FIELD OF THE INVENTION

[0001] This invention relates to the hydroprocessing of naphtha with removal of mercaptan from product. More particularly, naphtha feedstock is hydrotreated and hydrocracked. Sulfur-containing contaminants are then selectively removed from the naphtha.

BACKGROUND OF THE INVENTION

[0002] Environmental regulations covering the sulfur content of fuels for internal combustion engines are becoming more stringent with regard to allowable sulfur in fuels. It is anticipated that motor gasoline sulfur content may need to meet a sulfur limit of 30 wppm by 2004 with possible further reductions mandated in the future. The feedstocks for motor gasoline are typically catalytically cracked naphthas that contain substantial amounts of sulfur and olefins.

[0003] A common method for reducing the sulfur content of feedstocks is by hydrotreating using catalysts that convert sulfur-containing species to hydrogen sulfide. The extent to which hydrotreating lowers the sulfur content of the hydrotreated product is typically dependent on the catalyst and hydrotreating conditions. For any given hydrotreating catalyst, the more severe hydrotreating conditions would be expected to reduce the sulfur content to the greater extent. However, such severe hydrotreating conditions normally result in a loss of molecules contributing to desirable octane properties either by cracking to non-fuel molecules or hydrogenation of olefins to molecules having lower octane rating. As the hydrotreating catalyst ages, it normally becomes necessary to adjust reaction conditions to maintain an acceptable catalyst activity. However, such adjustments result in further loss of desirable molecules contributing to high octane. This then results in increased production costs to produce high octane fuels because of the need to boost octane through added process steps such as isomerization, blending or addition of octane boosting additives.

[0004] One method for addressing the loss of octane problem is by sequential hydrotreating following by selective cracking. Naphtha is first hydrotreated which results in some octane loss. Octane is then restored by selective cracking using an intermediate pore zeolite such as ZSM-5, either alone or in combination, with other zeolites.

[0005] Another method for addressing the loss of octane problem is to fractionate cracked gasoline into a lower boiling fraction and a higher boiling fraction. The lower boiling fraction is desulfurized using a non-hydroprocessing step such as mercaptan removal by extraction. Removal of mercaptans from the lower boiling fraction can be accomplished by other means including hydroprocessing. The higher boiling fraction is hydrotreated and octane loss is addressed by treatment with a catalyst of acidic functionality followed by a final hydrotreatment to remove any mercaptans formed.

[0006] It would be desirable to have a method for removing sulfur contaminants from naphtha while minimizing the octane loss that accompanies hydrogenation. SUMMARY OF THE INVENTION

[0007] It has been discovered that a naphtha feed can be hydrotreated and mercaptans removed from the hydrotreated naphtha without the need for a further hydrotreatment step and with improved octane value and yield. Accordingly, the present invention comprises a process for removing C5+ mercaptans from a hydrotreated naphtha which comprises: (a) hydrotreating a naphtha feed in at least one hydrotreating step under catalytic hydrotreating conditions to form a hydrotreated naphtha, (b) conducting at least a portion of the hydrotreated naphtha to a cracking zone and hydrocracking the hydrotreated naphtha with a hydrocracking catalyst under hydrocracking conditions to form a hydrocracked naphtha and C5+ recombinant mercaptans, (c) separating C5+ recombinant mercaptans from hydrocracked naphtha by selective extraction or adsorption.

[0008] In a preferred embodiment, the selective extraction includes contacting the hydrocracked naphtha and C5+ recombinant mercaptans with a composition comprising water, alkali metal hydroxide, cobalt phthalocyanine sulfonate, and alkylphenols and having at least two phases, the first phase containing dissolved alkali metal alkylphenylate, dissolved alkali metal hydroxide, water and dissolved sulfonated cobalt phthalocyanine and the second phase containing water and dissolved alkali metal hydroxide.

[0009] Another embodiment for removing mercaptans from a hydrotreated naphtha comprises: (a) hydrotreating a naphtha feed in at least one hydrotreating step under catalytic hydrotreating conditions to form a hydrotreated naphtha, - A -

(b) conducting at least a portion of the hydrotreated naphtha to a cracking zone and hydrocracking the hydrotreated naphtha with a hydrocracking catalyst under hydrocracking conditions to form a hydrocracked naphtha and C5+ recombinant mercaptans, (c) contacting at least a portion of hydrocracked naphtha and C5+ recombinant mercaptans with a first phase of a treatment composition having at least two phases, said treatment composition containing water, alkali metal hydroxide, cobalt phthalocyanine sulfonate, and alkyl phenols, wherein (i) a first phase contains dissolved alkali metal alkylphenylate, dissolved alkali metal hydroxide, water and dissolved sulfonated cobalt phthalocyanine, and (ii) a second phase contains water and dissolved alkali metal hydroxide, and (d) separating an upgraded naphtha having less recombinant mercaptans than the hydrocracked naphtha.

[0010] In a preferred embodiment, the first and second phases are substantially immiscible and the first phase is separated into an upgraded naphtha and an extractant containing recombinant mercaptans. In another embodiment, hydrocracked naphtha and C5+ recombinant mercaptans are contacted with a first phase of a treatment composition having at least two phases under substantially anaerobic conditions. In yet another embodiment, the extractant containing recombinant mercaptans is contacted with an oxidizing amount of oxygen wherein the mercaptan is oxidized to disulfide. In another embodiment, the naphtha feed is first fractionated into a lower boiling fraction containing mercaptans and a higher boiling fraction containing sulfur heterocyclic compounds prior to the hydrotreating step. DETAILED DESCRIPTION OF THE INVENTION

[(JOl 1] The feedstocks used in the present process comprise petroleum fractions boiling in the gasoline boiling range. Such feeds include fluid catalytically cracked (FCC) naphthas, steam cracked naphthas and coker naphthas boiling from 650F to 48O0F (180C to 2210C) as determined by ASTM D-86. Such naphthas include light cracked naphthas, intermediate cracked naphthas, heavy cracked naphthas and full range naphthas. Naphthas typically contain paraffins, olefins, naphthenes and aromatics as well as heteroatom species containing nitrogen and sulfur. Olefin contents of naphthas can range up to 60 wt.%, based on naphtha with typical olefin contents in the range from 5 to 40 wt.%. Sulfur contents of naphthas may range from 50 to greater than 5000 ppmw, based on naphtha. Nitrogen contents for these feeds are typically less than 500 ppmw. Olefin, nitrogen and sulfur contents may be determined by standard analytical techniques.

[0012] With regard to olefin and sulfur contents of naphtha feedstocks, lighter cracked naphthas (lower boiling naphthas) typically have the highest amounts of olefins and highest amounts of mercaptan sulfur compounds whereas heavy cracked naphthas have the least amounts of olefins and the highest amounts of heterocyclic sulfur compounds such as thiophenes. The removal of sulfur compounds from the various naphtha feeds is a function of the type of sulfur compounds. For the lighter mercaptans (C4 or less) typical in lower boiling naphthas, extraction or other non-hydrogenation methods can be employed for removal. Hydroprocessing options are also available for lighter mercaptans. For heterocyclic sulfur compounds, hydrotreatment is a generally accepted means of removal by hydrogenating heterocyclic sulfur compounds to hydrogen sulfide. [0013] In the present process, the feedstock may be separated into a lower boiling traction and a higher boiling fraction, if desired. The lower boiling fraction is relatively rich in olefins and mercaptan sulfur compounds while the higher boiling fraction relatively poor in olefins and relatively rich in heterocyclic sulfur compounds. By relatively rich is meant that, of the amount of the compounds of interest present in the original feedstock, those compounds of interest are predominantly found in the fraction in question. In the case of olefins present in the feed, such olefins will predominantly concentrate in the lower boiling fraction upon fractionation of the feed. In the case of mercaptan sulfur compounds, such mercaptans will predominantly concentrate in the lower boiling fraction upon fractionation of the feed. By relatively poor is meant that of the amount of compounds of interest, e.g., olefins, present in the original feedstock, then those compounds of interest are not predominantly found in the fraction in question.

[0014] The distillation cut point between the lower and higher boiling fractions may vary to optimize the process. The exact numerical value of the cut point will vary according to the sulfur distribution, type of sulfur compounds present, olefin content and distribution, as well as the final product specifications. Normally, the cut point should be selected to keep the sulfur compounds which cannot be readily removed by extraction, i.e., heterocyclic sulfur compounds, in the higher boiling fraction so that they may be removed by hydrodesulfurization but some of the mercaptans may be included in the higher boiling fraction as well since they may be removed under mild hydrotreatment conditions, although this may result in a loss of the high octane olefins from the front end of the feed. Higher cut points will be preferred in order to minimize the amount of feed which is passed to the hydrotreater. Usually, the cut point will be in the range from 1000F to 23O0F (380C to HO0C) and in most cases will be in the range from 14O0F to 18O0F (6O0C to 820C), since the sulfur which is present in components boiling below 15O0F (650C) is mostly in the form of mercaptans which may be removed by non-hydro genative extractive processes, for example, the extractive Merox® process. The sulfur compounds in the higher boiling fractions, specifically the thiophenes and substituted thiophenes are not, however, amenable to removal by these conventional sweetening processes such as Merox® although they may be removed by hydrogenative processing. A cut point in the range 14O0F to 18O0F (6O0C to 820C) will suffice to put the thiophene in the heavy cut. Higher cut points between the two fractions may, however, be used in order to decrease the magnitude of any yield loss across the hydrogenation step of the process. For example, a cut point of 23O0F (11O0C) will leave thiophene in the lower boiling cut but give a better yield across the hydrogenation step.

[0015] The mercaptans present in the lower boiling fractions are typically in the C1 to C4 range. These mercaptans can be removed by conventional extraction processes such as Merox®. These conventional extraction processes may employ techniques based on caustic extraction or extraction using cresylates.

[0016] Caustic extraction may also be accomplished using the MEROX™ and EXTRACTIVE MEROX™ processes which are available from UOP Products, Des Plains, IL. In these processes, oxidation of the caustic phase is accomplished using an iron group-based catalyst. Phase transfer catalysts may be added to the extraction. Phase transfer catalysts are known additives which facilitate transport of a reactive anion from an aqueous phase to an organic phase in which it might ordinarily be insoluble. Examples of phase transfer catalysts include quaternary ammonium and quaternary phosphonium salts, e.g., a quaternary ammonium hydroxide such as tetraalkyl ammonium hydroxide. Phase transfer catalysts are typically used in the absence of oxygen during the extraction step. [0017] If the naphtha feed is fractionated, the higher boiling fraction is hydrotreated under hydrotreating conditions to desulfurize and denitrogenate this fraction. If the naphtha feed is not fractionated, then the naphtha feed may be directly hydrotreated under hydrotreating conditions. Hydrotreating catalysts are well known in the art and may include at least one Group 6, Group 9 or Group 10 metal, based on the IUPAC periodic table format having Groups 1-18. Preferred metals include at least one of Ni, Mo, Co or W on a refractory support such as silica, alumina, silica-alumina or titania. Preferred combinations of metals include Ni-Mo or Co-Mo. The amount of metal, either individually or in combination is from 0.5 to 35 wt.%, based on catalyst. Hydrotreating conditions include temperatures of from 15O0C to 4000C, preferably 2000C to 35O0C, pressures of from 790 to 20786 kPa (100 to 3000 psig), preferably 2170 to 13891 kPa (300 to 2000 psig), a liquid hourly space velocity of 0.1 to 10, preferably 0.1 to 5 and a hydrogen to feed ratio of from 89 to 1780 m3/m3 (500 to 10000 scf/b), preferably 178 to 890 mVm3 (1000 to 5000 scf/b). The hydrotreating conditions may be adjusted to achieve target sulfur and nitrogen levels. These adjustments are known in the art of hydrotreating.

[0018] The hydrotreated naphtha fraction is then conducted to a cracking zone in which the hydrotreated naphtha fraction is contacted with an acidic cracking catalyst thereby increasing the octane number of this hydrocracked naphtha fraction. In this step, lower octane components such as n-paraffms and heavy paraffins are selectively cracked to higher octane products such as lighter paraffins and olefins. These catalysts have sufficient acidic functionality to bring the desired cracking reactions to at least partially restore octane loss during hydrotreating.

[0019] The catalysts for this selective cracking step are intermediate pore zeolites having a Constraint Index between 2 and 12. See U.S. Patent No. 4,784,745 for a description of measuring the Constraint Index, which reference is incorporated herein. Examples of suitable intermediate pore zeolites include ZSM- 5 (U.S. Pat. No. 3,702,886), ZSM-I l (U.S. Pat. No. 3,709,979), ZSM-12 (U.S. Pat. No. 3,832,449), ZSM-22 (U.S. 4,556,827), ZSM-23 (U.S. Pat No. 4,076,842), ZSM-35 (U.S. Pat. No. 4,016,245), ZSM-48 (U.S. 4,397,827), ZSM-57 (U.S. Pat. No. 4,046,685), MCM-22 (U.S. Pat. No. 4,962,256), MCM-56 (U.S. Pat. No. 5,632,697) and Offretite.

[0020] Other suitable catalysts are large pore zeolites having a Constraint Index up to 2. Examples of suitable large pore zeolites include zeolite beta, mordenite, zeolite X, zeolite L, zeolite Y, USY, REY, dealuminized Y and ZSM-4.

[0021] Another measure of a sufficient acid activity to have the desired cracking activity is the catalyst's alpha value. Alpha values are described in U.S. Pat. No. 4,016,218. A catalyst's alpha value can be controlled by known techniques such as the Si/Al ratio, steaming, steaming followed by de-alumination and substituting framework aluminum with other metals. In the present process, catalysts for the cracking zone have alpha values greater than 20, preferably 20 to 800, more preferably 50 to 200.

[0022] In addition to the zeolite, catalysts typically contain a binder material which may be any suitable refractory material such as silica, alumina, silica- alumina, silica-zirconia and silica-titania. The cracking zone catalyst may also contain a metal hydrogenation function. Examples of such metals include those of Groups 8, 9 and 10, with Groups 9 and 10 being preferred. Mixtures of such metal are also included. Preferred metals include at least one of Ni, Co, Pd or Pt, with Ni being especially preferred. [0023] Hydrocracking conditions for octane improvement include temperatures of from 15O0C to 4820C, preferably 1770C to 4270C, pressures of from 446 to 10444 kPa (50 to 1500 psig), preferably 2170 to 6996 kPa (300 to 1000 psig), liquid hourly space velocities of from 0.5 to 10 hr'1, preferably 1 to 6 hr"1, and hydrogen treat gas rates of from 0 to 890 m3/m3 (0 to 5000 scf/b), preferably 17.8 to 445 m3/m3 (100 to 2500 scf/b).

[0024] A disadvantage of the hydrocracking step to help restore octane is that the reaction conditions are such that any olefins present may react with hydrogen sulfide to form mercaptans. These mercaptans are known as reversion or recombinant mercaptans and are usually heavier mercaptans such as C5+ mercaptans.

[0025] Recombinant mercaptans in the C5+ range cannot be effectively removed by the conventional extraction techniques used for lighter mercaptans. In the present process, such recombinant mercaptans are removed without the need of further hydrotreatment steps. Instead of further hydrotreatment steps, an aqueous treatment solution may be formed from water, dissolved alkali metal hydroxide, dissolved sulfonated cobalt phthalocyanine, and dissolved alkali metal alky lpheny late. The hydrocracked naphtha fraction containing mercaptans is contacted with this treatment solution. The contacting may be under anaerobic conditions, i.e., in the essential absence of oxygen. While not wishing to be bound by any theory or model, it is believed that the presence of sulfonated cobalt phthalocyanine in the treatment solution lowers the interfacial energy between the aqueous treatment solution and the naphtha, which enhances the rapid coalescence of the discontinuous aqueous regions in the naphtha thereby enabling more effective separation of the treated naphtha from the treatment solution. This in turn allows the use of high hydroxide concentration treatment solutions, which have higher extractant power for C5 and higher molecular weight mercaptans (reversion mercaptans) than conventional treatment solutions.

[0026] Thus, the reduction in mercaptan reversion achieved by a process that includes using a hydrocracking step followed by mercaptan extraction, which produces a naphtha product useful in forming gasoline both low total sulfur and mercaptan sulfur, while preserving the olefins valuable for octane number. At technologically important deep desulfurization levels, e.g., 90-100 wt.% feed sulfur removal, particularly with relatively high sulfur content naphtha feeds (e.g., >1000- 7000 wppm sulfur), the contribution of sulfur from reversion mercaptans to the total sulfur, can be significant. Therefore, the control of mercaptan formation is necessary to reach sulfur levels of less than 150 wppm, especially less than 30 wppm.

[0027] The treatment solution may be prepared by combining alkali metal hydroxide, alkylphenols, sulfonated cobalt phthalocyanine, and water. The amounts of the constituents may be regulated so that the treatment solution forms two substantially immiscible phases, i.e., a less dense, homogeneous, top phase of dissolved alkali metal hydroxide, alkali metal alkylphenylate, and water, and a more dense, homogeneous, bottom phase of dissolved alkali metal hydroxide and water. An amount of solid alkali metal hydroxide may be present, preferably a small amount (e.g., 10 wt.% in excess of the solubility limit), as a buffer, for example. When the treatment solution contains both top and bottom phases, the top phase is frequently referred to as the extractant or extractant phase. The top and bottom phases are liquid, and are substantially immiscible in equilibrium in a temperature ranging from 8O0F to 1500F and a pressure range of ambient (zero psig) to 200 psig. [0028] In one embodiment, the two-phase treatment solution may be contacted with the hydrocracked naphtha and allowed to settle. Treated, hydrocracked naphtha settles above the top phase and separates from the top phase. Alternatively, the treatment solution may be separated into a top and bottom phase following which hydrocracked naphtha is contacted with the top phase. The top phase may be regenerated and recycled to the process for re-use.

[0029] The treatment solution may also be prepared to produce a single liquid phase of dissolved alkali metal hydroxide, alkali metal alkylphenylate, sulfonated cobalt pthalocyanine, and water provided the single phase formed is compositionally located on the phase boundary between the one-phase and two- phase regions of a ternary phase diagram. In other words, the top phase may be prepared directly without a bottom phase, provided the top-phase composition is regulated to remain at the boundary between the one-phase and two-phase regions of the dissolved alkali metal hydroxide-alkali metal alkylphenylate-water in the ternary-phase diagram. The phase diagram is further described in U.S. Published Application 2003/0052045 incorporated herein by reference. The compositional location of the treatment solution may be ascertained by determining its miscibility with the analogous aqueous alkali metal hydroxide. The analogous aqueous alkali metal hydroxide is the bottom phase that would be present if the treatment solution had been prepared with compositions within the two-phase region of the phase diagram. As the top phase and bottom phase are homogeneous and immiscible, a treatment solution prepared without a bottom phase will be immiscible in the analogous aqueous alkali metal hydroxide. The single-phase treatment is then contacted with the hydrocarbon. After the treatment solution has been used to contact the hydrocarbon, it may be regenerated for re-use, as discussed for two- phase treatment solutions, but no bottom phase is present in this embodiment. Such a single-phase treatment solution is also referred to as an extractant, even when no bottom phase is present.

[0030] The total sulfur amount in the naphtha product may be reduced by- removing sulfur species such as disulfides from the extractant. Therefore, one may treat a naphtha feed by the extraction of the mercaptans from the naphtha to an aqueous treatment solution where the mercaptans subsist as water-soluble mercaptides and then converting the water-soluble mercaptides to water-insoluble disulfides. The sulfur, now in the form of hydrocarbon-soluble disulfides, may then be separated from the treatment solution and conducted away from the process so that a treated naphtha substantially free of mercaptans and of reduced sulfur content may be separated from the process. Alternatively, a second hydrocarbon may be employed to facilitate separation of the disulfides and conduct them away. The process may be operated so that the flow of the treatment solution is cocurrent to naphtha flow, countercurrent to naphtha flow, or a combination thereof.

[0031] Mercaptan adsorption is a non-hydrotreating means of removing mercaptans from feeds and products. It is preferred that hydrotreated effluent from step one be stripped of hydrogen sulfide and ammonia prior to the adsorption step. In one embodiment, mercaptans are adsorbed by means of chemisorption using metals or metal oxides. Metals may be from Groups 7 - 12 of the IUPAC periodic table and include at least one of Ni, Co, Cu, Pt, Zn, Mn, and Cd, which metals or metal oxides may be supported on a porous carrier such as clay, carbon or metal oxides such as alumina. The metals or metal oxides adsorb sulfur by chemisorption, typically by formation of metal sulfides. Another form of adsorbent is based on adsorbents that physically adsorb mercaptans. This class of adsorbents typically utilizes molecular sieves as the adsorbent. Examples of this type of adsorbent include crystalline metal silicates and zeolites of the faujasite family such as zeolites X and Y, zeolite A and mordenite. Adsorbents may include metal exchanged forms with metals from Groups 1 - 12. U.S. Patent 5,843,300 is an example of the use of metal-exchanged zeolites. Adsorption can also be accomplished by ion-exchange resins. In the adsorption technique, the naphtha effluent from the HDS reactor is contacted with adsorbent usually in the form of a fixed bed. In the case of mercaptans that are removed by physical techniques, it may be possible to regenerate the adsorbent by heating, reduced pressure, stripping or some combination thereof to desorb the mercaptans. Those adsorbents that function by chemisorption are typically replaced when spent as they are non- regenerable or very difficult to regenerate. Contacting with adsorbent is normally at ambient temperatures for physical adsorbents whereas chemisorption operates at elevated temperatures of 7O0C up to 5000C.