JP2021152178A - Fuels - Google Patents

Abstract

To provide a fuel derived from a crude oil that is friendly to a fuel cost and an environment.SOLUTION: The fuel that meets or exceeds all ISO RMA 10 (ISO 2817-10) specifications except a flash point comprises a series of hydrocarbons with a highest boiling point of a component with the highest boiling point among solvent-soluble components suitable for an initial distillation point of naphtha and solvent separation, and the fuel has (a) sulfur in a range of 0.50% m/m (weight%) or less, preferably 0.05 to 0.20 m/m (weight%), and (b) 5.0 mg/Kg (weight ppm) or less, preferably, 1.0 mg/Kg (1.0 weight ppm) or less of metal, and (c) an ignition point of less than 60°C without ignition point treatment.SELECTED DRAWING: Figure 1

Description

The present invention relates to methods and devices for producing fuels with very low sulfur content from crude oils, refined residual oils and other contaminated liquid supplies. The fuel with a very low sulfur content produced by the present invention is particularly cost effective for the onboard of large maritime transport vessels and for large onshore combustion gas turbines.

The present invention is a long-known but unsolved major environmental problem, "on the open ocean".
Targeting that sulfur, nitrogen and metal oxides are carried into the natural environment when a vessel burns cheap low-grade heavy bunker oil and other heavy residues rich in sulfur, nitrogen and metals. There is. Such emissions are global and spread independently of the geographical boundaries of the country.

According to various third-party reports, the specific global emissions produced by burning such heavy fuels for water transport at sea are all vehicles and all vehicles that burn gasoline on land worldwide. It is many times more expensive than the combined diesel vehicle. Such offshore combustion emits SOx, NOx, CO _2, soot and harmful metals. For land vehicles, automobiles,
Many, including trucks, currently use mandatory "highway fuels" with very low sulfur content. Therefore, even though transportation by such large vessels is efficient based on "load per mile" and fuel consumption standards, in practice such vessels generate large emissions.

The introduction of certain important regulations that require ships to use cleaner combustion marine fuels is conditioned on the availability of such fuels in sufficient quantities. A solution is still needed to not command that it is neither technically, economically feasible nor practical.

For example, the International Maritime Organization (IMO), a division of the United Nations, publishes regulations on international shipping. While recognizing the technical constraints, IMO has sought to reduce emissions by tightening sulfur restrictions on marine fuels. IMO has 3.50% m / m of marine fuel burned in the open ocean since 2011 (eg, combustion outside the Emission Control Area (ECA), including 200 nautical miles from the United States, Europe and other coasts). It requires the fuel to have a sulfur content that does not exceed m. In 2015, the IMO amended the rules to limit the sulfur content of marine fuels to generally less than 0.1% for commercial vessels within the ECA.

However, after 2020, the IMO has significantly reduced the sulfur limit in the open ocean to 0.50% m / m. However, the IMO said that such aggressive reductions in 2020 depend on "the results of a review of the availability of required fuel oils to be completed by 2018" and the required fuels. 20 such reductions if is not available
It suggests the possibility of postponing it to 25 years. Regarding the regulation of air pollution in the marine industry,
See Marine Pollution Control Convention (MARPOL), Annex VI.

Therefore, problems can arise realistically and seriously with respect to the lack of availability of low-sulfur marine fuels and the lack of technology to achieve such supplies. For example, 201
A five-year industry publication states, "There are plans to reduce the allowed sulfur content in fuels below the [2014] levels required for emission-controlled waters ... Technology takes years because it is exorbitant for many shipping companies. " Such publications further stated, "Because of the potential for extra costs and mechanical problems, these regulations are continually reassessed and a step-by-step approach is adopted for implementation.""Many marine engines are not designed to handle low-sulfur gas oil, which is much thinner than heavy fuel oil and does not have the lubrication properties of heavy fuel oil. ,
Cooling the fuel to increase its viscosity, injecting additional lubricant into specific parts of the engine, etc.
We have taken various workarounds and are trying to make it work. "(Non-Patent Document 1).

As another example, in 2015, IMO regulations reduced the sulfur content of marine fuels to a maximum of 0.1% sulfur for commercial vessels within the designated ECA. Before entering the ECA, vessels must switch from open-sea burned, high-sulfur but inexpensive high-sulfur heavy bunker fuels to expensive low-sulfur fuels similar to highway diesel fuels. 2
Market supply and price by reducing fuel sulfur in ECA from 1.00% m / m (after July 1, 2010) to 0.10% m / m since January 1, 015. Setting challenges have been raised. The production and supply of marine fuels for IMO-related regulatory compliance competes with the demand for distilled fuels for highways and other onshore diesel applications, with favorable feed streams available, as well as existing refineries and supplies. It keeps the supply network away from highway use of diesel and other low-sulfur distillates. There are also other technical issues on board.

Regarding the 2015 IMO reduction of sulfur content within the ECA, the US Coast Guard said, "Vessels using higher sulfur-containing fuels must change to ultra-low-sulfur (ULS) fuel oil to meet new regulations. Must be. " Vessels using high sulfur fuel oil must use ULS fuel oil at all times during their home and international voyages, at the docks, and within the ECA. It is necessary to develop and implement a switching procedure for switching distilled fuels. The Coast Guard further stated that "other important technologies related to the use of ultra-low sulfur fuel oils and fuel oil switching mentioned in documents produced by ship class associations, insurance companies, engine manufacturers and industry groups. "There are many challenges" and "The energy content per unit volume of ULS fuel oil is
The existing throttle setting may differ from the residual fuel, such as not giving the desired propeller shaft RPM or generator load "(Non-Patent Document 2).

The harsh reality is that refineries are expensive and require significant capital investment, even for relatively minor changes to fuel products and manufacturing equipment and the addition of unit operations. That is. In 2003, refinery evaluation studies in Europe were conducted in anticipation of the need to reduce pollutants in marine fuels, as well as the requirements and capacity to produce such fuel requirements. See, for example, Non-Patent Document 3.

Such reports, in many countries, increase costs and reduce refinery utilization efficiency in trying to produce adequate marine fuel requirements, and in some cases at major ports. It raised major challenges, such as the lack of local basic facilities to locally produce and supply such marine fuels, and the lack of technology and equipment to produce such fuels.

The cited report found only three options. The "re-blending option" (blending heavy fuel oil with low-sulfur fuel) was considered as the lowest-cost option for producing low-sulfur bunker, but because it can process only the minimum amount of material at low cost. , Was not appropriate. This option was relatively low cost for logistics for the remixing of different categories of heavy fuels currently produced at European refineries, but failed in terms of quantity.

A second, more costly option is to use high sulfur-containing crude oils such as Arabian Wright, which are reported to contain 1.8% sulfur, and low-sulfur crude oils, such as 0.14% by weight sulfur. Processing of low-sulfur crude oil by replacing it with African crude oil such as Bonnie Wright, which has been reported to contain. The estimated incremental cost of maritime bunker incurred by this option was considered an overburden for the reasons stated in the report.

Finally, this old report presents a third and most expensive option for the production of low-sulfur ship-grade fuels using decompression residue desulfurization (VRDS). The report concludes, "But in contrast to the degree of desulfurization required for gasoline or diesel, hydrodesulfurization at the bottom of the barrel (resulfurization) is from residual oil to lighter products. It is important to realize that the process is not the very process that the purifier is currently planning to carry out, unless it is combined with some conversion of. Nevertheless, the VRDS depressurizes. If pursued solely for the sole purpose of desulfurizing the residue, the cost of this option is "about twice that of the second option, and is therefore even more unacceptable.

To meet the requirements of IMOs with prior art, operators can load both high sulfur fuel oils for use in the ocean and low sulfur content for use within the ECA, but this choice is for engines. Problems may arise with respect to technology, lubricity, and possible needs for different fuel injection systems for optimal operation and fuel switching mechanisms. Operators can add relatively large, expensive and complex post-combustion flue gas treatment equipment to maintain the highest performance levels. In some cases, liquefied natural gas (LNG) may be used as fuel for ships. In that case, for example, an LNG carrier could choose to use "evaporative gas" as fuel, but a very expensive LNG refueling station to extend this LNG engine concept to all cargo ships. Needs to be widespread,
Ports in rural areas that do not have local natural gas production supply facilities or liquefaction facilities will incur additional costs. However, in all cases, the use of LNG instead of liquid poses a real risk of leakage due to ventilation during refueling or incomplete combustion, or methane release during maneuvering and maintenance. Such methane emissions are of concern, as methane is considered by some to have many times the effect of sulfur dioxide as a greenhouse gas to the environment. From a similar perspective, some argue that emission reductions in marine applications can be achieved by burning natural gas during shipping or while calling at a port with a gas supply docking station. However, from one technical point of view, natural gas has methane leakage problems, and _{although natural gas combustion reduces CO 2} emissions, this _{is not due to low CO 2} emissions, but compared to LNG. If so, the use of natural gas is LNG
_{This is because CO 2} emissions generated in the process of liquefying _{the coal are avoided, and CO 2} is reduced during the recovery and exchange of coal for igniting the power plant supplied to the ships at the port of call. LNG as marine fuel
Or development activities to promote the replacement of natural gas with liquids should be considered, but in the absence of global gas infrastructure and the need for new refueling infrastructure, a practical and cost-effective ocean It does not provide a solution. Gas supply infrastructure is a tough facility and capital investment at ports in countries where gas is not produced and supplied locally.

Patent Document 8 (2009) by Lenglet describes a method for pre-producing crude oil for producing two non-asphaltene oils and pre-distillation, vacuum distillation, solvent deasphaltation, hydrogenation treatment, hydrocracking and residues of asphaltene oils. It describes the preparation of multiple products with hydroconversion. Non-Patent Document 4 states that sulfur is removed by hydrogenation and highly active Ni / M is used.
o Unit design, catalyst selection, hydrogen consumption and other operating conditions for producing products with less than 8 ppm sulfur by the use of catalysts are described. Page 6 of Non-Patent Document 5, Advanced Purification Technology, Publication No. 113/2013 of Specified Edition of Catalagram also has high activity CoM.
o Describes a hydrogenation treatment in which a catalyst is used to remove sterically hindered sulfur to 10 ppm by removing residual steric hindrance sulfur with a highly active NiMo catalyst.

However, effective fuel production technology has long had a void that causes a shortage of low-cost, large quantities of ultra-low sulfur marine fuel. There remains a need to fill this void.

The International Energy Agency's (EIA) oil industry and market sector has issued official documents describing the configurations of processes and equipment used to produce fuels and the configurations, products and margins of traditional refineries. There is. The terms used herein have the meaning specified in Non-Patent Document 4 and are incorporated herein by all purposes, unless otherwise defined or explicitly modified. EIA publications define and discuss configurations for processing crude oil and dividing each barrel of crude oil feedstock into multiple products for different uses or downstream processing.

The genetics of traditional refinery development and growth is somewhat fundamental, based on the evolution of social product demand, from basic kerosene-grade distillates for lighting to gasoline for automobiles and It has evolved into multiple products such as diesel, then aviation grade fuels, and raw materials for many more downstream chemical product applications. All refinery technology developments typically maximize the given splits obtained from each barrel of crude oil for a particular market segment, while maintaining the production of multiple products for a variety of end applications. It appears to have evolved in stages, guided to either adapt or adapt the various streams of the refinery to downstream chemicals.

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

In conventional purification, it is counterintuitive to separate the feedstock into different unit effluents and then recombining all of the effluents. For example, the above EI
References A define and describe conventional or typical atmospheric crude oil distillation, vacuum distillation, fuel solvent deasphaltification, catalytic hydrogenation and integrated gasification combined cycle techniques, but crude oil feedstocks. It does not describe the structure of the process of converting substantially all of the above to produce a single liquid fuel.

Within the scope of conventional refining processes are "upgrading", "topping" or "hydrogenation skimming" equipment. For crude oil upgraders, the primary purpose is usually,
Existing conventional refineries that process very heavy, viscous or solids mixed materials into lightweight, fluid materials to make the full range of fuel products, chemical raw materials and / or petroleum coke. It is to convert so that it can be reprocessed with. Upgraders simply convert heavier crude oil to lighter crude oil for supply to traditional refineries that are individually designed to process sulfur to meet their downstream product specifications. Sulfur reduction or metal removal is not the main purpose of the upgrader. The goal is to modify raw materials with very high densities compared to typical lower density crude oil raw materials. The heavier material is removed or separated from the supplied material, and the resulting modified product material density approaches the density of crude oil processed by existing conventional refinery equipment configurations. For toppings or "mini" refineries, they are often located in remote areas or on board oil sources. Topping refineries typically exclude, in some limited cases, naphtha modification for octane enhancement of gasoline and hydrogenation of multiple distillates to produce various products. Each barrel of crude oil feedstock, which targets naphtha rather than gasoline production, is split into multiple straight distillates, with no subsequent treatment or with minimal treatment. The purpose of a typical topping refinery is to produce a wide range of directly available fuels such as gasoline, kerosene, diesel and fuel oil for consumption in the local market. If some undesired toppings are performed and the topping product is used, or if the residue is not properly addressed, the harmful emissions to the environment will increase rather than decrease. .. Hydrogenation skimming refineries convert crude oil into multiple products, such as topping refineries, but typically to reformers that also produce the hydrogen consumed by the hydrogenation process in diesel production. Limit the amount of heavy naphtha added. Hydrogenation skimmers, like topping refineries, typically produce a wide range of gasoline, kerosene, diesel and fuel oils for local consumption, rather than just one product.

Various aspects of adapting a hydrogenation process are known in the art, including having an independent series or parallel hydrogenation reactor zone or an integrated hydrogenation reactor zone. Patent Document 1 of Cash et al. And the references cited therein disclose integrated hydrogenation of different feeds, including hydrogen and liquids from separate hydrogenation zones. The streams are distributed or combined by the disclosed methods. Various aspects of the use of solvent separation to extract deasphaltated oil from the pitch in the heavy residue stream and use the deasphaltated oil as a raw material for hydrogenation are to produce multiple product streams. When used, it is known in the art. For example, Brierley
Et al. Patent Document 2 describes the production of deasphaltated oil without cracking or decomposition by separation of feedstock based on solubility in liquid solvents such as propane or other paraffinic solvents below heptane such as butane and pentane. Describes solvent deasphaltization for. The residual pitch contains a high content of metal and sulfur. De-asphalated oils are hydrogenated to remove sulfur, nitrogen, concarbons and metals, as described in the references for the production of several products, including naphtha, kerosene, diesel and residuals. can do.

In the global market, sulfur is used to address global environmental problems at sea or on land with little or no natural gas resources and low fuel oil or unrefined crude oil with low power generation efficiency. And a large amount of fuel with low nitrogen content and essentially free of metal pollutants needs to be available.

Fuel producers require designs that differ from those developed for traditional refining to produce multiple product slate. To keep costs low, the design must be equipped with only the equipment needed to produce large quantities of clean fuel in a cost-effective and thermal-efficient manner in a way that keeps capital investment low. .. The design aims to produce primarily marine fuels, rather than extracting a relatively small fraction of each barrel of crude oil for marine fuels and using most of the barrels for other purposes. Should be.

The world needs a large amount (in an efficient way to avoid wasting energy expressed in short forms such as British Thermal Unit (BTU)) in an economical way for marine applications. It is a new "game changer" process that provides solutions to technical problems related to how to make relatively clean liquid fuels. Such a process fuels existing liquid marine fuel stations (eg, those that supply high sulfur fuel oil (HSFO)) that are spread around the world instead of creating new basic facilities for LNG. The facilities required and the associated capital and operating costs will be minimized. Any new process like this will use liquid BTU as an ultra-low sulfur diesel (UL) manufactured primarily for automobiles and trucks.
It is necessary to take a direction that supports the production in a form that is more cost-effective than SD). Such available diesels are widely available, but cost issues, and U
Due to lubricity issues that arise when LSDs are used in many existing marine diesel engines, they are not widely used at sea by large marine transport carriers.

International application PCT / US1999 / 00748 U.S. Pat. No. 7,686,941 U.S. Pat. No. 8,088,184 U.S. Patent Publication No. 201402217113

Josiah Topfer U.S. Coast Guard Vessel Inspector / Auditor-Accident Investigator, "Is it true that the 15 bigest ships in the world product morale product published on the Internet" article the car U.S. Coast Guard, U.S. Department of Homeland Security, Compliance Department, "Ultra Low Fuel Oil & Compliance with MARPOL Requires -15, Washington DC European Commission Directorate-general of the Environment, "Advice on Marine Fuel: Potential price premium for 0.5% S marine fuel; particular issues focusing fuel contract engine final engine" Draft, contract number ENV. C1 / SER / 2001/0063, Or der Slip n ° C1 / 3/2003, October 2003 US Energy Information Administration, "Glossary", October 2016 Wright et al., Lloyd's Register FOBAS, "Marine Distillate Oil Fuels Issues a nd implications associated with the ha rmonization of the minimum flashpoint requirement for marine distillate oil fuels with that of other users", writing for the Danish ship main Association, 2012 Rall et al., "Sulfur Compounds in Cru de Oil", Washington DC, UNT J. P. Wauquier "Petroleum Refining: Crude Oil. Petroleum Products. Process Flowsheets", 1995, Institut Francais du Petroleum Ackerson et al., "Revamping Diesel Hydrotrators For Ultra-Low Sulfur Using IsoTherming Technology" Shiflet et al., "Optimizing Hydroproc essing Catalyst Systems for Hydrocrack ing and Diesel Hydrotreating Applicati ons, Flexibility Through Catalyst", page 6, A dvanced Refining Technologies Catalagr am, Special Edition Issue, No. 113/2013

The present invention makes it possible to supply large quantities of very low sulfur, nitrogen and substantially metal-free fuels at low cost and fill voids in effective fuel manufacturing techniques. The fuel is particularly useful not only for large-scale land applications such as combustion gas turbines for power generation, but also for marine applications. As used herein and in the claims, the terms "essentially metal-free" or "zero metal" contain metals ranging from zero to less than 100 weight ppb (parts per billion). It means a quantity or a content that is so low that it is difficult to reliably measure it with conventional online instruments.

In conventional refining, crude oil feedstock is extracted into many parts, each part being sent to a separate market channel downstream. In contrast, we have captured each barrel of crude oil feedstock while capturing pollutants sulfur, nitrogen and harmful metals, with the exception of the crude oil portion, which provides the process utility and flow for conversion and capture. We have found that the maximum amount of can be converted into a single ultra-clean fuel. The present invention takes crude oil feedstock as only the minimum number of parts required for the capture and control of contaminants and then reassembles those parts to form a single fuel product.

Therefore, the present invention is different from conventional refining that divides each barrel of crude oil feedstock to accommodate multiple markets such as gasoline, diesel, fuel oil, or feedstock for downstream chemical manufacturing or application. Different, the method of the present invention is aimed at producing a primary clean fuel product. The present invention provides a low cost polishing system for unrefined and residual oils, which is suitable for high sulfur bunker fuels and other heavy residues used in commercial transport vessels and power plant combustion systems. It is necessary to produce a large amount of clean fuel on an alternative commercial scale. The present invention provides such fuels as well as methods and devices for making the fuels to reduce sulfur in a cost-effective manner.

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

In many variants of the invention, an amount that is essentially all of each barrel of feed, characterized as greater than or equal to 90% by volume in a particular variant, is converted to a single fuel and such variants. In the example, only a minimum amount, less than about 10% of each barrel of crude oil, is consumed for process utilities and flows for the conversion and capture of contaminants. The process of the present invention
For other operational considerations such as hydrogen balance, local demand for asphalt and coke and other residual products, overall production economy, and local availability of alternative low-cost process fuels and electricity. Allows adjustment of feedstocks allocated for fuel production, process utilities for conversion and capture of contaminants and flows. In a variant, with multiple hydrocarbon products, when at least 70% by volume of each barrel of crude oil feed is converted to a liquid fraction and subsequently processed, or untreated but compounded, It forms substantially one liquid fuel product with a sulfur content that does not exceed the target hydrocarbon content, and the rest of each barrel of the crude oil supply is in the residue or other vapor or product. Exists in.

Unlike conventional refining, which separates the crude oil supply into multiple parts and sends them to separate market channels, the present invention separates the crude oil supply into the minimum number of parts required to capture and control pollutants. Then, the removed parts are reassembled to form one fuel product that is very low in sulfur and nitrogen and is essentially metal-free. The methods and equipment configurations of the present invention make it possible to produce large quantities, low cost and efficient low sulfur fuels required for regulatory compliance in large marine and onshore turbine applications. These new fuel deployments have substantially lower cost of capital and operating costs compared to alternative traditional crude oil refining, thereby having very low sulfur and nitrogen levels in a very cost-effective manner. It can mass-produce fuels that are essentially metal-free. These new processes enable a very cost-effective means of simplifying the energy supply chain from oil fields to marine engines or onshore power plants.

For the shipping industry, the novel configuration of the present invention provides the amount of low-cost, low-sulfur marine fuel required to meet global marine sulfur reduction targets. The novel fuel production methods and equipment arrangements of the present invention have substantially lower cost of capital and operating costs than conventional crude oil refining, resulting in very low sulfur content and essentially metal-free. Produce large amounts of marine fuels with very low nitrogen content in a very cost-effective manner.

The fuel of the present invention replaces low grade heavy bunker oils high in sulfur and metals and is SO.
Significantly reduce the emission of x, NOx, CO _2, soot and harmful metals to the open ocean. In the practice of the present invention, instead of sulfur and metals that are carried to the environment when burning bunker oil,
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 these fuels provide sufficient lubricity to avoid excessive wear of the marine engine. Having, these new fuels can use the existing bunker ring fuel infrastructure without heating and fluidizing the fuel compared to other alternative fuels, so they are in tanks on land or on board. The energy consumed to heat the fuel can be reduced.

In one variant, the fuels of the invention are also crude oil or in large onshore combustion turbines located in equipment such as single-cycle or combined-cycle power plants, such as those that produce electricity and desalted water. It provides an alternative to burning heavy residues. The turbines that burn the fuels of the present invention _{have significantly lower turbine emissions of NOx, SOx, CO 2,} soot, harmful metals and other combustion by-products, and depending on the source, contaminated heavy crude oil or refinement. When burning residual oil, there is less contamination in high temperature zones or under ash formation conditions.

The present invention relates to a centralized conversion of a composite hydrocarbon feed material into a single fuel product for use in combustion applications such as marine engines, combustion gas turbines or combustion heaters. In a basic embodiment of the invention, a single ultra-clean product fuel is returned with crude oil coming in from the front, controlled to low sulfur levels, reduced nitrogen and demetallized. In a variant, the feed for distillation is one or more crude oils combined with one or more high sulfur fuel oils or other heavier residual oils, vacuum distillation, solvent separation, Flow to one or more other unit operations such as distillation or gasification A crude oil with the addition of light tight oil, high sulfur fuel oil, or both as part of the feed. ..

In other applications in the art, the terms "high sulfur fuel oil" or "HSFO" have different, often dissimilar, contradictory, and confusing meanings in various technical articles, patents and legislation. It is assigned and some of it changes over time. As used herein and in the claims, "high sulfur fuel oil" or "HSFO" is 0.50.
Means any substance used as a fuel with a sulfur content greater than% m / m (0.5% by weight). The terms "heavy oil", "heavy residual oil", "residue", "residue" or "other heavier oils" as used herein have a sulfur content of 0.50% m / m /. m (0.5% by weight)
) Exceeds petroleum-derived hydrocarbon substances. The term "high sulfur" means a value 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 a combination of streams with different sulfur contents. In a variant, each such combined stream could have a very low sulfur content by adjusting the unit operating conditions and flow rate to reduce the addition or removal of a stream with a very low sulfur content, or by different sulfur contents. By blending the feed, a provisional target sulfur content is formed. Variations of the present invention include (i) other crude oils, (ii) bunker fuels, (iii) high sulfur fuel oils or other distillates, or (iv) others, as required. 1 of other high sulfur or metal contamination residues, from sources of
Includes controlling product sulfur levels by supplying one or more. As used herein and in the claims, the terms "essentially metal-free" or "zero metal" have a metal content of zero to less than 100 weight ppb (parts per billion). It means a content that is so low that it is difficult to reliably measure it with conventional online instruments.

We have discovered that the production of low-sulfur fuels can be optimized by addressing the sulfur content distributions of different crude oil feedstocks.

The present inventors have found that a relatively large part of the case, and (ii) the sulfur present in the particular fraction in (i) a relatively small amount of a basic form of only sulfur basic H _{2 S} or RSH thiol type Can be addressed if is present in a more complex organic structural form, then the sulfur content begins to increase more rapidly and in some cases exponentially compared to lower fraction levels. Process flow rates and operating conditions can be adjusted based on the predicted break point fractions at higher or higher levels, such as.

We allow the bypassing of a particular flow to maximize that bypass, avoiding or reducing the processing of flows containing sulfur forms with less basic complexity, and include more complex forms. We have found that it is possible to arrange processes and equipment configurations so that the flow to be processed can be processed in different ways. This selectively excludes certain streams from hydrodesulfurization, and for other streams, feed the same to different hydrodesulfurization units to adjust different hydrotreating unit conditions, or solvents and / or Removal can be adjusted by reactive chemical-based treatment. It is then treated with multiple solvents or other removers in one or more removal units, and the respective ratios of the removers in each unit selectively remove less complex or high sulfur-containing molecules. It may include adjusting based on the sulfur distribution to each unit.

The terms "kerosene" and "light distillate" are often used in different references with the same, overlapping, or different meanings, but in a uniform temperature range (eg, 190 ° C. to 190 ° C.). It is defined based only on the fraction boundary point of the atmospheric distillation column at 250 ° C. or 180 ° C. to 230 ° C.), not on the sulfur content. Instead, expedient sulfur content measurements are made and reported based on the fraction boundary temperature range determined by the specifications of each product from conventional refineries. The inventors have found that this is not the best.

The present inventors have found that the cost reduction of low-sulfur combustion production can be optimized by changing the basic method of operating the crude oil distillation column. We have taken out specific distillates from kerosene,
Sidestream sulfur content, omitting analysis of the sulfur content of the crude oil feedstock or feed mixture to the distillation column, rather than the standard product temperature range specification for downstream use of jet fuel, diesel, etc. We found that it should be done based on the amount.

The present inventors have discovered how to define a "breaking point", which means that the change in sulfur content (slope of the graph) per unit volume change in the extracted product is no longer substantially flat. Instead, at the break point, as the withdrawal volume increases slightly, the sulfur content begins to change significantly, such as the slope of the graph per unit volume begins to change rapidly or. It begins to increase exponentially. Further, after the break point, the type and composition of the sulfur-containing compound, as well as the complexity, typically change depending on the type of crude oil supply raw material. A break point is an indicator from the separation of a stream or part of a stream that requires desulfurization, which can minimize or eliminate desulfurization.

The inventors directly extract and accumulate the maximum amount of a substance having a sulfur content below the break point and avoid or reduce the cost of processing for reducing or removing sulfur downstream. If you want to maximize the production of all liquids with the sulfur content of the following extracts,
We have found that the cost of capital and production of low-sulfur fuels can be minimized.

We have found that relatively large amounts of such substances below the break point, and in certain crude oils, the portion within the narrow specific zone above the break point, have already been treated to remove sulfur. It has been found that when combined with the extract, no treatment for sulfur removal or subsequent significant treatment is required. The present inventors not only promote atmospheric distillation conditions mainly by increasing the temperature profile of the feed or column, but also reduce or eliminate reflux, reduce the crude oil supply rate, or maximize the withdrawal amount to near the break point. By altering the composition of crude oil hydrocarbons or sulfur by mixing or diluting the supplied crude oil, the production of such untreated substances is maximized and the cost of desulfurization or other processing operations for the entire stream is reduced. do. Breakpoints are not defined from the standpoint of standard industry classifications or regulations that set temperature ranges for retrieval.

Within the scope of this specification and patent claims, we have defined "breaking points", in relation to crude oil analysis or other measurement methods, the mass% or volume of crude oil on the x-axis and sulfur on the y-axis. When the content is plotted, it is defined as the point where the sulfur content begins to increase rapidly or exponentially from a horizontal or near position in the sense of a large change in the slope of the graph per unit volume. The difference in the x-axis direction is the change in the unit volume of the distillate, the difference in the y-axis direction is the change in the sulfur content per unit volume, and the gradient is the slope of the graph. The slope of the slope of such a graph moves from a value close to zero or near horizontal to abruptly above 0.2 and then rapidly above 1 to a somewhat exponential increase in sulfur content. Moving towards, the break points vary based on crude oil or other feedstock to the distillation column. Therefore, "break point retrieval" or "hydrocarbon delimiter retrieval" exceeds the end point of the naphtha range, eg, the end point of the unstabilized pristine straight naphtha range, but per unit volume as described above. Provided is a means for determining the division into a hydrocarbon-containing liquid that boils below the break point, which is the point where the slope of the graph changes significantly and the sulfur content begins to increase rapidly or exponentially.

In the present specification and claims, the inventor may use the base "break point extraction" or the base "sulfur break point extraction" as an unstabilized pristine straight naphtha with respect to the sulfur content of the fraction. It is defined to mean a hydrocarbon-containing liquid that boils above the end point and below the break point in the range of When the break point is selected, the actual sulfur content of the combination fuel does not exceed the target sulfur content so that it is formed from all streams above the break point take-out selected for. In a variant, the fuel can be produced according to whether the target sulfur content is at the sulfur break point, or above or below the sulfur break point, and the combination of flows that produce the fuel is the actual sulfur content of the fuel. Is made efficiently based on the break point so that the sulfur does not exceed the sulfur target.

For many crude oils, sulfur demarcation points for atmospheric distillation columns, such as those that start boiling at 180 ° C or 190 ° C (or other kerosene range starting points), etc. (various methods in the art). It contains most of the substances in the kerosene range (as defined in) and can include lower or higher temperature range substances for simplification. However, the sulfur content, rather than the temperature or historical definition of substances in the kerosene range, is the determinant of the end point of the sulfur break range. The fuel can be formed according to the case where the target sulfur content is the sulfur break point, and the combination of flows forming the fuel is made so that the actual sulfur content of the fuel does not exceed the sulfur target.

In one embodiment, the crude oil feedstock is separated into streams, one or more liquid portions of such separation stream are treated, and the other portion is untreated. Most of the treated and untreated liquid streams are then recombined to form a liquid fuel with an actual sulfur content below the target sulfur content. The step steps include: (a) a light overhead distillation gas, a metal-rich residue insoluble in one or more solvents used for solvent separation, a gas containing sulfur, by means of one or more distillation and solvent separation steps of crude oil. And separate into a liquid distillate above the sulfur break point and a liquid distillate below the break point, (b) a liquid distillate above the sulfur break point, not a liquid distillate below the sulfur break point or an insoluble residue. To form one or more hydrotreated flows with reduced sulfur content, while leaving the other portion untreated, and ( c) Including the formation of the above liquid fuel having the actual sulfur content below the sulfur break point as the target sulfur content in combination with the liquid distillate below the hydrogenation treatment flow break point.

In yet another embodiment, the present invention provides a method of reducing emissions exceeding the IMO specification by a ship in the open ocean, within an ECA, or at a port by using a fuel produced in accordance with the present invention. The fuel may be at sea, in the ECA, or at a port.
It has an adjusted sulfur content below the maximum IMO specification that can be applied at the location of fuel use by the ship. In this way, the vessel can exceed the requirements and general expectations of the IMO.

In other embodiments, the present invention provides a method for ships that sells electricity generated using the fuel of the present invention at a port to a land distribution network, eg, to offset marine or port fuel costs. offer.

We have found that low cost ultra-clean marine fuels can be produced that far exceed the IMO's expectations for sulfur and metal limits, while taking into account the flash point and adjusting in an appropriate manner.

Thus, we have found that (i) minor flash point changes, (ii) large environmental benefits (huge SOx and NOx reduction and harmfulness), especially associated with large fuel consumption by large cargo ships. We have found a technical way to replace it with (essential elimination of metal). So far, no one has made such a discovery.

The International Convention for Safety at Ocean (SOLAS) outlines the flash point of fuel and its permissible use on cargo ships. "For many, the minimum flash point of 60 ° C for fuel in general operation as set forth in the SOLAS Convention may seem to be one of the foundations of the Law of the Sea, which was first introduced in the 1981 amendment. There are the first three SOLAS
The Convention (1914, 1929 and 1948) does not place a limit on the flash point of petroleum fuels, and even the 1960 Convention states that the fuel used by internal combustion engines has a flash point of 43 ° C or higher. I just requested a "new" passenger ship. It should be noted that this clause was essentially inherited by the current 1974 Convention as it was originally adopted. ”The above is a quotation from Non-Patent Document 5.

Writ et al., The flash point is empirical, not a real value, and "the flash point value is by no means a" safe "/" unsafe "border, and in the past such It has never been a borderline. " As a result, since the beginning of the oil industry, flash points have been used with some error as a means of identifying products that require greater control and attention with respect to storage and use. In fact, in marine applications, petroleum fuel fires,
Rather than being caused by vaporization ignition, it is caused by ignition caused by contact of the fuel with a surface higher than the spontaneous combustion temperature due to leakage or breakage of the pipe. Nevertheless, the flash point is
It has been used as a safety parameter in the Petroleum Safety Act from the beginning, even taking into account the fact that it is sometimes an empirical value, albeit with respect to some arbitrarily set limits.

SOLAS is making an exception for cargo ships. SOLAS stipulates that oil fuels with a flash point below 60 ° C should not be used, with the exception of "On cargo ships, [SOLA]
S] The use of fuels that have a flash point lower than the flash point specified in Section 2.1 (eg, 60 ° C.), such as crude oil, does not allow such fuels to be stored in any engine room, and It can be tolerated subject to the approval of the authorities. " It should also be noted that some countries do not have flash point standards and others allow relatively low flash points for marine applications.

The fuel flash point can be processed and adjusted as needed. As used herein and in the claims, the term "flash point treatment" means a composition that raises the flash point when combined with a material. In one variant, flash point treatment reduces the vapor pressure of the added material to reduce the risk of vapor ignition. In one variant, the flash point modifier is a solid or liquid additive with a flash point of 60 ° C. or higher, which is added to the low flash point fuel to raise the flash point of the fuel. These can include various types of fine particles and oils. For example, high flash point additives for treating carbon fuels are disclosed. For example, Patent Document 3 of Huges et al. Describes a "high flash point diluent" selected from the group consisting of paraffinic base oils having a flash point of 200 ° C. or higher and mixtures or combinations thereof. teeth,
Illustrates Calumet 100 (FP210 ° C.), Calpar325 (FP240 ° C.) and CalparP950 (FP257 ° C.) and paraffinic base oils and mixtures or combinations thereof having a flash point of 200 ° C. or higher, available from Calumet Lubricants, Indianapolis, Indiana. ing.

We have found that (i) minor flash point changes, (ii) large environmental benefits (huge SOx and NOx reductions and harmful metals) associated with large fuel consumption, especially by large cargo ships. I found a technical way to trade it for (essential exclusion of). So far, no one has made such a discovery.

Explanatory drawing schematically showing the sulfur content of various actual and hypothetical crude oils showing a break point range. Schematic diagram showing the 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 invention, the method for converting at least a portion of a hydrocarbon feed, crude oil with sulfur and metal, into a single liquid product is (i) one or more of the feed. By the distillation and solvent separation steps of, atmospheric distillation conditions as defined by the EIA or better, even if the debutane tower system is preferred due to certain local circumstances or at a cost that should be eliminated in other circumstances. Light overhead distillation gas (including only non-condensable distillation gas), metal-rich residues insoluble in one or more solvents used for solvent separation, sulfur-containing gases, and treated as being within the distillation range. Separation into a sulfur-containing liquid fraction, having distillates (having at least some of the substances in the kerosene range for some supplies) and hydrocarbons in the vacuum light oil range, (ii) below the sulfur break point. A selected withdrawal liquid fraction (preferably soluble) that is higher than the sulfur break point, rather than the withdrawal liquid fraction in (and preferably with respect to any fraction insoluble in the solvent used for solvent separation). Only the liquid liquid fraction is selected for the hydrocarbon treatment) is hydrocarbonized in one or more hydrocarbon treatment steps to reduce the sulfur content in one or more hydrocarbon treatment streams. And (iii) combining the untreated fraction with the treatment flow to form a fuel whose actual sulfur content is less than or equal to the target sulfur content. As used herein, the terms "step" or "zone" are used in device configurations and /.
Alternatively, it can refer to a unit operation or area having one or more processing operations having one or more divisions of a unit operation or subzone. Equipment items can include one or more tanks, vessels, distillation columns, separators, reactors or reactor vessels, heaters, exchangers, strippers, pipes, pumps, compressors and controllers. In a preferred modification of the invention, substantially all hydrocarbon compositions of the feed are separated into fractions, which are then recombined to form a fuel, one liquid fuel product. The fuel is a single liquid fuel product containing hydrocarbons in the range from the original supply, liquefied petroleum gas, or in one variant, from naphtha to hydrotreated deasphaltated oil. It contains and does not form multiple hydrocarbon products, but (i) in the light overhead gas of the distillate, (ii) in the residue insoluble matter, and (iii) in the sulfur or metal recovery stream. Hydrocarbon compositions containing hydrocarbons are excluded. Such a range is C3 or C5 to C2
Substantially the entire range of 0 or greater crude oil-derived hydrocarbons, said hydrocarbons having an initial boiling point, which is the lowest boiling point of any fraction in the untreated stream combined with the fuel. It has the highest boiling point, which is the highest boiling point of the processing flow combined with the fuel. As used herein and in the claims, the term "untreated" means unhydrogenated to reduce or remove sulfur, nitrogen or metals. In one variant, such fuels are substantially C
Range of hydrocarbons derived from crude oil from 3 or C5 to C20 or higher, or from about 35 ° C to about 31
Includes those having a range of crude oil-derived hydrocarbons having an initial distillate in the range of 5 ° C. or higher, preferably a range up to the last distillate of the deasphalized oil and the start of the deasphalized residue. , Which are insoluble in the solvent selected for solvent separation. In an even more preferred variation, the fuel of the present invention is a hydrocarbon in the range from the lowest boiling point portion of the untreated liquid fraction from atmospheric distillation to the highest boiling portion of the hydrotreated solubilized material from solvent separation. Including combinations. Therefore, the preferred fuels of the present invention are conventional gasoline, which are taken out in selected subranges and do not have a meaningful content in the maximum range of such hydrocarbons.
It is the exact opposite of diesel, kerosene and fuel oil. Therefore, one embodiment of the present invention is:
It is a fuel obtained as a single product for processing crude oil, and the fuel is 0.5% by weight or less.
It preferably has an actual sulfur content of 0.1% by weight or less and has substantially the entire range of C3 or C5 to C20 and above crude oil derived hydrocarbons. The hydrocarbon has an initial boiling point, which is the lowest boiling point of any distillate of the crude oil under atmospheric distillation conditions, and is the highest boiling point, which is the end point of the residual portion of the crude oil, which is insoluble in a solvent suitable for solvent separation. Has. In a variant, such a fuel is C3
Alternatively, it comprises substantially the entire range of crude oil-derived hydrocarbons from C5 to C20 and above, the hydrocarbon being the initial boiling point and the lowest boiling point of any fraction in the untreated stream combined in the fuel. It has an end point that is the highest boiling point of the combined processing flow in the fuel. One variant comprises a light overhead distillation gas of crude oil, a metal-rich residue insoluble in one or more solvents used for solvent separation, a sulfur-containing gas (including a sulfur-containing purge gas), and sulfur. It is separated into a liquid fraction, which has (i) a liquid fraction below the sulfur break point and (ii) a liquid fraction above the sulfur break point, both of which are the solvents used for solvent separation. Soluble or insoluble in (b) soluble liquid fractions above the sulfur break point, rather than liquid or insoluble fractions below the sulfur break point, are hydrolyzed by one or more hydrogenation steps. To form one or more treated streams with reduced sulfur content, (
c) The untreated fraction is combined with the treatment flow to form a fuel whose actual sulfur content is less than or equal to the target sulfur content.

In a variant, such residues are used for power production, as well as the production of at least a portion of hydrogen to capture at least a portion of the metal in the hydrotreated and removed gasifier solids. Combusted in one or more gasifiers, or the residue captures fumes sulfur and metals for use in auxiliary hydrogen generation unit operations to supply hydrogen for power generation and hydrogenation. Burn in one or more boilers. Preferably, all gases containing sulfur are sent to one or more common sulfur recovery units.

By implementing the present invention, the actual sulfur content of the fuel can be adjusted to meet the target sulfur content limiting specifications, eg, of continuous flow of untreated and treated flows for the combination forming the fuel. By adjusting the amount, the IMO specifications of marine fuel or the sulfur limit of combustion gas turbines can be met. For example, the target sulfur content of the fuel, EC
Adjusted to meet one or more target IMO specifications inside or outside A, eg, 3.5% by weight, 0.5% by weight, 0.1% by weight, or a specification selected from other IMO specifications. can do. Fuels produced according to the methods of the present invention are useful in combustion heaters such as marine engines, combustion gas turbines, boilers, and other applications.

In one variant, at least one of the hydrogenated streams is an ultra-low sulfur stream with less than 10 weight ppm of sulfur, which is actually by increasing or decreasing the amount of stream for the combination. Is used to regulate the formation of fuels whose sulfur content is less than or equal to the target sulfur content. In another variant, at least one of the hydrotreated streams is an ultra-low sulfur stream with sulfur of 10 wt ppm or less, and the untreated fraction has a sulfur content that exceeds the target sulfur content. The untreated fraction is then used as a trim control, and by reducing or increasing the amount of such untreated fraction with respect to the combination, a fuel having an actual sulfur content less than or equal to the target sulfur content is formed. In yet another variation, the first is a reduced sulfur stream with a sulfur content of less than 10 wt ppm when converting the crude oil feed into substantially one liquid fuel product rather than multiple hydrocarbon products. A second hydrocarbon treated fuel distillate having a reduced sulfur flow with a sulfur content in the range of 0.12 to 0.18 wt% was made and the untreated distillate was The first hydrocarbon treatment stream, the second hydrocarbon treatment stream, or both having a sulfur content that is less than or equal to the break point sulfur, exceeds the break point sulfur, and exceeds the target sulfur content, is the same for the above combination. By increasing or decreasing the amount of such flow, it is used as a trim control to form a fuel whose actual sulfur content is less than or equal to the target sulfur content.

In an even more preferred embodiment, the sulfur content of one or more crude oils, residual oils and other feeds is selected or the processing conditions are adjusted to at least 70 volumes of each barrel of the crude oil feed. When% is converted to a liquid fraction and then treated or untreated but combined, it forms a fuel with a sulfur content that is less than or equal to the target sulfur content, rather than multiple hydrocarbon products, and described above. Less than 30% of each barrel of crude oil supply is directed to non-fuel. In a preferred modification of the invention, at least one of each barrel of the hydrocarbon-based feed, depending on the composition of the feed, hydrogen balance, process economy and other factors, as well as process operating conditions and adjustment of flow velocity. Excludes streams where 80% by volume, more preferably about 90% or more of the barrel feed is not a plurality of hydrocarbon products and has very low sulfur 1
Converted into one liquid fuel product. The stream with very low sulfur is used as a trim to increase or decrease the trim flow and control the sulfur content of the final fuel product to a level that does not exceed the target sulfur content. Excess amounts of trim flow can be transferred individually for material balance and inventory control purposes. In such a preferred modification of the invention, about 10-30% by volume or less of each barrel of the crude oil feed is trapped in the metal-rich residue after atmospheric and vacuum distillation by solvent extraction.

In another variant, a high sulfur fuel oil having a sulfur content higher than the target sulfur content is used alone or in between before or during the combination of all treated and untreated fractions to form the fuel. Add with light tight oil. The high sulfur fuel oil can be supplied to one or more of the distillation steps, solvent separation steps or hydrogenation steps described above. In one preferred embodiment, the ultra-low sulfur stream has sulfur in the range of 10 wt ppm or less, the untreated fraction has a sulfur content above the target sulfur content, and the untreated fraction is It is used to increase or decrease the amount of the untreated fraction for the combination to form a product fuel whose actual sulfur content is less than or equal to the target sulfur content.

The equipment for practicing the method of the present invention can reduce its equipment area to a range of 20% to 30% of the equipment installation area of a conventional refinery having a typical downstream processing unit. Therefore, the cost of capital per barrel of the supplied material to be processed is substantially reduced. For example, in one particular embodiment of the invention, one or more of atmospheric distillation, vacuum distillation, solvent separation, hydrogenation and gasification, with the auxiliary equipment required to capture sulfur and metals. There is no hydrocarbon treatment operation downstream of the hydrogenation treatment, except for gasification, which uses only and uses the auxiliary equipment required to capture sulfur and metals.

A variant of the process configuration of the present invention is of an island structure (utility island) of equipment that provides integrated metal and sulfur trapping means while providing the necessary steps for electricity in addition to hydrogen, steam and fuel gas. Effective integration provides high efficiency, low cost operation.
Utility islands treat heavy metal-rich residues to capture and eliminate metal pollutants as a component of potential air emissions, preferably integrated, and therefore at a lower cost of capital, sulfur capture and treatment. , And having one or more gasification systems using sour gas and acid gas off-gas treatment from all sources as potential sources for removal. The island configuration of the present invention is an electrical process via a highly efficient combined cycle power generation means that utilizes hydrogen for a hydration process step and a specific flow for an electrical process and usually a waste flow to meet the process requirements. For producing steam and fuel gas.

In one variant of this embodiment of the invention, a light tight oil has a heavier hydrocarbon in the bottom fraction and residue sufficient to provide a treatment balance for hydrocarbon treatment and corresponding hydrogenation. It handles cases that are not contained in, and makes it possible to hydrocarbonize such light crude oils to reduce sulfur and metals and decontaminate them. This method adds the light crude oil to any or all of all heavier feeds leading to atmospheric distillation, vacuum distillation or solvent separation treatment, either separately or mixed with other feeds. Have a step to do.

In one variant, the design of the equipment for reduced pressure distillation, solvent separation, hydrogenation and gasification operations downstream of atmospheric distillation is from high sulfur fuel oil or another source outside the battery limit of the operation. Large enough to have additional or reserve capacity to process the additional heavy residue of the fuel, forming a fuel whose actual sulfur content is below the target fuel sulfur content limit level and from the additional heavy residue. Captures at least some of the sulfur and metals in the.

In another embodiment, the invention uses the fuel of the invention to generate electricity while the vessel is moored in a port, reducing rural emissions and selling to the land grid. Provide a way to do it. In one variant, the invention provides a technical method of reducing emissions in and around the port, which (a) produces the power normally supplied to the distribution network at or near the port. Check for sulfur or metal emissions per kilowatt hour (KWH) generated by onshore power plants, including those associated with the use of local power supplies when vessels are connected to such distribution networks at ports. (B) Includes technical analysis to confirm the emissions of sulfur or metal per KWH generated by the electricity generated on board the same vessel while at the port at point (b) (a). Comparing a) and (b), if the emissions generated by the ship due to (b) power generation are lower than the local power source of (a), the emissions on board are reduced and onboard. Providing all or part of the power generation to the distribution network. In this embodiment, if the electricity supplied locally is from a particular type of coal combustion source, or lower emission options are not available for local power generation, heavy crude oil or residual oil is burned. And when used for power generation, it can be particularly useful for reducing environmental emissions. Without offset, such provision by the ship to the local distribution network would be if the KWH cost of the ship's generated power exceeds the KWH cost of the local distribution network power, or so by the ship to the local distribution network. Unless the provision does not benefit the vessel in any other way, such as offsetting by emission reduction deductions such as subsidies paid by low emission power generation, unless there is an offset of port usage fees. Will not be.

If the ship's provision to the local power grid is beneficial, the ship will provide all or part of the power generated on board the ship to the onshore power grid while moored at the port using the fuel of the present invention. The profits generated by doing so can offset or reduce the cost of fuel incurred at sea. The above revenues generated from the provision to the distribution network during berthing at the port are the fuel cost for marine navigation depending on the berthing period at the port, and the actual fuel cost for marine navigation with these new fuels is high for marine navigation. It can be offset to a level that is lower than the cost of sulfur fuel oil.

FIG. 1 is a schematic plot of the sulfur content of various actual and hypothetical crude oils showing a break point range. The exemplary crude oil sulfur profiles 4, 5 and 6 are plotted based on the center points of the actual data extracted from Non-Patent Document 6. Hypothetical Crude Oil Sulfur Profile 1,
A few are obtained in part from actual data taken from various sources, including Non-Patent Document 7.

FIG. 1 shows a method of suggesting a definition of a "break point" for different crude oils for the process configuration of the present invention. FIG. 1 illustrates a break point, which is a point where the change in sulfur content (slope of the graph) per unit volume change of the extracted product is no longer substantially horizontal or flat. Instead, at the break point, the sulfur content begins to increase rapidly or exponentially as the withdrawal volume increases slightly, resulting in a large change in the slope of the graph per unit volume. In addition, after the break point, the sulfur-containing compound, the type and composition, and the complexity change depending on the type of crude oil supply raw material. Breakpoints allow you to determine how best to bypass costly intensive hydrogenation for operational efficiency.
Yet it makes it possible to produce fuels that meet the target sulfur content limiting specifications. That is, the break point is the maximum sulfur content of the atmospheric crude oil distillate, which is guided away from or reduced from further downstream treatments to reduce the sulfur content, eg, away from the hydrogenation treatment. Can be done. Fractions above the break point are led to downstream treatment to reduce sulfur content, while fractions below the break point are not treated, leading to substantial operational savings. In conventional purification, retrieval is fixed by temperature range rather than sulfur content. The target sulfur content can determine the choice of break point as an example of end-use requirements. If the break point is set too high, the untreated stream with an excessively higher sulfur content cannot be easily offset because the hydrogenated stream with a lower sulfur content will increase.

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

The stream of contaminated crude oil containing sulfur, nitrogen and metals enters the process via line 2 after pretreatment such as desalting, which is preferable for crude oil. In this embodiment, the crude oil supply raw material 2 can be a single crude oil, a combination of one or more crude oils, or a combination of crude oil and a residual oil such as a high sulfur fuel oil. The feedstock 2 is led to a atmospheric distillation column 100, where the feedstock is separated into a light overhead gas 4 and a plurality of extracts. Light overhead gas 4
Contains a non-condensable distilled gas 6 useful as a process fuel or is captured for other uses. In one preferred variant, capital expenditures associated with such a stabilization system for overhead gas 4 are avoided. However, according to local needs, such as special marine fuel maximum H _{2 S} specification can include a stabilization system. In the embodiment shown in FIG. 2, the plurality of ejectors have one or more streams within the following range, that is, (
1) Unstabilized pristine straight naphtha of line 16 via line 4, (2)
Sulfur break point extraction of line 18, (3) light distillate of line 24, (4) line 26
Intermediate distillate, (5) first heavy distillate of line 28, and (6) atmospheric residue of line 30 are included.

In various applications of the art, different meanings are assigned to the same or similar extracts in different parts of the world, the meanings of which may differ or overlap.
Often inconsistent or confusing. As used herein and in the claims, it has the following meanings. That is, (a) "naphtha" is an initial distillation point (IBP) of about 175 ° C. (about 350 degrees Fahrenheit) from a substance having at least three carbons C3 such as propane.
), And means a carbon-containing composition excluding low boiling point compounds such as methane and below. (B) “Stabilized naphtha” means that as far as naphtha or other naphtha range substances used as fuel blend substrates are concerned, low boiling point compounds below butane or propane are almost completely removed from naphtha or fuel. Meaning, for example, in a conventional refinery, the underflow from the naphtha debutane distillation column is stabilized naphtha. (C) “Destabilized naphtha” means naphtha in which light components of C4 or less have not been removed. For example, in a conventional refinery, the flow of raw materials to the naphtha debutane tower is destabilized naphtha. .. (D) "Unstabilized pristine straight naphtha" has an initial distillate (IBP) of about 175 ° C. (about 350 degrees Fahrenheit) from those having at least three carbons C3, such as propane. In the range of things,
Except for low boiling point compounds such as methane and below, atmospheric distillation overhead distillation gas may be contained, which means a carbon-containing composition recovered from atmospheric distillation. (E) “Natural naphtha” means an unstabilized light fraction of hydrogenation equipment effluent recovered from a distillation column or other separator in a hydrogenation process and is operational. Given that, collect one or more heavy distillates at or near the bottom of the separator, such as distillate ranges, heavy oil ranges, or other substances heavier than the naphtha portion of the feed to the separator. It is part of the hydrotreating zone and is not stabilized. (F) The “break point retrieval” has already been defined herein, and an example thereof is shown in FIG. (G) The "light distillate above the break point extract" or "light distillate" in the present specification is a fraction having an initial sulfur content higher than the maximum sulfur content of the break point extract. Yes, and correspondingly, it has a boiling point (IBP) higher than the highest end point of the break point extract. (H) "Intermediate distillate" means a distillate between a light distillate and a heavy distillate separated as an extract based on a preferred distillation column design, eg, an intermediate distillate. Can be eliminated and combined with either light distillate or heavy distillate. (I) "First heavy distillate" means the heaviest distillate of the atmospheric distillation unit, and its sulfur content and boiling point range are the sulfur composition of the raw material supplied by the distillation unit and the harshness of crude oil tower operation. It is determined by one or more operating conditions such as sulfur and downstream hydrogenation conditions. (
j) "First heavy distillate" means the heaviest distillate of the atmospheric distillation unit, which is related to the sulfur composition of the distillation unit supply material and the extraction of the sulfur break point, and the harshness of crude oil tower operation. It has a sulfur content and boiling range determined with reference to one or more operating factors, such as the severity of hydrogenation conditions for downstream distillates. (K) “Second heavy distillate” means the lightest distillate in the vacuum distillation column, and is related to the sulfur composition of the raw material supplied by the distillation unit and the extraction of the sulfur break point.
It has a sulfur content and boiling range determined by reference to one or more operating factors such as the harshness of crude oil tower operation, the harshness of hydrogenation treatment conditions for downstream distillates, and so on. (J) "Decompression gas oil" including "normal pressure residue", "decompression residue", "light decompression gas oil" and "heavy decompression gas oil",
"Solvent separation", "hydrogenation", other terms, and variations of these terms are known to those skilled in the art of treating crude oil.

Preferably, the flow combination of (1) the unstabilized pristine straight naphtha of line 16 via line 4 and (2) the sulfur break point extraction of line 18 is 0.
.. If the sulfur content is in the range of 06% to less than 0.08% by weight and the target sulfur content of the fuel combination of line 600 is 0.1% by weight or less, the sulfur content of the treatment flow 70 is 1.
Less than 0 ppm by weight, the flow rates of the vapors 10 and 70 are combined so that the fuel combination 600 does not exceed the target sulfur content.

In FIG. 2, the atmospheric residue is supplied to the vacuum distillation column 200 via the line 30 (1).
) Second heavy distillate of line 32, (2) light decompression gas oil of line 36, (3) heavy decompression gas oil of line 38, and (4) decompression residue of line 50 are produced. The reduced pressure residue is led to solvent separation 300 via line 50 to produce (1) a pitch of deasphalized oil of line 80 and a metal-rich heavy residue of line 90.

FIG. 2 shows an integrated hydrogenation system 400 including two hydrogenation zones, namely a distillate hydrogenation zone 430 and a heavy oil hydrogenation zone 460. Integrated hydrogen treatment systems are known in the art and are preferred for this application. However, hydrodesulfurization and hydrodesulfurization in both Zones 430 and 460 are about 117-
Mild hydrogenation conditions at relatively low pressures in the range of 138 bar (1700-2000 psi) are sufficient.

The light distillate 24, the intermediate distillate 26, the first heavy distillate 28 and the second heavy distillate 32 are
Preferably, it is supplied to the integrated hydrogenation system 400 and hydrogenated in the presence of a catalyst under hydrogenation conditions to form a distillate hydrogenation zone 430 effluent flow on line 60. Such a hydrogenation treatment apparatus effluent 60 is a substance within the following range, that is, (1) the expected boiling point range is higher than C5 (composition having 5 carbon atoms) to about 175 ° C. (about 350 degrees Celsius). Of pristine naphtha, and (2) preferably having a sulfur content of less than 10 wt ppm, light distillate 24, intermediate distillate 26, first heavy distillate 28 and the first. Double distillate 32
Includes ultra-low sulfur diesel, which is a reduced sulfur flow formed from a combination of treated distilled vapors with. At least a part of the by-products of the hydrogenation treatment in the zone 430 is sulfur-removed and reused as hydrogen to be added to the distillate hydrogenation treatment zone 430, the heavy oil hydrogenation treatment zone 460, or both. It is known to those skilled in the art of hydrogen treatment technology that it may contain sulfur-containing gases such as hydrogen sulfide and hydrogen-rich off gas, and typically a small amount of liquefied petroleum gas.

Light gas pressure gas oil 36, heavy gas gas gas oil 38 and deasphalt gas oil 80 are also preferably fed to the integrated hydrogenation system 400, hydrogenated under hydrogenation conditions in the presence of a catalyst and heavy. Quality Reduced gas oil hydrogenation treatment zone 460 effluent flow 70 is formed. Such hydrogenation equipment effluents are: (1) pristine, with an expected boiling point range above C5 (composition of 5 carbon atoms) to about 175 ° C (about 350 degrees Celsius). Naphtha, and (2)
Preferably, heavy oil hydrogenation is formed from the first portion of a combination of treated distilled steam having a sulfur content of less than 10 wt ppm and having a light depressurized gas oil 36, a heavy depressurized gas oil 38 and a deasphalized oil 80. Ultra-low sulfur diesel, which is the first reduced sulfur flow in the treatment zone, (3)
Preferably, the light reduced pressure gas oil 36, which has a sulfur content in the range of 0.12 to 0.18% by weight.
It has material within the range of a second reduced sulfur stream, formed from the second portion of a combination of treated distilled steam with heavy depressurized gas oil 38 and deasphalized oil 80. At least a part of the by-products of the hydrogenation treatment in the zone 460 is sulfur-removed and reused as hydrogen to be added to the distillate hydrogenation treatment zone 430, the heavy oil hydrogenation treatment zone 460, or both. It is known to those skilled in the art of hydride treatment that it may contain a gas containing sulfur gas such as hydrogen sulfide, hydrogen rich off gas, and typically a small amount of liquefied petroleum gas.

The untreated stream 10 and one or more hydrogenated liquid streams are combined through the lines 60 and 70 to provide a low sulfur, substantially metal-free fuel product to the line 600.
To form. As used herein, "combining" means forming by flow mixing, blending, or other intimate combination in the line. In one variant, unstabilized pristine straight naphtha via lines 4 and 16 and sulfur delimiter retrieval via line 18 are combined within 100 without additional treatment and then pristine. Formed in one or more effluents from distillate hydrogenation zone 430, including naphtha and ultra-low sulfur diesel, as well as pristine naphtha, ultra-low sulfur diesel and heavy oil hydrogenation zone 460. A fuel combination is formed at 600 by combining one or more effluents from the heavy oil hydrotreated zone 460 with a second reduced sulfur flow. In another variant, the hydrotreated zone 400 combines the effluents of zones 430 and 460 into a single (not shown) as if the lines 60 and 70 were combined within such a zone. Examples of such variants forming a flow are the hydrotreating devices 430 and 4
It is useful when it is not desirable to separate 60 effluents. Preferably, the reduced gas oil hydrogenated portion 460 has an overhead system flow and a bottom system flow, some of which are diesel boiling range materials. This may be in relatively small amounts compared to the combined diesel provided in combination 600 by zone 430 or 460, and the combined diesel side hydrogenated portion 430 is also block 60.
It has a pristine naphtha sidestream, either as an overhead system flow and a bottom system flow containing low sulfur diesel that is led to zero or used for trim or other purposes, alone or as part of it.

De-asphalt device containing asphalt and metal-rich heavy residue 300 Bottom heavy residue 9
0 is the heavy residue 90 in the presence of steam and oxygen, and any carbon-containing slurry quench.
Syngas is fed to an integrated gasification combined cycle system 500 containing one or more gasifiers for partial oxidation of the syngas, at least a portion of which is distillate hydrogen via line 502. It is converted to hydrogen for use by being sent to a hydration treatment system 400 including a chemistry treatment device 430 and a heavy oil hydration treatment device 460, and also gasified for power generation within 504 for process and other applications. It further has a high temperature turbine gas and a heat recovery generator for recovering heat from the high temperature gas turbine gas by forming a synthetic gas, which is a synthetic gas for burning the gas turbine of the combined cycle power generation unit in the system 500. It produces steam and is sent via 504 for additional power generation, driving a steam turbine to generate power. Each gasifier also produces metal-rich soot. The soot may be in the form of a granular solid and contains metal contaminants from crude oil and / or heavy feedstock, which solids are fed from each gasifier via line 506 for metal removal. The support system includes one or more gas treatment units and
All of the sulfur-containing gas streams from all unit operations, whether sour gas or acid gas, are supplied to the gas treatment unit via 508 for sulfur removal. Preferably, such a sulfur removal system is part of a utility island to which the gasification system is 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 has an acid gas removal unit and sour CO whose capacity and configuration have been optimized to produce the required hydrogen from at least a portion of the source synthetic gas produced within the gasification system. Includes shift system.

In the modified example of the integrated hydrogenation treatment system 400 shown in FIG. 2, the replenishment hydrogen-containing gas 502 from the gasification system 500 is the amount required for the hydrogenation treatment, and the amount of the internally reused hydrogen in the hydrogenation treatment block 400. With effective hydrogenation operating temperature, pressure, space adjusted based on the catalyst selected to achieve the desired level of desulfurization and demetallization and other conditions known in the art. Compressed and heated to speed and pressure. The hydrogen 502 thus prepared is first placed (along with recycled hydrogen) in the heavy oil hydrogenation zone 460, which is a high pressure zone. The effluent of the heavy oil hydrotreated zone 460 with the hydrotreated liquid and the hydrogen-containing gas is separated by a high pressure separator (not shown), where the liquids are accumulated in the zone 460 to hydrogenate. The contained liquid is recovered, passed through line 410 and sent to the distillate hydrogenation treatment apparatus 430 for use in the hydrogenation treatment in the low pressure zone. Hydrogenated liquids and purge gases with sour and acid gases from the hydrogenation zone 430 pass through line 412 into the heavy oil hydrotreat zone 460, where they are substantially mixed. Hydrogenated treatment solutions 430 and 46 in both zones 430 and 460
The zeros are separated via lines 60 and 70 and either charged separately into the combinatorial fuel 600 or combined zone 60, depending on the sulfur and other material balance needs of the process.
It can be added or removed as a trim to control the sulfur level of 0 (not shown). In the illustrated variant of the integrated hydrogenation process, the purge gas 420 in both zones 430 and 460 is directed via the line 420 to the sulfur recovery system and optionally the utility island 500 with a gasification or boiler. Although not shown in FIG. 2, various auxiliary high, medium and low pressure gas-liquid separators, flow heaters, gas reuse and purge lines, reflux drums for separating gas or light components and liquids, compressor,
Cooling systems, and other ancillary applications, are known to those of skill in the art of hydrotreating technology. Also, if located within a hydrotreating zone rather than within a common utility island, within the hydrotreating zone 400, various amines or other sulfur recoverant absorbers for sour gas or acid gas treatment and A peeling system may be included.

The parameters for the selection of the hydrogenation catalyst and the adjustment of the process conditions of the hydrogenation zone 400 are within the technical scope of those skilled in the art of the petroleum refining industry and are an addition to the implementation of the hydrogenation classification of the present invention. Does not require explanation. In the reaction zones of the distillate hydrogenation apparatus 430 and the heavy oil hydrogenation treatment apparatus 460, the hydrogenation treatment catalyst used increases the hydrogen content and / or sulfur, nitrogen, oxygen, phosphorus and metal hetero. Includes any catalytic composition useful for catalyzing the hydrogenation of a hydrocarbon feed to remove atomic contaminants. The particular catalyst type and various layer configurations used and the hydrogenation treatment conditions selected are the hydrocarbon product compositions of each feedstock processed by their respective units, as well as the sulfur and metal content and heavy carbon. Depends on the desired reduced sulfur and metal content in the residue and product flow from each zone. Such catalysts can be selected from any catalyst useful for the hydrogenation of hydrocarbon feedstock, but the operating conditions avoid or minimize ring saturation or hydroconversion in the practice of the preferred embodiments of the invention. It is adjusted to become. Patent Document 4 by Baldassari et al., Incorporated herein by reference, describes a suitable hydrogenation process that includes various integrated hydrogenation devices in addition to various suitable hydrogenation catalysts. Baldassari et al. Further summarize the various catalytic compositions and condition ranges for distillation and heavy oil hydrogenation treatments and identify the conditions for hydrocracking and residue hydroconversion. All of these are known to those skilled in the art of hydrogenation treatment. In Non-Patent Document 8, sulfur is removed by hydrogenation, and sulfur is removed by using a highly active Ni / Mo catalyst.
Unit design, catalyst selection, hydrogen consumption and other operating conditions for manufacturing products below ppm are described. Non-Patent Document 9 by Shiflet et al. Also uses a highly active CoMo catalyst for removing sulfur without steric hindrance and a highly active NiMo catalyst for removing residual steric hindrance sulfur to bring hydrogen to 10 ppm or less. The conversion process is described.

In another variant shown in FIG. 2, the sulfur content of feedstock 2 is measured by analysis showing the exponential break points and rate of increase of the sulfur profile. For example, a break point for sulfur content in the range of 0.06 to 0.08% by weight (or higher than the relative flow velocity of untreated and hydrotreated steam and their respective sulfur contents) and their respective. Using such a profile, control the adjustment of atmospheric distillation 100 to maximize the available amount of unstabilized pristine naphtha 16 and sulfur break point extraction 18. , Straight naphtha 16 and sulfur break point take-out 18 flow in combination by fluid mixing or compounding and are available in product accumulation zone 600 without treatment, if necessary (1) distillate hydrogenation treatment. The amount of flow of light distillate 24, intermediate distillate 26, first heavy distillate 28 or second heavy distillate 32 into zone 430, or (2) to heavy oil hydrothermalizer 460. The amount of flow of light decompressed gas oil 36, heavy decompressed gas oil 38 or deasphaltized oil 80 is measured or reduced, and these flows form a fuel product 600 whose actual sulfur content is below the target sulfur content limit. Therefore, an increased or decreased amount leads to the hydrogenation treatment. In yet another variant, the analysis controls the maximum amount of flow other than the untreated unstabilized pristine naphtha 16 and the untreated sulfur break point extraction 18 into the hydrogenation process. It can be used to determine the amount of flow going and to form the fuel 600 where the actual sulfur content is below the target sulfur content limit. That is, any (1) distillate hydrogenation treatment zone 430
Light distillate 24, intermediate distillate 26, first heavy distillate 28 or second heavy distillate 32
The amount of flow to the hydrogenation treatment 400, which is (2) the amount of flow of light decompression gas oil 36, heavy decompression gas oil 38 or deasphaltized oil 80 to the heavy oil hydrogenation treatment apparatus 460. , 600 can be increased or decreased to adjust the sulfur content of the effluent 60 or 70 of the hydrotreated zone 400 mixed with the untreated stream 10 or both.

In one modification, a fuel product 600 whose actual sulfur content is less than or equal to the target sulfur content limit,
It is formed by adjusting the sulfur level of the actual final product 600. Adjustments were made to the combination zone 600, (a) unstabilized pristine naphtha 16 or sulfur break point extraction 18, which may contain sulfur because it has not been treated to remove sulfur.
Or (b) a flow of entering and exiting the treated light distillate 24, intermediate distillate 26, first heavy distillate 28, second heavy distillate 32 and other distillate hydrogenating apparatus 430. Or (c) by increasing or decreasing the amount of one or more of the streams in and out of the heavy oil hydrogenation treatment apparatus, such as the treated gas-reduced gas oil 36, heavy-duty gas-fuel oil 38, and de-asphalized oil 80. Will be done. Here, such adjustments are based on the measurement of the relative contribution of each stream 60 or 70 to the combination 600 to the sulfur content.

In one embodiment, a light tight oil or condensate having a low metal content and a sulfur content below the target sulfur content limiting level for the fuel 600, or a light tight oil such as an agglomerate for the production of unaccompanied and shale gas. The combinations of, etc. are as follows, that is, (
a) Atmospheric distillation 100 or vacuum distillation 200, raw material supplied to solvent separation 300, light distillate 24 to distillate hydrogenation treatment apparatus 430, intermediate distillate 26, first heavy distillate 28 or One of the feedstocks of the second heavy distillate 32, or any of the gas oil 36, heavy decompressed gas oil 38, or deasphaltized oil 80 to the heavy oil hydrogenation treatment apparatus 460.
(B) Flow 10, formed from unstabilized pristine naphtha 16 and sulfur break point extraction 18 without additional treatment, (c) pristine naphtha and ultra-low sulfur Flows formed by distillate hydration treatment equipment containing diesel, (d) flows formed by heavy oil hydration treatment equipment containing pristine naphtha, ultra-low sulfur diesel and second reduced sulfur flow, (e). ) The combined effluent 70 of the combined hydrotreated unit 400, which is led to the final product fuel 600, or (f) the enclosure of the equipment producing such fuel, which is added to form the final product fuel. Combine with one or more of the other fuels, added internally or externally.

In one variant shown in FIG. 2, the sulfur content of the fuel product 600 is (a) combined 600, via line 10, unstabilized pristine straight naphtha 16 and sulfur break point extraction 18 Is supplied to such a stream without any additional treatment, then (b) the sulfur level 600 of the actual product, (1) the distillate hydrotreated zone 430 with a light distillate. 24, flow of intermediate distillate 26, first heavy distillate 28 or second heavy distillate 32, (2) light decompression gas oil 36 to heavy oil hydrothermal treatment apparatus 460, heavy decompression gas oil 38 or Adjusting by increasing or decreasing the amount of deasphaltized oil 80 flow into one or more combinations, (c) then for some reason raising the sulfur content of the actual product 600 to the target sulfur level. If necessary, light distillate 24, intermediate distillate 26, first heavy distillate 28 or second heavy distillate 3 via (1) line 60 to the combination.
Flow from distillate hydrogenation treatment zone 430 formed from 2, (2) heavy oil hydrogenation formed from light decompressed light oil 36, heavy decompressed light oil 38 and deasphaltified oil 80 via line 70. If it is necessary to reduce the amount of one or more of the flows from the treatment zone 460, or (d) for some reason reduce the hydrogen content of the actual product 600 to the target hydrogen level, then to the combination (d) Increasing one or more amounts of 1) the flow from the distillate hydrogenation zone 430 via line 60 and (2) the flow from the heavy oil hydrogenation zone 460 via line 70. , Controls below the target sulfur content limit level. Such facilitation, for example, for fuel supplies targeting less than 500 wt ppm sulfur fuels for offshore and onshore gas turbines, or for the same application in different locations requiring different target sulfur contents. Multiple sulfur grades can be efficiently produced, including in various ranges.

In a variant of the use of high sulfur fuel oils with sulfur content higher than the target sulfur content limit level of the final fuel in combination 600, the high sulfur fuel oils are part of one or more of the various feedstocks. , Supply to one or more of each unit operation. The high sulfur fuel oil is (a) to the supply line 2 to the atmospheric distillation 100 or the line 30 to the vacuum distillation 200.
Alternatively, (b) light distillate 24, intermediate distillate 26, first heavy distillate to line 50 to solvent separation 300, or (c) separately or to the distillate hydrogenation treatment apparatus 430. In combination with one or more of the feed 26 or the second heavy distillate 32 feedstock, to line 20 to the distillate hydrogenator 430, or (d) separately or lightly reduced gas oil 36, heavy. Quality Reduced gas oil 38 and deasphaltized oil 80 in combination with one or more, added to line 40 to heavy oil hydrogenation treatment equipment 460, fuel combination where the actual sulfur content is below the target sulfur content limit 600 can be formed. In one or more implementations of these variations on the use of high sulfur fuel oils as feedstocks and the choice of their supply points, the nature and nature of the high sulfur fuel oil supply, such as its sulfur content, asphaltene content, etc. Other factors regarding compatibility with processed crude oil or other feedstocks, container space and energy consumption, asphaltene content, undissolved component content, gum formation, and other efficiency issues may be considered. , Known to those skilled in the art of purification technology.

In another variant, the clean fuel in the combination 600 zone has a sulfur content higher than the target sulfur content limit level so that the actual sulfur content of the fuel 600 is below the target sulfur content limit. High-sulfur fuel oil that can be produced (a) Unstabilized pristine straight-running naphtha 16 without additional treatment depending on the sulfur content of the high-sulfur fuel oil.
And the flow 10 formed from the sulfur break point extraction 18 or (b) the flow 60 formed by the distillate hydrogen treatment apparatus 430 containing pristine naphtha and ultra-low sulfur diesel range material, or (c). Add to one or more of the stream 70 formed from the heavy oil hydrotreating apparatus 460 containing pristine naphtha, ultra-low sulfur diesel and the second reduced sulfur stream or the combined effluent 70 from the hydrotreated zone 400. It is formed by doing.

In a preferred variant of using high sulfur fuel oil in the preparation of the fuel composition 600, the sulfur content of such high sulfur fuel oil is measured and then the high sulfur fuel oil is used as part of the feedstock 50 as a solvent. Light distillate 24, intermediate distillate 26, first heavy distillate 26 or th Combined with one or more distillation streams of the distillate 32, it is fed to the distillate hydrogenation treatment apparatus 430, or the light depressurized gas oil 36, the heavy depressurized gas oil 38 and the deasphaltified oil. Distillate hydration treatment device 430 or heavy oil hydration treatment device 460, depending on the sulfur content of the high-sulfur fuel oil, combined with one or more of the 80 heavy oil streams, or both the distillation stream and the heavy oil stream. Alternatively, a part of the raw material to be supplied to both is formed, and the zone 43
Optimize the adjustment of 0 or 460 hydrogenation conditions, or adjust both zones to form a fuel whose actual sulfur content is below the target sulfur content limit.

In other embodiments of the invention, clean fuels whose specifications are below the sulfur content limit are typically atmospheric residue or heavier, non-specific or standard specifications for high-sulfur fuel oils. It can be formed by the use of heavy residual oils, including high sulfur fuel oils that may have a density or sulfur or metal content within. Due to market considerations, such heavy residual oils are often available from sources other than within the battery limits of fuel plants. Heavy residues with a sulfur content higher than the target sulfur content limiting level of fuel 600 are: (a) vacuum distillation column 200, either separately or in combination with atmospheric residue via line 30. 2nd heavy distillate 32, light vacuum gas oil 36,
A atmospheric distillation column 200 for producing at least a portion of any or all of the heavy decompression gas oil or decompression residue 50, or (b) solvent separation 300, separately or in line 50.
Combined with a reduced pressure residue feed to solvent separation 300 via, at least a portion of the deasphalized oil 80, or to the gasification system 500 for gasification, sulfur recovery and other ancillary treatments. It is supplied to one or more of solvent separators 300, which form a pitch 90 with a metal-rich heavy residue that passes through. Such heavy residual oil may also be combined with pitch via line 90 as a feed to Utility Island 500. In a variant, the untreated, having a relatively high sulfur content (greater than 0.5% by weight) or a high metal content, without treatment for trimming to adjust the sulfur content of the fuel 600 of the present invention. When using high sulfur fuel oils, such use shall be a relatively small adjustment if used without treatment to ensure that the combination 600 does not exceed the target sulfur content limit.

The flow sheet of FIG. 2 showing the various intermediate individual products is for the explanation and understanding of the major and by-products in the effluent of each unit operation depicted. The selected changes in separation or processing by each unit operation depend on the optimization of the selected crude oil and feedstock, as well as the intermediate products produced to produce fuels below the target sulfur specifications. For example, if the ultra-low diesel produced in Zone 430 is not filtered and all hydrogenated material is combined in Line 70 as shown in FIG. 2, a common gas-liquid separator (Figure). By using (not shown), both the effluents 60 and 70 from the hydrotreating devices 430 and 460 can be combined within the hydrotreating zone 400 and only the gas is removed. Alternatively, if the process objective is to trim control the sulfur content of the fuel in the final combination zone 600 or to separate or remove some of the pristine naphtha or ultra-low sulfur diesel for other reasons, hydrogenation. The effluents 60 and 70 from the treatment devices 430 and 460 may also be sent to the stripper or distillation column separately or in combination so that the pristine naphtha or ultra-low sulfur diesel fractions can be removed. good.

Although various embodiments of the present invention have been described, it should be understood that they are merely exemplary and not limiting. For example, untreated light tight oil or condensate with low metal content and sulfur content below the target sulfur content, or untreated light tight oil or condensate, if the ignition point of the fuel is not taken into account. The combination is added as part of the combination of the untreated fraction and the treatment flow to form a fuel whose actual sulfur content is less than or equal to the target sulfur content. As used herein, the terms "light tight oil" or "LTO" are used in (i) sulfur content in the range 0.1% to 0.2% by weight, and (ii) API (degrees). It means a source or shale gas condensate having a density in the range of 38-57 degrees and a wide hydrocarbon range based on (iii) sources. LTO
Typically, (a) 5 to 20% by weight of liquefied petroleum gas range, (b) 10 to 35% by weight of naphtha, (c) 15 to 30% by weight of kerosene, as% by weight of the total amount. d) 15-25
It has a distillate range of expected distillate removal, overlapping with each other, of% by weight diesel, (e) vacuum gas oil, and (f) zero (0%) to 10% by weight heavy residue.

In one variant, the invention is: (i) Crude oil having the quality of untreated light tight oil or condensate, for example, if the available oil has a production area outside the battery limits of the combustion production plant of the present invention. , Or a combination of light tight oil or condensate, (ii)
) Co-treatment with one or more other crude oil feedstocks according to the method of the present invention to produce a low cost fuel having a low metal content and a sulfur content less than the target sulfur content. Such light tight crude oils are likely not to contain sufficient heavy hydrocarbons in the bottom fraction (eg 0% or very low heavy residues) and the range of residues is desulfurization or other. It does not provide a processing balance for hydrodesulfurization, and the corresponding residues also hydrogenate such lighttight crude oil in a cost-effective manner to reduce sulfur and metals and decontaminate or decontaminate. Not enough to support the process of hydrogenation to provide sufficient lubricity and support its use in certain types of engines.

The novel fuel embodiment of the present invention is an ISO issued by the International Organization for Standardization (ISO).
It is better understood by reference to the 8217 standard. ISO 8217 describes a set of marine residual fuel categories and detailed specifications for onboard consumption. These specifications recognize that crude oil supply, refining methods, and other conditions vary widely as the basis for their development. Such specifications suggest that various international requirements for properties such as sulfur content are taken into account. ISO82, the toughest at the moment
Reference numeral 17 is RMA10, and the interpretation of the specification and claims should be based on this. A simulated composition of the novel fuel of the present invention (crude oil is divided into distillates, a portion of the distillate is hydrotreated to remove non-solvent residues during solvent separation, followed by untreated and treated categories. Based on (created by the reconstructing simulation model), these new fuels meet and / or exceed all ISO RMA 10 specifications except the flash point, and the flash point is the flash point requirement for the freight vessel. According to the SOLAS exception of, the present inventors claim that the fuel has novel features and improvements that distinguish these new fuels from the marine fuels consisting of the above residues.

In one variant, we present all ISO RMA10 (ISO2) except the flash point.
817-10) Conforms to or exceeds specifications and has the following notable features: (a) 0
.. Sulfur in the range of 50% m / m (% by weight), preferably 0.05 to 0.20 m / m (% by weight), (b) 5.0 mg / Kg (% by weight) or less, preferably 1. .0 mg / Kg
Any of (1.0 ppm by weight) or less, eg, 0.2 mg / Kg (0.2 wt ppm) of metal, and (c) a flash point of 60 ° C. or less, and features superior to other ISO RMA10 specifications. Provide improved fuel with or all. In the variants, these novel fuels also have the following notable features: (a) viscosity of 10 cSt or less, (b).
Pour point below 0 (zero) ° C., density in the range of ^{(c) 820-880 kg / M 3, (d) 80}
It has one or more CCAIs of 0 or less, (e) 20 mg / Kg or less, preferably 10 mg / Kg or less of sodium. All of the above are measured by the test or calculation method specified by ISO2817-10. Such fuels include a series of hydrocarbons having the highest boiling point of the highest boiling point of the solvent-soluble components suitable for solvent separation, such as the initial distillation point of naphtha and heptane. The metal can be reduced to 100 weight ppb, depending on the composition of the feedstock and the adjustment of operating conditions.

The present inventors have discovered that fuels having extremely low sulfur and metal amounts, which fall under the SOLAS exception of the flash point requirement for cargo ships, can be produced at low cost. If flash point treatment is required for other applications, flash point treatment for having a flash point of 60 ° C. or higher, or for such requirements, is 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 in connection with normal heating of residual oil, at refueling stations in ports or at sea. Allows pumping and handling. Heavy residual oil is thick and due to its relatively high pour point and high viscosity, in all of its storage, pumping and supply to marine engines.
It needs to be heated and kept at a high temperature, and such heating consumes energy.

Table 1 below shows two variants of the fuel of the invention, one with an extremely low sulfur content of 0.1% by weight and one with a further reduced level of 0.05% by weight, ISO RM.
The sulfur compared to A10 is shown in Table 1 below.

Such fuels of the present invention having the properties shown in Table 1 are further identified in that they have substantially the entire range of hydrocarbons derived from crude oils from C3 or C5 to C20 and above, and the initial distilling point of the hydrocarbons. Is the lowest of the boiling points of any fraction of the above crude oil under atmospheric distillation conditions.
The highest boiling point is the end point of the residual portion of the crude oil that is insoluble in a solvent suitable for solvent separation. In contrast, the residues are limited to very heavy substances, such as vacuum distillation residues, solvent deasphalted residues, other cokers, etc., which do not contain such a wide range of hydrocarbons.

From this specification and the disclosure of claims, the present invention not only meets or exceeds the criteria for compatibility with current marine reciprocating engines, but is also compatible with advanced combustion gas turbines that can be used in marine applications. It also enables the production of ultra-clean fuels. Such advanced turbine engines are currently available, but are typically for land use. These advanced turbine engines, once started on board, can have significant efficiency advantages while reducing corrosion or ash formation by burning the fuels of the invention during voyage. Also, depending on the fuel economy available at the port, ships will gain efficiency benefits by burning these new fuels at the port, generating electricity and sending that electricity to the local grid for profit. can do. Revenues from such port power generation can offset offshore fuel costs and reduce the actual total offshore fuel costs to ships below high sulfur fuel oil, thus the low sulfur fuels of the present invention are more expensive. Even if it is a nautical fuel, its usage cost will be offset. The greatest benefit is to the environment, SOx and NO in the comparison of specific normative cases.
It is possible to reduce the emission of x by 95% or more, and potentially reduce the emission of harmful metals during voyage by 99% or more (almost 100%). In addition, the environment has _{two benefits from CO 2} reduction: (i) the efficiency of advanced gas turbine engines on board, and (ii).
) Gaining the efficiency of power generation at the port, inefficient combustion of coal, crude oil, residual oil or some other fuel is replaced.

As such, the present invention is widely applicable to the production of fuels with reduced levels of sulfur and other pollutants and the use of such fuels. Certain features may be modified without departing from the spirit or scope of the invention. Therefore, the present invention is not limited to the specific embodiments or examples described, but is limited to those that are substantially equivalent to the appended claims or claims.

Claims (9)

In the fuel, the highest boiling point of the fuel is the highest boiling point portion of the effluent from the solvent separation and then hydrogenated to form part of the fuel, the fuel being 0.50% m. A fuel characterized by having a sulfur content of / m (% by weight) or less. A fuel, said fuel having an actual sulfur content of 0.50% m / m (% by weight) or less, comprising a range of C3 or C5 to C20 or more crude oil-derived hydrocarbons, said carbonization. Hydrogen has an initial distillate, which is the lowest boiling point of any fraction in the untreated stream combined with the fuel, and a highest boiling point, which is the highest boiling point of the hydrocarbonized stream combined with the fuel. The fuel according to claim 1. A liquid fuel comprising (a) a hydrogenation treatment flow of a liquid distillate higher than the sulfur break point and (b) an untreated liquid distillate below the sulfur break point, wherein the fuel is the fuel. The fuel according to claim 1, wherein the fuel has a maximum boiling point, which is the maximum boiling point of the hydrotreated flow combined with. Includes a hydrogenated ultra-low sulfur stream with sulfur up to 10 ppm by weight,
The fuel according to claim 1. Containing a combination of hydrocarbons ranging from the lowest boiling point portion of the untreated liquid fraction to the highest boiling point portion of the soluble material from the solvent separation, the fuel is insoluble in one or more solvents used for solvent separation. The fuel according to claim 1, which does not contain the residue of the above. A first hydrogenation treatment stream, which is a reduced sulfur stream having a sulfur content of 10 wt ppm or less, a second hydrogenation stream, which is a reduced sulfur stream having a sulfur content in the range of 0.12 to 0.18 wt%. According to claim 1, the untreated fraction contains a treated fuel fraction and has a sulfur content of more than 0.50% m / m (% by weight) or 0.50% m / m (% by weight) or less. Listed fuel. The fuel according to claim 1, characterized by a sulfur content adjusted to meet or exceed the IMO sulfur specifications for marine fuels. Lighttight oil or condensate, or lighttight oil and condensate with one or more untreated fractions, naphtha flow, said lighttight oil if the fuel ignition point is not taken into account. Has a sulfur content in the range of 0.1% by weight to 0.2% by weight and a density in the range of 38 to 57 degrees in API (degrees), and the fraction range for taking out the distillate is based on weight%. In (a) 5 to 20% by weight liquefied petroleum gas range, (b) 10 to 35% by weight naphtha, (c) 15 to 30% by weight kerosene, (d) 15 to 25% by weight diesel, ( e) The fuel according to claim 1, which comprises (f) zero (0%) to 10% by weight heavy residue of reduced gas oil. A fuel, a hydrocarbon having an initial distillation point in the range of about 35 ° C. to about 315 ° C. and a maximum boiling point higher than the above-mentioned about 315 ° C., and the maximum boiling point belongs to the range of the fuel. Contains hydrocarbons, which are the highest boiling points, which are the end points of the oil and the starting point of the initiation of the deasphaltinated residue which is insoluble in the solvent selected for solvent separation and does not belong to the range of said fuels. The fuel according to claim 1.

Images