WO1994022982A1

WO1994022982A1 - Integrated hydrocracking/hydrotreating process

Info

Publication number: WO1994022982A1
Application number: PCT/US1994/000292
Authority: WO
Inventors: F. Emmett Bingham
Original assignee: Union Oil Company of California
Current assignee: Union Oil Company of California
Priority date: 1993-04-07
Filing date: 1994-01-07
Publication date: 1994-10-13
Anticipated expiration: 1995-10-07
Also published as: AU6295594A

Abstract

In an integrated hydrocracking-hydrotreating process, the hydrocracked effluent is post-hydrotreated at a lower temperature than in the hydrocracking zone. Cooling between the hydrocracking and hydrotreating zones provides for extended cycle life while maintaining a naphtha product at less than about 1 ppmw mercaptan sulfur.

Description

INTEGRATED HYDROCRACKING/HYDROTREATING PROCESS BACKGROUND OF THE INVENTION

This invention relates to a catalytic hydrocracking process wherein high boiling hydrocarbons are converted to relatively lower boiling hydrocarbons. More particularly, the process involves the removal of organosulfur compounds from hydrocarbon-containing streams in an integrated hydrocracking-hydrotreating catalytic process.

Petroleum refiners often produce desirable products such as turbine fuel, diesel fuel, jet fuel, and other products known as middle distillates, as well as lower boiling liquids, such as naphtha and gasoline, by hydrocracking a hydrocarbon feedstock derived from crude oil. Feedstocks most often subjected to hydrocracking are gas oils and heavy gas oils recovered from crude oil by distillation. A typical gas oil comprises a substantial proportion of hydrocarbon components boiling above about 700° F. , usually at least about 50 percent by weight boiling above about 700° F. A typical heavy gas oil normally has a boiling point range between about 600° F. and 1050° F.

Hydrocracking is generally accomplished by contacting, in an appropriate reaction vessel (commonly referred to as a hydrocracker) , the gas oil or other feedstock to be treated with a suitable hydrocracking catalyst under conditions of elevated temperature and pressure in the presence of hydrogen (and usually small proportions of hydrogen sulfide) so as to yield a product containing a distribution of hydrocarbon products desired by the refiner. A significant influence on the yield of the products is the hydrocracking catalyst. Performance of a hydrocracking catalyst is evaluated by two main catalytic properties—activity and stability. Activity may be determined by comparing the temperature at which various catalysts must be utilized under otherwise constant hydrocracking conditions with the same feedstock so as to produce a given percentage, normally about 60 percent, of products boiling below 700° F. The lower the activity temperature for a given catalyst, the more active such a catalyst is in relation to a catalyst of higher activity temperature. Stability is a measure of how well a catalyst maintains its activity over an extended time period when treating a given hydrocarbon feedstock under the conditions of the activity test. Stability is generally measured in terms of the change in temperature required per day to maintain a 60 percent or other given conversion.

Undesirable components contained in the hydrocarbon products from a hydrocracker, particularly products in the naphtha boiling range, are the organosulfur components, such as mercaptans. For environmental approval, operational efficiency, product quality, etc., the petroleum refiner is typically required to reduce sulfur content in the naphtha-containing hydrocarbon products (other than hydrogen sulfide and other gaseous sulfur compounds) to less than about 0.5 ppmw. Of course, elevated sulfur contents in such hydrocarbon products can necessitate costly downstream desulfurization processing. And for those hydrocarbon products requiring further downstream processing over sulfur-sensitive catalysts, such as in reforming, the elevated sulfur levels can cause deleterious effects on downstream catalytic activity and stability.

Since the mid-60's problems relating to elevated sulfur content, particularly ercaptan content, from the hydrocracker effluent have been alleviated by positioning a hydrotreating zone within the hydrocracker at the effluent end (i.e., integrated hydrocracking- hydrotreating) . See, for instance, U.S. Patent No. 3,338,819 issued to Wood. The hydrotreating process involves reacting organosulfur compounds contained in liquid hydrocarbons with hydrogen to reduce the concentration thereof, in particular, mercaptans, utilizing a catalyst having minimal hydrocracking activity (i.e., typically less than 10, and more often less than 5 percent conversion of hydrocarbon components boiling above 700° F. to products boiling below 700° F.). Ordinarily, the total hydrocracker effluent passes through the hydrotreating zone at substantially the same conditions employed in the hydrocracking zone. However, as the hydrocracking process cycle proceeds, the temperature increase requirements of the hydrocracking catalyst to maintain desired hydrocracking yields are well above those early in the cycle. At the higher temperatures, olefinic compounds are produced by thermal cracking, hydrocracking, etc. , at a faster rate than they can be hydrogenated (e.g., saturated) to desired hydrocarbon products, and, thus, they form an increased proportion of the hydrocracked effluent. Such olefinic compounds contained in this hydrocracked effluent combine with hydrogen sulfide in the hydrocracked effluent downstream of the hydrocracking zone to increase the concentration of undesired organosulfur compounds (e.g., mercaptans) . The increased organosulfur concentration in the hydrocarbon products (typically above the desired concentration, i.e., above 0.5 ppmw S and usually in the range from 1-10 ppmw S) causes the petroleum refiner to shorten the length of the cycle or pass the sulfur- contaminated hydrocarbon products through further costly refining processes. Accordingly, the search continues for a hydrocracking process of increased cycle length thus providing increased production of sweet hydrocarbon streams.

SUMMARY OF THE INVENTION

According to one aspect of the invention, there is provided an integrated process for hydrotreating the total sulfur-containing and hydrocarbon-containing hydrocracked effluent from an upstream hydrocracking zone in a downstream hydrotreating zone at an inlet temperature into the downstream hydrotreating zone that is lower than the outlet temperature of the hydrocracked effluent and still sufficient to maintain or decrease organosulfur compounds contained in the downstream hydrotreating zone.

According to another aspect of the invention, there is provided a process for producing hydrocarbon products containing less than about 1 ppmw of mercaptan sulfur, calculated as S, the process comprising the following steps: (1) hydrocracking a hydrocarbon- containing feedstock comprising organosulfur components and greater than 50 weight percent of its hydrocarbon components boiling above 700° F. , (2) quenching the total hydrocracked effluent obtained from step (1) with a hydrogen-containing gas, and (3) hydrotreating the total effluent obtained from step (2) , and wherein the hydrocracking in step (1) comprises contacting a hydrocracking catalyst containing a molecular sieve with the feedstock under hydrocracking conditions including an average temperature from about 600° F. to about 850° F. and a hydrogen partial pressure from about 1,000 to about 3,000 p.s.i.g., to produce the hydrocracked effluent containing greater than 50 weight percent of its hydrocarbon components boiling at or below 700° F. , and the hydrotreating in step (3) comprising contacting a hydrotreating catalyst having less than 10 percent activity for hydrocracking at 650° F. and at a hydrogen partial pressure of 1,000 p.s.i.g. with the effluent obtained from step (2) under hydrotreating conditions to produce the hydrocarbon products.

Briefly, the present invention preferably relates to an integrated hydrocracking-hydrotreating process for producing relatively sweet hydrocarbon product streams, such as heavy and light naphtha and middle distillate products. The process may involve passing the total hydrocracker effluent through a bed of hydrotreating catalyst in a subsequent hydrotreating zone at substantially the same conditions employed in the hydrocracking zone, except at a lower temperature and typically at a higher space velocity. The hydrocracker effluent is preferably cooled at least 5° F. , and more preferably at least 20° F. , either simultaneously with or prior to contact with the hydrotreating catalyst which has a substantially lower cracking activity than does the upstream hydrocracking catalyst.

In a preferred embodiment, a relatively small bed of hydrotreating catalyst (i.e., usually less than 25 volume percent of the total catalyst volume of the reactor vessel) is placed in the hydrocracking reactor at the effluent end thereof. A hydrocracked effluent is cooled by quenching between the upstream hydrocracking and downstream hydrotreating catalyst beds, i.e., at the hydrocracking-hydrotreating junction. Cooling at the hydrocracking-hydrotreating junction enhances the saturation of olefinic compounds (produced by thermal and/or hydrocracking in the hydrocracking zone) and minimizes downstream olefinic combination with hydrogen sulfide, e.g., mercaptan formation.

By the present invention, a petroleum refiner can severely operate an existing hydrocracker under conditions necessary to maintain hydrocarbon product specification (including sulfur targets) , particularly over the later stages of the process cycle. The refiner need not resort to increasing the existing hydrocracker reactor volume, the catalyst amount, or increasing the pressure, in order to achieve extended cycle lengths, i.e., achieve greater total process throughput for a desired sweet hydrocarbon product distribution. The refiner may simply pass the effluent from the hydrocracker through a quench zone and then to a relatively small downstream hydrotreating zone.

Advantageously, the invention may reduce the burden on the hydrotreating catalyst for converting mercaptan compounds and allows the petroleum refiner to independently operate the hydrocracking and hydrotreating catalyst beds at temperatures sufficient to maximize both the hydrocracking and hydrotreating catalyst activity. Another advantage of the invention may be the reduction of organosulfur content from the hydrotreater effluent so as to prevent sulfur-poisoning of downstream catalysts during further processing of the hydrocarbon product streams.

DETAILED DESCRIPTION OF THE INVENTION

In the preferred embodiment of this invention, hydrocarbon feedstocks are catalytically treated in a single reactor vessel having a hydrocracking zone followed by a post-hydrotreating reaction zone, the latter containing an essentially non-cracking hydrotreating catalyst bed maintained at a temperature normally more than about 5° F. , and often at least 20° F., lower than the temperature in the upstream hydrocracking catalyst bed. By cooling means, the temperature of the exiting hydrocracked effluent from the most-downstream hydrocracking catalyst bed is lowered to a temperature measured at the inlet to the post-hydrotreating catalyst bed that is sufficient to (1) effect hydrogenation (i.e., saturation) of the olefinic compounds contained in the hydrocracked effluent and (2) still effect hydroconversion of organosulfur compounds in the post-hydrotreating catalyst reaction zone.

The catalysts are typically employed as a fixed bed of particulates in a suitable hydrocracker reactor vessel wherein the feedstock to be treated is introduced and subjected to elevated conditions of pressure and temperature, and ordinarily a substantial hydrogen partial pressure, so as to effect the desired degree of hydrocracking and sulfur reduction in the feedstock. The particulate catalyst is maintained, in sufficiently sulfided form, as a fixed bed with the feedstock passing upwardly or downwardly therethrough, most usually downwardly therethrough, and the total hydrocracked effluent, including hydrocarbons, organosulfur compounds and hydrogen sulfide, passing through a downstream fixed post-hydrotreating catalyst bed. In one embodiment of the invention, a hydrocarbon feedstock is passed through a single reactor containing a sulfided hydrocracking and hydrotreating catalyst bed (i.e., HC-HT, catalyst bed) at a temperature from about 450° F. to about 900° F. , but sufficient to both hydrocrack the feedstock and maintain an organosulfur content in the finished hydrocarbon product of less than about 1 ppmw as S, and preferably less than 0.5 ppmw as S. The single reactor contains means for maintaining an up- stream hydrocracking portion of the HC-HT catalyst bed at a different temperature than an immediately adjacent downstream hydrotreating portion of the HC-HT bed during processing. The downstream temperature is controlled by cooling means, such as fluid quench streams (i.e., hydrogen gas or cooled hydrocarbon liquids) and/or heat exchangers, located between the upstream hydrocracking catalyst bed and the downstream hydrotreating portion of the HC-HT catalyst bed. Thermocouples are conveniently positioned in the reactor vessel so the refiner can readily determine the critical temperature differentials required in the present invention. For instance, a thermocouple or other heat measuring device is positioned to determine the outlet temperature of the hydrocracked effluent from the most- downstream hydrocracking catalyst bed and another positioned to determine the inlet temperature of the downstream hydrotreating catalyst bed.

In a reactor vessel apparatus of the integrated hydrocracking-hydrotreating process of the invention, the hydrotreating catalyst, and the means for containing the hydrotreating catalyst within the reactor vessel, is located nearer the fluid outlet end of the reactor vessel (i.e., proximate the outlet end) than is the hydrocracking catalyst (which includes means for containing the hydrocracking catalyst within the reactor vessel) . Within the scope of the present invention is any means for cooling a hydrocarbon-containing fluid which passes from the upstream hydrocracking catalyst to the downstream hydrotreating catalyst. Preferably, the hydrocarbon- containing fluid is passed downwardly from a fluid inlet location near the top of the reactor vessel to a fluid outlet location near the bottom of the reactor vessel, and, consequently, essentially all of the hydrotreating catalyst is located beneath both the cooling means and essentially all of the hydrocracking catalyst. Typically a draining hydrocracked effluent is cooled between an upper tray, which supports the hydrocracking catalyst, and a lower tray, with each tray collecting the liquid draining from an immediate upstream location in the vessel. Each tray contains one or more openings for draining the liquid to below the tray, i.e., draining downward to a downstream location in the vessel. The reactor space between the upper and lower trays is the primary cooling zone where cooling fluids, such as a hydrogen-containing quench gas, are dispersed essentially uniformly throughout the cooling zone. The cooling fluid is dispersed through exit ports of a fluid flow conduit, such as a hydrogen quench ring, and mixed with the draining hydrocracked effluent fluid. Particularly when an existing reactor vessel is modified, the fluid flow conduit may conveniently provide a source of cooling fluid to the cooling zone by passing from outside the reactor vessel to the cooling zone through an existing catalyst unloading port (or other port) near the bottom of the reactor vessel.

In another but not preferred embodiment, the hydrocracking and hydrotreating catalysts are located in two or more separate reactors, such as in a multiple train reactor system having the reactors loaded with one or more types of catalyst, and the total hydrocracked effluent is passed through the reactor containing the hydrotreating catalyst. Furthermore, one or more reactors may be loaded with one type of catalyst and the remaining reactors with one or more other catalysts. In such multiple reactor embodiments, temperature controlling means are typically located between reactors, such as a line hydrogen quench or a heat exchanger; however, it is within the scope of the invention that each reactor in a multiple train have temperature controlling means along the reactor catalyst bed, as for instance, by external heat exchange or a cold hydrogen quench.

In either the single reactor system or the multiple reactor systems, the hydrocracking and post- hydrotreating reaction zones are generally operated under suitable and preferred conditions selected from those shown in the following TABLE A:

TABLE A Operating Conditions Suitable Range Preferred Range Temperature, ° F. 500 - 900 600 - 850

Hydrogen Pressure, p.s.i.g. 750 - 3, 500 1,000 - 3,000

Overall Space Velocity, LHSV 0.1 - 5 0.3 - 3.0

Post-Hydrotreating Space Velocity, LHSV 5 - 20 8 - 16 Hydrogen Recycle Rate, mscf/bbl 1 - 15 2 - 10

In the invention, the post-hydrotreating catalyst volume percentage of the total catalyst volume (hydrocracking catalyst and post-hydrotreating catalyst) is generally less than 20 percent, and typically in the range from about 3 to about 17 percent. Accordingly, the space velocity (i.e., LHSV) of the post-hydrotreating zone is preferably greater than about 5 times, and most preferably greater than about 10 times the space velocity of the hydrocracking zone.

Contemplated for treatment by the overall process of the invention are hydrocarbon-containing oils, including broadly all liquid and liquid/vapor hydrocarbon mixtures such as crude petroleum oils and synthetic crudes. Among the typical hydrocarbon oils contemplated are gas oils. particularly vacuum gas oils, distillate fractions of gas oils, thermally cracked or catalytically cracked gas oils, decant oils, creosote oils, shale oils, oils from bituminous sands, coal-derived oils, and blends thereof, which may contain sulfur, nitrogen and/or oxygen compounds. The process may be applied advantageously to the hydrocracking and hydrogenation of substantially any individual hydrocarbon, mixtures thereof, or mineral oil fractions boiling in the range of about 300° F. to about 1100° F. which may or may not contain a portion of organosulfur compounds. A preferred hydrocracking feedstock is a gas oil or other hydrocarbon fraction having at least 50 percent by weight, and most usually at least 75 percent by weight, of its components boiling at temperatures above the end point of the desired product, which end point, in the case of heavy gasoline, is generally in the range from about 380° F. to about 420° F. A most useful gas oil feedstock will contain hydrocarbon components boiling above about 550° F. (that is, more than about 25 volume percent boils above 550° F.) with highly useful results being achieved with feeds containing at least 25 percent by volume of components boiling between 600° F. and 1,000° F. A highly preferred feedstock processed in the present invention contains a substantial proportion (i.e., more than 50 percent by weight, and, in some cases, essentially all) of feedstock components boiling at greater than 700° F. , particularly a gas oil fraction. The preferred feedstocks include those conventionally treated in a hydrocracker. Typical hydrocarbon products produced from the process of the invention include middle distillates and naphthas. Preferred hydrocarbon products comprise mineral oil fractions boiling in the heavy naphtha, light naphtha, solvent naphtha, gasoline, turbine, jet or diesel fuel ranges. The middle distillate products generally have organosulfur contents (calculated as S) of less than about 0.05 wt. percent. Specifically contemplated hydrocarbon products comprise naphtha fractions boiling in the range of about 180° to about 400° F. (such as a heavy naphtha) , turbine or jet fuel fractions boiling in the range of about 250° to about 550° F. , diesel fuel fractions boiling in the range of about 300° to about 700° F. (at least about 95 volume percent of components boiling below 700° F.), all gasolines, including those fractions boiling from about 50° F. to about 185° F. , and the like. A typical naphtha- containing hydrocarbon product contains less than 1 ppmw of nitrogen components (calculated as N) , and less than about 1 ppmw of sulfur components (calculated as S) , and more often less than 0.5 ppmw (as S) .

In the case of a naphtha-containing hydrocarbon product, the hydrocracking per pass is such as to convert a significant portion, ordinarily at least 50 percent by volume, preferably at least 60 percent by volume, of the hydrocarbon-containing components of the feedstock boiling above about 400° F. to hydrocarbon products boiling below about 400° F. Under preferred hydrocracking conditions, and with a typical gas oil, the product distribution is such that, of the products boiling at a temperature less than about 400° F. , the gasoline product boiling between 50° F. and the end point of a typical gasoline fraction (i.e., about 185° F. ) and the gasoline product boiling between about 185° F. and the end point of a typical heavy gasoline fraction (i.e., about 400° F.), both usually containing less than 0.5 ppmw of mercaptan sulfur (as S) .

The hydrocarbon product distribution obtained from a conventionally hydrocracked effluent is occasionally objectionally contaminated with organosulfur compounds, particularly mercaptans, and even in cases where the initial feedstock is essentially free of mercaptans. These mercaptans (CH₃CH₂SH) are apparently synthesized during or after the hydrocracking operation by the reaction of olefins (e.g., ethylene, CH₂=CH₂) with hydrogen sulfide, as exemplified by the reaction:

CH₂=CH₂ + H₂S 5=* CH₃CH₂SH (1)

According to the present invention, the production of sour products by hydrocracking can be very simply and economically avoided without resorting to conventional separate post-treatments, by passing the total hydrocracked effluent through a bed of hydrotreating catalyst at substantially the same conditions of pressure, hydrogen rate, etc., as employed in the hydrocracker—except the temperature must be low enough where hydrogenation is not thermodynamically limited. Treatment in this manner is herein termed an integrated, intervening cooling hydrocracking-hydrotreating process. Also, as used herein, the term olefinic compounds, as represented in the reactions disclosed herein by ethylene, CH₂=CH₂, includes olefins or alkenes, the C, radical as well as C_xH_2x wherein x is an integer. In the same manner, the corresponding mercaptans derived from the olefinic counterparts are represented in the reactions disclosed herein by ethyl mercaptan, i.e., CH₃CH₂SH.

During the typical hydrocracking process, the hydrocracking catalyst suffers losses in activity and/or stability, and, consequently, the temperatures of the hydrocracking reaction must be increased to maintain the desired hydrocarbon product distribution. The increase in temperature in the hydrocracking zone is apparently, at least in part, responsible for the increase in formation of olefinic compounds. When the olefinic compounds are formed in the hydrocracking reaction zone at a faster rate than they can be hydrogenated downstream to desired sulfurless hydrocarbon product compounds (particularly at the increased temperatures) , the formation of mercaptans can occur in the hydrocracked effluent or downstream according to equilibrium reaction (1) above. The kinetics and thermodynamics involved in the formation of olefinic compounds and mercaptans, and in the elimination of mercaptans, by the novel process of this invention, are complex, and it is not intended to limit the invention to any theoretical explanation of the results obtained. It would appear, however, that the post-hydrotreating technique at a lower temperature than the temperature of the exiting hydrocracked effluent from the last hydrocracking zone reduces the concentration of mercaptans by (a) conventional hydrodesulfurization as illustrated by the reaction:

CH₃CH₂SH + H₂ → C₂H₆ + H₂S (2)

and by (b) hydrogenating (saturating) olefins as illustrated by the following reaction:

CH₂=CH₂ + H₂ → C₂H₆ ( 3 )

Thus the formation of the saturates according to reactions (2) and (3) appear to prevent further formation of mercaptans. It comes as a distinct surprise, therefore, to find that this desirable result can be obtained by only changing the process temperature conditions between the last hydrocracking catalyst bed and the post-hydrotreating catalyst bed while still maintaining the desired (and relatively severe) hydrocracking temperatures for the upstream hydrocracking catalyst. This discovery is advantageously applied in the process of the invention, especially in the last half of a process cycle when the desired hydrocracking temperatures to achieve the desired product distribution are necessarily increased as the activity of the hydrocracking catalyst diminishes. The refiner is able to operate the process of the invention for a longer time (i.e., longer cycle length) than an otherwise equivalent process, e.g., comparable process, which compensates for a loss of hydrocracking catalyst life and activity and an increase in organosulfur content in the product by operating at a lower hydrocracking temperature and having no cooling at the hydrocracking-post hydrotreating junction. Relative to such a comparable process, the process of the invention provides an increase in the total throughput of the desired hydrocarbon product (including its organosulfur content) . The total throughput, as used herein, is the total number of barrels of desired hydrocarbon product distribution produced from the post-hydrotreating zone over the course of the entire process cycle length.

HYDROCRACKING CATALYSTS

Hydrocracking catalysts useful in the invention, whether freshly prepared or regenerated, are effective in the conversion of a wide variety of hydrocarbon feedstocks to desired hydrocarbon products of the invention. As used herein "hydrocarbon" refers to any compound which comprises hydrogen and carbon, and "hydrocarbon feedstock" refers to any charge stock which contains greater than about 80 weight percent carbon and hydrogen, calculated as the elements. If the hydrocracking catalyst contains one or more hydrogenation components, it may be used to convert feedstocks in the presence of added hydrogen to a hydrocarbon product boiling at less than about 700° F. The hydrocracking catalyst contains a cracking component having sufficient acidity to impart activity for cracking a hydrocarbon-containing feedstock. Suitable cracking components include silica-alumina and crystalline molecular sieves having cracking activity. Crystalline molecular sieves are preferred cracking components. The term "crystalline molecular sieve" as used herein refers to any crystalline cracking component capable of separating atoms or molecules based on their respective dimensions. Crystalline molecular sieves may be zeolitic or. nonzeolitic. The term "nonzeolitic" as used herein refers to molecular sieves whose frameworks are not formed of substantially only silica and alumina tetrahedra. The term "zeolitic" as used herein refers to molecular sieves whose frameworks are formed of substantially only silica and alumina tetrahedra such as the framework present in ZSM-5 type zeolites, Y zeolites, and X zeolites. Examples of zeolitic crystalline molecular sieves which can be used as a cracking component of the catalyst include Y zeolite, fluorided Y zeolites, X zeolites, zeolite beta, zeolite L, mordenite and zeolite omega. Examples of non-zeolitic crystalline molecular sieves which may be used as a cracking component of the catalyst include silicoalumino- phosphates, alumina-phosphates, ferrosilicates, titanium aluminosilicates, borosilicates and chromosilicates.

The hydrocracking catalyst contains the cracking component combined with one or more inorganic refractory oxide components, or precursors thereof, such as alumina, silica, titania, magnesia, zirconia, beryllia, a pillared or delaminated clay, a naturally occurring clay such as kaolin, hectorite, sepiolite, attapulgite, montmorillonite or beidellite, silica-alumina, silica-magnesia, silica- titania, mixtures thereof, other such combinations and the like. Examples of precursors that may be used include peptized alumina, alumina gel, hydrated alumina, silica- alumina hydrogels, silica sols and the flocculated reaction product between a swelling clay and a pillaring agent such as polyoxymetal cations and colloidal particles of silica, alumina, titania and the like. The inorganic refractory oxide components or precursors thereof, which serve as a matrix for the cracking component such as zeolite, may be amorphous or crystalline and are usually mixed or comulled with the cracking component in amounts such that the final dry catalyst mixture will comprise (1) between about 2 and about 80 weight percent cracking component, preferably between about 5 and about 50 weight percent, and (2) between about 20 and about 98 weight percent of one or more inorganic refractory oxides, preferably between about 30 and about 80 weight percent. In some cases where the matrix is not capable of sufficiently binding with the cracking component, an inorganic refractory oxide such as peptized alumina may be used as a portion of the matrix where it serves as a binder. The desired inorganic refractory oxide component(s) or precursor(s) thereof is typically mulled, normally in the form of a powder, with the starting cracking component particles. If desired, a binder such as peptized alumina may also be incorporated into the mulling mixture, as also may one or more active metal hydrogenation components. Hydrogenation components may be incorporated into the catalyst by mulling, comulling, impregnation and the like. The hydrogenation components comprise metals selected from Group VIII or Group VIB of the Periodic Table of Elements. Preferred hydrogenation components comprise metals selected from the group consisting of platinum, palladium, cobalt, nickel, tungsten, chromium and molybdenum. In some cases, it may be desirable that the catalyst contain at least one Group VIII metal component and at least one Group VIB metal component.

If the hydrogenation component comprises a noble metal, it is generally desired that the dissolved hydrogenation component be present in an impregnation liquid in a proportion sufficient to ensure that the catalyst contains between about 0.05 and about 10 weight percent of the hydrogenation component, preferably between about 0.10 weight percent and about 3.0 weight percent, calculated as the metal. If the hydrogenation component comprises a non-noble metal, however, it is normally desired that the dissolved hydrogenation component be present in an impregnation liquid in a proportion sufficient to ensure that the catalyst contains between about 1.0 and about 40 weight percent of the hydrogenation component, preferably between about 10 weight percent and about 30 weight percent, calculated as the metal oxide. After impregnation or extrusion, the impregnates or extrudates are dried and calcined in air to produce the finished catalyst particles. Examples of hydrogenation metals loadings, cracking components, binder materials, etc., of preferred hydrocracking catalysts for use herein are disclosed in following U.S. Patent Nos. issued to Ward: 3,926,780; 3,929,672; 3,945,943; 4,419,271; 4,517,074; 4,610,973; 4,664,776; 4,429,053; 4,565,621; 4,604,187; 4,584,287; 4,062,809; 4,097,365; 3,767,734; 4,869,803; 4,762,813; 4,879,019; 4,990,476; 5,116,792; 4,120,825; 4,695,368; U.S. Patent Nos. issued to Ward et al: 4,517,073; 4,563,434; 4,576,711; and U.S. Patent NO. 3,963,644 issued to

Hansford, the disclosures of which are incorporated by reference herein in their entireties. Such exemplary catalysts can readily be employed in suitable upstream hydrocracking locations in the invention.

HYDROTREATING CATALYSTS

Hydrotreating catalysts employed in the downstream reaction zone in the present invention typically contain at least one hydrogenation metal component on a porous refractory oxide support and/or have at least some activity for hydrotreating hydrocarbon-containing feedstocks to convert organosulfur and/or organonitrogen components of the feedstock to hydrogen sulfide and/or ammonia, respectively. Furthermore, the hydrotreating catalyst has essentially no activity for hydrocracking (i.e., less than 5 percent conversion of hydrocarbon components boiling at or greater than 700° F. in a feedstock to hydrocarbon product components boiling below 700° F. under hydrocracking conditions including a temperature of 700° F. and a hydrogen pressure of 3,000 p.s.i.g.). The hydrotreating catalysts can be freshly prepared or regenerated. A preferred catalyst contains at least one Group VIB metal hydrogenation component and/or at least one Group VIII metal hydrogenation, and optionally and preferably, at least one phosphorus component on the porous refractory support. In a highly preferred embodiment, the catalyst contains at least one cobalt or nickel hydrogenation component, at least one molybdenum or tungsten hydrogenation component, and at least one phosphorus component supported on an amorphous, porous refractory oxide containing alumina, preferably gamma alumina. Porous refractory oxide support material of the hydrotreating catalysts employed herein typically contains amorphous, porous inorganic refractory oxides such as silica, magnesia, silica-magnesia, zirconia, silica- zirconia, titania, alumina, silica-alumina, etc., with supports containing gamma, theta, delta and/or eta alumina being highly preferred. Such support material is utilized to prepare catalysts having physical characteristics including a total pore volume greater than about 0.2 cc/gra and a surface area greater than about 100 m/gram. Ordinarily the total pore volume of the catalyst is about 0.2 to about 1.0 cc/gram, and preferably about 0.25 to about 0.80 cc/gram, and the surface area is in the range from about 150 to about 500 m²/gram, and preferably about 175 to about 350 m²/gram. The hydrotreating catalysts employed in the invention typically have porosities wherein a majority of the pore sizes are of diameters from about 40 to about 300 angstroms with a median pore diameter from about 50 to about 200 angstroms. Preferred catalysts have a relatively narrow pore size distribution wherein at least about 75 percent, more preferably at least about 80 percent, and most preferably at least about 85 percent of the total pore volume is in pores of diameter from about 50 to about 110 angstroms or from about 70 to about 130 angstroms. Another porosity feature of preferred catalysts employed herein is the narrow pore size distribution of pores of diameter slightly above or below the median pore diameter which typically lies in the range from about 65 to about 120 angstroms, preferably about 70 to about 100 angstroms. Ordinarily, at least about 50 percent of the total pore volume of the catalysts is contained in pores of diameter within 50 angstroms of the median pore diameter.

Examples of hydrogenation metals loadings and physical characteristics of preferred hydrotreating catalysts for use herein are disclosed in U.S. Patent No. 4,846,961 issued to Robinson et. al., U.S. Patent No. 4,686,030 issued to Ward, and U.S. Patent No. 4,500,424 issued to Simpson et al., the disclosures of which are incorporated by reference herein in their entireties. Such exemplary catalysts can readily be employed in suitable downstream hydrotreating locations in the invention. The process of the invention is most preferably utilized in conjunction with an upstream catalytic hydrotreating operation. That is, the feedstock to be subjected to hydrocracking in the process of the invention most usually comprises the entire effluent from a catalytic hydrotreater wherein, in the presence of the hydrotreating catalyst, a large percentage of the sulfur and nitrogen components in a hydrocarbon-containing liquid are converted by reaction with hydrogen at elevated temperatures and pressures to hydrogen sulfide and ammonia, respectively. In the preferred method of operation, therefore, hydrotreating will precede hydrocracking, and thus, the feedstock most usually subjected to hydrocracking and post- hydrotreating in the process of the present invention will be a hydrotreated feedstock, such as a hydrotreated gas oil or a hydrotreated cycle oil. Such a hydrotreated feedstock typically contains organonitrogen compounds in a concentration in the range from about 0.1 to about 500 ppmw, usually less than 100 ppmw, and preferably less than about 10 ppmw, calculated as N, and contains organosulfur compounds in a concentration less than about 500 ppmw, usually less than 100 ppmw, and preferably from 0 to 75 ppmw, calculated as S.

Although all or a portion of the effluent from a previously hydrotreated feedstock is passed through a hydrocracking zone to the post-hydrotreating zone, the process of the invention is not limited to this particular flow scheme. In another embodiment of the invention, two or more separate hydrocracking zones may be utilized in series in one reactor, or two or more reactors, with one zone containing one type of hydrocracking catalyst and the other(s) containing the same or a different hydrocracking catalyst. However, in all the embodiments, a post- hydrotreating zone immediately follows the last hydrocracking zone in a serial manner, and cooling means are present between the adjacent hydrocracking and post- hydrotreating zone at the junction. Because of the lower temperature in the post-hydrotreating zone of the invention, the mercaptan concentration of the hydrocarbon products can be maintained below an average of 1 ppmw S to achieve a substantially greater throughput than a comparable process wherein the cooling occurs between the last two most-downstream hydrocracking zones and no cooling at the hydrocracking - post-hydrotreating junction.

The invention is further illustrated by the following example which is illustrative of specific modes of practicing the invention and are not intended as limiting the scope of the invention as defined in the appended claims.

EXAMPLE

During an 840 day cycle of the process of the invention, a hydrotreated gas oil is passed through a single upright cylindrical hydrocracker vessel to produce a heavy naphtha liquid hydrocarbon product containing an average of less than 1 ppmw of sulfur (as S) in the form of mercaptans.

The hydrocracker contains four hydrocracking zones with each zone containing a bed of hydrocracking catalyst nominally containing 0.5 wt. percent of palladium on a support consisting of approximately 20 wt. percent of Y- type zeolite and approximately 80 wt. percent of alumina- containing binder and similar to the catalyst used in Example 6 of U.S. Patent No. 3,945,943. Adjacent and below the hydrocracking zones within the hydrocracker lies a commercial Ni-P-Mo-alumina hydrotreating catalyst bed occupying approximately 10 percent of the total reactor catalyst volume. The hydrotreating catalyst is located near the bottom effluent end of the vessel and separated from the bottom-most located bed of hydrocracking catalyst by a cooling zone containing a circular quench ring which uniformly sprays hydrogen gas over the cross-section of the cooling zone contacting, mixing and cooling the hydrocracked effluent that passes from the bottom-most hydrocracking zone. The cooled effluent is continuously passed through the hydrotreating zone and is then separated in a liquid/gas separator into liquid hydrocarbon products and a gas stream containing hydrogen sulfide.

At the start of the process cycle, the effluent temperature at the outlet of the bottom-most hydrocracking zone is approximately 695° F., the hydrogen gas to oil ratio is approximately 11,000 scf/brc at the inlet of the vessel, and the inlet temperature into the hydrotreating zone of the hydrocracked effluent passing from the cooling zone between the hydrocracking catalyst and hydrotreating catalyst (i.e., cooled hydrocracked effluent) is approximately 650° F. During the entire cycle, a lowered temperature differential, in the range from 25-50° F. , is maintained between the bottom-most hydrocracked effluent and the cooled hydrocracked effluent passing to the hydrotreating zone. At the end of the cycle the mercaptan content in the heavy naphtha product is still below an average of 1 ppmw (as S) .

In a previous and comparative hydrocracking process conducted in the same hydrocracking vessel with the same catalysts, the operating cycle ended at approximately 650 days when the mercaptan content of the heavy naphtha product consistently exceeded an average of greater than 1 ppmw as S (i.e., in the range from 2-8 ppmw S) during the final 30 days of operation. In the comparative process, all the operating conditions, feedstock blends, and the like, were essentially the same as in the 840 day cycle of the invention, except the temperature differential was maintained between the last two hydrocracking reaction zones, i.e., between the bottom-most hydrocracking zone and the hydrocracking zone immediate and adjacent above it. Also in the comparative process, no cooling zone was contained between the bottom-most hydrocracking reaction zone and the hydrotreating catalyst. While operating at a significantly higher temperature than in the comparative process, it is surprising that the stability of the hydrocracking catalyst employed in the process of the invention is better than in the comparative process.

While particular embodiments of the invention have been described, it will be understood, of course, that the invention is not limited thereto since many obvious modifications can be made, and it is intended to include within this invention any such modifications as will fall within the spirit or scope of the invention or defined by the appended claims.

Claims

1. An integrated process for hydrotreating the total sulfur-containing and hydrocarbon-containing hydrocracked effluent from an upstream hydrocracking zone in a downstream hydrotreating zone at an inlet temperature into said downstream hydrotreating zone that is lower than the outlet temperature of said hydrocracked effluent and still sufficient to maintain or decrease organosulfur compounds contained in said downstream hydrotreating zone.

2. The process defined in claim 1 wherein said inlet temperature into said downstream hydrotreating zone is at least 5° F. lower than said outlet temperature of said hydrocracked effluent.

3. The process defined in claim 1 wherein said hydrocracked effluent comprises at least one mercaptan compound or at least one olefinic compound.

4. The process defined in claim 3 wherein a liquid product effluent from said downstream hydrotreating zone contains less than about 1 ppmw of mercaptan sulfur, calculated as S.

5. The process defined in claim 1 wherein said inlet temperature of said downstream hydrotreating zone is sufficient to saturate olefinic compounds contained in said hydrocracked effluent.

6. The process defined in claim 1 wherein said inlet temperature into said downstream hydrotreating zone is sufficient to inhibit the formation of a substantial proportion of mercaptan compounds.

7. The process defined in claim 3 wherein said inlet temperature into said downstream hydrotreating zone is sufficient to increase the total throughput of a product effluent from said downstream hydrotreating zone compared to the total throughput of said product effluent from an otherwise comparable process operating at a lower outlet temperature of said hydrocracked effluent and an inlet temperature into said downstream hydrotreating zone being essentially the same or greater than the outlet temperature of said hydrocracked effluent.

8. An integrated hydrocracking-hydrotreating process in a single hydrocracking reactor vessel, said process comprising the following steps:

(1) contacting a hydrocracking catalyst with a hydrocarbon-containing feedstock under hydrocracking conditions to produce a hydrocracked effluent,

(2) cooling the hydrocracked effluent obtained from step (1) , and

(3) contacting the cooled hydrocracked effluent obtained from step (2) with a hydrotreating catalyst under hydrotreating conditions to produce a hydrocarbon product containing a smaller organosulfur content compared to an organosulfur content contained in said cooled hydrocracked effluent.

9. The process defined in claim 8 wherein said feedstock comprises any individual hydrocarbon, mixtures thereof, or mineral oil fractions boiling in the range from about 300° F. to about 1,100° F.

10. The process defined in claim 8 wherein said hydrocarbon product is a liquid selected from the group consisting of heavy naphtha, light naphtha, gasoline, turbine fuel, jet fuel and diesel fuel.

11. The process defined in claim 9 wherein said feedstock comprises a gas oil, and said hydrocarbon product comprises a naphtha containing less than about 1 ppmw of mercaptan sulfur, calculated as S.

12. The process defined in claim 8 wherein a quench fluid contacts said hydrocracked effluent in step (2) .

13. The process defined in claim 8 wherein the outlet temperature of said effluent obtained from step (2) is at least 5° F. lower than the outlet temperature of said hydrocracked effluent obtained from step (1) .

14. The process defined in claim 8 wherein said hydrocracking conditions include a temperature from about 500 to about 900° F. , a liquid hourly space velocity greater than 0.1 and a hydrogen partial pressure from about 750 to about 3,500 p.s.i.g., and said hydrotreating conditions include a liquid hourly space velocity greater than that of said hydrocracking conditions.

15. The process defined in claim 8 wherein the outlet temperature of said effluent obtained from step (2) is sufficient to saturate at least a portion of olefinic compounds contained in said effluent obtained from step (1).

16. The process defined in claim 8 wherein said hydrocarbon-containing feedstock is obtained from a hydrotreating process.

17. A process for producing hydrocarbon products containing less than about 1 ppmw of mercaptan sulfur, calculated as S, said process comprising the following steps:

(1) hydrocracking a hydrocarbon-containing feedstock comprising organosulfur components and greater than 50 weight percent of its hydrocarbon components boiling above 700° F. ,

(2) quenching the total hydrocracked effluent obtained from step (1) with a hydrogen-containing gas, and (3) hydrotreating the total effluent obtained from step (2) , and wherein said hydrocracking in step (1) comprises contacting a hydrocracking catalyst containing a molecular sieve with said feedstock under hydrocracking conditions including an average temperature from about 600° F. to about 850° F. and a hydrogen partial pressure from about 1,000 to about 3,000 p.s.i.g., to produce said hydrocracked effluent containing greater than 50 weight percent of its hydrocarbon components boiling at or below 700° F., and said hydrotreating in step (3) comprising contacting a hydrotreating catalyst having less than 10 percent activity for hydrocracking at 650° F. and at a hydrogen partial pressure of 1,000 p.s.i.g. with said effluent obtained from step (2) under hydrotreating conditions to produce said hydrocarbon products.

18. The process defined in claim 17 wherein said hydrocarbon product is a liquid selected from the group consisting of heavy naphtha, light naphtha and gasoline.

19. The process defined in claim 17 wherein the outlet temperature of said effluent obtained from step (2) is sufficient to saturate at least a portion of olefinic compounds contained in said hydrocracked effluent obtained from step (1) .

20. The process defined in claim 17 wherein said hydrocarbon-containing feedstock is obtained from a hydrotreating process.

21. An integrated hydrocracking-hydrotreating apparatus comprising: a catalytic reactor vessel containing a fluid inlet and fluid outlet; a hydrotreating catalyst contained within said vessel proximate to said fluid outlet; a hydrocracking catalyst contained within said vessel; and means for cooling a hydrocarbon-containing fluid passing from said hydrocracking catalyst to said hydrotreating catalyst.

22. The apparatus defined in claim 21 wherein essentially all of said hydrotreating catalyst is below said hydrocracking catalyst.

23. The apparatus defined in claim 21 wherein said cooling means comprise means for injecting a cooling fluid between said hydrocracking catalyst and said hydrotreating catalyst.

24. The apparatus defined in claim 22 wherein said cooling means comprise means for injecting a hydrogen- containing gas below said hydrocracking catalyst but above said hydrotreating catalyst.

25. The apparatus defined in claim 24 wherein said cooling means comprises an upper tray for supporting said hydrocracking catalyst, said upper tray having one or more openings for draining said hydrocarbon-containing fluid below said tray.

26. The apparatus defined in claim 24 wherein said cooling means comprise a fluid flow conduit having one or more fluid entry ports and one or more fluid exit ports.

27. The apparatus defined in claim 26 wherein said fluid flow conduit comprises a quench ring for dispersing said hydrogen-containing gaseous fluid below said tray.

28. The apparatus defined in claim 25 wherein said cooling means comprises a lower tray below said upper tray, said lower tray adapted to collect a cooled fluid draining from said upper tray, said lower tray having one or more openings for draining said cooled fluid below said lower tray.

29. The apparatus defined in claim 28 wherein essentially all of said hydrotreating catalyst is below said lower tray and essentially all of said hydrocracking catalyst is above said upper tray.

30. The apparatus defined in claim 21 wherein said reactor vessel comprises means for passing a hydrocarbon- containing fluid downwardly from said fluid inlet to said fluid outlet and said cooling means comprises means for injecting gases from a source of hydrogen-containing gas to a location between essentially all of said hydrocracking catalyst and essentially all of said hydrotreating catalyst.

31. The apparatus defined in claim 28 wherein said fluid flow conduit passes from a location outside said reactor vessel to a reactor space within said reactor vessel between said upper tray and said lower tray.