US3424673A - Process for hydrodesulfurizing the lower boiling fraction of a cracked gas oil blend - Google Patents

Description

Jan. 28, 1969 M. c. KIRK, JR 3,424,673

PROCESS FOR HYDRODESULFURIZING THE LOWER BOILING FRACTION OF A CRACKED GAS OIL BLEND Filed March 7, 1966 S pistillofion Hydro. I Sm er BR C4-400F Tower BR 400675 F Desulfurizer pp Desulfurized Gas Oil FIG. I

BR 400 F' IO Hz 7 9\ 4 8 o 2 Hydro. I BR C4 400 F Sf e Desulfurizer X Distillation BR P I Tower I5 BR 550-675F Desulfurized Gas Oil F BR 400 F+' FIG. 2

INVENTOR MERRlTT C. KIRK, JR.

BY 4W,

ATTORNEY United States Patent 01 lice 3,424,673 Patented Jan. 28, 1969 3,424,673 PROCESS FOR HYDRODESULFURIZING THE LOWER BOILING FRACTION OF A CRACKED GAS OIL BLEND Merritt C. Kirk, In, Claymont, Del., assignor to Sun Oil Company, Philadelphia, Pa., a corporation of New Jersey Filed Mar. 7, 1966, Ser. No. 532,298 US. Cl. 208--218 Int. Cl. Cg 31/00 8 Claims ABSTRACT OF THE DISCLOSURE This invention relates to the hydrodesulfurization of cracked gas oil fractions boiling mainly in the range of 400675 F. to produce fuel oils and fuel oil blending components and is particularly advantageous when the desulfurization is effected in liquid phase, especially in trickle phase.

In the preparation of distillate fuel oils such as household heating oils, cracked gas oils obtained from either catalytic or thermal cracking operations and boiling mainly in the range of 4006 75 F. generally are used as components. In the United States, the refiner will frequently produce a desulfurized cracked gas oil which meets ASTM standards for No. 2 fuel yet not market it directly as a heating oil but will blend it with other hydrocarbons, such as kerosene, and market the resulting blend as his brand of household heating oil. Such household heating oil blends normally contain a lower percentage of sulfur than does the desulfurized catalytic gas oil component, have more desirable ignition characteristics, a lighter color, and improved stability on storage. Occasionally, proprietary additives may be used to improve these properties of household fuel blends.

Before desulfurization, cracked gas oil can contain as little as 0.2% to over 3% by weight of sulfur. For use in fuel blending, the refiner requires less than 1% of sulfur in an oil, and prefers to use components containing no more than about 0.5% of sulfur. Usually he markets a blended household heating oil containing no more than 0.2% sulfur.

It is usual practice to remove sulfur from these cracked gas oils by catalytic hydrodesulfurization. Conventionally the entire 4006 75 F. cracked gas oil material is subjected to hydrodesulfurization in a plant of prefixed capacity designed to achieve a predetermined degree of sulfur removal. A conventional plant utilizing a given catalyst and selected hydrodesulfurization conditions (temperature, pressure, space rate, etc), will be capable of reducing the sulfur content to a particular level and no lower. Hence an existing hydrodesulfurization unit in processing the entire 400675 F. cracked gas oil material available daily will yield a product still containing a substantial proportion of the original sulfur content.

Usually in refinery practice only 30-70% of the original sulfur will be removed in the desulfurization step. Even though a lower sulfur level in the fuel oil product may be desirable, it will not normally be attainable without lowering the rate of production. In addition, when the desulfurization conditions are increased in severity beyond those necessary to remove from about 50 to 70% of the original sulfur in the catalytic gas oil, the desulfurization becomes significantly more costly because the hydrogen consumption per pound of sulfur removed increases greatly due to hydrocracking and more complete hydrogenation of unsaturated hydrocarbons in the gas oil.

A procedure has now been discovered whereby an existing hydrodesulfurizer of a prefixed capacity can be uti lized to produce from cracked gas oil the same daily amount of fuel oil but with a substantiallly lower sulfur content. Alternatively the procedure can be utilized to produce fuel oil of the same sulfur level but in larger amount. These benefits are achieved by splitting the 400675 F. cracked gas oil feed into lower and higher boiling portions, hydrodesulfurizing in the plant of prefixed capacity only the lower boiling portion, and then blending hydrodesulfurized product with the untreated higher boiling portion. The resulting blend will have a lower sulfur content than the conventionally processed material or, optionally, can have about the same sulfur level but constitute a larger daily volume of product.

More specifically, the process according to the invention involves separating a broad range cracked gas oil into lower and higher boiling fractions, the lower boiling fraction containing in the range of to 80% of the total sulfur in the cracked gas oil, then hydrodesulfurizing only the lower boiling fraction in the hydrodesulfurizer of prefixed capacity and blending the hydrodesulfurized product with the higher boiling fraction to produce a desirable blending component which meets the ASTM specifications for No. 2 fuel oil and which has a sulfur content no greater than would be obtained by hydrodesulfurizing the entire gas oil in said hydrodesulfurizer at the same temperature and pressure conditions.

When practiced in conjunction with the preparation of dimethyldecalins in accordance with applicants copending application Ser. No. 225,034, filed Sept. 20, 1962,

Y which matured into US. Patent No. 3,256,353 on June 14, 1966, in the name of Frank R. Shurnan, Jr., and Merritt C. Kirk, In, the present invention can be used to produce a blending component with an improved smoke number and improved cetane number due to removal from the fuel of dimethylnaphthalenes in the 480540 P. fraction of the cracked gas oil. This procedure is described in more detail hereinafter.

The cracked gas oils from most crudes have a relatively high sulfur content when compared with straightrun (virgin) gas oils, thus necessitating quite different desulfurization procedures. In particular, in the hydrodesulfurization of catalytic gas oils containing over about 1% of sulfur, such as those derived from Middle East and Venezuelan crudes, it is frequently preferable in fuel oil production to utilize liquid phase (including trickle phase) hydrodesulfurization under conditions such that the desulfurized gas oil product contains about 0.5% of sulfur, a sulfur level which is higher than that usually found in virgin gas oils before desulfurization.

Although this sulfur content is well within ASTM specifications D396-64T for No. 2 fuel oil, present industrial practice, particularly in urban areas, such as the industrialized East Coast of the United States, is to market No. 2 fuel containing only about 0.1% of sulfur. To produce an 0.1% sulfur fuel from such desulfurized catalytic gas oils containing over 0.5% sulfur, the refiner must either subject them to additional desulfurization or blend them with low sulfur content straight run gas oil, heavy naphtha, or other low sulfur content fuel oil fractions.

In hydrodesulfurization of catalytic gas oils, the refiner frequently finds it most economical to hydrodesulfurize in the trickle phase under temperature and pressure conditions such that only about 30-70% of the total sulfur in the gas oil is removed, utilizing trickle phase processes such as those of US. 2,897,141 to Honeycutt and Shuman and US. 3,162,597 to Davis and Honeycutt, which, when compared with vapor phase processes, require a lesser plant investment, use less fuel (due in part to lower reaction temperatures) and consume much less hydrogen per pound of sulfur removed. Normally gas oil in which less than 50% of the sulfur has been removed by such trickle-phase hydrodesulfurization has a lighter color which is more stable on storage and is a better blending component than a more severely desulfurized gas oil.

When designing a plant to hydrodesulfurize cracked gas oil the major consideration, which determines the plant size and the process used, is the refiners cracking operations. The plant is designed to reduce the sulfur content of the entire cracker output to a given percent of sulfur.

That is, the conventional way to operate a plant is to put through the desulfurizer all of the refiners cracked gas oil which is destined for fuel production. Therefore, in commercial scale plant production, the hydrodesulfurization capacity (measured in barrels per day of desulfurized products of a given sulfur content) of a given hydrodesulfurizer is prefixed by the operation of the cracker from which the cracked gas oil feed to the hydrodesulfurizer is derived. Thus, although in the laboratory it is possible to increase the weight of sulfur removed in a given time period by making large changes in gas recycle and in the catalyst/oil contact time (e.g., the space rate), on a plant scale only relatively minor changes in space rate and recycle are allowable due to the prefixed capacity factor. In addition, With a broad range (400- 675 F.) feed, increased contact time frequently decreases catalyst life, mainly due to more rapid coke formation.

Since within the limited range available in plant operation the effects of pressure and hydrogen recycle on sulfur removal are relatively small, the refiner has only temperature to use as a major variable in controlling his degree of desulfurization. However, in liquid phase and especially trickle phase desulfurization, the temperature and pressure are prefixed to a relatively narrow range by the critical point of the feed stock, the purity of the hydrogen, the design pressure of the hydrodesulfurizer, and by the refiners color requirements.

FIG. 1 of the attached drawings is a schematic flow sheet illustrating conventional plant scale practice, utilizing a hydrodesulfurizer of prefixed capacity, for hydrodesulfurization of cracked gas oils to produce a partially desulfurized cracked gas oil to use as a major component of blended household fuel oil. The cracked hydrocarbon feed to the distillation tower can be derived from thermal cracking, including coking, but usually is a catalytic gas oil such as that prepared by contacting straight run gas oil (boiling mainly from 4501000 F.) with a silicaalumina cracking catalyst at a temperature of about 900 F. and a pressure of about 20 p.s.ig.

The cracked hydrocarbon product from which the dry gases have been stripped, for example, the product from catalytically cracking a straight run gas oil, from which gases having less than 4 carbon atoms have been removed, is transported via line 1 to a distillation tower 2. A gasoline fraction boiling below about 400 F. is removed from the tower via line 4, a bottoms fraction boiling above about 635 F. and usually above 675 F. is removed via line 5, and a cracked gas oil fraction boiling mainly in the range from 400-675 F. is transported via line 3 to a desulfurizer 6. Hydrogen enters the hydrodesulfurizer through line 7 or, alternately, line 7 may connect with line 3 and the hydrogen and oil be allowed to intermingle prior to entering the hydrodesulfurizer.

Hydrodesulfurization can be effected under conditions such that the oil is either in liquid or in vapor phase, at

hydrogen pressures of from about 150 p.s.i.g. to over 3000 p.s.i.g., at temperatures from 450l000 F., in the presence of a catalyst such as tungsten-nickel sulfide or cobalt-molybdenum oxides (usually on an alumina support), the liquid hourly space velocity being 0.5-10, and the hydrogen rate being in the order of l0010,000 s.c.f. per barrel, depending upon the treatment phase and whether hydrogen is recycled.

The product from the hydrodesulfurizer passes through line 8 to a product stripper 9, where dry gases (H 5, NH H hydrocarbons with fewer than 4 carbon atoms, etc.) are removed via line 10, a gasoline fraction boiling below about 400 F. may be removed via line 11, and a desulfurized gas oil boiling mainly above 400 F. and containing no more than 0.5% sulfur is transported through line 12 to a storage area or through a blending area, such as a blending valve, where it is blended with other fuel components, such as virgin gas oil to produce household heating oil. Before such use in fuel blending, the desulfurized gas oil can be further processed to recover materials such as dimethylnaphthalenes.

There are numerous minor variations in the above processing scheme relating to the composition of the fractions in lines 10 and 11. For example, most modern refiners separate C hydrocarbons from the higher boiling hydrocarbons in the gasoline fraction in order that they may be used as a feed in an alkylation plant or for gasoline blending. Similarly 400 F. is a nominal end boiling point of the gasoline fraction and can vary from about 360 F. to about 430 F.

I have improved upon the above-outlined prior art hydrodesulfurization by separating the broad range cracked gas oil into lower and higher boiling fractions, such that the lower boiling fraction will contain between 40% and of the total weight of sulfur in the two fractions, and hydrodesulfurizing only the lower boiling fraction, usually at a proportionately lower liquid hourly space velocity and at similar temperature and pressure conditions as used in the conventional procedure of FIG. 1.

The product of this hydrodesulfurization of the lower boiling feed contains less sulfur than is found in a corresponding fraction of the same boiling range which is distilled from the product of hydrodesulfurizing the whole volume of cracked gas oil for the same total treating time, and at the same temperature and pressure conditions. When this product from hydr-odesulfurization of the lower boiling fraction is blended with the undesulfurized higher boiling fraction, the sulfur content of the resulting blend is no greater than the sulfur content of the hydrodesulfurized whole cracked gas oil, and, surprisingly, in most instances is actually less. In addition, catalyst life is increased, as is the volume yield of the resulting blend.

When practicing the present invention, I have also found that by contacting the lower boiling fraction at an intermediate liquid hourly space velocity the barrels per day throughput of blended 400-675 F. boiling range cracked gas oil, containing a given percent of sulfur can be increased over that obtainable by the conventional process at the same temperature and pressure conditions.

I have found, by analysis of a number of representative cracked gas oils boiling mainly between 400-675 F., that over 40% and less than 80% of the sulfur in said cracked gas oils is contained in the lower boiling portion, boiling mainly below from about 535565 F. and that for most cracked gas oils this point is about 550 F.

FIG. 2 in the attached drawings illustrates one manner of so practicing the present invention, utilizing a hydrodesulfurizer of prefixed capacity, in order to produce a desulfurized gas oil which is useful as a component of household fuel oil. A cracked gas oil feed (which can be a combined feed from several cracking operations) is distilled in distillation tower 2 in a manner similar to the operation of FIG. 1 except that a new line 13 is added at a higher position on the distillation tower than line 3 of FIG. 1 (at which the fraction boiling mainly in the range of 400-675 F. was collected). Distillation conditions are varied so that the material transported through the new line 13 boils mainly in the range of 400-550 F. and contains from 40% to 80% of the total sulfur present in the 400-675 F. cut. The higher boiling bottoms fraction, boiling mainly in the range of 550675 F is transported through line 14.

In plant practice, line 14 may be a new line which is installed at the distillation tower at a lower level than was the original line 3 of FIG. 1 or, by suitably varying the temperature gradient in the distillation tower, the refiner can utilize the original line 3 to collect the 550-675 P. fraction.

Alternatively, instead of adding one or more new lines to the distillation tower 2, the 400-675 F. fraction, which in FIG. 1 is transported via line 3, can be passed through a separate distillation zone (not shown) where it is separated into fractions boiling mainly above and below about 550 F. Although such a separate distillation gives a sharper cutoff point between the higher and lower boiling fractions, it requires more heat and a larger plant investment; therefore, the separation process of the FIG. 2 flow sheet is preferred for economic reasons. In addition, the resulting desulfurized catalytic gas oil blend usually has a lighter color when separated by the process of the flow sheet since more higher boiling colored impurities are contained in the lower boiling fraction, and are removed by the hydrosulfurization.

The higher boiling fraction, bypassing the hydrodesulfurizer, is transported directly via line 14 to a collection or blending area.

The lower boiling fraction, containing over 50% of the sulfur which was present in the 400-675 P. fraction, is transported to the same hydrodesulfurizer 6 of prefixed capacity which was previously utilized to desulfurize the 400-675 P. fraction of FIG. 1.

If the refiner has more than one cracking operation, and does not distill a combined feed, he can transport two or more of such lower boiling fractions (by means of additional lines, not shown) to a common blending area and then contact this blended feed with the catalyst. In such a method, the corresponding higher boiling fractions would bypass the hydr-odesulfurizer and be transported directly to the collection or blending area via lines (not shown) similar to line 14.

When the refiner has available at least one relatively low sulfur content cracked gas oil and at least one relatively low sulfur content gas oil (including straight run gas oil) as, for example, the gas oils of the previously mentioned US. Patent 3,162,597, it is usually advantageous to hydrodesulfurize a blend of lower boiling fractions of such gas oils .wherein the blend boils mainly below about 550 F. and contains from 4080% of the total sulfur contained in the combined undesulfurized gas oils.

The product of the hydrodesulfurization of the 400- 550 F. gas oil fraction is transported via line 8 to stripper 9 where a dry gas fraction is removed via line 10 and a gasoline fraction boiling mainly below 400 -F. is removed via line 11. The desnlfurized bottoms fraction boiling mainly above 400 F. is transported from the stripper through line 12 to a junction with line 14 where it is blended with the catalytic gas oil fraction boiling between about 550-675 F. in order to produce a desulfurized gas oil boiling mainly above about 400 F. and containing about 0.5% sulfur.

By practice of the present invention the refiner can more efliciently utilize his present hydrodesulfurizer, of a prefixed capacity, without making any substantial alteration in his temperature and pressure conditions for hydnodesulfurization and thus decrease the percent of sulfur in his catalytic gas oil without decreasing his rate of production thereof.

Alternatively, the refiner can increase the capacity of his hydrodesulfurizer (in terms of barrels per day throughput) by increasing the space rate at which he treats the 400-550 P. fraction while maintaining the salrne percent of sulfur in his final blended catalytic gas oil as he had theretofore obtained by hydrodesulfurizing the whole of his catalytic gas oil at a lower throughput under the same temperature and pressure conditions.

In both of the above outlined operations, or in combinations thereof, wherein both total throughput and sulfur removal are improved (but of course, neither result is maximized), increased efficiency results from a greater volume yield from the desulfurizer per volume of feed, an increase in the heavy gasoline produced and from greatly increased catalyst life (usually at least twice as many barrels of desulfurized 400-675 F. fuel are produced per pound of catalyst when using the present invention instead of the prior art method).

As a further alternative, the desulfurized bottoms boiling mainly above 400 F. can be separated (by means, for example, of stripper 9 utilizing an additional line, not shown) into a fraction boiling below 480 F., a fraction boiling above 540 F., and a fraction containing dimethylnaphthalene and boiling mainly in the range of 480-540 F. This 480 -540 F. fraction can be a source of dimethyldecalins when used as a feed in the process of the previously mentioned copending application Ser. No. 225,034. In this process the 480-540 F. feed fraction is catalytically hydrogenated to an aromatics content of less than 8% under hydrogenation conditions comprising a temperature in the range of 400 l000 F., a pressure in the range of 500-4000 p.s.i.g., a liquid hourly space velocity in the range of 0.ll0.0 and in the presence of 5000 to 15,000 s.c.f. of hydrogen per barrel of hydrocarbon feed. The hydrogenated product is distilled to separate a fraction containing at least dimethyldecalin and boiling in the range of 400-450 F. An especially preferred feed for long life of the platinum hydrogenation catalyst is obtained when the desulfurized product contains less than 300 p.p.m. (preferably under 50 p.p.m.) of sulfur; therefore the hydrodesulfuriz-ation of the 400-550 F. fraction is usually effected under more severe conditions (especially higher temperatures) than are normally used in fuel oil production. In many instances vapor phase conditions are used to attain the desired degree of desulfurization.

All of the material in this 400-550 F. fraction which is not recovered as dimethyldecalins can be combined with the desulfurized fraction boiling below 480 F. to produce an excellent fuel, meeting ASTM specification D396-64T for No. 1 fuel, and which has a high cetane number and a low smoke number and is useful as a component of jet fuel and diesel fuel This No. 1 fuel can also be blended with the stripper bottoms fraction boiling above 540 F. and with undesulfurized higher boiling fraction of line 14 to produce a desulfurized gas oil which is useful as a fuel or as a component of household heating oil.

Hydrodesulfurization conditions are well known in the art, one detailed review of prior art processes being the article by J. B. McKinley at pages 405-526 of vol. 5, Catalysis, edited by P. H. Emmett, Reinhold Publishing Corp., New York, 1957. Pages 475-497 are particularly useful in determining hydrodesulfurization conditions for catalytic gas oils boiling mainly in the range of 400- 675 F. The same conditions are useful for hydrodesulfurizing the fractions of said gas oils boiling mainly between about 400-550 F., when practicing the present invention, except that it is preferable to utilize a proportionately greater catalyst/ oil contact time for the lower boiling fraction in order to maximize sulfur removal at a given barrels per day production of blended No. 2 fuel of a given percent sulfur.

Molecular sieve zeolites containing cobalt or nickel when composited with molybdenum oxide, such as the catalysts of US. Patent 3,098,032, can be used as cat- 7 alysts for hydrodesulfurization of 400-550 F. cracked gas oil fractions.

Usually hydrogen consumption per pound of sulfur removed will increase with increased hydrogen pressure arid/or increased reaction temperature. Such increased hydrogen consumption per pound of sulfur removed becomes very great at hydrogen pressures above about 1200 p.s.i.g., due to hydrogenation of aromatic rings, and at temperatures above about 800 R, where considerable hydrocracking will also occur.

For calculating the maximum operating temperature for trickle phase hydrodesulfurization a method such as that shown in Chemical Engineering Process Symposium Series, No. 6, 49, 81 (1953), by E. I. Organick may be used. Such methods correlate the critical temperature and pressure as a function of the distillation curve of the feed hydrocarbon.

In order to improve color stability, the molybdenum oxide and cobalt oxide or nickel oxide catalysts used in hydrodesulfurization can be sulfided prior to use, such as by treating with hydrogen sulfide, carbon disulfide, ethyl mercaptan, sour gas oil, or the like, preferably in the I, except that the liquid hourly space velocity was proportionately decreased to 2.

This feed contained 1.13% sulfur and the desulfurized product contained 0.34% sulfur. The desulfurized product was blended with the undesulfurized cracked gas oil fraction boiling mainly above 550 F., and the resulting blended fuel contained 0.71% sulfur; therefore, the fuel component produced in Example I by the prior art process contained nearly 13% more sulfur than that produced in Example II by applicants process.

An additional benefit of applicants process was that the API gravity of the blended product had increased to 30.0, compared with 29.0 for the fuel produced in Example I. Since the ASTM specification D396-64T sets a minimum API gravity of for No. 2 fuel, applicants process not only produced a fuel with less sulfur, but also produced a fuel which met this ASTM specification for No. 2 fuel. The properties of the feed fraction, the desulfurized product, and the final blended product (which met all of the ASTM specifications for No. 2 fuel) are listed in the table below. In this example, as elsewhere in this application, percentages are by weight unless otherwise specified.

TABLE Example I (prior art), Example 11 (applicants process) whole CGO Lower boiling C GO fraction Blended product Feed Product Feed Product Wt. percent sulfur 1. 21 0.80 1.13 0.34 0. 71 Percent sulfur removed. 33. 4 41. 3 Wt. percent nitrogen. 0. 0148 0. 0095 0.0156 Gravity, API 60 29.0 28. 6 32. 2 30.0 Engler distillation (temp, F.), volume:

Initial 434 405 356 336 350 486 471 430 414 440 517 513 457 448 498 543 540 500 466 582 567 567 515 480 566 598 598 525 500 598 624 022 555 532 626 87. 25 87. 32 87. 65 87. 21 87. 04 Percent Hydrogen- 11. 58 12. 03 11.47 11. 86 11. 77 CI'H ratio 7. 7. 26 7. 64 7. 35 7. 39 Bromine 3. 6 2. 0 5. 0 3. 0 2. 7

presence of hydrogen. The amount of sulfur added is preferably at least 25% of the stoichiometric quantity necessary to convert the catalytic metal oxides to the corresponding sulfides.

In the following examples, Example I illustrates the 4 EXAMPLE I A catalytic gas oil, having the properties listed in the table below (wherein CGO stands for catalytic gas oil), is hydrodesulfurized in accordance with the procedure illustrated in FIG. 1. Hydrodesulfurization was effected, at a liquid hourly space velocity of 4 volumes of oil per volume of catalyst per hour, in trickle phase without any net flow of hydrogen through the desulfurization zone, as taught in US. 3,162,597 to Davis and Honeycutt. The catalyst analyzed 3% C00, 15% M00 and 82% A1 0 Reactor temperature was 575 F. at a hydrogen pressure of 400 p.s.i. (total pressure 500 p.s.i.g.).

Before hydrodesulfurization the catalytic gas oil contained 1.21% sulfur. The desulfurized product contained 0.80% sulfur; therefore overall sulfur removal was 33.4%. The properties of this product, suitable as a component for household fuel oil blending, are shown in the table.

EXAMPLE II Another portion of the same undesulfurized catalytic gas oil of Example I was fractionated by a separate atmospheric distillation into fractions boiling, respectively, above and below about 550 F. The lower boiling fraction which was of the volume of the whole gas oil, was subjected to the same hydrodesulfurization as in Example The invention claimed is:

1. In a process for partially desulfurizing cracked gas oil boiling mainly in the range of 400-675 F. to effect removal of not more than 70% of the sulfur therein, which process involves utilizing a catalytic hydrodesulfurizer of a prefixed capacity to effect the desulfurization, the improvement which comprises the steps of (l) separating from said cracked gas oil a lower boiling fraction, said fraction boiling mainly below 535565 F. and containing about 4080% of the total sulfur in said cracked gas oil, and a higher boiling fraction,

(2) hydrodesulfurizing only the lower boiling fraction in said hydrodesulfurizer, and

(3) blending hydrodesulfurized product with said higher boiling fraction, whereby the sulfur content of the resulting blend is no greater than the sulfur content would be by hydrodesulfurizing the entire cracked gas oil in said hydrodesulfurizer at the same temperature and pressure conditions.

2. Process according to claim 1 wherein the hydrocarbon products boiling ,below about 400 F. are removed from the hydrodesulfurizer effluent and the resulting hydrodesulfurized product boiling mainly above 400 F.

is blended back with said higher boiling fraction to produce a fuel meeting ASTM D396-64T specification for No. 2 fuel oil.

3. Process according to claim 1 wherein the separation of said cracked gas oil into lower and higher boiling fractions is made by withdrawing said fractions from plates at separate sections of a distillation tower and the lower boiling fraction is transported directly to the hydrodesulfurizer.

4. Process according to claim 1 wherein the hydrodesulfurization of said lower boiling fraction is effected at a liquid hourly space velocity such that a greater volume per day of blended, desul'furized cracked gas oil of a given sulfur content is produced than can be produced by desulfurizing the entire cracked gas oil in the same hydrodesulfurizer under the same temperature and pressure conditions.

5. Process according to claim 1 wherein the sulfur content of the resulting blend is less than the sulfur content which would be obtained by hydrodesulfurizing the entire cracked gas oil in said hydrodesulfurizer under the same temperature and pressure conditions.

6. Process according to claim 1 wherein the sulfur content of said cracked gas oil is above 1% and the resulting blend contains less than 0.5% sulfur.

7. Process according to claim 1 wherein the hydrodesulfurization is effected in trickle phase.

8. Process according to claim 1 wherein said higher boiling fraction boils mainly above 550 F.

References Cited UNITED STATES PATENTS FOREIGN PATENTS 10/ 1962 USSR.

15 DELBERT E. GANTZ, Primary Examiner.

G. J. CRASANAKIS, Assistant Examiner.

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