CATEGORY: DESULFURIZATION
Fuel Processing Technology, Volume 101,
September 2012, Pages 101–105
Investigation
of the oxidative desulfurization of LCO model mixture by GC-MS and FTIR
spectroscopy
Vesislava Toteva, Anton Georgiev, Liliana Topalova
University of Chemical Technology and Metallurgy, 8 “St. Kliment Ohridski”
Blvd., Sofia 1756, Bulgaria
Abstract
Describes
oxidative desulfurization of a model mixture of fluid-catalytic-cracked light
cycle oil (LCO). Oxidations of the sulfur compounds were monitored by FTIR
spectroscopy. Oxidized sulfur compounds and degree of desulfurization by
oxidation were determinad by gas chromatography-mass spectroscopy (GC-MS).
Researchers determined that after oxidation and proper extraction
process about 90% of the highly refractive by HDS (hydrodesulfurization) sulfur
compound like 4,6-Dimethyl-dibenzothiophene (4,6-DMDBT) is removed from the
oxidized model mixture.
Full Text Source (Subscription or Fee): http://www.sciencedirect.com/science/article/pii/S0378382012001282
Thursday, December 27, 2012
Devices And Processes For Deasphalting And/Or Reducing Metals In A Crude Oil With A Desalter Unit
CATEGORY: DESALTERS
PATENT
Devices And Processes For Deasphalting And/Or Reducing Metals In A Crude Oil With A Desalter Unit
Patent number: 8147678
Issue date: Apr 3, 2012
Application number: 12/252,017
Inventors: Sudhakar Chakka, Steve E. Orwig, Joachim Voelkening
Original Assignee: BP Corporation North America Inc.
Abstract
This invention relates to devices and processes for removing asphaltenes and/or metals from crude oil to increase refinery processing of heavy materials. The desalters of this invention reduce and/or remove at least a portion of asphaltenes and/or metals form the crude oil. The separation occurs by mixing water with the crude oil to result in an aqueous phase having water and water soluble salts, an interface phase having asphaltenes and/or metals along with water, and a hydrocarbon phase having desalted, deasphalted and/or reduced metal crude oil.
BACKGROUND
1. Field of the Invention
This invention relates to devices and processes for removing asphaltenes and/or metals from crude oil to increase refinery processing of heavy hydrocarbon feedstocks.
2. Discussion of RelatedArt
The current trend in refining includes utilization of heavier crude oil and alternative hydrocarbon sources, such as bitumen and tar sands. These heavier materials include an increased amount of asphaltenes and an increased amount of metals and/ or heavy metals, Which makes processing diflicult due to among other things, viscosity, fouling, and catalyst deactivation issues.
In response to this need, the petroleum refining industry has developed efforts and resources to develop neW Ways to solve problems associated With asphaltene-containing streams and metal-containing streams. HoWever, such efforts have only partially succeeded in providing practical methods and devices to maintain refinery capacity.
Solvent deasphalting is a commercially practiced process to separate the asphaltenes out of the heavy oils from a bottom of atmospheric and/or vacuum distillation toWers. Solvent deasphalting units require high capital expenditures and have high operating costs to recycle the solvent.
Stephenson et al., U.S. Pat. No. 6,120,678 discloses desalting adjunct chemistry and teaches asphaltene dispersing treatments to reduce the rag interface. Stephenson et al. does not teach or suggest collecting asphaltenes and/ or metals in a rag layer for separation from the crude oil in a desalter.
Wilson et al., U.S. Pat. No. 3,779,895 discloses high temperature steam treatment of asphaltene-containing streams to form an emulsion that is then solvent deasphalted. Wilson et al. does not teach or suggest collecting asphaltenes and/or metals in a rag layer for separation from the crude oil in a desalter.
Jorgensen, U.S. Patent Application Publication 2005/ 021 1602 discloses superheated steam treatment of high boiling temperature material to demetalize the feed. Jorgensen does not teach or suggest collecting asphaltenes and/ or metals in a rag layer for separation from the crude oil in a desalter.
Gunnerman, U.S. Patent Application Publication 2005/ 0205463 discloses using ultrasound of a suflicient intensity to convert heavy hydrocarbons in an emulsion to lighter components. Gunnerman does not teach or suggest collecting asphaltenes and/or metals in a rag layer for separation from the crude oil in a desalter.
Van der Toorn et al., U.S. Pat. No. 3,730,880 discloses problems of coking and catalyst issues for hyrdroconversion units When processing materials having asphaltenes and metals. Barger, U.S. Pat. No. 4,384,948 discloses similar problems With coking and catalyst poisoning in fluidized catalytic cracking units When processing materials With asphaltenes and metals.
Although the foregoing disclosures provide advances in the art, there is still a need for a method of removing asphaltenes and/or metals from crude oil, such as improved processability, reduced fouling, reduced viscosity, improved coke product quality, and/or, reduced catalyst deactivation.
SUMMARY
These and other aspects of this invention are met at least in part by a process and an apparatus for using a desalter to
remove and/ or reduce at least a portion of asphaltenes and/or metals from the crude oil, such as to improve processability, reduce fouling, reduce viscosity, improve coke product quality, reduce catalyst deactivation, and/ or the like.
According to one embodiment, this invention relates to a desalter unit for removing Water soluble salts and asphaltenes from a crude oil stream. The unit includes a separator for receiving a Water-in-oil emulsion formed from crude oil and Wash Water. The separator includes a first nozzle for WithdraWing an aqueous phase having Water and Water soluble salts, a second nozzle for WithdraWing an interface phase having asphaltenes and Water, and a third nozzle for WithdraWing a hydrocarbon phase having desalted and deasphalted crude oil.
According to a second embodiment, this invention relates to a process of desalting and deasphalting crude oil. The process includes mixing a Wash Water stream and a crude oil stream to form a Water-in-oil emulsion. The crude oil stream includes Water soluble salts and asphaltenes. The process includes separating the Water-in-oil emulsion in a desalter unit to form a first stream having Water and Water soluble salts, a second stream having asphaltenes and Water, and a third stream having desalted and deasphalted crude oil.
According to a third embodiment, this invention relates to a method of increasing asphaltene-containing crude oil processing capacity in a refinery With a hydroconversion unit having an asphaltene-based operating constraint. The method includes removing at least a portion of asphaltenes from an asphaltene-containing crude oil in a desalter unit, and increasing a volume of the asphaltene-containing crude oil to the refinery until an amount of asphaltenes in a feed to the hydroconversion unit reaches the asphaltene-based operating constraint.
According to a fourth embodiment, this invention relates to a method of increasing metal-containing crude oil processing capacity in a refinery With a hydroconversion unit having a metal-based operating constraint. The method includes removing at least a portion of metals from a metal-containing crude oil in a desalter unit, and increasing a volume of the metal-containing crude oil to the refinery until an amount of metals in a feed to the hydroconversion unit reaches the metal-based operating constraint. The metals can be any metal, such as those that deactivate a heavy oil hydroconversion catalyst.
Free Full Text Source: http://www.google.com/patents/US8147678?dq=novel+refinery
PATENT
Devices And Processes For Deasphalting And/Or Reducing Metals In A Crude Oil With A Desalter Unit
Patent number: 8147678
Issue date: Apr 3, 2012
Application number: 12/252,017
Inventors: Sudhakar Chakka, Steve E. Orwig, Joachim Voelkening
Original Assignee: BP Corporation North America Inc.
Abstract
This invention relates to devices and processes for removing asphaltenes and/or metals from crude oil to increase refinery processing of heavy materials. The desalters of this invention reduce and/or remove at least a portion of asphaltenes and/or metals form the crude oil. The separation occurs by mixing water with the crude oil to result in an aqueous phase having water and water soluble salts, an interface phase having asphaltenes and/or metals along with water, and a hydrocarbon phase having desalted, deasphalted and/or reduced metal crude oil.
BACKGROUND
1. Field of the Invention
This invention relates to devices and processes for removing asphaltenes and/or metals from crude oil to increase refinery processing of heavy hydrocarbon feedstocks.
2. Discussion of RelatedArt
The current trend in refining includes utilization of heavier crude oil and alternative hydrocarbon sources, such as bitumen and tar sands. These heavier materials include an increased amount of asphaltenes and an increased amount of metals and/ or heavy metals, Which makes processing diflicult due to among other things, viscosity, fouling, and catalyst deactivation issues.
In response to this need, the petroleum refining industry has developed efforts and resources to develop neW Ways to solve problems associated With asphaltene-containing streams and metal-containing streams. HoWever, such efforts have only partially succeeded in providing practical methods and devices to maintain refinery capacity.
Solvent deasphalting is a commercially practiced process to separate the asphaltenes out of the heavy oils from a bottom of atmospheric and/or vacuum distillation toWers. Solvent deasphalting units require high capital expenditures and have high operating costs to recycle the solvent.
Stephenson et al., U.S. Pat. No. 6,120,678 discloses desalting adjunct chemistry and teaches asphaltene dispersing treatments to reduce the rag interface. Stephenson et al. does not teach or suggest collecting asphaltenes and/ or metals in a rag layer for separation from the crude oil in a desalter.
Wilson et al., U.S. Pat. No. 3,779,895 discloses high temperature steam treatment of asphaltene-containing streams to form an emulsion that is then solvent deasphalted. Wilson et al. does not teach or suggest collecting asphaltenes and/or metals in a rag layer for separation from the crude oil in a desalter.
Jorgensen, U.S. Patent Application Publication 2005/ 021 1602 discloses superheated steam treatment of high boiling temperature material to demetalize the feed. Jorgensen does not teach or suggest collecting asphaltenes and/ or metals in a rag layer for separation from the crude oil in a desalter.
Gunnerman, U.S. Patent Application Publication 2005/ 0205463 discloses using ultrasound of a suflicient intensity to convert heavy hydrocarbons in an emulsion to lighter components. Gunnerman does not teach or suggest collecting asphaltenes and/or metals in a rag layer for separation from the crude oil in a desalter.
Van der Toorn et al., U.S. Pat. No. 3,730,880 discloses problems of coking and catalyst issues for hyrdroconversion units When processing materials having asphaltenes and metals. Barger, U.S. Pat. No. 4,384,948 discloses similar problems With coking and catalyst poisoning in fluidized catalytic cracking units When processing materials With asphaltenes and metals.
Although the foregoing disclosures provide advances in the art, there is still a need for a method of removing asphaltenes and/or metals from crude oil, such as improved processability, reduced fouling, reduced viscosity, improved coke product quality, and/or, reduced catalyst deactivation.
SUMMARY
These and other aspects of this invention are met at least in part by a process and an apparatus for using a desalter to
remove and/ or reduce at least a portion of asphaltenes and/or metals from the crude oil, such as to improve processability, reduce fouling, reduce viscosity, improve coke product quality, reduce catalyst deactivation, and/ or the like.
According to one embodiment, this invention relates to a desalter unit for removing Water soluble salts and asphaltenes from a crude oil stream. The unit includes a separator for receiving a Water-in-oil emulsion formed from crude oil and Wash Water. The separator includes a first nozzle for WithdraWing an aqueous phase having Water and Water soluble salts, a second nozzle for WithdraWing an interface phase having asphaltenes and Water, and a third nozzle for WithdraWing a hydrocarbon phase having desalted and deasphalted crude oil.
According to a second embodiment, this invention relates to a process of desalting and deasphalting crude oil. The process includes mixing a Wash Water stream and a crude oil stream to form a Water-in-oil emulsion. The crude oil stream includes Water soluble salts and asphaltenes. The process includes separating the Water-in-oil emulsion in a desalter unit to form a first stream having Water and Water soluble salts, a second stream having asphaltenes and Water, and a third stream having desalted and deasphalted crude oil.
According to a third embodiment, this invention relates to a method of increasing asphaltene-containing crude oil processing capacity in a refinery With a hydroconversion unit having an asphaltene-based operating constraint. The method includes removing at least a portion of asphaltenes from an asphaltene-containing crude oil in a desalter unit, and increasing a volume of the asphaltene-containing crude oil to the refinery until an amount of asphaltenes in a feed to the hydroconversion unit reaches the asphaltene-based operating constraint.
According to a fourth embodiment, this invention relates to a method of increasing metal-containing crude oil processing capacity in a refinery With a hydroconversion unit having a metal-based operating constraint. The method includes removing at least a portion of metals from a metal-containing crude oil in a desalter unit, and increasing a volume of the metal-containing crude oil to the refinery until an amount of metals in a feed to the hydroconversion unit reaches the metal-based operating constraint. The metals can be any metal, such as those that deactivate a heavy oil hydroconversion catalyst.
Free Full Text Source: http://www.google.com/patents/US8147678?dq=novel+refinery
Feasibility Study of Integrating Multi Effect Desalination and Gas Turbine Systems for Lavan Island Oil Refinery
CATEGORY: DESALINATION
Iran. J. Chem. Chem. Eng, Vol. 31, No. 3, 2012
Feasibility Study of Integrating Multi Effect Desalination and Gas Turbine Systems for Lavan Island Oil Refinery
Shakouri, Mahdi●*+
m.shakouri@srbiau.ac.ir
Young Researchers Club, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
Ghadamian, Hossein
Department of Energy Engineering, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
Mohammadpour Bagheri, Farzaneh
Department of Medical Engineering, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
ABSTRACT:
Researchers conducted a feasibility study of integrating thermal desalination unit with Gas Turbine (GT) using retrofit and grass root design techniques for Lavan Island Oil Refinery, located in Persian Gulf.
According to computed parameters on developed code for the power generation unit No.1 using EES (Engineering Equation Solver) software, thermal efficiency of the GT unit No.1 and thermal energy recovered by HRSG (Heat Recovery Steam Generator) are equal to 22.79% and 4847 kW, respectively. Therefore, it shows a considerable potential on heat recovery and motive steam production. Effect of variations on different quantitative and qualitative parameters has been reviewed on the next step of this research. Finally, effect of engineering and economical parameters has been compared based on the following scenarios:
● Integrating available Thermal Desalination Unit (TDU) with available steam boiler,
● Retrofitting available TDU with HRSG,
● Integrating GT unit No.1 with novel simulated TDU based of grass root design.
As a result, based on economical model, which has been developed using GAMS (Generalized Algebraic Modelling System) software, the selected scenario is the third scenario.
Free Full Text Source: http://www.sid.ir/en/VEWSSID/J_pdf/84320126313.pdf
Iran. J. Chem. Chem. Eng, Vol. 31, No. 3, 2012
Feasibility Study of Integrating Multi Effect Desalination and Gas Turbine Systems for Lavan Island Oil Refinery
Shakouri, Mahdi●*+
m.shakouri@srbiau.ac.ir
Young Researchers Club, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
Ghadamian, Hossein
Department of Energy Engineering, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
Mohammadpour Bagheri, Farzaneh
Department of Medical Engineering, Science and Research Branch, Islamic Azad University, Tehran, I.R. IRAN
ABSTRACT:
Researchers conducted a feasibility study of integrating thermal desalination unit with Gas Turbine (GT) using retrofit and grass root design techniques for Lavan Island Oil Refinery, located in Persian Gulf.
According to computed parameters on developed code for the power generation unit No.1 using EES (Engineering Equation Solver) software, thermal efficiency of the GT unit No.1 and thermal energy recovered by HRSG (Heat Recovery Steam Generator) are equal to 22.79% and 4847 kW, respectively. Therefore, it shows a considerable potential on heat recovery and motive steam production. Effect of variations on different quantitative and qualitative parameters has been reviewed on the next step of this research. Finally, effect of engineering and economical parameters has been compared based on the following scenarios:
● Integrating available Thermal Desalination Unit (TDU) with available steam boiler,
● Retrofitting available TDU with HRSG,
● Integrating GT unit No.1 with novel simulated TDU based of grass root design.
As a result, based on economical model, which has been developed using GAMS (Generalized Algebraic Modelling System) software, the selected scenario is the third scenario.
Free Full Text Source: http://www.sid.ir/en/VEWSSID/J_pdf/84320126313.pdf
Predicting Petroleum Coke Morphology From Feedstock Properties
CATEGORY: DELAYED COKING
PATENT
Predicting Petroleum Coke Morphology From Feedstock Properties
Document Type and Number: United States Patent Application 20120298553
Inventors:
Fern, Jared (Avondale, PA, US)
Application Number:
13/117446
Publication Date:
11/29/2012
Assignee:
Lyondell Chemical Company (Houston, Tx, Us)
Abstract:
A method of predicting the morphological type of coke produced in a delayed coking process is provided by measuring S-values of an asphaltene containing feedstock with an S-value machine. Improved refinery operations and delayed coking operations can be obtained by virtue of the invention.
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to the formation of coke by the delayed coker process. The coke formed can be a fuel grade coke, classified as either sponge coke or shot coke. The type of coke produced can be predicted from a preliminary testing of the feedstock to improve coke morphology.
2. Description of the related art
Delayed coking is a thermal cracking process used in petroleum refineries to upgrade and convert petroleum residuum (bottoms from distillation of crude oil) into liquid and gas product streams leaving behind a solid, concentrated carbon material, petroleum coke (hereinafter “coke”). Petroleum coke was first made by the pioneer oil refineries of Northwestern Pennsylvania in the 1860's. Those primitive refineries boiled crude oil in small, iron stills to recover kerosene, a valuable and much needed luminescent. The stills were heated by wood or coal fires built underneath the still which over-heated and coked the oil near the bottom. After the distillation was complete, the still was allowed to cool so that workmen could dig out the coke and tar before the next run.
The origin of the vertical coke drum was probably from thermal cracking of gas oil for the production of gasoline and diesel fuel. From 1912 to 1935 the Burton process developed by Standard Oil at Whiting, Indiana converted gas oil to gasoline with the production of petroleum coke. The lack of an adequate supply of crude oil and the lack of a heavy oil market caused land-locked middle American refineries to process the heavy fuel oil (atmosperic distillation bottoms and vacuum distillation bottoms) in a delayed coker to produce more gasoline and diesel fuel.
Delayed coking combined a number of the features and improvements from the development of the thermal cracking process. The use of pressure as well as heat for cracking and separating the heater from the coker and the use of two coking drums enabled the delayed coker to operate on a continuous basis. The number of cokers built before 1955 was small, with a surge in delayed coker construction between 1955 and 1975 at 6% per year and an 11% growth rate during the 1965 to 1970 period. The growth of delayed cokers was in step with the growth of fluid catalytic cracking and rapid decline in thermal cracking.
Today, the delayed coker is the only main process in a modern petroleum refinery that is a batch-continuous process. A schematic of a basic refinery is shown in FIG. 1. The flow through the tube furnace is continuous. The feed stream is switched between the two coker drums. One drum is on-line filling with coke while the other drum is being steam stripped, cooled, decoked, pressure checked and warmed up. The overheat vapors from the coke drums flow to a fractionator, usually called a combination tower. The fractionator, or combination tower, has a resevoir in the bottom where the fresh feed is combined with condensed product vapors (recyle) to make up the feed to the coker heater.
A basic coker operation flow diagram is shown as FIG. 2 to illustrate some of the delayed coking unit hardware.
Coke drum diameters range from 4 to 9 meters (13 to 30 feet) with the straight side being about 25 meters (82 feet) with a 1.5 meter diameter top blind flange closure and a 2 meter diameter bottom blind flange in which a 15 to 30 cm inlet nozzle is attached. Both the top blind flange and bottom blind flange must be removed when decoking the drum. The pressure in the drum ranges from 1 to 5.9 bars, typically about 2 to 3 bars.
A high pressure water jet is employed to cut the coke out of the drum, but other mechanical removal methods can be employed.
The physical structure of coke can be broken down into three main types, shot coke, sponge coke and needle coke. Shot coke is in the form of balls of 2 to 5 mm in size, but can agglomerate into larger balls as large as 25 centimeters. Sponge coke is named for its sponge-like appearance. One manner of influencing the production of sponge coke is disclosed in U.S. Pat. No. 4,096,097. Needle coke is named for its needle-like structure. Needle coke is produced from feedstocks without asphaltenes present. Such production requires special feedstocks and other special processing parameters as disclosed in U.S. Pat. No. 4,490,244. There are various methods for determining the properties, such as luster, of coke such as disclosed in U.S. Pat. No. 6,954,545, among others. However, none of these disclosures can predict the type of coke which will be produced from any given asphaltene-containing feedstock.
When crudes are processed where blends of shot coke and sponge coke are produced, the shot coke, composed of spherical particles, tend to agglomerate together. When this happens, regions within the coke drum do not cool as efficiently as the rest of the drum creating operational problems when cutting the coke out of the drum with high pressure water. Such operational problems are known as “hot spots” and “steam eruptions” when subsequently cutting the coke with a high pressure jet of water.
There are some techniques available in the literature for prediction of coke morphology. The most prevalent technique involves measuring the ratio of the microcarbon residue (hereinafter “MCR”) to the quantity of asphaltenes present in the resid. If this ratio is less than 2, the resid will produce primarily shot coke. If the ratio is higher than 2, the resid will produce primarily sponge coke. The MCR to asphaltene ratio is based upon historical plant experience and is engrained in coking lore, but this ratio is only accurate at the extremes of the morphology spectrum and not at the intermediate values that are typically found in refineries.
A second approach found in the literature is to experimentally measure the quantity of aromatic carbon and heteroatoms (O, S, N) present in a precipitated asphaltene sample. If the ratio is greater than 11 then primarily sponge coke will be formed and if the ratio is less than 7 primarily shot coke will be formed. The region between 7 and 11 is a transitional region where the coke can create hot spots. This technique does not quantify the intermediate resids processed at some refineries, and the analysis is difficult to perform in a timely manner without specialized equipment. Furthermore, each of these techniques add an additional error to the measurement because the resid suspension is broken to remove the asphaltene molecules for analysis. Another approach is disclosed in U.S. Pat. No. 7,803,627.
Thus, there exists a need to predict the type of coke to be produced in a delayed coker, based on the asphaltene containing feedstock used in the refinery
Each of the foregoing U.S. Patents are herein incorporated by reference in their entireties.
BRIEF SUMMARY OF THE INVENTION
The stability of a solution that contains asphaltenes can be measured using an S-value machine. An S-value machine is an analytical apparatus that measures the stability of heavy fuels. One such machine is available from ROFA FRANCE from the manufacturer, DPC SA of Grand Rue 86 CH-20075 Thielle-Wavre, SWITZERLAND. The parameters generated from the stability analysis are typically used to determine if two different crude oils are compatible for blending.
In one embodiment according to the present invention, the parameters measured by an S-value machine are used to predict the type of coke produced from a given asphaltene containing feedstock.
In another embodiment of the invention a delayed coking apparatus is utilized to primarily produce either shot coke or sponge coke.
These and other embodiments of the invention will become apparent when reading the following detailed description of preferred embodiments in connection with the appended drawings.
Free Full Text Source: http://www.freepatentsonline.com/y2012/0298553.html
PATENT
Predicting Petroleum Coke Morphology From Feedstock Properties
Document Type and Number: United States Patent Application 20120298553
Inventors:
Fern, Jared (Avondale, PA, US)
Application Number:
13/117446
Publication Date:
11/29/2012
Assignee:
Lyondell Chemical Company (Houston, Tx, Us)
Abstract:
A method of predicting the morphological type of coke produced in a delayed coking process is provided by measuring S-values of an asphaltene containing feedstock with an S-value machine. Improved refinery operations and delayed coking operations can be obtained by virtue of the invention.
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to the formation of coke by the delayed coker process. The coke formed can be a fuel grade coke, classified as either sponge coke or shot coke. The type of coke produced can be predicted from a preliminary testing of the feedstock to improve coke morphology.
2. Description of the related art
Delayed coking is a thermal cracking process used in petroleum refineries to upgrade and convert petroleum residuum (bottoms from distillation of crude oil) into liquid and gas product streams leaving behind a solid, concentrated carbon material, petroleum coke (hereinafter “coke”). Petroleum coke was first made by the pioneer oil refineries of Northwestern Pennsylvania in the 1860's. Those primitive refineries boiled crude oil in small, iron stills to recover kerosene, a valuable and much needed luminescent. The stills were heated by wood or coal fires built underneath the still which over-heated and coked the oil near the bottom. After the distillation was complete, the still was allowed to cool so that workmen could dig out the coke and tar before the next run.
The origin of the vertical coke drum was probably from thermal cracking of gas oil for the production of gasoline and diesel fuel. From 1912 to 1935 the Burton process developed by Standard Oil at Whiting, Indiana converted gas oil to gasoline with the production of petroleum coke. The lack of an adequate supply of crude oil and the lack of a heavy oil market caused land-locked middle American refineries to process the heavy fuel oil (atmosperic distillation bottoms and vacuum distillation bottoms) in a delayed coker to produce more gasoline and diesel fuel.
Delayed coking combined a number of the features and improvements from the development of the thermal cracking process. The use of pressure as well as heat for cracking and separating the heater from the coker and the use of two coking drums enabled the delayed coker to operate on a continuous basis. The number of cokers built before 1955 was small, with a surge in delayed coker construction between 1955 and 1975 at 6% per year and an 11% growth rate during the 1965 to 1970 period. The growth of delayed cokers was in step with the growth of fluid catalytic cracking and rapid decline in thermal cracking.
Today, the delayed coker is the only main process in a modern petroleum refinery that is a batch-continuous process. A schematic of a basic refinery is shown in FIG. 1. The flow through the tube furnace is continuous. The feed stream is switched between the two coker drums. One drum is on-line filling with coke while the other drum is being steam stripped, cooled, decoked, pressure checked and warmed up. The overheat vapors from the coke drums flow to a fractionator, usually called a combination tower. The fractionator, or combination tower, has a resevoir in the bottom where the fresh feed is combined with condensed product vapors (recyle) to make up the feed to the coker heater.
A basic coker operation flow diagram is shown as FIG. 2 to illustrate some of the delayed coking unit hardware.
Coke drum diameters range from 4 to 9 meters (13 to 30 feet) with the straight side being about 25 meters (82 feet) with a 1.5 meter diameter top blind flange closure and a 2 meter diameter bottom blind flange in which a 15 to 30 cm inlet nozzle is attached. Both the top blind flange and bottom blind flange must be removed when decoking the drum. The pressure in the drum ranges from 1 to 5.9 bars, typically about 2 to 3 bars.
A high pressure water jet is employed to cut the coke out of the drum, but other mechanical removal methods can be employed.
The physical structure of coke can be broken down into three main types, shot coke, sponge coke and needle coke. Shot coke is in the form of balls of 2 to 5 mm in size, but can agglomerate into larger balls as large as 25 centimeters. Sponge coke is named for its sponge-like appearance. One manner of influencing the production of sponge coke is disclosed in U.S. Pat. No. 4,096,097. Needle coke is named for its needle-like structure. Needle coke is produced from feedstocks without asphaltenes present. Such production requires special feedstocks and other special processing parameters as disclosed in U.S. Pat. No. 4,490,244. There are various methods for determining the properties, such as luster, of coke such as disclosed in U.S. Pat. No. 6,954,545, among others. However, none of these disclosures can predict the type of coke which will be produced from any given asphaltene-containing feedstock.
When crudes are processed where blends of shot coke and sponge coke are produced, the shot coke, composed of spherical particles, tend to agglomerate together. When this happens, regions within the coke drum do not cool as efficiently as the rest of the drum creating operational problems when cutting the coke out of the drum with high pressure water. Such operational problems are known as “hot spots” and “steam eruptions” when subsequently cutting the coke with a high pressure jet of water.
There are some techniques available in the literature for prediction of coke morphology. The most prevalent technique involves measuring the ratio of the microcarbon residue (hereinafter “MCR”) to the quantity of asphaltenes present in the resid. If this ratio is less than 2, the resid will produce primarily shot coke. If the ratio is higher than 2, the resid will produce primarily sponge coke. The MCR to asphaltene ratio is based upon historical plant experience and is engrained in coking lore, but this ratio is only accurate at the extremes of the morphology spectrum and not at the intermediate values that are typically found in refineries.
A second approach found in the literature is to experimentally measure the quantity of aromatic carbon and heteroatoms (O, S, N) present in a precipitated asphaltene sample. If the ratio is greater than 11 then primarily sponge coke will be formed and if the ratio is less than 7 primarily shot coke will be formed. The region between 7 and 11 is a transitional region where the coke can create hot spots. This technique does not quantify the intermediate resids processed at some refineries, and the analysis is difficult to perform in a timely manner without specialized equipment. Furthermore, each of these techniques add an additional error to the measurement because the resid suspension is broken to remove the asphaltene molecules for analysis. Another approach is disclosed in U.S. Pat. No. 7,803,627.
Thus, there exists a need to predict the type of coke to be produced in a delayed coker, based on the asphaltene containing feedstock used in the refinery
Each of the foregoing U.S. Patents are herein incorporated by reference in their entireties.
BRIEF SUMMARY OF THE INVENTION
The stability of a solution that contains asphaltenes can be measured using an S-value machine. An S-value machine is an analytical apparatus that measures the stability of heavy fuels. One such machine is available from ROFA FRANCE from the manufacturer, DPC SA of Grand Rue 86 CH-20075 Thielle-Wavre, SWITZERLAND. The parameters generated from the stability analysis are typically used to determine if two different crude oils are compatible for blending.
In one embodiment according to the present invention, the parameters measured by an S-value machine are used to predict the type of coke produced from a given asphaltene containing feedstock.
In another embodiment of the invention a delayed coking apparatus is utilized to primarily produce either shot coke or sponge coke.
These and other embodiments of the invention will become apparent when reading the following detailed description of preferred embodiments in connection with the appended drawings.
Free Full Text Source: http://www.freepatentsonline.com/y2012/0298553.html
Co-promotion of fluorine and boron on NiMo/Al2O3 for hydrotreating light cycle oil
CATEGORY: CATALYSIS
Catal. Sci. Technol., 2012,2, 1925-1932Catalysis Science & Technology, Issue 9, 2012
Co-promotion of fluorine and boron on NiMo/Al2O3 for hydrotreating light cycle oil
Songdong Yao , Ying Zheng , Lianhui Ding , Siauw Ng and Hong Yang
Department of Chemical Engineering,University of New Brunswick, P.O. Box 4400, Fredericton, Canada
Abstract
After modifying the hydrotreating catalyst NiMo/Al2O3 with various amounts of fluorine (F) and boron (B) through the pore-saturated impregnation method, researchers characterized the resulting catalysts by BET, pyridine-IR, XPS, and TEM techniques.
Incorporation of fluorine and boron led to the variations in the catalyst acidity and the dispersion of active metals, causing direct impacts on the hydrotreating activities of the catalysts. The hydrodesulfurization (HDS), hydrodenitrogenation (HDN) and hydrodearomatization (HDA) activities of the catalysts were examined in an autoclave reactor using real light cycle oil as feed. The HDS activity decreased in the order NiMo/F,B-Al(5.0) > NiMo/F,B-Al(7.0) > NiMo/F,B-Al(3.5), indicating the existence of an optimum amount of F and B.
Full Text Source (Subscription or Fee): http://pubs.rsc.org/en/content/articlelanding/2012/cy/c2cy20042b
Catal. Sci. Technol., 2012,2, 1925-1932Catalysis Science & Technology, Issue 9, 2012
Co-promotion of fluorine and boron on NiMo/Al2O3 for hydrotreating light cycle oil
Songdong Yao , Ying Zheng , Lianhui Ding , Siauw Ng and Hong Yang
Department of Chemical Engineering,University of New Brunswick, P.O. Box 4400, Fredericton, Canada
Abstract
After modifying the hydrotreating catalyst NiMo/Al2O3 with various amounts of fluorine (F) and boron (B) through the pore-saturated impregnation method, researchers characterized the resulting catalysts by BET, pyridine-IR, XPS, and TEM techniques.
Incorporation of fluorine and boron led to the variations in the catalyst acidity and the dispersion of active metals, causing direct impacts on the hydrotreating activities of the catalysts. The hydrodesulfurization (HDS), hydrodenitrogenation (HDN) and hydrodearomatization (HDA) activities of the catalysts were examined in an autoclave reactor using real light cycle oil as feed. The HDS activity decreased in the order NiMo/F,B-Al(5.0) > NiMo/F,B-Al(7.0) > NiMo/F,B-Al(3.5), indicating the existence of an optimum amount of F and B.
Full Text Source (Subscription or Fee): http://pubs.rsc.org/en/content/articlelanding/2012/cy/c2cy20042b
Novel Steam Reformer Based Hydrogen Plant Scheme For Enhanced Carbon Dioxide Recovery
CATEGORY: CARBON CAPTURE
PATENT
Novel Steam Reformer Based Hydrogen Plant Scheme For Enhanced Carbon Dioxide Recovery
Inventors: Tarun D. Vakil, Ulrich Wolf
Original Assignees: LURGI GmbH, L'Air Liquide Societe Anonyme Pour L'Etude ed I'Exploitaion Des Procedes Georges Claude
Current U.S. Classification: 423/652
Application number: 13/396,229
Publication number: US 2012/0141368 A1
Filing date: Feb 14, 2012
Abstract
A novel steam reformer unit design, a novel hydrogen PSA unit design, a novel hydrogen/nitrogen enrichment unit design, and novel processing scheme application are presented.
FIELD OF THE INVENTION
[0002] This invention relates to novel steam reformer unit design, a novel hydrogen PSA unit design, a novel hydrogen/ nitrogen enrichment unit design, and a novel processing scheme application.
BACKGROUND
[0003] The production of hydrogen by the steam reforming of hydrocarbons is Well knoWn. In the basic process, a hydrocarbon, or a mixture of hydrocarbons, is initially treated to remove, or convert and then remove, trace contaminants, such as sulfur and olefins, Which Would adversely affect the reformer and the doWn stream Water gas shift unit catalyst. Natural gas containing predominantly methane is a preferred starting material since it has a higher proportion of hydrogen than other hydrocarbons. HoWever, light hydrocarbons or refinery off gases containing hydrocarbons, or refinery streams such as LPG, naphtha hydrocarbons or others readily available light feeds might be utilized as Well.
[0004] The pretreated hydrocarbon feed stream is typically at a pressure of about 200 to 400 psig, and combined With high pressure steam, Which is at a higher than the feed stream pressure, before entering the reformer furnace. The amount of steam added is much in excess of the stoichiometric amount. The reformer itself conventionally contains tubes packed With catalyst through Which the stean1/hydrocarbon mixture passes. An elevated temperature, e.g. about 1580° F., or 860° C., is maintained to drive the endothermic reaction.
[0005] The efliuent from the reformer furnace is principally hydrogen, carbon monoxide, carbon dioxide, Water vapor, and methane in proportion close to equilibrium amounts at the furnace temperature and pres sure. The efliuent is conventionally introduced into a one- or tWo-stage Water gas shift reactor to form additional hydrogen and carbon dioxide. The shift reactor converts the carbon monoxide to carbon dioxide by reaction With Water vapor, Which generates additional Hydrogen. This reaction is endothermic. The combination of steam reformer and Water gas shift converter is Well knoWn to those of ordinary skill in the art.
[0006] If CO2 capture from the high pressure syngas stream exiting the Water gas shift unit is desired, the shift converter effluent, Which comprises hydrogen, carbon dioxide and Water With minor quantities of methane and carbon monoxide is introduced into a conventional absorption unit for carbon dioxide removal. Such a unit operates on the WellknoWn amine Wash or Benfield processes Wherein carbon dioxide is removed from the effluent by dissolution in an absorbent solution, i.e. an amine solution or potassium carbonate solution, respectively. Conventionally, such units can remove up to 99 percent or higher of the carbon dioxide in the shift converter efliuent.
[0007] The efliuent from the carbon dioxide absorption unit is introduced into a pressure sWing adsorption (PSA) unit. PSA is a Well-knoWn process for separating essentially pure hydrogen from the mixture of gases as a result of the difference in the degree of adsorption among them on a particulate adsorbent retained in a stationary bed.
[0008] Conventionally, the remainder of the PSA unit feed components, after recovery of pure hydrogen product, Which comprises carbon monoxide, the hydrocarbon, i.e. methane, hydrogen and carbon dioxide, is returned to the steam reformer furnace and combusted to obtain energy for use therein
[0009] To practice CO2 emissions capture from such hydrogen plants, one must consider total emissions resulting from the plant, Which includes CO2 recovery from reformer furnace flue gas as Well.
[0010] The CO2 emissions from a steam reformer based conventional hydrogen plant originate from the reformer furnace flue gas. The root source of this total CO2 in the furnace flue gas results from tWo sources:
[0011] (a) the reaction Within the reformer tubes and shift; and
[0012] (b) the combustion of fuel in reformer furnace. [0013] Each source contributes betWeen about 40 and about 60% of the total CO2 emitted through the reformer furnace flue gas. For CO2 capture, conventional schemes employed consist of:
[0014] (a) removal of CO2, only from the high pressure syngas stream exit shift unit; [0015] (b) removal of CO2, only from the reformer furnace flue gas; and
[0016] (c) removal of CO2 via both (a) and (b) above. [0017] Option (a) permits about 50 to about 60% of total CO2 emissions capture. Option (b) permits about 90% of total CO2 emissions capture. Option (c) permits about 95% of the total CO2 emissions capture. Option (a) permits only partial capture at reasonable cost, Option (b) is considered the most expensive of the three options, capital and utility requirements Wise. Option (c) is also expensive, utility intensive and quite elaborate. [0018] Therefore, it is very desirable and cost effective to have a H2 plant design that results in betWeen about 85% and about 95%+of total CO2 capture, solely from the high pressure syngas stream exit Water gas shift reactor.
SUMMARY
[0019] The present invention is a novel steam reformer design and method using the same. This method includes a variety of steps of Which the first is to provide a first gas mixture. This first gas mixture may comprise natural gas containing mostly methane, light hydrocarbons, refinery off gases containing hydrocarbons, refinery streams such as LPG, naphtha hydrocarbons or other readily available light feeds. Step tWo involves introducing said first gas mixture into either a pre-reforrner folloWed by a primary reformer, or directly into a primary reformer, thereby generating a second gas mixture comprising hydrogen, carbon monoxide, carbon dioxide. The novelty here is in the design and operating parameters of the primary reformer. The third step of the method includes introducing said second gas mixture into at least one isothermal shift reactor, or a combination of a high folloWed by a loW temperature shift reactor, or a medium temperature shift reactor, thereby generating a third gas mixture. Step four includes introducing said third gas mixture into an amine Wash, Wherein said third gas is separated into a fourth gas mixture and a carbon dioxide enriched stream. The fifth step includes introducing said fourth gas mixture into a standard hydrogen PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. In the final step, the reformer furnace uses the PSA purge gas as fuel With the supplemental fuel or remainder of the fuel for the reformer furnace being natural gas or a portion of the feed hydrocarbon stream, or any other external fuel. By virtue of the novel reformer, the syngas/ flue gas CO2 distribution is higher than the conventional design.
[0020] In one embodiment of the present invention, the novel steam reformer design along With a novel hydrogen PSA design that is loWer cost is used. Additionally, this embodiment is self-sufficient in reformer fumace fuel requirements and therefore does not require any import of supplemental fuel. This embodiment is the same With regard to steps one to four above but differs in the remaining steps. More specifically, the fifth step of this embodiment includes introducing said fourth gas mixture into either a standard recovery or a special loW recovery PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. In this particular embodiment, the reformer furnace uses all of the PSA purge gas as fuel. Additionally, it uses a novel hydrogen PSA design that is loWer cost. By virtue of this novel PSA design, the PSA purge gas is suflicient to satisfy all fuel requirements of the reformer furnace. Because the scheme is self-suflicient in reformer furnace fuel requirements, there is no requirement of any import of supplemental fuel. By virtue of the novel reformer and the novel PSA designs, the syngas/flue gas CO2 distribution is higher than the conventional design.
[0021] In a still further embodiment of the present invention, the novel steam reformer design is used along With a novel hydrogen PSA design that is loWer cost. This embodiment is self-suflicient in reformer furnace fuel requirements and therefore, does not require any import of supplemental fuel. Additionally, a second novel gas separation unit is designed to be included in this embodiment (preferably an adsorption based unit although a membrane or a cryogenic separation unit may be used) that separates the compressed primary PSA unit purge gas into tWo streams-one that is recycled back as feed to the reforming section and the other that is used as reformer furnace fuel. Steps one to four of this embodiment are the same With regard to steps one to four above. The fifth step includes introducing said fourth gas mixture into either a standard recovery or a special loW recovery PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. A second novel gas separation unit is additionally employed, preferably an adsorption based unit, that separates the compressed primary PSA unit purge gas into tWo streams, one that is recycled back as feed to the reforming section and the other that is used as reformer furnace fuel. While an adsorption based unit is preferred, a membrane or a cryogenic separation unit may also be used. The scheme is self-suflicient in reformer fumace fuel requirements and therefore, does not require any import of supplemental fuel. By virtue of the novel reformer, the novel primary hydrogen PSA, and the novel second adsorption
based separation unit, the syngas/ flue gas CO2 distribution is higher than the conventional design.
Free Full Text Source: http://www.google.com/patents?hl=en&lr=&vid=USPATAPP13396229&id=Ey8dAgAAEBAJ&oi=fnd&dq=novel+refinery&printsec=abstract#v=onepage&q=novel%20refinery&f=false
PATENT
Novel Steam Reformer Based Hydrogen Plant Scheme For Enhanced Carbon Dioxide Recovery
Inventors: Tarun D. Vakil, Ulrich Wolf
Original Assignees: LURGI GmbH, L'Air Liquide Societe Anonyme Pour L'Etude ed I'Exploitaion Des Procedes Georges Claude
Current U.S. Classification: 423/652
Application number: 13/396,229
Publication number: US 2012/0141368 A1
Filing date: Feb 14, 2012
Abstract
A novel steam reformer unit design, a novel hydrogen PSA unit design, a novel hydrogen/nitrogen enrichment unit design, and novel processing scheme application are presented.
FIELD OF THE INVENTION
[0002] This invention relates to novel steam reformer unit design, a novel hydrogen PSA unit design, a novel hydrogen/ nitrogen enrichment unit design, and a novel processing scheme application.
BACKGROUND
[0003] The production of hydrogen by the steam reforming of hydrocarbons is Well knoWn. In the basic process, a hydrocarbon, or a mixture of hydrocarbons, is initially treated to remove, or convert and then remove, trace contaminants, such as sulfur and olefins, Which Would adversely affect the reformer and the doWn stream Water gas shift unit catalyst. Natural gas containing predominantly methane is a preferred starting material since it has a higher proportion of hydrogen than other hydrocarbons. HoWever, light hydrocarbons or refinery off gases containing hydrocarbons, or refinery streams such as LPG, naphtha hydrocarbons or others readily available light feeds might be utilized as Well.
[0004] The pretreated hydrocarbon feed stream is typically at a pressure of about 200 to 400 psig, and combined With high pressure steam, Which is at a higher than the feed stream pressure, before entering the reformer furnace. The amount of steam added is much in excess of the stoichiometric amount. The reformer itself conventionally contains tubes packed With catalyst through Which the stean1/hydrocarbon mixture passes. An elevated temperature, e.g. about 1580° F., or 860° C., is maintained to drive the endothermic reaction.
[0005] The efliuent from the reformer furnace is principally hydrogen, carbon monoxide, carbon dioxide, Water vapor, and methane in proportion close to equilibrium amounts at the furnace temperature and pres sure. The efliuent is conventionally introduced into a one- or tWo-stage Water gas shift reactor to form additional hydrogen and carbon dioxide. The shift reactor converts the carbon monoxide to carbon dioxide by reaction With Water vapor, Which generates additional Hydrogen. This reaction is endothermic. The combination of steam reformer and Water gas shift converter is Well knoWn to those of ordinary skill in the art.
[0006] If CO2 capture from the high pressure syngas stream exiting the Water gas shift unit is desired, the shift converter effluent, Which comprises hydrogen, carbon dioxide and Water With minor quantities of methane and carbon monoxide is introduced into a conventional absorption unit for carbon dioxide removal. Such a unit operates on the WellknoWn amine Wash or Benfield processes Wherein carbon dioxide is removed from the effluent by dissolution in an absorbent solution, i.e. an amine solution or potassium carbonate solution, respectively. Conventionally, such units can remove up to 99 percent or higher of the carbon dioxide in the shift converter efliuent.
[0007] The efliuent from the carbon dioxide absorption unit is introduced into a pressure sWing adsorption (PSA) unit. PSA is a Well-knoWn process for separating essentially pure hydrogen from the mixture of gases as a result of the difference in the degree of adsorption among them on a particulate adsorbent retained in a stationary bed.
[0008] Conventionally, the remainder of the PSA unit feed components, after recovery of pure hydrogen product, Which comprises carbon monoxide, the hydrocarbon, i.e. methane, hydrogen and carbon dioxide, is returned to the steam reformer furnace and combusted to obtain energy for use therein
[0009] To practice CO2 emissions capture from such hydrogen plants, one must consider total emissions resulting from the plant, Which includes CO2 recovery from reformer furnace flue gas as Well.
[0010] The CO2 emissions from a steam reformer based conventional hydrogen plant originate from the reformer furnace flue gas. The root source of this total CO2 in the furnace flue gas results from tWo sources:
[0011] (a) the reaction Within the reformer tubes and shift; and
[0012] (b) the combustion of fuel in reformer furnace. [0013] Each source contributes betWeen about 40 and about 60% of the total CO2 emitted through the reformer furnace flue gas. For CO2 capture, conventional schemes employed consist of:
[0014] (a) removal of CO2, only from the high pressure syngas stream exit shift unit; [0015] (b) removal of CO2, only from the reformer furnace flue gas; and
[0016] (c) removal of CO2 via both (a) and (b) above. [0017] Option (a) permits about 50 to about 60% of total CO2 emissions capture. Option (b) permits about 90% of total CO2 emissions capture. Option (c) permits about 95% of the total CO2 emissions capture. Option (a) permits only partial capture at reasonable cost, Option (b) is considered the most expensive of the three options, capital and utility requirements Wise. Option (c) is also expensive, utility intensive and quite elaborate. [0018] Therefore, it is very desirable and cost effective to have a H2 plant design that results in betWeen about 85% and about 95%+of total CO2 capture, solely from the high pressure syngas stream exit Water gas shift reactor.
SUMMARY
[0019] The present invention is a novel steam reformer design and method using the same. This method includes a variety of steps of Which the first is to provide a first gas mixture. This first gas mixture may comprise natural gas containing mostly methane, light hydrocarbons, refinery off gases containing hydrocarbons, refinery streams such as LPG, naphtha hydrocarbons or other readily available light feeds. Step tWo involves introducing said first gas mixture into either a pre-reforrner folloWed by a primary reformer, or directly into a primary reformer, thereby generating a second gas mixture comprising hydrogen, carbon monoxide, carbon dioxide. The novelty here is in the design and operating parameters of the primary reformer. The third step of the method includes introducing said second gas mixture into at least one isothermal shift reactor, or a combination of a high folloWed by a loW temperature shift reactor, or a medium temperature shift reactor, thereby generating a third gas mixture. Step four includes introducing said third gas mixture into an amine Wash, Wherein said third gas is separated into a fourth gas mixture and a carbon dioxide enriched stream. The fifth step includes introducing said fourth gas mixture into a standard hydrogen PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. In the final step, the reformer furnace uses the PSA purge gas as fuel With the supplemental fuel or remainder of the fuel for the reformer furnace being natural gas or a portion of the feed hydrocarbon stream, or any other external fuel. By virtue of the novel reformer, the syngas/ flue gas CO2 distribution is higher than the conventional design.
[0020] In one embodiment of the present invention, the novel steam reformer design along With a novel hydrogen PSA design that is loWer cost is used. Additionally, this embodiment is self-sufficient in reformer fumace fuel requirements and therefore does not require any import of supplemental fuel. This embodiment is the same With regard to steps one to four above but differs in the remaining steps. More specifically, the fifth step of this embodiment includes introducing said fourth gas mixture into either a standard recovery or a special loW recovery PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. In this particular embodiment, the reformer furnace uses all of the PSA purge gas as fuel. Additionally, it uses a novel hydrogen PSA design that is loWer cost. By virtue of this novel PSA design, the PSA purge gas is suflicient to satisfy all fuel requirements of the reformer furnace. Because the scheme is self-suflicient in reformer furnace fuel requirements, there is no requirement of any import of supplemental fuel. By virtue of the novel reformer and the novel PSA designs, the syngas/flue gas CO2 distribution is higher than the conventional design.
[0021] In a still further embodiment of the present invention, the novel steam reformer design is used along With a novel hydrogen PSA design that is loWer cost. This embodiment is self-suflicient in reformer furnace fuel requirements and therefore, does not require any import of supplemental fuel. Additionally, a second novel gas separation unit is designed to be included in this embodiment (preferably an adsorption based unit although a membrane or a cryogenic separation unit may be used) that separates the compressed primary PSA unit purge gas into tWo streams-one that is recycled back as feed to the reforming section and the other that is used as reformer furnace fuel. Steps one to four of this embodiment are the same With regard to steps one to four above. The fifth step includes introducing said fourth gas mixture into either a standard recovery or a special loW recovery PSA, Wherein said fourth gas is separated into a hydrogen enriched stream and a PSA purge gas stream. A second novel gas separation unit is additionally employed, preferably an adsorption based unit, that separates the compressed primary PSA unit purge gas into tWo streams, one that is recycled back as feed to the reforming section and the other that is used as reformer furnace fuel. While an adsorption based unit is preferred, a membrane or a cryogenic separation unit may also be used. The scheme is self-suflicient in reformer fumace fuel requirements and therefore, does not require any import of supplemental fuel. By virtue of the novel reformer, the novel primary hydrogen PSA, and the novel second adsorption
based separation unit, the syngas/ flue gas CO2 distribution is higher than the conventional design.
Free Full Text Source: http://www.google.com/patents?hl=en&lr=&vid=USPATAPP13396229&id=Ey8dAgAAEBAJ&oi=fnd&dq=novel+refinery&printsec=abstract#v=onepage&q=novel%20refinery&f=false
Novel Fuel Compositions And Methods For Making Same
CATEGORY: BUNKER FUEL
PATENT
Novel Fuel Compositions And Methods For Making Same
United States Patent Application 20120246999
Inventors:
Stern, David L. (Fairfax, VA, US)
Di Mauro, Salvatore R. (Fairfax, VA, US)
Roccaro, Aldo (Legnano, IT)
Bessonette, Paul W. (Deptford, NJ, US)
Application Number:
13/431050
Publication Date:
10/04/2012
Assignee:
Exxonmobil Research And Engineering Company (Annandale, Nj, Us)
Abstract:
This invention relates to low sulfur marine/bunker fuel compositions and methods of making same. Contrary to conventional marine/bunker fuel compositions/methods, the inventive lower sulfur compositions/methods focus on use of mostly uncracked components, such as (cat feed) hydrotreated gasoils, and/or can also have reduced contents of residual components.
FIELD
This invention relates generally to methods for making marine/bunker fuels having relatively low sulfur content, as well as to the resulting low sulfur content fuel compositions made according to such methods.
BACKGROUND
As promulgated by the International Maritime Organization (IMO), issued as Revised MARPOL Annex VI, marine fuels will he capped globally with increasingly more stringent requirements on sulfur content. In addition, individual countries and regions are beginning to restrict sulfur level used in ships in regions known as Emission Control Areas, or ECAs.
The fuels used in global shipping are typically marine/bunker fuels, for larger ships. Bunker fuels are advantageous since they are less costly than other fuels; however, they are typically composed of cracked and/or resid fuels and hence have higher sulfur levels. Meeting the lower sulfur specs for marine vessels can be conventionally accomplished through the use of distillates. However, distillate fuels typically trade at a high cost premium for a variety of reasons, not the least of which is the utility in a variety of transport applications employing Compression ignition engines. They are produced at low sulfur levels, typically significantly below the sulfur levels specified in the IMO regulations.
Those regulations specify, inter alia, a 1.0 wt % sulfur content on ECA Fuels (effective July, 2010) for residual or distillate fuels, a 3.5 wt % sulfur content cap (effective January, 2012), which can impact about 15% of the current residual fuel supply, a 0.1 wt % sulfur content on ECA Fuels (effective January, 2015), relating mainly to hydrotreated middle distillate fuel, and a 0.5 wt % sulfur content cap (circa 2020-2025), centered mainly on distillate fuel or distillate/residual fuel mixtures. When the ECA sulfur limits and sulfur cap drops, various reactions may take place to supply low sulfur fuels. The 0.1% S ECA fuel can he challenging to supply, since shippers typically purchase lower sulfur fuel oils with properties suitable for marine applications, and at a steep price discount to distillate fuels.
Hydrotreaters in front of FCC units, commonly called CFHT, typically hydroprocess Virgin Gas Oils (VGOs) to sufficiently low sulfur levels such that the product fuels are sufficient to he sold as fuel with no further treatment, or with minimal incremental hydroprocessing.
It would be advantageous to utilize a fuel high energy content, low sulfur fuels in marine applications, which fuels have conventionally included cracked distillates. Distillates can typically command a much higher value than bunker fuels. An alternative low sulfur marine/bunker fuel, with the correct fuel quality characteristics, could command a high premium in the marketplace.
Indeed, there are some publications that disclose the desirability of lowering the sulfur content of marine/bunker fuels. A non-exclusive list of such publications includes, for example, U.S. Pat. Nos. 4,006,076, 4,420,388, 6,187,174, 6,447,671, and 7,651,605, U.S. Patent Application Publication No. 2008/0093262, PCT Publication Nos. WO 1999/057228 and WO 2009/001314, British Patent No. GB 1209967, Russian Patent No. RU 2213125, Japanese Patent No. JP 2006000726, and the following articles: Chem. & Tech. of. Fuels and Oils (2005), 41(4), 287-91; Ropa a Uhlie (1979), 21(8), 433-40; Godishnik na Visshya Khim. heski Institut, Sofiya (1979), 25(2), 146-48; and Energy Progress (1986), 6(1), 15-19.
Thus, it would be desirable to find compositions and methods for making them) in which hydrotreated and/or untracked gasoil products could he used in marine/bunker fuels, as described with reference to the invention herein.
SUMMARY OF EMBODIMENTS OF THE INVENTION
One aspect of the invention relates to a method for making a low sulfur marine and/or bunker fuel composition with a reduced concentration of components that have been cracked, the method comprising: contacting a gasoil feed stream having at least 7500 wppm, for example at least 2000 wppm, sulfur content with a hydrogen-containing gas in the presence of a hydrotreating catalyst under effective hydrotreating conditions in a catalytic feed hydrotreater, such that the product exhibits at most 5000 wppm, for example at most 1000 wppm, sulfur content, a pour point of at least 7° C., and a kinematic viscosity of at least 12 cSt at about 50° C., without the product being subject to cracking; optionally blending at least a portion of the uncracked product with 0-70 vol % of other components, selected from viscosity' modifiers, pour point depressants, lubricity modifiers, antioxidants, and combinations thereof, to form a marine and/or bunker fuel composition, the resulting marine and/or bunker fuel composition containing the uncracked product having: at most 5000 wppm, for example at most 1000 wppm, sulfur content; at most 25 vol %, based on all components of the marine and/or bunker fuel composition, of residual components selected from crude fractionation vacuum resid, crude fractionation atmospheric resid, visbreaker resid, deasphalted vacuum resid, slurry oil, and combinations thereof; less than 50 vol %, based on all components of the marine and/or bunker fuel composition, of residual components, components subject to a refinery cracking step, or both; and at least one of a kinematic viscosity at about 50° C. from 12 cSt to 50 cSt; a density at about 15° C. from 0.90 g/cm3 m to 0.94 g/c3, a pour point from 7° C. to 45° C., and a calculated carbon aromaticity index of 850 or less.
Another aspect of the invention relates to a low sulfur marine and/or bunker fuel composition comprising: 30 vol % to 100 vol % of an uncracked, hydrotreated gasoil product having at most 5000 wppm, for example at most 1000 wppm, sulfur content, a pour point of at least 7° C., and a kinematic viscosity of at least 12 cSt at about 50° C.; and up to 70 vol % of other components, selected from viscosity modifiers, pour point depressants, lubricity modifiers, antioxidants, and combinations thereof, wherein the low sulfur marine and/or bunker fuel composition has: at most 5000 wppm, for example at most 1000 wppm, sulfur content; at most 25 vol %, based on all components of the marine and/or bunker fuel composition, of residual components selected from crude fractionation vacuum resid, crude fractionation atmospheric resid, visbreaker resid, deasphalted vacuum resid, slurry oil, and combinations thereof; less than 50 vol %, based on all components of the marine and/or bunker fuel composition, of residual components, components subject to a refinery cracking step, or both; and at least one of a kinematic viscosity at about 50° C. from 12 cSt to 50 cSt, a density at about 15° C. from 0.90 g/cm3 to 0.94 g/cm3, a pour point from 7° C. to 45° C., and a calculated carbon aromaticity index of 850 or less.
Free Full Text Source: http://www.freepatentsonline.com/y2012/0246999.html
PATENT
Novel Fuel Compositions And Methods For Making Same
United States Patent Application 20120246999
Inventors:
Stern, David L. (Fairfax, VA, US)
Di Mauro, Salvatore R. (Fairfax, VA, US)
Roccaro, Aldo (Legnano, IT)
Bessonette, Paul W. (Deptford, NJ, US)
Application Number:
13/431050
Publication Date:
10/04/2012
Assignee:
Exxonmobil Research And Engineering Company (Annandale, Nj, Us)
Abstract:
This invention relates to low sulfur marine/bunker fuel compositions and methods of making same. Contrary to conventional marine/bunker fuel compositions/methods, the inventive lower sulfur compositions/methods focus on use of mostly uncracked components, such as (cat feed) hydrotreated gasoils, and/or can also have reduced contents of residual components.
FIELD
This invention relates generally to methods for making marine/bunker fuels having relatively low sulfur content, as well as to the resulting low sulfur content fuel compositions made according to such methods.
BACKGROUND
As promulgated by the International Maritime Organization (IMO), issued as Revised MARPOL Annex VI, marine fuels will he capped globally with increasingly more stringent requirements on sulfur content. In addition, individual countries and regions are beginning to restrict sulfur level used in ships in regions known as Emission Control Areas, or ECAs.
The fuels used in global shipping are typically marine/bunker fuels, for larger ships. Bunker fuels are advantageous since they are less costly than other fuels; however, they are typically composed of cracked and/or resid fuels and hence have higher sulfur levels. Meeting the lower sulfur specs for marine vessels can be conventionally accomplished through the use of distillates. However, distillate fuels typically trade at a high cost premium for a variety of reasons, not the least of which is the utility in a variety of transport applications employing Compression ignition engines. They are produced at low sulfur levels, typically significantly below the sulfur levels specified in the IMO regulations.
Those regulations specify, inter alia, a 1.0 wt % sulfur content on ECA Fuels (effective July, 2010) for residual or distillate fuels, a 3.5 wt % sulfur content cap (effective January, 2012), which can impact about 15% of the current residual fuel supply, a 0.1 wt % sulfur content on ECA Fuels (effective January, 2015), relating mainly to hydrotreated middle distillate fuel, and a 0.5 wt % sulfur content cap (circa 2020-2025), centered mainly on distillate fuel or distillate/residual fuel mixtures. When the ECA sulfur limits and sulfur cap drops, various reactions may take place to supply low sulfur fuels. The 0.1% S ECA fuel can he challenging to supply, since shippers typically purchase lower sulfur fuel oils with properties suitable for marine applications, and at a steep price discount to distillate fuels.
Hydrotreaters in front of FCC units, commonly called CFHT, typically hydroprocess Virgin Gas Oils (VGOs) to sufficiently low sulfur levels such that the product fuels are sufficient to he sold as fuel with no further treatment, or with minimal incremental hydroprocessing.
It would be advantageous to utilize a fuel high energy content, low sulfur fuels in marine applications, which fuels have conventionally included cracked distillates. Distillates can typically command a much higher value than bunker fuels. An alternative low sulfur marine/bunker fuel, with the correct fuel quality characteristics, could command a high premium in the marketplace.
Indeed, there are some publications that disclose the desirability of lowering the sulfur content of marine/bunker fuels. A non-exclusive list of such publications includes, for example, U.S. Pat. Nos. 4,006,076, 4,420,388, 6,187,174, 6,447,671, and 7,651,605, U.S. Patent Application Publication No. 2008/0093262, PCT Publication Nos. WO 1999/057228 and WO 2009/001314, British Patent No. GB 1209967, Russian Patent No. RU 2213125, Japanese Patent No. JP 2006000726, and the following articles: Chem. & Tech. of. Fuels and Oils (2005), 41(4), 287-91; Ropa a Uhlie (1979), 21(8), 433-40; Godishnik na Visshya Khim. heski Institut, Sofiya (1979), 25(2), 146-48; and Energy Progress (1986), 6(1), 15-19.
Thus, it would be desirable to find compositions and methods for making them) in which hydrotreated and/or untracked gasoil products could he used in marine/bunker fuels, as described with reference to the invention herein.
SUMMARY OF EMBODIMENTS OF THE INVENTION
One aspect of the invention relates to a method for making a low sulfur marine and/or bunker fuel composition with a reduced concentration of components that have been cracked, the method comprising: contacting a gasoil feed stream having at least 7500 wppm, for example at least 2000 wppm, sulfur content with a hydrogen-containing gas in the presence of a hydrotreating catalyst under effective hydrotreating conditions in a catalytic feed hydrotreater, such that the product exhibits at most 5000 wppm, for example at most 1000 wppm, sulfur content, a pour point of at least 7° C., and a kinematic viscosity of at least 12 cSt at about 50° C., without the product being subject to cracking; optionally blending at least a portion of the uncracked product with 0-70 vol % of other components, selected from viscosity' modifiers, pour point depressants, lubricity modifiers, antioxidants, and combinations thereof, to form a marine and/or bunker fuel composition, the resulting marine and/or bunker fuel composition containing the uncracked product having: at most 5000 wppm, for example at most 1000 wppm, sulfur content; at most 25 vol %, based on all components of the marine and/or bunker fuel composition, of residual components selected from crude fractionation vacuum resid, crude fractionation atmospheric resid, visbreaker resid, deasphalted vacuum resid, slurry oil, and combinations thereof; less than 50 vol %, based on all components of the marine and/or bunker fuel composition, of residual components, components subject to a refinery cracking step, or both; and at least one of a kinematic viscosity at about 50° C. from 12 cSt to 50 cSt; a density at about 15° C. from 0.90 g/cm3 m to 0.94 g/c3, a pour point from 7° C. to 45° C., and a calculated carbon aromaticity index of 850 or less.
Another aspect of the invention relates to a low sulfur marine and/or bunker fuel composition comprising: 30 vol % to 100 vol % of an uncracked, hydrotreated gasoil product having at most 5000 wppm, for example at most 1000 wppm, sulfur content, a pour point of at least 7° C., and a kinematic viscosity of at least 12 cSt at about 50° C.; and up to 70 vol % of other components, selected from viscosity modifiers, pour point depressants, lubricity modifiers, antioxidants, and combinations thereof, wherein the low sulfur marine and/or bunker fuel composition has: at most 5000 wppm, for example at most 1000 wppm, sulfur content; at most 25 vol %, based on all components of the marine and/or bunker fuel composition, of residual components selected from crude fractionation vacuum resid, crude fractionation atmospheric resid, visbreaker resid, deasphalted vacuum resid, slurry oil, and combinations thereof; less than 50 vol %, based on all components of the marine and/or bunker fuel composition, of residual components, components subject to a refinery cracking step, or both; and at least one of a kinematic viscosity at about 50° C. from 12 cSt to 50 cSt, a density at about 15° C. from 0.90 g/cm3 to 0.94 g/cm3, a pour point from 7° C. to 45° C., and a calculated carbon aromaticity index of 850 or less.
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