value of chemicals throughout the plant. Lighter materials, such as LPG and naphtha produced in the hydrocracker, can be used as feedstock for the olefins plant. Unconverted oil can also be used as feedstock for the thermal cracker.

[0018] The integrated thermal cracking and hydrocracking process disclosed herein provides high yields of target olefins, dienes, dienes, and aromatics. Valuable jet fuels and kerosene fuels can also be produced when needed. No separate crude oil separation unit is required. Each fraction can be optimally cracked using the embodiments described herein. The fuel oil produced in the thermal cracking unit can also be hydrocracking to generate more feedstock to the olefins plant. Light feedstock produced in the hydrocracker can also be thermally cracked to produce more olefins.

[0019] The process flow diagram shown in the appended sketch can be slightly modified for specific crude oil and product compositions. Further aspects and advantages will become apparent from the following description and the appended claims. Attached Figure Description

[0020] Figure 1 It is a simplified process flow diagram of a typical oil refining-petrochemical complex.

[0021] Figure 2 This is a simplified process flow diagram of an integrated thermal cracking-hydrocracking system for processing hydrocarbon mixtures according to embodiments of this article.

[0022] Figure 3 This is a simplified process flow diagram of an integrated thermal cracking-hydrocracking system for processing hydrocarbon mixtures according to embodiments of this article.

[0023] Figure 4 This is a simplified process flow diagram of an integrated thermal cracking-hydrocracking system for processing hydrocarbon mixtures according to embodiments of this article.

[0024] Figure 5 This is a simplified process flow diagram of an integrated thermal cracking-hydrocracking system for processing hydrocarbon mixtures according to embodiments of this article.

[0025] Figure 6This is a simplified process flow diagram of a HOPS tower used in conjunction with an integrated thermal cracking-hydrocracking system for processing hydrocarbon mixtures according to embodiments of this document.

[0026] Figure 7 This is a simplified process flow diagram of an integrated thermal cracking-hydrocracking system for processing hydrocarbon mixtures according to embodiments of this article. Detailed Implementation

[0027] The embodiments disclosed herein generally relate to the thermal cracking and hydrocracking of hydrocarbon mixtures (e.g., whole crude oil or other hydrocarbon mixtures) to produce olefins. More specifically, the embodiments disclosed herein relate to the efficient separation of hydrocarbon mixtures using heat recovered from the convection section of a heater performing the cracking.

[0028] The hydrocarbon mixtures that can be used in the embodiments disclosed herein may include a variety of hydrocarbon mixtures having a boiling point range, wherein the final boiling point of the mixture may be greater than 450°C or greater than 500°C, for example greater than 525°C, 550°C, or 575°C. The amount of high-boiling hydrocarbons (e.g., hydrocarbons with a boiling point exceeding 550°C) may be as low as 0.1 wt%, 1 wt%, or 2 wt%, but may be as high as 10 wt%, 25 wt%, 50 wt%, or higher. This specification is explained with reference to crude oil, but any hydrocarbon mixture with a high final boiling point may also be used, such as crude oil and condensate. For illustrative purposes, the following examples are described with reference to Nigerian light crude oil, but the scope of this application is not limited to such crude oils. The processes disclosed herein can be applied to crude oils, condensates, and hydrocarbons having broad boiling profiles and final boiling points above 500°C. This hydrocarbon mixture may include whole crude oil, crude crude oil, hydrotreated crude oil, gas oil, vacuum gas oil, heating oil, jet fuel, diesel, kerosene, gasoline, synthetic naphtha, reformate residue, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gasoline, distillates, crude naphtha, natural gas condensate, atmospheric tubular bottom stock, vacuum tubular fractions including bottom stock, wide-range naphtha to condensate gas oil, heavy non-crude hydrocarbon streams from refineries, vacuum gas oil, heavy gas oil, atmospheric residue, hydrocracking wax, and Fischer-Tropsch wax, etc. In some embodiments, the hydrocarbon mixture may include hydrocarbons ranging from naphtha fractionation range or lighter to vacuum gas oil fractionation range or heavier. If desired, these feedstocks may be pretreated upstream of the processes disclosed herein to remove a portion of sulfur, nitrogen, metals, and Conradson carbon.

[0029] Thermal cracking occurs via a free radical mechanism. Therefore, high ethylene yields can be achieved when cracking is performed at high temperatures. Lighter feedstocks (such as butane and pentane) require higher reactor temperatures to achieve higher olefin yields. Heavy feedstocks, such as gas oil and vacuum gas oil (VGO), require lower temperatures. Crude oil contains a distribution of compounds from butane to VGO and residue (e.g., feedstocks with a standard boiling point exceeding 520°C). Exposing unseparated whole crude oil to high temperatures produces high yields of coke (a byproduct of hydrocarbon cracking under harsh conditions) and clogs the reactor. Thermal cracking reactors must be shut down periodically to remove coke via steam / air decoking. The time between two decoking periods for olefin production is called the run length. When cracking crude oil without separation, coke deposits in the convection section coils (vaporizing fluid), the radiant section (where olefin formation occurs), and / or the transfer line heat exchanger (where the reaction is rapidly stopped by cooling to maintain olefin yield).

[0030] The embodiments disclosed herein use the convection section of a thermal cracking reactor (or heater) to preheat the hydrocarbon mixture feed and separate the hydrocarbon mixture feed into various fractions. Steam can be injected at appropriate locations to increase the vaporization of the hydrocarbon mixture and control the degree of heating and separation. The vaporization of hydrocarbons occurs at relatively low temperatures and / or under adiabatic conditions, thereby suppressing coking in the convection section.

[0031] Therefore, the convection section can be used to heat the entire hydrocarbon mixture, forming a gas-liquid mixture. The gaseous hydrocarbons are then separated from the liquid hydrocarbons, with only the separated vapor being fed into the radiant coils of one or more radiant chambers in a single heater. The geometry of the radiant coils can be of any type. For the desired hydrocarbon vapor mixture feed and reaction severity, the optimal residence coil can be selected to maximize olefins and run length.

[0032] If necessary, multiple heating and separation steps can be used to separate the hydrocarbon mixture into two or more hydrocarbon fractions. This allows for optimal cracking of each fraction, enabling the throughput, steam / oil ratio, heater inlet and outlet temperatures, and other variables to be controlled at desired levels to achieve desired reaction outcomes, such as achieving a desired product distribution while simultaneously engaging in limited coking in radiant coils and associated downstream equipment.

[0033] Because the various fractions (depending on the boiling points of the hydrocarbons in the mixture) are separated and cracked, coking in the radiant coils and transfer line heat exchangers can be controlled. Therefore, the operating length of the heaters can be increased to several weeks instead of hours, resulting in higher olefin yields.

[0034] The remaining liquid can be hydrotreated (e.g., hydrocracking and / or hydrocracking). When the fractionation point is low (e.g., around 200°C), the feed to the hydrocracker is higher. When the final boiling point is high, the feed to the hydrocracker is lower for any crude oil. Regardless of the fractionation point chosen, all remaining liquid can be fed to the hydrocracker. Alternatively, the liquid can be sent to a distillation column associated with the separation of hydrotreated products. In this column, jet fuel / kerosene (middle distillate) is separated, and only the VGO+ feedstock undergoes hydrocracking in the hydrocracker.

[0035] VGO+ feedstock can be further separated into VGO and residue oil. Any feedstock with a boiling point above 520°C can be considered residue oil. The aforementioned fractionation point of 520°C is exemplary; for example, it can vary between 480°C and 560°C. Through VGO / residue oil separation, VGO and residue oil can be processed separately using different hydrocrackers. Hydrocracking residue oil is more difficult than VGO. Depending on the quality of the crude oil and the quantity of residue oil, separating heavy liquids into VGO and residue oil may be economically attractive. If not economically attractive, all liquids can be hydrocracking in the same hydrocracker.

[0036] As mentioned above, the effluent from the hydrocracker can be separated in the distillation column. Even for hydrocracking, the recovery of residue oil must be carefully considered. To prevent over-coking in the reactor, some residue oil removal is required. This effluent is tar or bituminous fraction. When the 200°C+ liquid feed or 350°C+ feed from the vaporization system is fed directly to the hydrocracker without going to the hydrocracker effluent distillation column, the severity of the hydrocracker can be adjusted accordingly to, for example, mild severity or high severity cracking. Under mild conditions, only high molecular weight fractions undergo hydrocracking, most of the light feedstock (middle fraction) in the crude oil is retained, and the effluent is sent to the product separation column. This produces the largest amount of middle fraction fuel. In high severity mode, light components, such as LPG and naphtha fractions, will be added. For all cases described herein, a hydrodesulfurization unit can be used before the hydrocracker. Products such as LPG, naphtha, middle distillates, and unconverted oils with boiling points below the residue fractionation point (typically below 540°C) can be fed to the olefins plant as feedstock. Middle distillates can be sold as products if needed. When all products are sent to the olefins plant, the rate of chemical production increases. Only a small amount of tar (e.g., less than 5% of the total crude oil feed) can be sent as tar. This can be considered a chemical production maximization model. Chemical production decreases depending on the amount of middle distillates sold as products. The olefins plant produces hydrogen, methane, ethylene, ethane, propylene, propane, butadiene, butene, butane, C5-gasoline (C5-400°F), thermally cracked gas oil (PGO), and thermally cracked fuel oil (PFO>550°F). PGO and PFO fractions are highly hydrogen-deficient and are less desirable chemicals. Due to the use of a residue hydrocracker, all of the PGO and specific portions of the PFO (e.g., those with boiling points below 1000°F) can be sent to the residue hydrocracker. This maximizes olefin production in the olefin plant. Using a residue hydrocracker, high molecular weight PGO and PFO are hydrocracking, and low molecular weight LPG and naphtha, among other liquid products, can also be used as feedstock for the olefin plant. This maximizes chemical yield. All operations described herein can be performed without a crude oil tower. Minor modifications to the embodiments disclosed herein are possible to suit local conditions to improve process economics or desired products.

[0037] As stated above, without separation (e.g., by upstream distillation or fractionation into multiple hydrocarbon fractions), it is currently not feasible and economical to crack crude oil and / or heavy feedstocks with final boiling points above 520°C or 550°C. Instead, the embodiments described herein can separate various hydrocarbons for crude oil cracking using fractionators, with or without fractionators. Compared to processes requiring extensive fractionation, the embodiments described herein can have lower capital costs and require less energy. Furthermore, the embodiments described herein convert a significant portion of the crude oil through cracking to produce high yields of olefins.

[0038] By separating the hydrocarbon mixture into various fractions, coking in each stage can be controlled through appropriate equipment design and controlled operating conditions. When steam is present, the hydrocarbon mixture can be heated to high temperatures in the convection stage without coking. Additional steam can be added to further adiabatically vaporize the fluid. Therefore, coking in the convection stage is minimized. Since different fractions can be processed in separate coils, the severity of each fraction can be controlled. This reduces coking in the radiant coils and transfer line heat exchanger (TLE). Overall, olefin yield can be maximized compared to a single fraction removing heavy tail oil (high-boiling residue). Heavy oil processing schemes or conventional preheating of the entire crude oil without various boiling fractions produce less total olefins compared to the embodiments disclosed herein. In the processes disclosed herein, any material from low boiling points to any final boiling point can be processed under optimal conditions for that material. Crude oil can be processed into one, two, three, or more individual fractions, and each fraction can be processed separately under optimal conditions.

[0039] Saturated and / or superheated dilution steam can be added at appropriate points to vaporize the feed to the extent required for each stage. Primary separation of the hydrocarbon mixture can be performed, for example, via a flash tank or a separator with minimal theoretical plates, to separate the hydrocarbons into various fractions. Heavy tail oil can then be processed (as updated in this disclosure, as well as hydrocracking and recycling).

[0040] The hydrocarbon mixture can be preheated using waste heat from the process stream, which includes effluent from the cracking process or flue gas from the pyrolysis reactor / heater. Alternatively, a crude oil heater can be used for preheating. In this case, to maximize the thermal efficiency of the pyrolysis reactor, other cold fluids, such as boiler feedwater (BFW) or air preheaters or economizers, can be used as the uppermost cold sink in the convection section.

[0041] The process of cracking hydrocarbons in a thermal cracking reactor can be divided into three parts: a convection section, a radiative section, and a quench section (e.g., in a transfer line heat exchanger (TLE)). In the convection section, the feed is preheated, partially vaporized, and mixed with steam. In the radiative section, the feed is cracked (where the main cracking reaction occurs). In the TLE, the reaction fluid is rapidly cooled to stop the reaction and control the product mixture. Direct quenching of the oil instead of indirect quenching via heat exchange is also acceptable.

[0042] The embodiments described herein effectively utilize the convection section to enhance the cracking process. In some embodiments, all heating can be performed in the convection section of a single reactor. In other embodiments, separate heaters can be used for each fraction. In some embodiments, crude oil enters the top layer of the convection tank and is preheated to a moderate temperature at operating pressure by hot flue gas generated in the radiant section of the heater without the addition of any steam. Depending on the crude oil and yield, the outlet temperature can range from 150°C to 400°C. Under these conditions, 5% to 70% (by volume) of the crude oil may be vaporized. For example, the outlet temperature of this first heating step can allow naphtha (with a standard boiling point of up to about 200°C) to vaporize. Other fractionation points (final boiling points), such as 350°C (gas oil), can also be used. Because the hot flue gas generated in the radiant section of the heater preheats the hydrocarbon mixture, limited temperature variations and flexibility in the outlet temperature can be anticipated.

[0043] The preheated hydrocarbon mixture enters the flash tank for the separation of vaporized and unvaporized portions. The vapor can be further superheated, mixed with dilution vapor, and then sent to the radiant coils for cracking. If insufficient material is vaporized, superheated dilution vapor can be added to the fluid within the tank. If sufficient material is vaporized, cold (saturated or moderately superheated) vapor can then be added to the steam. For proper heat balance, superheated dilution vapor can also be used instead of cold vapor.

[0044] The mixture of vapor fraction (e.g., naphtha fraction, gas oil fraction, or light hydrocarbon fraction) and dilution steam is further superheated in the convection section and then enters the radiant coils. The radiant coils can be in different chambers, or a group of radiant coils in a single chamber can be used to crack the hydrocarbons in the vapor fraction. The amount of dilution steam can be controlled to minimize total energy consumption. Typically, the steam is controlled at a steam-to-oil ratio of approximately 0.5 w / w, where any value from 0.2 w / w to 1.0 w / w is acceptable, for example, from approximately 0.3 w / w to approximately 0.7 w / w.

[0045] The liquid (unvaporized) in the flash tank can be mixed with a small amount of dilution steam and further heated in the convection section of a second convection zone coil, which can be in the same or a different heater. The S / O (steam / oil ratio) of this coil can be approximately 0.1 w / w, with any value from 0.05 w / w to 0.4 w / w being acceptable. Since the steam will also be heated along with the crude oil, there is no need to inject superheated steam. Saturated steam is sufficient. However, superheated steam can be used instead of saturated steam. Superheated steam can also be fed to the second flash tank. This tank can be a simple gas / liquid separator or a more complex one, such as a tower with internal components. For most crude oils, the final boiling point is high, and some material will never vaporize at the outlet of this coil. Typical outlet temperatures can be in the range of approximately 300°C to approximately 500°C, for example, approximately 400°C. The outlet temperature can be selected to minimize coking in this coil. The amount of steam added to the stream is sufficient to achieve the maximum outlet temperature with minimal dilution flow and without coking. The presence of steam inhibits coking. For highly coking crude oil, a higher steam flow rate is preferred.

[0046] Superheated steam can be added to the tank and will further vaporize the hydrocarbon mixture. The steam is further superheated in the convection coil and then enters the radiant coil. To prevent any steam condensation in the line, a small amount of superheated dilution steam can be added to the tank outlet (steam side). This will prevent the condensation of heavy materials in the line, which could eventually lead to coking. The tank can also be designed to accommodate this function. In some embodiments, a Heavy Oil Processing System (“HOPS”) tower can be used to address the condensation of heavy materials.

[0047] Unvaporized liquid can be further processed or fed to fuel. If further processing is required, a HOPS column is preferred. If a portion of the unvaporized liquid is fed to fuel, the hot unvaporized liquid can be heat-exchanged with other cold fluids (e.g., hydrocarbon feedstocks or first liquid fractions) to maximize energy recovery. Alternatively, the unvaporized liquid can be processed as described herein to produce additional olefins and higher-value products. Furthermore, the available heat energy in this stream can be used to preheat other process streams or to generate steam.

[0048] Radiant coil technology can be of any type with a residence time ranging from 90 milliseconds to 1000 milliseconds, featuring multiple rows and parallel channels and / or branching coil arrangements. They can be vertical or horizontal. The coil material can be a high-strength alloy, with exposed and finned coils, or internally improved heat transfer tubes. The heater can consist of one radiant chamber with multiple coils and / or two radiant chambers with multiple coils in each chamber. The geometry and dimensions of the radiant coils in each chamber, as well as the number of coils, can be the same or different. Multi-flow heaters / heat exchangers can be used if cost is not a factor.

[0049] After cracking in radiant coils, one or more oil-to-line heat exchangers can be used to cool the product very rapidly and generate (ultra) high-pressure steam. One or more coils can be combined and connected to each heat exchanger. The heat exchangers can be two-tube heat exchangers or multi-tube shell-and-tube heat exchangers.

[0050] Direct quenching can also be used instead of indirect cooling. In such cases, oil can be injected at the outlet of the radiant coil. After oil quenching, water quenching can also be used. Using full water quenching instead of oil quenching is also acceptable. After quenching, the product is sent to the recovery section.

[0051] Figure 2 This is a simplified process flow diagram of an integrated thermal cracking-hydrocracking system according to embodiments of this document. A combustion tubular furnace 1 is used to crack hydrocarbons in a hydrocarbon mixture into ethylene and other olefin compounds. The combustion tubular furnace 1 has a convection section (or convection zone) 2 and a cracking section (or cracking zone) 3. The furnace 1 includes one or more process tubes 4 (radiant coils) through which a portion of the hydrocarbons introduced into the system via the hydrocarbon feed line 22 is cracked to produce gaseous products during heating. Radiant heat and convective heat are provided by combustion of a heating medium, which is introduced into the cracking section 3 of the furnace 1 through a heating medium inlet 8 (such as a hearth burner, floor burner, or wall burner) and discharged through an exhaust port 10.

[0052] Hydrocarbon feedstock 22 (which may be a mixture of crude oil 19 and gas oil 21, and may include hydrocarbons ranging from naphtha-class hydrocarbons to hydrocarbons with a standard boiling point greater than 450°C) can be introduced into heating coil 24 located in the convection section 2 of the thermal cracking heater 1. For example, hydrocarbon feedstock containing components with standard boiling points higher than 475°C, 500°C, 525°C, or 550°C can be introduced into heating coil 24. In heating coil 24, the hydrocarbon feedstock can be partially vaporized, i.e., the lighter components of the hydrocarbon feedstock, such as naphtha-class hydrocarbons, can be vaporized. The heated hydrocarbon feedstock 26 is then sent to separator 27 to separate into vapor fraction 28 and liquid fraction 60.

[0053] Steam can be supplied to the process via flow line 32. Different parts of the process can use low-temperature or saturated steam, while other parts can use high-temperature superheated steam. The steam to be superheated can be fed into the heating coil 34 via flow line 32, heated in the convection zone 2 of the pyrolysis heater 1, and recovered as superheated steam via flow line 36.

[0054] A portion of the steam can be fed through flow line 40 and mixed with vapor fraction 28 to form a steam / hydrocarbon mixture in line 42. The steam / hydrocarbon mixture in flow line 42 can then be fed into heating coil 44. The resulting superheated mixture can then be fed through flow line 46 into one or more cracking coils 4 located in the radiant zone 3 of the thermal cracking heater 1. As described above, the cracked hydrocarbon products can then be recovered via flow line 12 for heat recovery, quenching, and product recovery (not shown).

[0055] Superheated steam 36 can be injected directly into separator 27 via flow line 72. Injecting superheated steam into the separator may reduce the partial pressure and increase the hydrocarbon content in the vapor fraction 28. Steam or superheated steam can also be introduced into one or both of streams 22 and 26.

[0056] Hydrogen 59 and a liquid fraction 60 comprising high-boiling (residual) hydrocarbons from the feed mixture 22 can then be fed into a hydrocracking reactor system 61. The hydrocracking reactor system 61 may include one or more reaction zones and may include a fixed-bed reactor, a fluidized-bed reactor, or other types of reaction systems known in the art.

[0057] In the hydrocracking reactor system 61, hydrogen 59 and hydrocarbons in the liquid fraction 60 can be contacted with a hydrocracking catalyst to hydrocrackle a portion of the hydrocarbons in the liquid fraction to form lighter hydrocarbons, including olefins and other products. Effluent 63, which may include unreacted hydrogen and various hydrocarbons, can be recovered from the hydrocracking reactor system 61. Unreacted hydrogen 67 in the effluent can then be separated from hydrocarbons 69 using a separator 65. If desired, the unreacted hydrogen can be recycled to continue the reaction in the hydrocracking reactor system 61. The hydrocarbon effluent 69 can then be fractionated in a fractionation system 71, which may include an atmospheric distillation column and / or a vacuum distillation column, to separate the hydrocarbon effluent into two or more hydrocarbon fractions, which may include one or more light petroleum gas fractions 73, naphtha fractions 75, jet fuel or kerosene fractions 77, one or more atmospheric or vacuum gas oil fractions 79, and residue fractions 81. In some embodiments, gas oil fraction 79, or a portion thereof, can then be used as feed stream 21 and combined with whole crude oil 19 to form a mixed hydrocarbon feed 22, thereby integrating the hydrocracking reaction system with the thermal cracking unit. Other gas oil fractions (including those from exogenous sources) besides gas oil fraction 79, or as an alternative to gas oil fraction 79, can also be used as feed stream 21. Furthermore, although not shown, feed 22 may include other feeds similar to whole crude oil 19 and / or gas oil fraction 79. Residue fraction 81, or a portion thereof, can be returned to the hydrocracking reaction system for additional conversion and additional olefin production.

[0058] Figure 3 This is a simplified process flow diagram of an integrated thermal cracking-hydrocracking system according to embodiments of this document. A combustion tubular furnace 1 is used to crack hydrocarbons into ethylene and other olefin compounds. The combustion tubular furnace 1 has a convection section (or convection zone) 2 and a cracking section (or cracking zone) 3. The furnace 1 includes one or more process tubes 4 (radiant coils) through which a portion of the hydrocarbons fed via the hydrocarbon feed line 22 is cracked to produce gaseous products during heating. Radiant heat and convective heat are provided by combustion of a heating medium, which is introduced into the cracking section 3 of the furnace 1 through a heating medium inlet 8 (such as a hearth burner, floor burner, or wall burner) and discharged through an exhaust port 10.

[0059] Hydrocarbon feedstock 22 (which may be pure crude oil or a mixture of hydrocarbons including hydrocarbons from the naphtha range to hydrocarbons with a standard boiling point greater than 450°C) can be introduced into heating coil 24 located in the convection section 2 of the thermal cracking heater 1. For example, hydrocarbon feedstock containing components with standard boiling points higher than 475°C, 500°C, 525°C, or 550°C can be introduced into heating coil 24. In heating coil 24, the hydrocarbon feedstock can be partially vaporized, i.e., the lighter components of the hydrocarbon feedstock, such as hydrocarbons from the naphtha range, can be vaporized. The heated hydrocarbon feedstock 26 is then sent to separator 27 to separate it into a vapor fraction 28 and a liquid fraction 30.

[0060] Steam can be supplied to the process via flow line 32. Different parts of the process can use low-temperature or saturated steam, while other parts can use high-temperature superheated steam. The superheated steam can be sent to the heating coil 34 via flow line 32 for heating in the convection zone 2 of the pyrolysis heater 1, and then recovered as superheated steam via flow line 36.

[0061] A portion of the steam can be fed through flow line 40 and mixed with steam fraction 28 to form a steam / hydrocarbon mixture in line 42. The steam / hydrocarbon mixture in flow line 42 can then be sent to heating coil 44. The resulting superheated mixture can then be sent through flow line 46 to cracking coil 4 located in the radiant zone 3 of the thermal cracking heater 1. The cracked hydrocarbon products can then be recovered through flow line 12 for heat recovery, quenching, and product recovery.

[0062] In the same or different heaters, the liquid fraction 30 can be mixed with steam 50 and fed into a heating coil 52 located in the convection zone 2 of the thermal cracking reactor 1. In the heating coil 52, the liquid fraction, i.e., the lighter components remaining in the hydrocarbon feedstock, such as hydrocarbons ranging from middle distillates to gas oils, can be partially vaporized. Injecting steam into the liquid fraction 30 helps prevent coking in the heating coil 52. The heated liquid fraction 54 is then fed to a separator 56 to separate it into a vapor fraction 58 and a liquid fraction 60.

[0063] A portion of the superheated steam can be fed through flow line 62 and mixed with vapor fraction 58 to form a steam / hydrocarbon mixture in line 64. The steam / hydrocarbon mixture in flow line 64 can then be sent to heating coil 66. The resulting superheated mixture can then be sent through flow line 68 to cracking coil 4 located in the radiant zone 3 of the thermal cracking heater 1. The cracked hydrocarbon products can then be recovered through flow line 13 for heat recovery, quenching, and product recovery.

[0064] Superheated steam can be directly injected into separators 27 and 56 via flow lines 72 and 74, respectively. Injecting superheated steam into the separators can reduce the partial pressure and increase the hydrocarbon content in the vapor fractions 28 and 58.

[0065] In addition to heating hydrocarbon and steam streams, convection zone 2 can also be used to heat other process streams and steam streams, for example, via coils 80, 82, and 84. For instance, coils 80, 82, and 84 can be used to heat BFW (boiler feedwater) and preheat SHP (ultra-high pressure) steam.

[0066] The positions and numbers of coils 24, 52, 34, 44, 66, 80, 82, and 84 can vary depending on the design and the expected available feedstock. In this way, the convection section can be designed to maximize energy recovery from the flue gas. In some embodiments, it may be desirable to position superheated coil 44 at a higher flue gas temperature than superheated coil 66. Cracking of lighter hydrocarbons can be carried out at higher severities, and by appropriately positioning the superheated coils, cracking conditions can be enhanced or adjusted for specific vapor fractions. Similarly, when processing vapor fractions in different heaters, the coil positions, heater conditions, and other variables can be independently adjusted to match the cracking conditions to the desired severity.

[0067] In some embodiments, the first separator 27 may be a flash tank, and the second separator 56 may be a heavy oil processing system (HOPS) tower as described below (e.g. Figure 6 (As shown).

[0068] As mentioned above Figure 2 The liquid fraction 60 can then be processed in an integrated hydrocracking system. Hydrogen 59 and the liquid fraction 60, comprising high-boiling (residual) hydrocarbons from the feed mixture 22, can be fed to a hydrocracking reactor system 61, which may include one or more reaction zones and may include a fixed-bed reactor, a fluidized-bed reactor, or other types of reaction systems known in the art.

[0069] In the hydrocracking reactor system 61, the liquid fraction 60 can be contacted with a hydrocracking catalyst to crack a portion of the hydrocarbons in the liquid fraction to form lighter hydrocarbons, including olefins and other products. Effluent 63 can be recovered from the hydrocracking reactor system 61, and effluent 63 may include unreacted hydrogen and various hydrocarbons. Unreacted hydrogen 67 in the effluent can then be separated from hydrocarbons 69 using a separator 65. The hydrocarbon effluent 69 can then be fractionated in a fractionation system 71, which may include an atmospheric distillation column and / or a vacuum distillation column, to separate the hydrocarbon effluent into two or more hydrocarbon fractions, which may include one or more light petroleum gas fractions 73, naphtha fractions 75, jet fuel or kerosene fractions 77, one or more atmospheric or vacuum gas oil fractions 79, and residue oil fractions 81. Then, gas oil fraction 79, or a portion thereof, can be used as feedstock 21 and combined with whole crude oil 19 to form a mixed hydrocarbon feedstock 22, thereby integrating the hydrocracking reaction system with the thermal cracking unit. Residue fraction 81, or a portion thereof, can be returned to the hydrocracking reaction system for additional conversion and additional olefin production.

[0070] Although not in Figure 2 or Figure 3 As shown, additional hydrocarbons in liquid fraction 60 can be volatilized and cracked to maximize olefin recovery in the process. For example, liquid fraction 60 can be mixed with steam to form a steam / oil mixture. The resulting steam / oil mixture can then be heated in convection zone 2 of the thermal cracking reactor 1 to vaporize a portion of the hydrocarbons in the steam / oil mixture. The heated stream can then be sent to a third separator to separate a vapor fraction from the liquid fraction, the vapor fraction being, for example, hydrocarbons in the range of vacuum gas oil. Superheated steam can also be introduced into the separator to facilitate separation, and into the recovered vapor fraction to prevent the vapor fraction from condensing in the transfer line before being introduced into the cracking coil for olefin production. The liquid fraction recovered from the separator may include the heaviest component of the hydrocarbon mixture 22, such as hydrocarbons with a standard boiling point above 520°C or 550°C, and the resulting liquid fraction can be processed as described above regarding... Figure 2 and Figure 3 The integrated hydrocracking system is then used for further processing.

[0071] Compared to traditional methods that pre-fractionate the entire mixed hydrocarbon feedstock into separately processed fractions, Figure 2 and Figure 3 Its configuration has significant advantages. Using... Figure 4 The embodiments shown provide additional process flexibility, such as the ability to handle a wide range of variable raw materials.

[0072] like Figure 4As shown, where the same numbers represent the same components, the mixed hydrocarbon feed 22 can be fed to heater 90. In heater 90, the hydrocarbon feed can undergo indirect heat exchange contact with heat exchange medium 96 to increase the temperature of the hydrocarbon feed 22, resulting in heated feed 92. The heated feed 92 can be kept in a liquid state or partially vaporized. Heat exchange medium 96 can be heat exchange oil, steam, process streams, etc., used to provide heat to the mixed hydrocarbon feed 22.

[0073] The heated feed 92 can then be introduced into separator 27 to separate the lighter hydrocarbons from the heavier hydrocarbons. Steam 72 can also be introduced into separator 27 to increase the volatilization of the lighter hydrocarbons. Then, as described above... Figure 2 and Figure 3 The process involves handling vapor fraction 28 and liquid fraction 30, cracking one or more vapor fractions to produce olefins, and recovering heavy hydrocarbon fractions containing hydrocarbons with very high standard boiling points (e.g., above 550°C).

[0074] like Figure 4 As shown, when external preheating of crude oil is completed in a heat exchanger or preheater, the economizer or BFW coil 83 can occupy the top layer of convection section 2. To further improve efficiency, flue gas from two or more heaters can be collected, and additional heat can be recovered using the combined flue gas, for example, by preheating the feed, preheating the combustion air, generating low-pressure steam, or heating other process fluids.

[0075] Steam has a very low heat capacity, and the heat of vaporization of oil is also important. Furthermore, the available thermal energy in the convection zone of the pyrolysis reactor is not unlimited, and the multiple tasks of volatilizing the hydrocarbon feed, superheating the steam, and superheating the hydrocarbon / steam mixture fed to the radiant coils can result in significant high-boiling-point residues. Additional heaters can be used to preheat the hydrocarbon feed and / or dilute the steam, thereby increasing the overall process flexibility in handling hydrocarbon mixtures with both small and large amounts of heavier hydrocarbons and improving the total olefin yield from the hydrocarbon mixture.

[0076] This embodiment is in Figure 5 The design is expanded to include a dedicated heater 100 used solely for preheating hydrocarbon feedstock. Heater 100 preferably does not crack any feedstock into olefins. Instead, heater 100 performs the function of heating the convection section as described above. Regarding... Figure 5 The temperatures described are merely illustrative and can be varied to achieve the desired hydrocarbon fractionation.

[0077] Crude oil 102 is fed into heating coil 104 and preheated to a relatively low temperature in heater 100. The heated feed 106 is then mixed with steam 108, which can be dilution steam or superheated dilution steam. Preheating and contact with the steam vaporizes hydrocarbons with a standard boiling point of approximately 200°C or lower (i.e., naphtha fractions). The volatile hydrocarbons and vapors can then be separated from the non-volatile hydrocarbons in tank 110, recovering vapor fraction 112 and liquid fraction 114. Vapor fraction 112 can then be further diluted with steam (if necessary), superheated in a convection section, and sent to the radiant coil (not shown) of the pyrolysis reactor.

[0078] Liquid fraction 114 can be mixed with dilution vapor 116 (which may be saturated dilution vapor) and then fed to heating coil 117 and heated to a moderate temperature in combustion heater 100. The heated liquid fraction 118 can then be mixed with superheated dilution vapor 120, and the mixture is fed to flash tank 122. Hydrocarbons with a boiling range of about 200°C to about 350°C are vaporized and recovered as vapor fraction 124. Vapor fraction 124 can then be superheated and fed to the radiant section (not shown) of a pyrolysis reactor.

[0079] The liquid fraction 126 recovered from flash tank 122 is reheated with saturated (or superheated) dilution steam 127, passed through coil 128, and further superheated in combustion heater 100. Superheated dilution steam 130 can be added to the heated liquid / vapor stream 132 and sent to separator 134 to separate into vapor fraction 136 and liquid fraction 138. This separation will cut off a portion at 350°C to 550°C (VGO) for recovery as vapor fraction 136, which can be superheated by additional dilution steam (if necessary) and sent to the radiant section (not shown) of the pyrolysis reactor.

[0080] In some embodiments, separator 134 may be a flash tank. In other embodiments, separator 134 may be a HOPS tower. Alternatively, separation system 134 may include both a flash tank and a HOPS tower, wherein vapor fraction 136 may be recovered from the flash tank, then further heated with dilution steam, and fed to the HOPS tower. When using a HOPS unit, only vaporizable material is cracked. Unvaporized material 138 may be recovered and fed, for example, to fuel, or further processed as described below to produce additional olefins. Additional dilution steam (not shown) is added to the vapor before it is fed to the radiant section of the pyrolysis reactor. In this way, many fractions can be obtained using separate combustion heaters, and each fraction can be optimally cracked.

[0081] For each of the above embodiments, a common heater design is possible. To improve the thermal efficiency of such a heater, the top layer (cold source) can be any cryogenic fluid, BFW, or energy-saving device, such as... Figure 4 As shown. Heating and superheating of the fluid, with or without steam, can be completed in the convection section, radiation section, or both sections of a combustion heater. Additional superheating can be completed in the convection section of a cracking heater. In the heater, the maximum heating of the fluid should be limited to a temperature below the crude oil coking temperature, which for most crude oils may be around 500°C. At higher temperatures, sufficient dilution steam should be present to inhibit coking.

[0082] The dilution steam can also be superheated so that the energy balance of the cracking heater does not significantly affect the severity of the cracking. Typically, the dilution steam is superheated in the same heater used for feed cracking (referred to as an integrated superheater). Alternatively, the dilution steam can be superheated in a separate heater. The choice between an integrated or separate dilution steam superheater depends on the available energy in the flue gas.

[0083] exist Figure 6 A simplified sketch of a HOPS column 150 is shown. Various modifications can be made to this scheme. In the HOPS column, superheated dilution vapor 152 is added to hot liquid 154, and a separation zone 156 comprising 2 to 10 theoretical plates is used to separate vaporizable hydrocarbons from non-vaporizable hydrocarbons. This process reduces the residue of fine droplets in the overhead fraction 160, where high-boiling-point residues in the vapor would lead to coking. Heavy, non-vaporizable hydrocarbons are recovered in the bottom fraction 162, while vaporizable hydrocarbons and dilution vapor are recovered in the overhead product fraction 164. The HOPS column 150 may include internal distributors, packed and / or unpacked. When using a HOPS column, gas / liquid separation can be nearly ideal. The final boiling point of the vapor is predictable based on operating conditions, and any liquid residue in the gas phase can be minimized. Although this option is more expensive than a flash tank, the benefits of reduced coking far outweigh the increased cost. The liquid in the stream 162 can be recycled to the appropriate stage of the process for further processing.

[0084] In the embodiments described herein, all vapor fractions can be cracked in different coils within the same reactor. In this way, a single heater can be used for different fractions, and optimal conditions can be achieved for each fraction. Alternatively, multiple heaters can be used.

[0085] As mentioned above Figure 2 and Figure 3 The non-volatile materials obtained, such as those in streams 60 and 138, as described and illustrated, can be fed into the integrated hydrocracking unit.

[0086] In some embodiments, one or more liquid fractions (e.g., liquid fraction 30 or 60) may need to be further processed to remove metals, nitrogen, sulfur, or Conradson carbon residue before further processing within the integrated hydrocracking and pyrolysis system. Figure 7 The document illustrates a configuration for such further processing and integration according to embodiments thereof.

[0087] like Figure 7 As shown, for example, as mentioned above... Figure 2 and Figure 3 As described in feed 22, a hydrocarbon mixture 222 (such as crude oil or crude oil mixed with gas oil) is fed to the convection zone 202 of the thermal cracking heater 201. The heated mixture 224 is flashed in the separator 203, and the vapor fraction 204 is fed to the reaction section (radiation zone) 205 of the thermal cracking heater 201, where the vapor stream is converted into olefins. The resulting effluent 206 is then fed to the olefin recovery section 208, where hydrocarbons can be separated into various hydrocarbon fractions via fractionation, such as light petroleum gas fraction 209, naphtha fraction 210, jet fuel or diesel fraction 211, and heavy fraction 212.

[0088] The liquid fraction 214 recovered from separator 203 can be hydrotreated in fixed-bed reactor system 216 to remove one or more of metals, sulfur, nitrogen, CCR, and asphaltenes, producing a hydrotreated liquid 218 with a lower density. Liquid 218 is then fed to convection zone 220 of pyrolysis heater 221. In some embodiments, separator 219 can be used to remove vapor 245 from the hydrotreated liquid 218, wherein vapor 245 may react in reaction section 205 of pyrolysis heater 201 (in the same or a different coil than vapor 204).

[0089] Then, the heated mixture 243 obtained by heating the liquid 218 in the convection zone 220 is flashed in the separator 226, and the vapor 227 is sent to the reaction zone 228 of the thermal cracking heater 221, where the vapor stream is converted into olefins and sent to the olefin recovery section 208 via the flow line 247.

[0090] Liquid 229 from separator 226 is fed into fluidized bed or slurry hydrocracking reactor 250 for near-complete conversion of liquids with nominal boiling points above 550°C, converting hydrocarbons into products with boiling points below 550°C. Effluent 253 from hydrocracking reaction zone 250 can be sent to separation zone 255 (where lighter product 251 is distilled from the reactor effluent and sent to the respective thermal cracking reactor zones of heaters 201 and 221), and can be guided through hydrotreating processor 216 or simply combined with streams of similar boiling range sent to the thermal cracking reactor zone.

[0091] Liquid 212 (generally at 370-550°C) from fractionation section 208 is fed to a total conversion hydrocracking unit 260 integrated with the remaining fluidized bed or slurry hydrocracking system 250 for complete conversion to naphtha 261 or a stream of naphtha and unconverted oil 261. In the case where stream 261 consists entirely of naphtha products, naphtha 261 can be processed in the reaction zone (not shown) of a separate thermal cracking heater or in a heater coil in one of reaction zones 205, 228. In other embodiments, the naphtha and unconverted oil stream 261 can be separated into various fractions 274, 276 in one or more separators 270, 272, which can be fed to reaction zones 205, 228 for co-processing or separate processing with vapor fractions 204, 245, 227, respectively, in reaction zones 205, 228. In the convection section 290 of the pyrolysis heater 292, heating and separation of the unconverted oil stream or a portion thereof can occur. The liquid 280 in the unconverted oil stream can then be fed into its own pyrolysis reaction section 294 within the pyrolysis heater 292 to be converted into olefins. The pyrolysis effluent 296 can then be sent to the olefin recovery zone 208.

[0092] The embodiments described herein can completely eliminate the need for a refinery, while making the crude oil-to-chemicals process highly flexible in terms of crude oil. The process disclosed herein is flexible for crude oils with high levels of contaminants (sulfur, nitrogen, metals, CCR), which distinguishes it from whole-crude oil processes that can only process very light crude oils or condensates. Instead of hydrotreating the entire crude oil (which involves very large reactor volumes and is inefficient in terms of hydrogenation), the process described herein hydrogenates only as needed and at the correct sites within the process.

[0093] Furthermore, the embodiments described herein utilize a unique blend of the thermal cracking convection and reaction zones to process different types of feedstock derived from selective hydrocracking and hydrocracking crude oil components. Complete crude oil conversion can be achieved without a refinery.

[0094] Vapor and liquid generated in the convection section can be effectively separated via a HOPS separator. The embodiments described herein use the convection section of a first heater to separate light components that can be readily converted to olefins without requiring hydrotreating. The liquid can then be efficiently hydrotreated using a fixed-bed catalyst system for HDM, DCCR, HDS, and HDN to remove impurity atoms that affect yield / fouling rates, prior to further thermal cracking. The embodiments described herein may also utilize fluidized bed or slurry hydrocracking reactors and catalyst systems to convert the heaviest components of the crude oil in an intermediate step.

[0095] The embodiments described herein can further utilize a fixed-bed hydrocracking system to convert low-density aromatic products derived from the heaviest crude oil components into high-hydrogen-content products, which are then sent for thermal cracking. The embodiments described herein can also minimize the production of thermally cracked fuel oil by carefully hydrogenating and conducting the thermal cracking reaction in a dedicated heater customized for the feed being processed. The production of thermally cracked oil is minimized by enabling the hydrogenation system to handle different fractions of the feed (e.g., by separating the feed in a HOPS separator). The recovery and hydroprocessing of the thermally cracked oil produced by the embodiments described herein within different hydrocracking stages avoids the output of low-value thermally cracked oil.

[0096] Furthermore, a feature of the embodiments described herein is the hydrocracking of thermally cracked fuel oil and the thermal cracking of the hydrocracking feedstock. Typical VGO contains approximately 12-13 wt% hydrogen, while PFO contains approximately 7 wt% hydrogen. Additionally, PFO can contain a significant amount of polycyclic aromatic hydrocarbons, including hydrocarbon molecules with more than six rings. Therefore, hydrocracking of vacuum gas oil is easier compared to PFO. The hydrocrackers in the embodiments described herein can be designed to handle such heavy feedstocks.

[0097] Example

[0098] Example 1: Arab crude oil

[0099] Table 1 shows the calculated yields obtained from crude oil cracking. All calculations are based on theoretical models. The yields at high severity are shown, assuming that run length (even several hours) is not a factor, although other severity levels can be used.

[0100] For this example, Nigerian light crude oil is considered. The properties and distillation profile of this crude oil are shown in Table 1.

[0101] Table 1

[0102]

[0103] Table 2 shows the simulated thermal cracking yields of cracked crude oil based on model calculations. This example studies three cases: Case 1 – integration of all crude oil and gas oil products; Case 2 – integration of all crude oil and gas oil with residue hydrocracking unit; and a reference case, Case 3 – thermal cracking of full-range naphtha.

[0104] Naphtha fraction (<200℃), gas oil fraction (200-340℃), and VGO+ (>340℃) were considered. In Case 1, the naphtha and gas oil fractions were thus cracked in a thermal cracking coil. The VGO+ feedstock was sent to a residue hydrocracker. The hydrocracker products were sent to the thermal cracking unit. A small fraction was removed from the hydrocracker as percolate to minimize the scaling rate of the hydrocracker.

[0105] In Case 2, similar to Case 1, the generated thermally cracked gas oil and thermally cracked fuel oil (205℃+) are sent to the residue hydrocracking unit, and the products from the hydrocracking unit are sent to the thermal cracking unit.

[0106] For all cases, the feedstock was cracked under high severity to minimize material consumption. For reference, a typical full-range naphtha was considered. The naphtha characteristics are: specific gravity = 0.708, initial boiling point = 32°C, 50 vol% = 110°C, final boiling point = 203°C; alkanes = 68 wt%, cycloalkanes = 23.2 wt%, aromatics = 8.8 wt%.

[0107] In all cases, ethane and propane produced by the olefins plant are recycled until depleted. Ethane is cracked at a conversion rate of 65%. This example uses two highly selective SRT heaters. The coil outlet pressure is chosen to be 1.7 bara.

[0108] The following table shows the material balance for a typical 1 million tonne ethylene production under high-severity conditions.

[0109] Table 2

[0110]

[0111]

[0112]

[0113] Hydrocracking heavy oil and feeding the product as feedstock to olefin plants yields final yields comparable to naphtha crackers. When residue hydrocracking is not used, not only is residue hydrocracking performed, but fuel oil produced in the olefin plant can also be hydrocracking and integrated into the olefin plant feedstock. This improves final yields and is better than typical naphtha crackers. Crude oil can be processed in olefin plants by integration with conventional hydrocrackers and / or residue hydrocrackers without separating it into various fractions. This increases final olefin production, minimizes feedstock consumption, and improves the economics of crude oil cracking. The production of lower-value fuel oil is significantly reduced, thus saving resources.

[0114] When high-value fuels, such as kerosene and / or diesel, are required, these products can be obtained from the distillation column used in the hydrocracker. These products do not need to be sent to the olefins plant—since they have already passed through the hydrocracker, they will also meet fuel specifications, avoiding the separate hydroprocessing unit required by the crude oil distillation unit in cases where these products are produced from the crude oil column. This reduces capital investment. Furthermore, the flowchart presented herein can be modified to meet the desired olefins to fuel ratio.

[0115] Example 2

[0116] The following material balance is achieved using Arab crude oil.

[0117]

[0118]

[0119]

[0120]

[0121]

[0122] For this balance, a residue-free crude oil liquid of 10,000 kTA (excluding LPG) is selected as the base and blended with the corresponding 1564.3 kTA residue. The residue-free portion is the conventional feedstock. Under high severity (Case 1A), 3637.8 kTA ethylene and 1572.7 kTA propylene will be produced. Under low severity (Case 1B), the same amount of feedstock will produce 3435.5 kTA ethylene and 11926.7 kTA propylene. Since the crude oil contains residue, to obtain a 10,000 kTA crackable feedstock, 11564.3 kTA crude oil must be used, and the 1564.3 kTA residue will be discarded. The current crackable feedstock is light gas (668.4 kTA), light naphtha (2889.2 kTA), heavy naphtha (2390.0 kTA), and heavy oil (4052.4 kTA). Cases 1A, 2A, and 3A represent all feedstocks in a high-criticality cracking olefins plant. Cases 1B, 2B, and 3B represent the corresponding low-criticality cases.

[0123] Cases 1A and 1B use conventional methods with gaseous feed, naphtha feed, and heavy fluidized bed feed. Some of the heavy fluidized bed feed is hydrocracking to produce feedstock for the olefins plant.

[0124] Cases 2A and 2B use the same feedstock and hydrocracking the residue in the residue hydrotreating unit, and also crack the products of the hydrocracker in addition to the feedstock used in Cases 1A or 1B.

[0125] Cases 3A and 3B used all the feedstocks used in 2A or 2B, and also cracked the hydrotreated thermally cracked fuel oil (PFO). The PFO was hydrocracked in a special hydrocracker. The PFO was generated in the cracker and recycled back to the cracker after hydrocracking.

[0126] As shown in the table below, ethylene and propylene production increased significantly with the cracking of residual oil and the hydrocracking of recycled PFO. All values ​​are in KTA (thousand tons per year).

[0127]

[0128] By cracking residue oil and thermally cracked fuel olefins, yields are significantly improved. For a fixed amount of ethylene or olefin production, crude oil consumption is reduced. This is an advantage of hydrotreated cracked residue oil and thermally cracked fuel oil. In industry, %C2 + C3 shown in the table represents the final yield.

[0129] In some of the examples above, high-severity cracking was used. The embodiments described herein are not limited to high-severity. The thermal cracking heater can be modified to meet the desired propylene to ethylene ratio. When a very high propylene ratio is required, olefin conversion technologies can be used, for example, to produce propylene using the resulting butene and ethylene (e.g., disproportionation). When the butene produced in thermal cracking is insufficient for olefin conversion, ethylene dimerization technology can be used to produce additional butene. Thus, if desired, 100% propylene and 0% ethylene can be produced. Using reverse olefin conversion technology, propylene can be converted to ethylene and butene. Therefore, by integrating thermal cracking, residue hydrocracking, olefin conversion technology, and / or dimerization technology, 100% ethylene and 100% propylene can be produced from crude oil.

[0130] As described above, the embodiments described herein provide a flexible approach to processing whole crude oil and other hydrocarbon mixtures containing high-boiling-point coke precursors. Even under harsh conditions, the embodiments described herein can advantageously reduce coking and fouling during preheating, superheating, and cracking processes. The embodiments described herein can achieve desired yields while significantly reducing the capital and energy requirements associated with pre-fractionation and separation of fractions in multiple heaters.

[0131] According to the embodiments described herein, the suppression of coking and the integration of thermal cracking and hydrocracking throughout the cracking process offer significant advantages, including increased olefin yield, increased run-length (reduced downtime), and the ability to handle feedstocks containing heavy hydrocarbons. Furthermore, significant energy efficiency can be achieved compared to conventional processes that include distillation separation and separate cracking reactors.

[0132] Although this disclosure includes a limited number of embodiments, those skilled in the art who benefit from it will understand that other embodiments can be devised without departing from the scope of this disclosure. Therefore, the scope of the invention should be defined only by the appended claims.

Claims

1. A method for producing olefins and / or dienes, comprising: Partial vaporization of crude oil to form liquid and vapor fractions; The vapor fraction is superheated to form a superheated vapor fraction; The liquid fraction is hydrotreated to remove one or more of metals, sulfur, nitrogen, Conradson carbon residue (CCR), or asphaltenes to produce a hydrotreated liquid. The hydrogenated liquid is partially vaporized to form a second vapor fraction and a second liquid fraction; The second liquid fraction is partially vaporized to form a third vapor fraction and a third liquid fraction; The third liquid fraction is subjected to hydrocracking to convert hydrocarbon components with boiling points greater than 550°C into hydrocarbons with boiling points less than 550°C, and the hydrocracking effluent is recovered. The hydrocracking effluent is separated to recover light hydrocracking fractions and heavy hydrocracking fractions; The heavy hydrocracking fraction is hydrocracking to convert its hydrocarbon components into hydrocarbons in the naphtha range, and the second hydrocracking effluent is recovered. The second hydrocracking effluent is separated to recover a second light hydrocracking fraction and a second heavy hydrocracking fraction, the second light hydrocracking fraction containing hydrocarbons in the naphtha range; Partial vaporization of the second heavy hydrocracking fraction is used to recover the fourth vapor fraction and the fourth liquid fraction; The superheated vapor fraction (i), the third vapor fraction (ii), the second vapor fraction (iii), the fourth vapor fraction (iv), the second light hydrocracking fraction (v), and the fourth liquid fraction (vi) are thermally cracked to produce thermally cracked hydrocarbon effluents, each comprising a mixture of olefins and alkanes.

2. The method according to claim 1, wherein, The thermal cracking includes thermally cracking the superheated vapor fraction, the second vapor fraction, and the second light hydrocracking fraction together, and the method further includes mixing the superheated vapor fraction, the second vapor fraction, and the second light hydrocracking fraction.

3. The method according to claim 1, wherein, The thermal cracking includes thermally cracking the third vapor fraction and the fourth vapor fraction together, and the method further includes mixing the third vapor fraction and the fourth vapor fraction.

4. The method according to claim 1, wherein, The hydrogenation process also includes hydrogenating the light hydrocracking fraction.

5. The method of claim 1, further comprising separating the thermally cracked hydrocarbon effluent to recover one or more olefin fractions and fractions with boiling points above 370°C.

6. The method according to claim 5, wherein, The hydrocracking of the third liquid fraction and / or the hydrocracking of the heavy hydrocracking fraction further includes the hydrocracking of the fraction with a boiling point above 370°C.

7. A method for producing olefins and / or dienes, comprising: Partial vaporization of crude oil to form liquid and vapor fractions; The vapor fraction is superheated to form a superheated vapor fraction; The liquid fraction is hydrotreated to remove one or more of metals, sulfur, nitrogen, Conradson carbon residue (CCR), or asphaltenes to produce a hydrotreated liquid. The hydrogenated liquid is partially vaporized to form a second vapor fraction and a second liquid fraction; The second liquid fraction is partially vaporized to form a third vapor fraction and a third liquid fraction; The third liquid fraction is subjected to hydrocracking to convert hydrocarbon components with boiling points greater than 550°C into hydrocarbons with boiling points less than 550°C, and the hydrocracking effluent is recovered. The hydrocracking effluent is separated to recover light hydrocracking fractions and heavy hydrocracking fractions; The heavy hydrocracking fraction is hydrocracking to convert its hydrocarbon components into hydrocarbons in the naphtha range, and the second hydrocracking effluent is recovered. The second hydrocracking effluent is separated to recover a second light hydrocracking fraction and a second heavy hydrocracking fraction, the second light hydrocracking fraction containing hydrocarbons in the naphtha range; The superheated vapor fraction (i), the third vapor fraction (ii), the second vapor fraction (iii), the second heavy hydrocracking fraction (iv), and the second light hydrocracking fraction (v) are thermally cracked to produce thermally cracked hydrocarbon effluents, each comprising a mixture of olefins and alkanes.

8. The method according to claim 7, wherein, The thermal cracking includes thermally cracking the superheated vapor fraction, the second vapor fraction, and the second light hydrocracking fraction together, and the method further includes mixing the superheated vapor fraction, the second vapor fraction, and the second light hydrocracking fraction.

9. The method according to claim 7, wherein, The thermal cracking includes thermally cracking the third vapor fraction and the fourth vapor fraction together, and the method further includes mixing the third vapor fraction and the fourth vapor fraction.

10. The method according to claim 7, wherein, The hydrogenation process also includes hydrogenating the light hydrocracking fraction.

11. The method of claim 7, further comprising separating the thermally cracked hydrocarbon effluent to recover one or more olefin fractions and fractions with boiling points above 370°C.

12. The method according to claim 11, wherein, The hydrocracking of the third liquid fraction and / or the hydrocracking of the heavy hydrocracking fraction further includes the hydrocracking of the fraction with a boiling point above 370°C.

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