US3175966A

US3175966A - Treatment of a crude hydrocarbon oil in several stages to produce refined lower boiling products

Info

Publication number: US3175966A
Application number: US225450A
Authority: US
Inventors: Warren E Burch
Original assignee: Cities Service Research and Development Co
Current assignee: Cities Service Research and Development Co
Priority date: 1962-09-24
Filing date: 1962-09-24
Publication date: 1965-03-30
Anticipated expiration: 1982-03-30

Description

March 30, 1965 w. E. BURCH 3,175,956

IL IN SEVERAL STAGES TO PRODUCE REFINED LOWER BOILING PRODUCTS TREATMENT OF A CRUDE HYDROCARBON O Filed Sept. 24, 1962 ATTO R N EY ,casional treatment for sulfur removal.

3,l'75,966 TREATMENT F A CRUDE HYDRCARRN @H5 Hal SEVERAL STAGES T@ PRUDUQE REFNlED LQWER BQELING PRDUCTS Warren E. liuurch,` Westheld, NJ., assigner, by mesne assignments, to Cities Service Research and Development Company, a corporation of Delaware Filed Sept. 24, 1962, Ser. No. 225,450 tClaiins. (Cl. 2nd- 79) This invention relates to the treatment of hydrocarbon oil and more particularly to the treatment of hydrocarbon oil in the presence of hydrogen. The invention has particular application to the treatment of wide boiling range hydrocarbon oils such as crudes or synthetic crndes with hydrogen `in a variety of `hydrogen' treating steps to produce desired products.

In the refining of crude oil the usual procedure is to fractionate the crude oil into various distillate fractions. The bottoms material from such fractionation, which usually boils above 700 F., is often fed to a vacuum distillation unit in which further distillate material is removed. The residual material boiling above about 1000 F. is frequently sold as a low value fuel oil.

Thefdistillate fractionsrecovered from crude oil frequently require further upgrading before they are suit-` able as marketable products. For the very light ma-` terial boiling below about 200` F. it is generally not necessary to perform any additional refining except oc- The relatively heavier naphtha fractions boiling between about 200 and about 400 F. are frequently of too low an octane nurnber forsale as gasolene and require further treatment.`

Such materials are frequently treated by catalytic reforming to produce materialmore suitable for use as gasolene. Materialsboiling in the 400 to 650 F. range can sometimes be` marketed as furnace oil after treatment for sulfur removal and to improve stability. However, there `is frequently an excess of this material over the amount which can be disposed of as furnace oil, thus making it necessary to convert some of the material to gasolene boiling range material. Also, there is normally no appreciable market for heavy gas oils boiling between about 650 and about l000 F. While some portion of such heavy gas oils may be utilized in the production of lubricants, it is for the most part necessary to convert these heavy gas oils to lighter boiling range material for either the furnace oil market or the gasolene market. ln addition, considerably greater quantities of light naphtha are usually produced `than can be effectively used in blending motor fuel. The amount of light naphtha (boiling between about 65 and about 185 F.) which can be used inmotor fuel is limited by the vapor pressure requirements of motor fuel.

Conversion of distillate material in the 400 to l000 F. boiling range into lower boiling materials is normally accomplished by catalytic cracking processes. In these processes the material to be converted is contacted at high temperatures with cracking catalyst to give volumetric yields of saleable lower boiling materials on the order of 90 to 95 percent based on feed. The remaining feed material isconvertedto light gases or colte, either of` which represents a financial loss except to the extent that part of their fuel value can be reclaimed for use within the refinery. y i

`When residual material boiling above about 1.000o F. is in such `excess that it cannot be disposed of even as low priced fuel oil, it may be treated by various processes for conversion into lighter more useful materials.` Such processes include for instance visbreaking, thermal cracking, coliing and iluid coking.

The various combinations of refining steps such as y suisses Patented Mar. 30, 1965 those mentioned above as presently employed in the industry are wasteful of crude oil in that the total yield of saleable product generally representsonly about 85 to 95 volume percent of the original crude oil. This situation is aggravated in the case of crude oils containing significant amounts or residual material. Itis therefore an object of the present invention 'to provide an improved method of rening crude oils which gives considerably higher yields of saleable products per barrel `ofcrude oil for a given amount of processing. By use of the techniques of this invention it is feasible toV obtain yields of saleable products in excess of 100 volume percent based on crude oil feed. y

lt has now been found that crude oil may be treated p by a combination of refining processes, all of which include the use of hydrogen, to convert a large percentage, frequently in excess of 100 percent, of the virgin crude oil into useful product. In furtherance of this objective the crude oil may be fractionated into various fractions such as fuel gas, light naphtha, intermediate naphtha, kerosene, gas oil and residual fractions. The residual fraction is treated in a hydrogen conversion process to produce a residual fuel fraction and other `suitable fractions such as an intermediate naphtha fraction, a gas oil fraction, a light naplitha fraction and a normally gaseous fraction. The gas oil fractions may be subjected to a elatively milder hydrogen conversion process for production of a fuel oil fraction, an intermediate naphtha fraction, a light naphtha fraction and a normally gaseous fraction. The intermediate naphtha fractions may then be reformed to produce reformate suitable for blending into motor fuel as well as hydrogen and a normally gaseous hydrocrabon fraction. `The various normally gaseous hydrocarbon fractions are preferably passed to a gas recovery unit for recovery of C3 and C4 fractions thereof and the remaining fuel gas is preferably utilized as feed to a hydrogen production unit to provide the added hydrogen necessary for the hydrogen conversion steps mentioned above. The products obtained from the crude oil thus include mostly motor fuel and fuel oil components together with a relatively small amount of residual fuel oil which may be utilized within the refinery for fuel requirements.

For `a better understanding of the invention reference should be had to the accompanying drawing which is a somewhat diagrammatic illustration of a suitable arrangement of apparatus for carrying outa preferred embodiment of the present invention.

In the drawing feed oil enters through a conduit lll andpasses into a conventional crude distillation unit l2.`

The crude oil introduced as feed to the process through feedstoclrs mentioned above.

ln the embodiment of the invention shown the crude distillation unit l2 is a conventional atmospheric distillation unitfrorn which a kerosene product stream may be recovered through a conduit l5 and the residual frac-` tion therefrom, containing for instance that material boil-1` F. may be withdrawn through a ing above 700 conduit f1.3 and passed through a vacuum distillation unit la to provide a residual fraction which may be withdrawn through a conduit lo andpassed to a hydroconversion unit l?. It is also `possible to obtain the feed for 'the `hydroconversion unit 17 directly from an atmospheric crude distillat-ion unit by eliminating the vacuum distillation unit. The feed to the hydroconversion unit 17 thus represents the heavy residual portion of the 'original feed to the process, normally that portion boiling above about '1000o F. In the hydroconversion unit 17 the residual feed introduced through conduit 16 is contacted'in a hydroconversion reaction zone with added hydrogen introduced as through a conduit 18 in the presence of suitable hydrogenation catalyst under suitable hydrocracking'conditions to at least partially crack and hydrogenate such residual fraction to produce an improved product of lower boiling range suitable for -feed to a hydrocracking unit as described below.

The hydroconversion unit 17, like the other conversion and treating units to be described below, may comprise a single reaction vessel containing a single reaction zone and associated equipment such as separating drums, fractionation towers, pumps, etc., or may comprise two or more such reaction zones operated in parallel or in series. Selection of single or multi-stage reaction zones, auxiliary equipment, etc., is well within the ability of those skilled in the art. While the processing units described herein will generally be discussed as if they involved Vonly one reaction zone, it should be understood that such reactions might take place in multiple stage units lif desired.

While a wide variety of suitable operating conditions may be employed in the hydrogenation zone of the hydroconversion ,unit 17, it is preferred that hydrogen be Y introduced through the conduit 18 in suitable quantities such as between about 1,000 and about 20,000 standard cubic feet of hydrogen per barrel (s.c.f./b.) of feed to the unit, with hydrogen rates between 3,000-7,000 standard cubic feet per barrel being preferred. Such hydrogen may be in the form of relatively pure hydrogen or may be in the form of hydrogen Ycontaining gas such as recycle gas containing suitable quantities such as at least about 60 volume percent hydrogen. Other suitable sources of hydrogen may, ot' course, be used. Hydrogen partial pressure in the reaction zone of the hydroconversion unit 17 is maintained at suitable levels such as between about 500 and about 4,000 p.s.i.g. and temperatures are maintained within Asuitable limits such as betweenv about 650 and about 950 F., being preferred. Space velocities may vary considerably such as between about 0.1 and about volumes of feed per hour per volume of reactor capacity with space velocities between about 0.5 and about 3 volumes per hour per volume being preferred.

The catalyst used in the hydroconversion reaction zone of the hydroconversion unit 17 may be any suitable hydrogena'tion catalyst. For example, combinations of metals from groups 6 and 8 of the periodic table in various proportions supported on an alumina base may be used. Suitable catalysts for use on such bases include for instance cobalt, iron, molybdenum, tungsten, nickel, rhenium, platinum, palladium, etc., as well as combinations of the same. Such catalysts may be used in the oxide or sulfide yforms either alone or together with other suitable catalysts. Catalysts of the type mentioned above have no substantial cracking activity and may be present in the hydroconversion unit 17 in any suitable form but is vpreferably present in the form of an ebullated bed of catalyst of a particule size greater than about l@ inch. In an abullated bed reaction zone at least partially liquid feed and added hydrogen are flowed upwardly through the catalyst bed at a velocity suicient to expend the settled volume o'f the bed and catalyst is usually present in the reaction zone in concentrations of at least about 15 pounds of catalyst per cubic foot of reactor volume, pref-v i employ more conventional fixed bed catalyst. One of the major advantages of the ebullated bed operation is that catalyst may be added to or withdrawn from the bed without interruption of the hydroconversion process. Also, with suitable recycle the temperature differences within a hydroconversion zone employing an ebullated bed of catalyst may be maintained within about 25 F. For this purpose recycling liquid at a rate between about 3 and about 7 times the feed rate is normally recommend# ed. The cracking that occurs within reactor 17 is largely due to thermal effects. However, due to the presence of a high hydrogen partial pressure and the presence of hydrogenation catalyst within the reactor there is a suppression of the polymerization and the condensation -reactions which result in considerable coking in usual thermal cracking processes. Coke make isless than one tenth of one percent of the feed over the average operating period between turnarounds.

The hydroconversion unit 17 is normally operated so as to produce relatively lower boiling, at least partially hydrogenated products and a controlled amount of residual fuel product. The amount of residual fuel fraction left unconverted in the hydroconversion unit 17 should be normally only that amount which can be utilized as fuel in the refinery or for blending with lighter distillates to form heavy fuel oil. From the hydroconversion, unit 17 a high boiling fraction including residual material may be Withdrawn through a conduit 19 and passed through a vacuum distillation unit 21. From the vacuum distillation unit 21 residual fuel boiling above about l,000 F. may be withdrawn through a conduit 22 while lower boiling distillate material may be withdrawn through a conduit 23. Lower boiling distillate material from the hydroconversion unit 17 boiling between about 400 F. and about 700 F. and may pass through a conduit 24 to the conduit 23. Likewise, distillate material boiling between about 200 and about 400 F. may be recovered from the hydroconversion unit 17 through a conduit 30 for reforming as described below and a light naphtha fraction boiling between 65 and about 200 F. may be recovered from the hydroconversion unit 17 through a conduit 31 for use as motor fuel as described below. If desired, the vacuum distillation unit 21 may be eliminated and residual material withdrawn directly through the conduit 19 with lower boiling distillate being withdrawn through the

conduits

24 and 23. Normally gaseous material from the hydroconversion unit 17 normally boiling below about 65 F. may be withdrawn from the hydroconversion unit 17 through a conduit 29.

The distillate material from the hydroconversion unit 17 (preferably boiling between about 400 and about 700 F.) passes through the conduit 23 and a conduit 27 to a hydrocracking unit 25. Feed to the hydrocracking unit 26 might also include a gas oil fraction boiling for instance between about 400 and about 700 F. recovered from the original crude and withdrawn from the crude distillation unit 12 through conduit 27. Such feed may also include a gas oil fraction removed from the vacuum distillation unit 14 as through a conduit 28 and boiling between about 700 and about l,000 F. The hydrocracking unit 26 is intended to further hydrogenate and crack the feed thereto to produce more desirable products as described below.' Hydrogen for use in the hydrocracking unit 26 may be supplied from the conduit 18 through a conduit 32. Two-stage operation is frequently desirable in the hydrocracking unit 26 with the first stage being devoted to removal of nitrogen and improvement of the cracking characteristics of the feed to the unit and the second stage being devoted to cracking the feed with considerable conversion of relatively heavier gas oils to relatively lighter products such as gasolene and kerosene. As in the case of the hydroconversion zone 17, a different number of stages of operation in either parallel or series may be used if desired. In two stage operation of the hydrocracking unit 26, the pressure is maintained at a suitable level such asbetween about 500 and about 4,000 p.s.i.g. hydrogen partial pressure in'both stages, the temperature is maintained at a suitable level such as between about 650 and about 850 F. and bothstages are operated attspacevelo'cities between about 0.1 and about 5 `volumes of feed per hour per volume of reactor space with space velocities between about 0.5 and about 2 volumes per hour per volume being preferred. Catalysts for use in removing nitrogen and partially hydrogenating and cracking the feed in the first stage of the hydrocracking `unit 26 may include suitable hydrogenation catalysts having little if any cracking activity (such as catalyst of the type described above for use in the hydrol conversion unit 17) as well as hydrogenation catalyst having substantial cracking activity. Some thermal cracking may also take place. ,The catalyst for the second hydrocracking stage of the hydrocracking unit 26 may be any suitable hydrogenation catalyst having substantial `cracking activity although some thermal cracking may also take place in this portion of the unit. Suitable catalysts having substantial cracking activity include for instance combinations of metals from groups 6 and 8 of the periodic table in various lproportions supported on a base having an acid orA cracldng nature silica-alumina in various proportions has been found suitable as a base. Other bases having cracking properties, such as natural or artificial clays, iiuorided alumina, alumina-zirconia, etc., may however be used. Suitable metals for use on such bases include for instance cobalt, iron, molybdenum, tungsten, nickel, rhenium, platinum, palladium, etc., as well as combinations of the same. Such catalysts can be used in the oxide or sulfide forms either alone or together with other suitable catalysts and may be present in the reaction zone in any suitable form such as in the form of an ebullated bed or in the form of a slurry. For a better understanding of some ofthe various types of hydrocraclring processes which may be carried out in the hydrocracking unit 216, reference may be had to one or more of the co-pending applications of Roger P. VanDriesen or Roger P. Van Driesen and Warren E. Burch, filed June 13, 1962. For this purpose` the disclosures of such copending applications are to be considered as being incorporated in the present disclosure.

lProducts which may be recovered from the hydrocracking unit Z6 include normally gaseous product vboiling below about 65 F. which may be recovered through a conduit 33, light fuel oil product boiling between about 400 and about 650 F. may be withdrawn through a conduit 34 and a naphtha fraction boiling between about 200 and about 400 F. which may be recovered through a conduit 36 for reforming as described below. If desired, a portion of the light fuel oil recovered through conduit 34 may be blended with a portion of the residual fuel oil recovered through the conduit 22 to form a heavy fuel product which may be recovered through a conduit 25. A light naphtha fraction boiling between about 65 and about 200 F. may be recovered from the hydrocracking unit 26 as through a conduit 39 and combined with a similar fraction withdrawn from the crude distillation unit 12 through a conduit 4l for use in motor fuel product as described below. t

The naphtha fraction recovered from the hydrocracking unit 26 through conduit 36 may be combined with similar fractions recovered from the crude distillation unit l2 through a conduit 43 and from the hydroconversion unit 17 through conduit 30 and passed through a reforming unit 44. In the reforming unit 44 the intermediate naphtha feed thereto is treated in the presence of suitable reforming catalyst under suitable reforming conditions to produce a product of improved octane rating suitable for motor fuel. Any conventional reforming process may be utilized for this purpose and, as in other reforming processes, the principal reaction is dehydrogenation of napht'nenes to form aromatics. A limited amount of other reactions common to reforming reactions such as hydrogenation of other materials, hydroisomerization, etc., may take' place. A suitable reforming process for use in the reforming unit 44 might for instance include the use of a fluidized bed of suitable reforming catalyst such as platinum on an alumina base.

Such catalyst will normally be present in suitable particle sizes such as between about l/@ and about 1A inch. The reforming reaction zone may be operated under suitable reforming conditions such as temperatures between about 900 and about 980 F., space `velocitiesbetween about l and about 4 volumes of feed per hour per volume of reactor capacity, pressures between about 200 and about 700 p.s.i.g. and hydrogen rates: between about 1,000 and about 10,090 standard cubic feet of hydrogen per barrel of feed to the unit.

The product from the reforming unit 44 may include hydrogen which may conveniently be withdrawn through a conduit d6 and added to the hydrogen flowing through the conduit i3 for use in the various hydrogen consuming steps of the process, normally gaseous material boiling below about F. which may be withdrawnV through a Conduit 47 and passed through a gas recovery unit as described below and reformate product boiling generally in the range between about 200 and about 400 F. which may be withdrawn through a conduit 4d and blended with the light naphtha in the conduit 4l to form motor fuel product boiling between about 65 and about 400 F.

Gaseous material boiling below about 65 F. (C4 and lighter) is preferably recovered from the crude distillation unit i2 as through a conduit 56 and passed to a 1gas recovery unit 57 together with the gaseous material recovered from the hydroconversion unit i7 and hydrocracking unit 26 through conduits 29 and. 33 and similar material recovered `from the reforming unit 44 through the conduit 47. in the gas recovery unit 5'7 such normally gaseous material may be separated to form a C3 product Whichmay be withdrawnthrough a conduit 5d a C.; product which may be withdrawn through a conduit 59 and a dry fuel gas stream which may be withdrawn through a conduit 6l. The C3 product stream recovered through conduit 53 is normally marketable as LPG and the C4 stream recovered through the conduit 59 may be disposed of in a suitable manner such as by blending with material in the conduit 4l to form motor fuel or the C4 product or part thereof may be liquiiied for sale asa separate LPG product ormay be combined at least in part with the fuel gas flowing through the conduit by the use of a conduit'dtl. The fuel recovered from the gas recovery unit 57 through the conduit 6i may be passed through a conventional hydrogen production unit 62 for production of at least a portion of the hydrogen introduced through 4conduit l. The hydrogen production unit 62 may utilize any of the well known commercial processes for the production of hydrogen such as partial oxidation or steam reforming of light hydrocarbons. Hydrogen may `be recovered from the hydrogen production unit' 62 and recycled to the hydrogen consuming units of the process (hydrocracking units i7 and Z6 and hydrodesulfurization unit 5i) through the conduit i8.

in the operation of the process described above it is f {normallypossible by proper control of operating condihydrogen.

tions in the various units to obtain all the hydrogen necessary for the operation of the process from the crude oil feed to the process. the fact that all of the conversion operations utilized in the process are normally conducted in the` presenceof As is` apparent from a review of the above description of the process, the hydrogen for use in the hydrogen consuming steps of the process is obtained in part from the reforming unit 44 and in part `bytreatment of low boiling gases recovered from the hydrocracking and hydroconversion unitsfor production of additional hydrogen. Hydrogenproduction may therefore be increased by maintaining one or both of these units This may be done in spite of Y er n a g under relatively more severe cracking conditions to thereroperatedunder the following conditionsto yield the prodby form additional light gases. If this is desired, the uct fractions shown in Table II: yhydroconversion unit 17 is normally used for this puroperan-ng conditions. -pose since the residual fuel fraction 1s the least valuable H2 partial pressure 2,250 p sig portion of the crude oil feed and by operating the hydrO- 5 Total pressure 3,000 p sig' conversion unit 17 under relatively more severe crack- Temperature n .845 R ing conditions the amount of light gases produced may Space vdocity 1 0 v /hl/v, be increased and the amount of residual fuel produced Catalystconntration lbjft reactor, may be decreased without adversely effecting the recovery Hydrogen recycle rate 6,000 S.C.f/ b. of the more valuable intermediate products such as motor 10 Liquid recycle rate 7 v./v. of feed fuel and fuel oil. Hydrogen consumption 950 s.c.f./b.

Table II YIELDs FROM HYDROCONVERSION UNIT Rate Gravity Sulfur Boiling Fraction Conduit (b.p.d.) API) Content Range (wt. percent) F.)

C4 and Lighter 29 l 398, 000 to 105 Light Naphtha 3i 511 s4. o o. 1 105-240 Intermediate Naphth 1, 486 49. 0 0.2 240375 Light Gas oi1 24 4, 761 32. 5 0. 4 375-650 Residuum 19 9, 952 9. 7 1.6 above 650 1Lb./day.

By treating crude oil or other suitable feed in accordance with the present invention it is possible to pro duce a very desirable range of products in desired amounts. For instance, more conventional processes for complete refining of crude oil normally result in an excess of light naphtha over that amount which can be blended into motor fuel. While light naphtha in proper amounts is an entirely suitable and even desirable component of motor lfuel, excessive quantities of light naphtha have an adverse effect upon the vapor pressure of the resulting motor fuel. Processing of crude oil in accordance with the present invention allows relatively greater production of `the intermediate naphtha reformate fractions most desirable for motor fuel with the recoverey of only a desired amount of light naphtha product for blending with such reformate. The use of additional refining steps such as alkylation for production of motor ifuel components is generally rendered unnecessary when utilizing the present invention.

EXAMPLE In a typical application of .the present invention 45,000 barrels per day (b.p.d.) of Kuwait crude oil having a gravity of 31.8 API and a sulfur content of 2.52 weight percent is processed as described above and illustrated in `the drawing except that in this example the vacuum distillation unit 14 is not used and the residual fraction With-l drawn through conduit 13 is passed directly to the hydroconversion unit 17.

Various vfractions are recovered from the crude distillation unit 12 as shown in Table I below.

The residual fraction from the hydroconversion unit :17 is yfractionated in the vacuum distillation unit 21 to yield the products shown in Table III.

Table 111 YrELDs FROM VACUUM Drs'rrLLATroN UNIT Rate Gravity Sulfur Fraction Conduit (bpd.) API) (wt.

percent) Vacuum Gas Oil 23 6, 949 22. 0 1. '2 Residuum 22 3, 003 7. 0 3. 7

The hydrocracking unit 26 is operated in two stages with fractionation between stages to remove from the second stage feed material boiling below 400 F. Ebullated beds of g2 inch nickebtungsten catalyst on silica-alumina base are used in both stages, under the following operating conditions. Feed to the hydrocracking unit totals 23,545 bpd. and has a gravity of 28.3 API and a sulfur content of 1.58 Wt. percent.

The hydroconversion unit 17 uses 1&2 inch cobalt molybdate catalyst in the form of an ebullated bed and is Yields from the hydroconversion Table IV.

unit 26 are shown in Feed to the reforming unit 44 total 22,586 bpd. and has a' gravity of `57.8 the reforminguses a fixed bed of platinum on silica-alunnna` catalyst under the following Table IV YIELDS FROM HYDROCBACKING UNIT Rate Gravity Sulfur Boiling o Fraction i Conduit (bpd.) API) Content Range i (Wt. percent) F.)

C4 and Lighter 33 1 794, 000 below 105 Light N aphtha i 39 4, i 87. 2 l05-220 Intermediate Naphtha. 16,600 54. 0 0. 01 220`375 LlghtGas Oil 34 4, 966 42. 0.01 375-650 1 11n/day.

(d) reforming the intermediate naphtha. fractions from steps (a) and (c) under suitable reforming conditions and recovering therefrom hydrogen, a normally gaseoperating conditions to produce the yields shown in 15 ous fraction and a rcformate fraction, Table V. (e) subjecting at least a portion of said normally gase- Table V 1 Fraction Conduit Rate Gravity Octane Boiling API) F1 clear Range (F) Hydrogen 46 28,112,600 sar/d C4 andrLighter 47 873,000 1b./day 105 Intermediate Naphtha 4s 18,182 b.p.d 52.8 95 los-37s Total Feed to the gas recovery unit 57 is 2,050,000 ous fractions from steps (a), (b), (c) and (d) to pounds perday of C.; and lighter hydrocarbons. Yields treatment for production of hydrogen therefrom, from the gas recovery unit are as follows: and h o o 30 (f),recovering',al1 normally liquid material `resulting Fracu" Lgl/ from step (a) as product of the process except for 'C2 219000 such materialvvhich is treated in steps '(b), (c) or C1 316100 (d) and recovering all normallyliquid material re- CZ 5'" 603600 sulting from stepA (c) as'productof theprocess, ex- Y I 321400 35 cept for such material which istreated in step` (d). B Cz 649900 2. The process according to claim `l in Whichthe nor- `Net yields lof saleable products from the voverall process are as follows:

This represents a marked improvement over the maximum of 40,00043,000 hp d. of saleable products which could be obtained from the same feed using previously known refining processes.

While the invention has been described above in connection with certain preferred embodiments thereof, it Will be understood by those skilled in the art that various changes and modifications may be made without departing from the spirit and scope of the invention and it is intended to cover al1 such modications and changes in the appended claims.

I claim:

l 1. The process for treating hydrocarbon crude oil which comprises:

(a) fractionating said crude oil to `produce a normallyV gaseous fraction, an intermediate naphtha fraction, a gas oil fraction and a residual fraction,

(b) hydrocracking said residual fraction under suitable hydrocracking conditions in the presence of added hydrogen and recovering therefrom a normally gaseous fraction, a residual fraction and gas oil fraction,

(c) hydrocracking said gas oil fraction from step (b) and said gas oil fraction from step (a) under suitable hydrocracking conditions in the presence of added hydrogen and recovering therefrom a normally gaseous fraction, a fuel Ioil fraction and an intermediate naphtha fraction,

mally gaseous fractions from steps (a), (b), (c) and (d) are passed through a gas recovery process from which propane and heavier gases are separately recovered and the remaining lighter gases are treated for production of hydrogen therefrom.

3. The process according to claim 2 in which hydrogen produced in the process is the sole source of added hydrogen for steps (b) and (c).

4. The process for treating hydrocarbon crude oil which comprises:

(a) fractionating said crude oil by atmospheric distillation to produce a normally gaseous fraction, a light naphtha fraction, an intermediate naphtha fraction, a kerosene fraction, a gas oil fraction and a residual fraction,

(b) vacuum distilling said residual fraction and recovering therefroma gas oil fraction and a residual fraction,

(c) hydrocracking the residual fraction from step (b) under suitable hydrocracking conditions in the presence of added hydrogen and recovering therefrom a normally gaseous fraction, an intermediate naphtha fraction, gas oil fraction and a residual fraction,

(d) vacuum distilling the residual fraction from step (c) and recovering therefrom a residual fuel fraction and gas oilfraction,

(e) hydrocracking the gas oil fractions from steps (c) and (d) and the gas oil fraction from step (a) under suitable hydrocracking conditions in the presence of added hydrogen and'recovering therefrom a normally gaseous fraction, a light naphtha fraction, an inter` (a), (c), (e) and (b) for recovery therefrom of a C3 fraction, a C., fraction and a lower boiling gaseous fraction,

(i) treating said lower boiling gaseous fraction for production 'of hydrogen therefrom, and

(j) using hydrogen from steps (f) Aand (i) as the sole source of hydrogen to steps (c) and (e).

5..The process for treating hydrocarbon crude oil which comprises:

(a1) fractionating said crude oil by atmospheric distillation to produce a normally gaseous fraction boiling below about 65 F., a light naphtha fraction boiling between about 65 and about 200 F., an intermediate naphtha fraction boiling between about 200 and about 400 F., a kerosene fraction boiling between about 400 and about 500 F., a gas Aoil fraction boiling between about 400 and about 700 F. and a residual fraction boiling above about 700 F.,

(b) vacuum distilling said residual fraction from step (a) and recovering therefrom a heavy gas oil fraction boiling between about 700 and about 1,000 F. and aresidual fraction boiling above about 1,000 F.,

(c) hydrocracking the residual fraction from step (b) under suitable hydrocracking conditions in the presence of added hydrogen and recovering therefrom a normally gaseous fraction boiling below about 65 F., an 'intermediate naphtha fraction boiling between about 200 and about 400 F., gas oil fraction boiling between about 400 and about 700 F., and a residual fraction boiling above 700 F.

(-d) vacuum distilling of the residual fraction from step (c) and Yrecovering therefrom a residual fuel fraction boiling above about 1,000 F. and an intermediate distillate fraction boiling between about 700 and about 1,000V F.,

1.12 Y (e) hydrocracking'tihegas oil fractions from steps (c) and (d) and the gas oil fraction from step (at) under suitable hydrocracking conditions in the presence of added hydrogen then recovering therefrom a normally gaseous fraction boiling below aboutV 65 F., a light naphtha fraction boiling between about 65 and about 200 F. an intermediate naphtha fraction boilmg between about 200 and about 400 F. and a fuel oil fraction boiling between about 400 and about (f) reforming the intermediate naphtha fractions from steps (a), (c) and (e) under suitable reforming conditions and recovering therefrom hydrogen, a normally gaseous fraction boiling below about 65 F., and a reformate fraction boiling between about 200 and about 400`F., l

(g) recovering all normally liquid materialiresulting from step (a) as product of the process, except for such material which is treated in steps (b), (e) or (f) and recovering al1 normally liquid material resulting from step (e) as product of the process, except for such material which is treated in step (f),

(h) treating the normally gaseous fractions from steps (a), (c), (e) and (h) for recovery therefrom of a C3 fraction, a C4 fraction and fraction,

(i) treating said lower boiling gaseous fraction from step (l1) for production of hydrogen therefrom, and

(j) using hydrogen from steps (f) and as'th'e sole source of hydrogen .through steps (c) and (e).

References lCited bythe Examiner UNITED STATES VPATENTS 2,934,492 4/60 Hemminge'r et a1 20s-112 2,949,420 8/60 Eastman et al. `208-80 3,019,180 1/ 62 Schreiner et al 208-80 40 ALPHONSO D. SULLIVAN, Primary Examiner.

a lower boiling .gaseousY

Claims

1. THE PROCESS FOR TREATING HYDROCARBON CRUDE OIL WHICH COMPRISES: (A) FRACTIONATING SAID CRUDE OIL TO PRODUCE A NORMALLY GASEOUS FRACTION, AN INTERMEDIATE NAPHTHA FRACTION, A GAS OIL FRACTION AND A RESIDUAL FRACTION, (B) HYDROCRACKING SAID RESIDUAL FRACTION UNDER SUITABLE HYDROCRACKING CONDITIONS IN THE PRESENCE OF ADDED HYDROGEN AND RECOVERING THEREFROM A NORMALLY GASEOUS FRACTION, A RESIDUAL FRACTION AND GAS OIL FRACTION, (C) HYDROCRACKING SAID GAS OIL FRACTION FROM STEP (B) AND SAID GAS OIL FRACTION FROM STEP (A) UNDER SUITABLE HYDROCRACKING CONDITIONS IN THE PRESENCE OF ADDED HYDROGEN AND RECOVERING THEREFROM A NORMALLY GASEOUS FRACTION, A FUEL OIL FRACTION AND AN INTERMEDIATE NAPHTHA FRACTION, (D) REFORMING THE INTERMEDIATE NAPHTHA FRACTIONS FROM STEPS (A) AND (C) UNDER SUITABLE REFORMING CONDITIONS AND RECOVERING THEREFROM HYDROGEN, A NORMALLY GASEOUS FRACTION AND A REFORMATE FRACTION,