Fcc product vapor separation process for improved product recovery

Abstract

This document discloses a system and method for separating cracked hydrocarbon mixtures. A main fractionation column separates the cracked hydrocarbon mixture into top, side, and bottom fractions containing C1 to C6+ hydrocarbons. A top condenser and high-pressure separation system partially condenses the top fraction and compresses the uncondensed vapor to produce a compressed gas fraction and a compressed liquid fraction. A first distillation column receives the compressed liquid fraction and separates it into a first top vapor and a first bottom fraction. A second distillation column separates the first bottom fraction into a second top fraction and a second bottom fraction. An absorber receives a portion of the second bottom fraction and the side liquid fraction and contacts it in countercurrent flow with the compressed gas fraction, thereby producing an absorber top fraction and absorber bottom fraction containing exhaust gas. Such a system can be used to integrate existing FCC / RFCC units with petrochemical complexes.

Description

Technical Field

[0001] The embodiments disclosed herein generally relate to the efficient separation of hydrocarbons or other reaction products from catalytic cracking. Background Technology

[0002] Fluid catalytic cracking (FCC) units and residue fluid catalytic cracking (RFCC) units within refinery complexes are typically designed to produce finished products. These finished products typically include exhaust gas consisting of lighter hydrocarbons (rich in methane and ethane), a mixture of olefin-grade products recovered as light fractions (primarily containing ethylene, propylene, and butene, and possibly C5 olefins), and heavier hydrocarbon fractions including gasoline.

[0003] An example of a separation system based on conventional industrial practice is shown in Figure 1 (Prior Art). For the sake of simplicity, only the main equipment is shown. Various components of the separation system are illustrated to provide a comprehensive understanding of the system; however, those skilled in the art will recognize that many components, such as pumps, compressors, exchangers, valves, bypass lines, control systems, etc., are not shown.

[0004] The separation system includes a main fractionating column 102A, a main fractionating column top and high-pressure separation system 104A, a primary absorber 108A, a secondary absorber 108AA, and a fractionation zone including a deethaner 180A and a debutanizer 190A. The main products recovered from the separation system include fuel gas (C1, C2) fractions 140AA, LPG (C3, C4) fractions 150AA, naphtha-range fractions 160A, and heavy fractions 170A. Other fractions can also be recovered, such as various intermediate hydrocarbon fractions (not shown) recovered from the main fractionating column 102A.

[0005] The cracking effluent 112 can be fed to the main fractionating column 102A to separate the cracking effluent into a bottom fraction (heavy product fraction) 170A, one or more side-drip fractions (192A, 101A), one or more additional side-drip liquid fractions (not shown), and overhead vapor 118A. The side-drip liquid fraction 101A can be fed to a secondary absorber 108AA, while the overhead vapor 118A can be processed by a fractionating column top and high-pressure separation system 104A, which may include a cooler, flash tank, compressor, pump, etc. The separation system 104A provides crude naphtha 122, primary gas (C1-C4 enriched) 130A, and liquid intermediate 132A. Streams 122 and 130A are fed to primary absorber 108A, from which fuel gas 140A is recovered. This fuel gas is further fed to secondary absorber 108AA to remove C5+ range hydrocarbons. Stream 140AA recovered from secondary absorber 108AA is mixed with the refinery fuel gas header based on its properties and requirements. Side feed 101A from main fractionation column 102A is used as the absorption medium in secondary absorber 108AA. Bottom liquid 142A from secondary absorber 108AA is recycled back to main fractionation column 102A.

[0006] Liquid intermediate 132A from system 104A is fed to deethanizer 180A, which removes C1-C2 fractions and sends the remaining liquid 182A to debutanizer 190A. Debutanizer 190A separates liquid 182A into LPG fraction (150AA) and naphtha fraction (160A). A portion of naphtha fraction 160A, 192AA, is fed to primary absorber 108A for C3 and C4 fraction recovery as described above. This recirculation rate directly affects LPG recovery from the system and controls the size of most of the equipment. Naphtha liquid 160A is the product that is blended into the gasoline pool after necessary treatments (such as desulfurization).

[0007] With the increasing adoption of electric vehicles, on-road gasoline demand is expected to slow significantly or decline in the coming years. Therefore, conventional separation schemes used in FCC units may become unsuitable. As conventional FCC / RFCC units shift from gasoline production to naphtha enrichment with lighter molecules / BTX, commonly used FCC separation units, such as those shown in Figure 1, may not satisfactorily process reactor effluents into end-user products. Summary of the Invention

[0008] In one aspect, embodiments of this document relate to a hydrocarbon separation system. The hydrocarbon separation system includes a flow line for conveying a cracking reaction effluent containing a hydrocarbon mixture from one or more cracking reactors, the hydrocarbon mixture comprising methane (C1) to heavy (C12+) hydrocarbons. The separation system also includes a main fractionating column configured to receive the hydrocarbon mixture and configured to separate the hydrocarbon mixture into overhead vapor, a side liquid fraction, and a bottom product fraction containing C1 to C6+ hydrocarbons. A main fractionating column overhead condensation and high-pressure separation system is configured to partially condense the overhead vapor and compress the uncondensed vapor to produce a compressed gas fraction and a compressed liquid fraction. A demethanizer is configured to receive the compressed liquid fraction and separate it into a demethanizer overhead vapor fraction (containing methane-enriched gas) and a demethanizer bottom fraction (containing C2 to C6+ hydrocarbons). The depentanizer is configured to receive the bottom fraction from the demethanizer and separate it into a top fraction (containing C2 to C5 olefins) and a bottom fraction (containing C6+ hydrocarbons). Furthermore, the absorber is configured to receive a portion of the bottom fraction from the depentanizer and a side-flow liquid fraction, contacting it countercurrently with a compressed gas fraction to produce an absorber top fraction and an absorber bottom fraction containing methane.

[0009] In another aspect, embodiments of this document relate to a hydrocarbon separation system comprising a flow line for conveying a cracking reaction effluent containing a hydrocarbon mixture from one or more cracking reactors, the hydrocarbon mixture comprising methane (C1) to heavy (C12+) hydrocarbons. A main fractionating column is configured to receive the hydrocarbon mixture and to separate the hydrocarbon mixture into overhead vapor, a side-drip liquid fraction, and a bottom product fraction containing C1 to C6+ hydrocarbons. A main fractionating column overhead condensation and high-pressure separation system is configured to partially condense the overhead vapor and compress the uncondensed vapor to produce a compressed gas fraction and a compressed liquid fraction. A first distillation column is configured to receive the compressed liquid fraction and separate the compressed liquid fraction into a first overhead vapor fraction and a first bottom fraction. Furthermore, a second distillation column is configured to receive the first bottom fraction and separate the first bottom fraction into a second overhead fraction and a second bottom fraction. The system further includes an absorber configured to receive a portion of the second bottom fraction and a side-flow liquid fraction and contact it in countercurrent flow with the compressed gas fraction to produce an absorber top fraction and an absorber bottom fraction containing waste gas.

[0010] In some embodiments, the size and configuration of the first distillation column are designed to operate flexibly as a demethanizer in a first operating mode and flexibly as a deethanizer in a second operating mode.

[0011] In some embodiments, the size and configuration of the absorber are designed to operate flexibly to recover exhaust gas containing methane and substantially free of C2 hydrocarbons in a first operating mode, and to recover exhaust gas containing both methane and C2 hydrocarbons in a second operating mode.

[0012] In some embodiments, the size and configuration of the second distillation column are designed to operate flexibly as a butane remover in a first operating mode and flexibly as a pentane remover in a second operating mode.

[0013] In some embodiments, the system may further include a flow line for feeding the bottom fraction of the absorber column to the top condenser and high-pressure separation system of the main fractionation column.

[0014] Some embodiments of the hydrocarbon separation system further include flow lines for feeding the first overhead vapor fraction to the main fractionation column overhead condensation and high-pressure separation system.

[0015] In some embodiments, the resulting compressed liquid fraction includes a first compressed liquid fraction containing C4 to C6+ hydrocarbons and a second compressed liquid fraction containing C1 to C6+ hydrocarbons. In such and similar embodiments, a flow line is provided for feeding the first compressed liquid fraction to an absorber, a flow line is provided for feeding a portion of the second compressed liquid fraction to a first distillation column, and a flow line is provided for feeding a second portion of the compressed liquid fraction as reflux feed to a main fractionation column.

[0016] In some embodiments, the absorber is further configured to generate absorber-side fraction and receive cooled absorber-side fraction, and the system further includes a heat exchanger configured to cool the absorber-side fraction and generate cooled absorber-side fraction.

[0017] Some embodiments of the system further include a heat exchange system disposed downstream of the main fractionation column and upstream of the absorber, the heat exchange system comprising two or more heat exchangers configured to cool the main fractionation column side feed and generate a cooled main fractionation column side feed to the absorber.

[0018] In some embodiments, a flow control system is provided, configured to divert a portion of the cooled main fractionation column side feed as reflux back to the main fractionation column, and to feed the remaining portion of the cooled main fractionation column side feed to the absorber.

[0019] In some embodiments, a second heat exchange system is provided for cooling the bottom fraction of the main fractionation column. In some embodiments, the heat exchange system and the second heat exchange system are configured to heat water via the main fractionation column side and the bottom fraction of the main fractionation column to generate a medium-pressure or high-pressure steam stream.

[0020] Optionally, in some embodiments, at least one of two or more heat exchangers in the heat exchange system includes a heat exchanger configured to reboil the bottom stream recovered from the first distillation column and return the heated reboiled bottom stream to the first distillation column.

[0021] Some embodiments of the high-pressure separation system include: a heat exchanger and a condenser for partially condensing overhead vapor to produce a first liquid fraction and an overhead vapor fraction; a first-stage compressor configured to compress the overhead vapor fraction and produce a compressed overhead vapor fraction; a separator configured to separate condensate from the compressed overhead vapor fraction and produce a compressed vapor fraction and a compressed liquid fraction; a second-stage compressor configured to further compress the compressed vapor fraction and produce a second-stage compressor effluent; and a high-pressure separator configured to separate liquid and vapor contained in the second-stage compressor effluent and the compressed liquid fraction to produce a high-pressure separation system liquid stream (which can be fed as a compressed liquid fraction to a first distillation column) and a high-pressure separation system vapor stream (which can be fed as a compressed gas fraction). In some embodiments, a mixing system is configured to mix the second-stage compressor effluent with the absorber bottom stream and the first distillation column overhead vapor fraction.

[0022] Some embodiments of the system include a second distillation column overhead system comprising: a heat exchanger for partially condensing the overhead fraction of the second distillation column; a tank for separating the partially condensed overhead fraction into a second distillation column overhead liquid fraction and a second distillation column overhead vapor fraction; a separator for collecting any liquid entrained in the second distillation column overhead vapor fraction, thereby producing separator vapor and separator liquid; a compressor for compressing the separator vapor, thereby producing a compressed product; a flow line for feeding a portion of the second distillation column overhead liquid fraction as a reflux feed to the second distillation column; and a flow line for recovering the remaining portion of the second distillation column overhead liquid fraction as a mixed olefin enrichment product. In some embodiments, a mixing system is provided for mixing the compressed product and the mixed olefin enrichment product to form a combined product. A flow line for feeding the separator liquid to a main fractionation column may also be provided.

[0023] In another aspect, embodiments of this document relate to a method for separating hydrocarbon mixtures. This separation method includes feeding a cracking reaction effluent containing a hydrocarbon mixture (including methane (C1) to heavy (C12+) hydrocarbons) to a main fractionating column, wherein the main fractionating column receives the hydrocarbon mixture and separates it into overhead vapor, a side-drip liquid fraction, and a bottom product fraction containing C1 to C6+ hydrocarbons. The overhead vapor is fed to a main fractionating column overhead condenser and high-pressure separation system to partially condense the overhead vapor and compress the uncondensed vapor to produce a compressed gas fraction and a compressed liquid fraction. The compressed liquid fraction is fed to a demethanizer to separate it into a demethanizer overhead vapor fraction (containing methane-enriched gas) and a demethanizer bottom fraction (containing C2 to C6+ hydrocarbons). The bottom fraction of the demethanizer is fed into a depentanizer to separate the bottom fraction into a depentanizer overhead fraction (containing C2 to C5 olefins) and a depentanizer bottom fraction (containing C6+ hydrocarbons). The method also includes contacting a portion of the depentanizer bottom fraction and a side-dose liquid fraction with a compressed gas fraction in a countercurrent flow in an absorber to produce an absorber overhead fraction and an absorber bottom fraction containing methane.

[0024] In another aspect, embodiments of this document relate to a hydrocarbon separation method comprising feeding a cracking reaction effluent containing a hydrocarbon mixture (including methane (C1) to heavy (C12+) hydrocarbons) to a main fractionating column, wherein the main fractionating column receives the hydrocarbon mixture and separates the hydrocarbon mixture into overhead vapor, side-feed liquid fraction, and bottom product fraction containing C1 to C6+ hydrocarbons. The overhead vapor is fed to a main fractionating column overhead condenser and high-pressure separation system to partially condense the overhead vapor and compress the uncondensed vapor to produce a compressed gas fraction and a compressed liquid fraction. The compressed liquid fraction is fed to a first distillation column to separate the compressed liquid fraction into a first overhead vapor fraction and a first bottom fraction. The method further comprises feeding the first bottom fraction to a second distillation column to separate the first bottom fraction into a second overhead fraction and a second bottom fraction. The method also includes contacting a portion of the second bottom fraction and the side liquid fraction with the compressed gas fraction in the absorber in a countercurrent flow to produce an absorber top fraction and an absorber bottom fraction containing waste gas.

[0025] Other aspects and advantages will become apparent from the following description and the appended claims. Attached Figure Description

[0026] Figure 1 illustrates a simplified process flow diagram of the product recycling section based on conventional industrial practice (existing technology).

[0027] Figures 2 to 5A simplified process flow diagram of a product recovery section according to one or more embodiments disclosed herein is illustrated, wherein similar numbers denote similar components. The embodiments herein contemplate combining and integrating absorber and deethaner sections to produce a high-quality product mixture of C2 to C4 or C2 to C5 hydrocarbons and BTX (benzene, toluene, and mixed xylenes) enriched naphtha. Detailed Implementation

[0028] The embodiments described herein typically involve the conversion of heavy hydrocarbons to light hydrocarbons, such as through cracking or hydrocracking. The embodiments described herein further relate to the separation and recovery of the resulting cracked hydrocarbon products.

[0029] As mentioned above, refineries may be shifting from gasoline production in their FCC or RFCC units to the production of larger quantities of light hydrocarbons, such as ethylene, propylene, and butene. For example, cracking reaction systems, such as single regenerator dual catalyst (SRDC) or combinations of FCC / residue FCC and SRDC, can be used to produce cracked hydrocarbon effluents with a higher proportion of lighter hydrocarbons. SRDC systems and combined FCC+SRDC systems, as well as other products from Lummus Technology LLC, are described in U.S. Patent No. 10,758,883.

[0030] The effluent generated from the feed is processed in an SRDC or a combination of FCC+SRDC and can then be fed into a separation system according to embodiments of this document for the separation and recovery of various products.

[0031] The hydrocarbon feedstock of a cracking reactor (including SRDC, RFCC, and FCC reactors) can include any quantity of hydrocarbons, hydrocarbon fractions, or hydrocarbon mixtures or intermediates. Feedstocks can include typical fluidized catalytic cracking (FCC) feedstocks, such as gas oil, but feedstocks used to produce the cracking products described herein can be in the C2 or greater range. The hydrocarbon mixtures that can be used in the embodiments disclosed herein can include a variety of hydrocarbon mixtures, including those with a wide boiling point range, wherein the final boiling point of the mixture may be less than 450°C, such as cracked naphtha from an FCC unit or any olefin stream from a refinery. In some cases, it may also be greater than 450°C, depending on the source and type of feedstock. Various systems combined with SRDC can also process whole crude oil or condensate to produce cracked effluents fed into a separation system according to the embodiments of this document. In summary, the methods disclosed herein can be applied to crude oil, condensate, and hydrocarbon mixtures with broad boiling point profiles and endpoints. Such hydrocarbon mixtures may include whole crude oil, virgin crude oil, hydrotreated crude oil, gas oil, vacuum gas oil, heating oil, jet fuel, diesel, kerosene, gasoline, synthetic naphtha, raffinate reformate, Fischer-Tropsch liquids, Fischer-Tropsch gases, natural gasoline, distillate oils, virgin naphtha, cracked naphtha, natural gas condensate, atmospheric pipeline bottoms distillate, vacuum pipeline distillate stream (including bottoms distillate), wide-boiling-range naphtha to gas oil condensate; heavy non-straight-run hydrocarbon streams from refineries, vacuum gas oil, heavy gas oil, atmospheric residue, hydrocracker wax, and Fischer-Tropsch wax, etc. In some embodiments, the hydrocarbon mixture may include hydrocarbons with boiling ranges from naphtha range or lighter to vacuum gas oil range or heavier. If desired, these feedstocks may be pretreated upstream of the methods disclosed herein to remove a portion of sulfur, nitrogen, metals, and Comstock carbon residue.

[0032] After the cracking products are generated in the upstream cracking reaction system, the reaction effluent is fed into a separation system according to embodiments of this document, such as... Figure 2 As shown in the image.

[0033] Figure 2 A simplified process flow diagram of a separation system according to an embodiment of this document is illustrated. The separation system includes a main fractionating column 202, a fractionating column top and high-pressure separation system 204, an absorber 208, and a fractionation zone including a demethanizer 380 and a debutanizer / depentanizer 390. Major products recovered from the separation system may include a methane-enriched fraction 240, a mixture of C2-C5 or C2-C4 fractions 250a and / or 250b, a naphtha-range fraction 260, and a heavy product fraction 270. Other fractions, such as various intermediate hydrocarbon fractions (not shown) recovered from the main fractionating column 202, may also be recovered.

[0034] The cracking reactor effluent 212 is fed to the main fractionation column 202 to separate the cracking reactor effluent into a bottom fraction (heavy product fraction) 270, one or more side-drip liquid fractions 301, and overhead vapor 218. The side-drip liquid fraction, or a portion thereof, is fed to the absorber 208, while the overhead vapor 218 is processed through the main fractionation column overhead and high-pressure separation system 204. The side-drip liquid fraction 301 can be withdrawn from the main fractionation column at column height to provide a side-drip fraction primarily containing naphtha-range hydrocarbons, although some heavier components (such as light cycle oil) and lighter components may also be present. One or more heavier products 392A, such as light cycle oil and / or heavy cycle oil, can also be side-dried from an intermediate section of the main fractionation column 202.

[0035] The main fractionation column overhead and high-pressure compression system 204 is used for partial condensation and compression of the overhead vapor 218 to produce overhead liquid fraction 232, overhead compressed vapor fraction 230, and overhead compressed liquid fraction 222C. A portion 232B of the overhead liquid fraction 232 is fed as reflux to the main fractionation column, and a portion 232A can be fed to the absorber 209. The compressed liquid fraction 222C is fed as reflux to the demethanizer 380. The compressed gas fraction 230 is fed to the absorber 208.

[0036] Absorber 208 receives and contacts the side-take liquid fraction 301 and the overhead compressed gas fraction 230 in countercurrent flow. Heavy hydrocarbons contained in the side-take 301 and the liquid fraction 232A from the main fractionation column overhead and high-pressure system 204, as well as a portion of stable naphtha-range material from the fractionation (butanizer / pentanizer) zone 390, i.e., lean oil 392, are also fed to absorber 208 for the absorption of ethane and heavier hydrocarbons. The liquid from absorber 208 is recovered as absorber bottom fraction 236. Methane and any other light gases present (such as hydrogen, H2S, nitrogen, carbon dioxide, etc.) are recovered from absorber 208 as methane enrichment product fraction 240. In some embodiments, methane enrichment product fraction 240 can be recovered as waste gas and can be treated in a gas treatment unit to recover methane.

[0037] The compressed liquid fraction 222C from the high-pressure separation system 204 is fed into the fractionation zone for the separation and recovery of ethylene and ethane enrichments and heavier hydrocarbons from the desired hydrocarbon fraction. For example... Figure 2 As shown, the fractionation zone may include one or more distillation columns 380, 390, which are configured to separate the compressed liquid fraction 222C into a top vapor fraction 332 containing methane-enriched gas, light olefin-enriched fractions 250a and 250b (such as C2 to C4 or C2 to C5 hydrocarbon product fractions), and a bottom fraction 260 containing hydrocarbons in the range of C5+ or C6+ naphtha (BTX enrichment).

[0038] Light fraction 332 and absorber bottom liquid 236 are fed to the top of the fractionation column and high-pressure separation system 204 for further recovery of C2+ components and final separation of methane from absorber 208. Bottom fraction 260 (such as naphtha-range hydrocarbons from fractionation zone 380) and heavy product fraction 270 can be recycled to, for example, a cracking reactor for additional production of lighter C2-C5 range olefins or to meet endothermic heat balance requirements.

[0039] As mentioned above Figure 2 In brief, the separation system provides a method for efficiently and cost-effectively separating cracked hydrocarbon effluents, such as those from FCC, RFCC, or SRDC reactor systems, or combined product vapors from various cracking reactors, into light olefin-enriched product blends. The resulting light olefin-rich (C2 to C5 petrochemical structural units) product blends can then be separated into high-quality products, such as ethylene, propylene, butene, C5 olefins, and aromatics-enriched naphtha products. This separation into high-quality products can be carried out on-site, or the product blends can be transported to a central facility for further processing into high-quality products.

[0040] Compared to typical gasoline-mode FCC units, combinations of SRDC or light olefin FCC / RFCC or SRDC+FCC / RFCC reactor systems typically produce lighter molecule (C2, C3, C4, and C5) and BTX (benzene, toluene, and mixed xylene) enriched naphtha at increased volumes. As conventional FCC / RFCC units shift from gasoline production to lighter molecule and BTX enriched naphtha, conventionally used FCC separation units may not satisfactorily process reactor effluents into end-user products. For SRDC or any light olefin FCC / RFCC product vapors or other cracking products rich in light olefin molecules and BTX enriched naphtha, separation of heavy product mixtures and gasoline recovery will not be satisfactory. However, the separation systems according to embodiments herein can process such cracking effluents to produce blends of light olefin enriched C2-C4 or C2-C5 products as a single product stream. This can alleviate the burden on refineries in terms of capital costs, operating costs, and land area, without requiring product or gasoline disposal. Reducing gasoline consumption and increasing the production of light olefins in refineries can make them more profitable during periods of reduced gasoline demand.

[0041] As mentioned above, Figure 2 This is a simplified process flow diagram of the separation system according to embodiments of this document. Embodiments of the separation system described herein also provide for reduced absorbent (stabilized naphtha / gasoline) recycling between the primary absorber and downstream fractionation units. This helps reduce the size of several units and utility requirements.

[0042] As described above, absorber 208 may receive each of side feed 301 and compressed vapor 230, which may include methane and C2-C4 olefins, as well as other components. The compressed vapor may be fed to the lower portion of the absorber, while side feed 301 may be fed to the upper portion of the absorber, thereby contacting lighter hydrocarbons in a countercurrent flow with heavier hydrocarbons, absorbing ethylene and other olefins and hydrocarbons contained in the compressed vapor generated during the overhead processing. The absorber may also receive overhead condensate fraction 232A received from system 204 as an additional absorbent, and the primary absorbent, i.e., portion 392 of the bottom fraction of the depentanizer / debutanizer 390 that was not recovered as naphtha product fraction 260. The countercurrent contact of compressed vapor with multiple absorbents can provide efficient recovery of C2 and heavier hydrocarbons, producing absorber overhead fraction 240 containing methane-enriched gas and containing little or no hydrocarbons heavier than methane. The absorbent and absorbed hydrocarbons can be recovered as the bottom fraction 236 of the absorber column, which can be recycled back to the top of the main fractionation column 202 and the high-pressure separation system 204 for final reprocessing in fractionation zones 380 and 390. Additional temperature control of the absorber can be provided by using one or more interstage cooling loops to extract, cool, and return the liquid to the absorber 208.

[0043] The fractionation zone may include a demethanizer 380 and a depentanizer / butanizer 390 as primary separators. The demethanizer 380 receives the compressed liquid fraction 222C from the main fractionator 202, separating the hydrocarbons therein into a light overhead fraction 332 (which may primarily consist of methane and some light olefins) and a bottom fraction 382 (which may include C2 and heavier hydrocarbons present in the compressed liquid fraction 232). A reboiler 342 may be located on the main fractionator side (…). Figure 2 A portion (not shown) exchanges heat between itself and the reboiler fraction at the bottom of the demethanizer to provide reboiler vapor to the demethanizer 380.

[0044] The bottom fraction 382 can be fed to a depentanizer / debutanizer 390 to separate C2+ hydrocarbons. As the name suggests, when operating as a depentanizer, unit 390 can be operated to recover C5 and lighter components as the top fraction 394 and C6+ hydrocarbons as the bottom fraction 392. Similarly, when operating as a debutanizer, unit 390 can be operated to recover C4 and lighter components as the top fraction 394 and C5+ hydrocarbons as the bottom fraction 392. The top fraction 394 of the depentanizer / debutanizer can then be partially condensed (using a refrigeration or cooling water system if necessary) and recovered in a reflux tank 396. The condensed C2-C5 or C2-C4 hydrocarbon liquid can be refluxed to the depentanizer / debutanizer 390, and the remaining portion of the C2-C5 or C2-C4 hydrocarbon liquid can be recovered as the first light product stream 250a. C2-C5 or C2-C4 vapor 398 recovered from reflux tank 396 can be processed in separator 397 to recover any entrained liquid 395, and then the vapor is compressed via compressor 399 and recovered as a second light olefin enrichment product 250b. Alternatively, the first light olefin enrichment product can be fed to compressor 399 to prepare a light olefin enrichment product (C2 to C4 or C2 to C5), which can be conveyed to a central location for further product recovery. Alternatively, the first light olefin enrichment product stream 250a can be combined with the second light olefin enrichment product 250b downstream of compressor 399 to prepare a combined light olefin enrichment product (C2 to C4 or C2 to C5), which can be conveyed to a central location for further product recovery. The bottom fraction from the butanizer / pentanizer 390 can be cooled, and a portion of the C6+ or C5+ hydrocarbons can be recovered as naphtha product 260, while the remaining portion 392 of the bottom fraction can be returned to absorber 208. As described above, C2-C5 or C2-C4 product streams 250a and 250b can be combined and recovered as a single product stream (not shown).

[0045] The main fractionation column, absorber, demethanizer, and debutanizer / depentanizer can be integrated in terms of flow rate and heat. Therefore, integrating the unit in this or a similar manner provides efficient operation and separation of the cracking hydrocarbon reactor effluent into a product stream containing C2-C4 or C2-C5 olefins and one or more heavier streams, such as naphtha and heavy hydrocarbon fractions. Each of the heavier streams can be recovered as a product or returned to the cracking zone for continuous production of light olefins.

[0046] In some embodiments, the size and configuration of distillation column 380 allow it to be flexibly operated as a demethanizer or a deethaner, recovering C1 or C1-C2 hydrocarbons as top 332, respectively. Furthermore, in some embodiments, the size and configuration of distillation column 390 allow it to be flexibly operated as a depentanizer or a debutanizer, recovering C2-C5 or C2-C4 hydrocarbons as top 394 (or recovering C3-C5 or C3-C4 hydrocarbons when column 380 operates as a deethaner). The operational flexibility in demethanizer column 380 depends on the mass (primarily calorific value) of the methane gas mixture produced from absorber 208, and also on the demand for ethylene, which can be extracted from the C2-C5 mixture separated by depentanizer column 390. Operating column 380 as a deethaner would slightly increase operating costs. Similarly, operating it as a debutanizer instead of a depentanizer would slightly increase operating costs. The operating mode largely depends on the demand for C5. According to the embodiments described herein, flexible operation may include operating in a first operating mode for a period of time, followed by or before operating in a second production mode for a period of time.

[0047] In some embodiments, such as Figure 3 As shown, the hydrocarbon separation system may include a flow line 232A for feeding a portion of the condensate fraction to the absorber, and may provide a flow line 232B for feeding a second portion of the condensate as reflux feed to the main fractionation column. A flow line 222C may be provided for feeding a compressed liquid fraction to the first distillation column.

[0048] For example Figure 3 As shown, absorber 208 can be further configured to produce absorber-side fraction 238A and receive cooled absorber-side fraction 238B; although only one is shown, multiple side-feeds and cooling refluxes can be provided. The system may further include heat exchanger 239, which is configured to cool absorber-side fraction 238A and produce cooled absorber-side fraction 238B.

[0049] like Figure 3 As further shown, in some embodiments, the system may additionally include a flow line for feeding the separated liquid 395 from the separator 397 to the main fractionation column 202.

[0050] As mentioned above, various methods can be used to integrate the thermal requirements of a system. Several options for thermal integration include... Figure 4As shown. In some embodiments, the system may include a heat exchange system 344 disposed downstream of the main fractionation column 202 and upstream of the absorber 208. The heat exchange system may include one or more heat exchangers configured to cool the main fractionation column side feed 301A and produce a cooled main fractionation column side feed 301B fed to the absorber 208. In some embodiments, the resulting cooling flow may be returned from the heat exchange system to the main fractionation column as a cooling reflux, and this may be applied to one or more side feeds.

[0051] For example Figure 4 As shown, the system may include a flow control system, such as flow control valves V1 and V2, which are configured to divert a portion 301C of the cooled main fractionator side feed 301B as reflux to the main fractionator 202, and to feed the remaining portion 301D of the cooled main fractionator side feed 301B to the absorber 208.

[0052] like Figure 4 As further shown, the system may also include a second heat exchange system 345, which includes one or more heat exchangers for cooling the bottom fraction 270 of the main fractionation column.

[0053] In some embodiments, heat exchange system 344 and second heat exchange system 345 are configured to heat water via the main fractionator side 301A and the main fractionator bottom fraction 270 to generate a medium-pressure steam stream (15 to 150 psig) or a high-pressure steam stream (150 to 1000 psig).

[0054] Common Reference Figure 3 and Figure 4 In some embodiments, at least one of two or more heat exchangers in the heat exchange system 344 includes a heat exchanger 342 configured to reboil the bottom stream 346 recovered from the demethanizer 380 and return the heated reboiled bottom stream 346R to the demethanizer. For systems including more than one reboiler 342, additional reboiler vapor 346R can be provided by heating the bottom fraction 346 via indirect heat exchange with entrained liquid 395 during transport from the separator 397 to the main fractionation column 202.

[0055] Now for reference Figure 5The illustration shows one embodiment of the main fractionation column top and high-pressure separation system 204. The high-pressure separation system 204 may include a heat exchanger 540 to partially condense the overhead vapor 218 received from the main fractionation column 202, and the partially condensed overhead vapor 541 may be separated in a condenser 542 to provide condensate 232 and overhead vapor fraction 544. The condensate 232 can then be separated to provide reflux 232B to the main fractionation column 202 and feed 232A to the absorber 208. A first-stage compressor 501 is provided to compress the overhead vapor fraction 544 and produce a compressed overhead vapor fraction 502 fed to a separator 503. Any condensate can then be separated from the compressed overhead vapor fraction using the separator 503, resulting in a compressed vapor fraction 504 and a compressed liquid fraction 546. A second-stage compressor 506 may be provided to further compress the compressed vapor fraction 504 and produce a second-stage compressor effluent 506. The high-pressure separator 508 can then be used to separate the liquid and vapor contained in the second-stage compressor effluent 509 and the compressed liquid fraction 546 to produce a high-pressure separation system liquid stream 222C and a high-pressure separation system vapor stream 230. An acidic water stream 550 can also be produced.

[0056] In some embodiments, a mixing system may be provided to mix the second-stage compressor effluent 509 with the absorber bottom stream 236 and the demethanizer overhead vapor fraction 332. Such mixing may occur upstream of or inside the separator 508.

[0057] The operating conditions for some sections of the separation scheme according to the embodiments herein may differ significantly from the conventional separation scheme of Figure 1. Operating conditions should be set based on performance and product requirements under specific circumstances. However, the operating conditions for each section are summarized below.

[0058] Main Fractionating Column: Depending on the feed quality, rate, and type, as well as design requirements, the main fractionating column 202 can be equipped with trays, packing, or a combination thereof. The top temperature of the main fractionating column controls the final boiling point of the naphtha, and it can vary based on feed quality and recovery targets. The top temperature of the main fractionating column can vary between 90°C and 160°C, while the bottom temperature can vary between 190°C and 350°C, which controls the initial boiling point of the bottom fraction. The operating pressure typically depends on the required yield of the upstream reactor based on the feed, which can allow the top pressure to be as low as 0.2 kg / cm³. 2 (g) changed to as high as 3.0 kg / cm³ 2 (g) (where (g) represents gauge pressure).

[0059] Absorber: The operating conditions of absorber 208 can be optimized to achieve the desired recovery of light hydrocarbons. Depending on the yield, recovery rate, and utility system, the top operating pressure can range from 9 to 20 kg / cm³. 2The temperature can vary between (g) and 15°C to 60°C.

[0060] Demethanizer: The operating conditions of the demethanizer 380 can be optimized to achieve maximum recovery of C2 components, and depending on the C2 recovery utility system, the top operating pressure can be from 10 kg / cm³. 2 (g) changed to 20 kg / cm 2 (g), and the bottom operating temperature can vary between 30°C and 120°C.

[0061] Demethanizer as Deethaner: As mentioned above, depending on the specifications of the methane gas mixture and ethylene requirements, the Demethanizer 380 offers complete flexibility in operating as a deethaner. When operating as a deethaner, the top operating pressure can be from 9 kg / cm³. 2 (g) changed to 20 kg / cm 2 (g), and the temperature at the bottom of the column can vary between 70°C and 150°C.

[0062] Depentanizer: The bottom temperature of the depentanizer (390°C) depends on the endpoint of the C6+ mixture, which is indirectly controlled by the top temperature of the main fractionation column (202). The operating pressure at the top of the depentanizer depends on the available utility system and can range from 4.5 kg / cm³. 2 (g) changed to 12 kg / cm 2 (g), and the bottom temperature can vary between 160°C and 280°C. Higher bottom temperatures in depentanizers may increase scaling in the reboiler.

[0063] Pentane de-pentanizer as butane de-pentanizer: As mentioned above, depending on C5 requirements, the 390 pentane de-pentanizer offers complete flexibility in operation as a butane de-pentanizer. Similarly, the bottom temperature of the butane de-pentanizer is indirectly controlled by the top temperature of the main fraction, which fixes the C6+ mixture endpoint. The operating pressure at the top of the butane de-pentanizer can range from 9 to 16 kg / cm³. 2 The temperature varies between (g) depending on the availability of the utility system, and the bottom temperature can vary between 160°C and 280°C.

[0064] The table below illustrates the benefits of the embodiments disclosed herein. In particular, C2 is recovered quite efficiently in blended light olefin-enriched products (O-grade blends) while minimizing capital and operating costs.

[0065]

[0066]

[0067] As described above, the separation system of this paper can operate under a variety of conditions depending on the feed to the system's cracking reaction effluent and the desired product separation (methanizer vs. ethaneizer, butanizer vs. pentaneizer). In some embodiments, the product stream produced using the separation unit of this paper can meet the following specifications: C2-C5 product flow: C1 < 3.0 wt%, C2 > 2.0 wt%, C6+ = trace; C2-C4 product flow: C1 < 3.0 wt%, C2 > 2.0 wt%, C5+ = trace; Naphtha depentanizer / debutanizer bottom: TBP range: C6-250℃, RVP<4 kPa (depentanizer). TBP range: C5-250℃ (butanogenizer), RVP<8.0 kPa (butanogenizer). Main fractionation column bottom: TBP 5 Vol% > 190℃ As described above, the embodiments described herein offer a variety of benefits compared to conventional separation of FCC cracking effluents for gasoline production. The main benefits of the embodiments described herein may include one or more of the following: (a) The embodiments disclosed herein separate reaction effluents in a cost-effective manner, with lower overall operating and capital costs compared to current conventional industrial practices. (b) Due to the smaller number or fewer pieces of equipment required for separation, the proposed separation schemes also have lower energy intensity and require less land space. (c) With the increasing momentum of electric vehicles and a significant decline in gasoline demand, conventional or prior art separation methods will not provide the desired economic results. Therefore, the schemes of the embodiments described herein offer the opportunity to creatively reconfigure process schemes to process larger volumes of light olefin enriched products with minimal changes to existing equipment, such as converting an existing deethaner to a demethanizer. Such schemes help to significantly reduce lean recirculation and thus allow for the processing of larger volumes of light olefin enriched products with minimal modifications to existing FCC gas units. (d) The embodiments described herein also minimize utility consumption and help reduce capital, operating costs, and land space for the refinery complex. (e) The exhaust products generated by the embodiments described herein are still good in terms of heating / calorific value and can be mixed with refinery fuel gas systems to meet internal fuel requirements.

[0068] Unless otherwise defined, all technical and scientific terms used shall have the same meaning as commonly understood by one of ordinary skill in the art to which these systems, devices, methods, processes and compositions pertain.

[0069] Unless the context clearly indicates otherwise, the singular forms “a”, “an”, and “the” contain plural indicators.

[0070] As used herein and in the appended claims, the words “comprising,” “having,” and “including,” and all their grammatical variations, are each intended to have an open, non-limiting meaning and do not exclude additional elements or steps.

[0071] "Optional" means that the event or situation described below may or may not occur. The description includes both scenarios in which the event or situation occurs and scenarios in which the event or situation does not occur.

[0072] When the terms “approximately” or “about” are used, the term may indicate a value that varies by up to ±10%, up to 5%, up to 2%, up to 1%, up to 0.5%, up to 0.1%, or up to 0.01%.

[0073] A range can be expressed as from about one particular value to about another particular value, including endpoints. When expressing such a range, it should be understood that another embodiment is from one particular value to another particular value, as well as all particular values ​​within the range and combinations thereof.

[0074] As used herein, “mixing system,” “mixer,” or similar terms refer to a flow line or mixing tee that may or may not include a static mixer, as well as a pump, container, or agitator, or other equipment known in the art that can be used to combine and blend two or more flow streams.

[0075] While 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 should be limited only by the appended claims.

Claims

1. A hydrocarbon separation system, comprising: A flow line for conveying cracking effluent containing a hydrocarbon mixture from one or more cracking reactors, the hydrocarbon mixture comprising methane (C1) to heavy (C12+) hydrocarbons; A main fractionating column, wherein the main fractionating column is configured to receive the hydrocarbon mixture, and wherein the main fractionating column is configured to separate the hydrocarbon mixture into a top vapor fraction containing C1 to C6+ hydrocarbons, a side liquid fraction, and a bottom product fraction. The main fractionation column overhead condensation and high-pressure separation system is configured to partially condense the overhead vapor and compress the uncondensed vapor to produce compressed gas fractions and compressed liquid fractions; A first distillation column is configured to receive the compressed liquid fraction and separate the compressed liquid fraction into a first overhead vapor fraction and a first bottom fraction; as well as A second distillation column is configured to receive the bottom fraction of the first column and separate the bottom fraction into a second top fraction and a second bottom fraction. An absorber is configured to receive a portion of the second bottom fraction and the side-draw liquid fraction and to contact it in countercurrent flow with the compressed gas fraction, and to produce an absorber top fraction and an absorber bottom fraction containing waste gas.

2. The hydrocarbon separation system according to claim 1, wherein: The size and configuration of the first distillation column are designed to operate flexibly as a demethanizer in a first operating mode and flexibly as a deethanizer in a second operating mode. The size and configuration of the absorber are designed to operate flexibly to recover exhaust gas containing methane and substantially free of C2 hydrocarbons in the first operating mode, and to recover exhaust gas containing both methane and C2 hydrocarbons in the second operating mode.

3. The hydrocarbon separation system according to claim 1, wherein the size and configuration of the second distillation column are designed to operate flexibly as a butanizer in a first operating mode and flexibly as a pentanizer in a second operating mode.

4. The hydrocarbon separation system according to claim 1, further comprising one or both of the following: Flow lines for feeding the bottom fraction of the absorber column to the top condensation and high-pressure separation system of the main fractionation column; and The flow line used to feed the first top vapor fraction to the top condensation and high-pressure separation system of the main fractionation tower.

5. The hydrocarbon separation system of claim 1, wherein the compressed liquid fraction comprises a first compressed liquid fraction containing C4 to C6+ hydrocarbons and a second compressed liquid fraction containing C1 to C6+ hydrocarbons, and wherein the hydrocarbon separation system further comprises: A flow line for feeding a portion of the first compressed liquid fraction into the absorber; A flow line for feeding a second portion of the compressed liquid fraction as reflux feed to the main fractionation tower; as well as A flow line for feeding the second compressed liquid fraction into the first distillation column.

6. The system of claim 1, wherein the absorber is further configured to generate an absorber-side fraction and receive a cooled absorber-side fraction, the system further comprising a heat exchanger configured to cool the absorber-side fraction and generate the cooled absorber-side fraction.

7. The system according to claim 1, further comprising: A heat exchange system is provided downstream of the main fractionation column and upstream of the absorber, the heat exchange system comprising two or more heat exchangers configured to cool the main fractionation column side feed and generate a cooled main fractionation column side feed to the absorber; as well as A flow control system is configured to divert a portion of the cooled main fractionation column side feed as reflux back to the main fractionation column, and to feed the remaining portion of the cooled main fractionation column side feed to the absorber.

8. The system of claim 7, further comprising a second heat exchange system for cooling the bottom fraction of the main fractionation column, wherein the heat exchange system and the second heat exchange system are configured to heat water via the main fractionation column side and the bottom fraction of the main fractionation column to generate a medium-pressure or high-pressure steam flow.

9. The system of claim 7, wherein at least one of the two or more heat exchangers of the heat exchange system comprises a heat exchanger configured to reboil the bottom stream recovered from the first distillation column and return the heated reboiled bottom stream to the first distillation column.

10. The system of claim 1, wherein the high-pressure separation system comprises: Heat exchangers and condensers for partially condensing the overhead vapor to produce a first liquid fraction and an overhead vapor fraction; The first-stage compressor is configured to compress the overhead vapor fraction and produce a compressed overhead vapor fraction. A separator is configured to separate condensate from the overhead vapor fraction of the compression column and produce a compressed vapor fraction and a compressed liquid fraction; A second-stage compressor is configured to further compress the compressed vapor fraction and produce a second-stage compressor effluent. A high-pressure separator is configured to separate the liquid and vapor contained in the second-stage compressor effluent and the compressed liquid fraction to produce a high-pressure separation system liquid stream and the compressed gas fraction; as well as A mixing system configured to mix the effluent from the second-stage compressor with the bottom stream from the absorber and the top vapor fraction from the first distillation column upstream of the high-pressure separator.

11. The system of claim 1, further comprising a second distillation column top system, the second distillation column top system comprising: Heat exchanger used for partial condensation of the top fraction of the second distillation column; A tank used to separate the partially condensed overhead fraction of the second distillation column into the overhead liquid fraction and the overhead vapor fraction of the second distillation column. Separator is used to collect any liquid entrained in the vapor fraction at the top of the second distillation column, thereby producing separating vapor and separating liquid; A compressor is used to compress the liquid vapor, thereby producing a compressed product; A flow line used to feed a portion of the liquid fraction from the top of the second distillation column back into the second distillation column as reflux feed; as well as A flow line for recovering the remaining portion of the liquid fraction from the top of the second distillation column as a mixed olefin enrichment product.

12. The system of claim 11, further comprising one or both of the following: A mixing system for mixing the compressed product and the mixed olefin enrichment product to form a combined product; and A flow line used to feed the separated liquid into the main fractionation tower.

13. The system of claim 1, further comprising a reaction system including the one or more cracking reactors, wherein the cracking reactors are configured to produce C2 to C5 olefins and aromatics including benzene, toluene and a mixture of xylenes as target reaction products.

14. A method for separating hydrocarbons, comprising: The cracking reaction effluent containing a hydrocarbon mixture including methane (C1) to heavy (C12+) hydrocarbons is fed to a main fractionation column, wherein the main fractionation column receives the hydrocarbon mixture and separates the hydrocarbon mixture into overhead vapor, side liquid fraction and bottom product fraction containing C1 to C6+ hydrocarbons. The overhead vapor is fed to the overhead condensation and high-pressure separation system of the main fractionation column to partially condense the overhead vapor and compress the uncondensed vapor to produce compressed gas fractions and compressed liquid fractions; The compressed liquid fraction is fed into a first distillation column to separate the compressed liquid fraction into a first column top vapor fraction and a first column bottom fraction; The first bottom fraction is fed into the second distillation column to separate the first bottom fraction into the second top fraction and the second bottom fraction. as well as In the absorber, a portion of the second bottom fraction and the side-take liquid fraction are contacted with the compressed gas fraction in a countercurrent flow to produce an absorber top fraction and an absorber bottom fraction containing waste gas.

15. The hydrocarbon separation method according to claim 14, further comprising: The first distillation column is used as the first time period for the demethanizer operation and as the second time period for the deethanizer operation. as well as The absorber is operated to recover exhaust gas containing methane and substantially free of C2 hydrocarbons during the first time period, and to recover exhaust gas containing both methane and C2 hydrocarbons during the second time period.

16. The hydrocarbon separation method according to claim 14, wherein the size and configuration of the second distillation column are designed to operate flexibly as a butanizer in a first operating mode and flexibly as a pentanizer in a second operating mode.

17. The hydrocarbon separation method according to claim 14, further comprising one or both of the following: The bottom fraction of the absorber column is fed to the top condensation and high-pressure separation system of the main fractionation column; and The vapor fraction from the top of the first column is fed into the top condensation and high-pressure separation system of the main fractionation column.

18. The hydrocarbon separation method according to claim 14, wherein the compressed liquid fraction comprises a first compressed liquid fraction containing C4 to C6+ hydrocarbons and a second compressed liquid fraction containing C1 to C6+ hydrocarbons, the method further comprising feeding a first portion of the first compressed liquid fraction to the absorber, feeding the second compressed liquid fraction to the first distillation column, and feeding a second portion of the first compressed liquid fraction as reflux feed to the main fractionation column.

19. The method of claim 14, wherein the absorber is further configured to generate an absorber-side fraction and receive a cooled absorber-side fraction, the method further comprising cooling the absorber-side fraction to generate the cooled absorber-side fraction.

20. The method of claim 14, further comprising: The main fractionation column side feed is cooled in a heat exchange system located downstream of the main fractionation column and upstream of the absorber to produce a cooled main fractionation column side feed to the absorber. The heat exchange system includes two or more heat exchangers. A portion of the cooled main fractionation column is taken as reflux and diverted back to the main fractionation column, while the remaining portion of the cooled main fractionation column is fed into the absorber. as well as The bottom fraction of the main fractionating column is cooled in the second heat exchange system.

21. The method of claim 20, further comprising one or both of the following: Water is heated via the side portion of the main fractionating column and the bottom fraction of the main fractionating column to generate a medium- or high-pressure steam stream; and The bottom stream recovered from the first distillation column is reboiled, wherein at least one of the two or more heat exchangers in the heat exchange system includes a heat exchanger configured to reboil the bottom stream recovered from the first distillation column and return the heated reboiled bottom stream to the first distillation column.

22. The method of claim 14, wherein the operation of the high-pressure separation system comprises: The overhead vapor is cooled and partially condensed to produce a first liquid fraction and an overhead vapor fraction. The overhead vapor fraction is compressed in the first-stage compressor to produce a compressed overhead vapor fraction; Condensate is separated from the overhead vapor fraction of the compression column to produce a compressed vapor fraction and a compressed liquid fraction; The compressed vapor fraction is compressed in the second-stage compressor to produce the second-stage compressor effluent; The liquid and vapor contained in the effluent of the second-stage compressor are separated to produce the compressed liquid fraction fed to the first distillation column and the compressed gas fraction fed to the absorber; as well as The effluent from the second-stage compressor is mixed with the bottom stream from the absorber column and the vapor fraction from the top of the first distillation column.

23. The method of claim 14, further comprising, in the second distillation column top system: Partial condensation of the top fraction from the second distillation column; The partially condensed overhead fraction of the second distillation column is separated into the overhead liquid fraction and the overhead vapor fraction. Collect any liquid entrained in the vapor fraction at the top of the second distillation column, thereby producing separate vapor and separate liquid; The separated liquid is compressed to produce a compressed product; A portion of the liquid fraction at the top of the second distillation column is fed back into the second distillation column as reflux feed. as well as The remaining portion of the liquid distillate from the top of the second distillation column is recovered as a mixed olefin enrichment product.

24. The method of claim 23, further comprising one or both of the following: The compressed product and the mixed olefin enrichment product are mixed to form a composite product; and The separated liquid is fed into the main fractionation tower.

25. The method of claim 14, further comprising cracking a hydrocarbon feedstock in a reaction system comprising one or more cracking reactors to produce the cracking reaction effluent, wherein the one or more cracking reactors produce C2 to C5 olefins and aromatics comprising benzene, toluene and mixed xylenes as target reaction products.

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