Hydrotorting Of Shale To Produce Shale Oil

Abstract

Continuous process for recovering shale oil from a slurry of raw oil shale in shale oil. Water and hydrogen gas are injected under pressure into the raw oil shale--shale oil slurry, and the mixture is immediately introduced into an externally heated noncatalytic tubular retort maintained 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., and preferably at 500 p.s.i.g. for maximum yields of shale oil having a minimum nitrogen content. In the tubular retort under conditions of turbulent flow, the raw shale is completely stripped of kerogen in about 1/4 to 3 minutes (preferably less than a minute), and by simultaneous pyrolysis and hydrogenation without added catalyst, the kerogen is converted to a gaseous effluent from which shale oil is separated having a substantially reduced nitrogen and sulfur content. Yields of such shale oil from for example Colorado shale are about 116 percent of the Fischer Assay; however, if desired, still higher yields of shale oil (about 125 percent of the Fischer Assay) containing a greater amount of material in the middle distillate boiling range may be obtained by submitting the prehydrogenated gaseous effluent from the tubular reaction zone to catalytic hydrogenation, after first removing essentially all of the spent shale. Water is also produced by the system in quantities which are in excess of process requirements.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the recovery of oil from oil shale. More specifically it relates to an improved process which combines tubular retorting and hydrogenation of a raw oil shale--shale oil slurry to produce increased amounts of shale oil of improved quality and spent shale containing essentially no carbonaceous residue.

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 nitrogen 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 many proposed 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 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. 3,177,072 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 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 is heated in an aluminum retort at atmospheric pressure 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. Department 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.

Disadvantage 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. Furthermore, hydrogen consumption is generally excessive, pressures are high (above 1,000 p.s.i.g.), relatively long retort periods are necessary (6 to 20 hours), spent shale retains some carbonaceous residue, 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 (1) retorting raw shale to produce crude shale oil (2) delayed coking, (3) hydrogenation, and (4) 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 loses of valuable reactive unsaturated hydrocarbons.

In contrast with the prior art, by our hydrotorting process, a hydrogenated shale oil is produced at a comparatively moderate pressure. Furthermore, sulfur and nitrogen levels of the shale oil 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 technique 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

We have discovered a continuous process for preparing maximum yields of shale oil of reduced nitrogen and sulfur content 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 tone of raw shale) and water (about 0.01 to 0.6 tons 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. Furthermore, if desired, still greater yields of shale oil may be obtained (in some instances as much as 135 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.

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 out 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 one-eighth 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, noncatalytic tubular retorting zone of relatively great length in comparison with its cross-sectional area (for example about 1 to 8 inches inside diameter and larger, and about 500-4,000 feet long). A similar 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 in the tubular reaction zone are controlled to ensure highly turbulent flow conditions, which combined with heat and pressure therein promotes the disintegration of the shale and the dispersal of the shale particles in the slurry-hydrogen mixtures. 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 at least 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

where .epsilon..sub.m 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 gas-liquid contacting zone from about 5,000 to 20,000 s.c.f. of hydrogen per 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. Water is also injected into the slurry in the amount of about 0.01 to 0.6 tons of water per ton of crushed raw shale and preferably about 0.1 to 0.4 tons of water per ton of crushed raw oil shale. Both the hydrogen-rich gas (comprising 45 or more volume percent H.sub.2 dry basis) and the recycle water is supplied to the contacting zone at a pressure of about 25 to 200 p.s.i. greater than the system line pressure.

Addition of hydrogen to the slurry and the hydrogenation of the pyrolysis products of the kerogen improves the yield of the produce 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 brought about which allows conversion of the kerogen to crude shale oil in the retort coils at residence times of about 1/4 to 3 minutes. 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 concentrations 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 and is heated to a temperature in the range of about 700.degree. to 1,100.degree. F. and preferably 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 pressure range of about 475 to 525 p.s.i.g.

The residence time in the tubular retort must be long enough to permit disintegration of the raw shale, pyrolysis of all of the kerogen, and hydrogenation of the shale oil. However, excess time in the tubular retort may cause coking and result in degraded shale oil. Thus, the residence time in the tubular retort is maintained at about 1/4 to 3 minutes (preferably less than 1 minute) while at the previously mentioned conditions of temperature, pressure, turbulence and feed.

It was unexpected found that maximum yields of shale oil of improved quality and containing a greater amount of C.sub.6 material are obtained by operating the tubular retort within a critical pressure range of about 475 to 525 p.s.i.g. Oil yields of about 36.3 gallons of 24.0 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 which represents 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, CO, CH.sub.4, H.sub.2 S, and CO.sub.2, along with entrained spent shale particles (about 200 to 350 mesh) and is introduced into a suitable gas-solids separating zone to effect separation of the spent shale particles from the remaining gaseous stream. The gas-solids separator may include, for example, a downwardly converging bottom chamber containing baffling elements. The spent shale recovered is substantially free from carbonaceous material and is a suitable feedstock for further processing, such as making cement.

The hot gaseous effluent leaving overhead from the gas-solids separating zone comprises shale oil vapor, unreacted hydrogen, water vapor, hydrogen sulfide, ammonia, methane and carbon oxides. This gaseous stream may be cooled to liquefy and thereby facilitate the recovery of product shale oil, at a yield of 116 percent of Fischer Assay, and water. Or alternately, the hot gases may be subjected to gaseous hydrogenation over a hydrogenation catalyst to raise the yield of the recovered product shale oil to 125 percent of Fischer Assay, or more. For example, the hot effluent vapors from the gas-solids separator, 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 1000.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 secondly if desired, a second hydrogenation step may be added wherein the effluent from the first step is hydrogenated in a fixed or fluid bed of hydrogenation catalyst, after 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 hyrogenation step reduces the nitrogen contact 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 an increased characterization factor and .degree.API, improved distillation characteristics, greater yields (i.e. about 125 percent of the Fischer Assay), and considerably less sulfur, nitrogen and carbon residues. The characterization factor, K, is an index of the type of hydrocarbon recovered and is described by Watson, Nelson, and Murphy, Ind. Eng. Chem. 25, 880 (1933); 27, 1460 (1935).

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 gaseous hydrocarbons and heavy tars and coke.

A more complete understanding of the invention may be had by reference to the accompanying schematic drawing which shows the previously described process in 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.

FIRST EMBODIMENT

With reference to the drawing, in the first embodiment of our invention, 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 oil 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 conventional gas-liquid contactor 8, which may be in the form of a venturi mixer. Recycle hydrogen 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 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 intimate mixture of hydrogen gas, water, raw oil shale particles, and heavy shale oil at a temperature below the vaporization temperature of water leaving contactor 8 is 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 and shale dust in the form of a fine dry powder of about 200 to 325 mesh, leaves tubular retort 14 through line 15 and is discharged into gas-solids separator 16. Spent shale, substantially free from any hydrocarbonaceous residue, falls to the bottom of chamber 16 and is removed from the system through line 17. 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.

Since this first embodiment of our invention involves the production of shale oil by hytrotorting in tubular retort 14 only, that is, with no subsequent hydrogenation in a catalytic reactor 19, valves 20, 21, and 22 are closed and bypass valve 23 is opened. Hot gaseous effluent from separator 16 comprising shale oil vapor, water vapor, H.sub.2, and minor amounts of NH.sub.3, H.sub.2 S, CO.sub.2, CO and CH.sub.4 is then directed to cooler 24 by way of lines 18, 25, 26 and 27. The water and shale oil that are condensed out in cooler 24 pass through line 28 and into gas-liquid separator 29. Unreacted hydrogen and the other uncondensed gases are removed from the top of separator 29 and are passed through line 30 into compressor 331. Compressed hydrogen-rich gas from lines 32 and 9 are mixed in line 11 with makeup from line 10 in the manner previously described. If necessary this hydrogen-rich mixture may be heated to a temperature in the range of 100.degree. to 500.degree. F. before it is introduced into conductor 8 by means of one of the many heat exchangers in the system.

Shale oil-water mixture is withdrawn from the bottom of gas-liquid separator 29 and is passed through line 33 into shale oil-water separator 34, 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 34 through line 35 and is introduced into a standard water purifier 36 where H.sub.2 S, NH.sub.3 and CO.sub.2 are removed through line 37 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 38 and a portion may be recycled to contactor 8 by means of pump 39 through lines 40 and 12, in the manner previously described. Surplus water is discharged from the system through line 41. Since most oil shale deposits are located in arid regions, one significant advantage of our process is that there is not net consumption of water; but in fact, an excess of water may be produced.

The crude shale oil layer in separator 34 is withdrawn through line 42 and is introduced into stabilizer 43 where by fractionation, pentane and lighter hydrocarbon fractions are separated and are passed out the top through line 44. Crude shale oil is withdrawn from the bottom of stabilizer 43 through line 45 and is introduced into fractionation column 46. A portion of the heavy shale oil bottoms from column 46 at a temperature of about 600.degree. to 900.degree. F. is recycled through lines 47, 48 and 2 into mixing tank 3 for making the raw oil shale--shale oil slurry feed to the process, in the manner 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 49. Product shale oil is removed from the system through line 50.

SECOND EMBODIMENT

The second embodiment of our invention involves two separate hydrogenation steps: first, the raw oil shale--shale oil slurry is hydrogenated in the noncatalytic tubular retort as described previously in the first embodiment; and second, the prehydrogenated shale oil vapors from the first step are hydrogenated in a fixed or fluid bed hydrogenation catalytic reactor 19. Also, a gas purification system is integrated into the system to supply pure hydrogen to the catalytic reactor and to 600.degree.the buildup of gaseous impurities in the recycle hydrogen stream.

Catalytic reactor 19 and gas purifier 60 are introduced into the previously described first embodiment of our invention by closing bypass valve 23 and opening valves 20, 21 and 22. The hot gaseous stream from gas-solids separator 16 is then passed through lines 18, 61, and 62 into cooler 63 where heavy shale oil and tars condense out and pass with the uncondensed gases into gas-liquid separator 64 by way of line 65. Separator 64 also serves as a catch pot for any shale dust that may have passed through gas-solids separator 16. Heavy shale oil and tar, which are the least valuable portion of the product shale oil may then be removed from the system through line 66 at the bottom of separator 64. This also protects the catalyst in reactor 19 from contamination. However, if desired all or a portion of the material in line 66 may be introduced into mixing tank 3 by way of line 2 for slurrying with the raw shale.

The gaseous stream leaving from the top of gas-liquid separator 64 is passed through lines 67 and 68 and into the catalytic reactor 19 where hydrogenation takes place. This hydrogenation step is facilitated by a hot stream of pure hydrogen which is introduced into reactor 19 by way of line 69. The preferred mole ratio of hydrogen (from line 69) to gaseous feed to the catalytic chamber (from line 68) is within the range of 0.0 to 0.3. Heat exchanger 70 is provided to help maintain the gas stream at the inlet to catalytic reactor 19 at the proper temperature to effect maximum denitrification and desulfurization. If it is desired to operate the catalytic reactor at a higher pressure than the pressure in tubular retort 14, then a pump may be inserted in line 68. The effluent from catalytic reactor 19 is discharged through lines 71, 72, and 27 into cooler 24 where the treated shale oil and water are condensed out. Except for the gas purification unit, the remainder of the system involves shale oil-water separator 34, water purifier 36, stabilizer 43, and fractionation column 46. The operation and function of these units are the same as that which has already been described in connection with the first embodiment of our invention. To prevent the buildup of gaseous impurities in the system, a portion of the uncondensed gases from gas-liquid separator 29 comprising unreacted hydrogen and traces of H.sub.2 S, CO.sub.2, CO and CH.sub.4 is purified, and the hydrogen is returned to the system. For example, a portion of compressed recycle gas in line 32 is passed through lines 73 and 74 into a standard gas purifier 60 where H.sub.2 S, CO.sub.2, CO, and CH.sub.4 are separated from pure H.sub.2 and leave respectively by way of lines 75, 76, 77 and 78 for recovery. A standard gas purifier utilizing refrigeration and chemical absorption may be employed to effect separation of the gases, e.g. U.S. Pat. No. 3,001,373 issued to DuBois Eastman and Warren G. Schlinger. Hydrogen leaves gas purifier 60 by way of line 79 and is passed into heater 80 where it is raised to a temperature in the range of about 800.degree. to 900.degree. F. before it is introduced through line 69 into catalytic reactor 19, in the manner previously described. If desired, high purity makeup hydrogen from an external source may be introduced into the system by mixing with the H.sub.2 in line 79. The preferred mole ratio of gases recycled in line 73 to gases passed through line 11 is in the range of about 0.1 to 1.0.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

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 0 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, as described in the aforesaid 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 high yields of product shale oil having a higher .degree.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##

EXAMPLE II

This example demonstrates the critical relationship between shale oil yields and pressure for the continuous noncatalytic tubular hydrotort described previously in the first embodiment of our invention.

Shale oil is produced from Colorado shale in a noncatalytic tubular retort at a pressure of 500 p.s.i.g. in accordance with the operating conditions and test results summarized in table I, column 1, representing the first embodiment of our invention. The process is repeated at essentially the same operating conditions but at other pressures in the range of from about 300 to 1,000 p.s.i.g. Test results are summarized in table II.

In particular it may be shown from the data in table II 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. Hydrotort 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 higher than 950.degree. F. due to cracking of the oil to gas. At temperatures lower than 850.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 denitification occurs at a critical pressure of about 500-600 p.s.i.g. However, desulfurization and water yield vary directly with retort pressure. ##SPC2##

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 invention.

Claims

We claim:

1. A continuous process for hydrotorting raw oil shale to produce shale oil or 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 below the vaporization temperature of water the raw oil shale--shale oil slurry of (1), a stream of recycle water as defined hereinafter in an amount sufficient to substantially reduce the decomposition of inorganic carbonates in the raw 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) into a noncatalytic tubular reaction zone located in immediate juxtapositon 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 1/4 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 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.sub.2 and CO;

4. introducing the gaseous effluent stream from (3) into a gas-solids separating zone, withdrawing substantially all of the spent shale and ash substantially free from organic matter from said gas-solids separating zone, and withdrawing the remainder of the gaseous stream substantially free from spent shale and ash particles from said separating zone;

5. partially cooling the solids-free gaseous effluent stream from (4) in a gas cooling zone to a temperature below the dew point of the tars and heavy shale oil therein but above the dew point of water and product shale oil, and introducing said liquid and uncondensed gaseous materials into a gas-liquid separating zone;

6. withdrawing the stream of uncondensed gaseous materials from the gas-liquid separating zone of (5) and introducing said stream in admixture with a stream of hydrogen as defined hereinafter into a reaction zone containing a hydrogenation catalyst;

7. cooling the gaseous effluent stream from (6) 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;

8. removing the crude shale oil and water mixture from the separating zone of (7) and introducing said liquid mixture into a crude shale oil-water separation zone;

9. removing the water from the crude shale oil-water separation zone of (8) 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;

10. withdrawing a portion of the pure water from the water purifying zone of (9) and recycling said water under pressure to the contacting zone of (2);

11. withdrawing the hydrogen containing gas from the gas-liquid separating zone of (7), compressing said gas, adding makeup H.sub.2 to a portion of said compressed gas, and recycling said gas to the contacting zone of (2) as said hydrogen rich gas;

12. introducing the remainder of the compressed gas from (11) into a gas purifying zone and separating H.sub.2 from other gases present;

13. withdrawing hydrogen from the gas purifying zone of (12), heating said hydrogen to a temperature in the range of 700.degree. to 1,000.degree. F., and introducing said hydrogen into the catalytic reaction zone of (6) as said stream of hydrogen;

14. removing the crude shale oil from the crude shale oil-water separating zone of (8) and introducing said crude shale oil into a fractionation zone where pentane and lighter hydrocarbon fractions are separated from heavier shale oil fractions;

15. distilling the heavier shale oil fractions from (14) 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

16. withdrawing a portion of the heavy shale oil bottoms from the fractionation zone of (15) for recycle to the mixing zone of (1) as said heavy shale oil carrier.

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, and said slurry is introduced into the contacting zone of (2) 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 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; 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 .01 to 0.6 tons of water per ton of raw oil shale; said hydrogen rich gas and said recycle water are introduced into said contacting zone at a pressure in the range of from 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 at a temperature below the vaporization temperature of water and at a turbulence level,

in the range of about 25 to 100,000 where .epsilon..sub.m is the average apparent viscosity and .nu. is the kinematic viscosity; and the reaction zone of (6) comprises a fixed bed of catalyst selected from the group consisting of cobalt-molybdate, cobalt-nickel or nickel-molybdate catalyst at a temperature in the range of about 700.degree. to 1,000.degree. F. and a pressure in the range of about 300 to 1,500 p.s.i.g.