JP7389776B2 - Fuel and its combination - Google Patents

Description

The present invention provides a novel method for producing fuel and a wide range of fuels produced from crude oil (C3 or C5 to
A novel method for preparing a composition intended for fuels having hydrocarbons (C20 or higher) is provided.
Preferred feedstocks in the process of the invention are, for example, refinery intermediates, high sulfur fuel oils, low sulfur fuel oils or light tight oils, condensate, very heavy oils, tar sands and asphalt. is a hydrocarbon source that has hitherto been considered undesirable as a feedstock. The above fuel provided by the present invention is an ultra-clean fuel with very low sulfur and nitrogen content and very low metal content measured by many techniques, with almost no metals detected and substantially no metal content. It is a particularly cost-effective fuel not only for use on large ocean transport vessels, but also on land for use in large land-based combustion gas turbines, boilers and transport vehicles and trains.

The present invention addresses at least three problems: (1) converting low-value hydrocarbons into high-value fuels; (2) cost-effectively reducing sulfur and nitrogen and substantially removing metals from the fuels;
and (3) adapting the fuel for use in combustion-type heaters such as marine or land-based engines, combustion gas turbines, or boilers.

Certain hydrocarbon sources are undesirable as refinery feedstocks and may be undervalued by refineries. Conventional refineries strive to divide each barrel of crude oil with all or a wide range of hydrocarbons into feedstocks from multiple fuel products and downstream chemical products. Refineries often prefer feedstocks with a wide range of hydrocarbons. In competition where profit margins are often very thin, a particular refinery must not only meet the supply constraints of its customers, but also balance the materials and energy required to satisfy all unit operations. In order to achieve
Although requiring most of the total carbon range of crude oil, these refineries also tend to choose feedstocks that do not pose processing problems or increase operating costs.

Traditional refineries suffer from operational problems, for example with very heavy crudes such as Maya (Mexico), BCF-17 (Venezuela), and Oriente (Ecuador), which pose equipment, operating and investment cost issues. encounter. Such problems can similarly occur in the processing of oil shale obtained from organic-rich sedimentary kerogen-bearing rocks and condensates.

Conventional refineries also face problems processing light-tight oil, which is sometimes described as ``lacking most of the bottom of the barrel'' compared to crude oil. Light tight oils (also simply referred to as tight oils) are currently widely available as produced from shale and other low permeability formations such as sandstone and carbonates. Compared to conventional crude oil,
Tight oils have an excess of light ends but boil above 425°C or 565°C, or The bottom of the barrel has little or no hydrocarbons in the heavy range materials. See Non-Patent Document 1.

As used herein, "tight oil", "light tight oil" or "LT
The term "O" refers to (i) a sulfur content ranging from almost unmeasurable or zero (0)% to 0.2% by weight; (ii) a density, API (degrees) ranging from 38 to 57 degrees; means oil well condensate, unassociated natural gas condensate or shale gas condensate having a wide variation in source based on iii) metal traces and (iv) hydrocarbon range, but not all are the same. LTO from different sources has different distillation takeoff fraction ranges. According to the descriptions that a particular refinery uses for the range of characterized fractions, exemplary variations in LTO include (a) a liquefied petroleum gas range of 5-20% by weight; (b) a range of 10-35% by weight. of naphtha, (c) 15-30% by weight kerosene/jet range, (d) 15-25% by weight diesel and heavy distillates, (e) trace levels to 10% or more vacuum gas oil, and (f) It may have from zero (0%) to about 5% or more heavy residue.

Such light tight oils, especially those with a small amount of heavy gas oil and substantially zero or very little heavy residue, contain substantially no heavy hydrocarbons in the bottom fraction within the gas oil. ,
sulfur and metals in such light crude oils without sufficient corresponding residue to maintain the residue range or process hydrogen production to provide process balance for desulfurization or other hydrotreating. Can be cost-effectively hydrotreated to reduce and decontaminate or have sufficient lubricity for use in certain types of engines. See, for example, Non-Patent Document 2, which provides composition ranges for specific tight oils. Blending tight oil with heavy asphalt crude oil is a desirable distillation profile for many refineries in order to balance the mixture of product withdrawals from the crude distillation column and make it compatible with many refinery operations. This is meaningful because it brings about This is recognized by those skilled in the art;
Executing this may lead to compatibility problems such as asphaltene destabilization (Non-Patent Document 3).

Also in high sulfur fuel oil or "HSFO", which is sometimes described as being part of the "bottom of the barrel" or "devoid of much of the top of the barrel" compared to crude oil. Traditional refineries face processing problems. Other uses in the art include '
The term "high sulfur fuel oil" or "HSFO" has been assigned different, sometimes dissimilar, contradictory, and confusing meanings in various technical articles, patents and statutes, some of which change over time. It is something. The widely used term "high sulfur fuel oil" refers to light, low boiling, but high sulfur (and therefore high smoke) kerosene containing more than 3.5% sulfur by weight, including those other than those used in fuels. Heavy marine bunker fuel or mast with quantity
t) or other heavy residue "bottom of the barrel" material, and in some cases does not have clear or uniformly applied specifications. A specific metric reporting system is based on the ISO 8217 specification that identifies HSFO as having a sulfur content of RMG.
3.5% as a fuel oil, although different sulfur contents are used elsewhere.

As used herein and in the claims, "high sulfur fuel oil" or "HSFO
” means a material used as a fuel with a sulfur content of more than 0.50% m/m (0.5% by weight). As used herein, "heavy oil", "heavy residual oil", "residue", "
The terms "residue" or "other heavy oil", "tar sands" and "very heavy oil" refer to petroleum-derived hydrocarbons with a sulfur content exceeding 0.50% m/m (0.5% by weight) Contains system substances. "
The term "high sulfur" means a value above the fuel's target sulfur content limit or the applicable legal sulfur limit, whichever is lower.

Another problem is that the market for high sulfur fuel oil is shrinking and it is not possible to blend large amounts of HSFO.
It cannot be transported. Many countries that burn HSFO to meet their electricity needs are substituting natural gas for local supply. For example, in 2015, Mexico went from being a net importer to an HSFO exporter when its power plants converted to local supply of natural gas.

For example, some states in the United States have changed their requirements for home heating oil to 500 ppm or less sulfur by weight instead of 2,000 ppm or more. As a result, certain pipelines and distribution networks have limited access to high-sulfur fuel oil in certain regions, particularly where local refineries do not have the feedstock, equipment, or technology to efficiently process low-sulfur fuel oil. Japan is refusing to transport "high sulfur fuel oil" due to the effects of an oversupply of fuel oil. For many refinery managers, the practical option of increasing the quality of the residue to meet the required capital investment with a HSFO investment return is far less than the alternative investment. The use of HSFO as a turbine fuel causes corrosion and contamination problems, leading to unreliability.

Prior art refinery designs using atmospheric crude oil and/or vacuum distillation units, solvent separation, hydrotreating, gasification, and many other unit operations separate each barrel of crude oil feedstock for different uses or downstream processing. Each product is divided into multiple products with different specifications.

A hydroskimming refinery converts crude oil into multiple products similar to a topping refinery, but typically involves a heavy feed to a reformer that also produces the hydrogen consumed by the hydrotreater in diesel production. The addition of quality naphtha is limited. Hydrogenation skimmers, such as Topping Refinery, typically produce a wide range of gasoline,
Produces kerosene, diesel and fuel oil. Various embodiments of accommodating hydroprocessing are known in the art, including separate series or parallel hydroprocessing reactor zones or integrated hydroprocessing reactor zones. Cash et al., US Pat. The containing streams are distributed or combined according to the methods disclosed.

Early boiling-type systems were described by Johanson, US Pat.
(1965) and residue hydroconversion processing of heavy oils and residues in ebullated bed reactors is known in the art. Ebullated bed reactors have fluid contact of heavy hydrocarbon liquids with hydrogen in the presence of a catalyst in a reaction vessel, with various associated auxiliary gas-liquid separators and hydrogen configurations and regeneration streams, and sulfur-containing Gas treatment systems are well known and commercially practiced in the art. U.S. Pat. No. 5,300,301 to Colyar et al. describes a series of boiling reactors, and U.S. Pat. U.S. Pat. No. 6,300,301 (2014) by Baldassari et al. describes various hydroconversion, hydrocracking, and hydrotreating steps, including various integrated hydroconversion, hydrocracking, and hydrotreating units. Hydrocracking and hydroprocessing catalysts are also described. Baldassari et al. further summarize various catalyst compositions and condition ranges for distillation and heavy oil hydroprocessing and categorize conditions for hydrocracking and residue hydroconversion. All of these are known to those skilled in the art of hydroprocessing.

Various aspects of the use of solvent separation to extract deasphalted oil from pitch in a heavy residue stream and use the deasphalted oil as a feedstock for hydroprocessing to produce multiple product streams As used are known in the art. For example, Brierley et al., US Pat. Describes solvent deasphaltization for oil production. Pitch residue has a high content of metals and sulfur. According to Brierley et al., deasphalted oil is processed to remove sulfur, nitrogen and metals as described in references for the production of several products including naphtha, kerosene, diesel and residues. Hydrocracked and hydrotreated.

U.S. Pat. No. 5,300,301 (2009) by Lenglet describes a method for pre-producing crude oil to produce two non- asphaltenic oils and pre-distillation, vacuum distillation, solvent de-asphaltization, hydroprocessing, hydrocracking and residue of asphaltene oils. The production of multiple products with hydrogenation conversion is described. Non-Patent Document 4 describes that sulfur is removed by hydrogenation and highly active Ni/M
The unit design, catalyst selection, hydrogen consumption, and other operating conditions for producing products with less than 8 ppm sulfur through the use of O catalysts are described. Non-patent Document 5, page 6, Advanced Purification Technology, Specific Edition Publication No. 113/2013 of Catalog also describes highly active CoM.
describes a hydrogenation process in which sterically unhindered sulfur is removed using an o catalyst and residual sterically hindered sulfur is removed to 10 ppm using a highly active NiMo catalyst.

Thus, although many improvements have been made to address the technical problems arising from processing light tight oils and residues in conventional refineries, significant problems remain without solutions. ing. Such problems have caused a technological gap resulting in substantially underutilization of light tight oils and high sulfur fuel oils.

PCT/US1999/00478 U.S. Patent No. 2,987,465 U.S. Patent No. 3,197,288 U.S. Patent No. 6,270,654 U.S. Patent No. 6,447,671 U.S. Patent Publication No. 20140221713 (U.S. Patent Application No. 13/75 8,429) U.S. Patent No. 7,686,941 International Application No. PCT/FR2006/000671 (U.S. Patent Application No. 11/912,771)

“Refining America’s New Light Tight Oil Production”, OPIS 16th Annual National Supply Summit, Las Vegas October 2014) Ba Ker & O’Brien “The North Dakota Petroleum Council Study on Bakken Crude Properties Bakken Crude Characterization Task Force” (2014), T. urner & mason Benoit et al., “Overcoming the Challenges of tight/shale oil refining”, Proceeding Shale Feedstocks, (2014) Ackerson et al., “Revamping Diesel Hydrotreaters For Ultra-Low Sulfur Using IsoTherming Technology” Shiflet et al., “Optimizing Hydroproc essing Catalyst Systems for Hydrocrack ing and Diesel Hydrotreating Applications, Flexib ity Through Catalyst”, Advanced Refining Technologies Catalog Special Edition Issue No. 113/2013, 6 pages

The present invention makes it possible to use light tight oils and high sulfur fuel oils to produce large amounts of fuel with very low sulfur and nitrogen and virtually no metals, effectively and at low cost. It is intended to bridge the technological gap. The fuel is particularly useful in large-scale land-based applications such as combustion gas turbines for power generation, as well as marine applications. As used herein and in the claims, the term "essentially/substantially free of metals" or "zero metals" refers to a range of from zero to less than 100 parts per billion (ppb). Metal content or content so low that it is difficult to reliably measure by conventional online instrumentation.

The present invention provides a new method for preparing compositions from high sulfur fuel oils and light tight oils having a wide range of hydrocarbons (C3 or C5 to C20 and above) and intended for fuels produced from crude oil. Preferred feedstocks to the process of the invention are hydrocarbon sources that have heretofore been considered undesirable as feedstocks in conventional refineries, such as high sulfur fuel oils and light tight oils.

The fuel of the present invention is an ultra-clean fuel with very low sulfur and nitrogen content and virtually no metals, and is particularly suitable for use in large seaborne transport vessels, as well as large land-based combustion gas turbines, boilers and transportation. It is also a particularly cost-effective fuel on land for vehicles and trains.

Traditional refining involves extracting a crude oil feedstock into many parts, with each part sent downstream to a separate market channel. In contrast, we took the "top of the barrel" light tight oil and the "bottom of the barrel" high sulfur fuel oil and combined them at a low cost to produce the oil produced from crude oil.
It has been found that fuels can be produced envisioning fuels with a wide range of hydrocarbons.

The present invention provides a low cost system that combines light tight oil and residual oil at low cost to produce large quantities of clean fuel on a commercial scale. The fuel replaces high sulfur bunker fuels and other heavy residues used in commercial shipping vessels and power plant combustion systems. The present invention
Such fuels and methods and apparatus for making them are provided to reduce sulfur, nitrogen and toxic metal emissions in a cost effective manner. For the shipping industry, the novel configuration of the present invention provides low cost, low sulfur marine fuel in the quantities necessary to meet or exceed global ocean sulfur reduction goals.

In addition, the fuels of the present invention can also be used to burn crude oil or heavy fuels in large land-based combustion turbines deployed in equipment, eg, single-cycle or combined-cycle power plants, such as those producing electrical power and desalinated water. Provides an alternative to residue combustion. Turbines burning the fuel of the present invention have significantly lower turbine exhaust emissions of NOx, SOx, CO2 _, soot, toxic metals and other combustion by-products, and, depending on the source, less polluted heavy oil. Or when burning refined residues, there is also less pollution under corrosive or ash-forming conditions in the hot zone.

These new processes use counter-heuristic steps to lower manufacturing costs while controlling the final product sulfur content below target sulfur levels in a surprisingly effective manner. Traditional purification does not involve recombining the extracts after they have been separated.

For example, in the prior art regarding blending, the focus of the blending is on blending to form gasoline, diesel, or jet fuel, where all of the separate refinery products are blended to form a single fuel. isn't it. That is, the crude oil is not separated into a number of fractions by distillation, but all are then simply recombined. For example, the technology avoids blending large amounts of diesel range materials into gasoline ranges. Also, end users do not have to blend diesel with gasoline. Similarly, the confusion surrounding the terms "kerosene" and "light ends" may be due to temperature ranges (e.g. 190°C to 250°C or 180°C to 230°C) or the distillation column cutoff point at normal pressure or other This is due to the fact that these terms are not uniformly defined based solely on established standards and are often used with different meanings between the same, overlapping, or different reference materials. For example, the EIA defines "middle distillates: refined petroleum products, including the general class of distilled fuel oils and kerosene." Therefore, refining boundary points in temperature ranges are determined by the specifications of each product from a conventional refinery, are often set locally, and are not defined based on sulfur content. The inventors have found that this is not optimal.

As used herein, the term "component" is used to describe an unexpected phenomenon discovered by "combining components" in the practice of the present invention, as opposed to simply combining components. Ru. The typical use of the term "component" to refer to a combination of human intervention gives an expectation of a result due to the presence of the components. That is, the ingredients are
When added, it imparts characteristic expected physical or chemical properties as a whole.

Conventional refineries do not blend gasoline with diesel or treated residual oil to make fuel. Instead, the output is separated by different engine types.

Unknown to those skilled in the art of refining, until now disclosed by the present invention, are novel fuel formulations that include a number of light (L), intermediate (M) and heavy (H) configurations. (as taught and defined below) and the best way to combine the selected components to form a low sulfur, substantially metal-free fuel. Something like that sees a warehouse filled with cooking ingredients, but without the lowest-cost, lowest-calorie cake recipes, and the amazing interactions that occur by processing and combining ingredients in a certain way. Very similar to the baker who doesn't even know about the phenomenon.

Schematic diagram showing the basic equipment and processing steps for combining untreated light tight oil and treated high sulfur fuel oil to form a fuel with very low sulfur. Explanatory diagram showing the production of low-sulfur fuel with adjusted flash point by simplifying the processing of light cycle oil and high-sulfur fuel oil Schematic diagram showing the equipment layout and processing steps for using crude oil alone or with light tight oils and high sulfur fuel oils to produce ultra-clean fuels with very low sulfur, nitrogen and metals. Recipes for novel fuels and combinations of one or more components with light (L), intermediate (M) and/or heavy (H) materials to form such fuels are taught and disclosed herein. Explanatory diagram schematically showing the volume fraction and density profile of the reference fuel produced by the method and its ranges of (L), (M) and (H) teaches recipes for novel fuels and combinations of one or more components with light (L), intermediate (M) and/or heavy (H) materials to form such fuels; Figure 3 shows the volume fraction and density profile of a reference light condensate that can be used as a "barrel top" (with the majority of (L) present and minor amounts of naturally occurring (M) and (H)). The top of the barrel is an illustration of the "bottom of the barrel" (H) components that are combined with (H) from other sources to form the fuel of the present invention.

The present invention provides a method for converting various hydrocarbon-based feedstocks from sources other than conventional crude oil, alone or together with conventional feedstocks, to form fuels having a wide range of hydrocarbons. In a variation, the fuel formed by the light tight oil feedstock and the high sulfur fuel oil feedstock is a hydroconverted liquid derived from the high sulfur fuel oil from the lowest boiling point of the light tight oil forming the fuel. A wide range of hydrocarbons, up to those with a maximum boiling point of , form the fuels mentioned above.

In one embodiment, one or more high sulfur fuel oils are fed to a residue hydroconversion zone;
(1) contacting with hydrogen in the presence of a catalyst in an ebullated bed reactor at residue hydroconversion conditions;
forming a hydroconversion reactor effluent that is separated into a hydroconversion product liquid and a purge gas having hydrogen and sulfur; and (2) an unconverted oil that is directed to solvent separation. Such unconverted oil is (A
) form a soluble deasphalted oil that is recovered to the hydroconversion reactor and (B) an insoluble pitch that is sent to pitch processing, either separately or with an added high sulfur fuel oil feedstock as a feedstock; The product fuel is formed by combining all or a portion of the light tight oil with the hydroconversion product liquid described above. In one variation, prior to use as part of the combination, the light tight oil is fractionated to remove overhead distillate gases, leaving a separator bottom that is combined with the hydroconversion zone product liquid to form the fuel. . In other variations, a portion of the feed to the solvent separation has high sulfur total oil that is added directly to the solvent separation or fed to the solvent separation in combination with a hydroconversion reactor unconverted oil. . Additionally, additional high sulfur fuel oil can be combined with the soluble deasphalted oil and fed as part of the feed to the hydroconversion reactor. For flash point and other considerations, light tight oils are fractionated before they are added to the fuel combination, removing overhead distillate gases and using upper zone light distillates with naphtha range hydrocarbons and high boiling bottom fractions. minutes can be formed. In one variation, at least a portion of such light fraction is rich in naphtha and is sent to a reformer or other aroma oil unit operation where it is contacted with hydrogen under reforming conditions to form a light processing stream. form. In another variation, all or a portion of the light treated stream, the untreated light stream and the high boiling bottoms fraction are combined with the hydroconverted liquid to form a fuel. In still other variations, the effluent from the hydroconversion reactor is fractionated to separate two or more treated liquid fractions, at least one of the fractions having a sulfur content higher than the target sulfur content. One is used as part of the feed to a residue hydroconversion reactor or as part of the feed to solvent separation.

In one embodiment, the residue hydroconversion zone integrates a residue hydroconversion reactor with a heavy oil range hydrotreater and a distillate range hydrotreater, and includes a gas-liquid separator, a hydrogen stream, a purge gas,
Integrate one or more of the sulfur recovery steps and common process liquid recovery. In other variations, in such an integration, process liquid recovery can be configured separately, allowing measurement of the sulfur content of each stream and adjustment of the flow rate to the combined zone, respectively, and practical forming a fuel having a sulfur content below the target sulfur content. In a variation, the process product stream from the upper zone of the hydroconversion reactor zone effluent is fractionated to separate two or more hydroconversion liquid fractions with a sulfur content higher than the target sulfur content. at least one of said fractions having a sulfur content of less than said target sulfur content is sent to another hydrotreating zone and contacted with hydrogen at hydrotreating conditions in the presence of a catalyst, said low sulfur hydrotreating having a sulfur content less than said target sulfur content. form a flow. Then,
The hydrotreated stream is combined with other hydroconverted liquid fractions and the untreated stream from the light tight oil to form a fuel having an actual sulfur content less than or equal to the target sulfur content.

In one embodiment, the light tight oil feedstock has an API density in the range of 45 to 55 degrees, the high sulfur fuel oil has an API density in the range of 14 to 21 degrees, and the hydroconverted fluid has an API density in the range of 14 to 21 degrees.
The combined fuel product has an API density ranging from 37 to 43 degrees and a sulfur content of less than 0.5% by weight. The actual sulfur content of the fuel of the present invention is adjusted to meet the target sulfur content within the IMO specifications for marine fuels or the turbine manufacturer's specifications for combustion gas turbines, as disclosed herein. can do.

In another embodiment of the invention, a method of co-processing crude oil with light tight oil and high sulfur fuel oil is provided. Within the scope of this specification and claims, the inventors use the mass or volume percent of the crude oil as the x-axis and the sulfur content as the y-axis in the context of crude oil analysis or other measurement methods. The "breakpoint" is defined as the point at which the sulfur content begins to increase rapidly or exponentially from a horizontal or near horizontal position with a high rate of increase per unit run. The difference in operation is the change in unit volume of the fraction, the difference in rise is the change in sulfur content,
The slope is the amount of increase in operation. The slope for the increase in such operations moves rapidly from zero or near horizontal values to more than 0.2, quickly to more than 1, and toward an exponential increase in sulfur content. The movement, breakpoints vary based on the crude oil or other feedstock to the distillation column. "Breakpoint withdrawal" or "sulfur breakpoint withdrawal" is therefore beyond the end of the range for naphtha, e.g. Provides a means for determining the fractionation of hydrocarbon-containing liquids that have a high rate of rise and boil below a break point, which is the point at which the sulfur content begins to increase rapidly or exponentially.

In this specification and claims, we refer to base ``breakpoint withdrawal'' or base ``sulfur breakpoint withdrawal'' as being above the end of the range for unstabilized wild straight-run naphtha with respect to the sulfur content of the cut. , is defined to mean a hydrocarbon-containing liquid that boils below the break point. Then, if the fuel product stream is formed from the combination of all raw streams below the breakpoint and all streams above the breakpoint withdrawal selected to be added to form the combination, then The points are selected such that the actual sulfur content of the combined fuel does not exceed the target sulfur content. In a variant, a fuel may be produced where the target sulfur content is at, above or below the sulfur breakpoint, and the combination of streams producing the fuel is The actual sulfur content is efficiently made relative to the breakpoint so that it does not exceed the sulfur target.

Hydrocarbon-based feedstocks, including crude oils and high-sulfur oils with relatively high sulfur, nitrogen, and metal contents, are fed to atmospheric and vacuum distillations to produce (1) light overhead distillate gas, and (2) below the sulfur break point. (3) (A) a sulfur-containing distillation range fraction; (B) a sulfur-containing vacuum gas oil range fraction; and (C) a sulfur-containing vacuum residue fraction above the sulfur break point. , and (4) distillation unit distillation gas, which is separated into a sulfur-containing purge gas, such as a small amount of sulfur-containing gas from the stripper and other unit operating overheads. The liquid fraction below the sulfur breakpoint is fed as raw liquid to the combination zone and forms at least a portion of the fuel. The distillation range fraction and the vacuum gas oil range fraction are contacted with added hydrogen at hydrotreating conditions in the presence of a catalyst in a distillation and vacuum gas oil hydrotreater to produce one or more hydrotreated liquids. Form. The hydrotreated liquid is sent to a combination zone and a purge gas with sulfur. The vacuum residue is sent to a boiling residue hydroconversion zone where it is contacted with added hydrogen at boiling hydroconversion conditions in the presence of a catalyst and (1) fed to a combination zone to form a portion of the fuel; another process liquid, (2) a purge gas having sulfur, and (3) a soluble deasphalted oil that is fed to the solvent separation and (A) fed alone or in combination with the vacuum residue to the residue hydroconversion. and (B) unconverted oil that forms insoluble pitch that is sent to pitch processing. The untreated liquid is combined with the treated liquid to form a fuel having an actual sulfur content less than or equal to the target sulfur content. Preferably, at least one of the hydrotreated streams is an ultra-low sulfur stream having less than or equal to 10 ppm by weight of sulfur, and by increasing or decreasing the amount of said stream for the combination, the actual sulfur content is reduced. The fuel is formed by adjusting the sulfur content to be less than or equal to the target sulfur content.

In a variation of the process of the invention, the above crude oil is removed, except for the hydrocarbon composition having hydrocarbons in (i) light overhead distillate gas of the distillate, (ii) pitch and (iii) sulfur or metal recovery steam. Substantially all of the hydrocarbon composition of the feedstock can be separated into fractions and subsequently recombined to form the fuel, which is one liquid fuel product rather than multiple hydrocarbon products. can. The fuel is treated with hydrocarbons ranging from the lowest boiling portion of the raw liquid fraction from atmospheric distillation to the highest boiling portion of the stream recovered from solvent separation and then treated in a hydroprocessing or hydroconversion reactor. and a stream that is recovered and incorporated into the fuel. In one variation, at least one of the hydrotreated vapors has 10
an ultra-low sulfur stream having less than ppm by weight of sulfur, the raw fraction having a sulfur content exceeding the target sulfur content, and the raw fraction being used as a trim control; Reducing or increasing the amount of such raw fraction relative to the target sulfur content results in a fuel having an actual sulfur content that is less than or equal to the target sulfur content. In another variation, the first hydrotreated stream is made as a reduced sulfur stream with a sulfur content of less than 10 ppm by weight, and the second hydrotreated fuel fraction has a sulfur content of 0. produced as a stream having a reduced sulfur content ranging from .12 to 0.18 wt. The stream and/or the second hydrotreated stream are used for trim control, increasing or decreasing the amount of such streams relative to the combination to form a fuel whose actual sulfur content is less than or equal to the target sulfur content.

In one variation, the residue hydroconversion and hydrotreating zone has separate distillation hydrotreating reactors, heavy oil hydrotreating reactors, and residue hydroconversion reactors, each reactor having a separate forming process effluents, each process effluent being fed to a separate shared wall separator to form a common overhead gas with sulfur and one or more separate reductions associated with each reactor process effluent. The treated gas-liquid treated effluents are separately withdrawn from said separators at rates based on their respective sulfur contents and (a) are sent to combination with said untreated liquid streams so that the actual sulfur content is equal to the target sulfur content. or (b) sent to reserve storage for subsequent trim control of the sulfur content of the fuel. In certain variations of the process of the invention, the amount of output product fuel may exceed the total amount of input feedstock, at least in part due to the capacity increase caused by the addition of hydrogen.

These new methods can adjust the sulfur content of the combined fuel to meet a target sulfur content within IMO specifications for marine fuels or turbine manufacturer specifications for combustion gas turbines. The fuels are therefore particularly useful in marine or land-based engines, combustion gas turbines or combustion heaters. Certain fuel variants derived by combining light tight oils and high sulfur fuel oils treated by residual hydroconversion have an actual sulfur content of less than 0.5% by weight and are free of crude oil derived hydrocarbons. Create fuels in the range of about C5 to C20 or higher. The hydrocarbons have an initial boiling point that is the lowest boiling point of any fraction in the raw stream combined with the fuel and a highest boiling point of the highest boiling portion of the effluent from solvent separation and then hydrotreated. or treated by hydroconversion and combined to form part of the fuel.

FIG. 1 provides an overview of one embodiment of the present invention, illustrating in simplified form the main components in a method for converting a hydrocarbon-based feedstock having sulfur and metals to form a fuel. The light tight oil feedstock 1 is preferably passed through a basic gas-liquid separator to separate light entrained gases or to stabilize, remove water and sediment, or Subject to other minor adjustments. The light tight oil feedstock 1 comprises substantially light and mid-range hydrocarbons with relatively low amounts of sulfur and metals and relatively low amounts of heavy oil and enters the combined zone 600 as a raw liquid stream without additional treatment. provided to. High sulfur fuel oil having sulfur, nitrogen and metals is fed via line 41 to a residue hydroconversion zone 401 where the residue hydroconversion zone 401 is operated in a selected ebullated bed reactor based on the feedstock composition. The oil 41 is contacted with hydrogen in the presence of a catalyst at residual hydroconversion conditions in a reactor or other suitable hydroconversion apparatus, and the reaction is divided into zone 401 into (1) a treated hydroconversion liquid 411; The vessel section effluent (referred to herein as a type of process liquid, ``hydroconverted liquid'') contains substantially the entire range of hydrocarbons from the boiling point range of about C5 to the lowest boiling point of unconverted oil 409. and (2) unconverted oil 409. Such separation is preferably in the form of vacuum distillation; for certain feedstock examples, near atmospheric distillation may be effective in separating unconverted oil. Unconverted oil 409 is fed to solvent deasphaltization in zone 301. Solvent deasphaltization separation 301 forms (A) soluble deasphaltized oil 311 as a feed to the hydroconversion reactor in zone 401;
It is recycled either separately or in combination with the high sulfur fuel oil feedstock 41 added to the reactor. Solvent deasphalting separation 301 also forms (B) insoluble pitch 351 that is fed to pitch processing within utility island 501. In the variant shown in FIG. 1, pitch 351 is fed to utility island 501 for processing.
In this example, the pitch is combusted in one or more gasifiers (not shown) to capture electrical power and at least a portion of the metals removed within the hydrogen conversion and gasifier solids. at least a portion of the hydrogen for the production of hydrogen.

The untreated liquid in line 1 is combined with the treated liquid 411 in the combination zone 600.
form fuel within. The fuel 600 combines the light and intermediate range hydrocarbons (i) of a light tight oil feedstock, condensate or other light feedstock 1 with the high sulfur fuel present in the treated liquid effluent 411 of the hydroconversion zone 401. Oil 41 heavier range hydrocarbons (ii)
The fuel 600 has a wide range of hydrocarbons from C5 to C20 or higher. The fuel thus formed has a wide range of hydrocarbons ranging from the lowest boiling point of the light tight oil forming the fuel to the highest boiling point of the hydrocarbons in line 311 that dissolve in solvent separation 301. , subsequently treated with hydrogen in zone 401 to form part of the effluent 411 to form the fuel described above. Compositions 1 and 41
The amount and flow rate of 1 can be adjusted based on the respective sulfur content such that the actual sulfur content of the fuel 600 is less than or equal to the target sulfur content. For example, and without limitation, if stream 1 has elevated sulfur content to an unacceptable level and cannot be used for combination within zone 600, the raw stream 1 may be fractionated (separated). (not shown), any higher sulfur content heavy bottoms portion can be sent to the integrated hydrotreater in zone 401 for processing, with the other portion of stream 1 remaining unprocessed in the combination zone. 600 can be passed. However, higher sulfur withdrawals resulting from processing upstream of the above hydroconverters, e.g. atmospheric distillation bottoms, are hydrocracked in the hydroconversion conditions, unnecessarily consuming hydrogen, and reducing the It is not fed to the hydroconversion as part of stream 41 as it produces lighter materials present in the tight oil feedstock. Alternatively, such higher sulfur withdrawal is sent to a separate hydroprocessing zone, as shown in the variation below. In this variation, the production zone effluent treated by one or more reactors in zone 401 can be separated by fractional distillation into two or more hydroconverted liquid fractions, and at least one of such fractions has a sulfur content higher than the target sulfur content, such fraction or fractions, alone or together with other streams from outside zone 401 having a similar sulfur content and boiling range, is sent to one or more separate hydrotreating zones within zone 401 to contact hydrogen at hydrotreating conditions in the presence of a catalyst and with a reduced sulfur content, preferably 0.5% by weight or less. , more preferably 0.2% by weight or less of the hydrotreated stream;
The low sulfur hydrotreated stream is combined with the light tight oil derived untreated stream or the stream remaining from fractionation or other processing of the light tight oil so that the actual sulfur content is less than or equal to the target sulfur content. form a certain fuel. In one variation, the in-line or integrated hydrotreater has a sulfur content of less than or equal to 10 ppm by weight, depending on the amount of ultra-low sulfur or low sulfur treatment liquid required for the combined stream that has a sulfur content less than or equal to its target sulfur content. gives a sulfur content of 0.1% by weight.

In a variation of the retentate hydroconversion system 401 shown in FIG. The recycled hydrogen is compressed, heated and, based on the selected catalyst and other conditions, effective operating temperatures, pressures and spaces known in the art to achieve the desired level of hydroconversion. Adjusted to speed and pressure. The effluent of the zone 401 reactor with process liquid and hydrogen-containing gas is separated and recovered in a high pressure separator (not shown). Purge gas with sour and acid gases is supplied via line 420 to a utility island 501 containing a pitch treatment and sulfur recovery system.
Pitch processing can involve combustion in one or more boilers to produce electricity and steam, alone or with a diluent, and in some cases sulfur from flue gases and other process gases. Hydrogen generation units with pressure swing absorption units and ancillary equipment for removing or reducing metals can be used. In other variations, pitch processing is by transfer for asphalt production or use as a coker feedstock for green coke production. In yet another variation, the pitch is combusted in one or more gasifiers for power generation, hydroconversion or hydroprocessing and to release at least a portion of the metal in the gasifier solids. Producing at least a portion of the hydrogen for capture for metal removal via such solids. The optimal choice of how to handle the pitch depends on the amount of pitch being produced, the availability of low cost hydrogen sources, and the potential sales channels for the pitch.

Not shown in Figure 1 are various auxiliary high, medium and low pressure gas-liquid separators, steam heaters, gas reuse and purge lines, and reflux drums for separating gases or lights from liquids. , compressors, refrigeration systems, and other ancillary applications are known to those skilled in the hydroconversion art. In addition, a common utility island 501
If not located within, hydroconversion zone 401 will include various amine or other sulfur recovery agent absorbents and stripping systems for sour gas or acid gas processing.

The parameters for selecting the residue hydroconversion catalyst and adjusting the process conditions of the residue hydroconversion zone 401 are within the skill of those in the petroleum refining industry and are suitable for the residue hydroconversion catalyst of the present invention. No additional explanation is required for the implementation of the classification. In the reaction zone, the residue hydroconversion catalyst used increases the hydrogen content and/or sulfur,
Includes any catalyst composition useful for catalyzing the hydroconversion of heavy hydrocarbon feeds to remove nitrogen, oxygen, phosphorus, Conradsonian carbon, and metal heteroatom contaminants. The specific catalyst type used and the various support and particle size configurations and residue hydroconversion conditions selected will depend on the sulfur and metal content and heavy carbon residue, as well as the It depends on the hydrocarbon feed composition of the feedstock and the desired reduced sulfur and metal content in the product stream from the reactor. Such catalysts can be selected from any catalyst useful for residue hydroconversion of hydrocarbon feedstocks. U.S. Pat. Hydrogenation conversion catalysts are also described. Ba
ldassari et al. further summarize various catalyst compositions and condition ranges for distillation and heavy oil residue hydroconversion, and distinguish between conditions for hydroconversion. All of these are known to those skilled in the art of residue hydroconversion. In a preferred embodiment of the invention,
Ebullated bed hydrogenation conversion has a reaction temperature range of 380°C to 450°C and a reaction pressure range of 70 bar to 17 bar.
0 bar (hydrogen partial pressure), preferably at a liquid hourly space velocity range of 0.2 to 2.0 h ^-1 and at 550
Conversion to minus C ranges from 30% to 80%.

In another preferred variation, the pitch 351 is integrated into an integrated gasifier having one or more gasifiers for partially oxidizing said pitch 351 in the presence of steam and oxygen and an optional carbon-containing slurry quench. fed to a combined cycle system 501 to form syngas, at least a portion of which is converted to hydrogen and syngas, similar to the formation of hot turbine gas;
The hydrogen is sent via line 502 to a hydroconversion system 401 for use, and the syngas is used to power a gas turbine of a combined cycle power unit in a utility island system 501 for power generation in process applications and other uses 504. burn. Integrated gasification
Combined cycle system 501 further includes a heat recovery generator to recover heat, such as from hot turbine gases, to produce extracted steam via line 507 internal process use or to drive a steam turbine, via line 504 Directed to additional generation of electricity. Each gasifier is
Metal-rich soot is also produced. The soot may be in the form of particulate solids and have metal contaminants from high sulfur fuel oils and/or heavy feedstocks. The solids are transferred from each gasifier to line 506.
The metal is then sent to be removed. The support system has one or more gas treatment units and all sulfur-containing gas streams from all unit operations, whether sour gas or acid gas, are routed for sulfur removal via 508. is supplied to the above gas processing unit. Preferably, such a sulfur removal system is part of a utility island of which the gasification system is also part. More preferably, one or more sulfur-containing gas streams are used in commercial sulfur acid production as part of the overall sulfur removal. The gasification system within utility zone 501 is typically an acid gas removal system optimized in capacity and configuration to produce the required hydrogen from at least a portion of the feed syngas produced within the gasification system. unit and acidic CO shift system.

In the embodiment of the method of the invention shown in FIG. 2, a liquid stream 4 from a high sulfur fuel oil feedstock 41
11 is combined with liquid stream 15 from light tight oil feedstock 3 in a combination zone 600 to produce a fuel with an actual sulfur content less than or equal to the target sulfur content.

The light tight oil enters processing in line 3 and heads to separator 101 where the feedstock 3 is divided into at least two fractions: (a) at least a portion of the naphtha range hydrocarbons in the light tight oil feedstock 3; Upper zone withdrawal containing all of the lighter low-grade hydrocarbons 5
, and (b) separated into a bottom portion that includes those substantially outside the scope of (a). Separator 101
The bottom 11 of is fed via lines 11 and 15 to the combination zone 600 and forms part of the product fuel. The upper zone naphtha and lower take-off 5 pass through a separator (not shown) and pass through line 7 to light distillate gas for internal use as process fuel or capture or for other applications; and (ii) stream 9, which is primarily naphtha range hydrocarbons.
has. After removal of the light gases, all or part of stream 9 is sent directly to line 15 for direct combination (via connectors, lines 9 and 17, not shown) and to zone 60.
0 or, considering the flash point of combination 600, at least the low ignition portion of stream 9 is a fuel such as a conventional aromatic oil complex having a catalytic reformer as is well known in the refining art. Passing through processing unit 151, stream 9 is contacted with a catalyst within unit 151 to produce byproduct hydrogen 505 and light process stream 155, which is recovered via line 159, for non-fuel or other uses. Unit 151 may produce useful by-products, such as fluidized petroleum gas 153 that is used internally as a process fuel or captured for other uses.

In FIG. 2, high sulfur fuel oil, alone or with other heavy residues or extra heavy oils, enters the process via line 41 and is fed to residue hydroconversion zone 401 to have very low sulfur. A liquid stream 41 is produced. As previously discussed in FIG. 1, the parameters for selecting the residue hydroconversion equipment and adjusting the various process conditions of the integrated residue hydroconversion zone 401 are within the skill of those in the petroleum refining industry. The implementation of the residue hydroconversion section of the present invention does not require detailed explanation. In the illustrated modification of this embodiment,
Integrated zone 401 has a hydroconversion reactor to which high sulfur fuel oil and other heavy feedstocks in 41 are fed. Such heavy feedstock 41 is preferably processed in a residue hydroconversion zone 401 with an ebullated bed reactor and separated into (1) a process liquid 411 and a purge gas 420 having hydrogen and sulfur; vessel effluent, and (2) unconverted oil 4
09 is formed. The unconverted oil 409 is fed to solvent separation 301 . Solvent separation 301 forms (A) a soluble deasphalted oil 31 and is combined with a high sulfur fuel oil feedstock 51 that is added separately or to the solvent separation zone 301 as a feed to the reactor 401; and collected. Solvent separation 301 is also fed to (B) pitch processing, FIG.
A substantially insoluble metal-rich pitch 351 is formed, which is the embodiment shown in FIG.

In the utility variant shown in FIG. 3, the pitch 351 is fed to a boiler and combusted to produce steam for steam turbine power generation 561. The boiler exhaust gas 429
At least a portion of the hydrocarbon conversion zone 401, either separately or in a purge or other gas stream from the hydrocarbon conversion zone 401, together with acid gas 420, e.g., sour gas or acid gas for sulfur capture and removal via line 565. The gases are processed in zone 701 via various amine or other sulfur recovery agent absorbents and stripping systems, and optionally via a separation system for metal capture and removal via line 563. Ru. Not shown in Figure 2 are various auxiliary high, medium and low pressure gas-liquid separators, flow heaters, gas reuse and purge lines, reflux drums for separating liquid from gas or lights; Compressors, cooling systems, and other ancillary equipment are known to those skilled in the hydroconversion and hydroprocessing arts. In the illustrated variation, in addition to any byproduct hydrogen 505 from process unit 151, other constituent hydrogen supplies to zone 401 are from hydrogen generation unit 517 with hydrogen source 519 via lines 503 and 509. For example, but not limited to, a natural gas-fed steam cracker having a pressure swing absorption unit,
At least a portion of the boiler steam from utility zone 501, described below, can be used.

contacting the combined heavy residue feed to hydroconversion reactor zone 401 with hydrogen in the presence of a catalyst and at residue hydroconversion conditions in an ebullated bed reactor in zone 401; (1) A reactor section effluent is separated into process liquid 411 and purge gas 420 having hydrogen and sulfur, and (2) forming unconverted oil 409. Also included in the hydroconversion zone 401 or a separate sulfur recovery zone 701 are various amine or other sulfur recovery agent absorbents and stripping systems for sour gas or acid gas processing, where a high sulfur purge gas 4
28 is supplied. A product fuel is formed by feeding the treated steam 411 to a combination zone 600 and combining it with untreated stream 15 to form a combination such that the actual sulfur content is less than or equal to the target sulfur content.

In the embodiment of the process of the invention shown in FIG. 3, the contaminated crude oil stream with sulfur, nitrogen and metals enters the process via line 2 after a pretreatment such as desalination suitable for the crude oil. In this example, the crude oil feedstock 2 can be a single crude oil, a mixture of one or more crude oils, or a mixture of crude oil and residual oil, such as light tight oil or high sulfur fuel oil, or both. . In the illustrated variant, the crude oil feedstock 2 and the light tight oil feedstock 3 are fed separately to the atmospheric distillation column 100. Preferably, the light tight oil 3 is in column 1.
A feedstock passage zone at 00 feeds at or near the top of the crude oil 2 and separates the feedstock into light overhead gas 4 and a plurality of withdrawals. The light overhead gases 4 include non-condensable distillate gases 6 useful as process fuels or captured for other uses. In one preferred variant, the investments associated with a stabilization system for such overhead gases 4 are avoided. However, depending on local needs, stabilization systems will be included, for example special marine fuel maximum _H2S specifications.

In the embodiment shown in FIG. 3, the plurality of withdrawals include (1) unstabilized wild straight-run naphtha in line 16 via line 4, (2) sulfur breakpoint withdrawal in line 18;
3) a light distillate in line 24; (4) a middle distillate in line 26; (5) a first heavy distillate in line 28; and (6) an atmospheric residue in line 30. or may include multiple streams. Preferably, the sulfur breakpoint flow combination (1) line 4 via line 16
unstabilized wild straight-run naphtha and (2) the line 18 sulfur breakpoint withdrawal containing from 0.06 wt.% to less than 0.08 wt.% sulfur and the target sulfur content of fuel combination 600 being If the sulfur content of the treated stream is less than 10 wt. Adjusted so as not to exceed the sulfur content. In a variant, the untreated low sulfur low metal light tight oil stream is fed directly to combination 600 via line 53 in addition to the combination of lines 10, 65, 75 and 85 to determine the final sulfur content and combination zone. Adjust 600 other parameters.

In FIG. 3, atmospheric residue is fed to vacuum distillation column 200 via line 37, alone or with an added residue oil feedstock 35, such as high sulfur fuel oil, and (1) to line 32; Double heavy distillation, (2) light vacuum gas oil in line 36, (3) heavy vacuum gas oil in line 38, and (
4) Produce vacuum residue in line 50. The vacuum residue 50 is sent via lines 57 and 317 to an integrated residue hydroconversion and hydroprocessing zone 401, either alone or with an added residue oil 55, such as a high sulfur fuel oil.

The parameters for the selection of the integrated residue hydroconversion and hydrotreating equipment and catalyst and the adjustment of the various process conditions within the integrated residue hydroconversion and hydrotreating zone 401 will be understood by those skilled in the art in the petroleum refining industry. The implementation of the residue hydroconversion and hydroprocessing sections of the present invention is within the technical scope of the present invention and does not require detailed explanation. In the illustrated modification of this embodiment,
Consolidation zone 401 includes (A) the heaviest and most contaminated feedstocks in lines 57 and 317;
(B) the heaviest distillate Gas oil and gas oil are supplied via line 39, for example, having (1) a light vacuum gas oil in line 36 and (2) a heavy vacuum gas oil in line 38, and in zone 410 a hydroconversion reactor effluent. (C) a lighter, less contaminated feedstock is supplied via line 20; For example, (1) the light distillate in line 24, (2) the middle distillate in line 26, (3) the first heavy distillate in lines 28 and 32, and (4) the second heavy distillate. and a distillation hydroprocessing reactor zone 430 that is fed via line 29 with distillation range material separated into zone 401 from the hydroconversion reactor effluent. For example, the second heavy distillate in line 32 can instead be fed to heavy oil hydrotreater 460 depending on the line 32 composition and load on the hydrotreater reactors in zones 430 and 460. balance and control of sulfur content levels. In such an integrated residue hydroconversion and hydroprocessing zone 401, the recycle and constituent hydrogen streams 410
and 414 and purge gas streams 412 and 416 have integrated recycling, separation and removal systems known to those skilled in the refining art. Not shown in Figure 3 are various auxiliary high, medium and low pressure gas-liquid separators, flow heaters, gas reuse and purge lines, reflux drums for separating liquid from gas or lights; Compressors, cooling systems, and other ancillary equipment are known to those skilled in the hydroconversion and hydroprocessing arts. In the illustrated variant, the hydrogen supply 503 is from a hydrogen generation unit 517 having a hydrogen source 519, such as, but not limited to, a natural gas-fed steam cracker having a pressure swing absorption unit, which is located in the utility zone described below. At least a portion of the boiler steam from 501 can be used.

Heavy residue feedstock 317 combined in hydroconversion reactor zone 490 is contacted with hydrogen in the ebullated bed reactor of zone 401 at residue hydroconversion conditions in the presence of a catalyst to (1) Two vacuum distillation units (not shown) preferably produce (1) a process liquid 85 comprising (i) naphtha, (ii) middle distillate and (iii) vacuum gas oil, purge gases 416 and 428 comprising hydrogen and sulfur. (2) forming a reactor section effluent that is separated into unconverted oil 409; Also included in the hydroconversion zone 401 or a separate sulfur recovery zone 701 are various amine or other sulfur recovery agent absorbents and stripping systems for sour gas or acid gas processing, to which a high sulfur purge gas 428 is supplied. Ru. As is known in the art, spent catalyst from the ebullated bed of the hydroconversion reactor 490 containing metals and/or other contaminants deposited on the ebullated bed or during processing within the ebullated bed of the reactor 490. At least some of the other materials that have accumulated with the catalyst are removed via line 421 and transferred to line 423.
is exchanged with the constituent catalyst via the In one variation, the process liquid 85 comprising (i) naphtha, (ii) middle distillate, and (iii) vacuum gas oil is fractionated, the middle distillate is sent to distillation hydrotreater 430, and the vacuum gas oil is It is sent to the heavy oil hydrotreating unit 460.

The hydroconverted unconverted oil 409 is sent to solvent separation 301 . The solvent separation 301 is (A
) in the steam hydroconversion reactor 490 or, in other variations, in the zone 460, either separately or in combination with the vacuum residue 50, together if high sulfur fuel oil feedstock 55 is added to the hydroconversion reactor 490; Forming a soluble deasphalted oil 311, which is fed via lines 57 and 317 to. Solvent separation 301 also includes (B) utility island 501
An insoluble metal-rich pitch 351 is formed to be supplied to the inner pitch treatment. In the utility variant shown in FIG. or zone 401 with acid gas 428, e.g., treated with various amines or other sulfur recovery agent absorbents, sulfur capture and removal via line 561 by a sour gas or acid gas stripping system, and line 563 by a separation system. The process of metal capture and removal is carried out through

In the variation shown in FIG. 3, the sulfur content of the fuel product 600 is controlled below the target sulfur content limit level as follows. (a) unstabilized wild straight-run naphtha 16 and sulfur breakpoint withdrawal 18 without any additional processing of either such stream;
combination 600 via line 10 followed by (b) actual product sulfur level 6
00 (1) light distillate 24, middle distillate 26, first heavy distillate 28 and second heavy distillate 3
2 to the combination of one or more of the streams 401 or to the integration zone 401.
The middle distillates in the hydroconverter reactor effluent formed in the distillation hydrotreater zone 4
30 or (2) increase or decrease the amount of stream 39 having light vacuum gas oil 36 and heavy vacuum gas oil 38 or formed hydroconverter effluent into integrated hydroconversion (401). vacuum gas oil (not shown) is added or reduced to the heavy oil hydrotreater 460, and then (c) (1) light distillate 24, middle distillate 26, first heavy distillate 28 and/or or distillation hydrotreater zone 4 via line 65 formed from second heavy distillate 32
30 and any hydrotreating converter effluent middle distillate; (2) light vacuum gas oil 36;
Stream from heavy oil hydrotreater zone 460 via line 75 formed from heavy vacuum gas oil 38 and any hydroconverter effluent vacuum gas oil, or (3) actual product 600 sulfur level for any reason. the combination of one or more of naphtha and other treated liquid effluents 85 from the hydroconversion reaction zone 490, if necessary to increase the sulfur level to the target sulfur level.
or (d) (1) line 6 from distillation hydrotreater 430.
(2) the flow through the line from the heavy oil hydrotreater 460, or (3) if for any reason it is necessary to reduce the actual product 600 sulfur content below the target sulfur limit level; One or more of the process streams from the hydroconversion reaction zone via line 85 are increased to the combination 600 . Such promotion will, for example, provide fuel supplies targeting sulfur fuels of 500 ppm or less for offshore and land-based gas turbines;
Multiple sulfur grades can be efficiently produced, such as different ranges for different end-use locations requiring different target sulfur content in the same application.

In a variation that uses a high sulfur fuel oil having a sulfur content higher than the target sulfur content limit level of the final fuel in combination 600, the high sulfur fuel oil is one of one or more various feedstocks. as a unit to one or more unit operations. Depending on its sulfur content, the high sulfur fuel oil is routed (a) to feed line 2 to atmospheric distillation 100 or line 30 to vacuum distillation 200, (b) remaining via lines 55, 57 and 317. (c) light distillate 24, middle distillate 26, first heavy distillate 26, or second (d) in combination with one or more of heavy distillate 32 feedstocks to distillate hydrotreater 430; (d) separately or in combination with one or more of light vacuum gas oil 36 or heavy vacuum gas oil 38; into line 39 to heavy oil hydrotreater 460 or (e) via line 59 to solvent separation zone 301 to form fuel combination 600 with an actual sulfur content less than or equal to the target sulfur content limit. be able to.

In another variation, the combination 600 zone clean fuel comprises: (a) a high sulfur fuel oil that can have a sulfur content higher than the target sulfur content limit level; Stream 10 formed from unstabilized wild straight run naphtha 16 and sulfur break point withdrawal 18 added depending on the sulfur content of the sulfur fuel oil, (b) wild naphtha and ultra-low sulfur diesel range material or (c) a stream 65 formed from a distillate hydrotreater 430 comprising wild naphtha, ultra-low sulfur diesel, and a second stream formed from a heavy oil hydrotreater 460 having a stream having a reduced sulfur content. (d) treated effluent 85 from hydroconversion reactor 85;
The treatment conditions and sulfur content of the respective streams 5 and 85 are such that the sulfur content of the raw steam 10, if any, is such that the actual sulfur content of the fuel 600 is below the target sulfur content limit. It is formed by adjusting while considering.

In one preferred variation of using a high sulfur fuel oil in making the fuel composition 600, the high sulfur fuel oil is added to a portion of the feedstocks 55 and 59 after the sulfur content of such high sulfur fuel oil is determined. to one or more of the solvent separation unit 301 or the residual hydrocarbon reaction zone 490 to optimize the adjustment of the hydroconversion conditions of the zone 490 and the adjustment of the sulfur content of the treated liquid effluent 85. A fuel is formed in zone 600, as determined by the sulfur content of the sulfur fuel oil, and the actual sulfur content is less than or equal to the target sulfur content limit.

The flow sheets of Figures 1, 2 and 3 showing various intermediate individual products are for illustration and understanding of the major products and by-products in the effluent of each unit operation depicted. It is.
The selected variant of separation or processing by each unit operation depends on the crude oil and feedstock selected and the optimization of the intermediate products produced to produce a fuel with sulfur below target specifications. For example, FIG.
The respective process effluents 65, 75, and 85 shown in can be combined in a consolidation zone 401 through the use of a common gas-liquid separator (not shown). For example, the ultra-low diesel produced in the hydrotreater 430 is transferred to the hydrotreater 460 or the hydroconversion reactor 4.
All hydrotreated materials 65, 75, and 85 that are not separated from the higher sulfur content hydrotreated materials produced at 90 are combined and fed into any one stream to combination zone 600. Integrated residue hydroconversion and hydroprocessing zone 40 as described above.
The parameters for adjusting the various process conditions within 1 are within the skill of those in the petroleum refining industry. For example, hydroconversion and hydrotreating conditions may be adjusted more gently to avoid decomposition if fewer light parts are desired in the mixture, and more severe if fewer heavy parts are desired. be adjusted.

Figures 4 and 5 illustrate novel fuels and combinations of one or more components with a range of light (L), intermediate (M) and/or heavy (H) materials to form such fuels. Teach the recipe.

FIG. 4 is a plot of both the temperature and density profile versus volume fraction of a reference fuel produced by the method of the present invention and its (L
), (M) and (H).

FIG. 5 shows the temperature and density profiles for the volume fraction of a reference light condensate that can be used as the "barrel top" for the combination. That is, such a condensate has the majority of the naturally occurring (L) components, with minor amounts of naturally occurring (M) and (H) 1 . Selected condensates are combined with additives (H)2 from other sources such as "bottom of the barrel" to constitute the fuel of the present invention.

FIG. 5 teaches by example that while the inventory materials in the refinery's "warehouse" for selecting possible combinations are rather large, the selection recipes taught herein are not. .

The essential requirement is that when the fuel of the present invention is formed by combining a series of hydrocarbon components, (L), (M) and (H), the resulting combination, based on a total volume of 100% by volume: It shall be determined as follows.
(a) (L)% + (M)% + (H)% = 100%,
(b) (L)% = (H)% = (100% - (M)%)/2) and (c) If (M)% is zero or less than 100%, the remaining ( L)%/(H)
% rate is 0.4/1 to 0.6/1,
Such a combination includes (1) density at 15°C within 820 to 880 Kg/M3, (2
) The sulfur content is 0.25% by weight or less, and (3) the metal content is 40 ppm by weight or less. As described herein, less sulfur and metals are preferred.

The potential components of (L), (M) and (H) are combined into industrial compositions in order to enable those skilled in the essential oil art to know for the first time how to choose which to combine according to the recipe of the invention. It is first summarized from a reference point of view and then narrowed by the limitations of the requirements above and below.

For example, with respect to the "(L)" or "light components" range of ingredients, certain ingredients may be those within the variations found within locally available refinery "warehouses" and others. may require manufacturing if not locally available. As a requirement herein, (L) as applied may include, but not all, components of naphtha and kerosene range materials, for example, due to the sulfur and density requirements for the fuel combinations described above. As used herein and in the claims, (L) has an initial boiling point of 38° C. (100° F.) or less, 90% plus an end point of 190° C. (374° F.) to about 205° C. 401 degrees). (L) shall be (a) purified or partially purified, (b) unpurified, or (c) extracted and subjected to fractional distillation, hydrotreating or other processing steps other than any separation of light gases or water. It can be used without doing anything. For example, specific components of (L) or precursors of (L) are published in the industry submission system, Platts, but the provided range of materials is not based on a sulfur breakpoint. This is because the breakpoint is new and
This is because the processing of the materials added to the combination or low sulfur substitute must be considered. Therefore, the ingredient descriptions below are a guide as to where to refer.

Such applied components of (L) also include, but are not limited to, EIA
(including conversions from Fahrenheit to Celsius in parentheses) (i) Naphtha: Refined or ``A general term referring to partially refined petroleum fractions'', and (ii) ``Naphtha: generally [50°C to 204°C]
．． 5° C.] (122 to 401° F.). It is further compounded or mixed with other substances to form premium motor gasoline and jet fuel. It is also used as a solvent and petrochemical feedstock, and as a raw material for city gas production. Accordingly, in accordance with the requirements taught herein and implementing the teachings of the present invention, manufacturing or procuring one or more suitable (L) or light components, or manufacturing such components. Procuring the starting materials for
Known to those skilled in the purification arts. For example, the (L) component preferably has a sulfur content at or near the break point, but the sulfur content in combination with the (M)
and (H) may exceed the breakpoint provided that the sulfur content of (H) does not exceed the fuel sulfur limit. Preferably, the range of the heavier portion of (L) ends at the sulfur breakpoint of the crude oil from which it was produced.

As used herein, components to which the "(M)" or "intermediate component" range applies are defined as from about 190° C. (374° F.) to about 205° C. (205° C.) for all purposes herein. means a refined or partially refined petroleum fraction having an initial boiling point of 401 degrees Fahrenheit) and a 90% plus end point of about 385 degrees Celsius (725 degrees Fahrenheit) to 410 degrees Celsius (770 degrees Fahrenheit). However, it is preferred that the range of the lighter portion of (M) begins at the sulfur break point of the crude oil from which it was produced. (M)
The composition can include a bottom portion of light tight oil that is heavier than the naphtha range. In a preferred variation, as another requirement herein, the starting component of (M) has a middle distillate combination of hydrocarbons from about 1/3 kerosene range to about 2/3 diesel range;
It has a density in the range 820-880 Kg/M3 at 15° C. according to D4052.

It will be known to those skilled in the refining arts to manufacture or procure one or more suitable (M) or intermediate components when implementing the teachings of the present invention in accordance with the requirements taught herein. be. In the many variations found within the available refining "warehouses", as (M), those within the definitions specified by the EIA (including, but not limited to, Fahrenheit to Celsius conversions in parentheses) ) (i) "middle distillates: a general class of refined petroleum products, including distilled fuel oils and kerosene", boiling below 385 degrees Celsius (725 degrees Fahrenheit); (ii) "kerosene: space heaters, cooking Kerosene, a light petroleum distillate used in stoves, water heaters, and as a light source when burned in wick lamps, has a maximum distillation temperature of 10% recovery point [204.4 degrees Celsius] (401 degrees Fahrenheit) and an end point of [300 degrees Fahrenheit]. °C] (572 degrees Fahrenheit) and minimum flash point [37.8 °C] (100 degrees Fahrenheit). Two grades No. 1-K, No. 2- certified by ASTN standard D3699.
K, and No. (iii) "Light gas oil: approximately [205°C to 343.8°C] (
"liquid petroleum distillates heavier than naphtha boiling in the range 401 to 650 degrees Fahrenheit" and (iv
) "Heavy gas oil: a petroleum distillate boiling at approximately 343.8°C to 537.8°C (651°F to 1000°F)" (iv) that boils below 385°C (725°F). (M) is required to include only the portion that boils below 385°C (725°F). (M) is also a material within the EIA definition (v) “kerosene-type jet fuel”; (vi) “
No. 1 Distillate", (vii) "No. 1 Diesel Fuel", (viii) "No. 2 Distillate", (ix) "No. 2 Diesel Fuel", (x) "No. 2 Fuel Oil", ( xi) "
distilled fuel oil” and (xii) if possible No. 4 fuel or no. All of the above, including some diesel fuels, are required to boil below about 385 degrees Celsius (725 degrees Fahrenheit). The EIA defines diesel fuel as ``Diesel fuel: broadly includes formulations with residual oil as a fuel consisting of distillates obtained in petroleum refining operations or blends of such distillates with residual oils used in motor vehicles.'' Diesel fuel has a higher boiling point and higher specific gravity than gasoline. Thus, since the residual oil is within the substance defined as diesel, one skilled in the art of refining can determine whether a given diesel is (M) or (H) based on the factors taught by this invention. How it works is evaluated. EIA has announced that “High Sulfur Diesel (H
SD) Fuel: Defined as "Diesel fuel containing more than 500 ppm sulfur" Many diesels fall under (M) or (H) due to other requirements of this invention, as further explained herein. do. However, as defined by EIA, “low sulfur diesel (LSD) fuel: 1
"Diesel fuel containing more than 5 ppm but not more than 500 ppm sulfur" and "Ultra Low Sulfur Diesel (ULSD) fuel: Diesel fuel containing up to 15 ppm sulfur" (M
), but due to other aspects of the invention, as further explained herein, (H)
may apply.

Subject to other requirements described herein, the required attributes of the (M) component range are:
In order to be able to form part of the combination of the present invention with a combination density that is between 20 and 880 Kg/M3, the (M) standard (often referred to as bulk) density for such range is Must be between 820Kg/M3 and 880Kg/M3 at 15°C. That is, even if the individual components of (M) are outside the range, the aggregate of (M) will have a temperature of 82°C at 15°C.
Applies to 0 to 880Kg/M3.

In a variation, the (M) component range has a higher sulfur content than the break point prior to treatment such as hydrotreating described herein for removal of sulfur. However, except in limited cases where the (M) component may be above the break point, the treated (M) component, such as a hydrotreater effluent, is not treated, such as a hydroconverter effluent. After treatment, the sulfur content when combined with (H) is determined so that the combination of (L), (M) and (H) when both are combined with (L) does not exceed the fuel sulfur limit. (M) Sulfur content must be below the break point. The higher level of the selected breakpoint allows the maximum amount of material in (L) to bypass downstream processing such as hydrotreating if used for sulfur removal, reducing hydrogen production costs and other Lower operating costs. In one variation, (M) is hydrotreated to produce a very low sulfur content in the range of about 10 ppm by weight and a very low or substantially metal-free effluent. (M)
Various grades of specific hydroprocessed materials that can be selected for use as components or precursors are published in Platts, a well-known industry offering system. (
If M) is not present or added, the boundary between (L) and (H) shall satisfy the requirements of (M).

As used herein, "(H)" or "heavy component" components are defined as Stationary point, approx. 815
Refers to a refined or partially refined petroleum fraction having an end point below 1499 degrees Fahrenheit. Such (H) endpoints are attributes of the (H) component that can be known through acquisition research or manufacturing testing. In one variation, (H) the end point is the highest boiling point of the components of the stream recovered from solvent separation, subsequently treated in a hydrotreating or hydroconverting reactor, recovered and combined to form said fuel. It is set depending on the raw material oil and/or processing conditions.

(H) One essential attribute of the component range is that during production, sulfur and certain heavy asphaltenes and metals are appropriate amounts of ingredients treated to reduce the presence of, or (
Other processing steps that reduce sulfur and metals to levels that can be added to the combination of L), (M) and (H) and meet the sulfur and metal specifications of the fuels of this invention. (H) Other essential attributes of range components are (H) range density and contribution to the final fuel combination, subject to other requirements described herein, density at 15°C of that fuel combination. is 820Kg/M3~880K
g/M3 to enable the formation of some of the combinations of (L), (M) and (H) of the present invention.

Therefore, when practicing the teachings of the present invention in accordance with the requirements described herein, (H)
The production or procurement of one or more suitable components of the heavy components or feedstocks and methods of producing the same are known to those skilled in the oil refining art. Purification available
In many variants found within the warehouse, the starting material for component (H) is, but is not limited to, those within the definitions specified by the EIA (i) and (iii) heavy gas oil. :
343.8 degrees Celsius to 537.8 degrees Celsius (651 degrees Fahrenheit to 1000 degrees Fahrenheit), the portion of a petroleum distillate that boils above about 385 degrees Celsius (725 degrees Fahrenheit). ) is required to be included in (H). (H) is also about 3
"Heavy gas oil: petroleum distillate boiling generally between 651 degrees Fahrenheit and 1000 degrees Fahrenheit" with an initial boiling point of 85 degrees Celsius (725 degrees Fahrenheit), ASTN Standards D396 and D975 and Federal Standard VV-F
(ii) Residual Fuel Oil: No. 815C remaining after distilled fuel oil and light hydrocarbons are distilled off in refinery operations. 5 and no. 6 includes the general classification of heavy oils known as fuel oils. No. 5 is a medium viscosity residual fuel oil, also known as Navy Special, that meets military specifications MIL-F-85 including Amendment 2 (NATO Symbol F-770).
9E and is used on steam-powered vessels in government agencies and coastal power plants. No.
No. 6 fuel oil includes Bunker C fuel oil, which is used for power generation, indoor heating, ship bunkering, and various industrial purposes, and (ii) the EIA defines "No. 6 residual fuel oil."

FIG. 4 shows one embodiment of the composition of the fuel of the invention produced by the method of the invention.

FIG. 4 shows two profiles versus volume fraction, a temperature profile 602 and a specific gravity profile 604, for a reference crude oil processed according to the present invention. That is, in FIG. 4, in both the top and bottom charts, the x-axis 610 represents the volume fraction of crude oil.
The y-axis 612 of the top chart shows the boiling point in degrees Celsius of the various outputs as data points that depict the temperature profile curve 602. The y-axis 614 of the bottom chart of FIG. 4 shows the specific gravity data of the reference crude oil, which depicts the density profile curve 604.

In both the top and bottom charts of Figure 4, the two vertical dotted lines LM606 and MH6
08 is drawn across the temperature profile 602 and density profile 604 curves. Vertical lines LM 602 and MH 604 are drawn as the volume fraction of the reference crude oil at the selected yield splits (L) range 622 and (M) range 624. In FIG. 4, LM6
The intersection point of 06 is 205° C., and the intersection point of MH608 is 385° C., determining the respective ranges of (L) 622 and (M) 624. For crude oils that are lighter or heavier than the reference crude, shift the line to the right or left.

Point 609 marks the end of the (H) range with vacuum gas oil cut up to 565°C and deasphalted oil from vacuum residue remaining below 565°C. It is understood that the temperature at point 609 depends on the deasphalted oil rise and 100% by volume representing pitch is not indicated from point 609. Temperature point 611 is the treated (H) heavy vacuum gas oil interface point used in the combination, with the (H) 626 portion from point 611 to point 609 being deasphalted oil. The corresponding density points are shown in Figure 4 as 615 for the entire range of raw crude oil. 613 is a straight line passing through the bulk densities of (L), (M), and (H) in the treated crude oil.

Therefore, the highest boiling end point of (L) range 622 and the initial boiling point of (M) range 624 share a common vertical line LM 606. The maximum boiling end point of (M) range 624 and the initial boiling point of (L) range 626 share a common vertical line MH 608 . The actual end point 609 of the precursor to the (H) range 626 is shown in other embodiments of the invention and includes certain heavy asphaltenes and other complex hydrocarbons as described in the definition of (H). The cut point is to remove the metal, substantially removing the metal and leaving a very low amount of sulfur (H) that contributes to the final fuel.

FIG. 4 further illustrates the methods disclosed herein for fuels produced by the methods of the present invention for forming fuel compositions contemplated by the fuels of the present invention produced by the methods of the present invention.
It shows how the components in L), (M) and (H) are combined. A variant overview examines the components and plots the density against volume fraction, with a line 640 for the required minimum density of 820 Kg/M3 at 15°C and a line for the maximum density of 880 Kg/M3 at 15°C. 64
Find the center point of the (M) range between 2 and 2. Center point 630 (density pivot defined later)
is the density-to-volume intersection point in the middle of the (M) range, with ±10% by volume or very little or no (M) range component, at or between which (L) ends;
(H) is the starting point. The central black square 630 is the (M) range bulk density center point,
631 and 633 are bulk density center points of the (L) range and (H) range, respectively.

When a crude oil lighter than the reference crude oil is processed to produce fuel by the method of the present invention, the vertical line LM
606 and MH608 are shifted to the right, and ranges (L) 622, (M) 624, and (H) 626 are lighter components (L) The volume of range 622 becomes larger and the volume of range (H) 626 becomes smaller. It means that. Density pivot 630 moves slightly and the fuel density decreases, but remains within density fulcrum 632 (defined below). The opposite occurs when a heavy oil that is heavier than the reference crude oil is processed to make fuel by the method of the present invention. That is, vertical lines LM626 and MH6
28 is shifted to the left, meaning that the volume of the component (H) becomes larger and the volume of the range (L) becomes smaller. Fuel density increases, but the point of fuel combination density pivot 630
Stay in the 820-880 Kg/M3 density zone between 40 and 642. Examples of such lighter and heavier feedstocks are 820-880 Kg/M3 for combined fuels.
Supply fuel having a bulk density within the range of (L) to a fuel combination density zone between lines 640 and 642, with the required aggregate density to balance each range of (L) and (H).
and (H) component (as well as (M) component, if present).

Therefore, very light feedstocks such as light tight oils and condensates, which are primarily (L) range materials, will have a final product bulk density within the density fulcrum and a fuel combination density zone of 820-880 Kg/M3. does not have sufficient amounts of heavy material (M) or (H) to act as a single material, providing fuel within it.

As used herein and in the claims: (a) the term "density fulcrum" means approximately ±10% of the volume at the density pivot with a bulk density of 820-880 KG/M3 at 15°C; means the center located at or near the density pivot (defined below) within the fractional range. For purposes of illustration, and not by way of limitation, 48% nominally by volume measures within 43-53% by volume, and 85% nominally by volume measures within 80-90% by volume. (b) The term "density pivot" means the center point of the density fulcrum which, when combining components (L) and (H) of the same volume, is equilibrated with or without component (M). density can be achieved. All of the quoted lines lie at one end of density curve 604 such that both ends are within the 820-880 Kg/M3 fuel combination density zone between lines 640 and 642, and the bulk density of the combination is at point 630. Whether the range is upward or downward, it passes through the necessary bulk density fulcrum, which serves as an essential guide for the formulation of the fuel.

Observing the density profile 604 shown in FIG. 4, the (bulk) density extends into an almost linear profile, with small fluctuations, but tilts outside the parallel zone range of the density fulcrum 632 and pivots around the center 630 of the density fulcrum. I understand. As shown, the density range is 882 at 15°C.
~880 Kg/M3, the substantially equal volumes of (L) and (H) lift and rotate line 604 for all formulations, and the bulk between 640 and 642 of the clean fuel of the present invention fall within the density range.

If the density of the final combined fuel product is less than the lowest density at density fulcrum 632 (e.g., a low density requirement of less than about 820), the calorific value will be reduced and to achieve equivalent energy efficiency, the fuel consumption will be reduced. An increase will be required. If the density of the final product exceeds the highest density of density fulcrum 632 (eg, upper density requirement above about 880), problems occur with engine fuel feedstocks, handling systems, and other end uses.

If all other conditions are satisfied, without disturbing the balance of the density fulcrum, (M
It is surprising that it is possible to substantially reduce or eliminate ) and still form a satisfactory fuel of (L) and (H). This allows the top and bottom of a particular barrel combination to recover the diesel range from (M) and still form a satisfactory fuel with the remaining (L) and (H).

FIG. 5 shows, for example, that the method of the present invention uses (L) light tight oil as the range component "top of the barrel" together with other components as (H) "bottom of the barrel". It shows how to form a fuel composition assuming the fuel to be manufactured.

In FIG. 5, condensate is used as the reference light tight oil type material shown in the top chart of FIG. This is an example of a light "top of the barrel" material with an API of 53°, approximately 69 vol% (L) range 722 ending at line 706, and only 28 vol% (M) ending at line 708. ) 724 and about 3% by volume atmospheric residual bottoms as part of (H)1 shown as 726 contributing to the final combination. A yield curve 702 of the above condensate reference material at various temperatures 712 plotted against volume fraction 710 is shown in the chart of FIG. As noted above, this reference material analysis yields, as a general approximation, approximately 69 vol.% (L) range 722, 28 vol.% (M) range 724, and a small amount of (H)1 range of approximately 3 vol.%. 726. The bottom is relatively light gas oil range material with only a small amount of heavy residue, so
End point 711 is 100% by volume. If the density fulcrum is shown for reference only (no added (H)2 shown in the bottom chart of Figure 5 only), then approximately 85% of the volume fraction of the original standard without added (H)2 Appears on the right side around . Therefore, to achieve a balance of the combination curve within the density target range of 820-880 Kg/M3 between line 740 and line 742, at least an additional (M) range component, preferably (M) + ( H) Components or, more preferably, primarily (H) substances are necessary for combination together with component (M).

In this example, shown in the bottom chart of Figure 5, approximately 69 vol.% (L)722, 28 vol.%
Each barrel of this reference condensate naturally occurring as (M)724 and 3% by volume of H1 range 726 is supplemented with other sources, such as (H)2 non-condensate produced as a full range effluent by hydroconversion. 0.69 barrels of 727 condensate are added. The central black square 730 is the bulk density center point of the (M) range, and 731 and 733 are the bulk density center points of the (L) range and the entire (H) range, respectively. The combination with addition (H)2 is 1.69 barrels ((L)+(M)+(H)1+
(H)2 (100% by volume as shown in the bottom chart of FIG.
It has a density of ~880 Kg/M3, an example of which is shown in Table 1.

（配合燃料は、低硫黄及び金属仕様を満たす）

(The blended fuel meets low sulfur and metal specifications)

Yet another variation of the invention reduces the amount of M in the combination to near zero.
This is due to a shortage in the supply of (M) range diesel and other materials, which is required due to ultra-low sulfur diesel track requirements and high demand for low sulfur marine and gas turbine applications. In this variation, a combination of substantially equal (L) and (H) portions with little or no (M) is created to form a blended fuel. "Heavier condensate"
or light-tight oil selection results in more atmospheric residue and, in some cases,
Some light oil range materials shift the vertical line (LM) to the left, with the density fulcrum rising as density increases due to the contribution of heavier light tight oils.

In one embodiment applying the above, we have determined that 1 consisting of (L), (M) and (H)
A novel blended fuel having a combination of one or more components is provided. Here, the respective amounts relative to the total combined amount of 100% by volume are determined as follows. (a) (
L)%+(M)%+(H)%=100%, (b)(L)%=(H)%=(100%-(M
)%)/2), and (c) (M) If % is zero or less than 100%, the remaining portion (
The L)%/(H)% ratio is 0.4/1 to 0.6/1, and the combination has (1) a density of 820 to 880 Kg/M3 at 15°C, (2) 0.25% by weight Sulfur content less than or equal to (3) 40
The fuel has a total metal content of less than ppm by weight. In one variation, the sulfur is reduced to 0.1% by weight or less and the metals are reduced to 25 ppm by weight or less. In one variation, 10% to 90%
(M) is present, and the remaining portion has a (L)/(H) ratio of 0.4/1 to 0.6/1. In another variation, the (M) present is between 20% and 80%, and the remaining portion has an (L)/(H) ratio of 0.
It is 4/1 to 0.6/1. In yet another variation, 30% to 70% (M) is present;
The (L)/(H) ratio of the remaining portion is 0.4/1 to 0.6/1. In a simplified embodiment, (M) ranges from 30% to 70% by volume, with the remainder having a (L)/(H) ratio of 0.9/1 to 1/0.9. It consists of (L) and (H) parts equal to . In other embodiments, (M) ranges from 40% to 60% by volume of the total, and the density at 15° C.
880Kg/M3, sulfur content is 0.25% by weight or less, and metal content is 40% by weight or less.

Therefore, we targeted a density at 15° C. of 820-880 Kg/M3 or less and used precursors with hydrocarbons from a combination of light tight oils and hydroconverted high sulfur fuel oils. It has been discovered that by utilizing alternative component manufacturing, fuels with very low sulfur levels of 0.1% by weight can be formulated or produced. The fuel has an initial boiling point that is the lowest boiling point of any fraction of the oil under atmospheric distillation conditions, and a maximum boiling point that is the highest boiling point of the residual portion of the high sulfur fuel oil that is soluble in a suitable solvent for solvent separation. It has a boiling point. For example, when practicing the present invention, if heptane is used as a solvent for acquisition metrics for combination component acquisition or as a solvent for manufacturing using the solvent separation portion of the manufacturing process of the present invention. , treated or untreated, the maximum boiling end point for the combination is higher than when pentane is selected as the metric or solvent for production.

We have applied the methods of the present disclosure described above to the selection of (L) + (M) + (H) precursors to envision a wide range of hydrocarbon blend fuel combinations useful as clean turbine fuels. It was discovered that it can be used for processing. The above turbine fuel has the following characteristics. (a)
According to ISO8754, 0.05% by weight (500ppm by weight) to 0.1% by weight (1000% by weight)
ppm by weight) of sulfur, (b) 820-880K at 15°C according to ASTM D4052
density in g/M3, (c) not more than 25 ppm by weight, preferably 1 according to ISO 14597.
less than 0 ppm by weight, more preferably less than 1 ppm by weight of all metals, (d) 43.81-4
HHV of 5.15 MJ/kg, and (e) LHV of 41.06-42.33 MJ/kg.
The flash point varies based on the lowest flash point component of the combination. The inventors have discovered a variant with the following additional envisaged properties. (a) 50°C below 10mm ² /s
( ^b ) ISO 103
70 carbon residue is between 0.32 and 1.5; (c) the solid gum is less than 5 according to ISO 6246; (d) the oxidative stability according to ASTM D2272 is about 0.5;
(e) The acid value according to ASTM D664 is 0.05 mgKOH/g. For use as marine fuel, reference is made to the test or calculation methods specified in ISO 2817-10.

Therefore, the present invention is broadly applicable to the production of fuels with reduced and low levels of sulfur and other pollutants, and the use of such fuels. Certain features may be changed without departing from the spirit or scope of the invention. Accordingly, the invention is not limited to the particular embodiments or examples described above, but is defined only in the appended claims or their equivalents.

Claims (3)

A fuel (600) comprising a liquid hydrocarbon component, the liquid hydrocarbon component comprising:
(a) having a sulfur content in the range of (i) zero (0) wt. Condensate or light tight oil (1) containing associated natural gas condensate or shale gas condensate ;
(b) a hydroconverted liquid effluent (411) of the residue hydroconversion (401) ;
The hydroconverted liquid effluent (411) of said (b) residue hydroconversion (401) is:
(i) a high sulfur fuel oil (41) supplied to the residue hydroconversion (401);
(ii) the soluble oil effluent (301) from the partial hydroconversion of the components of the high sulfur fuel oil (41) in the residue hydroconversion (401) of the unconverted oil (409); 311) and
is the hydroconverted liquid effluent (411) of the residue hydroconversion (401) of the components of;
the soluble oil effluent (311) is recycled as feed to the residue hydroconversion (401), and the insoluble unconverted oil (409) is removed from the residue hydroconversion (401);
(c) said fuel comprises a full range of hydrocarbons from the boiling point of C5 to the maximum boiling point of the highest boiling component of said liquid effluent (411) from said residue hydroconversion (401); Fuel (600). The fuel (600) includes a hydrocarbon ranging from a hydrocarbon having an initial boiling point to a hydrocarbon having a highest boiling point,
(a) the hydrocarbon having the initial boiling point is a hydrocarbon of condensate or light tight oil including oil well condensate, unassociated natural gas condensate or shale gas condensate;
(b) The hydrocarbon having the highest boiling point is
(1) is a liquid hydrocarbon of the high sulfur fuel oil (41) in (b)(i) above or the soluble oil effluent (311) in (b)(ii);
(2) hydroconverted high sulfur fuel oil or hydroconverted solubles of unconverted oil (409) recycled from said residue hydroconversion (401) of a feedstock comprising high sulfur fuel oil; liquid hydrocarbons of the oil spill (311);
The hydroconverted high sulfur fuel oil or the hydroconverted soluble oil effluent or the hydroconverted high sulfur fuel oil and the hydroconverted soluble oil effluent may be (x) hydroconverted. treated with hydrogen in the presence of a catalyst and mixed with the light tight oil or the condensate to form the fuel, either by conversion alone or (y) hydroconversion and subsequent hydrotreatment. 1. The fuel (600) according to 1. The soluble oil effluent (311) is a solvent separation (301) of insoluble substances from unconverted oil (409), the solvent being propane, butane, pentane, heptane or other paraffinic solvents. 1. The fuel (600) according to 1.

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