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Publication numberUS2952611 A
Publication typeGrant
Publication dateSep 13, 1960
Filing dateMar 11, 1958
Priority dateMar 11, 1958
Publication numberUS 2952611 A, US 2952611A, US-A-2952611, US2952611 A, US2952611A
InventorsHaxton Manford R, Johnston Jr Walker F, Muller Jr Karl A
Original AssigneeAmerican Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Regenerative platinum catalyst reforming
US 2952611 A
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Description  (OCR text may contain errors)

Spt. 13, 1960 Filed March 11, 1958 WATER CONCENTRATION, PPM

VOL. '70

(Based on Nuphtha Feed) (1) M. R. HAXTON ET AL 2,952,611

REGENERATIVE PLATINUM CATALYST REFORMING V 2 Sheets-Sheet 2 6 J so m Fig. 2 r- 79 cc 7a o l-L LLI II 77 WATER CONCENTRATION, PPM (Based on Naphthu Feed) 3O 6O 90 I20 I50 I80 2IO 240 270 300 330 360 390 420 450 480 510 540 HOURS ON OIL Fig. 3

United States Patent, Office 2,952,611 Patented Sept. 13, 1960 REGENERATIVE PLATINUM CATALYST REFORMING Manford R. Haxton, Texas City, Walker F. Johnston, In, La Marque, and Karl A. Muller, Jr., Houston, Tex., assignors to The American Oil Company, Texas City, Tex., a corporation of Texas Filed Mar. 11, 1958, Ser. No. 720,750 16 Claims. 61. 208-65 This application relates to the regenerative hydroforming of petroleum naphthas over supported platinum catalysts. More particularly, it relates to a method and means for coping with the unique problems associated with the presence of even minute amounts of water in the reaction Zone of regenerative hydroforming systems which operate at low pressure and employ halogen-containing supported platinum catalysts to produce very high octane reformates.

When reforming hydrocarbon naphthas using halogencontaining platinum supported catalyst, e.g., 0.1 to 2 weight percent platinum and about .05 to 2 weight percent halogen, usually fluoride or chloride, supported on some form of alumina-containing base, water addition was heretofore considered a method of suppressing hydrocracking and thus raising yields (see, for example, Berger et al. U.S.P. 2,642,383, June 16, 1953). Moreover, this suppression of hydrocracking went beyond the effect of mere halogen stripping. With the advent of regenerative hydroforming processes (such as exemplified by UltraformingPetroleum Engineer, vol. XXVI, No. 4, April 1954, at page C-35) employing low pressures, i.e., less than about 400 pounds per square inch gage, to obtain Very high octane reformates, i.e., octanes above about 95 clear, Research method (CFRR), unexpected eflects from the presence of even minute quantities of water were discovered. It was also discovered that conventional techniques used in non-regenerative reforming systems for water control (e.g., drying of naphtha or recycle gas) were ineffective in the case of regenerative reforming. a

It is therefore an object of the present invention to improve low pressure regenerative platinum catalyst reforming by achieving superdry conditions continuously with the greatest economy and minimum regeneration cycle time. Another object is to provide an improved low-pressure regenerative platinum catalyst reforming system which continuously maximizes yields, octane potential, and catalyst life and limits the need for halogen replacement to that associated with halogen loss during regeneration. It is still another object of the present invention to provide an integrated drying system which copes with the unique Water problems associated with low-pressure regenerative platinum catalyst hydroforming systems operating at very high octane levels. These and other objects of the present invention will become apparent as the detailed description proceeds.

Unlike operations at substantially higher pressures and lower octane levels, the yield of high octane reformate from low-pressure regenerative reforming systems is improved at constant catalyst halogen levels by lowering water levels. The improvement in reformate yields is slight as water content is reduced to a level of about 100 parts per million. Below this level, however, it has been discovered that a very rapid and surprising increase in reformate yields is obtained. Also, in addition to minimizing halogen stripping and maximizing reformate yields and octane potential, achieving the super dry conditons of the present invention during the oil cycle substantially decreases the rate of loss of catalyst surface area during the regeneration cycle. Thus, the number of regenerations to which the catalyst may be subjected and ultimate catalyst life is maximized.

It has also now been discovered that to achieve the surprising benefits associated with such super-dry conditions when producing very high octane reformates at low pressure, unique water sources must be coped with in regenerative reforming systems, particularly when operations require substantially daily regenerations of a reactor. With the problem now recognized, we achieve these heretofore unappreciated advantages by maintaining the total water in the reaction system continuously and substantially below about parts per million, preferably below about 50 parts per million, and optimally below about 20 parts per million, based on charge stock. (A convenient method of ascertaining water content in the reaction system is to measure the water content of the eflluent stream from the last on-stream reactor.)

We accomplish this new type operation by a unique drying system, i.e., a combination of feed driers, recycle gas driers, regeneration gas driers, and scrubbers for removing carbon oxides from flue gas usedto seal reactor switch valves. More specifically, our improved method of operation comprises drying the naphtha charge stock to lower the water content below about 20 p.p.m., based on charge stock; drying the separated hydrogen-rich gas from the product separator to lower the water content to a level at least below that corresponding to a 40 F. dew point at atmospheric pressure; drying catalyst regeneration gases to a water content below that corresponding to a F. dew point at atmospheric pressure; and scrubbing flue gas used for sealing the reactor switch valves to reduce the carbon oxides content below at least about 1 mol percent. I

For drying the charge stock we prefer to contact the naphtha in the liquid phase with a conventional solid desiccant, e.g., silica gel, activated alumina (bauxite), molecular sieves, anhydrous calcium sulfate, and the like. This adsorbent drier is normally supplemented by a water coalescer to remove entrained water from the naphtha before charging the naphtha to the drier. Following the drier, water content of the naphtha may still further be reduced by stripping water therefrom with a portion of the hydrogen rich separator gas, which has also been dried, at least intermittently, as hereinafter described. For drying hydrogen-rich separator gas for recycling and stripping, the gas is normally charged to a conventional solid desiccant drier, e.g., silica gel, bauxite, anhydrous calcium sulfate, and the like. For reducing moisture content of regeneration gases, solid desiccant driers such as above may be used, but generally a cool-water spray tower is used in place of or in addition to, the desiccant drier to lower the dew point of the regeneration gases below about 150 F., and preferably to at least about 100 F. Drying of regeneration gasesis particularly important where regeneration gases are recirculated. For removing carbon oxides from flue gas usedfor sealing reactor switch valves, any technique of the prior art may be used, for example, water scrubbing, contacting with activated charcoal, or, preferably, contacting the flue gas with an aqueous ethanolamine solution. Co'ntacting of the flue gas is preferably carried out at temperatures below about 150 F., e.g., about 100 F.,, to condense out water.

As will be described in detail in the specific examples hereinafter, there are several unique sources of water in regenerative hydroforming systems which are not present in non-regenerative systems. Among these unique sourcesof water is the water produced by reduction over platinum catalyst of carbon oxides in the flue gas used for sealing the reactor switch valves. Sufficient flue gas leaks into the reaction system to produce as much as several hundred parts per million of equivalent water. Removal of carbon oxides from seal gas eliminates this source of water. Another significant source of water results from the moisture adsorbed andoxides formed during the regeneration cycle. Condensing water from the recirculated regeneration gases substantially reduces moisture sorbed on the catalyst. As soon as a reactor of freshlyregenerated catalyst is returnedto on-stream operation, however, hydrogen in the reaction zone reduces the oxides formed during regeneration to form substantial quantities of water, for example, up to about 1000 parts per million, during the first 1 to hours after the reaction zone is returned to on-stream operation. This intermittent source of water presented no grave problem in multi-reactor systems employing a swing reactor for regeneration until the advent of operations near the 100 octane level (CPR-R clear), at which level high-frequency (at least one reactor daily) regenerations are employed. At such levels the so called intermittent source of water becomes substantially continual. Drying separator gas at least immediately'after returning a reactor to on-stream operation eliminates this moisture.

In a specific embodiment of the invention we take advantage of the fact that recycle gas drying is required only during the first few hours after returning a reactor to on-stream operation. Specifically, the recycle gas is dried only during the first portion of the period after a reactor is returned to on-stream operation. The drier is then removed for regeneration and again returned to the system when another reactor of platinum catalyst is brought on-stream after regeneration. Generally, an interval of more than at least about 12 hours passes between swinging reactors of freshly-regenerated catalyst to on-stream operation. Thus, separator gas drying is required for less than half the interval. This embodiment has the substantial advantages of requiring only one drier, rather than at least two driers alternating between drying cycles and regeneration cycles. It also has the advantage of reducing pressure drop in the recycle gas system during the period when no drying is required and thus reducing compression costs.

The invention will be more clearly understood by reference to the following example read in conjunction with the accompanying drawing which is a schematic flow diagram of an Ultraforming system in which the problem of water control has been successfully solved.

In normal operation of an Ultraforming system a naphtha charge, such as, for example, the 200360 F. fraction of a Gulf Coast naphthenic' naphtha having a water content of about 400 parts per million, or about 60 percent above the saturation value of 250 parts per million at 105 F., is introduced from source 1 to coalescer-settler 2, from which entrained water in the naphtha is removed via line 2a. Coalescer 2 may be of conventional design, such as a cartridge-type or porous plastic membrane-type coalescer-settler. Naphtha leaving coalescer-settler 2 by means of pump 2b in line 3 may contain about 250 parts per million of water. Naphtha in line 3 is charged via line 3a to drier 4a or Via line 3b to. drier 4b, wherein water is further reduced by a solid desiccant, e.g., activated bauxite, to a level of about 40 parts per million. Driers 4a and 4b are alternated between on-stream operation and regeneration, as will be further described hereinafter. Dried naphtha leaving drier 4a or 4b via lines 5a or 5b respectively is then charged via line 6 to stripper 7, wherein separator gas from line 31 is used to strip the water content to less than about 10 parts per million. To accomplish such stripping, the separator gas from line 31 must have a very low water content, which is achieved by scrubbing carbon oxides from the seal gas, by dewaten'ng regeneration gases, and by drying the'separator gas for at least a short period simultaneously with returning a reactor of '4 freshly-regenerated catalyst to on-s-tream operation, as will be described hereinafter.

Stripped naphtha is then charged via line 8 and preheater 9 to' transfer line 10, from which the preheated charge may be by-passed via line 11 to the product recovery system during start-up procedure. In on-strearn operation transferline 10 will discharge through lines 12 and 13 to reactor 14 along with hydrogen-rich recycle gas from line 15 which is preheated in heater 16. Effluent from reactor 14 passes through line 17, reheater 18 and transfer line 19 to reactor 20. Eflluent from reactor 20 passes through line 21, reheater 22 and transfer line 23 to tail reactor 24. It should be understood that more than three reheater-reactor. stages may be employed in the system. .Efiiuent from the tail reactor flows through lines 25 and 25c, heat exchanger 26, and cooler 27 to separator 28 from which hydroforrned product is withdrawn through line 29 to a stabilizer and/or conventional product recovery system and hydrogen-rich gas is withdrawn via line 30.

Transfer lines 11a, 13a, 19a and 23a may be selectively connected to header 34 for discharging through line 35 to swing reactor 36, the effluent from which passes through line 37 to header 38 and thence through line 17a to line 17, line 21a to line-21, or line 25a to line 25. During normal on-stream operation without the swing reactor the valves in lines 11, 11a, 13a, 13b, 17a, 17b, 19a, 19b, 21a, 21b, 23a, 23b, 25a, and25b remain closed and the valves in lines 12, 13,17, 19, 21, 23 and 25 remain open.

The swing reactor may be substituted for the lead reactor by opening Valves in lines 13a, 35, 37 and 17a and closing valves in lines 13 and 17. Alternatively, it may be substituted for intermediate reactor 20 by opening valves in lines 19a, 35, 37 and 21a andclosing the valves in lines 19 and 21. The swing reactor may take the place of the tail reactor by opening valves in lines 23a, 35, 37 and 25a and closing valves in lines 23 and 25. It will thus be seen that each of the reactors may be taken oil-stream for regeneration and replaced by the swing reactor and that, alternatively, the swing reactor may be connected to operate in parallel with any of the other on-stream reactors during periods when no regeneration is required.

Each of the reactors is provided with a refractory lining of low iron content, and metal surfaces may preferably be aluminized. They may each contain about the same amount of catalyst although, if desired, the subsequent reactors may contain somewhat more catalyst than the initial reactors. The catalyst may be of any known type of supported platinum catalyst, and the platinum is preferably supported on alumina; it maybe prepared by compositing a platinum chloride with an alumina support asdescribed, for example, in US, Patent 2,659,701, and it preferably contains about .3 to .6 weight percent of platinum.

For optimum-operations halogen level on the catalyst should be maintained at some predetermined level within the range of about .0;5 to 1.5 weight percent, e.g., 1.0 weight percent, and this level should preferably be maintained constant'throughout the oil cycle of each reactor. The exact halogenlevel depends on' the particular operating conditions, feed stock, etc. The super dry operation permitted by the method and means of the present invention substantially eliminates halogen stripping during the oil cycleand thus assures substantially constant halogen level. Any halogen lost during regenera tion may be replaced by halogen treating of the catalyst prior to. on-stream operation. Halogen stripping during regeneration i minimized bytcontrolling moisture content of-regeneration gases} Conveniently, such water control is achieved by cooling regeneration gases to condense excess moisture-by, for example, a-water spray tower further describedhereinafter. Sulfur level in the fieetionzone is maintained at -the level of about 10 to 100 parts per million, and, if the naphtha charge stock is desulfurized to lower equivalent levels, sulfur may be added back to arrive at the desired sulfur level in the reaction zone.

The on-stream pressure is usually below about 400 pounds per square inch gage, e.g., in the range of 200 to 350 pounds per square inch gage. The inlet tempera tures to each reactor are usually in the range of about 800 to 1000" F., e.g., about 920 F., and may be approximately the same for each reactor although it is sometimes desirable to employ somewhat lower inlet temperature to the initial reactor than to the remaining reactors. The overall weight space velocity may be in the range of about 0.5 to 5 pounds of naphtha per pound of catalyst per hour. There is, of course, a pressure drop in the system so that the lead reactor may operate at about 20 to 100 pounds per square inch higher pressure than the tail reactor.

Prior to regeneration hot hydrogen-rich gas for stripping hydrocarbons from catalyst in a blocked-out reactor may be introduced by line 63 to manifold line 40 and thence through one of lines 13b, 19b, 23b, or 35b to the selected reactor. Also, if desired, hydrogen-rich gas may be introduced from line 15 via line 64 to mani fold line 39 and thence through one of lines 17b, 21b, 25b, or 37b to the selected reactor.

For effecting purging and/or regeneration of the catalyst in any bed, purge gases and/ or regeneration gases may be introduced either through manifold line 39 and a selected one of lines 17b, 21b, 25b or 37b or through manifold line 40 and a selected one of lines 13b, 19b, 23b, or 35b. Such purge and regeneration gases may be selectively withdrawn through corresponding lines at the top or bottom of the reactor, as the case may be, to the appropriate manifold. Gases may be vented or flared from manifold line 39 via valved line 58. Correspondingly, gases may be vented or flared from manifold line 40 via valved line 41.

Flue gas from source 42, which is normally the products from combustion of hydrocarbons in air, may be introduced to the system by compressor 43 and passed by lines 44 and 45 through a drying chamber 46 which is preferably a scrubbing tower into which cool water is introduced through line 47 and from which water is withdrawn through line 48. The scrubbed flue gas withdrawn from the top of the tower through line 49 is passed by compressor 50 through line 51, heat exchanger 52, and heater 53 either to line 54 and manifold line 39 or to lines 55, 56 and manifold 40, when it is desired to introduce flue gas into the system for purging and/or regeneration. By closing the valves in lines 54 and 56 and opening the valves in lines 55- and 57, the flue gas may be recirculated through line 57, heat exchanger 52 and line 45 back to scrubber 46. Air may be introduced from source 60 by compressor 61 for eflecting regeneration and/or regeneration-rejuvenation of the catalyst. Rejuvenation is an additional oxidative treatment after the regenerative coke burn. During regeneration excess flue gas may be vented from the system by line 62. Air and/orflue gas from manifold line 39 may be introduced to the inlet of circulating compressor 33 by line 59.

One unique characteristic of the Ultraforming process, in "contrast with non-regenerative platinum reforming processes, is the fact that an Ultraformer can be started up without use of extraneous hydrogen. Such a startup procedure, is described in co-pending application S.N. 502,604, filed April 20, 1955, now issued as U.S. Patent No. 2,910,430.

The method of eflecting catalyst regeneration will be described as applied to the swing reactor but it will be understood that the same procedure may be employed for any one of the other reactors when it is blocked out. When the charge inlet valve in line 35 is closed and ,whilethe .valve in line 37 remains open, hot hydrogenrich gas is introduced by line 63 to manifold line 40 and thence through line 35b to strip out any hydrocarbons that may remain in the reactor, this stripped material being discharged through lines 37, 38, 25a, and 250. Next, the valve in lines 63 and 37 are closed and reactor 36 is depressured by opening valve in lines 37b and 58. Next, the reactor is purged to eliminate hydrogen-rich gas by introducing flue gas from the regeneration facilities via lines 55, 56, 40, and 3511, the purge gases being vented through lines 37b, 39, and 58. After the flue gas purge, valve in line 58 is closed and introduction of flue gas from source 42 is continued to pressure the reactor with flue gas to approximately the same pressure as that employed in on-stream processing, i.e., about 300 pounds per square inch gage. The temperature of the catalyst bed is adjusted to about 700' to 750 F. preparatory to initiating regeneration by circulating flue gas, under such pressure, upflow through the reactor by means of compressor 50. The circulating flue gas leaves and returns to swing reactor 36 via 35b, 40, 56, 57, 52, 45, 46, 49, 50, 51, 52, 53, 54, 39, and 37b, the appropriate valves being open or closed as the case may be. Heat may be supplied to the circulating gas by heater 53, if necessary.

Next, controlled amounts of air are introduced from source 60 by compressor 61 into the circulating flue gas stream at a rate to effect combustion of carbonaceous deposits without exceeding a combustion zone temperature of about 1050 F. The combustion front starts at the bottom of the catalyst bed and progressively passes up through the bed. The hot flue gas leaving the reactor at about this temperature passes via lines 35b, 40, 56, and 57 through heat exchanger 52 and thence through line 45 to scrubber 46 wherein the gas is scrubbed with cool water for condensing and eliminating most of the water formed by combustion of hydrocarbonaceous deposits. The net amount of flue gas production is vented from the system through line 62, the valve in which is set to maintain the desired back pressure of about 300 pounds per square inch gage. The cooled flue gas which is recirculated by compressor 50 may be further dried by passing through a desiccant bed (not shown) before it is returned through heat exchanger 52 to heater 53 which, during regeneration, maintains a transfer line temperature of approximately 700 F.

If rejuvenation is required, the introduction of flue gas is stopped and the introduction of air is continued so that the catalyst is treated wtih a circulating air stream at a pressure of about to 350 pounds per square inch gage and a temperature of about 950 F. to 1100 F. for a period of about one-half hour to twelve hours or more depending upon the extent of rejuvenation required.

After the regeneration (or after rejuvenation if rejuvenation has also been effected) the introduction of air is stopped, and flue gas is again circulated to adjust catalyst bed temperature, if necessary. Simultaneously, additional flue gas is introduced from source 42 to displace oxygen from the swing reactor and from the regeneration system. Part of the circulating gases is vented via lines 58 and/or 41 at about the same rate as flue gas is added, thereby maintaining pressure substantially constant. After oxygen content is reduced below at least about 1 mol percent, the valves in lines 54 and 56 are closed, and introduction of flue gas is stopped. Swing reactor 36 is then depressured to about atmospheric pressure by slowly opening valve in line 58. After depressuring, valve in line 56 is again opened, and swing reactor 36 is again purged at about atmospheric pressure with line gas to remove all residual oxygen via line 58, after which the valve in line 56 is again closed. 7

After removal of all oxygen, the system is purged at about atmospheric pressure with hydrogen-rich recycle gas from line 15, which is introduced through lines 63, 40 and 35b by opening the valve in line 63. Valve in line 58 is then set to hold back reforming pressure, e.g., 300 pounds per square inch gage, and the system is pressuredup with hydrogen-rich recycle gas. When the re 7 actor is thus brought to desired operating pressure, valves in lines 63, 35b and 37b are closed, and the reactor may be'placed on-stream by opening valves in lines 35 and 37.

During regeneration and rejuvenation, dangerous and possibly explosive contact of oxygen-containing regeneration and rejuvenation gases with hydrogen and hydrocarbons is prevented by gas sealing reactor switch valves with inert flue gas. Thus, during regeneration/rejuvenation of swing reactor 36, valves in lines 63, 13b, 19b, 23b, 17b, 21b, and 25b, at a minimum, are gas sealed. The sealing gas is obtained from source 42 and ,is passed via compressor 43 and line 66 to seal gas scrubber 67, wherein substantially all carbon oxides are removed, i.e., to a level of less than about 1 mol percent. Convenient techniques for removing carbon oxides include adsorption on such solid adsorbents as activated carbon or zeolite molecular sieves, scrubbing with water (see Gas Adsorption Data for Carbon Oxides in Water, Chemical Engineers Handbook, Third Edition, McGraw-Hill, page 674), or adsorption by contact with an ethanolamine solution, e.g., aqueous solution of monoethanolamine or diethanolamine. If substantial water, e.g., more than that equivalent to a dew point of about 100 F., is present in the flue gas,

simultaneous removal of both the water and carbon oxides may be carried out, for example, by contacting flue gas with cold water such as in a water spray contacting tower. Alternatively, Water and carbon oxides may be removed in separate steps. In a preferred embodiment the flue gas is reduced to a temperature below about 150 F., e.g., 100 F. to condense water therefrom and then charged to an ethanolamine scrubber, e.g. a monoethanolamine contactor, to remove carbon oxides. The scrubbed sealing gas, which is substantially pure nitrogen, is then passed via line 68 and a sealing gas distribution system (not shown) to the valve bonnets of the appropriate valves. 7 V

' It is both the regeneration and, particularly, rejuvenation which leaves the catalyst (and often system internals) in a highly oxidized state. When the reactor is then returned to on-stream operation, hydrogen in the hydrogen-rich separator gas reduces the oxides to form substantial quantities of Water in the system during the next few hours. The present invention successfully copes with this source of water as well as any adsorbed water on the catalyst. Thus long periods of purging with inert gas to remove adsorbed water and/ or with hydrogen-rich gas to remove adsorbed water and/ or water formed by reduction of oxides, e.g., platinum oxides, are no longer required. This substantially reduces regeneration cycle time and'permits raising regeneration frequency and, thus, overall activity levels.

To eliminate water in recycle gas, said water desorbed from regenerated catalyst and/or being formed in large part by reduction of oxides formed during regeneration/ rejuvenation, hydrogen-rich gas from separator 28 is passed via line 30 and 30b to drier 69 wherein the moisture content is lowered to at least below that corresponding to a --40 F. dew point at atmospheric pressure, preferably to a level corresponding to a -60 F. dew point at atmospheric pressure. Drier 69 may preferably employ a solid desiccant, e.g. silica gel, for adsorbing water.

After drying, the hydrogen-rich separator gas is passed 7 via line 70 to line 31 wherein a portion, e.g., 2000-8000 standard cubic feet per barrel of naphtha charge stock, is diverted to line 32 and compressor 33 for recycling vialine 15. At least another portion, usually the entire remainder of the separator gas, is passed vialine 31 to stripper 7 wherein the gas strips residual water from naphtha feed stock introduced via line 6. Off gas from stripper 7 is vented via line 71. 7

Since water resulting from. reduction of catalyst oxides formed during regeneration and/ or rejuvenation is formed only during about the first 1-5 hours after returning a reactor of freshly-regenerated catalyst to on-stream operation, drier '69 need only be in the system for such period. After about l-5 hours hydrogen-rich gas from separator 28 may be passed via line 30 and 30a directly to line 31, valves in lines 30b and being closed. The desiccant in'drier 69 may then be regenerated by heating to drive ofi adsorbed water and thereafter cooling prior to being returned to the system for drying the hydrogenrich separator gas. This has the substantial advantage of requiring only one drying vessel and also reducing pressure drop (by, for example, l-S pounds per square inch), and thus compression cost, in the recycle system during the period when desiccant in drier 69' is being regenerated. r V

A convenient technique for regenerating desiccant in drier 69 is to use oif gas from stripper 7 which is passed via'lines 71, 72, and 73a to heater 74, e.g., a salt bath heater, wherein the gas is heated to about 450 F., following which, via lines 75 and 70, it is passed, preferably downflow, through drier 69 to remove water. Regeneration gases leaving drier 69 are then passed via line 76 to cooler 77 and scrubber (gas-liquid separator) 78, wherein condensed water and/or naphtha is removed via line 79. The gas is then returned via line 80 to the olfgas line 71. After removing water from the desiccant in drier 69, which may take 1-2 hours at 450 F., the desiccant is cooled by ofi-gas from stripper 7 which is passed to drier 69 via lines 71, 72, and 73b, and 75 (thereby by-passing heater 74) Naphtha driers 4a and 4b may be regenerated in similar fashion. For example, oif-gas from stripper 7 is passed via line 71 and 72 to line 81 and salt bath heater '82, where it is heated to about 500 F. and then, via line 83, passed, preferably downflow, through driers 4a during its regeneration cycle and, alternately, through 4b during its regeneration cycle. After heating the desiccant and removing water therefrom the desiccant is cooled using elf-gas which is by-passed around heater 82 via line 84. Regeneration gases from the driers may be returned to off gas via 85, 76, 77, 78, 80 and 71.

It thus can be seen that the super dry conditions required in low pressure regenerative reforming systems operating at very high octane numbers are obtained by the method and means of the present invention. Cooling tower 46 in the catalyst regeneration facilities reduces water content in the regeneration gases and thus the adsorbed water content of the catalyst after regeneration. Thus, a minimum of adsorbed water remains on the catalyst after purging prior to returning the reactor to onstream operation. The adsorbed water that does remain and water formed by reaction of hydrogenrin recycle gas and freshly-oxidized catalyst is removed by drier 69. After removing such water, drier 69 may then be taken out of the system for regeneration, thereby reducing recycle compression costs. Carbon monoxide poisoning of platinum-alumina catalyst and water formation resulting from the reduction of carbon oxides in switch valve seal gas is prevented by scrubbing substantially -'all carbon 7 oxides from seal gas in scrubber 67. Water in the feed stock is substantially eliminated by coalescing entrained water in coalescer-settlerZ, absorbing additional water in driers 4a and 4b alternately, and stripping residual water, using hydrogen-rich'separator gas in stripper 7.

Operating the Ultraforming system as above described maintains water levels well below parts per million, preferably less than-20 parts per million. As a result, yields, octane potential, and catalyst life are maximized; halogen levels are maintained during on-stream operation; and halogen stripping during'regeneration and regeneration cycle time are minimized.

The invention and the advantages thereof are further illustrated in the following examples.

' Example I To demonstrate the drastic elfect of even minute amounts of water when producing high-octane reformates' #at low pressure, a series of tests were run one pilot-plantsc'ale Ultraformer having six reactors including a swing reactor. The alumina-based catalyst contained about 0.6 "percent'platinum and about 0.6 percent chloride. Feed stock was a full-boiling range naphtha which was reformedtooctane levels of about 100, unleaded, Research method. Operating conditions included temperatures in therauge of about 900-950, a space velocity of about 1, -fand ahydrogen recyclerate of about 5000 standard cubic lfe'et'rper barrel of naphtha charge. Regeneration frequency was approximately one reactor per day.

Water was variedfrom .less than about parts per million :toover 9'00:parts per million; based on naphtha feed. The results at the 100 unleaded octane level, Researchimethod, are presented in Figure 2. As water is decreased from about 900 parts per million to about i 100:parts.per million, yield was increased by about 1 percentby volume. As water is decreased from about 100 .partsper million .to lessthan about 10 parts per million, yield was surprisingly increased by about 3 percent by "volume. By varying water from relatively dry to rela- 'tively wet conditions and back again, theeffects of water on yieldwere found to bereversible. This is illustrated :in Figure 3. By 'adjusting'data to constant conditions, :i:e.,'an"average catalyst bed temperature of 915'F., and varying waterlevels, it was found that the octane of unleadedreformate was 1015, Research method, at a water'level of about 10 parts-per million and only about TIDO' ata-W-ater level of about 800-900 parts per million.

Example "II :To demonstrate the many sources of water in a lowpressure high-octane 'Ultraforniing unit and how the method and means of the "presentinvention coped with the water problem, a study of water levels in a commercial Ultraforming installation, having six reactors including a "swing reactor, was made. The capacity of the unit is about 23,000 barrels per stream day, and it is used toupgrade Gulf Coast naphthas to octane levels in excess of 100 unleaded, Research method. Feed stock to the unit was foundto have a water content of about 390 parts per million at 105 F. After installation of a coalescers'ettler'to remove'entrained water, such as above described, water-content of the feed was reduced to about 250 parts 'perfmillion. This water level is further reducedto about 10 parts per million by two desiccantdriers which are operated alternately between a drying operation and 'a regeneration operation with a 24-hour onstream cycle time. Each drier contains 21,800 pounds of activated bauxite desiccant mesh), 'said desiccant having a pressure drop through the bed of about 3.4 pounds per squareinch. After drying by means of..the desiccant, the fnaplitha'is further stripped by means of hydrogen-rich .separator gas to a waterlevel of'less than 10 parts per million. 1

I fPrior to installation'of sealgasscrubbers it was found that seal gas leakagecorresponded -to a water addition rate to the reaction system of about 250 parts per million, based on naphtha charge. Installation of a monoethanolamine absorption unit to scrub carbon oxides content below about 1 mol percent substantially eliminated this source of water. Prior to installation of driers for separator gas, water in the reaction zone attributable to water desorbed from freshly-regenerated catalyst and to reduction of platinum oxides was found to approximate about 300-500 parts per million, based on naphtha charge, for about two hours after returning a reactor of freshlyregenerated catalyst to on-stream operation. Installation of a silica gel drier (32,000 pounds of silica gel) substantially eliminates this source of water. The problem of water desorbed from the catalyst was, of course, alleviated in part by means of the water wash scrubbing tower in the catalyst regeneration system to reduce water content of catalyst regeneration gases.

As a result of the above drying system, water levels in means to reduce the carbon oxides content below .the reaction systemare maintained at less than 20 per million and usually less than 10 parts perm-illion.

Yields at the unleaded octane level, Researchmethod,

are thusraised about 2-4 percent by volume, and octane potential ofthe unit is raised by about l2-Re search units.

While the inventionhas been described in connection with an Ultraforming system, it should beunjderstood that it is equally applicable to other regenerative multitemperatures inthe range of about 800 to 1050 F. andiat pressures below about 400 pounds persquare inch/gage, said system including at least four reactors of which at least one reactor is regenerated daily by contact with oxygen-containing gases, the improved method of operation which comprises removing from the system water and substances affording water under the reactionconditions so as to maintain the total water content in the efiluent stream from the last reactor below 100 parts per million parts by weight of naphtha contained therein, whereby halogen loss from the catalyst is inhibited and reformate yield, octane potential, and catalyst life are enhanced.

2. The improved method of operation of claim 1 wherein the hydroforming system includes flue-gas-seale'd closures for separating hydrogen and hydrocarbon-containing vapors in the system from oxygen-containing regeneration gases, and said water content is maintained by drying the naphtha feed to lower the water content below about 20 parts per million, based on naphtha feed,

correspondingto a F. dew point at atmospheric pressure, and scrubbing flue gas used for sealing the closure at least about 1 mol percent.

3. The improved method of operation of claim 1 including'the step of drying said recycled hydrogen, at least immediately after returning a reactor of regenerated catalyst to on-stream operation, to lower thewaterco'ntent to a level at least below that corresponding to a 40 F. dew point at atmospheric pressure.

4. In a'regenerative catalytic hydroforming system-for upgrading a naphtha charge stock in the presence of a halogen-containing supported platinum catalyst to unleaded octane-number levels in excess of about '95 Research, said system including at least three normally onstream reactors plus a swing reactor capable of being substituted for any one of the other reactors while catalyst in the latter is regenerated by contact with oxygen-containing gases, a product separator wherein a hydrogenrich gas is separated from hydrocarbon product, at least a portion of the separated hydrogen-rich gas being recycled to the on-stream reactors, and flue-gas-sealed closure means for separating hydrogen and hydrocarboncontaining vapors in the system from oxygen-containing regeneration gases, the improved method of operation which comprises drying the naphtha charge stock to lower the water content below about 20 parts per million, based on charge stock; drying the separated hydrogen-rich gas to lower the water content to a level at least below that corresponding to a -40 F. dew point at atmospheric pressure; drying catalyst regeneration gases to a water content below that corresponding to a 150 F. dew point at atmospheric pressure; and scrubbing flue gas used for sealing the closure means to reduce the carbon oxides content below at least about "{w'ater in the reaction system rsheld continuously and sub- 1 stantially below about 100 parts per million, based on charge' stock, halogen u and reformate yield, octane potential, and the number 5 fswing-rea'ction zone; passing the 'stock' is dried by contacting said charge stock in the" loss from the catalyst is minimized of regeneration cycles to which the catalyst is subjected before substantial loss of catalyst surface area are maximrz' ed; 5; The method of claim 4 wherein the naphtha charge liquid phase with a solid drying desiccant.

"6. The method of claim 5 wherein the desiccant is I bauxite.

7 'The method of claim 4 wherein said naphtha charge stock is dried by the steps of coalescing and separating entrained water therefrom, then contacting the charge stock with a solid desiccant dryer, and thereafter stripping :the charge stock with a portion of the hydrogen-rich gas from the product separator.

8. The method of claim 4 wherein said separated hydrogen-rich gas is dried by contacting said 'gas with a solid drying desiccant.

9. The method of claim 4 wherein said separated hy- "drogen-rich gas is dried by contacting said gas with silica gel, whereby total water in the reaction system is reduced to below about 10 parts per million.

10. The method of claim 4 wherein carbon oxides are scrubbed from the flue gas by contacting said flue gas with aqueous ethanolamine solution at a temperature below about 150 F.

11. In a regenerative catalytic hydroforming system for upgrading charge naphtha to octane levels 'in excess of 95 CPR-R, unleaded, in the presence of hydrogen and a halide-containing supported platinum catalyst at tempera- .tures in the range of about 8001050 F. and at pressure below about 400 pounds persquare'inch gage, said system including a first reaction zone, at least one intermediate reaction zone, a tail reaction zone, and a swing reaction zone capable of being substituted for any one of the norjma'lly on-streamreaction zones, the improved method of operation which comprises drying said charge naphtha to .awater content below about parts per million, based on naphtha; preheating the dried naphtha and recycled ;hydrogen; passing the preheated naphtha and hydrogen through the first reaction zone;

. the said first reaction zone; passing the reheated effluent "through said intermediate reaction zone; reheating the efiiuent from the intermediate reaction zone;'passing the reheated efliuent through said tail reaction zone; passing ;-the efiiuent-from the tail reaction'zone to a product sep- ,5

aration zone-wherein a hydrogen-rich gas is separated from 'reform'ate product, 'at' least a portion of the separated hydrogen-rich gas being recycled for reheating and introduction into said first reaction zone; periodically substituting the swing reaction zone for, and isolating, any:

. selected one of the other reaction zones; regenerating cat alyst in the isolated reaction zone by contacting the catreheating the effluent from r alyst withfa'n oxygen-containing 'gas; returning the. isolated reaction zone after regenerationto on-stream operation and withdrawing "the swing reaction zone from onstream'operation; periodically regenerating catalystin the separated hydrogen-rich 'gas from the product separatorthroughia drying zone 11 containing a drying desiccant'foratleast the first hour after placing a reaction zone'on-stream after regenerai tion,

and thereafter, but prior'to' returning another reaction zone to on-stream operation, regenerating the drying desiccant; whereby water content in the reaction: zones is continuously maintained at a level at least below about lOO parts per millio'mbased on naphtha, halogen loss lfromthe catalyst and loss of catalyst surface" area is minimized, and yield of reformate product and octane 1 potential is maximized.

12. The improved method of operation of claim'll Wher'eina reaction zone is isolated foriregenerationby means of flue-gas-sealed 'valve means and the flue gas used for sealing 1 the valve means is scrubbed to reduce the carbon oxides content below at least about 1 mol percent.

13. The improved method of operation of claim 11 "wherein the naphtha is dried at least in part by passing said naphtha athrough a stripping zone wherein a portion a plurality of desiccant portion of said separatedhydrogen-rich gas,'passing't he heated gas through the drying desiccant whereby'water is removed from the desiccant, and thereafter cooling the 'desiccant by contacting it with separated hydrogen-rich gas which has not been heated.

' 16. The improved method of operation of claim 11 wherein at least a portion of the regeneration gases leaving the isolated-reaction zone during regeneration are recirculated to the isolated reaction zone and the recirculated gases are dried to awater level not in excess ofthat corresponding to a'dew point of'150 F. at atmospheric 7' "pressure. 7

-R efere nc es Cited in the file ofithis. patent UNTTED STATES PATENTS 2,746,909 Hemminger May 22, 1956 2,759,876. Y Teter et al..* Aug. 21,1956 2,773,014 Snuggs et al Dec. 4,1956 2,792,337 Engel May 14,- 1957 2,842,482- Voorhies et al.' July 8, 1958 2,880,161 Moore et a1. Mar; 31, 1959

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Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3116987 *Oct 27, 1960Jan 7, 1964Black Sivalls & Bryson IncProcess and apparatus for removal of water from a fluid stream
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Classifications
U.S. Classification208/65, 208/139, 208/140, 208/187, 208/138
International ClassificationB01J23/96, B01J23/90
Cooperative ClassificationB01J23/96
European ClassificationB01J23/96