EE05796B1 - Integrated process for oil shale oil refining - Google Patents

Abstract

Integrated processes for the enrichment of crude oil shale oils, such as those obtained by cracking or in situ extraction of oil shale or mixtures thereof. Published processes for oil shale crude oil enrichment are based on a discrete flow treatment scheme. The concept of discrete flow described herein, i.e. one or more stages of hydrotreating petroleum and kerosene and one or more stages of gas oil treatment, requires the use of additional equipment compared to alternative crude oil hydrotreating. Contrary to the widespread perception that this requires a larger capital investment to produce a similar list of end products, operating power, time efficiency, and product quality are far more valuable than somewhat higher equipment costs in a disconnected flow concept.

Description

TECHNOLOGY FIELD

[0001] The embodiments disclosed herein generally relate to a process for enriching crude oil shale, such as crude oil derived from crude oil shale produced by cracking or in situ extraction of oil shale.

STATE OF THE ART

[0001] Oil shale crude oil contains a wide range of distillates and residual fractions with varying compositions, from light hydrocarbons typically boiling in the C4 region and extending over a wide range of higher boiling hydrocarbons and heteroatoms to compounds boiling at 524°C and above in the vacuum residue region. These wide boiling ranges of hydrocarbons and heteroatoms can create a wide range of variable reactivities for downstream catalytic and thermal enrichment processes. Oil shale crude oil may contain nitrogen-containing compounds, metals, arsenic and/or selenium and arsenic and/or selenium compounds, and other impurities such as sulfur-containing compounds. In addition, shale crude oil may contain particulate matter, which is fine particles of oil shale suspended or trapped in enriched products of shale crude oil, originating from upstream cracking or in situ extraction processes. The hydrocarbons in shale crude oil may include various paraffins, olefins, diolefins, and aromatics, including heavy oil, gas oil, and asphaltenes containing a variety of fused aromatic ring compounds.

[0002] Oil shale crudes are usually processed in a single hydrotreating reactor. The reactor operates in a single strict hydrotreating regime, but it cannot yet perform the necessary hydrotreating reactions to enrich the oil shale crude without the processing setbacks such as gas generation due to fouling/clogging and low selectivity. This is a consequence of the different compositions and reactivities of the various fractions in the oil shale crude.

[0003] Processes for the enrichment of crude oil from oil shale have been disclosed. For example, US4133745 discloses a process for the processing of oil shale in which the oil shale is fractionated into a petroleum fraction boiling below 177°C and a gas oil fraction boiling above 177°C. The petroleum fraction is then hydrotreated to remove nitrogen and the gas oil is treated to remove impurities, such as by treating with sodium hydroxide. The gas oil is then hydrotreated to remove nitrogen compounds and fractionated to yield a second petroleum fraction boiling below 450°F. Since this approach hydrotreats only a small portion of the light petroleum fraction, it has the disadvantage of contamination, plugging, and selectivity problems.

ESSENCE OF THE INVENTION

[0004] In contrast to previously known processes, the embodiments disclosed herein successfully separate oil shale crude oil or partially hydrotreated oil shale crude oil such that the necessary hydrotreating reactions, namely diolefin saturation; hydrodemetallization (HDM); monoolefin saturation; hydrodenitrogenation (HDN); hydrodesulfurization (HDS); hydrodeoxygenation (HDO), can be efficiently performed, without the damage caused by fouling/blockages and low selectivity, such as gas generation, ensuring the production of high-value hydrocarbon products.

[0005] Contrary to common industry thinking, the flow schemes disclosed herein, based on the concept of divergent flow hydroprocessing of different shale oil fractions in separate hydroprocessing reactors, may be economically viable, even if they require additional reactors and other associated processing equipment. However, the ability to optimize the hydroprocessing conditions in each separate hydroprocessing reactor allows for significant improvements, such as minimizing catalyst fouling rates; increasing product processing time and production efficiency; and significantly improving the quality of the hydroprocessed product, in which case the product yield increases, thereby reducing the total cost of processing and mitigating capital investment costs.

[0006] In one aspect, the embodiments disclosed herein provide an integrated process for enriching oil shale crude oils obtained by cracking or in situ extraction of oil shale, or indirect production of mixtures thereof. The process may include the steps of: (a) fractionating oil shale crude oil into a first fraction comprising naphtha, kerosene, and diesel oil and an atmospheric bottom fraction comprising gas oil and residues; (b) contacting the first fraction with hydrogen in a first stage hydrotreating reactor containing a hydrogenation catalyst to saturate the diolefins contained in the first fraction and disposing of the residues from the first stage hydrotreating reactor; (c) directing the effluent from the first stage hydrotreating reactor of step (b) without phase separation to a second stage hydrotreating reactor operating in an upstream mode and containing catalysts for hydrodemetallization and saturation of monoolefins in the effluent from the first stage hydrotreating reactor and collecting the effluent from the second stage hydrotreating reactor; (d) directing the effluent from the second stage hydrotreating reactor of step (c) without phase separation to a third stage hydrotreating reactor containing one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and aromatic saturation of the effluent from the second stage hydrotreating reactor and collecting the effluent from the third stage hydrotreating reactor; (e) directing the atmospheric bottoms fraction and hydrogen to a fourth stage hydrotreating reactor operating in an upstream mode, which contains a catalyst for hydrodemetallization of the atmospheric bottoms fraction and where the fourth stage reactor effluent is collected; (f) directing the effluent from the fourth stage hydrotreating reactor of step (e) without phase separation to a fifth stage hydrotreating reactor containing one or more catalyst beds, each containing a catalyst for performing one or more hydrotreatments or hydrocrackings of the effluent from the fourth stage hydrotreating reactor and where the fifth stage hydrotreating reactor effluent is collected; and (g) treating the effluent from the fifth stage hydrotreating reactor of step (f) and the third stage hydrotreating reactor of step (d) in a separation line to collect two or more hydrocarbon fractions.

[0007] In another aspect, the embodiments disclosed herein provide an integrated process for enriching oil shale crude oils produced by oil shale cracking or in situ extraction, or combinations thereof. The process may include the steps of: (a) fractionating oil shale crude oil into a first fraction comprising naphtha, kerosene and diesel oil and an atmospheric bottoms fraction comprising gas oil and residues; (b) directing the first fraction and hydrogen to a first stage hydrotreating reactor comprising a hydrogenation catalyst for saturating olefins comprising the first fraction and collecting effluents from the first stage hydrotreating reactor; (c) directing the effluent from the first stage hydrotreating reactor of step (b) without phase separation to a second stage hydrotreating reactor operating in an upstream mode and containing catalysts for hydrodemetallization and saturation of monoolefins in the effluent from the first stage hydrotreating reactor and collecting the effluent from the second stage hydrotreating reactor; (d) directing the atmospheric bottoms fraction and hydrogen to a third stage hydrotreating reactor operating in an upstream mode, containing a catalyst for hydrodemetallization and collecting the effluent from the third stage reactor; (e) directing the effluent from the third stage hydrotreating reactor of step (d) without phase separation to a fourth stage hydrotreating reactor comprising one or more catalyst beds, each containing a catalyst for performing one or more hydrotreating or hydrocracking operations on the effluent from the third stage hydrotreating reactor and collecting the effluent from the fourth stage hydrotreating reactor; (f) directing the effluent from the second stage hydrotreating reactor of step (c) and the effluent from the fourth stage hydrotreating reactor of step (e) without phase separation to a fifth stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and aromatic saturation of the effluent from the second and fourth stage hydrotreating reactors and collecting the effluent from the fifth stage hydrotreating reactor; and (g) treating the effluent from the fifth stage hydrotreating reactor of step (f) in a separation line to collect two or more hydrocarbon fractions.

[0008] In another aspect, the embodiments disclosed herein provide an integrated process for enriching oil shale crude oils produced by oil shale cracking or in situ extraction, or combinations thereof. The process may include the steps of: (a) contacting oil shale crude oil and hydrogen in a first stage hydrotreating reactor comprising hydrogenation catalysts for saturating diolefins contained in the oil shale crude oil and collecting effluents from the first stage hydrotreating reactor; (b) directing the effluent from step (a) without phase separation to a second stage hydrotreating reactor operating in an upstream mode and comprising catalysts for hydrodemetallization and saturating monoolefins in the effluent from the first stage hydrotreating reactor and collecting effluents from the second stage hydrotreating reactor; (c) fractionating the effluent from the second stage hydrotreating reactor of step (b) into a partially hydrotreated fraction comprising oil, kerosene and diesel oil and a partially hydrotreated bottoms fraction comprising gas oil and residues; (d) passing the partially hydrogenated fraction to a third stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and hydrodearomatization of the partially hydrogenated fraction and collecting the effluent from the third stage hydrotreating reactor; (e) passing the partially hydrogenated bottoms fraction to a fourth stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and hydrodearomatization of the partially hydrogenated bottoms fraction and collecting the effluent from the fourth stage hydrotreating reactor; and (f) treating the effluent from the third stage hydrotreating reactor of step (d) and the fourth stage hydrotreating reactor of step (e) in a separation line to produce two or more hydrocarbon fractions.

[0009] In another aspect, the embodiments disclosed herein provide an integrated process for enriching crude oil from oil shale produced by oil shale cracking or in situ extraction, or combinations thereof. The process may include the steps of: (a) contacting shale oil and hydrogen in a first stage hydrotreating reactor comprising catalysts for diolefins contained in the shale oil and collecting effluents from the first stage hydrotreating reactor; (b) directing the effluent from step (a) without phase separation to a second stage hydrotreating reactor operating in an upstream mode and comprising catalysts for hydrodemetallization and saturation of monoolefins in the effluent from the first stage hydrotreating reactor and collecting effluents from the second stage hydrotreating reactor; (c) fractionating the effluent from the second stage hydrotreating reactor of step (b) into a partially hydrotreated fraction comprising naphtha, kerosene and diesel oil and a partially hydrotreated bottoms fraction comprising gas oil and residues; (d) passing the partially hydrogenated bottoms fraction to a third stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and aromatic saturation of the partially hydrogenated bottoms fraction and collecting effluent from the third stage hydrotreating reactor; (e) mixing the partially hydrogenated fraction from the third stage hydrotreating reactor and the effluent from the third stage hydrotreating reactor to form a mixture; (f) passing the mixture to a fourth stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and aromatic saturation of the mixture and collecting effluent from the third stage hydrotreating reactor; (g) treating the effluent from the fourth stage hydrotreating reactor in a separation line to produce two or more hydrocarbon fractions.

[0010] In another aspect, the embodiments disclosed herein provide an integrated process for enriching crude oil from oil shale produced by oil shale cracking or in situ extraction, or combinations thereof. The process may include the steps of: (a) contacting shale oil and hydrogen in a first stage hydrotreating reactor comprising catalysts for diolefins contained in the shale oil and collecting effluents from the first stage hydrotreating reactor; (b) passing the effluent from step (a) without phase separation to a second stage hydrotreating reactor operating in an upstream mode and comprising catalysts for hydrodemetallization and conversion of monoolefins in the effluent from the first stage hydrotreating reactor and collecting effluents from the second stage hydrotreating reactor; (c) directing the effluent from the second stage hydrotreating reactor of step (b) without phase separation to a third stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and aromatic saturation of the effluent from the second stage hydrotreating reactor and collecting the effluent from the third stage hydrotreating reactor; (d) fractionating the effluent from the third stage hydrotreating reactor of step (c) into a partially hydrotreated fraction comprising naphtha, kerosene and diesel oil and a partially hydrotreated vacuum gas oil fraction; (e) directing the partially hydrotreated vacuum gas oil fraction to a fourth stage hydrotreating reactor comprising one or more catalyst beds for hydrocracking the partially hydrotreated vacuum gas oil fraction and collecting the effluent from the fourth stage hydrotreating reactor; (f) directing the effluent from the fourth stage hydrotreating reactor to the fractionation step (d).

[0011] Other aspects and advantages will become apparent from the following description of the invention and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0012] Figures 1-5 illustrate simplified process flow diagrams of oil shale crude oil enrichment processes according to embodiments disclosed herein.

EXAMPLE OF THE INVENTION

[0013] In one aspect, the embodiments disclosed herein relate to the hydroprocessing of oil shale crude oil, such as crude oils produced from oil shale either by shale cracking or in situ extraction, or mixtures thereof. Oil shale crude oil, as mentioned above, contains a wide range of distillate fractions with varying compositions and reactivities. The embodiments disclosed herein separate oil shale crude oil or partially hydrotreated oil shale crude oil so that the necessary hydroprocessing reactions, namely diolefin saturation (DOS), hydrodemetallization (HDM), monoolefin saturation (MOS), hydrodenitrogenation (HDN), hydrodesulfurization (HDS), hydrodeoxygenation (HDO), hydrodearomatization (HDA), and gas oil hydrocracking (HYC), can be efficiently performed without severe fouling/blockage and low selectivity losses, i.e., without high gas evolution, yielding high value hydrocarbon products.

[0014] Referring now to Fig. 1, there is illustrated a simplified flow diagram of an integrated process according to embodiments for the enrichment of crude oil shale, such as those produced by cracking or in situ extraction of oil shale, or mixtures thereof. The crude oil 10 may be fed to a fractionator 12 for fractionation of the crude oil shale into a first fraction 14 comprising naphtha, kerosene, and diesel oil (NKD) and a second fraction 16 comprising gas oil and residues (AGO).

[0015] The first fraction 14 and hydrogen 15 may be fed to a first stage hydrotreating reactor, or NKD first stage hydrotreating reactor 18, which contains a hydrogenation catalyst, to saturate the diolefins contained in the first fraction. Following hydrogenation, the effluent 20 from the NKD first stage hydrotreating reactor 18 may be collected.

[0016] The effluent 20 from the NKD first stage hydrotreating reactor 18 can then be fed without phase separation to the second stage hydrotreating reactor, or NKD second stage hydrotreating reactor 22. The NKD second stage hydrotreating reactor 22 can operate in an upstream mode and can contain catalysts for hydrometallization and saturation of monoolefins in the effluent 20 collected from the NKD first stage hydrotreating reactor 18. Following the reaction in the NKD second stage hydrotreating reactor 22, the effluent 24 from the NKD second stage hydrotreating reactor can be collected.

[0017] The effluent 24 from the NKD second stage hydrotreating reactor 22 may then be fed without phase separation to the tertiary hydrotreating reactor, or NKD third stage hydrotreating reactor 26. The NKD third stage hydrotreating reactor may include one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation, and hydrodearomatization of the effluent 24 collected from the NKD second stage hydrotreating reactor 22. Following hydrotreating, the effluent 28 from the NKD third stage hydrotreating reactor 26 may be collected.

[0018] The second fraction 16 and hydrogen 29 may be fed to a fourth stage hydrotreating reactor, or AGO first stage hydrotreating reactor 30. The AGO first stage hydrotreating reactor 30 may operate in an upstream mode and may contain catalysts to effect hydrodemetallization of the second fraction 16. Following the reaction, the effluent 32 from the AGO first stage hydrotreating reactor 30 may be collected.

[0019] The effluent 32 from the AGO first stage hydrotreating reactor 30 may be fed without phase separation to the fifth stage hydrotreating reactor, or AGO second stage hydrotreating reactor 34. The AGO second stage hydrotreating reactor 34 may include one or more catalyst beds, each containing a catalyst for performing one or more hydrotreating and hydrocracking operations on the effluent 32 collected from the AGO first stage hydrotreating reactor 30. Following the hydrotreating and/or hydrocracking operations, the effluent 36 from the AGO second stage hydrotreating reactor 34 may be collected.

[0020] The effluents 28, 36 from the AGO second stage hydrotreater 34 and the NKD third stage hydrotreater 26 may be combined to form a mixed stream 38, which may be fed to a separation line 40. The separation line 40 may include one or more distillation and/or extractive distillation columns for separating the effluents into two or more hydrocarbon fractions. In some embodiments, such as the embodiment illustrated in FIG. 1, the two or more fractions may include a light fuel oil co-product and unreacted hydrogen 42, kerosene 44, diesel oil 46, and a residual fraction 48. In various embodiments, other hydrocarbon fractions may also be collected. [0021] The treatment of the first fraction 14 and the second fraction 16 may be carried out in a continuous process. However, upstream reactors 22, 30 may require much more frequent catalyst replacement than reactors 18, 26, 34. Bypass lines 25, 33 may be provided to bypass at least one of the NKD second stage hydrotreating reactor 22 and the AGO first stage hydrotreating reactor 30 to allow catalyst replacement in the reactors while continuing to operate the remainder of the process, including fractionation in columns 12, 40 and reaction in reactors 18, 26, 34. The ability to bypass reactors 22 and 30 allows catalyst replacement in reactors 22, 30 without shutting down the remainder of the process, increasing the uptime of the unit and continuing to convert the oil shale crude oil into useful hydrocarbons.

[0022] Referring now to FIG. 2 , there is illustrated a simplified flow diagram of an integrated process for enriching oil shale crude oils produced by oil shale cracking or in situ extraction, or mixtures thereof, in accordance with embodiments. Oil shale crude oil 210 may be fed to a fractionator 212 for fractionating the oil shale crude oil into a first fraction 214 comprising naphtha, kerosene and diesel oil (NKD) and a second fraction 216 comprising gas oil and residue (AGO).

[0023] The first fraction 214 and hydrogen 215 may be fed to a first stage hydrotreating reactor, or NKD first stage hydrotreating reactor 218, which contains a hydrogenation catalyst to saturate the diolefins contained in the first fraction. Following hydrogenation, the effluent 220 from the NKD first stage hydrotreating reactor 218 may be collected.

[0024] The effluent 220 from the NKD first stage hydrotreating reactor 218 can then be fed without phase separation to the second stage hydrotreating reactor, or NKD second stage hydrotreating reactor 222. The NKD second stage hydrotreating reactor 222 can operate in an upstream mode and can contain catalysts for hydrometallization and saturation of monoolefins in the effluent 220 collected from the NKD first stage hydrotreating reactor 218. Following the reaction in the NKD second stage hydrotreating reactor 222, the effluent 224 from the NKD second stage hydrotreating reactor can be collected.

[0025] The second fraction 216 and hydrogen 227 may be fed to a tertiary hydrotreating reactor, or AGO first stage hydrotreating reactor, which operates in an upstream mode and contains catalysts for hydrometallization. Following the reaction, the effluent 228 from the AGO first stage hydrotreating reactor 226 may be collected.

[0026] The effluent 228 from the AGO first stage hydrotreating reactor 226 may be fed without phase separation to a fourth stage hydrotreating reactor, or AGO second stage hydrotreating reactor 230, which includes one or more catalyst beds, each containing a catalyst for performing one or more hydrotreating and hydrocracking operations on the effluent collected from the AGO first stage hydrotreating reactor 226. Following the hydrotreating and/or hydrocracking, the effluent 232 from the AGO second stage hydrotreating reactor 230 may be collected.

[0027] The effluents 224, 232 from the NKD second stage hydrotreating reactor 222 and the AGO second stage hydrotreating reactor 230, respectively, are fed without phase separation to the fifth stage hydrotreating reactor 234, which contains a catalyst for hydrodenitrification, hydrodesulfurization, hydrodeoxygenation, and hydrodearomatization of the combined effluent stream. Following hydrotreating, effluent 236 from the fifth stage hydrotreating reactor 234 may be collected.

[0028] The effluent from the fifth stage hydrotreating reactor 234 may then be fed to a separation line 238. The separation line 238 may include one or more distillation and/or extractive distillation columns for separating the effluent into two or more hydrocarbon fractions. In some embodiments, such as the embodiment illustrated in FIG. 2 , the two or more fractions may include a light fuel oil co-product and unreacted hydrogen 242, kerosene 244, diesel oil 246, and a residual fraction 248. In various embodiments, other hydrocarbon fractions may also be collected.

[0029] The processing of the first fraction 214 and the second fraction 216 may be carried out as a continuous process. However, the upstream reactors 222, 226 may require much more frequent catalyst replacement than the reactors 218, 230, 234. Bypass lines 225, 229 may be provided to bypass at least one of the second stage hydrotreating reactor 222 and the third stage hydrotreating reactor 226 to allow catalyst replacement in the reactors while continuing to operate the remainder of the process, including fractionation in columns 212, 238 and reaction in reactors 218, 230, 234. The ability to bypass reactors 222 and 226 allows the catalysts in reactors 222, 226 to be replaced without shutting down the remainder of the process, increasing the uptime of the unit and continuing to convert the oil shale crude oil into useful hydrocarbons.

[0030] As described above with reference to FIGS. 1 and 2, the combined light distillate stream (containing naphtha, kerosene, and diesel oil material) from fractionation of oil shale crude oil is first passed through a diolefin saturation (DOS) reactor operating at relatively low temperatures. The DOS reactor is followed by an upstream reactor (UFR) loaded with various types of hydrodemetallization (HDM) catalysts. Some olefins are also saturated in this reactor. Following the HDM reactor, the light distillates are passed to a primary hydrotreating reactor where hydrodesulfurization (HDS), hydrodenitrogenation (HDN), hydrodeoxygenation (HDO), and some aromatic saturation reactions occur. The effluent from the primary hydrotreating reactor is passed to a separator where most of the light gases, ammonia, and hydrogen sulfide are removed. The combined heavy distillate stream (containing gas oil and residues) is first passed through an upstream reactor (UFR) loaded with various types of hydrodemetallization (HDM) catalysts. Olefins can also be saturated in this reactor. After the HDM reactor, the heavy distillates are passed to a hydrotreater for hydrocracking and hydrotreating of heavy hydrocarbons.

[0031] The hydrotreated heavy and light distillate streams can then be further processed, either together or separately, to recover useful hydrocarbon products. For example, the hydrotreated streams can be subjected to reduced pressure to remove ammonia and hydrogen sulfide. Optionally, the resulting liquid streams can also be directed to an aromatics saturation reactor (not shown in Figures 1 and 2). The reactor effluents are evaporated to remove hydrogen, and the liquid hydrocarbon products can be fractionated to recover the product. If Syncrude oil is desired, only a simple evaporator is required to recover the product. Much more complex distillation lines can be used to produce hydrocarbon products with discrete boiling ranges.

[0032] The reaction section shown in Figs. 1 and 2 thus comprises two parallel hydrotreating reactor systems in the same high pressure circuit. In one reactor system, a feedstock heavy gas oil is hydrotreated, while in the other reactor system, a combined narita, kerosene and diesel oil are hydrotreated to remove contaminants. An alternative scheme, as referred to above, includes an aromatics saturator reactor to enrich the hydrotreated oil shale crude oil into end products. Without an aromatics saturator reactor, either blending with direct products or crude oil production are also possible options available to obtain the end products. The reaction section may also include equipment for separating hydrogen-rich gas from the final reactor effluent. This gas stream may be compressed and recycled through the high pressure reactor circuit and, if necessary, combined with the final hydrogen.

[0033] While the simplified flow diagrams shown in Figs. 1 and 2 have been described above, various parts of the plant may be used to process the feed and effluent products of each reactor and separation system, including heat exchangers, filters, condensers, evaporators, and other devices known to those skilled in the art. A more detailed description of one embodiment of the process is provided below. Similar aspects may be extended to other embodiments provided herein, such as the flow diagrams described below, which provide alternative means for parallel hydrotreating of the heavy gas oil feed and the NKD fraction.

[0034] A crude oil, kerosene, and diesel (NKD) feed stream may be directed through a feed filter and pumped up the reactor circuit under pressure by a feed pump. In some embodiments, the feed filter may be an automatic backwash type filter. Alternatively, a 1 micron cone filter may be used downstream of the automatic backwash filter for shale oil feedstock. The filtered fresh NKD feed is mixed with preheated hydrogen-rich recycle gas and directed through a naphtha, kerosene, and diesel diolefin saturation reactor (NKD DOS). The NKD DOS reactor operates at a relatively high liquid hourly space velocity (LHSV) and a relatively low temperature to facilitate the saturation of the diolefins, thereby preventing the formation of gum that would foul the indirect catalyst for the polymerization reactions. The NKD DOS effluent can be preheated in a feed-to-effluent exchanger and passed through the NKD upstream capture reactor (NKD UFR) where metal contaminants are removed. The NKD UFR effluent is further heated in a second feed-to-effluent exchanger and then in the reactor feed furnace. The reactor feed furnace inlet temperature can be controlled by setting an oil feed bypass around the feed-to-effluent exchangers to maintain a sufficiently heated inlet section in the furnace. Maintaining such a heated inlet in the furnace ensures stable reactor inlet temperature control and allows operators to quickly reduce the reactor inlet temperature in an emergency.

[0035] From the reactor furnace, the flow is directed to the oil, kerosene, diesel oil HDT reactor (NKD HDT). The NKD HDT reactor operates for HDS and HDN together with olefin saturation at somewhat lower LHSV and higher temperatures. Here, the oil feed is hydrotreated and partially converted to products. The exothermic HDS, HDN and saturation reactions release a large amount of heat, which increases the temperature of the reactants. This increased temperature in turn increases the reaction rate. To control this temperature increase and at the same time the reaction rate, the catalyst may be distributed in several layers in the NKD HDT reactor. To quench the reaction of the reacting fluids, a cold recycle gas may be introduced between the layers, thus controlling the temperature increase and the reaction rate.

[0036] In a parallel circuit, the crude gas oil stream is directed through a feed filter and a 1 micron cone filter and then pumped up the reactor loop under pressure by feed pumps. The filtered fresh oil feed is mixed with preheated hydrogen-rich recycle gas, which has been preheated in a feed/exhaust exchanger, and is passed through a gas oil upstream capture reactor (gas oil UFR) where metal contaminants are removed. The gas oil UFR exhaust products are further heated in a second feed-exhaust exchanger and then in the reactor feed furnace. The reactor feed furnace inlet temperature can be controlled by setting an oil feed bypass around the feed-exhaust exchangers to maintain a sufficiently heated inlet section in the furnace. Maintaining such a heated inlet in the furnace provides stable reactor inlet temperature control and allows operators to quickly reduce the reactor inlet temperature in an emergency.

[0037] From the reactor furnace, the stream is directed to the gas oil HDT reactor (gas oil HDT). Here, the oil feed is hydrotreated and partially converted into products. The exothermic hydrocracking and saturation reactions release a large amount of heat, which increases the temperature of the reactants. This increased temperature in turn increases the reaction rate. To control this temperature increase and at the same time the reaction rate, the catalyst in the gas oil HDT reactor is distributed in several layers. To quench the reaction of the reacting fluids, cold recycle gas can be introduced between the layers, thus controlling the temperature increase and the reaction rate.

[0038] The reactor interior between the catalyst beds can also be designed to ensure thorough mixing of the reactants with the quench gas and good distribution of the vapor and the flow of the liquid down to the next bed. Good distribution of the reactants between the catalyst beds prevents the occurrence of local overheating and maximizes the performance and life of the catalyst. For example, the ISOMIX system offered by Chevron Lummus Global can be used to achieve complete mixing and equilibration of the reactants between the catalyst beds, correcting for any temperature and concentration misdistributions with a small pressure drop while using minimal reactor volume. ISOMIX allows the successful use of new, highly active catalysts in new and retrofit reactors without the risk of very low reactor temperature misdistribution and local overheating often associated with highly active catalysts.

[0039] The gas oil HDT reactor effluent contains light evaporated hydrocarbons, distillate oils, heavy unconverted oil, and excess hydrogen not consumed in the reaction. The effluent stream is cooled in a heat exchanger with the oil-gas reactor feed mixture before being passed through a cascade of separators.

[0040] The effluents from both the NKD HGT and the gas oil HDT reactors are cooled by exchanging heat with their respective feedstocks and are introduced separately into parallel hot high pressure separators (HHPS). The vapor streams from the respective HHPSs are combined and cooled by exchanging heat with the reactor feedstock and the cold low pressure separator (CLPS) fluid. At this point, water may be continuously sprayed into the inlet piping of the HHPS vapor air cooler to prevent salt deposits in the air cooler tubes. Without water injection, ammonia (NH3) and hydrogen sulfide (H2S), which are produced in the reactor feedstock by hydrodesulfurization of sulfur species and hydrodenitrification of nitrogen species, can form solid ammonium bisulfide (NH4HS) at cooling temperatures. This solid can deposit on the air cooler tubes, reducing heat transfer and ultimately clogging the tubes. Since ammonium bisulfide is water soluble, the NH4HS formed is continuously dissolved in the surrounding water and the deposition of NH4HS solids in the air cooler pipes is prevented. Both the water injection piping and the air cooler inlet piping must satisfy certain conditions to ensure uniform water distribution for the exhaust air cooler. This assembly is designed to divert the condensate from the upstream fractionator for reuse.

[0041] In the HHPS off-gas vapor air cooler, off-gas vapor is cooled to maximize recovery of hydrocarbon liquids. The cooled off-gas is separated into its hydrogen-rich vapor, hydrocarbon liquid, and water phases. The sulfur-rich water stream containing ammonium bisulfite is directed to the sulfur-rich water evaporator. The hydrocarbon liquid is fed to the CLPS.

[0042] The hydrogen-rich gas from the CHPS flows into the liquid separator drum before entering the H2S absorber. Due to the extremely high H2S concentration, a high-pressure amine absorber can be used to maintain the quality of the recycle gas. To ensure the required hydrogen partial pressure, the operating pressure of the high-pressure circuit can be significantly reduced by using an amine absorber, increasing the purity of the recycle gas. This can be beneficial for the separation of aromatic compounds and facilitates the use of lower reactor temperatures.

[0043] The sulfur-free gas then flows into the liquid separator drum and then into the recycle gas compressor. The compressor suction line is regulated by heating, ensuring liquid-free vapor. From the recycle compressor, the recycle gas is discharged into the reactor circuit. There is an outlet pipe located upstream of the recycle gas compressor, which can be used to direct the amine sulfur-free recycle gas to the outlet pipe if necessary. However, in normal operation, there is no need for a purge with high-pressure gas. An emergency outlet pipe may be installed upstream of the recycle gas compressor, which ensures a rapid pressure drop in the recycle circuit if necessary in the event of a breakdown of the recycle compressor or other disturbances to control the temperature.

[0044] A portion of the gas discharged from the recycle compressor is fed to the reactors as a quench to control the reactor temperature. The remaining portion of the recycle gas, not used as a quench, is combined with the collected hydrogen to provide the reactor feed gas. Reliable, uninterrupted operation of the recycle compressor can contribute to the safe operation of the entire plant. One type of reliable recycle compressor is a steam turbine-driven centrifuge. Before being combined with the oil feed streams for each reaction stage, the reactor feed gas in both stages is heated by heat exchange with the HHPS steam.

[0045] The process requires a continuous supply of high-pressure hydrogen. In addition to chemical consumption, hydrogen leaves the system as spent gas from the cold low pressure separator (CLPS), as dissolved hydrogen in the distilled feedstock, and may also escape from system leaks.

[0046] In the high pressure circuit, the liquid stream from the HHPS is depressurized and directed to the hot low pressure separator (HLPS). The liquid gas oil from the HLPS is directed directly to the product evaporator and the vapor stream is directed to the air cooler and then to the gas oil low pressure separator (CLPS). In the gas oil CLPS, the liquid is separated from the vapor and heated in a heat exchanger with the gas oil HHPS vapor, then combined with the liquid from the NKD HHPS and fed to the NKD HLPS. The sulfur-rich gas from the gas oil CLPS and the NKD HLPS can be directed to further processing and hydrogen recovery. The liquid from the NKD HLPS is pumped up the oil/kerosene/diesel/aromatic saturation (NKD ASAT) reactor loop by a feed pump. This is a preheated feed/exhaust gas exchanger, mixed with preheated hydrogen-rich recycle gas. The mixture is further heated relative to the NKD exhaust gas and fed to the NKD ASAT reactor.

[0047] The preheated stream enters the NKD ASAT reactor. The catalyst in this reactor promotes saturation of aromatics and further hydrodesulfurization. Cold recycle gas is introduced between the beds to suppress inter-fluid reactions and thus control the extent of reaction temperature rise and reaction rate.

[0048] The effluent from both NKD ASAT reactors is cooled by heat exchange with the NKD ASAT reactor feed, hydrogen-rich recycle gas and NKD vaporized feed and then passed through the effluent air cooler. At this point, water is continuously sprayed into the NKD ASAT reactor effluent air cooler piping to prevent salt deposits in the air cooler piping.

[0049] In the NKD ASAT reactor exhaust air cooler, the exhaust is cooled from the vapor to maximize the recovery of hydrocarbon liquids. The cooled exhaust is separated into its hydrogen-rich vapor, hydrocarbon liquid, and water phases in the NKD CHPS. The vapor is combined with gas oil CHPS vapor and is directed to a liquid separator drum before entering the H2S absorber. The sulfur-rich water stream containing ammonium bisulfite is directed to the sulfur-rich water evaporator. The hydrocarbon liquid is fed to the NKD CLPS.

[0050] In the NKD CLPS, the liquid is separated from the vapor and heated by heat exchange with the exhaust product of the NKD ASAT reactor before being directed to the NKD product evaporator. The sulfur-rich gas from the NKD CLPS is directed for further processing and hydrogen regeneration.

[0051] When processing synthetic feedstock, the entire aromatics saturation stage can be omitted and the hydrogen and product regeneration sections can be combined.

[0052] The fractionation section may include a gas oil product evaporator, a naphtha/kerosene/diesel oil product evaporator, and a product fractionator. The fractionation section may be configured to separate the reaction products into light end products such as LPG, naphtha, kerosene, diesel oil, and processed gas oil.

[0053] The primary function of the product evaporator is to separate light products at sufficient pressure to feed them to the deethanizer column in the light end product regeneration section without the need for a sulfur-rich gas compressor.

[0054] After hydrogen gas purification, the remaining reactor liquid effluent is directed to the product evaporator. The product evaporator removes gas, propane, butane, and some unstable oil from the reactor effluent for processing in the light end product recovery section. The heavier products from the gas oil product evaporator are then directed to the bottom of the treated gas oil residue. The heavier products from the oil/kerosene/diesel product evaporator, a combination of treated oil, jet fuel, and diesel oil, are directed from the bottom to the fractionator feed furnace for heating prior to entering the fractionator, which operates at low pressure.

[0055] The unstable oil from the product evaporator is allowed to run back and is evaporated together with the superheated stream. The water from the product evaporator cannot be recycled to the spray water system due to the high concentration of ammonium bisulfite.

[0056] In the fractionator system, the effluent from the NKD ASAT reactor is separated into oil, kerosene and diesel oil. Excess vapor from the fractionator is condensed in a general condenser and directed to the accumulator at the top. A certain amount of liquid is directed back to the fractionator in the reflux. A steam pipe is added to the system extending from the top of the accumulator to the bottom to prevent any vapor from forming. The liquid end product of the accumulator is oil, which is directed to the light end product regeneration section. Water from the top accumulator is directed to the water spray drum in the reaction section.

[0057] The fractionator is equipped with trays for separating oil and kerosene and kerosene and diesel oil. Liquid is drawn from the fractionator and sent to the kerosene side fraction evaporator. The overhead vapor is sent back to the fractionator. The bottom stream of the evaporator is pumped by the kerosene product pump and then cooled. The cooled product is sent to a tank. The bottom streams of the fractionator are pumped by the fractionator bottom pump to the preheated heat exchanger of the fractionator feed product and, after cooling, are sent to the tank.

[0058] As described above, catalysts may be added to each reactor for performing various hydrotreating operations, including hydrogenation (diolefin saturation, monoolefin saturation, and/or aromatic saturation), hydrodeoxygenation, hydrodemetallization, hydrodenitrogenation, hydrocracking, hydrodesulfurization, and hydrotreating. For example, the hydrotreating catalyst may be any catalyst composition that can be used to catalyze the hydrogenation of a hydrocarbon feedstock to increase its hydrogen content and/or remove heteroatom contaminants. For example, the hydrocracking catalyst may be any catalyst composition that can be used to catalyze the addition of hydrogen to large or complex hydrocarbon molecules, as well as to catalyze the cracking of molecules to produce smaller, lower molecular weight molecules.

[0059] Hydrotreating catalyst compositions for use in the processes of the embodiments disclosed herein are well known to those skilled in the art and are commercially available from W.R. Grace & Co., Criterion Catalysts & Technologies, and Albermarle, among others. Suitable hydroconversion catalysts may include one or more elements selected from groups 4-12 of the periodic table of elements. In some embodiments, hydroconversion catalysts of the embodiments disclosed herein may be, consist of, or consist essentially of one or more of nickel, cobalt, tungsten, molybdenum, and combinations thereof, either unsupported or supported on a porous substrate such as silica, alumina, titania, or combinations thereof. As supplied by the manufacturer or as a result of a regeneration process, hydroconversion catalysts may be in the form of metal oxides, metal hydrides, or metal sulfides, for example. In some embodiments, the catalysts may be presulfided and/or preconditioned prior to their introduction into the reactor(s).

[0060] Hydrotreating and hydrogenation catalysts that may be used include catalysts that generally comprise a hydrogenation component selected from Group 6 elements (such as molybdenum and/or tungsten) and Group 8-10 elements (such as cobalt and/or nickel) or mixtures thereof, which may be supported on an alumina support. Phosphorus (Group 15) oxide is optionally added as an active ingredient. A typical catalyst may contain from 3 to 35% by weight of the hydrogenation components in combination with an alumina binder. The catalyst pellets may range in size from 1/32 inch to 1/8 inch and may be spherical, extruded, tri-pronged or tetra-pronged. The catalyst layer(s) for demetallization, if present, may comprise catalyst(s) having an average pore size of 125 to 225 angstroms and a pore volume of 0.5 to 1.1 cm3/g. The catalyst layer(s) for denitrogenation/desulfurization may comprise catalyst(s) having an average pore size of 100 to 190 angstroms and a pore volume of 0.5 to 1.1 cm3/g. U.S. Patent No. 4,990,243 describes a hydrotreating catalyst having a pore size of at least about 60 angstroms and preferably from about 75 angstroms to about 120 angstroms. A demetallization catalyst useful in the present invention is described, for example, in U.S. Patent No. 4,976,848, the disclosure of which is hereby incorporated by reference in its entirety for all purposes. Similarly, catalysts useful for the desulfurization of heavy streams are described, for example, in U.S. Patent Nos. 5,215,955 and 5,177,047, the disclosure of which is hereby incorporated by reference in its entirety for all purposes. Catalysts useful for the desulfurization of middle distillate, vacuum gas oil streams, and petroleum streams are described, for example, in U.S. Patent No. 4,990,243, the disclosure of which is hereby incorporated by reference in its entirety for all purposes.

[0061] Reactors for hydrogenating light distillate fractions, such as reactors 18 and 218, can operate under reaction conditions such as a temperature in the range of about 100°C to about 250°C, a hydrogen partial pressure in the range of about 27.6 to about 34.5 bar, and a liquid hourly space velocity in the range of about 2 to about 61 liters per hour of catalyst.

[0062] Reactors for hydrodemetallizing light distillate fractions, such as reactors 22 and 222, may be operated under reaction conditions such as a temperature in the range of about 200°C to about 440°C, a hydrogen partial pressure in the range of about 27.6 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.5 to about 5.0 liters per hour of catalyst.

[0063] Reactors for hydrotreating light distillate fractions (HDN, HDS, HDO, HDA, etc.), such as reactor 26, can operate at reaction conditions such as a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55.2 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.3 to about 4.0 liters per hour of catalyst.

[0064] Reactors for hydrodemetallization of gas oil fractions, such as reactors 30, 226, can operate under reaction conditions such as a temperature in the range of about 200°C to about 440°C, a hydrogen partial pressure in the range of about 27.6 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.5 to about 5.0 liters per hour of catalyst.

[0065] Reactors for hydrotreating gas oil fractions (HDN, HDS, HDO, HDA, etc.), such as reactors 34, 230, can operate at reaction conditions such as a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55.2 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.3 to about 4.0 liters per hour of catalyst.

[0066] Reactors for hydrotreating a mixture of light distillate and heavy distillate fractions (HDN, HDS, HDO, HDA, etc.), such as reactor 223, can operate at reaction conditions such as a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55.2 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.3 to about 4.0 liters per hour of catalyst.

[0067] In reactor 18, where the diolefin saturation reactions (DOS) take place, the catalysts used are designed for double bond saturation and low heteroatom removal (HDN, HDS, HDO, HDA) is achieved. The diolefin saturation ranges from about 90% to about 100%.

[0068] In reactors where hydrodemetallization reactions occur, HDN removal ranges from about less than 1% to about 15%. HDS removal ranges from about less than 1% to about 15%. HDO removal ranges from about 10% to about 50%. HDM removal ranges from about 70% to about 100%. These include reactors 22, 30.

[0069] In reactors where hydrotreating reactions occur, HDN removal ranges from about 40% to about 100%. HDS removal ranges from about 40% to about 100%. HDO removal ranges from about 80% to about 100%. HDM removal ranges from about 30% to about 100%. These include reactors 26, 34.

[0070] The processes as described with reference to FIGS. 1 and 2 may include additional hydrocarbon feedstocks in addition to the shale crude oil. For example, one or more additional hydrocarbon feedstocks may be fed to fractionator 12, 212. The one or more additional hydrocarbon feedstocks may be hydrocarbon materials derived from thermal tars, bitumen, coke oven tars, asphaltenes, coal gasification tars, biomass derived tars, black liquor tars, or reactive hydrocarbon materials derived from thermal tars, bitumen, coke oven tars, asphaltenes, coal gasification tars, biomass derived tars, black liquor tars, produced by one or more thermal cracking, pyrolysis, and steaming processes. As another example, one or more additional hydrocarbon feedstocks may be fed to hydrotreating reactors 30, 226.

[0071] Referring now to FIG. 3, there is illustrated a simplified flow diagram of an integrated process for enriching oil shale crudes produced by cracking oil shale, in accordance with embodiments. Oil shale crude 310 and hydrogen 311 may be contacted in a first stage hydrotreating reactor 312 containing hydrogenation catalysts to saturate the diolefins contained in the oil shale crude. Following hydrogenation, effluents 314 may be collected from the first stage hydrotreating reactor 312.

[0072] The effluent 314 from the first stage hydrotreating reactor 312 may be fed without phase separation to a second stage hydrotreating reactor 316, which may be operated in an upstream mode and which contains catalysts for hydrodemetallization and saturation of monoolefins in the effluent 314 collected from the first stage hydrotreating reactor 312. Following hydrotreating, effluent 318 may be collected from the second stage hydrotreating reactor 316.

[0073] The effluent 318 may then be fed to a fractionation system 320 to separate the effluent 318 into a first partially hydrotreated fraction 322, comprising oil, kerosene, and diesel oil, and a second partially hydrotreated fraction 324, comprising gas oil and residues.

[0074] The first partially hydrotreated fraction 322 may then be fed to a third stage hydrotreating reactor 326, which includes one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation, and aromatic saturation of the first partially hydrotreated fraction 322. Following hydrotreating, effluents 328 may be collected from the third stage hydrotreating reactor 326.

[0075] The second partially hydrotreated fraction 324 may also be fed to a fourth stage hydrotreating reactor 330, which includes one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation, and aromatic saturation of the second partially hydrotreated fraction 324. Following hydrotreating, effluents 332 may be collected from the fourth stage hydrotreating reactor 330.

[0076] Unreacted hydrogen may be collected from the top of the fractionation system 320 along with the first partially hydrotreated fraction 322. If necessary, additional hydrogen may be fed via flow line 323 to a third stage reactor 326 for hydrotreatment. Similarly, dissolved hydrogen may be contained in the second partially hydrotreated fraction 324. If necessary, additional hydrogen may be fed via flow line 325 to a fourth stage reactor 330 for hydrotreatment.

[0077] The effluents 328, 332 from the third and fourth stage hydrotreating reactors 326, 330, respectively, may then be fed to a separation line 334 for separation and collection of two or more hydrocarbon fractions. Separation line 334 may include one or more distillation and/or extractive distillation columns for separation of the effluents into two or more hydrocarbon fractions. In some embodiments, such as the embodiment illustrated in FIG. 3 , the two or more fractions may include at least one light gas co-product and unreacted hydrogen 342, kerosene 344, diesel oil 346, and a residual fraction 348. In various embodiments, other hydrocarbon fractions may also be collected.

[0078] Referring now to FIG. 4, there is illustrated a simplified flow diagram of an integrated process for enriching oil shale crudes produced by cracking oil shale, in accordance with embodiments. Oil shale crude 410 and hydrogen 411 may be contacted in a first stage hydrotreating reactor 412 containing hydrogenation catalysts to saturate the diolefins contained in the oil shale crude. Following hydrogenation, effluents 414 may be collected from the first stage hydrotreating reactor 412.

[0079] The effluent 414 from the first stage hydrotreating reactor 412 may be fed without phase separation to a second stage hydrotreating reactor 416, which may be operated in an upstream mode and which contains catalysts for hydrodemetallization and saturation of monoolefins in the effluent 414 collected from the first stage hydrotreating reactor 412. Following hydrotreating, effluent 418 may be collected from the second stage hydrotreating reactor 416.

[0080] The effluent 418 may then be fed to a fractionation system 420 to separate the effluent 418 into a first partially hydrotreated fraction 422, comprising oil, kerosene, and diesel oil, and a second partially hydrotreated fraction 424, comprising gas oil and residues.

[0081] The second partially hydrotreated fraction 424 may then be fed to a tertiary hydrotreating reactor 430, which includes one or more catalyst beds for hydrodenitrogenating, hydrodesulfurizing, hydrodeoxygenating, and aromatics saturating the second partially hydrotreated fraction 424. Following hydrotreating, effluents 432 may be collected from the tertiary hydrotreating reactor 430.

[0082] The first partially hydrotreated fraction 422 and the effluent 432 may then be fed to a fourth stage hydrotreating reactor 426, which includes one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation, and aromatic saturation of the first partially hydrotreated fraction 422 and the effluent 432. Following hydrotreating, effluent 428 may be collected from the fourth stage hydrotreating reactor 426.

[0083] Unreacted hydrogen may be collected from the top of fractionation system 420 along with the first partially hydrotreated fraction 422. If necessary, additional hydrogen may be fed via flow line 423 to a fourth stage reactor 426 for hydrotreatment. Similarly, dissolved hydrogen may be contained in a second partially hydrotreated fraction 424. If necessary, additional hydrogen may be fed via flow line 425 to a third stage reactor 430 for hydrotreatment.

[0084] The effluent 428 from the fourth stage hydrotreating reactor 426 may then be fed to a separation line 434 for separation and collection of two or more hydrocarbon fractions. Separation line 434 may include one or more distillation and/or extractive distillation columns for separation of the effluent into two or more hydrocarbon fractions. In some embodiments, such as the embodiment illustrated in FIG. 4 , the two or more fractions may include at least one light gas co-product and unreacted hydrogen 442, kerosene 444, diesel oil 446, and a residual fraction 448. In various embodiments, other hydrocarbon fractions may also be collected. [0085] Referring now to FIG. 5 , there is illustrated a simplified flow diagram of an integrated process for enriching oil shale crude oils produced by cracking oil shale, in accordance with embodiments. Oil shale crude oil 510 and hydrogen 511 may be contacted in a first stage hydrotreating reactor 518 containing catalysts to saturate the diolefins contained in the oil shale crude oil. Following hydrogenation, effluents 514 may be collected from the first stage hydrotreating reactor 518.

[0086] The effluent 514 from the first stage hydrotreating reactor 518 may be fed without phase separation to a second stage hydrotreating reactor 522, which may be operated in an upstream mode and which contains catalysts for hydrodemetallization and saturation of monoolefins in the effluent 514 collected from the first stage hydrotreating reactor 522. Additional hydrogen 515 may be added if necessary. Following hydrotreating, effluent 524 may be collected from the second stage hydrotreating reactor 522.

[0087] The effluent 524 from the second stage hydrotreating reactor 522 may be fed, with or without phase separation, to a third stage hydrotreating reactor 526, which includes one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation, and aromatic saturation of the effluent from the second stage hydrotreating reactor 522. Following hydrotreating, effluent 528 may be collected from the third stage hydrotreating reactor 526.

[0088] The effluent 528 from the tertiary hydrotreating reactor 526 may then be fed to a separation line 538. The separation line 538 may include one or more distillation and/or extractive distillation columns for separating the effluent into two or more hydrocarbon fractions. In some embodiments, such as the embodiment illustrated in FIG. 5 , the separation line 538 may include an atmospheric distillation column 539 and a vacuum distillation column 540 for separating the effluent 528 into distillate fractions comprising a light gas fraction 542, a naphtha 544, a kerosene, jet fuel and diesel oil fraction 546, as well as a hydrotreated gas oil fraction 548 and a low sulfur fuel oil fraction 550.

[0089] The hydrotreated vacuum gas oil fraction 548 and hydrogen 549 may then be fed to a fourth stage hydrotreating reactor 534, which may include one or more catalyst beds to effect hydrocracking of the hydrotreated vacuum gas oil fraction. Following the hydrocracking or from the fourth stage hydrotreating reactor 534, a effluent 536 is collected. The effluent 536 from the fourth stage hydrotreating reactor 534 may then be fed to a separation line 538 for separation as described above.

[0090] The processing of oil through the reactors illustrated in FIG. 5 may be carried out in a continuous mode. Similar to reactors 222, 226, reactor 522 may require more frequent catalyst changes than reactors 518, 526, 534. To change the catalyst in the reactor while continuing to perform the remainder of the process, a bypass line 555 may be used to bypass the second stage reactor 522.

[0091] In the embodiment illustrated in FIG. 5, oil shale oil is first fed to reactors 518, 522, and 526 to achieve nearly complete demetallization, hydrodenitrogenation, hydrodesulfurization, and some aromatic saturation. Limited hydrocracking may also occur. After product separation, vacuum gas oil fraction 548 may be hydrocracked to final products, yielding about 60% conversion per pass. In addition, the unconverted oil collected from the bottom of the vacuum column is an excellent quality FCC feed.

[0092] In the process illustrated in Fig. 5, as well as in other embodiments herein, the first stage reactor may be enhanced to accommodate feedstock variations, to provide high quality FCC feedstocks, and to provide continuous feed to the hydrocracking reactor 534, providing, among other advantages, high quality middle distillates and extended catalyst life.

[0093] Thus, Figures 3, 4 and 5 illustrate an alternative flow diagram for the enrichment of heavy and light components of crude oil from oil shale by hydrotreating. The catalysts used in the description relating to Figures 3-5 are similar to those described in connection with Figures 1 and 2.

[0094] Reactors for hydrodemetallization of a crude oil fraction from shale, such as reactors 316, 416, and 522, may be operated at reaction conditions such as a temperature in the range of about 200°C to about 400°C, a hydrogen partial pressure in the range of about 27.6 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.5 to about 5.0 liters per hour of catalyst.

[0095] Reactors for hydrotreating light distillate fractions (HDN, HDS, HDO, ASAT, etc.), such as reactor 326, can operate at reaction conditions such as a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55.2 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.3 to about 4.0 liters per hour of catalyst.

[0096] Reactors for hydrotreating light and heavy distillate (HDN, HDS, HDO, ASAT, etc.), such as reactors 426 and 526, can operate at reaction conditions such as a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55.2 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.3 to about 4.01 liters per hour of catalyst.

[0097] Reactors for hydrotreating heavy distillate fractions (HDN, HDS, HDO, ASAT, etc.), such as reactors 330, 430, can operate at reaction conditions such as a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55.2 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.3 to about 4.0 liters per hour of catalyst.

[0098] In reactors where diolefin saturation reactions (DOS) take place, the catalysts used are designed for double bond saturation and low heteroatom removal (HDN, HDS, HDO, ASAT) is achieved. Diolefin saturation ranges from about 90% to about 100%. These are reactors 312, 412, 518.

[0099] In reactors where hydrodemetallization reactions occur, HDN removal ranges from about less than 1% to about 15%. HDS removal ranges from about less than 1% to about 15%. HDO removal ranges from about 10% to about 50%. HDM removal ranges from about 70% to about 100%. These include reactors 226, 316, 416, 522.

[00100] In reactors where hydrotreating reactions occur, HDN removal ranges from about 40% to about 100%. HDS removal ranges from about 40% to about 100%. HDO removal ranges from about 80% to about 100%. HDM removal ranges from about 30% to about 100%. These include reactors 230, 234, 326, 426, 526.

[00101] In reactor 526, where hydrocracking of the partially hydrotreated gas oil fraction occurs, the conversion per pass may range from about 40% to about 70%.

[00102] The processes as described with reference to FIGS. 3-5 may include additional hydrocarbon feedstocks in addition to the shale crude oil. For example, one or more additional hydrocarbon feedstocks may be fed to reactors 312, 412. The one or more additional hydrocarbon feedstocks may be hydrocarbon materials derived from thermal tars, bitumen, coke oven tars, asphaltenes, coal gasification tars, biomass derived tars, black liquor tars, or reactive hydrocarbon materials derived from thermal tars, bitumen, coke oven tars, asphaltenes, coal gasification tars, biomass derived tars, black liquor tars, produced by one or more thermal cracking, pyrolysis, and steaming processes. As another example, one or more additional hydrocarbon feedstocks may be fed to hydrotreating reactors 330, 430, or 534.

[00103] As described above, a divergent flow processing scheme for the enrichment of crude oil from oil shale is disclosed herein. The divergent flow concept described herein, i.e., where the hydroprocessing of oil and kerosene is carried out in one or more stages and the hydroprocessing of gas oil is carried out in one or more stages, requires additional equipment compared to alternative approaches to hydroprocessing of oil shale. Contrary to the popular belief that it requires a larger capital investment to achieve the same end product list, the operational efficiency, time efficiency, and product quality of the divergent flow concept far outweigh the somewhat higher equipment costs.

[00104] As noted above, the embodiments disclosed herein address the disadvantages inherent in alternative shale oil hydrotreating. Furthermore, the divergent processing embodiments disclosed herein optimize catalyst utilization, product yields, and hydrogen consumption. These advantages directly translate into lower capital investment, increased profitability, and reduced labor costs. The disclosed embodiments avoid a number of problems inherent in prior art shale oil hydrotreating solutions, including: inhibition of heavy oil hydrocracking (either directly or by reducing hydrogen partial pressure); cracking out of some desired products (diesel oil) because the conditions for crude oil hydrotreating are much more stringent than those for diesel oil hydrotreating; increased hydrogen consumption due to excessive hydrocracking and supersaturation of heavy oils; and inhibition of diesel oil hydrotreating function due to the presence of very large molecules from heavy oil streams. This aspect becomes very important when producing ULSD (ultra-low sulfur diesel).

[00105] While the description of the invention includes a limited number of embodiments, it will be apparent to one skilled in the art from this description that other embodiments may be added without departing from the scope of the present invention. Therefore, the scope of the invention is determined solely by the appended claims.

Claims (26)

1. An integrated process for the enrichment of crude oil from oil shale obtained by cracking oil shale, in situ extraction, or mixtures thereof, the process comprising the following steps: (a) fractionating crude oil from oil shale into a first fraction containing naphtha, kerosene, and diesel oil and, at atmospheric pressure, into a bottom fraction containing gas oil and residue; (b) contacting the first fraction with hydrogen in a first-stage hydrotreating reactor comprising a hydrogenation catalyst for saturating diolefins contained in the first fraction and collecting the effluent from the first-stage hydrotreating reactor; (c) feeding the effluent from step (b) from the first-stage hydrotreating reactor without phase separation to a second-stage hydrotreating reactor operating in an upstream mode and comprising catalysts for hydrodemetallization and saturating monoolefins in the effluent from the first-stage hydrotreating reactor and collecting the effluent from the second-stage hydrotreating reactor; (d) feeding the effluent from the second stage hydrotreating reactor of step (c) without phase separation to a third stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and aromatic saturation of the effluent from the second stage hydrotreating reactor and collecting the effluent from the third stage hydrotreating reactor; (e) feeding the bottom fraction and hydrogen at atmospheric pressure to a fourth stage hydrotreating reactor operating in an upflow mode and comprising catalysts for hydrodemetallization of the bottom fraction at atmospheric pressure and collecting the effluent from the fourth stage reactor; (f) feeding the effluent from the fourth stage hydrotreating reactor of step (e) without phase separation to a fifth stage hydrotreating reactor comprising one or more catalyst beds, each containing a catalyst for performing one or more hydrotreating and hydrocracking of the effluent from the fourth stage hydrotreating reactor (a), and collecting the effluent from the fifth stage hydrotreating reactor; (g) treating the effluent from the fifth stage hydrotreating reactor of step (f) and the effluent from the third stage hydrotreating reactor of step (d) in a separation line to regenerate two or more hydrocarbon fractions. 2. The process of claim 1, wherein the two or more hydrocarbon fractions recovered in step (g) comprise at least one of a petroleum fraction, a kerosene fraction, and a residual fraction. 3. The process according to claim 1, wherein the catalyst in the first stage reactor is an alumina-based pressed catalyst with nickel and molybdenum as active metals; the catalyst in the second stage reactor is an alumina-based spheroidal catalyst with nickel and molybdenum as active metals; the catalyst in the third stage reactor is a layered catalyst comprising a layer of an amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals and a pressed base metal catalyst layer comprising amorphous and zeolite components with nickel and tungsten as active metals; the catalyst in the fourth stage reactor is an alumina-based spheroidal catalyst with nickel and molybdenum as active metals; and the catalyst in the fifth stage reactor is an amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals. 4. The process of claim 1, further comprising operating the first stage hydrotreating reactor under reaction conditions comprising a temperature in the range of about 100°C to about 250°C, a hydrogen partial pressure in the range of about 27.5 to about 34.5 bar, and a liquid hourly space velocity in the range of about 2 to about 6 liters per hour per liter of catalyst; operating the second stage reactor under reaction conditions comprising a temperature in the range of about 200°C to about 440°C, a hydrogen partial pressure in the range of about 27.5 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.5 to about 5 liters per hour per liter of catalyst; operating the third stage reactor under reaction conditions comprising a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55 to about 179.3 bar, a liquid hourly space velocity in the range of about 0.3 to about 4.0 liters per hour per catalyst; operating the fourth stage reactor under reaction conditions comprising a temperature in the range of about 200°C to about 440°C, a hydrogen partial pressure in the range of about 27.5 to about 179.3 bar, a liquid hourly space velocity in the range of about 0.5 to about 5.01 liters per hour per catalyst; operating the fifth stage reactor under reaction conditions such as a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.3 to about 4.01 liters per hour of catalyst. 5. The process of claim 1, further comprising providing at least one bypass between the second stage hydrotreating reactor of step (c) and the fourth stage hydrotreating reactor of step (e) to allow catalyst replacement in the reactors while continuing to perform steps (a), (b), (d), (f) and (g). 6. The process of claim 1, further comprising feeding one or more additional hydrocarbon feedstocks to the fractionation step (a), wherein the one or more additional hydrocarbon feedstocks are former hydrocarbon materials derived from thermal tars, bitumen, coke oven tars, asphaltenes, coal gasification tars, biomass derived tars, black liquor tars. 7. The process of claim 1, further comprising feeding one or more additional hydrocarbon feedstocks to the fourth stage hydrotreating reactor of step (e), wherein the one or more additional hydrocarbon feedstocks are hydrocarbon materials derived from thermal tars, bitumen, coke oven tars, asphaltenes, coal gasification tars, biomass derived tars, black liquor tars. 8. An integrated process for the enrichment of crude oil from oil shale obtained by cracking oil shale, in situ extraction, or mixtures thereof, the process comprising the following steps: (a) fractionating crude oil from oil shale into a first fraction containing naphtha, kerosene, and diesel oil and, at atmospheric pressure, into a bottom fraction containing gas oil and residue; (b) feeding the first fraction and hydrogen to a first stage hydrotreating reactor comprising a hydrogenation catalyst for saturating the diolefins contained in the first fraction and collecting the effluent from the first stage hydrotreating reactor; (c) feeding the effluent from step (b) from the first stage hydrotreating reactor without phase separation to a second stage hydrotreating reactor operating in an upstream mode and comprising catalysts for hydrodemetallization and saturating monoolefins in the effluent from the first stage hydrotreating reactor and collecting the effluent from the second stage hydrotreating reactor; (d) feeding the bottoms fraction and hydrogen at atmospheric pressure to a third stage hydrotreating reactor operating in an upstream mode and containing catalysts for performing hydrodemetallization and collecting the effluent from the third stage reactor; (e) feeding the effluent from the third stage hydrotreating reactor of step (d) without phase separation to a fourth stage hydrotreating reactor containing one or more catalyst beds, each containing a catalyst for performing one or more hydrotreating and hydrocracking of the effluent from the third stage hydrotreating reactor and collecting the effluent from the fourth stage hydrotreating reactor; (f) feeding the effluent from the second stage hydrotreating reactor of step (c) and the fourth stage hydrotreating reactor of step (e) without phase separation to a fifth stage hydrotreating reactor (e) comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and aromatic saturation of the effluent from the second and fourth stage hydrotreating reactors and collecting the effluent from the fifth stage hydrotreating reactor; (g) treating the effluent from the fifth stage hydrotreating reactor of step (f) in a separation line to regenerate two or more hydrocarbon fractions. 9. The process of claim 8, wherein the two or more hydrocarbon fractions comprise at least one of a petroleum fraction, a kerosene fraction, and a residual fraction. 10. The process according to claim 8, wherein the catalyst in the first stage reactor is an alumina-based pressed catalyst with nickel and molybdenum as active metals; the catalyst in the second stage reactor is an alumina-based spheroidal catalyst with nickel and molybdenum as active metals; the catalyst in the third stage reactor is an alumina-based spheroidal catalyst with nickel and molybdenum as active metals; the catalyst in the fourth stage reactor is an amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals; and the catalyst in the fifth stage reactor is a layered catalyst comprising a layer of an amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals and a layer of a pressed base metal catalyst comprising amorphous and zeolite components with nickel and tungsten as active metals. 11. The process of claim 8, further comprising operating the first stage reactor under reaction conditions comprising a temperature in the range of about 100°C to about 250°C, a hydrogen partial pressure in the range of about 27.5 to about 34.5 bar, a liquid hourly space velocity in the range of about 2 to about 6 liters per hour per liter of catalyst; operating the second stage reactor under reaction conditions comprising a temperature in the range of about 200°C to about 400°C, a hydrogen partial pressure in the range of about 27.5 to about 179.3 bar, a liquid hourly space velocity in the range of about 0.5 to about 5.0 liters per hour per liter of catalyst; operating the third stage reactor under reaction conditions such that the temperature is in the range of about 280°C to about 440°C, the hydrogen partial pressure is in the range of about 55 to about 179.3 bar, the liquid hourly space velocity is in the range of about 0.3 to about 4.0 liters per hour per catalyst; operating the fourth stage reactor under reaction conditions such that the temperature is in the range of about 280°C to about 440°C, the hydrogen partial pressure is in the range of about 55 to about 179.3 bar, the liquid hourly space velocity is in the range of about 0.3 to about 4.0 liters per hour per catalyst; operating the fifth stage reactor under reaction conditions such as a temperature in the range of about 280°C to about 440°C, a hydrogen partial pressure in the range of about 55 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.3 to about 4.01 liters per hour of catalyst. 12. The process of claim 8, further comprising providing at least one bypass between the second stage hydrotreating reactor of step (c) and the fourth stage hydrotreating reactor of step (d) to allow catalyst replacement in the reactors while continuing to perform steps (a), (b), (e), (f) and (g). 13. The process of claim 8, further comprising feeding one or more additional hydrocarbon feedstocks to the fractionation step (a), wherein the one or more additional hydrocarbon feedstocks are former hydrocarbon materials derived from thermal tars, bitumen, coke oven tars, asphaltenes, coal gasification tars, biomass derived tars, black liquor tars. 14. The process of claim 8, further comprising feeding one or more additional hydrocarbon feedstocks to the tertiary hydrotreating reactor of step (d), wherein the one or more additional hydrocarbon feedstocks are hydrocarbon materials derived from thermal tars, bitumen, coke oven tars, asphaltenes, coal gasification tars, biomass derived tars, black liquor tars. 15. An integrated process for the enrichment of oil shale crude oils obtained by oil shale cracking, in situ extraction, or mixtures thereof, the process comprising the following steps: (a) contacting oil shale crude oil and hydrogen in a first stage hydrotreating reactor comprising a hydrogenation catalyst for saturating diolefins contained in the oil shale crude oil and collecting the effluent from the first stage hydrotreating reactor; (b) feeding the effluent from step (a) without phase separation to a second stage hydrotreating reactor operating in an upstream mode and comprising catalysts for hydrodemetallization and saturating monoolefins in the effluent from the first stage hydrotreating reactor and collecting the effluent from the second stage hydrotreating reactor; (c) fractionating the effluent from the second stage hydrotreating reactor of step (b) into a partially hydrotreated fraction comprising oil, kerosene and diesel oil and a partially treated bottoms fraction comprising gas oil and residue; (d) feeding the partially hydrotreated fraction to a third stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and hydrodearomatization of the partially hydrotreated fraction and collecting the effluent from the third stage hydrotreating reactor; (e) feeding the partially hydrotreated bottoms fraction to a fourth stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and hydrodearomatization of the partially hydrotreated bottoms fraction and collecting the effluent from the fourth stage hydrotreating reactor; (f) treating the effluent from the third stage hydrotreating reactor of step (d) and the fourth stage hydrotreating reactor of step (e) in a separation line to regenerate two or more hydrocarbon fractions. 16. The process of claim 15, wherein the two or more hydrocarbon fractions comprise at least one of a petroleum fraction, a kerosene fraction, and a residual fraction. 17. The process according to claim 15, wherein the catalyst in the first stage reactor is an alumina-based pressed catalyst with nickel and molybdenum as active metals; the catalyst in the second stage reactor is an alumina-based spheroidal catalyst with nickel and molybdenum as active metals; the catalyst in the third stage reactor is a layered catalyst comprising a layer of amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals and a pressed base metal catalyst layer comprising amorphous and zeolite components with nickel and tungsten as active metals; the catalyst in the fourth stage reactor is an amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals. 18. The process of claim 15, further comprising operating the first stage reactor under reaction conditions comprising a temperature in the range of about 100°C to about 250°C, a hydrogen partial pressure in the range of about 27.5 to about 34.5 bar, and a liquid hourly space velocity in the range of about 2 to about 6 liters per hour per liter of catalyst; operating the second stage reactor under reaction conditions comprising a temperature in the range of about 200°C to about 440°C, a hydrogen partial pressure in the range of about 27.5 to about 179.3 bar, and a liquid hourly space velocity in the range of about 0.5 to about 5 liters per hour per liter of catalyst; the third stage reactor is operated under reaction conditions such that the temperature is in the range of about 280°C to about 440°C, the hydrogen partial pressure is in the range of about 55 to about 179.3 bar, the liquid hourly space velocity is in the range of about 0.3 to about 4.0 liters per hour per catalyst; the fourth stage reactor is operated under reaction conditions such that the temperature is in the range of about 280°C to about 440°C, the hydrogen partial pressure is in the range of about 55 to about 179.3 bar, the liquid hourly space velocity is in the range of about 0.3 to about 4.0 liters per hour per catalyst. 19. An integrated process for the enrichment of oil shale crude oils obtained by oil shale cracking, in situ extraction, or mixtures thereof, the process comprising the following steps: (a) contacting oil shale crude oil and hydrogen in a first stage hydrotreating reactor comprising catalysts for saturating diolefins contained in the oil shale crude oil and collecting the effluent from the first stage hydrotreating reactor; (b) feeding the effluent from step (a) without phase separation to a second stage hydrotreating reactor operating in an upstream mode and comprising catalysts for hydrodemetallization and saturating monoolefins in the effluent from the first stage hydrotreating reactor and collecting the effluent from the second stage hydrotreating reactor; (c) fractionating the effluent from the second stage hydrotreating reactor of step (b) into a partially hydrotreated fraction comprising oil, kerosene and diesel oil and a partially hydrotreated bottom fraction comprising gas oil and residue; (d) feeding the partially hydrotreated bottom fraction to a third stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenating, hydrodesulfurizing, hydrodeoxygenating and saturating the partially hydrotreated bottom fraction (a) and collecting the effluent from the third stage hydrotreating reactor; (e) mixing the partially hydrotreated fraction and the effluent from the third stage hydrotreating reactor to form a mixture; (f) feeding the mixture to a fourth stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenating, hydrodesulfurizing, hydrodeoxygenating and saturating the aromatics and collecting the effluent from the fourth stage hydrotreating reactor; (g) treating the effluent from the fourth stage hydrotreating reactor in a separation line, recovering two or more hydrocarbon fractions. 20. The process of claim 19, wherein the two or more hydrocarbon fractions comprise at least one of a petroleum fraction, a kerosene fraction, and a residual fraction. 21. The process of claim 19, wherein the catalyst in the first stage reactor is an alumina-based pressed catalyst with nickel and molybdenum as active metals; the catalyst in the second stage reactor is an alumina-based spheroidal catalyst with nickel and molybdenum as active metals; the catalyst in the third stage reactor is an amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals; and the catalyst in the fourth stage reactor is a layered catalyst comprising a layer of amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals and a layer of pressed base metal catalyst comprising amorphous and zeolite components with nickel and tungsten as active metals. 22. The process of claim 19, further comprising operating the first stage reactor under reaction conditions comprising a temperature in the range of about 100°C to about 250°C, a hydrogen partial pressure in the range of about 27.5 to about 34.5 bar, a liquid hourly space velocity in the range of about 2 to about 6 liters per hour per liter of catalyst; operating the second stage reactor under reaction conditions comprising a temperature in the range of about 200°C to about 440°C, a hydrogen partial pressure in the range of about 27.5 to about 179.3 bar, a liquid hourly space velocity in the range of about 0.5 to about 5.0 liters per hour per liter of catalyst; the third stage reactor is operated under reaction conditions such that the temperature is in the range of about 280°C to about 440°C, the hydrogen partial pressure is in the range of about 55 to about 179.3 bar, the liquid hourly space velocity is in the range of about 0.3 to about 4.0 liters per hour per catalyst; the fourth stage reactor is operated under reaction conditions such that the temperature is in the range of about 280°C to about 440°C, the hydrogen partial pressure is in the range of about 55 to about 179.3 bar, the liquid hourly space velocity is in the range of about 0.3 to about 4.0 liters per hour per catalyst. 23. An integrated process for the enrichment of oil shale crude oils obtained by cracking oil shale, in situ extraction, or mixtures thereof, the process comprising the following steps: (a) contacting oil shale crude oil and hydrogen in a first stage hydrotreating reactor comprising catalysts for saturating diolefins contained in the oil shale crude oil and collecting the effluent from the first stage hydrotreating reactor; (b) feeding the effluent from step (a) without phase separation to a second stage hydrotreating reactor operating in an upstream mode and comprising catalysts for hydrodemetallization and saturating monoolefins in the effluent from the first stage hydrotreating reactor and collecting the effluent from the second stage hydrotreating reactor; (c) feeding the effluent from the second stage hydrotreating reactor of step (b) without phase separation to a third stage hydrotreating reactor comprising one or more catalyst beds for hydrodenitrogenation, hydrodesulfurization, hydrodeoxygenation and aromatic saturation of the effluent from the second stage hydrotreating reactor and collecting the effluent from the third stage hydrotreating reactor; (d) fractionating the effluent from the third stage hydrotreating reactor of step (c) into a partially hydrotreated fraction comprising naphtha, kerosene and diesel oil and a partially hydrotreated vacuum gas oil fraction. (e) feeding the partially hydrotreated vacuum gas oil fraction to a fourth stage hydrotreating reactor comprising one or more catalyst beds for hydrocracking the partially hydrotreated vacuum gas oil fraction and collecting the effluent from the fourth stage hydrotreating reactor; (f) feeding the effluent from the fourth stage hydrotreating reactor to fractionation step (d). 24. The process of claim 23, wherein the two or more hydrocarbon fractions comprise at least one of a petroleum fraction, a kerosene fraction, and a residual fraction. 25. The process of claim 23, wherein the catalyst in the first stage reactor is an alumina-based pressed catalyst with nickel and molybdenum as active metals; the catalyst in the second stage reactor is an alumina-based spheroidal catalyst with nickel and molybdenum as active metals; the catalyst in the third stage reactor comprises a layer of amorphous type II pressed base metal catalyst with an organic compound and nickel and molybdenum as active metals and a pressed base metal catalyst layer comprising amorphous and zeolite components with nickel and tungsten as active metals; and the catalyst in the fourth stage reactor comprises a pressed base metal catalyst comprising amorphous and zeolite components with nickel and tungsten as active metals. 26. The process of claim 23, further comprising operating the first stage reactor under reaction conditions comprising a temperature in the range of about 100°C to about 250°C, a hydrogen partial pressure in the range of about 27.5 to about 34.5 bar, a liquid hourly space velocity in the range of about 2 to about 6 liters per hour per liter of catalyst; operating the second stage reactor under reaction conditions comprising a temperature in the range of about 200°C to about 440°C, a hydrogen partial pressure in the range of about 27.5 to about 17.3 bar, a liquid hourly space velocity in the range of about 0.5 to about 5 liters per hour per liter of catalyst; operating the third stage reactor under reaction conditions such that the temperature is in the range of about 280°C to about 440°C, the hydrogen partial pressure is in the range of about 55 to about 179.3 bar, the liquid hourly space velocity is in the range of about 0.3 to about 4.0 liters per hour per catalyst; and operating the fourth stage reactor under reaction conditions such that the temperature is in the range of about 330°C to about 400°C, the hydrogen partial pressure is in the range of about 82.7 to about 179.3 bar, the liquid hourly space velocity is in the range of about 0.7 to about 1.5 liters per hour per catalyst.