U.S. patent number 3,923,635 [Application Number 05/479,745] was granted by the patent office on 1975-12-02 for catalytic upgrading of heavy hydrocarbons.
This patent grant is currently assigned to Exxon Research & Engineering Co.. Invention is credited to Clyde L. Aldridge, Bernard L. Schulman.
United States Patent |
3,923,635 |
Schulman , et al. |
December 2, 1975 |
Catalytic upgrading of heavy hydrocarbons
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.
Inventors: |
Schulman; Bernard L. (Golden,
CO), Aldridge; Clyde L. (Baton Rouge, LA) |
Assignee: |
Exxon Research & Engineering
Co. (Linden, NJ)
|
Family
ID: |
23905248 |
Appl.
No.: |
05/479,745 |
Filed: |
June 17, 1974 |
Current U.S.
Class: |
208/50; 208/127;
208/108; 208/157 |
Current CPC
Class: |
C10G
45/16 (20130101) |
Current International
Class: |
C10G
45/02 (20060101); C10G 45/16 (20060101); C10G
013/02 (); C10G 037/04 () |
Field of
Search: |
;208/50,108,127,157,110,112 |
References Cited
[Referenced By]
U.S. Patent Documents
|
|
|
3541002 |
November 1970 |
Rapp |
3546103 |
December 1970 |
Hamner et al. |
3617481 |
November 1971 |
Voorhies et al. |
3715303 |
February 1973 |
Wennerberg et al. |
3726791 |
April 1973 |
Kimberlin et al. |
|
Primary Examiner: Levine; Herbert
Attorney, Agent or Firm: Gibbons; M. L.
Claims
What is claimed is:
1. 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 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.degree. to about 1000.degree.F. 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 1000.degree. to about
1700.degree.F., whereby at least a portion of the carbonaceous
deposition is converted to a gas comprising hydrogen and carbon
monoxide, and
f. recycling a portion of the catalyst particles from the
gasification zone to said reaction zone of step (a).
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.degree. to about 1200.degree.F. and at a pressure ranging
from about 0 to about 150 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.degree. to about 1200.degree.F. 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 (d), said separated catalyst particles are heated in a heating
zone.
7. The process of claim 1, wherein said solid carbon-containing
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 carbon-containing
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 carbon-containing
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.degree. to about
900.degree.F.
16. The process of claim 1, wherein an oxygencontaining gas is
introduced into the gasification zone of step (d).
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 carbon-containing 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.degree. to about 900.degree.F. 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;
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 1000.degree. to about
1700.degree.F., whereby at least a portion of the carbonaceous
deposition is converted to a gas comprising hydrogen and carbon
monoxide, and
f. 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 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 an ebullient
bed reaction zone maintained at an average temperature ranging from
about 700.degree. to about 1000.degree.F. 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;
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;
d. passing said catalyst-containing slurry to a fluid coking zone
operated at a temperature of about 850.degree. to about
1200.degree.F. and at a pressure ranging from about 0 to about 150
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 carbon-containing 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.degree. to about 1000.degree.F. 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.degree. to about
1200.degree.F. 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.
23. The process of claim 22 wherein a substantial portion of the
heavy liquid hydrocarbons are removed 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.degree. to about 1000.degree.F. 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 1000.degree. to about
1700.degree.F., whereby at least a portion of the carbonaceous
deposition is converted to a gas comprising hydrogen and carbon
monoxide, and
f. recycling a portion of the catalyst particles from the
gasification zone to said reaction zone of step (a).
Description
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.degree. to about 1000.degree.F. 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 1000.degree. to about
1700.degree.F., 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 is continuously regenerated and freed of
carbonaceous deposits which 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 110 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 600.degree.F. at atmospheric pressure,
preferably hydrocarbon feeds containing at least 10 weight percent
hydrocarbons having a boiling point greater than 900.degree.F. 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 wax 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 in the 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.degree. to about
1000.degree.F., preferably from about 750.degree. to about
900.degree.F., more preferably from about 775.degree. to about
875.degree.F., 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 20 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.sub.2 S. 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 these
deposits 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.degree.
to about 1200.degree.F., preferably, at about 950.degree. to about
1050.degree.F., and at a pressure of about 0 to about 150 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 1000.degree. to about 1700.degree.F., preferably from
about 1200.degree.F. to about 1500.degree.F. 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 metal-carbon
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.degree.
to about 800.degree.F. in excess of the actual coker operating
temperature. The burner may be operated, for example, at a
temperature between about 1400.degree. and 1500.degree.F. Air is
introduced into burner 5 via line 52 to oxidize a portion of the
coke deposit to carbon oxides with a resulting 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.degree. and 1500.degree.F., for
example, in this embodiment, between 1100.degree. and
1200.degree.F. 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 provide 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 10
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 potassium carbonate was gasified with
steam at a temperature of about 1180.degree. to about
1240.degree.F. and a pressure of 200 psig until 30 to 35 weight
percent of the coke was gasified. The resulting activated
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 1200.degree.F. 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
1300.degree.F. 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
300.degree.F. 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.sub.2 S by cadmium acetate
scrubbers.
The oil and solids were separated. The solids were then dried in a
vacuum oven at 302.degree.F. 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
1000.degree.F. 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 1300.degree.F. 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 1300.degree.F. 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 1000.degree.F. 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 which the ratio of K-coke 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, 10 and 11 . In this set of experiments, first 90.01 grams
of Jobo crude were treated under the indicated conditions over
28.88 grams (30 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 are shown in the Table. The
separation of the solids from the oil was completed by extraction
with benzene. The solids were coked and overall yields for the
three runs are listed in the Table. Run 12 was a comparative
(blank) run in which 29.9 grams (30 cc.) of fluid coke with no
potassium was the solid component in the slurry. The conditions
were substantialy the same as in Runs 9, 10 and 11 . The data in
the Table show that Runs 9, 10 and 11 in which the feed was
hydrogen-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 Run 12 in which fluid coke with no potassium was
used.
TABLE
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Feed Blend for Run No. Saf.Atm. Jobo Crude Run 6 1 2 3 4
__________________________________________________________________________
Conditions T. .degree.F., Avg. 801 846 866 824 Time, Min. on Temp.
75 56 50 50 H.sub.2 P.P., psig Start of Run 1515 1505 1610 1530 End
of Run 542 584 566 538 Average 1028 1045 1088 1034 Oil Charge 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 K-coke (B)
Gms. 52.39 57.46 57.42 53.95 Wt.% K, (wt.K/wt. coke .times. 100)
9.8 15.7 15.7 15.7 H.sub.2 Consumption, SCF/B of feed 619 526 555
475 Product Yields,wt. % on feed Oil 84.7 75.8 62.8 84.6 Adsorbed
material 9.8 14.3.sup.(h) 19.2.sup.(h) 8.2 Gas from treating
Methane 2.4 2.7 1.9 1.3 C.sub.2 -C.sub.4 3.1 7.2 16.1 5.9 Coke
after coking adsorbed material -- 8.4.sup.(b) -- 5.2.sup.(b) Oil
Analyses S,wt.% 4.00 3.99 1.78 2.32 2.78 2.71 2.03 Metals, ppm NI
22 85 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.% 0.26 0.66 0.183 0.224 0.238 0.186
Con.C. wt. % 11.52 12.75 -- 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 %
0.11.sup.(a) 0.18 Aromatic + Indanes, wt. % 14.6 Sat. + Unsats.,
wt. % 85.4 Bromine No. 24.7 22.0 H.sub.2 S in Exit gas, ppm 511 408
720 6050 5.sup.(c) 6.sup.(d) 7.sup.(e,f) 8 9,10,11.sup.(g) 12
Conditions T. .degree.F., Avg. 824 825 821 715 849 841 Time, Min.
on Temp. 50 20 70 60 35 35 H.sub.2 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
Saf.Atm. Saf.Atm. Jobo Crude Jobo Crude Gms. 92.47 68.49 89.77
90.79 233.67 90.72 Solids Charge wet solids- Description K-coke(B)
K-coke(B) from Run 6 K-coke(A) K-coke Fluid Coke Gms. 57.30 57.00
55.01 53.37 28.88 29.60 Wt.% K, (wt.K/wt. coke .times. 100) 15.7
15.7 -- 9.8 15.7 0 H.sub.2 Consumption, SCF/B of feed 937 209 926
<<364(leak) 1170 716 Product Yields, wt. % on feed Oil 88.2
85.4 92.9 83.6 75.2 Adsorbed 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.sub.2 -C.sub.4
2.8 0.58 3.60 nil 8.12 10.69 Coke after coking adsorbed material
4.0.sup.(b) 5.9 3.7 9.4 Oil Analyses S, wt. % 1.46 0.80 1.50 3.17
1.81 2.54 Metals, ppm Ni 2.70 1.43 1.60 39.9 20 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. % 0.208 0.147 0.177
0.258 0.53 0.40 Con.C. wt. % 4.66 3.2 4.0 6.08 6.27 8.82
Asphaltenes 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 + Indanes, wt. % Sat. + Unsats., wt. % Bromine No. 9.9
10.9 H.sub.2 S in Exit gas, ppm 0
__________________________________________________________________________
.sup.(a) Indirect by determination of sulfur content of a benzene
solutio .sup.(b) After coking of solids at 1000.degree.F. and
regeneration of catalyst at 1300.degree.F. and deducting OH +
CO.sub.3 from apparent coke yield. .sup.(c) Differs from the other
runs in having a preheat to 750.degree.F. under pressure, cooling,
replacing H.sub.2 then proceeding. .sup.(d) Similates second stage
of staged contacting of feed with fresh catalyst. .sup.(e)
Simulates first stage of staged contacting. .sup.(f) Preheat to
750.degree.F. and replacement with fresh H.sub.2 as i run 5.
.sup.(g) Three successive runs with fresh oil contacting the same
batch o K-coke. .sup.(h) Approximate cm What is claimed is:
* * * * *