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    • 专利摘要:
    The present invention relates to a process for the upgrading of residual hydrocarbon feedstocks which may include: contacting a residual hydrocarbon and hydrogen with a catalyst of hydroconversion in a waste hydroconversion reactor system; the recovery of an effluent from the waste hydroconversion reactor system; separating the effluent to recover two or more hydrocarbon fractions including at least a vacuum residue fraction and a heavy vacuum gas oil fraction; combining at least a portion of the heavy vacuum gas oil fraction and at least a portion of the vacuum residue fraction to form a mixed heavy hydrocarbon fraction; feeding at least a portion of the mixed heavy hydrocarbon fraction into a coker; operating the coker in conditions to produce anode-grade green coke and distilled hydrocarbons; the recovery of distillate hydrocarbons from the coker; the fractionation of distillate hydrocarbons to recover hydrocarbon fractions including a light distillates fraction, a heavy gas oil fraction from the coker and a recycle fraction (...).
    公开号:BR112015023148B1
    申请号:R112015023148-9
    申请日:2014-02-21
    公开日:2021-06-08
    发明作者:Gary Sieli；Ahmad Faegh；Ujjal K. Mukherjee；Mario C. Baldassari；Marvin I. Greene
    申请人:Lummus Technology Inc；
    IPC主号:
    专利说明:

    Description field
    [001] The modalities described in this document generally refer to processes to improve vacuum residue streams derived from petroleum, tar sands, shale oils, coal liquids, coal gasification tars and biopetroleums, among others. More particularly, the embodiments in that document relate to processes for producing distillate fuels and anode grade coke from vacuum residual hydrocarbon feedstocks. Even more particularly, the modalities described in that document relate to processes for improving the residual vacuum raw materials for distilling the combustible products using fluidized bed or slurry hydrocracking, delayed coking, and improving fixed bed catalytic vacuum gas oil. Historic
    [002] Thermal coking processes allow crude oil refineries to process heavier hydrocarbons into petroleum, tar sands and other hydrocarbon sources. In general, thermal coking processes employ high gravity thermal decomposition (or "cracking") to maximize the conversion of very heavy, low value waste feeds to lower boiling hydrocarbon products of higher value. The raw materials for these coking processes typically consist of refining process streams that cannot be economically further distilled, catalytically cracked, or otherwise processed to make fuel grade blend streams. Typically, these materials are not suitable for catalytic operations because of catalyst fouling and/or deactivation by ash and metals. Common coking feedstocks include atmospheric still, vacuum still, catalytic cracker waste oil, hydrocracker waste oil, and waste oil from other refining units.
    [003] Three types of coking processes used in crude oil refineries and improving facilities to convert heavy hydrocarbon fractions into lighter hydrocarbons and petroleum coke include delayed coking, fluid coking and flexicoking. In all three of these coking processes, petroleum coke is considered a by-product that is tolerated in the interest of more complete conversion of refining residues to lighter hydrocarbon compounds. The resulting hydrocarbons and other products move from the coking flask to a fractionator in the form of vapor. Heavier cracked liquids (eg gas oils) are commonly used as raw materials for further refining processing (eg Fluid Catalytic Cracking Units or FCCUs) which turn them into transport fuel blend stocks.
    [004] Crude oil refineries have regularly increased the use of heavier oils in their crude mixtures due to better availability and lower costs. These heavier crudes have a higher ratio of heavier hydrocarbon components, increasing the need for coker capacity. Thus, the coker often becomes a bottleneck that limits refining performance. Also, these heavier crudes often contain higher concentrations of large, aromatic structures (eg, asphaltenes and resins) that contain higher concentrations of sulfur, nitrogen, and heavy metals such as vanadium and nickel.
    [005] As a result, the coking reactions (or mechanisms) are substantially different and tend to produce a denser coke crystal structure (or morphology), in spheres (vs. sponge) with higher concentrations of undesirable contaminants in the coke oil and gas oils from the coker. Unfortunately, many of the technological improvements in trying to deal with the above (factory capacity / bottlenecks, changes in raw material composition, etc.) have substantially lowered the quality of the resulting petroleum coke. Most technological improvements and heavier acidic oils tend to push petroleum coke from porous sponge coke to sphere coke with higher concentrations of unwanted impurities. The resulting change in coke quality may require a major shift in coke markets (eg anode to fuel grade) and dramatically decrease the value of coke. Technology changes and associated feedstock changes can result in reduced fuel grade coke quality, having lower volatile material and gross heating value, among other properties, making fuel grade coke less desirable. Summary of Claimed Modalities
    [006] In one aspect, the modalities described in this document refer to a process for improving residual hydrocarbon feedstocks. The process may include: contacting a residual hydrocarbon and hydrogen with a hydroconversion catalyst in a residue hydroconversion reactor system; recovering an effluent from the waste hydroconversion reactor system; separating the effluent from the residue hydroconversion reactor system to recover two or more hydrocarbon fractions including at least one vacuum residue fraction and a heavy vacuum gas oil fraction; combining at least a portion of the heavy vacuum gas oil fraction and at least a portion of the vacuum residue fraction to form a mixed heavy hydrocarbon fraction; feeding at least a portion of the mixed heavy hydrocarbon fraction to a coker; operate the coker in conditions to produce anode grade green coke and distilled hydrocarbons; recovering the distillate hydrocarbons from the coker; fractionating the distillate hydrocarbons recovered from the coker to recover three or more hydrocarbon fractions including a light distillates fraction, a heavy gas oil fraction from the coker and a recycle fraction from the coker.
    [007] In another aspect, the modalities in this document refer to a system for improving the waste hydrocarbon raw materials. The system may include: a residue hydroconversion reactor system for contacting a residual hydrocarbon and hydrogen with a hydroconversion catalyst; a fractionation system for separating an effluent from the residue hydroconversion reactor system into two or more hydrocarbon fractions including at least a vacuum residue fraction and a heavy vacuum gas oil fraction; a mixing device for combining at least a portion of the heavy vacuum gas oil fraction and at least a portion of the vacuum residue fraction to form a mixed heavy hydrocarbon fraction; a coker to convert the mixed heavy hydrocarbon fraction to produce anode grade green coke and distill hydrocarbons; a fractionation system for fractionating the distillate hydrocarbons recovered from the coker into three or more hydrocarbon fractions including a light distillate fraction, a heavy gasoil fraction from the coker, and a recycle fraction from the coker.
    [008] Other aspects and advantages will be apparent from the following description and the appended claims. Brief Description of Drawings
    [009] Figure 1 is a simplified process flowchart of a process to improve the waste hydrocarbon raw materials according to the modalities described in this document.
    [0010] Figure 2 is a simplified process flowchart of a process for improving the waste hydrocarbon raw materials according to the modalities described in this document.
    [0011] Figure 3 is a simplified process flowchart of a portion of a process for improving waste hydrocarbon feedstocks according to the modalities in this document.
    [0012] Equal numerals represent equal parts in all figures. Detailed Description
    [0013] In one aspect, the modalities in this document generally refer to processes for improving vacuum residue streams derived from petroleum, tar sands, shale oils, coal liquids, coal gasification tars and biopetroleums, among others. More particularly, the embodiments in that document relate to processes for producing distillate fuels and anode grade coke from vacuum residual hydrocarbon feedstocks. Even more particularly, the modalities described in that document relate to processes for vacuuming residual raw materials for distilling combustible products using fluidized bed or slurry hydrocracking, delayed coking, and fixed bed catalytic vacuum gas oil improvement.
    [0014] The hydroconversion processes described in this document can be used to react to waste hydrocarbon feedstocks under conditions of elevated temperatures and pressures in the presence of hydrogen and one or more hydroconversion catalysts to convert the feedstock to hydrocarbon products. lower molecular weight with reduced levels of contaminant (such as sulfur and/or nitrogen). Hydroconversion processes can include, for example, hydrogenation, desulfurization, denitrogenation, cracking, conversion, demetallization, and metal removal, Conradson Carbon Residue (RCC) or asphaltenes removal, etc.
    [0015] As used in this document, residual hydrocarbon fractions, or like terms referring to residual hydrocarbons, are defined as a hydrocarbon fraction that has boiling points or a boiling range above about 340°C, but it could also include full heavy oil processing. Residue hydrocarbon feedstocks that can be used with the processes described in this document may include various refineries and other hydrocarbon streams such as atmospheric or vacuum petroleum residues, deasphalted oils, deasphalting pitch, hydrocracked atmospheric tower or lower parts of the vacuum tower, straight-line vacuum gas oils, hydrocracked vacuum gas oils, fluid catalytically cracked slurry oils (FCC), vacuum diesel from a fluidized bed hydrocracking process, shale derived oils, derived oils of coal, tar sand bitumen, tall oils, bio-derived crude oils, black oils, as well as other similar hydrocarbon streams or a combination thereof, each of which may be straight-line, process-derived, hydrocracked , partially desulfurized, and/or partially demetallized chains. In some embodiments, the residual hydrocarbon fractions can include hydrocarbons that have a normal boiling point of at least 480°C, at least 524°C, or at least 565°C.
    In some embodiments, the residual feedstock has a metal content of less than about 100 ppm by weight of nickel and less than about 200 ppm of vanadium, a sulfur content of less than about 2.5 percent by weight, and an asphaltenes content of less than about 12 percent by weight. In various embodiments, the residue may include at least one of the atmospheric residues of petroleum or vacuum, deasphalted oils, deasphalting pitch, hydrocracked atmospheric tower or lower part of the vacuum tower, straight-line vacuum gas oil, hydrocracked vacuum gas oil, fluid catalytically cracked slurry oils (FCC), vacuum diesel from a fluidized bed process, oils derived from shale, oils derived from coal, bio-derived crude oils, tar sand bitumen, tall oils, oils black. For example, the residual hydrocarbon can be derived from one or more crude oils Arab Heavy, Arab Light, Arab Medium, Kuwait Export, Basrah Light, Rubble, Bahrain, Oman, Upper Zakam, REBCO, Kumkol, Ural, Azeri Light , Siberian Light, Siberian Heavy, and Tengiz. Oils derived from shale can be generated either in an in situ extraction process or an above ground oil shale retort process. Coal gasification by-product oils can be derived from a fixed bed gasifier or a fluid bed gasifier or a moving bed gasifier. Oils derived from coal can be derived from a pyrolysis unit or a thermal hydroliquefaction unit or a catalytic hydroliquefaction unit.
    [0017] Now with reference to figure 1, a simplified process flowchart of a process for improving waste hydrocarbon feedstocks is illustrated. A fraction of residual hydrocarbon 10 (residue 10) and hydrogen 12 can be fed to a hydroconversion reactor system 13, which can include one or more hydroconversion reactors in series or parallel. In hydroconversion reactor system 13, the residue and hydrogen can be contacted with a hydroconversion catalyst to convert at least a portion of the residue to lighter hydrocarbons, demetallize the metals contained in the residue, remove the Conradson Carbon Residue, or otherwise way to convert the waste into useful products.
    [0018] Hydroconversion reactors useful in the modalities herein may include fluidized bed hydroconversion reactors or reactor systems, as well as fluid phase hydrocracking reactor systems, fixed bed VGO hydrocracking reactor systems, and/or systems of fluidized bed VGO hydrocracking reactor. In some embodiments, fixed bed hydrocracking reactor systems may include one or more as described in US 6797154; 6783660; 6514403; 6224747; 6200462; 6096190; 5925235; 5593570; 5439860; and 5277793.
    [0019] Conversion rates in the waste hydroconversion reactor system 13 may be at least 50% in some embodiments, such as at least 70% or at least 85% in other embodiments. The residue hydroconversion reactor system 13 can be operated at a pressure in the range of about 1000 psig (6.89x106 Pa.g) to about 4000 psig (2.76x107 Pa.g), an LHSV in the range of about from 0.1 L/h/L to about 4.0 L/h/L, a reactor temperature in the range of about 400°C to about 500°C, a residual feedstock ratio of hydrogen/ vacuum between about 2000 and 6000 SCF/Bbl (356 and 1068 m3/m3), a fresh catalyst composition ratio in the range of about 0.1 to about 0.6 lb/Bbl (0.007 to about 0. 04 kg/m3) of residual vacuum raw material. Catalysts useful in the hydroconversion reactor system 13 can include one or more nickel, cobalt, tungsten, molybdenum and combinations thereof, whether unsupported or supported on a porous substrate such as silica, alumina, titania, or combinations thereof, as will be described in more detail below.
    [0020] After conversion of the fluidized bed reactor system 13, Partially converted hydrocarbons can be recovered through flow lines 15 and fed into a fractionation system 18 to recover two or more hydrocarbon fractions including at least one residue fraction of vacuum of a heavy fraction of vacuum diesel. As illustrated, the fractionation system 18 can be used to recover an exhaust gas 20 having light hydrocarbon gases and hydrogen sulfide (H2S), a light naphtha fraction 22, a heavy naphtha fraction 24, a kerosene fraction 26 , a diesel fraction 28, a light vacuum diesel fraction 30, a heavy diesel fraction 32, and a vacuum residue fraction 34. In some embodiments, a portion of the vacuum residue fraction 34 may be recycled, such as through flow line 37 for further processing in the glass reactor system with fluidized bed version 13. For example, the vacuum residue fraction 34 a portion thereof may be combined with at least a portion of the heavy gas oil fraction. vacuum 32 to form a mixed heavy hydrocarbon fraction 35. In some embodiments, the upstream conditions and feed ratios can be controlled so that the mixed heavy hydrocarbon fraction 35 has a nickel content. of less than about 70 ppmw, a vanadium content of less than about 70 ppmw, a Conradson Asphaltenes/Carbon Residue (RCC) ratio of less than 0.7 to 1, such as less than 0 .5/1 or less than 0.3/1, and a total sulfur content of less than about 24,000 ppm by weight.
    [0021] The mixed heavy hydrocarbon fraction 35 can then be fed into a coking system 36, which can be operated under conditions to produce anode grade green coke and distilled hydrocarbons. In some embodiments, the coker system 36 can include one or more delayed coker units (delayed coker).
    [0022] The coker can be operated at a heating coil outlet temperature of at least 500°C, such as at least 520°C, a pressure in the range of about 20 psig (1.38x105 Pa.g) at about 35 psig (2.41x105 Pa.g). The exit steam temperature of the coke drum can be controlled to be at least 450°C, at least 460°C, at least 470°C, or at least 480°C. Drying times after the coking cycle can be at least 2 hours, at least 4 hours, at least 6 hours, or at least 8 hours in various modes. For example, the exit steam temperature of the coke drum can be controlled to be at least 470°C or 480°C with drying times of at least 5 hours and preferably at least 8 hours, or at temperatures of at least 450 °C or at least 460 °C with a drying time of at least 6 hours or at least 7 hours, where drying is conducted by passing a stream of superheated steam through the filled coke drum.
    [0023] Distillates hydrocarbons can be recovered from the coker system 36 through flow line 40 and fractionated in a fractionation system 38 to recover three or more hydrocarbon fractions, such as a light distillates fraction 21, a diesel fraction of heavy coker 23, and a recycle fraction from coker 25. In some embodiments, the heavy gasoil fraction from coker 23 has a Polycyclic Index based on Ultraviolet Absorption Spectrophotometry of less than 10,000, such as less than about 6000 or less than about 4000.
    [0024] In some embodiments, the mixed heavy hydrocarbon fraction 35 may be mixed with the recycle fraction from the coker 25 to form a coker feed mix 39. As the properties of the resulting coke may be affected by the quality of the feed, it may It is desired to limit the amount of coker recycle fraction in the coker feed mix. In some embodiments, the recycle fraction from the coker leaves less than 30 percent by weight of the coker feed mix, such as from about 15 percent by weight to about 25 percent by weight of the coker feed mix.
    [0025] The heavy fraction of coker gas oil 23 and hydrogen 29 may be contacted with a hydroconversion catalyst in a hydroconversion reactor system 94, which may include one or more fixed bed hydroconversion reactors, to convert at least a portion of the heavy gasoil fraction from the coker 23 to distillate fuel range hydrocarbons. An effluent 96 can be recovered from hydroconversion reactor system 94 and fractionated in a fractionation system to form two or more hydrocarbon fractions. For example, effluent 96 can be separated into an exhaust gas 99 containing light hydrocarbon gases, a fraction of light naphtha 100, a fraction of heavy naphtha 102, a fraction of kerosene 104, a fraction of diesel 106, a fraction of light vacuum gas oil 108, a heavy gas oil fraction 110, and a vacuum residue fraction 112. One or more of these fractions may optionally be recycled to hydroconversion reactor system 13, fractionation system 38, reactor system 94, or coker system 36.
    [0026] Anode grade green coke produced according to the processes in this document may have the following properties: nickel less than about 175 ppm; vanadium less than about 250 ppm; sulfur less than about 35,000 ppm by weight; Hardgrove Grinding Index (HGI) of less than about 100, and Combustible Volatile Matter of less than about 12% by weight. In order to make anode grade green coke according to the modalities in this document, which is much higher in commercial value compared to normal petroleum coke or "fuel grade", the initial hydroconversion unit and the delayed coking unit have to operate over a specific range of gravities dictated by the nature of the particular vacuum waste feedstock. To produce anode grade coke, the fluidized bed unit must be operated at the proper gravity to produce an unconverted residual vacuum oil suitable for conversion in the Delayed Coke unit to produce a green coke that has the correct specifications for green coke production of anode grade. The severity of Delayed Coking will need to be controlled in order to achieve the required specifications for anode grade coke. The combination of correct operating severities of both the fluidized bed hydrocracking unit and the delayed coking unit is neither obvious nor trivial.
    [0027] In some embodiments, the coker system 36 may be operated at a Coker Yield Ratio, defined as the sum of the fresh coker feed rate plus the coker net recycle rate divided by the fresh coker feed rate on a net volumetric basis, of less than about 1.25/1, such as less than about 1.20/1 or less than about 1.15/1.
    [0028] Now with reference to Figure 2, a simplified process flowchart of processes according to the modalities in this document to improve residual hydrocarbons and produce anode grade green coke is illustrated. A fraction of residual hydrocarbon (residue) 10 and hydrogen 12 can be fed into a fluidized bed reactor system 14, which can include one or more fluidized bed reactors arranged in series or parallel, where the hydrocarbons and hydrogen are contacted with a hydroconversion catalyst to react at least a portion of the residue with hydrogen to form lighter hydrocarbons, demetallize the metals contained in the residue, remove the Conradson Carbon Residue, or otherwise convert the residue into useful products.
    [0029] The reactors in fluidized bed reactor system 14 can be operated at temperatures in the range of about 380°C to about 450°C, hydrogen partial pressures in the range of about 70 bara (70x105 Pa) to about 170 bara (170x105 Pa), and net hourly space velocities (LHSV) in the range of about 0.2 h-1 to about 2.0 h-1. Within fluidized bed reactors, the catalyst can be mixed back and kept in random motion by recirculating the liquid product. This can be done by first separating the recirculated oil from the gaseous products. The oil can then be recirculated through an external pump, or, as illustrated, through a pump that has a rotor mounted on the bottom head of the reactor.
    [0030] Target conversions in fluidized bed reactor system 14 can be in the range of about 30% by weight to about 75% by weight, such as more than about 50%, more than about 70%, or more than about 85%, where the conversion may depend on the operating conditions and properties of the raw material being processed. In any case, target conversions could be kept below level, where sediment formation becomes excessive and thus prevents continuity of operations. In addition to converting residual hydrocarbons to lighter hydrocarbons, sulfur removal can be in the range of about 40% by weight to about 65% by weight, metal removal can be in the range of about 40% by weight to 65% by weight and Conradson Carbon Residue (RCC) removal can range from about 30% by weight to about 60% by weight.
    [0031] Reactor gravity can be defined as the average catalyst temperature in degrees Fahrenheit of the catalysts loaded in one or more fluidized bed hydrocracking reactors multiplied by the average partial pressure of hydrogen of the fluidized bed hydrocracking reactors in absolute Bar and divided by LHSV in fluidized bed hydrocracking reactors. The reactor gravity of fluidized bed reactor system 14 can range from about 105,000 °F-Bara-Hr (5.83x109 °C-Pa-Hr) to about 446,000 °F-Bara-Hr (2, 48x1010 °C-Pa-Hr).
    [0032] After conversion in the fluidized bed reactor system 14, partially converted hydrocarbons can be recovered through flow line 16 as a mixed vapor/liquid effluent and fed into a fractionation system 18 to recover one or more fractions of hydrocarbon. As illustrated, the fractionation system 18 can be used to recover an exhaust gas 20 containing light hydrocarbon gases and hydrogen sulfide (H2S), a light naphtha fraction 22, a heavy naphtha fraction 24, a kerosene fraction 26 , a diesel fraction 28, a light vacuum diesel fraction 30, a heavy diesel fraction 32, and a vacuum residue fraction 34. In some embodiments, a portion of the vacuum residue fraction 34 may be recycled, such as as through flow line 37, for further processing in the fluidized bed hydroconversion reactor system 14.
    [0033] Fractionation system 18 (not illustrated in detail) may include, for example, a high pressure, high temperature (HP/HT) separator to separate the effluent vapor from the effluent liquids. The separated steam can be routed through gas cooling, recycle gas purification and compression, or it can be processed first through an Integrated Hydroprocessing Reactor System (IHRS), which can include one or more additional hydroconversion reactors alone. or in combination with external distillates and/or distillates generated in the hydrocracking process, and thereafter routed for gas cooling, purification and compression.
    [0034] The liquid separated from the HP/HT separator can be illuminated and routed into an atmospheric distillation system along with other distillates recovered from the gas cooling and purification section. Atmospheric tower bottoms, such as hydrocarbons that have an initial boiling point of at least about 340°C, such as an initial boiling point in the range of about 340°C to about 427°C, can then also be processed through a vacuum distillation system to recover the vacuum distillates.
    [0035] The product of vacuum tower bottoms, such as hydrocarbons having an initial boiling point of at least about 480°C, such as an initial boiling point in the range of about 480°C to about 565°C, can then be routed, optionally with a portion of the heavy vacuum gas oil fraction 32, as a mixed feedstock from the coker 35, to a coking system 36 for producing anode grade green coke.
    [0036] The raw material from the coker 35 can be introduced into the lower portion of a fractionator of the coker 38, where it combines with condensed hydrocarbons from the steam stream of the coker 40. The resulting mixture 42 is then pumped through a heater 44 of the coker, where it is heated to the desired coking temperature, such as between 850°F (454.44°C) and 1100°F (593.33°C), causing partial vaporization and moderate cracking of the coker raw material . The temperature of the raw material 46 of the heated coker can be measured and controlled through the use of a temperature sensor 48 which sends a signal to a control valve 50 to regulate the amount of fuel 52 fed to the heater 44. If desired, a Steam or boiler feed water 54 can be injected into the heater to reduce coke formation in tubes 56.
    [0037] The raw material 46 of the heated coker can be recovered from the heater 44 of the coker as a vapor-liquid mixture to feed the coking drums 58. Two or more drums 58 can be used in parallel to provide continuous operation during the operating cycle (coke production, coke recovery (decoking), preparation for the next coke production cycle, repeat). Sufficient residence time is provided in the coking drum 58 to allow the thermal cracking and coking reactions to proceed to completion. In this way, the vapor-liquid mixture is thermally cracked in the coking drum 58 to produce lighter hydrocarbons, which vaporize and exit the coke drum through flow line 60. Petroleum coke and some residues (eg, hydrocarbons cracked) remain in the coking drum 58. When the coking drum 58 is sufficiently full of coke, the coking cycle ends. The raw material 46 from the heated coker is then switched from the first coking drum 58 to a parallel coking drum to start its coking cycle. Meanwhile, the decoking cycle starts at the first coking drum.
    [0038] In the decoking cycle, the contents of the coking drum are cooled, remaining volatile hydrocarbons are removed, the coke is perforated or otherwise removed from the coking drum, and the coking drum is prepared for the next coking cycle . Cooling the coke normally takes place in three distinct stages. In the first stage, the coke is cooled and hulled by steam or other pickling means 62 to economically maximize the removal of recoverable hydrocarbons entrained or otherwise remaining in the coke. In the second stage of cooling, water or other cooling medium 64 is injected to reduce the temperature of the coking drum while avoiding thermal shock to the coking drum. Water vaporized from this cooling medium further promotes the removal of additional vaporizable hydrocarbons. In the final cooling stage, the coke drum is quenched by water or other extinguishing means 66 to quickly reduce coke drum temperatures to conditions favorable for safe coke removal. After quenching is complete, the lower and upper heads 68, 70 of the coking drum 58 are removed. The anode 72 grade green coke is then removed from the coking drum. After removal of the coke, the coking drum heads 68, 70 are replaced, the coking drum 58 is preheated, and otherwise prepared for the next coking cycle.
    [0039] The lighter hydrocarbon vapors recovered as a top fraction 60 from the coking drum 58 are then transferred to the coker fractionator 38 as a vapor stream from the coker 40, where they are separated into two or more fractions of hydrocarbon and recovered. For example, a heavy coke gas oil fraction (HCGO) 74 and a light coke gas oil fraction (LCGO) 76 can be withdrawn from the fractionator in the desired boiling temperature ranges. HCGO can include, for example, hydrocarbons boiling in the range of 650 to 870°F (343.33 to 465.56°C). LCGO can include, for example, hydrocarbons boiling in the range 400 to 650°F (204.44 to 343.33°C). In some embodiments, other hydrocarbon fractions may also be recovered from the coker fractionator 38, such as a quenched oil fraction 78, which may include hydrocarbons heavier than HCGO, and/or a wash oil fraction 80. The upper stream from the fractionator, wet gas fraction from coker 82 goes to a separator 84, where it is separated into a dry gas fraction 86, a water/aqueous fraction 88, and a naphtha fraction 90. A portion of naphtha fraction 90 can be returned to the fractionator as a reflux 92. Other fractionation schemes may also be used, and may result in light petroleum gas fractions, naphtha fractions from the coker, diesel fractions from the coker, and/or other hydrocarbon fractions as may be wanted.
    [0040] The temperature of the materials inside the coking drum 58 throughout the coke formation stage and the drying stage can be used to control the type of crystalline structure of the coke and the amount of volatile combustible material in the coke. The temperature of the vapors leaving the coke drum through the flow line 60 is thus an important control parameter used to represent the temperature of the materials inside the coking drum 58 during the coking process, and can be controlled as described in this document .
    [0041] The temperature of the upper vapor fraction of the coking drum 60 can be used to monitor and control the coking process and the quality of the coke product (VCM content, crystal structure, etc.). In some embodiments, the temperature of the steam product recovered from the coking drum can be controlled, for example, by using a digital control system (DCS) or other process control systems to be within the range of about 700° F (371.11°C) to about 900°F (482.22°C); in the range of about 725°F (385°C) to about 875°F (468.33°C) in other embodiments; in the range of about 750°F (398.89°C) to about 850°F (454.44°C) in other embodiments; and in the range of about 775°F (412.78°C) to about 800°F (426.67°C) in still other embodiments. In some embodiments, the coker heater outlet temperature can range from about 900°F (482.22°C) to about 1100°F (593.33°C). DCS can also be used to control the decoking cycle as described below.
    [0042] Various chemical and/or biological agents can be added to the coking process to inhibit the formation of coke in spheres and/or promote the formation of desirable sponge coke. In particular embodiments, an anti-foaming agent can be added, such as a silicon-based additive. Chemical and/or biological agents can be added at any point in the process.
    [0043] After conversion and fractionation in the coker system 36 and fractionation system 38, the heavy gas oil fraction from the coker 74 can be fed to a hydroconversion reactor system 94, which may include one or more bed hydroconversion reactors fixed. Fixed bed hydroconversion reactors 94 can contain hydroprocessing catalysts adapted to one or more hydroconversion reactions such as hydrocracking, hydrodesulfurization, hydrodenitrogenation, olefin saturation, hydrodeoxygenation and hydrodearomatization. In some embodiments, fixed bed hydroconversion reactors 94 can contain a mixture of hydrotreating catalysts and hydrocracking catalysts. Examples of catalysts that can be used, among others, can be found in US 4,990,243; US 5,215,955; and US 5,177,047, all of which are incorporated herein by reference in their entirety. In some embodiments, fixed bed hydroconversion reactors 94 may not provide any demetallization and demetallization catalysts may not be needed.
    [0044] After reaction, the effluent 96 recovered from the hydroconversion reactor system 94 can be sent to a fractionation system 98 for separation of the effluent into two or more hydrocarbon fractions. For example, effluent 96 can be separated into an exhaust gas 99 which contains light hydrocarbon gases, a fraction of light naphtha 100, a fraction of heavy naphtha 102, a fraction of kerosene 104, a fraction of diesel 106, a fraction of light vacuum gas oil 108, a heavy gas oil fraction 110, and a vacuum residue fraction 112. One or more of these fractions may optionally be recycled to hydroconversion reactor system 14, fractionation system 38, reactor system 94 , or coker system 36.
    [0045] Figure 3 illustrates a modality for the IHRS mentioned above; however, other modalities can be readily envisioned by those skilled in the art based on the description below. Partially converted hydrocarbons recovered via flow line 16 from fluidized bed reactor system 14 can be cooled in a heat exchanger (not shown) and fed into an HP/HT V/L 120 separator where a stream of steam 122 including the light products and distillates boiling below about 1000°F (537.78°C) at the normal boiling point and a stream of liquid 124 including unconverted residue can be separated and processed separately in downstream equipment. Steam stream 122 can be fed into a fixed bed hydroprocessing reactor 126 to perform hydrotreating, hydrocracking or a combination thereof. An effluent stream 128 from the fixed bed reactor system IHRS 126 is fed into the atmospheric tower 18A of the fractionation system 18 to recover various fractions as described with respect to Figure 2. The liquid stream 124 can be cooled in a heat exchanger (not shown) and depressurized into a pressure outlet system (not shown) before being fed into a vacuum fractionation system 18B of the fractionation system 18 to recover various fractions as described with respect to Figure 2.
    [0046] Hydroconversion catalyst compositions for use in the hydroconversion process according to the modalities described herein are well-known to those skilled in the art and several are commercially available from W.R. Grace & Co., Criterion Catalysts & Technologies, and Albemarle, among others. Suitable hydroconversion catalysts can include one or more elements selected from groups 4-12 of the Periodic Table of Elements. In some embodiments, hydroconversion catalysts in accordance with the modalities described herein may comprise, consist of, or consist essentially of one or more of nickel, cobalt, tungsten, molybdenum and combinations thereof, whether unsupported or supported on such a porous substrate such as silica, alumina, titania, or combinations thereof. As supplied from a manufacturer or resulting from a regeneration process, hydroconversion catalysts can be in the form of metal oxides, for example. In some embodiments, hydroconversion catalysts can be presulfated and/or preconditioned prior to introduction into the hydrocracking reactor(s).
    [0047] Distillate hydrotreating catalysts that may be useful include the catalyst selected from those elements known to provide catalytic hydrogenation activity. At least one metal component selected from the group 8-10 elements and/or the group 6 elements is generally chosen. Group 6 elements can include chromium, molybdenum, and tungsten. Group 8-10 elements can include iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, and platinum. The amount(s) of hydrogenation component(s) in the catalyst suitably ranges from about 0.5% to about 10% by weight of the group 8-10 metal component(s) and from about 5 % to about 25% by weight of the Group 6 metal component(s), calculated as the metal oxide(s) per 100 parts by weight of total catalyst, where the weight percentages are based on the weight of the catalyst before sulfation. The hydrogenation components in the catalyst can be in oxidic and/or sulphidic form. If a combination of at least one group 6 and group 8 metal component is present as (mixed) oxides, it will be subjected to a sulfation treatment prior to proper use in hydrocracking. In some embodiments, the catalyst comprises one or more nickel and/or cobalt components and one or more molybdenum and/or tungsten components or one or more platinum and/or palladium components. Catalysts containing nickel and molybdenum, nickel and tungsten, platinum and/or palladium are useful.
    [0048] Waste hydrotreating catalyst that may be useful includes catalysts generally composed of a hydrogenation component, selected from group 6 elements (such as molybdenum and/or tungsten) and group 8-10 elements (such as cobalt and/or nickel) or a mixture thereof, which can be supported on an alumina support. Phosphorus oxide (Group 15) is optionally present as an active ingredient. A typical catalyst may contain from 3 to 35% by weight of the hydrogenation components, with an alumina binder. Catalyst pellets can range in size from 1/32 inch (0.00079375 meters) to 1/8 inch (0.003175 meters) and can be spherical, extruded, trilobed or quadrilobed in shape. In some embodiments, the feed passing through the catalyst zone first contacts a pre-selected catalyst for metal removal, although removal of some sulfur, nitrogen, and aromatics may also occur. Subsequent catalyst layers can be used for sulfur and nitrogen removal, although they are also expected to catalyze metal removal and/or cracking reactions. The catalyst layer(s) for demetallization, when present, may comprise the catalyst(s) having an average pore size ranging from 125 to 225 Angstroms (1.25x10-8 to 2.25x10-8 meters) and a pore volume ranging from 0.5-1.1 cm3/g (0.0005-0.0011 m3/kg). The catalyst layer(s) for the denitrogenation/desulfurization may comprise the catalyst(s) having an average pore size ranging from 100 to 190 Angstroms (1.00x10-8 to 1.90x10-8 meters) with a pore volume 0.5-1.1 cm3/g (0.0005-0.0011 m3/kg). U.S. Patent No. 4,990,243 describes a hydrotreating catalyst having a pore size of at least about 60 Angstroms (6.00x10-9 meters) and preferably about 75 Angstroms (7.50x10-9 meters) at about 120 Angstroms (1.20x10-8 meters). A demetallization catalyst useful for the present process is described, for example, in U.S. Patent No. 4,976,848, the entire description of which is incorporated herein by reference for all purposes. Likewise, catalysts useful for the desulfurization of heavy chains are described, for example, in U.S. Pat. 5,215,955 and 5,177,047, the entire descriptions of which are incorporated herein by reference for all purposes. Catalysts useful for the desulfurization of middle distillate, vacuum gas oil streams, and naphtha streams are described, for example, in U.S. Patent No. 4,990,243 , the entire disclosures of which are incorporated herein by reference for all purposes.
    Useful waste hydrotreating catalysts include those catalysts having a porous refractory base consisting of alumina, silica, phosphorus, or various combinations thereof. One or more types of catalysts can be used as the waste hydrotreating catalyst and where two or more catalysts are used, the catalysts can be present in the reactor zone as layers. Catalysts in the lower layer(s) may have good demetallization activity. Catalysts can also have hydrogenation and desulfurization activity and it may be advantageous to use catalysts with large pore sizes to maximize metal removal. Catalysts having these characteristics are not optimal for the removal of Conradson Carbon Residue and sulfur. The average pore size for the catalyst in the bottom layer or layers will generally be at least 60 Angstroms (6x10-9 meters) and in many cases will be considered larger. The catalyst can contain a metal or combination of metals such as nickel, molybdenum or cobalt. Catalysts useful in the lower layer or layers are described in U.S. Pat. 5,071,805 5,215,955 and 5,472,928. For example, those catalysts as described in U.S. Patent No. 5,472,928 and having at least 20% pores in the range 130 to 170 Angstroms (1.30x10-8 to 1.70x10-8 meters), based on nitrogen method, may be useful in the lower catalyst layer(s). Catalysts present in the upper layer or layers of the catalyst zone should have greater hydrogenation activity as compared to catalysts in the lower layer or layers. Consequently, catalysts useful in the top layer or layers can be characterized by smaller pore size and greater Conradson Carbon Residue removal, denitrogenation and desulfurization activity. Typically, catalysts will contain metals such as, for example, nickel, tungsten, and molybdenum to enhance the hydrogenation activity. For example, those catalysts as described in U.S. Patent No. 5,472,928 and having at least 30% pores in the range of 95 to 135 Angstroms (9.50x10-9 to 1.35x10-8 meters), based on nitrogen method, can be useful in the layers of higher catalysts. Catalysts can be molded catalysts or spherical catalysts. In addition, denser, less friable catalysts can be used in the fixed catalyst zones with upward flow to minimize catalyst particle breakage and particulate entrainment in the product recovered from the reactor.
    [0050] One skilled in the art will recognize that the various catalyst layers may not consist of just a single catalyst, but may be composed of an intermixture of different catalysts to achieve the optimum level of metals or Conradson Carbon Residue removal and desulfurization for that layer. Although some hydrogenation occurs in the lower portion of the zone, the removal of Conradson Carbon, Nitrogen and Sulfur residue may occur primarily in the upper layer or layers. Obviously, the removal of additional metals will also take place. The specific catalyst or catalyst mixture selected for each layer, the number of layers in the zone, the proportional bed volume of each layer and the specific hydrotreating conditions selected will depend on the raw material being processed by the unit, the desired product to be recovered, as well as commercial considerations such as catalyst cost. All of these parameters are within the skill of a person involved in the oil refining industry and should not need further elaboration here.
    [0051] Although described above with respect to separate fractionation systems 18, 38, 98, the modalities described here also contemplate the fractionation of two or more of the effluents 16, 35, 40, 96 in a common fractionation system. For example, effluents 16, 96 can be fed into a common gas cooling, purification and compression loop prior to further processing in an atmospheric tower and a vacuum tower as described above.
    [0052] As described above, the modalities here refer to a system for upgrading residual hydrocarbon feedstocks. The system may include: a residue hydroconversion reactor system for contacting a residual hydrocarbon and hydrogen with a hydroconversion catalyst; a fractionation system for separating an effluent recovered from the waste hydroconversion reactor system into two or more hydrocarbon fractions including at least one vacuum waste fraction and a heavy vacuum gas oil fraction; a mixing device for combining at least a portion of the heavy vacuum gas oil fraction and at least a portion of the vacuum residue fraction to form a mixed heavy hydrocarbon fraction; a coker for converting the mixed heavy hydrocarbon fraction to produce anode grade green coke and distilled hydrocarbons; and a fractionation system for fractionating the distillate hydrocarbons recovered from the coker into three or more hydrocarbon fractions including a light distillate fraction, a heavy gasoil fraction from the coker, and a recycle fraction from the coker.
    [0053] The systems described herein may also include a mixing device for mixing the mixed heavy hydrocarbon fraction with the recycle fraction of the coker to form a coker feed mixture. Mixing devices useful herein may include tees, mixing tees, pumps, agitated vessels, or other devices as known in the art to intimately blend and mix two (possibly viscous) liquid streams.
    [0054] The systems described here may also include a flow metering and control system so that the control of the recycle fraction of the coker is less than 30 percent by weight of the coker feed mixture so as to be in range from about 15 percent by weight to about 25 percent by weight of the coker feed mix.
    [0055] The system may also include: a hydroconversion reactor for contacting the coker diesel heavy fraction and hydrogen with a hydroconversion catalyst to convert at least a portion of the coker diesel heavy fraction to distill fuel strip hydrocarbons ; and a separation system for fractionating a hydroconversion reactor effluent to form two or more hydrocarbon fractions.
    [0056] The systems herein may also include an operating system configured to control the waste hydroconversion reactor system to produce the mixed heavy hydrocarbon fraction having a nickel content of less than about 70 ppm by weight, a vanadium content less than about 70 ppmw, an asphaltenes/Conradson Carbon Residue (CCR) ratio of less than 0.7 to 1 and preferably less than 0.5/1 and more preferably less than 0.3/ 1 and a total sulfur content of less than about 24,000 ppm by weight. The operating system may also be configured to one or more of: controlling the conversion rate in the waste hydroconversion reactor system to be at least 50% and more preferably at least 70% and most preferably at least 85%; operation of the hydroconversion reactor system at a pressure approximately in the range of about 1000 psig (6.89x106 Pa.g) to about 4000 psig (2.76x107 Pa.g), an LHSV in the range of about 0.1 L/h/L at about 4.0 L/h/L, a reactor temperature in the range of about 400°C to about 500°C, a hydrogen feedstock/vacuum residue ratio of about of 2000-6000 SCF/Bbl (356-1068 m3/m3), a fresh catalyst composition ratio in the range of about 0.1 to about 0.6 lb/Bbl (0.007 to certain 0.04 kg/ m3) of residual vacuum raw material; operating the coker at a heating coil output temperature of at least 500°C or at least 520°C; a pressure of about 2035 psig (1.38x105 - 2.41x105 Pa.g) and with a drying time after the coking cycle of at least 2 hours or at least 4 hours or at least 6 hours or at least 8 hours ; operating the exit steam temperature of the coke drum in said coking unit to be at least 470°C or at least 480°C for a drying time of at least 5 hours and preferably at least 8 hours or at least 450° C or at least 460°C for a drying time of at least 6 hours or at least 7 hours by passing a stream of superheated steam through the filled coke drum; Controlling the Coker Yield Ratio, defined as the sum of the coker fresh feed rate plus the coker liquid recycling rate divided by the fresh coker feed rate on a net volumetric basis, to be less than about 1 .25/1 and preferably less than 1.20/1 and more preferably less than about 1.15/1.
    [0057] As described above, the modalities here refer to the conversion of heavy hydrocarbon feedstocks to produce hydrocarbons in the distilled range and anode grade green coke. As an example of the systems and processes described above, the atmospheric and/or vacuum residue derived from the fractionation of crude oil is heated, mixed with hydrogen-rich treatment gas and loaded into the hydrocracking stage which consists of a single or can use a multiplicity of reactors arranged in parallel and/or in series. Here the residue fraction, typically defined as having a boiling point above 524°C (975°F) and preferably above 566°C (1050°F), is hydrocracked under hydrogen partial pressures of 70 to 170 bara ( 1000-2400 psia (70x105 to 170x105 Pa)), temperatures from 380 to 450°C in an LHSV from 0.2 to 2.0 h-1 in the presence of catalyst.
    [0058] Within the fluidized bed, the catalyst is mixed again and kept in random motion by recirculating liquid product. This is done by first separating the recirculated oil from the gaseous products. The oil is then recirculated by means of an external pump or a pump whose rotor is mounted in the lower head of the reactor.
    [0059] The conversion of the target residue from the hydrocracking stage can be in the range of 50 to 88% by weight depending on the raw material being processed. It is anticipated that metal removal will be in the range of 80 to 90%, sulfur removal will be in the range of 80 to 90% and Conradson Carbon Residue (CCR) removal in the range of 45 to 65%.
    [0060] The liquid and vapor effluent from the hydrocracking reactors enters the high pressure and high temperature separator (ie, HP/HT separator). The separated steam is directly routed through a common gas cooling, recycle gas purification and compression system or processed first through an Integrated Hydroprocessing Reactor System, alone or in combination with external distillates and/or distillates generated in the process hydrocracking and thereafter routed a common gas cooling, purification and compression system.
    [0061] The liquid separated from the HP/HT Separator then appeared and was routed to the Atmospheric Distillation System with other distilled products recovered from the cooling and gas purification section. Atmospheric tower bottoms (ie, nominally 360°C to 427°C + boiling fraction) are further processed through a Vacuum Distillation System to recover vacuum distillates. In this case, the product from the lower parts of the vacuum tower (i.e., nominally 482°C to 565°C + boiling fraction) is then routed to a hot Delayed Coking Unit or after cooling, such as through exchange of direct heat or by direct injection of a portion of the waste fed into the product from the lower parts of the vacuum tower. The last route thus eliminates the need for direct heat exchange of product from the lower parts of the vacuum tower, which is known to be fouling.
    [0062] In the Delayed Coking Unit, unconverted oil and heavy vacuum gas oil normally flows through the preheat exchangers to the bottom of the main fractionator under level control. There the feed mixes with the internal recycle liquid (controlled amount within the range of 15% to 25% of fresh feed) condensed from the coke drum effluent. This combined feed and recycle is pumped from the bottom of the fractionator through the coking heater where each pass is flow controlled. A controlled amount of high pressure value is injected into each heater pass to ensure satisfactory speed to minimize coking in the heater tubes. The main function of the coking heater is to quickly heat the feed to the required coking temperature to initiate the cracking reaction without premature formation of coke in the heater tubes.
    [0063] The effluent from the coking heater flows through a switch valve into the bottom of one of the two coke drums where further cracking and then polymerization takes place to form coke. Each drum is designed to be filled to a safe operating level with coke produced during the coking cycle. Antifoam is injected into the coke drum during the last part of the filling cycle to minimize the transport of foam, coke fines and pitch into the fractionator. The coke drum is operated in cycles to maintain continuity of operation with a minimum cycle time of 24 hours being employed in this descriptive report. The operation of each coke drum is staggered. One of the drums of each pair is always in service to receive the effluent from the coking heater.
    [0064] The steam from the coke drum is cooled sharply by heavy diesel to stop the cracking and polymerization reactions and thus minimize the formation of coke in the suspended line from the coke drums to the fractionator. The fractionator is divided into two sections by the heavy diesel extraction vessel. The top section consists of valve trays; the lower section contains special internal parts consisting of a two-layer fractionator spray chamber. Steam from the coke drum enters the fractionator below the spray heads. The steam flows upward through a specially designed lower section of the tower where it contacts the flow drops of the reflux liquid and does not overheat the steam. The internal recycle stream thus condensed is collected at the bottom of the tower where it mixes with the fresh feed load. Steam leaving the lower section of the tower flows to the upper section through risers in the heavy diesel extraction vessel. This steam consists of light hydrocarbons, naphtha, kerosene, light and heavy gas oils, vaporized reflux and steam. This mixture is fractionated in the upper section of the tower.
    [0065] The drying portion of the cycle provides uniform heat distribution and produces a more uniform coke structure and density and allows unreacted tar at the front of the reaction inside the coke drum to complete the coking reaction. Drying the coke bed increases the mechanical strength of coke, thereby increasing coke hardness (improving HGI) and reducing the Volatile Combustible Matter (VCM) of green coke before steam out of the main column or into the purge system.
    [0066] After an empty coke drum is filled until coking it is exchanged for another preheated empty coke drum by means of switch valve(s). The contents of the complete drum are then "dried" for approximately 5 to 8 hours using superheated steam such as coker diesel vapors, coker naphtha, steam and any other suitable superheated non-coking hydrocarbon vapors. After drying, the coke drum filled with anode grade green coke is first vaporized into the main column and then into the purge system followed by the quench/temper operation. Then the coke drum undergoes hydraulic coke withdrawal.
    [0067] The superheated drying medium may consist of superheated steam or superheated vapors generated from the non-coking portion of the C5+ coking liquid or any other hydrocarbon stream that can be vaporized and superheated without the coking risk. The drying medium must be introduced into the coke drum through the inlet feed line, but through a separate line other than the residual oil feed line. The temperature of the superheated steam is controlled around approximately 5IOC at the entrance to the coke drum. The drying cycle continues until a suspended coke drum temperature between 470 to 480C is reached and maintained after 4 to 8 hours of drying time and more preferably 450 to 460C for 4-5 hours. Compared to the increased yield ratio mode, for example, high liquid recycling rates in the coker, the use of a non-coking medium allows for heat distribution without increasing coke production and loss of liquid yield.
    [0068] As described above, the modalities here provide systems and processes for converting heavy hydrocarbon feedstocks to produce hydrocarbons in the distilled range and anode grade green coke. More specifically, the processes described here provide a process for upgrading raw materials from vacuum residues to distill fuel products using fluidized bed or slurry hydrocracking, delayed coking, and fixed bed catalytic VGO upgrade technologies to maximize the costs. coker distillate yields, co-produce high-quality anode-grade coke without resorting to the use of very high coker liquid recycling rates, and co-produce high-quality heavy coker diesel feeds for downstream catalytic VGO upgrade, as per fixed bed hydrocracking or fluid bed catalytic cracking means for distilling fuels.
    [0069] The processes described here have several advantages. For example, the processes described herein may include one or more of the following advantages when compared to current prior art flow schemes, including: higher total distillates yields in coking units and hydrocracking units; the simultaneous co-production of high-grade anode coke; achieving anode coke quality without the need for high coker liquid recycling rates; and the production of high quality coker gas oils, a distillate yields advantage, resulting from higher conversions in the hydroconversion reactor system for the conversion of waste feedstocks and operation of the coker to make anode grade coke under conditions that maximize distillate yields by using relatively low coker liquid recycling rates. The modalities here may not advantageously use light solvents to dilute the asphaltenes in the feed to the Coking Unit. Additionally, the processes here can produce an unexpectedly low polynuclear aromatics content in the HCGO fraction, which allows its efficient and economically advantageous upgrade in a fixed bed hydrocracker rather than a fluid catalytic cracker.
    [0070] In addition, the fluidized bed upstream of the Delayed Coking Unit can effectively unclog the Delayed Coking Unit by reducing the amount of vacuum residue required to be processed while at the same time producing a much higher value coke product. Without this combination, there would be incremental production of low value coke that would adversely impact the refinery's economy. Example
    [0071] According to one or more embodiments of the present description is the use of hydroprocessed vacuum residue fraction from hydrocracking of virgin vacuum residual raw materials, such as in a fluidized bed hydrocracker, which has unique properties than the residues virgin and thermally cracked have no regard for their ability to simultaneously produce anode grade coke and high distillate yields in a delayed coking plant. Said delayed coking unit would be operated under economically desirable reaction conditions to produce anode grade coke. The following experimental example illustrates the comparative performance of feeding a virgin vacuum residue and the raw material of this invention into a delayed coking unit. I. Raw Material Compositions
    [0072] A refinery processes a mixture of crude petroleum oils as shown in Table I-1 below. Crude oil is fractionated in an atmospheric tower to produce virgin distillates and a virgin atmospheric residue fraction. The virgin atmospheric residue is fractionated in a vacuum tower to produce vacuum diesel distillates and a virgin vacuum residue. Table I-1

    [0073] The properties of the virgin vacuum residue are shown in the first column of Table I-2 below. Table I-2
    II. Raw material
    [0074] The virgin vacuum residue fraction is subjected to fluidized bed hydrocracking at 2200 psig (1.52x107 Pa.g), 1.2 LHSV, 440°C reactor temperature and 6000 scf/bbl (1068 m3/g) m3) of treatment rate with H2 over a nickel-based hydroconversion catalyst. The recovered liquid products are subjected to atmospheric fractionation and vacuum fractionation, in which a hydroprocessed vacuum residue (HVR) and a hydroprocessed vacuum gas oil (HVGO) are recovered. The VGO hydroprocessed at 900-1050°F (482.22-565.56°C) is mixed with the vacuum residue hydroprocessed at 1050°F+ (565.56°C+) in a ratio of 0.8/1 by weight . Said mixture is the heavy hydrocarbon feed mixture (stream 35, Figure 1) fed into the Coker. The properties of said stream are shown in the second column of Table I-2. III. Virgin Vacuum Residue Coking
    [0075] The virgin vacuum residue fraction is subjected to delayed coking at an average coke bed temperature at 860°F (460°C), coke drum pressure at 35 psig (2.41x105 Pa.g) and a recycling rate, defined as the weight ratio of the sum of the fresh coker feed and the coker liquid recycling rates to that of the fresh coker feed rate, of 1.25. The coke product failed to meet the anode grade coke specifications as shown in Table III-1 below. Table III-1
    IV. Coking of Hydroprocessed VGO/VR Blend: Effect of Coke Drum Pressure
    [0076] A series of experiments was done to show the effects of coke drum pressure on coke quality and yields of C5+ liquids at coker liquid recycling rate 1.25 and average coke bed temperature at 862- 869°F (461.11 - 465°C). In both tests, anode-grade coke specifications were met. By decreasing coke drum pressure from 35 to 20 psig (2.41x105 to 1.38x105 Pa.g), total C5+ liquid yields by about 5-6 percentage points with a concomitant decrease in coke yields as shown in Table IV-1. Table IV-1
    V. VGO/VR Hydroprocessed Blend Coking: Effect of Liquid Recycle Rate
    [0077] A series of experiments was done to show the effects of coker liquid recycling rate on coke quality and yields of C5+ liquids at coke drum pressure at 20 psig (1.38x105 Pa.g) and temperature coke bed average at 862-869°F (461.11 - 465°C). In both tests, anode-grade coke specifications were met. By decreasing the coker liquid recycling rate from 1.35 to 1.25, the total C5+ liquid yields increase by about 4 percentage points with a concomitant decrease in coke yields as shown in Table V-1 below. Table V-1

    [0078] Although the description includes a limited number of embodiments, those of skill in the art having the benefit of this description will appreciate that other embodiments may be devised which do not depart from the scope of the present description. Consequently, the scope is to be limited only by the appended claims.
    权利要求:
    Claims (26)
    [0001]
    1. Process for upgrading residual hydrocarbon feedstocks, CHARACTERIZED by comprising: contacting a residual hydrocarbon (10) and hydrogen (12) with a hydroconversion catalyst in a residue hydroconversion reactor system (13); recovering an effluent (15) from the waste hydroconversion reactor system (13); separating the effluent (15) from the waste hydroconversion reactor system (13) to recover two or more fractions of hydrocarbon (20, 22, 24, 26, 28, 30, 32, 34) including at least one fraction of waste a vacuum (34) and a heavy vacuum gas oil fraction (32); combining at least a portion of the heavy vacuum gas oil fraction (32) and at least a portion of the vacuum residue fraction (34) to form a mixed heavy hydrocarbon fraction (35); feeding at least a portion of the mixed heavy hydrocarbon fraction (35) into a coker (36); operating the coker (36) under conditions to produce anode grade green coke (72) and distilled hydrocarbons (40); recovering distilled hydrocarbons (40) from the coker (36); fractionating the distillate hydrocarbons (40) recovered from the coker (36) to recover three or more hydrocarbon fractions including a light distillates fraction (21), a heavy gas oil fraction from the coker (23), and a recycle fraction from the coker ( 25).
    [0002]
    A process according to claim 1, further comprising mixing the mixed heavy hydrocarbon fraction (35) with the recycle fraction from the coker (25) to form a coker feed mixture (39).
    [0003]
    3. Process according to claim 2, CHARACTERIZED by the fact that the recycle fraction of the coker (25) is less than 30 percent by weight of the coker feed mixture (39).
    [0004]
    4. Process according to claim 2, CHARACTERIZED by the fact that the recycle fraction of the coker (25) is from about 15 percent by weight to about 25 percent by weight of the coker feed mixture (39 ).
    [0005]
    5. Process according to claim 1, CHARACTERIZED in that it further comprises: contacting the heavy fraction of gas oil from the coker (23) and hydrogen (29) with a hydroconversion catalyst in a hydroconversion reactor (94) to convert at least one portion of the heavy gas oil fraction from the coker (23) for distilling fuel strip hydrocarbons; recovering an effluent (96) from the hydroconversion reactor (94); and fractionating the effluent (96) to form two or more hydrocarbon fractions (99, 100, 102, 104, 106, 108, 110, 112).
    [0006]
    6. Process according to claim 1, CHARACTERIZED by the fact that the heavy fraction of gas oil in the coker (23) has a Polycyclic Index based on Ultraviolet Absorption Spectrometry of less than 10,000.
    [0007]
    7. Process according to claim 1, CHARACTERIZED by the fact that the residual hydrocarbon (10) has a metal content less than about 100 ppm by weight of nickel and less than about 200 ppm of vanadium, a sulfur content less than about 2.5 percent by weight and an asphaltenes content less than about 12 percent by weight.
    [0008]
    8. Process according to claim 1, CHARACTERIZED by the fact that the mixed heavy hydrocarbon fraction (35) has a nickel content of less than about 70 ppm by weight, a vanadium content of less than about 70 ppm by weight, an Asphaltenes/Conradson Carbon Residue (CCR) ratio of less than 0.7 to 1, and a total sulfur content of less than about 24,000 ppm by weight.
    [0009]
    9. Process according to claim 1, CHARACTERIZED by the fact that the residual hydrocarbon (10) comprises at least one of the atmospheric or vacuum oil residues, deasphalted oils, deasphalting pitch, hydrocracked atmospheric tower or lower part of the vacuum tower , straight-line vacuum diesel, hydrocracked vacuum diesel, fluid catalytically cracked slurry oils (FCC), vacuum diesel from a fluidized bed process, shale derived oils, coal derived oils, crude oils bioderivatives, tar sand bitumen, tall oils, black oils.
    [0010]
    10. Process according to claim 1, CHARACTERIZED by the fact that the conversion rate in the waste hydroconversion reactor system (13) is at least 50%.
    [0011]
    11. Process according to claim 1, CHARACTERIZED by the fact that the residual hydrocarbon (10) is a vacuum residue raw material and the residue hydroconversion reactor system (13) is operated at: a pressure in the range from about 1000 psig (6.89x106 Pa.g) to about 4000 psig (2.76x107 Pa.g); LHSV in the range of about 0.1 to about 4.0 L/h/L; a reactor temperature in the range of about 400°C to about 500°C; a hydrogen feedstock/vacuum residue ratio of about 2000-6000 SCF/Bbl (356-1068 m3/m3); a fresh catalyst composition ratio in the range of about 0.1 to 0.6 lb/Bbl (0.007 to 0.04 kg/m3) of vacuum residual feedstock; and using a catalyst comprised of one or more of nickel, cobalt, tungsten, molybdenum and combinations thereof, whether unsupported or supported on a porous substrate such as silica, alumina, titania, or combinations thereof.
    [0012]
    12. Process according to claim 1, CHARACTERIZED by the fact that the coker (36) is operated at: a heating coil outlet temperature of at least 500°C; a pressure in the range of about 20 psig (1.4x105 Pa.g) to about 35 psig (2.41x105 Pa.g); and with a drying time after the coking cycle of at least 2 hours.
    [0013]
    13. Process according to claim 1, CHARACTERIZED by the fact that the exit temperature of steam from the coke drum in said coking unit (36) is operated at: at least 470°C for a drying time of at least at least 5 hours, or at least 450°C for a drying time of at least 6 hours by passing a stream of superheated steam through the filled coke drum.
    [0014]
    14. Process according to claim 1, CHARACTERIZED by the fact that said anode grade green coke has the following properties: nickel less than about 175 ppm; vanadium less than about 250 ppm; sulfur less than about 35,000 ppm by weight; Hardgrove Grinding Index less than about 100 and Combustible Volatile Matter less than about 12% by weight.
    [0015]
    15. Process according to claim 1, CHARACTERIZED by the fact that the coker (36) is operated at a Coker Yield Ratio, defined as the sum of the fresh coker feed rate plus the liquid recycling rate of the coker divided by the fresh coker feed rate on a liquid volumetric basis, less than about 1.25/1.
    [0016]
    16. Process according to claim 1, CHARACTERIZED by the fact that the residual hydrocarbon (10) is a vacuum residue raw material derived from one or more of the crude oils Arab Heavy, Arab Light, Banoco Arab Medium , Kuwait Export, Basrah Light, Rubble, Bahrain, Oman, Upper Zakam, REBCO, Kumkol, Azeri Light, Siberian Light, Siberian Heavy, and Tengiz.
    [0017]
    17. System for upgrading residual hydrocarbon feedstocks, CHARACTERIZED by comprising: a waste hydroconversion reactor system (13) for contacting a residual hydrocarbon (10) and hydrogen (12) with a hydroconversion catalyst; a fractionation system (18) for separating an effluent (15) recovered from the waste hydroconversion reactor system (13) into two or more hydrocarbon fractions (20, 22, 24, 26, 28, 30, 32, 34) including at least a vacuum residue fraction (34) and a heavy vacuum gas oil fraction (32); a mixing device for combining at least a portion of the heavy vacuum gas oil fraction (32) and at least a portion of the vacuum residue fraction (34) to form a mixed heavy hydrocarbon fraction (35); a coker (36) for converting the mixed heavy hydrocarbon fraction (35) to produce anode grade green coke (72) and distilled hydrocarbons (40); a fractionation system (38) for fractionating the distillate hydrocarbons (40) recovered from the coker (36) into three or more hydrocarbon fractions including a light distillates fraction (21), a heavy gasoil fraction from the coker (23), and a recycle fraction from the coker (25), and carrying out the process for updating residual hydrocarbon raw materials as defined in claims 1 to 16.
    [0018]
    18. The system according to claim 17, characterized in that it further comprises a mixing device for mixing the mixed heavy hydrocarbon fraction (35) with the recycle fraction of the coker (25) to form a coker feed mixture ( 39).
    [0019]
    19. The system according to claim 17, CHARACTERIZED by further comprising a flow measurement and control system so that the control of the recycle fraction of the coker (25) is less than 30 percent by weight of the feed mixture of the coker (39).
    [0020]
    20. The system according to claim 17, CHARACTERIZED by further comprising a flow measurement and control system so that the control of the recycle fraction of the coker (25) is from about 15 percent by weight to about 25 percent percent by weight of the coker feed mix (39).
    [0021]
    21. The system according to claim 17, CHARACTERIZED in that it further comprises: a hydroconversion reactor (94) for contacting the heavy fraction of gas oil from the coker (23) and hydrogen (29) with a hydroconversion catalyst to convert at least a portion of the heavy gasoil fraction from the coker to distillate fuel strip hydrocarbons; and a separation system (98) for fractionating an effluent (96) from the hydroconversion reactor (94) to form two or more hydrocarbon fractions (99, 100, 102, 104, 106, 108, 110, 112).
    [0022]
    22. The system of claim 17, further comprising an operating system configured to control the waste hydroconversion reactor system (13) to produce a mixed heavy hydrocarbon fraction (35) having a nickel content of less than about of 70 ppm by weight, a vanadium content of less than about 70 ppm by weight, a Conradson Asphaltenes/Carbon Residue (CCR) ratio of less than 0.7 to 1, and a total sulfur content of less than about 24,000 ppm by weight.
    [0023]
    23. System according to claim 17, CHARACTERIZED by the fact that the coker (36) is a delayed coker.
    [0024]
    24. System according to claim 17, CHARACTERIZED by the fact that the waste hydroconversion reactor system (13) comprises a fluidized bed hydroconversion reactor system.
    [0025]
    25. System according to claim 17, CHARACTERIZED by the fact that the waste hydroconversion reactor system (13) comprises a slurry phase hydrocracking process.
    [0026]
    26. The system according to claim 17, CHARACTERIZED by the fact that the hydroconversion reactor (94) comprises a fixed bed VGO hydrocracking reactor system, a fluidized bed VGO hydrocracking reactor system.
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    同族专利:
    公开号 | 公开日
    RU2628067C2|2017-08-14|
    BR112015023148A8|2019-09-03|
    TWI490326B|2015-07-01|
    PT2970787T|2019-02-21|
    TW201446958A|2014-12-16|
    KR101831041B1|2018-02-21|
    KR20150139538A|2015-12-11|
    CA2908540A1|2014-10-02|
    MX2015012422A|2016-04-25|
    RS58353B1|2019-03-29|
    RU2015143429A|2017-04-28|
    CN105164233B|2017-07-04|
    HRP20190293T1|2019-04-05|
    MY172502A|2019-11-27|
    US20140275676A1|2014-09-18|
    WO2014158527A1|2014-10-02|
    BR112015023148A2|2017-07-18|
    CN105164233A|2015-12-16|
    BR112015023148B8|2021-09-14|
    EP2970787A4|2017-01-04|
    ES2711399T3|2019-05-03|
    SG11201507544QA|2015-10-29|
    HUE042580T2|2019-07-29|
    US9452955B2|2016-09-27|
    TR201902143T4|2019-03-21|
    EP2970787B1|2018-11-14|
    CA2908540C|2018-01-16|
    PL2970787T3|2019-05-31|
    EP2970787A1|2016-01-20|
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    法律状态:
    2018-11-13| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2019-10-08| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2020-06-30| B06A| Patent application procedure suspended [chapter 6.1 patent gazette]|
    2021-02-09| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-06-08| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 21/02/2014, OBSERVADAS AS CONDICOES LEGAIS. |
    2021-09-14| B16C| Correction of notification of the grant [chapter 16.3 patent gazette]|Free format text: REF. RPI 2631 DE 08/06/2021 QUANTO AO TITULO. |
    优先权:
    申请号 | 申请日 | 专利标题
    US201361784462P| true| 2013-03-14|2013-03-14|
    US61/784,462|2013-03-14|
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