BACKGROUND OF THE INVENTION Crude petroleum is a mixture of many different hydrocarbon molecules, ranging in size from very small to very large. The number of carbon atoms that a molecule contains generally governs the size of the molecule. The petroleum refining process initially entails separation of these compounds by boiling point. The boiling point is dependent on the size and structure of the molecules, and very large molecules tend to have very high boiling points. Thus, the recovery of various mid-range hydrocarbon products often leaves a residual stream of large-molecule hydrocarbons, often referred to as heavy oil. Petroleum refiners often convert these heavy-oil residual streams into desirable products such as kerosene, diesel fuel and other middle distillates and lower boiling hydrocarbon liquids, such as naphtha and gasoline, by hydroprocessing.

Hydroprocessing may involve any of several catalytic processes including, but not limited to, hydroisomerization, hydrodesulfurization, hydrogenation, and hydrocracking.

Hydrocracking entails the cracking of large molecules and the concurrent addition of hydrogen. The mix of hydrocarbon products that results can be partially controlled by controlling process conditions and the selection of catalyst, if there is one. Hydrocracking is generally accomplished by contacting the feedstock with a suitable hydrocracking catalyst in a hydrocracking reaction vessel or reaction zone under conditions of elevated temperature and pressure in the presence of hydrogen so as to yield a product containing a distribution of hydrocarbon products desired by the refiner. Suitable hydrocracking catalysts are well-known in the art and are typically metal-deposited catalysts on acidic supports. The feedstock, operating conditions, and hydrocracking catalysts within a hydrocracking reactor influence the yield of the hydrocracked products.

Conventional hydrocracking operations produce some amount of naphtha through cracking of larger-chain hydrocarbons. The probability of cracking a given carbon-to-carbon bond depends upon that bond's position in the carbon chain. The closer a given bond is to the end of the carbon chain, the lower the probability that the bond will be cracked. For example, when a hydrocarbon is cracked, the probability of formation of Cl or C2 hydrocarbons is very

low-i. e. , the probability that the hydrocarbon will crack, at the first or second carbon-carbon bond is very low. The probability of formation of C4 species is about the same as the probability of formation of C5+ species. Thus, the probability of cracking peaks around four carbons from the end of the chain and is basically the same at any point further from the end than four carbon atoms. However, the probability that a bond that is three carbons from the end of a hydrocarbon chain will crack is about half of that of bonds that are four or more carbons from the end.

Therefore, when cracking relatively smaller molecules, naphtha and lighter hydrocarbons production is greater because of the higher frequency of bonds that are less than about five carbons from the end as compared to bonds that are four or more carbons from the end.

The naphtha production is proportional to the per pass conversion in a conventional unit.

As per-pass conversion is increased, more middle distillate hydrocarbons are being produced and cracked again to light hydrocarbons in the naphtha range and also to lighter hydrocarbons below the naphtha range. As middle distillates are produced from higher hydrocarbons, the proportion of bonds available for cracking that are near the end of the hydrocarbon chain increases relative to those bonds available for cracking that are far from the end of the hydrocarbon chain. Thus, large hydrocarbon molecules may crack into middle distillates and further crack into lighter hydrocarbons before leaving the reactor generating excess naphtha.

Hydroisomerization involves the saturation of olefinic and oxygenated hydrocarbons and the conversion of hydrocarbons containing carbon chains into skeletal isomers. Generally, it involves increasing the branching of relatively straight carbon chains. Hydroisomerization is effective for reducing the pour point of hydrocarbon streams by dewaxing. Besides isomerization, hydroisomerization may also produce some cracking. Cracking of longer carbon chains can produce a beneficial dewaxing effect; however, cracking of shorter carbon chains will produce hydrocarbons in the naphtha range and even lighter hydrocarbons. Thus, it is desirable to prevent lighter products from remaining in the reaction zone longer than is necessary. Other hydroprocessing processes have similar naphtha-producing effects.

It is desirable to minimize naphtha production when producing middle distillates from hydrocarbon synthesis wax (e. g. , Fischer-Tropsch wax). Naphtha must generally be separated from the middle-distillate fractions because of vapor pressure concerns. Fischer-Tropsch middle- distillate paraffins, which are subject to further cracking, are beneficial for increasing cetane number, an important product specification in the production of diesel fuel. Therefore, to obtain a high yield of diesel product with a good cetane number, it is desirable to avoid further cracking of middle-distillate paraffin molecules.

With improved selectivity toward middle distillates, conventional hydroprocessing operations would be able to operate at higher conversion rates without excess naphtha production.

Further, as mentioned above, some hydroprocessing processes are more susceptible to selectivity problems. Processes that are more susceptible include those in which the feedstock has a higher paraffin content, as paraffins crack much more easily than aromatics and are more likely to continue cracking to lighter components. Thus, the need for better selectivity in such processes is more acute.

The product from a hydrocarbon synthesis process, such as a Fischer-Tropsch process, is one example of a high paraffin content feedstock that might be fed to a process comprising hydroprocessing. The Fischer-Tropsch process is a catalytic process by which a mixture of carbon monoxide and hydrogen, called syngas, is converted to various hydrocarbons. In commercial syngas production processes, the syngas may be derived from natural gas, coal, petroleum coke, and the like. Thus, natural gas, which comprises primarily methane, is converted to syngas, which is a mixture of H2 and CO and which is in turn converted into larger paraffin hydrocarbons during the Fischer-Tropsch synthesis. One feature of the Fischer-Tropsch process is that it produces generally linear, or straight-chain, hydrocarbon molecules comprising from one to more than eighty carbon atoms. The heavier Fischer-Tropsch reaction products generally include long, straight-chain paraffins that are commonly known as wax. As in the case of crude oil refining, it is typically desirable to separate the various hydrocarbon products, so as to attain the best use for each. Thus, refiners may hydrocrack the heavier Fischer-Tropsch reaction products so as to form upgraded fuels and lubricating oils. The linearity of the Fischer-Tropsch products makes them more conducive to selective hydroprocessing than the crude-oil-derived refined products.

SUMMARY OF THE INVENTION In a preferred embodiment of the present invention, a method is provided for increasing the efficiency and output of a hydroprocessing unit engaged in hydroprocessing products of a hydrocarbon synthesis process by removing middle distillate and lighter components from the reaction zone as they are produced, thereby minimizing unwanted secondary cracking of the hydrocarbons already in the desired range. These components are removed by a catalytic distillation system that selectively vaporizes lighter components as they are made. Such a system is capable of creating one or more distillate products from a heavy hydrocarbon synthesis wax product. Another embodiment of the present invention provides an apparatus for catalytically distilling a hydrocarbon synthesis product and recovering one or more distillate products while reducing excess naphtha and lighter hydrocarbons production.

These and other embodiments, features, and advantages of the present invention will become apparent with reference to the following description.

BRIEF DESCRIPTION OF THE FIGURES A better understanding of the present invention can be obtained when the following detailed description of the preferred embodiment is considered in conjunction with the following drawings: Figure 1 is a schematic drawing of a catalytic distillation unit in accordance with a preferred embodiment of the present invention; Figure 2 depicts diesel: naphtha ratios for catalytic distillation and conventional hydrocracking operations over a range of conversions; the results shown are calculated assuming a temperature of 330° C and pressure of 4.7 MPa (660 psig), a hydrogen feed rate of 1,500 standard cubic feet per barrel of liquid (270 standard cubic meters of hydrogen per cubic meter of liquid), and a liquid feed comprising essentially of C21+ hydrocarbon products from a low- temperature Fischer-Tropsch synthesis with an alpha value of 0.93 ; Figure 3 is a schematic drawing in accordance with an alternate embodiment of the present invention employing three distillation zones; and Figure 4 is a schematic drawing in accordance with an alternate embodiment of the present invention employing two catalyst beds.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS The present invention describes a method and apparatus for hydroprocessing a hydrocarbon synthesis product. As discussed above, a hydrocarbon synthesis product stream may comprise hydrocarbon molecules that contain from one to eighty, or more, carbon atoms each.

These molecules are predominantly straight-chain paraffins. One well known hydrocarbon synthesis process is the Fischer-Tropsch process. Generally, low-temperature Fischer-Tropsch products contain some olefins, and oxygenates, but paraffins are by far the major component. In addition, Fischer-Tropsch products generally do not contain substantial amounts of metals, and sulfur-containing and nitrogen-containing compounds. In this regard, Fischer-Tropsch products differ substantially from conventional crude oil refinery feedstocks for hydrocrackers, which generally contain large amounts of aromatics and naphthenes. In particular, hydrocarbon synthesis products generated by a low-temperature Fischer-Tropsch synthesis are substantially free of cyclic hydrocarbons. Due to these differences, different operating conditions are necessary for processing Fischer-Tropsch products.

Referring initially to Figure 1, one embodiment of the present system includes a catalytic distillation unit 20 including inlet lines 10 and 80 and outlet lines 60 and 90 and a separation vessel 74. Outlet line 60 feeds into a condenser 70, which in turn feeds into a separation vessel

74. Separation vessel 74 preferably includes a vapor outflow line 76 and a liquid outflow line 77.

Liquid outflow line 77 is preferably split into a reflux line 72, which is recycled into the top of catalytic distillation unit 20, and an overhead liquid product line 78. Similarly, a portion of the liquid in outlet line 90 can be passed through a heat exchanger 91 and returned to the bottom of catalytic distillation unit 20.

Catalytic distillation unit 20 is preferably a substantially vertical cylindrical vessel.

However, unit 20 may comprise various shapes and sizes and may comprise more than one vessel connected in series. Preferably, unit 20 is a vertical cylindrical vessel similar to a conventional distillation tower. Its exact dimensions will depend upon the individual operating conditions as is well known to one having ordinary skill in the art. Unit 20 may have various nozzles and fittings to allow connection of various piping to accommodate process flows.

Unit 20 may comprise a single catalyst bed 30, but more preferably contains at least one catalyst bed 30 and at least one distillation zone 40. The catalyst beds and distillation zones do not have to be in any particular arrangement. Their arrangement may be changed to optimize catalyst performance or to optimize distillation performance or both. Still more preferably, catalytic distillation unit 20 contains one catalyst bed 30 and two distillation zones 40,50 in the arrangement shown in Figure 1, and inlet line 10 preferably enters unit 20 above catalyst bed 30 and below distillation zone 40. However, inlet line 10 may also be fed below the top of catalyst <BR> <BR> bed 30 (i. e. , in the midst of catalyst bed 30) in order to contact some of the vaporized feed with catalyst before it reaches distillation zone 40. Further, catalytic distillation unit 20 may have multiple feed connections for feeding at various points to accommodate different operating scenarios.

Condenser 70 may be any type of heat exchanger, and any suitable cooling medium may be used, such as air, cooling water, or other process stream. The outlet temperature of condenser 70 will depend on the particular operating conditions of the unit, such as pressure and available cooling media. Preferably, the outlet temperature of condenser 70 is between about-20° C and about 200° C, more preferably from about 20° C to about 100° C, and most preferably from about 30° C to about 80° C. Generally, the condensed vapor will be sent to a separation vessel 74.

Separation vessel 74 may be of any suitable type, such as vertical cylindrical or horizontal cylindrical.

The hydrocarbon synthesis product entering via inlet line 10 may be a full range product from a Fischer-Tropsch unit containing Cl to C80+ hydrocarbons, or the hydrocarbon synthesis product may be stabilized prior to being sent to the catalytic distillation unit 20. Stabilization may involve removing C5 and lighter components, C4 and lighter components, or any suitable cutpoint up to C20 to reduce light ends in the catalytic distillation unit 20. Stabilization will

lower the feed rate to catalytic distillation unit 20 and will likely lower energy usage; however, leaving lighter hydrocarbons in the feed to unit 20 may be more efficient. Some light hydrocarbons will be produced in catalytic distillation unit 20 requiring stabilization. Therefore, it may be more cost effective to accomplish the stabilization once rather than twice. The preference depends upon the individual circumstances of a specific unit.

As mentioned above, the hydrocarbon synthesis product may be fed to catalytic distillation unit 20 at any of various points. Preferably, hydrocarbon synthesis product is preheated prior to being fed to catalytic distillation unit 20 to improve processing efficiency.

Preheat temperatures may range from about 200° C to about 500° C, preferably from about 250° C to about 450° C, and most preferably from about 300° C to about 400° C. Methods for heating and otherwise conditioning feed streams are well known in the art. Assuming the hydrocarbon synthesis product is properly preheated to column conditions at the desired feed point in catalytic distillation unit 20, part of the hydrocarbon synthesis product may be vapor upon entry into unit 20 and part may remain in the liquid phase. Thus, the liquid portion will flow downward through catalyst bed 30, and the vapor portion will rise through distillation zone 40.

The liquid feeds into unit 20 can be distributed across the cross section of unit 20 by any conventional liquid distribution system. Liquid distribution systems are well known in the art.

Similarly, vapor inputs to unit 20 are generally distributed through nozzles or distributors depending upon velocity, as is well known to one having ordinary skill in the art.

In distillation zone 40, heavier components are condensed and returned to catalyst bed 30 for hydroprocessing, while lighter components rise through the zone 40 and leave the tower through the outlet line 60. Distillation zone 40 may comprise random or structured packing, or trays, or combinations thereof. Packing and tray selection and design are well known to one having ordinary skill in the art. Specific designs will depend upon individual operating conditions. Preferably, distillation zone 40 is designed to efficiently vaporize components within or lighter than a desired distillate product and condense products heavier than a desired distillate product, while allowing for some acceptable amount of overlap based on optimization of separation efficiency as well as on capital and operating costs.

It should be remembered throughout this specification that described cuts are only approximate. Any cutpoint described will have some components outside the recited range due to the nature of distillation separation. This overlap is generally not a problem in fuels production.

Thus, any recited cutpoint in this specification should be read as only a rough approximation rather than as a real boundary to the composition of a stream or product.

The vapor product in outflow line 76 generally contains hydrogen, methane, ethane, propane, butanes, and traces of other light hydrocarbons depending upon the operation of

catalytic distillation unit 20. The liquid may be split between reflux line 72 and overhead liquid product line 78. In one embodiment, the product in overhead liquid product line 78 will contain the distillate product along with trace, or larger, amounts of light hydrocarbons, such as methane, ethane, propane, and butane. It should be understood, although not shown in Figure 1, that the stream in vapor outflow line 76, which comprises hydrogen, can be recycled partially or totally to catalytic distillation unit 20, preferably below catalyst bed 30; more preferably, it may be combined with inlet line 80. In addition, components of the stream in vapor outflow line 76 could be separated to generate a hydrogen-rich stream which then could be recycled in part or totally to catalytic distillation unit 20, preferably below catalyst bed 30 and/or combined with the stream in inlet line 80.

As an example, and not by way of limitation, the desired distillate product may be a hydrocarbon stream containing predominantly molecules with three to twenty-two carbon atoms (C3 to C22). To obtain a product in this range, distillation zone 40 is operated to remove about <BR> <BR> C22 and lighter components-i. e. , to send about C22-out through outlet line 60 as vapor. After condensing, the overhead liquid product in overhead liquid product line 78 contains predominantly the C3 to C22 material. The remaining liquid product leaving distillation zone 40 drops into catalyst bed 30, through a suitable liquid distributor, to be reacted. As the liquid is reacted, forming C22 or lighter components, at least a portion of those components in turn vaporize and are lifted out of bed 30 and into distillation zone 40.

To provide hydrogen to the hydroprocessing reaction and to aid in the removal of lighter hydrocarbons from catalyst bed 30, a hydrogen-rich stream may be fed to catalytic distillation unit 20, preferably via inlet line 80. The hydrogen-rich stream may have any desired concentration of hydrogen; however, the hydrogen-rich stream preferably contains greater than 50 vol. % hydrogen, more preferably greater than 75 vol. % hydrogen. Higher hydrogen concentrations will result in higher hydrogen partial pressure in catalyst bed 30, which will help preserve catalyst life. Hydrogen may be supplied from an upstream syngas production unit or from an outside source, so long as it is substantially free of contaminants that might harm any catalyst in the unit. Contaminants can comprise water or heteroatomic compounds such as compounds comprising sulfur and nitrogen. The hydrogen-rich stream may also contain (or be combined with) a portion of the stream in vapor outflow line 76, which comprises unconverted hydrogen. The hydrogen-rich stream may be fed to any of various locations in catalytic distillation unit 20. Preferably, the hydrogen-rich stream is fed below catalyst bed 30, or below distillation zone 50. These locations allow the vapor in the hydrogen-rich stream to flow counter- currently to the heavier hydrocarbon liquid flowing through catalyst bed 30 and allow the <BR> <BR> hydrogen-rich stream to strip any remaining light hydrocarbons (i. e. , those within the desired

distillate product range or lighter) from the hydrocarbon liquid that is within and that drains from catalyst bed 30. The hydrogen-rich vapor passing through distillation zone 50 and catalyst bed 30 reduces the partial pressure of light hydrocarbons and induces vaporization, as is well known by one having ordinary skill in the art.

Distillation zone 50 is designed to remove components within the desired distillate product range and lighter components. Distillation zone 50 may comprise structured packing, random packing, or trays, or combinations thereof. Selection and arrangement of separation equipment are based on individual operating conditions, and the techniques involved are well known to a person having ordinary skill in the art.

While components within the desired distillate product range and lighter components are removed from the catalytic distillation unit 20 above the catalyst bed 30, heavy liquid exits the catalytic distillation unit 20 via outlet line 90. The bottoms product in outlet line 90 may be removed from the unit and processed further or disposed of, or may be recycled within the unit.

For example, although not shown in Figure 1, preferably at least a portion of the bottoms product may be combined with the Fischer-Tropsch product in inlet line 10 as feed to catalytic distillation unit 20. Alternatively, the bottoms product may be fed to catalytic distillation unit 20 through a separate feed connection above catalyst bed 30. In either case, a portion of the bottoms product in outlet line 90 may be recycled to catalytic distillation unit 20 while the remaining portion of the bottoms product leaves the unit 20, but the bottoms product is preferably recycled to extinction.

Because hydroprocessing paraffins involves little heat generation, catalytic distillation unit 20 may require some additional heat input to accomplish the separation of the desired distillate product from the heavier hydrocarbons. With reference to Figure 1, heat input may be accomplished via heat exchanger 91. However, heat input may be accomplished in a variety of ways, including external or internal reboilers or feed preheat. Any reboiler type is suitable, including thermosyphon, kettle, forced circulation, or other conventional reboiler type. Also, a reboiler heating bundle may be inserted into catalytic distillation unit 20. In an alternate embodiment, heat may be input by preheating the feed such that substantially all or most of the hydrocarbon synthesis product entering via inlet line 10 is vapor upon entering catalytic distillation unit 20. In this alternate embodiment, the hydrocarbon synthesis product may be fed below catalyst bed 30 and above distillation zone 50.

Heat for catalytic distillation unit 20 may be from any conventional heat source.

Conventional heat sources may include steam, other process streams, or combustion of fuel, among other things. Suitable fuels include natural gas, unreacted synthesis gas from the Fischer- Tropsch process, heavy oil, coal, or any other suitable fuel.

As noted above, catalytic distillation unit 20 preferably contains at least one catalyst bed 30. Catalyst bed 30 comprises at least one type of hydroprocessing catalyst suitable for processing hydrocarbon feedstocks. The catalyst may be a hydrocracking catalyst, a hydroisomerization catalyst, a hydrodesulfurization catalyst, or any other type of hydroprocessing catalyst. Catalyst bed 30 may contain one or more additional types of catalyst for pretreating the feed to the catalyst bed, for different hydroprocessing functions. Also, catalyst bed 30 may contain various types of support for retaining catalyst bed 30 and for trapping and disbursing any feed contaminants that might plug the bed. Design of catalyst bed layouts is well known to one having ordinary skill in the art. Suitable hydroprocessing catalysts include metal components such as nickel, molybdenum, tungsten, platinum, palladium, cobalt, iron, or the like, including combinations such as nickel-molybdenum or nickel-tungsten, distributed on a support comprising a zeolitic material, or a refractory metal oxide, such as alumina, silica, zirconia, or any combinations thereof. Hydroprocessing catalyst selection and appropriate operating conditions for hydrocracking, hydrotreating, or hydroisomerizing hydrocarbon synthesis waxes are well known to one having ordinary skill in the art.

A significant benefit of an embodiment of the present invention is demonstrated with reference to Figure 2. As previously discussed, removing lighter hydrocarbons from the hydrocracking zone helps prevent overcracking, resulting in better yields of higher hydrocarbon products. In Figure 2, a graph of diesel: naphtha ratios for conventional hydrocracking and catalytic distillation hydrocracking are depicted over a range of conversions for a given set of operating conditions. The results shown are calculated assuming a temperature of 330° C and pressure of 4.7 kPa (660 psig), a hydrogen feed rate of 1,500 standard cubic feet per barrel of liquid (270 standard cubic meters of hydrogen per cubic meter of liquid), and a liquid feed comprising essentially C21+ hydrocarbon products of a low-temperature Fischer-Tropsch synthesis with an alpha value of 0.93. As can be seen from Figure 2, over the entire range of conversions shown, the catalytic distillation hydrocracking operation provides a greater proportion of diesel to naphtha than the conventional hydrocracking operation. Thus, higher yields of diesel range material are possible with an embodiment of the present invention.

One additional benefit of an embodiment of the present invention is the presence of a temperature gradient across catalyst bed 30, which may be generated by some heat of reaction and heat input through the reboiler. As discussed previously, Fischer-Tropsch products are predominantly straight-chain hydrocarbons that produce little or no exotherm when subjected to hydroprocessing. For efficient hydroprocessing operation, the temperature across the catalyst bed may rise as the feed progresses through the bed because the lower concentration of reactive feed components later in the bed may require more activity. Thus, the temperature at the bottom of the

catalyst bed may be higher than at the top, assuming a downward flow of liquid. An embodiment of the present invention provides the necessary exotherm. Catalyst bed 30 within catalytic distillation unit 20 acts as a packing material promoting liquid-vapor contact. Such contact, combined with the effects of hydroprocessing, may produce a concentration gradient across catalyst bed 30 that results in higher temperatures toward the lower end of catalyst bed 30. These higher temperatures increase catalyst activity and promote conversion of the residual, less reactive, feedstocks. Further, the hydroprocessing catalyst may be formed into structured or random packing or other vapor-liquid contact structures to promote vapor-liquid contact and catalytic activity simultaneously.

Once appropriate operating conditions are determined for catalyst bed 30, catalytic distillation unit 20 can be operated in order to maintain those conditions in catalyst bed 30. In particular, preheat of Fischer-Tropsch product, heat input through the reboiler, and heat removal in the condenser all may be controlled in order to achieve the proper temperature and pressure in catalyst bed 30 to crack Fischer-Tropsch product and to separate the desired distillate product from any residual Fischer-Tropsch product remaining after the hydroprocessing operation.

Catalyst bed 30 operates in a counter-current manner. The hydrogen-rich stream combined with any reboiler effluent and any vapor stripped in distillation zone 50 flows upward through catalyst bed 30 while the heavier liquid flows downward through catalyst bed 30. Thus, the flow of the hydrogen-rich stream must be selected such that entrainment and flooding of catalyst bed 30 are avoided. As the flow of the hydrogen-rich stream combined with other vapor increases, the vapor velocity and the pressure drop across catalyst bed 30 may increase to the point where liquid flowing down can no longer pass through catalyst bed 30. In such a situation, catalytic distillation unit 20 may flood, depriving the unit of all separation capability and causing a drastic upset. To avoid such a scenario, the flow of the hydrogen-rich stream along with any reboiler vapor must be carefully controlled. To aid in the control of the hydrogen-rich stream, the pressure differential across catalyst bed 30 can be measured in order to control vapor throughput to the catalyst bed.

The preceding discussion describes the preferred method for hydroprocessing and separating a Fischer-Tropsch product to achieve a distillate range material. However, other embodiments are possible and may be beneficial under certain circumstances. The following discussion indicates some of the potential modifications of the present invention to different operating conditions, but it should not be construed as an exhaustive list of potential modifications. Different constraints than those in the following discussion may result in different embodiments than those described, and the present invention is not intended to be limited to the examples disclosed herein. Further, different configurations of the operating equipment are

possible, such as different condenser or reboiler arrangements. Such modifications or optimizations are intended to be encompassed within the scope of the present invention.

Referring to Figure 3, distillation zones 40 and 50 may include many or only a few theoretical plates depending on the separation desired. Also, additional distillation zones may be provided for separating additional products. For example, assuming again that the desired distillate product range is C3 to C22, overhead liquid product in overhead liquid product line 78 might be separated into two or even three products downstream, such as a naphtha, a jet, and a diesel range material. This additional separation, if desired, would require at least one additional distillation tower. However, with reference to Figure 3, the separation could be accomplished in catalytic distillation unit 20 by adding a distillation zone 100 above distillation zone 40. A liquid draw tray 110 may be installed between distillation zones 100 and 40 to draw off a heavier distillate product such as a lube oil, a diesel, or a kerosene range material. The heavier distillate product may be taken directly from catalytic distillation unit 20 as a product, or it may be further processed in a side stripper 120 as shown in Figure 3. Side stripper 120 aids the separation by stripping lighter hydrocarbons from the heavier distillate product. The stripping in side stripper 120 may be accomplished by reboiler 130, as shown, or it may be accomplished by steam injection in side stripper 120, as is common in crude oil processing. If draw tray 110 was desired for producing a diesel range material, an additional distillation zone and draw tray could be added above distillation zone 100 for producing a kerosene range material. As a continuation of the above example, and not by way of limitation, if a diesel range material were desired from draw tray 110, the diesel range material drawn off through line 135 in Figure 3 may contain substantially a C 11 to C22 material, while the overhead liquid product in overhead liquid product line 78 may be substantially a C3 to C10 material. Further, one or more side streams 131,132, 133 may be drawn from any of distillation zones 40,50, 100 if desired. Each of these side draws may also comprise side strippers. In this manner, catalytic distillation unit 20 may be adapted to prevent the additional expense of another tower downstream for further separating the distillate range material.

In an alternate embodiment with reference to Figure 4, the hydrocarbon synthesis product may be fed to catalytic distillation unit 20 in between catalyst beds 140 and 30. In this embodiment, vapor in the feed stream will rise through catalyst bed 140 with little cracking occurring. However, as liquid from distillation zone 40 drains into catalyst bed 140 through a suitable liquid distributor, it will condense the heavier hydrocarbons in the vapor in catalyst bed 140, allowing them a chance to react, be vaporized, and be removed from the downflowing liquid above the feed point. This alternate embodiment may be desired for more control over cracking.

For example, a milder, less active catalyst may be used in catalyst bed 140 to avoid overcracking

the lighter hydrocarbons present in this bed. Alternatively, catalyst bed 140 may comprise a hydroisomerization catalyst, a hydrocracking catalyst, another hydroprocessing catalyst, or combination thereof. Also, catalyst bed 140 will be at a lower temperature than catalyst bed 30, reducing the severity of the cracking activity of any of the hydroprocessing catalysts. Thus, this operation may be desired to optimize conversion without overcracking. Also, another fractionation zone (not shown) could be present in between catalyst beds 140 and 30. Further, one side stream may be drawn from any of distillation zones 40 and 50, or in between catalyst beds 140 and 30 if desired.

Throughout the specification, the term"Cx+ material"is meant to represent a material comprising molecules with at least a number"x"of carbon atoms; whereas"Cy-material"is meant to represent a material comprising molecules with at most a number"y"of carbon atoms.

The preceding discussion indicates that a variety of operations and arrangements are possible by varying distillation zones and catalyst beds. All of these operations are within the scope of the present invention. Further variations are obvious to one having ordinary skill in the art depending upon the desired product range and cracking severity. The present invention is not intended to be limited by any of the foregoing examples, but rather, is only intended to be limited by the following claims.