Patent Application
20090200205
1. Field of the Disclosure
Embodiments disclosed herein relate generally to processes for reducing the sulfur content in naphtha streams. More specifically, embodiments disclosed herein relate to a process for the extraction of sulfur-containing compounds from straight run gasoline.
2. Background
Petroleum distillate streams contain a variety of organic chemical components. Generally the streams are defined by their boiling ranges which determine the composition. The processing of the streams also affects the composition. For instance, products from either catalytic cracking or thermal cracking processes contain high concentrations of olefinic materials as well as saturated (alkanes) materials and polyunsaturated materials (diolefins). Additionally, these components may be any of the various isomers of the compounds.
The composition of untreated naphtha as it comes from the crude still, or straight run naphtha, is primarily influenced by the crude source. Naphthas from paraffinic crude sources have more saturated straight chain or cyclic compounds. As a general rule most of the “sweet” (low sulfur) crudes and naphthas are paraffinic. The naphthenic crudes contain more unsaturated and cyclic and polycylic compounds. The higher sulfur content crudes tend to be naphthenic. Treatment of the different straight run naphthas may be slightly different depending upon their composition due to crude source.
Reformed naphtha or reformate generally requires no further treatment except perhaps distillation or solvent extraction for valuable aromatic product removal. Reformed naphthas have essentially no sulfur contaminants due to the severity of their pretreatment for the process and the process itself.
Cracked naphtha as it comes from the catalytic cracker has a relatively high octane number as a result of the olefinic and aromatic compounds contained therein. In some cases this fraction may contribute as much as half of the gasoline in the refinery pool together with a significant portion of the octane.
Catalytically cracked naphtha gasoline boiling range material currently forms a significant part (˜⅓) of the gasoline product pool in the United States and is the cause of the majority of the sulfur found in gasoline. These sulfur impurities may require removal in order to comply with product specifications or to ensure compliance with environmental regulations, which may be as low as 10, 20 or 50 wppm, depending upon the jurisdiction.
The most common method of removal of the sulfur compounds is by hydrodesulfurization (HDS). During HDS, the petroleum distillate is typically passed over a solid particulate catalyst comprising a hydrogenation metal supported on an alumina base. Additionally, large amounts of hydrogen are included in the feed. After the hydrotreating is complete, the product may be fractionated or simply flashed to release the hydrogen sulfide and collect the now desulfurized naphtha. The loss of olefins by incidental hydrogenation is detrimental because it causes a reduction of the octane rating of the naphtha and the reduction in the pool of olefins for other uses.
In addition to supplying high octane blending components, cracked naphthas are often used as sources of olefins in other processes such as etherifications. The conditions of hydrotreating of the naphtha fraction to remove sulfur will also saturate some of the olefinic compounds in the fraction reducing the octane and causing a loss of source olefins.
Various proposals have been made for removing sulfur while retaining the more desirable olefins. Since the valuable olefins in the cracked naphtha are mainly in the low boiling fraction of these naphthas and the sulfur containing impurities tend to be concentrated in the high boiling fraction, the most common solution has been prefractionation prior to hydrotreating. The conventional prefractionation produces a light boiling range naphtha which boils in the range of C5 to about 250° F. and a heavy boiling range naphtha which boils in the range of from about 250-475° F.
The predominant light or lower boiling sulfur compounds are mercaptans while the heavier or higher boiling compounds are thiophenes and other heterocyclic compounds. The separation by fractionation alone will not remove the mercaptans. However, in the past the mercaptans have been removed by oxidative processes involving caustic washing. A combination oxidative removal of the mercaptans followed by fractionation and hydrotreating of the heavier fraction is disclosed in U.S. Pat. No. 5,320,742. In the oxidative removal of the mercaptans the mercaptans are converted to the corresponding disulfides.
U.S. Pat. No. 6,596,914 discloses a method for removing sulfur- and nitrogen-containing compounds from petroleum stocks using aqueous acetic acid. Such a process, as given in the background, may provide improved economics for smaller refiners, as very few have surplus hydrogen from their catalytic reforming units. Sulfur reduction requirements for gasoline and diesel fuels have eliminated most surplus hydrogen.
Other alternative methods to hydrogenation previously explored include solvent extraction, such as with methanol or ethanol, to extract the polar molecules. Another alternative is the oxidation and solvent extraction of the sulfur-containing compounds. However, oxidation reaction selectivity, safety, cost, and other concerns are considerable disadvantages of such processes.
U.S. Pat. No. 5,770,047 discloses a process for removing nitrogen-containing compounds from petroleum stocks using an aqueous acid solution, forming amine salts which are soluble in the aqueous phase. The aqueous acid may be hydrochloric acid, sulfuric acid, or nitric acid, at concentrations ranging from 0.001 mol/l to 0.010 mol/l. The removal of nitrogen-containing compounds may then be followed by standard hydrodesulfrization to remove sulfur-containing compounds.
U.S. Pat. No. 7,119,244, a crude alkylate containing butyl hydrogen sulfate was contacted with 98% H2SO4 and shaken vigorously for about 2 minutes. The resulting mixture was allowed to phase separate. The hydrocarbon phase contained 5.7 wppm total sulfur after the H2SO4 treatment.
U.S. Pat. No. 5,935,422 discloses a process for the removal of organic sulfur compounds from petroleum feedstocks using a regenerable sorbent, such as zeolite Y exchanged with an alkali or alkaline earth metal cation and impregnated with a group VIII metal.
U.S. Pat. No. 6,228,254 discloses a process for reduction of sulfur compounds from gasoline including first hydrotreating the gasoline followed by contacted the hydrotreated gasoline stream with a solid sorbent of liquid extractant to remove some or all of the remaining sulfur compounds. Liquid extractants disclosed therein include caustic and n-formylmorpholine.
As noted in several of the above references, the caustic wash, solvent extraction, oxidation/solvent extraction, and other processes may not be particularly suitable for removing the numerous types of organic sulfur compounds (e.g., mercaptans, thiophenes, mono- and di-sulfides, and other sulfur compounds) from the petroleum feedstock. For example, caustic wash processes typically cannot remove thiophenes.
Accordingly, there exists a need for a process to remove sulfur-containing compounds from petroleum feedstocks.
In one aspect, embodiments disclosed herein relate to a process for reducing the sulfur content of a gasoline fraction comprising one or more organic sulfur compounds including mercaptans, thiophenes, and mono-and di-sulfides, the process including: contacting a gasoline fraction having an initial organic sulfur content with a sulfuric acid-rich composition to extract organic sulfur compounds from the gasoline fraction and produce a gasoline fraction having reduced sulfur content and a sulfuric acid fraction having increased organic sulfur content; and separating the gasoline fraction having reduced organic sulfur content and the sulfuric acid-rich fraction having increased organic sulfur content.
Other aspects and advantages will be apparent from the following description and the appended claims.
In one aspect, embodiments disclosed herein relate to a process for reducing the sulfur content of a naphtha stream. In some embodiments, the process may include contacting a gasoline fraction having an initial sulfur content with a sulfuric acid-rich composition to extract organic sulfur compounds (sulfur-containing hydrocarbons). The process may result in the production of a gasoline fraction having reduced sulfur content and a sulfuric acid fraction having increased sulfur content. The gasoline fraction having reduced sulfur content and the sulfuric acid-rich fraction may then be separated. In some embodiments, the gasoline may be processed through a single extraction stage. In other embodiments, the gasoline may be processed through two or more extraction stages.
The present process is effective for reducing the sulfur content of a gasoline stream or gasoline. As used herein, a gasoline fraction includes individual refinery streams suitable for use as a blend stock for gasoline, or a blended gasoline stream formed by blending two or more streams, each of which are suitable for use as a gasoline blend stock. A suitable gasoline blend stock, when blended with other refinery streams, produces a combined stream which meets the requirements for gasoline, which requirements are well documented in Federal and State regulations.
The feed to the process may be a sulfur-containing petroleum fraction which boils in the gasoline boiling range, including FCC gasoline, coker pentane/hexane, coker naphtha, FCC naphtha, straight run gasoline, and mixtures containing two or more of these streams. Such gasoline blending streams typically have a normal boiling point within the range of 0° C. and 260° C., as determined by an ASTM D86 distillation. Feeds of this type include light naphthas typically having a boiling range of about C6 to 165° C. (330° F.); full range naphthas, typically having a boiling range of about C5 to 215° C. (420° F.), heavier naphtha fractions boiling in the range of about 125° C. to 210° C. (260° F. to 412° F.), or heavy gasoline fractions boiling at, or at least within, the range of about 165° C. to 260° C. (330° F. to 500° F.), preferably about 165° C. to 210° C. In general, a gasoline fuel will distill over the range of from about room temperature to 260° C. (500° F.).
Sulfur compounds present in these gasoline fractions occur principally as mercaptans, aromatic heterocyclic compounds, and mono- and di-sulfides. Relative amounts of each depend on a number of factors, many of which are refinery, process and feed specific. In general, heavier fractions contain a larger amount of sulfur compounds, and a larger fraction of these sulfur compounds are in the form of aromatic heterocyclic compounds. In addition, certain streams commonly blended for gasoline, such as FCC feedstocks, contain high amounts of the heterocyclic compounds. Gasoline streams containing significant amounts of these heterocyclic compounds are often difficult to process using many of the prior art methods described above. Very severe operating conditions have been conventionally specified for hydrotreating processes to desulfurize gasoline streams, resulting in a large octane penalty. Adsorption processes, used as an alternative to hydrogen processing, have very low removal efficiencies, since the aromatic heterocyclic sulfur compounds have adsorptive properties similar to the aromatic compounds in the hydrocarbon matrix.
Aromatic heterocyclic compounds that may be removed by the processes disclosed herein include alkyl substituted thiophene, thiophenol, alkylthiophene and benzothiophene. Among the aromatic heterocyclic compounds of particular interest are thiophene, 2-methylthiophene, 3-methylthiophene, 2-ethylthiophene, benzothiophene and dimethylbenzothiophene. These aromatic heterocyclic compounds are collectively termed “thiophenes.” Mercaptans that may be removed by the processes described herein often contain from 2-10 carbon atoms, and are illustrated by materials such as 1-ethanthiol, 2-propanethiol, 2-butanethiol, 2-methyl-2-propanethiol, pentanethiol, hexanethiol, heptanethiol, octanethiol, nonanethiol and thiophenol.
Sulfur in gasoline originating from these gasoline streams may be in one of several molecular forms, including thiophenes, mercaptans and mono- and di-sulfides.
For a given gasoline stream, the sulfur compounds tend to be concentrated in the higher boiling portions of the stream. Such a stream may be fractionated, and the heavier fraction treated using the processes described herein. Alternatively, the entire stream may be treated using the processes described herein. For example, light gasoline streams that are particularly rich in sulfur compounds, such as coker pentane/hexane, may be suitably treated as a blend stream which also contains a higher boiling, lower sulfur containing component.
In general, gasoline streams suited for treatment using the processes disclosed herein contain greater than about 10 ppm thiophenic compounds. Typically, streams containing more than 40 ppm thiophenic compounds, up to 2000 ppm thiophenic compounds and higher may be treated using the processes as described herein. The total sulfur content of the gasoline stream to be treated using the processes disclosed herein will generally exceed 50 ppm by weight, and typically range from about 150 ppm to as much as several thousand ppm sulfur. For fractions containing at least 5 volume percent boiling over about 380° F. (over about 193° C.), the sulfur content may exceed about 1000 ppm by weight, and may be as high as 4000 to 5000 ppm by weight or even higher.
After treatment according to the processes described herein, the sulfur content of the treated stream may be less than about 150 ppm in some embodiments; less than 100 ppm in other embodiments; less than 50 ppm in other embodiments; less than 40 ppm in other embodiments; less than 30 ppm in other embodiments; less than 20 ppm in other embodiments; less than 10 ppm in other embodiments; less than 5 ppm in other embodiments; and less than 1 ppm in yet other embodiments, where each of the above are based on weight. The gasoline may have a total sulfur content of less than 20 mg/l in other embodiments; less than 10 mg/l in other embodiments; and less than 5 mg/l in yet other embodiments.
Embodiments of the processes disclosed herein use sulfuric acid-rich compositions. Sulfuric acid-rich compositions are defined herein as compositions having at least 50 weight percent H2SO4. In some embodiments, the sulfuric acid-rich compositions may contain at least 80 weight percent H2SO4; at least 90 weight percent H2SO4 in other embodiments. In various embodiments, the sulfuric acid-rich composition may be fresh sulfuric acid, regenerated sulfuric acid, spent sulfuric acid, or combinations thereof. For example, spent acid from an alkylation process may be used.
The volume ratio of the sulfuric acid-rich composition to the gasoline may affect the separations achieved, depending upon contact time, organic sulfur compound concentration in the petroleum fraction, sulfuric acid concentration, and other process variables. In some embodiments, the volume ratio of the sulfuric acid-rich composition to the gasoline may be within the range of 0.01 to 500; ranging from 0.1 to 100 in other embodiments; ranging from 0.8 to 50 in other embodiments; and from 1 to 15 in yet other embodiments.
Petroleum fractions may also include components, such as benzene and toluene, which add significant octane value to the stream. Removal of these compounds may not be desired due to their contribution to the octane value or their use as a valuable end product if separated and purified. It has been found that sulfuric acid may extract these compounds from the gasoline fraction. However, shorter residence times have been found to adequately extract sulfur-containing compounds without extracting a significant amount of the benzene and toluene.
Extraction of sulfur compounds according to embodiments disclosed herein may result in little or no loss of these valuable hydrocarbon components. For example, a ratio of benzene and toluene in the product stream, the gasoline fraction having reduced sulfur content, to the benzene and toluene in feed stream, the gasoline fraction having an initial sulfur content, may be within the range from 0.95:1 to 1:1, based on weight. In other embodiments, a ratio of benzene and toluene in the product stream to that in the feed stream may be within the range from 0.97:1 to 1:1, based on weight.
It has been found that after an excessive amount of contact between the sulfuric acid-rich composition and the gasoline fraction may result in formation of sulfonates from various aromatics. Thus, systems according to various embodiments disclosed herein may provide for a limited residence time for contact of the sulfuric acid-rich composition and the gasoline fraction. Residence times for the contacting of the sulfuric acid-rich composition may be less than 15 minutes in some embodiments; less than 10 minutes in other embodiments; and less than 5 minutes in some embodiments. In other embodiments, the contact time may be less than 2 minutes; less than 1.5 minutes in other embodiments; less than 1 minute in other embodiments; less than 45 seconds in other embodiments; less than 30 seconds in other embodiments; and less than 15 seconds in yet other embodiments.
Following extraction of sulfur compounds from the gasoline fraction, at least a portion of the sulfuric acid-rich composition may be recycled to perform subsequent extractions. In other embodiments, the sulfuric acid-rich composition may be used in another process within the plant, such as an alkylation process. Each of these may be performed prior to or subsequent to additional processing, such as separation of the sulfuric acid from the sulfur-containing hydrocarbons. For embodiments where the contact time of the sulfuric acid-rich composition and the gasoline fraction is lengthy, recycle of the sulfuric acid-rich composition may not be desired.
Additionally, the sulfuric acid may be regenerated prior to recycle or reuse so as to remove the extracted sulfur-containing hydrocarbons. For example, at least a portion of the sulfur-containing hydrocarbons in the sulfuric acid fraction may be reacted to form a hydrocarbon fraction and at least one of hydrogen sulfide and sulfur dioxide. The hydrogen sulfide and the sulfur dioxide may then be converted to sulfuric acid by known processes, resulting in additional sulfuric acid for use in the system.
Contacting of the sulfuric acid and the gasoline fractions may be performed in a manner similar to that of sulfuric acid alkylation processes, including countercurrent and co-current processes. Similarly, contact of the sulfuric acid-rich composition with the gasoline fraction may be performed over a contact structure to enhance the contact of the two phases. In some embodiments, contact of the sulfuric acid-rich composition and the gasoline fraction may occur in a trickle bed.
Extraction of sulfur compounds from a gasoline fraction may occur in one or more contact stages as described herein. For example, two, three, or more trickle beds or other means to contact a sulfuric acid-rich composition and a gasoline fraction may be placed in series, where treated gasoline from a first stage contacting may be contacted with another sulfuric acid-rich composition in a second stage to remove additional sulfur compounds from the gasoline fraction. In this manner, it may be possible to extract sulfur from the gasoline fraction while avoiding the formation of sulfates due to the low residence time during each contact stage.
Referring now to
Contact of the gasoline fraction 12 and the sulfuric acid-rich composition 14 results in a partitioning of the sulfur-containing compounds between the two phases. Following contact, the two phases may be separated, such as through a coalescer or other suitable means to allow the phases to separate based upon their differing densities, resulting in a gasoline fraction of reduced sulfur content 18 and a sulfuric acid-rich composition containing organic sulfur compounds 20.
The treated gasoline fraction 18 may be recovered and processed further, such as through additional extraction stages, if necessary. Alternatively, gasoline fraction 18 may be used as a gasoline feedstock or blendstock.
As illustrated in
As shown in
Referring now to
Contact structures 34 may include any type of device or structure commonly used for contacting two liquids or for contacting vapors and liquids, including agitated vessels, static mixers, trickle beds, dispersers, and other structures known in the art. For example, a disperser material having at least 50 volume % open space up to about 99 volume % open space may be used. Disperser materials may include, for example, multi filament components and structural elements, e.g., knit wire. Other packings that may be used include random or dumped distillation packings, structured packings, and others, such as those described in U.S. Pat. No. 6,774,275, which is incorporated herein by reference.
Other suitable structures are disclosed in U.S. Pat. Nos. 5,730,843, 6,000,685, and 6,995,296, which are each incorporated herein in its entirety.
Other processes suitable for liquid-liquid extractions may also be used to extract organic sulfur compounds from a gasoline fraction as described above.
Single stage extractions are conducted on a straight run gasoline composition having approximately 199 mg/l total sulfur (about 60 weight percent mercaptans, 20 weight percent mono- and di-sulfides, 20 weight percent thiophenes, and other sulfur compounds), approximately 1.4 weight percent benzene and approximately 1.7 weight percent toluene, and a Bromine number of 0.3. The extractions are performed using the volume ratios of sulfuric acid to straight run gasoline as given in Table 1. The extractions are performed at ambient temperatures (about 22° C.) with fresh sulfuric acid (98 weight percent H2SO4, 2 weight percent water) and spent sulfuric acid (titrating as 90 weight percent H2SO4/water mixtures; for the purposes of describing the acid content, we use the terminology “titrates as” or “titrating as” to indicate a sulfuric acid/water mixture which has the same acidity, understanding that the spent acid mixture used herein is more complex in chemical makeup), as indicated. The total sulfur remaining in the straight run gasoline following the extractions is determined by ASTM D5453-93, the results of which are also given in Table 1.
In addition to the above results, the acid layer resulting from Extraction 4 was analyzed as titrating as an 89.5 weight percent H2SO4/water mixture, and containing 2.6 weight percent water (water content measured in an ABB BOMEN FT Near Infrared Spectrometer calibrated to determine water content in spent acid streams). The results given in Table 1 illustrate that a single extraction stage may effectively reduce the total sulfur content of a straight run gasoline stream. The results also indicate that spent acid may also be used to reduce the total sulfur content of a straight run gasoline; however, a higher volume ratio of spent acid may be required to obtain an equivalent reduction in sulfur content.
2 ml spent sulfuric acid (as defined above) is added to 100 cc aliquots of natural gasoline, predominately mixed C5's with a few percent aromatics. The mixtures are then agitated for various times from about 3 minutes to 3 hours. In one case, a “double wash” is performed, where a 100 cc aliquot is contacted with 2 ml acid for 2 minutes, phase separated, then contacted with another 2 ml spent acid for another 2 minutes. Similar conditions and analytical procedures as given in Example 1 are used. The results of the extractions are summarized in Table 2.
The extraction results shown in Table 2 indicate that contact time is an important variable to maximizing the amount of sulfur extracted, where contact times of 30 minutes and 3 hours result in a greater total sulfur content in the treated gasoline fraction than for the 12 minute or 3 minute extractions. The use of a double wash (more than one extraction stage) is effective at removing additional sulfur from the gasoline fraction without significant loss of aromatic content.
As described above, processes disclosed herein may provide for the extraction of sulfur-containing compounds from gasoline fractions. Advantageously, embodiments disclosed herein may provide for effective alternatives to the harsh conditions of hydrodesulfurization and other processes for sulfur removal. Processes disclosed herein may be especially advantageous for sulfur removal in straight run gasoline fractions, due to the limited infrastructure and the lower cost compared to hydrodesulfurization.
Additionally, as sulfuric acid is commonly used in refineries for alkylation processes, a supply of sulfuric acid is often readily available for use in processes disclosed herein. Further, sulfuric acid has been commonly used in refineries for decades, the safety and handling of which is known to those skilled in the art.
While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims.
