RU2454450C2 - Method of producing low-sulphur diesel fuel and high-octane naphtha - Google Patents

Abstract

FIELD: chemistry.

SUBSTANCE: method of producing low-sulphur diesel fuel and high-octane naphtha is characterised by that the output stream of distillate from the hydrodesulphurisation reaction zone and the output stream from the hydrocracking reaction zone, supplied with dealkylated, high-aromatic material, are mixed and separated to obtain a gas stream of hydrogen, low-sulphur diesel fuel and high-octane naphtha.

EFFECT: feeding hydrogen as a source of hydrogen for the hydrodesulphurisation reaction zone minimises the load on the recirculation compressor, and use of a common separation and fractionation zone gives the advantage of lower capital and operational costs.

10 cl, 1 dwg, 2 tbl, 1 ex

Description

FIELD OF THE INVENTION

This invention relates to a method for producing low sulfur diesel fuel and high octane naphtha. More specifically, the invention is a combined method of hydrodesulphurization of gas oil hydrocarbon streams and hydrocracking of highly aromatic hydrocarbon streams.

Refiners produce the desired products, such as gas turbine fuel, light diesel fuel and gas oil, as well as naphtha and gasoline, by hydrocracking hydrocarbon feedstocks obtained, for example, from crude oil. The most commonly hydrocracked feedstocks are gas oil and heavy gas oil extracted from crude oil by distillation. Oil refiners also subject gas oil hydrocarbon streams to hydrodesulfurization. Although a large number of process flow diagrams, operating conditions, and catalysts are used in industrial activities, there is always a need for new hydroprocessing methods that provide lower costs, more significant product yields, and improved performance.

State of the art

US Pat. No. 4,943,366 (Fischer et al.) Discloses a hydrocracking process for the conversion of highly aromatic, substantially dealkylated feedstocks to high octane gasoline.

SUMMARY OF THE INVENTION

The present invention is a combined method for producing low sulfur diesel fuel and high octane naphtha. The method of the present invention uses a gas oil hydrocarbon stream and a highly aromatic hydrocarbon stream. The gas oil hydrocarbon feed interacts with fresh hydrogen replenishment in the hydrodesulfurization reaction zone, and the high aromatic hydrocarbon stream interacts with recycle hydrogen in the hydrocracking zone. The resulting effluent from two zones is introduced into a common liquid and high pressure vapor separator to produce a hydrogen-rich recycle gas and a liquid stream containing sulfur-free diesel fuel and high-octane naphtha, which are then subsequently separated.

The use of hydrogen recharge as a source of hydrogen for the hydrodesulfurization reaction zone minimizes the load on the recirculation compressor, and the use of common separation and rectification zones provides the advantages of lower capital and operating costs.

Other embodiments of the present invention cover further details, such as detailed characteristics of the feedstock, hydrodesulfurization catalysts, hydrocracking catalysts, and preferred mode of operation, which are further disclosed in the following discussion of each of these aspects of the invention.

Brief description of the drawing

The figure is a simplified flow diagram of a method of a preferred embodiment of the present invention. The figure is intended to schematically illustrate the present invention, and not its limitations.

Detailed description of the invention

The present invention is a combined method for hydrodesulfurization of gas oil hydrocarbon streams and hydrocracking of highly aromatic hydrocarbon streams. Preferred feeds for the hydrodesulfurization zone include hydrocarbon distillates boiling at temperatures above 149 ° C (300 ° F), and more preferably boiling in the range from 149 ° C (300 ° F) to 399 ° C (750 ° F). Raw hydrocarbon distillates are most often extracted from crude oil by distillation. However, hydrocarbon distillates from any convenient source can be used, such as, for example, extraction from tar sands and the conversion of natural gas to liquid hydrocarbons. In addition, the hydrocarbon distillate feed may contain from 0.1 to 4 wt.% Sulfur.

A preferred high aromatic hydrocarbon feed is boiling in the range of 149 ° C. (300 ° F) to 343 ° C. (650 ° F). Highly aromatic, substantially dealkylated hydrocarbons are produced during the catalytic cracking of vacuum gas oil in a fluidized bed (FCC) to produce hydrocarbons with a boiling range of high octane gasoline. FCC is a thermally stringent process that takes place in the absence of added hydrogen to remove carbon in the coke and produce tailings. In catalytic cracking, high molecular weight raw materials disproportionate into relatively hydrogen-rich light liquids and aromatic, hydrogen-poor, heavier distillates and residues. Catalytic cracking in the absence of hydrogen does not provide significant desulfurization, nor does it reduce the nitrogen content in the feed selectively freed from coke. Therefore, sulfur and nitrogen are concentrated in heavier cracking products and convert significant amounts of highly aromatic, hydrogen-poor medium and heavy distillates with a high content of sulfur and nitrogen. Recycling these fluids in a catalytic cracking unit is not an attractive mode. A typical lightweight catalytic cracking oil (LCO) from FCC contains 3% by weight of sulfur, 700 parts by weight per million nitrogen and more than 80% by weight of aromatic hydrocarbons. The demands of the modern market make streams of difficult to process products, such as light catalytic cracking oil, particularly difficult to sell as commercially valuable products.

In one embodiment of the present invention, a highly aromatic, hydrogen-poor and substantially dealkylated hydrocarbon feed is introduced into the hydrocracking zone. The hydrocracking zone may contain one or more layers of the same or different catalyst. In one embodiment, preferred hydrocracking catalysts use an amorphous base or a low zeolite base combined with one or more hydrogenating components of a Group VIII or Group VIB metal. In another embodiment, the hydrocracking zone comprises a catalyst that generally contains any crystalline cracking zeolite base onto which hydrogenation components of Group VIII metals are deposited in a small relative proportion. Additional hydrogenating components to combine with the zeolite base can be selected from group VIB. Zeolite cracking bases are sometimes referred to in the art as molecular sieves and are usually composed of silica, alumina and one or more exchangeable cations, such as sodium, magnesium, calcium, rare earth metals, etc. They also differ in crystal pores of relatively uniform diameter between 4 and 14 angstroms (10 ^-10 m). It is preferable to use zeolites having a silica / alumina molar ratio between 3 and 12. Suitable zeolites found in nature include, for example, mordenite, stilbit, heylandite, ferrierite, daciardite, chabazite, erionite and faujasite. Suitable synthetic zeolites include, for example, crystalline types B, X, Y and L, for example synthetic faujasite and mordenite. Preferred zeolites are those having a crystal pore diameter between 8 and 12 angstroms (10 ^-10 m), and having a silica / alumina molar ratio of from 4 to 6. The most important examples of zeolites that fall into the preferred group are synthetic molecular Y-type sieves

Naturally occurring zeolites are usually in the sodium form, alkaline earth metal form, or mixed forms. Synthetic zeolites are almost always obtained first in sodium form. In any case, for use as a cracking base, it is preferable that most or all of the starting zeolite monovalent metals are replaced by a multivalent metal ion and / or ammonium salt, followed by heating to split the ammonium ions bound to the zeolite, leaving ions in their place hydrogen and / or exchange sites that would actually be decationed by further removal of water. Hydrogen or "decationized" Y zeolites of this nature are described in more detail in US Pat. No. 3,130,006.

Mixed polyvalent metal-hydrogen zeolites can be prepared by exchanging the ion first with an ammonium salt, then by partial reverse exchange with a polyvalent metal salt, and then calcining. In some cases, as in the case of synthetic mordenite, hydrogen forms can be prepared by direct acid treatment of zeolites with an alkali metal. Preferred cracking bases are those that are at least 10 percent, and preferably at least 20 percent, metal cation deficient based on the initial ion exchange capacity. A particularly desirable and stable class of zeolites are those in which at least 20 percent of the ion exchange capacity is saturated with hydrogen ions.

The active metals used as hydrogenation components in the preferred hydrocracking catalysts of the present invention are Group VIII metals, i.e., iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium and platinum. In addition to these metals, other promoters can also be used in conjunction with them, including Group VIB metals, such as molybdenum and tungsten. The amount of hydrogenation metal in the catalyst can vary widely. In general, any amount between 0.05 and 30 wt.% Can be used. In the case of noble metals, it is usually preferable to use from 0.05 to 2 wt.%. A preferred method for combining the hydrogenation metal is to contact the zeolite base material with an aqueous solution of a suitable compound of the desired metal, in which the metal is present in cationic form. After adding the selected hydrogenating metal or metals, the resulting catalyst powder is then filtered, dried, tableted with added lubricants, binders or the like, if desired, and calcined in air at a temperature of, for example, 371 ° -648 ° C (700 ° -1200 ° F) to activate the catalyst and decomposition of ammonium ions. Alternatively, the zeolite component may be preformed first, followed by the addition of a hydrogenating component and activation by calcination. The aforementioned catalysts can be used in undiluted form, or the zeolite powdery catalyst can be mixed and tableted together with other relatively less active catalysts, diluents or binders, such as alumina, silica gel, aluminosilicate clogs, activated clays and the like, in ratios, stacking between 5 and 90 wt.%. These diluents may be used as such or they may contain a small proportion of the added hydrogenation metal, such as a metal of group VIB and / or group VIII.

Hydrocracking catalysts promoted with an additional metal, which may also be used in the process of the present invention, include, for example, aluminophosphate molecular sieves, crystalline chromosilicates and other crystalline silicates. Crystalline chromosilicates are more fully described in US Pat. No. 4,363,718 (Klotz).

Hydrocracking of a hydrocarbon-containing feed in contact with a hydrocracking catalyst is carried out in the presence of hydrogen, and preferably in a hydrocracking reactor, which includes a temperature of 260 ° C (500 ° F) to 426 ° C (800 ° F), a pressure of 7.0 MPa (1000 lb / ⁱⁿ²⁾ to 10.5 MPa (1500 lb / ^in2), a liquid hourly space velocity (LHSV) of from 0.1 to 30 h ^-1 and a hydrogen circulation rate of from 2000 (337 normal m ³ / m ³⁾ to 25,000 (4,200 normal m ³ / m ³ ) standard cubic feet per barrel.

The resulting stream leaving the hydrocracking zone is preferably contacted with an aqueous stream to dissolve any ammonium salts and partially condensed, and then introduced into a liquid and high pressure vapor separator operating at a pressure substantially equal to the pressure in the hydrocracking zone and a temperature in the range 38 ° C (100 ° F) to 71 ° C (160 ° F). The water stream is recovered from the liquid and steam separator. The hydrogen-rich gas stream is removed from the liquid and steam separator so as to ensure that at least most and preferably all of the hydrogen is introduced into the hydrocracking zone.

In one embodiment of the present invention, a hydrocarbon distillate boiling at a temperature of more than 149 ° C (300 ° F) is introduced into the desulfurization zone together with a hydrogen-rich make-up stream under desulfurization conditions. Preferred desulfurization conditions include a temperature of 260 ° C (500 ° F) to 426 ° C (800 ° F), pressures from 7.0 MPa (1000 lb / ⁱⁿ²⁾ to 10.5 MPa (1500 lb / ⁱⁿ²⁾ and hourly volumetric fluid velocity from 0.1 hours ^-1 to 10 hours ^-1 .

Suitable desulfurization catalysts for use in the present invention are any known desulfurization catalysts and include those which consist of at least one Group VIII metal, preferably iron, cobalt and nickel, more preferably cobalt and / or nickel and at least one Group VI metal, preferably molybdenum and tungsten, on a support material with a high surface area, preferably alumina. Other suitable desulfurization catalysts include zeolite catalysts as well as noble metal catalysts, where the noble metal is selected from palladium and platinum. It is within the scope of the present invention that more than one type of desulfurization catalyst is used in the same reaction vessel. Two or more catalyst beds and one or more cooling steps may be used in the reaction reactor or reactors. Group VIII metal is usually present in an amount ranging from 2 to 20 wt.%, Preferably from 4 to 12 wt.%. Group VI metal is usually present in an amount ranging from 1 to 25 wt.%, Preferably from 2 to 25 wt.%.

The resulting effluent from the desulfurization reaction zone is contacted with the water stream and partially condensed, and then introduced into the previously described liquid and high pressure vapor separator.

Fresh hydrogen feed is introduced directly into the desulfurization reaction zone to supply high purity hydrogen to maximize the activity of the desulfurization catalyst. In a preferred embodiment, at least a large portion of the hydrogen-rich recycle gas that is recovered in the liquid and high pressure vapor separator is returned to the hydrocracking zone, and more preferably substantially all of the hydrogen-rich recycle gas is returned to the hydrocracking zone.

Detailed description of the figure

In the figure, the method of the present invention is illustrated by means of a simplified process flow diagram from which details such as pumps, equipment, heat exchangers and heat recovery circuits, compressors and similar technical means are excluded as being not essential for understanding the implied techniques. The use of such mixed equipment is well known in the art.

In the figure, the hydrocarbon distillate feed is introduced into the process through line 3 and mixed with a fresh feed stream of hydrogen, which is introduced through line 1. The resulting mixture is transported through line 4 and introduced into the hydrodesulfurization reaction zone 5. The resulting effluent from the hydrodesulfurization reaction zone 5 is transmitted along the lines 6 and 8 and is introduced into the low-temperature high-pressure separator 9. The hydrogen-rich gas stream is removed from the low-temperature high-pressure separator 9 via line 10 and introduced into the compressor rub 11. The resulting compressed hydrogen-rich gas stream is transported along lines 12 and 14 and mixed with the light catalytic cracking oil feed fed through line 16, and the resulting mixture is transported along line 2 and introduced into the hydrocracking zone 17. The resulting effluent from the hydrocracking zone 17 transferred through lines 7 and 8 and introduced into the low-temperature high-pressure separator 9. Another hydrogen-rich gas stream is introduced via line 15 into the hydrodesulfurization reaction zone 5. Another hydrogen-rich gas th stream is introduced via line 13 into hydrocracking zone 17 for cooling. The liquid hydrocarbon stream is removed from the low temperature high pressure separator 9 via line 18 and introduced into the low pressure evaporation drum 19. A gas stream containing hydrogen and low boiling gas hydrocarbons is removed from the low pressure evaporation drum 19 via line 20 and is recovered. The liquid hydrocarbon stream is removed from the low pressure evaporation drum 19 via line 21 and introduced into the rectification zone 22. Typically, the gaseous hydrocarbon stream is removed from the rectification zone 22 via line 23 and recovered. The high octane naphtha stream is removed from the rectification zone 22 via line 24 and recovered. The high octane naphtha stream may be recovered from the distillation zone 22 in any convenient manner and is preferably lateral, as shown in the drawing. The low sulfur diesel stream is removed from rectification zone 22 via line 25 and recovered.

The method of the present invention is described below using the following illustrative embodiment. This illustrative embodiment does not limit the method of the present invention, but further explains the advantages of the embodiment described above. The following examples illustrate the effectiveness of the present invention.

An example implementation of the method

A mixture of straight-run diesel fraction and light coking gas oil (LCGO) in an amount of 4372 m ³ / day (27500 barrels per day) and having the indicators shown in Table 1 is introduced together with a high-purity hydrogen feed stream into the hydrodesulfurization reaction zone operating under hydrodesulfurization conditions summarized and presented in Table 2.

The flow of light catalytic cracking oil FCC (LCO) in an amount of 3657 m ³ / day (23000 barrels per day), having the indicators shown in Table 1, is introduced into the hydrocracking zone, operating under the conditions summarized and presented in Table 2.

The resulting effluent from the hydrodesulfurization reaction zone and the hydrocracking zone is cooled, partially condensed and introduced into the low temperature separator liquid and high pressure vapor, operating at 9.7 MPa (1400 lb / ⁱⁿ²⁾ and a temperature of 43 ° C (110 ° F) for obtaining a recycle stream of hydrogen-rich gas and a stream containing liquid hydrocarbons. The hydrogen-enriched gas recycle stream is returned to the hydrocracking zone, and the liquid hydrocarbon containing stream is fractionated to produce a high-octane naphtha (gasoline) stream boiling in the range from 88 ° C (185 ° F) to 193 ° C (380 ° F), the amount of 2145 m ³ / day (13500 barrels per day) and having an octane rating of 87, and the flow of diesel fuel boiling at a temperature of more than 193 ° C (380 ° F) in the amount of 5500 m ³ / day (34500 barrels per day) and having a sulfur content <10 ppm and cetane index 46.

TABLE 1 Feedstock Analysis Diesel fraction / LCGO Light catalytic cracking oil Specific gravity 0.87 0.96 The total sulfur content, wt.% 2 one The total nitrogen content, mass. ppm 725 900 Distillation, ° C (° F) Initial Boiling Point (IBP) 146 (295) 215 (420) 10% 222 (432) 263 (506) fifty% 278 (543) 304 (580) 90% 336 (638) 349 (660) Boiling Point (EP) 390 (735) 371 (700)

TABLE 2 OPERATING MODE Hydrodesulfurization Hydrocracking Pressure, MPa (lbs / ⁱⁿ²⁾ 9.7 (1400) 9.7 (1400) Temperature ° C (° F) 371 (700) 371 (700)

The preceding description, figure, and illustrative embodiment clearly explain the advantages encompassed by the process of the present invention and the advantages provided by its application.

Claims (10)

1. The method of producing low sulfur diesel fuel and high octane naphtha, which includes
a) the interaction of the raw hydrocarbon distillate having a boiling point of more than 149 ° C (300 ° F) and a gaseous stream enriched with hydrogen feed in the hydrodesulfurization reaction zone containing the desulfurization catalyst to obtain an effluent from the hydrodesulfurization reaction zone containing low hydrocarbons sulfur concentration;
b) the interaction of highly aromatic, substantially dealkylated hydrocarbon feedstocks in the hydrocracking zone containing the hydrocracking catalyst to produce an effluent from the hydrocracking zone containing monocyclic aromatic compounds boiling in the naphtha range;
c) mixing the stream exiting the hydrodesulfurization reaction zone and the stream exiting the hydrocracking zone to obtain a mixture stream; and
g) separating the mixture obtained in stage c) to obtain a gas stream enriched with hydrogen, a stream of low sulfur diesel fuel and a stream of high octane naphtha. 2. The method according to claim 1, in which the resulting mixed stream of the effluent from the hydrodesulfurization reaction zone and the effluent from the hydrocracking zone is introduced into a liquid and high pressure vapor separator to produce a hydrogen-rich gas stream and a mixture containing liquid hydrocarbons from the stream, exiting the hydrodesulfurization reaction zone, and a stream exiting the hydrocracking zone. 3. The method according to claim 1, in which most of the hydrogen-rich gas stream from stage g) is returned to the hydrocracking zone, while the hydrogen-enriched gas stream contains hydrogen both from the effluent of the hydrodesulfurization reaction zone and from the effluent of the hydrocracking zone . 4. The method according to claim 1, in which the highly aromatic, largely dealkylated hydrocarbon feedstock contains hydrocarbons boiling in the range from 149 ° C (300 ° F) to 343 ° C (650 ° F). 5. The method according to claim 1, in which the hydrocarbon distillate feed, having a reduced hydrocarbon content of the naphtha range, boils in the range from 149 ° C (300 ° F) to 399 ° C (750 ° F). 6. The method of claim 1 wherein the hydrodesulfurization reaction zone pressure is from 7.0 MPa (1000 lb / ⁱⁿ²⁾ to 10.5 MPa (1500 lb / ⁱⁿ²⁾ and a temperature of - 260 ° C (500 ° F) up to 426 ° C (800 ° F). 7. The method according to claim 1, wherein the highly aromatic, substantially dealkylated hydrocarbon feedstock comprises light catalytic cracking oil. 8. The method of claim 1, wherein the pressure in the hydrocracking zone is from 7.0 MPa (1000 lb / ⁱⁿ²⁾ to 10.5 MPa (1500 lb / ⁱⁿ²⁾ and a temperature of - 260 ° C (500 ° F ) up to 426 ° С (800 ° F). 9. The method according to claim 1, in which stage (g) is carried out in at least one rectification zone, in which the high-octane naphtha stream is separated from the hydrocarbon content of the mixture of the effluent from the hydrodesulfurization reaction zone and the effluent from the hydrocracking zone. 10. The method according to claim 1, in which essentially all of the hydrogen-rich gas stream from stage (g) is returned to the hydrocracking zone.

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