1. Field of the Invention
This invention relates to oxidative desulfurization and more particularly to a process and system for integrated oxidative desulfurization and fluid catalytic cracking of liquid hydrocarbon feedstocks.
2. Description of Related Art
In conventional oil refinery operations, various processes occur in discrete units and/or steps. This is generally due to the complexity of naturally occurring whole crude oil mixtures, and the fact that crude oil feedstocks processed at refineries often differ based on the location and age of the production well, pre-processing activities at the production well, and the means used to transport the crude oil to the refinery plant.
Two very important and conventionally separate refining processes include desulfurization to reduce the organosulfur compounds present and fluidized catalytic cracking (FCC) for converting heavy hydrocarbon, including gasoils and residues into lighter hydrocarbon fractions.
Desulfurization is a vital step in refining hydrocarbons into transportation and heating fuel. The discharge into the atmosphere of sulfur compounds during processing and end-use of the petroleum products derived from sulfur-containing sour crude oil poses health and environmental problems. Stringent reduced-sulfur specifications applicable to transportation and other fuel products have impacted the refining industry, and it is necessary for refiners to make capital investments to greatly reduce the sulfur content in gas oils to 10 parts per million by weight (ppmw) or less. In the industrialized nations such as the United States, Japan and the countries of the European Union, refineries have already been required to produce environmentally clean transportation fuels. For instance, in 2007 the United States Environmental Protection Agency required the sulfur content of highway diesel fuel to be reduced 97%, from 500 ppmw (low sulfur diesel) to 15 ppmw (ultra-low sulfur diesel). The European Union has enacted even more stringent standards, requiring diesel and gasoline fuels sold in 2009 to contain less than 10 ppmw of sulfur. Other countries are following in the footsteps of the United States and the European Union and are moving forward with regulations that will require refineries to produce transportation fuels with ultra-low sulfur levels.
To keep pace with recent trends toward production of ultra-low sulfur fuels, refiners must choose among the processes or crude oils that provide flexibility that ensures future specifications are met with minimum additional capital investment, in many instances by utilizing existing equipment. Conventional technologies such as hydrocracking and two-stage hydrotreating offer solutions to refiners for the production of clean transportation fuels. These technologies are available and can be applied as new grassroots production facilities are constructed. However, many existing hydroprocessing facilities, such as those using relatively low pressure hydrotreaters, represent a substantial prior investment and were constructed before these more stringent sulfur reduction requirements were enacted.
With the increasing prevalence of more stringent environmental sulfur specifications in transportation fuels mentioned above, the maximum allowable sulfur levels are being reduced to no greater than 15 ppmw, and in some cases no greater than 10 ppmw. This ultra-low level of sulfur in the end product typically requires either construction of new high pressure hydrotreating units, or a substantial retrofitting of existing facilities, e.g., by incorporating gas purification systems, reengineering the internal configuration and components of reactors, and/or deployment of more active catalyst compositions.
Sulfur-containing compounds that are typically present in hydrocarbon fuels include aliphatic molecules such as sulfides, disulfides and mercaptans as well as aromatic molecules such as thiophene, benzothiophene and its long chain alkylated derivatives, and dibenzothiophene and its alkyl derivatives such as 4,6-dimethyl-dibenzothiophene.
Aliphatic sulfur-containing compounds are more easily desulfurized (labile) using conventional hydrodesulfurization methods. However, certain highly branched aliphatic molecules can hinder the sulfur atom removal and are moderately more difficult to desulfurize (refractory) using conventional hydrodesulfurization methods.
Among the sulfur-containing aromatic compounds, thiophenes and benzothiophenes are relatively easy to hydrodesulfurize. The addition of alkyl groups to the ring compounds increases the difficulty of hydrodesulfurization. Dibenzothiophenes resulting from addition of another ring to the benzothiophene family are even more difficult to desulfurize, and the difficulty varies greatly according to their alkyl substitution, with di-beta substitution being the most difficult to desulfurize, thus justifying their “refractory” appellation. These beta substituents hinder exposure of the heteroatom to the active site on the catalyst.
Conventional hydrodesulfurization processes can be used to remove a major portion of the sulfur from petroleum distillates for the blending of refinery transportation fuels. However, most hydrodesulfurization processing units cannot be operated efficiently for removal of sulfur from compounds where the sulfur atom is sterically hindered as in multi-ring aromatic sulfur compounds. This is especially true where the sulfur heteroatom is hindered by two alkyl groups (e.g., 4,6-dimethyldibenzothiophene). These hindered dibenzothiophenes predominate at low sulfur levels such as 50 to 100 ppm. Severe operating conditions, including higher hydrogen partial pressure, higher temperature, and higher catalyst volume, are conventionally applied to remove the sulfur from these sterically hindered compounds. The increase of hydrogen partial pressure can only be done by increasing the recycle gas purity, or by design and construction of new grassroots hydrodesulfurization units, which is a very costly option. Furthermore, the use of severe operating conditions results in yield loss, reduced catalyst cycle time and product quality deterioration.
The economical removal of refractory sulfur-containing compounds is therefore exceedingly difficult to achieve, and accordingly removal of sulfur-containing compounds in hydrocarbon fuels to an ultra-low sulfur level is very costly by current hydrotreating techniques. When previous regulations permitted sulfur levels up to 500 ppmw, there was little need or incentive to desulfurize beyond the capabilities of conventional hydrodesulfurization, and hence the refractory sulfur-containing compounds were not targeted. However, in order to meet the more stringent sulfur specifications, these refractory sulfur-containing compounds must be substantially removed from hydrocarbon fuels streams.
The development of alternative desulfurization routes has been widely studied and applied with varying degree of success, including the oxidative route where sulfur-containing compounds are oxidized. In oxidative desulfurization processes, sulfur-containing hydrocarbon compounds are converted to their respective oxides, i.e., sulfoxides and/or sulfones. The oxidized sulfur compounds are subsequently removed typically by extraction or adsorption.
Oxidative desulfurization of residual hydrocarbons boiling above 370° C. is a developing technology, and there remains little literature teaching effective processes. This is due to the nature of heavier hydrocarbon fractions, which contain elemental sulfur above 2 weight % (W %). The organic sulfur level is much higher because sulfur is in the hydrocarbon structure, and can be above 12 W % depending upon the molecular weight of the hydrocarbons in a particular fraction. Accordingly, oxidation of organic sulfur compounds followed by separation of the oxidized compounds can result in undesirable removal of large portion of the valuable hydrocarbon component. Hydrocarbons in these separated oxidized sulfur compounds must subsequently be recovered, e.g., by breakage of the carbon-sulfur bonds, in order to increase the overall hydrocarbon yield.
Another very important and ubiquitous operation in hydrocarbon refinery operations relates to catalytic conversion. There are two basic modes for catalytic conversion of hydrocarbon feedstocks. The first mode is catalytic conversion of hydrocarbons without the addition of hydrogen to the conversion zone, which is typically conducted at temperatures in the range of from about 480° C. to about 550° C. using a circulating stream of catalyst. The second mode is the catalytic conversion of hydrocarbon feedstock with added hydrogen at reaction conversion temperatures less than about 540° C. with the reaction zone comprising a fixed bed of catalyst.
This first mode, commonly referred to as fluid catalytic cracking (FCC), has the advantage of being performed without the added expense of in influent hydrogen stream, and is conducted at relatively low pressure, i.e., about 3 kg/cm2 to about 4 kg/cm2 or less. However, this mode is incapable of upgrading the hydrocarbon product by hydrogenation, and requires relatively high reaction temperatures which accelerate conversion of hydrocarbons into coke thereby decreasing the potentially greater volumetric yield of the normally liquid hydrocarbon product. This coke forms on the catalyst, therefore FCC processes require catalyst regeneration to burn off the coke and allow the catalyst to be recycled.
The second mode, commonly known as fixed bed hydrocracking processes, has achieved commercial acceptance by petroleum refiners, this process has several disadvantages. In order to attempt to achieve long runs and high on-stream reliability, fixed bed hydrocrackers require a high inventory of catalyst and a relatively high pressure reaction zone which is generally operated at 150 kg/cm2 or greater to achieve catalyst stability. In addition, two phase flow of reactants over a fixed bed of catalyst often creates uneven distribution within the reaction zone, resulting in inefficient utilization of catalyst and incomplete conversion of the reactants. Further, momentary misoperation or electrical power failure can cause severe catalyst coking which may require the process to be shut down for offline catalyst regeneration or replacement.
In conventional refinery operations, desulfurization and cracking of hydrocarbons are carried-out in separate unit operations, e.g., a fluid catalytic cracking unit to break the carbon-carbon bond to convert the high boiling point hydrocarbons into low boiling point hydrocarbons, and either hydrotreating to break the carbon-sulfur bond and convert sulfur into hydrogen sulfide or oxidative desulfurization processes where sulfur is oxidized into sulfoxides and/or sulfones and then removed from hydrocarbon streams.
Therefore, it would be desirable to increase the efficacy of the conventional cracking and desulfurization processes.