Patent Application
20250066677
Embodiments of the present disclosure generally relate to thermal cracking of wide boiling hydrocarbon mixtures to produce olefins.
Generation of hydrocarbon fractions of various boiling point ranges for thermal cracking may be performed in a crude distillation column and a vacuum distillation tower. This type of operation may provide various fractions including naphtha range hydrocarbons and other atmospheric distillates such as kerosene, as well as various vacuum distillates, such as vacuum gas oil and others, as well as a vacuum residue fraction. Ethylene producers then use various fractions, such as the LPG, naphtha, atmospheric gas oil, and vacuum gas oil, as feeds to produce ethylene. However, this approach consumes energy as the crude and the desired fractions have to be heated by external sources, then cooled and transported to the cracking heaters, where the hydrocarbons are again heated by flue gas requiring separate combustion sources. With heating and cooling, overall heat utilization (efficiency) is reduced. The capital expenditures associated with such systems are also high and energy consumption is high.
Referring now to
The hydrocarbon feedstock, such as a whole crude or a hydrocarbon mixture including hydrocarbons boiling from naphtha range hydrocarbons to hydrocarbons having a normal boiling point temperature greater than 450° C., may be introduced to a heating coil 24, disposed in the convective section 2 of the pyrolysis heater 1. For example, hydrocarbons having a normal boiling temperature greater than 475° C., greater than 500° C., greater than 525° C., or greater than 550° C. may be introduced to heating coil 24. In the heating coil 24, the hydrocarbon feedstock may be partially vaporized, vaporizing the lighter components in the hydrocarbon feedstock, such as naphtha range hydrocarbons. The heated hydrocarbon feedstock 26 is then fed to a separator 27 for separation into a vapor fraction 28 and a liquid fraction 30.
Steam may be supplied to the process via flow line 32. Various portions of the process may use low temperature or saturated steam, while others may use high temperature superheated steam. Steam to be superheated may be fed via flow line 32 into heating coil 34, heated in the convection zone 2 of the pyrolysis heater 1, and recovered via flow line 36 as superheated steam.
A portion of the steam may be fed via flow line 40 and mixed with vapor fraction 28 to form a steam/hydrocarbon mixture in line 42. The steam/hydrocarbon mixture in stream 42 may then be fed to a heating coil 44. The resulting superheated mixture may then be fed via flow line 46 to a cracking coil 4 disposed in a radiant zone 3 of the pyrolysis heater 1. The cracked hydrocarbon product may then be recovered via flow line 12 for heat recovery, quenching, and product recovery.
The liquid fraction 30 may be mixed with steam 50 and fed to heating coil 52 disposed in the convective zone 2 of pyrolysis reactor 1. In heating coil 52, the liquid fraction may be partially vaporized, vaporizing the remaining lighter components in the hydrocarbon feedstock, such as mid to gas oil range hydrocarbons. The injection of steam into the liquid fraction 30 may help prevent formation of coke in heating coil 52. The heated liquid fraction 54 is then fed to a separator 56 for separation into a vapor fraction 58 and a liquid fraction 60.
A portion of the superheated steam may be fed via flow line 62 and mixed with vapor fraction 58 to form a steam/hydrocarbon mixture in line 64. The steam/hydrocarbon mixture in stream 64 may then be fed to a heating coil 66. The resulting superheated mixture may then be fed via flow line 68 to a cracking coil 4 disposed in a radiant zone 3 of the pyrolysis heater 1. The cracked hydrocarbon product may then be recovered via flow line 13 for heat recovery, quenching, and product recovery.
Superheated steam can be injected via flow lines 72, 74 directly into separators 27, 56, respectively. The injection of superheated steam into the separators may reduce the partial pressure and increase the amount of hydrocarbons in the vapor fractions 28, 58.
In addition to heating the hydrocarbon and steam streams, the convection zone 2 may be used to heat other process streams and steam streams, such as via coils 80, 82, 84. For example, coils 80, 82, 84 may be used to heat BFW (Boiler feed water) and preheating SHP (super high pressure) steam, among others.
The placement and number of coils 24, 52, 34, 44, 66, 80, 82, 84 can vary depending upon the design and the expected feedstocks available. In this manner, convection section may be designed to maximize energy recovery from the flue gas. In some embodiments, it may be desired to dispose superheating coil 44 at a higher flue gas temperature location than superheating coil 66. Cracking of the lighter hydrocarbons may be carried out at higher severity, and by locating the superheating coils appropriately, cracking conditions may be enhanced or tailored to the specific vapor cut.
As illustrated in
Liquid fraction 114 may be mixed with dilution steam 116, which may be a saturated dilution steam, fed to heating coil 117 and heated in the fired heater 100 to moderate temperatures. The heated liquid fraction 118 may then be mixed with superheated dilution steam 120 and the mixture fed to flash drum 122. Hydrocarbons boiling in the range from about 200° C. to about 350° C. are vaporized and recovered as a vapor fraction 124. The vapor fraction 124 may then be superheated and sent to a radiant section of a pyrolysis reactor (not shown).
The liquid fraction 126 recovered from flash drum 122 is again heated with saturated (or superheated) dilution steam 126, and passed through coils 128 and further superheated in the fired heater 100. Superheated dilution steam 130 may be added to the heated liquid/vapor stream 132 and fed to separator 134 for separation into a vapor fraction 136 and a liquid fraction 138. This separation will cut a 350° C. to 550° C. (VGO) portion, recovered as a vapor fraction 136, which may be superheated with additional dilution steam, if required, and sent to a radiant section of a pyrolysis reactor (not shown).
In one aspect, embodiments disclosed herein relate to a process for producing olefins from a crude oil. The process includes heating a high temperature stable heat transfer fluid in a convection section of a steam cracking furnace to generate a heated heat transfer fluid. The crude oil is heated via indirect heat exchange with the heated heat transfer fluid to form a heated crude oil, and the heated crude oil is desalted to form a desalted crude. The desalted crude is then heated to a first temperature via indirect heat exchange with the heated heat transfer fluid to form a pre-heated desalted crude, which is separated to recover a first hydrocarbon vapor fraction and a first hydrocarbon liquid fraction. The first hydrocarbon vapor fraction is superheated in a convective section of the same or a different steam cracking furnace to recover a first superheated vapor fraction, which is thermally cracked in a radiant section of the steam cracking furnace to recover a first cracked effluent comprising olefins.
In another aspect, embodiments disclosed herein relate to a process for producing olefins from a wide boiling hydrocarbon mixture. The process includes heating a high temperature stable heat transfer fluid in a convection section of a steam cracking furnace to generate a heated heat transfer fluid. The wide boiling hydrocarbon mixture is heated via indirect heat exchange with the heated heat transfer fluid to form a heated hydrocarbon mixture, which is separated to recover a first hydrocarbon vapor fraction and a first hydrocarbon liquid fraction. The first hydrocarbon vapor fraction is superheated in a convective section of the steam cracking furnace to recover a first superheated vapor fraction, which is then thermally cracked in a radiant section of the steam cracking furnace to recover a first cracked effluent comprising olefins. The first hydrocarbon liquid is heated via indirect heat exchange with the heated heat transfer fluid to form a heated first hydrocarbon liquid, which is separated to recover a second hydrocarbon vapor fraction and a second hydrocarbon liquid fraction. The second hydrocarbon vapor fraction is superheated in a convective section of the same or a different steam cracking furnace to recover a second superheated vapor fraction, which is thermally cracked to recover a second cracked effluent comprising olefins.
In another aspect, embodiments disclosed herein relate to a system for producing olefins from a crude oil. The system includes a steam cracking furnace including a radiant heating section and a convective heating section. One or more heating coils are disposed in the convective heating section for heating a high temperature stable heat transfer fluid to generate a heated heat transfer fluid. A first heat exchanger is provided for heating the crude oil via indirect heat exchange with the heated heat transfer fluid to form a heated crude oil, and a desalter is provided for desalting the crude oil to form a desalted crude. A second heat exchanger is provided for heating the desalted crude to a first temperature via indirect heat exchange with the heated heat transfer fluid to form a pre-heated desalted crude, and a first separator is provided for separating the preheated desalted crude to recover a first hydrocarbon vapor fraction and a first hydrocarbon liquid fraction. a heating coil is disposed in the convective section of the steam cracking furnace for superheating the first hydrocarbon vapor fraction to recover a first superheated vapor fraction, and a radiant heating coil is disposed in the radiant heating section of the steam cracking furnace for thermally cracking the first superheated vapor fraction to recover a first cracked effluent comprising olefins.
Other aspects and advantages will be apparent from the following description and the appended claims.
The systems as described in
Embodiments herein overcome one or more of these difficulties, and thus relate to improved systems and processes for separation and cracking of whole crudes and other wide boiling hydrocarbons. Embodiments as described hereinbelow include improvements in one or more of feed flexibility, operating window, heat efficiency, and overall operability. Embodiments herein may also provide for decreased fouling in heaters or heating coils.
Embodiments herein relate to processes and systems that take crude oil and/or other wide boiling 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.
Processes disclosed herein can be applied to feedstocks such as crude oils, condensates, condensate liquids and hydrocarbons. Restated, embodiments herein may apply to various hydrocarbon mixtures having a boiling point range inclusive of two or more fractions that may be preferentially cracked at different operating conditions. Embodiments herein may also process wide boiling feedstocks, inclusive of those having end points higher than 500° C.
Hydrocarbon feedstocks that may be processed according to embodiments herein include hydrocarbon mixtures such as 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, atmospheric distillates, vacuum 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 (natural gas or ethane) to the vacuum gas oil range or heavier.
One or more of the above hydrocarbon feedstocks may be fed to systems and processes herein to produce olefins and aromatics. As used herein, the term “petrochemicals” refers to hydrocarbons including light olefins and diolefins and C6-C8 aromatics. Petrochemicals thus refers to hydrocarbons including ethylene, propylene, butenes, butadienes, pentenes, pentadienes, as well as benzene, toluene, and xylenes. Referring to a subset of petrochemicals, the term “chemicals,” as used herein, refers to ethylene, propylene, butadiene, 1-butene, isobutylene, benzene, toluene, and para-xylenes.
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 fraction. If multiple fractions of particular cut points are desired, the resulting heavy (liquid) fraction may be further heated and separated to recover, for example, an intermediate boiling fraction and a residue fraction. Such sequential separations may be performed to generate two, three or more vaporized fractions, having a boiling range and cut point, and a residue fraction. Separation of various fractions, such as a low boiling fraction (a 160° C.− fraction, for example) and a high boiling fraction (a 160° C.+ fraction, for example), or such as a low, middle and high boiling fractions (a 160° C.− fraction, a 160-490° C. fraction, and a 490° C.+ fraction, for example) may enhance the capital efficiently and operating costs of the processes and systems disclosed herein. While referring to three cuts in many embodiments herein, it is recognized by the present inventors that condensates, typically having a small amount of high boiling components, and whole crudes, having a greater quantity of high boiling components, may be processed differently. Accordingly, one, two, three or more individual cuts can be performed for the wide boiling range petroleum feeds, and each cut can be processed separately at optimum conditions.
Heating and separating of the hydrocarbon feedstock mixtures in embodiments herein is performed external to a fired heater, using a high temperature stable heat transfer fluid. The heat transfer fluid is heated within one or more heating coils of a fired, electric, or hybrid electric/fired cracking furnace, and then the heated heat transfer fluid is transported and used to heat the hydrocarbon feedstock for the desired separations. High temperature stable heat transfer fluids, as used herein, refer to molten salts, heat transfer oils, and other similar heat transfer fluids that may be heated to relatively high temperatures, such as up to 400° C., 425° C., 450° C., 500° C., or higher, with minimal degradation. Some high temperature stable heat transfer fluids are available under various trade names, such as DYNALENE, DURATHERM, MULTITHERM, SYLTHERM, or THERMINOL, for example.
Systems such as described in relation to
Following heating with the heated heat transfer fluid, separation of the whole crude or other wide boiling hydrocarbon feedstock 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 petroleum 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.
In some embodiments, systems and processes herein may be used for producing olefins or olefins and aromatics from a crude oil. “Crude oil” as used in the following discussion and the claims, is inclusive of natural gas condensates and condensate liquids produced from a hydrocarbon-bearing reservoir. Such feedstocks may undergo various upstream processing, such as proximate a well, to meet transport regulations or pipeline requirements for transportation to a chemical plant, petrochemical plant, or refinery. Various contaminants that are produced along with the hydrocarbons from the reservoir or that are introduced in such upstream processing are removed during the desalting process. Embodiments herein that are used for converting a crude oil to petrochemicals or olefins may thus include a step of desalting the crude oil.
Numerous desalting processes are known in the art and vary in the separation mechanisms used for contacting the hydrocarbon with water and the desired phase separations. For example, some desalting processes include two-phase separations (water/brine and oil) while others three (water/brine, oil, and vapor). Some systems use gravity settling of water droplets from the oil, others facilitate settling via electrostatics or use of liquid-liquid settling plates or other internals. Regardless of the desalting system used, the crude oil is typically heated, such as to a temperature between 100° C. to 150° C. (varies depending upon system used, with some desalters operating at higher temperatures). to perform the desired separations. For embodiments where desalting is required, embodiments herein may provide heat requirements for the desalting process using the heated heat transfer fluid. Embodiments herein using the heated heat transfer fluid to heat the crude oil for desalting have been found to reduce process-side pressure drops and to be more economically favorable for preheating the crude oil to meet desalter requirements, similarly avoiding the back and forth of the hydrocarbon feedstock to and from the heater as noted above in relation to hydrocarbon feedstock separations.
Following separations, the hydrocarbon vapor stream, or the multiple hydrocarbon vapor streams, are superheated in a convection section of the steam cracking furnace, and then fed to a radiant coil in a radiant section of the steam cracking furnace, rapidly heating the hydrocarbon feed up to cracking temperatures, producing a cracked hydrocarbon effluent. The one or more steam cracker effluents are then quenched and separated. For example, the effluents may be collectively or individually quenched to halt the cracking reaction, quickly bringing the temperature of the effluent(s) to below steam cracking temperatures. Quench may be performed in transfer line exchangers, using direct or indirect quench against various hydrocarbon or steam streams present in the process, and other heat exchange to reduce a temperature of the steam cracker effluent(s) to desired separation feed temperatures. Following quenching and heat recovery, the thermally cracked effluent(s) may be fractionated in a fractionation zone to recover one or more hydrocarbon fractions.
As a more specific description of some embodiments herein for processing crude oils and other wide boiling hydrocarbon mixtures, the above-described feeds may be fed to a desalter, producing a desalted feedstock. The desalted feed is then heated, using a heat exchange system providing indirect heat exchange with a high temperature stable heat exchange fluid that is heated in a convection coil located in the convection section of a thermal cracking furnace. In some embodiments the desalted feed is split into multiple streams and fed to two or more heaters or convection coils to increase a temperature of the desalted feed. For example, the desalted feed may be heated to a temperature in a range from about 135° C. to about 210° C., such as 150° C.° to 180° C.
Following desalting and heating, the heated feedstock is then fed to a separation system for separating a light paraffinic fraction or cut, recovered as a vapor from the separation system, from the heavier hydrocarbons in the desalted feed, recovered as a liquid from the separation system. The separation system may include, for example, an integrated separation device (ISD) or a HOPS, as noted earlier. In some embodiments, the separation system is a simple flash drum, recovering the hydrocarbons volatilized in the heat exchanger. Due to the fouling tendency of heavier hydrocarbons, the ISD or HOPS are preferred over simple flash drums or stripers so as to limit entrainment of liquid droplets that may contain the heavier hydrocarbons. The light paraffinic cut recovered as a vapor from the separation system may have an end boiling point, for example, in a range from 135° C. to 225° C., such as from about 160° C. to about 180° C.
The light paraffinic cut may then be further heated and superheated using one or more heat exchangers. The heaters used for superheating the light paraffinic fraction may be located external to the cracking furnace, within the convection zone of the cracking furnace, or both. In some embodiments, the external heaters used may be electric heaters, or may use steam or other heat transfer fluids to increase the temperature of the light paraffinic cut.
The light paraffinic cut is then fed to a radiant coil of the cracking furnace to rapidly increase the temperature of the hydrocarbons therein to a cracking temperature, such as greater than 700° C. up to about 1100° C., thereby thermally cracking the hydrocarbons to produce lighter hydrocarbons, such as ethylene, propylene, and butenes, among others.
The effluent(s) from the radiant coils are then fed to a transfer line exchanger to rapidly quench the cracked effluent to a temperature below cracking temperature. Additional heat may then be recovered from the cracked effluent and the cooled effluent is fed to a fractionation zone to separate the cracked effluent into various hydrocarbon fractions. Separation systems associated with a thermal cracking system may vary, and may be used to separate the cracked effluent into broad cuts, such as a hydrogen fraction, a C1, C2-, C3- or C4-cut, a naphtha range cut, a diesel or jet fuel range cut, a gas oil range cut, and a pyrolysis oil (heavy/bottoms) fraction. Some separation systems used in embodiments of fractionation zones herein may include demethanizers, deethanizers, depropanizers, as well as separators to recover the various olefins, such as a deethylenizer to separate ethylene from ethane, a depropylenizer to separate propane from propylene, as well as debutanizers, deisobutylenizers, or other various separators and distillation columns or extractive distillation columns that are known in the art for recovering specific hydrocarbons or hydrocarbon cuts from a mixture of hydrocarbons.
Depending upon the aromaticity, sweetness, or fouling tendency of middle boiling components in the crude or condensate liquid feedstock, the end boiling point of the light fraction may range up to about 350° C. In some embodiments a first separator, such as an ISD or a HOPS, may be used to recover a light boiling fraction, such as having an end boiling point in a range from 160° C. to 180° C., as described above, and following heating of the remaining heavier hydrocarbons, a second separator, such as an ISD or a HOPS, may be used to recover an intermediate boiling range hydrocarbon cut, such as having an initial boiling point in a range from 160° C. to 180° C. and an end boiling point in a range from 280° C. to 350° C. The intermediate cut may be superheated and fed to a radiant coil to produce chemicals, such as ethylene and propylene, among others, and the cracked intermediate cut effluent may be quenched in a common or separate transfer line exchanger, fed to heat recovery, and thence to the fractionation zone for recovery of the various hydrocarbon fractions along with the other cracked effluents.
Light fractions processed, such as a 180° C.− cut, are generally suitable for direct feed for cracking, and do not require further processing. Depending upon the aromaticity, sweetness, or fouling tendency of middle and higher boiling components in the hydrocarbon feedstock, it may be desirable to further treat (hydrotreat, hydrodesulfurize, hydrodemetalize, hydroprocess, etc.) the one or more middle boiling cuts and/or the one or more heavier cuts so as to improve the crackability of the hydrocarbons in the respective cuts. The further treating and integration of such treating systems to provide “crackable” hydrocarbon feeds to the cracking furnace used may depend upon the feedstock(s) being processed and are not described here in greater detail. Examples of such systems are described, for example, in U.S. Pat. No. 10,793,793, adding hydrocracking of a residue fraction which may be used to provide additional naphtha range hydrocarbons to a cracking furnace, as well as more intricate systems such as described in U.S. Pat. Nos. 11,390,817, 11,365,361, 11,180,706, and 11,084,993, among others, each of which may benefit from the high temperature stable heat transfer heating as described herein.
Cracking furnaces of some embodiments herein include a convective heating section that includes heating coils used for heating the high temperature stable heat transfer fluid, generating steam, superheating steam, and superheating hydrocarbon feeds immediately prior to cracking. In such embodiments, all heating of hydrocarbon feedstocks for desalting and separations into the desired vapor cuts or fractions is performed external to the cracking furnace using the thus heated high temperature stable heat transfer fluid. The heating of the heat transfer fluid within the convection zone of the cracking furnace, and pumping of the hot heat transfer fluid to perform the heating of the hydrocarbons proximate an associated separator, thus provides flexibility in heater operations, disassociating the heating requirements from the various hydrocarbon feedstocks and cuts that may processed.
The high temperature stable heat transfer fluid, as described above, may be used in multiple heaters. For example, the heat transfer fluid may be provided to a hydrocarbon pre-heater upstream of a desalter, a heater for heating the desalted feed upstream of a first separator used to recover volatilized hydrocarbons for cracking, a heater for heating the liquid from the first separator used to recover additional volatilized hydrocarbons for cracking, etc. One or multiple heaters may be used in series or in parallel to provide the required heating of the hydrocarbon using the heat transfer fluid.
The heaters used to transfer heat between the hydrocarbons and the heat transfer fluid may be single pass, receiving heated heat transfer fluid from the convective heating section, which, after exchanging heat with the hydrocarbon, may recirculate the heat transfer fluid back to the convective section for re-heating. In other embodiments, such as where an outlet temperature of the heat transfer fluid from one heating zone is sufficient to provide the necessary heat to a second heating zone, the heat transfer fluid may be used in multiple heating zones before being returned to the convective heating section for re-heating.
While configurations of the heat transfer heating systems may vary based on the primary expected feedstock(s) and other requirements of the system, some embodiments herein may include heat transfer temperature control loops that are used to provide a desired inlet heat exchange fluid temperature to a given heat exchanger, adding hot heat exchange fluid to the circulating heat transfer fluid to attain or maintain the heater inlet temperature while withdrawing cool heat exchange fluid from the loop for re-heating. One or multiple storage tanks may also be used to store the heated heat exchange fluid, the cooled heat exchange fluid, or intermediate temperature heat exchange fluids, and such storage tanks may be associated with individual heater flow loops or with an overall system flow loop for providing hot and receiving cool heat exchange fluids from the individual heater flow loops.
Referring now to
The resulting desalted hydrocarbon 324 is then heated in one or more exchangers 330 to a temperature sufficient to vaporize volatile (light) hydrocarbons in the crude oil, such as naphtha range and lighter hydrocarbons. The heated desalted crude oil 332 is then fed to a separation device 334, a HOPS device being illustrated, although others may be used. Separation device 334 is then used to separate the volatile hydrocarbons, recovered as a light fraction via flow line 336, from a residual liquid fraction recovered via flow line 338. The light fraction 336 may then be superheated in one or more convective coils 340, 342 located in a convective heat recovery section 343 of a cracking furnace 344. The superheated light fraction 346 is then fed to a radiant coil 348 located in a radiant zone 350 of cracking furnace 344, where it is rapidly heated to cracking temperatures. The resulting cracked effluent 352 is then quenched in a transfer line exchanger 354 and the quenched effluent 356 may be fed to downstream heat recovery and product separations (not illustrated). While not illustrated in
Utilities for the heaters used to heat the crude oil, and to heat the desalted crude oil, are provided by a heat transfer fluid. A heat transfer fluid 360 is fed to a convective coil 362 located in the convective heat recovery section 343 of cracking furnace 344, producing a heated heat transfer fluid 364. Heated heat transfer fluid 364 may then fed via one or more flow systems 366, 368, 370 to heat exchangers 314, 316, 330. The heated heat transfer fluid is cooled against the crude oil or desalted crude oil in the exchangers, and the resulting cooled heat transfer fluid effluents 372, 374, 376 may be recirculated for reheating in cracking furnace 344 and for continued use in heating the hydrocarbon feedstock being processed.
In this manner, the heat may be transported to the hydrocarbon feedstock being processed, rather than continually transporting the hydrocarbon feedstock back on forth to the heat. Such has been found to be cost effective, reducing piping requirements and associated process-side pressure drops. Further, by heating the hydrocarbon for desalting and separations external to the heater, the operability and flexibility of the cracking furnace and the convective heating zone is improved.
Condensate liquid may have a small quantity of tails (high boiling hydrocarbons), and thus a single separation device 334, as illustrated in
As with the embodiment of
The particular arrangement of the hot oil system may depend upon the feedstock(s) being processed, as well as upon the heating requirements needed for desalting and performing the desired separations. Thus, the heated heat transfer fluid may be provided to each heat exchanger to meet the heating requirements or, as illustrated in
Other various heat transfer fluid flow systems may be crafted depending upon the heating requirements, location (ambient temperatures expected), and other various factors known to one skilled in the art. For example, a “cold” heat exchange fluid tank and a “hot” heat exchange fluid tank may be used, providing heat exchange fluids to heat transfer fluid temperature control loops associated with each heat exchanger or train of heat exchangers. The heat exchange fluid in the “hot” tank may be maintained at an appropriate temperature via heating in a convective coil of the cracking furnace. While a variety of heat transfer fluid systems are not illustrated herein, one skilled in the art can appreciate the various manners in which the heat from the convective section of the cracking furnace may be recovered using a heat transfer fluid, and the thus heated heat transfer fluid may be used to transport the heat to the hydrocarbons being processed, rather than transporting the hydrocarbons back and forth to and from the heat, so as to provide the benefits noted herein.
Embodiments herein are described with respect to crude oil, such as whole crude oil or a desalted whole crude oil, but any high boiling end point hydrocarbon mixture or wide boiling hydrocarbon mixture can be used. While
Convective heating sections of cracking furnaces according to embodiments herein may include, as described above, one or more heating coils for heating a high temperature stable heat transfer fluid, one or more coils for generating steam or superheating steam, and one or more coils for superheating the vaporized hydrocarbon fractions for cracking within the radiant section of the cracking furnace. As may be appreciated by one skilled in the art, the temperature of the exhaust gas from the radiant section of the furnace decreases as heat is recovered from the exhaust gas in the convective heating section. The location and number of the respective coils may depend upon the overall requirements of the system, and thus are not provided in detail herein. Preheating of combustion air may be provided using coils in the convective heating section in some embodiments, and may be provided using heated heat transfer fluid in an external heat exchanger in other embodiments.
In some embodiments, no heating coils are provided in the convective heating section for heating of a hydrocarbon liquid fraction, and all heating of hydrocarbon liquids is performed external to the cracking furnace using a heated high temperature stable heat transfer fluid in the convective section of the cracking furnace. In this manner, a simplified arrangement of hydrocarbon piping may be achieved, resulting in numerous benefits to the overall system. Superheating the hydrocarbon plus dilution mixture before entering the radiant coil is performed in the convection section, where the fluegas has the available energy to achieve the desired cross over temperature.
In some embodiments herein, first heat transfer fluid is heated in the convection section instead of crude or any other hydrocarbon. Heat transfer fluid is the heated against crude in an exchanger to the required temperature level for desalter. After the desalter, the crude is again heated in another exchanger to the required level for separating the naphtha fraction. A naphtha+dilution steam fraction coming out of the separator as an overheads enters the lower mixed preheat section of the convection section. From this section onwards, for processing of the naphta fraction the convection section is similar to a typical ethylene heater, superheating and cracking. For flow control for each coil, a hydrocarbon plus dilution steam mixture will be controlled using control valves and then flow venturis may be used to split the flow to parallel tubes. For embodiments using a HOPS, a HOPS operates at constant pressure, and the overhead can be set at a desired level that dictates the amount of naphtha taken out of crude (cut point set). The dilution steam is superheated in the convection section. For the fixed HOPS pressure, an almost fixed dilution steam flowrate and temperature achieve a desired level of vaporization. However, with just flue gas alone, sometimes the duty may not be sufficient. Instead of flue gas, embodiments herein use a heat transfer fluid that is heated in the convection section. If needed, the heat transfer fluid can be heated by other sources (external heaters, electric heaters, etc.). Heat transfer fluid heating can be common to more than one heater and hence piping is simplified. Heater control becomes easier. Further, controlling the HOPS overhead can be independent of the heater operation. By this arrangement, when split cracking (some coils of the same heater are cracking one feed while other coils in that heater are cracking a different feed), operation becomes simplified. The heater for cracking purpose receives only a feed mixed with dilution steam. There is no need to consider preheating the feed in the convection section. Therefore, preheating the feed for separating the naphtha or separting gasoil from the heavies will not control or dictate the heater design. Thus, when there is excess enthalpy or insifficient enthalpy in the flue gas, it affects only the heat transfer fluid heating level. If excess duty is available in the flue gas, more heat transfer fluid can be heated and additional heat transfer fluid can be used for other purposes. If duty is insufficient, external heat (steam heating or electric heating) can be used to heat the heat transfer fluid, which will supply heat to crude and/or gasoil or directly to heat the process fluid. Concepts herein thus simplifies the operation and complexity of the design.
As illustrated in
Referring now to
While the embodiment of
While not illustrated in
Further, a single HOPS or ISD may be used to provide feed to multiple heaters. For example, a single HOPS separating a naphtha range fraction from a wide boiling hydrocarbon mixture may provide a vaporized naphtha stream to multiple steam cracking furnaces. When whole plant energy balance is considered, additional energy available in the flue gas in any heater may be used to supply the energy for preheating the feed where it is deficient via heat transfer fluid heated in the heaters. HOPS is based on feed basis and not heater basis. That is, all or many heaters cracking naphtha share the same HOPS and each heater need not supply the same amount of energy for naphtha vaporization in the HOPS. Only the total is important for vaporization. As a result, in real operation, each heater can operate at different severities and still the HOPS can produce vapor stream for all those heaters.
Embodiments herein also permit cracking feeds other than crude. For embodiments changing feeds, transitioning from a lighter feed to a heavier feed may result in bypass of a separation device in the train, such that an appropriate temperature heat transfer fluid may be provided to the hydrocarbon. For example, a naphtha type feed will be heated by heat transfer fluid and steam will be added to a first stage HOPS. If the feed does not contain significant naphtha range hydrocarbons, the first separation stage may be bypassed and the feed may be heated and fed to the second stage HOPS. Still heavier feeds may bypass a first and second stage HOPS and be fed to a third stage HOPS. Note that superheated dilution steam addition before or in HOPS helps vaporizing the fluid at low temperatures. So, overall, the design according to embodiments herein also permits other feeds and feed flexibility. Since the heating and separation of the hydrocarbon feedstocks are independently controlled, the overhead products by themselves or with other external feeds can be split cracked. There is also no issue of co-cracking feeds. Any feed that has to be co-cracked can be mixed with the appropriate HOPS outlet and the hydrocarbon plus dilution steam flow rate is regulated for each coil.
The independence of separations versus heating requirements provides several advantages over systems in which a majority or all of the hydrocarbon heating is performed within the cracking furnace.
The heater allocation for 1025 KTA ethylene plant is shown in Table 1 as an example for Permian crude cracking. Embodiments herein are not limited to Permian crude, but any crude can be used. Typically light crudes show significant economic advantage over other crudes.
Crude is separated into Naphtha after desalter in a HOPS (HOPS-1). This is mixed with C6 recycle from the recovery section after BTX extraction. There are two types of SRT VII cracking heaters. The first is light heater preferably used for cracking naphtha and light feeds (LPG and ethane). The second one is a heavy feed heater where gasoil is preferably cracked. Note that the gas oil heater can accept naphtha and light feeds. Naphtha heater cannot accept gas oil feeds due to significant transfer line exchanger fouling that would occur. For illustration SRT VII heater is shown. Any heater type can be used instead of SRT VII.
In the Table, we have used energy balance on the basis of the whole plant. To recover maximum energy contained in the effluents, light and heavy feed heater designs are used. Spare heater is usually a heavy feed heater. Naphtha separated in HOPS-1 after desalter is mixed with C6 recycle and cracked in a full heater which has 7 SRT VII high selective coils and in 4 coils of a heater that split cracks with C4s in 3 coils and in 4 coils of a heavy feed heater that is split cracked with gasoil (from HOPS-2) in 3 coils and in 7 coils (one full heater) of a heavy feed heater. The gas oil (3 coils) is split cracked with naphtha in 4 coils of a heater and the remaining gas oil is cracked in 4 heavy heaters (7 coils in each heater). The flowrates of each feed going into the heater are shown along with number of coils used. LPG is also locally produced after removing C4H6 and normal butenes and saturating the remaining fraction and it is recycled to extinction. This example clearly shows Permian crude can be directly cracked using HOPS technology and split cracked for other feeds. The system is in complete heat balance. The gasoil fraction is based on 520° C. cut point and hence 4.8% of crude is rejected as residue which is blended with fuel oil. HOPS-1 outlet temperature operates at 179° C. and HOPS-2 operates at 369° C. for the assumed pressure profile. At this pressure, a small import of super high-pressure steam (about 28 T/h) is required to meet the high-end point used for separating gasoil from residue. By optimizing the system and/or lowering the cut point to 490° C. for gasoil, super high-pressure steam import is not required. The amount of residue will increase only to 8%. So, light and also heavy crudes can be economically cracked and with low CAPEX they can be designed to separate naphtha and gasoil fractions without a crude separation unit. Note that for the deep cutting used in this example (520° C.), crude separation requires an atmospheric column and a vacuum column operating at 10 mm Hg. These are expensive and energy intensive units. Embodiments herein do not require a crude and vacuum column and, using heat transfer fluid and dilution steam, the whole crude can be cracked to produce olefins.
For a typical system, such as illustrated in
In contrast, embodiments herein simplify the process flow, reduce the capital requirements, and improve heat recovery. Maximum amount of crude to chemicals can thus be realized. Split cracking of different feeds with different separators operating at different conditions and of external feeds is also possible.
Using the heat transfer fluid concept according to embodiments herein, heat is recovered from the flue gas to the maximum extent possible, as the heat is exchanged against a single fluid. This fluid is then used to provide heat to process fluids operating at different conditions (cold liquids to hot vapors at different pressures). As these conditions are not encountered in the convection section, the design of the convection section becomes simple as only one fluid (heat transfer fluid) is considered. The heat is transferred to process fluid outside the convection section using conventional exchangers. Different exchangers can be used for different services exchanging heat against heat transfer fluid. These heat exchangers can be optimized for individual services. As they are outside the convection section they can easily be maintained, serviced and spared. Hence, the reliability of the overall system is improved. The heating is done to get a desired fraction from crude using HOPS or other separation technology. By adjusting the heating, the HOPS tower control (operation) becomes easy.
Without the heat transfer fluid, the operation becomes complex and only a narrow range of operating conditions at full capacity can be realized. This use of the heat transfer fluid increases the operating window and permits split cracking with improved efficiency. High temperature stable heat transfer fluids can be heated to high temperatures with minimum degradation and hence they act as circulating fluid exchanging heat from flue gas to process fluid in an indirect way. Heat transfer to different process streams happens outside the convection section exchanging heat against the heat transfer fluid. Therefore, each service can be optimized. In a worst-case scenario, the exchanger can be spared and the reliability of the system is improved; further, it is much more expensive to spare a convection section than an exchanger.
Unless defined otherwise, all technical and scientific terms used have the same meaning as commonly understood by one of ordinary skill in the art to which these systems, apparatuses, methods, processes and compositions belong.
The singular forms “a,” “an,” and “the” include plural referents, unless the context clearly dictates otherwise.
As used here and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.
“Optionally” means that the subsequently described event or circumstances may or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur.
When the word “approximately” or “about” are used, this term may mean that there can be a variance in value of up to +10%, of up to 5%, of up to 2%, of up to 1%, of up to 0.5%, of up to 0.1%, or up to 0.01%.
Ranges may be expressed as from about one particular value to about another particular value, inclusive. When such a range is expressed, it is to be understood that another embodiment is from the one particular value to the other particular value, along with all particular values and combinations thereof within the range.
While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims.
| Number | Date | Country | |
|---|---|---|---|
| 63586479 | Sep 2023 | US | |
| 63578422 | Aug 2023 | US |
