Hydrotorting Of Shale To Produce Shale Oil

Abstract

Continuous process for recovering shale oil from a slurry of raw oil shale in shale oil. In a contacting zone, water and hydrogen gas are injected under pressure into the raw oil shale-shale oil slurry and the mixture is immediately introduced into a tubular retort maintained at a temperature in the range of about 850.degree. to 950.degree. F. and at a pressure in the range of about 300 to 1,000 p.s.i.g. and preferably at 500 p.s.i.g. for maximum yields of shale oil having a minimum nitrogen content. Under conditions of turbulent flow, in the tubular retort the raw shale is completely stripped of kerogen in about one-fourth to 3 minutes (preferably less than a minute), and by simultaneous pyrolysis and hydrogenation the kerogen is converted to a gaseous effluent from which shale oil is separated having a substantially reduced nitrogen and sulfur content. Further, essentially all of the spent shale is removed from the gaseous stream by means of a unique centrifugal separator and recovered without the loss of hydrogen or the reduction in line pressure, as spent shale containing essentially no carbonaceous residue. Yields of such shale oil from for example Colorado shale are about 116 percent of the Fischer Assay and contain less than 0.50 weight percent of spent shale. Water is also produced by the system in quantities which are in excess of process requirements.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the recovery of shale oil from oil shale. More specifically it relates to an improved process which combines tubular hydrotorting of a raw oil shale-shale oil slurry and the centrifugal separation of entrained spent shale from the gaseous effluent stream.

2. Description of the Prior Art

Oil shale consists of compacted sedimentary inorganic rock particles, generally laminated and partly or entirely encased with a high-molecular-weight organic solid material called kerogen, which is present in the amount of about 6-22 weight percent. Kerogen is derived from aquatic organisms or waxy spores and pollen grains, comprising hydrocarbons and complex organic-nitrogen, oxygen, and sulfur compounds. Nitrogen in kerogen is largely in the form of quinoline-pyridine-type compounds, and the sulfur is largely present in the form of thiophene-type compounds. Crude shale oil produced from the oil shale by the pyrolysis of the kerogen differs from crude petroleum by being more unsaturated and having a higher content of nitrogen compounds. Further, poor color stability and disagreeable odor of the shale oil products are related to the presence of these compounds. One approximate empirical formula for raw oil shale is C.sub.158 H.sub.265 O.sub.15 N.sub.4 .sup.. 6 S.

In most contemporary procedures, crude shale oil is obtained by pyrolysis of the solid insoluble organic part of the raw shale (kerogen). Thus, raw shale is subjected to destructive distillation in a retort at a temperature of about 850.degree. to 950.degree. F. The chemical decomposition of the kerogen which takes place by the action of heat alone yields crude shale oil vapors, together with water, gas, and spent shale containing a carbonaceous residue and mineral matter. The application of hydrogenation to the tubular retorting of oil shale for upgrading shale oil has been previously proposed, for example U.S. Pat. No. 3,117,072 issued to DuBois Eastman and Warren G. Schlinger. However, the liquid yields in prior art processes are generally less than the Fischer Assay, the nitrogen content in the crude shale oil is still high, consumption of pure hydrogen is high, and relatively high reaction pressures and temperature (1,000 to 20,000 p.s.i.g. and up to 1,500.degree. F.) are required.

The Fischer Assay Test is a laboratory evaluation test for estimating the maximum oil recoverable in a conventional air retort system at atmospheric pressure. It does not measure the total hydrocarbon content of oil shale, and spent shale from this assay typically contains 5-percent organic and free carbon. In the Fischer Assay a 100-gram sample of crushed (-8 mesh) oil shale, in an aluminum retort at atmospheric pressure, is brought to a temperature of 932.degree. F. (500.degree. C.) in 40 minutes; and, it is then maintained at this temperature for an additional 20 minutes. The overhead vapors from the retort comprising essentially shale oil and water are cooled, condensed, and collected in a graduated centrifuge tube. Water is separated from the oil by centrifuging, the quantities of oil and water produced are measured, and the results for each are reported in units of gallons per ton of raw shale. For further details of the Fischer Assay refer to "Method of Assaying Oil Shale by a Modified Fischer Retort" by K. E. Stanfield and I. C. Frost, R. I. 4477, June 1949, U.S. Dept. of the Interior.

Contemporary retorting methods may be classified in general by the manner which heat is applied: (1) indirect heating through the wall of the retorting vessel; (2) direct heating by hot gases from combustion within the retorting vessel; (3) heat transfer from an externally heated carrier fluid; and (4) heat transfer from recycled hot solids.

Disadvantages of some proposed retorting schemes include low heat transfer rates and correspondingly low shale throughput, limited vessel size, poor thermal control and low thermal efficiency, difficult material-handling problems, high operating and equipment costs, low yields in comparison with the Fischer Assay, and poor quality of the shale oil. Further, hydrogen consumption is generally excessive, pressures are high (about 1,000 p.s.i.g.), relatively long retort periods are necessary (6 to 20 hours), spent shale retains some carbonaceous values, and in comparison with crude petroleum, the shale oil recovered is a very low grade.

Most commercial processes for converting raw shale into such liquid fuels as jet and diesel fuels include the operations of retorting raw shale to produce crude shale oil; and the delayed coking of the crude shale oil, followed by hydrogenation and fractionation. Established procedures for shale oil refining generally involve a combination of cracking, distillation, and chemical refining treatment which must of necessity be very carefully controlled in order to prevent excessive losses of valuable reactive unsaturated hydrocarbons.

In contrast with the prior art, by our hydrotorting process at comparatively moderate pressures, a hydrogenated shale oil is produced which contains comparatively no spent shale particles. The absence of spent shale particles is especially desirable when the product shale oil is further processed. For example, the life of a catalyst bed is affected by shale particles in the treated shale oil. Furthermore, regarding the shale oil produced, sulfur and nitrogen levels may be reduced to those usually found in crude petroleum, there is minimum degradation in the distillate boiling range, and yields are greater. Such shale oil would then be amenable to further processing by conventional crude refinery techniques with high yields for a minimum of treating. Further, the spent shale is comparatively free from any organic or carbonaceous residue from the kerogen. By our process, retorting and hydrogenation may be combined in one operation, obviating the delayed coking step commonly used by other processes during refining, and thereby saving costs.

SUMMARY l

We have discovered a continuous process for preparing maximum yields of shale oil of reduced nitrogen and sulfur content and containing substantially no spent shale particles from raw shale under relatively reduced pressure. More particularly, the invention relates to the discovery that raw shale can be readily converted to shale oil and relatively kerogen-free dry powdered shale by injecting a slurry of raw oil shale in shale oil with hydrogen (about 5,000 to 20,000 s.c.f. of hydrogen per ton of raw shale) and water (about 0.01 to 0.6 ton of water per ton of raw shale) under pressure, and immediately introducing the mixture into an externally fired tubular retort under conditions of turbulent flow. Within a period of from about one-fourth to 3 minutes at an outlet temperature of about 850.degree. to 950.degree. F. and at a pressure in the range of about 300 to 1,000 p.s.i.g. and preferably at a critical pressure of about 475 to 525 p.s.i.g., hydrogenation takes place with no addition of a supplementary catalyst. Shale oil is produced having a substantially reduced nitrogen and sulfur content and with increased yields of about 116 volume percent of the Fischer Assay. A unique centrifugal gas-solids separating scheme, which utilizes the kinetic energy of the gaseous effluent from the retorting zone at a minimum velocity of 33.6 f.p.s., is provided to effect separation of substantially all of the entrained solids from the shale oil vapors with no loss of hydrogen or reduction in system pressure. Furthermore, if desired, still greater yields of shale oil may be obtained (in some instances as much as 125 percent of the Fischer Assay) by submitting solids-free prehydrogenated gaseous effluent from the tubular reaction zone to further hydrogenation in a separate catalytic hydrogenation zone.

The principal object of this invention is to recover from raw oil shale increased yields of hydrogenated shale oil of improved product quality.

Another object of this invention is to simultaneously retort raw oil shale and hydrogenate the kerogen and shale oil to produce increased yields of a shale oil with a substantially reduced nitrogen and sulfur content and containing less than 0.05 weight percent of spent shale.

A further object of this invention is to separate and recover as a pumpable slurry essentially all of the spent particles in the effluent stream from the oil shale hydrotort without loss of hydrogen nor reduction in system pressure.

A still further object of this invention is to provide a continuous process for producing shale oil, water, and spent shale containing essentially no carbonaceous matter from raw oil shale by means of a continuous process having a high thermal efficiency, high oil yield, and a high retorting rate.

DESCRIPTION OF THE INVENTION

The present invention involves an improved process for recovering high-quality shale oil from raw oil shale at substantially improved yields. Crushed raw oil shale is mixed with heavy shale oil derived by the process of our invention, as hereinafter described, to produce a pumpable raw oil shale-shale oil slurry comprising from about 30 to 80 weight percent of raw oil shale. The particle size of the crushed raw oil shale preferably is less than 1/4-inch diameter (more preferably 1/8 inch or less) and the slurry is pumpable at reasonable pressure levels, i.e. 100 p.s.i.g.

The raw oil shale-shale oil slurry is pumped to an externally heated, elongated, tubular retorting zone of relatively great length in comparison with its cross-sectional area (for example about 1 inch to 8 inches inside diameter and larger, and about 500-4,000 feet long). Such a tubular retort is described in U.S. Pat. No. 3,117,072 issued to DuBois Eastman and Warren G. Schlinger. However, immediately prior to being introduced into said tubular retorting zone, the raw oil shale-shale oil slurry is introduced into a contacting zone where it is mixed with a stream of hydrogen gas and a stream of liquid water under pressure. The volume and velocities of the slurry, hydrogen, and water entering the tubular reaction zone are controlled to (1) ensure highly turbulent flow conditions therein, which combined with heat and pressure therein promotes the disintegration of the shale and the dispersal of the shale particles in the slurry-hydrogen mixture, and (2) provide the gaseous stream entering the gas-solids separator with a minimum velocity to maximize spent shale removal. By the improvement of our invention, turbulence in the tubular reactor is increased and the desired turbulence level in the range of about 25 to 100,000 and preferably 1,000 is easier to attain than ever before. Thus, the velocity of the slurry may be decreased for a given-sized tubular reactor without affecting the high reaction rate. As used herein, turbulence level is defined by the ratio of where is the average apparent viscosity and .nu. is the kinematic viscosity, and is more fully described in U.S. Pat. No. 2,989,461 issued to DuBois Eastman et al.

For example, in a venturi mixer, from about 5,000 to 20,000 s.c.f. of hydrogen per ton of raw shale and preferably a minimum of 13,800 s.c.f. of H.sub.2 /ton of raw shale at a temperature of about 100.degree. to 500.degree. F. are injected into the slurry maintained at a temperature in the range of about 100.degree. to 500.degree. F. for hydrogenation and to ensure maximum removal of spent shale in the gas-solids separator. To provide this volume of hydrogen, the inlet velocity of the slurry hydrogen is maintained at about 5 to 50 f.p.s., and preferably a minimum of 9 f.p.s. (basis inlet conditions). Further, recycle water of a temperature in the range of about 100.degree. to 500.degree. F. is injected into the slurry in the amount of about 0.01 to 0.6 ton of water per ton of crushed raw shale and preferably about 0.1 to 0.4 ton of water per ton of crushed oil shale. Both the hydrogen-rich gas (comprising 45 or more volume percent H.sub.2 on a dry basis) and the recycle water is supplied to the venturi mixer at a pressure of about 25 to 200 p.s.i. greater than the system line pressure. The process removes 99.5 weight percent of spent shale, of which 90-95 percent passes through a U.S. standard 325-mesh sieve.

Addition of hydrogen to the slurry and the hydrogenation of the pyrolysis products of the kerogen improves the yield of the product shale oil and provides the product with a greater amount of the desirable middle distillate material, while the formation of heavy polymers, unsaturated hydrocarbons and carbonaceous residues which characterize known processes are suppressed. Injecting water into the slurry before the tubular retort was found to have several new, unexpected and unobvious results. The velocity through the tubular retort, the turbulent flow, and the heat transfer coefficient of the mixture in the retort are all increased. Thus, rapid heat transfer is effected which allows conversion of the kerogen to crude shale oil in the retort coils at residence times of about one-fourth to 3 minutes and preferably less than 1 minute. Furthermore, vaporization of the water in the coils tends to disintegrate the shale particles and facilitates atomization of the shale oil. Also, coking of the slurry may be minimized or eliminated at a substantially reduced hydrogen consumption. Other unobvious advantages for injecting the water under pressure into the shale-oil slurry just prior to introducing the slurry into the tubular reactor include: (1)greater concentration of raw shale may be incorporated in pumpable oil-shale slurries, (2) less water is required in our process than when water is added to the shale in the slurry mixing tank; (3) clogging of the retort tubing is prevented; (4) better control of the amount of water added; and finally, (5) it was unexpectedly found that water addition reduces the endothermic decomposition of inorganic carbonates in the shale to form CO.sub.2, thereby preventing the undesirable reaction between CO.sub.2 and hydrogen to form H.sub.2 O and CO. Thus by water injection, there is a savings of energy in the form of heat used for carbonate decomposition as well as a reduction of hydrogen consumption in the tubular retort.

The mixture of raw oil shale-shale oil slurry, water, and hydrogen is introduced into the tubular retort at an inlet velocity such that the velocity of the effluent from the tubular retort entering the gas-solids separator is in the range of about 25 to 100 f.p.s. and preferably greater than about 33.6 f.p.s. As the slurry mixture passes through the tubular retort it is heated to a temperature in the range of about 700.degree. to 1,100.degree. F. and preferably to an outlet temperature of 850.degree. to 950.degree. F. while at a pressure in the range of from 300 to 1,000 p.s.i.g., and preferably at a critical pressure range of about 475 to 525 p.s.i.g. It was unexpectedly found that maximum yields of shale oil of improved quality and containing a greater amount of C.sup.+ .sub.6 material are obtained by operating within this critical pressure range. Further, oil yields of about 36.3 gallons of 24.0.degree. API gravity oil per ton of raw shale may be expected in comparison with a Fischer Assay of about 31.2 gallons per ton. This represents an increase of about 16 percent and is an improvement over the yield from contemporary processes. Also, examination of the hydrotort shale oil produced at this pressure shows it to be of superior quality; that is compared with a Fischer Assay of the same shale the sulfur and nitrogen content of our shale oil are each about 25 to 35 percent lower. Further, the nitrogen content of the hydrotort oil reaches a minimum at the critical pressure of about 500 p.s.i.g. However, the sulfur content of the shale oil decreases as the pressure increases above 500 p.s.i.g.

The gaseous effluent stream leaving the tubular retort, comprises vapors of shale oil and water, unreacted hydrogen, NH.sub.3,CH.sub.4, H.sub.2 S, CO.sub.2 and CO, along with entrained spent shale particles (about 200 to 350 mesh)and is introduced into a suitable gas-solids separating zone maintained at about the same temperature and pressure as in the tubular retort less normal line losses to effect separation of the spent shale particles from the remaining gaseous stream. The spent shale recovered is substantially free from carbonaceous material and is a suitable feedstock for further processing, such as making cement. By introducing the gaseous effluent stream from the tubular retort into the gas-solid separator of our invention at a minimum velocity of about 33.6 f.p.s., the collection efficiency (weight of shale dust collected to shale dust in feedstream to the separator) of our gas-solids separator is in excess of 99.50 weight percent. Essentially all of the suspended insoluble ash constituents, spent shale particles, and particulate carbon particles are simultaneously removed from the hot effluent vapors from the tubular reactor by means of our unique gas-solids separator. Further, because of the high temperature and pressure involved and the requirement for essentially complete solids removal, cyclone separators of conventional design are unsuitable. Instead, in our process, gas-solids separation takes place in an elongated, vertical, cylindrical-shaped pressure chamber. The effluent stream leaving the tubular reactor at high velocity enters the gas-solids separator about midpoint. Passing through a downwardly directed pipe coil of one or more loops, the effluent stream is then discharged into the separation vessel at a high circumferential speed. On account of "centrifugal force" (actually, the absence of centripetal force necessary to restrain them), the solid particles in the effluent stream move to the wall of the vessel and fall to the bottom. The spent shale at the bottom of the gas-solids separator contains about 40 volume percent of hydrogen. A spent shale discharge system, which effectively solves the problem of removing the dry, powdery, and difficult-to-handle spent shale from the bottom of the gas-solids separator without the loss of hydrogen or the reduction of system pressure, is employed and will be described later. Essentially solids-free gas is removed through an exit pipe which depends axially from the upper end of the vessel and terminates above said inlet coil. A "T" fitting is joined to the lower end of the exit pipe to baffle and further separate out minute solid particles and to regulate the flow and direction of the exit gases.

The solids-free hot gaseous effluent leaving overhead from the gas-solids separating zone comprises shale oil vapor, unreacted hydrogen, water vapor, hydrogen sulfide, CO.sub.2, CO, CH.sub.4 and ammonia. This hot gaseous stream may be cooled to recover product shale oil and water. Or alternately, the hot gases may be subjected to further hydrogenation in a bed of hydrogenation catalyst to increase the yield of the recovered product shale oil to about 125 percent of Fischer Assay. For example, with essentially all of the suspended insoluble ash constituents and spent shale particles removed by the gas-solids separator, the hot effluent vapors from the tubular reactor, at a pressure in the range of about 300 to 1,500 p.s.i.g. and preferably the same pressure as in the tubular retort less normal pressure drop in the lines of about 100 p.s.i.g. and at a temperature in the range of about 700.degree. to 1,000.degree. F. and preferably the same temperature as in the retort less line losses are directed over one or more beds of catalyst which are effective for promoting the hydrogenation of hydrocarbons, such as a fixed bed of cobalt-molybdate, cobalt-nickel or nickel-molybdate hydrogenation catalyst. Effective catalysts in general include compounds of the Group VI metals and of the first transition series of Group VIII of the Periodic Table of the Elements. Suitable known solid hydrogenation catalysts include oxides or sulfides of molybdenum, cobalt, tungsten, chromium, iron, vanadium, or nickel on a suitable carrier material such as silica, alumina, bauxite, magnesia, zirconia, aluminum silicate, or clay. For example, the catalyst may comprise from about 1 to 10 weight percent of cobalt oxide and about 5 to 20 percent of molybdenum oxide on an alumina support.

Thus by our improved process, shale oil may be produced by one or two hydrogenation steps: in one step, water under pressure is injected into a raw oil shale-shale oil slurry and hydrotorting takes place immediately in a tubular retort with no supplementary hydrogenation catalyst added; and if desired, a second hydrogenation step is added wherein hydrogenation of the effluent from the first step takes place in a fixed or fluid bed of hydrogenation catalyst, after substantially all of the particulate matter, tar, and heavy hydrocarbons are removed. Direct contact of the gaseous effluent with catalyst in the second step eliminates the need for condensing and reheating the hydrocarbons prior to catalytic treatment. The first hydrogenation step reduces nitrogen content of the shale oil to a level which permits the use of fixed bed catalysts. The more reactive olefins and hydrocarbons present are also saturated and the Conradson carbon is reduced to only one-fourth to one-half the carbon residue normally associated with shale oil. Thus the gaseous effluent is suitable for direct vapor catalytic processing without the normal coke-stilling step. At the cost of additional hydrogen, the second hydrogenation step over a fixed catalyst bed may be used, if desired, to improve both the quantity and quality of the shale oil product. Thus, shale oil recovered by our double hydrogenation process was unexpectedly found to show increased API gravity and characterization factor, improved distillation characteristics, greater yields, i.e. 125 percent of Fischer Assay, and considerably less sulfur, nitrogen and carbon residue.

By the process of our invention, the higher boiling hydrocarbons are subjected to viscosity-breaking with substantially immediate hydrogenation of the molecular fragments and without further breakdown, thereby materially increasing the production of material boiling in the 400.degree.-700.degree. F. range without substantial increase in lower boiling gasoline range materials or the formation of normally gaseous hydrocarbons and heavy tars and coke.

DESCRIPTION OF THE DRAWING

A more complete understanding of the invention may be had by reference to the accompanying schematic drawing which shows the previously described process in greater detail. Although the drawing illustrates a preferred embodiment of the process of this invention, it is not intended to limit the invention to the particular apparatus or materials described.

With reference to the drawing, particles of raw shale in line 1 and heavy shale oil in line 2 are introduced into mixing tank 3 where they are mixed by agitator 4, forming a raw shale-shale oil slurry. This slurry is passed from the bottom of mixing tank 3 through valve 5 and into the suction end of screw pump 6. At a temperature in the range of about 100.degree. to 500.degree. F., the slurry is pumped through line 7 to a gas-liquid contactor 8, which may be in the form of a venturi mixer. Recycle hydrogen rich gas from line 9 and makeup hydrogen from line 10 are mixed in line 11 and injected into the accelerated slurry stream at the throat of the venturi mixer 8. Recycle water in line 12 is similarly injected into the slurry. The pressure of each of the streams in lines 11 and 12 exceeds the system line pressure by about 25 to 200 p.s.i.

The resulting intimate mixture of hydrogen gas, water, raw oil shale particles, and heavy shale oil at a temperature below the vaporization temperature of water is accelerated to a high velocity in contactor 8 and is then directed through line 13 into externally heated tubular retort 14 situated immediately after contactor 8. Under conditions of high turbulence in tubular retort 14, the mixture is raised within seconds to a temperature in the range of about 700.degree. to 1,100.degree. F. and disintegration and pyrolysis of the raw shale, vaporization of the shale oil and water, and hydrogenation of the kerogen and shale oil all take place simultaneously. No supplementary catalyst need be added to the aforesaid materials in the tubular retort to promote the reactions therein.

A hot gaseous effluent stream comprising shale oil vapor, unreacted hydrogen, water vapor, H.sub.2 S, NH.sub.3, CO.sub.2, CO, CH.sub.4, and shale dust in the form of a fine dry powder of about 200-325 mesh, leaves tubular retort 14 at high velocity through line 15 and is discharged into gas-solids separator 16 where the kinetic energy of the gaseous effluent is employed to effect separation of the spent shale from the rest of the effluent stream. Separator 16 is a vertical cylindrical-shaped chamber with line 15 entering about midpoint and then descending in a spiral of about two loops 17. Thus, whirling motion is imparted to the gaseous effluent at its discharges from the end of the spiral pipe at point 18. By centrifugal force or acceleration, shale dust particles in the gaseous effluent are separated from the remainder of the effluent and move to the walls of the separating chamber. From there, the dry spent shale dust, substantially free from any hydrocarbonaceous residue, falls to the bottom of chamber 16 and is removed through line 19, which leads to the spent shale discharge system. To prevent plugging with spent shale and heat loss, the gas-solids separation chamber 16, the overhead transfer lines, line 15 from the tubular reactor, and exposed flanges and pipe joints are insulated to maintain the gaseous stream at a temperature of about 850.degree. to 950.degree. F.

Spent shale is removed from separator 16 without severe loss of hydrogen or pressure drop in the gaseous system by the following steps: valve 20 in line 19 is opened and valve 21 is closed to permit spent shale to collect in line 22 between the valves; water, steam, or both from line 23 is introduced into line 22, thereby displacing the hydrogen gas therein and forcing the gas back into line 19 and chamber 16; valve 20 is closed and valve 21 is opened; water, steam, or both from line 24 is introduced into line 22, thereby discharging the hot shale powderwater slurry in line 22, through valve 21 and into storage, or the discharge material may be used directly as preheated feedstock in some chemical process not shown, such as making cement.

An exit pipe 25 for removing essentially solids-free gas from separator 16 depends axially from the upper end of separator 16, and terminates above loop 17. A "T" fitting 26 with two ports open in a direction perpendicular to the axis of the separating chamber is joined to the end of exit pipe 25 inside of the chamber. Since this embodiment of our invention involves the production of shale oil by hydrotorting in tubular retort 14 only, that is, with no subsequent hydrogenation in a catalytic reactor, the hot solids-free gaseous effluent from separator 16 comprising shale oil vapor, water vapor, H.sub.2 S, CO.sub.2, CH.sub.4, CO, and NH.sub.3 is then directed through line 27 into cooler 28. Water and shale oil are condensed out in cooler 28 and pass through line 29 into gas-liquid separator 30. Unreacted hydrogen rich gas is removed from the top of separator 30 and is passed through line 31 into compressor 32. Compressed recycle hydrogen-rich gas is passed through lines 33, 34, 35 and 9 and is mixed in line 11 with makeup hydrogen from line 10 in the manner previously described. If necessary this hydrogen mixture may be heated to a temperature in the range of about 100.degree. to 500.degree. F. before it is introduced into contactor 8 by means of a heat exchanger in the system.

Build up of gaseous impurities in the system, such as H.sub.2 S, CO.sub.2, CO, CH.sub.4, may be prevented by introducing all or a portion of the hydrogen-rich gas in line 33 through lines 36 and 37 into a standard gas purifier 38. Valves 39 and 40 control flow. Gas purifier 38 utilizes refrigeration and chemical absorption to effect separation of the gases, such as described in U.S. Pat. No. 3,001,373 issued to DuBois Eastman and Warren G. Schlinger. H.sub.2 S, CO.sub.2, CO, CH.sub.4, and H.sub.2 are separated from each other and leave gas purifier 38 by respective lines 41, 42, 43, 44 and 45. Hydrogen from lines 45 and 9 is mixed in line 11 with makeup hydrogen from line 10 and may constitute the hydrogen feed to venturi contactor 8 as previously described.

Shale oil-water mixture is withdrawn from the bottom of gas-liquid separator 30 and is passed through line 46 into shale oil-water separator 47, where the lighter shale oil separates out and floats on a water layer which contains dissolved H.sub.2 S, NH.sub.3 and CO.sub.2. The water layer is removed at the bottom of separator 47 through line 48 and is introduced into a standard water purifier 49 where H.sub.2 S, NH.sub.3, and CO.sub.2 are removed through line 50 and are directed to a standard NH.sub.3, H.sub.2 S, and CO.sub.2 recovery system. Purified water is removed through line 51 and a portion is recycled to contactor 8 by means of pump 52 through lines 53 and 12, in the manner as previously described. Surplus water is discharged from the system through line 54.

The crude shale oil layer in separator 47 is withdrawn through line 55 and introduced into stabilizer 56 whereby fractionation, pentane and lighter hydrocarbon fractions are separated and pass out at the top through line 57. Crude shale oil is withdrawn from the bottom of stabilizer 56 through line 58 and is introduced into fractionation column 59. A portion of the heavy shale oil bottoms from column 59 at a temperature up to 800.degree. F. is recycled through lines 60 and 2 into mixing tank 3 for making the raw oil shale-shale oil slurry feed to the process, in the manner as previously described. Generally, no heavy shale oil recycle pump is necessary since the system pressure will move the oil to the mix tank. The remainder of the heavy shale oil is removed from the system through line 61. Product shale oil is removed from the system through line 62.

Since most shale deposits are located in arid regions, one significant advantage of our process is that there is no net consumption of water; but in fact, an excess of water may be produced.

EXAMPLES

The following examples are offered as a better understanding of the present invention but the invention is not to be construed as limited thereto.

EXAMPLE I

Colorado oil shale having a Fischer Assay of 31.2 gallons of shale oil per ton of raw oil shale and 2.9 gallons of H.sub.2 O per ton of raw oil shale is crushed to -8 mesh and mixed with heavy shale oil to form a slurry comprising 75.6 weight percent of raw shale. Immediately after water and hydrogen are injected into the slurry under pressure, the mixture is hydrogenated in a 1-inch SCH. 40-pipe .times. 530-feet-long noncatalytic tubular retort.

Operating conditions and results of runs, in accordance with the first embodiment of the process of our invention as previously described are summarized in table I, column 1. In column 2 there is shown a summary of the conditions and results of double hydrogenation, first in the noncatalytic tubular retort and second over a Co-Mo hydrogenation catalyst, representing a second embodiment of our invention. It appears, from a comparison of columns 1 and 2, that the second embodiment is the preferred procedure because it provides higher yields of product shale oil having a higher API and characterization factor, improved distillation characteristics and considerably less sulfur, nitrogen, and carbon residue. Further, in comparison with the Fischer Assay, the data for both embodiments show a substantial increase in product-oil yields; an improvement in API gravity, pour point, and yield of distillate; and a reduction in the nitrogen and the sulfur content in the shale oil product. ##SPC1## ##SPC2##

EXAMPLE II

This example will demonstrate the relationship between shale oil yields and pressure in the continuous noncatalytic tubular hydrotort described previously. By maintaining all of the operating conditions described in example I substantially the same with the exception of pressure in the tubular retort, it may be shown from the data in table II below that shale oil yields increase with pressure to a maximum of 500 p.s.i.g. Then yields decrease with increasing pressure to about 900 p.s.i.g. where they seem to level out. Line numbers refer to the drawing. The shale oil yields range from 103 to 116 percent of the Fischer Assay (F.A.) and the water yields range from 159 to 283 percent of the F.A. Lower yields would be expected at temperatures in the tubular retort which are higher than 950.degree. F. due to cracking of the oil to gas. At temperatures lower than 800.degree. F. incomplete cracking of kerogen would be anticipated, producing lower liquid yields. It is also shown from the data in table II that maximum denitrification occurs at a critical pressure of about 500-600 p.s.i.g. However, desulflurization and water yield vary directly with retort pressure. ##SPC3##

EXAMPLE III

In table III below there is shown the relationship between the velocity of the gaseous effluent stream entering gas-solids separator 16 (at inlet conditions of temperature and pressure), and the weight percent of spent shale removed from the gaseous stream. All other operating conditions are maintained substantially the same as described previously in example I. From table III it appears that 100 percent of the spent shale is removed from the gaseous effluent stream by introducing the gaseous stream into separator 16 at a minimum velocity of 33.6 f.p.s. (at inlet conditions of temperature and pressure). At this rate, there was supplied to contactor 8 a minimum of 13,800 s.c.f. of hydrogen per ton of raw shale. --------------------------------------------------------------------------- --------------------------------------------------------------------------- TABLE III

Velocity of Gaseous Hydrogen Stream Supplied to Entering Contactor 8 Spent Shale Separator 16 s.c.f./ton Removed Run No. f.p.s. Raw Shale wt. % __________________________________________________________________________ CS-9 20.5 7,540 26 CS-12 33.6 13,800 100 CS-23 50.0 20,700 100 __________________________________________________________________________

the process of the invention has been described generally and by examples with reference to raw shale-shale oil slurry feedstocks of particular compositions for purposes of clarity and illustration only. It will be apparent to those skilled in the art from the foregoing that various modifications of the process and materials disclosed herein can be made without departure from the spirit of the invention.

Claims

We claim:

1. A continuous process for hydrotorting raw oil shale to remove essentially all of the kerogen in said oil shale to produce shale oil of improved quality and yield and to produce spent shale containing essentially no carbonaceous matter or carbon comprising:

1. introducing a pumpable raw oil shale-shale oil slurry into a contacting zone;

2. introducing separate preheated high-pressure streams of hydrogen in the range of about 5,000 to 20,000 s.c.f. of H.sub.2 per ton of raw shale and liquid water in the range of about 0.01 to 0.6 ton of H.sub.2 O per ton of raw oil shale into the contacting zone of (1) to effect mixing of said hydrogen and water streams with said raw oil shale-shale oil slurry, and immediately passing said mixture at a temperature in the range of about 100.degree. to 500.degree. F. into a noncatalytic tubular reaction zone having a turbulence level, , in the range of about 25 to 100,000 where is the average apparent viscosity and .nu. is the kinematic viscosity;

3. pyrolyzing in said tubular reaction zone the raw shale in the slurry of (2) at an outlet temperature in the range of about 850.degree. to 950.degree. F. and at a pressure in the range of about 300 to 1,000 p.s.i.g. for a period of from about one-fourth to 3 minutes, while simultaneously hydrogenating the products of said pyrolysis to produce a high-velocity gaseous effluent stream of denitrogenated and desulfurized shale oil vapor, water vapor, CH.sub.4, NH.sub.3, H.sub.2 S, CH.sub.4, CO.sub.2, CO and spent shale;

4. introducing the gaseous effluent stream from (3) into a gas-solids separating zone;

5. separately withdrawing from the separating zone of (4), a stream of solids-free shale oil vapor containing gas and a stream of spent shale particles essentially free of carbonaceous matter from kerogen; and

6. separating shale oil from the solids-free shale oil vapor containing stream of (5) in amounts and quality that exceed the Fischer Assay.

2. The process of claim 1 wherein the raw oil shale is present in the raw oil shale-shale oil slurry of (1) in an amount in the range of about 30 to 80 weight percent; the hydrogen injected into the slurry in (2) is supplied to the contacting zone of (1) at a temperature in the range of about 100.degree. to 500.degree. F. and in a minimum amount of 13,800 s.c.f. ton of raw shale and at an inlet velocity in the range of about 5 to 50 f.p.s.; and wherein the gaseous effluent stream from (3) is introduced into the gas-solids separating zone of (4) at a minimum velocity of 33.6 f.p.s. to effect more than 99.50 weight percent separation of solid particles dispersed in said gaseous stream.

3. The process of claim 1 wherein the noncatalytic tubular reaction zone is maintained at an outlet temperature in the range of about 910.degree. to 940.degree. F., and at a pressure in the range of about 475 to 525 p.s.i.g., and the shale oil produced by the process is greater than the Fischer Assay.

4. The process of claim 1 wherein the spent shale particles in (5) are withdrawn from said gas-solids separating zone with substantially no loss of gas or pressure drop in the system by steps of

1. collecting spent shale in a valvular zone comprising upper and lower spaced valves in an exit pipe leading from said gas-solids separating zone by opening said upper valve, and closing said lower valve;

2. introducing H.sub.2 O upstream of said lower valve thereby displacing all of the gas in said spent shale and forcing said gas back into said gas-solids separating zone while forming a shale-H.sub.2 O mixture between said valves;

3. closing said upper valve and opening said lower valve; and

4. pushing said shale-H.sub.2 O mixture out of the system by introducing H.sub.2 O downstream of said upper valve.

5. The process of claim 1 wherein the gaseous effluent stream from (3) is introduced at a velocity of from about 25 to 100 f.p.s. into the gas-solids separating zone of (4) maintained at substantially the same temperature and pressure as the tubular retort of (3).

6. A continuous process for hydrotorting raw oil shale to produce shale oil of improved quality and yield comprising

1. forming in a mixing zone a pumpable slurry of raw oil shale particles in a heavy shale oil carrier as defined hereinafter;

2. mixing together in a contacting zone the raw oil shale-shale oil slurry of (1), a stream of recycle water in an amount sufficient to substantially reduce the decomposition of inorganic carbonates in the raw oil shale, and a stream of hydrogen-rich gas in an amount sufficient to provide substantially all of the hydrogen required in the next hydrotorting step;

3. introducing the mixture from the contacting zone of (2) at high velocity into a noncatalytic tubular reaction zone located in immediate juxtaposition to said contacting zone under conditions of turbulent flow and at a pressure in the range of about 300 to 1,000 p.s.i.g., heating said mixture to an outlet temperature in the range of about 850.degree. to 950.degree. F., for a period of about one-fourth to 3 minutes while simultaneously subjecting the raw shale oil particles in said mixture to the disintegrating action of the highly turbulent flow therein and to the volumetric expansion and vaporization of the water and shale oil, thereby simultaneously effecting pyrolysis and hydrogenation of the raw shale and hydrogenation of the shale oil produced and forming a high-velocity gaseous stream of solid particles of spent shale and ash dispersed in shale oil vapor, unreacted hydrogen, water vapor, H.sub.2 S, NH.sub.3, CO, CH.sub.4 and CO.sub.2 ;

4. introducing the high-velocity gaseous effluent stream from (3) at a velocity of from about 25 to 100 f.p.s. into a gas-solids separating zone at substantially the same temperature and pressure as in the tubular reaction zone of (3), and withdrawing substantially all of the spent shale and ash substantially free from organic matter from said gas-solids separating zone;

5. cooling the solids-free gaseous effluent from (4) in a gas cooling zone to condense out crude shale oil and water containing dissolved NH.sub.3, H.sub.2 S and CO.sub.2, and introducing said liquid and uncondensed gaseous materials substantially comprising unreacted hydrogen containing gas into a gas-liquid separating zone;

6. removing the crude shale oil and water mixture from the separating zone of (5) and introducing said liquid mixture into a crude shale oil-water separation zone;

7. removing the water from the crude shale oil-water separation zone of (6) and introducing said water into a water-purifying zone where NH.sub.3, H.sub.2 S and CO.sub.2 are separated from pure water;

8. withdrawing a portion of the pure water from the water-purifying zone of (7) and recycling said water under pressure to the contacting zone of (2);

9. withdrawing the hydrogen containing gas from the gas-liquid separating zone of (5), compressing said gas, adding makeup hydrogen and recycling said gas to the contacting zone of (2) as said hydrogen-rich gas;

10. removing the crude shale oil from the crude shale oil-water separating zone of (6) and introducing said crude shale oil into a fractionation zone where pentane and lighter hydrocarbon fractions are separated from heavier shale oil fractions;

11. distilling the heavier shale oil fractions from (10) in a fractionation zone to produce a product shale oil substantially free from carbon and with reduced nitrogen and sulfur content, and a heavy shale oil bottoms product; and

12. withdrawing a portion of the heavy shale oil bottoms from the fractionation zone of (11) for recycle to the mixing zone of (1) as said heavy shale oil carrier.

7. The process of claim 6 wherein the raw oil shale is present in the raw oil shale-shale oil slurry of (1) in an amount in the range of about 30 to 80 weight percent; and the slurry is maintained at a temperature in the range of about 100.degree. to 500.degree. F.; the hydrogen-rich gas injected into the slurry in (2) comprises 45 or more volume percent of hydrogen on a dry basis and is supplied to the contacting zone at a temperature in the range of about 100.degree. to 500.degree. F. and in an amount in the range of about 5,000 to 20,000 s.c.f. of hydrogen per ton of raw shale and at an inlet velocity in the range of about 5 to 50 f.p.s.; the recycle water is injected into the slurry in (2) at a temperature in the range of about 100.degree. to 500.degree. F. and in an amount in the range of about 0.01 to 0.6 ton of water per ton of raw oil shale; and said hydrogen-rich gas and said recycle water are introduced into the contacting zone at a pressure in the range of about 25 to 200 p.s.i. greater than the line pressure; and the mixture from the contacting zone of (2) is introduced into the noncatalytic tubular reaction zone of (3) at a turbulence level, in the range of about 25 to 100,000, where is the average apparent viscosity and .nu. is the kinematic viscosity, and at a temperature below the vaporization temperature of water.

8. The process of claim 6 wherein the contacting zone of (2) is a venturi mixer and as said raw oil shale-shale oil slurry is passed axially through said venturi mixer said hydrogen-rich gas and said recycle water are introduced into said slurry at the throat of said venturi mixer.

9. The process of claim 7 wherein the noncatalytic tubular reaction zone is maintained at an outlet temperature in the range of about 910.degree. to 940.degree. F., and at a pressure in the range of about 475 to 525 p.s.i.g.; said hydrogen-rich gas supplied to the contacting zone is supplied in a minimum amount of 13,800 s.c.f. of hydrogen per ton of raw shale; said high-velocity gaseous effluent stream is introduced into said gas-solids separating zone at a minimum velocity of 33.6 f.p.s.; and the shale oil produced by the process is greater than the Fischer Assay and is essentially free from spent shale.

10. Apparatus for continuously separating spent shale particles from a gaseous stream of spent shale particles in vaporized shale oil and steam at a temperature in the range of about 850.degree. to 1,000.degree. F. and a pressure in the range of about 300 to 1,000 p.s.i.g., comprising

1. an elongated, vertical, cylindrical-shaped pressure chamber having a closed top and a closed bottom;

2. a downwardly directed open-ended pipe coil of at least one loop, said pipe coil being mounted concentrically in said chamber about midpoint and having an upper inlet end and a lower discharge end, said upper end passing through the vertical wall of said chamber and making a pressuretight seal therewith;

3. an open-ended vertical exit gas pipe depending axially from the top of said pressure chamber and having an upper end and a lower end, said upper end of the exit pipe passing through the closed top of said pressure chamber and making a pressure tight seal therewith, a "T" fitting joined to the lower end of said exit pipe and having two open ports in axial alignment, said axis being disposed perpendicular to the axis of said pressure chamber and said ports being located above the pipe coil of (2); and

4. a vertical spent shale discharge pipe with open ends and having an upper portion and a lower portion, said upper end passing through the center of said chamber bottom and making a pressuretight seal therewith, and said lower portion depending below said pressure chamber.

11. The apparatus of claim 10 with the addition of a first valve in the lower portion of the spent shale discharge pipe of (4), a second valve in said shale discharge pipe and located below said first valve, a first means for introducing H.sub.2 O downstream from said first valve and into the space in said shale discharge pipe between said first and second valves, and a second means for introducing H.sub.2 O upstream from said second valve and into the space in said shale discharge pipe between said first and second valves.