Process and system for upgrading heavy oil unconverted by hydrocracker

Abstract

Methods and systems for upgrading hydrocracker unconverted heavy oil are provided. The invention can be used to upgrade unconverted heavy oil, such as residue derived from a hydrocracking process, and can be used to upgrade such residue to form fuel oil, such as marine low sulfur fuel oil. A combination of solutions is used in the invention, including use of a separation process on unconverted heavy oil comprising hydrocracker residue, combining an aromatic feed with the unconverted heavy oil, and then subjecting the unconverted heavy oil to a hydroprocessing process.

Description

[0001] This application is a divisional application of Chinese patent application No. 201880075001.9, filed on November 21, 2018, entitled "Method and System for Upgrading Unconverted Heavy Oil in Hydrocracking Unit".

[0002] Cross-references to related applications

[0003] This application relates to and claims priority to U.S. Provisional Application No. 62 / 588,924, filed November 21, 2017, entitled “VR HYDROCRACKER UNCONVERTED OILUPGRADING PROCESS,” the entire contents of which are incorporated herein by reference. Technical Field

[0004] This invention relates to methods and systems for upgrading unconverted heavy oil from hydrocracking processes. The invention can be used to upgrade unconverted heavy oil, such as residue oil derived from hydrocracking processes, and can be used to upgrade such residue oil to form fuel oils such as low-sulfur marine fuel oil. Background Technology

[0005] Oil refineries worldwide face numerous challenges, including deteriorating crude oil quality, stringent product specifications, and changing market demands for various refined products. Refineries are using heavier and dirtier crude oil, resulting in increasing amounts of heavy oil fractions and residues with limited uses and lower value. Demand for high-value products, such as transportation fuels, is growing. Simultaneously, emissions and other specifications for transportation fuels such as gasoline and diesel are becoming increasingly stringent. Therefore, the oil industry is under pressure to convert process residues into light and middle fractions and increase production capacity while simultaneously improving product quality.

[0006] Many conversion methods can be used to convert low-value residue into more valuable transportation fuels, including decarbonization and hydrotreating for residue conversion and upgrading. In terms of distillate quality, the hydrotreating route is superior to the decarbonization route. Fractions produced through hydroconversion processes have lower levels of sulfur, nitrogen, aromatics, and other contaminants, better stability, and can meet stringent environmental regulations. The deep conversion of heavy oil and residue into light fractions via hydroconversion has become increasingly important.

[0007] Residue hydrocracking is a high-pressure, high-temperature hydroconversion method that uses a catalytically fluidized bed (EB) to upgrade low-value heavy oil to high-value products through thermal cracking in the presence of hydrogen. EB residue hydrocracking units can process heavier feedstocks than fixed-bed gas oil hydrocracking units. Residue hydrocracking units, such as LC-FINING, are particularly useful for increasing the production of high-quality diesel and kerosene while reducing residual fuel oil production. EB units also produce heavier products, such as vacuum gas oil (VGO), which can be further processed and upgraded to other products via FCC or hydrocracking. Residue hydrocracking units typically process 60-80% of the vacuum residue range, producing 20-40% of the vacuum residue range (vacuum bottoms, VTB) unconverted oil (UCO) product. The formation of sludge or sediment often limits residue conversion. UCO residue contains organic solids and fine hydrocracking catalyst powder, has extremely high viscosity, and is very prone to flocculation and forming a (semi-solid) slurry. It easily forms fouling in processing equipment, making further processing almost impossible. Therefore, UCO residue is generally considered to have low value and can be sent to a coking unit (a unit operation designed to process slurries) or blended into (fuel) fuel oil without further processing or upgrading.

[0008] Due to the aforementioned characteristics of UCO residue, and the fact that it retains sulfur compounds that are most resistant to hydrotreating—those that survived prior to deep hydrotreating—a suitable hydrotreating method has yet to be found to improve the UCO residue for use in other products.

[0009] The regulatory directives also incentivize the development of new solutions in new hydrotreating systems and methods. In particular, the new IMO sulfur specification for marine fuel oil, scheduled to come into effect on 1 January 2020, will reduce the maximum permissible sulfur content of fuel oil used on ships operating outside designated control areas to 0.50% m / m (from 3.5%) (ISO 8217 and Annex VI of the IMO MARPOL Convention). This low sulfur tolerance limit severely restricts or eliminates the option of blending high-sulfur components (e.g., unconverted residue containing approximately 0.75–2.5% by weight sulfur) into fuel oil. Consequently, alternative methods are needed to meet the sulfur content limits of the 2020 IMO fuel oil specification, particularly for marine fuel oil.

[0010] Another very stringent management recommendation is that the sediment content after aging must be less than or equal to 0.1% according to ISO 10307-2 (also known as IP390). The sediment content requirement according to ISO 10307-1 (also known as IP375) differs from that according to ISO 10307-2 (also known as IP390). The sediment content requirement according to ISO 10307-2 is a more restrictive specification and corresponds to the specifications applicable to marine oils.

[0011] Given the above, new solutions are needed to address the issues related to upgraded unconverted heavy oil (UCO residuum) and to meet fuel oil regulations such as the IMO 2020 sulfur content limit.

[0012] Additional background information relating to the invention is provided in the publications and patents identified herein. Where permitted, each of these publications and patents is incorporated herein by reference in its entirety. Summary of the Invention

[0013] This invention addresses the aforementioned problems through an innovative combination of solutions, thereby allowing for further processing of UCO residue in a heavy oil hydrotreating processor. The solution also allows for the use of UCO residue in fuel oils in accordance with IMO 2020 regulations. Furthermore, it provides an innovative process option that integrates a residue hydrocracker and a UCO residue heavy oil hydrotreating processor.

[0014] In summary, the present invention relates to methods for upgrading unconverted heavy oil in a hydrotreating system, methods for preparing low-sulfur fuel oil from unconverted heavy oil, methods for upgrading a hydrotreating system, methods for stabilizing unconverted heavy oil, and methods for hydrotreating unconverted heavy oil. The invention also provides hydrotreating systems for use with these methods.

[0015] The methods and systems of this invention relate to the treatment of unconverted heavy oil feed containing hydrocracker residue, i.e., the unconverted heavy oil has already passed through a hydrotreating system including hydrocracking. Unconverted heavy oil (UCO) or residue is the portion of the hydrotreating system feed that has passed through the system and remains unconverted as hydrocracker residue (or sludge). The hydrocracker residue can be derived, for example, as a bottom product from an EB (electrolyte-bed) reactor, or it can be a bottom product from an atmospheric or vacuum distillation column (ATB or VTB) downstream of the EB process.

[0016] In the method and system for upgrading and reducing sulfur fuel oil of the present invention, unconverted heavy oil feed (or a mixture of UCO feed and aromatic feed) comprising hydrocracker residue is fed directly to a separation process, or more particularly a filtration process, to remove insoluble matter, thereby forming an unconverted heavy oil stream. The aromatic feed is then mixed with the unconverted heavy oil (UCO) feed to form a mixture, such that at least one aromatic feed is combined with the UCO feed before or after a separation process step (or more specifically, a filtration process step). The unconverted heavy oil stream (i.e., the mixture of UCO feed and aromatic feed) is then fed into a heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil stream from the unconverted heavy oil stream. The hydrotreated unconverted heavy oil stream is then further subjected to a recovery process to obtain products and / or further processing or treatment.

[0017] The methods and systems of the present invention for stabilizing unconverted heavy oil typically involve a low-solids UCO feedstock comprising hydrocracking residue and having less than about 0.5% by weight of solids. The UCO feedstock is fed to a filtration process to remove insolubles and, if necessary, mixed with an aromatic feedstock prior to filtration. The unconverted heavy oil stream is recovered, wherein the UCO heavy oil is stabilized and suitable for further processing.

[0018] In the method and system of the present invention for hydrotreating unconverted heavy oil containing hydrocracker residue, the unconverted heavy oil feed (or a mixture of UCO feed and aromatic feed) is directly introduced into the hydrotreating process. The unconverted heavy oil feed forms a hydrotreated heavy oil stream, which is then recovered or further processed.

[0019] The inventors were surprised to find that the aforementioned method and related system made it possible to process UCO residue oil (through a combination of mixing with aromatic feedstock, separation of insolubles and hydrotreating) to obtain unconverted residue oil after such treatment, which is then upgraded and suitable for, for example, low-sulfur fuel oil.

[0020] The embodiments of the present invention include:

[0021] 1) A method for upgrading unconverted heavy oil, the method comprising:

[0022] Unconverted heavy oil feed is provided from the hydrotreatment system, wherein the unconverted heavy oil feed includes hydrocracker residue;

[0023] Optionally, a first aromatic feed is added to the unconverted heavy oil feed to form a mixture;

[0024] The unconverted heavy oil feed or the mixture is directly fed into the separation process to remove insoluble matter, thereby forming an unconverted heavy oil stream;

[0025] Optionally, the second aromatic feed is combined with the unconverted heavy oil stream to form a second mixture;

[0026] The unconverted heavy oil stream or the second mixture is introduced into the heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil stream from the unconverted heavy oil stream or the second mixture.

[0027] Wherein at least one of the first aromatic feed or the second aromatic feed is combined with the unconverted heavy oil feed or the unconverted heavy oil stream; and optionally,

[0028] The hydrotreated heavy oil stream can be recovered or further processed.

[0029] 2) A method for preparing low-sulfur fuel oil from unconverted heavy oil, the method comprising:

[0030] Unconverted heavy oil feed is provided from the hydrotreatment system, wherein the unconverted heavy oil feed includes hydrocracker residue;

[0031] Optionally, a first aromatic feed is added to the unconverted heavy oil feed to form a mixture;

[0032] The unconverted heavy oil feed or the mixture is directly fed into the separation process to remove insoluble matter, thereby forming an unconverted heavy oil stream;

[0033] Optionally, the second aromatic feed is combined with the unconverted heavy oil stream to form a second mixture;

[0034] The unconverted heavy oil stream or the second mixture is introduced into the heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil stream from the unconverted heavy oil stream or the second mixture.

[0035] Wherein at least one of the first aromatic feed or the second aromatic feed is combined with the unconverted heavy oil feed or the unconverted heavy oil stream;

[0036] The hydrotreated heavy oil stream is fed into the fractionator; and

[0037] Recycle low-sulfur fuel oil products.

[0038] 3) A method for an upgrading and hydrogenation treatment system, the method comprising:

[0039] Unconverted heavy oil feed is provided from the hydrotreatment system, wherein the unconverted heavy oil feed includes hydrocracker residue;

[0040] Optionally, the first aromatic feed is added to the unconverted heavy oil feed to form a mixture;

[0041] The unconverted heavy oil feed or the mixture is directly fed into the separation process to remove insoluble matter, thereby forming an unconverted heavy oil stream;

[0042] Optionally, the second aromatic feed is combined with the unconverted heavy oil stream to form a second mixture;

[0043] The unconverted heavy oil stream or the second mixture is introduced into the heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil stream from the unconverted heavy oil stream or the second mixture.

[0044] Wherein at least one of the first aromatic feed or the second aromatic feed is combined with the unconverted heavy oil feed or the unconverted heavy oil stream; and optionally,

[0045] The hydrotreated heavy oil stream can be recovered or further processed.

[0046] 4) A method for stabilizing unconverted heavy oil containing less than about 0.5% by weight of solids, the method comprising:

[0047] Unconverted heavy oil feed is provided from the hydrotreating system, wherein the unconverted heavy oil feed comprises hydrocracking residue oil having less than about 0.5% by weight solids;

[0048] Optionally, aromatic feedstock is added to the unconverted heavy oil feedstock to form a mixture;

[0049] The unconverted heavy oil feed or the mixture is directly fed into a filtration process to remove insoluble matter, thereby forming an unconverted heavy oil stream; and

[0050] Recover the unconverted heavy oil stream;

[0051] The unconverted heavy oil stream is stabilized to make it suitable for further hydrotreating.

[0052] 5) A method for hydrotreating unconverted heavy oil, the method comprising:

[0053] Unconverted heavy oil feed is provided from the hydrotreatment system, wherein the unconverted heavy oil feed includes hydrocracker residue;

[0054] The unconverted heavy oil feed is introduced into the heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil feed stream from the unconverted heavy oil feed; and

[0055] The hydrotreated heavy oil stream can be recovered or further processed.

[0056] 6) The method according to any one of embodiments 1-5, wherein the unconverted heavy oil is oil that has passed through the hydrotreating system and remains unconverted.

[0057] 7) The method according to any one of embodiments 1-5, wherein the hydrotreating system comprises fluidized bed hydrocracking.

[0058] 8) The method according to any one of embodiments 1-5, wherein the unconverted heavy oil has been hydrocracking and demetallized.

[0059] 9) The method according to any one of embodiments 1-5, wherein the method provides a product for meeting IMO specifications for low-sulfur fuel oil.

[0060] 10) According to the method of embodiment 9, the sulfur content of the low-sulfur fuel oil is less than 0.5% by weight, or less than 0.3% by weight, or less than 0.1% by weight.

[0061] 11) Low-sulfur fuel oil prepared by the method according to any one of implementation schemes 1-3 or 5.

[0062] 12) The method according to any one of embodiments 1-3 or 5, wherein the method does not include a ripening or aging step.

[0063] 13) The method according to any one of embodiments 1-3 or 5, wherein the method does not include a settling step.

[0064] 14) According to the method of embodiment 5, the unconverted heavy oil feed has been directly fed from the hydrotreating system into the filtration process to remove insoluble matter, thereby forming the unconverted heavy oil feed.

[0065] 15) The method according to any one of embodiments 1-5, wherein the unconverted heavy oil feed comprises bottom products from a fluidized bed hydrocracking process.

[0066] 16) The method according to any one of embodiments 1-5, wherein the unconverted heavy oil feed is derived from atmospheric residue, vacuum residue, tar from a solvent deasphalting unit, atmospheric gas oil, vacuum gas oil, deasphalted oil, oil derived from tar sands or bitumen, oil derived from coal, heavy crude oil, oil derived from circulating oil waste and polymers, or combinations thereof.

[0067] 17) The method according to any one of embodiments 1-4, wherein the separation process includes filtration selected from screening, sieving, cross-flow filtration, backwashing filtration, or combinations thereof.

[0068] 18) The method according to embodiment 17, wherein the filtration comprises a filter membrane with an average pore size of less than 10 micrometers.

[0069] 19) The method according to embodiment 17, wherein the filtration comprises a filter membrane with an average pore size of less than 5 micrometers.

[0070] 20) The method according to embodiment 17, wherein the filtration comprises a filter membrane with an average pore size of less than 2 micrometers.

[0071] 21) The method according to embodiment 18, wherein the filter membrane is composed of a material selected from metals, polymers, ceramics, glass, nanomaterials or combinations thereof.

[0072] 22) The method according to embodiment 18, wherein the filter membrane is composed of a metal selected from stainless steel, titanium, bronze, aluminum, nickel, copper and their alloys.

[0073] 23) The method according to embodiment 18, wherein the membrane is further coated with an inorganic metal oxide coating.

[0074] 24) The method according to any one of embodiments 1-4, wherein the aromatic feed is selected from light circulating oil, medium circulating oil, heavy circulating oil, oil slurry, vacuum gas oil or mixtures thereof.

[0075] 25) The method according to any one of embodiments 1-4, wherein the aromatic feed comprises more than about 20% by volume of an aromatic compound, or more than about 30% by volume of an aromatic compound, or more than about 50% by volume of an aromatic compound, or more than about 70% by volume of an aromatic compound, or more than about 90% by volume of an aromatic compound.

[0076] 26) The method according to any one of embodiments 1-3 or 5, wherein the feed for the hydrogenation process meets one or more of the following: API of -5 to 15, sulfur content in the range of 0.7 to 3.5% by weight, residual carbon content of 8 to 35% by weight, or total Ni and V content of less than 150 ppm.

[0077] 27) The method according to any one of embodiments 1-3 or 5, wherein the hydrotreated heavy oil stream from the hydrotreating process satisfies one or more of the following: API in the range of 2 to 18, sulfur content in the range of 0.05 to 0.70% by weight, residual carbon content in the range of 3 to 18% by weight, or total Ni and V content less than 30 ppm.

[0078] 28) The method according to any one of embodiments 1-3 and 5, wherein the heavy oil hydrotreating process includes a catalyst selected from demetallization catalysts, desulfurization catalysts, or combinations thereof.

[0079] 29) The method according to any one of embodiments 1-3 and 5, wherein the heavy oil hydrotreating process includes a catalyst composition comprising about 5-20 vol% of a staged and demetallized catalyst, about 10-30 vol% of a transition conversion catalyst and about 50-80 vol% of a deep conversion catalyst.

[0080] 30) The method according to any one of embodiments 1-3 and 5, wherein the heavy oil hydrotreating process includes a catalyst composition comprising about 10-15 vol% of a staged and demetallized catalyst, about 20-25 vol% of a transition conversion catalyst and about 60-70 vol% of a deep conversion catalyst.

[0081] 31) A hydrotreating system for upgrading unconverted heavy oil according to any one of embodiments 1-3 and 5, the system comprising the following hydrotreating units: an integrated heavy oil processor (HOT), a filtration system (FS), a heavy oil stripping tower (HOS), one or more high-pressure high-temperature separators (HPHT), one or more medium-pressure high-temperature separators (MPHT), an atmospheric distillation column fractionator (ACF), an optional vacuum distillation column fractionator (VCF), and an optional HOT stripping tower;

[0082] The hydrotreating system units are fluidly connected and fluidly linked to allow the hydrocarbon-containing feed stream to flow through the hydrotreating process. The hydrotreating system units are arranged according to the following conditions:

[0083] The FS unit is located upstream of the HOT unit and downstream of the HOS unit;

[0084] The HPHT unit is located upstream of the MPHT unit;

[0085] The HOS unit is located upstream of the VCF unit;

[0086] The HOT stripping tower is located downstream of the HOT unit;

[0087] The HPHT unit and the MPHT unit are located upstream of the HOS unit;

[0088] The HPHT unit and the optional MPHT unit are located upstream of the HOT unit;

[0089] The HPHT unit and the optional MPHT unit are located upstream of the ACF and VCF units; and

[0090] The ACF unit, and optionally the VCF unit, are located downstream of the HOT unit.

[0091] 32) The hydrogenation treatment system according to embodiment 31, wherein the system units are arranged in the following flow order: HOS unit, followed by FS unit, followed by VCF unit, followed by HOT unit, and then ACF unit.

[0092] 33) The hydrogenation treatment system according to embodiment 31, wherein the system units are arranged in the following flow order: HOS unit, followed by VCF unit, followed by FS unit, followed by HOT unit, and then ACF unit.

[0093] 34) The hydrogenation treatment system according to embodiment 31, wherein the system units are arranged in the following flow order: HOS unit, followed by FS unit, followed by HOT unit, and then ACF unit.

[0094] 35) The hydrogenation treatment system according to embodiment 31, wherein the system units are arranged in the following flow order: HOS unit, followed by FS unit, followed by HOT unit, followed by ACF unit, and then VCF unit.

[0095] 36) The hydrotreating system according to embodiment 31, wherein the system units are arranged in the following flow order: HOS unit, followed by FS unit, followed by VCF unit; and HOT unit, followed by ACF unit, wherein the VCF unit includes a bottom fraction recirculation fluid connection, the connection being connected to the feed flow connection of the HOT unit.

[0096] 37) The hydrogenation treatment system according to embodiment 31, wherein the system units are arranged in the following flow order: HOS unit, followed by FS unit, followed by HOT unit, followed by ACF unit, and then VCF unit.

[0097] 38) The hydrotreating system according to embodiment 31, wherein the system units are arranged in the following flow order: HOS unit, followed by FS unit, followed by VCF unit, followed by first HOT unit, followed by HPHT unit, followed by HOT stripping tower unit, wherein the HOT stripping tower unit includes a top fraction recirculation fluid connector, the connector being connected to the feed flow connector of the HOS unit; and a second HOT unit, followed by ACF unit; wherein the HPHT unit following the first HOT unit includes a top fraction recirculation fluid connector, the connector being connected to the feed flow connector of the first HOT unit.

[0098] 39) A hydrogenation treatment system according to any one of embodiments 31-35 or 37, wherein the HPHT unit and the MPHT unit are located downstream of the HOT unit and upstream of the ACF unit.

[0099] 40) The hydrogenation treatment system according to embodiment 36, wherein the HPHT unit is located upstream of the HOT unit, and the HPHT unit is located downstream of the HOT unit and upstream of the ACF unit.

[0100] 41) The hydrogenation treatment system according to embodiment 38, wherein the HPHT unit is located upstream of the second HOT unit, and the HPHT unit is located downstream of the second HOT unit and upstream of the ACF unit.

[0101] 42) A hydrogenation treatment system according to any one of embodiments 31-41, wherein the system is configured to add hydrogen, other feed streams, quenched gas or liquid, or combinations thereof to one or more system units or fluid connections between units.

[0102] 43) A hydrotreating system according to any one of embodiments 35 or 37, wherein the VCF unit includes a bottom fraction recirculation fluid connection connected to the feed flow connection of the HOT unit; and / or includes a bottom fraction recirculation fluid connection connected to the feed flow connection of the fluidized bed reactor system.

[0103] 44) A hydrotreating system according to any one of embodiments 31-43, wherein the system includes a fluid connection and is configured to introduce a feed stream upstream of the system's HOS unit and optionally downstream of the HOS unit.

[0104] 45) A hydrotreating system according to any one of embodiments 31-44, wherein the system includes a fluid connection and is configured for a feed stream selected from: unconverted heavy oil, unconverted vacuum residue, unconverted vacuum residue from a fluidized bed hydrocracker, a combination of unconverted vacuum residue from a fluidized bed hydrocracker with a diluent or fraction, unconverted atmospheric residue from a fluidized bed hydrocracker, or a combination of unconverted atmospheric residue from a fluidized bed hydrocracker with a diluent or fraction.

[0105] 46) The hydrotreating system according to embodiment 45, wherein the diluent or fraction is selected from kerosene, diesel, FCC / RFCC light cycle oil, or FCC / RFCC heavy cycle oil, FCC / RFCC diluted crude oil (DCO) / slurry, vacuum gas oil (VGO), atmospheric residue (AR), vacuum residue (VR), or combinations thereof.

[0106] 47) A hydrotreating system according to any one of embodiments 45-46, wherein the feed stream originates from a fluidized bed reactor or an atmospheric column or a heavy oil stripping column, and optionally the operating conditions are from about 2 psig to about 300 psig and the temperature is from about 160°F to about 720°F.

[0107] 48) A hydrotreating system according to any one of embodiments 45-46, wherein the feed stream is the bottom product of a fluidized bed vacuum tower, and optionally the operating conditions are a vacuum pressure of about 20-700 mm Hg and a temperature of about 176-720°F.

[0108] 49) A hydrotreating system according to any one of embodiments 45-48, wherein the feed stream further comprises refining process unit products with a boiling range of about 180-1050°F, or 1050-1700°F or 180-1700°F.

[0109] 50) A hydrogenation treatment system according to any one of embodiments 31 to 49, wherein the FS unit is a backwash filter, a cross-flow filter, a cartridge filter, or a combination thereof.

[0110] 51) The hydrogenation processing system according to embodiment 50, wherein the FS unit is configured to operate at a pressure in the range of about 10-600 psig and a temperature in the range of about 176-700°F.

[0111] 52) A hydrotreating system according to any one of embodiments 31-51, wherein the unconverted heavy oil feed stream or feed stream component is filtered before entering the hydrotreating system for processing, optionally in a backwash filter, cross-flow filter, cartridge filter or combination thereof.

[0112] 53) A hydrotreating system according to any one of embodiments 31-52, wherein the system is configured to provide the feed stream to the HOT unit at a pressure in the range of about 1000-3500 psig and a temperature in the range of about 500-900°F or 500-750°F.

[0113] 54) A hydrotreating system according to any one of embodiments 31-53, wherein the HOT unit comprises an upflow fixed-bed reactor, a downflow fixed-bed reactor or a combination thereof, optionally wherein any one of the reactors is a multi-catalyst bed reactor, or a plurality of single-catalyst bed reactors or a combination thereof.

[0114] 55) The hydrogenation treatment system according to embodiment 54, wherein the system is configured to provide the addition of quench gas and / or quench liquid between reactors or reactor beds, optionally wherein a heat exchanger is provided between HOT unit reactors.

[0115] 56) A hydrogenation treatment system according to any one of embodiments 3-55, wherein the effluent from the HOT unit is optionally cooled in a heat exchanger and flashed in the HPHT unit at a temperature in the range of about 550-800°F. (Overhead effluent).

[0116] 57) A hydrotreating system according to any one of embodiments 31-35, wherein the HPHT unit is located downstream of the HOT unit and upstream of the ACF unit, and wherein the HPHT unit includes a vapor fractionation connector connected to the HPHT unit located upstream of the HOS unit.

[0117] 58) The hydrogenation treatment system according to embodiment 37, wherein the system further includes an HPHT unit between the HOT unit and the ACF unit, and wherein the system includes a fluid connection to guide vapor from the HPHT unit to the HOT high-pressure loop for cooling, water washing, hydrogen sulfide removal and ammonia removal.

[0118] 59) The hydrogenation treatment system according to embodiment 36, wherein the system further includes an HPHT unit upstream of the HOT unit, wherein overhead vapor from the HPHT unit is used as part or all of the gas feed to the HOT unit.

[0119] 60) A hydrotreating system according to any one of embodiments 31-59, wherein the system is configured to produce bottom products of the ACF unit, optionally producing low-sulfur fuel oil products from the ACF unit.

[0120] 61) The hydrogenation processing system according to embodiment 60, wherein the system is configured to deliver the bottom product of the ACF unit to the VCF unit.

[0121] 62) The hydrotreating system according to embodiment 61, wherein the system is configured to produce bottom products of the VCF unit, optionally producing low-sulfur fuel oil products from the VCF unit. Attached Figure Description

[0122] Figures 1 to 7 Non-limiting aspects of the method configuration and embodiments according to the present invention and claims are illustrated. The scope of the invention is not limited by these illustrations and should be understood as being defined by the claims. Detailed Implementation

[0123] Typically, a method for upgrading unconverted heavy oil includes: providing an unconverted heavy oil feed from a hydrotreating system, wherein the unconverted heavy oil feed comprises hydrocracker residue; optionally, adding a first aromatic feed to the unconverted heavy oil feed to form a mixture; allowing the unconverted heavy oil feed or the mixture to directly enter a separation process to remove insolubles, thereby forming an unconverted heavy oil stream; optionally, combining a second aromatic feed with the unconverted heavy oil stream to form a second mixture; allowing the unconverted heavy oil stream or the second mixture to enter a heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil stream from the unconverted heavy oil stream or the second mixture; wherein at least one of the first or second aromatic feed is combined with the unconverted heavy oil feed or the unconverted heavy oil stream; and optionally, recovering or further processing the hydrotreated heavy oil stream.

[0124] The present invention discloses a method for preparing low-sulfur fuel oil from unconverted heavy oil, the method comprising: providing unconverted heavy oil feed from a hydrotreating system, wherein the unconverted heavy oil feed comprises hydrocracker residue; optionally, adding a first aromatic feed to the unconverted heavy oil feed to form a mixture; allowing the unconverted heavy oil feed or the mixture to directly enter a separation process to remove insoluble matter, thereby forming an unconverted heavy oil stream; optionally, combining a second aromatic feed with the unconverted heavy oil stream to form a second mixture; allowing the unconverted heavy oil stream or the second mixture to enter a heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil stream from the unconverted heavy oil stream or the second mixture; wherein at least one of the first aromatic feed or the second aromatic feed is combined with the unconverted heavy oil feed or the unconverted heavy oil stream; allowing the hydrotreated heavy oil stream to enter a fractionator; and recovering the low-sulfur fuel oil product.

[0125] The method of the present invention for an upgrading hydrotreating system comprises: providing unconverted heavy oil feed from the hydrotreating system, wherein the unconverted heavy oil feed comprises hydrocracker residue; optionally, adding a first aromatic feed to the unconverted heavy oil feed to form a mixture; allowing the unconverted heavy oil feed or the mixture to directly enter a separation process to remove insolubles, thereby forming an unconverted heavy oil stream; optionally, combining a second aromatic feed with the unconverted heavy oil stream to form a second mixture; allowing the unconverted heavy oil stream or the second mixture to enter a heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil stream from the unconverted heavy oil stream or the second mixture; wherein at least one of the first aromatic feed or the second aromatic feed is combined with the unconverted heavy oil feed or the unconverted heavy oil stream; and optionally, recovering or further processing the hydrotreated heavy oil stream.

[0126] The method of the present invention for stabilizing unconverted heavy oil containing less than about 0.5% by weight solids, the method comprising: providing an unconverted heavy oil feed from a hydrotreatment system, wherein the unconverted heavy oil feed comprises hydrocracking residue having less than about 0.5% by weight solids; optionally, adding an aromatic feed to the unconverted heavy oil feed to form a mixture; allowing the unconverted heavy oil feed or mixture to directly enter a filtration process to remove insolubles, thereby forming an unconverted heavy oil stream; and recovering the unconverted heavy oil stream; wherein the unconverted heavy oil stream is stabilized to make it suitable for further hydrotreatment.

[0127] The present invention provides a method for hydrotreating unconverted heavy oil, the method comprising: providing unconverted heavy oil feed from a hydrotreating system, wherein the unconverted heavy oil feed comprises hydrocracker residue; introducing the unconverted heavy oil feed into a heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil feed stream from the unconverted heavy oil feed; and recovering or further processing the hydrotreated heavy oil feed stream.

[0128] The unconverted heavy oil used in the methods and systems of this invention, also referred to herein as UCO, UCO heavy oil, or UCO residue, includes hydrocracker residue or residue components. Thus, UCO heavy oil is unconverted oil that has passed through a hydrotreating system including hydrocracking and in which hydrocracker residue has been formed. Typically, such residue is derived as a bottom product from a fluidized bed (EB) reactor process, but can also be derived as an unconverted heavy oil residue from a vacuum distillation column (ATB) or VTB. During hydrotreating, the unconverted heavy oil may undergo both hydrocracking and demetallization simultaneously.

[0129] The UCO heavy oil used in the methods and systems of this invention differs from heavy oil that can be used as feedstock for hydrotreating systems in that the UCO heavy oil used herein has already undergone hydrotreating. Heavy oil feedstocks that can be used as unprocessed feedstocks typically include atmospheric residue, vacuum residue, tar from solvent deasphalting units, atmospheric gas oil, vacuum gas oil, deasphalted oil, oil derived from tar sands or bitumen, oil derived from coal, heavy crude oil, oil derived from circulating oil waste and polymers, or combinations thereof. UCO feedstocks for the methods and systems of this invention can be obtained from these sources after hydrotreating them in a hydrotreating system that includes hydrocracking to form hydrocracker residue.

[0130] The UCO heavy oil feed used may consist only of hydrocracking residue, for example, derived from EB bottom products, or may include other suitable feed components in combination with hydrocracking residue. Preferably, the UCO heavy oil feed is primarily hydrocracking residue, but may also contain more than about 70% by volume, or more than about 90% by volume. The UCO heavy oil feed may also contain more than one hydrocracking residue component. Other suitable components for the UCO heavy oil feed include, for example, the heavy oil feed described above or its hydrotreated form, and other suitable blends including the aromatic feed components described herein.

[0131] Aromatic feedstocks combined with UCO heavy oil feedstocks typically include a significant aromatic component, for example, greater than about 20% by volume, or greater than about 30% by volume, or greater than about 50% by volume, or greater than about 70% by volume, or greater than about 90% by volume. Suitable aromatic feedstocks can be selected from light cycle oil (LCO), medium cycle oil (MCO), heavy cycle oil (HCO), decanted oil (DCO), or slurry oil, vacuum gas oil (VGO), or mixtures thereof. Aromatic UCO or deasphalted oil (DAO) from hydrocracking processes can also be used.

[0132] Aromatic feed can be mixed with UCO heavy oil feed before or after the UCO feed or a mixture of UCO feed and aromatic feed is sent to the subsequent separation process, or more specifically, before or after the filtration process. Aromatic feed can also be mixed with UCO heavy oil feed before and after the separation (filtration) process step.

[0133] The boiling point of the aromatic feed added to the UCO feed is preferably 250-1300°F, more preferably 350-1250°F, and most preferably 500-1200°F. Light aromatic solvents such as benzene, toluene, xylene, or Hi-Sol are undesirable for use in the aromatic feed. Alkane solvents, such as hydrotreated diesel and FT wax, are also unsuitable as aromatic feedstocks. The API specific gravity of the aromatic feed is preferably -20 to 20 degrees, more preferably -15 to 15 degrees, and most preferably -10 to 15 degrees. The aromatic content in the aromatic feed can be determined by compositional analysis (22×22) or SARA testing, and is preferably >20%, more preferably >30%. The viscosity of the aromatic feed at 100°C is preferably 0.2-100 cSt, more preferably 1-60 cSt. The amount of aromatic feed is preferably 3-20%, more preferably 5-15%, and most preferably 5-10%.

[0134] UCO heavy oil feed, whether alone or in combination with aromatic feed before a separation (filtration) process step, is preferably fed directly into the separation process, or more specifically, the filtration process step, without intermediate steps. In this regard, the description of "feeding unconverted heavy oil feed or mixture directly to the separation process" or "feeding unconverted heavy oil feed or mixture directly to the filtration process" is intended to exclude intermediate steps. In particular, it is intended that certain intermediate steps, such as ripening or aging processes or settling steps, be excluded from the process before the separation or filtration of UCO heavy oil feed or its mixture with aromatic compound feed.

[0135] Unconverted heavy oil feed, whether alone or in combination with aromatic compound feed to form a mixture, is directly introduced into the separation process step, or more specifically, into the filtration process step. Although the separation process is preferably a filtration process, suitable equivalent processes can be used instead, or in addition to the filtration process step. However, as stated above, aging, maturation, or settling steps are not intended to be used prior to the separation or filtration process step.

[0136] Separation or filtration steps remove insoluble substances from the UCO heavy oil stream, including, for example, catalyst fines, particles, precipitates, agglomerated oil, and aggregates. Preferably, the separation process includes or is a filtration process or step. Suitable filtration methods typically include sieving, screening, cross-flow filtration, backwashing filtration, or combinations thereof. Preferred filtration methods include membrane filtration methods, such as microfiltration, which use membranes having an average pore size of less than 10 micrometers, more particularly, less than 5 micrometers, or less than 2 micrometers. Although not limited thereto, the filter membrane can be made of materials selected from metals, polymeric materials, ceramics, glass, nanomaterials, or combinations thereof. Suitable metals include stainless steel, titanium, bronze, aluminum, nickel, copper, and their alloys. Such membranes can also be coated with various materials for a variety of reasons, including inorganic metal oxide coatings.

[0137] A relevant aspect of this invention relates to the use of filtration as a means of stabilizing UCO heavy oil. In this respect, the inventors have surprisingly discovered that, by using the filtration method according to the invention, this difficult and unstable hydrocracking residue oil can be stabilized to prevent sedimentation and other instabilities. The aromatic feedstocks described herein can also be combined with UCO heavy oil and subjected to such a filtration process to stabilize the UCO heavy oil and make it suitable for further hydrotreating.

[0138] The invented heavy oil hydrotreating (HOT) method is used for hydrotreating unconverted heavy oil feed or a mixture of UCO heavy oil feed and aromatics feed. Suitable operating conditions generally include ranges known in the art, for example, ranges that may be known for reactor processes in residual oil desulfurization systems (RDS), with notable exceptions. For the heavy oil hydrotreating (HOT) according to the invention, the reactor space velocity is typically low, for example, from about 0.06 to 0.25 hr. -1 Within this range, the idle speed used in RDS systems is typically between approximately 0.15 and 0.40 hr. -1 Within the specified range. For HOT operation, the target catalyst lifetime is also significantly increased, typically 2-3 years compared to 6-14 months for RDS systems. Other HOT operating conditions include: reactor pressure of approximately 2500 psig (2000-3000 psig); average reactor temperature of 690-770°F; hydrogen-to-oil ratio of 4500-5000 SCFB; and hydrogen consumption of 500-1200 SCFB.

[0139] Heavy oil hydrotreating (HOT) units may include upstream fixed-bed reactors, downstream fixed-bed reactors, or combinations thereof. Any of these reactors may be a multi-catalyst-bed reactor, or multiple single-catalyst-bed reactors, or a combination thereof.

[0140] Certain feedstock and product specifications are also applicable to the HOT process. For example, feedstocks for the hydrotreating process typically meet one or more of the following conditions: API content between -5 and 15, sulfur content between 0.7 and 3.5 wt%, residual carbon content between 8 and 35 wt%, or total Ni and V content less than 150 ppm. Hydrotreated heavy oil streams from the hydrotreating process typically also meet one or more of the following conditions: API range of 2 to 18, sulfur content between 0.05 and 0.70 wt%, residual carbon content between 3 and 18 wt%, or total Ni and V content less than 30 ppm. Furthermore, sulfur conversion rates in the HOT process are typically in the range of 40-90%, MCR conversion rates are typically in the range of 30-70%, and Ni+V metal conversion rates are typically in the range of 50-95%.

[0141] Heavy oil hydrotreating methods typically include catalysts selected from demetallization catalysts, desulfurization catalysts, or combinations thereof. More particularly, such catalysts may comprise catalyst compositions containing about 5-20 vol% of a staged and demetallized catalyst, about 10-30 vol% of a transition conversion catalyst, and about 50-80 vol% of a deep conversion catalyst. More preferred ranges include catalyst compositions containing about 10-15 vol% of a staged and demetallized catalyst, about 20-25 vol% of a transition conversion catalyst, and about 60-70 vol% of a deep conversion catalyst. To sequentially treat unconverted heavy oil streams, the staged and demetallized catalyst, the transition conversion catalyst, and the deep conversion catalyst can be stratified.

[0142] Suitable catalysts for use as staged and demetallization catalysts, transition conversion catalysts, and deep conversion catalysts are described in various patents, including, for example, US 5,215,955; US 4,066,574; US 4,113,661; US ​​4,341,625; US 5,089,463; US 4,976,848; US 5,620,592; and US 5,177,047.

[0143] Staged catalysts offer enhanced trapping of particles and highly reactive metals to mitigate fouling and pressure drop, while dealmetallizers provide the high dealmetallization activity and metal uptake capacity required to achieve desired run-time. Staged and dealmetallizers are used for metal removal and exhibit low HDS, HDN, and HDMCR activities. As determined by N2 physisorption using the Brunauer-Emmett-Teller (BET) method, these catalysts exhibit high pore volumes (typically > 0.6 cc / g), large average mesopore diameters (> 180 Å), and low surface areas (< 150 m² / g). The active metal contents (Mo and Ni) on staged and dealmetallizers are low, with Mo content typically < 6 wt% and Ni content < 2 wt%.

[0144] Transition and conversion catalysts offer moderate demetallization activity and metal uptake capacity, along with moderate HDS and MDMCR activity. Compared to staged and demetallization catalysts and deep conversion catalysts, transition and conversion catalysts exhibit moderate pore volume, pore size, and active metal content. Pore volume, measured by the BET method, is typically 0.5–0.8 cc / g, and surface area is 100–180 m². 2 / g, and the average mesopore diameter is 100-200 Å. The active Mo content is typically 5-9 wt%, and Ni is 1.5-2.5 wt%.

[0145] Deep conversion catalysts transform the least reactive S, N, and MCR substances to achieve deep catalytic conversion and reach the target product. Deep conversion catalysts exhibit low demetallization activity and metal absorption capacity. They also possess low pore volume, high surface area, small pore size, and high metal content. Measured by the BET method, the catalyst pore volume is typically <0.7 cc / g, and the surface area is >150 m². 2 / g, and the average mesopore diameter is <150 Å. Active Mo content is typically >7.5 wt%, and nickel >2 wt%.

[0146] If necessary, a diluent may be added after the hydrotreating process step. Such a diluent can be an aromatic diluent, such as LCO or MCO from the FCC process, an aromatic solvent such as toluene, xylene, or Hi-Sol, or a non-aromatic diluent such as jet fuel or diesel. If added, the total amount of diluent is typically in the range of 1-50%, more preferably 5-40%, and most preferably 10-30%. The amount of aromatic diluent is preferably half or more of the total added diluent (aromatic + non-aromatic). The boiling point of the diluent added to the product to prepare the low-sulfur fuel oil product is preferably 100 to 1200°F, more preferably 200 to 1000°F, and most preferably 300 to 800°F.

[0147] The method of the present invention can be advantageously used to prepare products for low-sulfur fuel oils, particularly those meeting the IMO 2020 sulfur content specifications. More particularly, such a method can be used to manufacture products for low-sulfur fuel oils with a sulfur content of less than 0.5% by weight, or less than 0.3% by weight, or less than 0.1% by weight.

[0148] The hydrotreating system configuration used in the method of this invention typically includes the following hydrotreating units: an integrated heavy oil processor (HOT), a filtration system (FS), a heavy oil stripping tower (HOS), one or more high-pressure high-temperature separators (HPHT), one or more medium-pressure high-temperature separators (MPHT), an atmospheric distillation column fractionator (ACF), an optional vacuum distillation column fractionator (VCF), and an optional HOT stripping tower. The hydrotreating system units should be understood as fluidly connected and fluidly linked to allow the hydrocarbon-containing feed stream to flow through the hydrotreating process. The hydrotreating system units are arranged according to the following conditions:

[0149] The FS unit is located upstream of the HOT unit and downstream of the HOS unit;

[0150] The HPHT unit is located upstream of the MPHT unit;

[0151] The HOS unit is located upstream of the VCF unit;

[0152] The HOT stripping tower is located downstream of the HOT unit;

[0153] The HPHT unit and the MPHT unit are located upstream of the HOS unit;

[0154] The HPHT unit and the optional MPHT unit are located upstream of the HOT unit;

[0155] The HPHT unit and the optional MPHT unit are located upstream of the ACF and VCF units; and

[0156] An ACF unit, and an optional VCF unit, are located downstream of the HOT unit.

[0157] In some illustrative embodiments, the hydrogenation treatment system units may be arranged in the following flow order: HOS unit, followed by FS unit, followed by VCF unit, followed by HOT unit, and then ACF unit.

[0158] In some illustrative embodiments, the hydrogenation treatment system units may be arranged in the following flow order: HOS unit, followed by VCF unit, followed by FS unit, followed by HOT unit, and then ACF unit.

[0159] In another illustrative embodiment, the hydrogenation treatment system units may be arranged in the following flow order: HOS unit, followed by FS unit, followed by HOT unit, and then ACF unit.

[0160] In another illustrative embodiment, the hydrogenation treatment system units may be arranged in the following flow order: HOS unit, followed by FS unit, followed by HOT unit, followed by ACF unit, and then VCF unit.

[0161] In another illustrative embodiment, the hydrotreating system units may be arranged in the following flow sequence: HOS unit, followed by FS unit, followed by VCF unit; and HOT unit, followed by ACF unit, wherein the VCF unit includes a bottom fraction recirculation fluid connection that is connected to the feed flow connection of the HOT unit.

[0162] In another illustrative embodiment, the hydrogenation treatment system units may be arranged in the following flow order: HOS unit, followed by FS unit, followed by HOT unit, followed by ACF unit, and then VCF unit.

[0163] In another illustrative embodiment, the hydrotreating system units may be arranged in the following flow sequence: a HOS unit, followed by an FS unit, followed by a VCF unit, followed by a first HOT unit, followed by an HPHT unit, followed by a HOT stripping tower unit, wherein the HOT stripping tower unit includes an overhead fraction recirculation fluid connector connected to the feed flow connector of the HOS unit; and a second HOT unit, followed by an ACF unit; wherein the HPHT unit following the first HOT unit includes an overhead fraction recirculation fluid connector connected to the feed flow connector of the first HOT unit.

[0164] Each of the foregoing illustrative embodiments is in Figure 1-7 As shown in the diagram. In each diagram, the specific units, processes, and product flows are identified as follows:

[0165] Process units: fluidized bed reactor (10); high pressure separator, HPHT (20); medium pressure separator, MPHT (30); atmospheric pressure tower or heavy oil stripping tower, HOS (40); separation process or filtration process unit (50); vacuum tower (60); HOT hydrogenation processor (70); HPHT separator (80); MPHT separator (90); fractionator (100) and (110); heater (120).

[0166] Process flow: EB reactor feed (11); hydrogen feed (12); other feed (71); other hydrogen (72); quenched gas or liquid (76).

[0167] The processes and / or product streams not specifically identified above but listed in the illustrative figures are intended to identify normal processes and product streams from such units and do not require further description for the purposes of this document.

[0168] Although not specifically shown in these figures, additional aromatic feedstocks according to the method of the invention may be added before or after the separation or filtration process unit (50). Other diluents may also be added after the HOT hydrogenation processor (70) as described above.

[0169] Example

[0170] Various supporting studies were conducted to verify the advantages associated with the present invention. Atmospheric bottoms product (ATB) and vacuum bottoms product (VTB) were collected and mixed with and / or filtered with aromatic feed components according to the present invention to provide the following results.

[0171] Examples 1-6: Effects of aromatic feedstock and filtration on the stability of unconverted residue oil

[0172] Unconverted residue oil contains inorganic particles such as alumina, silica, and iron sulfide, which originate from ground catalyst and organic precipitate particles.

[0173] As shown in Table 1, the newly obtained unconverted residue (made from atmospheric bottoms or ATB) contains various metals (Example 1). Undesirable metals in the residue, such as molybdenum, indicate catalyst grinding. Filtration on a 0.45-micron filter removes most metals, such as Ni, V, Al, Fe, Mo, Na, and Si (Example 2). Ni and V remaining in the permeate may be part of organic compounds still dissolved in the unconverted residue. Modifiers derived from free-flowing catalytic cracking (FCC) introduce additional Al and Si from the ground FCC catalyst (Example 3). Filtration also removes these fine FCC catalyst particles (Example 4).

[0174] Table 1: Effects of Modifiers and Filtration on the Stability of Unconverted Residue Oil

[0175] Note: UDL stands for limit of detection, which is usually less than 1 ppm; N / A means not applicable.

[0176] a This was derived from metal analysis based on ATB and the modifier.

[0177] Sediment content reflects feed stability. At any stage of the process, unconverted residue oil has a high initial sediment content and tends to settle further, leading to equipment scaling and clogging. Sediment content was quantified using Shell's thermal filtration method ASTM D4870. Table 1 lists the sediment content of some unconverted residue oils before and after filtration and / or the addition of a modifier. Notably, the sediment contains both inorganic and organic particles. Without a modifier or filtration, the sediment content in the unconverted residue oil was very high, reaching 37,621 ppm (Example 1). Adding a modifier alone reduced the sediment to 31,637 ppm (Example 5). Filtration alone (using a 0.45-micron filter) reduced the sediment to 190 ppm (Example 2), demonstrating that filtration effectively removed both inorganic solids (confirmed by metal analysis) and large organic solids. With the addition of a modifier followed by filtration, the sediment level was reduced to a maximum of 145 ppm (Example 6).

[0178] Examples 7-12: The effectiveness of filtration in reducing sediment in unconverted residue oil

[0179] Table 2 demonstrates the effectiveness of filtration in removing inorganic particles (milled catalyst) from unconverted residue produced from VTB. These milled and used demetallized catalysts were detected at 43.8 ppm Al, 19.5 ppm Si, 7.3 ppm Mo, and 94.5 ppm Fe (Example 7). Filtration (using a 0.45-micron filter) removed most metals, such as Ni, V, Al, Fe, Mo, Na, and Si (Example 8). The remaining 24.3 ppm Ni and 19.7 ppm V were predominantly in soluble organic forms.

[0180] The effect of filter size was also investigated (Examples 9-12). Metal analysis showed that filter pore sizes of 0.45-20 micrometers were sufficient to remove most of the ground catalyst.

[0181] Table 2: Effectiveness of filtration in reducing inorganic precipitates in unconverted residue oil

[0182] Note: UDL stands for limit of detection, which is usually less than 1 ppm; N / A means not applicable.

[0183] Examples 13-16: Effects of Modifiers on the Flowability of Unconverted Residue Oil

[0184] Table 3 lists the viscosity of the residue hydrocracking UCO feed to the hydrotreating processor before and after the addition of the modifier. 5% by weight of the modifier can reduce the viscosity of 100% of ATB-derived unconverted residue. o C viscosity was reduced from 61.4 cSt to 58.4 cSt (Examples 13 and 14). 10% by weight of the modifier can reduce 100% of the unconverted VTB-derived residue oil. o C viscosity decreased by 31% from 347.6 cSt to 240.9 cSt (Examples 15 and 16). Clearly, the modifier improves stability (weight % of precipitate) and viscosity, thereby significantly enhancing the ease of processing unconverted residue oil.

[0185] Table 3: Effect of adding aromatic diluents on the viscosity of unconverted residue oil

[0186] Examples 17-19: Effects of Modifiers and Filtration on the Stability of Hydrotreated Unconverted Residue Oil

[0187] Table 4 compares the effects of modifier addition on the stability of unconverted residue oil after filtration and hydrotreating, determined using Shell's thermal filtration method ASTM D4870. Low sediment content in the oil indicates good stability. If the unconverted residue oil is unfiltered and no modifier is added, the sediment content in the final hydrotreated product is 1210 ppm, indicating instability, a tendency to settle, and potential operational problems (Example 17). If the unconverted residue oil is only filtered (without modifier), the sediment content in the product is reduced to 156 ppm, indicating a moderate tendency to settle (Example 18). The combination of modifier addition and filtration alone resulted in an acceptable sediment level of 31 ppm in the hydrotreated product (Example 19).

[0188] Table 4: Effects of Modifiers and Filtration on the Stability of Unconverted Residue Oil

[0189] Examples 20-22: The impact of aromatic feedstocks and filtration on the feasibility of hydrotreating

[0190] Table 5 highlights the importance of adding aromatic feed components and feed filtration for the feasibility of hydrotreating unconverted residue. Without aromatic feed components and filtration, the pressure drop on the fixed-bed hydrotreating unit increases at an excessively high rate, effectively ruling out the time required for economical operation (typically at least six months).

[0191] Table 5: Effects of Modifiers and Filtration on the Feasibility of Hydrotreating

[0192] Examples 23-25: Efficacy Description of the Entire Process

[0193] Table 6-8 illustrates the effectiveness of the combination of modifier addition, filtration, and hydrotreating in converting unconverted residue oil into low-sulfur fuel oil (LSFO).

[0194] Tables 6 (Example 23) and 7 (Example 24) illustrate the LSFO products generated from unconverted VTB and ATB source residues, respectively. Both cases result in significant volume expansion (increased API) and reduced contaminants. Both products meet the 0.5% by weight sulfur content limit specified in IMO 2020 regulations.

[0195] Table 8 (Example 25) illustrates how the hydrotreating processor increases the conversion of initially unconverted vacuum residue, resulting in an additional C2-900°F of nearly 12% by weight. The hydrotreating processor also increases the total sulfur conversion from 80% to 90% and improves the conversion of N, MCR, asphaltenes, V, and Ni.

[0196] Table 6: Upgrading of unconverted VTB residue to LSFO

[0197] Table 7: Upgrading of unconverted residue from ATB source to LSFO

[0198] Table 8: Effects of UCO hydrotreating on vacuum residue upgrading

[0199] Example 26: Evaluation of LSFO Products

[0200] Example 26 illustrates the use of 80% modified, filtered, and hydrotreated unconverted residue oil (680... o How does the method of blending F+ fraction with 20% light cycle oil (LCO) meet the IMO 2020 LSFO marine fuel oil residue fuel grade RMG380 (low sulfur fuel oil with sulfur content <0.5 wt%)?

[0201] Table 9: Blending with diluent fraction feed to achieve RMG380 specification

[0202] Further detailed descriptions and information relating to this invention are provided in the publications and patents identified herein. Each of these publications and patents is incorporated herein by reference in its entirety. The claims provided in this application further describe the scope of the invention, as well as specific embodiments within the scope of the invention. Where any dependent claim relates to one or more preceding claims, it should be understood that all such combinations of the claimed features are within the scope of the invention, regardless of whether a particular combination of features is expressly stated.

[0203] The foregoing description of the invention, including any specific embodiments and incorporated disclosures, is primarily for illustrative purposes, and it is understood that variations may be used while still retaining the essence of the invention. In determining the scope of the invention, reference should be made to the following claims.

Claims

1. A method for upgrading unconverted heavy oil, the method comprising: Unconverted heavy oil feed is provided from the fluidized bed hydrocracking, wherein the unconverted heavy oil feed includes hydrocracker residue; The first aromatic feed is added to the unconverted heavy oil feed to form a mixture; The mixture is allowed to enter a dedicated filtration unit to remove insoluble matter, thereby forming an unconverted heavy oil stream. The dedicated filtration unit is selected from cross-flow filters, backwash filters, cartridge filters, membrane filters, or combinations thereof. The second aromatic feed is combined with the unconverted heavy oil stream to form a second mixture; After removing insoluble matter in a dedicated filtration unit, the second mixture is introduced into the heavy oil hydrotreating process, thereby forming a hydrotreated heavy oil feed stream from the second mixture; This method does not include a curing step, an aging step, or a settling step.

2. The method according to claim 1, wherein the dedicated filtration unit is a membrane filter.

3. The method of claim 2, wherein the membrane filter has an average pore size of less than 10 micrometers.

4. The method of claim 2, wherein the membrane filter has an average pore size of less than 5 micrometers.

5. The method of claim 2, wherein the membrane filter has an average pore size of less than 2 micrometers.

6. The method according to any one of the preceding claims, wherein the unconverted heavy oil is oil that has been processed by a hydrotreating system and remains unconverted.

7. The method according to any one of the preceding claims, wherein the unconverted heavy oil has been hydrocracking and demetallized.

8. The method according to any one of the preceding claims, wherein the unconverted heavy oil feed comprises bottom products from a fluidized bed hydrocracking process.

9. The method according to any one of the preceding claims, wherein a dedicated filtration unit removes insoluble matter from the mixture, thereby forming an unconverted heavy oil feed stream suitable for direct access to a heavy oil hydrotreating process.

10. The method of claim 9, wherein the insoluble matter comprises catalyst powder, particles, precipitates, agglomerated oil, aggregates, or combinations thereof, and wherein removing the insoluble matter reduces the tendency of unconverted heavy oil streams to scale during hydrotreating.

11. The method according to any one of the preceding claims, wherein the first aromatic feed is selected from light circulating oil, medium circulating oil, heavy circulating oil, slurry oil, vacuum gas oil, or mixtures thereof.

12. The method of claim 11, wherein the first aromatic feed comprises more than about 30% by volume of an aromatic compound.

13. The method according to any one of the preceding claims, wherein the boiling point of the first aromatic feed is 500 to 1200°F.

14. The method of claim 13, wherein the first aromatic feed is present in an amount of 3 to 20% by weight based on the unconverted heavy oil feed.

15. The method according to any one of the preceding claims, wherein the first and second aromatic feeds each comprise 20 to 100% by volume of an aromatic compound.

16. The method according to any one of the preceding claims, wherein the heavy oil hydrotreating process comprises a catalyst selected from demetallization catalysts, desulfurization catalysts, or combinations thereof.

17. The method of claim 16, wherein the heavy oil hydrotreating process comprises a catalyst composition comprising about 5 to 20 vol% of a staged and demetallized catalyst, about 10 to 30 vol% of a transition conversion catalyst and about 50 to 80 vol% of a deep conversion catalyst.

18. The method of claim 17, wherein the catalyst composition comprises about 10 to 15 vol% of a staged and demetallized catalyst, about 20 to 25 vol% of a transition conversion catalyst and about 60 to 70 vol% of a deep conversion catalyst.

19. The method according to any one of the preceding claims, wherein the second mixture entering the heavy oil hydrotreating process has an API content of -5 to 15, a sulfur content of 0.7 to 3.5% by weight, a residual carbon content of 8 to 35% by weight, and a total Ni and V content of less than 150 ppm.

20. The method of claim 19, wherein the hydrotreated heavy oil stream has an API content of 2 to 18, a sulfur content of 0.05 to 0.70% by weight, a residual carbon content of 3 to 18% by weight, and a total Ni and V content of less than 30 ppm.

21. The method according to any one of the preceding claims further includes feeding the hydrotreated heavy oil stream into a fractionator and recovering the low-sulfur fuel oil product.

22. The method of claim 21, wherein the recovered low-sulfur fuel oil product has a sulfur content of less than 0.5% by weight.

23. The method according to any one of the preceding claims, wherein the combination of adding aromatic feed and removing insoluble matter in a dedicated filtration unit provides an unconverted heavy oil stream with improved hydrotreating operability.

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