Imported: 10 Mar '17 | Published: 27 Nov '08
USPTO - Utility Patents
The instant invention comprises a hydroprocessing method having at least two stages. The first stage employs a hydroprocessing catalyst which may contain hydrotreating catalyst, hydrocracking catalyst, or a combination of both. The subsequent stage is limited to hydrocracking. Conversion in subsequent stages may be improved by the addition of multiple reaction zones for hydrocracking, with flash separation zones between the stages. Middle distillate yield is thereby increased and the volume of the recycle stream is reduced. This invention reduces the need for equipment which would normally be required for a large recycle stream.
This application is a continuation-in-part of co-pending application Ser. No. 10/001,737, filed Oct. 25, 2001 and claims priority therefrom.
The invention relates to hydrocracking, and more particularly to hydrocracking occurring in more than one stage.
In the refining of crude oil, vacuum gas oil hydrotreaters and hydrocrackers are employed to remove impurities such as sulfur, nitrogen and metals from the feed. Typically, the middle distillate boiling material (boiling in the range from 250 F.-735 F.) from VGO hydrotreating or moderate severity hydrocrackers does not meet the smoke point, the cetane number or the aromatic specification required.
Removal of these impurities in subsequent hydroprocessing stages (often known as upgrading), creates more valuable middle distillate products. Hydroprocessing technology (which encompasses hydrotreating, hydrocracking and hydrodewaxing processes) aims to increase the value of the crude oil by fundamentally rearranging molecules. The end products are also made more environmentally friendly.
In most cases, this middle distillate is separately upgraded by a middle distillate hydrotreater or, alternatively, the middle distillate is blended into the general fuel oil pool or used as home heating oil. Recently hydroprocessing schemes have been developed which permit the middle distillate to be hydrotreated in the same high pressure loop as the vacuum gas oil hydrotreating reactor or the moderate severity hydrocracking reactor. The investment cost saving and/or utilities saving are significant since a separate middle distillate hydrotreater is not required.
There are several U.S. patent publications which are directed to multistage hydroprocessing within a single high pressure hydrogen loop. In U.S. Patent Application 20030111386, high conversion of heavy gas oils and the production of high quality middle distillate products is possible in a single high-pressure loop with reaction stages operating at different pressure and conversion levels. The flexibility offered is great and allows the refiner to avoid decrease in product quality while at the same time minimizing capital cost. Feeds with varying boiling ranges are introduced at different sections of the process, thereby minimizing the consumption of hydrogen and reducing capital investment.
U.S. Patent Application 2003111387 also discloses multi-stage hydroprocessing for the production of middle distillates. A major benefit of this invention is the potential for simultaneously upgrading difficult cracked stocks such as Light Cycle Oil, Light Coker Gas Oil and Visbroken Gas Oil or Straight-Run Atmospheric Gas Oils utilizing the high-pressure environment required for mild hydrocracking.
This invention, as are those discussed in the Background, is directed to processes for upgrading the fraction boiling in the middle distillate range which is obtained from VGO hydrotreaters and moderate severity hydrocrackers. This invention preferably involves a multiple stage process employing a single hydrogen loop. It could, however, be used in any fixed bed hydroprocessing scheme such as mild hydrocracking, conventional single stage or two stage hydrocracking and hydrotreating applications.
In this invention, removing distillate products as they are formed helps to improve the environment of the cracking reactions by more effective utilization of the reactor space, hydrogen and catalyst. Improved selectivity for distillates results, providing the yield of low per pass conversion, but without recycling large quantities of recycle oil.
The investment cost saving, as well as utilities savings, are significant since the hydrocracking reactor could be potentially taken out of a conventional recycle gas loop. Less catalyst volume and less hydrogen are required in the hydrocracking reactor as well. This invention may be employed in a reactor having multiple catalyst beds, or in a scheme employing several small, single bed reactors in series. Improved catalyst kinetics and activity also result from this invention.
The hydroprocessing method of the instant invention, which has at least two reaction stages, comprises the following steps:
The FIGURE illustrates the preferred embodiment of the invention. The oil feed in line 1 is preheated, and pumped up to the first stage hydrotreating reactor pressure by the first stage feed pump (not shown). Oil feed in line 1 is combined with preheated recycle gas (line 2) to form line 3. Line 3 is further heated by process heat exchange (not shown). Line 3 is also heated in the first stage feed furnace 5.
The combined feed is sent to the first stage hydrotreating reactor 10. In this reactor, the feed is hydrotreated and partially hydrocracked. Hydrogen recycle gas (line 4) is used to quench the reaction exothermic heat release. The effluent from this reactor, line 6, is composed of H2S, NH3, light gases, naphtha, middle distillate and hydrotreated heavy gas oil.
This first stage reactor effluent 6 is then cooled by preheating feed and/or steam generation (exchanger bank 25) and routed to a Hot High Pressure Separator (HHPS) 30 situated between the first stage hydrotreating reactor and the second stage hydrocracking reactor In HHPS, most of the 700-material is removed through line 8 and sent to hydrogen recovery and product fractionation. Material in line 8 is cooled (by steam generation or process heat exchange) and sent to a Cold High Pressure Separator (not shown) on its way to the recycle gas compressor.
HHPS is operated at a slightly lower pressure than the first stage hydrotreating reactor. HHPS bottoms, line 7, mainly composed of unconverted oil, is let-down under pressure (valve 35), combined with line 12, mixed with fresh makeup hydrogen (line 13) and routed to the inlet of the second stage hydrotreating or hydrocracking reactor 20. Line 12 is composed of recycle oil from fractionation (line 9) and fresh aromatic feed oil (line 11).
The liquid from the top bed (20a) of this hydrotreating or hydrocracking reactor is taken but (line 16) and flashed in a side vessel 40. Distillate products are removed overhead via line 17. The liquid from this side vessel 40 is removed via line 18 and is cooled in an indirect heat exchanger 45 heating a process stream-and put back to the bed below (20b) after added adequate fresh makeup hydrogen (line 23). This set is repeated for the subsequent beds in the hydrocracking reactor, with the effluent of bed 20b (line 19) being taken out and flashed in a side vessel 50. Distillate products are removed overhead via line 21. The liquid from this side vessel 50 is removed via line 22 and is cooled in an indirect heat exchanger 55 heating a process stream and put back to the bed below (20c) under its own pressure by gravity flow after added adequate fresh makeup hydrogen (line 26). The final liquid product is removed via line 23.
The total fresh makeup hydrogen for the plant is routed through the second stage hydrocracking reactor and the excess hydrogen arrives back in the recycle gas loop at the recycle gas compressor suction to satisfy the needs of first stage reactor.
The concept of removing products as they are formed results in better utilization of the given second stage hydrocracking reactor catalyst volume by incrementally increasing the true residence time available for the still unconverted oil and by delivering shots of high purity hydrogen to where specifically needed in the liquid phase. This further gives an incremental kinetics boost and results in higher per pass conversion. This gives the direct benefit of less recycle liquid from fractionator bottoms to achieve desired target conversion.
A customized hydrocracking catalyst system in an ascending/descending temperature profile would be used in the second stage reactor using relatively mild hydrocracking catalyst at the top beds and progressively higher activity stable (zeolitic) hydrocracking catalysts in subsequent beds.
Converted material from the Cold High Pressure Separator, side vessels, and reactor effluents from subsequent stages could be combined or kept separate and sent to product distillation and recovery. Or the second stage effluent could be post-treated by adding catalyst in the side vessels or in a downstream, low pressure, cleaner environment post-treat step.
The product distillation (not shown) could be a combined unit operation for the first stage hydrotreating reactor and second stage hydrocracking reactor products or could be a divided unit operation (within one shell) for separate distillation of first stage hydrotreating reactor and second stage hydrocracking reactor products.
In either step, the HHPS bottoms liquid would be cooled only to around 650 F (or desired second stage hydrocracking reactor inlet temperature) and using a hot high differential pressure pump directly sent to the second stage inlet without the need for an intermediate cooling/heating train or storage or a furnace. If required, any startup heating requirement of the second stage hydrocracking reactor could be combined with the first stage hydrotreating reactor feed furnace.
A wide variety of hydrocarbon feeds may be used in the instant invention. Typical feedstocks include any heavy or synthetic oil fraction or process stream having a boiling point above 392 F (200 C). Feeds to this invention generally include hydrocarbons boiling in the range form 500 F to 1500 F. Such feedstocks include vacuum gas oils, demetallized oils, deasphalted oil, Fischer-Tropsch streams, FCC and coker distillate streams, heavy crude fractions, etc. Other streams include heavy atmospheric gas oil, delayed coker gas oils, visbreaker gas oils, aromatic extracts, heavy residue thermal or catalyst upgrader gas oils, and thermal or catalyst fluid cracker cycle oils. Typical feedstocks contain from 100-5000 ppm nitrogen and from 0.2-5 wt. % sulfur.
The recycle oil (from the product distillation) can be introduced at the second stage hydrocracking inlet or at a suitable bed.
The hydrocracking process of this invention is especially useful in the production of middle distillate fractions boiling in the range of about 250-700 F (121-371 C). A middle distillate fraction is defined as having a boiling range from about 250 to 700 F. The term middle distillate includes the diesel, jet fuel and kerosene boiling range fractions. The kerosene or jet fuel boiling point range refers to the range between 280 and 525 F (138-274 C). The term diesel boiling range refers to hydrocarbons boiling in the range from 250 to 700 F (121-371 C). Gasoline or naphtha normally boils in the range below 400 (204 C). Boiling ranges of various product fractions recovered in any particular refinery will vary with such factors as the characteristics of the crude oil source, local refinery markets and product prices.
Hydroprocessing conditions is a general term which refers primarily in this application to hydrocracking or hydrotreating, preferably hydrocracking.
Hydrotreating conditions include a reaction temperature between 400 F-900 F (204)C-482 C), preferably 650 F-850 F (343 C -454 C); a pressure between 500 to 5000 psig (pounds per square inch gauge) (3.5-34.6 MPa), preferably 1000 to 3000 psig (7.0-20.8 MPa); a feed rate (LHSV) of 0.5 hr (1) to 20 hr (1) (v/v); and overall hydrogen consumption 300 to 2000 scf per barrel of liquid hydrocarbon feed (53.4-356 m (3)/m (3)feed).
Typical hydrocracking conditions include a reaction temperature of from 400 F-950 F (204 C-510 C), preferably 650 F-850 F (343 C-454 C). Reaction pressure ranges from 500 to 5000 psig (3.5-34.5 MPa), preferably 1500-3500 psig (10.4-24.2 MPa). LHSV ranges from 0.1 to 15 hr (1)(v/v), preferably 0.25-2.5 hr (1). Hydrogen consumption ranges from 500 to 2500 scf per barrel of liquid hydrocarbon feed (89.1445 m (3)H (2)/m (3)feed).
A hydroprocessing zone may contain only one catalyst, or several catalysts in combination.
The hydrocracking catalyst generally comprises a cracking component, a hydrogenation component and a binder. Such catalysts are well known in the art. The cracking component may include an amorphous silica/alumina phase and/or a zeolite, such as a Y-type or USY zeolite. Catalysts having high cracking activity often employ REX, REY and USY zeolites. The binder is generally silica or alumina. The hydrogenation component will be a Group VI, Group VII, or Group VIII metal or oxides or sulfides thereof, preferably one or more of molybdenum, tungsten, cobalt, or nickel, or the sulfides or oxides thereof. If present in the catalyst, these hydrogenation components generally make up from about 5% to about 40% by weight of the catalyst. Alternatively, noble metals(preferably used in lower beds), especially platinum and/or palladium, may be present as the hydrogenation component, either alone or in combination with the base metal hydrogenation components molybdenum, tungsten, cobalt, or nickel. If present, the platinum group metals will generally make up from about 0.1% to about 2% by weight of the catalyst.
Hydrotreating catalyst is preferably used in the upper beds. Hydrotreating catalysts will typically be a composite of a Group VI metal or compound thereof, and a Group VIII metal or compound thereof supported on a porous refractory base such as alumina. Examples of hydrotreating catalysts are alumina supported cobalt-molybdenum, nickel sulfide, nickel-tungsten, cobalt-tungsten and nickel-molybdenum. Typically, such hydrotreating catalysts are presulfided.