ELECTRICAL CRACKING HEATER FOR HEAVY FEEDS TO PRODUCE OLEFINS

BACKGROUND

[0001]Pyrolysis or integrated pyrolysis and hydrocracking of hydrocarbon mixtures, such as whole crudes or other hydrocarbon mixtures, to produce olefins and other chemicals is a heat intensive process. Presently, plants primarily use fuel fired heaters that lead to emissions associated with firing of a hydrocarbon containing fuel. In this process, ethane and other hydrocarbons may be cracked to produce ethylene. Though ethane produces significant amount of hydrogen, after meeting the requirements for hydrogenation of acetylene (to produce additional ethylene) and hydrogenation of methylacetylene and propadiene (MAPD), excess hydrogen is often not sufficient to satisfy the heat requirement in a conventional cracking heater. This results in additional methane or other hydrocarbon needing to be added to the fuel gas mix. Any additional hydrocarbon that is burned produces CO2 and hence contributes to CO2 emissions.

[0002]To reduce the CO2 emissions from the heaters, various methods have been proposed to utilize electric cracking heaters to replace some or all of the energy supplied by burning hydrocarbon containing fuel. Unfortunately, such systems contain inefficiencies associated with the manners in which they minimize the radiant duty of the electric cracking heater and configure the system to account for fouling and other issues associated with hydrocarbon processing.

[0003]Referring now to FIG. 1, a process diagram of a prior art (WO 2023/274970 A1) process for cracking hydrocarbon feed streams is illustrated. FIG. 1 is similar to FIG. 1 of WO 2023/274970 A1. As described in WO 2023/274970 A1, the system 10 is configured to receive a hydrocarbon feed stream 12, pre-heat the hydrocarbon feed stream 12 via a pre-heating assembly 14, at least substantially vaporize hydrocarbons in the hydrocarbon feed stream 12 via a vaporizer assembly 16, separate heavy components 18 and/or liquid from the hydrocarbon feed stream 12, and supply the substantially vaporized hydrocarbons to a cracking furnace 20 for cracking. Following cracking in the cracking furnace 20, the cracked hydrocarbons 22 may be supplied to a distillation section 24 for at least partially separating the cracked hydrocarbons 22 into products 26, which may include desired intermediate or final product and heavy products 28, which may include heavy fractions, such as wash oil or quench oil. As shown in FIG. 1, in some embodiments of the vapor-liquid separator 48, the shell 50 may include a vapor and liquid outlet (e.g., in an upper portion of the shell 50) through which the hydrocarbon vapor and liquid 64 may flow to a vapor and liquid line 66. The vapor and liquid line 66 may provide flow communication with a vapor and liquid heater 68 configured to substantially complete vaporization of the hydrocarbon feed stream 12 and dilution steam, and/or to heat the hydrocarbon feed stream 12 and dilution steam to an inlet temperature desired for being supplied to the cracking furnace 20. In some embodiments, the vapor and liquid heater 68 may include an electrically-powered heater, a combination of an electrically-powered heater and a steam heater, and/or an electrically-powered heater and a heat transfer fluid positioned and configured to heat the hydrocarbon vapor and liquid 64, for example, as explained herein. In some embodiments, the vapor and liquid heater 68 may be an electrically-powered heater, which may be configured to use a hot oil system and exchange heat with the hydrocarbon vapor and liquid 64. The use of this additional electrically-powered heater 64 requires increased energy consumption and the potential for fouling that should be avoided.

SUMMARY

[0004]This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0005]In one aspect, embodiments disclosed herein relate to a system for converting a hydrocarbon mixture to produce olefins including a first preheater configured for preheating a hydrocarbon feed and producing a hydrocarbon stream. The system includes one or more separation systems to receive a preheated hydrocarbon stream and produce a vaporized hydrocarbon stream and a liquid hydrocarbon stream. A secondary transferline exchanger transfers heat to the vaporized hydrocarbon stream from a cooled hydrocarbon product stream to produce a heated vaporized hydrocarbon stream and a hydrocarbon product stream. A thermal cracking heater is configured for cracking the vaporized hydrocarbon stream and producing a cracked hydrocarbon product stream. A primary transferline exchanger receives the cracked hydrocarbon product stream to quench the cracked hydrocarbon product stream and recover the cooled hydrocarbon product stream. A flow line is configured for transferring the cooled hydrocarbon product stream to the secondary transferline exchanger to produce a hydrocarbon product stream.

[0006]In another aspect, embodiments disclosed herein relate to a process for converting a hydrocarbon mixture to produce olefins including preheating a hydrocarbon feed in a first preheated to produce a preheated hydrocarbon stream. The preheated hydrocarbon stream is separated in one or more separation systems, producing a vaporized hydrocarbon stream and a liquid hydrocarbon stream. The vaporized hydrocarbon stream is heated in a secondary transferline exchanger, producing a heated hydrocarbon stream. The liquid hydrocarbon stream is heated using a third preheater to produce a second heated hydrocarbon stream. The heated hydrocarbon stream and the second heated hydrocarbon stream are cracked using a thermal cracking heater to produce a cracked hydrocarbon product stream. The cracked hydrocarbon product stream is fed to a primary transferline exchanger for quenching the cracked hydrocarbon product stream and recovering a cooled hydrocarbon product stream. The cooled hydrocarbon product stream is fed to a secondary transferline exchanger to produce a hydrocarbon product stream.

[0007]In another aspect, embodiments disclosed herein relate to a method for flexibly converting hydrocarbon feeds to produce olefins including a first and a second time period. In the first time period, a first hydrocarbon feed is preheated in a first preheater to produce a preheated hydrocarbon stream. The preheated hydrocarbon stream is separated in one or more separation systems to produce a vaporized hydrocarbon stream and a liquid hydrocarbon stream containing the heavy hydrocarbons. The vaporized hydrocarbon stream is heated using a secondary transferline exchanger and a cooled hydrocarbon product stream to produce a heated vaporized hydrocarbon stream and a hydrocarbon product stream. The liquid hydrocarbon stream is heated in a third preheated to produce a second heated hydrocarbon stream. The heated vaporized hydrocarbon stream and the second heated hydrocarbon stream are cracked using a thermal cracking heater to produce a cracked hydrocarbon product stream. The cracked hydrocarbon product is fed to a primary transferline exchanger for quenching the cracked hydrocarbon product stream and recovering a cooled hydrocarbon product stream. The cooled hydrocarbon product stream is fed to a secondary transferline exchanger to recover the hydrocarbon product stream. During the second time period, a second hydrocarbon feed is preheated in a first preheater, producing a vaporized hydrocarbon stream. The separation system is bypassed and the vaporized hydrocarbon stream is heated using a cooled hydrocarbon product stream in the secondary transferline exchanger to produce a heated vaporized hydrocarbon stream and a hydrocarbon product stream. The heated vaporized hydrocarbon stream is cracked using the thermal cracking heater to produce a cracked hydrocarbon product stream. The cracked hydrocarbon product stream is fed to the primary transferline exchanger for quenching the cracked hydrocarbon product stream, recovering a cooled hydrocarbon product stream. The cooled hydrocarbon product stream is fed to the secondary transferline exchanger, recovering the hydrocarbon product stream.

[0008]Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

[0009]FIG. 1 is a process diagram from a prior art system for cracking hydrocarbon feed streams.

[0010]FIG. 2 is a process diagram in accordance with one or more embodiments.

[0011]FIG. 3 is a process diagram depicting a flash drum bypass in accordance with one or more embodiments.

[0012]FIG. 4 is a process diagram using a Heavy Oil Processing Scheme separator system in accordance with one or more embodiments.

[0013]FIG. 5 is a process diagram of a Heavy Oil Processing Scheme separator system in accordance with one or more embodiments.

[0014]FIG. 6 is a process diagram depicting an additional preheated dilution steam stream bypass line in accordance with one or more embodiments.

[0015]FIG. 7 is a graph of the molar mass of paraffins against atmospheric equivalent boiling point in accordance with one or more embodiments.

DETAILED DESCRIPTION

[0016]In one aspect, embodiments disclosed herein relate to a system for converting a hydrocarbon mixture to produce olefins. In another aspect, embodiments disclosed herein relate to a process for converting a hydrocarbon mixture to produce olefins. In another aspect, embodiments disclosed herein relate to a method for flexibly converting hydrocarbon mixtures to produce olefins.

[0017]Embodiments herein relate to processes and systems that take crude oil and/or other hydrocarbon mixtures as a feedstock to produce petrochemicals, such as light olefins and diolefins (ethylene, propylene, butadiene, and/or butenes) and aromatics. More specifically, embodiments herein are directed toward methods and systems for making olefins and aromatics by thermal cracking of hydrocarbons.

[0018]Processes disclosed herein can be applied to feedstocks such as crude oils, condensates, condensate liquids and other hydrocarbon mixtures. Restated, embodiments herein may apply to various hydrocarbon mixtures having a boiling point range inclusive of two or more fractions that may be processed so as to improve overall heat efficiency of the cracking system. Embodiments herein may also process wide boiling feedstocks, inclusive of those having end points higher than 500° C.

[0019]Hydrocarbon mixtures useful as the hydrocarbon feed in embodiments disclosed herein may include various hydrocarbon mixtures having a boiling point range, where the end boiling point of the mixture may be greater than 450° C. or greater than 500° C., such as greater than 525° C., 550° C., or 575° C. The amount of high boiling hydrocarbons, such as hydrocarbons boiling over 550° C., may be as little as 0.1 wt %, 1 wt % or 2 wt %, but can be as high as 10 wt %, 25 wt %, 50 wt % or greater. Processes disclosed herein can be applied to crudes, condensates and hydrocarbons with a wide boiling curve and end points higher than 500° C. Such hydrocarbon mixtures may include whole crudes, virgin crudes, hydroprocessed crudes, gas oils, vacuum gas oils, heating oils, jet fuels, diesels, kerosenes, gasolines, synthetic naphthas, raffinate reformates, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gasolines, distillates, virgin naphthas, natural gas condensates, atmospheric pipestill bottoms, vacuum pipestill streams including bottoms, wide boiling range naphtha to gas oil condensates, heavy non-virgin hydrocarbon streams from refineries, vacuum gas oils, heavy gas oils, atmospheric residuum, hydrocracker wax, and Fischer-Tropsch wax, among others. In some embodiments, the hydrocarbon mixture may include hydrocarbons boiling from the naphtha range or lighter to the vacuum gas oil range or heavier. If desired, these feeds may be pre-processed to remove a portion of the sulfur, nitrogen, metals, and Conradson Carbon upstream of processes disclosed herein. Lighter hydrocarbon feeds, such as ethane, propane, butanes, etc., and mixtures of multiple of these various lighter hydrocarbons may also be used as feedstocks to cracking heaters herein.

[0020]The above feedstocks are processed in embodiments herein to initially preheat the hydrocarbons, and then in a radiant heater to further heat the hydrocarbons up to a thermal cracking temperature to crack the hydrocarbons to produce a cracked effluent containing olefins, such as ethylene and propylene, among other products. Following cracking, the cracked effluent from the heater is quenched in a transfer line exchanger, and the quenched effluent is then processed for additional heat recovery in a secondary transfer line exchanger, and thence to a fractionation zone for recovery of the various hydrocarbon products or product fractions resulting from the cracking reaction.

[0021]Various hydrocarbons in many of the above feedstocks may be considered foulant hydrocarbons due to their inclination to foul the heat exchangers and process units within the system. This typically correlates to heavy and/or asphaltenic hydrocarbons in the feed that do not vaporize readily.

[0022]Heating of heavy feeds such as described above in an exchanger, such as a transfer line exchanger or a secondary transfer line exchanger, will cause excessive fouling if care is not taken and will require frequent cleaning. With light feeds like naphtha, heating is generally not an issue; however, with feeds having a higher fouling tendency, such as in heavy feed cracking, it is typical of prior art systems that only dilution steam is superheated in secondary transfer line exchangers against cooling heater effluent. This limits the maximum achievable mixed feed cross over temperature for heavy feeds. The heat capacity of dilution steam is lower than the heat capacity of the heater effluent and hence even for reasonable duty transfer large exchangers are required.

[0023]Instead of heating dilution steam only, embodiments herein preheat heavier and wide boiling feedstocks to moderate temperatures and partially vaporize the feed by adding hot dilution steam, after which it is sent to a separation system where the resulting vapor and liquid are separated. As a result, all or essentially all of the dilution steam is in the vapor phase and a significant portion of the hydrocarbon feed is also in the recovered vapor phase. For example, for a gas oil, the initial fraction of hydrocarbon that vaporizes at lower temperature has a low coking tendency and behaves similar to naphtha, which can be superheated in secondary exchangers to high temperatures without risk of fouling. By adding hydrocarbon to the dilution steam prior to heating, rather than simply heating pure dilution steam, the heat capacity is increased, which in turn increases the amount of heat that can be recovered from the cracked effluent, and a more economical exchanger design is achieved. As part of the heavy feed is already superheated to high temperatures, mixing with a moderately heated remaining portion of the heavy feed achieves a high outlet temperature suitable for feed to a cracking heater. This temperature, in some embodiments, is comparable to that achieved in current fired heaters and hence the required radiant duty is also comparable, i.e., not too high. In some embodiments, this also eliminates the need for any additional (electrical) preheat of the hydrocarbon plus dilution steam mixture up to a desired crossover temperature, reducing energy consumption needs.

[0024]Systems and processes herein include a heating and separation system for separating the wide boiling hydrocarbon feedstock into a light fraction containing volatilized hydrocarbons and a heavy (liquid) fraction. The above-described hydrocarbon feed stream is preheated in a first preheater and combined with a dilution steam feed that is also preheated in a second preheater, forming a partially vaporized mixture of the preheated hydrocarbon stream and the preheated dilution steam stream. In some embodiments, the hydrocarbon feed stream and the dilution steam feed may be combined and preheated within the same preheater. The first preheater and the second preheater may be an electric heater in some embodiments; other types of heaters (steam, feed/effluent, etc.) may also be used. In some embodiments, the first preheater may be a single preheater. In other embodiments, the first preheater may include multiple preheaters. In some embodiments, the second preheater may be a single preheater. In other embodiments, the second preheater may include multiple preheaters. When there are multiple preheaters, the preheaters may be in series, in parallel, or a combination of both. The preheated steam and hydrocarbon may be mixed at a steam to oil ratio, for example, in a range from 0.1 to 2.0.

[0025]In some embodiments, the resulting steam plus hydrocarbon mixture is fed to a separation system. Following heating and admixture, separation of the hydrocarbon feedstock and steam mixture into the desired light and heavy fractions may be performed using one or more separators (strippers, flash drums, etc.). In some embodiments, separation of the mixed hydrocarbon plus steam feeds may be performed in an integrated separation device (ISD), such as disclosed in US20130197283. In the ISD, an initial separation of a low boiling fraction is performed in the ISD based on a combination of centrifugal and cyclonic effects to separate the desired vapor fraction from liquid. In other embodiments, separation of the petroleum feeds may be performed in a Heavy Oil Processing Scheme (HOPS unit), such as described in U.S. Pat. No. 10,793,793, for example. In the HOPS unit, the hydrocarbon feedstock is preheated, mixed with dilution steam, and separated to recover a light fraction, vapor mixed with dilution steam, and a heavy fraction, a liquid stream comprising compounds that cannot be easily vaporized. An ISD or HOPS may be used, for example, to limit or eliminate carry over of liquid droplets that may contain heavier hydrocarbons that may have a tendency to foul heat exchangers and radiant coils.

[0026]Depending upon the aromaticity, sweetness, or fouling tendency of middle and higher boiling components in the hydrocarbon feedstock, the end boiling point of the light fraction may range up to about 460° C., but the end boiling point may be lower for feeds with higher fouling tendencies. In system configurations using a flash drum as the separation system, for example, the flash drum separates the partially vaporized mixture of the preheated hydrocarbon stream and the preheated dilution steam stream into a vapor stream and a liquid stream. The vapor hydrocarbon stream contains steam and hydrocarbons with a low coking tendency and lower boiling points, generally below 450° C. The liquid stream contains hydrocarbons with higher boiling points that do not readily vaporize. The resulting vaporized hydrocarbon plus steam stream has an increased heat capacity relative to pure steam as it flows to the secondary transfer line exchanger. This enables more of the available heat from the cracked effluent to be recovered in the secondary transfer line exchanger to enable a higher temperature for the hydrocarbon plus dilution steam fed to the heater. It may also allow for a more economical, typically smaller, secondary transfer line exchanger design for a given crossover temperature. The vaporized hydrocarbon stream is heated in the secondary transfer line exchanger, producing a heated vaporized hydrocarbon stream. Additionally, coking can cause fouling within heat exchangers and can thus require frequent cleanings. By ensuring the feed to the secondary transfer line exchanger has a low coking tendency following the operation of the flash drum, the secondary transfer line exchanger maintains a high efficiency and requires less maintenance.

[0027]The liquid hydrocarbon stream exiting the flash drum is heated through a third preheater, producing a second heated hydrocarbon stream. The third preheater is a steam heater, using super high pressure steam (SHP steam) to heat the high boiling point liquid hydrocarbon stream. The heated hydrocarbon stream and the second heated hydrocarbon stream combine and are fed to the thermal cracking heater.

[0028]The thermal cracking heater contains a radiant zone. In some embodiments, the thermal cracking heater is an electric heater. In other embodiments, the thermal cracking heater is a fuel-fired heater. In other embodiments, the thermal cracking heater may be a hybrid heater consisting of both an electrical portion and a fuel-fired portion. When using an electric or hybrid heater, radiant duty is particularly important and should be reduced when it is feasible to do so. Effectively heating the feed to the thermal cracking heater using the secondary transfer line exchanger and the third preheater results in a lower radiant duty.

[0029]The thermal cracking reaction proceeds via a free radical mechanism. Hence, high ethylene yield can be achieved when hydrocarbons are cracked at high temperatures. Lighter feeds, like butanes and pentanes, require a high reactor temperature to obtain high olefin yields. Heavy feeds, like gas oil and vacuum gas oil (VGO), require lower temperatures. Crude contains a distribution of compounds from butanes to VGO and residue (material having a normal boiling point over 520° C., for example), and thus co-cracking (in the same coil) of the light and heavy portions of the feed, once recombined, may result in a variety of cracked hydrocarbon products.

[0030]The thermal cracking heater produces a cracked hydrocarbon product stream containing olefins. Following cracking in the radiant coils, a primary transfer line exchanger (PTLE) may be used for quenching the cracked hydrocarbon product stream in order to cool the products very quickly, stopping the cracking reaction and producing a cooled hydrocarbon product stream. One or more radiant coils may be combined and connected to the primary transfer line exchanger. The primary transfer line exchanger may be a double pipe or shell and tube exchanger(s). The cracked hydrocarbon product stream will enter one side of the primary transfer line exchanger. On the other side, the primary transfer line exchanger will generate high pressure steam. Since generating steam has a very high heat transfer coefficient, the mixture may be quenched quickly in a short distance in the primary transfer line exchanger.

[0031]The cooled hydrocarbon product stream may then be fed to the secondary transfer line exchanger (STLE), as previously discussed. The cooled hydrocarbon product stream contains heat that is transferred to the vaporized hydrocarbon stream passing through the secondary transfer line exchanger, producing a hydrocarbon product stream that is further cooled and providing the heat to the vaporized hydrocarbon stream before it enters the thermal cracking heater.

[0032]In some embodiments, the hydrocarbon feed may contain only lighter, easily cracked hydrocarbons with a low fouling tendency. In this case, it may be advantageous to bypass the separation system (flash drum, ISD, HOPS, etc.) altogether, as the light hydrocarbon feed more readily vaporizes, has a lower coking tendency, and has a higher heat capacity than steam alone, making the separation system unnecessary. When bypassing the separation system, the mixture of the preheated hydrocarbon stream and the preheated dilution steam stream flow directly to the secondary transfer line exchanger. The secondary transfer line exchanger heats the mixture of the preheated hydrocarbon stream and the preheated dilution steam stream, producing a heated vaporized hydrocarbon stream, which continues to flow to the thermal cracking heater to process the stream identically to the previously described embodiment. Embodiments herein, as will be described further, may thus include bypasses and valving so as to flexibly process various feeds according to their fouling tendencies while maintaining high operability and heat efficiency of the overall system.

[0033]The steam flow rate and temperature of the steam mixed with the heated hydrocarbon feedstock may be used to influence the cut point of the hydrocarbons vaporized and recovered during the initial separations. Lower cut points may require a lower temperature steam or a lesser steam to oil ratio. Higher cut points may require a higher temperature steam or a higher steam to oil ratio. Regardless of the cut point, however, it may be desirable to have a particular steam to oil ratio for the hydrocarbon-steam stream that is used to recover heat in the secondary transfer line exchanger, or for the final mixed hydrocarbon-steam stream that is fed to the radiant coil. In some embodiments, the preheated dilution steam stream may flow partially to the preheated hydrocarbon stream and partially, through a bypass line, to the vaporized hydrocarbon stream exiting the separation system. The duty of the first preheater and second preheater may be varied to control the temperature of the preheated hydrocarbon stream and the preheated dilution steam stream, respectively. A steam bypass ratio represents the amount of the preheated dilution steam stream that flows through the bypass line to the vaporized hydrocarbon stream exiting the flash drum relative to the amount of the preheated dilution stream that mixes with the preheated hydrocarbon stream. Adjusting the steam bypass ratio will allow for control of the temperature (cut point) and flow rate of the vaporized hydrocarbon stream to the secondary transfer line exchanger. This will further impact the ratio of vaporized hydrocarbons to liquid hydrocarbons in the system.

[0034]FIG. 2 illustrates an embodiment of a system 200 for cracking various hydrocarbon mixtures, including wide boiling hydrocarbon mixtures containing hydrocarbons having a high tendency for fouling heat exchangers, such as secondary transfer line exchangers. The hydrocarbon feed 201 flows to the first preheater 203, producing a preheated hydrocarbon stream 206. A dilution steam stream 209 flows to a second preheater 212, producing a preheated dilution steam stream 215. The preheated hydrocarbon stream 206 and the preheated dilution steam stream 215 combine and are fed to separation system 227, which may be a flash drum, HOPS, ISD, etc., as described above. The separation system 227 produces a vaporized hydrocarbon stream 230 and a liquid hydrocarbon stream 218. The vaporized hydrocarbon stream 230 also contains steam. The liquid hydrocarbon stream 218 is fed to a third preheater 221, producing a second heated hydrocarbon stream 224. The vaporized hydrocarbon stream 230 is fed to the secondary transfer line exchanger 233, producing a heated vaporized hydrocarbon stream 239 and a hydrocarbon product stream 236. The heated vaporized hydrocarbon stream 239 combines with the second heated hydrocarbon stream 224, to form a mixture 242 that is fed to the thermal cracking heater 245. The thermal cracking heater produces a cracked hydrocarbon product stream 248 that is fed to the primary transfer line exchanger 251. The primary transfer line exchanger 251 quenches the cracked hydrocarbon product stream 248 and produces a cooled hydrocarbon product stream 253. The cooled hydrocarbon product stream 253 is further cooled in the secondary transfer line exchanger 233, producing the hydrocarbon product stream 236.

[0035]In FIGS. 2-4, each of the preheaters may use heat from a super high pressure steam stream. The super high pressure steam stream may have a pressure in a range of 1600 to 2000 psi. In one or more embodiments, the pressure of the super high pressure steam stream may be 1800 psi. Where such high pressure steam is limited in supply, electrical preheaters may also be used to achieve the desired temperatures.

[0036]FIG. 3 illustrates an embodiment of the system 300, which is similar to the embodiment of FIG. 2, but includes a bypass in accordance with one or more embodiments to provide additional feed and processing flexibility. The hydrocarbon feed 301 flows to the first preheater 303, producing a preheated hydrocarbon stream 306. A dilution steam stream 309 flows to a second preheater 312, producing a preheated dilution steam stream 315. The preheated hydrocarbon stream 306 and the preheated dilution steam stream 315 form a mixture. When the system 300 processes wide boiling hydrocarbon mixtures containing fouling hydrocarbons, the system may be operated as described with respect to FIG. 2. When the bypass is in use, such as when hydrocarbon feed 301 is an easily vaporizable hydrocarbon containing little or no fouling type hydrocarbons, the valve 310 in the flow line to the separation system 327 is closed and the valve 308 in the flow line 307 is opened. The mixture of the preheated hydrocarbon stream 306 and the preheated dilution steam stream 315 is fed to the line typically carrying the vaporized hydrocarbon stream 330 directly into the secondary transfer line exchanger 333, producing a heated vaporized hydrocarbon stream 339. The heated vaporized hydrocarbon stream 339 flows to the thermal cracking heater 345. The thermal cracking heater produces a cracked hydrocarbon product stream 348 that is fed to the primary transfer line exchanger 351. The primary transfer line exchanger 351 quenches the cracked hydrocarbon product stream 348 and produces a cooled hydrocarbon product stream 353. The cooled hydrocarbon product stream 353 is further cooled in the secondary transfer line exchanger 333, producing a hydrocarbon product stream 336.

[0037]FIG. 4 illustrates an embodiment of the system 400 using a Heavy Oil Processing Scheme separator system (HOPS separator system) in accordance with one or more embodiments. The hydrocarbon feed 401 flows to the first preheater 403, producing a preheated hydrocarbon stream 406. A dilution steam stream 409 flows to a second preheater 412, producing a preheated dilution steam stream 415. The preheated hydrocarbon stream 406 and the preheated dilution steam stream 415 are mixed and fed to the HOPS separator system 427. The HOPS separator system produces a vaporized hydrocarbon stream 430 and a liquid hydrocarbon stream 418. The vaporized hydrocarbon stream 430 also contains steam. The liquid hydrocarbon stream 418 is fed to a third preheater 421, producing a second heated hydrocarbon stream 424. The vaporized hydrocarbon stream 430 is fed to the secondary transfer line exchanger 433, producing a heated vaporized hydrocarbon stream 439. The heated vaporized hydrocarbon stream 439 combines with the second heated hydrocarbon stream 424, to form a mixture 442 that is fed to the thermal cracking heater 445. The thermal cracking heater 445 produces a cracked hydrocarbon product stream 448 that is fed to the primary transfer line exchanger 451. The primary transfer line exchanger 451 quenches the cracked hydrocarbon product stream 448 and produces a cooled hydrocarbon product stream 453. The cooled hydrocarbon product stream 453 is further cooled in the secondary transfer line exchanger 433, producing a hydrocarbon product stream 436.

[0038]A simple sketch of a HOPS separator system 550 is shown in FIG. 5. Various modifications of this scheme are possible. In the HOPS separator system, preheated dilution steam 552 is added to preheated hydrocarbon stream 554, and a separation zone 556 including 2 to 10 theoretical stages are used to separate the readily vaporizable hydrocarbons from the non-vaporizable hydrocarbons. By this process, carryover of fine droplets to the overhead fraction 560 is reduced, as high boiling carryover liquids in the vapor will cause coking. The heavy, non-vaporizable hydrocarbons are recovered in bottoms fraction 562, and the vaporized hydrocarbons and dilution steam are recovered in overhead product fraction 564. The HOPS separator system 550 may include some internal distributors with and/or without packing. When the HOPS separator system is used, vapor/liquid separation may be nearly ideal. The end point of the vapor is predictable, based on operating conditions, and any liquid carry over in the vapor phase can be minimized. While this option is more expensive than a flash drum, the benefits of reduced coking sufficiently outweigh the added expense. The liquid hydrocarbons 562 in the bottoms fraction may be fed to an appropriate stage of the process for continued processing.

[0039]FIG. 6 illustrates an embodiment of the system 600 depicting an additional preheated dilution steam stream bypass line in accordance with one or more embodiments. The hydrocarbon feed 601 flows to the first preheater 603, producing a preheated hydrocarbon stream 606. A dilution steam stream 609 flows to a second preheater 612, producing a preheated dilution steam stream 615. The preheated hydrocarbon stream 606 and a portion of the preheated dilution steam stream 615 combine and are fed to the flash drum 627. The flash drum produces a vaporized hydrocarbon stream 630 and a liquid hydrocarbon stream 618. The vaporized hydrocarbon stream 630 also contains steam. A portion of the preheated dilution steam stream flows through a bypass line 617 when a valve 616 is opened to combine with and control the temperature of the vaporized hydrocarbon stream 630. The liquid hydrocarbon stream 618 is fed to a third preheater 621, producing a second heated hydrocarbon stream 624. The vaporized hydrocarbon stream 630 is fed to the secondary transfer line exchanger 633, producing a heated vaporized hydrocarbon stream 639. The heated vaporized hydrocarbon stream 639 combines with the second heated hydrocarbon stream 624, to form a mixture 642 that is fed to the thermal cracking heater 645. The thermal cracking heater 645 produces a cracked hydrocarbon product stream 648 that is fed to the primary transfer line exchanger 651. The primary transfer line exchanger 651 quenches the cracked hydrocarbon product stream 648 and produces a cooled hydrocarbon product stream 653. The cooled hydrocarbon product stream 653 is further cooled in the secondary transfer line exchanger 633, producing a hydrocarbon product stream 636.

[0040]While illustrated and described separately with respect to FIGS. 3 and 6, embodiments herein may include both a steam bypass line and a separation system bypass line. Thus, systems according to embodiments herein may provide full feed flexibility, providing for (steam plus hydrocarbon) bypass around the separation system when it is not needed, and for steam bypass when it is desired to control a cut point of a hydrocarbon feedstock that is being partially vaporized and separated. Such bypasses thus allow systems herein to change feedstocks, as may be desired on occasion due to supply availability, feedstock price fluctuations, product targets, and other factors. In some embodiments, the system may be configured to initially process the hydrocarbon feed through the preheaters and to the separation system in a first time period. In a second time period, the system may be configured to process the hydrocarbon feed through the preheaters before bypassing the separation system to heat the vaporized hydrocarbon stream in the secondary transfer line exchanger to produce a heated vaporized hydrocarbon stream. This configuration allows for flexibility between process flows based on system requirements, such as when a lighter hydrocarbon is fed to the system.

[0041]It is also noted that, while the steam bypass may not be required for full vaporization of a low fouling hydrocarbon feed, it may be desirable to limit the steam to oil ratio in the vapor stream fed to the secondary transfer line exchanger. However, that steam to oil ratio may be different than that required or desired in the cracking coil. In such embodiments, the bypassed steam may be combined with the vaporized hydrocarbon-steam stream downstream of the secondary transfer line exchanger and upstream of the cracking heater. It is further noted that steam may be fed to other various feed lines, such as combined with the liquid hydrocarbon upstream of the third preheater, or with the vaporized heavy hydrocarbons downstream of the third preheater. To minimize the electrical power loading in the radiant cell, an additional optional electrical heater of convective type outside the radiant cell be used for all the options.

Example

[0042]In some embodiments, the flash drum serves to vaporize hydrocarbons and combine with the dilution steam in order to increase the heat capacity of the fluid flowing through the secondary transfer line exchanger. Hydrocarbons with lower boiling points will vaporize in the flash drum more readily. FIG. 7 shows the molar mass of various hydrocarbon feeds against their atmospheric equivalent boiling point. As expected, naphtha, considered a “light feed,” has the lowest boiling point of those displayed on the graph. This graph illustrates that when heating a hydrocarbon feed, an initial lower boiling point paraffin will vaporize. As shown, middle distillates such as diesel will have a portion vaporize within the flash drum. The portion that vaporizes is rich in paraffins and has low potential to coke on the shell side of the secondary transfer line exchanger.

[0043]For further illustration, Table 1 below shows the properties of Gasoil.

[0044]In a conventional approach to hydrocracking, hydrocracked vacuum gasoil (HVGO) is preheated to moderate temperatures of 500-600° F. using steam and other heating medium. If heated to high temperatures in methods other than steam addition, the HVGO will coke and cause issues within the heat exchangers. Sources of high heated steam include the heater effluent from the primary transfer line exchanger and super high pressure superheated steam (SHP steam). Generally, plants produce SHP steam between 600-1800 psi that may be superheated to 850 to 1000° F. depending on turbine requirements. The following calculations assumed a pressure of 1800 psi and a temperature of 900° F. The single radiant coil will require a hydrocarbon flow rate of 11,000 lb/hr/coil-25,000 lb/hr/coil. The calculations used a hydrocarbon flow rate of 19,840 lb/hr/coil, a steam flow rate of 15,870 lb/hr/coil, and a steam to hydrocarbon ratio (S/O ratio) of 0.8 w/w. The dilution steam was fed at 383° F. The hydrocarbon feed was fed at 194° F. The heater effluent after the primary transfer line exchanger is 1100° F. In general, temperatures of the hydrocarbon product stream exiting the secondary transfer line exchanger are above 750° F. to prevent fouling that may be caused if more drastic, rapid cooling occurring. Alternatively, naphtha could be used in place of the HVGO feed, at temperatures as low as 660° F.

[0045]Case 3 is based on FIG. 2 according to embodiments herein. In these calculations, the dilution steam stream 209 is at 100 psi. The flow rate of the dilution steam is 9,920 lb/hr. The cooled hydrocarbon product stream 253 entering the secondary transfer line exchanger 233 is at a temperature of 1125° F. and cools to a temperature of 733° F. as it exits the secondary transfer line exchanger 233. The vaporized hydrocarbon stream 230 containing dilution steam enters the secondary transfer line exchanger 233 at 662° F. and flows out through a flow line containing the heated vaporized hydrocarbon stream 239 at 1069° F. For naphtha cracking, the secondary transfer line exchanger cools the cooled hydrocarbon product stream 253 to 733° F. to avoid condensation of heavy molecules.

[0046]In Table 2, Case 1 involves using a traditional process flow with cold dilution steam in the secondary transfer line exchanger. Though the hydrocarbon feed is fully vaporized, the radiant cell must supply additional duty to an electric heater or an additional electric preheater is needed, as the vaporized hydrocarbon and dilution steam mixed outlet temperature is 822° F. In Case 2, higher temperature dilution steam in a traditional process flow results in a low vaporized hydrocarbon and dilution steam mixed outlet temperature at 833° F. However, in Case 3, using the flash drum results in high heat recovery and improved vaporized hydrocarbon and dilution steam mixed outlet temperature at 932° F., significantly reducing the radiant duty. The data demonstrates that using the flash drum in the system maximizes the heat recovery from the secondary transfer line exchanger for heavy hydrocarbon feeds while simultaneously being equipped with processing lighter feeds, such as naphtha.

[0047]Embodiments of the present disclosure may provide at least one of the following advantages. Following the flash drum, the vaporized hydrocarbon stream flows to the secondary transfer line exchanger. The vaporized hydrocarbon stream has an increased heat capacity relative to pure steam. This improves the efficiency of the heat transfer in the secondary transfer line exchanger and allows for a more economical secondary transfer line exchanger design compared to technology using steam through the secondary transfer line exchanger. Optimizing the transfer line exchanger results in a lower radiant duty for the thermal cracking heater, which is particularly important when using an electric heater in this application. Without this, an additional heater would be required for further preheating of the streams. The flexibility of the system, including the flash drum bypass lines, allows the system to be suitable for light hydrocarbon feeds, such as naphtha, as well. Additionally, the flexibility of the system to use a HOPS separator system in place of the flash drum allows the system to be suitable for particularly heavy feeds.

[0048]Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.