Patent Application
20240026234
The field is the reaction of feed with fluid catalyst. The field particularly relates to an FCC process to produce light olefins with multiple reactors.
Catalytic cracking can create a variety of products from larger hydrocarbons. Often, a feed of a heavier hydrocarbon, such as a vacuum gas oil, is provided to a catalytic cracking reactor, such as a fluid catalytic cracking (FCC) reactor. Various products may be produced from such a system, including a gasoline product and/or light product such as propylene and/or ethylene.
In such systems, a single reactor or a dual reactor can be utilized. Although additional capital costs may be incurred by using a dual reactor system, one of the reactors can be operated to tailor conditions for maximizing products, such as light olefins including propylene and/or ethylene.
It can often be advantageous to maximize yield of a product in one of the reactors. Additionally, there may be a desire to maximize the production of a product from one reactor that can be recycled back to the other reactor to produce a desired product, such as propylene.
Moreover, some dual reactor systems utilize a mixture of catalysts, such as a larger pore catalyst and a smaller pore catalyst. In some instances, the proportion of smaller pore catalysts limit the production of desired light olefins. Consequently, it typically would be beneficial to segregate the catalysts for controlling the reaction thereof.
Thus, there can be a desire to provide a reactor system for catalytic cracking that may maximize operation conditions for maximizing propylene product.
A process for catalytic production of olefins comprises contacting a first hydrocarbon stream and a first stream of fluid catalyst in a first riser to produce a first cracked product stream and a spent catalyst stream. The first cracked product stream is separated in a main column. An overhead stream from the main column is separated into a second hydrocarbon stream. The second hydrocarbon stream is contacted with a second stream of fluid catalyst in a second riser to produce a second cracked product stream and a first stream of cool catalyst. A third hydrocarbon stream is obtained from the overhead stream and/or from the second cracked product stream. The third hydrocarbon stream is contacted with a third stream of fluid catalyst in a third riser to produce a third cracked product stream and a second stream of cool catalyst.
Additional details and embodiments of the invention will become apparent from the following detailed description of the invention.
The
The term “downstream communication” means that at least a portion of fluid flowing to the subject in downstream communication may operatively flow from the object with which it fluidly communicates.
The term “upstream communication” means that at least a portion of the fluid flowing from the subject in upstream communication may operatively flow to the object with which it fluidly communicates.
The term “direct communication” means that fluid flow from the upstream component enters the downstream component without passing through any other intervening vessel.
The term “indirect communication” means that fluid flow from the upstream component enters the downstream component after passing through an intervening vessel.
The term “bypass” means that the object is out of downstream communication with a bypassing subject at least to the extent of bypassing.
As used herein, the term “predominant” or “predominate” means greater than 50%, suitably greater than 75% and preferably greater than 90%.
The term “column” means a distillation column or columns for separating one or more components of different volatilities. Unless otherwise indicated, each column includes a condenser on an overhead of the column to condense and reflux a portion of an overhead stream back to the top of the column and a reboiler at a bottom of the column to vaporize and send a portion of a bottoms stream back to the bottom of the column. Feeds to the columns may be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottom outlet temperature. Overhead lines and bottoms lines refer to the net lines from the column downstream of any reflux or reboil to the column. Stripper columns may omit a reboiler at a bottom of the column and instead provide heating requirements and separation impetus from a fluidized inert media such as steam. Stripping columns typically feed a top tray and take main product from the bottom.
As used herein, the term “separator” means a vessel which has an inlet and at least an overhead vapor outlet and a bottoms liquid outlet and may also have an aqueous stream outlet from a boot. A flash drum is a type of separator which may be in downstream communication with a separator that may be operated at higher pressure.
As used herein, the term “boiling point temperature” means atmospheric equivalent boiling point (AEBP) as calculated from the observed boiling temperature and the distillation pressure, as calculated using the equations furnished in ASTM D1160 appendix A7 entitled “Practice for Converting Observed Vapor Temperatures to Atmospheric Equivalent Temperatures”.
As used herein, the term “True Boiling Point” (TBP) means a test method for determining the boiling point of a material which corresponds to ASTM D-2892 for the production of a liquefied gas, distillate fractions, and residuum of standardized quality on which analytical data can be obtained, and the determination of yields of the above fractions by both mass and volume from which a graph of temperature versus mass % distilled is produced using fifteen theoretical plates in a column with a 5:1 reflux ratio.
As used herein, “pitch” means the hydrocarbon material boiling above about 524° C. (975° F.) AEBP as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, D6352 or D7169, all of which are used by the petroleum industry.
As used herein, the term “T5” or “T95” means the temperature at which 5 mass percent or 95 mass percent, as the case may be, respectively, of the sample boils using ASTM D-86 or TBP.
As used herein, the term “initial boiling point” (IBP) means the temperature at which the sample begins to boil using ASTM D-7169, ASTM D-86 or TBP, as the case may be.
As used herein, the term “end point” (EP) means the temperature at which the sample has all boiled off using ASTM D-7169, ASTM D-86 or TBP, as the case may be.
As used herein, “vacuum gas oil” means a hydrocarbon material having an IBP of at least about 232° C. (450° F.), a T5 of between about 288° C. (550° F.) and about 392° C. (700° F.), typically no more than about 343° C. (650° F.), a T95 between about 510° C. (950° F.) and about 570° C. (1058° F.) and, or an EP of no more than about 626° C. (1158° F.) prepared by vacuum fractionation of atmospheric residue as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, D6352 or D7169, all of which are used by the petroleum industry.
As used herein, “atmospheric residue” means a hydrocarbon material having an IBP of at least about 232° C. (450° F.), a T5 of between about 288° C. (550° F.) and about 392° C. (700° F.), typically no more than about 343° C. (650° F.), and a T95 between about 510° C. (950° F.) and about 700° C. (1292° F.) obtained from the bottoms of an atmospheric crude distillation column.
As used herein, “vacuum residuum” means hydrocarbon material boiling with an IBP of at least about 500° C. (932° F.).
We have found that twice cracked naphtha or once or twice cracked C4 hydrocarbons can still be cracked to generate more propylene. However, conditions should be tailored for cracking twice cracked naphtha or C4 hydrocarbons to maximize propylene production. We propose a third riser to provide the favorable reaction conditions to maximize the yield of propylene.
Now turning to the FIGURE, wherein like numerals designate like components, a process and apparatus generally includes an FCC unit section 6 and a product recovery section 8. The FCC unit section 6 includes a first FCC reactor 10 comprising a first reactor unit 12 and a catalyst regenerator 14. Process conditions in the first FCC reactor 10 may include a cracking reaction temperature of about 400° to about 600° C., preferably about 538° C. to about 593° C. at the reactor outlet, and a catalyst regeneration temperature of about 500° to about 900° C. Both the cracking and regeneration occur at an absolute pressure between about 100 kPa (14 psia) to about 650 kPa (94 psia), preferably between about 140 kPa (20 psia) to about 450 kPa (65 psia).
The catalyst can be a single catalyst or a mixture of different catalysts. Usually, the catalyst includes two components or catalysts, namely a first component or catalyst, and a second component or catalyst. Such a catalyst mixture is disclosed in, e.g., U.S. Pat. No. 7,312,370 B2. Generally, the first component may include any of the well-known catalysts that are used in the art of FCC, such as an active amorphous clay-type catalyst and/or a high activity, crystalline molecular sieve. Zeolites may be used as molecular sieves in FCC processes. Preferably, the first component includes a large pore zeolite, such as a Y-type zeolite, an active alumina material, a binder material, including either silica or alumina, and an inert filler such as kaolin.
Typically, the zeolitic molecular sieves appropriate for the first component have a large average pore size. Usually, molecular sieves with a large pore size have pores with openings of greater than about 0.7 nm in effective diameter defined by greater than about 10, and typically about 12, member rings. Pore Size Indices of large pores can be above about 31. Suitable large pore zeolite components may include synthetic zeolites such as X and Y zeolites, mordenite and faujasite. A portion of the first component, such as the zeolite, can have any suitable amount of a rare earth metal or rare earth metal oxide.
The second component may include a medium or smaller pore zeolite catalyst, such as a MFI zeolite, as exemplified by at least one of ZSM-5, ZSM-11, ZSM-12, ZSM-23, ZSM-35, ZSM-38, ZSM-48, and other similar materials. Other suitable medium or smaller pore zeolites include ferrierite, and erionite. Preferably, the second component is a medium or small pore zeolite dispersed on a matrix including a binder material such as silica or alumina and an inert filler material such as kaolin. The second component may also include some other active material such as Beta zeolite. These compositions may have a crystalline zeolite content of about 10 to about 50 wt % or more, and a matrix material content of about 50 to about 90 wt %. Components containing about 40 wt % crystalline zeolite material are preferred, and those with greater crystalline zeolite content may be used. Generally, medium and smaller pore zeolites are characterized by having an effective pore opening diameter of less than or equal to about nm, rings of about 10 or fewer members, and a Pore Size Index of less than about 31.
The total catalyst mixture in the first FCC reactor 12 may contain about 1 to about 25 wt % of the second component, namely a medium to small pore crystalline zeolite with greater than or equal to about 1.75 wt % of the second component being preferred. The first component may comprise the balance of the catalyst composition. In some preferred embodiments, the relative proportions of the first and second components in the mixture may not substantially vary throughout the first FCC reactor 12. The high concentration of the medium or small pore zeolite as the second component of the catalyst mixture can improve selectivity to light olefins. In one exemplary embodiment, the second component can be a ZSM-5 zeolite and the mixture can include about 4 to about 10 wt % ZSM-5 zeolite excluding any other components, such as binder and/or filler.
Preferably, at least one of the first and/or second catalysts is an MFI zeolite having a silicon to aluminum ratio greater than about 15, preferably greater than about 75. In one exemplary embodiment, the silicon to aluminum ratio can be about 15:1 to about 35:1.
The contacting may occur in a narrow first riser 20, extending upwardly to the bottom of a first reactor vessel 22. The contacting of the first hydrocarbon feedstock and the first stream of fluid catalyst is fluidized by gas such as steam from a fluidizing distributor 24. In an embodiment, heat from the catalyst vaporizes the first hydrocarbon feedstock, and the first hydrocarbon feedstock is thereafter cracked to a first cracked product stream of lighter molecular weight in the presence of the first catalyst stream as both are transferred up the riser 20 into the reactor vessel 22 providing a first mixture of catalyst and product gases.
The pressure in the first riser 20 may be about 200 kPa (29 psia) to about 450 kPa (65 psia), but it could be lower. A steam rate of about 3 to about 7 wt % of the first hydrocarbon feedstock is added to the first riser 20. Inevitable side reactions occur in the first riser 20 leaving coke deposits on the catalyst that lower catalyst activity to provide a spent catalyst stream. The first cracked product stream in the first mixture of catalyst and product gases is thereafter separated from the spent catalyst stream using cyclonic separators which may include one or two stages of cyclones 62 in the reactor vessel 22. A gaseous, first cracked product stream exits the reactor vessel 22 through a first product outlet 31 to line 32 for transport to the downstream product recovery section 8.
The spent or coked catalyst requires regeneration for further use. The spent catalyst stream, after separation from the first cracked product stream by means of a disengagement device 54 in a first disengagement chamber 56, falls into a stripping section 34 where steam is injected through a distributor 35 to purge any residual hydrocarbon vapor. After the stripping operation, the stripped coked catalyst is carried to the catalyst regenerator 14 through a spent catalyst standpipe 36. Another portion of the stripped coked catalyst may be recycled to the riser 20 by the recirculation catalyst standpipe 19 without undergoing regeneration.
The product recovery section 8 is in downstream communication with the product outlet 31. In the product recovery section 8, the first cracked product stream in line 32 is directed to a lower section of an FCC main fractionation column 92. The main column 92 is in downstream communication with the first product outlet 31. Several fractions of FCC product may be separated and taken from the main column including a heavy slurry oil from the bottoms in line 93, a heavy cycle oil stream in line 94, a light cycle oil in line 95 taken from outlet 95a and a heavy naphtha stream in line 96 taken from outlet 96a. Any or all of lines 93-96 may be cooled and pumped back to the main column 92 to cool the main column typically at a higher location. Gasoline and gaseous light hydrocarbons are removed in a main overhead line 97 from the main column 92 and condensed before entering a main column receiver 99. The main column receiver 99 is in downstream communication with the product outlet 31, and the main column 92 is in upstream communication with the main column receiver 99. The second hydrocarbon stream and perhaps a third hydrocarbon stream is taken from the main overhead line 97.
An aqueous stream is removed from a boot in the main column receiver 99. Moreover, a condensed light naphtha stream is removed in line 101 while an overhead stream is removed in line 102. The overhead stream in line 102 contains gaseous light hydrocarbon which is very olefinic. The streams in lines 101 and 102 may enter a vapor recovery section 120 of the product recovery section 8.
The vapor recovery section 120 is shown to be an absorption-based system, but any vapor recovery system may be used including a cold box system. To obtain sufficient separation of light gas components, the gaseous stream in line 102 is compressed in compressor 104. More than one compressor stage may be used, but typically a dual stage compression is utilized. The compressed light hydrocarbon stream in line 106 is joined by streams in lines 107, 108 and 422, chilled and delivered to a high-pressure receiver 110. An aqueous stream from the receiver 110 may be routed to the main column receiver 99. A gaseous hydrocarbon stream in line 112 is routed to a primary absorber 114 in which it is contacted with unstabilized gasoline from the main column receiver 99 in line 101 to effect a separation between C3+ and C2−hydrocarbons. The primary absorber 114 is in downstream communication with the main column receiver 99. A liquid C3+ hydrocarbon stream in line 107 is returned to line 106 prior to chilling. A primary off-gas stream in line 116 from the primary absorber 114 may be directed to a secondary absorber 118, where a circulating stream of light cycle oil in line 121 diverted from line 95 absorbs most of the remaining C5+ and some C3-C4 hydrocarbons in the primary off-gas stream. The secondary absorber 118 is in downstream communication with the primary absorber 114. Light cycle oil from the bottom of the secondary absorber in line 119 richer in C3+ hydrocarbons is returned to the main column 92 via the pump-around for line 95. The overhead of the secondary absorber 118 comprising dry gas of predominantly C2-hydrocarbons with hydrogen sulfide, ammonia, carbon oxides and hydrogen is removed in a secondary off-gas stream in line 122.
Liquid from the high-pressure receiver 110 in line 124 is sent to a stripper 126. Most of the C2− hydrocarbons is removed in the overhead of the stripper 126 and returned to line 106 via overhead line 108. A liquid bottoms stream from the stripper 126 is sent to a first debutanizer column 130 in a bottoms line 128. The first debutanizer column 130 provides an overhead stream in line 132 comprising a C3-C4 hydrocarbon stream from the first debutanizer column. A bottoms stream in line 134 may comprise a first debutanized naphtha stream.
In a first embodiment, a first recycle light cracked naphtha stream may be taken in line 137 through a control valve thereon from the first debutanized naphtha stream in line 134 while the remainder of the first debutanized naphtha stream in line 141 may be further processed into gasoline or other products through a control valve thereon. In this embodiment it is envisioned that a naphtha splitter column 136 may be located upstream in the product recovery section 8.
In an alternative embodiment, the first debutanized naphtha stream in line 134 may be fed to the naphtha splitter column 136 in line 142 through a control valve thereon. In this alternative embodiment, the naphtha splitter column is located downstream in the product recovery section 8 as depicted in the FIGURE and the control valves on lines 137 and 141 will be closed. The naphtha splitter column separates the debutanized naphtha stream into a first split light naphtha stream in an overhead line 138 comprising C5-C7 hydrocarbons and a heavy naphtha stream in a bottoms line 140. An alternative first recycle light cracked naphtha stream may be taken in line 139 through a control valve thereon while the remainder of the first split light naphtha stream in the overhead line 138 may be further processed into gasoline or other products.
The C3-C4 hydrocarbon stream taken in line 132 may be separated in a C3-C4 splitter column 144 into a C3 hydrocarbon stream in an overhead line 146 and a C4 hydrocarbon stream in a bottoms line 148. A first recycle C4 hydrocarbon stream may be taken in line 149 through a control valve thereon while the remainder C4 hydrocarbon stream may be further processed into other products in line 147. The C3 hydrocarbon stream in the overhead line 146 may be further processed for propylene recovery.
One or both of the first recycle light cracked naphtha stream taken in line 137 from the first debutanized naphtha stream in line 134 from the first debutanizer column 130 in downstream communication with the main column 92 comprising olefinic C5-C7 hydrocarbons or the alternative first recycle light cracked naphtha stream taken from an overhead line 138 of the naphtha splitter column 136 in downstream communication with the main column 92 in line 139 comprising olefinic C5-C7 hydrocarbons and the first recycle C4 stream comprising olefinic C4 hydrocarbons taken from a bottoms line 148 of the C3-C4 splitter column also in downstream communication with the main column 92 in line 149 may be recycled to a second FCC reactor 202 in a second charge line 150 as the second hydrocarbon stream. The second hydrocarbon stream may be preheated to a temperature of about 221° C. (400° F.) to about 704° C. (1300° F.) and charged to the second FCC reactor 202.
The FIGURE shows a second FCC reactor 200 comprising a second reactor unit 202 and a catalyst heater 238. The second reactor unit 202 includes a second riser 212 in which the second hydrocarbon stream in line 150 charged through a distributor 213 or more near the base of the second riser 212 is contacted with a second stream of fluid catalyst in a second riser 212. The second hydrocarbon stream may comprise at least 20 wt % olefins, suitably at least wt % olefins and preferably at least 70 wt % olefins. The second hydrocarbon stream may comprise at least 1 wt % paraffins, suitably at least 15 wt % paraffins and preferably at least 25 wt % paraffins. The second hydrocarbon stream may comprise once cracked C4 to C7 hydrocarbons.
The second riser 212 extends upwardly through a second reactor vessel 210 in the second FCC reactor 202. A second stream of fluid catalyst may be fluidized with steam distributed from a distributor 218 at a bottom of the second riser 212. The second hydrocarbon stream is contacted with a second stream of fluid catalyst in the second riser 212. The second stream of fluid catalyst may be provided by a mixture of a first stream of hot catalyst from a first hot catalyst pipe 220 and a first stream of recycle catalyst from a first recycle catalyst pipe 222. The second hydrocarbon stream vaporizes and converts or cracks to a second cracked product stream comprising ethylene and propylene in greater concentration than in the second hydrocarbon stream. Molar expansion causes the second hydrocarbon stream and the second cracked product stream to rapidly ascend the second riser 212 entraining the second stream of fluid catalyst as a second mixture of catalyst and product gas.
The second stream of fluid catalyst can comprise less than about 20 wt %, preferably less than about 5 wt %, of the first component and at least 20% by weight, of the second component. In one preferred embodiment, the second stream of fluid catalyst can include at least about 20 wt % of a ZSM-5 zeolite and less than about 20 wt %, preferably less than about 5 wt % of a Y-zeolite. In another preferred embodiment, the second stream of fluid catalyst can predominantly comprise the second component and in a further embodiment can contain only the second component, preferably a ZSM-5 zeolite, as the catalyst.
In an aspect, the second stream of fluid catalyst may comprise coke from about 0.005 wt % to about 1.2 wt % coke. The presence of coke in this concentration passivates acid sites to help in preventing the production of dry gas. The dry gas may be defined as H2, H2S, carbon oxides, and C1-C2 hydrocarbons. Dry gas represents a loss in yield of valuable products and increases operation costs and equipment costs resulting from the handling of greater gas flow rates. The presence of coke in an amount from about 0.005 wt % to about 1.2 wt % in the riser sufficiently passivates acid site which in turn limits the production of dry gas.
Coke concentration is increased in the second riser by circulating unregenerated catalyst to the riser and promoting coke generation in the riser. If the FCC reaction generates coke on the catalyst recycle of a first stream of catalyst in a first recycle catalyst pipe 222 to the second riser 212 will increase coke in the riser because it bypasses regeneration. Increasing the recycle rate of the first recycle catalyst relative to the recycle rate of the first stream of hot catalyst from a first hot catalyst pipe 220 will increase coke concentration in the second riser. Some types of catalyst, such as ZSM5, generate little coke in an FCC reactor. If coke generation in the second riser is not sufficient, other ways may be used to increase coke concentration in the second riser which will be described hereinafter.
Process conditions in the second riser 212 will be more severe than in the first riser 20 because the second hydrocarbon stream is less crackable than the first hydrocarbons stream due to the former having been previously cracked in the first riser 20. The second riser 212 may operate at one or more of the following conditions relative to the first riser 20: a higher outlet temperature, a lower hydrocarbon partial pressure or a different catalyst density. Hydrocarbon partial pressure is reduced by reducing the total pressure in the second riser 212 independent of the pressure in the first FCC reactor 10 and perhaps adjusting the steam rate to the second riser 212.
Conditions in the second riser 212 may include a cracking reaction temperature of 400° to 650° C., preferably about 565° C. to about 635° C. at the reactor outlet. The cracking occurs at an absolute pressure between about 100 kPa (14 psia) to about 506 kPa (74 psia), preferably between about 138 kPa (20 psia) to about 310 kPa (45 psia). A steam flow rate of about 5 to about 25 wt % of the second hydrocarbon stream is added to the second riser 20. However, the steam rate in the second riser 212 can be as low as about 2 to about 25 wt % or it can be eliminated. Control valves on the first hot catalyst pipe 220 and on the first recycle catalyst pipe 222 can be used to adjust the catalyst density in the second riser 212 thus enabling control of the space velocity therein. Also, increasing the flow rate of the first recycle catalyst to the second riser 212 in the first recycle catalyst pipe 222 can increase the catalyst density in the second riser without impacting the heat input to the second riser supplied the first stream of hot catalyst in the first hot catalyst pipe 220 that is fed to the second riser 212.
The second riser 212 terminates in an upper end of a second disengagement chamber 211 located within the second reactor vessel 210 at a curved duct 214 or a plurality thereof. The curved duct 214 may centrifugally discharge a second mixture of product gas and catalyst into the second disengagement chamber 211. By centrifugal discharge, the first mixture is discharged from inwardly to outwardly. Centrifugal discharge of gases and catalyst produces a swirling helical pattern about the interior of the second disengagement chamber 211 to effect a disengagement of the second mixture of catalyst and product gas into a second cracked product stream and a first stream of cool catalyst in the second disengagement chamber 211.
The first stream of cool catalyst collects in a dense catalyst bed 228. The second stream of product gas passes upwardly through a second gas recovery conduit 226, is further separated from catalyst in cyclones 232 and is discharged from the second reactor vessel 210 through an outlet 230 in product line 231.
The FIGURE illustrates a third FCC reactor unit 302 in which a third hydrocarbon stream in line 315 distributed through a distributor 313 or more near the base of a third riser 312 is contacted with a third stream of fluid catalyst in the third riser. In an embodiment, the third FCC reactor unit 302 is integrated in the second FCC reactor 200 with the second FCC reactor unit 202. However, the third FCC reactor unit 302 may stand alone from the second FCC reactor unit 202 in its own FCC reactor. The third hydrocarbon stream may comprise at least 20 wt % olefins, typically at least 30 wt % olefins, suitably at least 50 wt % olefins and preferably at least 60 wt % olefins. The third hydrocarbon stream may comprise at least 25 wt % paraffins and preferably at least 35 wt % paraffins. The second hydrocarbon stream is typically more olefinic and/or more crackable than the third hydrocarbon stream. The third hydrocarbon stream may comprise a twice cracked light cracked naphtha stream and/or a twice cracked C4 hydrocarbon stream and/or a once cracked C4 hydrocarbon stream. The third hydrocarbon stream may be preheated to a temperature of about 221° C. (400° F.) to about 704° C. (1300° F.) and charged to the third FCC reactor 302.
The third stream of catalyst may be fluidized with steam distributed from a distributor 358 at a bottom of the third riser 312. The third stream of catalyst may have the same catalyst composition as the second stream of catalyst. The first stream of catalyst has a catalyst composition that is different from the catalyst composition of the second stream of catalyst and the third stream of catalyst. The third hydrocarbon stream is contacted with the third stream of fluid catalyst in the third riser 312. The third stream of fluid catalyst may be provided by a mixture of a second stream of hot catalyst from a second hot catalyst pipe 362 and a second stream of recycle catalyst from a second recycle catalyst pipe 264. The third hydrocarbon feedstock converts or cracks to a third cracked product stream comprising hydrocarbons of smaller molecular weight than the third hydrocarbon stream. Molar expansion causes the third hydrocarbon stream and the third cracked product stream to rapidly ascend the third riser 312 entraining the third stream of fluid catalyst as a third mixture of catalyst and product gas.
Process conditions in the third riser 312 may be more severe than in the second riser 212 and the first riser 20. The third riser 312 may operate at one or more of the following conditions relative to the second riser 212: a higher outlet temperature, a lower hydrocarbon partial pressure and a different catalyst density than the second riser. Hydrocarbon partial pressure may be reduced by reducing total pressure in the third riser 312 independent of the pressure in the first FCC reactor 10 and perhaps adjusting the steam rate to the third riser 312.
Conditions in the third riser 312 may include a cracking reaction temperature of about 400° C. to about 705° C., preferably about 565° C. to about 675° C. at the reactor outlet. The cracking occurs at an absolute pressure between about 100 kPa (14 psia) to about 506 kPa (74 psia), preferably between about 138 kPa (20 psia) to about 310 kPa (45 psia). Steam of about 25 to about 50 wt % of third hydrocarbon stream rate is added to the third riser 312. However, the steam rate in the third riser 312 can be as low as about 2 to about 50 wt % and it can be eliminated. Control valves on the second hot catalyst pipe 362 and on the second recycle catalyst pipe 264 can be used to adjust the catalyst density in the third riser 312 thus enabling control of the space velocity therein. Also, increasing the flow rate of the spent, second recycle catalyst stream to the third riser 312 in the second recycle catalyst pipe 264 can increase the catalyst density in the third riser 312 without impacting heat input to the third riser.
Coke concentration is increased in the third riser 312 by circulating unregenerated catalyst to the riser and promoting coke generation in the riser. If the FCC reaction generates coke on the catalyst recycle of a second stream of recycle catalyst in a second recycle catalyst pipe 264 to the third riser 312 will increase coke in the riser because it bypasses regeneration. Increasing the recycle rate of the second recycle catalyst stream relative to the recycle rate of the second stream of hot catalyst from a second hot catalyst pipe 362 will increase coke concentration in the third riser 312. Some types of catalyst, such as ZSM5, generate little coke in an FCC reactor. If coke generation in the third riser 312 is not sufficient, other ways may be used to increase coke concentration in the third riser which will be described herein after.
The third riser 312 of the third FCC reactor 302 may be located external to the second reactor vessel 210 but share the second reactor vessel with the second riser 212 and the second FCC reactor 202. The third riser 312 comprises a discharge opening 349 in a third disengagement chamber 360. The third disengagement chamber 360 contains the discharge opening 349 of the third riser 312. The third disengagement chamber 360 may be in the second reactor vessel 210. In an embodiment, a horizontal transfer line 348 of the third riser 312 terminates in the third disengagement chamber 360. The discharge opening 349 of the third riser 302 tangentially discharges the third mixture of catalyst and product gas into the third disengagement chamber 360. In other embodiments, the horizontal transfer line 348 may be exchanged for an alternative connector such a T-type connector or an elbow with a more acute or more obtuse angle. Tangential discharge of the third mixture of catalyst and product gas through the discharge opening 349 from the third riser 312 produces a swirling helical pattern about the interior of the third disengagement chamber 360. The disengagement of the third mixture of catalyst and product gas into a second stream of cool catalyst and a third cracked product stream may be conducted outwardly and concentrically of the disengagement of the second mixture of catalyst and product gas into a second cracked product stream and the first stream of cool catalyst. It is important that the second mixture of catalyst and product gas does not mix with the third mixture of catalyst and product gas until the bulk of the catalyst is removed from the product gas to maximize selectivity to propylene.
In an embodiment, the second stream of cool catalyst collects in the dense catalyst bed 228 along with the first stream of cool catalyst. In a further embodiment, the third stream of cracked product passes upwardly through the second gas recovery conduit 226 along with the second stream of cracked product, is further separated from catalyst in cyclones 232 and is discharged from the second reactor vessel 210 through an outlet 230 in the product line 231 as a second product stream.
A mixed stream of disengaged cool catalyst from the dense catalyst bed 228 passes downwardly through a stripping section 284. A stripping fluid, typically steam enters a lower portion of stripping section 284 through a distributor 234. Countercurrent contact of the catalyst with the stripping fluid through a series of stripping baffles, packing or grates displaces product gases from the catalyst as it continues downwardly through the stripping section 284.
A first stream of stripped catalyst from the stripping section 284 passes through a heater conduit 236 to a catalyst heater 238. In one embodiment, the catalyst heater 238 heats the catalyst by heat exchange with regenerated catalyst from the regenerator. In the second embodiment, the catalyst heater 238 contacts the first stream of stripped catalyst with an oxygen supply gas from line 219 to combust coke from the catalyst. Flue gas is discharged in line 242. The second embodiment is applicable when the catalyst generates ample coke in the FCC reaction. The catalyst heater 238 provides the first stream of hot catalyst in the first hot catalyst pipe 220 that is fed to the second riser 212 and the second stream of hot catalyst in the second hot catalyst pipe 362 that is fed to the third riser 312.
A second stream of stripped catalyst from the dense bed 228 passes in a recycle conduit 240 to provide the first stream of recycle catalyst in the first recycle catalyst pipe 222 to the second riser 212 and the second stream of recycle catalyst in the second recycle catalyst pipe 264 to the third riser 312. In the first embodiment of the catalyst heater 238, the catalyst in the second FCC reactor 202 and the third FCC reactor 302 may not coke up as much as in the first FCC reactor 12. Hence, in the second and third FCC reactors 202, 302, insufficient coke may be burned to balance heat demands in the reactors. To supplement heat to the second FCC reactor 202 and the third FCC reactor 302, a portion of the hot regenerated catalyst may be transported to a catalyst heater 238 in a regenerator heater standpipe 42. In the catalyst heater, a portion of the second stream of fluid catalyst may be heat exchanged with a portion of the hot regenerated catalyst before contacting the second stream of fluid catalyst with the second hydrocarbon stream. Moreover, a portion of the third stream of fluid catalyst may be heat exchanged with a portion of the hot regenerated catalyst before contacting the third stream of fluid catalyst with the third hydrocarbon stream. In the catalyst heater 238 of the first embodiment hot regenerated catalyst may be on one side of an indirect heat exchanger while the second stream of fluid catalyst and the third stream of fluid catalyst may be on the other side of the indirect heat exchanger. Catalyst from the second FCC reactor 202 and third FCC reactor 302 may be delivered to the catalyst heater 238 by the heater conduit 236. Cooled regenerated catalyst can be returned to the regenerator 14 from the catalyst heater 238 in a cooled regenerated catalyst conduit 48.
It is envisioned that a heat exchange fluid may also be used in the first embodiment of the catalyst heater 238 to transfer heat to the second and third catalyst streams from the regenerated catalyst instead of by direct heat exchange between catalyst streams. In an embodiment, heat can be exchanged either by direct or indirect means from flue gas from flue gas outlet 47 to heat the second and third catalyst streams. In another embodiment, the catalyst heater 238 may have fuel firing to supply the heat needed. A portion of the second stream of fluid catalyst gets heated in the catalyst heater 238 before contacting said second stream of fluid catalyst with the second hydrocarbon stream. A portion of the third stream of fluid catalyst gets heated in the catalyst heater 238 before contacting said third stream of fluid catalyst with the third hydrocarbon stream. A flue gas stream in line 242 generated out of the catalyst heater 238 may be appropriately routed to the flue gas treatment unit. In another embodiment, the fuel firing in catalyst heater 238 may be replaced by electrical coils powered by renewable or fossil fuel-based electricity.
To generate more coke on catalyst, a C4+ hydrocarbon stream may be fed to the catalyst heater 238 of the first embodiment in a first coking line 221 directly to catalyst in the catalyst heater 238 or one or more of a second coking line 223 to the first stream of hot catalyst in the first hot catalyst pipe 220, a third coking line 225 to the second stream of hot catalyst in the second hot catalyst pipe 362, a fourth coking line 227 to the recycle catalyst in the first recycle catalyst pipe 222, and a fifth coking line 229 to the recycle catalyst in the second recycle catalyst pipe 264. The C4+ injection in the catalyst pipes will help optimize the coke level in the catalyst which maximizes propylene selectivity in second and third risers. C4+ hydrocarbon injections should be located downstream of the control valve in the catalyst pipes. The coke distribution in the catalyst shall be about 0.005 to about 5 wt % coke on catalyst, preferentially about 0.1 to about 2 wt % coke on catalyst in the second riser 212, and about 0.1 to about 1 wt % coke on catalyst in the third riser 312. In an embodiment, the coke on catalyst may be about 0.005 to about 1.2 wt % coke on catalyst in the second riser 212 and in the third riser 312. A hydrocarbon stream may also be fed to the catalyst heater 238 of the second embodiment in the first coking line 221 if necessary to increase the heat of combustion to provide more heat input for the FCC reaction in the second reactor 202 and third reactor 302.
The coked catalyst from stripping section 284 can be dispensed directly and periodically to the catalyst regenerator 14 in a dispense conduit 250. The dispensed catalyst can combine with the catalyst mixture in the catalyst regenerator 14 and provide additional catalyst activity to the catalyst in the FCC unit section 6.
The second product stream in line 231 from the second riser 212 and the third riser 312 may be passed to a wash column 392. In the wash column 392, the second product stream in line 231 is contacted with a wash stream. In an embodiment, the wash stream may be a fresh charge stream in line 394 that is contacted with the hot second product stream to effect a direct heat exchange. The direct heat exchange quenches the hot second product stream and absorbs catalyst fines from the second product stream. The quenched charge stream with catalyst fines is discharged from the bottom of the wash column 392 in line 15 and taken as the first hydrocarbon stream charged to the first FCC reactor 12.
In another embodiment, the second product stream in line 231 may be used for preheating the second hydrocarbon stream 150 and/or third hydrocarbon stream 315 by indirect heat exchange before it is passed to the wash column 392. In another embodiment, the second hydrocarbon stream 150 and/or third hydrocarbon stream 315 may be preheated by the flue gas stream 48 from flue gas outlet 47.
The quenched second product overhead stream is taken from a wash overhead line 396 from a top of the wash column 392 after some stages of cooling pump-arounds to further cool the second product stream in line 396 to the product recovery section 90. The wash column 392 is in downstream communication with the second product outlet 231. In the product recovery section 90, the second product stream in the wash overhead line 396 is directed to a wash column receiver 399. The wash column receiver 399 is in downstream communication with the second product outlet 231.
An aqueous stream is removed from a boot in the wash column receiver 399. Moreover, a condensed light naphtha stream is removed in line 401 while an overhead gas stream is removed in wash receiver overhead line 402. The overhead stream in line 402 contains gaseous light hydrocarbon which are very olefinic. The streams in lines 401 and 402 may enter a wash recovery section 420 of the product recovery section 90. In another embodiment, the wash column 392 may be an integral part of product recovery section 8 by making use of a downstream depropanizer column therein that is not shown and the first debutanizer column 130 in the vapor recovery section 120.
The wash recovery section 420 is shown to be an absorption-based system, but any vapor recovery system may be used including a cold box system. To obtain sufficient separation of light gas components, the overhead stream in line 402 is compressed in compressor 404. More than one compressor stage may be used, but typically a dual stage compression is utilized. A compressed light hydrocarbon stream in line 406 is delivered to a high-pressure receiver 410. Aqueous streams may be taken from the receivers 399 and 410. A high-pressure liquid stream from a bottom of the receiver 410 in line 412 is routed to a depropanizer column 420 with the light naphtha stream in line 401 from a bottom of the wash column receiver 399 in line 414.
The depropanizer column 420 separates the high-pressure liquid stream in line 412 and the light naphtha stream in line 401 into a C3−hydrocarbon stream in line 422 and adds it to the compressed light hydrocarbon stream in line 106 to be processed therein. A depropanized bottom stream in line 424 may be routed to a debutanizer flash drum 426. In the debutanizer flash drum 426 the depropanized bottom stream is separated into a second C4 hydrocarbon stream in an overhead line 432 and a debutanizer naphtha stream in the bottoms line 434. The second C4 hydrocarbon stream may be recycled in line 432 through a control valve thereon to the second recycle stream in line 314.
The debutanizer feed stream in line 434 is fed to a second debutanizer column 440. The second debutanizer column 440 separates the debutanizer feed stream into a C4 product stream in an overhead line 442 and a second light cracked naphtha stream in the bottoms line 444. A second recycle light cracked naphtha stream may be taken in line 446 through a control valve thereon while the remainder may be further processed into gasoline or other products. The second recycle light cracked naphtha stream in line 446 may be fed to the second recycle stream in the second recycle line 314.
One or both of the second recycle light cracked naphtha stream taken from the second debutanizer column 440 in downstream communication with the wash column 392 in line 446 comprising olefinic C5-C7 hydrocarbons and the second recycle C4 stream comprising olefinic C4 hydrocarbons taken from the debutanizer flash drum 426 also in downstream communication with the wash column 392 in line 432 may be recycled to the third FCC reactor 302 as the third hydrocarbon stream in a third charge line 315. The third hydrocarbon stream may be preheated to a temperature of about 204° C. (400° F.) to about 704° C. (1300° F.) and charged to the third FCC reactor 302.
The second hydrocarbon stream and/or the third hydrocarbon stream can be supplemented with C4 hydrocarbon stream, a C5 hydrocarbon stream or a light cracked naphtha stream from a refinery or a steam cracking unit. Such streams will typically comprise more than 20 wt % olefins.
In a further embodiment, some or all of the first C4 hydrocarbon stream in line 149 may be taken in line 160 through a control valve thereon and fed to the second recycle line 314. The first C4 hydrocarbon stream fed to the second recycle line 314 may be taken in the third charge line 315 as the third hydrocarbon stream as all or part of the third hydrocarbon stream.
The third FCC reactor 302 can be used to further crack olefinic feeds to produce additional propylene by cracking a less crackable feed in a third riser 312 at conditions that are more severe than in the second riser 212 and which are uniquely favorable to propylene production for the third hydrocarbon stream.
A hydrocarbon feed was cracked in three separate risers having the compositions in the Table. C4 hydrocarbons from the first riser effluent was charged to the second riser, and consequentially C4 hydrocarbons from the second riser were fed to the third riser. Only propylene was reported in the third riser effluent. Yields are provided in Table 1. Riser conditions are in line with what is taught in the Detailed Description.
By use of three separate risers, over 26 wt % of propylene as a percentage of feed can be produced.
A hydrocarbon feed was cracked in two separate risers having the compositions in the Table. All C5-C7 hydrocarbons from the first riser effluent was fed to the second riser. In case 1, the MFI-type catalyst was fully regenerated in the second riser, so the catalyst contains less than 0.005 wt % coke. In case 2, the catalyst in the second riser contained coke with distribution in the range of 0.005 to 1.2 wt % coke on the MFI-type catalyst. The total product yields of the first and second risers are provided in Table 2. Riser conditions are in line with what is taught in the Detailed Description.
By recycling the C5-C7 hydrocarbons from the first riser to the second riser, more light olefins were produced, such as ethylene, propylene, and butylene. On ZSM-5 catalyst, the propylene selectivity of 40-60% is achieved. Partially coked catalyst enhances the propylene and butylene yields while reducing the dry gas and heavies production.
While the following is described in conjunction with specific embodiments, it will be understood that this description is intended to illustrate and not limit the scope of the preceding description and the appended claims.
A first embodiment of the invention is a process for catalytic production of olefins comprising contacting a first hydrocarbon stream and a first stream of fluid catalyst in a first riser to produce a first cracked product stream and a spent catalyst stream; separating the first cracked product stream in a main column; separating an overhead stream from the main column into a second hydrocarbon stream; contacting the second hydrocarbon stream with a second stream of fluid catalyst in a second riser to produce a second cracked product stream and a first stream of cool catalyst; and obtaining a third hydrocarbon stream from the overhead stream and/or from the second cracked product stream; and contacting the third hydrocarbon stream with a third stream of fluid catalyst in a third riser to produce a third cracked product stream and a second stream of cool catalyst. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the second hydrocarbon stream is more olefinic and/or more crackable than the third hydrocarbon stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the second hydrocarbon stream is a light cracked naphtha stream and further comprising separating the overhead stream from the main column into a first C4 hydrocarbon stream and taking the first C4 hydrocarbon stream as the third hydrocarbon stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising washing the second cracked product stream in a wash column and obtaining the third hydrocarbon stream from the wash column. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the second hydrocarbon stream is a first C4 hydrocarbon stream and the third hydrocarbon stream is a second C4 hydrocarbon stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising compressing an overhead stream from the wash column to provide a compressed overhead stream and depropanizing the compressed overhead stream to provide a depropanized compressed overhead stream and taking the third hydrocarbon stream from the depropanized compressed overhead stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating a depropanized compressed overhead stream into a second C4 stream and a second light cracked naphtha stream and taking the third hydrocarbon stream from the second light cracked naphtha stream and/or from the second C4 stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the second stream of fluid catalyst and the third stream of fluid catalyst comprise about 0.005 to about 1.2 wt % coke. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the third riser operates at a higher outlet temperature and/or a lower hydrocarbon partial pressure and/or a different catalyst density than the second riser. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising regenerating the stream of spent catalyst by combustion of coke from the spent catalyst to provide hot regenerated catalyst and heat exchanging a portion of the second stream of fluid catalyst with a portion of the hot regenerated catalyst before contacting the second stream of fluid catalyst with the second hydrocarbon stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising regenerating the stream of spent catalyst by combustion of coke from the spent catalyst to provide hot regenerated catalyst and heat exchanging a portion of the third stream of fluid catalyst with a portion of the hot regenerated catalyst stream before contacting the third stream of fluid catalyst with the third hydrocarbon stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the third hydrocarbon stream has more than 20 wt % olefins. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising recycling a C4+ stream to a catalyst pipe that provides catalyst to the second riser and/or to the third riser.
A second embodiment of the invention is a process for catalytic production of olefins comprising contacting a first hydrocarbon stream and a first stream of fluid catalyst in a first riser to produce a first cracked product stream and a spent catalyst stream; separating the first cracked product stream in a main column; obtaining a second hydrocarbon stream from the main column; contacting the second hydrocarbon stream with a second stream of fluid catalyst in a second riser to produce a second cracked product stream and a first stream of cool catalyst; and separating the second cracked product stream in a wash column and obtaining the third hydrocarbon stream from the wash column; and contacting the third hydrocarbon stream with a third stream of fluid catalyst in a third riser to produce a third cracked product stream and a second stream of cool catalyst. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising compressing an overhead stream from the wash column to provide a compressed overhead stream and depropanizing the compressed overhead stream to provide a depropanized compressed overhead stream and taking the third hydrocarbon stream from the depropanized compressed overhead stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph wherein the third hydrocarbon stream has more than 20 wt % olefins.
A third embodiment of the invention is a process for catalytic production of olefins comprising contacting a first hydrocarbon stream and a first stream of fluid catalyst in a first riser to produce a first cracked product stream and a spent catalyst stream; separating the first cracked product stream in a main column; obtaining a second hydrocarbon stream from an overhead line of the main column system; contacting the second hydrocarbon stream with a second stream of fluid catalyst in a second riser to produce a second cracked product stream and a first stream of cool catalyst; and obtaining a third hydrocarbon stream from the first cracked product stream or the second cracked product stream; and contacting the third hydrocarbon stream with a third stream of fluid catalyst in a third riser to produce a third cracked product stream and a second stream of cool catalyst. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph wherein the second hydrocarbon stream is more olefinic and/or more crackable than the third hydrocarbon stream. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph wherein the third hydrocarbon stream has more than 20 wt % olefins. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph further comprising operating the third riser at a greater severity than the second riser.
Without further elaboration, it is believed that using the preceding description that one skilled in the art can utilize the present invention to its fullest extent and easily ascertain the essential characteristics of this invention, without departing from the spirit and scope thereof, to make various changes and modifications of the invention and to adapt it to various usages and conditions. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limiting the remainder of the disclosure in any way whatsoever, and that it is intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.
In the foregoing, all temperatures are set forth in degrees Celsius and, all parts and percentages are by weight, unless otherwise indicated.
| Number | Date | Country | |
|---|---|---|---|
| 63391756 | Jul 2022 | US |
