JP7596352B2 - Method for providing on-board generated electricity to a land-based power grid - Patents.com - Google Patents

Description

The present invention relates to a method and apparatus for producing very low sulfur fuels from crude oil, refinery residuals and other contaminated liquid feeds. The very low sulfur fuels produced by the present invention are particularly cost effective for use on board large ocean-going vessels and for large land-based combustion gas turbines on land.

The present invention targets a long-known but heretofore unsolved major environmental problem: the delivery of sulfur, nitrogen and metal oxides into the natural environment when "off the high seas" ships burn cheap low-grade heavy bunker oil and other heavy residuals high in sulfur, nitrogen and metals. Such emissions are global in scale and extend regardless of national geographic boundaries.

According to various third party reports, the specific global emissions resulting from the burning of heavy fuels for such waterborne transport at sea are many times higher than all of the world's land-based gasoline-burning and diesel-burning vehicles combined. Such burning at sea emits SOx, NOx, _CO2 , soot and harmful metals. Land vehicles include cars, trucks, etc., many of which now use mandated "highway fuels" that have very low sulfur content. Thus, even if such large vessels are efficient based on "loads per mile" and fuel consumption standards, in practice, such vessels generate large amounts of emissions.

The introduction of certain significant regulations mandating the use of cleaner burning marine fuels on ships is conditional on such fuels being provided in sufficient and usable quantities. A solution is still needed to avoid mandating things that are neither technically nor economically possible nor practical.

For example, the International Maritime Organization (IMO), a division of the United Nations, issues regulations for international shipping. While recognizing technical constraints, the IMO has sought to reduce emissions by imposing stricter sulfur limits on marine fuels. The IMO requires that marine fuels burned on the high seas (e.g., outside Emission Control Areas (ECAs), which include the United States, Europe, and other areas 200 nautical miles from the coast) after 2011 must have a sulfur content not exceeding 3.50% m/m. In 2015, the IMO revised its regulations to generally limit the sulfur content of marine fuels to less than 0.1% for commercial ships within ECAs.

However, the IMO has again significantly lowered the open sea sulphur limit to 0.50% m/m for 2020 and beyond. However, the IMO has stated that such an aggressive reduction in 2020 is contingent on "the outcome of the review of the availability of the required fuel oil, due to be completed by 2018", suggesting that such reductions may be postponed to 2025 if the required fuel is not available. For the regulation of air pollution in the maritime industry, see the International Convention for the Prevention of Pollution from Ships (MARPOL), Annex VI.

Thus, there is a real and significant potential for problems to arise 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 sulfur content permitted in fuels below the [2014] levels required for emission control areas... but this will take many years as current technology would make it cost-prohibitive for many shipping companies." The publication further stated that "because of the extra costs and possible mechanical problems, these regulations are being continually reevaluated and a phased approach to implementation is being taken" because "many marine engines are not designed to handle low-sulfur diesel, which is much thinner than heavy fuel oil and does not have the lubricating properties of heavy fuel oil. Companies are trying to make it work with various workarounds, such as cooling the fuel to increase its viscosity or injecting additional lubricants into certain parts of the engine" (Non-Patent Document 1).

As another example, in 2015, IMO regulations lowered the sulfur content of marine fuels to a maximum of 0.1% sulfur for commercial ships within designated ECAs. Before entering an ECA, ships must change from the high-sulfur heavy bunker fuel oil burned in the open seas, which is high in sulfur but inexpensive, to more expensive low-sulfur fuels similar to highway diesel fuel. The reduction in fuel sulfur from 1.00% m/m (since July 1, 2010) to 0.10% m/m within ECAs since January 1, 2015 has created market supply and pricing challenges. The production and supply of marine fuels for IMO-related compliance competes with distillate fuel demand for highway and other land-based diesel applications, shifting available preferred feed streams, and existing refineries and feed supply networks, away from highway uses of diesel and other low-sulfur distillates. Other technical issues arise on board.

Regarding the 2015 IMO reduction in sulfur content in ECAs, the U.S. Coast Guard has warned that "vessels using higher sulfur content fuels must change to ultra-low sulfur (ULS) fuel oil to meet the new regulations." Because vessels must use ULS fuel oil during homebound and outbound voyages, at dock, and at all times within ECAs, vessels using high sulfur content fuel oil must develop and implement changeover procedures to switch between residual and distillate fuels before entering ECAs. The Coast Guard further warns that "there are a number of other significant technical challenges associated with the use of ultra-low sulfur fuel oil and fuel oil changeover that are mentioned in documents prepared by classification societies, insurance companies, engine manufacturers, and industry associations," and that "the energy content per unit volume of ULS fuel oil may differ from that of residual fuel, such that existing throttle settings may not provide the desired propeller shaft RPM or generator load" (Non-Patent Document 2).

The hard 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 investments. In 2003, a refinery evaluation study in Europe was conducted looking at the need to reduce pollutants in marine fuels, and the requirements and capabilities to produce the required quantities of such fuels. See, for example, "European refinery evaluation study: a review of marine fuels and their potential applications," Marine Fuel and Marine Products, vol. 14, no. 1, pp. 111-115, 2003.

These reports have highlighted significant challenges in many countries, including rising costs and declining refinery utilisation in producing the required quantities of suitable marine fuels, as well as in some cases the lack of local infrastructure near major ports to manufacture and supply such marine fuels locally, and the lack of technology and equipment to make such fuels.

The cited report found only three options. The "re-blending option" (blending heavy fuel oil into low-sulphur fuel) was considered as the lowest-cost option to produce low-sulphur bunkers, but was not suitable as it would only process the smallest amount of material without incurring significant costs. This option was relatively low-cost in terms of logistics for the reformulation of different categories of heavy fuels currently produced in European refineries, but failed in terms of volumes.

The second, more costly option would be to process low-sulfur crude oil by replacing high-sulfur crude oil, such as Arabian Light, which is reported to contain 1.8% sulfur, with a low-sulfur crude oil, for example an African crude oil, such as Bonny Light, which is reported to contain 0.14% sulfur by weight. The estimated incremental costs of offshore bunkering incurred by this option were deemed excessive for reasons stated in the report.

Finally, the older report presents the third and most expensive option for producing low-sulfur marine grade fuels, using 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, bottom-of-the-barrel hydrotreating (residual desulfurization) is not a process that refiners are currently considering implementing unless it is combined with some conversion of the residual to lighter products. Nevertheless, if VRDS were pursued for the sole purpose of desulfurizing the vacuum residue, the cost of this option would be about twice that of the second option, making it even less acceptable."

To meet the IMO requirements, the prior art allows ship operators to load both high sulfur content fuel oil for marine use and low sulfur content for use in ECAs, but this choice can face problems with respect to engine technology, lubricity, and possible needs for different fuel injection systems for optimal operation and fuel switching mechanisms. Ship operators can add relatively large, expensive and complex post-combustion flue gas treatment equipment to maintain the highest performance levels. In some cases, the use of liquefied natural gas (LNG) as ship fuel is considered. In that case, for example, LNG carriers can choose to use "vapor gas" as fuel, but extending this LNG engine concept to all cargo ships would require widespread use of very expensive LNG fueling stations and would impose additional costs on ports in regions that do not have local natural gas production supply or liquefaction facilities. However, in all cases, the use of LNG instead of liquids creates real risks of leaks due to ventilation during bunkering or incomplete combustion, or methane emissions during operation and maintenance. Such methane emissions are a concern because methane is considered by some to have many times the greenhouse gas impact on the environment as sulfur dioxide. In a similar vein, some argue that emissions reductions in marine applications can be achieved by burning natural gas during ship transit or while in port with gas supply docking stations. However, from a technical standpoint, natural gas has methane leakage issues, 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 during the process of liquefying LNG and reduces the _CO2 emissions during the recovery and replacement of coal to fire the power plants that supply ships in port. Development activities promoting the replacement of LNG or natural gas with liquids as marine fuels should be considered, but do not provide a practical cost-effective marine solution in the absence of a global gas infrastructure and the need for new refueling infrastructure. Gas supply infrastructure represents a severe equipment and capital investment in ports in countries without local gas production supply.

US Patent No. 8,2009, by Lenglet, describes a method for pre-purifying crude oil to produce two non-asphaltene oils and the production of multiple products with pre-distillation, vacuum distillation, solvent deasphalting, hydrotreating, hydrocracking and residue hydroconversion of asphaltene oils. Non-Patent Document 4 describes the unit design, catalyst selection, hydrogen consumption and other operating conditions for removing sulfur by hydrogenation and producing a product with less than 8 ppm sulfur by using a highly active Ni/Mo catalyst. Non-Patent Document 5, page 6, Advanced Refining Technology, Catalagram Special Edition Publication No. 113/2013 also describes hydrotreating to remove unhindered sulfur using a highly active CoMo catalyst and the remaining sterically hindered sulfur to 10 ppm by using a highly active NiMo catalyst.

However, a gap has long existed in effective fuel production technologies creating a supply shortage of low-cost, high-volume ultra-low sulfur marine fuels. There remains a need to fill this gap.

The International Energy Agency (EIA) Petroleum Industry and Markets Division publishes public documents describing the process and equipment configurations used to produce fuels and describing conventional refinery configurations, products, and margins. Terms used herein have the meanings assigned to them in the International Energy Agency's Petroleum Industry and Markets Division, unless otherwise defined or expressly modified, and are incorporated herein for all purposes. EIA publications define and discuss configurations for processing crude oil and splitting each barrel of crude oil feedstock into multiple products for different uses or downstream processing.

The genetics of traditional refinery development and growth have been somewhat primordial, based on the evolution of society's product needs, progressing from a basic kerosene grade distillate for lighting, to multiple products such as gasoline and diesel for automobiles, then aviation grade fuels, and then feedstocks for many downstream chemical applications. All refinery technological developments, while retaining the production of multiple products for various end uses, typically appear to have evolved in stages, guided to adapt to either maximizing a given fraction obtained from each barrel of crude oil for a particular market segment, or to accommodate the various refinery streams for downstream chemical products.

Thus, prior art refinery designs that use atmospheric crude and/or vacuum distillation units, solvent separation, hydrotreating, gasification and many other unit operations split each barrel of crude oil feedstock into multiple products with different specifications, each for a different use or downstream processing.

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

Within the range of conventional refining processes are "upgrading", "topping" or "hydroskimming" facilities. For crude oil upgraders, the primary objective is typically to convert very heavy, viscous or solids-laden material to a lighter, flowable material that can be reprocessed in existing conventional refineries that process the lighter, flowable material to make a full range of fuel products, chemical feedstocks and/or petroleum coke. The upgrader simply converts heavier crude oil to lighter crude oil for feed to conventional refineries that are specifically designed to process sulfur to meet the respective downstream product specifications; sulfur reduction or metals removal is not the primary objective of the upgrader. The goal is to upgrade a feedstock that has a very high density compared to the typical lower density crude feedstock. The heavier material is rejected or separated from the feed material and the resulting density of the upgraded product material approaches that of the crude oil processed by the existing conventional refinery configuration. As for topping or "mini" refineries, they are often located in remote or opportunistic locations of the crude oil source. Topping refineries typically split each barrel of crude oil feedstock into multiple straight run fractions targeting naphtha rather than gasoline production with no or minimal subsequent processing, except in some limited cases naphtha reforming for gasoline octane enhancement and hydrotreating multiple distillates to produce various products. The objective of a typical topping refinery is to produce a wide range of directly usable fuels such as gasoline, kerosene, diesel, and fuel oil for consumption in the local market. Some undesirable topping practices and uses of the topping products or failure to properly address residuals can increase rather than reduce harmful emissions to the environment. Hydroskimming 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 hydrotreater in diesel production. Hydro skimmers typically produce a wide range of gasoline, kerosene, diesel and fuel oil for local consumption, rather than just one product, as topping refineries do.

Various aspects of adapting hydroprocessing are known in the art, including having separate series or parallel hydroprocessing reactor zones or integrated hydroprocessing reactor zones. U.S. Patent No. 6,233,933 to Cash et al. and references cited therein disclose integrated hydroprocessing of different feeds, where hydrogen-containing and liquid-containing streams from separate hydroprocessing zones are distributed or combined by the disclosed method. Various aspects of the use of solvent separation to extract deasphalted oil from pitch in heavy residual streams and use the deasphalted oil as a feedstock for hydroprocessing are known in the art when used to produce multiple product streams. For example, U.S. Patent No. 6,233,933 to Brierley et al. describes solvent deasphalting for the production of deasphalted oil without cracking or decomposition by separation of the feed based on solubility in liquid solvents such as paraffinic solvents up to heptane, including propane, butane, pentane and heptane. The remaining pitch contains high metal and sulfur contents. The deasphalted oil can be hydrotreated to remove sulfur, nitrogen, carbon and metals as described in the references for the production of several products including naphtha, kerosene, diesel and residual materials.

The global market requires the availability of large quantities of fuels that are low in sulfur and nitrogen and essentially free of metal contaminants to address global environmental concerns on the high seas and on land locations that have little or no natural gas resources and use high sulfur fuel oil or unrefined crude oil for power generation with low efficiency.

Fuel producers require different designs than those developed for traditional refineries that produce multiple product slates. To keep costs low, designs must be equipped with only the equipment necessary to produce large quantities of clean fuel in a cost-effective, thermally efficient manner, in a way that limits capital investment. Such designs should be targeted primarily at producing marine fuel, rather than extracting a relatively small fraction of each barrel of crude oil for marine fuel and using the majority of the barrel for other uses.

What the world needs is a "game-changing" new process that provides a solution to the technical problem of how to make large quantities of relatively clean liquid fuel (in an efficient form to avoid wasting energy expressed in short forms such as British Thermal Units (BTUs)) in an economical way for marine applications. Such a process would allow existing liquid marine fueling stations (e.g., those serving high sulfur fuel oil (HSFO)) spread around the world to be used for fuel distribution instead of building new infrastructure for LNG, thus minimizing the facilities required and the associated capital and operating costs. Any such new process would need to be directed in favor of making liquid BTU in a cost-effective manner that is superior to ultra-low sulfur diesel (ULSD) produced primarily for cars and trucks. Although such usable diesel is widely available, it is not widely used at sea by large ocean carriers due to cost issues and lubricity issues that arise when ULSD is used in many existing marine diesel engines.

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

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

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

In conventional refining, a crude oil feedstock is broken down into many parts, with each part being sent downstream to a separate market channel. In contrast, the inventors have discovered that the maximum amount of each barrel of crude oil feedstock can be converted into a single ultra-clean fuel while capturing the contaminants sulfur, nitrogen and harmful metals, except for the crude oil part that provides the process utilities and streams for conversion and capture. The present invention breaks down the crude oil feedstock into only the minimum number of parts necessary to capture and control the contaminants, and then reassembles the parts to form a single fuel product.

Thus, the present invention differs from conventional refining, where each barrel of crude oil feedstock is split to serve multiple markets, such as gasoline, diesel, fuel oil, or feedstock for downstream chemical production or applications, in that the method of the present invention is directed to producing a primary clean fuel product. The present invention provides a low-cost polishing system for unrefined and residual oils that is needed to produce large commercial quantities of clean fuels to replace high sulfur bunker fuels and other heavy residuals used in commercial shipping and power plant combustion systems. The present invention provides such fuels and methods and apparatus for making the fuels to reduce sulfur in a cost-effective manner.

These new processes use counterintuitive steps to lower production costs while controlling the final product sulfur content below target sulfur levels in a surprisingly effective manner. The present invention provides a new way to convert the maximum amount of each barrel of crude oil feed into a single ultra-clean fuel while simultaneously capturing polluting sulfur, nitrogen and harmful metals during fuel production.

In many variations of the present invention, essentially all of each barrel of feed, characterized in certain variations as 90% by volume or more, is converted to 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 streams for pollutant conversion and capture. The process of the present invention allows for adjustments in the proportion of feedstock allocated to fuel production and the proportion of feedstock allocated to process utilities and streams for pollutant conversion and capture for purposes of hydrogen balance, local demand for asphalt, coke and other residual products, overall production economics, and other operational considerations such as the local availability of alternative low-cost process fuels and power. In variations, at least 70% by volume of each barrel of crude oil feed is converted to liquid fractions that, when subjected to further processing or when blended unprocessed, form substantially one liquid fuel product having a sulfur content not exceeding a target sulfur content rather than multiple hydrocarbon products, with the remaining portion of each barrel of the crude oil feed being present in the residue or other vapors or products.

Unlike conventional refining, where a crude oil feed is separated into multiple portions and sent to separate market channels, the present invention separates the crude oil feed into the minimum number of portions necessary to capture and control contaminants, and then reassembles the portions 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 allows for the low sulfur fuel required for regulatory compliance in large scale offshore and onshore turbine applications to be produced in large quantities, at low cost and efficiently. These novel fuel deployments have substantially lower capital and operating costs than alternative conventional crude oil refineries, thereby allowing for the mass production of very low sulfur and nitrogen content and essentially no metals content fuel in an extremely cost-effective manner. These novel processes allow for a very cost-effective means of simplifying the energy supply chain from the oil field to the marine engines or onshore power plants.

For the shipping industry, the novel configuration of the present invention provides low-cost, low-sulfur marine fuel in the quantities necessary to meet global marine sulfur reduction goals. The novel fuel production method and arrangement of the present invention has substantially lower capital and operating costs than conventional crude oil refining, thereby producing large volumes of marine fuel that are very low in sulfur, essentially metal-free, and very low in nitrogen in an extremely cost-effective manner.

The fuel of the present invention replaces low grade heavy bunker oils that are high in sulfur and metals, significantly reducing the emissions of SOx, NOx, _CO2 , soot and harmful metals into the open sea. Instead of sulfur and metals being carried to the environment during the combustion of bunker oil, in the practice of the present invention, sulfur, nitrogen and metals are captured and removed during combustion production in an environmentally friendly manner. In some embodiments, the present invention provides certain low sulfur alternative fuels at a lower cost than diesel, but which have sufficient lubricity to avoid excessive wear on marine engines, and these new fuels can use existing bunkering fuel infrastructure without heating the fuel to make it flowable, reducing the energy consumed to heat the fuel in tanks onshore or on board ships, compared to other alternative fuels.

In one variation, the fuels of the invention also provide an alternative to burning crude oil or heavy residuals in large land-based combustion turbines located in facilities such as single-cycle or combined-cycle power plants, such as those producing electricity and desalinated water. Turbines burning the fuels of the invention have significantly lower turbine exhaust emissions of NOx, SOx, _CO2 , soot, toxic metals and other combustion by-products, and, depending on the source, less pollution under hot zone corrosive or ash-forming conditions when burning contaminated heavy crude oil or refinery residuals.

The present invention relates to the centralized conversion of complex hydrocarbon feedstocks into a single fuel product for use in combustion applications such as marine engines, combustion gas turbines or fired heaters. In a basic embodiment of the invention, crude oil enters up front and returns a single ultra-clean product fuel with controlled low sulfur levels, reduced nitrogen and metals removed. In a variant, the feed for distillation can be one or more crude oils combined with one or more high sulfur fuel oils or other heavier residual oils, with further addition of light tight oil or high sulfur fuel oil, or both, as part of the stream feed to one or more other unit operations such as vacuum distillation, solvent separation, hydrotreating or gasification.

In other applications in the art, the term "high sulfur fuel oil" or "HSFO" has 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 material used as a fuel having a sulfur content greater than 0.50% m/m (0.5% by weight). As used herein, the terms "heavy oil," "heavy residual oil," "resid," "residual," or "other heavier oils" include petroleum-derived hydrocarbon-based materials having a sulfur content greater than 0.50% m/m (0.5% by weight). The term "high sulfur" means above the target sulfur content limit or, where applicable, the statutory sulfur limit, whichever is lower.

In a preferred embodiment, the sulfur content of the final product fuel is controlled by combining streams having different sulfur contents. In a variant, each such combined stream is made to an interim target sulfur content by adjusting unit operation conditions and flow rates, by reducing the addition or removal of very low sulfur streams, or by blending feeds of different sulfur contents. Variations of the invention include controlling product sulfur levels by feeding the selected crude oil, as needed, with one or more of: (i) other crude oils, (ii) bunker fuels, (iii) high sulfur fuel oils or other distillates, or (iv) other high sulfur or metal-contaminated residuals from other sources. As used herein and in the claims, the term "essentially metal-free" or "zero metals" means a metal content of zero to less than 100 parts per billion by weight or a content so low that it is difficult to measure reliably by conventional online instrumentation.

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

The inventors are able to address the cases where (i) only a relatively small amount of sulfur is present in a particular fraction in basic H2S or RSH thiol-type basic forms, and (ii) a relatively large proportion of the sulfur is present in more complex organic structural forms, and can then adjust process flow rates and operating conditions based on predicted breakpoint fractions at upper or higher levels where the sulfur content begins to increase more rapidly, possibly exponentially, compared to lower fraction levels.

The inventors have found that process and equipment configurations can be arranged to allow for and maximize bypass of certain streams, avoid or reduce processing of streams containing basic, less complex sulfur forms, and process streams containing more complex forms differently. This can include selectively rejecting certain streams from hydrodesulfurization and feeding the same to different hydrotreaters to tailor different hydrotreating unit conditions for other streams, or tailoring removal by solvent and/or reactive chemical based treatments, including treating with multiple solvents or other stripping agents in one or more stripping units, with the respective ratios of stripping agents in each unit being tailored based on the sulfur distribution to each unit to selectively remove low or high complexity sulfur containing molecules.

The terms "kerosene" and "light distillate", although often used with the same, overlapping, or different meanings in different references, are uniformly defined solely based on atmospheric column cut-off points by temperature range (e.g., 190°C-250°C or 180°C-230°C) and not based on sulfur content. Instead, conventional sulfur content measurements are made and reported based on cut-off point temperature ranges dictated by the specifications for each product from conventional refineries. The inventors have found this to be suboptimal.

The inventors have discovered that a change in the fundamental way crude distillation towers are operated can optimize the cost savings of low sulfur combustion production. The inventors have discovered that specific distillate takeoffs should be based on the sulfur content of the side streams, without analysis of the sulfur content of the crude feedstock or feed mixture to the tower, rather than on standard product temperature range specifications for traditional downstream uses such as kerosene, jet fuel, diesel, etc.

The inventors have discovered how to define a "breakpoint" that refers to the point at which the change in sulfur content (slope) per unit volume change in the withdrawn product is no longer substantially flat, but instead begins to increase rapidly or exponentially, such that as the withdrawal volume increases slightly, the sulfur content begins to change significantly per unit volume. Also, the type and composition of sulfur-containing compounds, as well as their complexity, typically change from the breakpoint onward, depending on the type of crude feedstock. The breakpoint is an indication from the separation of the stream or portion of the stream requiring desulfurization that desulfurization may be minimized or eliminated.

The inventors have found that capital and production costs of low sulfur fuels can be minimized if the maximum amount of material having a sulfur content below the breakpoint is directly removed and accumulated, and the production of total liquids having a sulfur content below the breakpoint is maximized so as to avoid or reduce the cost of downstream processing to reduce or remove sulfur.

The inventors have discovered that the relatively large amounts of such material below the breakpoint, and in certain crudes within a narrow specific zone above the breakpoint, when combined with other takes that have already been treated for sulfur removal, do not require treatment or significant subsequent processing for sulfur removal. The inventors maximize the production of such untreated material and reduce the cost of desulfurization or other processing operations throughout the stream by driving atmospheric distillation conditions primarily through increasing the feed or column temperature profile, but also by modifying the crude hydrocarbon or sulfur composition by reducing or eliminating reflux, or reducing the crude feed rate, or blending or diluting the feed crude to maximize takeoffs up to near the breakpoint. The breakpoint is not defined in terms of standard industry classifications or regulations that set temperature ranges for takeoffs.

In this specification and claims, we define a "breakpoint" in the context of a crude oil analysis or other measurement method as a point at which the sulfur content begins to increase abruptly 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 when the crude oil mass percent or volume is plotted on the x-axis against the sulfur content on the y-axis. The difference along the x-axis is the change in unit volume of the fraction, the difference along the y-axis is the change in sulfur content per unit volume, and the slope is the slope of the graph. The slope of the slope of such a graph moves from zero or near-horizontal to abruptly above 0.2 and then rapidly above 1 toward a somewhat exponential increase in sulfur content, and the breakpoint varies based on the crude oil or other feed to the distillation column. Thus, "breakpoint take" or "sulfur breakpoint take" provides a means of determining the fractionation into hydrocarbon-containing liquids boiling below the breakpoint beyond the end of the naphtha range, e.g., the end of the range for unstabilized, pristine, straight-run naphtha, but at the point where the slope of the graph per unit volume changes significantly and the sulfur content begins to increase rapidly or exponentially, as described above.

The inventors define herein and in the claims to mean a base "breakpoint take" or base "sulfur breakpoint take" to mean a hydrocarbon-containing liquid boiling above the end of the range of unstabilized, natural, straight-run naphtha and below a breakpoint with respect to the sulfur content of the cut, where the breakpoint is selected such that a fuel product stream is formed from the combination of all raw streams below the breakpoint and all streams above the breakpoint take selected for addition to the combination, such that the actual sulfur content of the combined fuel does not exceed the target sulfur content. In the alternative, the fuel can be produced according to where the target sulfur content is the sulfur breakpoint or is higher or lower than the sulfur breakpoint, and the combination of streams that produce the fuel is effectively made relative to the breakpoint such that the actual sulfur content of the fuel does not exceed the sulfur target.

For many crudes, the sulfur breakpoint take for the atmospheric distillation tower will contain most of the kerosene range material (as defined in various ways in the art), such as that beginning to boil at 180°C or 190°C (or other kerosene range start), and for simplicity may include lower or higher temperature range material. However, sulfur content, not temperature or historical definitions of kerosene range material, is the determining factor for the end of the sulfur breakpoint range. Fuels can be formed according to where the target sulfur content is the sulfur breakpoint, and the combination of streams forming the fuel is made such that the actual sulfur content of the fuel does not exceed the sulfur target.

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

In yet another embodiment, the present invention provides a method for reducing emissions exceeding IMO specifications by ships at sea, in an ECA, or in port by using fuel produced according to the present invention, the fuel having a regulated sulfur content lower than the maximum IMO specification that may apply where the fuel is used by the ship, whether at sea, in an ECA, or in port. In this way, the ship can exceed IMO requirements and public expectations.

In another embodiment, the present invention provides a method for a marine vessel to sell electricity generated using the fuel of the present invention at port to an onshore power grid, for example to offset marine or port fuel costs.

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

The inventors have thus discovered a technical method to trade (i) a minor flash point modification for (ii) a large environmental benefit (enormous SOx and NOx reduction and essentially elimination of toxic metals), especially related to the large fuel consumption by large cargo ships. No one has been able to make such a discovery before.

The International Convention for Safety at Sea (SOLAS) outlines fuel flash points and their permissible use on cargo ships. "To many, the minimum fuel flash point of 60°C for general service in the SOLAS Convention may seem like a cornerstone of maritime law, but it was only introduced in the 1981 amendments. The first three SOLAS Conventions (1914, 1929, and 1948) placed no limit on the flash point of petroleum fuels, and even the 1960 Convention only required "modern" passenger ships to have fuels for use by internal combustion engines with a flash point of at least 43°C. This provision has been carried over to the current 1974 Convention essentially as originally adopted," quoted from Non-Patent Document 5.

Wright et al. state that flash points are empirical, not real values, and that "flash point values are not, and have never been, the dividing line between 'safe' and 'unsafe'." As a result, from the beginning of the oil industry, flash points have been used, somewhat erroneously, as a means of identifying products that require greater care and attention in storage and use. In fact, in marine applications, petroleum fuel fires occur not so much as from vapor ignition, but from leaks or broken pipes that cause the fuel to ignite when it comes into contact with a surface above its autoignition temperature. Nevertheless, flash points have been used as safety parameters in the Oil Safety Act from the beginning, even if against sometimes somewhat arbitrarily set limits, or taking into account the fact that they are empirical values.

SOLAS makes an exception for cargo ships. SOLAS specifies that oil fuels with a flash point below 60°C must not be used, but with the exception that "cargo ships may be permitted to use fuels, e.g. crude oil, having a flash point lower than that specified in [SOLAS] Chapter 2.1 (e.g. 60°C), provided that such fuels are not stored in any machinery space and subject to the approval of the authorities." Note that some countries have no flash point standards and others allow relatively low flash points for marine applications.

Fuel flash points can be adjusted, if necessary, by treatment. The term "flash point treatment" as used herein and in the claims means a composition that, when combined with a material, raises the flash point. In one variation, the flash point treatment lowers the vapor pressure of the added material to lower the risk of vapor ignition. In one variation, flash point modifiers are solid or liquid additives with a flash point of 60° C. or higher that are added to low flash point fuels to raise the flash point of the fuel. These can include various types of particulates and oils. For example, high flash point additives for treating carbon-based fuels have been disclosed. For example, U.S. Patent No. 5,333,393 to 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 more and mixtures or combinations thereof, and specifically exemplifies Calpar 100 (FP 210° C.), Calpar 325 (FP 240° C.) and Calpar P 950 (FP 257° C.) available from Calumet Lubricants, Inc., Indianapolis, Indiana, and paraffinic base oils having a flash point of 200° C. or more and mixtures or combinations thereof.

The inventors have discovered a technical method to trade (i) a minor flash point modification for (ii) a large environmental benefit (enormous SOx and NOx reduction and essentially elimination of toxic metals), especially related to the large fuel consumption by large cargo ships. No one has been able to make such a discovery before.

Schematic illustration of the sulfur content of various actual and hypothetical crude oils showing breakpoint ranges. FIG. 1 is a schematic diagram showing a process layout for processing crude oil to produce a single liquid product useful as a fuel according to the present invention.

In one embodiment of the present invention, a method for converting at least a portion of a hydrocarbon feed that is a sulfur- and metal-bearing crude oil into a single liquid product comprises (i) subjecting the feed to one or more distillation and solvent separation steps to remove light overhead distillation gases (including only distillation gases that are not condensable at atmospheric distillation conditions as defined by the EIA or higher, even if a debutanizer system is preferred due to specific local circumstances or at cost to be eliminated in other circumstances), metal-rich residues that are insoluble in one or more solvents used in the solvent separation, sulfur-containing gases, and (for some feeds that are treated as being in the distillation range, at least a portion of the kerosene range materials) (ii) hydrotreating a selected taken liquid fraction above the sulfur breakpoint (and preferably only soluble liquid fractions are selected for hydrotreating) but not the taken liquid fraction below the sulfur breakpoint (and preferably not any portion of the fraction that is insoluble in the solvent used for solvent separation) through one or more hydrotreating steps to form one or more hydrotreated streams having reduced sulfur content, and (iii) combining the untreated fractions with the treated streams to form a fuel having an actual sulfur content equal to or less than a target sulfur content. As used herein, the term "step" or "zone" can refer to a unit operation or area having one or more processing operations having one or more sections of equipment configurations and/or unit operations or subzones. Equipment items can have one or more tanks, vessels, distillation columns, separators, reactors or reactor vessels, heaters, exchangers, strippers, pipes, pumps, compressors, and controllers. In a preferred variation of the invention, substantially all of the hydrocarbon compositions of the feed are separated into fractions, which are then recombined to form a single liquid fuel product, the fuel, which is a single liquid fuel product that includes hydrocarbons ranging from the original feed liquefied petroleum gas, or in one variation, from naphtha to hydrotreated deasphalted oil, without forming multiple hydrocarbon products, but excluding hydrocarbon compositions including those in (i) the light overhead gas of the distillate, (ii) in the residue insolubles, and (iii) in the sulfur or metal recovery streams. Such ranges are substantially the entire range of hydrocarbons from C3 or C5 to C20 and above crude oil, with an initial boiling point that is the lowest boiling point of any fraction in the untreated stream combined with the fuel, and a maximum boiling point that is the highest boiling point of the treated stream combined with the fuel. The term "untreated" as used in this specification and claims means that it has not been subjected to hydrotreatment to reduce or remove sulfur, nitrogen, or metals. In one variation, such fuels include those having substantially the range of hydrocarbons derived from C3 or C5 to C20 or higher crude oil or from crude oil having an initial boiling point within the range of about 35° C. to about 315° C. or higher, preferably from the end of the deasphalted oil and the beginning of the deasphalted residue, which are not soluble in the solvent selected for solvent separation. In an even more preferred variation, the fuel of the present invention comprises a combination of hydrocarbons ranging from the lowest boiling portion of the untreated liquid fraction from atmospheric distillation to the highest boiling portion of the hydrotreating solubles from the solvent separation. Thus, the preferred fuel of the present invention is the opposite of conventional gasoline, diesel, kerosene and fuel oil, which are taken out in selected subranges and do not have a significant content of the full range of such hydrocarbons. Thus, one embodiment of the present invention is a fuel obtained as a single product of processing crude oil, said fuel having substantially the full range of hydrocarbons derived from C3 or C5 to C20 or higher crude oil, with an actual sulfur content of 0.5% by weight or less, preferably 0.1% by weight or less. The hydrocarbons have an initial boiling point that is the lowest boiling point of any fraction of the crude oil under atmospheric distillation conditions, and a maximum boiling point that is the end point of the remaining portion of the crude oil that is insoluble in a solvent suitable for solvent separation. In a variant, such fuels comprise substantially the full range of hydrocarbons derived from crude oil from C3 or C5 through C20 and above, the hydrocarbons having an initial boiling point that is the lowest boiling point of any fraction in the unprocessed stream combined in the fuel, and an end point that is the highest boiling point of the processed stream combined in the fuel. In one variation, the crude oil is separated into a light overhead distillation gas, a metal-rich residue insoluble in one or more solvents used in the 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 breakpoint, and (ii) a liquid fraction above the sulfur breakpoint, both of which are soluble or insoluble in the solvent used in the solvent separation; (b) the soluble liquid fraction above the sulfur breakpoint, but not the liquid fraction below the sulfur breakpoint or the insoluble fraction, is hydrotreated in one or more hydrotreating steps to form one or more treated streams having reduced sulfur content; and (c) the untreated fractions are combined with the treated streams to form a fuel having an actual sulfur content equal to or less than a target sulfur content.

In a variant, such residues are combusted in one or more gasifiers for use in power production and to generate at least a portion of the hydrogen for hydrotreating and capturing at least a portion of the metals in the removed gasifier solids, or the residues are combusted in one or more boilers to capture flue gas sulfur and metals for use in auxiliary hydrogen generation unit operations to provide hydrogen for power generation and hydrotreating. Preferably, all sulfur-containing gases are sent to one or more common sulfur recovery units.

By practicing the present invention, the actual sulfur content of the fuel can be adjusted to meet target sulfur content limit specifications, e.g., to meet IMO specifications for marine fuels or sulfur limits for combustion gas turbines, by adjusting the amounts of the continuous streams of untreated and treated streams to the combination that forms the fuel. For example, the target sulfur content of the fuel can be adjusted to meet one or more target IMO specifications, e.g., 3.5 wt%, 0.5 wt%, 0.1 wt%, or other IMO specifications, within or outside the ECA. Fuels produced according to the methods of the present invention are useful in marine engines, combustion gas turbines, fired heaters such as boilers, and other applications.

In one variation, at least one of the hydrotreated streams is an ultra-low sulfur stream having 10 ppm sulfur or less by weight, and increasing or decreasing the amount of said stream relative to the combination is used to adjust the formation of a fuel having an actual sulfur content equal to or less than the target sulfur content. In another variation, at least one of the hydrotreated streams is an ultra-low sulfur stream having 10 ppm sulfur or less by weight, and the untreated fraction has a sulfur content greater than the target sulfur content, and the untreated fraction is used as a trim control, and decreasing or increasing the amount of such untreated fraction relative to the combination to form a fuel having an actual sulfur content equal to or less than the target sulfur content. In yet another variation, when converting a crude oil feed to substantially one liquid fuel product rather than multiple hydrocarbon products, a first hydrotreated stream is produced that is a reduced sulfur stream having a sulfur content of less than 10 ppm by weight, a second hydrotreated fuel fraction is produced that has a reduced sulfur stream with a sulfur content in the range of 0.12 to 0.18 wt%, and an untreated fraction has a sulfur content below or above the breakpoint sulfur and above the target sulfur content, and the first hydrotreated stream or the second hydrotreated stream or both are used as trim controls by increasing or decreasing the amount of such streams relative to the combination to form a fuel with an actual sulfur content below the target sulfur content.

In an even more preferred embodiment, the sulfur content of one or more crude oils, residual oils and other feeds is selected or process conditions are adjusted so that at least 70% by volume of each barrel of the crude oil feed is converted into liquid fractions and then processed or unprocessed but combined to form a fuel having a sulfur content equal to or less than the target sulfur content, rather than a plurality of hydrocarbon products, and 30% or less of each barrel of the crude oil feed is directed to something other than fuel. In a preferred variation of the 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 of each barrel of the hydrocarbonaceous feed, more preferably about 90% or more of each barrel of the feed, is converted into a liquid fuel product rather than a plurality of hydrocarbon products, except for a stream with very low sulfur. The stream with very low sulfur is used as a trim to increase or decrease the trim stream to control the sulfur content of the final fuel product to a level not exceeding the target sulfur content. The excess of the trim stream can be transferred separately for mass balance and inventory purposes. In such a preferred variation of the invention, no more than about 10-30% by volume of each barrel of the crude oil feed is captured in the metal-rich residue after atmospheric and vacuum distillation by solvent extraction.

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

The equipment for carrying out the method of the present invention can reduce its facility footprint to within the range of 20% to 30% of the equipment footprint of a conventional refinery with a typical downstream processing unit. Thus, the capital cost per barrel of feed processed is substantially reduced. For example, one particular embodiment of the present invention uses only one or more of atmospheric distillation, vacuum distillation, solvent separation, hydrotreating and gasification with the auxiliary equipment required to capture sulfur and metals, and has no hydrocarbon processing operations downstream of hydrotreating, except for gasification with the auxiliary equipment required to capture sulfur and metals.

The process configuration variants of the present invention provide high efficiency, low cost operation through the effective integration of utility islands that provide the process needs for hydrogen, steam and fuel gas as well as electricity while providing integrated metal and sulfur capture means. The utility island has one or more gasification systems with sour gas and acid gas off-gas processing from all sources as potential emission sources, preferably integrated and therefore lower capital cost sulfur capture, treatment and removal, processing heavy metal rich residues to capture and eliminate metal contaminants as potential air emission components. The island configuration of the present invention produces hydrogen for hydroprocessing steps, and steam and fuel gas for the electrical process and via a highly efficient combined cycle power generation means that utilizes certain streams that would normally be waste streams to meet process demands.

One variation of this embodiment of the invention addresses the case where the light tight oil does not contain sufficient heavier hydrocarbons in the bottoms and residue to provide a processing balance for hydrocarbon processing and corresponding hydrogen production, allowing such light crude oil to be hydrotreated to reduce and decontaminate sulfur and metals. The method includes adding the light crude oil, either separately or mixed with other feeds, to any or all of the heavier feeds that are directed to atmospheric distillation, vacuum distillation or solvent separation processing.

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

In another embodiment, the invention provides a method for generating electricity using the fuel of the invention while the ship is in port and selling it to the onshore grid in addition to reducing local emissions. In one variation, the invention provides a technical method for reducing emissions at port and its vicinity, the method comprising: (a) a technical analysis ascertaining sulfur or metal emissions per kilowatt hour (KWH) generated by onshore generating equipment that generates electricity normally supplied to the grid at or near the port location (including, for example, emissions associated with the use of local electricity supplies when the ship is connected to such grid at the port); and (b) a technical analysis ascertaining sulfur or metal emissions per KWH generated by electricity generated on board the same ship when in port at the location of (a); comparing (a) with (b), if the emissions generated by the ship for electricity generation in (b) are lower than the local generating sources in (a), reducing the onboard emissions and providing all or a portion of the onboard electricity generation to the grid. This embodiment may be particularly useful in reducing environmental emissions when the electricity provided locally is from certain types of coal combustion sources, or when lower emission options are not available for local generation and heavy crude or residual oil is burned to generate electricity. Without offsets, such contributions by the vessel to the local grid would not be made except with port charge offsets when the KWH cost of the vessel generated electricity exceeds the KWH cost of the local grid electricity, or when such contributions by the vessel to the local grid would not otherwise benefit the vessel, such as offsets from emission reduction credits such as subsidies paid for low emission generation.

If contribution to the local electricity grid by the vessel is beneficial, the vessel can offset or reduce fuel costs incurred at sea by revenues generated by providing all or part of the electricity generated on board the vessel to the onshore electricity grid while in port using the fuels of the present invention. The revenues generated by providing to the electricity grid while in port can offset fuel costs for marine operations to a level such that the actual marine fuel costs with these new fuels are lower than the costs of high sulfur fuel oil for marine operations, depending on the duration of the port stay.

Figure 1 is a schematic plot of the sulfur content of various actual and hypothetical crude oils showing breakpoint ranges. Exemplary crude oil sulfur profiles 4, 5, and 6 are plotted based on the center points of actual data extracted from "Sulfur Content of Crude Oils," Journal of Chemical Engineering, Vol. 6, No. 1, pp. 1171-1175, 2002. Hypothetical crude oil sulfur profiles 1, 2, and 3 are derived in part from actual data taken from various sources, including "Sulfur Content of Crude Oils," Journal of Chemical Engineering, Vol. 6, No. 1, pp. 1171-1175, 2002.

FIG. 1 illustrates how to define "breakpoints" for different crudes for the process configuration of the present invention. FIG. 1 illustrates breakpoints, which are points where the change in sulfur content (slope of the graph) per unit volume change of the withdrawn product is no longer substantially horizontal or flat, but instead where the sulfur content begins to increase rapidly or exponentially with small increases in withdrawal volume, resulting in a large change in the slope of the graph per unit volume. Also, from the breakpoint onwards, the sulfur-containing compounds, type and composition, as well as the complexity, change depending on the type of crude feedstock. The breakpoints allow for determining how best to bypass costly intensive hydroprocessing for operational efficiency, while still producing a fuel that meets the target sulfur content limit specification. That is, the breakpoint can be the maximum sulfur content of the atmospheric crude tower fraction that is directed away or reduced from further downstream processing to reduce the sulfur content, e.g., away from hydroprocessing. The fraction above the breakpoint is directed to downstream processing for sulfur content reduction, while the fraction below the breakpoint is not processed, resulting in substantial operational savings. In conventional refining, the takeoff is fixed by the temperature range, not the sulfur content. The target sulfur content, as an example of end-use requirements, can determine the choice of breakpoint. If the breakpoint is set too high, the excess higher sulfur untreated stream cannot be easily offset by the increased amount of lower sulfur hydrotreated stream.

Figure 2 provides an overview of another embodiment of the present invention, showing in simplified form the major components of a process configuration for the production of a single liquid product suitable for use as a fuel. Figure 2 shows how atmospheric and vacuum distillation, solvent separation, hydroprocessing and gasification are integrated to produce a single low sulfur, essentially metal-free fuel product.

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

In various applications in the art, different meanings are assigned to the same or similar takeoffs in different parts of the world, and the meanings are often different, overlapping, contradictory, and confusing. As used in this specification and claims, the following meanings are used: (a) "naphtha" means a carbon-containing composition ranging from those having a minimum of three carbons C3, such as propane, to those having an initial boiling point (IBP) of about 175°C (about 350°F), excluding low boiling compounds such as methane and below. (b) "stabilized naphtha" means, insofar as naphtha or other naphtha range materials used as fuel blend stocks are concerned, that low boiling compounds below butane or propane have been almost completely removed from the naphtha or fuel, e.g., in a conventional refinery, the bottom stream from the naphtha debutanizer is stabilized naphtha. (c) "Unstabilized naphtha" means naphtha from which the lighter components C4 and below have not been removed; for example, in a conventional refinery, the feed stream to the naphtha debutanizer is unstabilized naphtha. (d) "Unstabilized pristine straight-run naphtha" means carbon-containing compositions recovered from atmospheric distillation ranging from those having a minimum of three carbons C3, such as propane, to those having an initial boiling point (IBP) of about 175° C. (about 350° F.), excluding low boiling compounds such as methane and below, and which may include atmospheric distillation overhead gases. (e) "Pristine naphtha" means the unstabilized light fraction of the hydrotreater effluent recovered from a distillation column or other separator in hydroprocessing, which is operationally considered to be part of a hydroprocessing zone that recovers one or more heavy fractions at or near the separator bottoms, such as the distillate range, heavy oil range, or materials heavier than the naphtha portion of the feed to the other separator, and which is not stabilized. (f) "Breakpoint take" has been previously defined herein, and an example is shown in FIG. 1. (g) "Light distillate above the breakpoint take" or "light distillate" herein is a cut having an initial sulfur content higher than the maximum sulfur content of the breakpoint take, and correspondingly a higher boiling point (IBP) than the maximum end of the breakpoint take. (h) "Middle distillate" means a cut between the light and heavy distillates separated as a take based on the preferred distillation column design, e.g., the middle take may be rejected and combined with either the light or heavy cut. (i) "First heavy distillate" means the heaviest cut of the atmospheric distillation unit, whose sulfur content and boiling range are determined by one or more operating conditions, such as the sulfur composition of the distillation unit feed, the severity of the crude tower operation, and downstream hydroprocessing conditions. (j) "First heavy distillate" means the heaviest fraction of an atmospheric distillation unit, having a sulfur content and boiling range related to the sulfur composition of the distillation unit feed and the sulfur breakpoint takeoff, and determined with reference to one or more operational factors, such as the severity of the crude tower operation, the severity of the hydrotreating conditions of the downstream distillate, and the like. (k) "Second heavy distillate" means the lightest fraction of a vacuum distillation tower, having a sulfur content and boiling range related to the sulfur composition of the distillation unit feed and the sulfur breakpoint takeoff, and determined with reference to one or more operational factors, such as the severity of the crude tower operation, the severity of the hydrotreating conditions of the downstream distillate, and the like. (j) "Vacuum gas oil", including "atmospheric residue", "vacuum residue", "light vacuum gas oil" and "heavy vacuum gas oil", "solvent separation", "hydrotreating", and other terms, and variations of these terms, are known to those skilled in the art of processing crude oil.

Preferably, the combination of the streams (1) unstabilized straight run naphtha in line 16 via line 4, and (2) the sulfur breakpoint takeoff in line 18 contain sulfur in the range of 0.06 wt.% to less than 0.08 wt.%, and the sulfur content of the process stream 70 is less than 10 ppm by weight if the target sulfur content of the fuel combination in line 600 is 0.1 wt.% or less, and the flow rates of steam 10 and 70, taken together, are adjusted so that the fuel combination 600 does not exceed the target sulfur content.

In FIG. 2, the atmospheric residue is fed to a vacuum distillation tower 200 via line 30 to produce (1) a second heavy distillate via line 32, (2) a light vacuum gas oil via line 36, (3) a heavy vacuum gas oil via line 38, and (4) a vacuum residue via line 50. The vacuum residue is led to a solvent separation 300 via line 50 to produce (1) a deasphalted oil via line 80 and pitch, which is a metal-rich heavy residue via line 90.

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

The light distillate 24, the middle distillate 26, the first heavy distillate 28 and the second heavy distillate 32 are preferably fed to an integrated hydrotreating system 400 and hydrotreated under hydrotreating conditions in the presence of a catalyst to form a distillate hydrotreating zone 430 effluent stream in line 60. Such hydrotreater effluent 60 includes materials within the following ranges: (1) pristine naphtha having an expected boiling range from above C5 (carbon number 5 composition) to about 175° C. (about 350° C.); and (2) ultra-low sulfur diesel, which is a reduced sulfur stream formed from a combination of treated distillation steam having a sulfur content of less than 10 ppm by weight and having the light distillate 24, the middle distillate 26, the first heavy distillate 28 and the second heavy distillate 32. It is known to those skilled in the hydroprocessing art that the by-products of hydroprocessing in zone 430 may include hydrogen sulfide, sulfur-containing gases such as hydrogen-rich off-gas, and typically small amounts of liquefied petroleum gas, at least a portion of which is treated to remove sulfur and recycled as hydrogen for addition to distillate hydroprocessing zone 430 or heavy oil hydroprocessing zone 460, or both.

The light vacuum gas oil 36, the heavy vacuum gas oil 38 and the deasphalted oil 80 are also preferably fed to the integrated hydrotreating system 400 and hydrotreated under hydrotreating conditions in the presence of a catalyst to form the heavy vacuum gas oil hydrotreating zone 460 effluent stream 70. Such hydrotreater effluents have materials within the following ranges: (1) pristine naphtha with an expected boiling range from above C5 (carbon number 5 composition) to about 175° C. (about 350 degrees Celsius); and (2) ultra low sulfur diesel, a heavy oil hydrotreater zone first reduced sulfur stream, preferably having a sulfur content of less than 10 ppm by weight and formed from a first portion of the combined treated distillate steam having light vacuum gas oil 36, heavy vacuum gas oil 38 and deasphalted oil 80; and (3) a second reduced sulfur stream, preferably having a sulfur content in the range of 0.12 to 0.18 weight percent and formed from a second portion of the combined treated distillate steam having light vacuum gas oil 36, heavy vacuum gas oil 38 and deasphalted oil 80. It is known to those skilled in the hydroprocessing art that the by-products of hydroprocessing in zone 460 may include hydrogen sulfide, sulfur-containing gases such as hydrogen-rich off-gas, and typically small amounts of liquefied petroleum gas, at least a portion of which is treated to remove sulfur and recycled as hydrogen for addition to the distillate hydroprocessing zone 430 or the heavy oil hydroprocessing zone 460, or both.

The untreated stream 10 and one or more hydrotreated liquid streams are combined via lines 60 and 70 to form a low sulfur, substantially metal-free fuel product in line 600. Here, "combining" means forming by mixing, blending, or other intimate combination of the streams in the lines. In one variation, the unstabilized virgin straight run naphtha via lines 4 and 16 and the sulfur breakpoint takeoff via line 18 are combined without additional processing in 100, and then a fuel combination is formed in 600 by combining one or more effluents from the distillate hydroprocessing zone 430, including virgin naphtha and ultra-low sulfur diesel, and one or more effluents from the heavy oil hydroprocessing zone 460, with the virgin naphtha, ultra-low sulfur diesel, and a second reduced sulfur stream formed in the heavy oil hydroprocessing zone 460. In another variation, hydroprocessing zone 400 combines the effluents of zones 430 and 460 to form a single stream as if lines 60 and 70 were combined in such zone (not shown), and such variation is useful when it is not desirable to separate the effluents of hydrotreaters 430 and 460. Preferably, vacuum gas oil hydroprocessing section 460 has an overhead system flow and a bottoms system flow, a portion of which is diesel boiling range material. This may be relatively small compared to the combined diesel provided to combination 600 by zones 430 or 460, and the combined diesel side hydroprocessing section 430 also has a pristine naphtha side stream, either alone or as part of the overhead system flow and bottoms system flow, which includes low sulfur diesel that is directed to block 600 or used for trim or other purposes.

The deasphalter 300 bottoms heavy residue 90, containing asphalt and metal-rich heavy residue, is fed 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 a synthesis gas, at least a portion of which is sent via line 502 to the hydrotreating system 400, including the distillate hydrotreater 430 and the heavy oil hydrotreater 460, to be converted into hydrogen for use in 504 to generate electricity for process and other uses, and further includes a heat recovery generator for recovering heat from the hot turbine gas and the hot gas turbine gas, which produces steam, which is sent via 504 for additional electricity generation, to drive a steam turbine to generate electricity. Each gasifier also produces metal-rich soot. The soot may be in the form of particulate solids, including metal contaminants from crude oil and/or heavy feedstocks, which are fed from each gasifier via line 506 for metal removal. The support system includes one or more gas processing units to which all of the sulfur-containing gas streams from all unit operations, whether sour gas or acid gas, are fed for sulfur removal via 508. Preferably, such sulfur removal systems are part of the utility island of which the gasification system is a part. More preferably, one or more sulfur-containing gas streams are directed to commercial sulfur acid production as part of the overall sulfur removal. The gasification system 500 typically includes an acid gas removal unit and a sour CO shift system optimized in capacity and configuration to produce the required hydrogen from at least a portion of the raw syngas produced in the gasification system.

In the variation of the integrated hydrotreating system 400 shown in FIG. 2, the make-up hydrogen-containing gas 502 from the gasification system 500 is compressed and heated in the amount required for hydrotreating together with the internal recycle hydrogen in the hydrotreating block 400 to the effective hydrotreating operating temperature, pressure, space velocity and pressure adjusted based on the catalyst selected and other conditions known in the art to achieve the desired level of desulfurization and demetalization. The hydrogen 502 thus prepared (along with the recycle hydrogen) is initially placed in the high pressure zone, the heavy oil hydrotreating zone 460. The effluent of the heavy oil hydrotreating zone 460 with hydrotreating liquid and hydrogen-containing gas is separated in a high pressure separator (not shown), whereupon the liquids are collected in the zone 460 and the hydrogen-containing liquid is recovered and sent through line 410 to the distillate hydrotreater 430 for hydrotreating in the low pressure zone. The hydrotreated liquid with sour and acid gases and purge gas from hydroprocessing zone 430 pass through line 412 into heavy oil hydroprocessing zone 460 where they are substantially mixed. The hydrotreated liquids 430 and 460 of both zones 430 and 460 are separated via lines 60 and 70 and may be separately injected into combined fuel 600, added as a trim to control the sulfur level of combined zone 600, or withdrawn (not shown), depending on the sulfur and other mass balance needs of the process. In the illustrated integrated hydroprocessing variation, the purge gas 420 of both zones 430 and 460 is directed via line 420 to a utility island 500 having a sulfur recovery system and optionally a gasification or boiler. Although not shown in FIG. 2, various auxiliary high, medium and low pressure gas-liquid separators, flow heaters, gas recycle and purge lines, reflux drums for separating gas or lights and liquids, compressors, refrigeration systems, and other auxiliary applications are known to those skilled in the hydroprocessing art. Also, various amine or other sulfur recovery agent absorbents and stripping systems for sour gas or acid gas processing may be included in the hydroprocessing zone 400 if located within the hydroprocessing zone rather than within a common utility island.

The selection of hydrotreating catalysts and the parameters for adjusting the process conditions of the hydrotreating zone 400 are within the skill of those skilled in the art of the petroleum refining industry and do not require further explanation for the practice of the hydrotreating section of the present invention. In the reaction zones of the distillate hydrotreater 430 and the heavy oil hydrotreater 460, the hydrotreating catalysts used include any catalyst composition useful for catalyzing the hydrogenation of hydrocarbon feeds to increase the hydrogen content and/or remove sulfur, nitrogen, oxygen, phosphorus and metal heteroatom contaminants. The specific catalyst types and various layer configurations used and the hydrotreating conditions selected depend on the hydrocarbon product composition, as well as the sulfur and metal content and heavy carbon residues of each feedstock processed by the respective units, and the desired reduced sulfur and metal content in the product streams from each zone. Such catalysts can be selected from any catalysts useful for hydrotreating hydrocarbon feedstocks, but the operating conditions are adjusted to avoid or minimize ring saturation or hydroconversion in the practice of preferred embodiments of the present invention. US Patent No. 5,399,433 by Baldassari et al., incorporated herein by reference, describes suitable hydrotreating processes including various integrated hydrotreaters as well as various suitable hydrotreating catalysts. Baldassari et al. further summarize various catalyst compositions and condition ranges for distillation and heavy oil hydrotreating, and identify conditions for hydrocracking and residue hydroconversion, all of which are known to those skilled in the art of hydrotreating. US Patent No. 5,399,433 by Baldassari et al., describes unit designs, catalyst selections, hydrogen consumption, and other operating conditions for removing sulfur by hydrogenation and producing products with less than 8 ppm sulfur by using a highly active Ni/Mo catalyst. US Patent No. 5,399,433 by Shiflet et al. also describes hydrotreating to 10 ppm or less using a highly active CoMo catalyst to remove unhindered sulfur, and a highly active NiMo catalyst to remove residual sterically hindered sulfur.

In another variation shown in FIG. 2, the sulfur content of the feedstock 2 is measured by analysis showing an exponential breakpoint and rate of rise of the sulfur profile. For example, a breakpoint of sulfur content in the range of 0.06-0.08 wt.% (or higher, given the relative flow rates of the untreated and hydrotreated steam and their respective sulfur contents) and such a profile may be used to control the adjustment of atmospheric distillation 100 to maximize the available amount of unstabilized raw straight run naphtha 16 and sulfur breakpoint take 18, where the straight run naphtha 16 and sulfur breakpoint take 18 are combined and flowed together by fluid mixing or blending to produce a product without treatment. The amounts of (1) the light distillate 24, middle distillate 26, first heavy distillate 28 or second heavy distillate 32 streams to the distillate hydrotreating zone 430 or (2) the light vacuum gas oil 36, heavy vacuum gas oil 38 or deasphalted oil 80 streams to the heavy oil hydrotreater 460 available in the product accumulation zone 600, if necessary, are measured or reduced, and these streams are directed to hydrotreating in increased or reduced amounts to form a fuel product 600 whose actual sulfur content is at or below the target sulfur content limit. In yet another variation, the analysis can be used to control the maximum amount of streams other than the raw unstabilized straight run naphtha 16 and the raw sulfur breakpoint take 18 to determine the amount of streams directed to hydrotreating to form a fuel 600 whose actual sulfur content is at or below the target sulfur content limit. That is, the various flow rates to hydroprocessing 400, either (1) the amount of light distillate 24, middle distillate 26, first heavy distillate 28 or second heavy distillate 32 stream to distillate hydroprocessing zone 430, or (2) the amount of light vacuum gas oil 36, heavy vacuum gas oil 38 or deasphalted oil 80 stream to heavy oil hydrotreater 460, can be increased or decreased to adjust the sulfur content of the effluent 60 or 70 of hydroprocessing zone 400, or both, that are mixed with the untreated stream 10 at 600.

In one variation, a fuel product 600 with an actual sulfur content at or below the target sulfur content limit is formed by adjusting the sulfur level of the actual final product 600 by increasing or decreasing the amount of one or more of: (a) unstabilized, natural straight run naphtha 16 or sulfur breakpoint take 18, which may contain sulfur because it has not been treated for sulfur removal, or (b) streams to or from a distillate hydrotreater 430, such as the processed light distillate 24, middle distillate 26, first heavy distillate 28, second heavy distillate 32, or (c) streams to or from a heavy oil hydrotreater, such as the processed light vacuum gas oil 36, heavy vacuum gas oil 38, deasphalted oil 80, to or from the combined zone 600, where such adjustment is based on a measurement of the relative contribution of each stream 60 or 70 to the sulfur content of the combined 600.

In one embodiment, a light tight oil or condensate having low metal content and sulfur content below the target sulfur content limit level for fuel 600, or a combination of light tight oils such as condensates for non-associated gas and shale gas production, is used for the following: (a) as a feedstock for atmospheric distillation 100 or vacuum distillation 200, solvent separation 300, as a feedstock for any of light distillate 24, middle distillate 26, first heavy distillate 28 or second heavy distillate 32 to distillate hydrotreater 430, or as a feedstock for any of light vacuum gas oil 36, heavy vacuum gas oil 38 or deasphalted oil 80 to heavy oil hydrotreater 460, (b) as a feedstock for further processing; (c) a stream formed from the unstabilized straight run naphtha 16 and sulfur breakpoint takeoff 18 without further processing; (d) a stream formed from the distillate hydrotreater including the raw naphtha and ultra-low sulfur diesel; (e) a combined effluent 70 of the combined hydrotreating unit 400 that is directed to the final product fuel 600; or (f) another fuel that is added to form the final product fuel, either inside or outside the enclosure of the facility that produces such fuel.

In one variation shown in FIG. 2, the sulfur content of the fuel product 600 is adjusted by (a) feeding the combination 600 with unstabilized, natural straight run naphtha 16 and sulfur breakpoint takeoff 18 via line 10 without additional processing of such streams, and then (b) adjusting the actual product sulfur level 600 by increasing or decreasing the amount of one or more combinations of (1) the light distillate 24, middle distillate 26, first heavy distillate 28, or second heavy distillate 32 streams to the distillate hydrotreating zone 430, (2) the light vacuum gas oil 36, heavy vacuum gas oil 38, or deasphalted oil 80 streams to the heavy oil hydrotreater 460, and (c) if for any reason the sulfur content of the actual product 600 needs to be increased to the target sulfur level, the combination The sulfur content of the actual product 600 is controlled below the target sulfur content limit level by decreasing the amount of one or more of the following to the combination: (1) the stream from the distillate hydrotreating zone 430, via line 60, formed from the light distillate 24, the middle distillate 26, the first heavy distillate 28, or the second heavy distillate 32; (2) the stream from the heavy oil hydrotreating zone 460, via line 70, formed from the light vacuum gas oil 36, the heavy vacuum gas oil 38, and the deasphalted 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 following to the combination: (1) the stream from the distillate hydrotreating zone 430, via line 60; or (2) the stream from the heavy oil hydrotreating zone 460, via line 70. Such facilitation allows for the efficient production of multiple sulfur grades, such as fuel supplies targeted at less than 500 ppm sulfur fuel by weight for offshore and onshore gas turbines, and various ranges for the same application in different locations requiring different target sulfur content.

In a variation of the use of 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 as part of one or more of the various feedstocks to one or more of the respective unit operations. The high sulfur fuel oil can be added (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) to line 20 to distillate hydrotreater 430, either separately or in combination with one or more of the light distillate 24, middle distillate 26, first heavy distillate 26 or second heavy distillate 32 feeds to said distillate hydrotreater 430, or (d) to line 40 to heavy oil hydrotreater 460, either separately or in combination with one or more of light vacuum gas oil 36, heavy vacuum gas oil 38 and deasphalted oil 80 to form a fuel combination 600 whose actual sulfur content is at or below the target sulfur content limit. It is known to those skilled in the refining art that in implementing one or more of these variations regarding the use of high sulfur fuel oil as a feedstock and the selection of its feed point, consideration is given to the nature of the high sulfur fuel oil feed, such as its sulfur content, asphaltene content, and other factors related to compatibility with co-processed crude oil or other feedstocks, vessel space and energy consumption, asphaltene content, content of undissolved components, gum formation, and other efficiency issues.

In another variation, the clean fuel of 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 (a) stream 10 formed from unstabilized virgin straight run naphtha 16 and sulfur breakpoint take 18, which are not further processed due to the sulfur content of the high sulfur fuel oil, or (b) stream 60 formed by distillate hydrotreater 430, which includes virgin naphtha and ultra-low sulfur diesel range material, or (c) stream 70 formed from heavy oil hydrotreater 460, which includes virgin naphtha, ultra-low sulfur diesel and a second reduced sulfur stream, or the combined effluent 70 from hydrotreating zone 400, which includes virgin naphtha, ultra-low sulfur diesel and a second reduced sulfur stream, such that the actual sulfur content of fuel 600 is at or below the target sulfur content limit.

In one preferred variation in which high sulfur fuel oil is used to make the fuel composition 600, the sulfur content of such high sulfur fuel oil is measured and then the high sulfur fuel oil is fed as part of the feedstock 50 to a solvent separation unit to form part of the deasphalted oil stream 80, or is combined with one or more distillate streams of the light distillate 24, the middle distillate 26, the first heavy distillate 26 or the second heavy distillate 32 as part of the feedstock 20 and fed to the distillate hydrotreater 430, or or combined with one or more of the light vacuum gas oil 36, heavy vacuum gas oil 38, and deasphalted oil 80 heavy oil streams, or both the distillate and heavy oil streams, depending on the sulfur content of the high sulfur fuel oil, to form part of the feed to the distillate hydrotreater 430 or the heavy oil hydrotreater 460, or both, optimizing adjustment of the hydrotreating conditions in zone 430 or 460, or adjusting both zones to form a fuel with an actual sulfur content below the target sulfur content limit.

In another embodiment of the invention, clean fuels whose specifications are below the sulfur content limit can be formed by the use of heavy residual oils, including typically atmospheric residuals or high sulfur fuel oils that are heavier and may have a density or sulfur or metal content outside the specifications or within the standard specifications for high sulfur fuel oil. Due to market considerations, such heavy residual oils are often available from sources other than within the battery limits of the fuel plant. The heavy residue having a sulfur content higher than the target sulfur content limit level for fuel 600 is fed to one or more of the following: (a) a vacuum distillation column 200, either separately or in combination with the atmospheric residue via line 30, which feeds the distillation column 200 to produce at least a portion of any or all of a second heavy distillate 32, a light vacuum gas oil 36, a heavy vacuum gas oil, or a vacuum residue 50; or (b) a solvent separation 300, either separately or in combination with the vacuum residue feed to the solvent separation 300 via line 50 to form at least a portion of the deasphalted oil 80, or a pitch 90 having a heavy metals-rich residue which is passed to a gasification system 500 for gasification, sulfur recovery, and other auxiliary processing. Such heavy residue may also be combined with the pitch via line 90 as a feed to a utility island 500. Alternatively, if untreated high sulfur fuel oils having relatively high sulfur content (greater than 0.5 wt%) or high metal content are used without treatment to trim the sulfur content of the fuel 600 of the present invention, such use would require a relatively small amount of adjustment when used without treatment to ensure that the combination 600 does not exceed the target sulfur content limit.

The flowsheet of FIG. 2 showing the various intermediate individual products is for the explanation and understanding of the major products and by-products in the effluent of each depicted unit operation. The selected variation of separation or processing by each unit operation depends on the selected crude oil and feedstock, and the optimization of the intermediate products produced to produce fuels below the target sulfur specification. For example, if the ultra-low diesel produced in zone 430 is not filtered and all hydrotreated materials are combined in line 70 as shown in FIG. 2, both effluents 60 and 70 from hydrotreaters 430 and 460 can be combined in hydrotreater zone 400 by using a common gas-liquid separator (not shown) and only gases are removed. Alternatively, if the process objective is the separation or removal of a portion of the raw naphtha or ultra-low sulfur diesel for trim control of the sulfur content of the final combined zone 600 fuel or for other reasons, the effluents 60 and 70 from hydrotreaters 430 and 460 can be sent to a stripper or distillation tower, either separately or combined, to remove the raw naphtha or ultra-low sulfur diesel fraction.

While various embodiments of the present invention have been described, it should be understood that they are illustrative and not limiting. For example, if the flash point of the fuel is not considered, an untreated light tight oil or condensate, or a combination of untreated light tight oil or condensate having a low metal content and a sulfur content below the target sulfur content, is added as part of the combination of the untreated fraction and the treated stream to form a fuel with an actual sulfur content below the target sulfur content. As used herein, the term "light tight oil" or "LTO" refers to a wellhead condensate or shale gas condensate having (i) a sulfur content in the range of 0.1% to 0.2% by weight, and (ii) a density in the range of 38 to 57 degrees API, and (iii) a wide range of hydrocarbons based on the source. LTO typically has overlapping ranges of expected distillate takeoffs, expressed as a percentage by weight of the total: (a) 5-20 wt.% liquefied petroleum gas range, (b) 10-35 wt.% naphtha, (c) 15-30 wt.% kerosene, (d) 15-25 wt.% diesel, (e) vacuum gas oil, and (f) zero (0%) to 10 wt.% heavy residue.

In one variation, the present invention involves co-processing (i) crude oil having unprocessed light tight oil or condensate quality, or a combination of light tight oil or condensate, for example when the available oil has a production location outside the battery limits of the combustion production plant of the present invention, with (ii) one or more other crude oil feedstocks, by the method 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 oils likely do not contain sufficient heavy hydrocarbons in the bottoms fraction (e.g., 0% or very low heavy residue), the extent of the residue does not provide a processing balance for desulfurization or other hydroprocessing, and the corresponding residue is not sufficient to cost-effectively hydroprocess such light tight crude oil to reduce and decontaminate sulfur and metals, or provide sufficient lubricity to support the process of hydrogen production to support use in certain types of engines.

The novel fuel embodiments of the present invention are better understood by reference to the ISO 8217 standard published by the International Organization for Standardization (ISO). ISO 8217 describes a range of marine residual fuel categories and detailed specifications for consumption on board ships. These specifications recognize, as the basis for their development, the wide variations in crude oil supply, refining methods, and other conditions. Such specifications imply that various international requirements for properties such as sulfur content have been taken into account. The most stringent ISO 8217 to date is RMA 10, and interpretation of the specification and claims should be based on this. Based on simulated compositions of the new fuels of the present invention (created by a simulation model of splitting crude oil into fractions, hydrotreating some of the fractions, removing non-solvent residues during solvent separation, and then reconstituting the untreated and treated fractions), the inventors assert that these new fuels meet and/or exceed all ISO RMA 10 specifications except for flash point, which falls within the SOLAS exception to the flash point requirement for cargo ships, and that the fuels have novel characteristics and improvements that distinguish them from marine fuels made from the above residues.

In one variation, the inventors provide an improved fuel which meets or exceeds all ISO RMA 10 (ISO 2817-10) specifications except for flash point, and has any or all of the following notable characteristics: (a) sulfur not exceeding 0.50% m/m (wt%), preferably in the range of 0.05 to 0.20 m/m (wt%); (b) metals not exceeding 5.0 mg/Kg (ppm by weight), preferably not exceeding 1.0 mg/Kg (1.0 ppm by weight), e.g., 0.2 mg/Kg (0.2 ppm by weight); and (c) a flash point of 60° C. or less, and other characteristics superior to the ISO RMA 10 specifications. In a variant, these new fuels have one or more of the following notable characteristics: (a) viscosity of 10 cSt or less, (b) pour point of 0°C or less, (c) density in the range of 820-880 Kg/ ^m3 , (d) CCAI of 800 or less, and (e) sodium of 20 mg/Kg or less, preferably 10 mg/Kg or less, all as measured by the test or calculation methods specified by ISO 2817-10. Such fuels include a range of hydrocarbons with an initial boiling point of naphtha and a maximum boiling point of the highest boiling point soluble in a solvent suitable for solvent separation, such as heptane. Metals can be reduced to 100 ppb by weight depending on the feed composition and adjustment of operating conditions.

The inventors have discovered that fuels can be produced at low cost that have extremely low sulfur and metals that fall within the SOLAS exception to the flash point requirements for cargo ships. If flash point treatment is required for other applications, flash point treatments to have a flash point of 60°C or greater or for such requirements are known in the art.

The use of the low viscosity, low pour point fuels of the present invention in marine engines avoids or reduces the energy consumption required associated with heating conventional residual oils, allowing them to be pumped and handled at fueling stations in port or at sea. Heavy residual oils are thick and, due to their relatively high pour point and high viscosity, must be heated and kept at high temperatures during storage, pumping, and delivery to marine engines, all of which consumes energy.

Table 1 below shows two variants of the fuel of the present invention, one with a very low sulfur content of 0.1% by weight and one with an even lower level of 0.05% by weight, with sulfur compared to ISO RMA 10 as shown in Table 1 below.

Such fuels of the present invention having the properties shown in Table 1 are further distinguished in that they contain substantially the entire range of hydrocarbons from C3 or C5 to C20 and above crude oil, with the initial boiling point being the lowest of the boiling points of any fraction of said crude oil under atmospheric distillation conditions, and the highest boiling point being the end point of the remaining portion of said crude oil that is not soluble in a solvent suitable for solvent separation. In contrast, the residue is limited to only very heavy materials, as vacuum distillation residues, solvent deasphalting residues, other cokers, etc. do not contain such a wide range of hydrocarbons.

From the disclosure herein and in the claims, the present invention allows for the production of ultra-clean fuels that not only meet or exceed standards for compatibility with current marine reciprocating engines, but are also compatible with advanced combustion gas turbines that can be used in marine applications. Such advanced turbine engines are currently available, but are typically land-based. Once started on board, these advanced turbine engines can have significant efficiency benefits by burning the fuels of the present invention while at sea, with less corrosion or ash formation. Also, depending on the fuel economy available at port, ships can obtain efficiency benefits by burning these novel fuels at port, generating electricity and sending that electricity to the local power grid for revenue generation. Such port generation revenues can offset marine fuel costs, lowering the actual total marine fuel cost to the ship below high sulfur fuel oil, thus offsetting the cost of using the low sulfur fuel of the present invention, even when it is a more expensive voyage fuel. The greatest benefit is to the environment, where in certain reference case comparisons, SOx and NOx emissions can be reduced by over 95%, and emissions of toxic metals during the voyage can potentially be reduced by over 99% (almost 100%). Furthermore, the environment benefits two-fold from the _CO2 reduction: (i) the efficiency of advanced gas turbine engines on board, and (ii) the efficiency of power generation at port, replacing the inefficient burning of coal, crude oil, residual oil, or certain other fuels.

Thus, the present invention has broad application to the production of fuels having reduced levels of sulfur and other contaminants and the use of such fuels. Specific features may be modified without departing from the spirit or scope of the present invention. Accordingly, the present invention is not limited to the specific embodiments or examples described, but rather to the appended claims or substantial equivalents thereof.

Claims (6)

1. A method for providing all or a portion of a ship's electrical power generated by burning fuel to a land-based electrical grid while the ship is at port, comprising:
The fuel has an actual sulfur content of 0.50% m/m (wt%) or less and comprises a range of hydrocarbons derived from crude oil from C3 or C5 to greater than C20;
The hydrocarbons have a minimum boiling point and a maximum boiling point, the minimum boiling point being the minimum boiling point of a fraction of crude oil-derived hydrocarbons from C3 or C5 to over C20 that have been combined with the fuel and have not been treated with hydrogen in the presence of a catalyst, and the maximum boiling point being the maximum boiling point of a fraction of crude oil-derived hydrocarbons from C3 or C5 to over C20 that are soluble in a solvent suitable for solvent separation;
the solvent is selected from paraffinic solvents including propane or butane, pentane, heptane;
the maximum boiling point of said component is either not treated with hydrogen in the presence of a catalyst or has been treated with hydrogen in the presence of a catalyst and combined with said fuel;
The method of any one of claims 1 to 5, wherein the fuel meets or exceeds all ISORMA 10 (ISO 8217-10) specifications except for flash point, which is less than 60°C. The method of claim 1, wherein the series of hydrocarbons has a minimum boiling point of naphtha and is soluble in a solvent suitable for solvent separation, and the component exhibiting the maximum boiling point is treated with hydrogen for sulfur removal before or after solvent separation. 1. A method for providing all or a portion of a ship's electrical power generated by burning fuel from the ship to a land-based electrical grid while the ship is temporarily anchored in port, comprising:
The ship fuel is the fuel described in claim 1, wherein the fuel has an actual sulfur content of 0.50% m/m (wt%) or less and comprises a range of hydrocarbons derived from crude oil from C3 or from C5 to above C20,
The hydrocarbons have a minimum boiling point and a maximum boiling point, the minimum boiling point being the minimum boiling point of a C3 or C5 to over C20 crude oil derived hydrocarbon fraction that is combined with the fuel and has not been treated with hydrogen in the presence of a catalyst, and the maximum boiling point being the maximum boiling point of a C3 or C5 to over C20 crude oil derived hydrocarbon fraction that is soluble in a solvent suitable for solvent separation;
the solvent is selected from paraffinic solvents including propane or butane, pentane, heptane;
the maximum boiling point of said component is either not treated with hydrogen in the presence of a catalyst or has been treated with hydrogen in the presence of a catalyst and combined with said fuel;
the fuel meets or exceeds all ISORMA 10 (ISO 8217-10) specifications except for flash point, which is less than 60° C.;
The method includes analyzing the cost of a kilowatt hour (kWh) of electricity generated by a land-based generating facility and the cost of a kilowatt hour (kWh) of electricity generated on the ship by burning fuel on the ship while in port;
(i) The cost of onshore generating equipment to the port's electricity grid,
(a) the ship receives power from the grid; or
(b) the vessel delivering power to the power grid;
The cost of the case, and
(ii) the cost of the ship being temporarily anchored in port,
(a) the ship receives power from the grid; or
(b) the vessel delivering power to the power grid;
Regarding the cost in the case
2. The method of claim 1, further comprising: (iii) connecting the ship temporarily anchored at the port to the power grid and controlling a power generating facility of the ship to send electricity to the power grid for compensation of the ship if the cost of (i)(a)+(ii)(a) is higher than the cost of (i)(b)+(ii)(b). 2. A variation of the fuel of claim 1, wherein the ship fuel is produced by processing crude oil, the fuel having an actual sulfur content of 0.50% m/m (wt%) or less and comprising a range of hydrocarbons derived from crude oil from C3 or C5 to above C20;
The hydrocarbons have a minimum boiling point and a maximum boiling point, the minimum boiling point being the minimum boiling point of a fraction of crude oil-derived hydrocarbons from C3 or C5 to over C20 that have been combined with the fuel and have not been treated with hydrogen in the presence of a catalyst, and the maximum boiling point being the maximum boiling point of a fraction of crude oil-derived hydrocarbons from C3 or C5 to over C20 that are soluble in a solvent suitable for solvent separation;
the solvent is selected from the group consisting of propane or paraffinic solvents including butane, pentane, and heptane, treated with hydrogen in the presence of a catalyst and combined with the fuel;
2. The method of claim 1, wherein the fuel meets or exceeds all ISO RMA 10 (ISO 8217-10) specifications except for flash point, which is less than 60°C. The fuel of the ship is
(a) a viscosity of 10 cSt or less;
(b) a pour point of 0 (zero) ° C. or less;
(c) a density of 820 kg/m ³ to 880 kg/m ³ at 15° C.;
(d) a CCAI of 800 or less;
(e) less than 10 mg/Kg sodium, less than 0.2 mg/Kg vanadium, and less than 0.2 mg/Kg of a combination of silicon and aluminum;
2. The method of claim 1 further comprising one or more of the following features: The method of claim 1, wherein the ship's fuel falls within a SOLAS exception to the flash point requirements for cargo ships or includes a flash point treatment where the ship's fuel has a flash point of 60°C or greater.