US3923637A - Hydrodesulfurization process with a portion of the feed added downstream - Google Patents

Abstract

A process is described for fixed bed hydrodesulfurizing a nonasphaltic oil feed or feed blend for a zeolitic FCC riser cracking system in which cracking occurs at a space velocity sufficiently high to prevent formation of a catalyst bed. It is found that sulfur dioxide emissions from the zeolite catalyst regenerator associated with the riser are reduced to a lower extent than total sulfur removal from the feed oil. This indicates uneven sulfur removal in the hydrodesulfurization step whereby a smaller portion of the sulfur is removed from the heavy portion of the feed from which the coke is derived than from the lighter portion of the feed. The present invention shows an advantage in keeping hydrocracking at a specified low level during the hydrodesulfurization step. This is accomplished in part by introduction of the high boiling portion of the feed to the upstream end of the hydrodesulfurization reactor and the low boiling portion of the feed downstream in the hydrodesulfurization reactor. In this manner maximum sulfur removal from the high boiling portion of the feed is approached, while hydrocracking is maintained at the specified low level. The further discovery is demonstrated herein that the ratio of gasoline to total conversion during the subsequent riser cracking step is enhanced by maintaining hydrocracking at said specified low level.

Description

Christman et a1.

1 1 Dec. 2, 1975 [54] HYDRODESULFURIZATION PROCESS WITH A PORTION OF THE FEED ADDED DOWNSTREAM [75] Inventors: Robert D. Christman, Penn Hills Township; Joel D. McKinney, Indiana Township; Thomas C. Readal, McCandless Township; Stephen J. Yanik, Hampton Township, all of Pa.

[73] Assignee: Gulf Research & Development Company, Pittsburgh, Pa.

[22] Filed: Mar. 29, 1973 [21] Appl. No.: 346,175

52 US. Cl. .f, 208/89; 208/216 [51] Int. Cl. C10G 23/00 [58] Field of Search 208/89, 211, 216

I 56] References Cited UNITED STATES PATENTS 2,338,573 1/1944 Creelman 260/6735 2,897,143 7/1959 Lester et al 2,938,857 5/1960 Johnson ct al. 208/89 2,958,654 11/1960 Honeycutt 208/89 3,011,971 12/1961 Slyngstad et al.. 208/216 3,193,495 7/1965 Ellor ct al. 208/216 3.475327 10/1969 Eng ct a1 208/216 3,617,512 11/1971 Bryson et al.. 208/80 3,658,681 4/1972 Wilson ct a1.. 208/211 3.700586 10/1972 Schulman 208/89 3,728,249 4/1973 Antezana et a1 208/59 3,784,463 l/1974 Reynolds et a1, 208/120 Primary ExaminerDelbert E. Gantz Assistant Examinerlames W. Hellwege [57] ABSTRACT A process is described for fixed bed hydrodesulfurizing a non-asphaltic oil feed or feed blend for a zeolitic FCC riser cracking system in which cracking occurs at a space velocity sufficiently high to prevent formation of a catalyst bed. It is found that sulfur dioxide emissions from the zeolite catalyst regenerator associated with the riser are reduced to a lower extent than total sulfur removal from the feed oil. This indicates uneven sulfur removal in the hydrodesulfurization step whereby a smaller portion of the sulfur is removed from the heavy portion of the feed from which the coke is derived than from the lighter portion of the feed. The present invention shows an advantage in keeping hydrocracking at a specified low level during the hydrodesulfurization step. This is accomplished in part by introduction of the high boiling portion of the feed to the upstream end of the hydrodesulfurization reactor and the low boiling portion of the feed downstream in the hydrodesulfurization reactor. In this manner maximum sulfur removal from the high boiling portion of the feed is approached, while hydrocracking is maintained at the specified low level. The further discovery is demonstrated herein that the ratio of gasoline to total conversion during the subsequent riser cracking step is enhanced by maintaining hydrocracking at said specified low level.

5 Claims, 7 Drawing Figures US. Patent Dec. 2, 1975 Sheet 1 of 6 3,923,637

HYDRODESULFURIZATION OF KUWAIT GAS OIL AND VARIOUS KUWAIT LUBE OIL EXTRACT BLENDS:

SULFUR REMOVED VERSUS TEMPERATURE Catalyst: l/l6-inch NiCoMo on Alumina Operating Conditions; IOOO PSIG, 2.0LHSV, ZOOOSCF/Bbl. 0f 70% H (Recycle Gas scrubbed), 85% H Makeup Light Lube Extrolcf g (5.06% s;-,|o-s 0% B R.=695-8 ZOF)/ 5 .4: l4 0 25' G] I (I) j Br qhf Stock u Extra (4.9r%s, o-9c%e.R E -!0!o 2:32 m m I D II ,I" 5 o I 1y 70%60: 01 and 30% 3 Exzr lct Clend J ,3 (APlusE or us 3 A e /O/ 1' Full Range Gus OI 2.S|3/S;lO-90/BR.=

a Q-IQLPF) v Average Reactor Temperature F U.S. Patent Dec. 2, 1975 Sulfur Content "lobesulfurizotion Sheet 2 of 6 3,923,637

DESULFURIZATION OF KUWAIT C -68OF DlSTlLLATE CHARGE Blend of 43.5% Deb. Ncphtho and 56.5% Furnace Oil S Content of Nophthu .04% 8 Content of Furnace Oil I.O2%

CONDITIONS- 4.o-5.0 LHSV, 700psig press., 1,200 SCF of H -rich (90%)gos/bbl, gas scrubbed with amine, 400 psi H pp of outlet.

: a .2 --E(I-0NAPHTHA 80 /j PREaENT if 0 /5.ou+s;v 8 1o O f C 5 1 3 60 f TEMPERATUREIF US. Patent Dec. 2, 1975 Sheet 3 of6 3,923,637

DESULFURIZATION OF HEAVY OIL PLUS LIGHT OIL Sulfur in Heuvy Portion Only of the Product Sulfur Weight Percent Sultiu in Total Liq id Product o I00 Point 01 In ection of Light Oil! Percent of Bed Depth (Heavy Oil Injected 0t 0 Percent Bed Depth In all Cases) us. Patent Dec. 2, 1975* Sheet4of6 3,923,637

In 4 mm zv m o .(e G 3 g Q w I G D q m Vela A F 9 S\ A Q a) {m www W, 0 G wSR .I Q 2 \m m Q m n m .m m m U D II I t m m D m bl mm m 0, w MW P l L l M O O 0 O O O O 0 O 0 O O O 0 0O 4 3 2 l 5 4 3 2 I O 9 8 7 4 w w m M 9 9 9 9 9 6 6 6 6 6 6 5 5 5 3 3 3 3 3 2 uoz om 33m 0m V0 22039::

r. 350m 253? O o mePsemaEw at om 2320 cm 230. cmmz om uucoeotmo SuHur in Feed) Sulfur Removed: Weight Percent of Feed (Reactor Length) U.S. Patent ASTM DISTILLATION TEMPERATURE: "F

Dec. 2, 1975 Sheet 5 of6 3,923,637

HYDRQDESULFURIZATIQN OF OISTILLATE CONTAINING 0.3l WEIGHT PERCENT SULFUR WEIGHT PERCENT DESULFURIZATION US. Patent Dec. 2, 1975 Sheet 6 of6 3,923,637

HYDRODESULFURIZA ION OF KUWAIT GAS OIL Catalyst Activity Data Ni'CoMa on alumina \l/ 80 Q h iCa a on alu ina mill C.5/o iIiCO Desulfurizationj Percent By Weight Average Reactor Temperature: F

FIG. 7

To al Conve sion: 76.3% Gasoline: 0.2%

Piehydrage aiion A1(90%'| PTS.) l9'F Total Cit-aversion; 1D in From 74ml T ble I7 Vol Vol Taial Conversion: 87.7%

Gasoline: 55.2% Prehydroc enaiion l T (90% IO% PTSJ. 24F

Hydrogen fiansumed: SCF/B S Gasoline:

g I I 8 I" Tafal Qarvarsian: 7?.l% Gasoline: 59.5%

0 Prehydr pgenaiion g Toiai Conversion: ELM

L9 6080 i091 6L3 Ya Dom F omk 50 0 7 5 Table I9 HYDRODESULFURIZATION PROCESS WITH A PORTION OF THE FEED ADDED DOWNSTREAM The present invention is directed to the hydrodesulfurization of non-asphaltic distillate or extract oils. The present invention is particularly directed to the hydrodesulfurization of distillate or extract oils prior to riser cracking of the oils with a zeolite catalyst at a low riser residence time without catalystbed formation in the riser reaction flow path. 1

In accordance with this inyention, in riser cracking processes charging sulfur-containing feeds, the sulfur content of the feed is reduced by hydrodesulfurization in order to reduce sulfur emissions to the atmosphere. One means of reducing such sulfur emissions to the atmosphere is to hydrodesulfurize substantially an entire gas oil feed stream prior to cracking by passing the gas oil feed stream containing sulfur in the presence of hydrogen downflow over a fixed compacted bed of catalyst particles comprising at least one Group V1 and at least one Group VIII metal catalyst on a suitable noncracking support such as alumina which may or may not contain a stabilizing but non-cracking quantity of silica, ie less than about 1 or 0.5 weight percent silica. Examples of suitable hydrodesulfurization catalysts include nickel-cobalt-molybdenum, cobalt-molybdenum, nickel-tungsten and nickel-molybdenum. Suitable hydrodesulfurization conditions include a temperature range of 650 to 800F., generally, and 670 to 800F., preferably, a pressure range of 500 to 1,800 psig, generally, 800 to 1,500 psig, preferably, and 800 to 1,200 psig, most preferably, a space velocity range of 0.5 to 5 Ll-lSV, based upon the heavy portion of the total feed only (e.g. 650 to 1,050F. feed), generally, and 0.7 to 2 LHSV, preferably, and a circulation rate of 1,000 to 8,000 SCF/B, generally, and 2,000 to 3,000 SCF/ B, preferably, based on the heavy feed portion of the total feed (i.e. the 650 to 1050F. feed portion) of hydrogen or a gas containing generally about 75 to 80 percent hydrogen. Hydrogeen consumption varies depending on process conditions, feed sulfur content, etc. and can range from 100 to 500 SCF/B, based on said heavy portion of the feedstock, generally. For example, in a feed containing about 3.0 weight percent sulfur, about 400 SCF/B of hydrogen consumption occurs at about 1,000 psig and about 500 SCF/B of hydrogen is consumed at about 1,800 psig. The above ranges are based upon the heavy oil portion only of a total feed, which can also contain a light portion (such as 400F. to 600 or 650F. furnace oil), because the primary objective of the hydrodesulfurization is the removal of the sulfur from the heavy oil portion and it is the heavy oil portion in which most of the sulfur is concentrated.

When a desulfurized feed is charged to a zeolite FCC riser operated without hydrogen addition thereto and having a catalyst regenerator associated therewith for continuous catalyst regeneration, removal of sulfur from the feed stream results in a reduction in sulfur emitted in the product gases from the riser and also results in a reduction in sulfur emitted from the flue gases of the regenerator. However, we have found that the reduction of sulfur emitted from the riser is greater than the reduction of sulfur emitted from the regenerator. This is a disadvantageous feature because the sulfur emitted from the FCC riser is emitted in the form of hydrogen sulfide which is formed by the scission of a molecule at an internal sulfur atom by means of splitting off hydrogen sulfide from the molecule, thereby producing olefinic fragments of the parent molecule. The formation of hydrogen sulfide is not particularly serious because the hydrogen sulfide can be scrubbed from gases from the FCC riser with an amine solution, such as monoethanolamine, which is known to be capable of removing hydrogen sulfide. Therefore, the 1 hydrogen sulfide formed in the riser does not reach the atmosphere.

On the other hand, sulfur off-gas formation in the regenerator is due to the presence of sulfur-containing coke which forms on the zeolite cracking catalyst when the liquid feed first contacts hot regenerated catalyst at the bottom of the riser. The coke is formed from the highest boiling portions of the feed which fail to vaporize and most of the sulfur present in the coke which reaches the regenerator is the sulfur present in the highest boiling hydrocarbon feed molecules. Upon combustion in the regenerator in the presence of oxygen, the sulfur in the coke is converted to sulfur dioxide or sulfur trioxide, while the carbon is converted to carbon monoxide or carbon dioxide. The sulfur oxides formed in the regenerator form a more serious atmospheric pollution problem than the hydrogen sulfide formed in the FCC riser because the sulfur oxides cannot be easily removed by scrubbing of the regenerator flue gas prior to reaching the atmosphere. Therefore, sulfur oxides formed by combustion in the regenerator are emitted to the atmosphere in the regenerator flue gas as noxious atmospheric pollutant. For a diagrammatic scheme of a riser-regenerator system of the type contemplated in this invention, see FIG. 3 of US. Pat. No. 3,617,512, which is hereby incorporated herein, wherein sulfur dioxide is removed from the regenerator through line 74 while hydrogen sulfide is removed from the riser through line 56, from which it can be aminescrubbed.

We have found that, disadvantageously, for any degree of sulfur removal in the total hydrocarbon feed stream to the FCC riser the percent reduction in the noxious sulfur dioxide formed in the regenerator is less than the overall percent of sulfur removed from the total feed stream. The reason is that the sulfur dioxide formed in the regenerator is derived from sulfur present in the higher boiling molecules of the feed which are the molecules in the feed which are the most difficult to hydrodesulfurize. These high boiling molecules do not vaporize when the feed stream contacts hot regenerated catalyst at the equilibrium flash vaporization temperature at the bottom of the riser and therefore are converted to the coke which is formed on the catalyst in the bottom of the riser. In one test it was found that the desulfurization of a West Texas gas oil blend reduced the sulfur content from a feed sulfur content of 1.75 weight percent to 0.21 weight percent (88.0 percent reduction in sulfur). When this feed containing 1.75 weight percent sulfur was cracked without hydrodesulfurization the weight fraction of feed sulfur which ended up in the regenerator flue gas was 0.05 1 whereas when the feed was hydrodesulfurized as described the weight fraction of sulfur in the hydrodesulfurization feed which appeared in the flue gas increased to 0.087. Multiplying 1.75 pounds of sulfur per pounds of non-hydrodesulfurized feed times the 0.051 weight fraction equals 0.089 pounds of sulfur emitted; whereas multiplying 0.21 pounds of sulfur per 100 pounds of hydrodesulfurized feed times the 0.087 weight fraction equals 0.018 pounds of sulfur. This represents a reduction of only 79.8 percent in the weight of sulfur emitted from the regenerator flue gas as compared to a total reduction of 88.0 percent reduction in sulfur in the feed. Therefore an 88 percent reduction of sulfur content in the feed stream results in only a 79.8 percent reduction in sulfur emitted from the FCC regenerator stack gases.

The following table shows how hydrodesulfurization of the aforementioned gas oil feed stream changed the distribution of sulfur in the various streams associated with an FCC riser. The non-desulfurized feed contained 1.75 weight percent sulfur. The desulfurized feed contained 0.21 weight percent sulfur.

SULFUR DISTRIBUTION IN PERCENT NON-DESULFURIZED FEED In Regenerator The above data show that, although the total amount of sulfur in the flue gas is reduced, the proportion of total remaining sulfur that ends up in the regenerator flue gas almost doubles as a result of desulfurization of the feed. I-Iydrodesulfurization of the feed oil clearly results in uneven removal of sulfur from the feed oil.

The above data indicate that any hydrodesulfurization process for the removal of sulfur from the feed stream to an FCC zeolite cracking riser (fluid catalytic cracker) should be encouraged to be more favorable to removal of sulfur from the highest boiling molecules as compared to the lowest boiling molecules in the feed. This is because the data show a disproportionate increase in sulfur in the regenerator flue gas and in the cycle oil, both of which streams are derived from the sulfur in the highest boiling portions of the feed. This presents a difficult problem because the desulfurization reaction rate constant for the lower boiling molecules in the cracking feed stream is exponentially higher than the desulfurization reaction rate constant of the higher boiling molecules. For example, the desulfurization reaction rate constant of a feed having a volume average boiling point of 493F. is 185 whereas the desulfurization reaction rate constant of a feed having a volume average boiling point of l,043F. is only 2.75. The exponential relationship between desulfurization reaction rate constant and volume average boiling point of a hydrocarbon feed is shown in Table I.

The above data illustrate the great difficulty associated with removing sulfur from the high boiling portions of a feed stream as compared with the low boiling portions of the same feed when the feed source has a significantly wide boiling range.

In accordance with the present invention we have discovered a means of improving desulfurization of the higher boiling components in a hydrocarbon feed stream. Our discovery is based upon data showing the existence of a synergistic effect in desulfurization reaction rate between the lowest and the highest boiling sulfur-containing molecules in the hydrodesulfurization process wherein desulfurization of the highest boiling sulfur-containing molecules is enhanced at the expense of desulfurization of the lower boiling sulfur-containing molecules but because the higher boiling portions of the feed are richer in sulfur there is a net positive effect in terms of total sulfur removal due to the synergism. We have found that when the hydrodesulfurization reaction is controlled in such a manner that there is a high degree of selectivity toward desulfurization as contrasted to hydrocracking the synergistic effect may be used to maximum advantage. The low boiling molecules assist the high boiling molecules in the desulfurization process, perhaps by alternating use of the same reaction sites wherein the rapidly reacting lighter molecules utilize a given site between utilization of the site by consecutive slower reacting heavy molecules. Because the lighter molecules react so rapidly, the active sites are available to the heavy molecules a greater portion of the time than when the heavy molecules are processed alone at the same space velocity. We have observed that as the boiling range of a hydrocarbon feed stream is increased the amount of catalyst required to accomplish a given degree of hydrodesulfurization per barrel of feed diminishes as compared to the hydrodesulfurization of the high and low boiling portions of the same stream in separate reactors at the same conditions, indicating the occurrence of a synergistic sulfur removal effect between molecules of different boiling points. For example, Table 2 shows that for a particular crude source as the difference in temperature between the end point and the initial boiling point of a feed stream having a volume average boiling point of 850F. increases there is a proportional reduction in catalyst requirement, compared to that required for treating the light and heavy halves of the feed separately, to accomplish a given amount of sulfur removal. Table 3 shows that for the same crude source, as the difference in temperature between the end point and the initial boiling point of a feed stream having a volume average boiling point of 750F. increases there is a corresponding reduction in catalyst requirement as compared to that required for treating the light and heavy halves separately, without changing other conditions. The reduction in catalyst requirement to accomplish a given amount of sulfur removal without changing other reaction conditions is different when the feed has a volume average boiling point of 750F. as compared to a feed having a volume average boiling point of 850F. In both cases, the reduction in catalyst requirement increases as the breadth of boiling range increases. The basis for comparison in determining the reduction in catalyst requirement in Tables 2 and 3 is the amount of catalyst that would be required if the same amount of feed oil containing a given amount of sulfur is treated, except that the temperature differential between the E. P. and I. B. P. is changed as indicated. For example, the 0 data point in Tables 2 and 3 represent a given quantity of oil, all of which boils at 850 and 750F.. respectively. The second data point represents the same quantity of oil having a boiling range extending over 100F. The third data point represents the same quantity of oil having a boiling range extending over 200F. The data show that significant reductions in catalyst requirements become a total feed stream. With certain feeds, the reduced catalyst requirement when treating the blend permits the V blend-treatment process to be terminated before depossible when the boiling range of the feed oil is at least 400 or 500F. wide when the volume average boiling point of the feed is at least 750F. Even greater savings in catalyst becomes possible if the range between the feed IE? and EP is at least 600F.

TABLE 2 Reduction in Catalyst Requirement for Feed It is important to the present invention that the catalyst economy permitted by broadening the feed boiling range be correlated with the synergistic effect to remove a substantial amount of the most refractory sulfur in the feed with diminished hydrocracking. Therefore, in accordance with the present invention the synergistic effect should not be permitted to reduce the catalyst quantity to the extent that the 90 percent point of the feed is not reduced at least 10F. or l5F., indicating a substantial removal of the most refractory sulfur in the feed in spite of the reduced quantity of catalyst. At the same time, the catalyst reduction should be sufficient so that the 10 percent distillation point of the feed is not lowered more than F. more than the 90 percent distillation point, and in any event the 10 percent distillation point is not lowered more than 50F. In this manner, the amount of catalyst is limited to advantageously permit both enhanced desulfurization (cleavage of carbon-sulfur bonds) while significantly inhibiting hydrocracking (cleavage of carbon-carbon bonds). Therefore, in accordance with this invention, under the same reaction conditions proportionately more catalyst is required to remove the same amount of sulfur from the higher-boilin g half of the total feed when it is treated by itself than if the higher-boiling half of the total feed is hydrodesulfun'zed in blend with a lower boiling half of creasing the boiling characteristics of the feed beyond that described above.

FIGS. 1-7 contain graphs of data taken to illustrate the present invention.

Data were taken (Table 4 and FIG. 1) to illustrate that the synergistic effect of the present invention is highly surprising and is a synergistic effect based upon the sulfur removal reaction. For example, data were taken employing as a hydrodesulfurization feed a full range gas oil containing 2.93 percent sulfur. The 10 and 90 percent distillation points of the full range gas oil were 680 and 1,01 1F. respectively. Thereupon, blends of the gas oil and lubricating oil extracts were prepared, each lubricating oil extract stock having about the same sulfur content but a different boiling range and a different viscosity. In one case the lubricating oil extract was a light lubricating oil extract containing 5.06 weight percent sulfur having 10 and 90 percent distillation points of 695 and 820F., respectively. The light lubricating oil had a boiling range within the boiling range of the full range gas oil and was of about the same viscosity. In the second case the lubricating oil extract was a bright stock extract whose boiling range extended considerably outside the boiling range of the full gas oil on the high side, having a 10 percent distillation point of 1,010 and an estimated 90 percent distillation point of l,l32F., respectively, and was considerably more viscous than the gas oil. The bright stock extract had a sulfur content of 4.97 weight percent. In each case where a gas oil-lubricating oil extract blend was desulfurized, the blend comprised percent of a portion of the same gas oil together with 30 percent of the particular lubricating oil extract, i.e. either the light lubricating oil extract or the bright stock extract.

It would be expected that the blend containing the bright stock extract would have been more difficult to desulfurize because it had a higher average boiling point and was more viscous than the blend containing the light lubricating oil extract which had a boiling point within the range of the gas oil with which it was blended and about the same viscosity. This expectation is especially true since data show that the bright stock extract, by itself, was considerably more difficult to hydrodesulfurize than the light lubricating oil extract, by itself. However, it was unexpectedly found that there was a considerable synergistic effect in regard to sulfur removal in the case of the blend of the bright stock extract and the gas oil, even though the bright stock boiled considerably above the upper boiling point of the gas oil and had a considerably higher viscosity, which would be expected to slow the reaction rate. It was further found that there was no synergistic effect in regard to sulfur removal in the case of the blend of the gas oil and the light lubricating oil extract whose boiling range was within the boiling range of the gas oil. These results are shown in Table 4 and are illustrated in FIG. 1.

TABLE 4 Full Range Gas Oil 70% 6.0. 30% Light Lube Extract Charge and Product Inspections 70% 6.0. 3071 Bright Stock Extract Charge Charge Charge Hydrodesulfurization (Not hydro- (Not hydro- (Not hydro- Temperature: F. desulfurized) desulfurized) 680 710 desulfurized) 680 710 Inspections Gravity: API 22.4 18.1 23.6 24.4 19.2 23.9 24.5 Sulfur: by Weight 2.93 3.63 0.91 0.60 3.66 0.94 0.61 Viscosity: SUS

130F. 119.3 220 82.3 74.9 310 171.2 146 210F. 48.7 42.2 51.0 55.1 52.1 Distillation, Vacuum: D1 160 at F. 689 700 671 643 710 710 687 30% 754 738 728 719 792 803 777 50% 818 780 773 765 894 903 864 70% 897 845 837 827 999 1004 964 90% 1011 948 944 936 1079 1110 1061 End Point: F.

The surprising results in regard to Table 4 are shown in the following summation entitled Table 4A which contains data directly extracted from Table 4.

TABLE 4A Table 4A also shows that the gas oil-light lubricating oil extract blend was not capable of hydrodesulfurization without an increase in the temperature difference 70% G.O. 30% Light Lube Extract Hydrodesulfurization Temperature: F.

Sulfur in Feed Weight Percent Sulfur in Product Weight Percent Increase in difference between the 10 and 90 percent distillation points due to hydrodesulfurization Temperature of 90 percent point: F

70% 6.0. Bright Stock Extract Table 4A shows that the mixture containing the gas oil and light lube extract had about the same sulfur content as the mixture containing the gas oil and bright stock extract. Table 4A further shows that at desulfurization temperatures of 680 and 710F., respectively, about the same degree of sulfur removal occurred with each charge stock. These data tend to obscure and hide the discovery of the present invention since they tend to show that any feedstock having a fixed feed sulfur content is desulfurized to the same extent at the same desulfurization conditions. However, the results shown in Table 4A become surprising when it is realized that the bright stock extract mixture is much more viscous than the mixture containing the light lube oil extract and therefore would have been expected to result in a lower degree of sulfur removal due to diffusion difficulties arising from its higher viscosity. This expectation is especially true in view of FIG. 1 which shows that the unblended and less viscous light lubricating oil extract is more easily desulfurized than the unblended and more viscous bright stock extract under similar conditions. Tables 4 and 4A show that a synergistic effect becomes controlling due to a widening of feed boiling range by blending a material having an overlapping, continuous or broader boiling range. As explained below, the synergistic effect upon reaction rate upon blending is also illustrated in FIG. 1, by comparing curves B and C and observing that in blend they both produce curve D.

between the 10 and percent distillation points of more than 20F, indicating the onset of significant hydrocracking, whereas the 720F. test with the gas oilbright stock extract blend resulted in only a 5F. increase in this temperature differential, indicating very little hydrocracking accompanying the desulfurization reaction, while the 90 percent point dropped from l,079 to l,06lF. (18F), indicating a significant removal of sulfur from the highest boiling, most viscous portion of the feed. In the test in which there was only a 5F. temperature differential increase, this low temperature differential increase was accomplished because there was no increase in quantity of catalyst upon widening the boiling range of the feed. If the quantity of catalyst were increased, as by lengthening the catalyst bed, extensive hydrocracking would have been encountered when low sulfur levels were reached because the presence of sulfurserves to inhibit onset of extensive hydrocracking. Therefore, the sulfur-removal synergistic effect of the present invention requires that the quantity of catalyst be controlled or limited as the boiling range of the feed oil is widened if extensive hydrocracking is being experienced with that boiling range. Thereby, the savings in catalyst required increases as the boiling range of the feed widens.

FIG. 1 illustrates diagrammatically the synergistic effect based upon the data in Table 4 and Table 4A. Referring to FIG. 1, line A shows the desulfurization characteristics versus reaction temperatures of the full range gas oil by itself. Line B shows the desulfurization characteristics of the light lubricating oil extract by itself versus reaction temperatures. Line C shows the desulfurization characteristics of the much heavier bright stock extract by itself versus reaction temperatures. FIG. 1 shows that even though the bright stock extract had about the same amount of sulfur in the feed as the light lubricating oil extract, because of its higher viscosity, and lower reaction rate due to its higher boiling range, as expected, less sulfur was removed when it was treated by itself. This shows that when the bright stock extract is treated by itself and when the light lubricating oil extract is treated by itself viscosity and reaction rate due to boiling range (see Table l) is a controlling feature in the hydrodesulfurization reaction.

Line D in FIG. 1 represents the sulfur removal characteristics versus reaction temperatures of (1) the blend of the gas oilof curve A and the light lubricating oil extract curve B, and also (2) the separate blend of the gas oil of curve A and the bright'stock extract of curve C. Line D unexpectedly shows the same desulfurization results are achieved whena 70 percent 30 percent blend of gas oil is" made up with either the light lubricating oil extract or the much heavier and more viscous bright stock extract. Line D therefore shows there is a synergistic effect in reaction rate between the bright stock extract, which boils above the boiling range of the gas oil, which overcomes the diffusion limitation due to viscosity whereas there is no synergistic effect in the case of the blend of the gas oil and the light lubricating oil extract wherein the light lubricating oil boils within the boiling range of the gas oil. In general, the wider the boiling range to which a feedstock can be extended, the greater will be the synergistic effect between the lightestandheaviest-boiling components in regard to hydrodesulfurization synergism.

There are two surprising aspects in the discovery that the blend of high boiling bright stock extract and gas oil provide the same hydrodesulfuriztion characteristics as the. blend of the lower boiling. light lubricating oil extract and gas oil. Since the bright stock extract has a boiling range higher than the gas oil, it is not only more viscous than the gas oil and therefore should provide a action but also, as shown in Table 1, it has a lower reaction rate constant because of its high average boiling point, as compared to the lower boiling light lubricating oil extract. However, both (1) the high viscosity diffusion effect which provides resistance against the hydrodesulfurization reaction in the absence of blending and (2) the lower reaction rate constant of the bright stock extract due to its higher average boiling point were overcome to the extent that the bright stock extract blend with the gas oil exhibited the same hydrodesulfurization characteristics as the blend of the light lubricating oil extract with the gas oil, the latter blend not having overlapping boiling ranges. Therefore, there is a considerable synergistic effect in reaction rate by combining stocks having overlapping boiling ranges causing the boiling range of the blend to be wider than the 'boiling range of either component alone. The same effect could be obtained by preparing directly via distillation a hydrodesulfurization feedstock having a very wide boiling range. The advantageous result of the present invention can be achieved by combining feedstocks in a single reactor which ordinarily are hydrodesulfurized in several reactors such as furnace oil, light gas oil, heavy gas oil, light and medium lubricating oil, light and medium lubricating oil extracts, coker gas oil, FCC cycle oil, and so forth, in a manner that the improved synergism in regard to the sulfur removal reaction rate is greater than the detriment due to the inhibited diffusion effect and low reaction rate contributed by the higher-boiling component. Example 7 shows a special effect occurs when a virgin gas oil is blended with coker gas oil. One or all of the mixed streams can be separated from the hydrodesulfurized blend effluent, if desired. For example, heavy gas oil and furnace oil can be blended prior to hydrodesulfurization and then separated following desulfurization, with the furnace oil being employed as a fuel and the heavy gas oil being employed as an FCC feedstock.

Tables 4B and 4C present a tabulation of the feed and product data from which curves B and C of FIG. 1 were obtained. In Table 4C, certain boiling points of the feed were estimated because of the difficulty of distillation of very high boiling material.

TABLE 43 HYDRODESULFURIZATION OF KUWAIT LIGHT LUBE EXTRACT at 1000 p ig 2 vol/hr/vol and 2000 SCF/B Hydrodesulfurization Charge Temperature: F. (Not hydro- 680 710 740 desulfun'zecl) 1 Inspections Gravity: API 9.4 16.9 17.7 18.6 Sulfur: by weight 5.06 1.77 1.18 0.73 Desulfurization'. 65.0 76.8 85.7

Distillation, Vacuum: Dl 160 10% at F. 695 633 612 574 30% 718 680 673 654 742 712 707 694 771 744 740 738 820 793 807 784 End Point 884 856 855 high diffusion resistance in the hydrodesulfurization re- TABLE 4C at l000F.. 2 vol/hr/vol and 2000 SCF/B Hydrodesulfurization Temperature F.

Charge (Not hydro- 680 710 740 TABLE 4C-continued HYDRODESULFURlZATlON OF KUWAIT BRIGHT STOCK EXTRACTS at 1000F., 2 vol/hr/vol and 2000 SCF/B Further tests were performed to illustrate the syneron the low-temperature side of the range. Tests were gistic effect in hydrodesulfurization reaction rate utilizmade in which a blend containing 35 weight percent of ing a nickel-cobalt-molybdenum on alumina catalyst 20 furnace oil having a boiling range of 475 to 638F. was (all hydrodesulfurization tests reported herein utilized added to full range gas oil having a boiling range of this type of catalyst composition unless otherwise 615 to 1,005F. containing light lubricating oil extract noted) when the added stream has a boiling range having a boiling range of 706 to 840F. The results of which overlaps, is contiguous with or extends beyond these tests are shown in Table 5 and in Table 6.

TABLE 5 HYDRODESULFURIZATION OF BLENDED'CHARGE STOCKS Conditions: 680F., 940 psig, 0.8 LHSV, 2000 SCF/B (80% H Charge Sulfur Content Kuwait Product Sulfur Content l 1 ppm 1.43 weight Furnace Oil Product Yield 97.91 wt of fresh feed (475-638TF. Unit Hydrogen Consumption 387 SCF/B B.R.) Aromatics decreased from 36 to 21 vol Charge Sulfur Content Kuwait Full Product Sulfur Content 0.18 wt 2.74 weight RangeGas Product Yield 96.65 wt 70 of fresh feed Oil Unit Hydrogen Consumption 499 SCF/B (6l5-1005F. Aromatics decreased from 51 to 41 vol B.R.) Charge Sulfur Content Kuwait Lube Product Sulfur Content 0.88 wt 6.03 weight Oil Extract* Product Yield 94.52 wt of fresh feed (706-840F. Unit Hydrogen Consumption 1024 SCF/B B.R.) Aromatics decreased from 88 to 81 vol Hydrodesulfurizing a Blend of 35 wt Kuwait Furnace Oil 53 wt Kuwait Full Range Gas Oil 12 wt Kuwait Lube Oil Extract Charge Sulfur Content Calc. Results Product Sulfur Content 0.20 wt 2.68 weight for the Product Yield 96.84 wt of Fresh Feed Blended Hydrogen Consumption 514 SCF/B Material Aromatics 38.2 vol Charge Sulfur Content Observed Results -a Product Sulfur Content 0. 14 wt 2.68 wt for the Blended Product Yield 96.26 wt of fresh feed Material Unit Hydrogen Consumption 463 SCF/B that of the primary stream, but where the extension is Aromatics 40.0 vol This run was made at 300 SCF/B reactor gas rate to compensate for high hydrogen consumption. Results calculated by algebraic combination of component results shown above.

TABLE 6 HYDRODESULFURIZATION OF BLENDED CHARGE STOCKS Conditions: 680F., 940 psig, 1.6 LHSV. 2000 SCF/B (80% H Product Sulfur Content 55 ppm Product Yield 98.03 wt 7: of fresh feed Unit Hydrogen Consumption 276 SCF/B Product Sulfur Content 0.37 wt Product Yield 97.00 wt 7: of fresh feed Unit Hydrogen Consumption 356 SCF/B Product Sulfur Content 1.71 wt Product Yield 96.40 wt of fresh feed Unit Hydrogen Consumption 884 SCFIB Hydrodesulfurizing a Blend of 35 wt 70 Kuwait Furnace Oil 53 wt 7: Kuwait Full Range Gas Oil 12 wt 7: Kuwait Lube Oil Extract Charge Sulfur Content Cale. Results Product Sulfur Content 0.40 wt 2.68 weight 7: for the Blended Product Yield 97.29 wt 7 of fresh feed Material Hydrogen Consumption 383 SCF/B Aromatics 40.5 vol 9: Charge Sulfur Content Observed Results Product Sulfur Content 0.28 wt 7 TABLE 6-continued 2.68 weight for the Blended Material Product Yield 97.39 wt of fresh feed Unit Hydrogen Consumption 370 SCF/B Aromatics 40.9 vol% This run made at 3000 SCF/B reactor gas rate to compensate for high hydrogen consumption.

Results calculated by algebraic combination of component results shown above.

Table shows that when the full range gas oil, the light lubricating oil extract and the furnace oil is each hydrodesulfurized by itself, the calculated results would indicate a product having 0.20 weight percent sulfur but that when the streams were blended and desulfurized together the product had a sulfur content of 0.14 weight percent sulfur, indicating the existence of a synergistic effect upon the reaction rates by blending a stream (the furnace oil) which extends beyond the boiling range of the primary stream on the lower boiling side. Table 6 shows a proportionally similar synergistic effect occurs (sulfur removal is increased from an expected value of 85 percent to a value of 90 percent) with the same system when the space velocity is doubled from 0.8 to 1.6 LI-ISV. Tables 5 and 6 also show that unit hydrogen consumption (chemical hydrogen consumption by free hydrogen balance around the unit) is lower when the blend is treated than would have been expected, even though more sulfur is removed than expected. This demonstrates the synergistic effect, whereby sulfur removal is high while the extent of undesirable hydrogen-consuming reactions (hydrogenation and hydrocracking) are limited. Of course, limiting hydrogen consumption is economically advantageous, and controlling both hydrogenation and hydrocracking leads to the production of a superior gasoline in the subsequent riser cracking step.

Table 7 shows the characteristics of the furnace oil feedstock of Tables 5 and 6 and the furnace oil effluent from the hydrodesulfurization reactor at a space velocity of both 0.8 and 1.6 when the furnace oil is hydrodesulfurized by itself.

TABLE 7 I-IYDRODESULFURIZING OF KUWAIT FURNACE OIL Average Reactor TABLE 7-continued I-IYDRODESULFURIZING OF KUWAIT FURNACE OIL I TABLE 8 HYDRODESULFURIZING OF KUWAIT LUBE OIL EXTRACT Average Reactor Temperature: F. Reactor Pressure:

psrg 941 941 LHSV: vol/hr/vol 0.80 1.59

Gas Rate: SCF/B 2969 2988 I-1 Content of Reactor Gas:

vol 80.3 79.4

Hydrogen Consumption:

SCF/B (Unit) 1042 884 Total Liquid Product Yield:

wt of fresh feed 94.52 96.40

Liquid Product Inspections Feed Gravity: API 9.3 18.6 18.1

Sulfur: wt 6.03 0.88 1.71

Distillation, ASTM Vacuum: 10 MM EP 840 831 829 5% 706 584 622 10% 709 616 646 20% 716 648 669 30% 728 667 684 40% 73 5 684 700 50% 743 698 712 60% 754 712 726 765 726 740 779 742 754 799 765 781 81 3 V 778 795 Table 9 shows the characteristics of the gas oil feedstock of Tables 5 and 6 and the gas oil hydrodesulfurized effluent when the gas oil feedstock is hydrotreated by itself at space velocities of 0.8 and 1.6.

TABLE 9 HYDRODESULFURIZING OF KUWAIT GAS OIL Average Re actor TABLE 9-continued I'IYDRODESULFURIZING OF KUWAIT GAS OIL Table 10 shows the characteristics of the blend of the furnace oil, gas oil and the light lubricating oil extract feedstock of Tables and 6-and also shows the characteristics of the effluent from the hydrodesulfurization reactor' when this feedstock blend is hydrodesulfurized at a space velocity of about 0.8 and 1.6.

TABLE 10 HYDRODESULFURIZING OF A BLENDED CHARGE STOCK Charge: Blend of 35 wt Kuwait furnace oil,

53 wt Kuwait gas oil, 12 wt Kuwait lube oil extract Average Reactor Temperature: F. 680 680 Reactor Pressure:

pslg 937 939 LHSV: vol/hr/vol 1.64 0.78

Gas Rate: SCF/Bbl 1907 2000 H Content of Reactor Gas:

vol 79.4 80.3

Hydrogen Consumption:

SCF/Bbl (Unit) 370 463 Total Liquid Product Yield:

wt of fresh feed 97.39 96.26

Total Product Inspections Feed Gravity: API 26.3 30.3 31.9

Sulfur: wt 2.68 0.28 0.14

Distillation, ASTM Vacuum: 10 MM I The present hydrodesulfurization process can be advantageously applied to a situation where a relatively low-boiling, low sulfur-containing hydrocarbon stream from a first crude source, such as furnace oil boiling be tween 400 and 600 or 650F., which does not meet commercial sulfur requirements (which is 0.2 weight percent sulfur, or lower) and therefore would require desulfurization in a first reactor while in the same refinery a relatively high-boiling, high sulfur-containing gas oil from a secondcrude source having a volume average boiling point above 750F. is hydrodesulfurized in a second reactor. In accordance with the present invention, a relatively high boiling portion of the furnace oil, after separation from the furnace oil, is blended with the gas oil to produce a total hydrodesulfurization feed oil blend having a volumetric average boiling point of at least 700 or 750F., but lower than the original volume average boiling point of the gas oil. Sufficient high boiling high sulfur-containing material is separaed from the furnace oil for blending with the gas oil that the remaining light furnace oil is sufficiently low in sulfur to meet commercial domestic sulfur specifications (below 0.2 weight percent) without requiring passage through a hydrodesulfurization zone. In this manner, the boiling range of the heavy gas oil is advantageously broadened to impart a synergistic sulfur-removal effect to it, while no desulfurizer is required for the light furnace oil, thereby avoiding construction of a furnace oil desulfurizer.

Similarly, the present invention can be applied to combining an entire light oil stream (such as furnace oil) with an entire gas oil stream (boiling between 600 or 650 and 1,050F.) to produce a wide-boiling blended total stream having a high synergistic effect which is processed in a single reactor, instead of charging the separate streams to separate reactors because the lighter oil is destined for use as a furnace oil whereas the heavier gas oil is destined for use as an FCC feed. If desired, the hydrodesulfurized blend can be charged in its entirety to the FCC riser or it can be fractionated and the furnace oil can be used as a fuel oil and the gas oil only can be charged to the FCC riser. The blend of the two streams should have an average boiling point of at least 700 or 750F.

Additional tests were conducted to illustrate the hydrodesulfurization of blends of oils to show the effect upon sulfur removal in the lower boiling portion of the blend. In these tests a blend of a naphtha range feed with a furnace oil feed was hydrodesulfurized with a catalyst comprising nickel-cobalt-molybdenum on alumina. The results of the tests are shown in FIG. 2.

FIG. 2 not only shows that the sulfur content in the lighter portion of the feed, that is the naphtha, is much lower (0.04 weight percent or 400 ppm) as compared to the sulfur content in the furnace oil (102 weight percent) but also that the sulfur in the naphtha oil portion of the blend at any given hydrodesulfurization temperature is removed relatively more easily than the sulfur of the heavier fumace oil fraction. FIG. 2 compares the sulfur content of the naphtha portion of the effluent and the furnace oil portion of the effluent when operating at space velocities of 4.0 and 5.0, respectively. Line E of FIG. 2 shows the level of sulfur removal that would occur in the furnace oil at 5 LI-ISV if the naphtha was not present in the blend. Line E shows that the naphtha exerts a synergistic effect upon sulfur removal of the heavier furnace oil portion of the feed.

Data were also taken by hydrodesulfurizing a heavier naphtha alone, without the presence of furnace oil, and these data tend to show that the presence of the heavier furnace oil inhibits removal of sulfur from the lighter naphtha portion of the blend. Therefore, the mechanism of the synergistic effect upon reaction rate is apparently that the lighter portion of the blend advantageously tends to increase sulfur removal from the 17 heavier portion of the blend while the heavier portion of the blend tends to inhibit sulfur removal from the lighter portion of the blend and the net effect is an overall enhancement of sulfur removal clue to blending.

The important feature of the present invention is that the presence of lighter material assists removal of sulfur from the heavier material. This fact is important because, as noted above, it is the sulfur in the heavier ma-' terialwhich is not easily vaporized and which is theretha product when the naphtha was present in a blend 7 with furnace oil. I

be scrubbed from riser off-gases with an amine, such as diethanolamine, and is thereby prevented from polluting the atmosphere. Furthermore, it was shown above that in any hydrodesulfurization process sulfur removal from the light feed material occurs more easily and to a greater extent than sulfur removal from a heavier material present in the hydrodesulfurizing feed whereby a smaller percentage reduction in sulfur dioxide is observed than the percent reduction in total sulfur in the feed to an FCC unit.

Table 11 shows the characteristics of the naphtha in the feed of the blend of FIG. 2 and also shows the characteristics of the naphtha portion in the product from the hydrodesulfurization process of FIG. 2.

TABLE 1 l INSPECTION DATA FOR c,-3s0F. NAPHTI-IA PRODUCTS FROM DESULFURIZAT ION AT A FEED RATE OF 5.0 LHSV I C .,-680F. Charge Distillate Operating Conditions LI-ISV: vol/hr/vol 5.0 Reactor Pressure: 5.0

p s 700 Average Reactor As shown in Table l l and as shown in FIG. 2 at about a hydrodesulfurization temperature of 640F. the sulfur content in the naphtha portion of the hydrodesulfurization product is about 1 ppm. It is noted that the data points in FIG. 2 for the naphtha product show that less severe conditions did 'not produce a 1 ppm sulfur naph- Table 12 shows the results of a test treating a higher boiling naphtha in an unblended condition with a similar catalystto hydrodesulfurize the naphtha at conditions of 300 psig, 600F., 5.6 LI-ISV and 300SCF/B of hydrogen. Each one of these test conditions is much less severe than the comparable condition employed in the hydrodesulfurization reaction illustrated in Table l l. The characteristics of the unblended naphtha feed and the unblended naphtha hydrodesulfurization product of these tests are illustrated in Table l2.

TABLE 12 HYDRODESULFURIZATION OF A LOW SULFUR CONTENT vVIRGIN NAPHTHA AT LOW HYDROGEN PARTIAL PRESSURE Operating Conditions Temperature: F. 600 Pressure: psig 300 Space Velocity:

vol/hr/vol Gas Circulation: 5.6 SCF/B 300 H 846 Inspections Charge Gravity: API 48.0 47.8 Sulfur: ppm 400 l Distillation: ASTM D86 IBP: F. 27I 270 EP: F. 4l I 41 l 10% at F. 297 302 30% 315 3l8 50% 331 333 70% 346 349 90% 373 373 Table 12 shows that under much less severe hydrodesulfurizing conditions, when employing an unblended naphtha feed the sulfur content of the product was reduced to about the same level, i.e. about 1 ppm, as when the naphtha was treated in the presence of furnace oil but under much more severe conditions, indicating that the presence of a heavier material with the naphtha feed tended to inhibit sulfur removal in the naphtha portion of the blend. As noted above and as shown in FIG. 2, in a blended condition the naphtha required the full reaction severity indicated to achieve the 1 ppm sulfur level. These data indicate that although according to the synergistic sulfur removal reaction effect of the present invention the presence of a lighter material enhances the rate of sulfur removal of the heavier portion of the blend, at the same time the sulfur removal from the lighter portion of the blend tends to be inhibited.

A variation of the present invention is presented in the process illustrated in FIG. 3 wherein the synergistic effect of this invention can be partially foregone with advantage. FIG. 3 illustrates the degree of sulfur removal when a blend of two'ditferent feed portions having adjacent or overlapping boiling ranges including a light portion (such as a furnace oil having a boiling range between 400 and 650F.) and a heavy portion (such as gas oil having a volume average boiling point above 750F.) are added to a hydrodesulfurization reactor employing the same type of nickel-cobalt-molybdenum on alumina catalyst employed in the prior tests, together with hydrogen, in downflow reactor operation over a stationary bed of compacted catalyst particles.

In the system of FIG. 3, a virgin oil which has a relatively high boiling range, and a relatively high sulfur 19 content, is the heavy portion of the blend and the effluent sulfur content of this fraction only of the total product is indicated by line G in FIG. 3.

Line F of FIG. 3 illustrates the sulfur content in the total product when a virgin oil having a lower boiling range (volume average boiling point below 750F.) and having a lower sulfur content is combined with the heavy oil (volume average boiling point above 750F.). In the abscissa-of the curve of FIG. 3 it is shown that when the total blend employing the light oil together with the heavy oil is charged to the inlet of the reactor percent of bed depth), the sulfur in the total product is at its lowest value while the sulfur in the heavy oil portion distilled out of the total product (line G) is at its highest value.

Line G represents the sulfur content in the heavy oil distilled out of the total product including both light oil and heavy oil, except that the terminus of line G, indicated by point K, indicates the sulfur content of the heavy gas oil effluent when the heavy oil is charged through the entire catalyst bed without any of the light oil. Point K shows that the total absence of light oil permitted maximum desulfurization of the heavy oil because the heavy oil did not have to compete withthe light oil for catalyst sites. Therefore, although the light oil provides the synergistic effect of this invention, it also inherently produces a negative dilution effect and the following discussion of FIG. 3 illustrates a system wherein the synergistic effect of the light oil can be partially obtained while holding to a minimum its negative effect of dilution of the heavy oil.

Referring to FIG. 3, the unusual feature is observed that very close to a minimum level of sulfur content in the total product, as indicated by point H, is achieved if the heavy oil portion of the total blend only is added to the top of the catalyst bed and permitted to pass through about 80 percent of the catalyst bed undiluted by light oil while the light oil portion of the total blend only is added to the reactor at a point about 80 percent downwardly into the bed depth. The total blend has a volume average boiling point of at least 750F. FIG. 3

shows that when the heavy oil portion of the blend is added with hydrogen at the top of the. catalyst bed and the light oil is added at a point about 90 percent downwardly into the bed depth, the sulfur content in the heavy oil fraction of the product and in the total product is about equal, since this is the point at which curves F and G cross. FIG. 3 further shows, that if the light oil portion (having a volume average boiling point below 750F.) of the blend is not added to the hydrodesulfurization reactor but the heavy oil alone (having a volume average boiling point above 750F.) passes through the entire catalyst bed having access to catalyst sites which is uninhibited by the presence of the light oil, the heavy oil portion itself is desulfurized to the greatest extent (point K). FIG. 3 also shows that if the light oil in a nondesulfurized condition is blended with the hydrodesulfurized heavy gas oil effluent, the sulfur content of the total product is a maximum, and is at an unacceptably high value (point J), which indicates a highly inefficient mode of operation, and may not even constitute 80 percent sulfur removal from the total feed including both high and low boiling portions. Therefore, according to FIG. 3, the most advantageous mode of operation for sulfur removal from the heavy oil is to add the heavy oil at the top of the reactor bed and not to add light oil to the reactor at all. But if the light oil is ultimately to be blended with-the heavy oil, or if the light oil must be desulfurized, FIG. 3 indicates the most economical mode of operation is to add the light oil fraction to a point at about percent downwardly in the bed depth so that the sulfur content in the total effluent is nearly a minimum, as indicated by point H, while the sulfur content in the heavy oil portion only of the total product nearly approaches its minimum value at point K (see point 1). Although this mode of operation gives up-the synergistic effect contributed by the light portion along the top 80 percent of the catalyst bed, it does have the advantage of not diluting the refractory sulfur-containing molecules in the heavy fraction along the top 80 percent of the bed depth and thereby permitting greater sulfur removal from the heavy fraction only while employing a smaller reactor and a smaller quantity of catalyst and thereby achieving a large economic advantage while giving up only a small advantage in terms of the sulfur content in the total product.

If the synergistic effect of this invention is the only consideration, it would be advantageous to charge the light oil portion to the top of the catalyst bed together with the heavy oil portion so that the light oil portion can exert a maximum sulfur removal synergistic effect upon the heavy portion of the total product, However, by adding the light portion late to the reactor an additional advantage is achieved in that it is easier for the process to achieve 80 percent total desulfurization with a limited amount of catalyst and without increasing the temperature differential between the 10 and percent distillation points of the total feed more than 20F., although the temperature drop of the 90 percent point is more easily lowered at least 10 or I5F., indicating enhanced sulfur removal from the high-boiling portion and rendering the high-boiling high-sulfur compounds more easily vaporizable in a subsequent FCC riser, to reduce sulfur dioxide formation. Whatever mode of operation is employed the entire effluent can be changed to the FCC step or the effluent can be distilled to recover light oil for use as furnace oil, and heavy oil, for charging the FCC riser. Points H and I of FIG. 3 indicate that operation of the hydrodesulfurization reactor by injecting the light portion at about 80 percent of the bed depth represents an ideal compromise between the synergistic and dilution effects of the light oil in that the sulfur level in the total product is almost a minimum (Point H) while the sulfur level in the heavy portion only of the product is also close to a minimum (Point I). Injection of the light oil at greater than 80 percent of the bed depth improves sulfur removal from the heavy portion of the product only slightly while greatly increasing the sulfur level in the total product. FIG. 3 illustrates results with a particular feed blend but with other feed blends the optimum point of injection of the light oil (point H) might be elsewhere in the bed, e. g. at 50, 60, 70 or even at a deeper percentage of the bed depth.

An especially important feature of the present invention is illustrated in FIG. 4. FIG. 4 represents the variation of the 10 percent distillation point and the 90 percent distillation point in a feed oil during a hydrodesulfurization process of the present invention. Suitable feed oils for this invention include the overhead of atmospheric or vacuum distillations and include oils in the furnace oil and gas'oil boiling ranges. The 90 percent distillation point represented by line M in FIG. 4 is particularly important because the 90 percent distillation point material represents the heavy material in the system in which the sulfur content is richest, from which it is most difficult to remove sulfur, and which contains the sulfur which is present in the coke of a subsequent FCC riser which ends up as sulfur dioxide in an FCC regeneration operation. A significant drop in the 90 percent distillation point, i.e. at least F., or more, is tangible evidence of significant removal of sulfur from the heaviest material in the feed stream. Therefore, it is important to a hydrodesulfurization process of the present invention that a significant drop occur in the 90 percent distillation curve of a feed moving through a hydrodesulfurization reactor. In the process of PEG. 4, the feed and hydrogen flow downwardly over a fixed, stationary bed of nickelcobalt molybdenum on alumina catalyst particles.

The line L in FIG. 4 represents the drop in temperature of the 10 percent distillation point. The 10 percent distillation point drops more readily than the 90 percent distillation point because it represents the accumulation of all light components produced due to either sulfur removal or hydrocracking of higher boiling materials. The removal of sulfur from the 10 percent distillation point material of the feed occurs most readily because, as shown in Table 1, above, the desulfurization reaction rate constant is low in high boiling materials but increases exponentially as the boiling point of the sulfur-containing component decreases. However, it is noted that the 10 percent point should not drop more than 40 or 50F. At point P, which represents the hydrocracking limit of the process of FIG. 4, it is noted that the 10 percent distillation temperature dropped almost 40F. and is in a region of a further very sharp drop upon passage over any additional catalyst.

The presence of a significant quantity of sulfur in the hydrocarbon in a hydrodesulfurization system acts as an inhibitor against appreciable hydrocracking in the hydrodesulfurization system. Hydrocracking is indicated by a very rapid drop in the 10 percent distillation point. Hydrocracking, which is the severance of carbon-carbon bonds, as contrasted to sulfur removal by severance of carbonsulfur bonds, is highly undesirable in the present invention because it represents a needless consumption of hydrogen in the preparation in the feed for an FCC process wherein hydrogen is not added and cracking occurs without consuming hydrogen. Therefore, the consumption of hydrogen to accomplish cracking is an economic waste in the preparation of a feed for an FCC process. Furthermore, gasoline range components produced by hydrocracking have a lower octane number due to the saturation of olefins caused by the presence of hydrogen. Olefins are known gasoline ocatane-improvers. On the other hand, gasoline produced in a zeolitic FCC riser in the absence of added hydrogen is rich in olefins and these olefins con tribute to a high octane number gasoline product. One means of inhibiting hydrocracking is to use recycle hydrogen as a coolant or quench to be injected at various positions in the hydrodesulfurization reactor to accomplish cooling. It is advantageous to employ a single hydrodesulfurization reactor chamber, with one or a plurality of separated beds, with the total feed hydrocarbon blend introduced at the reactor inlet and with the total hydrogen either added at the reactor inlet or divided and added both to the reactor inlet and also at several positions along the length thereof. preferably between catalyst beds, to provide a quenching effect.

A further reason for avoiding extensive hydrocracking in the hydrodesulfurization process is that the hydrodesulfurization operation of the present process is designed to accomplish a synergistic effect in sulfur removal between the light (represented by the 10 percent distillation point of FIG. 4) components and the heavy (represented by the 90 percent distillation point of FIG. 4) components in the feed blend moving through the hydrodesulfurization reactor. As explained above, this synergistic effect in the sulfur removal reaction between high reaction rate components and low reaction rate components can be translated into a savings in catalyst required per barrel of feed and also a savings in hydrogen consumed per barrel of feed due to the smaller catalyst bed. If the feed traveling through the reactor is permitted to remain in the reactor sufficiently long to permit extensive hydrocracking at the reactor outlet region, this is evidence that the catalyst bed is excessively great in length in relation to its sulfur-removing function and therefore the catalyst savings that could be achieved due to the synergistic effect of this invention if the reaction were limited essentially to sulfur removal is rendered innocuous, to say nothing of resulting wasteful hydrogen consumption.

Since it is an objective of the present invention to remove as much sulfur as possible from the 90 percent distillation point components of the feed, as evidenced by a drop in the 90 percent distillation point of the material traveling through the reactor, sufficient catalyst should be present to permit as great a drop as possible in the 90 percent distillation point. However, in order not to exceed the range of the synergistic effect advantage of the present invention, the amount of catalyst present, and therefore the depth of the reactor bed, should be limited to a range such that the sulfur-level does not become sufficiently low that the inhibitory power of sulfur against extensive hydrocracking is avoided. This objective is realized by a limitation in the drop of the 10 percent distillation point of the material traveling through the reactor. We have found that the present invention is best performed to accomplish re duction in the 90 percent distillation point (representing the most desirable sulfur removal) without encountering an excessive reduction in the 10 percent distillation point (representing excessive hydrocracking) by employing a catalyst bed of sufficient depth so that at least percent of the sulfur is removed from the hydrocarbon feed while permitting the temperature difference between the percent and the 10 percent distillation points to increase but not to increase by an amount exceeding 10, 15, or 20F. It is important that at least 80 percent of the sulfur be removed, because line M of FIG. 4 shows that in the removal of only 50 or 60 percent of the total sulfur in the feed, very little effect upon the 90 percent distillation point is apparent, while line L shows most of the initial sulfur removal was from the lighter material.

Referring again to FIG. 4, line N illustrates the increase in temperature differential between the 10 percent distillation point and the 90 percent distillation point of the feed as it travelsthrough the reactor. At position 0 on line N, 80 percent of the total sulfur in the feed has been removed, satisfying the requirements of this invention. At the same time, the 90 percent distillation point has dropped at least 10F, indicating a significant amount of the sulfur removal was from the most refractory sulfur, which would be likely to be present in the coke formation of a subsequent cracking unit. At position 0, the temperature differential between the l percent point and the 90 percent has not yet increased by 20F., also satisfying the requirements of this invention. It is not until position P on line N has been reached that the increase in temperature differential between the percent and 90 percent distillation points just reaches 20F. It is noted that line N begins to move abruptly upwardly in an exponential manner once the 20F. increase is achieved. It is at this point that the sulfur level becomes so low that the amount of sulfur in the feed is inadequate to effectively inhibit hydrocracking so that hydrocracking begins to occur at an excessive and undesirable rate. As already stated, hydrocracking at an excessive and undesirable rate is to be avoided because it results in an economic waste of hydrogen and because it produces gasoline having a lower octane number than the gasoline that can be produced in a subsequent FCC riser operation in the substantial absence of added hydrogen. The reaction of the present invention is terminated at least at the catalyst depth (reactor length) represented by point P. More particularly, the catalyst depth should be in the region represented between the points 0 and P, i.e. the bed depth is great enough to accomplish at least 80 percent sulfur removal, with a drop in the 90 percent distillation point of at least 10F, with an increase in temperature differential between the 10 percent and 90 percent distillation points but without the temperature differential increase exceeding 20F. and without the 10 percent point dropping more than 40 or 50F. When the bed depth is between the points indicated by O and P of FIG. 4-, the catalyst savings due to the synergistic sulfur removal effect of the present invention is realized. A savings in reaction time and in prevention of excessive hydrocracking is also realized. If the catalyst bed depth exceeds that represented by point P, the total sulfur removal is greater but the catalyst economy feature of this invention becomes valueless because insufficient sulfur remains in the stream for effective synergism in sulfur removal,as evidenced by the fact that the additional catalyst contributes relatively more heavily to hydrocracking reactions rather than to hydrodesulfurization reactions. The onset of excessive hydrocracking therefore indicates the synergistic reaction effect of this invention is essentially terminated. Therefore, the catalyst economy advantage of the present invention is a transient advantage which becomes useless when the increase temperature differential between the 10 and 90 percent distillation points exceeds 20F Preferably, the increase in the temperature differential can be below F. It is noted that further widening of the boiling range of the feed of FIG. 4 by addition of a furnace oil would permit a higher degree of desulfurization of the gas oil than that indicated by point P without excessive hydrocracking.

It has already been noted that the presence of sulfur in the feed material must be sufficiently great to inhibit hydrocracking. While FIG. 4 indicates that the feed sulfur content is 2.74 weight percent, FIG. 5 illustrates the hydrodesulfurization of a feed containing only 0.31 weight percent sulfur. FIG. 5 shows the variation in the 10, 30, 50, 70 and 90 percent distillation points (the average of which represents the volume average boiling point of a hydrocarbon stream) with increasing levels of desulfurization with a feed containing this low level of sulfur content. Referring to FIG. 5, it is seen that at 80 percent desulfurization of the feed the temperature differential between the 10 percent and the 90 percent distillation points has increased 25F, as compared to the feed, which is beyond the permissible 20 degree temperature differential at 80 percent desulfurization in accordance with this invention. FIG. 5 shows that the temperature differential had already reached 20F. when only 75 percent of the feed sulfur was removed. Therefore, the feed illustrated in FIG. 5 has too low a level of sulfur to be included within the present invention. The sulfur level of such a feed is so low that it cannot adequately inhibit hydrocracking with its attendant expense in hydrogen consumption while it accomplishes desulfurization. As noted earlier, it is desired to reserve cracking for the subsequent FCC unit. Furthermore, the level of sulfur in the feed of FIG. 5 is so low that the requirement for the synergistic sulfur removal effect of the present invention is not as important as with the feed illustrated in FIG. 4. Moreover, the low feed sulfur level shown in FIG. 5 indicates that the feed will not be a major source of sulfur dioxide contamination in a subsequent regeneration unit of a downstream FCC riser cracker.

FIG. 6 presents data to illustrate the importance to the hydrodesulfurization process of the present invention of avoiding a catalyst containing silica. The data shown in FIG. 6 were taken by passing a Kuwait gas oil having 2.93 weight percent sulfur, an ASTM 10 percent point of 689F. and an ASTM 90 percent point of 1,011F., downfiow over a bed of 1/16 inch nickelcobalt-molybdenum on alumina catalyst particles at a pressure of 1,000 psig, 2,000 SCF/B of to percent hydrogen, a Ll-ISV of 2.0, while scrubbing the recycle gas with NaCaOH. In the upper curve of FIG. 6, the alumina support is essentially silica-free while in the lower curve of FIG. 6 the catalyst is promoted with 0.5 weight percent silica. It is seen from FIG. 6 that at all temperatures, the promotion of the catalyst with silica results in a lower weight percent desulfurization of the feed oil. The data of FIG. 6 show the importance of employing a hydrodesulfurization catalyst having less than 0.5 weight percent silica and preferably of employing catalyst containing less than 0.25 weight percent silica or even 0.1 weight percent silica, or less.

The present invention is to be distinguished from prior art processes in which a cracking feed is hydrogenated or hydrodesulfurized in advance of a cracking operation in order to accomplish a hydrogen donation effect in the cracking operation. Hydrogen donation, is a direct transfer of hydrogen from certain partially or completely saturated ring compounds, such as aromatics or naphthenes, to other refractory compounds during cracking without the addition of free hydrogen in order to render the refractory compounds less refractory. It occurs during a cracking operation which permits sufficient residence time for such hydrogen donation to occur. Hydrogen donation has the overall effect of rendering the feed less refractory even though no free hydrogen is added to the cracking system. In such hydrogen transfer processes, hydrogen is added to easily hydrogenated aromatic or naphthenic compounds in a prehydrogenation stage and then during cracking the hydrogen is transferred directly to a more refractory, hydrogen deficient compound to render the more refractory compound more susceptible to cracking. However, as stated, such hydrogen donation requires sufficient residence time for its occurrence. The cracking operation of the present invention occurs with a highly active zeolite cracking catalyst at a residence time of less than five seconds, preferably less than 2 or 3 sec- 25 onds, and occurs with hydrocarbon feed and regenerated or fresh catalyst flowing concurrently upwardly through the reactor at about the same velocity, without permitting catalyst bed formation (whereby backmixing of hydrocarbon occurs) anywhere in the reaction flow path. Such a riser cracking process is described in US. Pat. No. 3,617,512, which is hereby incorporated by reference. In FIG. 3 of U.S. Pat. No. 3,617,512, chamber 2 could comprise a hydrodesulfurization reactor of this invention. The residence time in the cracking riser is preferably three seconds or less and can be one or two seconds or less. The top of the riser is capped and provided with lateral exit slots to insure immediate disengagement of reactants and catalyst at the riser exit, thereby preventing overcracking of gasoline after vapors and catalyst leave the riser. To illustrate the absence of hydrogen donation in a cracking riser of the present invention, a cracking riser test is illustrated in Table 13. As shown in Table 13, two tests were con-' ducted, one of which employed 100 percent cyclohexane (the saturated aromatic) as feed and the other employing a 2:1 mole ratio of cyclohexane to pentene-2, pentene-2 constituting the hydrogen-deficient compound. The cyclohexane-pentene-2 blend had an impurity of 0.16 weight percent isopentane.

TAB LE 13 2:1 Mole Ratio of Cyclohexane/ Pentene-2 with 0.16 100% wt ic, Feed Cyclohexane Impurity Operating Conditions Riser Temperature: F. 1000 Contact Time: Sec. l .2 Cat/Oil Ratio: wt/wt 8.0 Regen.Cat.Temp: F. l 1 15 Carbon on Catalyst: wt 0.45 Feed Temp: F. 80

Yields: wt FF Unconverted Feed 98.75 99.24 v lsopentane 0.04 0.14* Normal Pen tane 0.00 0.00 lsobutane 0.72 0.1 1 Propane 0.00 0.03 Acetylene 0.15 0.16 Hydrogen 0.34 0.32 TOTAL 100.00 100.00

Less iC yicld than was present as a feed impurity Comparing the two tests shown in Table 13, at the very low residence time of the riser cracking reaction it is seen that hydrogen transfer from the cyclohexane to the pentene-2 was so low that there was a net loss of hydrogen from the pentene-2 rather than a net gain in that the yield of the second test contained only 0.14 weight percent total pentanes, which is lower than the 0.16 weight percent isopentane impurity present in the feed. Therefore, no hydrogen donation occurred from the cyclohexane to the pentene-2. It is noted that the cyclohexane and the pentene-2 are both materials boiling within the gasoline boiling range. Materials boiling within the gasoline boiling range are much more refractory than materials boiling above the gasoline range. Due to this refractoriness, both tests illustrated in Table 13 showed that essentially no cracking occurred during the tests. This absence of cracking allows the data to illustrate quite pointedly that under the standard cracking conditions of this invention which are adapted for cracking material boiling above; the gasoline range down to the gasoline range with minimal overcracking of gasoline range material itself, no hydrogen transfer occurs. I

The zeolite riser crzickingconditions and system (known as FCCor fluid catalyticfcracking) of this invention do not employ added hydrogen and incorporate the cracking conditions disclosed in US. Pat. No. 3,617,512. The cracking temperature can be 900 to 1,100F., or more. The preferred temperature range is 950 to 1,050F. The reaction pressure can vary widely and can be, for example, 5 to 50 psig, or preferably 20 to 30 psig. The maximum residencetime is 5 -seconds, and for most charge stockswill be 0.5 to 2.5 seconds. A suitable weight ratio of catalyst to total oil charge is 4:1 to about 12:1 or even 25: 1. The velocity of catalyst and oil through the riser can be 25 to feet per second. There is substantially instantaneous vaporization of oil upon contact with the hot regenerated catalyst. Catalyst regeneration can occur at 1,240 or 1,250F. or more to reduce the level of carbon on the regenerated catalyst from the range of about 0.6 to 1.5 to about 0.05 to 0.3 percent by weight. Riser space velocity should not be below 35 and should preferably be above 100 and can be 400 or 500, or more, based on hydrocarbon feed and instantaneous catalyst inventory in the riser. The density at the riser inlet can be below 4 or 4.5 pounds per cubic foot. There is no catalyst bed formation anywhere in the zeolite catalyst reaction flow path once regenerated catalyst contacts hydrocarbon feed until disengagement between the two occurs and the cracking reaction is terminated.

A series of tests were performed to determine in various cracking systems the effect upon the ratio of FCC gasoline to total FCC conversion wherein the FCC feed boils above the gasoline range. Tests are presented to illustrate the effect upon this ratio of the use of a zeolite as campared to a nonzeolite-containing catalyst. The results of these tests showed that a zeolite-containing catalyst produced a considerably higher ratio of gasoline to conversion than a nonzeolite catalyst.

Additional tests are presented to illustrate the effect when employing a zeolite catalyst in riser cracking at a high velocity without permitting formation of a catalyst bed as compared to cracking systems wherein a catalyst bed is permitted to form with a zeolite catalyst. These tests show that the ratio of gasoline to conversion increases when a riser cracking system (non-dense bed) is employed with a zeolite catalyst as compared to a zeolite fluidized dense bed system.

Further tests were performed to illustrate a riser cracking system employing a zeolite catalyst wherein the total feed gas oil is in a nonhydrogenated condition as compared to a hydrogenated condition. These tests showed that the ratio of gasoline to conversion can be increased in a riser cracking system employing a zeolite catalyst without permitting formation of a catalyst bed anywhere in the reaction flow path by pretreating the total feed via hydrogenation when charging the hydrodesulfurization effluent boiling above the gasoline or furnace oil range to an FCC riser as compared to the same oil in a non-hydrodesulfurized condition.

Finally, tests were performed employing a riser cracking system with a zeolite catalyst without formation of a catalyst bed anywhere in the reaction flow path wherein the feed is hydrogenated to an extent that the temperature differential between the 10 percent distillation point and the percent distillation point

Claims (5)

1. A HYDRODESULFURIZATION PROCESS COMPRISING PASSING A RELATIVELY HIGH BOILING NON-ASPHALTIC PETROLEUM FEED OIL HAVING A VOLUME AVERAGE BOILING POINT ABOVE 750*F. TOGETHER WITH HYDROGEN DOWNFLOW THROUGH A FIXED BED OF CATALYST COMPRISING GROUP VI AND GROUP VIII METALS ON A NON-CRACKING ALUMINA SUPPORT, ADDING TO SAID BED AT A DOWNSTREAM POSITION WHICH IS AT LEAST 50 PERCENT THROUGH SAID BED A RELATIVELY LOW BOILING NON-ASPHALITIC PETROLEUM FEED OIL HAVING A VOLUME AVERAGE BOILING POINT BELOW 750*F. TO FORM A BLEND OF SAID HIGH AND LOW BOILING OILS, SAID POSITION OF ADDITION AND THE PROPORTION OF SAID LOW BOILING OIL RELATIVE TO SAID HIGH BOILING OIL BEING SUCH THAT SAID BLEND AT SAID POSITION OF ADDITION HAS A HIGHER SULFUR CONTENT THAN THE SULFUR CONTENT OF THE HIGH BOILING OIL ALONE AT SAID POSITION OF ADDITION AND SO THAT SAID BLEND IS DESULFURIZED IN SAID CATALYST BED DOWNSTREAM FROM SAID POSITION OF ADDITION TO PRODUCE AN EFFLUENT BLEND STREAM HAVING A LOWER SULFUR CONTENT THAN THE SULFUR COTENT OF THE HEAVY OIL ALONE AT SAID POSITION OF ADDITION.

2. In the process of claim 1, passing at least the high boiling oil portion of the effluent blend stream to a zeolite riser cracking process.

3. In the process of claim 1, separating the effluent blend stream into a fuel oil and a heavy oil, and passing the heavy oil to a zeolite cracking process.

4. The process of claim 1 wherein said relatively low boiling feed oil is furnace oil and said relatively high boiling feed oil is gas oil.

5. the process of claim 1 wherein the pressure is 800 to 1,200 psi.

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