Patent Application
20140353209
This invention generally relates to a process for treating a naphtha stream.
Generally, regulations pertaining to motor gasoline specifications are requiring reduced amounts of total aromatics, such as lower concentrations of benzene, toluene, ethylbenzene, xylenes, methylethylbenzenes, trimethylbenzenes, propylbenzenes, and other aromatics having C10+ hydrocarbons. Typically, the largest component of the motor gasoline pool is the hydrotreated fluid catalytic cracking naphtha component, and this component may contain, unfractionated, up to 50-60%, by weight, aromatics. Hence, it would be desirable to remove these aromatic compounds from the fluid catalyst cracking naphtha while utilizing such molecules for other purposes.
One exemplary embodiment can be a process for treating a naphtha stream. The process may include providing the naphtha stream to a fractionation zone. The fractionation zone may include a fractionation column producing a first stream having one or more C5− hydrocarbons, and a second stream withdrawn at a lower elevation on the fractionation column than the first stream and having one or more C5+ hydrocarbons, and sending at least a portion of the second stream to an aromatics complex for producing at least one of benzene, toluene, and para-xylene.
Another exemplary embodiment can be a process for treating a naphtha stream. The process can include passing the naphtha stream to a thiol reduction zone, passing at least a portion of an effluent from the thiol reduction zone to a fractionation zone having a fractionation column, and obtaining a first stream having one or more C5− hydrocarbons, and a second stream withdrawn at a lower elevation on the fractionation column than the first stream and having one or more C5+ hydrocarbons.
A further exemplary embodiment may be a process for treating a naphtha stream. The process can include passing the naphtha stream to a thiol reduction zone, passing at least a portion of an effluent from the thiol reduction zone to a fractionation zone including a fractionation column, obtaining a first stream having one or more C5− hydrocarbons and a second stream withdrawn at a lower elevation on the fractionation column than the first stream and having one or more C5+ hydrocarbons, and passing the second stream through a first hydrotreating zone and then a second hydrotreating zone. Often, the second hydrotreating zone is at a second, higher reaction temperature then the first hydrotreating zone.
In one exemplary embodiment, a full-boiling range naphtha is sweetened and fractionated. The recovered fraction may be lighter than thiophene and be used as a low sulfur blending component of about 10-about 15 ppm, by weight. In another exemplary embodiment, the thiophene-rich, aromatic-rich, heavier fraction can be hydrodesulfurized in a selective hydrotreating stage having one or two stages with a cobalt-molybdenum catalyst. The selectively hydrodesulfurized product may be processed in a post-hydrotreating stage to remove recombination thiols and/or refractory sulfur species so that the product sulfur is typically about 0.1-about 0.5 ppm, by weight. As such, the high octane, low-aromatic fraction may be used as a blending component for motor gasoline, tert-Amyl methyl ether, or naphtha cracking technology, and the high-aromatic fraction can be processed in an aromatics complex for making petrochemicals.
As used herein, the term “stream” can include various hydrocarbon molecules, such as straight-chain, branched, or cyclic alkanes, alkenes, dialkenes, and alkynes, and optionally other substances, such as gases, e.g., hydrogen, or impurities, such as heavy metals, and sulfur and nitrogen compounds. The stream can also include aromatic and non-aromatic hydrocarbons. Moreover, the hydrocarbon molecules may be abbreviated C1, C2, C3 . . . Cn where “n” represents the number of carbon atoms in the one or more hydrocarbon molecules. Furthermore, a superscript “+” or “−” may be used with an abbreviated one or more hydrocarbons notation, e.g., C3+ or C3−, which is inclusive of the abbreviated one or more hydrocarbons. As an example, the abbreviation “C3+” means one or more hydrocarbon molecules of three carbon atoms and/or more. A “stream” may also be or include substances, e.g., fluids or substances behaving as fluids, other than hydrocarbons, such as air, hydrogen, or catalyst.
As used herein, the term “zone” can refer to an area including one or more equipment items and/or one or more sub-zones. Equipment items can include one or more reactors or reactor vessels, heaters, exchangers, pipes, pumps, compressors, and controllers. Additionally, an equipment item, such as a reactor, dryer, or vessel, can further include one or more zones or sub-zones.
As used herein, the term “rich” can mean an amount of at least generally about 50%, and preferably about 70%, by mole, of a compound or class of compounds in a stream.
As used herein, the term “substantially” can mean an amount of at least generally about 80%, preferably about 90%, and optimally about 99%, by mole, of a compound or class of compounds in a stream.
As used herein, the term “overhead stream” can mean a stream withdrawn at or near a top of a column, typically a distillation column.
As used herein, the term “bottom stream” can mean a stream withdrawn at or near a bottom of a column, typically a distillation column.
As used herein, the term “naphtha” can include one or more C5-C12 hydrocarbons and have a boiling point range of about 25-about 190° C.
As used herein, the term “sweetening” can refer to converting sulfur compounds, such as thiols, into other compounds, such as disulfide compounds.
As used herein, the terms “thiol” and “mercaptan” may be used interchangeably, and the terms “thiophene” and “thiofuran” may be used interchangeably.
As used herein, the term “alkali” can mean any substance that in solution, typically a water solution, has a pH value greater than about 7.0, and exemplary alkali can include sodium hydroxide, potassium hydroxide, or ammonia. Such an alkali in solution may be referred to as an alkaline solution or an alkaline.
As used herein, the term “hydrogenation” can refer to processing one or more hydrocarbons in the presence of hydrogen, and can include hydrotreating, hydrodesulfurizing, and/or hydrocracking.
As used herein, the term “hydrotreating” can refer to a process including contacting a hydrogen gas with hydrocarbon optionally in the presence of suitable catalysts primarily for removing heteroatoms, such as sulfur, nitrogen and metals from the hydrocarbon. Often in hydrotreating, hydrocarbons with double and triple bonds as well as aromatics may be saturated. Hydrodesulfurization can be similar to hydrotreating except primarily sulfur heteroatoms are removed from the hydrocarbon.
As used herein, the term “hour” may be abbreviated “hr”, the term “kilopascal” may be abbreviated “KPa”, the term “megapascal” may be abbreviated “MPa”, and the terms “degrees Celsius” may be abbreviated “° C”.
As used herein, the term “parts per million” may be abbreviated “ppm” and is typically expressed by weight.
The FIGURE is a schematic depiction of an exemplary naphtha treating apparatus.
Referring to the FIGURE, a naphtha treating apparatus 10 can include a thiol reduction zone 100, a fractionation zone 200, one or more hydrogenation zones 300, and an aromatics complex 400. At least a portion of a naphtha stream 40 including one or more C5-C12 hydrocarbons can be provided to the thiol reduction zone 100. The naphtha stream 40 can be obtained from any suitable source, such as an atmospheric distillation column, and may have a boiling point range of about 25-about 190° C. The naphtha stream 40 can be combined with an oxygen-containing stream 50 and an alkaline stream 60 to form a combined feed 80 before entering the thiol reduction zone 100. The oxygen-containing stream 50 may be from any suitable oxygen source, such as air. The alkaline stream 60 may optionally include a metal phthalocyanine compound, which is disclosed in, e.g., U.S. Pat. No. 2,882,224. The alkaline stream 60 may include a sodium hydroxide aqueous solution with a concentration of sodium hydroxide of about 1-about 40%, by weight, and optionally about 0.1-about 10%, by weight, of a metal phthalocyanine compound.
The thiol reduction zone 100 can include a reactor 120, which may be a vertical vessel including a fixed bed of contact material. The combined feed 80 can be provided above the fixed bed of contact material. A ring can be formed within the vessel and be formed integrally with a porous screen to define an annular separation zone. The contacting material may optionally support a suitable oxidation catalyst to promote the desired conversion of the mercaptans. As an example, an exemplary supported catalyst including a metal compound of tetrapyridinoporphyrazine is disclosed in, e.g., U.S. Pat. No. 3,923,645. The contacting material can take any suitable shape, such as spheres or cylindrical extrudates, and may include inert solids, such as charcoal, clay, silicate, diatomaceous earth, kieselguhr, kaolin, alumina, and/or zirconia. Generally, the thiol reduction zone 100 operates at a temperature of about 10-about 150° C., and a pressure of about 1,100-about 7,000 KPa. An exemplary thiol reduction zone 100 is disclosed in, e.g., U.S. Pat. No. 4,481,106. Alternatively, a heterogenous catalytic process may be utilized that sweetens by alkylating alkenes with thiols and saturates dialkenes to alkenes. An effluent 130 from the thiol reduction zone 100 can be passed to a fractionation zone 200, which may include a fractionation column 220.
The fractionation column 220 can provide a first stream 230 or overhead stream 230 including one or more C5− hydrocarbons and a second stream 240 or bottom stream 240 including one or more C5+ hydrocarbons. Often, the overhead stream 230 is rich or substantially has one or more C5− hydrocarbons and the bottom stream 240 is rich or substantially has one or more C5+ hydrocarbons. Generally, the first stream 230 is a cut lighter than thiophene with a low sulfur content of about 10-about 15 ppm, by weight, and the second stream 240 has components heavier than thiophene. The second stream 240 may be withdrawn at a lower elevation 244 from the first stream 230.
The second stream 240 can be provided to one or more hydrogenation zones 300. The one or more hydrogenation zones 300 can include a first hydrotreating zone 320 at a first reaction temperature effective to convert a portion of the sulfur content to hydrogen sulfide, and a second hydrotreating zone 340 at a second, higher reaction temperature with a catalyst effective to desulfurize. In at least one exemplary embodiment, the one or more hydrogenation zones 300 are, independently, one or more hydrodesulfurization zones.
The first hydrotreating zone 320 can remove sulfur from the second stream 240 while disfavoring alkene saturation to generally maintain octane level. Typically, the second stream 240 may be combined with a stream including hydrogen and introduced into the first hydrotreating zone 320. Suitable hydrotreating catalysts can include at least one metal from groups 6 and 8-10 of the periodic table, and can include one or more metals of iron, cobalt, nickel, platinum, palladium, molybdenum and tungsten on a support, such as silica and/or alumina support. Other suitable hydrotreating catalysts can include zeolitic components. More than one type of hydrotreating catalyst can be used in the same reaction vessel. The metal from groups 8-10 is typically present in an amount of about 0.5-about 20%, by weight, and the metal from group 6 is typically present in an amount of about 1-about 25%, by weight. An exemplary hydrocracking catalyst and methods of making thereof are disclosed in, e.g., U.S. Pat. No. 4,775,460.
The first hydrotreating zone 320 can operate at a temperature of about 260-about 320° C., a pressure of about 0.6-about 3.5 MPa, and a liquid hourly space velocity of the second stream 240 of about 0.5-about 10 hr−1. The first hydrotreating zone 320 may contain single or multiple reactors and each reactor, independently, may contain one or more reaction zones with the same or different catalysts to convert sulfur and nitrogen to hydrogen sulfide and ammonia. The first hydrotreating zone 320 can provide a first hydrotreating zone effluent 330.
The effluent 330 can be provided to the second hydrotreating zone 340. Optionally, the effluent 330 from the first hydrotreating zone 320 is fed through a preheater to raise the temperature to that required by the second hydrotreating zone 340. As further described below, hydrogen sulfide removed from the effluent 330 to the second hydrotreating zone 340 is generally unnecessary because the selected operating conditions generally minimize subsequent thiol formation. Often, the effluent 330 is combined with a stream including hydrogen before being introduced into the second hydrotreating zone 340 to further selectively remove sulfur.
The second hydrotreating zone 340 may be operated at selected hydrotreating conditions, such as a temperature of about 310-about 400° C., a pressure from about 0.60-about 3.5 MPa, a liquid hourly space velocity of the effluent 330 from about 0.5-about 15 hr−1. Other hydrotreating conditions are also possible depending on the particular feed stocks being treated. The second hydrotreating zone 340 may contain single or multiple reactors and each reactor may contain one or more reaction zones with the same or different catalysts to convert sulfur and nitrogen to hydrogen disulfide and ammonia.
The second hydrotreating zone 340 may include an optimized catalyst configuration having a layered or eggshell configuration with an inner core and an outer layer containing active, desulfurization metals. In such an aspect, the outer core has an active layer with a thickness optimized to favor desulfurization reactions over alkene saturation reactions. Often, the thickness of the outer layer is about 5-about 100 microns. In one exemplary embodiment, the layered catalyst composition includes an inner core composed of an inorganic oxide, which can have a substantially lower adsorptive capacity for catalytic metal precursors relative to the outer layer. Examples of refractory and non-refractory inorganic oxides suitable for the inner core may include alpha alumina, theta alumina, silicon carbide, metals, cordierite, zirconia, titania and a mixture thereof.
The inner core can be coated with an outer layer of a non-refractory inorganic oxide which is the same or different from the inorganic oxide that may be used as the inner core. Examples of non-refractory inorganic oxides suitable for the outer layer can include theta alumina, silicon carbide, metals, zirconia, titania, gamma alumina, delta alumina, eta alumina, silica/alumina, zeolites, non-zeolitic molecular sieves, hydrotalcite and a mixture thereof. In one exemplary embodiment, this outer layer of non-refractory oxide can have a relatively high surface area of about 50-about 200 m2/g based on the weight of the outer layer. In one aspect, the outer layer thickness may be between about 1-about 100 microns.
The pores in the outer layer of the catalyst may have a pore radius size distribution of about 20-about 250 Angstrom.
Optionally, the layered configuration can have dispersed by, e.g., impregnation, at least one metal from groups 6 and 8-10 of the periodic table, and can include one or more metals of iron, cobalt, nickel, platinum, palladium, molybdenum and tungsten. The metal from groups 8-10 is typically present in an amount of about 0.5-about 10%, by weight, and the metal from group 6 is typically present in an amount of about 1-about 25%, by weight. The metal can be present as an oxide. More than one type of hydrotreating catalyst can be used in the same reaction vessel. Exemplary hydrotreating zones and catalyst, including methods of making thereof, are disclosed in, e.g., U.S. Pat. No. 7,749,375.
Thus, the selective operating conditions in the second hydrotreating zone 340 may effectively convert about 80-about 90%, by weight, sulfur to hydrogen sulfide in order to preferably reduce sulfur levels to no more than about 10, preferably about 0.1-about 0.5, ppm, by weight. Simultaneously, the conditions may also minimize alkene saturation. Generally, the effluent 370 from the second hydrotreating zone 340 minimizes loss of octane rating.
One or two selective hydrotreating stages can be utilized as long as aromatics are preserved while at the same time meeting the requirements for downstream petrochemical uses by minimizing sulfur concentrations, e.g., about 0.1-about 0.5 ppm, by weight, sulfur. In one exemplary embodiment, a cobalt-molybdenum hydrotreating catalyst may be used with a reactor outlet pressure of at least about 1,800 KPa. Optionally, a post-treat hydrotreating stage may be added to prevent recombination of thiols and/or refractory sulfur species. The effluent 370 can be provided to an aromatics complex 400.
The aromatics complex 400 can include suitable zones for the manufacture of benzene, toluene, and one or more xylenes, including para-xylene. Such zones can include a naphtha hydrotreating zone, a reforming zone, an extraction zone, a transalkylation zone, a para-xylene-separation zone, an alkylaromatic isomerization zone, and one or more fractionation zones. The aromatics complex 400 can produce a benzene stream 410, a toluene stream 420, and one or more xylenes stream 430, which in this embodiment can be a para-xylene stream 430. An exemplary aromatics complex is disclosed in, e.g., U.S. Pat. No. 7,727,490. Typically, the one or more xylenes can be used as feed stocks for manufacturing polymers.
Although the effluent 370 can be provided to the aromatics complex 400, it should be understood that at least a portion of the effluent 330 from the first hydrotreating zone 320 may be provided as well if the sulfur concentration, e.g., about 0.1-about 0.5 ppm, by weight is sufficiently low in the effluent 330. Usually, the effluent 370 and/or 330 would not undergo a naphtha hydrotreating process to selectively hydrogenate alkenes to alkanes in the aromatics complex 400 as this conversion is typically accomplished in the hydrotreating zones 320 and/or 340. Alternatively, at least a portion of the effluents 370 and/or 330 due to their low sulfur content may be sent to gasoline blending instead of the aromatics complex 400.
Without further elaboration, it is believed that one skilled in the art can, using the preceding description, utilize the present invention to its fullest extent. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way whatsoever.
In the foregoing, all temperatures are set forth in degrees Celsius and, all parts and percentages are by weight, unless otherwise indicated.
From the foregoing description, one skilled in the art can easily ascertain the essential characteristics of this invention and, without departing from the spirit and scope thereof, can make various changes and modifications of the invention to adapt it to various usages and conditions.
