CA2439549A1 - Use of gas from a gas accumulation for pre-refining liquid conventional oil - Google Patents

Abstract

Use of a gas of deposit in its region of production in which: a) one converts a fraction of this gas into hydrogen, b) one selects and supplies a conventional crude oil P1 fluid and of point, of flow lower or equal to - 10 .degree.C, c) P1 petroleum is treated in an installation (I), the treatment comprising at least one catalytic hydrotreatment, or hydroconversion, or hydrocracking stage of a fraction mainly comprising compounds with a boiling point greater than 343.degree.C, using at least a fraction of the stream H2, to produce at least one pre-refined PA oil intended to be refined in a refinery separate and distant from the installation (I).

Description

USE OF DEPOSIT GAS FOR PRE-REFINING OIL
FLUID CONVENTIONAL
Field of the invention The present invention relates to the petroleum refining industry, and the use of heavy residues refinery sulfur. Oil is traditionally processed in refineries of oil by a set fractionation and chemical conversion operations to produce a set of products commercial end products meeting technical standards or specifications precise, for example distillation intervals, sulfur contents, technical indices characteristics such as the octane number or the diesel number, etc.
The main commercial end products are petrochemical naphtha, gasoline, kerosene, diesel (also called diesel fuel), heating oil, as well as different categories of fuel oils more or less sulfur, road bitumens, liquefied petroleum gases, and sometimes other products:
lubricating oils, solvents, paraffin etc ... An oil refinery therefore produces a number relatively large commercial end products, from a certain number of oils raw, chosen according to their composition and their price.
Market developments on the one hand, in particular the growing competition from gas natural, and specifications for discharges from combustion plants on the other hand (releases of sulfur oxides, nitrogen oxides, solid particles, especially in Europe) lead to strongly penalize outlets for sulfur-containing heavy fuel oils, for example heavy fuel oil at most 3.5%
or 4% sulfur. The refiners are therefore faced with a very important technical problem, that of the use of sulfur residues from refinery, taking into account regulatory provisions. This Technical problem is not new, and it has been known for several decades that refining, especially the European refining, faces a historical trend of reduction in heavy fuel oil markets, and in particular of sulfur-containing heavy fuel oil.
As an indication, the residues from the refining of oils from the Middle East, oils that constitute about two-thirds of the world's oil reserves conventional, most often more than 3% and even 4% by weight of sulfur. The new standards of combustion plants in Europe lead to limit the use of fuel oil to only 1% by weight of sulfur if there is no desulfurization of fumes.
Significant work has been done to resolve this usage problem sulfur residues of refinery - a first path is the development of efficient techniques for smoke treatment the from the combustion of sulfur fuel oil, with elimination or strong reduction of sulfur oxides, of nitrogen oxide, and solid particles contained in the fumes of combustion. Some techniques can greatly limit releases and respect regulations. They therefore allow certain sulfur-containing heavy fuel oil markets to be retained, and particular to use this type fuel oil for internal refinery fuel consumption.
Unfortunately these smoke treatment techniques lead to significant complexification facilities of

2 combustion and are very expensive. The simplest techniques are insufficient to satisfy discharge regulations and pose an environmental problem, - a second known way is the implementation of desulfurization processes often with a chemical hydroconversion of sulfur residues, under high hydrogen pressure (typically about 1.2 to 1.8 MPa of partial pressure H2), to both crack partially the residue and reduce their sulfur content. The main processes are processes hydrotreatment or catalytic hydroconversion of sulfur residues, carried out in a fixed bed, or in movable bed, or in bed bubbling, or in "slurry" depending on the mode of use of the catalyst. Word slurry, according to the Anglo-Saxon terminology, designates here a suspension of the residue to be treated in presence of fines catalytic particles with an average diameter typically less than 100 micrometers, and in the presence of hydrogen-rich gas. Operational conditions and usable catalysts for these processes are described later in this description.
This route of hydrodesulfurization and / or hydroconversion of residues is sometimes called hydrotreating of residues, or improperly hydrocracking of residues (the hydrocracking term to be reserved for the high conversion of loads substantially without asphaltenes or metals on particular, bifunctional catalysts), is a technically efficient with respect to desulfurization of residues up to levels of the order of 1.5% by weight of sulfur in the final residue, (or even between 0.5 and 1.25% by weight if we choose processes and suitable conditions) as well than converting the residue into distillable products boiling below from 565 ° C, this conversion which can typically be from 20 to 70% if a residue is sought final stable, or so higher and even around 95% with slurry processes. The problem posed by these processes is their high energy consumption, linked in part to the significant consumption hydrogen. The hydrogen typically produced in a refinery by reforming naphtha is indeed in insufficient quantity to carry out both hydrotreatments of distillates (including kerosene and diesel) and the hydroconversion of residues. The refinery must therefore produce the significant amount of hydrogen required for hydroconversion of residues. Two main processes of production of hydrogen are then usable: the partial oxidation of part of the residues and steam reforming of natural gas. Partial oxidation of residues is an expensive and leads to reject to the atmosphere significant amounts of CO2. Steam reforming of natural gas is a cheaper process of from an investment point of view, but uses gas, an expensive raw material on most sites refinery. The gas distributed in national networks is typically composed of natural gas routed by gas pipelines often several thousand km long (by example for gas from Russia and distributed in Western Europe) and / or from gas natural liquefied transported by cryogenic vessels. Network gas is therefore a fuel expensive whose production and distribution entail significant energy expenditure and so also notable releases of C02.

3 The hydroconversion of residues in a refinery is also difficult to implement for the most part refineries of low or medium capacity, such as 3 to 8 million tonnes per year of capacity petroleum refining because the relatively small amount of residues does not not allow gains investment by size effect.
- The third way to use sulfur refinery residues is to export these residues in the form high sulfur fuel oil to countries in the world where regulations on releases from smoke from combustion plants is less severe. Apart from the fact that this is to move environmental pollution and not to reduce it, the recovery of residue by export is very bad due to the unfavorable supply / demand ratio. In addition, transportation of sulfur oil is made in specific boats with temperature maintained at around 70 ° C for the fuel oil can remain pumpable and fluid. This transport is therefore expensive and leads to energy consumption and notable C02 releases.
The known ways of using sulfur refinery discharges therefore pose significant problems from an environmental point of view andYou require complex techniques and expensive to process.
Apart from the problem of using sulfur residues, the refining is also faced with another problem, that of the insufficient quantity of middle distillates (kerosene +
diesel) obtained in a conventional refining scheme, compared to market developments, especially in Europe. In the United States of America, the most sought are typically kerosene and often naphtha cuts suitable for gasoline production by reforming Catalytic.
The invention, according to different variants and embodiments, proposes resolve or reduce the importance of these problems in several ways one of the objects of the invention is to implement a technical solution allowing to reduce, directly or indirectly, the excess sulfur residues from refining, In the conditions techno-economic favorable compared to known ways of using these residues.
Another object of the invention is to make one or more refineries compatible, directly or indirectly, with a larger fraction of the crude oil in place at the level global and therefore to increase access to a greater quantity of oil which will be extracted from the subsoil terrestrial or submarine in the coming decades.
Another object of the invention is to be able to access, directly or indirectly to crude oils at better costs, more diverse qualities of oil, from a greater number of deposits, by obtaining regular or long-term supply contracts etlou term by direct or indirect supply of point cargo. Another goal, linked to diversification direct or indirect supplies, is to improve the cost of access to at least some oils by the competition between suppliers, and / or reduce relative dependence by compared to light, low sulfur crudes of increasing cost.
Another object of the invention is to use more rational energy.

4 Another object of the invention is to implement a technical solution allowing a reduction overall release of pollutants and in particular greenhouse gases, by compared to alternative routes known.
Another object of the invention is a technical solution which can benefit many, if not all petroleum refineries, regardless of their refining capacity, and whatever their current level of excess sulfur residues.
Another object of the invention is to allow, directly or indirectly an increase in quantity of middle distillates produced in refineries, and in particular of allow an increase of the quantity produced of diesel bases with a high cetane number.
Other objects or advantages of the invention will be explained below.
Description of the invention To achieve these objectives, the invention proposes to use deposit, in production region of this gas, or of the purified deposit gas, in particular for producing hydrogen in order to achieve in a facility (I) processing crude oil, or a feed of hydrocarbons comprising a refinery residue, for example from a hydrocarbon feedstock comprising a crude oil and a residue refining, this treatment comprising at least one catalytic step on solid catalyst supported, hydrotreatment, or hydroconversion, or hydrocracking of a fraction with less load comprising compounds with a boiling point above 343 ° C, often boiling point higher than 371 ° C and generally boiling point compounds higher than 565 ° C in order to produce at least one pre-refined PA oil. Field gas, or refined deposit, can can also be used advantageously as a combustible gas in the installation of treatment and / or in the hydrogen production facility. Preferably, the treatment is applied, or applied also at fractions boiling above 565 ° C, in quantity sufficient for the residue under PA vacuum either in% weight significantly reduced compared to that of the load and / or petroleum departure, for example reduced by at least 20%, or 30%, or at least 40%, or let this residue be significantly less sulfur, and has a sulfur content reduced by at least 20%, or 30%, or 40%
see more. Preferably, PA has no vacuum residue, or includes a vacuum residue substantially free of asphaltenes and very low sulfur content, typically less than 0.4%, and often at 500 ppm by weight, or 300 ppm by weight or even less.
Field gases are abundant in many parts of the world, and including regions distant from the major gas consumption areas of Europe, United States of America (excluding Alaska) and Japan. In areas far from places of consumption, gas, when it is abundant, is available at very low prices, often three, four, or even ten times weaker than in high consumption areas. This very low cost of gas allows according to the invention to produce typically low-cost hydrogen, and use that hydrogen for the desulfurization and / or cracking heavy petroleum fractions, or refinery residues. It allows also, by hydrotreating at notable severity or by hydrocracking of particular heavy fractions of produce distillates means in quantity and in superior quality (in particular index or number of cetane) and boost the or oils from processing into highly recoverable products, especially kerosene, cut

5 high cetane diesel, and possibly good quality reforming charge for production petrol.
The abovementioned hydrogen treatments typically lead to a reduction notable of the amount of sulfur-containing vacuum residue from effluents or residue after refining later, or even, with certain treatments, with the complete elimination of residues above 1% by weight sulfur. They allow therefore to solve the problems of excess sulfur residues from refining, either directly in them reprocessing to transform them at least partly into oil, or indirectly by producing typically pre-refined petroleum with reduced sulfur residue content. this allows therefore, directly or indirectly, increase the possibilities of access to crude oils from more diverse quality, corresponding to a larger proportion of the world's oil reserves gross, and improve thus the conditions of purchase of these oils.
Being installed on a separate site from a refinery, the pre-refined petroleum product is not related to a special refinery but can be sent in transport conditions substantially equal towards different refineries, for example European refineries. He can therefore feed all refineries, including refineries of low or medium capacity, and avoid these refineries from do a residue treatment with an unfavorable scale factor.
All of these improvements are achieved by consuming gas, including usually mainly methane, including conversion for the production of hydrogen emits much less of CO2, a greenhouse gas, that the production of hydrogen by gasification residue. In addition, this gas can advantageously, in its region of production, be transported by pipeline, without prior liquefaction. Its use on such a site rather than its transportation to countries consumers often distant from 3000 km or more avoids energy consumption such as those of recompression stations, or liquefaction gas, its transport cryogenic and regasification at the LNG terminal. The use of gas near his deposit allows, compared to the same use (in particular hydrogen production for the treatment of residues), to have a more rational management of energy and to reduce the energy consumption and releases of greenhouse gases.
The invention is in a general form applicable to all types of oils and / or residues of refinery. The treatment may include carbon rejection in the form of coke or no rejection of carbon. However, the invention is preferably used with a treatment without carbon rejection, according to several characteristic variants allowing to obtain advantages notable vis-à-vis various objectives or objects of the invention previously cited. Terms used (such as:
deposit, carbon release etc ...) are explained later in this description.

6 The use of hydrotreatment or hydroconversion of petroleum processes on the production site, or relatively close to this site is already well known to the state of the technical in the field of production of petroleum that is difficult or impossible to transport such as heavy rough, rough bituminous, etc ... One can in particular find such processes in patents the United States America: US No. 3,676,331, US 4,294,686, US 4,347,120, US 5,069,775.
Typically, techniques and methods for processing petroleum in the field aim for a goal main: to make transportable crude oil which is not, or difficulty. The word transportable here means transportable by "pipeline" according to Anglo-Saxon terminology which means channeling.
Certain techniques aim to achieve the minimum transformation (at cost minimum) so that the processed petroleum is simply transportable for refining in special refineries.
Other techniques are aimed at achieving sufficient quality improvement oil so that it can be refined in a conventional refinery. We can in particular find a description of such heavy crude oil processing in Venezuela in the review "0i1 and Gas journal"
(oil and gas journal), Publisher Pennwell Corporation, Tulsa, USA, July 16, 2001, pages 52-55. The treatment described is applied to a viscous heavy crude. He produces coke and crude at low sulfur content substantially free of asphaltenes, comprising a cut index diesel cetane less than 42. This treatment is of the "carbon rejection" type because it co-product of coke, in significant amount.
Other known treatments include another form of carbon rejection:
rejection of asphalt (obtained by deasphalting of vacuum residue), by combustion, in particular for recovery assisted by heavy crude oil, and / or the production of hydrogen by oxidation partial asphalt.
The aforementioned patent No. US 5,069,775 further describes a process crude oil hydroconversion heavy viscous, typically with a liquid catalyst comprising molybdenum in solution, using natural gas to produce hydrogen, to produce a crude fluid transported to a refinery.
Typically, the processes of "upgrading" of crude oil (the word upgrading meaning quality improvement) reflect the technical philosophy of the producers of petroleum:
lower cost minimal processing to make oil a) transportable, and which can be refined in a special refinery, b) possibly, which can be refined in a conventional refinery.
The oil trades are very compartmentalized in an oil company : the people refiners are not involved in oil production; similarly the oil producers are directly affected by the fact that their product is transportable and sellable to refineries, but are not involved in refining.
As a result, the interest of oil producers in upgrading "is typically directed to elements that influence the price of oil: viscosity and point of flow (which condition the

7 transport), density (which determines the quantity produced in barrels: the oil is sold in barrels, not in tonnes) and the sulfur content which induces penalties on the price.
Petroleum is thus considered as a "global substance" characterized by its viscosity, its point flow, density and sulfur content.
One of the specific aspects of the invention is, according to different variants, to use fillers and / or specific processing steps to achieve technical objectives individuals, relative no only to the "petroleum substance" but also to its different fractions, in terms of refining.
The invention can thus implement one or more catalytic steps using certain processes well known in the art a) Hydrotreatments (symbolically designated by the acronym HDT) of charges without asphaltenes Hydrotreatments of hydrocarbon distillates or deasphalted oil (charges substantially lacking asphaltenes) are well known processes in the state of technical. Their main purpose is the at least partial elimination of undesirable compounds, typically of sulfur, nitrogen, possibly metals such as iron, nickel or vanadium, etc ... They are also often used for the hydrogenation of aromatics, generally simultaneously with desulfurization of charge.
Conventionally, for those among the aforementioned charges which include compounds boiling above 371 ° C, we call hydrotreating a process whose conversion of these compounds into compounds with a boiling point below 371 ° C is less than or equal to 20% by weight.
For processes treating the same loads, but with conversion greater than 20% by weight, we will speak of hydroconversion (symbolically designated by the acronym HDC), or hydrocracking (symbolically noted HDK), these methods being presented below.
Hydrotreatment processes operate under hydrogen pressure, and use catalysts supported solids, typically granular solids or extrudates of characteristic dimension (diameter for balls or equivalent diameter (corresponding to the same section) for extruded) between 0.4 and 5 mm, in particular between 1 and 3 mm, The conditions and in particular the space velocity (VVH) and the hydrogen molar ratio over hydrocarbon (H2 / HC) vary according to the cuts treated, the impurities present and the final specifications sought.
Typical and nonlimiting examples of operating conditions are given in the following table

8 Point Velocity Pressure Temperature Report Consumption of Sectional cross section of H2 start of H21HC of H2 oil (C) (h-1) (bar) cycle (Nm3 / m3) (% mass) (VS) Naphtha 70-180 4-10 5-10 260-300 100 0.05-0.01 Krosne 160-2402-4 15-30 300-340 150 0.01-0.02 Diesel and 230-3711-3 20-40 320-350 150-300 0.3-0.8 Diesel fuel Diesel under 371-5651-2 40-70 360-380 300-500 0.4-0.9 empty Asphalt oil> 565 0.5-1.5 50-110 360-380 500-1000 0.5-1 Hydrotreatment catalysts typically include a metal, or compound of a metal from group VIB and of a metal or compound of a metal of group VIII, on a support.
The most common catalysts are composed of an oxide support and a active phase under the form of molybdenum or tungsten sulfide promoted by cobalt or nickel. The formulas commonly used are the CoMo, NiMo and NiW associations for the phase active, and alumina y of large specific area for the support. Metal contents are often around

9 to 15% by weight of molybdenum and 2.5 to 5% by weight of cobalt or nickel.
Some of these catalytic formulas are sometimes doped with phosphorus.
Other oxide supports are used such as mixed oxides of the silica-alumina or titanium type alumina.
These supports are typically of low acidity, to obtain durations of catalytic cycle acceptable.
Typical examples of catalysts and hydrotreatment, including cuts diesel, diesel or diesel under vacuum are the HR448 and HR426 catalysts from the French company AXENS.
When traces of metals, especially nickel and vanadium are present in the load, we advantageously uses a catalytic support comprising a suitable porosity at the filing of these metals.
An example of such a catalyst is the HMC 841 from the company AXENS.
For the hydrotreatment of a deasphalted oil (DAO) comprising metals, we can by example use a first bed with an HMC 841 catalyst, for the demetallization and then a second HR 448 bed for desulfurization and denitrogenation.
b) Hydrocracking processes (symbolically referred to as HDK) from charges without asphaltenes:
Hydrocracking processes are also well known processes of the state of technique. They apply exclusively to loads substantially free of asphaltenes or metals such as nickel or vanadium.

The hydrocracking charge is typically composed of diesel under vacuum, sometimes added with gas oil and / or deasphalted oil (deasphalted vacuum residue, typically by a group solvent formed by propane, butane, pentane and their mixtures, and preferably propane and butane).
We can also do a hydrocracking of deasphalted oil (often called "DAO" for deasphalted oil according to English terminology, which means oil deasphalted). The CAD must then have sufficient quality: typically, a hydrocracking charge includes less than 400 ppm (parts per million by weight) of asphaltenes, preferably less than 200 ppm and very preferred less than 100 ppm. The metal contents (typically nickel + vanadium) of a charge hydrocracking are typically less than 10 ppm, preferably less than 5 ppm, and very preferably less than 3 ppm.
Conventionally, it is considered that a load is substantially without a ~ haltènes if its rate asphaltenes is less than 400 ppm.
Typically the hydrocracking charge is first pre-refined on a hydrotreating catalyst, typically different from the hydrocracking catalyst. This catalyst, typically lower acidity to that of the hydrocracking catalyst is chosen to substantially eliminate metals, reduce traces of asphaltenes, and reduce organic nitrogen, which inhibits reactions hydrocracking, up to typically less than 100 ppm, preferably 50 ppm and so very preferred lower at 20 ppm.
Hydrocracking catalysts are typically catalysts bifunctional having a double function: acid on the one hand and hydrogenating / dehydrogenating on the other.
Typically, the carrier has a relatively high acidity such that the ratio of hydrogenating activity on isomerizing activity H / A as defined in French patent No 2 805 276 pages 1 line 24 to page 3 line 5, is greater than 8, or preferably greater than 10 or so very favorite superior to 12, or even greater than 15. Typically, hydrotreating is carried out upstream of the reactor or of the hydrocracking zone with a hydrotreating catalyst, the HlA report, supra is less than 8, in particular less than 7.
Hydrocracking catalysts typically comprise at least one metal or metallic compound from group VIB (such as Mo, W) and a metal or metal compound from group VIII
(such as Ni ...) deposited on a support. The atomic ratio of the group VIII metal (MvIIi) to the sum of metals groups VIII and VI B, i.e. the atomic ratio Mv ~ II ~ (Mmn + Mm B
), especially for NiMo and NiW couples is often close to 0.25, for example between 0.22 and 0.28.
The metal content is often between 10 and 30% by weight.
The group VIII metal can also be a noble metal such as palladium or platinum, to contents of the order of 0.5 to 1% by mass.

The acid support can comprise an alumina doped with a halogen, or a silica-alumina having sufficient acidity, or a zeolite for example a Y or USY zeolite dealuminized, having often a double pore distribution with a double porosity network including micropores with a size mainly between 4 to 10 ä and dimension mesopores 5 mainly between 60 and 500ä. The silica / alumina ratio of structure of the zeolite is often between 6.5 and 12.
For example, one can use a hydrotreatment sequence then hydrocracking with HR 448 (HDT) and then HYC 642 (HDK) catalysts marketed by the company French AXENS. Yes the load includes metals, we can use upstream of these two beds catalytic a bed of

Demetallization catalyst such as HMC 841 also marketed by the company AXENS.
Examples of operating conditions for hydrocracking are typically - VVH space speed between 0.3 and 2 h- ~, - Temperature between 360 and 440 ° C, 1 S - Recycling of hydrogen between 400 and 2000 Nm3 per m3 of charge, - The partial pressure of hydrogen and the total pressure may vary significantly depending on the load and the conversion sought. By convention, a conversion greater than or equal to 20% weight and less than 42% by weight corresponds to a mild hydrocracking (noted symbolically M-HDK); a conversion greater than or equal to 42% by weight and less than 60% by weight corresponds to a medium pressure hydrocracking (symbolically noted MP-HDK); a conversion higher or equal to 60% by weight (and typically less than 95% by weight corresponds to a high hydrocracking pressure (symbolically noted HP-HDK).
By definition, conversion is that of temperature products boiling above 371 ° C, products boiling below 371 ° C.
Typically, the partial pressure of hydrogen is, depending on the loads, often between approximately 2 MPa and 6 MPa for mild hydrocracking, between approximately 5 MPa and 10 MPa for hydrocracking medium pressure, and between approximately 9 MPa and 17 MPa for high hydrocracking pressure. The total pressure is often between 2.6 and 8 MPa for hydrocracking sweet, between about 7 and 12 MPa for medium pressure hydrocracking, and between 12 and 20 MPa for high hydrocracking pressure.
Hydrocracking processes are typically operated in a fixed bed with granular solids or extruded of characteristic size (diameter for balls or diameter equivalent (corresponding to the same section) for extrudates) between 0.4 and 5 mm, especially between 1 and 3 mm. It would not go beyond the scope of the invention if the hydrocracking were made in movable bed (bed granular catalyst typically in the form of extrudates or favorite of balls, of dimensions similar to those described for a fixed bed.

11 Other technical elements relating to hydrocracking can be found in the work of reference: "Hydrocracking Science and Technology"
hydrocracking), J
Scherzer and AJ Gruia, Publisher Marcel Dekker, New-York.
c) Hydroconversion processes (symbolically desired by the acronym HDC) of a screed without asphaltenes (for example DAO type) but comprising significant quantities of metals (Ni, V):
Such methods are known for achieving conversions (with the same definition as for hydrocracking) greater than 20% by weight and often much greater (for example from 20% to 50%, or from 50% to 85% by weight, for example bubbling bed processes. These processes can use variable partial pressures of hydrogen, for example between 4 and 12 MPa, temperatures between 380 and 450 ° C, and a hydrogen recycling of, for example, between 300 and 1000 Nm3 per m3 of charge, The catalysts used are similar or similar to that of the hydrotreatment catalysts or hydroconversion of residues, defined below, and have a porosity allowing to have an ability notable in demetallization.
It is possible, for example, to use a catalyst of the HTS 358 type, sold by French society AXENS.
d) The) ~ residue treatment (symbolically designated by the acronym RHDT) or residue hydroconversions (symbolically designated by the acronym RHDC):
Residue hydrotreatment (and residue hydroconversion) processes are good processes known from the state of the art.
The operating conditions of these processes are typically: Spatial velocity hourly (or VVH) between 0.1 and 0.5. Partial pressure H2 between 1 and 1.7 MPa. Recycling of hydrogen between 600 and 1600 Nm3 per m3 of load. Temperature between 340 and 450 ° C.
Catalysts for fixed, mobile or bubbling bed processes are the most often solids supported macroscopic, e.g. medium diameter beads or extrusions between 0.4 and 5 millimeters. Typically, these are supported catalysts comprising a metal or compound metallic group VIB (Cr, Mo, W) and a metal or metallic compound of group VIII (Fe, Co, Ni, ...) on a mineral support, for example cobalt-based catalysts and molybdenum on alumina, or nickel and molybdenum on alumina.
For hydrotreating or hydroconversion in a fixed bed, you can use for example a HMC 841 hydrodemetallization catalyst, then catalysts hydroconversion and hydrocracking: HT 318, then HT 328 marketed by the French company AXENS.
For a bubbling bed, an HOC 458 type catalyst can be used, also marketed by the French company AXENS.

12 The catalysts for slurry processes are more diverse and can understand particles of crushed coal or lignite impregnated with iron sulphate or other metals, catalyst crushed spent hydrotreatment, particles of molybdenum sulfide associated with a matrix hydrocarbon, obtained by in situ decomposition of precursors such as molybdenum naphthenate etc ... The particle sizes are typically less than 100 micrometers or even a lot even weaker.
Other characteristics of hydroconversion processes and catalysts residues are given in the general work referenced A: "Refining and conversion of heavy products of oil ", by JF Le Page, SG Chaula, M Davidson, Editions Technip, Paris, 1990, in the chapter 4 (Conversion catalytic under hydrogen pressure), and chapter 3 paragraph 3.2.3. We may also refer to the general work referenced B: "book 3: Transformation processes" by P
Leprince, in the collection "The refining of petroleum" published by Technip, Paris, 1998, in chapter 13 (hydroconversion of residues), as well as the general work: "upgrading petroleum residues and heavy oils "which means: improving the quality of petroleum residues and oils lourdes, by Murray R. Gray, editor Marcel Dekker inc. New York, in Chapter 5.
The production of hydrogen from purified gas, for example by steam reforming on catalyst at nickel then conversion of CO to steam then purification is a good process known, described in the work referenced B above, in chapter 14, or in the reference work:
"The desulfurization of heavy oils and residua ", J
Speight, Publisher Marcel Dekker, Inc. New-York.
According to one of the preferred variants of the invention, in the region of gas production, a gas of deposit, or a purified deposit gas G as follows:
a) converting at least a fraction G1 of this gas G, to obtain a current hydrogen (H2), b) a pipeline is selected and supplied by a tanker crude oil conventional P1 fluid and pour point less than or equal to - 10 ° C, c) in an installation (I) for processing hydrocarbons, a charge processing of hydrocarbons comprising petroleum P1, alone or mixed with others fractions, the processing of this oil P1 being produced substantially without rejection of carbon, and comprising at least one step catalytic on solid catalyst supported hydrotreating (HDT, RHDT) or hydroconversion (HDC, RHDC) or hydrocracking (HDK) of at least a fraction of the oil P1, this fraction mainly comprising compounds with a boiling point greater than 343 ° C, this stage using at least a fraction of the current H2, to produce at least one pre-purified PA oil comprising compounds derived from of this step, this P "oil being intended to be rowed in a separate and distant refinery from (installation (I).
Fluid conventional oil (defined later in this description) has characteristics intrinsic which easily classify it in the category of oils transportable Its viscosity is

13 low. Its pour point is less than 0 ° C, often at -10 ° C, often below - 12 ° C, typically below - 14 ° C or sometimes below - 16 ° C or at - 18 ° C, or even at - 20 ° C.
Carry out a pre-treatment treatment on such oil, which has already been transported by pipeline (like a conventional oil, that is to say, according to the invention, without dilution / separation / recycle thinner as it is sometimes used to transport crude oils heavy or heavy oils) or which has already been transported by oil tanker, is surprising because this oil can be easily sent directly to an oil refinery. If the techniques heavy oil upgrading viscous (or processing oils with pour points above 0 ° C) can theoretically be applied to such a conventional crude there is no motivation of such treatment compared to the direct shipment of this oil to a refinery for the trade person oil production. The person skilled in the art of petroleum production looking indeed typically to carry out the minimal treatment for the oil to be transportable and salable.
This can be seen from reading various patents, and for example from above-mentioned patent No US 5 069 775. The process described is said to be applicable to crude oils which may have an API density between - 5 and 35, which includes relatively light oils but don't say that these oils include easily transportable oils. We know indeed light oils having a API density greater than 30 and which have a pour point at a temperature positive who can pose significant transportation problems. For example, petroleum Libyan "Es Sider" has a API density of 37 and a pour point of + 7 ° C for crude oils from Gabon "Gamba" and "Mandji blend "(Mandji blend) have an API density of 31.4 and 30.1 respectively but one point flow rates of 32 ° C and 9 ° C respectively; On the contrary, it is indicated in the aforementioned patent that the field of the invention is the upgrading of viscous heavy crudes, and that the process is particularly well suited for the treatment of heavy oils and oils waste. The first one claim of this patent describes a treatment "for obtaining an oil fluid then carry this petroleum in a refinery at least by pipeline transportation. "
Processing is not performed only on a fraction of the initial oil, in order to carry out a treatment minimum sufficient to ensure fluidity of the output oil. Only the viscosity parameter of the oil produced is mentioned, and the composition of the petroleum produced, or the properties of its fractions are not mentioned. The catalyst used is a liquid additive, to minimize the cost of treatment (typically, such processes are less expensive than processes using solid catalysts macroscopic supported, but less effective for desulfurization).
The use of low value methane for the production of hydrogen is mentioned but does not appear as the motivation for treatment, but simply as a technical means annex usable advantageously in the context of a production project oil difficult to carry. This patent is quite characteristic of technical philosophy and economical oil production people looking to get an oil marketable, by simple means, minimal investment, characteristics of operations on oil field.

14 Besides, for a fluid and low point conventional oil flow, technical logic is to carry out the ramage directly in a conventional refinery, and not to "stop in path "to produce an intermediate oil to be transported to new to be refined in oil refinery.
On the contrary, it has been found, according to the invention, that the processing of an oil conventional fluid, transported without diluent presents, vis-à-vis the desired objectives, significant benefits by compared to the traditional upgrading of heavy crude oil with difficulty transportable:
- By simulations and modeling of installations for different charges and processes residue processing, it has surprisingly been found that, with a view to produce a given quantity of improved petroleum reducing excess sulfur fuel oil during refining subsequent investment required is significantly lower for conventional crude oil. This comes from different reasons which often combine:
- Heavy crude oils are typically unripe crude oils having amounts of high vacuum residue and very generally have metal contents (Ni, V) very high which strongly reduce the activity of supported catalysts.
- The typically very aromatic composition of a heavy crude oil produced, after hydroconversion diesel fractions with a relatively low cetane number, typically less than 49, and often at 45 or even 42, that it would be difficult and costly to improve to transform them into databases diesel fuel.
In addition, heavy crudes often include a quantity of vacuum diesel limited compared to vacuum residue. Now it has been found according to the invention that the amount of diesel vacuum, or diesel vacuum with deasphalted oil was an important parameter in a upgrading project at technical and economic level. These deasphalted cuts are indeed product precursors highly recoverable which can be converted with less investment high than a residue under vacuum.
- The asphaltene content of the vacuum residue, often very high with crudes heavy is also appeared as an important parameter, in particular with regard to the diagrams of possible treatment.
- In addition, the production of heavy crude oil (typically produced from a high number of wells distant from each other), and its routing to the installation of treatment lead to investments and high energy costs.
Typically, a fluid conventional crude oil is selected according to the invention, which has a connection mass J = (GO + VGO) / (GO + VGO + R) greater than 0.45, in particular greater than 0.50, in a way preferred greater than 0.54, or even greater than 0.58 and most preferably greater at 0.62.
Conventionally, GO represents the mass percentage (figure included between 0 and 100), by relative to petroleum, the fraction of boiling petroleum (depending on the distillation TBP, boiling points true) between 343 and 371 ° C. VGO represents the mass percentage of the fraction of boiling oil between 371 ° C and 565 ° C, and R is the mass percentage of the residue sous vide (boiling at a temperature greater than or equal to 565 ° C) in this oil. The parameter J is an indicator of percentage of heavy fractions which is not residual.
The parameter H = VGO + R (100- 2xAs) / 100, in which As is the mass rate (number between 0 and 100) of asphaltenes in the vacuum residue is also important. This parameter is an indicator of 5 the non-asphaltic heavy oily fraction which can be recovered more easily. Preferably H
is greater than 35, in particular greater than 0.38, preferably greater than 0.41 and very preferred greater than 0.45.
The conventional fluid crude oil selected preferably also has a level of asphaltenes As its vacuum residue less than 11% by weight, or 10% by weight, or less at 9% by weight, often 10 less than 8% by weight and very preferably less than 7% by weight. This rate is correlated with the difficulty in processing the residue under vacuum, linked to the quantity asphaltenes.
Consider the parameter L = VGO + R (100- 2xAs) / 100 x (lOlAs) "3, in which As is the rate mass of asphaltenes of the vacuum residue (number between 0 and 100), taking As = 6 if the value of As is less than 6. This parameter is an indicator corrected for the parameter H.

15 L is preferably greater than 0.33, or 0.35, or 0.37, or 0.39, or 0.41, or 0.43, or 0.45 or at 0.47.
The asphaltene content of the selected conventional fluid oil itself (and either its residue) is also often less than 5% by weight and preferably less than 3.3% by weight and very preferably less than 2.2% by weight.
Preferably, a petroleum P1 is chosen whose quantity of metals (Ni + V) in the vacuum residue is less than 800 ppm weight, in particular 700 ppm, or 550 ppm, or 400 ppm, or at 300 ppm, or at 200 ppm and preferably less than 150 ppm or even 100 ppm, very favorite lower at 80 ppm.
Other variants of the invention are described below which can be advantageously used with conventional fluids, but also with all other types of petroleum, including heavy oils, and also with petroleum residues.
According to another alternative embodiment of the invention, a treatment including an initial step comprising a fractionation, to obtain a fraction F
substantially free of asphaltenes and mainly comprising boiling point compounds higher than 371 ° C, - at least one hydroconversion (HDC) or hydrocracking (HDK) stage of a at least part of fraction F, with a conversion of the boiling point compounds higher than at least 371 ° C
equal to 42% by weight, in particular greater than 48% by weight, often greater than 52 % by weight and by example greater than 60% by weight.
Preferably, a sufficient hydrocracking pressure is chosen (which increases the index and the number of cetane distillates produced), incorporated into the fractions composing petroleum pre-refined PA a sufficient fraction of the hydrocracking effluents, and eventually we incorporate

16 in PA oil, a direct distillation diesel fraction from P1, after hydrotreatment (HDT) at sufficient pressure, so that the pre-refined petroleum P ,, includes a diesel fraction cetane number at least 48, or 49, or 50, often at least 51 or same 52. So preferred, especially if PA oil is intended for the European market, the index cetane fraction diesel of this oil can be greater than 51 and for example between 52 and 70.
Such use of hydrocracking, in particular hydrocracking with medium or high pressure is amazing in an upgrading project: A hydrocracker is a "high unit"
often "
the most expensive unit in a refinery, which many refineries do not can acquire. The characteristic of hydrocracking is, in a refinery, to produce cuts diesel and / or kerosene and / or oil bases with very high quality. This is typically stranger to philosophy technique of upgrading according to the prior art.
Treatment variants with deasphalting:
According to another characteristic variant for carrying out the invention, we perform a step of deasphalting of at least part of the vacuum residue of the charge hydrocarbon or crude P1, to obtain a stream of DAO deasphalted oil, as well as a stream of asphalt As, and we mix at least part of this current As with at least one hydrocarbon current of mixed typically directly from the feed or after treatments) at least in part, to produce (after possible separation of certain fractions of the mixture) a petroleum reconstituted, or petroleum refined.
According to a particular provision, a) the mixing conditions, and in particular the relative quantity of the mixture compared to the quantity of asphalt As and the composition of the mixing stream, are chosen so that the residue under vacuum of this reconstituted or refined petroleum has a level of asphaltenes significantly higher than that of vacuum residue feeding the deasphalting unit.
The vacuum residue of the reconstituted petroleum may have an asphaltenes level increased by at least 18%
relative to the asphaltene content of the vacuum residue sent to deasphalting, often increased by at least 22%, or even at least 26%, preferably at least 30% and very favorite way at least 35% relative to the asphaltene content of the vacuum residue intitial.
Typically, the crude oil A1 and / or the hydrocarbon feedstock are chosen for that the rate of asphaltenes from the initial vacuum residue for example the vacuum residue from the gross A1, or that of the load is less than 12% by weight, often 11% by weight, preferably at 10% by weight or 8%
weight and very preferably at 7% by weight, for example between 0.5 and 6.5% by weight.
The asphaltene content of the vacuum residue of the reconstituted crude oil can be according to cases, greater than 8%
weight, usually 10% by weight, often 11% by weight. Preferably it is between 12%
weight and 25% weight and very preferably between 13% weight and 20% weight.
We thus realize a high concentration of asphaltenes, which reduces the volume of residue sulfur.

17 The vacuum residue sent to deasphalting may include compounds having cracked, for example thermal cracking under hydrogen pressure or a hydrotreating. Typically, preferably, this vacuum residue is a virgin residue, comprising virgin alphaltenes, not having undergone, at least for the most part, or entirely, processing operation chemical or previous cracking.
The mixing stream can advantageously comprise a fraction of content in sulfur significantly reduced compared to that of the initial CAD, for example a part or all of the CAD itself, after hydrotreating ebou hydroconversion andJou hydrocracking, in a fixed bed, mobile, or bubbling, as described in connection with figure 4. It can also understand some of the residue under initial vacuum, or a stream of crude oil (or a fraction of crude oil), especially if this crude oil has a vacuum residue whose asphaltenes content is less than 11%, or 10%, or 9 %, or preferably 8% and very preferably 7%. Typically the mixing currents include a vacuum residue with a sulfur content of less than 1.25% by weight, or at 1% by weight and preferably less than 0.8 or even 0.6% by weight. This reconstruction of a oil with concentration of asphaltenes can be achieved on all or on only a fraction of the residue load or petroleum vacuum P 1.
Such a residue treatment scheme is described in Figure 4.
According to another particular variant according to the invention, described in the figure 5, the treatment of the residue R
includes deasphalting (SDA) of part of the residue, hydrotreating (RHDT) or hydroconversion (RHDC) of another part of the residue, and mixing a at least part of asphalt from deasphalting, and at least part of the effluent hydrotreating or hydroconversion to obtain a pre-refined crude PB. This pre-refined crude can also understand a part of the initial residue and / or another crude oil or a fraction of another crude oil.
This treatment regimen is particularly interesting when the initial vacuum residue, or the fraction vacuum residue of residue R a a relatively high content of asphltenes such as from 8% by weight to 20%
weight, or 9% weight to

18% by weight, in particular from 10% by weight to 18% by weight, or from 11% by weight to 16%
weight and typically from 12% by weight to 16% by weight. In this case, a reduction of asphaltenes by hydroconversion allows ability to concentrate other asphaltenes without exceeding a rate too important. The proportion of hydroconverted residue is for example between 15 and 75%
weight, often between 20 and 65% by weight.
According to another characteristic variant of the invention, the installation (I) of treatment of hydrocarbons according to the invention produces at least two separate oils PA and PB, typically intended to be sent separately to one or more oil refineries by pipeline and / or oil tanker.
Generally, these two oils are intended to be transported separately by tankers on distances exceeding 1000 km, or even 1500 km, and generally towards different refineries.

This allows, using different compositions for the two oils, improve their global valuation. So, for example, a petroleum rich in kerosene has generally a valuation raised in the United States of America; a petroleum rich in high diesel cut index or number of cetane generally has a high valuation in Europe, whereas this characteristic is less important in the United States of America.
An oil comprising a sulfur-containing residue in significant quantity is generally better valued in the Far East than in Europe.
Typically, one of the two oils differs from the other by at least 10%, often 15%, and generally 20% for at least one of the following parameters: percentage kerosene weight, percentage diesel cutting weight, percentage weight of vacuum residue having more than 1.25% by weight sulfur content.
Generally, one of the two oils includes a diesel cut whose index of cetane CI is at least 2 points higher, often 3 points and generally 4 points that of the other oil.
- According to a first embodiment, one of the two oils P ,, is free vacuum residue having more than 1.5% by weight of sulfur, often free of residue having more than 1.25%
weight of sulfur, or even more than 1% by weight, or preferably more than 0.8% by weight of sulfur, then than the other PB oil includes a vacuum residue with an SRB sulfur content greater than 1.25%
weight, and typically greater than 1.5% by weight. PA can thus include a vacuum residue of lower sulfur content or equal to 1% by weight.
- According to a particular embodiment of the previous mode, PA oil is an oil substantially free of asphaltenes (less than 400 ppm conventionally), or even residue under vacuum, boiling point greater than or equal to 371 ° C. Yes P ,, includes a residue under empty, this typically has an SRA sulfur content of less than 0.4%
weight, often less than 0.2% by weight, for example less than 0.1% by weight or even at 100 ppm by weight.
The ratios of the mass percentages of the two oils in Kerosene andlou diesel coupe check then often one or more of the following inequalities K> 1.1 (or 1.15, or 1.2, or 1.3, or 1.4) KB
DA> 1.1 (or 1.15 or 1.2, or 1.3, or 1.4) DB
CIA-CIB> 2 (or 3, or 4, or 5), in which KA and KB denote the weight percentages of kerosene in the P ,, and PB, DA oils and DB-the diesel cut weight percentages in PA and PB petroleum, and CIA
and CIB the indices of cetane from diesel cuts of PA and PB oils.
This difference in cetane number can be obtained by incorporating into the crude PA greater relative quantity of diesel hydrocracking cut, in particular hydrocracking at high pressure, when the installation (I) comprises a hydrocracker that. She can also be obtained in

19 incorporating PA crude oil into a more deeply hydrotreated diesel cut example with speed lower spatial pressure (VVH) or higher pressure. The mass ratio between PA oil and the PB oil can vary for example between 0.6 and 6, often between 1.2 and 5, especially between 1.5 and 4.5.
According to another characteristic variant of (invention, the charge installation hydrocarbon (I) includes a refining residue Ro> typically supplied by boat tanker and coming by example of refineries more than 1000 or even 1500 km away, for example refineries, in sulfur oil, from the European Economic Community.
Such a residue Ro typically comprises at least 30% by weight, or 40% by weight, or even 50% weight vacuum residue from refinery, preferably vacuum residue virgin, i.e. residue under direct distillation vacuum. Such a residue, which has not been cracked in a visbreaking unit, or other, is a better load for at least partial transformation in oil according to the invention. The transport of a refinery residue in an area of gas production, for transforming this residue into oil is a variant making it possible to reduce directly the surplus of sulfur oil.
The residue Ro can also include aromatic cuts originating from a cracking unit catalytic fluid bed (often called FCC) of the refinery (boiling typically between 220 and 550 ° C, especially between around 220 ° C and 343 ° C (cutting called LCO) or between about 340 ° C and 550 ° C (cut called HCO).
The residue can also comprise, according to the invention, a light diluent such as naphtha or kerosene, in order to lower its viscosity and to be able to transport it in a boat conventional tanker, without.
require heating or maintaining at a temperature above 40 ° C, or even 30 ° C> so preferred without significant heating of this residue during transport, and very favorite way without no heating.
The residue Ro can in particular comprise - from 30 to 80% by weight, and often from 40 to 70% by weight of vacuum residue from direct distillation in rafimerie, - from 0 to 50% by weight, and often from 10 to 40% by weight of aromatic cuts of catalytic cracking (LCO / HCO) - from 0 to 30% by weight, and often from 5 to 20% by weight of compound diluent typically by a cut of refinery boiling below 340 ° C.
Catalytic stages: HDT, HDC, HDK, RHDT, RHDC (including variants hydrocracking soft, medium pressure and high pressure) can be implemented, depending on one of the variants preferred of the invention, with supported solid catalysts macroscopic, this term applying, by convention according to the invention, to granular solids or dimension extrusions characteristic (diameter for balls or equivalent diameter (corresponding to the same section) for extrusions) between 0.4 and 5 mm, especially between about 0.8 and 3 mm. These catalysts comprise at least one metal, or composed of a group VIB metal (comprising molybdenum and tungsten) and at least one metal or compound of a group VIII metal (including nickel).
This therefore excludes, for this variant, the catalysts used in slurry which typically have 5 characteristic dimensions less than or equal to about 100 micrometers, and who often does not do not include the association of metals of the above groups.
Residue treatment processes (RHDT, RHDC) can however be employees as well with macroscopic supported solid catalysts comprising at least one metal, or compound a group VIB metal and a metal or a group VIII metal, that with 10 catalysts used in slurry. According to one of the preferred variants according to the invention, so we use exclusively solid catalysts of macroscopic type, comprising at least minus a metal, or composed of a group VIB metal and at least one metal or composed of a metal of group VIII, which typically have better desulfurization activity than catalysts used in slurry, and don't do not pose significant problems of solid content in the oil (s) PA and Play PB products According to the invention Furthermore, they typically produce less gas.
One of the characteristics of processes in slurry is indeed to achieve a very thorough conversion (up to more than 90%, or 95%, or even 98% by weight of distillable compounds: vacuum distillate or compounds lighter) The residue ultimate is indeed unstable, loaded with carbonaceous solids.
According to another preferred variant of the invention, the conversion of the residues treated is however

20 carried out at very high conversion, in the range [70% -98% weight], and preferably [80% -98% weight], either in a bubbling bed followed by deasphalting, or preferably in slurry, possibly followed deasphalting, in particular for recycling the catalyst with the asphalt.
In these cases, the residue ultimate is unstable and is burned on site, for example in a boiler incinerator producing pressurized water vapor.
The conversion to slurry is then interesting because it allows to minimize the ultimate residue by the use of a very high level of conversion.
The different variants of the invention will be explained more fully from the figures attached:
- Figure 1 shows an example of a load treatment installation of hydrocarbons for the use of a hydrocarbon charge for the use of purified deposit according to the invention.
The installation is supplied by a load C comprising three components:
crude oil P1 supplied by line 1, typically a conventional fluid oil and transportable; crude oil P2, possibly conventional fluid and transportable, or petroleum heavier, viscous crude andHigh pour point, and therefore difficult or not transportable by a pipe not heated; finally, a refinery residue Ro supplied by line 3.

21 These three load components are treated separately or mixed in unit 100. This unit is typically a distillation at substantially atmospheric pressure, or a split more summary (simplified distillation with a limited number of stages). According to one variant, charge C, can be pre-cracked, in whole or in part (for example after elimination light fractions), in unit 100. This prior cracking may include a) thermal cracking under hydrogen pressure (process known as hydro-visbreaking), or b) cracking in the presence of a hydrogen donor diluent, typically called DDH, and compound typically of a previously hydrogenated aromatic cut, or else c) hydroconversion in a slurry reactor.
The preferred variant for unit 100 is a simple splitting in two steps, without pre-cracking simplified distillation or fractionation at substantially reduced pressure atmospheric, then, - vacuum distillation.
Unit 100 typically produces a gas comprising hydrocarbons having from 1 to 4 carbon atoms typically processed downstream to recover liquid fractions: propane and butane, evacuated by the line 4; an evacuated naphtha (N) by line 5; a kerosene / diesel cut (KID) evacuated by line 6; a diesel cut, or diesel atmospheric (GO) evacuated by line 7; a cup of gasoil under vacuum (VGO) evacuated by the line 8; a vacuum residue R1, discharged via line 12; cutting aromatic (LCO / HCO) from the Ro residue, discharged via line 13.
Kerosene, diesel and atmospheric diesel cuts (defined later in description, are hydrotreated (HDT) in unit 200. The hydrotreated diesel keroseneJdiesel cut is evacuated by the line 201, a fraction that can be taken per line 202 to be sold as refined product, by example of diesel fuel.
The fraction of atmospheric diesel (GO), is evacuated after hydrotreatment by line 203, a part of this hydrotreated diesel that can be withdrawn by line 204 for be sold as fuel oil domestic or heating oil. Other fractions can also be hydrotreated in the unit 200, such as naphtha (N) supplied by lines 9 then 6, or diesel under vacuum (VGO) powered by line 11. The hydrotreating unit (of distillates) 200 is by elsewhere supplied with hydrogen by line 502, this hydrogen being produced from gas of deposit (or deposit gas clean). In general, a hydrotreating unit 200 can include hydrotreating common, or separate, for each of the treated cuts.
In FIG. 1, two output lines 201 and 203 are shown, corresponding to two separate hydrotreatment. We could also hydrotreat separately the kerosene, in particular sell a fraction of this kerosene as a refined product, or on the contrary hydrotreat all distillates mixed in a common hydrotreating unit.

22 The vacuum gas oil (VGO) is evacuated from unit 100 by line 8, and feeds, at least in part, unit 300 for processing heavy distillates. This unit can also process a fraction of diesel atmospheric (GO) supplied by lines 10 then 8. It can also treat a fraction of oil deasphalted (DAO) supplied by lines 401 then 8. The unit 300 can be a unit hydrotreatment (HDT), or, according to a preferred variant of (invention a hydrocracking unit (HDK), according to one of the aforementioned variants.
Very advantageously, a hydrotreatment (HDT) is carried out beforehand hydrocracking.
Unit 300 is supplied with hydrogen by line 503, this hydrogen being typically produced at from reservoir gas. The effluents from unit 300 are evacuated by the line 301.
Typically, when hydrocracking at sufficient pressure is used high, such as 8 MPa, or 10 MPa or preferably 12 MPa, or very preferably 15 MPa, the effluent from unit 300 include a diesel cut whose number of cetane and cetane number are greater than 52, often 54, preferably 56, and very preferred 60.
The residue R1, evacuated from unit 100 by line 12, supplies unit 400 with residue treatment.
Typically, R1 is a vacuum residue, or a residue comprising gas oil vacuum (VGO) or atmospheric residue. Unit 400 is also (optionally) powered by a cut aromatic from the refinery Ro residue. This aromatic cut can understand typically cuts from a catalytic cracking unit (called FCC), such as boiling cuts in the field of kerosene and diesel, commonly called LCO, or diesel atmospheric and vacuum of FCC, called HCO. This cut can also understand a diesel of poor quality produced in a refinery, for example a boiling cut in the same areas distillation than LCO and or HCO, from a coking unit.
Unit 400 of residue treatment may include residue hydrotreatment (RHDT) or hydroconversion residue (RHDC), typically under high hydrogen pressure, for example under pressure total between 10 and 25 MPa.
RHDT hydrotreatment, or catalytic hydroconversion of RHDC residues, can be realized with one or more reactors in a fixed, mobile, bubbling, or slurry bed.
Other diagrams of treatment of residue R1 are shown in Figures 2, 4 and S. Unit 400 is also powered by hydrogen produced from field gas, supplied by the line 504. Unit 400 produces typically an effluent current flowing in line 403. It can also produce a current deasphalted oil (DAO) flowing in line 401, and a coke stream, or asphalt (especially liquid) discharged via line 402. The preferred variants of the invention did produce however no coke, or asphalt discharged as such (not mixed in an oil, or a oil).
When using hydrotreating in a bubbling bed, it often limits the conversion to VGO and lighter products in the 30 to 70% range, not exceeding the level of conversion making the unstable ultimate residue. Operating conditions (including pressure hydrogen, temperature), and

23 the catalyst can be chosen so that the ultimate residue is less than 1%
weight of sulfur. We can however minimize investment by operating at high VVH (space speed hourly), if seeks to desulfurize the ultimate residue only to 2% by weight of sulfur.
The hydrotreated distillates circulating in lines 201 and 203 are combined in line 205, then mixed, at least in part, with the effluents from unit 300, circulating in line 301, and added with naphtha (N) supplied by line 5, also with a make-up gas, especially butane and propane which can dissolve in heavier liquid products, powered by lines 4 then 5. The overall mixture then forms a substantially pre-refined oil without PA asphaltenes. The effluents from unit 400, flowing in line 403, are typically plus a current of hydrotreated distillates flowing in line 206, and a current of mothballs circulating in the line 16 (produced in unit 100, the corresponding output of unit 100 not being shown on the figure 1 ).
The treated residue, diluted by these relatively light fractions then constitutes PB, residual oil, or reconstituted petroleum, which is also typically pre-refined when it includes hydrotreated compounds.
Optionally, PA oil and PA oil can be optionally mixed thanks to the line connection 302.
The installation of Figure 1 also includes lines 14 and 15 evacuation respectively gas and naphtha (N), for the sale of butane / propane and naphtha.
FIG. 1 also shows a production unit 500 hydrogen from gas purified deposit supplied by line 501, hydrogen product circulating in lines 502, 503, 504 to supply units 200, 300 and 400 respectively.
Unit 500 can include any known type of hydrogen production (for example example steam reforming + conversion of CO to water vapor + fractionation by PSA adsorption, or any other mode of production, including for example a partial oxidation step or using the process autothermal).
Figures 2 to 6 show variants of installation or parts installation according to the invention and use the same numbering of lines or units as those of the figure 1.
FIG. 2 represents an installation for processing hydrocarbons according to the invention with a diagram particular embodiment of the unit 100 for initial load processing.
The unit 100a is a unit of fractionation of the so-called atmospheric distillation type, for example at a column head pressure between 0.105 and 0.18 MPa, with number of separation stages of limited preference, for example between 2 and 10 theoretical platforms or even between 2 and 6 theoretical platforms. We can use a significant steam stripping, for example greater than 40% by weight or 60% by weight or even 100%
weight relative to the bottom product of the column, this stripping flow and the bottom temperature of the column 100a being chosen to obtain at least one end point distillate (ASTM) greater than 380 ° C, for example between 390 and 470 ° C, especially between 400 and 460 ° C. This distillate

24 therefore includes boiling light vacuum diesel fuel (LVGO) fractions between 371 and 460 ° C, which can be discharged via line 6a, mixed with other fractions such as kerosene (K), diesel (D) and atmospheric diesel (GO). The global distillate is then hydrotreated, preferably in mixture, in unit 200. The bottom product of column 100a circulates in line 12a, is subdivided between a fraction feeding a vacuum distillation column 100b, and a fraction not subjected to vacuum distillation, bypassing unit 100b by line 12b to be mixed with the bottom product of unit 100b (vacuum residue). The R1 mixture in resulting, and including typically the vacuum residue and a relatively heavy part of the diesel vacuum-packed, is then sent to unit 400. Typically, for the installation of FIG. 2, unit 400 is a unit fixed, mobile, bubbling or slurry hydroconversion, and preferably a unit hydroconversion in) fixed) or bubbling (s) beds. Vacuum diesel relatively heavy separated at the head of column 100b is hydrodesulfurized then hydrocracked in unit 300, for example medium pressure between 7 and 12 MPa, or at higher pressure between 12 and 20 MPa for obtain a conversion into products boiling below 371 ° C
between 42 and 94% by weight in particular between 45 and 85% by weight, and for example between 50 to 80% by weight load ratio hydrocracked. Alternatively, all of the bottom product of column 100a is sent to the vacuum distillation 100b. According to another variant, from 10 to 90% in particular 20 to 80%, or 30 at 70% and for example from 40 to 60% by weight of the bottom product of column 100a bypasses the column vacuum distillation 100b. Vacuum distillation is then fed by the balance, from 10 to 90 %, 20 to 80%, 30 to 70%, or 40 to 60% by weight of the bottom product of the column 100a. The installation of FIG. 2 makes it possible to adjust the quantity of hydrocracked charge to the quantity necessary for a goal target, for example the overall diesel cut quantity and / or the index or the minimum number of cetane sought, in conjunction with the other parameters (conversion level and hydrocracking pressure) FIG. 3 represents an example of a vacuum diesel treatment unit 300 comprising - a hydrocracking unit 300a (typically after hydrotreating), supplied by line 8a by a charge comprising a relatively light vacuum gas oil (LVGO) or a mixture (LVGO +
VGO) - a 300b hydrotreating or mild hydrocracking unit (conversion 20 to 42 % weight) of load supplied by line 8b, and comprising a vacuum diesel relatively heavy (HVGO) or a mixture (HVGO + VGO), these charges can be added with oil deasphalted (DAO) supplied by line 3l. The proportion of the overall load of the unit 300 which powers the 300a unit can vary for example between 20 and 80%, or between 30 and 70% by weight. The 300a and 300b units can also be supplied with the same charge, for example from VGO.
The units are supplied with hydrogen by lines 503a and 503b, and their effluents circulate in lines 301a and 301b, for example to be mixed downstream and to enter in the composition of PA oil.

This scheme makes it possible to reserve a relatively light charge for hydrocracking.
easier to hydrocracking, and perform hydrotreating and / or moderate hydrocracking, easier to obtain, on the relatively heavy load (which can for example have an initial point (ASTM method) more 15 to 110 ° C higher than that of the relatively light charge).
5 FIG. 4 represents an association of a variant unit 400 of treatment of a residue R1, comprising a solvent deasphalting unit 400a (propane, butane, pentane, hexane or any of mixtures, or other), with a 300c oil conversion unit deasphalted produced (DAO).
Preferably, the unit 300c not only performs hydrotreatment, but also a hydroconversion of the DAO load, in a fixed bed or preferably in a bed bubbly. For example, 10 conversion to products boiling below 371 ° C can be for example between 30 and 80% by weight, or between 40 and 70% by weight relative to the load of CAD. The cracking can be a hydrocracking (I ~ K) or mild hydrocracking (M-HI ~ K), after hydrotreatment, or a hydroconversion (HDC), for example in a bubbling bed. This hydroconversion can be performed at medium pressure (for example between around 5 and 12 MPa). The effluent hydroconverted from unit 300c 15 circulates in lines 301c then 303, to be mixed with the asphalt, evacuated from unit 400a by lines 403a, then 403. A fraction of the initial residue R1 (for example between 5 and 50% weight) can also bypass deasphalting with lignel2d and be incorporated into mixed. A fraction of the effluent from unit 300c (for example between 5 and 60% by weight) can also be evacuated by the line 304, for example to be incorporated into PA petroleum. The notable conversion of the CAD leads to 20 reduce the proportion of uncracked oil in the final mixture, and realize a concentration of asphaltenes in the final residue (typically PB oil), as it already has been said, especially for residues with moderate asphaltenes content.
For example, we can split a light Arabic crude (or any other crude conventional), by

25 "atmospheric" distillation then under vacuum, deasphalting with pentane of the vacuum residue R1, to produce, compared to R1, typically around 80% by weight of CAD and 20%
asphalt weight As in the case of light Arabic. We can then submit the CAD to a HDC hydroconversion, or a HDT hydrotreating quite advanced, under hydrogen pressure included by example between 7 and 14 MPa, to make this DAO compatible with its subsequent supply to catalytic cracking fluid (in a refinery different from the installation according to the invention).
Preferably, we submit this DAO has a mild hydrocracking (M-HDK, or mild hydrocracking), under a pressure similar hydrogen but with a catalyst producing moderate cracking, to get 30 to 40% conversion weight, mainly in GO diesel and kerosene K cuts.
The effluent from hydroconversion, or hydrotreatment, or mild hydrocracking of the DAO can then, in part or all, be mixed with asphalt As (preferably maintained hot form liquid), as well as other distillable fractions: naphtha, kerosene, diesel, vacuum distillate, from fractionation of the starting crude, these fractions being preferably hydrotreated beforehand,

26 especially for kerosene K or heavier fractions, in order to obtain reconstituted oil PB whose fluidity is high, allowing its transport by pipes not heated (as for the PA oil).
We can also try to dilute the asphalt As not to reconstitute a PB oil but a fuel, in particular HTS fuel (high sulfur content, typically lower at 3%, 3.5%, or 4%
sulfur weight according to national standards). This HTS fuel can advantageously to be used locally, in part or in whole, as bunker fuel for oil tankers (boats).
may mix As asphalt with a reduced amount of thinner, desulfurized preference:
use some of the hydrotreated CAD, or preferably effluent mild hydrocracking (M-HDK) of DAO, in particular the lightest fractions produced (GO, LVGO, VGO). We can also use a light part or fraction of an effluent hydrotreating or hydrocracking mild VGO, or a VGO-DAO mixture, in any proportion. The proportion thinner by compared to asphalt As is generally between 25% and 150% by weight, and chosen according to two criteria: the need for an acceptable viscosity for fuel (therefore a diluting enough fluid and in sufficient quantity), and the sulfur content sought for the fuel. Fuel can also be obtained by diluting the asphalt with a small amount of topped crude. The fuel may finally have undergone a visbreaking, or visbreaking to reduce its viscosity.
In this variant of the invention with production of fuel, a product is therefore produced.
white oil PA
typically desulphurized for the most part, and a small amount (for example from 5 to 15%
weight) of fuel oil, the sulfur content of which is typically lower than that of crude vacuum residue of departure. The VGO fractions of the initial crude can typically be processed by HDT, M-HDK, or hydrocracking at medium or high pressure, before being generally incorporated into petroleum white PA, with at least part of the CAD after HDT or M-HDK, fractions K and GO often hydrotreated, and naphtha fractions desulfurized or not, all of these fractions from crude departure. The sulfur content of white petroleum PA can be less than 500 ppm weight, or even 150 ppm or even 10 ppm.
Of course, all the technical characteristics described above can be used for produce not fuel oil, but PB oil. Likewise, the productions of [PA oil + PB oil]
on the one hand, or [PA oil + fuel] on the other hand do not prevent the production of a certain quantity refined products, including naphtha, petrol, kerosene and / or diesel. In particular, some of these products: kerosene and diesel can be obtained from HDT from GO and 1 or HDK or MP-HDK from VGO and / or DAO. Essences can be obtained from reforming or hydroisomerization of naphtha. In the case of reforming, this allows produce a party at less hydrogen used for H2 units (HDT, HDK, etc ...).
FIG. 5 represents a residue treatment unit also comprising a unit of deasphalting 400a, but also a residue hydrotreating unit 400b (RHDT), or hydroconversion of residues (RHDC). A fraction of the residue R1 (for example between 25 and

27 75% by weight, or between 30 and 70% by weight) feeds unit 400b via line 12e, the effluent being discharged by line 403b. The fraction of the residue R1 feeding the unit 400a of deasphalting can typically be between 25 and? 5% by weight, or between 30 and 70% by weight. A fraction complementary, typically between 0 and 50% by weight can possibly bypass the 400a and 400b units.
This fraction can also be zero, all the residue R1 being treated. A
diluent stream (e.g.
part or all of the DAO, after hydroconversion as described in figure 4) can be incorporated into the overall effluent (from 403a, 403b, and possible part of R1 not processed) by line 303.
This treatment scheme is well suited to residues with a percentage notable asphaltenes (by example more than 10% by weight), as indicated previously. According to a variant, all of the residue R1 feeds section 400b; there is then no more deasphalting.
Typically, in an installation (I) according to the invention, the effluents from each of the 200 units, 300, 400 can be evacuated without fractionation or with a fractionation part. For example, hydrocracking effluents (unit 300, in particular of the M-HDK, MP-HDK type, or HDK, from preferably in single pass, often with moderate conversion between 30 and 60% weight) can be evacuated without fractionation of the hydrocracking effluent (or only a split of a part of the unconverted vacuum diesel fuel, for recycling). We can not realize that a stripping of H2S
product. For unit 400, and the constitution of PB oil, we can also, preferably do not separate, or only partially, often without recycling fractions. Yes we make a hydroconversion, the quantity of light naphtha will preferably be limited by output, to improve the stability of hydroconverted residues. The ratio of light naphtha to heavy naphtha PB oil will possibly be less than 0.3, even 0.2, even 0.15.
In general, whatever the treatment used according to (invention, we are trying to achieve preferably maximum thermal integration, and to avoid as much as possible the coolings then intermediate reheating of products, and intermediate storage of products, between the various units. For example, if you use an installation of the type of that of the Figure 1, including a unit 100 of initial distillation then under vacuum, a unit 200 hydrotreating of middle distillates, an HDT hydrotreating or hydrocracking unit 300 (M-HDK, MP-HDK, or HDK), one unit 400 of hydroconversion of residues, for example in a bubbling bed or in slurry, we will avoid preferably any intermediate cooling, and any storage between the unit 100 on the one hand, and 200, 300, and 400 units on the other hand. We can however realize possibly cooling limited number of cuts produced by the distillation columns of unit 100, so that the pumps transferring these cuts to units 200, 300, and 400, typically under strong hydrogen pressure and high total pressure, operate at a temperature which is not excessive, for example between 150 and 350 ° C.
Thermal integration could eventually lead to the implementation of a exchange train for the reheating of the starting crude oil at the entrance to unit 100, upstream of the distillation column atmospheric or possible desalter, this exchange train allowing the heat exchange with a

28 part or all of the effluents from units 200, 300, and 400. This amounts to to operate a train charge / effluent exchange not mainly in the unit of splitting 100 but at the level of the entire crude processing facility. This type of installation thermally integrated can also be implemented with any type of installation according to the invention, and is made possible by the makes these facilities much less complex than a refinery complete, and allow therefore further integration. For example it is also applicable to installation variants with deasphalting, the raw input can also exchange heat with some or all effluents from any HDT units from GO, K, VGO, DAO (separately or mixed), and / or any units of HI ~ K, M-HI ~ K, MP-I ~ K of VGO and / or DAO (separately or in mixture), and / or any residual RHDC units. We will also seek to limit storage intermediates (e.g. only hot liquid asphalt), or remove. Likewise, the vacuum distillation will preferably be attached without cooling or distillation storage atmospheric, which will typically perform a summary fractionation simplified.
We can also implement design facilities simplified, using parts common to several units. We can notably choose pressures operating identical or similar for at least part or all of the units under hydrogen pressure such as, possibly: HDT, HDK, M-HDK, MP-HDK, HDC or RHDC of charges GO, K, VGO, DAO, or Residue (separately or in mixture), in order to be able to use a hydrogen loop common for several units (2 or more), i.e. that hydrogen supplies these parallel units, i.e.
that it feeds them in series. This allows to have a common compressor for these units, and a system common purge gas treatment and / or amine wash. As example, we could use an IUT or MI ~ K DAO unit with a hydrogen loop which is common with a VGO MP-HDK unit. You can use a loop supplying these units with parallel, the pressure at the compressor supply being for example around 10 MPa. We can also use hydrogen in series in the two units, the pressures in the reaction zones corresponding being offset by approximately 1 to 3 MPa.
Similarly, a common hydrogen loop can be used, parallel or in series, for units of HDK, for example of VGO, and of hydroconversion of RHDT residue, by example in bed bubbling or slurry, with pressures in the range of about 13 to 18 MPa.
Another type of simplification can result from a mixed treatment, by HDT example of K / GO
/ VGO mixed.
FIG. 6 represents an example of flow of charges and products around a installation (I) for the use of purified deposit gas according to the invention. This installation is powered by a load with three components - a fluid P1 conventional oil with high transportability, supplied typically by boat tanker from a distant area which may be more than 2000 distant km (e.g. imported from one of the countries with a coast in the Arabian Gulf),

29 - P2 oil produced near the installation (I), possibly a heavy, viscous oil, difficult to transport, - a refinery residue Ro, for example from a refinery of REF3 oil from the USA
from America or typically from a European country belonging to the Community European.
The installation (I) can produce refined petroleum products PR1, ..., PRn (in quantity generally relatively limited), for a local or regional market. She also produced according to the invention at least one pre-refined petroleum, in particular such as petroleum P ,,, pre-oil, no waste, of high quality and high recovery, which can be exported to a refinery in REF1 oil, for example from a refinery in the United States of America or typically from a country of Europe belonging to the European Community. Typically, this oil is intended for a refinery wishing to reduce its production of heavy fuel oil. The installation of figure 6 product also PB oil, waste oil, the vacuum residue of which includes asphaltenes and a a sulfur content typically lower than that of the residue of the feedstock departure, usually less than 2% by weight, more preferably than 1% by weight and very preferred to 0.8% by weight. This sulfur content of the vacuum residue of PB is typically greater than 0.52%
weight and for example between 0.52 and 0.75% by weight. Such oil can be exported and find a valuation satisfactory in many refineries, for example a refinery of United States of America or from a European country belonging to the European Community or from a country from South America.
Typically, this oil is intended for a refinery that can find a outlet for heavy fuel oil resulting from its refining.
Advantageously, the oils PA and PB are of composition suitable for a maximum recovery. Through example PA oil, if exported to the European Community, may have a content high in hydrocracking diesel cut (very high number and index of cetane, for example higher or equal to 54), while residual PB oil may, in particular if it is exported to the United States from America, have a lower cetane number or index. Its content kerosene will be advantageously higher than that of PA oil, The installation (I) of FIG. 6 is advantageously located on a site or gas is plentiful and low cost, typically near large gas fields. She may be located in Australia, in Malaysia, Indonesia, or Africa in a country relatively close to the Gulf of Guinea (by for example Angola, Gabon, Nigeria), or Mexico, or a country from South America, or by example chosen in the countries and territories of the group formed by Argentina, Brazil, Colombia, the Venezuela, and the islands located less than 300 km from the mainland coast of these countries for example Trinidad and Tobago. Advantageously, the installation can be located not away from water resources, for example from a river, and withdraw and consume water, which is not often possible in many desert areas in the Middle East (for information only around 4.5 tonnes of water to produce one tonne of hydrogen by steam reforming). She can also, quite easily in the aforementioned countries and territories, be located in an area relatively populated which gives local outlets for certain products (diesel, kerosene, and also butane and propane which are transportable products at relatively high cost.
The aforementioned countries and territories are typically considered by many investors like areas where investment security is good, which makes it possible to obtain interest rates 5 satisfactory for the loans necessary for the construction of a installation according to the invention, which is favorable to the profitability of a project. In addition, the remoteness of the site from installation (I) of large oil reserves of the various countries of the Arab-Persian Gulf erase the differences distance techniques for supplies from these countries, reduces appearance competitive, more important between geographically very close countries, especially in times of 10 oil quotas, and allows access to all the oils of the Middle East equally without favor the oil of a given country, which therefore improves conditions access to a number of more diverse oils. This distance does not cause any disadvantages logistics sensitive of oil transport because these countries and territories mentioned above are very close at least one of the two sea routes: Arabian-Persian Gulf / Europe and Arabian-Persian Gulf / States-United of America which 15 are the paths of the main oil flows worldwide. The different countries or territories aforementioned are, on a world scale, relatively close to the Venezuela, country of which it heavy oil reserves are known to be substantial, or have access to oil reserves own. The installation of an installation according to the invention in one of the aforementioned areas present therefore, very generally, an interest in extended access to oils from 20 large and diversified reserves. Installation of a facility in one of the above areas, which leads to importing oil from a continent, to pre-refine this oil near, or "on its destination" towards one of the major world consumption zones, and re-export pre-refined oil to the major world consumption zones located in other continents therefore has an amazing set of advantages.
The invention can also be implemented with an implantation of treatment facility of hydrocarbons in the country or region of production of crude oils (P1, P2) processed. We can for example treat in one of the following group 1 countries: (Saudi Arabia, United Arab Emirates, Iraq, Iran, Kuwait, Oman, Qatar) one or more crude oils produced in the same country or in one of the countries of the aforementioned group These locations in countries where gas is very abundant allow

30 also easily export a residual oil (PB) to the Extreme-Orient or the outlets for heavy fuel oil are relatively important. We can also treat in Oil alaska produced in Alaska, or for example treat in one of the countries of the following group (Canada, United States from America, Kazakhstan, Mexico, Russia, Venezuela) one or more oils from this same country.
These locations do not penalize by excessive transport costs supply of a residue from the Ro refinery from Europe, for example from one of the Community European, or the United States of America. Indeed it is possible for residues from these country to use an oil tanker with dual use

31 - conventional use of this oil tanker for the transport of crude oil from country A
oil producer to country B oil consumer, - use of the same tanker, typically on the return route, to transport a residue refinery (typically comprising residue from one or more refineries from country B), towards country A or to a country C close to A (for example in the case where A and C
belong to group 1 supra. The installation (I) according to the invention is then typically installed in country A or C, from preferably near a port for discharging the transported residue.
The invention also provides a process for pre-refining a crude oil P1 for the use of gas according to any of the variants described above, and in particular a method comprising:
- an initial fractionation stage of a P1 oil for production in particular of a fraction F, substantially free of asphaltenes and predominantly comprising compounds point boiling above 371 ° C, - a hydrocracking stage of at least most of this fraction F, under pressure total of at least 7 MPa, preferably between 8 and 18 MPa, especially between 9 and 15 MPa, - optionally, but preferably, an incomplete fractionation of hydrocracking effluents (i.e. a fractionation which does not eliminate the entire vacuum diesel no converted included in these effluents), for example not eliminating at least 30%
weight, or at least 40% by weight and typically at least 50% by weight and most often 100% by weight of the vacuum diesel unconverted, or from the boiled fraction at a higher or equal temperature at 371 ° C.
- optionally, the addition to the hydrocracking effluents of at least one fraction of petroleum Pl free of asphaltenes, especially a fraction of middle distillates hydrotreated to form a PA oil substantially free of asphaltenes comprising a cut index diesel cetane greater than or equal to S0.
The invention also relates to any pre-refined petroleum substantially without asphaltenes (PA,), and / or all residual oil (P $,) produced by an installation (I) according to the invention, or by the process according to the invention or according to the use of gas corresponding to any one of variants of the invention previously described.
The invention also relates to any petroleum fraction or refined product.
including at least one fraction from petroleum (PA), or (PB) produced by a facility (I) according to the invention, or by the process according to the invention or according to the use of gas corresponding to one any of the variants of the invention previously described.
The invention also relates to oil produced by the installation (I) and / or a pre-refined PA oil, also produced by (I), and / or a feedstock from a refinery petroleum and / or filler to supply an initial petroleum distillation unit to a petroleum refinery this charge having the following characteristics: (in what follows and until the end of paragraph we call

32 charge, any of the above charges but also a petroleum or refined petroleum (PA) produced by an installation (I) according to the invention, as mentioned above) - API density between 40 and 64, or between 41 and 60, or between 42 and 54, Typically, the flash point of the charge is less than 58, or even less than 56, or at 54, or at 52, or at 50, or at 47, or at 43, or at 40, or even lower, for example less than 37, or at 34, or 31, or possibly at 28 ° C. Obtaining a low flash point is easy in leaving or incorporating into the charge light fractions such as naphtha in sufficient quantity.
The initial point (ASTM) of the load is typically less than 150 ° C, especially below 130 ° C, or 110 ° C, or 90 ° C, or 70 ° C, and can be below 60 ° C, or even below 50 ° C. Point final (ASTM) of the load is often above 350 ° C, usually higher than 362 ° C, by example higher than 373 ° C, in particular 385 ° C, and typically higher than 395 ° C, or even higher than 405 ° C, and even at 420 ° C.
The 10% distilled percentage (ASTM) of the charge can for example be between 50 and 110 ° C, or between 30 and 90 ° C, or between 70 and 170 ° C; The percentage distilled 90%
distilled (ASTM) can for example be greater than 305 ° C, especially greater than 315 ° C, or greater than 325 ° C, or even between 340 and 550 ° C, or between 300 and 500 ° C, or between 373 and 580 ° C.
The percentage distilled at 285 ° C can by example be less than 76%, or 70%.
Getting a higher or lower starting or ending point is easy for humans of the trade, by incorporating more or less significant quantities of light and / or heavy naphtha and modulating, for the end point, the quantity of vacuum diesel fuel left in PA. Amounts of naphtha can be increased if necessary by carrying out a more severe vacuum diesel hydrocracking. of the excess fractions can be incorporated into another petroleum, PB, produced according to the invention.
Likewise the person of the trade knows how to adapt distilled percentages, by incorporating or eliminating appropriate cuts.
- Sulfur content between 4 ppm by weight and 1% by weight or between 4 ppm weight and 0.5% weight or between 4 and 800 ppm weight, in particular between: 4 and 700 ppm, or 4 and 600 ppm, or 4 and 500 ppm, or 4 and 400 ppm, or 4 and 300 ppm, or 4 and 200 ppm or 4 and 100 ppm, or 4 and 50 ppm, or 4 and 30 ppm, or 4 and 10 ppm, or between: 50 and 800 ppm by weight, in particular between 50 and 700 ppm, or 50 and 600 ppm, or 50 and 500 ppm, or 50 and 400 ppm, or 50 and 300 ppm, or 50 and 200 ppm or 50 and 100 ppm, or between:
100 and 800 ppm weight, in particular between: 4 and 700 ppm, or 4 and 600 ppm, or 4 and 500 ppm, or 4 and 400 ppm, or 4 and 300 ppm, or 4 and 200 ppm.
Typically, this charge may include an asphaltene level below 0.5% by weight or less than 0.1% by weight, or less than 0.05% by weight, or less than 300 ppm weight, or less than 200 ppm weight, or less than 100 ppm weight, or less than 50 ppm weight, or less than 30 ppm weight, or less than 20 ppm weight, or less than 12 ppm weight, or less than 8 ppm weight, or less than 5 or less than 3 ppm by weight, or less than 2 ppm by weight, or less than 1 ppm weight.

33 The atomic H / C ratio of these asphaltenes can be understood in particular between 0.96 and 1.2, or between between 1.0 and 1.2, or between 1.03 and 1.15. The% sulfur weight of these asphaltenes can be greater than that of the load by a factor greater than 6, or 10, or 15, or 15, or 20 see more.
This charge may also include a diesel fraction of cetane number between 45 and 70, or between 52 and 70, or between 53 and 70, or between 54 and 70. This charge can also understand a diesel fraction of number of cetane between 47 and 73, or between 49 and 73, or between 50 and 73, or between 51 and 73, or between 52 and 73, or between 53 and 73, or between 54 and 73, or between 55 and 73. She can also include a diesel fraction with an aromatics rate in%
weight, or a% weight of aromatic carbon between 2 and 35%, or between 2 and 25%, or between 2 and 15%, or between 2 and 12 %, or between 2 and 8% by weight. The sulfur content of this diesel fraction can be between 2 ppm weight and 1% weight, or between 2 ppm and 0.5% weight, or between 2 ppm and 0.3%
weight, or between 2 ppm and 0.1% by weight, or between 2 ppm and 500 ppm, or between 2 and 300 ppm, or between 2 and 200 ppm or between 2 and 150 ppm or between 2 and 100 ppm, or between 2 and 70 ppm, or between 2 and 40 ppm, or between 2 and 25 ppm, or between 2 and 15 ppm, or between 2 and 10 ppm.
This charge can also include a fraction boiling above 343 ° C or 371 ° C, either of these fractions may have a density of less than 0.900, or less than 0.890, or less than 0.880, or less than 0.870, or less than 0.865, or less than 0.86, and generally greater than 0.840. The aromatic content in% by weight, or the% weight of carbon aromatic of one either of these fractions can be between 2 and 25%, or between 2 and 20%, or between 2 and 15%, or between 2 and 12%, or between 2 and 8% by weight. The sulfur content of one or the other of these fractions can be between 2 ppm weight and 1% weight, or between 2 ppm and 0.5% weight, or between 2 ppm and 0.3%
weight, or between 2 ppm and 0.1% weight, or between 2 ppm and 500 ppm, or between 2 and 300 ppm, or between 2 and 200 ppm or between 2 and 150 ppm or between 2 and 100 ppm, or between 2 and 70 ppm, or between 2 and 40 ppm, or between 2 and 25 ppm, or between 2 and 15 ppm, or between 2 and 10 ppm.
The content of the charge in (nickel + vanadium) may for example be lower at 50 ppm weight, or ppm, or at 20 ppm, or at 10 ppm, or typically less than 5 ppm, in particular at 3 ppm, and often 2 ppm and even 1 ppm weight.
The content of the fraction of the charge boiling above 565 ° C in (nickel + vanadium) can be for example less than 20 ppm by weight, or less than 10 ppm, or typically less at 5 ppm, especially at 30 3 ppm, and often 2 ppm and even 1 ppm by weight.
Typically, the% weight of olefins in the charge is less than 4% and generally less than 1%.
The Research octane number is typically less than 82, and even less than 78 and generally less than 75.
Obtaining such properties, usable jointly when they do not are not contradictory, can be done by processing an oil such as light arabic, which is conventional and fluid and low point according to the invention, by separate hydrotreating of naphtha, kerosene mixed with the

34 cutting diesel and diesel, and by performing a high pressure hydrocracking of the diesel under vacuum. The residue can be treated by hydrotreatment and incorporated into PB petroleum. We can get:
- high index diesel cuts or cetane number by making a advanced hydrotreatment of the direct distillation cut (low VVH, high pressure) ed or by performing more hydrocracking high pressure and conversion of diesel under vacuum. The intensification of these operations also reduces the sulfur. The person skilled in the art can easily modify the different parameters by playing on several factors - the possibility of eliminating certain cuts in the form of refined products, or incorporated into another PB oil.
- intensification or moderation of hydrotreatment operations and / or hydrocracking - the percentage of charge supplied for these operations, - bypassing by part of the load, untreated. This can particular simulate some pollution during a transfer of the oil produced, by traces of other less pure products.
The different elements described in this description: variants, selection of oils, choice of parameters and properties of products etc ... can possibly be combined together and put implemented according to the invention; Any combination of these elements therefore part of this request.
Definitions and conventions according to the invention / Properties - By a ~ deposit, we mean any hydrocarbon gas from one or more deposits, the production being carried out on land and / or at sea. Field gases include gases from deposits of natural gas, gas associated with petroleum, so-called "gas condensas "(including, in addition gaseous hydrocarbons, light liquid hydrocarbons and traces more hydrocarbons heavy) and their mixtures, and generally any gas from deposits) underground) and / or submarines) including significant amounts of methane.
Such gases typically also include 2, 3 or 4 hydrocarbons carbon atoms, and generally small amounts of higher hydrocarbons from 5 to 20 carbon atoms or even more. They often include non-hydrocarbon compounds such as N2, COZ, HZS and sometimes rare gases. The use of deposit gases for the production of hydrogen therefore requires in the g majority of cases prior purification of the gas to remove the compounds undesirable. The gas purification may include, for example, washing steps amines, dehydration, degassing.
Field gases are abundant in many parts of the world, and especially in regions far from the major gas consumption areas of Europe, United States from America except Alaska, and Japan.

By gas production region is meant the region around one or more gas fields used according to the invention, after purification, such as any point in the region is located at most 1200 km a deposit or a set of deposits from which at least 70% by weight comes purified gas used according to the invention. Typically, at least 90% by weight and often the entire gas is produced unless 5 of 1200 km from the installation (I), generally less than 1000 km and even less than 500 or typically km.
- A pre-refined oil (PA) or a residual oil (PRS, produced according to one of the variants of the invention is, according to the invention a complex mixture of hydrocarbons derived of an installation of treatment of hydrocarbons (I) according to the invention, this mixture being so feature intended for 10 be processed in one (or more) oil refineries, as feed at least one unit of initial petroleum distillation (often called atmospheric distillation petroleum).
The pre-purified petroleum (P ,,) comprises, according to the invention, compounds which have been hydrotreated etlou hydroconverted and / or hydrocracked by any one of the variants of the invention of the installation treatment of hydrocarbons according to the invention. Oil (P $) can possibly be an oil Free of the above compounds, e.g. reconstituted petroleum including a rate residue of asphaltenes increased. Generally, (PB) is also a pre-refined petroleum in the specified sense previously.
According to the invention, an oil (P "or PB) produced according to the invention is a "final product of the installation treatment of hydrocarbons (I) ", not an intermediate product circulating inside for example 20 from an oil refinery. It is intended to be refined, in one or several oil refineries, conventionally separate from the site of the installation of treatment of hydrocarbons (I) at least 100 km (distance (s) evaluated) taking the smallest distance between on the one hand initial oil distillation unit of the refinery concerned, and on the other hand a unit of treatment in the presence of hydrogen: HDT, HDC, HDK or other, of the installation treatment 25 of hydrocarbons). Often the oil (s) produced (PA and / or PB) are intended to be for a at least refined parts at very large distances such as 2000 km or more, especially on a other continent, and transported by oil tanker, in particular by boat very large tanker tonnage such as at least 150,000 tonnes deadweight, typically in a category of boat carrier of petroleum, or crude petroleum, according to the classification of a classification society such 30 that Bureau Véritas (France) or the "American Bureau of Shipping) (Bureau American Navigation).
An oil (PA and / or PB) produced according to the invention is also a product prepared for the purpose of a regular production and marketing and not such a product that a product transferred very occasionally, for example a refined product temporarily outside specifications, or a product

35 temporary during shutdowns of certain units in an oil refinery. he is therefore typically a normal feedstock for a distillation oil initial in a petroleum refinery, this type of feed being typically treated by campaigns.

36 Typically, it is not classified as a refined petroleum product, in the sense petroleum products conventional refiners of the group formed by (liquefied petroleum gases, gasolines, solvents, aviation fuels such as kerosene, kerosene, diesel fuel, fuel oil domestic, possibly called heating oil, fuel oil for boats, light fuel oils, heavy fuel oils, lubricating oils, bitumens and fluxed bitumens), and this typically according to the classification of a refinery refining this oil, edou according to the administrative classification of the country where is located (I), or that of a country or is discharged this oil to be refined, and / or the customs classification of the country where is located (I), and / or that of a country or is discharged this oil for to be refined. On the contrary, an oil according to the invention is typically classified, according to at least one, or any of them, or each of these authorities, as petroleum, or crude oil, or petroleum synthetic, or pre-refined petroleum, possibly "syncrude", translated from English by gross synthetic, this type of classification explaining its destination.
An oil produced according to the invention generally comprises at least three cuts, often four cuts or even five cuts of the group formed by: light naphtha, naphtha heavy, kerosene, gas oil, vacuum gas oil, in which, conventionally, according to the invention, we designate necks or fractions of a hydrocarbon or petroleum charge by their interval true distillation (TBP), lower bound included, upper bound not included, and in which light naphtha denotes the cut between 28 ° C and 71 ° C, heavy naphtha denotes the cuts between 71 ° C and 160 ° C, the kerosene means cutting between 165 ° C and 282 ° C diesel means cutting between 282 ° C and 343 ° C on diesel means the cut between 343 ° C and 371 ° C, diesel under vacuum designates the section between 371 ° C and 565 ° C, and the vacuum residue cuts it boiling at a temperature greater than or equal to 565 ° C.
Typically an oil according to the invention comprises at least 1.5% and often at minus 3% of its total weight in at least 3, 4, or S of these cuts. Often a PA oil can have 2 to 15% weight light naphtha (or 3 to 12%), S to 20% heavy naphtha (or 6 to 17%), from 6 to 24% of kerosene (or 8 to 21%), 4 to 20% diesel cut or (6 to 17%), 1.5 10% diesel, and 2 to 28% diesel under vacuum and residue substantially free of asphaltenes).
This definition of sections or fractions is applicable for the calculation of properties of fractions of a complex mixture, such as sulfur content, cetane number, rate asphaltenes etc ...
The sections described in the description of the variants and figures are fractionation cuts much less sharp, and can for example be defined by values ASTM temperatures from the initial and final point, and can have a fairly coarse fractionation.
A conventional fluid oil is according to the invention a petroleum having an API density of at least 25, - a viscosity at 2 ° C lower than 230 cs (centistokes), and at 15 ° C below 80 cs, - a pour point below 0 ° C.

37 This definition is restrictive. It is possible to pump products with a viscosity of 1000 cs or more.
This definition is for example more restrictive than the conditions mentioned in the work of reference: "upgrading petroleum residues and heavy oils" which means:
improve residue quality oil and heavy oils, by Murray R. Gray, publisher Marcel Dekker inc.
New York, page 37 lines 6 to 13 which mentions a condition to be able to transport by pipeline and sell products on the free market which is: lower viscosity or equal to around 250 cs at 2-3 ° C, or at around 100 cs at 15 ° C.
Typically the viscosities of a conventional fluid crude according to the invention are, to others temperatures: below 35 cs at 38 ° C, and below 20 cs at 99 ° C. Generally, petroleum conventional fluid selected will have even lower viscosities, namely:
less than (150 cs, 65 cs, 50 cs, 32 cs, 15 cs) respectively at (2 ° C, 15 ° C, 21 ° C,

38 ° C, 99 ° C), or even less than (120 cs, 50 cs, 35 cs, 20 cs, 10 cs) for the same temperatures.
Heavy crudes have, according to a commonly accepted definition, and indicated like a classification recognized in the aforementioned reference work ("upgrading ..."), page 2, an API density between 10 and 20. They also have a significantly higher viscosity high as the values mentioned above, making transport very difficult without thinner, or even impossible.
Typically, the selected conventional conventional oils include minus 20% by weight, often at least 24% by weight, or even 26% by weight of temperature compounds boiling less than 325 ° C. Their vacuum residue typically represents less 36% by weight, often less than 34% by weight, in particular less than 32% by weight relative to petroleum whole conventional.
According to the invention, when selecting a fluid conventional oil, we typically chooses a petroleum whose characteristics (viscosity and pour point) allow to transport it easily in its production region, in particular in pipelines conventional no heated. Conventional fluid oil can therefore be transported by conventional means, without using the known process for transporting heavy oils: 1 ' use of a dilution separation of the diluent on arrival of the pipeline / recycling of the thinner which can therefore be avoided.
A conventional fluid oil according to the invention is therefore chosen, depending on of the installation site of treatment, to be easily transportable. Generally, petroleum conventional fluid is produced from an underwater or terrestrial deposit, often at a point altitude less than 1000 m, and routed to the treatment facility (I) which is typically located on a terrestrial site, often distant by several km, often by several tens of km, and sometimes by several hundred km.
The choice according to a preferred variant of the invention of a transportable oil is therefore important for limit investments. Often we choose an oil that has already been transported by pipelines conventional for at least 10 km for 2 years or more, for which it is so known that he is transportable.

Conventionally, according to the invention, a treatment with carbon residue is a treatment comprising - either a step of coking a residue in a fluidized bed or in a chamber, producing solid coke, - or a process comprising a pyrolysis of residue on a solid not organic, at temperature high above 500 ° C, forming coke, on this solid, this coke being typically burned, - either a process producing asphalt by deasphalting of residue, a at least part of this asphalt being fed to a partial oxidation unit for production hydrogen, or burnt or discharged as asphalt, i.e. without being incorporated into a oil or fuel oil.
According to the invention, it is possible to use carbon rejection, for example less of 10% weight of the charge of (I). But typically, we don't use much rejection of carbon, that is, conventionally, less than 2% weight of the load, and preferably none carbon release.
Conventionally, according to the invention, the liquid yield of the treatment performed, the report the mass of the compounds of the hydrocarbon charge having at least 3 atoms of carbon, on the mass of the compounds included in the hydrocarbon liquids produced by installation (I), having also at least 3 carbon atoms. This ratio is calculated excluding the sulfur content of the load and products of (installation.
According to a preferred variant of the invention, excluding the gasification and the burning of asphalt and asphalt disposal, as well as all coke-forming processes, liquid returns can according to the invention reach at least 96% by weight, or at least 97% by weight minus 98% by weight or at minus 99% by weight, or even at least 100%, if more hydrogen is incorporated that we don't lose light compounds (methane + ethane). The use of catalysts macroscopic supported, such as described above (rather than liquid catalytic additives or slurry) typically allows to limit, for hydrocracking and hydroconversion operations, residues gas production (methane ethane at less than 0.8% by weight for each step, and even less than 0.6 % weight. Of preferably we also limit the conversion of products boiling above 565 ° C (for example at less than 70% by weight, or less than 65% by weight, or less than 60% by weight). The conversion level is typically chosen so that the unconverted residue (boiling over 565 ° C) is stable in the petroleum produced, for example PB. We can use a stability test such as hot filtration test from SHELL, or another known test for the stability of fuel oils or residues.
The liquids produced by an installation (I) according to the invention comprise one or more oils PA, PB, but also possible refined products such as naphtha, or fuel oil, or kerosene.
Typically, refined products can represent cumulatively between 0 and 92% weight by compared to all the liquid products from the installation (I), in particular between 0 and 85% by weight, generally between 0 and 75% by weight, or between 0 and 60% by weight, for example between 0 and 50% by weight, often between 0 and 30% by weight, preferably between 0 and 20% by weight, and so highly preferred, less than 10% by weight and in particular 0% (no refined products).

39 Pre-refined oil can be shipped to one or more refineries in petroleum, usually alone, or mixed with other natural or synthetic oils.
The different parameters characterizing properties of an oil or a refined product or a petroleum fraction can be measured by a person skilled in the art specialized in analyzes according to the the most appropriate method. he can also use or select one following methods insofar as it is adapted to the measurement of the parameter concerned, either directly, either by diluting the product, or possibly using additional techniques allowing to use one of these methods. If one of the methods described is not suitable, or if several methods are possible and give different results, the analysis man can select the ASTM method corresponding to the specifications of the product concerned, or the most appropriate.
ASTM is the "American Society for Testing and Materials"
Tests and Materials).
Measuring method Others) methods) Measured variable normalized usable normalized usable according to according the invention the invention or method quivalente Sulfur content: 1P 61/99 1P 336/95 petroleum, residual, VGO IP 242/83 Sulfur content: Diesel / diesel / V60IP 243/94 ISO 4260: 1987 after I-IDT or 1-IDC or HDK

Kinematic viscosity (petroleum) IP 71, section 1 / 97D 445-97 Density (g / cm ') and density ASTM D 1298-85 API

Connection point (oil) IP 15/95 D 97-96a Ctane index (dieseUgasoil) IP 380/98 ISO 4264: 1995 ASTM D 4737-96a Number of ctane (diesel / diesel) IP 41/99 ASTM D 613-95 ASTM distillation (point ASTM D 86 initial, final and % distills) Vapor pressure REID D 323 Asphalt content IP 143/01 ASTM D 6560 Metal content Ni + V IP 433/2000 IP 285/79 Hydrogen content D 1018 Aromatic content or IP 391/01 1P 392 carbon aromatic Pntrabilit needle ASTM DS

Pressure distillation ASTM D1189 with reduced Clear point, if> 40 ASTM D 93 D 56 Clear point, if <40 IP 170/99 D 56

Claims (14)

1. Use, in a gas production region, of a purified field gas G
in which:
a) converting at least a fraction G1 of this gas G, to obtain a current hydrogen (H2) b) selecting and supplying, by pipeline and / or oil tanker, crude oil conventional P1 fluid and pour point less than or equal to 10 ° C, c) in an installation (I) for processing hydrocarbons, a charge processing of hydrocarbons comprising petroleum P1, alone or mixed with others fractions, the treatment of this oil P1 being carried out substantially without rejection of carbon, and including at minus one hydrotreatment step (HDT, RHDT) or hydroconversion (HDC, RHDC) or hydrocracking (HDK) of at least a fraction of the oil P1, this fraction comprising mainly compounds with a boiling point above 343 ° C, this step using a at least fraction of the current H2, to produce at least one pre-refined oil PA including compounds from this stage, this PA oil being intended to be refined in a refinery separate and distant from the installation (I). 2. Use of gas according to claim 1, wherein petroleum selected P1 has a rate asphaltenes less than 3.3% by weight, or includes a vacuum residue of rate asphaltenes less than 11% by weight. 3. Use of gas according to one of claims 1 and 2, wherein the P1 oil processing includes:
an initial step comprising a fractionation, to obtain a fraction F
sensibly free of asphaltenes and predominantly comprising point compounds boiling higher than 371 ° C, - at least one hydroconversion (HDC) or hydrocracking (HDK) stage of a party at less than fraction F, with conversion of the boiling point compounds better than 371 ° C at least equal to 42% by weight, 4. Use of gas according to claim 3, comprising a step hydrocracking (HDK) at least part of said fraction F, with conversion of the compounds point boiling above 371 ° C between 42 and 95% by weight. 5. Use of gas according to claim 4, in which one chooses a pressure of sufficient hydrocracking, and / or incorporated into the component fractions oil pre-refined PA a sufficient fraction of the hydrocracking effluents, and eventually we incorporates a direct distillation diesel fraction into PA petroleum from P1, after hydrotreating (HDT) at sufficient pressure, so that the petroleum prewashed PA
includes a diesel fraction with a cetane number of at least 50. 6. Use of gas according to one of the preceding claims, in which installation (I) produces at least two separate oils PA and PB intended to be sent separately to one or several petroleum refineries. 7. Use of gas according to claim 6, wherein the PA oil includes a residue under vacuum of sulfur content less than or equal to 1% by weight and PB oil includes a residue under vacuum with sulfur content greater than 1.25% by weight. 8. Use of gas according to claim 6, wherein the PA oil is substantially free of asphaltenes, the fraction of PA oil boiling temperature greater than or equal to 371 ° C
being either absent or with a sulfur content of less than 0.4% by weight, and the PB oil includes a vacuum residue with sulfur content greater than or equal to 1.25% by weight. 9. Use of gas according to one of the preceding claims, in which charge of the installation (I) comprises a residue from a refinery distant from the installation (I), this residue comprising at least a fraction of vacuum distillation residue direct and preferably fractions (LCO, HCO) from a catalytic cracking unit fluid (FCC), and optionally a thinner. 10. Method for pre-refining a crude oil P1 for the use of gas according to one of previous claims, comprising:
- an initial fractionation stage of P1 oil for production including a fraction F, substantially free of asphaltenes and mainly comprising point compounds boiling above 371 ° C, - a hydrocracking stage of at least most of this fraction F, under a total pressure of at least 7 MPa, - optionally, an incomplete fractionation of the hydrocracking effluents, - optionally, the addition to the hydrocracking effluents of at least one fraction of oil P1 free of asphaltenes, especially a fraction of middle distillates hydrotreated, for form a PA oil substantially without asphaltenes comprising a cut index diesel cetane greater than or equal to 50. 11. Installation (I) for the use of gas according to one of claims 1 to 9 or for the process according to claim 10, comprising a line (1) supplying a crude oil P1 connected to a fractionation unit (100), a line (8) for circulation of a section including vacuum diesel, connecting the fractionation unit (100) to a unit (300) hydrocracking type without complete fractionation of unconverted vacuum diesel, at least one line (6.7) connecting the fractionation unit (100) to a hydrotreating unit (200) of a charge mainly comprising middle distillates, at least one line (2011205, 203/205) connecting the hydrotreating unit (200) to an evacuation line (301) effluent hydrocracking itself connected to the hydrocracking unit (300), optionally a line connecting the fractionation unit (100) to the evacuation line (301) hydrocracking effluents, for the production of pre-refined PA oil, also comprising a installation (400) of residue treatment, connected upstream to the fractionation unit (100), and downstream to a line (403) evacuation of a treated residue, this line being optionally connected to the unit of fractionation (100) by a line (16), or to the hydrotreatment unit (200) by a line (201/205 / 206,203 / 205/206), for the production of PB residual oil, and comprising a line (503) connecting a hydrogen production unit (500) from gas of a refined deposit supplied by a line (501), to the hydrocracking unit (300), and a line (502) connecting the hydrogen production unit (500) to the unit hydrotreatment (200), 12. Pre-refined petroleum without asphaltenes (P A.) produced by the installation (I) according to claim 10, or by the process according to claim 9, or for the use of gases according to one of claims 1 to 8. 13. Waste oil (P B.) produced by the installation (I) according to the claim 11, or by the method according to claim 10, or for the use of gas according to one of claims 1 at 9. 14. Petroleum fraction or refined product comprising at least one fraction from petroleum (PA), or (PB) according to one of claims 12 and 13.