CA2520046C - Process for reducing the level of sulfur compounds from liquid hydrocarbon streams - Google Patents
Process for reducing the level of sulfur compounds from liquid hydrocarbon streams Download PDFInfo
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- CA2520046C CA2520046C CA 2520046 CA2520046A CA2520046C CA 2520046 C CA2520046 C CA 2520046C CA 2520046 CA2520046 CA 2520046 CA 2520046 A CA2520046 A CA 2520046A CA 2520046 C CA2520046 C CA 2520046C
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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
- C10G49/00—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00
- C10G49/007—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00 in the presence of hydrogen from a special source or of a special composition or having been purified by a special treatment
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D3/00—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping
- B01D3/34—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping with one or more auxiliary substances
- B01D3/343—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping with one or more auxiliary substances the substance being a gas
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D3/00—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping
- B01D3/34—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping with one or more auxiliary substances
- B01D3/38—Steam distillation
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/48—Sulfur compounds
- B01D53/52—Hydrogen sulfide
-
- 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
- C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
- C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/30—Alkali metal compounds
- B01D2251/304—Alkali metal compounds of sodium
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2251/00—Reactants
- B01D2251/60—Inorganic bases or salts
- B01D2251/604—Hydroxides
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- Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Engineering & Computer Science (AREA)
- General Chemical & Material Sciences (AREA)
- Organic Chemistry (AREA)
- Health & Medical Sciences (AREA)
- Biomedical Technology (AREA)
- Environmental & Geological Engineering (AREA)
- Analytical Chemistry (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Gas Separation By Absorption (AREA)
Abstract
A refined petroleum feedstock, such as diesel fuel, containing a low concentration of sulfur contaminants (such as would be taken up during pipeline conveyance), is desulfurized in a hydrotreating process characterized by mild conditions. Gaseous H2 is added to the feedstock in a ratio in the range of 0.5-25 SCM/SCM. The mixture is treated in a catalytic reactor at a temperature in the range 140 - 330°C and a pressure in the range 3 - 60 bar absolute, to convert contaminants to gaseous H2S. Produced gaseous H2 and H2S are separated from the liquid hydrocarbons. The gas mixture is scrubbed with liquid absorbent to remove H2S and purified H2 is recycled.
Description
1 "PROCESS FOR REDUCING THE LEVEL OF SULFUR COMPOUNDS
2 FROM LIQUID HYDROCARBON STREAMS"
4 Technical Description 7 This invention relates to a process for reducing the level of sulfur 8 contaminants in liquid hydrocarbon streams, particularly refined fuel streams 9 such as diesel and gasoline, that are transported through a pipeline.
12 Sulfur and sulfur compounds (collectively referred to herein as 'sulfur 13 contaminants') may be present in varying concentrations in refined 14 hydrocarbon streams. The maximum allowable sulfur contaminant content of fuels such as diesel and gasoline is regulated by governments and is being 16 reduced over time by legislation. This results in the need to further reduce the 17 already low levels of sulfur contaminants in such streams.
18 In some cases, sulfur contamination will take place as a consequence 19 of transporting the hydrocarbon streams through pipelines that contain sulfur contaminants remaining in the pipeline from the transportation of high sulfur 21 content streams, such as petroleum crude oils. This can result in the 22 hydrocarbon streams not being within specification due to higher sulfur 23 content than allowable or due to other specifications, such as the copper strip E5090787.DOC;1 y 1 corrosion test, that are related to the corrosiveness of some sulfur 2 compounds.
3 While there are many well-established technologies to remove sulfur 4 contaminants, such as hydrotreating and sulfur absorbent processes, the cost of the existing processes is relatively high in either or both of capital cost or 6 operating cost, considering the small amount of sulfur contaminants that may 7 be required to be removed in some cases. For aqueous caustic-based 8 processes for the removal of primarily elemental sulfur, the process is specific 9 to one or a few compounds of sulfur and may not achieve the desired level of sulfur reduction required. A need still exists in the art for increasing the 11 efficiency and improving the economics of sulfur removal from liquid 12 hydrocarbon streams contaminated with low levels of sulfur and/or sulfur 13 compounds.
SUMMARY OF THE INVENTION
16 We provide a process for reducing the sulfur content of a refined liquid 17 hydrocarbon stream such as gasoline, gasoline octane enhancer, diesel fuel, 18 stove oil, kerosene or jet fuel, which has a low sulfur content, for example as a 19 result of transportation through a multi-product pipeline. In accordance with this process, we add hydrogen to the stream, optionally heat the resulting 21 mixture and introduce it into a reactor containing a bed of hydrotreating 22 catalyst.
(E5090787.DOC;1}
1 Some of the sulfur contaminants in the treated stream react with 2 hydrogen to form hydrogen sulfide. In connection with this we prefer to use a 3 small packaged hydrogen generator plant to supply the limited amount of net 4 hydrogen gas needed for the process.
The reactor operating conditions of temperature, pressure and 6 hydrogen quantity are milder than a typical hydrotreater process, because of 7 the low level of sulfur contaminants required to be removed and the nature of 8 these contaminants.
9 From the reactor effluent, the hydrocarbons are separated as a liquid product from the gaseous hydrogen and hydrogen sulfide. The separated gas 11 stream, containing largely hydrogen, is fed to a means, such as a scrubber, 12 for removal of hydrogen sulfide using an absorbent, such as aqueous caustic.
13 The so-purified hydrogen gas is then recycled to form the major part of the 14 hydrogen supplied to the process. Preferably, all or part of the recycled gas stream is purified further in a conventional hydrogen purification process, such 16 as a pressure swing absorption unit, to remove other contaminants, such as 17 methane, that may form as a by-product in the reactor or be present in trace 18 quantities in the liquid hydrocarbon feed stream.
19 In an alternative configuration, the reactor effluent may be first cooled and then contacted with a liquid absorbent, such as aqueous caustic, prior to 21 or simultaneous with separation of the hydrogen-containing gas from the 22 liquid hydrocarbon stream in a separator vessel.
{E5090787.DOC;1}
1 The invention is characterized by the following features:
2 ~ It preferably uses a small hydrogen generator plant to inexpensively 3 supply the limited amount of net hydrogen needed to treat the small 4 quantity of sulfur contaminants involved;
~ It combines low severity or mild conditions of temperature and low 6 quantity of hydrogen with the provision of the catalyst to effect sulfur 7 contaminants conversion to an easily removable form (hydrogen 8 sulfide);
9 ~ It preferably integrates the hydrogen purification requirement for the recycle gas with the hydrogen purification unit that is a common feature 11 of hydrogen generator plants; and 12 ~ It disposes of the hydrogen sulfide formed by using a liquid absorbent, 13 such as aqueous caustic, or a low cost solid absorbent, such as a 14 metal oxide, both of which are cost effective for the low levels of sulfur compounds involved.
16 In one embodiment the invention is concerned with a process for 17 desulphurizing refined liquid hydrocarbons, comprising the steps of:
providing 18 a feed stream of refined liquid hydrocarbons containing a low concentration of 19 sulfur contaminants that corresponds with less than 500mg of sulfur per liter;
treating the stream in a catalytic reactor, containing hydrotreating catalyst, 21 with gaseous hydrogen, in the ratio of between 0.5 and 25 standard cubic 22 meters of hydrogen gas per standard cubic meter of liquid hydrocarbon, the 23 reactor being operated at a temperature in the range of 140-330°C
and at a 24 pressure in the range of 3-60 bar absolute, to react sulfur contaminants with {E5090787. DOC;1 }
1 the hydrogen to produce gaseous hydrogen sulfide; removing an effluent, 2 comprising liquid hydrocarbons, reduced in sulfur contaminants concentration 3 relative to the feed stream, and a gaseous mixture comprising hydrogen 4 sulfide and hydrogen, which gases are partially or wholly dissolved in the liquid hydrocarbon, from the reactor; separating the gaseous mixture of the 6 effluent from the liquid hydrocarbons to produce a liquid hydrocarbon product 7 and a gaseous mixture stream; contacting the gaseous mixture stream with a 8 liquid or solid absorbent for the hydrogen sulfide to remove hydrogen sulfide 9 from the gaseous mixture and produce purified gaseous hydrogen; and recycling the purified gaseous hydrogen to the reactor to provide part of the 11 hydrogen supplied to the reactor.
14 The hydrocarbons that are treated in accordance with the present invention are preferably selected from the group consisting of gasoline, 16 gasoline octane enhancer, diesel fuel, stove oil, kerosene and jet fuel.
The 17 gasoline octane enhancer may be iso-octane or petroleum refinery alkylate.
18 The gasoline and gasoline octane enhancer will have a boiling range from 19 about 10°C to about 230°C, at atmospheric pressure. In a preferred embodiment, the liquid hydrocarbon stream will be distillate fuels, such as 21 diesel fuel, stove oil, kerosene and jet fuel. Such streams typically have a 22 boiling range from about 140°C to about 600°C, at atmospheric pressure, and 23 more typically from about 150°C to about 400°C, at atmospheric pressure.
{E5090787. DOC;1 }
1 The liquid hydrocarbon stream can contain sulfur compounds as high 2 as 500 mg sulfur per liter, but typically will contain less than 50 mg sulfur per 3 liter. The performance of the present invention will vary with the operating 4 conditions and the specific sulfur compounds present, but it is intended to produce a product hydrocarbon stream with less than 15 mg of sulfur per liter, 6 and in some cases less than 5 mg sulfur per liter.
7 Having reference to the Figures, the liquid hydrocarbon stream 1 is 8 mixed with hydrogen gas 8 and the mixture 2 is introduced into a catalytic 9 reactor 3 operated at moderately elevated pressure and temperature, selected to effect reaction of the contained sulfur contaminants to produce 11 hydrogen sulfide. While the hydrogen gas 8 can be added separately to the 12 reactor 3, it would normally be added to the liquid hydrocarbon stream 1 13 under pressure but before heating to reactor inlet temperature.
14 Hydrogen preferably should be added in excess of that required stoichiometrically for the reaction of hydrogen with the sulfur contaminants.
16 The quantity of hydrogen should provide sufficient hydrogen partial pressure 17 to promote the reaction with the contaminants at mild operating temperatures 18 and to minimize undesirable coke or fouling compound forming reactions of 19 hydrocarbons with other hydrocarbons or sulfur compounds. More preferably, the amount of hydrogen added will be between 0.5 and 25 standard cubic 21 meters of hydrogen gas per standard cubic meter of hydrocarbon liquid. More 22 typically, the amount is expected to range from 1 to 10 standard cubic meters 23 of hydrogen gas per standard cubic meter of hydrocarbon liquid. This amount 24 of hydrogen is less than that used in conventional hydrotreating, and it is {E5090787.DOC;1}
1 made possible by recognizing that: (a) the small amount of sulfur 2 contaminants requiring removal do not appreciably consume the hydrogen 3 present; and (b) the refined hydrocarbons have typically been previously 4 hydrotreated or hydrocracked such that the consumption of hydrogen to saturate aromatic hydrocarbons or olefins will be low.
6 Preferably, the hydrogen generator 12 will provide the total net make-? up amount of hydrogen 13 for the process. The hydrogen generator will 8 typically be a commercially-available packaged unit that will have a larger 9 than normal purification section 7 to handle a portion of the recycle hydrogen gas stream. For example, such packaged hydrogen generator units are 11 licensed by Haldor Topsoe A/S who have ten plants in operation worldwide 12 using methanol as the feedstock, and 21 others using natural gas or other 13 hydrocarbons as feedstock. The quantity of hydrogen make-up 13 required is 14 expected to be between 0.1 and 6 standard cubic meters of hydrogen gas per standard cubic meter of hydrocarbon liquid. This quantity is in excess of the 16 hydrogen consumed in the reactor as there are other losses of hydrogen, 17 such as in the compressor seals and unrecovered dissolved/entrained 18 hydrogen gas in the liquid hydrocarbon product. However the quantity is less 19 than conventional hydrotreating.
The operating temperature of the reactor 3 is expected to be between 21 140°C and 330°C, but more typically is expected to range from 200 to 290°C.
22 A lower temperature will require more catalyst volume for a given flowrate of 23 hydrocarbon, but will minimize the undesirable side reactions of cracking and 24 coke or fouling compound formation. Cracking is a process of decomposition {E5090787.DOC;1}
g 1 of a compound to smaller compounds through the action of elevated 2 temperature, time, and with or without the presence of catalyst. The coke or 3 fouling compound formation is more problematic than simple cracking and 4 would adversely affect the process by plugging the catalyst surface causing high pressure drop or reduced reaction rate, both of which can lead to a 6 shortened operating time between catalyst change-outs. By operating at lower 7 temperatures than a typical hydrotreater reactor, these reactions are 8 ameliorated even though the quantity of hydrogen is less than in a 9 conventional hydrotreater reactor.
The reactor operating pressure may be maintained between 3 bar and 11 60 bar absolute, but more typically will be between 10 bar and 40 bar 12 absolute. To improve the process energy efficiency, compared to a 13 conventional hydrotreater, it is preferred, although not necessary, to operate 14 at a high enough pressure to avoid significant vapourization of the hot hydrogen-hydrocarbon mixture.
16 The catalyst used is a conventional hydrotreating catalyst, preferably 17 with high desulfurization activity and low cracking activity. These catalysts are 18 typically a combination of a Group VI metal and a Group VIII metal on a 19 suitable refractory support such as alumina. Such catalysts are well known in the art. The amount of catalyst required for a given liquid hydrocarbon 21 flowrate will vary with the amount and species of sulfur compounds present, 22 and the operating conditions of pressure and temperature. The volume of 23 catalyst, expressed as a Liquid Hourly Space Velocity (LHSV) will typically 24 range from 0.5 to 20, based on liquid hydrocarbon standard volume flowrate.
{E5090787. DOC;1 }
1 The reactor effluent mixture 4 requires separation of the unreacted 2 hydrogen gas and the hydrogen sulfide gas formed from the liquid 3 hydrocarbons. This separation may be accomplished in a stripper/scrubber 4 section 5 where a stripping gas 20 is used to remove hydrogen sulfide and may also remove hydrogen. The stripping step preferably takes place in a 6 stripper vessel 15 at a temperature of between 30°C and 300°C
and a 7 pressure of between 0.5 bar absolute and 10 bar absolute. Non-limiting 8 examples of the stripping gases used are steam or recycled hydrogen. A low 9 pressure of 0.5 to 2 bar absolute is favoured to reduce the amount of stripping gas needed, but such low pressure is not required. The low pressure 11 separation and recovery of hydrogen from the liquid hydrocarbon product, 12 compared to a conventional hydrotreater, reduces the entrained and dissolved 13 hydrogen gas losses, making the process more economical.
14 The stripper vessel gas effluent 21 is cooled and any liquid formed may be removed in a gas-liquid separator vessel 16. The gas stream 17 from the 16 separator 16 is routed to a scrubber vessel 18. In the scrubber vessel 18 a 17 scrubbing liquid 10 is contacted with the hydrogen sulfide-containing gas 18 stream 17. The scrubber vessel 18 can be a simple gas-liquid separator and 19 may utilize a static mixer, or can be a counter-current or co-current multistage contactor containing a static mixer or packing or contacting trays. The 21 scrubbing liquid 10 can be a caustic solution or another suitable solution 22 containing a compound that will absorb hydrogen sulfide. Preferably, the 23 scrubber vessel 18 will be a vertical packed column containing a bed of 24 packing 8 to 20 feet in length, over which a 5 to 35 weight percent caustic {E5090787. DOC;1 }
1 aqueous solution is circulated to the top, and the gas stream 17 is introduced 2 countercurrently at the bottom of the packed bed. The treated gas 6 is 3 withdrawn from the top, and the scrubbing liquid draw-off 9, containing 4 absorbed hydrogen sulphide, is collected and withdrawn from the bottom of S the column 18. The scrubbing operation typically takes place at a temperature 6 of between 10°C and 100°C, although more typically between 30°C and 60°C.
7 The operating pressure of the scrubber can vary widely between 0.5 bar and 8 50 bar absolute, but more typically will be between 1 and 5 bar absolute.
9 In an alternative configuration to effect hydrogen sulphide removal that 10 is not shown in the Figures, the reactor effluent is first cooled to between 10°C
11 and 100°C, and then contacted with a liquid absorbent, such as aqueous 12 caustic, prior to or simultaneous with separation of the hydrogen-containing 13 gas from the liquid hydrocarbon stream in a separator vessel, operating at a 14 pressure of between 0.5 and 10 bar absolute. A coalescer may be added downstream of the separator vessel on the liquid hydrocarbon product to 16 remove trace quantities of aqueous absorbent liquid. The hydrocarbon liquid 17 product 11 exiting the stripper/scrubber section 5 will be largely free of 18 hydrogen sulfide and hydrogen gases, and will have a reduced sulfur content.
19 It may be pumped and cooled on its way to storage.
The hydrogen gas (6) from the stripper/scrubber section 5, scrubbed 21 free of hydrogen sulfide, may contain some small amount of other gas 22 impurities that were in the liquid hydrocarbon feed or formed in the reactor.
23 The gas requires compression and may also require purification prior to being 24 recycled as the hydrogen gas mixed into the liquid hydrocarbon feed. The {E5090787.DOC;1}
1 hydrogen gas recycle is compressed and all or part is sent to the hydrogen 2 purification unit of the hydrogen generator. In some cases, there may be no 3 significant generation and accumulation of gas impurities. For those cases 4 the purification step can be omitted, although a small purification unit would still be provided as part of the hydrogen generator unit.
6 In another alternative configuration, not shown in the Figures, the 7 reactor effluent 4 can be contacted in an absorbent vessel filled with a bed of 8 low cost solid absorbent, such as a metal oxide, to effect hydrogen sulphide 9 removal. The absorber would be an alternative to the caustic scrubber vessel and associated caustic supply and caustic bottoms re-circulation pump. The 11 temperature of the absorber is expected to be from 10°C up to 330°C, and the 12 pressure from 0.8 to 60 bar absolute. A stripper vessel or flash drum would 13 still be needed to recover hydrogen for recycle.
{E5090787.DOC;1 }
12 Sulfur and sulfur compounds (collectively referred to herein as 'sulfur 13 contaminants') may be present in varying concentrations in refined 14 hydrocarbon streams. The maximum allowable sulfur contaminant content of fuels such as diesel and gasoline is regulated by governments and is being 16 reduced over time by legislation. This results in the need to further reduce the 17 already low levels of sulfur contaminants in such streams.
18 In some cases, sulfur contamination will take place as a consequence 19 of transporting the hydrocarbon streams through pipelines that contain sulfur contaminants remaining in the pipeline from the transportation of high sulfur 21 content streams, such as petroleum crude oils. This can result in the 22 hydrocarbon streams not being within specification due to higher sulfur 23 content than allowable or due to other specifications, such as the copper strip E5090787.DOC;1 y 1 corrosion test, that are related to the corrosiveness of some sulfur 2 compounds.
3 While there are many well-established technologies to remove sulfur 4 contaminants, such as hydrotreating and sulfur absorbent processes, the cost of the existing processes is relatively high in either or both of capital cost or 6 operating cost, considering the small amount of sulfur contaminants that may 7 be required to be removed in some cases. For aqueous caustic-based 8 processes for the removal of primarily elemental sulfur, the process is specific 9 to one or a few compounds of sulfur and may not achieve the desired level of sulfur reduction required. A need still exists in the art for increasing the 11 efficiency and improving the economics of sulfur removal from liquid 12 hydrocarbon streams contaminated with low levels of sulfur and/or sulfur 13 compounds.
SUMMARY OF THE INVENTION
16 We provide a process for reducing the sulfur content of a refined liquid 17 hydrocarbon stream such as gasoline, gasoline octane enhancer, diesel fuel, 18 stove oil, kerosene or jet fuel, which has a low sulfur content, for example as a 19 result of transportation through a multi-product pipeline. In accordance with this process, we add hydrogen to the stream, optionally heat the resulting 21 mixture and introduce it into a reactor containing a bed of hydrotreating 22 catalyst.
(E5090787.DOC;1}
1 Some of the sulfur contaminants in the treated stream react with 2 hydrogen to form hydrogen sulfide. In connection with this we prefer to use a 3 small packaged hydrogen generator plant to supply the limited amount of net 4 hydrogen gas needed for the process.
The reactor operating conditions of temperature, pressure and 6 hydrogen quantity are milder than a typical hydrotreater process, because of 7 the low level of sulfur contaminants required to be removed and the nature of 8 these contaminants.
9 From the reactor effluent, the hydrocarbons are separated as a liquid product from the gaseous hydrogen and hydrogen sulfide. The separated gas 11 stream, containing largely hydrogen, is fed to a means, such as a scrubber, 12 for removal of hydrogen sulfide using an absorbent, such as aqueous caustic.
13 The so-purified hydrogen gas is then recycled to form the major part of the 14 hydrogen supplied to the process. Preferably, all or part of the recycled gas stream is purified further in a conventional hydrogen purification process, such 16 as a pressure swing absorption unit, to remove other contaminants, such as 17 methane, that may form as a by-product in the reactor or be present in trace 18 quantities in the liquid hydrocarbon feed stream.
19 In an alternative configuration, the reactor effluent may be first cooled and then contacted with a liquid absorbent, such as aqueous caustic, prior to 21 or simultaneous with separation of the hydrogen-containing gas from the 22 liquid hydrocarbon stream in a separator vessel.
{E5090787.DOC;1}
1 The invention is characterized by the following features:
2 ~ It preferably uses a small hydrogen generator plant to inexpensively 3 supply the limited amount of net hydrogen needed to treat the small 4 quantity of sulfur contaminants involved;
~ It combines low severity or mild conditions of temperature and low 6 quantity of hydrogen with the provision of the catalyst to effect sulfur 7 contaminants conversion to an easily removable form (hydrogen 8 sulfide);
9 ~ It preferably integrates the hydrogen purification requirement for the recycle gas with the hydrogen purification unit that is a common feature 11 of hydrogen generator plants; and 12 ~ It disposes of the hydrogen sulfide formed by using a liquid absorbent, 13 such as aqueous caustic, or a low cost solid absorbent, such as a 14 metal oxide, both of which are cost effective for the low levels of sulfur compounds involved.
16 In one embodiment the invention is concerned with a process for 17 desulphurizing refined liquid hydrocarbons, comprising the steps of:
providing 18 a feed stream of refined liquid hydrocarbons containing a low concentration of 19 sulfur contaminants that corresponds with less than 500mg of sulfur per liter;
treating the stream in a catalytic reactor, containing hydrotreating catalyst, 21 with gaseous hydrogen, in the ratio of between 0.5 and 25 standard cubic 22 meters of hydrogen gas per standard cubic meter of liquid hydrocarbon, the 23 reactor being operated at a temperature in the range of 140-330°C
and at a 24 pressure in the range of 3-60 bar absolute, to react sulfur contaminants with {E5090787. DOC;1 }
1 the hydrogen to produce gaseous hydrogen sulfide; removing an effluent, 2 comprising liquid hydrocarbons, reduced in sulfur contaminants concentration 3 relative to the feed stream, and a gaseous mixture comprising hydrogen 4 sulfide and hydrogen, which gases are partially or wholly dissolved in the liquid hydrocarbon, from the reactor; separating the gaseous mixture of the 6 effluent from the liquid hydrocarbons to produce a liquid hydrocarbon product 7 and a gaseous mixture stream; contacting the gaseous mixture stream with a 8 liquid or solid absorbent for the hydrogen sulfide to remove hydrogen sulfide 9 from the gaseous mixture and produce purified gaseous hydrogen; and recycling the purified gaseous hydrogen to the reactor to provide part of the 11 hydrogen supplied to the reactor.
14 The hydrocarbons that are treated in accordance with the present invention are preferably selected from the group consisting of gasoline, 16 gasoline octane enhancer, diesel fuel, stove oil, kerosene and jet fuel.
The 17 gasoline octane enhancer may be iso-octane or petroleum refinery alkylate.
18 The gasoline and gasoline octane enhancer will have a boiling range from 19 about 10°C to about 230°C, at atmospheric pressure. In a preferred embodiment, the liquid hydrocarbon stream will be distillate fuels, such as 21 diesel fuel, stove oil, kerosene and jet fuel. Such streams typically have a 22 boiling range from about 140°C to about 600°C, at atmospheric pressure, and 23 more typically from about 150°C to about 400°C, at atmospheric pressure.
{E5090787. DOC;1 }
1 The liquid hydrocarbon stream can contain sulfur compounds as high 2 as 500 mg sulfur per liter, but typically will contain less than 50 mg sulfur per 3 liter. The performance of the present invention will vary with the operating 4 conditions and the specific sulfur compounds present, but it is intended to produce a product hydrocarbon stream with less than 15 mg of sulfur per liter, 6 and in some cases less than 5 mg sulfur per liter.
7 Having reference to the Figures, the liquid hydrocarbon stream 1 is 8 mixed with hydrogen gas 8 and the mixture 2 is introduced into a catalytic 9 reactor 3 operated at moderately elevated pressure and temperature, selected to effect reaction of the contained sulfur contaminants to produce 11 hydrogen sulfide. While the hydrogen gas 8 can be added separately to the 12 reactor 3, it would normally be added to the liquid hydrocarbon stream 1 13 under pressure but before heating to reactor inlet temperature.
14 Hydrogen preferably should be added in excess of that required stoichiometrically for the reaction of hydrogen with the sulfur contaminants.
16 The quantity of hydrogen should provide sufficient hydrogen partial pressure 17 to promote the reaction with the contaminants at mild operating temperatures 18 and to minimize undesirable coke or fouling compound forming reactions of 19 hydrocarbons with other hydrocarbons or sulfur compounds. More preferably, the amount of hydrogen added will be between 0.5 and 25 standard cubic 21 meters of hydrogen gas per standard cubic meter of hydrocarbon liquid. More 22 typically, the amount is expected to range from 1 to 10 standard cubic meters 23 of hydrogen gas per standard cubic meter of hydrocarbon liquid. This amount 24 of hydrogen is less than that used in conventional hydrotreating, and it is {E5090787.DOC;1}
1 made possible by recognizing that: (a) the small amount of sulfur 2 contaminants requiring removal do not appreciably consume the hydrogen 3 present; and (b) the refined hydrocarbons have typically been previously 4 hydrotreated or hydrocracked such that the consumption of hydrogen to saturate aromatic hydrocarbons or olefins will be low.
6 Preferably, the hydrogen generator 12 will provide the total net make-? up amount of hydrogen 13 for the process. The hydrogen generator will 8 typically be a commercially-available packaged unit that will have a larger 9 than normal purification section 7 to handle a portion of the recycle hydrogen gas stream. For example, such packaged hydrogen generator units are 11 licensed by Haldor Topsoe A/S who have ten plants in operation worldwide 12 using methanol as the feedstock, and 21 others using natural gas or other 13 hydrocarbons as feedstock. The quantity of hydrogen make-up 13 required is 14 expected to be between 0.1 and 6 standard cubic meters of hydrogen gas per standard cubic meter of hydrocarbon liquid. This quantity is in excess of the 16 hydrogen consumed in the reactor as there are other losses of hydrogen, 17 such as in the compressor seals and unrecovered dissolved/entrained 18 hydrogen gas in the liquid hydrocarbon product. However the quantity is less 19 than conventional hydrotreating.
The operating temperature of the reactor 3 is expected to be between 21 140°C and 330°C, but more typically is expected to range from 200 to 290°C.
22 A lower temperature will require more catalyst volume for a given flowrate of 23 hydrocarbon, but will minimize the undesirable side reactions of cracking and 24 coke or fouling compound formation. Cracking is a process of decomposition {E5090787.DOC;1}
g 1 of a compound to smaller compounds through the action of elevated 2 temperature, time, and with or without the presence of catalyst. The coke or 3 fouling compound formation is more problematic than simple cracking and 4 would adversely affect the process by plugging the catalyst surface causing high pressure drop or reduced reaction rate, both of which can lead to a 6 shortened operating time between catalyst change-outs. By operating at lower 7 temperatures than a typical hydrotreater reactor, these reactions are 8 ameliorated even though the quantity of hydrogen is less than in a 9 conventional hydrotreater reactor.
The reactor operating pressure may be maintained between 3 bar and 11 60 bar absolute, but more typically will be between 10 bar and 40 bar 12 absolute. To improve the process energy efficiency, compared to a 13 conventional hydrotreater, it is preferred, although not necessary, to operate 14 at a high enough pressure to avoid significant vapourization of the hot hydrogen-hydrocarbon mixture.
16 The catalyst used is a conventional hydrotreating catalyst, preferably 17 with high desulfurization activity and low cracking activity. These catalysts are 18 typically a combination of a Group VI metal and a Group VIII metal on a 19 suitable refractory support such as alumina. Such catalysts are well known in the art. The amount of catalyst required for a given liquid hydrocarbon 21 flowrate will vary with the amount and species of sulfur compounds present, 22 and the operating conditions of pressure and temperature. The volume of 23 catalyst, expressed as a Liquid Hourly Space Velocity (LHSV) will typically 24 range from 0.5 to 20, based on liquid hydrocarbon standard volume flowrate.
{E5090787. DOC;1 }
1 The reactor effluent mixture 4 requires separation of the unreacted 2 hydrogen gas and the hydrogen sulfide gas formed from the liquid 3 hydrocarbons. This separation may be accomplished in a stripper/scrubber 4 section 5 where a stripping gas 20 is used to remove hydrogen sulfide and may also remove hydrogen. The stripping step preferably takes place in a 6 stripper vessel 15 at a temperature of between 30°C and 300°C
and a 7 pressure of between 0.5 bar absolute and 10 bar absolute. Non-limiting 8 examples of the stripping gases used are steam or recycled hydrogen. A low 9 pressure of 0.5 to 2 bar absolute is favoured to reduce the amount of stripping gas needed, but such low pressure is not required. The low pressure 11 separation and recovery of hydrogen from the liquid hydrocarbon product, 12 compared to a conventional hydrotreater, reduces the entrained and dissolved 13 hydrogen gas losses, making the process more economical.
14 The stripper vessel gas effluent 21 is cooled and any liquid formed may be removed in a gas-liquid separator vessel 16. The gas stream 17 from the 16 separator 16 is routed to a scrubber vessel 18. In the scrubber vessel 18 a 17 scrubbing liquid 10 is contacted with the hydrogen sulfide-containing gas 18 stream 17. The scrubber vessel 18 can be a simple gas-liquid separator and 19 may utilize a static mixer, or can be a counter-current or co-current multistage contactor containing a static mixer or packing or contacting trays. The 21 scrubbing liquid 10 can be a caustic solution or another suitable solution 22 containing a compound that will absorb hydrogen sulfide. Preferably, the 23 scrubber vessel 18 will be a vertical packed column containing a bed of 24 packing 8 to 20 feet in length, over which a 5 to 35 weight percent caustic {E5090787. DOC;1 }
1 aqueous solution is circulated to the top, and the gas stream 17 is introduced 2 countercurrently at the bottom of the packed bed. The treated gas 6 is 3 withdrawn from the top, and the scrubbing liquid draw-off 9, containing 4 absorbed hydrogen sulphide, is collected and withdrawn from the bottom of S the column 18. The scrubbing operation typically takes place at a temperature 6 of between 10°C and 100°C, although more typically between 30°C and 60°C.
7 The operating pressure of the scrubber can vary widely between 0.5 bar and 8 50 bar absolute, but more typically will be between 1 and 5 bar absolute.
9 In an alternative configuration to effect hydrogen sulphide removal that 10 is not shown in the Figures, the reactor effluent is first cooled to between 10°C
11 and 100°C, and then contacted with a liquid absorbent, such as aqueous 12 caustic, prior to or simultaneous with separation of the hydrogen-containing 13 gas from the liquid hydrocarbon stream in a separator vessel, operating at a 14 pressure of between 0.5 and 10 bar absolute. A coalescer may be added downstream of the separator vessel on the liquid hydrocarbon product to 16 remove trace quantities of aqueous absorbent liquid. The hydrocarbon liquid 17 product 11 exiting the stripper/scrubber section 5 will be largely free of 18 hydrogen sulfide and hydrogen gases, and will have a reduced sulfur content.
19 It may be pumped and cooled on its way to storage.
The hydrogen gas (6) from the stripper/scrubber section 5, scrubbed 21 free of hydrogen sulfide, may contain some small amount of other gas 22 impurities that were in the liquid hydrocarbon feed or formed in the reactor.
23 The gas requires compression and may also require purification prior to being 24 recycled as the hydrogen gas mixed into the liquid hydrocarbon feed. The {E5090787.DOC;1}
1 hydrogen gas recycle is compressed and all or part is sent to the hydrogen 2 purification unit of the hydrogen generator. In some cases, there may be no 3 significant generation and accumulation of gas impurities. For those cases 4 the purification step can be omitted, although a small purification unit would still be provided as part of the hydrogen generator unit.
6 In another alternative configuration, not shown in the Figures, the 7 reactor effluent 4 can be contacted in an absorbent vessel filled with a bed of 8 low cost solid absorbent, such as a metal oxide, to effect hydrogen sulphide 9 removal. The absorber would be an alternative to the caustic scrubber vessel and associated caustic supply and caustic bottoms re-circulation pump. The 11 temperature of the absorber is expected to be from 10°C up to 330°C, and the 12 pressure from 0.8 to 60 bar absolute. A stripper vessel or flash drum would 13 still be needed to recover hydrogen for recycle.
{E5090787.DOC;1 }
Claims (14)
1. A process for desulphurizing refined liquid hydrocarbons, comprising the steps of:
providing a feed stream of refined liquid hydrocarbons containing a low concentration of sulfur contaminants that corresponds with less than 500 mg of sulfur per liter;
treating the stream in a catalytic reactor, containing hydrotreating catalyst, with gaseous hydrogen in the ratio of between 0.5 and 25 standard cubic meters of hydrogen per standard cubic meter of liquid hydrocarbon, the reactor being operated at a temperature in the range of 140-330°C and at a pressure in the range of 3-60 bar absolute, to react sulfur contaminants with the hydrogen to produce gaseous hydrogen sulfide;
removing an effluent, comprising liquid hydrocarbons reduced in sulfur contaminants concentration relative to the feed stream, and a gaseous mixture comprising hydrogen sulfide and hydrogen, which gases are partially or wholly dissolved in the liquid hydrocarbon, from the reactor;
separating the gaseous mixture of the effluent from the liquid hydrocarbons to produce a liquid hydrocarbon product and a gaseous mixture stream;
contacting the gaseous mixture stream with a liquid or solid absorbent for the hydrogen sulfide to remove hydrogen sulfide from the gaseous mixture and produce purified gaseous hydrogen; and recycling the purified gaseous hydrogen to the reactor to provide part of the hydrogen supplied to the reactor.
providing a feed stream of refined liquid hydrocarbons containing a low concentration of sulfur contaminants that corresponds with less than 500 mg of sulfur per liter;
treating the stream in a catalytic reactor, containing hydrotreating catalyst, with gaseous hydrogen in the ratio of between 0.5 and 25 standard cubic meters of hydrogen per standard cubic meter of liquid hydrocarbon, the reactor being operated at a temperature in the range of 140-330°C and at a pressure in the range of 3-60 bar absolute, to react sulfur contaminants with the hydrogen to produce gaseous hydrogen sulfide;
removing an effluent, comprising liquid hydrocarbons reduced in sulfur contaminants concentration relative to the feed stream, and a gaseous mixture comprising hydrogen sulfide and hydrogen, which gases are partially or wholly dissolved in the liquid hydrocarbon, from the reactor;
separating the gaseous mixture of the effluent from the liquid hydrocarbons to produce a liquid hydrocarbon product and a gaseous mixture stream;
contacting the gaseous mixture stream with a liquid or solid absorbent for the hydrogen sulfide to remove hydrogen sulfide from the gaseous mixture and produce purified gaseous hydrogen; and recycling the purified gaseous hydrogen to the reactor to provide part of the hydrogen supplied to the reactor.
2. The process as set forth in claim 1 wherein make-up hydrogen is added to the reactor to provide the balance of the hydrogen needed for the conversion of sulfur contaminants to hydrogen sulfide and for other losses or reactions that consume hydrogen.
3. The process as set forth in claim 2 wherein the make-up hydrogen is supplied by a hydrogen generator plant.
4. The process as set forth in any one of claims 1 to 3 wherein the reactor is operated at a temperature in the range of 200-290°C and a pressure in the range of 10-40 bar absolute and the quantity of gaseous hydrogen added to the reactor is in the range of 1 - 10 standard cubic meters per standard cubic meter of liquid hydrocarbons.
5. The process as set forth in any one of claims 1 to 4 wherein the step of separating the gaseous mixture of the reactor effluent from the liquid hydrocarbons includes stripping the gases from the effluent with a stripping gas in a stripper vessel.
6. The process as set forth in any one of claims 1 to 5 wherein the step of contacting the separated gaseous mixture stream with an absorbent comprises scrubbing the hydrogen sulfide from the gaseous mixture stream with a liquid absorbent in a scrubber vessel.
7. The process as set forth in claim 6 wherein the liquid absorbent is aqueous caustic.
8. The process as set forth in claim 5 wherein stripping is carried out at a temperature in the range of 30-300°C and at a pressure in the range of 0.5-bar absolute.
9. The process as set forth in claim 5 or 8 wherein the stripping gas is steam or hydrogen.
10. The process as set forth in claim 6, 7, 8 or 9 wherein scrubbing is carried out at a temperature in the range of 10-100°C and at a pressure in the range of 0.5-50 bar absolute.
11. The process as set forth in claim 3 wherein a hydrogen purification section of the hydrogen generator plant is used to also further purify all or part of the hydrogen that is recovered for recycle back to the reactor.
12. The process as set forth in any one of claims 1 to 11 wherein the refined liquid hydrocarbons are selected from the group consisting of gasoline, gasoline octane enhancer, diesel fuel, stove oil, kerosene and jet fuel.
13. The process as set forth in claim 12 wherein the refined liquid hydrocarbons have been conveyed through a multi-product pipeline prior to desulphurization.
14. The process as set forth in any one of claims 1 to 13 wherein the refined liquid hydrocarbons contain a concentration of sulfur contaminants of less than 50 mg of sulfur per liter.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2520046 CA2520046C (en) | 2004-09-16 | 2005-09-16 | Process for reducing the level of sulfur compounds from liquid hydrocarbon streams |
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| Application Number | Priority Date | Filing Date | Title |
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| CA2,481,990 | 2004-09-16 | ||
| CA2481990 | 2004-09-16 | ||
| CA 2520046 CA2520046C (en) | 2004-09-16 | 2005-09-16 | Process for reducing the level of sulfur compounds from liquid hydrocarbon streams |
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| CA2520046C true CA2520046C (en) | 2010-06-29 |
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