JPH03131685A - Method of slurry type hydrogenation - Google Patents

Abstract

PURPOSE: To retain high catalytic activity by reacting a heavy fossil fuel, with hydrogen in the presence of a hydrogenation catalyst, separating the catalyst from the product thus obtained and then regenerating the separated catalyst to recycle.

CONSTITUTION: A heavy fossil fuel such as petroleum, coal, shale oil, bitumen oil, etc., is subjected to hydrogen treatment in the presence of a hydrogen treating catalyst containing a non-noble metal such as molybdenum sulfide, Ni, Co, etc., under the conditions that the temperature is about 343.3-415.6°C and the pressure is 56.2-281.3 kg/cm². Then, the catalyst is separated from the hydrogenated product and is subjected to hydrogen stripping for regeneration under the conditions that the temperature is about 341,3-415.6°C and the pressure is 56.2-281.3 kg/cm² and the regenerated catalyst is recycled to the hydrogen treating zone.

COPYRIGHT: (C)1991,JPO

Description

[Detailed Description of the Invention] [Industrial Application Field] The present invention is directed to vacuum gas oil
s) and heavy gas oils
The present invention relates to a method of using a catalyst slurry used in the hydroprocessing of heavy fossil fuel raw materials such as More specifically, the present invention relates to a method of maintaining high catalyst activity by circulating the catalyst between a hydrotreating zone and a hydrogen stripping zone.

[Conventional technology]

In the petroleum industry, heavy vacuum gas oils, particularly coker gas oils, are subjected to hydrotreating to make them suitable as liquid catalytic cracking (FCC) feedstocks. Hydrotreating saturates polycyclic aromatics to produce monocyclic aromatics or fully saturated naphthenic compounds. In catalytic cracking, it is important to establish a technology that maintains a low degree of coking (and a high production rate of gasoline). Polycyclic aromatic compounds are not effectively decomposed into products such as mogas and heated oil.Hydrotreating also has an inhibitory effect on the decomposition process. It can remove sulfur and nitrogen.

Catalysts used in hydroprocessing tend to be poisoned by organic nitrogen compounds in the feedstock. This compound adsorbs onto the catalyst and covers the active sites necessary for the hydrogenation reaction, causing the hydrogenation reactor to drop or shut down. This problem can be solved by raising the temperature to a higher temperature; however, at high temperatures, polycyclic aromatic compounds tend to remain unreacted and undesirable thermodynamic equilibrium tends to occur.

The present invention aims to avoid the reaction rate and equilibrium limit problems encountered in conventional hydroprocessing processes using fixed bed catalysts. It is a further object of the present invention to provide an improved hydroprocessing process using a slurry catalyst. The present invention furthermore aims to provide a method for regenerating the catalyst used in the process according to the invention by hydrogen stripping in a substantially continuous circulation mode.

Compared to the process of the present invention, it has been found that hydrogen stripping of the catalyst in a conventional fixed bed reactor only temporarily activates the catalyst, and its activity is only 2. Therefore, in fixed-bed hydrotreating methods, reactor operation must be stopped frequently to perform effective hydrogen stripping. This is necessary and would be a waste of money.

On the other hand, a hydrotreating method using a slurry of a dispersed catalyst in which the catalyst is mixed with hydrocarbon oil is known. For example, US Pat. No. 4.557.821 (Lopez et al.
pez et al.) disclose a method for hydrotreating heavy oil using a circulating slurry catalyst, and other publications include U.S. Pat. (No. 115 discloses a slurry hydrotreating method.

[Problem to be solved by the invention]

Various problems exist in the slurry hydrotreating methods disclosed in the prior literature, which clearly hinder commercialization. For example, U.S. Pat. No. 4.557,821;
Nos. 2.912.375 and 2.700. (According to the method disclosed in No. 115, the catalyst needs to be regenerated by air oxidation, but air oxidation requires an expensive locked hopper and hydrogen The need to depressurize the catalyst space between the treatment reactor and the regenerator is expensive, and expensive equipment is required to avoid the formation of airborne impurities and the risk of explosion.

[Means to solve the problem]

The present invention is intended to provide a method for maintaining high catalytic activity in a slurry-type hydrotreating method for heavy fossil fuels. Boiling point petroleum or synthetic fuel is contacted with a particulate hydroprocessing catalyst. The catalyst is circulated between the hydrotreating reaction zone and the hydrogen stripping catalyst regeneration zone.

Various objects in addition to those mentioned above are achieved by the present invention. The present invention comprises: (1) reacting a heavy fossil fuel with hydrogen in a hydrotreating zone in the presence of a hydrotreating catalyst; (2) separating the catalyst from the hydrogenation product in the hydrotreating zone; ) regenerating the catalyst by hydrogen stripping in a catalyst regeneration zone; (4) recycling the regenerated catalyst to the hydroprocessing zone.

The present invention provides a method for recycling the catalyst used in the hydroprocessing zone.
It is contemplated to provide a slurry hydrotreating process which is regenerated by hydrogen stripping, preferably in a continuous process.

The catalyst is regenerated in a catalyst regeneration zone separate from the hydroprocessing zone and recycled to the hydroprocessing zone. Furthermore,
A new catalyst or a regenerated (reactivated) catalyst can be continuously added while removing or regenerating the catalyst whose activity has decreased or has been deactivated from the system. Because the catalyst is constantly being regenerated according to the process of the present invention, slurry hydroprocessing processes require more severe conditions (such conditions tend to deactivate the catalyst) than in conventional fixed bed hydrogenation processes. Hydrotreating can be carried out using a certain amount of potash.In conventional fixed bed hydrotreating, the hydrotreating unit is usually shut down after about one or two years of operation to replace the catalyst. In the slurry hydrotreating method of the present invention incorporating catalyst regeneration, the activity of the catalyst is improved compared to fixed bed hydrogenation.

It should be noted that the hydroprocessing process of the present invention, which regenerates the catalyst by stripping the hydrogen, reduces the permanent deactivation of the catalyst that occurs in conventional fixed bed hydrogenation processes. This permanent deactivation of the catalyst is believed to be due to coking resulting from the polymerization reaction and metal deactivation caused by the presence of organometallic compounds present in the feedstock. Such polymerization reactions can be prevented by periodically removing the raw materials adsorbed on the catalyst with hydrogen to regenerate the catalyst.

The slurry hydrotreating method of the present invention uses catalytic cracking recycled heavy oil (
It is capable of processing a wide variety of feedstocks including fossil fuels such as HCCO), coke oven gas oil, -' and vacuum gas oil (VGO). oil, coal, bichkomen,
Tar sands, or similar gas oils fractionated from sier oil, are suitable feedstocks for the process of the present invention.

Raw materials suitable for the treatment method according to the invention are 260-648
．． in the range of 96C (500-1200'F), preferably 343.3-593.3C (650-1100'F)
It includes distillate gas oils that are distilled at temperatures in the range of . 6
For fractions with temperatures above 48.9°C (1200°F), it is difficult to remove all the raw materials adsorbed on the catalyst with hydrogen.
Otherwise, the catalyst will be covered with coke. Additionally, concarbon and asphaltenes deactivate the catalyst. The feedstock used in this invention should not have more than 10% boiling above 565.6'C (1050°F). The nitrogen content in the raw material is usually greater than 1500 ppm. Aromatic components of 3 or more ring systems will usually be present at 25% by weight or more. The polar aromatic compound is usually present in an amount of 5% by weight or more, and the concarbon is present in an amount of 1% by weight or more.

Catalysts used in the process of the invention are well known in the art and include molybdenum sulfide and Ni, Mo, Co
Examples include, but are not limited to, mixtures of sulfides of transition metals such as , Fe, W, and Mn. Typical catalyst combinations include NiMo, %CoMo,
Or CoN1M.

- For boat fishing, sulfides of group I metals are suitable (the periodic table cited here was published in 1964 by the Chemical Rubber Publishing Company of Cleveland, Ohio). "Handbook at Chemistry"
and Physics), 45th edition). These catalyst raw materials may be used alone, or alumina,
Inorganic oxides such as silica, titania, silica alumina, silica magnesia and mixtures thereof can be used as supports. Heptaolide such as USY, aluminized CAB-〇-8I L (aluminate
Acid microcarriers (a
cid mlcro 5upports) can be used by appropriately mixing with these carriers.

Catalysts prepared in situ from soluble precursors such as Ni and Mo naphthenates or phosphomolybdates are suitable.

In general, catalyst particles have a diameter of 1 μ to 3.18 mm (1
μ to 1/8 inch). Preferably, the diameter of the catalyst particles is in the range l -400μ to minimize or ignore intraparticle diffusion limitations during hydroprocessing.

When using a supported catalyst, the transition metal such as Mo should be 5 to 3
Suitably it is present in a proportion of 0% by weight, preferably 10-20% by weight. Active metals such as Ni and/or CO are generally present in proportions of 1 to 15% by weight.

The surface area of the catalyst particles is about 80~400r&g, preferably 150~300rr> /g is suitable.

The catalyst can be prepared by known methods. Typically, alumina supports are prepared by mixing an alkaline aqueous solution of aluminate with an acidic reagent to precipitate the alumina in a hydrated form.
This precipitate of hydrated alumina forms a slurry, which is concentrated and usually subjected to spray drying to obtain a catalyst support. Subsequently, the carrier is impregnated with a catalytic metal and then fired. Suitable reagents and conditions for preparing carriers are described, for example, in U.S. Pat.
．． No. 398. To prepare catalysts with an average diameter of 200 microns or less, spray drying is generally considered the method of choice to obtain the final shape of the catalyst particles.

For example, the average diameter is approximately 0.794 to 3.18 marks (1/32
Extrusion methods are commonly employed to prepare large diameter catalysts (~1/8 inch). To prepare catalyst particles with average diameters ranging from 200μ to 0.794 mm (1/32 inch), the oil drop method was used.
thod) is preferred. The well-known oil drop process involves the preparation of alumina hydrosils, for example by reacting aluminum with hydrochloric acid to obtain hydrosils, which are treated with suitable gelling agents. The mixture is then dropped into an oil bath until hydrogel spheres are formed. Thereafter, the generated spheres are continuously collected from the oil bath, washed, dried, and fired. This treatment transforms the alumina hydrogel into the corresponding crystalline gamma-alumina. These particles are then impregnated with a metal catalyst and become spray dried particles. These treatments are described, for example, in U.S. Pat. No. 3,745.
No. 112 and No. 2.620.314.

In FIG. 1, a feed stream 1 consisting of, for example, a gas oil feed, is introduced into a slurry hydrogenation reactor 2, before which the feed stream 1 is typically mixed with a hydrogen-containing gas in stream 3 and then heated into a heating furnace. Alternatively, it is heated to the reaction temperature by the preheater 4. A stream of fresh hydrogen gas 30 can be introduced into hydrogen stream 3 , while it can also be mixed with feed stream I and in the hydroprocessing reactor 2 .

Hydrotreating reactor 2 contains about 10-70% by weight, preferably 40-60% by weight of catalyst in slurry form. In the embodiment shown in FIG. 1, - the feedstock is introduced from the bottom of the hydrogenation reactor 2 and
ing) or bubbled into the reactor through a fluidized bed.

Depending on the catalyst, the inlet of the hydroprocessing reactor and/or
Alternatively, a filter may be provided at the outlet. A flare may be provided to prevent catalyst particles from escaping over the outlet when the reactor is operated at a minimum flow rate.

Although the process of the present invention can be carried out in a single slurry hydrotreating reactor, to carry it out more efficiently, two or It is carried out using more than one reactor.

Thus, one or more stages of low temperature treatment can be followed by high temperature treatment. For example, 404.4℃ (
The fresh feedstock can be processed at 7606F) and the first stage product can be processed at 382, 28C (720°F). First, the first stage is treated at 371.1°C (700°F) and the product is processed at 393.3°C (740°F) in the second stage.
°F) and further the product in a third stage at 415 °F.
Several stages of processing can be performed sequentially at lower temperatures, such as processing at 6°C (780°F). Such improvements increase the reaction rate of the first stage and lower the equilibrium level of polycyclic aromatics in the final stage (which provides a greater kinetic driving force). Staged treatment is particularly advantageous for the process of the invention compared to fixed bed hydroprocessing processes. This is because in the slurry method,
This is because heat exchange is good and thermal diffusion does not limit the reaction rate, making it possible to perform the first stage at a high temperature.

Referring again to FIG. 1, the fluid containing liquid and gas and substantially free of catalyst solids exiting the hydroprocessing reactor 2 passes via stream 5 to a cooler 6 and to a gas-liquid separator. Alternatively, it is introduced into the gas-liquid separation device 7. There, hydrogen gas along with ammonia and hydrogen sulfide, which are by-products of the hydrogenation reaction, are separated from the liquid product of stream 8. The gas in the separated stream 11 passes through the compressor 10 and returns to the hydrogen gas-containing stream 3 for reuse. In order to control the negative effects of hydrogen sulfide and ammonia on the hydroprocessing rate and to reduce the resulting corrosion, the recycled gas is typically passed through a scrubber to remove the hydrogen sulfide and ammonia.

In many cases, the liquid product of stream 8 is washed with dilute alkali to ensure complete removal of hydrogen sulfide.

If even a small amount of hydrogen sulfide remains in the product,
This is because when exposed to air, it oxidizes to elemental sulfur, which may exceed environmental pollution prevention standards or cause more corrosion of the equipment than was predicted by design.

To regenerate the catalyst in hydroprocessing reactor 2, the outlet stream containing catalyst solids is passed from the reactor as stream 12 to a filter, flash vacuum distiller, etc.
e flash), centrifuge, or similar solids separation device 14, where it is split into a catalyst stream 15 and a liquid stream 16, which is recycled via pump 17 to the hydroprocessing reactor 2.

The catalyst stream 15 separated by the solid separator 14 is
Contains about 30-60% by weight catalyst.

Optionally, the catalyst stream is diluted with a low boiling liquid, such as naphtha, to impart fluidity to the catalyst or to facilitate transport of the catalyst. Note that low-boiling liquids such as naphtha can be easily separated by distillation and can be reused. In any case, the catalyst material is conveyed to a removal reactor or regenerator 20. Hydrogen stream 22 is preferably heated in heater 21 before being introduced into regenerator 20 where the catalyst is subjected to hydrogen stripping. The regenerator produces a regenerated catalyst stream 23, which is recycled back to the hydroprocessing reactor 2. A catalyst that has lost its activity is
It is removed from stream 23 via line 24 and replaced with freshly prepared catalyst introduced into the feed stream via line 18. The regenerated catalyst generated in the regenerator 20 is 4
For 53.6g (11b) of gas oil feedstock, regenerated catalyst 2
It is appropriately returned to the hydrotreating reactor 2 at a rate of 2.7-21.8 g (0.05-0.51 bs).

Regenerator 20 produces a gas stream 25, which is
After exiting the regenerator 20, it passes through a cooler 26, a gas-liquid separator 27, a stream 13, and a hydrogen reuse stream 1.
Mixed with 1. Off-gas can also be discharged via line 29. The liquid separated by the gas-liquid separator 27 is
It can be returned to the hydroprocessing reactor 2 via stream 28.

The operating conditions of the process according to the invention depend to some extent on the particular raw material to be treated. The temperature of the hydrotreating zone of the hydrotreating reactor is approximately 343.3~415=J3℃ (
650-780°F), preferably 357, 2-398
．． 9°C (675-750'F) and the pressure is 56.3
~281.3 kg/cm2 (800~4000psi
g), preferably 105.5 to 175.8 kg/cm
2 (1500-2500 psig). Hydrogen treatment gas velocity is 1500-10. OOOSCF/B (Standard Cubic Feet/Versil), preferably 25”00~
5000 SCF/B. Space velocity or residence time (
WHS V, raw material (lb)/catalyst (lb)-hr) is
It is 0.2-0.5, preferably 0.5-2.0.

The temperature of the regeneration zone is approximately 343.3-415.6°C (6
50-780°F), preferably 357.2-398,
9°C (675-750°F) and the pressure is approximately 56°C.
3~281.3kg/cm2 (800~4000psi
g), preferably lO5.5 to 175.8 kg
/cm2 (1500-2500 psig). The stripping rate for treating 453.6 g (l lb) of catalyst is 8.50 X 10-4 to 1.98 X 10
-'rn'/hr (0,03~7SCF/lb
cat-hr), preferably 4.25X10-4,
25 X 10-'rr1'/hr co, 15-1
．． 5 SCF/1bcat-hr).

〔Example〕

In order to explain the slurry hydrogenation treatment method which is the first step of the present invention, the following experiment was conducted. KF-840, a commercially available hydroprocessing catalyst, was ground and passed through a 32/42 mesh sieve. The characteristics of the catalyst are shown in Table 1. This pulverized catalyst was reacted overnight with hydrogen gas containing 10% hydrogen sulfide gas to form a sulfide, and 3 g of the IO was mixed with heavy vacuum gas oil, heavy coke oven gas oil, coke oven residue (c
kerbottoms) and catalytic cracking recycled heavy oil 100TLI! together with 300m2
! volume autoclave under stirring. The quality of the raw materials is listed in Table 2.

Table 1 N i O, weight % M o Os , weight % p20. , weight% Surface area, resistance/g Pore volume, cJl/g 3.8 19.1 6.4 75 0.38 Sulfur content 4% by weight Nitrogen content 9% by weight Carbon content 2% by weight Hydrogen content 1% by weight Specific gravity, 'API Measured by HPLC 1% by weight Saturated compounds Monocyclic aromatic compounds Bicyclic aromatic compounds Aromatic compounds with 3 or more rings Polar aromatic compounds 1.63 0.39 87, 6 3 9. 60 9.2 GC fraction, 'C (()' F) 5% 3 51.7
(665) 20% 4 00
．． 6 (753)50%
472.2 (882) 80%
540.0 (1,004)95%
621.1 (1150) 8” 4
．． Under 4 kg/cd (1200 psig) hydrogen pressure,
The autoclave was heated to 720°F. The autoclave was operated in gas flow to continuously introduce hydrogen treatment gas while releasing gaseous products. Hydrogen gas was passed through the entire stroke of the apparatus such that the sum of the initial hydrogen gas and fresh hydrogen gas was equal to 3500 SCF/B of liquid charged to the autoclave. After reacting under these conditions for 2 hours, the autoclave was quickly cooled to stop the reaction.

After releasing the pressure, the reaction solution was filtered to obtain a liquid product, and HD
Analysis was conducted to measure the extent of S (hydrodesulfurization reaction), HDN (hydrodesulfurization reaction), and aromatic hydrogenation reaction.

On the other hand, 30.9 g of the same catalyst used in the above experiment was added to a two-legged autoclave along with 100 g of the raw material used in the above experiment, and treated under the same conditions as in the above experiment. The results are shown in Table 3 together with the results of the above experiment.

Ju-ichi 1 Weight% (based on raw materials) 0.0 10.5 31.5
I1m% Sulfur 1.63 0.32 0.10
Nitrogen 0.39 0.22 0.093
S-1-IR345566 <3R+P 55 28 1
8P 12 4.1
1.2S: Saturated compound lR: Monocyclic aromatic compound<3R: Aromatic compound with 3 or more ring systems P: Polar aromatic compound From these results, fresh catalyst slurry contains organic sulfur compounds from the heavy raw material blend. It can be concluded that it is very effective in removing organic nitrogen compounds. Even if the amount of catalyst added is only 10% of the new raw material, the organic sulfur compound will increase to 20% with unreacted raw material remaining.
Organic nitrogen compounds have been reduced to 55%, and aromatic compounds with three or more rings have been reduced by half. Even the polar aromatic compound with the highest boiling point was reduced by 17/3. When the amount of catalyst added was increased to 31% of the fresh feed, a high level of impurities was removed. That is, organic sulfur compounds are reduced to 6%, organic nitrogen compounds are reduced to 1/4, and high-boiling aromatic compounds are reduced to 1/3. Polar aromatic compounds have also been reduced to 10% of the raw materials used.

The following experiment was conducted to illustrate the second stage of the present invention, which involves a catalyst regeneration step with 3Bq main hydrogen. Example 1 of the present invention No. 1
A hydrogenation experiment was conducted under the same conditions as the second experiment in step 2, and the catalyst taken out from the autoclave after the reaction was stripped with a H2S/H2 mixed gas at 343.3°C (650°F) for 18 hours.

After the first gas treatment in the autoclave, the catalyst has an amount equivalent to 3.6% after hydrogen stripping.
"coke" or hydrocarbons were deposited. Actually 30
．． This catalyst, which is 9 g of NiMo/alumina catalyst, 32
．． 0 g of the same raw material used in Example 1, 100 m/
The mixture was also charged into a 300-liter autoclave, and operated under the same conditions as in Example 1 for 17 days. After completion, the catalyst was filtered off from the product and stripped again with hydrogen for further use. This operation was repeated until the analytical value of the catalytic hydrogenation product was outside a certain level.

The autoclave was operated under the same conditions as in Example 1, and the catalyst taken out therefrom was collected by filtration, and then filled into the autoclave again with the same raw materials used in Example 1 to carry out a hydrogenation reaction. In this way, the filtered catalyst was repeatedly used as is in order to obtain an overview of the performance of the catalyst without hydrogen stripping. The above experimental results are shown in Table 4.

Table 4 Catalyst type Strip-tub treatment Amount of untreated catalyst added in weight% (based on raw material) 31.5 31.5 Quality of product 1% by weight Sulfur 0.10 0.i2Nitrogen
0.093 0.18S + i R6
461 <3R+P 18 23P
1.2 2.7 From the above results, it is clear that the repeatedly reused catalyst (well, still similar to the hydrogenation reaction of aromatic compounds) has high activity for desulfurization and denitrification reactions and Although the catalytic activity for denitrification reactions and hydrogenation reactions of high-boiling aromatic components has decreased somewhat, the newly prepared catalyst It takes one summer to bring the catalyst activity to a similar level.

Example 3 To further illustrate the hydrogen stripping catalyst regeneration method,
The following experiment was conducted. The feedstock was treated in a fixed bed reactor for several hundred hours using the same commercially available catalyst used in Examples 1-3 in large amounts. Before removing the catalyst, 371
．． Storing with hydrogen gas for several hours at 7°C (700°F)]7. After removing the catalyst from the fixed bed reactor, a portion of it was crushed and passed through a 32/42 mesh sieve.

This catalyst had 21.2% coke or hydrocarbon deposits. 39.2 g of this catalyst, essentially 30.9 g of NiMo/alumina catalyst, was charged into an autoclave with the same raw materials used in the previous examples.

After the reaction was completed, the catalyst was collected by filtration and reused several times in order to obtain an overview of the performance of this catalyst. Table 5 shows the results of these experiments for catalysts that were repeatedly reused after hydrogen stripping and for catalysts that were simply filtered and reused.
It was shown to.

Relationship between the type of catalyst and the quality of the product [St. 13) Whet treatment Amount of untreated catalyst added in weight% (based on raw material) 31.5 31.5 Product quality 9% by weight Sulfur content 0.20 0 .25 nitrogen content
0.14 0.27S+IR6256 <3R+P 25 29P content
3.6 5.2 From the above results it can be concluded that the hydrogen-stripped catalyst is less active than the fresh catalyst, but substantially more active than the non-hydrogen-stripped catalyst. On the other hand, catalysts that are repeatedly reused without hydrogen stripping lose much of their activity.

Thus, the method of the present invention has been disclosed in a fishing boat and by way of specific example only for the purpose of clarifying and illustrating the invention. From the foregoing it will be apparent to those skilled in the art that various modifications to the methods described herein may be made without departing from the spirit and scope of the invention.

[Brief explanation of the drawing]

FIG. 1 shows an example of a process diagram illustrating the method of the present invention, which includes a slurry hydrotreating step and a catalyst regeneration step by hydrogen stripping.

Claims (1)

[Scope of Claims] (1) A method for hydrotreating heavy fossil fuels for hydrogenating high-boiling aromatic compounds and desulfurizing sulfur components, in the presence of a hydrotreating catalyst containing a non-noble metal. , reacting the heavy fossil fuel with hydrogen in a hydroprocessing zone; separating the catalyst from the hydrogenation product in the hydroprocessing zone; hydrogen stripping the catalyst in a catalyst regeneration zone separate from the hydroprocessing zone; and recycling the regenerated catalyst to the hydroprocessing zone. (2) The temperature of the catalyst regeneration zone is approximately 343.3°C to 415°C.
．． 6°C (650-780°F) and a pressure of about 56°C.
2~281.3kg/cm^2 (800~4000ps
ig).The method according to claim (1). (3) The temperature of the hydrotreating zone is approximately 343.3 to 415
．． 6°C (650-780°F) and a pressure of about 56°C.
2~281.3kg/cm^2 (800~4000ps
ig).The method according to claim (1). 4. The method of claim 1, wherein the heavy fossil fuel is the product of a conversion process of petroleum, coal, shale oil, bitumen, tar sands, or synthetic fuels. (5) The method according to claim (1), wherein the heavy fossil fuel is catalytic cracking recycled heavy oil, coke oven gas oil, or vacuum gas oil. (6) Heavy fossil fuel is 260-648.9℃ (500-1
200°F).
1) The method described. (7) Claim (1) encompassing a multi-stage hydrotreating zone
) method described. (8) Claim (1) wherein the catalyst comprises molybdenum sulfide.
Method described. (9) The method according to claim (8), wherein the catalyst contains nickel and/or cobalt. (10) Claim in which the catalyst is supported on an inorganic oxide (
9) The method described. (11) Inorganic oxides include alumina, silica, titania,
The method according to claim 10, wherein the material is selected from the group consisting of silica alumina, silica magnesia, and mixtures thereof. (12) The average diameter of the catalyst is 10μ to 3.18
The method according to claim 1, wherein the thickness is 10 μm to 1/8 inch. (13) The method according to claim (1), wherein the average diameter of the catalyst is 10μ to 400μ. (14) The method according to claim (1), wherein the surface area of the catalyst is 80 to 400 m^2/g. (15) The pressure in the catalyst regeneration zone is between 105.5 and 175.
The method according to claim 1, wherein the pressure is 8 kg/cm^2 (1500 to 2500 psig). (16) The hydrogen stripping rate was 453.6 g of catalyst (
4.25 x 10^-^3~1.98 x 10 per 1lb)
^-^1m^3/hr (0.15~7SCF/lbca
t-hr).The method according to claim (1). (17) 453.6 g (1 lb) of raw material, 453.6 g (1 lb) of regenerated catalyst
A method according to claim 1, wherein the circulation is carried out at a rate of 5.4 to 136.1 g (0.1 to 0.3 lbs). (18) A method for hydrotreating heavy fossil fuels, the method comprising reacting heavy fossil fuels with hydrogen in a hydrotreating zone in the presence of a hydrotreating catalyst; in the hydrotreating zone at a temperature of about 343.3 to 415
．． 6°C (650-780°F), pressure approximately 56.2-28
4.25 x per 1 lb of catalyst under 1.3 kg/cm^2 (800-4000 psig)
10^-^3~1.98 x 10^-^1m^3/hr(
Regenerate the catalyst by stripping at a hydrogen gas rate of 0.15 to 7 SCF/lb cat-hr); and feedstock 453
．． 45.4 to 136.1 of regenerated catalyst per 6 g (1 lb)
recirculating to the hydroprocessing zone at a rate of 0.1 to 0.3 lbs. (19) The method according to claim (1), wherein the catalyst is regenerated by performing hydrogen stripping in a continuous circulation process. (20) The method according to claim (18), wherein the catalyst is regenerated by performing hydrogen stripping in a continuous circulation process.