Title:
Method for recovery of hydrocarbon oils from oil shale and other carbonaceous solids
Kind Code:
A1


Abstract:
A continuous, efficient surface method for thermal recovery of hydrocarbons from a solid feedstock is described that includes a self-contained process that produces hydrogen for upgrading the hydrocarbons to produce motor fuel. The hydrogen also is used as a clean burning fuel for the thermal processing. The hydrogen is produced as a component of synthesis gas formed by gasification of coal. The synthesis gas is processed to remove and dispose of carbon dioxide and by-product sulfur. Combustion of the hydrogen to provide indirect heating of the solid feedstock maximizes hydrocarbons that can be upgraded and reduces or eliminates the emission of carbon dioxide into the atmosphere.



Inventors:
Hatfield, Kent E. (Salt Lake City, UT, US)
Coates, Ralph L. (Salt Lake City, UT, US)
Smoot, Douglas L. (Provo, UT, US)
Application Number:
11/710389
Publication Date:
08/28/2008
Filing Date:
02/23/2007
Assignee:
Combustion Resources, L.L.C. (Provo, UT, US)
Primary Class:
International Classes:
C10G1/06
View Patent Images:
Related US Applications:



Primary Examiner:
PO, MING CHEUNG
Attorney, Agent or Firm:
TRASKBRITT, P.C. (SALT LAKE CITY, UT, US)
Claims:
What is claimed is:

1. A surface method for continuously producing hydro treated and/or hydro cracked liquid hydrocarbons from a solid feedstock, said method comprising: preparing a first solid feedstock to a predetermined size and moisture content; preparing a second solid feedstock to complement first solid feedstock; providing a reactor suited for processing said first solid feedstock at substantially atmospheric pressure; providing sufficient thermal energy to said reactor to operate said reactor; preheating a reactor sweep gas; feeding said first solid feedstock into said reactor to thermally liberate hydrocarbons from said first solid feedstock; directing said preheated reactor sweep gas through said reactor to remove said hydrocarbons from said reactor; cooling said hydrocarbons to condense liquid hydrocarbons; separating said liquid hydrocarbons from gaseous hydrocarbons, other reactor off-gases and reactor sweep gas; treating said liquid hydrocarbon with hydrogen to produce a hydro treated and/or hydro cracked liquid hydrocarbon; gasifying or reforming said second solid feedstock to produce a syngas; and processing said syngas to produce an amount of hydrogen sufficient to hydro treat said liquid hydrocarbons, producing said hydro treated liquid hydrocarbons and also to provide said clean burning fuel to heat said reactor.

2. The method of claim 1, wherein said first solid feedstock is oil shale.

3. The method of claim 1, wherein said first solid feedstock is tar sands.

4. The method of claim 1, wherein said second solid feedstock is coal.

5. The method of claim 1, wherein said reactor is an indirectly heated kiln.

6. The method of claim 5, wherein said kiln is a rotary kiln.

7. The method of claim 1, wherein said condensing is accomplished using a coolant.

8. The method of claim 7, wherein said coolant is water.

9. The method of claim 1, wherein off-gases produced in said reactor are captured and utilized in said method to provide a source of heat.

10. The method of claim 1, wherein spent said first solid feedstock is collected from said reactor, said spent first solid feedstock being mixed with said second solid feedstock during said gasifying.

11. The method of claim 1, wherein fines produced during said preparing of said first solid feedstock are mixed with said second solid feedstock during said gasifying.

12. The method of claim 1, wherein said gaseous hydrocarbons and said reactor off-gases are mixed with said second solid feedstock during said gasifying.

13. The method of claim 1, wherein said gasifying is accomplished in a device selected from a group consisting of an entrained gasifier, a fixed gasifier and a fluid bed gasifier.

14. The method of claim 1, wherein said syngas is processed to remove particulates and contaminants from said syngas.

15. The method of claim 14, wherein said contaminants include sulfur and carbon dioxide.

16. The method of claim 1, wherein said gasifying or reforming of said second solid feedstock is performed physically proximate to said reactor.

17. The method of claim 1, where the treating of said liquid hydrocarbon with hydrogen to produce hydro treated and or hydro cracked liquid hydrocarbon is preformed physically proximate to said reactor.

18. The method of claim 1, wherein said thermal energy is provided by burning said second solid feedstock directly.

19. The method of claim 1, wherein said second solid feedstock is selected from the group consisting of coal, natural gas, gilsonite, spent shale and shale fines.

20. The method of claim 1, wherein said reactor is a stationary reactor having a solid screw feed system and transport system.

21. The method of claim 1, wherein said reactor is also suited for operation at elevated pressures.

22. The method of claim 20, wherein said reactor is operated at a pressure which exceeds atmospheric pressure.

23. The method of claim 1, wherein spent said first solid feedstock and off-gas produced in said reactor are subsequently burned to generate electrical energy.

24. The method of claim 1, wherein said reactor sweep gas is formed by heating water to produce steam.

25. The method of claim 1, wherein said second solid feedstock is selected from the group consisting of a solid, liquid and gaseous feedstock.

26. The method of claim 24, wherein said second solid feedstock is selected from the group consisting of gilsonite, petroleum and natural gas.

27. The method of claim 1, further comprising processing spent said first solid feedstock to produce cement.

28. The method of claim 1, wherein the second solid feedstock is further processed to produce a fuel.

29. The method of claim 28, wherein said fuel is further processed to remove particulates and contaminants.

30. The method of claim 28, wherein said fuel is combusted to provide the thermal energy requirements of said reactor.

31. The method of claim 1, wherein said first solid feedstock is preheated.

32. The method of claim 31, wherein said first solid feedstock is preheated using a heated gas selected from the group consisting of effluent gas, a reactor off-gas and gas produced from a combustion of spent said first solid feedstock.

33. The method of claim 1, wherein said sweep gas is preheated using a heated gas selected from the group consisting of effluent gas, a reactor off-gas and gas produced from a combustion of spent said first solid feedstock.

34. The method of claim 1, wherein said second solid feedstock is processed in a quantity sufficient to solely heat said reactor during said processing of said first solid feedstock and produce a quantity of hydrogen sufficient to hydro treat said liquid hydrocarbon.

35. A continuous surface method for producing hydro treated and/or hydro cracked liquid hydrocarbons from a solid feedstock, said method comprising: preparing a first solid feedstock to a predetermined size and moisture content; preparing a second solid feedstock to complement the first solid feedstock; providing a reactor suited for processing said first solid feedstock at substantially atmospheric pressure; heating said reactor; preheating a reactor sweep gas; feeding said first solid feedstock into said reactor to thermally liberate hydrocarbons from said first solid feedstock; directing said preheated reactor sweep gas through said reactor to remove said liberated hydrocarbons from said reactor; cooling said hydrocarbons to condense liquid hydrocarbons; separating said liquid hydrocarbons from gaseous hydrocarbons, other reactor off-gases and said reactor sweep gas; treating said liquid hydrocarbon with hydrogen to produce a hydro treated and/or hydro cracked liquid; gasifying or reforming said second solid feedstock to produce a syngas; further processing said syngas to remove particulates, sulfur, carbon dioxide and other contaminants and to produce hydrogen; combusting a fuel selected from the group consisting of said second solid feedstock, said syngas, spent said first solid feedstock, said reactor off-gas, fines produced during said preparing of said first solid feedstock, and said hydrogen; utilizing heat produced from said combusting to heat said reactor and said preheating reactor sweep gas; and preheating said first solid feedstock by direct contact with hot flue gas from said combusting or from gases produced by combusting a fuel selected from the group consisting of said second solid feedstock, said syngas, spent said first solid feedstock, said reactor off-gas, and said hydrogen.

36. A method of claim 35, wherein said second solid feedstock syngas is shifted to produce mostly hydrogen and then cleaned to remove sulfur, carbon dioxide and other contaminants producing a nearly pure hydrogen stream.

37. A method of claim 36, wherein said hydrogen is divided into two portions, the first to hydro treat and/or hydro crack said liquid hydrocarbons and the second portion of said hydrogen combusted with air within the external shell of said reactor to produce principally high temperature steam and nitrogen with no carbon dioxide.

38. A method of claims 36 and 37, which results in little or no emissions of carbon dioxide gas from such process method in order to reduce the impact on global warming.

Description:

GOVERNMENT RIGHTS

This invention was made with government support under DOE/SBIR Grant DF-FG-02-06ER84596. The Government has certain rights to this invention.

BACKGROUND OF THE INVENTION

1. Field

This invention relates to methods for recovering hydrocarbon oils from various solid materials. More specifically, this invention is directed to methods for recovering hydrocarbon oils from oil shale, tar sands and other carbonaceous materials.

2. Statement of the Art

Oil has been produced commercially from shale since at least as early as the mid-nineteenth century. Currently, oil production from shale is being pursued in eighteen different countries world-wide. Over the past century, the extensive oil shale deposits of the western United States have been viewed as being a potential solution to the nation's energy problems. The economic viability of oil production from shale deposits has been affected by the expansion of crude oil availability. As the price for crude oil has risen due to political instability in the Middle East, a renewed interest in oil shale production has emerged. During the Carter Administration, the President announced a massive program to produce 2.5 million barrels of crude oil per day from coal and oil shale by 1990. However, a subsequent drop in oil prices resulted in a substantial discontinuation in investment in oil shale technology and research. Recently, political unrest and hostilities in the Arabian Gulf have again resulted in significant increases in the price of crude oil thereby reinvigorating the interest in the processing of the national reserves of oil shale and tar sands.

Past oil shale recovery techniques have typically made use of some form of heating to drive off the oil from the rock. Both in-situ (below ground) and above ground heating processes have been used. The advantages of the in-situ processes include:

    • (1) Mining of the shale is typically minimal or not required;
    • (2) no disposal of the spent shale is mandated;
    • (3) the process permits access to resources which are otherwise not minable;
    • (4) the process allows for the use of lower quality shale; and
    • (5) the process requires no crushing of the shale or transportation of the shale to a processing facility.

Although past in-situ shale recovery processes have significant advantages, they are not, however, devoid of disadvantages. Some of these disadvantages are as follows:

    • (1) such processes involve significant drilling costs;
    • (2) control of the recovery process is oftentimes difficult;
    • (3) such processes typically recover a low percentage of the available shale oil;
    • (4) the oil shale treated typically has low permeability restricting flow rates of the shale oil and gas;
    • (5) such processes carry the possibility of water contamination in the area in which the processes are employed;
    • (6) control of the shale bed boundaries and operating conditions are difficult;
    • (7) such processes typically have very long residence times; and
    • (8) such processes conventionally consume high quantities of expensive energy, especially those processes which utilize electricity as the heating source.

The alternative approach of above ground processing offers the following notable advantages:

    • (1) high recovery efficiency;
    • (2) improved control of process conditions;
    • (3) easy product recovery; and
    • (4) continuous processing capability.

Despite these advantages, prior development of methods for surface processing of U.S. shale ore to recover shale oil have not resulted in commercial viability and they have been criticized for producing unacceptable air emissions.

Another consideration of importance in the economical recovery and use of shale oil is the difference between shale oil and the oil produced from conventional oil wells. The conjugated olefin structure of the hydrocarbon molecule of crude shale oil requires substantial upgrading before it can be efficiently used as a motor fuel. Relatively large quantities of hydrogen and high temperature and high pressure catalytic operating conditions are required for the processing of the shale oil. The upgrading requirements and the availability of the hydrogen to carry out the upgrading often render such oil unamenable to the processing capabilities of existing conventional oil refineries.

It is readily apparent that there continues to be a need for more efficient and more environmentally acceptable processing methods for producing high quality oil products from solid feedstocks such as oil shale.

SUMMARY OF THE INVENTION

A process suited for thermally removing liquid hydrocarbons from a solid feedstock and upgrading these liquids is disclosed. The process is specifically directed to continuously removing condensable hydrocarbons from such feedstocks as oil shale. In preferred embodiments, the process is utilized on the surface as opposed to below the surface of the earth.

The process may include the following steps:

    • (1) Preparing a first solid feedstock to a predetermined size and moisture content;
    • (2) Preparing a second solid feedstock to complement first solid feedstock;
    • (3) Drying and pre-heating the first solid feedstock;
    • (4) Providing a reactor suited for processing the first solid feedstock at an elevated temperature;
    • (5) Providing sufficient clean burning fuel to heat the reactor;
    • (6) Providing a heated reactor sweep gas;
    • (7) Feeding the first solid feedstock into the reactor to thermally liberate hydrocarbons from the first solid feedstock;
    • (8) Directing the heated reactor sweep gas through the reactor to remove the hydrocarbons from the reactor;
    • (9) Cooling the hydrocarbons to condense liquid hydrocarbons;
    • (10) Separating the liquid hydrocarbons from gaseous hydrocarbons, other reactor off-gases and reactor sweep gas;
    • (11) Treating the liquid hydrocarbon with hydrogen to produce a hydro treated and/or hydro cracked liquid hydrocarbon;
    • (12) Processing the second solid feedstock and the reactor off-gases to produce a syngas;
    • (13) Processing the syngas to produce an amount of hydrogen sufficient to hydro treat the liquid hydrocarbons producing the hydro treated liquid hydrocarbons and also to provide the clean burning fuel to heat the reactor.

In an alternative embodiment, the quantity of second solid feedstock which is processed is limited to the amount sufficient to solely produce an amount of hydrogen sufficient to hydro treat the hydrocarbons liberated from the first solid feedstock and to provide the thermal energy requirements for operating the reactor vessel.

In a preferred embodiment the process is utilized to process a first solid feedstock which may be oil shale or tar sands. Other first solid feedstocks are also within contemplation.

The processing of the second solid feedstock may include the use of a gasifer or alternatively may include the reforming of the second solid feedstock to produce the requisite hydrogen. Processing steps may be incorporated downstream of such a gasifier to remove carbon dioxide from the syngas produced by the gasifier in order to reduce carbon dioxide emissions. Various gasifier constructions may be utilized in the process, including but not limited to entrained gasifiers, fixed bed gasifiers and fluidized bed type gasifiers. In an alternative embodiment of the process, the second solid feedstock is processed by steam reforming. The process may utilize a number of solid, liquid and/or gases for second solid feedstocks such as, but not limited to, coal, gilsonite, petroleum and natural gas.

The reactor vessel utilized in the process may be an indirectly heated rotary kiln, or a stationary, i.e., non-rotating reactor with solid screw feed system and transport system. The reactor vessel may be constructed for operation at or near atmospheric pressure conditions. Alternatively, the reactor may be adapted for use at elevated pressures to thereby increase the capacity of the reactor.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of an embodiment of the process of the invention;

FIG. 2 is a flow sheet illustrating various procedural steps of an embodiment of the invention directed to coal gasification to produce hydrogen.

FIG. 3 is a flow sheet illustrating various procedural steps of an embodiment of the invention directed to the drying and preheating of oil shale;

FIG. 4 is a flow sheet which illustrates various procedural steps of an embodiment of the invention directed to shale oil recovery in a rotary kiln;

FIG. 5 is a flow sheet illustrating various procedural steps of an embodiment of the invention concerning shale oil separation; and

FIG. 6 is a flow sheet illustrating various procedural steps of an embodiment of the invention directed to shale oil upgrading.

DETAILED DESCRIPTION OF THE ILLUSTRATED EMBODIMENTS

FIG. 1 presents a simplified block diagram of an embodiment of the method of the invention. An abbreviated disclosure of the process utilizing the schematic diagram of FIG. 1 will now be discussed. Hereinafter, a more detailed description of the various components of the process will be provided.

As shown in FIG. 1, coal 10 is ground to a preselected size in coal preparation unit 12. Coal preparation unit 12 may include a conventional coal pulverizer. The pulverized coal is fed to coal gasification reactor 18 together with oxygen 16, recycled off-gas 69 and steam 17A. Oxygen 16 is produced by air separation process 15. Steam 17A is produced in syngas cooling and cleaning unit 21 and in heat recovery steam generation unit 35. Off-gas 69 is produced in syngas processing unit 25, shale oil recovery unit 60 and hydro treating and reforming process unit 65. Hot syngas 19 and ash 20 flow from the coal gasification reactor 18. Hot syngas 19 containing fine particulates produced by the coal gasification reactions is directed to syngas cooling and cleaning process 21 where particulates 20A are removed and steam 17 is generated as shown in FIG. 2. Clean syngas 22 and steam 17B enters processing unit 25 where carbon monoxide is shifted to carbon dioxide and hydrogen and sulfur 26, carbon dioxide 27, hydrogen 28 and an off-gas mixture 30 are separated. The sulfur 26 is further processed to produce elemental sulfur. The carbon dioxide 27 may be compressed for sequestration or other use rather than emitted to the atmosphere. Hydrogen 28 is divided and hydrogen 28A is used in the shale oil hydro treating and reforming unit 65 and hydrogen 28B is used as fuel for the shale ore processing unit 50. Excess hydrogen 28C and the off-gas 30 are used as fuel in a heat recovery steam generator (hereinafter a “HRSG”) unit 35. Water and waste products 24 produced in syngas process unit 25 are directed to treatment and disposal.

Shale ore 40 is mined and then crushed to a preselected size in processing step 41. The crushed shale ore 42, which forms the feedstock of the overall recovery process is introduced into preheating and drying unit 45 where, in direct contact with flue gas 48 from shale oil processing rotary kiln unit 50, it is dried and pre-heated. The cooled flue gas 37 enters flue gas cleaning unit 36 where solid particulates 38 are separated before the gas is vented to the atmosphere 39. Gas cleaning unit 36 may be a baghouse.

The dry and preheated shale 46 then enters shale ore processing rotary kiln unit 50 together with sweep steam 47. The shale is heated and pyrolysed sufficiently in unit 50 to liberate shale oil liquid, vapor and gas 53 from spent shale 51. Spent shale 51 is contacted and partially combusted with air 57 in spent shale processing unit 55. Spent shale processing unit 55 may be a fluidized bed. Heated and oxygen containing gas 56 from unit 55 enters a burner assembly surrounding shale ore processing unit 50 where it combusts with hydrogen 28B to indirectly heat the oil shale 46.

Shale oil liquid, vapor, shale gas and steam 53 are then cooled and separated in shale oil separation unit 60. (See FIG. 5.) A mixture 62 of light hydrocarbons, carbon monoxide, carbon dioxide, hydrogen and hydrogen sulfide are removed and sent to the gasification reactor 18 to produce hydrogen and to separate sulfur and carbon dioxide. Condensed water 64 is sent to spent shale processing unit 55 and disposed of with combusted spent shale 52. Crude shale oil fractions 61 are sent to the hydro treating and reforming unit 65 (See FIG. 6) where it is reacted with hydrogen 28A to produce motor fuels 70 and residual products, e.g. asphalt, 71. Off-gas stream 66 from processing unit 65 is recycled to the gasification reactor 18.

FIG. 2 illustrates an embodiment of the coal gasification and hydrogen production portion of the process. Coal 10 is delivered to the processing site by truck, rail or other conventional means. The coal is unloaded and transferred directly into storage silo 105. Alternatively, it can be stockpiled on site and then transferred to the silo 105. It is fed from silo 105 into pulverizer 110 where the particle sizes are reduced until at least 70% of the particles pass through a 200 mesh screen. Air is blown by fan 106 into combustor 108, where it reacts with recycled off-gas 69B. The hot flue gas 109 then passes through pulverizer 110, heating and drying the coal particles. The flue gas then transports coal particles through cyclone 111, where oversize particles are removed and recycled, and the fine particles 112 are directed to storage vessel 113. The flue gas then passes out of vessel 113 and through bag house 114 before venting to the atmosphere 115.

The pulverized coal within vessel 113 passes into lock hopper vessel 116, where it is pressurized by recycled off-gas 69D. Following pressurization it passes into feed vessel 117 then through feeding device 122 where it is picked up by recycled off-gas 69C and blown into the gasification reactor 18. Oxygen 16 from oxygen separator 15 is fed into gasification reactor 18 together with steam 17A. Ash produced in the gasification reactor drops into ash lock 131 where is picked up by a water stream 155 and periodically discharged 132 to separator 151. A particulate and ash stream 20 from separator 151 is combined with spent shale stream 52 for landfill disposal. (See FIG. 4.) Separator 151 may be a gravity separator. Syngas stream 19 flows out of the gasification reactor 18 and through gas cooler 140, filter 141, scrubber 146 and into shift reactor 142. There it reacts with steam 17B to convert carbon monoxide to carbon dioxide and hydrogen. The shifted syngas passes into cooler and knock-out unit 143 where the excess steam is condensed. Knock-out unit 143 may be a heat exchanger. From unit 143 the syngas passes through an amine selective absorption unit 144 where sulfur and carbon dioxide are removed and then into pressure swing absorbing (“PSA”) unit 145 where the final hydrogen product 28 is separated.

FIG. 2 depicts dry coal feeding of coal into gasification reactor 18. Slurry coal feeding as is well known in the art of coal gasification is an alternative embodiment. In this alternative embodiment off-gas 69C would be fed separately into gasification reactor 18 and steam 17A would be reduced or eliminated.

In another embodiment of the invention, hot cyclones are positioned upstream of gas cooler 140 or filter 141. The cyclones are used to remove the coarser ash and carbon particles. Wet scrubber 146 removes the final traces of particulates. Ammonia and trace metal compounds like lead, mercury and arsenic, present in very small amounts, are also removed at wet scrubber 146.

Steam is produced in cooling passages of coal gasification reactor 18, in gas cooler 140 and HRSG 35.

As shown in FIG. 2, sulfur in the form of H2S is then removed in a dual amine unit 144. It is typically removed in three steps. The first step is the contacting of the H2S with an acid gas solvent, such as methyldiethanolamine [MDEA], whereby H2S is extracted from the gas stream and regenerated as a fairly pure H2S stream. The H2S goes to a classical Claus Sulfur plant 110 where solid sulfur is formed and removed from the system. This sulfur is usually sold as a fertilizer additive for the use with alkaline soils.

As further shown in FIG. 2, carbon dioxide 27 also is removed in amine unit 144. A CO2 selective solvent similar to that in the sulfur contactor unit, absorbs the CO2 from the syngas stream. The absorbed CO2 is then stripped and subsequently pressurized or condensed by compressor 149 depending on the intended underground disposal method or for purposes of secondary petroleum recovery. This step in processing of the syngas may be eliminated in a plant having unrestricted CO2 emissions requirements.

The syngas stream from amine unit 144 contains hydrogen, carbon monoxide, carbon dioxide and small amounts of methane, nitrogen and argon. The hydrogen is separated from this mixture in a pressure swing absorption unit 145 that produces 99% pure hydrogen 28 for plant hydro-processing 28A and fuel needs 28B and 28C. (See FIG. 1) Off-gas 30A from the PSA unit 145 is combined with off-gas 69. The combined off gases are directed to the shift reactor 142 and to the gasification reactor 69A. A portion of the combined compressed off gases are also directed through the ejector 154 where they are combined with particulates 20A and subsequently directed to the gasification reactor 18. Further the combined off gases are directed to combuster 108.

FIG. 3 illustrates an embodiment of the shale ore drier and pre-heater portion of the process. Shale ore is typically mined from deposits which typically lie near the surface. In some instances, the overburden covering a shale ore deposit may be 1000 feet in depth. The ore is conventionally mined and thereafter crushed to a processing size of minus ⅜ inch by conventional techniques. As shown, the crushed shale ore 40 is delivered to the processing site by truck, rail or other conventional means. The shale ore can be delivered to an on-site stock pile or conveyed directly into a storage silo 77 via conveyor 73 and elevator 74. Thereafter the shale ore is moved by conveyor 76 and elevator 78 to a first screw 76 which transfers the ore to rotary drier and heater 80. The ore is then heated by direct contact with hot flue gas 48 from indirect-fired rotary kiln 90. (See FIG. 4) The flue gas typically flows co-currently with the flow of shale ore and the ore is heated to a temperature less than that corresponding to the onset of pyrolysis reactions, e.g. 400-500 degrees F.

Flue gas 37 is drawn from drier and heater 80 and through cyclones 82 and dust bag house 83 by fan 84 and then exhausted to the atmosphere through stack 85. Dust 38 from the cyclones and bag house is transported to the dry, pre-heated ore stream 46 by conveyors 85 and 86.

FIG. 4 illustrates an embodiment of the shale recovery unit. It shows shale ore 46 from the preheater 80 is directed by screw 86 into an indirect-fired rotary kiln 90. A stream of sweep steam 17 from HSRG 35 is passed through the screw 86 with the shale ore. An alternative embodiment might employ two or more parallel indirectly heated rotary kilns rather than the single kiln depicted in FIG. 4.

In rotary kiln 90 the shale ore is indirectly heated to a temperature typically between 900 F and 1100 F resulting in pyrolysis reactions releasing oil liquid, vapor, hydrocarbon gases, hydrogen, carbon monoxide, carbon dioxide and hydrogen sulfide. This final temperature must be closely controlled in order to release the hydrocarbon material while not releasing significant amounts of CO2 by decomposition of the calcite and dolomite (carbonate) materials present in the shale ore.

Kiln 90 is heated by burning hydrogen 28B with pre-heated oxygen rich flue gas 56 from the spent shale processor 55, which may be a fluidized bed contactor 94. Flue gas 56 is produced by blowing air with fan 95 through spent shale processor 94 where it is heated and reacts with charred hydrocarbon material in the spent shale.

Coal ash slurry 20 is fed into the lower outlet of kiln 90 to enable disposal with the spent shale. The spent shale and ash are discharged through screw 89 into spent shale processor 94. Waste water stream 64 enters the lower section of processor 94 to enable disposal of waste water with the spent shale and the cooled, moist spent shale and ash 52 is discharged through screw 98. In an alternate embodiment, in order to take advantage of the cement like properties of the spent shale and ash the feed rate of water in stream 64 may be adjusted and proportioned so as to obtain a moisture content of about 20% in the resultant mixture.

Shale oil, liquids, vapors and gases 53 pass through cyclone 91 before leaving kiln 90 in order to remove entrained particulates. Fine particulates are removed from the gases 53 using electrostatic precipitator 92. In an alternative embodiment precipitator 92 may be eliminated.

FIG. 5 depicts an embodiment of cooling the stream of vapors and gases 53 from kiln 90 and separating them into oil and gas fractions. Stream 53 is partially cooled and the dust removed by a sprayed diesel fraction 61B1. The vapors and gases are then further cooled to about 400 F in a pump around system using refinery type air coolers and a packed tower (Residual & Diesel Knockout Vessel 160) where a large part of the shale oil is condensed as a diesel boiling fraction 61B. As shown the diesel fraction is initially passed into Diesel Receiver 180 and thereafter through pump 171 and then through cooler 165. A portion of the diesel fraction is directed to Diesel Air Cooler 161 and thereafter returned to the Knockout Vessel 160. The Residual Fraction 61A is removed from the Knockout Vessel 160 and is then cooled in cooler 165. Subsequently the Residual Fraction passes through pump 173 and thereafter through Residual Filter 192.

The shale gas 166 is then further cooled to 150-175 F using a water stream (condensed steam) in gasoline condenser 170. A gasoline boiling cut 61C is condensed out in this step, along with most of the steam 64A. Gasoline boiling cut 61C is thereafter directed through cooler 165C and pump 174. Steam 64A is directed through pump 175. A portion of stream 64A is directed to an air cooler 162 and subsequently reintroduced into condenser 170. A gas and water vapor mixture 167 is withdrawn from condenser 170 and is The gas is next compressed to 100 psig by gas compressor 178 and cooled in a water-cooled heat exchanger 165D, where the remainder of the steam [water] and a fraction of the shale oil is condensed. Gases 62, composed of C1, C2, C3, CO, CO2, H2, and H2S, are sent to the coal gasification and hydrogen production and purification section of the plant. The C4, C5 and C6 fraction 61D is directed to further processing. The condensate gases are directed to a receiver gravity separator vessel 190 which functions to separate light gases 62 from liquids 61D (C4-C6 fractions) (and water 64B. Water 64B is thereafter directed through pump 176 and thereafter mixed with water 64A, which is exiting pump 175, to form water stream 64. A portion of residual product 70A is recycled through compressor 211 to heater 201 and hydro cracker 204.

FIG. 6 illustrates an embodiment of the process for shale oil upgrading. Residual fraction 61A and hydrogen stream 28A1 pass through heater 201 and then through hydro cracker 204. The resulting upgraded liquids are then separated in cooler and knock-out 207 from unreacted excess hydrogen and off-gases. The unreacted excess hydrogen 28A2 is compressed and recycled by compressor 216 and the off-gas 66A is compressed by compressor 218 and recycled to the coal gasification and hydrogen production section of the plant. The upgraded liquid 219 from cooler and knock-out 207 is separated in distillation column 215 into diesel fraction 191, gasoline fraction 192 and final residual product 70A.

Diesel fraction 61B, diesel fraction stream 191 and hydrogen stream 28A2 pass through heater 202 and then pass through hydro pyrolysis unit 205. The resulting upgraded liquids are then separated in cooler and knock-out 208 from unreacted excess hydrogen 222 and off-gases 66B. The unreacted excess hydrogen is compressed and recycled by compressor 217 and the off-gas 66B is compressed in compressor 218 and recycled to the coal gasification and hydrogen production section of the plant. The final upgraded diesel product is stream 70B.

Gasoline fraction 61C, C4-C6 fraction 61D and gasoline fraction stream 192 pass with hydrogen stream 28A3 through heater 203 and then through hydro pyrolysis unit 206. The resulting upgraded liquids 223 are then separated in cooler and knock-out 209 into unreacted excess hydrogen 224 and off-gases 66C and gasoline product 225. The gasoline product 225 is then passed through reformer 210 to form gasoline product 70C. The unreacted excess hydrogen 224 is compressed and recycled by compressor 217 and the off-gas 66C is compressed in compressor 218. Both gases are recycled, with some of the gases being directed to the coal gasification and hydrogen production section of the plant. The upgraded liquid 225 is sent to reformer 70C to produce the final gasoline product, stream 70C. The off gases 66A, 66B, 66C and 220 are compressed by compressor 218 and a portion thereof is used as fuel for heaters 201, 202 and 203. The balance of the gases 66 is combined with off gas 62 to form stream 69 (See FIG. 1). Water 155 is directed through a water treatment unit 156, which may be an ion exchanger. Thereafter the water 155 is directed through a deaerator 157 forming boiling feed water (BFW) 240 which is introduced into boiler 35.

All hydrogen produced in the process is used either for liquid upgrading or for producing process heating, with any excess being used for generating steam. Any steam so generated which is not needed for the process would be sent to a turbine for purposes of electrical power generation.

Changes may be made to the embodiments described in this disclosure without departing from the broad inventive concepts they illustrate. Accordingly, this invention is not limited to the particular embodiments disclosed, but is intended to cover all modifications that are within the scope of the invention as defined by the appended claims.