Heavy oil upgrading process using hydrogen and water

Abstract

A method for upgrading heavy oil is provided, which integrates thermal cracking, hydrogenolysis, and catalytic aquathermolysis. A catalytic hydrogen-aquathermolysis reactor receives a heavy oil feed, water, and hydrogen. A catalytic material and a viscosity reducer are also introduced. The catalytic hydrogen-aquathermolysis reactor is operated under conditions effective to produce an upgraded heavy oil product.

Description

[0001] Related applications

[0002] This application claims priority to U.S. patent application No. 16 / 911,827, filed on June 25, 2020. Background Art Technical Field

[0003] The present invention relates to the thermal cracking of heavy oil feedstocks.

[0004] Description of Related Technology

[0005] Residues and heavy hydrocarbon oils contain heteroatoms, heavy aromatic molecules, and asphaltenes that adversely affect the ability to upgrade these materials. Asphaltenes are present in crude oils and their heavier fractions in varying amounts depending on various factors including, but not limited to, the source of the crude oil and the age of the producing wells.

[0006] Asphaltenes are brown to black powders rich in polynuclear aromatic compounds that are insoluble in normal paraffins. They contain heteroatoms such as nitrogen, sulfur, and oxygen and are soluble in carbon disulfide and aromatic solvents such as toluene and benzene. Their tendency to precipitate is determined by adding specific amounts of selected normal paraffins to heavy oil fractions.

[0007] Asphaltenes and polyaromatic compounds are present in the petroleum products discussed above and are produced in the oil mixture during any upgrading process. They are dispersed in the oil medium and solvated by alkyl appendages that are cross-linked with different substances present in the oil (including polyaromatic rings and cycloalkane clusters). During upgrading, thermal energy breaks the cross-linking bonds, which allows the asphaltene molecules to move freely in the oil medium. These free asphaltene molecules approach each other and combine to form larger aggregates. These aggregates associate with each other and form layers of aggregates through mechanisms including free radical recombination reactions and polar-polar interactions. These layers lead to coke formation and deposition during the heavy oil upgrading process.

[0008] Current state-of-the-art technologies for upgrading heavy oils include thermal cracking, delayed coking, hydrotreating followed by fluid catalytic cracking of residue, hydrocracking, catalytic steam reforming, slurry cracking, and aquathermal cracking. Prior art technologies are disclosed with reference to: Supercritical Water Process (SCW); (AQC); Super Oil Cracking (SOC) developed by Asahi, Nippon Mining Co. and Chiyoda Chemical Engineering and Construction Co., Ltd.; Eni Slurry Technology (EST) developed by Eni (Italy); and reference is made to U.S. Patent 5,885,441, U.S. Patent 3,240,718, U.S. Patent Application 2008 / 0099376, U.S. Patent Application 2009 / 0159498, U.S. Patent Application 2009 / 0166261; and disclosed in Fathi M., Pereira-Almao P. (2011) Catalytic Aquaprocessing of Arab Light Vacuum Residue via Short Space Times, Energy & Fuel, 25:4867-4877.

[0009] Despite the existence of prior art processes for upgrading heavy petroleum oils, there remains a need in the industry for alternative processes with improved efficiencies. Summary of the Invention

[0010] A heavy oil upgrading process is disclosed that integrates thermal cracking, hydrogenolysis, and catalytic aquathermolysis. The process operates under low to moderate operating conditions. The inclusion of small amounts of hydrogen, water, and highly dispersed catalytic particles in the heavy oil improves conversion and minimizes asphaltenes generation and aggregation. In addition, catalytic hydrogenation occurs due to the presence of hydrogen and moderate operating pressures.

[0011] This upgrading process combines thermal cracking, hydrogenolysis, and catalytic aquathermolysis in a single unit operation. The catalytic material is provided in the form of highly dispersed catalyst particles, and the operating conditions include relatively low pressures. This integration of thermal cracking, hydrogenolysis, and catalytic aquathermolysis represents an industrial advancement and provides enhanced commercial value by meeting fuel oil demand, increasing gains in oil output, improving refining economics, and improving heavy oil properties for subsequent upgrading or refining processes.

[0012] In a further embodiment, a solvent deasphalting process is integrated downstream of a combined thermal cracking, hydrogenolysis, and catalytic aquathermolysis unit operation.

[0013] The catalytic hydrogen-water thermal cracking process herein advantageously uses low-pressure hydrogen, water and catalytic particles (injected into the heavy hydrocarbon feed and / or otherwise closely mixed with the heavy hydrocarbon feed) to enhance the upgrading of heavy oil. The mixture is maintained at a relatively moderate pressure level and a relatively high temperature level. Coke and asphaltene production are reduced by improved water autolysis and catalytic cracking by free radical mechanisms. In addition, hydrogen addition promotes saturation of free hydrocarbon radicals (radicals) and inhibits hydrogen abstraction reactions. As described above, in certain embodiments, the upgraded heavy oil is subjected to solvent deasphalting, wherein at least a portion of the catalyst particles are removed with the asphalt phase. In addition, in certain embodiments, multiple upgrading cycles are employed to maximize heavy oil conversion and minimize by-products. BRIEF DESCRIPTION OF THE DRAWINGS

[0014] The disclosed process and system will be described in further detail below and with reference to the accompanying drawings, in which:

[0015] Figure 1 is a process flow diagram for a process incorporating a catalytic hydrogen aquathermolysis unit operation;

[0016] Figure 2 is a process flow diagram of a solvent deasphalting process for effectively separating asphaltenes and, in certain embodiments, spent catalyst materials from a catalytic hydroaquathermolysis effluent;

[0017] Figure 3 is a process flow diagram for an adsorption process for effectively removing asphaltenes, polynuclear heavy aromatic asphaltenes, and, in certain embodiments, spent catalyst material from a catalytic hydroaquathermolysis effluent;

[0018] Figure 4 is a process flow diagram for an adsorption-enhanced solvent deasphalting process that effectively separates asphaltenes and, in certain embodiments, spent catalyst material from a catalytic hydroaquathermolysis effluent; and

[0019] Figure 5 is a process flow diagram of another embodiment of an adsorption-enhanced solvent deasphalting process that effectively separates asphaltenes and, in certain embodiments, spent catalyst material from a catalytic hydroaquathermolysis effluent. DETAILED DESCRIPTION

[0020] There is a desire to find new economical processes and unit operations for upgrading heavy petroleum products such as atmospheric and / or vacuum residues. Furthermore, there is an incentive to utilize other low-value by-products of petroleum refining to produce valuable commodities that can be used as starting materials to generate energy or steam, or to be used in upgrading processes. In particular, it is desirable to implement processes that have low hydrogen requirements and in which refiners can utilize hydrogen from the refinery fuel gas (RFG) system.

[0021] This process involves upgrading heavy oils through the combined action of hydrogen and water in an aquathermolysis process in a single unit operation. In certain embodiments, this unit operation is followed by solvent deasphalting. The addition of hydrogen, water, and catalytic particles to the oil medium improves its conversion and minimizes the production and accumulation of asphaltenes. Furthermore, the presence of hydrogen and low to moderate operating pressures result in low-level catalytic hydrotreating.

[0022] Heavy oils are upgraded by the disclosed process and unit operations, which combine thermal cracking, hydrogenolysis, and catalytic aquathermolysis. The process is referred to herein as "catalytic hydrogen-aquathermolysis." Types of heavy oils that can benefit from the characteristics of catalytic hydrogen-aquathermolysis include atmospheric and / or vacuum resids containing asphaltenes, nitrogen, sulfur, and metal contaminants.

[0023] Catalytic hydrogen-aquathermolysis uses heat and a highly dispersed homogeneous catalyst along with steam and / or water, and a small amount of hydrogen (e.g., from RFG or other sources) to improve heavy oil conversion and suppress asphaltene and coke production while reducing asphaltene accumulation. This expands heavy oil upgrading and conversion opportunities because the stream can tolerate increased operational severity in downstream processes to improve conversion and production.

[0024] In another embodiment, the upgraded oil is treated with a light precipitant to allow the asphaltenes to precipitate, thereby reducing the concentration of catalyst remaining in the upgraded oil. Furthermore, the addition of the precipitant to the heavy oil significantly reduces its viscosity and thereby reduces its ability to retain catalytic particles, which enhances the separation of the catalytic particles under the influence of gravity.

[0025] In order to further remove asphaltenes and polynuclear heavy aromatic compounds, in certain embodiments, the deasphalted upgraded oil is subjected to a selective adsorption process to capture and retain the adsorbate. Adsorbent materials or mixtures of adsorbent materials that effectively capture heavy large polyaromatic compounds and asphaltenes include those characterized by high surface area, large pore volume and wide pore size distribution. The deasphalted upgraded oil is then transferred to atmospheric and vacuum distillation towers to separate light products. The heavy bottoms from the vacuum tower can be sent to a fuel depot fuel oil pool, partially or completely transferred to a gasification process, and / or returned to a catalytic hydrogen-water thermal cracking unit operation for additional upgrading cycles.

[0026] In the catalytic hydrogen-aquathermolysis unit operation described herein, the addition of hydrogen, water, and catalytic particles to the oil medium improves conversion to relatively lighter molecules and minimizes the production and accumulation of asphaltenes. In addition, due to the presence of hydrogen and moderate operating pressures, low catalytic hydroprocessing occurs, such as sulfur removal of up to about 50 W%, and nitrogen removal of up to about 30 W%.

[0027] The hydrogen-water thermal cracking reaction occurs by simultaneously cracking the molecular bonds between heavy oil molecules and their alkyl appendages by thermal energy to produce hydrocarbon radicals. A highly dispersed catalyst promotes the availability of hydrogen radicals to hydrogenate the generated hydrocarbon radicals and olefins (which are typical thermal cracking products).

[0028] Highly dispersed catalysts promote the addition of hydrogen to hydrocarbon radicals regardless of the source of the hydrogen. Highly dispersed catalytic particles have many advantages over supported catalyst matrices, including reduced diffusion control and improved efficient contact between water, oil, hydrogen, and catalyst particles.

[0029] The catalytic hydrogen-aquathermolysis process described herein reduces asphaltenes and minimizes coke formation during heavy oil upgrading by using a slurry-type catalyst, water, and a low-pressure hydrogen supply, such as from a refinery fuel gas (RFG) system or other source. The adsorbed and solvent-precipitated asphaltenes and heavy residue can be gasified in downstream processes to minimize or nearly eliminate by-product asphaltenes and residue, and in turn produce valuable products, hydrogen and electricity. In other embodiments in which an adsorbent material is used, such material having asphaltenes adsorbed therein or thereon can also be passed to the gasification step.

[0030] In certain embodiments, the highly dispersed submicron or nanometer-sized catalytic particles used in the catalytic hydrogen-water thermal cracking process do not require a carrier, which minimizes diffusion control compared to supported catalysts. The submicron or nanometer-sized catalyst size allows for higher dispersion, the availability of accessible active sites, and improved contact time, which allows for low catalyst concentrations. Utilizing submicron or nanometer-sized catalysts eliminates the possibility of establishing thermal gradients. In addition, the catalyst also promotes the addition of hydrogen to the thermal cracking oil free radicals, thereby reducing asphaltene and polycyclic aromatic compound free radical association and hydrogen abstraction reactions.

[0031] refer to Figure 1Shown is a process flow diagram for a catalytic hydrogen-water thermal cracking unit operation as described herein. A heavy feed stream 6, water and / or steam 8, and a catalytic material 10 are intimately mixed, for example, using an online mixing device and / or a separate mixing zone 14 to produce a mixture 16. In certain embodiments, a viscosity reducing agent stream 12 may be added. In certain embodiments, a surfactant and / or co-surfactant may also be added. In certain embodiments, a recycle stream 50 is also added. When the mixing zone 14 replaces the online mixing device or is used in combination with the series mixing device, the mixing zone 14 may be a high shear mixing unit such as a continuous stirred tank to produce an intimate mixture. In certain embodiments, one or more of an aqueous or oil-soluble catalytic metal precursor, a viscosity reducing agent, a surfactant, and a co-surfactant may be mixed with an oil feedstock. In certain embodiments, the mixing of the initial stream 6 and the catalytic material 10, and the optional viscosity reducing agent stream 12 and the optional surfactant and / or co-surfactant is carried out in the absence of added hydrogen.

[0032] The catalytic particles are submicron or nanometer sized catalyst particles that become highly dispersed in the mixture 16 due to in-line mixing and / or mixing zone 14. When a precursor is used, the in-line mixing device and / or separate mixing zone 14 effectively enhances catalyst mixing and dispersion and in-situ catalyst preparation. Mixing occurs at effective temperature and pressure levels, for example, in the range of about 40°C to 100°C, 50°C to 100°C, 40°C to 80°C, or 50°C to 80°C and exceeding about 1 bar, for example, in the range of about 1-30, 1-20, or 1-10 bar. The mixing conditions are selected to prevent or minimize evaporation of any added water or other optional components (such as viscosity reducers, surfactants, and co-surfactants).

[0033] The mixture 16 of the obtained heavy feed, water, highly dispersed catalytic particles and optional components (such as viscosity reducers, surfactants and co-surfactants) is heated, for example, in a loading heater 18, to provide a preheated mixture 20. Water is added via logistics 8 to minimize the formation of coke in the furnace 18. In certain embodiments, the mixture is preheated in the absence of added hydrogen. For example, the heater 18 can be operated under conditions that are effective as a catalyst preparation step to decompose the added catalyst to produce a catalytically active material, or to promote catalyst formation when a catalyst precursor is provided instead of a catalytically active material or in combination with a catalytically active material. In certain embodiments, the mixture is preheated to a suitable reaction temperature in the range of about 400-500°C, 400-460°C, 400-450°C, 435-500°C, 435-460°C or 435-450°C. In other embodiments, the mixture is preheated to a temperature below the reaction temperature, for example, below about 400° C., 390° C., 380° C., or 370° C., and in certain embodiments, in the range of about 350-400° C., 350-390° C., 350-380° C., or 350-370° C., and additional heating occurs in the reactor 36 or in a second heater 35 upstream of the reactor and downstream of the hydrogen and water / steam injection point 22. In certain embodiments, additional heating occurs in the reactor due to backmixing and the presence of hydrogen and its consumption to provide a near-isothermal reactor.

[0034] The preheated mixture 20 of heavy feed and highly dispersed catalyst particles is combined with hydrogen and water and / or steam. In certain embodiments, this stage of the reaction scheme is the first instance of hydrogen being added. Figure 1 , this is via a mixing valve at the hydrogen and water / steam injection site 22, however, other equipment may also be used to combine hydrogen with water and / or steam together or separately. The added hydrogen (logistics 24) may be obtained from a suitable source, such as a fuel gas stream containing hydrogen, including a low hydrogen partial pressure waste gas (off-gas) stream. Water and / or steam 32 is also combined with the hydrogen (e.g., via the mixing valve 22) or separately. The water and / or steam 32 may optionally be preheated using a heat exchanger 30, which heats the incoming water and / or steam 28 using a liquid effluent 42 from a catalytic hydrogen-water thermal cracking reactor 36 via a separator 38. Thus, for example, a mixture 34 is provided from the mixing valve 22, which may optionally be further preheated via a second heater 35 before being loaded into the reactor 36.

[0035] The catalytic hydrogen-water thermal cracking reactor 36 can be configured as a tubular reactor or a continuous stirred tank reactor. In the catalytic hydrogen-water thermal cracking reactor 36, thermal cracking occurs in the presence of hydrogen and water to upgrade the heavy oil. The mixed gas and liquid reactor effluent stream is sent to a vapor-liquid separator 38 to separate a light effluent stream 40 containing gas and light liquid from the upgraded heavy oil effluent 42. At least a portion of the stream 40 is recovered (stream 40a), and the stream 40a is sent to a light liquid product recovery unit (not shown). The unrecovered gas can be combined with the fuel gas stream 26, for example, to be included in a refinery fuel gas system (not shown). This stream can be used to obtain a low hydrogen partial pressure waste gas stream, which can be used as a source of hydrogen 24 for the catalytic hydrogen-water thermal cracking reactor 36.

[0036] The liquid product 42 from the catalytic hydrogen-water thermal cracking reactor 36 (or the cooled liquid product if the effluent is used as a heat exchange fluid) can be collected as a product, for example, in the fuel reservoir C fuel oil pool, or used as an upgraded feedstock in one or more different downstream processes. Figure 1 A fractionator unit 44 is shown (from which the separated streams may be conventionally processed), Figure 2 、 4 and 5 show the solvent deasphalting process, in Figure 3 , an adsorption unit is shown. In other embodiments (not shown), the downstream process for processing all or a portion of the liquid product 42 from the catalytic hydrogen-aquathermolysis reactor 36 may include a delayed coking process, full-scale catalytic hydroprocessing, gasification, or a combination of the foregoing uses or processes. In certain embodiments, a portion of the effluent from one or more of the downstream fractionator unit, adsorption unit, solvent deasphalting unit, delayed coking unit, or catalytic hydroprocessing unit may be recycled as a recycle stream 50, Figure 1 As used herein, stream 50 represents one or more of the recycle streams obtained from one or more of the aforementioned downstream processes, e.g. Figure 1Stream 48 in. In other embodiments, stream 50 may include all or a portion of the effluent from a process that processes liquid products from reactor 36, such as heavy products from delayed coking, a catalytic hydroprocessing unit such as a residue hydrotreating unit, an adsorption process, and / or solvent deasphalting (not shown). Recycle stream 50 may be charged directly with feed 6 to the in-line mixing device and / or mixing unit 14 as shown, and / or to one or more of mixing valve 22, charging heater 18, and / or reactor 36. Recycle stream 50 may be included in the range of about 0-50, 0-40, 0-30, 5-50, 5-40, 5-30, 10-50, 10-40, or 10-30 W % (based on the total weight of the feed to reactor 36).

[0037] In certain embodiments (by Figure 1 In a separation zone 44, liquid product 42 is fractionated to recover hydrocarbon products 46 and a bottoms stream 48. Hydrocarbon products, including, for example, naphtha, diesel, and vacuum gas oil, may be recovered, for example, with nominal boiling ranges of about 36-180° C., 180-370° C., and 370-520° C. (although those skilled in the art will appreciate that these ranges may vary), respectively, and sent to other processing units, such as a hydrotreating unit for refining and sulfur removal, before further processing. Bottom stream 48 may contain unconverted bottoms and have, for example, an initial boiling point in the range of about 450-565° C., 500-565° C., or 520-565° C., and an end point based on the characteristics of feed 6.

[0038] In certain embodiments, multiple upgrading cycles are employed to maximize heavy oil conversion and minimize byproducts. For example, to perform multiple upgrading cycles, bottoms stream 48 can be recycled by feeding feed 6 directly to an in-line mixing device and / or mixing unit 14, to a mixing valve 22, to a heater 18, and / or to a reactor 36, as follows. Figure 1 50, 50-70, 50-100, 50-90, 50-70, or 30-50 W%. In other embodiments, the bottoms 48 from the fractionation step may be processed by solvent deasphalting and / or adsorption as further described herein, or another type of processing unit such as a delayed coking process, residue hydroprocessing, and / or gasification, or integrated into an asphalt pond.

[0039] In order to form effective catalytic emulsion, in certain embodiments, one or more of aqueous or oil-soluble catalytic metal precursors, water, viscosity reducers based on aromatic compounds, surfactants and cosurfactants can be mixed with oil feedstock, for example, in mixing unit 14, mix.When homogeneous catalyst provides in the form of active submicron or nanometer-sized particles, and when homogeneous catalyst provides in the form of catalytic precursor materials that in situ decomposes into catalytically active materials, viscosity reducers can be used. Viscosity reducers are used to reduce viscosity for fully mixing and improving mobility. Suitable viscosity reducers include those that are lower paraffins or non-paraffins in nature, such as light aromatics or light aromatics-rich solvents. For example, one or more refinery streams can be used as viscosity reducers, include but are not limited to one or more cycle oils, straight-run kerosene or straight-run gas oils from fluidized catalytic cracking process. The oil feedstock and the viscosity reducer are thoroughly mixed to reduce the oil viscosity to a suitable level, such as (expressed in centipoise at 40° C.) 200-500, 350-500, 200-400, or 350-400. For example, to achieve the desired viscosity level, the amount of viscosity reduction (weight % based on the total loaded feed) may be in the range of about 10-40, 10-25, 15-40, or 15-25; however, this amount may be determined based on the desired viscosity of the total feedstock, the viscosity of the initial heavy oil feedstock, and the viscosity of the selected viscosity reducer. Furthermore, in certain embodiments where the homogeneous catalyst is provided in the form of an aqueous catalytic precursor material that decomposes in situ to a catalytically active material, the effective amount of surfactant and / or co-surfactant (wt % based on total added feed) to achieve the desired level of homogeneity may be in the range of about 0.1-5.0, 0.1-3.0, 0.1-1.5, 0.75-5.0, 0.75-3.0, or 0.75-1.5.

[0040] The mixture of oil to be upgraded, water, viscosity reducer, and any surfactant or co-surfactant is maintained at a suitable temperature and pressure, for example, a temperature in the range of about 0° C. to 100° C. and a pressure in the range of about 1 to 30, 1 to 20, or 1 to 10 bar. These conditions are suitable to avoid evaporation of any added water, viscosity reducer, and any surfactant or co-surfactant.

[0041] In the case of using a homogeneous catalyst in the processes and systems described herein, submicron or nanometer-sized catalytic particles are well dispersed before loading the reactor 36. In certain embodiments, a catalytic precursor material is provided that decomposes into catalytically active materials in situ at a temperature within or upstream of the reactor 36, for example, at a temperature in the range of about 320-400°C, 350-400°C, 360-400°C, 320-380°C, 350-380°C, or 360-380°C. In order to maximize the uniform dispersion of the catalytic particles in the feed to the reactor 36, the particles are uniformly dissolved or dispersed in a medium such as water (aqueous) or oil (oil-soluble), respectively. In certain embodiments, a surfactant, optionally in combination with a co-surfactant, is added to finely disperse the aqueous catalytic precursor and / or particles in the oil medium. In certain embodiments, a surfactant and / or co-surfactant is used when the homogeneous catalyst is provided in the form of an aqueous catalytic precursor material that decomposes into catalytically active materials in situ. In the embodiment that homogeneous catalyst is provided in the form of active submicron or nanometer-sized particles that do not need to be decomposed into catalytically active material, the use of surfactant and / or cosurfactant is optional.In addition, in the embodiment using oil-soluble catalytic metal precursor, surfactant and cosurfactant are optional.Water-based and / or oil-soluble catalytic precursor is preferably decomposed because directly adding catalytic particles to the oil without using a medium increases the possibility of particle agglomeration and poor dispersion.In an embodiment, when using surfactant and / or cosurfactant, they can include the material effectively being dispersed in the oil medium with a hydrophilic lipophilic balance (HLB) within the scope of 7-16,8-16,7-11 or 8-11. Cosurfactant is added to improve surfactant effectiveness and to share similar HLB value ranges with surfactants having different functional groups. For example, suitable surfactant and cosurfactant are nonionic surfactants, including alcohol ethoxylates, alcohol alkoxylates, fatty acid alkanolamides, alkylamine oxides, oligo(ethylene glycol), alkyl polyglucosides and alkylphenol ethoxylates.

[0042] The catalytic emulsion is decomposed at a temperature below the oil cracking temperature over a given residence time to form an oil-catalytic suspension, i.e., a mixture of heavy feed and highly dispersed catalytic particles 16. After preheating in a loading heater 18, the mixture is combined at a mixing valve 22 with hydrogen 24 at an effective level, such as (in terms of standard cubic meters of hydrogen to feed (Nm3)). 3 / m 3) represents) 1-1000, 1-250, 50-1000 or 50-250. In addition, water and / or steam are combined via stream 32 at mixing valve 22 in a range of about 1-20, 1-15, 1-10, 3-20, 3-15 or 3-10 (weight % based on the total mass of the feed added). Hydrogen can be supplied by hydrogen-rich refinery fuel gas 26 or by another suitable hydrogen source. The use of excess hydrogen from refinery fuel gas improves refining economics and reduces operating costs. Other hydrogen sources, including hydrogen from gasification or steam methane reforming, can also be used after appropriate treatment.

[0043] In certain embodiments, efficient mixing of the feed, hydrogen, and water and / or steam is achieved by maximizing turbulence at the mixing valve 22. For example, hydrogen and steam injection can be performed at an effective angle (e.g., about 90°). After decomposition (i.e., catalyst activation), the viscosity reducer can be recycled back to the feed preparation unit. The metal in its organic or inorganic form decomposes to form catalytically active species. The collected water can also be recycled to the mixing valve 22 after appropriate treatment, or discharged to the API oil-water separator.

[0044] In the process, the addition of low partial pressure hydrogen improves oil stability and partially desulfurizes and denitrogenates the oil, thereby obtaining light and heavy hydrocarbon products with moderate desulfurization and denitrogenation, for example, by reducing sulfur by about 10-50% by weight and nitrogen by about 5-20% by weight. In addition, hydrogen improves catalyst stability, resulting in a reduction in the required catalyst volume.

[0045] Suitable catalytic materials 10 for catalytic hydrogen-aquathermolysis reactors are characterized by cracking, desulfurization, denitrogenation, hydrogenation and demetallization functions. Highly dispersed homogeneous catalysts are multifunctional non-supported submicron or nanometer-sized particles with at least two metals, and the metals are selected from non-precious transition metal groups and alkali and / or alkaline groups, such as potassium, calcium and nickel. The catalyst material is captured by asphaltene and heavy polyaromatic compound fractions. The catalyst precursor may include inorganic and organic composites of elements of Groups 1 or 2 of the IUPAC Periodic Table of Elements and / or non-precious transition metals of Groups 4, 5, 6, 7, 8, 9 or 10. For example, inorganic and organic composites (including potassium, calcium, nickel and / or platinum) are effective catalyst materials. These metals may initially be in the form of oxides. In certain embodiments, metal acetates (such as nickel acetate (II) tetrahydrate) in the form of hydrates are effective. In certain embodiments, sulfides of platinum or nickel are effective active catalysts. In certain embodiments, oxides of platinum or nickel are effective active catalysts. The catalyst precursor may be oil-based or in aqueous form.The catalyst particles in active form are characterized by an effective diameter (nanometers) in the range of 5-250, 10-250, 50-250, 5-200, 10-200, 50-200, 10-100, 20-100, or 50-100. The total concentration of catalyst material (ppmw, based on total feed weight) can be in the range of 100-20,000, 300-20,000, 500-20,000, 1,000-20,000, 100-5,000, 300-5,000, 500-5,000, 1,000-5,000, 100-1,500, 300-1,500, 500-1,500, 1,000-1,500, 100-1,200, 300-1,200, 500-1,200, or 100-1,000.

[0046] The catalytic hydrogen-aquathermolysis reactor 36 can be a suitable configuration, such as one or more tubular and / or continuously stirred tank reactor vessels. The catalytic hydrogen-aquathermolysis reactor 36 is operated under suitable conditions, such as low to moderate hydrogen partial pressure levels, for example, about 5-60, 10-60, 15-60, 20-60, 30-60, 5-50, 10-50, 15-50, 20-50, 30-50, 5-40, 10-40, 20-40, 5-35, 10-35, 5-30, 10-30, or 1 The reactor may be operated at a temperature in the range of about 400-500° C., 400-460° C., 400-450° C., 435-500° C., 435-460° C., or 435-450° C.; and the liquid hourly space velocity (LHSV) level (based on fresh feed, relative to the reactor volume) may be in the range of about 0.1-20, 0.1-10, 1-20, 1-20, 5-20, or 5-10 h -1 The catalytic hydrogen-aquathermolysis reactor conditions are optimized to achieve the highest conversion while maintaining suitable asphaltene content stability. In certain embodiments, the hydrogen-aquathermolysis reactor product is stable, for example, having a P value of at least about 1.20 ± 0.05. The P value (peptization value) is widely tested in the oil industry to measure the asphaltene stability of heavy hydrocarbon products by providing a numerical value (for example, determined by ASTM method D7060) representing the flocculation tendency of asphaltene. Typical feedstocks for catalytic hydrogen-aquathermolysis reactors contain asphaltene that is stable and in solution, for example, asphaltene with a P value greater than about 1.5. During processing, the ratio of resin to asphaltene changes, resulting in instability, which in turn leads to sediment formation. In addition, the presence of hydrogen and low to medium operating pressures result in low-level catalytic hydrotreating, for example, hydrodesulfurization in the range of about 10-80 or 10-50W% sulfur reduction.

[0047] To accommodate any lost BTU value in the refinery fuel gas due to hydrogen consumption, the gas products (including C1-C4 gases and impurities such as hydrogen sulfide and ammonia) from the catalytic hydrogen-aquathermolysis reactor 36 (and optionally (when used) a fractionator unit) can be sent to the main refinery fuel gas conduit 26.

[0048] In certain embodiments, the upgraded oil is treated with a light precipitant, such as a C3-C8 or C4-C8 paraffin solvent, to allow precipitation of asphaltenes, thereby reducing the concentration of catalyst remaining in the upgraded oil. The ratio of light precipitant to upgraded oil (weight to weight) is in the range of about 2:1-10:1, 2:1-8:1, 2:1-7:1, 3:1-10:1, 3:1-8:1, or 3:1-7:1. In addition, the addition of a precipitant to the heavy oil significantly reduces its viscosity and thereby reduces its ability to retain catalytic particles, which enhances the separation of the catalytic particles under the influence of gravity.

[0049] In an embodiment where the downstream process for processing the liquid products from the reactor 36 or the bottoms 48 from the fractionation step is a coking process, the recycle stream 50 may comprise coker gas oil and / or heavy coker gas oil from the coker liquid products. The coking operation may be operated according to known cokers used in refineries, including the more commonly known delayed coker units, and in some units, a fluid coking process. In general, a coking operation is a decarbonization process for converting a relatively low-value atmospheric or vacuum distillation residue stream into lighter products, thermally cracked hydrocarbon products. Coking of residues from heavy, high-sulfur or sour crude oils is typically performed to convert some of the material into more valuable liquid and gaseous products. Typical coking processes include delayed coking and fluid coking, wherein products are removed from the coking unit product fractionator, including coker gas, coker naphtha, and coker gas oil (which may be discharged as a full range stream or separated into light and heavy coker gas oils). In certain embodiments, such as in the case of a delayed coking unit, the coke produced is removed from the drum and is typically processed as a low-value by-product or collected for different uses depending on its quality. In a fluid coking unit, the coke is removed as particles and a portion is recycled to provide a hot surface for thermal cracking. The coker feed stream, such as all or a portion of the liquid products and / or bottoms stream 48 from reactor 36, is mixed with steam and the mixture is rapidly heated to a coking temperature in a coking furnace and then fed to a coke drum. The hot mixed coker feed stream is maintained in the coke drum under coking conditions at temperatures and pressures at which the feed decomposes or cracks to form coke and volatile components. The volatile components are collected as vapor and transferred to a coked product fractionator. One or more heavy fractions of the coke drum vapors can be condensed, such as by quenching or heat exchange. In certain embodiments, the coke drum vapor contacts with heavy gas oil in the coking unit product fractionator, and the heavy fraction forms all or part of a recycle oil stream of coking unit product vapor and heavy gas oil with condensation. In certain embodiments, the heavy gas oil from the coking feed fractionator is added to the flash zone of the fractionator to condense the heaviest components from the coking unit product vapor. The delayed coking unit is typically configured with two or more parallel drums and operates in an alternating switching mode if there are two drums, or in a sequential cycle operation mode if there are three or more drums. It is also possible to have a parallel coking drum train (train) with two or more drums per column. When the coke drum is full of coke, the feed is switched to another drum, and the full drum is cooled. The liquid and gas stream from the coke drum is transferred to the coking product fractionator for collection. Any hydrocarbon vapor remaining in the coke drum is removed, for example, by steam injection. The coke remaining in the drum is typically cooled with water and then removed from the coke drum by conventional methods, such as by hydraulic and / or mechanical techniques, to remove the green coke from the drum walls for recovery.The conditions in the coke drum include a temperature of about 425-650°C, 425-510°C, 425-505°C, 425-500°C, 450-650°C, 450-510°C, 450-505°C, 450-500°C, 485-650°C, 485-510°C, 485-505°C, 485-500°C, 470-650°C, 470-510°C, 470-505°C, or 470-500°C; a pressure of about 1-20, 1-10, or 1-3 bar; The invention relates to a process for producing a coke mixture having an operating pressure, and in certain embodiments, a moderately superatmospheric pressure; wherein steam is introduced or injected with the heated residual oil at a steam introduction rate of about 0.1-3%, 0.5-3% by weight, or 1-3% by weight relative to the heated residual oil to increase the velocity in the tube furnace and reduce the partial pressure of the feed oil in the drum; and in a cycle of about 10-30, 10-24, 10-18, 12-30, 12-24, 12-18, 16-30, 16-24, or 16-18 hours. In certain embodiments, a fluid coking process is used in which circulating coke particles contact the feed and in which coking occurs on the surface of the coke particles, such as Flexicoking, which is commercially available from ExxonMobil. TM Process. In the operation of the fluid coking unit, the coker feed (all or a portion of the liquid product and / or bottoms stream 48 from the reactor 36) and steam are introduced into the coking furnace to be heated to a predetermined temperature or temperature range, for example, typically at about the coking temperature. For example, a burner or heater with horizontal tubes is used to reach a temperature level at or below the thermal cracking temperature, for example, in the range of about 425-650°C, 425-570°C, 425-525°C, 450-650°C, 450-570°C, 450-525°C, 485-650°C, 485-570°C or 485-525°C. With a short residence time in the tubes of the coking furnace and the addition of steam, coking of the feed on the tubes is minimized or avoided. In the fluid coking unit, coking occurs on the coke particles in the coking reactor. In addition, additional heat for coking is provided by recycling the heated coke particles that are burned in the coke drum.

[0050] In embodiments where the downstream process treating the liquid product from reactor 36 or bottoms 48 from the fractionation step is a catalytic hydroprocessing unit such as a residue hydroprocessing unit, the recycle stream 50 comprises heavy liquid process bottoms from that unit, e.g., having a boiling point greater than about 450°C, 475°C, 500°C, or 520°C. Thus, for example, all or a portion of the liquid product and / or bottoms stream 48 from reactor 36 may be passed to a resid hydrotreater, which may be, for example, a fixed bed, slurry, or ebullating bed reactor operated under suitable conditions with an effective hydrotreating catalyst (e.g., the resid hydrotreater may be operated under the following conditions: a reactor temperature in the range of about 370-470°C, 370-450°C, 370-440°C, 370-430°C, 380-470°C, 380-450°C, 380-440°C, 380-430°C, 390-450°C, 390-440°C, or 390-430°C; a reactor temperature in the range of about 80-250°C, 80-200°C, 80-150°C, 90-250°C, 90-200°C, 90-150°C, 100-250°C, 100-20 ... 50, 100-200 or 100-150 bar; a hydrogen feed rate of up to about 3500, 3000 or 2500, and in certain embodiments about 1000-3500, 1000-3000, 1000-2500, 1500-3500, 1500-3000, 1500-2500, 2000-3500, 2 000-3000 or 2000-2500 standard liters per liter of hydrocarbon feed (SLt / Lt); and about 0.1-4.0, 0.1-2.0, 0.1-1.5, 0.1-1.0, 0.2-4.0, 0.2-2.0, 0.2-1.5, 0.2-1.0, 0.5-4.0, 0.5-2.0, 0.5-1.5 or 0.5-2.0h -1 The liquid hourly space velocity (LISV) of the catalyst is based on fresh feed relative to the hydrotreating catalyst. Suitable catalysts for residue hydrotreaters typically contain an effective amount (e.g., about 5-40 wt. % based on the weight of the catalyst) of one or more active metal components selected from Groups 6, 7, 8, 9, and 10 of the IUPAC Periodic Table of Elements or metal compounds (oxides or sulfides). In certain embodiments, the active metal component is one or more of Co, Ni, W, and Mo. The active metal component is typically deposited or otherwise incorporated onto a support (such as amorphous alumina, amorphous silica-alumina, zeolite, or a combination thereof). One or more reactor trains may be provided, with different catalysts in different reactors in each train. LPG, naphtha, and middle distillates may be recovered, with the remainder being heavy oil and asphalt. All or a portion of the heavy oil and asphalt may be used as a recycle stream 50.

[0051] In certain embodiments where the process for treating the liquid product from reactor 36 is a solvent deasphalting process, the recycle stream 50 may comprise a portion that is insoluble in the C3-C8 paraffin solvent used for deasphalting. Solvent deasphalting may be integrated to remove asphaltenes from all or a portion of the liquid product from reactor 36, or from the bottoms of a fractionator receiving the liquid product from reactor 36 (e.g., see Figure 1

[0045] The asphalt phase is separated from all or a portion of stream 48). In embodiments of the process of the present invention in which the feed to the solvent deasphalting operation comprises an unsupported catalyst material, submicron or nanometer-sized catalytic particles are conveyed with the asphalt phase. These particles are present, for example, in a range of up to about 5000, 1000, or 500 ppmw, such as at a concentration of about 300-500, 300-3000, 300-1800, 300-1000, 300-500, 460-5000, 460-3000, 460-1800, or 460-1000 ppmw.

[0052] As is well known, solvent deasphalting uses a suitable solvent to precipitate the asphaltene fraction from the feed. Typically, in the solvent deasphalting zone, the feed is mixed with a solvent so that the deasphalted oil is solubilized in the solvent. Insoluble asphalt is precipitated from the mixed solution. The separation of the deasphalted oil (DAO) phase (solvent-DAO mixture) and the asphalt / pitch phase typically occurs in one or more containers or extractors designed to effectively separate the two phases and minimize the entrainment of pollutants in the DAO phase. The DAO phase is then heated to a condition where the solvent becomes supercritical. Under these conditions, the separation of the solvent and DAO is promoted in the DAO separator. Typically, a low-pressure steam stripping device is used to strip any entrained solvent from the DAO phase and the pitch phase. The collected solvent is condensed and combined with the solvent collected from the DAO separator under high pressure. The solvent is then recycled back to mix with the feed.

[0053] Solvent deasphalting is carried out in the liquid phase, and accordingly the temperature and pressure are set. There are typically two phase separation stages in solvent deasphalting. In the first separation stage, the temperature is maintained at a lower level than in the second stage to separate most of the asphaltenes. The temperature of the second stage is carefully selected to control the final deasphalted / demetalized oil quality and quantity. An excessively high temperature level will result in a decrease in the yield of deasphalted / demetalized oil, but the deasphalted / demetalized oil will be lighter, have a lower viscosity, and contain less metal, asphaltenes, sulfur, and nitrogen. An insufficient temperature level has the opposite effect, increasing the deasphalted / demetal yield but decreasing the product quality. The operating conditions of the solvent deasphalting unit are typically based on a specific solvent and feed to produce a deasphalted / demetalized oil with a specific yield and quality. Thus, for a given solvent, the extraction temperature is essentially fixed and usually only minor adjustments are made to maintain the deasphalted / demetalized oil quality. The composition of the solvent is also an important process variable. The solubility of the solvent increases with an increase in the critical temperature, such that C3 < iC4 < nC4 < iC5, i.e., the solubility of iC5 is greater than that of nC4, the solubility of nC4 is greater than that of iC4, and the solubility of iC4 is greater than that of C3. An increase in the solvent critical temperature increases the yield of deasphalted / demetalized oil. However, a solvent with a higher critical temperature provides lower selectivity, resulting in a lower quality of deasphalted / demetalized oil. The solvent deasphalting unit operates at a pressure high enough to keep the solvent in the liquid phase and is typically fixed and varies with the solvent composition. The volume ratio of the solvent to the solvent deasphalting unit loading is also important in its effect on selectivity and, to a lesser extent, on the yield of deasphalted / demetalized oil. The main effect of the solvent-to-oil ratio is that for a fixed deasphalted / demetal yield, a higher ratio results in a higher quality of deasphalted / demetalized oil. A high solvent-to-oil ratio is preferred because of better selectivity, but the increased operating cost typically indicates that the ratio is limited to a relatively narrow range. The choice of solvent is also a factor in establishing an operable solvent-to-oil ratio. The required solvent-to-oil ratio decreases with an increase in the critical solvent temperature. Thus, the solvent-to-oil ratio is a function of the desired selectivity, operating cost, and solvent choice. In certain embodiments, the solvent-to-oil ratio (weight to weight) is in the range of about 2:1 - 10:1, 2:1 - 8:1, 2:1 - 7:1, 3:1 - 10:1, 3:1 - 8:1, or 3:1 - 7:1.

[0054] In known solvent deasphalting operations, the asphalt phase contains a large portion of the contaminants from the charge, i.e., metals, asphaltenes, Conradson carbon, and is also rich in aromatics and asphaltenes. In addition to the solvent deasphalting operations described herein, other solvent deasphalting operations are also suitable, although less common. For example, a three-product unit can be used in which resin, DAO, and asphalt are recovered, wherein a range of asphalts can be produced from different resin / asphalt blends.

[0055] In an example of a typical solvent deasphalting unit that can be integrated with the catalytic hydrogen-aquathermolysis process herein, Figure 2 An embodiment of a solvent deasphalting zone that can be integrated with the catalytic hydrogen-aquathermolysis process described herein is schematically depicted. The solvent deasphalting zone receives a feed 60 that can include a feed from a catalyst described herein and combined with a catalyst. Figure 1 The feed 60 may be a liquid product from the reactor 36, or a bottoms stream such as stream 48 from a fractionator downstream of the reactor 36, wherein the feed 60 contains dispersed metal particles that were present in the feed to the reactor 36 and removed in the solvent deasphalting zone. In other embodiments, the feed 60 may be a heavy liquid product from a catalytic hydroprocessing unit such as a residue hydroprocessing unit; in these embodiments, the dispersed metal particles contained in the heavy liquid product are removed in the solvent deasphalting zone. The dispersed metal particles from the catalyst are concentrated in the heaviest unconverted oil fractions due to a viscosity slump effect. The polarity of the catalytic metal particles induces their attraction to the heaviest fractions of the oil through polar-polar interactions. The heavy polyaromatic condensation compounds and asphaltenes encapsulate the metal particles through a caging effect. Any metal particles remaining in the deasphalted oil may be separated, for example, by electrostatic precipitation. In other embodiments, the feed 60 may include all or a portion of the effluent from a process that treats the liquid product 42 or heavy portion 48 from the reactor 36 (such as a heavy liquid product from a delayed coking unit), whereby all or a portion of the dispersed metal particles are removed as the coke is removed from the coking unit.

[0056] An example of a solvent deasphalting zone generally includes a primary phase separation zone 52, a secondary phase separation zone 54, a deasphalted oil separation zone 56, and an asphalt separation zone 58. Primary phase separation zone 52 includes an inlet for receiving a feed 60 and a solvent 62, which may include a solvent make-up 64, a recycle solvent stream 66, and / or a recycle solvent stream 68. Feed 60 comprises, consists of, or consists essentially of all or a portion of the liquid product of reactor 36, or a bottoms stream from a fractionator that receives the liquid product of reactor 36 (e.g., see FIG. 1 ). Figure 1In some embodiments, a solvent drum (not shown) is integrated to receive a source of recycled and supplemental solvent in the solvent deasphalting system. The primary phase separation zone 52 also includes an outlet for discharging an asphalt phase 70 and an outlet for discharging a phase 72 with a reduced asphalt content (as a primary DAO phase). The secondary phase separation zone 54 includes an inlet in fluid communication with the primary DAO phase 72 outlet fluid from the primary phase separation zone 52, and an outlet for discharging the asphalt phase 74, all or a portion of which may optionally be in fluid communication with the primary phase separation zone 52 via line 76 (shown in dotted lines). The secondary phase separation zone 54 includes an outlet for discharging a secondary DAO phase 78 in fluid communication with the DAO inlet fluid of the separation zone 56. The separation zone 56 includes an outlet for discharging a solvent stream 66 in fluid communication with the primary phase separation zone 52, and an outlet for discharging a DAO product 80. The asphalt stream 70 outlet is connected to the inlet of the separation zone 58 for solvent collection. The asphalt stream 70 may optionally be heated before being transferred to the inlet of the separation zone 58. Separation zone 58 also includes an outlet in fluid communication with primary phase separation zone 52 for discharging a recycle solvent stream 68 , and an outlet for discharging asphalt 82 .

[0057] In the operation of the deasphalting process herein, a feed 60 (which in certain embodiments has dispersed particles of a catalyst used in a catalytic hydrogen-aquathermolysis reactor) and a solvent stream 62 are mixed, for example, using an in-line mixer or a separate mixing vessel (not shown). The mixing can be performed as part of the primary phase separation zone 52 or before entering the primary phase separation zone 52. The solvent stream 62 includes all or a portion of the recycle streams 66, 68 and the make-up solvent stream 64. The mixture of hydrocarbons and solvent is conveyed to the primary phase separation zone 52 where phase separation occurs. The primary phase separation zone 52 serves as the first stage for extracting DAO from the feedstock. The two phases formed in the primary phase separation zone 52 are an asphalt phase and a primary DAO phase, which are collected via outlets 70, 72, respectively. In embodiments using a feed 60 having dispersed particles of a catalyst used in a catalytic hydrogen-aquathermolysis reactor, all or a substantial amount of these particles are removed with the asphalt phase. For example, at least about 75, 85, 90, 95, or 99% by weight can be removed based on the total weight of the catalyst particles used. The temperature of the contents of the primary phase separation zone 52 is maintained low enough to maximize the recovery of DAO from the feedstock. Typically, components with higher solubility in the non-polar solvent will be conveyed with the primary DAO phase 72. The primary DAO phase 72 comprises a major portion of the solvent, a minor portion of the asphalt content of the feedstock, and a major portion of the DAO content of the feedstock.

[0058] The conditions in the primary phase separation zone 52 are maintained below the critical temperature and pressure of the solvent. In certain embodiments, the solvent selected for use in the mixing vessel and the first separation vessel in the enhanced solvent deasphalting process herein is a C3-C8 paraffin solvent. Table 1 below provides critical temperature and pressure data for C3 to C8 paraffin solvents:

[0059] Table 1

[0060]

[0061]

[0062] In a typical solvent deasphalting unit, the primary DAO phase 72 from the primary phase separation zone 52 is passed to a secondary phase separation zone 54, which serves as the final stage of extraction. The asphalt phase separates and forms at the bottom of the secondary phase separation zone 54, which approaches the critical temperature of the solvent due to the elevated temperature. In certain embodiments, the asphalt phase, which includes metal particles from the effluent of the catalytic hydrogen-aquathermolysis reactor, is recovered via outlet 74 and may contain small amounts of solvent and DAO. The asphalt phase 74 is optionally recycled back to the primary phase separation zone 52 to recover the remaining DAO, or is optionally mixed with the asphalt stream 70. The secondary DAO phase is discharged from the secondary phase separation zone 54 as stream 78 and is typically passed to the DAO separation zone 56 to recover and recycle the solvent.

[0063] The DAO separation zone 56 comprises one or more suitable vessels arranged and sized to allow for rapid and efficient flash separation of the solvent from the DAO stream 72. The solvent is flashed from the DAO separation zone 56 and discharged as stream 66 for recycling to the primary phase separation zone 52. The bottoms stream 80 from the separation zone 56 is DAO, which is optionally passed to a steam stripper (not shown) to steam strip the product as is conventionally known to recover a steam-stripped DAO product stream and a steam and solvent mixture for solvent recovery. In certain embodiments, steam stripping may be avoided.

[0064] The asphalt stream 70 from the primary phase separation zone 52 is loaded into the asphalt separation zone 58. The asphalt stream 70 may be optionally heated in a heater (not shown) before being conveyed to the inlet of the separation zone 58. Additional solvent is flashed from the separation zone 58 and discharged as stream 68 for recycling to the primary phase separation zone 52. The bottoms asphalt stream 82 from the separation zone 58 is optionally conveyed to a steam stripper (not shown) to steam strip the asphalt as conventionally known to recover the steam stripped asphalt phase and a steam and solvent mixture for solvent recovery. In embodiments using a feed 60 containing dispersed particles of the catalyst used in the catalytic hydrogen-aquathermolysis reactor, all or a large portion of these particles are conveyed to the asphalt stream 82. The asphalt stream 82 containing precipitated asphaltenes is periodically removed from the solvent deasphalting unit to facilitate the deasphalting process, and the precipitated asphaltene may be conveyed to other refining processes such as gasification or delayed coking, or integrated in the asphalt pool.

[0065] In certain embodiments of the integrated processes herein, and in order to maximize yield and minimize asphalt and / or resin in the system, one or more asphalt phase streams from the solvent deasphalting may be recycled to the catalytic hydrogen-aquathermolysis reactor 36. For example, this may include all or a portion of the asphalt stream 70 from the primary phase separation zone 52, all or a portion of the asphalt stream 74 from the secondary phase separation zone 55, and / or all or a portion of the asphalt stream 82 from the separation zone 58. Figure 1 The recycle is loaded as described above with respect to stream 50. In other embodiments, a portion of the deasphalted upgraded oil 66 is recycled to the catalytic hydrogen-aquathermocracking reactor 36 as all or part of the recycle stream 50, either directly or via the mixing unit 14, mixing valve 22, and / or loading heater 18.

[0066] In embodiments where the process for treating the liquid product from reactor 36 is an adsorption process, the recycle stream 50 comprises heavy hydrocarbons separated from the desorption solvent, such as those eluted with a solvent having a Hildebrand solubility factor of at least 14. Adsorption may be integrated in certain embodiments to further remove asphaltenes, sulfur and nitrogen containing molecules, and polynuclear heavy aromatic compounds. Adsorption may be performed on one or more of the catalytic hydrogen-aquathermolysis effluents or on the heavy portion of the effluent from one or more different processes downstream of the catalytic hydrogen-aquathermolysis. In certain embodiments, all or a portion of the liquid product from reactor 36, or the bottoms from a fractionator receiving the liquid product from reactor 36 (e.g., see FIG. 1 ), may be subjected to a filtration step. Figure 1In certain embodiments, all or a portion of the DAO from the solvent deasphalted autocatalytic hydro-aquathermolysis effluent 42 or effluent bottoms 48 may be contacted with an effective type and amount of adsorbent material, and under effective conditions, to remove asphaltenes, sulfur- and nitrogen-containing molecules, and polynuclear heavy aromatic compounds for further downstream processing.

[0067] In one embodiment, the adsorption feed is contacted with an effective type and amount of adsorbent material, under effective conditions, to remove asphaltenes and polynuclear heavy aromatics. The resulting mixture is subjected to atmospheric distillation to recover, for example, a distillate having an initial boiling point of about 36°C and a final boiling point between about 350-400°C; such as naphtha, kerosene, gas oil, and atmospheric residue, wherein the adsorbent material is conveyed with the atmospheric residue. At this stage, asphaltenes, sulfur- and nitrogen-containing molecules, and polynuclear heavy aromatics from the feed are adsorbed on and / or within the pores of the adsorbent material. The mixture of atmospheric residue and adsorbent material can be further separated in a vacuum distillation unit to recover, for example, a distillate having an initial boiling point between about 350-480°C and a final boiling point between about 480-560°C, such as vacuum gas oil and vacuum residue, wherein the adsorbent material is conveyed with the vacuum residue. The adsorbent material can be regenerated and recycled to the return recovery and the regenerated adsorbent material in the return to contact the feed. Examples of processes and systems that can be integrated in this manner are disclosed in commonly owned US Patent Nos. 7,799,211 and 8,986,622, which are incorporated herein in their entireties.

[0068] For example, reference Figure 3 , shows an integrated adsorption system that converts a catalytic hydrogen-water thermal cracking reactor effluent, such as effluent 42 or bottoms stream 48 (both referenced to Figure 1All or a portion of the catalyst (described) is taken as feed stream 111. In certain embodiments, feed stream 111 contains dispersed metal particles present in the feed to reactor 36 and is removed in the integrated adsorption system. In other embodiments, feed stream 111 may be a heavy liquid product from a catalytic hydroprocessing unit such as residue hydroprocessing; in these embodiments, dispersed metal particles contained in the heavy liquid product are removed in the adsorption zone. Dispersed metal particles from the catalyst are concentrated in the heaviest unconverted oil fraction due to the viscosity drop effect. The polarity of the catalytic metal particles causes their attraction to the heaviest fraction of the oil through polar-polar interactions. Heavy polyaromatic condensation compounds and asphaltenes encapsulate the metal particles through an enveloping effect. Any metal particles remaining in the adsorption treated oil can be separated, for example, by electrostatic precipitation. In other embodiments, the feed stream 111 may comprise all or a portion of the effluent from a process that treats the liquid product 42 or heavy fraction 48 from the reactor 36, such as a heavy liquid product from a delayed coking unit, whereby all or a portion of the dispersed metal particles are removed with the coke removed from the coking unit. In still other embodiments, the feed stream 111 may comprise all or a portion of the DAO from a solvent deasphalting operation that separates asphaltenes from the liquid product 42 or heavy fraction 48 obtained from the reactor 36, whereby all or a portion of the dispersed metal particles are removed with the asphalt phase.

[0069] Figure 3 The integrated adsorption system shown in FIG includes a contact or mixing vessel 110, an atmospheric flash separator vessel 120, a vacuum flash separator vessel 130, a filtration / regeneration vessel 140, and in certain embodiments, a solvent treatment vessel 150. Figure 3 In embodiments of a continuous process for an adsorption system of the present invention, a feed stream 111 and a solid adsorbent 112 are fed into a contact vessel 110 and mixed to form a slurry. The contact vessel 110 can be operated as an ebullating bed or fixed bed reactor, a tubular reactor, or a continuous stirred tank reactor. In certain embodiments, the contact vessel 110 is operated as a mixing vessel equipped with a suitable mixing device, such as a rotating stirring blade or paddle, which provides gentle but thorough mixing of the contents. The stirring rate is selected for a given vessel and mixture of adsorbent, solvent, and feedstock so that the loss of adsorbent particles or particles is minimized, if any.

[0070] The solid adsorbent / crude oil slurry mixture 113 is then transferred to an atmospheric flash separator 120 for separation and recovery of an atmospheric distillate 121. An atmospheric residue bottoms stream 122 from vessel 120 is sent to a vacuum flash separator vessel 130. A vacuum distillate stream 131 is withdrawn from the top of vessel 130, and bottoms 132, comprising vacuum flash residue and solid adsorbent, is sent to a solvent adsorbent regeneration unit vessel 140. A vacuum residue product 141 is withdrawn from the top of vessel 140, and bottoms 142 is withdrawn and separated, allowing reusable regenerated adsorbent 143 to be recycled back and introduced into vessel 110 along with fresh adsorbent material 112 and feedstock 111; the unused portion 144 of the regenerated adsorbent is removed for disposal.

[0071] In certain embodiments, the adsorbent regeneration unit 140 is operated in a switching mode so that the production of regenerated absorbent is continuous. When the adsorbent material in the stream 132 from the vacuum distillation unit 130 introduced into one regeneration unit, such as 140A, reaches capacity, the flow of feed stream 132 is then directed to another column 140B. The adsorbed compounds are desorbed, for example, by heating or solvent treatment. The adsorbed compounds containing nitrogen and PNA can be desorbed by applying heat at a pressure of 1-10 Kg / cm2 accompanied by an inert nitrogen flow, or desorbing with available fresh or recycled solvent streams 146 or 152 or refinery streams (such as naphtha, diesel, toluene, acetone, dichloromethane, xylene, benzene or tetrahydrofuran) at a temperature (°C) range of, for example, about 20-250°C.

[0072] In the case of thermal desorption, the desorbed compounds are removed from the bottom of the column as stream 145 for use in other refinery processes such as residue upgrading facilities including hydrotreating, coking, asphalt units, or directly for fuel oil blending.

[0073] In the case of solvent desorption, solvents are selected based on their Hildebrand solubility factor or by their two-dimensional solubility factor. The total Hildebrand solubility parameter is a well-known polarity measure and has been calculated for many compounds. See, Journal of Paint Technology, vol. 39, no. 505 (February 1967). Suitable solvents can also be described by their two-dimensional solubility parameters comprising a complexing solubility parameter and a field force solubility parameter. See, for example, IA Wiehe, Ind & Eng. Res., 34 (1995), 661. The complex solubility parameter component (describing hydrogen bonding and electron donor-acceptor interactions) measures the interaction energy between an atom of one molecule and a second atom of a different molecule requiring a specific orientation. The field force solubility parameter (describing van der Waals forces and dipole interactions) measures the interaction energy of a liquid that is not disrupted by changes in the orientation of the molecules.

[0074] according to Figure 3 In certain embodiments, the one or more (if more than one solvent is used) non-polar solvents preferably have an overall Hildebrand solubility parameter of less than about 18.0 or a composite solubility parameter of less than 0.5 and a field force parameter of less than 7.5. Suitable non-polar solvents include, for example, saturated aliphatic hydrocarbons such as pentane, hexane, heptane, paraffin naphtha, C5-C11, kerosene C12-C15, diesel C16-C20, normal paraffins and branched paraffins, and mixtures of any of these solvents. In certain embodiments, the solvent is a C5-C7 paraffin and a C5-C11 paraffin naphtha.

[0075] according to Figure 3 In certain embodiments, the polar solvent has an overall solubility parameter greater than about 18 or a combined solubility parameter greater than 1 and a field force parameter greater than 8. Examples of polar solvents that meet the required minimum solubility parameters are toluene (18.3), benzene (18.7), xylene (18.2), and tetrahydrofuran (18.5). In certain embodiments, the polar solvent is toluene or tetrahydrofuran.

[0076] In the case of solvent desorption, the solvent and the effluent stream 148 from the adsorption column are sent to the fractionation unit 150 within the cell limits. The recovered solvent stream 152 is recycled back to the adsorbent regeneration unit 140 or 140A and 140B for reuse. The bottoms stream 154 from the fractionation unit 150 can be sent to other refinery processes.

[0077] In other embodiments, enhanced solvent deasphalting can be integrated with catalytic hydrogen-aquathermolysis. For example, enhanced solvent deasphalting methods such as those described in commonly owned U.S. Patent No. 7,566,394 (which is incorporated herein by reference in its entirety) are used to treat all or a portion of the catalytic hydrogen-aquathermolysis reactor effluent.

[0078] For example, reference Figure 4 , shows an embodiment of an enhanced solvent deasphalting process that converts a catalytic hydrogen-aquathermolysis reactor effluent, such as effluent 42 or bottoms stream 48 (both referenced to Figure 1 All or a portion of the catalyst is taken as feed stream 202. In certain embodiments, feed stream 202 contains dispersed metal particles present in the feed to reactor 36 and is removed in the integrated adsorption system. In other embodiments, feed stream 202 may be a heavy liquid product from a catalytic hydroprocessing unit such as a residue hydroprocessing; in these embodiments, dispersed metal particles contained in the heavy liquid product are removed in an enhanced solvent deasphalting zone. Dispersed metal particles from the catalyst are concentrated in the heaviest unconverted oil fraction due to the viscosity drop effect. The polarity of the catalytic metal particles induces their attraction to the heaviest fractions of the oil through polar-polar interactions. The heavy polyaromatic condensation compounds and asphaltenes encapsulate the metal particles through an enveloping effect. Any metal particles remaining in the deasphalted oil can be separated, for example, by electrostatic precipitation. In other embodiments, the feed stream 202 may comprise all or a portion of the effluent from a process that treats the liquid product 42 or heavy portion 48 from the reactor 36 (such as a heavy liquid product from a delayed coking unit), whereby all or a portion of the dispersed metal particles are removed as the coke is removed from the coking unit.

[0079] Reference Figure 4 The system shown includes a mixing vessel 210, a first separation vessel 220, a filtration vessel 230, a fractionator 240, and a second separation vessel 250. A heavy hydrocarbon feed stream 202, a paraffinic solvent 204, and a solid adsorbent slurry 206 having an effective amount of solid adsorbent material are introduced into the mixing vessel 210. The mixing vessel 210 is equipped with a suitable mixing device, such as a rotating stirring blade or paddle, which provides gentle but thorough mixing of the contents. The stirring rate is selected for a given vessel and mixture of adsorbent, solvent, and feedstock so that the loss of adsorbent particles or particles, if any, is minimized. For example, mixing can be performed for 30 to 150 minutes.

[0080] A mixture of feed stream 202, paraffinic solvent 204, and solid adsorbent 206 is discharged through line 212 to a first separation vessel 220 at a temperature and pressure below the critical temperature and pressure of the solvent to separate the feed mixture into an upper layer comprising a light, low-polarity fraction which is removed as stream 222, and a bottoms comprising asphaltenes and solid adsorbent 224. A vertical flash tank may be used for this separation step. Figure 2 The solvent deasphalting process described maintains conditions in the mixing vessel and the first separation vessel below the critical temperature and pressure of the solvent.

[0081] The asphalt and adsorbent slurry 224 is mixed with an aromatic and / or polar solvent stream 226 in a filter vessel 230 to separate and clean the adsorbent material. The solvent stream 226 may be similar to that described above with reference to Figure 3 The adsorption system described is as described. In certain embodiments, the adsorbent slurry and asphalt mixture 224 is washed with an aromatic or polar solvent 226 in a filter vessel 230 at a solvent to feed ratio (weight to weight) of about 1:1-8:1, 1:1-6:1, or 1:1-3:1 to dissolve and remove adsorbed compounds. A clean solid adsorbent stream 238 is collected and recycled to the mixing vessel 210, a stream 236 of rejected material is collected, and the spent adsorbent 234 is discharged. The solvent-asphalt mixture 232 is removed from the filter vessel 230 and sent to a fractionator 240 to separate the solvent from the asphalt phase, and the asphalt phase is removed as stream 242 for appropriate treatment. The clean aromatic and / or polar solvent is collected as stream 244 and recycled to the filter vessel 230.

[0082] The recovered deasphalted oil and solvent stream from the first separation vessel 222 is introduced into a second separation vessel 250, which is maintained at an effective temperature and pressure to separate the solvent from the deasphalted oil, such as between the boiling point and critical temperature of the solvent at a pressure of 1-3 bar. In certain embodiments, the solvent stream 252 is recovered and returned to the mixing vessel 210 in a continuous operation. A deasphalted oil stream 254 is discharged from the bottom of the vessel 250.

[0083] In certain embodiments of the integrated processes herein, in order to maximize yield and minimize pitch and / or resin in the system, one or more of the pitch or other rejected compounds (such as those desorbed from the adsorbent material) may be recycled to the catalytic hydrogen-aquathermolysis reactor 36. For example, this may include all or a portion of the rejected material in stream 236 and / or all or a portion of the pitch phase 242. Figure 1The recycle is loaded as described above with respect to stream 50. In other embodiments, a portion of the deasphalted upgraded oil 254 is recycled to the catalytic hydrogen-aquathermocracking reactor 36 as all or a portion of the recycle stream 50, either directly or via the mixing unit 14, mixing valve 22, and / or loading heater 18.

[0084] Figure 5 Another embodiment of an enhanced solvent deasphalting process is shown that converts a catalytic hydrogen-aquathermolysis reactor effluent, such as effluent 42 or bottoms stream 48 (both referred to as Figure 1 All or a portion of the catalyst is used as feed stream 302. In certain embodiments, feed stream 302 contains dispersed metal particles present in the feed to reactor 36 and is removed in the integrated adsorption system. In other embodiments, feed stream 302 may be a heavy liquid product from a catalytic hydroprocessing unit such as a residue hydroprocessing; in these embodiments, dispersed metal particles contained in the heavy liquid product are removed in an enhanced solvent deasphalting zone. Dispersed metal particles from the catalyst are concentrated in the heaviest unconverted oil fraction due to the viscosity drop effect. The polarity of the catalytic metal particles induces their attraction to the heaviest fractions of the oil through polar-polar interactions. The heavy polyaromatic condensation compounds and asphaltenes encapsulate the metal particles through an shrouding effect. Any metal particles remaining in the deasphalted oil can be separated, for example, by electrostatic precipitation. In other embodiments, the feed stream 302 may comprise all or a portion of the effluent from a process that treats the liquid product 42 or heavy portion 48 from the reactor 36 (such as a heavy liquid product from a delayed coking unit), whereby all or a portion of the dispersed metal particles are removed as the coke is removed from the coking unit.

[0085] Reference Figure 5 The system shown includes a first separation vessel 320, a second separation vessel 350, a filter vessel 330, and a fractionator 340. Feed stream 302 and paraffinic solvent 304 are introduced into the first separation zone 320, where the bitumen is separated from the feed stream and withdrawn from the first separation zone 320 as stream 324. The conditions in the first separation vessel are maintained below the critical temperature and pressure of the solvent, as described above using Figure 2In certain embodiments, the solvent selected for use in the first separation vessel of the enhanced solvent deasphalting process of this invention is a C3-C8 paraffinic hydrocarbon solvent. The combined deasphalted oil and solvent stream 322 is discharged from the first separation zone 320 and mixed with an effective amount of solid adsorbent material 306, for example, using an in-line mixing device and / or a separate mixing zone to produce a mixture of deasphalted oil, solvent and solid adsorbent material, which is conveyed to the second separation zone 350. The mixture is maintained in the second separation zone 350 at an effective temperature and pressure for separating the solvent from the deasphalted oil, such as between the boiling point and critical temperature of the solvent at a pressure of 1-3 bar. In addition, the mixture is maintained in the second separation zone 350 for a time sufficient to adsorb any remaining asphaltenes and / or sulfur-containing polynuclear aromatic molecules and / or nitrogen-containing polynuclear aromatic molecules on the adsorbent material. The solvent is then separated and recovered from the deasphalted oil and adsorbent material and recycled to the first separation zone 320 as stream 352.

[0086] The slurry 355 of deasphalted oil and adsorbent from the second separation vessel 350 is mixed with the aromatic and / or polar solvent stream 326 in the filtration vessel 330 to separate and clean the adsorbent material. The solvent stream 326 may be similar to that described above with reference to Figure 3 The adsorption system described herein is described. The solvent stream 326 may include benzene, toluene, xylene, tetrahydrofuran, dichloromethane. In certain embodiments, the deasphalted oil and adsorbent mixture 355 is washed in a filter vessel 330 with an aromatic or polar solvent 326 at a solvent to feed ratio (weight to weight) of about 1:1-8:1, 1:1-6:1 or 1:1-3:1 to dissolve and remove adsorbed sulfur and nitrogen compounds. The clean solid adsorbent stream 338 is collected and recycled to mix with the deasphalted oil stream 322. The spent adsorbent material is discharged from the filter vessel as stream 334. The deasphalted oil and solvent mixture 332 is conveyed from the filter vessel 330 to a fractionator 340 to separate the solvent from the rejected material stream 342 for appropriate treatment. The clean aromatic and / or polar solvent is collected as stream 344 and recycled to the filter vessel 330. The deasphalted oil is collected as stream 346.

[0087] In certain embodiments of the integrated processes herein, and in order to maximize yield and minimize pitch and / or resin in the system, one or more of the pitch or other rejected compounds (such as those desorbed from the adsorbent material) may be recycled to the catalytic hydrogen-aquathermolysis reactor 36. For example, this may include all or a portion of the pitch phase 324 and / or all or a portion of the rejected materials in stream 342. Figure 1The recycle is loaded as described above with respect to stream 50. In other embodiments, a portion of the deasphalted upgraded oil 254 is recycled to the catalytic hydrogen-aquathermocracking reactor 36 as all or a portion of the recycle stream 50, either directly or via the mixing unit 14, mixing valve 22, and / or loading heater 18.

[0088] Effectively capture heavy large polyaromatic compounds and asphaltenes in Figure 3-5 The solid adsorbent material or mixture of solid adsorbent materials used in embodiments of the present invention include those characterized by high surface area, large pore volume, and broad pore size distribution. Types of adsorbent materials that are effective for contacting all or a portion of the catalytic hydro-hydrothermolysis effluent, either directly or after one or more different downstream processes, include molecular sieves, silica gels, activated carbon, activated alumina, silica-alumina gels, zinc oxide, clays such as attapulgite clay, fresh zeolite catalyst materials, used zeolite catalyst materials, spent catalysts from other refining operations, and mixtures of two or more of these materials. Effective adsorbent materials are characterized by any suitable shape, such as granules, extrudates, tablets, spheres, pellets, or natural shapes, having an average particle size in the range of about 0.01-4.0, 0.1-4.0, or 0.2-4.0 mm, an average pore size in the range of 1-5000, 1-2000, 5-5000, 5-2000, 100-5000, or 100-2000 nm, a pore volume in the range of about 0.08-1.2, 0.3-1.2, 0.5-1.2, 0.08-0.5, 0.1-0.5, or 0.3-0.5 cubic centimeters per gram, and a surface area of ​​at least about 100 square meters per gram. The amount of solid adsorbent material used in embodiments herein (weight basis, feed to adsorbent) is about 0.1:1-20:1, 0.1:1-10:1, 1:1-20:1, or 1:1-10:1.

[0089] In other embodiments, the solid adsorbent material comprises spent catalyst. In certain embodiments, the spent catalyst may be obtained from any type of reactor, such as a fixed bed, continuously stirred tank (CSTR), or tubular reactor, that needs to be taken off-stream for catalyst removal due to loss of utility of the material as a catalytic material at the end of its normal life. In certain embodiments, the spent catalyst may be obtained from any type of reactor that includes catalyst removal and replenishment in operation, such as a slurry bed, ebullating bed, or moving bed reactor. For example, catalyst that is normally taken out for regeneration or replacement may be used as a solid adsorbent material in any embodiment herein that uses a source solid adsorbent material. In other embodiments, such as when a membrane wall gasifier is integrated, overall process waste is significantly reduced by disposing of spent solid catalyst materials rather than discarding them as waste materials (which incurs considerable expense and involves environmental considerations).

[0090] Advantageously, the processes and systems of the present invention combine low pressure operation, low cost of highly dispersed catalytic particles, water and low hydrogen requirements, including the ability to utilize low hydrogen partial pressure off-gas streams, thereby increasing the conversion of heavy oils and improving their asphaltene stability to reduce their aggregation, association and ultimately coke formation.

[0091] The present process and system enable the economical upgrading of heavy petroleum products, such as atmospheric and / or vacuum residues. Furthermore, otherwise low-value by-products can be used to generate valuable commodities (which in turn can be used as starting materials in the petrochemical industry), for energy or steam generation, or for use in upgrading processes. The present process and system enable a low-hydrogen demand process that can utilize waste hydrogen streams from refineries, such as refinery fuel gas (RFG) systems.

[0092] Using the catalytic hydrogen-aquathermolysis process described herein, refiners can improve refining economics by minimizing the amount of coke, asphaltenes, and wasted hydrogen. Dispersed catalytic particles can be derived from two, three, or more metals, with relatively small amounts of water and hydrogen injected. The net result is a reduction in hydrogen abstraction reactions occurring during the thermal cracking process, leading to improved heavy oil conversion. The process described herein is further complemented by the integration of a solvent deasphalting process.

[0093] The process and system of the present invention have been described above and in the accompanying drawings; however, modifications will be apparent to one of ordinary skill in the art, and the scope of the invention is defined by the following claims.

Claims

1. A process for upgrading heavy oil, the process integrating thermal cracking, hydrogenolysis and catalytic aquathermolysis, the process comprising: Loading into catalytic hydrogen-water thermal cracking reactor Heavy oil feed, Water, in an amount of 1 to 20% by weight relative to the mass of the heavy oil feed, Hydrogen, in an amount of 1 to 1000 normal cubic meters of hydrogen per cubic meter of heavy oil feed, a viscosity reducer in an amount of 10 to 40 wt% relative to the mass of the heavy oil feed, and catalytic material in an amount of 100 to 20,000 parts per million by weight of active catalyst particles relative to the mass of the heavy oil feed; At a hydrogen pressure not exceeding 60 bar hydrogen partial pressure, a temperature of at least 400° C. and a temperature of at least 0.1 h based on fresh feed relative to the reactor volume -1 The method further comprises operating the catalytic hydrogen-aquathermolysis reactor at a liquid hourly space velocity of at least 1.0, discharging a mixed gaseous and liquid reactor effluent from the catalytic hydrogen-aquathermolysis reactor, and passing the mixed gaseous and liquid reactor effluent to a vapor-liquid separator to separate a light effluent from an upgraded heavy oil effluent, wherein the upgraded heavy oil effluent has a stability P value of at least 1.

2.

2. The process of claim 1 , wherein the heavy oil feed comprises vacuum residue, atmospheric residue, or a combination of vacuum residue and atmospheric residue.

3. The process of claim 2, wherein the heavy oil feed further comprises effluent from one or more of a downstream fractionator unit, a solvent deasphalting unit, a delayed coking unit, a gasification unit, or a catalytic hydroprocessing unit.

4. The process according to any one of claims 1 to 3, further comprising: Prior to loading the reactor, mixing the heavy oil feed, water, catalytic particles, and viscosity reducer at a pressure in the range of 1-30 bar and at a temperature of 40° C. to 80° C. to produce a first mixture; preheating the first mixture to a reaction temperature in the range of 400° C. to 500° C.; mixing the preheated first mixture with hydrogen and water to provide a second mixture, and The second mixture is loaded into the reactor.

5. The process of claim 4, wherein generating and preheating the first mixture occurs in the absence of added hydrogen.

6. The process according to any one of claims 1 to 3, further comprising: Prior to loading the reactor, mixing the heavy oil feed, water, catalytic particles, and viscosity reducer at a temperature of up to 100° C. to produce a first mixture; preheating the first mixture to a temperature below the reaction temperature; mixing the preheated first mixture with hydrogen and water to provide a second mixture, and The second mixture is loaded into the reactor, wherein the second mixture is heated to a reaction temperature in the range of 400°C to 500°C in the reactor.

7. The process of claim 6, wherein generating and preheating the first mixture occurs in the absence of added hydrogen.

8. The process according to any one of claims 1 to 3, further comprising: mixing the heavy oil feed, water, catalytic particles, and viscosity reducer at a temperature of up to 100° C. to produce a first mixture prior to charging into a reactor; preheating the first mixture to a temperature below the reaction temperature; mixing the preheated first mixture with hydrogen and water to provide a second mixture, preheating the second mixture upstream of the reactor to a reaction temperature in the range of 400°C to 500°C; and The preheated second mixture was charged into the reactor.

9. The process of claim 8, wherein generating and preheating the first mixture occurs in the absence of added hydrogen.

10. The process of claim 9, wherein during the step of preheating the first mixture, catalytic material is converted into active catalyst particles.

11. The process of claim 4, wherein the catalytic material is provided in the form of particles that decompose during the preheating step to form active catalyst particles.

12. The process of claim 6, wherein the catalytic material is provided in the form of particles that decompose during the preheating step to form active catalyst particles.

13. The process of claim 10, wherein the catalytic material is provided in the form of catalyst particles that decompose during the first preheating step to form active catalyst particles.

14. The process of claim 4, wherein the catalytic material is provided in the form of a catalytic metal precursor that forms active catalyst particles during the preheating step.

15. The process of claim 6, wherein the catalytic material is provided in the form of a catalytic metal precursor that forms active catalyst particles during the preheating step.

16. The process of claim 10, wherein the catalytic material is provided in the form of a catalytic metal precursor that forms active catalyst particles during the first preheating step.

17. The process of claim 1 further comprising recycling at least a portion of the light effluent from the reactor effluent back to the reactor.

18. The process of claim 1, wherein the reactor is operated under the following conditions: Hydrogen partial pressure of 5-60 bar; a temperature of 400-500°C; and In 0.1-20h -1 The liquid hourly space velocity (LHSV) relative to the catalyst, based on fresh feed, is in the range of .

19. The process of claim 1 further comprising passing the reactor effluent to a separation zone to recover hydrocarbon products and bottoms.

20. The process of claim 19, further comprising sending the bottoms and C3 to C8 light paraffins to a solvent deasphalting unit to separate the deasphalted oil phase and the asphalt phase at a solvent to bottoms ratio in the range of 2:1 to 10:1 on a weight to weight basis, collecting the deasphalted upgraded oil as the deasphalted oil phase; and The bitumen and catalyst particles are discharged as a bitumen phase.

21. The process of claim 20, wherein all or part of the bituminous phase comprising catalyst particles is recycled to catalytic hydrogen-aquathermolysis.

22. The process of claim 1, further comprising sending the upgraded heavy oil effluent and C3 to C8 light paraffins to a solvent deasphalting unit to separate the deasphalted oil phase and the asphalt phase at a solvent to upgraded heavy oil ratio in the range of 2:1 to 10:1 on a weight to weight basis, collecting the deasphalted upgraded oil as a deasphalted oil phase; and Pitch and catalyst particles are discharged as the pitch phase.

23. The process of claim 22, wherein all or part of the bituminous phase comprising catalyst particles is recycled to catalytic hydrogen-aquathermolysis.

24. The process according to claim 1, comprising mixing an upgraded heavy oil effluent with a paraffinic solvent and an effective amount of a solid adsorbent material at a temperature and pressure below the critical pressure and temperature of the solvent to promote solvent flocculation of solid asphaltenes and for a time sufficient to adsorb sulfur- and nitrogen-containing polynuclear aromatic molecules contained in the upgraded heavy oil effluent onto the solid adsorbent material to form a mixture; transferring the mixture to a first separation vessel; separating a solid phase comprising asphaltenes and solid adsorbent material from a liquid phase comprising deasphalted oil and a paraffinic solvent; transferring the solid phase to a filtration vessel with an aromatic and / or polar solvent to desorb the adsorbed contaminants and recover the regenerated solid adsorbent material; and The liquid phase is passed to a second separation vessel to separate the deasphalted oil and the paraffinic solvent, and optionally at least a portion of the separated paraffinic solvent is recycled to the step of mixing the reactor effluent with the paraffinic solvent and an effective amount of a solid adsorbent material.

25. The process of claim 19, comprising mixing the bottoms with a paraffinic solvent and an effective amount of a solid adsorbent material at a temperature and pressure below the critical pressure and temperature of the solvent to promote solvent flocculation of the solid asphaltenes and for a time sufficient to adsorb sulfur- and nitrogen-containing polynuclear aromatic molecules on the solid adsorbent material to form a mixture; transferring the mixture to a first separation vessel; separating a solid phase comprising asphaltenes and solid adsorbent material from a liquid phase comprising deasphalted oil and a paraffinic solvent; passing the solid phase to a filtration vessel with an aromatic and / or polar solvent to desorb the adsorbed contaminants and recover the regenerated solid adsorbent material; and The liquid phase is passed to a second separation vessel to separate the deasphalted oil and the paraffinic solvent, and optionally at least a portion of the separated paraffinic solvent is recycled to the step of mixing the bottoms with the paraffinic solvent and an effective amount of a solid adsorbent material.

26. The process of claim 1, comprising mixing the upgraded heavy oil effluent and a paraffinic solvent in a first separation vessel at a temperature and pressure below the critical pressure and temperature of the paraffinic solvent to promote solvent flocculation of solid asphaltenes; discharging an asphalt stream from the first separation vessel; passing the combined deasphalted oil and paraffinic solvent stream from the first separation vessel, and an effective amount of solid adsorbent material to a second separation vessel; maintaining the mixture in the second separation vessel for a time sufficient for the solid adsorbent material to adsorb remaining asphaltenes and / or sulfur-containing polynuclear aromatic molecules and / or nitrogen-containing polynuclear aromatic molecules in the deasphalted oil; separating and recovering at least a portion of the paraffinic solvent from the deasphalted oil and adsorbent material; passing the deasphalted oil and solid adsorbent material from the second separation vessel to a filtration vessel with an aromatic and / or polar solvent to desorb the adsorbed contaminants and recover regenerated solid adsorbent material; and The mixture of the deasphalted oil and the aromatic and / or polar solvent is sent to a fractionator to recover the aromatic and / or polar solvent and the deasphalted oil.

27. The process of claim 19, comprising mixing the bottoms and a paraffinic solvent in a first separation vessel at a temperature and pressure below the critical pressure and temperature of the paraffinic solvent to promote solvent flocculation of the solid asphaltenes; discharging an asphalt stream from the first separation vessel; passing the combined deasphalted oil and paraffinic solvent stream from the first separation vessel, and an effective amount of solid adsorbent material to a second separation vessel; maintaining the mixture in the second separation vessel for a time sufficient for the solid adsorbent material to adsorb remaining asphaltenes and / or sulfur-containing polynuclear aromatic molecules and / or nitrogen-containing polynuclear aromatic molecules in the deasphalted oil; separating and recovering at least a portion of the paraffinic solvent from the deasphalted oil and adsorbent material; passing the deasphalted oil and solid adsorbent material from the second separation vessel to a filtration vessel with an aromatic and / or polar solvent to desorb the adsorbed contaminants and recover regenerated solid adsorbent material; and The mixture of the deasphalted oil and the aromatic and / or polar solvent is sent to a fractionator to recover the aromatic and / or polar solvent and the deasphalted oil.

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