CA1231660A - Process for the recovery and recycle of effluent gas from the regeneration of particulate matter with oxygen and carbon dioxide - Google Patents

Process for the recovery and recycle of effluent gas from the regeneration of particulate matter with oxygen and carbon dioxide

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Publication number
CA1231660A
CA1231660A CA000470693A CA470693A CA1231660A CA 1231660 A CA1231660 A CA 1231660A CA 000470693 A CA000470693 A CA 000470693A CA 470693 A CA470693 A CA 470693A CA 1231660 A CA1231660 A CA 1231660A
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Prior art keywords
stream
gas
carbon dioxide
oxygen
combustion
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CA000470693A
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French (fr)
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William P. Hegarty
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Air Products and Chemicals Inc
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Air Products and Chemicals Inc
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Classifications

    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25JLIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J3/00Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/04Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream for air
    • F25J3/04521Coupling of the air fractionation unit to an air gas-consuming unit, so-called integrated processes
    • F25J3/04527Integration with an oxygen consuming unit, e.g. glass facility, waste incineration or oxygen based processes in general
    • F25J3/04533Integration with an oxygen consuming unit, e.g. glass facility, waste incineration or oxygen based processes in general for the direct combustion of fuels in a power plant, so-called "oxyfuel combustion"
    • BPERFORMING OPERATIONS; TRANSPORTING
    • B01PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01JCHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J29/00Catalysts comprising molecular sieves
    • B01J29/90Regeneration or reactivation
    • BPERFORMING OPERATIONS; TRANSPORTING
    • B01PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01JCHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
    • B01J8/00Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes
    • B01J8/18Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes with fluidised particles
    • B01J8/24Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes with fluidised particles according to "fluidised-bed" technique
    • B01J8/26Chemical or physical processes in general, conducted in the presence of fluids and solid particles; Apparatus for such processes with fluidised particles according to "fluidised-bed" technique with two or more fluidised beds, e.g. reactor and regeneration installations
    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G11/00Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G11/14Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts
    • C10G11/18Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts according to the "fluidised-bed" technique
    • C10G11/182Regeneration
    • CCHEMISTRY; METALLURGY
    • C10PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10GCRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G11/00Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G11/14Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts
    • C10G11/18Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts according to the "fluidised-bed" technique
    • C10G11/185Energy recovery from regenerator effluent gases
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25JLIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J3/00Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/04Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream for air
    • F25J3/04521Coupling of the air fractionation unit to an air gas-consuming unit, so-called integrated processes
    • F25J3/04527Integration with an oxygen consuming unit, e.g. glass facility, waste incineration or oxygen based processes in general
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F25REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
    • F25JLIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
    • F25J3/00Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
    • F25J3/02Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
    • F25J3/04Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream for air
    • F25J3/04521Coupling of the air fractionation unit to an air gas-consuming unit, so-called integrated processes
    • F25J3/04563Integration with a nitrogen consuming unit, e.g. for purging, inerting, cooling or heating
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02PCLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00Technologies relating to chemical industry
    • Y02P20/10Process efficiency
    • Y02P20/129Energy recovery, e.g. by cogeneration, H2recovery or pressure recovery turbines
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02PCLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P30/00Technologies relating to oil refining and petrochemical industry
    • Y02P30/40Ethylene production

Abstract

ABSTRACT
A unique process arrangement is disclosed wherein the effluent flue gas from the removal of hydrocarbonaceous coke from particulate matter by combustion in a mixture of pure oxygen diluted with carbon dioxide is processed to provide a carbon dioxide-rich recycle gas stream to be mixed with oxygen as regenerator feed gas; and a net combustion product stream from which are recovered S0x and N0x to eliminate atmospheric emissions, and a pure C02 product for export. An alternate embodiment also produces hydrogen or synthesis gas for export.

Description

~3~6C~

h PROCESS FOR THE RECOVERY AND RECYCLE OF EUPHONY GAS
FROM THE REGENERATION OF Particulate MATTER WITH
OXYGEN AND CARBON DIOXIDE

TECHNICAL FIELD
The present invention us directed to the field of hydrocarbonaceous coke removal from particulate matter by combust10n in a gas mixture of corr~erc~ally pure oxygen diluted with carbon dioxide. A unique process arrangement us disclosed for the recovery of flue gas effluent from the combust10n of coke on a mixture of pure oxygen diluted with carbon d10xlde, 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 prodllct stream from which are recovered 50x and No to eliminate atmospheric emissions, and a pure C02 product for export. An alternate embodiment also produces hydrogen or synthesis gas for export.

BACKGROUND OF THE PRIOR ART
With 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 reflnlncJ of residues from roughening operations of traditional or higher quality petroleum stocks. The refining of low quality stock or the heavy residues from the roughening of high quality stocks present problems for the refining industry with respect to the capability of the reining process to handle more complex hydrocarbons of higher molecular weight as well as increased carbon residue, organornetallic, nitrogen and sulfur contaminants.
A traditional roughening technique has been the use of a fluldlzed bed catalytic cracker for refining of petroleum stocks. Despite the ag1tat10n and inherent abrasion of catalyst in a fluldl7ed bed reactor, , i60 the cracking operation which occurs on petroleum ref1nlng leaves the particulate catalyst on an ~nact1vated state due to coke buildup on the surface of the catalyst. In order to perform a relatively steady state operation on the flu1d1zed catalytic cracker it us necessary to remove coked catalyst from the reactor on a continuous bass and to regenerate such catalyst. The regenerated catalyst us then returned to the flu1dlzed catalytic cracker reactor without shut down of the latter.
Regenerat10n us usually performed on a flu1dlzed bed with an upflow1ng oxidant gas at elevated temperatures in the regenerator. In thus manner coke on the catalyst us burned and removed as carbon monoxide carbon d10xide and water. Thus exotherm~c combust10n provides heat which us absorbed by the regenerator catalyst and the heated catalyst us returned to the fluld~zed bed catalytic cracker reactor wherein the regenerat10n heat us ut111zed on the endotherm1c cracking process.
As heavier and heavier petroleum stocks are refined on thus manner add1t10nal coking of the catalyst occurs and add1tlonal contam1nat10n of the catalyst with nitrogen and sulfur constituents 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 roughening of such heavy residual petroleum stocks the necessity for more gas through-put on the regenerator has occurred and thus requirement has been the llm1t1ng factor on the amount of heavy residual petroleum stock which may be processed on the flu1d~zed catalytic cracker react10n zone.
Add1t10nally as coke on catalyst goes up more coke burning occurs in regeneration and added heat releases become a 11mitat10n on residuum processing.
The trad1t10nal oxidant gas used on a regenerator us elf. In order to meet the through-put requirements of regenerators exper1enc1ng elevated levels of coke on catalyst the industry has utilized oxygen-enr1ched air mixtures on order to complete the combust10n requirements necessary for removal of the coke from the catalyst [without exceeding velocity l~m1tat10ns]. However thus results on a regenerator temperature increase. McGovern et at. on US. Patent 4 370 222 teaches that oxygen enriched air coupled with heat removal from the catalyst by ~23~6~

steam golfs or catalyst coolers can achieve increased coke burning capacity thin temperature and velocity constraints.
M~guer1an, et at. on US. Patent 4,300,997 have taught a hot regeneration technique using special catalyst on the flu1d1zed catalytic cracker that promotes the burning of carbon monoxide to carbon d10%1de with attendant higher temperatures and vacates on the regenerator and increased heat release. The special catalyst sorbs at least some of the sulfur oxides, but the nitrogen oxides reman untreated.
It is known to ut111ze an oxygen-conta1n1ng gas which us dotted with voyeurs inert gases. In US. Patent 4,146,463, a process us set forth whereon an oxygen-contalnlng gas, such as air us diluted with moderators, such as carbon d10x1de, nitrogen or regenerator recycle gas as the oxidant for the coked catalyst. Sulfur oxides and carbon monoxide from other puritans of the refinery are also introduced unto the regenerator.
In US. Patent 4,118,339, a process us disclosed whereon the effluent gas from a flu1dlzed catalytic cracker regenerator us controlled by the 1ntroduct10n of a noble metal ox1dat10n promoter-conta1n1ng solvent unto the regenerat10n zone. The promoter catalyzes essentially complete combust10n of the regenerator carbon monoxide and results on opportune at higher temperatures with zealot thermally stable catalysts and avoids the carbon monoxide pollutant problem encountered Wyeth proviso regenerat10n techniques. The increased regenerat10n gas, heat release and regenerat10n temperature, however, 1ntens1fy these 11m1tat10ns with heavy residuum feeds.
US. Patent 4,274,942 discloses a process for the regenerat10n of flu1d1zed catalytic cracker catalyst whereon control of the sulfur oxide em~ss10ns us performed by sensing the output from the regenerat10n zone and pretreating the coked catalyst with steam before regenerat10n us performed.
In the conventional regeneration of catalyst, air or oxygen-enrtched air results on a large amount of nitrogen being passed through the regenerating catalyst with no benef1clal effect. Such effluent gases generally contain nitrogen, carbon dlox1de, carbon monoxide, oxygen, hydrogen sulfide, sulfur oxides and nitrogen oxides. The high nitrogen I

content of the effluent gas renders the recovery of the carbon d10x1de and the conversion of carbon monoxide to hydrogen impractical and uneconomical. In add1tlon, the sulfur and nitrogen oxides and the carbon monoxide constitute a palatine problem. This problem us heightened by the processing of heavy residuum Shea contains high levels of nitrogen and sulfur constituents.
The use of mixtures of essentially pure oxygen dotted with flue gas or other inert gases, such as C02, for the flu1d1za-t10n/combust10n gas mixture in an FCC regenerator us taught by Pratt, et at. on US. Patent lo 4,304,659. Since flue gas is typically 80-9OX nitrogen when air us the combust10n gas, dateline of pure oxygen with flue gas has nearly the same effect on the regenerator heat balance and gas velocity as oxygen enrichment of elf.
The use of a mixture of essentially pure oxygen and C02 as the FCC
regenerator combust1cn gas however, has a s1gnlf1cant effect on the regenerator heat balance and gas velocity. The benefits of 02/C02 combustion gas mixtures are taught by Rowe in US. Patent 4,388,218.
Rowe also recognizes that FCC flue ads containing carbon monoxide can be processed to obtain a CO enriched chemical feed stock. However, no process scheme us proposed to recover C02 from the flue gas for recycling to the regenerator, or CO for chemical feed stock, nor is ellmlnat10n of flue gas sulfur emlss~ons contemplated.
Different dry and wet flue gas scrubbing technologies are available for ellmlnat1ng more than 90X of the sulfur oxide emlss10ns from the FCC
flue gas. Render, et at. teaches in US. Patent 3,970,740 that catalyst fines and cold gases can be removed by 1nJect10n of an aqueous scrubbing mixture on a defined pi range controlled by add1t10n of Noah or other caustic maternal. Thus process us practical when scrubbing flue gas conta1nlng predominantly nitrogen, but the Noah consumpt10n is s1gnlflcantly increased when the flue gas is predominantly C02. A
major water treating problem also results.
Kosselm, et at. on US. Patent 4,201,752 teach a process for selective absorption of sulfur oxides from flue gas streams containing 10-15X C02 and predo~lnant`~y nitrogen. Again, flue gas containing YO-YO

I

predominantly carbon dioxide would result in s1gntflcant C02 coabsorptlon and make this process unattractive.
Scarified teaches the use of mixtures of 2 and C02 to regenerate catalytic reformer noble metal catalyst on US. Patent 4,354,925. The benefit of increased heat removal allows regenerat10n with higher oxygen concentration resulting on stgnlf1cantly increased combust10n rates. An integrated continuous recycle process is not proposed for this cyclic, non-steady state regenerat10n opportune.
Additional patents of interest include US. Patent 2,322,075, US.
Patent 3,838,036, US. Patent 3,844,973, US. Patent 4,036,740, US.
Patent 4,176,084, US. Patent 4,206,038 and US. Patent 4,300,997.
The prior art has recognized the use of oxygen and carbon dlox1de mixtures as combustion gas on FCC catalyst regenerators, as well as on catalytic reformer noble metal catalyst regenerat10n, to burn coke from the spent catalyst and thereby regenerate it for further use. No where on the prior art is an integrated processing scheme taught for the regeneration of catalyst with a mixture of pure oxygen diluted with carbon dlox1de, the recovery and recycle of C02 from effluent flue gas to the regenerator, the recovery and processing of the net CO and C02 combustion products to saleable products, and the essentially complete ellmtnatton of atmospheric em7ss10ns by recovery of concentrated SO, NO
or H25 streams for further processing.
While the increased coke burning capacity benefits of using 2 and C2 mixtures for FCC catalyst regenerat10n have been recognized in the prowar art, these mixtures are not used because the cost of oxygen is so high. However, the tntegrdted process of this lnYentton achieves the FCC
coke burning capacity benefits while producing hydrogen and carbon dioxide products for sale and el1mlnatlng sulfur and nitrogen oxide atmospheric emlss10ns completely, resulting in an economically attractive way to process high coke yielding feed stocks in an FCC unit without the addition of internal heat removal systems to cool the catalyst.
Other flutd1zed processing systems wherein hydrocarbonaceous coke is removed from particulate matter by combust10n in air are described by US. Patent 4,243,514 for the treatment of asphalt residuum in a bed of inert particulate matter, US. Patent 2,527,575 for fluid coking of ~3~i60 residuum, and US. Patent 3,661,543 for gasifying flu1dtzed cove. The use of pure oxygen dotted with carbon d10x1de can benefit these processes on the same manner as it benefits the regenerat10n of fluid catalytic cracking catalyst, but the cost of oxygen and carbon d10x1de have up to now prevented commercial appl1cat10ns.

BRIEF SUMMARY OF THE INVENTION
The present 1nventlon is directed to a process for the recovery, treatment and recycle of a carbon d10x1de rich recycle gas as well as the separat10n of a net combust10n product stream from the effluent flue gas from the combust10n in a combust10n zone of hydrocarbonaceous coke from particulate matter using a mixture of commercially pure oxygen diluted with carbon d10x1de from the recycle gas, such process comprising the steps of: recovering the effluent gas from sand combust10n which contains carbon monoxide, carbon d10x1de, oxygen, sulfur oxides, nitrogen oxides and water; oxidizing the carbon monoxide in sand effluent gas to carbon d10x1de by combustlng the carbon monoxide with added oxygen;
cooling the oxidized effluent gas and recovering waste heat; quenching the effluent gas by the 1ntroduct10n of water unto the gas on order to condense water vapor and entrain part1culates into the water on order to separate the condensate and part1culates from sand effluent gas;
compressing the cooled effluent gas and spitting it unto a carbon d10x1de recycle stream and a net gas stream; recycling the carbon dlox1de recycle stream to the combust10n zone and m1x1ng it with commercially pure oxygen as the flu1d1z1ng and combust10n gas; compressing, aftercool~ng and drying the net gas stream; and separating the dried net gas stream by fract10nal d1st111at10n unto a llqu1d stream contaln1ng concentrated oxides of sulfur and nitrogen, an essentially pure llqu1d carbon d10x1de stream and a gaseous oxygen and carbon d10x1de-conta1n1ng stream.
Preferably the stream continuing concentrated oxides of sulfur and n1$rogen us processed on a Claus sulfur plant or a sulfuric acid plant to produce a valuable by-product and completely eliminate Six and No atmospheric em1ss10ns.

7 66~3 An advantage of the present process us the utll1zat10n of the pure carbon dioxide stream as a recovery medium for an enhanced owe recovery operation. The combustion us preferably the regenerat10n of catalyst on an FCC regenerator.
The FCC regenerator can also be operated on a complete combust10n mode such that the effluent gas from the regenerator contains no carbon I-monoxide The same processing steps would be used, except that the combust10n of carbon monoxide with 2 would be unnecessary.
Alternately, on another embodiment the process can comprise the steps of: combust1ng 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, which gas contains, carbon monoxide, carbon dlox~de, oxygen, sulfur oxides, nitrogen oxides and water; passing the effluent gas over a deoxygenatlon and reducing catalyst to el1mlnate oxygen and reduce 50x to H25 and NO to No; 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 partlculates into the water on order to separate the condensate and part1culates from the effluent gas; compressing said effluent stream to a higher pressure and aftercoollng and drying said compressed stream;
separating a C02 recycle stream from the net combustion products;
recycling the C02 recycle stream to the combust10n zone and mlx1ng it lath commercially pure oxygen gas as the fluldlzlng and combustion gas;
compressing the net gas stream conslst1ng primarily of the net CO and C2 combustion products; shlft1ng the carbon monoxide content of the net gas stream with steam to carbon d10x1de and hydrogen over a shift catalyst; separating the resulting hydrogen from the carbon dlox1de on said effluent stream by contact of sand stream with a physical solvent to selectively absorb US first, and then carbon dlox1de over hydrogen;
recovering a concentrated hydrogen product stream and a gaseous carbon dlox1de product stream; and recovering a concentrated HIS stream for further processlng9 typically on a Claus sulfur plant.
The gaseous carbon dioxide stream can be compressed to high pressure for use as a recovery medium on enhanced owe recovery or liquefied for 8 Lowe merchant sales. The concentrated hydrogen stream can be used as us or further pur1fled as necessary. Alternatively, only a part of the carbon monoxide can be shifted to hydrogen to produce an Ho and CO synthesis gas mixture for further use.
Again, preferably the combust10n comprises the regeneration of catalyst in an FCC regenerator. :-The process of the present 1nventlon is also applicable to regeneration of inert particulate matter from a reactor processing and upgrading petroleum crude prowar to a flu1dlzed catalytic cracking reactor.
Alternatively, the present 1nvent10n can be used to regenerate coke on fluid coking and heat and gasify coke in the FLEXICOKING process.
This 1nvent10n comprises a unique, integrated comb1natlon of processing steps using a mixture of 02/C02 as FCC regenerator combust10n gas that simultaneously increases FCC coke burning capacity;
recovers pure, high pressure carbon dlox1de product; and essentially eliminates FCC atmospheric emlss10ns of oxides of sulfur and nitrogen and partlculates. In the alternate embodiment, a gaseous hydrogen product or synthesis gas us also produced.

BRIEF DESCRIPTION OF THE DRAWINGS
FIG l shows a dotted process flow example of the preferred embodiment of the present 1nventlon for the separation, recycle, and recovery of carbon d10xlde from the effluent of a fluldlzed catalytic cracker regenerator using 02/C02 combustion gas.
FIG 2 shows a detailed process flow example of the alternate embodiment of the present invention for the separat10n, recycle, and recovery of gaseous hydrogen and C02 from the effluent of a flu1dlzed catalytic cracker regenerator using 02/C02 combustion gas.
FIG 3 shows a schematic flow scheme of the process of this invention applied to a fluid coyer.
FIG 4 shows a schematic flow scheme of the process of thus invention applied to a fluid coyer and gas1f1er.

I

DETAILED DESCRIPTION I THE INVENTION
Fluld~zed catalytic cracker catalyst regeneration with commercially pure oxygen and dlluent carbon d10xlde, whereon the oxygen content us 60X
to 21X, preferably 30X-24X of the total gas feed to the regenerator, obtains s19n1f1cant benefits over the prowar art operat10ns of regenerators, while enabling practical and economical recovery of carbon I-d10x1de, hydrogen and sulfur by-products.
With reference to FIG l, the process of the present 1nventlon as aped to the FCC process wow now be described on detail. An owe feed 10 us dispersed unto hot regenerated catalyst 12 on the presence of steam if. The d~spers10n passes upward through a riser reactor 13 where the endotherm~c cracking ricketiness occur, that also cool the catalyst and deposit coke on the catalyst. The reactor 13 discharges unto a separator lo where the bulk of the catalyst us disengaged. The cracked product vapors pass through a cyclone 18 to separate entrained catalyst and then go to further processing 19. Catalyst on the flu~dtzed 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 on fine 14.
The catalyst now on lone 17 us introduced unto a typical regenerator 20, which constitutes a flu1d1zed 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 on the gas phase as combust10n products such as carbon dlox1de and carbon monoxide, as well as other effluent ~mpurlt1es. The combustion cleaned catalyst us then continuously returned to the cracker reactor for further catalytic duty through Noah 12.
In the present 1nvent10n, the oxidizing gas which contacts the spent catalyst on the regenerator comprises a mixture of commercially pure oxygen and preferably a dtlut1ng puritan of carbon d10x~de introduced on Noah 22. Preferably, the oxygen would constitute 24-30X of the ox1d171ng gas wow carbon d10xlde would constitute essentially the rest of the gas as a Dante. The ox1dlz~ng gas us a mixture of oxygen 76 separated on an air separat10n unit and the recycled carbon d~oxlde 75 from the effluent of the regenerator. The bulk of the oxygen reacts with the coke ~3~6~) on tune catalyst to heat it and regenerate or decode it by the exotherm1c ricketiness:

OH + 1/2 2 H20 C l/2 2 C0 C0 l/2 2 The heat capacity of the carbon d10x1de will absorb some of the heat ofreact10n and moderate the regenerator temperature increases. The effluent from such an oxygen enriched regenerat10n is typically comprised of carbon d10x1de 83%, water 9X, carbon monoxide 7%, oxygen 0.5X, sulfur oxides 0.5%, and nitrogen oxides 500 Pam. Thus effluent flue gas stream us separated from catalyst on cyclone separator 21. The regenerator 20 us of typical materials of construct10n and subject to typical temperature 11m1tat10ns. However, the carbon d10xlde Dante of a 70/30 carbon d10x1de/oxygen regenerat10n feed gas has a heat capacity equivalent to a nitrogen Dante on air. Accordingly, the higher oxygen concentrat10n, wow reducing regenerator veloc1t1es and relaxing velocity related capacity 11m1tat~ons wow not increase regenerat10n temperatures above those for air regenerat10n, typically 620-760C.
The flue gas stream on Noah 23 comprises oxygen, carbon monoxide, carbon d10xlde, water, sulfur oxides, nitrogen oxides and part1culates.
The latter components constitute noxious by-products which, of vented to the atmosphere, would present environmental palatine problems.
Therefore, it us desirable to eliminate these components of the effluent flue gas stream 23. The stream 23 flue gas passes to the carbon monoxide ox1dat10n zone 30, where the effluent flue gas stream us subjected to further ox1dat10n on the presence of add1tlonal oxygen 34. The residual carbon monoxide and any fuels on the effluent flue gas stream are combusted to carbon d10x1de. Thus combust10n treatment of the effluent flue gas stream further elevates the temperature of the stream.
Therefore, it us necessary to moderate the combust10n temperature by recycling carbon d10x1de on fine 33. The hot combustion gases then pass ~31660 through a waste heat boiler 31 and are cooled to about 260C by generating steam.
When operating the FCC regenerator on the complete combust70n mode whereon all COG is combusted to C02 in the FCC regenerator such that the flue gas stream 23 comprises oxygen, carbon d10x1de, water, sulfur oxides, nitrogen oxides, partlculates and no carbon monoxide, the flue I-gas stream 23 us sent directly to the waste heat Burr 31 and no carbon monoxide combust10n zone 30 us necessary or the gas passes through the zone without opportune of the combust10n.
The oxidized effluent stream 24 us adiabatically quenched to typically 95C by recycle water stream 28 typically on a venturi scrubber 25 to separate the fine catalyst part1culates from the vapor stream. The venturi scrubber effluent on stream 37 us separated unto a vapor and Cody phase on vessel 35. The Cody phase consists of primmer water with essentially all catalyst partlculates and sulfur tr10xtde on the FCC
regenerator effluent 23. Thus water on Noah 26 us pumped (27) back to the venturi scrubber 25 on Noah 28. A net process water stream 29 continuing the net water from combust10n of coke and net catalyst part1culates us withdrawn for further processing. Other gas cooling schemes can be employed 7nclud7ng schemes without the venturi scrubber or with heat exchangers on place of the direct quench tower. However, on the preferred method with a venturi scrubber followed by a direct quench cooling tower particulate removal us fac711tated, temperature us reduced to a range where plastic pecking and rubber 17n1ngs can be used to reduce Carson, and pressure drop us m1n7m7zed.
The vapor phase from separator 35 comprised of carbon d10x1de, oxygen, water, sulfur oxides, and nitrogen oxides passes unto vessel 38 where it us further quenched to typically less than 38C against a spray of cool water from Noah 43. The quench water us withdrawn from vessel 38 on Noah 39 and pumped (41) through cooler 42 to reduce the temperature to typically less than 35C and reenacted to quench tower 38 on lone 43.
Net process water us withdrawn on Noah 45 and 1n~ected unto vessel 35.
Fresh makeup water can be added to quench tower 38 on Noah 40, but process water produced from the combust10n of coke should be sufflc1ent to makeup for all water losses.

~316~

Since the regenerator effluent stream 23 contains water and sulfur tr10x1de, sulfuric acid must wow be present and all process streams below the flue gas water Dupont typically between 70-200C will be corrosive. Thus includes all streams processed on the venturi scrubber 25, separator 35, and quench tower 38. Most sulfuric acid wow be absorbed on the water resulting on the net water stream 29 having a low phi The net effluent gas 44 from quench tower 38 wow contain most of the sulfur d10x~de produced from the combust10n of coke. No attempt is made to absorb S02 on the process water. Yost sulfur tr10x1de and sulfuric acid wow be absorbed on the quench water, but traces of cold must part ales less than l micron on size wow reman on effluent stream 44.
Effluent stream I us then pressured up on booster compressor 36 to the level required to recycle 60-80% of the stream back to the FCC
regenerator 20. Typical FCC regenerator outlet pressure us l-2.5 atmospheres resulting on required booster compressor outlet pressures of 1.5-3.0 atmospheres. The booster compressor 36 outlet temperature must typically be kept below about 65C to prevent Sirius Carson problems from the trace quantities of sulfuric acid must when using convent10nal compressor maternal alloys. Thus can be accomplished by 1nterstage cooling or Shea no the compressor suct10n.
At this point on the processing, a portion of the effluent stream us then separated unto a recycle stream 51 and a remanning stream 50.
Preferably the recycle stream 51 would be set to Dwight the oxygen on stream 22 to 30% and provide necessary C02 on stream 33 for C0 combust10n 30. This would be about 61-80% of stream 44, with the net gas stream 50 comprising the balance of about 30X. The recycle stream on Noah 51 us directed back to the inlet of the regenerator 20 on lone 75 to be blended with pure oxygen on lone 76 and introduced unto the regenerator 20 on fine 22. The carbon d10x1de acts as a dlluent to control ox1dat10n and peak temperature of the regenerator and catalyst being regenerated. The recycle 51 can be supplemented with add1t10nal carbon d10x~de 74 from downstream processing.

~3~66~

The net combustion gas stream in fine 50 is then directed through a multlstaged, tntercooled compressor 52 to achieve an exit pressure of about 20-40 elm. Sour, sulfur oxldes-conta1nlng condensate streams are separated on the lntercoollng heat exchangers 48 and 49 and removed on fines 46 and 47 and own the previous sulfur conta1nlng water stream in fine 29. The compressed effluent stream in fine 53 15 then after cooled in heat exchangers 54 and 56 and additional sour water is condensed and removed 55 and 57.
The effluent stream 58 is cooled to about okay and dehydrated on lo drier 59. The drier 59 can constitute a switching bed of desslcant 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 fine 60 is introduced into a dlstlllatlon 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 dlst111atlon column 61 as a net bottom stream in fine 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 cold plant. Reboil for the column is supplied in heat exchanger 64. S02 and N02 are less volatile than C02 and will therefore be separated from C02 in the bottom stream 62. While No is very volatile, boiling at -152C, the equll1brlum of the reaction: t No l/2 2 N02 25 favors N02 formation at low temperatures and uniquely the rate of N02 formation increases as temperature is reduced. Therefore, with excess
2 present, calculations indicate no No will be present in the dlstlllatlon tower; all No wow convert to N02 which is then separated from C02 and removed with the sulfur oxides in stream 63.
An essentially pure carbon dioxide killed product can be taken as a sldestream from the rectlflcatlon section of the dlstlllatlon column and exported as a product. This product stream is removed in fine 65 and pumped to pressure in pump 66 before export in Noah 67. The carbon dioxide midgut stream 1s~sufflclently pure such that it may be plpellned and utilized in other industrial processes such as enhanced oil recovery I, .

66i0 operations. Note however that the liquid C02 product will be contaminated with trace quints of no. The trace 2 can be eliminated of desired by using a two column d1sttllatton system with the second column being a stripper with bottom reboiling to strop trace 2 overhead for re1n~ect10n unto d1st111at10n column 61 or unto refr19erated heat exchanger 69 for recovery. The stripper column Cody can be a :-s1destream as stream 65 or can be taken from reflex stream 70.
A carbon dtox~de and oxygen-conta1n~ng overhead stream is removed from d1st111at10n column 61 on Noah 68. Reflex us provided for the upper puritan of column 61 by cooling overhead stream 68 on refrigerated heat exchanger 69. A part of the stream us condensed and returned on Noah 70 as reflex. The rema1nlng portion of the overhead stream us removed from heat exchanger 69 on Noah 71. Thus stream may be mixed with the recycle C2 I on Noah 75 and recycled to the flu1d1zed catalytic cracking regenerator 20 or delivered to ox1dat10n zone 30. Recycling stream 74 results on nearly complete uttl~zat10n of the oxygen introduced unto the regenerat10n and recycle system of the present 1nvent~on. A small puritan of the oxygen and carbon d10x~de-conta~n1ng stream on Noah 71 us vented to the atmosphere through valve 72 and Noah 73 to purge hefts such as No and argon from the system.
Under some circumstances dlluent carbon dlox~de on stream 75 may be imported or it may be desirable to operate the regenerator ut111z1ng pure oxygen undiluted with carbon d10xtde. 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 1ntroduct10n unto the regenerator increased temperatures of about 50C can be expected to be experienced by the catalyst and the regenerator. In some regeneration systems it would be expected that oxygen atmospheres on the heated regenerator would not approximate dangerous cond1t10ns on fight of the back mixing on the flu~d~zed bed of the regenerator in which oxygen would be rapidly mixed with the constituents and gas phase exlst1ng in the regenerator. Accordingly to the extent that complete back mixing occurs the regenerat10n of catalyst with pure oxygen would not necessary result on excessive temperatures. All back mix systems however do involve a f1n1te m1xlng Noah. In such a flu1d~zed catalytic Rio cracker regeneration m~x1ng zone, oxygen concentrat10ns would traverse the range from essentially lox oxygen at the inlet zone of the regenerator to extremely lo concentrat10ns of oxygen do the effluent zone of the reactor. In the preliminary m1x1ng 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 I-regeneration equipment materials. Add1t10nally, inlet oxygen metal plopping and d1str1butors on some systems might be expected to 1gn1te and burn on such pure oxygen atmospheres. Therefore, on such systems it would be preferable to utilize the preferred embodiment of the present ~nvent10n on which the inlet gas to the regenerator contains a predominant amount of carbon d10xlde Dante such as us supplied on the present 1nvent10n through fines 51 or 74 or from an extraneous source providing fresh carbon d10x1de. The molar heat capacity of carbon d10x1de us about 60% greater than the molar heat capacity of nitrogen, and the mlx~ng of a carbon d10x1de Dante to 30X oxygen for the 1nfluent gas provides a heat capacity equivalent to air despite the enrichment of 30X oxygen existing in the inlet gas. Thus would favorably avoid metal component flammab111ty and the overheating of catalyst with its attendant problems on catalyst foe and activity.
Thus 1nvent10n comprises a unique, integrated comb1nat10n of processing steps, using a mixture of C02 and 2 for FCC regenerat10n that simultaneously increases FCC coke burning capacity, recovers a pure high pressure C02 product (preferably as a Cody) and completely el1mlnates noxious CO, part1culates, and sulfur and nitrogen oxide em1ss10ns. Wow the benefits of C02 and 2 mixtures on 1ncreas1ng FCC coke burn capacity compared to air regenerat10n have been recognized in the prowar art, heretofore 02/C02 regenerat10n has not been practiced because it us uneconomical due to the high cost of I and C02. However, it becomes economical with the process comb1nat10n of thus 1nvent10n because of the value of the recovered C02 product and the el1m1nat10n of flue gas em1ss10ns which eliminates the need for expensive flue gas desulfurlzat10n processes that achieve only partial SO removal and m1n1mal NO removal.

I
I

When elf is used for FCC catalyst regenerat10n, the regenerator flue gas us typically No comprising about 14 volt C02 excess 2~ and SO and NO. Recovery of pure C02 from this gas is expensive. C02 contatn1ng No is of Utile value in enhanced oil recovery or merchant markets. Separation by dlstlllatlon us impractical because the gas would have to be compressed so that C02 partial pressure would be above the --triple point pressure of 5.1 elm. For 14% C02 flue gas, the dlstlllat10n pressure would have to be above 36 elm. and the compression energy requirements and costs would be prohlb1t1ve. But when C02 and 2 mixtures are utilized, the regenerator flue gas us primarily C02 contaminated with SO, NO, 2~ and some argon wafter CO is combusted to C02 and water us removed). After 60-80X of the flue gas us recycled to the regenerator to provide C02 dlluent for the 2~ the net combustion flue gas can be compressed to above 5 elm. to liquefy, recover and purify the C02 by dlstlllat10n. The compression requlre~ents are lower than with elf because the pressure us reduced and the large No compression requirement us eliminated.
After the net C02 is compressed to recover high pressure C02 gas or l~qu1d product, it then becomes lnexpens1ve and practical to separate the SO, NO and excess 2 by dlstlllatlon. Sulfur dlox1de us much less volt than C02 and is therefore essay distilled from C02.
SD3 us even less volatile and is readily separated with the S02.
N02 us also less volatile than C02 and will separate with the S02 and S03. While NO is very volatile, bullying at -152~C, it will react Thea excess 2 on the colder portions of the dlst111atlon system to form nonvolatile N02 and therefore separate with the S02 and S03 as previously noted. Accordingly, it can be seen that thus reaction on the dlstlllat10n system us an important means of obtaln1ng complete NO
separation.
In the process of the present ~nventlon the use of extolling flue gas wet scrubbing technology to remove sulfur oxides typified by Render, et at. on US. Patent 3,970,740 is not practical. The high C02 concentrat10n (86X vs. Rudders 15X) would result on high caustic consumption resulting in a high water nicotine rate and a major water treating problem. The water conta1nlng sodium sulfite requires I

slgn~flcantly more processing than the d1stlllatlon separation of Six and Ho which can then be directly processed on a Claus or sulfuric cold 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 ~n~ectlon us required as the combustion product water us suff1c~ent to rod the system of parttculates. Thus reduces the amount of water and the sulfate concentration slgnlflcantly compared to Render et at. thereby mlnlmlzlng the water treating requirements.
Separation of 2 from C02 by d1stlllat~on is also complicated by C2 freezing problems that develop below the C02 triple point temperature of -56.5C. To separate pure 2 would require 2 liquid reflex at temperatures below the 2 critical temperature of -118DC. In the proposed system the 2 rectlflcatlon section top temperature is held above -56.5C to avoid freezing and this gives an impure 2 reject stream containing substantial C02. Preferably in the proposed system this reject stream is recycled to the FCC regeneration section thereby avoiding losses of valuable 2 and C02. A small vent stream will be required to purge neuritis from the system.
From the foregoing the unique integrated ~nteract10n of the proposed system us evident. FCC regeneration with 02/C02 can give increased coke burning capacity but alone it us uneconomical. Recovery of C2 from FCC regenerator flue gas us desirable but uneconomical with elf regeneration due to the large amount of nitrogen present.
El~m~nat~on of FCC regenerator SO and NO emlss~ons is increasingly required to meet air quality demands but available technology us expensive and gives only partial removal. The proposed lnvent~on allows substantially complete 2 utlllzat10n substantially complete recovery of pure C02 product and essentially complete separation of SO and NO
pollutants from the flue gas that can be processed in a Claus sulfur plant or on a sulfuric cold plant to generate usable byproducts In FIG 2 an alternate embodiment of the present invention is shown on which coked spent catalyst 117 from a flu~d~zed catalytic cracker reactor 113 us introduced into the regenerator 120 and us regenerated by an up flow 122 on a fluldlzlng manner of a mixture of commercially pure ~23~6~) I

oxygen gas diluted with carbon dockside on the same manner previously described on the preferred embodiment of thus 1nvent~on. The reactor and regenerator and their parts are numbered corresponding to FIG 1 but with the 100 serves of numbers.
The effluent stream from the regenerator leaves on Noah 123 and consists of the same components as described in the preferred embodiment - C0 C02 H20- 2 sulfur oxides nitrogen oxides and part~culates.
The effluent gas stream 123 us 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 HIS and I The catalyst us typically sulf~ded cobalt and molybdenum on sillca-alum~na support as described by Beacon in US. Patent 3 752 877 temperature will be a function of the specie catalyst employed. The hydrogen required for the reduction reactions will be generated by shifting the C0 and H20 on 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 lnterstage cooling to remove the heat of reaction. In this instance 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 no comprises carbon monoxide carbon dockside water hydrogen HIS No and partlculates along with other trace gases such as argon introduced on the oxygen stream 176 to the regenerator. Stream 129 us cooled in waste heat bowler 131 to about 260C producing high quality steam. The cooled effluent 133 us then adiabatically quenched to less than 95C by recycle water stream 137 typically in a venturi scrubber 135 to separate the fine catalyst partlculates from the vapor stream. The venturi scrubber effluent 139 us separated unto a vapor and liquid phase in vessel 140.
The llqu~d phase is primarily water containing essentially all partlculates from stream 133 and some dissolved HIS. The sour water 136 is pumped (134) back to the venturi scrubber 135 on lone 137. A net sour process water stream 138 produced from the combustion of coke and contaln~rlg the net catalyst part~culates us withdrawn for further 19 ~'~3~6~

processing. Other gas cooling schemes can be employed 1nclud1ng schemes without the venturi scrubber or with heat exchangers in place of the direct quench tower. However on this preferred method with a Yentur1 scrubber followed by a direct quench cooling tower particulate removal is fac111tated temperature us reduced and pressure drop us m1nlmlzed.
The vapor phase from separator 1~0 comprising CO C02 H20 :-HIS No Us passes into vessel 1~1 where it us further typically quenched to less than 38C against a spray of cool water from fine 153.
The quench water is withdrawn from vessel 141 in fine 143 and pumped (147) through cooler 14g to reduce the temperature to typically less than 35C and reheated into quench tower 141 in fine 153. Net process water is withdrawn on fine lSl and 1n~ected unto vessel 140. Fresh makeup water can be added to quench tower 141 in fine 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 H25 on reactor 128 no sulfuric cold is present thus ellmlnatlng sulfuric acid Carson problems. The quenched effluent gas 155 from tower 141 us compressed in a multistage compressor 159 preferably to a pressure of 10-20 elm. depending on the COOK Wright of the gas. Interstate cooling us performed in exchangers 161 and 163 and sour water is removed on Nazi 165 and 167 and combined with sour water from fine 138 in fine 169. The compressed gas 171 us then after cooled to a temperature of about 40C in aftercoollng heat exchanger 173 which is supplied with ambient cold water and additional sour water is knocked out on Noah 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 on stream 177 us cooled to as low a temperature as possible - typically 5-10C - on heat exchanger 179 to condense as much water as possible without forming hydrates. Water is separated from the chilled gas which us then dried on an absorpt10n system 181 smiler to that described in the primary embodiment. The dried gas enters the auto-refr19erated heat exchanger 183 where it is cooled to about -50C. The recycle C02 us 11quefted and then separated from the net combust10n gas vapor 201 in vessel 187. The net gas vapor 2nl is warmed to about 0C against the cooling feed in exchanger 183.

~3~L66~

The liquid recycle C02 189 is flashed in 3-T valve 190 to obtain refr1geratton. To prevent freezing of the recycle C02, the pressure downstream of valve 190 us controlled to malnta1n the temperature in fine 191 at about -55C. The cold recycle 2 in fine 191 is warmed against the cooling feed in exchanger 183. The rewarmed recycle C02 193 is then expanded to about 1.5-3 elm. in turbine 195 to recover power, warmed :-on exchanger 199, providing low temperature cooling for the downstream gas separation, and finally warmed against the cooling effluent gas 177 on exchanger 179. The recycle C02 197, comprising primarily C02 and small quantities of C0 and HIS, 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 C2 and net combustion 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 refr1geratlon duty required in exchangers 179 and 183 and the power recovered in 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 ~ustlf1ed.
The warmed vapor stream 203 containing the net combustion products C0, C02, HIS, No and Ho is compressed in compressor 205 to about 40 elm.
The net effluent flue gas stream 213 is then heated in heat exchanger 215 to 315-345C.
Steam is added to the heated stream 217 from fine 221 and the combined stream in fine 223 us introduced into the first of three shift reactors 225, 239 and 243.
Shift reactor 225 contains a sour shift catalyst because of the HIS content of the gas, such as sulflded cobalt-molybdenum on alumina able to withstand large temperature increases. The shift reaction converts carbon monoxide as follows:
C0 H 0 H + C0 The reaction partially shifts the carbon monoxide toward equlllbrlum Thea hydrogen exothermlcally, resulting in a substantial temperature rise.
Exit stream 227 prom the reactor 225 is cooled in heat exchanger 231 to 21 ~3~L~6~

315-345C and the cooled stream on Noah 233 undergoes a second shift on reactor 239. This reactor also contains sour shift catalyst and add1tlonal carbon monoxide us shifted to hydrogen. The effluent us cooled on heat exchanger 241 to approximately 200C and enters the third shift reactor 243 continuing sour shift catalyst.
The shifted effluent gas stream us cooled on heat exchanger 240 to :-ambient temperature and condensate us removed on Noah 242. The cooled stream 244 comprises primarily hydrogen carbon d10x1de and water with small amounts of CO HIS and argon. It enters hydrogen sulfide absorber tower 246 where it is contacted with an HIS lean physical solvent 261 to selectively absorb essentially all hydrogen sulfide and only a fract10n of the C02. HIS rich solvent 291 us withdrawn from the bottom of absorber 246 and fed to C02 stripper 295. The coabsorbed C2 us flashed and stropped with some of the product hydrogen 296 from the HIS rich solvent on vessel 295. The C02 vapor 297 us compressed to about 40 elm. on compressor 301. The h19h pressure C02 stream 303 us combined with the cooled shift effluent stream 244 and recycled to the HIS absorber 246. The HIS rich solvent 305 from stripper 295 us flashed to about lo elm. on valve 307 and 1n~ected unto the HIS
stripper 309 to regenerate the solvent. Stropping gas us generated by rebiller 323. The stripper overhead 311 us partially condensed on exchanger 313 and separated on vessel 315. The liquid 317 us returned to the column as reflex and the vapor 319 which contains concentrated HIS us withdrawn from separator 315 as a net product 319 for processing to sulfur typically on a Claus sulfur plant. The lean solvent 321 continuing essentially no Ho or C02 is withdrawn from the HIS
stripper 309 bottoms and pumped (325) to about 40 elm. Thus solvent on Noah 327 us combined with lean solvent 283 from the C02 stripper 273.
Overhead gas 245 from HIS absorber 246 comprising C02 and Ho with some CO and essentially no HIS us cooled on exchanger 247 and fed to C02 absorber 253 on Noah 251 where it us contacted with clean physical solvent 25S to absorb carbon dockside. Hydrogen product essentially free of carbon dlox1de us removed from tower 253 as an overhead stream on Noah 257. The hydrogen stream 257 contains residual carbon monoxide that typically would be essentially completely eliminated by catalytic methanat10n.
The carbon d10x1de loaded solvent us removed as bottom stream 258, and d1v1ded unto two streams. Part of the stream us pumped (259) to about 40 elm. to provide HIS lean solvent 261 for HIS absorber 246.
The net C02 rich solvent us flashed on valve 263 before being phase separated on separator 267. Gaseous carbon d10x1de is removed as an overhead stream on Noah 265 as a pure product that can be compressed to high pressure and used for enhanced owe recovery operat10ns or 11quefled for export product uses.
The solvent on separator 267 is removed as bottom stream 269 and introduced unto stripper column 273 where residual carbon d10x1de is stropped from the solvent with nitrogen introduced in fine 277 and the stropped gas us vented on Noah 275. The lean solvent us removed in fine 279 and pumped to pressure on pump 281. Lean solvent 283 us combined with lean solvent 327, cooled by heat exchanger 285 and reintroduced into tower 253 through Noah 255.
Thus net gas separation process is described by Nicholas, et at. on US. Patent 4,242,108 This embodiment of the present ~nvent10n 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 C02 product for sale on enhanced oil recovery or merchant use, plus two add1t10nal advantages:
produces a pure hydrogen product, and . reduces oxygen consumption.
FCC regenerator flue gas comprises typically 0-15X C0, lox H20, lo sulfur and nitrogen oxides, traces of HIS and oxygen, with C02 making up the balance when the fluldlzatlon/combustlon gas us a mixture of 02/C02. To make product10n of hydrogen from thus stream practical, a process must accomplish four thongs:

2316~i0 el~m1nat10n of oxygen and potential for producing solid sulfur by react10n with HIS, separation of recycle C02 from the net flue gas combust10n products, concentrat10n of C0 for favorable shift equilibrium, and . separation of sulfur species from product C02. - --The unique, integrated process conf19uratlon defined in thus embodiment makes hydrogen product10n from FCC flue gas C0 economically practical. The deoxygenatlon, reduct10n reactor, the auto-refr19erated J-T C0/C02 separat10n, the sour shift system, and the selective HIS
removal system work on concert to achieve the benefits of this embodiment.
The deoxygenat10n, reduct10n reactor is required to prevent plugging from the format10n of solid sulfur in the downstream equipment via reaction of oxygen, HIS, and S02. Trace components such as COY and nitrogen oxides are also eliminated on the process. By reducing all sulfur and nitrogen species to HIS and No, sulfur bu11dup in the recycle loop us reduced since HIS us much more volt than S02; the corrosion problem caused by sulfuric acid format10n from sulfur tr10xide and water us eliminated; and a gas stream that can be processed over a commercially ava11able sour shift catalyst at lower steamtdry gas ratios than required for conventional iron-chrome "sweet shift catalysts results. The auto-refr1gerated, J-T flash separat10n of C0/C02 provides a highly concentrated C02 recycle stream comprising I C0 and c2% HIS and a concentrated C0 stream comprising the net combust10n C0 and C02 for shifting to hydrogen. The physical properties of carbon d10xlde make thus type of C0/C02 separat10n process possible, whereas it us not possible to separate nitrogen on thus manner.
The selective HIS remove produces a sulfur free C02 product that can be compressed to h19h pressure for use in enhanced oil recovery or coughed for merchant sales.
Although thus embodiment of the present 1nvent10n shifts C0 essentially completely to hydrogen, it is possible to only partially shift the C0 to hydrogen thereby producing a Ho and C0 synthesis gas 24 ~231~0 mixture. Thus wow reduce the amount of C02 product by the amount of C0 on the synthesis gas.
Although the present 1nventlon So herein described on two preferred ernbod1ments with respect to regenerat10n of fluld~zed cracker catalyst, it us also contemplated that the 1nvent10n can be practiced on other flu1dlzed hydrocarbon and petroleum processing systems whereon particulate matter us continuously cycled from a reactor to a regenerator.
For example, the present 1nvent10n can be ut111zed in the asphalt residuum treatment process (ART) of Englehard Minerals and Chemicals Corp., as described on US. Patent 4,243,514 1nappropr1ate for direct processing on a flu1d1zed catalytic cracking reactor, us 1n1t1ally processed in a flooded reactor continuing a h19h temperature inert particulate matter, such as a specially treated kaolin clay. High Boeing and coking components, as veil as metals prom the residuum are deposited on hot particulate matter on the flu1d1zed reactor wow the remanning residuum us vaporized and removed for ref1nlng in a flu1d1zed catalytic cracker. The carbon and metals fouled particulate matter us removed to a regenerator where oxygen and carbon d10x1de flu1dlze the fouled particulate matter and burn the carbon from the inert particles. Metal bu11d-up us allowed to proceed unwept a predetermined level us achieved and fresh particulate matter us added and metal fouled inert particles are removed from the regenerator. The effluent from the regenerator us treated on a smear manner to that described above.
Carbon d10x1de from the effluent can be recycled to Dwight and moderate the n1trogen-free oxygen feed to the inert particulate matter regenerator.
The present 1nventlon can also be practiced on a thermal flu1d1zed cracking system as shown on FIG 3. Exemplary of a thermal system us the flu1dcok1ng process, such as is described on US. Patent 2,527,575 such as a heavy vacuum residuum, us cracked on a flu1d1zed reactor loaded with hot particulate coke. The coke thermally cracks the residuum and on turn fresh carbonaceous matter deposits on the particulate coke. As the ~L23~

process continues, the coke becomes larger and it us necessary to continuously remove some of the carbonaceous maternal coated coke to reheat it and reduce it on size. The coated coke us removed to a regenerator on 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 on the reactor. Reheated coke us returned to the reactor and a coke product us removed from the regenerator. Again, thus regenerator or coke burner can be flu~d1zed and the combust10n sustained with a mixture of oxygen and carbon d10x1de. The resulting effluent can be treated, and the carbon d10x1de recycled as described above.
In a var1at10n of the flu1dcok1ng system, a flex~cok1ng process can also be operated on the manner of the present 1nvent10n as shown on FIG 4. Flex1coking partially combusts the net coke such as us produced on flu1dcok1ng to produce a low BTU fuel gas effluent of high temperature. Thus effluent, on turn, is used as the fluld1z1ng gas in the regenerator or coke heater. As described on US. Patent 3,661,543, process whereon particulate matter on the form of hot coke cracks the hydrocarbon feed, usually a heavy residuum. Carbonaceous maternal on the form of add1t10nal coke us deposited on the particulate coke of the flu1d1zed reactor, and the coke us reduced on temperature. Part o-f thus coke us 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 combust10n of coke on yet another vessel, a coke gas1f1er or regenerator. The reheated coke us continuously returned to the reactor and the low BTU fuel gas high gave up heat to the coke us removed from the coke heater as an effluent. The net coke from the reactor Shea passes through the heater us partially combusted on the gas~f1er generating the heat necessary for thermal cracking. In the present lnvent10n, the gas1f1er us supplied with a stream of oxygen and carbon d10x1de, the latter of which can be recycled carbon d10x1de from the effluent of the coke heater. Thus on flex1cok1ng, the oxygen/carbon d10x1de us fed to the gas~f1er or heat regenerator, and the effluent to be treated us removed from the coke heater. Thus, of course, is the gas produced on the gas~f1er and heat exchanged on the coke heater.

~3~L660 In thus context, the term particulate matter refers to a number of substrates which can be used on a flu1dlzed hydrocarbon refining reactor as contact particles, such as catalyst for catalytic cracking, inert clays for the asphalt residual treatment and coke for the flu1dcoklng and flexlcoklng processes. The carbon or coke buildup on such particles is generally termed carbonaceous r~ter1al. Lastly, in this spec1f1cat~on, the term regenerator is understood to include regenerators for fluldlzed catalytic cracking, burners for the asphalt residuum treatment and the fluldcok~ng process, and the coke gaslfler for the flexlcoklng process.
The present invention has been described in detail with the specific embodiments set forth above, but it is deemed that the lnvent10n could be practiced by one skilled in the art with various modlflcatlons.
Therefore, the scope of the present invention should not be deemed to be 11mlted to the spec1f1c embodiments set forth, but rather should be ascertained from the claims which follow.

Claims (12)

The embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows:-
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) 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;

d) compressing the effluent gas to approximately the inlet pressure of the combustion zone;

e) splitting the effluent gas into a carbon dioxide-rich recycle gas stream and a net gas stream, and f) recycling the carbon dioxide-rich recycle gas stream to the combustion zone as the diluent for oxygen fed to the zone for combustion.
2. The process of Claim 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 with the attendant removal of condensed water;

i) 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 nitrogen.
3. The process of Claim 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, wherein essentially no residual carbon monoxide exists, with a mixture of oxygen diluted with 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 with the attendant removal of condensed water;

i) 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 nitrogen.
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 with 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 H2S and NOx 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 entrainment 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 dioxide-rich recycle stream to the combustion zone as the diluent for oxygen fed to the zone for combustion.
9. The process of Claim 8 further comprising the steps of:
h) compressing the net combustion product gas to an elevated pressure;

i) shifting 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.
10. The process of Claim 8 wherein the separation of step f) is performed predominantly with auto refrigeration.
11. The process of Claim 9 wherein the separation of step j) is performed by a physical solvent which selectively absorbs H2S to a greater extent than CO2 and does not absorb an appreciable amount of H2 .
12. The process of Claim 9 wherein the shifting of carbon monoxide of step i) is only partially complete and the separation of step j) results in the hydrogen stream having a significant carbon monoxide content.
CA000470693A 1984-04-13 1984-12-20 Process for the recovery and recycle of effluent gas from the regeneration of particulate matter with oxygen and carbon dioxide Expired CA1231660A (en)

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US4542114A (en) 1985-09-17
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EP0162251A1 (en) 1985-11-27
DE3563691D1 (en) 1988-08-18

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