CA1272153A - Single-stage hydrotreating process - Google Patents
Single-stage hydrotreating processInfo
- Publication number
- CA1272153A CA1272153A CA000488159A CA488159A CA1272153A CA 1272153 A CA1272153 A CA 1272153A CA 000488159 A CA000488159 A CA 000488159A CA 488159 A CA488159 A CA 488159A CA 1272153 A CA1272153 A CA 1272153A
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- Prior art keywords
- catalyst
- hydrotreating
- stacked
- bed
- hydrogen
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
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Classifications
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
- C10G65/02—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only
- C10G65/04—Treatment of hydrocarbon oils by two or more hydrotreatment processes only plural serial stages only including only refining steps
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- Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Engineering & Computer Science (AREA)
- Chemical Kinetics & Catalysis (AREA)
- General Chemical & Material Sciences (AREA)
- Organic Chemistry (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Catalysts (AREA)
Abstract
A B S T R A C T
SINGLE-STAGE HYDROTREATING PROCESS
A process for catalytically hydrotreating hydrocarbon oils having a tendency to deactivate hydrotreating catalysts by coke formation, in the presence of hydrogen at elevated temperature and pressure which comprises passing:
a) oils having a final boiling point greater than 538 °C and containing less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 °C - 538 °C, or c) mixtures thereof, downwardly with a hydrogen-containing gas into a hydrotreating zone over a stacked-bed of hydrotreating catalysts under conditions suitable to convert more than 25% of the sulphur compounds present to H2S; wherein said stacked-bed comprises an upper zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB, a Group VIII metal, metal oxide or metal sulphide and a phosphorus compound and a lower zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB, a Group VIII metal, metal oxide or metal sulphide, and less than 0.5 %w phosphorus and separating the reaction product from said hydrotreating zone into a hydrogen-rich gas and a liquid hydrocarbon oil having reduced sulphur and/or heavy metal content.
SINGLE-STAGE HYDROTREATING PROCESS
A process for catalytically hydrotreating hydrocarbon oils having a tendency to deactivate hydrotreating catalysts by coke formation, in the presence of hydrogen at elevated temperature and pressure which comprises passing:
a) oils having a final boiling point greater than 538 °C and containing less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 °C - 538 °C, or c) mixtures thereof, downwardly with a hydrogen-containing gas into a hydrotreating zone over a stacked-bed of hydrotreating catalysts under conditions suitable to convert more than 25% of the sulphur compounds present to H2S; wherein said stacked-bed comprises an upper zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB, a Group VIII metal, metal oxide or metal sulphide and a phosphorus compound and a lower zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB, a Group VIII metal, metal oxide or metal sulphide, and less than 0.5 %w phosphorus and separating the reaction product from said hydrotreating zone into a hydrogen-rich gas and a liquid hydrocarbon oil having reduced sulphur and/or heavy metal content.
Description
SINGLE-STAGE HYDROT~EATING PROCESS
The present invention relates to a single-stage hydrorefining process for treating heavy oils using catalysts arranged in a particular manner, referenced to herein as "stacked bed". It particularly relates to a single-stage hydrorefining process for treating oils having a tendency to deactivate hydro~reating cata-ly3ts by coke formation, these being oils with high boiling compo-n~nts and~or oils with a low asphaltene content and very high boilin~ components, with a particular stacked bed catalyst arrange-ment. It has been found that the use of a stacked bed increases the 1~ cata~yst life or allows increased conversions relative to the more traditional ~atalysts used for the treating of these oils. The invention is particularly useful for meeting the demands of increa-sing hydrotreatment severity, such as sulphur removal, for poorer quality~heavy oil fractions both directly distilled or extracted 1~ from crude or crude fraction and oil fractions from thermal, steam, or catalytic cracking processes including mixtures of any of these ~aterials.
The continual changes in the refining industry such as the trend to poorer quality crudes and the continual increase in the
The present invention relates to a single-stage hydrorefining process for treating heavy oils using catalysts arranged in a particular manner, referenced to herein as "stacked bed". It particularly relates to a single-stage hydrorefining process for treating oils having a tendency to deactivate hydro~reating cata-ly3ts by coke formation, these being oils with high boiling compo-n~nts and~or oils with a low asphaltene content and very high boilin~ components, with a particular stacked bed catalyst arrange-ment. It has been found that the use of a stacked bed increases the 1~ cata~yst life or allows increased conversions relative to the more traditional ~atalysts used for the treating of these oils. The invention is particularly useful for meeting the demands of increa-sing hydrotreatment severity, such as sulphur removal, for poorer quality~heavy oil fractions both directly distilled or extracted 1~ from crude or crude fraction and oil fractions from thermal, steam, or catalytic cracking processes including mixtures of any of these ~aterials.
The continual changes in the refining industry such as the trend to poorer quality crudes and the continual increase in the
2~ stringency of oil product specifications (e.g. lower allowed 3ulphur content) is in part requiring the refiner to increase the s~verity of hydrotreating of traditional oil fractions and/or process fractions not traditionally treated. The increased severity and/or unusual feed generally have been causing increased deacti-vation of hydrotreating catalysts. By using the process according to the present invention the run length of a hydrotreating process with these oil fractions can be increased and/or higher severity operation and/or processing poorer quality oils can be allowed.
The use of lower price or locally available crudes frequently results in increased sulphur and/or nitrogen content of the oil fractions. Conversion processes such as thermal cracking, coking %~
~nd catalytic cracking are either being brought on-stream or are already processing poorer quality oils. The products from such processes are laden with heteroatoms such as sulphur and are more hydrogen deficient relative to products from better quality crudes 5 or oils distilled directly from crude or crude fractions. As a result, the products of the conversion processes and/or poorer crudes have to be additionally hydrotreated to meet specifications or to prepare for further treating/conversion. However, the higher operating temperatures required to remove the additional hetero-1~ ~to~s and adding additional hydrogen in addition to the hydrogen-deficient coke-like nature of these feeds result in increasing deactlvation of the hydrotreating catalysts due to coking. Any increase in hydrotreating catalyst activity and/or stability would anable refiners to upgrade the lower value poor quality and/or 1~ cracked oils at a significant economic benefit.
It is well known that hydrogen-deficient poor quality oils can be hydrotreated/hydrorefined with low catalyst deactivation rates at higher hydrorefining unit conditions - higher hydrogen pressure, and/or hydrogen-to-oil ratio, and/or oil-catalyst contact time. To _~ stay within the physical or design constraints of a unit or to continue to process the required volumes of oil, only relatively small variations in these parameeers can be made. As a result, very e~pensive hydrotreating equipment must be added to meet the changing goals unless catalysts with longer lives are available. Alterna-~5 tively, the refiner has to accept very short catalyst lives andincreased down time for frequent catalyst changes or use continuous o~ semicontinuous regeneration facilities. Larger and/or more ve3sels and additional equipment would be needed to process a given quantity of feedstock with these options. Of particular importance 3a to a refiner is the ability to process the hydrogen-deficient and/or poorer quality oils in existing hydrotreating units which do not have sufficient hydrogen pressure to prevent uneconomically rapid catalyst activity loss with existing catalysts utilized in a non-stacked bed configuration. Thus, improved processes and highly stable catalysts are in great demand.
.. ... . .
Several two-stage hydrotreating processes have been proposed in the art to overcome some of the difficulties of hydrotreating heavy oils. Re~erence is made to five patent specifications, wherein use is made of two catalyst reactor vessels.
In U.S. patent specification 3,766,058 a two-stage process is disclosed for hydrodesulphurizing high-sulphur vacuum residues. In the ~irst stage some of the sulphur is removed and some hydrogena-tion of the feed occurs, preferably over a cobalt-molybdenum catalyst supported on a composite of ZnO and Al2O3. In the second 3tage ehe effluent is treated under conditions to provide hydro-cracking and desulphurization of asphaltenes and large resin nt~lecules contained in the feed, preferably over molybdenum suppor-ted on alumina or silica, wherein the second catalyst has a greater averaga pore diameter than the first catalyst.
1~ In U.S. patent specification 4,016,049 a two-stage process is disclosed for hydrodesulphurizing metal- and sulphur-containing asphaltenic heavy oils with an interstage flashing step and with pareial feed oil bypass around the first stage.
In U.S. patent specification 4,048,060 a two-stage hydrodesul-phurization and hydrodemetallization process is disclosed wherein a different catalyst is utilized in each stage and wherein the second stage catalyst has a larger pore size than the first catalyst and a ~pecific pore size distribu~ion.
In U.S. patent specification 4,166,026 a two-step process is _~ taught wherein a heavy hydrocarbon oil containing large amounts of asphaltenes and heavy metals is hydrodemeta]lized and selectively cracked in the first step over a catalyst which contains one or ~re catalytic metals supported on a carrier composed mainly of m~gn~sium silicate. The effluent from the first step, with or 3n without separation of hydrogen-rich gas, is contacted with hydrogen in the presence of a catalyst containing one or more catalytic metals supported on a carrier, preferably alumina or silica-alumina, having a particular pore volume and pore size distribution. This two-step method is claimed to be more efficient than a conventional process wherein a residual oil is directly hydrodesulphurized in a one-step treatment.
In U.S. patent specification 4,392~945 a two-stage hydro~
refining process for treating heavy oils containing certain types of organic sulphur compounds is disclosed wherein use is made of a specific sequence of catalysts with interstage removal of ~12S and NH3. A nickel-containing conventional hydrorefining catalyst is present in the first stage. A cobalt-containing conventional hydrorefining catalyst is present in the second stage. The first 1~ 3t~ge is preferably operated under conditions to effect at least 5~ ~w de~ulphuri~ation, while thè second stage is preferably operRted tmder conditions to achieve at least about 90 %w desul-phuri3ation, relative to sulphur present in the initial oil feed to tha first stage. This process is primarily applicable to distillate s oil feeds boiling below 343 C which contain little or no heavy metals.
All of the patent specifications referred to hereinabove relate to two-stage hydrotreating processes for various hydrocarbon oils utili~ing certain advantageous catalysts and/or supports. In some of thesè processes removal of H2S and NH3 is required. ~owever, no reference is made in any of the afore-mentioned patent specifica-tions to a process whereby oils with final boiling points from 343 C to 538 C andlor oil with a low asphaltene content and with components boiling above 538 C can be hydrotreated with signifi-cantly improved catalyst life relative to a single catalyst system.
It has now been found that by using a specific stacked~bed catalyst arr~nge~ent containing different catalytically active compositions, oils with high boiling components (about 343 C - 538 C and/or oils with a low asphaltene content and with very high boiling 3a components (above 538 C) can be treated in a single stage hydro-treating process with improved catalyst-system life and/or increased hydrotreating conversions for a given feedstock. The process according to the present invention allows easy conversion of existing catalytic hydrotreating reactors to a stacked bed of specified catalysts. The present process operates well at hydrogen pressures below 75 bar (7500 kPa), so that no additional high pressure reactors need be constructed. The particular stacked bed combination of catalysts in accordance with the invention results in longer runs between replacements or regenerations for a given 5 oil than would be experienced with either catalyst used alone.
Alternatively, poorer quality oils can be processed at equivalent con~rersions or higher conversions for a given oil can be maintained with the same time between replacement or regeneration with the use o~ ehe single-stage stacked bed catalyst system according to the 1~ presant invention. The invention can be applied most usefully in s~tuations where rapid catalyst deactivation is occurring.
The present invention thus relates to a process for catalyti-cally hydrotreating hydrocarbon oils at elevated temperature and pressure in the presence of hydrogen by passing:
1~ a) oils having a final boiling point greater than 538 C and containing less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 C to 538 C, or c) mixtures thereof, down~ardly ~ith hydrogen or a hydrogen-containing gas into a hydrotrea~ing zone over a stacked-bed of hydrotreating catalysts under conditions suitable to convert more than 25% of the sulphur compounds present to hydrogen sulphide; wherein said stacked-bed comprises an upper zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB
~f the Periodic Table, a Group VIII metal, metal oxide or met~l ulphide and a phosphorus oxide and/or sulphide, and a lower zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIb, a Group VIII metal, matal o~ide or metal sulphide and less than 0.5 %w of phosphorus;
3a and separating the reaction product from said hydrotreating zone into a hydrogen-rich gas and a liquid hydrocarbon oil having a reduced heteroatom content.
The process according to the present invention is particularly suitable for systems where catalyst deactivation due to coking is a constraint. The bottom bed catalyst is preferably Ni-promoted when iii3 nitrogen removal is the predominant concern and is preferably Co-promoted when sulphur removal is the predominant concern.
~ ccording to the present invention oils having a) final boiling points above 538 C whilst having a heptane asphaltenes content less than about 2% by weight, b) final boiling points in the range between 343 C and 538 C, or c) mixtures thereof are contacted with hydrogen or a hydrogen-containing gas and passed downwardly under hydrodesulphurization conditions over a stacked-bed catalyse. The boiling points referred to in the present des-1~ cription are as defined by the American Society for Testing And~aterials ( AS~I) method D ?887-83 ("Boiling Range Distribution of Petroleum Fractions by Gas Chromatography") and is commonly known as TBP-GLC (true boiling point by gas liquid chromatography).
Normal heptane asphaltenes (asphaltenes) as discussed herein are me~sured by ehe Institute of Petroleum, London, method IP 143/78 ("Asphaltenes Precipitation with Normal Heptane").
The oils to be used as feedstock in the process according to the present invention will be oils having a tendency to deactivate hydrocreating catalysts by coke formation, under hydrotreating 2~ conditions and particularly under hydrodesulphurization conditions.
Downwardly has been used in this specification to indicate a ~irection and not an orientation and hence should not be construed to imply an orientation limitation on the instant invention. A
do~nwardly series flow of oil and gas through a reactor is the `2~ usual pattern; however, one could invert the reactor conceptually and put oil and gas in at the bottom in which the first catalyst ~one (Ni- and P-containing catalyst) should be the first main ~atalyst contacted by the oil and gas and would thus be in the bottom of the first reactor. ~s is well known in the industry, multiple reactors connected in series are placed individually. Oil and gas out of one reactor is piped up to the top of the next reactor; however, this process could be inverted. The above-des-cribed reactor configurations, as well as others apparent to those skilled in the art, are deemed to be within the scope of this
The use of lower price or locally available crudes frequently results in increased sulphur and/or nitrogen content of the oil fractions. Conversion processes such as thermal cracking, coking %~
~nd catalytic cracking are either being brought on-stream or are already processing poorer quality oils. The products from such processes are laden with heteroatoms such as sulphur and are more hydrogen deficient relative to products from better quality crudes 5 or oils distilled directly from crude or crude fractions. As a result, the products of the conversion processes and/or poorer crudes have to be additionally hydrotreated to meet specifications or to prepare for further treating/conversion. However, the higher operating temperatures required to remove the additional hetero-1~ ~to~s and adding additional hydrogen in addition to the hydrogen-deficient coke-like nature of these feeds result in increasing deactlvation of the hydrotreating catalysts due to coking. Any increase in hydrotreating catalyst activity and/or stability would anable refiners to upgrade the lower value poor quality and/or 1~ cracked oils at a significant economic benefit.
It is well known that hydrogen-deficient poor quality oils can be hydrotreated/hydrorefined with low catalyst deactivation rates at higher hydrorefining unit conditions - higher hydrogen pressure, and/or hydrogen-to-oil ratio, and/or oil-catalyst contact time. To _~ stay within the physical or design constraints of a unit or to continue to process the required volumes of oil, only relatively small variations in these parameeers can be made. As a result, very e~pensive hydrotreating equipment must be added to meet the changing goals unless catalysts with longer lives are available. Alterna-~5 tively, the refiner has to accept very short catalyst lives andincreased down time for frequent catalyst changes or use continuous o~ semicontinuous regeneration facilities. Larger and/or more ve3sels and additional equipment would be needed to process a given quantity of feedstock with these options. Of particular importance 3a to a refiner is the ability to process the hydrogen-deficient and/or poorer quality oils in existing hydrotreating units which do not have sufficient hydrogen pressure to prevent uneconomically rapid catalyst activity loss with existing catalysts utilized in a non-stacked bed configuration. Thus, improved processes and highly stable catalysts are in great demand.
.. ... . .
Several two-stage hydrotreating processes have been proposed in the art to overcome some of the difficulties of hydrotreating heavy oils. Re~erence is made to five patent specifications, wherein use is made of two catalyst reactor vessels.
In U.S. patent specification 3,766,058 a two-stage process is disclosed for hydrodesulphurizing high-sulphur vacuum residues. In the ~irst stage some of the sulphur is removed and some hydrogena-tion of the feed occurs, preferably over a cobalt-molybdenum catalyst supported on a composite of ZnO and Al2O3. In the second 3tage ehe effluent is treated under conditions to provide hydro-cracking and desulphurization of asphaltenes and large resin nt~lecules contained in the feed, preferably over molybdenum suppor-ted on alumina or silica, wherein the second catalyst has a greater averaga pore diameter than the first catalyst.
1~ In U.S. patent specification 4,016,049 a two-stage process is disclosed for hydrodesulphurizing metal- and sulphur-containing asphaltenic heavy oils with an interstage flashing step and with pareial feed oil bypass around the first stage.
In U.S. patent specification 4,048,060 a two-stage hydrodesul-phurization and hydrodemetallization process is disclosed wherein a different catalyst is utilized in each stage and wherein the second stage catalyst has a larger pore size than the first catalyst and a ~pecific pore size distribu~ion.
In U.S. patent specification 4,166,026 a two-step process is _~ taught wherein a heavy hydrocarbon oil containing large amounts of asphaltenes and heavy metals is hydrodemeta]lized and selectively cracked in the first step over a catalyst which contains one or ~re catalytic metals supported on a carrier composed mainly of m~gn~sium silicate. The effluent from the first step, with or 3n without separation of hydrogen-rich gas, is contacted with hydrogen in the presence of a catalyst containing one or more catalytic metals supported on a carrier, preferably alumina or silica-alumina, having a particular pore volume and pore size distribution. This two-step method is claimed to be more efficient than a conventional process wherein a residual oil is directly hydrodesulphurized in a one-step treatment.
In U.S. patent specification 4,392~945 a two-stage hydro~
refining process for treating heavy oils containing certain types of organic sulphur compounds is disclosed wherein use is made of a specific sequence of catalysts with interstage removal of ~12S and NH3. A nickel-containing conventional hydrorefining catalyst is present in the first stage. A cobalt-containing conventional hydrorefining catalyst is present in the second stage. The first 1~ 3t~ge is preferably operated under conditions to effect at least 5~ ~w de~ulphuri~ation, while thè second stage is preferably operRted tmder conditions to achieve at least about 90 %w desul-phuri3ation, relative to sulphur present in the initial oil feed to tha first stage. This process is primarily applicable to distillate s oil feeds boiling below 343 C which contain little or no heavy metals.
All of the patent specifications referred to hereinabove relate to two-stage hydrotreating processes for various hydrocarbon oils utili~ing certain advantageous catalysts and/or supports. In some of thesè processes removal of H2S and NH3 is required. ~owever, no reference is made in any of the afore-mentioned patent specifica-tions to a process whereby oils with final boiling points from 343 C to 538 C andlor oil with a low asphaltene content and with components boiling above 538 C can be hydrotreated with signifi-cantly improved catalyst life relative to a single catalyst system.
It has now been found that by using a specific stacked~bed catalyst arr~nge~ent containing different catalytically active compositions, oils with high boiling components (about 343 C - 538 C and/or oils with a low asphaltene content and with very high boiling 3a components (above 538 C) can be treated in a single stage hydro-treating process with improved catalyst-system life and/or increased hydrotreating conversions for a given feedstock. The process according to the present invention allows easy conversion of existing catalytic hydrotreating reactors to a stacked bed of specified catalysts. The present process operates well at hydrogen pressures below 75 bar (7500 kPa), so that no additional high pressure reactors need be constructed. The particular stacked bed combination of catalysts in accordance with the invention results in longer runs between replacements or regenerations for a given 5 oil than would be experienced with either catalyst used alone.
Alternatively, poorer quality oils can be processed at equivalent con~rersions or higher conversions for a given oil can be maintained with the same time between replacement or regeneration with the use o~ ehe single-stage stacked bed catalyst system according to the 1~ presant invention. The invention can be applied most usefully in s~tuations where rapid catalyst deactivation is occurring.
The present invention thus relates to a process for catalyti-cally hydrotreating hydrocarbon oils at elevated temperature and pressure in the presence of hydrogen by passing:
1~ a) oils having a final boiling point greater than 538 C and containing less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 C to 538 C, or c) mixtures thereof, down~ardly ~ith hydrogen or a hydrogen-containing gas into a hydrotrea~ing zone over a stacked-bed of hydrotreating catalysts under conditions suitable to convert more than 25% of the sulphur compounds present to hydrogen sulphide; wherein said stacked-bed comprises an upper zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB
~f the Periodic Table, a Group VIII metal, metal oxide or met~l ulphide and a phosphorus oxide and/or sulphide, and a lower zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIb, a Group VIII metal, matal o~ide or metal sulphide and less than 0.5 %w of phosphorus;
3a and separating the reaction product from said hydrotreating zone into a hydrogen-rich gas and a liquid hydrocarbon oil having a reduced heteroatom content.
The process according to the present invention is particularly suitable for systems where catalyst deactivation due to coking is a constraint. The bottom bed catalyst is preferably Ni-promoted when iii3 nitrogen removal is the predominant concern and is preferably Co-promoted when sulphur removal is the predominant concern.
~ ccording to the present invention oils having a) final boiling points above 538 C whilst having a heptane asphaltenes content less than about 2% by weight, b) final boiling points in the range between 343 C and 538 C, or c) mixtures thereof are contacted with hydrogen or a hydrogen-containing gas and passed downwardly under hydrodesulphurization conditions over a stacked-bed catalyse. The boiling points referred to in the present des-1~ cription are as defined by the American Society for Testing And~aterials ( AS~I) method D ?887-83 ("Boiling Range Distribution of Petroleum Fractions by Gas Chromatography") and is commonly known as TBP-GLC (true boiling point by gas liquid chromatography).
Normal heptane asphaltenes (asphaltenes) as discussed herein are me~sured by ehe Institute of Petroleum, London, method IP 143/78 ("Asphaltenes Precipitation with Normal Heptane").
The oils to be used as feedstock in the process according to the present invention will be oils having a tendency to deactivate hydrocreating catalysts by coke formation, under hydrotreating 2~ conditions and particularly under hydrodesulphurization conditions.
Downwardly has been used in this specification to indicate a ~irection and not an orientation and hence should not be construed to imply an orientation limitation on the instant invention. A
do~nwardly series flow of oil and gas through a reactor is the `2~ usual pattern; however, one could invert the reactor conceptually and put oil and gas in at the bottom in which the first catalyst ~one (Ni- and P-containing catalyst) should be the first main ~atalyst contacted by the oil and gas and would thus be in the bottom of the first reactor. ~s is well known in the industry, multiple reactors connected in series are placed individually. Oil and gas out of one reactor is piped up to the top of the next reactor; however, this process could be inverted. The above-des-cribed reactor configurations, as well as others apparent to those skilled in the art, are deemed to be within the scope of this
3~ invention.
The feedstocks to be applied in the process in accordance with this invention may be taken from straight run oils (non-cracked) or thermally-, steam-3 or catalytically cracked hydrocarbonaceous materials, Suitable feeds include petroleum derived gas oils distilled from crude or crude fractions at atmospheric or at reduced pressure; solvent extracted oils such as extracted oils commonly referred to as Deasphalted Oils; thermally or steamed cracked oils or fractions ~hereof such as coker gas oils; gas oils or cycle oils from catalytic cracking and mixtures of two or more 1~ of the above materials.
Multiple uses of these feedstocks after initial treating in accordance with the process according to the present invention are also possible. Depending on particular feedstocks treated, suitable use3 may include feed and additions to feed to units for slgnifi-1~ cant molecular weight reduction such as catalytic cracking units orhydrocracking units; direct use or by blending with other oils or additives for sale as transportation fuels such as diesel oils; or for refinery fuel.
The stacked-bed catalyst system to be used in the process a according to the present invention comprises firstly a normally Ni-and P-containing conventional hydrotreating catalyst. The second catalyst to be contacted by the oil normally comprises a low- or no-phosphorus content conventional catalyst. Preferably~ the second catalyst contains no phosphorus. The second catalyst is also a ~2~ convantional catalyst and contains Ni and/or Co in the formulation.
When desulphurization is the primary ob~ective of the hydrotreating process, the second catalyst contains Co in preference to Ni; when denitrogenation is the primary ob;ective, the second catalyst prP~erably contains Ni in preference to Co. The catalysts herein 3a can be prepared by techniques well known in the art. The advantages of this invention primarily accrue from the particular combination of operable hydrotreating catalysts in a stacked-bed rather than from any particular method or manner of fabricating the catalyst.
The first main hydrotreating zone catalyst used in the process according to the present invention suitably comprises a Ni- and P-con~aining conventional hydrotreating catalyst. Conventional hydro~reating catalysts which are suitable for the first catalyst 20ne generally comprise a phosphorus oxide and/or sulphide compo-nent and a component, selected from group VIB of the Periodic Table and a group ~III metal, metal oxide, or metal sulphide and/or mi~tures thereof composited with a support. These catalysts will contain up to 10 %w, usually 1 to about 5 %w of the group VIII
metal compound calculated basis the metal content, from 3 to about 15 `~w of the group VIB metal compound calculated basis the metal n ~ontent, and from 0.1 to 10 %w phosphorus compounds calculated basis phosphorus content. Preferably, the catalyst comprises a nickel component and a molybdenum and/or tungsten component with an alumina support which may additionally contain silica. A more preferred catalyst comprises a nickel component, a molybdenum component, and a phosphorus component with an alumina support which may also contain small amounts of silica. Preferred amounts of components range from 2 to 4 %w of a nickel component calculated basis metal content, 8-15 %w of a molybdenum component calculated basis metai content, and 1 to 4 %w, more preferably 2 to 4 %w, of a phosphorus component calculated basis the phosphorus content. The catalyse can be used in any of a variety of shapes such as spheres and e~trudates. The preferred shape is a trilobal extrudate.
Preferably, the catalyst is sulphided prior to use, as is well known to the art.
~5 The use of low-phosphorus or no-phosphorus catalysts in the s~rond ~one is thought to be of benefit due to reduced deactivation by Cokin8-Low-phosphorus content catalysts having high surface areas tgraater than about ~00 m2/g) and high compacted bulk densities t0.6-0.85 gtcm3) are preferably used for the second zone as they appear to be highly active. The high surface area increases reac-tion rates due to generally increased dispersion of the active components. ~igher density catalysts allow one to load a larger amount of active metals and promoter per reactor volume, a factor which is commercially important. The metal content specified above g provides high activity per reactor volume. Lower metal contents normally result in catalysts exerting too low activities for proper use in the process according to the present invention. Higher metal loadings than specified above do not contribute significantly to the performance and thus lead to an inefficient use of the metals resulting in high catalyst cost with little advantage. Since deposits of coke are thought to cause the majority of the catalyst deactivation, fresh catalyst pore volume should be at or above a modest level (0.4-0.8 cm3/g, more narrowly 0.5-0.7 cm3/g). The second zone catalyst can be used like the first zone catalyst in a vasiety of shapes. Preferably, the catalyst is sulphided prior to use as is well ~nown to the art.
The Ni-containing catalyst used for the first zone is prefera-bly a high activity conventional catalyst suitable for high levels ~f hydrogenation. Such catalysts have high surface areas (greater than 140 m2/g) and high compacted bulk densities (0.65-0.95 g/cm3, more narrowly 0.7-0.95 g/cm9). The high surface area increases reaction rates due to generally increased dispersion of the active components. Higher density catalysts allow one to load a larger amount of active metals and promoter per reactor volume, a factor which is commercially important. The metal and phosphorus content specified above provides the high activity per reactor volume.
Lo~er metal contents result in catalysts exerting too low activi-ties for proper use in the process according to the present inven-tion~ Higher metal contents do not contribute significantly to theperformanca and thus lead to an inefficient use of the metals and hi8her cost for the catalyst. Since deposits of coke are thought to cause the majority of the catalyst deactivation, fresh catalyst pore volume should be at a modest level (0.4-0.8 cm3/g, more 3~ nflrrowly 0.4-0.~ cm3/g).
A low-phosphorus or no-phosphorus conventional hydrotreating caealyse is used in the second zone of the caealyst system. Co and/or Ni containing conventional catalysts can be suitably applied.
The second zone catalyst differs from the first zone catalyst primarily in its low-phosphorus content (less than 0.5 %w). The preferred catalyst contains less than about 0.5 %w phosphorus and comprises a component from group VIB and a group VIII metal, metal o~ide, or metal sulphide and/or mixtures thereof composited with a SUppO1t Preferably, the catalyst comprises a nickel and/or cobalt 5 component and a molybdenum and/or tungsten component with an alumina support which may additionally contain silica. Preferred metal contents are up to 10 %w, usually 1 to 5 %w of group VIII
metal component(s) calculated basis the metal content, and from 3 to 30 ~w of group VIB metal component(s) basis the metal content. A
more preferred catalys~ comprises a cobalt or nickel component and molybdanum component with an alumina support.
The present invention preferably relates to a process for hy~rotreating oils having a tendency to deactivate hydrotreating catalysts by coke formation, by passing a) oils having a final ls boiling point above 588 C and having less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 C to 538 C, or c) mi~tures thereof downwardly with hydrogen or a hydrogen-containing gas (mixture) in~o a hydrotreating zone over a stacked-bed of two hydrotreating catalysts under conditions suitable ~d to convert more than 25% of the sulphur compounds present to H2S, wherein said stacked-bed comprises an upper zone containing of from 15-85 %v, basis total catalyst, of a high-activity hydrotreating catalyst which comprises from 2-4 %w nickel, from 8-15 %w molyb-denum and from 1-4 %w phosphorus supported on a carrier consisting ~5 mostly of alumina, and a lower zone containing of from 15-85 %v, ba~is total catalyst, of a high-activity, hydrodesulphurization catalyst which comprises from 2-4 %w cobalt and/or nickel, from 8-15 %w molybdenum and less than 0.5 %w phosphorus supported on a carrier consisting mostly of alumina; and separating the reaction 3a product from said hydrotreating zone into a hydrogen-rich gas and a liquid oil having reduced sulphur and/or heavy metal content.
The physical characterizations of the catalysts referred to herein are common to those skilled in the catalyst development art.
Surface areas refer to nitrogen adsorption surface areas preferably determined by at least three points. Pore size distributlons are determined by mercury intrusion and calculated with a 130 degree contact angle. Pore volumes stated are water pore volumes and indicate the volume of water per weight of catalyst necessary to fill the catalyst pores to an incipient wetness of the catalyst.
The volume of the first catalyst zone in the present invention is from 15 to 85 %v of the main catalyst charge. The remaining fraction of the main catalyst charge is composed of the second catalyst. The division of the catalyst volumes over the zones in the bed depends upon the requirement for nitrogen conversion versus the requlrements for stability and other hydrotreating reactions such a~ sulphur and metals removal. Stacked-beds can be used to cailor the amount of nitrogen removal, sulphur and metals removal, and system stability. An increase in the first catalyst will increase the nitrogen removal but will effect the hydrodesulphuri-1~ æation tHD~) activity and stability of the system. Below a catalystratio of 15:85 or above a catalyst ratio of 85:15 (upper:lower) the benefits for the stacked-bed system are not large enough to be of practical significance. There is no physical limit on using a s~aller percentage of one or the other beds.
The catalyst zones referred to herein may be in the same or different reactors. For existing units with one reactor the catalysts are layered one on top of the other. Many hydrotreating reactors consist of two or more reactors in series. The catalyst zones are not restricted to the particular volume of one vessel and can -~ e~tend into the next ~prior) vessel. The zones discussed herein refer to the main catalyst bed. Small layers of catalysts which are different sizes are frequently used in reactor loading as is known to those skilled in the art. Intervessel heat exchange and/or hydrogen addition may also be used in the process according to the 3~ present invention.
The pore siæe of the catalyst does not play a critical role in the process according to the present invention. The catalysts in the two zones may be based upon the same carrier. Normally, the finished catalysts will have small differences in their average pore sizes due to the diff~rences in the respective metal and phosphorus loadings.
Suitable conditions for operating the catalyst system in accordance with the present invention are given in Table I.
TABLE I
_ Broadest Broad Narrow Narrowest Conditions range range range range MyAro~en p~rtlal 6.8-75 20-75 20-55 34-55 ~rassura, bar ~otAl pressure, bar 13.6-95 27-95 27-75 47-75 ~ydrogen/feed ratio, 17-1780 17-890 51-255 85-255 Nl/kg feed .
Temperaturej C 150-455 285-455 285-42S 345-425 Liquid hourly space 0.1-10.0 - 0.5-5.0 velocity, kg/kg.h At temperatures below 285 C (for very heavy feeds) and below ~5 150 C (for heavy feeds), the catalysts do not exhibit sufficient ~ctivity for the rates of conversion to be of practical signifi-c~nce. At temperatures above 455 C the rate of coking and cracking ba~oma e~cessive resulting in increasingly impractical operations.
RaActor metflllurgy n~ay also be a limitating constraint above 455 ~C
3a ~t the highar pressures.
At liquid space velocities below 0.1 kg/kg.h, the residence time of the oil is long enough to lead to thermal degradation and coking. At liquid space velocities above 10 kg/kg.h the conversion ~cross the reactor is too small to be of practical use. For space i3 velocity and gas-to-oil ratio calculations referred to herein, volumes are measured at 15.5 C and atmospheric pressure.
Hydrogen partial pressure is very important in determining the rate of catalyst coking and deactivation. At pressures below 6.8 bar, the catalyst system cokes too rapidly even ~ith better quality oil containing high boiling components. At pressures above 75 bar, the deactivation mechanism of the catalyst system appears to be predominantly that of metals deposition, if present, which results in pore-mouth plugging. Catalysts of varying porosity can Id be used to address deactivation by metals deposition, as is known ~y those skilled in the art. The hydrogen to feed ratio to be applied in the process according to the present invention is raquired to be above 17 Nl/kg feed since the reactions occurring during hydrotreating consume hydrogen, resulting in a deficiency of hydrogen at the bottom of the reactor. This deficiency may cause rapid coking of the catalyst and leads to impractical operation. At hydrogen to feed ratios in excess of ~90 Nl/kg feed~ no substantial `benefit is"obtained; thus`the expense of compression beyond this rate is not warranted.
Nitrogen removal is an important factor in hydrotreating heavy oils. Catalysts without phosphorus can be more stable with heavy oils under the conditions noted above; however, nitrogen removal activity is low for no-phosphorus catalysts relative to their phosphorus promoted counterparts. Additionally, Co promoted cata-2$ lyses are less active for nitrogen removal than are Ni promotedcatalysts. Stacked catalyst beds can be used to taiIor the amount o~ nitrogen removal, sulphur and metals removal, and system stabi-lity. It has been found that a stacked-bed system also improves activities (other than nitrogen removal) as well as the stability of the overall catalyst system relative to either catalyst used individually. The stacked-bed catalyst system is applicable when processing feeds under conditions where a heavy feed is causing deactivation primarily by coking.
The process according to the present invention should be operated at conditions suitable to remove at least 25% and gene-rally conditions will be applied to remove 30-80%, more preferably 45-75~, of the sulphur in the feed. When metals such as Ni and V
are present in the feed and demetallization is the primary focus the process can be operated at the lower levels of desulphurization.
S l~hen there is little metal in the feed and demetallization is not the primary goal, one can operate the process at higher sulphur removal rates.
The invention is accompanied by Figures 1 and 2 wherein some of the results as described in the Examples are depicted graphi-lly.
Figura 1 represents a graph showing the advantage obtained in the reactor inlet temperature as a function of time when the stacked-bed according to the present invention is utilized.
Figure 2 represents a graph showing the advantage obtained in lS the reactor outlet temperature as a function of time when the stacked-bed according to the present invention is utilized.
The following Examples are presented to illus~rate the present invention.
E~A~LE 1 A cstalyst A containing nickel, molybdenum and phosphorus ~upported on a gamma alumina carrier was prepared from commercially available alumina powders. This carrier was extruded into 1.6 mm pellets having a trilobal cross section. The pellets were dried and calcined before being impregnated with the appropriate catalytically active metals by a dry pore volume method i.e., by adding only enough solution to Eill the alumina pore volume. Carriers containing in addition to alumina, a few per cent of othar components like silica or magnesia can also be applied. An appropriate aqueous solution of nickel nitrate, nickel carbonate, phosphoric acid, 3~ hydrogen peroxide, and ammonium molybdate was used to impregnate the carrier. The metal loadings and some properties of the dried, calcined catalyst (A) are given in Table II.
A catalyst B containing cobalt and molybdenum supported on a similar alumina carrier as used to prepare catalyst A was prepared.
Likewise, this carrier was also extruded into 1.6 mm pellets having a trilobal cross-section. The pellets were dried before being impregnated with ~he appropriate catalytically active metals by a dry pore volume method. An appropriate aqueous solution of cobalt carbonate, ammonium dimolybdate and ammonia was used to impregnate the carrier. The metal loadings and properties of the dried, calcined catalyst (B) are also given in Table II.
TABLE II
Catalyst - A B
~iameter 1.6 mm 1.6 mm Cross-section Trilobal Trilobal Composition, %w Ni 3.0 Co - 3.2 ~o 13.0 9.6 3.2 Comp~cted bulk density, g/cm3 0.82 0.71 Surface Area, m2/g 164 226 Hg-pora volume, cm9/g 0.47 0.61 -Three different commercial runs with a main catalyst charge o~
25 a Ni-Mo-P/alumina catalyst, a Co-Mo/alumina catalyst and a stacked-bed of a Ni-Mo-P/alumina catalyst over a Co-Mo/alumina catalyst ~ere carried out. In Fig. 1 the reactor inlet temperature (RIT in C) necessary to maintain 0.3~ weight sulphur in the product is ~raphically represented as a Eunction of time (days), which is a 3~ conveniqnt measure of general catalyst activity. The Ni-Mo-P cata-lyst data are represented as circles (upper line)~ the Co-Mo catalyst data as triangles (middle line) and the stacked catalyst data as diamonds (lower line). The stacked-bed system has good activity and stability for sulphur removal as well as denitrifica-tion advantages. The average feed properties and average unit conditions are given in Table III. The feed applied was a heavy vacuum gas oil l1aving a final boiling point above 538 C and containing less than 2 %w of heptane asphaltenes. Feed to the unit and unit conditions were remarkably constant during the runs considering the unie is a commercial unit. In the stacked-bed system the ~i-Mo-P catalyst formed about 33% of the main catalyst load while the Co-Mo catalyst made up the remainder of the main catalyst load. Oil and gas flowed in a single-stage and serially over first the ~i-Mo-P catalyst and then over the Co-Mo catalyst.
The main advantages of the stacked-bed system sho~n by this ~ample comprise a) a significant increase in catalyst stability as can be seen in Fig, 1 where the increase in RIT with time is ~ignificantly less for the stacked-bed system (3.1 C/month versus 1~.5 C/month) relative to the single catalyst system; b) an 1~ increase in catalyst activity as represented by about a 8.1 C
lower initial RIT for the same level of sulphur in the product;
c) a resulting greatly improved estimated catalyst life of about 400% for the stacked-bed relative to the single bed due to the improvements in activity and stability. An end of run temperature ~a of 416 C and a continued linear decline rate was used to estimaee the catalyst life of the stacked-bed system.
- 17 ~
TABLE III
Feed/Process properties Hydrogen partial pressure 38 bar Liquid hourly space velocity 3 kg/kg.h Sulphur, ~ wt 1.1 Nickel, ppm 0.6 Vanadium, ppm 0.7 RCR, ~ wt 0.3 TBP-~LC~ C
IBP/10~ 265/347 90~95% 524/538 .
E~LE 2 A second set of two commercial runs with a Ni-~lo-P/alumina caealyst and a stacked-bed of a Ni-Mo-P/alumina catalyst over a Co-Mo/alumina catalyst ~as also carried out. A Ni-Mo-P/alumina catalyst would be one that one skilled in the art would traditio-nally have chosen ~or this feedstock when considering hydrogena-tion, denitrificationJ and de~.ulphurization catalyst activity rather than a Co-~o catalyst. Table IV summarizes approximate average unit conditions and feedstock. The oil is a blend of straight run vacuum gas oil tdistilled from non-cracked oil) and a I a coker heavy gas oil. In Table V the approximate average performance for the two runs at two catalyst ages is summarized and in Figure 2 the reactor outlet temperature necessary to maintain 0.75% weight and 0.60% weight sulphur in the product for the single catalyst and the stacked bed system is depicted as a function of time (days~.
~5 The main advantages of the stacked-bed system relative to the single bed system shown by this Example comprise a) higher sulphur conversion, even at lower operating temperatures, b) greater catalyst stability when processing the same type feed -- about first 60 days --, c) processing a heavier feed at comparable stabilities -- about after 60 days --9 and d) greater hydrogen addition even at lower operating temperatures. It can be seen from Fig. 2 that the single bed system has a lower start of run tempera-S ture in the first one or two weeks but this temperature relates to 0.~5 ~w sulphur in the produ~t where the temperature for the stacked-bed system relates to 0.60 %w sulphur in the product. To obtain also 0.6 %weight sulphur in the product initially with the single bed system an additional 7.5 C would be required, thereby ID making the single bed about 4.4 C less active initially. It will be clear from Fig. 2 that although the two different catalyst con~igurations have similar temperatures at the start of run (for the different sulphur targets), the stacked-bed system has about a 12.~ C advantage after 2 months indicating the greater stability lS when processing the same type feed containing about 30% by volume of the coker material. After about 60 days the coking tendency of the feed to the single bed system was reduced by decreasing the a~ount of the full range coker heavy gas oil from about 30% down to 20% by volume (indicated by an arrow in the upper line of Fig. 2).
The single bed system stability improved with the feed having reduced coking tendency and is beginning to approach that of the stacked-bed system although still at the higher sulphur in product level. This data shows that the stacked-bed system can be used to process a feed with greater coking tendency with equivalent catalysts ~5 life and for this case even with higher sulphur conversion. Table V
provides some data indicating that the hydrogen consumption of the stacked-bed system is some 6% better (lower) than that of the single bed system. The best comparison is at the 1 month point where the catalysts are processing the same feed. The larger 3d hydrogen consumption is reflected in the greater temperature rise across the reactor (Reactor delta T in Table V); hydrogen addition is a ma~or factor in the heat release during hydrotreating.
TABLE IV
Feed properties and operating parameters Feed Vacuum gas oil/
coker heavy gas oil Ratio 40/60 End Point, C above 538 C
Feed Sulphur, ~w ~3 LHSV, kg/kg.h 2.76 H2 pressure (Reactor inlet) bar 49.3 H2/oil ratio (Nl/kg feed) 289 .
Individual feedstocks Vac. gas oil Coker heavy gas oil Molecular weight 369 312 Carbon, 7,w 85.4 85.2 Hydrogen, %w 11.8 11.0 ` Sulphur, ~w 2.5 . 3.2 TBP-GLC wt 538 C 91.2 95.0 ;i3 TABLE V
-Catalysts and performance Gatalyst age 1 month 4 months Catalyst* 1 1 & 2 1 1 & 2 Reactor temp., out, C 360 357.2 376.7 362.8 Reactor delta T, C 37.5 40.6 34.4 40.6 consumption, Nl/kg feed 63.8 68 63.8 68 Product sulphur, %w 0.75 0.6 0.75 0.6 _ * Catalyst 1 is Ni-Mo-P
Catalyst 2 is Co-Mo _ E~A~IPLE 3 A third set of two commercial runs with a Ni-Mo-P/alumina catalyst and a stacked-bed of a`Ni-Mo-P/alumina catalyst and a Co-Mo/alumina catalyst was also made. The feed used has a final boiling point between 343 C and 5~8 C and contained straight run light gas oil, coker naphtha, coker light gas oil and light cycle oil. In Table VI the approximate average unit conditions and feed stock properties are summarized. Analysis of the data for these two runs showed that the stacked-bed used in accordance with the present in~tant invention showed the following advantages when ~ compared to the single catalyst:
a) lower inlet temperature, b~ lower sulphur in the product, and c) the ability to operate at the same reactor delta tempera-ture even though the reactor inlet temperature was lower.
i3 TABLE VI
-Feed properties and operating parameter Feed gravity 0.92 Distillation, C, end point 455 Feed sulphur, %w 1.3 Liquid hourly space velocity kg/kg.h 2.6 H~ pressure (reactor inlet, bar)35.4 H2/oil ratio, Nl~kg feed 168.3
The feedstocks to be applied in the process in accordance with this invention may be taken from straight run oils (non-cracked) or thermally-, steam-3 or catalytically cracked hydrocarbonaceous materials, Suitable feeds include petroleum derived gas oils distilled from crude or crude fractions at atmospheric or at reduced pressure; solvent extracted oils such as extracted oils commonly referred to as Deasphalted Oils; thermally or steamed cracked oils or fractions ~hereof such as coker gas oils; gas oils or cycle oils from catalytic cracking and mixtures of two or more 1~ of the above materials.
Multiple uses of these feedstocks after initial treating in accordance with the process according to the present invention are also possible. Depending on particular feedstocks treated, suitable use3 may include feed and additions to feed to units for slgnifi-1~ cant molecular weight reduction such as catalytic cracking units orhydrocracking units; direct use or by blending with other oils or additives for sale as transportation fuels such as diesel oils; or for refinery fuel.
The stacked-bed catalyst system to be used in the process a according to the present invention comprises firstly a normally Ni-and P-containing conventional hydrotreating catalyst. The second catalyst to be contacted by the oil normally comprises a low- or no-phosphorus content conventional catalyst. Preferably~ the second catalyst contains no phosphorus. The second catalyst is also a ~2~ convantional catalyst and contains Ni and/or Co in the formulation.
When desulphurization is the primary ob~ective of the hydrotreating process, the second catalyst contains Co in preference to Ni; when denitrogenation is the primary ob;ective, the second catalyst prP~erably contains Ni in preference to Co. The catalysts herein 3a can be prepared by techniques well known in the art. The advantages of this invention primarily accrue from the particular combination of operable hydrotreating catalysts in a stacked-bed rather than from any particular method or manner of fabricating the catalyst.
The first main hydrotreating zone catalyst used in the process according to the present invention suitably comprises a Ni- and P-con~aining conventional hydrotreating catalyst. Conventional hydro~reating catalysts which are suitable for the first catalyst 20ne generally comprise a phosphorus oxide and/or sulphide compo-nent and a component, selected from group VIB of the Periodic Table and a group ~III metal, metal oxide, or metal sulphide and/or mi~tures thereof composited with a support. These catalysts will contain up to 10 %w, usually 1 to about 5 %w of the group VIII
metal compound calculated basis the metal content, from 3 to about 15 `~w of the group VIB metal compound calculated basis the metal n ~ontent, and from 0.1 to 10 %w phosphorus compounds calculated basis phosphorus content. Preferably, the catalyst comprises a nickel component and a molybdenum and/or tungsten component with an alumina support which may additionally contain silica. A more preferred catalyst comprises a nickel component, a molybdenum component, and a phosphorus component with an alumina support which may also contain small amounts of silica. Preferred amounts of components range from 2 to 4 %w of a nickel component calculated basis metal content, 8-15 %w of a molybdenum component calculated basis metai content, and 1 to 4 %w, more preferably 2 to 4 %w, of a phosphorus component calculated basis the phosphorus content. The catalyse can be used in any of a variety of shapes such as spheres and e~trudates. The preferred shape is a trilobal extrudate.
Preferably, the catalyst is sulphided prior to use, as is well known to the art.
~5 The use of low-phosphorus or no-phosphorus catalysts in the s~rond ~one is thought to be of benefit due to reduced deactivation by Cokin8-Low-phosphorus content catalysts having high surface areas tgraater than about ~00 m2/g) and high compacted bulk densities t0.6-0.85 gtcm3) are preferably used for the second zone as they appear to be highly active. The high surface area increases reac-tion rates due to generally increased dispersion of the active components. ~igher density catalysts allow one to load a larger amount of active metals and promoter per reactor volume, a factor which is commercially important. The metal content specified above g provides high activity per reactor volume. Lower metal contents normally result in catalysts exerting too low activities for proper use in the process according to the present invention. Higher metal loadings than specified above do not contribute significantly to the performance and thus lead to an inefficient use of the metals resulting in high catalyst cost with little advantage. Since deposits of coke are thought to cause the majority of the catalyst deactivation, fresh catalyst pore volume should be at or above a modest level (0.4-0.8 cm3/g, more narrowly 0.5-0.7 cm3/g). The second zone catalyst can be used like the first zone catalyst in a vasiety of shapes. Preferably, the catalyst is sulphided prior to use as is well ~nown to the art.
The Ni-containing catalyst used for the first zone is prefera-bly a high activity conventional catalyst suitable for high levels ~f hydrogenation. Such catalysts have high surface areas (greater than 140 m2/g) and high compacted bulk densities (0.65-0.95 g/cm3, more narrowly 0.7-0.95 g/cm9). The high surface area increases reaction rates due to generally increased dispersion of the active components. Higher density catalysts allow one to load a larger amount of active metals and promoter per reactor volume, a factor which is commercially important. The metal and phosphorus content specified above provides the high activity per reactor volume.
Lo~er metal contents result in catalysts exerting too low activi-ties for proper use in the process according to the present inven-tion~ Higher metal contents do not contribute significantly to theperformanca and thus lead to an inefficient use of the metals and hi8her cost for the catalyst. Since deposits of coke are thought to cause the majority of the catalyst deactivation, fresh catalyst pore volume should be at a modest level (0.4-0.8 cm3/g, more 3~ nflrrowly 0.4-0.~ cm3/g).
A low-phosphorus or no-phosphorus conventional hydrotreating caealyse is used in the second zone of the caealyst system. Co and/or Ni containing conventional catalysts can be suitably applied.
The second zone catalyst differs from the first zone catalyst primarily in its low-phosphorus content (less than 0.5 %w). The preferred catalyst contains less than about 0.5 %w phosphorus and comprises a component from group VIB and a group VIII metal, metal o~ide, or metal sulphide and/or mixtures thereof composited with a SUppO1t Preferably, the catalyst comprises a nickel and/or cobalt 5 component and a molybdenum and/or tungsten component with an alumina support which may additionally contain silica. Preferred metal contents are up to 10 %w, usually 1 to 5 %w of group VIII
metal component(s) calculated basis the metal content, and from 3 to 30 ~w of group VIB metal component(s) basis the metal content. A
more preferred catalys~ comprises a cobalt or nickel component and molybdanum component with an alumina support.
The present invention preferably relates to a process for hy~rotreating oils having a tendency to deactivate hydrotreating catalysts by coke formation, by passing a) oils having a final ls boiling point above 588 C and having less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 C to 538 C, or c) mi~tures thereof downwardly with hydrogen or a hydrogen-containing gas (mixture) in~o a hydrotreating zone over a stacked-bed of two hydrotreating catalysts under conditions suitable ~d to convert more than 25% of the sulphur compounds present to H2S, wherein said stacked-bed comprises an upper zone containing of from 15-85 %v, basis total catalyst, of a high-activity hydrotreating catalyst which comprises from 2-4 %w nickel, from 8-15 %w molyb-denum and from 1-4 %w phosphorus supported on a carrier consisting ~5 mostly of alumina, and a lower zone containing of from 15-85 %v, ba~is total catalyst, of a high-activity, hydrodesulphurization catalyst which comprises from 2-4 %w cobalt and/or nickel, from 8-15 %w molybdenum and less than 0.5 %w phosphorus supported on a carrier consisting mostly of alumina; and separating the reaction 3a product from said hydrotreating zone into a hydrogen-rich gas and a liquid oil having reduced sulphur and/or heavy metal content.
The physical characterizations of the catalysts referred to herein are common to those skilled in the catalyst development art.
Surface areas refer to nitrogen adsorption surface areas preferably determined by at least three points. Pore size distributlons are determined by mercury intrusion and calculated with a 130 degree contact angle. Pore volumes stated are water pore volumes and indicate the volume of water per weight of catalyst necessary to fill the catalyst pores to an incipient wetness of the catalyst.
The volume of the first catalyst zone in the present invention is from 15 to 85 %v of the main catalyst charge. The remaining fraction of the main catalyst charge is composed of the second catalyst. The division of the catalyst volumes over the zones in the bed depends upon the requirement for nitrogen conversion versus the requlrements for stability and other hydrotreating reactions such a~ sulphur and metals removal. Stacked-beds can be used to cailor the amount of nitrogen removal, sulphur and metals removal, and system stability. An increase in the first catalyst will increase the nitrogen removal but will effect the hydrodesulphuri-1~ æation tHD~) activity and stability of the system. Below a catalystratio of 15:85 or above a catalyst ratio of 85:15 (upper:lower) the benefits for the stacked-bed system are not large enough to be of practical significance. There is no physical limit on using a s~aller percentage of one or the other beds.
The catalyst zones referred to herein may be in the same or different reactors. For existing units with one reactor the catalysts are layered one on top of the other. Many hydrotreating reactors consist of two or more reactors in series. The catalyst zones are not restricted to the particular volume of one vessel and can -~ e~tend into the next ~prior) vessel. The zones discussed herein refer to the main catalyst bed. Small layers of catalysts which are different sizes are frequently used in reactor loading as is known to those skilled in the art. Intervessel heat exchange and/or hydrogen addition may also be used in the process according to the 3~ present invention.
The pore siæe of the catalyst does not play a critical role in the process according to the present invention. The catalysts in the two zones may be based upon the same carrier. Normally, the finished catalysts will have small differences in their average pore sizes due to the diff~rences in the respective metal and phosphorus loadings.
Suitable conditions for operating the catalyst system in accordance with the present invention are given in Table I.
TABLE I
_ Broadest Broad Narrow Narrowest Conditions range range range range MyAro~en p~rtlal 6.8-75 20-75 20-55 34-55 ~rassura, bar ~otAl pressure, bar 13.6-95 27-95 27-75 47-75 ~ydrogen/feed ratio, 17-1780 17-890 51-255 85-255 Nl/kg feed .
Temperaturej C 150-455 285-455 285-42S 345-425 Liquid hourly space 0.1-10.0 - 0.5-5.0 velocity, kg/kg.h At temperatures below 285 C (for very heavy feeds) and below ~5 150 C (for heavy feeds), the catalysts do not exhibit sufficient ~ctivity for the rates of conversion to be of practical signifi-c~nce. At temperatures above 455 C the rate of coking and cracking ba~oma e~cessive resulting in increasingly impractical operations.
RaActor metflllurgy n~ay also be a limitating constraint above 455 ~C
3a ~t the highar pressures.
At liquid space velocities below 0.1 kg/kg.h, the residence time of the oil is long enough to lead to thermal degradation and coking. At liquid space velocities above 10 kg/kg.h the conversion ~cross the reactor is too small to be of practical use. For space i3 velocity and gas-to-oil ratio calculations referred to herein, volumes are measured at 15.5 C and atmospheric pressure.
Hydrogen partial pressure is very important in determining the rate of catalyst coking and deactivation. At pressures below 6.8 bar, the catalyst system cokes too rapidly even ~ith better quality oil containing high boiling components. At pressures above 75 bar, the deactivation mechanism of the catalyst system appears to be predominantly that of metals deposition, if present, which results in pore-mouth plugging. Catalysts of varying porosity can Id be used to address deactivation by metals deposition, as is known ~y those skilled in the art. The hydrogen to feed ratio to be applied in the process according to the present invention is raquired to be above 17 Nl/kg feed since the reactions occurring during hydrotreating consume hydrogen, resulting in a deficiency of hydrogen at the bottom of the reactor. This deficiency may cause rapid coking of the catalyst and leads to impractical operation. At hydrogen to feed ratios in excess of ~90 Nl/kg feed~ no substantial `benefit is"obtained; thus`the expense of compression beyond this rate is not warranted.
Nitrogen removal is an important factor in hydrotreating heavy oils. Catalysts without phosphorus can be more stable with heavy oils under the conditions noted above; however, nitrogen removal activity is low for no-phosphorus catalysts relative to their phosphorus promoted counterparts. Additionally, Co promoted cata-2$ lyses are less active for nitrogen removal than are Ni promotedcatalysts. Stacked catalyst beds can be used to taiIor the amount o~ nitrogen removal, sulphur and metals removal, and system stabi-lity. It has been found that a stacked-bed system also improves activities (other than nitrogen removal) as well as the stability of the overall catalyst system relative to either catalyst used individually. The stacked-bed catalyst system is applicable when processing feeds under conditions where a heavy feed is causing deactivation primarily by coking.
The process according to the present invention should be operated at conditions suitable to remove at least 25% and gene-rally conditions will be applied to remove 30-80%, more preferably 45-75~, of the sulphur in the feed. When metals such as Ni and V
are present in the feed and demetallization is the primary focus the process can be operated at the lower levels of desulphurization.
S l~hen there is little metal in the feed and demetallization is not the primary goal, one can operate the process at higher sulphur removal rates.
The invention is accompanied by Figures 1 and 2 wherein some of the results as described in the Examples are depicted graphi-lly.
Figura 1 represents a graph showing the advantage obtained in the reactor inlet temperature as a function of time when the stacked-bed according to the present invention is utilized.
Figure 2 represents a graph showing the advantage obtained in lS the reactor outlet temperature as a function of time when the stacked-bed according to the present invention is utilized.
The following Examples are presented to illus~rate the present invention.
E~A~LE 1 A cstalyst A containing nickel, molybdenum and phosphorus ~upported on a gamma alumina carrier was prepared from commercially available alumina powders. This carrier was extruded into 1.6 mm pellets having a trilobal cross section. The pellets were dried and calcined before being impregnated with the appropriate catalytically active metals by a dry pore volume method i.e., by adding only enough solution to Eill the alumina pore volume. Carriers containing in addition to alumina, a few per cent of othar components like silica or magnesia can also be applied. An appropriate aqueous solution of nickel nitrate, nickel carbonate, phosphoric acid, 3~ hydrogen peroxide, and ammonium molybdate was used to impregnate the carrier. The metal loadings and some properties of the dried, calcined catalyst (A) are given in Table II.
A catalyst B containing cobalt and molybdenum supported on a similar alumina carrier as used to prepare catalyst A was prepared.
Likewise, this carrier was also extruded into 1.6 mm pellets having a trilobal cross-section. The pellets were dried before being impregnated with ~he appropriate catalytically active metals by a dry pore volume method. An appropriate aqueous solution of cobalt carbonate, ammonium dimolybdate and ammonia was used to impregnate the carrier. The metal loadings and properties of the dried, calcined catalyst (B) are also given in Table II.
TABLE II
Catalyst - A B
~iameter 1.6 mm 1.6 mm Cross-section Trilobal Trilobal Composition, %w Ni 3.0 Co - 3.2 ~o 13.0 9.6 3.2 Comp~cted bulk density, g/cm3 0.82 0.71 Surface Area, m2/g 164 226 Hg-pora volume, cm9/g 0.47 0.61 -Three different commercial runs with a main catalyst charge o~
25 a Ni-Mo-P/alumina catalyst, a Co-Mo/alumina catalyst and a stacked-bed of a Ni-Mo-P/alumina catalyst over a Co-Mo/alumina catalyst ~ere carried out. In Fig. 1 the reactor inlet temperature (RIT in C) necessary to maintain 0.3~ weight sulphur in the product is ~raphically represented as a Eunction of time (days), which is a 3~ conveniqnt measure of general catalyst activity. The Ni-Mo-P cata-lyst data are represented as circles (upper line)~ the Co-Mo catalyst data as triangles (middle line) and the stacked catalyst data as diamonds (lower line). The stacked-bed system has good activity and stability for sulphur removal as well as denitrifica-tion advantages. The average feed properties and average unit conditions are given in Table III. The feed applied was a heavy vacuum gas oil l1aving a final boiling point above 538 C and containing less than 2 %w of heptane asphaltenes. Feed to the unit and unit conditions were remarkably constant during the runs considering the unie is a commercial unit. In the stacked-bed system the ~i-Mo-P catalyst formed about 33% of the main catalyst load while the Co-Mo catalyst made up the remainder of the main catalyst load. Oil and gas flowed in a single-stage and serially over first the ~i-Mo-P catalyst and then over the Co-Mo catalyst.
The main advantages of the stacked-bed system sho~n by this ~ample comprise a) a significant increase in catalyst stability as can be seen in Fig, 1 where the increase in RIT with time is ~ignificantly less for the stacked-bed system (3.1 C/month versus 1~.5 C/month) relative to the single catalyst system; b) an 1~ increase in catalyst activity as represented by about a 8.1 C
lower initial RIT for the same level of sulphur in the product;
c) a resulting greatly improved estimated catalyst life of about 400% for the stacked-bed relative to the single bed due to the improvements in activity and stability. An end of run temperature ~a of 416 C and a continued linear decline rate was used to estimaee the catalyst life of the stacked-bed system.
- 17 ~
TABLE III
Feed/Process properties Hydrogen partial pressure 38 bar Liquid hourly space velocity 3 kg/kg.h Sulphur, ~ wt 1.1 Nickel, ppm 0.6 Vanadium, ppm 0.7 RCR, ~ wt 0.3 TBP-~LC~ C
IBP/10~ 265/347 90~95% 524/538 .
E~LE 2 A second set of two commercial runs with a Ni-~lo-P/alumina caealyst and a stacked-bed of a Ni-Mo-P/alumina catalyst over a Co-Mo/alumina catalyst ~as also carried out. A Ni-Mo-P/alumina catalyst would be one that one skilled in the art would traditio-nally have chosen ~or this feedstock when considering hydrogena-tion, denitrificationJ and de~.ulphurization catalyst activity rather than a Co-~o catalyst. Table IV summarizes approximate average unit conditions and feedstock. The oil is a blend of straight run vacuum gas oil tdistilled from non-cracked oil) and a I a coker heavy gas oil. In Table V the approximate average performance for the two runs at two catalyst ages is summarized and in Figure 2 the reactor outlet temperature necessary to maintain 0.75% weight and 0.60% weight sulphur in the product for the single catalyst and the stacked bed system is depicted as a function of time (days~.
~5 The main advantages of the stacked-bed system relative to the single bed system shown by this Example comprise a) higher sulphur conversion, even at lower operating temperatures, b) greater catalyst stability when processing the same type feed -- about first 60 days --, c) processing a heavier feed at comparable stabilities -- about after 60 days --9 and d) greater hydrogen addition even at lower operating temperatures. It can be seen from Fig. 2 that the single bed system has a lower start of run tempera-S ture in the first one or two weeks but this temperature relates to 0.~5 ~w sulphur in the produ~t where the temperature for the stacked-bed system relates to 0.60 %w sulphur in the product. To obtain also 0.6 %weight sulphur in the product initially with the single bed system an additional 7.5 C would be required, thereby ID making the single bed about 4.4 C less active initially. It will be clear from Fig. 2 that although the two different catalyst con~igurations have similar temperatures at the start of run (for the different sulphur targets), the stacked-bed system has about a 12.~ C advantage after 2 months indicating the greater stability lS when processing the same type feed containing about 30% by volume of the coker material. After about 60 days the coking tendency of the feed to the single bed system was reduced by decreasing the a~ount of the full range coker heavy gas oil from about 30% down to 20% by volume (indicated by an arrow in the upper line of Fig. 2).
The single bed system stability improved with the feed having reduced coking tendency and is beginning to approach that of the stacked-bed system although still at the higher sulphur in product level. This data shows that the stacked-bed system can be used to process a feed with greater coking tendency with equivalent catalysts ~5 life and for this case even with higher sulphur conversion. Table V
provides some data indicating that the hydrogen consumption of the stacked-bed system is some 6% better (lower) than that of the single bed system. The best comparison is at the 1 month point where the catalysts are processing the same feed. The larger 3d hydrogen consumption is reflected in the greater temperature rise across the reactor (Reactor delta T in Table V); hydrogen addition is a ma~or factor in the heat release during hydrotreating.
TABLE IV
Feed properties and operating parameters Feed Vacuum gas oil/
coker heavy gas oil Ratio 40/60 End Point, C above 538 C
Feed Sulphur, ~w ~3 LHSV, kg/kg.h 2.76 H2 pressure (Reactor inlet) bar 49.3 H2/oil ratio (Nl/kg feed) 289 .
Individual feedstocks Vac. gas oil Coker heavy gas oil Molecular weight 369 312 Carbon, 7,w 85.4 85.2 Hydrogen, %w 11.8 11.0 ` Sulphur, ~w 2.5 . 3.2 TBP-GLC wt 538 C 91.2 95.0 ;i3 TABLE V
-Catalysts and performance Gatalyst age 1 month 4 months Catalyst* 1 1 & 2 1 1 & 2 Reactor temp., out, C 360 357.2 376.7 362.8 Reactor delta T, C 37.5 40.6 34.4 40.6 consumption, Nl/kg feed 63.8 68 63.8 68 Product sulphur, %w 0.75 0.6 0.75 0.6 _ * Catalyst 1 is Ni-Mo-P
Catalyst 2 is Co-Mo _ E~A~IPLE 3 A third set of two commercial runs with a Ni-Mo-P/alumina catalyst and a stacked-bed of a`Ni-Mo-P/alumina catalyst and a Co-Mo/alumina catalyst was also made. The feed used has a final boiling point between 343 C and 5~8 C and contained straight run light gas oil, coker naphtha, coker light gas oil and light cycle oil. In Table VI the approximate average unit conditions and feed stock properties are summarized. Analysis of the data for these two runs showed that the stacked-bed used in accordance with the present in~tant invention showed the following advantages when ~ compared to the single catalyst:
a) lower inlet temperature, b~ lower sulphur in the product, and c) the ability to operate at the same reactor delta tempera-ture even though the reactor inlet temperature was lower.
i3 TABLE VI
-Feed properties and operating parameter Feed gravity 0.92 Distillation, C, end point 455 Feed sulphur, %w 1.3 Liquid hourly space velocity kg/kg.h 2.6 H~ pressure (reactor inlet, bar)35.4 H2/oil ratio, Nl~kg feed 168.3
Claims (13)
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. A process for catalytically hydrotreating hydrocarbon oils at eleva-ted temperature and pressure in the presence of hydrogen, which comprises pass-ing:
a) oils having a final boiling point greater than 538 °C and containing less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 °C to 538 °C, or c) mixtures thereof, downwardly with hydrogen or a hydrogen-containing gas into a hydrotreating zone over a stacked-bed of hydrotreating catalysts under conditions suitable to convert more than 25% of the sulphur compounds present to hydrogen sulphide, wherein said stacked-bed comprises an upper zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB of the Periodic Table, a Group VIII metal, metal oxide or metal sulphide and a phosphorus oxide and/or sulphide, and a lower zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB, a Group VIII metal, metal oxide or metal sulphide and less than 0.5 %w of phosphorus; and separating the reaction product from said hydrotreating zone into a hydrogen-rich gas and a liquid hydrocarbon oil having a reduced heteroatom content.
a) oils having a final boiling point greater than 538 °C and containing less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 °C to 538 °C, or c) mixtures thereof, downwardly with hydrogen or a hydrogen-containing gas into a hydrotreating zone over a stacked-bed of hydrotreating catalysts under conditions suitable to convert more than 25% of the sulphur compounds present to hydrogen sulphide, wherein said stacked-bed comprises an upper zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB of the Periodic Table, a Group VIII metal, metal oxide or metal sulphide and a phosphorus oxide and/or sulphide, and a lower zone containing 15-85 %v, basis total catalyst, of a hydrotreating catalyst comprising a component from Group VIB, a Group VIII metal, metal oxide or metal sulphide and less than 0.5 %w of phosphorus; and separating the reaction product from said hydrotreating zone into a hydrogen-rich gas and a liquid hydrocarbon oil having a reduced heteroatom content.
2. A process according to claim 1, wherein a stacked-bed is used containing an upper zone containing up to 10 %w of a Group VIII component, 3-15 %w of a Group VIB component and 0.1-10 %w of phosphorus, and a lower zone con-taining up to 10 %w of a Group VIII component and 3-30 %w of a Group VIB compo-ment.
3. A process according to claim 1 wherein a stacked-bed is used contain-ing an upper zone comprising a nickel component, a molybdenum and/or tungsten component and phosphorus on an alumina support which may additionally contain silica, and a lower zone comprising a nickel and/or cobalt component and a molybdenum and/or tungsten component on an alumina support which may additionally contain silica.
4. A process according to claim 3,wherein a stacked-bed is used contain-ing an upper zone containing 2-4 %w of nickel, 8-15 %w of molybdenum and 1-4 %w of phosphorus supported on a carrier consisting mostly of alumina, and a lower zone containing 2-4 %w of cobalt and/or nickel, from 8-15 %w of molybdenum and less than 0.5 %w of phosphorus supported on a carrier consisting mostly of alumina.
5. A process according to claim 1, 2 or 3 wherein a stacked-bed is used wherein the upper zone catalyst has a compacted bulk density of 0.65-0.93 g/cm3, in particular 0.76-0.88 g/cm3 and a surface area greater than 140 m2/g, in particular greater than 150 m2/g, and wherein the lower zone cata-lyst has a compacted bulk density of 0.6-0.8 g/cm3, in particular 0.67-0.69 g/cm3 and a surface area greater than 180 m2/g, in particular greater than 200m 2/g.
6. A process according to claim 1, 2 or 3, wherein the process is carried out at a hydrogen pressure not exceeding 75 bar.
7. A process according to claim 1, 2 or 3, wherein use is made of a stacked-bed catalyst containing in its lower zone 2-4 %w of cobalt and essen-tially no nickel and no phosphorus.
8. A process according to claim 1, 2 or 3, wherein use is made of a stacked-bed catalyst containing in its lower zone 2-4 %w of nickel and essentially no cobalt and no phosphorus.
9. A process according to claim 1, 2 or 3, wherein use is made of a stacked-bed containing a trilobally shaped catalyst in the upper and/or the lower zone.
10. A process according to claim 1, 2 or 3, wherein use is made of a stacked-bed containing a trilobally shaped catalyst in the upper and/or the lower zone wherein the catalyst carrier is extruded into a trilobal shape before impregnation.
11. A process according to claim 1, 2 or 3, wherein the hydrotreating zone is contained in a single reactor and the upper zone of the stacked-bed catalyst comprises about one-third of the total catalyst volume.
12. A process according to of claim 1, 2 or 3, wherein hydrocarbon oils having a tendency to deactivate hydrotreating catalysts by coke formation are hydrotreated by passing:
a) oils having a final boiling point above 538 °C and having less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 °C to 538 °C, or c) mixtures thereof, downwardly with hydrogen or a hydrogen-containing gas into a hydrotreating zone over a stacked-bed of two hydrotreating catalysts under conditions suitable to convert more than 25% of the sulphur compounds present to H2S; said stacked-bed comprising an upper zone containing of from 15-85 %v,basis total catalyst, of a high-activity hydrotreating catalyst which comprises from 2-4 %w nickel, from 8-15 %w molybdenum and from 1-4 %w phosphorus supported on a carrier consisting mostly of alumina, said catalyst having a compacted bulk density of 0.65-0.95 g/cm3 and a surface area greater than 140 m2/g; and a lower zone contain-ing from 15-85 %v, basis total catalyst, of a high-activity, hydrodesulphuriza-tion catalyst which comprises from 2-4 %w cobalt and/or nickel and from 8-15 %w molybdenum and less than 0.5 %w phosphorus supported on a carrier consisting mostly of alumina, said catalyst having a compacted bulk density of 0.6-0.8 g/cm3 and a surface area greater than 180 m2/g; and separating the reaction product from said hydrotreating zone into a hydrogen-rich gas and a liquid hydrocarbon oil having reduced sulphur and/or heavy metal content.
a) oils having a final boiling point above 538 °C and having less than 2 %w of heptane asphaltenes, b) oils having a final boiling point from 343 °C to 538 °C, or c) mixtures thereof, downwardly with hydrogen or a hydrogen-containing gas into a hydrotreating zone over a stacked-bed of two hydrotreating catalysts under conditions suitable to convert more than 25% of the sulphur compounds present to H2S; said stacked-bed comprising an upper zone containing of from 15-85 %v,basis total catalyst, of a high-activity hydrotreating catalyst which comprises from 2-4 %w nickel, from 8-15 %w molybdenum and from 1-4 %w phosphorus supported on a carrier consisting mostly of alumina, said catalyst having a compacted bulk density of 0.65-0.95 g/cm3 and a surface area greater than 140 m2/g; and a lower zone contain-ing from 15-85 %v, basis total catalyst, of a high-activity, hydrodesulphuriza-tion catalyst which comprises from 2-4 %w cobalt and/or nickel and from 8-15 %w molybdenum and less than 0.5 %w phosphorus supported on a carrier consisting mostly of alumina, said catalyst having a compacted bulk density of 0.6-0.8 g/cm3 and a surface area greater than 180 m2/g; and separating the reaction product from said hydrotreating zone into a hydrogen-rich gas and a liquid hydrocarbon oil having reduced sulphur and/or heavy metal content.
13. Hydrotreated hydrocarbon oils whenever obtained by a process accord-ing claim 1, 2 or 3.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US06/735,620 US4776945A (en) | 1984-11-30 | 1985-05-21 | Single-stage hydrotreating process |
| US735,620 | 1985-05-21 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1272153A true CA1272153A (en) | 1990-07-31 |
Family
ID=24956534
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000488159A Expired - Fee Related CA1272153A (en) | 1985-05-21 | 1985-08-06 | Single-stage hydrotreating process |
Country Status (9)
| Country | Link |
|---|---|
| EP (1) | EP0203228B2 (en) |
| JP (1) | JPH0633364B2 (en) |
| CN (1) | CN1006230B (en) |
| BR (1) | BR8503786A (en) |
| CA (1) | CA1272153A (en) |
| DE (1) | DE3570088D1 (en) |
| ES (1) | ES8604292A1 (en) |
| PT (1) | PT80934B (en) |
| ZA (1) | ZA855849B (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US7914670B2 (en) | 2004-01-09 | 2011-03-29 | Suncor Energy Inc. | Bituminous froth inline steam injection processing |
Families Citing this family (9)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US5116484A (en) * | 1990-10-31 | 1992-05-26 | Shell Oil Company | Hydrodenitrification process |
| US5227353A (en) * | 1991-07-24 | 1993-07-13 | Mobil Oil Corporation | Hydroprocessing catalyst composition |
| JP2000515198A (en) * | 1996-08-01 | 2000-11-14 | シエル・インターナシヨネイル・リサーチ・マーチヤツピイ・ベー・ウイ | Hydrogen treatment method |
| EP0870817A1 (en) | 1997-04-11 | 1998-10-14 | Akzo Nobel N.V. | Process for effecting deep HDS of hydrocarbon feedstocks |
| US7513989B1 (en) | 1997-07-15 | 2009-04-07 | Exxonmobil Research And Engineering Company | Hydrocracking process using bulk group VIII/Group VIB catalysts |
| US7232515B1 (en) | 1997-07-15 | 2007-06-19 | Exxonmobil Research And Engineering Company | Hydrofining process using bulk group VIII/Group VIB catalysts |
| US7229548B2 (en) | 1997-07-15 | 2007-06-12 | Exxonmobil Research And Engineering Company | Process for upgrading naphtha |
| US7288182B1 (en) * | 1997-07-15 | 2007-10-30 | Exxonmobil Research And Engineering Company | Hydroprocessing using bulk Group VIII/Group VIB catalysts |
| AU2004279081A1 (en) * | 2003-10-02 | 2005-04-14 | Exxonmobil Research And Engineering Company | Process for upgrading naphtha |
Family Cites Families (7)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| DE2300038C2 (en) * | 1973-01-02 | 1987-05-07 | Basf Ag, 6700 Ludwigshafen | Use of a sulfurized catalyst for the production of technical white oils |
| US4016067A (en) * | 1975-02-21 | 1977-04-05 | Mobil Oil Corporation | Process for demetalation and desulfurization of petroleum oils |
| DE2837018A1 (en) * | 1978-08-24 | 1980-03-06 | Basf Ag | USE OF COBALT AND / OR NICKEL MOLYBDAEN OXIDE CATALYSTS FOR THE HYDRATING REFINING OF PETROLEUM HYDROCARBONS |
| AU530497B2 (en) * | 1978-09-28 | 1983-07-21 | Amoco Corporation | Catalyst comprising hydrogenation component on support containing alumina and phosphorus oxides |
| US4406779A (en) * | 1981-11-13 | 1983-09-27 | Standard Oil Company (Indiana) | Multiple catalyst system for hydrodenitrogenation of high nitrogen feeds |
| AU571189B2 (en) * | 1982-12-06 | 1988-04-14 | Amoco Corporation | Hydrotreating catalyst |
| US4500424A (en) * | 1983-04-07 | 1985-02-19 | Union Oil Company Of California | Desulfurization catalyst and process |
-
1985
- 1985-07-29 EP EP85201248A patent/EP0203228B2/en not_active Expired - Lifetime
- 1985-07-29 DE DE8585201248T patent/DE3570088D1/en not_active Expired
- 1985-08-02 ZA ZA855849A patent/ZA855849B/en unknown
- 1985-08-06 CA CA000488159A patent/CA1272153A/en not_active Expired - Fee Related
- 1985-08-09 ES ES546041A patent/ES8604292A1/en not_active Expired
- 1985-08-09 PT PT80934A patent/PT80934B/en not_active IP Right Cessation
- 1985-08-09 BR BR8503786A patent/BR8503786A/en not_active IP Right Cessation
- 1985-08-09 JP JP60174439A patent/JPH0633364B2/en not_active Expired - Fee Related
- 1985-08-09 CN CN85106942.8A patent/CN1006230B/en not_active Expired
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US7914670B2 (en) | 2004-01-09 | 2011-03-29 | Suncor Energy Inc. | Bituminous froth inline steam injection processing |
| US8685210B2 (en) | 2004-01-09 | 2014-04-01 | Suncor Energy Inc. | Bituminous froth inline steam injection processing |
Also Published As
| Publication number | Publication date |
|---|---|
| DE3570088D1 (en) | 1989-06-15 |
| BR8503786A (en) | 1986-12-09 |
| JPH0633364B2 (en) | 1994-05-02 |
| ZA855849B (en) | 1986-03-26 |
| CN85106942A (en) | 1987-02-04 |
| ES8604292A1 (en) | 1986-01-16 |
| EP0203228B2 (en) | 1996-10-23 |
| EP0203228B1 (en) | 1989-05-10 |
| PT80934A (en) | 1985-09-01 |
| JPS61266490A (en) | 1986-11-26 |
| CN1006230B (en) | 1989-12-27 |
| ES546041A0 (en) | 1986-01-16 |
| PT80934B (en) | 1987-09-30 |
| EP0203228A1 (en) | 1986-12-03 |
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