Environmentally friendly marine fuel

Abstract

This invention provides a method for supplying electricity generated on board a ship to the land-based power distribution network. [Solution] In an emission-controlled sea area or port, by burning a fuel having a sulfur content lower than the maximum amount of the IMO specification for applicable sulfur content at the location of the vessel, wherein the fuel is obtained by processing crude oil, the actual sulfur content of the fuel is 0.50% m / m (weight %) or less, and the fuel contains crude oil-derived hydrocarbons from C3 or C5 to C20 or higher, wherein the hydrocarbons have a minimum boiling point which is the lowest boiling point of any fraction in the untreated flow combined with the fuel, and a maximum boiling point which is the highest boiling point of the hydrogenated flow combined with the fuel.

Description

Technical Field

[0001] The present invention relates to a method and an apparatus for producing a fuel having a very low sulfur content from crude oil, refined residual oil, and other contaminated liquid feeds. The fuel having a very low sulfur content produced according to the present invention is particularly cost-effective for use on board large marine transport ships and for large onshore combustion gas turbines on land.

Background Art

[0002] The present invention targets the fact that when "offshore" ships, which is a long-known but hitherto unsolved major environmental problem, burn inexpensive low-grade heavy bunker oil and other heavy residues rich in sulfur, nitrogen, and metals, oxides of sulfur, nitrogen, and metals are carried into the natural environment. Such emissions are on a global scale and spread regardless of national geographical boundaries.

[0003] According to various third-party reports, certain global emissions resulting from burning heavy fuels for such waterborne transportation at sea are many times higher than the combined emissions of all gasoline-powered and all diesel-powered vehicles burning gasoline on land worldwide. Such combustion at sea emits SOx, NOx, CO2, soot, and harmful metals. Land vehicles include automobiles, trucks, etc., many of which currently use mandated "highway fuels" having a very low sulfur content. Therefore, even if transportation by such large ships is efficient based on "load per mile" and fuel consumption criteria, in reality, such ships generate a large amount of emissions.

[0004] The introduction of certain important regulations mandating the use of cleaner burning marine fuels for ships is conditional on such fuels being adequately provided in available quantities. A solution is still needed so as not to mandate something that is not technically, economically, or practically possible.

[0005] For example, the International Maritime Organization (IMO), a division of the United Nations, issues rules on international shipping. The IMO has sought to reduce emissions by tightening sulfur restrictions on marine fuels, while acknowledging technical limitations. Since 2011, the IMO has required that marine fuels burned in the open ocean (for example, outside of emission control areas (ECAs), including 200 nautical miles from the coasts of the United States, Europe, and other countries) must have a sulfur content not exceeding 3.50 m / m. In 2015, the IMO amended its rules to limit the sulfur content of marine fuels for commercial vessels within ECAs to generally less than 0.1%.

[0006] However, the IMO has again significantly lowered the sulfur limit in the open ocean to 0.50% m / m for 2020 and beyond. But the IMO has stated that such aggressive reductions in 2020 depend on "the results of a review of the availability of the required fuel oil, which is scheduled to be completed by 2018," and has indicated that such reductions may be postponed to 2025 if the required fuel is not available. For regulations on air pollution in the marine industry, see Annex VI of the International Convention for the Prevention of Pollution from Ships (MARPOL).

[0007] Therefore, there is a realistic and significant possibility of problems arising with regard to the lack of availability of low-sulfur marine fuels and the lack of technology to achieve such availability. For example, a 2015 industry publication stated that "plans are being made to reduce the permissible sulfur content in fuel to below the

[2014] levels required in emission-controlled areas...but this will take many years, as the cost would be prohibitive for many shipping companies with current technology." Such publications further stated that "these regulations are being continuously re-evaluated and a phased approach is being taken to implementation due to the extra costs and potential mechanical problems," because "many marine engines are not designed to handle low-sulfur diesel, which is much leaner than heavy fuel oil and does not have the same lubricating properties as heavy fuel oil. Companies are trying to make it work by employing various workarounds, such as cooling the fuel to increase its viscosity and injecting additional lubricants into specific parts of the engine" (Non-Patent Literature 1).

[0008] Another example is the 2015 IMO regulation that reduced the sulfur content of marine fuel to a maximum of 0.1% sulfur for commercial vessels within designated ECAs (Emergency Carriage Areas). Before entering an ECA, vessels must switch from inexpensive, high-sulfur heavy bunker fuel oil, which is burned in the open ocean, to more expensive, low-sulfur fuel similar to highway diesel fuel. Since January 1, 2015, the reduction of fuel sulfur within ECAs from 1.00% m / m (since July 1, 2010) to 0.10 m / m has created challenges for market supply and pricing. The production and supply of marine fuels to comply with IMO-related regulations competes with the demand for distilled fuels for highway and other onshore diesel applications, diverting available preferred feedstock flows and existing refining facilities and supply networks away from highway use of diesel and other low-sulfur distillates. Other technical issues also arise on board.

[0009] Regarding the 2015 IMO reduction in sulfur content within the ECA, the U.S. Coast Guard has warned that "ships using higher sulfur-containing fuels must switch to ultra-low sulfur (ULS) fuel oil to meet the new regulations." Because ships must use ULS fuel oil at all times during domestic and international voyages, in dock, and within the ECA, ships using high-sulfur-containing fuel oils must develop and implement switching procedures to switch between residual fuel and distilled fuel before entering the ECA. The Coast Guard further warns that "there are many other important technical challenges related to the use of ultra-low sulfur fuel oil and fuel oil switching, as mentioned 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 may differ from that of residual fuel, such as existing throttle settings not providing the desired propeller shaft RPM or generator load" (Non-Patent Literature 2).

[0010] The undeniable reality is that refineries are expensive, and even seemingly minor changes to fuel products or manufacturing equipment, or the addition of unit operations, require significant capital investment. In 2003, an evaluation study of refineries in Europe was conducted with a view to the need to reduce pollutants in marine fuels, as well as the requirements and capacity for producing the necessary quantities of such fuels. See, for example, Non-Patent Document 3.

[0011] Such reports highlighted significant challenges in many countries, including rising costs and reduced refinery utilization efficiency in producing adequate amounts of marine fuel, as well as, in some cases, the lack of local basic facilities near major ports to locally manufacture and supply such fuel, and the absence of the technology and equipment to produce it.

[0012] The cited report identified only three options. The “recombination option” (blending heavy fuel oil with low-sulfur fuel) was considered as the lowest-cost option for producing low-sulfur bunkers, but was deemed unsuitable because, while not costly, it could only process minimal amounts of material. This option was relatively low-cost in terms of logistics for recombining different categories of heavy fuel currently produced in European refineries, but it failed in terms of volume.

[0013] A second option, which would increase costs, is the processing of low-sulfur crude by replacing high-sulfur crude, such as Arabian Light, which is reported to contain 1.8% sulfur, with low-sulfur crude, such as African crude, like Bonnie Light, which is reported to contain 0.14% by weight sulfur. The estimated incremental costs of offshore bunkers resulting from this option were deemed an excessive burden for the reasons stated in the report.

[0014] This older report finally presents a third and most expensive option for producing low-sulfur marine-grade fuels: vacuum residue desulfurization (VRDS). The report concludes, "However, it is important to note that, in contrast to the degree of desulfurization required for gasoline or diesel, the hydrotreatment of the bottom of the barrel (residue desulfurization), unless combined with some conversion of the residue into a lighter product, is not the process that refiners are currently considering implementing. Nevertheless, if VRDS were pursued solely for the purpose of desulfurizing vacuum residue, the cost of this option would be about twice that of the second option, and therefore even more unacceptable."

[0015] Prior art allows shipwrights to load both high-sulfur fuel oil for offshore use and low-sulfur fuel oil for use within the ECA to meet IMO requirements, but this choice may present challenges in terms of engine technology, lubrication, and the potential needs for different fuel injection systems for optimal operation and fuel switching mechanisms. Shipwrights may add relatively large, expensive, and complex post-combustion flue gas treatment systems to maintain the highest performance levels. In some cases, liquefied natural gas (LNG) could be used as marine fuel. In that case, for example, LNG carriers could choose to use "evaporated gas" as fuel, but extending this LNG engine concept to all cargo ships would require the widespread availability of very expensive LNG refueling stations, and would incur additional costs for ports in rural areas that do not have local natural gas production and liquefaction facilities. However, in all cases, using LNG instead of liquid introduces realistic risks such as leaks due to refueling or ventilation during incomplete combustion, or methane emissions during operation and maintenance. Such methane emissions are a cause for concern because some believe methane has several times the environmental impact of sulfur dioxide as a greenhouse gas. From a similar perspective, some argue that emission reductions in marine applications can be achieved by burning natural gas during transit or while docked at ports equipped with gas supply docking stations. However, from one technical standpoint, natural gas has methane leakage problems, and while burning natural gas reduces CO2 emissions, this is not because it emits less CO2, but because, compared to LNG, the use of natural gas avoids the CO2 emissions generated in the LNG liquefaction process and reduces CO2 emissions from the recovery and replacement of coal used to ignite power plants supplying ships in port. Development efforts to replace LNG or natural gas in liquid form as marine fuel should be considered, but they do not provide a practical and cost-effective marine solution where global gas infrastructure is lacking and new refueling infrastructure is required. Gas supply infrastructure represents a significant investment in equipment and capital in ports in countries where gas production and supply are not locally available.

[0016] These global environmental problems related to marine fuels, which have been recognized for many years without cost-effective technological solutions, need to be addressed. Furthermore, the availability of new, low-cost fuels produced by new process configurations and equipment will encourage shipowners to adopt highly efficient combined-cycle propulsion power generation systems that are more efficient than diesel engines in terms of efficient use of waste heat recovery and do not experience the fuel lubrication problems that many engines encounter when burning expensive, ultra-low sulfur diesel fuels, which are in limited supply.

[0017] However, effective fuel production technologies have long suffered from a gap in the supply of low-cost, large-volume ultra-low-sulfur marine fuel. The need to fill this gap remains.

[0018] The Petroleum Industry and Markets Section of the International Energy Agency (EIA) publishes official documents describing the configurations of processes and equipment used in fuel production, and describing the configurations, products, and margins of conventional refineries. Terms used herein have the meanings set forth in Non-Patent Document 4 unless otherwise defined or expressly altered, 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.

[0019] The genetics of traditional refinery development and growth are somewhat fundamental, based on the evolution of societal product demand, progressing from basic kerosene-grade distillates for lighting to gasoline and diesel for automobiles, then aviation-grade fuels, and further to multiple products such as raw materials for numerous downstream chemical applications. All refinery technological development appears to have evolved stepwise, typically guided by adapting to either maximizing a given fraction obtained from each barrel of crude oil for a particular market segment, or adapting the refinery's various flows to downstream chemical products, while maintaining the production of multiple products for various end uses.

[0020] Thus, in prior art refinery designs using atmospheric crude oil and / or vacuum distillation units, solvent separation, hydrogenation, gasification, and many other unit operations, each barrel of crude feedstock is divided into multiple products of different specifications for different uses or downstream processes.

[0021] In conventional refining processes, it is counterintuitive to separate the feedstock into different unit effluents and then recombine all of those effluents. For example, the EIA references mentioned above define and describe conventional or typical atmospheric crude oil distillation, vacuum distillation, fuel solvent deasphaltization, catalytic hydrogenation, and integrated gasification combined cycle technologies, but they do not describe the configuration of a process that converts substantially all of the crude oil feedstock into a single liquid fuel.

[0022] Within the scope of conventional refining processes are “upgrading,” “topping,” or “hydrogen skimming” facilities. For crude oil upgraders, the primary objective is typically to convert very heavy, viscous, or solid-containing material into a lighter, more fluid material that can be reprocessed in existing conventional refineries to produce the entire range of fuel products, chemical raw materials, and / or petroleum coke. Upgraders simply convert heavier crude oil into lighter crude oil for supply to conventional refineries, which are individually designed to process sulfur to meet their respective downstream product specifications; sulfur reduction or metal removal is not the primary objective of upgraders. The goal is to modify raw materials that have a much higher density compared to typical lower-density crude raw materials. The heavier material is removed or separated from the supplied material, and the density of the resulting modified product material approaches the density of crude oil processed by existing conventional refining facility configurations. Topping or “mini” refineries are often located in remote areas or in locations convenient to the crude oil source. Topping refineries typically split each barrel of crude feedstock, targeting naphtha rather than gasoline production, into multiple direct distillates, with little to no further processing, except in a few limited cases, for naphtha reforming to enhance the octane of gasoline and hydrogenation of multiple distillates to produce various products. The goal of a typical topping refinery is to produce a wide range of directly usable fuels, such as gasoline, kerosene, diesel, and fuel oil, for local market consumption. When topping is carried out in some undesirable ways, and when the topping products are used, or when residues are not properly dealt with, harmful emissions to the environment increase rather than decrease. Hydrogenation skimming refineries convert crude oil into multiple products like topping refineries, but typically limit the amount of heavy naphtha added to the reformer, which also produces hydrogen consumed by the hydrogenation treatment unit in diesel production. Hydrogenation skimmers, like topping refineries, typically produce a wide range of gasoline, kerosene, diesel, and fuel oil for local consumption, rather than just a single product.

[0023] Various configurations for adapting the hydrogenation process, including having independent series or parallel hydrogenation reactor zones or integrated hydrogenation reactor zones, are known in the art. Cash et al.'s Patent Document 1 and the references cited therein disclose an integrated hydrogenation of different feeds, in which hydrogen-containing and liquid-containing flows from separate hydrogenation zones are distributed or combined in the disclosed manner. Various configurations of using solvent separation to extract deasphaltized oil from pitch in a heavy residue flow and use the deasphaltized oil as a raw material for hydrogenation are known in the art when used to generate multiple product flows. For example, Brierley et al.'s Patent Document 2 describes solvent deasphaltization for the production of deasphaltized oil without cracking or decomposition by separation of feeds based on solubility in liquid solvents such as paraffinic solvents up to heptane, including propane, butane, pentane, and heptane. The residual pitch contains high levels of metals and sulfur. Deasphaltized oil can be hydrotreated to remove sulfur, nitrogen, carbon, and metals, as described in references on the production of several products including naphtha, kerosene, diesel, and residual substances.

[0024] In global markets, there is a need for large quantities of fuel that is low in sulfur and nitrogen and essentially free of metallic contaminants to be available in order to address global environmental problems in offshore locations or onshore locations with little or no natural gas resources, where high-sulfur fuel oil or unrefined crude oil with low power generation efficiency is used.

[0025] Fuel producers require a design different from those developed conventionally for refining to produce multiple product slates. To keep costs low, the design must be equipped only with the equipment necessary to produce large quantities of clean fuel in a cost-effective and thermally efficient manner in a way that suppresses capital investment. The above design should aim to mainly produce marine fuels rather than extracting a relatively small fraction of each barrel of crude oil for marine fuels and using most of the barrel for other purposes.

[0026] What the world needs is a "game-changer" new process that provides solutions to technical problems regarding a method of making large quantities of relatively clean liquid fuels in an economical way (in an efficient form that avoids waste of energy expressed in short forms such as British Thermal Units (BTU)) for marine applications. Such a process can use existing liquid marine fuel filling stations (e.g., those supplying high-sulfur fuel oil (HSFO)) that are spread around the world instead of building new basic facilities for LNG for fuel distribution, so that the necessary facilities and the associated capital and operating costs can be minimized. Any such new process needs to be directed towards supporting the creation of liquid BTU in a cost-effective form compared mainly to ultra-low sulfur diesel (ULSD) manufactured for automobiles and trucks. Such available diesel is widely available, but due to cost issues and lubricity problems that occur when ULSD is used in many existing marine diesel engines, it is not widely used at sea by large marine carriers.

Prior Art Documents

Patent Documents

[0027]

Patent Document 1

Patent Document 2

Patent Document 3

Patent Document 4

Non-Patent Document

[0028]

Non-Patent Document 1

Non-Patent Document 2

Non-Patent Document 3

Non-Patent Document 4

Non-Patent Document 5

[0029] The present invention enables the supply of very low-sulfur, nitrogen- and substantially metal-free fuels in large quantities at low cost, filling a gap in effective fuel production technologies. These fuels are particularly useful for offshore applications as well as large-scale onshore applications such as combustion gas turbines for power generation. As used herein and in the claims, the terms “essentially metal-free” or “zero metal” mean a metal content ranging from zero to less than 100 parts by weight ppb (parts per billion) or a content so low that it is difficult to reliably measure by conventional online instruments.

[0030] Conventional refining processes extract crude oil feedstock into many parts, each part of which is sent to a separate downstream market channel. In contrast, the inventors have found that the maximum amount of crude oil feedstock from each barrel can be converted into a single ultra-clean fuel while capturing contaminants such as sulfur, nitrogen, and heavy metals, while removing only the crude oil portion that provides process utility and flow for conversion and capture. The invention extracts crude oil feedstock into only the minimum number of parts necessary for the capture and control of contaminants, and then reassembles these parts to form a single fuel product. [Means for solving the problem]

[0031] Accordingly, the present invention differs from conventional refining methods that divide each barrel of crude oil feedstock to meet multiple markets such as gasoline, diesel, fuel oil, or feedstock for downstream chemical manufacturing or applications. The method of the present invention aims to produce a primary clean fuel product. The present invention provides a low-cost polishing system for unrefined and residual oil, which is necessary to produce large quantities of clean fuel on a commercial scale to replace high-sulfur bunker fuel and other heavy residues used in commercial transport ships and power plant combustion systems. The present invention provides such fuel, as well as methods and apparatus for producing such fuel, with cost-effective sulfur reduction.

[0032] These novel processes reduce manufacturing costs by using counterintuitive steps while controlling the final product sulfur content below target levels in a remarkably effective manner. The present invention provides a novel method for converting the maximum amount from each barrel of crude feed into a single ultra-clean fuel while simultaneously capturing contaminating sulfur, nitrogen, and harmful metals during fuel production.

[0033] In many variations of the present invention, essentially the entirety of each barrel of feed, characterized in certain variations as 90% by volume or more, is converted into a single fuel, and in such variations, only a minimum amount, less than about 10% of each barrel of crude oil, is consumed for process utilities and flows for contaminant conversion and capture. The processes of the present invention allow for adjustment of the proportion of feedstock allocated to fuel production and the feedstock allocated for process utilities and flows for contaminant conversion and capture, for purposes of other operational considerations such as hydrogen balance, local demand for asphalt, coke and other residual products, overall production economics, and the local availability of alternative low-cost process fuels and electricity. In variations, at least 70% by volume of each barrel of crude oil feed is converted into a liquid fraction, which, when subsequently processed or blended but unprocessed, forms substantially one liquid fuel product having a sulfur content not exceeding a target sulfur content, rather than multiple hydrocarbon products, and the remainder of each barrel of crude oil feed is present in residues or other vapors or products.

[0034] Unlike conventional refining, which divides a crude oil feed into numerous parts and sends them to separate market channels, the present invention divides a crude oil feed into the minimum number of parts necessary for capturing and controlling contaminants, and then reassembles these parts to form a single fuel product with very low sulfur and nitrogen content and essentially no metals. The method and apparatus configuration of the present invention enables the mass, low-cost, and efficient production of low-sulfur fuel required for regulatory compliance in large-scale offshore and onshore turbine applications. These novel fuel deployments have substantially lower capital and operating costs compared to alternative conventional crude oil refining, thereby enabling the mass production of fuel with very low sulfur and nitrogen content and essentially no metals in an extremely cost-effective manner. These novel processes enable a highly cost-effective means of simplifying the energy supply chain from oil fields to ship engines or onshore power plants.

[0035] For the shipping industry, the novel configuration of the present invention provides the necessary amount of low-cost, low-sulfur marine fuel to achieve global marine sulfur reduction targets. The novel fuel production method and apparatus configuration of the present invention have substantially lower capital and operating costs than conventional crude oil refining, thereby producing large quantities of marine fuel with very low sulfur content, essentially metal-free, and very low nitrogen content in an extremely cost-effective manner.

[0036] The fuels of the present invention replace low-grade heavy bunker oils that are high in sulfur and metals, significantly reducing emissions of SOx, NOx, CO2, soot, and harmful metals into the open ocean. Instead of sulfur and metals being carried into the environment during the combustion of bunker oil, in the implementation 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, while these fuels have sufficient lubricity to avoid excessive wear on marine engines, and these novel fuels can use existing bunkering fuel infrastructure without heating the fuel to make it fluid, compared to other alternative fuels, thus reducing the energy consumed to heat the fuel in tanks on land or on board.

[0037] In one variation, the fuel of the present invention also provides an alternative to burning crude oil or heavy residues in large onshore combustion turbines deployed in facilities such as single-cycle or combined-cycle power plants that generate electricity and demineralized water, for example. Turbines burning the fuel of the present invention produce significantly lower turbine exhaust emissions of NOx, SOx, CO2, soot, harmful metals, and other combustion by-products, and, depending on the source, also produce less contamination under high-temperature corrosion or ash-forming conditions when burning contaminated heavy crude oil or refined residues.

[0038] The present invention relates to the centralized conversion of composite hydrocarbon feed materials 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 enters from the front and returns a single ultra-clean product fuel that has been controlled to low sulfur levels, nitrogen reduced, and metals removed. In a variation, the feed for distillation may be one or more crude oils combined with one or more high-sulfur fuel oils or other heavier residues, and further added light-tight oil or high-sulfur fuel oil, or both, as part of a flow feed to one or more other unit operations such as vacuum distillation, solvent separation, hydrotreatment, or gasification.

[0039] In other applications in the art, the terms “high-sulfur fuel oil” or “HSFO” have been assigned different, often dissimilar, contradictory, and confusing meanings in various technical articles, patents, and statutes, some of which have changed over time. As used herein and in the claims, “high-sulfur fuel oil” or “HSFO” means any substance used as a fuel having a sulfur content greater than 0.50% m / m (0.5 wt%). As used herein, the terms “heavy oil,” “heavy residue oil,” “residue,” “sustain,” or “other heavier oils” include petroleum-derived hydrocarbon substances with a sulfur content greater than 0.50% m / m (0.5 wt%). The term “high-sulfur” means a value exceeding the lower of the target sulfur content limit or, where applicable, the statutory sulfur limit.

[0040] In a preferred embodiment, the sulfur content of the final product fuel is controlled by a combination of flows having different sulfur content. In a variation, each such combined flow is formed to a provisional target sulfur content by adjusting unit operating conditions and flow velocity, by reducing the amount of addition or removal of very low sulfur content flows, or by blending feeds with different sulfur content. A variation of the present invention includes, as necessary, controlling the product sulfur level by supplying a selected crude oil with one or more of the following to it: (i) other crude oil, (ii) bunker fuel, (iii) high-sulfur fuel oil or other distillates, or (iv) other high-sulfur or metallic contaminant residues from other sources. As used herein and in the claims, the terms “essentially metallic” or “zero metallic” mean a metallic content of zero to less than 100 parts by weight ppb (parts per billion) or a content so low that it is difficult to reliably measure by conventional online instruments.

[0041] 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.

[0042] The inventors can address cases where (i) only a relatively small amount of sulfur is present in a particular fraction in a basic form of H2S or RSH thiol, and (ii) a relatively large portion of sulfur is present in a more complex organic structural form, in which case the process flow rate and operating conditions can be adjusted based on a predicted boundary fraction at a higher or higher level such that the sulfur content begins to increase more rapidly, and in some cases exponentially, compared to lower fraction levels.

[0043] The inventors have found that it is possible to configure process and apparatus configurations to enable bypass treatment of specific flows and maximize that bypass, thereby avoiding or reducing the treatment of flows containing basic, less complex sulfur forms, and allowing flows containing more complex forms to be treated in a different manner. This allows for the selective exclusion of specific flows from hydrodesulfurization, while for other flows, the same flows can be supplied to different hydrotreatment devices to adjust different hydrotreatment unit conditions, or removal can be adjusted by solvent and / or reactive chemical-based treatment. This may include treatment with multiple solvents or other removers in one or more removal units, where the respective ratios of the removers in each unit are adjusted based on the sulfur distribution to each unit to selectively remove sulfur-containing molecules of low or high complexity.

[0044] The terms "kerosene" and "light distillates" are often used interchangeably, overlappingly, or with different meanings across different references, but are uniformly defined solely based on the fractional boundary points of an atmospheric distillation column within a temperature range (e.g., 190°C–250°C or 180°C–230°C), and not on sulfur content. Instead, convenient sulfur content measurements are performed and reported based on the fractional boundary point temperature range determined by the specifications of each product from conventional refineries. The inventors found this to be less than ideal.

[0045] The inventors have discovered that cost reductions in low-sulfur combustion production can be optimized by changing the fundamental operating method of crude oil distillation columns. They found that specific distillate removal should be performed based on the sulfur content of the by-stream, while also considering the analysis of the sulfur content of the crude oil feedstock or feed mixture supplied to the distillation column, rather than based on the specifications of the standard product temperature range for long-standing downstream use such as kerosene, jet fuel, and diesel.

[0046] The inventors have discovered how to define a "tip," which refers to the point at which the change in sulfur content per unit volume change in the extracted product (the slope of the graph) is no longer substantially flat. Instead, at the tip, as the extraction amount increases slightly, the sulfur content begins to increase rapidly or exponentially, such that the slope of the graph per unit volume begins to change significantly. Furthermore, beyond the tip, the type, composition, and complexity of sulfur-containing compounds typically change depending on the type of crude oil feedstock. The tip is an indicator from which desulfurization can be minimized or eliminated, representing the separation of the flow or portion of the flow that requires desulfurization.

[0047] The inventors have found that the capital and manufacturing costs of low-sulfur fuels can be minimized by directly extracting and collecting the maximum amount of material having a sulfur content below a threshold, thereby maximizing the total amount of liquid produced that has a sulfur content below a threshold, thus avoiding or reducing the cost of processing downstream to reduce or remove sulfur.

[0048] The inventors have found that relatively large quantities of such material below a certain threshold, and in certain crude oils, portions within a narrow, specific zone above the threshold, do not require further sulfur removal or significant subsequent processing when combined with other extracts that have already undergone sulfur removal treatment. The inventors maximize the production of such untreated material and reduce the cost of desulfurization or other treatment operations for the entire flow by not only advancing atmospheric distillation conditions, primarily by increasing the feed or column temperature profile, but also by reducing or eliminating reflux, lowering the crude oil feed rate, or altering the crude hydrocarbon or sulfur composition by mixing or diluting the feed crude oil to maximize the extraction amount near the threshold. The threshold is not defined from a standard industry classification or regulatory standpoint that sets the extraction temperature range.

[0049] In this specification and in the claims, the inventors define a “tip point” as the point at which, in relation to the analysis or other measurement method of crude oil, when the mass % or volume % of crude oil is plotted on the x-axis and the sulfur content on the y-axis, the sulfur content begins to increase sharply or exponentially from a horizontal or near-horizontal position, in the sense of a large change in the slope of the graph per unit volume. The difference in the x-axis direction is the change in the unit volume of the fraction, the difference in the y-axis direction is the change in the sulfur content per unit volume, and the slope is the slope of the graph. The slope of such a graph moves sharply from zero or a value near horizontal to a value greater than 0.2, and then rapidly to a value greater than 1, toward a somewhat exponential increase in sulfur content, and the tip point changes based on the crude oil or other feedstock supplied to the distillation column. Therefore, “delimiter extraction” or “sulfur delimiter extraction” provides a means for determining the delimiter to a boiling hydrocarbon-containing liquid below a delimiter, which is the point where the change in the slope of the graph per unit volume is large and the sulfur content begins to increase rapidly or exponentially, as described above, beyond the endpoint of the naphtha range, for example, the endpoint of the range of unstabilized, as-spontaneous straight-run naphtha.

[0050] In this specification and in the claims, the inventors define base “delimiter extraction” or base “sulfur delimiter extraction” as a hydrocarbon-containing liquid that boils above the endpoint and below the delimiter in the range of unstabilized, as-is straight-run naphtha with respect to the sulfur content of the fraction, provided that the delimiter is selected such that the fuel product flow is formed from a combination of all untreated flows below the delimiter and all flows above the delimiter extraction selected to be added to the combination, in which case the actual sulfur content of the combined fuel does not exceed the target sulfur content. In a modified example, fuel can be produced according to whether the target sulfur content is at the sulfur delimiter, or higher or lower than the sulfur delimiter, and the combination of flows that produce the fuel is efficiently made relative to the delimiter such that the actual sulfur content of the fuel does not exceed the sulfur target.

[0051] For most crude oils, the sulfur boundary extract for atmospheric distillation columns contains most of the substances in the kerosene range (as defined in various ways in the art), such as those that begin to boil at 180°C or 190°C (or other kerosene range starting point), and for simplification, substances in lower or higher temperature ranges may also be included. However, it is the sulfur content, not the temperature or historical definition of the kerosene range substances, that determines the endpoint of the sulfur boundary range. Fuel can be formed according to the sulfur boundary, where the target sulfur content is the sulfur boundary, and the combination of flows forming the fuel is made so that the actual sulfur content of the fuel does not exceed the sulfur target.

[0052] In one embodiment, crude oil feedstock is separated into flows, one or more liquid portions of such separated flows are treated, and the other portions are left untreated. The treated and untreated portions of the liquid flows are then recombined to form a liquid fuel having an actual sulfur content below a target sulfur content. The process steps include: (a) separating crude oil into a light overhead distillation gas, a metal-rich residue insoluble in one or more solvents used for solvent separation, a sulfur-containing gas, and liquid fractions above and below the sulfur threshold by one or more distillation and solvent separation steps; (b) treating the liquid fraction above the sulfur threshold, rather than the liquid fraction below the sulfur threshold or the insoluble residue, by one or more hydrogenation steps to form one or more hydrogenated flows with reduced sulfur content, leaving the other portions untreated; and (c) combining the hydrogenated flows with the liquid fraction below the threshold to form the liquid fuel having an actual sulfur content below the sulfur threshold as the target sulfur content.

[0053] In yet another embodiment, the present invention provides a method for reducing emissions exceeding IMO specifications by vessels in the open ocean, within an ECA, or in a port by using a fuel manufactured according to the present invention. The fuel has a sulfur content adjusted to be lower than the maximum amount of IMO specifications applicable at the location where the fuel is used by the vessel, whether at sea, within an ECA, or in a port. In this way, vessels can exceed IMO requirements and general expectations.

[0054] In another embodiment, the present invention provides a method for a ship to sell electricity generated using the fuel of the present invention in a port to an onshore power grid, for example, to offset offshore or port fuel costs.

[0055] The inventors have found that, by appropriately considering and adjusting the flash point, it is possible to produce low-cost, ultra-clean marine fuels that far exceed the IMO's expectations regarding sulfur and metal restrictions.

[0056] Thus, the inventors have discovered a technical method for exchanging (i) minor changes in flash point for (ii) large-scale environmental benefits (enormous reductions in SOx and NOx and the essential elimination of harmful metals), particularly in relation to the massive fuel consumption of large cargo ships. No one has ever made such a discovery before.

[0057] The International Convention for Safety at Sea (SOLAS) outlines the flash points of fuels and their permissible use on cargo ships. "To many people, the minimum flash point of 60°C for fuels in general operation, as presented in the SOLAS Convention, may seem like one of the foundations of maritime law, but this was only introduced in the 1981 amendment. The first three SOLAS Conventions (1914, 1929, and 1948) did not impose any restrictions on the flash points of petroleum fuels, and even the 1960 Convention only required that the fuels used in internal combustion engines have a flash point of 43°C or higher for 'new' passenger ships. This provision was essentially carried over into the current 1974 Convention, as originally adopted," the above is a quote from Non-Patent Document 5.

[0058] Wright et al. state that flash point is not an actual value but an empirical one, and that "the flash point value is never, and has never been, a boundary between 'safe' and 'unsafe'." As a result, from the beginning of the petroleum industry, flash point has been used, with some inaccuracies, as a means of identifying products that require greater control and care regarding storage and use. In reality, in marine applications, petroleum fuel fires occur not so much due to vaporization ignition, but rather due to ignition caused by leaks or pipe ruptures, where the fuel comes into contact with a surface above its autoignition temperature. Nevertheless, flash point has been used from the outset as a safety parameter in petroleum safety laws, even if the limit is sometimes set somewhat arbitrarily, or taking into account the fact that it is an empirical value.

[0059] SOLAS makes exceptions for cargo ships. SOLAS stipulates that oil fuels with a flash point below 60°C are not permitted, but the exception states that "in cargo ships, the use of fuels with a flash point lower than those specified in Chapter 2.1 of [SOLAS] (e.g., 60°C), such as crude oil, may be permitted, provided that such fuels are not stored in any engine room and that the authorities approve." It should also be noted that some countries do not have flash point standards, and others permit relatively low flash points for marine applications.

[0060] The flash point of a fuel can be adjusted by treatment as needed. As used herein and in the claims, the term “flash point treatment” means a composition that raises the flash point when combined with a material. In one variation, flash point treatment lowers the vapor pressure of an added material to reduce the risk of vapor ignition. In another variation, the flash point modifier is a solid or liquid additive having a flash point of 60°C or higher, which is added to a low flash point fuel to raise the fuel’s flash point. These can include various types of particulate matter and oils. For example, high flash point additives for treating carbon-based fuels are disclosed. For example, Patent Document 3 by Hughes et al. 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, and specifically cites Calpar100 (FP210°C), Calpar325 (FP240°C), and CalparP950 (FP257°C), which are available from Calumet Lubricants, Inc. in Indianapolis, Indiana, and paraffinic base oils having a flash point of 200°C or higher and mixtures or combinations thereof.

[0061] The inventors have discovered a technical method that (i) exchanges a minor change in flash point for (ii) substantial environmental benefits (enormous reductions in SOx and NOx and the essential elimination of harmful metals), particularly in relation to the massive fuel consumption of large cargo ships. No one has ever made such a discovery before. [Brief explanation of the drawing]

[0062] [Figure 1] A schematic diagram illustrating various actual and hypothetical crude oil sulfur content ranges. [Figure 2] A schematic diagram showing the process layout for processing crude oil to produce a single liquid product useful as fuel according to the present invention. [Modes for carrying out the invention]

[0063] In one embodiment of the present invention, a method for converting at least a portion of a hydrocarbon feedstock, which is crude oil containing sulfur and metals, into a single liquid product, (i) by one or more distillation and solvent separation steps, the feedstock is subjected to one or more distillation and solvent separation steps, which include only light overhead distillation gas (including only distillation gas that does not condense under atmospheric distillation conditions as defined by the EIA or better, even though a debutane column system may be preferred in terms of costs that should be eliminated in particular local circumstances or otherwise), metal-rich residue insoluble in one or more solvents used for solvent separation, gas containing sulfur, and (at least a portion of substances in the kerosene range for some feedstocks that are treated as being within the distillation range). The process includes: (ii) separating a distillate (having) and a sulfur-containing liquid fraction having hydrocarbons in the vacuum diesel range; (ii) hydrogenating a selected extracted liquid fraction above the sulfur boundary (preferably only soluble liquid fractions are selected for hydrogenation), rather than an extracted liquid fraction below the sulfur boundary (and preferably not any fraction insoluble in the solvent used for solvent separation), by one or more hydrogenation steps to form one or more hydrogenated flows with reduced sulfur content; and (iii) combining the untreated fraction with the treatment flows to form a fuel in which the actual sulfur content is less than or equal to the target sulfur content. As used herein, the terms “step” or “zone” may refer to a unit operation or area having one or more processing operations having one or more divisions of an apparatus configuration and / or unit operation or subzone. The apparatus may have one or more tanks, vessels, distillation columns, separators, reactors or reactor vessels, heaters, exchangers, strippers, pipes, pumps, compressors and controllers. In a preferred modification of the present invention, substantially all of the hydrocarbon composition of the feed is separated into fractions, which are then recombined to form a fuel, which is a single liquid fuel product.The fuel is a single liquid fuel product comprising hydrocarbons ranging from the original feedstock liquefied petroleum gas, or in one variation, ranging from naphtha to hydrogenated deasphaltized oil, and does not form multiple hydrocarbon products, but excludes hydrocarbon compositions comprising hydrocarbons in (i) the light overhead gas of the distillate, (ii) the insoluble residue, and (iii) the sulfur or metal recovery flow. Such a range is substantially the entire range of crude oil-derived hydrocarbons from C3 or C5 to C20 or higher, wherein the hydrocarbons have an initial boiling point which is the lowest boiling point of any fraction in the untreated flow combined with the fuel, and a maximum boiling point which is the highest boiling point of the treated flow combined with the fuel. As used herein and in the claims, the term “untreated” means not having undergone hydrogenation to reduce or remove sulfur, nitrogen, or metals. In one modification, such a fuel includes substantially a range of crude oil hydrocarbons from C3 or C5 to C20 or higher, or a range of crude oil hydrocarbons having an initial boiling point in the range of about 35°C to about 315°C or higher, preferably up to the initial boiling point of the end of the deasphaltized oil and the beginning of the deasphaltized residue, which are insoluble in the solvent selected for solvent separation. In a further preferred modification, the fuel of the present invention includes a combination of hydrocarbons ranging from the lowest boiling point portion of the untreated liquid fraction from atmospheric distillation to the highest boiling point portion of the hydrosolubilable product from solvent separation. Thus, the preferred fuel of the present invention is the opposite of conventional gasoline, diesel, kerosene and fuel oils, which are separated into selected partial ranges and do not have a meaningful content of the maximum range of such hydrocarbons. Accordingly, one embodiment of the present invention is a fuel obtained as a single product of processing crude oil, the fuel having an actual sulfur content of 0.5% by weight or less, preferably 0.1% by weight or less, and containing substantially the entire range of crude oil hydrocarbons from C3 or C5 to C20 or higher. The above hydrocarbon has an initial boiling point, which is the lowest boiling point of any fraction of the crude oil under atmospheric distillation conditions, and a maximum boiling point, which is the endpoint of the residual portion of the crude oil that is insoluble in solvents suitable for solvent separation.In a modified example, such a fuel comprises substantially the entire range of crude oil-derived hydrocarbons from C3 or C5 to C20 or higher, wherein the hydrocarbons have an initial boiling point which is the lowest boiling point of any fraction in the untreated flow combined in the fuel, and an endpoint which is the highest boiling point of the treated flow combined in the fuel. In one modification, crude oil is separated into a light overhead distillation 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 liquid fraction, the liquid fraction having (i) a liquid fraction below the sulfur boundary and (ii) a liquid fraction above the sulfur boundary, both of which are soluble or insoluble in the solvent used for solvent separation; (b) the soluble liquid fraction above the sulfur boundary, rather than the liquid fraction below or insoluble fraction, is hydrogenated in one or more hydrogenation steps to form one or more treated streams having a reduced sulfur content; and (c) the untreated fraction is combined with the treated streams to form a fuel in which the actual sulfur content is less than or equal to the target sulfur content.

[0064] In a modified version, such residues are burned in one or more gasifiers for use in power production and the generation of at least some hydrogen for hydrogenation and capturing at least some of the metals in the gasifier solids to be removed, or the residues are burned in one or more boilers that capture flue gas sulfur and metals for use in auxiliary hydrogen generation unit operations to supply hydrogen for power generation and hydrogenation. Preferably, all sulfur-containing gases are sent to one or more common sulfur recovery units.

[0065] By implementing the present invention, the actual sulfur content of the fuel can be adjusted to meet target sulfur content limit specifications, for example, by adjusting the amount of untreated and treated continuous flow for the combination forming the fuel, thereby meeting IMO specifications for marine fuels or sulfur limits for combustion gas turbines. For example, the target sulfur content of the fuel can be adjusted to meet one or more target IMO specifications, either inside or outside the ECA, for example, 3.5 wt%, 0.5 wt%, 0.1 wt%, or other IMO specifications selected from those. Fuels produced according to the method of the present invention are useful for marine engines, combustion gas turbines, combustion heaters such as boilers, and other applications.

[0066] In one modification, at least one of the hydrogenated flows is an ultra-low sulfur flow having 10 ppm by weight or less of sulfur, and is used to adjust the formation of a fuel in which the actual sulfur content is below the target sulfur content by increasing or decreasing the amount of the flow relative to the combination. In another modification, at least one of the hydrogenated flows is an ultra-low sulfur flow having 10 ppm by weight or less of sulfur, the untreated fraction has a sulfur content exceeding the target sulfur content, and the untreated fraction is used as trim control, and by reducing or increasing the amount of such untreated fraction relative to the combination, a fuel in which the actual sulfur content is below the target sulfur content is formed. In further variations, when converting a crude oil feedstock into substantially one liquid fuel product rather than multiple hydrocarbon products, a first hydrotreatment flow is produced, which is a reduced sulfur flow having a sulfur content of less than 10 ppm by weight, and a second hydrotreatment fuel fraction is produced, which has a reduced sulfur flow with a sulfur content in the range of 0.12 to 0.18% by weight, and the untreated fraction has a sulfur content that is below or above the threshold sulfur and exceeds the target sulfur content, and the first hydrotreatment flow or the second hydrotreatment flow or both are used as trim control by increasing or decreasing the amount of such flow relative to the above combination to form a fuel in which the actual sulfur content is below the target sulfur content.

[0067] In a more preferred embodiment, the sulfur content of one or more crude oils, residual oils, and other feeds is selected, or processing conditions are adjusted so that at least 70% by volume of each barrel of the crude feed is converted to a liquid fraction, which is then processed or combined but unprocessed, to form a fuel with a sulfur content below the target sulfur content, rather than multiple hydrocarbon products, and less than 30% of each barrel of the crude feed is directed to something other than fuel. In preferred modifications of the present invention, depending on the feed composition, hydrogen balance, process economics, and other factors, as well as adjustments to process operating conditions and flow rates, at least 80% by volume, more preferably about 90% or more of each barrel of hydrocarbon feed is converted to a single liquid fuel product, rather than multiple hydrocarbon products, excluding a flow with very low sulfur. The flow with very low sulfur is used as a trim to increase or decrease the trim flow to control the sulfur content of the final fuel product to a level that does not exceed the target sulfur content. The excess amount of trim flow can be transferred separately for material balance and inventory management purposes. In such preferred modifications of the present invention, about 10-30% or less of each barrel of the crude oil feed is captured in the metal-rich residue after atmospheric and vacuum distillation by solvent extraction.

[0068] In other variations, a high-sulfur fuel oil having a sulfur content higher than the target sulfur content is added alone or with light-tight oil before or during the combination of all treated and untreated fractions to form the fuel. The high-sulfur fuel oil can be supplied to one or more of the distillation, solvent separation, or hydrogenation steps described above. In one preferred embodiment, the ultra-low sulfur stream has a sulfur content in the range of 10 ppm by weight or less, the untreated fraction has a sulfur content exceeding the target sulfur content, and the untreated fraction is used to adjust the amount of the untreated fraction in the combination to form a product fuel in which the actual sulfur content is less than or equal to the target sulfur content.

[0069] The apparatus for carrying out the method of the present invention can reduce its installation area to 20% to 30% of the installation area of ​​a conventional refinery with a typical downstream processing unit. Thus, the capital cost per barrel of feed to be processed is substantially reduced. For example, in one particular embodiment of the present invention, only one or more of atmospheric distillation, vacuum distillation, solvent separation, hydrogenation, and gasification are used, along with auxiliary equipment necessary for capturing sulfur and metals, and there are no hydrocarbon processing operations downstream of hydrogenation, except for gasification with auxiliary equipment necessary for capturing sulfur and metals.

[0070] Modifications of the process configuration of the present invention provide highly efficient, low-cost operation through the effective integration of an island-like structure (utility island) of equipment that supplies hydrogen, steam, and fuel gas, as well as processes required for power generation, while providing integrated metal and sulfur capture means. The utility island has one or more gasification systems that process heavy metal-rich residues to capture and eliminate metal contaminants as components of potential air emission sources, preferably using integrated, and therefore lower capital cost, sulfur capture, treatment, and removal, with sour gas and acid gas off-gas treatment from all sources as potential emission sources. The island configuration of the present invention produces hydrogen for the hydrogenation treatment step, as well as steam and fuel gas for the electric process via a highly efficient combined cycle power generation means that utilizes specific flows, which are usually waste flows, to meet process requirements.

[0071] One modification of this embodiment of the present invention addresses a case where light-tight oil does not contain sufficient heavier hydrocarbons in the bottom fraction and residue to provide a treatment balance for hydrocarbon treatment and corresponding hydrogen production, and enables the hydrogenation of such light crude oil to reduce sulfur and metals and decontaminate it. The method comprises the step of adding the light crude oil, separately or in combination with other feeds, to any or all of the heavier feeds that are to be led to atmospheric distillation, vacuum distillation, or solvent separation treatments.

[0072] In one modified example, the design of the apparatus for vacuum distillation, solvent separation, hydrogenation, and gasification operations downstream of atmospheric distillation is such that it has additional or reserve capacity to process additional heavy residues from high-sulfur fuel oil or another source outside the battery limit of the operations, forming a fuel whose actual sulfur content is below the target fuel sulfur content limit level, and capturing at least some of the sulfur and metals from the additional heavy residues.

[0073] In other embodiments, the present invention provides a method for generating electricity using the fuel of the present invention while a vessel is anchored in a port, reducing local emissions, and selling it to an onshore power grid. In one modification, the present invention provides a technical method for reducing emissions in and near a port, the method comprising (a) a technical analysis to determine the amount of sulfur or metal emissions per kilowatt-hour (kWh) generated by onshore power generation equipment that generates electricity normally supplied to a power grid at or near a port (including, for example, emissions associated with the use of local power supplies when a vessel is connected to such a power grid in a port), and (b) a technical analysis to determine the amount of sulfur or metal emissions per kWh generated by electricity generated on board the same vessel while it is in the port at the location in (a), and comparing (a) and (b), if the emissions generated by the vessel for power generation in (b) are lower than those of the local power source in (a), the onboard emissions are reduced and all or part of the onboard power generation is supplied to the power grid. This embodiment may be particularly useful in reducing environmental emissions when locally supplied electricity comes from a specific type of coal combustion source, or when lower-emission options are not available for local power generation and heavy crude oil or residual oil is burned for power generation. Without offsetting, such provision by a vessel to the local power grid would not be made unless there is offsetting of port charges, unless the kWh cost of the vessel-generated electricity exceeds the kWh cost of the local power grid electricity, or unless such provision by a vessel to the local power grid would not benefit the vessel in other ways, such as offsetting by emission reduction deductions such as subsidies paid for low-emission power generation.

[0074] If it is beneficial for a vessel to supply power to the local distribution network, the vessel can offset or reduce fuel costs incurred at sea with revenue generated by supplying all or part of the electricity it generates on board using the fuel of the present invention to the onshore distribution network while it is docked in port. Depending on the length of the port stay, the revenue generated from supplying power to the distribution network while docked in port can offset the fuel costs of sea travel to a level where the actual sea travel fuel costs using these new fuels are lower than the cost of high-sulfur fuel oil for sea travel.

[0075] Figure 1 is a schematic plot of various actual and hypothetical crude oil sulfur content values, showing delimiter ranges. Exemplary crude oil sulfur profiles 4, 5, and 6 are plotted based on the center points of actual data extracted from Non-Patent Literature 6. Hypothetical crude oil sulfur profiles 1, 2, and 3 are derived in part from actual data taken from various sources, including Non-Patent Literature 7.

[0076] Figure 1 illustrates a method suggesting the definition of “tip points” for different crude oils for the process configuration of the present invention. Figure 1 illustrates a tip point, which is the point where the change in sulfur content per unit volume change of the extracted product (slope of the graph) is no longer substantially horizontal or flat, and instead, as the extraction amount increases slightly, the sulfur content begins to increase rapidly or exponentially, resulting in a large change in the slope of the graph per unit volume. Also, beyond the tip point, the sulfur-containing compounds, types and compositions, and complexity change depending on the type of crude oil feedstock. The tip point makes it possible to determine how to best bypass costly and intensive hydrotreatment for operational efficiency, while still producing fuel that conforms to the target sulfur content limit specifications. That is, the tip point can be the maximum sulfur content of the atmospheric crude oil column fraction that moves away from or reduces further downstream treatments to reduce sulfur content, for example, in the direction away from hydrotreatment. Fractions above the threshold are directed to downstream processing to reduce sulfur content, while fractions below the threshold are left unprocessed, resulting in substantial operational savings. In conventional purification, extraction is fixed by a temperature range, not by sulfur content. The target sulfur content can be used as an example of end-use requirements to determine the selection of the threshold. If the threshold is set too high, the excess untreated flow with higher sulfur content cannot be easily offset by the increase in the hydrogenated flow with lower sulfur content.

[0077] Figure 2 outlines another embodiment of the present invention and shows a simplified representation of the key components of a process configuration for producing a single liquid product suitable for use as fuel. Figure 2 illustrates a method for producing a single low-sulfur, essentially metal-free fuel product by integrating atmospheric and vacuum distillation, solvent separation, hydrogenation, and gasification.

[0078] The stream of contaminated crude oil containing sulfur, nitrogen, and metals enters the main process via line 2 after pretreatment such as desalination, which is preferable for the crude oil. In this embodiment, 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 with residual oil such as high-sulfur fuel oil. The feedstock 2 is led to an atmospheric distillation column 100, where the feedstock is separated into light overhead gas 4 and several extracts. The light overhead gas 4 contains non-condensable distillation gas 6, which is useful as process fuel, or is captured for other uses. In one preferred modification, the capital expenditure associated with a stabilization system for such overhead gas 4 is avoided. However, depending on local needs, a stabilization system may be included, for example, a special marine fuel with a maximum H2S specification. In the embodiment shown in Figure 2, the multiple extracts include one or more flows within the following ranges: (1) unstabilized as-is straight-run naphtha from line 16 via line 4, (2) sulfur delimiter extract from line 18, (3) light distillate from line 24, (4) intermediate distillate from line 26, (5) first heavy distillate from line 28, and (6) atmospheric pressure residue from line 30.

[0079] In various applications of this art, different meanings are assigned to the same or similar extracts in different parts of the world, and these meanings are often different, overlapping, contradictory, or confusing. As used herein and in the claims, the following meanings apply: (a) “Naphtha” means a carbon-containing composition ranging from those having at least three carbon atoms (C3), such as propane, to those having an initial boiling point (IBP) of about 175°C (about 350°F), excluding low-boiling-point compounds such as methane and below. (b) “Stabilized naphtha” means, as far as naphtha or other naphtha-range substances used as fuel blend base materials, that low-boiling-point compounds such as butane or propane and below have been almost completely removed from the naphtha or fuel, for example, in conventional refineries, the bottom flow from the naphtha debutane distillation column is stabilized naphtha. (c) “Unstabled naphtha” means naphtha from which light components below C4 have not been removed. For example, in conventional refineries, the feedstock flow to the naphtha debutane column is unstable naphtha. (d) “Unstabilized, natural straight-run naphtha” means a carbon-containing composition recovered from atmospheric distillation, ranging from those with at least three carbon atoms (C3), such as propane, to those with an initial boiling point (IBP) of approximately 175°C (approximately 350°F), excluding low-boiling-point compounds such as methane and below, and may include atmospheric distillation overhead distillation gas. (e) “Natural naphtha” means the unstabilized light fraction of the hydrotreatment effluent recovered from a distillation column or other separator in a hydrotreatment process. From an operational perspective, this refers to a part of the hydrotreatment zone that recovers one or more heavy fractions from the bottom of the separator or its vicinity, such as the distillate range, the heavy oil range, or substances heavier than the naphtha portion of the feedstock to other separators, and which is unstabilized. (f) “Delimiter extract” has already been defined herein, and an example thereof is shown in Figure 1. (g) “Light distillate above delimiter extract” or “light distillate” as used herein is a fraction having an initial sulfur content higher than the maximum sulfur content of the delimiter extract, and correspondingly having a boiling point (IBP) higher than the highest endpoint of the delimiter extract.(h) “Intermediate distillate” means the fraction between the light distillate and the heavy distillate that is separated as an extract based on a preferred distillation column design, for example, the intermediate distillate extract may be excluded and combined with either the light distillate or the heavy distillate. (i) “First heavy distillate” means the heaviest fraction of the atmospheric distillation unit, whose sulfur content and boiling point range are determined by one or more operating conditions such as the sulfur composition of the feedstock for the distillation unit, the severity of the crude oil column operation, and the downstream hydrogenation treatment conditions. (j) “First heavy distillate” means the heaviest fraction of the atmospheric distillation unit, which has a sulfur content and boiling point range that are determined in relation to the sulfur composition of the feedstock for the distillation unit and the sulfur delimiter extraction, and with reference to one or more operating factors such as the severity of the crude oil column operation, the severity of the downstream hydrogenation treatment conditions, etc. (k) “Second heavy distillate” means the lightest fraction of the vacuum distillation column and has a sulfur content and boiling point range determined in reference to one or more operating factors such as the severity of crude oil column operation and the severity of the hydrotreatment conditions of the downstream distillate, relating to the sulfur composition of the feedstock for the distillation unit and the extraction of the sulfur delimiter. (j) “Vacuum fuel,” including “atmospheric residue,” “vacuum residue,” “light vacuum fuel,” and “heavy vacuum fuel,” “solvent separation,” “hydrotreatment,” and other terms, and variations thereof, are known to those skilled in the art of crude oil processing technology.

[0080] Preferably, the flow combination of (1) unstabilized as-is straight-run naphtha from line 16 via line 4, and (2) sulfur delimiter extraction from line 18 contains sulfur in the range of 0.06% to less than 0.08% by weight, and if the target sulfur content of the fuel combination in line 600 is 0.1% by weight or less, the sulfur content of the treatment flow 70 is less than 10 ppm by weight, in which case the flow velocities of steam 10 and 70 are adjusted so that the combined fuel combination 600 does not exceed the target sulfur content.

[0081] In Figure 2, the atmospheric pressure residue is supplied to the vacuum distillation column 200 via line 30, producing (1) the second heavy distillate in line 32, (2) light vacuum diesel in line 36, (3) heavy vacuum diesel in line 38, and (4) the vacuum residue in line 50. The vacuum residue is led to the solvent separation 300 via line 50, producing (1) deasphaltized oil in line 80 and pitch, which is a metal-rich heavy residue in line 90.

[0082] Figure 2 shows an integrated hydrogenation system 400 including two hydrogenation zones, namely a distillate hydrogenation zone 430 and a heavy oil hydrogenation zone 460. Integrated hydrogenation systems are known in the art and are preferred for this application. However, for hydrogenated desulfurization and hydrogenated demetallation in both zones 430 and 460, relatively low pressure and mild hydrogenation conditions in the range of about 117–138 bar (1700–2000 psi) are sufficient.

[0083] The light distillate 24, intermediate distillate 26, first heavy distillate 28, and second heavy distillate 32 are preferably supplied to an integrated hydrogenation system 400 and hydrogenated under hydrogenation conditions in the presence of a catalyst to form a distillate hydrogenation zone 430 effluent flow in line 60. Such hydrogenation treatment effluent 60 includes substances within the following ranges, namely (1) as-is naphtha with an expected boiling point range above C5 (compositions with 5 carbon atoms) to about 175°C (about 350°C), and (2) ultra-low sulfur diesel, which is a reduced sulfur flow formed from a combination of treatment distillation vapors having a sulfur content of less than 10 ppm by weight and containing the light distillate 24, intermediate distillate 26, first heavy distillate 28, and second heavy distillate 32. It is known to those skilled in the art of hydrogenation that the by-products of hydrogenation in Zone 430 may include, at least a portion thereof, sulfur-containing gases such as hydrogen sulfide and hydrogen-rich-off gas, and typically small amounts of liquefied petroleum gas, which are desulfurized and reused as hydrogen to be added to the distillate hydrogenation zone 430 or the heavy oil hydrogenation zone 460, or both.

[0084] Light vacuum diesel 36, heavy vacuum diesel 38, and deasphaltized oil 80 are also preferably supplied to an integrated hydrogenation system 400 and hydrogenated under hydrogenation conditions in the presence of a catalyst to form a heavy vacuum diesel hydrogenation zone 460 spillway 70. Such hydrogenation treatment effluents contain substances within the following ranges: (1) natural naphtha with an expected boiling point range above C5 (compositions with 5 carbon atoms) to about 175°C (about 350°C); (2) ultra-low sulfur diesel, which is a heavy oil hydrogenation treatment zone first reduced sulfur flow, formed from a first portion of a treatment distillation vapor combination having a sulfur content of less than 10 ppm by weight and containing light vacuum diesel 36, heavy vacuum diesel 38 and deasphaltized oil 80; and (3) a second reduced sulfur flow, which is formed from a second portion of a treatment distillation vapor combination having a sulfur content in the range of 0.12 to 0.18% by weight and containing a sulfur content in the range of 0.12 to 0.18% by weight. It is known to those skilled in the art of hydrogenation that the by-products of hydrogenation in Zone 460 may include, at least a portion thereof, sulfur-containing gases such as hydrogen sulfide and hydrogen-rich-off gas, and typically small amounts of liquefied petroleum gas, which are desulfurized and reused as hydrogen to be added to distillate hydrogenation Zone 430 or heavy oil hydrogenation Zone 460, or both.

[0085] The untreated flow 10 and one or more hydrotreated liquid flows 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 flow mixing, blending, or other close combinations in the lines. In one modification, unstabilized as-is straight-run naphtha via lines 4 and 16 and a sulfur delimiter extraction via line 18 are combined in 100 without additional processing, and then a fuel combination is formed in 600 by combining one or more spills from distillate hydrotreatment zone 430, which includes as-is naphtha and ultra-low sulfur diesel, and one or more spills from heavy oil hydrotreatment zone 460, which has as-is naphtha, ultra-low sulfur diesel, and a second reduced-sulfur flow formed in heavy oil hydrotreatment zone 460. In other modifications, the hydrotreatment zone 400 combines the effluents of zones 430 and 460 to form a single flow (not shown) as if lines 60 and 70 were combined within such a zone. Such modifications are useful when it is undesirable to separate the effluents of the hydrotreatment devices 430 and 460. Preferably, the reduced-pressure diesel hydrotreatment section 460 has an overhead system flow and a bottom system flow, part of which is diesel boiling-range material. This may be in relatively small amounts compared to the combined diesel supplied to the combination 600 by zone 430 or 460, and the combined diesel side hydrotreatment section 430 also has a natural naphtha byflow, either as an overhead system flow or as part of a bottom system flow, containing low-sulfur diesel that is led to block 600 or used for trimming or other purposes.

[0086] The heavy residue 90 at the bottom of the deasphalter 300, which contains asphalt and metal-rich heavy residue, is supplied to an integrated gasification combined cycle system 500, which includes one or more gasifiers for partial oxidation of the heavy residue 90 in the presence of steam and oxygen and an optional carbon-containing slurry quench, to form synthesis gas, which is at least a portion of which is converted into hydrogen used in a hydrotreatment system 400, which includes a distillate hydrotreatment system 430 and a heavy oil hydrotreatment system 460 via line 502, and also the synthesis gas used to burn a gas turbine in a combined cycle power generation unit within the gasification system 500 for power generation within 504 for process and other applications, and further has a heat recovery generator for recovering heat from the high-temperature gas turbine gas, generating steam, which is sent via 504 for additional power generation, driving a steam turbine to generate electricity. Each gasifier also produces metal-rich soot. The soot may be in the form of particulate solids and may contain metallic contaminants derived from crude oil and / or heavy feedstock, which are supplied from each gasifier to metal removal via line 506. The support system includes one or more gas processing units, and all sulfur-containing gas flows from all unit operations, whether sour gas or acidic gas, are supplied to the gas processing units via 508 for sulfur removal. Preferably, such a sulfur removal system is part of a utility island, of which the gasification system is part. More preferably, one or more sulfur-containing gas flows are directed to commercial sulfur acid production as part of the overall sulfur removal. The gasification system 500 typically includes an acidic gas removal unit and a sour CO shift system, whose capacity and configuration are optimized to produce the required hydrogen from at least a portion of the raw material synthesis gas produced within the gasification system.

[0087] In a modified version of the integrated hydrogenation system 400 shown in Figure 2, the supplemental hydrogen-containing gas 502 from the gasification system 500 is compressed and heated in the amount required for hydrogenation, together with the internally reused hydrogen in the hydrogenation block 400, until it reaches an effective hydrogenation operating temperature, pressure, space velocity, and pressure adjusted based on a catalyst selected to achieve the desired level of desulfurization and demetallation, and other conditions known in the art. The hydrogen 502 thus prepared (together with the reused hydrogen) is first placed in the heavy oil hydrogenation zone 460, which is a high-pressure zone. The effluent from the heavy oil hydrogenation zone 460, containing the hydrogenation liquid and hydrogen-containing gas, is separated in a high-pressure separator (not shown), where the liquids are collected within zone 460, the hydrogen-containing liquid is recovered and sent through line 410 to the distillate hydrogenation treatment device 430 for use in hydrogenation in the low-pressure zone. The hydrogenated liquid and purge gas from the hydrogenation zone 430, containing sour and acidic gases, pass through line 412 into the heavy oil hydrogenation zone 460, where they are substantially mixed. The hydrogenated liquids 430 and 460 from both zones 430 and 460 are separated via lines 60 and 70 and may be separately fed into the combined fuel 600, added as a trim to control the sulfur level in the combined zone 600, or removed (not shown), depending on the requirements for the sulfur and other substance balance of the process. In the illustrated modified integrated hydrogenation system, the purge gas 420 from 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. Although not shown in Figure 2, various auxiliary high, medium, and low pressure gas-liquid separators, flow heaters, gas reuse and purge lines, reflux drums for separating gas or light components from liquids, compressors, cooling systems, and other auxiliary applications are known to those skilled in the field of hydrotreatment technology. Also, if located within the hydrotreatment zone rather than within a common utility island, the hydrotreatment zone 400 may include various amines or other sulfur recovery absorbers and stripping systems for sour gas or acid gas treatment.

[0088] The selection of the hydrogenation catalyst and the parameters for adjusting the process conditions of the hydrogenation zone 400 are within the technical scope of those skilled in the art engaged in the petroleum refining industry and do not require further explanation regarding the implementation of the hydrogenation sections of the present invention. In the reaction zones of the distillate hydrogenation apparatus 430 and the heavy oil hydrogenation apparatus 460, the hydrogenation catalyst used includes any catalyst composition useful for catalyzing the hydrogenation of hydrocarbon feedstocks to increase the hydrogen content and / or remove sulfur, nitrogen, oxygen, phosphorus and metal heteroatomic contaminants. The specific type of catalyst used and the various layer configurations, as well as the selected hydrogenation conditions, depend on the hydrocarbon product composition of each feedstock processed by each unit, as well as the sulfur and metal content and heavy carbon residues, and the desired reduction of sulfur and metal content in the product flow from each zone. Such catalysts can be selected from any catalyst useful for the hydrogenation of hydrocarbon feedstocks, but the operating conditions are adjusted to avoid or minimize ring saturation or hydrogenation in the implementation of preferred embodiments of the present invention. Patent Document 4 by Baldassari et al., incorporated herein by reference, describes a suitable hydrogenation process, including various integrated hydrogenation apparatuses, as well as various suitable hydrogenation catalysts. Baldassari et al. further summarize various catalyst compositions and condition ranges for distillation and heavy oil hydrogenation and identify conditions for hydrocracking and residue hydrogenation. All of these are known to those skilled in the art of hydrogenation. Non-Patent Document 8 describes a unit design, catalyst selection, hydrogen consumption, and other operating conditions for producing a product with sulfur removed by hydrogenation and with sulfur content below 8 ppm using a highly active Ni / Mo catalyst. Non-Patent Document 9 by Shiflet et al. also describes a hydrogenation process to reduce sulfur content to below 10 ppm using a highly active CoMo catalyst for removing sterically unhindered sulfur and a highly active NiMo catalyst for removing residual sterically hindered sulfur.

[0089] In other variations shown in Figure 2, the sulfur content of the feedstock 2 is measured by an analysis showing the exponential boundary points and rate of increase of the sulfur profile. For example, using a sulfur content boundary point and such profile in the range of 0.06–0.08 wt% (or higher, taking into account the relative flow rates and respective sulfur content of the untreated and hydrotreated vapors), the adjustment of atmospheric distillation 100 is controlled to maximize the available amount of unstabilized, as-is straight-run naphtha 16 and sulfur boundary point extracts 18, in which case the straight-run naphtha 16 and sulfur boundary point extracts 18 are combined and flowed by fluid mixing or blending, and produced without treatment. Available in the product accumulation zone 600, if necessary, the amount of (1) light distillate 24, intermediate distillate 26, first heavy distillate 28, or second heavy distillate 32 flowing into the distillate hydrogenation zone 430, or (2) the amount of light vacuum diesel 36, heavy vacuum diesel 38, or deasphaltized oil 80 flowing into the heavy oil hydrogenation treatment unit 460 is measured or reduced, and these flows are directed to hydrogenation in increased or reduced amounts to form a fuel product 600 in which the actual sulfur content is below the target sulfur content limit. In further variations, the analysis can be used to control the maximum amount of flow other than untreated, unstabilized, as-is straight-run naphtha 16 and untreated sulfur delimiter take-off 18 to determine the amount of flow toward hydrogenation and to form a fuel 600 in which the actual sulfur content is below the target sulfur content limit. In other words, various flow rates to the hydrogenation treatment 400, which are (1) the amount of light distillate 24, intermediate distillate 26, first heavy distillate 28, or second heavy distillate 32 flowing into any distillate hydrogenation treatment zone 430, or (2) the amount of light vacuum diesel 36, heavy vacuum diesel 38, or deasphaltized oil 80 flowing into the heavy oil hydrogenation treatment device 460, can be increased or decreased to adjust the sulfur content of the effluent 60 or 70 or both of the hydrogenation treatment zone 400 effluent that is mixed with the untreated flow 10 in 600.

[0090] In one modified example, a fuel product 600 in which the actual sulfur content is below the target sulfur content limit is formed by adjusting the sulfur level of the actual final product 600. The adjustment is made by increasing or decreasing the amount of one or more of the following into the combination zone 600: (a) unstabilized, as-is straight-run naphtha 16 or sulfur delimiter extract 18, which may contain sulfur because it has not undergone sulfur removal treatment; (b) flows into and out of the distillate hydrogenation treatment apparatus 430, such as treated light distillates 24, intermediate distillates 26, first heavy distillate 28, second heavy distillate 32; or (c) flows into and out of the heavy oil hydrogenation treatment apparatus, such as treated light vacuum diesel 36, heavy vacuum diesel 38, deasphaltized oil 80. Here, such adjustment is based on measuring the relative contribution of each flow 60 or 70 to the sulfur content of the combination 600.

[0091] In one embodiment, light-tight oil or condensate having a low metal content and a sulfur content below the target sulfur content limit level for fuel 600, or a combination of light-tight oil such as unassociated gas and shale gas production condensate, is used as follows: (a) feedstock for atmospheric distillation 100 or vacuum distillation 200, solvent separation 300, feedstock for any of light distillate 24, intermediate distillate 26, first heavy distillate 28, or second heavy distillate 32 to distillate hydrogenation treatment apparatus 430, or feedstock for any of light vacuum diesel 36, heavy vacuum diesel 38, or deasphaltized oil 80 to heavy oil hydrogenation treatment apparatus 460, (b) additional processing Without performing the above, the flow 10 formed from unstabilized as-is straight-run naphtha 16 and sulfur delimiter point take-off 18 is combined with one or more of the following: (c) a flow formed by a distillate hydrogenation treatment including as-is naphtha and ultra-low sulfur diesel; (d) a flow formed by a heavy oil hydrogenation treatment including as-is naphtha, ultra-low sulfur diesel and a second reduced sulfur flow; (e) a combined outflow 70 from a coupled hydrogenation unit 400 which leads to the final product fuel 600; or (f) another fuel which is added inside or outside the enclosure of the equipment producing such fuel, which is added to form the final product fuel.

[0092] In one modified example shown in Figure 2, the sulfur content of the fuel product 600 is adjusted by (a) supplying unstabilized, as-is straight-run naphtha 16 and sulfur delimiter extraction 18 to the combination 600 via line 10 without adding any further processing to such flow; then (b) adjusting the actual sulfur level of the product 600 by increasing or decreasing the amount of (1) the flow of light distillate 24, intermediate distillate 26, first heavy distillate 28 or second heavy distillate 32 to the distillate hydrogenation zone 430, or (2) the flow of light vacuum diesel 36, heavy vacuum diesel 38 or deasphaltized oil 80 to the heavy oil hydrogenation treatment device 460, or (c) then, if for any reason it is necessary to raise the sulfur content of the actual product 600 to a target sulfur level, the combination The sulfur content is controlled to be below the target sulfur limit level by (1) reducing the amount of one or more of the flow from the distillate hydrogenation zone 430 via line 60, which consists of light distillate 24, intermediate distillate 26, first heavy distillate 28, or second heavy distillate 32, or (2) reducing the amount of the flow from the heavy oil hydrogenation zone 460 via line 70, which consists of light vacuum diesel 36, heavy vacuum diesel 38, and deasphaltized oil 80, or (d) if for any reason it is necessary to reduce the sulfur content of the actual product 600 to the target sulfur level, by increasing the amount of one or more of the above-mentioned flow from the distillate hydrogenation zone 430 via line 60, or (2) increasing the amount of the above-mentioned flow from the heavy oil hydrogenation zone 460 via line 70. Such advancements enable the efficient production of multiple sulfur grades, for example, fuel supplies targeting less than 500 ppm by weight of sulfur for offshore and onshore gas turbines, or a variety of ranges for the same application in different locations requiring different target sulfur content.

[0093] In a modified example of using high-sulfur fuel oil having a sulfur content higher than the target sulfur content limit level of the final fuel in combination 600, the high-sulfur fuel oil is supplied to one or more of the respective unit operations as part of one or more different feedstocks. The high-sulfur fuel oil can be added to line 20 to the distillate hydrogenation treatment device 430, either (a) to the feed line 2 to atmospheric distillation 100 or to line 30 to vacuum distillation 200, or (b) to line 50 to solvent separation 300, or (c) separately, or in combination with one or more feedstocks of light distillate 24, intermediate distillate 26, first heavy distillate 26, or second heavy distillate 32 to the distillate hydrogenation treatment device 430, or (d) separately, or in combination with one or more of light vacuum diesel 36, heavy vacuum diesel 38, and deasphaltized oil 80, to line 40 to the heavy oil hydrogenation treatment device 460, thereby forming a fuel combination 600 in which the actual sulfur content is below the target sulfur content limit. It is known to those skilled in the art of refining that in one or more of these modifications relating to the use of high-sulfur fuel oil as a feedstock and the selection of its supply point, other factors relating to the nature of the supply of high-sulfur fuel oil, such as its sulfur content and asphaltene content, and its compatibility with co-processed crude oil or other feedstocks, container space and energy consumption, asphaltene content, content of undissolved components, gum formation, and other efficiency issues are taken into consideration.

[0094] In other variations, the clean fuel in the combination 600 zone is formed by adding a high-sulfur fuel oil, which may have a sulfur content higher than the target sulfur content limit level, to one or more of the following: (a) a flow 10 formed from unstabilized, as-is straight-run naphtha 16 and sulfur delimiter take-off 18, which are not further treated depending on the sulfur content of the high-sulfur fuel oil; (b) a flow 60 formed by a distillate hydrogenation treatment device 430 containing as-is naphtha and ultra-low sulfur diesel range substances; or (c) a flow 70 formed from a heavy oil hydrogenation treatment device 460 containing as-is naphtha, ultra-low sulfur diesel and a second reduced sulfur flow, or a combination spill 70 from the hydrogenation zone 400.

[0095] In one preferred modification using high-sulfur fuel oil in the preparation of the fuel composition 600, the sulfur content of such high-sulfur fuel oil is measured, and then the high-sulfur fuel oil is supplied to a solvent separation unit as part of the feedstock 50 to form part of the deasphaltized oil flow 80, or as part of the feedstock 20, combined with one or more distillation flows of light distillate 24, intermediate distillate 26, first heavy distillate 26, or second heavy distillate 32 and supplied to a distillate hydrogenation treatment device 430. Alternatively, one or more of the light vacuum diesel 36, heavy vacuum diesel 38, and deasphaltized oil 80 flows, or a combination of both the distillation flow and the heavy oil flow, may be used to form part of the feedstock for the distillate hydrogenation treatment device 430 or the heavy oil hydrogenation treatment device 460, or both, depending on the sulfur content of the high-sulfur fuel oil, thereby optimizing the adjustment of the hydrogenation treatment conditions in zone 430 or 460, or adjusting both zones to form a fuel in which the actual sulfur content is below the target sulfur content limit.

[0096] In other embodiments of the present invention, clean fuels whose specifications are below the sulfur content limit can be formed by the use of heavy residue oils, which are typically atmospheric residues or heavier and may include high-sulfur fuel oils that have a density or sulfur or metal content outside the specifications of high-sulfur fuel oils or within standard specifications. Due to market considerations, such heavy residue oils are often available from sources other than those within the battery limits of fuel plants. Heavy residues having a sulfur content higher than the target sulfur content limit level of fuel 600 are supplied to one or more of the following: (a) a vacuum distillation column 200, which is supplied to the distillation column 200 separately or in combination with atmospheric residue via line 30 to produce at least a portion of any or all of the second heavy distillate 32, light vacuum diesel 36, heavy vacuum diesel, or vacuum residue 50; or (b) a solvent separation 300, which is supplied separately or in combination with the vacuum residue feed to the solvent separation 300, which forms at least a portion of the deasphaltized oil 80, or a pitch 90 having metal-rich heavy residue that passes to the gasification system 500 for gasification, sulfur recovery, and other auxiliary treatment. Such heavy residue oil may also be supplied to the utility island 500 in combination with pitch via line 90. In a modified example, when using untreated high-sulfur fuel oil having a relatively high sulfur content (more than 0.5% by weight) or high metal content without performing any trimming treatment to adjust the sulfur content of fuel 600 according to the present invention, such use would result in a relatively small adjustment amount if used without any treatment to ensure that combination 600 does not exceed the target sulfur content limit.

[0097] The flow sheet in Figure 2, which shows various intermediate individual products, is for the purpose of explaining and understanding 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 selected crude oil and feedstock, as well as the optimization of 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 Figure 2, then both effluents 60 and 70 from hydrotreatment equipment 430 and 460 can be combined in hydrotreatment zone 400 by the use of a common gas-liquid separator (not shown), with only the gas being removed. Alternatively, if the process objective is the separation or removal of some of the raw naphtha or ultra-low sulfur diesel for trim control of the sulfur content of the fuel in the final combined zone 600 or for other reasons, effluents 60 and 70 from hydrotreatment equipment 430 and 460 may be sent separately or combined to a stripper or distillation column so that fractions of raw naphtha or ultra-low sulfur diesel can be removed.

[0098] While various embodiments of the present invention have been described, it should be understood that these are merely illustrative and not limiting. For example, if the flash point of the fuel is not considered, an untreated lighttight oil or condensate, or a combination of untreated lighttight oils or condensates having a low metal content and a sulfur content below the target sulfur content, may be added as part of the combination of the untreated fraction and the treatment flow to form a fuel in which the actual sulfur content is below the target sulfur content. As used herein, the terms “lighttight oil” or “LTO” mean source condensates or shale gas condensates having (i) a sulfur content in the range of 0.1% to 0.2% by weight, (ii) a density in the range of 38 to 57 degrees on the API (degrees), and (iii) a broad hydrocarbon range depending on the source. LTO typically has an overlapping expected distillate extraction fraction range, as weight percent of the total volume, consisting of (a) 5–20 wt% liquefied petroleum gas, (b) 10–35 wt% naphtha, (c) 15–30 wt% kerosene, (d) 15–25 wt% diesel, (e) vacuum diesel, and (f) zero (0%)–10 wt% heavy residue.

[0099] In one modification, the present invention co-processes (i) crude oil having the quality of untreated light-tight oil or condensate, or a combination of light-tight oil or condensate, with (ii) one or more other crude oil feedstocks, by the method of the present invention, for example, when the available oil has a production area outside the battery limit of the combustion production plant of the present invention, to produce a low-cost fuel having a low metal content and a sulfur content below the target sulfur content. Such light-tight crude oil is likely to not contain sufficient heavy hydrocarbons in the bottom fraction (e.g., 0% or very low heavy residue), the range of residue does not provide a treatment balance for desulfurization or other hydrogenation treatment, and the corresponding residue is not sufficient to support a hydrogenation process to cost-effectively hydrogenate such light-tight crude oil to decontaminate by reducing sulfur and metals, or to provide sufficient lubricity to support use in certain types of engines.

[0100] Embodiments of the novel fuels of the present invention are better understood by referring to the ISO 8217 standard issued by the International Organization for Standardization (ISO). ISO 8217 describes a set of categories and detailed specifications for marine residual fuels for onboard consumption. These specifications recognize that crude oil supply, refining methods, and other conditions vary considerably as the basis for their development. Such specifications suggest that various international requirements for properties such as sulfur content are taken into consideration. The most stringent version of ISO 8217 at present is RMA 10, and the interpretation of the specification and claims should be based on this. Based on simulated compositions of the novel fuels of the present invention (prepared by a simulation model in which crude oil is divided into fractions, a portion of the fractions is hydrogenated, non-solvent residues are removed during solvent separation, and then the untreated and treated portions are reconstructed), the inventors assert that these novel fuels conform to and / or exceed all ISO RMA10 specifications except for the flash point, and that the flash point falls under the SOLAS exception to the flash point requirements for cargo ships, and that these fuels have novel characteristics and improvements that distinguish them from marine fuels consisting of the above-mentioned residues.

[0101] In one modification, the inventors provide an improved fuel that conforms to or exceeds all ISO RMA10 (ISO2817-10) specifications except for the flash point, and has any or all of the following notable features: (a) sulfur content of 0.50% m / m (weight%) or less, preferably in the range of 0.05 to 0.20 m / m (weight%), (b) metal content of 5.0 mg / Kg (weight ppm) or less, preferably 1.0 mg / Kg (1.0 weight ppm) or less, for example, 0.2 mg / Kg (0.2 weight ppm), and (c) a flash point of 60°C or less, and features superior to other ISO RMA10 specifications. In a modification, these novel fuels further have the following notable features: (a) viscosity of 10 cSt or less, (b) pour point of 0°C or less, and (c) viscosity of 820 to 880 kg / m 3The fuel has one or more of the following: (d) a density within the range of (i) 800 or less CCAI, and (e) 20 mg / kg or less sodium, preferably 10 mg / kg or less. All of the above are measured by the test or calculation methods specified in ISO 2817-10. Such fuels contain a range of hydrocarbons having the highest boiling point of the component with the highest boiling point among the components soluble in solvents suitable for solvent separation, such as naphtha and heptane. The metal can be reduced to 100 ppb by weight, depending on the composition of the feedstock and adjustment of the operating conditions.

[0102] The inventors have discovered that it is possible to produce fuel with extremely low sulfur and metal content that meets the SOLAS exception for flash point requirements for cargo ships at low cost. Flash point treatment for other applications requiring a flash point of 60°C or higher, or for such requirements, is known in the art.

[0103] The low viscosity, low pour point fuel of the present invention, when used in marine engines, avoids or reduces the energy consumption required in connection with the heating of conventional residual oils, enabling pumping and handling at refueling stations in ports or at sea. Heavy residual oils are concentrated and, due to their relatively high pour point and high viscosity, must be heated and kept at high temperatures throughout their storage, pumping, and supply to marine engines, and such heating consumes energy.

[0104] Table 1 below shows two variations of the fuel of the present invention, namely one with an extremely low sulfur content of 0.1% by weight and one with a further reduced level of 0.05% by weight, and the sulfur content compared to ISO RMA10 is shown in Table 1 below.

[0105] [Table 1]

[0106] Such fuels of the present invention, having the characteristics shown in Table 1, are further distinguished in that they comprise substantially the entire range of crude oil-derived hydrocarbons from C3 or C5 to C20 or higher, the initial boiling point of the hydrocarbon being the lowest of the boiling points of any fraction of the crude oil under atmospheric distillation conditions, and the highest boiling point being the endpoint of the residual portion of the crude oil that does not dissolve in a solvent suitable for solvent separation. In contrast, the residue is limited to very heavy substances, such as vacuum distillation residues, solvent deasphaltization residues, and other cokers, which do not contain such a wide range of hydrocarbons.

[0107] From the disclosures of this specification and claims, the present invention enables the production of ultra-clean fuels that not only meet or exceed the standards of compatibility with current offshore reciprocating engines, but also have compatibility with advanced combustion gas turbines usable for offshore applications. Such advanced turbine engines are currently available, but are typically for land use. Once started on board, these advanced turbine engines can achieve significant efficiency advantages by burning the fuels of the present invention during voyages, while minimizing corrosion or ash formation. Furthermore, depending on the fuel economy available in the port, ships can gain efficiency advantages by burning these new fuels in port, generating electricity, and supplying that power to the local power grid for revenue. Revenue from such port power generation can offset offshore fuel costs, bringing the actual total offshore fuel costs to a level below that of high-sulfur fuel oil, and thus offsetting the cost of use even if the low-sulfur fuels of the present invention are more expensive voyage fuels. The greatest benefit is to the environment, where, in comparison to specific normative cases, it is possible to reduce SOx and NOx emissions by more than 95%, and potentially reduce emissions of harmful metals during voyages by more than 99% (almost 100%). Furthermore, the environment gains two benefits from the CO2 reduction: (i) increased efficiency of advanced gas turbine engines on board ships, and (ii) increased efficiency of power generation in ports, as inefficient combustion of coal, crude oil, residual oil, or certain other fuels is replaced. [Industrial applicability]

[0108] Thus, the present invention is broadly applicable to the production of fuels with reduced levels of sulfur and other contaminants and to the use of such fuels. Certain features may be modified without departing from the spirit or scope of the invention. Accordingly, the present invention is not limited to the specific embodiments or examples described, but is limited to the appended claims or substantially equivalent thereto.

Claims

1. A method for converting crude oil containing sulfur and metals, The crude oil is separated into flows based on its sulfur content, one or more liquid fractions of the separated flows are treated to remove sulfur, while the other fractions are left untreated, and then the treated fractions and most of the untreated fractions are remixed as a combined fuel (600) to form a liquid fuel with a sulfur content less than or equal to a target sulfur content. The aforementioned method, (a) A step of separating the crude oil (2) into the following fractions by one or more distillation steps (100, 200), The aforementioned fraction is (a) (1) Liquid fraction below the sulfur boundary (10), (a) (2) A liquid fraction (20, 30) higher than the sulfur delimiter, The liquid fraction (20, 30) above the sulfur boundary includes (i) a fraction soluble in the solvent used for solvent separation, and (ii) a metal-containing fraction including a fraction insoluble in the solvent used for solvent separation, in a step, (b) A step of supplying the metal-containing fraction to a solvent separation (300) step to remove metal-rich residue (90) that is insoluble in one or more solvents used for the solvent separation, (c) A step of treating the liquid fraction with a sulfur content higher than the sulfur boundary point, which is soluble in the solvent used for solvent separation, by one or more hydrogenation steps to form one or more hydrogenation flows (60, 70) having a reduced sulfur content, (d) A step of combining the hydrogenation treatment flow (60, 70) with the liquid fraction (10) below the sulfur delimiter to form the combined fuel (600), A method characterized by including

2. The method according to claim 1, wherein one or more of the separated flows are ultra-low sulfur flows having a sulfur content of 10 ppm by weight or less, and the sulfur content is controlled by increasing or decreasing the amount of the ultra-low sulfur flows relative to the combination so that the sulfur content is below a sulfur threshold which is a target sulfur content, thereby adjusting the formation of the fuel.

3. The method according to claim 1, comprising only four main unit operations consisting of one or more atmospheric distillation and vacuum distillation, solvent separation, and hydrogenation, and having no hydrogenation process downstream of the hydrogenation process except for auxiliary equipment necessary for combustion of residues, generation of hydrogen, generation of process utilities, and capture of metals and sulfur, and all sulfur-containing gases being sent to one or more sulfur recovery units.

4. The method according to claim 1, wherein the combined fuel is formed by combining the lowest boiling point portion of the combined fuel, which is the untreated lowest boiling point portion of the liquid fraction (10) below the sulfur boundary point, and the highest boiling point portion of the combined fuel, which is the treated highest boiling point portion of the liquid fraction that is soluble in the solvent used for solvent separation and is above the sulfur boundary point.

5. The method according to claim 1, wherein the residue (90) is burned in one or more gasifiers to generate at least a portion of the hydrogen for power generation and the hydrogenation process, and to capture at least a portion of the metal of the gasifier solid to be removed.

6. The residue (90) is burned in one or more boilers and used for auxiliary hydrogen generation unit operations for power generation and hydrogen supply for the hydrogenation process. The method according to claim 1.

7. The nearly entire amount of the aforementioned crude oil is converted into essentially one liquid fuel product, At least one of the hydrogenation treatment flows is an ultra-low sulfur flow having less than 10 ppm by weight of sulfur, The method according to claim 1, wherein the untreated fraction has a sulfur content exceeding the sulfur boundary, and is used as an adjustment amount to control the adjustment of the sulfur content of the combined fuel by increasing or decreasing the amount of the untreated fraction relative to the combined fuel, thereby forming a fuel with a sulfur content less than or equal to a target sulfur content.

8. The aforementioned crude oil is converted into essentially one liquid combination fuel product, At least one of the separated flows is a hydrogenated first reduced-sulfur flow having a sulfur content of 10 ppm by weight or less. At least one of the separated flows is a hydrogenated second reduced-sulfur flow having a sulfur content of 0.12 to 0.18% by weight. The (a)(1) liquid fraction (10) below the sulfur boundary is an untreated fraction having a sulfur content that exceeds or falls below the target sulfur content. The method according to claim 1, wherein at least one of the first reduced sulfur flow or the second reduced sulfur flow is used as an adjustment amount to control the adjustment of the sulfur content of the combined fuel by increasing or decreasing the amount of the flow relative to the combined fuel, thereby forming a fuel in which the sulfur content is less than or equal to a target sulfur content.

9. The method according to claim 1, wherein at least 70% by volume of the crude oil is used to form a single combined liquid fuel product.

10. The method according to claim 1, wherein the sulfur content of the fuel is adjusted to meet the IMO specifications for marine fuel as the target sulfur content.

11. The method according to claim 1, wherein high-sulfur fuel oil is added to one or more of the crude oils, or supplied separately to one or more of the distillation step, the solvent separation step, or the hydrogenation step.

12. A fuel is formed by combining crude oil having untreated light-tight oil, condensate, or a combination of light-tight oil or condensate with one or more untreated fractions or fuel formed by a hydrogenation flow. The method according to claim 1, wherein the light-tight oil has a sulfur content in the range of 0.1% to 0.2% by weight and a density in the range of 38 to 57 degrees on the API (degrees), and the untreated fraction comprises (a) 5 to 20% by weight of liquefied petroleum gas, (b) 10 to 35% by weight of naphtha, (c) 15 to 30% by weight of kerosene, (d) 15 to 25% by weight of diesel, (e) vacuum diesel, and (f) zero (0%) to 10% by weight of heavy residue.

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