Search Images Maps Play YouTube News Gmail Drive More »
Sign in
Screen reader users: click this link for accessible mode. Accessible mode has the same essential features but works better with your reader.

Patents

  1. Advanced Patent Search
Publication numberUS3923635 A
Publication typeGrant
Publication dateDec 2, 1975
Filing dateJun 17, 1974
Priority dateJun 17, 1974
Publication numberUS 3923635 A, US 3923635A, US-A-3923635, US3923635 A, US3923635A
InventorsAldridge Clyde L, Schulman Bernard L
Original AssigneeExxon Research Engineering Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Catalytic upgrading of heavy hydrocarbons
US 3923635 A
Abstract
Heavy mineral oils are upgraded by reaction with hydrogen in the presence of a catalyst comprising a solid carbon-containing material and an alkali metal component. The spent solids are reactivated in a catalytic gasification process.
Images(1)
Previous page
Next page
Claims  available in
Description  (OCR text may contain errors)

United States Patent Schulman et al. 1 Dec. 2, 1975 15 1 CATALYTIC UPGRADING F HEAVY 3.546.103 12/1970 Hamner ct al. 208/211 HYDROCARBONS 3.617.481 11/1971 Voorhies 6t 211. 3.715.303 2/1973 Wennerberg ct al. [751 Inventor B rn q m n, Golden, 3.726.791 4/1973 Kimberlin ct 111. 208/127 Colo.; Clyde L. Aldridge, Baton Rouge, La. [73] Assignee: Exxon Research & Engineering Co., Primary Examine" ld lerbert Linden, Attorney. Agent. or F1rmM. L. 6113130115 22 Filed: June 17, 1974 [21] Appl. No.: 479,745

[57] ABSTRACT [52] US. Cl. 208/50; 208/108; 208/127;

208/157 Heavy mineral 011s are upgraded by reaction with hy- 51 Int. c1. c100 13/02; c100 37/04 drogen in the-Presence of a Catalyst Comprising a Solid 5 Field of Search 208/50 127. 157, carbon-containing material and an alkali metal com- 3 208/] 10 1 l2 ponent. The spent solids are reactivated in a catalytic gasification process. [56] References Cited UNITED STATES PATENTS Claims, 2 Drawing Figures 3.541.002 11/1970 Rapp 208/157 T IS l4 US. Patent Dec. 2, 1975 Figure l Figure 2 CATALYTIC UPGRADING OF HEAVY HYDROCARBONS BACKGROUND OF THE INVENTION 1. Field of the Invention This invention relates to a combination catalytic hydrogen treatment for upgrading heavy mineral oils and regeneration of the catalyst. It particularly relates to catalytic hydrodesulfurization, hydroconversion and demetallization of heavy mineral oils and regeneration of the catalyst in an integrated coking and gasification process.

2. Description of the Prior Art U.S. Pat. No. 3,617,481 discloses a combination hydrotreatment, coking and gasification process in which alkali metal salts may be used in the coke gasification reaction.

U.S. Pat. No. 3,715,303 discloses a hydrotreating process utilizing an activated carbon and an alkali metal component or an alkaline earth component.

U.S. Pat. Nos. 2,481,300 and 2,379,654 disclose desulfurization processes utilizing catalysts comprising carbon and an alkaline compound.

U.S. Pat. No. 3,112,257 discloses catalytical desulfurization utilizing a catalyst containing an alkali metal component.

U.S. Pat. No. 3,775,294 discloses a process for hydrotreating whole crude oil followed by coking of the residuum material to obtain low sulfur coke.

U.S. Pat. No. 3,773,653 discloses hydrotreating of a hydrocarbon residuum in an ebullient bed.

It has now been found that a catalytic hydrogen upgrading of heavy mineral oils in combination with a gasification process wherein the catalyst is regenerated offers advantages which will become apparent in the following description.

SUMMARY OF THE INVENTION In accordance with the invention there is provided a process for upgrading a heavy hydrocarbon feed containing sulfur contaminants, which comprises: contacting said hydrocarbon feed with hydrogen and catalyst particles comprising a solid carbon-containing material and at least 2 weight per cent of an alkali metal component (calculated as the metal based on the carbon-containing material) in a reaction zone maintained at an average temperature ranging from about 700 to about 1000F. and at a hydrogen partial pressure of about 200 to about 4000 psig to produce a vaporous product comprising normally liquid light hydrocarbons of reduced sulfur content, a carbonaceous residue, at least a portion of said carbonaceous residue depositing on said catalyst particles, and heavy liquid hydrocarbons, removing from said reaction zone a slurry of at least a portion of said heavy liquid hydrocarbons and a portion of said catalyst particles; separating the catalyst particles from said slurry; contacting at least a portion of the separated catalyst particles with steam in a gasification zone operated at a temperature ranging from about l000 toabout 1700F., whereby at least a portion of the carbonaceous deposition is converted to a gas comprising hydrogen and carbon monoxide, and recycling a portion of the catalyst particles from the gasification zone to said reaction zone.

In one embodiment of the invention, the separation of catalyst particles from the slurry is effected in a fluid coking zone.

In the process of the present invention, the alkali metal-containing catalyst iscontinuously regenerated and freed of carbonaceous depositswhich occur.

BRIEF DESCRIPTION OF THE DRAWING FIG. 1 is a schematic flow plan of one embodiment of the invention.

FIG. 2 is a schematic flow plan of another embodiment of the invention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS Referring to FIG. 1, a sulfur-containing heavy hydrocarbon feed such as, for example, a petroleum residuum containing about 4 weight percent sulfur contaminants and weight ppm metal contaminants is mixed, in liquid phase, with an alkali metal-containing carbonaceous catalyst and is introduced via line 10 into an ebullient bed reactor 1. Although the ebullient bed reactor is preferred, other suspension flow systems in which a liquid-solids slurry can be contacted with a gas are also suitable. Although petroleum residuum will be used in the following description for simplicity of description, suitable sulfur contaminated hydrocarbon feeds include feeds having from about 2 weight percent to about 8 weight percent sulfur, such as hydrocarbon feeds containing at least 10 weight percent hydrocarbons boiling above 600F. at atmospheric pressure, preferably hydrocarbon feeds containing at least 10 weight percent hydrocarbons having a boiling point greater than 900F. at atmospheric pressure. The total metal content (vanadium, nickel, iron, etc.) of such feeds may range up to 2000 weight ppm and higher. Generally, these feeds will have a Conradson carbon content of about 3 to about 50 weight percent, preferably above 5 weight percent. By way of example, suitable hydrocarbon feeds include whole petroleum crudes; petroleum atmospheric residua; petroleum vacuum residua; heavy hydrocarbon oils and other heavy hydrocarbon residua; deasphalted residua; asphaltene fractions from deasphalting operations; bottoms of catalytic cracking process fractionator; cokerproduced oils; cycle oils, such as, catalytically cracked cycle oils; pitch, asphalt, and bitumen from coal, tar sands or shales which may include ash or particulates; naturally occurring tars as well as tars resulting from petroleum refining processes; shale oil; tar sand oils which may include sand or clay; hydrocarbon feedstreams containing heavy viscous materials, including petroleum wa fractions, etc.

The catalyst utilized in reactor 1 is a normally solid carbon-containing material comprising at least 2 weight percent alkali metal (calculated as the metal based on the carbonaceous material) preferably, from about 5 to about 20 weight percent alkali metal.

The term normally solid carbon-containing material is intended herein to designate a solid (at standard conditions) composition containing less than 1.5 hydrogen atoms per 1 carbon atom. Suitable carbon-containing materials for use at the start of the process include various, grades of coal, coal coke, petroleum coke, activated carbon, lignite, peat, graphite, and charcoal. Preferably, the solid carbon-containing material is petroleum coke.

The alkali metal carbon-containing catalyst may be prepared in several ways. It may be prepared by coking a hydrocarbon feed in the presence of an alkali metal compound or by impregnating a solid carbon-containing material with an alkali metal compound or by mixing a solid carbon-containing material with an alkali metal compound or in situ inthe process or in any other suitable manner.

Suitable alkali metal compounds for use in preparing the alkali metal-carbon containing catalyst include the carbonates, acetates, formates, sulfides, hydrosulfides, sulfites, sulfates, vanadates, oxides, and hydroxides of lithium, sodium, potassium, rubidium and cesium. Preferred alkali metal components are potassium, rubidium and cesium components, more preferably a potassium component.

Hydrogen is injected into reactor 1 via line 12. The oil-catalyst-hydrogen mix flows upwardly through reactor 1 with the catalyst being suspended in the oil. Reactor 1 is maintained at an average temperature ranging from about 700 to about 1000F., preferably from about 750 to about 900F., more preferably from about 775 to about 875F., a hydrogen partial pressure ranging from about 200 to about 4000 pounds per square inch gauge (psig), preferably from about 500 to about 3000 psig, more preferably from about 1000 to about 2000 psig.

The feed rate ranges from about 0.1 to about volumes of oil feed per volume of catalyst per hour and the hydrogen throughput ranges from about 1000 to about 15,000 standard cubic feet of hydrogen per barrel of feed, preferably from about 2000 to about 10,000 standard cubic feet of hydrogen per barrel of feed. The throughput rate of upflowing liquid and gas causes the mass of catalyst particles to become expanded and at the same time placed in random motion. The gross volume of the mass of catalyst particles expands when ebullated without, however, any substantial quantity of particles being carried out of the reactor by the upflowing fluids, and,-therefore, a well defined upper level of randomly moving particles establishes itself in the upflowing fluids. Although it is preferred to use an ebullient bed contacting system, other types of gas contacting liquidsolid slurries are also suitable. The hydrogen treatment reaction may be conducted in one or more stages. For example, reactor 1 may contain two or more zones in which the feed is successively treated with fresh catalyst. Alternatively, when the hydrogen treatment is carried out in more than one stage, the stages may be located in separate vessels. A. portion of the sulfur compounds present in the feed is converted to H 8. During the hydrogen treatment operation, a number of reactions occur which include desulfurization, demetallization, hydrogenation and conversion of a portion of the feed to lower boiling products. The vaporous lower boiling products, which include normally gaseous and normally liquid light hydrocarbon products, are removed overhead from reactor 1 via line 14 and sent to a conventional separator 2 which separates the gases from the liquid hydrocarbons. The gases are removed via line 16. The separated liquid hydrocarbons have a reduced content of sulfur and metals relative to the residuum feed and are removed via line 18.

During the hydrogen treatment in reactor 1, feed metals, sulfur and a carbonaceous residue (coke)'are deposited on the alkali metal-carbon containing catalyst. The accumulation of thesedeposits decreases the catalytic activity of the catalyst. To regenerate the catalyst, a slurry of alkali metal-carbon containing catalyst particles and heavier relative to the light liquid hydrocarbon products) liquid hydrocarbon products is removed from the bottom of reactor 1 via line 20 to separate the catalyst particles from the slurry so that the catalyst particles may thereafter be subjected to a steam gasification (regeneration) treatment.

The separation of the catalyst particles from the slurry may be carried out in several alternative methods. In one alternative, the slurry is passed to a separation zone where the liquid hydrocarbons-are removed from the catalyst particles, for example, by washing the slurry with a light oil (for example, coker oil). The separated catalyst particles may subsequently be passed directly to the steam gasification regeneration treatment. Alternatively, after the washing step, the separated particles may be sent to a devolatilization zone and subsequently subjected to a steam gasification regeneration treatment. The devolatilization of the separated catalyst particles may be conducted in a fluid bed drier, or in a fluidized bed of solid particles operated at conventional fluid coking conditions. The fluidized bed treatment serves to devolatilize the carbonaceous residue which is deposited on the catalyst particles and to form a harder, dry coke deposition.

In the embodiment of the invention shown in FIG. 1, the catalyst particles are separated from the slurry by subjecting the slurry of catalyst particles and heavy liquid hydrocarbons to a fluid coking zone. Returning to FIG. 1, if desired, additional alkali metal compound may be added to the slurry via line 22 or injected at other suitable points in the system. The slurry is then passed to a fluid coker reactor 3 which contains a fluidized bed of solid contact particles maintained at a temperature of about 850 to about 1200F., preferably, at about 950 to about 0F., and at a pressure of about 0 to about psig, preferably under 45 psig. The coker vaporous products are removed overhead via line 24. A stream of coker reactor bed solids is sent via line 26 to a catalytic gasifier 4 wherein steam via line 34 and an oxygen-containing gas, such as air or oxygen, via line 32 are introduced to gasify the coke deposition and thereby regenerate the deactivated alkali metal carbon-containing catalyst. The gasifier may be operated within a wide range of pressures depending on the desired gas product. Suitable pressures in the gasifier include a pressure ranging from about 0 to about 4000 psig, for example, a pressure of about 0 to about 200 psig, and a temperature ranging from about l000 to about 1700F., preferably from about 1200F. to about l500F. In the gasifier, the coke deposited on the alkali metal-carbon-containing catalyst reacts with the steam and oxygen-containing gas to produce a gaseous product comprising hydrogen and carbon monoxide which is removed from the gasifier via line 36. If desired, the hydrogen and carbon monoxide containing-gas formed in the gasifier can be sent to a conventional water-gas shift and purification stage to make substantially pure hydrogen which can be utilized for the hydrogen treatment step. A portion of the regenerated alkali metalcarbon containing catalyst is then recycled to reactor 1 via line 38. The recycled catalyst may be injected into reactor 1 with the residuum feed via line 10. If desired, a mixing vessel (not shown) may be placed in the line. Alternatively, the recycled catalyst may be introduced separately into reactor 1. Because of the higher operating temperature in the coker reactor and gasifier, there can be a net heat flow to the residuum and hydrogen stream. An other portion of the regenerated catalyst is passed to coker 3 via line 28 to provide a portion of the heat therein. If desired, a small portion of the regenerated catalyst stream may be purged from the system via line 30 to prevent metals build-up or a stream of catalyst could be purged from reactor 3 or from gasifier 4.

FIG. 2 illustrates an embodiment of the invention in which heat is provided in the system by circulating a stream of catalyst particles to an external heating zone. The FIG. 2 embodiment differs from that of FIG. 1 in that a stream of coker reactor 3 bed solids is sent via line 50 to a conventional burner to heat the solids to a higher temperature than the actual operating temperature of coker reactor 3, for example, from about 100 to about 800F. in excess of the actual coker operating temperature. The burner may be operated, for example, at a temperature between about l400 and l500F. Air is introduced into burner 5 via line 52 to oxidize a portion of the coke deposit to carbon oxides with a re sulting rise of temperature of the solids. A- stream of heated solids is withdrawn from the burner and passed via line 56 to a catalytic gasifier 4 maintained at a temperature between about 1000 and 1500F., for example, in this embodiment, between 1 100 and l200F. It should be understood that instead of heating the solids in a burner, the solids could be heated in other types of external heating zones by direct or indirect heat exchange. A stream of gasifier solids is recycled to burner 5 via line 58 for reheating. Steam is introduced into gasifier 4 via line 34. Optionally, oxygen may be introduced into the gasifier via line 32. In gasifier 4, at least a portion of the carbonaceous deposit of the alkali metal-containing catalyst reacts with the steam to form a hydrogen and carbon monoxide-containing gas (synthesis gas) and regenerated alkali metalcarbon containing catalyst. A stream of regenerated catalyst is removed from the gasifier via line 60. Part of the stream of the regenerated catalyst is passed via line 62 for recycle into the ebullient bed reactor with the residuum feed via line 10. An other portion of the regenerated catalyst is passed to coking reactor 3 via line 64 to pro vide heat to the coker. If desired, the hydrogen and carbon monoxide-containing gas formed in gasifier 4 can be removed overhead via line 66 and sent to a conventional water-gas shift and purification stage indicated at 6 where the carbon monoxide is converted to carbon dioxide by reaction with steam. Additional steam may be introduced via line 68, if desired. The carbon dioxide is removed via line 70 and a substantially pure hydrogen stream is removed from purification stage 6 via line 72. This hydrogen can be utilized as the hydrogen required for the hydrogen treatment which occurs in ebullient bed reactor 1. Thus, hydrogen can be passed from line 72 into line to mix with the residuum feed carried in line 10. Alternatively, the synthesis gas may be recycled as such to the ebullient bed reactor to provide at least a portion of the required hydrogen.

It should be understood that the hydrogen can also be produced in a similar manner from the gasifier effluent of the embodiment of the invention illustrated in FIG. 1.

EXAMPLE This example illustrates the hydrogen treatment reaction of the present invention.

Experiments were conducted utilizing various hydrocarbon feeds and activated potassium-coke as the solid catalyst. The potassium-coke was prepared as follows:

a batch of fluid petroleum coke to which was added 10 weight percent potassiumcarbonate was gasified with steam at a temperature of about 1 to about l240F. and a pressure of 200 psig until 30 to 35 weight percent of the coke was gasified. The resulting acti' vated potassium-coke contained 3.7 weight percent potassium (calculated as the metal). Ten weight percent potassium carbonate was added to this 3.7 weight percent potassium-coke and the mixture was heated for 2 hours at 1200F. in the absence of air. The resulting K- coke product contained 9.8 weight percent potassium (calculated as the metal) and will be designated hereinafter K-coke (A). The operating conditions and product yields and analyses are summarized in the following table. For some of the runs, additional potassium was provided in the catalyst by adding to K-coke (A) an additional 10 weight percent potassium carbonate and treating it at l300F. for 3 hours in the absence of air. This K-coke product contained 15.7 weight per cent potassium and will be designated hereinafter as K-coke (B). The hydrogen treatment experiments were carried out batchwise in a small (300 cc) magnetically stirred autoclave. The procedure was to pressure with hydrogen, then to heat up to reaction temperature within a period of approximately 45 minutes. The temperature was maintained for the indicated time, after which the autoclave was rapidly cooled, about 300F. per minute with an internal water coil.

The product gases from the autoclave were measured by wet test meter and the samples were analyzed by mass spectrometric analysis. From this, hydrogen consumption and gas yield were calculated. The excess gases were analyzed for H 8 by cadmium acetate scrubbers.

The oil and solids were separated. The solids were then dried in a vacuum oven at 302F. and oil pump pressure for an hour with periodic flushing of the vaporous space with nitrogen. The dried solids were weighed to determine the amount of remaining adsorbed material.

The coke yield was determined by a two-step procedure. First, the solids containing the adsorbed material were heated at 1000F. to drive off any gas or liquid plus any adsorbed moisture. The difference in weight remaining was taken as apparent coke yield. Second, because of the exposure to air, the resultant solids and the coke contained at least some of the potassium as hydroxide and carbonate. Correction for this was made by heating the solids at l300F. in the absence of air to restore the potassium to a degree of reduction which it had at the start of the treatment. The off-gas gases from this 1300F. treat were analyzed for carbon monoxide and carbon dioxide and the weight of the oxygen picked up incidentally from the air during handling was deducted from the apparent coke yield at 1000F. to give the corrected coke yield.

In runs 1 to 8, 60 cc. of solids weighing from about 52 to 57 grams were utilized in the autoclave.

Run 6 simulates the second stage of a two-stage hydrotreatment operation in which the oil is further contacted in the second stage with fresh 7 Run 7 simulates a first stage contacting of the feed in a staged hydrotreatment operation. As can be seen from the Table, the hydrogen treatment of the residuum feed with potassium-coke catalyst resulted in desulfurization of the liquid hydrocarbons, conversion of at least a portion of the asphaltenes of the feed, and demetallization of the liquid products. An other set of experiments in 7 which the ratio of K-eoke to oil feed in the hydrogen treatment was considerably lower than the ratio of K- coke to oil feed in Runs 1 to 8 was conducted and reported herein as Runs 9. and 1 1 In this set of experiments, first 90.01 grams of Jobo crude were treated under the indicated conditions over 28.88 grams cc.) of K-coke containing 15.7 weight percent potassium (calculated as the metal). After cooling and recovering the gas. the liquid product was decanted while protecting the solids from air with argon. Second, an additional 72.18 grams of the oil feed was treated over the same K-coke under the same conditions and separated in the same manner. Third, an additional 71.47 grams of oil feed was treated over the same K-coke under the same conditions and the oil separated. Each of the three oil products was analyzed and all were substantially identical in properties. The average analyses 19 treated in the presence of an alkali metal-coke catalyst in accordance with the present invention show more hydrogen consumption, less coke yield. lower sulfur content and lower Conradson carbon content of the liquid products and more conversion of the feed than 15 Run 12 in which fluid coke with no potassium was used.

TABLE Feed Blend for Run No. SalIAtm. Jobo Crude Run 6 1 2 3 4 Conditions 801 846 866 824 T. F., A\'g. Time. Min. on Temp. 56 50 50 H P.P.. psig Start of Run ISIS 1505 1610 1530 End of Run 542 584 566 538 Average 1028 1045 1088 1034 Oil Charge Y Name Saf.Atm. Saf.Atm. Saf.Atm. Saf.Atm. Gms. 91.23 91.57 90.77 92.29 Solids Charge Description K-coke (A) K-coke (B) K-coke (B) K-eoke (B) Gms. 52.39 57.46 57.42 53.95 Wtfi K. (wLK/wt. coke X 100) 9.8 15.7 15.7 15.7 H- Consumption. SCF/B of feed 619 526 555 475 Product Yields.\\'t. "/1 on feed ()il 84.7 75.8 62.8 84.6 Adsorhed material 9.8 14.3"" 19.2"" 8.2 Gas from treating Methane 2.4 2.7 1.9 1.3 C. .C 3.1 7.2 16.1 5.9 Coke after coking adsorbed material 8.4"" 5.2" Oil Analyses A S.\\'t./1 4.00 3.99 1.78 2.32 2.78 2.71 2.03 Metals. ppm N1 22 3.1 16.2 0.67 0.44 1.90 Fe 4 8 2.7 0 1.15 3.64 0.01 V 80 429 0.0 49.1 0.11 0.12 1.96 N.Wt./1 0.26 0.66 0.183 0.224 0.238 0.186 Con.C. wt. 7: 11.52 1 .75 7.58 7.28 6.3 5.28 Asphaltenes 9.6 13.19 1.6 6.9 2.5 1.8 2.6 Potassium. ppm 8.2 62.0 16 API Gravity 14.4 8 23.5 33.7 (24.8) Naphtha Analyses Sulfur "/1 0.11" 0.18 Aromatic lndanes. wt. 71 14.6 Sat. Unsats.. wt. Z 85.4 Bromine No. 24.7 22.0 H. -S in Exit gas. ppm 511 408 720 6050 51m 1m 71ml) 8 1 0 01) 12 Conditions '1. F.. Arg. 824 825 821 715 849 841 Time. Min. on Temp. 50 20 70 60 35 35 H. P.P.. psig Start of Run 2690 1995 2807 1055 3102 2840 End of Run 1256 1724 629 739 1234 1543 Average 1973 1860 1718 897 2168 2192 Oil Charge Name Saf.Atm. Blend Sat.Atm. Saf.Atm. Jobo Crude Jobo Crude Gms. 92.47 68.49 89.77 90.79 233.67 90.72 Solids Charge wet solids- H Description K-coke(B) K-coke(B) from Run 6 K-cokc(A) K-cokc (B) Fluid Coke Gms. 57.30 57.00 55.01 53.37 28.88 29.60 Wt.7( K. (wLK/wt. coke X 15.7 15.7 9.8 15.7 0 H Consumption. SCF/B of feed 937 209 926 364( leak) 1170 716 Product Yields. wt. 71 on feed Oil 88.2 85.4 92.9 83.6 75.2 Adsorbcd Material 7.4 8.7 7.1 5.4 11.34 Gas from treating Methane 1.6 0.55 2.31 nil 2.87 2.84 C -C 2.8 0.58 3.60 nil 8.12 10.69 Coke after coking adsorbed material 4.0"" 5.9 3.7 9.4 Oil Analyses S. wt. '7: 1.46 0.80 1.50 3.17 1.81 2.54

TABLE-continued Feed Blend for Run No. SafAtm. Jobo Crude Run 6 l 2 3 4 Metals. ppm Ni 2 70 1.43 1.60 39.9 88

Fe 1.35 0.00 7.1 0 5.7 V 2.56 0.60 1.18 81.2 42 42.4 N, wt. (76 0.208 0.147 0.177 0,258 0.53 0.40 Con.C. wt. '7: 4.66 3.2 4.0 6.08 6.27 8.82 Asphaltcnes 1.1 0.3 1.0 2 84 2.62 Potassium. ppm 208 API Gravity 28.0 28.0 29.3 26.9 26.5 Naphtha Analyses Sulfur, Aromatic lndancs, wt. '71 Sat. Unsats., wt. /z

Bromine No. 9.9 10.9

H 5 in Exit gas, ppm 0 Indirect by determination of sulfur content of a benzene solution After coking of solids at 1000F. and regeneration of catalyst at 1300F. and deducting OH CO;, from apparent coke yield. Differs from the other runs in having a preheat to 750F. under pressure, cooling. replacing H, then proceeding.

" Similates second stage of staged contacting of feed with fresh catalyst.

"" Simulates first stage of staged contacting.

" Preheat to 750F. and replacement with fresh H as in run 5.

"' Three successive runs with fresh oil contacting the same batch of Kcoke. Approximate What is claimed is:

l. A process for upgrading a heavy hydrocarbon feed containing sulfur contaminants, which comprises:

a. contacting said hydrocarbon feed with hydrogen and catalyst particles comprising a solid carboncontaining material and at least 2 weight percent of an alkali metal component (calculated as the metal based on the carbon-containing material) in.a reaction zone maintained at an average temperature ranging from about 700 to about l00OF. and at a hydrogen partial pressure of about 200 to 4000 psig to produce a vaporous product comprising normally liquid light hydrocarbons of reduced sulfur content, a carbonaceous residue, at least a portion of said carbonaceous residue depositing on said catalyst particles, and heavy liquid hydrocarbons;

b. removing said vaporous product overhead from said reaction zone;

c. removing from the bottom of said reaction zone a slurry of a portion of said heavy liquid hydrocarbons and a portion of said catalyst particles;

d. separating the catalyst particles from said slurry;

e. contacting at least a portion of the separated catalyst particles with steam in a gasification zone operated at a temperature ranging from about l0O0 to about 1700F., whereby at least a portion of the carbonaceous deposition is converted to a gas comprising hydrogen and carbon monoxide, and

. recycling a portion of the catalyst particles from the gasification zone to said reaction zone of step 2. The process of claim 1, wherein said reaction zone of step (a) comprises an ebullient bed.

3. The process of claim 1, wherein the separation of catalyst particles from said slurry comprises passing said catalyst-containing slurry to a separation-zone to remove the liquid hydrocarbons, and subsequently passing at least a portion of the separated catalyst particles to said gasification zone of step (d).

4. The process of claim 1, wherein the separation of catalyst particles from said slurry comprises passing the catalyst-containing slurry to a separation zone to remove a substantial portion of the liquid hydrocarbons, and passing the separated catalyst particles to a devolatilization zone containing a fluidized bed of solid particles maintained at a temperature of about 850 to about 1200F. and at a pressure ranging from about 0 to about psig to dry said separated catalyst particles and, subsequently, passing at least a portion of the dried catalyst particles to the gasification zone of step (d).

5. The process of claim 1, wherein the separation of catalyst particles from said slurry comprises passing said catalyst-containing slurry to a fluid coking zone operated at a temperature of about 850 to about 1200F. and at a pressure ranging from about 0 to 150 psig to volatilize said heavy liquid hydrocarbons and thereby separate said catalyst particles from the slurry, and, subsequently, passing at least a portion of the separated particles to said gasification zone of step (d).

6. The process of claim 1, wherein prior to said steam contacting step ((1), said separated catalyst particles are heated in a heating zone.

7. The process of claim 1, wherein said solid carboncontaining material is a solid composition containing less than 1.5 hydrogen atoms per one carbon atom.

8. The process of claim 1, wherein said solid carboncontaining material is selected from the group consisting of coal, coal coke, petroleum coke, activated carbon, lignite, peat, graphite and charcoal.

9. The process of claim 1, wherein said solid carboncontaining material is petroleum coke.

10. The process of claim 1, wherein said catalyst comprises from about 5 to about 20 weight percent of an alkali metal component (calculated as the metal based on said solid carbon-containing material).

11. The process of claim 1, wherein said alkali metal component is a potassium component.

12. The process of claim 1, wherein said alkali metal component is a cesium component.

13. The process of claim 1, wherein said heavy hydrocarbon feed additionally contains metal contaminants.

14. The process of claim 1, wherein said contacting step (a) is; conducted in more than one stage.

15. The process of claim 1, wherein said contacting step (a) is conducted at a temperature ranging from about 750 to about 900F.

16. The process of claim 1, wherein an oxygencon- 1 1 taining gas is introduced into the gasification zone of step (d). v

17. The process of claim 1, wherein at least a portion of the hydrogen and carbon monoxide gas formed in the gasification zone is passed to said reaction' zone of step (a).

18. The process of claim 1, wherein at least a portion of the hydrogen and carbon monoxide gas formed in the gasification zone is passed to a water gas shift stage to react with steam and form hydrogen and carbon dioxide, separating the hydrogen from the carbon dioxide and passing at least a portion of the separated hydrogen to said reaction zone of step (a).

19. A process for upgrading a heavy hydrocarbon feed containing metal contaminants, which comprises:

a. contacting said hydrocarbon feed with hydrogen and catalyst particles comprising a solid carboncontaining material and at least 2 weight percent of an alkali metal component (calculated as the metal based on the solid carbon-containing material) in an ebullient bed reaction zone maintained at an average temperature ranging from about 750 to about 900F. and at a hydrogen partial pressure of about 200 to about 4000 psig to produce a vaporous product comprising normally liquid light hydrocarbons of reduced content of metal contaminants, a carbonaceous residue, at least a portion of said carbonaceous residue depositing on said catalyst particles, and heavy liquid hydrocarbons;

b. removing said vaporous product overhead from said ebullient bed reaction zone;

c. removing from the bottom of said ebullient bed reaction zone a slurry of a portion of said heavy liquid hydrocarbons and a portion of said catalyst particles;

. separating the catalyst particles from said slurry; e. contacting at least a portion of the separated catalyst particles with steam in a gasification zone operated at a temperature ranging from about l000 to about 1700F., whereby at least a portion of the carbonaceous deposition is converted to a gas comprising hydrogen and carbon monoxide, and recycling a portion of the catalyst particles from the gasification zone to the ebullient bed reaction zone of step (a).

20. A process for upgrading a heavy hydrocarbon feed containing sulfur contaminants, which comprises:

a. contacting said hydrocarbon feed with hydrogen and catalyst particles comprising a solid carboncontaining material and at least 2 weight percent of an alkali metal component (calculated as the metal based on the carbon-containing material) in an ebullient bed reaction zone maintained at an average temperature ranging from about 700 to about 1000F. and at a hydrogen partial pressure of about 200 to about 4000 psig, to produce a vaporous product comprising normally liquid light hydrocarbons of reduced sulfur content, a carbonaceous residue, at least a portion of said carbonaceous residue depositing on said catalyst particles, and heavy liquid hydrocarbons;

b. removing said vaporous product overhead from said ebullient bed reaction zone;

0. removing from the bottom of said ebullient bed reaction zone a slurry of a portion of said heavyliquid hydrocarbons and a portion of said catalyst particles; i

d. passing said catalyst-containing slurry to a fluid coking zone operated at a temperature of about 850 to about l200F. and at a pressure ranging from about 0 to about psig to volatilize said heavy liquid hydrocarbons and thereby separate said catalyst particles from said slurry;

e. passing at least a portion of the catalyst particles resulting from step (d) to a gasification zone operated at a higher temperature than the operating temperature of said coking zone and contacting the same with steam and an oxygen-containing gas, whereby at least a portion of the carbonaceous deposition is converted to a gas comprising hydrogen and carbon monoxide;

f. recycling a portion of the catalyst particles from the gasification zone to the ebullient bed reaction zone of step (a), and

g. passing an other portion of the catalyst particles from the gasification zone to the coking zone.

21. The process of claim 20 wherein said heavy hydrocarbon feed also contains metal contaminants.

22. A process for upgrading a heavy hydrocarbon feed containing sulfur contaminants, which comprises:

a. contacting said hydrcarbon feed with hydrogen and catalyst particles comprising a solid carboncontaining material and at least 2 weight percent of an alkali metal component (calculated as the metal based on the solid carbon-containing material) in an ebullient bed reaction zone maintained at an average temperature ranging from about 700 to about 1000F. and at a hydrogen partial pressure of about 200 to about 4000 psig, to produce a vaporous product comprising normally liquid light hydrocarbons of reduced sulfur content, a carbonaceous residue, at least a portion of said carbonaceous residue depositing on the catalyst particles, and heavy liquid hydrocarbons;

b. removing said vaporous product overhead from said ebullient bed reaction zone;

c. removing from the bottom of said ebullient bed reacton zone a slurry of a portion of said heavy liquid hydrocarbons and a portion of said catalyst particles;

d. passing said catalyst-containing slurry to a fluid coking zone operated at a temperature ranging from about 850 to about 1200F. and at a pressure ranging from about 0 to about 150 psig to volatilize said heavy liquid hydrocarbons and thereby separate the catalyst particles from said slurry;

e. passing at least a portion of the catalyst particles from the coking zone to a heating zone operated at a higher temperature than the operating temperature of the coking zone to heat said catalyst particles;

f. passing a portion of the heated catalyst particles to a gasification zone operated at an intermediate temperature between the coking zone temperature and the heating zone temperature and contacting said heated catalyst particles with steam to form a gas comprising hydrogen and carbon monoxide;

- g. passing a first portion of catalyst particles from the gasification zone to the heating zone;

h. passing a second portion of catalyst particles from the gasification zone to the coking zone, and

i. passing a third portion of catalyst particles from the gasification zone to the ebullient bed reaction zone. l

23. The process of claim 22 wherein a substantial portion of the heavy liquid hydrocarbons are removed 13 from the catalyst-containing slurry and the recovered catalyst particles are thereafter passed to said fluid coking zone of step (c).

24. The process of claim 22, wherein at least a portion of the hydrogen and carbon monoxide gas formed in the gasification zone is passed to a water gas shift stage to react with steam and form hydrogen and carbon dioxide, separating the hydrogen from the carbon dioxide and passing at least a portion of the separated hydrogen to said ebullient bed reaction zone.

25. A process for upgrading a heavy hydrocarbon feed containing sulfur contaminants, which comprises:

a. contacting said hydrocarbon feed with hydrogen and catalyst particles consisting essentially of a solid carbon-containing material and at least 2 weight percent of an alkali metal component (calculated as the metal based on the carbon-containing material) in a reaction zone maintained at an average temperature ranging from about 700 to about 1000F. and at a hydrogen partial pressure of about 200 to 4000 psig to produce a vaporous product comprising normally liquid light hydrocar- 14 bons of reduced sulfur content, a carbonaceous residue, at least a portion of said carbonaceous residue depositing on said catalyst particles, and heavy liquid hydrocarbons;

b. removing said vaporous product overhead from said reaction zone;

c. removing from the bottom of said reaction zone a slurry of a portion of said heavy liquid hydrocarbons and a portion of said catalyst particles;

d. separating the catalyst particles from said slurry; e. contacting at least a portion of the separated cataf. recycling a portion of the catalyst particles from the gasification zone to said reaction zone of step

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US3541002 *Dec 29, 1967Nov 17, 1970Cities Service Res & Dev CoParticulate catalyst regeneration method
US3546103 *Feb 3, 1969Dec 8, 1970Exxon Research Engineering CoHydrogenation catalysts on charcoal in guard chamber for removing metals from petroleum residua
US3617481 *Dec 11, 1969Nov 2, 1971Exxon Research Engineering CoCombination deasphalting-coking-hydrotreating process
US3715303 *May 18, 1971Feb 6, 1973Standard Oil CoHydrotreatment of fossil fuels
US3726791 *Jul 16, 1970Apr 10, 1973Exxon Research Engineering CoHydrogen production from an integrated coker gasifier system
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US4204943 *Sep 15, 1978May 27, 1980Exxon Research & Engineering Co.Combination hydroconversion, coking and gasification
US4223728 *Nov 30, 1978Sep 23, 1980Garrett Energy Research & Engineering Inc.Method of oil recovery from underground reservoirs
US4244810 *Dec 10, 1979Jan 13, 1981Texaco Inc.Fluidized catalytic cracking process for increased hydrogen production
US4331529 *Nov 5, 1980May 25, 1982Exxon Research & Engineering Co.Fluid coking and gasification process
US4340466 *May 15, 1980Jul 20, 1982Chiyoda Chemical Engineering & Construction Co., Ltd.Process for hydrotreating heavy oils containing metals
US4394250 *Jan 21, 1982Jul 19, 1983Chevron Research CompanyDelayed coking process
US4406772 *Jun 11, 1982Sep 27, 1983Director-General Of Agency Of Industrial Science & TechnologyHydroconversion of heavy hydrocarbon oils
US4411777 *Feb 4, 1982Oct 25, 1983Phillips Petroleum CompanyProducing increased yield of hydrogen by cracking petroleum with potassium-containing catalyst
US4521382 *Jun 9, 1980Jun 4, 1985Alberta Research CouncilFormation of coke from heavy crude oils in the presence of calcium carbonate
US4521383 *Jun 9, 1980Jun 4, 1985Alberta Research CouncilLime addition to heavy crude oils prior to coking
US4529501 *May 29, 1984Jul 16, 1985Research Council Of AlbertaHydrodesulfurization of coke
US4541919 *Aug 7, 1984Sep 17, 1985Mobil Oil CorporationShape selective dewaxing using coke modified large pore zeolites
US4609456 *Feb 8, 1985Sep 2, 1986Institut Francais Du PetroleProcess for converting heavy petroleum residues to hydrogen and gaseous distillable hydrocarbons
US5167796 *May 22, 1989Dec 1, 1992Ucar Carbon Technology CorporationMethod of forming an electrode from a sulfur containing decant oil feedstock
US5284574 *Mar 12, 1992Feb 8, 1994Exxon Research And Engineering CompanyImproved integrated coking-gasification process with mitigation of slagging
US6511937Oct 3, 2000Jan 28, 2003Exxonmobil Research And Engineering CompanyCombination slurry hydroconversion plus solvent deasphalting process for heavy oil upgrading wherein slurry catalyst is derived from solvent deasphalted rock
US7402547Dec 16, 2004Jul 22, 2008Shell Oil CompanySystems and methods of producing a crude product
US7413646Dec 16, 2004Aug 19, 2008Shell Oil CompanySystems and methods of producing a crude product
US7416653Dec 16, 2004Aug 26, 2008Shell Oil CompanySystems and methods of producing a crude product
US7534342Dec 16, 2004May 19, 2009Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7588681Dec 16, 2004Sep 15, 2009Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7591941Dec 16, 2004Sep 22, 2009Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7615142Aug 31, 2006Nov 10, 2009Headwaters Technology Innovation, LlcExpanded bed reactor system and method for hydroprocessing wax produced by Fischer-Tropsch reaction and contaminated with solids
US7615196Dec 16, 2004Nov 10, 2009Shell Oil CompanySystems for producing a crude product
US7625481Jul 9, 2008Dec 1, 2009Shell Oil CompanySystems and methods of producing a crude product
US7628908Dec 16, 2004Dec 8, 2009Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7648625Dec 16, 2004Jan 19, 2010Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7674368Dec 16, 2004Mar 9, 2010Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7674370Dec 16, 2004Mar 9, 2010Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7678264Apr 7, 2006Mar 16, 2010Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7736490Dec 16, 2004Jun 15, 2010Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7745369Jun 22, 2006Jun 29, 2010Shell Oil CompanyMethod and catalyst for producing a crude product with minimal hydrogen uptake
US7749374Oct 3, 2007Jul 6, 2010Shell Oil CompanyMethods for producing a crude product
US7763160Dec 16, 2004Jul 27, 2010Shell Oil CompanySystems and methods of producing a crude product
US7780844Dec 16, 2004Aug 24, 2010Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7807046Dec 16, 2004Oct 5, 2010Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7811445Dec 16, 2004Oct 12, 2010Shell Oil CompanySystems and methods of producing a crude product
US7828958Dec 16, 2004Nov 9, 2010Shell Oil CompanySystems and methods of producing a crude product
US7837863Dec 16, 2004Nov 23, 2010Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7854833May 12, 2008Dec 21, 2010Shell Oil CompanySystems and methods of producing a crude product
US7879223Dec 16, 2004Feb 1, 2011Shell Oil CompanySystems and methods of producing a crude product
US7918992Apr 7, 2006Apr 5, 2011Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7955499Mar 25, 2009Jun 7, 2011Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7959796Dec 16, 2004Jun 14, 2011Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US7959797Jan 27, 2009Jun 14, 2011Shell Oil CompanySystems and methods of producing a crude product
US8025791Dec 16, 2004Sep 27, 2011Shell Oil CompanySystems and methods of producing a crude product
US8025794Dec 16, 2004Sep 27, 2011Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US8070936Jan 27, 2009Dec 6, 2011Shell Oil CompanySystems and methods of producing a crude product
US8070937Dec 16, 2004Dec 6, 2011Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US8163166May 12, 2008Apr 24, 2012Shell Oil CompanySystems and methods of producing a crude product
US8241489Dec 16, 2004Aug 14, 2012Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US8268164May 12, 2008Sep 18, 2012Shell Oil CompanySystems and methods of producing a crude product
US8394254Apr 14, 2011Mar 12, 2013Shell Oil CompanyCrude product composition
US8475651Mar 25, 2009Jul 2, 2013Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US8481450Mar 9, 2011Jul 9, 2013Shell Oil CompanyCatalysts for producing a crude product
US8506794Dec 16, 2004Aug 13, 2013Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US8608938Apr 14, 2011Dec 17, 2013Shell Oil CompanyCrude product composition
US8608946Dec 16, 2004Dec 17, 2013Shell Oil CompanySystems, methods, and catalysts for producing a crude product
US8613851Apr 14, 2011Dec 24, 2013Shell Oil CompanyCrude product composition
US8663453Apr 14, 2011Mar 4, 2014Shell Oil CompanyCrude product composition
US20050148487 *Dec 17, 2004Jul 7, 2005Brownscombe Thomas F.Method of decomposing polymer
US20100122932 *Nov 15, 2008May 20, 2010Haizmann Robert SIntegrated Slurry Hydrocracking and Coking Process
EP0073690A1 *Jul 16, 1982Mar 9, 1983Institut Francais Du PetroleCatalytic hydroconversion process of heavy hydrocarbons in the presence of a dispersed catalyst and of carbonaceous particles
WO1998000477A1 *Jun 25, 1997Jan 8, 1998Community Energy AlternativesMethod and system for producing fuel from a heavy hydrocarbon feedstock
WO2001027225A1 *Oct 6, 2000Apr 19, 2001Exxon Research Engineering CoCombination slurry hydroconversion plus solvent deasphalting process
WO2003006578A2 *Jul 9, 2002Jan 23, 2003Grace W R & CoGasoline sulfur reduction in fluid catalytic cracking
WO2005061664A2 *Dec 16, 2004Jul 7, 2005Shell Oil CoSystems and methods of producing a crude product
Classifications
U.S. Classification208/50, 208/127, 208/157, 208/108
International ClassificationC10G45/02, C10G45/16
Cooperative ClassificationC10G45/16
European ClassificationC10G45/16