PROCESS FOR THE RECOVERY AND RECYCLE OF EFFLUENT GAS FROM THE REGENERATION OF PARTICULATE MATTER WITH OXYGEN AND CARBON DIOXIDE

Abstract: A unique process arrangement is disclosed wherein the effluent flue gas stream (23) from the removal of hydrocar­ bonaceous coke from particulate matter by combustion in a mixture of pure oxygen diluted with carbon dioxide is pro­ cessed to provide a carbon dioxide-rich recycle gas stream (51) to be mixed with oxygen as regenerator feed gas; and a net combustion product stream (50) from which are re­ covered SO x and NO x to eliminate atmospheric emissions, and a pure CO₂ product for export. An alternate embodiment also produces hydrogen or synthesis gas for export.

Description: A PROCESS FOR THE RECOVERY AND RECYCLE OF EFFLUENT GAS FROM THE REGENERATION OF PARTICULATE MATTER WITH OXYGEN AND CARBON DIOXIDE CROSS REFERENCE TO RELATED APPLICATIONS This application is a contlnuatSon-1n-part of U.S. Application Serial No. 404,676 filed August 3, 1982. TECHNICAL FIELD The present invention is directed to the field of hydrocarbonaceous coke removal from particulate matter by combustion in a gas mixture of commercially pure oxygen diluted with carbon dioxide. A unique process arrangement is disclosed for the recovery of flue gas effluent from the combustion of coke in a mixture of pure oxygen diluted with carbon dioxide, and the processing of effluent to produce a carbon dioxide rich recycle gas stream to be mixed with the pure oxygen, as the combustion feed gas, and a net combustion product stream from which are recovered SOx and NO to eliminate atmospheric emissions, and a pure CO2 product for export. An alternate embodiment also produces hydrogen or synthesis gas for export. BACKGROUND OF THE PRIOR ART Wlth the exhaustion of many sources of high quality petroleum resources, the refining industry has turned to the recovery and refining of less desirable petroleum stocks and to the further refining of residues from refinlng,operatlons of traditional or higher quality petroleum stocks. The refining of low quality stock or the heavy residues from the refining of htgh quality stocks present problems for the reflntng industry with respect to the capability of the refining process to handle more complex hydrocarbons of higher molecular weight as well as increased carbon residue, organometallic, nitrogen and sulfur contaminants. A traditional refining technique has been the use of a fluidized bed catalytic cracker for refining of petroleum stocks. Despite the agitation and inherent abrasion of catalyst in a flutdized bed reactor, the cracking operation which occurs tn petroleum refining leaves the particulate catalyst in an inactivated state due to coke buildup on the surface of the catalyst. In order to perform a relatively steady state operation in the fluidized catalytic cracker1 it is necessary to remove coked catalyst fro the reactor on a continuous basis and to regenerate such catalyst. The regenerated catalyst is then returned to the fluidized catalytic cracker reactor without shut down of the latter. Regeneration is usually performed in a fluidized bed with an upflowing oxidant gas at elevated temperatures in the regenerator. In thins manner, coke on the catalyst ts burned and removed as carbon monoxide, carbon dioxide and water. This exothermic combustion provides heat which is absorbed by the regenerator catalyst, and the heated catalyst is returned to the fluidized bed catalytic cracker reactor wherein the regeneratton heat is utilized in the endothermic cracktng process. As healer and healer petroleum stocks are refined in this manner, additional coking of the catalyst occurs, and additional contamination of the catalyst with nitrogen and sulfur constttuents is experienced. The removal of such coke requires a given through-put of oxidant gas. As the coke on catalyst value has gone up with the refining of such heavy residual petroleum sttks, the necessity for more gas through-put in the regenerator has occurred, and this requirement has been the limiting factor on the amount of heavy residual petroleum stock which may be processed in the fluidized catalytic cracker reaction zone. Additionally, as coke on catalyst goes up, more coke burning occurs in regeneration and added heat releases become a limitation on restduum processing. The traditional oxtdant gas used in a regenerator is air. In order to meet the through-put requlrements of regenerators experiencing elevated levels of coke on catalyst, the industry has utilized oxygen-enrlched air mixtures tn order to complete the combustlon requirements necessary for removal of the coke from the catalyst without exceeding velocity llmltatlons). However, this results in a regenerator temperature increase. McGovern, et al. in U.S. Patent 4,370,222 teaches that oxygen enriched air coupled with heat removal from the catalyst by steam coils or catalyst coolers can achieve increased coke burning capacity within temperature and velocity constratnts-. Miguerian, et al. in U.S. Patent 4,300,997 have taught a hot regeneration technique using special catalyst in the fluidized catalytic cracker that promotes the burning of carbon monoxide to carbon dioxide with attendant higher temperatures and velocities in the regenerator and increased heat release. The special catalyst sorbs at least some of the sulfur oxides, but the nitrogen oxides remain untreated. It is known to utilize an oxygen-containing gas which is diluted with various inert gases. In U.S. Patent 4,146,463, a process ts set forth wherein an oxygen-containing gas, such as air is diluted with moderators, such as carbon dioxide, nitrogen or regenerator recycle gas as the oxidant for the coked catalyst. Sulfur oxides and carbon monoxide from other portions of the refinery are also introduced into the regenerator. In U.S. Patent 4,118,339, a process is disclosed wherein the effluent gas from a fluidized catalytic cracker regenerator is controlled by the introduction of a noble metal oxidation promoter-contalntng solvent into the regeneration zone. The promoter catalyzes essentially complete combustion of the regenerator carbon monoxide and results in operation at higher temperatures wlth zeolite thermally stable catalysts and avoids the carbon monqxide pollutant problem encountered wlth previous regeneration techniques. The increased regeneration gas, heat release and regeneration temperature, however, intensify these limitations with heavy residuum feeds. U.S. Patent 4,274,942 discloses a process for the regeneration of fluidized catalytic cracker catalyst wherein control of the sulfur oxide emissions is performed by senstng the output from the regeneration zone and pretreating the coked catalyst with steam before regeneration is performed. In the conventional regeneration of catalyst, atr or oxygen-enriched air results in a large amount of nitrogen being passed through the regenerating catalyst wtth no beneficial effect. Such effluent gases generally contain nitrogen, carbon dioxide, carbon monoxide, oxygen, hydrogen sulftde, sulfur oxides and nitrogen oxides. The high nitrogen EMI4.1 content of the effluent gas renders the recovery of the carbon dioxide and the conversion of carbon monoxide to hydrogen impractical and uneconomical. In addition, the sulfur and nitrogen oxides and the carbon monoxide constitute a pollution problem. This problem is heightened by the processing of heavy residuum which contatns high levels of nitrogen and sulfur constituents. The use of mixtures of essentially pure oxygen diluted with flue gas or other invert gases, such as CO2, for the fluidization/combustion gas mixture in an FCC regenerator ts taught by Pratt, et al. in U.S. Patent 4,304,659. Since flue gas is typically 80-90X nltrogen when alr is the combustion gas, dilution of pure oxygen with flue gas has nearly the same effect on the regenerator heat balance and gas velocity as oxygen enrichment of air The use of a mixture of essentially pure oxygen and C02 as the FCC regenerator combustion gas however, has a significant effect on the regenerator heat balance and gas velocity. The benefits of 02/C02 combustion gas mixtures are taught by Rowe in U.S. Patent 4,388,218. Rowe also recognizes that FCC flue gas containing carbon monoxide can be processed to obtain a CO enriched chemical feedstock. However, no process scheme is proposed to recover CO2 from the flue gas for recycling to the regenerator, or CO for chemical feedstock, nor is elimination of flue gas sulfur emissions contemplated. Different dry and wet flue gas scrubbing technologies are available for eliminating more than 90X of the sulfur oxide emissions from the FCC flue gas. Reeder, et al. teaches in U.S. Patent 3,970,740 that catalyst fines and acid gases can be removed by inection of an aqueous scrubbing mixture in a defined pH range controlled by addition of NaOH or other caustic material. This process is practical when scrubbing flue gas containing predominantly nitrogen, but the NaOH consumption is significantly increased when the flue gas is predominantly CO. A EMI4.2 razor water EMI4.3 problem also results. kosseim, et al. in U.S. Patent 4,201,752 teach a process for selective absorption of sulfur oxides from flue gas streams containing 10-15% C02 and predominantly nitrogen. Again, flue gas containing predominantly carbon dioxide would result in significant CO2 coabsorption and make this process unattractive. Schorfheide teaches the use of mixtures of O2 and CO2 to regenerate catalytic reformer noble metal catalyst in U.S. Patent 4,354,925. The benefit of increased heat removal allows regeneration with hlgher oxygen concentration resulting in significantly increased combustlon rates. An integrated continuous recycle process is not proposed for this cyclic, non-steady state regeneration operatlon. Additional patents of interest include U.S. Patent 2,322,075, U.S. Patent 3,838,036, U.S. Patent 3,844,973, U.S. Patent 4,036,740, U.S. Patent 4,176,084, U.S. Patent 4,206,038 and U.S. Patent 4,300,997. The prior art has recognized the use of oxygen and carbon dioxide mixtures as combustion gas in FCC catalyst regenerators, as well as in catalytic reformer noble metal catalyst regeneration, to burn coke from the spent catalyst and thereby regenerate it for further use. No where in the prior art is an integrated processing scheme taught for the regeneration of catalyst with a mixture of pure oxygen diluted with carbon dioxide, the recovery and recycle of CO2 from effluent flue gas to the regenerator, the recovery and processing of the net CO and CO2 combustion products to saleable products, and the essentially complete elimination of atmospheric emissions by recovery of concentrated SOX, NOX or H2S streams for further processing. While the increased coke burning capacity benefits of using 2 and CO2 mixtures for FCC catalyst regeneration have been recognlzed in the prior art, these mlxtures are not used because the cost of oxygen is so high. However, the integrated process of this invention achieves the FCC coke burning capacity benefits while producing hydrogen and carbon dioxide products for sale and eliminating sulfur and nitrogen oxide atmospheric emissions completely, resulting in an economically attractive way to process high coke yielding feedstocks in an FCC unit without the addition of internal heat removal systems to cool the catalyst. Other fluidized processing systems wherein hydrocarbonaceous coke is removed from particulate matter by combustion in air are described by U.S. Patent 4,243,514 for the treatment of asphalt residuum in a bed of inert particulate matter, U.S. Patent 2,527,575 for fluld coking of residuum, and U.S. Patent 3,661,543 for gasifying fluidized coke. The use of pure oxygen diluted with carbon dioxide can benefit these processes in the same manner as it benefits the regeneration of fluid catalytic cracking catalyst, but the cost of oxygen and carbon dioxide have up to now prevented commercial applications. BRIEF SUMMARY OF THE INVENTION The present invention is directed to a process for the recovery, treatment and recycle of a carbon dioxide rich recycle gas as well as the separation of a net combustion product stream from the effluent flue gas from the combustion in a combustion zone of hydrocarbonaceous coke from particulate matter using a mixture of coninercially pure oxygen diluted with carbon dioxide from the recycle gas, such process comprising the steps of: recovering the effluent gas from sald combustion which contains carbon monoxide, carbon dioxide, oxygen, sulfur oxides, nitrogen oxides and water; oxidizing the carbon monoxide in said effluent gas to carbon dioxide by toibusting the carbon monoxide with added oxygen; cooling the oxidized effluent gas and recovering waste heat; quenching the effluent gas by the introduction of water into the gas in order to condense water vapor and entrain particulates tnto the water in order to separate the condensate and particulates from sald effluent gas; compressing the cooled effluent gas and splitting it into a carbon dioxide recycle stream and a net gas stream; recycling the carbon dioxide recycle stream to the combustion zone and mixing it with commerclally pure oxygen as the fluidizing and combustlon gas; compressing, aftercooling and drying the net gas stream; and separating the dried net gas stream by fractlonal distillation into a liquid stream containing concentrated oxides of sulfur and nitrogen, an essentially pure liqutd carbon dioxide stream and a gaseous oxygen and carbon dloxtde-containtng stream. Preferably the stream containing concentrated oxides of sulfur and nitrogen is processed in a Claus sulfur plant or a sulfuric acid plant to produce a valuable by-product and completely eliminate SO and NOx atmospheric emissions. An advantage of the present process is the utilization of the pure carbon dioxide stream as a recovery medium for an enhanced oil recovery operation. The combustion is preferably the regeneration of catalyst in an FCC regenerator. The FCC regenerator can also be operated in a complete combustion mode such that the effluent gas from the regenerator contains no carbon monoxide. The same processing steps would be used, except that the combustion of carbon monoxide with 2 would be unnecessary. Alternately, in another embodiment the process can comprise the steps of: combusting hydrocarbonaceous coke from particulate matter using a mixture of commercially pure oxygen diluted with carbon dioxide from the recycle gas; recovering the effluent gas from said regenerator, whlch gas contalns, carbon monoxide, carbon dioxide, oxygen, sulfur oxides, nitrogen oxides and water; passing the effluent gas over a deoxygenatton and reducing catalyst to eliminate oxygen and reduce SOX to H2S and NOX to N2; cooling and recovering waste heat from said effluent gas stream; quenching the effluent gas by the introduction of water into the gas in order to condense water vapor and entrain particulates into the water in order to separate the condensate and particulates from the effluent gas; compressing said effluent stream to a higher pressure and aftercooling and drying said compressed stream; separating a CO2 recycle stream from the net combustion products; recycling the CO2 recycle stream to the combustion zone and mixing it with commercially pure oxygen gas as the fluldtztng and combustion gas; compressing the net gas- stream consisting primarily of the net CO and CO2 combustion products; shifting the carbon monoxide content of the net gas stream with steam to carbon dioxide and hydrogen over a shift catalyst; separating the resulting hydrogen from the carbon dioxide in said effluent stream by contact of said stream with a physical solvent to selectively absorb H 2S first, and then carbon dioxide over hydrogen; recovering a concentrated hydrogen product stream and a gaseous carbon dioxide product stream; and recovering a concentrated H2S stream for further processing, typically in a Claus sulfur plant. The gaseous carbon dioxide stream can be compressed to high pressure for use as a recovery medium in enhanced oil recovery or liquefied for merchant sales. The concentrated hydrogen stream can be used as is or further purified as necessary. Alternatively, only a part¯of the carbon monoxide can be shifted to hydrogen to produce an H2 and CO synthesis gas mixture for further use. Agaln, preferably the combustion comprises the regeneration of catalyst tn an FCC regenerator. The process of the present invention is also applicable to regeneration of inert particulate matter from a reactor processing and upgrading petroleum crude prior to a fluidized catalytic crackling reactor. Alternatively, the present invention can be used to regenerate coke tn fluld coking and heat and gastfy coke in the FLEXICOKING process. This invention comprises a unique. integrated combination of processing steps using a mixture of zJC02 as FCC regenerator combustion gas that simultaneously increases FCC coke burning capacity; recovers pure, high pressure carbon dioxide product; and essentially eliminates FCC atmospheric emissions of oxides of sulfur and nitrogen and particulates In the alternate embodiment, a gaseous hydrogen product or synthesis gas is also produced. BRIEF DESCRIPTION OF THE DRAWINGS FIG 1 shows a detailed process flow example of the preferred embodiment of the present invention for the separation, recycle, and recovery of carbon dioxide from the effluent of a fluidized catalytic cracker regenerator using O2ICO2 combustion gas. FIG 2 shows a detailed process flow example of the alternate embodiment of the present invention for the separation, recycle, and recovery of gaseous hydrogen and CO2 from the effluent of a fluidized catalytic cracker regenerator using O2/C02 combustion gas. FIG 3 shows a schematic flow scheme of the process of this invention applied to a fluid coker. FIG 4 shows a schematic flow scheme of the process of this invention applied to a fluid coker and gasifier. DETAILED DESCRIPTION OF THE INVENTION Fluidized catalytic cracker catalyst regeneration with commercially pure oxygen and diluent carbon dioxide, wherein the oxygen content is 60% to 21%, preferably 30%-24% of the total gas feed to the regenerator, obtains significant benefits over the prior art operations of regenerators, while enabling practical and economical recovery of carbon dioxide, hydrogen and sulfur by-products. With reference to FIG 1, the process of the present invention as applied to the FCC process will now be described in detail. An oil feed 10 is dispersed into hot regenerated catalyst 12 in the presence of steam 11. The dispersion passes upward through a riser reactor 13 where the endothermic cracking reactions occur, that also cool the catalyst and depostt coke on the catalyst. The reactor 13 discharges into a separator 15 where the bulk of the catalyst is disengaged The cracked product vapors pass through a cyclone 18 to separate entrained catalyst and then go to further processing 19. Catalyst in the fluidized catalytic cracking reactor, which has been deactivated by the coking of the catalyst surface with carbon deposits passes down through the reactor stripper 16 where hydrocarbons are removed overhead by steam in line 14. The catalyst now in line 17 is introduced into a typical regenerator 20, which constitutes a fluidized up flow reactor. The catalyst experiences an oxidizing, high temperature environment in which the coked carbon deposits on the catalyst are combusted and separated from the catalyst in the gas phase as combustlon products such as carbon dioxide and carbon monoxide, as well as other effluent impurities. The combustion cleaned catalyst is then continuously returned to the cracker reactor for further catalytic duty through line 12. In the present invention, the oxidizing gas which contacts the spent catalyst in the regenerator comprises a mixture of commercially pure oxygen and preferably a diluting portion of carbon dioxide introduced in line 22. Preferably, the oxygen would constitute 24-30X of the oxidizing gas, while carbon dioxide would constitute essentially the rest of the gas as a diluent. The oxidizing gas is a mixture of oxygen 76 separated in an air separatlon unit and the recycled carbon dioxide 75 from the effluent of the regenerator. The bulk of the oxygen reacts with the coke on the catalyst to heat it and regenerate or decoke it by the exothermic reactions: EMI10.1 The heat capacity of the carbon dioxide will absorb some of the heat of reaction and moderate the regenerator temperature increases. The effluent from such an oxygen enriched regeneratton is typically comprised of carbon dioxide 83X, water 9%, carbon monoxide 7X, oxygen 0.5X, sulfur oxides 0,5X, and nitrogen oxides 500 ppm. This effluent flue gas stream is separated from catalyst in cyclone separator 21. The regenerator 20 is of typical materials of construction and subject to typical temperature limitations. However, the carbon dioxide diluent of a 70/30 carbon dloxlde/oxygen regeneration feed gas has a heat capacity equivalent to a nitrogen diluent in air. Accordingly, the higher oxygen concentratlon, uhlle reducing regenerator velocities and relaxing velocity related capacity limitations will not increase regeneration temperatures above those for air regeneration, typically 620-760 C. The flue gas stream in line 23 comprises oxygen, carbon monoxide, carbon dioxide, water, sulfur oxides, nitrogen oxides and particulates. The latter components constitute noxious by-products which, if vented to the atmosphere, would present envlronmental pollutlon problems. Therefore, it Is desirable to eliminate these components of the effluent flue gas stream 23. The stream 23 flue gas passes to the carbon monoxide oxidation zone 30, where the effluent flue gas stream is subJected to further oxidation in the presence of additional oxygen 34. The residual carbon monoxide and any fuels in the effluent flue gas stream are combusted to carbon dioxide. This combustion treatment of the effluent flue gas stream further elevates the temperature of the stream. Therefore, it is necessary to moderate the combustion temperature by recycling carbon dioxide in line 33. The hot combustion gases then pass through a waste heat boiler 31 and are cooled to about 260"C by generating steam. When operating the FCC regenerator tn the complete combustion mode wherein all CO is combusted to CO2 in the FCC regenerator such that the flue gas stream 23 comprises oxygen, carbon dioxide, water, sulfur oxides, nitrogen oxides, particulates and no carbon monoxide, the flue gas stream 23 is sent directly to the waste heat boiler 31 and no carbon monoxide combustion zone 30 Is necessary or the gas passes through the zone without operation of the combustion. The oxidized effluent stream 24 is adiabatically quenched to typically 950C by recycle water stream 28 typically in a venture scrubber 25 to separate the fine catalyst particulates from the vapor stream. The venture scrubber effluent in stream 37 ts separated into a vapor and liquid phase in vessel 35. The liquid phase conslsts of primarily water with essentially all catalyst particulates and sulfur trioxide in the FCC regenerator effluent 23. Thins water in line 26 is pumped (27) back to the venture scrubber 25 in line 28. A net process water stream 29 containing the net water from combustion of coke and net catalyst particulates is withdrawn for further processing. Other gas cooling schemes can be employed including schemes without the venture scrubber or with heat exchangers in place of the direct quench tower. However, in the preferred method with a venture scrubber followed by a direct quench cooling tower particulate removal is facilitated, temperature is reduced to a range where plastic packing and rubber linings can be used to reduce corrosion, and pressure drop ls minimized. The vapor phase from separator 35 comprised of carbon dioxide, oxygen, water, sulfur oxides, and nitrogen oxides passes into vessel 38 where it is further quenched to typically less than 38"C against a spray of cool water from line 43. The quench water is wlthdrawn from vessel 38 in line 39 and pumped (41) through cooler 42 to reduce the temperature to typically less than 35"C and reinjected to quench tower 38 in line 43. Net process water is withdrawn tn line 45 and injected into vessel 35. Fresh makeup water can be added to quench tower 38 in line 40, but process water produced from the combustlon of coke should be sufficient to makeup for all water losses. Since the regenerator effluent stream 23 contains water and sulfur trioxide, sulfuric acid mist will be present and all process streams below the flue gas water dewpoint typically between 70-200"C will be corrosive. This includes al streams processed in the venture scrubber 25, separator 35, and quench tower 38. Most sulfuric acid will be absorbed in the water resulting in the net water stream 29 having a low pH. The net effluent gas 44 from quench tower 38 will contain most of the sulfur dioxide produced from the combustion of coke. No attempt is made to absorb S02 in the process water. Most sulfur trioxide and sulfuric acrid will be absorbed in the quench water, but traces of acid mist particles less than l micron in size will remain in effluent stream 44. Effluent stream 44 is then pressured up in booster compressor 36 to the level required to recycle 60-80X of the stream back to the FCC regenerator 20. Typical FCC regenerator outlet pressure is 1-2.5 atmospheres resulting in required booster compressor outlet pressures of 1.5-3.0 atmospheres. The booster compressor 36 outlet temperature must typically be kept below about 65 C to prevent serious corrosion problems from the trace quantities of sulfuric acid mist when using conventional compressor material alloys. This can be accomplished by interstage cooling or chilling the compressor suction. At this point In the processing, a portion of the effluent stream is then separated into a recycle stream 51 and a remaining stream 50. Preferably the recycle stream 51 would be set to dilute the oxygen in stream 22 to 3t% and provide necessary C02 in stream 33 for CO combustion 30. This would be about 61-80X of stream 44, with the net gas stream 5Q comprising the balance of about 30X. The recycle stream in line 51 is directed back to the inlet of the regenerator 20 in line 75 to be blended wlth pure oxygen tn line 76 and introduced into the regenerator 20 in line 22. The carbon dioxide acts as a diluent to control oxidation and peak temperature of the regenerator and catalyst belng regenerated. The recycle 51 can be supplemented with additional carbon dioxide 74 from downstream processing. The net combustion gas stream tn line 50 is then directed through a multistaged, intercooled compressor 52 to achieve an exit pressure of about 20-40 atm. Sour, sulfur ox1des-conta7n1ng condensate streams are separated in the intercooling heat exchangers 48 and 49 and removed in lines 46 and 47 and jotn the previous sulfur containing water stream in line 29. The compressed effluent stream in line 53 is then aftercooled in heat exchangers 54 and 56 and additional sour water is condensed and removed 55 and 57. EMI13.1 The effluent stream 58 is cooled to about 5"k and dehydrated in drier 59. The drier 59 can constitute a switching bed of dessicant such as alumina or it can be any other known drying means for gas streams, such as a recirculating glycol treatment. The dried effluent stream in line 60 is introduced into a distillation column 61 wherein the-carbon dioxide component of the stream is separated from residual sulfur and nitrogen oxides. The sulfur and nitrogen oxides are removed from the distillation column 61 as a net bottom stream in line 63. This net stream can be further processed in a Claus plant to provide an elemental sulfur product for sale or export. Alternately, it can be fed to a sulfuric acid plant. Reboil for the column is supplied in heat exchanger 64. SO2 and NO2 are less volatile than CO2 and will therefore be separated from C02 in the bottom stream 62. While NO is very volatile, boiling at -152"C, the equilibrium of the reaction: EMI13.2 favors N02 formation at low temperatures and uniquely the rate of N02 formatlon increases as temperature ls reduced. Therefore, with excess 2 present, calculations indicate no NO will be present in the distillation tower; all NO will convert to NO2 which is then separated from C02 and removed with the sulfur oxides in stream 63. An essentially pure carbon dioxide liquid product can be taken as a sidestream from the rectification- section of the distillation column and exported as a product. This product stream is removed in line 65 and pumped to pressure tn pump 66 before export in line 67. The carbon dioxide mid-cut stream is sufficiently pure such that it may be pipeline and utilized in other industrial processes such as enhanced oil recovery EMI13.3 operations. Note however that the liquid C02 product will be contaminated with trace quantities of 02. The trace 2 can be eliminated if desired by using a two column distillation system with the second column being a stripper with bottom recoiling to strip trace 02 overhead for reinlection into distillation column 61 or into refrigerated heat exchanger 69 for recovery. The stripper column liquid can be a sidestream as stream 65 or can be taken from reflux stream 70. A carbon dioxide and oxygen-containing overhead stream is removed from distillation column 61 in line 68. Reflux is provided for the upper portion of column 61 by cooling overhead stream 68 in refrigerated heat exchanger 69. A part of the stream is condensed and returned in line 70 as reflux. The remaining portion of the overhead stream ts removed from heat exchanger 69 In line 71. This stream may be mixed with the recycle CO2 51 In line 75 and recycled to the fluidized catalytic cracking regenerator 26 or delivered to oxidation zone 30. Recycllng stream 74 results in nearly complete utilization of the oxygen introduced into the regeneration and recycle system of the present invention. A small portion of the oxygen and carbon dioxlde-contalning stream in line 71 is vented to the atmosphere through valve 72 and ftne 73 to purge inerts, such as N2 and argon, from the system. Under some circumstances1 diluent carbon dioxide in stream 75 may be Imported or it may be desirable to operate the regenerator utilizing pure oxygen undiluted with carbon dioxide. Under these circumstances, all of stream 44 will be compressed and stream 71 can be vented or added to stream 22. Under the circumstances of pure oxygen gas introduction into the regenerator, increased temperatures of about 50"C can be expected to be experienced by the catalyst and the regenerator. In some regeneration systems it would be expected that oxygen atmospheres in the heated regenerator would not approximate dangerous conditions in light of the back mixing in the fluidized bed of the regenerator, in which oxygen would be rapidly mixed with the constituents and gas phase existing in the regenerator. Accordingly, to the extent that complete back mixing occurs, the regeneration of catalyst with pure oxygen would not necessarily result In excessive temperatures. All back mix systems, however, do involve a finite mixing zone. In such a fluidized catalytic cracker regeneration mixing zone, oxygen concentrations would traverse the range from essentially 100% oxygen at the inlet zone of the regenerator to extremely low concentrations of oxygen at the effluent zone of the reactor. In the preliminary mixing zones of the regenerator, excessive high oxygen reaction rates and heat release could be expected to give locally high temperatures that could damage some catalysts and regeneration equipment materials. Additionally, inlet oxygen metal piping and distributors in some systems might be expected to ignite and burn in such pure oxygen atmospheres. Therefore, in such systems, it would be preferable to utilize the preferred embodiment of the present invention in which the inlet gas to the regenerator contains a predominant amount of carbon dioxide diluent such as is supplied in the present invention through lines 51 or 74 or from an extraneous source providing fresh carbon dioxide. The molar heat capacity of carbon dioxide is about 60% greater than the molar heat capacity of nitrogen, and the mixing of a carbon dioxide diluent to 30% oxygen for the effluent gas provides a heat capacity equivalent to air despite the enrichment of 30X oxygen existing In the inlet gas This would favorably avoid metal component flammability and the overheating of catalyst with its attendant problems in catalyst life and activity. This invention comprises a unique, integrated combtnatton of processing steps, ustng a mixture of CO2 and Q2 for FCC regeneration that simultaneously increases FCC coke burning capacity, recovers a pure high pressure CO2 product (preferably as a liquid) and completely eliminates noxious CO, particulates, and sulfur and nitrogen oxide emissions. While the benefits of CO2 and 02 mixtures in increasing FCC coke burn capacity compared to alr regeneration have been recognized in the prior art, heretofore 02/ CO2 regeneration has not been practiced because it is uneconomical due to the hugh cost of 02 and C02. However, it becomes economical with the process combination of this invention because of the value of the recovered CO2 product and the elimination of flue gas emisslons which eliminates the need for expensive flue gas desulfurization processes that achieve only partial SOX removal and minimal NOX removal. When air is used for FCC catalyst regeneration, the regenerator flue gas is typically 2 comprising about 14 vol% CO2, excess 2 and SOX and NOX. Recovery of pure C02 from th1s gas 1s expenslve. Co2 containing N2 is of little value in enhanced oil recovery or merchant markets. Separation by distillation is impractical because the gas would have to be compressed so that C02 partial pressure would be above the triple point pressure of 5.1 atm. For 14X CO2 flue gas, the distillation pressure would have to be above 36 atm. and the compression energy requirements and costs would be prohibitive. But when CO2 and Qz mixtures are utilized, the regenerator flue gas is primarily CO2 contaminated with SOX, NOX, 2 and some argon (after CO is combusted to CO2 and water is removed). After 60-80X of the flue gas is recycled to the regenerator to provide C02 diluent for the 02, the net combustion flue gas can be compressed to above 5 atm. to liquefy, recover and purify the C02 by distillation. The-compression requirements are lower than with air because the pressure is reduced and the large N2 compression requirement is eliminated. After the net CO2 is compressed to recover high pressure CO2 gas or liquid product, it then becomes inexpensive and practical to separate the SOX, NOX and excess O by distillation. Sulfur dioxide is much less volatile than CO2 and is therefore easily distilled from CO2. 503 is even less volatile and is readily separated with the SO2. 1102 Is also less volatile than C02 and will separate with the S02 and SO3. while NO is very volatile, boiling at -152*C, it will react with excess n in the colder portions of the distillation system to form nonvolatlle 1102 and therefore separate with the S02 and SO3 as previously noted. Accordingly, it can be seen that this reaction in the distillation system is an important means of obtaining complete NO separation. In the process of the present invention the use of existing flue gas wet scrubbing technology to remove sulfur oxides typified by Reeder, et al. in U.S. Patent 3,970,740 is not practical. The high CO2 concentration (86X vs. Reeder's 15X) would result in high caustic consumption resulting in a high water injection rate and a major water treating problem. The water containing sodium sulfAte requires significantly more processing than the distillation separation of SO x and NOx which can then be directly processed in a Claus or sulfuric acid plant. In the present process, no attempt is made to absorb S02 from the flue gas into the water beyond what naturally occurs. No continuous water injection is required as the combustion product water is sufficient to rtd the system of particulates. This reduces the amount of water and the sulfate concentration significantly compared to Reeder, et al., thereby minimizing the water treating requirements. Separation of O2 from C02 by distillation is also complicated by CO2 freezing problems that develop below the CO2 triple point temperature of -56.5 C. To separate pure O2 would require 02 liquid reflux at temperatures below the O2 critical temperature of -118 C. In the proposed system, the 02 rectification section top temperature is held above -56.5 C to avoid freezing and this gives an impure 2 reject stream containing substantial CO2. Preferably, tn the proposed system this reject stream is recycled to the FCC regeneration sectlon thereby avoiding losses of valuable 2 and CO2. A small vent stream will be required to purge inverts from the system. From the foregoing, the unique integrated interaction of the proposed system is evident. FCC regeneration wlth 2/CO2 can give increased coke burning capacity, but alone it is uneconomical. Recovery of CO2 from FCC regenerator flue gas is desirable but uneconomical with air regeneration due to the large amount of nitrogen present. Elimination of FCC regenerator SOX and NOX emissions is increasingly required to meet air quality demands, but available technology is expensive and gives only partial removal. The proposed invention allows substantially complete 02 utilization, substantially complete recovery of pure C02 product and essentially complete separation of SOX and NOX pollutants from the flue gas that can be processed in a Claus sulfur plant or in a sulfuric acid plant to generate usable by-products. In FIG 2, an alternate embodiment of the present invention is shown in which coked, spent catalyst 117 from a fluidized catalytic cracker reactor 113 is introduced into the regenerator 120 and ls regenerated by an upflow 122, in a fluidizing manner, of a mixture of commercially pure oxygtr. gas diluted with carbon dioxide in the same manner previously described in the preferred embodiment of thins invention. The reactor and regenerator and their parts are numbered corresponding to FIG l, but with the 100 serles of numbers. The effluent stream from the regenerator leaves in line 123 and consists of the same components as described in the preferred embodiment - CO, CO21 H20, 02, sulfur oxides, nitrogen oxides and particulates. The effluent gas stream 123 is cooled in waste heat boiler 125 to 150-425C by producing high quality steam. The cooled effluent 127 is passed through catalytic reactor 128 to eliminate oxygen and reduce sulfur and nitrogen species to H2S and N2. The catalyst is typically sulfided cobalt and molybdenum on silica-alumina support as described by Beavon In U.S. Patent 3,752,877 incorporated here by reference. The temperature will be function of the specific catalyst employed. The hydrogen required for the reduction reactions will be generated by shifting the CO and H2O in FCC effluent stream 127 over the catalyst. Since the oxygen content of effluent 127 can vary, it may be necessary to have multiple reactor beds with interstate coollng to remove the heat of reaction. In this instance1 it may be desirable to add hydrogen 126 to reactor 128 to enhance the sulfur and nitrogen reduction rates. The deoxygenated and reduced effluent gas 129 from reactor 128 nou comprises carbon monoxide. carbon dioxide, water, hydrogen, H2S,N2 and particulates along with other trace gases such as argon introduced in the oxygen stream 176 to the regenerator. Stream 129 is cooled tn waste heat boiler 131 to about 260"C producing high quality steam. The cooled effluent 133 is thenadiabatically quenched to less than 95"C by recycle water stream 137 typically in a venture scrubber 135 to separate the fine catalyst particulates from the vapor stream. The venturi scrubber effluent 139 is separated into a vapor and liquid phase in vessel 140. The liquid phase is primarily water containing essentially all particulates from stream t33 and some dissolved H2S. The sour water 136 is pumped (134) back to the venturi scrubber 135 in line 137. A net sour process water stream 138 produced from the combustion of coke and containing the net catalyst particulates is withdrawn for further processing. Other gas cooling schemes can be employed including schemes without the venturt scrubber or wlth heat exchangers in place of the dlrect quench tower. However, in this preferred method with a venture scrubber followed by a direct quench cooling tower, particulate removal is facilitated, temperature is reduced, and pressure drop is minimized. The vapor phase from separator 140 comprising CO, CO2, H20, H2S, N2, H2 passes into vessel 141 where it is further typically quenched to less than 38"C against a spray of cool water from line 153. The quench water is withdrawn from vessel 141 in line 143 and pumped (147) through cooler 149 to reduce the temperature to typically less than 35"C and reinjected into quench tower 141 in line 153. Net process water is withdrawn in line 151 and injected into vessel 140. Fresh makeup water can be added to quench tower 141 in line 145, but process water produced from the combustion of coke should be sufficient to make up all water losses. Since all sulfur oxides are reduced to H2S in reactor 128, no sulfuric acid is present, thus eliminating sulfuric acid corrosion problems. The quenched effluent gas 155 from tower 141 is compressed in a multistage compressor 159 preferably to a pressure of 10-20 atm. dependlng on the CO/CO2 ratio of the gas. Interstage cooling is performed in exchangers 161 and 163 and sour water is removed in lines 165 and 167 and combined wlth sour water from line 138 in line 169. The compressed gas 171 is then aftercooled to a temperature of about 40"C in aftercooling heat exchanger 173 which is supplied with ambient- cold water and additional sour water ts knocked out in line 175. The recycle C02 in effluent stream 177 is separated from the net combustion products in an auto-refrlgerated, Joule-Thomson flash separation. The compressed gas in stream 177 is cooled to as low a temperature as possible - typically 5-lO0C - in heat exchanger 179 to condense as much water as possible without forming hydrates. Water is separated from the chilled gas which is then dried in an absorption system 181 similar to that described in the primary embodiment. The dried gas enters the auto-refrigerated heat exchanger 183 where it is cooled to about -50 C. The recycle C02 is liquefied and then separated from the net combustion gas vapor 201 in vessel 187. The net gas vapor 201 is warmed to about 0 C against the cooling feed in exchanger 183. The llquld recycle CO2 189 is flashed in 3-T valve 190 to obtain refrigeration. To prevent freezing of the recycle CO2, the pressure downstream of valve 190 Is controlled to maintain the temperature in line 191 at about -55 C. The cold recycle C02 in line 191 is warmed against the cooling feed in exchanger 183. The reuarmed recycle C02 193 is then expanded to about 1.5-3 atm. in turbine l95 to recover power, warmed in exchanger l99, providing low temperature cooling for the downstream gas separation, and finally warmed against the cooling effluent gas 177 in exchanger 179. The recycle CO2 197, comprising primarily CO2 and small quantities of Co and H2S, is then mixed with oxygen 176 to provide combustion gas 122 to the FCC regenerator. The compressor 159 supplies the energy input to separate the recycle CO2 and net conbustlon products, with the pressure and temperature of separator 187 controlled to make the amount of recycle C02 197 required for regenerator combustion gas 122. The refrigeration duty required in exchangers 179 and 183 and the power recovered tn turbine 195 are dependent on atmospheric energy losses. The insulation standards employed will define whether auxiliary refrigeration is required to cool stream 186 and whether turbine 195 is economically justified. The warmed vapor stream 203 containing the net combustion products CO, C02, N2S, N2 and H2 is compressed in compressor 205 to about 40 atm. The net effluent flue gas stream 213 is then heated in heat exchanger 215 to 315-345*C. Steam is added to the heated stream 217 from line 221 and the combined stream in line 223 is introduced into the first of three shift reactors 225, 239 and 243. Shift reactor 225 contains a sour shift catalyst because of the content of the gas, such as sulfided cobalt-molybdenum on alumina able to withstand large temperature increases. The shift reaction converts carbon monoxide as follows: EMI20.1 The reactlon partially shifts the carbon monoxide toward equilibrium with hydrogen exothermically, resulting In a substantial temperature rise. Exlt stream 227 from the reactor 225 is cooled tn heat exchanger 231 to 315-345"C and the cooled stream in line 233 undergoes a second shift in reactor 239. This reactor also contains sour shift catalyst and additional carbon monoxide is shifted to hydrogen. The effluent is cooled in heat exchanger 241 to approximately 200"C and enters the third shift reactor 243 containing sour shift catalyst. The shifted effluent gas stream is cooled in heat exchanger 240 to ambient temperature and condensate is removed in line 242. The cooled stream 244 comprises primarily hydrogen, carbon dioxide, and water with small amounts of CO, H2S, and argon. It enters hydrogen sulfide absorber tower 246 where it is contacted with an H2S lean physical solvent 261 to selectively absorb essentially all hydrogen sulfide and only a fraction of the C02. H2S rich solvent 291 is withdrawn from the bottom of absorber 246 and fed to C02 stripper 295. The coabsorbed CO2 is flashed and stripped with some of the product hydrogen 296 from the H2S rich solvent in vessel 295. The C02 vapor 297 is compressed to about 40 atm. in compressor 301. The high pressure CO2 stream 303 is combined wlth the cooled shift effluent stream 244 and recycled to the H2S absorber 246. The H2S rich solvent 305 from stripper 295 is flashed to about 1.5 atm. in valve 307 and injected into the H2S stripper 309 to regenerate the solvent. Stripping gas is generated by reboiler 323. The stripper overhead 311 is partially condensed in exchanger 313 and separated in vessel 315. The liquid 317 is returned to the column as reflux and the vapor 319, which contains concentrated H2S, is withdrawn from separator 315 as a net product 319 for processing to sulfur typically in a Claus sulfur plant. The lean solvent 321, containing essentially no H2 or CO2 is withdrawn from the H2S stripper 309 bottoms and pumped (325) to about 40 atm. This solvent in line 327 is combined with lean solvent 283 from the CO2 stripper 273. Overhead gas 245 from H2S absorber 246, comprising CO2 and H2 with some CO and essentially no H2S is cooled in exchanger 247 and fed to C02 absorber 253 in line 251 where it is contacted with clean physical solvent 255 to absorb carbon dioxide. Hydrogen product, essentially free of carbon dioxide is removed from tower 253 as an overhead stream in line 257. The hydrogen stream 257 contalns residual carbon monoxide that typically would be essentially completely eliminated by catalytic methanation. The carbon dioxide loaded solvent is removed as bottom stream 258, and divided into two streams, Part of the stream is pumped (259) to about 40 atm, to provide H2S lean solvent 261 for H2S absorber 246. The net CO2 rlch solvent Is flashed in valve 263 before being phase separated in separator 267. Gaseous carbon dioxide is removed as an overhead stream in line 265 as a pure product that can be compressed to high pressure and used for enhanced oil recovery operations or liquefied for export product uses. The solvent In separator 267 is removed as bottom stream 269 and introduced Into stripper column 273 where residual carbon dioxide is stripped from the solvent with nltrogen introduced in line 277 and the stripped gas is vented In line 275. The lean solvent is removed in line 279 and pumped to pressure In pump 281. Lean solvent 283 is combined with lean solvent 327, cooled by heat exchanger 285 and re-1ntroduced into tower 253 through line 255. This net gas separation process is described by Nicholas,et al. In U.S. Patent 4,242,108 Incorporated herein by reference. This embodiment of the present invention has the same advantages over the prior art as the primary embodiment, namely; Increases FCC regenerator coke burning capacity, eliminates FCC sulfur and nitrogen oxide and particulate atmospheric emissions, produces a pure CO2 product for sale in enhanced oil recovery or merchant use, plus two additional advantages: produces a pure hydrogen product, and reduces oxygen consumption. FCC regenerator flue gas comprises typically 0-15X CO, 10% H20, < 1% sulfur and nitrogen oxides, traces of H2S and oxygen, wlth CO2 making up the balance when the fluidization/combustion gas Is a mixture of O2/CO2. To make production of hydrogen from this stream practica, a process must accomplish four things: elimination of oxygen and potential for producing solid sulfur by reaction with H2S, separation of recycle C02 from the net flue gas combustion products, concentration of CO for favorable shift equilibrium, and separation of sulfur species from product CO2. The unique, integrated process configuration defined in this embodiment makes hydrogen production from FCC flue gas CO economically practical. The deoxygenation, reduction reactor, the auto-refrNgerated J-T CO/CO2 separation, the sour shift system, and the selective H2S removal system work in concert to achieve the benefits of this embodiment. The deoxygenation, reduction reactor is required to prevent plugging from the formation of solid sulfur in the downstream equipment via reaction of oxygen, H2S, and SO2. Trace components such as COS and nitrogen oxides are also eliminated in the process. By reducing all sulfur and nitrogen specters to H2S and N2, sulfur buildup in the recycle loop is reduced since H2S ts much more volatile than SO2; the corrosion problem caused by sulfuric acld formation from sulfur trioxide and water is eliminated; and a gas stream that can be processed over a commercially available sour shift catalyst at lower steam/dry gas ratios than required for conventional iron-chrome 'sweet" shift catalysts results. The auto-refrigerated, J-T flash separation of CO/CO2 providers a highly concentrated CO2 recycle stream comprising < 1% CO and < 2% H2S and a concentrated CO stream comprising the net combustton CO and C02 for shifting to hydrogen. The physical properties of carbon dioxide make this type of CO/CO2 separation process posslble, whereas it is not posslble to separate nitrogen in this manner. The selective H2S removel produces a sulfur free CO2 product that can be compressed to high pressure for use in enhanced oil recovery or liquefied for merchant sales. Although this embodiment of the present invention shifts CO essentially completely to hydrogen, it is posslble to only partially shift the CO to hydrogen thereby producing a H2 and CO synthesis gas mixture This will reduce the amount of C02 product by the amount of CO in the synthesis gas. Although the present invention is heretn described in two preferred embodiments wlth respect to regeneration of fluidized cracker catalyst, It Is also contemplated that the invention can be practiced in other fluidized hydrocarbon and petroleum processing systems wherein particulate matter Is continuously cycled from a reactor to a regenerator. For example, the present invention can be utilized tn the asphalt residuum treatment process (ART) of Englehard Minerals and Chemicals Corp , as described in U.S. Patent 4,243,514 which is incorporated by reference hereln. In the ART process, g heavy residuum which Is inappropriate for direct processing in a fluidized catalytic cracktng reactor. Is initially processed in a fluidized reactor containing a high temperature inert particulate matter, such as a specially treated kaolin clay. Hlgh boiling and coking components, as well as metals from the resXdeus are deposited on hot particulate matter In the fluidized reactor whiethe remaining residuum is vaporized and removed for refining in a fluidized catalytic cracker. The carbon and metals fouled particulate matter Is removed to a regenerator where oxygen and carbon dioxide fluidize the fouled particulate matter and burn the carbon from the inert particles. Metal build-up is allowed to proceed until a predetermined level Is achieved and fresh partlculate matter Is added and metal fouled inert particles are removed from the regenerator. The effluent from the regenerator Is treated in a similar manner to that described above. Carbon dioxide from the effluent can be recycled to dilute and moderate the nitrogen-free oxygen feed to the inert particulate matter regenerator. The present invention can also be practiced in a thermal fluidized cracking system as shown in FIG 3. Exemplary of a thermal system ts the fluidcoklng process, such as is descrlbed in U.S. Patent 2,527,575, which is incorporated by reference hereln. In fluldcoking, a hydrocarbon feed, such as a heavy vacuum residuum, is cracked in a fluidized reactor loaded with hot particulate coke. The coke thermally cracks the residuum and In turn fresh carbonaceous matter deposits on the particulate coke. As the process continues, the coke becomes larger and it is necessary to continuously remove some of the carbonaceous material coated coke to reheat it and reduce it in size. The coated coke is removed to a regenerator in order that some of the carbonaceous coating or coke can be burned to produce heat and to remove a part of the net carbon or coke produced in the reactor. Reheated coke is returned to the reactor and a coke product is removed from the regenerator. Again, this regenerator or coke burner can be fluidized and the combustion sustained wlth a mixture of oxygen and carbon dioxide. The resulting effluent can be treated, and the carbon dioxide recycled as described above. In a variation of the fluidcoking system, a flexicoking process can also be operated in the manner of the present invention as shown in FIG 4. Flexicoking partially combusts the net coke such as is produced In fluidcoking to produce a low BTU fuel gas effluent of high temperature. This effluent, in turn, Is used as the fluidizing gas in the regenerator or coke heater. As described in U.S. Patent 3,661,543, which is incorporated by reference herein, flexicoking is a fluidized bed process wherein particulate matter in the form of hot coke cracks the hydrocarbon feed, usually a heavy residuum. Carbonaceous material in the form of additional coke is deposited on the particulate coke of the fluidized reactor, and the coke is reduced in temperature. Part of this coke ts then continuously removed to a coke heater. In the coke heater, the cool coke is reheated by a hot, low BTU fuel gas produced by the combustlon of coke in yet another vessel, a coke gasifies or regenerator. The reheated coke is continuously returned to the reactor and the low BTU fuel gas which gave up heat to the coke is removed from the coke heater as an effluent. The net coke from the reactor which passes through the heater is partially combusted in the gasifier generating the heat necessary for thermal cracking. In the present invention, the gasifier is supplied with a stream of oxygen and carbon dioxide, the latter of whlch can be recycled carbon dioxide from the effluent of the coke heater. Thus in flexicoking, the oxygen/carbon dioxide ts fed to the gasifies or heat regenerator, and the effluent to be treated is removed from the coke heater. This, of course, is the gas produced tn the gasifier and heat exchanged in the coke heater. In this context, the term particulate matter refers to a umber of substrates which can be used in a fluidized hydrocarbon refining reactor as contact particles, such as catalyst for catalytic cracktng, inert clays for the asphalt residual treatment and coke for the fluidcoking and flexicoking processes. The carbon or coke build-up on such particles ts generally termed carbonaceous material. Lastly, in this specification, the term regenerator Is understood to include regenerators for fluidized catalytic cracking, burners for the asphalt residuum treatment and the fluidcoking process, and the coke gasifier for the flexicoking process. The present invention has been described in detail with the specific embodiments set forth above, but it is deemed that the invention could be practiced by one skilled in the art with various modifications. Therefore, the scope of the present invention should not be deemed to be limited to the specific embodiments set forth, but rather should be ascertaln-ed froin the claims which follow.

Claims: CLAIMS 1. A process wherein the effluent flue gas from the removal of hydrocarbonaceous coke from particulate matter by combustion in a combustion zone with a mixture of commercially pure oxygen diluted with carbon dioxide is treated to provide a carbon dioxide-rich recycle gas stream, comprising the steps of: : a) introducing the effluent flue gas into a carbon monoxide combustion stage wherein essentially all of the carbon monoxide content of the gas is converted to carbon dioxide by combustion with oxygen gas; b) reducing the temperature of the resulting combusted effluent gas of step a) and recovering the waste heat from said gas; c) coollng and quenching the effluent gas by the introduction of a water stream into the gas with the attendant condensation of water of combustion and the entrainment of particulates into the water stream with subsequent removal of the stream from the gas; d) compressing the effluent gas to approximately the inlet pressure of the combustion zone; ; e) splitting the effluent gas into a carbon dloxlde-r1ch recycle gas stream and a net gas stream, and f) recycling the carbon dloxlde-rich recycle gas stream to the combustion zone as the diluent for oxygen fed to the zone for combustion. 2. The process of Clalm 1 further including the steps of: g) compressing the net gas stream to a further elevated pressure; h) after cooling the compressed net gas stream wlth the attendant removal of condensed water'. drying the net gas stream to remove essentially any residual moisture; t) distilling the net gas stream to recover a gaseous overhead stream of oxygen and carbon dioxide, a liquid carbon dioxide sidestream and a liquid bottom stream containing oxides of sulfur and nitrogen. 3. The process of Clam 2 further including the step of recycling substantially all of the gaseous overhead stream of oxygen and carbon dioxide In step j) to the combustion zone to be mixed with oxygen and recycled carbon dioxide. 4. A process wherein the effluent flue gas from the removal of hydrocarbonaceous coke from particulate matter by complete combustion in a combustion zone, whereln essentially no residual carbon monoxide exists, with a mixture of oxygen dlluted wlth carbon dioxide Is treated to provide a carbon dioxide-rich recycle gas stream comprising the steps of: : a) reducing the temperature of the resulting combusted effluent gas and recovering the waste heat from said gas; b) cooling and quenching the effluent gas by the introduction of a water stream into the gas with the attendant condensation of water of combustion and the entrainment of particulates into the water stream with subsequent removal of the stream from the gas; c) compressing the effluent gas to approximately the inlet pressure of the combustion zone; d) splitting the effluent gas into a carbon dioxide-rich recycle gas stream and a net gas stream, and e) recycling the carbon dioxide-rich recycle gas stream to the combustion zone as the diluent for oxygen fed to the zone for combustion. 5. The process of Claim 4 further including the steps of: g) compressing the net gas stream to a further elevated pressure; h) after cooling the compressed net gas stream wlth the attendant removal of condensed water; drying the net gas stream to remove essentially any residual moisture; J) distilling the net gas stream to recover a gaseous overhead stream of oxygen and carbon dioxide, a liquid carbon dioxide sidestream and a liquid bottom stream containing oxides of sulfur and nttrogen. 6. The process of Claim 5 further including the step of recycling substantially all of the gaseous overhead stream of oxygen and carbon dioxide of step j) to the combustion zone to be mixed wlth oxygen and recycled carbon dioxide. 7. The process of Claim 1 wherein a portion of the carbon dioxide recycle stream is removed and introduced into the carbon monoxide combustion stage to moderate the temperature of combustion. 8. A process wherein the effluent flue gas from the removal of hydrocarbonaceous coke from particulate matter by combustion in a combustion zone with a mixture of oxygen diluted with carbon dioxide is treated to provide a carbon dioxide-rich recycle gas stream and a carbon-monoxide-rich stream for further processing, comprising the steps of: : a) reducing the temperature of the effluent flue gas from the combustion zone to 150-425 C and recovering waste heat; b) passing the effluent flue gas over a deoxygenation and reducing catalyst to eliminate oxygen and reduce SOX to H2 S and HO, to N2; c) further reducing the temperature of the effluent flue gas recovering waste heat; d) quenching the effluent flue gas by the IntroductIon of a water stream into the gas with the attendant condensation of water of combustion and the entralnment of particulates into the water stream with subsequent removal of the stream from the gas; ; e) compressing the effluent flue gas to a pressure in the range of 10 to 10 atm. and drying the pressurized stream; f) separating a carbon dioxide-rich recycle stream from the net combustion product gases in a low temperature phase separation of the effluent flue gas; g) recycling the carbon dloxide-r1ch recycle stream to the combustion zone as the dlluent for oxygen fed to the zone for combustion. 9. The process of Claim 8 further comprising the steps of: h) compressing the net combustlon product gas to an elevated pressure; 5) sh1ft1ng the carbon monoxide content of the net combustion product stream to reduce the carbon monoxide content of the stream and produce hydrogen and additional carbon dioxide; and J) separating the stream into a carbon dioxide stream, a hydrogen stream and a hydrogen sulfide stream by a solvent sorption system. lO. The process of Claim 8 wherein the separation of step f) is performed predominantly with auto refrigeration. ll. The process of Claim 9 wherein the separation of step j) is performed by a physical solvent which selectively absorbs H2 S to a greater extent than C02 and does not absorb an appreciable amount of H2. 12. The process of Claim 9 wherein the shifting of carbon monoxide of step 1) is only partially complete and the separation of step j) results In the hydrogen stream havlng a significant carbon monoxide content.

Inventors: HEGARTY, WILLIAM PATRICK
Applicants: AIR PRODUCTS AND CHEMICALS, INC.
Application year: 1985
Main classification: B01J8
IPC codes: F25J3, B01J8, B01J29, C10J3, C10G11