BRPI0803072A2 - methods for producing higher value products from sulfur-containing petroleum - Google Patents

Abstract

  A process for improving the quality, or refining, of high sulfur-containing heavy hydrocarbon oil to a lighter oil having a lower sulfur concentration and thus being a higher value product is described. The process includes reacting the high sulfur heavy hydrocarbon oil in the presence of a catalyst and low pressure hydrogen to produce a reaction product stream from which the light oil is recovered. Part of the reaction product is separated and subjected to further quality improvement for the production of a low sulfur oil product for application as distilled fuels. The quality improvement process also produces a waste oil suitable for the production of olefins, carbon fibers, or asphalt. Catalysts used in the processes of the invention may include a transition metal-containing compound, the metal being selected from the V, VI and VIII groups of the Periodic Table of the Elements, and mixtures of such metals.

Description

Patent Descriptive Report: METHODS FOR PRODUCING HIGHEST VALUE PRODUCTS FROM SULFUR OIL.

Correlated Order

The present patent application claims priority of U.S. Provisional Patent Application Serial No. 60 / 679,903, filed May 11, 2005.

Background of the Invention

1. Field of the Invention.

The present invention is generally related to the processing of high density oils with high sulfur content or heavy hydrocarbons. More specifically, the present invention relates to an improved process for improving the quality of a heavy hydrocarbon petroleum feedstock to an oil that is less dense or lighter and containing lower sulfur content than the original heavy hydrocarbon feedstock, also producing materials. higher added value, such as ear aromatic olefins.

2. Description of the Correlated Technique.

The invention is generally related to a process for treating a heavy hydrocarbon oil, also referred to herein as "oleocru". More particularly, the process described herein is directed towards improving the quality or upgrading of a heavy hydrocarbon petroleum feedstock by hydrotreating aided by a hydro-processing catalyst. Although the term hydrocracking will often be applied to such types of processes, the term hydroconversion (or hydro-processing, or hydrotreating) will be used herein to avoid confusion with conventional diesel hydrocracking. Weighing oils are chemically composed of a very wide range of very different molecules. terms of molecular weight (MW) and chemical properties. In addition, heavy oils from different formations and locations around the world have different characteristics. Given the large number of variable characteristics of heavy oils around the world, it is difficult to define heavy oils simply by having individual molecular components. In several places, various separation procedures are used to separate feed into several smaller fractions that can be more consistently identified. One technique involves separation into solubility classes using solvents of varying polarity and additional separation using column chromatography. Such fractions may be further characterized in terms of an average nuclear magnetic resonance (NMR) structure or other analytical technique known to those skilled in the art.

Despite the fact that heavy oils vary widely in terms of their physical and chemical compositions and properties, they are typically characterized by their relatively high viscosity, high boiling point, high Conradson carbon residue, low API density (generally below). 25) and high concentrations of sulfur, nitrogen and metallic impurities. In addition, the carbon-to-carbon ratio of heavy crude oils is lower than desirable. In addition, much of the world's oil also contains a relatively high concentration of sulfur. As used herein, the term crude oil or heavy crude oil should be considered to include oils with heavy hydrocarbons, tarred sands, bitumen and waste oils, that is, column bottom or vacuum bottom oils. , crude oils consist of paraffins, cycloparaffins (naphthenes) and aromatics with various ring sizes and degrees of aliphatic chain substitution, polarities and nitrogen and sulfur containing heterocycles content. Molecular weights of crude oils range from several thousand daltons and boiling points to 700 ° C or more. Most crude oils are believed to be colloidal systems with high mw polar decomposing micelles (asphaltenes) stabilized by intermediate polarity components (resins). Asphaltenes components contain most metals (V, Ni and Fe) complexed by polyidentated N and S binders such as porphyrins.

Over the past two decades, environmental and economic considerations have necessitated the development of processes for the removal of hetero atoms, such as sulfur, nitrogen, oxygen and metal impurities, from heavy hydrocarbon oil feedstocks, and to convert heavy hydrocarbon oil feedstocks to reduce your boiling points. Such processes generally undergo crude oils with heavy hydrocarbons, or fractions thereof, thermal cracking or hydrocracking to convert fractions having higher boiling points to fractions having lower boiling points, optionally followed by hydrotreating to hetero-atom removal.

The main features of all hydroconversion processes are similar. The heavy crude oil raw material is preheated, mixed with hydrogen under pressure and passed to a reactor kept at the temperature of the oil. Sometimes some or all of the hydrogen is added directly to the reactor. The liquid residence time in the reactor can typically range from 1 to 10 hours. The following hydrotreated products pass to a series of one or more vapor / liquid separators. Typically, a high pressure hot separator removes heavy tar-containing liquid. , and the steam passes to a high pressure cold separator to separate gases from the distilled product. Intermediate separators can be used to reduce temperature and pressure at stages. In some processes, a vapor phase hydrogenation unit is used to further treat the vapor before passing it to the cold separator. The gas from the cold separator is then sent to a scrubber or scrubber or PSA unit for removal of H2S and NH3 and light hydrocarbons (which are used as fuel gas) and the hydrogen gas is then recirculated to the reactor. Fresh hydrogen, usually produced by methane vapor reforming, is added to replace the consumed hydrogen.

Technologies for upgrading / upgrading heavy oils, including bitumen and waste oils, to produce lighter and more useful oils and hydrocarbons can be broadly divided into two types of processes: carbon rejection processes and hydrogen deadening processes. Such processes employ high temperatures (usually above 400 ° C) to "crack" the long chains or branches of the hydrocarbons that make up the heavy hydrocarbon oil. No rejection process of. carbon, heavy hydrocarbon oil is converted to lighter oils and coke. In some carbon rejection processes, coke is used elsewhere in the refinery to provide heat or fuel for other processes.

Hydrogen addition processes involve sandblasting heavy oils with an external hydrogen source, resulting in a general increase in the hydrogen to carbon ratio. One benefit of hydrogen-killing processes over carbon-burning processes is that in the hydrogen addition process, coke formation is prevented by the addition of high pressure hydrogen. Examples of hydrogen killing processes include: catalytic hydroconversion (hydrocracking) using active HDS catalysts, fixed bed catalytic hydroconversion, boiling catalytic bed hydroconversion, thermal suspension hydroconversion (hydrocracking), hydroviscoquebrae and hydropyrolysis.

The primary goal of upgrading or upgrading heavy oils is to reduce the molecular weight of larger molecules to produce components with boiling points and adequate hydrogen to carbon ratios for liquid fuels. Concomitantly, contaminants such as sulfur, nitrogen, and metals should be removed and aromatics saturated. Generally speaking, these different "steps" of improvement require different processes and processing conditions to achieve the desired properties. As an example, hydrogenation of aromatics is best performed at moderate temperatures, with metal catalysts, in the absence of sulfur and nitrogen compounds, while sulfur and nitrogen removal uses sulfur-based metal sulfide-based HDS catalysts and operate at higher temperatures. Therefore, the process as a whole generally involves several steps for separating heavy crude oil into chemically different components and treating them by the most suitable process for each step. However, economic constraints prevent the use of such a strategy. Therefore, the only separation usually made is distillation for removal of lighter fractions, or removal of solvents asphalts to remove asphaltenes. For the reasons set forth herein, it is believed that the present invention overcomes such economic restrictions.

Upgrading heavy oils and waste oils results in the formation of free radical chain reactions. Free radicals are highly reactive intermediates that have a unique electron. Tertiary alkyl free radicals are more stable than secondary alkyl free radicals and secondary alkyl free radicals are more stable than primary alkyl free radicals. Thus the t-butyl radical (a tertiary radical) is energetically more favored than the ethyl radical. An example of a free radical reaction is as follows:

1. Initiation:

M kl-> 2R (minor alkyl radical) (1)

M = mother molecule

2. Propagation:

R + M k2-> RH + M (chain reaction) (2)

M k3-> R + Olefins (P separation reaction) (3)

3. Termination:

R + R k4-> ProductsFree radical reactions are influenced by reactor pressure and, in particular, by hydrogen pressure. Consequently, hydrogen pressure is important for hydro-processing systems. High pressures, ie above 7 MPa, reactions under low pressure generally have no continuation. Under high hydrogen pressure, hydrogen addition reactions become more favorable. In addition, P separation reactions are less significant at high pressure. Therefore, at elevated pressures, rather than multistage cracking through olefin formation, free radicals are stabilized in a single step without olefin formation. In the intermediate pressure range of 3 to 7 MPa a complex two-step mechanism is possible. At lower pressures, cracking reactions form olefins that can be used as raw materials for fluid catalytic cracking.

Thiols, aliphatic sulfides (thio ethers) and disulfides are very reactive under thermal conditions and can constitute up to 50% of the total sulfur in various oils and asphalts of heavy oils. The thermal reactions of such types of sulfur are favorable because carbon - sulfur bonds are weaker than other carbon - carbon bonds. For example,

R-S-R '+ 2 H 2 H 2 S + RH + R'H

When thermal cracking occurs in the presence of hydrogen and a catalyst the reaction pathways change significantly. Although thermal cracking still occurs, hydrogenation and parallel hydrogenolysis also occur, thereby changing the chemical nature of the molecules being cracked. Sulfur and onitrogen are removed from heterocycles producing H2S and NH3 and the formation of carbon - hydrogen bonds. Resulting aliphatic rises can then be broken down for the production of light hydrocarbons such as methane, ethane, etc.

Hydrogen can also capear radicals and terminate polymerization reactions, thereby reducing or eliminating coke formation. Therefore, it was found that partial pressure and hydrogen purity are significant. As described herein, high hydrogen pressure maintenance is required in the hydro-processing unit. However, what is also important is the partial pressure of hydrogen. Therefore, it is desirable to reduce the concentration of impurities (light hydrocarbon gases) to maintain a high hydrogen partial pressure in the hydrotreating unit. The catalysts commonly used in hydrotreating are metal sulfide based and greatly accelerate hydrodesulphurization reactions leading to lower sulfur products. Although it is believed that the catalyst does not directly catalyze significant cracking, and it is known that catalysts are easily poisoned by the metals normally present in heavy crude oils, catalysts may still be designed to accelerate the decaying reaction. In addition, although metal sulfides catalyze the hydrogenation of aromatics, since such reaction is reversible and highly exothermic, the temperatures normally employed to achieve high conversion of raw material are high, for example at approximately 450 ° C or more, and thus tend to favor reverse reaction (dehydrogenation of aromatics).

Unless they are operated at high hydrogen pressure and low LHSV (to reduce temperature and still allow for high conversions), most upgrading processes can only achieve low aromatic saturation levels. This leads to yields of C1 to C5 hydrocarbon gases which can reach up to 10% by weight of the feed. One of the benefits of the present invention is that more value is obtained from such hydrocarbon gases. Since each mole of gas consumes approximately one mole of hydrogen, total hydrogen consumption can reach 3% by weight of feed (approximately 2000 scf / bbl) in a relatively high pressure process.

All of the above methods involve contacting heavy crude oils with hydrogen at a pressure above about 70.31 kg / cm2 (1000 psi) and temperatures up to 470 ° C. Thermally cracked and hydrogenated heavy crude oil feedstock for the production of higher hydrogen to carbon ratio products, reduced sulfur and nitrogen contents and boiling points suitable for refining various liquid fuels. Generally, the processes can be divided into those employing high activity HDS catalysts based on metals such as cobalt, molybdenum and nickel which produce low sulfur products, and those that use less catalytically active additives or very low concentrations of a lower catalyst. designed to inhibit coke formation and demetallization, which produces higher sulfur products that require more extensive hydrotreating. Catalytic promoters such as phosphorus, silica, alkaline earth alkaline metals are also useful.

Prior art methods also encounter transport limitations in the upgrading process. Generally speaking, there are two common forms of reactor phasiphases (gaseous, liquid and solid catalysts), such as suspension and rickle-bed (contrary flow of liquids and gases in a decatalyst bed). It is often assumed that systems are in perfect mix. In reality, systems do not completely mix. Hydrogenous bubble formation can in fact prevent the mass transfer of hydrogen to the catalyst surface. To solve such a problem, the reaction as a whole consists of the following sequence of events: mass transport of the bubble to bulk liquid interface, mixture to bulk liquid buildup, mass transfer to the outer surface of the catalyst particles, and reaction on the surface of the liquid. catalyst. Although it is expected that the introduction of agitation would allow uniform liquid conditions, such gas - liquid mixing is often limited. Therefore the present invention addresses this problem by providing better mass transport in the de-grading process. In addition, processes for the ecatalytic thermal rearrangement of heavy hydrocarbon oils and other similar raw materials are described by Bruijnet al. U.S. Patent Nos. 5,104,516 and 5,322,617, which is incorporated herein by reference. In the described processes, a heavy hydrocarbon crude oil, or a heavy hydrocarbon crude oil dispersion, reacts with synthesis gas in the presence of a catalyst to reduce the viscosity and density of the heavy hydrocarbon oil, thereby making it more suitable for pipeline transport. . The processes described in Bruijn et al. provide hydrogen recovery and carbon dioxide gases as by-products, and carbon monoxide recirculation for the rearrangement process. The use of a bifunctional catalyst present in about 0.03 to about 15% is described under conditions and pressures that facilitate both gas displacement sandblasting and the rearrangement of hydrocarbons. The bifunctional catalyst includes an inorganic base and a transition metal-containing catalyst such as iron, chromium, molybdenum, or cobalt.

The gas displacement reaction is an industrial process in which carbon monoxide (CO) and water (H20) in the form of vapor react in the presence of a catalyst producing carbon dioxide (CO2) and hydrogen (H2), as shown in the following equation. :

CO (g) + H2 O (g) CO2 (g) + H2 (g)

In the process described by de Bruijn et al., Gas displacement sandblasting is used to generate the hydrogen used for the rearrangement of hydrocarbons in the raw material and also to produce excess gas recovered as a by-product. As described by Bruijnet al., The source of CO may be carbon monoxide mixed with synthesis gas, or generated in situ from the methanol composition. Synthesis gas (syngas) consists of a mixture of hydrogen (H2) and carbon monoxide (CO) typically in a ratio range between about 0.9 and about 3.0. It is commonly produced by the controlled combustion of methane, coal, or naphtha with oxygen to produce a mixture of gases including hydrogen (H2 ), carbon monoxide (CO), carbon dioxide (CO2), hydrogen sulfide (H2S), carbonyl sulfide (COS) and others. It is conventional to "clean" the flue gases produced to obtain pure synthesis gas. A critical prerequisite for the use of syngas in transition metal catalyzed reactions is the removal of sulfur-containing compounds, such as H2S or COS, formed from sulfur compounds in natural hydrocarbons or coal.

The processes described by de Bruijn et al., Also known as CANMET technology, suffer from designative deficiencies when practiced on an industrial scale. Specifically, CANMET technology does not have a suitable source for process gas synthesis gas; generates useless products such as coke, heavy hydrocarbon crude oil waste, exhausted catalyst that must be disposed of in an environmentally sound manner; generates highly hydrocarbon-contaminated by-products that require significant treatment before being released into the environment; requires an economical heat source for upgrading / rearrangement reactions; prefers a separate disulfide step to activate the catalysts used in the upgrading / rearrangement reactions; is limited by the slow kinetics of the gas displacement reaction; and has problems with the stability and breakage of heavy hydrocarbon crude oil and the dispersion of heavy hydrocarbon crude oil. Subsequent revelations by Khan et al. U.S. Patent No. 5,935,419, entitled "METHODS FOR ADDING VALUE TO HEAVY OIL", USING SOLUBLE METAL CATALYST ", in U.S. Patent No. 6,059,957, entitled" METHODS FORADDING VALUE TO HEAVY OIL ", provide a solution to the above problems. However, these two patents involve the use of water in the raw material, together with the crushed oil, specifically to integrate the deupgrading process with a gasification process. The use of crude oil water, although beneficial under certain degassing conditions, can create serious operational difficulties in an upgrading unit. Such difficulties include the fact that water is a scarce resource in many parts of the world, particularly in the Middle East. Secondly, the use of water in a pressurized upgrading unit may pose serious operational challenges as water vaporizes and expands in reaction.

Therefore, an advantage of the present invention is the ability to define a better way to use hydrogen during processing of crushed oil under low operating pressure. In addition, the hydrogen containing gas preferably used in the de-grading process has a high purity (> 90% hydrogen), thereby improving the overall reaction chemistry. Previous upgrading processes did not address the importance of hydrogen purity quality in the upgrading process, while maintaining relatively low operating pressure. The present invention also describes the benefit of oil-soluble catalysts (also known as nanocatalysts). Unlike heterogeneous catalysts, homogeneous oil soluble catalysts easily disperse and do not precipitate during crude oil processing. The present invention is also directed to improving mass transport by premixing the eliquid gas with a dispersed catalyst prior to reactions in a well stirred reactor system where oleocru upgrading occurs. The improved / upgraded product is subsequently separated and further treated to improve quality. Several fractions can then be separated and used in the most economical way. H2S and CO2 generated during upgrading of crude oil may also be injected into a reservoir for reuse.

The waste generated in an upgrading process is generally of low value. In addition, light-free gases, for example methane, ethane and propane, are not of great value. One of the objectives of the present invention is to use the residue, together with light gases, to transform such materials into value-added products, such as aromatics and olefins, into a catalytic fluid cracking unit ("FCC"). The FCC unit consists of a carbon rejection and hydrogen transfer device. The FCC process models the carbon distribution based on the hydrocarbon structures in the raw material and the tendency to balance the cracking process. Historically, the FCC unit was regarded as a relatively inexpensive generator of gasoline and light olefins, which now has significant application as a residual oil upgrading unit. The FCC unit and its parts are well known to those skilled in the art. Examples of the FCC unit can be found in U.S. Patent No. 2,737,479. Some FCC units may work with waste oil and / or heavy oils.

Hydrocarbon catalytic cracking processes increasingly employ a system whereby hydrocarbon feedstock is cracked in the presence of a high activity cracking catalyst in a riser or column type reactor. Generally, the FCC process occurs by contacting heat regenerated catalyst with a hydrocarbon feed in a reaction zone under conditions suitable for cracking: separation of cracked hydrocarbon gases from exhausted catalyst using a cutter separator followed by conventional cyclones; vapor extraction of exhausted catalyst into a degeneration chamber, where a controlled volume of air is introduced to burn carbon deposits in the catalyst; return the regenerated catalyst to the reaction zone.

Most FCC units are operated to maximize conversion to gasoline. This is particularly true when gasoline supplies increase at peak demand. Maximum conversion of a specific raw material is usually limited by design constraints of the FCC unit (eg regenerator temperature, wet gas capacity, etc.) and by processing objectives. However, within such limitations, the FCC unit operator may select from many operating variables and catalyst properties to achieve maximum conversion. The main variables available to the FCC unit operator for maximum unit conversion for a given raw material quality can be divided into two groups: catalytic variables (catalyst activity, design) and process variables (temperature, pressure, reaction time, degree of regeneration). catalyst, etc.). Such variables are not always available to maximize conversion, as most FCC units are already operating at an ideal conversion level corresponding to a given feed rate, set of processing conditions, and catalyst, or one or more unit constraints (for example, unit capacity). wet gas compressor, fractionation capacity, air blower capacity, reactor temperature, regenerator temperature, catalyst circulation). Therefore, the operator can adjust only a few variables. Once the optimal conversion level is found, the operator has no additional degree of freedom to modify the operating variables. However, the operator may collaborate with the catalyst supplier to design the catalyst properties to remove operating restrictions and shift operation to a higher optimal conversion level or alternatively use low cost raw material that will maximize light olefins per unit cost of the raw material. on a suitable FCC unit.

It is well known to those skilled in the art that for crystalline ossilicates long chain olefins tend to crack at a much higher rate than corresponding long chain asparafins. When crystalline silicates are employed as catalysts for converting paraffins to olefins, the conversion rate drops as time elapses in the stream, which is due to the formation of coke (carbon) deposited on the catalyst. Several commercially available advanced catalysts can be used to convert a variety of raw materials into a typical FCC. The main decay catalysts are made of zeolites and a matrix (clay and a binder or binder). For higher production of C2 and C3 olefins, ZSM-5 additives are also used. Typical FCC sulfur reduction additives are also used, such as for example AKZO Nobel RESOLVE®.

Known FCC processes are employed to degrade heavy paraffinic molecules to lighter molecules. However, when depropylene production is desired, not only yields are low, but also the stability of the crystalline silicate catalyst is low. As an example, in an FCC unit, a typical depropylene yield is 3.5% by weight. Propylene yield can be increased to about 7 to 8% by weight in the FCC unit by introducing the ZSM-5 catalyst into the FCC unit to "squeeze out" more propylene from the hydrocarbon feedstock being cracked. Not only is such an increase in yield very small, but also the ZSM-5 catalyst has poor stability in the FCC unit.

The petrochemical industry is currently facing a significant shortage of propylene availability as a consequence of the growth of propylene derivatives. Traditional methods for increasing propylene production are not completely satisfactory. For example, additional naphtha vapor cracking units, which produce about twice as much ethylene as propylene, are a costly way to produce propylene, as the raw material is valuable. and very high capital investment. Naphtacompete is typically a raw material for steam crackers as a base for refinery gasoline production. Propane hydrogenation provides a high yield of propylene, but the raw material (propane) is of interest only in terms of cost over limited periods of the year, making the process expensive and limiting production of propylene. Propylene is obtained from FCC units, but with a relatively low yield. Elevated dormancy has been shown to be expensive and limited.

There is therefore a demand for a method for producing high yield propylene that can be easily integrated with a refinery or petrochemical unit for the use of less expensive raw materials in the market (with few alternatives in the market). The heavy waste fraction and light gases released from an upgrading unit, which contain a significant amount of C2 to Cs products, including aromatics, olefins and naphtha, are excellent raw materials for an FCC unit to produce higher value products.

Summary of the Invention

In one embodiment of the process of the invention, a heavy hydrocarbon oil or a dispersion of a heavy hydrocarbon raw oil feedstock is reacted with high purity hydrogen in the presence of a transition metal catalyst to produce a stream of products having a lighter oil. and a waste heavy oil from heavy hydrocarbons.

The present invention is directed to an improved process for upgrading or upgrading heavy hydrocarbon oils to a lighter, lower sulfur and lower density oil. One embodiment of the process of the invention involves contacting a heavy hydrocarbon crude oil with a catalyst, then reacting with high-purity hydrogen gas at a relatively low pressure to produce a product stream having a lighter oil and an oil residue. heavy hydrocarbon crude, and lighter oil separation from the product stream, with additional treatment being performed on a second processor for improvement / upgrade. A preferred range of low pressure ranges from 35.15 kg / cm2 (500 psi) to 105.5 kg / cm2 (1500 psi). Additional treatment may occur in a conventional hydrotreater with a catalyst for removal of additional closely bound residual sulfur. Light gases and heavy fractions can be sent to a conventional fluid catalytic cracking unit to convert materials to higher value-added products such as olefins and aromatics. The waste of heavy hydrocarbon crude oil may also be further fractionally treated, where a portion is sent to prepare a raw material for the production of carbon based products, such as carbon fibers, asphalt for road application, or materials. of combustion for power generation (optionally after preparing a suspension in water) In addition, a portion may be recirculated to chain from heavy hydrocarbon crude oil weighed at the start of the process. The heavy hydrocarbon crude oil residue can also be processed in a high shear environment to reduce hazardousness.

In another aspect, the invention is directed to the formation of a product stream that is separated into a light oil stream and a heavy hydrocarbon crude oil waste stream. Part of the heavy hydrocarbon crude oil waste stream can be mixed with the heavy hydrocarbon crude oil feedstock for additional high purity hydrogen in the presence of a transition metal catalyst, while the heavy hydrocarbon waste oil remainder can be used. for the production of asphalt for road construction or for combustion in power generation.

In another embodiment, it is directed to a sulfur-containing petroleum desulphurization process. The process comprises the hydrodelsufurization steps of a sulfur-containing crude oil feed using an oil-soluble catalyst in an oil desulfurization unit to obtain a crude sulfur oil; separation of desulphurized crude oil into a light gas fraction, a light oil fraction, a heavy oil fraction and a residual fraction; passing the light oil fraction portion and a portion of the heavy oil fraction in combination with hydrogen to the reaction zone of a secondary upgrading unit; hydrocracking the light oil fraction portion and the reaction nazone heavy oil fraction portion of the secondary upgrading unit to produce an effluent; passing part of the residual fraction and part of the light gas fraction through a catalytic fluid cracking unit; and cracking the portion of the residual fraction and the portion of the light gas fraction in the catalytic fluid cracking unit to produce at least one light olefin and at least one aromatic product.

In yet another aspect, the invention is directed to a process for providing a reduced sulfur fuel and a commodity product. The process comprises the steps of dehydrurising a petroleum feed using an oil-soluble catalyst in an petroleum desulphurization unit to obtain a desulphurized hydrotreated petroleum; fractionate the hydrotreated petroleum into at least one gaseous product, one light oil fraction and one heavy oil fraction; cracking the heavy oil fraction along with each of at least one light gas in a column reactor of a fluid catalytic decaying unit in the presence of a cracking catalyst and a sulfur removal catalyst for producing at least one cracked product and an exhausted catalyst; separating at least one depleted product from the exhausted catalyst into a separator; fractionating the at least one cracked product to produce a hydrogen-containing gaseous stream and a low sulfur degasoline stream, an olefinic raw material stream and a heavier stream than gasoline. Another feature of this process comprises the steps of obtaining a heavy naphtha from the fractionation of step (e) and recirculating the heavy naphtha to the column reactor; Obtain a hydrogen-containing gas from fractionation and combine the hydrogen-containing gas with desulphurized hydrotreated oil.

The invention is also directed to a method for increasing the stability of a heavy hydrocarbon oil dispersion and the composition of the heavy hydrocarbon oil / fuel dispersion.

Brief Description of the Drawings

These and other features of the present invention will become clearer by describing illustrative embodiments of the invention. The description is given with reference to the attached drawing and in which:

Figure 1 is a schematic process flowchart of an illustrative embodiment of the present invention.

Although the invention is described in connection with the preferred embodiment, it should be clear that it is not intended to limit the invention to such embodiment. By contrast, it is intended to cover all alternatives, modifications and equivalents that may be incorporated into the spirit and scope of the invention as defined in the appended claims.

Detailed Description of the Invention

In Figure 1 a flowchart of embodiments of the present invention is shown. In such a flowchart, it should be clear that components such as the upgrading unit 204 and the shear unit 202 have been represented as "boxes" for simplicity of illustration. As will be appreciated by those skilled in the art, both units contain various components, such as reactors in upgrading unit 204 and element heaters and mixing elements in shredding unit 202. In general, shredding unit 202 can also be referred to as an emulsifier mixer, dispersion mixer , unitsonic, or preheater. Those skilled in the art should note that the actual process implementation will be more detailed and will also depend, among other things, on the scale, cost, quality and quantity of the raw material and the available space at the reactor site. As illustrated in Figure 1, oil heavy crude hydrocarbon from stream 100 ("heavy oil") is combined with stream catalyst101 to form reaction mixture 200. reaction mixture 200 is transferred along with stream 102 to shear unit 202 where reaction mixture 200 is preheated and agitated using a stator rotor system to form a heavy hydrocarbon oil dispersion. In one embodiment, the shear unit 202 is a 450X series equipment produced by Ross to provide shear force. Unlike traditional homogenizers, the 450X series rotor-stator consists of an array of interconnected channels. With the rotor rotating at high speeds (ie tip speeds up to 17,000 rpm) the 450X machine can produce dispersions comparable to those produced by a high pressure homogenizer. However, it should be clear that several other commercially available units may be suitable for this purpose. As an example, shear in the shredding unit 202 may also be achieved by the use of low cost ultrasonic devices such as those available from Hielscher USA, Inc., 19Forest Road, Ringwood, NJ 07456, USA; ActiveUltrasonics, Puits-Godet 6A, CH-2000, Neuchatel, Switzerland; Silverston Machine, Inc., 355 Chestnut St., PO Box589, East Longmeadow, Massachusetts 01028, USA.

In one embodiment, the shear unit 202 used in the present invention consists of a high precision produced rotor / stator head that far outperforms conventional blends, reducing processing times by up to 90%, improving product quality, consistency. and process efficiency. Such a high shear mixer is available through Silverson Machine, Inc. The crude oil and catalyst mixture in shear unit 202 forms a heavy hydrocarbon crude oil dispersion which can then be transferred together with stream 104 to the upgrading unit204. Alternatively, the reaction mixture 200 is stirred to form a heavy hydrocarbon crude oil dispersion for feeding to the scrambling unit 202.

Typically, the reaction mixture 200 is preheated in the shear unit 202 to a temperature in the range of about 300 ° C to 350 ° C, although the preheat step may occur prior to introduction of the reaction mixture into the shear unit 202. During this step, the catalyst is believed to interact with the sulfur groups of the heavy hydrocarbon crude oil and the catalyst is sulfated in situ. The terms "sulfate" and "sulfate" as used herein mean the chemical act of combining a sulfur element or compound or one or more sulfur-containing compounds. Shear of crude oil under such conditions leads to dissociation from some weak bonding forces and therefore at least partial upgrading of heavy oil from heavy hydrocarbons occurs in the shear unit202. In addition, it is believed that during such a step the heavy hydrocarbon oil is conditioned by temperature so that the heavy hydrocarbon crude oil becomes suitable for use in the deupgrading unit reactor 204 without coke formation or dereversion reactions.

Typically, the concentration of catalyst introduced into the reaction mixture 200 is in the range of about 50 ppm and about 0.1% of crude oil. It has been found that when a combination of catalysts is used, the total amount of catalyst added is typically less than the amount used for any single catalyst. Thus, when a catalyst combination is used to achieve a stabilized dispersion, the catalyst concentration typically ranges from about 100 ppm to about 0.1% of the heavy crude oil feed. Oil-soluble catalysts are preferred to oil-insoluble catalysts that tend to settle and clog reactors.

In a specific embodiment, a hydrogen-containing gas may also be combined with the reaction mixture 200. As illustrated in Figure 1, hydrogen containing gas is introduced into the decaying unit 202 along with the stream 103 and therefore combined with the reaction mixture 200 in the unit. However, it should be clear that hydrogen containing gas may be combined with the reaction mixture or any of the components of the reaction mixture200 prior to the introduction of the reaction mixture 200 into the shear unit 202. Alternatively, the hydrogen containing gas may be combined with the reaction mixture. reaction mixer 20 on upgrading unit 204.

After formation of the heavy hydrocarbon oil dispersion, with or without combination with hydrogen containing gas, the heavy hydrocarbon oil dispersion is introduced into upgrading unit 204 through stream 104 at an appropriate point, depending on the project. The hydrogen containing gas may also be introduced into the upgrading unit 204 at a suitable point of gas separator 206 along with stream 106.

Regardless of the source, the hydrogen-containing gas is preferably preheated using preheating devices known to those skilled in the art prior to insertion into the upgrading unit 204, the scrubbing unit 202, or any of the components of the reaction mixture. This invention may be generated elsewhere in the refinery, such as an FCC effluent, or may be purchased "over the counter" from a supplier. Therefore, while Figure 1 shows hydrogen containing gas originating from both stream 103 and gas separator 206, it should be clear that hydrogen containing gas can be introduced into the scrambling unit 202 or upgrading unit 204 from any source known to those skilled in the art. in the area.

An alternative to purchasing hydrogen-containing gas from a supplier is shown in Figure 1. Alternatively, hydrogen-containing gas is obtained from the reactors in the upgrading unit 204 by purifying the reactor outlet gases under pressure, as described in Order No. U.S. Patent No. Serial No. 10 / 788,947, filed September 1, 2005, which is incorporated herein in its entirety. In a specific preferred embodiment, the hydrogen containing gas contains 90% or more hydrogen and is therefore referred to as "high purity hydrogen". The term hydrotreatment includes processes such as hydrocracking and hydrogenation.

Within the upgrading unit 204, the oil of the reaction mixture 200 is converted to the desired light oil end product. The upgrading unit 204 may include a single reactor or multiple reactor units, either in parallel or in series. In a preferred embodiment, upgrading unit 204 comprises two series reactor assemblies.

In a specific embodiment, an additional charge of the heavy hydrocarbon crude oil dispersion is introduced into the upgrading unit reactor 204 together with current 104 at a point between the reactor series so that the two reactors operate at approximately the same temperature. Reactors are generally operated in the temperature range of about 400 ° C to about 500 ° C, with a pressure range of about 35.15 kg / cm2 (500 psi) to about 154.68 kg / cm2 ( 2200 psi), preferably between 35.15 kg / cm2 (500 psi) and more preferably between 70.31 kg / cm2 (1000 psi) and 84.37 kg / cm2 (1200 psi), and with a flow rate in the range of about 19l / day (5 gal / day) and about 100,000 BBL / day. In a preferred embodiment, the reactor is designed for upstream operation, with each reactor having its own power distribution system. Other reactor schemes may be suitable and therefore used within the scope of the present invention.

While not wishing to be bound by any theory, the Applicant believes that the main reaction occurring within the reactors of upgrading unit 204, where hydrocarbon cracking, which is crude heavy hydrocarbon oil, generates most of the light oil product.

In another embodiment, the catalyst, or additional catalyst, may be introduced directly into the reactors ((not shown in Figure 1) of the downgrading unit 204 in a variety of ways, including, but not limited to, a mixture with the heavy hydrocarbon oil feed, by co-injection with heavy oil crude oil feed dispersion, or by direct injection into the deupgrading reactor 204.

The catalyst in the catalyst stream 101 preferably contains a transition metal, a compound containing a transition metal, or mixtures thereof, wherein the transition metal is selected from the elements of groups V, VI and VIII of the Periodic Table of Elements. More preferably, the transition metal is selected from the group wherein the metal is vanadium, molybdenum, iron, cobalt, nickel, or combinations thereof. Both dispersion and oil-soluble transition metal compounds can be used in the catalyst, including metal naphthenates, metal sulfates, polyionic anion ammonium salts, MOLYVAN ™ 855, which is a patented material of an organic amide molybdenum complex (Reg. CAS No. 64742-52-5), containing 7 to 15% demolbdenum, commercially available from RTVanderbilt Company, Inc. of Norwalk, Connecticut, USA, Molybdenum HEX-CEM, which consists of a proprietary blend containing 15% Molybdenum 2-ethyl hexanoate available from Mooney Chemicals, Inc. of Cleveland, Ohio, USA, and other similar compounds. MOLYVAN ™ 855 contains four component systems and can serve as an excellent upgrading catalyst. However, it should be clear that other suitable catalysts, which are highly oil soluble, having a relatively high demolibdenum charge, may also be suitable catalysts.

In addition, an effluent stream containing transition metals, for example from a polyolefin / methyl t-butyl ether process, containing from 2 to 10% molybdenum in an organic medium, which is mainly composed of demolibdenum glycol ethers, is also a source. Furthermore, the addition of certain inorganic particles, including nickel and vanadium, to the catalyst stream 105 has been shown to increase yield and reduce the density of the final light oil product.

The heavy hydrocarbon crude oil feedstock typically has a sulfur content of about 3%. By reacting a portion of the heavy hydrocarbon crude oil dispersion in the upgrading unit 204 of the present invention with a molybdenum-based catalyst, such as the MOLYVAN ™ family of catalysts, and a mixture containing vanadium and nickel compounds, the sulfur content is reduced to a value in the range between about 1.2% and 1.5%. Therefore, the processes of the present invention are capable of removing sulfur from heavy crude oil.

In one embodiment of the present invention, the gas by-product is removed from the upgrading unit 204 together with stream 105 and introduced into separator 206. useful gases derived from the separation process, including hydrogen and gaseous hydrocarbons, may be recirculated to the unit. upgrading 204 from the gas separator 206 by transferring such elements and compounds together with stream 106 to the upgrading unit 204. Alternatively, the hydrocarbon gases may be sent to an FCC unit.

In a preferred embodiment, the off-gas hydrogen sulphide (or off-gas) is separated from the gaseous by-product in the gas separator 206 and recirculated to the upgrading unit 204 together with chain 106 to sulfate the catalyst in the deupgrading unit 204. Alternatively , the hydrogen sulfide gas may be recirculated to the shredding unit 202, or anywhere else along the process to sulfate the catalyst. In such an embodiment, at least a part of the hydrogen sulfide gas generated during the separation process of the reaction product in the gas separator 206 is re-introduced into the deupgrading unit 204. Preferably, this hydrogen sulfide gas is mixed with the dispersion of feed of heavy hydrocarbon crude oil prior to normal injection of upgrading unit 204, that is, into decaying unit 202 or together with stream 104 before entering upgrading unit 204. Sulfated catalyst is believed to increase the yield of light oil products boiling points below 538 ° C (1000 ° F). In addition, such a presulphide operation reduced operating cost and was shown to improve the chemical kinetic upgrading reaction as a whole. Experiments conducted in the absence and presence of H2S or CS2 narration demonstrated that the presence of sulfur compounds improves the quality of the light oil product, for example with higher distillate yield and asphaltenes content.

Those skilled in the art will appreciate the cost and performance benefits of in situ activation and transition metal catalyst sulfurization. In state-of-the-art processes, such steps are conducted in the form of stepped steps within the reactor, or in a separate part of the refining unit. By conducting the in situ sulfurization activation step according to the present invention, the standstill reactor time required to perform the sulfidation steps on the upgrading reactor itself, and the capital costs of separate units, are eliminated. Additional savings can be obtained by eliminating the conventional gas flushing steps conducted in the synthesis gas production.

The upgrading unit product stream 107 leaving the upgrading unit 204 consists of a mixture that includes heavy hydrocarbon crude oil and light oil residues. When olefins are the most desired products, stream 107 can be separated into a light oil fraction and a heavy oil fraction. Conventional separation technology can be used to separate components from the product stream 107 of the deupgrading unit. As shown in Figure 1, the first separator 208 is used to separate the product stream 107 from the upgrading unit into the light oil stream 108 and the heavy oil residue stream 109. Preferably, the second separator 210 also separates the light oil from from heavy oil waste stream 109. This second light oil stream 110 may then be combined with the first light oil stream 108 on the secondary upgrading unit 212 for further processing. Alternatively, one or both light oil streams108 and 110 may be final products.

In a preferred embodiment of the present invention, the heavy hydrocarbon crude oil residue in the heavy crude oil waste stream 109 is firstly separated from the product stream 107 of the upgrading unit in the first separator 208, which is a heated separator. also separated into the first separator 208 and carried along with the light oil stream. However, most of the light oil is separated from the heavy crude oil residue stream 107 in the second separator 210, which is a cold separator. The light oil is then removed from the second separator 210 together with the light oil chain 110.

If light oil streams 108 and 110 are end products, the light oil may be stabilized by bubbling nitrogen or other inert gas through it to remove any dissolved gases. Light oil in the form of end products may be used elsewhere in the refining unit, or could be used as a preferred solvent to separate hydrogen from the off-gas in the gas separator 206.

In addition, light oil streams 108 and 110 may be further processed into one or two secondary upgrading units 212 for the formation of ultra pure fuels, which are removed from the secondary upgrading unit 212 together with chain 111. Secondary upgrading may be accomplished. one- or two-step processes. Distilled fuels may also be formed from the secondary grading unit 212, or stream 111, and thus separated from ultra pure fuels together with stream 112.

In another specific embodiment, the distillate fuel stability may be increased by homogenization of the heavy hydrocarbon crude oil waste streams 109, 111. By the crude processing of heavy hydrocarbon crude oil 109, 111, in detail, the asphaltenes agglomerates and other sediments are reduced. in size, which increases the stability of distilled fuels.

In one embodiment of the present invention, an oil waste stream part 109, 111 may be used as feed for the Fluid Catalytic Cracking Unit (FCC).

In another embodiment, the heavy broadcaster crude oil waste streams 109, 111, and light gases from upgrading equipment 204 and 212, are passed to an FCC unit to maximize oil conversion. During desulphurization and upgrading of petroleum, a significant amount of light gases such as methane, ethane and propane are released. It is an object of the present invention to maximize the benefit of low-level light gases, which are of low value compared to chemical raw materials such as olefins. Cracked products from the FCC unit can be separated to receive the cracked product and the oxide catalyst. The cracked product will contain at least one low sulfur gasoline stream, one olefin feedstock and a heavier current than gasoline. Heavy fractionation naphtha is recirculated to the column reactor.

Heavy hydrocarbon crude oil waste stream 111 from second separator 210, or, if no second separator 210 is used, heavy hydrocarbon crude oil waste stream 109 may be used in higher added value products such as feed A, together with stream 301 for use in forming carbon fiber materials. Heavy hydrocarbon residue oil rising streams109 and 111 have been found to have a boiling point in the range of 400 ° C to 520 ° C and is a suitable feedstock for the production of carbon fiber materials. Therefore, in another aspect of the present invention, a carbon fiber feed may also be formed from cruppled oil.

Heavy hydrocarbon crude oil waste streams 109 and 111 can also be used in higher value-added products such as feed B along with stream 302 for use in asphalt production for road applications or as asphalt suspension combustion materials - Water energy nageration.

It is well known that asphalt quality can be improved by the addition of sulfur. Therefore, in one embodiment, the asphalt quality of the separated material is improved by the addition of elemental sulfur as indicated in Figure 1 with respect to feed B as the process part for the production of asphalt or asphalt-water suspension combustion materials. power.

Alternatively, heavy hydrocarbon oil waste streams 109 and 111 may be recirculated together with stream 303 back to shear unit 202 for further refining.

In one embodiment of the present invention, at least a portion of light gases, for example methane, is used as fuel for a combustion unit that heats up the upgrading unit 204 or the shredding unit 202. In such embodiment, a conventional combustion unit is used. As an option, combustion is conducted after a small amount of Cao is introduced with the asphalt, in which case sulfur emission is significantly reduced during combustion. In yet another embodiment of the present invention, a portion of the reaction mixture 200 may have a boiling point. below 538 ° C (1000 ° F). Such part may be subjected to hydrotreatment while still hot in a process called secondary hydrotreatment or integrated hydrotreatment. Such secondary hydrotreating of such a portion of the reaction mixture 200 may be effected using hydrotreating conditions known to those skilled in the art. Secondary hydrotreatment generally involves reacting such part of reaction mixture 200 with a hydrogen-containing gas in the presence of a supported metal oxide catalyst under elevated pressure and temperature conditions. Catalysts that may be used in the integrated hydrotreating process of such an embodiment may be selected from several commercially available catalysts, including Criterion TEX-2719 catalyst, a commercially available silica-supported, alumina-supported molybdenum oxide / deniquel oxide catalyst; Criterion HDS-2443 catalyst, a commercially available alumina-supported molybdenum oxide / deniquel oxide catalyst promoted by silica and phosphorus oxide; and Criterion 424 catalyst, a commercially available alumina supported molybdenum oxide / deniquel oxide catalyst promoted by phosphorus oxide, and other similar catalysts. All of the above catalysts are available through CriterionCatalysts from Houston, Texas, USA. Another alternative is the use of the Akzo Nobel catalyst called Nebula, which provides high activity.

The following example is included herein to demonstrate various embodiments of the invention. It will be appreciated by those skilled in the art that the techniques described in the following examples represent techniques invented by the Applicant for proper operation in the practice of the invention and, therefore, may be regarded as constituting preferred modes for its practice. However, those skilled in the art will appreciate in light of the present disclosure that various changes may be made in the specific embodiments described and still obtain a similar or similar result without departing from the spirit and scope of the invention.

EXAMPLE

In the following example, the heavy hydrocarbon oil feed is a heavy oil having the characteristics shown in Table 1 as follows:

Table 1

<table> table see original document page 34 </column> </row> <table>

This heavy crude oil was pretreated by an ultrasonic and shear system in the presence of gaseous hydrogen to disperse the system. To such a mixture sufficient commercially available MOLYVAN ™ 8 55 was added to provide a concentration of 100 ppm in the heavy crude oil dispersion. After proper conditioning of the crude oil dispersion was completed, the dispersion reacted in a well stirred reactor of the upgrading unit 204 with hydrogen gas at a temperature of about 430 ° C and a pressure of about 105.5 kg / cm2 (1500 (psi)). within the dispersion of crushed oil LHSV 1.0.

The light oil product was TH separated from the reaction product for the production of an oil having the properties of Table 2.

Table 2

Net product <table> table see original document page 35 </column> </row> <table>

The light oil product of this example was obtained after hydrotreating the improved product in secondary de-grading unit 212.

The API density of the light oil product of this example was significantly high, indicating a lighter oil product. In addition, a beneficial reduction in asphaltenes concentration and sulfur and metal concentration was observed.

As described above, a sulfur removing byproduct of the heavy crude oil consists of H2Sgasoso. Therefore, in an alternate embodiment, the process generated H2Sgasous is reinjected into the empty reservoirs to minimize total sulfur removal and sulfur unit costs.

Although the compositions and methods of the present invention have been described in terms of preferred embodiments, it will be clear to those skilled in the art that variations may be applied to the process described herein without departing from the concept, spirit and scope of the invention. All of these similar substitutions and modifications clear to those skilled in the art are considered to be within the spirit, scope and concept of the invention and are set forth in the claims. As an example, the oil and catalyst may be combined in the cracking unit to form reaction mixture. Additionally, the hydrogen containing gas may be combined with the reaction mixture after the reaction mixture enters the upgrade unit. In addition, hydrogen containing gas may be introduced into the processes of the present invention together with one or both of the upstream 103 or 106.

Claims (35)

1. A process for the refining of sulfur-containing heavy hydrocarbon oil, comprising the steps of: (a) combining a part of the heavy hydrocarbon oil with an oil-soluble catalyst to form a reaction mixture, wherein the catalyst is capable of hydrogenating at least a part of the (b) heat and stir the reaction mixture for a time sufficient to form a pretreated petroleum, wherein at least a portion of the heavy hydrocarbon oil in the pretreated petroleum is sheared, (c) combine a hydrogen-containing gas with the pretreated oil to form a pretreated feedstock d) reacting the pretreated feedstock under relatively low hydrogen pressure and for a sufficient amount of time to form a product stream, wherein a first part of the product stream includes an oil lightweight having a higher API density than petroleum API density heavy hydrocarbon oil and lower sulfur concentration than heavy hydrocarbon oil, a second part of the product stream includes a heavy oil waste, and a third part of the product stream includes a light hydrocarbon gas; e) separate the product stream in a light hydrocarbon gas stream, a light oil stream and a heavy oil waste stream; and f) injecting a portion of the light hydrocarbon gas stream into a cracking unit to produce streams containing hydrogen and at least one oil. The process according to claim 1, further comprising placing hydrogen sulfide in contact with the catalyst, wherein at least one catalyst part is sulfated. The process of claim 2 further comprising forming a dispersion of the petroleum feedstock having the petroleum and a dispersed catalyst prior to contacting the catalyst with hydrogen sulfide. The process according to claim 1, wherein the hydrogen-containing gas includes at least 90% by weight of hydrogen. The process according to claim 1, wherein the catalyst is at least partially soluble in heavy hydrocarbon oil and includes a metal-transferring selected from elements in group Y, group VI and group VIII of the Periodic Table of Elements, and mixtures thereof. . The process according to claim 5, wherein the catalyst is a transition metal compound wherein the metal is selected from the group consisting of molybdenum, iron, cobalt, nickel and combinations thereof. The process according to claim 1, wherein the catalyst is selected from the group consisting of iron naphthenate, demolibdenum naphthenate, an organic amideorganic molybdenum complex in petroleum processing oil, deammonium molybdate, 2-ethyl molybdenum hexanoate, mixtures of etherglycolic and molybdenum and combinations thereof. The process according to claim 1, wherein the heavy hydrocarbon oil and catalyst are mixed using a rotor-stator system or an ultrasonic device. The process according to claim 1, wherein the heavy hydrocarbon oil and catalyst are mixed using an ultrasonic device. The process according to claim 1, wherein the pretreated feedstock reacts at a temperature in the range of about 400 ° C to about 500 ° C and a pressure in the range of about 35.15 kg / kg. cm2 (500 psi) at about 154.68 kg / cm2 (2200 psi). The process according to claim 1, wherein the heavy hydrocarbon oil contains a first sulfur concentration and the light oil contains a second sulfur concentration and wherein the second sulfur concentration is lower than the first sulfur concentration. The process according to claim 1, wherein the light oil is further refined to form a fuel. The process according to claim 12, wherein the fuel is homogenized, thereby increasing fuel stability. The process according to claim 1, wherein at least a portion of the heavy oil residue is recirculated for further refining by combining the heavy oil residue part with the reaction mixture. The process according to claim 1, wherein at least a portion of the heavy oil residue is further processed to carbon fiber formation. The process according to claim 1, wherein a portion of the heavy oil residue is further processed to asphalt formation. The process according to claim 16 wherein sulfur is combined with the heavy oil waste part as part of further processing of the heavy oil waste part to form asphalt. The process of claim 1 further comprising the step of: separating at least one outlet gas from the pretreated raw material. The process according to claim 18 wherein at least one of the outlet gases is a hydrogen containing exhaust gas. The process according to claim 19, wherein the hydrogen containing outlet gas is recirculated by combining a portion of the hydrogen outlet gas with the pretreated feedstock. The process according to claim 19, wherein the hydrogen containing outlet gas includes at least 90% by weight of hydrogen. The process according to claim 19, wherein the hydrogen containing outlet gas is hydrogen sulfide. The process of claim 18 further comprising the step of: injecting at least one of the outlet gases into a reservoir. The process of claim 1 further comprising the step of: hydrogenating a portion of the product stream having a boiling point below 538 ° C (1000 ° F). The process according to claim 1, wherein the heavy hydrocarbon oil includes an oil selected from the group consisting of full oil, desalinated oil, top oil, dephthalated oil, vacuum gas oils, petroleum residues, petroleum dispersions. , dispersions of heavy oil hydrocarbon fractions and mixtures thereof. The process according to claim 1, wherein the catalyst is a hydrotreating catalyst. The process according to claim 1, wherein the catalyst is sulfated in the reaction mixture. The process according to claim 1, wherein the catalyst is sulfated before being combined with heavy hydrocarbon oil. The process according to claim 1, wherein the catalyst is sulfated in situ by the addition of a decomposable sulfur compound to the reaction mixture before stirring and heating the reaction mixture. The process of claim 1 further comprising the step of: heating the light oil. The process according to claim 1, wherein the catalyst also comprises at least one catalyst promoter. The process according to claim 31, wherein the catalyst promoter is selected from the group consisting of phosphorus, silica, zeolites, alkaline and alkaline earth metal oxides, and detal combinations. 33. A sulfur-containing petroleum desulphurization process, comprising: (a) hydrodesulphurizing a sulfur-containing oil feed using an oil-soluble catalyst in a petroleum desulphurization unit to obtain a desulphurized oil, (b) separating the desulphurized oil into a fraction light gas fraction, a light oil fraction, a heavy oil fraction and a residual fraction, (c) pass a part of the light oil fraction and part of the heavy oil fraction in combination with hydrogen to a reaction zone of a secondary deupgrade unit. (d) hydrocracking the oil fraction portion and the heavy oil fraction portion in the reaction zone of the secondary upgrade unit for the production of an effluent; (e) passing a portion of the residual fraction and a portion of the light gas fraction through a catalytic fluid decay unit; and (f) cracking the portion of the residual fraction apart from the light gas fraction in the catalytic fluid cracking unit to produce at least one light olefin and at least one aromatic product. 34. A process for providing a reduced sulfur fuel and a commodity product, the process comprising: (a) hydrodesulphurizing an oil feed using an oil-soluble catalyst in a petroleum desulphurization unit to obtain a desulphurized hydrotreated oil; (b) fractionate the hydrotreated oil into at least one gaseous product, a light oil fraction and a heavy oil fraction, (c) crack the heavy oil fraction together with each of the at least one light gases in a single reactor of a fluid catalytic cracking unit. presence of a cracking catalyst and a sulfur removal catalyst for the production of at least one cracked product and an exhausted catalyst (d) separating at least one exhausted cracked catalyst product into a separator; and (e) fractionating at least one cracked product to produce a hydrogen-containing gas stream and a low sulfur gasoline stream, an olefinic feedstock stream, and a heavier stream than gasoline. The process of claim 34 further comprising the steps of: (a) obtaining a heavy naphtha from the fractionation of step (e) and recirculating the heavy naphtha to the column reactor; and (b) obtain a hydrogen-containing gas from fractionation and combine the hydrogen-containing gas with desulphurized hydrotreated oil.