AU761961B2

AU761961B2 - Integrated hydroconversion process with reverse hydrogen flow

Info

Publication number: AU761961B2
Application number: AU22182/99A
Authority: AU
Inventors: Martin J. Armstrong; Dennis R. Cash; Arthur J. Dahlberg; Hyung-Jae Yoon
Original assignee: Chevron USA Inc
Current assignee: Chevron USA Inc
Priority date: 1998-03-14
Filing date: 1999-01-08
Publication date: 2003-06-12
Anticipated expiration: 2019-01-08
Also published as: ES2218987T3; CA2323910A1; WO1999047626A9; WO1999047626A1; DK1064343T3; AR014713A1; PL189544B1; HUP0101799A3; BR9908753A; AU2218299A; DE69915599T2; DE69915599D1; PL342895A1; JP2002506919A; BR9908753B1; EP1064343A1; JP4383659B2; HUP0101799A2; EA200000945A1; EP1064343B1

Description

WO 99/47626 PCT/US99/00478 INTEGRATED HYDROCONVERSION PROCESS WITH REVERSE HYDROGEN FLOW FIELD OF THE INVENTION The present invention relates to the field of hydroprocessing. In particular, the present invention relates to hydroprocessing to obtain high conversions, product selectivity and selective hydrotreating of specific boiling range products.

BACKGROUND OF THE INVENTION Much of refinery processing involves reaction of refinery streams in a hydrogen atmosphere. In order to maximize conversion efficiencies and to maintain catalyst life, excess hydrogen is generally used in the catalytic conversion processes, with the unreacted hydrogen being recovered, purified and repressurized for use as a recycle stream. Such recycle processes are costly, both in energy and in equipment. Some progress has been made in developing methods for using a single hydrogen loop in a two-stage reaction process.

U.S. Patent No. 5,114,562 teaches a multi-reactor zone process for the production of low aromatics, low sulfur jet fuel or diesel fuel. The two reaction zones, one for desulfurization and one for hydrogenation, operate in a series flow arrangement with a common hydrogen supply system. This process uses strippers to remove H2S from cooled hydrogen rich gases recovered from effluent streams, to permit use of the stripped hydrogen stream in both the desulfurization reaction zone and the hydrogenation reaction zone.

U.S. Patent No. 5,403,469 teaches a parallel hydrotreating and hydrocracking process.

Effluent from the two processes are combined in the same separation vessel and separated into a vapor comprising hydrogen and a hydrocarbon-containing liquid. The hydrogen is shown to be supplied as part of the feedstreams to both the hydrocracker and the hydrotreater.

U.S. Patent No. 3,172,836 teaches a general process for processing a hydrocarbon feed in a catalyst bed, passing a liquid fraction from a first catalyst bed, together with hydrogen, through a second catalyst bed, separating the effluent from the second catalyst bed into a liquid portion and a vapor portion. The vapor portion is combined with the hydrocarbon feed in the first catalyst bed.

U.S. Patent No. 4,197,184 discloses a conventional multiple-stage process for hydrorefining and hydrocracking a heavy hydrocarbonaceous charge stock. In the process, P:\OPER\PHH\2339627 amedclaims.doc-17/01203 -2hydrocracked effluent is admixed with hydrorefined effluent and the combination separated into a hydrogen rich vaporous stream and normally liquid material. The cooled vapor stream is then used as a source of hydrogen and as a quench fluid for both the hydrorefining reaction zone and the hydrocracking reaction zone.

EP 787,787 discloses a hydroprocess in parallel reactors, with hydrogen flowing in series between the reactors. Effluent from a first reaction zone is separated into a first hydrogen rich gaseous stream and a first hydroprocessed product stream. The first hydrogen rich gaseous stream is shown as being used as quench for a second reaction zone.

The first hydrogen rich gaseous stream is also combined with a second hydrocarbon feedstock and fed to the second reaction zone, at a lower hydrogen partial pressure than is the first reaction zone. Effluent from the second reaction zone is separated, the second hydrogen rich gaseous stream being recycled to the first reaction zone, both as a quench stream and as a reactant in combination with a first hydrocarbon feedstock.

SUMMARY OF THE INVENTION S. An advantage of the present invention is the potential to reduce the number of S. reactor vessels required for hydroprocessing in a refinery.

S" The present invention provides an integrated hydroconversion process comprising: combining a first refinery stream with a first hydrogen-rich gaseous stream S 20 to form a first feedstock; passing the first feedstock to a first reaction zone which is maintained at a reaction temperature in the range of from 340-455 0 C (644-851°F), a reaction pressure in the range of 3.5-24.2 MPa (500-3500 pounds per square inch) employing a feed rate (vol oil/vol cat h) from 0.1 to 20 hr and a hydrogen circulation rate ranging from 350 std liters H 2 /kg oil to 1780 std liters H 2 /kg oil (2310-11,750 standard cubic feet per barrel), thereby effecting a boiling range conversion of the first refinery stream of at least 25%, to form a first reaction zone effluent comprising normally liquid phase components and normally gaseous phase components; combining the entire first reaction zone effluent with a second refinery stream having a boiling point range below the boiling point range of the P:\OPERPHM2339627 aIendcaiMs.dcl 17)2A)3 -3first refinery stream to form a second feedstock; passing the second feedstock to a second reaction zone maintained at a reaction temperature in the range of from 340-455°C (644-851'F), a reaction pressure in the range of 3.5-24.2 MPa (500-3500 pounds per square inch) employing a feed rate (vol oil/vol cat h) from 0.1 to 20 hr' and a hydrogen circulation rate ranging from 350 std liters Hz/kg oil to 1780 std liters H 2 /kg oil (2310 to 11,750 standard cubic feet per barrel) which are conditions sufficient for converting at least a portion of the aromatics present in the second refinery stream, to form a second reaction zone effluent; separating the second reaction zone effluent into at least one distillate fraction and a second hydrogen-rich gaseous stream; and recycling at least a portion of the second hydrogen-rich gaseous stream to the first reaction zone.

The invention also extends to diesel fuel and/or jet fuel produced by a process as described in the immediately preceding paragraph.

In the process, the first reaction zone may be operated for molecular weight reduction and boiling point conversion of the first refinery stream, and may use relatively S• more active catalysts. The second reaction zone may be operated for sulfur, nitrogen and S 20 aromatics removal, and may use catalysts active for hydrotreating reactions. The total first reaction zone effluent is combined with the second refinery stream for passage over catalyst in the second reaction zone. The effluent stream from the second reaction zone is separated to form at least one distillate fraction and a second hydrogen-rich gaseous stream, at least some of which may be recycled to the first reaction zone. The at least one *•oo 25 distillate fraction is a liquid stream that may be fractionated to form at least one middle distillate stream and a bottoms product. In the process, advantageously asphaltenes remaining in the second reaction zone effluent are separated from the recycle stream going S•to the first reaction zone, in order to prevent fouling of the first reaction zone catalyst.

IN THE FIGURES One embodiment of a process in accordance with the invention will now be P:\OPER\PHH\2339627 amcdcaiis.doc-17)2/(A)3 -4described, by way of example only, with reference to the accompanying drawings, in which: Fig. 1 shows an embodiment of the invention with two reaction zones in a single reactor vessel.

DETAILED DESCRIPTION OF THE INVENTION The invention relates to two reaction processes, using two dissimilar feeds, which are combined into a single integrated reaction process, using a single hydrogen supply and recovery system. The reactant and product flows and reaction conditions in the present process are selected to avoid contaminating catalysts or products while maintaining catalyst performance and process efficiencies. The feeds to the process include a first refinery stream containing relatively lesser amounts of aromatics, including multi-ring aromatics such as asphaltenes, and a second refinery stream which contains relatively greater amounts of aromatics and multi-ring aromatics. The process is particularly useful for treating a relatively clean feedstock under cracking conditions and a more aromatic .i feed under treating conditions in an integrated process, using a single hydrogen supply and recovery system, without fouling the cracking catalysts with the contaminants in the second refinery stream or without overcracking the second refinery stream.

A suitable first refinery stream is a VGO boiling in a temperature range above about 500°F (260°C), usually within the temperature range of 500°-1100°F (260-593°C).

The first refinery stream may contain nitrogen, usually present as organonitrogen compounds, in amounts greater than 1 ppm. It is a feature of the present process that feeds with high levels of nitrogen and sulfur, including those containing up to 0.5 wt% (and S higher) nitrogen and up to 2 wt% and higher sulfur may be treated. Preferred feed streams oe 25 for the first reaction zone contain less than about 200 ppm nitrogen and less than 0.25 wt% sulfur. The first refinery stream is also preferably a low aromatic stream, including multiring aromatics and asphaltenes. Suitable first refinery streams, including feedstocks to the first reaction zone which may contain recycle streams, contain less than about 500 ppm asphaltenes, preferably less than about 200 ppm asphaltenes, and more preferably less than about 100 ppm asphaltenes. Example first refinery streams include light gas oil, heavy gas oil, vacuum gas oil, straight run gas oil, deasphalted oil, and the like. The first refinery P:\OPER\PHHU339627 nn.dclihsdoc.I 7/M12A13 stream may have been processed, e.g. by hydrotreating, prior to the present process to reduce or substantially eliminate its heteroatom content. The first refinery stream may also comprise recycle components.

The first reaction step removes nitrogen and sulfur from the first refinery stream in the first reaction zone and effects a boiling range conversion, so that the normally liquid portion of the first reaction zone effluent has a normal boiling range below the normal boiling point range of the first refinery feedstock. By "normal" is meant a boiling point or boiling range based on a distillation at one atmosphere pressure, such as that determined in a D 1160 distillation. Unless otherwise specified, all distillation temperatures listed herein refer to normal boiling point and normal boiling range temperatures. The process in the first reaction zone may be controlled to a certain cracking conversion or to a desired product sulfur level or nitrogen level or both. Conversion is generally related to a reference temperature, such as, for example, the minimum boiling point temperature of the feedstock. The extent of conversion relates to the percentage of feed boiling above the reference temperature which is converted to products boiling below the reference temperature.

*.The first reaction zone effluent includes normally liquid phase components, e.g.

i reaction products and unreacted components of the first refinery stream which are liquids at ambient conditions, and normally gaseous phase components, e.g. reaction products and 20 unreacted hydrogen, which are normally vapors at ambient conditions. In the process, the first reaction zone is maintained at conditions sufficient to effect a boiling range conversion of the first refinery stream of at least about 25%, based on a 650'F (343°C) reference temperature. Thus, at least 25% by volume of the components in the first refinery stream which boil above about 650'F are converted in the first reaction zone to *o 25 components which boil below about 650'F.. Operating at conversion levels as high as o•100% is also within the scope of the invention. Example boiling range conversions are in the range of from about 30% to 90% by volume or from about 40% to 80% by volume.

i The first reaction zone effluent is further decreased in nitrogen and sulfur content, which at least about 50% of the nitrogen containing molecules in the first refinery stream being converted in the first reaction zone. Preferably the normally liquid products present in the first reaction zone effluent contain less than about 1000 ppm sulfur and less than about 200 P:\OPER\PHH\2339627 acndclaims.doc-17/)2/O3 -6ppm nitrogen, more preferably less than about 250 ppm sulfur and about 100 ppm nitrogen.

Reaction conditions in the first reaction zone include a reaction temperature from about 340 0 C to about 455 0 C (644-851 0 pressures from about 3.5 MPa to about 24.2 MPa (500-3,500 psi), and a fed rate (vol oil/vol cat h) from about 0.1 to about 20 hr-.

Hydrogen circulation rates are generally in the range from about 350 std liters H 2 /kg oil to 1780 std liters H 2 /kg oil (2,310-11,750 standard cubic feet per barrel). Preferred total reaction pressures range from about 7.0 MPa to about 20.7 MPa (1,000-3,000 psi). With the preferred catalyst system, it has been found that preferred process conditions include contacting a petroleum feedstock with hydrogen under hydrocracking conditions comprising a pressure of about 13.8 MPa to about 20.7 MPa (2,000-3000 psi), a gas to oil ratio between about 379-909 std liters H 2 /kg oil (2,500-6,000 scf/bbl), a LHSV of between about 0.5-1.5 hr" 1 and a temperature in the range of 360 0 C to 427 0 C (680-800 0

F).

The first and second reaction zones contain one or more catalysts. If more than one distinct catalyst is present in either of the reaction zones, they may either be blended or be present as distinct layers. Layered catalyst systems are taught, for example, in US Patent No. 4,990,243. Hydrocracking catalysts useful for the first reaction zone are well known.

In general, the hydrocracking catalyst comprises a cracking component and a hydrogenation component on an oxide support material or binder. The cracking component may include an amorphous cracking component and/or a zeolite, such as a Ytype zeolite, an ultrastable Y type zeolite, or dealuminated zeolite. A suitable amorphous cracking component is silica-alumina.

The hydrogenation component of the catalyst particles is sleeted from those elements known to provide catalytic hydrogenation activity. At least one metal component 25 selected from the Group VIII (IUPAC Notation) elements and/or from the Group VI (IUPAC Notation) elements are generally chosen. Group VI elements include chromium, molybdenum and tungsten. Group VIII elements include iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. The amount(s) of hydrogenation component(s) in the catalyst suitably range from about 0.5% to about 10% by weight of Group VIII metal component(s) and from about 5% to about 25% by weight of Group VI metal component(s), calculated as metal oxide(s) per 100 parts by weight of total catalyst, P:\OPERPHHt2339627 mcndcaims.docW 7/02M/3 -7where the percentages by weight are based on the weight of the catalyst before sulfiding.

The hydrogenation components in the catalyst may be in the oxidic and/or the sulphidic form. If a combination of at least a Group VI and a Group VIII metal component is present as (mixed) oxides, it will be subjected to a sulfiding treatment prior to proper use in hydrocracking. Suitably, the catalyst comprises one or more components of nickel and/or cobalt and one or more components of molybdenum and/or tungsten or one or more components of platinum and/or palladium. Catalysts containing nickel and molybdenum, nickel and tungsten, platinum and/or palladium are particularly preferred.

The hydrocracking catalyst particles that may be used in the process may be prepared by blending, or co-mulling, active sources of hydrogenation metals with a binder.

Examples of suitable binders include silica, alumina, clays, zirconia, titania, magnesia and silica-alumina. Preference is given to the use of alumina as binder. Other components, such as phosphorus, may be added as desired to tailor the catalyst particles for a desired application. The blended components are then shaped, such as by extrusion, dried and calcined to produce the finished catalyst particles. Alternative, equally suitable methods of preparing the amorphous catalyst particles include preparing oxide binder particles, such as *by extrusion, drying and calcining, followed by depositing the hydrogenation metals on the i oxide particles, using methods such as impregnation. The catalyst particles, containing the hydrogenation metals, and then further dried and calcined prior to use as a hydrocracking S 20 catalyst.

The effluent from the first reaction zone comprises normally liquid phase components and normally gaseous phase components. The normally gaseous phase components includes unreacted hydrogen from the first reaction zone. In conventional processing, the reaction zone effluent is normally separated in one or more separation zones, operated at decreasing temperature and/or pressure, in order to recover a substantially pure hydrogen stream for recycle. It is a preferred feature of the present process that the normally gaseous phase components are passed, with the entire effluent from the first reaction zone, to the second reaction zone at substantially the same pressure as the first reaction zone and without substantial cooling, that is at substantially the same temperature as the first reaction zone.

Thus, unreacted hydrogen and other effluent from the first reaction zone is P\OPER\PHH2339627 aflendclaini.dwo-17IA)3 -8combined with a second refinery stream, and the combined feedstock, along with optionally added hydrogen containing gas, is cascaded to a second catalyst bed in a second reaction zone, which is maintained at hydrotreating conditions sufficient to remove at least a portion of the nitrogen and a portion of the aromatic compounds from the second refinery stream. The feedstocks may flow through one or both of the reaction zones in gravity flow in a downwardly direction or upwardly against gravity.

The second reaction step is for hydrotreating a second refinery stream at conditions sufficient to remove at least a portion of the aromatic compounds. Preferably, at least about 50% of the aromatics are removed from the second refinery stream in the integrated process. Typical hydrotreating functions also include removing heteroatoms such as sulfur and nitrogen, removing metals contained in the feed, and saturating at least some of the olefins in the feed. It is particularly desirable to remove multi-ring aromatic materials during hydrotreating, as they are particularly prone to fouling a hydrocracking catalyst which they might contact. A measure of cracking conversion may also occur, depending on the severity of the hydrotreating conditions.

In one embodiment, the second reaction step is for hydrotreating a low boiling refinery stream to reduce the aromatic content of a second refinery stream without 2 overcracking. A substantial proportion of this light feed boils in a temperature range *below the temperature range of the first refinery stream, and generally in the middle distillate range or slightly higher, so that the process of hydrotreating in the second reaction zone produces substantial amounts of high quality middle distillate fuels. Thus, at least about 75 vol of a suitable second refinery stream has a normal boiling point temperature of less than about 538'C (1000'F). A refinery stream with at least about Sv/v of its components having a normal boiling point temperature within the range of 250' 25 700'F is an example of a preferred second refinery stream. The process provides a method for hydrotreating a second refinery stream containing a larger amount of aromatics than the oo•$ first refinery stream. The aromatics content of the second refinery stream may be greater than 50%. Suitable second refinery streams include straight run middle distillate streams from a crude fractionation unit, including straight run diesel; synthetic cracked stocks such as cracked products from an FCC or coker, including light and heavy cycle oil and coker gas oil; deasphalted oil: VGO streams from a synthetic fuel process and the like. While a P:\OPERPHHU339627 amendcklims.doc-17/02/13 -9substantial portion of the second refinery stream may boil in the middle distillate range, so that additional molecular weight reduction by cracking is unnecessary and even undesirable, the feed to the second reaction zone generally contains high amounts of aromatics or olefins, which contribute to undesirable middle distillate fuel properties if they are not removed. Indeed, the aromatic components in the second refinery streams may inhibit the activity of the hydrocracking catalyst were the hydrocracking catalyst contacted with the second refinery stream. The present invention is thus based on the surprising discovery that catalytic cracking activity for boiling point reduction increases, hydrogen consumption improves is reduced), and middle distillate yields increase when the first refinery stream and the second refinery stream are introduced as separate streams, to different locations in the integrated hydroconversion process, rather than being mixed and passed together through both the first and second reaction zones. When light feeds are employed as the second refinery stream, an optional bottoms recycle stream to the first reaction zone will contain substantially no unreacted components of the second refinery stream.

Hydrotreating conditions typically used in the second reaction zone will include a *0 reaction temperature from about 340°C to about 455°C (644-851'F), pressures from about MPa to about 24.2 MPa (500-3,500 psi), and a feed rate (vol oil/vol cat h) from about 0.1 to about 20 hr Hydrogen circulation rates are generally in the range from about 350 20 std liters H 2 /kg oil to 1780 std liters H 2 /kg oil (2,310-11,750 standard cubic feet per barrel).

Preferred total reaction pressures range from about 7.0 MPa to about 20.7 MPa (1,000- 3,000 psi).

In one embodiment, the second reaction zone is maintained at a temperature and at a pressure which is substantially the same as the temperature and the pressure maintained 25 in the first reaction zone.

S The hydrotreating catalyst for the beds will typically be a composite of a Group VI *metal or compound thereof, and a Group VIII metal or compound thereof supported on a oo porous refractory base such as alumina. Examples of hydrotreating catalysts are alumina supported cobalt-molybdenum, nickel sulfide, nickel-tungsten, cobalt-tungsten and nickelmolybdenum. Typically such hydrotreating catalysts are presulfided.

The subject process is especially useful in the production of middle distillate P:\OPER\PHH\2339627 ilendclaims.doc-17/02/113 fractions boiling in the range of about 121 0 -371'C (250 0 -700 0 F) as determined by the appropriate ASTM test procedure. By a middle distillate fraction having a boiling range of about 121 0 -371 0 C (250-700°F) is meant that at least 75 vol%, preferably 85 vol%, of the components of the middle distillate have a normal boiling point of greater than about 121 °C (250 0 F) and furthermore that at least about 75 vol%, preferably 85 vol%, of the components of the middle distillate have a normal boiling point of less than 371 C (700°F). The term "middle distillate" is intended to include the diesel, jet fuel and kerosene boiling range fractions. The kerosene or jet fuel boiling point range is intended to refer to a temperature range of about 138'-274°C (280 0 -525 0 F) and the term "diesel boiling range" is intended to refer to hydrocarbon boiling points of about 121 0 -371°C (250 0 -700°F). Gasoline or naphtha is normally the C 5 to 204 0 C (400°F) endpoint fraction of available hydrocarbons. The boiling point ranges of the various product fractions recovered in any particular refinery will vary with such factors as the characteristics of the crude oil source, refinery local markets, product prices, etc. Reference is made to ASTM standards D-975 and D-3699-83 for further details on kerosene and diesel fuel properties.

In the process a single hydrogen supply provides hydrogen for both the first and the second reaction zones. Make-up hydrogen is combined with low pressure recycle S* hydrogen from the second reaction zone, and the combination is passed to the first reaction zone. Unreacted hydrogen from the first reaction zone is passed without substantial cooling to the second reaction zone. In contrast to conventional processes in which the unreacted hydrogen from the first reaction zone is separated from the reaction zone effluent, cooled, depressurized and purified to remove contaminants, the unreacted hydrogen is passed with all of the effluent from the first reaction zone to the second reaction zone at substantially the same pressure as the first reaction zone and without 25 additional cooling, except for the incidental pressure and temperature losses incurred in conducting the effluent from the first reaction zone to the second reaction zone. The *preferred temperature of the unreacted hydrogen which is passed form the first to the S•second reaction zones is at least about 177°C (350°F), more preferably at least about 260°C (500 0 F) and most preferably at least about 371°C (650 0 Unreacted hydrogen from the second reaction zone is purified to remove contaminants and recycled to the first P:\OPER\PHH2339627 -mtldcainsdoc- 17/U2/)3 -11reaction zone.

Reference is now made to the figure, which discloses a preferred embodiment of the invention. Not included in the figure are 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.

In Fig. 1, a single, downflow reactor vessel 80 contains at least two vertically aligned reaction zones. A first reaction zone 115 is for cracking a first refinery stream A second reaction zone 20 is for removing nitrogen-containing and aromatic molecules from a second refinery stream 5. A suitable volumetric ratio of the catalyst volume in the first reaction zone to the catalyst volume in the second reaction zone encompasses a broad range, depending on the ratio of the first refinery stream to the second refinery stream.

Typical ratios generally lie between 20:1 and 1:20. A preferred volumetric range is between 10:1 and 1:10. A more preferred volumetric ratio is between 5:1 and 1:2.

In the integrated process, a first refinery stream 85 is combined with a first gaseous feed stream 170 to form a first feedstock 105 which is heated in first feed furnace 110 and passed to first reaction zone 115 contained within reactor vessel 80. First gaseous feed stream 170 contains greater than 50% hydrogen, the remainder being varying amounts of light gases, including hydrocarbon gases. First gaseous feed stream 170 shown in the S 20 figure is a blend of make-up hydrogen 95 and recycle hydrogen 175. The use of a recycle hydrogen stream is particularly advantageous for economic reasons. In the process, the first feedstock 105 is passed to the first reaction zone 115 at conditions sufficient to effect a boiling range conversion, to form a first reaction zone effluent 120 comprising normally liquid phase components and normally gaseous phase components.

o The first reaction zone effluent 120 is passed to interstage region 125, a region in "the reactor vessel which contains means for mixing and redistributing liquids and gases from the reaction zone above before they are introduced into the reaction zone below.

Such mixing and redistribution improves reaction efficiency and reduces the chances of thermal gradients or hot spots in the reaction zone below. In the process, second refinery stream 5, is combined with optional hydrogen containing stream 140 forming combined feedstock 15, which is heated in second feed furnace 10 and passed to the interstage region P:\OPER\PHH2339627 nmcndcinA.doc- I7A)2/(13 12- 125. Hydrogen added in stream 140 restores the hydrogen reacted in the first reaction zone, and is not required if sufficient hydrogen is added through stream 170 to the first reaction zone. While stream 140 may include recycled hydrogen, it may also include make-up hydrogen, depending on the hydrogen availability at a particular production location. The entire first reaction zone effluent is passed for combination with the combined, second feedstock 15, at substantially the same temperature and at substantially the same pressure as the first reaction zone.

The second feedstock 15, in combination with the effluent from the first reaction zone, is passed to second reaction zone 20, maintained at conditions sufficient for converting at least a portion of the aromatics present in the second refinery stream, to form a second reaction zone effluent. Since the first reaction zone effluent is already relatively free of the contaminants to be removed in the second reaction zone, the first reaction zone effluent passes largely unchanged through the second reaction zone. However, the presence of the first reaction zone effluent plays an important and unexpected economic :benefit in the integrated process. Leaving the first reaction zone, the effluent carries with it substantial thermal energy, which is passed to the second feedstock in the interstage region between the two reaction zones. This permits adding a cooler second stream to the S: integrated system than would otherwise be required, and saves on furnace and heating 20 costs. As the second feedstock passes through the second reaction zone, the temperature again tends to increase due to the exothermic reaction heating in the second reaction zone.

Having the liquid first effluent in the second feedstock serves as a heat sink, which moderates the temperature increase through the second reaction zone, and therefore reduces the requirement for quench gas introduction. The heat energy contained in the 25 liquid reaction products leaving the second reaction zone is further available for exchange with other streams requiring heating. Generally, the outlet temperature of the second o000 reaction zone will be higher than the outlet temperature of the first zone. In this case, the process will afford the added heat transfer advantage of elevating the temperature of the first reaction zone effluent for more effective heat transfer. The effluent from the first reaction zone also carries the unreacted hydrogen for use in the second reaction zone without any heating or pumping requirement to increase pressure.

P;\OPER\PHH2339627 andclim,-sdo--17/0O2/03 13 Second reaction zone effluent 25 contains unreacted hydrogen, a hydrocarbonaceous component and impurity gases generated during reaction, including hydrogen sulfide and ammonia. The second reaction zone effluent 25 is passed to a separation zone 30, for separating a liquid product from a normally gaseous product, often in a series of separation units operated at varying pressures and temperatures in order to maximize the efficiency of the separation, and to produce a high purity hydrogen stream.

Ammonia and H 2 S produced during hydrotreating are removed, typically by water scrubbing, and optionally by scrubbing using a sorbent such as an amine adsorbent. An example separation scheme for a hydroconversion process is taught in U.S. Patent No.

5,082,551. The effluent may also be cooled by any conventional means, by heat exchanger 180. At least a hydrogen rich gaseous stream 150 and a second liquid stream are recovered from the second separation zone 30. The hydrogen rich gaseous stream 150 leaving the second separation zone is relatively free of both hydrogen sulfide and ammonia. A preferred hydrogen rich gaseous stream 150 is cooled and recovered at a temperature in the range of about 38°C to about 149°C (100°-300'F) or preferably in the range of about 38'C to about 930 (100 0 F-200 0 The now purified hydrogen rich gaseous stream 150 is repressurized through compressor 160, and distributed to various locations in the process. A portion of stream 150 may be introduced to second reaction zone 20 as a second quench stream 145, added to the second reaction zone to adsorb some of the excess S 20 heat from the zone generated by the exothermic hydrotreating reactions occurring therein.

An additional portion of stream 150 may be introduced to first reaction zone 115 as a first quench stream 155. An additional portion of stream 150 is combined with make-up hydrogen 95 for use in the first reaction zone 115. An additional portion of stream 150 may be introduced to second reaction zone 20 as stream 140.

oo 25 Second liquid stream 35 is passed to fractionation zone 40, which is typically a S .i "distillation section comprising one or more atmospheric distillation columns and optionally one or more vacuum distillation columns. A light product and at least one liquid product are recovered. Fractionation zone 40, in the preferred embodiment, is operated to produce a number of distillate streams. Five streams are shown in Fig. 1. These include light product 45, light naphtha stream 50, heavy naphtha stream 55, kerosene stream 60 and diesel stream 65. A liquid bottoms stream 70, which contains unreacted and partially P:\OPER\PHH\2339627 allcndclaims.doc-17)2l)3 14reacted products and materials which boil above a target temperature, greater than about 260 0 C/500°F) is also withdrawn. Stream 70 may be recovered as product stream for processing elsewhere, e.g. additional distillation, treating in an FCC unit or a dewaxing unit for making a lubricating oil base stock. At least a portion of stream 70 and/or at least a portion of one of the distillate fractions streams 50, 55, 60 or 65) may also be recycled to the first reaction zone 115.

Fig. 1 shows two reaction zones contained in one or two reactor vessels. It will be recognized that one or more additional reaction zones upstream of the first reaction zone, and one or more additional reaction zones downstream of the second reaction zone, may also be present in the reactor vessel or in accompanying reactor vessels. As used herein, the relative positions "upstream" and "downstream" are related to a reference position by the direction of liquid flow through the reactor vessel. Employing a minimum number of reactor vessels in the present process may be preferred for economic reasons. However, depending on the particular application of the present process, the required total catalyst volume may require multiple reaction vessels. It will be further recognized that the process as described herein may be incorporated into a larger process involving other hydroconversion reactions.

S Reference is now made to the following examples of a specific embodiment of the invention, which illustrate the benefit of the process of this invention.

20 Example 1 A reactor system was prepared containing 65 vol% Catalyst I over 36 vol% Catalyst II (see Table I) A heavy VGO (Feed A in Table II) was contacted with 5000 SCF/Bbl hydrogen over Catalyst I. A light cycle oil (Feed B in Table II) at approximately the same volumetric flow rate was contacted, along with the effluent from Catalyst I over 25 Catalyst II. Conditions and results are tabulated in Table III.

Table I .9..F *o 99999 Composition Vol% in reactor Catalyst 4% Ni 20% W/ 20 64 I USY Catalyst 3% Ni 21% Mo 3% P 36

II

Table II Heavy Light Cycle Mixed Feed (Feed C): VGO Oil (Feed B) 51.5 wt Feed A (Feed A) 48.5 wt% Feed B API Gravity 21.3 16.3 19.1 Nitrogen, ppm 716 1014 909 Sulfur, Wt 2.93 0.59 1.72 C 1.7 j ompos Lon Paraffins Naphthenes Paraffins/Naphthenes Aromatics Olefins Simulated Distillations (D 2887) 0.5/5 10/30 70/90 95/99.5 19.0 25.4 55.6

OF

536/671 710/786 834 878/937 967/1031 15.1 81.4

OF

224/389 437/502 562 626/706 736/795 12.6 21.2 66.2 261/433 472/579 701 808/899 934/1003 Comparative Example In a comparative example, the quantities of Feed A and Feed B from the examples above were combined in a mixture, and the mixture contacted with 5000 SCFB hydrogen over Catalyst A at the rate of addition used in Example 1. Effluent from Catalyst A were then introduced to Catalyst B. Conditions and results are tabulated in Table III.

As shown by the data, the cracking activity, as measured by the conversion of 680 0

F+

components in the feed to 680°F- components in the product, was surprisingly higher in the process of the invention than in the conventional comparative case. Even more surprising is the significantly reduced hydrogen consumption in the process of the invention, and the increased middle distillate selectivity, where middle distillate selectivity is the volumetric .i ratio of products boiling in the 338°-680 0 F range to the products boiling in the 149 0 -338°F range.

o o o 15 9 9 .9 9 9 9 9 9 9** F Table III Reactor I Reactor 2 Fee Te Pres Feed Te Pres Conver Hydroge Middle d mp, sure mp, OF sure sion n Distillate OF<680 0 F consumption, Selectivity SCF/BbI Fee 74 2300 675 230 78 1440 5.7 d A 5 0 Fee 74 2300 Effluent from 660 230 78 1337 5.2 d A 5 Reactor I Feed B 0 Fee 74 2300 710 230 79 1624 4.8 d A 5 0 Fee 74 2300 710 230 63 d C 5 _0 Fee 75 2300 Effluent from 720 230 67 d C 5 Reactorl1 0 Fee 77 2300 740 -230 75 1943 3.8 dC 5 0 Example II A blended Arabian vacuum residuum feed (see Table 1) was hydrotreated in a vacuum residuum hydrotreating unit.

Table I Arabian Blend Vacuum Residuum Feed Degrees API 4.6 S ecific Gravity, gcc 1.04 Sulfur, Wt 5.73 Nitrogen, Wt 0.47 Nickel, ppmwt 46 Vanadium, ppmwt 105 Carbon Residue, Wt 0% 24 Product yields from the hydrotreating step are shown in Figure Table II.

Table II Yields and Product Proerties from Residuum Hydrotreating Step TBP Cut Points, OF 0

P

I I LV %of VR Feed Sulfur, Wt Liqu Product Ligh Naphtha Heal Naphtha Dies Desn

VGO

VGC

Desu Residuuj Fuel iid

OAPI

C5-180 81.7 0.36 0.007 ly180-330 56.5 2.04 0.013 el 330-690 31.9 13.46 0.068 Ilfurized 690-1000 18.9 27.40 0.259 )Product Ilfurized Oil 690-1000 1000+ r 1 4 12.4 60.10 0.900 t 4.

Oil 690+ 14.4 87.51 14.4 8.51 0705 -17 The desulfurized vacuum gas oil product from the residuum hydrotreating step was hydrocracked to give the products shown in Table III.

Table III Yields and Product Properties from Hydrocracking the Desulfurized

VGO

Product from the Residuum Hydrotreater TBP Cut Points, °F Liquid Products oAPI LV of Desulfuri zed VGO FePPd Light Cs-180 80.0 8.51 Naphtha Sulfur, ppmwt Heavy Naphtha Diesel Desulfurized

VGO

VGO Product Desulfurized Residuum Fuel Oil 180-330 54.0 23.99 I I I 330-690 690-1000 690-1000 1000+ 690+ 40.0 74.80 32.3 5.00 In Table IV the yields and product properties for the overall integrated process are listed. The benefit of the present invention can be seen by a comparison between the I columns entitled "LV% of VR Feed" in Table II and in Table IV. Table II lists data for the S comparative case, with residuum hydrotreating without hydrocracking. Table IV lists data for the invention. Including hydrocracking in the integrated process resulted in significantly higher yields of naphtha and diesel, the desired products of the process, and much lower fuel oil yields.

S.

18 Table IV Overall Yields and Product Properties from the Combined Process of this Invention TBP Cut LV of Sulfur, Liquid Points, OF °API VR Feed Wt% PJ d-.nn IV Ucts Light Naphtha Heavy Naphtha Diesel Desulfurized

VGO

VGO Product Desulfurized Residuum Fuel Oil

C

5 -180 80.2 2.69 0.001 180-330 54.6 8.61 0.003 330-690 690-1000 690-1000 1000+ 1000+ 36.7 32.3 12.4 12.4 33.95 1.37 60.10 60.10 0.030 0.005 0.900 0.900 Table V shows that the cetane number of the diesel product was much higher for the integrated process than for the comparative process using only residuum hydrotreating.

6 6* 0* 0 Table Residuum hydrotreating only Hydrocracking process Process of the invention

V

Cetane Index Although only specific embodiments of the present invention have been described, numerous variation can be made in these embodiments without department from the sprit of the invention and all such variations that fall within the scope of the appended claims are intended to be embraced thereby.

66 66

G

6 .060 0 S *666 666* 660 6666 0* 6 6 19 P:\OPER\PHH\2339627 ;nIcdclaims.doc-I7/02/A3 Throughout this specification and the claims which follow, unless the context requires otherwise, the word "comprise", and variations such as "comprises" and "comprising", will be understood to imply the inclusion of a stated integer or step or group of integers or steps but not the exclusion of any other integer or step or group of integers or steps.

The reference to any prior art in this specification is not, and should not be taken as, an acknowledgment or any form of suggestion that that prior art forms part of the common general knowledge in Australia.

S

o* So 9**9 o

Claims

1. An integrated hydroconversion process comprising: combining a first refinery stream with a first hydrogen-rich gaseous stream to form a first feedstock; passing the first feedstock to a first reaction zone which is maintained at a reaction temperature in the range of from 340-455 0 C (644-851°F), a reaction pressure in the range of 3.5-24.2 MPa (500-3500 pounds per square inch) employing a feed rate (vol oil/vol cat h) from 0.1 to 20 hr"' and a hydrogen circulation rate ranging from 350 std liters H 2 /kg oil to 1780 std liters H 2 /kg oil (2310-11,750 standard cubic feet per barrel), thereby effecting a boiling range conversion of the first refinery stream of at least to form a first reaction zone effluent comprising normally liquid phase components and normally gaseous phase components; combining the entire first reaction zone effluent with a second refinery stream having a boiling point range below the boiling point range of the first refinery stream to form a second feedstock; passing the second feedstock to a second reaction zone maintained at a reaction temperature in the range of from 340-455 0 C (644-851 0 a reaction pressure in the range of 3.5-24.2 MPa (500-3500 pounds per square inch) employing a feed rate (vol oil/vol cat h) from 0.1 to 20 hr" and a hydrogen circulation rate ranging from 350 std liters H 2 /kg oil to 1780 std liters H 2 /kg oil (2310 to 11,750 standard cubic feet per barrel) which are 0*0 25 conditions sufficient for converting at least a portion of the aromatics present in the second refinery stream, to form a second reaction zone :0 effluent; separating the second reaction zone effluent into at least one distillate fraction and a second hydrogen-rich gaseous stream; and recycling at least a portion of the second hydrogen-rich gaseous stream to the first reaction zone. P:\OPERPHH\2339627 ,cmndcaims~do- 702/0U3 22

2. The process according to Claim 1 wherein a boiling range conversion of between and 90% occurs in the first reaction zone.

3. The process according to Claim 1 or Claim 2 wherein the first refinery stream has a normal boiling point range within the temperature range 260-593'C (500-1100F).

4. The process according to any one of the preceding claims wherein the first refinery stream is derived from a hydro treating process. The process according to any one of the preceding claims wherein the first refinery stream is a VGO.

6. The process according to any one of the preceding claims wherein at least about vol% of the second refinery stream has a normal boiling point temperature of less than about 538'C (1000°F).

7. The process according to any one of the preceding claims wherein at least about vol% of the second refinery stream has a normal boiling point temperature within the range of 121-371°C (250-700'F).

8. The process according to any one of the preceding claims wherein the second refinery stream is a synthetic cracked stock.

9. The process according to any one of the preceding claims wherein the second refinery stream is selected from the group consisting of VGO, light cycle oil, heavy cycle oil and coker gas oil. The process according to any one of the preceding claims wherein the second refinery stream has an aromatics content of greater than about

11. The process according to any one of the preceding claims wherein the second refinery stream has an aromatics content greater than the first refinery stream.

12. The process according to any one of the preceding claims wherein the entire first reaction zone effluent is passed to the second reaction zone at substantially the same temperature and at substantially the same pressure as the first reaction zone.

13. The process according to Claim 12 wherein the second reaction zone is maintained at a temperature and at a pressure which are substantially the same as the 30 temperature and the pressure in the first reaction zone.

14. The process according to any one of the preceding claims wherein the second P:\OPER\PHH\2339627 ;lendclainls doc-17/12/13 -23 hydrogen-rich gaseous stream is recovered from a separation zone at a temperature in the range of 38-149 0 C (100-300°F). The process according to any one of the preceding claims wherein the at least one distillate fraction is a liquid stream that is fractionated to form at least one middle distillate fraction and a bottoms product.

16. The process according to Claim 15 wherein the at least one middle distillate stream has a boiling range within the temperature range 121-371 0 C (250-700 0 F).

17. The process according to any one of the preceding claims for producing a diesel fuel.

18. The process according to any one of the preceding claims for producing a jet fuel.

19. The processing according to any one of the preceding claims wherein the distillate fraction recovered from the second reaction zone effluent further comprises components boiling in the range C 5 -204°C (400°F). An integrated hydroconversion process substantially as herein described with reference to the accompanying drawing and/or the Examples (excluding the comparative examples).

21. Diesel fuel produced by a process according to any one of claims 1 to

22. Jet fuel produced by a process according to any one of claims 1 to 20 Dated this 17th day of February, 2003 Chevron U.S.A. Inc. By Its Patent Attorneys DAVIES COLLISON CAVE g o o