KR20030090677A - Two stage hydrocracking process - Google Patents

Abstract

The two-stage hydrolysis method is characterized by the operation of the second hydrolysis zone under reduced pressure which leads to the decomposition of the highly paraffinic effluent of the first hydrolysis zone. The method also passes a partially compressed hydrogen make-up gas stream into the second hydrolysis zone and then compresses the gas recovered from the second hydrolysis zone effluent to recover the make-up gas for the first stage hydrolysis zone. It is characterized by forming. There is no recycle gas stream for the second hydrolysis zone.

Description

Two Step Hydrolysis Method {TWO STAGE HYDROCRACKING PROCESS}

Technical field

The present invention relates to a hydrocarbon conversion process, referred to in the art as hydrogenolysis. This process is used industrially in petroleum refineries to reduce the average molecular weight of heavy or intermediate grades of crude oil. The present invention more directly relates to an integrated hydroprocessing / hydrohydrolysis process with a particular supplemental hydrogen flow path.

Background technology

Large quantities of hydrocarbons derived from petroleum are converted into high value hydrocarbon classifications used as automotive fuels by a purification process called hydrogenolysis. In this process, the heavy feed is contacted with the stationary phase of the solid catalyst in the presence of hydrogen at high and high pressure conditions, as a result of which a significant portion of the feed molecule is broken down into smaller and more volatile molecules. The high economic value of petroleum fuels has led to extensive development of hydrocracking catalysts and related process technologies.

Raw petroleum fractions contain significant amounts of organic sulfur and nitrogen. Sulfur and nitrogen must be removed to meet modern fuel specifications. Removing or reducing sulfur and nitrogen is also advantageous for operation of the hydrolysis reactor. Sulfur and nitrogen are removed in a process referred to as hydrotreating where organic sulfur and nitrogen are converted to hydrogen / sulfide and ammonia. Because the process conditions used in plasticizing and hydrocracking are similar, it is often the case that the two processes are integrated into one complete process unit with separate sequential reactors for the two reactions and a common product recovery section. have.

Related Fields

Hydrogenation and hydrogenolysis are both widely practiced industrial processes. Because of the very high economic utility of the hydrocracking process, much effort has been put into improving the process and developing better catalysts for use in the process. A general review and classification of the different hydrolysis process flow diagrams and description of the hydrolysis catalysts is given in Julius Scherzer and A.J., published in 1996 by Marcel Decker Incorporated. Gruia's Hydrocracking Science and Technology, pages 174-183. 10.2, 10.3 and 10.4 show a hydrotreating reactor upstream of the hydrolysis reactor. As mentioned herein, this is a conventional practice of first passing the hydrolysis unit feed stream through a hydrotreating reactor to lower the concentration of sulfur and nitrogen bound to the target petroleum molecule. Some form of intermediate separator between the hydrocracking zones can be used to reduce the amount of product hydrocarbons and hydrogen sulfide that pass to the second hydrocracking zone with hydrocarbon phase using two hydrocracking reaction zones in a row. have. As shown in Figures 10.4 and 10.5, this type of unit is generally referred to as a two-stage hydrolysis unit.

The high pressure used for the hydrocracking preserves the pressure of any portion of the hydrocracking effluent to be recycled, and also assists the effort to utilize the pressure reduction as a separation mechanism in the product recovery portion of the process. Thus, the effluent of a high pressure reactor, such as a hydrolysis reactor, is usually operated at a pressure similar to the outlet pressure of the reaction zone and flows into a vessel referred to as a high pressure separator (HPS). The vapor stream recovered from the HPS is often a precursor of a recycle gas or a hydrogen concentrated gas stream that is recycled to the reactor.

In the hydrocracking process, it is common practice to use a multistage compressor or compressor bank to pressurize a supplemental hydrogen stream and another compressor to pressurize the recycle gas stream. Such use of two different compressors is disclosed, for example, in US Pat. No. 4,197,184.

The field also includes the adsorption treatment of a liquid hydrocarbon recycle stream in a hydrogenolysis process to remove polynuclear aromatic (PNA) compounds as disclosed in US-A-4,447,315 and US-A-5,190,633.

Summary of the Invention

The present invention is, in part, a two stage hydrogenolysis process characterized by a fresh hydrogen stream. The entire make-up hydrogen stream enters the process through a second stage hydrolysis reactor operated at a pressure low enough to use the gas from the second stage of the three stage make-up gas compressor. Steam recovered from the second stage reactor is fed to the compression zone of the third stage. Low pressure in the second stage hydrolysis reaction zone has been found to promote the decomposition of paraffinic hydrocarbons that do not degrade in the first stage hydrolysis reactor. Thus, preferred second stage operating conditions synergistically interact with the process flow.

Broad embodiments of the invention may be characterized by a two-stage hydrolysis process. This process allows a feed stream containing hydrocarbons having a boiling point of at least 371 ° C. (700 ° F.) and hydrogen to be passed through a first hydrolysis zone operating at hydrolysis conditions including the first pressure and including a hydrolysis catalyst. Generating a first hydrocracked zone effluent stream comprising hydrogen, hydrogen sulfide, unconverted feed component and product hydrocarbons; Separation of the first hydrocracking zone effluent yields a recycle gas stream and a first liquid process stream, which are passed through a product fractionation zone to produce a bottoms stream and distillation product comprising unconverted feed components. Generating a stream; Passing the bottoms stream and the supplemental hydrogen gas stream to a second hydrolysis zone operating at paraffin selective hydrolysis conditions comprising a lower second pressure, and generating a second hydrolysis zone effluent stream; Separating the second hydrolysis zone effluent stream into a vapor phase stream and a liquid phase stream and passing the liquid stream through a product fractionation zone; And compressing the vapor phase stream and passing the vapor phase stream as a make-up gas stream to the hydrotreating reaction zone. In this embodiment, the first hydrolysis zone may comprise a hydroprocessing catalyst as a separate phase or as a reactor and is operated at a pressure at least 2068 kPa (300 psi) higher than the pressure in the second hydrolysis zone. desirable.

Brief description of the drawings

1 is a simplified process flow diagram illustrating supplemental hydrogen entering the second stage hydrocracking reactor 27. The vapor from the effluent of the reactor flows to the make-up gas compressor of the third stage 31 used in this process.

Detailed Description and Preferred Embodiments

Most of the crude oil produced cannot be directly used as a modern fuel or petrochemical feedstock. If sulfur and nitrogen are present in the fuel that increase air pollution, they must be purified to remove them. Crude oil must be refined to reduce the average molecular weight of the heavy components of the crude oil to match the volatility or flow characteristics of the fuel. Finally, the purification must meet the quality criteria for the particular hydrocarbon product.

The required purification can be carried out in several ways. One of the better established methods is to use catalytic hydrotreating and catalytic hydrogenolysis sequentially. This is a well developed method used in many petroleum refineries. The present invention relates to a flow diagram of a two-stage hydrolysis unit modified for the purpose of reducing the cost of the unit and potentially improving the distillation product.

Various feed materials derived from petroleum can be introduced into the process. Typical feedstocks include virtually any heavy mineral or synthetic oil classification having a boiling point of about 204 ° C. (400 ° F.) or greater. Thus, feedstocks such as straight run gas oil, vacuum gas oil, demetallized oil, coke-distillate distillate, cat cracker distillate and the like are included. Preferred feedstocks should not contain detectable asphaltenes. The hydrocracking feed may comprise nitrogen, which is present as the organic nitrogen compound, generally in an amount of 1 ppm to 1.0% by weight. The feed generally contains sufficient sulfur containing compound to provide sulfur in an amount of at least 0.15% by weight. The feed may also include mononuclear and / or polynuclear aromatic compounds in an amount of at least 35% by volume. Compounds in the feed to the hydrotreating zone may have boiling points within a wide range of from about 204 ° C. (400 ° F.) to about 593 ° C. (1100 ° F.), preferably from about 316 ° C. (600 ° F.) to about 550 ° C. (1022 ° F.).

In a representative example of a conventional hydrocracking process, heavy gas oil is introduced into the process and mixed with a hydrocarbon recycle stream. The resulting mixture of the two liquid streams is heated by indirect heat exchange means and combined with a hydrogen concentrated gas stream. The mixture of input hydrocarbons, recycle hydrocarbons and hydrogen is heated in a tubular heater to achieve the desired inlet temperature for the hydrocracking reaction zone. In the reaction zone a mixture of hydrocarbon and hydrogen is contacted with one or more beads of a solid hydrocracking catalyst maintained under hydrocracking conditions. Much of the hydrocarbons entering this contact are converted to molecules of lower molecular weight, resulting in lower boiling points.

Thus, with the remaining hydrogen not consumed in the reaction, light hydrocarbons such as methane, ethane, propane, butane and pentane formed by the decomposition of the feed hydrocarbons, and hydrogen sulfide and ammonia formed by the hydrodesulfurization and hydrogenonitride reactions; A reaction zone effluent stream is produced comprising a mixture of other reaction byproducts, such as. The reaction zone effluent also includes the desired product hydrocarbons boiling in the gasoline, diesel fuel, kerosene and / or fuel oil boiling ranges and some unconverted feed hydrocarbons boiling at temperatures above the boiling ranges of the desired products. The effluent of the hydrolysis reaction zone contains a very wide and varied mixture of individual compounds.

The hydrocracking reaction zone effluent is separated from contact with the catalyst bed, heat exchanged with the feed fed to the reaction zone for heat recovery, and then passed through a vapor-liquid separation zone, which generally comprises one or more high pressure separators. Let's do it. Further cooling may be carried out before separation. In some instances, a high temperature flash separator is used upstream of the high pressure separator. It is another option to use a "cold" separator to remove condensate from the steam removed from the hot separator. The liquid recovered in these vapor-liquid separation zones is passed through a product recovery zone comprising one or more fractional columns. Product recovery methods for hydrogenolysis are known and conventional methods can be used in the present invention.

In many cases, the overall conversion obtained in the hydrocracking reactor (s) is not complete and some heavy hydrocarbons are removed from the product recovery zone as "drag streams" removed from the product fractionator. Removing the drag stream from the hydrocracking process can make the conditions in the reaction zone (s) less stringent. The size of the drag stream ranges from 1-20% by volume of the process feed stream, although a range of 2-10% by volume is preferred. The unconverted hydrocarbon can be recycled to the first or second stage, preferably recycled to the second stage. If the entire process includes a hydrotreating reactor, the recycle stream can be passed to the first stage hydrotreating reactor. It may also be passed directly to the first stage hydrolysis reactor.

Over the years, hydrotreating and hydrocracking catalysts and process technologies have made significant advances. Nevertheless, the selectivity of the industrial hydrocracking process of converting the feed to hydrocarbons whose boiling point is within the selected boiling range is still incomplete. To optimize the process, operating parameters must be compromised, and selectivity improvement is a goal throughout the industry. It is an object of the present invention to provide an optional hydrocracking process for treating relatively light feeds that only require limited decomposition to convert to the desired product. It is a specific object of the present invention to provide an optional hydrocracking process for use with a feed stream comprising a significant amount of hydrocarbon already boiling within the desired product boiling range.

In this process, it is preferred to first carry out a hydrotreating step on the feed stream. This has traditionally been done as a means of removing sulfur and nitrogen from the feedstock to prepare a feed for the downstream hydrocracking reactor. One reason is that lower sulfur or nitrogen content tends to increase the observed activity of the hydrocracking catalyst. However, hydrogenation is optional. For example, the use of an amorphous (non-zeolitic) hydrolysis catalyst in the first stage generally eliminates the need for hydrogenation. As disclosed in the references, the hydrotreatment is often integrated with the first hydrolysis step. This can be done by placing a separate hydrolysis reactor immediately in front of the first hydrolysis reactor, or by actually including the hydrotreating catalyst upstream of the hydrolysis catalyst.

The hydrotreating step is a feed quality improvement step rather than a conversion or cracking step. The effluent from the hydrotreating reactor preferably comprises a mixture of hydrocarbons having a boiling point range that is about the same as the reactants entering the hydrotreating zone. Only a small amount, preferably 10%, is converted by decomposition in the hydrotreating process. Most preferably, less than 5% conversion in the hydrotreating band. Although conversion can occur to produce some lower boiling hydrocarbons, it is recommended that most of the feed pass through the hydrotreatment zone with a slight change in boiling point. Thus, the effluent of the downstream hydrolysis zone is fractionated to yield the final product distillate stream. Conversion is generally not preferred in the hydrotreating step because it lowers the yield of the desired intermediate distillation product. As used herein, the term "conversion" refers to the chemical change required to convert feed stream molecules into product hydrocarbons that become part of the distillation product recovered from the effluent of each reaction zone. Thus, the conversion is mainly related to boiling point changes rather than chemical changes relating to hydrogenation or desulfurization.

The HPS container may include some limited separation aids, or for example trays or structured packings, to facilitate better separation than that provided by a simple one step instantaneous separation. However, the high pressure in these vessels necessitates thick vessel walls and conduits, so that large high pressure separation devices such as columns are enormously expensive, resulting in a significant increase in equipment costs. There is no reflux or reboiling of HPS. Thus, the separation in the high pressure separator is inaccurate, and the composition of the classifications removed from the HPS will be quite redundant.

In general terminology of hydrolysis, a high pressure separator is a separator that operates at a pressure close to that of the upstream reactor. While some pressure drop may occur, such as inherent in fluid delivery through process lines and control valves, HPS is generally operated at a pressure within 1034 kPa (150 psi) of the upstream reactor. It is not advisable to reduce the pressure in the HPS to eliminate the significant cost of recompressing the hydrogen enriched gas recycled to the reaction zone.

Typically the maximum pressure process in petroleum refineries is a hydrogenolysis process. Thus, it is unlikely that it would be possible to supply supplemental hydrogen to replace the hydrogen consumed in the reaction and dissipated in the effluent during the process at a pressure similar to that of the hydrogenocatalyst unit. Therefore, the pressure of the feed or make-up hydrogen must be increased. Typically, this pressure increase is carried out in a dedicated compressor referred to as a supplemental compressor. A separate recycle compressor is used to circulate the gas stream flowing through the process. The use of multistage compression is basically implemented in an apparatus comprising a supplemental compressor. This is because in a single step the input energy required to perform this kind of compression, for example from 689 kPa (100 psi) to 17,237 kPa (2500 psi), is much greater.

1 is a simplified process flow diagram not shown for a typical apparatus required for the performance of a process such as valves, pumps and control systems. Referring to the drawings below, the feed stream enters the process via line 1 and is mixed with a hydrogen enriched make-up gas stream passing through line 2. As used herein, the term "rich" means that the molar concentration of a given chemical or compound species is at least 50%, preferably at least 70%. The mixture of make-up hydrogen and feed stream is mixed with the recycle gas stream in line 12. If necessary, the feed stream is heated by means not shown. The feed and hydrogen are passed through line 4 to the hydroprocessing reaction zone represented by reactor 5. The reactions occurring in this zone form some light hydrocarbons due to hydrogen sulfide and ammonia and undesirable side reactions, but only a very small fraction of the heavy hydrocarbons entering the reactor are decomposed. Thus, a mixed phase hydroprocessing reaction zone effluent stream is formed which passes through line 6 to the first hydrolysis zone represented by reactor 7. The reactor is operated under conditions that allow a significant amount of incoming feed compound to be converted to a low molecular weight compound. These conditions usually include pressures of about 12,409 kPa (1800 psia) or more, but can be as low as 10,342 kPa (1500 psi). Pressures of 13,788-17,237 kPa (2000-2500 psig) are commonly used. This results in a mixed-phase first hydrocracked zone effluent stream comprising gas such as hydrogen and hydrogen sulfide, reaction products and liquid unconverted feed hydrocarbons.

The first hydrolysis reaction zone effluent stream passes through a high pressure separator (HPS) 9 via line 8. This vessel is designed and operated to separate the inlet mixed phase mixture into a gaseous stream which is removed in line 10 and a liquid stream which is removed in line 13. The gaseous stream then passes through line 10 as a recycle gas stream. Since the recycle gas is recovered under reduced pressure due to the pressure drop occurring in the two reactors and conduits, it must be compressed back to the desired inlet pressure by the recycle compressor 34. The liquid stream comprises most of the product distillate boiling range hydrocarbons and unconverted feed hydrocarbons. These materials pass through line 13 through a product recovery and separation zone, represented by a single fractional distillation column 14. In general, one or more additional vapor liquid separations are carried out between HPS 9 and column 14 to separate most of the light hydrocarbons, such as methane and propane, produced as by-products.

Typically, it is not desirable to pass large amounts of these light compounds through the distillate production column. Thus, the liquid removed from the HPS 9 can be flowed to the column via conventional hot instant separators or cold high pressure separators (not shown). These separators, generally the stripping column in front of the product recovery column and the product recovery column itself, all remove volatiles such as hydrogen sulfide in the evaporated gas phase. The result is hydrogen sulfide, an unconverted compound with almost no organic sulfur and a recovered distillation product, depending on the effectiveness of the upstream hydrogenation. Low concentrations of sulfur and nitrogen assist the hydrocracking catalyst activity in the second stage.

Compounds that have passed through the product fractionation zone are separated into one or more distillation product streams depending on a number of purification specific factors. Two columns can be used to effect this separation, and the hard end stripping column is often located before the main product fractionation column. The distillation product may comprise a naphtha boiling range product of line 15, a kerosene boiling range product of line 16 and a diesel boiling range product of line 17. The hydrolysis zone rarely operates to convert 100% of the feed to the product. Instead, a percentage in the range of about 5-40% by volume of the feed may be removed from the process as a "unconverted" or "drag" material. Since unconverted is classified and subjected to significant hydrogenation and desulfurization of this material, it is generally superior to the corresponding feed compound. Degradation that occurs in this process will change the relative composition of these heavy materials so that compounds that are more difficult or more difficult to dissolve will be present at higher concentrations in the feed. As used herein, the term “unconverted” refers to a compound recovered from the product fractionation zone as part of a stream having a boiling point higher than desired in any product distillate stream.

The stream comprising unconverted hydrocarbonaceous material is removed from column 14 via line 18. This material has a higher concentration of paraffinic hydrocarbons than the feed stream. Some of the optionally unconverted material can be discharged from the process as drag stream as needed. The unconverted material of line 18 is preferably passed through an adsorption zone 19 that is designed and operated to selectively adsorb polynuclear aromatics (PNA). Process techniques for treating recycle streams in hydrocracking processes have been used industrially and are described in US-A-4,447,315; US A-4,618,412; References such as US-A-4,954,242 and US-A-5,190,633 are disclosed. Removal of PNA may be advantageous by preventing these materials from depositing in cold parts of the process, such as ion exchangers, to reduce heat exchanger efficiency. Deposition of PNA at these locations can cause excessive pressure drop in the process line and the exchanger, which can degrade heat exchange efficiency. In this process, the main purpose of removing PNA is to promote stable operation of the downstream hydrolysis zone. The activity and useful life of the catalyst in this zone can be much reduced from the normal range by the accumulation of PNA due to the operation at the desired low hydrogen pressure. This PNA removal zone can be operated under conditions of stream removed from the bottom of column 14. Many adsorbents comprising alumina are known and it is preferred to use activated carbon. As a result of the contact, it is desirable to produce a treatment stream of unconverted hydrocarbons with a low PNA content as measured by the method disclosed in the cited literature.

The treated hydrocarbon stream is removed from the PNA adsorption zone 19 via line 20 and mixed with the hydrogen concentrated gas stream passing through line 25. In this process, this gas stream is the make-up gas for the whole process and is preferably discharged from the second stage 24 of the three stage compression train. The flow rate of the make-up gas stream should generally be sufficient to meet the desired hydrogen concentration in the downstream second hydrolysis zone. If the feed stream requires only nominal hydrogenation, or if the hydrogen demand in the process is low for some other reason, the make-up gas stream of line 25 may be combined with the recycle gas. However, it is preferable not to introduce the recycle gas into the second hydrolysis zone. It is also desirable to compress all gases recovered from the second hydrolysis zone effluent and put them into the first hydrolysis zone. Gas separation is also preferably carried out using only a single HPS as illustrated.

The mixed-phase stream of unconverted hydrocarbon and hydrogen is heated as needed and passes through line 26 a second hydrocracking zone, represented by a single reactor 27. This reactor comprises a phase of a hydrolysis catalyst which is operated under paraffin selective cracking conditions different from the conditions of the first stage in that the pressure for hydrolysis is relatively low. Preferred operating pressures for this zone range from about 8270 to 12,400 kPa (1200 to 1800 psia). This low pressure has been found to promote the decomposition of paraffinic hydrocarbons compared to the typical high pressures used in the first hydrolysis zone 7.

Another prominent feature of the process is the use of a second stage supplemental hydrogen for the process as the only hydrogen stream introduced into the second stage hydrolysis zone. The ability to do this is related to the counterintuitive acquisition that lower pressures favor paraffin conversion by hydrogenolysis in the second stage. This is inferred from the relevant paraffin hydrolysis studies and is believed to result from the dehydrogenation step in the degradation mechanism. Typical unused feeds may comprise about 35-50% by volume aromatic hydrocarbons, depending on the source. The liquid recycle stream of the hydrocracking process has a much lower aromatic content, typically less than 10% total aromatic concentration.

The supplemental hydrogen introduced into the process in line 21 is compressed in a first stage compressor 22 and passes through a second stage or second compressor 24 via line 23. Depending on the design of the compressor zone, which includes three compressor stages, line 23 can be placed inside the compressor zone. It is preferred to pass the entire gas stream from the second stage through line 25 to the second hydrogenolysis reactor. This description assumes that supplemental hydrogen in line 21 is delivered to the process at a pressure indicating the use of a three stage compressor. Delivery of make-up hydrogen at higher pressure requires only one stage of compression before passing the make-up gas to the second hydrolysis zone.

Because of this and the benefits of the new hydrogen flow, the capital and operating costs associated with gas compression are reduced. However, a significant part of the capital cost savings of the process comes from a reduction in the operating pressure in the second stage, which lowers the process vessel and pipe plant costs. The second hydrolysis zone is at least 2068 kPa (300 psi) lower than the inlet pressure for the first hydrolysis zone comprising any prehydrolysis zone and at an inlet pressure of less than about 12,409 kPa (1800 psia). It is desirable to work. According to some factors, the second hydrolysis zone can be operated using an inlet pressure that is at least 3450 kPa (500 psig) lower than the first hydrolysis zone. A further advantage of this process is due to the lower pressure used in the second step. This lower pressure has been found to reduce the pour point of recovered diesel boiling range hydrocarbons, thereby increasing paraffin conversion which generally improves product quality.

Hydrocarbons removed as drag streams from the bottom of the product recovery column may be high value products, but are not considered distillates or conversion products in view of the definition of conversion. The desired "distillate" product of the hydrocracking process is generally recovered as a sidecut of the product fractional distillation column and includes naphtha, kerosene and diesel fractions. The product distribution of this process is determined by the selectivity of the catalyst and the feed composition at the conversion obtained in the reaction zone under the selected operating conditions. Therefore, it becomes a cause of considerable deviation. The process is particularly useful for producing intermediate distillate fractions that boil in the range of about 127 to 371 ° C. (260 to 700 ° F.) as determined by appropriate ASTM test procedures.

The term "middle distillate" is intended to include diesel, jet fuel and kerosene boiling range classifications. The terms “kerosene” and “jet fuel boiling range” mean about 127-288 ° C. (260-550 ° F.), and the diesel boiling range refers to a hydrocarbon boiling range of 127-371 ° C. (260-700 ° F.). Gasoline or naphtha classifications are typically considered to be 204 ° C. (400 ° F.) endpoint classifications in C ₅ to available hydrocarbons. The boiling point range of the various product classifications recovered in any particular refinery depends on factors such as the nature of the crude oil source, refinery local market, product price and the like. See ASTM Standard Methods D-975 and D-3699 for further details on kerosene and diesel fuel properties and D-1655 for aircraft turbine feeds. These definitions are provided for inherent variations in feeds and desired products per refinery. Typically, this definition requires the production of distillate hydrocarbons having a boiling point of about 371 ° C. (700 ° F.) or less.

The hydrotreatment zone is maintained at the conditions characterized such as the hydrotreatment conditions and the hydrolysis zone is maintained at the hydrolysis conditions, but these conditions may be somewhat similar. The pressure maintained in the hydrotreating and hydrocracking reaction zone should be within the broad range of about 6895-17,237 kPa (1000-2500 psia). Preference is given to using a pressure of at least 10,342 kPa (1500 psia) in the first hydrolysis zone. The reaction zone is operated at a hydrogen ratio of hydrocarbons (5,000-18,000 hydrogen standard ft ³ / barrel of feedstock) 843-3033 standard m ³ / m ³ . This ratio is preferably at least 1100 standard m ³ / m ³ in both hydrolysis zones. Thus, the second hydrolysis zone operates at lower pressures but not at milder hydrolysis conditions. The hydroprocessing zone may be operated at an inlet temperature of about 232-354 ° C. (450-670 ° F.). The hydrolysis zone can be operated at an inlet temperature of 338-427 ° C (640-800 ° F). In this process, the reaction zone is operated at a condition that includes a liquid hourly space velocity of about 0.2 to 10 hr ⁻¹ , preferably about 1.0 to about 2.5 hr ⁻¹ .

Preferred embodiments of the invention comprise the steps of compressing a first hydrogen make up stream to an intermediate first pressure through at least a first stage of a make-up gas compressor train; The feed stream, the recycle hydrogen stream, and the second make-up hydrogen stream comprising hydrocarbons having a boiling point of at least 371 ° C. (700 ° F.) are passed through a hydrotreating reaction zone operating under hydrotreating conditions, and the hydrogen, hydrogen sulphide and boiling points are weak. Generating a hydroprocessed reaction zone effluent stream comprising unconverted feed component at or above 371 ° C. (700 ° F.); The hydrotreatment reaction zone effluent stream is passed through a first hydrolysis zone containing a hydrolysis catalyst and operated at hydrolysis conditions including a first pressure to produce a first hydrolysis zone effluent stream. Doing; Separation of the first hydrocracking zone effluent yields a recycle gas stream and a first liquid process stream, which are passed through a product fractionation zone to produce a bottoms stream and distillation product comprising unconverted feed components. Generating a stream; The bottoms stream is passed through a PNA adsorption zone, passed through a second hydrolysis zone operating at paraffin selective hydrolysis conditions comprising a lower second pressure with a first supplemental hydrogen gas stream, and a second hydrolysis. Generating a band effluent stream; Separating the second hydrolysis effluent stream into a vapor phase stream and a liquid phase stream, and passing the liquid stream through a product fractionation zone; And compressing the gaseous stream to a higher second pressure in the final stage of the make-up gas compressor train and passing the vapor phase stream as a second hydrogen make-up stream to the hydrotreating reaction zone. It is done.

The process can use two different kinds of catalysts, namely hydrotreating catalysts and hydrocracking catalysts. These two types of catalysts generally share many similarities. For example, these catalysts may be relatively similar in particle shape and size. Generally both catalysts comprise an inorganic support material and at least one metal hydride. However, the two types of catalysts will be quite different because they are tailored to perform different functions. One of the most obvious differences is that the hydrogenolysis catalyst comprises at least one acidic decomposition component such as silica-alumina and / or Y-zeolite. Hydrotreating catalysts typically do not contain zeolite materials or molecular sieve materials and often contain only one or more metals on amorphous alumina. The two catalysts are expected to differ in different respects, such as the metal used as the hydrogenation component, particle pore volume distribution and density. Catalysts suitable for use in the reaction zone of the process are commercially available from various salespeople.

Hydrolysis and hydrotreating catalysts typically comprise a basic metal hydrogenation component selected from nickel, cobalt, molybdenum and tungsten, and promoters such as phosphorus supported on inorganic oxide catalysts. The metal hydride is generally a Group VIB and / or Group VIII metal component and each base metal is present at a concentration corresponding to about 2 to about 18 weight percent based on the finished catalyst as measured as a common metal oxide. The metals of the platinum group are preferably present at lower concentrations of about 0.1 to 1.5% by weight. Preferred catalyst types are extrudates having a symmetrical cross-sectional shape, preferably cylinder or multi-leaf type. The cross-sectional diameter of the particles is generally from 0.635 mm to 3.175 mm (1/40 to 1/8 inch), preferably from 0.794 mm to 2.116 mm (1/32 to 1/12 inch). Four-leaf cross-sections similar to four-leaf clover are shown in US Pat. No. 4,028,227. Other shapes that can be used in the catalyst are disclosed in this patent and in US Pat. No. 4,510,261.

Preferred high active hydrotreating catalysts comprise a hydrogenation component comprising nickel and molybdenum on an extruded porous support of alumina containing phosphorus. Details for the preparation of hydroprocessing catalysts comprising these four components are described in US Pat. No. 4,738,944; US-A-4,818,743 and US-A-5,389,595, which are incorporated by reference.

Both the hydrotreating catalyst and the hydrocracking catalyst preferably comprise a support material that is highly porous, uniform in composition, and relatively resistant to the conditions used in the hydrocarbon conversion process. The catalyst may include various support materials conventionally used in hydrocarbon conversion catalysts such as alumina, titanium dioxide, zirconium dioxide, silica-alumina, silica-magnesia, silica-zirconia, silica or silica gel, clays, and the like, and resistant inorganic oxides. Can be. Preferred support material for the hydrotreating catalyst is alumina.

When using the present invention, the physical properties and composition of the catalyst such as shape and surface area are not limited. For example, the catalyst may be present as a stationary phase in the reaction zone in the form of eggs, pellets, granules, broken fragments, spheres, or various special shapes such as three-lobed extrudate. Alternatively, the catalyst can be prepared in a suitable form for use in a mobile phase reaction zone in which hydrocarbon feedstock and catalyst are passed in countercurrent or cocurrent flow. Another alternative is to use a fluidized or ebullated phase in which the feedstock passes upwards through the turbulent bed of the finely divided catalyst, or the catalyst is slurried in the feedstock and the resulting mixture is transported to the reaction zone. To use a suspension reaction zone. The feedstock can be passed through the reactor (s) in liquid or mixed phase and upstream or downstream. Thus, the reaction zone need not be a fixed bed system as shown in the figure.

The catalyst particles can be prepared by any method known in the art, including known oil dropping and extrusion methods. The preferred form of catalyst used in this process is an extrudate.

Spherical catalysts for use in the hydrotreating or hydrocracking sections of the process are described in US-A-2,620,314; US-A-3,096,295; It can be formed using an oil dropping technique as disclosed in US-A-3,496,115 and US-A-3,943,070. Preferably, this method comprises dropping a mixture of molecular sieve, alumina sol and gelling agent into an oil bath maintained at high temperature. Droplets of this mixture are placed in an oil bath until cured to form a hydrogel sphere. The spheres are then discharged continuously from the initial oil bath and subjected to a special aging treatment in oil and ammonia solution to further improve the properties. Other references describing oil dropping methods for catalyst preparation include US Pat. No. 4,273,735; US-A-4,514,511 and US-A-4,542,113. The preparation of spherical catalyst particles by different methods is described in US-A-4,514,511; US-A-4,599,321; US-A-4,628,040 and US-A-4,640,807.

The hydrogenolysis catalyst preferably comprises 1 to 90% by weight of Y zeolite, preferably about 5 to 80% by weight. The zeolite catalyst composition should comprise a porous, resistant inorganic oxide support (matrix) capable of forming from about 10 to 99 weight percent, preferably from 20 to about 90 weight percent of the support of the finished catalyst composite. Most preferred matrices comprise a mixture of silica-alumina and alumina, wherein the silica-alumina constitutes 15-85% by weight of the matrix. The support also preferably comprises about 5 to about 45 weight percent of alumina.

Y zeolites have the essential X-ray powder diffraction pattern disclosed in US Pat. No. 3,130,007. The Y zeolite unit cell size is preferably in the range of about 24.20 to 24.40 mm 3, most preferably in the range of about 24.30 to 24.38 mm 3. The Y zeolite is preferably dealuminated, with a framework Si0 ₂ : Al ₂ 0 ₃ ratio of 6 or more, most preferably 6-25. It is also envisaged that other zeolites such as beta, omega, or ZSM-5 can be used as a zeolite component of the hydrogenolysis catalyst in place of or in conjunction with the preferred Y zeolite.

Claims (7)

(a) A feed stream comprising hydrocarbons having a boiling point of at least 371 ° C. (700 ° F.) and hydrogen are passed through a first hydrolysis zone operating at hydrolysis conditions including the first pressure and comprising a hydrolysis catalyst. And generating a first hydrocracked zone effluent stream comprising hydrogen, hydrogen sulfide, unconverted feed component and product hydrocarbons; (b) separating the first hydrocracking zone effluent to yield a recycle gas stream and a first liquid process stream, which is passed through a product fractionation zone to produce a bottoms stream comprising unconverted feed components. Producing a distillate product stream; (c) passing the bottoms stream and the supplemental hydrogen gas stream to a second hydrolysis zone operating at paraffin selective hydrolysis conditions comprising a lower second pressure, producing a second hydrolysis zone effluent stream. Doing; (d) separating the second hydrocracking effluent stream into a vapor phase stream and a liquid phase stream and passing the liquid stream through a product fractionation zone; And (e) compressing the vapor phase stream and passing the vapor phase stream as a make-up gas stream to a first hydrocracking reaction zone. The method of claim 1, wherein the bottom stream passes through the second hydrolysis zone after passing through the PNA adsorption zone. 3. The method of claim 1, wherein the second hydrolysis zone is operated at an inlet pressure at least 2068 kPa (300 psi) lower than the first hydrolysis zone. 4. The process of claim 1 or 2, wherein the first hydrogen make up stream is compressed to an intermediate first pressure, (a) The feed stream, recycle hydrogen stream, and second make-up hydrogen stream are passed through a hydrotreating reaction zone operating under hydrotreating conditions, and unconverted hydrogen, hydrogen sulfide, and boiling point above about 371 ° C. (700 ° F.). Produce a hydrotreating reaction zone effluent stream comprising the feed component; Passing the first make-up hydrogen gas stream to the first hydrocracking zone, with the bottom stream passing to the second hydrocracking zone, Compressing the gaseous stream to a higher second pressure to provide a second hydrogen make up stream. The method of claim 4, wherein the second hydrocracking zone is at least 2068 kPa lower than the first hydrocracking zone and is operated at an inlet pressure of less than 12,753 kPa. The process of claim 4, wherein the first hydrogen make up stream is compressed through at least a first stage of the make up gas compressor train; The vapor phase stream is compressed to a higher second pressure in the final stage of the make-up gas compressor train. The process of claim 6, wherein the entire vapor phase stream recovered from the second hydrocracking effluent stream is passed through a hydrotreating reaction zone.