阅读说明：本技术 用于加氢处理烃残留物流的方法 (Process for hydrotreating a hydrocarbon residue stream ) 是由 孙平 于 2020-08-31 设计创作，主要内容包括：本发明题为“用于加氢处理烃残留物流的方法”。本发明提供了一种用于加氢处理烃残留物流的方法。所述方法包括通过脱金属催化剂加氢处理所述烃残留物流以使所述烃残留物流脱金属以提供金属和硫浓度降低的脱金属烃残留物流。在热分离器中分离所述脱金属烃残留物流以提供包含氢气的塔顶蒸汽流和塔底液体流。将所述塔底液体流分成第一液体流和包含低硫燃料油的第二液体流。回收所述第二液体流作为低硫燃料油产物流。在所述塔顶蒸汽流的至少一部分的存在下,通过脱硫催化剂加氢处理所述第一液体流以提供脱硫烃残留物流。本发明方法提供了包含0.3重量％至1.5重量％的硫的低硫燃料油产物流。(The invention relates to a method for hydrotreating a hydrocarbon residue stream. The present invention provides a process for hydrotreating a hydrocarbon residue stream. The process includes hydrotreating the hydrocarbon residue stream over a demetallization catalyst to demetallize the hydrocarbon residue stream to provide a demetallized hydrocarbon residue stream having a reduced concentration of metals and sulfur. The demetallized hydrocarbon residue stream is separated in a hot separator to provide an overhead vapor stream comprising hydrogen and a bottom liquid stream. The bottoms liquid stream is separated into a first liquid stream and a second liquid stream comprising a sweet fuel oil. Recovering the second liquid stream as a low sulfur fuel oil product stream. Hydrotreating the first liquid stream over a desulfurization catalyst in the presence of at least a portion of the overhead vapor stream to provide a desulfurized hydrocarbon residue stream. The present process provides a low sulfur fuel oil product stream comprising from 0.3 wt.% to 1.5 wt.% sulfur.)

1. A process for hydrotreating a hydrocarbon residue stream, the process comprising:

a) hydrotreating said hydrocarbon residue stream over a demetallization catalyst in the presence of a first hydrogen stream to demetallize said hydrocarbon residue stream to provide a demetallized hydrocarbon residue stream having a reduced concentration of metals and sulfur;

b) separating the demetallized hydrocarbon residue stream in a hot separator to provide an overhead vapor stream comprising hydrogen and a bottom liquid stream;

c) said bottoms liquid stream is divided into a first liquid stream and a second liquid stream comprising sweet fuel oil;

d) recovering said second liquid stream as a low sulfur fuel oil product stream; and

e) hydrotreating the first liquid stream over a desulfurization catalyst in the presence of a second hydrogen stream to provide a desulfurized hydrocarbon residue stream.

2. The method of claim 1, wherein recovering the second liquid stream as a low sulfur fuel oil product stream comprises separating the second liquid stream to provide a flash overhead stream and the low sulfur fuel oil product stream.

3. The method of claim 1, wherein the low sulfur fuel oil product stream comprises sulfur in an amount of 0.3 wt.% to 1.5 wt.%.

4. The method of claim 1, further comprising separating the desulfurized hydrocarbon residue stream to provide a vapor stream and a liquid stream.

5. The process of claim 4, further comprising separating the liquid stream to provide a hot flash vapor stream and a hot flash liquid stream.

6. The method of claim 5, further comprising:

said hot flash liquid stream is divided into a first flash liquid stream and a second flash liquid stream; and

mixing the first flash liquid stream with the second liquid stream to produce the low sulfur fuel oil product stream comprising from 0.05 wt% to 0.5 wt% sulfur.

7. The process of claim 4, further comprising separating the vapor stream in a second cold separator to provide a second cold vapor stream and a second cold liquid stream, and obtaining the first hydrogen stream from the second cold vapor stream.

8. The method of claim 7, wherein the entire second cold vapor stream is taken as the first hydrogen stream.

9. The process of claim 1, further comprising separating the overhead vapor stream in a first cold separator to provide a first cold vapor stream and a first cold liquid stream.

10. The method of claim 9, further comprising separating the first cold vapor stream into a purge stream and a recycle stream; and

the recycle stream is used as the second hydrogen stream.

Technical Field

The art relates to processes for hydrotreating hydrocarbon residue streams. In particular, the art relates to the desulfurization of hydrocarbon residue streams.

Background

Produced from the bottom of a fractionating columnA residue or a residue stream. The Atmospheric Residue (AR) is the bottom product of the atmospheric column. The Vacuum Residue (VR) is the bottom product of the vacuum distillation column. One application of a residue stream is for the production of a particular process feed. A residue stream is a generic term describing a hydrocarbon-containing stream having a boiling point higher than that which can be distilled in a distillation column. For example, in relation to atmospheric distillation of the prior art, a majority of the weight fraction of the residue oil has a boiling point greater than 343 ℃ (650 ° F). If vacuum distillation of the prior art is involved, most of the weight fraction of the residue oil has a boiling point greater than 524 ℃ (975 ° F). One of the main applications of the residual stream is as fuel in ships. The main type of "tank" oil of ships is heavy fuel oil, which is distilled from crude oil as a residue. The residue contains sulfur, which eventually becomes an emission from the ship after combustion in the engine. Sulfur oxides (SOx) are known to be harmful to human health and the environment. Limiting SO from ships_xEmissions will improve air quality and protect the environment.

For reducing Sulfur Oxides (SO) from ships_x) The International Marine Organization (IMO) regulation of emissions was first in effect in 2005, according to annex VI of the international convention for preventing pollution from ships (known as MARPOL convention). The MARPOL convention is intended to prevent ship contamination of the marine environment for operational or accidental reasons. MARPOL specifies limits for sulfur-containing compounds; for example, Sulfur Oxides (SO) emitted from exhaust gas of ships_x) And in particular to the deliberate emission of sulphur-containing compounds. Since then, the limits on sulfur oxides have been gradually tightened. Before 31/12/2019, the limit of the sulfur content of the fuel oil of the ship was 3.50% m/m (mass/mass) for ships operating outside the emission control area. From 1/2020, the limit of sulfur in fuel oil used on ships operating outside the specified emission control region has been further reduced to 0.50% m/m (mass/mass). IMO regulations are designed to significantly reduce the amount of sulfur oxides emanating from ships and provide significant health and environmental benefits to the world, particularly for people living near ports and coasts.

The residual stream contains high boiling hydrocarbon and heteroatom rich contaminants. Hydrotreating is a hydrotreating process whose primary purpose is to remove metals, sulfur and nitrogen from atmospheric residue or vacuum residue feeds to make the product suitable for use as fuel oil meeting environmental regulations, or to produce an intermediate product that can be further processed in another refining process. Hydrotreating is a process that applies a catalytic hydrogenation reaction to sulfur, nitrogen-containing sites, and unsaturated carbon molecules to remove sulfur, nitrogen, and heavy metals from residual oil molecules, thereby producing valuable fuel oil end products or intermediates with suitable properties for feeding into other processes. Other classes of hydroprocessing (e.g., hydrocracking) focus on boiling point reduction, in many cases targeted for mass fraction reduction above 50 wt% of the material, to bring boiling points in the residue stream equal to or above 524 ℃ (975 ° F) to boiling points below 524 ℃ (975 ° F), compared to hydroprocessing of residue oils for heteroatom removal and aromatic/naphthenic ring saturation.

Hydrotreating and hydrocracking are distinguished by the inherent chemistry and operating conditions of each of these processes. The hydrotreatment of residual oils in many cases relies on hydrogenation of unsaturated carbon-carbon ring structures or carbon-heteroatom bonds, which due to their exothermic nature benefit thermodynamically from lower temperatures. The net result of hydrotreating is to maximize heteroatom removal and carbon-carbon bond saturation, but a smaller boiling point reduction does occur due to molecular matrix decomposition. However, the boiling point shift of materials with boiling points of 523 ℃ (975 ° F) or higher is limited to 20% to 50% or lower due to the hydroprocessing reactions only. In contrast, a viable hydrocracking process requires higher temperatures to occur due to the need to overcome bonds to effectively lower boiling points as compared to hydrotreating. This is particularly true for treating residue feeds, thereby making the residue feed hydrocracking process conditions significantly different from the hydrotreating process conditions. Hydrocracking processes that treat the residue feed are operated at much higher hydrotreating conditions, such as at 426 ℃ (800 ° F) or higher temperatures, to achieve a target 50% or higher conversion of materials with boiling points of 523 ℃ (975 ° F) or higher. Hydrocracking catalysts with more cracking functionality may be applied when the hydrocracking process is used for residue feed boiling point reduction. However, it was found that hydrocracking catalysts have a significantly shortened life when processing residual feedstocks due to severe catalyst deactivation by residual molecules.

To meet various environmental conditions (such as MARPOL environmental conditions), refiners are trading off technical solutions for producing fuel products to meet newer and more stringent sulfur specifications. It would be highly desirable to have a residue oil hydrotreating process that can effectively demetallize and desulfurize the residue stream below a particular sulfur specification. The dynamically changing fuel oil prices and the option of using the residual oil hydrotreating process to produce a range of quality and priced streams provide the refiner with the opportunity to optimize its processing and maximize profits at different prices.

Accordingly, there is a need for alternative processes for hydrotreating a residue stream to provide a demetallized and desulfurized residue stream. Moreover, it would be desirable to provide new apparatus and methods for providing cost-effectiveness in terms of lower capital and operating expenditures. Other desirable features and characteristics of the present subject matter will become apparent from the subsequent detailed description of the subject matter and the appended claims, taken in conjunction with the accompanying drawings and this background of the subject matter.

Disclosure of Invention

Various embodiments contemplated herein relate to methods and apparatus for hydrotreating a hydrocarbon residue stream. The exemplary embodiments presented herein provide a process for hydrotreating a hydrocarbon residue stream.

According to an exemplary embodiment, a process for hydrotreating a hydrocarbon residue stream is provided. The process includes hydrotreating the hydrocarbon residue stream over a demetallization catalyst in the presence of a hydrogen stream to demetallize the hydrocarbon residue stream to provide a demetallized hydrocarbon residue stream having a reduced concentration of metals and sulfur. The demetallized hydrocarbon residue stream can be separated in a hot separator to provide an overhead vapor stream comprising hydrogen and a bottom liquid stream. The bottoms liquid stream can be separated into a first liquid stream and a second liquid stream comprising a sweet fuel oil. The second liquid stream can be recovered as a low sulfur fuel oil product stream. The first liquid stream can also be hydrotreated over a desulfurization catalyst in the presence of at least a portion of the overhead vapor stream to provide a highly desulfurized hydrocarbon residue stream.

According to another exemplary embodiment, a process for hydrotreating a hydrocarbon residue stream is provided. The process comprises adding a hydrogen stream to the hydrocarbon residue stream. The hydrocarbon residue stream may be hydrotreated in the presence of the hydrogen stream over a demetallization catalyst to demetallize the hydrocarbon residue stream to provide a demetallized hydrocarbon residue stream having reduced concentrations of metals and sulfur. The demetallized hydrocarbon residue stream can be separated in a first stage hot separator to provide a first stage vapor stream comprising hydrogen and a first stage liquid stream. The first stage liquid stream can be divided into a first liquid stream and a second liquid stream comprising sweet fuel oil. The second liquid stream can be recovered as a low sulfur fuel oil product stream. The first liquid stream can be hydrotreated over a desulfurization catalyst in the presence of at least a portion of the first stage vapor stream to provide a highly desulfurized hydrocarbon residue stream. The desulfurized hydrocarbon residue stream can be separated in a second stage hot separator to provide a second stage vapor stream and a second stage liquid stream. At least a portion of the second stage liquid stream can be mixed with the low sulfur fuel oil product stream to meet final low sulfur fuel oil product specifications. The remaining portion of the second stage liquid stream may be withdrawn as a co-product stream which may be further processed.

The disclosed method contemplates providing a low sulfur fuel oil product that meets the latest MARPOL regulations in force from 1 month 1 day 2020. The process of the present disclosure provides a low sulfur fuel oil product having sulfur in an amount less than 0.5 wt.%. The low sulfur fuel oil product obtained by the present current process meets current regulations for MARPOL regulations on sulfur that may be present in the fuel oil. Optionally, the present scheme can co-produce another residue product stream that can be suitable for other refining processes, such as Fluid Catalytic Cracking (FCC). The process for hydrotreating a hydrocarbon residue stream of the present disclosure also provides flexible refiner options in terms of product make-up. The process is applicable to conditions targeted for controlled removal from the residue oil product that differ from typical conditions of a hydrocracking process targeted for at least 50% conversion of materials in the residue oil feed having a boiling point of 523 ℃ (975 ° F) or higher, more specifically, the difference depending on operating temperature conditions.

These and other features, aspects, and advantages of the present disclosure will become better understood with regard to the following detailed description, accompanying drawings, and appended claims.

Drawings

Various embodiments are described below in conjunction with the following drawing figures, wherein like numerals denote like elements.

FIG. 1 is a schematic diagram of a process and apparatus for hydrotreating a hydrocarbon residue stream, according to an exemplary embodiment.

Definition of

As used herein, the term "column" means one or more distillation columns for separating the components of one or more different volatile materials. Unless otherwise noted, each column includes a condenser at the top of the column to condense the overhead vapor and reflux a portion of the overhead stream to the top of the column. A reboiler at the bottom of the column is also included to vaporize and return a portion of the bottoms stream to the bottom of the column to provide fractionation energy. The feed to the column may be preheated. The top pressure is the pressure of the overhead vapor at the column outlet. The bottom temperature is the liquid bottom outlet temperature. Overhead and bottoms lines refer to the net lines to the column from the column downstream of reflux or reboil. Alternatively, the stripping stream may be used for heat input at the bottom of the column.

As used herein, the term "stream" may include various hydrocarbon molecules and other materials.

As used herein, the term "overhead stream" may mean a stream withdrawn from the top of a vessel (such as a column) or a line extending at or near the top.

As used herein, the term "bottoms stream" can mean a stream withdrawn from the bottom of a vessel (such as a column) or a line extending at or near the bottom.

As used herein, the term "transfer" includes "feeding" and "filling" and means the transfer of a substance from a tube or container to an object.

As used herein, the term "fraction" means an amount or fraction taken from or separated from the main stream without any change in composition as compared to the main stream. In addition, it includes dividing the extracted or separated portion into a plurality of portions, wherein each portion maintains the same composition as compared to the main stream.

As used herein, the term "unit" may refer to a region that includes one or more items of equipment and/or one or more sub-units. Equipment items may include one or more reactors or reactor vessels, heaters, separators, tanks, exchangers, piping, pumps, compressors, and controllers. In addition, an equipment item such as a reactor, dryer, or vessel may also include one or more units or sub-units.

The term "communicate" means operatively permitting the flow of a substance between enumerated components.

The term "downstream communication" means that at least a portion of a substance flowing to the body in downstream communication can operatively flow from an object with which it is in communication.

The term "upstream communication" means that at least a portion of the substance flowing from the body in upstream communication can operatively flow to the object in communication therewith.

The term "directly in communication with" or "directly" means flowing from an upstream component into a downstream component without compositional changes due to physical fractionation or chemical conversion.

As used herein, the term "boiling point" refers to the boiling point of a material more conveniently determined by gas chromatography simulated distillation methods ASTM D-2887 and ASTM D-7169.

As used herein, the term "true boiling point" (TBP) means a test method corresponding to ASTM D-2892 for determining the boiling point of a material used to produce standardized masses of liquefied gases, fractions and residues from which analytical data can be obtained, and determining the yields of such fractions by both mass and volume from which a plot of distillation temperature versus mass% is obtained in a column having a reflux ratio of 5: 1 using fifteen theoretical plates.

As used herein, the term "initial boiling point" (IBP) means the temperature at which a sample begins to boil, as determined using ASTM D-7169.

As used herein, the terms "T5", "T70", or "T95" refer to the temperature at which a sample boils at 5, 70, or 95 mass percent (as the case may be) using ASTM D-7169, respectively.

As used herein, the term "separator" means a vessel having an inlet and at least one overhead vapor outlet and one bottom liquid outlet, and may also have an outlet for an aqueous stream from a storage tank (boot). The flash tank is one type of separator that may be in downstream communication with the separator. The separator may be operated at a higher pressure than the flash tank.

As used herein, the term "Conradson carbon residue" or "CCR" means the weight fraction of carbonaceous residue after standard oil pyrolysis testing using ASTM D189. CCR can be estimated from microcarbon residue (MCR) in a similar test by ASTM D4530, but with a much smaller amount of sample. CCR measures the extent of oil coking tendency or hydrogen deficiency.

Detailed Description

The following detailed description is merely exemplary in nature and is not intended to limit the various embodiments or the application and uses thereof. Furthermore, there is no intention to be bound by any theory presented in the preceding background or the following detailed description. The drawings are simplified by eliminating the large number of equipment typically employed in processes of this nature, such as vessel internals, temperature and pressure control systems, flow control valves, recirculation pumps, etc. (which are not particularly required to illustrate the performance of the process). Furthermore, the description of the current method in the embodiments of the specific figures is not intended to limit the method to the specific embodiments described herein.

As shown, the process flow lines in the figures may be interchangeably referred to as, for example, lines, pipes, branches, distributors, streams, effluents, feeds, products, portions, catalyst, withdrawals, recycles, pumps, discharges, and coke breeze.

The present invention provides a two-stage hydroprocessing process for hydroprocessing hydrocarbon residue streams with flexible product targets. The process for hydrotreating a hydrocarbon residue stream is addressed with reference to the process and apparatus 100 according to the embodiment shown in the figure. Referring to the figures, the process and apparatus 100 includes a first stage hydroprocessing unit 101, a first stage separation section 161, a second stage hydroprocessing unit 201, and a second stage separation section 261. In an exemplary embodiment, the hydrocracking unit 101 may include a two-stage hydrocracking reactor. As shown, the hydrocarbon residue stream in residue line 102 and the first stage hydrogen stream in first hydrogen line 282 are fed to the first stage hydroprocessing unit 101.

In one embodiment, the hydrocarbon residue stream may comprise a hydrocarbon feed stream comprising a residue hydrocarbonaceous feedstock. The residual hydrocarbonaceous feedstock can be taken from the bottom of an atmospheric fractionation column or a vacuum fractionation column. In exemplary embodiments, the hydrocarbon residue stream can include AR having T5 of 316 ℃ (600 ° F) to 399 ℃ (750 ° F) and T70 of 510 ℃ (950 ° F) to 704 ℃ (1300 ° F). VR with T5 in the range of 482 ℃ (900 ° F) to 565 ℃ (1050 ° F) may also be suitable feeds. VR, atmospheric gas oil of T5 having 288 ℃ (550 ° F) to 315 ℃ (600 ° F) and Vacuum Gas Oil (VGO) of T5 having 316 ℃ (600 ° F) to 399 ℃ (750 ° F) can also be blended with AR to make suitable residue feeds. Deasphalted oil, visbreaker bottoms, clarified slurry oil, and shale oil may also be suitable residue feeds, alone or blended with AR or VR.

Typically, these residual feeds contain large concentrations of metals that need to be removed by contacting an HDM catalyst designed to have large storage for metal-containing byproducts before deeper catalytic desulfurization can occur, as the metals will adsorb on the HDS catalyst, thereby reducing the surface available for reaction and lacking storage to deactivate it. Suitable residue feeds can include from 50 to 500wppm metals or less than 200wppm metals. Nickel, vanadium and iron are some typical metals in the residual feed. The residue feed may comprise 5 to 200wppm nickel, 50 to 500wppm vanadium, 1 to 150wppm iron and/or 5 to 25 wt.% Conradson carbon residue. The residue feed may comprise from 10,000wppm to 60,000wppm sulfur. Generally, contaminants that may be present in the residue feed and their Conradson carbon residue can be characterized by a range of residue oil specific chemistries (e.g., the presence of asphaltenes) and can be measured as the amount of material that is insoluble in low carbon number solvents such as n-heptane or n-pentane. Thus, a hydrotreating process for a residue comprising a feedstock has unique and different considerations compared to a feed comprising no residue or minimal residue. Typically, refineries have target product specifications, depending on the downstream application of the hydrotreated product, primarily sulfur and metals content. In an exemplary embodiment, the process can employ a feed comprising at least 50 wt.% of material having a boiling point greater than 343 ℃ (650 ° F). In another exemplary embodiment, the process may employ a feed comprising at least 8 wt% asphaltenes.

The first stage hydrogen stream in first hydrogen line 282 can be combined with the residue stream in residue line 102 to provide a hydrocarbon residue stream in residue feed line 104. The hydrocarbon residue stream in residue feed line 104 can be heated in fired heater 110. Optionally, the hydrocarbon residue stream in the residue feed line 104 and the first stage hydrogen stream in the first hydrogen line 282 can be separately passed to the fired heater 110. The heated hydrocarbon residue stream in the residue feed line 112 can be fed to the first demetallization reactor 120 of the first stage hydroprocessing unit 101.

Hydrotreating is a process in which hydrogen is contacted with hydrocarbons in the presence of a hydrotreating catalyst that is primarily used to remove heteroatoms, such as sulfur, nitrogen, and metals, from a hydrocarbon feedstock. Hydrotreating of residual oil feeds mainly applies hydrogenation conditions for aromatic or naphthenic saturation and removal of sulfur or nitrogen elements by chemical bond weakening induced by bond saturation between carbon and heteroatom molecules and subsequent chemical bond cleavage. Typically, the residue oil hydrotreating process employs such hydrogenation conditions, including hydrotreating temperatures of 405 ℃ (760 ° F) or less. In contrast, hydrocracking conditions typically include a hydrocracking temperature of 426 ℃ (800 ° F) or higher to achieve a reduction in the boiling point of the residue molecules. However, hydrocracking processes of residual oils can remove contaminants, primarily through temperature-enabled radical cracking mechanisms or less through hydrogenation of unsaturated bonds due to thermodynamic limitations. In particular, due to thermodynamic limitations, a process operating at residue feed hydrocracking conditions will not achieve appreciable hydrogenation of unsaturated carbon-carbon bonds, and instead, if effective control measures are not taken to prevent coke build-up and deposition in the reactor system, the dehydrocondensation reaction will proceed to a level that in many cases results in excessive coke formation. In many cases, processes operating under residue feed hydrocracking conditions avoid the application of fixed bed catalyst within the reactor, thereby avoiding coke deposition or deactivation of any catalyst surface that is standing in the reactor. Thus, if used in conjunction with hydrotreating catalysts and processes, in many cases results in short runs, making the process commercially impractical.

Hydrotreating is a process of applying a catalytic hydrogenation reaction to sulfur, nitrogen-containing sites, and unsaturated carbon molecules to remove sulfur, nitrogen, and heavy metals from residual oil molecules. In the hydrotreating process, the hydrocarbon aromatic ring molecules are stabilized by stable isomerization. Generally, hydrogenation of aromatic rings is aided by heterogeneous catalysts that catalyze the dissociation of hydrogen, and further attaches the conjugated pi-bonds of the aromatic structures and converts them to sigma carbon-carbon bonds, forming cycloalkane rings. Sulfur-containing hydrocarbon molecules (especially thiophene compounds) also rely on active sites on the catalyst for transfer, in many cases as a key step by thiophene ring opening or hydrogenation. All hydrogenation reactions are thermodynamically more favored by lower temperatures. Thus, under commercial reactor conditions, the hydrotreating reactor is operated with a fixed bed supported catalyst, and the reactor temperature is typically maintained below 426 ℃ (800 ° F) to achieve the appropriate degree of aromatic ring hydrogenation, hydrodesulfurization, or hydrodenitrogenation.

In contrast, cracking reactions involve carbon-carbon bond cleavage and benefit thermodynamically from higher temperatures. As a net result of the cracking reaction, large molecules are converted to smaller molecules, resulting in a reduction in boiling point. The cracking reaction is usually accompanied by thermal cracking and catalytic cracking. Thermal cracking proceeds by a free radical mechanism, and appreciable conversion in many cases requires high temperatures, such as 426 ℃ (800 ° F) and above. Catalytic cracking (and especially catalytic hydrocracking) relies on an acidic catalyst assisted carbocationic mechanism. Under hydrocracking conditions, the main cracked products formed by the carbocation mechanism remain saturated due to the hydrogen supply and the bifunctional catalyst.

The first stage hydroprocessing unit 101 can include two demetallization reactors including a first demetallization reactor 120 and a second demetallization reactor 130. More or fewer demetallization reactors may also be used and each demetallization reactor 120 and 130 may comprise a portion of a demetallization reactor or comprise one or more demetallization reactors. Each demetallization reactor 120 and 130 may include a portion of a catalyst bed or one or more catalyst beds in one or more demetallization reactor vessels. In the figure, the first stage hydroprocessing unit 101 includes two demetallization reactors 120 and 130, each comprising a single bed of HDM catalyst.

The fixed bed reactor may comprise supported or unsupported catalysts, but they are strongly bound and shaped and are stationary relative to the reaction vessel in which only the liquid hydrocarbon feed and hydrogen-rich gas are fed over the catalyst surface. Fixed bed reactors are commonly used for hydrotreating or hydrogenation of contaminants comprising petroleum feedstocks. Fluidized bed reactors can also be used for residue oil hydroprocessing, where the catalyst is frequently loaded and fluidized within the reactor, but remains in the reaction vessel unless discharged after the catalyst is exhausted. Transport reactors can also be used for residual oil treatment, but are primarily designed for boiling point reduction or hydrocracking, where the catalyst flows through or travels with a liquid feed and a hydrogen-containing gas stream. In an exemplary embodiment, the demetallization reactors 120 and 130 each comprise a fixed bed of HDM catalyst.

Suitable HDM catalysts that may be used in the first stage hydroprocessing unit 101 may include any conventional residue hydroprocessing catalyst and include those composed of at least one group VIII metal or iron, cobalt and nickel, or nickel and/or cobalt and at least one group VI metal (e.g., molybdenum and tungsten) on a high surface area support material such as alumina. More than one type of hydrotreating catalyst may also be used in the same reaction vessel or catalyst bed. The group VIII metal may be present on the HDM catalyst in an amount in the range of 1 wt.% to 10 wt.%, or 2 wt.% to 5 wt.%. The group VI metal will typically be present on the HDM catalyst in an amount in the range of from 1 wt% to 20 wt%, or from 2 wt% to 10 wt%. Moreover, suitable catalysts that may be used in the first stage hydroprocessing unit 101 do not include compounds that enhance catalyst acidity intended for boiling point reduction purposes. In contrast, catalysts for hydrocracking processes typically comprise a solid acid, examples of which include crystalline silica alumina, such as molecular sieves or zeolitic materials; chloridized alumina; and amorphous silica-alumina. The enhanced acidic functionality often performs significant carbon-carbon bond cleavage by forming carbocations that are achieved by the acidic functionality added in the catalyst. Hydrocracking catalysts with enhanced acidity may be 2 to 100 times stronger than the naturally weak acidity of hydrotreating catalysts.

In one embodiment, the first demetallization reactor 120 and the second demetallization reactor 130 may comprise HDM catalysts comprising cobalt and molybdenum on gamma alumina. The HDM catalyst in the first demetallization reactor 120 and the second demetallization reactor 130 may have a bimodal pore size distribution, wherein at least 25% of the pores on the catalyst particles are characterized as small pores in the range of 5nm to no more than 30nm micropores or mesopores, and at least 25% of the pores are characterized as large pores in the range of greater than 30nm to 100nm mesopores or macropores. Macropores are more suitable for demetallization and micropores for desulfurization. In the first demetallization reactor 120 and the second demetallization reactor 130, the ratio of large pores to small pores may decrease from upstream to downstream. In another embodiment, the first demetallization reactor 120 may have a larger ratio of large pores to small pores than the second demetallization reactor 130.

The hydrocarbon residue stream in line 104 can be fed to a first demetallization reactor 120 and a second demetallization reactor 130. It is contemplated that more or fewer demetallization reactors may be provided in the first stage hydroprocessing unit 101. In the first demetallization reactor 120, the hydrocarbon residue stream in line 104 or the heated hydrocarbon residue stream in residue feed line 112 is hydrotreated over a demetallization catalyst to demetallize the hydrocarbon residue stream in line 104 or the heated hydrocarbon residue stream in residue feed line 112 in the presence of a first stage hydrogen stream to provide a demetallized hydrocarbon residue stream having a reduced concentration of metals and sulfur. The hydrotreated/demetallized effluent stream in line 122 can be passed to a second demetallization reactor 130. The first demetallization reactor 120 and the second demetallization reactor 130 are intended to demetallize the hydrocarbon residue feed stream 104 or the heated hydrocarbon residue stream 112 in order to reduce the metal concentration by 40 wt.% to 100 wt.% and typically by 65 wt.% to 95 wt.% to produce a demetallized hydrocarbon residue stream exiting one, some or all of the first demetallization reactor 120 and the second demetallization reactor 130. The demetallized hydrocarbon residue stream can have a metals content of less than 50wppm or between 1wppm and about 25 wppm. The first demetallization reactor 120 and the second demetallization reactor 130 may also desulfurize and denitrify the hydrocarbon residue stream. In an exemplary embodiment, the first stage hydroprocessing unit 101 can desulfurize from 50 wt% to 80 wt% of the sulfur present in the hydrocarbon residue stream. The demetallized hydrocarbon residue stream having a reduced concentration of metals and sulfur relative to the residue feed stream fed to the reactors may exit the first demetallization reactor 120 and the second demetallization reactor 130.

The reaction conditions of each of the first demetallization reactor 120 and the second demetallization reactor 130 can include a temperature of from 66 ℃ (151 ° F) to 426 ℃ (800 ° F), or from 316 ℃ (600 ° F) to 418 ℃ (785 ° F), or from 343 ℃ (650 ° F) to 399 ℃ (750 ° F); a pressure of from 2.1MPa (gauge) (300psig) to 27.6MPa (gauge) (4000psig), or from 13.8MPa (gauge) (2000psig) to 20.7MPa (gauge) (3000 psig); 0.1hr^-1To 5hr^-1Or 0.2hr of fresh residue feed^-1To 2hr^-1(ii) a And 168Nm³/m³(1,000scf/bbl) to 1,680Nm³/m³Hydrogen rate of oil (10,000scf/bbl), or 674Nm³/m³Oil (4,000scf/bbl) to 1,011Nm³/m³Oil (6,000 scf/bbl). No appreciable boiling point change is observed with the current process under the given reaction conditions of the first stage hydroprocessing unit 101. The boiling point ranges of the feed in line 112 and the products in the demetallized hydrocarbon residue stream in line 122 remain the same. In exemplary embodiments, typically no more than 50% of the feed in line 112 having a boiling point above 523 ℃ (975 ° F) can be converted to a product having a boiling point equal to or below 523 ℃ (975 ° F). Specifically, no more than 40% and suitably no more than about 20% of the feed boiling above 523 ℃ (975 ° F) in line 112 can be converted to products boiling at or below 523 ℃ (975 ° F).

The demetallized hydrocarbon residue stream in line 132 can exit the second demetallization reactor 130 or the last demetallization reactor of the first stage hydroprocessing unit 101. The demetallized hydrocarbon residue stream in line 132 can be separated in a first stage hot separator 140 to provide a first stage overhead vapor stream comprising hydrogen in line 142 and a first stage bottoms liquid stream in line 144. The demetallized hydrocarbon residue stream in line 132 can be cooled by heat exchange with a first stage hydrogen stream in line 282 and enter the first stage separation section 161 comprising a first stage hot separator 140. The first stage separation section 161 includes one or more separators in downstream communication with the first stage hydroprocessing unit 101 including the first stage hot separator 140. The demetallized hydrocarbon residue stream in line 132 can be cooled in a heat exchanger and passed to a first stage hot separator 140. Thus, the second stage thermal separator 140 is in downstream communication with the first demetallization reactor 120 and the second demetallization reactor 130.

Since the reaction of the nitrogen and sulfur in the feed occurs in the first stage hydroprocessing unit 101, ammonia and hydrogen sulfide are formed. The first stage hot separator 140 removes hydrogen sulfide and ammonia from the first stage bottoms liquid stream in a first hot bottoms line 144 to the first stage overhead vapor stream in a first hot overhead line 142 to provide a sweetened demetallized residue stream for desulfurization in the second stage hydroprocessing unit 201.

The first stage hot separator 140 separates the demetallized hydrocarbon residue stream 132 to provide a hydrocarbon-containing first stage overhead vapor stream in a first hot overhead line 142 and a hydrocarbon-containing first stage bottoms liquid stream in a first hot bottoms line 144. The first stage overhead vapor stream in line 142 comprises a majority of the hydrogen sulfide from the demetallized residue stream. The first stage bottoms liquid stream in line 144 has a lower concentration of hydrogen sulfide than the demetallized hydrocarbon residue stream in line 132. The second stage hydrogen stream can be taken from the first stage overhead vapor stream in line 142.

The first stage hot separator 140 can be operated at a temperature of about 177 ℃ (350 ° F) to 371 ℃ (700 ° F), and preferably at 232 ℃ (450 ° F) to 315 ℃ (600 ° F). The first stage hot separator 140 may be operated at a slightly lower pressure (taking into account the pressure drop through the intervening equipment) than the second demetallization reactor 130. The first stage hot separator 140 can be operated at a pressure between 3.4MPa (gauge) (493psig) and 20.4MPa (gauge) (2959 psig). The temperature of the hydrocarbon-containing first stage overhead vapor stream in first hot overhead line 142 can be the operating temperature of first stage hot separator 140.

The first stage overhead vapor stream in the first hot overhead line 142 can be cooled by heat exchange with a first stage hydrogen stream in line 282 prior to entering the first cold separator 160. The first cold separator 160 may be in downstream communication with the first hot overhead line 142. The first stage overhead vapor stream in line 142 can be separated in a cold separator 160 to provide a first cold vapor stream comprising a hydrogen-rich gas stream comprising ammonia and hydrogen sulfide in a first cold overhead line 162 and a first cold liquid stream in a first cold bottoms line 164. The first cold separator 160 is used to separate the hydrogen rich gas from the hydrocarbon liquid in the first stage overhead vapor stream in line 142 for recycle to the second stage hydroprocessing unit 201. Thus, the first cold separator 160 is in downstream communication with the first stage overhead vapor stream in the first hot overhead line 142 of the first stage hot separator 140.

The first cold separator 160 can be operated at a temperature of 38 ℃ (100 ° F) to 66 ℃ (150 ° F), or 46 ℃ (115 ° F) to 63 ℃ (145 ° F) and at a pressure just below that of the second demetallizing reactor 130 or the final demetallizing reactor and the first stage hot separator 140 of the first stage hydroprocessing unit 101 (taking into account the pressure drop through the intervening equipment) to keep hydrogen and light gases overhead and normally liquid hydrocarbons at the bottom of the column. The first cold separator 160 can be operated at a pressure between 3MPa (gauge) (435psig) and 20MPa (gauge) (2,901 psig). The first cold separator 160 may also have a reservoir for collecting the aqueous phase. The aqueous phase may be taken from a storage tank in line 166. The temperature of the first cold liquid stream in the first cold bottom line 164 can be the operating temperature of the first cold separator 160. In one embodiment, the first cold liquid stream in the first cold bottom line 164 may be delivered to the cold flash drum 190 after mixing with the second cold liquid stream in the second cold bottom line 264. The cold flash drum 190 may be in downstream communication with the first cold bottom line 164 of the first cold separator 160.

The first cold vapor stream in the first cold overhead line 162 is enriched in hydrogen. Thus, hydrogen can be recovered from the first cold vapor stream in line 162. However, the first cold vapor stream in line 162 contains significant amounts of hydrogen sulfide and ammonia that are separated from the demetallized residue stream in line 132. The first cold vapor stream in cold overhead line 162 can be passed through a tray or packed recycle scrubber 170, where the cold gas stream can be scrubbed by a scrubbing extract (such as an aqueous solution fed through line 171) to remove the acid gas containing hydrogen sulfide and carbon dioxide by extraction into the aqueous solution. The aqueous solution may include lean amines such as alkanolamine DEA, MEA and MDEA. Other amines may be used instead of or in addition to the listed lean amines. The lean amine contacts the first cold vapor stream in line 162 and absorbs acid gas contaminants such as hydrogen sulfide and carbon dioxide. The resulting "tempered" first cold vapor stream is withdrawn from the overhead outlet of the recycle scrubber column 170 in recycle scrubber overhead line 172 and rich amine is withdrawn from the bottom of the recycle scrubber column at the bottom outlet of the recycle scrubber column in recycle scrubber bottom line 179. Spent wash liquid from the bottom of the column can be regenerated and recycled back to the recycle wash column 170 in line 171. The scrubbed hydrogen-rich stream is discharged from the scrubber via recycle scrubber overhead line 172. A portion of the scrubbed hydrogen-rich stream may be recycled in recycle line 174 and added to the make-up hydrogen stream in make-up line 212 for supplying the second stage hydrogen stream in second hydrogen line 214 to the second stage hydroprocessing unit 201. Thus, the second stage hydrogen stream in the second hydrogen line 214 may be taken from the first stage overhead vapor stream in the first hot overhead line 142 and the first cold vapor stream in the first cold overhead line 162. A portion of the scrubbed hydrogen-rich stream in recycle scrubber overhead line 172 can be purged in line 178. Another portion of the hydrogen-rich stream in the recycle scrubber overhead line 176 may be forwarded to the hydrogen recovery unit 180. The recycle scrubber 170 can be operated at a gas inlet temperature between 38 ℃ (100 ° F) and 66 ℃ (150 ° F) and an overhead pressure of 3MPa (gauge) (435psig) to 20MPa (gauge) (2900 psig).

Of the first stage bottoms liquid stream transported in the first hot bottoms line 144, the demetallized first stage bottoms liquid stream exits the first stage hydroprocessing unit 101 and the first stage separation section 161 with reduced concentrations of metals, sulfur and nitrogen relative to the hydrocarbon residue stream in line 102.

The first stage bottoms liquid stream in first hot bottoms line 144 can be divided into a first liquid stream in line 146 and a second liquid stream comprising low sulfur fuel oil in line 148. The low sulfur fuel oil product can be separated from the second liquid stream in line 148. In one embodiment, the second liquid stream in line 148 can be passed to a flash drum 150. In the flash drum 150, the low sulfur fuel oil product can be separated from the second liquid stream in line 148. The low sulfur fuel oil product stream is taken from the bottom of the flash drum in bottoms line 154 and the flash overhead stream is taken from the top of the flash drum in overhead line 152. In exemplary embodiments, the low sulfur fuel oil product stream in line 154 comprises sulfur in an amount of from 0.3 wt.% to 1.5 wt.%. In another exemplary embodiment, the low sulfur fuel oil product stream in line 154 comprises sulfur in an amount of from 0.4 wt.% to 1.4 wt.%. In yet another exemplary embodiment, the low sulfur fuel oil product stream in line 154 comprises sulfur in an amount from 0.05 wt.% to 0.5 wt.%.

In accordance with the inventive process, the low sulfur fuel oil product stream 154 separated from the second liquid stream in line 148 comprises sulfur in an amount of from 0.05 to 1.5 weight percent. The low sulfur fuel oil product stream 154 can be considered a low sulfur fuel oil product for use as a fuel oil that meets the sulfur regulations of the MARPOL convention. In another embodiment, the second liquid stream in line 148 can be sent directly as a low sulfur fuel oil product stream, either as a major component of the fuel oil pool or as part of the final blend.

The make-up hydrogen stream in line 202 can be passed to a compressor to provide a compressed make-up hydrogen stream in line 212. The hydrogen-rich recycle stream in line 174 can be mixed with the make-up hydrogen stream in line 212 to provide a second stage hydrogen stream in a second hydrogen line 214. The second stage hydrogen stream in line 214 may be heated in a fired heater 220. The heated second stage hydrogen stream in line 222 can be mixed with the demetallized first liquid stream in line 146 and fed to the second stage hydroprocessing unit 201.

The first liquid stream in line 146 is at an elevated temperature prior to entering the second stage hydroprocessing unit 201 and may not require further heating. In one embodiment, the second stage hydroprocessing unit 201 includes a first desulfurization reactor 230 and a second desulfurization reactor 240, which may include a Hydrodesulfurization (HDS) catalyst. More or fewer desulfurization reactors may be used. The HDS catalyst may comprise nickel or cobalt and molybdenum on a gamma alumina support to convert organic sulfur to hydrogen sulfide. The HDS catalyst may have a monomodal or unimodal distribution of mesopore sizes, with at least 50% of the pores on the catalyst particles in the range of 10nm to 50 nm. Moreover, suitable catalysts that may be used in the second stage hydroprocessing unit 201 do not include compounds with enhanced acidity intended for boiling point reduction.

The first desulfurization reactor 230 and the second desulfurization reactor 240 can be operated in series with the effluent stream in line 232 from the first desulfurization reactor 230 staged into the inlet of the second desulfurization reactor 240. The first 230 and second 240 desulfurization reactors desulfurize the demetallized residue feed present in the first liquid stream in line 146 to reduce the sulfur concentration of the first liquid stream in line 146 by 40 wt.% to 100 wt.% and typically by 65 wt.% to 95 wt.%, thereby producing a desulfurized hydrocarbon residue stream in line 242 exiting the second desulfurization reactor 240. Also, the second stage hydroprocessing unit 201 is in a sweeter gas environment due to gas cleanliness compared to the first stage hydroprocessing unit 101. In the figure, the second stage hydroprocessing unit 201 includes two desulfurization reactors 230 and 240, each of which includes a single bed of HDM catalyst. In an exemplary embodiment, the desulfurization reactors 230 and 240 each include a fixed bed of HDM catalyst.

The first desulfurization reactor 230 and the second desulfurization reactor 240 may be operated under the following conditions: a temperature of 66 ℃ (151 ° F) to 426 ℃ (800 ° F), suitably 316 ℃ (600 ° F) to 418 ℃ (785 ° F), and preferably 343 ℃ (650 ° F) to 399 ℃ (750 ° F); a pressure of from 2.1MPa (gauge) (300psig) to 27.6MPa (gauge) (4000psig), preferably from 13.8MPa (gauge) (2000psig) to 20.7MPa (gauge) (3000 psig); 0.1hr^-1To 5hr^-1Preferably 0.2hr of fresh residue feed^-1To 2hr^-1(ii) a And 168Nm³/m³(1,000scf/bbl) to 1,680Nm³/m³Hydrogen rate of oil (10,000scf/bbl), preferably 674Nm³/m³Oil (4,000scf/bbl) to 1,011Nm³/m³Oil (6,000 scf/bbl). No boiling point change is observed with the current process at the given reaction conditions of the second stage hydroprocessing unit 201. The boiling point ranges of the feed in line 112 or line 224 and the products in the desulfurized hydrocarbon residue stream in line 242 remain the same. In an exemplary embodiment, no more than 5% of the feed in line 112 or line 224 having a boiling point above 524 ℃ (975 ° F) can be converted to a product having a boiling point equal to or below 524 ℃ (975 ° F).

The desulfurized hydrocarbon residue stream can exit the second desulfurization reactor 240 in a desulfurized effluent line 242, be cooled by heat exchange with a first stage hydrogen stream (not shown) in line 282, and enter a second stage separation section 261 comprising a second stage thermal separator 250. The second stage separation section 261 includes one or more separators in downstream communication with a second stage hydroprocessing unit 201 that includes a second stage hot separator 250. The desulfurized hydrocarbon residue stream in line 242 delivers the relatively cooled desulfurized effluent stream to the second stage hot separator 250. Thus, the second stage hot separator 250 is in downstream communication with the first desulfurization reactor 230 and the second desulfurization reactor 240.

In accordance with the present disclosure, the operating conditions of the first stage hydroprocessing unit 101 and the second stage hydroprocessing unit 201 are different than typical operating conditions of a hydrocracking process, with the goal of at least 50% conversion of materials present in the residue oil feed having a boiling point of 524 ℃ (975 ° F) or higher. Specifically, the temperature of the first stage hydroprocessing unit 101 and the second stage hydroprocessing unit 201 is below the typical operating temperature of the hydrocracking process.

A second stage hot separator 250 separates the desulfurized hydrocarbon residue stream in line 242 to provide a hydrocarbon-containing second stage vapor stream in a second hot overhead line 252 and a hydrocarbon-containing second stage liquid stream in a second hot bottoms line 254. The second stage thermal separator 250 can be operated at a temperature of 177 ℃ (350 ° F) to 371 ℃ (700 ° F) or 232 ℃ (450 ° F) to 315 ℃ (600 ° F). The second stage hot separator 250 may be operated at a slightly lower pressure than the second desulfurization reactor 240 (taking into account the pressure drop through the intervening equipment). The second stage hot separator 250 can be operated at a pressure between 3.4MPa (gauge) (493psig) and 20.4MPa (gauge) (2959 psig). The temperature of the second stage vapor stream in the second hot overhead line 252 can be the operating temperature of the second stage thermal separator 250. The second stage liquid stream in the second hot bottom line 254 can be fed to a hot flash drum 270 to provide a hot flash vapor stream in line 272 and a hot flash liquid stream in line 274.

The second stage vapor stream in the second hot overhead line 252 can be cooled by heat exchange prior to entering the second cold separator 260. The second cold separator 260 is in downstream communication with the second hot overhead line 252 of the second stage hot separator 250.

The second stage vapor stream in line 252 can be separated in a second cold separator 260 to provide a second cold vapor stream in line 262 and a second cold liquid stream in a second cold bottom line 264. The second cold vapor stream in line 262 can be recycled to the first stage hydroprocessing unit 101 as a first stage hydrogen stream. The second stage cold separator 260 is used to separate the hydrogen rich gas in the second stage vapor stream in line 252 from the hydrocarbon liquid into a second cold vapor stream for recycle to the first stage hydroprocessing unit 101 in a second cold overhead line 262. The hydrogen-enriched second cold vapor stream in line 262 can be compressed in compressor 280 and then recycled as the first stage hydrogen stream in first hydrogen line 282. Thus, the first stage hydrogen stream in the first hydrogen line 282 can be taken from the second stage vapor stream in the second hot overhead line 252 and the second cold vapor stream in the second cold overhead line 262.

The second stage liquid stream in second hot bottoms line 254 can be pressure dropped and flashed in hot flash drum 270 to provide a light hot flash vapor stream in hot flash overhead stream in line 272 and a hot flash liquid stream in hot flash bottoms line 274. The hot flash drum 270 may be in direct downstream communication with the second hot bottoms line 254 and in downstream communication with the second stage hydroprocessing unit 201. The hot flash liquid stream in line 274 can be divided into a first flash liquid stream in line 276 and a second flash liquid stream in line 278.

The thermal flash tank 270 can be operated at the same temperature as the second thermal separator 250 but at a lower pressure (or no more than 3.8MPa (gauge) (550psig)) of between 1.4MPa (gauge) (200psig) and 6.9MPa (gauge) (1000 psig). The hot flash liquid stream in the hot flash bottom line 274 can have a temperature that is the operating temperature of the hot flash tank 270.

The desulfurized hydrocarbon residue stream in line 242 is produced from the second stage hydroprocessing unit 201 that employs an HDS catalyst having a unimodal or unimodal distribution of mesopore sizes that has a relatively high hydrogenation activity. Thus, the desulfurized hydrocarbon residue stream in the second stage product of line 242 is highly desulfurized. In addition, the desulfurized hydrocarbon residue stream in line 242 is highly refined in terms of the nitrogen, metals, Conradson carbon residue, and asphaltene content that can be present in the hydrocarbon residue stream in line 242. The hot flash liquid stream in line 274 obtained downstream of the separation of the desulfurized hydrocarbon residue stream in line 242 is also highly desulfurized and highly cleaned with respect to the nitrogen, metals, Conradson carbon residue and asphaltene content of the stream. In one embodiment, the hot flash liquid stream in line 274 can comprise sulfur in an amount of from 0.1 wt.% to 0.4 wt.%. The latest MARPOL regulation from 1/2020 has reduced the amount of sulfur that can be present in fuel oil. The new MARPOL regulation limits the presence of sulfur in fuel oil to 0.50% m/m. To meet the desired limit of the amount of sulfur present in the low sulfur fuel oil product stream, a trim stream can be separated from the highly desulfurized and cleaned hot flash liquid stream 274 and mixed with the second liquid stream in line 148 to recover a low sulfur fuel oil product stream having the desired amount of sulfur. Also, the remaining portion of the hot flash liquid stream 274 may be processed downstream to produce other desired products. According to one embodiment, the first flash liquid stream in line 276 can be separated from the hot flash liquid stream 274. The first flash liquid stream in line 276 can be blended with the low sulfur fuel oil product stream in line 154 to provide a final low sulfur fuel oil product stream in line 156. In exemplary embodiments, the final low sulfur fuel oil product stream in line 156 comprises sulfur in an amount of from 0.05 wt.% to 0.5 wt.%. Applicants have found that mixing the first flash liquid stream in line 276 with the low sulfur fuel oil product stream in line 154 can reduce the volume of HDM catalyst required in the first stage hydroprocessing unit 101 and thus reduce the size of the first stage hydroprocessing unit 101. Because the first flash liquid stream in line 276 is derived from the desulfurized effluent line 242, it is highly desulfurized as a result of the desulfurization in the second stage hydroprocessing unit 201 of HDS catalyst. Thus, the catalyst volume of the HDM catalyst may be relatively reduced to demetallize and desulfurize the hydrocarbon residue stream in the first stage hydroprocessing unit 101.

In another exemplary embodiment, the final low sulfur fuel oil product stream in line 156 comprises sulfur in an amount of from 0.1 to 0.5 weight percent. In yet another exemplary embodiment, the final low sulfur fuel oil product stream in line 156 comprises sulfur in an amount of from 0.2 wt.% to 0.5 wt.%. In yet another exemplary embodiment, the final low sulfur fuel oil product stream in line 156 comprises sulfur in an amount of from 0.3 wt.% to 0.5 wt.%. The final low sulfur fuel oil product stream in line 156 can be passed to a fuel oil pool.

The second flash liquid stream in line 278 that comprises a portion of the hot flash liquid stream in line 274 is highly desulfurized and cleaned with respect to the nitrogen, metals, Conradso carbon residue, and asphaltene content of the stream. Thus, the current process can produce a minimum of two liquid product streams: the low sulfur fuel product stream 154 and another highly desulfurized and refined stream 278 having a lower sulfur concentration than the low sulfur fuel product stream that can be further processed downstream to produce other desired desulfurized and demetallized products. Thus, the second flash liquid stream in line 278 can be separated and further processed to produce other products, e.g., for gasoline and petrochemical production. In one embodiment, the second flashed liquid stream in line 278 can be passed to a Fluid Catalytic Cracking (FCC) process. The current method also provides flexible product goals. To provide a low sulfur fuel that meets MARPOL regulations for sulfur amounts, an appropriate amount of highly desulfurized first flash liquid stream 276 separated from the hot flash liquid stream in line 274 can be mixed with the low sulfur fuel oil product stream 154.

The second stage cold separator 260 can be operated at 38 ℃ (100 ° F) to 66 ℃ (150 ° F), or 46 ℃ (115 ° F) to 63 ℃ (145 ° F) and at a pressure lower than that of the second desulfurization reactor 240 and the second stage hot separator 250 (taking into account the pressure drop through the intervening equipment) to keep hydrogen and light gases overhead and normally liquid hydrocarbons at the bottom of the column. The second stage cold separator 250 can be operated at a pressure between 3MPa (gauge) (435psig) and 20MPa (gauge) (2,901 psig). The second stage cold separator 250 can also have a storage tank for collecting the aqueous phase in line 266. The temperature of the second cold liquid stream in the second cold bottom line 264 can be the operating temperature of the cold separator 260. The second cold liquid stream in the second cold bottom line 264 can be delivered to the cold flash drum 190 and separated in the cold flash drum 190 with the first cold liquid stream in the first cold bottom line 164. In one embodiment, the second cold liquid stream in second cold liquid bottom line 264 can be mixed with the first cold liquid stream in first cold bottom line 164 to provide a combined cold liquid stream in line 168. The combined cold liquid stream in line 168 can be separated in cold flash drum 190.

In one embodiment, the second cold liquid stream in the second cold bottom line 264 can be sent to fractionation. In another embodiment, the second cold liquid stream in line 264 can be pressure dropped and flashed in the cold flash drum 190 to separate the fuel gas from the second cold liquid stream in the second cold flash bottom line 264 and provide a cold flash liquid stream in the cold flash bottom line 194. The cold flash drum 190 may be in direct downstream communication with the second cold bottom line 264 of the cold separator 260. In exemplary embodiments, the cold flash drum 190 may separate the first cold liquid stream in the first cold bottom line 164 to provide a fuel gas stream in a cold flash overhead line 192 and a cold flash liquid stream in a cold flash bottom line 194. The second cold liquid stream in the second cold bottom line 264 and the first cold liquid stream in the first cold bottom line 164 may be separated and flashed together in the cold flash drum 190. The cold flash liquid stream in cold flash bottoms line 194 can be sent to product fractionation and can then be stripped to remove hydrogen sulfide from the product stream including the desulfurized residue stream. As shown, the stripping column 310 and the fractionation column 320 may be in downstream communication with the cold flash drum 190 and the cold flash drum bottom line 194. In another exemplary embodiment, the first cold liquid stream in the first cold bottom line 164 and the second cold liquid stream in the second cold bottom line 264 can be fractionated in the fractionation column 320 to provide a bottoms stream in line 326. The cold flash liquid stream in cold flash bottom line 194 can be passed to stripper column 310. A suitable stripping medium may also be passed to stripper column 310 in line 302. In an exemplary embodiment, the stripping medium may be a stream. The stripped cold flash liquid stream in line 312, after passing through the overhead receiver of stripper column 310, may be passed in combination or separately in lines 316 and 318 to fractionation column 320. The reflux in line 317 can be passed to stripper column 310. The stripped cold flash liquid stream can be fractionated in a fractionation column 320 to provide an overhead stream in line 322. The overhead stream in line 322 can be passed to an overhead receiver 330, wherein the overhead stream 322 can be separated into a receiver overhead vapor stream in line 332 and a receiver bottom liquid stream in line 336. The reflux in line 334 can be passed to the fractionation column 320. The bottoms stream in line 314 from the stripper column 310 can be combined with the bottoms stream in line 324 from the fractionator column 320 to provide a combined bottoms stream in line 326. In exemplary embodiments, the bottoms stream in line 326 can comprise sulfur in an amount from 0.01 wt.% to 0.25 wt.%. The combined bottoms stream in line 326 can be hydrotreated in a downstream hydrotreating unit (not shown). The hydrotreated bottoms stream may be further processed to produce other products. In an exemplary embodiment, the hydrotreated bottoms stream may be passed to a fluid cracking process (FCC). In another exemplary embodiment, a portion of the bottoms stream in line 326 can be mixed with the low sulfur fuel oil product stream in line 154.

The cold flash drum 190 can operate at the same temperature as the second cold separator 260, but typically at a lower pressure of between 1.4MPa (gauge) (200psig) and 6.9MPa (gauge) (1000psig), or between 3.0MPa (gauge) (435psig) and 3.8MPa (gauge) (550 psig). The flashed aqueous stream can be removed from the storage tank of the cold flash drum 190 in line 196. The temperature of the cold flash liquid stream in the cold flash bottoms line 194 may be the same as the operating temperature of the cold flash drum 190.

Detailed description of the preferred embodiments

While the following is described in conjunction with specific embodiments, it is to be understood that this description is intended to illustrate and not limit the scope of the foregoing description and the appended claims.

A first embodiment of the present disclosure is a process for hydrotreating a hydrocarbon residue stream, the process comprising: hydrotreating said hydrocarbon residue stream over a demetallization catalyst in the presence of a first hydrogen stream to demetallize said hydrocarbon residue stream to provide a demetallized hydrocarbon residue stream having a reduced concentration of metals and sulfur; separating the demetallized hydrocarbon residue stream in a hot separator to provide an overhead vapor stream comprising hydrogen and a bottom liquid stream; said bottoms liquid stream is divided into a first liquid stream and a second liquid stream comprising sweet fuel oil; recovering said second liquid stream as a low sulfur fuel oil product stream; and hydrotreating the first liquid stream over a desulfurization catalyst in the presence of a second hydrogen stream to provide a desulfurized hydrocarbon residue stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein recovering the second liquid stream as a low sulfur fuel oil product stream comprises separating the second liquid stream to provide a flash overhead stream and the low sulfur fuel oil product stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the low sulfur fuel oil product stream comprises sulfur in an amount from 0.3 wt.% to 1.5 wt.%. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the desulfurized hydrocarbon residue stream to provide a vapor stream and a liquid stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the liquid stream to provide a hot flash vapor stream and a hot flash liquid stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising dividing the hot flash liquid stream into a first flash liquid stream and a second flash liquid stream; and mixing the first flash liquid stream with the second liquid stream to produce the low sulfur fuel oil product stream comprising from 0.05 wt% to 0.5 wt% sulfur. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the vapor stream in a second cold separator to provide a second cold vapor stream and a second cold liquid stream, and taking the first hydrogen stream from the second cold vapor stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph wherein the entire second cold vapor stream is taken as the first hydrogen stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the overhead vapor stream in a first cold separator to provide a first cold vapor stream and a first cold liquid stream. An embodiment of the disclosure is one, any or all of prior embodiments of this paragraph up through the first embodiment of this paragraph further comprising separating the first cold vapor stream into a purge stream and a recycle stream; and using the recycle stream as the second hydrogen stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating the first cold liquid stream and the second cold liquid stream to provide a fuel gas stream and a cold flash liquid stream, and subjecting the cold flash liquid stream to fluid catalytic cracking. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising fractionating the cold flash liquid stream in a fractionation column to provide a bottoms stream; and mixing the bottoms stream with the low sulfur fuel oil product stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, further comprising adding the second liquid stream to a fuel oil pool. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, further comprising at least one of: sensing at least one parameter of an integrated process for maximizing hydrogen recovery and generating a signal or data in accordance with the sensing; generating and transmitting a signal; or generate and transmit data.

A second embodiment of the present disclosure is a process for hydrotreating a hydrocarbon residue stream, the process comprising: adding a first hydrogen stream to the hydrocarbon residue stream; hydrotreating said hydrocarbon residue stream over a demetallization catalyst in the presence of said first hydrogen stream to demetallize said hydrocarbon residue stream to provide a demetallized hydrocarbon residue stream having a reduced concentration of metals and sulfur; separating the demetallized hydrocarbon residue stream in a first stage hot separator to provide a first stage vapor stream comprising hydrogen and a first stage liquid stream; said first stage liquid stream is divided into a first liquid stream and a second liquid stream comprising a sweet fuel oil; recovering said second liquid stream as a low sulfur fuel oil product stream; hydrotreating said first liquid stream over a desulfurization catalyst in the presence of a second hydrogen stream to provide a desulfurized hydrocarbon residue stream; separating the desulfurized hydrocarbon residue stream in a second stage hot separator to provide a second stage vapor stream and a second stage liquid stream; and mixing at least a portion of the second stage liquid stream with the low sulfur fuel oil product stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph wherein recovering the second liquid stream as a low sulfur fuel oil product stream comprises separating the second liquid stream to provide a flash overhead stream and the low sulfur fuel oil product stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph wherein the low sulfur fuel oil product stream comprises from 0.3 wt.% to 1.5 wt.% sulfur. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph further comprising separating the second stage liquid stream to provide a flash vapor stream and a flash liquid stream; said flash liquid stream is divided into a first flash liquid stream and a second flash liquid stream; and mixing the first flash liquid stream with the second liquid stream to produce the low sulfur fuel oil product stream comprising from 0.05 wt% to 0.5 wt% sulfur.

A third embodiment of the present disclosure is a process for hydrotreating a hydrocarbon residue stream, the process comprising: adding a first hydrogen stream to the hydrocarbon residue stream; hydrotreating said hydrocarbon residue stream over a demetallization catalyst in the presence of said first hydrogen stream to demetallize said hydrocarbon residue stream to provide a demetallized hydrocarbon residue stream having a reduced concentration of metals and sulfur; separating the demetallized hydrocarbon residue stream in a first stage hot separator to provide a first stage vapor stream comprising hydrogen and a first stage liquid stream; said first stage liquid stream is divided into a first liquid stream and a second liquid stream comprising a sweet fuel oil; recovering the second liquid stream as a low sulfur fuel oil product stream comprising from 0.3 wt% to 1.5 wt% sulfur; and hydrotreating the liquid stream over a desulfurization catalyst in the presence of a second hydrogen stream to provide a desulfurized hydrocarbon residue stream. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, further comprising separating the desulfurized hydrocarbon residue stream in a second stage hot separator to provide a second stage vapor stream and a second stage liquid stream; and mixing at least a portion of the second stage liquid stream with the second liquid stream to produce the low sulfur fuel oil product stream comprising from 0.05 wt% to 0.5 wt% sulfur.

Without further elaboration, it is believed that one skilled in the art can, using the preceding description, utilize the present disclosure to its fullest extent and can readily ascertain the essential characteristics of the present disclosure without departing from the spirit and scope of the invention, and that various changes and modifications of the present disclosure may be made and adapt it to various usages and conditions. Accordingly, the foregoing preferred specific embodiments are to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way whatsoever, and is intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

In the foregoing, all temperatures are shown in degrees celsius and all parts and percentages are by weight unless otherwise indicated.