Process for recovering cracked products

Abstract

A process for catalytic cracking recovery positions a stripper to receive a main column receiver liquid. A column for removing light hydrocarbons from the liquid stream is removed from the high pressure section, thereby saving energy.

Description

[0001] Priority Statement

[0002] This application claims priority to Indian Provisional Application No. 202211065725, filed on November 16, 2022, the entire disclosure of which is incorporated herein by reference. Technical Field

[0003] The field is the recovery of cracked products from the reaction of feedstock with a fluid catalyst. The field particularly relates to fluid catalytic processes for recovering cracked products rich in light olefins. Background Art

[0004] Catalytic cracking can form a variety of products from larger hydrocarbons. Generally, a heavy hydrocarbon feedstock, such as vacuum gas oil, is provided to a catalytic cracking reactor, such as a fluid catalytic cracking (FCC) reactor. A variety of products can be produced, including gasoline products and / or light products, such as propylene and / or ethylene. The spent catalyst is regenerated by combustion and returned to the catalytic cracking reactor.

[0005] The FCC effluent is introduced into a main column to cool and fractionate the products. The gas concentration section in the FCC unit is responsible for recovering lighter hydrocarbons from the top of the main column. The FCC unit is designed to produce more propylene to meet the demands of the plastics industry. The greater production of propylene drives the capacity of the gas concentration section. The gas concentration section typically includes a large recycle loop from the bottom of the debutanizer tower to a primary absorber tower in the high-pressure section. The stripper tower in this loop requires a large amount of energy to boil the light gases recycled to the high-pressure section of the primary absorber tower.

[0006] Accordingly, it is desirable to provide a recovery system for catalytic cracking that can reduce the energy required to recover larger amounts of ethylene and propylene products. Summary of the Invention

[0007] A method for catalytic cracking positions a stripper tower to receive the liquid from the top receiver of the main column. The tower for removing light hydrocarbons from the liquid stream is removed from the high-pressure section, thereby reducing the heating load.

[0008] Other details and embodiments of the present invention will become apparent from the following detailed description of the invention. Brief Description of the Drawings

[0009] The drawing is a schematic front view of the method of the present disclosure.

[0010] Definition

[0011] The term "downstream communication" means that at least a portion of the fluid flowing towards the main body in the downstream communication can operably flow from an object in fluid communication therewith.

[0012] The term "upstream connection" means that at least a portion of the fluid flowing out of the main body in an upstream connection can operably flow to an object that is in fluid communication therewith.

[0013] The term "direct connection" means that the fluid flow from an upstream component enters a downstream component without passing through any other intermediate container.

[0014] The term "indirect connection" means that the fluid flow from an upstream component enters a downstream component after passing through an intermediate container.

[0015] The term "bypass" means that the object loses downstream connection with the bypassing main body at least within the scope of the bypass.

[0016] As used herein, the terms "major" or "substantial" mean greater than 50%, suitably greater than 75%, and preferably greater than 90%.

[0017] The term "tower" means one or more distillation towers for separating one or more components having different volatilities. Unless otherwise specified, each tower includes a condenser at the top of the tower for condensing a portion of the overhead stream and refluxing it back to the top of the tower, and a reboiler at the bottom of the tower for vaporizing a portion of the bottoms stream and returning it to the bottom of the tower. The feed to the tower can be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the tower. The bottom temperature is the liquid bottom outlet temperature. The top line and the bottom line refer to the net lines from downstream of the tower to any reflux or reboiling back to the tower. A stripper tower can omit the reboiler at the bottom of the tower and instead provide the heating requirements and separation driving force for a liquefied inert medium (such as steam). A stripper tower typically feeds from the top tray and withdraws the major product from the bottom.

[0018] As used herein, the term "separator" means a container that has an inlet and at least one overhead vapor outlet and one bottoms liquid outlet, and may also have an aqueous stream outlet from a boot. A flash drum is a type of separator that can be in downstream connection with a separator that can operate at a higher pressure. A receiver is a separator.

[0019] As used herein, the term "boiling point temperature" means the atmospheric equivalent boiling point (AEBP) calculated from the observed boiling temperature and the distillation pressure, as calculated using the formula provided in ASTM D1160 Appendix A7, titled "Practice for Converting Observed Vapor Temperatures to Atmospheric Equivalent Temperatures".

[0020] As used herein, the term "True Boiling Point" (TBP) means the test method for determining the boiling point of a substance in accordance with ASTM D-2892, which is used to produce liquefied gas, distillate fractions, and residues of standardized quality from which analytical data can be obtained, and to determine the yields of the above fractions by both mass and volume. Based on this mass and volume, a graph of distillation temperature versus mass % is obtained in a column with fifteen theoretical plates at a reflux ratio of 5:1.

[0021] As used herein, the terms "T5" or "T95" mean the temperatures at which 5 mass percent or 95 mass percent of a sample boils, respectively, as determined using ASTM D-86 or TBP, as appropriate.

[0022] As used herein, the term "Initial Boiling Point" (IBP) means the temperature at which a sample begins to boil, as determined using ASTM D-7169, ASTM D-86, or TBP, as appropriate.

[0023] As used herein, the term "End Point" (EP) means the temperature at which a sample has completely boiled, as determined using ASTM D-7169, ASTM D-86, or TBP, as appropriate.

[0024] As used herein, "vacuum gas oil" means a hydrocarbonaceous material prepared by vacuum fractionation of atmospheric residue and having an IBP of at least 232 °C (450 °F), a T5 between 288 °C (550 °F) and 392 °C (700 °F), usually not exceeding 343 °C (650 °F), a T95 between 510 °C (950 °F) and 570 °C (1058 °F), and / or an EP not exceeding 626 °C (1158 °F), as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, D6352, or D7169, all of which are used in the petroleum industry.

[0025] As used herein, "atmospheric residue" refers to a hydrocarbonaceous material obtained from the bottom of an atmospheric crude distillation column and having an IBP of at least 232 °C (450 °F), a T5 between 288 °C (550 °F) and 392 °C (700 °F), usually not exceeding 343 °C (650 °F), and a T95 between 510 °C (950 °F) and 700 °C (1292 °F).

[0026] As used herein, "atmospheric residue" means a hydrocarbonaceous material that boils at an IBP of at least 500 °C (932 °F). Detailed Description

[0027] The FCC gas concentration section generally includes a large recycle loop from the debutanizer bottom to the primary absorber column. The proposed method aims to remove this recycle stream from the high-pressure section by rearranging the stripper column immediately downstream of the main column top receiver. The operation of the stripper column can thus be carried out at a lower pressure, thereby reducing the energy consumption in the stripper reboiler. The C5+ hydrocarbons from the stripper column bottom will be sent as an absorbent to the primary absorber column. Removing the light components from the absorbent in the primary absorber column improves absorption.

[0028] Turning now to the drawings, where like numbers represent like components, the method generally includes an FCC unit section 6 and a product recovery section 8. The FCC unit section 6 includes an FCC reactor 12 and a catalyst regenerator 14. The process conditions in the FCC reactor 12 can include a cracking reaction temperature of 400 °C to 600 °C, preferably 538 °C to 593 °C, at the reactor outlet, and a catalyst regeneration temperature of 500 °C to 900 °C. Both cracking and regeneration are carried out at an absolute pressure between 100 kPa (14 psia) and 650 kPa (94 psia), preferably between 140 kPa (20 psia) and 450 kPa (65 psia).

[0029] Figure 1 shows the FCC reactor 12, where the hydrocarbon feedstock distributed through the distributor 16 in line 15 contacts the fluid catalyst stream entering from the regenerated catalyst riser 18 and the recycle catalyst riser 19. The hydrocarbon feedstock can include vacuum gas oil, atmospheric residue, deasphalted oil, vacuum residue, or any other stream processed in a conventional FCC unit.

[0030] The catalyst can be a single catalyst or a mixture of different catalysts. Generally, the catalyst includes two components or catalysts, namely a first component or catalyst and a second component or catalyst. Such catalyst mixtures are disclosed, for example, in U.S. Patent No. 7,312,370 B2. Generally, the first component can include any well-known catalyst used in the FCC field, such as an active amorphous clay-type catalyst and / or a highly active crystalline molecular sieve. Zeolites can be used as molecular sieves in the FCC process. Preferably, the first component includes a large-pore zeolite (such as zeolite Y), an activated alumina material, a binder material (including silica or alumina), and an inert filler (such as kaolin).

[0031] Generally, the zeolite molecular sieves suitable for the first component have a large average pore diameter. Generally, molecular sieves with large pore diameters have pores where the pore openings are greater than 0.7 nm, and the effective diameter is defined by more than 10, and usually 12, member rings. The pore diameter index of the large pores can be above 31. Suitable large-pore zeolite components can include synthetic zeolites, such as X and Y zeolites, mordenite, and faujasite. A portion of the first component (such as zeolite) can have any suitable amount of rare earth metals or rare earth metal oxides.

[0032] The second component may include mesoporous or smaller pore zeolite catalysts, such as MFI zeolites, e.g., at least one of ZSM-5, ZSM-11, ZSM-12, ZSM-23, ZSM-35, ZSM-38, ZSM-48, and other similar materials. Other suitable mesoporous or smaller pore zeolites include ferrierite and erionite. Preferably, the second component is a mesoporous or smaller pore zeolite dispersed on a matrix, which includes a binder material (such as silica or alumina) and an inert filler (such as kaolin). The second component may also include some other active materials, such as beta zeolite. These compositions may have a crystalline zeolite content of 10 wt% to 50 wt% or higher and a matrix material content of 50 wt% to 90 wt%. Components containing 40 wt% crystalline zeolite material are preferably included, and those with a greater crystalline zeolite content may be used. Generally, mesoporous and smaller pore zeolites are characterized by an effective pore opening diameter of less than or equal to 0.7 nm, a ring of 10 or fewer members, and a pore size index of less than 31.

[0033] The total catalyst mixture in the FCC reactor 12 may contain 1 wt% to 25 wt% of the second component, i.e., mesoporous to small pore crystalline zeolite, preferably greater than or equal to 1.75 wt% of the second component. The first component may make up the remainder of the catalyst composition. In some preferred embodiments, the relative proportions of the first and second components in the mixture may be substantially constant throughout the FCC reactor 12. A high concentration of mesoporous or small pore zeolite as the second component of the catalyst mixture may improve the selectivity to light olefins. In one exemplary embodiment, the second component may be ZSM-5 zeolite, and the mixture may include 4 wt% to 10 wt% of ZSM-5 zeolite, excluding any other components, such as binders and / or fillers.

[0034] Preferably, at least one of the first and / or second catalysts is an MFI zeolite with a silicon to aluminum ratio greater than 15, preferably greater than 75. In one exemplary embodiment, the silicon to aluminum ratio may be from 15:1 to 35:1.

[0035] This contact may occur in a narrow riser 20 that extends upward to the bottom of the reactor vessel 22. The contact of the hydrocarbon feed with the first fluid catalyst stream is fluidized by a gas such as steam from the fluidization distributor 24. In the embodiment, the heat from the catalyst evaporates the hydrocarbon feed, and then the hydrocarbon feed cracks into a lighter molecular weight cracked product stream in the presence of the first catalyst stream as both are transferred upward along the riser 20 into the reactor vessel 22, thus providing a mixture of catalyst and product gas.

[0036] The pressure in the riser 20 can be from 200 kPa (29 psia) to 450 kPa (65 psia), but it can also be lower. The steam flow rate added to the riser 20 is 3 wt% to 7 wt% of the hydrocarbon feedstock. Inevitably, side reactions occur in the riser 20, leaving coke deposits on the catalyst to reduce the catalyst activity, generating a spent catalyst stream. Subsequently, a cyclone separator is used to separate the cracked product stream from the spent catalyst stream in the mixture of the catalyst and the product gas. The cyclone separator may include one or two stages of cyclone separators 62 in the reactor vessel 22. The gaseous cracked product stream leaves the reactor vessel 22 through the product outlet 31 and enters the pipeline 32 for transportation to the downstream product recovery section 8.

[0037] The spent catalyst or coked catalyst needs to be regenerated for further use. After the spent catalyst stream is separated from the cracked product stream by the separation device 54 in the disengaging chamber 56, it falls into the stripping section 34, where steam is injected through the distributor 35 to remove any residual hydrocarbon vapors. After the stripping operation, the stripped coked catalyst is carried to the catalyst regenerator 14 through the spent catalyst standpipe 36. Another part of the stripped coked catalyst can be recycled to the riser 20 through the recycle catalyst standpipe 19 without undergoing regeneration.

[0038] Figure 1 shows the regenerator 14, which is called a burner. However, other types of regenerators are also suitable. In the catalyst regenerator 14, a stream of oxygen-containing gas (such as air) is introduced through the air distributor 38 to contact the coked catalyst. The coked catalyst burns in the combustion chamber 80 to form coke, providing a regenerated catalyst and flue gas. The catalyst regeneration process adds a large amount of heat to the catalyst, thus providing energy to offset the endothermic cracking reaction occurring in the riser 20. The catalyst and air flow upward together in the combustion chamber 80 of the regenerator 14, and after regeneration, they are discharged through the settler 40 for preliminary separation and enter the separation chamber 86. The regenerated catalyst and flue gas leaving the settler 40 are further recovered using the first-stage cyclone separator 44 and the second-stage cyclone separator 46 in the separation chamber 86 of the catalyst regenerator 14. The catalyst separated from the flue gas is distributed through the dip tubes in the cyclone separators 44 and 46, while the relatively lighter flue gas in the catalyst leaves the cyclone separators 44 and 46 in sequence and leaves the regenerator vessel 14 through the flue gas outlet 47 in the flue gas pipeline 48. The regenerated catalyst is carried back to the riser 20 through the regenerated catalyst standpipe 18. Due to coke combustion, the flue gas vapor leaving the top of the catalyst regenerator 14 contains CO, CO2, N2, and H2O along with a smaller amount of other substances.

[0039] The product recovery section 8 is in downstream communication with the product outlet 31. In the product recovery section 8, the cracked product stream in line 32 is directed to the lower section of the FCC main fractionator tower 92. The main tower 92 is in downstream communication with the product outlet 31. Several fractions of the FCC product can be separated and withdrawn from the main tower, including heavy slurry oil from the bottom in line 93, the heavy recycle oil stream in line 94, the light recycle oil in line 95 withdrawn from outlet 95a, and the heavy naphtha stream in line 96 withdrawn from outlet 96a. Any or all of the lines 93 to 96 can be cooled and pumped back to the main tower 92 to cool the main tower at a generally higher location. Gasoline and gaseous light hydrocarbons are removed from the main tower 92 in the main tower top line 97 and condensed before entering the main tower receiver 99. The main tower receiver 99 is in downstream communication with the product outlet 31, and the main tower 92 is in upstream communication with the main tower receiver 99.

[0040] The water-containing stream is removed from the reservoir in the main tower receiver 99. In addition, the main net gas stream is removed in the receiver top line 101, while the condensed main tower top net liquid stream containing light naphtha is removed in the receiver bottom line 102. The main net gas stream in line 101 contains gaseous light hydrocarbons with a very high olefin content. The main net gas stream in line 101 can enter the vapor recovery section 120 of the product recovery section 8.

[0041] The condensed main net liquid stream containing the unstabilized light naphtha stream in the receiver bottom line 102 is delivered to the stripper tower 126. Preferably, the main net liquid stream in the receiver bottom line 102 is sent directly to the stripper tower 126. Thus, the stripper tower 126 is in direct downstream communication with the main tower receiver 99 through the receiver bottom line 102. Most of the C2-hydrocarbons and light gases are removed in the stripper top stream in the stripper top line 128 extending from the top of the stripper tower 126 and are delivered, together with the main net gas stream in the receiver top line 101, to the first-stage compressor 104 in upstream communication with the first-stage compressor 104. The stripper top stream in line 128 contains a small amount of C3-C5 hydrocarbons. The stripped bottom stream in the stripper bottom line 130 extending from the bottom of the stripper tower 126 containing C3+ hydrocarbons is divided into a reboil stream and a net stripper bottom stream in the net stripper bottom line 132, and the reboil stream is boiled and returned to the tower. The stripper tower 126 can be operated at a bottom temperature of 140°C to 175°C and a top pressure of 200 kPa to 400 kPa. The stripper tower 126 is not located on a high-pressure pipeline and operates at a lower pressure, thereby reducing the energy consumption in the stripper reboiler.

[0042] The illustrated vapor recovery section 120 is an absorption-based system, but any vapor recovery system, including a cold box system, can be used. To obtain sufficient separation of the light gas components, the main net gas stream in line 101 and the stripper overhead stream in line 128 are compressed in the first stage compressor 104. At least one compressor stage can be used, but usually two-stage compression is used. The first compressed main net gas stream in line 106 is combined with the vapor light hydrocarbon stream in the net fractionator overhead line 117, cooled, and fed to the interstage separator 107. The interstage separator 107 separates the first compressed main net gas stream and the vapor light hydrocarbon stream into a first stage main net gas stream in line 109 and a first stage main liquid stream in line 110. The first stage main net gas stream in line 109 is compressed in the second stage compressor 111 to provide a second compressed main net gas stream in line 113. The second compressed main net gas stream is combined with the rich absorbent stream in the primary absorber bottom line 116 and the first stage liquid stream in line 110, cooled, and transferred to the high pressure receiver 122. The high pressure receiver 122 separates the cooled second compressed main net gas stream, the rich absorbent stream, and the first stage liquid stream into a gaseous hydrocarbon stream containing C2 - hydrocarbons in the high pressure receiver overhead line 123 and a liquid hydrocarbon stream containing C3+ hydrocarbons in the high pressure receiver bottom line 124. The water stream from the high pressure receiver 122 can be sent to the main column receiver 99.

[0043] The gaseous hydrocarbon stream in pipeline 123 is directed to the primary absorber tower 114, where it contacts the primary absorbent in the primary absorbent pipeline 133 to achieve the separation between C2-hydrocarbons and C3+-hydrocarbons. The primary absorbent includes the net stripped bottoms stream in pipeline 132 from the bottom of the stripper tower 126, the net heavy hydrocarbon stream in the fractionator bottoms pipeline 148, and the deethanizer overhead liquid stream in the deethanizer receiver bottoms pipeline 156. The primary absorber 114 is in downstream communication with the stripper tower 126 and the main tower receiver 99. The primary absorber tower 114 can be in direct downstream communication with the bottom of the stripper tower 126 through the stripper bottoms pipeline 130. In the primary absorber tower 114, the net stripped bottoms stream in pipeline 132 (possibly via the primary absorbent pipeline 133) contacts the gaseous hydrocarbon stream in pipeline 123 to absorb the C3+-hydrocarbons in the gaseous hydrocarbon stream, so as to provide the absorbed gaseous hydrocarbon stream in the absorber overhead pipeline 115 and the rich absorbent stream in the primary absorber bottoms pipeline 116. The net stripped bottoms stream in pipeline 132, possibly in the primary absorbent pipeline 133, is fed to the primary absorber tower 114 at a higher elevation, and the gaseous hydrocarbon stream in pipeline 123 is fed to the tower at a lower elevation to achieve countercurrent contact in the primary absorber 114. The primary absorber 114 is capable of removing C3 and C4 hydrocarbons by contacting with the net stripped bottoms stream as the primary absorbent. As mentioned, the net heavy hydrocarbon stream in the fractionator bottoms pipeline 148 from the fractionator 140 and the deethanizer overhead liquid stream in the deethanizer receiver bottoms pipeline 156 can supplement the net stripped bottoms stream to provide sufficient primary absorbent in the primary absorbent pipeline 133. Therefore, the gaseous hydrocarbon stream in pipeline 123 can also contact the net heavy hydrocarbon stream in pipeline 148 and / or the deethanizer overhead liquid stream in pipeline 156 to absorb the C3+-hydrocarbons in the gaseous hydrocarbon stream.

[0044] The absorbent stream rich in C3+-hydrocarbons in pipeline 116 returns to the high-pressure receiver 122 together with the first-stage liquid stream in pipeline 110 and the second compressed main net gas stream in pipeline 113. Pipeline 113 is located downstream of the first compressor 104 and the second compressor 111, thus eliminating the need for additional compressor capacity. The rich absorbent stream in pipeline 116 is thus separated into the gaseous hydrocarbon stream in pipeline 123 and the liquid hydrocarbon stream in pipeline 124. The absorbent stream rich in C3+-hydrocarbons in pipeline 116 returns to the second compressed main net gas stream in pipeline 113 and is then cooled. The primary waste gas stream in pipeline 115 from the primary absorber 114 can be directed to the secondary absorber tower 118. The primary absorber tower 116 can operate at a bottom temperature of 38°C to 62°C and a top pressure of 1700 kPa to 2200 kPa.

[0045] In the secondary absorber tower 118, the primary waste gas stream in line 115 contacts the recycle sidestream of the light recycle oil in line 134, which is delivered from line 95 taken from the main tower 90, and it absorbs most of the remaining C5+ and some C3-C4 hydrocarbons in the primary waste gas stream. The secondary absorber tower 118 is in downstream communication with the primary absorber tower 114. The light recycle oil rich in C3+ hydrocarbons from the bottom of the secondary absorber tower 118 in line 136 is pumped via line 95 and recycled back to the main tower 92. The top of the secondary absorber tower 118 delivers a dry gas stream in the secondary waste gas stream in line 119, which mainly contains C2- hydrocarbons as well as hydrogen sulfide, ammonia, carbon oxides, and hydrogen. The secondary waste gas stream in line 119 can be processed in a downstream ethylene recovery unit (not shown). The secondary absorber tower 118 can be operated at a bottom temperature of 38°C to 60°C and a top pressure of 1700 kPa to 2000 kPa.

[0046] The liquid hydrocarbon stream containing C3+ hydrocarbons in the receiver bottom line 124 from the high-pressure receiver can be delivered to the fractionation debutanizer tower 140. The fractionation tower 140 can be a debutanizer tower, a depentanizer tower, or a dehexanizer tower for fractionating the liquid hydrocarbon stream in line 124 into a light hydrocarbon stream in the fractionator top line 142 and a heavy hydrocarbon stream in the fractionator bottom line 144. The fractionation tower 140 is typically operated as a debutanizer tower, but can be operated as a depentanizer tower or a dehexanizer tower if further cracking is required to produce additional olefins.

[0047] The light hydrocarbon stream in the fractionator top line 142 can be cooled and separated in the fractionation receiver 145 to provide a vapor light hydrocarbon stream in the net fractionator top line 117 and a liquid light hydrocarbon in the fractionation receiver bottoms line 146. The fractionation net gas stream in the net fractionator top line 117 can be combined with the first compressed main net gas stream in line 106 to be cooled, compressed in the inter-stage separator 107, and its vapor further compressed in the second compressor 111 to provide a compressed main net gas stream 113. The liquid light hydrocarbon stream in line 146 can be fed to the deethanizer 150. A heavy hydrocarbon stream containing C5+ hydrocarbons from the bottom of the fractionator 140 in the fractionator bottoms line 144 extending from the bottom of the fractionator 140 is split into a net heavy hydrocarbon stream in the net fractionator bottoms line 148, a reboil stream that is boiled and returned to the column, and a net fractionated product stream in the product line 149. The C5+, C6+, or C7+ hydrocarbons in the net fractionated product line 149 can be further processed into gasoline or petrochemical products. The net heavy hydrocarbon stream in line 148 can be supplemented with the deethanizer top liquid stream in the deethanizer receiver bottoms line 156 for supplementing the stripper bottoms stream in line 132 as a primary absorbent in the primary absorbent line 133 to the primary absorber 114. The fractionator 140 can be operated at a bottom temperature of 190 °C to 220 °C and a top pressure of 1300 kPa to 1500 kPa.

[0048] The liquid light hydrocarbon stream in the bottoms line 146 of the fractionation receiver can be de-ethanized in the de-ethanizer tower 150 to provide a de-ethanizer overhead stream in line 152 and a de-ethanizer bottoms stream in line 154. The de-ethanizer overhead feed stream in the de-ethanizer overhead line 152 can be cooled and separated in the de-ethanizer receiver 154 to provide a net de-ethanizer gas stream in the net de-ethanizer overhead line 155 and a de-ethanizer overhead liquid stream in the de-ethanizer receiver bottoms line 156. The net de-ethanizer gas stream in the net de-ethanizer overhead line 155 can be added to the gaseous hydrocarbon stream in the high-pressure receiver overhead line 123 to contact the primary absorbent (including the stripped bottoms stream in line 132) in line 133 to absorb C3+ hydrocarbons from the gaseous hydrocarbon stream and the de-ethanizer gas stream. The de-ethanizer overhead liquid stream in the de-ethanizer receiver bottoms line 156 can supplement the net heavy hydrocarbon stream in line 148, and together they can supplement the net stripper stream in the net stripper bottoms line 132 as the primary absorbent stream in line 133 to the primary absorber tower 114. The de-ethanizer bottoms stream containing C3 hydrocarbons from the bottoms of the de-ethanizer tower 150 in the de-ethanizer bottoms line 154 extending from the bottoms of the de-ethanizer tower 140 can be split into a net de-ethanizer bottoms stream containing C3 hydrocarbons in the net de-ethanizer bottoms line 160 and a reboil stream that is boiled and returned to the tower. The net de-ethanizer bottoms stream in the de-ethanizer bottoms line 160 can enter a propylene recovery unit (not shown) as a C3 hydrocarbon product stream. The de-ethanizer tower 150 can be operated at a bottoms temperature of 36°C to 42°C and a top pressure of 2000 kPa to 2200 kPa.

[0049] Embodiment

[0050] We simulated the operation of the disclosed improved method and compared it with a conventional method for a 12083 m 3 / day (76000 bbl / day) unit with a stripper downstream of the absorber. The improvement of the conventional unit may only require a new refrigeration system of about $2M. The disclosed method pushes 20%-30% of the reactor vapor into the gas concentration section that usually exists, resulting in a 20%-30% greater margin. We increased the feed rate of the existing FCC unit by 20%, which we estimate will increase the gross profit margin by $69M. The improved method did not result in additional operating costs because the energy in the gas concentration section reduced due to the reduced liquid and vapor loads is balanced by the greater low-pressure steam use in the vapor absorption refrigeration cycle to maintain propylene recovery in the primary absorber.

[0051] Specific implementation plan

[0052] While the following is described in connection with specific embodiments, it should be understood that the description is intended to illustrate and not limit the scope of the foregoing description and the appended claims.

[0053] A first embodiment of the present invention is a method for recovering catalytic cracking products, the method comprising contacting a hydrocarbon stream with a catalyst stream to produce a cracked product stream; fractionating the cracked product stream in a main column; separating the overhead stream from the main column into a main net gas stream and a main overhead liquid stream; and stripping the main overhead liquid stream to provide a stripper overhead stream and a stripped bottoms stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises contacting the stripped bottoms stream with a gaseous hydrocarbon stream to absorb C3+ hydrocarbons from the gaseous hydrocarbon stream to provide an absorbed gaseous hydrocarbon stream and a rich absorbent stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises compressing the main net gas stream to provide a compressed net gas stream, and separating the compressed net gas stream to provide the gaseous hydrocarbon stream and a liquid hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises fractionating the liquid hydrocarbon stream to provide a light hydrocarbon stream and a heavy hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises contacting the gaseous hydrocarbon stream with the heavy hydrocarbon stream to absorb C3+ hydrocarbons from the gaseous hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises separating the rich absorbent stream from the compressed net gas stream to provide the gaseous hydrocarbon stream and the liquid hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises separating the light hydrocarbon stream into a vapor light hydrocarbon stream and a liquid light hydrocarbon stream and de-ethanizing the liquid light hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises compressing the vapor light hydrocarbon stream with the main net gas stream to provide the compressed net gas stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises contacting the absorbed gaseous stream with a side stream from the main column to further absorb C3+ hydrocarbons in the absorbed gaseous stream to provide a dry gas stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises recovering ethylene from the dry gas stream.

[0054] A second embodiment of the present invention is a method for recovering catalytic cracking products, the method comprising contacting a hydrocarbon stream with a catalyst stream to produce a cracked product stream; fractionating the cracked product stream in a main column; separating the overhead stream from the main column into a main net gas stream and a main overhead liquid stream; stripping the main overhead liquid stream to provide a stripper overhead stream and a stripped bottoms stream; and contacting the stripped bottoms stream with a gaseous hydrocarbon stream to absorb C3+ hydrocarbons from the gaseous hydrocarbon stream to provide an absorbed gaseous hydrocarbon stream and a rich absorbent stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises compressing the main net gas stream to provide a compressed net gas stream, and separating the compressed net gas stream to provide the gaseous hydrocarbon stream and the liquid hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises fractionating the liquid hydrocarbon stream fractionation to provide a light hydrocarbon stream and a heavy hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises contacting the gaseous hydrocarbon stream with the heavy hydrocarbon stream to absorb C3+ hydrocarbons from the gaseous hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises separating the rich absorbent stream from the compressed net gas stream to provide the gaseous hydrocarbon stream and the liquid hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises separating the light hydrocarbon stream into a vapor light hydrocarbon stream and a liquid light hydrocarbon stream and deethanizing the liquid light hydrocarbon stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises compressing the vapor light hydrocarbon stream with the main net gas stream to provide the compressed net gas stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises contacting the absorbed gaseous stream with a side stream from the main column to further absorb C3+ hydrocarbons in the absorbed gaseous stream to provide a dry gas stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises recovering ethylene from the dry gas stream.

[0055] A third embodiment of the present invention is a method for recovering catalytic cracking products, the method comprising contacting a hydrocarbon stream with a catalyst stream to produce a cracked product stream; fractionating the cracked product stream in a main column; separating the overhead stream from the main column into a main net gas stream and a main overhead liquid stream; stripping the main overhead liquid stream to provide a stripper overhead stream and a stripped bottoms stream; contacting the stripped bottoms stream with a gaseous hydrocarbon stream to absorb C3+ hydrocarbons from the gaseous hydrocarbon stream to provide an absorbed gaseous hydrocarbon stream and a rich absorbent stream; contacting the absorbed gaseous stream with a sidestream from the main column to further absorb C3+ hydrocarbons from the absorbed gaseous stream to provide a dry gas stream; and recovering ethylene from the dry gas stream.

[0056] Although no further detailed description is provided, it is believed that those skilled in the art can make the most of the present invention by using the foregoing description and can easily determine the basic features of the present invention without departing from the essence and scope of the present invention to make various changes and modifications thereto and adapt it to various uses and conditions. Therefore, the foregoing preferred specific embodiments should be construed as illustrative only and not in any way limiting the remainder of the disclosure, and are intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

[0057] In the foregoing, all temperatures are shown in degrees Celsius and all parts and percentages are by weight unless otherwise indicated.

Claims

1. A method for recovering catalytic cracking products, the method comprising: Contact a hydrocarbon stream with a catalyst stream to produce a cracked product stream; Fractionate the cracked product stream in a main column; Separate an overhead stream from the main column into a main net gas stream and a main overhead liquid stream; And Strip the main overhead liquid stream to provide a stripper overhead stream and a stripped bottoms stream.

2. The method according to claim 1, the method comprising contacting the stripped bottoms stream with a gaseous hydrocarbon stream to absorb C3+ hydrocarbons from the gaseous hydrocarbon stream to provide an absorbed gaseous hydrocarbon stream and a rich absorbent stream.

3. The method according to claim 2, the method further comprising compressing the main net gas stream to provide a compressed net gas stream and separating the compressed net gas stream to provide the gaseous hydrocarbon stream and a liquid hydrocarbon stream.

4. The method according to claim 3, the method further comprising fractionating the liquid hydrocarbon stream to provide a light hydrocarbon stream and a heavy hydrocarbon stream.

5. The method according to claim 4, the method further comprising contacting the gaseous hydrocarbon stream with the heavy hydrocarbon stream to absorb the C3+ hydrocarbons from the gaseous hydrocarbon stream.

6. The method according to claim 2, the method further comprising separating the rich absorbent stream from the compressed net gas stream to provide the gaseous hydrocarbon stream and the liquid hydrocarbon stream.

7. The method according to claim 4, the method further comprising separating the light hydrocarbon stream into a vapor light hydrocarbon stream and a liquid light hydrocarbon stream, and de-ethanizing the liquid light hydrocarbon stream.

8. The method according to claim 7, the method further comprising compressing the vapor light hydrocarbon stream with the main net gas stream to provide the compressed net gas stream.

9. The method according to claim 2, the method further comprising contacting the absorbed gaseous stream with a side stream from the main column to further absorb C3+ hydrocarbons from the absorbed gaseous stream to provide a dry gas stream.

10. The method according to claim 9, the method further comprising recovering ethylene from the dry gas stream.

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