U.S. patent application number 13/156487 was filed with the patent office on 2012-12-13 for predicting petroleum coke morphology from feedstock properties.
This patent application is currently assigned to LYONDELL CHEMICAL COMPANY. Invention is credited to Farhad Fadakar.
Application Number | 20120312721 13/156487 |
Document ID | / |
Family ID | 46317533 |
Filed Date | 2012-12-13 |
United States Patent
Application |
20120312721 |
Kind Code |
A1 |
Fadakar; Farhad |
December 13, 2012 |
PREDICTING PETROLEUM COKE MORPHOLOGY FROM FEEDSTOCK PROPERTIES
Abstract
According to one embodiment, a method includes desulfurizing a
hydrocarbon feedstock in the presence of a desulfurization
catalyst. A hydrocarbon product is recovered. The color of the
hydrocarbon product is improved and the sulfur content of the
hydrocarbon product is reduced by flash distilling the product.
Inventors: |
Fadakar; Farhad; (Chadds
Ford, PA) |
Assignee: |
LYONDELL CHEMICAL COMPANY
Houston
TX
|
Family ID: |
46317533 |
Appl. No.: |
13/156487 |
Filed: |
June 9, 2011 |
Current U.S.
Class: |
208/88 ; 208/108;
208/208R; 208/243; 208/97 |
Current CPC
Class: |
C10G 2300/202 20130101;
C10G 2400/04 20130101; C10G 47/00 20130101; C10G 67/02 20130101;
C10G 45/08 20130101; C10G 45/02 20130101; C10L 1/08 20130101; C10G
65/12 20130101 |
Class at
Publication: |
208/88 ;
208/208.R; 208/243; 208/97; 208/108 |
International
Class: |
C10G 55/06 20060101
C10G055/06; C10G 31/00 20060101 C10G031/00 |
Claims
1. A method for processing a hydrocarbon feedstock comprising:
desulfurizing a hydrocarbon feedstock in the presence of a
desulfurization catalyst; recovering a hydrocarbon product; and
improving the color of the hydrocarbon product and reducing the
sulfur content of the hydrocarbon product by flash distilling the
hydrocarbon product.
2. The method as recited in claim 1, further comprising
hydrocracking the hydrocarbon feedstock in the presence of hydrogen
and a hydrocracking catalyst.
3. The method as recited in claim 1, wherein the feedstock
comprises hydrocarbons with a boiling point above the diesel
boiling range.
4. The method as recited in claim 1, wherein the hydrocarbon
product comprises diesel.
5. The method as recited in claim 1, wherein the hydrocarbon
product comprises greater than or equal to 75 percent by weight
diesel.
6. The method as recited in claim 1, wherein the color of the
hydrocarbon product is improved to a color of less than or equal to
2.5 as determined by ASTM standards.
7. The method as recited in claim 1, wherein the color of the
hydrocarbon product is improved to a color of less than or equal to
1.5 as determined by ASTM standards.
8. The method as recited in claim 1, wherein flash distilling the
hydrocarbon product reduces the sulfur content of the hydrocarbon
product.
9. The method as recited in claim 8, wherein the sulfur content of
the hydrocarbon product is reduced by less than or equal to 40
percent by weight of the total hydrocarbon product.
10. The method as recited in claim 8, wherein the sulfur content of
the hydrocarbon product is reduced by greater than or equal to 40
percent by weight of the total hydrocarbon product
11. The method as recited in claim 1, wherein flash distilling the
hydrocarbon product generates an overhead hydrocarbon stream
comprising 99 percent by weight diesel.
12. The method as recited in claim 2, wherein hydrocracking the
hydrocarbon feedstock occurs prior to desulfurizing the hydrocarbon
feedstock.
13. The method as recited in claim 2, wherein desulfurizing the
hydrocarbon feedstock occurs prior to hydrocracking the hydrocarbon
feedstock.
14. The method as recited in claim 2, wherein desulfurizing the
hydrocarbon feedstock occurs concurrently to hydrocracking the
hydrocarbon feedstock.
15. The method as recited in claim 2, wherein the hydrocracking
catalyst and the desulfurization catalyst are the same.
16. The method as recited in claim 2, wherein the hydrocracking
catalyst and the desulfurization catalyst are dissimilar.
17. The method as recited in claim 1, wherein the desulfurization
catalyst is a nickel molybdenum catalyst.
Description
FIELD OF TECHNOLOGY
[0001] The present application is directed to systems and methods
for processing hydrocarbons.
BACKGROUND
[0002] The petroleum refining industry encounters many stringent
environmental and market demands for cleaner and more purified
fractions of fuels. Hydrotreating and hydrocracking can be used to
remove sulfur and convert heavy hydrocarbons into a broad range of
lighter hydrocarbon fractions.
[0003] Hydrocracking is typically a two-stage process combining
sulfur removal, catalytic cracking and hydrogenation. In a
hydrotreating stage, sulfur is removed from feedstock. In a
cracking stage, heavier components of feedstock are cracked in the
presence of hydrogen to produce more desirable products. The
process employs high pressure, high temperature, a catalyst and
hydrogen.
[0004] A wide variety of process flow schemes, operating conditions
and catalysts have been used in commercial hydrocracking processes.
However, systems and methods which provide improved product yield
and improved catalyst characteristics are needed in the field of
art.
SUMMARY
[0005] Systems and methods for processing hydrocarbons are herein
disclosed. According to one embodiment, a method includes
desulfurizing a hydrocarbon feedstock in the presence of a
desulfurization catalyst. A hydrocarbon product is recovered. The
color of the hydrocarbon product is improved and the sulfur content
of the hydrocarbon product is reduced by flash distilling the
product.
[0006] The foregoing and other objects, features and advantages of
the present disclosure will become more readily apparent from the
following detailed description of exemplary embodiments as
disclosed herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] Embodiments of the present application are described, by way
of example only, with reference to the attached Figures,
wherein:
[0008] FIG. 1 illustrates an exemplary system for hydrocracking
hydrocarbons according to one embodiment;
[0009] FIG. 2 illustrates an exemplary system for hydrotreating
hydrocarbons according to one embodiment; and
[0010] FIG. 3 illustrates an exemplary system for processing ultra
low sulfur diesel according to one embodiment.
DETAILED DESCRIPTION
[0011] It will be appreciated that for simplicity and clarity of
illustration, where considered appropriate, reference numerals may
be repeated among the figures to indicate corresponding or
analogous elements. In addition, numerous specific details are set
forth in order to provide a thorough understanding of the example
embodiments described herein. However, it will be understood by
those of ordinary skill in the art that the example embodiments
described herein may be practiced without these specific details.
In other instances, methods, procedures and components have not
been described in detail so as not to obscure the embodiments
described herein.
[0012] The feedstock for the systems and methods disclosed herein
can include, but are not limited to hydrocarbons, organic
materials, mineral oils, synthetic oils, shale oils, tar sands,
atmospheric gas oils, vacuum gas oils, deasphalted residua, vacuum
residue, atmospheric residua, hydrotreated residual oils, coker
distillates, straight run distillates, pyrolysis-derived oils, high
boiling synthetic oils, cycle oils, cat cracker distillates,
diesel, ultra low sulfur diesel and fractions and mixtures
thereof.
[0013] FIG. 1 illustrates an exemplary system for hydrocracking
hydrocarbons according to one embodiment. A feed stream can
include, but is not limited to hydrocarbons, organic materials,
mineral oils, synthetic oils, shale oils, tar sands, atmospheric
gas oils, vacuum gas oils, deasphalted residua, vacuum residue,
atmospheric residua, hydrotreated residual oils, coker distillates,
straight run distillates, pyrolysis-derived oils, high boiling
synthetic oils, cycle oils, cat cracker distillates or fractions
and mixtures thereof.
[0014] The feed stream is provided via line 1 and is mixed with
hydrogen gas provided via line 36. The resulting mixture is
introduced into a hydrocracking zone 3 via line 2. The
hydrocracking zone 3 can include one or more reactors containing
one or more beds of the same or different hydrocracking catalysts
used to hydrocrack the feed stream.
[0015] The hydrocracking catalyst can include, but is not limited
to amorphous bases and low-level zeolite bases combined with one or
more Group VIII or Group VIB metal hydrogenating components. The
hydrocracking catalyst can also include, but is not limited to any
crystalline zeolite cracking base with a Group VIII metal
hydrogenating component deposited within the zeolite. Additional
hydrogenating components can be selected from Group VIB metal
hydrogenating components for incorporation with the zeolite
base.
[0016] Zeolite cracking bases can be referred to as molecular
sieves and are usually composed of silica, alumina and one or more
exchangeable cations such as sodium, magnesium, calcium or rare
earth metals. Suitable zeolites found in nature include, for
example, mordenite, stilbite, heulandite, ferrierite, dachiardite,
chabazite, erionite and faujasite. Suitable synthetic zeolites
include, for example, the B, X, Y and L crystal types, e.g.,
synthetic faujasite and mordenite.
[0017] The active metal hydrogenation components used in
hydrocracking catalysts herein disclosed can include, but are not
limited to Group VIII components including iron, cobalt, nickel,
ruthenium, rhodium, palladium, osmium, iridium and platinum. In
addition to these metals, other promoters can also be used in
conjunction therewith, including Group VIB metals such as,
molybdenum and tungsten.
[0018] The amount of hydrogenating metal in the catalyst can vary
within wide ranges. In an exemplary embodiment, any amount between
about 0.05 percent and 30 percent by weight can be used and in the
case of noble metals an amount between about 0.05 to about 2 weight
percent can be used. The hydrogenating metal can be incorporated
into the hydrocracking catalyst by contacting a zeolite base
material with an aqueous solution of desired metal in cationic
form. Following addition of the selected hydrogenating metal or
metals, the resulting catalyst powder can be filtered, dried,
pelleted and calcined in air at temperatures of, for example, 371
to 648.degree. C. in order to activate the catalyst and decompose
ammonium ions.
[0019] The zeolite component can also first be pelleted, followed
by the addition of the hydrogenating component and activation by
calcining. The hydrocracking catalysts can be used in undiluted
form or the powdered zeolite catalyst can be mixed and copelleted
with other relatively less active catalysts, diluents or binders
such as alumina, silica gel, silica-alumina cogels, activated clays
and the like. These diluents can contain a minor proportion of an
added hydrogenating metal such as a Group VIB and/or Group VIII
metal.
[0020] The hydrocracking of the feed stream occurs by contacting
the hydrocracking catalyst with the feed stream in the presence of
hydrogen in the hydrocracking zone 3. The hydrocracking of the feed
stream breaks carbon-carbon bonds within the feed stream.
[0021] In an exemplary embodiment, hydrocracking herein disclosed
can occur at the following range of operating conditions:
Temperature: 250-460.degree. C.
Pressure: 8-200 bar
[0022] Liquid Hourly Space Velocity: 0.1-30 hr.sup.-1
H.sub.2/Hydrocarbon Ratio: 3,000-10,000 SCFB
H.sub.2 Consumption: 1,200-3,500 SCFB
[0023] The hydrocracked feed stream can be introduced into a hot,
high pressure stripper 5 via line 4. The stripper 5 can be
maintained at essentially the same pressure as the hydrocracking
zone 3 and a temperature from about 232-468.degree. C. The feed
stream is contacted with a counter-current flow of hydrogen gas or
a hydrogen-rich gas stream to produce an overhead vapor hydrocarbon
stream comprising diesel boiling range hydrocarbons and a bottom
liquid hydrocarbon stream comprising hydrocarbons with a higher
boiling point then the overhead vapor hydrocarbon stream.
[0024] The bottom liquid hydrocarbon stream is carried via line 6
and introduced into hot flash drum 7 to produce a vapor stream
carried via line 8. The vapor stream carried via line 8 can be
cooled in a heat exchanger (not shown) and the resulting cooled
stream can be introduced into cold flash drum 11 via lines 8 and
10.
[0025] The overhead vapor hydrocarbon stream is carried via line 24
and can be mixed with a hydrocarbon stream carried via line 39. The
resulting mixed vapor hydrocarbon stream is carried via line 25 and
introduced into a desulfurization zone 26. The desulfurization zone
26 can include one or more reactors containing one or more beds of
the same or different desulfurization catalysts used to remove
sulfur from the mixed vapor hydrocarbon stream.
[0026] The desulfurization catalyst can include, but is not limited
to hydrocracking catalysts herein disclosed including at least one
Group VII metal component such as, iron, cobalt and/or nickel and
at least one Group VI metal such as, molybdenum and/or tungsten, on
a high surface area support material, such as alumina. Other
suitable desulfurization catalysts include zeolitic catalysts, as
well as noble metal catalysts where the noble metal is selected
from palladium and platinum. More than one type of desulfurization
catalyst can be used in the same reaction vessel or zone.
[0027] In an exemplary embodiment, the Group VIII metal is
typically present in an amount ranging from about 2 to about 20
weight percent. The Group VI metal is typically present in an
amount ranging from about 1 to about 25 weight percent.
[0028] The desulfurization of the mixed vapor hydrocarbon stream
carried via line 25 occurs by contacting the desulfurization
catalyst with the mixed vapor hydrocarbon stream in the
desulfurization zone 26. The desulfurization of the mixed vapor
hydrocarbon stream removes sulfur from the mixed vapor hydrocarbon
stream. The desulfurization catalyst can also be contacted with the
mixed vapor hydrocarbon stream to remove nitrogen, saturate
aromatics and improve cetane.
[0029] In an exemplary embodiment, desulfurization can occur at the
following range of operating conditions:
Temperature: 200-485.degree. C.
Pressure: 8-200 bar
[0030] Liquid Hourly Space Velocity: 0.1-10 hr.sup.-1
[0031] The resulting desulfurization effluent is carried via line
27 and is introduced into a high pressure separator 28. A
hydrogen-rich vapor is removed from the high pressure separator via
line 29 and introduced into acid recovery zone 30. A lean solvent
can be introduced via line 31 into acid gas recovery zone 30 to
contact the hydrogen-rich vapor stream and dissolve acid gas
therein. A rich solvent containing acid gas can be removed from the
acid gas recovery zone via line 32 for recovery. A hydrogen-rich
vapor stream containing a reduced concentration of acid gas is
removed from the acid gas recovery zone 30 via line 33. The
hydrogen-rich vapor stream can be mixed with a hydrogen make-up
stream via line 34 and the resulting mixture can be carried via
line 35. The hydrogen-rich vapor stream carried via line 35 can be
bifurcated. A first stream can be carried via line 36 and
introduced into the hydrocracking zone 3 via line 2 and a second
stream can be carried via line 37 and introduced as stripping gas
into the hot, high pressure stripper 5.
[0032] As previously described, the bottom liquid hydrocarbon
stream is carried via line 6 from the hot, high pressure stripper 5
and introduced into hot flash drum 7 to produce a vapor stream
carried via line 8. The vapor stream carried via line 8 can be
cooled in a heat exchanger (not shown) and the resulting cooled
stream can be introduced into cold flash drum 11 via lines 8 and
10.
[0033] A liquid hydrocarbon stream is removed from high pressure
separator 28 and transported via lines 9 and 10 and introduced into
cold flash drum 11. A vapor hydrocarbon stream is removed from cold
flash drum 11 via line 12 and recovered. A liquid stream is removed
from cold flash drum 11 via line 13 and introduced into stripper
14. A vapor stream is removed from stripper 14 via line 15 and
recovered.
[0034] A liquid hydrocarbon stream is removed from stripper 14 via
line 16 and introduced into a first section of a distillation
column 17. Naphtha hydrocarbon streams can be removed from the
distillation column 17 via line 18 and recovered. Kerosene boiling
range hydrocarbon streams can be removed from the distillation
column 17 via line 19 and recovered. Low sulfur diesel boiling
range hydrocarbon vapor streams can be removed from the
distillation column 17 via line 20 and recovered.
[0035] A liquid hydrocarbon stream can be removed from hot flash
drum 7 via line 21 and introduced into a second section of the
distillation column 17 to produce a liquid hydrocarbon stream
containing diesel boiling range hydrocarbons, which is removed from
the distillation column 17 via line 22. The hydrocarbon stream
carried via line 22 can be mixed with a second feed stream which is
introduced via line 38 and the resulting mixture can be carried via
lines 39 and 25 and introduced into desulfurization zone 26. A
liquid stream containing ultra low sulfur diesel boiling range
product can be removed from the bottoms of the distillation column
17 via line 23 and recovered for further processing as disclosed
with respect to FIG. 3 below.
[0036] It will be understood by those of ordinary skill in the art
that the hydrocracking and desulfurization processes herein
disclosed can include modifications, additional features and
additional components. For example, in other commercial
hydrocracking processes desulfurization of the hydrocarbon
feedstock can occur prior to, after or concurrently with
hydrocracking of the feedstock.
[0037] In an exemplary embodiment, the hydrocracking of a
hydrocarbon feedstock is a two stage process wherein
desulfurization occurs prior to hydrocracking. Preheated feedstock
is mixed with recycled hydrogen and sent to a first-stage reactor,
where catalysts convert sulfur and nitrogen compounds to hydrogen
sulfide and ammonia. In the first stage, limited to no
hydrocracking occurs. After the hydrocarbon mixture leaves the
first stage, it is cooled and liquefied and run through a
hydrocarbon separator. Hydrogen gas is recycled for mixing with
additional feedstock and a liquid hydrocarbon stream is charged to
a fractionator. Depending on the desired products and product
specification, the fractionator is run to eliminate particular
components from the first stage reactor out-turn. Kerosene-range
material can be taken as a separate side-draw product or included
in the fractionator bottoms. The fractionator bottoms can be mixed
with a hydrogen stream and charged to the second stage. Since this
material has already been subjected to some hydrogenation,
cracking, and reforming in the first stage, the operations of the
second stage are more severe (higher temperatures and pressures).
Like the outturn of the first stage, the second stage product is
separated from the hydrogen and charged to the fractionator. A
diesel range hydrocarbon product can be recovered from this
two-stage process for further processing as disclosed with respect
to FIG. 3 below.
[0038] FIG. 2 illustrates an exemplary system 200 for hydrotreating
hydrocarbons according to one embodiment. A feed stream 202 can
include, but is not limited to hydrocarbons, organic materials,
mineral oils, synthetic oils, shale oils, tar sands, atmospheric
gas oils, vacuum gas oils, deasphalted residua, vacuum residue,
atmospheric residua, hydrotreated residual oils, coker distillates,
straight run distillates, pyrolysis-derived oils, high boiling
synthetic oils, cycle oils, cat cracker distillates or fractions
and mixtures thereof.
[0039] The feed stream 202 can be heated in a series of heat
exchangers 204, 206 and a furnace 208 before it is introduced into
a hydrotreating desulfurization zone 210. The desulfurization zone
210 can include one or more reactors containing one or more beds of
the same or different desulfurization catalysts.
[0040] The desulfurization catalyst can include, but is not limited
to hydrocracking catalysts herein disclosed including at least one
Group VII metal component such as, iron, cobalt and/or nickel and
at least one Group VI metal such as, molybdenum and/or tungsten, on
a high surface area support material, such as alumina. Other
suitable desulfurization catalysts include zeolitic catalysts, as
well as noble metal catalysts where the noble metal is selected
from palladium and platinum. More than one type of desulfurization
catalyst can be used in the same reaction vessel or zone to remove
sulfur from the feed stream 202. In an exemplary embodiment, the
desulfurization catalyst is a nickel molybdenum catalyst.
[0041] The desulfurization of the feed stream 202 occurs by
contacting the desulfurization catalyst with the feed stream 202 in
the desulfurization zone 210. The desulfurization of the feed
stream 202 reduces the sulfur content of the feed. The
desulfurization catalyst can also be contacted with the feed stream
202 to remove nitrogen, saturate aromatics and improve cetane.
Typically, limited to no cracking occurs in the desulfurization
zone 210 in the system 200. However, it is contemplated that
substantial cracking of the feed stream 202 could also occur in the
desulfurization zone 210 depending on the desulfurization catalyst,
operating temperature and pressure used within the desulfurization
zone 210.
[0042] In an exemplary embodiment, desulfurization can occur at the
following range of operating conditions:
Temperature: 200-485.degree. C.
Pressure: 8-200 bar
[0043] Liquid Hourly Space Velocity: 0.1-10 hr.sup.-1
[0044] A desulfurized feed stream 230 can be introduced into a
stripper 212. Hydrogen gas or a hydrogen-rich gas stream can also
be introduced into the stripper 212 from a hydrogen gas source 214.
The desulfurized feed stream 230 is contacted with a
counter-current flow of hydrogen gas or a hydrogen-rich gas to
produce an overhead stream 226 and a bottoms stream 228.
[0045] The overhead stream is a sour gas stream 226 that can
contain sulfur, hydrogen, methane, ethane, hydrogen sulfide,
NH.sub.3, propane, butane, heavier components and/or other
impurities. The overhead sour gas stream 226 can be cooled by
exchanging heat with the feed stream 202 in a heat exchanger 204,
thereby cooling and/or condensing the overhead sour gas stream 226
and heating the feed stream 202. The cooled, condensed or partially
condensed overhead sour gas stream can be flashed in a hot flash
drum 216, further cooled in a heat exchanger 220 and one or more
hot flash vapor coolers 218, 222 and flashed in a cold flash drum
224.
[0046] A bottoms stream 240 containing hydrocarbons can be taken
from the hot flash drum 216, cooled in a heat exchanger 232 and fed
to a product fractionator 234 or distillation column 234 for
separation into component parts. An overhead stream 242 of sour
hydrogen gas can be taken from the cold flash drum 224. A bottoms
stream 244 containing hydrocarbons can be taken from the cold flash
drum 224, heated in a heat exchanger 220 and fed to a product
fractionator 234 or distillation column 234 for separation into
component parts.
[0047] The bottoms stream 228 from the stripper 212 is a
hydrocarbon product stream 228. The hydrocarbon product stream can
be cooled in a heat exchanger 232 and separated into various
hydrocarbon fractions in a product fractionator 234 or distillation
column 234 to produce an overhead stream 236 within the naphtha
boiling point range and a bottoms stream product 238 within the
diesel boiling point range, such as an ultra low sulfur diesel
(ULSD) recovered for further processing as disclosed with respect
to FIG. 3 below.
[0048] The hydrocracking and hydrotreating processes herein
disclosed (e.g., as shown in FIGS. 1-2) can produce ULSD products.
However, the hydrocracking and desulfurization catalysts must be
changed frequently when the color of ULSD exceeds the specification
target. Although the catalyst may still be active in removing
sulfur, the color ULSD can be off-specification.
[0049] In an exemplary embodiment, the color of the ULSD cannot
exceed 2.5 ASTM and when exceeded the hydrocracking catalyst and/or
the desulfurization catalyst will have more than or equal to 5
months until deactivation. The exemplary systems herein disclosed
for processing ULSD can improve the color of a hydrocarbon product
comprising diesel within a required specification as determined by
ASTM standards.
[0050] FIG. 3 illustrates an exemplary system for processing ULSD
according to one embodiment. ULSD produced from a hydrocracking or
hydrotreating process is provided as feedstock for the system. In
an exemplary embodiment, the ULSD feed contains less than or equal
to 20 ppm sulfur and more preferably less than or equal to 10 ppm
sulfur.
[0051] ULSD is provided from a fractionator or distillation column
of a hydrocracking or hydrotreating process described herein and
introduced into a heat exchanger 102 via line 100 for heating. In
an exemplary embodiment, ULSD enters the heat exchanger 102 at an
inlet temperature of 238.degree. C. and is heated to an outlet
temperature of 324.degree. C.
[0052] ULSD exits the heat exchanger 102 and is introduced into a
furnace 108 via lines 104 and 106 for further heating. In an
exemplary embodiment, USLD enters the furnace 108 at an inlet
temperature of 324.degree. C. and is heated to an outlet
temperature of 366.degree. C.
[0053] Heated ULSD is introduced into a flash distillation tank 110
and the ULSD is distilled or flash vaporized to separate impurities
and colorants from the ULSD. The bottoms stream from the flash
distillation tank 110 can comprise heavy diesel, colorants, sulfur
and/or other impurities. In an exemplary embodiment, the bottoms
stream of the flash distillation tank 110 contains 1% or less by
weight heavy diesel with the remainder of the composition
comprising colorants and sulfur.
[0054] The bottoms stream from the flash distillation tank 110 can
be carried via line 112 for additional processing. In additional
processing steps, the bottoms stream from the flash distillation
tank 110 can be recovered for further processing.
[0055] The overhead product of the flash distillation tank 110
comprises ULSD having improved color within specification as
determined by ASTM standards. In an exemplary embodiment, the
overhead product is 99 percent by weight pure diesel having a color
of less than or equal to 2.5 as determined by ASTM standards. In
another exemplary embodiment, the overhead product is 99 percent by
weight pure diesel having a color of less than or equal to 1.5 as
determined by ASTM standards.
[0056] The overhead product of the flash distillation tank 110 can
be carried via line 114 into the heat exchanger 102 and used as
heating fluid for heating the ULSD feedstock. The overhead product
of the flash distillation tank 110 is cooled in the heat exchanger
102 as heat is exchanged between the ULSD feedstock and the
overhead product of the flash distillation tank 110. The overhead
product of the flash distillation tank 110 can be carried via line
116 and introduced into a secondary heat exchanger 118 for further
cooling. The cooled product can be introduced into a surge tank 122
via line 120. Excess gas, such as hydrogen gas and nitrogen gas can
be removed from the product and vented in an overhead stream
flowing from the surge tank 122. The bottoms product of the surge
tank can be pumped via pump 124 and carried via line 126 for
further cooling, processing and recovery.
[0057] The systems and methods herein disclosed for processing ULSD
can be used to improve the color quality of ULSD. In an exemplary
embodiment, the color of an off-specification ULSD feedstock
provided from a hydrocracking process can be improved from 5.6 to
1.5 as measure by ASTM standards by flash distilling the ULSD
feedstock as disclosed herein.
[0058] The systems and methods herein disclosed for processing ULSD
can also reduce the sulfur concentration of ULSD. In exemplary
embodiments, flash distillation of a ULSD feedstock reduced the
sulfur concentration of the ULSD feedstock between about 20 percent
by weight to about 40 percent by weight reduction in sulfur. The
hydrocracking or hydrotreating process from which the ULSD
feedstock is produced can be conducted at lower temperatures and
yield products with higher sulfur content due to the additional
reduction in sulfur obtained from flash distilling the ULSD
feedstock as disclosed herein. The life of the hydrocracking
catalysts and the desulfurization catalysts is extended by
conducting hydrocracking at lower temperatures. Additionally,
deeper cuts or fractions of light cycle oil (LCO) can be produced
in the hydrocracking or hydrotreating process from which the ULSD
feedstock is produced.
[0059] The systems and methods herein disclosed for processing ULSD
can also improve API Gravity. In an exemplary embodiment, the API
Gravity of ULSD is increased by about 0.3 by flash distilling the
ULSD feedstock as disclosed herein.
Examples
[0060] The following examples are provided for illustrative
purposes. The examples are not intended to limit the scope of the
present disclosure and they should not be so interpreted.
[0061] A ULSD feedstock from a hydrotreating process was used in
the illustrative Examples herein disclosed. The feedstock was
heated to a temperature of 366.degree. C. with the use of a heat
exchanger and furnace as described with respect to FIG. 2. The
feedstock was fed into a flash distillation tank and flashed
distilled in order to remove impurities including colorants, sulfur
and other impurities. The overhead ULSD product from the flash
distillation tank was recovered and the bottoms stream impurities
from the flash distillation tank were further processed as
described with respect to FIG. 2. The product exhibited improved
color and reduced sulfur content. The color and sulfur content for
three exemplary ULSD feed compositions before and after flash
distillation are provided in Tables 1 and 2.
TABLE-US-00001 TABLE 1 Color Improvement of ULSD Feed Color Product
Color Feed (ASTM) (ASTM) Feedstock 1 5.2 1.1 Feedstock 2 3.7 0.6
Feedstock 3 3.3 0.4 Feedstock 4 3.5 0.5 Feedstock 5 2.7 0.5
Feedstock 6 5.1 0.4 Feedstock 7 3.9 0.3
TABLE-US-00002 TABLE 2 Sulfur Content Reduction of ULSD Feed S
Product S Content Content Sulfur Reduction Feed (ppm) (ppm) (weight
percent) Feedstock 1 9.5 5.7 40% Feedstock 7 25 13.1 48% Feedstock
8 6.9 5.2 25% Feedstock 9 6.9 2.8 59% Feedstock 10 6.1 5.4 12%
[0062] As illustrated in Table 1, the color of Feedstock 1 was
improved from 5.2 to 1.1; the color of Feedstock 2 was improved
from 3.7 to 0.6; the color of Feedstock 3 was improved from 3.3 to
0.4; the color of Feedstock 4 was improved from 3.5 to 0.5; the
color of Feedstock 5 was improved from 2.7 to 0.5; the color of
Feedstock 6 was improved from 5.1 to 0.4; and the color of
Feedstock 7 was improved from 3.9 to 0.3.
[0063] As illustrated in FIG. 2, the sulfur content of Feedstock 1
was reduced by 40 percent by weight; the sulfur content of
Feedstock 7 was reduced by 48 percent by weight; the sulfur content
of Feedstock 8 was reduced by 25 percent by weight, the sulfur
content of Feedstock 9 was reduced by 59 percent by weight; and the
sulfur content of Feedstock 10 was reduced by 12 percent by
weight.
[0064] Example embodiments have been described hereinabove
regarding improved systems and methods for processing hydrocarbons.
Various modifications to and departures from the disclosed example
embodiments will occur to those having ordinary skill in the art.
The subject matter that is intended to be within the spirit of this
disclosure is set forth in the following claims.
* * * * *