CA1095846A - Method of preventing fouling of hot separator in hydroconversion of heavy hydrocarbon oils - Google Patents
Method of preventing fouling of hot separator in hydroconversion of heavy hydrocarbon oilsInfo
- Publication number
- CA1095846A CA1095846A CA294,123A CA294123A CA1095846A CA 1095846 A CA1095846 A CA 1095846A CA 294123 A CA294123 A CA 294123A CA 1095846 A CA1095846 A CA 1095846A
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- Canada
- Prior art keywords
- liquid
- separator
- heavy
- zone
- hydrocracking
- Prior art date
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Classifications
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G49/00—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00
- C10G49/005—Inhibiting corrosion in hydrotreatment processes
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G49/00—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00
- C10G49/22—Separation of effluents
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- Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Engineering & Computer Science (AREA)
- Chemical Kinetics & Catalysis (AREA)
- General Chemical & Material Sciences (AREA)
- Organic Chemistry (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
METHOD OF PREVENTING FOULING OF
HOT SEPARATOR IN HYDROCONVERSION
OF HEAVY HYDROCARBON OILS
Abstract of the Disclosure The operation of a hydrocracking process to recover valuable liquid hydrocarbons from heavy hydro-carbon oils, such as heavy bituminous oil extracted from tar sands, is significantly improved when the downstream liquid-gas separator is operated at the pressure of the hydrocracking stage and the effluent from the hydro-cracking stage is introduced into the liquid-gas separator below the liquid level in the separator. This reduces settling of mineral matter contained in the effluent, prevents phase separation of the hydrocarbon liquid in the separator, reduces hydrogen starvation thereby preventing polymerization and coking of the hydrocarbon liquid in the separator and substantially eliminates sludge formation in the separator and plugging of the liquid outlet.
HOT SEPARATOR IN HYDROCONVERSION
OF HEAVY HYDROCARBON OILS
Abstract of the Disclosure The operation of a hydrocracking process to recover valuable liquid hydrocarbons from heavy hydro-carbon oils, such as heavy bituminous oil extracted from tar sands, is significantly improved when the downstream liquid-gas separator is operated at the pressure of the hydrocracking stage and the effluent from the hydro-cracking stage is introduced into the liquid-gas separator below the liquid level in the separator. This reduces settling of mineral matter contained in the effluent, prevents phase separation of the hydrocarbon liquid in the separator, reduces hydrogen starvation thereby preventing polymerization and coking of the hydrocarbon liquid in the separator and substantially eliminates sludge formation in the separator and plugging of the liquid outlet.
Description
This invention relates to the treatment of hydro-carbon oils and, more particularly, to the hydrocracking ; of heavy hydrocarbon oils to produce improved products of lower boiling range.
Hydrocracking processes for the conversion of heavy hydrocarbon oils to light and intermediate naphthas of good quality for reforming feed stock~, fuel oil and gas oil are well known. These heavy hydrocarbon oils can be such mat-erials as petroleum crude oil, atmospheric tar bottoms products, vaccuum tar bottoms products, heavy cycle oils, shale oils, coal-derived liquids, crude oil residuum, top-ped crude oils and heavy bituminous oils extracted from tar sands. Of particular interest are the oils extracted from tar sands and which contain wide boiling range mat-erials from naphthas through kerosene, gas oil, pitch, etc. and which contain a large portion of material boiling above 524C. These heavy hydrocarbon oils contain nitrogen and sulfur compounds in extremely large quantities and often contain excessive quantities of organo-metallic contaminants which tend to be detrimental to various catalytic processes which may subsequently be carried out, such as hydrofining. Of the metallic contaminants those containing nickel and vanadium are most common, although other metals are often present.
These metallic contaminants, as well as others, are usually present within the bituminous material as organo-' metallic compounds of relatively high molecular weight.
A considerable quantity of the organo-metallic complexes are linked with asphaltenic material and contains sulphur.
As the reserves of conventional crude oils decline, the heavy oils must be upgraded to meet the
Hydrocracking processes for the conversion of heavy hydrocarbon oils to light and intermediate naphthas of good quality for reforming feed stock~, fuel oil and gas oil are well known. These heavy hydrocarbon oils can be such mat-erials as petroleum crude oil, atmospheric tar bottoms products, vaccuum tar bottoms products, heavy cycle oils, shale oils, coal-derived liquids, crude oil residuum, top-ped crude oils and heavy bituminous oils extracted from tar sands. Of particular interest are the oils extracted from tar sands and which contain wide boiling range mat-erials from naphthas through kerosene, gas oil, pitch, etc. and which contain a large portion of material boiling above 524C. These heavy hydrocarbon oils contain nitrogen and sulfur compounds in extremely large quantities and often contain excessive quantities of organo-metallic contaminants which tend to be detrimental to various catalytic processes which may subsequently be carried out, such as hydrofining. Of the metallic contaminants those containing nickel and vanadium are most common, although other metals are often present.
These metallic contaminants, as well as others, are usually present within the bituminous material as organo-' metallic compounds of relatively high molecular weight.
A considerable quantity of the organo-metallic complexes are linked with asphaltenic material and contains sulphur.
As the reserves of conventional crude oils decline, the heavy oils must be upgraded to meet the
- 2 -~L
q~
iO95~6 demands. In this upgrading, the heavier material is con-verted to lighter fractions and most of the sulphur, nitrogen and metals must be removed. This is usually done by means of coking or hydrocracking processes. The coking processes involve removal of carbon resulting in 20~ by weight or more material as coke. This material referred to as "coke" is a carbonaceous material which may contain insoluble organic material, mineral matter, metals, sulphur, quinoline and benzene soluble organic materials. The content of these other materials means that the coke cannot be used as a fuel and this represents an excessive waste of resources.
Various special procedures have been developed in an effort to prevent the formation of coke within the hydrocracking zone as well as the deposition of coke on the surface of any catalyst used and on the interior walls of the hydrocracking chamber itself. A second particularly troublesome area in terms of coke deposits is the down-stream liquid-gas hot separator. For instance, U.S. Patent
q~
iO95~6 demands. In this upgrading, the heavier material is con-verted to lighter fractions and most of the sulphur, nitrogen and metals must be removed. This is usually done by means of coking or hydrocracking processes. The coking processes involve removal of carbon resulting in 20~ by weight or more material as coke. This material referred to as "coke" is a carbonaceous material which may contain insoluble organic material, mineral matter, metals, sulphur, quinoline and benzene soluble organic materials. The content of these other materials means that the coke cannot be used as a fuel and this represents an excessive waste of resources.
Various special procedures have been developed in an effort to prevent the formation of coke within the hydrocracking zone as well as the deposition of coke on the surface of any catalyst used and on the interior walls of the hydrocracking chamber itself. A second particularly troublesome area in terms of coke deposits is the down-stream liquid-gas hot separator. For instance, U.S. Patent
3,842,122, issued October 15, 1974, describes a procedure in which the conditions in the liquid-gas hot separator are very carefully controlled in terms of temperatures and superficial liquid velocities to prevent coking within the separator. They found these conditions to be critical and also found that increase in pressure did not prevent the formation of coke within the separator. Of course, it becomes a major added expense if the hot separator must be operated at conditions different from that of the hydrocracking zone.
3~ U.S. Patent 3,841,981, iss~ed October 15, 1974, describes another procedure aimed at preventing formation of coke in the separator and avoiding phase separation of --` 109S8~i the liquid in the separator. In that case, the effluent from the hydrocracking zone was quenched with a quench oil so as to lower the temperature of the effluent before it entered into the gas-liquid separator.
Yet another method of preventing fouling is des-cribed in U.S. Patent 3,544,477, issued December 1, 1970, which involves reducing the pressure of a high boiling hydrocarbon liquid stream obtained from a hydrocracking process and immediately contacting this liquid stream with a cool liquid hydrocarbon stream , this pressure reduction and quenching being aimed at substantially!re-ducing the polymerization of polymerizable constituents.
It is the object of the present invention to pro-vide a method of operating a liquid-gas separator down-stream of a hydrocracking zone such that fouling will be substantially eliminated while avoiding the need of going to the complex additional equipment and procedures as outlined in the prior systems.
SUMMARY OF THE INVENTION
This invention relates to a hydrocracking process in which a heavy hydrocarbon oil feed is treated with hydrogen in a reaction zone under conditions of high pressure of about 500 to 3,500 psig. and high temperatures of about 400 - 490C., resulting in a mixed effluent containing a high boiling hydrocarbon liquid component at the above pressures and temperatures and a gaseous component. This mixed effluent is passed into a sep-aration zone maintained substantially at the pressure of the hydrocracking zone whereby the mixed effluent is separated into a gaseous phase comprising hydrogen and l~g5~'6 vaporous hydrocarbons and a liquid phase comprising heavy hydrocarbons. The gaseous phase is removed from an outlet in an upper region of the separation zone and the liquid phase is removed through an outlet in a lower region of the separation zone. According to the novel feature of this invention, a minimum liquid level is maintained in the separation zone sufficient to maintain a liquid seal in the liquid phase outlet and the mixed effluent from the hydrocracking zone is introduced intc the separation zone below the liquid level therein.
This has been found to provide an excellent mixing action in the liquid phase in the bottom of the separation zone including mixing of the hydrogen in the effluent stream with the heavy hydrocarbon liquid and stripping most of the light hydrocarbons from the heavy hydrocarbon li~uid. This procedure has been found to be very effective in reducing settling of mineral matter contained in the effluent, preventing phase separation of the heavy hydrocarbon liquid, reducing hydrogen starvation thereby preventing polymerization and coking of the heavy hydro-carbon liquid and substantially eliminating sludge form-ation within the separator and plugging of the heavy hydrocarbon liquid outlet.
The effluent stream from the hydrocracking zone must, of course, be introduced into the liquid in the hot separator so as to provide as uniform distribution as possible through the liquid phase. Thus, the number and spacing of effluent discharge out~ets depend on the size of the separator vessel. Also, the necessary minimum liquid level and the distance of the effluent discharge outlets below the liquid level vary widely depending on 109~84~
the design of the separator vessel and the process conditions. The optimum separator conditions for each particular separator design and hydrocracking process can be easily determined by routine procedure.
The process of this invention is particularly well suited for the treatment of heavy oils having a large proportion, preferably at least 50% by volume, which boils above 524C. The hydrocracking can be operated at quite moderate pressure in the range of 500-3,500 psig., preferably 500-2,500 psig., most preferably 1000-2000 psig, without coke formation in the hydrocracking zone.
The hydrocracking temperature can be in the range of 400 to 490C., with 430 to 470C. being particularly preferred. The hot separator can be operated over a wide temperature range of from 150 to 500C.
The process according to this invention can be carried out with advantage in a variety of known reaction systems. For instance, it is useful with either non-catalytic or ~atalytic hydrocracking systems, using fixed bed or slurry-type reactors. Moreover, it is advantageous when used with once-through systems without recycle of heavy hydrocarbon liquid as well with systems which include heavy hydrocarbon liquid recycle. It is particularly well suited to an up-flow tubular reactor, with the effluent from the top of the reactor passing into the hot separator maintained near the temperature of the hydrocracking zone.
~ or best results the heavy hydrocarbon from the hot separator is recycled back into the frec;h fe-d to the hydrocracking zone in a volume ratio of recycle to fresh feed of at least 2:1. It is also preferred that the combined recycle and fresh fee~ flow be at a rate such that the 1~9~8~6 superficial liquid upflow velocity in the hydrocracking zone is at least 0.25 cm./sec. The liquid houriy space velocity is preferably in the range of 0.5 to 4Ø
It has also been found that the system does not require a high hydrogen recirculation to avoid coking.
Thus, a hydrogen recirculation of about 2,000 to 10,000 scf per bbl of feed stock can be used.
The gaseous stream from the hot separator is preferably passed to a cold seParator maintained at about 25C. The non-condensable gases from the cold separator are passed through a water scrubber to remove ammonium sulphide and then through an oil scrubber to remove ~2S and light hydrocarbons. The effluent gas from the oil scrubber, rich in hydrogen, together with makeup hydrogen is recycled to the hydrocracking zone where it is combined with the feedstock, including re-cycled heavy hydrocarbons from the hot separator . The liquid stream from the cold separator represents the light hydrocarbon oil product of the present invention and can be sent for secondary treatment.
For a better understanding of the invention, reference is ~ade to the accompanying drawings which illustrate diagrammatically preferred embodiments of the present invention. In the drawings:
Figure 1 is a schematic flow sheet of a hydro-cracking process;
Figure 2 is a schematic illustration of a liquid-gas separator; and Figure 3 is a further illustration of a liquid-gas separator.
1095.8~-~
Heavy hydrocarbon oil feed 10 is pumped via feed pump 11 through inlet line ~2 and preheater 40 into the bottom of an empty tower 15. Recycled gases and makeup hydrogen from line 13 are simultaneously fed into tower 15 through line 12 along with recycle heavy hydro-carbon liquid through line 14. A liquid-gas mixture is withdrawn from the top of tower 15 through line 16 and introduced into the bottom of hot separator 17. In the hot separator, the effluent from tower 15 is separated into a gaseous stream 22 and a liquid stream 18. The liquid stream 18 is in the form of a heavy hydrocarbon oil containing pitch and a portion of this stream 18 is recycled through pump 19 and line 14 into inlet line 12 upstream or downstream of preheater 44 The balance of liquid stream 18 exits via line 20 and is withdrawn via pump 21 for collection. The pump 21 may be replaced in a commercial operation by let-down valves.
The ga~eous stream from hot separator 17 is carried by line 22 into a cold separator 23. Within this vessel the product is separated into a gaseous stream rich in hydrogen which is drawn off through line 26 and an oil product which is drawn off through line 24 and collected in receiver 25. This represents the light oil product of the invention.
The hydrogen rich stream 26 is passed through a water scrubher 27 to remove dmmonium sulphide and the stream 28 from the water scrubber is passed through a packed tower 29 where it is scrubbed by means of organic liquid 32 which is cycled through the tower by means of pump 31 and recyc~e loop 30.
The scrubbed hydroyen rich stream emerges from the scrubber via line 33 and is combined with fresh make up hydrogen added through line 34 and recycled by 1ine 35, through 1~958~6 gas pump 36, orifice 37 and line 13 back to tower 15.
The hot separator 17 is shown in greater detail in Figures 2 and 3. It includes a main cylindrical portion 40 with a truncated conical lower portion 41 merging into a liquid phase outlet pipe 18. A gaseous phase outlet pipe 22 is provided at the top of the sep-arator.
The liquid phase is maintained with a liquid level 42 and this is kept at a minimum sufficient to achieve a liquid seal into the pipe 18 while minimizing the residence time of the liquid within the separator.
As shown in Figure 2, the effluent from the hydrocracking zone is introduced into the separator by way of pipe 16 which is brought directly down through the cylindrical portion 40 below the liquid level 42. This pipe 16 terminates in a distributor 43 which uniformly distri-butes the effluent into the liquid.
An alternative embodiment is shown in Figure 3 in which the pipe 16 is introduced through the sidewall at a point below the liquid level 42, again connecting to a distributor 43 for uniformly distributing the effluent within the liquid phase.
Certain preferred embodiments of the invention will now be further illustrated by the following non-limitative examples.
1~95~6 Example 1 The charge stock employed was an ~thabasca bitumen having the ~ollowing propertles:
Specific gravity, 60/60F1.010 Sulphur, wt. % 4.73 . Ash, wt. % 0.56 Viscosity, cst at 210F 175.8 Conradson Carbon Residue, wt.% 13.7 Pentane Insolubles, wt. %15.6 10 Benzene Insolubles, wt % 0 57 Nickel, ppm 68 Vanadium, ppm 211 The above feed stock was passed through the reaction sequence shown in the attached drawing using two different operating conditions as follows:
, .._ _ Run Number R-2-1-2 R-2-2-4 , .__ . .. _ Duration, h 477 283 Pressure MPa 13.89 13.89 Gas Flow, g mol/kg of feed51.56 51.56 H2 Purity, vol. % 85 85 LHSV, 1.0 1.0 Reactor Temp. C. 4'0 460 l~ot Separator Temp. C., 450 450 2l Actual Feed Flow, q/ll 4535 ~554 Recycle Oil Flow , g/h 9060 12700 Recycle/Actual Feed Ratio ~ 2.8 There were no operational problems encountered during these runs. After completion of the runs, the pilot plant was dismantled and inspected for coke de-position or any type of contamination. No major foulinq of the hot separator was observed.
The yields and properties of the heavy hydrocarbon liquid withdrawn from the hot separator were as follows:
1~9~846 Reactor Temperature 450C 460 C
Run Number R-2-1-2 R-2-2-4 _ Yield on feed, wt. % 20.74 16.43 Yield on total liquid 22.95 18.33 product, wt. %
Specific gravity, 1.095 1.129 S. wt. ~ 3.6~ 3.59 N, ppm 8916 availahle Ni, ppm 241 361 V, ppm 755 1041 Ash, wt. % 2.67 3.53 Conradson Carbon residue, wt.~ 30.14 36.52 Pentane-insoluble, wt. % 30.62 38.15 Benzene-insoluble, wt. % 10.82 14.95 Distillate, (-524C), wt. %55.6 54.2 Distillate, sp. gr. 0.990 1.004 Pit~h (+524C), wt.% 44.4 45.8 . . . .
Example 2 In order to demonstrate the effects of the liquid velocities in the hot separator, parallel tests were run with and without recycle of heavy hydrocarbon liquid from the hot separator. The results are shown in the following table.
~95846 Run Number A-450 B-450 A-460 B-460 . _ . .. . ._. .
Reactor temp. C. 450 450460 460 Average liquid flow, g/h 219211261 1955 14906 Recycle oil withdrawal_ 976 _ 748 rate, g/h Superficial liquid velocity O. 053 0.274 0.048 0.360 in the reactor, cm/~ec.
Superficial average1.54 0.301.53 0.23 residence time for the firs t pass, h .
10 Total residence time for _ 3.8 _ 5.4 the recycle oil, h.
Liquid velocity in0.059 0.244 0.037 0.330 the separator, cm/sec.
__ ..
No major fouling of the hotseparatorwas observed during the above runs.
Example 3 (a) Hydrogenation reactions were carried out using the same pilot plant as in Example 1, with the same feedstock and the same reaction condition except a hot separator temperature of only 350C. The reactions were carried out both with and without a dip tube to introduce the mixed effluent below the liquid level in the separator and the results were compared.
After a running time of only 2 hours without dip tube being used, the bottom core and outlet line of the hot separator had become completely plugged. On the other hand, after a running time of 16 days using the dip tube, the system was still operational. Total deposits of about 6600 g. had formed in the total system, mostly within the hydrocracking reactor. Only small amounts of deposit had formed within the hot separator, mainly on the walls of the separator and the separator bottom. E~owever, these - 12 ~
1~9~
separator deposits were not sufficient to interfere with its operaticn.
(b) Because of the substantial deposits in the hydrocracking reactor, further tests were carried out under the same conditions as part (a) above using both a dip tube in the hot separator and a coal getter in the oil feed to the hydrocracking reactor. The coal getter was utilized as described in copending Canadian application Serial no. 269,020 filed December 31, 1976.
In one test with the coal getter and dip tube, only 132 g. of total deposits in the system had accumulated after 21 days of operation. In another test a total of 940 g. of deposits had accumulated after 3 days.
However, in both of these tests substantially all of the deposits were in the reactor and the hot separator was substantially free of any deposits.
Thus, it will be seen that the method of operating the hot separator according to this invention is highly effective in eliminating the problem of coke deposits in the hot separator regardless of the conditions in the hydrocracking reactor.
3~ U.S. Patent 3,841,981, iss~ed October 15, 1974, describes another procedure aimed at preventing formation of coke in the separator and avoiding phase separation of --` 109S8~i the liquid in the separator. In that case, the effluent from the hydrocracking zone was quenched with a quench oil so as to lower the temperature of the effluent before it entered into the gas-liquid separator.
Yet another method of preventing fouling is des-cribed in U.S. Patent 3,544,477, issued December 1, 1970, which involves reducing the pressure of a high boiling hydrocarbon liquid stream obtained from a hydrocracking process and immediately contacting this liquid stream with a cool liquid hydrocarbon stream , this pressure reduction and quenching being aimed at substantially!re-ducing the polymerization of polymerizable constituents.
It is the object of the present invention to pro-vide a method of operating a liquid-gas separator down-stream of a hydrocracking zone such that fouling will be substantially eliminated while avoiding the need of going to the complex additional equipment and procedures as outlined in the prior systems.
SUMMARY OF THE INVENTION
This invention relates to a hydrocracking process in which a heavy hydrocarbon oil feed is treated with hydrogen in a reaction zone under conditions of high pressure of about 500 to 3,500 psig. and high temperatures of about 400 - 490C., resulting in a mixed effluent containing a high boiling hydrocarbon liquid component at the above pressures and temperatures and a gaseous component. This mixed effluent is passed into a sep-aration zone maintained substantially at the pressure of the hydrocracking zone whereby the mixed effluent is separated into a gaseous phase comprising hydrogen and l~g5~'6 vaporous hydrocarbons and a liquid phase comprising heavy hydrocarbons. The gaseous phase is removed from an outlet in an upper region of the separation zone and the liquid phase is removed through an outlet in a lower region of the separation zone. According to the novel feature of this invention, a minimum liquid level is maintained in the separation zone sufficient to maintain a liquid seal in the liquid phase outlet and the mixed effluent from the hydrocracking zone is introduced intc the separation zone below the liquid level therein.
This has been found to provide an excellent mixing action in the liquid phase in the bottom of the separation zone including mixing of the hydrogen in the effluent stream with the heavy hydrocarbon liquid and stripping most of the light hydrocarbons from the heavy hydrocarbon li~uid. This procedure has been found to be very effective in reducing settling of mineral matter contained in the effluent, preventing phase separation of the heavy hydrocarbon liquid, reducing hydrogen starvation thereby preventing polymerization and coking of the heavy hydro-carbon liquid and substantially eliminating sludge form-ation within the separator and plugging of the heavy hydrocarbon liquid outlet.
The effluent stream from the hydrocracking zone must, of course, be introduced into the liquid in the hot separator so as to provide as uniform distribution as possible through the liquid phase. Thus, the number and spacing of effluent discharge out~ets depend on the size of the separator vessel. Also, the necessary minimum liquid level and the distance of the effluent discharge outlets below the liquid level vary widely depending on 109~84~
the design of the separator vessel and the process conditions. The optimum separator conditions for each particular separator design and hydrocracking process can be easily determined by routine procedure.
The process of this invention is particularly well suited for the treatment of heavy oils having a large proportion, preferably at least 50% by volume, which boils above 524C. The hydrocracking can be operated at quite moderate pressure in the range of 500-3,500 psig., preferably 500-2,500 psig., most preferably 1000-2000 psig, without coke formation in the hydrocracking zone.
The hydrocracking temperature can be in the range of 400 to 490C., with 430 to 470C. being particularly preferred. The hot separator can be operated over a wide temperature range of from 150 to 500C.
The process according to this invention can be carried out with advantage in a variety of known reaction systems. For instance, it is useful with either non-catalytic or ~atalytic hydrocracking systems, using fixed bed or slurry-type reactors. Moreover, it is advantageous when used with once-through systems without recycle of heavy hydrocarbon liquid as well with systems which include heavy hydrocarbon liquid recycle. It is particularly well suited to an up-flow tubular reactor, with the effluent from the top of the reactor passing into the hot separator maintained near the temperature of the hydrocracking zone.
~ or best results the heavy hydrocarbon from the hot separator is recycled back into the frec;h fe-d to the hydrocracking zone in a volume ratio of recycle to fresh feed of at least 2:1. It is also preferred that the combined recycle and fresh fee~ flow be at a rate such that the 1~9~8~6 superficial liquid upflow velocity in the hydrocracking zone is at least 0.25 cm./sec. The liquid houriy space velocity is preferably in the range of 0.5 to 4Ø
It has also been found that the system does not require a high hydrogen recirculation to avoid coking.
Thus, a hydrogen recirculation of about 2,000 to 10,000 scf per bbl of feed stock can be used.
The gaseous stream from the hot separator is preferably passed to a cold seParator maintained at about 25C. The non-condensable gases from the cold separator are passed through a water scrubber to remove ammonium sulphide and then through an oil scrubber to remove ~2S and light hydrocarbons. The effluent gas from the oil scrubber, rich in hydrogen, together with makeup hydrogen is recycled to the hydrocracking zone where it is combined with the feedstock, including re-cycled heavy hydrocarbons from the hot separator . The liquid stream from the cold separator represents the light hydrocarbon oil product of the present invention and can be sent for secondary treatment.
For a better understanding of the invention, reference is ~ade to the accompanying drawings which illustrate diagrammatically preferred embodiments of the present invention. In the drawings:
Figure 1 is a schematic flow sheet of a hydro-cracking process;
Figure 2 is a schematic illustration of a liquid-gas separator; and Figure 3 is a further illustration of a liquid-gas separator.
1095.8~-~
Heavy hydrocarbon oil feed 10 is pumped via feed pump 11 through inlet line ~2 and preheater 40 into the bottom of an empty tower 15. Recycled gases and makeup hydrogen from line 13 are simultaneously fed into tower 15 through line 12 along with recycle heavy hydro-carbon liquid through line 14. A liquid-gas mixture is withdrawn from the top of tower 15 through line 16 and introduced into the bottom of hot separator 17. In the hot separator, the effluent from tower 15 is separated into a gaseous stream 22 and a liquid stream 18. The liquid stream 18 is in the form of a heavy hydrocarbon oil containing pitch and a portion of this stream 18 is recycled through pump 19 and line 14 into inlet line 12 upstream or downstream of preheater 44 The balance of liquid stream 18 exits via line 20 and is withdrawn via pump 21 for collection. The pump 21 may be replaced in a commercial operation by let-down valves.
The ga~eous stream from hot separator 17 is carried by line 22 into a cold separator 23. Within this vessel the product is separated into a gaseous stream rich in hydrogen which is drawn off through line 26 and an oil product which is drawn off through line 24 and collected in receiver 25. This represents the light oil product of the invention.
The hydrogen rich stream 26 is passed through a water scrubher 27 to remove dmmonium sulphide and the stream 28 from the water scrubber is passed through a packed tower 29 where it is scrubbed by means of organic liquid 32 which is cycled through the tower by means of pump 31 and recyc~e loop 30.
The scrubbed hydroyen rich stream emerges from the scrubber via line 33 and is combined with fresh make up hydrogen added through line 34 and recycled by 1ine 35, through 1~958~6 gas pump 36, orifice 37 and line 13 back to tower 15.
The hot separator 17 is shown in greater detail in Figures 2 and 3. It includes a main cylindrical portion 40 with a truncated conical lower portion 41 merging into a liquid phase outlet pipe 18. A gaseous phase outlet pipe 22 is provided at the top of the sep-arator.
The liquid phase is maintained with a liquid level 42 and this is kept at a minimum sufficient to achieve a liquid seal into the pipe 18 while minimizing the residence time of the liquid within the separator.
As shown in Figure 2, the effluent from the hydrocracking zone is introduced into the separator by way of pipe 16 which is brought directly down through the cylindrical portion 40 below the liquid level 42. This pipe 16 terminates in a distributor 43 which uniformly distri-butes the effluent into the liquid.
An alternative embodiment is shown in Figure 3 in which the pipe 16 is introduced through the sidewall at a point below the liquid level 42, again connecting to a distributor 43 for uniformly distributing the effluent within the liquid phase.
Certain preferred embodiments of the invention will now be further illustrated by the following non-limitative examples.
1~95~6 Example 1 The charge stock employed was an ~thabasca bitumen having the ~ollowing propertles:
Specific gravity, 60/60F1.010 Sulphur, wt. % 4.73 . Ash, wt. % 0.56 Viscosity, cst at 210F 175.8 Conradson Carbon Residue, wt.% 13.7 Pentane Insolubles, wt. %15.6 10 Benzene Insolubles, wt % 0 57 Nickel, ppm 68 Vanadium, ppm 211 The above feed stock was passed through the reaction sequence shown in the attached drawing using two different operating conditions as follows:
, .._ _ Run Number R-2-1-2 R-2-2-4 , .__ . .. _ Duration, h 477 283 Pressure MPa 13.89 13.89 Gas Flow, g mol/kg of feed51.56 51.56 H2 Purity, vol. % 85 85 LHSV, 1.0 1.0 Reactor Temp. C. 4'0 460 l~ot Separator Temp. C., 450 450 2l Actual Feed Flow, q/ll 4535 ~554 Recycle Oil Flow , g/h 9060 12700 Recycle/Actual Feed Ratio ~ 2.8 There were no operational problems encountered during these runs. After completion of the runs, the pilot plant was dismantled and inspected for coke de-position or any type of contamination. No major foulinq of the hot separator was observed.
The yields and properties of the heavy hydrocarbon liquid withdrawn from the hot separator were as follows:
1~9~846 Reactor Temperature 450C 460 C
Run Number R-2-1-2 R-2-2-4 _ Yield on feed, wt. % 20.74 16.43 Yield on total liquid 22.95 18.33 product, wt. %
Specific gravity, 1.095 1.129 S. wt. ~ 3.6~ 3.59 N, ppm 8916 availahle Ni, ppm 241 361 V, ppm 755 1041 Ash, wt. % 2.67 3.53 Conradson Carbon residue, wt.~ 30.14 36.52 Pentane-insoluble, wt. % 30.62 38.15 Benzene-insoluble, wt. % 10.82 14.95 Distillate, (-524C), wt. %55.6 54.2 Distillate, sp. gr. 0.990 1.004 Pit~h (+524C), wt.% 44.4 45.8 . . . .
Example 2 In order to demonstrate the effects of the liquid velocities in the hot separator, parallel tests were run with and without recycle of heavy hydrocarbon liquid from the hot separator. The results are shown in the following table.
~95846 Run Number A-450 B-450 A-460 B-460 . _ . .. . ._. .
Reactor temp. C. 450 450460 460 Average liquid flow, g/h 219211261 1955 14906 Recycle oil withdrawal_ 976 _ 748 rate, g/h Superficial liquid velocity O. 053 0.274 0.048 0.360 in the reactor, cm/~ec.
Superficial average1.54 0.301.53 0.23 residence time for the firs t pass, h .
10 Total residence time for _ 3.8 _ 5.4 the recycle oil, h.
Liquid velocity in0.059 0.244 0.037 0.330 the separator, cm/sec.
__ ..
No major fouling of the hotseparatorwas observed during the above runs.
Example 3 (a) Hydrogenation reactions were carried out using the same pilot plant as in Example 1, with the same feedstock and the same reaction condition except a hot separator temperature of only 350C. The reactions were carried out both with and without a dip tube to introduce the mixed effluent below the liquid level in the separator and the results were compared.
After a running time of only 2 hours without dip tube being used, the bottom core and outlet line of the hot separator had become completely plugged. On the other hand, after a running time of 16 days using the dip tube, the system was still operational. Total deposits of about 6600 g. had formed in the total system, mostly within the hydrocracking reactor. Only small amounts of deposit had formed within the hot separator, mainly on the walls of the separator and the separator bottom. E~owever, these - 12 ~
1~9~
separator deposits were not sufficient to interfere with its operaticn.
(b) Because of the substantial deposits in the hydrocracking reactor, further tests were carried out under the same conditions as part (a) above using both a dip tube in the hot separator and a coal getter in the oil feed to the hydrocracking reactor. The coal getter was utilized as described in copending Canadian application Serial no. 269,020 filed December 31, 1976.
In one test with the coal getter and dip tube, only 132 g. of total deposits in the system had accumulated after 21 days of operation. In another test a total of 940 g. of deposits had accumulated after 3 days.
However, in both of these tests substantially all of the deposits were in the reactor and the hot separator was substantially free of any deposits.
Thus, it will be seen that the method of operating the hot separator according to this invention is highly effective in eliminating the problem of coke deposits in the hot separator regardless of the conditions in the hydrocracking reactor.
Claims (8)
1. In a hydrocracking process wherein a heavy hydrocarbon oil feed is treated with hydrogen in a reaction zone under conditions of high pressure of about 500 to 3,500 psig. and high temperatures of about 400 to 490°C., resulting in a mixed effluent containing a high boiling hydrocarbon liquid component at said pressure and temperature and a gaseous component and said mixed effluent is passed into a separation zone maintained substantially at the pressure of the reaction zone whereby the mixed effluent is separated into a gaseous phase comprising hydrogen and vaporous hydro-carbons and a liquid phase comprising heavy hydrocarbons, the gaseous phase being removed from an outlet in an upper region of said separation zone and the liquid phase being removed through an outlet in a lower region of said separation zone, the improvement which comprises:
maintaining a minimum liquid level in said separation zone sufficient to maintain a liquid seal in said liquid phase outlet and introducing said mixed effluent into the separation zone below said liquid level whereby phase separation and coke formation in the heavy hydrocarbon liquid phase is substantially eliminated.
maintaining a minimum liquid level in said separation zone sufficient to maintain a liquid seal in said liquid phase outlet and introducing said mixed effluent into the separation zone below said liquid level whereby phase separation and coke formation in the heavy hydrocarbon liquid phase is substantially eliminated.
2. The method of claim 1 wherein the separation zone is maintained at a temperature in the range of 150 to 500°C.
3. The method of claim 2 wherein a large proportion of said heavy hydrocarbon oil feed boils above 524°C.
4. The method of claim 2 wherein the heavy hydro-carbon oil feed is a heavy bituminous oil extracted from tar sands.
5. The method of claim 2 wherein the hydrocracking reaction zone is an up-flow tubular zone.
6. The method of claim 5 wherein heavy hydrocarbon liquid from the hot separator is recycled into the fresh feed to the hydrocracking zone in a volume ratio of recycle to fresh feed of at least 2:1.
7. The method of claim 1, 2 or 6 wherein the liquid hourly space velocity in the hydrocracking zone is in the range of 0.5 to 4Ø
8. The method of claim 1, 2 or 6 wherein the hydrogen recirculation is about 2,000 to 10,000 scf per bbl of feed.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA294,123A CA1095846A (en) | 1977-12-29 | 1977-12-29 | Method of preventing fouling of hot separator in hydroconversion of heavy hydrocarbon oils |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA294,123A CA1095846A (en) | 1977-12-29 | 1977-12-29 | Method of preventing fouling of hot separator in hydroconversion of heavy hydrocarbon oils |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1095846A true CA1095846A (en) | 1981-02-17 |
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ID=4110412
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA294,123A Expired CA1095846A (en) | 1977-12-29 | 1977-12-29 | Method of preventing fouling of hot separator in hydroconversion of heavy hydrocarbon oils |
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| Country | Link |
|---|---|
| CA (1) | CA1095846A (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2010002513A2 (en) | 2008-06-30 | 2010-01-07 | Uop Llc | Integrated process for upgrading a vapor feed |
-
1977
- 1977-12-29 CA CA294,123A patent/CA1095846A/en not_active Expired
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2010002513A2 (en) | 2008-06-30 | 2010-01-07 | Uop Llc | Integrated process for upgrading a vapor feed |
| EP2291491A2 (en) * | 2008-06-30 | 2011-03-09 | Uop Llc | Integrated process for upgrading a vapor feed |
| EP2291491A4 (en) * | 2008-06-30 | 2014-05-14 | Uop Llc | Integrated process for upgrading a vapor feed |
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