U.S. patent number 3,891,403 [Application Number 05/339,547] was granted by the patent office on 1975-06-24 for oil shale hydrogasification process.
This patent grant is currently assigned to Institute of Gas Technology. Invention is credited to Dharamvir Punwani, Paul B. Tarman, Sanford A. Weil.
United States Patent |
3,891,403 |
Weil , et al. |
* June 24, 1975 |
Oil shale hydrogasification process
Abstract
A process for producing a high methane content, synthetic
pipeline gas from oil shale. The process includes providing a
hydrogasification reaction chamber having a hydrogen partial
pressure of at least 100 psig and a temperature of about
1000.degree.-1400.degree.F. The shale is introduced at the top of
the reaction chamber which includes an upper, oil shale preheat
zone having a temperature up to 1000.degree.F., a hydrogasification
reaction zone at a temperature of about 1000.degree.-1400.degree.F.
and a lower hydrogen preheat zone, also having a temperature of
about 1000.degree.-1400.degree.F. Solids from the shale are passed
downwardly through the chamber so that the shale, and particularly
the oil therein, is gradually heated to the reaction temperature
over a relatively extended period of at least ten minutes so as to
inhibit the formation of a carbon residue. A hydrogen rich gas,
containing hydrogen in excess of stoichiometric amounts needed for
the hydrogasification of the oil in the shale, is passed upwardly
in the reaction chamber and countercurrent to the shale solids
passing downwardly therethrough. A hydrogenation reaction is
promoted in the reaction chamber between the oil or organic
material in the shale and the hydrogen so as to produce a gaseous
mixture which includes volatilized liquids, methane and hydrogen.
The mixture is thereafter separated into hydrogasifiable and
non-hydrogasifiable liquid fractions, hydrogen, and the desired
high methane content synthetic pipeline gas. The hydrogen and the
hydrogasifiable liquid fraction are circulated back to the reaction
chamber, the hydrogen being used as at least a portion of the
hydrogen rich gas reacting in the chamber and the hydrogasifiable
liquid enters the hydrogasification or the hydrogenation
reaction.
Inventors: |
Weil; Sanford A. (Chicago,
IL), Tarman; Paul B. (Elmhurst, IL), Punwani;
Dharamvir (Chicago, IL) |
Assignee: |
Institute of Gas Technology
(Chicago, IL)
|
[*] Notice: |
The portion of the term of this patent
subsequent to June 24, 1992 has been disclaimed. |
Family
ID: |
23329540 |
Appl.
No.: |
05/339,547 |
Filed: |
March 9, 1973 |
Current U.S.
Class: |
48/197R;
208/400 |
Current CPC
Class: |
C10J
3/20 (20130101); C10J 3/482 (20130101); C10J
3/06 (20130101); C10J 2300/0946 (20130101); C10J
2300/1807 (20130101); C10J 2300/0959 (20130101); C10J
2300/0976 (20130101); C10J 2300/1884 (20130101) |
Current International
Class: |
C10J
3/02 (20060101); C10J 3/06 (20060101); C10j
003/06 () |
Field of
Search: |
;48/197R,211,213,210,199R,201 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
|
|
|
|
|
|
|
654,289 |
|
Dec 1962 |
|
CA |
|
503,183 |
|
Oct 1937 |
|
GB |
|
Primary Examiner: Bashore; S. Leon
Assistant Examiner: Kratz; Peter F.
Attorney, Agent or Firm: Molinare, Allegretti, Newitt &
Witcoff
Claims
What we claim and desire to secure by Letters Patent is:
1. A process for producing a high methane content, synthetic
pipeline quality gas from kerogen containing oil shale, wherein
there is a minimal carbon residue formation resulting from the
conversion of the kerogen to the pipeline quality gas which
comprises the steps of:
a. continuously flowing the kerogen containing oil shale through a
preheat zone at a flow rate sufficient to provide at least ten
minutes to gradually heat the oil shale from a temperature of
600.degree. to a temperature of 1000.degree.F.;
b. continuously contacting the oil shale in the preheat zone during
the gradual heating with a countercurrently flowing
hydrogasification product gas stream as removed from a hereinafter
defined hydrogasification zone;
c. said hydrogasification gas stream containing at least
stoichiometric amounts of hydrogen to achieve a high hydrogen to
oil ratio in the preheat zone;
d. withdrawing a preheated kerogen containing oil shale from the
preheat zone and passing the preheated shale to a hydrogasification
zone;
e. hydrogasifying, in the hydrogasification zone, the preheated
kerogen containing oil shale at a temperature of
1200.degree.-1500.degree.F. in the presence of a countercurrently
flowing hydrogen rich gas stream containing at least stoichiometric
amounts of hydrogen to achieve a high hydrogen to oil ratio and, to
produce hot spent shale and a hydrogasification product gas
stream;
f. passing said hydrogasification product gas stream to said
preheat zone of step (b) as said hydrogasification product gas
stream;
g. maintaining the hydrogen partial pressure in the preheat and
hydrogasification zone at a pressure of at least 100 psig.;
h. withdrawing a final product gas stream from said preheat zone
comprising hydrogen, volatilized liquid products and gaseous
hydrogasification products;
i. separating said final product gas stream into a hydrogen rich
gas stream, said high methane content synthetic pipeline gas, a
hydrogasifiable liquid distillate fraction and a hydrogasifiable
non-distillate fraction;
j. recycling the hydrogen rich gas to said hydrogasification
zone;
k. passing the hydrogasifiable distillate fraction to the
hydrogasification zone; and
l. passing the non-distillate fraction to the preheat zone at a
point where the shale is at a temperature of
600.degree.-700.degree.F. whereby a maximum net conversion of
kerogen to substitute natural gas is obtained.
2. A process according to claim 1 where the hydrogen rich gas
stream passed to the hydrogasification zone is first contacted with
the hot spent shale.
3. A process according to claim 1 wherein said shale is
additionally gradually heated from 1000.degree. to 1200.degree.F.
for at least 5 minutes in said preheat zone.
4. A process as in claim 1 wherein said hydrogen partial pressure
is about 500 psig..
5. A process as in claim 1 wherein the oil shale has a residence
time in the preheat zone of 10 - 120 minutes.
6. A process as in claim 1 wherein said hydrogen rich gas stream
has a residence time in the hydrogasification reaction zone of 20 -
50 seconds.
7. A process as in claim 1 wherein said hydrogasifiable liquid
distillate includes a light liquid fraction, said light liquid
fraction being converted to make up hydrogen for use in said
process.
8. The process of claim 1 including the step of producing said
hydrogen rich gas in a synthesis gas generator, said hydrogen rich
gas having a temperature up to 2200.degree.F., said synthesis gas
also including carbon monoxide, carbon dioxide and steam.
9. The process of claim 1 wherein said oil shale is first crushed
to provide shale pellets having a size of about 1/4-1 inches in
diameter.
10. A process as in claim 1 wherein said non-distillate fraction is
provided by distillation and boils above 650.degree.F..
Description
BACKGROUND OF THE INVENTION FIELD OF THE INVENTION and DESCRIPTION
OF THE PRIOR ART
This invention relates to a process for the production of a high
methane content, synthetic pipeline gas suitable for use as a
substitute for or as a supplement to natural gas, and the invention
particularly relates to a process wherein oil shale is used in the
production of the synthetic gas.
It is well recognized that there is an increasing shortage of
natural gas supplies in the United States, and there is a generally
limited supply of natural gas throughout the world, as compared to
more abundant reserves of liquid petroleum oils, coal, oil shale,
etc. Natural gas suitable for distribution to residential,
commercial and industrial consumers is characterized by heating
values ranging from about 900 to 1100 Btu/SCF and by a high methane
content, normally 80 percent by volume or greater. Such natural gas
often includes ethane and sometimes nitrogen. If the nitrogen
content is high in natural gas, propane and butane may be added and
ethane may be left in the gas to compensate for the diluting effect
of the nitrogen. Various sulfur compounds, carbon dioxide, and
higher hydrocarbons are normally removed from natural gas before
distribution to consumers because such components have an
undesirable effect on transmission, distribution and usage of the
natural gas. Therefore, in order to provide a suitable substitute
for or supplement to natural gas, such a substitute or supplement
should consist largely of methane, some ethane, but should have
only a minimum of other constituents.
The elementary composition of suitable natural gas supplements or
substitutes is about 25 percent by weight of hydrogen and 75
percent by weight of carbon. Substantial difficulties are
encountered in producing natural gas substitutes or supplements
from oil shale because oil shale contains organic carbon and
hydrogen in a much higher weight ratio than 3:1, as about 7 - 8:1
and the organic material (kerogen) in the oil shale is intimately
bound up with inorganic shale components. Thus, in order to produce
a suitable synthetic pipeline gas from oil shale, hydrogen must be
added during the manufacturing process and the kerogen or organic
material must be separated from the shale. The presently known
conventional methods of usefully removing the organic material from
oil shale still leaves 20 to 30 percent of the organic material or
kerogen with the spent shale in a form of carbon which, as
presently known, cannot be reacted by any method other than by
burning the organic material as a low grade fuel. The potential
shortages of natural gas and of energy, in general, place emphasis
on more efficient use of the kerogen in the shale, that is, a
greater useful recovery of the kerogen or organic material is
highly desirable.
It is therefore, clearly highly desirable to provide a
hydrogasification process for oil shale, wherein the amount of
unreacted carbon residue is minimized so as to lead to an overall
improvement in the economics of the process and in the conservation
of energy resources.
The classical or conventional method for recovering kerogen from
oil shale is by retorting by heating the shale to about
900.degree.-1000.degree.F. at atmospheric pressure to produce a
crude shale oil which can then be gasified by several known
techniques including direct hydrogenation with an external source
of hydrogen and/or indirect hydrogenation by reaction of the oil
shale with steam to form hydrogen and carbon monoxide which are
then recombined to form methane by a catalytic process.
The Fischer Assay Test is a laboratory evaluation test for oil
shales based on the retort procedure. In studies by the Bureau of
Mines (RI 4825), such retorting leaves behind about 20 percent of
the organic carbon in the spent shale. When the retorting is
carried out in a hydrogen atmosphere, the process has been referred
to as "hydrotorting". In typical processes exemplified in U.S. Pat.
Nos. 3,565,784; 3,617,469 and 3,617,470, the hydrotorting is
carried out at several hundred pounds pressure of hydrogen and the
shale is brought to and maintained at temperature
(700.degree.-1100.degree.F) for a total of less than 3 minutes. The
resultant shale oil is greater in the hydrotorting process.
However, as reported in U.S. Pat. No. 3,565,784, the organic carbon
residue is 3.5 percent of the spent shale which corresponds to 20
percent of the original organic carbon according to Bureau of Mines
Report, RI 4825.
In another process wherein hydrogen was reacted with oil shale at
temperatures suitable for formation of methane
(1150.degree.-1360.degree.F.), the shale and hydrogen are rapidly
heated to the reaction temperature in a co-current manner and the
shale is maintained at such a temperature for about ten minutes. In
this process, it is preferable to use large hydrogen to shale
ratios to achieve low carbon residues. Even then, however, the
minimum carbon residue achieved was 13 percent of the original
organic carbon in the shale.
Another recent process for the production of pipeline quality gas
from oil shale is set forth in U.S. Pat. No. 3,703,052 wherein both
a gasifier and a hydrogasifier are used and circulating solids are
used as a heat transfer medium. This process involves rapid
retorting of the shale, followed by hydrogasification of the shale
oil thereby leaving about 20 percent of the kerogen in the retorted
state to be used as a low grade fuel.
SUMMARY OF THE INVENTION
It is therefore an important object of this invention to provide a
process for producing a synthetic pipeline quality gas from oil
shale wherein the process is characterized by a greatly reduced
amount of unreacted carbon residue remaining with the spent
shale.
It is also an object of this invention to provide a highly
economical and thermally efficient process for producing a
synthetic pipeline quality gas from oil shale wherein the product
gas has a heating value in substantially the same range as natural
gas, such as 900-1100 BTU/SCF.
It is a further object of this invention to provide a process for
producing a high methane content, synthetic pipeline gas from oil
shale wherein the shale, by proper heating, in a stream of
hydrogen, has the organic material removed therefrom to a greater
extent than in known prior art processes.
It is yet another object of this invention to provide a continuous
process for producing synthetic pipeline quality gas from oil
shale.
Further purposes and objects of this invention will appear as the
specification proceeds.
It is known that high hydrogen/oil ratios, that is, at least above
the stoichiometric ratio, are necessary to avoid severe carbon
formation at temperatures in the range of about
1200.degree.-1500.degree.F., which temperatures are generally
considered necessary for hydrogasification. It is also known that,
even at high hydrogen/oil ratios, rapid heat up, as of the order of
a minute, to hydrogasification temperatures, can result in severe
carbon deposition. Our experiments have shown that if the shale is
properly heated in a stream of hydrogen, it is possible to remove
and recover the organic material from the shale to a greater extent
than previously developed processes. Particularly, it was found
that very rapid heat up of an oil shale in hydrogen to temperatures
required for hydrogasifiction, leaves a characteristic minimum
amount of carbonaceous residue, in some instances, as much as 12
percent. However, if the same shale is, in excess hydrogen, brought
to temperature slowly, of the order of 20 minutes or longer to go
from 600.degree. to 1300.degree.F., the residual carbon will be
much less than half that value. Even a 10 minute heat up period
shows significant improvement. Furthermore, if the same principle
of slow heatup is applied to any non-volatile component of the
products of primary shale treatment, it is possible to get maximum
net conversion of kerogen to substitute natural gas.
We have discovered that the foregoing objects are accomplished by
providing a process for producing a high methane content, synthetic
pipeline quality gas from oil shale wherein the process includes
passing the oil shale through a hydrogasification reaction chamber.
The shale is passed through the reaction chamber at a flow rate
which provides at least ten minutes for heating the shale,
preferably 10 to 120 minutes and the carbonaceous material therein,
gradually, to a reaction temperature of about
1200.degree.-1500.degree.F. The hydrogen rich gas, which is
supplied in a quantity to provide a high hydrogen/oil ratio, is
passed upwardly through the reaction chamber in countercurrent flow
to the downwardly moving oil shale in the reaction chamber. In the
hydrogasification chamber, a hydrogenation reaction is promoted
between the organic material in the shale and the hydrogen rich gas
in order to produce a gaseous mixture which includes volatilized
liquids, methane and hydrogen. Preferably, the shale, in the
presence of excess hydrogen, is heated for at least ten minutes, or
even more preferably, for twenty minutes, to increase the
temperature of the shale from 600.degree. to 1300.degree.F. The
hydrogen in the product gas is desirably separated from the methane
and is recirculated back to the hydrogasifier for reaction while
the methane rich gas is fed to the pipeline.
BRIEF DESCRIPTION OF THE DRAWINGS
Particular embodiments of the present invention are illustrated in
the accompanying drawings wherein:
FIG. 1 is a block diagram illustrating a simplified embodiment of
our inventive process;
FIG. 2 is another block diagram illustrating one preferred and more
efficient form of our inventive process; and
FIG. 3 is a further block diagram illustrating another preferred
and more efficient form of our invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Referring to FIG. 1, our hydrogasification process for oil shale is
illustrated in an extremely simplified diagrammatic form. A
hydrogasifier or reactor 10 includes three major heating zones. The
top portion of the reactor or hydrogasification reaction chamber 10
is an oil shale preheat zone 12. The second major zone of the
hydrogasification reaction chamber 10 is the central portion or
reaction zone 14. The third major zone in the bottom portion of the
chamber 10 is the hydrogen preheat zone 16.
The oil shale useful in our process, is generally of the type which
is found in the deposits in the northwestern area of Colorado, and
in the adjoining areas of Utah and Wyoming. The oil shale which is
introduced to the reactor 10 has been previously subjected, in a
conventional manner, to an oil shale crusher (not shown) for
reducing the mined oil shale to the size of pebbles having a
diameter in the range of about 1/4 - 1 inches. The shale is moved
downwardly in the reactor 10, in the pebble form, in a packed
moving bed, or alternatively, in a series of fluidized beds which
are heated by the upwardly moving or countercurrent flowing
hydrogen rich gas. The shale moving downwardly in the reactor 10
generally has a velocity range of about 0.2 to 2 feet per minute,
and preferably has a velocity of about 1 foot per minute.
The flow rate of the oil shale causes the shale, including the
organic material or kerogen therein, to be preheated to the
reaction temperature, gradually for at least 10 minutes. More
specifically, the shale is preferably heated from a temperature of
600.degree. to 1000.degree.F., in a period of at least 10 minutes,
and then to 1200.degree.-1300.degree.F. in at least an additional 5
minutes.
The oil shale then moves into the reaction zone 14 where the
temperature is at about 1200.degree.-1500.degree.F. in order to
achieve proper hydrogasification conditions. The residence time of
the shale in this zone is not considered critical since the organic
material or kerogen in the shale has been removed from the shale in
the previous or oil shale preheat zone 12. Therefore, in the
reaction zone 14, the shale is in a free fall condition or a moving
bed condition, whichever is convenient. The length of time at which
the shale is at the reaction temperature need not be more than
about 10 seconds although longer times, as up to several minutes,
is not considered detrimental. The residence time of the hydrogen
rich gas in the reaction zone is more significant, as will be
discussed hereinafter in more detail.
The hydrogen preheat zone 16 is used to preheat the hydrogen rich
gas by heat exchange with the hot shale which is moving downwardly
from the reaction zone 14. The shale solids leaving the hydrogen
preheat zone 16 may be as low as 300.degree. - 700.degree.F. The
spent shale is discharged from the system after passage from the
lower end of the reactor 10.
The hydrogen rich gas stream is introduced at the bottom of the
reactor 10 and flows upwardly or countercurrent to the shale
passing downwardly in the reactor 10. The hydrogen gas enters the
reaction zone 14 in order to react with the various organic
materials which are introduced directly into the reaction zone or
which are introduced with the oil shale. The gas or hydrogen flow
rate and size of the reaction zone 14 is designed for a hydrogen
residence time of about 20 - 50 seconds within the reaction zone
14, although somewhat longer periods of time are not considered
detrimental to the process. The upwardly moving product gas stream,
at this position, consists of hydrogen, gaseous hydrogasification
products, and volatilized liquid products, which then pass up to
the shale preheat zone. Reaction between the shale and hydrogen
also occurs in the preheat zone for generating additional gaseous
and volatilized liquid products. This gaseous mixture is carried
upwardly and out of the reactor 10 by the gas stream to a series of
processing steps, to be hereinafter described, utilized for the
separation of the substitute and supplementary natural gas,
primarily methane, from the other gases or volatilized liquids in
the gaseous mixture.
The pressure in the reaction chamber 10 has a hydrogen partial
pressure of at least 100 psig. Preferably, the partial pressure of
the hydrogen in the chamber 10 is about 500 psig. Although the
upper limit of the total pressure in the reactor 10 is not
considered critical to the process, a typical practical total
pressure limit in the chamber 10 is about 1500 psig. The pressure
conditions are similar in all three zones, 12, 14 and 16 of the
hydrogasification reaction 10.
As seen in the simplified flow diagram of our process illustrated
in FIG. 1, vaporized liquids and gases are produced in the
hydrogasification reaction 10. These gases generally include
methane, hydrogen, and carbon dioxide, while the vaporized liquids
include aromatic compounds formed in the high temperature regions
and lighter oils formed in the low temperature regions.
The first step in the process, following the formation of this
mixture of vaporized liquids and gases, is the separation of the
mixture into a liquid phase and a gaseous phase. The liquid-gas
separation step can be accomplished by any suitable cooling
technique, such as a quenching operation by a direct water spray
quench or a heat recovery system. The quenching or cooling of the
mixture coming from the reactor 10 may reach a rather low
temperature, as 100.degree.F., so as to separate the original
gaseous mixture into a normally liquid phase and a normally gaseous
phase. The separated gaseous phase is then separated into a high
methane content, as at least 80 percent by volume, of a pipeline
quality gas, having a heating value in the range of 900-1100
BTU/SCF, and a hydrogen rich fraction. In the methane-hydrogen
separation step, the separation is preferably accomplished by
subjecting the gaseous mixture of methane and hydrogen to cryogenic
temperatures, at least about -260.degree.F., the approximate
boiling point of methane. The methane condenses and the hydrogen
fraction remains in the gaseous state. Any suitable separation
method can be used such as chemical processes wherein the hydrogen
is extracted by reaction and is subsequently regenerated.
In the simplified diagrammatic embodiment shown in FIG. 1, there is
no indication of further use of the separated hydrogen or separated
liquids. In the practical and preferred application of our process,
however, the hydrogen and separated liquids are used as integral
parts of the process in order to provide a highly thermally
efficient process. FIG. 2 illustrates one preferred embodiment of
our invention, wherein the hydrogen is separated from the methane
and is recycled back to the reactor 10 and the liquid phase is
separated into a heavy liquid fraction, which is subsequently
gasified and a light liquid fraction, consisting primarily of
benzene and other light aromatics, which are difficult to
hydrogenate. This embodiment provides one type of highly thermally
efficient manner of using our process.
As seen in FIG. 2, the light oils are introduced to a hydrogen
plant and are reacted with steam in order to produce hydrogen
useful as make-up hydrogen for passage to the reactor 10.
Alternately, if desired, these light aromatic liquids can be sold
and hydrogen produced from less expensive carbonaceous materials.
The gaseous mixture of methane and hydrogen is also separated into
a hydrogen rich fraction, which is recirculated back to the reactor
10, and a methane rich fraction which is useful as the pipeline
quality gas. As can be seen from the embodiment of FIG. 2, a highly
thermally efficient process is provided for hydrogasifying a high
proportion of the organic material in the shale for the production
of a methane content pipeline quality gas.
In the embodiment of FIG. 2, the hydrogasifier reactor 10 is
constructed in the same manner as the hydrogasification reactor 10
of the embodiment of FIG. 1. Again, there is an oil shale preheat
zone 12, a reaction zone 14, and a hydrogen preheat zone 16. The
temperature and pressure conditions are also the same as for the
process discussed in connection with the simplified process
embodied in FIG. 1. As in the embodiment of FIG. 1, the flow rate
of the shale passing through the reactor 10 and the flow rate of
the hydrogen passing upwardly, in the embodiment of FIG. 2, is such
as to provide the desired heating of the shale to the reaction
temperatures, as discussed in the process embodiment of FIG. 1. The
spent shale is discharged and disposed at the bottom of the reactor
10.
In the process embodiment of FIG. 2, for simplification of
discussion, the oil shale being fed to the hydrogasifier 10 will be
considered as a 25 gal./ton Fischer Assay oil shale which contains
11.5 percent organic carbon by weight and a carbon-hydrogen weight
ratio of 7.2. Upon hydrogasification of the shale, the product gas
passing from the top of the hydrogasifier 10 includes methane,
hydrogen, carbon dioxide, water vapor, aromatic products of
hydrogasification, such as benzene, naphthalene, and higher
aromatic and vaporized liquids from the shale having an empirical
formula of CH.sub.1.7. The gaseous stream passing from the reactor
10 may also carry, as a mist, condensed liquids derived from the
shale. The mixture of gases and liquids are separated into a liquid
phase and a gaseous phase, as by the quenching operation described
in connection with FIG. 1.
The liquid phase separated during the liquid-gas separation step
includes both readily and difficultly hydrogasifiable oils. The
most difficult hydrogasifiable oil is benzene which is also the
component with the lowest boiling point in the liquid phase and is
most easily separated by a simple distillation procedure. The
remaining liquid fraction is further separated, as by distillation,
into a distillate fraction, preferably at a temperature below about
650.degree.F., and an undistilled fraction. The distillate fraction
is returned or recycled directly to the reaction zone 14 of the
reaction chamber 10, as it is not necessary to subject these
distilled liquids to the important gradual heat up. However, the
undistilled fraction is directed to the oil shale preheat zone 12,
as this fraction must undergo the gradual heat up. Specifically,
the non-distilled fraction is added to the shale preheat zone 12 at
a position where the temperature is in a range of
600.degree.-700.degree.F., whereby the downwardly moving shale in
the reactor 10 raises these nonvolatile or nondistilled components
gradually to reaction temperature in the reaction zone 14.
As to the light oils, primarily benzene, these oils are directed to
the hydrogen plant 18 of a commercially available type to produce
make-up hydrogen used as part of the reactant hydrogen in the
hydrogasifier 10. The hydrogen plant 18 may be of any suitable
commercial available design, such as a hydrogen plant using the
well known steam-iron process or a hydrogen plant using the well
known partial oxidation method.
As indicated in FIG. 2, a raw or retort oil, as shale oil, derived
from the shale fed to the hydrogasifier 10, or from shale fines or
other less desirable shale components, may, if needed, be added to
the hydrogen plant 18 in order to make an adequate amount of
hydrogen for use in the hydrogasifier 10. As indicated, the make-up
hydrogen passing from the make-up hydrogen plant 18 is mixed with
the hydrogen rich mixture passing from the methanehydrogen
separation. Instead of the low grade shale oil, other cheaper
fossil fuels, if available, may be used to produce hydrogen in the
hydrogen plant 18.
Intermediate the liquid gas separation step and the
methane-hydrogen separation, the gas stream preferably undergoes
purification steps not indicated in FIG. 2, for removal of carbon
dioxide, hydrogen sulfide, and water vapor as discussed below. The
methane-hydrogen separation step is accomplished by any suitable
technique, as cryogenically, and produces the hydrogen rich
fraction and the high methane content synthetic pipeline gas
fraction or substitute natural gas. Generally, the pipeline quality
gas resulting from the methane-hydrogen separating step contains at
least about 80 percent by volume of methane. Also, at least 80
percent by volume of the hydrogen rich fraction is hydrogen. Also,
as shown in the flow diagram of FIG. 2, for the thermally efficient
operation of our process, the hydrogen rich fraction resulting from
the methane-hydrogen separation step is combined with make-up
hydrogen coming from the hydrogen plant 18 in order to provide a
sufficient amount of hydrogen for use in the reaction zone 14 of
the hydrogasifier 10.
Referring to FIg. 3, there is shown another embodiment of our
invention, also providing a practical, thermally efficient
hydrogasification system for oil shale. As in the embodiments of
FIGS. 1 and 2, the hydrogasifier 10 of the embodiment of the
process shown in FIG. 1 includes the shale preheat zone 12, the
hydrogenation reaction zone 14, and the hydrogen preheat zone 16.
Also, the same reaction pressures and zone temperatures are
provided in the hydrogasifier 10 of the embodiment of FIG. 3, as is
done in the process embodiments of FIGS. 1 and 2. Again, the flow
rate of the shale passing through the reactor 10 provides the
important gradual heat up of the shale to the reaction temperature.
The spent shale is discharged from the bottom of the reactor 10. As
in the embodiment of FIG. 2, the embodiment of the process
described in FIG. 3 relates to the use of a shale having a 25
gallon per ton Fischer Assay which contains 11.5 percent organic
carbon by weight and a carbon-hydrogen weight ratio of 7.2 as an
example.
The embodiment of FIG. 3 is preferably used when it is desirable to
add heat to the reactor 10. More specifically, the embodiment of
FIG. 3 uses a hot synthesis gas, to supply the make-up hydrogen for
hydrogasification. Other gases and steam entering the hydrogasifier
10 are included in the synthesis gas, whereby the product gas
passing from the hydrogasifier 10 of FIG. 3 includes carbon
monoxide, carbon dioxide and steam, in addition to methane,
hydrogen and heavy and light liquids found in the product gas in
the hydrogasification reactors of the process embodiments of FIGS.
1 and 2.
The first step following the formation of the product gas in the
process of FIG. 3 is the separation of the mixture into three
fractions. The first fraction is water, which is simply separated.
The second fraction is the gaseous fraction, and the third fraction
is the liquid or oil fraction. The preferred technique for the
water-oil-gas separation step is quenching the whole mixture in a
quenching tower (not shown), for example, which separates the
normal gases and normal liquids from each other. The liquids,
containing oil and water, are allowed to settle in a settling tank
separator (not shown) wherein water is removed from the bottom and
oil from the upper layers.
The oils resulting from the water-oil separation step are further
separated into heavy or hydrogasifiable oils and light liquids or
oils. The gasifiable oils are fed directly to the hydrogasification
zone, in the case of distillates and to the oil shale preheat zone
12, in the case of undistilled liquids, as in the case of the
embodiment of FIG. 2. As described in the embodiment of FIG. 2, the
undistilled fraction is gradually heated to reaction temperatures
from a range of 600.degree.-700.degree.F. while the distillates may
be fed directly to the reaction zone 14. The recycle hydrogen from
the hydrogen-methane separation step is fed to the hydrogen preheat
zone 16, as will be described hereinafter.
The embodiment of FIG. 3 is preferably used when it is desirable to
add heat to the reactor 10. The synthesis gas generated in the
synthesis gas generator has a temperature as high as
2200.degree.F., whereas in the embodiment of FIGS. 1 and 2, the
hydrogen may be at room temperature. The synthesis gas generator 20
desirably uses the well known partial oxidation process for making
synthesis gas which includes hydrogen, carbon monoxide, carbon
dioxide, and gaseous water, resulting from the reaction of steam,
oxygen and a suitable hydrocarbon such as from a supplementary
fuel.
The synthesis gas generator may also react the light oils passing
from the liquid separation step either alone or in combination with
the supplementary fuel. The light oils from the liquid separation
step may, alternatively, be used in the overall process, as for
example, by use as an energy source in the compression of the high
methane content pipeline quality gas resulting from the described
process.
As to the gaseous phase, resulting from the water-liquid-gas
separation step, the gases are pre-purified to remove carbon
dioxide and hydrogen sulfide. Suitable pre-purification techniques
include the well known hot carbonate and monoethanolamine scrubbing
systems. Following the pre-purification step, the gaseous mixture
is passed to a shift reactor 22, wherein the gases are subjected to
the well known water gas shift reaction. In this reaction, carbon
dioxide is formed to be subsequently removed by a technique similar
to that used for purification. The gas, with the carbon dioxide
removed, is then methanated using any conventional methanation
technique to result in the gaseous mixture of hydrogen and
methane.
The mixture of hydrogen and methane then undergoes a
methane-hydrogen separation step, as by use of a cryogenic
technique wherein the methane is condensed and the hydrogen remains
in the gaseous state. The methane or methane rich pipeline quality
gas is then compressed. The high methane content, as at least 80
percent methane, synthetic pipeline quality gas has a heating value
of 900-1100 BTU/SCF. The hydrogen fraction, as at least 80 percent
hydrogen, resulting from the hydrogenmethane separation, is used as
the principal source of hydrogen for the hydrogasifier 10. As with
the embodiment of FIG. 2, the process embodiment of FIG. 3 is a
highly thermally efficient process for the hydrogasification of oil
shale.
While in the foregoing, there has been provided a detailed
description of particular embodiments of the present invention, it
is to be understood that all equivalents obvious to those having
skill in the art are to be included within the scope of the
invention as claimed.
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