Patent Application
20090308788
The present invention relates to the oil industry and to the use of sulphur-containing heavy refinery residues. Oil is traditionally treated in the oil refinery by a set of fractionation and chemical conversion operations to produce a set of final commercial products satisfying well defined standards or specifications, for example distillation ranges, sulphur contents, or characteristic technical indices such as the octane number or diesel number, etc.
The principal final commercial products are petrochemical naphtha, gasoline, kerosene, gas oil (also termed diesel fuel), domestic fuel, and other categories of fuel with greater or lesser sulphur contents, road asphalt, liquefied petroleum gas, and sometimes other products: lubricating oils, solvents, paraffin, gas turbine fuel, etc. An oil refinery product thus produces a relatively large number of final commercial products from a certain number of crude oils, selected as a function of their composition and their price.
Changes in markets, particularly increasing competition from natural gas, and specifications regarding discharges from burning facilities (discharge of oxides of sulphur, oxides of nitrogen, solid particles, in particular in Europe) has led to a sharp reduction in the markets for sulphur-containing heavy fuels, for example heavy fuel containing at most 3.5% or 4% of sulphur. Thus, refiners are confronted with a major technical problem, namely that of using sulphur-containing refinery residues, while satisfying regulatory requirements. Such sulphur-containing fuels are typically excessive and many states are tending to limit the sulphur in fuels to 1% of sulphur and in future to 0.5% or even 0.3%.
A further tendency in the use of oil products is a tendency to increase the consumption of middle distillates and gasoline to the detriment of fuel, the increase in the consumption of middle distillates tending to be greater than that of gasoline.
The invention concerns a process for pre-refining oil, typically in the production region, to improve the quality of the oil in the face of market changes.
The Applicant's French patent application FR-04/02.088 already proposes the use of a field gas, which is typically cheap, to pre-refine a conventional oil and typically produce an oil Pa with a low sulphur content substantially free of asphaltenes, and also a residual oil Pb (comprising the starting asphaltenes, partially converted by a hydrogenating treatment). After refining, the oil Pa produced shall produce very little or no sulphur-containing fuel, and may have a high middle distillate content, market demand for which is increasing. This is a high quality oil. The oil Pb typically comprises inferior quality fractions, in particular residual asphaltenes.
The corresponding process is a process for pre-refining crude oil, i.e. a process producing pre-refined oils Pa, Pb (with improved quality, at least for Pa) as final products. These (pre-refined) oils are typically sold, evacuated and transferred to oil refineries. The pre-refining process also envisages possible co-production of final commercial oil products: naphtha, gas oil, etc.
That prior art process thus produces a high quality oil Pa demanded by the market. However, there is still a need for a further improvement to market matching and for high quality oil, to satisfy market demands and to further upgrade the proposed product.
The invention proposes a process for pre-refining crude oil, generally conventional, which can produce not two, but at least three pre-refined oils Pa, Pb and Pc, wherein two (Pa and Pb) are high quality oils, substantially free of asphaltenes which, after refining, will produce a plurality of high value products (naptha, gasoline, middle distillates). In contrast, Pc is an oil having a residue containing asphaltenes, and after refining will produce large quantities of fuel.
According to an essential characteristic of the invention, the two oils Pa and Pb have different relative potentials as regards the balance (naphtha+gasoline/middle distillates) after conventional refining. Thus, a given refinery will stock itself not only with its fuel needs (by using oil Pc), but also by modulating the distribution of its stocks of oils Pa and Pb to perfectly match itself to its own market and in particular to the (naphtha+gasoline)/middle distillates balance. A refinery principally located close to urban areas will not have exactly the same gasoline/diesel distribution as a refinery located in a rural area. There will also be differences for a refinery located close to a petrochemicals complex containing naphtha or for a refinery located close to a mountainous zone (increased consumption of domestic fuel because the climate is colder). Thus, the invention can finely tune each refinery to the market. Thus, by introducing a market adjustment means, it provides better access to this market and thus better upgrading of the proposed high quality oils Pa and Pb.
This efficient fine tuning means is decoupled from fuel production, essentially linked to the use of residual oil Pc. Thus, the naphtha+gasoline/middle distillates balance may be adjusted independently of fuel production.
The invention proposes an oil pre-refining process which, from a crude oil P (or several oils P1, P2, etc), can produce at least 3 pre-refined oils Pa, Pb, Pc. Pa and Pb are typically high quality oils, i.e. oils substantially free of asphaltenes. The process may also possibly produce more than 3 pre-refined oils, for example 3 asphaltene-free oils. It may also produce 2 or 3 residual oils (containing asphaltenes), or more. The scope of the present invention does not exclude the process from co-producing final or refined products: fuel, naptha, kerosene, gas oil, domestic fuel, oils or oil bases, etc.
The crude oil(s) P is/are typically conventional, but it is also possible to use any type of crude oil, conventional, heavy, asphaltenic, and in particular any oil with an API of 5 to 50.
The process uses fractionation of oil P by at least initial distillation (termed “atmospheric”) and generally a vacuum distillation. The initial distillation preferably separates it into at least two fractions, one being relatively richer in middle distillates and the other being relatively richer in naphtha (or at least having different naphtha/middle distillate ratios).
The process also typically comprises at least one hydrotreatment unit HDT or a conversion unit, in particular vacuum distillate hydrocracking VGO. It usually comprises a vacuum residue deasphalting unit and a unit for hydrotreatment and/or hydrocracking of the deasphalted oil DAO produced. Finally, it generally comprises a unit RHDC for hydroconversion of residues.
In accordance with an essential characteristic of the invention, the fractionations, unit conversions and distribution of components Pa and Pb are determined so that Pa is relatively rich in gasoline and naphtha precursors, and relatively poor in middle distillates: kerosene and diesel cut while Pb, in contrast, is an oil which is relatively poor in gasoline and naphtha precursors and relatively rich in middle distillates.
An oil which is substantially free of asphaltenes can be characterized by the ratio:
R=(0.9N+0.5VGO+)/(MD+0.1VGO+), in which:
N=naphtha: % by weight of cut boiling (TBP distillation) between 30° C. and 170° C.;
MD=middle distillates: % by weight of cut boiling above 170° C. and at most at 360° C.;
VGO+=% by weight of fraction boiling above 360° C. It should be noted that, with oils Pa and Pb, VGO+ denotes fractions (typically hydrotreated or hydrocracked) of unconverted VGO and DAO, which are non asphaltenic (substantially free of asphaltenes).
If the yields obtained by conventional oil refining are examined, the following can be established:
As a result, the ratio R characterizes the gasoline potential with respect to the middle distillates potential: an oil with a high ratio R will produce relatively more gasoline, while an oil with a low ratio R will produce relatively more middle distillates.
Typically, according to the invention, the ratio Ra for oil Pa is higher than the ratio Rb for the oil Pb. This may readily be obtained, for example by incorporating relatively more naphtha N and/or unconverted VGO into Pa than into Pb, and in contrast by incorporating more middle distillates MD into Pb than into Pa. Decomposition of the initial oil into fractions having different naphtha, middle distillates and VGO+ contents can in fact allow ready re-composition to enrich one or the other of the oils Pa, Pb in middle distillates or gasoline precursors. For effluents from conversion units, the conversion can be adapted and/or the VGO+ content of the effluents can be measured (by distillation, chromatographic analysis, etc), to determine their naphtha, middle distillates and VGO+ contents, to produce the desired re-composition of Pa and Pb.
In general, the invention proposes a process for pre-refining at least one crude oil P with catalytic hydrogenating treatment of one or more cuts derived from P, comprising:
R=(0.9N+0.5VGO+)/(MD+0.1VGO+), in which:
N=naphtha: % by weight of cut boiling between 30° C. and 170° C. (for example N=25 if there is 25% by weight of naphtha in the effluent or the hydrocarbon stream under consideration);
MD=middle distillates: % by weight of cut boiling above 170° C. and at most at 360° C.;
Typically, Pa and Pb are essentially formed from fractions derived from the following group of cuts derived from P, optionally hydrotreated and/or hydroconverted and/or hydrocracked: naphtha N, middle distillates MD, intermediate gas oil IGO, light LVGO, heavy HVGO or total VGO vacuum distillate, deasphalted oil DAO, with respective TBP distillation intervals:
N: [30° C./170° C.]; MD: [170° C./360° C.]; IGO: [340° C./420° C.]; LVGO: [360° C./450° C.]; HVGO: [450° C./565° C.]; VGO: [360° C./565° C.]; DAO: >565° C.
Since fractionation is not perfect, the scope of the invention encompasses the cuts cited above being composed, for example, of at least 50% by weight of compounds in the respective distillation ranges mentioned:
Typically, 1.10<Ra/Rb<4.5. Usually, 1.15<Ra/Rb<4. Preferably, 1.3<Ra/Rb<3. More preferably, 1.4<Ra/Rb<2.5.
In general, 0.7<Ra<2.0. Usually, 0.8<Ra<1.7. Preferably, 1.3<Ra<3. More preferably, 1.4<Ra/Rb<2.5.
Preferably, 1.0<Ra<1.5 and 0.35<Rb<0.9.
In general, 0.8<Ra<1.7 and 0.3<Rb<1.0.
Preferably, Pc comprises at least the major portion of the effluent from ebullated bed hydroconversion, RHDC, of R2.
In a variation of the invention, R2 is a vacuum distillate VGO.
In a further variation of the invention, R2 is asphalt AS obtained by solvent deasphalting SDA. In this case, AS is usually ebullated bed hydroconverted, supplemented with a liquid diluent DIL comprising at least 30% by weight of compounds boiling below 340° C.
Typically, the quantity of diluent is in the range 4% to 40% by weight of AS, preferably in the range 5% to 30% by weight of AS, and highly preferably, between 6% and 25% by weight of AS.
DIL generally comprises 3% to 25% by weight, preferably 4% to 20% by weight of AS, and more preferably between 5% and 15% by weight of fractions boiling at more than 360° C.
The solvent used for deasphalting is preferably relatively heavy (in particular heavier than propane) and thus produces an asphalt which is concentrated in asphaltenes. Suitable solvents comprise all principally paraffinic hydrocarbons (possibly olefinic) containing 3 to 7 carbon atoms. However, highly preferably, they comprise propane-butane mixtures, butane, pentane, hexane, heptane, light gasoline and mixtures obtained from the solvents cited above. Preferred solvents comprise butane, pentane, hexane and mixtures thereof. Highly preferred solvents comprise butane, pentane and mixtures thereof.
The solvent deasphalting operation SDA may be operated under conventional conditions: reference should be made to the article by BILLON et al published in 1994 in volume 49, No 5 of the review by the Institut Français du Pétrole, pp 495-507, in the book “Raffinage et conversion des produits lourds du pétrole” [Refining and converting heavy oil products] by J F Le Page, S G Chatila and M Davidson, TECHNIP publications, pp 17-32, or to the description given in FR-B-2 480 773 or in FR-B-2 681 871 or in U.S. Pat. No. 4,715,946. Deasphalting may in particular be carried out at a temperature in the range 60° C. to 250° C. with one of the solvents cited above, optionally supplemented with an additive. The solvents used and the additives are in particular described in the documents cited above and in the following patent documents: U.S. Pat. No. 1,948,296; U.S. Pat. No. 2,081,473; U.S. Pat. No. 2,587,643; U.S. Pat. No. 2,882,219; U.S. Pat. No. 3,278,415 and U.S. Pat. No. 3,331,394. The solvent may be recovered by vaporization or distillation, or by an opticritical process, i.e. under supercritical conditions. Deasphalting may be carried out in a mixer-decanter or in an extraction column.
In another variation of the invention, the asphalt is not converted: untreated asphalt AS is directly mixed with one or more oil fractions, typically derived from P, to form the oil Pc, the vacuum residue of which then contains virgin asphaltenes in an increased quantity compared with the vacuum residue of oil P. Typically, said oil fractions comprise at least one fraction of crude oil which is mixed with AS.
In a variation of the invention, Pa, Pb and Pc are formed so that the percentage of compounds boiling between 360° C. and 400° C. with respect to the fraction VGO is lower for Pb than for P, as well as for at least one of oils Pa, Pc. As an example, after hydrotreatment or mild hydrocracking, an IGO or LVGO fraction is preferably orientated towards Pa and/or Pc rather than towards Pa. It is also possible for IGO or LVGO to be converted by more than 50% or more than 70% to supply more effluent to Pa and/or Pc. This relative depletion of Pb in compounds boiling between 360° C. and 400° C. means that middle distillates can be distilled more easily from Pb (MD/VGO fractionation) and thus larger quantities of middle distillates MD can be incorporated into Pb without causing a problem when refining Pb at the initial distillation stage.
In accordance with the invention, Pa, Pb and Pc are three oils, final products from the pre-refining process, each intended to be used as an initial distillation feed for one or typically more oil refineries.
Pa, Pb and Pc are final oils from the pre-refining process, which are conventional oil refinery feeds and not final products or intermediate refining products, or final products intended for a particular straight run distillation. They each typically comprise at least 6% by weight of naphtha N, at least 10% by weight of middle distillates MD (for example at least 4% by weight of kerosene [170° C./250° C.] and at least 6% by weight of diesel cut [250° C./360° C.]) and at least 10% by weight of vacuum distillate VGO.
In general, at least the major part of Pa and Pb is transported by pipelines and oil tankers for their use as initial distillation feeds for one or typically several oil refineries.
Reference will now be made to
A crude oil P, typically conventional (for example Arabian light), is supplied via a line 1 to a desalter 2. The desalted oil supplies, via a line 3, a preliminary distillation column PRE-DIST, with reference numeral 4 (often termed initial distillation or atmospheric distillation) typically functioning at a pressure in the range 0.1 to 0.5 MPa. This column, which may optionally carry out summary fractionation, produces a light stream, typically naphtha and lighter compounds, via a line 30, a stream of middle distillates MD, typically kerosene and diesel cut via line 5, and a stream of intermediate gas oil IGO via a line 6, may comprise fractions principally boiling between 340° C. to 420° C. Said intermediate gas oil, which is relatively heavy for an atmospheric column, may be obtained by major steam stripping.
The column 4 also produces an atmospheric residue via a line 7, which supplies a vacuum distillation column, VAC-DIST, with reference numeral 8. This column, which typically functions at a pressure in the range 0.004 to 0.04 MPa, produces a stream of vacuum distillate VGO via a line 10, and a stream of vacuum residue VR via a line 9. It may also optionally produce a stream of light vacuum distillate LVGO via a line 11.
The vacuum residue VR is supplied to a solvent deasphalting unit SDA with reference numeral 12 (preferably pentane) to produce a deasphalted oil DAO moving in the line 13 and an asphalt stream AS evacuated via a line 14.
The asphalt AS is mixed with a diluent stream DIL supplied via a line 15. This stream typically comprises a stream of desalted oil supplied from line 3 via line 15 and a stream of middle distillates MD supplied from line 5 via a line 22 and/or a stream of intermediate gas oil IGO supplied via the line 6 via lines 23 and 22. DIL may also comprise naphtha N removed from a line 30. The flow rate of the diluent with respect to the flow of asphalt AS is typically in the range 3% to 50% by weight, preferably in the range 4% to 40% by weight, in general in the range 5% to 30% by weight and more preferably in the range 6% to 26% by weight.
The mixture of asphalt and diluent (fluxed asphalt) then supplies the ebullated bed hydroconversion unit RHDC with reference numeral 16. This unit typically comprises at least 2, and preferably at least 3 ebullated bed reactors arranged in series.
At the outlet from the RHDC unit, the hydroconversion effluent is supplemented by several streams moving in lines 30c, 31c, 32c, 33c and 34c. These streams typically comprise naphtha N (line 30c), hydrotreated middle distillates MD (line 31c), hydrotreated or hydrocracked (generally partially) intermediate gas oil IGO (line 32c), hydrotreated or hydrocracked (generally partially) vacuum distillate VGO (line 34c). Thus, a (pre-refined) oil Pc is reconstituted from the hydroconversion effluent, which comprises unconverted asphaltenic fractions, and typically hydrotreated or hydrocracked non-asphaltenic fractions, and thus with a reduced sulphur content. Said oil Pc has a much lower sulphur content than that of the initial oil P.
Fractions MD, IGO, VGO, DAO are then hydrotreated and/or hydrocracked (typically partially) in units H1 with reference numeral 21, H2 with reference numeral 20, H3 with reference numeral 19 and H4 with reference numeral 18. Typically, H1 (and often H2) is a hydrotreatment HDT, and H3 and H4 are mild hydrocracking units: M-HDK, medium pressure: MP-HDK, or high pressure: HP-HDK. Preferably, H4 is an ebullated bed hydrocracking unit.
The light stream moving in line 30 is subdivided into 3 elementary streams 30a, 30b, 30c.
The effluent from H1 moving in line 31 is subdivided into 3 elementary streams 31a, 31b, 31c.
The effluent from H2 moving in line 32 is subdivided into 3 elementary streams 32a, 32b, 32c.
The effluent from H3 moving in line 33 is subdivided into 3 elementary streams 33a, 33b, 33c.
The effluent from H4 moving in line 34 is subdivided into 3 elementary streams 34a, 34b, 34c.
From streams 30a, 31a, 32a, 33a and 34a, a pre-refined oil Pa is formed by mixing. Pa is an oil which is substantially free of asphaltenes since each of its components is also free of them (asphaltenes are only contained in the stream AS). It is also an oil with a very low sulphur content since the majority of its components are desulphurized, and naphtha, supplied via line 30a, is typically low in sulphur (as an option, it may also be hydrotreated).
Analogously, a pre-refined oil Pb is formed by mixing streams 30b, 31b, 32b, 33b and 34b. For the reasons given for Pa, Pb is also an oil which is substantially free of asphaltenes and has a very low sulphur content.
In accordance with the invention, the conversions of the units are determined and the distribution of components Pa and Pb are determined so that Pa is relatively rich in gasoline and naptha precursors, and relatively low in middle distillates: kerosene and a diesel cut while Pb, in contrast, is an oil which is relatively low in gasoline and naphtha precursors, and relatively richer in middle distillates.
Typically in accordance with the invention, the ratio Ra for oil Pa is higher than the ratio Rb for oil Pb. This may readily be achieved, for example, by incorporating relatively more naphtha N and unconverted VGO+ into Pa (via lines 30a and 33a) than into Pb (via line 30b and 33b), and in contrast by incorporating more middle distillates MD into Pb (via line 31b) than into Pa (via line 31a). De-composing the initial oil into fractions allows ready re-composition to enrich one or the other of oils Pa, Pb in middle distillates or gasoline precursors. For effluents from conversion units, the conversion may be adapted and/or the VGO+ content in the effluents may be measured (by distillation, chromatographic analysis, etc), to determine their VGO+ contents.
In general, oils Pa and Pb are re-composed so that Ra/Rb is more than 1.08 or even more than 1.12 or 1.2, in particular in the range 1.08 to 3.0; usually in the range 1.12 to 2.50; preferably in the range 1.20 to 2.0; and more preferably in the range 1.25 to 1.80.
Thus, before re-composing oils Pa, Pb and Pc, the invention can use one or more catalytic steps using certain processes which are well known in the art, in particular desulphurizing treatments, under a pressure of hydrogen, which consume large quantities or raised quantities of hydrogen.
According to the invention, the term “catalytic hydrogenating treatment” is used to define a treatment comprising at least one of the treatments defined below symbolized by the following terms: HDT, HDC, HDK (which covers M-HDK, MP-HDK and HP-HDK), RHDT, RHDC. The following catalytic hydrogenating treatments can thus be distinguished:
a) Hydrotreatments (Denoted HDT) of Feeds without Asphaltenes:
Hydrotreatment of hydrocarbon distillates or deasphalted oil (feeds substantially free of asphaltenes) are processes which are well known in the art. Their principal aim is at least partial elimination of unwanted compounds, typically sulphur, nitrogen, possibly metals such as iron, nickel or vanadium, etc. They are also often used for aromatic hydrogenation, generally simultaneously with feed desulphurization.
Conventionally, regarding those of the feeds cited above which comprise compounds boiling above 371° C., the term “hydrotreatment” defines a process wherein the conversion of these compounds into compounds with a boiling point of less than 371° C. is 20% by weight or less. For processes treating the same feeds, but with a conversion of more than 20% by weight, the term “hydroconversion” (denoted HDC), or “hydrocracking” (denoted HDK), said processes being presented below, is used.
Hydrotreatment processes functioning under hydrogen pressure use supported solid catalysts, typically granular solids or extrudates with a characteristic dimension (diameter for beads or equivalent diameter (corresponding to the same section) for extrudates) in the range 0.4 to 5 mm, in particular 1 to 3 mm. The operating conditions, in particular the space velocity (HSV) and the molar ratio of hydrogen to hydrocarbon (H2/HC), varies between cuts, the impurities present and the desired final specifications.
Non-limiting examples of the operating conditions are given in the following table:
The hydrotreatment catalysts typically comprise a metal or a compound of a metal from group VIB and a metal or compound of a metal from group VIII, on a support. The most usual catalysts are composed of an oxide support and an active phase in the form of a molybdenum or tungsten sulphide promoted by cobalt or nickel. The usual formulae used are CoMo, NiMo and NiW associations for the active phase, and 7 alumina with a large specific surface area for the support. The amounts of metals are usually of the order of 9% to 15% by weight of molybdenum and 2.5% to 5% by weight of cobalt or nickel.
Certain of these catalytic formulae are sometimes doped with phosphorus. Other oxide supports are employed, such as mixed oxides of the silica-alumina or titanium-alumina type.
Said supports are typically of low acidity, to obtain acceptable catalytic cycle times.
Examples of types of catalysts and hydrotreatments, in particular diesel cuts, gas oil or vacuum gas oil cuts are catalysts HR448 and HR426 from French company AXENS.
When traces of metals, in particular nickel and vanadium, are present in the feed, a catalytic support with a porosity adapted to deposition of said metals is advantageously used.
One example of such a catalyst is HMC841 from AXENS.
For the hydrotreatment of a deasphalted oil (DAO) comprising metals, it is possible, for example, to use a first bed with a HMC841 catalyst, for demetallization, then a second bed of HR448 for desulphurization and denitrogenation.
Other technical elements relating to hydrotreatments may be found in the reference text: “Conversion processes”, by P Leprince, Technip, publishers, Paris 15th district, pages 533-574.
Hydrocracking processes are also processes which are well known in the art. They apply exclusively to feeds which are substantially free of asphaltenes or metals such as nickel or vanadium.
The hydrocracking feed is typically composed of vacuum gas oil, occasionally supplemented with gas oil and/or deasphalted oil (deasphalted vacuum residue, typically deasphalted by a solvent from the group formed by propane, butane, pentane and mixtures thereof, preferably propane and butane).
It is also possible to carry out hydrocracking of the deasphalted oil DAO. The DAO must therefore be of sufficient quality: typically, a hydrocracking feed comprises less than 400 ppm (parts per millions by weight) of asphaltenes, preferably less than 200 ppm and highly preferably less than 100 ppm. The metals contents (typically nickel+vanadium) in a hydrocracking feed are typically less than 10 ppm, preferably less than 5 ppm, and highly preferably less than 3 ppm.
Conventionally, it is considered that a feed is substantially asphaltene-free if its asphaltenes content is less than 400 ppm. (In a similar manner, a pre-refined oil is considered to be without asphaltenes, or non-asphaltenic, if the fraction boiling above 524° C. contains less than 400 ppm of asphaltenes).
Typically, the hydrocracking feed is initially pre-refined on a hydrotreatment catalyst, which is typically different from the hydrocracking catalyst. This catalyst, typically with a lower acidity than the hydrocracking catalyst, is selected to substantially eliminate metals, reduce traces of asphaltenes, and reduce organic nitrogen, which inhibits hydrocracking reactions, to a value which is typically less than 100 ppm, preferably less than 50 ppm and highly preferably less than 20 ppm.
The hydrocracking catalysts are typically bifunctional catalysts having a double function: firstly, acidic, and secondly, hydrogenating/dehydrogenating.
Typically, the support has a relatively high acidity so that the ratio of the hydrogenating activity to the isomerizing activity, H/A, as defined in French patent FR-A-2 805 276 pages 1 line 24 to page 3 line 5, is more than 8, or preferably more than 10 or highly preferably more than 12, or even more than 15. Typically, hydrotreatment is carried out upstream of the reactor or the hydrocracking zone with a hydrotreatment catalyst wherein said ratio H/A is less than 8, in particular less than 7.
The hydrocracking catalysts typically comprise at least one metal or compound of a metal from group VIB (such as Mo, W) and a metal or compound of a metal from group VIII (such as Ni, etc) deposited on a support. The atomic ratio of metal from group VIII (MVIII) to the sum of metals from groups VIII and VIB, i.e. the atomic ratio MVIII/(MVIII+MVIB), in particular for NiMo and NiW pairs, is usually close to 0.25, for example in the range 0.22 to 0.28.
The metals content is usually in the range 10% to 30% by weight.
The group VIII metal may also be a noble metal such as palladium or platinum, in amounts of the order of 0.5% to 1% by weight.
The acidic support may comprise an alumina doped with a halogen, or a silica-alumina having a sufficiently acidity, or a zeolite, for example a dealuminated Y or USY zeolite, often having a double pore distribution with a double pore network in particular comprising micropores with a dimension principally in the range 4 to 10 Å and mesopores with a dimension principally in the range 60 to 500 Å. The silica/alumina ratio of the zeolite structure is normally in the range 6.5 to 12.
As an example, it is possible to use a sequence of hydrotreatment then hydrocracking with HR448 (HDT) then HYC642 (HDK) catalysts sold by French company AXENS. If the feed comprises metals, upstream of said two catalytic beds it is possible to use a demetallization catalyst such as the catalyst HMC841 also sold by AXENS.
Typical examples of the operating conditions for hydrocracking are as follows:
By definition, the conversion is that of products with a boiling point of more than 371° C. into products boiling below 371° C.
Typically, depending on the feeds, the partial pressure of hydrogen is usually in the range from about 2 MPa to 6 MPa for mild hydrocracking, between about 5 MPa and 10 MPa for medium pressure hydrocracking and between about 9 MPa and 17 MPa for high pressure hydrocracking. The total pressure is usually in the range 2.6 to 8 MPa for mild hydrocracking, between about 7 and 12 MPa for medium pressure hydrocracking and between 12 and 20 MPa for high pressure hydrocracking.
Hydrocracking processes are typically operated in a fixed bed with granular solids or extrudates with a characteristic dimension (diameter for beads or equivalent diameter (corresponding to the same section) for extrudates) in the range 0.4 to 5 mm, in particular in the range 1 to 3 mm. The scope of the invention encompasses hydrocracking being carried out in a moving bed (granular bed of catalyst typically in the form of extrudates or more preferably as beads), with dimensions similar to those described for a fixed bed.
Other technical elements relating to hydrocracking may be found in the reference work “Hydrocracking Science and Technology”, J Scherzer and A J Gruia, Marcel Dekker, publisher, New York, and in the reference work “Conversion processes”, P Leprince, Technip, Paris 15th district, pages 334-364.
Processes are known which can achieve conversions (with the same definition as for hydrocracking) of more than 20% by weight and frequently much higher (for example 20% to 50% or 50% to 85% by weight), for example ebullated bed processes. Said processes may use variable partial pressures of hydrogen, for example between 4 and 12 MPa, temperatures of between 380° C. and 450° C., and a hydrogen recycle which is, for example, in the range 300 to 1000 Nm3 per m3 of feed.
The catalysts used are similar or of a type close to that of catalysts for hydrotreatment or residue hydroconversion, defined below, and have a porosity which can provide a considerable demetallization capacity.
As an example, it is possible to use a catalyst of the HTS358 type, sold by French company AXENS.
Processes for hydrotreatment of residues (and hydroconversion of residues) are processes which are well known in the art.
Typical operating conditions for said processes are: hourly space velocity (HSV) in the range 0.1 to 0.5. Partial pressure of H2 between 1 and 1.7 MPa. Hydrogen recycle between 600 and 1600 Nm3 per m3 of feed. Temperature between 340° C. and 450° C.
Catalysts for fixed, moving or ebullated bed processes are usually supported macroscopic solids, for example beads or extrudates with middle distillates in the range 0.4 to 5 millimetres. Typically, they are supported catalysts comprising a metal or a metallic compound from group VIB (Cr, Mo, W), and a metal or metallic compound from group VIII (Fe, Co, Ni, etc) on a mineral support, for example catalysts based on cobalt and molybdenum on alumina, or nickel and molybdenum on alumina.
For fixed bed hydrotreatment or hydroconversion it is possible, for example, to use a hydrodemetallization catalyst HMC841, then hydroconversion and hydrocracking catalysts: HT 318, then HT328 sold by French company AXENS.
For an ebullated bed, it is possible to use a HOC458 type catalyst, also sold by French company AXENS.
The catalysts for slurry processes are more diversified and may comprise particles of ground lignite or charcoal impregnated with iron sulphate or other metals, ground used hydrotreatment catalyst, particles of molybdenum sulphide associated with a hydrocarbonaceous matrix, obtained by in situ decomposition of precursors such as molybdenum napthenate, etc. The typical dimensions of the particles are less than 100 micrometres, or even much smaller.
Other characteristics of processes and catalysts for hydroconversion of residues are given in general reference work A: “Raffinage et conversion des produits lourds du pétrole” [Refining and converting heavy products from oil] by J F Le Page, S G Chatila, M Davidson, Technip, Paris, 1990, in Chapter 4 (Conversion catalytique sous pression d'hydrogène) [catalytic conversion in hydrogen], and Chapter 3, paragraph 3.2.3. Reference could also be made to general reference work B: “Conversion processes”, P Leprince, Technip, Paris 15th District, pages 411-450, in Chapter 13 (hydroconversion de résidus) [Residue hydroconversion], and to the general work: “Upgrading petroleum residues and heavy oils”, by Murray R Gray, Marcel Dekker Inc, New York, Chapter 5.
Purified gas may be used for the production of hydrogen for carrying out said catalytic hydrogenating treatments, for example by steam reforming on a nickel catalyst then steam conversion of CO followed by purification—this is a well known process, described in the work with reference B cited above, p. 451-502, or in the reference work “The desulphurization of heavy oils and residues”, J Speight, Marcel Dekker, Inc, New York.
The yields in the examples below are expressed without taking account of sulphur, as a % by weight with respect to the feed.
A middle eastern oil P was pre-refined by carrying out the following operations:
a) P was fractionated by atmospheric distillation then vacuum distillation to produce 4 cuts:
MD was hydrotreated (HDT) and the VGO was 25% converted, including 1% of C4-gas, 5% of naphtha and 19% of middle distillates, by mild hydrocracking M-HDK.
The vacuum residue VR was 60% converted into VGO and lighter products by ebullated bed hydroconversion RHDC.
The following cuts were mixed: N, hydrotreated MD (HDT effluent), hydrocracked VGO (M-HDK effluent), and 75% by weight of the mixture was separated to produce an oil P*a which was of high quality: no asphaltenes and a low sulphur content (for example less than 0.3% by weight or even less than 0.1%). The remaining 25% by weight of the mixture was added to the RHDC hydroconversion effluent to form a second refined oil P*b which contained unconverted asphaltenes and was thus a residual oil.
The oil of Example 1 was pre-refined by carrying out the following operations:
a) P was fractionated by atmospheric distillation then vacuum distillation to produce 5 cuts:
MD was hydrotreated, IGO was 20% converted, including 1% of C4-gas, 4% of naphtha and 15% of middle distillates, by mild hydrocracking M-HDK, and HVGO was 30% converted, including 2% of C4-gas, 6% of naphtha and 22% of middle distillates, by mild hydrocracking M-HDK.
The vacuum residue VR was 60% converted by ebullated bed hydroconversion RHDC to VGO and lighter products.
A first mixture Ma was produced with the following cuts: 60% by weight of N, 40% by weight of hydrotreated MD (HDT effluent) and hydrotreated IGO and 75% by weight of mixture Ma was separated to produce an oil Pa which was of high quality: no asphaltenes and with a low sulphur content (for example less than 0.3% by weight or even less than 0.1%). Pa was an oil with a relatively high gasoline potential and a relatively low middle distillates potential: Ra=1.209.
A second mixture Mb was produced with the following cuts: 40% by weight of N, 60% by weight of hydrotreated MD (HDT effluent) and hydrocracked HVGO and 75% by weight of mixture Mb was separated to produce an oil Pb which was of high quality: no asphaltenes and with a low sulphur content (for example less than 0.3% by weight or even less than 0.1%). Pb was an oil with a relatively low gasoline potential and a relatively high middle distillates potential: Rb=0.7.
The remaining 25% by weight portions of Ma and Mb were added to the residue hydroconversion effluent RHDC to form a third refined oil Pc which contained unconverted asphaltenes and was thus a residual oil.
The Ra/Rb ratio was thus established at 1.73. Typically, a refinery could be stocked with oil Pc to satisfy its residual fuel market, then to estimate, as a function of the refining yields for Pc, the relative requirement for naphtha, gasoline and middle distillates. It thus has two oils Pa and Pb to hand, and the distribution can be selected to adjust the (naphtha+gasoline)/middle distillates balance.
| Number | Date | Country | Kind |
|---|---|---|---|
| 0504301 | Apr 2005 | FR | national |
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/FR2006/000671 | 3/24/2006 | WO | 00 | 4/13/2009 |
