Patent Application
20150136647
1. Field
Embodiments described herein generally relate to systems and method for fluidized catalytic cracking. More particularly, such embodiments relate to systems and methods for fluidized catalytic cracking using dual risers for diesel production.
2. Description of the Related Art
Fluid Catalytic Cracking (FCC) is a technology used in refineries to produce transportation fuels such as gasoline and distillates and other liquid and/or gaseous hydrocarbon products from higher molecular weight feedstocks. The FCC process uses a reactor called a riser, which is essentially a pipe where a hydrocarbon is contacted with fluidized catalyst particles to convert the hydrocarbon feed to more valuable products. The resulting hydrocarbon product and catalyst mixture both flow through the riser where larger hydrocarbon molecules are “cracked” into smaller molecules, hence the term fluid catalytic cracking.
Typical FCC units have a single riser, with its feed injected at the base of the riser. To achieve desired products, FCC operators adjust catalytic parameters, temperatures, steam, and pressures to adjust product yields for a given hydrocarbon feed. Single riser FCC units are configured to produce gasoline and/or light olefins, with minor amounts of Light Cycle Oil (LCO) or diesel range boiling material. Recent economic factors have increased demand for diesel boiling range products. Single riser FCC units, however, are not optimal for maximizing diesel yields because this operating mode results in a low conversion of the feed per pass with high bottoms (slurry) yields.
There is a need, therefore, for improved systems and methods for producing diesel.
A method for producing diesel is disclosed. The method can include cracking a first hydrocarbon feed in a first riser under first cracking conditions to provide a first effluent containing a first light cycle oil, a heavy cycle oil, and a first bottoms and fractionating at least a portion of the first effluent to separate the first bottoms and the heavy cycle oil from the first light cycle oil. The method can include cracking the separated first bottoms in a second riser under second cracking conditions to produce a second effluent containing a second light cycle oil and a second bottoms. The method can also include cracking the separated heavy cycle oil in the first riser under third cracking conditions to provide a third effluent and mixing the third effluent with the first hydrocarbon feed to provide the first cracking conditions.
Another method for producing diesel is also disclosed. The method can include cracking a first hydrocarbon feed in a first riser under first cracking conditions to provide a first effluent containing a first light cycle oil, a heavy cycle oil, and a slurry oil, fractionating at least a portion of the first effluent to separate the slurry oil and the heavy cycle oil from the first light cycle oil, and stripping the slurry oil to provide a first bottoms. The method can include cracking the first bottoms in a second riser under second cracking conditions to produce a second effluent containing a second light cycle oil and a second bottoms and fractionating at least a portion of the second effluent to separate the second bottoms from the second light cycle oil. The method can also include cracking the separated heavy cycle oil in the first riser under third cracking conditions to provide a third effluent, mixing the third effluent with the first hydrocarbon feed to provide the first cracking conditions, and mixing the first light cycle oil with the second light cycle oil to provide a light cycle oil product.
An additional method for producing diesel is also disclosed. The method can include cracking a first hydrocarbon feed in a first riser under first cracking conditions including temperatures from about 450° C. to about 530° C. to provide a first effluent containing a first light cycle oil, a heavy cycle oil, and a slurry oil, fractionating at least a portion of the first effluent to separate the slurry oil and the heavy cycle oil from the first light cycle oil, and stripping the slurry oil to provide a first bottoms. The method can include cracking the first bottoms in a second riser under second cracking conditions including temperatures from about 450° C. to about 650° C. to produce a second effluent containing a second light cycle oil and a second bottoms and fractionating at least a portion of the second effluent to separate the second bottoms from the second light cycle oil. The method can also include cracking the heavy cycle oil in the first riser under third cracking conditions including temperatures from about 500° C. to about 650° C. to provide a third effluent, mixing the third effluent with the first hydrocarbon feed to provide the first cracking conditions, and mixing the first light cycle oil with the second light cycle oil to provide a light cycle oil product. The method can also include separating the first effluent to produce a first spent-catalyst and a first gaseous product, separating the second effluent to produce a second spent-catalyst and a second gaseous product, and combining the first spent-catalyst and the second spent-catalyst to provide a mixed spent-catalyst. The method can further include regenerating the mixed spent-catalyst by combusting coke in a regenerator to produce regenerated catalyst and recycling the regenerated catalyst to the first and second risers.
A system fix producing diesel is also disclosed. The system can include a first riser having a first reaction zone and a second reaction zone, wherein the second reaction zone is adapted to crack a first hydrocarbon feed under first cracking conditions to provide a first effluent containing a first light cycle oil, a heavy cycle oil, and a slurry oil. The system can include a fractionator in fluid communication with the first riser, the fractionator adapted to fractionate at least a portion of the first effluent to separate the heavy cycle oil and the bottoms from the first light cycle oil. The system can also include a stripper in fluid communication with the fractionator, the stripper adapted to separate a first bottoms from the slurry oil. The system can also include a second riser for cracking the separated first bottoms under second cracking conditions to produce a second effluent containing a second light cycle oil and a second bottoms. The system can also include a mixing zone located in the first riser for mixing a third effluent with the first hydrocarbon feed to provide the first cracking conditions, wherein the first reaction zone of the first riser is adapted to crack the separated heavy cycle oil to provide the third effluent.
A first hydrocarbon or first feed via line 120 can be introduced to the first riser 102 where it is mixed with one or more catalysts via line 122. The first hydrocarbon entering the riser 102 via line 120 can be introduced anywhere along the length of the riser 102. For example, the first hydrocarbon via line 120 can be introduced to the uppermost or top half of the first riser 102. The first hydrocarbon via line 120 can also be introduced to the top third of the height of the first riser 102. The first hydrocarbon via line 120 can also be introduced to the top quarter of the height of the first riser 102. The first hydrocarbon via line 120 can also be introduced to the first riser 102 within the top 40%, the top 30%, the top 20%, the top 10%, or the top 5% of the total height of the first riser. Although not shown, the first hydrocarbon feed via line 120 can be introduced to the riser 102 at any location along the bottom half of the riser 102. For example, the first hydrocarbon via line 120 can be introduced to the base of the riser 102.
The hydrocarbon in line 120 can be or include any hydrocarbon or combination of hydrocarbons, such as gas oils, vacuum gas oils, a hydrotreated vacuum gas oils, reduced crudes, atmospheric tower bottoms, vacuum tower bottoms, or any mixture thereof. The hydrocarbon in line 120 can be or include any hydrocarbon or combination of hydrocarbons having eight or more carbon atoms (C8+ hydrocarbons). As such, the hydrocarbon in line 120 can also be referred to as a “C8+ hydrocarbon” or a “C8+ hydrocarbon containing feed.” The hydrocarbon in line 120 can be or include any paraffinic or other hydrocarbon having four or more carbon atoms. Illustrative hydrocarbon compounds that can be present in the hydrocarbon in line 120 can include, but are not limited to, paraffinic, cycloparaffinic, monoolefinic, diolefinic, cycloolefinic, naphthenic, aromatic hydrocarbons, hydrocarbon oxygenates, or any mixture or combination thereof. Hydrocarbons that can be present in line 120 in addition to the C8+ hydrocarbon(s) can include, but are not limited to, light paraffinic naphtha (naphtha limited to hydrocarbon molecules having less than 12 carbon atoms and at least 80 wt % paraffins, no more than 10 wt % aromatics, and no more than 40 wt % cycloparaffins), heavy paraffinic naphtha (naphtha having hydrocarbon molecules with at least 12 carbon atoms and at least 80 wt % paraffins, no more than 10 wt %® aromatics, and no more than 40 wt % cycloparaffins), light olefinic naphtha (naphtha limited to hydrocarbon molecules having less than 12 carbon atoms and at least 20 wt % olefins), heavy olefinic naphtha (naphtha having hydrocarbon molecules with at least 12 carbon atoms and at least 20 wt % olefins), non-aromatic fractions from an aromatics extraction unit; oxygenate-containing products from a Fischer-Tropsch unit; or the like; or any mixture or combination thereof. In addition to the C8+ hydrocarbon(s), the hydrocarbon in line 120 can also include one or more oxygenates, one or more ethers, or any mixture or combination thereof.
The hydrocarbon in line 120 can have a concentration of C8+ hydrocarbons from a low of about 15 wt %, about 20 wt %, about 25 wt %, about 35 wt %, or about 45 wt % to a high of about 85 wt %, about 90 wt %, about 95 wt %, about 99 wt %, or about 99.99 wt %. For example, the feed in line 120 can have a C8+ hydrocarbon concentration from about 25 wt % to 100 wt %, about 45 wt % to about 99 wt %, or about 55 wt %© to about 95 wt %. In an example, the hydrocarbon in line 120 can contain less than 25 wt %, less than 20 wt %, less than 15 wt %, less than 10 wt %, less than 5 wt %, less than 3 wt %©, or less than 1 wt % hydrocarbon compounds having less than 8 carbon atoms.
The hydrocarbon in line 120 can have a 10 percent point of at least about 100° C. and a 90 percent point below about 750° C. as determined by distillation in accordance with the standard method of ASTM-D1160. The hydrocarbon in line 120 can also have a 10 percent point of at least about 250° C. and a 90 percent point below about 650° C. as determined by distillation in accordance with the standard method of ASTM-D1160. The hydrocarbon in line 120 can also have a 10 percent point of at least about 330° C. and a 90 percent point below about 585° C. as determined by distillation in accordance with the standard method of ASTM-D1160.
The hydrocarbon in line 120 can have a C8-C60 hydrocarbons concentration from about 10 wt %, about 20 wt %, about 25 wt %, about 30 wt %, about 35, about 40 wt %, or about 45 wt % to about 55 wt %, about 65 wt %, about 75 wt %, about 85 wt %, about 90 wt %, about 95 wt %, about 99 wt %, or about 100 wt %. For example, the hydrocarbon in line 120 can have a C8-C60 hydrocarbons concentration of about 15 wt % to about 95 wt %, about 28 wt % to about 88 wt %, about 42 wt % to about 80 wt %, or about 50 wt % to about 60 wt %. The hydrocarbon in line 120 can have a C8-C50 hydrocarbons concentration from about 25 wt %, about 30 wt %, about 35, about 40 wt %, about 45 wt %, or about 55 wt % to about 65 wt %, about 75 wt %, about 85 wt %, about 90 wt %, or about 95 wt %. For example, the hydrocarbon in line 120 can have a C8-C40 hydrocarbons concentration of about 32 wt % to about 94 wt %, about 38 wt % to about 88 wt %, about 48 wt % to about 80 wt %, or about 50 wt % to about 70 wt %. The hydrocarbon in line 120 can have a C8+ hydrocarbons concentration from about 30 wt %, about 45 wt %, about 55 wt %, about 65 wt %, about 75 wt %, or about 85 wt % to about 90 wt %, about 95 wt %, about 99 wt %, or about 100 wt %. For example, the hydrocarbon in line 120 can have a C8+ hydrocarbons concentration of about 35 wt % to about 100 wt %, about 55 wt % to about 99.99 wt %, about 70 wt % to about 99 wt %, about 80 wt % to about 99 wt %, about 90 wt % to about 100 wt %, or about 95 wt % to about 100 wt %. The hydrocarbon in line 120 can have a C12+ hydrocarbons concentration from about 25 wt %, about 40 wt %, about 50 wt %, about 60 wt %, about 70 wt %, or about 75 wt % to about 80 wt %, about 90, about 95 wt %, about 99 wt %, or about 100 wt %. For example, the hydrocarbon in line 120 can have a C12+ hydrocarbons concentration of about 30 wt % to about 100 wt %, about 50 wt % to about 99.99 wt %, about 70 wt % to about 99 wt %, about 80 wt % to about 99 wt %, about 90 wt % to about 100 wt %, or about 95 wt % to about 100 wt %. The hydrocarbon in line 120 can have a C15+ hydrocarbons concentration from about 20 wt %, about 35 wt %, about 40 wt %, about 50 wt %, about 60 wt %, or about 70 wt % to about 80 wt %, about 90, about 95 wt %, about 99 wt %, or about 100 wt %. For example, the hydrocarbon in line 120 can have a C15+ hydrocarbons concentration of about 25 wt % to about 100 wt %, about 40 wt % to about 99.99 wt %, about 60 wt % to about 99 wt %, about 75 wt % to about 99 wt %, about 85 wt % to about 100 wt %, about 90 wt % to about 100 wt %, or about 95 wt % to about 100 wt %.
The hydrocarbon introduced via line 120 to the first riser 102 can include one or more olefins in an amount from a low of about 0 wt %, about 0.1 wt %, or about 2 wt % to a high of about 4 wt %, about 8 wt %, or about 10 wt %. For example, the hydrocarbon in line 120 can have an olefins concentration from about 0.01 wt % to about 10 wt %, about 1 wt % to about 7 wt %, or about 2 wt % to about 5 wt %. The hydrocarbon in line 120 can have a sulfur concentration from about 0.01 wt %, about 0.05 wt %, about 0.1 wt %, about 0.2 wt %, or about 0.5 wt % to about 0.6 wt %, about 0.8 wt %, about 1.2 wt % about 1.5 wt %, about 2.5 wt %, or about 5 wt %. The hydrocarbon in line 120 can have a nitrogen concentration of about 100 ppmw, about 250 ppmw, about 500 ppmw, about 750 ppmw, or 1,000 ppmw to about 1,250 ppmw, about 1,500 ppmw, about 2,000 ppmw, about 5,000 ppmw, or about 10,000 ppmw. The hydrocarbon in line 120 can have a nickel concentration of about 0.01 ppmw, about 0.05 ppmw, about 0.1 ppmw, about 0.2 ppmw, or about 0.4 ppmw to about 0.5 ppmw, about 1 ppmw, about 5 ppmw, about 10 ppmw, or about 25 ppmw. The hydrocarbon in line 120 can have a vanadium concentration of about 0.01 ppmw, about 0.05 ppmw, about 0.1 ppmw, about 0.2 ppmw, or about 0.5 ppmw to about 0.7 ppmw, about 1 ppmw, about 5 ppmw, about 10 ppmw, or about 25 ppmw.
The hydrocarbon in line 120 can be a byproduct or downstream product from the production of syngas. For example, the hydrocarbon in line 120 can have concentrations of sulfur or other impurities. The hydrocarbon in line 120 can have a concentration of sulfur and/or one or more sulfur compounds of less than about 1 wt %, less than about 500 ppmw, less than about 100 ppmw, less than about 10 ppmw, or less than about 1 ppmw. The hydrocarbon in line 120 can have a concentration of sulfur and/or one or more sulfur compounds of less than about 1,000 parts per million by weight (ppmw), less than about 500 ppmw, less than about 100 ppmw, less than about 10 ppmw, or less than about 1 ppmw. In some embodiments, the hydrocarbon in line 120 can be sulfur-free or substantially free of sulfur. As used herein, the term “substantially free of sulfur” means the hydrocarbon in line 120 contain less than about 1 ppmw sulfur.
The hydrocarbon in line 120 can be cracked in the first riser 102 under first cracking conditions to produce a first riser effluent containing spent catalyst and a first cracked product. The first cracked product can exit the FCC system 100 via line 140. The first cracked product can be or include fuel gas, liquefied petroleum gas (LPG), gasoline, light cycle oil (LCO), heavy cycle oil (HCO), bottoms (slurry oil) or any combination thereof. The first cracked product via line 140 can have a gasoline concentration of about 1 wt %, about 5 wt %, about 10 wt %, about 20 wt %, about 30 wt %, or about 35 wt % to about 40 wt %, about 50 wt %, about 55 wt %, about 60 wt %, or about 70 wt %, based on the total weight of the first cracked product. The first cracked product via line 140 can have a light cycle oil concentration of about 5 wt %, about 10 wt %, about 15 wt %, about 25 wt %, about 30 wt %, or about 35 wt % to about 40 wt %, about 50 wt %, about 55 wt %, about 60 wt %, or about 70 wt %, based on the total weight of the first cracked product. The first cracked product via line 140 can have a heavy cycle oil concentration of about 1 wt %, about 5 wt %, about 8 wt %, about 15 wt %, or about 20 wt % to about 25 wt %, about 30 wt %, about 35 wt %, or about 40 wt %, based on the total weight of the first cracked product. The first cracked product recovered via line 140 can have a liquefied petroleum gas (LPG) concentration of about 0.1 wt %, about 0.5 wt %, about 1 wt %, about 5 wt %, about 10 wt %, about 15 wt %, or about 20 wt % to about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, or about 50 wt %, based on the total weight of the first cracked product. As used herein, the term “liquefied petroleum gas” or “LPG” refers to propane, propylene, butanes, or butylenes, or any mixture thereof. As used herein, the term “fuel gas” refers to hydrogen, methane, ethane, ethylene, or hydrogen sulfide, or any mixture thereof.
A second hydrocarbon or second feed via line 124 can be introduced to the second riser 104 where it is mixed with one or more catalysts via line 126. The second hydrocarbon entering the riser 104 via line 124 can be introduced anywhere along the length of the riser 104. For example, the second hydrocarbon via line 124 can be introduced to the lowermost or lower half of the second riser 104. The second hydrocarbon via line 124 can also be introduced to the bottom third of the height of the second riser 104. The second hydrocarbon via line 124 can also be introduced to the bottom or base of the second riser 104.
The second hydrocarbon in line 124 can be or include any hydrocarbon or combination of hydrocarbons, such as slurry oil, heavy cycle oil, gas oils, vacuum gas oils, a hydrotreated vacuum gas oils, reduced crudes, atmospheric tower bottoms, vacuum tower bottoms, or any mixture thereof. The second hydrocarbon in line 124 can be or include any hydrocarbon or combination of hydrocarbons having 12 or more carbon atoms (C12+ hydrocarbons). As such, the second hydrocarbon feed can also be referred to as a “C12+ feed” or a “C12+ hydrocarbon containing feed.” The second hydrocarbon can be or include any paraffinic or olefinic hydrocarbon having 12 or more carbon atoms. Illustrative hydrocarbon compounds that can be present in the second feed can include, but are not limited to, paraffinic, cycloparaffinic, monoolefinic, diolefinic, cycloolefinic, naphthenic, aromatic hydrocarbons, hydrocarbon oxygenates, or any mixture or combination thereof.
The second hydrocarbon feed via line 124 can include a mixture of C18 to C30 hydrocarbons. For example, the second hydrocarbon feed via line 124 can be slurry oil. The second hydrocarbon feed via line 124, or second bottoms feed, can have a boiling point in the range of about 260° C. to about 560+° C. in accordance with ASTM D-1160. The second hydrocarbon feed via line 124 can have a boiling point in the range of about 360° C. to about 560° C. in accordance with ASTM D-1160. The second hydrocarbon feed via line 124 can be obtained from a separator or fractionator disposed downstream of and in fluid communication with the FCC system 100. For example, the second hydrocarbon feed via line 124 can be obtained from a fractionator disposed downstream of the first riser 102. The second hydrocarbon feed via line 124 can also be obtained from as a bottoms stream from a fractionator disposed downstream of the first riser 102. The second hydrocarbon feed via line 124 can also be separated from the first cracked product. For example, the second hydrocarbon feed via line 124 can be a slurry oil separated from the first cracked product.
The second hydrocarbon feed via line 124 can be cracked within the second riser 104 in the presence of the catalyst via line 126 under second cracking conditions, conditions sufficient to form a second cracked product and spent catalyst mixture or “second riser effluent.” The second cracked product can be or include fuel gas, LPG, gasoline, LCO, HCO, slurry oil, or any combination thereof. The second cracked product via line 142 can have a gasoline concentration of about 8 wt %, about 13 wt %, about 18 wt %, about 25 wt %, or about 35 wt % to about 42 wt %, about 48 wt %, about 55 wt %, about 60 wt %, or about 65 wt %, based on the total weight of the second cracked product. The second cracked product via line 142 can have a light cycle oil concentration of about 10 wt %, about 15 wt %, about 20 wt %, about 25 wt %, or about 30 wt % to about 38 wt %, about 44 wt %, about 50 wt %, about 55 wt %, or about 60 wt %, based on the total weight of the second cracked product. The second cracked product via line 142 can have a heavy cycle oil concentration or about 0.1 wt %, about 0.5 wt %, about 1 wt %, about 2 wt %, or about 4 wt % to about 6 wt %, about 8 wt %, about 10 wt %, about 14 wt %, or about 20 wt %, based on the total weight of the second cracked product. The second cracked product recovered via line 142 can have a LPG concentration of about 4 wt %, about 8 wt %, about 12 wt %, about 16 wt %, about 20 wt %, or about 25 wt % to about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, about 50 wt %, or about 55 wt %, based on the total weight of the second cracked product. In an example, cracking the second hydrocarbon feed via line 124 in a second riser 104 under second cracking conditions to produce a second effluent containing a second LPG, a second gasoline, a second light cycle oil, and a second slurry oil.
A third hydrocarbon or third feed via line 132 can be introduced to the first riser 102 where it is mixed with the one or more catalysts via line 122. The third hydrocarbon entering the riser 102 via line 132 can be introduced anywhere along the length of the riser 102. For example, the third hydrocarbon via line 132 can be introduced to the lowermost or lower half of the first riser 102. The third hydrocarbon via line 132 can also be introduced to the bottom third of the height of the first riser 102. The third hydrocarbon via line 132 can be introduced to the first riser 102 at any location on the first riser 102 upstream of where the first hydrocarbon via line 120 is introduced to the first riser 102. For example, the third hydrocarbon via line 132 can be introduced to the first riser 102 at a location between where the first hydrocarbon via line 120 and the catalyst via line 122 are introduced. The third hydrocarbon via line 132 can also be introduced to the bottom or base of the first riser 102.
The third hydrocarbon in line 132 can be or include any hydrocarbon or combination of hydrocarbons, such as slurry oil, heavy cycle oil, gas oils, vacuum gas oils, a hydrotreated vacuum gas oils, reduced crudes, atmospheric tower bottoms, vacuum tower bottoms, or any mixture thereof. The third hydrocarbon in line 132 can be or include any hydrocarbon or combination of hydrocarbons having 12 or more carbon atoms (C12+ hydrocarbons). As such, the third hydrocarbon feed can also be referred to as a “C12+ feed” or a “C12+ hydrocarbon containing feed.” The third hydrocarbon can be or include any paraffinic or olefinic hydrocarbon having 12 or more carbon atoms. Illustrative hydrocarbon compounds that can be present in the third feed can include, but are not limited to, paraffinic, cycloparaffinic, monoolefinic, diolefinic, cycloolefinic, naphthenic, aromatic hydrocarbons, hydrocarbon oxygenates, or any mixture or combination thereof.
The third hydrocarbon feed via line 132 can include a mixture of C18 to C30 hydrocarbons. For example, the third hydrocarbon feed via line 132 can be heavy cycle oil (HCO). The third hydrocarbon feed via line 132, or HCO feed, can have a boiling point in the range of about 260° C. to about 500° C. in accordance with ASTM D-1160. The third hydrocarbon feed via line 132 can have a boiling point in the range of about 360° C. to about 500° C. in accordance with ASTM D-1160. The third hydrocarbon feed via line 132 can be obtained from a separator or fractionator disposed downstream of and in fluid communication with the FCC system 100. For example, the third hydrocarbon feed via line 132 can be obtained from a fractionator disposed downstream of the first riser 102. The third hydrocarbon feed via line 132 can also be obtained from a stripping column disposed downstream of the first riser 102. For example, the third hydrocarbon feed via line 132 can be separated from the first cracked product. The third hydrocarbon feed via line 132 can also be a HCO separated from the first cracked product. The third hydrocarbon via line 132, or HCO feed, can have a composition that is the same or different from that of the second hydrocarbon via line 124, or bottoms feed.
The third hydrocarbon feed via line 132 can be cracked within the first riser 102 in the presence of the catalyst under third cracking conditions, conditions sufficient to form a third cracked product and spent catalyst mixture or “third riser effluent” contained within the first riser 102. The third cracked product can be contained at a location in the first riser 102 at or upstream of where the first hydrocarbon via line 120 is introduced to the first riser 102. The third product can be or include fuel gas, LPG, gasoline, LCO, HCO, bottoms or any combination thereof. The third cracked product in the first riser 102 can have a gasoline concentration of about 8 wt %, about 13 wt %, about 18 wt %, about 25 wt %, or about 35 wt % to about 42 wt %, about 48 wt %, about 55 wt %, about 60 wt %, or about 65 wt %, based on the total weight of the third cracked product. The third cracked product in the first riser 102 can have a light cycle oil concentration of about 10 wt %, about 15 wt %, about 20 wt %, about 25 wt %, or about 30 wt % to about 38 wt %, about 44 wt %, about 50 wt %, about 55 wt %, or about 60 wt %, based on the total weight of the third cracked product. The third cracked product in the first riser 102 can have a heavy cycle oil concentration of about 0.1 wt %, about 0.5 wt %, about 1 wt %, about 2 wt %, or about 4 wt % to about 6 wt %, about 8 wt %, about 10 wt %, about 14 wt %, or about 20 wt %, based on the total weight of the third cracked product. The third cracked product in the first riser 102 can have a LPG concentration of about 4 wt %, about 8 wt %, about 12 wt %, about 16 wt %, about 20 wt %, or about 25 wt % to about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, about 50 wt %, or about 55 wt %, based on the total weight of the third cracked product.
At least 10 wt %, at least 20 wt %, at least 30 wt %, at least 40 wt %, or at least 50 wt % of the feed in line 120 can be converted to LCO. For example, a low of about 12 wt %, about 15 wt %, or about 25 wt % to a high of about 35 wt %, about 50 wt %, or about 70 wt % of the feed in line 120 can be converted to LCO. The first cracked product recovered via line 140 and the second cracked product recovered via line 142 can have a combined LCO yield of at least 15 wt %, at least 35 wt %, at least 50 wt %, or at least 65 wt %.
The catalyst in lines 122, 126 can be the same or different and can be regenerated catalyst withdrawn from the catalyst regenerator 116. The catalyst in lines 122, 126 can be or include any catalyst suitable for the conversion of hydrocarbons to LCO. The catalyst in lines 122, 126 can be one that favors the production of LCO within the first riser 102, the second riser 104, or both from the hydrocarbons introduced thereto. For the cracking of hydrocarbons, one or more zeolite catalysts, e.g., crystalline zeolite molecular sieves, morphologically modified zeolite molecular sieves, containing both silica and alumina, can be used for the fluidized catalytic cracking. The zeolite catalyst can also be used with one or more modifiers such as phosphorous. The zeolite catalyst can also be used in conjunction with other known catalysts useful in fluidized catalytic cracking. Illustrative catalysts can include, but are not limited to, ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, ZSM-57, X-type zeolites (zeolite X), Y-type zeolites (zeolite Y), USY, REY, RE-USY, MCM-9, MCM-22, MCM-41, silicoaluminophosphate (SAPO) molecular sieves, faujasite, mordenite, and other synthetic and naturally occurring zeolites and mixtures thereof.
The catalyst in lines 122, 126 can include at least one catalytic component. The catalytic component can include a zeolite, an amorphous material, and/or a porous matrix. For example, the catalytic component can be, but is not limited to, ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, or any combination thereof. In an example, the catalytic component can be ZSM-5. In another example, the catalytic component can include, but is not limited to, zeolite X, zeolite Y, USY, REY, RE-USY, MCM-9, MCM-22, MCM-41, SAPO-5, SAPO-37, SAPO-40, naturally occurring zeolites such as faujasite, mordenite, and the like, or any combination thereof. In a further example, the catalytic component can include boehmite, pseudoboehmite alumina, peptized pseudoboehmite alumina (PSA), alumina-containing gels, hydrotalcites, bauxite, and the like, or any combination thereof. In an even further example, the catalytic component can include one or more bottoms cracking additives such as BCMT™-500, BCMT™-500 LRT, BCMT™-DC, and BCMT™-MD, all commercially available from Albermarle Corporation, and BCA-105®, commercially available from the InterCat division of Johnson Mathey Corporation.
The catalytic component can be supported on, in, or otherwise about a support material, matrix, or binder. Illustrative support materials can include, but are not limited to, alumina, silica gel, and/or naturally occurring clays. The support material can be catalytically active or inactive. In one or more embodiments, the active support material, or active matrix, can include boehmite, pseudoboehmite alumina, peptized pseudoboehmite alumina (PSA), or alumina-containing gels.
The FCC system 100 can also include one or more first ducts or transfer lines 106 and one or more first catalyst separation or disengagement zones 110. The first riser 102 can be fluidly coupled to or connected to the first transfer line 106. The first transfer line 106 can also be fluidly coupled to or connected to the first catalyst disengagement zone 110. The first catalyst disengagement zone 110 can include one or more cyclone separators fluidly coupled to a plenum 144 disposed within the FCC system 100. The plenum 144 can be fluidly coupled to or connected to line 140 for withdrawing the first cracked product from the FCC system 100. A first fluid-tight seal (not shown) can be formed between the first catalyst disengagement zone 110 and the plenum 144. A second fluid-tight seal (not shown) can be formed between the plenum 144 and line 140.
The FCC system 100 can further include one or more second ducts or transfer lines 108 and one or more second catalyst separation or disengagement zones 112. The second riser 104 can be fluidly coupled to or connected to the second transfer line 108. The second transfer line 108 can also be fluidly coupled to or connected to the second catalyst disengagement zone 112. The second catalyst disengagement zone 112 can include one or more cyclone separators fluidly coupled to or connected to line 142 tor withdrawing the second cracked product from the FCC system 100. A third fluid-tight seal (not shown) can be formed between the second catalyst disengagement zone 112 and line 142. The first disengagement zone 110 can be fluidly isolated from the second disengagement zone 112. In an example, the first disengagement zone 110, the second disengagement zone 112, or both can prevent the first effluent, the first cracked product, or both from mixing or otherwise combining with the second effluent, the second cracked product, or both. In an example, either the first disengagement zone 110 or the second disengagement zone 112, but not both, is in fluid communication with the stripper 114 for withdrawing the steam and hydrocarbon vapors from the FCC system 100. In another example (not shown), the first disengagement zone 110 and the second disengagement zone 112 can be in fluid communication with each other, allowing the first effluent, the first cracked product, or both to mix or otherwise combine with the second effluent, the second cracked product, or both. In the same example, either the first disengagement zone 110 or the second disengagement zone 112, or both, are in fluid communication with the stripper 114 for withdrawing the steam and hydrocarbon vapors from the FCC system 100.
The first effluent from the first riser 102 can be introduced to the transfer line 106 and the second effluent from the second riser 104 can be introduced to the transfer line 108. The first riser effluent can flow, via first transfer line 106, from the first riser 102 to the first catalyst disengagement zone 110, where spent-catalyst particulates and/or other particulates can be separated from gaseous hydrocarbons, steam, and inerts of the first cracked product. Likewise, the second riser effluent can flow, via second transfer line 108, from the second riser 104 to the second catalyst disengagement zone 112, where spent-catalyst particulates and/or other particulates can be separated from gaseous hydrocarbons, steam, and inerts of the second cracked product. The first and second disengagement zones 110, 112 can each have a larger cross-sectional area than their respective risers 102, 104 and/or transfer lines 106, 108, which reduces the velocity of the cracked product mixtures, allowing the heavier spent-catalyst particulates and/or other particulates to separate from the gaseous hydrocarbons, steam, and inerts. In one or more embodiments, a steam purge (not shown) can be added to the first and second disengagement zones 110, 112 to assist in separating the gaseous hydrocarbons from the spent-catalyst particulates, i.e., stripping the gaseous hydrocarbons from the solids. In other words, the first and second disengagement zones 110, 112 can be self-stripping separators, e.g., self-stripping cyclones. An additional steam purge can be provided at the base of the stripper 114 to assist in separating the gaseous hydrocarbons from the spent-catalyst particulates, i.e., stripping the gaseous hydrocarbons from the solids.
The FCC system 100 can include a catalyst stripper 114 and a catalyst regenerator 116. The stripper 114 can be located at any location within the FCC system 100. For example, the catalyst system can be disposed below the first and second catalyst disengagement zones 110, 112. The regenerator 116 can also be located at any location within the FCC system 100. For example, the regenerator 116 can be located below the stripper 114, disposed about or around the stripper 114, or both.
Separated solids, i.e., spent catalyst particulates, can free fall through the first and second disengagement zones 110, 112 to mix and be introduced to a stripper 114 disposed within the FCC system 100 at a location below the first and second disengagement zones 110, 112. The falling stripped catalyst particles, or coked-catalyst particles, can then be introduced to the regenerator 116 where coke can be burned from the catalyst. Regenerated catalyst particles can be withdrawn from the catalyst regenerator via lines 122, 126 for delivery to the first and second risers 102, 104, respectively.
A third side draw via line 230, a third bottoms via line 234, and a second overhead via line 212 can be withdrawn from the second fractionator 204. One or more second strippers, or second LCO strippers 224, can be coupled to line 230. A second recycle stream via line 232 and a second LCO product via line 236 can be withdrawn from the second LCO stripper 224. Line 232 can be coupled to the second fractionator 204 so that the second recycle stream via line 232 can be recycled to the second fractionator 204. Line 228 can be coupled with line 236 to form a line 238, so that the first LCO product via line 228 can be mixed with the second LCO product via line 236 to form a combined LCO product via line 238.
One or more third strippers, or HCO strippers 220, can be coupled to line 214 that is withdrawn from the first fractionator 202. A third recycle stream via line 218 can be withdrawn from the HCO stripper 220 as overhead. The third hydrocarbon feed can be withdrawn from the HCO stripper 220 as the HCO via line 132. Line 218, containing the third recycle stream, can be coupled to the first fractionator 202 at any location. For example, line 218 can be coupled to the first fractionator 202 at any location below where the second side draw via line 216 is withdrawn from the first fractionator 202.
One or more fourth strippers, or bottoms strippers 248, can be coupled to line 244. A fourth recycle stream via line 246 can be withdrawn from the bottoms stripper 248 as overhead. The second hydrocarbon feed can be withdrawn from the bottoms stripper 248 as a first bottoms via line 124 (the second hydrocarbon feed via line 124). Line 246, containing the third recycle stream, can be coupled to the first fractionator 202 at any location. For example, line 246 can be coupled to the first fractionator 202 at any location below where the first side draw via line 214 is withdrawn from the first fractionator 202. One or more fifth strippers, or second bottoms strippers (not shown), can be coupled to line 234 and improve LCO recovery from the third bottoms stream via line 234.
The first and second fractionation columns 202, 204, the first and second LCO strippers 222, 224, the HCO stripper 220, and the bottoms stripper 248 can include one or more trays, random packing, or structured packing sections disposed within. Illustrative trays can include, but are not limited to perforated trays, sieve trays, bubble cap trays, floating valve trays, fixed valve trays, tunnel trays, cartridge trays, dual flow trays, baffle trays, shower deck trays, disc and donut trays, orbit trays, horseshoe trays, cartridge trays, snap-in valve trays, chimney trays, slit trays, or any combination thereof. The packing material can increase the effective surface area within the column, which can improve the mass transfer between liquid and gas phases within the column. The packing material can be made of any suitable material, for example metals, non-metals, polymers, ceramics, glasses, or any combination thereof. Illustrative examples of random packing material can include, but are not limited to, Raschig rings, Lessing rings, 1-rings, saddle rings, Intalox saddles, Tellerettes, Pall rings, U-rings, or any combination thereof. Illustrative examples of commercially available structured packing can include, but are not limited to, structured packing, corrugated sheets, crimped sheets, gauzes, grids, wire mesh, monolith honeycomb structures, or any combination thereof. For example, suitable structured packing can include FLEX1PAC and GEMPAK structured packing manufactured by the Koch-Glitsch Corporation.
Referring to
The first bottoms in line 124 can be pre-heated prior to introduction to the second riser 104. The regenerative heat exchanger (not shown) using waste process heat can also be used to pre-heat the first bottoms in line 124. The temperature of the first bottoms in line 124 can be from about 150° C. to about 400° C., about 200° C. to about 350° C., or about 250° C. to about 300° C. The pressure of the first bottoms in line 124 can be from about 101 kPag to about 2,100 kPag, about 350 kPag to about 1,500 kPag, or about 450 kPag to about 700 kPag. Within the first and second risers 102, 104, the pressure and temperature can be adjusted either manually or automatically to compensate for variations in the composition of the feeds and to maximize the yield of preferred hydrocarbons obtained in the cracked products recovered via lines 140, 144.
The steam introduced via lines 128, 130 to the first and second risers 102, 104, respectively, can be saturated. The pressure of the saturated steam can be from about 101 kPag to about 6,000 kPag, about 500 kPag to about 6,000 kPag, or about 2,000 kPag to about 6,000 kPag. For example, the pressure of the saturated steam can range from about 101 kPag to about 8,300 kPag, about 101 kPag to about 4,000 kPag, or about 101 kPag to about 2,000 kPag.
The steam introduced via lines 128, 130 to the first and second risers 102, 104, respectively, can be superheated. The pressure of the superheated steam can be from a low of about 100 kPag to a high of about 8,500 kPag. The pressure of the superheated steam via line 125 can range from about 100 kPag to about 8,300 kPag, about 100 kPag to about 4,000 kPag, or about 100 kPag to about 2,000 kPag. The temperature of the superheated steam via lines 128, 130 can be a minimum of about 200° C., about 230° C., about 260° C., or about 290° C.
The first riser 102 can include at least two reaction zones. A first reaction zone 150, operated under the third cracking conditions, can be located below or upstream of the location of the inlet of the hydrocarbon via line 120. A second reaction zone 152, operated under the first cracking conditions, can be located at or above the location of the inlet of the hydrocarbon via line 120. In the first reaction zone 150 of the first riser 102, the catalyst-to-hydrocarbon weight ratio of catalyst via line 122 to the HCO via line 132 can range from about 2:1 to about 35:1, from about 2:1 to about 30:1, from about 5:1 to about 25:1, from about 10:1 to about 20:1, or from about 15:1 to about 18:1. The first reaction zone 150 can be operated at a temperature from a low of about 300° C., about 320° C., about 330° C., about 350° C., about 380° C., or about 400° C. to a high of about 480° C., about 500° C., about 550° C., about 575° C., about 600° C., or about 650° C. For example, the first reaction zone 150 can be operated at a temperature from about 450° C. to about 620° C., from about 470° C. to about 600° C., from about 490° C. to about 580° C., or from about 500° C. to about 550° C.
In the second reaction zone 152 of the first riser 102, the catalyst-to-hydrocarbon weight ratio of catalyst via line 122 to the hydrocarbon via line 120 can range from about 0.5:1 to about 15:1, from about 1:1 to about 10:1, from about 1.5:1 to about 8:1, from about 2:1 to about 6:1, or from about 3:1 to about 5:1. The second reaction zone 152 can be operated at a temperature from a low of about 450° C., about 465° C., about 475° C., about 485° C., about 495° C., or about 500° C. to a high of about 505° C., about 510° C., about 515° C., about 520° C., about 525° C., or about 530° C. For example, the second reaction zone 152 can be operated at a temperature from about 400° C. to about 525° C., from about 465° C. to about 515° C., from about 485° C. to about 512° C., or from about 500° C. to about 510° C. In at least one specific embodiment, the second reaction zone 152 can be operated at a temperature of about 498° C., about 502° C., about 504° C., about 506° C., about 508° C., or about 512° C.
In the second riser 104, operated under second cracking conditions, the catalyst-to-hydrocarbon weight ratio of catalyst via line 126 to the first bottoms via line 124 can range from about 2:1 to about 35:1, from about 2:1 to about 30:1, from about 5:1 to about 25:1, from about 10:1 to about 20:1, or from about 15:1 to about 18:1. The second riser 104 can be operated at a temperature from a low of about 450° C., about 475° C., about 500° C., about 515° C., about 525° C., or about 550° C. to a high of about 575° C., about 585° C., about 595° C., about 615° C., about 650° C., or about 700° C. For example, the second riser 104 can be operated at a temperature from about 400° C. to about 675° C., from about 500° C. to about 600° C., from about 510° C. to about 590° C., or from about 515° C. to about 580° C. In at least one specific embodiment, the second riser 104 can be operated at a temperature of about 535° C., about 540° C., about 545° C., about 550° C., about 555° C., or about 560° C.
Heat in the first and second risers 102, 104 can be provided by steam via lines 128, 130, respectively, and the catalyst via lines 122, 126, respectively. As used herein, reference to a riser temperature shall mean the temperature of the riser effluent exiting at the top of the riser. The thermal equilibrium of the riser feed can be lower than the riser exit temperature and the temperature can vary throughout the riser depending on the reactions.
The pressure in the first riser 102 can be from a low of about 40 kPag, about 55 kPag, about 65 kPag, or about 70 kPag to a high of about 650 kPag, about 675 kPag, about 700 kPag, or about 725 kPag. Other operating conditions for the first riser 102 can be as discussed and described in U.S. Pat. No. 7,128,827. In at least one specific embodiment, the hydrocarbon feed via line 120 can be heated within the first riser 120 to a temperature of about 498° C. to about 512° C. at a pressure of about 68 kPag to about 690 kPag.
The pressure in the second riser 104 can be from a low of about 40 kPag, about 55 kPag, about 65 kPag, or about 70 kPag to a high of about 650 kPag, about 675 kPag, about 700 kPag, or about 725 kPag. Other operating conditions for the second riser 104 can be as discussed and described in U.S. Pat. No. 7,128,827. In at least one specific embodiment, the first bottoms via line 124 can be heated within the second riser 104 to a temperature of about 535° C. to about 560° C. at a pressure of about 68 kPag to about 690 kPag.
The velocity of the reaction mixture flowing through the first reaction zone 150 of the first riser 102, or the mixture of the third hydrocarbon feed via line 132 and the catalyst via line 122, can be from about 3 m/sec to about 27 m/sec, about 6 m/sec to about 25 m/sec, or about 9 m/sec to about 21 m/sec. The residence time of the reaction mixture in the first reaction zone 150 of the first riser 102 can be less than about 20 seconds, less than about 10 seconds, less than about 8 seconds, less than about 4 seconds, or less than about 2 seconds. The velocity of the reaction mixture flowing through the second reaction zone 152 of the first riser 102, or the mixture of the third effluent and the first hydrocarbon feed via line 120, can be from about 3 m/sec to about 27 m/sec, about 6 m/sec to about 25 msec, or about 9 m/sec to about 21 m/sec. The residence time of the reaction mixture in the second reaction zone 152 of the first riser 102 can be less than about 10 seconds, less than about 5 seconds, less than about 2 seconds, less than about 1 seconds, or less than about 0.5 second. The residence time of the second reaction zone 152 can be about 95% or less, about 90% or less, about 85%© or less, about 75% or less, about 50% or less, about 35% or less, about 25% or less, about 10% or less, or about 5% or less of the residence time of the first reaction zone 150.
The velocity of the reaction mixture flowing through the second riser 104 can be from about 3 m/sec to about 27 m/sec, about 6 m/sec to about 25 m/sec, or about 9 rn/sec to about 21 m/sec. The residence time of the reaction mixture in the second riser 104 can be less than about 20 seconds, less than about 10 seconds, less than about 8 seconds, less than about 4 seconds, or less than about 2 seconds.
The first riser effluent can flow, via first transfer line 106, from the first riser 102 to the first catalyst disengagement zone 110, where spent-catalyst particulates and/or other particulates can be separated from gaseous hydrocarbons, steam, and inerts of the first cracked product. The second riser effluent can flow, via second transfer line 108, from the second riser 104 to the second catalyst disengagement zone 112, where spent-catalyst particulates and/or other particulates can be separated from gaseous hydrocarbons, steam, and inerts of the second cracked product. The first and second disengagement zones 110, 112 can each have a larger cross-sectional area than their respective risers 102, 104 and/or transfer lines 106, 108, which reduces the velocity of the cracked product mixtures, allowing the heavier spent-catalyst particulates and/or other particulates to separate from the gaseous hydrocarbons, steam, and inerts. In one or more embodiments, a steam purge (not shown) can be added to the first and second disengagement zones 110, 112 to assist in separating the gaseous hydrocarbons from the spent-catalyst particulates, i.e., stripping the gaseous hydrocarbons from the solids. In other words, the first and second disengagement zones 110, 112 can be self-stripping separators, e.g., self-stripping cyclones. An additional steam purge can be provided at the base of the stripper 114 to assist in separating the gaseous hydrocarbons from the spent-catalyst particulates, i.e., stripping the gaseous hydrocarbons from the solids.
The gaseous hydrocarbons, the first cracked product via line 140 and the second cracked product via line 142 can be separately recovered from the first and second disengagement zones 110, 112, respectively. The first and second cracked products in lines 140, 142 can be further processed, such as by fractionating as shown in
The first disengagement zone 110 can separate from a low of about 90%, about 90.5%, about 91%, or about 91.5% to a high of about 98%, about 99%, about 99.5%, or about 99.999% of the particulates from the first effluent via the transfer line 106. The second disengagement zone 112 can separate from a low of about 90%, about 90.5%, about 91%, or about 91.5% to a high of about 98%, about 99%, about 99.5%, or about 99.999% of the particulates from the second effluent via the transfer line 108. The first disengagement zone 110 can be fluidly isolated from the second disengagement zone 112. In an example, the first disengagement zone 110, the second disengagement zone 112, or both can prevent the first effluent, the first cracked product, or both from mixing or otherwise combining with the second effluent, the second cracked product of both. For example, the first cracked product can leave the disengagement zone and enter a fluid tight plenum 144 where the first cracked product is withdrawn from the FCC system 100 via line 140. Also the second cracked product can be separately withdrawn from the FCC system 100 via line 142. In an example, either the first disengagement zone 110 or the second disengagement zone 112, but not both, is in fluid communication with the stripper 114 for withdrawing the steam and hydrocarbon vapors from the FCC system 100. In another example (not shown), the first disengagement zone 110 and the second disengagement zone 112 can be in fluid communication with each other, allowing the first effluent, the first cracked product, or both to mix or otherwise combine with the second effluent, the second cracked product, or both. In the same example, either the first disengagement zone 110 or the second disengagement zone 112, or both, are in fluid communication with the stripper 114 for withdrawing the steam and hydrocarbon vapors from the FCC system 100.
The solids, i.e., spent-catalyst particulates, can free fall through the first and second disengagement zones 110, 112 to mix and be introduced to the stripper 114. In the stripper 114, the spent catalyst particulates can fall via gravity from a dilute phase to contact baffles or packing disposed within the stripper 114. At the same time, rising gases, such as steam, can flow upward through the stripper to contact the baffles or packing and the falling spent catalyst particles. The steam can be introduced at any location of the stripper 114 below the baffles or packing. The rising steam can remove volatile components from the falling spent catalyst. The removed volatile components can flow concurrently with the rising steam and can enter one of either the first or second disengagement zone 110 or 112 to exit the FCC unit 100 via the first cracked product line 140 or the second cracked product line 142.
The falling stripped catalyst particles, or coked catalyst particles, can then be introduced to the regenerator 116. The coked catalyst particulates can be combined with one or more fluids (not shown) within the regenerator 116 to provide a flue gas via line 136 and regenerated catalyst via lines 122, 126. The one or more fluids can include one or more oxidants and/or supplemental fuel. Illustrative oxidants can include, but are not limited to, air, oxygen, oxygen-enriched air, ozone, hydrogen peroxide, an essentially nitrogen-free oxidant, or any combination thereof. As used herein, the term “essentially oxygen” refers to a fluid containing more than 50 vol % oxygen. As used herein, the term “oxygen-enriched air” refers to a fluid containing about 21 vol % oxygen to about 50 vol % oxygen. Oxygen-enriched air and/or essentially oxygen can be obtained, for example, from cryogenic distillation of air, pressure swing adsorption, membrane separation, or any combination thereof. As used herein, the term “essentially nitrogen-free,” refers to an oxidant that contains about 5 vol % nitrogen or less, about 4 vol % nitrogen or less, about 3 vol % nitrogen or less, about 2 vol % nitrogen or less, or about 1 vol % nitrogen or less. The supplemental fuel can include any combustible material. For example, the supplemental fuel can include, but is not limited to, C1 to C30 hydrocarbons and/or carbon. The supplemental fuel can be introduced to the regenerator 116 as a liquid, gas, solid, or any combination thereof. The supplemental fuel can be introduced in a separate line from the oxidant. The oxidants can react with the carbonaceous matter on the coked catalyst particulates to combust or otherwise burn the carbon (“coke”) off the surface of the catalyst particulate. Should the supplemental fuel be introduced, the oxidants can react with the supplemental fuel to combust the supplemental fuel and generate heat. The removal of the coke from the surface of the catalyst particulates re-exposes the reactive surfaces of the catalyst particulates, thereby “regenerating” the catalyst particulates and permitting reuse thereof. Combustion by-products, such as carbon monoxide, sulfur oxides, nitrogen oxides, nitrogen oxide precursors, and carbon dioxide, can be removed from the regenerator 116 as a waste or flue gas via line 136. The regenerated catalyst particulates can be recovered via lines 122, 126, which can be recycled to the first and second risers 102, 104, respectively. In one or more embodiments, fresh, unused, catalyst can be added (not shown) to the regenerator 116, the regenerated catalyst in lines 122, 126, and/or to the first and second risers 102, 104.
The coked catalyst particulates can be combined with one or more oxidants (not shown) within the regenerator 116 to provide a flue gas via line 136 and regenerated catalyst via lines 122, 126. In one or more embodiments, the oxidants can react with the carbonaceous matter on the coked catalyst particulates to combust or otherwise burn the carbon (“coke”) off the surface of the catalyst particulate without the need for supplemental fuel. For example, a flue gas via line 136 and regenerated catalyst via lines 122, 126 can be obtained from the regenerator 116 in the absence of supplemental fuel. In one or more embodiments, the coked catalyst particles obtained from using the larger pore catalytically active component can result in a reduction of supplemental fuel added to the regenerator. For example, the coked catalyst particles obtained from using the larger pore catalytically active component can result in a reduction of at least 5 wt %, at least 20 wt %, at least 50 wt %, or at least 80 wt % or all of the supplemental fuel added to the regenerator.
The regenerator 116 can be operated in full burn mode, partial burn mode, or anywhere in between. The flue gas via line 136 can be introduced to one or more optional CO boilers (not shown) to remove additional CO. The one or more CO boilers can be any type of CO boiler. At least a portion of the flue gas via line 136 and/or flue gas from the optional CO boiler can be vented to the atmosphere and/or sent to one or more heat recovery units (not shown) and then vented to the atmosphere, sequestered underground, or otherwise disposed.
As discussed and described above, the hydrocarbon via line 120 can be introduced to the first riser 102 of the FCC system 100 to produce the first cracked product containing LCO via line 140. The first cracked product via line 140 can then be introduced to the fractionator 202. The first cracked product can be separated or fractionated in the first fractionator 202 to provide the first overhead containing fuel gas, gasoline and LPG via line 210, the first side draw via line 216 containing LCO, the second side draw via line 214 containing HCO. The first bottoms via line 124 can be obtained as the first bottoms stream from the first fractionator 202 and recycled to the second riser 104.
The first overhead in line 210 can include from about 1 wt %, about 5 wt %, or about 10 wt % to about 15 wt %, about 20 wt %, or about 25 wt % LPG and from about 65 wt %, about 70 wt %, about 75 wt % to about 80 wt %, about 85 wt %, about 90 wt % gasoline. For example, the first overhead in line 210 can include about 8 wt % to about 22 wt %, about 10 wt % to about 20 wt %, about 12 wt % to about 18 wt %, or about 14 wt % to about 16 wt % LPG and about 72 wt % to about 88 wt %, about 75 wt % to about 85 wt %, or about 78 wt % to about 82 wt % gasoline. The first side draw in line 216 can include from about 80 wt %, about 85 wt %, or about 90 wt % to about 92 wt %, about 95 wt %, or about 99 wt % LCO and from about 1 wt %, about 5 wt %, or about 8 wt % to about 10 wt %, about 15 wt %, or about 20 wt % HCO. The second side draw in line 214 can include from about 80 wt %, about 85 wt %, or about 90 wt % to about 92 wt %, about 95 wt %, or about 99 wt % HCO and about 1 wt %, about 5 wt %, or about 8 wt % to about 10 wt %, about 15 wt %, or about 20 wt % bottoms.
The first side draw in line 216 can be introduced to the first LCO stripper 222 to obtain LCO via line 228 and the first recycle stream 226 that can be recycled to the first fractionator 202. The first LCO product via line 228 can include about 90 wt %, about 95 wt %, or about 97 wt % to about 98 wt %, about 99 wt %, or about 99.99 wt % LCO. The second side draw in line 214 can be introduced to the HCO stripper 220 to obtain the first HCO via line 132 and a second recycle stream 218 that can be recycled to the first fractionator 202.
The first fractionator bottoms, or slurry oil containing stream, via line 244 can be introduced to the bottoms stripper 248 to obtain the first bottoms via line 124. The first bottoms via line 124 can then be introduced to the second riser 104 to produce the second cracked product via line 142. The second cracked product via line 142 can be separated or fractionated in the second fractionator 204 to provide the second overhead containing gasoline and LPG via line 212, the third side draw via line 230 containing LCO, and the third bottoms stream via line 234. In an example (not shown), the first fractionator bottoms via line 244 can be introduced directly to the second riser 104 of the FCC system 100 to produce the second cracked product containing LCO via line 142.
The second overhead in line 212 can include about 15 wt %, about 20 wt %, about 25 wt %, or about 30 wt % to about 40 wt %, about 45 wt %, about 50 wt %, or about 55 wt % LPG and about 35 wt %, about 45 wt %, or about 50 wt % to about 55 wt %, about 60 wt %, or about 70 wt % gasoline. The second bottoms in line 234 can include about 1 wt %, about 3 wt %, or about 5 wt % to about 8 wt %, about 10 wt %, or about 12 wt % HCO.
The third side draw stream 230 can be introduced to the second LCO stripper 224 to obtain LCO via line 236 and the third recycle stream 232 that can be recycled to the second fractionator 204. The second LCO product via line 236 can include about 90 wt %, about 95 wt %, or about 97 wt % to about 98 wt %, about 99 wt %, or about 99.99 wt % LCO. The first LCO product via line 228 and the second LCO product via line 236 can be mixed or combined to provide the combined LCO product via line 238. The combined LCO product via line 238 can include about 90 wt %, about 95 wt %, or about 97 wt % to about 98 wt %, about 99 wt %, or about 99.99 wt % LCO.
The combined LCO product via line 238 can include a Cetane Index, in accordance with ASTM D4737, of about 25, about 28, or about 32 to about 36, about 40, or about 44 and an API gravity of about 20, about 24, about 26, or about 27 to about 29, about 31, about 33, or about 35. The combined LCO product yield can be at least about 20%, at least about 30%, at least about 40%, at least about 45%, at least about 55%, or at least about 60%. For example, the combined LCO product yield can be from about 25%, about 30%, about 35%, or about 40% to about 45%, about 50%, about 55%, or about 60%.
One or more first strippers, or LCO strippers 322, can be coupled to line 316. A first recycle stream via line 326 and a first LCO product via line 328 can be withdrawn from the LCO stripper 322. Line 326 can be coupled to fractionator 302 so that the first recycle stream via line 326 can be recycled to the fractionator 302. One or more second strippers, or bottoms strippers 304, can be coupled to line 324. A second recycle stream via line 312 can be withdrawn from the bottoms stripper 304 as overhead. The second hydrocarbon feed can be withdrawn from the bottoms stripper 304 as the first bottoms via line 124 (the second hydrocarbon feed via line 124). Line 312, containing the third recycle stream, can be coupled to the fractionator 302 at any location. For example, line 312 can be coupled to the fractionator 302 at any location below where the first side draw via line 314 is withdrawn from the fractionator 302.
One or more third strippers, or HCO strippers 320, can be coupled to line 314. A third recycle stream via line 318 can be withdrawn from the HCO stripper 320 as overhead. The third hydrocarbon feed can be withdrawn from the HCO stripper 320 as the HCO via line 132. Line 318, containing the third recycle stream, can be coupled to the fractionator 302 at any location. For example, line 318 can be coupled to the fractionator 302 at any location below where the second side draw via line 316 is withdrawn from the fractionator 302. The fractionation column 302, the LCO stripper 322, the bottoms stripper 304, and the HCO stripper 320 can include one or more trays, random packing, or structured packing sections disposed within, as disclosed herein.
Referring to
The overhead in line 310 can include from about 1 wt %, about 5 wt %, or about 10 wt % to about 15 wt %, about 20 wt %, or about 25 wt % LPG and from about 65 wt %, about 70 wt %, about 75 wt % to about 80 wt %, about 85 wt %, about 90 wt % gasoline. For example, the overhead in line 310 can include about 8 wt % to about 22 wt %, about 10 wt % to about 20 wt %, about 12 wt % to about 18 wt %, or about 14 wt % to about 16 wt % LPG and about 72 wt % to about 88 wt %, about 75 wt % to about 85 wt %, or about 78 wt % to about 82 wt % gasoline. The second side draw in line 316 can include from about 80 wt %, about 85 wt %, or about 90 wt % to about 92 wt %, about 95 wt %, or about 99 wt % LCO and from about 1 wt %, about 5 wt %, or about 8 wt % to about 10 wt %, about 15 wt %, or about 20 wt % HCO. The first side draw in line 314 can include from about 80 wt %, about 85 wt %, or about 90 wt % to about 92 wt %, about 95 wt %, or about 99 wt % HCO and about 1 wt %, about 5 wt %, or about 8 wt % to about 10 wt %, about 15 wt %, or about 20 wt % slurry oil.
The second side draw in line 316 can be introduced to the LCO stripper 322 to obtain LCO via line 328 and the first recycle stream 326 that can be recycled to the fractionator 302. The LCO product via line 328 can include about 90 wt %, about 95 wt %, or about 97 wt % to about 98 wt %, about 99 wt %, or about 99.99 wt % LCO. The first side draw in line 314 can be introduced to the HCO stripper 320 to obtain the HCO via line 132 and a third recycle stream 318 that can be recycled to the fractionator 302. The HCO via line 132 can then be introduced to the first riser 102 where it is mixed with one or more catalysts via line 122.
The fractionator bottoms via line 324 can be introduced to the bottoms stripper 304 to obtain the first bottoms via line 124. The first bottoms via line 124 can then be introduced to the second riser 104 to produce the second cracked product via line 142. The second cracked product via line 142 can be separated or fractionated in the fractionator 302 to provide at least a portion of the overhead via line 310, the first side draw via line 316 containing LCO, the second side draw via line 314 containing HCO, and the fractionator bottoms via line 324.
The LCO in line 310 can include a Cetane Index, in accordance with ASTM D4737, of about 25, about 28, or about 32 to about 36, about 40, or about 44 and an API gravity of about 20, about 24, about 26, or about 27 to about 29, about 31, about 33, or about 35. The LCO product yield can be at least about 20%, at least about 30%, at least about 40%, at least about 45%, at least about 55%, or at least about 60%. For example, the LCO product yield can be from about 25%, about 30%, about 35%, or about 40% to about 45%, about 50%, about 55%, or about 60%.
As used herein, the term “gasoline” refers to a mixture of C4 to C12 hydrocarbons suitable for use as fuel in a spark ignition internal combustion engine, having an octane number of at least 60, and determined in accordance with ASTM D4814-09b.
As used herein, the term “light cycle oil” refers to a mixture of C8 to C20 hydrocarbons having a boiling point in the range of about 150° C. to about 415° C. in accordance with ASTM D-2887.
As used herein, the term “heavy cycle oil refers to a mixture of C18 to C30 hydrocarbons having a boiling point in the range of about 260° C. to about 500° C. in accordance with ASTM D-2887.
As used herein, the term “paraffinic” in reference to a feed or stream refers to a light hydrocarbon mixture including at least 80 wt % paraffins, no more than 10 wt % aromatics.
As used herein, the term “aromatic” in reference to a feed or stream refers to a light hydrocarbon mixture including more than 20 wt % aromatics.
As used herein, the term “olefinic” in reference to a feed or stream refers to a hydrocarbon mixture including at least 20 wt % olefins.
To provide a better understanding of the foregoing discussion, the following non-limiting examples are provided. All parts, proportions and percentages are by weight unless otherwise indicated.
A simulation was performed for a dual-riser FCC configuration. In this simulation a hydrotreated vacuum gas oil having an API gravity of 22.5 was selected as the hydrocarbon feed, or fresh feed, for the first riser. Fractionator bottoms from a first fractionator receiving effluent the first riser was injected into the second riser for further cracking. Based on results obtained from this simulation, the total product rate of LCO from both risers, the combined LCO product, can reach 55.8 vol % of fresh feed. The API and Cetane Index for the combined LCO product were found to be 27.7 and 33.9, respectively. The gasoline and LPG product rates were found to be 34.0 vol % and 13.1 vol % of the fresh feed, respectively. The slurry oil product was found to be only 1.6 vol % of the fresh feed.
Table 1 shows the properties of the feed for both risers and the operating conditions for both risers.
Table 2 shows the yield results based on the properties and operating conditions of Table 1.
The overall material balance for the FCC unit is summarized in Table 3. The material balance was based on the total fresh feed to the FCC unit. There were no external feeds to the FCC unit.
The properties of the products from the FCC unit are summarized in Table 4.
The API of the LCO from the first riser was 29.9 and the estimated Cetane Index was 36.9. After combining the LCO from the first riser with the LCO from the second riser, the overall LCO product demonstrated an API of 27.7 and a Cetane Index of 33.9.
Embodiments of the present disclosure further relate to any one or more of the following paragraphs:
1. A method for producing diesel, comprising: cracking a first hydrocarbon feed in a first riser under first cracking conditions to provide a first effluent comprising a first light cycle oil, a heavy cycle oil, and a first bottoms; fractionating at least a portion of the first effluent to separate the first bottoms and the heavy cycle oil from the first light cycle oil; cracking the separated first bottoms in a second riser under second cracking conditions to produce a second effluent comprising a second light cycle oil and a second bottoms; cracking the separated heavy cycle oil in the first riser under third cracking conditions to provide a third effluent; and mixing the third effluent with the first hydrocarbon feed to provide the first cracking conditions.
2. The method according to paragraph 1, wherein the first hydrocarbon feed comprises gas oil, vacuum gas oil, hydrotreated vacuum gas oil, reduced crude, atmospheric tower bottoms, vacuum tower bottoms, or any mixture thereof.
3. The method according to paragraphs 1 or 2, further comprising: separating the first effluent to produce a first spent-catalyst and a first gaseous product; separating the second effluent to produce a second spent-catalyst and a second gaseous product; combining the first spent-catalyst and the second spent-catalyst to provide a mixed spent-catalyst; regenerating the mixed spent-catalyst by combusting coke in a regenerator to produce regenerated catalyst; and recycling the regenerated catalyst to the first and second risers.
4. The method according to any one of paragraphs 1 to 3, wherein the first cracking conditions comprise temperatures from about 450° C. to about 530° C. and pressures from about 68 kPag to about 690 kPag.
5. The method according to paragraph 4, wherein the first cracking conditions further comprise a residence time of less than about 4 seconds and a catalyst-to-hydrocarbon weight ratio of catalyst to the first hydrocarbon feed of about 2:1 to about 6:1.
6. The method according to any one of paragraphs 1 to 5, wherein the second cracking conditions comprise temperatures from about 450° C. to about 650° C., pressures from about 68 kPag to about 690 kPag, a residence time of less than about 8 seconds and a catalyst-to-hydrocarbon weight ratio of catalyst to the first bottoms of about 10:1 to about 20:1.
7. The method according to any one of paragraphs 1 to 6, wherein the third cracking conditions comprise temperatures from about 500° C. to about 650° C., pressures from about 68 kPag to about 690 kPag, a residence time of less than about 8 seconds and a catalyst-to-hydrocarbon weight ratio of catalyst to the first heavy cycle oil of about 10:1 to about 20:1.
8. The method according to any one of paragraphs 1 to 7, further comprising fractionating at least a portion of the second effluent to provide the second light cycle oil and second bottoms, wherein the fractionating of the second effluent is independent of the fractionating of the first effluent.
9. The method according to any one of paragraphs 1 to 8, wherein the first light cycle oil and second light cycle oil have a combined yield of about 35% to about 60%.
10. A method for producing diesel, comprising: cracking a first hydrocarbon feed in a first riser under first cracking conditions to provide a first effluent comprising a first light cycle oil, a heavy cycle oil, and a slurry oil; fractionating at least a portion of the first effluent to separate the slurry oil and the heavy cycle oil from the first light cycle oil; stripping the slurry oil to provide a first bottoms; cracking the first bottoms in a second riser under second cracking conditions to produce a second effluent comprising a second light cycle oil and a second bottoms; fractionating at least a portion of the second effluent to separate the second bottoms from the second light cycle oil; cracking the separated heavy cycle oil in the first riser under third cracking conditions to provide a third effluent; mixing the third effluent with the first hydrocarbon feed to provide the first cracking conditions; and mixing the first light cycle oil with the second light cycle oil to provide a light cycle oil product.
11. The method according to paragraph 10, wherein the first hydrocarbon feed comprises a C8+ hydrocarbons concentration from about 95 wt % to about 99 wt %.
12. The method according to paragraphs 10 or 11, further comprising: separating the first effluent to produce a first spent-catalyst and a first gaseous product; separating the second effluent to produce a second spent-catalyst and a second gaseous product; combining the first spent-catalyst and the second spent-catalyst to provide a mixed spent-catalyst; regenerating the mixed spent-catalyst by combusting coke in a regenerator to produce regenerated catalyst; and recycling the regenerated catalyst to the first and second risers.
13. The method according to any one of paragraphs 10 to 12, wherein the first cracking conditions comprise temperatures from about 450° C. to about 530° C., pressures from about 68 kPag to about 690 kPag, a residence time of less than about 4 seconds and a catalyst-to-hydrocarbon weight ratio of catalyst to the first hydrocarbon feed of about 2:1 to about 6:1.
14. The method according to any one of paragraphs 10 to 13, wherein the second cracking conditions comprise temperatures from about 450° C. to about 650° C., pressures from about 68 kPag to about 690 kPag, a residence time of less than about 8 seconds and a catalyst-to-hydrocarbon weight ratio of catalyst to the first bottoms of about 10:1 to about 20:1.
15. The method according to any one of paragraphs 10 to 14, wherein the third cracking conditions comprise temperatures from about 500° C. to about 650° C., pressures from about 68 kPag to about 690 kPag, a residence time of less than about 8 seconds and a catalyst-to-hydrocarbon weight ratio of catalyst to the heavy cycle oil of about 10:1 to about 20:1.
16. The method according to any one of paragraphs 10 to 15, wherein the fractionating of the second effluent is independent of the fractionating of the first effluent.
17. The method according to any one of paragraphs 10 to 16, wherein the first hydrocarbon feed comprises gas oil, vacuum gas oil, hydrotreated vacuum gas oil, reduced crude, atmospheric tower bottoms, vacuum tower bottoms, or any mixture thereof.
18. The method according to any one of paragraphs 10 to 17, wherein the light cycle oil product has a yield of about 35% to about 60%.
19. A method for producing diesel, comprising: cracking a first hydrocarbon feed in a first riser under first cracking conditions comprising temperatures from about 450° C. to about 530° C. to provide a first effluent comprising a first light cycle oil, a heavy cycle oil, and a slurry oil; fractionating at least a portion of the first effluent to separate the slurry oil and the heavy cycle oil from the first light cycle oil; stripping the slurry oil to provide a first bottoms, cracking the first bottoms in a second riser under second cracking conditions comprising temperatures from about 450° C. to about 650° C. to produce a second effluent comprising a second light cycle oil and a second bottoms; fractionating at least a portion of the second effluent to separate the second bottoms from the second light cycle oil; cracking the heavy cycle oil in the first riser under third cracking conditions comprising temperatures from about 500° C. to about 650° C. to provide a third effluent; mixing the third effluent with the first hydrocarbon feed to provide the first cracking conditions; mixing the first light cycle oil with the second light cycle oil to provide a light cycle oil product; separating the first effluent to produce a first spent-catalyst and a first gaseous product; separating the second effluent to produce a second spent-catalyst and a second gaseous product; combining the first spent-catalyst and the second spent-catalyst to provide a mixed spent-catalyst; regenerating the mixed spent-catalyst by combusting coke in a regenerator to produce regenerated catalyst; and recycling the regenerated catalyst to the first and second risers.
20. The method according to paragraph 19, wherein the first hydrocarbon feed comprises gas oil, vacuum gas oil, hydrotreated vacuum gas oil, reduced crude, atmospheric tower bottoms, vacuum tower bottoms, or any mixture thereof.
21. A system for producing diesel, comprising: a first riser comprising a first reaction zone and a second reaction zone, wherein the second reaction zone is adapted to crack a first hydrocarbon feed under first cracking conditions to provide a first effluent comprising a first light cycle oil, a heavy cycle oil, and a slurry oil; a fractionator in fluid communication with the first riser, the fractionator adapted to fractionate at least a portion of the first effluent to separate the heavy cycle oil and the bottoms from the first light cycle oil; a stripper in fluid communication with the fractionator, the stripper adapted to separate first bottoms from the slurry oil, a second riser for cracking the separated first bottoms under second cracking conditions to produce a second effluent comprising a second light cycle oil and a second bottoms; and a mixing zone located in the first riser for mixing a third effluent with the first hydrocarbon feed to provide the first cracking conditions, wherein the first reaction zone of the first riser is adapted to crack the separated heavy cycle oil to provide the third effluent.
22. The system according to paragraph 21, further comprising: a first fluid outlet of the first riser in fluid communication with a first catalyst disengagement zone; a second fluid outlet of the second riser in fluid communication with a second catalyst disengagement zone; a first cracked product outlet in fluid communication with the first catalyst disengagement zone; a second cracked product outlet in fluid communication with the second catalyst disengagement zone; and a catalyst regenerator in fluid communication with the first and second catalyst disengagement zones.
23. The system according to paragraphs 21 or 22, wherein the first and second catalyst disengagement zones each comprise one or more cyclone separators.
24. The system according to any one of paragraphs 21 to 23, wherein the first catalyst disengagement zone is fluidly isolated from the second catalyst disengagement zone.
25. The system according to paragraph 24, further comprising a second fractionator fluid communication with the second riser, wherein the second fractionator is fluidly isolated from the first fractionator.
Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. Certain lower upper limits, and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.
While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
