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Publication numberUS3306845 A
Publication typeGrant
Publication dateFeb 28, 1967
Filing dateAug 4, 1964
Priority dateAug 4, 1964
Publication numberUS 3306845 A, US 3306845A, US-A-3306845, US3306845 A, US3306845A
InventorsPoll Harry F
Original AssigneeUnion Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Multistage hydrofining process
US 3306845 A
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Description  (OCR text may contain errors)

Feb. 28, 1967 H. FfPoLl.

MULTISTAGE HYDROFINING lPROCESS Filed Aug. 4, 1964 S/Jam 4free/Vey United States Patent O 3,306,845 MULTISTAGE HYDROFINING PROCESS Harry F. Poll, North Hollywood, Calif., assignor to Union Oil Company of California, Los Angeles, Calif., a corporation of California Filed Aug. 4, 1964, Ser. No. 387,417 17 Claims. (Cl. 208-254) This invention relates to a multistage catalytic hydrofining process for treating high-sulfur, high-nitrogen mineral oil fractions, and more particularly to a process for producing a substantially nitrogen-free naphtha, a moderately severely treated diesel and a less severely treated gas' oil. Briefly, the process comprises the following steps:

(l) Subjecting a nitrogen-containing raw gas oil feedy stock to catalytic hydrofining under relatively mild conditions;

(2) Fractionating the effluent from Step 1 to recover a'partially rened gas foil product, a lower boiling partially refined synthetic diesel fraction, and a still lower boiling partially refined synthetic naphtha fraction;

(3) Subjecting a nitrogen-containing raw diesel feed- `stock to catalytic hydrofining in a separate hydrofining product fraction from the eiiiuent from Step 5.

Many mineral oil fractions, such as petroleum and shale oil distillates, must be treated to remove sulfur, nitrogen, oxygen and other undesirable c-ontaminants, and to hydrogenate unsaturated components in order that resultant products meet commercial quality standards, or are otherwise suitable for subsequent catalytic processing. Al-

though, under suitable processing conditions, essentially all such contaminants can be removed, it is frequently uneconomical and unnecessary to fully refine all fractions of a crude oil. Ideally, each fraction should be treated in such manner as to effect the minimum quality improvement necessary, depending on the requirements of subsequent refining processes or ultima-te commercial product specifications. Single-stage hydrofining of a full-range feed is not practical where each of the treated product fractions, resulting from fractionation of the full-range effluent, require different degrees of refining. In singlestage treating, not only must some of the fractions be over-treated to assure that those fractions having more stringent quality requirements receive adequate treatment, but optimum processing conditions for each fraction cannot be attained.

Prefractionation of a wide-boiling-range hydrocarbon feedstock, followed by separate hydrofining of individual distillate fractions, does not fully over-come these disadvantages. Although prefractionation may permit processing of each distillate fraction under optimum conditions, overtreating or undertreating -of some of the resulting product fractions may still be a problem due to the formation of lower boiling components in the hydrofining process. Catalytic hydrofining of a contaminated feedstock results in a treated effluent of higher gravity and substantially wider boiling range, primarily due to the production of light `hydrocarbons resulting from the decomposition of organic sulfur, nitrogen, and oxygen compounds. These -synthetic light hydrocarbons must frequently be recompletely inoperable.

3,306,845 Patented Feb. 28, 1967 lCC moved from the treated product to meet flash point, initial boiling point or other specifications, yet they are often not sufficiently refined in the first treating stage to meet product specifications for that particular boiling range fraction, therefore requiring additional hydrofining treatment.

I have found that multistage hydrofining wherein the lighter, partially refined product fractions are further treated in admixture with untreated feed stocks, or other partially treated hydrocarbons, of similar boiling range, can be adapted to effectively overcome these inherent difficulties and achieve desired treatment of the various product fractions under optimum processing conditions. In one comprehensive aspect, my process comprises prefractionation of a crude oil, crude shale oil, or other Wideboiling-range hydrocarbon feed into raw naphtha, diesel and gas oil feed fractions; separate hydrofining of the distillate feed fractions under optimum conditions; removal of low-boiling fractions formed as a by-product of the hydrofining reactions; and secondary treatment of these low-boiling synthetic fractions in combination with a raw feed fraction of comparable boiling range. The wide-boiling feed is thus converted to a substantially nitr-ogen-free naphtha, a commercial diesel oil, and a gas oil of improved quality, each like-boiling fraction of the net treated product, thereby being refined to comparable sulfur and nitrogen levels. Although my process isy adapted to the treatment of any nitrogen-containing hydrocarbon feedstock, it is particularly advantageous in the treament of high nitrogen feedstocks, such as those having nitrogen contents above about 0.3 Weight percent.

The overall object is to upgrade high-nitrogen naphtha, diesel and gas oil fractions to treated products comparable in boiling range to the feed fractions by processing in a hydrofining complex providing maximum economy in hydrogen consumption, catalyst utilization and product yields. A more specific object is to remove sulfur, nitrogen, and other undesirable constituents from crude petroleum or shale oil fractions so as to yield a naphtha reformer feed stock essentially free of sulfur and nitrogen, and yield less completely refined diesel and gas oil products. Another object is to provide a multistage hydrofining process wherein several component feed fractions receive optimum hydrofining treatment, thereby minimizing overtreatment of the product fractions. Other objects will be apparent from the more detailed description which follows.

The extent to which sulfur, nitrogen and oxygen'compounds must be removed from a given feed depends on the subsequent catalytic processing steps to be employed, and the end use of the fraction. For example, the gasoline fractions of both petroleum and shale oils are typically low in octane value and must be reformed to improve engine performance. Mostcatalytic reforming processes are susceptible to sulfur, nitrogen and oxygen contained in the-feed, in that these contaminants effect a reduction in catalyst activity, and can even render such process On the other extreme, little or no hydrogen treatment of high boiling residuum fractions is required, as these materials are generally blended directly to fuel oil, visbroken for fuel oil blending, converted to asphalt, or coked to increase the yield of light distillates. The treatment required of middle distillate fractions is generallyy intermediate between the severe treatment required of gasoline, jet fuel and solvents on the one extreme, and the slight treatment required of high boiling residuum on the other. Stove oil and diesel distillate fractions generally require intermediate treatment to remove substantial amounts of sulfur, nitrogen and oxygen, and may require hydrogenation of unstable olefin, diolefin and acetylene-type hydrocarbons to improve burning characteristics, performance, color, pour point and storage stability. However, middle distillate fractions may require more severe treatment if they are to be subjected to subsequent catalytic processing such as catalytic hydrocracking.

The term hydroning, as employed herein, means the contacting of hydrocarbon feed stock with a suitable lsolid catalyst at elevated temperature and pressure in the presence of hydrogen, under conditions whereby there is no net production of hydrogen and little or no hydrocracking of hydrocarbon molecules. The net effect of hydroning is to bring Iabout a selective decomposition of organic sulfur, nitrogen and oxygen compounds and like contaminants, and to saturate olefin, diolen, and acetylene bonds with hydrogen. The organically bound sulfur, nitrogen and oxygen -atoms (herein termed heteroatoms) are replaced in the contaminant molecules with hydrogen, the hereteroatorns being converted to hydrogen sulfide, ammonia and water, respectively.

Usually the heteroatoms in a contaminant molecule Awill form a connecting linkage in a ring, chain or sidechain structure. Replacement of the heteroatom with hydrogen causes a cleavage of the molecule, resulting in an opening of the ring, or severing of the chain or side chain. Frequently, several heteroatoms will be contained in a single molecule, and when they are removed the original molecule will be broken into several fragments. The effect of removing the heteroatoms from the molecule is usually a reduction in molecular size, and accordingly, the formation of lower boiling fractions. Thus, the hydrofining of a contaminated feedstock almost always results in a treated product of wider boiling range and higher API gravity (lower density) than the corresponding feedstock. Although some higher boiling fractions may be formed by polymerization, or other mechanism, the boiling range increase is largely attributable to the formation of lower boiling fractions,

In the usual case, processing conditions will be controlled to accomplish only moderate treatment of higher boiling fractions. Under such conditions, a number of the molecules containing a heteroatom may have only one carbon-hereteroatom bond severed, thereby resulting in the formation of mercaptans, primary amines, alcohols and the like. Other contaminant molecules, containing a plurality of hereteroatorns may have only one heteroatom removed, thereby forming lighter molecules still containing one or more heteroatoms. Thus, the result of partial treatment of heavy stocks is that at least a portion of the lighter synthetic fractions formed do not meet the quality standards for the lower boiling fractions and must be subjected to subsequent hydroning treatment. My hydr-ofining process accomplishes secondary treatment of these lower boiling synthetic fractions by combining them with untreated or partially treated raw feed fractions of similar boiling range for subsequent hydrofning.

The catalyst employed in my process may comprise any of the oxides and/or sulfides of the transitional metals, and especially an loxide or sulde of a Group VIII metal (particularly iron, cobalt or nickel) mixed with an oxide or sulfide of a group VI-B metal (preferably molybdenum or tungsten). Such catalysts may be employed in undiluted form, but preferably are distended and supported on an adsorbent carrier in proportions ranging betwen about 2% and about 25% by weight. Suitable carriers include in general the diicultly reducible inorganic oxides, eg., alumina, silica, zirconia, titania, clays such as bauxite, bentonite, etc. The carrier should display little or no cracking activity, and hence highly acidic carriers are to be avoided. Preferably, the catalyst base should have a Cat-A activity index below about 20. The preferred carrier is activated alumina, and especially activated alumina containing about 3-15 by weight of coprecipitated silica gel.

The preferred hydroning catalyst consists of sulfded composites of cobalt oxide plus molybdenum oxide supported on silica-stabilized alumina. Compositions originally containing between about 2% and 8% of CoO 4% and 20% ofMoO3, 3% and 15% of SiO2, and the balance 4 Al203, and wherein the mole-ratio of COO/M003 is between about 0.2 and 4 are especially preferred.

The naphtha, diesel and gas oil hydr-oning zones may each consist of a single hydroning reactor arranged as described herein, or a large number of reactors may be employed in a single zone. The catalyst may be disosed in a fixed stationary bed, or any of the various moving or fluidized bed techniques may be utilized. The individual reactors can be operated under either vapor phase or liquid-vapor mixed phase conditions. In any case, hydrogen and liquid hydrocarbon feedstocks are preheated to an appropriate inlet temperature of between about 450 F. and about 800 F., either separately or in combination. The preheated hydrogen, usually a mixture of recycle and make-up hydrogen, and hydrocarbon feedstock are then contacted with the bed of hydroning catalyst. The reactions occurring in the hydroning zone are largely exoyithermic, giving rise to an increase in temperature, the increase depending on the degree of contamination of the feed, the completeness of treatment and the recycle gas ratio. Conditions are generally controlled tov maintain maximum temperatures below about 875 F., and preferably below about 800 F. Where the increase is greater than about 200 F., it may be desirable to provide intercooling, either by means of exchange of the reactant with a coolant, or by addition of a cold hydrogen quench gas to the system.

The feed rate, temperature, pressure, hydrogen gas purity, hydrogen gas rate and space velocity can all be controlled to yield the desired degree of refining. The reactor effluent, consisting of unreacted hydrogen, hydrocarbon gases, normally liquid hydrocarbons, hydrogen sulde, ammonia and water, is partially condensed by cooling, usually at least a portion of the heat being interchanged with the feed. The resulting gas phase may be recycled to the reactor, a portion being withdrawn as a purge gas to prevent accumulation of non-condensible gases which dilute the hydrogen. Wa-ter may be added to the condensing effluent for removal of hydrogen sulfide and ammonia, and subsequently withdrawn as a separate aqueous phase. The condensed hydrocarbon effluent is then stripped to remove light gases and residual hydrogen sulfide and ammonia.

The details of my multistage hydroning process can be more readily comprehended by reference to the accompanying drawing which is a flow-sheet illustrating one specific embodiment thereof. Auxiliary equipment, such as pumps, heat exchangers, vessels, heaters, instrumentation, etc. is of conventional design and deleted for clarity. Similarly, the individual hydroning steps are illustrated in block fashion, since any appropriate hydroning pro-cess may be employed. The flow sheet and description thereof is illustrative of only one operable embodiment, and is not meant to exclude other modifications.

Referring to the drawing, a crude petroleum oil, crude shale oil, or other wide-boiling liquid hydrocarbon feedstock, is fractionated in atmospheric fractionator 2 to prepare distillate feedstocks of narrower boiling range. The wide-boiling range feed enters fractionator 2 through line 1, and in this embodiment, a light naphtha is produced via line 3 as an overhead product. Although the light naphtha usually consists of C5 and lighter hydrocarbons boiling below about F., heavier hydrocarbons boiling up to about 230 F., or higher, can be included. A raw heavy naphtha distillate and a raw diesel distillate are produced as side cuts through lines 4 and 5, respectively. The heavy naphtha will usually have an initial boiling point between about F. and about F., and a final boiling point between about 350 F. and about 450 F. The heavy naph-tha and diesel distillates may be contiguous fractions, or an intermediate boiling fraction may be produced. Where the diesel and heavy naphtha are contiguous, the diesel will have an initial boiling point between about 350 F. and about 4501 F., and normally will have a final boiling point between about 600 F. and about 675 F. An atmospheric fractionator bottoms is withdrawn from fractionator 2, and fed, via line 6, to vacuum fractionator 7.

Vacuum fractionator 7 is a conventional vacuum` flash separator operated at reduced pressure to separa-te a raw gas oil distillate from a reduced residuum bottoms product. The gas oil distillate is produced overhead through line 8, and the reduced residuum is withdrawn from the bottom of the fractionator through line 9. The gas oil distillate usually has an initial boiling point between about 600 F. and about 675 F. and a final boiling point between about 950 F. and about 1,050 F. Vacuum fractionator 7 is usually operated between about 25 and about 5 mm., and preferably between about 20 and about mm. of Hg absolute pressure. If the distillate feed stocks are of suitable boiling range, both the atmospheric and vacuum fractionation steps may be eliminated and the feed stocks fed directly to the appropriate hydrofiner.

Raw gas oil distillate is fed through line 8 to gas oil hydrofiner 50 for mild catalytic hydrofining to reduce the sulfur and nitrogen content and partially saturate the unsaturated hydrocarbon bonds. A high-nitrogen gas oil may contain between about 10,000 p.p.m. and about 30,000 p.p.m. nitrogen. Full refining of the gas oil fraction is unnecessary and undesired. The gas oil nitrogen content is typically reduced to between about 1/5 and about 1A0 of the feed value in this hydrofining step, thereby typically yielding a product containing between about 2.00 and 6,000 p.p.m. nitrogen, although processing conditions can be varied to effect more or less nitrogen removal. Gas, primarily hydrogen, separated from the treated eiuent, is recycled to the reactor inlet via line 51, and make-up hydrogen is supplied via line 52. Purge gas is withdrawn via line 53. The treated liquid eiuent is yproduced through line 55 to stripper 56, the Cgand lighter constituents being removed overhead through line 54. A C4+ treated gas oil efliuent is withdrawn from treated gas oil stripper 56 and fed to treated gas oil fractionator 58 through line 57. Treated gas oil fractionator 58 is operated -to produce a partially treated synthetic naphtha overhead, a partially treated synthetic diesel fraction as a side cut, and a gas oil product fraction is withdrawn as bottoms through line 60. The treated gas oil product normally will have a boiling range similar to that of the feed to hydroner 50. Relatively sharp fractionation of each of the synthetic fractions is nceessary to prevent heavy ends entering the higher severity hydrofiners.

The partially refined synthetic hydrocarbons boiling in the diesel boiling range, formed on hydrofining the gas oil feed fraction, are withdrawn from fractionator 58 through line 61 and combined with the raw diesel distillate in line 5. The combined diesel fraction is fed to the inlet of diesel hydroner 30. Aternatively, where the synthetic diesel fraction requires less hydrofining than the raw diesel distillate, the synthetic fraction can be fed to an intermediate hydrofining reaction stage by clos-ing valve 63 and opening valve 64, the synthetic diesel then flowing through line 62 to a downstream section of the hydrofiner. Recycle hydrogen iiow is maintained via line 31 and make-up hydrogen is supplied via line 32. Purge -gas is withdrawn through line 33l and a treated liquid eiuent is withdrawn through line 35 for subsequent stripping in treated diesel stripper 36. The propane and lighter constituents of the treated diesel efliuent are produced overhead via line 34 and a C4+ diesel effluent is Withdrawn from the bottom of the stripper through line 37. The lolwer boiling naphtha fraction of the C44- diesel effluent is removed in diesel fractionator 38, thereby y-ielding a treated diesel bottoms product produced through line 40, the diesel product normally having a boiling range similar to that of the combined diesel feed to hydrofiner 30. The diesel fraction of a high-nitrogen crude oil will normally contain between about 1,000 and about 20,000 p.p.m. nitrogen. AProduct nitrogen is normally reduced to between about 1760 and 1,4200 of the feed val-ue.

The partially treated, synthetic naphtha boiling range materials produced in the gas oil and diesel hydrofiners are conveyed, via lines 59 and 39, respectively, to line 4, where they are admixed with the raw naphtha feed fraction. Combined naphtha is fed to naphtha hyd'rofiner 10 for severe hydrofining to remove substantially all of the organic sulfur, nitrogen and oxygen, and to saturate substantially all of the olefin, d-iolen and acetylene bonds. Raw naphtha distillate nitrogen contents can be as high as 10,000 p.p.m. Typically, the treated naphtha product will have less than 1100 p.p.m. nitrogen, and if hydrofined for subsequent reformin-g, less than 5 p.p.m. nitrogen, and preferably less than 1.0 p.p.m. Under proper conditions it is possible to completely remove any last traces of nitrogen contamination. Where the synthetic naphtha requires less hydrofining than the raw feed naphtha, the combined synthetic naphthas in line 59 can be fed to an intermediate hydrofining stage by closing valve 19 and opening valve 20, the synthetic naphtha then flowing through line 1S to a downstream section of the hydroner. Hydrogen -is recycled through line 11 and make-up hydrogen supplied through line 12. P urge gas is withdrawn through line 13. The treated naphtha effluent is withdrawn through line 15 and fed to naphtha stripper 1'6 for removal of propane and lighter constituents as an overhead product, the gases being produced through line 14. A C4| treated naphtha product is withdrawn from the bottom of naphtha stripper 16 via line 17. The C4 treated naphtha may be fractionated to yield a light treated naphtha and a heavy treated naphtha, if desired, by the inclusion of an additional fractionation step, not shown.

The various purge .gases and stripper overhead gases may be directed to tail gas for subsequent treatment and disposal as fuel, as illustrated, 'or subjected to' any number of other process steps without affecting the critical features of my process. The various treated liquid products may also be further processed, blended or fractionated into additional distillate fractions without affecting the scope of the invention.

The following example is cited to illustrate the quality improvement obtainable on catalytically hydroiining shale oil distillates according to the method of this invention. Since this example is illustrative of only one embodiment of my invention, it is-not to be construed as limiting the scope thereof.

Example `In this example, a crude Colorado shale oil, recovered by combustive retorting and subsequently stabilized, is fractionated and hydrofined substantially as illustrated in the drawing. Characteristic properties of the stabilized crude shale oil are set forth in Table I.

TABLE I.-CRUDE SHALE OIL PROPERTIES` Gravity, API 20 Basic nitrogen, wt. percent 0.95 Total nitrogen, wt. percent 1.90 Total sulfur, wt. percent 0.75 ASTM Distillation (D-1160) i 180 50% 6-90 ep 1,050 Percent Rec 92.5 Percent Res 7.5

Approximately 30,000 b.p.s.d. of stabilized crude shale oil is fed to the atmospheric fractionator, operating at about 30 p.s.i.g. A virgin C4-C5 light distillate is produced overhead from the atmospheric fractionator at a rate of about 1,150 b.p.s.d. This distillate fraction is not hydrolined as it is not a desirable reformer feedstock,

-and may be more effectively des-ulfurized by other processing techniques. A Cgi-380 F. naphtha distillate and a 380 Fir-625 F. diesel fraction are withdrawn as side cuts from the atmospheric fractionator. The atmospheric fractionator bottoms are subjected to vacuum fiash separation to yield a gas oil fraction boiling between about 625 F. and about 1,000 F., and a heavy residuum boiling above about 1,000 F. The heavy residuum is produced at a rate of 5,750 lb.p.s.d. without further treatment.

The ra'w naphtha, diesel and gas oil distillate fractions are hydrofined in separate reaction systems, with the light hydrocarbons formed on hydrofining the heavier stocks being further treated with the raw distillate of comparable boiling range. The catalyst employed in each reaction system is a presulfided cobalt molybd-ate, pelleted catalyst comprising (before sulfiding) about 4% by weight of cobalt oxide and about 15% by weight molybdenum oxide supported on a .silicon dioxide, 95% alumina coprecipitated carrier. Target nitrogen contents are about 1 'p.p.m. for the naphtha, about 300 p.p.m. for the diesel, and about 2,000 p.p.m. for the gas oil. Illustrative processing conditions to achieve these product nitrogen contents are summarized in Table Il.

1 Gas rates based on raw distillate feeds only. 2 Barrels of Fresh (Raw) Feed.

Feed characteristicspand flow rates to the various hydrofining zones are as follows:

TABLE IIL-SUMMARY OF HYDROFINER FEED RATESv AND PROPERTIES Boiling Feed Total Range, Rate, Nitrogen, F. b.p.s.d. p.p.m.

Naphtha Hydrofiner:

Fresh Feed C6-380 4, 500 6, 300 Synthetic Feed:

From Diesel Hydrofiner (J4-380 3, 560 40 From Gas Oil Hydroner C4-380 2, 325 123 Combined Naphtha Feed. C4-380 10, 385 2, 870 Diesel Hydrefiner:

Fresh Feedr-; S80-625 7, 200 14, 000 Synthetic Feed, From Ga Oil Hydroflner 380-625 4, 780 1, 290 CombinedDiesel Feed; S80-625 11, 980 9, 000 Gas Oil Hydroner: Fresh Feed.. 625-1, 000 11,400 20, 100

The final product characteristic-s and yields are summarized in Table IV.

TABLE IVr-SUMMA'RY OF PRODUCT YIELDS A-ND PROPERTIES Boiling Yield, Total Nitro- Range, F. b.p.s.d. gen, p.p.m.

Naphtha C4-380 10, 550 0.8 Diesel 380-625 8, 720 137 Gas Oil 625-1, 000 4, 640 1, 990

The foregoing example may be modified by employing different catalysts, by adjusting the reaction conditions to achieve different degrees of refining treatment, by fractionating the' feed and products into distillate fractions of different boiling ranges, by producing a portion of the semi-refined products without secondary hydrogen treatment, or' otherwise as may be obvious to' those skilled in the art, without departing from the scope and spirit of my invention as defined by the following claims.

I claim: 1. A method of refining nitrogen-containing naphtha, diesel and gas oil feed fractions which require different degrees of refining comprising:

catalytically hydrof'ining a raw gas oil feed in a gas oil hydroner operated under relatively mild hydrofining conditions to yield a gas oil effluent;

fractionating said gas oil effluent to recover a partially refined first synthetic naphtha fraction, a partially refined synthetic diesel fraction and a gas -oil fraction, and withdrawing said gas oil fraction as a treated Vgas -oil product of reduced nitrogen content;

catalytically hydroning a raw diesel feed in admixture with said partially refined synthetic diesel fraction in a separate diesel hydrofiner operated under hydrofining conditions relatively more severe than employed in said gas oil hydrolining to yield a diesel efiiuent;

fractionating said diesel eflient to recover a second partially refined synthetic naphtha fraction and a diesel efiiuent fraction, and withdrawing said diesel effluent fraction as a treated diesel product -of reduced nitrogen content;

catalytically hydrofining a raw naphtha feed in admixture with said first and said second synthetic naphtha fractions in a separate naphtha hydrofiner operated under relatively more severe hydrofining conditions than employed in said diesel hydrofining to yield a naphtha effluent; and

recovering a treated naphtha product yof reduced nitrogen content from said naphtha effluent.

2. The method of claim 1 wherein said naphtha, diesel and gas oil feed fractions are obtained from a crude shale oil.

3. The method of claim 1 wherein said hyd-rofining' zones contain cobalt molybdate catalyst and wherein said feed fractions are contacted with said catalyst in the presence of hydrogen at temperatures between about 450 F. and about 875 F.

4. The method of claim 1 wherein at least one of said feed fractions is partially hydr-ofined prior to admixture with said synthetic fraction, the admixed fractions then being subjected to secondary hydroning.

5. The method of claim 1 `wherein said gas oil hydrofining conditions are controlled to reduce the nitrogen content of said treated gas oil product to between about 1/5 and `about 1/40 of the nitrogen content of said raw gas oil feed.

6. The method of claim 1 wherein said diesel hydro fining conditions are controlled to reduce the nitrogen content of said treated diesel product to 'between about 1/60 and about 1200 of the nitrogen content of said raw diesel feed.

7. The method of claim 1 wherein said naphtha hydrofining conditions are controlled to reduce the nitrogen content of said treated naphtha product to less than about 5 p.p.m.

8. A process for refining a nitrogen-containing crude oil comprising: l

fractionating said crude oil to recover a raw naphtha feed fraction, a raw diesel feed fraction and a raw gas oil feed fraction;

catalytically hydrofining said raw gas oil feed fraction in a gas oil hydrofiner operated under relatively mild hydrofining conditions to yield a gas oil e'luent of increased boiling range;

fraetionating said gas oil effluent to recover a partially refined first synthetic naphtha fraction, a partially refined synthetic diesel fraction and a gas oil efliuent fraction substantially comparable in boiling range to said raw gas oil feed fraction, and withdrawing said gas oil efiiuent fraction as a treated gas oil product of reduced nitrogen content;

catalytically hydroiining said raw diesel feed fraction in admixture with sai-d partially refined synthetic diesel fraction in a separate diesel hydroner operated under hydroning conditions relatively more severe than employed in said gas oil hydrolining to yield a diesel effluent of increased boiling range;

fractionating said diesel eluent to recover a partially treated second synthetic naphtha fraction and a diesel eluent fraction substantially comparable in boiling range to said raw diesel feed fraction, and withdrawing said diesel eiuent fraction as a treated diesel product of reduced nitrogen content; catalytically hydroning said raw naphtha feed -fraction in admixture with said first and said second synthetic naphtha fractions in a separate naphtha hydrofiner operated under relatively more severe hydroning conditions than employed in said diesel hydroning t-o yield a naphtha eluent; and

vrecovering a treated naphtha product of reduced nitro- -gen content from said naphtha efliuent.

9. The process of claim 8 wherein said raw naphtha feed fraction is primarily in the C6-380" F. boiling range, said raw diesel feed fraction boils between about 380 F. and about 625 F. and said -raw gas oil feed fraction boils between about 625 F. and about l,000 F.

10. The process of claim 8 wherein said crude oil feed stock is a crude shale oil.

11. The process of -claim 8 wherein said gas oil hydron'er contains a cobalt molybdate catalyst maintained at a temperature of between about 450 F. and about 875 F.

12. The process of claim 8 wherein said diesel hydroner contains a cobalt molybdate catalyst maintained at between about 450 F. and about 875 F.

13. The process of claim 8 wherein said naphtha hydroner contains a cobalt molybdate catalyst maintained at between about 450 F. yand about 875 F.

14. The process of claiml 8 wherein at least one of said hydr-oner 4feed fractions is partially hydrofined prior to admixture with said synthetic fraction, the admixed fractions then being subjected to secondary hydrolining.

15. The process of claim 8 wherein said gas oil hydroning conditions are controlled to reduce the nit-rogen content of said treated gas oil product to between about 1K5 and about it() of the nitrogen content of said raw gas oil lfeed fraction.

UNITED STATES PATENTS 2,587,987 3/1952 Franklin 208-210 2,878,179 3/1959' Henning 208-210 2,901,417 8/1959 Cook et al. 208-210 3,077,448 2/ 1963 Kardash et al 208-210 DELBERT E. GANTZ, Primary Examiner.

S. P. JONES, Assistant Examiner.

Patent Citations
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Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3531398 *May 3, 1968Sep 29, 1970Exxon Research Engineering CoHydrodesulfurization of heavy petroleum distillates
US3617525 *Apr 3, 1969Nov 2, 1971Exxon Research Engineering CoResiduum hydrodesulfurization
US3617526 *Sep 5, 1969Nov 2, 1971Texaco IncHydrodesulfurization of a vacuum gas oil and vacuum residuum
US3619417 *Aug 29, 1969Nov 9, 1971Chevron ResSplit feed hydrodenitrification
US3902991 *Apr 27, 1973Sep 2, 1975Chevron ResHydrodesulfurization process for the production of low-sulfur hydrocarbon mixture
US4022683 *Dec 22, 1975May 10, 1977Gulf Research & Development CompanyHydrodenitrogenation of shale oil using two catalysts in parallel reactors
US4133745 *Jun 5, 1978Jan 9, 1979Atlantic Richfield CompanyProcessing shale oil cuts by hydrotreating and removal of arsenic and/or selenium
US5290429 *Nov 25, 1992Mar 1, 1994Union Oil Company Of CaliforniaCatalytic aromatic saturation in the presence of halide
US6793804 *Nov 7, 2001Sep 21, 2004Uop LlcEmploying two denitrification and desulfurization stages with intermediate high pressure stripping treatment then acid gas scrubbing
US7276151Sep 10, 1999Oct 2, 2007Jgc CorporationGas turbine fuel oil and production method thereof and power generation method
DE3235127A1 *Sep 23, 1982Apr 14, 1983Inst Francais Du PetroleVerfahren zur herstellung von benzin durch veredelung von kohlenwasserstoff-oelen
EP1130080A1 *Sep 10, 1999Sep 5, 2001JGC CorporationGas turbine fuel oil and production method thereof and power generation method
WO2012085406A1 *Dec 16, 2011Jun 28, 2012AxensMethod for converting hydrocarbon feedstock comprising a shale oil by hydroconversion in an ebullating bed, fractionation by atmospheric distillation and liquid/liquid extraction of the heavy fraction
WO2012085407A1 *Dec 16, 2011Jun 28, 2012AxensMethod for converting hydrocarbon feedstock comprising a shale oil by hydroconversion in an ebullating bed, fractionation by atmospheric distillation and hydrocracking
WO2012085408A1 *Dec 16, 2011Jun 28, 2012AxensMethod for converting hydrocarbon feedstock comprising a shale oil by decontamination, hydroconversion in an ebullating bed, and fractionation by atmospheric distillation
Classifications
U.S. Classification208/254.00H, 208/217, 208/210
International ClassificationC10G65/00
Cooperative ClassificationC10G65/00
European ClassificationC10G65/00