US3506567A

US3506567A - Two-stage conversion of nitrogen contaminated feedstocks

Info

Publication number: US3506567A
Application number: US570350A
Authority: US
Inventors: Bion D Barger Jr; Robert J Hengstebeck; Thomas M Moore; Leonard W Russum
Original assignee: Standard Oil Co
Current assignee: Standard Oil Co
Priority date: 1966-08-04
Filing date: 1966-08-04
Publication date: 1970-04-14
Anticipated expiration: 1987-04-14

Description

April 14,' 19770 B D BRGER, JR ET 3,506,567

TWO-STAGE CONVERSION OF4 NITROGEN CONTAMINATED FEEDSTOCKS Filed Aug. 4, 1966 4 2 Sheets-Sheet 1 n) JL QQ m. m uit v O .D 1. QR Nm MN m. M.Q\ m 6 W mmbm (mm. .mmm W wim. wm I 0 mtmm l am mm.; wm M R mmwv mm Mm mm mm B J. Mm 11 d mm al .wm S w om m w Nm f Nm. .m M o M mw #um QS mm n .m m l n vm mm QE vxm mm m :Si SSE w mf. mm um. @mi .ww hm Qn u .ummm um mm #Swm .Q W mmv u N. #Hx m k TIL T ma w vm mmm .Q ww mm ww l. MV Mm., NL NM w QEQS nml E: Nv wv n vm. wm f i mv 5mm km vm swr f mw QM. ms( NNI Q\ QM S N mv wmmmv m S3 EL. ,S R. ./f. mk .25 WQQ April 14, 1970 B D. BARGER, JR;, ET AL 3,505,567

TWO-STAGE CONVERSION OF NITROGEN CONTAMINATED FEEDSTOCKS 2 Sheets-#Sheet l l Filed Aug'. 4, 1966 g MQ N INVENTORS. B/an D. Barger, Jr. Robert J. Hengsebeck Tim/nas M Moore Leonard W. Russi/m United States Patent O U.S. Cl. 208--89 20 Claims ABSTRACT OF THE DISCLOSURE The process comprises a hydroning stage and a hydrocracking stage, wherein dual quenching media are used to quench the hydrogen-hydrocarbon mixture passing through the hydroning stage, part of the liquid petroleum feed serving as the quenching stream to the inlet portion of the hydroining stage and recycled hydrogen-containing gas serving as the quenching stream to the outlet portion of the hydroning stage; hydrogencontaining gas is used to quench the hydrogen-hydrocarbon mixture passing through the hydrocracking stage; efliuent from the feed-preparation stage is subjected to limited cooling, followed by separation of a small amount of condensed material from the vapor at a high pressure, followed by cooling of the resulting vapor and separation of the cooled vapor into a hydrogen-containing gas and a liquid stream; and a hydrogen-containing gas is er1- riched prior to recycle.

This invention relates to the catalytic conversion of hydrocarbon feedstocks. More particularly, it relates to an improved processing scheme for the hydrocracking of relatively high-boiling hydrocarbon feedstocks containing at least parts per million nitrogen to produce lower-boiling hydrocarbons which boil predominantly in the gasoline boiling range.

Hydrocracking is a general term which is applied to petroleum refining processes wherein hydrocarbon feedstocks which have relatively high molecular weights are converted to lower-molecular-Weight hydrocarbons at elevated temperature and pressure in the presence of a hydrocracking catalyst and a hydrogen-containing gas. Hydrogen is,y consumed in the conversion of organic nitrogen andy sulfur to ammonia and hydrogen sulde, respectively, in the splitting of high-molecular-weight compounds into lower-molecular-weight compounds, and in the saturation of olens and other unsaturated compounds. In hydrocracking processes, hydrocarbon feedstocks, such as gas oils that boil in the range of about 350 F. to about 1000 F., typically, catalytic cycle oils boiling between about 350 F. and 850 F., are converted to lower-molecular-weight products, such as gasoline-boiling-range products and light distillates.

Generally, low-temperature hydrocracking processes for maximizing gasoline-boiling-range products employ two processing stages. In the rst stage, the feedstock is hydrotreated to remove nitrogen and sulfur that are typically found in the usual refinery feedstocks. In the second stage, the pretreated hydrocarbon stream is converted to lower-boiling products. Consequently, the rst stage is a feed-preparation stage and the second stage is a hydrocracking stage.

In the two-stage hydrocracking process, the temperature in the feed-preparation stage tends to rise as de`- nitrogenation occurs. This temperature increase can be controlled conveniently by injecting cooler fluid into the reactor at selected points. Generally, the cooler fluid that is used is a gas stream obtained from the same source as 3,506,567 Patented Apr. 14, 1970 ice the hydrogen-containing gas that is recycled to the feedpreparation stage. This cooler lluid is injected or introduced into the feed-preparation stage at selected points along the length of the feed-preparation stage and serves to cool or quench the hydrocarbons, both reactant and product, flowing through the catalyst beds in the feedpreparation stage. We have provided an improved hydrocracking process wherein two quench fluids are used to control the temperatures in the feed-preparation stage. The use of such a scheme will advantageously result in more economical operation.

In a prior-art multiple-stage hydrocracking process, the effluent from the feed-preparation stage is condensed to a relatively low temperature and then separated into a hydrogen-containing gas and liquid hydrocarbons. The hydrogen-containing gas is reheated and returned to the feed-preparation stage ywhile the liquid hydrocarbons are flashed in a flash drum to remove other low-boiling constituents. A major portion of the liquid hydrocarbons are then introduced into a fractionation zone wherein the very high-boiling constituents are separated therefrom prior to the introduction of the denitrogenated hydrocarbons into the hydrocracking stage or zone.

In our improved hydrocracking process, the effluent from the feed-preparation stage is cooled to a temperature which will cause only the very-high-boiling material to condense. The vapor portion of the effluent, which is a major portion of the effluent, is subsequently cooled and separated into a liquid and a hydrogen-containing gas. The liquid is combined with lighter hydrocarbons which are separated from the very-high-boiling material to form a combined liquid, light gases are separated from the resulting combined liquid and sent to a vapor recovery unit, and the liquid hydrocarbons remaining are introduced into a fractionation zone. A hydrocrackingfeed fraction is obtained and sent to the hydrocracking stage.

Cooling of the effluent from the feed-preparation stage to a temperature which is suicient to prevent most of the hydrocarbons from condensing and which permits only the very high boiling hydrocarbons to condense results in more economical operation. When this condensed material is fractionated in a rerun tower or a fractionation zone to separate from this condensed material hydrocarbons which may be included in hydrocracker feed, less heat must be added and equipment having less capacity is needed.

The temperature to which the eluent is cooled is selected to cause effective condensation of only those very high boiling materials which would be considered bottoms and would include those tarry-like substances which are known to be poisonous to conventional hydrocracking catalysts.

In view of the fact that the hydrogen-containing gas subsequently separated from the vapor portion of the efuent may contain appreciable quantities of methane and ethane, the hydrogen-containing gas is enriched by contacting it with an absorbent medium, such as an intermediate naphtha, prior to its return to the feed-preparation stage. The naphtha washes or removes most of the methane and ethane from the hydrogen-containing gas. As the procedure for separating the condensed material from the cooled eiuent from the feed-preparation stage approaches a flashing step, the greater is the need for enriching the hydrogen-containing gas produced.

In accordance with the present invention, there is provided a two-stage process for hydrocracking a stream of petroleum hydrocarbons containing at least 10 parts per million nitrogen. This process comprises: combining a major portion of the stream of petroleum hydrocarbons containing at least 10 parts per million nitrogen with a first hydrogen-containing gas to obtain a rst hydrogenhydrocarbon mixture; heating the first hydrogen-hydrocarbon mixture to obtain a first heated hydrogen-hydrocarbon mixture; introducing the first heated hydrogenhydrocarbon mixture into a feed-preparation stage to contact a hydrofining catalyst under hydrofining conditions, said feed-preparation stage being divided into an inlet section and an outlet section; introducing a minor portion of the stream of petroleum hydrocarbons into the feedpreparation stage at at least one point along the length of the inlet section to quench the hydrogen and hydrocarbons in the inlet section; introducing a second hydrogen-containing gas into the feed-preparation stage at at least one point along the length of the outlet section to quench the hydrogen and hydrocarbons in the outlet section; cooling the etiiuent from the feed-preparation stage to a temperature which is sufiicient to condense a specified amount of the higher-boiling hydrocarbons in the eiuent from said feed-preparation stage to form a first cooled efiiuent; separating the first cooled efiiuent under a high pressure and a high temperature into a first condensed stream and a first vapor stream; cooling the first vapor stream to obtain a second cooled eliiuent; separating said second cooled efiiuent into a third hydrogen-containing gas and a first liquid hydrocarbon stream under a high pressure and a low temperature; adding the first liquid hydrocarbon stream to a second liquid hydrocarbon stream to form a third liquid hydrocarbon stream; heating the first condensed stream under a reduced pressure to obtain a first heated condensed stream and fractionating the first heated condensed stream into a fourth liquid hydrocarbon stream and a heavy bottoms fraction; combining the fourth liquid hydrocarbon stream with the third liquid hydrocarbon stream to form a first hydrocarbon mixture; separating under low pressure and low temperature the first hydrocarbon mixture into light gases and a second hydrocarbon mixture, which light gases are sent to a vapor recovery unit; heating the second hydrocarbon mixture to obtain a second heated hydrocarbon mixture and introducing the second heated hydrocarbon mixture into a fractionation zone; enriching the third hydrogen-containing gas by contact with an absorbent medium from said fractionation zone to form an enriched third hydrogen-containing gas and sending the absorbent medium which has been used to enrich the third hydrogen-containing gas to and into said fractionation zone; separating the enriched third hydrogen-containing gas into a first portion and a second portion, the rst portion being the first hydrogen-containing gas and `the second portion being the second hydrogen-containing gas; separating the hydrocarbons in said fractionation zone into wet gas, light gasoline, absorbent medium, and a heavier-hydrocarbon stream; separating said hea'vierhydrocarbon stream into 180+ F. gasoline and a hydrocracking feed stream; combining the hydrocracking feed stream with a fourth hydrogen-containing gas to form a second hydrogen-hydrocarbon mixture; heating the second hydrogen-hydrocarbon mixture to obtain a second heated hydrogen-hydrocarbon mixture; introducing said second heated hydrogen-hydrocarbon mixture into a hydrocracking stage to contact a hydrocracking catalyst under hydrocracking conditions; introducing a fifth hydrogen-containing gas into the hydrocracking stage at at least one point along the length of the hydrocracking stage to cool the hydrogen and hydrocarbons in the hydrocracking stage; cooling the effluent from the hydrocracking stage to form a third cooled efiiuent; separating the third cooled efiiuent under high pressure into a sixth hydrogen-containing gas and the second liquid hydrocarbon stream, said sixth hydrogen-containing gas being divided into a third portion and a fourth portion, said third portion being said fifth hydrogen-containing gas and a make-up hydrogen-containing gas being added to said fourth portion to form said fourth hydrogen-containing gas; combining said second liquid hydrocarbon stream with said first liquid hydrocarbon stream to form said third liquid hydrocarbon stream; and recovering said light gasoline and said 180+ F. gasoline as usable hydrocar-bon products.

Advantageously, the process step of enriching the third hydrogen-containing gas is included in the process scheme with the process step of separating the first cooled efiiuent under a high pressure and a high temperature into a first condensed stream and a first vapor stream, since excessive amounts of light hydrocarbons tend to remain in the vapors of the first vapor stream. This is particularly true, if a simplified flashing technique is used to separate the vapors from the liquid. The enriching is brought about through the use of an absorbent medium, such as an intermediate naphtha. This enriching step removes eiciently the light hydrocarbons from the hydrogen-containing gas.

Our improved two-stage process for the hydrocracking of nitrogen-containing feedstocks presents several novel features which make this process more advantageous than the two-stage hydrocracking processes now available. These novel features will hereinafter be referred to as improvements.

In the first improvement, two distinct types of quench streams are used to control the temperature rise in the feed-preparation stage resuling from the denitrogenation. Liquid-hydrocarbon streams are used to quench the hydrogen-hydrocarbon mixture in the inlet section of the feed-preparation stage while hydrogen-containing gas is introduced into the outlet section of the feed-preparation stage to quench the hydrogen-hydrocarbon mixture therein. Oil is not used as the quench media throughout the length of the feed-preparation stage, since oil that would be injected near the outlet of the feed-preparation stage might not become sufiiciently denitrogenated and desulfurized. If hydrogen-containing gas, such as recycle gas, is used as the quench medium near the outlet, the possibility of incomplete denitrogenation is eliminated. On the other hand, if the gas were used to quench the hydrogenhydrocarbon mixtures in both the inlet and the outlet sections of the feed-preparation stage, considerably more gas-handling equipment and gas-compressing equipment would be required.

In the second improvement, the efliuent from the feedpreparation stage is cooled to a temperature which will permit only the very high-boiling or very heavy material to condense at a high pressure and a high temperature while the major portion of the efiiuent from the feedpreparation stage is allowed to remain in the vapor phase. This very heavy material comprises the tarry-like substances which would be deleterious to a hydrocracking catalyst. The temperature at which this very heavy material begins to condense is dependent upon the operating conditions that are employed in the feed-preparation stage, such as pressure, rate of material fiowing through said feed-preparation stage, and the end point of the feedstock passing through the feed-preparation stage. It is not known how much of this heavy material will be formed from a particular feedstock, but it is believed that such material will constitute less than 2 volume percent of the feedstock, generally, will make up less than one volume percent, and optimally will make up less than 0.5 volume percent of the feedstock. The condensed heavy material is then separated from the vapors- In this way, the very high-boiling material can be removed easily from the other hydrocarbons and the amount of additional heat needed is reduced appreciably. As a result, there will be a saving of heat, and less-expensive process equipment will be needed.

In the third improvement, the enriching of the third hydrogen-containing gas, i.e., the hydrogen-containing gas to be recycled to the feed-preparation stage, is used in the processing scheme as an adjunct to the step of separating the first cooled effluent into a first condensed stream and a first vapor stream. As mentioned above, this step of enriching the gas is used to purify the hydrogen-containing stream. Of course, if the separation is more sophisticated than a single flashing step, the need for the gas enriching step may be greatly decreased.

The feed-preparation treatment may be operated in the liquid phase, the vapor phase, or mixed vapor-liquid phase. The catalyst may be of a fixed-bed type, a fxed-uidizedbed type, or some other appropriate type of system. Feedstocks which may be used may be derived from petroleum, shale, gilsonite, and other sources.

The petroleum hydrocarbon feedstocks which may be hydrocracked satisfactorily in this improved process may have a wide range of compositions. Such feedstocks may consist essentially of all saturates, or they may consist of practically all aromatics, or they may be mixtures of the two types of hydrocarbons. The saturates are hydrocracked to gasoline-boiling-range parans containing isoparains in the product in a concentration that is greater than that found for equilibrium. The polynuclear aromatics are partially hydrogenated and the hydrogenated ring portion is hydrocracked to produce an equally substituted benzene and isoparaflin. Suitable feedstocks may contain the high-boiling fractions of crude oil, which may boil at a temperature as high as 1200 F. However, generally the feedstock will range from naphtha and kerosene to and through the heavy gas oils. Normally the feedstocks will boil between about 350 F. and about 850 F. Therefore, a light catalytic cycle oil, which boils between about 350 F. and 650 F., a heavy catalytic cycle oil, which boils within the range between about 500 F. and about 800 F., and a virgin gas oil, which boils within the range between about 400 F. and about 1000 F. are suitable feedstocks.

Amounts of sulfur which are found in such feedstocks do not generally affect adversely the catalyst employed in the hydrocracking stage. However, as noted above, combined nitrogen, as well as oxygen, in such feedstocks, deleteriously affect the hydrocracking catalyst; therefore, their concentration in the feedstock should be maintained as low as possible in order to provide the desired rate of reaction in the hydrocracking stage without accelerating hydrocracking-catalyst contamination and deactivation. Such feedstock, as mentioned above, may contain as much as 0.1 weight percent nitrogen, or even higher. This nitrogen concentration is readily reduced in the feed-preparation stage to a value which is conducive to a more satisfactory catalyst life.

In the present improved hydrocracking process, as is done in many of the conventional two-stage hydrocracking processes, the petroleum hydrocarbon feedstock is contacted with a suitable hydroining catalyst in the presence of hydrogen in the feed-preparation stage. Elevated temperatures and pressures are employed. Suitable hydrotining catalysts include those which comprise the oxides and/ or suldes of the Group VI-B and/or Group VIII metals supported on a suitable carrier. Examples of satisfactory carriers are alumina, titania, and silica-alumina. A cobaltmolybdenum catalyst, supported on a silica-alumina carrier, would be a satisfactory catalyst for use in the feedpreparation stage.

Suitable operating conditions that may be yused. in the feed-preparation stage include a reactor temperature within the range between about 500 F. and about 800 F., a pressure within the `range between about 200 and about 2500 p.s.i.g., a hydrogen-to-oil ratio within the range between about 500 standard cubic feet of hydrogen per barrel of hydrocarbon and about 10,000 standard cubic feet of hydrogen. per barrel of hydrocarbon, and `a liquid hourly space velocity within the range between about 0.2 and about 20. Preferably, the temperature may range between about 600 F. and 725 F.; the pressure, v,between about 1200 and 1800 p.s.i.g.; the hydrogen-to-oil ratio, between about 1000 and about 7500 standard cubic feet of hydrogen per barrel of hydrocarbon; and the liquid hourly space velocity, between about 0.5 and about 10.0 volumes of hydrocarbon per hour per volume of catalyst.

In the hydrocracking stage, the hydrocarbons are contacted with a suitable hydrocracking catalyst in the presence of hydrogen at elevated temperatures and pressures. Such catalysts may be selected from various well-known hydrocracking catalysts, which typically comprise a hydrogenation component and a solid acidic cracking component.

The hydrogenation component possesses hydrogenationdehydrogenation activity and may exist in the metallic form or as a compound such as the oxides or sulfides thereof. A large number of well-known metallic hydrogenation catalysts may be used in the hydrocracking catalyst. Preferably, this metallic hydrogenation catalyst is selected from the metals of Group VIII of the Periodic Table, for example, cobalt, nickel, and platinum, or from the metals of Group VI-B, for example, molybdenum and-tungsten. These hydrogenation components can be introduced into the catalyst by impregnating the acidic cracking component with a heat-decomposible compound of the hydrogenation metal and then calcining the resulting composite.

The acidic cracking component of the hydrocracking catalyst may be made up of one or more of the following s'olid acidic components: silica-alumina (naturally occurring and/ or synthetic), silica-alumina-zirconia, silica-magnesia, acid-treated aluminas, with or without halogens, such as uorided alumina, boria-alumina, and the various heteropoly acid-treated-aluminas, and other similar solid acidic components, such as zeolitic crystalline aluminosilicate molecular sieves or zeolitic crystalline aluminosilicate molecular sieves suspended in a matrix of alumina or a matrix of silica-alumina. yEach acidic component must possess substantial cracking activity in the finished catalyst composite. The preparation and the proper-ties of such acidic cracking components are well known to those skilled in the art and need not be considered further. A discussion concerning some of these components may be lfound in Emmetts Catalysis, vol. 7, Reinhold Publishing Corporation, ppl-91. A preferred hydrocracking catalyst also comprises an activity-control-affording material. Such a material balances the activities of the various catalytic elements so that a low rate for hydrogenation relative to that for isomerization results. Such balanced activities in the catalyst provide more branched parains and a better product distribution. The normally solid elements of the Group VI-A of the Periodic Table, particularly sulfur, and the normally solid elements of Group VV-A of the Periodic Table, particularly arsenic and antimony, and metals such as lead, mercury, copper, zinc, and cadmium can provide an advantageous balance in activities between the metallic hydrogenation component and the solid acidic component. Such activity-control-affording elements may be introduced into the catalyst during the catalyst manufacture by impregnating a composite of a hydrogenation component on a solid acidic component with a solution of an organic or inorganic compound, for example, triphenyl arsine, mercuric nitrate, and arsenic trixide. Of course, the composite of hydrogenation component on acidic cracking component could be treated with a sulfur compound, such as hydrogen sulfide or carbon disulfide. Only small amounts of these activitycontiol-affording elements are required in the catalyst. Therefore, in the case of arsenic or antimony, only about 0.1 to 5 moles of arsenic or antimony, preferably about 0.1 to l mole, and optimally about 0.25 to 0.75 mole, of these elements are used per mole of the hydrogenation metal. Not only will the use of these activity-controlaffording elements result in an increase of branched-chain paraffins, but also catalyst regeneration is facilitated.

Suitable operating conditions that are employed in the hydrocracking stage include a temperature within the -range between about 450 F. and about 750 F., a pressure within the range between about 200 and 3000 p.s.i.g., a liquid hourly space velocity within the range between about 0.2 and about 5 volumes of hydrocarbon per hour per volume of catalyst, and a hydrogen-to-oil ratio within the range between about 2,000 and about 15,000 standard cubic feet of hydrogen per barrel of hydrocarbons. Preferably, the temperature ranges from 500 F. to 700 F.; the pressure, from about 1000 to about 1800 p.s.i.g.; the liquid hourly space velocity, from about 0.5 to about 2 volumes of hydrocarbon per hour per volume of catalyst; and the hydrogen-to-oil ratio, from about 5,000 to about 10,000 standard cubic feet of hydrogen per barrel of hydrocarbons.

The present invention will be more fully understood by reference to the following discussion and associated figures. FIGURE 1 is a simplified flow diagram of a preferred embodiment of this improved hydrocracking process. Since this ligure represents a simplified ow diagram of this process, it does not include all of the various pieces of auxiliary equipment such as heat exchangers, condensers, pumps and compressors, which, of course, would be necessary for a complete processing scheme and which would be known and used by those skilled in the art.

FIGURE 2 represents that portion of the processing scheme of FIGURE 1 in which the effluent from the feedpreparation stage is cooled and separated into condensed material and vapors. Each piece of equipment in FIG- URE 2 has the same number as it has in FIGURE l. FIGURES 3, 4, and 5 show alternate processing schemes for the section of equipment presented in FIGURE 2.

EXAMPLE I This example is a preferred embodiment of our irnproved hydrocracking process and is presented for the purpose of illustration only. It is not intended to limit the scope of this invention.

Referring to FIGURE 1, 833 barrels per hour (b./h.) of a light catalytic cycle oil (LCCO) are introduced into the processing scheme via line 10. The LCCO is pumped by pump 11 through line 12. A minor portion of the LOCO in line 12 is passed through line 22 at the rate of about 37 b./h. The major portion of LCCO in line 12, about 796 b./h., is passed into line 13. Reformer make gas is added to the LOCO in line 13 by way of line 13a. This make gas contains approximately 80% hydrogen and is added at the rate of 8,700 s.c.f.m. Other hydrogencontaining gas is passed through line 14 into line 13 to be combined with the LCCO in line 13. The hydrogen-containing gas is passed through line 14 at the rate of approximately 120,700 to 123,700 standard cubic feet per minute (s.c.f.m.). The combined hydrogen and hydrocarbons in line 13 are passed into heater 15. The heated hydrogenhydrocarbon mixture is then passed through line 16 into reactor 17.

Reactor 17 constitutes the feed-preparation stage of this embodiment of the improved process and contains four beds of a hydroining catalyst. The hydroiining catalyst comprises nickel-tungsten-sulfde on a silica-alumina carrier. The four beds of catalyst, starting from the top of the reactor, are numbered consecutively 18, 19, 20, and 21. Reactor 17 is conveniently divided into an inlet section and an outlet section. The inlet section contains catalyst beds 18 and 19, while the outlet section contains

catalyst beds

20 and 21. The total weight of the catalyst in the four beds is 85,000 pounds. The operating conditions in reactor 17 include a pressure of about 1520 p.s.i.g. and a catalyst temperature within the range between about 680 F. and about 750 F.

The minor portion of the LCCO which is passed through line 22 is passed through lines 23 and 24 into reactor 17. Line 23 is connected to reactor 17 such that the LCCO passing through line 23 will be introduced into reactor 17 between catalyst beds 18 and 19. Line 24 is connected to reactor 17 such that the LCCO passing through line 24 will be introduced into reactor 17 between catalyst beds 19 and 20. The portion of LCCO passing through lines 22, 23, and 24 has not been heated by heater 13 and is introduced into reactor 17 to cool the hydrogen and hydrocarbons passing through inlet section of reactor 17 Hydrogen-containing gas is introduced into the reactor 17 between

catalyst beds

20 and 21 by way of line 25. This hydrogen-containing gas is used to quench the hydrogen and hydrocarbons passing through the outlet section of reactor 17 and is added at a rate ranging between 14,000 s.c.f.m. and 17,000 s.c.f.m.

The effluent from reactor is passed through line 26, heat exchanger 27 and line 28 into flash drum 29. The heat exchanger 27 and

lines

26 and 28 are designed so that the efliuent will be cooled to a specified temperature, which, in this case, is 625 F. The conditions in ash drum 29 include a pressure of about 1520 p.s.i.g. and a temperature of about 625 F. The condensed material resulting from the cooling is separated from the rest of the eiuent in flash drum 29 and is passed through line 30. The vapors in flash drum 29 are passed through line 31, heat exchanger 32, line 33, condenser 34, and line 35 into flash drum 36. Flash drum 36 is operated at a temperature of about 105 F. and a pressure of about 1455 p.s.i.g.

Water may be added to the system by way of line 37 which is connected to line 33. This water is used to wash ammonia formed in the feed-preparation stage from the vapors and is separated from the cooled efuent in ash drum 36 by way of line 38.

In iiash drum 36, hydrogen-containing gas is separated from the condensed material and removed from ash drum 36 by way of line 39. This hydrogen-containing gas passes through line 39 at a rate of about 137,700 s.c.f.m. into absorber 40, where it is contacted with an intermediate naphtha, which intermediate naphtha is introduced into absorber 40 by line 41. This intermediate naphtha washes the methane and the ethane from the hydrogen-containing gas as it passes through absorber 40. The methane-ethane-laden naphtha is withdrawn from the bottom of absorber 40 by way of line 42, is passed through heat exchanger 43, line 44, into fractionator 45. An intermediate naphtha fraction is withdrawn from fractionator 45 at line 46, passed through heat exchanger 43, line 47, cooler 48, line 49, pump 50 and line 41 into absorber 40, where it is used to enrich the hydrogen-containing gas passing through absorber 40.

The enriched hydrogen-containing gas is withdrawn from the top of absorber 40 by line 51. As mentioned above, a small portion of this enriched hydrogen-containing gas in line 51 is withdrawn into line 25 at a rate of about 14,000 to 17,000 s.c.f.m. This small portion of gas is used to quench the hydrogen and hydrocarbons passing through the outlet section of reactor 17. The substantial portion of hydrogen-containing gas passing through line 51 is passed through line 14 to be combined with the LCCO flowing through line 13. As mentioned above, this substantial portion of hydrogen-containing gas passes through line 14 at a rate ranging between 120,700 s.c.f.m. and 123,700 s.c.f.m.

The condensed material is removed from flash drum 36 by way of line 52. The flow rate of this condensed material passing through line 52 is approximately 842 b./h.

The condensed material in line 30 is passed through valve 53, line 54, heater 55, and line 56 into and through rerun tower 57. In rerun tower 57, the usable catalytic cycle oil is separated from the very heavy bottoms. Conventional reux equipment is shown in FIGURE l as part of rerun tower 57 and is not numbered. The heavy bottoms are removed from rerun tower 57 at a rate of about 17 b./h. by way of line 58 to be sent to a catalytic cracking unit. The LCCO is removed from rerun tower 57 by way of line 59 at a rate of about 69 b./h. Rerun tower 57 is operated at a pressure of about 5 p.s.i.g. The temperature of the LCCO in line 59 is about 105 F.

The hydrocarbons in line 52 are augmented by 1377 b./h. of hydrocarbons from line 105. The material then tlowing through line 52 at a rate of 2219 b./h. is combined with the LCCO in line 59. The resultant hydrocarbon mixture is passed at a rate of about 2288 b./h. through line 60 into low pressure separator 61. Low pressure separator 61 is operated at a temperature of about 100 F. and a pressure of about 205 p.s.i.g. The condensed material in separator 61 is passed through line 62, heat exchanger 63 and line 64 into fractionator 45. The flow rate of the material in line 62 is about 2232 b./h. The vapors from separator 61 are passed through line 65 at a rate of about 3400 s.c.f.m. to a vapor recovery unit (VRU). Conventional reflux equipment is shown as part of fractionator 45 and is not numbered. Fractionator 45 is operated at a pressure of about 75 p.s.i.g.

Light gasoline is withdrawn from fractionator 45 at a rate of about 346 b./h. by way of line 66. This light gasoline is a usable hydrocarbon product. Wet gas is withdrawn from fractionator 45 through line 67 and sent to a vapor recovery unit. The heavier hydrocarbon fraction-is withdrawn from the bottom of fractionator 45 by way of line 68 at a rate of about 1712 b./h. and is introduced into gasoline-recycle splitter 69. Gasoline-recycle splitter 69 is operated at a pressure of about 30 p.s.i.g. Conventional reflux equipment is indicated for gasolinerecycle splitter 69, but is not numbered. A fraction composed of 18W-360 F. end point gasoline is withdrawn from gasoline-recycle splitter 69 by Way of line 70, cooler 71, line 72, valve 73, and line 74. This 180-360 F. end point gasoline fraction is a usable hydrocarbon product and is withdrawn at a rate of about 661 b./h. A reboiler system for gasoline-recycle splitter 69 is alsoshown, but is not numbered.

The heavier material from gasoline-recycle splitter 69 is passed through line 75 at a rate of about 1051 b./h. Reformer make gas is added at a rate of about 21,300 s.c.f.m. through line 76, compressor 77, and line 78. This reformer make gas is combined with hydrogen-containing recycle gas from line 99. The flow of the recycle gas through line 99 is about 134,500 s.c.f.m. The combined hydrogen-containing gas in line 78 is then combined with the hydrocarbons in line 75. The combined hydrogen and hydrocarbons are then passed through line 79, heat exchanger 80, line 81, heater 82, and line 83 into hydrocracking reactor 84.

Hydrocracking reactor 84 contains four catalyst beds containing a total weight of a hydrocracking catalyst of 195,000 pounds. A nickel-arsenided-on-lluorided-silicaalumina catalyst is used in hydrocracking reactor 84. The four beds, starting at the top of the reactor are numbered consecutively 85, 86, 87, and 88. Operating conditions in reactor 84 include a temperature ranging between about 580 and about 720 F. and a pressure of about 1595 p.s.i.g. The eflluent from hydrocracking reactor 84 is passed through line 89, heat exchanger 90, line 91, cooler 92, and line 93 into separator 94. Separator 94 is maintained at a temperature of about 105 F. and a pressure of about 1530 p.s.i.g. Hydrogen-containing gas is withdrawn from separator 94 through line 95 at a rate of about 179,500 s.c.f.m., compressed by compresser 96, and passed through line 97. This gas is split into two streams, the smaller stream, having a flow rate of about 45,100 s.c.f.m., is passed through line 98, while the large stream, having a flow rate of 134,400 s.c.f.m., is passed through line 99. The gas in line 98 is introduced into hydrocracking reactor 84 at selected points along the length of reactor 84 by way of

lines

100, 101, and 102. The rate of flow of gas in each of

lines

100, 101, and 102 is approximately 15,000 s.c.f.m. This gas is injected or introduced into hydrocracking reactor 84 to regulate the temperature in hydrocracking reactor 84. Line 100 injects the gas into hydrocracking reactor 84 between

catalyst beds

85 and 86. Line 101 injects the gas into hydrocracking reactor 84 between

catalyst beds

86 and 87. Line 102 injects the gas into hydrocracking reactor 84 between

catalyst beds

87 and 88.

The liquid hydrocarbons separated in separator 94 are passed through line 103, valve 104, and line 105 at a rate of about 1377 b./h. These separated hydrocarbons are introduced into line 52 to be combined with the liquid material being separated in separator 36. This combined hydrocarbon stream, having a rate of about 2219 b./h., is then combined with the liquid material in line 59. The total material is then passed through line 60 at a rate of about 2288 `b./h. into low pressure separator 61. It is to be understood that this preferred embodiment of this invention is for illustration only and is not intended to limit the scope of the present invention. Variations in the process scheme as are known to those skilled in the art may be employed. For example, it is conceivable that the fractionator 45 could be located above rerun tower 57 in the same piece of equipment.

Moreover, in this preferred embodiment there is shown one way in which the eflluent from the feed-preparation stage (reactor 17) is cooled and separated into an amount of condensed material and vapors. This high-boiling condensed liquid is separated from the vapors at a temperature which permits a substantial portion of the hydrocarbons to remain in the vapor phase. Several variations of this scheme have been devised.

The simplest system for separating the eflluent from the feed-preparation stage into vapors and liquid is presented in Example 1 and FIGURE 1. The appropriate portion of FIGURE 1 is presented in FIGURE 2. Effluent from reactor 17 is passed through line 26, heat exchanger 27, and line 28 into flash drum 29, where the condensed material is separated from the vapors. The condensed material is withdrawn through line 30 while the vapors are passed through line 31, heat exchanger 32, line 33, cooler 34, and line 35 into flash drum 36. Hydrogen-containing gas is withdrawn `by line 39 while the liquid material is passed through line 52. The hydrogen-containing gas is recycled to reactor 17. In this embodiment, the temperature of the effluent is adjusted to the value where the desired percentage of oil is condensed, the condensate is separated, and the remainder of the reactor effluent is cooled to obtain hydrogen-containing gas (recycle gas) and hydrocracker feed. As is shown in FIGURE l, the condensate may be rerun n auxiliary equipment to recover acceptable hydrocracker feed from it.

A more elaborate system is shown in FIGURE 3. Eflluent from feed-preparation stage reactor 106 is passed through line 107, heat exchanger 108, and line 109 into rectifier 110. The high-boiling material is removed from the bottom or rectifier 110 through line 111 while the vapors are recovered from the conventional reflux equipment through line 112, and passed through heat exchanger `113, line 114, cooler 115, and line 116 into flash drum 117. The condensed material is separated from the eluent and removed by way of line 118 while vapors are removed by line 119. These vapors, which make up a hydrogen-containing gas, are recycled to the feed-preparation stage. This system should provide a better separation than the system shown in FIGURE 2, since poor selectivity is inherent in the one-stage flash of the system in FIGURE 2. In this more elaborate system in FIGURE 3, the rectifying section 110 enriches the effluent from feedpreparation stage reactor 106, i.e., it removes vaporized heavy ends from the vapor stream. As a result of this system, the Ibottom product removed through line 111 may approach, or slightly exceed, the heavy-ends concentration of reactor-106-eflluent dew-point liquid. In view of the fact that the reflux gives some temperature control, temperature adjustment may not be required in this system.

A further modification is presented in-FIGURE 4. Effluent from feed-preparation stage reactor 120 is passed through line 121, heat exchanger 122, and line 123 into stripper 124. The stripping medium is introduced into the stripper by way of line 125. The stripping medium may be steam or gas, such as make-up hydrogen. The

conventional reflux system is shown as part of stripper 124 and is not numbered. The heavy bottoms material is removed from stripper 124 by way of line 126. The vapors are removed by way of line 127 and are passed through heat exchanger 128, line 129, cooler 130, and line 131 into tiash drum 132. The condensed material is removed from ash drum 132 by way of line 133, while the vapors are removed by way of line 134. The vapors that are removed by Way of line 134 make up a hydrogencontaining gas which is recycled to the feed-preparation stage. In such an operation, the pressure ordinarily will be too high for satisfactory reboiler operation. The stripper 124 may be operated with or without a rectifying section. The stripper reduces the light-oil concentration of the heavy-bottoms product.

In the case of the situation where the etiiuent from the feed-preparation stage contains a substantial amount of liquid, the following scheme may be used. This scheme is presented in FIGURE 5. Eiuent from feed-preparation stage reactor 135 is passed through line 136, heater 137, and line 138 into stripper 139. Stripping medium is added at the bottom of stripper 139 by way of line 140. This stripping medium may be steam or gas, such as a hydrogen-containing gas. Stripper 139 is equipped with a conventional reliux system, which is not numbered. Heavy bottoms material is removed from stripper 139 by way of line 141. Vapors are removed from the reux system of stripper 139 by way of line 142, heat exchanger 143, line 144, cooler, 145, and line 146 to be passed into flash drum 147. Condensed materials are removed from flash drurn 147 by way of line 148 while hydrogencontaining gas is removed by way of line 149, to be recycled to reactor 135. In this scheme, the effluent from reactor 135 is heated in order to attain a high percentage of vaporization. The heat added is recoverable in the heatexchange train which follows, Through the use of such a scheme, there is avoided the need for revaporizing the hydrocarbons that are present as vapor in the effluent from reactor 135 and the sensible heat in the liquid portion of the effluent is conserved.

Each of the latter four embodiments is but a more sophisticated variation of our improvement to remove the very high-boiling material from the efliuent from the feedpreparation stage while keeping the major portion of the effluent in the vapor phase. These variations are intended to demonstrate the various ways this improvement can be accomplished and are not intended to limit the scope of our invention.

What is claimed is:

1. In a two-stage process for the hydrocracking of a stream of petroleum hydrocarbons containing at least l parts per million nitrogen, said stream of petroleum hydrocarbon being divided into a major portion and a minor portion, wherein said major portion of said stream of petroleum hydrocarbons is combined with a rst hydrogencontaining gas to form a hydrogen-hydrocarbon mixture and said hydrogen-hydrocarbon mixture is passed through a feed-preparation stage to contact a hydroning catalyst under hydroiining conditions, said feed-preparation stage being divided into an inlet section and an outlet section, the temperature of the efliuent from said feed-preparation stage is adjusted to provide the desired degree of vaporization of said effluent from said feed-preparation stage to form a second hydrogen-containing gas and a second liquid stream, said second hydrogen-containing gas is separated from said second liquid stream, at least a portion of said second hydrogen-containing gas is recycled as said iirst hydrogen-containing gas, said second liquid stream is separated subsequently into a light gasoline, 180+ F. gasoline, and a hydrocracker feedstock, said hydrocracker feedstock is passed through a hydrocracking stage to contact a hydrocracking catalyst under hydrocracking conditions in the presence of hydrogen, the efliuent from said hydrocracking stage is cooled and is separated into a third hydrogen-containing gas and a third liquid stream, said third liquid stream is combined with said second liquid stream, and said light gasoline and said F. gasoline are recovered as usable hydrocarbon prooucts, the improvement which comprises: quenching said hydrogen-hydrocarbon mixture passing through said feed-preparation stage by introducing said minor portion of said stream of petroleum hydrocarbons into said feed-preparation stage at at least one point along the length of said inlet section and by introducing a fourth hydrogen-containing gas into said feed-preparation stage at at least one point along the length of said outlet section.

2. The process of claim 1 wherein said fourth hydrogen-containing gas is a portion of said first hydrogencontaining gas.

3. In a two-stage process for the hydrocracking of a stream of petroleum hydrocarbons containing at least 10 parts per million nitrogen, said stream of petroleum hydrocarbons being divided into a major portion and a minor portion, wherein said major portion of said stream of petroleum hydrocarbons is combined with a first hydrogen-containing gas to form a hydrogen-hydrocarbon mixture and said hydrogen-hydrocarbon mixture is passed through a feed-preparation stage to contact a hydrotining catalyst under hydrotining conditions, said feed-preparation stage being divided into an inlet section and an outlet section, the temperature of the effluent from said feed-preparation stage is adjusted to provide the desired degree of vaporization of said eiuent from said feedpreparation stage to form a second hydrogen-containing gas and a second liquid stream, said second hydrogencontaining gas is separated from said second liquid stream, at least a portion of said second hydrogen-containing gas is recycled as said first hydrogen-containing gas, said second liquid stream is separated subsequently into light gasoline, 180+F. gasoline, and a hydrocracker feedstock, said hydrocracker feedstock is passed through a hydrocracking stage to contact a hydrocracking catalyst under hydrocracking conditions in the presence of hydrogen, the effluent from said hydrocracking stage is cooled and is separated into a third hydrogen-containing gas and a third liquid stream, said third liquid stream is combined with said second liquid stream, and said light gasoline and said 180+ F. gasoline are recovered as usable hydrocarbon products, the improvement which comprises: quenching said hydrogen-hydrocarbon mixture passing through said feed-preparation stage by introducing said minor portion of said stream of petroleum hydrocarbons into said feed-preparation stage at at least one point along the length of said inlet section and by introducing a fourth hydrogen-containing gas into said feed-preparation stage at at least one point along the length of said outlet section, said fourth hydrogen-containing gas being a portion of said first hydrogen-containing gas; cooling said eiiiuent from said feed-preparation stage to a temperature which is suicient to condense only a small amount of the very-high-boiling hydrocarbons in said effluent from said feed-preparation stage to form condensed material and vapor materal; separating under a high pressure and a high temperature said condensed material from said vapor material; further cooling said vapor material in said cooled eluent to form cooled vapor material; separating said cooled vapor material into said second hydrogen-containing gas and said second liquid stream; treating said condensed material to remove very-high-boiling hydrocarbons from lower-boiling hydrocarbons; and cornbining said lower-boiling hydrocarbons with said second liquid stream prior to the separation of said second liquid stream into said light gasoline, said 180+ F. gasoline, and said hydrocracker feedstock.

4. The process of claim 3 wherein said second hydrogen-containing gas is enriched by contacting said second hydrogen-containing gas with a naphtha which boils within the range between about 180 F. and 360 F.

5. The process of claim 3 wherein said third hydro- 13 gen-containing gas is a portion of said first hydrogencontaining gas.

6. The process of claim 3 wherein said small amount comprises tarry-like substances which are deleterious to a hydrocracking catalyst.

7. The process of claim 3 wherein said small amount comprises tarry-like substances which boil above a temperature of 500 F.

8. The process of claim 3 wherein said small amount is less than an amount which is equivalent to 2 volume percent of said stream of petroleum hydrocarbons containing at least l parts per million nitrogen.

9. The process of claim 3 wherein said small amount is less than an amount which is equivalent to 1 volume percent of said stream of petroleum hydrocarbons containing at least l0 parts per million nitrogen.

10. The process of claim 3 wherein said small amount I is less than an amount which is equivalent to 0.5 volume percent of said stream of petroleum hydrocarbons containing at least 10 parts per million nitrogen.

11. The process of claim 3 wherein said high pressure is at least 1000 p.s.i.g. and said high temperature is at least 550 F.

12. The process of claim 3 wherein said high pressure is at least 1500 p.s.i.g. and said high temperature is at least 600 F.

13. A two-stage process for hydrocracking a stream of petroleum hydrocarbons containing at least 10 parts per million nitrogen, which process comprises: combining a major portion of said stream with a first hydrogen-containing gas to obtain a first hydrogen-hydrocarbon mixture; heating said first hydrogen-hydrocarbon mixture to obtain a first heated hydrogen-hydrocarbon mixture; introducing said first heated hydrogen-hydrocarbon mixture into a feed-preparation stage to contact a hydrofining catalyst under hydroning conditions, said feedpreparation stage being divided into an inlet section and an outlet section; introducing a minor portion of said stream into said feed-preparation stage at at least one point along the length of said inlet section to quench the hydrogen and hydrocarbons in said inlet section; introducing a second hydrogen-containing gas into said feedpreparation stage at at least one point along the length of said outlet section to quench the hydrogen and hydrocarbons in said outlet section; cooling the effluent from said feed-preparation stage to a temperature which is sufficient to condense a small amount of the higher-boiling hydrocarbons in said effluent from said feed-preparation stage to form a first cooled effluent; separating said first cooled effluent Iunder a high pressure and a high temperature into a first condensed stream and a first vapor stream; cooling said first vapor stream to obtain a second cooled effluent; separating said second cooled eflluent into a third hydrogen-containing gas and a first liquid hydrocarbon stream under a high pressure and a low temperature; adding said first liquid hydrocarbon stream to a second liquid hydrocarbon stream to form a third liquid hydrocarbon stream; heating said first condensed stream under a reduced pressure to obtain a first heated condensed stream and fractionating said first heated condensed stream into a fourth liquid hydrocarbon stream and a heavy bottoms fraction; combining said fourth liquid hydrocarbon stream with said third liquid hydrocarbon stream to form a first hydrocarbon mixture; separating under low pressure and low temperature said first hydrocarbon mixture into light gases and a second hydrocarbon mixture, which light gases are sent to a vapor recovery unit; heating said second hydrocarbon mixture to obtain a second heated hydrocarbon mixture and introducing said second heated hydrocarbon mixture into a fractionation zone; enriching said third hydrogencontaining gas by contact with an absorbent medium from said fractionation zone to form an enriched third hydrogen-containing gas and sending the absorbent medium which has been used to enrich said third hydrogencontaining gas to and into said fractionation zone; separating said enriched third hydrogen-containing gas into a first portion and a second portion, said first portion being said first hydrogen-containing gas and said second portion being said second hydrogen-containing gas; separating the hydrocarbons in said fractionation zone into wet gas, light gasoline, absorbent medium, and a heavierhydrocarbon stream; separating said heavier-hydrocarbon stream into F. gasoline and a hydrocracking feed stream; combining said hydrocracking feed stream with a fourth hydrogen-containing gas to form a second hydrogen-hydrocarbon mixture; heating said second hydrogen-hydrocarbon mixture to obtain a second heated hydrogen-hydrocarbon mixture; introducing said second heated hydrogen-hydrocarbon mixture into a hydrocracking stage to contact a hydrocracking catalyst under hydrocracking conditions; introducing a fifth hydrogen-containing gas into said hydrocracking stage at at least one point along the length of said hydrocracking stage to cool the hydrogen and hydrocarbons in said hydrocracking stage; cooling the effluent from said hydrocracking stage to form a third cooled effluent; separating said third cooled effluent under high pressure into a sixth hydrogen-containing gas and said second liquid hydrocarbon stream, said sixth hydrogen-containing gas being divided into a third portion and a fourth portion, said third portion being said fifth hydrogen-containing gas and a make up hydrogen-containing gas being added to said fourth portion to form said fourth hydrogen-containing gas; combining said second liquid hydrocarbon stream with said first liquid hydrocarbon stream to form said third liquid hydrocarbon stream; and recovering said light gasoline and said 180+ F. gasoline as usable hydrocarbon products.

14. The process of claim 13 wherein said small amount comprises tarry-like substances which are deleterious to a hydrocracking catalyst.

1S. The process of claim 13 wherein said small amount comprises tarry-like substances which boil above a ternperature of 500 F.

16. The process of claim 13 wherein said small amount is less than an amount which is equivalent to 2 volume percent of said stream of petroleum hydrocarbons containing at least 1-0 parts per million nitrogen.

17. The process of claim 13 wherein said small amount is less than an amount which is equivalent to 1 volume percent of said stream of petroleum hydrocarbons containing at least 10 parts per million nitrogen.

18. The process of claim 13 wherein said small amount is less than an amount which is equivalent to 0.5 volume percent of said stream of petroleum hydrocarbons containing at least 10 parts per million nitrogen.

19. The process of claim 13 wherein said high pressure is at least 1000 p.s.i.g. and said high temperature is at least 550 F.

20. The process of claim 13 wherein said high pressure is at least 1500 p.s.i.g. and said high temperature is at least 600 F.

References Cited UNITED STATES PATENTS 3/1964 Butler et a1. 208-264 9/ 1967 Gutberlet 208-89 U.S. Cl. X.R. 208-59, 254

,Imi

P50 UNITED STA' ES PA'IIENl OFFICE CERT'HPICATE Patent No. 3, 506, 567

Dated April lh, A1970 Inventor(s) Bion D. Barger, Jr., Robert J. Hengstebeck, Thomas M. Moore,

and Leonard W. Bussum It is certified that,` error ap'pe'ars in the above-identified patent and that seid Letters Patent are hereby corrected v'as showri below:

Column 8, line l0, the number' "17" was omitted. Column lO',

lne )49, "or" should be of Column ll, line 53, "hydrocarbon" -should be hydrocarbons Column l2, lineV 1+ "'prooucts" should be .product l-ine- 59, "meteral" should bematerial (SEAL) SIGNED AND SEALED mm E. BGPNYIIER, JR milione? 0t- Potente,