JP2023026441A - Method for providing electricity generated onboard to land power grid - Google Patents

Abstract

PROBLEM TO BE SOLVED: To provide a method for providing electricity generated onboard to a land power grid.

SOLUTION: The fuel is the one obtained by processing crude oil and by burning the fuel with a lower sulfur content than the maximum sulfur content based on the IMO specification which regulates a sulfur content applicable to a ship in the locations of emission control areas or emission control ports. The fuel has the actual sulfur content of 0.50%m/m (weight %) or less and includes the hydrocarbon with C3 or C5 to C20 or higher derived from crude oil. The hydrocarbon has the lowest boiling point which is the lowest boiling point of any fraction in an untreated flow combined with the fuel and the highest boiling point which is the highest boiling point of the hydrotreating flow combined with the fuel.

SELECTED DRAWING: Figure 1

COPYRIGHT: (C)2023,JPO&INPIT

Description

The present invention relates to a method and apparatus for producing fuels with very low sulfur content from crude oil, refinery bottoms and other contaminated liquid feeds. The very low sulfur content fuel produced by the present invention is particularly cost-effective for onboard large marine transport vessels and for large land-based combustion gas turbines on land.

The present invention addresses a long-known but heretofore unsolved major environmental problem, the use of "open-sea" vessels to reduce the cost of low-grade heavy bunker oil and other sulfur-, nitrogen- and metal-rich heavy fuels. The target is that sulfur, nitrogen and metal oxides are carried into the natural environment when the residues are burned. Such emissions are global in scale and extend irrespective of national geographical boundaries.

According to various third-party reports, the specific global emissions produced by the burning of such heavy fuels for waterborne transportation at sea are estimated to be 1.5% for all gasoline-burning land-based vehicles and vehicles worldwide. Many times more expensive than diesel vehicles combined. Such offshore combustion emits SOx, NOx, _CO2 , soot and harmful metals. Land vehicles include cars, trucks, etc., many of which now use mandated "highway fuels" with very low sulfur content. Therefore, even though transportation by such large vessels is efficient on a "load per mile" and fuel consumption basis, in practice such vessels generate large amounts of emissions.

The introduction of certain significant regulations mandating ships to use cleaner burning marine fuels is contingent on such fuels being provided in sufficient usable quantities. Solutions are still needed to avoid mandating what is neither technically, economically possible nor practical.

For example, the International Maritime Organization (IMO), a division of the United Nations, publishes regulations on international shipping. Recognizing the technical limitations, the IMO has tried to reduce emissions by tightening sulfur limits in marine fuels. Since 2011, the IMO has stated that marine fuel burned offshore (e.g., burning outside Emission Control Areas (ECAs), including 200 nautical miles from the shores of the United States, Europe and other countries) has been reduced to 3.50% m/ It requires the fuel to have a sulfur content not exceeding m. In 2015, the IMO amended the regulations to limit the sulfur content of marine fuels to generally less than 0.1% for commercial vessels within the ECA.

However, the IMO has again significantly reduced the open ocean sulfur limit to 0.50% m/m for 2020 and beyond. However, the IMO said such aggressive cuts in 2020 would be contingent on "the outcome of a review of the availability of the required fuel oil, which is expected to be completed by 2018". It suggests the possibility of deferring such cuts to 2025 if no such reductions are available. For control of air pollution in the marine industry, see the Marine Pollution Prevention Convention (MARPOL), Annex VI.

Therefore, there is a real and significant potential for problems to arise with respect to the lack of supply availability of low sulfur marine fuels and the lack of technology to achieve such supply. For example, in a 2015 industry publication, "Plans are being made to reduce the permissible sulfur content in fuels below the [2014] levels required for emission control areas... but this It will take many years because current technology would make the cost prohibitive for many shipping lines." Such publications further stated that "because of the extra cost and possible mechanical problems, these regulations are continually being reassessed and a phased approach to implementation is being adopted", which , "Many marine engines are not designed to handle low-sulfur diesel, which is much leaner than heavy fuel oil and does not have the lubricating properties of heavy fuel oil." , cooling the fuel to make it more viscous, and injecting additional lubricants into specific parts of the engine. .

Another example is that in 2015, IMO regulations lowered the sulfur content of marine fuels to a maximum of 0.1% sulfur for commercial vessels within designated ECAs. Before entering the ECA, the vessel must change from high-sulfur, but cheap, high-sulfur heavy bunker fuel oil burned in the open sea to an expensive, low-sulfur fuel similar to highway diesel fuel. Since January 1, 2015, the reduction of fuel sulfur in the ECA from 1.00% m/m (since July 1, 2010) to 0.10% m/m has reduced market supply and prices. A configuration issue was triggered. The production and supply of marine fuels for IMO-related regulatory compliance will compete with distillate fuel demand for highway and other land-based diesel applications, and the availability of preferred feedstock streams and existing refineries and supplies. diverting the commodity supply chain away from highway utilization of diesel and other low-sulfur distillates. There are also other technical problems on board.

Regarding the 2015 IMO reductions in sulfur content within ECAs, the U.S. Coast Guard said, "Vessels using higher sulfur content fuels must switch to ultra-low sulfur (ULS) fuel oil to meet the new regulations." You must,” he warned. Since ships must use ULS fuel oil at all times during their inbound and outbound voyages, at dock and within the ECA, ships using high sulfur content fuel oil should be A changeover procedure for switching distillate fuels needs to be developed and implemented. The Coast Guard further added that "other important technologies related to the use of ultra-low sulfur fuel oils and fuel oil switching" are referred to in documents prepared by classification societies, insurance companies, engine manufacturers and industry groups. and that the energy content per unit volume of ULS fuel oil can differ from residual fuel, such as existing throttle settings not providing the desired propeller shaft RPM or generator load. (Non-Patent Document 2).

The stark reality is that refineries are expensive, requiring large capital investments to make even seemingly relatively minor changes in fuel products or manufacturing equipment or the addition of unit operations. That is. During 2003, a refinery evaluation study in Europe was conducted with an eye to the need to reduce the pollutants of marine fuels, as well as the requirements and capacities of producing the required quantities of such fuels. See, for example, Non-Patent Document 3.

Such reports point to rising costs and inefficiencies in refinery utilization in trying to produce adequate marine fuel needs in many countries, as well as, in some cases, major ports. It posed major challenges, such as the lack of local infrastructure for the local production and supply of such marine fuels nearby, as well as the lack of technology and equipment to make such fuels.

The cited report found only three options. The 're-blending option' (blending heavy fuel oil into low-sulphur fuel) was considered the lowest cost option for manufacturing low-sulphur bunkers, as it does not incur significant costs and can process minimal amounts of material. , was not appropriate. This option was relatively low cost in terms of logistics for reformulation of different categories of heavy fuels currently produced in European refineries, but failed in terms of volume.

A second, more costly alternative is to use a high sulfur content crude such as Arabian Light, which is reported to contain 1.8% sulfur, and a low sulfur crude, e.g., 0.14% by weight sulfur. It is the processing of low sulfur crudes by substituting them with African crudes such as Bonnie Light, which is reported to contain. The estimated incremental sea bunkering costs incurred by this option were deemed excessive for the reasons given in the report.

This old report finally points to the third and most expensive option for the production of low sulfur marine grade fuel using vacuum residual desulfurization (VRDS). The report concludes, "However, in contrast to the degree of desulphurization required for gasoline or diesel, hydrotreating the bottom of the barrel (residual oil desulphurization) reduces residual oil to lighter products. It is important to realize that the treatment is not exactly the process that refiners are currently considering implementing, unless it is combined with some conversion of the VRDS. If pursued for the sole purpose of desulphurizing residues, the cost of this option would be about twice that of the second option, and is therefore even less acceptable.

In order to meet IMO requirements according to the prior art, a vessel operator could load both high sulfur content fuel oil for use at sea and low sulfur content for use within an ECA, but this choice Problems may be encountered with respect to technology, lubricity, and the possible need for different fuel injection systems for optimum operation and fuel switching mechanisms. Ship operators can add relatively large, expensive and complex post-combustion flue gas treatment equipment to maintain the highest performance levels. In some cases, the use of liquefied natural gas (LNG) as a marine fuel is conceivable. In that case, for example, LNG carriers could choose to use "evaporation" as fuel, but to extend this LNG engine concept to all cargo ships would require very expensive LNG filling stations. are required, and ports in rural areas that do not have local natural gas production supply facilities or liquefaction facilities will incur additional costs. In all cases, however, the use of LNG instead of liquid poses a real risk of leakage due to ventilation during refueling or incomplete combustion, or methane release during operation and maintenance. Such methane emissions are of concern because methane is believed by some to have many times the impact of sulfur dioxide as a greenhouse gas on the environment. From a similar perspective, some argue that emission reductions in marine applications can be achieved by burning natural gas during shipping or while in port with a gas supply docking station. However, from one technical point of view, natural gas has methane leakage problems, and although natural gas combustion reduces _CO2 emissions, this is not due to less _CO2 emissions, but compared to LNG. If so, the use of natural gas avoids the _CO2 emissions generated in the process of liquefying LNG and reduces _CO2 in the recovery and exchange of coal to fire power plants that supply ships in port. It is from. Development efforts to promote the replacement of LNG or natural gas with liquids as ship fuels should be considered, but the lack of a global gas infrastructure and the need for new refueling infrastructure would impose practical costs. It does not provide a highly effective marine solution. Gas distribution infrastructure represents a demanding facility and capital investment for ports in countries with no local gas production and supply.

Lenglet, US Pat. No. 5,200,900 discloses a crude oil preformation process to produce two non-asphaltenic oils and predistillation of asphaltenic oils, vacuum distillation, solvent deasphalting, hydrotreating, hydrocracking and residuals. The preparation of multiple products with hydroconversion is described. Non-Patent Document 4 describes unit design, catalyst selection, hydrogen consumption and other operations for removing sulfur by hydrogenation and producing a product with less than 8 ppm sulfur by using a highly active Ni/Mo catalyst. conditions are stated. Non-Patent Document 5, p. 6, Advanced Purification Technology, Catalagram Specific Edition Issue No. 113/2013 also describes hydrotreating to sterically unhindered sulfur using a highly active CoMo catalyst and residual sterically hindered sulfur removal to 10 ppm by a highly active NiMo catalyst.

However, there has long been a gap in effective fuel production technology that has created a shortage of low-cost, high-volume ultra-low-sulfur marine fuels. There remains a need to fill this void.

The Petroleum Industry and Markets Division of the International Energy Agency (EIA) has published official documents describing the composition of processes and equipment used to make fuels and describing the composition, products and margins of conventional refineries. there is Terms used herein, unless otherwise defined or expressly changed, have the meanings given in Non-Patent Document 4 and are incorporated herein for all purposes. EIA publications define and discuss configurations for processing crude oil and splitting each barrel of crude oil feedstock into multiple products for different uses or downstream processing.

The genetics of conventional refinery development and growth are somewhat primordial, based on the evolution of society's product needs, ranging from basic kerosene-grade distillates for lighting to gasoline for automobiles and It has progressed into multiple products such as diesel, then aviation grade fuel, and feedstock for many downstream chemical applications. All refinery technology developments typically maximize a given split yield from each barrel of crude oil for a particular market segment while still producing multiple products for various end uses. It appears to have evolved step by step, guided by either adapting refinery flows to downstream chemicals.

Thus, prior art refinery designs using atmospheric crude and/or vacuum distillation units, solvent separation, hydrotreating, gasification, and many other unit operations, each barrel of crude feedstock is processed differently. Split into multiple products with different specifications for each application or downstream process.

In conventional refining, it is counterintuitive to separate the feedstock into different unit effluents and then recombining all of the effluents. For example, the above EIA references define and describe conventional or typical atmospheric crude oil distillation, vacuum distillation, fuel solvent deasphalting, catalytic hydrotreating and integrated gasification combined cycle technologies. , do not describe the configuration of a process for converting substantially all of a crude oil feedstock to make a single liquid fuel.

Within conventional refining processes are "upgrading", "topping" or "hydroskimming" equipment. For crude oil upgraders, the primary purpose is usually to process very heavy, viscous or solids-laden materials and lighter, flowable materials into fuel products, chemical feedstocks and/or The goal is to convert the entire range of petroleum coke so that it can be reprocessed in existing conventional refineries. Upgraders simply convert heavier crudes to lighter crudes for supply to conventional refineries that are individually designed to process sulfur to meet their respective downstream product specifications. Sulfur reduction or metal removal is not the primary objective of the upgrader. The goal is to upgrade feedstocks that have very high densities compared to typical lower density crude feedstocks. Heavier materials are eliminated or separated from the feed material and the density of the resulting modified product material approaches that of crude oil processed by existing conventional refinery configurations. With respect to topping or "mini" refineries, they are often located in remote or opportunistic locations of crude oil sources. Topping refineries typically include, in a few limited cases, naphtha reforming for octane enrichment of gasoline and hydrotreating of multiple distillates to produce various products. to split each barrel of crude feedstock into a plurality of straight run fractions that target naphtha rather than gasoline production with no or minimal subsequent processing. The purpose of a typical topping refinery is to produce a wide range of directly usable fuels such as gasoline, kerosene, diesel and fuel oils for local market consumption. Some undesired topping practices and the use of topping products or failure to adequately address residues can increase rather than reduce harmful emissions to the environment. . A hydroskimming refinery converts crude oil into multiple products like a topping refinery, but typically feeds a reformer that also produces hydrogen that is consumed by a hydrotreater in diesel production. Limit the amount of heavy naphtha added. Hydrogenation skimmers, like Topping refineries, typically produce a wide range of gasoline, kerosene, diesel and fuel oils for local consumption rather than just one product.

Various aspects of adapting hydroprocessing are known in the art, including having independent series or parallel hydroprocessing reactor zones or integrated hydroprocessing reactor zones. US Pat. No. 6,330,000 to Cash et al. and references cited therein disclose integrated hydrotreating of different feeds, wherein hydrogen-containing and liquid-containing hydrotreating from separate hydrotreating zones Flows are split or combined according to the disclosed methods. Various embodiments of the use of solvent separation to extract deasphalted oil from pitch within a heavy residue stream and use the deasphalted oil as a hydroprocessing feedstock to produce multiple product streams. When used, they are known in the art. For example, Brierley, et al., US Pat. No. 5,300,300, describes deasphalting without cracking or decomposition by separation of the feed based on solubility in liquid solvents such as paraffinic solvents up to heptanes including propane, butane, pentane and heptane. Solvent deasphalting for oil production is described. The residual pitch has a high content of metals and sulfur. Deasphalted oils are hydrotreated to remove sulfur, nitrogen, concarbons and metals as described in references for the production of several products including naphtha, kerosene, diesel and residuals. can do.

In the global market, sulfur is used to address global environmental concerns in offshore or land-based locations with little or no natural gas resources and using low-efficiency high-sulfur fuel oils or unrefined crude oil. and large quantities of low-nitrogen, essentially metal contaminant-free fuels must be available.

Fuel producers require different designs than those developed for conventional refining to produce multiple product slates. To keep costs low, the design must include only the equipment necessary to produce large quantities of clean fuel in a cost-effective, thermally efficient manner in a manner that limits capital investment. . The design is primarily aimed at producing marine fuel rather than extracting a relatively small fraction of each barrel of crude oil for marine fuel and using the bulk of the barrel for other uses. should be

What the world needs is large quantities of energy (in an efficient way to avoid wasting energy in short forms such as British Thermal Units (BTU)) in an economical manner for marine applications. It is a "game-changer" novel process that provides a solution to the technical problem of how to make relatively clean liquid fuels. Such a process would use existing liquid marine fueling stations spread around the world (e.g. those supplying high sulfur fuel oil (HSFO)) for fuel distribution instead of creating new infrastructure for LNG. , minimizing the required facilities and associated capital and operating costs. Any such new process would be a direction in favor of making liquid BTU cost-effectively superior to Ultra Low Sulfur Diesel (ULSD), which is primarily produced for automobiles and trucks. There is a need to. Such available diesels are widely available, but due to cost issues and lubricity issues that arise when ULSDs are used in many existing marine diesel engines, they are often shipped offshore by large marine carriers. not widely used in

International Application No. PCT/US1999/00478 U.S. Pat. No. 7,686,941 U.S. Pat. No. 8,088,184 U.S. Patent Publication No. 20140221713

Josiah Toepfer, U.S. Coast Guard Ship Inspector/Auditor and Accident Investigator, "Is it true that the 15 biggest ships in the world produce more pollution than all the cars?" Internet article published by Quora U.S. Coast Guard, U.S. Homeland Security Inspection Agency, Office of Compliance, “Ultra Low Sulfur Fuel Oil & Compliance with MARPOL Requirements Before entering and while operating within Emission Control Areas,” March 3, 2015, Safety Advisory 2-15, Washington D.C. European Commission Environment Directorate General, "Advice on Marine Fuel: Potential price premium for 0.5%S marine fuel; particular issues facing fuel producers in different parts of the EU; and commentary on marine fuels market", Final Draft Report, Contract No. ENV. C1/SER/2001/0063, Order Slipn° C1/3/2003, October 2003 US Energy Information Administration, "Glossary", October 2016 Wright et al., Lloyd's Register FOBAS, "Marine Distillate Oil Fuels Issues and implications associated with the harmonization of the minimum flashpoint requirement for marine distillate oil fuels with that of other users," for the Danish Shipowners' Association, 2012. Rall et al., “Sulfur Compounds in Crude Oil,” Washington, DC, UNT J. P. Wauquier, “Petroleum Refining: Crude Oil. Petroleum Products. Process Flowsheets,” 1995, Institut Francais du Petrole Ackerson et al., Revamping Diesel Hydrotreaters For Ultra-Low Sulfur Using IsoTherming Technology. Shiflet et al., "Optimizing Hydroprocessing Catalyst Systems for Hydrocracking and Diesel Hydrotreating Applications, Flexibility Through Catalyst," p. 6, Advanced Refining Technologies Catalog, Special Edition Issue, No. 113/2013.

The present invention fills a gap in effective fuel manufacturing technology by enabling the provision of very low sulfur, nitrogen and substantially metal free fuels in large quantities and at low cost. The fuel is particularly useful in marine applications, as well as large-scale land-based applications such as combustion gas turbines for power generation. The term "essentially metal-free" or "zero metals" as used herein and in the claims means a metal content ranging from zero (zero) to less than 100 parts per billion (ppb) by weight. content so low that it is difficult to measure reliably by volume or conventional on-line instrumentation.

Conventional refining takes crude oil feedstock into many parts, each part being sent to a separate downstream market channel. In contrast, the inventors have determined that each barrel of crude oil feedstock should be can be converted into a single ultraclean fuel. The present invention removes crude oil feedstock in only the minimum number of portions required for contaminant capture and control, and then reassembles the portions to form a single fuel product.

Thus, the present invention is a departure from conventional refining, which divides each barrel of crude feedstock to serve multiple markets such as gasoline, diesel, fuel oil, or feedstock for downstream chemical production or applications. Different, the method of the present invention is aimed at producing a primary clean fuel product. The present invention provides a low cost polishing system for unrefined and residual oils, which is suitable for high sulfur bunker fuels and other heavy residues used in commercial shipping and power plant combustion systems. It is necessary to produce alternative commercial scale large quantities of clean fuel. The present invention provides such fuels and methods and apparatus for making them to reduce sulfur in a cost-effective manner.

These new processes use counter-intuitive steps to lower manufacturing costs while controlling final product sulfur content below target sulfur levels in a surprisingly effective manner. The present invention provides a novel method of converting the maximum amount of each barrel of crude oil feed into a single ultra-clean fuel while simultaneously capturing polluting sulfur, nitrogen and toxic metals during fuel manufacture.

In many variations of the invention, essentially all of each barrel of feed, in certain variations characterized as 90% by volume or more, is converted to a single fuel, and such variations In an example, only a minimal amount of less than about 10% of each barrel of crude oil is consumed for process utilities and streams for pollutant conversion and capture. The process of the present invention is useful for other operations such as hydrogen balance, local demand for asphalt and coke and other residual products, overall production economics, and local availability of alternative low cost process fuels and electricity. For the purposes of the above considerations, it allows adjustment of the proportion of feedstock allocated to fuel production as well as the feedstock allocated to process utilities and streams for conversion and capture of pollutants. In a variation, at least 70% by volume of each barrel of crude oil feed is converted to liquid fractions and subjected to subsequent processing, or raw but blended, in a plurality of hydrocarbon products. and a sulfur content not exceeding a target sulfur content, and the remaining portion of each barrel of said crude feed is contained in a residue or other vapor or product. exists in

Unlike conventional refining, which removes the crude oil feed in multiple portions and sends them to separate market channels, the present invention removes the crude oil feed in the minimum number of portions required for contaminant capture and control. The removed parts are then reassembled to form a fuel product that is very low in sulfur and nitrogen and essentially metal-free. The methods and apparatus configurations of the present invention enable the low-cost, efficient production of large quantities of the low-sulfur fuels required for regulatory compliance in large-scale offshore and onshore turbine applications. These new fuel deployments have substantially lower capital and operating costs than alternative conventional crude oil refining, thereby having very low sulfur and nitrogen content in an extremely cost-effective manner. , capable of mass-producing fuels that are essentially metal-free. These new processes enable a highly cost-effective means of simplifying the supply chain of energy from oilfields to ship engines or onshore power plants.

For the shipping industry, the novel configuration of the present invention provides the necessary quantities of low cost, low sulfur marine fuel to meet global marine sulfur reduction targets. The novel fuel production process and equipment arrangement of the present invention has substantially lower capital and operating costs than conventional crude oil refining, resulting in very low sulfur, essentially metal-free, Bulk marine fuel with very low nitrogen content is produced in a very cost effective manner.

The fuel of the present invention replaces low grade heavy bunker oil high in sulfur and metals and significantly reduces emissions of SOx, NOx, _CO2 , soot and harmful metals into the open ocean. Instead of sulfur and metals being carried into the environment upon combustion of bunker oil, in the practice of the present invention sulfur, nitrogen and metals are captured and removed during combustion production in an environmentally friendly manner. In some embodiments, the present invention provides certain low-sulfur alternative fuels at a lower cost than diesel, yet these fuels provide sufficient lubricity to avoid excessive wear on marine engines. and these new fuels can be used in existing bunkering fuel infrastructure without heating and fluidizing the fuel, compared to other fuel alternatives, so they can be used on land or in tanks on board ships. can reduce the energy consumed to heat the fuel.

In one variation, the fuels of the present invention are also used in large land-based combustion turbines located in installations such as single-cycle or combined-cycle power plants, such as those that produce electricity and demineralized water, for example, crude oil or Provides an alternative to burning heavy residues. Turbines burning the fuels of the present invention have significantly lower turbine exhaust emissions of NOx, SOx, _CO2 , soot, hazardous metals and other combustion by-products and, depending on the source, polluted heavy crude oil or refineries. There is also less fouling under hot zone corrosive or ash forming conditions when burning residual oil.

The present invention relates to the concentrated conversion of a complex hydrocarbon feedstock into a single fuel product for use in combustion applications such as marine engines, combustion gas turbines or combustion heaters. In a basic embodiment of the present invention, crude oil is pre-entered and returned as a single, ultra-clean product fuel that is controlled to low sulfur levels, nitrogen-reduced, and metal-free. In a variation, the feed for distillation is one or more crude oils combined with one or more high sulfur fuel oils or other heavier bottoms, which are subjected to vacuum distillation, solvent separation, It can be a crude oil with the further addition of light tight oil or high sulfur fuel oil, or both, as part of the stream feed to one or more other unit operations such as hydroprocessing or gasification. .

In other uses in the art, the terms "high sulfur fuel oil" or "HSFO" have different, often dissimilar, contradictory and confusing meanings in various technical articles, patents and statutes. assigned, some of which change over time. As used herein and in the claims, "high sulfur fuel oil" or "HSFO" is used as a fuel with a sulfur content greater than 0.50% m/m (0.5 wt%) means any substance. The terms "heavy oil", "heavy residual oil", "residue", "residue" or "other heavier oil" as used herein refer to sulfur content of 0.50% m/ contains more than 0.5 m (0.5% by weight) of petroleum-derived hydrocarbonaceous material. The term "high sulfur" means above the target sulfur content limit or, where applicable, the legal sulfur limit, whichever is lower.

In a preferred embodiment, the sulfur content of the final product fuel is controlled by combining streams with different sulfur contents. In variations, each such combined stream may be mixed by adjusting the unit operating conditions and flow rates, by reducing the addition or removal of very low sulfur content streams, or by adding or removing different sulfur content streams. The interim target sulfur content is formed by blending the feed. Variations of the present invention optionally include the addition of selected crude oils to (i) other crude oils, (ii) bunker fuels, (iii) high sulfur fuel oils or other distillates, or (iv) other and other high sulfur or metal contaminant residues from sources of The term "essentially metal-free" or "zero metals" as used herein and in the claims means a metal content of zero (zero) to less than 100 parts per billion (ppb) by weight or It means a content so low that it is difficult to measure reliably by conventional on-line instruments.

The inventors have discovered that the production of low sulfur fuels can be optimized by addressing the sulfur content distribution of different crude oil feedstocks.

We have found that (i) if only a relatively small amount of sulfur is present in a particular fraction in basic form of the basic H2S or RSH thiol type, and (ii) a relatively large proportion of sulfur is more When present in complex organic structural forms, such that the sulfur content then begins to increase more rapidly, sometimes exponentially, compared to lower fraction levels. , the process flow rate and operating conditions can be adjusted based on the predicted breakpoint fraction at a higher or higher level.

The inventors have determined that by-passing certain streams to maximize their bypassing, avoiding or reducing the treatment of streams containing sulfur forms of low basic complexity, and containing more complex forms. We have found that it is possible to arrange the process and equipment configuration to allow the streams to be treated differently. This can be done by selectively excluding certain streams from hydrodesulfurization and for other streams feeding the same to different hydrotreating units to adjust different hydrotreating unit conditions, or removing solvent and/or The removal can be tailored by reactive chemical-based treatments. In so doing, treatment with multiple solvents or other scavenging agents in one or more removal units, the respective ratios of scavenging agents in each unit selectively removing low or high complexity sulfur-containing molecules. may include making adjustments based on the sulfur distribution to each unit to achieve this.

Although the terms “kerosene” and “light distillates” are often used with the same, overlapping, or different meanings in different references, they are uniformly used in temperature ranges (e.g., 190° C. to 250° C. or 180° C. to 230° C.) and is not defined based on sulfur content. Instead, expedient sulfur content measurements are made and reported based on cut boundary point temperature ranges determined by the specifications of each product from a conventional refinery. The inventors have found that this is less than optimal.

The inventors have discovered that the cost savings of low sulfur combustion production can be optimized by changing the basic method of operating a crude distillation column. The inventors have determined that the specific distillate withdrawal is the crude feedstock or feed mixture to the distillation column rather than the standard product temperature range specifications for traditional downstream uses such as kerosene, jet fuel, diesel, etc. It was found that the analysis of the sulfur content of the stream should be taken into account while omitting the analysis of the sulfur content of the secondary stream.

The inventors have discovered how to define a "breakpoint", where the change in sulfur content per unit volume change in the discharged product (the slope of the graph) is no longer substantially flat. Instead, at the breakpoint, as the take-off increases slightly, the sulfur content changes rapidly, such as the slope of the graph per unit volume begins to change dramatically, or begin to increase exponentially. Also, after the breakpoint, the type and composition of the sulfur-containing compounds typically change, as well as the complexity, depending on the type of crude oil feedstock. Breakpoints are indicators from the separation of streams or portions of streams requiring desulfurization that may minimize or eliminate desulfurization.

We directly extract and accumulate the maximum amount of material with a sulfur content below the breakpoint, avoiding or reducing the cost of downstream processing for sulfur reduction or removal. It has been found that the capital and manufacturing costs of low sulfur fuels can be minimized if the production of all liquids with the sulfur content of the following takeoffs is maximized.

The inventors have found that a relatively large amount of such material below the breakpoint, and in certain crudes the portion within a narrow specified zone above the breakpoint, has already been treated for sulfur removal. It has been found that when combined with the discharge, it does not require treatment for sulfur removal or significant subsequent treatment. We not only drive atmospheric distillation conditions primarily by increasing the feed or column temperature profile, but also reduce or eliminate reflux, or reduce the crude feed rate, or maximize removal to near a breakpoint. By altering the composition of crude hydrocarbons or sulfur by mixing or diluting the feed crude oil so as to maximize the production of such raw material and reduce the cost of overall stream desulfurization or other treatment operations. do. Breakpoints are not defined in terms of standard industry classifications or regulations that set temperature ranges for withdrawal.

In this specification and claims, we refer to "breakpoints" in relation to crude oil analysis or other methods of measurement, with mass % or volume of crude oil on the x-axis and sulfur on the y-axis. If the content is plotted, it is defined as the point at which the sulfur content begins to increase sharply or exponentially at or near the horizontal, in the sense of a large change in the slope of the graph per unit volume. The difference along the x-axis is the change in unit volume of the fraction, the difference along the y-axis is the change in sulfur content per unit volume, and the slope is the slope of the graph. The slope of the slope of such a graph moves from zero (zero) or near-horizontal values, abruptly above 0.2, and rapidly above 1 to a somewhat exponential increase in sulfur content. The breakpoint will change based on the crude oil or other feed to the distillation column. Thus, "breakpoint extraction" or "sulphur breakpoint extraction" refers to the above-mentioned per unit volume of but above the end of the naphtha range, e.g. It provides a means of determining the split into hydrocarbon-containing liquids boiling below the breakpoint, the point at which the change in slope of the graph is large and the sulfur content begins to increase sharply or exponentially.

In this specification and claims, the inventors use the term base "breakpoint withdrawal" or base "sulfur breakpoint withdrawal" with respect to the sulfur content of the fraction to destabilize pristine straight run naphtha is defined to mean a hydrocarbon-containing liquid boiling above the end point of the range of The actual sulfur content of the combined fuel does not exceed the target sulfur content if the breakpoint is selected to be formed from all streams above the selected breakpoint withdrawal. Alternatively, the fuel can be produced according to whether the target sulfur content is at, or above or below the sulfur breakpoint, and the combination of streams that produce the fuel is the actual sulfur content of the fuel. is efficiently made relative to the breakpoint so that the sulfur target is not exceeded.

For many crude oils, the sulfur breakpoint take-off for the atmospheric distillation column is such as to begin boiling at 180°C or 190°C (or other kerosene range starting points) (various methods in the art). ), and for simplicity may include lower or higher temperature range materials. However, the sulfur content, rather than the temperature or historical definition of the material in the kerosene range, is the determinant of the endpoint of the sulfur breakpoint range. The fuel may be formed according to where the target sulfur content is the sulfur breakpoint, and the combination of streams forming the fuel is made such that the actual sulfur content of the fuel does not exceed the sulfur target.

In one embodiment, a crude feedstock is separated into streams and a portion of one or more liquids of such separated streams is treated while the other portion is left untreated. The majority of the treated and untreated liquid streams are then recombined to form a liquid fuel having an actual sulfur content equal to or less than the target sulfur content. The process steps include (a) subjecting crude oil to one or more distillation and solvent separation steps to produce light overhead distillate gases, metal-rich residues insoluble in the one or more solvents used for solvent separation, sulfur-containing gases; and (b) a liquid fraction above the sulfur breakpoint and not a liquid fraction below the sulfur breakpoint or an insoluble residue. is treated by one or more hydrotreating steps to form one or more hydrotreated streams with reduced sulfur content while leaving other portions untreated, and ( c) combining with the liquid fraction below the hydroprocessing stream breakpoint to form the above liquid fuel having an actual sulfur content below the sulfur breakpoint as a target sulfur content.

In yet another embodiment, the present invention provides a method of reducing emissions exceeding IMO specifications by vessels on the open sea, within ECAs, or in ports by using fuels produced according to the present invention. The fuel has a sulfur content regulated below the maximum of the IMO specifications applicable at the point of use of the fuel by ships, whether at sea, within the ECA, or in port. In this way, the vessel can exceed IMO requirements and public expectations.

In other embodiments, the present invention provides a method for ships to sell electricity generated using fuels of the present invention in port to the onshore grid, for example, to offset marine or port fuel costs. offer.

The inventors have found that it is possible to produce a low-cost, ultra-clean marine fuel that greatly exceeds IMO expectations regarding sulfur and metal limits, while considering and adjusting the flash point in an appropriate manner.

Thus, we have found that (i) minor flashpoint modifications (ii) large-scale environmental benefits (huge SOx and NOx reductions and harmful found a technological way to replace it with the essential elimination of metals. Until now, no one has been able to make such a discovery.

The International Convention for Safety at Sea (SOLAS) outlines the flashpoints of fuels and their permissible use on cargo ships. “For many people, the minimum fuel flash point of 60°C in general service as set out in the SOLAS Convention may appear to be one of the cornerstones of the law of the sea, but it was first introduced in the 1981 amendment. The first three SOLAS conventions (1914, 1929 and 1948) did not set limits on the flashpoint of petroleum fuels, and even the 1960 convention does not allow fuels used by internal combustion engines to exceed 43°C. It only required "new" passenger ships to have a flash point. It should be noted that this provision was essentially carried over into the current 1974 Convention as it was originally adopted.”

Wright et al. argue that the flash point is an empirical rather than a real value, and that ``the flash point value is never a 'safe'/'unsafe' boundary line, nor has such a value been used in the past. It's never been a borderline," he said. As a result, since the beginning of the petroleum industry, flash point has been used, somewhat erroneously, as a means of identifying products that require greater control and attention in terms of storage and use. In practice, in marine applications, petroleum fuel fires are ignited not so much by vapor ignition, but by leaks or broken pipes causing the fuel to come into contact with surfaces above the self-ignition temperature. Nevertheless, from the outset as a safety parameter in the Petroleum Safety Act, taking into account the fact that the flashpoint is an empirical value, albeit sometimes to somewhat arbitrarily set limits, has been used.

SOLAS is making an exception for cargo ships. SOLAS stipulates that oil fuels with a flash point of less than 60°C shall not be used, with the exception that "cargo ships shall not use a flashpoint specified in [SOLAS] section 2.1 (e.g. 60°C ), such as crude oil, may be permitted provided that such fuels are not stored in any engine room and subject to approval by the authorities." It should also be noted that some countries do not have flashpoint standards and others allow relatively low flashpoints in marine applications.

The fuel flash point can be adjusted by processing if desired. As used herein and in the claims, the term "flashpoint treatment" means a composition that raises the flashpoint when combined with a material. In one variation, flashpoint treatment lowers the vapor pressure of added materials to reduce the risk of vapor ignition. In one variation, the flash point modifier is a solid or liquid additive that has a flash point of 60° C. or higher and is added to the low flash point fuel to raise the flash point of the fuel. These can include various types of particulates and oils. For example, high flash point additives have been disclosed for treating carbonaceous fuels. For example, Hughes et al., US Pat. No. 6,200,303, describes a "high flash point diluent" selected from the group consisting of paraffinic base oils having a flash point of 200° C. or higher and mixtures or combinations thereof, specifically uses Calpar 100 (210°C FP), Calpar 325 (240°C FP) and Calpar P950 (257°C FP) available from Calumet Lubricants, Indianapolis, Indiana and paraffinic base oils and mixtures or combinations thereof having a flash point of 200°C or greater. exemplified.

The inventors have found that (i) minor flashpoint modifications are associated with (ii) large-scale environmental benefits (huge SOx and NOx reductions and toxic metal found a technical way to replace it with the essential elimination of Until now, no one has been able to make such a discovery.

Schematic representation of sulfur content of various actual and hypothetical crude oils showing breakpoint ranges Schematic diagram showing a process arrangement for processing crude oil to produce a single liquid product useful as a fuel according to the present invention.

In one embodiment of the present invention, a process for converting at least a portion of a hydrocarbon feed that is crude oil having sulfur and metals into a single liquid product comprises (i) dividing the feed into one or more The distillation and solvent separation steps of . light overhead distillate gases (including only distillate gases that do not condense in the (ii) a sulfur-containing liquid fraction having vacuum gas oil range hydrocarbons, (ii) below the sulfur breakpoint; (and preferably not the portion of any fraction that is insoluble in the solvent used for solvent separation), but the selected withdrawal liquid fraction above the sulfur breakpoint (and preferably the soluble only the liquid fraction selected for hydrotreating) is hydrotreated by one or more hydrotreating steps to produce one or more hydrotreated streams with reduced sulfur content. and (iii) combining said untreated fraction with said treated stream to form a fuel having an actual sulfur content less than or equal to a target sulfur content. As used herein, the term "step" or "zone" refers to a unit operation having one or more processing operations having one or more divisions of equipment configurations and/or unit operations or subzones. You can point to a region. Equipment items can have one or more tanks, vessels, distillation columns, separators, reactors or reactor vessels, heaters, exchangers, strippers, pipes, pumps, compressors and controllers. In a preferred variation of the invention, substantially all of the hydrocarbon composition of the feed is separated into fractions and then recombined to form one liquid fuel product, fuel. The fuel is a single liquid fuel product containing hydrocarbons ranging from the original feed, liquefied petroleum gas, or in one variation, from naphtha to hydrotreated deasphalted oil. (i) in the distillate light overhead gas, (ii) in the residual insolubles, and (iii) in the sulfur or metals recovery stream, but which do not form a plurality of hydrocarbon products. Hydrocarbon compositions containing hydrocarbons are excluded. Such ranges are substantially the entire range of C3 or C5 to C20 or higher crude oil derived hydrocarbons, said hydrocarbons being the lowest boiling point of any fraction in the raw stream combined with said fuel. and has a maximum boiling point that is the maximum boiling point of the process stream combined with the fuel. As used herein and in the claims, the term "untreated" means not undergoing hydrotreating to reduce or remove sulfur, nitrogen or metals. In one variation, such fuels are substantially in the range of C3 or C5 to C20 or higher crude oil-derived hydrocarbons, or crude oil-derived hydrocarbons having an initial boiling point within the range of about 35° C. preferably up to the initial boiling point at the end of the deasphalted oil and the beginning of the deasphalted residue, which are selected for solvent separation. not soluble in solvents. In an even more preferred variant, the fuel of the present invention comprises hydrocarbons ranging from the lowest boiling fraction of the untreated liquid fraction from atmospheric distillation to the highest boiling fraction of the hydrotreated solubles from solvent separation. Including combinations. Thus, the preferred fuels of the present invention are in direct contrast to conventional gasoline, diesel, kerosene and fuel oils, which are extracted in selected subranges and do not have a significant content of the maximum range of such hydrocarbons. is. Accordingly, one embodiment of the present invention is a fuel obtained as a single product from processing crude oil, said fuel having an actual sulfur content of 0.5 wt.% or less, preferably 0.1 wt.% or less. with substantially the entire range of C3 or C5 to C20 or higher crude oil derived hydrocarbons. The hydrocarbon has an initial boiling point that is the lowest boiling point of any fraction of the crude oil under atmospheric distillation conditions and a highest boiling point that is the end point of the remaining portion of the crude oil that is insoluble in the solvent suitable for solvent separation. have In variations, such fuels include substantially the entire range of C3 or C5 to C20 or higher crude oil derived hydrocarbons, said hydrocarbons being any of the crude streams combined in said fuel. It has an initial boiling point, which is the lowest boiling point of the fraction, and an end point, which is the highest boiling point of the process streams combined in the fuel. In one variation, the crude oil is treated as a light overhead distillate gas, a metal-rich residue insoluble in one or more solvents used for solvent separation, a sulfur-containing gas (including a sulfur-containing purge gas), and a sulfur-containing separating into liquid fractions, said liquid fractions having (i) a liquid fraction below the sulfur breakpoint and (ii) a liquid fraction above the sulfur breakpoint, both of which are the solvent used in the solvent separation; and (b) hydrotreating the soluble liquid fraction above the sulfur breakpoint, not the liquid fraction below the sulfur breakpoint or the insoluble fraction, by one or more hydrotreating steps (c) combining said untreated fraction with said treated stream such that the actual sulfur content is equal to the target sulfur content; Forming a fuel that is:

In a variant, such residue for use in power production and at least a portion of the hydrogen for capturing at least a portion of the metals in the gasifier solids to be hydrotreated and removed, Combusted in one or more gasifiers or the residue captures flue gas sulfur and metals for use in auxiliary hydrogen generation unit operations to supply hydrogen for power generation and hydroprocessing. is combusted in one or more boilers. Preferably, all gases containing sulfur are sent to one or more common sulfur recovery units.

By practicing the present invention, the actual sulfur content of the fuel can be adjusted to meet target sulfur content limit specifications, e.g. By adjusting the amount, IMO specifications for marine fuels or sulfur limits for combustion gas turbines can be met. For example, the target sulfur content of the fuel may be adjusted to one or more target IMO specifications, such as 3.5 wt%, 0.5 wt%, 0.1 wt% or other IMO can be adjusted to meet specifications selected from Fuels produced according to the method of the present invention are useful in marine engines, combustion gas turbines, combustion heaters such as boilers, and other applications.

In one variation, at least one of the hydrotreated streams is an ultra-low sulfur stream having no more than 10 ppm sulfur by weight, and increasing or decreasing the amount of said stream relative to the combination actually is used to regulate the formation of fuels whose sulfur content is below the target sulfur content. In another variation, at least one of the hydrotreated streams is an ultra-low sulfur stream having 10 ppm by weight or less of sulfur, and the untreated fraction has a sulfur content exceeding a target sulfur content. and the untreated fraction is used as a trim control, reducing or increasing the amount of such untreated fraction relative to the above combination to form a fuel in which the actual sulfur content is equal to or less than the target sulfur content. In yet another variation, when converting a crude oil feed into substantially one liquid fuel product, rather than multiple hydrocarbon products, the first to produce a second hydrotreated fuel fraction having a reduced sulfur stream having a sulfur content in the range of 0.12 to 0.18 wt%, the untreated fraction comprising Having a sulfur content that is less than or equal to or above the breakpoint sulfur and above a target sulfur content, the first hydroprocessed stream or the second hydroprocessed stream or both are Such an increase or decrease in the amount of flow is used as a trim control to form a fuel in which the actual sulfur content is less than or equal to the target sulfur content.

In an even more preferred embodiment, the sulfur content of one or more of crude oils, residual oils and other feeds is selected or the processing conditions are adjusted to provide at least 70 volumes of each barrel of said crude feeds. % is converted to a liquid fraction and then treated or untreated but combined to form a fuel having a sulfur content that is less than or equal to the target sulfur content, rather than a plurality of hydrocarbon products, and Less than 30% of each barrel of crude oil supply is directed to non-fuel. In a preferred variation of the invention, at least each barrel of hydrocarbonaceous feed is Eighty percent by volume of the barrel feed, more preferably about 90% or more, is converted to one liquid fuel product, excluding streams with very low sulfur, rather than multiple hydrocarbon products. The very low sulfur stream is used as a trim to increase or decrease trim flow to control the sulfur content of the final fuel product to a level that does not exceed the target sulfur content. The trim stream excess can be transferred separately for material balance and inventory control purposes. In such preferred variations of the invention, no more than about 10-30% by volume of each barrel of the crude feed is trapped in the metal-rich residue after atmospheric and vacuum distillation by solvent extraction.

In another variation, a high sulfur fuel oil having a sulfur content higher than the target sulfur content, either alone or during combination of all the treated and untreated fractions to form the fuel Add with light tight oil. The high sulfur fuel oil may be fed to one or more of the distillation, solvent separation or hydrotreating steps described above. In one preferred embodiment, the ultra-low sulfur stream has sulfur in the range of 10 ppm by weight or less, the untreated fraction has a sulfur content exceeding the target sulfur content, the untreated fraction comprising: It is used to adjust the amount of untreated fraction to the combination by increasing or decreasing to form a product fuel in which the actual sulfur content is equal to or less than the target sulfur content.

Equipment for the practice of the process of the invention can reduce its footprint in the range of 20% to 30% of the equipment footprint of conventional refineries with typical downstream processing units. Thus, the capital cost per barrel of feed processed is substantially reduced. For example, in one particular embodiment of the invention, one or more of atmospheric distillation, vacuum distillation, solvent separation, hydrotreating and gasification, along with the necessary auxiliary equipment to capture sulfur and metals. There is no hydrocarbon processing operation downstream of the hydrotreating, except for gasification with the auxiliary equipment required to capture sulfur and metals.

A variation of the process configuration of the present invention is the construction of islands of equipment (utility islands) that supply hydrogen, steam and fuel gas plus the processes required for electrical power while providing integrated metal and sulfur capture means. Effective integration provides high efficiency, low cost operation. A utility island processes heavy metal-rich residue to capture and eliminate metal contaminants as a potential source of air emission constituents, preferably integrated, thus lower capital cost, sulfur capture, treatment , and with one or more gasification systems using sour gas and acid gas off-gas treatment from all sources as potential sources for removal. The island configuration of the present invention utilizes hydrogen for the hydrotreating step as well as the electrical process via a highly efficient combined cycle power means that utilizes specific streams for the electrical process and normally waste streams to meet process requirements. to produce steam and fuel gas for

A variation of this embodiment of the invention is that the light tight oil has sufficient heavier hydrocarbons in the bottoms distillate and residue to provide a process balance for hydrocarbon processing and corresponding hydrogen production. It deals with the case where it does not contain , allowing such light crudes to be hydrotreated to reduce and decontaminate sulfur and metals. This process adds the light crude oil, either separately or mixed with other feeds, to any or all of the heavier feeds that are led to atmospheric distillation, vacuum distillation or solvent separation processes. have the step of

In one variation, the design of the equipment for vacuum distillation, solvent separation, hydrotreating and gasification operations downstream of atmospheric distillation may be from high sulfur fuel oil or another source outside the battery limits of said operations. sized to have additional or spare capacity to treat the additional heavy residues of the fuel, forming a fuel with an actual sulfur content below the target fuel sulfur content limit level, and removing the additional heavy residues from traps at least a portion of the sulfur and metals in the

In another embodiment, the present invention uses the fuel of the present invention to generate electricity while ships are in port to reduce local emissions, as well as sell to the onshore electrical grid. provide a way to In one variant, the invention provides a technical method of reducing emissions at and near ports, which method (a) generates the electricity normally supplied to the grid at or near the port; ascertain sulfur or metal emissions per kilowatt hour (KWH) generated by onshore power generation facilities (including, for example, emissions associated with the use of local power supplies when ships are connected to such grids at ports); and (b) a technical analysis to ascertain the emissions of sulfur or metals per KWH caused by the electricity generated on board the same vessel when in port at the point in (a), Comparing a) with (b), if (b) the emissions generated by the ship for power generation are lower than the local source of power generation in (a), reduce emissions on board and reduce emissions on board. Provide all or part of the power generation to the distribution grid. This embodiment may be useful when the locally supplied power is from certain types of coal-fired sources, or when lower emission options are not available for onsite power generation and heavy crude or residual oil is burned. can be particularly useful in reducing environmental emissions when used to generate electricity. In the absence of offset, such delivery by ships to the local grid may not be permitted if the KWH cost of ship-generated electricity exceeds the KWH cost of local grid electricity, or such delivery by ships to the local grid. provision does not benefit the ship in any other way, such as by offsetting emission reduction credits such as subsidies paid for low-emission power generation, unless there is offsetting of port charges. will not be.

If the ship's contribution to the local grid is beneficial, the ship will provide all or part of the electricity generated on board while in port using the fuel of the present invention to the onshore grid. The revenues generated by this can offset or reduce fuel costs incurred at sea The above revenues generated from serving the grid while berthed at the port will contribute to the cost of seagoing fuel, depending on the duration of the berth at the port, while the actual seagoing fuel costs from these new fuels will be higher for seagoing. It can be offset to a level that is lower than the cost of sulfur fuel oil.

FIG. 1 is a schematic plot of the sulfur content of various actual and hypothetical crude oils showing breakpoint ranges. Exemplary crude oil sulfur profiles 4, 5, 6 are plotted based on actual data center points extracted from Non-Patent Document 6. Hypothetical Crude Oil Sulfur Profiles 1, 2, 3 are derived in part from actual data taken from various sources, including Non-Patent Document 7.

FIG. 1 shows a method suggesting the definition of "breakpoints" for different crude oils for the process configuration of the present invention. FIG. 1 illustrates a breakpoint, which is the point at which the change in sulfur content per change in unit volume of product removed (the slope of the graph) is no longer substantially horizontal or flat. , at the breakpoint instead, the sulfur content begins to increase rapidly or exponentially as the withdrawal increases slightly, resulting in a large change in the slope of the graph per unit volume. Also, after the breakpoint, sulfur-containing compounds, type and composition, and complexity change depending on the type of crude oil feedstock. Breakpoints allow us to determine how costly and intensive hydroprocessing is best bypassed for operational efficiency, while still producing a fuel that meets target sulfur content limit specifications. make it possible to That is, the breakpoint is the maximum sulfur content of an atmospheric crude column fraction that is directed away from or reduced further downstream processing to reduce the sulfur content, e.g., away from hydroprocessing. can be done. The fraction above the breakpoint is directed to downstream processing for sulfur content reduction, while the fraction below the breakpoint is not processed, leading to substantial operating savings. In conventional refining, take-off is fixed by temperature range rather than by sulfur content. Target sulfur content can dictate breakpoint selection as an example of end-use requirements. If the breakpoint is set too high, the excess higher sulfur raw stream cannot be easily compensated for by the lower sulfur hydrotreated stream.

Figure 2 outlines another embodiment of the invention and shows in simplified form the main components of a process configuration for the production of a single liquid product suitable for use as a fuel. . FIG. 2 illustrates the integration of atmospheric and vacuum distillation, solvent separation, hydrotreating and gasification to produce a single low sulfur, essentially metal free fuel product.

A polluted crude oil stream containing sulfur, nitrogen and metals enters the process via line 2 after pretreatment such as desalting which is preferred for crude oil. In this example, the crude oil feedstock 2 can be a single crude oil, a blend of one or more crude oils, or a blend of crude oil and residual oil such as high sulfur fuel oil. Feedstock 2 is directed to atmospheric distillation column 100 where the feedstock is separated into light overhead gases 4 and multiple withdrawals. Light overhead gases 4 include non-condensed distillate gases 6 useful as process fuels or captured for other uses. In one preferred variant, the capital expenditure associated with a stabilization system for such overhead gas 4 is avoided. However, depending on local needs, stabilization systems can be included, for example special marine fuel max H2S specifications. In the embodiment shown in FIG. 2, the multiple takeouts include one or more flows within the following ranges: (1) unstabilized pristine straight run of line 16 through line 4; naphtha, (2) sulfur breakpoint withdrawal in line 18, (3) light distillate in line 24, (4) middle distillate in line 26, (5) first heavy distillate in line 28, and (6) atmospheric residue in line 30;

Various applications in the art assign different meanings to the same or similar retrievals in different parts of the world, and the meanings may be different, overlapping, contradictory, or confusing. I often invite them. As used in the specification and claims, it has the following meanings. That is, (a) "naphtha" ranges from having at least three carbons C3, such as propane, to having an initial boiling point (IBP) of about 175°C (about 350°F), and methane means a carbon-containing composition, excluding low-boiling compounds such as: (b) "stabilized naphtha", as far as naphthas or other naphtha range materials used as fuel blend stocks are concerned, means that low boiling compounds below butane or propane have been almost completely removed from the naphtha or fuel; For example, in a conventional refinery, the bottom stream from the naphtha debutanizer distillation column is stabilized naphtha. (c) "Destabilized naphtha" means naphtha from which the C4 and lighter components have not been removed, e.g., in a conventional refinery the feed stream to the naphtha debutanizer is destabilized naphtha . (d) "Unstabilized pristine straight-run naphtha" has an initial boiling point (IBP) of about 175°C (about 350°F) from having at least 3 carbons C3, such as propane and may include atmospheric distillation overhead distillation gas, excluding low boiling point compounds such as methane and below, and refers to carbon-containing compositions recovered from atmospheric distillation. (e) "Natural naphtha" means the unstabilized light fraction of hydrotreater effluent recovered from a distillation column or other separator in a hydrotreating process and is operationally Consider recovering one or more heavy fractions at or near the bottom of the separator, such as the distillate range, the heavy oil range, or other materials heavier than the naphtha portion of the feed to the separator. It is part of the hydrotreating zone and is not stabilized. (f) "Breakpoint Take" has been previously defined herein, an example of which is shown in FIG. (g) "light distillate above breakpoint take-off" or "light distillate" herein means a cut with an initial sulfur content higher than the maximum sulfur content of the breakpoint take-off; Yes, with a correspondingly higher boiling point (IBP) than the highest endpoint of the breakpoint take. (h) "middle distillate" means the fraction between light and heavy distillate separated as a takeoff based on a preferred distillation column design, e.g. can be eliminated and combined with either light distillate or heavy distillate species. (i) "First Heaviest Distillate" means the heaviest fraction of an atmospheric distillation unit, the sulfur content and boiling range of which is determined by the sulfur composition of the distillation unit feed, the severity of the crude column operation; determined by one or more operating conditions such as thickness and downstream hydrotreating conditions. (j) "First Heaviest Distillate" means the heaviest fraction of an atmospheric distillation unit, related to the sulfur composition of the distillation unit feed and the sulfur breakpoint removal, and the severity of the crude column operation; , the sulfur content and boiling range determined with reference to one or more operating factors such as the severity of the downstream distillate hydrotreating conditions. (k) "Second Heavier Distillate" means the lightest fraction of a vacuum distillation column and is related to the sulfur composition of the distillation unit feed and the sulfur breakpoint removal, the severity of the crude column operation, downstream It has a sulfur content and boiling range determined with reference to one or more operating factors such as the severity of the distillate hydrotreating conditions. (j) "vacuum gas oil," including "atmospheric retentate," "vacuum retentate," "light vacuum gas oil," and "heavy vacuum gas oil," "solvent separation," "hydrotreating," and other terms; and variations of these terms are known to those skilled in the art of processing crude oil.

Preferably, the combined streams of (1) unstabilized pristine straight run naphtha in line 16 via line 4 and (2) sulfur breakpoint take off in line 18 are 0.06 wt% If the fuel combination in line 600 has a sulfur content in the range of less than 0.08 wt. , where the flow rates of steam 10 and 70 are adjusted together so that fuel combination 600 does not exceed the target sulfur content.

In FIG. 2, the atmospheric residue is fed to vacuum distillation column 200 via line 30 to provide (1) second heavy distillate in line 32, (2) light vacuum gas oil in line 36, and (3) Heavy vacuum gas oil in line 38 and (4) vacuum retentate in line 50 are produced. The vacuum residue is directed via line 50 to solvent separation 300 to produce (1) deasphalted oil in line 80 and metal-rich heavy residue pitch in line 90 .

FIG. 2 shows an integrated hydroprocessing system 400 that includes two hydroprocessing zones, a distillate hydroprocessing zone 430 and a heavy oil hydroprocessing zone 460 . Integrated hydroprocessing systems are known in the art and preferred for this application. However, mild hydrotreating conditions at relatively low pressures in the range of about 117-138 bar (1700-2000 psi) are sufficient for hydrodesulfurization and hydrodemetalization in both zone 430 and zone 460. .

The light distillate 24, the middle distillate 26, the first heavy distillate 28 and the second heavy distillate 32 are preferably fed to an integrated hydroprocessing system 400 and, in the presence of a catalyst, Hydrotreated under hydrotreating conditions to form the distillate hydrotreating zone 430 effluent stream in line 60 . Such hydrotreater effluents 60 are those materials within the following ranges: and (2) a light distillate 24, a middle distillate 26, a first heavy distillate 28 and a second It includes ultra-low sulfur diesel, which is a reduced sulfur stream formed from a combination of treated distillate vapors with a double distillate 32 . At least a portion of the hydroprocessing by-products in zone 430 are treated for sulfur removal and recycled as hydrogen added to distillate hydroprocessing zone 430 or heavy oil hydroprocessing zone 460, or both. It is known to those skilled in the hydroprocessing art that the gas may contain sulfur-containing gases such as hydrogen sulfide, hydrogen-rich off-gases, and typically small amounts of liquefied petroleum gas.

Light vacuum gas oil 36, heavy vacuum gas oil 38 and deasphalted oil 80 are also preferably fed to integrated hydrotreating system 400 and hydrotreated under hydrotreating conditions in the presence of a catalyst to produce heavy A low pressure gas oil hydrotreating zone 460 effluent stream 70 is formed. Such hydrotreating unit effluents are described below as follows: (1) pristine, with an expected boiling range of above C5 (a five-carbon composition) to about 175°C (about 350°C); naphtha and (2) preferably having a sulfur content of less than 10 ppm by weight and formed from a first portion of a combination of treated distillation vapors having light vacuum gas oil 36, heavy vacuum gas oil 38 and deasphalted oil 80. (3) a light vacuum gas oil, preferably having a sulfur content in the range of 0.12 to 0.18 wt. , a second reduced sulfur stream formed from a second portion of the combination of treated distillation vapors having heavy vacuum gas oil 38 and deasphalted oil 80 . At least a portion of the hydroprocessing byproducts in zone 460 are treated for sulfur removal and reused as hydrogen for addition to distillate hydroprocessing zone 430 or heavy oil hydroprocessing zone 460, or both. It is known to those skilled in the hydroprocessing art that hydrogen sulfide, gases containing sulfur gas such as hydrogen-rich off-gases, and typically small amounts of liquefied petroleum gas may be included.

Raw stream 10 and one or more hydrotreated liquid streams are combined via lines 60 and 70 to form a low sulfur, substantially metal-free fuel product in line 600 . Here, "combined" means formed by in-line flow mixing, blending, or other intimate combination. In one variation, unstabilized pristine straight run naphtha via lines 4 and 16 and sulfur breakpoint removal via line 18 are combined without additional treatment in 100, followed by pristine of naphtha and ultra-low sulfur diesel from distillate hydroprocessing zone 430, and pristine naphtha, ultra-low sulfur diesel and heavy oil hydroprocessing zone 460. A fuel combination is formed at 600 by combining one or more effluents from heavy oil hydroprocessing zone 460 with a second reduced sulfur stream. In another variation, hydrotreating zone 400 combines the effluents of zones 430 and 460 into a single effluent as if lines 60 and 70 were combined within such zone (not shown). Forming streams and such variations are useful when it is undesirable to separate the effluents of hydrotreaters 430 and 460 . Preferably, the vacuum gas oil hydroprocessing portion 460 has an overhead system flow and a bottoms system flow, a portion of which is diesel boiling range material. This may be a relatively small amount compared to the combined diesel provided to combination 600 by zones 430 or 460, and combined diesel side hydrotreating portion 430 may also be directed to block 600 or trim or otherwise. and pristine naphtha side streams, either alone or as part of the overhead and bottoms system flows containing low sulfur diesel used for the purpose of

Deasphaltizer 300 bottom heavy residue 90 containing asphalt and metal-rich heavy residue is one or more for partial oxidation of the heavy residue 90 in the presence of steam and oxygen, and an optional carbon-containing slurry quench. and synthesis gas, at least a portion of which is supplied via line 502 to distillate hydrotreater 430 and heavy oil hydrotreater 460. The gas turbine of the combined cycle power unit in gasification system 500 for power generation in 504 for process applications and other applications. Combusting syngas to form syngas, further comprising a hot turbine gas and a heat recovery generator for recovering heat from the hot gas turbine gas to produce steam and for additional power generation. 504 to drive a steam turbine to generate electricity. Each gasifier also produces metal-rich soot. The soot may be in the form of particulate solids, containing metal contaminants from crude oil and/or heavy feedstocks, which are fed from each gasifier via line 506 to metal removal. The support system includes one or more gas processing units, and all sulfur-containing gas streams from all unit operations, whether sour gas or acid gas, are processed for sulfur removal via 508. supplied to the gas treatment unit. Preferably such a sulfur removal system is part of a utility island of which the gasification system is part. More preferably, the one or more sulfur-containing gas streams are directed to commercial sulfur acid production as part of overall sulfur removal. Gasification system 500 typically includes an acid gas removal unit and sour CO Including shift system.

In a variation of the integrated hydroprocessing system 400 shown in FIG. 2, the make-up hydrogen-bearing gas 502 from the gasification system 500 is used in the amount required for hydroprocessing and the internal recycle hydrogen within the hydroprocessing block 400. together with effective hydrotreating operating temperatures, pressures, and spaces adjusted based on the catalyst selected and other conditions known in the art to achieve the desired levels of desulphurization and demetallation. Compressed and heated to velocity and pressure. The hydrogen 502 thus prepared (along with the recycled hydrogen) is first placed in a high pressure zone, the heavy oil hydrotreating zone 460 . The effluent of heavy oil hydrotreating zone 460 having hydrotreated liquid and hydrogen-containing gas is separated in a high pressure separator (not shown), whereupon the liquids are collected in zone 460 to produce hydrogen. The contained liquid is recovered and passed through line 410 to distillate hydrotreating unit 430 for use in hydrotreating in the lower pressure zone. The hydrotreated liquid with sour and acid gases and purge gas from hydrotreating zone 430 pass through line 412 into heavy oil hydrotreating zone 460 where they are substantially mixed. The hydrotreated effluents 430 and 460 of both zones 430 and 460 are separated via lines 60 and 70 and separately fed to a combined fuel 600 depending on the sulfur and other material balance needs of the process. It can be input, added as a trim to control the sulfur level in combination zone 600, or removed (not shown). In the integrated hydroprocessing variant shown, the purge gas 420 of both zones 430 and 460 is directed via line 420 to a utility island 500 having a sulfur recovery system and optionally a gasification or boiler. Not shown in FIG. 2 are various auxiliary high, medium and low pressure gas-liquid separators, flow heaters, gas recycle and purge lines, reflux drums for separating gas or lights and liquids, Compressors, refrigeration systems, and other ancillary applications are known to those skilled in the hydroprocessing arts. Also within the hydroprocessing zone 400 are various amine or other sulfur scavenger sorbents and sorbents for sour gas or acid gas processing when located within the hydroprocessing zone rather than within a common utility island. A stripping system may be included.

The parameters for the selection of hydrotreating catalysts and adjustment of process conditions for hydrotreating zone 400 are within the skill of those in the petroleum refining industry and are additional to the practice of the hydrotreating section of the present invention. need no explanation. In the reaction zones of the distillate hydrotreater 430 and the heavy oil hydrotreater 460, the hydrotreating catalysts used increase the hydrogen content and/or release sulfur, nitrogen, oxygen, phosphorus and metal hetero It includes any catalyst composition useful for catalyzing the hydrogenation of a hydrocarbon feed to remove atomic contaminants. The specific catalyst types and various bed configurations used and the hydrotreating conditions selected will depend on the hydrocarbon product composition of each feedstock processed by each unit, as well as the sulfur and metals content and heavy carbon content. It depends on the residue and desired reduced sulfur and metals content in the product stream from each zone. Such catalysts can be selected from any catalyst useful for hydrotreating hydrocarbon feedstocks, although operating conditions are such that ring saturation or hydroconversion is avoided or minimized in the practice of preferred embodiments of the invention. adjusted to fit. US Pat. No. 6,200,000 to Baldassari et al., which is incorporated herein by reference, describes suitable hydrotreating processes including various integrated hydrotreating units, as well as various suitable hydrotreating catalysts. Baldassari et al. further summarize various catalyst compositions and condition ranges for distillation and heavy oil hydroprocessing, and identify conditions for hydrocracking and residue hydroconversion. All of these are known to those skilled in the art of hydroprocessing. Non-Patent Document 8 describes unit design, catalyst selection, hydrogen consumption and other operating conditions for hydrogenation to remove sulfur and produce products with less than 8 ppm sulfur by using highly active Ni/Mo catalysts. is described. Shiflet et al., 2003, also report hydrogen reduction to below 10 ppm using a highly active CoMo catalyst to remove sterically unhindered sulfur and a highly active NiMo catalyst to remove residual sterically hindered sulfur. processing is described.

In another variant, shown in FIG. 2, the sulfur content of feedstock 2 is determined by an analysis showing exponential breakpoints and rate of rise of the sulfur profile. For example, breakpoints for sulfur content in the range of 0.06-0.08 wt% (or higher given the relative flow rates of the raw and hydrotreated steams and their respective sulfur contents) and their Such a profile is used to control the tuning of atmospheric distillation 100 to maximize the amount of unstabilized pristine straight run naphtha 16 and sulfur breakpoint take-off 18 available, wherein , straight-run naphtha 16 and sulfur breakpoint take-off 18 flow combined by fluid mixing or blending and are available without treatment in the product accumulation zone 600 and, if required, (1) distillate hydrotreating (2) the amount of light distillate 24, middle distillate 26, first heavy distillate 28 or second heavy distillate 32 flow to zone 430; A stream of light vacuum gas oil 36, heavy vacuum gas oil 38 or deasphalted oil 80 is measured or reduced in quantity and these streams form a fuel product 600 having an actual sulfur content less than or equal to the target sulfur content limit. Therefore, it is directed to hydrotreating in increased or decreased amounts. In yet another variation, the analysis controls the maximum amount of streams other than the untreated unstabilized virgin naphtha 16 and the untreated sulfur breakpoint take-off 18 to hydrotreat. The amount of onward flow can be determined and used to form a fuel 600 in which the actual sulfur content is less than or equal to the target sulfur content limit. That is, any (1) amount of light distillate 24, middle distillate 26, first heavy distillate 28 or second heavy distillate 32 flow to distillate hydrotreating zone 430 or (2) the amount of flow of light vacuum gas oil 36, heavy vacuum gas oil 38 or deasphalted oil 80 to heavy oil hydrotreater 460. The sulfur content of hydroprocessing zone 400 effluent 60 or 70 or both mixed with process stream 10 may be increased or decreased to adjust.

In one variation, a fuel product 600 with an actual sulfur content less than or equal to the target sulfur content limit is formed by adjusting the sulfur level of the actual final product 600 . Conditioning includes (a) unstabilized pristine straight run naphtha 16 or sulfur breakpoint take-off 18, which may contain sulfur because it has not been treated for sulfur removal; or (b) streams entering or exiting the distillate hydrotreater 430 such as treated light distillate 24, middle distillate 26, first heavy distillate 28, second heavy distillate 32; or (c) the streams entering and exiting the heavy oil hydroprocessing unit, such as processed light vacuum gas oil 36, heavy vacuum gas oil 38, deasphalted oil 80. done. Here, such adjustments are based on measuring the relative contribution of each stream 60 or 70 to the combination 600 to the sulfur content.

In one embodiment, a light tight oil such as a light tight oil or condensate with a low metal content and a sulfur content below the target sulfur content limit level for Fuel 600 or agglomerate for unassociated gas and shale gas production such as: (a) atmospheric distillation 100 or vacuum distillation 200, feed to solvent separation 300, light distillate 24 to distillate hydrotreater 430, middle distillate 26, The feedstock of either the first heavy distillate 28 or the second heavy distillate 32 or the light vacuum gas oil 36, the heavy vacuum gas oil 38 or the deasphalted oil 80 to the heavy oil hydrotreater 460 Any feedstock, (b) stream 10 formed from unstabilized pristine straight run naphtha 16 and sulfur breakpoint take-off 18 without additional treatment, (c) pristine of naphtha and ultra-low sulfur diesel; (e) the combined effluent 70 of the combined hydroprocessing unit 400 directed to the final product fuel 600; or (f) such fuel added to form the final product fuel. another fuel that is added inside or outside the enclosure of the producing facility.

In one variation shown in FIG. 2, the sulfur content of fuel product 600 is (a) combined 600 via line 10 with unstabilized pristine straight run naphtha 16 and sulfur breakpoint take-off 18 . without any additional treatment to such stream, and then (b) actual product sulfur level 600 to (1) light distillate to distillate hydrotreating zone 430 24, flow of middle distillate 26, first heavy distillate 28 or second heavy distillate 32; (2) light vacuum gas oil 36, heavy vacuum gas oil 38 or (c) then for whatever reason increase the sulfur content of the actual product 600 to the target sulfur level; formed from light distillate 24, middle distillate 26, first heavy distillate 28 or second heavy distillate 32 via line 60 to a combination, if desired; , a stream from distillate hydrotreating zone 430; or (d) if for some reason the sulfur content of the actual product 600 needs to be reduced to the target sulfur level, (1) line 60 to the combination (2) the stream from the heavy oil hydrotreating zone 460 via line 70; controlled below the volume limit level. Such facilitation will enable, for example, fueling targeted less than 500 ppm by weight sulfur fuels for offshore and onshore gas turbines and for the same applications in different locations requiring different target sulfur contents. Multiple sulfur grades can be efficiently produced, such as varying ranges.

In a variation of using a high sulfur fuel oil having a sulfur content higher than the target sulfur limit level of the final fuel in combination 600, the high sulfur fuel oil may be used as part of one or more of the various feedstocks. , to one or more of the respective unit operations. The high sulfur fuel oil may be (a) feed line 2 to atmospheric distillation 100 or line 30 to vacuum distillation 200, or (b) line 50 to solvent separation 300, or (c) separately or in combination with one or more of the light distillate 24, middle distillate 26, first heavy distillate 26 or second heavy distillate 32 feed to the distillate hydrotreater 430, to line 20 to distillate hydrotreating unit 430; or (d) heavy oil hydrotreating separately or in combination with one or more of light vacuum gas oil 36, heavy vacuum gas oil 38 and deasphalted oil 80; It can be added in line 40 to processor 460 to form a fuel combination 600 with an actual sulfur content less than or equal to the target sulfur content limit. In implementing one or more of these variations regarding the use of the high sulfur fuel oil as a feedstock and the selection of its feed point, the nature of the high sulfur fuel oil feed, such as its sulfur content, asphaltenes content, etc. Other factors related to compatibility with processed crude oil or other feedstocks, vessel space and energy consumption, asphaltenes content, content of undissolved components, gum formation, and other efficiency issues may be considered. , are known to those skilled in the purification art.

In another variation, the combined 600 zone clean fuel has a sulfur content higher than the target sulfur content limit level such that the actual sulfur content of the fuel 600 is less than or equal to the target sulfur content limit. (a) unstabilized pristine straight-run naphtha 16 and sulfur breakpoint take-off 18 without additional processing depending on the sulfur content of the high sulfur fuel oil; or (b) stream 60 formed by distillate hydrotreater 430 comprising pristine naphtha and ultra-low sulfur diesel range materials, or (c) pristine naphtha, formed by adding to one or more of the stream 70 formed from the heavy oil hydrotreating unit 460 or the combined effluent 70 from the hydrotreating zone 400 containing ultra-low sulfur diesel and a second reduced sulfur stream. .

In one preferred variation of using a high sulfur fuel oil to make the fuel composition 600, the sulfur content of such high sulfur fuel oil is measured and then the high sulfur fuel oil is added to the solvent as part of the feedstock 50. The light distillate 24 , middle distillate 26 , first heavy distillate 26 or second Combined with one or more distillate streams of dual heavy distillate 32 and fed to distillate hydrotreater 430 or light vacuum gas oil 36, heavy vacuum gas oil 38 and deasphalted oil one or more of the 80 heavy oil streams, or combined with both the distillate stream and the heavy oil stream, depending on the sulfur content of the high sulfur fuel oil, distillate hydrotreater 430 or heavy oil hydrotreater 460; or forming part of the feed to both, optimizing the adjustment of hydroprocessing conditions in zone 430 or 460, or adjusting both zones to produce a fuel whose actual sulfur content is below the target sulfur content limit. to form

In other embodiments of the present invention, clean fuels whose specifications are below the sulfur content limit are typically atmospheric residuals or heavier and are off-spec or standard specifications for high-sulfur fuel oils. It can be formed by the use of heavy residual oils, including high sulfur fuel oils, which may have a certain density or sulfur or metal content. Due to market considerations, such heavy residual oils are often available from sources other than within the battery limits of the fuel plant. Heavy residues having a sulfur content higher than the target sulfur content limit level of fuel 600 are: (a) vacuum distillation column 200, either separately or in combination with atmospheric residue via line 30; atmospheric distillation column 200 to produce at least a portion of any or all of second heavy distillate 32, light vacuum gas oil 36, heavy vacuum gas oil or vacuum residue 50, or (b) Solvent Separation 300, either separately or in combination with the vacuum residue feed to Solvent Separation 300 via line 50, at least a portion of deasphalted oil 80, or gasification, sulfur recovery and , solvent separation 300 forming a pitch 90 with metal-rich heavy residues that passes to gasification system 500 for other ancillary processing. Such heavy residuals may also be combined with pitch via line 90 as a feed to utility island 500 . Alternatively, the fuel 600 of the present invention may not be treated for a trim to adjust the sulfur content, and the untreated fuel 600 may have a relatively high sulfur content (greater than 0.5 weight percent) or a high metal content. When using high sulfur fuel oil, such use would be a relatively small amount of adjustment when used without treatment to ensure that the combination 600 does not exceed the target sulfur content limit.

The flowsheet of FIG. 2, showing various intermediate individual products, is for illustration and understanding of the major and by-products in the effluent of each unit operation depicted. The selected variation of separation or treatment by each unit operation depends on the optimization of the crude oil and feedstock selected and the intermediate products produced to produce fuel below the target sulfur specification. For example, if the ultra-low diesel produced in zone 430 is not filtered and all hydrotreated material is combined in line 70 as shown in FIG. (not shown) allows both effluents 60 and 70 from hydrotreating units 430 and 460 to be combined in hydrotreating zone 400 and only gases are removed. Alternatively, if the process objective is to separate or eliminate a portion of the pristine naphtha or ultra-low sulfur diesel for trim control of the sulfur content of the fuel in the final combination zone 600 or for other reasons, the hydrogenation Effluents 60 and 70 from treatment units 430 and 460 may be sent separately or in combination to strippers or distillation columns so that crude naphtha or ultra-low sulfur diesel fractions can be removed. good.

While various embodiments of the invention have been described, it is to be understood that they are illustrative only and not limiting. For example, untreated light tight oil or condensate with low metals content and sulfur content below the target sulfur content, or untreated light tight oil or condensate, if the flash point of the fuel is not considered A combination is added as part of the combination of the untreated fraction and the treated stream to form a fuel having an actual sulfur content less than or equal to the target sulfur content. The term “light tight oil” or “LTO” as used herein means (i) a sulfur content in the range of 0.1% to 0.2% by weight and (ii) API (degrees) means source condensate or shale gas condensate with a density in the range of 38-57 degrees and (iii) a broad hydrocarbon range based on the source. LTO is typically, as a weight percent of the total, (a) 5-20 weight percent liquefied petroleum gas range, (b) 10-35 weight percent naphtha, (c) 15-30 weight percent kerosene, Expected distillate take-off fraction ranges overlapping each other: (d) 15-25 wt% diesel, (e) vacuum gas oil, and (f) zero (0%) to 10 wt% heavy residues. have

In one variation, the present invention provides: (i) raw light tight oil or crude oil of condensate quality, for example when the available oil has a production area outside the battery limits of the combustion manufacturing plant of the present invention; or a combination of light tight oil or condensate and (ii) one or more other crude oil feedstocks are co-processed according to the process of the present invention to produce low metal content and less than target sulfur content sulfur Making low cost fuel with content. Such light tight crudes likely do not contain enough heavy hydrocarbons in the bottoms distillate (e.g. 0% or very low heavy residues) and the range of residues may be due to desulfurization or other It does not provide a process balance for hydrotreating and the corresponding residue is either hydrogenating such light tight crudes in a cost-effective manner to reduce sulfur and metals and decontaminate, or It provides sufficient lubricity and not enough to support the process of hydrogen production to support use in certain types of engines.

The novel fuel embodiments of the present invention are better understood with reference to the ISO 8217 standard published by the International Organization for Standardization (ISO). ISO 8217 provides a set of marine residual fuel categories and detailed specifications for consumption on board ships. These specifications, as a basis for their development, recognize varying crude oil supplies, refinery processes, and other conditions. Such specifications imply that various international requirements for properties such as sulfur content are taken into account. The strictest ISO 8217 at present is RMA10, and interpretation of the specification and claims should be based on this. A simulated composition of the novel fuel of the present invention (crude oil is split into fractions, a portion of the fraction is hydrotreated, non-solvent residues are removed during solvent separation, and then the untreated and treated fractions are based on the simulation model to reconstruct), these new fuels meet and/or exceed all ISO RMA10 specifications except for flashpoint, which meets the flashpoint requirements for cargo ships. The inventors claim that the fuels fall under the SOLAS exception of the above-mentioned fuels and have new features and improvements that distinguish these new fuels from the residual marine fuels described above.

In one variation, we have met or exceeded all ISO RMA10 (ISO2817-10) specifications, except for flash point, and have the following notable characteristics: (a) 0.50% m/m (wt%) or less, preferably in the range of 0.05 to 0.20 m/m (wt%), (b) 5.0 mg/Kg (wt ppm) or less, preferably 1.0 mg /Kg (1.0 ppm by weight) or less, such as 0.2 mg/Kg (0.2 ppm by weight) of metal; to provide an improved fuel having any or all of In a variant, these novel fuels also have the following notable characteristics: (a) viscosity no greater than 10 cSt; (b) pour point no greater than 0 (zero) °C; ³ , (d) CCAI of 800 or less, (e) sodium of 20 mg/Kg or less, preferably 10 mg/Kg or less. All of the above are measured by tests or calculation methods specified by ISO2817-10. Such fuels comprise a range of hydrocarbons with the initial boiling point of naphtha and the highest boiling point of the component with the highest boiling point among the components soluble in solvents suitable for solvent separation, such as heptane. Metals can be reduced to 100 weight ppb depending on feedstock composition and operating conditions adjustment.

The inventors have discovered that very low sulfur and metal content fuels that meet the SOLAS exception to flashpoint requirements for cargo ships can be produced at low cost. If flash point treatment is required for other applications, having a flash point of 60° C. or higher, or for such requirements, flash point treatments are known in the art.

The use of the low viscosity, low pour point fuels of the present invention in marine engines avoids or reduces the energy consumption required associated with normal residual oil heating and can be used at filling stations in port or at sea. Allows for pumping and handling. Heavy residue oils are dense and because of their relatively high pour point and high viscosity, all of their storage, pumping, and supply to marine engines must be heated and kept at high temperatures. Heating consumes energy.

Table 1 below shows two variants of the fuel of the present invention, one with a very low sulfur content of 0.1 wt. Sulfur compared to is shown in Table 1 below.

Such fuels of the present invention having the properties shown in Table 1 are further distinguished in having substantially the entire range of hydrocarbons derived from crude oil from C3 or C5 to C20 or higher, said hydrocarbons having an initial boiling point of is the lowest boiling point of any fraction of the crude oil under atmospheric distillation conditions, and the highest boiling point is the endpoint of the remaining portion of the crude oil that is not soluble in the solvent suitable for solvent separation. . Residues, on the other hand, are limited to very heavy materials only, vacuum distillation residua, solvent deasphalted residuum, other cokers, etc. do not contain such a wide range of hydrocarbons.

From the disclosure of this specification and claims, the present invention not only meets or exceeds the standards of compatibility with current marine reciprocating engines, but is also compatible with advanced combustion gas turbines available for marine applications. It also allows the production of ultra-clean fuels. Such advanced turbine engines, which are currently available, are typically land based. These advanced turbine engines, once started on board, can have significant efficiency advantages with less corrosion or ash formation by burning the fuel of the present invention while at sea. Also, depending on the fuel economy available at the port, ships will gain efficiency benefits by burning these new fuels at the port to generate electricity and send it to the local power grid for revenue generation. can do. Revenues from such port power generation can offset marine fuel costs and reduce the actual total marine fuel costs to vessels below the high sulfur fuel oil, thus making the low sulfur fuel of the present invention more expensive. Even if it is a nautical fuel, it will offset the cost of its use. The greatest benefit is for the environment, which in certain normative case comparisons can reduce SOx and NOx emissions by more than 95%, potentially reducing toxic metal emissions during voyages. More than 99% (almost 100%) can be reduced. Furthermore, the environment benefits in two ways from _CO2 reduction: (i) the efficiency of advanced gas turbine engines on board ships, and (ii) the efficiency of power generation at ports, which can be used for coal, crude oil, residual oil or Inefficient combustion of some other fuel is displaced.

Thus, the present invention has broad application to the production and use of fuels with reduced levels of sulfur and other contaminants. 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, but rather to the appended claims or their substantial equivalents.

Claims (6)

1. A method of providing all or part of a ship's electrical power generated by burning fuel to an onshore electrical grid while at port, comprising the steps of:
said fuel has an actual sulfur content of 0.50% m/m (wt%) or less and comprises a range of hydrocarbons derived from crude oil from C3 or from C5 to over C20;
Said hydrocarbon has a lowest boiling point and a highest boiling point, said lowest boiling point being from C3 or C5 to over C20 crude oil combined with said fuel and not treated with hydrogen in the presence of a catalyst. wherein said highest boiling point is the highest boiling point of the hydrocarbon fraction from C3 or from C5 to above C20 that is soluble in a solvent suitable for solvent separation. ,
the solvent is selected from propane or paraffinic solvents including butane, pentane, heptane;
the highest boiling point of said component is either untreated with hydrogen in the presence of a catalyst, or treated with hydrogen in the presence of a catalyst and combined with said fuel;
wherein said fuel meets or exceeds all ISORMA 10 (ISO 8217-10) specifications, except for flash point, said flash point being less than 60°C. . Said series of hydrocarbons has the lowest boiling point of naphtha and is soluble in a solvent suitable for solvent separation, and said component with the highest boiling point is treated with hydrogen for sulfur removal before or after solvent separation. 2. The method of claim 1, wherein: 1. A method of providing all or part of a ship's electrical power generated by burning the ship's fuel from a ship to an onshore electrical grid during a temporary berth in port, comprising the steps of:
The ship's fuel is the fuel according to claim 1, wherein the fuel has an actual sulfur content of 0.50% m/m (wt%) or less and is from C3 or from C5. including a range of hydrocarbons from crude oil up to and above C20;
Said hydrocarbon has a lowest boiling point and a highest boiling point, said lowest boiling point being from C3 or C5 to over C20 crude oil combined with said fuel and not treated with hydrogen in the presence of a catalyst. wherein said highest boiling point is the highest boiling point of a component of a crude oil-derived hydrocarbon from C3 or from C5 to above C20 that is soluble in a solvent suitable for solvent separation;
the solvent is selected from propane or paraffinic solvents including butane, pentane, heptane;
the highest boiling point of said component is either untreated with hydrogen in the presence of a catalyst, or treated with hydrogen in the presence of a catalyst and combined with said fuel;
The fuel meets or exceeds all ISORMA 10 (ISO 8217-10) specifications, except for flash point, wherein the flash point is less than 60°C;
The method calculates the cost of kilowatt-hours (kWh) of electricity generated by onshore power plants and the cost of kilowatt-hours (kWh) of electricity generated on board a ship by burning the ship's fuel while moored in port. and analyzing
(i) the cost of onshore power generation facilities relative to the port's grid, comprising:
(a) the ship receives power from the grid; or
(b) said ship transmits power to said electrical grid;
the cost of the case, and
(ii) costs while said vessel is temporarily in port,
(a) the ship receives power from the grid; or
(b) said ship transmits power to said electrical grid;
For the cost of the case
(iii) if the cost of (i)(a) + (ii)(a) is higher than the cost of (i)(b) + (ii)(b), the 2. A method according to claim 1, characterized by connecting a ship to the power grid and controlling the power plant of the ship to send power to the power grid for compensation of the ship. 2. The fuel variation of claim 1, wherein said ship's fuel is produced by processing crude oil, said fuel having an actual sulfur content of 0.50% m/m (wt%) or less. and comprising a range of crude oil derived hydrocarbons from C3 or from C5 to over C20;
Said hydrocarbon has a lowest boiling point and a highest boiling point, said lowest boiling point being from C3 or C5 to over C20 crude oil combined with said fuel and not treated with hydrogen in the presence of a catalyst. wherein said highest boiling point is the highest boiling point of the hydrocarbon fraction from C3 or from C5 to above C20 that is soluble in a solvent suitable for solvent separation. ,
said solvent is selected from propane or paraffinic solvents including butane, pentane, heptane, treated with hydrogen in the presence of a catalyst and combined with said fuel;
The fuel meets or exceeds all ISORMA10 (ISO8217-10) specifications, except for flash point, wherein said flash point is less than 60°C. Item 1. The method according to item 1. The fuel of said ship is
(a) a viscosity of 10 cSt or less;
(b) a pour point of 0 (zero) °C or less;
(c) a density of 820 Kg/m ³ to 880 Kg/m ³ at 15°C;
(d) a CCAI of 800 or less;
(e) 10 mg/Kg or less sodium, 0.2 mg/Kg or less vanadium, and 0.2 mg/Kg or less silicon and aluminum in combination;
2. The method of claim 1, further comprising one or more of the features of: 2. The ship's fuel as set forth in claim 1, wherein said ship's fuel meets a SOLAS exception to flash point requirements for cargo ships or includes a flash point treatment wherein said ship's fuel has a flash point of 60°C or higher. the method of.

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