Hydroprocessing with drum blanketing gas compositional control

Abstract

A catalytic naphtha hydrodesulfurization process is operated in a process unit having a surge drum with equipped for gas blanketing with a blanketing gas containing controlled levels of CO and CO.sub.2. If the gas selected for blanketing normally contains more than the acceptable level of these inhibitors, they should be reduced to the levels appropriate for retention of catalyst functionality.

Claims

1. A selective catalytic naphtha hydrodesulfurization process operated in the presence of a hydrogen-containing treat gas in a process unit having a surge drum equipped for gas blanketing, which comprises blanketing the naphtha in the surge drum with a blanketing gas containing CO and/or CO.sub.2 at concentrations which result in concentrations of CO and/or CO.sub.2 in the naphtha at which the activity of a catalyst of the hydrodesulfurization process is maintained, wherein the catalyst comprises about 1 to 10 wt. % Mo03; 0.1 to 5 wt. % CoO; a Co/Mo atomic ratio of about 0.1 to 1.0; and a median pore diameter of about 6 to 20 nm; a Mo0.sub.3 surface concentration in g Mo0.sub.3/m.sup.2 of 0.5×10-4 to 3×10-4; and an average particle size diameter of less than about 2.0 mm; and wherein the process is carried out in a two stage process in which the naphtha boiling range feed is contacted with hydrogen over a first hydrotreating catalyst in the vapor phase to remove at least 70 wt. % of the sulfur, to produce a first stage effluent which is cooled to condense the naphtha vapor which is then separated from the H.sub.2S containing gas and passed with hydrogen into the a second vapor phase stage at a temperature at least 10° C. greater than in the first stage and at a space velocity at least 1.5 times greater than in the first stage, to remove at least 80 wt. % of the remaining sulfur from the naphtha and form a desulfurized naphtha vapor.

2. A process according to claim 1 in which the blanketing gas excludes natural gas.

3. A process according to claim 1 in which the olefin-retentive hydrodesulfurization is carried out at a temperature of 250-325° C., a total system pressure of 1000-3500 kPag, a hydrogen partial pressure of 600-2500 kPa and 1-10 hr.sup.−1 LHSV.

4. A process according to claim 1 in which the effluent of the second stage comprises a naphtha which contains less than 5 wt. % of the amount of sulfur present in the feed but retaining at least 40 vol. % of the olefin content of the feed.

5. A process according to claim 1 in which the catalyst in both stages comprises Co and Mo on a support in an amount of less than a total of 12 wt. % calculated as the respective metal oxides CoO and MoO3 with a Co to Mo atomic ratio from 0.1 to 1.0.

6. A process according to claim 1 in which the olefin-retentive hydrodesulfurization is carried out in each stage at a temperature from 230 to 400° C., a pressure of from 400-34000 kPag, a space velocity of from 1-10 v/v/hr.sup.−1 and with a space velocity in the second stage greater than that in the first stage.

7. A process according to claim 1 in which the blanketing gas contains CO+CO.sub.2 at concentrations which result in concentrations of CO and/or CO.sub.2 in the naphtha corresponding to a total concentration of CO and/or CO.sub.2 in the treat gas of not more than 30 ppmw.

8. A process according to claim 1 in which the concentration of total CO+CO.sub.2 in the blanketing gas is less than 0.4 vol %.

Description

DRAWINGS

(1) The single figure of the accompanying drawings represents the results of the simulation studies reported below in the Examples.

DETAILED DESCRIPTION

(2) Catalytic Treatment Processes

(3) Olefin retentive selective catalytic naphtha hydrodesulfurization processes to which the present blanketing gas control techniques are potentially applicable include those described in U.S. Pat. Nos. 5,853,570; 5,906,730; 4,243,519; 4,131,537; 5,985,136 and 6,013,598 (to which reference is made for descriptions of such processes).

(4) The hydrodesulfurization (HDS) of naphtha feeds is carried out in a process which in which sulfur is hydrogenatively removed while retaining olefins to the extent feasible. The HDS conditions needed to produce a hydrotreated naphtha stream which contains non-mercaptan sulfur at a level below the mogas specification as well as significant amounts of mercaptan sulfur will vary as a function of the concentration of sulfur and types of organic sulfur in the cracked naphtha feed to the HDS unit. Generally, the processing conditions will fall within the following ranges: 250-325° C. (about 475-620° F.), 1000-3500 kPag (about 150-500 psig) total pressure, 600-2500 kPa (about 90-350 psig kPa) hydrogen partial pressure, 200-300 Nm3/m3 hydrogen treat gas rate, and 1-10 hr.−1 LHSV.

(5) SCANfining™ Process

(6) The present method of monitoring and controlling the composition of the blanketing gas is particularly applicable to the SCANfining catalytic naphtha hydrodesulfurization process which optimizes desulfurization and denitrogenation while retaining olefins for gasoline octane. This process, which is commercially available under license from ExxonMobil Research and Engineering Company, incorporates aspects of the processes described in the following patents: U.S. Pat. Nos. 5,985,136; 6,231,753; 6,409,913; 6,231,754; 6,013,598; 6,387,249 and 6,596,157. SCANfining is also described in National Petroleum Refiners Association Paper AM-99-31 titled “Selective Cat Naphtha Hydrofining with Minimal Octane Loss”.

(7) The operation of the SCANfining process relies on a combination of a highly selective catalyst with process conditions designed to achieve hydrodesulfurization with minimum olefin saturation. The process may be operated either in a single stage or two stage with an optional mercaptan removal step following the hydrodesulfurization to remove residual mercaptans to an acceptable level, possibly permitting the hydrodesulfurization stage or stages to be operated at lower severity while still meeting sulfur specifications. The single stage version of the SCANfining process can be used with a full range catalytic naphtha or with an intermediate catalytic naphtha (ICN), for example a nominal 65-175° C. (150-350° F.) or a heavy catalytic naphtha (HCN), for example, a nominal 175° C.+(350° F.+) naphtha, or both. The two-stage version of the process, as described in U.S. Pat. No. 6,231,753, WO 03/048273 and WO 03/099963, adds a second reactor and inter-stage removal of H.sub.2S allowing very deep HDS with very good olefin retention. Suitable mercaptan removal processes are described in US 2007/114156 and US 2014/174982.

(8) Typical SCANfining conditions in the one and two stage processes react the feedstock in the first reaction stage under hydrodesulfurization conditions in contact with a catalyst comprised of about 1 to 10 wt. % MoO.sub.3; and about 0.1 to 5 wt. % CoO; and a Co/Mo atomic ratio of about 0.1 to 1.0; and a median pore diameter of about 6 to 20 nm; and a MoO.sub.3 surface concentration in g MoO.sub.3/m.sup.2 of about 0.5−10.sup.−4 to 3×10.sup.−4; and an average particle size diameter of less than about 2.0 mm. The reaction product of the first stage may then be optionally passed to a second stage, also operated under hydrodesulfurization conditions, and in contact with a catalyst comprised of at least one Group VIII metal selected from Co and Ni, and at least one Group VI metal selected from Mo and W, preferably Mo, on an inorganic oxide support material such as alumina. The preferred catalyst is the Albemarle Catalyst RT-235.

(9) In a preferred two-stage SCANfining process configuration, typical process conditions will contact the naphtha with hydrogen over the first hydrotreating catalyst in the vapor phase to remove at least 70 wt. % of the sulfur, to produce a first stage effluent which is cooled to condense the naphtha vapor to liquid which contains dissolved H.sub.2S which is then separated from the H.sub.2S containing gas. The first stage naphtha reduced in H.sub.2S is then passed with hydrogen treat gas into the second vapor phase stage in the presence of a hydrodesulfurization catalyst at a temperature at least 10° C. (about 20° F.) greater than in the first stage and at a space velocity at least 1.5 times greater than in the first stage, to remove at least 80 wt. % of the remaining sulfur from the naphtha and form a desulfurized naphtha vapor. The second stage vapor effluent is then cooled to condense and separate the naphtha from the H.sub.2S to form a desulfurized naphtha product liquid which contains less than 5 wt. % of the amount of the sulfur present in the feed but retaining at least 40 vol. %

(10) of the olefin content of the feed. In this configuration, the catalyst in both stages comprising Co and Mo on a support and present in an amount of less than a total of 12 wt. % calculated as the respective metal oxides CoO and MoO.sub.3 with a Co to Mo atomic ratio from 0.1 to 1.0. Reaction conditions in each stage normally range from 230-400° C. (about 450-750° F.), a pressure of from 400-34000 kPag (about 60-600 psig), a treat gas ratio of from 1000-4000 scf/b and a space velocity of from 1-10 v/v/hr; under these conditions, the percent desulfurization in the second stage is typically at least 90%. Space velocity in the second will normally be greater than that in the first stage and can range up to 6 hr..sup.−1 LHSV.

(11) Table 2 below shows typical SCANfining reactor operating conditions.

(12) TABLE-US-00002 TABLE 2 SCANfiner Reactor Operating Conditions Total Exotherm ° C. 24 Reactor Inlet Pressure barg 19.0 Treat Gas Rate Nm3/m3 253 Treat Gas Purity vol % H2 94.0 Desulfurization % HDS 83.0 Olefin Saturation % OSAT 15.4
Blanketing Gas

(13) The present invention is applicable to catalytic refining processes in which a hydrocarbon feed stream, especially a naphtha fraction, is treated over a catalyst in a processing unit in which, at some point prior to the catalytic treatment, the feed stream is passed through a vessel or drum in which the held under a blanketing gas. The composition of the blanketing gas is monitored and controlled to maintain the total concentration of the carbon monoxide and carbon dioxide in the blanketing gas at a value resulting in a dissolved CO/CO.sub.2 level in the stream equivalent to no more than 30 ppmv total CO/CO.sub.2 in the treat gas stream. As shown below, the level of CO/CO.sub.2 content in the blanketing gas can be empirically related to an equivalent level of these contaminants in the treat gas. If the proportion of CO and/or CO.sub.2 in the blanketing gas exceeds the value(s) equivalent to 30 ppmv total in the treat gas stream, appropriate control measures are taken to ensure continued catalyst functioning.

(14) Natural gas is available in many refineries and may be considered as a potential blanketing gas. Table 3 shows a typical natural gas composition.

(15) TABLE-US-00003 TABLE 3 Typical Natural Gas Composition Composition, vol % N.sub.2 1.4 CO Trace CO.sub.2 1.2 CH.sub.4 93.1 C.sub.2H.sub.6 3.2 C.sub.3H.sub.8 0.7 C.sub.4H.sub.10 0.4

(16) Natural gas can contain as high as 2 vol % CO.sub.2 or even higher, some of which can dissolve in the FCC naphtha. CO also may dissolve in the naphtha when used as a blanketing gas.

(17) Determination of Acceptable CO/CO.sub.2 Levels in Blanketing Gas

(18) It has been found that under the conditions prevailing in the surge drum of the

(19) SCANfining process, components of the blanketing gas become dissolved in the naphtha feed stream to an extent varying with pressure and temperature. If the dissolved components such as CO and CO.sub.2 undesirably inhibit catalyst functioning, selection of an alternative blanketing gas becomes appropriate or, alternatively, the selected blanketing gas may be treated e.g. by absorption, adsorption or even by washing with a suitable solvent for the deleterious component(s). CO may be removed, for example, by absorption in a soda-lime bed and CO.sub.2 may be removed by adsorption in a molecular sieve such as zeolite 4A.

(20) The extent to which the CO and CO.sub.2 need to be removed may be determined empirically. A suitable sequence is to use the PRO II simulation (SimSci, Invensys) to predict the permissible concentrations of these gases under appropriate processing conditions. For any known combination of naphtha feed composition, catalyst properties, process conditions, the concentrations of CO and CO.sub.2 in the blanketing gas which will result in the maintenance of catalyst activity, especially hydrodesulfurization activity relative to olefin saturation activity will be determined and the blanketing gas composition controlled accordingly.

EXAMPLE 1

(21) For the purposes of demonstrating the technique by which acceptable levels of CO and CO.sub.2 in the blanketing gas can be determined, a typical FCC naphtha feed was selected having the composition set out in Table 3 below in order to simulate the CO and CO.sub.2 solubilities in the naphtha under surge drum conditions.

(22) TABLE-US-00004 TABLE 3 FCC Naphtha Properties API Distillation, ° C. 62.3 IBP 65 10 wt % 73 30 wt % 81 50 wt % 95 70 wt % 133 90 wt % 197 EP 223

(23) A PRO-II simulation was conducted under the conditions shown in Table 5 below.

(24) TABLE-US-00005 TABLE 5 Feed Surge Drum Conditions Pressure, bar 3.4 Temperature, ° C. 37.8 Blanketing Gas/Naphtha 3.4 Ratio (Sm.sup.3/m.sup.3)

(25) The simulation assumed the use of the natural gas of Table 3 as the blanketing gas. CO.sub.2 dissolved in this FCC naphtha was 0.00948 wt % that was equivalent to 94 ppmv CO.sub.2 in the treat gas (based on treat gas/naphtha ratio of 338 Sm.sup.3/m.sup.3) which is much higher than the 30 ppmv total CO/CO.sub.2 concentration allowable in the treat gas.

EXAMPLE 2

(26) To determine the CO or CO.sub.2 concentration allowable in the blanketing gas, the Pro-II simulation was extended to various CO and CO.sub.2 concentrations in the blanketing gas using the natural gas composition shown in Table 1 as the base case. For simplicity, the methane concentration was varied according to total CO/CO.sub.2 concentration in the simulated blanketing gas. The simulation conditions were the same as Table 6. The treat gas/naphtha ratio was the same: 338 Sm.sup.3/m.sup.3 and the blanketing gas/naphtha ratio 3.4 Sm.sup.3/m.sup.3.

(27) The results are summarized in Table 6.

(28) TABLE-US-00006 TABLE 6 Simulation Results CO in vol % 1.2 1 0.5 0.2 Blanketing CO2 in vol % 1.2 1 0.5 0.2 Blanketing Gas CH4 in vol % 91.9 92.3 93.3 93.9 Blanketing Gas Other Gases in Blanketing Gas (as in Table 2) Dissolved CO wt % 0.00289 0.00241 0.00121 0.000484 in Naphtha Dissolved CO2 wt % 0.00948 0.00786 0.00393 0.00157 in Naphtha CO2 in Treat ppmv 33 28 14 6 Gas Equivalent CO in Treat ppmv 94 78 39 16 Gas Equivalent Conditions Pressure bar 3.4 Temperature C. 37.8 Blanketing Sm3/m3 3.4 Gas/Naphtha Ratio Treat Sm3/m3 338 Gas/Naphtha Ratio
FIG. 1 illustrates these results graphically.

(29) The results showed that the maximum allowable total CO+CO.sub.2 concentration in the blanketing gas with this naphtha composition and natural gas composition under the conditions assumed for the determination should be less 0.4 vol % and better, less than 0.2 vol %. If a blanketing gas contains both CO and CO.sub.2, Table 6 or FIG. 1 can be used to determine the individual allowable CO and CO.sub.2 concentrations in the blanketing gas.