U.S. patent number 3,617,470 [Application Number 04/786,952] was granted by the patent office on 1971-11-02 for hydrotorting of shale to produce shale oil.
This patent grant is currently assigned to Texaco Inc.. Invention is credited to Dale R. Jesse, Warren C. Schlinger, Joseph P. Tassoney.
United States Patent |
3,617,470 |
Schlinger , et al. |
November 2, 1971 |
HYDROTORTING OF SHALE TO PRODUCE SHALE OIL
Abstract
Continuous process for recovering shale oil from a slurry of raw
oil shale in shale oil. In a contacting zone, water and hydrogen
gas are injected under pressure into the raw oil shale-shale oil
slurry and the mixture is immediately introduced into a tubular
retort maintained at a temperature in the range of about
850.degree. to 950.degree. F. and at a pressure in the range of
about 300 to 1,000 p.s.i.g. and preferably at 500 p.s.i.g. for
maximum yields of shale oil having a minimum nitrogen content.
Under conditions of turbulent flow, in the tubular retort the raw
shale is completely stripped of kerogen in about one-fourth to 3
minutes (preferably less than a minute), and by simultaneous
pyrolysis and hydrogenation the kerogen is converted to a gaseous
effluent from which shale oil is separated having a substantially
reduced nitrogen and sulfur content. Further, essentially all of
the spent shale is removed from the gaseous stream by means of a
unique centrifugal separator and recovered without the loss of
hydrogen or the reduction in line pressure, as spent shale
containing essentially no carbonaceous residue. Yields of such
shale oil from for example Colorado shale are about 116 percent of
the Fischer Assay and contain less than 0.50 weight percent of
spent shale. Water is also produced by the system in quantities
which are in excess of process requirements.
Inventors: |
Schlinger; Warren C. (Pasadena,
CA), Jesse; Dale R. (Hacienda Heights, CA), Tassoney;
Joseph P. (Whittier, CA) |
Assignee: |
Texaco Inc. (New York,
NY)
|
Family
ID: |
25140038 |
Appl.
No.: |
04/786,952 |
Filed: |
December 26, 1968 |
Current U.S.
Class: |
208/408; 201/20;
208/417; 201/29 |
Current CPC
Class: |
C10G
1/065 (20130101) |
Current International
Class: |
C10G
1/06 (20060101); C10G 1/00 (20060101); C10b
053/06 () |
Field of
Search: |
;208/8,10,11
;201/20,29,31,32,33,36,37,38 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Davis; Curtis R.
Claims
We claim:
1. A continuous process for hydrotorting raw oil shale to remove
essentially all of the kerogen in said oil shale to produce shale
oil of improved quality and yield and to produce spent shale
containing essentially no carbonaceous matter or carbon
comprising:
1. introducing a pumpable raw oil shale-shale oil slurry into a
contacting zone;
2. introducing separate preheated high-pressure streams of hydrogen
in the range of about 5,000 to 20,000 s.c.f. of H.sub.2 per ton of
raw shale and liquid water in the range of about 0.01 to 0.6 ton of
H.sub.2 O per ton of raw oil shale into the contacting zone of (1)
to effect mixing of said hydrogen and water streams with said raw
oil shale-shale oil slurry, and immediately passing said mixture at
a temperature in the range of about 100.degree. to 500.degree. F.
into a noncatalytic tubular reaction zone having a turbulence
level, , in the range of about 25 to 100,000 where is the average
apparent viscosity and .nu. is the kinematic viscosity;
3. pyrolyzing in said tubular reaction zone the raw shale in the
slurry of (2) at an outlet temperature in the range of about
850.degree. to 950.degree. F. and at a pressure in the range of
about 300 to 1,000 p.s.i.g. for a period of from about one-fourth
to 3 minutes, while simultaneously hydrogenating the products of
said pyrolysis to produce a high-velocity gaseous effluent stream
of denitrogenated and desulfurized shale oil vapor, water vapor,
CH.sub.4, NH.sub.3, H.sub.2 S, CH.sub.4, CO.sub.2, CO and spent
shale;
4. introducing the gaseous effluent stream from (3) into a
gas-solids separating zone;
5. separately withdrawing from the separating zone of (4), a stream
of solids-free shale oil vapor containing gas and a stream of spent
shale particles essentially free of carbonaceous matter from
kerogen; and
6. separating shale oil from the solids-free shale oil vapor
containing stream of (5) in amounts and quality that exceed the
Fischer Assay.
2. The process of claim 1 wherein the raw oil shale is present in
the raw oil shale-shale oil slurry of (1) in an amount in the range
of about 30 to 80 weight percent; the hydrogen injected into the
slurry in (2) is supplied to the contacting zone of (1) at a
temperature in the range of about 100.degree. to 500.degree. F. and
in a minimum amount of 13,800 s.c.f. ton of raw shale and at an
inlet velocity in the range of about 5 to 50 f.p.s.; and wherein
the gaseous effluent stream from (3) is introduced into the
gas-solids separating zone of (4) at a minimum velocity of 33.6
f.p.s. to effect more than 99.50 weight percent separation of solid
particles dispersed in said gaseous stream.
3. The process of claim 1 wherein the noncatalytic tubular reaction
zone is maintained at an outlet temperature in the range of about
910.degree. to 940.degree. F., and at a pressure in the range of
about 475 to 525 p.s.i.g., and the shale oil produced by the
process is greater than the Fischer Assay.
4. The process of claim 1 wherein the spent shale particles in (5)
are withdrawn from said gas-solids separating zone with
substantially no loss of gas or pressure drop in the system by
steps of
1. collecting spent shale in a valvular zone comprising upper and
lower spaced valves in an exit pipe leading from said gas-solids
separating zone by opening said upper valve, and closing said lower
valve;
2. introducing H.sub.2 O upstream of said lower valve thereby
displacing all of the gas in said spent shale and forcing said gas
back into said gas-solids separating zone while forming a
shale-H.sub.2 O mixture between said valves;
3. closing said upper valve and opening said lower valve; and
4. pushing said shale-H.sub.2 O mixture out of the system by
introducing H.sub.2 O downstream of said upper valve.
5. The process of claim 1 wherein the gaseous effluent stream from
(3) is introduced at a velocity of from about 25 to 100 f.p.s. into
the gas-solids separating zone of (4) maintained at substantially
the same temperature and pressure as the tubular retort of (3).
6. A continuous process for hydrotorting raw oil shale to produce
shale oil of improved quality and yield comprising
1. forming in a mixing zone a pumpable slurry of raw oil shale
particles in a heavy shale oil carrier as defined hereinafter;
2. mixing together in a contacting zone the raw oil shale-shale oil
slurry of (1), a stream of recycle water in an amount sufficient to
substantially reduce the decomposition of inorganic carbonates in
the raw oil shale, and a stream of hydrogen-rich gas in an amount
sufficient to provide substantially all of the hydrogen required in
the next hydrotorting step;
3. introducing the mixture from the contacting zone of (2) at high
velocity into a noncatalytic tubular reaction zone located in
immediate juxtaposition to said contacting zone under conditions of
turbulent flow and at a pressure in the range of about 300 to 1,000
p.s.i.g., heating said mixture to an outlet temperature in the
range of about 850.degree. to 950.degree. F., for a period of about
one-fourth to 3 minutes while simultaneously subjecting the raw
shale oil particles in said mixture to the disintegrating action of
the highly turbulent flow therein and to the volumetric expansion
and vaporization of the water and shale oil, thereby simultaneously
effecting pyrolysis and hydrogenation of the raw shale and
hydrogenation of the shale oil produced and forming a high-velocity
gaseous stream of solid particles of spent shale and ash dispersed
in shale oil vapor, unreacted hydrogen, water vapor, H.sub.2 S,
NH.sub.3, CO, CH.sub.4 and CO.sub.2 ;
4. introducing the high-velocity gaseous effluent stream from (3)
at a velocity of from about 25 to 100 f.p.s. into a gas-solids
separating zone at substantially the same temperature and pressure
as in the tubular reaction zone of (3), and withdrawing
substantially all of the spent shale and ash substantially free
from organic matter from said gas-solids separating zone;
5. cooling the solids-free gaseous effluent from (4) in a gas
cooling zone to condense out crude shale oil and water containing
dissolved NH.sub.3, H.sub.2 S and CO.sub.2, and introducing said
liquid and uncondensed gaseous materials substantially comprising
unreacted hydrogen containing gas into a gas-liquid separating
zone;
6. removing the crude shale oil and water mixture from the
separating zone of (5) and introducing said liquid mixture into a
crude shale oil-water separation zone;
7. removing the water from the crude shale oil-water separation
zone of (6) and introducing said water into a water-purifying zone
where NH.sub.3, H.sub.2 S and CO.sub.2 are separated from pure
water;
8. withdrawing a portion of the pure water from the water-purifying
zone of (7) and recycling said water under pressure to the
contacting zone of (2);
9. withdrawing the hydrogen containing gas from the gas-liquid
separating zone of (5), compressing said gas, adding makeup
hydrogen and recycling said gas to the contacting zone of (2) as
said hydrogen-rich gas;
10. removing the crude shale oil from the crude shale oil-water
separating zone of (6) and introducing said crude shale oil into a
fractionation zone where pentane and lighter hydrocarbon fractions
are separated from heavier shale oil fractions;
11. distilling the heavier shale oil fractions from (10) in a
fractionation zone to produce a product shale oil substantially
free from carbon and with reduced nitrogen and sulfur content, and
a heavy shale oil bottoms product; and
12. withdrawing a portion of the heavy shale oil bottoms from the
fractionation zone of (11) for recycle to the mixing zone of (1) as
said heavy shale oil carrier.
7. The process of claim 6 wherein the raw oil shale is present in
the raw oil shale-shale oil slurry of (1) in an amount in the range
of about 30 to 80 weight percent; and the slurry is maintained at a
temperature in the range of about 100.degree. to 500.degree. F.;
the hydrogen-rich gas injected into the slurry in (2) comprises 45
or more volume percent of hydrogen on a dry basis and is supplied
to the contacting zone at a temperature in the range of about
100.degree. to 500.degree. F. and in an amount in the range of
about 5,000 to 20,000 s.c.f. of hydrogen per ton of raw shale and
at an inlet velocity in the range of about 5 to 50 f.p.s.; the
recycle water is injected into the slurry in (2) at a temperature
in the range of about 100.degree. to 500.degree. F. and in an
amount in the range of about 0.01 to 0.6 ton of water per ton of
raw oil shale; and said hydrogen-rich gas and said recycle water
are introduced into the contacting zone at a pressure in the range
of about 25 to 200 p.s.i. greater than the line pressure; and the
mixture from the contacting zone of (2) is introduced into the
noncatalytic tubular reaction zone of (3) at a turbulence level, in
the range of about 25 to 100,000, where is the average apparent
viscosity and .nu. is the kinematic viscosity, and at a temperature
below the vaporization temperature of water.
8. The process of claim 6 wherein the contacting zone of (2) is a
venturi mixer and as said raw oil shale-shale oil slurry is passed
axially through said venturi mixer said hydrogen-rich gas and said
recycle water are introduced into said slurry at the throat of said
venturi mixer.
9. The process of claim 7 wherein the noncatalytic tubular reaction
zone is maintained at an outlet temperature in the range of about
910.degree. to 940.degree. F., and at a pressure in the range of
about 475 to 525 p.s.i.g.; said hydrogen-rich gas supplied to the
contacting zone is supplied in a minimum amount of 13,800 s.c.f. of
hydrogen per ton of raw shale; said high-velocity gaseous effluent
stream is introduced into said gas-solids separating zone at a
minimum velocity of 33.6 f.p.s.; and the shale oil produced by the
process is greater than the Fischer Assay and is essentially free
from spent shale.
10. Apparatus for continuously separating spent shale particles
from a gaseous stream of spent shale particles in vaporized shale
oil and steam at a temperature in the range of about 850.degree. to
1,000.degree. F. and a pressure in the range of about 300 to 1,000
p.s.i.g., comprising
1. an elongated, vertical, cylindrical-shaped pressure chamber
having a closed top and a closed bottom;
2. a downwardly directed open-ended pipe coil of at least one loop,
said pipe coil being mounted concentrically in said chamber about
midpoint and having an upper inlet end and a lower discharge end,
said upper end passing through the vertical wall of said chamber
and making a pressuretight seal therewith;
3. an open-ended vertical exit gas pipe depending axially from the
top of said pressure chamber and having an upper end and a lower
end, said upper end of the exit pipe passing through the closed top
of said pressure chamber and making a pressure tight seal
therewith, a "T" fitting joined to the lower end of said exit pipe
and having two open ports in axial alignment, said axis being
disposed perpendicular to the axis of said pressure chamber and
said ports being located above the pipe coil of (2); and
4. a vertical spent shale discharge pipe with open ends and having
an upper portion and a lower portion, said upper end passing
through the center of said chamber bottom and making a
pressuretight seal therewith, and said lower portion depending
below said pressure chamber.
11. The apparatus of claim 10 with the addition of a first valve in
the lower portion of the spent shale discharge pipe of (4), a
second valve in said shale discharge pipe and located below said
first valve, a first means for introducing H.sub.2 O downstream
from said first valve and into the space in said shale discharge
pipe between said first and second valves, and a second means for
introducing H.sub.2 O upstream from said second valve and into the
space in said shale discharge pipe between said first and second
valves.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to the recovery of shale oil from oil shale.
More specifically it relates to an improved process which combines
tubular hydrotorting of a raw oil shale-shale oil slurry and the
centrifugal separation of entrained spent shale from the gaseous
effluent stream.
2. Description of the Prior Art
Oil shale consists of compacted sedimentary inorganic rock
particles, generally laminated and partly or entirely encased with
a high-molecular-weight organic solid material called kerogen,
which is present in the amount of about 6-22 weight percent.
Kerogen is derived from aquatic organisms or waxy spores and pollen
grains, comprising hydrocarbons and complex organic-nitrogen,
oxygen, and sulfur compounds. Nitrogen in kerogen is largely in the
form of quinoline-pyridine-type compounds, and the sulfur is
largely present in the form of thiophene-type compounds. Crude
shale oil produced from the oil shale by the pyrolysis of the
kerogen differs from crude petroleum by being more unsaturated and
having a higher content of nitrogen compounds. Further, poor color
stability and disagreeable odor of the shale oil products are
related to the presence of these compounds. One approximate
empirical formula for raw oil shale is C.sub.158 H.sub.265 O.sub.15
N.sub.4 .sup.. 6 S.
In most contemporary procedures, crude shale oil is obtained by
pyrolysis of the solid insoluble organic part of the raw shale
(kerogen). Thus, raw shale is subjected to destructive distillation
in a retort at a temperature of about 850.degree. to 950.degree. F.
The chemical decomposition of the kerogen which takes place by the
action of heat alone yields crude shale oil vapors, together with
water, gas, and spent shale containing a carbonaceous residue and
mineral matter. The application of hydrogenation to the tubular
retorting of oil shale for upgrading shale oil has been previously
proposed, for example U.S. Pat. No. 3,117,072 issued to DuBois
Eastman and Warren G. Schlinger. However, the liquid yields in
prior art processes are generally less than the Fischer Assay, the
nitrogen content in the crude shale oil is still high, consumption
of pure hydrogen is high, and relatively high reaction pressures
and temperature (1,000 to 20,000 p.s.i.g. and up to 1,500.degree.
F.) are required.
The Fischer Assay Test is a laboratory evaluation test for
estimating the maximum oil recoverable in a conventional air retort
system at atmospheric pressure. It does not measure the total
hydrocarbon content of oil shale, and spent shale from this assay
typically contains 5-percent organic and free carbon. In the
Fischer Assay a 100-gram sample of crushed (-8 mesh) oil shale, in
an aluminum retort at atmospheric pressure, is brought to a
temperature of 932.degree. F. (500.degree. C.) in 40 minutes; and,
it is then maintained at this temperature for an additional 20
minutes. The overhead vapors from the retort comprising essentially
shale oil and water are cooled, condensed, and collected in a
graduated centrifuge tube. Water is separated from the oil by
centrifuging, the quantities of oil and water produced are
measured, and the results for each are reported in units of gallons
per ton of raw shale. For further details of the Fischer Assay
refer to "Method of Assaying Oil Shale by a Modified Fischer
Retort" by K. E. Stanfield and I. C. Frost, R. I. 4477, June 1949,
U.S. Dept. of the Interior.
Contemporary retorting methods may be classified in general by the
manner which heat is applied: (1) indirect heating through the wall
of the retorting vessel; (2) direct heating by hot gases from
combustion within the retorting vessel; (3) heat transfer from an
externally heated carrier fluid; and (4) heat transfer from
recycled hot solids.
Disadvantages of some proposed retorting schemes include low heat
transfer rates and correspondingly low shale throughput, limited
vessel size, poor thermal control and low thermal efficiency,
difficult material-handling problems, high operating and equipment
costs, low yields in comparison with the Fischer Assay, and poor
quality of the shale oil. Further, hydrogen consumption is
generally excessive, pressures are high (about 1,000 p.s.i.g.),
relatively long retort periods are necessary (6 to 20 hours), spent
shale retains some carbonaceous values, and in comparison with
crude petroleum, the shale oil recovered is a very low grade.
Most commercial processes for converting raw shale into such liquid
fuels as jet and diesel fuels include the operations of retorting
raw shale to produce crude shale oil; and the delayed coking of the
crude shale oil, followed by hydrogenation and fractionation.
Established procedures for shale oil refining generally involve a
combination of cracking, distillation, and chemical refining
treatment which must of necessity be very carefully controlled in
order to prevent excessive losses of valuable reactive unsaturated
hydrocarbons.
In contrast with the prior art, by our hydrotorting process at
comparatively moderate pressures, a hydrogenated shale oil is
produced which contains comparatively no spent shale particles. The
absence of spent shale particles is especially desirable when the
product shale oil is further processed. For example, the life of a
catalyst bed is affected by shale particles in the treated shale
oil. Furthermore, regarding the shale oil produced, sulfur and
nitrogen levels may be reduced to those usually found in crude
petroleum, there is minimum degradation in the distillate boiling
range, and yields are greater. Such shale oil would then be
amenable to further processing by conventional crude refinery
techniques with high yields for a minimum of treating. Further, the
spent shale is comparatively free from any organic or carbonaceous
residue from the kerogen. By our process, retorting and
hydrogenation may be combined in one operation, obviating the
delayed coking step commonly used by other processes during
refining, and thereby saving costs.
SUMMARY l
We have discovered a continuous process for preparing maximum
yields of shale oil of reduced nitrogen and sulfur content and
containing substantially no spent shale particles from raw shale
under relatively reduced pressure. More particularly, the invention
relates to the discovery that raw shale can be readily converted to
shale oil and relatively kerogen-free dry powdered shale by
injecting a slurry of raw oil shale in shale oil with hydrogen
(about 5,000 to 20,000 s.c.f. of hydrogen per ton of raw shale) and
water (about 0.01 to 0.6 ton of water per ton of raw shale) under
pressure, and immediately introducing the mixture into an
externally fired tubular retort under conditions of turbulent flow.
Within a period of from about one-fourth to 3 minutes at an outlet
temperature of about 850.degree. to 950.degree. F. and at a
pressure in the range of about 300 to 1,000 p.s.i.g. and preferably
at a critical pressure of about 475 to 525 p.s.i.g., hydrogenation
takes place with no addition of a supplementary catalyst. Shale oil
is produced having a substantially reduced nitrogen and sulfur
content and with increased yields of about 116 volume percent of
the Fischer Assay. A unique centrifugal gas-solids separating
scheme, which utilizes the kinetic energy of the gaseous effluent
from the retorting zone at a minimum velocity of 33.6 f.p.s., is
provided to effect separation of substantially all of the entrained
solids from the shale oil vapors with no loss of hydrogen or
reduction in system pressure. Furthermore, if desired, still
greater yields of shale oil may be obtained (in some instances as
much as 125 percent of the Fischer Assay) by submitting solids-free
prehydrogenated gaseous effluent from the tubular reaction zone to
further hydrogenation in a separate catalytic hydrogenation
zone.
The principal object of this invention is to recover from raw oil
shale increased yields of hydrogenated shale oil of improved
product quality.
Another object of this invention is to simultaneously retort raw
oil shale and hydrogenate the kerogen and shale oil to produce
increased yields of a shale oil with a substantially reduced
nitrogen and sulfur content and containing less than 0.05 weight
percent of spent shale.
A further object of this invention is to separate and recover as a
pumpable slurry essentially all of the spent particles in the
effluent stream from the oil shale hydrotort without loss of
hydrogen nor reduction in system pressure.
A still further object of this invention is to provide a continuous
process for producing shale oil, water, and spent shale containing
essentially no carbonaceous matter from raw oil shale by means of a
continuous process having a high thermal efficiency, high oil
yield, and a high retorting rate.
DESCRIPTION OF THE INVENTION
The present invention involves an improved process for recovering
high-quality shale oil from raw oil shale at substantially improved
yields. Crushed raw oil shale is mixed with heavy shale oil derived
by the process of our invention, as hereinafter described, to
produce a pumpable raw oil shale-shale oil slurry comprising from
about 30 to 80 weight percent of raw oil shale. The particle size
of the crushed raw oil shale preferably is less than 1/4-inch
diameter (more preferably 1/8 inch or less) and the slurry is
pumpable at reasonable pressure levels, i.e. 100 p.s.i.g.
The raw oil shale-shale oil slurry is pumped to an externally
heated, elongated, tubular retorting zone of relatively great
length in comparison with its cross-sectional area (for example
about 1 inch to 8 inches inside diameter and larger, and about
500-4,000 feet long). Such a tubular retort is described in U.S.
Pat. No. 3,117,072 issued to DuBois Eastman and Warren G.
Schlinger. However, immediately prior to being introduced into said
tubular retorting zone, the raw oil shale-shale oil slurry is
introduced into a contacting zone where it is mixed with a stream
of hydrogen gas and a stream of liquid water under pressure. The
volume and velocities of the slurry, hydrogen, and water entering
the tubular reaction zone are controlled to (1) ensure highly
turbulent flow conditions therein, which combined with heat and
pressure therein promotes the disintegration of the shale and the
dispersal of the shale particles in the slurry-hydrogen mixture,
and (2) provide the gaseous stream entering the gas-solids
separator with a minimum velocity to maximize spent shale removal.
By the improvement of our invention, turbulence in the tubular
reactor is increased and the desired turbulence level in the range
of about 25 to 100,000 and preferably 1,000 is easier to attain
than ever before. Thus, the velocity of the slurry may be decreased
for a given-sized tubular reactor without affecting the high
reaction rate. As used herein, turbulence level is defined by the
ratio of where is the average apparent viscosity and .nu. is the
kinematic viscosity, and is more fully described in U.S. Pat. No.
2,989,461 issued to DuBois Eastman et al.
For example, in a venturi mixer, from about 5,000 to 20,000 s.c.f.
of hydrogen per ton of raw shale and preferably a minimum of 13,800
s.c.f. of H.sub.2 /ton of raw shale at a temperature of about
100.degree. to 500.degree. F. are injected into the slurry
maintained at a temperature in the range of about 100.degree. to
500.degree. F. for hydrogenation and to ensure maximum removal of
spent shale in the gas-solids separator. To provide this volume of
hydrogen, the inlet velocity of the slurry hydrogen is maintained
at about 5 to 50 f.p.s., and preferably a minimum of 9 f.p.s.
(basis inlet conditions). Further, recycle water of a temperature
in the range of about 100.degree. to 500.degree. F. is injected
into the slurry in the amount of about 0.01 to 0.6 ton of water per
ton of crushed raw shale and preferably about 0.1 to 0.4 ton of
water per ton of crushed oil shale. Both the hydrogen-rich gas
(comprising 45 or more volume percent H.sub.2 on a dry basis) and
the recycle water is supplied to the venturi mixer at a pressure of
about 25 to 200 p.s.i. greater than the system line pressure. The
process removes 99.5 weight percent of spent shale, of which 90-95
percent passes through a U.S. standard 325-mesh sieve.
Addition of hydrogen to the slurry and the hydrogenation of the
pyrolysis products of the kerogen improves the yield of the product
shale oil and provides the product with a greater amount of the
desirable middle distillate material, while the formation of heavy
polymers, unsaturated hydrocarbons and carbonaceous residues which
characterize known processes are suppressed. Injecting water into
the slurry before the tubular retort was found to have several new,
unexpected and unobvious results. The velocity through the tubular
retort, the turbulent flow, and the heat transfer coefficient of
the mixture in the retort are all increased. Thus, rapid heat
transfer is effected which allows conversion of the kerogen to
crude shale oil in the retort coils at residence times of about
one-fourth to 3 minutes and preferably less than 1 minute.
Furthermore, vaporization of the water in the coils tends to
disintegrate the shale particles and facilitates atomization of the
shale oil. Also, coking of the slurry may be minimized or
eliminated at a substantially reduced hydrogen consumption. Other
unobvious advantages for injecting the water under pressure into
the shale-oil slurry just prior to introducing the slurry into the
tubular reactor include: (1)greater concentration of raw shale may
be incorporated in pumpable oil-shale slurries, (2) less water is
required in our process than when water is added to the shale in
the slurry mixing tank; (3) clogging of the retort tubing is
prevented; (4) better control of the amount of water added; and
finally, (5) it was unexpectedly found that water addition reduces
the endothermic decomposition of inorganic carbonates in the shale
to form CO.sub.2, thereby preventing the undesirable reaction
between CO.sub.2 and hydrogen to form H.sub.2 O and CO. Thus by
water injection, there is a savings of energy in the form of heat
used for carbonate decomposition as well as a reduction of hydrogen
consumption in the tubular retort.
The mixture of raw oil shale-shale oil slurry, water, and hydrogen
is introduced into the tubular retort at an inlet velocity such
that the velocity of the effluent from the tubular retort entering
the gas-solids separator is in the range of about 25 to 100 f.p.s.
and preferably greater than about 33.6 f.p.s. As the slurry mixture
passes through the tubular retort it is heated to a temperature in
the range of about 700.degree. to 1,100.degree. F. and preferably
to an outlet temperature of 850.degree. to 950.degree. F. while at
a pressure in the range of from 300 to 1,000 p.s.i.g., and
preferably at a critical pressure range of about 475 to 525
p.s.i.g. It was unexpectedly found that maximum yields of shale oil
of improved quality and containing a greater amount of C.sup.+
.sub.6 material are obtained by operating within this critical
pressure range. Further, oil yields of about 36.3 gallons of
24.0.degree. API gravity oil per ton of raw shale may be expected
in comparison with a Fischer Assay of about 31.2 gallons per ton.
This represents an increase of about 16 percent and is an
improvement over the yield from contemporary processes. Also,
examination of the hydrotort shale oil produced at this pressure
shows it to be of superior quality; that is compared with a Fischer
Assay of the same shale the sulfur and nitrogen content of our
shale oil are each about 25 to 35 percent lower. Further, the
nitrogen content of the hydrotort oil reaches a minimum at the
critical pressure of about 500 p.s.i.g. However, the sulfur content
of the shale oil decreases as the pressure increases above 500
p.s.i.g.
The gaseous effluent stream leaving the tubular retort, comprises
vapors of shale oil and water, unreacted hydrogen,
NH.sub.3,CH.sub.4, H.sub.2 S, CO.sub.2 and CO, along with entrained
spent shale particles (about 200 to 350 mesh)and is introduced into
a suitable gas-solids separating zone maintained at about the same
temperature and pressure as in the tubular retort less normal line
losses to effect separation of the spent shale particles from the
remaining gaseous stream. The spent shale recovered is
substantially free from carbonaceous material and is a suitable
feedstock for further processing, such as making cement. By
introducing the gaseous effluent stream from the tubular retort
into the gas-solid separator of our invention at a minimum velocity
of about 33.6 f.p.s., the collection efficiency (weight of shale
dust collected to shale dust in feedstream to the separator) of our
gas-solids separator is in excess of 99.50 weight percent.
Essentially all of the suspended insoluble ash constituents, spent
shale particles, and particulate carbon particles are
simultaneously removed from the hot effluent vapors from the
tubular reactor by means of our unique gas-solids separator.
Further, because of the high temperature and pressure involved and
the requirement for essentially complete solids removal, cyclone
separators of conventional design are unsuitable. Instead, in our
process, gas-solids separation takes place in an elongated,
vertical, cylindrical-shaped pressure chamber. The effluent stream
leaving the tubular reactor at high velocity enters the gas-solids
separator about midpoint. Passing through a downwardly directed
pipe coil of one or more loops, the effluent stream is then
discharged into the separation vessel at a high circumferential
speed. On account of "centrifugal force" (actually, the absence of
centripetal force necessary to restrain them), the solid particles
in the effluent stream move to the wall of the vessel and fall to
the bottom. The spent shale at the bottom of the gas-solids
separator contains about 40 volume percent of hydrogen. A spent
shale discharge system, which effectively solves the problem of
removing the dry, powdery, and difficult-to-handle spent shale from
the bottom of the gas-solids separator without the loss of hydrogen
or the reduction of system pressure, is employed and will be
described later. Essentially solids-free gas is removed through an
exit pipe which depends axially from the upper end of the vessel
and terminates above said inlet coil. A "T" fitting is joined to
the lower end of the exit pipe to baffle and further separate out
minute solid particles and to regulate the flow and direction of
the exit gases.
The solids-free hot gaseous effluent leaving overhead from the
gas-solids separating zone comprises shale oil vapor, unreacted
hydrogen, water vapor, hydrogen sulfide, CO.sub.2, CO, CH.sub.4 and
ammonia. This hot gaseous stream may be cooled to recover product
shale oil and water. Or alternately, the hot gases may be subjected
to further hydrogenation in a bed of hydrogenation catalyst to
increase the yield of the recovered product shale oil to about 125
percent of Fischer Assay. For example, with essentially all of the
suspended insoluble ash constituents and spent shale particles
removed by the gas-solids separator, the hot effluent vapors from
the tubular reactor, at a pressure in the range of about 300 to
1,500 p.s.i.g. and preferably the same pressure as in the tubular
retort less normal pressure drop in the lines of about 100 p.s.i.g.
and at a temperature in the range of about 700.degree. to
1,000.degree. F. and preferably the same temperature as in the
retort less line losses are directed over one or more beds of
catalyst which are effective for promoting the hydrogenation of
hydrocarbons, such as a fixed bed of cobalt-molybdate,
cobalt-nickel or nickel-molybdate hydrogenation catalyst. Effective
catalysts in general include compounds of the Group VI metals and
of the first transition series of Group VIII of the Periodic Table
of the Elements. Suitable known solid hydrogenation catalysts
include oxides or sulfides of molybdenum, cobalt, tungsten,
chromium, iron, vanadium, or nickel on a suitable carrier material
such as silica, alumina, bauxite, magnesia, zirconia, aluminum
silicate, or clay. For example, the catalyst may comprise from
about 1 to 10 weight percent of cobalt oxide and about 5 to 20
percent of molybdenum oxide on an alumina support.
Thus by our improved process, shale oil may be produced by one or
two hydrogenation steps: in one step, water under pressure is
injected into a raw oil shale-shale oil slurry and hydrotorting
takes place immediately in a tubular retort with no supplementary
hydrogenation catalyst added; and if desired, a second
hydrogenation step is added wherein hydrogenation of the effluent
from the first step takes place in a fixed or fluid bed of
hydrogenation catalyst, after substantially all of the particulate
matter, tar, and heavy hydrocarbons are removed. Direct contact of
the gaseous effluent with catalyst in the second step eliminates
the need for condensing and reheating the hydrocarbons prior to
catalytic treatment. The first hydrogenation step reduces nitrogen
content of the shale oil to a level which permits the use of fixed
bed catalysts. The more reactive olefins and hydrocarbons present
are also saturated and the Conradson carbon is reduced to only
one-fourth to one-half the carbon residue normally associated with
shale oil. Thus the gaseous effluent is suitable for direct vapor
catalytic processing without the normal coke-stilling step. At the
cost of additional hydrogen, the second hydrogenation step over a
fixed catalyst bed may be used, if desired, to improve both the
quantity and quality of the shale oil product. Thus, shale oil
recovered by our double hydrogenation process was unexpectedly
found to show increased API gravity and characterization factor,
improved distillation characteristics, greater yields, i.e. 125
percent of Fischer Assay, and considerably less sulfur, nitrogen
and carbon residue.
By the process of our invention, the higher boiling hydrocarbons
are subjected to viscosity-breaking with substantially immediate
hydrogenation of the molecular fragments and without further
breakdown, thereby materially increasing the production of material
boiling in the 400.degree.-700.degree. F. range without substantial
increase in lower boiling gasoline range materials or the formation
of normally gaseous hydrocarbons and heavy tars and coke.
DESCRIPTION OF THE DRAWING
A more complete understanding of the invention may be had by
reference to the accompanying schematic drawing which shows the
previously described process in greater detail. Although the
drawing illustrates a preferred embodiment of the process of this
invention, it is not intended to limit the invention to the
particular apparatus or materials described.
With reference to the drawing, particles of raw shale in line 1 and
heavy shale oil in line 2 are introduced into mixing tank 3 where
they are mixed by agitator 4, forming a raw shale-shale oil slurry.
This slurry is passed from the bottom of mixing tank 3 through
valve 5 and into the suction end of screw pump 6. At a temperature
in the range of about 100.degree. to 500.degree. F., the slurry is
pumped through line 7 to a gas-liquid contactor 8, which may be in
the form of a venturi mixer. Recycle hydrogen rich gas from line 9
and makeup hydrogen from line 10 are mixed in line 11 and injected
into the accelerated slurry stream at the throat of the venturi
mixer 8. Recycle water in line 12 is similarly injected into the
slurry. The pressure of each of the streams in lines 11 and 12
exceeds the system line pressure by about 25 to 200 p.s.i.
The resulting intimate mixture of hydrogen gas, water, raw oil
shale particles, and heavy shale oil at a temperature below the
vaporization temperature of water is accelerated to a high velocity
in contactor 8 and is then directed through line 13 into externally
heated tubular retort 14 situated immediately after contactor 8.
Under conditions of high turbulence in tubular retort 14, the
mixture is raised within seconds to a temperature in the range of
about 700.degree. to 1,100.degree. F. and disintegration and
pyrolysis of the raw shale, vaporization of the shale oil and
water, and hydrogenation of the kerogen and shale oil all take
place simultaneously. No supplementary catalyst need be added to
the aforesaid materials in the tubular retort to promote the
reactions therein.
A hot gaseous effluent stream comprising shale oil vapor, unreacted
hydrogen, water vapor, H.sub.2 S, NH.sub.3, CO.sub.2, CO, CH.sub.4,
and shale dust in the form of a fine dry powder of about 200-325
mesh, leaves tubular retort 14 at high velocity through line 15 and
is discharged into gas-solids separator 16 where the kinetic energy
of the gaseous effluent is employed to effect separation of the
spent shale from the rest of the effluent stream. Separator 16 is a
vertical cylindrical-shaped chamber with line 15 entering about
midpoint and then descending in a spiral of about two loops 17.
Thus, whirling motion is imparted to the gaseous effluent at its
discharges from the end of the spiral pipe at point 18. By
centrifugal force or acceleration, shale dust particles in the
gaseous effluent are separated from the remainder of the effluent
and move to the walls of the separating chamber. From there, the
dry spent shale dust, substantially free from any hydrocarbonaceous
residue, falls to the bottom of chamber 16 and is removed through
line 19, which leads to the spent shale discharge system. To
prevent plugging with spent shale and heat loss, the gas-solids
separation chamber 16, the overhead transfer lines, line 15 from
the tubular reactor, and exposed flanges and pipe joints are
insulated to maintain the gaseous stream at a temperature of about
850.degree. to 950.degree. F.
Spent shale is removed from separator 16 without severe loss of
hydrogen or pressure drop in the gaseous system by the following
steps: valve 20 in line 19 is opened and valve 21 is closed to
permit spent shale to collect in line 22 between the valves; water,
steam, or both from line 23 is introduced into line 22, thereby
displacing the hydrogen gas therein and forcing the gas back into
line 19 and chamber 16; valve 20 is closed and valve 21 is opened;
water, steam, or both from line 24 is introduced into line 22,
thereby discharging the hot shale powderwater slurry in line 22,
through valve 21 and into storage, or the discharge material may be
used directly as preheated feedstock in some chemical process not
shown, such as making cement.
An exit pipe 25 for removing essentially solids-free gas from
separator 16 depends axially from the upper end of separator 16,
and terminates above loop 17. A "T" fitting 26 with two ports open
in a direction perpendicular to the axis of the separating chamber
is joined to the end of exit pipe 25 inside of the chamber. Since
this embodiment of our invention involves the production of shale
oil by hydrotorting in tubular retort 14 only, that is, with no
subsequent hydrogenation in a catalytic reactor, the hot
solids-free gaseous effluent from separator 16 comprising shale oil
vapor, water vapor, H.sub.2 S, CO.sub.2, CH.sub.4, CO, and NH.sub.3
is then directed through line 27 into cooler 28. Water and shale
oil are condensed out in cooler 28 and pass through line 29 into
gas-liquid separator 30. Unreacted hydrogen rich gas is removed
from the top of separator 30 and is passed through line 31 into
compressor 32. Compressed recycle hydrogen-rich gas is passed
through lines 33, 34, 35 and 9 and is mixed in line 11 with makeup
hydrogen from line 10 in the manner previously described. If
necessary this hydrogen mixture may be heated to a temperature in
the range of about 100.degree. to 500.degree. F. before it is
introduced into contactor 8 by means of a heat exchanger in the
system.
Build up of gaseous impurities in the system, such as H.sub.2 S,
CO.sub.2, CO, CH.sub.4, may be prevented by introducing all or a
portion of the hydrogen-rich gas in line 33 through lines 36 and 37
into a standard gas purifier 38. Valves 39 and 40 control flow. Gas
purifier 38 utilizes refrigeration and chemical absorption to
effect separation of the gases, such as described in U.S. Pat. No.
3,001,373 issued to DuBois Eastman and Warren G. Schlinger. H.sub.2
S, CO.sub.2, CO, CH.sub.4, and H.sub.2 are separated from each
other and leave gas purifier 38 by respective lines 41, 42, 43, 44
and 45. Hydrogen from lines 45 and 9 is mixed in line 11 with
makeup hydrogen from line 10 and may constitute the hydrogen feed
to venturi contactor 8 as previously described.
Shale oil-water mixture is withdrawn from the bottom of gas-liquid
separator 30 and is passed through line 46 into shale oil-water
separator 47, where the lighter shale oil separates out and floats
on a water layer which contains dissolved H.sub.2 S, NH.sub.3 and
CO.sub.2. The water layer is removed at the bottom of separator 47
through line 48 and is introduced into a standard water purifier 49
where H.sub.2 S, NH.sub.3, and CO.sub.2 are removed through line 50
and are directed to a standard NH.sub.3, H.sub.2 S, and CO.sub.2
recovery system. Purified water is removed through line 51 and a
portion is recycled to contactor 8 by means of pump 52 through
lines 53 and 12, in the manner as previously described. Surplus
water is discharged from the system through line 54.
The crude shale oil layer in separator 47 is withdrawn through line
55 and introduced into stabilizer 56 whereby fractionation, pentane
and lighter hydrocarbon fractions are separated and pass out at the
top through line 57. Crude shale oil is withdrawn from the bottom
of stabilizer 56 through line 58 and is introduced into
fractionation column 59. A portion of the heavy shale oil bottoms
from column 59 at a temperature up to 800.degree. F. is recycled
through lines 60 and 2 into mixing tank 3 for making the raw oil
shale-shale oil slurry feed to the process, in the manner as
previously described. Generally, no heavy shale oil recycle pump is
necessary since the system pressure will move the oil to the mix
tank. The remainder of the heavy shale oil is removed from the
system through line 61. Product shale oil is removed from the
system through line 62.
Since most shale deposits are located in arid regions, one
significant advantage of our process is that there is no net
consumption of water; but in fact, an excess of water may be
produced.
EXAMPLES
The following examples are offered as a better understanding of the
present invention but the invention is not to be construed as
limited thereto.
EXAMPLE I
Colorado oil shale having a Fischer Assay of 31.2 gallons of shale
oil per ton of raw oil shale and 2.9 gallons of H.sub.2 O per ton
of raw oil shale is crushed to -8 mesh and mixed with heavy shale
oil to form a slurry comprising 75.6 weight percent of raw shale.
Immediately after water and hydrogen are injected into the slurry
under pressure, the mixture is hydrogenated in a 1-inch SCH.
40-pipe .times. 530-feet-long noncatalytic tubular retort.
Operating conditions and results of runs, in accordance with the
first embodiment of the process of our invention as previously
described are summarized in table I, column 1. In column 2 there is
shown a summary of the conditions and results of double
hydrogenation, first in the noncatalytic tubular retort and second
over a Co-Mo hydrogenation catalyst, representing a second
embodiment of our invention. It appears, from a comparison of
columns 1 and 2, that the second embodiment is the preferred
procedure because it provides higher yields of product shale oil
having a higher API and characterization factor, improved
distillation characteristics and considerably less sulfur,
nitrogen, and carbon residue. Further, in comparison with the
Fischer Assay, the data for both embodiments show a substantial
increase in product-oil yields; an improvement in API gravity, pour
point, and yield of distillate; and a reduction in the nitrogen and
the sulfur content in the shale oil product. ##SPC1## ##SPC2##
EXAMPLE II
This example will demonstrate the relationship between shale oil
yields and pressure in the continuous noncatalytic tubular
hydrotort described previously. By maintaining all of the operating
conditions described in example I substantially the same with the
exception of pressure in the tubular retort, it may be shown from
the data in table II below that shale oil yields increase with
pressure to a maximum of 500 p.s.i.g. Then yields decrease with
increasing pressure to about 900 p.s.i.g. where they seem to level
out. Line numbers refer to the drawing. The shale oil yields range
from 103 to 116 percent of the Fischer Assay (F.A.) and the water
yields range from 159 to 283 percent of the F.A. Lower yields would
be expected at temperatures in the tubular retort which are higher
than 950.degree. F. due to cracking of the oil to gas. At
temperatures lower than 800.degree. F. incomplete cracking of
kerogen would be anticipated, producing lower liquid yields. It is
also shown from the data in table II that maximum denitrification
occurs at a critical pressure of about 500-600 p.s.i.g. However,
desulflurization and water yield vary directly with retort
pressure. ##SPC3##
EXAMPLE III
In table III below there is shown the relationship between the
velocity of the gaseous effluent stream entering gas-solids
separator 16 (at inlet conditions of temperature and pressure), and
the weight percent of spent shale removed from the gaseous stream.
All other operating conditions are maintained substantially the
same as described previously in example I. From table III it
appears that 100 percent of the spent shale is removed from the
gaseous effluent stream by introducing the gaseous stream into
separator 16 at a minimum velocity of 33.6 f.p.s. (at inlet
conditions of temperature and pressure). At this rate, there was
supplied to contactor 8 a minimum of 13,800 s.c.f. of hydrogen per
ton of raw shale.
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TABLE III
Velocity of Gaseous Hydrogen Stream Supplied to Entering Contactor
8 Spent Shale Separator 16 s.c.f./ton Removed Run No. f.p.s. Raw
Shale wt. %
__________________________________________________________________________
CS-9 20.5 7,540 26 CS-12 33.6 13,800 100 CS-23 50.0 20,700 100
__________________________________________________________________________
the process of the invention has been described generally and by
examples with reference to raw shale-shale oil slurry feedstocks of
particular compositions for purposes of clarity and illustration
only. It will be apparent to those skilled in the art from the
foregoing that various modifications of the process and materials
disclosed herein can be made without departure from the spirit of
the invention.
* * * * *