US3565784A

US3565784A - Hydrotorting of shale to produce shale oil

Info

Publication number: US3565784A
Application number: US786951A
Authority: US
Inventors: Warren G Schlinger; Dale R Jesse; Joseph P Tassoney
Original assignee: Texaco Inc
Current assignee: Texaco Inc
Priority date: 1968-12-26
Filing date: 1968-12-26
Publication date: 1971-02-23
Anticipated expiration: 1988-02-23

Abstract

CONTINUOUS PROCESS FOR RECOVERING SHALE OIL FROM A SLURRY OF RAW OIL SHALE IN SHALE OIL. WATER AND HOT UNQUENCHED SYNTHESIS GAS FROM THE REACTION ZONE OF A PARTIAL OXIDATION GENERATOR ARE INJECTED INTO THE RAW OIL SHALE-SHALE OIL SLURRY UNDER PRESSURE AND THE MIXTURE IS IMMEDIATELY INTRODUCED INTO A NONCATALYTIC TUBULAR RETORT MAINTAINED AT A TEMPERATURE IN THE RANGE OF ABOUT 850 TO 950* F. AND AT A PRESSURE IN THE RANGE OF ABOUT 300 TO 1000 P.S.I.G., AND PREFERABLY AT 500 P.S.I.G. FOR MAXIMUM YIELDS OF SHALE OIL HAVING A MINIMUM NITROGEN CONTENT. SUBSTANTIALLY ALL OF THE HYDROGEN AND A LARGE FRACTION OF THE HEAT REQUIRED IN THE TUBULAR RETORT ARE PROVIDED BY THE SYNTHESIS GAS. IN THE TUBULAR RETORT ARE PROVIDED BY THE SYNTHESIS GAS. 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 THE KEROGEN IS CONVERTED TO A GASEOUS EFFLUENT FROM WHICH SHALE OIL IS SEPARATED. SIMULTANEOUSLY, HYDROGEN IS GENERATED IN THE TUBULAR RETORT BY THE EXOTHERMIC WATER-GAS SHIFT REACTION, WHEREBY CO IN THE SYNTHESIS GAS REACTS WITH H2O THE SPENT SHALE ACTING AS A SHIFT CATALYST. PURE HYDROGEN AND THE PREHYDROGENATED SHALE OIL ARE INTRODUCED INTO A CATALYTIC REACTOR TO PRODUCE DENITROGENATED AND DESULFURIZED SHALE OIL AT YIELDS OF ABOUT 125% OF THE FISCHER ASSAY. FEED TO THE SYNTHESIS GAS GENERATOR COMPRISES A PORTION OF THE HEAVY SHALE OILE AND STEAM PRODUCED BY THE PROCESS AND IN THIS RESPECT THE PROCESS IS SELF-SUSTAINING.

Description

Feb; 23, 1971 w' G sCHLlNGER ETAL 3,565,784

HYDROTORTING oF SHALE ToPRoDucE sHALE OIL Filed Dec. 26, 196e Unted States Patent O 3,565,784 HYDROTORTING OF SHALE TO PRODUCE SHALE OIL Warren G. Schlinger, Pasadena, Dale R. Jesse, Hacienda Heights, and Joseph P. Tassoney, Whittier, Calif., assignors to Texaco Inc., New York, N.Y., a corporation of Delaware Filed Dec. 26, 1968, Ser. No. 786,951 Int. Cl. Cg 1/02 U.S. Cl. 208-11 8 Claims ABSTRACT OF THE DISCLOSURE Continuous process for recovering shale oil from a slurry of raw oil shale in shale oil. Water and hot unquenched synthesis gas from the reaction zone of a partial oxidation generator are injected into the raw oil shale-shale oil slurry under pressure and the mixture is immediately introduced into a noncatalytic tubular retort maintained at a temperature in the range of about 850 to 950 F. and at a pressure in the range of about 300 to 1000* p.s.i.g., and preferably at 500 p.s.i.g. for maximum yields of shale oil having a minimum nitrogen content. Substantially all of the hydrogen and a large fraction of the heat required in the tubular retort are provided by the synthesis gas. In the tubular retort under conditions of turbulent flow, the raw shale is completely stripped of kerogen in about 1A 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. Simultaneously, hydrogen is generated in the tubular retort by the exothermic Water-gas shift reaction, whereby CO in the synthesis gas reacts with H2O the spent shale acting as a shift catalyst. Pure hydrogen and the prehydrogenated shale oil are introduced into a catalytic reactor to produce denitrogenated and desulfurized shale oil at yields of about 125% of the Fischer Assay. Feed to the synthesis gas generator comprises a portion of the heavy shale oil and steam produced by the process and in this respect the process is self-sustaining.

BACKGROUND OF THE INVENTION 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 noncatalytic tubular hydrotorting and catalytic hydrogenation to produce shale oil of improved quality and yield and spent shale containing essentially no carbonaceous residue.

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 wt. 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 3,565,784 Patented Feb. 23, 1971 ICC.

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 epirical formula for raw oil shale is 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 to 950 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. 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 1500 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 the oil shales and spent shale from this assay typically contains 5 percent organic and free carbon. In the Fischer Assay a gram sample of crushed (-8 mesh) oil shale is heated in an aluminum retort at atmospheric pressure to a temperature of 932 F. (500 C.) in 40 minutes; 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, lune 1949, U.S. Dept. of the Interior.

Contemporary retorting methods may be classified in general by the manner which heat is applied: (l) 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 throughout, limited vessel size, poor thermal control and low thermal efficiency, ditiicult 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 1000 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 (l) 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 rening treatment which must of necessity be very carefully controlled in order to prevent excessive losses of valuable reactive unsaturated hydrocarbons.

In contrast, by our hydrotorting process hydrogenated shale oil is produced, at a comparatively moderate pressure. Furthermore, su'lfur and nitrogen levels of the shale oil are comparable 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 is combined in one operation, obviating the delayed coking step commonly used by other processes during refining, land thereby saving costs. lFurther, by integrating into the system the generation of synthesis gas for use in the hydrogenation step, substantial savings vare effected.

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 synthesis gas plus recycle gas and Water `in the amount of 0.01 to 0.6 ton of water per ton of raw shale under pressure. The mixture of synthesis gas, water, and the shaleoil slurry is immediately introduced into an externally fired tubular retort under conditions of turbulent ow. Within a period of from about 1A to 3 minutes at a temperature of about 850 to 1000 F. and at a pressure in the range of about 300 to 1000 p.s.i.g. and preferably about 475 to 525 p.s.i.g., hydrogenation takes place. Shale oil is produced having a substantially reduced nitrogen and sulfur content and with increased yields of about 115 volume percent of the Fischer Assay. Still greater yields of shale oil are then obtained (in some instances as much as 125% of the Fischer Assay) by submitting the prehydrogenated gaseous effluent from the tubular reaction zone, after the entrained solids are removed, to further `hydrogenation in a separate catalytic hydrogenation zone. Substantial savings in the cost of hydrogen for the tubular retort are obtained by integrating into the system a synthesis gas generator which produces a mixed stream of hot hydrogen and carbon monoxide at a temperature in the range of 2000-3000 F. by the partial oxidation of shale oil. Thus the unquenched effluent gas stream from the reaction zone of the synthesis gas generator is introduced into the tubular retort and supplies the necessary hydrogen and heat for hydrotorting the slurry. Further, by the water-gas shift reaction in the tubular retort with spent ,shale serving as a shift catalyst, the CO in the synthesis gas is simultaneously converted into H2, liberating additional heat. Also, portions of the heavy shale oil and the steam produced by the process of our invention are used as feedstock to the synthesis gas generator. Thus little or no water or fuel from an external source are required and in this respect the process is self-sustaining.

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 further object of this invention is to provide a process for producing shale oil, water, and spent shale contain- 4 ing essentially no carbonaceous matter fromy raw oil shale by means of a continuous process having a high thermal etliciency, high oil yield, and a high retorting rate.

Still another object of this invention is to separate and recover as a pumpable slurry essentially all of the spent shale particles in the effluent stream from the oil shale hydrotort Without loss of synthesis gas nor reduction in system pressure.

A still further object of this invention is to pyrolyze and hydrogenate raw oil shale to produce shale oil and steam using a loW cost hot synthesis gas that provides substantially all of the necessary heat, pressure, and hydrogen required in the process; and which process is self-sustaining in that a portion of the shale oil and steam produced are recycled to the partial oxidation gas generator to produce Imore of said hot synthesis gas.

DESCRIPTION OF THE INVENTION The present invention involves an improved process for receiving 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 ra'w oil shale. The particle size of the crushed raw oil shale preferably is less than M1 diameter (more preferably Ms or less) and the slurry is pumpable at reasonable pressure levels, i.e. p.s.1.g.

The raw oil shale-shale oil slurry is pumped to an elongated tubular retort of relatively great length in cornparison with its cross-sectional area (for example about l to 8 inside diameter and larger, and about SOO-4000 ft. long). Such a tubular retort is described in U.S. 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 shaleshale oil slurry is introduced into a contacting zone, such as a venturi mixer, where the slurry is mixed with a stream of hot hydrogen rich gas and a stream of Water under pressure. The volume and velocities of the slurry, synthesis gas, 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 containing gaseous mixture. 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 preferable at least 1,000, is easier to attain than even before. Thus, the velocity of the slurry may be less for a given sized tubular reactor Without affecting the high reaction rate. As used herein, turbulence level is defined 'by the ratio of 'gm/v where :m is the average apparent viscosity and 11 isi-the kinematic viscosity, and is more fully described in U.S. Pat. 2,989,461 issued to DuBois Eastman et al.

For example, from about 3 to 20 volumes of recycle hydrogen containing gas at a temperature in the range of about 100 to 500 F. and comprising about 45 to 90 volume percent H2 on a dry basis are mixed with each volume of effluent gas leaving the reaction zone of a partial oxidation synthesis gas generator at a temperature in the range of about 2000 to 3000 F. and a pressure in the range of about 300 to 1000 p.s.i.g., producing a hydrogen rich gas mixture comprising from about 30 to 70 volume percent of hydrogen and about 5 to 50 volume percent of carbon monoxide. This hydrogen enriched synthesis gas mixture provides from about 5,000 to 20,000 s.c.f. of HZ-l-CO per ton of raw shale and preferably a minimum of 13,800 s.c.f. of HZ-l-CO` per ton of raw shale. The temperature of the slurry in the contacting zone is below the vaporization temperature of Water and in the range of about 100 to 500 F. However, the sensible heat of the synthesis gas provides a large fraction of the necessary heat to raise the temperature of the slurry-gas-water mixture in the tubular retort to about 700 to 1l00 F. and preferafbly 850 to 950 F. while at a. pressure in the range of from about 300 to 1000 p.s.i.g., and preferably at a pressure range of about 475 to 525 p.s.i.g. Thus, a substantial portion of the heat required in the process may be obtained from the hot synthesis gas, at a substantial economic benefit.

Addition of the hydrogen to the slurry and the hydrogenation of the pyrolysis products of the kerogen improves the yield of the product shale oil and provides greater amount of the desirable middle distillate in the shale oil product, while the formation of heavy polymers, unsaturated hydrocarbons and carbonaceous residues which characterize known processes are suppressed.

The hydrogen for our process is obtained primarily from synthesis gas by integrating into the process of our invention a noncatalytic partial oxidation generator as described in U.S. 2,582,938 issued to DuBois Eastman. The feed to the synthesis gas generator preferably comprises substantially pure oxygen (99.6 mole percent O2) at a temperature in the range of 250 to 350 F., heavy shale oil and tars at a temperature in the range of 600 to 700 F., and steam at a temperature in the range of about 300 to 900 F. A decided economic benefit is o'btained in our process by using a portion of the steam, shale oil and tar which are produced elsewhere in our process. The ratio of atoms of oxygen to atoms of carbon in the hydrocarbon feed to the synthesis gas generator should be in the range of about .70 to 1.2. The relative proportions of steam and oil may vary over a wide range, for example, from about 0.2 to about `3 pounds of steam per pound of shale oil and tar supplied to the reaction zone. Thegenerator may be operated so as to produce synthesis gas at the line pressure desired in the hydrogenation retort (300 to 1000 p.s.i.g.), thereby saving an expensive high temperature gas compressor. Entrained in the stream of gaseous euent from the synthesis generator is about from 1 to 3 wt. percent (basis carbon in the hydrocarbon feed) of unburned particulate carbon which is simultaneously removed along with the spent shale and ash in the gas-solids separator, to be described further.

It was unexpectedly found that the spent shale in the tubular retort acts like a shift catalyst and that simultaneously with the hydrotorting in the tubular retort the CO supplied by the synthesis gas undergoes an exothermic water-gas shift reaction to produce additional hydrogen gas and CO2. Thus the following additional savings are brought about by our improved process (1) costly hydrogen may be replaced by relatively inexpensive synthesis gas to effect denitrogenation and desulfurization of shale oil, (2) H2 is produced from CO supplied by low cost synthesis gas, and (3) additional heat is produced in the tubular retort during the water-gas shift reaction.

Recycle water at a temperature in the range of about 100 to 500 F. is also injected into the slurry in the amount of about 0.01 to 0.6 ton of water per ton of crushed raw oil shale, and preferably about 0.1 to 0.4 ton of water per ton of crushed raw oil shale. Both the hydrogen rich gas and the recycle water are supplied to the contacting zone at a pressure of about to 200 p.s.i.g. greater than the system line pressure. Injecting water into the slurry before the tubular retort was found to have several new, unexpected and unobvious results. The mass 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 1A to 3 minutes and preferably instances less than 1 minute. Furthermore, vaporization and expansion 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 shaleoil slurry just prior to introducing the slurry into the tubular reactor include: (1) greater concentrations of shale may be incorporated in pumpable oil-shale slurries, (2) less water is required in our process and better control of its addition may be obtained than is possible by adding water to the shale in the slurry mixing tank; and (3) clogging of the retort tubing is prevented. Furthermore, it was unexpectedly found that adding water to the raw oil shaleshale oil slurry at the point of entry to the tubular retort reduces the endothermic decomposition of inorganic carbonates in the shale and the production of CO2, which reacts with H2 to form H2O and CO. Thus by water injection, there is a savings of energy in the form of heat ordinarily consumed by the decomposition of inorganic carbonates; and further, there is a considera-ble reduction of hydrogen consumption in the tubular reactor.

The mixture of raw oil shale-shale oil slurry, water and hydrogen containing gas at an inlet velocity in the range of 10 to 100 ft./sec. is introduced into the tubular retort and is heated to a temperature in the range of about 700 to l F. and preferably 850 to 950 F. while at a pressure in the range of from 300 to 1000 p.s.i.g., and preferably at a 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 C6 material are obtained by operating within this critical pressure range. 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 a net yield of about 112% of the Fischer Assay and is substantially greater than the yield from conventional retorting. The gross yield is about of the Fischer Assay, but is reduced by the shale oil used as feed to the synthesis gas generator. 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% lower. Further, the nitrogen cont-ent of our hydrotorted 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 residence time in the tubular retort must be long enough to permit disintegration of the raw shale, pyrolysis of all 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 res1- dence 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.

The gaseous eluent stream leaving the tubular retort, comprises vapors of shale oil and water, unreacted hydrogen, NH3, H2S, and CO2, 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 Vspent shale recovered is substantially `free from carbonaceous material and is 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 ft./sec., the collection eciency (wt. of shale dust collected to shale dust in feedstream to the separator) of our gas-solids separator is in excess of 99.50 wt. percent, of which about 90-95 wt. percent passes through a 325 mesh sieve. Essentially all of the suspended insoluble ash constituents, spent shale particles, and particulate carbon particles are simultaneously removed from the hot efiluent vapors from the tubular reactor by means of our unique gas-solids separator. Thus,

when the feed to the tubular retort comprises raw oil shale-shale oil slurries having 30-80 wt. percent of shale on a solids-oil basis, and with a minimum of about 13,800 s.c.f. of hydrogen injected into the slurry in the contacting zone per ton of raw shale per hour, the solids in the gaseous effluent leaving from the exit pipe may be reduced to about 0.50 wt. per cent. 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 vessel. The effluent stream leaving the tubular retort 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-solid separator contains about 40 volume percent of hydrogen. By means of two valves and two H2O input lines properly spaced in a common discharge line, the spent shale may be removed from the bottom of the gas-solids separator without the loss of hydrogen or the reduction of system pressure. 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 ow and direction of the exit gases.

The solids-free hot gaseous effluent leaving overhead from the gas-solids separator substantially comprises vaporized shale oil fractions, unreacted hydrogen, water vapor, hydrogen sulfide, ammonia, carbon oxides, and methane. This gaseous stream is then partially cooled below the dew point of the tars and heavy shale oil 12-19 API) in the stream in order to separate these materials from the gaseous stream as liquids and thereby prevent contamination of the hydrogenation catalyst employed in a subsequent step. Furthermore, the separated tars and heavy shale oil are valuable as feedstock to the partial oxidation generator, as previously described. After the solids and heavy shale oil and tar are removed, the gaseous effluent stream is passed into a total condenser wherein the effluent gas is cooled below the dew points of water and light shale oil, which liquefy and are separated by gravity in a gas-oil-water settling tank. Uncondensed gas is withdrawn `from the top of this separator and comprises the following in mole percent dry basis: H2 45 to 85, HZS 0.5 to 2.0, CO2 l to 15, CO 3 to 30, and CH., 2 to 20. This gas is compressed and a portion is passed into a gas purifier. A stream of hydrogen is withdrawn from the gas purifier, and is mixed with said prehydrogenated light shale oil. At a pressure in the range of about 300 to 2200 p.s.i.g. and at a temperature in the range of about 700 to 900 F., the mixture of shale oil and pure hydrogen is reacted in one or more beds of catalyst which are effective for promoting the hydrogenation of hydrocarbons, such as a fixed bed of cobaltmolybdate 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, colbalt, 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 l to 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 and hot synthesis gas under pressure are 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 preferably, a second hydrogenation step may be added wherein the prehydrogenated shale oil from the first step is reacted with hydrogen in a fixed or fluid bed of hydrogenation catalyst, after substantially all of the particulate matter (carbon particles and spent shale), tar, and heavy hydrocarbons are removed. The first hydrogenation step reduces the nitrogen level in the product shale oil to below 1.6 wt. percent. Reduction of nitrogen and the use of pure hydrogen makes practical the subsequent hydrogenation of shale oil in a catalytic reactor. The more reactive olefins and hydrocarbons present during hydrogenation are also saturated and the Conradson carbon is reduced to only 1A to 1/2 of the carbon residue normally associated with shale oil. Thus the gaseous eiuent from the catalytic reactor is suitable for direct vapor catalytic processing without the coke-stilling step used in current methods.

At the cost of additional hydrogen, the second hydrogenation step over a fixed catalyst bed improves both the quantity and quality of the shale oil product. Thus, shale oil recovered by our new double hydrogenation process was unexpectedly found to show increased API and characterization factor, improved distillation characteristics, greater yields, i.e. 125% of Fischer Assay, and considerably less sulfur and nitrogen.

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 400-700 F. range without substantial increase in lower boiling gasoline range materials or the formation of normally gaseous hydrocarbons and heavy tars and coke.

In summary, by the process of our invention, wherein raw oil shale-shale oil slurry is injected with water and hot synthesis gas under pressure and hydrogenation takes place in two steps as previously described, the following objectives are achieved: (l) quick disintegration of raw oil shale into minute particles; (2) availability of hydrogen during the pyrolysis of solid kerogen released from the raw oil shale particles; (3) a mechanism by which the kerogen is raised to a high enough temperature to fracture; and (4) a porous structure of the shale particles is maintained during retorting to enable cracked kerogen in the interior to quickly escape before being converted to polymeric or gaseous products. In our process, shale oil and hot synthesis gas act as heat transfer agents by conducting heat to the surface of the shale particles. Flashing water lends turbulence to the mixture to allow continuous flow and mixing in the retorting section; and the hydrogen is able to permeate into the shale matrix so that it is available to properly terminate the hydrocarbon fractures before coke is formed plugging the pathway to the shale particle surface. lEvidence of the success of this method can be seen by the unusually high yield of high quality product shale oil, the production of excess water, and by the finely ground kerogen-free quality of the spent shale. Finally, the self-sustaining features of the process makes it particularly attractive for use in arid lands.

DESCRIPTION OF TH-E 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 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 oil 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 to 500 F., the slurry is pumped through line 7 into a gas-liquid contactor `8, which may be in the form of a venturi mixer. Unquenched hot synthesis gas from the reaction zone of partial oxidation synthesis ygas generator 9 is passed through line 10, into line 11 where it is mixed with recycle hydrogen containing gas from line 12 and then injected into the accelerated slurry stream at the throat of the venturi contactor 8. Recycle water in line 13 is also injected into the slurry at the throat of the venturi mixer. Ordinarily, the pressure of each of the streams in lines 11 and 13 exceeds the system line pressure by about 25 to 200 p.s.i.g. The synthesis gas may be generated at the desired pressure and thereby eliminate a costly high temperature gas compressor. Moreover, a substantial portion of the heat necessary in the next hydrotorting step may be obtained from the sensible heat in the synthesis gas.

The resulting intimate mixture of synthesis gas, water, raw shale particles, and heavy shale oil (about 12 to 19 API) at a temperature below the vaporization temperature of water is accelerated to a. high velocity in contactor 8 and is then directed through line 14 in to tubular retort 15 situated immediately after contactor 8. Although tubular retort 15 may be externally heated, little or no heating is usually necessary because of the heat supplied with the hot synthesis gas and the exothermic shift reaction that takes place therein. Under conditions of high tubulence in tubular retort 15, the mixture is raised Within a minute to a temperature in the range of about 700 to l100 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 efuent stream comprising a shale oil fraction, unreacted hydrogen, Water vapor, H2S, NH3, CO, CO2, carbon particulate and shale dust in the form of a line dry powder of about 325 mesh, leaves tubular retort 15 at high velocity through line 16 and is discharged into gas-solids separator 17 where the kinetic energy of the gaseous eluent is employed to effect separation of the spent shale from the rest of the effluent stream. Separator 17 is a vertical cylindrical shaped chamber with line 16 entering about midpoint and then descending in a spiral of about two loops 18. Thus, whirling motion is imparted to the gaseous efuent at its discharges from the end of the spiral pipe at point 19. By centrifugal force or acceleration, shale dust particles in the gaseous efliuent 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 17 and is removed through line 20, which leads the spent shale discharge system. To prevent plugging with spent shale and heat loss, the gas-solids separation chamber 17, the overhead transfer lines, line 16 from the tubular reactor, and exposed flanges and pipe joints are insulated to maintain the gaseous stream at a temperature of about 850 to 950 F.

Spent shale essentially free from carbon and carbonaceous matter is removed from separator 17 without severe loss of hydrogen or pressure drop in the gaseous system by means of a shale removal system not shown. The hot spent shale powder is suitable for use as preheated feedstock in a chemical process, such as making cement.

An exit pipe 21 for removing essentially solids-free gas from separator 17 depends axially from the upper end of separator 17, and terminates above loop 18. A T fitting 22 with two ports open in a direction perpendicular to the axis of the separating chamber is joined to the end of exit pipe 21 inside of the chamber.

Hot gaseous euent is withdrawn through line 23 at the top of gas-solids separator 17 and is introduced into waste heat boiler 24 which is used to produce steam which is fed to synthesis gas generator 9. The hot gaseous eluent is cooled in waste heat boiler 24 to condense only the heavy shale oil fractions and tar. The uncondensed p0rtion of gaseous effluent and the heavy shale oil liquid and tar are passed through line 25 into gas-oil separator 26. A portion of heavy shale oil and tar is withdrawn through line 27 at the bottom of gas-oil separator 26 and introduced as feed to synthesis gas generator 9. The remainder of the heavy shale oil from the bottom of separator 26 may be recycled to the slurry mixing tank 3 by way of line 2. Generally, no heavy shale oil recycle pump is necessary since the system pressure will move the oil to mixing tank 3. Hot gaseous eflluent is withdrawn from the top of separator 26 through line 28 and passed into total condenser 29 where water is condensed out along with the remainder 0f the shale oil vapors in the gaseous stream. Uncondensed gases comprising H2, H2S, NH3, CO2, and CH4 along with water and light shale oil are passed through line 30 into gas-oil-water separator 31 where the light shale oil separates and oats on the Water layer containing dissolved NH3, CO2, and H2S. Unreacted H2 and substantially all of the CO and CH., leave the system through line 32 at the top of separator 31 and are directed through lines 32, 33, and 34 by means of compressor 35 and into

lines

36, 37 and gas purier 38 where pure hydrogen is separated from the other gases. Pure H2 leaves gas purifier 38 through line 39 while H25, CO2, CO, and CH4 leave by way of

lines

40, 41, 42 yand 43 respectively. About 0.3 mole of gas are recycled through line 37 to the gas purifier 38 per mole of hydrogen containing gas passed through line 12. Standard gas purifier 38 utilizes refrigeration and chemical absorption to effect separation of the gases, such as described in U.S. 3,001,373 issued to DuBois Eastman and Warren G. Schlinger. A bleed stream of olf gas may be taken periodically through line 44 to prevent the build-up in the system of gaseous impurities.

Light shale oil is withdrawn from separator 31 by way of line 45 and is mixed in line 46 with hydrogen from line 39 at a ratio of about 1,000 to 7,000 moles of H2 per mole of light shale oil. The mixture is then raised to a temperature in the range of about 700 to 900 F. by means of heater 47, and at a pressure in the range of about 300 to 2200 p.s.i.g., the feed mixture is then introduced through line 48 into a fixed bed catalytic reactor 49 containing cobalt molybdate hydrogenation catalyst. The catalytic reactor 49 may be operated at a higher pressure than tubular retort 15. For example, by inserting a pump in line 45, catalytic reactor 49 may be operated at a pressure of 2200 p.s.i.g. while tubular retort 15 is simultaneously being operated at a preferred pressure of 500 p.s.i.g. and thereby obtain maximum yields of shale oil having a minimum nitrogen content.

The effluent stream from catalytic reactor 49 comprising essentially hydrorened light shale oil and unreacted H2 is passed through line 50 into cooler 51 where the treated oil is condensed as a liquid which flows with the uncondensed gases through line 52 into accumulator 53. Unreacted H2 and some carbon oxides, H2S and CH., are withdrawn through line 54 at the top of accumulator 53, mixed in line 33 with the gases leaving gas-Oil-water separator 31 through line 32, and puried in gas purifier 38, as previously described. Treated oil and light gases leave accumulator 53 through line SS and are fractionated in a fractionation column 56 to produce product shale oil, C5 and lighter fractions, and heavy shale oil which leave column 56 through

lines

57, 58 and 59 respectively. A portion of the heavy shale oil is discharged from the system through line 60 and the remainder is recycled to mix tank 3 by Way of lines 61 and 62.

ent gaseous stream leaving gas-solids separator 17 through 10 23. The steam from waste heat boiler 24 is passed through line 67 into synthesis gas generator 9. The remainder of the pure water in line 64 is directed to other areas of the system through line 65 for use in the process. Makeup water, if required, may be supplied through line 68. NH3 H28 and CO2 are removed from the system through line 69 at the top of water purifier 63 and recovered.

EXAMPLES OF TI-IE 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 H2O per ton of raw oil shale is crushed to -8 mesh and mixed with heavy shale oil to form a raw oil shale slurry. 'In a venturi mixer, hydrogen gas and water under a pressure of 625 p.s.i.g. are injected into the slurry. The slurry mixture at a velocity of 9.0 ft./ sec. and a temperature of 140 F. is immediately introduced into a noncatalytic tubular reactor consisting of a 1 inch SCH 40 pipe x 530 feet long, in accordance with the process of our invention as previously described and as shown in the drawing.

Operating conditions are summarized in Table I. The results are summarized in Table II as Run No. l along with the Fischer Assay for comparison. The results clearly show that compared with the Fischer Assay, greater amounts of shale oil and water are produced =by the process of our invention. Further, the shale oil has irnproved characteristics and considerably less sulfur and nitrogen. The spent shale contains substantially no kerogen residue.

TABLE I.-OPERATING CONDITIONS Synthesis gas generator 9: Run No. l

Feed to generator:

Heavy shale oil 27, API 15 at 450 F.,

lbs./hr. 17.5 Oxygen, 99.6 mole percent at 160 F.,

lbs/hr. 18.0 Steam at 800 F., lbs/hr. 8.0 O/C ratio, moles O/rnole of C in HC feed 0.90 Temperature in reaction zone, F. 2,500 Pressure in reaction zone, p.s.i.g. 625 Composition of synthesis gas 10, mole percent:

H2 47.1 CO 46.5 CO2 5.0 N2 0.8 CH.,E 0.2 HZS and COS 0.4

Mixing tank 3:

Raw oil shale 1, lbs/hr. 980 Heavy shale oil 2, lbs/hr 315 Contactor 8:

Synthesis gas 10, s.c.f.h 837 Recycle hydrogen-rich gas 12, s.c.f.h. 4,305 Recycle water 13, lbs./ ton raw shale 1 100 Oil shale-shale oil slurry 7, lbs/hr. 1,295

l2 TABLE I-'Continued Non-catalytic tubular retort 15:

Pressure, p.s.i.g 500 Retorting period, seconds 19.6 Turbulence level 2,800

Reaction temperature, F. 925 Hydrogen consumption, s.c.f./ ton of raw shale 1 520 Gas solids separator 17:

Velocity at inlet I19, ft./sec. 33.6 Temperature, F. 925 Pressure, p.s.i.g 500 Catalytic reactor 49:

Light shale oil 4S at a temperature of 120 F., gal./hr. 15.8 Hydrogen 39 at a temperature of 60 F.,

s.c.f.h. 1,200 Hydrogen consumption, s.c.f./ ton of raw Shale 1 1,040 Pressure, p.s.i.g 1,500 Liquid hourly space Velocity, bbl./ hr./ bbl. 1.5 Catalyst Co/Mo TABLE II.-RESULTS Run Fischer No. 1 assay Gross water yield 64, gals/ton of raw shale 1 14. 1 2. 9 Make-up water 68, gals/ton 0f raw shale 1 l. 2 N Spent, shale:

Removal from gas stream 16 by separator 17,

wt. percent N Spent shale 20, lbs./ton raw shale 1 1, G30 1, 670 Carbonaceous residue, wt. percent 3. 5 5. 0 Shale Oil Yield:

Line 27 plus line 55, gals/ton of raw shale 1 39. 0 31. 2 Percent Fischer Assay 100. 0 C5 and lighter 58, gals/t0n of raw shale 1 N Product shale 01157, gals/ton of raw shale 1-.... 34. 8 N Heavy shale oil 60, gals/t0n of raw shale 1 None N Treated shale 01155 and Fischer assay shale oil:

Gravity, API 32 24. l Viscosity, SSU at 122 43 70 Pour point, F 60 75 Sulfur, wt. percent 0. 02 0. 98 Nitrogen, Wt. percent- 0.05 l. 80 Conradson carbon, wt. percent 0. 1 2. 3 Characterization factor (K) 11. 7 11. 4 ASTM Distillation, F.:

IBP 192 270 336 440 518 510 655 580 705 640 680 l N o'rE.-N =N0t applicable.

EXAMPLE II This example will demonstrate the relationship between shale oil yields and pressure with respect to 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 III below that shale oil yields increase with pressure to a maximum at 5 00 p.s.i.g. in the tubular retort. Then shale oil yields decrease with increasing pressure to about 900 p.s.i.g. where they seem to level out. The gross shale oil yields range from 111 to 125 percent of the Fischer Assay (F.A.). All of the hydrogen required in the catalytic reactor 49 is produced by a portion of the product shale oil being fed to the synthesis gas generator. Consequently the net shale oil yields are lower. The data presented in Table III represents the average of three runs at each pressure level. Lower yields would be expected at temperatures in the tubular retort which are higher than 950 F. due to cracking of the kerogen. At temperatures lower than 900 F. incomplete cracking lower liquid yields. The low nitrogen and sulfur content of the product oil in line 55 as shown from the data in Table III indicates that maximum denitriiication and desulphurization are obtained by our two-step hydrogenation process.

TABLE IIL-EFFECT OF PRESSURE Gross shale oil yield,

lines 27+55 N et shale oil yield--line 55 Tubular retort Percent Percent Nitrogen Sulfur, pressure, p.s.i.g. gaL/ton F.A. GaL/ton F.A wt. percent Wt. percent 34. 111 30. 3 97 0. 1 0. 05 37. 2 119 33. 0 106 0. l 0. 05 39. 1 125 34. 9 112 0. l 0. O5 37. 9 122 33. 7 108 0. 1 0. 05 37. 2 120 33. 0 106 0. 1 0. 05 36. 2 116 32.0 103 0. 1 0.05 35. 7 114 31. 3 100 0. l 0. 05 35.5 114 31. 1 100 0. 1 0.05

EXAMPLE III l (7) separately withdrawing from the separating zone This example will demonstrate the economic advantages of water injection in accordance with the process of our invention. The process as described in Example I is repeated at substantially the same operating conditions but with the exception that no water is injected into contactor 8 through line 13. Without water injection, very little CO will be converted to H2 in tubular retort 15. Then, to maintain the same gross yield of shale oil (lines 554-27) it is necessary to supply more hydrogen to the system. This may be accomplished by increasing the quantity of synthesis gas introduced into the system through line 10 to about 1685 s.c.f.h. This will of course increase the consumption of shale oil, oxygen, and H2O fed to the gas generator. It will also increase the volume of gas processed through gas purier 38.

The process of the invention has been described generally and by examples with reference to raw oil shaleshale oil slurry feedstocks and synthesis gas 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 Vmaterials disclosed herein can be made without departure from the spirit of the invention.

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 comprising:

(l) introducing a pumpable raw oil shale-shale oil slurry into a contacting zone;

(2) mixing the hot unquenched effluent gas from the reaction zone of a synthesis gas generator with a recycle stream of a hydrogen containing gas to form a gas mixture comprising essentially CO and H2 in the amount of about 5,000 to 20,000 scf. of H2+CO per ton of raw shale;

(3) introducing the gas mixture of (2) and water in the range of about 0.01 to 0.6y tons of H2O per ton of raw oil shale into the contacting zone of (l) to effect mixing of said hydrogen and water streams with said raw oil shale-shale oil slurry;

(4)y immediately introducing the mixture of (3) at a temperature in the range of about 100 to 500 F. into a noncatalytic tubular reaction zone having a turbulence level, Elm/v, in the range of about to 100,000, where fm is the average apparent viscosity and u is the kinematic viscosity;

(5) pyrolyzing in said tubular reaction zone the raw shale in the slurry of 3) at a temperature in the range of about 850 to 950 F. and at a pressure in the range of about 300 to 1000 p.s.i.g. for a period of from about 1A to 3 minutes, while simultaneously hydrogenating the products of said pyrolysis to produce a high velocity gaseous efuent stream of denitrogenated and desulfurized oil vapor, water vapor, H2', CO, CO2 NH3, HZS, CH4, and spent shale;

(6) introducing the gaseous etliuent stream from (5) at a velocity of from about to 100 feet per second into a gas-solids separating zone;

of (6), a stream of solids-free shale oil vapor containing gas and a stream of spent shale essentially free of carbonaceous residue from kerogeng'and (8) separating shale oil from the solids-free shale oil vapor containing stream of (7) in amounts and quality that exceed the Fischer Assay.

2. The process of claim 1 wherein gaseous eluent stream from (5) is introduced into the gas-solids separating zone of (6) at an angular velocity in the r-ange of about 35 to 100 feet per second to effect more than 99.50% separation of the solids particles dispersed in said gaseous stream.

3.1A continuous process for hydrotorting raw oil shale to produce shale oil of improved quality and yield cornprlslng:

(l) forming in a mixing zone a pumpable slurry of raw oil shale particles in a shale oil carrier as defined hereinafter;

(2) mixing together in a contacting zone the raw oil shale-shale oil slurry of (l), a stream of recycle water in an amount sutlicient 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) 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 t0 1000 p.s.i.g., heating said mixt-ure to a temperature in the range of about 850 to 950 F., for a period of about 1A to 3 minutes While simultaneously subjecting the raw shale oil particles in said mixture to the disintegrating action of the highly turbulent ow 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, CO, CO2, H28, and NH3;

(4) introducing the high velocity gaseous efliuent 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 gassolids separating zone, and withdrawing the remainder of the gaseous stream substantially free from spent shale, ash and carbon particles from said separating zone;

(5) cooling the solids-free gaseous eluent from (4) in a gas cooling zone to condense out heavy shale oil and tars, and introducing said liquid and runcondensed gaseous materials into a gas-liquid separating zone;

(6) removing heavy shale oil and tars from the separating zone of (5) and introducing said liquid mixture into a synthesis gas generating zone as feedstock;

(7) withdrawing the uncondensed gaseous materials from the gas-liquid separating zone of (5), cooling l said gas to condense out light shale oil and water and passing the uncondensed gases and the liquids into a gas-shale oil-water separating zone;

(8) removing the water from the separation zone of (7) and introducing said water into a water purifying zone where NH3, H2S, and CO2 are separated from degassed water;

(9) withdrawing a portion of the degassed water from the water purifying zone of (8) and recycling said water under pressure to the contacting zone of (2);

() withdrawing a portion of the degassed water from the water purifying zone of (8), heating said water to form steam and introducing said steam to the synthesis gas generating zone of (6) as feedstock;

(l1) withdrawing the light shale oil from the separating zone of (7), and introducing said light shale oil into a fractionation zone where butane and lighter hydrocarbon fractions, product shale oil, and heavier shale oil fractions are produced and are separated, said product shale oil being characterized by a low carbon residue and reduced nitrogen and sulfur content; and

(l2) 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.

4. The process of claim 3 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 to 80 weight percent; and the slurry is maintained at a temperature in the range of about 100 to 500 F.; the hydrogen rich gas injected into the slurry in (2) is formed by mixing the hot unquenched gas from the reaction zone of a synthesis gas generator with a recycle stream of a Hydrogen containing gas to form a gas mixture comprising essentially CO and H2 in an amount in the range of about 5,000 to 20,000 s.c.f. of H2|CO per ton of raw shale; the sensible heat of said hydrogen rich gas is sufficient to provide a large fraction of the heat necessary to raise the temperature of the slurry to about 850 to 950 F.; the recycle water is injected into the slurry in (2) at a temperature in the range of about 10Q to 500 F. and in an amount in the range of about .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 25 to 200 p.s.i.g. greater than the line pressure; and the mixture from the contacting zone of (2) is introduced at a velocity in the range of about to 100 ft./sec. into the noncatalytic tubular reaction zone at a turbulence level, l'm/v, in the range of about 25 to 100,000,

wherein em is the average apparent viscosity and v is the kinematic viscosity.

5. The process of claim 4 wherein the noncatalytic tubular reaction zone is maintained at a temperature in the 'range of about 850 to 950 F., and 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.

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 shale oil carrier as defined hereinafter;

(2) mixing together in a contacting zone the raw oil vshale-shale oil slurry of (l), a stream of recycle water in an amount sulcient to substantially reduce the decomposition of inorganic carbonates in the raw shale, and a stream of hydrogen rich gas in an amount suicient to provide substantially all of the v 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 llow and at a pressure in the range of about 300 to 1000 p.s.i.g., heating said mixture to a temperature in the range of about 850 to 950 F., for a period of about 1A 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, CO, CO2, H2S, and NH3;

(4) introducing the high velocity 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 gassolids separating zone, and withdrawing the remainder of the gaseous stream substantially free from spent shale, ash, and carbon particles from said separating zone;

(5) cooling the solids-free gaseous effluent from (4) in a gas cooling zone to condense out heavy shale oil and tars, and introducing said liquid and uncondensed gaseous materials into a gas-liquid separating zone;

(7 withdrawing the uncondensed gaseous materials from the gas-liquid separating zone of (5), cooling said gas to condense out light shale oil and water and passing the uncondensed gases and the liquids into a gas-shale oil-water separating zone;

(8) removing the water from the separation zone of (7 and introducing said water into a water purifying zone where NH3, H2S and CO2 are separated from pure water;

(9) withdrawing a portion of the pure water from the water purifying zone of (8) and recycling said water under pressure to the contacting zone of (2);

( l0) withdrawing a portion of the pure Water from the water purifying zone of (8), heating said water to form steam and introducing said steam to the synthesis gas generating zone of (6) as feedstock;

(l1) withdrawing the prehydrogenated light shale oil from the separating zone of (7), mixing it with pure hydrogen, and introducing the mixture into a catalytic hydrogenation zone;

(12) cooling the hydrogenated eiuent from (11) in a cooling zone to produce liquefied shale oil fractions and uncondensed gaseous eiuent, and separating said gas and liquid in a separating zone;

(13) combining the uncondensed gaseous eluent of (12) and uncondensed gases from the gas-shale oilwater separating zone of (7), introducing the combined gases into a gas purification zone, and separately removing H2S, CO2, CO, CH4, and hydrogen from said gas purification zone;

(14) supplying the pure H2 of 13) as said pure hydrogen in (1l) for mixing with said prehydrogenated light shale oil;

(l5) introducing the liquefied shale oil fractions from 12) into a fractionating zone and separately remov ing C5 and lighter fractions, product shale oil, and heavy shale oil; and

(16) recycling a portion of said heavy shale oil from (l5) to the mixing zone of (l) as said 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 to 500 F.; the hydrogen rich gas injected into the slurry in (2) is formed by mixing the hot un- 17 quenched gas from the reaction zone of a synthesis gas generator with a recycle stream of a hydrogen containing gas to form a gas mixture comprising essentially CO and H2 and in which the hydrogen is present in an amount in the range of about 5,000 to 20,000 s.c.f. of hydrogen per ton of raw oil shale; and said hydrogen rich gas is introduced into said contacting zone with suflicient heat to raise the temperature of the slurry to about 850 to 950 F. in about 1A to 3 minutes; the recycle water is injected into the slurry in (2) at a temperature in the range of about 100 to 500 F. and in an amount in the range of about .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 100 to 200 p.s.i.g. greater than the line pressure; and the mixture from the contacting zone of (2) is introduced at a velocity in the range of about 35 to 100 ft./sc. into the noncatalytic tubular reaction zone at a turbulence level, s m/v, in the range of about 25 to 100,000

where em is the average apparent viscosity and u is the kinematic viscosity; the reaction zone of (11) comprises a xed bed of cobalt molybdate catalyst; and from about 1,000 to 5,000 s.c.f. of purified hydrogen are introduced into the catalytic reactor per bbl. of shale oil feed to the Catalytic reactor.

8. The process of claim 6 wherein the tubular reaction zone of (3) and in the gas-Solids separating zone of (4), the CO in the synthesis gas reacts with the recycle H2O to produce H2+CO2 with the spent shale acting as a water-gas shift catalyst.

References Cited UNITED STATES PATENTS U.S. Cl. X.R.