Note: Descriptions are shown in the official language in which they were submitted.
~
' CA 02262392 2005-O1-10
r
I~YDROCA.RBC~N CONVERSION PROCESS
g; e'! d o~~ the Invention
This invention relates to a process -for upgrading
hydrocarbon feedstocks for subsequent use in steam cracking. Yn
particular, this invention describes a process for upgrading
hydrocarbon feedstocks for use in steam cracking by the
application of hydrotreating and concomitant partial
hydrogenation of the unsaturated and/or aromatic species found
therein, and the resultant yield increase of hydrogen, C1-Ca
hydrocarbons,, steam cracked naphtha and steam cracked gas oil,
and the concomitant decrease in the yield of steam cracked gas
tar, upon 'steam cracking of the hydrotreated hydrocarbon
feedstocks.
Backg~ o ~n of t 3,~wenti n
Steam cranking is.a process widely known in the
petrochemical art. The primary intent of the process is the
production of C~-Ca hydrocarbons, particularly ethylene,
propylene, and butadiene, by thermal cracking of hydrocarbon
feedstocks in the presence of steam at elevated temperatures.
The steam cracking process in general has been well described in
the publication entitled "Manufacturing Ethylene'' by S. B.
Zdonik et. al, Oil and Gas Journal Reprints 1966 - 19?0.
Typical liquid feedstocks for conventional steam crackers. are
straight run (virgin? and hydrotreated straight run (virgin)
feedstocks ranging from light naphthas to vacuum gas oils:
,3o Gaseous feedstocks such as ethane,.propane~and butane are also
commonly processed in the steam cracker.
The selection of a feedstock for processing in the
steam cracker is a function of several criteria includinga (i)
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availability of the feedstock, {ii) cost of the feedstock and
(iii) the yield slate derived by steam cracking of that
feedstock. Feedstock availability and cost are predominantly a
function of global supply and demand issues. On the other hand,
the yield slate derived by steam cracking of a given feedstock
is a function of the chemical characteristics of that feedstock.
In general, the yield of high value C1-Cd hydrocarbons,
particularly ethylene, propylene and butadiene, is greatest when
the steam cracker feedstocks are gaseous feedstocks such as
ethane, propane and butane. The yield of high value steam
cracked naphtha and low value steam cracked gas oil (SCGO) and
particularly low value steam cracked tar (SCT) upon steam
cracking of a straight run (virgin) or hydrotreated strsight run
(virgin) feedstocks increases as the boiling range of the
feedstock increases. Thus, the steam cracking of liquid
feedstocks such as naphthas, gas oils and vacuum gas oils
generally results in a greater proportion of particularly low
value steam cracked products, i.e., steam cracked tar. In
addition, steam cracking facilities where naphthas and gas oils
are processed require additional capital infrastructure in order
to process the large volume of liquid co-products resulting from
steam cracking of those feedstocks.
What is more, the yield of the least desirable
products of steam cracking, steam cracked tar, is generally even
higher when low quality hydrogen deficient cracked feedstocks
such as thermally cracked naphtha, thermally cracked gas oil,
catalytically cracked naphtha, catalytically cracked gas oil,
coker naphthas and coker gas oil are processed. The
significantly increased yield of the low value steam cracked tar
product relative to production of high value C1-CQ hydrocarbon
products obtained when processing the low quality hydrogen
deficient cracked feedstocks is such that these feedstocks are
rarely processed in steam crackers.
Catalytic hydrodesulfurization (sulfur removal),
hydrodenitrification (nitrogen removal) and hydrogenation
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(olefins, diolefins and aromatics saturation) are well known in
the petroleum refining art. Hydrodesulfurization,
hydrodenitrification and partial hydrogenation have been applied
to upgrading feedstocks for steam cracking as described by
Zimmermann in U.S. Patent No. 4,619,757. This two stage
approach employed base metal, bi-metallic catalysts on both non-
acidic (alumina) and acidic (zeolite) supports.
Minderhoud et. al., U.S. Patent No. 4,960,505,
described an approach for upgrading of kerosene and fuel oil
feedstocks by first pre-treating the feedstock to effect
hydrodesulfurization and hydrodenitrification to yield a liquid
product with sulfur and nitrogen contaminants at levels of less
than 1,000 and 50 ppm wt., respectively. Thereafter, the low
impurity hydrocarbon stream was subjected to hydrogenation to
yield a high cetane number fuel oil product.
Winquist et. al., U.S. Patent No. 5,391,291, described
an approach for upgrading of kerosene, fuel oil, and vacuum gas
oil feedstocks by first pre-treating the feedstock to effect
hydrodesulfurization and hydrodenitrification, and thereafter
hydrogenation of the resultant liquid hydrocarbon fraction to
yield a high cetane number fuel oil product.
It has been found that the present invention which
comprises hydrotreating followed by steam cracking results in
significant yield improvements for hydrogen, C1-Cd hydrocarbons
and steam cracked naphtha when applied to straight run (virgin)
feedstocks; and results in high yields of hydrogen, C1-Cd
hydrocarbons and steam cracked naphtha and reduced yields of
steam cracked tar when applied to low quality, hydrogen
deficient, cracked feedstocks such as thermally cracked naphtha,
thermally cracked kerosene, thermally cracked gas oil,
catalytically cracked naphtha, catalytically cracked kerosene,
catalytically cracked gas oil, cokes naphthas, cokes kerosene,
cokes gas oil, steam cracked naphthas and steam cracked gas
oils. The ability of this process to treat low quality hydrogen
deficient cracked feedstocks, such as steam cracked gas oil,
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permits these i:eretofore undesirable feedstocks to be _-cvcled
to e:ctinction through the combined feedstock upgrading and steam
cracking system.
It has further been found that ;~ydrogen, _ .,_
hydrocarbons and steam cracked naphtha can be produced in ~~igher
quantities in a process in which the effluent from at least one
hydrotreating zone containing at least two hydrotreating
catalysts is passed to a steam cracking zone. The effluents
from the steam cracking zone are then passed to one or :note
1C fractionating zones in which the effluents are separated i.~.to a
fraction comprising hydrogen and C_-Ca hydrocarbons, _ steam
,.r3CkeC1 naphtha frdCtlOn, a Stedm Cracked gaS Oil IraCtion dnd 3
Steam crackea gar frdCtlOn. The prOCeSS Cfi the pr~?S2nt
invention results in improved yields of the high value steam
'~5 crac'.~ced products, i.e., C~:-C; hydrocarbons, particularly
ethylene, propylene, and butadiene, and steam cracked naph~ha,
particularly isoprene, cis-pentadiene, traps-pentadiene,
cyclopentadiene, and benzene, and reduced yields of steam
racked tar.
20 Summary cf the Invention
''his invention provides an integrated process for
converting a hydrocarbon feedstock having components boiling
above 100°C into steam cracked products comprisv~ng hydrogen, C_-
C_ hydrocarbons, steam cracked naphtha (boilir:g from C= to
25 220°C) , steam cracked gas oil (boiling from 220°C to
275°C) and
steam cracked tar (boiling above 275°C).
The process of the present invention therefore
comprises: (i) passing the hydrocarbon feedstock through at
least one hydrotreating zone wherein said feedstock is contacted
30 at an elevated temperature and at a pressure in the range of
from about 400 psig (27 bar) to about 1,250 psig (85 bar) with a
hydrogen source and at least two hydrotreating catalysts to
effect substantially complete conversion of organic sulfur
and/or nitrogen compounds contained therein to HAS and NH3,
35 respectively; (ii) passing the product from said hydrotreating
zone to a product separation
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WO 98/06795 PCT/LTS97/14437
zone to remove gases and, if desired,. light hydrocarbon
fractions; (iii) passing the product from said separation zone
to a steam cracking zone and thereafter; (iv) passing the
product from said steam cracking zone to one or more product
separation zones to separate the product into a fraction
comprising hydrogen and C1-C~ hydrocarbons, a steam cracked
naphtha fraction, a steam cracked gas oil fraction and a steam
cracked tar fraction, wherein the yields of ethylene and
propylene and butadiene in the HZ and Ci-Cd hydrocarbons fraction
are each increased by at least about 5 percent, relative to the
yields obtained when the untreated hydrocarbon feedstock is
subjected to said steam cracking and product separation, the
yield of isoprene, cis-pentadiene, trans-pentadiene,
cyclopentadiene and benzene in the steam cracked naphtha
fraction are each increased by at least about l0 percent,
relative to when the untreated hydrocarbon feedstock is
subjected to said steam cracking and product separation, the
yield of steam cracked gas oil is increased by at least about 20
percent, relative to when the untreated hydrocarbon feedstock is
subjected to said steam cracking and product separation, and the
yield of steam cracked tar is reduced by at least about 15
percent, relative to when the untreated hydrocarbon feedstock is
subjected to said steam cracking and product separation.
Descr? nt? on of the Prc~ft~r~-pri ~bodi mPnt-,~
As used in this specification, the term "Cl-Cd
hydrocarbons" refers to methane, ethane, ethylene, acetylene,
propane, propylene, propadiene, methylacetylene, butane,
isobutane, isobutylene, butene-1, cis-butene-2, trans-butene-2,
butadiene, and C,-acetylenes. As used in this specification, the
term "steam cracked naphtha" refers to products boiling between
CS and 220°C, including isoprene, cis-pentadiene, trans-
pentadiene, cyclopentadiene, methylcyclopentadiene, and benzene.
The hydrocarbon feedstock in the process of the
present invention typically comprises a hydrocarbon fraction
having a major proportion, i.e., greater than about 95 percent,
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of its components boiling above about 100°C, preferably above
about 150°C or higher. Suitable feedstocks of this type include
straight run (virgin) naphtha, cracked naphthas (e. g.
catalytically cracked, steam cracked, and coker naphthas and the
like), straight run (virgin) kerosene, cracked kerosenes (e. g:
catalytically cracked, steam cracked, and coker kerosenes and
the like), straight run (virgin) gas oils (e.g. atmospheric and
vacuum gas oil and the like), cracked gas oils (e.g. coker and
catalytically cracked light and heavy gas oils, steam cracked
gas oils and the like) visbreaker oil, deasphalted oil, thermal
cracker cycle oil, synthetic gas oils and coal liquids.
Normally the feedstock will have an extended boiling range,
e.g., up to 650°C or higher, but may be of more limited ranges
with certain feedstocks. In general, the feedstocks will have
a boiling range between about 150°C and about 650°C.
In the hydrotreating zone, the hydrocarbon feedstock
and a hydrogen source are contacted with at least two
hydrotreating catalysts to effect substantially complete
decomposition of organic sulfur and/or nitrogen compounds in the
feedstock, i.e., organic sulfur levels below about 100 parts per
million, preferably below about 50 parts per million, and more
preferably below about 25 parts per million, and organic
nitrogen levels below about 15 parts per million, preferably
below about 5 parts per million, and more preferably below about
3 parts per million. The source of hydrogen will typically be
hydrogen-containing mixtures of gases which normally contain
about 70 volume percent to about 100 volume percent hydrogen.
In one embodiment, the hydrotreating zone contains two
hydrotreating catalysts in a stacked bed or layered arrangement.
When a stacked bed catalyst configuration is utilized, the first
hydrotreating catalyst typically comprises one or more Group VIB
and/or Group VIII (Periodic Table of the Elements) metal
compounds supported on an amorphous carrier such as alumina,
silica-alumina, silica, zirconia or titanic. Examples of such
metals comprise nickel, cobalt, molybdenum and tungsten. The
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first hydrotreating catalyst is preferably an oxide and/or
sulfide of a Group VIII metal, preferably cobalt or nickel,
mixed'with an oxide and/or a sulfide of a Group VIB metal,
preferably molybdenum or tungsten, supported on alumina or
silica-alumina. The second hydrotreating catalyst typically
comprises. one or more Group VIB and/or Group VIII metal
components supported on an acidic porous support. From Group
VIB, molybdenum, tungsten and mixtures thereof are preferred.
From Group VIII, cobalt, nickel and mixtures thereof are
preferred. Preferably, both Group VIB and Group VIII metals are
present. In~ a particularly preferred embodiment, the
hydrotreating component of the second hydrotreating catalyst is
nickel and/or cobalt combined with tungsten and/or molybdenum
with nickel/tungsten or nickel/molybdenum being particularly
preferred. With respect to the second hydrotreating catalyst,
the Group VIB and Group VIII metals are supported on an acidic
carrier, such as, for example, silica-alumina, or a large pore
molecular sieve, i.e. zeolites such as zeolite Y, particularly,
ultrastable zeolite Y (zeolite USY), or other dealuminated
zeolite Y. Mixtures of the porous amorphous inorganic oxide
carriers and the molecular sieves can also be used. Typically,
both the first and second hydrotreating catalysts in the stacked
bed arrangement are sulfided prior to use.
The hydrotreating zone is typically operated at
temperatures in the range of from about 200°C to about 550°C,
preferably from about 250°C to about 500°C, and more preferably
from about 275°C to about 425°C. The pressure in the
hydrotreating zone is generally in the range of from about 400
psig to about 1,250 psig, preferably from about 400 psig to
about 1, 000 psig, and more preferably from about 400 psig to
about 750 psig. Liquid hourly space velocities (LHSV) will
typically be in the range of from about 0.1 to about 10,
preferably from about 0.5 to about 5 volumes of liquid
hydrocarbon per hour per volume of catalyst, and hydrogen to oil
ratios will be in the range of from about 500 to about 10,000
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standard cubic feet of hydrogen per barrel of feed (SCr~/BBL)
(about .089 to about 2.0 standard cubic meters per liter of feed
(m'/~)), preferably from about 1,000 to about 5,000 SCF/BBL
(about 0.18 to about 1.00 m3/~), most preferably from about
2,000 to about 3,000 SCF/BBL (about .35 to about .53 m'/z).
These conditions are adjusted to achieve substantially complete
desulfurizatien and denitrification, i.e., organic sulfur levels
below about 100 parts per million, preferably below about 50
parts per million, and more preferably below about 25 parts per
million, and organic nitrogen levels below about 15 parts per
million, preferably below about 5 parts per million, and more
preferably below about 3 parts per million.
Alternatively, the hydrotreating step may be carried
out utilizing two or more hydrotreating zones. ccr example, in
one embodiment, the hydrotreating step can be carried out i.~. t:ne
manner described below in which two zones, a first hyarotreating
zone and a second hydrotreating zone, are used.
In the first hydrotreating zone, the hydrocarbon
feedstock and a hydrogen source are contacted with a first
hydrotreating catalyst. The source of hydrogen will typically
be hydrogen-containing mixtures of gases which normally contain
about 70 volume percent to about 100 volume percent hydrogen.
The first hydrotreating catalyst will typically include cne or
more Group VIB and/or Group VIII metal compounds on an amorphous
carrier such as alumina, silica-alumina, silica, zirconia or
titania. Examples of such metals comprise nickel, cobalt,
molybdenum and tungsten. The first hydrotreating catalyst is
preferably an oxide and/or sulfide of a Group VIII metal,
preferably cobalt or nickel, mixed with an oxide and/or a
sulfide of a Group VIB metal, preferably molybdenum or tungsten,
supported on alumina or silica-alumina. The catalysts are
preferably in sulfided form.
The first hydrotreating zone is generally operated at
temperatures in the range of from about 200°C to about 550°C,
preferably from about 250°C to about 500°C, and more preferably
from about 275°C to about 425°C. The pressure in the first
hydrotreating zone is generally in the range of from about 27
_g_
AMENDED SHEET
>o'c~C~?3
CA 02262392 1999-02-04
bar to about 85 bar, preferably from about 27 bar to about 58
bar, and more preferably from about 27 bar to about 51 bar.
Liquid hourly space velocities (LHSV) will typically be in the
range of from about 0.2 to about 2, preferably from about 0.5 to
about 1 volumes of liquid hydrocarbon per hour per volume of
catalyst, and hydrogen to oil ratios will be in the range of
from about 500 to about 10, 000 s tandard cubic feet of hydrogen
per barrel of feed (SCF/BBL) (about .089 m'/P to about 2.0
m''/~), preferably from about 1,000 to about 5,000 SCF/BBL (about
0.18 to about 1.0 mv/P), most preferably from about 2,000 to
about 3,000 SCF/BBL about .35 to about .53 m'/e). These
conditions are adjusted to achieve the desired degree of
desulfurization and denitrification. Typically, it is desirable
in the first hydrotreating zone to reduce the organic sulfur
level to below about 500 parts per million, preferably below
about 200 parts per millicn, and the organic nitrogen level to
below about 50 parts per million, preferably below about 25
parts per million.
The product from the first hydrotreating zone may
then, optionally, be passed to a means whereby ammonia and
hydrogen sulfide are removed from the hydrocarbon product by
conventional means. The hydrocarbon product from the first
hydrotreating zone is then sent to a second hydrotreating zone.
Optionally, the hydrocarbon product may also be passed to a
fractionating zone prior to being sent to the second
hydrotreating zone if removal of light hydrocarbon fractions is
desired.
In the second hydrotreating zone, the product from
the first hydrotreating zone and a hydrogen source, typically
hydrogen, about 70 volume percent to about 100 volume percent,
in admixture with other gases, are contacted with at least one
second hydrotreating catalyst. The operating conditions
normally used in the second hydrotreating reaction zone include
a temperature in the range of from about 200°C to about 550°C,
preferably from about 250°C to about 500°C, and more preferably,
from about 275°C to about 425°C, a liquid hourly space velocity
_g_
AMENDED SHEET
CA 02262392 1999-02-04
9620~'_ .. . ,
..
(LHSV) of about 0.1 to about 10 volumes of liquid hydrocarbon
per hour per volume of catalyst, preferably an LHSV of about 0.5
to about 5, and a total pressure within the range of about 27
bar to about 85 bar, preferably from about 27 bar to about 68
bar, and more preferably from about 27 bar to about 51 bar. The
hydrogen circulation rate is generally in the range of from
about 500 to about 10,000 standard cubic feet per barrel
(SCF/BBL) (about .089 to about 2.0 m'/P), preferably from about
1,000 to 5,000 SCF/BBL (about 0.18 to about 1.0 m'/P), and more
preferably from about 2,000 to 3,000 SCF/BBL (about .35 to about
.53 m3/P). These conditions are adjusted to achieve
substantially complete desulfurization and denitrification.
Typically, it is desirable that the hydrotreated product
obtained from the hydrotreating zone or zones have an organic
sulfur level below about 100 parts per million, preferably below
about SO parts per milkon, and more preferably below about 25
parts per million, and an organic nitrogen level below about 15
parts per million, preferably below about 5 parts per million
and more preferably below about 3 parts per million. It is
understood that the severity of the operating conditions is
decreased as the volume of the feedstock and/or the level of
nitrogen and sulfur contaminants to the second hydrotreating
zone is decreased. For example, if product gases, including HAS
and NH3 (ammonia), and, optionally, light hydrocarbon fractions
are removed after the first hydrotreating zone, then the
temperature in the second hydrotreating zone will be lower, or
alternatively, the LHSV in the second hydrotreating zone will be
higher.
The catalysts typically utilized in the second
hydrotreating zone comprise an active metals component supported
on an acidic porous support. The active metal component, "the
hydrotreating component", of the second hydrotreating catalyst
is selected from a Group VIB and/or a Group VIII metal
component. From Group VIB, molybdenum, tungsten and mixtures
thereof are preferred. From Group VIII, cobalt, nickel and
mixtures thereof are preferred. Preferably, both Group VIB and
Groin VIII metals are present. In a particularly preferred
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CA 02262392 2005-O1-10
r
embodiment,~the hydrotreating component is nickel and/or cobalt
combined with tungsten and/or molybdenum with nickel/tungsten or
niokel/molybdenum being particularly preferred. The components
are typically present in the sulfide for:u:
The Group VIB and Group VI=I metals are supported on
an acidic carrier. Two rain classes o~ ~carri.ers knawn in the
. art are typically utilized: (aj silic:a-alumina, and (bj the
large pore molecular s3.eves, i ~~e: zeolites such as 2eolite Y,
Mordenite, Zeolite Beta and the like. Mixtures of the porous
amorphous inorganic oxide carriers and the molecular sieves are
also used. The term "silica--alumina" refers to non~Zeolit~.e
aluminosilicates.
The most preferred support <:omprises a zeolite Y,
preferably a dealuminuated zeolite Y such as an ultrastable
zeolite Y (zeolite U~Yj. The~ultrastable zeolites used herein
are well known to those. skilled in the art. They .are also
exemplified in U.S. Patent Nos. 3,293,192 and 3,449,0?0. They
are generally prepared from sodium zeolite Y by dealumination.
The zeohte is aomposited w3.th a binder selected from
alumina, silica, silica-alumina and mixtures thereof.
Preferably the binder is alumina, preferably a gamma .alumina
binder or a precursor thereto, such as an' alumina hydrogel,
aluminum trihydroxide, aluminum oxyhydroxide or pseudoboehmite.
The Group V=H/Group VIIJC second hydrotreating
catalysts are preferably sulfided prior to use in the ri~econd
hydrotreating zone. Typically, the catalysts are sulf~.ded by
heating the catalysts to elevated temperatures (e.g., 200~400°C)
in the presence of hxdrogen and sulfur or a sulfur-containing
material.
The product from the final hydrotreating zone. is then
passed to a steam cracking, i.e.;w..pyrolysis, zone. Prior to
being sent to the steam cracking zone, however, if desired, the
hydrocarbon product from the final hydrotreating zone may be
11
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CA 02262392 1999-02-04
passed to a fractionating zone for removal of product gases, and
light hydrocarbon fractions.
In the steam cracking zone, the product from the
hydrotreating zone and steam are heated to cracking
temperatures. The operating conditions of the steam cracking
zone normally include a coil outlet temperature greater than
about 700°C, in particular between about 700°C and 925°C,
and
preferably between abcut 750°C and about 900°C, with steam
present at a steam to hydrocarbon weight ratio in the range of
from about 0.1:1 to about 2.0:1. The coil outlet pressure _=
the steam cracking zone is typically in the range of from about
0 bar to about 5 bar, preferably in the range of from about 0
bar to about 4 bar. The residence time for the cracking
reaction is typically in the range of from about 0.01 second to
about 5 seconds and preferably in the range of from about C.';
second to about 1 second.
After the starting hydrocarbon feed has been
subjected to a hydrotreating step and a steam cracking step, the
effluent from the steam cracking step may be sent to one or more
fractionating zones wherein the effluent is separated into a
fraction comprising hydrogen and C;-C~ hydrocarbons, a steam
cracked naphtha fraction boiling from C~ to about 220°C, a steam
cracked gas oil fraction boiling in the range of from about
220°C to about 275°C and a steam cracked tar fraction boiling
above about 275°C. The amount of the undesirable steam cracked
product, i.e., steam cracked tar, obtained utilizing the process
of the present invention is greatly reduced. The yield of steam
cracked tar is reduced by at least about 15 percent, relative to
that obtained when the untreated hydrocarbon feedstock is
subjected to steam cracking and product separation.
The process according to the present invention may be
carried out in any suitable equipment. The hydrotreating zone or
zones in the present invention typically comprise one or more
vertical reactors containing at least one catalyst bed and are
equipped with a means of injecting a hydrogen source into the
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reactors. A fixed bed hydrotreating reactor system wherein the
feedstock is passed over one or more stationary beds of catalyst
in each zone is particularly preferred.
The ranges and limitations provided in the instant
specification and claims are those which are believed to
particularly point out and distinctly claim the instant
invention. It is, however, understood that other ranges and
limitations that perform substantially the same function in
substantially the same manner to obtain the same or
substantially the same result are intended to be within the
scope of the instant invention as defined by the instant
specification and claims.
The invention will now be described by the following
examples which are illustrative and are not intended to be
construed as limiting the scope of the invention.
rl_lLStrat,_'ye Embodimprt-
Example 1 and Comparative Example 1-A below were each
carried out using a 100% Heavy Atmospheric Gas Oil (HAGO)
feedstock having the properties shown in Table 1 below. Example
1 illustrates the process of the present invention. Comparative
Example 1-A illustrates HAGO which has not been subjected to
hydrotreating prior to steam cracking.
Fxamp 1~
Example 1 describes the process of the present
invention using a 100% Heavy Atmospheric Gas Oil (HAGO) feed
having the properties shown in Table 1 below was hydrotreated
using two hydrotreating catalysts in a stacked bed system as
follows.
A commercial alumina supported nickel/molybdenum
catalyst, available under the name of.KF-756 from Akzo Chemicals
Inc., U.S.A., was used as the first hydrotreating catalyst
(catalyst A) while a commercial zeolite nickel/tungsten
catalyst, available under the name of Z-763 from Zeolyst
International, was used as the second hydrotreating catalyst
(catalyst B).
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Catalysts A and B catalysts were operated as a
"stacked bed" wherein the HAGO and hydrogen contacted catalyst A
first and -hereafter catalyst B, with the volume ratio of the
catalysts (A:B) being 1:1. The HAGO was hydrotreated at 360°C
(o75°F), 39.8 bar total unit pressure, an overall LHSV of 0.5
hr-1 and a hydrogen flow rate of 3,000 SCF/BBL )0.53 m3/P).
The hydrotreated product was then passed to the steam
cracking zone where it was contacted with steam at a temperature
of 745 to 7'o5°C, a pressure of 0.88 to 1.73 bar, and a steam to
hydrocarbon weight ratio of 0.3:1 to 0.45:1. The residence time
in the steam cracker was 0.4 to 0.o seconds. The steam cracked
product was then sent to a fractionating zone to quantify total
hydrogen (Hz) and C~,-C~ Pydrocarbons, steam cracked naphtha
(SCN), steam cracked gas oil (SCGO), and steam cracked tar
(SCT). The steam cracking results are presented in Table 3
below.
Comparative Example 1-A
A 100% Heavy Atmospheric Gas Oil (HAGO) feed was
treated in the same manner as forth in Example 1 above, except
that it was not subjected to hydrotreating prior to steam
cracking. The steam cracking results are presented in Table 3
below.
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WO 98/06795 PCT1US97/14437
Properties of HAGO Feed (Comp. Ex. 1-A) and
Hydrotreated HAGO (Ex. 1)
HALO Hydrotreated
Feed HAGO
(1-A) (Ex. 1)
wt. % H 12.76 13.47
ppm wt. S 12,400 41
ppm iat . N 42 6 1
Density, G/cm3 0.8773 0.8242
@ 15C
Simulated Distillation, D-2887 (ASTM), C
IBP 99 37
5% 200 99
10% 238 124
30% 304 200
50% 341 261
70% 374 337
90% 421 389
95% 443 413
FBP 491 485
I3AG0 feed (Comparative Example 1-A) and hydrotreated
HAGO (Example 1) were analyzed by GC-MS in order to determine
the structural types of the hydrocarbons present. These results
are shown in Table 2 below. The results clearly show that the
process of the present invention (Example 1) is effective at
reducing the aromatic content of hydrocarbon feed streams with
a concomitant rise in the quantity of both
paraffins/isoparaffins and naphthenes.
Molecular Structural Types Observed in HALO, HT-HAGO,
Hydrotreated HAGO and Distilled Saturated HT-HAGO
3 0 Relative Abundance of Various Hydrotreated
Molecular HAGO HAGO
Types, Vol. % (1-A) (Ex. 1)
Paraffins/Isoparaffins 27.69 28.70
Naphthenes 38.87 41.29
3 5 Aromatics 33.46 30.00
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WO 98106795 PCT/US97/14437
Laboratory Steam Cracking Yields for Gaseous
Products, Naphtha, Gae Oil, and Tar
FIAGO Hydrotreated
Product Yield, wt. % (1-A) 8AG0
Based on Feedstock (Ex. 1)
Total H2 and C1-C, 48.73 52.66
Hydrocarbons
Total Others, C5 and Greater 51.27 47.34
SCN, CS-220°C (430°F) 23.54 29.50
SCGO, 220-275°C(430-525°F) 4.83 6.06
SCT, 275°C (526°F) and Above 22.90 11.78
Total 100.0 100.0
Hydrogen 0.39 0.46
Methane 7.64 8.02
Ethane 4.03 3.91
Ethylene 14.39 16.54
Acetylene 0.06 0.07
Propane 0.72 0.62
2 0 Propylene 12.06 12.80
Propadiene & Methylacetylene 0.18 0.18
Butane & Isobutane 0.13 0.16
Isobutylene 1.88 2.16
Butene-1 2.21 2.72
2 5 Butadiene-1,3 3.32 3.74
Butene-2 (cis & trans) 1.25 1.27
C4 acetylenes 0.01 0.01
Selected Li
uid Prod
t
q
uc 0.89 1.08
s
Isoprene
3 0 Pentadiene (cie & trans) 0.74 0.95
Cyclopentadiene 1.19 1.48
Methylcyclopentadiene 0.81 1.06
Benzene 3.35 3.88
As can be seen in Table 3 above, the yield of each of
35 the particularly valuable steam cracked mono- and diolefin
products in the HZ and C1-Cd hydrocarbons fraction, i.e.,
ethylene, propylene, and butadiene, is increased by at least
about 6.0 percent, the yield of each of the valuable steam
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CA 02262392 1999-02-04
cracked diolefin and aromatic products in the steam cracked
naphtha fraction, i.e., ~~soprene, cis-pentadiene, trans-
pentadiene, cyclopentadiene, and benzene, is increased by at
least about 15 percent, the yi eld of the steam cracked gas oil
product is increased by about 25 percent and the yield of the
low value steam cracked tar product is decreased by about 48
percent when the process of the present invention comprising
hydrotreating and steam cracking (Example 1) is utilized
relative to the yields obtained when the untreated hydrocarbon
feed alone is subjected to steam cracking (Comparative Example
1-A) .
Illustrative Embcdiment 2
Example 2 and Comparative Example 2-A below were each
carried out using a 100 Catalytically Cracked Naphtha (CCN)
feedstock having the properties shown in Table 4 below. Example
2 illustrates the process of the present invention. Comparative
Example 2-A is illustrative of CCN which has not been subjected
to hydrotreating prior to steam cracking.
Example 2
Example 2 describes the process of the present
invention using a 1000 Catalytically Cracked Naphtha (CCN) feed.
A commercial alumina supported nickel/molybdenum
catalyst (1/20" trilobe), available under the name of C-411 from
Criterion Catalyst Company, was used as the first hydrotreating
catalyst (catalyst A) while a commercial prototype
hydroprocessing catalyst (1/8" cylinder), available under the
name of HC-10 from Linde AG was used as the second hydrotreating
catalyst (catalyst B).
The catalysts A and B were operated in the
hydrotreating zone as a "stacked bed" wherein the feedstock and
hydrogen were contacted with catalyst A first and thereafter
with catalyst B; the volume ratio of the catalysts (A:B) in the
hydrotreating zone was 2:1. The feed stock was hydrotreated at
370°C (700°F) , 40.8 bar total unit pressure, an overall LHSV of
0.33 hr-1 and a hydrogen flow rate of 2,900 SCF/BBL (0.52 m3/P),
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.: . _:r'
96305:H
CA 02262392 1999-02-04
Hydrotreating of the CCN feed consumed 860 SCF/BBL
(0.15 m3/~) of hydrogen. and resulted in the production of 0.9
percent by weight of light gases (methane, ethane, propane and
butane) and 2.5 percent by weight of liquid hydrocarbon boiling
between C; and 150°C ( 300°F) .
The hydrotreated CCN was then passed to the steam
cracking zone when? it was contacted with steam at a temperature
of 790 to 805°C, a pressure of between i . 22 to 1 . 39 bar, and a
steam to hydrocarbon weight ratio of 0.3:1 to 0.45:1. The
residence time in the steam cracker was 0.4 to 0.6 seconds. The
steam cracked product was -hen sent to a fractionating zone to
quantify total hydrogen (H_) and . -C,) hydrocarbons, steam
cracked naphtha (SCN), steam cracked gas oil (SCGC), and steam
cracked tar (SCT). The steam cracking results are presented in
Table 6 below.
Comparative Example 2-A
A 100% Catalytically Cracked Naphtha (CCN) feed was
treated in the same manner as set forth in Example 2 above,
except that it was not subjected to hydrotreating prior to steam
cracking. The steam cracking results are presented in Table 6
below.
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AMENDED SiirET
CA 02262392 1999-02-04
WO 98/06795 PCT/US97J14437
Properties of CCN Feed (Com . Ex 2-A) and Hydrotreated CCN (Ex 2)
CCN Hydrotreated
Feed CCN
(2-A) (Ex 2)
wt. % C 89.15 88.31
wt. % H 10.31 11.78
ppm wt. S
ppm wt. N 4,130 ~2
217 <1
Density, g/cm3 0.9071 0.8714
@15°C
Simulated Distillation, D-2887 (ASTM), °C
IBP 189 75
5%
202 161
10% 205 183
30% 212 204
50% 221 212
70% 230 223
90%
236 235
95% 242 244
FBP 376 341
CCN Feed (Comparative Example 2-A) and the hydrotreated CCN
(Example 2) were analyzed by GC-MS in order to determine the structural types
2 0 of the hydrocarbons present. These results are shown in Table 5 below. As
can be seen in Table 5, the process of the present invention (Example 2) ie
effective at reducing the aromatic content of hydrocarbon feed streams with
a concomitant rise in the quantity of both paraffins/isoparaffins and
naphthenes.
2 5 TABLE 5
Molecular Structural Types Observed in CCN Feed (Comp. Ex.
2-A) and Hydrotreated CCN (Ex 2)
Relative Abundance of Various CCN Hydrotreated
Molecular Feed CCN
3 0 Types, Vol. % (2-A) (Ex 2)
Paraffins/Isoparaffins 7:97 10.92
Naphthenes 5.19 26.79
Aromatics 86.83 62.27
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WO 98/06795 PCT/US97/14437
Laboratory Stesm Cracking Yields for GaseousProducts
Naphtha, Gas Oil, and Tar
Product Yield wt. % CCN Hydrotreated
Baeed on Feedetock Feed C~
(2-A) (Ex 2)
Total Hz and C1-C, Hydrocarbons 27.67 33.32
Total Others CS and Greater 72.33 66.68
SCN, CS 220C (430F) 40.85 35.79
SCGO, 220-275C(430-525F) 7.75 12.00
SCT, 275C (526F) and Above 23.73 lg,8g
Total 100.00 100.00
Selected GaseoLS ProdLCts
Hydrogen
0.65 0.74
Methane 8.03 9.58
Ethane 1.91 2.66
Ethylene 9.09 10.81
Acetylene 0.08 0.09
Propane 0.07 0.07
Propylene 4.79 5.81
2 Propadiene & Methylacetylene 0,08 0.08
0
Butane & Isobutane 0.03 0.02
Isobutylene 0.87 0.91
Butene-1 0.25 0.27
Butadiene-1,3 1.28 1.53
2 Butene-2 (cis & trane) 0.32 0.43
5
C, acetylenes 0.00 0.00
Selected L? r
~i d ProdLCts
, 0.00 0.35
Isoprene
Pentadiene (cis & traps) 0.13 0.15
3 Cyclopentadiene 0.49 0.80
0
methylcyclopentadiene 0.10 0.00
Benzene 2.79 4.03
As can be seen in Table 6 above, the yield of each of
the particularly valuable steam cracked mono- and diolefin
35 products in the HZ and C~-C4 hydrocarbons fraction, i.e.,
ethylene, propylene, and butadiene, is increased by at least
about 18 percent, the yield of each of the valuable steam
cracked diolefin and aromatic products in the steam cracked
naphtha fraction, i.e., isoprene, cis-pentadiene, trans-
40 pentadiene, cyclopentadiene, and benzene, is increased by at
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CA 02262392 1999-02-04
WO 98/06795 PCT/US97114437
least about 15 percent, the yield of the steam cracked gas oil
product is increased by about 54 percent and the yield of the
low value steam cracked tar product is decreased by about 20
percent when the process of the present invention comprising
hydrotreating and steam cracking (Example 2) is utilized
relative to the yields obtained when the untreated hydrocarbon
feed alone is subjected to steam cracking (Comparative Example
2-A) .
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