Patent Application
20080081938
Those skilled in the art and guided by the teachings herein provided will recognize and appreciate that the illustrated system or process flow diagrams have been simplified by the elimination of various usual or customary pieces of process equipment including some heat exchangers, process control systems, pumps, fractionation systems, and the like. It may also be discerned that the process flow depicted in the figures may be modified in many aspects without departing from the basic overall concept of the invention.
A stream rich in ethylene and containing carbon dioxide can be processed to effectively and efficiently to remove carbon dioxide therefrom. Additionally, a heavy hydrocarbon feedstock can be effectively and efficiently processed via hydrocarbon cracking processing to obtain light olefins substantially free of carbon dioxide.
More particularly, a suitable ethylene-rich hydrocarbon and carbon dioxide-containing stream such as derived from hydrocarbon cracking processing of a heavy hydrocarbon feedstock, as described in greater detail below, is suitably introduced via a line 20 into the absorption zone 12.
As described above, ethylene-rich hydrocarbon and carbon dioxide-containing streams as used herein generally refer to carbon dioxide-containing hydrocarbon streams that typically contain somewhere in the range of about 0.5 mol. % to about 2.5 mol % carbon dioxide and also generally contain at least 20 percent ethylene and, in accordance with at least certain preferred embodiments alternatively contain at least 25 percent ethylene, at least 30 percent ethylene, at least 35 percent ethylene, at least 40 percent ethylene or about 40 to about 60 percent ethylene. In general, such a stream of material to be treated will typically be at a temperature of about 100-120° F. (38-49° C.) and a pressure in the range of about 2750-3450 kPag (about 400-500 psig).
An absorption solvent to affect desired CO2 absorption is introduced into the absorption zone 12 via a line 22. Suitable absorption solvents for use in the practice of the invention include various such materials such as known in the art to effect removal of CO2 and H2S. Those skilled in the art and guided by the teachings herein provided will appreciate, for example, that aqueous solutions of various amine absorption solvents such as known in the art to effect removal of CO2 and H2S can be used in the practice of the invention and thus the broader practice of the invention is not necessarily limited by or to practice with particular or specific absorption solvents. Suitable absorption solvents for use in the practice of the invention include tertiary amines such as methyl diethanol amine (MDEA), secondary amines such as diethanol amine (DEA) and diisopropanol amine (DIPA) and primary amines such as monoethanol amine (MEA), for example.
As will be appreciated by those skilled in the art and guided by the teachings herein provided, suitable absorption zones for use in the practice of the invention may desirably be in the form of a column and contains or includes an active absorber section or portion 24 such as includes trays, packing or other column internals such as may be desired to facilitate or otherwise help effect the desired absorption action. A suitable such amine system absorber, in accordance with one preferred embodiment, desirably operates at a pressure in the range of about 1720 kPag to about 3450 kPag (about 250 psig to about 500 psig), more preferably in a range of about 3100 kPag to about 3450 kPag (about 450 psig to about 500 psig), and with a bottoms temperature in the range of about 40° to about 80° C.
As shown, the point of introduction into the absorption zone 12 of the line 20 containing the stream of material to be treated, i.e., the ethylene-rich hydrocarbon and carbon dioxide-containing stream, may desirably be situated below the active absorber section 24 and the point of introduction into the absorption zone 12 of the line 22 containing the stream of the absorption solvent may desirably be situated above the active absorber section 24, such that the absorption solvent and the material to be treated within the absorption zone are in at least a general countercurrent flow arrangement. Moreover, such placement of the points of introduction of the stream of material to be treated and the absorption solvent, respectively, can desirably maximize the effect of any column internals and the effective contact time and residence time of the stream materials within the active absorber section 24.
A stream of treated gas is withdrawn from the absorption zone 20 via an overhead line 26. Prior to exiting the absorption zone 20, the gas is passed through a wash zone 30 where a wash material such as water is introduced through a line 32 to contact the treated gas and to desirably remove entrained absorption solvent that may have remained therewith. The used wash material containing such removed absorbent material is withdrawn from the absorption zone via a line 34 and can desirably be sent for absorption solvent recovery processing (not shown), as is known in the art.
It is to be understood that the treated gas in the overhead line 26 or one or more selected portions thereof may, if desired, be subjected to additional processing (not shown) such as via a caustic treatment step to ensure that the CO2 and H2S have been suitably removed to the level required for desired light olefin product specifications.
A carbon dioxide-rich absorption solvent-containing process stream is withdrawn from the absorption zone 12 via a line 36. The carbon dioxide-rich absorption solvent-containing process stream or at least a portion thereof is passed via a valve 40 and a line 42 to the first stripping zone 14.
As will be appreciated by those skilled in the art and guided by the teachings herein provided, suitable first stripping zones for use in the practice of the invention may desirably be in the form of a column and contains or includes an active stripping section or portion 44 such as includes a selected number of trays or other stripping column internals such as may be desired to facilitate or otherwise help effect the desired stripping action. As shown, the point of introduction into the first stripping zone 14 of the line 42 containing the stream of carbon dioxide-rich absorption solvent may desirably be situated above the active stripping section 44 and the point of introduction into the first stripping zone 14 of a line 46 containing a stream of a selected stripping fluid may desirably be situated below the active stripping section 44, such that the stripping fluid and the material to be treated within the first stripping zone 14 are in at least a general countercurrent flow arrangement. Moreover, such placement of the points of introduction of the stream of material to be treated and the stripping fluid, respectively, can desirably maximize the effect of any column internals and the effective contact time and residence time of the stream materials within the first stripping zone active stripping section 44.
Thus, whereas conventional amine treatment systems such as used in the treatment of conventional FCC effluent streams may simply employ a flash column, the incorporation and use of a stripping zone such as the above-described first stripping zone 14 helps ensure the desired separation present hydrocarbons including ethylene and propylene such as may otherwise be more strongly physisorbed than non-olefinic hydrocarbons.
In accordance with one preferred embodiment, the first stripping zone 14 desirably includes a stripper column such as having typically less than 15 ideal stages and generally no more than about 8-12 ideal stages.
The first stripping zone 14 is desirably operated in a manner, including first stripping conditions, effective to strip at least a portion of hydrocarbons remaining in the carbon dioxide-rich absorption solvent-containing process stream therefrom and to form a first process stream containing stripped hydrocarbons and a second process stream containing carbon dioxide and absorption solvent. Suitable such stripping conditions generally include: an operating pressure such as in the range of about 34 kPag to about 173 kPag (about 5 psig to about 25 psig) or, in accordance with one preferred embodiment in the range of about 34 kPag to about 69 kPag (about 5 psig to about 10 psig). Moreover, the feed rate to this stripper is desirably set so that the combined amount of ethylene and propylene in the stripper bottoms is less than 100 ppm and, in accordance with a preferred embodiment the feed rate to this stripper is desirably set so that the combined amount of ethylene and propylene in the stripper bottoms is less than 5 ppm.
A stream containing stripped hydrocarbons, including stripped ethylene and stripped propylene, is withdrawn from the first stripping zone 14 via an overhead line 50. As will be appreciated by those skilled in the art, the stream withdrawn in such overhead line may in addition to stripped hydrocarbons including ethylene and propylene also contain some minor amount, e.g., typically less than 1 wt. % of carbon dioxide.
The line 50 and the stream of stripped hydrocarbons and CO2 contained therewithin can be sent for further processing such as is known in the art. For example, in accordance with one preferred embodiment, such stream or at least selected portions thereof can desirably be returned to the main column receiver so as to permit desired olefin recovery therefrom. Those skilled in the art and guided by the teachings herein provided will appreciate that while such return and processing may lead to the recycle of some CO2, the amount of such recycle in practice will generally not be so significant as to make such processing uneconomical.
A process stream primarily containing absorption solvent and remaining carbon dioxide is withdrawn from the first stripping zone 14 via a line 52. The process stream in the line 52 is passed through a pump 54, a line 56, a lean/rich CO2 stream heat exchanger 60 and a line 62 into the second stripping zone 16.
As will be appreciated by those skilled in the art and guided by the teachings herein provided, suitable second stripping zones for use in the practice of the invention may desirably be in the form of a column and contains or includes an active stripping section or portion 64 such as includes a selected number of trays or other stripping column internals such as may be desired to facilitate or otherwise help effect the desired stripping action. As shown, the point of introduction into the second stripping zone 16 of the line 62 containing absorption solvent and remaining carbon dioxide may desirably be situated above the active stripping section 64 and the point of introduction into the second stripping zone 16 of a line 66 containing a stream of a selected stripping fluid may desirably be situated below the active stripping section 64, such that the stripping fluid and the material to be treated within the second stripping zone 16 are in at least a general countercurrent flow arrangement. Moreover, such placement of the points of introduction of the stream of material to be treated and the stripping fluid, respectively, can desirably maximize the effect of any column internals and the effective contact time and residence time of the stream materials within the second stripping zone active section 64.
The second stripping zone 16 is desirably operated in a manner, including second stripping conditions, effective to strip at least a portion of the carbon dioxide from the second process stream to form a carbon dioxide overhead stream, shown as a line 70, an absorption solvent bottoms stream, shown as a line 72, that is substantially free of carbon dioxide.
In general it is preferred to operate at as low a pressure as possible in order to most appropriately limit the temperature of the bottoms stream. In practice, suitable such stripping conditions generally include: an operating pressure such as in the range of about 103 kPag to about 138 kPag (about 15 psig to about 20 psig).
Prior to exiting the second stripping zone 16, the carbon dioxide overhead stream materials are passed through a wash zone 74 where a wash material, such as water, is introduced through a line 76 to contact the stripped materials and to desirably remove entrained absorbent solvent that may have remained therewith. The used wash material containing such removed absorption solvent is withdrawn from the second stripping zone 16 via a line 78 and can desirably be processed in a manner as is known in the art, such as to provide additional stripping vapor.
If desired and as shown, a first portion of the CO2 overhead stream 70 can be returned to the first stripping zone 14 such as via the line 46 for use as a stripping fluid therein. A second or remaining portion of the CO2 overhead stream 70 can form a purge stream, shown as in a line 80.
A first portion of the absorption solvent bottoms stream from the line 72 can pass through a line 82 to a reboiler 84 and through the line 66 back into the second stripping zone 16. A second portion of the absorption solvent bottoms stream from the line 72 can pass through a line 90 to the lean/rich CO2 stream heat exchanger 60 and then through lines 92 and 94 to a recirculation pump 96 and then through lines 100 and 22 to be appropriately introduced into the absorption zone 12. A portion of the absorption solvent material in the line 100 can be processed via a line 102 through a filter device 104 and then back through a line 106 to form a portion of the stream of material in the line 94 introduced into the recirculation pump 96.
As will be appreciated by those skilled in the art and guided by the teachings herein provided, conventional amine system treatment processing may generally involve a tradeoff involving operating pressure. At low pressure operation, there is generally reduced or minimal coabsorption of hydrocarbon, but the required rate for solvent recycle is relatively large. In contrast, at high pressure operation, the solvent flow rate may desirably be reduced, but more hydrocarbons (in the case of the processing of the subject ethylene-rich streams, particularly ethylene and propylene) may be coabsorbed. With a subject amine treatment section such as described above, however, such coabsorbed ethylene and propylene is desirably recovered via the first stripping zone 14 such that the overall loss of light olefins due to amine treatment is minimized or avoided. Consequently, the subject amine treatment section can desirably be operated at relative higher pressures such as to reduce or minimize solvent recirculation. Thus, in accordance with a preferred embodiment, the absorption zone 12 and the amine absorber thereof are advantageously located at a high, if not highest, pressure location in the process scheme in order to minimize solvent recirculation.
The first stripping zone will generally operate most efficiently and require the least amount of CO2 recirculation when operated at relatively low pressures. In the above-described embodiment, such as when the stream of hydrocarbons in the first stripper overhead line 50 is returned to the main column receiver, such as operates at about 34 kPag (5 psig), the pressure in the first stripping zone 14 generally needs to be high enough to permit the return of such off-gas stream to the main column receiver while allowing for line pressure drops, e.g., slightly greater than the main column receiver operating pressure.
The second stripping zone will generally operate at a pressure high enough to permit CO2 to be desirably circulated to the lower portion of the first stripping zone stripper while allowing for line and unit pressure drops. This obviates the need to use a recycle blower in order to return CO2 to the first stripping zone. Consequently, in a preferred embodiment, the second stripping zone preferably operates at a pressure greater than the operating pressure of the first stripping zone.
Thus, effective and efficient amine system processing of high olefin content (e.g., ethylene-rich) carbon dioxide-containing streams such as for the effective separation and removal of carbon dioxide therefrom while desirably permitting increased or improved olefin recovery are provided.
The treatment of ethylene-rich hydrocarbon and carbon dioxide-containing streams in the manner described above can find particular application in the production of light olefins via the catalytic cracking of a heavy hydrocarbon feedstock.
Turning to
In the system 210, a suitable heavy hydrocarbon feedstock stream is introduced via a line 212 into a fluidized reactor zone 214 wherein the heavy hydrocarbon feedstock contacts with a hydrocarbon cracking catalyst zone to produce a hydrocarbon effluent comprising a range of hydrocarbon products, including light olefins, and a quantity of carbon dioxide.
Suitable fluidized catalytic cracking reactor zones for use in the practice of such an embodiment may, as is described in above-identified U.S. Pat. No. 6,538,169 B1 to Pittman et al., include a separator vessel, a regenerator, a blending vessel, and a vertical riser that provides a pneumatic conveyance zone in which conversion takes place. The arrangement circulates catalyst and contacts feed in a specifically described manner.
More specifically and as described therein, the catalyst typically comprises two components that may or may not be on the same matrix. The two components are circulated throughout the entire system. The first component may include any of the well-known catalysts that are used in the art of fluidized catalytic cracking, such as an active amorphous clay-type catalyst and/or a high activity, crystalline molecular sieve. Molecular sieve catalysts are preferred over amorphous catalysts because of their much-improved selectivity to desired products. Zeolites are the most commonly used molecular sieves in FCC processes. Preferably, the first catalyst component comprises a large pore zeolite, such as a Y-type zeolite, an active alumina material, a binder material, comprising either silica or alumina and an inert filler such as kaolin.
The zeolite molecular sieves appropriate for the first catalyst component should have a large average pore size. Typically, molecular sieves with a large pore size have pores with openings of greater than 0.7 nm in effective diameter defined by greater than 10 and typically 12 membered rings. Pore Size Indices of large pores are above about 31. Suitable large pore zeolite components include synthetic zeolites such as X-type and Y-type zeolites, mordenite and faujasite. It has been found that Y zeolites with low rare earth content are preferred in the first catalyst component. Low rare earth content denotes less than or equal to about 1.0 wt-% rare earth oxide on the zeolite portion of the catalyst. Octacat™ catalyst made by W. R. Grace & Co. is a suitable low rare earth Y-zeolite catalyst.
The second catalyst component comprises a catalyst containing, medium or smaller pore zeolite catalyst exemplified by ZSM-5, ZSM-11, ZSM-12, ZSM-23, ZSM-35, ZSM-38, ZSM-48, and other similar materials. U.S. Pat. No. 3,702,886 describes ZSM-5. Other suitable medium or smaller pore zeolites include ferrierite, erionite, and ST-5, developed by Petroleos de Venezuela, S.A. The second catalyst component preferably disperses the medium or smaller pore zeolite on a matrix comprising a binder material such as silica or alumina and an inert filer material such as kaolin. The second component may also comprise some other active material such as Beta zeolite. These catalyst compositions have a crystalline zeolite content of 10-25 wt. % or more and a matrix material content of 75-90 wt. %. Catalysts containing 25 wt. % crystalline zeolite material are preferred. Catalysts with greater crystalline zeolite content may be used, provided they have satisfactory attrition resistance. Medium and smaller pore zeolites are characterized by having an effective pore opening diameter of less than or equal to 0.7 nm, rings of 10 or fewer members and a Pore Size Index of less than 31.
The total catalyst composition should contain 1-10 wt. % of a medium to small pore zeolite with greater than or equal to 1.75 wt. % being preferred. When the second catalyst component contains 25 wt. % crystalline zeolite, the composition contains 4-40 wt. % of the second catalyst component with a preferred content of greater than or equal to 7 wt. %. ZSM-5 and ST-5 type zeolites are particularly preferred since their high coke resistivity will tend to preserve active cracking sites as the catalyst composition makes multiple passes through the riser, thereby maintaining overall activity. The first catalyst component will comprise the balance of the catalyst composition. The relative proportions of the first and second components in the catalyst composition will not substantially vary throughout the FCC unit.
The high concentration of the medium or smaller pore zeolite in the second component of the catalyst composition improves selectivity to light olefins by further cracking the lighter naphtha range molecules. But at the same time, the resulting smaller concentration of the first catalyst component still exhibits sufficient activity to maintain conversion of the heavier feed molecules to a reasonably high level.
The relatively heavier feeds suitable for processing in accordance herewith include conventional FCC feedstocks or higher boiling or residual feeds. A common conventional feedstock is vacuum gas oil which is typically a hydrocarbon material prepared by vacuum fractionation of atmospheric residue and which has a broad boiling range of from 315-622° C. (600-1150° F.) and, more typically, which has a narrower boiling point range of from 343-551° C. (650-1025° F.). Heavy or residual feeds, i.e., hydrocarbon fractions boiling above 499° C. (930° F.), are also suitable. The fluidized catalytic cracking processing the invention is typically best suited for feedstocks that are heavier than naptha range hydrocarbons boiling above about 177° C. (350° F.).
The effluent or at least a selected portion thereof is passed from the fluidized reactor zone 214 through a line 216 into a hydrocarbon separation system 220, such as includes a main column section 222 and a staged compression section 224. The main column section 222 may desirably include a main column separator with an associated main column overhead high pressure receiver wherein the fluidized reactor zone effluent can be separated into desired fractions including a main column vapor stream, such as passed through a line 226, and a main column liquid stream, such as passed through a line 230.
To facilitate illustration and discussion, other fraction lines such as including a heavy gasoline stream, a light cycle oil (“LCO”) stream, a heavy cycle oil (“HCO”) stream and a clarified oil (“CO”) stream, for example, may not here be shown nor hereinafter specifically described.
The main column vapor stream line 226 is introduced into the staged compression section 224, such as constituting a two-stage compression. The staged compression section 224 results in the formation of a high pressure separator liquid stream in a line 232 and a high pressure separator vapor stream in a line 234. While the pressure of such high pressure liquid and high pressure vapor can vary, in practice such streams are typically at a pressure in the range of about 1375 kPag to about 2100 kPag (about 200 psig to about 300 psig). The compression section 224 may also result in the formation of a stream of spill back materials largely composed of heavier hydrocarbon materials and such as can be returned to the main column section 222 via a line 235.
The high pressure separator liquid stream includes C3+ hydrocarbons and is substantially free of carbon dioxide. The high pressure separator vapor stream includes C3− hydrocarbons and includes a quantity of carbon dioxide.
The separator vapor stream line 234 is introduced into an absorption zone, generally designated by the reference numeral 236, via a line 237. The absorption zone 236 includes a primary absorber 240 wherein the separator vapor stream contacts with a debutanized gasoline material provided by the line 242 and the main column liquid stream provided by the line 230 to absorb C3+ and separate C2 and lower boiling fractions from the gas to the primary absorber 240. In general, the absorption zone 236 includes a primary absorber that suitably includes a plurality of stages with at least one and preferably two or more intercoolers interspaced therebetween to assist in achieving desired absorption. In practice, such a primary absorber typically includes about five absorber stages between each pair intercoolers. Thus, a primary absorber to achieve desired absorption in accordance with one preferred embodiment desirably includes at least about 15 ideal stages with at least 2 intercoolers appropriately spaced therebetween. In another preferred embodiment, a suitable preferred primary absorber to achieve desired absorption desirably includes at least about 20 ideal stages with at least 3 intercoolers appropriately spaced therebetween. In yet another preferred embodiment, a suitable preferred primary absorber to achieve desired absorption desirably includes at about 20 to about 25 ideal stages with 4 or more intercoolers appropriately spaced therebetween. While the broader practice of the invention is not necessarily so limited, in at least certain preferred embodiments, it has been found advantageous to employ propylene as a refrigerant in one or more of such primary absorber the intercoolers to assist in achieving the desired absorption.
C3+ hydrocarbons absorbed in or by the debutanized gasoline and main column liquid can be passed via a line 243 for further processing in accordance with the invention as later described herein.
The off gas from the primary absorber 240 passes via a line 244 to a secondary or sponge absorber 246. The secondary absorber 246 contacts the off gas with light cycle oil from a line 250. Light cycle oil absorbs most of the remaining C4 and higher hydrocarbons and returns to the main fractionators via a line 252. A stream of C2− hydrocarbons is withdrawn as off gas from the secondary or sponge absorber 246 in a line 254 for further treatment as later described herein.
The separator liquid stream in the line 232 and contents from the line 243 are passed through a line 260 into a stripper 262 which removes most of the C2 and lighter gases in a line 264. In practice, such a stripper can desirably be operated at a pressure in the range of about 1650 kPag to about 1800 kPag (about 240 psig to about 260 psig) with a C2/C3 molar ratio in the stripper bottoms of less than 0.001 and preferably with a C2/C3 molar ratio in the stripper bottoms of less than about 0.0002 to about 0.0004.
As shown, C2 and lighter gases in the line 264 can desirably be combined with high pressure separator vapor from the line 234 to form the line 237 that is fed into the primary absorber 240. The stripper 262 supplies a liquid C3+ stream via a line 266 to a debutanizer 270. A suitable such debutanizer, in accordance with one preferred embodiment, includes a condenser (not specifically shown) that desirably operates at a pressure in the range of about 965 kPag to about 1105 kPag (about 140 psig to about 160 psig), with no more than about 5 mol % C5 hydrocarbons in the overhead and no more than about 5 mol % C4 hydrocarbons in the bottoms. More preferably, the relative amount of C5 hydrocarbons in the overhead is less than about 1-3 mol % and the relative amount of C4 hydrocarbons in the bottoms is less than about 1-3 mol %.
A stream of C3 and C4 hydrocarbons from the debutanizer 270 are taken overhead by a line 272 for further treatment, such as later described herein.
A line 274 withdraws a stream of debutanized gasoline from the debutanizer 270. A portion of the stream of debutanized gasoline is returned to the primary absorber 240 via the line 242 to serve as the first absorption solvent. Another portion of the stream of debutanized gasoline is passed in a line 276 to a naptha splitter 280.
In accordance with one preferred embodiment, the naptha splitter 280 is desirably in the form of a dividing wall separation column, such as having a dividing wall 281 positioned therewithin. Such a dividing wall separation column naptha splitter is desirably effective to separate the debutanized gasoline introduced therein into a light fraction stream comprising compounds containing five to six carbon atoms, an intermediate fraction stream comprising compounds containing seven to eight carbon atoms, and a heavy fraction stream comprising compounds containing more than eight carbon atoms. More specifically, such a dividing wall separation column may generally operate at a condenser pressure in the range of about 34 kPag to about 104 kPag (about 5 psig to about 15 psig) and, in accordance with one embodiment operated at a condenser pressure of about 55 kPag to about 85 kPag (about 8 psig to about 12 psig).
Such light, intermediate and heavy fraction streams, are appropriately passed via corresponding lines 282, 284, and 286, respectively, for further processing or product recovery, as may be desired.
Returning to the processing of the stream of C2− hydrocarbons withdrawn from the secondary or sponge absorber 246 in the line 254, such stream materials can be passed through a further compression section 290 to form a line 292 that is passed into a compression or discharge drum 294. The discharge drum 294 forms a knockout stream generally composed of heavy components (e.g., C3+ hydrocarbons that liquefy in the discharge drum 294) and such as withdrawn in a line 296. The discharge drum 294 also forms an overhead stream that primarily comprising C2− hydrocarbons, with typically no more than trace amounts (e.g., less than 1 wt. %) of C3+ hydrocarbons, and a quantity of carbon dioxide, withdrawn in a line 300.
The overhead stream in the line 300 is passed to an amine treatment section 302 such as described above, to effect CO2 removal therefrom. A stream containing C2− hydrocarbons substantially free of carbon dioxide is passed through a line 304 to a drier section 306 with water withdrawn therefrom in a line 307. A stream containing stripped hydrocarbons and possibly minor amounts (e.g., typically less than 1 wt. %) of CO2 is conveyed via a line 308 such as back to the compression section 224 such as for further processing such as consistent with the above description. A stream containing CO2 rich purge gas, such as corresponding to the purge line 80 from the second stripping zone 16 in the above-described amine treatment system 10, is conveyed from the amine treatment section 302 via a line 309.
A stream containing dried C2− hydrocarbons substantially free of carbon dioxide is passed via a line 310 to an acetylene conversion section or unit 320. As is known in the art, acetylene conversion sections or units are effective to convert acetylene to form ethylene. Thus, an additionally ethylene-enriched process stream is withdrawn in a line 322 from the acetylene conversion section or unit 320.
As the acetylene conversion may result in additional formation of water, the process stream in the line 322 can, if desired, be introduced into an optional drier unit 324 such as with water being withdrawn therefrom in a line 326 and with the resulting dried process stream passed via a line 330 to an optional further treatment section 332 such as in the form of a CO2, carbonyl sulfide (“COS”), Arsine and/or Phosphine treater as is known in the art to effect removal of CO2, COS, Arsine and/or Phosphine, withdrawn in a line 334, and a treated stream such as withdrawn in a line 336.
The treated stream in the line 336 may desirably be introduced into a demethanizer 340. A suitable such demethanizer, in accordance with one preferred embodiment, includes a condenser (not specifically shown) that desirably operates at a temperature of no greater than about −90° C. (−130° F.), more preferably operates at a temperature in the range of about −90° C. to about −102° C., preferably about −96° C. (−130° to about −150° F., preferably at about −140° F.). In addition, a preferred demethanizer for use in the practice of the invention desirably operates with a methane to ethylene molar ratio in the bottoms of no greater than about 0.0005 and, more preferably at a methane to ethylene molar ratio in the bottoms of no greater than about 0.0003 to about 0.0002.
A stream of methane and hydrogen gas from the demethanizer 340 is taken overhead via a line 342 such as for use as a fuel or, if desired for further processing or treatment such as to a pressure swing absorption unit (not shown) for H2 recovery.
A line 344 withdraws a stream of demethanized material from the demethanizer 340. The line demethanized material 344 is passed to an ethylene/ethane splitter 346. A suitable such ethylene/ethane splitter, in accordance with one preferred embodiment, includes a condenser (not specifically shown) that desirably operates at a pressure in the range of about 1930 kPag to about 2105 kPag (about 280 psig to about 305 psig), and desirably operates such that there is no more than about 0.5 vol. % ethane in the ethylene product stream, preferably less than about 0.1 vol. % ethane in the ethylene product stream and, more preferably, less than about 0.05 vol. % ethane in the ethylene product stream.
The ethylene/ethane splitter 346 forms a vapor stream of remaining light ends, a partial condensate stream of ethylene and a bottoms stream of ethane which are passed through lines 350, 352 and 354, respectively, such as either for product recovery or further desired processing, as is known in the art.
Returning to the processing of the stream containing C3 and C4 hydrocarbons taken overhead from the debutanizer 270 via the line 272, as such a process stream may contain some significant relative amounts of hydrogen sulfide, the line 272 can desirably be passed to a sulfide removal treatment unit 360 such as known in the art, such as in the form of an amine treatment section, such as to form a treated stream passed via a line 362. The hydrogen sulfide content of the treated stream is desirably reduced down to about 20 ppm, with hydrogen sulfide being removed via a line 364.
If desired or required, the treated stream line 362 can be introduced into an optional caustic treatment or the like section 366 such as to effect further hydrogen sulfide removal such as down to a hydrogen sulfide content of 1 ppm or less. Hydrogen sulfide is shown as removed from the caustic treatment section 366 via a line 370.
A treated stream with an appropriately reduced hydrogen sulfide content is passed via a line 372 to a mercaptan treatment section 374, such as to effect mercaptan removal from the stream materials such as via caustic wash as is known in the art. Mercaptans are shown as removed via a line 376.
The resulting stream is passed via a line 380 to C3/C4 splitter 382. A suitable such C3/C4 splitter, in accordance with one preferred embodiment, includes a condenser (not specifically shown) that desirably operates at a pressure in the range of about 1650 kPag to about 1800 kPag (about 240 psig to about 260 psig), preferably at a pressure of about 1724 kPag (about 250 psig) and desirably operates such that there is no more than about 5 mol. % C4S in the overhead product stream, preferably less than about 1 mol. % C4s in the overhead product stream and no more than about 5 mol. % C3s in the bottoms stream, preferably less than about 1 mol. % C3s in the bottoms stream.
The C3/C4 splitter 382 forms a stream of C4+ hydrocarbons which is passed through a line 384 such as either for product recovery or further desired processing, as is known in the art.
The C3/C4 splitter 382 also forms a stream composed primarily of C3 hydrocarbons which is passed through a line 386.
The stream in the line 386 can be passed to a propylene/propane splitter 390. A suitable such propane/propylene splitter, in accordance with one preferred embodiment, desirably operates such that at least 98 wt. % and, preferably, at least about 99 wt. % of the propylene recovery is in the overhead stream and the propylene in the overhead stream is at least about 99.5% pure.
The propylene/propane splitter 390 forms a stream of propylene and a stream of propane which are passed through lines 392 and 394, respectively, such as either for product recovery or further desired processing, as is known in the art.
Thus processing schemes and arrangements are desirably provided for obtaining light olefins substantially free of carbon dioxide via the catalytic cracking of a heavy hydrocarbon feedstock. More particularly, processing schemes and arrangements are provided that advantageously utilize absorption separation of hydrocarbon effluent products to produce or otherwise form process streams containing specifically desired ranges of hydrocarbons.
The invention illustratively disclosed herein suitably may be practiced in the absence of any element, part, step, component, or ingredient which is not specifically disclosed herein.
While in the foregoing detailed description this invention has been described in relation to certain preferred embodiments thereof, and many details have been set forth for purposes of illustration, it will be apparent to those skilled in the art that the invention is susceptible to additional embodiments and that certain of the details described herein can be varied considerably without departing from the basic principles of the invention. For example, while the invention has been described above making specific reference to an embodiment wherein the amine treatment section 302 is placed downstream of the further compression section 290, those skilled in the art and guided by the teachings herein provided will appreciate that the broader practice of the invention is not necessarily so limited. This in certain embodiments it may be desired that the amine treatment section be disposed upstream of such further compression.
